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, 2021
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 28, 2021	
 		
American Electric Power Company, Inc.	503,651,677 		
 	($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, 2021	
 	 			 	
 	 			Page	
 	 			Number	
Glossary of Terms	i	
 	 			 	
Forward-Looking Information	vi	
 	 			 	
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	55	
 	 			 	
AEP Texas Inc. and Subsidiaries:		
	Management’s Narrative Discussion and Analysis of Results of Operations	62	
	Condensed Consolidated Financial Statements	67	
					
AEP Transmission Company, LLC and Subsidiaries:	 	
 	Management’s Narrative Discussion and Analysis of Results of Operations	74	
 	Condensed Consolidated Financial Statements	76	
					
Appalachian Power Company and Subsidiaries:	 	
 	Management’s Narrative Discussion and Analysis of Results of Operations	82	
 	Condensed Consolidated Financial Statements	87	
 	 			 	
Indiana Michigan Power Company and Subsidiaries:	 	
 	Management’s Narrative Discussion and Analysis of Results of Operations	94	
 	Condensed Consolidated Financial Statements	99	
 	 			 	
Ohio Power Company and Subsidiaries:	 	
 	Management’s Narrative Discussion and Analysis of Results of Operations	106	
 	Condensed Consolidated Financial Statements	111	
 	 			 	
Public Service Company of Oklahoma:	 	
 	Management’s Narrative Discussion and Analysis of Results of Operations	117	
 	Condensed Financial Statements	121	
 	 			 	
Southwestern Electric Power Company Consolidated:	 	
 	Management’s Narrative Discussion and Analysis of Results of Operations	128	
 	Condensed Consolidated Financial Statements	132	
 	 			 	
Index of Condensed Notes to Condensed Financial Statements of Registrants	138	
 	 			 	
Controls and Procedures	243	

															
Part II.  OTHER INFORMATION	 	
 	 	 	 	 	
 	Item 1.	  Legal Proceedings	244	
 	Item 1A.	  Risk Factors	244	
 	Item 2.	  Unregistered Sales of Equity Securities and Use of Proceeds	244	
	Item 3.	  Defaults Upon Senior Securities	244	
 	Item 4.	  Mine Safety Disclosures	244	
 	Item 5.	  Other Information	245	
 	Item 6.	  Exhibits	246	
 	 	 	 	 	
SIGNATURE	 	 	248	

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.	
	
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.	
ALJ		Administrative Law Judge.	
AMI		Advanced Metering Infrastructure.	
AMR		Automated Meter Reading.	
AOCI	 	Accumulated Other Comprehensive Income.	
APCo	 	Appalachian Power Company, an AEP electric utility subsidiary.	
Appalachian Consumer Rate Relief Funding		Appalachian Consumer Rate Relief Funding LLC, a wholly-owned subsidiary of APCo and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to the under-recovered Expanded Net Energy Cost deferral balance.	
APSC		Arkansas Public Service Commission.	
	
ARO		Asset Retirement Obligations.	
	
ASU		Accounting Standards Update.	
CAA		Clean Air Act.	
	
CARES Act		Coronavirus Aid, Relief, and Economic Security Act signed into law in March 2020.	
CCR		Coal Combustion Residual.	
CLECO		Central Louisiana Electric Company, a nonaffiliated utility company.	
CO2	 	Carbon dioxide and other greenhouse gases.	
Conesville Plant		A retired, single unit coal-fired generation plant totaling 651 MW located in Conesville, Ohio. The plant was jointly-owned by AGR and a nonaffiliate.	
i

									
Term		Meaning	
 	 	 	
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.	
CWIP	 	Construction Work in Progress.	
DCC Fuel		DCC Fuel X, DCC Fuel XI, DCC Fuel XII, DCC Fuel XIII, DCC Fuel XIV, DCC Fuel XV and DCC Fuel XVI, 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.	
ELG		Effluent Limitation Guidelines.	
	
Energy Supply		AEP Energy Supply LLC, a nonregulated holding company for AEP’s competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP.	
Equity Units		AEP’s Equity Units issued in August 2020 and March 2019.	
ERCOT	 	Electric Reliability Council of Texas regional transmission organization.	
ESP	 	Electric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO.	
ETT		Electric Transmission Texas, LLC, an equity interest joint venture between AEP Transmission Holdco and Berkshire Hathaway Energy Company formed to own and operate electric transmission facilities in ERCOT.	
Excess ADIT		Excess accumulated deferred income taxes.	
FAC		Fuel Adjustment Clause	
FASB	 	Financial Accounting Standards Board.	
Federal EPA		United States Environmental Protection Agency.	
FERC	 	Federal Energy Regulatory Commission.	
FGD	 	Flue Gas Desulfurization or scrubbers.	
FIP		Federal Implementation Plan.	
FTR	 	Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.	
GAAP	 	Accounting Principles Generally Accepted in the United States of America.	
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.	
KTCo		AEP Kentucky Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.	
KWh		Kilowatt-hour.	
ii

									
Term		Meaning	
 	 	 	
LPSC	 	Louisiana Public Service Commission.	
MATS		Mercury and Air Toxic Standards.	
Maverick		Maverick, part of the North Central Wind Energy Facilities, consists of 287 MWs of wind generation in Oklahoma.	
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.	
NCWF		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.	
	
NOx		Nitrogen oxide.	
	
NSR	 	New Source Review.	
OCC	 	Corporation Commission of the State of Oklahoma.	
	
Oklaunion Power Station		A retired, single unit coal-fired generation plant totaling 650 MW located in Vernon, Texas. The plant was jointly-owned by AEP Texas, PSO and certain nonaffiliated entities.	
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.	
	
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.	
iii

									
Term		Meaning	
 	 	 	
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.	
	
SEC		U.S. 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.	
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.	
Sundance		Sundance, acquired in April 2021 as part of the North Central Wind Energy Facilities, consists of 199 MWs of wind generation in Oklahoma.	
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 VIE formed for the purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation. In July 2020, the final AEP Texas Central Transition Funding II securitization bond matured.	
Transource Energy		Transource Energy, LLC, a consolidated VIE formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates.	
Traverse		Traverse, part of the North Central Wind Energy Facilities, consists of 999 MWs of wind generation in Oklahoma.	
Trent		Trent Wind Farm LLC, a 156 MW wind electricity generation facility located between Abilene and Sweetwater in West Texas in which AEP owns a 100% interest.	
Turk Plant	 	John W. Turk, Jr. Plant, a 650 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.	
Utility Money Pool	 	Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.	
iv

									
Term		Meaning	
 	 	 	
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.	
v

FORWARD-LOOKING INFORMATION

This report made by the Registrants contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.  Many forward-looking statements appear in “Part I – 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, costs of compliance with vaccination or testing mandates to AEP, electricity usage, employees including employee reactions to potential vaccination mandates, customers, service providers, vendors and suppliers.	
•	Inflationary or deflationary interest rate trends.	
•	Volatility in the financial markets, particularly developments affecting the availability or cost of capital to finance new capital projects and refinance existing debt.	
•	The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.	
•	Decreased demand for electricity.	
•	Weather conditions, including storms and drought conditions, and the ability to recover significant storm restoration costs.	
•	The cost of fuel and its transportation, the creditworthiness and performance of fuel suppliers and transporters and the cost of storing and disposing of used fuel, including coal ash and SNF.	
•	The availability of fuel and necessary generation capacity and the performance of generation plants.	
•	The ability to recover fuel and other energy costs through regulated or competitive electric rates.	
•	The ability to build or acquire renewable generation, transmission lines and facilities (including the ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms, including favorable tax treatment, and to recover those costs.	
•	New legislation, litigation and government regulation, including changes to tax laws and regulations, oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or PM and other substances that could impact the continued operation, cost recovery and/or profitability of generation plants and related assets.	
•	Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including coal ash and nuclear fuel.	
•	Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance.	
•	Resolution of litigation.	
•	The ability to constrain operation and maintenance costs.	
•	Prices and demand for power generated and sold at wholesale.	
•	Changes in technology, particularly with respect to energy storage and new, developing, alternative or distributed sources of generation.	
•	The ability to recover through rates any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives.	
•	Volatility and changes in markets for coal and other energy-related commodities, particularly changes in the price of natural gas.	
•	Changes in utility regulation and the allocation of costs within RTOs including ERCOT, PJM and SPP.	
vi

						
•	Changes in the creditworthiness of the counterparties with contractual arrangements, including participants in the energy trading market.	
•	Actions of rating agencies, including changes in the ratings of debt.	
•	The impact of volatility in the capital markets on the value of the investments held by the pension, OPEB, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements.	
•	Accounting standards periodically issued by accounting standard-setting bodies.	
•	Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, naturally occurring and human-caused fires, cyber- security threats and other catastrophic events.	
•	The ability to attract and retain the requisite work force and key personnel.	

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

The Company may use its website as a distribution channel for material company information. Financial and other important information regarding the Company is routinely posted on and accessible through the Company’s website at www.aep.com/investors/. In addition, you may automatically receive email alerts and other information about the Company when you enroll your email address by visiting the “Email Alerts” section at www.aep.com/investors/.
vii

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

EXECUTIVE OVERVIEW

Impacts of Severe Winter Weather

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

Storm Restoration Costs

The impact of the severe winter weather resulted in power outages and extensive damage to transmission and distribution infrastructures across the service territories of APCo, KPCo and SWEPCo. As of September 30, 2021, an estimated $67 million of capital expenditures and $149 million of restoration expenses have been incurred related to the severe winter weather. Approximately $142 million of the expenses represent incremental restoration expenses and have been deferred as regulatory assets. The KPSC and LPSC issued orders authorizing the deferral of incremental restoration expenses as regulatory assets. KPCo intends to seek recovery of these incremental storm restoration costs in their next base rate case while APCo is expected to seek recovery in separate filings. In October 2021, SWEPCo requested recovery of these storm costs, in addition to storm costs from Hurricanes Delta and Laura, in a filing with the LPSC. As part of the filing, SWEPCo requested recovery of the carrying charges on the regulatory asset at a weighted average cost of capital through a rider beginning in January 2022. If any of the restoration costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Impacts in SPP

The severe winter weather also had a significant impact in SPP resulting in the declaration of Energy Emergency Alert Levels 2 and 3 for the first time in SPP’s history. The winter storm increased the demand for natural gas and restricted the available natural gas supply resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system.

Retail Customers

As of September 30, 2021, PSO and SWEPCo have deferred regulatory assets of $673 million and $433 million, respectively, relating to natural gas expenses and purchases of electricity incurred from February 9, 2021, to February 20, 2021, as a result of severe winter weather. SWEPCo’s deferred regulatory asset consists of $107 million, $151 million and $175 million related to the Arkansas, Louisiana and Texas jurisdictions, respectively. PSO and SWEPCo have active fuel clauses that allow for the recovery of prudently incurred fuel and purchased power expenses. Given the significance of these costs, PSO and SWEPCo expect the costs to be subject to prudency reviews. Management believes these costs are probable of future recovery, but expects the recovery period to be extended to mitigate the impact on customer bills.

In March 2021, the APSC issued an order authorizing recovery of the Arkansas jurisdictional share of the retail customer fuel costs over five years, with the appropriate carrying charge to be determined at a later date. Accordingly, in April 2021, SWEPCo began recovery of its Arkansas jurisdictional share of these fuel costs, which are subject to true-up by the APSC. SWEPCo is recovering these fuel costs at an interim carrying charge of 0.8%. Also in April 2021, SWEPCo filed testimony supporting a five-year recovery with a carrying charge of 6.05% which has been supported by APSC staff. Various other parties have recommended recovery periods ranging from 5-20 years with a carrying charge of 1.65%. The APSC ordered more testimony regarding the option of utilizing
1

securitization to recover the fuel costs. SWEPCo is awaiting a decision from the APSC. The prudency of these fuel costs is expected to be addressed in a separate proceeding.

In March 2021, the LPSC approved a special order granting a temporary modification to the FAC that allows SWEPCo to recover the Louisiana jurisdictional share of these retail fuel costs over a longer period than what the FAC traditionally allows. In April 2021, SWEPCo began recovery of its Louisiana jurisdictional share of these fuel costs based on a five year recovery period. SWEPCo is recovering these fuel costs at an interim carrying charge of 3.25%. SWEPCo will work with the LPSC to finalize the actual recovery period and determine the appropriate carrying charge in future proceedings.

In April 2021, the OCC approved a waiver for PSO allowing the deferral of the extraordinary fuel and purchase of electricity costs, including a carrying charge at an interim rate of 0.75%, over a longer time period than what the FAC traditionally allows. Also in April 2021, legislation was enacted in Oklahoma to permit securitization of the extraordinary fuel and purchase of electricity costs impacting the utilities within the state. Under the legislation, the OCC has the authority to determine, after receiving an application from a rate-regulated utility, if the extraordinary fuel and purchase of electricity costs incurred in February 2021 may be mitigated through securitization to reduce the impact on customer bills. PSO has filed an application for a financing order to pursue securitization. The application requests an order on the prudency of the extraordinary fuel and purchase of electricity costs and a carrying charge of the commission authorized weighted average cost of capital until securitization bonds can be issued. In October 2021, OCC staff and intervenors filed testimony supporting securitization of these costs and a carrying charge until costs are securitized ranging from the interim rate of 0.75% to the actual cost of capital used to finance the costs of 2.32%. In addition, OCC staff supported the prudency of PSO's requested costs while one intervenor recommended disallowances of up to $40 million. A procedural schedule has been set with an ALJ report to be filed in January 2022. An order from the OCC is expected in the first quarter of 2022.

In August 2021, SWEPCo filed an application with the PUCT to implement a net interim fuel surcharge for the Texas jurisdictional share of these retail fuel costs. The application supported a five-year recovery at a carrying charge of 7.18%. In October 2021, various intervenors filed testimony supporting a five-year recovery with a carrying charge ranging from 0.082% to 1.625%. A hearing with the PUCT is scheduled for November 2021.

Wholesale Customers

During the first quarter of 2021, SWEPCo billed wholesale customers $104 million resulting from the severe winter weather events. SWEPCo worked with wholesale customers to establish payment terms for the outstanding accounts receivable. As of September 30, 2021, $56 million of accounts receivable from wholesale customers are outstanding. Management believes these receivables are probable of future collection.

PSO and SWEPCo Cash Flow Implications

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

Although the February 2021 severe winter weather did not materially impact AEP’s results of operations for the three and nine months ended September 30, 2021, if either PSO or SWEPCo is unable to recover these fuel and purchased power costs, or obtain authorization of a reasonable carrying charge on these costs, it could reduce future net income and cash flows and impact financial condition.
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COVID-19

In 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 resulted in reduced demand for energy, particularly from commercial and industrial customers. In 2021, weather-normalized customer demand has improved from the pandemic levels experienced in 2020. Management expects continued improvement during the remainder of 2021 as additional vaccinations occur and economic activity improves.

During 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. As of September 30, 2021, AEP’s electric operating companies have resumed customary disconnection practices in all regulated jurisdictions with the exception of residential customers in Virginia. AEP continues to work with regulators and stakeholders in Virginia and management currently anticipates resuming customary disconnection practices once available relief funds are received from the state.

AEP has been and continues to be proactive in engaging with customers to collect payments or establish payment arrangements for outstanding balances. As of September 30, 2021, AEP currently does not expect accounts receivable aging to have a material adverse impact on the Registrants’ allowance for uncollectible accounts based on considerations of the COVID-19 impacts and past trends during times of economic instability. Management continues to monitor developments that could have an impact on customer collections.

The Registrants continue to take steps to mitigate the potential risks to customers, suppliers and employees posed by the spread of COVID-19. As of September 30, 2021, there has been no material adverse impact to the Registrants’ business operations and customer service as a result of the current remote work model. In the second quarter of 2021, management announced a Future of Work model designating employees as: (a) On-Site employees, (b) Hybrid employees and (c) Remote employees. Management began transitioning On-Site employees back to their AEP workplace and Hybrid employees with set schedules back to their AEP workplace in October 2021. Remote employees are scheduled to begin transitioning back to their AEP workplace in November 2021 on an as-needed basis. Management will continue to review and modify plans as conditions change.

In 2021, the Registrants have experienced certain supply chain disruptions driven by several factors including staffing and travel issues caused by the COVID-19 pandemic, increased demand due to the economic recovery from the pandemic, labor shortages in certain trades and shortages in the availability of certain raw materials. These supply chain disruptions have not had a material impact on the Registrants net income, cash flows and financial condition, but have extended lead times for certain goods and services. Management has implemented risk mitigation strategies in an attempt to mitigate the impacts of these supply chain disruptions. However, a prolonged continuation or a future increase in the severity of supply chain disruptions could impact the cost of certain goods and services and extend lead times which could reduce future net income and cash flows and impact financial condition.

Customer Demand

AEP’s weather-normalized retail sales volumes for the third quarter of 2021 increased by 3% from the third quarter of 2020. Weather-normalized residential sales decreased by 1.6% in the third quarter of 2021 from the third quarter of 2020. AEP’s third quarter 2021 industrial sales volumes increased by 7% compared to the third quarter of 2020. The increase in industrial sales was spread across many industries. Weather-normalized commercial sales increased 5% in the third quarter of 2021 from the third quarter of 2020.

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AEP’s weather-normalized retail sales volumes for the nine months ended September 30, 2021 increased by 2.3% compared to the nine months ended September 30, 2020. Weather-normalized residential sales decreased by 0.9% for the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020. AEP’s industrial sales volumes for the nine months ended September 30, 2021 increased 4.2% compared to the nine months ended September 30, 2020. The recovery in industrial sales volumes was spread across many industries. Weather-normalized commercial sales increased 4.3% for the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020.

The current year increase in industrial and commercial sales volumes is primarily driven by a recovery from the COVID-19 pandemic. In 2020, public health restrictions significantly disrupted economic activity and industrial and commercial demand for energy in AEP’s service territory. Similarly, the current year decline in weather-normalized residential sales volumes is driven by the cessation of stay at home restrictions that were in place in 2020 and the gradual return of customers to the workplace.

AEP revised its forecast for 2021 weather-normalized retail sales volumes in September 2021 from the forecast presented in the 2020 10-K. In 2021, AEP currently anticipates weather-normalized retail sales volumes will increase by 2.2%. AEP expects industrial class sales volumes to increase by 4.3% in 2021, while weather-normalized residential sales volumes are projected to decrease by 0.9%. Finally, AEP currently projects weather-normalized commercial sales volumes to increase by 3.7%.

(a)Percentage change for the year ended December 31, 2020 as compared to the year ended December 31, 2019.
(b)As presented in the 2020 AEP 10-K: Forecasted percentage change for the year ending December 31, 2021 compared to the year ended December 31, 2020.
(c)Revised in September 2021: Forecasted percentage change for the year ending December 31, 2021 compared to the year ended December 31, 2020.

Regulatory Matters

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

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•2017-2019 Virginia Triennial Review - In November 2020, the Virginia SCC issued an order on APCo’s 2017-2019 Triennial Review filing concluding that APCo earned above its authorized ROE but within its ROE band for the 2017-2019 period, resulting in no refund to customers and no change to APCo base rates on a prospective basis. The Virginia SCC approved a prospective 9.2% ROE for APCo's 2020-2022 triennial review period with the continuation of a 140 basis point band (8.5% bottom, 9.2% midpoint, 9.9% top).

In December 2020, an intervenor filed a petition at the Virginia SCC requesting reconsideration of: (a) the failure of the Virginia SCC to apply a threshold earnings test to the approved regulatory asset for APCo’s closed coal-fired generation assets, (b) the Virginia SCC’s use of a 2011 benchmark study to measure the replacement value of capacity for purposes of APCo’s 2017 – 2019 earnings test and (c) the reasonableness and prudency of APCo’s investments in AMI meters.

In December 2020, APCo filed a petition at the Virginia SCC requesting reconsideration of: (a) certain issues related to APCo’s going-forward rates and (b) the Virginia SCC’s decision to deny APCo tariff changes that align rates with underlying costs. For APCo’s going-forward rates, APCo requested that the Virginia SCC clarify its final order and clarify whether APCo’s current rates will allow it to earn a fair return. If the Virginia SCC’s order did conclude on APCo’s ability to earn a fair return through existing base rates, APCo further requested that the Virginia SCC clarify whether it has the authority to also permit an increase in base rates.

In March 2021, the Virginia SCC issued an order confirming certain of its decisions from the November 2020 order and rejecting the various requests for reconsideration from APCo and an intervenor. In confirming its decision to reject an intervenor’s recommendation that APCo’s AMI costs incurred during the triennial period be disallowed, the Virginia SCC clarified that APCo established the need to replace its existing AMR meters, and that based on the uncertainty surrounding the continued manufacturing and support of AMR technology, APCo reasonably chose to replace them with AMI meters. In March 2021, APCo filed a notice of appeal of the reconsideration order with the Virginia Supreme Court. In September 2021, APCo submitted its brief before the Virginia Supreme Court. The brief was in alignment with the assignments of error filed by APCo in March 2021. In October 2021, the Virginia SCC and certain intervenors filed briefs with the Virginia Supreme Court disagreeing with APCo’s assignments of error in its appeal of the Triennial Review decision. Additionally, the Virginia SCC and APCo filed briefs disagreeing with an intervenor’ s assignments of error in a separate appeal of the same decision.

APCo ultimately seeks an increase in base rates through its appeal to the Virginia Supreme Court. Among other issues, this appeal includes APCo’s request for proper treatment of the closed coal-fired plant assets in APCo’s 2017-2019 triennial period, reducing APCo’s earnings below the bottom of its authorized ROE band. If APCo’s appeals regarding treatment of the closed coal plants are granted by the Virginia Supreme Court, it could initially reduce future net income and impact financial condition. The initial negative impact for the write-off of closed coal-fired plant asset balances would potentially be partially offset by an increase in base rates for earning below APCo’s 2017-2019 authorized ROE band.

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

•Hurricane Laura - In August 2020, Hurricane Laura hit the coasts of Louisiana and Texas, causing power outages to more than 130,000 customers across SWEPCo’s service territories. Prior to Hurricane Laura, SWEPCo did not have a catastrophe reserve or automatic deferral authority within any of its jurisdictions. In October 2020, the LPSC issued an order allowing Louisiana utilities, including SWEPCo, to establish a regulatory asset to track and defer expenses associated with Hurricane Laura. In October 2020, as part of the 2020 Texas Base Rate Case, SWEPCo requested deferral authority of incremental other operation and maintenance expenses. As of September 30, 2021, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $92 million ($89 million of which has been deferred as a regulatory asset related to the Louisiana jurisdiction) and incremental capital expenditures of $18 million, all of which is related to the Louisiana jurisdiction. In October 2021, SWEPCo requested recovery of these storm costs, in addition to SWEPCo’s various other storm costs, in a filing with the LPSC.

•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. 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. In 2017, the Texas District Court upheld the PUCT’s 2014 order and intervenors filed appeals with the Texas Third Court of Appeals. In July 2018, the Texas Third Court of Appeals reversed the PUCT’s judgment affirming the prudence of the Turk Plant and remanded the issue back to the PUCT. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court.

In March 2021, the Texas Supreme Court issued an opinion reversing the July 2018 judgment of the Texas Third Court of Appeals and agreeing with the PUCT’s judgment affirming the prudence of the Turk Plant. In addition, the Texas Supreme Court remanded the AFUDC dispute back to the Texas Third Court of Appeals. In August 2021, the Texas Third Court of Appeals reversed the Texas District Court judgement affirming the PUCT’s order on AFUDC, concluding that the language of the PUCT’s original 2008 order intended to include AFUDC in the Texas jurisdictional capital cost cap, and remanded the case to the PUCT for future proceedings. SWEPCo disagrees with the Court of Appeals decision and expects to submit a Petition for Review with the Texas Supreme Court in November 2021.

If SWEPCo is ultimately unable to recover capitalized Turk Plant costs including AFUDC in excess of the Texas jurisdictional capital cost cap it would result in a pretax net disallowance ranging from $80 million to $100 million. In addition, if AFUDC is ultimately determined to be included in the Texas jurisdictional capital cost cap, SWEPCo estimates it may be required to make customer refunds ranging from $0 to $160 million related to revenues collected from February 2013 through September 2021 and such determination may reduce SWEPCo’s future revenues by approximately $15 million on an annual basis.

•In July 2019, Ohio House Bill 6 (HB 6), which offered incentives for power-generating facilities with zero or reduced carbon emissions, was signed into law by the Ohio Governor.  HB 6 phased out current energy efficiency programs as of December 31, 2020, including OPCo’s shared savings revenues of $26 million annually and renewable mandates after 2026. HB 6 also provided for the recovery of existing renewable energy contracts on a bypassable basis through 2032 and included a provision for recovery of OVEC costs through 2030 which will be allocated to all electric distribution utilities on a non-bypassable basis.  OPCo’s Inter-Company Power Agreement for OVEC terminates in June 2040. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of the Speaker of the Ohio House of Representatives, Larry Householder, four other individuals, and Generation Now, an entity registered as a 501(c)(4) social welfare organization, in connection with an alleged racketeering conspiracy involving the adoption of HB 6. Certain defendants in that case have since pleaded guilty. In August 2020, an AEP
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shareholder filed a putative class action lawsuit against AEP and certain of its officers for alleged violations of securities laws in connection with HB 6. On May 10, 2021, the defendants filed a motion to dismiss the securities litigation for failure to state a claim, which was fully briefed on July 26, 2021. Oral arguments on the motion to dismiss is scheduled for November 23, 2021. In addition, four AEP shareholders have filed derivative actions purporting to assert claims on behalf of AEP against certain AEP officers and directors, all of which are currently stayed. See Litigation Related to Ohio House Bill 6 section of Litigation below for additional information.

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

•In December 2020, APCo and WPCo filed a proposal with the WVPSC to implement an investment tracker surcharge mechanism for recovering costs associated with capital investment made between base rate cases. The initial filing requested a total annual increase of $50 million ($41 million related to APCo), which represents recovery of costs associated with infrastructure investments made over an approximate three-year period since the companies’ last base rate case filing in 2018. The filing also proposed that APCo and WPCo could submit annual filings with requested increases capped to a percentage of total retail revenues (3.5% in the first year and 3% in subsequent filings with an overall cap of 9.5%).

In June 2021, the WVPSC issued an order approving the investment tracker mechanism with an initial annual revenue requirement of $44 million ($36 million related to APCo) effective September 2021 based on a 9.25% ROE. The order also allows APCo and WPCo to request future year investment tracker increases for assets placed in service during the most recent 12-month period ending September 30th, subject to an annual three percent rider increase cap on base year total retail revenues. Under the conditions of the order and with certain exceptions as outlined by the WVPSC, APCo and WPCo are prohibited from filing a base rate case before June 30, 2024.

•In April 2021, the FERC issued a supplemental Notice of Proposed Rulemaking (NOPR) proposing to modify its incentive for transmission owners that join RTOs (RTO Incentive). Under the supplemental NOPR, the RTO Incentive would be modified such that a utility would only be eligible for the RTO Incentive for the first three years after the utility joins a FERC-approved Transmission Organization. This is a significant departure from a previous NOPR issued in 2020 seeking to increase the RTO Incentive from 50 basis points to 100 basis points. The supplemental NOPR also required utilities that have received the RTO Incentive for three or more years to submit, within 30 days of the effective date of a final rule, a compliance filing to eliminate the incentive from its tariff prospectively. The supplemental NOPR was subject to a 60 day comment period followed by a 30 day period for reply comments. In July 2021, AEP submitted reply comments. A final rule could be issued in the fourth quarter of 2021.

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

In July 2021, the FERC issued an order denying Dayton Power and Light’s request for a 50 basis point RTO incentive on the basis that its RTO participation was not voluntary, but rather is required by Ohio law.
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This precedent could have an impact on AEP’s transmission owning subsidiaries whose RTO membership is not voluntary, including OPCo and AEP Ohio Transmission Company.

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

Utility Rates and Rate Proceedings

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

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

Completed Base Rate Case Proceedings

				Approved Revenue			Approved		New Rates	
Company		Jurisdiction		Requirement Increase			ROE		Effective	
				(in millions)						
KPCo		Kentucky		$	52.7 		(a)		9.3%		January 2021	

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

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Pending Base Rate Case Proceedings

											Commission Staff/	
				Filing		Requested Revenue			Requested		Intervenor Range of	
Company		Jurisdiction		Date		Requirement Increase			ROE		Recommended ROE	
						(in millions)							
OPCo		Ohio		June 2020		$	42.3 				10.15%		8.76%-9.78%	(a)	
SWEPCo		Texas		October 2020		100.4 		(b)		10.35%		9%-9.22%	(c)	
SWEPCo		Louisiana		December 2020		94.7 				10.35%		9.1%-9.8%	(d)	
PSO		Oklahoma		April 2021		127.5 				10%		9%-9.4%	(e)	
I&M		Indiana		July 2021		104.0 		(f)		10%		9.1%-9.3%	(g)	
SWEPCo		Arkansas		July 2021		85.0 				10.35%		(h)		

(a)In March, 2021 a joint stipulation and settlement agreement was filed with the PUCO which included a $68 million decrease in base rates based upon a ROE of 9.7%.
(b)The request would move transmission and distribution interim revenues recovered through riders into base rates. Eliminating these riders would result in a net annual requested base rate increase of $85 million primarily due to increased investments.
(c)An ALJ proposed a base rate increase of $41 million based upon a ROE of 9.45%.
(d)LPSC staff recommended a base rate increase of $6 million.
(e)In September 2021, a contested joint stipulation and settlement agreement was filed with the OCC which included a $51 million increase in base rates based upon a ROE of 9.4%.
(f)Proposed to be phased-in with a $73 million annual increase effective May 2022 and the remaining $31 million annual increase effective January 2023.
(g)Intervenors proposed a decrease in base rates ranging from $13 million to $68 million.
(h)Intervenor testimony is expected in December 2021.

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.

As of September 30, 2021, subsidiaries within AEP’s Generation & Marketing segment had approximately 1,633 MWs of contracted renewable generation projects in-service.  In addition, as of September 30, 2021, these subsidiaries had approximately 155 MWs of renewable generation projects under construction with total estimated capital costs of $221 million related to these projects.

Regulated Renewable Generation Facilities

In 2020, PSO received approval from the OCC and SWEPCo received approval from the APSC and LPSC to acquire the NCWF, comprised of three Oklahoma wind facilities totaling 1,485 MWs, on a fixed cost turn-key basis at completion. Both the APSC and LPSC approved the flex-up option, agreeing to acquire the Texas portion, which the PUCT denied. PSO will own 45.5% and SWEPCo will own 54.5% of the project, which will cost approximately $2 billion.
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In June 2021, the IRS issued a notice extending the “Continuity Safe Harbor” deadlines for qualifying renewable energy projects. Under the June 2021 IRS notice, the Continuity Safe Harbor for qualifying renewable energy projects that began construction in calendar years 2016 through 2019 is extended to six years. Additionally, the Continuity Safe Harbor is extended to five years for qualifying projects that began construction in calendar year 2020. Provided that each facility does satisfy the Continuity Safe Harbor, under the current IRS guidance, the Sundance wind facility will qualify for 100% of the federal PTC, and the Maverick and Traverse wind facilities will qualify for 80% of the federal PTC.

In April 2021, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Sundance during its development and construction for $270 million, the first of the three NCWF acquisitions. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Sundance assets in proportion to their undivided ownership interests. Sundance was placed in-service in April 2021. In September 2021, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Maverick during its development and construction for $383 million, the second of the three NCWF acquisitions. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Maverick assets in proportion to their undivided ownership interests. Maverick was placed in-service in September 2021. As of September 30, 2021, PSO and SWEPCo had approximately $314 million and $376 million, of Property, Plant and Equipment on the balance sheets, respectively, related to the Sundance and Maverick NCWF projects. The Traverse wind facility is targeted to be acquired and placed in-service between January and April 2022. See Note 6 - Acquisitions for additional information.

In June 2021, SWEPCo issued requests for proposals to acquire up to 3,000 MWs of wind and 300 MWs of solar generation resources. The wind and solar generation projects would be subject to regulatory approval.

In September 2021, PSO issued draft requests for proposals to acquire up to 2,600 MWs of wind and 1,350 MWs of solar generation resources. The wind and solar generation projects would be subject to regulatory approval.

Disposition of KPCo and AEP Kentucky Transmission Company, Inc. (KTCo)

In October 2021, AEP entered into a Stock Purchase Agreement to sell KPCo and KTCo to Liberty Utilities Co., a subsidiary of Oakville, Ontario, Canada based Algonquin Power & Utilities Corp. (Liberty), for approximately a $2.85 billion enterprise value. The sale is subject to regulatory approvals from the FERC, the KPSC, clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, and clearance from the Committee on Foreign Investment in the United States.

KPCo currently operates and owns a 50% interest in the 1,560 MW coal-fired Mitchell Power Plant (Mitchell Plant) with the remaining 50% owned by WPCo. The Stock Purchase Agreement is further contingent upon approval by the KPSC, WVPSC and FERC of a new proposed Mitchell Plant Operations and Maintenance Agreement and Mitchell Plant Ownership Agreement between KPCo and WPCo pursuant to which WPCo will replace KPCo as the operator of the Mitchell Plant and KPCo employees at the Mitchell Plant will become employees of WPCo at closing of the transaction. Under the proposed Ownership Agreement, WPCo is obligated to purchase KPCo’s 50% interest in the Mitchell Plant on December 31, 2028 unless KPCo and WPCo have agreed to retire the Mitchell Plant earlier or, absent such agreement, if WPCo elects prior to December 31, 2027 to retire the Mitchell Plant on December 31, 2028. The Ownership Agreement provides that the purchase price for KPCo’s 50% ownership interest in the Mitchell Plant will be determined through the mutual agreement of WPCo and KPCo (subject to approval from the KPSC and WVPSC) or through a fair market valuation determination conducted by independent appraisals if KPCo and WPCo are unable to reach agreement as to the purchase price.

The sale is expected to close in the second quarter of 2022 with Liberty acquiring the assets and assuming the liabilities of KPCo and KTCo, excluding pension and other post-retirement benefit plan assets and liabilities. AEP expects to provide customary transition services to Liberty for a period of time after closing of the transaction.

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AEP expects to receive approximately $1.45 billion in cash, net of taxes and transaction fees. AEP plans to use the proceeds to eliminate forecasted equity needs in 2022 as the company invests in regulated renewables, transmission and other projects. AEP expects the sale to have a one-time, immaterial impact on after-tax earnings.

Racine

In February 2021, AEP signed an agreement to sell Racine to a nonaffiliated party. As of September 30, 2021, the net book value of Racine was $45 million. The sale of Racine was approved by the U.S. Army Corps of Engineers in the third quarter of 2021. The sale also requires approval from the FERC. The sale is expected to close in the fourth quarter of 2021 and result in an immaterial gain. Racine was not presented as Held for Sale on AEP’s balance sheets due to immateriality.

Dolet Hills Power Station and Related Fuel Operations

DHLC provides 100% of the fuel supply to Dolet Hills Power Station. During the second quarter of 2019, the Dolet Hills Power Station initiated a seasonal operating schedule. In 2020, management of SWEPCo and CLECO determined DHLC would not proceed developing additional Oxbow Lignite Company (Oxbow) mining areas for future lignite extraction and ceased extraction of lignite at the mine in May 2020. 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 ceased in October 2021. In addition, 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 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 non-fuel costs are recoverable by SWEPCo through base rates. As of September 30, 2021, SWEPCo’s share of the net investment in the Dolet Hills Power Station is $146 million, including CWIP and materials and supplies, before cost of removal.

Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses. Under the fuel agreements, SWEPCo’s fuel inventory and unbilled fuel costs from mining related activities were $44 million as of September 30, 2021. Also, as of September 30, 2021, SWEPCo had a net under-recovered fuel balance of $39 million, excluding impacts of the February 2021 severe winter weather event, which includes fuel consumed at the Dolet Hills Power Station. Additional operational, reclamation and other land-related costs incurred by DHLC and Oxbow will be billed to SWEPCo and included in future fuel clauses.

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

In March 2021, the LPSC issued an order allowing SWEPCo to recover up to $20 million of fuel costs in 2021 and defer approximately $30 million of additional costs with a recovery period to be determined at a later date.

In March 2021, the APSC approved fuel rates that provide recovery of the Arkansas share of the 2021 Dolet Hills Power Station fuel costs over five years through the existing fuel clause.

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

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Pirkey Power Plant and Related Fuel Operations

In 2020, management announced plans to retire the Pirkey Power Plant in 2023. The Pirkey Power Plant non-fuel costs are recoverable by SWEPCo through base rates and fuel costs are recovered through active fuel clauses. As of September 30, 2021, SWEPCo’s share of the net investment in the Pirkey Power Plant is $203 million, including CWIP, before cost of removal. Sabine is a mining operator providing mining services to the Pirkey Power Plant. Under the provisions of the mining agreement, SWEPCo is required to pay, as part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. SWEPCo expects fuel deliveries, including billings of all fixed and operating costs, from Sabine to cease during the first quarter of 2023. Under the fuel agreements, SWEPCo’s fuel inventory and unbilled fuel costs from mining related activities were $108 million as of September 30, 2021. Also, as of September 30, 2021, SWEPCo had a net under-recovered fuel balance of $39 million, excluding impacts of the February 2021 severe winter weather event, which includes fuel consumed at the Pirkey Power Plant. Additional operational, reclamation and other land-related costs incurred by Sabine will be billed to SWEPCo and included in future fuel clauses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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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 suit 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 sought a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. See “Obligations under the New Source Review Litigation Consent Decree” section below for additional information.

After the litigation proceeded at the District Court and Circuit Court levels, on April 20, 2021, I&M and AEGCo reached an agreement to acquire 100% of the interests in Rockport Plant, Unit 2 for $115.5 million from certain financial institutions that own the unit through trusts established by Wilmington Trust, the nonaffiliated owner trustee of the ownership interests in the unit, with closing to occur as of the end of the Rockport Plant, Unit 2 lease in December 2022. The agreement is subject to customary closing conditions, including regulatory approvals and as of the closing will result in a final settlement of, and release of claims in, the lease litigation. As a result, in May 2021, at the parties’ request, the district court entered a stipulation and order dismissing the case without prejudice to plaintiffs asserting their claims in a re-filed action or a new action. Management believes its financial statements appropriately reflect the resolution of the litigation.

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

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

Litigation Related to Ohio House Bill 6 (HB 6)

In 2019, Ohio adopted and implemented HB 6 which benefits OPCo by authorizing rate recovery for certain costs including renewable energy contracts and OVEC’s coal-fired generating units. OPCo engaged in lobbying efforts and provided testimony during the legislative process in connection with HB 6. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of an Ohio legislator and associates in connection with an alleged racketeering conspiracy involving the adoption of HB 6. After AEP learned of the criminal allegations against the Ohio legislator and others relating to HB 6, the Company, with assistance from
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outside advisors, conducted a review of the circumstances surrounding the passage of the bill. We do not believe that AEP was involved in any wrongful conduct in connection with the passage of HB 6.

In August 2020, an AEP shareholder filed a putative class action lawsuit in the United States District Court for the Southern District of Ohio against AEP and certain of its officers for alleged violations of securities laws. The amended complaint alleges misrepresentations or omissions by AEP regarding: (a) its alleged participation in or connection to public corruption with respect to the passage of HB 6 and (b) its regulatory, legislative, political contribution, 501(c)(4) organization contribution and lobbying activities in Ohio. The complaint seeks monetary damages, among other forms of relief. On May 10, 2021, the defendants filed a motion to dismiss the securities litigation for failure to state a claim and the motion was fully briefed as of July 26, 2021. The Court has scheduled oral argument for November 23, 2021 on the motion to dismiss. The company will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

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

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

In May 2021, AEP received a subpoena from the SEC’s Division of Enforcement seeking various documents, including documents relating to the benefits to AEP from the passage of HB 6 and documents relating to AEP’s financial processes and controls. AEP is cooperating fully with the SEC’s subpoena. Although the outcome of the SEC’s investigation cannot be predicted, management does not believe the results of this inquiry will have a material impact on our financial condition, results of operations, or cash flows.

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.  Management is engaged in the development of possible future requirements including the items discussed
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below.  Management believes that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.

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

Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed below will have a material impact on AEP System generating units.  Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of September 30, 2021, the AEP System owned generating capacity of approximately 25,000 MWs, of which approximately 12,100 MWs were coal-fired.  Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on fossil generation. Based upon management estimates, AEP’s future investment to meet these existing and proposed requirements ranges from approximately $350 million to $700 million through 2027.

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

Obligations under the New Source Review Litigation Consent Decree

In 2007, the U.S. District Court for the Southern District of Ohio approved a consent decree between AEP subsidiaries in the eastern area of the AEP System and the Department of Justice, the Federal EPA, eight northeastern states and other interested parties to settle claims that the AEP subsidiaries violated the NSR provisions of the CAA when they undertook various equipment repair and replacement projects over a period of nearly 20 years.  The consent decree’s terms include installation of environmental control equipment on certain generating units, a declining cap on SO2 and NOX emissions from the AEP System and various mitigation projects. The consent decree has been modified six times, for various reasons, most recently in 2020. All of the environmental control equipment required by the consent decree has been installed.

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 periodically reviews and revises the NAAQS for criteria pollutants under the CAA. Revisions tend to increase the stringency of the standards, which in turn may require AEP to make investments in pollution control equipment at existing generating units, or, since most units are already well controlled, to make changes in how units are dispatched and operated. Most recently, the Biden administration has indicated that it is likely to
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revisit the NAAQS for ozone and PM, which were left unchanged by the prior administration following its review. Management cannot currently predict if any changes to either standard are likely or what such changes may be, but will continue to monitor this issue and any future rulemakings.

Regional Haze

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

Arkansas has an approved regional haze SIP and all of SWEPCo's affected units are in compliance with the relevant requirements.

In Texas, the Federal EPA disapproved portions of the Texas regional haze SIP and 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. Legal challenges to these various rulemakings are pending in both the U.S. Court of Appeals for the Fifth Circuit and the U.S. Court of Appeals for the District of Columbia Circuit. Management cannot predict the outcome of that litigation, although management supports the intrastate trading program as a compliance alternative to source-specific controls and has intervened in the litigation in support of the Federal EPA.

Cross-State Air Pollution Rule

CSAPR is a regional trading program designed to address interstate transport of emissions that contributed significantly to downwind non-attainment with the 1997 ozone and PM NAAQS.  CSAPR relies on SO2 and 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.

In January 2021, the Federal EPA finalized a revised CSAPR rule, which substantially reduces the ozone season NOX budgets in 2021-2024. Management believes it can meet the requirements of the rule in the near term, and is evaluating its compliance options for later years, when the budgets are further reduced.

Climate Change, CO2 Regulation and Energy Policy

In 2019, the Affordable Clean Energy (ACE) rule established a framework for states to adopt standards of performance for utility boilers based on heat rate improvements for such boilers. However, in January 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the ACE rule and remanded it to the Federal EPA. Management is unable to predict how the Federal EPA will respond to the court’s remand.

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

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

In February 2021, AEP announced new intermediate and long-term CO2 emission reduction goals, based on the output of the company’s integrated resource plans, which take into account economics, customer demand, grid reliability and resiliency, regulations and the company’s current business strategy. The intermediate goal is an 80% reduction from 2000 CO2 emission levels from AEP generating facilities by 2030; the long-term goal is net-zero CO2 emissions from AEP generating facilities by 2050. AEP’s total estimated CO2 emissions in 2020 were approximately 44 million metric tons, a 73% reduction from AEP’s 2000 CO2 emissions. AEP has made significant progress in reducing CO2 emissions from its power generation fleet and expects its emissions to continue to decline. Technological advances, including energy storage, will determine how quickly AEP can achieve zero emissions while continuing to provide reliable, affordable power for customers.

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

Coal Combustion Residual Rule

The Federal EPA’s CCR rule regulates the disposal and beneficial re-use of CCR, including fly ash and bottom ash created from coal-fired generating units and FGD gypsum generated at some coal-fired plants.  The rule applies to active and inactive CCR landfills and surface impoundments at facilities of active electric utility or independent power producers.

In August 2020, the Federal EPA revised the CCR rule to include a requirement that unlined CCR storage ponds cease operations and initiate closure by April 11, 2021. The revised rule provides two options that allow facilities to extend the date by which they must cease receipt of coal ash and close the ponds.

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

Company		Plant Name and Unit		Generating
Capacity		Net Book Value (a)		Projected
 Retirement Date	
				(in MWs)		(in millions)			
AEGCo		Rockport Plant, Unit 1		655		$	232.0 			2028	
APCo		Amos		2,930		2,111.7 			2040	
APCo		Mountaineer		1,320		962.3 			2040	
I&M		Rockport Plant, Unit 1		655		525.1 		(b)	2028	
KPCo		Mitchell Plant		780		586.5 			2040	
SWEPCo		Flint Creek Plant		258		269.2 			2038	
WPCo		Mitchell Plant		780		588.9 			2040	

(a)Net book value before cost of removal including CWIP and inventory.
(b)Amount includes a $176 million regulatory asset related to the retired Tanners Creek Plant. The IURC and MPSC authorized recovery of the Tanners Creek Plant regulatory asset over the useful life of Rockport Plant, Unit 1 in 2015 and 2014, respectively.

In addition, AGR owns Cardinal Plant, Unit 1 a competitive generation unit. A nonaffiliate owns Cardinal Plant, Unit 2 and Unit 3 and operates all three units at the Cardinal Plant. The nonaffiliate filed an application for additional time to develop alternative disposal capacity for the Cardinal Plant. As of September 30, 2021, the net book value of Cardinal Plant, Unit 1, including materials and supplies and CWIP, was approximately $43 million.

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The second option is a retirement option, which provides a generating facility an extended operating time without developing alternative CCR disposal. Under the retirement option, a generating facility would have until October 17, 2023 to cease operation and to close CCR storage ponds 40 acres or less in size, or through October 17, 2028 for facilities with CCR storage ponds greater than 40 acres in size. Pursuant to this option, AEP informed the Federal EPA of its intent to retire the Pirkey Power Plant and cease using coal at the Welsh Plant:
																																	
Company		Plant Name and Unit		Generating
Capacity		Net Investment (a)		Accelerated Depreciation Regulatory Asset		Projected
 Retirement Date	
				(in MWs)		(in millions)			
SWEPCo		Pirkey Power Plant		580		$	135.4 			$	68.0 			2023 (b)	
SWEPCo		Welsh Plants, Units 1 and 3		1,053		493.7 			35.6 			2028 (c)(d)	

(a)Net book value including CWIP excluding cost of removal and materials and supplies.
(b)Pirkey Power Plant is currently being recovered through 2025 in the Louisiana jurisdiction and through 2045 in the Arkansas and Texas jurisdictions.
(c)In November 2020, management announced it will cease using coal at the Welsh Plant in 2028.
(d)Unit 1 is currently being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Unit 3 is currently being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.

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

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

If removal of ash is required without providing similar assurances of cost recovery in regulated jurisdictions, it would impose significant additional operating costs on AEP, which could lead to increased financing costs and liquidity needs. Other units in Virginia, Ohio, West Virginia and Kentucky have already been closed in place in 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

The Federal EPA’s ELG rule for generating facilities establishes limits on FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater, which are to be implemented through each facility’s wastewater discharge permit. A recent revision to the ELG rule, published in October 2020, establishes additional options for reusing and discharging small volumes of bottom ash transport water, provides an exception for retiring units and extends the compliance deadline to a date as soon as possible beginning one year after the rule was published but no later than December 2025. Management has assessed technology additions and retrofits to comply with the rule and the impacts of the Federal EPA’s recent actions on facilities’ wastewater discharge permitting for FGD wastewater and bottom ash transport water. Permit modifications for affected facilities were filed in January 2021 that reflect the outcome of that assessment. We continue to work with state agencies to finalize permit terms and conditions.

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In August 2021, the Federal EPA and the Army Corps of Engineers announced their plan to reconsider and revise the Navigable Waters Protection Rule, which defines “waters of the United States” under the Clean Water Act. Shortly thereafter, the United States District Court for the District of Arizona vacated and remanded the Navigable Waters Protection Rule, which had the effect of reinstating the prior, much broader, version of the rule. Because the scope of waters subject to Federal EPA and Army Corps of Engineers jurisdictions is broader under the prior rule, permitting decisions made in recent years are subject to reevaluation; permits may now be necessary where none were previously required, and issued permits may need to be reopened to impose additional obligations. Management will continue to monitor rulemaking on this issue.

CCR and ELG Compliance Plan Filings

Mitchell Plant (Applies to AEP)

KPCo and WPCo each own a 50% interest in the Mitchell Plant. In December 2020 and February 2021, WPCo and KPCo filed requests with the WVPSC and KPSC, respectively, to obtain the regulatory approvals necessary to implement CCR and ELG compliance plans and seek recovery of the estimated $132 million investment for the Mitchell Plant that would allow the plant to continue operating beyond 2028. Within those requests, WPCo and KPCo also filed a $25 million alternative to implement only the CCR-related investments with the WVPSC and KPSC, respectively, which would allow the Mitchell Plant to continue operating only through 2028.

In July 2021, the KPSC issued an order approving the CCR only alternative and rejecting the full CCR and ELG compliance plan. In August 2021, the WVPSC approved the full CCR and ELG compliance plan for the WPCo share of the Mitchell Plant. In September 2021, WPCo submitted a filing with the WVPSC to reopen the CCR/ELG case that was approved by the WVPSC in August 2021. Due to the rejection by the KPSC of the KPCo share of the ELG investments, WPCo requested the WVPSC consider approving the construction and recovery of all ELG costs at the plant. In October 2021, the WVPSC affirmed its August 2021 order approving the construction of CCR/ELG investments and directed WPCo to proceed with CCR/ELG compliance plans that would allow the plant to continue operating beyond 2028. The WVPSC’s order further states WPCo will not share capacity and energy from the plant with KPCo customers if those customers are not paying for ELG compliance costs, or for any new capital investment or continuing operations costs incurred, to allow the plant to operate beyond 2028 or prevent downgrades prior to 2028. The WVPSC also ordered that WPCo will be given the opportunity to recover, from its customers, the new capital and operating costs arising solely from the WVPSC's directive to operate the plant beyond 2028 if the WVPSC finds that the costs are reasonably and prudently incurred. In October 2021, an intervenor filed a petition for reconsideration at the WVPSC requesting clarification on certain aspects of the order, primarily the jurisdictional allocation of future operating expenses and plant costs.

As of September 30, 2021, the Mitchell Plant ELG investment balance in CWIP was $3 million split equally between KPCo and WPCo. As of September 30, 2021, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $587 million.

If any of the ELG costs are not approved for recovery and/or the retirement date of the Mitchell Plant is accelerated to 2028 without commensurate cost recovery, it would reduce future net income and cash flows and impact financial condition.

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Amos and Mountaineer Plants (Applies to AEP and APCo)

In December 2020, APCo submitted filings with the Virginia SCC and WVPSC requesting regulatory approvals necessary to implement CCR and ELG compliance plans and seek recovery of the estimated $240 million investment for the Amos and Mountaineer plants. Intervenors in Virginia and West Virginia recommended that only the CCR-related investments be constructed at Amos and Mountaineer and, as a consequence, that APCo close these generating facilities at the end of 2028.

In August 2021, the Virginia SCC issued an order approving APCo’s request to construct CCR-related investments at the Amos and Mountaineer Plants and approved recovery of CCR-related other operation and maintenance expenses and investments through an active rider. The order denied APCo’s request to construct the ELG investments and denied recovery of previously incurred ELG costs. APCo may refile for approval of the ELG investments and previously incurred ELG costs at a later date.

Also in August 2021, the WVPSC approved the request to construct CCR/ELG investments at the Amos and Mountaineer Plants and approved recovery of the West Virginia jurisdictional share of these costs through an active rider. In September 2021, APCo submitted a filing with the WVPSC to reopen the CCR/ELG case that was approved by the WVPSC in August 2021. Due to the initial rejection by the Virginia SCC of the Virginia jurisdictional share of the ELG investments, APCo requested the WVPSC consider approving the construction and recovery of all ELG costs at the plants. In October 2021, the WVPSC affirmed its August 2021 order approving the construction of CCR/ELG investments and directed APCo to proceed with CCR/ELG compliance plans that would allow the plants to continue operating beyond 2028. The WVPSC’s order further states that APCo will not share capacity and energy from the plants with customers from Virginia if those customers are not paying for ELG compliance costs, or for any new capital investment or continuing operations costs incurred, to allow the plants to operate beyond 2028 or prevent downgrades prior to 2028. The WVPSC also ordered that APCo will be given the opportunity to recover, from West Virginia customers, the new capital and operating costs arising solely from the WVPSC's directive to operate the plants beyond 2028 if the WVPSC finds that the costs are reasonably and prudently incurred. In October 2021, an intervenor filed a petition for reconsideration at the WVPSC requesting clarification on certain aspects of the order, primarily the jurisdictional allocation of future operating expenses and plant costs.

APCo expects total Amos and Mountaineer Plant ELG investment, including AFUDC, to be approximately $177 million. As of September 30, 2021, APCo’s Virginia jurisdictional share of the net book value, before cost of removal including CWIP and inventory, of the Amos and Mountaineer Plants was approximately $1.5 billion and APCo’s Virginia jurisdictional share of its ELG investment balance in CWIP for these plants was $19 million.

If any of the ELG costs are not approved for recovery and/or the retirement dates of the Amos and Mountaineer plants are accelerated to 2028 without commensurate cost recovery, it would reduce future net income and cash flows and impact financial condition.

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Impact of Environmental Regulation on Coal-Fired Generation

Compliance with extensive environmental regulations requires significant capital investment in environmental monitoring, installation of pollution control equipment, emission fees, disposal costs and permits. Management continuously evaluates cost estimates of complying with these regulations which may result in a decision to retire coal-fired generating facilities earlier than their currently estimated useful lives.

Previously, management retired or announced early closure plans for Welsh Unit 2, Oklaunion Power Station, Dolet Hills Power Station and Northeastern Plant Unit 3.

The table below summarizes the net book value, as of September 30, 2021, of generating facilities retired or planned for early retirement:
																																							
Company		Plant		Net
Investment (a)		Accelerated Depreciation Regulatory Asset		Actual/Projected
Retirement
Date		Current Authorized
Recovery
Period		Annual Depreciation (b)	
				(in millions)					(in millions)	
PSO		Northeastern Plant, Unit 3		$	175.1 			$	123.6 			2026		(c)		$	14.9 		
PSO		Oklaunion Power Station		— 			33.0 			2020		(d)		2.0 		
SWEPCo		Dolet Hills Power Station		13.0 			126.8 			2021		(e)		7.7 		
SWEPCo		Pirkey Power Plant		135.4 			68.0 			2023		(f)		13.4 		
SWEPCo		Welsh Plant, Units 1 and 3		493.7 			35.6 			2028 (g)		(h)		32.9 		
SWEPCo		Welsh Plant, Unit 2		— 			35.2 			2016		(i)		— 		

(a)Net book value including CWIP excluding cost of removal and materials and supplies.
(b)These amounts represent the amount of annual depreciation that has been collected from customers over the prior 12-month period.
(c)Northeastern Plant, Unit 3 is currently being recovered through 2040.
(d)Oklaunion Power Station is currently being recovered through 2046.
(e)Dolet Hills Power Station is currently being recovered through 2026 in the Louisiana jurisdiction and through 2046 in the Arkansas and Texas jurisdictions.
(f)Pirkey Power Plant is currently being recovered through 2025 in the Louisiana jurisdiction and through 2045 in the Arkansas and Texas jurisdictions.
(g)In November 2020, management announced it will cease using coal at the Welsh Plant in 2028.
(h)Welsh Plant, Unit 1 is being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Welsh Plant, Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.
(i)Welsh Plant, Unit 2 is being recovered over the blended useful life of Welsh Plant, Units 1 and 3.

Management is seeking or will seek regulatory recovery, as necessary, for any net book value remaining when the plants are retired. To the extent the net book value of these generation assets are not deemed recoverable, it could materially reduce future net income, cash flows and impact financial condition.
21

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

Generation & Marketing

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

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

The following discussion of AEP’s 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, 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.

22

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

	Three Months Ended		Nine Months Ended	
	September 30,		September 30,	
 	2021		2020		2021		2020	
 	(in millions)	
Vertically Integrated Utilities	$	437.7 			$	393.5 			$	936.3 			$	894.7 		
Transmission and Distribution Utilities	155.9 			147.4 			424.0 			403.1 		
AEP Transmission Holdco	166.8 			138.3 			507.5 			370.4 		
Generation & Marketing	100.7 			116.7 			189.7 			211.0 		
Corporate and Other	(65.1)			(47.3)			(108.3)			(114.6)		
Earnings Attributable to AEP Common Shareholders	$	796.0 			$	748.6 			$	1,949.2 			$	1,764.6 		

AEP CONSOLIDATED

Third Quarter of 2021 Compared to Third Quarter of 2020

Earnings Attributable to AEP Common Shareholders increased from $749 million in 2020 to $796 million in 2021 primarily due to:

•Favorable rate proceedings in AEP’s various jurisdictions.
•An increase in transmission investment, which resulted in higher revenues and income.

These increases were partially offset by:

•An increase in Other Operation and Maintenance expenses driven by the COVID-19 pandemic which resulted in lower expenses in the second quarter of 2020.
•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.
•Unrealized losses on AEP’s investment in ChargePoint.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020

Earnings Attributable to AEP Common Shareholders increased from $1,765 million in 2020 to $1,949 million in 2021 primarily due to:

•Favorable rate proceedings in AEP’s various jurisdictions.
•An increase in weather-related usage.
•An increase in transmission investment, which resulted in higher revenues and income.

These increases were partially offset by:

•An increase in Other Operation and Maintenance expenses driven by the COVID-19 pandemic which resulted in lower expenses in 2020.
•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.
23

VERTICALLY INTEGRATED UTILITIES

		Three Months Ended		Nine Months Ended	
		September 30,		September 30,	
 Vertically Integrated Utilities		2021		2020		2021		2020	
 		(in millions)	
Revenues		$	2,759.3 			$	2,434.8 			$	7,557.2 			$	6,753.5 		
Fuel and Purchased Electricity		855.3 			693.7 			2,364.7 			1,947.0 		
	
Gross Margin		1,904.0 			1,741.1 			5,192.5 			4,806.5 		
Other Operation and Maintenance		796.9 			715.9 			2,240.6 			2,031.8 		

Depreciation and Amortization		436.3 			398.8 			1,302.2 			1,173.8 		
Taxes Other Than Income Taxes		124.1 			121.0 			375.6 			355.6 		
Operating Income		546.7 			505.4 			1,274.1 			1,245.3 		

Other Income (Expense)		4.1 			(0.7)			9.9 			2.3 		
Allowance for Equity Funds Used During Construction		9.6 			15.9 			30.3 			33.1 		
Non-Service Cost Components of Net Periodic Benefit Cost		17.0 			16.9 			51.0 			50.9 		
Interest Expense		(144.3)			(140.2)			(425.5)			(426.5)		
Income Before Income Tax Expense (Benefit) and Equity Earnings		433.1 			397.3 			939.8 			905.1 		
Income Tax Expense (Benefit)		(4.6)			3.8 			3.4 			10.5 		
Equity Earnings of Unconsolidated Subsidiary		1.0 			0.7 			2.5 			2.2 		
Net Income		438.7 			394.2 			938.9 			896.8 		
Net Income Attributable to Noncontrolling Interests		1.0 			0.7 			2.6 			2.1 		
Earnings Attributable to AEP Common Shareholders		$	437.7 			$	393.5 			$	936.3 			$	894.7 		

Summary of KWh Energy Sales for Vertically Integrated Utilities

		Three Months Ended		Nine Months Ended	
		September 30,		September 30,	
		2021		2020		2021		2020	
 		(in millions of KWhs)	
Retail:		 		 		 		 	
Residential		9,119 			9,066 			25,125 			24,304 		
Commercial		6,468 			6,257 			17,396 			16,773 		
Industrial		8,485 			8,161 			24,798 			24,335 		
Miscellaneous		604 			595 			1,672 			1,636 		
Total Retail		24,676 			24,079 			68,991 			67,048 		
									
Wholesale (a)		5,713 			4,574 			14,842 			13,116 		
									
Total KWhs		30,389 			28,653 			83,833 			80,164 		

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

24

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		Nine Months Ended	
		September 30,		September 30,	
		2021		2020		2021		2020	
 		(in degree days)	
Eastern Region		 		 		 		 	
Actual – Heating (a)		1 			3 			1,710 			1,456 		
Normal – Heating (b)		4 			4 			1,742 			1,752 		
									
Actual – Cooling (c)		847 			867 			1,209 			1,204 		
Normal – Cooling (b)		744 			739 			1,087 			1,081 		
									
Western Region		 		 		 		 	
Actual – Heating (a)		— 			1 			993 			699 		
Normal – Heating (b)		1 			1 			901 			902 		
									
Actual – Cooling (c)		1,485 			1,291 			2,163 			2,015 		
Normal – Cooling (b)		1,410 			1,416 			2,137 			2,144 		

(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.

25

Third Quarter of 2021 Compared to Third Quarter of 2020

Reconciliation of Third Quarter of 2020 to Third Quarter of 2021	
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities	
(in millions)	
 			
Third Quarter of 2020		$	393.5 		
 		 	
Changes in Gross Margin:		 	
Retail Margins		142.2 		
Margins from Off-system Sales		(0.1)		
Transmission Revenues		18.2 		
Other Revenues		2.6 		
Total Change in Gross Margin		162.9 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(81.0)		
	
Depreciation and Amortization		(37.5)		
Taxes Other Than Income Taxes		(3.1)		

Other Income		4.8 		
Allowance for Equity Funds Used During Construction		(6.3)		
Non-Service Cost Components of Net Periodic Pension Cost		0.1 		
Interest Expense		(4.1)		
Total Change in Expenses and Other		(127.1)		
 		 	
Income Tax Expense		8.4 		
Equity Earnings of Unconsolidated Subsidiary		0.3 		
Net Income Attributable to Noncontrolling Interests		(0.3)		
			
Third Quarter of 2021		$	437.7 		

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 $142 million primarily due to the following:
•A $42 million increase at APCo and WPCo due to rider revenues primarily in Virginia. This increase was partially offset in other expense items below.
•A $40 million increase at I&M primarily due to an increase in rider revenues and the reversal of a provision for refund. This increase was partially offset in other expense items below.
•A $24 million increase in weather-related usage primarily in the residential class.
•A $22 million increase in revenue from rate riders at PSO. This increase was partially offset in other expense items below.
•A $15 million increase due to lower customer refunds related to Tax Reform primarily at APCo and WPCo. This increase was partially offset in Income Tax Expense below.
•An $11 million increase at KPCo due to rider revenues. This increase was partially offset in other expense items below.
•A $9 million increase at KPCo due to base rate case revenues implemented in January 2021.
These increases were partially offset by:
•A $15 million decrease in weather-normalized retail margins driven by a $26 million decrease in the residential class partially offset by a $10 million increase in the industrial and commercial classes.
•A $9 million decrease at PSO due to PTC benefits provided to customers. This decrease is offset in Income Tax Expense.
26

•An $8 million decrease in deferred fuel at APCo and WPCo primarily due to the timing of recoverable PJM expenses.
•Transmission Revenues increased $18 million primarily due to:
•An $8 million increase due to increased transmission investment at APCo. This increase is partially offset in Depreciation and Amortization expenses below.
•A $7 million increase in load and transmission investment at SWEPCo.

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

•Other Operation and Maintenance expenses increased $81 million primarily due to the following:
•A $58 million increase in PJM transmission service expenses.
•A $23 million increase in vegetation management expenses.
•A $17 million increase in administrative and general expenses.
•A $13 million increase in SPP transmission service expenses.
These increases were partially offset by:
•A $34 million decrease in employee-related expenses.
•Depreciation and Amortization expenses increased $38 million primarily due to a higher depreciable base at APCo, I&M, PSO and SWEPCo and an increase in depreciation rates at APCo. This increase was partially offset in Gross Margin above.
•Other Income increased $5 million primarily related to carrying charges on regulatory assets resulting from the February 2021 severe winter weather event at SWEPCo.
•Allowance for Equity Funds Used During Construction decreased $6 million primarily due to the adoption of the FERC’s temporary AFUDC waiver which was implemented in July 2020 retroactive to March 2020.
•Interest Expense increased $4 million primarily due to increased long-term debt balances at I&M and SWEPCo.
•Income Tax Expense decreased $8 million primarily due to a decrease in state income tax expense and an increase in PTC. This decrease was partially offset by an increase in pretax book income and a decrease in parent company loss benefit.

27

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020

Reconciliation of Nine Months Ended September 30, 2020 to Nine Months Ended September 30, 2021	
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities	
(in millions)	
 			
Nine Months Ended September 30, 2020		$	894.7 		
 		 	
Changes in Gross Margin:		 	
Retail Margins		336.7 		
Margins from Off-system Sales		23.7 		
Transmission Revenues		29.4 		
Other Revenues		(3.8)		
Total Change in Gross Margin		386.0 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(208.8)		
	
Depreciation and Amortization		(128.4)		
Taxes Other Than Income Taxes		(20.0)		

Other Income		7.6 		
Allowance for Equity Funds Used During Construction		(2.8)		
Non-Service Cost Components of Net Periodic Pension Cost		0.1 		
Interest Expense		1.0 		
Total Change in Expenses and Other		(351.3)		
 		 	
Income Tax Expense		7.1 		
Equity Earnings of Unconsolidated Subsidiary		0.3 		
Net Income Attributable to Noncontrolling Interests		(0.5)		
			
Nine Months Ended September 30, 2021		$	936.3 		

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

•Retail Margins increased $337 million primarily due to the following:
•An $88 million increase at I&M due to the annual wholesale formula rate true-up, an increase in Indiana and Michigan base rate revenues and an increase in rider revenues. This increase was partially offset in other expense items below.
•An $84 million increase in weather-related usage primarily in the residential class.
•A $66 million increase at APCo and WPCo due to rider revenue in Virginia and West Virginia. This increase was partially offset in other expense items below.
•A $41 million increase at PSO due to rider revenues. This increase was partially offset in other expense items below.
•A $38 million increase at KPCo due to rider revenues. This increase was partially offset in other expense items below.
•A $20 million increase at KPCo due to base rate case revenues implemented in January 2021.
•A $13 million increase in municipal and cooperative revenues at SWEPCo primarily due to the February 2021 severe winter weather event.
•A $12 million increase due to lower customer refunds related to Tax Reform primarily at APCo and WPCo. This increase was partially offset in Income Tax Expense below.
•A $10 million increase in recoverable fuel costs at SWEPCo primarily due to timing of recovery.
•A $6 million increase in municipal and cooperative revenues at SWEPCo primarily due to the annual generation formula rate true-up.

28

These increases were partially offset by:
•A $32 million decrease in weather-normalized retail margins primarily in the residential class.
•A $24 million decrease in weather-normalized wholesale margins, including the loss of a significant wholesale contract at I&M.
•An $11 million decrease at PSO due to PTC benefits provided to customers. This decrease is offset in Income Tax Expense.
•Margins from Off-system Sales increased $24 million primarily due to Turk Plant merchant sales as a result of the February 2021 severe winter weather event at SWEPCo.
•Transmission Revenues increased $29 million primarily due to the following:
•A $22 million increase due to increased transmission investment at APCo. This increase is partially offset in Depreciation and Amortization expenses below.
•A $12 million increase due to increased load and increased transmission investment at SWEPCo.
These increases were partially offset by:
•A $7 million decrease as a result of the transmission formula rate true-up.
•Other Revenues decreased $4 million primarily due to the following:
•A $6 million decrease at PSO primarily due to lower business development revenue. This decrease was partially offset in Other Operation and Maintenance expenses below.
•A $2 million decrease primarily due to lower pole attachment revenue at KPCo.
These decreases were partially offset by:
•A $4 million increase at I&M primarily due to an increase in reconnection fees and joint license agreements.

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

•Other Operation and Maintenance expenses increased $209 million primarily due to the following:
•A $131 million increase in PJM transmission service expenses including the annual formula rate true-up.
•A $56 million increase in vegetation management expenses.
•A $50 million increase in SPP transmission service expenses including the annual formula rate true-up.
•A $10 million increase in administrative overheads.
•An $8 million increase due to the capitalization of previously expensed North Central Wind Energy Facilities costs at PSO and SWEPCo in 2020.
These increases were partially offset by:
•A $20 million decrease primarily due to a decrease in Indiana jurisdictional Demand Side Management expenses at I&M. This decrease was offset in Retail Margins above.
•A $14 million decrease in employee-related expenses.
•An $11 million decrease in factoring expenses.
•Depreciation and Amortization expenses increased $128 million primarily due to a higher depreciable base at APCo, I&M, PSO and SWEPCo and increased depreciation rates at APCo and I&M. This increase was partially offset in Gross Margin above.
•Taxes Other Than Income Taxes increased $20 million primarily due to the following:
•A $12 million increase at SWEPCo primarily due to increased property taxes resulting from the expiration of the Louisiana Industrial Tax Exemption related to Stall Plant.
•A $4 million increase at I&M primarily due to property taxes driven by an increase in utility plant.
•Other Income increased $8 million primarily due to carrying charges on regulatory assets resulting from the February 2021 severe winter weather event.
•Income Tax Expense decreased $7 million primarily due to a decrease in state income tax expense and an increase in PTC. This decrease was partially offset by a decrease in amortization of Excess ADIT, a decrease in parent company loss benefit and an increase in pretax book income. The decrease in amortization of Excess ADIT is partially offset above in Retail Margins.
29

TRANSMISSION AND DISTRIBUTION UTILITIES

		Three Months Ended		Nine Months Ended	
		September 30,		September 30,	
Transmission and Distribution Utilities		2021		2020		2021		2020	
 		(in millions)	
Revenues		$	1,200.3 			$	1,165.3 			$	3,391.8 			$	3,306.7 		
Purchased Electricity		188.1 			183.8 			561.6 			522.7 		
	
Gross Margin		1,012.2 			981.5 			2,830.2 			2,784.0 		
Other Operation and Maintenance		442.6 			439.1 			1,168.6 			1,158.2 		

Depreciation and Amortization		164.6 			163.5 			515.8 			585.0 		
Taxes Other Than Income Taxes		167.5 			156.4 			483.5 			444.4 		
Operating Income		237.5 			222.5 			662.3 			596.4 		
Interest and Investment Income		0.4 			0.9 			1.1 			2.0 		
Carrying Costs Income		0.1 			0.3 			1.1 			1.3 		
	
Allowance for Equity Funds Used During Construction		11.3 			9.0 			24.3 			23.7 		
Non-Service Cost Components of Net Periodic Benefit Cost		7.3 			7.4 			21.8 			22.1 		
Interest Expense		(77.3)			(74.0)			(228.8)			(217.6)		
Income Before Income Tax Expense		179.3 			166.1 			481.8 			427.9 		
Income Tax Expense		23.4 			18.7 			57.8 			24.8 		
Net Income		155.9 			147.4 			424.0 			403.1 		
Net Income Attributable to Noncontrolling Interests		— 			— 			— 			— 		
Earnings Attributable to AEP Common Shareholders		$	155.9 			$	147.4 			$	424.0 			$	403.1 		

Summary of KWh Energy Sales for Transmission and Distribution Utilities

		Three Months Ended		Nine Months Ended	
		September 30,		September 30,	
		2021		2020		2021		2020	
 		(in millions of KWhs)	
Retail:		 		 		 		 	
Residential		8,093 			8,277 			21,082 			20,876 		
Commercial		7,125 			6,722 			19,189 			18,154 		
Industrial		6,048 			5,417 			17,667 			16,473 		
Miscellaneous		207 			206 			558 			568 		
Total Retail (a)		21,473 			20,622 			58,496 			56,071 		
									
Wholesale (b)		644 			502 			1,692 			1,347 		
									
Total KWhs		22,117 			21,124 			60,188 			57,418 		

(a) Represents energy delivered to distribution customers.
(b) Primarily Ohio’s contractually obligated purchases of OVEC power sold to PJM.
30

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		Nine Months Ended	
		September 30,		September 30,	
		2021		2020		2021		2020	
 		(in degree days)	
Eastern Region		 		 		 		 	
Actual – Heating (a)		1 			2 			1,993 			1,767 		
Normal – Heating (b)		5 			6 			2,071 			2,086 		
									
Actual – Cooling (c)		787 			809 			1,148 			1,126 		
Normal – Cooling (b)		689 			682 			996 			986 		
									
Western Region		 		 		 		 	
Actual – Heating (a)		— 			1 			319 			98 		
Normal – Heating (b)		— 			— 			188 			188 		
									
Actual – Cooling (d)		1,308 			1,357 			2,278 			2,524 		
Normal – Cooling (b)		1,379 			1,378 			2,436 			2,436 		

(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.

31

Third Quarter of 2021 Compared to Third Quarter of 2020

Reconciliation of Third Quarter of 2020 to Third Quarter of 2021	
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities	
(in millions)	
 		 	
Third Quarter of 2020		$	147.4 		
 		 	
Changes in Gross Margin:		 	
Retail Margins		45.1 		
Margins from Off-system Sales		(31.1)		
Transmission Revenues		27.4 		
Other Revenues		(10.7)		
Total Change in Gross Margin		30.7 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(3.5)		
Depreciation and Amortization		(1.1)		
Taxes Other Than Income Taxes		(11.1)		
Interest and Investment Income		(0.5)		
Carrying Costs Income		(0.2)		
Allowance for Equity Funds Used During Construction		2.3 		
Non-Service Cost Components of Net Periodic Benefit Cost		(0.1)		
Interest Expense		(3.3)		
Total Change in Expenses and Other		(17.5)		
 		 	
Income Tax Expense		(4.7)		
 		 	
Third Quarter of 2021		$	155.9 		

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity were as follows:

•Retail Margins increased $45 million primarily due to the following:
•A $40 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 $22 million increase due to prior year refunds in Texas of Excess ADIT and excess federal income taxes collected as a result of Tax Reform. This increase was partially offset in Income Tax Expense below.
•A $15 million increase related to various rider revenues in Ohio. This increase was partially offset in Margins from Off-system Sales, Other Revenues and other expense items below.
•A $13 million increase from interim rate increases driven by increased distribution investment in Texas.
•A $3 million increase from interim rate increases driven by increased transmission investment in Texas.
•A $3 million increase in usage in Ohio primarily from the industrial and commercial class.
These increases were partially offset by:
•A $24 million decrease due to the ending of the Energy Efficiency and Peak Demand Rider in Ohio in December 2020. This decrease was partially offset in Other Operation and Maintenance expenses below.
•A $15 million decrease in revenues in Ohio associated with the Universal Service Fund (USF). This decrease was offset in Other Operation and Maintenance expenses below.
•A $9 million decrease in weather-normalized margins in Texas primarily in the industrial class.
•A $3 million decrease in weather-related usage in Texas primarily due to a 4% decrease in cooling degree days.
•Margins from Off-system Sales decreased $31 million primarily due to the following:
•A $22 million decrease in Texas primarily due to the retirement of the Oklaunion Power Station in September 2020. This decrease was partially offset in Depreciation and Amortization expenses below.
32

•A $19 million decrease in deferrals of OVEC costs in Ohio. This decrease was offset in Retail Margins above and Other Revenues below.
These decreases were partially offset by:
•A $10 million increase in off-system sales at OVEC in Ohio. This increase was offset in Retail Margins above and Other Revenues below.
•Transmission Revenues increased $27 million primarily due to the following:
•A $20 million increase from interim rate increases driven by increased transmission investment in Texas.
•An $8 million increase due to prior year refunds to customers associated with the most recent base rate case in Texas. This increase was offset in Other Revenues below.
•Other Revenues decreased $11 million primarily due to the following:
•A $10 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 in Depreciation and Amortization expenses and Interest Expense below.
•An $8 million decrease due to prior year refunds to customers associated with the most recent base rate case in Texas. This decrease was partially offset in Retail Margins and Transmission Revenues above.
This decrease was partially offset by:
•An $8 million increase primarily due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs in Ohio. This increase was offset in Retail Margins and Margins from Off-system Sales above.

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

•Other Operation and Maintenance expenses increased $4 million primarily due to the following:
•A $34 million increase in PJM transmission expenses. This increase was partially offset in Retail Margins above.
•A $10 million increase in vegetation management expenses. This increase was partially offset in Retail Margins above.
•A $10 million increase in distribution related expenses due to increased maintenance, storms and billings.
•A $3 million increase due to timing of AEPSC taxes.
These increases were partially offset by:
•A $19 million decrease in Texas due to the Oklaunion Power Station retirement in September 2020 and its sale to a nonaffiliated third-party in October 2020. This decrease was offset in Gross Margin above.
•A $16 million decrease in energy efficiency/demand side management expenses in Ohio. This decrease was partially offset in Retail Margins above.
•A $15 million decrease in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This decrease was offset in Retail Margins above.
•A $6 million decrease in employee-related expenses.
•Depreciation and Amortization expenses increased $1 million primarily due to the following:
•A $10 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
This increase was partially offset by:
•A $9 million decrease in securitization amortizations in Texas primarily related to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset in Other Revenues above.
•Taxes Other Than Income Taxes increased $11 million primarily due to increased property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
•Interest Expense increased $3 million primarily due to higher long-term debt balances.
•Income Tax Expense increased $5 million primarily due to a decrease in amortization of Excess ADIT. This increase was partially offset in Gross Margin above.
33

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020

Reconciliation of Nine Months Ended September 30, 2020 to Nine Months Ended September 30, 2021	
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities	
(in millions)	
 			
Nine Months Ended September 30, 2020		$	403.1 		
 		 	
Changes in Gross Margin:		 	
Retail Margins		146.3 		
Margins from Off-system Sales		(87.2)		
Transmission Revenues		69.9 		
Other Revenues		(82.8)		
Total Change in Gross Margin		46.2 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(10.4)		
Depreciation and Amortization		69.2 		
Taxes Other Than Income Taxes		(39.1)		
Interest and Investment Income		(0.9)		
Carrying Costs Income		(0.2)		
Allowance for Equity Funds Used During Construction		0.6 		
Non-Service Cost Components of Net Periodic Benefit Cost		(0.3)		
Interest Expense		(11.2)		
Total Change in Expenses and Other		7.7 		
 		 	
Income Tax Expense		(33.0)		
 		 	
Nine Months Ended September 30, 2021		$	424.0 		

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity were as follows:

•Retail Margins increased $146 million primarily due to the following:
•A $129 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 $71 million increase related to various rider revenues in Ohio. This increase was partially offset in Margins from Off-system Sales, Other Revenues and other expense items below.
•A $34 million increase from interim rate increases driven by increased distribution investment in Texas.
•An $18 million increase from interim rate increases driven by increased transmission investment in Texas.
•A $10 million increase in weather-related usage in Texas primarily due to a 226% increase in heating degree days, partially offset by a 10% decrease in cooling degree days.
These increases were partially offset by:
•A $71 million decrease due to the ending of the Energy Efficiency and Peak Demand Rider in Ohio in December 2020. This decrease was partially offset in Other Operation and Maintenance expenses below.
•A $43 million decrease in revenues in Ohio associated with the USF. This decrease was offset in Other Operation and Maintenance expenses below.
•An $8 million decrease in weather-normalized margins in Texas primarily in the industrial class.
•Margins from Off-system Sales decreased $87 million primarily due to the following:
•A $51 million decrease in Texas primarily due to the retirement of the Oklaunion Power Station in September 2020. This decrease was partially offset in Depreciation and Amortization expenses below.
34

•A $51 million decrease in deferrals of OVEC costs in Ohio. This decrease was offset in Retail Margins above and Other Revenues below.
These decreases were partially offset by:
•A $16 million increase in off-system sales at OVEC in Ohio. This increase was offset in Retail Margins above and Other Revenues below.
•Transmission Revenues increased $70 million primarily due to the following:
•A $59 million increase from interim rate increases driven by increased transmission investment in Texas.
•A $14 million increase due to a prior year one-time credit to transmission customers in Texas as a result of Tax Reform and the most recent base rate case. This increase was offset in Income Tax Expense below.
•Other Revenues decreased $83 million primarily due to the following:
•A $104 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 in Depreciation and Amortization expenses and Interest Expense below.
This decrease was partially offset by:
•A $21 million increase in Ohio primarily due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins and Margins from Off-system Sales above.

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

•Other Operation and Maintenance expenses increased $10 million primarily due to the following:
•A $131 million increase in PJM transmission expenses including the annual formula rate true-up. This increase was partially offset in Retail Margins above.
•A $16 million increase in vegetation management expenses. This increase was offset in Retail Margins above.
•An $11 million increase in distribution related expenses.
•A $7 million increase in storm expenses.
These increases were partially offset by:
•A $47 million decrease in energy efficiency/demand side management expenses in Ohio. This decrease was partially offset in Retail Margins above.
•A $43 million decrease in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This decrease was offset in Retail Margins above.
•A $41 million decrease in Texas due to the Oklaunion Power Station retirement in September 2020 and its sale to a nonaffiliated third-party in October 2020. This decrease was offset in Gross Margin above.
•A $19 million decrease in factored customer accounts receivable expenses primarily due to bad debt expenses and a current year adjustment to allowance for doubtful accounts.
•A $5 million decrease in employee-related expenses.
•Depreciation and Amortization expenses decreased $69 million primarily due to the following:
•A $102 million decrease in securitization amortizations in Texas primarily related to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset in Other Revenues above.
These decreases were partially offset by:
•An $18 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
•An $8 million increase in amortization of plant primarily related to capitalized software in Ohio.
•A $7 million increase in recoverable DIR depreciable expense in Ohio. This increase was partially offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $39 million primarily due to property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
•Interest Expense increased $11 million primarily due to higher long-term debt balances.
35

•Income Tax Expense increased $33 million primarily due to a decrease in amortization of Excess ADIT and an increase in pretax book income, partially offset by favorable discrete adjustments recognized during the periods. The decrease in amortization of Excess ADIT is partially offset in Gross Margin above.
36

AEP TRANSMISSION HOLDCO

		Three Months Ended		Nine Months Ended	
		September 30,		September 30,	
AEP Transmission Holdco		2021		2020		2021		2020	
 		(in millions)	
Transmission Revenues		$	391.6 			$	317.9 			$	1,146.8 			$	877.8 		
Other Operation and Maintenance		40.3 			30.1 			96.9 			85.9 		
Depreciation and Amortization		78.1 			63.6 			225.5 			182.8 		
Taxes Other Than Income Taxes		62.7 			53.8 			183.4 			157.5 		
Operating Income		210.5 			170.4 			641.0 			451.6 		
Interest and Investment Income		0.3 			0.2 			0.7 			2.6 		

Allowance for Equity Funds Used During Construction		16.1 			20.3 			49.3 			54.9 		
Non-Service Cost Components of Net Periodic Benefit Cost		0.5 			0.5 			1.6 			1.5 		
Interest Expense		(37.6)			(34.0)			(108.4)			(99.0)		
Income Before Income Tax Expense and Equity Earnings		189.8 			157.4 			584.2 			411.6 		
Income Tax Expense		42.0 			38.2 			131.2 			101.3 		
Equity Earnings of Unconsolidated Subsidiary		20.1 			20.1 			57.7 			62.8 		
Net Income		167.9 			139.3 			510.7 			373.1 		
Net Income Attributable to Noncontrolling Interests		1.1 			1.0 			3.2 			2.7 		
Earnings Attributable to AEP Common Shareholders		$	166.8 			$	138.3 			$	507.5 			$	370.4 		

Summary of Investment in Transmission Assets for AEP Transmission Holdco

		September 30,	
		2021		2020	
		(in millions)	
Plant in Service		$	11,256.0 			$	9,644.6 		
Construction Work in Progress		1,609.6 			1,732.5 		
Accumulated Depreciation and Amortization		758.1 			553.1 		
Total Transmission Property, Net		$	12,107.5 			$	10,824.0 		
37

Third Quarter of 2021 Compared to Third Quarter of 2020
 
Reconciliation of Third Quarter of 2020 to Third Quarter of 2021
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)

Third Quarter of 2020		$	138.3 		
			
Changes in Transmission Revenues:			
Transmission Revenues		73.7 		
Total Change in Transmission Revenues		73.7 		
			
Changes in Expenses and Other:			
Other Operation and Maintenance		(10.2)		
Depreciation and Amortization		(14.5)		
Taxes Other Than Income Taxes		(8.9)		
Interest Income		0.1 		
	
Allowance for Equity Funds Used During Construction		(4.2)		
	
Interest Expense		(3.6)		
Total Change in Expenses and Other		(41.3)		
			
Income Tax Expense		(3.8)		
	
Net Income Attributable to Noncontrolling Interests		(0.1)		
			
Third Quarter of 2021		$	166.8 		

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

•Transmission Revenues increased $74 million primarily due to continued investment in transmission assets.

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

•Other Operation and Maintenance expenses increased $10 million primarily due to the following:
•A $2 million increase in vegetation management expenses.
•A $2 million increase in an accrual for NERC compliance costs.
•A $2 million increase in employee-related expenses.
•A $1 million increase in rent expense.
•Depreciation and Amortization expenses increased $15 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxes increased $9 million primarily due to higher property taxes as a result of increased transmission investment.
•Allowance for Equity Funds Used During Construction decreased $4 million primarily due to lower CWIP.
•Interest Expense increased $4 million primarily due to higher long-term debt balances.
•Income Tax Expense increased $4 million primarily due to an increase in pretax book income, partially offset by an increase in parent company loss benefit.
38

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020
 
Reconciliation of Nine Months Ended September 30, 2020 to Nine Months Ended September 30, 2021
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)

Nine Months Ended September 30, 2020		$	370.4 		
			
Changes in Transmission Revenues:			
Transmission Revenues		269.0 		
Total Change in Transmission Revenues		269.0 		
			
Changes in Expenses and Other:			
Other Operation and Maintenance		(11.0)		
Depreciation and Amortization		(42.7)		
Taxes Other Than Income Taxes		(25.9)		
Interest Income		(1.9)		
	
Allowance for Equity Funds Used During Construction		(5.6)		
Non-Service Cost Components of Net Periodic Pension Cost		0.1 		
Interest Expense		(9.4)		
Total Change in Expenses and Other		(96.4)		
			
Income Tax Expense		(29.9)		
Equity Earnings of Unconsolidated Subsidiary		(5.1)		
Net Income Attributable to Noncontrolling Interests		(0.5)		
			
Nine Months Ended September 30, 2021		$	507.5 		

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

•Transmission Revenues increased $269 million primarily due to the following:
•A $206 million increase due to continued investment in transmission assets.
•A $45 million increase 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 $16 million increase 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 $11 million primarily due to the following:
•A $4 million increase in vegetation management expenses.
•A $2 million increase in an accrual for NERC compliance costs.
•A $2 million increase in rent expense.
•A $1 million increase in property insurance premiums.
•Depreciation and Amortization expenses increased $43 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxes increased $26 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 lower CWIP.
•Interest Expense increased $9 million primarily due to higher long-term debt balances.
•Income Tax Expense increased $30 million primarily due to an increase in pretax book income.
•Equity Earnings of Unconsolidated Subsidiary decreased $5 million primarily due to lower pretax equity earnings at PATH-WV and ETT.
39

GENERATION & MARKETING

		Three Months Ended		Nine Months Ended	
		September 30,		September 30,	
Generation & Marketing		2021		2020		2021		2020	
 		(in millions)	
Revenues		$	621.1 			$	490.0 			$	1,691.9 			$	1,305.5 		
Fuel, Purchased Electricity and Other		444.7 			391.6 			1,368.7 			1,050.4 		
	
Gross Margin		176.4 			98.4 			323.2 			255.1 		
Other Operation and Maintenance		38.2 			27.2 			98.8 			85.1 		

Depreciation and Amortization		21.1 			18.5 			59.7 			54.1 		
Taxes Other Than Income Taxes		2.6 			3.3 			8.1 			10.4 		
Operating Income		114.5 			49.4 			156.6 			105.5 		
Interest and Investment Income		1.3 			0.4 			2.4 			2.6 		
	
Non-Service Cost Components of Net Periodic Benefit Cost		3.8 			3.9 			11.5 			11.6 		
Interest Expense		(4.0)			(3.8)			(11.1)			(20.5)		
Income Before Income Tax Expense (Benefit) and Equity Earnings (Loss)		115.6 			49.9 			159.4 			99.2 		
Income Tax Expense (Benefit)		8.3 			(70.9)			(31.0)			(104.3)		
Equity Earnings (Loss) of Unconsolidated Subsidiaries		(7.8)			(6.2)			(6.2)			0.1 		
Net Income		99.5 			114.6 			184.2 			203.6 		
Net Loss Attributable to Noncontrolling Interests		(1.2)			(2.1)			(5.5)			(7.4)		
Earnings Attributable to AEP Common Shareholders		$	100.7 			$	116.7 			$	189.7 			$	211.0 		

Summary of MWhs Generated for Generation & Marketing

		Three Months Ended		Nine Months Ended	
		September 30,		September 30,	
		2021		2020		2021		2020	
 		(in millions of MWhs)	
Fuel Type:		 		 		 		 	
Coal		1 			1 			3 			3 		
Renewables		1 			— 			3 			2 		
	
Total MWhs		2 			1 			6 			5 		
40

Third Quarter of 2021 Compared to Third Quarter of 2020

Reconciliation of Third Quarter of 2020 to Third Quarter of 2021	
Earnings Attributable to AEP Common Shareholders from Generation & Marketing	
(in millions)	
 		 	
Third Quarter of 2020		$	116.7 		
 		 	
Changes in Gross Margin:		 	
Merchant Generation		(2.5)		
Renewable Generation		8.9 		
Retail, Trading and Marketing		71.6 		
Total Change in Gross Margin		78.0 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(11.0)		

Depreciation and Amortization		(2.6)		
Taxes Other Than Income Taxes		0.7 		
Interest and Investment Income		0.9 		

Non-Service Cost Components of Net Periodic Benefit Cost		(0.1)		
Interest Expense		(0.2)		
Total Change in Expenses and Other		(12.3)		
 		 	
Income Tax Expense		(79.2)		
Equity Earnings (Loss) of Unconsolidated Subsidiaries		(1.6)		
Net Loss Attributable to Noncontrolling Interests		(0.9)		
 		 	
Third Quarter of 2021		$	100.7 		

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

•Merchant Generation decreased $3 million primarily due to the retirement of Oklaunion Plant in 2020.
•Renewable Generation increased $9 million primarily due to higher solar and wind production.
•Retail, Trading and Marketing increased $72 million due to higher mark-to-market hedge gains driven by higher commodity prices.

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

•Other Operation and Maintenance expenses increased $11 million primarily due to the following:
•An $18 million increase due to gains recorded in 2020 on the sale of land.
This increase was partially offset by:
•A $7 million decrease in expenses related to the installment sale of Amazon substations and the retirement of Oklaunion Plant in 2020.
•Income Tax Expense increased $79 million primarily due to the recognition of a discrete tax adjustment in 2020 attributable to the CARES Act, the impact of PTCs on the annualized effective tax rate and an increase in pretax book income.

41

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020

Reconciliation of Nine Months Ended September 30, 2020 to Nine Months Ended September 30, 2021	
Earnings Attributable to AEP Common Shareholders from Generation & Marketing	
(in millions)	
 		 	
Nine Months Ended September 30, 2020		$	211.0 		
 		 	
Changes in Gross Margin:		 	
Merchant Generation		6.6 		
Renewable Generation		17.2 		
Retail, Trading and Marketing		44.3 		
Total Change in Gross Margin		68.1 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(13.7)		

Depreciation and Amortization		(5.6)		
Taxes Other Than Income Taxes		2.3 		
Interest and Investment Income		(0.2)		
	
Non-Service Cost Components of Net Periodic Benefit Cost		(0.1)		
Interest Expense		9.4 		
Total Change in Expenses and Other		(7.9)		
 		 	
Income Tax Benefit		(73.3)		
Equity Earnings (Loss) of Unconsolidated Subsidiaries		(6.3)		
Net Loss Attributable to Noncontrolling Interests		(1.9)		
 		 	
Nine Months Ended September 30, 2021		$	189.7 		

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

•Merchant Generation increased $7 million primarily due to higher market prices in PJM which drove increased generation at Cardinal Plant.
•Renewable Generation increased $17 million primarily due to increased solar and wind production.
•Retail, Trading and Marketing increased $44 million due to higher mark-to-market hedge gains driven by higher commodity prices. This increase was partially offset by lower trading and retail margins due to unprecedented cold temperatures and record ERCOT market prices in February 2021.

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

•Other Operation and Maintenance expenses increased $14 million primarily due to the following:
•A $20 million increase from gains recorded in 2020 on the sale of land.
•A $17 million increase related to the Oklaunion PPA with AEP Texas primarily due to an ARO revision in 2020.
These increases were partially offset by:
•A $10 million decrease due to the retirement of Conesville Plant Unit 4 in 2020.
•A $5 million decrease due to a planned outage at Cardinal Plant in 2020.
•A $4 million decrease due to the retirement of Oklaunion Plant in 2020.
•A $4 million decrease due to the installment sale of Amazon substations.
•Depreciation and Amortization expenses increased $6 million due to a higher depreciable base from increased investments in renewable energy sources.
42

•Interest Expense decreased $9 million due to lower borrowing costs in 2021.
•Income Tax Benefit decreased $73 million primarily due to the recognition of a discrete tax adjustment in 2020 attributable to the CARES Act, the impact of PTCs on the annualized effective tax rate and an increase in pretax book income.
•Equity Earnings (Loss) of Unconsolidated Subsidiaries decreased $6 million primarily due to lower revenues due to lower wind production from jointly owned assets.
43

CORPORATE AND OTHER

Third Quarter of 2021 Compared to Third Quarter of 2020

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $47 million in 2020 to a loss of $65 million in 2021 primarily due to:

•A $26 million unrealized loss from an investment in ChargePoint.
•A $6 million decrease in interest income due to a lower return on investments held by EIS and lower interest income from affiliates.

These items were partially offset by:

•A $9 million decrease in Income Tax Expense due to lower pretax book income and a decrease in the consolidated tax adjustment.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020

Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $115 million in 2020 to a loss of $108 million in 2021 primarily due to:

•A $23 million increase in equity earnings from unrealized investment gains.
•A $16 million decrease in interest expense.
•A $12 million gain from an investment in ChargePoint, of which $7 million is unrealized.

These items were partially offset by:

•A $21 million decrease in interest income primarily due to lower interest income from affiliates.
•A $12 million increase in the EIS reserve.
•An $8 million increase in general corporate expenses.
•A $6 million increase in estimated health care benefits for certain retirees.

AEP SYSTEM INCOME TAXES

Third Quarter of 2021 Compared to Third Quarter of 2020

Income Tax Expense increased $71 million primarily due to the following:
•A $52 million increase due to the recognition of a discrete tax adjustment in 2020 attributable to the CARES Act.
•A $25 million increase due to an increase in pretax book income.
•An $8 million increase due to a decrease in amortization of Excess ADIT.
These increases were partially offset by:
•A $15 million decrease in state income tax expense.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020

Income Tax Expense increased $128 million primarily due to the following:
•A $66 million increase due to an increase in pretax book income.
•A $52 million increase due to the recognition of a discrete tax adjustment in 2020 attributable to the CARES Act.
•A $19 million increase due to the remeasurement of deferred state income taxes as a result of legislative changes in 2021.
These increases were partially offset by:
•A $23 million increase in PTC.

44

FINANCIAL CONDITION

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

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization

 	September 30, 2021		December 31, 2020	
 	(dollars in millions)	
Long-term Debt, including amounts due within one year	$	34,578.3 			58.0 	%		$	31,072.5 			57.2 	%	
Short-term Debt	2,504.0 			4.2 			2,479.3 			4.6 		
Total Debt	37,082.3 			62.2 			33,551.8 			61.8 		
AEP Common Equity	22,278.1 			37.4 			20,550.9 			37.8 		
Noncontrolling Interests	249.1 			0.4 			223.6 			0.4 		
Total Debt and Equity Capitalization	$	59,609.5 			100.0 	%		$	54,326.3 			100.0 	%	

AEP’s ratio of debt-to-total capital increased from 61.8% as of December 31, 2020 to 62.2% as of September 30, 2021 primarily due to an increase in debt to help address the cash flow implications resulting from the February 2021 severe winter weather event in addition to supporting distribution, transmission and renewable investment growth.

Liquidity

Liquidity, or access to cash, is an important factor in determining AEP’s financial stability.  Management believes AEP has adequate liquidity under its existing credit facilities.  As of September 30, 2021, AEP had $5 billion of revolving credit facilities to support its commercial paper program.  Additional liquidity is available from cash from operations and a receivables securitization agreement.  Management is committed to maintaining adequate liquidity.  AEP generally uses short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged.  Sources of long-term funding include issuance of long-term debt, leasing agreements, hybrid securities or common stock. In February 2021, severe winter weather impacted certain AEP service territories resulting in disruptions to SPP market conditions. In March 2021, AEP entered into a $500 million 364-day Term Loan and borrowed the full amount to help address the cash flow implications resulting from the February 2021 severe winter weather event. See Note 4 - Rate Matters for additional information.

Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments.  As of September 30, 2021, available liquidity was approximately $5.1 billion as illustrated in the table below:

		Amount		Maturity	
Commercial Paper Backup:	(in millions)			
	Revolving Credit Facility	$	4,000.0 			March 2026	
	Revolving Credit Facility	1,000.0 			March 2023	
 	364-Day Term Loan	500.0 			March 2022	
Cash and Cash Equivalents	1,372.7 			 	
Total Liquidity Sources	6,872.7 			 	
Less:	AEP Commercial Paper Outstanding	1,254.0 			 	
 	364-Day Term Loan	500.0 			 	
					
Net Available Liquidity	$	5,118.7 			 	

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 2021 was $2.5 billion.  The weighted-average interest rate for AEP’s commercial paper during 2021 was 0.24%.
45

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 five uncommitted facilities totaling $375 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of September 30, 2021 was $180 million with maturities ranging from October 2021 to August 2022.

Securitized Accounts Receivables

AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and was amended in September 2021 to include a $125 million and a $625 million facility which expire in September 2023 and 2024, respectively. As of September 30, 2021, the affiliated utility subsidiaries are in compliance with all requirements under the agreement.

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, 2021, this contractually-defined percentage was 59.3%. 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 facilities do not permit the lenders to refuse a draw on any facility if a material adverse change occurs.

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

At-the-Market (ATM) Program

AEP participates in an ATM offering program that allows AEP to issue, from time to time, up to an aggregate of $1 billion of its common stock, including shares of common stock that may be sold pursuant to an equity forward sales agreement. As of September 30, 2021, approximately $534 million of equity is available for issuance under the ATM offering program. See Note 12 - Financing Activities for additional information.

Equity Units

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

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

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See Note 12 - Financing Activities for additional information.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.78 per share in October 2021, a $0.04 per share increase as compared to the quarterly dividend declared in July 2021. Future dividends may vary depending upon AEP’s profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. Management does not believe these restrictions will have any significant impact on its ability to access cash to meet the payment of dividends on its common stock. See “Dividend Restrictions” section of Note 12 for additional information.

Credit Ratings

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

CASH FLOW

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

	Nine Months Ended 
September 30,	
 	2021		2020	
 	(in millions)	
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	$	438.3 			$	432.6 		
Net Cash Flows from Operating Activities	2,973.0 			2,922.2 		
Net Cash Flows Used for Investing Activities	(4,906.2)			(4,707.3)		
Net Cash Flows from Financing Activities	2,921.6 			1,816.3 		
	
Net Increase in Cash and Cash Equivalents	988.4 			31.2 		
Cash, Cash Equivalents and Restricted Cash at End of Period	$	1,426.7 			$	463.8 		

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Operating Activities

	Nine Months Ended 
September 30,	
	2021		2020	
	(in millions)	
Net Income	$	1,949.5 			$	1,762.0 		
Non-Cash Adjustments to Net Income (a)	2,353.8 			2,196.7 		
Mark-to-Market of Risk Management Contracts	101.0 			46.4 		
Pension Contributions to Qualified Plan Trust	— 			(110.3)		
Property Taxes	415.1 			396.9 		
Deferred Fuel Over/Under-Recovery, Net	(1,356.8)			27.4 		

Change in Other Noncurrent Assets	(270.7)			(322.0)		
Change in Other Noncurrent Liabilities	162.7 			(25.1)		
Change in Certain Components of Working Capital	(381.6)			(1,049.8)		
Net Cash Flows from Operating Activities	$	2,973.0 			$	2,922.2 		

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

Net Cash Flows from Operating Activities increased by $51 million primarily due to the following:
•A $668 million increase in cash from the Change in Certain Components of Working Capital. The increase is primarily due to timing of accounts receivables and payables and a decrease in fuel, material and supplies balances primarily due to decreases in coal and lignite inventory on hand.
•A $345 million increase in cash from Net Income, after non-cash adjustments. See Results of Operations for further detail.
•A $188 million increase in cash from Change in Other Noncurrent Liabilities. The increase is primarily due to changes in regulatory liabilities driven by timing differences between collections from and refunds to customers under rate rider mechanisms.
•A $110 million increase in cash due to a discretionary contribution to the qualified pension plan made in the prior year. See Note 7 for additional information.
These increases in cash were partially offset by:
•A $1.4 billion decrease in cash primarily due to fuel and purchased power expenses incurred as a result of the February 2021 severe winter weather event in SPP impacting PSO and SWEPCo. Approximately $1.1 billion of these expenses are attributable to retail customers and are recorded as deferred fuel regulatory assets. PSO and SWEPCo are working with their respective regulatory commissions to determine the recovery period from customers as well as the appropriate carrying charge on the regulatory assets. See Note 4 - Rate Matters for additional information.
•A $142 million decrease in cash due to incremental other operation and maintenance storm restoration expenses incurred by APCo, SWEPCo and KPCo as a result of the February 2021 severe winter weather event. These incremental expenses have been deferred as regulatory assets. KPCo intends to seek recovery of these incremental storm restoration costs in their next base rate case while APCo is expected to seek recovery in separate filings. In October 2021, SWEPCo requested recovery of these storm costs, in addition to storm costs from Hurricanes Delta and Laura, in a filing with the LPSC. See Note 4 - Rate Matters for additional information.

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Investing Activities

	Nine Months Ended 
September 30,	
 	2021		2020	
 	(in millions)	
Construction Expenditures	$	(4,087.0)			$	(4,690.4)		
Acquisitions of Nuclear Fuel	(63.2)			(68.4)		
	
Acquisition of the North Central Wind Energy Facilities	(652.8)			— 		
Acquisition of the Dry Lake Solar Project	(114.4)			— 		
Other	11.2 			51.5 		
Net Cash Flows Used for Investing Activities	$	(4,906.2)			$	(4,707.3)		

Net Cash Flows Used for Investing Activities increased by $199 million primarily due to the following:
•A $767 million increase due to the acquisition of the North Central Wind Energy Facilities and the Dry Lake Solar Project. See Note 6 - Acquisitions and Dispositions for additional information.
This increase in the use of cash was partially offset by:
•A $603 million decrease in construction expenditures, primarily due to decreases in Transmission and Distribution Utilities of $302 million, Vertically Integrated Utilities of $136 million and AEP Transmission Holdco of $76 million.

Financing Activities

	Nine Months Ended 
September 30,	
 	2021		2020	
 	(in millions)	
Issuance of Common Stock	$	548.0 			$	136.5 		
Issuance/Retirement of Debt, Net	3,537.2 			2,844.0 		
	
Dividends Paid on Common Stock	(1,122.7)			(1,055.7)		
Other	(40.9)			(108.5)		
Net Cash Flows from Financing Activities	$	2,921.6 			$	1,816.3 		

Net Cash Flows from Financing Activities increased by $1.1 billion primarily due to the following:
•A $1.1 billion increase in issuances of long-term debt. See Note 12 - Financing Activities for additional information.
•A $466 million increase due to changes in short-term debt. See Note 12 - Financing Activities for additional information.
•A $412 million increase in issuances of common stock primarily due to AEP’s participation in an At-the-Market offering program. See Note 12 - Financing Activities for additional information.
These increases in cash were partially offset by:
•An $849 million increase in retirements 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, 2021 through October 28, 2021, the date that the third quarter 10-Q was issued.

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BUDGETED CAPITAL EXPENDITURES

Management forecasts approximately $6.9 billion of capital expenditures in 2021. For the four year period, 2022 through 2025, management forecasts capital expenditures of $30.4 billion. The expenditures are generally for transmission, generation, distribution, regulated and contracted renewables, and required environmental investment to comply with the Federal EPA rules.  Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital.  Management expects to fund these capital expenditures through cash flows from operations and financing activities.  Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged. For complete information of forecasted capital expenditures, see the “Budgeted Capital Expenditures” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2020 Annual Report.

CONTRACTUAL OBLIGATION INFORMATION

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING STANDARDS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

ACCOUNTING STANDARDS

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

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

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

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

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

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Management employs risk management contracts including physical forward and financial forward purchase-and-sale contracts.  Management engages in risk management of power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business.  As a result, AEP is subject to price risk.  The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors.  AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures.  The Regulated Risk Committee consists of AEPSC’s Chief Financial Officer, Chief Operating Officer, Executive Vice President of Generation, Senior Vice President of Grid Solutions, Senior Vice President of Treasury and Risk and Chief Risk Officer.  The Competitive Risk Committee consists of AEPSC’s Chief Financial Officer, Senior Vice President of Treasury and Risk and Chief Risk Officer in addition to Energy Supply’s President and Senior 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 continue to be monitored, and while markets have shown improvement, credit risks remain as counterparties encounter business and supply chain disruptions.

Due to multiple defaults of market participants, ERCOT has a large outstanding unpaid balance associated with the February storm. Socialized losses are allocated to load serving entities through their qualified scheduling entities and in that role AEPEP is exposed, but not materially. If the market rules were to change on how socialized losses are allocated this could affect AEPEP’s exposure. Regardless of the approach of how socialized losses are allocated there are potential downstream impacts that could push counterparties into financial distress and or bankruptcy, affecting AEPEP, AEP Texas and ETT.
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The following table summarizes the reasons for changes in total MTM value as compared to December 31, 2020:

MTM Risk Management Contract Net Assets (Liabilities)	
Nine Months Ended September 30, 2021	
								
	Vertically
Integrated
Utilities		Transmission
and
Distribution
Utilities		Generation
&
Marketing		Total	
 	(in millions)	
Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2020	$	41.2 			$	(109.5)			$	168.1 			$	99.8 		
Gain from Contracts Realized/Settled During the Period and Entered in a Prior Period	(20.4)			(5.6)			(11.9)			(37.9)		
Fair Value of New Contracts at Inception When Entered During the Period (a)	— 			— 			1.0 			1.0 		
	
Changes in Fair Value Due to Market Fluctuations During the Period (b)	— 			— 			138.1 			138.1 		
Changes in Fair Value Allocated to Regulated Jurisdictions (c)	46.3 			26.4 			— 			72.7 		
Total MTM Risk Management Contract Net Assets (Liabilities) as of September 30, 2021	$	67.1 			$	(88.7)			$	295.3 			273.7 		
Commodity Cash Flow Hedge Contracts			 				359.5 		
Interest Rate Cash Flow Hedge Contracts			 		 		4.9 		
Fair Value Hedge Contracts			 		 		(25.4)		
Collateral Deposits			 		 		(271.3)		
	
Total MTM Derivative Contract Net Assets as of September 30, 2021			 		 		$	341.4 		

(a)Reflects fair value on primarily long-term structured contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location and delivery term. A significant portion of the total volumetric position has been economically hedged.
(b)Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(c)Relates to the net gains (losses) of those contracts that are not reflected on the statements of income.  These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable.

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

Credit Risk

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

AEP has risk management contracts (includes non-derivative contracts) with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, exposures change daily. As of September 30, 2021, credit exposure net of collateral to sub investment grade counterparties was approximately 1.8%, 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).
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As of September 30, 2021, the following table approximates AEP’s counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:

Counterparty Credit Quality		Exposure
Before
Credit
Collateral		Credit
Collateral		Net
Exposure		Number of
Counterparties
>10% of
Net Exposure		Net Exposure
of
Counterparties
>10%	
 		(in millions, except number of counterparties)	
Investment Grade		$	505.7 			$	33.6 			$	472.1 			3 			$	199.3 		

No External Ratings:		 		 				 		 	
Internal Investment Grade		80.4 			— 			80.4 			3 			61.9 		
Internal Noninvestment Grade		14.2 			4.2 			10.0 			2 			5.8 		
Total as of September 30, 2021		$	600.3 			$	37.8 			$	562.5 						

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, 2021, a near term typical change in commodity prices is not expected to materially impact net income, cash flows or financial condition.

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

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

VaR Model
Trading Portfolio

Nine Months Ended		Twelve Months Ended	
September 30, 2021		December 31, 2020	
End		High		Average		Low		End		High		Average		Low	
(in millions)		(in millions)	
$	1.7 			$	3.6 			$	0.3 			$	0.1 			$	0.1 			$	0.3 			$	0.1 			$	— 		
VaR Model
Non-Trading Portfolio

Nine Months Ended		Twelve Months Ended	
September 30, 2021		December 31, 2020	
End		High		Average		Low		End		High		Average		Low	
(in millions)		(in millions)	
$	7.7 			$	7.8 			$	2.3 			$	0.7 			$	2.2 			$	2.9 			$	1.0 			$	0.1 		

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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, 2021 and 2020, a 100 basis point change in the benchmark rate on AEP’s variable rate debt would impact pretax interest expense annually by $32 million and $18 million, respectively.
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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2021 and 2020
(in millions, except per-share and share amounts)
(Unaudited)

		Three Months Ended		Nine Months Ended	
		September 30,		September 30,	
		2021		2020		2021		2020	
REVENUES									
Vertically Integrated Utilities		$	2,716.8 			$	2,400.1 			$	7,445.9 			$	6,655.4 		
Transmission and Distribution Utilities		1,195.0 			1,124.1 			3,366.9 			3,208.7 		
Generation & Marketing		617.4 			464.8 			1,641.6 			1,223.4 		
Other Revenues		93.8 			77.4 			276.2 			220.4 		
TOTAL REVENUES		4,623.0 			4,066.4 			12,730.6 			11,307.9 		
									
EXPENSES		 		 		 		 	
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation		1,441.4 			1,200.4 			4,126.1 			3,316.3 		
	
Other Operation		735.3 			702.9 			1,894.6 			1,871.0 		
Maintenance		277.8 			237.6 			817.0 			730.5 		

Depreciation and Amortization		700.3 			644.6 			2,103.9 			1,996.3 		
Taxes Other Than Income Taxes		360.8 			337.7 			1,061.4 			976.3 		
TOTAL EXPENSES		3,515.6 			3,123.2 			10,003.0 			8,890.4 		
									
OPERATING INCOME		1,107.4 			943.2 			2,727.6 			2,417.5 		
									
Other Income (Expense):		 		 		 		 	

Other Income (Expense)		(20.6)			5.5 			34.2 			15.4 		
Allowance for Equity Funds Used During Construction		37.0 			45.2 			103.9 			111.7 		
Non-Service Cost Components of Net Periodic Benefit Cost		29.6 			29.7 			88.9 			89.2 		
	
Interest Expense		(303.7)			(291.3)			(895.5)			(877.4)		
									
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS		849.7 			732.3 			2,059.1 			1,756.4 		
									
Income Tax Expense (Benefit)		69.8 			(1.2)			185.5 			57.9 		
Equity Earnings of Unconsolidated Subsidiaries		17.0 			14.7 			75.9 			63.5 		

	

NET INCOME		796.9 			748.2 			1,949.5 			1,762.0 		
									
Net Income (Loss) Attributable to Noncontrolling Interests		0.9 			(0.4)			0.3 			(2.6)		
									
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS		$	796.0 			$	748.6 			$	1,949.2 			$	1,764.6 		
									
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING		501,233,680 			496,177,968 			499,418,278 			495,479,190 		

	
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS		$	1.59 			$	1.51 			$	3.90 			$	3.56 		
									
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING		502,606,836 			497,458,523 			500,600,237 			496,916,187 		

	
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS		$	1.58 			$	1.50 			$	3.89 			$	3.55 		

									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
55

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

		Three Months Ended		Nine Months Ended	
		September 30,		September 30,	
		2021		2020		2021		2020	
Net Income		$	796.9 			$	748.2 			$	1,949.5 			$	1,762.0 		
									
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES		 		 		 		 	
Cash Flow Hedges, Net of Tax of $47.8 and $10.5 for the Three Months Ended September 30, 2021 and 2020, Respectively, and $97.3 and $4.7 for the Nine Months Ended September 30, 2021 and 2020, Respectively		179.7 			39.3 			365.9 			17.6 		
	
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.5) and $(0.5) for the Three Months Ended September 30, 2021 and 2020, Respectively, and $(1.6) and $(1.4) for the Nine Months Ended September 30, 2021 and 2020, Respectively		(2.0)			(1.8)			(6.1)			(5.3)		
		 		 		 		 	
TOTAL OTHER COMPREHENSIVE INCOME		177.7 			37.5 			359.8 			12.3 		
									
TOTAL COMPREHENSIVE INCOME		974.6 			785.7 			2,309.3 			1,774.3 		
									
Total Comprehensive Income (Loss) Attributable To Noncontrolling Interests		0.9 			(0.4)			0.3 			(2.6)		
									
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS		$	973.7 			$	786.1 			$	2,309.0 			$	1,776.9 		
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
56

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

	AEP Common Shareholders					
	Common Stock						Accumulated
Other
Comprehensive
Income (Loss)					
	Shares		Amount		Paid-in
Capital		Retained
Earnings				Noncontrolling
Interests		Total	
TOTAL EQUITY – DECEMBER 31, 2019	514.4 			$	3,343.4 			$	6,535.6 			$	9,900.9 			$	(147.7)			$	281.0 			$	19,913.2 		
														
Issuance of Common Stock	1.0 			6.8 			49.3 			 						56.1 		
Common Stock Dividends							(359.1)		(a)			(4.6)			(363.7)		
Other Changes in Equity					(29.0)							(1.2)			(30.2)		
	
ASU 2016-13 Adoption							1.8 							1.8 		
Net Income	 		 		 		495.2 					4.1 			499.3 		
Other Comprehensive Loss	 		 		 		 		(68.8)					(68.8)		
TOTAL EQUITY – MARCH 31, 2020	515.4 			3,350.2 			6,555.9 			10,038.8 			(216.5)			279.3 			20,007.7 		
														
Issuance of Common Stock	0.8 			5.2 			49.7 			 		 		 		54.9 		
Common Stock Dividends	 		 		 		(337.7)		(a)	 		(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)		(a)			(2.0)			(351.1)		
Other Changes in Equity					(104.0)		(b)					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 		
														
TOTAL EQUITY – DECEMBER 31, 2020	516.8 			$	3,359.3 			$	6,588.9 			$	10,687.8 			$	(85.1)			$	223.6 			$	20,774.5 		
														
Issuance of Common Stock	2.7 			17.1 			167.5 									184.6 		
Common Stock Dividends							(369.5)		(c)			(2.5)			(372.0)		
Other Changes in Equity					(21.9)			(0.6)					3.4 			(19.1)		
Acquisition of Dry Lake Solar Project											18.9		18.9 		
Net Income							575.0 					3.8 			578.8 		
Other Comprehensive Income									54.3 					54.3 		
TOTAL EQUITY – MARCH 31, 2021	519.5 			3,376.4 			6,734.5 			10,892.7 			(30.8)			247.2 			21,220.0 		
														
Issuance of Common Stock	0.9 			6.3 			66.0 									72.3 		
Common Stock Dividends							(371.8)		(c)			(2.7)			(374.5)		
Other Changes in Equity					(0.2)			(0.4)					11.1 			10.5 		
	
Net Income (Loss)							578.2 					(4.4)			573.8 		
Other Comprehensive Income									127.8 					127.8 		
TOTAL EQUITY – JUNE 30, 2021	520.4 			3,382.7 			6,800.3 			11,098.7 			97.0 			251.2 			21,629.9 		
														
Issuance of Common Stock	3.4 			21.8 			269.3 					 		 		291.1 		
Common Stock Dividends	 				 		(371.7)		(c)	 		(4.5)			(376.2)		
Other Changes in Equity	 		 		6.3 					 		1.5 			7.8 		
	
Net Income	 		 		 		796.0 			 		0.9 			796.9 		
Other Comprehensive Income	 		 		 		 		177.7 			 		177.7 		
TOTAL EQUITY – SEPTEMBER 30, 2021	523.8 			$	3,404.5 			$	7,075.9 			$	11,523.0 			$	274.7 			$	249.1 			$	22,527.2 		

(a)    Cash dividends declared per AEP common share were $0.70.
(b)    Includes $(121) million related to a forward equity purchase contract associated with the issuance of Equity Units.
(c)    Cash dividends declared per AEP common share were $0.74.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
57

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2021 and December 31, 2020
(in millions)
(Unaudited)

 		September 30,		December 31,	
 		2021		2020	
CURRENT ASSETS		 		 	
Cash and Cash Equivalents		$	1,372.7 			$	392.7 		
Restricted Cash
(September 30, 2021 and December 31, 2020 Amounts Include $54 and $45.6, Respectively, Related to Transition Funding, Restoration Funding and Appalachian Consumer Rate Relief Funding)		54.0 			45.6 		
Other Temporary Investments
(September 30, 2021 and December 31, 2020 Amounts Include $211.5 and $194.6, Respectively, Related to EIS and Transource Energy)		218.4 			200.8 		
Accounts Receivable:		 		 	
Customers		701.2 			613.6 		
Accrued Unbilled Revenues		279.3 			248.7 		
Pledged Accounts Receivable – AEP Credit		1,071.1 			1,018.4 		
Miscellaneous		50.5 			33.1 		
Allowance for Uncollectible Accounts		(51.7)			(71.1)		
Total Accounts Receivable		2,050.4 			1,842.7 		
Fuel		290.1 			629.4 		
Materials and Supplies		688.4 			680.6 		
Risk Management Assets		369.2 			94.7 		
Accrued Tax Benefits		226.6 			185.3 		
Regulatory Asset for Under-Recovered Fuel Costs		307.0 			90.7 		
Margin Deposits		73.2 			62.0 		
	
Prepayments and Other Current Assets		135.1 			127.0 		
TOTAL CURRENT ASSETS		5,785.1 			4,351.5 		
					
PROPERTY, PLANT AND EQUIPMENT		 		 	
Electric:		 		 	
Generation		24,135.9 			23,133.9 		
Transmission		29,555.1 			27,886.7 		
Distribution		25,057.7 			23,972.1 		
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)		5,668.5 			5,294.6 		
Construction Work in Progress		4,151.0 			4,025.7 		
Total Property, Plant and Equipment		88,568.2 			84,313.0 		
Accumulated Depreciation and Amortization		21,877.0 			20,411.4 		
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		66,691.2 			63,901.6 		
					
OTHER NONCURRENT ASSETS		 		 	
Regulatory Assets		5,031.5 			3,527.0 		
Securitized Assets		580.4 			657.0 		
Spent Nuclear Fuel and Decommissioning Trusts		3,609.8 			3,306.7 		
Goodwill		52.5 			52.5 		
Long-term Risk Management Assets		278.3 			242.2 		
Operating Lease Assets		779.8 			866.4 		
Deferred Charges and Other Noncurrent Assets		3,528.5 			3,852.3 		
TOTAL OTHER NONCURRENT ASSETS		13,860.8 			12,504.1 		
					
TOTAL ASSETS		$	86,337.1 			$	80,757.2 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
58

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 2021 and December 31, 2020
(in millions, except per-share and share amounts)
(Unaudited)

 		 		 			September 30,		December 31,	
 							2021		2020	
CURRENT LIABILITIES		 		 	
Accounts Payable							$	1,597.1 			$	1,709.7 		
Short-term Debt:							 		 	
Securitized Debt for Receivables – AEP Credit							750.0 			592.0 		
Other Short-term Debt							1,754.0 			1,887.3 		
Total Short-term Debt							2,504.0 			2,479.3 		
Long-term Debt Due Within One Year
(September 30, 2021 and December 31, 2020 Amounts Include $203.2 and $198.3, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)			2,521.8 			2,086.1 		
Risk Management Liabilities							106.5 			78.8 		
Customer Deposits							400.2 			335.6 		
Accrued Taxes							1,046.6 			1,476.4 		
Accrued Interest							349.7 			267.6 		
Obligations Under Operating Leases							241.8 			241.3 		
Regulatory Liability for Over-Recovered Fuel Costs					3.5 			52.6 		
	
Other Current Liabilities							1,182.8 			1,199.3 		
TOTAL CURRENT LIABILITIES							9,954.0 			9,926.7 		
								
NONCURRENT LIABILITIES		 		 	
Long-term Debt
(September 30, 2021 and December 31, 2020 Amounts Include $887 and $950.1, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)			32,056.5 			28,986.4 		
Long-term Risk Management Liabilities							199.6 			232.8 		
Deferred Income Taxes							8,644.8 			8,240.9 		
Regulatory Liabilities and Deferred Investment Tax Credits			8,687.8 			8,378.7 		
Asset Retirement Obligations							2,612.0 			2,469.2 		
Employee Benefits and Pension Obligations							322.2 			336.4 		
Obligations Under Operating Leases							586.8 			638.4 		
Deferred Credits and Other Noncurrent Liabilities			672.9 			728.0 		
TOTAL NONCURRENT LIABILITIES							53,782.6 			50,010.8 		
										
TOTAL LIABILITIES							63,736.6 			59,937.5 		
										
Rate Matters (Note 4)										
Commitments and Contingencies (Note 5)										
										
MEZZANINE EQUITY					
	
Contingently Redeemable Performance Share Awards							73.3 			45.2 		
TOTAL MEZZANINE EQUITY							73.3 			45.2 		
										
EQUITY		 		 	
Common Stock – Par Value – $6.50 Per Share:							 		 	
		2021		2020			 		 	
Shares Authorized		600,000,000		600,000,000			 		 	
Shares Issued		523,773,631		516,808,354			 		 	
(20,204,160 Shares were Held in Treasury as of September 30, 2021 and December 31, 2020, Respectively)			3,404.5 			3,359.3 		
Paid-in Capital							7,075.9 			6,588.9 		
Retained Earnings							11,523.0 			10,687.8 		
Accumulated Other Comprehensive Income (Loss)			274.7 			(85.1)		
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY			22,278.1 			20,550.9 		
										
Noncontrolling Interests							249.1 			223.6 		
										
TOTAL EQUITY							22,527.2 			20,774.5 		
										
TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY		$	86,337.1 			$	80,757.2 		
										
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
59

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)
															
 		Nine Months Ended September 30,	
 		2021		2020	
OPERATING ACTIVITIES		 		 	
Net Income		$	1,949.5 			$	1,762.0 		

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:		 		 	
Depreciation and Amortization		2,103.9 			1,996.3 		
Rockport Rent, Unit 2 Operating Lease Amortization		100.8 			102.4 		
Deferred Income Taxes		191.1 			142.5 		

Allowance for Equity Funds Used During Construction		(103.9)			(111.7)		
Mark-to-Market of Risk Management Contracts		101.0 			46.4 		
Amortization of Nuclear Fuel		61.9 			67.2 		
Pension Contributions to Qualified Plan Trust		— 			(110.3)		
Property Taxes		415.1 			396.9 		
Deferred Fuel Over/Under-Recovery, Net		(1,356.8)			27.4 		

	

Change in Other Noncurrent Assets		(270.7)			(322.0)		
Change in Other Noncurrent Liabilities		162.7 			(25.1)		
Changes in Certain Components of Working Capital:		 		 	
Accounts Receivable, Net		(199.2)			(138.9)		
Fuel, Materials and Supplies		347.4 			(97.4)		
Accounts Payable		107.6 			21.9 		
Accrued Taxes, Net		(471.1)			(502.9)		
Rockport Plant, Unit 2 Operating Lease Payments		(73.9)			(73.9)		
Other Current Assets		(33.3)			26.0 		
Other Current Liabilities		(59.1)			(284.6)		
Net Cash Flows from Operating Activities		2,973.0 			2,922.2 		
					
INVESTING ACTIVITIES		 		 	
Construction Expenditures		(4,087.0)			(4,690.4)		
	
Purchases of Investment Securities		(1,612.3)			(1,329.5)		
Sales of Investment Securities		1,571.7 			1,293.0 		
Acquisitions of Nuclear Fuel		(63.2)			(68.4)		
Acquisition of the Dry Lake Solar Project		(114.4)			— 		

Acquisition of the North Central Wind Energy Facilities		(652.8)			— 		
Other Investing Activities		51.8 			88.0 		
Net Cash Flows Used for Investing Activities		(4,906.2)			(4,707.3)		
					
FINANCING ACTIVITIES		 		 	
Issuance of Common Stock		548.0 			136.5 		
Issuance of Long-term Debt		5,062.3 			3,985.8 		
Issuance of Short-term Debt with Original Maturities greater than 90 Days		1,178.5 			1,304.5 		
Change in Short-term Debt with Original Maturities less than 90 Days, Net		(632.5)			(1,445.8)		
Retirement of Long-term Debt		(1,549.8)			(700.5)		
	
Redemption of Short-term Debt with Original Maturities Greater than 90 Days		(521.3)			(300.0)		
Principal Payments for Finance Lease Obligations		(45.3)			(46.3)		
Dividends Paid on Common Stock		(1,122.7)			(1,055.7)		
Redemption of Noncontrolling Interest in Trent and Desert Sky Windfarms		— 			(56.5)		
Other Financing Activities		4.4 			(5.7)		
Net Cash Flows from Financing Activities		2,921.6 			1,816.3 		

	

Net Increase in Cash and Cash Equivalents		988.4 			31.2 		
Cash, Cash Equivalents and Restricted Cash at Beginning of Period		438.3 			432.6 		
Cash, Cash Equivalents and Restricted Cash at End of Period		$	1,426.7 			$	463.8 		
					
SUPPLEMENTARY INFORMATION					
Cash Paid for Interest, Net of Capitalized Amounts		$	775.2 			$	690.5 		
Net Cash Paid (Received) for Income Taxes		9.3 			(23.9)		
Noncash Acquisitions Under Finance Leases		23.0 			33.0 		
Construction Expenditures Included in Current Liabilities as of September 30,		764.1 			830.1 		
Construction Expenditures Included in Noncurrent Liabilities as of September 30,		— 			8.3 		
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,		0.3 			1.0 		
	
Noncash Contribution of Assets to Cedar Creek Project		(9.3)			— 		
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage		0.6 			2.4 		
Noncontrolling Interest Assumed - Dry Lake Solar Project		35.0 			— 		
	
Forward Equity Purchase Contract Included in Current and Noncurrent Liabilities as of September 30,		— 			120.6 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
60

AEP TEXAS INC.
AND SUBSIDIARIES

61

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,	
 	2021		2020		2021		2020	
 	(in millions of KWhs)	
Retail:	 		 					
Residential	3,997 			4,112 			9,821 			9,736 		
Commercial	3,014 			2,941 			7,907 			7,700 		
Industrial	2,414 			2,037 			6,898 			6,618 		
Miscellaneous	182 			184 			478 			486 		
Total Retail	9,607 			9,274 			25,104 			24,540 		

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,	
 	2021		2020		2021		2020	
 	(in degree days)	
Actual – Heating (a)	— 			1 			319 			98 		
Normal – Heating (b)	— 			— 			188 			188 		
								
Actual – Cooling (c)	1,308 			1,357 			2,278 			2,524 		
Normal – Cooling (b)	1,379 			1,378 			2,436 			2,436 		

(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.

62

Third Quarter of 2021 Compared to Third Quarter of 2020

AEP Texas Inc. and Subsidiaries	
Reconciliation of Third Quarter of 2020 to Third Quarter of 2021	
Net Income	
(in millions)	
	
Third Quarter of 2020		$	82.6 		
 		 	
Changes in Gross Margin:			
Retail Margins		29.8 		
Margins from Off-system Sales		(30.1)		
Transmission Revenues		29.7 		
Other Revenues		(18.4)		
Total Change in Gross Margin		11.0 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(2.6)		
Depreciation and Amortization		20.1 		
Taxes Other Than Income Taxes		(2.9)		
	
Interest Income		(0.3)		
	
Allowance for Equity Funds Used During Construction		4.8 		
	
Interest Expense		0.3 		
Total Change in Expenses and Other		19.4 		
 		 	
Income Tax Expense		(13.5)		
 		 	
Third Quarter of 2021		$	99.5 		

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

•Retail Margins increased $30 million primarily due to the following:
•A $22 million increase due to prior year refunds of Excess ADIT and excess federal income taxes collected as a result of Tax Reform. This increase was partially offset in Income Tax Expense below.
•A $13 million increase from interim rate increases driven by increased distribution investment.
•A $3 million increase from interim rate increases driven by increased transmission investment.
These increases were partially offset by:
•A $9 million decrease in weather-normalized margins primarily in the industrial class.
•A $3 million decrease in weather-related usage primarily due to a 4% decrease in cooling degree days.
•Margins from Off-system Sales decreased $30 million primarily due to the retirement of the Oklaunion Power Station in September 2020. This decrease was partially offset in Depreciation and Amortization expenses below.
•Transmission Revenues increased $30 million primarily due to the following:
•A $20 million increase from interim rate increases driven by increased transmission investment.
•An $8 million increase due to prior year refunds to customers associated with the most recent base rate case. This increase was offset in Other Revenues below.
•Other Revenues decreased $18 million primarily due to the following:
•A $10 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.
•An $8 million decrease due to prior year refunds to customers associated with the most recent base rate case. This decrease was partially offset in Retail Margins and Transmission Revenues above.

63

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 $5 million increase in transmission expenses. This increase was partially offset in Gross Margin above.
•A $2 million increase in distribution-related expenses.
These increases were partially offset by:
•A $5 million decrease due to the prior year write-off of land associated with the Oklaunion Power Station.
•Depreciation and Amortization expenses decreased $20 million primarily due to the following:
•A $16 million decrease in depreciation expense due to the retirement of the Oklaunion Power Station in September 2020. This decrease was partially offset above in Margins from Off-system Sales and Other Operation and Maintenance expenses.
•A $9 million decrease in securitization amortizations primarily related to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset in Other Revenues above.
These decreases were partially offset by:
•A $7 million increase in depreciation expense due to an increase in the depreciable base of transmission
and distribution assets.
•Allowance for Equity Funds Used During Construction increased $5 million due to a current year adjustment to rates.
•Income Tax Expense increased $14 million primarily due to an increase in pretax book income, a decrease in amortization of Excess ADIT and the recognition of a favorable discrete adjustment in the prior year. The decrease in amortization of Excess ADIT was partially offset above in Gross Margin.
64

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020

AEP Texas Inc. and Subsidiaries	
Reconciliation of Nine Months Ended September 30, 2020 to Nine Months Ended September 30, 2021	
Net Income	
(in millions)	
	
Nine Months Ended September 30, 2020		$	197.1 		
 		 	
Changes in Gross Margin:			
Retail Margins		54.2 		
Margins from Off-system Sales		(73.2)		
Transmission Revenues		74.5 		
Other Revenues		(103.7)		
Total Change in Gross Margin		(48.2)		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(18.1)		
Depreciation and Amortization		148.7 		
Taxes Other Than Income Taxes		(10.7)		
	
Interest Income		(0.6)		
	
Allowance for Equity Funds Used During Construction		2.3 		
Non-Service Cost Components of Net Periodic Benefit Cost		(0.1)		
Interest Expense		(3.3)		
Total Change in Expenses and Other		118.2 		
 		 	
Income Tax Expense		(41.7)		
 		 	
Nine Months Ended September 30, 2021		$	225.4 		

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 $54 million primarily due to the following:
•A $34 million increase from interim rate increases driven by increased distribution investment.
•An $18 million increase from interim rate increases driven by increased transmission investment.
•A $10 million increase in weather-related usage primarily due to a 226% increase in heating degree days partially offset by a 10% decrease in cooling degree days.
These increases were partially offset by:
•An $8 million decrease in weather-normalized margins primarily in the industrial class.
•Margins from Off-system Sales decreased $73 million primarily due to the retirement of the Oklaunion Power Station in September 2020. This decrease was partially offset in Depreciation and Amortization expenses below.
•Transmission Revenues increased $75 million primarily due to the following:
•A $59 million increase from interim rate increases driven by increased transmission investment.
•A $14 million increase due to a prior year one-time credit to transmission customers as a result of Tax Reform and the most recent base rate case. This increase was offset in Income Tax Expense below.
•Other Revenues decreased $104 million primarily due to securitization revenues driven by 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.

65

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

•Other Operation and Maintenance expenses increased $18 million primarily due to the following:
•A $17 million increase due to the prior year revision of the Oklaunion Power Station ARO. This increase was offset in Margins from Off-System Sales above.
•An $8 million increase in transmission expenses. This increase was partially offset in Gross Margin above.
These increases were partially offset by:
•A $5 million decrease due to the prior year write-off of land associated with the Oklaunion Power Station.
•Depreciation and Amortization expenses decreased $149 million primarily due to the following:
•A $102 million decrease in securitization amortizations primarily related to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset in Other Revenues above.
•A $48 million decrease in depreciation expense due to the retirement of the Oklaunion Power Station in September 2020. This decrease was partially offset above in Margins from Off-system Sales and Other Operation and Maintenance expenses.
•Taxes Other Than Income Taxes increased $11 million primarily due to property taxes as a result of increased distribution and transmission investment.
•Interest Expense increased $3 million primarily due to higher long-term debt balances.
•Income Tax Expense increased $42 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 was partially offset above in Gross Margin.
66

AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

 	 	Three Months Ended		Nine Months Ended	
		September 30,		September 30,	
 	 	2021	 	2020		2021		2020	
REVENUES	 	 	 	 					
Electric Transmission and Distribution	 	$	430.8 			$	390.1 			$	1,189.1 			$	1,165.2 		
Sales to AEP Affiliates	 	0.9 			41.4 			2.9 			89.4 		
Other Revenues	 	0.9 			0.5 			3.3 			2.5 		
TOTAL REVENUES	 	432.6 			432.0 			1,195.3 			1,257.1 		
	 								
EXPENSES	 	 		 		 		 	
Fuel and Other Consumables Used for Electric Generation		— 			10.4 			— 			13.6 		
Other Operation	 	135.3 			134.3 			367.1 			344.7 		
Maintenance	 	22.0 			20.4 			59.8 			64.1 		
Depreciation and Amortization	 	87.6 			107.7 			287.1 			435.8 		
Taxes Other Than Income Taxes	 	41.6 			38.7 			117.4 			106.7 		
TOTAL EXPENSES	 	286.5 			311.5 			831.4 			964.9 		
	 								
OPERATING INCOME	 	146.1 			120.5 			363.9 			292.2 		
	 								
Other Income (Expense):	 	 		 		 		 	
Interest Income	 	0.2 			0.5 			0.6 			1.2 		
	
Allowance for Equity Funds Used During Construction		9.2 			4.4 			16.7 			14.4 		
	
Non-Service Cost Components of Net Periodic Benefit Cost		2.8 			2.8 			8.3 			8.4 		
Interest Expense	 	(44.2)			(44.5)			(132.5)			(129.2)		
	 								
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	 	114.1 			83.7 			257.0 			187.0 		
	 								
Income Tax Expense (Benefit)	 	14.6 			1.1 			31.6 			(10.1)		
									
NET INCOME	 	$	99.5 			$	82.6 			$	225.4 			$	197.1 		
									
The common stock of AEP Texas is wholly-owned by Parent.	
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
67

AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

 		Three Months Ended		Nine Months Ended	
		September 30,		September 30,	
		2021		2020		2021		2020	
Net Income		$	99.5 			$	82.6 			$	225.4 			$	197.1 		
 									
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, 2021 and 2020, Respectively, and $0.2 and $0.2 for the Nine Months Ended September 30, 2021 and 2020, 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, 2021 and 2020, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2021 and 2020, Respectively		— 			— 			0.1 			0.1 		
									
TOTAL OTHER COMPREHENSIVE INCOME		0.3 			0.3 			0.9 			0.9 		
									
TOTAL COMPREHENSIVE INCOME		$	99.8 			$	82.9 			$	226.3 			$	198.0 		
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	

68

AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

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

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

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

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

Net Income		 		79.8 					79.8 		
Other Comprehensive Income		 				0.3 			0.3 		
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2021		1,457.9 			1,882.9 			(8.3)			3,332.5 		

Net Income				99.5 					99.5 		
Other Comprehensive Income						0.3 			0.3 		
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2021		$	1,457.9 			$	1,982.4 			$	(8.0)			$	3,432.3 		
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	

69

AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2021 and December 31, 2020
(in millions)
(Unaudited)

 	 	September 30,		December 31,	
 	 	2021	 	2020	
CURRENT ASSETS	 	 	 	 	
Cash and Cash Equivalents		$	0.1 			$	0.1 		
Restricted Cash
(September 30, 2021 and December 31, 2020 Amounts Include $43.9 and $28.7, Respectively, Related to Transition Funding and Restoration Funding)		43.9 			28.7 		
Advances to Affiliates		54.6 			7.1 		
Accounts Receivable:	 	 		 	
Customers	 	142.1 			112.8 		
Affiliated Companies	 	4.8 			5.1 		
Accrued Unbilled Revenues		81.0 			65.8 		
	
Allowance for Uncollectible Accounts		(4.1)			(0.1)		
Total Accounts Receivable	 	223.8 			183.6 		
	
Materials and Supplies	 	72.5 			70.0 		
	
Accrued Tax Benefits		23.7 			16.8 		
Prepayments and Other Current Assets	 	6.9 			4.6 		
TOTAL CURRENT ASSETS	 	425.5 			310.9 		
	 				
PROPERTY, PLANT AND EQUIPMENT	 	 		 	
Electric:	 	 		 	
	
Transmission	 	5,627.1 			5,279.6 		
Distribution	 	4,823.7 			4,580.8 		
Other Property, Plant and Equipment	 	944.3 			868.4 		
Construction Work in Progress	 	539.4 			614.1 		
Total Property, Plant and Equipment	 	11,934.5 			11,342.9 		
Accumulated Depreciation and Amortization	 	1,621.1 			1,529.3 		
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	 	10,313.4 			9,813.6 		
	 				
OTHER NONCURRENT ASSETS	 	 		 	
Regulatory Assets	 	290.4 			266.8 		
Securitized Assets
(September 30, 2021 and December 31, 2020 Amounts Include $389.1 and $446.8, Respectively, Related to Transition Funding and Restoration Funding)		389.1 			446.8 		
	
Deferred Charges and Other Noncurrent Assets	 	213.1 			192.1 		
TOTAL OTHER NONCURRENT ASSETS	 	892.6 			905.7 		
	 				
TOTAL ASSETS	 	$	11,631.5 			$	11,030.2 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
70

AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2021 and December 31, 2020
(in millions)
(Unaudited)

 	 	September 30,		December 31,	
 	 	2021	 	2020	
CURRENT LIABILITIES	 				
Advances from Affiliates	 	$	— 			$	67.1 		
Accounts Payable:	 				
General	 	194.3 			231.7 		
Affiliated Companies	 	29.4 			44.0 		
	
Long-term Debt Due Within One Year – Nonaffiliated
(September 30, 2021 and December 31, 2020 Amounts Include $90.1 and $88.7, Respectively, Related to Transition Funding and Restoration Funding)		315.1 			88.7 		

Accrued Taxes	 	114.7 			78.3 		
Accrued Interest
(September 30, 2021 and December 31, 2020 Amounts Include $3 and $2.5, Respectively, Related to Transition Funding and Restoration Funding)		60.7 			43.9 		
	
Obligations Under Operating Leases		14.1 			14.5 		
	
Other Current Liabilities	 	98.4 			108.6 		
TOTAL CURRENT LIABILITIES	 	826.7 			676.8 		
	 				
NONCURRENT LIABILITIES	 	 		 	
Long-term Debt – Nonaffiliated
(September 30, 2021 and December 31, 2020 Amounts Include $350.9 and $403.9, Respectively, Related to Transition Funding and Restoration Funding)		4,901.0 			4,731.7 		
	
Deferred Income Taxes	 	1,087.1 			1,016.7 		
Regulatory Liabilities and Deferred Investment Tax Credits	 	1,256.8 			1,270.8 		
	
Obligations Under Operating Leases		64.5 			71.0 		
Deferred Credits and Other Noncurrent Liabilities	 	63.1 			57.2 		
TOTAL NONCURRENT LIABILITIES	 	7,372.5 			7,147.4 		
	 				
TOTAL LIABILITIES	 	8,199.2 			7,824.2 		
	 				
Rate Matters (Note 4)					
Commitments and Contingencies (Note 5)	 				
	 				
COMMON SHAREHOLDER’S EQUITY	 	 		 	
Paid-in Capital	 	1,457.9 			1,457.9 		
Retained Earnings	 	1,982.4 			1,757.0 		
Accumulated Other Comprehensive Income (Loss)		(8.0)			(8.9)		
TOTAL COMMON SHAREHOLDER’S EQUITY	 	3,432.3 			3,206.0 		
	 				
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	 	$	11,631.5 			$	11,030.2 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
71

AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

 	 	Nine Months Ended September 30,	
 	 	2021	 	2020	
OPERATING ACTIVITIES	 	 	 	 	
Net Income	 	$	225.4 			$	197.1 		
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:	 	 		 	
Depreciation and Amortization	 	287.1 			435.8 		
Deferred Income Taxes	 	45.8 			(11.5)		
Allowance for Equity Funds Used During Construction		(16.7)			(14.4)		
Mark-to-Market of Risk Management Contracts	 	— 			0.1 		
Pension Contributions to Qualified Plan Trust		— 			(11.3)		

Change in Other Noncurrent Assets	 	(73.4)			(77.3)		
Change in Other Noncurrent Liabilities	 	17.5 			(30.0)		
Changes in Certain Components of Working Capital:	 	 			
Accounts Receivable, Net	 	(40.2)			(40.2)		
Fuel, Materials and Supplies	 	(2.5)			(9.4)		
Accounts Payable	 	(10.9)			24.2 		
	
Accrued Taxes, Net		29.5 			73.4 		
	
Other Current Assets	 	(2.0)			(0.8)		
Other Current Liabilities	 	(5.0)			(49.8)		
Net Cash Flows from Operating Activities	 	454.6 			485.9 		
	 				
INVESTING ACTIVITIES	 	 		 	
Construction Expenditures	 	(742.4)			(976.1)		
Change in Advances to Affiliates, Net		(47.5)			58.8 		
	
Other Investing Activities		29.6 			24.1 		
Net Cash Flows Used for Investing Activities	 	(760.3)			(893.2)		
	 				
FINANCING ACTIVITIES	 	 		 	
	
Issuance of Long-term Debt – Nonaffiliated		444.2 			652.8 		
Change in Short-term Debt, Net – Nonaffiliated		— 			2.0 		
Change in Advances from Affiliates, Net	 	(67.1)			— 		
Retirement of Long-term Debt – Nonaffiliated	 	(52.2)			(356.5)		
Principal Payments for Finance Lease Obligations	 	(5.0)			(4.7)		
	
Other Financing Activities		1.0 			0.8 		
Net Cash Flows from Financing Activities	 	320.9 			294.4 		
					
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	 	15.2 			(112.9)		
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	 	28.8 			157.8 		
Cash, Cash Equivalents and Restricted Cash at End of Period	 	$	44.0 			$	44.9 		
	 				
SUPPLEMENTARY INFORMATION	 	 		 	
Cash Paid for Interest, Net of Capitalized Amounts	 	$	110.0 			$	102.0 		
Net Cash Paid (Received) for Income Taxes	 	(8.4)			(55.6)		
Noncash Acquisitions Under Finance Leases	 	3.3 			5.1 		
Construction Expenditures Included in Current Liabilities as of September 30,	 	134.9 			167.6 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
72

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
73

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,	
		2021		2020	
		(in millions)	
Plant In Service		$	10,851.9 			$	9,240.4 		
Construction Work in Progress		1,507.4 			1,680.9 		
Accumulated Depreciation and Amortization		730.4 			531.8 		
Total Transmission Property, Net		$	11,628.9 			$	10,389.5 		

Third Quarter of 2021 Compared to Third Quarter of 2020

AEP Transmission Company, LLC and Subsidiaries	
Reconciliation of Third Quarter of 2020 to Third Quarter of 2021	
Net Income	
(in millions)	
			
Third Quarter of 2020		$	117.6 		
			
Changes in Transmission Revenues:			
Transmission Revenues		72.9 		
Total Change in Transmission Revenues		72.9 		
			
Changes in Expenses and Other:			
Other Operation and Maintenance		(9.2)		
Depreciation and Amortization		(14.5)		
Taxes Other Than Income Taxes		(8.8)		
	
Allowance for Equity Funds Used During Construction		(4.2)		
Interest Expense		(3.4)		
Total Change in Expenses and Other		(40.1)		
			
Income Tax Expense		(5.0)		

Third Quarter of 2021		$	145.4 		

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

•Transmission Revenues increased $73 million primarily due to continued investment in transmission assets.

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

•Other Operation and Maintenance expenses increased $9 million primarily due to the following:
•A $2 million increase in vegetation management expenses.
•A $2 million increase in an accrual for NERC compliance costs.
•A $2 million increase in employee-related expenses.
•A $1 million increase in rent expense.
•Depreciation and Amortization expenses increased $15 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxes increased $9 million primarily due to higher property taxes as a result of increased transmission investment.
•Allowance for Equity Funds Used During Construction decreased $4 million primarily due to lower CWIP.
•Interest Expense increased $3 million primarily due to higher long-term debt balances.
•Income Tax Expense increased $5 million primarily due to an increase in pretax book income.
74

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020

AEP Transmission Company, LLC and Subsidiaries	
Reconciliation of Nine Months Ended September 30, 2020 to Nine Months Ended September 30, 2021	
Net Income	
(in millions)	
	
Nine Months Ended September 30, 2020		$	309.1 		
 		 	
Changes in Transmission Revenues:		 	
Transmission Revenues		266.4 		
Total Change in Transmission Revenues		266.4 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(11.6)		
Depreciation and Amortization		(42.6)		
Taxes Other Than Income Taxes		(26.1)		
Interest Income		(1.9)		
Allowance for Equity Funds Used During Construction		(5.6)		
Interest Expense		(9.4)		
Total Change in Expenses and Other		(97.2)		
 		 	
Income Tax Expense		(32.6)		
 		 	
Nine Months Ended September 30, 2021		$	445.7 		

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

•Transmission Revenues increased $266 million primarily due to the following:
•A $204 million increase due to continued investment in transmission assets.
•A $45 million increase 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 $14 million increase 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 $12 million primarily due to the following:
•A $4 million increase in vegetation management expenses.
•A $2 million increase in an accrual for NERC compliance costs.
•A $2 million increase in rent expense.
•A $1 million increase in property insurance premiums.
•Depreciation and Amortization expenses increased $43 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxes increased $26 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 lower CWIP.
•Interest Expense increased $9 million primarily due to higher long-term debt balances.
•Income Tax Expense increased $33 million primarily due to an increase in pretax book income.

75

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

		Three Months Ended		Nine Months Ended	
		September 30,		September 30,	
		2021	 	2020	 	2021	 	2020	
REVENUES									
Transmission Revenues		$	79.2 			$	62.9 			$	239.3 			$	184.6 		
Sales to AEP Affiliates		297.6 			241.2 			864.6 			652.6 		
Other Revenues		0.2 			— 			0.3 			0.6 		
TOTAL REVENUES		377.0 			304.1 			1,104.2 			837.8 		
									
EXPENSES		 		 		 		 	
Other Operation		32.6 			25.3 			78.1 			72.0 		
Maintenance		5.4 			3.5 			12.3 			6.8 		
Depreciation and Amortization		76.0 			61.5 			219.0 			176.4 		
Taxes Other Than Income Taxes		61.0 			52.2 			178.9 			152.8 		
TOTAL EXPENSES		175.0 			142.5 			488.3 			408.0 		
									
OPERATING INCOME		202.0 			161.6 			615.9 			429.8 		
									
Other Income (Expense):		 		 		 		 	
Interest Income - Affiliated		0.2 			0.2 			0.4 			2.3 		
Allowance for Equity Funds Used During Construction		16.0 			20.2 			49.3 			54.9 		
	
Interest Expense		(36.1)			(32.7)			(104.5)			(95.1)		
									
INCOME BEFORE INCOME TAX EXPENSE		182.1 			149.3 			561.1 			391.9 		
									
Income Tax Expense		36.7 			31.7 			115.4 			82.8 		
									
NET INCOME		$	145.4 			$	117.6 			$	445.7 			$	309.1 		
									
AEPTCo is wholly-owned by AEP Transmission Holdco.	
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
76

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY
For the Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

 	 	Paid-in
Capital		Retained
Earnings		Total	
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2019	 	$	2,480.6 			$	1,528.9 			$	4,009.5 		
 	 						
Capital Contribution from Member		185.0 					185.0 		
Net Income		 		117.8 			117.8 		
TOTAL MEMBER'S EQUITY – MARCH 31, 2020		2,665.6 			1,646.7 			4,312.3 		

Dividends Paid to Member				(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 		
 	 						
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2020	 	$	2,765.6 			$	1,947.3 			$	4,712.9 		
							
Capital Contribution from Member		124.0 					124.0 		
Net Income				151.7 			151.7 		
TOTAL MEMBER'S EQUITY – MARCH 31, 2021		2,889.6 			2,099.0 			4,988.6 		
 	 						
Capital Contribution from Member		60.0 					60.0 		
	
Net Income				148.6 			148.6 		
TOTAL MEMBER'S EQUITY – JUNE 30, 2021		2,949.6 			2,247.6 			5,197.2 		

Dividends Paid to Member				(112.5)			(112.5)		
Net Income	 	 		145.4 			145.4 		
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2021	 	$	2,949.6 			$	2,280.5 			$	5,230.1 		
							
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
77

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2021 and December 31, 2020
(in millions)
(Unaudited)

 	 	September 30,	 	December 31,	
 	 	2021	 	2020	
CURRENT ASSETS	 	 	 	 	
Advances to Affiliates	 	$	79.2 			$	109.1 		
Accounts Receivable:	 				
Customers	 	31.0 			22.9 		
Affiliated Companies	 	96.7 			81.2 		
	
Total Accounts Receivable	 	127.7 			104.1 		
Materials and Supplies	 	9.0 			8.5 		
	
Prepayments and Other Current Assets	 	3.5 			14.1 		
TOTAL CURRENT ASSETS	 	219.4 			235.8 		
	 				
TRANSMISSION PROPERTY	 	 		 	
Transmission Property	 	10,458.4 			9,593.5 		
Other Property, Plant and Equipment	 	393.5 			329.5 		
Construction Work in Progress	 	1,507.4 			1,422.6 		
Total Transmission Property	 	12,359.3 			11,345.6 		
Accumulated Depreciation and Amortization	 	730.4 			572.8 		
TOTAL TRANSMISSION PROPERTY – NET	 	11,628.9 			10,772.8 		
	 				
OTHER NONCURRENT ASSETS	 	 		 	
	
Regulatory Assets	 	10.1 			15.1 		
Deferred Property Taxes	 	66.1 			220.1 		
Deferred Charges and Other Noncurrent Assets	 	6.6 			2.2 		
TOTAL OTHER NONCURRENT ASSETS	 	82.8 			237.4 		
	 				
TOTAL ASSETS	 	$	11,931.1 			$	11,246.0 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
78

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND MEMBER’S EQUITY
September 30, 2021 and December 31, 2020
(in millions)
(Unaudited)

 	 	September 30,	 	December 31,	
 	 	2021	 	2020	
CURRENT LIABILITIES	 	 	 	 	
Advances from Affiliates	 	$	13.9 			$	156.7 		
Accounts Payable:	 			 	
General	 	298.8 			380.4 		
Affiliated Companies	 	67.6 			97.3 		
	
Long-term Debt Due Within One Year – Nonaffiliated		50.0 			50.0 		
Accrued Taxes	 	269.5 			418.1 		
Accrued Interest	 	50.2 			23.9 		
Obligations Under Operating Leases		0.9 			1.2 		
Other Current Liabilities	 	8.1 			9.9 		
TOTAL CURRENT LIABILITIES	 	759.0 			1,137.5 		
	 				
NONCURRENT LIABILITIES	 	 		 	
Long-term Debt – Nonaffiliated	 	4,343.4 			3,898.5 		
Deferred Income Taxes	 	955.2 			906.9 		
Regulatory Liabilities	 	633.9 			581.8 		
Obligations Under Operating Leases		1.0 			0.4 		
Deferred Credits and Other Noncurrent Liabilities	 	8.5 			8.0 		
TOTAL NONCURRENT LIABILITIES	 	5,942.0 			5,395.6 		
	 				
TOTAL LIABILITIES	 	6,701.0 			6,533.1 		
	 				
Rate Matters (Note 4)	 				
Commitments and Contingencies (Note 5)	 				
	 				
MEMBER’S EQUITY	 	 		 	
Paid-in Capital		2,949.6 			2,765.6 		
Retained Earnings	 	2,280.5 			1,947.3 		
TOTAL MEMBER’S EQUITY	 	5,230.1 			4,712.9 		
	 				
TOTAL LIABILITIES AND MEMBER’S EQUITY	 	$	11,931.1 			$	11,246.0 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
79

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

 	 	Nine Months Ended September 30,	
 	 	2021		2020	
OPERATING ACTIVITIES	 				
Net Income	 	$	445.7 			$	309.1 		
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:	 				
Depreciation and Amortization	 	219.0 			176.4 		
Deferred Income Taxes	 	46.8 			65.4 		
Allowance for Equity Funds Used During Construction	 	(49.3)			(54.9)		
Property Taxes	 	154.0 			136.3 		
	
Change in Other Noncurrent Assets	 	2.3 			(1.5)		
Change in Other Noncurrent Liabilities	 	8.3 			19.5 		
Changes in Certain Components of Working Capital:	 			 	
Accounts Receivable, Net	 	(23.6)			(30.1)		
Materials and Supplies		(0.5)			0.2 		
Accounts Payable	 	(10.7)			26.0 		
Accrued Taxes, Net	 	(138.8)			(139.0)		
Accrued Interest	 	26.3 			29.0 		
Other Current Assets	 	0.5 			9.1 		
Other Current Liabilities	 	(3.6)			(10.7)		
Net Cash Flows from Operating Activities	 	676.4 			534.8 		
	 				
INVESTING ACTIVITIES	 	 		 	
Construction Expenditures	 	(1,070.8)			(1,163.8)		
Change in Advances to Affiliates, Net	 	29.9 			(21.3)		

Other Investing Activities	 	(7.9)			1.1 		
Net Cash Flows Used for Investing Activities	 	(1,048.8)			(1,184.0)		
	 				
FINANCING ACTIVITIES	 			 	
Capital Contributions from Member	 	184.0 			185.0 		
Issuance of Long-term Debt – Nonaffiliated		443.7 			519.4 		
Change in Advances from Affiliates, Net	 	(142.8)			(50.2)		
Dividends Paid to Member		(112.5)			(5.0)		
	
Net Cash Flows from Financing Activities	 	372.4 			649.2 		
	 				
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	 	$	75.8 			$	63.3 		
Net Cash Paid for Income Taxes	 	37.6 			1.9 		
Construction Expenditures Included in Current Liabilities as of September 30,	 	206.8 			283.6 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
80

APPALACHIAN POWER COMPANY
AND SUBSIDIARIES
81

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,	
	2021		2020		2021		2020	
 	(in millions of KWhs)	
Retail:	 		 		 		 	
Residential	2,657 			2,772 			8,524 			8,229 		
Commercial	1,596 			1,612 			4,483 			4,410 		
Industrial	2,223 			2,193 			6,590 			6,507 		
Miscellaneous	206 			203 			602 			585 		
Total Retail	6,682 			6,780 			20,199 			19,731 		
								
Wholesale	1,414 			1,187 			3,636 			2,894 		
								
Total KWhs	8,096 			7,967 			23,835 			22,625 		

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,	
	2021		2020		2021		2020	
 	(in degree days)	
Actual – Heating (a)	— 			1 			1,397 			1,098 		
Normal – Heating (b)	2 			2 			1,404 			1,413 		
								
Actual – Cooling (c)	945 			988 			1,330 			1,354 		
Normal – Cooling (b)	831 			825 			1,214 			1,208 		

(a)Heating degree days are calculated on a 55 degree temperature base.
(b)Normal Heating/Cooling represents the thirty-year average of degree days.
(c)Cooling degree days are calculated on a 65 degree temperature base.

82

Third Quarter of 2021 Compared to Third Quarter of 2020

Appalachian Power Company and Subsidiaries	
Reconciliation of Third Quarter of 2020 to Third Quarter of 2021	
Net Income	
(in millions)	
	
Third Quarter of 2020		$	116.6 		
 		 	
Changes in Gross Margin:		 	
Retail Margins		40.7 		
Margins from Off-system Sales		0.5 		
Transmission Revenues		7.7 		
Other Revenues		(0.3)		
Total Change in Gross Margin		48.6 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(53.8)		
Depreciation and Amortization		(12.2)		
Taxes Other Than Income Taxes		(1.0)		
Interest Income		(0.4)		
	
Allowance for Equity Funds Used During Construction		(2.4)		
	
Interest Expense		2.2 		
Total Change in Expenses and Other		(67.6)		
 		 	
Income Tax Expense		(11.3)		
 		 	
Third Quarter of 2021		$	86.3 		

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

•Retail Margins increased $41 million primarily due to the following:
•A $40 million increase due to rider revenues primarily in Virginia. This increase was partially offset in other expense items below.
•A $10 million increase due to lower customer refunds related to Tax Reform. This increase was partially offset in Income Tax Expense below.
•A $6 million increase in weather-normalized margins driven by an increase in the industrial class, partially offset by a decrease in the residential class.
These increases were partially offset by:
•An $11 million decrease in deferred fuel primarily due to the timing of expenses recovered through the Expanded Net Energy Cost (ENEC). This decrease was offset in expense items below.
•A $4 million decrease in weather-related usage primarily driven by a 4% decrease in cooling degree days.
•Transmission Revenues increased $8 million primarily due to an increase in transmission investment. This increase was partially offset in Depreciation and Amortization expenses below.

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

•Other Operation and Maintenance expenses increased $54 million primarily due to the following:
•A $33 million increase in recoverable PJM transmission expenses. This increase was partially offset in Retail Margins above.
•A $13 million increase in vegetation management expenses. This increase was partially offset in Retail Margins above.
•Depreciation and Amortization expenses increased $12 million primarily due to an increase in depreciation rates in Virginia and a higher depreciable base. This increase was partially offset in Retail Margins and Transmission Revenues above.
83

•Income Tax Expense increased $11 million primarily due to a decrease in amortization of Excess ADIT. This increase was partially offset in Retail Margins above.
84

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020

Appalachian Power Company and Subsidiaries	
Reconciliation of Nine Months Ended September 30, 2020 to Nine Months Ended September 30, 2021	
Net Income	
(in millions)	
	
Nine Months Ended September 30, 2020		$	313.2 		
 			
Changes in Gross Margin:		 	
Retail Margins		103.0 		
Margins from Off-system Sales		2.8 		
Transmission Revenues		21.9 		
Other Revenues		(1.2)		
Total Change in Gross Margin		126.5 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(98.7)		
Depreciation and Amortization		(40.6)		
Taxes Other Than Income Taxes		(2.5)		
Interest Income		(0.6)		
	
Allowance for Equity Funds Used During Construction		0.6 		
Non-Service Cost Components of Net Periodic Benefit Cost		0.1 		
Interest Expense		1.6 		
Total Change in Expenses and Other		(140.1)		
 		 	
Income Tax Expense		(24.5)		
 		 	
Nine Months Ended September 30, 2021		$	275.1 		

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 $103 million primarily due to the following:
•A $63 million increase due to rider revenues in Virginia and West Virginia. This increase was partially offset in other expense items below.
•A $30 million increase in weather-related usage primarily driven by a 27% increase in heating degree days.
•A $10 million increase in weather-normalized margins primarily driven by increases in the commercial and industrial classes, partially offset by a decrease in the residential class.
•A $9 million increase due to lower customer refunds related to Tax Reform. This increase was partially offset in Income Tax Expense below.
These increases were partially offset by:
•A $7 million decrease in deferred fuel primarily due to the timing of expenses recovered through the ENEC. This decrease was offset in expense items below.
•Transmission Revenues increased $22 million primarily due to an increase in transmission investment. This increase was partially offset in Depreciation and Amortization expenses below.

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

•Other Operation and Maintenance expenses increased $99 million primarily due to the following:
•A $44 million increase in recoverable PJM transmission expenses. This increase was partially offset in Retail Margins above.
•A $40 million increase in vegetation management expenses. This increase was partially offset in Retail Margins above.
85

•A $13 million increase in PJM transmission expenses as a result of the annual transmission formula rate true-up. This increase was partially offset in Retail Margins above.
•A $7 million increase due to the current year amortization of regulatory assets related to the 2017-2019 Virginia triennial review which authorized regulatory recovery of previously retired coal-fired generation assets.
These increases were partially offset by:
•A $6 million decrease in distribution expenses related to storm restoration costs.
•Depreciation and Amortization expenses increased $41 million primarily due to an increase in depreciation rates in Virginia and a higher depreciable base. This increase was partially offset in Retail Margins and Transmission Revenues above.
•Income Tax Expense increased $25 million primarily due to a decrease in amortization of Excess ADIT. This increase was partially offset in Retail Margins above.

86

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

 		Three Months Ended		Nine Months Ended	
 		September 30,		September 30,	
 		2021		2020		2021		2020	
REVENUES		 		 		 		 	
Electric Generation, Transmission and Distribution		$	748.5 			$	688.9 			$	2,149.2 			$	1,989.9 		
Sales to AEP Affiliates		52.4 			44.4 			140.6 			124.9 		
Other Revenues		3.1 			2.4 			8.2 			7.8 		
TOTAL REVENUES		804.0 			735.7 			2,298.0 			2,122.6 		
									
EXPENSES		 		 		 		 	
Fuel and Other Consumables Used for Electric Generation		170.8 			166.0 			471.9 			430.9 		
Purchased Electricity for Resale		82.4 			67.5 			248.4 			240.5 		

Other Operation		173.0 			136.3 			442.1 			379.1 		
Maintenance		69.1 			52.0 			184.4 			148.7 		
Depreciation and Amortization		135.4 			123.2 			406.6 			366.0 		
Taxes Other Than Income Taxes		39.8 			38.8 			116.7 			114.2 		
TOTAL EXPENSES		670.5 			583.8 			1,870.1 			1,679.4 		
									
OPERATING INCOME		133.5 			151.9 			427.9 			443.2 		
									
Other Income (Expense):		 		 		 		 	
Interest Income		0.2 			0.6 			0.8 			1.4 		
	
Allowance for Equity Funds Used During Construction		4.3 			6.7 			12.1 			11.5 		
Non-Service Cost Components of Net Periodic Benefit Cost		4.7 			4.7 			14.2 			14.1 		
Interest Expense		(52.8)			(55.0)			(160.6)			(162.2)		
									
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)		89.9 			108.9 			294.4 			308.0 		
									
Income Tax Expense (Benefit)		3.6 			(7.7)			19.3 			(5.2)		
									
NET INCOME		$	86.3 			$	116.6 			$	275.1 			$	313.2 		
									
The common stock of APCo is wholly-owned by Parent.	
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
87

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

 		Three Months Ended		Nine Months Ended	
 		September 30,		September 30,	
		2021		2020		2021		2020	
Net Income		$	86.3 			$	116.6 			$	275.1 			$	313.2 		
									
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES		 						 	
Cash Flow Hedges, Net of Tax of $0 and $0.1 for the Three Months Ended September 30, 2021 and 2020, Respectively, and $2.3 and $(1.2) for Nine Months Ended September 30, 2021 and 2020, Respectively		(0.3)			0.6 			8.5 			(4.4)		
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.2) and $(0.3) for the Three Months Ended September 30, 2021 and 2020, Respectively, and $(0.8) and $(0.8) for the Nine Months Ended September 30, 2021 and 2020, Respectively		(1.0)			(0.9)			(3.1)			(2.8)		
									
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		(1.3)			(0.3)			5.4 			(7.2)		
									
TOTAL COMPREHENSIVE INCOME		$	85.0 			$	116.3 			$	280.5 			$	306.0 		
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
88

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

		Common
Stock		Paid-in
Capital		Retained
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Total	
TOTAL COMMON SHAREHOLDER’S
   EQUITY - DECEMBER 31, 2019		$	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 		
											
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2020		$	260.4 			$	1,828.7 			$	2,248.0 			$	7.2 			$	4,344.3 		
											
Common Stock Dividends						(12.5)					(12.5)		
	
Net Income						122.5 					122.5 		
Other Comprehensive Income								7.9 			7.9 		
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2021		260.4 			1,828.7 			2,358.0 			15.1 			4,462.2 		
											
Common Stock Dividends						(12.5)					(12.5)		
	
Net Income						66.3 					66.3 		
Other Comprehensive Loss								(1.2)			(1.2)		
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2021		$	260.4 			$	1,828.7 			$	2,411.8 			$	13.9 			$	4,514.8 		
											
Common Stock Dividends						(12.5)					(12.5)		
Net Income						86.3 					86.3 		
Other Comprehensive Loss								(1.3)			(1.3)		
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2021		$	260.4 			$	1,828.7 			$	2,485.6 			$	12.6 			$	4,587.3 		
											
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	

89

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2021 and December 31, 2020
(in millions)
(Unaudited)

		September 30,		December 31,	
		2021		2020	
CURRENT ASSETS		 		 	
Cash and Cash Equivalents		$	5.0 			$	5.8 		
Restricted Cash for Securitized Funding		10.1 			16.9 		
Advances to Affiliates		185.2 			21.4 		
Accounts Receivable:		 		 	
Customers		119.3 			142.8 		
Affiliated Companies		77.4 			64.3 		
Accrued Unbilled Revenues		53.6 			80.1 		
Miscellaneous		0.2 			0.3 		
Allowance for Uncollectible Accounts		(1.6)			(3.1)		
Total Accounts Receivable		248.9 			284.4 		
Fuel		66.6 			193.6 		
Materials and Supplies		100.3 			99.6 		
Risk Management Assets		47.0 			22.4 		
	
Regulatory Asset for Under-Recovered Fuel Costs		49.2 			5.3 		
	
Prepayments and Other Current Assets		72.1 			24.7 		
TOTAL CURRENT ASSETS		784.4 			674.1 		
					
PROPERTY, PLANT AND EQUIPMENT		 		 	
Electric:		 		 	
Generation		6,670.8 			6,633.7 		
Transmission		4,052.9 			3,900.5 		
Distribution		4,621.1 			4,464.3 		
Other Property, Plant and Equipment		682.4 			627.2 		
Construction Work in Progress		567.7 			484.6 		
Total Property, Plant and Equipment		16,594.9 			16,110.3 		
Accumulated Depreciation and Amortization		4,973.1 			4,716.2 		
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		11,621.8 			11,394.1 		
					
OTHER NONCURRENT ASSETS		 		 	
Regulatory Assets		818.6 			686.3 		
Securitized Assets		191.3 			210.1 		
Employee Benefits and Pension Assets		156.8 			150.1 		
	
Operating Lease Assets		70.4 			78.8 		
Deferred Charges and Other Noncurrent Assets		93.5 			121.7 		
TOTAL OTHER NONCURRENT ASSETS		1,330.6 			1,247.0 		
					
TOTAL ASSETS		$	13,736.8 			$	13,315.2 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
90

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2021 and December 31, 2020
(Unaudited)

 		September 30,		December 31,	
 		2021		2020	
 		(in millions)	
CURRENT LIABILITIES		 		 	
Advances from Affiliates		$	— 			$	18.6 		
Accounts Payable:		 		 	
General		224.7 			212.0 		
Affiliated Companies		97.2 			97.1 		
Long-term Debt Due Within One Year – Nonaffiliated		380.6 			518.3 		

Customer Deposits		72.9 			77.8 		
	
Accrued Taxes		88.5 			109.9 		
Accrued Interest		80.0 			49.9 		
Obligations Under Operating Leases		15.1 			14.9 		
	
Other Current Liabilities		107.6 			119.2 		
TOTAL CURRENT LIABILITIES		1,066.6 			1,217.7 		
					
NONCURRENT LIABILITIES		 		 	
Long-term Debt – Nonaffiliated		4,557.2 			4,315.8 		

	
Deferred Income Taxes		1,739.3 			1,749.9 		
Regulatory Liabilities and Deferred Investment Tax Credits		1,250.9 			1,224.7 		
Asset Retirement Obligations		393.6 			304.8 		
Employee Benefits and Pension Obligations		42.9 			44.0 		
Obligations Under Operating Leases		55.9 			64.4 		
Deferred Credits and Other Noncurrent Liabilities		43.1 			49.6 		
TOTAL NONCURRENT LIABILITIES		8,082.9 			7,753.2 		
					
TOTAL LIABILITIES		9,149.5 			8,970.9 		
					
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		2,485.6 			2,248.0 		
Accumulated Other Comprehensive Income (Loss)		12.6 			7.2 		
TOTAL COMMON SHAREHOLDER’S EQUITY		4,587.3 			4,344.3 		
					
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY		$	13,736.8 			$	13,315.2 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
91

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

 		Nine Months Ended September 30,	
 		2021		2020	
OPERATING ACTIVITIES		 		 	
Net Income		$	275.1 			$	313.2 		
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:		 		 	
Depreciation and Amortization		406.6 			366.0 		
Deferred Income Taxes		(12.0)			(28.2)		

Allowance for Equity Funds Used During Construction		(12.1)			(11.5)		
Mark-to-Market of Risk Management Contracts		(26.8)			8.0 		
Pension Contributions to Qualified Plan Trust		— 			(7.0)		
	
Deferred Fuel Over/Under-Recovery, Net		(43.9)			38.8 		
Change in Other Noncurrent Assets		(39.2)			5.4 		
Change in Other Noncurrent Liabilities		20.2 			(26.0)		
Changes in Certain Components of Working Capital:		 		 	
Accounts Receivable, Net		38.1 			7.2 		
Fuel, Materials and Supplies		126.3 			12.4 		
Accounts Payable		26.5 			(74.0)		
Accrued Taxes, Net		(48.0)			1.9 		
Other Current Assets		(20.7)			10.1 		
Other Current Liabilities		0.5 			(9.7)		
Net Cash Flows from Operating Activities		690.6 			606.6 		
					
INVESTING ACTIVITIES		 		 	
Construction Expenditures		(586.4)			(566.6)		
	
Change in Advances to Affiliates, Net		(163.8)			(137.4)		
	
Other Investing Activities		12.4 			4.6 		
Net Cash Flows Used for Investing Activities		(737.8)			(699.4)		
					
FINANCING ACTIVITIES		 		 	
Issuance of Long-term Debt – Nonaffiliated		494.0 			557.2 		
Change in Advances from Affiliates, Net		(18.6)			(232.4)		
Retirement of Long-term Debt – Nonaffiliated		(393.0)			(90.3)		

Principal Payments for Finance Lease Obligations		(5.8)			(5.6)		
Dividends Paid on Common Stock		(37.5)			(150.0)		
Other Financing Activities		0.5 			0.3 		
Net Cash Flows from Financing Activities		39.6 			79.2 		
					
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding		(7.6)			(13.6)		
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period		22.7 			26.8 		
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period		$	15.1 			$	13.2 		
					
SUPPLEMENTARY INFORMATION		 		 	
Cash Paid for Interest, Net of Capitalized Amounts		$	124.2 			$	130.0 		
Net Cash Paid (Received) for Income Taxes		52.6 			(10.7)		
Noncash Acquisitions Under Finance Leases		1.3 			3.0 		
Construction Expenditures Included in Current Liabilities as of September 30,		92.3 			90.0 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
92

INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES
93

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,	
 	2021		2020		2021		2020	
 	(in millions of KWhs)	
Retail:	 		 		 		 	
Residential	1,531 			1,531 			4,244 			4,230 		
Commercial	1,267 			1,219 			3,481 			3,362 		
Industrial	1,853 			1,849 			5,542 			5,324 		
Miscellaneous	13 			14 			42 			47 		
Total Retail	4,664 			4,613 			13,309 			12,963 		
								
Wholesale	1,610 			1,536 			5,055 			5,552 		
								
Total KWhs	6,274 			6,149 			18,364 			18,515 		

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,	
 	2021		2020		2021		2020	
 	(in degree days)	
Actual – Heating (a)	2 			7 			2,343 			2,186 		
Normal – Heating (b)	9 			10 			2,417 			2,429 		
								
Actual – Cooling (c)	679 			637 			1,004 			923 		
Normal – Cooling (b)	581 			576 			848 			841 		

(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.
94

Third Quarter of 2021 Compared to Third Quarter of 2020

Indiana Michigan Power Company and Subsidiaries	
Reconciliation of Third Quarter of 2020 to Third Quarter of 2021	
Net Income	
(in millions)	
			
Third Quarter of 2020		$	76.7 		
 		 	
Changes in Gross Margin:		 	
Retail Margins		30.9 		
	
Margins from Off-system Sales		0.2 		
Transmission Revenues		(0.2)		
Other Revenues		4.0 		
Total Change in Gross Margin		34.9 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(3.0)		
	
Depreciation and Amortization		(6.1)		
Taxes Other Than Income Taxes		(0.4)		
Other Income		0.3 		

	
Interest Expense		(3.3)		
Total Change in Expenses and Other		(12.5)		
 		 	
Income Tax Expense		5.0 		
 		 	
Third Quarter of 2021		$	104.1 		

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

•Retail Margins increased $31 million primarily due to the following:
•A $40 million increase primarily due to an increase in rider revenues and the reversal of a provision for refund. This increase was partially offset in other expense items below.
•A $4 million increase in weather-related usage primarily due to a 7 % increase in cooling degree days.
•A $2 million decrease in fuel related expenses due to timing of recovery related to wholesale contracts.
These increases were partially offset by:
•A $19 million decrease in weather-normalized retail margins primarily in the residential class.
•Other Revenues increased $4 million primarily due to increases in barging revenues by River Transportation Division (RTD), reconnection fees and joint license agreements. The increase in RTD barging revenues are partially offset in Other Operation and Maintenance expenses below.

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

•Other Operation and Maintenance expenses increased $3 million primarily due to the following:
•A $10 million increase in recoverable PJM transmission expenses. This increase was partially offset in Retail Margins above.
•A $5 million increase in distribution expenses primarily due to an increase in vegetation management expenses.
•A $2 million increase in nonutility operation expenses primarily due to an increase in RTD expenses. This increase was partially offset in Other Revenues above.
These increases were partially offset by:
•A $9 million decrease in employee-related expenses.
•A $7 million decrease in Indiana jurisdictional Demand Side Management expenses. This decrease was offset in Retail Margins above.
95

•Depreciation and Amortization expenses increased $6 million primarily due to a higher depreciable base. This increase was partially offset in Retail Margins above.
•Income Tax Expense decreased $5 million primarily due to an increase in amortization of Excess ADIT and flow through tax benefits and an unfavorable discrete tax adjustment recorded in 2020 that did not recur in 2021, partially offset by an increase to pretax book income. The increase in amortization of Excess ADIT is partially offset above in Retail Margins.
96

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020
									
Indiana Michigan Power Company and Subsidiaries	
Reconciliation of Nine Months Ended September 30, 2020 to Nine Months Ended September 30, 2021	
Net Income	
(in millions)	
			
Nine Months Ended September 30, 2020		$	232.8 		
 		 	
Changes in Gross Margin:		 	
Retail Margins		57.0 		

Transmission Revenues		(5.2)		
Other Revenues		4.0 		
Total Change in Gross Margin		55.8 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(43.7)		
	
Depreciation and Amortization		(25.1)		
Taxes Other Than Income Taxes		(4.3)		
Other Income		1.1 		

Non-Service Cost Components of Net Periodic Benefit Cost		(0.2)		
Interest Expense		(0.9)		
Total Change in Expenses and Other		(73.1)		
 		 	
Income Tax Expense		16.6 		
 		 	
Nine Months Ended September 30, 2021		$	232.1 		

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 $57 million primarily due to the following:
•An $88 million increase due to the annual wholesale formula rate true-up, an increase in Indiana and Michigan base rate revenues and an increase in rider revenues. This increase was partially offset in other expense items below.
•A $14 million increase in weather-related usage primarily due to a 7% increase in heating degree days and a 9% increase in cooling degree days.
•A $5 million decrease in fuel related expenses due to timing of recovery related to wholesale contracts.
These increases were partially offset by:
•A $36 million decrease in weather-normalized retail margins primarily in the residential class.
•A $24 million decrease in weather-normalized wholesale margins, including the loss of a significant wholesale contract.
•Transmission Revenues decreased $5 million primarily due to the annual transmission formula rate true-up.
•Other Revenues increased $4 million primarily due to an increase in reconnection fees and joint license agreements.

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

•Other Operation and Maintenance expenses increased $44 million primarily due to the following:
•A $27 million increase in recoverable PJM transmission expenses. This increase was partially offset in Retail Margins above.
•A $17 million increase in transmission expenses primarily due to an $8 million increase in vegetation management expenses and a $6 million increase as a result of the annual transmission formula rate true-up.
97

•An $8 million increase in distribution expenses primarily due to an increase in vegetation management expenses.
•A $4 million increase due to a decreased Nuclear Electric Insurance Limited distribution in 2021.
These increases were partially offset by:
•A $17 million decrease in Indiana jurisdictional Demand Side Management expenses. This decrease was offset in Retail Margins above.
•A $4 million decrease in nuclear expenses primarily due to a $9 million decrease in Cook Plant refueling outage expenses partially offset by a $5 million increase in various maintenance activities.
•Depreciation and Amortization expenses increased $25 million primarily due to a higher depreciable base and an increase in depreciation rates. This increase was partially offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $4 million primarily due to property taxes driven by an increase in utility plant and higher tax rates.
•Income Tax Expense decreased $17 million primarily due to an increase in flow through tax benefits, a decrease in state income tax expense and a decrease in pretax book income.
98

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

 		Three Months Ended		Nine Months Ended	
 		September 30,		September 30,	
 		2021		2020		2021		2020	
REVENUES		 		 		 		 	
Electric Generation, Transmission and Distribution		$	618.2 			$	570.1 			$	1,735.1 			$	1,648.4 		
Sales to AEP Affiliates		1.1 			1.3 			2.6 			9.1 		
Other Revenues – Affiliated		14.7 			14.1 			41.2 			42.4 		
Other Revenues – Nonaffiliated		1.7 			1.2 			5.1 			3.7 		
TOTAL REVENUES		635.7 			586.7 			1,784.0 			1,703.6 		
									
EXPENSES		 		 		 		 	
Fuel and Other Consumables Used for Electric Generation		43.7 			44.4 			129.9 			146.0 		
Purchased Electricity for Resale		44.9 			37.5 			131.9 			128.1 		
Purchased Electricity from AEP Affiliates		63.3 			55.9 			172.7 			135.8 		
Other Operation		167.5 			165.5 			482.4 			459.7 		
Maintenance		52.0 			51.0 			165.4 			144.4 		
	
Depreciation and Amortization		110.6 			104.5 			328.7 			303.6 		
Taxes Other Than Income Taxes		27.8 			27.4 			83.8 			79.5 		
TOTAL EXPENSES		509.8 			486.2 			1,494.8 			1,397.1 		
									
OPERATING INCOME		125.9 			100.5 			289.2 			306.5 		
									
Other Income (Expense):		 		 		 		 	
Other Income		2.5 			2.2 			8.9 			7.8 		

	
Non-Service Cost Components of Net Periodic Benefit Cost		4.1 			4.1 			12.3 			12.5 		
Interest Expense		(30.2)			(26.9)			(86.6)			(85.7)		
									
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)		102.3 			79.9 			223.8 			241.1 		
									
Income Tax Expense (Benefit)		(1.8)			3.2 			(8.3)			8.3 		
									
NET INCOME		$	104.1 			$	76.7 			$	232.1 			$	232.8 		
									
The common stock of I&M is wholly-owned by Parent.	
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
99

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

 		Three Months Ended		Nine Months Ended	
 		September 30,		September 30,	
		2021		2020		2021		2020	
Net Income		$	104.1 			$	76.7 			$	232.1 			$	232.8 		
									
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, 2021 and 2020, Respectively, and $0.3 and $0.3 for the Nine Months Ended September 30, 2021 and 2020, Respectively		0.4 			0.4 			1.3 			1.2 		
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2021 and 2020, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2021 and 2020, Respectively		— 			(0.1)			(0.1)			(0.1)		
									
TOTAL OTHER COMPREHENSIVE INCOME		0.4 			0.3 			1.2 			1.1 		
									
TOTAL COMPREHENSIVE INCOME		$	104.5 			$	77.0 			$	233.3 			$	233.9 		
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
100

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

		Common
Stock		Paid-in
Capital		Retained
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Total	
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2019		$	56.6 			$	980.9 			$	1,518.5 			$	(11.6)			$	2,544.4 		
											
Common Stock Dividends		 		 		(21.3)			 		(21.3)		
ASU 2016-13 Adoption						0.4 					0.4 		
Net Income		 		 		92.3 			 		92.3 		
Other Comprehensive Income		 		 		 		0.4 			0.4 		
TOTAL COMMON SHAREHOLDER'S EQUITY -MARCH 31, 2020		56.6 			980.9 			1,589.9 			(11.2)			2,616.2 		
											
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 		
		 		 		 		 		 	
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2020		$	56.6 			$	980.9 			$	1,718.7 			$	(7.0)			$	2,749.2 		
											
Common Stock Dividends						(25.0)					(25.0)		
	
Net Income						70.8 					70.8 		
Other Comprehensive Income								0.5 			0.5 		
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2021		56.6 			980.9 			1,764.5 			(6.5)			2,795.5 		
											
Common Stock Dividends		 		 		(75.0)			 		(75.0)		
Net Income		 		 		57.2 			 		57.2 		
Other Comprehensive Income		 		 		 		0.3 			0.3 		
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2021		56.6 			980.9 			1,746.7 			(6.2)			2,778.0 		
											
Common Stock Dividends						(75.0)					(75.0)		
Net Income						104.1 					104.1 		
Other Comprehensive Income								0.4 			0.4 		
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2021		$	56.6 			$	980.9 			$	1,775.8 			$	(5.8)			$	2,807.5 		
											
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
101

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2021 and December 31, 2020
(in millions)
(Unaudited)

		September 30,		December 31,	
 		2021		2020	
CURRENT ASSETS		 		 	
Cash and Cash Equivalents		$	3.2 			$	3.3 		
Advances to Affiliates		80.6 			13.3 		
Accounts Receivable:		 		 	
Customers		39.8 			44.0 		
Affiliated Companies		37.9 			51.3 		
	
Miscellaneous		2.8 			2.0 		
Allowance for Uncollectible Accounts		(0.3)			(0.3)		
Total Accounts Receivable		80.2 			97.0 		
Fuel		46.7 			86.0 		
Materials and Supplies		172.2 			175.8 		
Risk Management Assets		5.5 			3.6 		
Accrued Tax Benefits		0.1 			10.3 		
Regulatory Asset for Under-Recovered Fuel Costs		6.1 			5.4 		

Prepayments and Other Current Assets		26.7 			24.1 		
TOTAL CURRENT ASSETS		421.3 			418.8 		
					
PROPERTY, PLANT AND EQUIPMENT		 		 	
Electric:		 		 	
Generation		5,329.6 			5,264.7 		
Transmission		1,749.4 			1,696.4 		
Distribution		2,734.6 			2,594.6 		
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)		684.5 			686.7 		
Construction Work in Progress		377.6 			362.4 		
Total Property, Plant and Equipment		10,875.7 			10,604.8 		
Accumulated Depreciation, Depletion and Amortization		3,811.9 			3,552.5 		
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		7,063.8 			7,052.3 		
					
OTHER NONCURRENT ASSETS		 		 	
Regulatory Assets		436.1 			404.8 		
Spent Nuclear Fuel and Decommissioning Trusts		3,609.8 			3,306.7 		
	
Operating Lease Assets		154.7 			218.1 		
Deferred Charges and Other Noncurrent Assets		219.5 			237.6 		
TOTAL OTHER NONCURRENT ASSETS		4,420.1 			4,167.2 		
					
TOTAL ASSETS		$	11,905.2 			$	11,638.3 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
102

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2021 and December 31, 2020
(dollars in millions)
(Unaudited)

 		September 30,		December 31,	
 		2021		2020	
CURRENT LIABILITIES		 		 	
Advances from Affiliates		$	— 			$	103.0 		
Accounts Payable:		 		 	
General		132.8 			153.2 		
Affiliated Companies		86.2 			80.5 		
Long-term Debt Due Within One Year – Nonaffiliated
   (September 30, 2021 and December 31, 2020 Amounts Include $78.7 and $75.7,
   Respectively, Related to DCC Fuel)		132.7 			369.6 		
Risk Management Liabilities		2.5 			0.1 		
Customer Deposits		42.4 			41.7 		
Accrued Taxes		72.0 			102.5 		
Accrued Interest		25.0 			35.6 		
Obligations Under Operating Leases		86.2 			85.6 		
Regulatory Liability for Over-Recovered Fuel Costs		3.5 			20.8 		
Other Current Liabilities		104.2 			111.9 		
TOTAL CURRENT LIABILITIES		687.5 			1,104.5 		
					
NONCURRENT LIABILITIES		 		 	
Long-term Debt – Nonaffiliated		3,098.4 			2,660.3 		
	
Deferred Income Taxes		1,082.9 			1,064.4 		
Regulatory Liabilities and Deferred Investment Tax Credits		2,201.2 			2,041.9 		
Asset Retirement Obligations		1,869.2 			1,812.9 		
Obligations Under Operating Leases		88.4 			135.9 		
Deferred Credits and Other Noncurrent Liabilities		70.1 			69.2 		
TOTAL NONCURRENT LIABILITIES		8,410.2 			7,784.6 		
					
TOTAL LIABILITIES		9,097.7 			8,889.1 		
					
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		1,775.8 			1,718.7 		
Accumulated Other Comprehensive Income (Loss)		(5.8)			(7.0)		
TOTAL COMMON SHAREHOLDER’S EQUITY		2,807.5 			2,749.2 		
					
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY		$	11,905.2 			$	11,638.3 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
103

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

 		Nine Months Ended September 30,	
 		2021		2020	
OPERATING ACTIVITIES		 		 	
Net Income		$	232.1 			$	232.8 		
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:		 			
Depreciation and Amortization		328.7 			303.6 		
Rockport Plant, Unit 2 Operating Lease Amortization		51.1 			51.9 		
Deferred Income Taxes		(36.6)			(6.1)		
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net		(2.5)			21.3 		

Allowance for Equity Funds Used During Construction		(9.7)			(8.8)		
Mark-to-Market of Risk Management Contracts		0.5 			5.6 		
Amortization of Nuclear Fuel		61.9 			67.2 		
Pension Contributions to Qualified Plan Trust		— 			(6.4)		
Deferred Fuel Over/Under-Recovery, Net		(18.0)			23.4 		
Change in Other Noncurrent Assets		7.3 			40.8 		
Change in Other Noncurrent Liabilities		(10.2)			30.2 		
Changes in Certain Components of Working Capital:		 		 	
Accounts Receivable, Net		18.2 			32.2 		
Fuel, Materials and Supplies		43.0 			(15.4)		
	
Accounts Payable		20.1 			(0.9)		
	
Accrued Taxes, Net		(20.3)			(84.4)		
	
Rockport Plant, Unit 2 Operating Lease Payments		(36.9)			(36.9)		
Other Current Assets		(0.7)			6.6 		
Other Current Liabilities		(28.0)			(59.1)		
Net Cash Flows from Operating Activities		600.0 			597.6 		
					
INVESTING ACTIVITIES		 		 	
Construction Expenditures		(370.2)			(409.1)		
Change in Advances to Affiliates, Net		(67.3)			(0.1)		
Purchases of Investment Securities		(1,586.3)			(1,290.0)		
Sales of Investment Securities		1,556.6 			1,257.1 		
Acquisitions of Nuclear Fuel		(63.2)			(68.4)		
	
Other Investing Activities		12.9 			8.3 		
Net Cash Flows Used for Investing Activities		(517.5)			(502.2)		
					
FINANCING ACTIVITIES		 		 	
Issuance of Long-term Debt – Nonaffiliated		507.0 			— 		
Change in Advances from Affiliates, Net		(103.0)			44.7 		
Retirement of Long-term Debt – Nonaffiliated		(307.2)			(71.1)		
Principal Payments for Finance Lease Obligations		(4.9)			(4.8)		
Dividends Paid on Common Stock		(175.0)			(63.7)		
Other Financing Activities		0.5 			0.3 		
Net Cash Flows Used for Financing Activities		(82.6)			(94.6)		
					
Net Increase (Decrease) in Cash and Cash Equivalents		(0.1)			0.8 		
Cash and Cash Equivalents at Beginning of Period		3.3 			2.0 		
Cash and Cash Equivalents at End of Period		$	3.2 			$	2.8 		
					
SUPPLEMENTARY INFORMATION		 		 	
Cash Paid for Interest, Net of Capitalized Amounts		$	93.9 			$	97.5 		
Net Cash Paid for Income Taxes		11.8 			59.7 		
Noncash Acquisitions Under Finance Leases		3.1 			1.9 		
Construction Expenditures Included in Current Liabilities as of September 30,		59.0 			57.6 		
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,		0.3 			1.0 		
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage		0.6 			2.4 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
104

OHIO POWER COMPANY AND SUBSIDIARIES

105

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,	
	2021		2020		2021		2020	
 	(in millions of KWhs)	
Retail:	 		 		 		 	
Residential	4,096 			4,165 			11,261 			11,140 		
Commercial	4,112 			3,781 			11,282 			10,454 		
Industrial	3,633 			3,380 			10,769 			9,855 		
Miscellaneous	25 			22 			80 			82 		
Total Retail (a)	11,866 			11,348 			33,392 			31,531 		
								
Wholesale (b)	643 			502 			1,691 			1,347 		
								
Total KWhs	12,509 			11,850 			35,083 			32,878 		

(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,	
	2021		2020		2021		2020	
 	(in degree days)	
Actual – Heating (a)	1 			2 			1,993 			1,767 		
Normal – Heating (b)	5 			6 			2,071 			2,086 		
								
Actual – Cooling (c)	787 			809 			1,148 			1,126 		
Normal – Cooling (b)	689 			682 			996 			986 		

(a)Heating degree days are calculated on a 55 degree temperature base.
(b)Normal Heating/Cooling represents the thirty-year average of degree days.
(c)Cooling degree days are calculated on a 65 degree temperature base.
106

Third Quarter of 2021 Compared to Third Quarter of 2020

Ohio Power Company and Subsidiaries	
Reconciliation of Third Quarter of 2020 to Third Quarter of 2021	
Net Income	
(in millions)	
			
Third Quarter of 2020		$	59.0 		
 		 	
Changes in Gross Margin:		 	
Retail Margins		15.1 		
Margins from Off-system Sales		(8.7)		
Transmission Revenues		(2.3)		
Other Revenues		7.8 		
Total Change in Gross Margin		11.9 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(6.1)		
Depreciation and Amortization		(2.8)		
Taxes Other Than Income Taxes		(8.2)		
Interest Income		(0.2)		
Carrying Costs Income		(0.2)		
Allowance for Equity Funds Used During Construction		(2.6)		
Non-Service Cost Components of Net Periodic Benefit Cost		(0.1)		
Interest Expense		(3.5)		
Total Change in Expenses and Other		(23.7)		
 		 	
Income Tax Expense		9.2 		
 		 	
Third Quarter of 2021		$	56.4 		

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity were as follows:

•Retail Margins increased $15 million primarily due to the following:
•A $40 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 $15 million increase related to various rider revenues. This increase was partially offset in Margins from Off-system Sales, Other Revenues, and other expense items below.
•A $3 million increase in usage primarily from the industrial and commercial classes.
These increases were partially offset by:
•A $24 million decrease due to the ending of the Energy Efficiency and Peak Demand Rider in December 2020. This decrease was partially offset in Other Operation and Maintenance expenses below.
•A $15 million decrease in revenues associated with the Universal Service Fund (USF). This decrease was offset in Other Operation and Maintenance expenses below.
•Margins from Off-system Sales decreased $9 million primarily due to the following:
•A $19 million decrease in deferrals of OVEC costs. This decrease was offset in Retail Margins above and Other Revenues below.
This decrease was partially offset by:
•A $10 million increase in off-system sales at OVEC. This increase was offset in Retail Margins above and Other Revenues below.
•Other Revenues increased $8 million primarily due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins and Margins from Off-system Sales above.

107

Expenses and Other changed between years as follows:

•Other Operation and Maintenance expenses increased $6 million primarily due to the following:
•A $34 million increase in recoverable PJM transmission expenses. This increase was partially offset in Retail Margins above.
•A $5 million increase in recoverable distribution expenses primarily related to vegetation management. This increase was offset in Retail Margins above.
These increases were partially offset by:
•A $15 million decrease in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This decrease was offset in Retail Margins above.
•A $15 million decrease in energy efficiency/demand side management expenses. This decrease was partially offset within Retail Margins above.
•A $5 million decrease in factored customer accounts receivable expenses primarily due to bad debt expenses and a current year adjustment to allowance for doubtful accounts.
•Taxes Other Than Income Taxes increased $8 million primarily due to property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
•Interest Expense increased $4 million primarily due to higher long-term debt balances.
•Income Tax Expense decreased $9 million primarily due to an unfavorable discrete adjustment recorded in 2020 that did not recur in 2021 and a decrease in pretax book income.
108

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020

Ohio Power Company and Subsidiaries	
Reconciliation of Nine Months Ended September 30, 2020 to Nine Months Ended September 30, 2021	
Net Income	
(in millions)	
			
Nine Months Ended September 30, 2020		$	215.0 		
 		 	
Changes in Gross Margin:		 	
Retail Margins		92.1 		
Margins from Off-system Sales		(36.0)		
Transmission Revenues		(4.6)		
Other Revenues		20.8 		
Total Change in Gross Margin		72.3 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(38.6)		
Depreciation and Amortization		(24.2)		
Taxes Other Than Income Taxes		(28.4)		
Interest Income		(0.3)		
Carrying Costs Income		(0.2)		
Allowance for Equity Funds Used During Construction		(1.7)		
Non-Service Cost Components of Net Periodic Benefit Cost		(0.3)		
Interest Expense		(7.8)		
Total Change in Expenses and Other		(101.5)		
 		 	
Income Tax Expense		12.8 		
 		 	
Nine Months Ended September 30, 2021		$	198.6 		

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity were as follows:

•Retail Margins increased $92 million primarily due to the following:
•A $129 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 $71 million increase related to various rider revenues. This increase was partially offset in Margins from Off-system Sales, Other Revenues, and other expense items below.
•A $4 million increase in usage primarily from the commercial and industrial classes.
These increases were partially offset by:
•A $71 million decrease due to the ending of the Energy Efficiency and Peak Demand Rider in December 2020. This decrease was partially offset in Other Operation and Maintenance expenses below.
•A $43 million decrease in revenues associated with the USF. This decrease was offset in Other Operation and Maintenance expenses below.
•Margins from Off-system Sales decreased $36 million primarily due to the following:
•A $51 million decrease in deferrals of OVEC costs. This decrease was offset in Retail Margins above and Other Revenues below.
This decrease was partially offset by:
•A $16 million increase in off-system sales at OVEC. This increase was offset in Retail Margins above and Other Revenues below.
•Transmission Revenues decreased $5 million primarily due to a decrease in net affiliated transmission expenses.
•Other Revenues increased $21 million primarily due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins and Margins from Off-system Sales above.
109

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

•Other Operation and Maintenance expenses increased $39 million primarily due to the following:
•A $112 million increase in recoverable PJM transmission expenses. This increase was partially offset in Retail Margins above.
•A $15 million increase in recoverable distribution expenses related to vegetation management. This increase was offset in Retail Margins above.
•A $9 million increase in PJM expenses primarily related to the annual transmission formula rate true-up.
•An $8 million increase in distribution maintenance expenses related to the annual major storm reserve true-up. This increase was offset in retail margins.
These increases were partially offset by:
•A $45 million decrease in energy efficiency/demand side management expenses. This decrease was partially offset within Retail Margins above.
•A $43 million decrease in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This decrease was offset in Retail Margins above.
•A $19 million decrease in factored customer accounts receivable expenses primarily due to bad debt expenses and a current year adjustment to allowance for doubtful accounts.
•Depreciation and Amortization expenses increased $24 million primarily due to the following:
•An $8 million increase in amortization of plant primarily related to capitalized software.
•A $7 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
•A $7 million increase in recoverable DIR depreciation expense. This increase was partially offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $28 million primarily due to the following:
•A $23 million increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
•A $3 million increase in excise taxes driven by increased metered KWh usage in 2021. This increase was offset in Retail Margins above.
•Interest Expense increased $8 million primarily due to higher long-term debt balances.
•Income Tax Expense decreased $13 million primarily due to an unfavorable discrete tax adjustment recorded during 2020 and a decrease in pretax book income.
110

OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

 		Three Months Ended		Nine Months Ended	
 		September 30,		September 30,	
 		2021		2020		2021		2020	
REVENUES		 		 		 		 	
Electricity, Transmission and Distribution		$	761.0 			$	730.4 			$	2,167.8 			$	2,031.4 		
Sales to AEP Affiliates		4.3 			8.3 			21.9 			33.0 		
Other Revenues		2.4 			2.3 			6.8 			7.3 		
TOTAL REVENUES		767.7 			741.0 			2,196.5 			2,071.7 		
									
EXPENSES		 		 		 		 	
Purchased Electricity for Resale		184.7 			149.3 			513.6 			412.3 		
Purchased Electricity from AEP Affiliates		3.5 			24.1 			48.0 			96.8 		
	
Other Operation		245.1 			244.6 			622.9 			608.5 		
Maintenance		39.3 			33.7 			116.4 			92.2 		
Depreciation and Amortization		76.9 			74.1 			228.6 			204.4 		
Taxes Other Than Income Taxes		126.0 			117.8 			366.2 			337.8 		
TOTAL EXPENSES		675.5 			643.6 			1,895.7 			1,752.0 		
									
OPERATING INCOME		92.2 			97.4 			300.8 			319.7 		
									
Other Income (Expense):		 		 		 		 	
Interest Income		0.2 			0.4 			0.5 			0.8 		
Carrying Costs Income		0.1 			0.3 			1.1 			1.3 		
Allowance for Equity Funds Used During Construction		2.0 			4.6 			7.6 			9.3 		
Non-Service Cost Components of Net Periodic Benefit Cost		3.7 			3.8 			11.0 			11.3 		
Interest Expense		(32.9)			(29.4)			(96.2)			(88.4)		
									
INCOME BEFORE INCOME TAX EXPENSE		65.3 			77.1 			224.8 			254.0 		
									
Income Tax Expense		8.9 			18.1 			26.2 			39.0 		
									
NET INCOME		$	56.4 			$	59.0 			$	198.6 			$	215.0 		
									
The common stock of OPCo is wholly-owned by Parent.	
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
111

OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

		Common
Stock		Paid-in
Capital		Retained
Earnings		Total	
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 		
		 		 		 		 	
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020		$	321.2 			$	838.8 			$	1,532.7 			$	2,692.7 		
									
Common Stock Dividends						(21.9)			(21.9)		
Net Income						68.2 			68.2 		
	
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2021		321.2 			838.8 			1,579.0 			2,739.0 		
									
Common Stock Dividends		 		 		(21.9)			(21.9)		
Net Income		 		 		74.0 			74.0 		
	
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2021		321.2 			838.8 			1,631.1 			2,791.1 		
									
Common Stock Dividends						(28.1)			(28.1)		
Net Income						56.4 			56.4 		
	
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2021		$	321.2 			$	838.8 			$	1,659.4 			$	2,819.4 		
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
112

OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2021 and December 31, 2020
(in millions)
(Unaudited)

 		September 30,		December 31,	
 		2021		2020	
CURRENT ASSETS		 		 	
Cash and Cash Equivalents		$	6.8 			$	7.4 		
Advances to Affiliates		622.9 			— 		
Accounts Receivable:		 		 	
Customers		31.0 			50.0 		
Affiliated Companies		64.7 			65.1 		
Accrued Unbilled Revenues		15.3 			14.8 		
Miscellaneous		5.8 			3.9 		
Allowance for Uncollectible Accounts		(0.6)			(0.6)		
Total Accounts Receivable		116.2 			133.2 		
Materials and Supplies		70.9 			66.9 		
Renewable Energy Credits		31.1 			29.5 		

	
Prepayments and Other Current Assets		29.6 			19.3 		
TOTAL CURRENT ASSETS		877.5 			256.3 		
					
PROPERTY, PLANT AND EQUIPMENT		 		 	
Electric:		 		 	
Transmission		2,936.3 			2,831.9 		
Distribution		5,989.2 			5,708.3 		
Other Property, Plant and Equipment		979.9 			899.6 		
Construction Work in Progress		331.7 			362.3 		
Total Property, Plant and Equipment		10,237.1 			9,802.1 		
Accumulated Depreciation and Amortization		2,438.7 			2,350.0 		
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		7,798.4 			7,452.1 		
					
OTHER NONCURRENT ASSETS		 		 	
Regulatory Assets		343.8 			385.8 		
	
Operating Lease Assets		84.2 			92.0 		
Deferred Charges and Other Noncurrent Assets		292.4 			524.2 		
TOTAL OTHER NONCURRENT ASSETS		720.4 			1,002.0 		
					
TOTAL ASSETS		$	9,396.3 			$	8,710.4 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
113

OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2021 and December 31, 2020
(Unaudited)

 		September 30,		December 31,	
 		2021		2020	
		(in millions)	
CURRENT LIABILITIES		 		 	
Advances from Affiliates		$	— 			$	259.2 		
Accounts Payable:		 		 	
General		169.0 			181.0 		
Affiliated Companies		101.5 			118.4 		
Long-term Debt Due Within One Year – Nonaffiliated		500.1 			500.1 		
Risk Management Liabilities		3.5 			8.7 		
Customer Deposits		123.5 			55.1 		
Accrued Taxes		344.8 			631.0 		
	
Obligations Under Operating Leases		13.1 			13.1 		
Other Current Liabilities		149.6 			139.6 		
TOTAL CURRENT LIABILITIES		1,405.1 			1,906.2 		
					
NONCURRENT LIABILITIES		 		 	
Long-term Debt – Nonaffiliated		2,968.0 			1,930.1 		
Long-term Risk Management Liabilities		86.9 			101.6 		
Deferred Income Taxes		1,010.7 			955.1 		
Regulatory Liabilities and Deferred Investment Tax Credits		995.7 			1,005.2 		
	
Obligations Under Operating Leases		71.6 			79.5 		
Deferred Credits and Other Noncurrent Liabilities		38.9 			40.0 		
TOTAL NONCURRENT LIABILITIES		5,171.8 			4,111.5 		
					
TOTAL LIABILITIES		6,576.9 			6,017.7 		
					
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		1,659.4 			1,532.7 		
	
TOTAL COMMON SHAREHOLDER’S EQUITY		2,819.4 			2,692.7 		
					
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY		$	9,396.3 			$	8,710.4 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
114

OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

 		Nine Months Ended September 30,	
 		2021		2020	
OPERATING ACTIVITIES		 		 	
Net Income		$	198.6 			$	215.0 		
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:		 		 	
Depreciation and Amortization		228.6 			204.4 		
Deferred Income Taxes		29.3 			35.6 		
	
Allowance for Equity Funds Used During Construction		(7.6)			(9.3)		
Mark-to-Market of Risk Management Contracts		(19.9)			9.7 		
	
Property Taxes		234.9 			225.1 		
	
Change in Other Noncurrent Assets		(1.1)			(93.8)		
Change in Other Noncurrent Liabilities		4.6 			(58.3)		
Changes in Certain Components of Working Capital:		 		 	
Accounts Receivable, Net		20.7 			33.4 		
Materials and Supplies		(0.6)			(19.8)		
Accounts Payable		(19.1)			(19.9)		
Customer Deposits		68.4 			12.4 		
Accrued Taxes, Net		(289.7)			(266.2)		
Other Current Assets		(7.8)			(2.5)		
Other Current Liabilities		5.8 			(35.7)		
Net Cash Flows from Operating Activities		445.1 			230.1 		
					
INVESTING ACTIVITIES		 		 	
Construction Expenditures		(536.6)			(604.6)		
Change in Advances to Affiliates, Net		(622.9)			— 		
Other Investing Activities		10.7 			14.1 		
Net Cash Flows Used for Investing Activities		(1,148.8)			(590.5)		
					
FINANCING ACTIVITIES		 		 	
Issuance of Long-term Debt – Nonaffiliated		1,037.5 			347.0 		
Change in Advances from Affiliates, Net		(259.2)			84.9 		
Retirement of Long-term Debt – Nonaffiliated		(0.1)			(0.1)		
Principal Payments for Finance Lease Obligations		(3.7)			(3.5)		
Dividends Paid on Common Stock		(71.9)			(65.6)		
Other Financing Activities		0.5 			0.6 		
Net Cash Flows from Financing Activities		703.1 			363.3 		
					
Net Increase (Decrease) in Cash and Cash Equivalents		(0.6)			2.9 		
Cash and Cash Equivalents at Beginning of Period		7.4 			3.7 		
Cash and Cash Equivalents at End of Period		$	6.8 			$	6.6 		
					
SUPPLEMENTARY INFORMATION		 		 	
Cash Paid for Interest, Net of Capitalized Amounts		$	78.6 			$	69.7 		
Net Cash Paid (Received) for Income Taxes		0.3 			(6.0)		
Noncash Acquisitions Under Finance Leases		1.4 			5.2 		
Construction Expenditures Included in Current Liabilities as of September 30,		66.5 			75.9 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
115

PUBLIC SERVICE COMPANY OF OKLAHOMA
116

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,	
	2021		2020		2021		2020	
 	(in millions of KWhs)	
Retail:	 		 		 		 	
Residential	2,179 			2,019 			5,068 			4,838 		
Commercial	1,476 			1,358 			3,781 			3,549 		
Industrial	1,566 			1,461 			4,383 			4,299 		
Miscellaneous	355 			347 			935 			912 		
Total Retail	5,576 			5,185 			14,167 			13,598 		
								
Wholesale	162 			130 			350 			261 		
								
Total KWhs	5,738 			5,315 			14,517 			13,859 		

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,	
	2021		2020		2021		2020	
 	(in degree days)	
Actual – Heating (a)	— 			1 			1,195 			874 		
Normal – Heating (b)	1 			1 			1,078 			1,078 		
								
Actual – Cooling (c)	1,491 			1,274 			2,075 			1,979 		
Normal – Cooling (b)	1,404 			1,412 			2,079 			2,088 		

(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.
117

Third Quarter of 2021 Compared to Third Quarter of 2020

Public Service Company of Oklahoma	
Reconciliation of Third Quarter of 2020 to Third Quarter of 2021	
Net Income	
(in millions)	
			
Third Quarter of 2020		$	80.3 		
			
Changes in Gross Margin:			
Retail Margins (a)		29.7 		
Margins from Off-system Sales		(0.4)		
Transmission Revenues		2.1 		
Other Revenues		(0.1)		
Total Change in Gross Margin		31.3 		
			
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(11.9)		
Depreciation and Amortization		(8.8)		
	
Interest Income		1.3 		
	
Allowance for Equity Funds Used During Construction		(0.8)		

Interest Expense		(1.6)		
Total Change in Expenses and Other		(21.8)		
 		 	
Income Tax Expense		3.4 		
 		 	
Third Quarter of 2021		$	93.2 		

(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 $30 million primarily due to the following:
•A $22 million increase in revenue from rate riders. This increase was partially offset in other expense items below.
•A $13 million increase in weather-related usage primarily due to a 17% increase in cooling degree days.
•A $3 million increase in weather-normalized retail margins primarily in the commercial class.
These increases were partially offset by:
•A $9 million increase in fuel expense due to NCWF PTC benefits provided to customers. This decrease was offset in Income Tax Expense below.

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

•Other Operation and Maintenance expenses increased $12 million primarily due to the following:
•A $10 million increase in recoverable SPP transmission expense. This increase was partially offset in Retail Margins above.
•Depreciation and Amortization increased $9 million primarily due to a higher depreciable base and the timing of refunds to customers under rate rider mechanisms.
•Income Tax Expense decreased $3 million primarily due to an increase in PTC, partially offset by an increase in pretax book income.
118

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020

Public Service Company of Oklahoma	
Reconciliation of Nine Months Ended September 30, 2020 to Nine Months Ended September 30, 2021	
Net Income	
(in millions)	
			
Nine Months Ended September 30, 2020		$	116.4 		
 		 	
Changes in Gross Margin:		 	
Retail Margins (a)		46.8 		
Margin from Off-system Sales		(0.6)		
Transmission Revenues		5.3 		
Other Revenues		(5.7)		
Total Change in Gross Margin		45.8 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(13.4)		
Depreciation and Amortization		(19.2)		
Taxes Other Than Income Taxes		(1.3)		
Interest Income		2.9 		
	
Allowance for Equity Funds Used During Construction		(1.7)		
	
Non-Service Cost Components of Net Periodic Benefit Cost		0.1 		
Interest Expense		1.2 		
Total Change in Expenses and Other		(31.4)		
 		 	
Income Tax Expense		5.8 		
 		 	
Nine Months Ended September 30, 2021		$	136.6 		
(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 $47 million primarily due to the following:
•A $41 million increase in revenue from rate riders. This increase was partially offset in other expense items below.
•A $9 million increase in weather-related usage primarily due to a 37% increase in heating degree days and a 5% increase in cooling degree days.
•An $8 million increase in weather-normalized retail margins primarily in the commercial and residential classes.
These increases were partially offset by:
•An $11 million increase in fuel expense due to NCWF PTC benefits provided to customers. This decrease was offset in Income Tax Expense below.
•Transmission Revenues increased $5 million primarily due to the following:
•A $3 million increase due to increased transmission investments.
•A $2 million increase due to the annual transmission formula rate true-up.
•Other Revenues decreased $6 million primarily due to lower business development revenue. 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 increased $13 million primarily due to the following:
•A $19 million increase in transmission expenses primarily due to a $13 million increase in recoverable SPP transmission expense and a $5 million increase as a result of the annual transmission formula rate true-up. These increases were partially offset in Retail Margins above.
•A $3 million increase due to the prior year capitalization of previously expensed North Central Wind Energy Facilities costs.
119

These increases were partially offset by:
•A $5 million decrease in distribution expenses primarily due to a decrease in overhead line maintenance.
•A $5 million decrease in business development expenses. This decrease was partially offset in Other Revenues above.
•Depreciation and Amortization expenses increased $19 million primarily due to a higher depreciable base and the timing of refunds to customers under rate rider mechanisms.
•Income Tax Expense decreased $6 million primarily due to an increase in PTC, partially offset by an increase in pretax book income.
120

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

 		Three Months Ended		Nine Months Ended	
 		September 30,		September 30,	
 		2021		2020		2021		2020	
REVENUES		 		 		 		 	
Electric Generation, Transmission and Distribution		$	481.3 			$	379.8 			$	1,117.4 			$	976.3 		
Sales to AEP Affiliates		1.0 			1.4 			3.1 			3.8 		
Other Revenues		1.5 			1.0 			3.9 			8.0 		
TOTAL REVENUES		483.8 			382.2 			1,124.4 			988.1 		
									
EXPENSES		 		 		 		 	
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation		195.9 			125.6 			440.8 			350.3 		

Other Operation		102.3 			91.7 			262.7 			248.5 		
Maintenance		21.2 			19.9 			68.1 			68.9 		
Depreciation and Amortization		48.9 			40.1 			149.0 			129.8 		
Taxes Other Than Income Taxes		12.1 			12.1 			37.1 			35.8 		
TOTAL EXPENSES		380.4 			289.4 			957.7 			833.3 		
									
OPERATING INCOME		103.4 			92.8 			166.7 			154.8 		
									
Other Income (Expense):		 		 		 		 	
Interest Income		1.3 			— 			3.0 			0.1 		
	
Allowance for Equity Funds Used During Construction		0.5 			1.3 			1.5 			3.2 		
	
Non-Service Cost Components of Net Periodic Benefit Cost		2.1 			2.1 			6.4 			6.3 		
Interest Expense		(16.2)			(14.6)			(44.7)			(45.9)		
									
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)		91.1 			81.6 			132.9 			118.5 		
									
Income Tax Expense (Benefit)		(2.1)			1.3 			(3.7)			2.1 		
									
NET INCOME		$	93.2 			$	80.3 			$	136.6 			$	116.4 		
									
The common stock of PSO is wholly-owned by Parent.	
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
121

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

 		Three Months Ended		Nine Months Ended	
 		September 30,		September 30,	
		2021		2020		2021		2020	
Net Income		$	93.2 			$	80.3 			$	136.6 			$	116.4 		
									
OTHER COMPREHENSIVE LOSS, NET OF TAXES		 		 		 		 	
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2021 and 2020, Respectively, and $0 and $(0.2) for the Nine Months Ended September 30, 2021 and 2020, Respectively.		— 			(0.3)			(0.1)			(0.8)		
		 		 		 		 	
TOTAL COMPREHENSIVE INCOME		$	93.2 			$	80.0 			$	136.5 			$	115.6 		
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
122

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

		Common
Stock		Paid-in
Capital		Retained
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Total	
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019		$	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 		
											
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020		$	157.2 			$	414.0 			$	974.3 			$	0.1 			$	1,545.6 		

	
Capital Contribution from Parent				425.0						425.0 		
Net Loss						(2.7)					(2.7)		
Other Comprehensive Loss								(0.1)			(0.1)		
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2021		157.2 			839.0 			971.6 			— 			1,967.8 		
											
Capital Contribution from Parent				200.0 							200.0 		
Common Stock Dividends		 		 		(10.0)			 		(10.0)		
Net Income		 		 		46.1 			 		46.1 		
	
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2021		157.2 			1,039.0 			1,007.7 			— 			2,203.9 		
											
Common Stock Dividends						(10.0)					(10.0)		
Net Income						93.2 					93.2 		
	
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2021		$	157.2 			$	1,039.0 			$	1,090.9 			$	— 			$	2,287.1 		
											
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
123

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
September 30, 2021 and December 31, 2020
(in millions)
(Unaudited)

 		September 30,		December 31,	
 		2021		2020	
CURRENT ASSETS		 		 	
Cash and Cash Equivalents		$	3.6 			$	2.6 		
Advances to Affiliates		59.5 			— 		
Accounts Receivable:		 		 	
Customers		29.7 			30.8 		
Affiliated Companies		31.7 			15.6 		
Miscellaneous		0.4 			2.0 		
	
Total Accounts Receivable		61.8 			48.4 		
Fuel		7.6 			17.9 		
Materials and Supplies		54.4 			54.0 		
Risk Management Assets		18.5 			10.3 		
	
Accrued Tax Benefits		35.7 			10.9 		
Regulatory Asset for Under-Recovered Fuel Costs		133.4 			30.1 		
Prepayments and Other Current Assets		13.1 			7.1 		
TOTAL CURRENT ASSETS		387.6 			181.3 		
					
PROPERTY, PLANT AND EQUIPMENT		 		 	
Electric:		 		 	
Generation		1,795.2 			1,480.7 		
Transmission		1,095.9 			1,069.9 		
Distribution		2,959.7 			2,853.0 		
Other Property, Plant and Equipment		427.8 			393.3 		
Construction Work in Progress		127.7 			128.7 		
Total Property, Plant and Equipment		6,406.3 			5,925.6 		
Accumulated Depreciation and Amortization		1,682.6 			1,605.6 		
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		4,723.7 			4,320.0 		
					
OTHER NONCURRENT ASSETS		 		 	
Regulatory Assets		1,052.3 			375.0 		
	
Employee Benefits and Pension Assets		66.2 			65.8 		
Operating Lease Assets		70.4 			42.6 		
Deferred Charges and Other Noncurrent Assets		18.9 			6.0 		
TOTAL OTHER NONCURRENT ASSETS		1,207.8 			489.4 		
					
TOTAL ASSETS		$	6,319.1 			$	4,990.7 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
124

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2021 and December 31, 2020
(Unaudited)

 		September 30,		December 31,	
 		2021		2020	
 		(in millions)	
CURRENT LIABILITIES		 		 	
Advances from Affiliates		$	— 			$	155.4 		
Accounts Payable:		 		 	
General		146.4 			107.0 		
Affiliated Companies		32.0 			43.4 		
Long-term Debt Due Within One Year – Nonaffiliated		0.5 			0.5 		
	
Customer Deposits		54.0 			54.8 		
Accrued Taxes		60.9 			26.8 		
	
Obligations Under Operating Leases		6.9 			6.5 		

Other Current Liabilities		67.9 			84.2 		
TOTAL CURRENT LIABILITIES		368.6 			478.6 		
					
NONCURRENT LIABILITIES		 		 	
Long-term Debt – Nonaffiliated		1,912.8 			1,373.3 		
	
Deferred Income Taxes		764.0 			688.5 		
Regulatory Liabilities and Deferred Investment Tax Credits		846.2 			802.2 		
Asset Retirement Obligations		55.0 			45.7 		
	
Obligations Under Operating Leases		63.7 			36.2 		
Deferred Credits and Other Noncurrent Liabilities		21.7 			20.6 		
TOTAL NONCURRENT LIABILITIES		3,663.4 			2,966.5 		
					
TOTAL LIABILITIES		4,032.0 			3,445.1 		
					
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		1,039.0 			414.0 		
Retained Earnings		1,090.9 			974.3 		
Accumulated Other Comprehensive Income (Loss)		— 			0.1 		
TOTAL COMMON SHAREHOLDER’S EQUITY		2,287.1 			1,545.6 		
					
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY		$	6,319.1 			$	4,990.7 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
125

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

 		Nine Months Ended September 30,	
 		2021		2020	
OPERATING ACTIVITIES		 		 	
Net Income		$	136.6 			$	116.4 		
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:		 		 	
Depreciation and Amortization		149.0 			129.8 		
Deferred Income Taxes		109.8 			(3.2)		
	
Allowance for Equity Funds Used During Construction		(1.5)			(3.2)		
Mark-to-Market of Risk Management Contracts		(8.2)			(0.3)		
	
Property Taxes		(10.9)			(10.6)		
Deferred Fuel Over/Under-Recovery, Net		(776.4)			(46.6)		
	
Change in Other Noncurrent Assets		(12.8)			(7.2)		
Change in Other Noncurrent Liabilities		4.5 			6.1 		
Changes in Certain Components of Working Capital:		 		 	
Accounts Receivable, Net		(13.4)			(5.6)		
Fuel, Materials and Supplies		9.9 			(17.2)		
Accounts Payable		16.4 			(26.1)		
Accrued Taxes, Net		9.3 			36.9 		
Other Current Assets		(5.9)			(0.1)		
Other Current Liabilities		(18.4)			(16.4)		
Net Cash Flows from (Used for) Operating Activities		(412.0)			152.7 		
					
INVESTING ACTIVITIES		 		 	
Construction Expenditures		(219.6)			(256.4)		
Change in Advances to Affiliates, Net		(59.5)			38.8 		
Acquisition of the North Central Wind Energy Facilities		(297.0)			— 		
Other Investing Activities		1.9 			3.9 		
Net Cash Flows Used for Investing Activities		(574.2)			(213.7)		
					
FINANCING ACTIVITIES		 		 	
Capital Contributions from Parent		625.0 			— 		
Issuance of Long-term Debt – Nonaffiliated		1,290.0 			— 		
Change in Advances from Affiliates, Net		(155.4)			77.8 		
Retirement of Long-term Debt – Nonaffiliated		(750.4)			(13.0)		
	
Principal Payments for Finance Lease Obligations		(2.5)			(2.7)		
Dividends Paid on Common Stock		(20.0)			— 		
Other Financing Activities		0.5 			0.4 		
Net Cash Flows from Financing Activities		987.2 			62.5 		
					
Net Increase in Cash and Cash Equivalents		1.0 			1.5 		
Cash and Cash Equivalents at Beginning of Period		2.6 			1.5 		
Cash and Cash Equivalents at End of Period		$	3.6 			$	3.0 		
					
SUPPLEMENTARY INFORMATION		 		 	
Cash Paid for Interest, Net of Capitalized Amounts		$	42.9 			$	45.5 		
Net Cash Paid (Received) for Income Taxes		(101.2)			(9.5)		
Noncash Acquisitions Under Finance Leases		3.1 			3.0 		
Construction Expenditures Included in Current Liabilities as of September 30,		44.2 			23.5 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
126

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

127

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,	
 	2021		2020		2021		2020	
 	(in millions of KWhs)	
Retail:	 		 		 		 	
Residential	1,999 			1,950 			4,973 			4,702 		
Commercial	1,616 			1,552 			4,221 			4,016 		
Industrial	1,203 			1,185 			3,468 			3,614 		
Miscellaneous	19 			19 			58 			59 		
Total Retail	4,837 			4,706 			12,720 			12,391 		
								
Wholesale	2,170 			1,571 			5,103 			4,081 		
								
Total KWhs	7,007 			6,277 			17,823 			16,472 		

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,	
 	2021		2020		2021		2020	
 	(in degree days)	
Actual – Heating (a)	— 			— 			789 			522 		
Normal – Heating (b)	1 			1 			723 			724 		
								
Actual – Cooling (c)	1,478 			1,308 			2,251 			2,051 		
Normal – Cooling (b)	1,416 			1,420 			2,195 			2,200 		

(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.

128

Third Quarter of 2021 Compared to Third Quarter of 2020

Reconciliation of Third Quarter of 2020 to Third Quarter of 2021	
Earnings Attributable to SWEPCo Common Shareholder	
(in millions)	
			
Third Quarter of 2020		$	87.9 		
 		 	
Changes in Gross Margin:		 	
Retail Margins (a)		16.2 		
Margins from Off-system Sales		0.1 		
Transmission Revenues		8.1 		
Other Revenues		0.7 		
Total Change in Gross Margin		25.1 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		2.1 		
	
Depreciation and Amortization		(6.3)		
Taxes Other Than Income Taxes		(2.2)		
Interest Income		2.2 		
Allowance for Equity Funds Used During Construction		(2.0)		

Interest Expense		(2.4)		
Total Change in Expenses and Other		(8.6)		
 		 	
Income Tax Expense		4.5 		
Equity Earnings of Unconsolidated Subsidiary		0.3 		
Net Income Attributable to Noncontrolling Interest		(0.3)		
 		 	
Third Quarter of 2021		$	108.9 		

(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 $16 million primarily due to the following:
•A $12 million increase in weather-related usage primarily due to a 13% increase in cooling degree days.
•A $2 million increase in recoverable fuel costs primarily due to timing of recovery.
•Transmission Revenues increased $8 million primarily due to increased load and transmission investment.

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

•Other Operation and Maintenance expenses decreased $2 million primarily due to the following:
•A $6 million decrease in administrative & general expenses and employee-related expenses.
This decrease was partially offset by:
•A $5 million increase in transmission expense primarily due to increased load.
•Depreciation and Amortization expenses increased $6 million primarily due to a higher depreciable base.
•Income Tax Expense decreased $5 million primarily due to the following:
•A $10 million decrease in state income taxes.
•A $6 million increase in PTC.
The overall decrease was partially offset by:
•A $3 million increase due to an increase in pretax book income.
•A $3 million decrease in parent company loss benefit.
•A $2 million decrease in amortization of Excess ADIT, partially offset in Retail Margins above.
•A $2 million discrete tax adjustment recognized in 2021.
129

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020

Reconciliation of Nine Months Ended September 30, 2020 to Nine Months Ended September 30, 2021	
Earnings Attributable to SWEPCo Common Shareholder	
(in millions)	
			
Nine Months Ended September 30, 2020		$	161.8 		
 		 	
Changes in Gross Margin:		 	
Retail Margins (a)		62.4 		
Margins from Off-system Sales		21.2 		
Transmission Revenues		5.4 		
Other Revenues		1.9 		
Total Change in Gross Margin		90.9 		
 		 	
Changes in Expenses and Other:		 	
Other Operation and Maintenance		(13.9)		
	
Depreciation and Amortization		(13.5)		
Taxes Other Than Income Taxes		(12.0)		
Interest Income		5.2 		
Allowance for Equity Funds Used During Construction		(0.3)		
Non-Service Cost Components of Net Periodic Benefit Cost		(0.1)		
	
Interest Expense		(3.3)		
Total Change in Expenses and Other		(37.9)		
 		 	
Income Tax Expense		(6.5)		
Equity Earnings of Unconsolidated Subsidiary		0.3 		
Net Income Attributable to Noncontrolling Interest		(0.5)		
 		 	
Nine Months Ended September 30, 2021		$	208.1 		

(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 $62 million primarily due to the following:
•A $25 million increase in weather-related usage primarily due to a 51% increase in heating degree days and a 10% increase in cooling degree days.
•A $13 million increase in municipal and cooperative revenues primarily due to the February 2021 severe winter weather event.
•A $10 million increase in recoverable fuel costs primarily due to timing of recovery.
•A $6 million increase in municipal and cooperative revenues due to the annual generation formula rate true-up.
•A $6 million increase due to a decrease in the return of Excess ADIT benefits to customers. This increase was offset in Income Tax Expense below.
•Margins from Off-system Sales increased $21 million primarily due to Turk Plant merchant sales as a result of the February 2021 severe winter weather event.
•Transmission Revenues increased $5 million primarily due to the following:
•A $12 million increase due to increased load and transmission investment.
This increase was partially offset by:
•A $6 million decrease due to the annual transmission formula rate true-up.
130

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

•Other Operation and Maintenance expenses increased $14 million primarily due to the following:
•A $19 million increase in transmission expense primarily due to a $10 million increase as a result of the annual formula rate true-up and a $12 million increase in NITS expense due to increased load.
•A $5 million increase due to the prior year capitalization of previously expensed North Central Wind Energy Facilities costs.
These increases were partially offset by:
•A $6 million decrease in administrative & general expenses and employee-related expenses.
•A $2 million decrease in overhead line maintenance primarily related to storm restoration.
•Depreciation and Amortization expenses increased $14 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxes increased $12 million primarily due to increased property taxes resulting from the expiration of the Louisiana Industrial Tax Exemption related to Stall Plant.
•Interest Income increased $5 million primarily related to carrying charges on regulatory assets resulting from the February 2021 severe winter weather event.
•Interest Expense increased $3 million primarily due to higher long-term debt balances.
•Income Tax Expense increased $7 million primarily due to the following:
•An $11 million increase due to an increase in pretax book income.
•A $10 million decrease in amortization of Excess ADIT, partially offset in Retail Margins above.
•A $3 million decrease in parent company loss benefit.
•A $2 million decrease in flow through tax benefits.
•A $2 million discrete tax adjustment recognized in 2021.
The overall increase was partially offset by:
•A $12 million decrease in state income tax expense.
•A $10 million increase in PTC.

131

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

		Three Months Ended		Nine Months Ended	
 		September 30,		September 30,	
 		2021		2020		2021		2020	
REVENUES		 		 		 		 	
Electric Generation, Transmission and Distribution		$	570.1 			$	505.7 			$	1,596.6 			$	1,284.3 		
Sales to AEP Affiliates		13.5 			10.9 			32.2 			31.5 		
	
Other Revenues		0.5 			0.7 			1.5 			2.4 		
TOTAL REVENUES		584.1 			517.3 			1,630.3 			1,318.2 		
									
EXPENSES		 		 		 		 	
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation		214.4 			172.7 			652.7 			431.5 		

Other Operation		91.7 			96.8 			270.6 			259.0 		
Maintenance		33.7 			30.7 			99.5 			97.2 		
	
Depreciation and Amortization		74.8 			68.5 			217.4 			203.9 		
Taxes Other Than Income Taxes		28.9 			26.7 			89.0 			77.0 		
TOTAL EXPENSES		443.5 			395.4 			1,329.2 			1,068.6 		
									
OPERATING INCOME		140.6 			121.9 			301.1 			249.6 		
									
Other Income (Expense):		 		 				 	
Interest Income		2.8 			0.6 			6.9 			1.7 		
Allowance for Equity Funds Used During Construction		1.4 			3.4 			5.4 			5.7 		
Non-Service Cost Components of Net Periodic Benefit Cost		2.1 			2.1 			6.2 			6.3 		
	
Interest Expense		(31.7)			(29.3)			(92.4)			(89.1)		
									
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		115.2 			98.7 			227.2 			174.2 		
									
Income Tax Expense		6.3 			10.8 			19.0 			12.5 		
Equity Earnings of Unconsolidated Subsidiary		1.0 			0.7 			2.5 			2.2 		
									
NET INCOME		109.9 			88.6 			210.7 			163.9 		
									
Net Income Attributable to Noncontrolling Interest		1.0 			0.7 			2.6 			2.1 		
									
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER		$	108.9 			$	87.9 			$	208.1 			$	161.8 		
									
The common stock of SWEPCo is wholly-owned by Parent.	
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
132

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

 		Three Months Ended		Nine Months Ended	
 		September 30,		September 30,	
	
 		2021		2020		2021		2020	
Net Income		$	109.9 			$	88.6 			$	210.7 			$	163.9 		
									
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, 2021 and 2020, Respectively, and $0.3 and $0.3 for the Nine Months Ended September 30, 2021 and 2020, Respectively		0.3 			0.4 			1.1 			1.1 		
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2021 and 2020, Respectively, and $(0.3) and $(0.3) for the Nine Months Ended September 30, 2021 and 2020, Respectively		(0.4)			(0.4)			(1.2)			(1.1)		
									
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		(0.1)			— 			(0.1)			— 		
									
TOTAL COMPREHENSIVE INCOME		109.8 			88.6 			210.6 			163.9 		
									
Total Comprehensive Income Attributable to Noncontrolling Interest		1.0 			0.7 			2.6 			2.1 		
									
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER		$	108.8 			$	87.9 			$	208.0 			$	161.8 		
									
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
133

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

	SWEPCo Common Shareholder		 		 	
	Common
Stock		Paid-in
Capital		Retained
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Noncontrolling
Interest		Total	
TOTAL EQUITY – DECEMBER 31, 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	(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 		
												
TOTAL EQUITY – DECEMBER 31, 2020	$	0.1 			$	812.2 			$	1,811.9 			$	1.9 			$	1.6 			$	2,627.7 		
												
Capital Contribution from Parent			100.0								100.0 		
	
Common Stock Dividends – Nonaffiliated									(1.0)			(1.0)		
	
Net Income					62.4 					1.0 			63.4 		
	
TOTAL EQUITY – MARCH 31, 2021	0.1 			912.2 			1,874.3 			1.9 			1.6 			2,790.1 		
												
Capital Contribution from Parent			75.0								75.0 		
	
Common Stock Dividends – Nonaffiliated	 		 		 		 		(0.6)			(0.6)		
Net Income	 		 		36.8 			 		0.6 			37.4 		
	
TOTAL EQUITY – JUNE 30, 2021	0.1 			987.2 			1,911.1 			1.9 			1.6 			2,901.9 		
												
Capital Contribution from Parent			105.0 									105.0 		
	
Common Stock Dividends – Nonaffiliated									(2.2)			(2.2)		
Net Income					108.9 					1.0 			109.9 		
Other Comprehensive Loss							(0.1)					(0.1)		
TOTAL EQUITY – SEPTEMBER 30, 2021	$	0.1 			$	1,092.2 			$	2,020.0 			$	1.8 			$	0.4 			$	3,114.5 		

		

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
134

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2021 and December 31, 2020
(in millions)
(Unaudited)

 		September 30,		December 31,	
 		2021		2020	
CURRENT ASSETS		 		 	
Cash and Cash Equivalents
(September 30, 2021 and December 31, 2020 Amounts Include $41 and $10.1, Respectively, Related to Sabine)		$	45.0 			$	13.2 		
Advances to Affiliates		2.1 			2.1 		
Accounts Receivable:		 		 	
Customers		76.2 			27.1 		
Affiliated Companies		35.6 			25.1 		
Miscellaneous		23.3 			12.7 		
	
Total Accounts Receivable		135.1 			64.9 		
Fuel
(September 30, 2021 and December 31, 2020 Amounts Include $6.7 and $35.2, Respectively, Related to Sabine)		95.4 			191.1 		
Materials and Supplies
(September 30, 2021 and December 31, 2020 Amounts Include $15.9 and $23.3, Respectively, Related to Sabine)		86.8 			95.8 		
Risk Management Assets		17.5 			3.2 		
	
Accrued Tax Benefits		19.8 			29.9 		
Regulatory Asset for Under-Recovered Fuel Costs		38.7 			2.6 		
Prepayments and Other Current Assets		20.8 			25.2 		
TOTAL CURRENT ASSETS		461.2 			428.0 		
					
PROPERTY, PLANT AND EQUIPMENT		 		 	
Electric:		 		 	
Generation		5,065.5 			4,681.4 		
Transmission		2,264.6 			2,165.7 		
Distribution		2,499.2 			2,382.5 		
Other Property, Plant and Equipment
(September 30, 2021 and December 31, 2020 Amounts Include $220.2 and $223.7, Respectively, Related to Sabine)		817.6 			788.8 		
Construction Work in Progress		195.5 			228.3 		
Total Property, Plant and Equipment		10,842.4 			10,246.7 		
Accumulated Depreciation and Amortization
(September 30, 2021 and December 31, 2020 Amounts Include $156.7 and $126.5, Respectively, Related to Sabine)		3,478.5 			3,158.5 		
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		7,363.9 			7,088.2 		
					
OTHER NONCURRENT ASSETS		 		 	
Regulatory Assets		1,068.0 			403.1 		
Long-term Risk Management Assets		2.1 			— 		
	
Deferred Charges and Other Noncurrent Assets		277.3 			234.8 		
TOTAL OTHER NONCURRENT ASSETS		1,347.4 			637.9 		
					
TOTAL ASSETS		$	9,172.5 			$	8,154.1 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
135

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 2021 and December 31, 2020
(Unaudited)

 		September 30,		December 31,	
 		2021		2020	
 		(in millions)	
CURRENT LIABILITIES		 		 	
Advances from Affiliates		$	122.9 			$	124.6 		
Accounts Payable:		 		 	
General		114.7 			135.9 		
Affiliated Companies		43.4 			43.0 		
Short-term Debt – Nonaffiliated		— 			35.0 		
Long-term Debt Due Within One Year – Nonaffiliated		381.2 			106.2 		
Risk Management Liabilities		— 			0.7 		
Customer Deposits		60.7 			61.3 		
Accrued Taxes		103.1 			41.0 		
Accrued Interest		23.0 			34.6 		
	
Obligations Under Operating Leases		8.3 			7.9 		
	
Other Current Liabilities		119.6 			173.4 		
TOTAL CURRENT LIABILITIES		976.9 			763.6 		
					
NONCURRENT LIABILITIES		 		 	
Long-term Debt – Nonaffiliated		2,748.7 			2,530.2 		
Long-term Risk Management Liabilities		— 			1.0 		
Deferred Income Taxes		1,067.6 			1,017.6 		
Regulatory Liabilities and Deferred Investment Tax Credits		879.8 			863.4 		
Asset Retirement Obligations		193.4 			193.7 		
Employee Benefits and Pension Obligations		23.8 			18.6 		
	
Obligations Under Operating Leases		79.2 			44.1 		
Deferred Credits and Other Noncurrent Liabilities		88.6 			94.2 		
TOTAL NONCURRENT LIABILITIES		5,081.1 			4,762.8 		
					
TOTAL LIABILITIES		6,058.0 			5,526.4 		
					
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 			0.1 		
Paid-in Capital		1,092.2 			812.2 		
Retained Earnings		2,020.0 			1,811.9 		
Accumulated Other Comprehensive Income (Loss)		1.8 			1.9 		
TOTAL COMMON SHAREHOLDER’S EQUITY		3,114.1 			2,626.1 		
					
Noncontrolling Interest		0.4 			1.6 		
					
TOTAL EQUITY		3,114.5 			2,627.7 		
					
TOTAL LIABILITIES AND EQUITY		$	9,172.5 			$	8,154.1 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
136

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2021 and 2020
(in millions)
(Unaudited)

 		Nine Months Ended September 30,	
 		2021		2020	
OPERATING ACTIVITIES		 		 	
Net Income		$	210.7 			$	163.9 		
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:		 		 	
Depreciation and Amortization		217.4 			203.9 		
Deferred Income Taxes		22.5 			(0.3)		
	
Allowance for Equity Funds Used During Construction		(5.4)			(5.7)		
Mark-to-Market of Risk Management Contracts		(18.1)			(2.3)		
Pension Contributions to Qualified Plan Trust		— 			(8.9)		
Property Taxes		(20.0)			(16.5)		
Deferred Fuel Over/Under-Recovery, Net		(506.8)			16.3 		
Change in Regulatory Assets		(91.5)			(64.5)		
Change in Other Noncurrent Assets		38.3 			3.2 		
Change in Other Noncurrent Liabilities		40.0 			21.0 		
Changes in Certain Components of Working Capital:		 		 	
Accounts Receivable, Net		(70.2)			8.0 		
Fuel, Materials and Supplies		115.1 			(70.9)		
Accounts Payable		(21.1)			88.0 		
Accrued Taxes, Net		72.2 			46.6 		
	
Other Current Assets		4.2 			1.3 		
Other Current Liabilities		(48.2)			(50.3)		
Net Cash Flows from (Used for) Operating Activities		(60.9)			332.8 		
					
INVESTING ACTIVITIES		 		 	
Construction Expenditures		(277.2)			(319.5)		
	
Acquisition of the North Central Wind Energy Facilities		(355.8)			— 		
Other Investing Activities		2.1 			4.8 		
Net Cash Flows Used for Investing Activities		(630.9)			(314.7)		
					
FINANCING ACTIVITIES		 		 	
Capital Contribution from Parent		280.0 			— 		
Issuance of Long-term Debt – Nonaffiliated		496.4 			— 		
	
Change in Short-term Debt – Nonaffiliated		(35.0)			23.7 		
Change in Advances from Affiliates, Net		(1.7)			11.9 		
Retirement of Long-term Debt – Nonaffiliated		(4.7)			(19.7)		
Principal Payments for Finance Lease Obligations		(8.1)			(8.0)		
	
Dividends Paid on Common Stock – Nonaffiliated		(3.8)			(2.3)		
Other Financing Activities		0.5 			0.3 		
Net Cash Flows from Financing Activities		723.6 			5.9 		
					
Net Increase in Cash and Cash Equivalents		31.8 			24.0 		
Cash and Cash Equivalents at Beginning of Period		13.2 			1.6 		
Cash and Cash Equivalents at End of Period		$	45.0 			$	25.6 		
					
SUPPLEMENTARY INFORMATION		 		 	
Cash Paid for Interest, Net of Capitalized Amounts		$	98.0 			$	95.2 		
Net Cash Paid (Received) for Income Taxes		(11.3)			11.9 		
Noncash Acquisitions Under Finance Leases		4.4 			5.9 		
Construction Expenditures Included in Current Liabilities as of September 30,		46.8 			50.6 		
					
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.	
137

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		139	
New Accounting Standards		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		141	
Comprehensive Income		AEP, AEP Texas, APCo, I&M, PSO, SWEPCo		142	
Rate Matters		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		153	
Commitments, Guarantees and Contingencies		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		170	
Acquisitions and Dispositions		AEP, PSO, SWEPCo		176	
Benefit Plans		AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo		178	
Business Segments		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		183	
Derivatives and Hedging		AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo		188	
Fair Value Measurements		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		202	
Income Taxes		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		219	
Financing Activities		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		222	
	
Property, Plant and Equipment		AEP, APCo		231	
Revenue from Contracts with Customers		AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo		232	
Subsequent Events		AEP, AEPTCo		241	
138

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, 2021 is not necessarily indicative of results that may be expected for the year ending December 31, 2021.  The condensed financial statements are unaudited and should be read in conjunction with the audited 2020 financial statements and notes thereto, which are included in the Registrants’ Annual Reports on Form 10-K as filed with the SEC on February 25, 2021.

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,	
	2021		2020	
	(in millions, except per share data)	
	 		$/share				$/share	

Earnings Attributable to AEP Common Shareholders	$	796.0 			 		$	748.6 			 	
								
Weighted-Average Number of Basic AEP Common Shares Outstanding	501.2 			$	1.59 			496.2 			$	1.51 		
Weighted-Average Dilutive Effect of Stock-Based Awards	1.4 			(0.01)			1.3 			(0.01)		
Weighted-Average Number of Diluted AEP Common Shares Outstanding	502.6 			$	1.58 			497.5 			$	1.50 		

	Nine Months Ended September 30,	
	2021		2020	
	(in millions, except per share data)	
	 		$/share				$/share	

Earnings Attributable to AEP Common Shareholders	$	1,949.2 			 		$	1,764.6 			 	
								
Weighted-Average Number of Basic AEP Common Shares Outstanding	499.4 			$	3.90 			495.5 			$	3.56 		
Weighted-Average Dilutive Effect of Stock-Based Awards	1.2 			(0.01)			1.4 			(0.01)		
Weighted-Average Number of Diluted AEP Common Shares Outstanding	500.6 			$	3.89 			496.9 			$	3.55 		

Equity Units are potentially dilutive securities but were excluded from the calculation of diluted EPS for the three and nine months ended September 30, 2021 and 2020, as the dilutive stock price thresholds were not met. See Note 12 - Financing Activities for more information related to Equity Units.

139

There were 377 thousand and 0 antidilutive shares outstanding as of September 30, 2021 and 2020, respectively. The antidilutive shares were excluded from the calculation of diluted EPS.

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

Restricted Cash primarily includes funds held by trustees for the payment of securitization bonds.

Reconciliation of Cash, Cash Equivalents and Restricted Cash

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

		September 30, 2021	
		AEP		AEP Texas		APCo	
		(in millions)	
Cash and Cash Equivalents		$	1,372.7 			$	0.1 			$	5.0 		
Restricted Cash		54.0 			43.9 			10.1 		
Total Cash, Cash Equivalents and Restricted Cash		$	1,426.7 			$	44.0 			$	15.1 		

		December 31, 2020	
		AEP		AEP Texas		APCo	
		(in millions)	
Cash and Cash Equivalents		$	392.7 			$	0.1 			$	5.8 		
Restricted Cash		45.6 			28.7 			16.9 		
Total Cash, Cash Equivalents and Restricted Cash		$	438.3 			$	28.8 			$	22.7 		

140

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. There are no new standards expected to have a material impact on the Registrants’ financial statements.

141

3.  COMPREHENSIVE INCOME

The disclosures in this note apply to all Registrants except AEPTCo and OPCo 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 information.

AEP

 		Cash Flow Hedges		Pension		 	
Three Months Ended September 30, 2021		Commodity		Interest Rate		and OPEB		Total	
 		(in millions)	
Balance in AOCI as of June 30, 2021		$	110.3 			$	(32.2)			$	18.9 			$	97.0 		
Change in Fair Value Recognized in AOCI		220.8 			4.9 		(a)	— 			225.7 		
Amount of (Gain) Loss Reclassified from AOCI									
	
Purchased Electricity for Resale (b)		(59.7)			— 			— 			(59.7)		
Interest Expense (b)		— 			1.5 			— 			1.5 		
Amortization of Prior Service Cost (Credit)		— 			— 			(4.8)			(4.8)		
Amortization of Actuarial (Gains) Losses		— 			— 			2.3 			2.3 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(59.7)			1.5 			(2.5)			(60.7)		
Income Tax (Expense) Benefit		(12.5)			0.3 			(0.5)			(12.7)		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(47.2)			1.2 			(2.0)			(48.0)		
Net Current Period Other Comprehensive Income (Loss)		173.6 			6.1 			(2.0)			177.7 		
Balance in AOCI as of September 30, 2021		$	283.9 			$	(26.1)			$	16.9 			$	274.7 		

 		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)		

	

	

	

	

	

	

142

AEP
																											
 		Cash Flow Hedges		Pension		 	
Nine Months Ended September 30, 2021		Commodity		Interest Rate		and OPEB		Total	
 		(in millions)	
Balance in AOCI as of December 31, 2020		$	(60.6)			$	(47.5)			$	23.0 			$	(85.1)		
Change in Fair Value Recognized in AOCI		534.5 			17.6 		(a)	— 			552.1 		
Amount of (Gain) Loss Reclassified from AOCI									
Generation & Marketing Revenues (b)		0.7 			— 			— 			0.7 		
Purchased Electricity for Resale (b)		(241.2)			— 			— 			(241.2)		
Interest Expense (b)		— 			4.8 			— 			4.8 		
Amortization of Prior Service Cost (Credit)		— 			— 			(14.5)			(14.5)		
Amortization of Actuarial (Gains) Losses		— 			— 			6.8 			6.8 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(240.5)			4.8 			(7.7)			(243.4)		
Income Tax (Expense) Benefit		(50.5)			1.0 			(1.6)			(51.1)		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(190.0)			3.8 			(6.1)			(192.3)		
Net Current Period Other Comprehensive Income (Loss)		344.5 			21.4 			(6.1)			359.8 		
Balance in AOCI as of September 30, 2021		$	283.9 			$	(26.1)			$	16.9 			$	274.7 		

 		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)		

143

AEP Texas

		Cash Flow Hedge –		Pension			
Three Months Ended September 30, 2021		Interest Rate		and OPEB		Total	
	(in millions)	
Balance in AOCI as of June 30, 2021		$	(1.8)			$	(6.5)			$	(8.3)		
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, 2021		$	(1.5)			$	(6.5)			$	(8.0)		

		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)		

144

AEP Texas

		Cash Flow Hedge –		Pension			
Nine Months Ended September 30, 2021		Interest Rate		and OPEB		Total	
	(in millions)	
Balance in AOCI as of December 31, 2020		$	(2.3)			$	(6.6)			$	(8.9)		
Change in Fair Value Recognized in AOCI		— 			— 			— 		
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, 2021		$	(1.5)			$	(6.5)			$	(8.0)		

							
		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)		

145

APCo

		Cash Flow Hedge –		Pension			
Three Months Ended September 30, 2021		Interest Rate		and OPEB		Total	
	(in millions)	
Balance in AOCI as of June 30, 2021		$	8.0 			$	5.9 			$	13.9 		
Change in Fair Value Recognized in AOCI		0.2 			— 			0.2 		
Amount of (Gain) Loss Reclassified from AOCI							

Interest Expense (b)		(0.6)			— 			(0.6)		
Amortization of Prior Service Cost (Credit)		— 			(1.2)			(1.2)		
	
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(0.6)			(1.2)			(1.8)		
Income Tax (Expense) Benefit		(0.1)			(0.2)			(0.3)		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.5)			(1.0)			(1.5)		
Net Current Period Other Comprehensive Income (Loss)		(0.3)			(1.0)			(1.3)		
Balance in AOCI as of September 30, 2021		$	7.7 			$	4.9 			$	12.6 		

		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)		
146

																					
APCo							
		Cash Flow Hedge –		Pension			
Nine Months Ended September 30, 2021		Interest Rate		and OPEB		Total	
	(in millions)	
Balance in AOCI as of December 31, 2020		$	(0.8)			$	8.0 			$	7.2 		
Change in Fair Value Recognized in AOCI		9.3 			— 			9.3 		
Amount of (Gain) Loss Reclassified from AOCI							

Interest Expense (b)		(1.0)			— 			(1.0)		
Amortization of Prior Service Cost (Credit)		— 			(3.9)			(3.9)		
	
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(1.0)			(3.9)			(4.9)		
Income Tax (Expense) Benefit		(0.2)			(0.8)			(1.0)		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.8)			(3.1)			(3.9)		
Net Current Period Other Comprehensive Income (Loss)		8.5 			(3.1)			5.4 		
Balance in AOCI as of September 30, 2021		$	7.7 			$	4.9 			$	12.6 		

							
		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)		

147

																					
I&M							
		Cash Flow Hedge –		Pension			
Three Months Ended September 30, 2021		Interest Rate		and OPEB		Total	
	(in millions)	
Balance in AOCI as of June 30, 2021		$	(7.4)			$	1.2 			$	(6.2)		
Change in Fair Value Recognized in AOCI		— 			— 			— 		
Amount of (Gain) Loss Reclassified from AOCI							

Interest Expense (b)		0.5 			— 			0.5 		
Amortization of Prior Service Cost (Credit)		— 			(0.2)			(0.2)		
Amortization of Actuarial (Gains) Losses		— 			0.2 			0.2 		
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.5 			— 			0.5 		
Income Tax (Expense) Benefit		0.1 			— 			0.1 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.4 			— 			0.4 		
Net Current Period Other Comprehensive Income (Loss)		0.4 			— 			0.4 		
Balance in AOCI as of September 30, 2021		$	(7.0)			$	1.2 			$	(5.8)		

		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)		
148

																					
I&M							
		Cash Flow Hedge –		Pension			
Nine Months Ended September 30, 2021		Interest Rate		and OPEB		Total	
	(in millions)	
Balance in AOCI as of December 31, 2020		$	(8.3)			$	1.3 			$	(7.0)		
Change in Fair Value Recognized in AOCI		— 			— 			— 		
Amount of (Gain) Loss Reclassified from AOCI							

Interest Expense (b)		1.6 			— 			1.6 		
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		1.6 			(0.1)			1.5 		
Income Tax (Expense) Benefit		0.3 			— 			0.3 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		1.3 			(0.1)			1.2 		
Net Current Period Other Comprehensive Income (Loss)		1.3 			(0.1)			1.2 		
Balance in AOCI as of September 30, 2021		$	(7.0)			$	1.2 			$	(5.8)		

							
		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)		

			

	

	

	

	

	

									

	

	

	

	

	

									

	

	

	

	

	

									

	

	

	

	

	

149

									
PSO			
		Cash Flow Hedge –	
Three Months Ended September 30, 2021		Interest Rate	
 	(in millions)	
Balance in AOCI as of June 30, 2021		$	— 		
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, 2021		$	— 		

		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 –	
Nine Months Ended September 30, 2021		Interest Rate	
 	(in millions)	
Balance in AOCI as of December 31, 2020		$	0.1 		
Change in Fair Value Recognized in AOCI		— 		
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)		(0.1)		
Balance in AOCI as of September 30, 2021		$	— 		

			
		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 		
150

																					
SWEPCo							
		Cash Flow Hedge –		Pension			
Three Months Ended September 30, 2021		Interest Rate		and OPEB		Total	
	(in millions)	
Balance in AOCI as of June 30, 2021		$	0.5 			$	1.4 			$	1.9 		
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)		— 			(0.5)			(0.5)		
	
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.4 			(0.5)			(0.1)		
Income Tax (Expense) Benefit		0.1 			(0.1)			— 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.3 			(0.4)			(0.1)		
Net Current Period Other Comprehensive Income (Loss)		0.3 			(0.4)			(0.1)		
Balance in AOCI as of September 30, 2021		$	0.8 			$	1.0 			$	1.8 		

		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)		
151

																					
SWEPCo							
							
		Cash Flow Hedge –		Pension			
Nine Months Ended September 30, 2021		Interest Rate		and OPEB		Total	
	(in millions)	
Balance in AOCI as of December 31, 2020		$	(0.3)			$	2.2 			$	1.9 		
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)		
	
Reclassifications from AOCI, before Income Tax (Expense) Benefit		1.4 			(1.5)			(0.1)		
Income Tax (Expense) Benefit		0.3 			(0.3)			— 		
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		1.1 			(1.2)			(0.1)		
Net Current Period Other Comprehensive Income (Loss)		1.1 			(1.2)			(0.1)		
Balance in AOCI as of September 30, 2021		$	0.8 			$	1.0 			$	1.8 		

							
		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)		
(a)The change in fair value includes $(1) million and $(1) million, respectively, for the three months ended September 30, 2021 and 2020 and $(5) million and $6 million, respectively, for the nine months ended September 30, 2021 and 2020 related to AEP's investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC.
(b)Amounts reclassified to the referenced line item on the statements of income.

152

4.  RATE MATTERS

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

As discussed in the 2020 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2020 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2021 and updates the 2020 Annual Report.

Coal-Fired Generation Plants (Applies to AEP, PSO and SWEPCo)

Compliance with extensive environmental regulations requires significant capital investment in environmental monitoring, installation of pollution control equipment, emission fees, disposal costs and permits. Management continuously evaluates cost estimates of complying with these regulations which has resulted in, and in the future may result in, a decision to retire coal-fired generating facilities earlier than their currently estimated useful lives.

Management is seeking or will seek regulatory recovery, as necessary, for any net book value remaining when the plants are retired. To the extent the net book value of these generation assets are not deemed recoverable, it could materially reduce future net income and cash flows and impact financial condition.

Regulated Generating Units that have been Retired

PSO

The Oklaunion Power Station was retired in September 2020 and sold to a nonaffiliated third-party in October 2020. As of September 30, 2021, PSO has a regulatory asset for accelerated depreciation pending approval recorded on its balance sheet of $33 million. PSO has requested recovery of the Oklaunion Power Station as part of its 2021 Oklahoma base rate case. See “2021 Oklahoma Base Rate Case” section below for additional information.

SWEPCo

In April 2016, Welsh Plant, Unit 2 was retired. As part of the 2016 Texas Base Rate Case, SWEPCo received approval from the PUCT to recover the Texas jurisdictional share of Welsh Plant, Unit 2. See “2016 Texas Base Rate Case” section below for additional information. As part of the 2019 Arkansas Base Rate Case, SWEPCo received approval from the APSC to recover the Arkansas jurisdictional share of Welsh Plant, Unit 2. In December 2020, SWEPCo filed a request with the LPSC to recover the Louisiana jurisdictional share of Welsh Plant, Unit 2. See “2020 Louisiana Base Rate Case” section below for additional information. As of September 30, 2021, SWEPCo has a regulatory asset for plant retirement costs pending approval recorded on its balance sheet of $35 million related to the Louisiana jurisdictional share of Welsh Plant, Unit 2.

Regulated Generating Units to be Retired

PSO

In 2014, PSO received final approval from the Federal EPA to close Northeastern Plant, Unit 3, in 2026. The plant was originally scheduled to close in 2040. As a result of the early retirement date, PSO revised the useful life of Northeastern Plant, Unit 3, to the projected retirement date of 2026 and the incremental depreciation is being deferred as a regulatory asset. PSO has requested recovery of Northeastern Plant, Unit 3 as part of its 2021 Oklahoma base rate case. See “2021 Oklahoma Base Rate Case” section below for additional information.
153

SWEPCo

In January 2020, as part of the 2019 Arkansas Base Rate Case, management announced that the Dolet Hills Power Station was probable of abandonment and was to be retired by December 2026. As a result of the announcement, SWEPCo began recording a regulatory asset for accelerated depreciation. In March 2020, management announced plans to retire the plant in 2021.

In November 2020, management announced plans to retire Pirkey Power Plant in 2023 and that it will cease using coal at the Welsh Plant in 2028. As a result of the announcement, SWEPCo began recording a regulatory asset for accelerated depreciation.

The table below summarizes the net book value including CWIP, before cost of removal and materials and supplies, as of September 30, 2021, of generating facilities planned for early retirement:

Plant		Net Book Value		Accelerated Depreciation Regulatory Asset		Cost of Removal
Regulatory Liability			Projected
Retirement Date		Current Authorized
Recovery Period		Annual
Depreciation (a)	
		(dollars in millions)	
Northeastern Plant, Unit 3		$	175.1 			$	123.6 			$	20.0 		(b)		2026		(c)		$	14.9 		
Dolet Hills Power Station		13.0 			126.8 			24.4 				2021		(d)		7.8 		
Pirkey Power Plant		135.4 			68.0 			39.2 				2023		(e)		13.5 		
Welsh Plant, Units 1 and 3		493.7 			35.6 			58.2 		(f)		2028		(g)		33.1 		
(a)Represents the amount of annual depreciation that has been collected from customers over the prior 12-month period.
(b)Includes Northeastern Plant, Unit 4, which was retired in 2016. Removal of Northeastern Plant, Unit 4, will be performed with Northeastern Plant, Unit 3, after retirement.
(c)Northeastern Plant, Unit 3 is currently being recovered through 2040.
(d)Dolet Hills Power Station is currently being recovered through 2026 in the Louisiana jurisdiction and through 2046 in the Arkansas and Texas jurisdictions.
(e)Pirkey Power Plant is currently being recovered through 2025 in the Louisiana jurisdiction and through 2045 in the Arkansas and Texas jurisdictions.
(f)Includes Welsh Plant, Unit 2, which was retired in 2016. Removal of Welsh Plant, Unit 2, will be performed with Welsh Plant, Units 1 and 3, after retirement.
(g)Unit 1 is being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.

Dolet Hills Power Station and Related Fuel Operations (Applies to AEP and SWEPCo)

DHLC provides 100% of the fuel supply to Dolet Hills Power Station. During the second quarter of 2019, the Dolet Hills Power Station initiated a seasonal operating schedule. In 2020, management of SWEPCo and CLECO determined DHLC would not proceed developing additional Oxbow Lignite Company (Oxbow) mining areas for future lignite extraction and ceased extraction of lignite at the mine in May 2020. 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 ceased in October 2021. In addition, 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 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 non-fuel costs are recoverable by SWEPCo through base rates. As of September 30, 2021, SWEPCo’s share of the net investment in the Dolet Hills Power Station is $146 million, including CWIP and materials and supplies, before cost of removal.

Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses. Under the fuel agreements, SWEPCo’s fuel inventory and unbilled fuel costs from mining related activities were $44 million as of September 30, 2021. Also, as of September 30, 2021, SWEPCo had a net under-recovered fuel balance of $39 million, excluding impacts of the February 2021 severe winter weather event, which includes fuel consumed at the Dolet Hills Power Station. Additional operational, reclamation and other land-related costs incurred by DHLC and Oxbow will be billed to SWEPCo and included in future fuel clauses.

154

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

In March 2021, the LPSC issued an order allowing SWEPCo to recover up to $20 million of fuel costs in 2021 and defer approximately $30 million of additional costs with a recovery period to be determined at a later date.

In March 2021, the APSC approved fuel rates that provide recovery of the Arkansas share of the 2021 Dolet Hills Power Station fuel costs over five years through the existing fuel clause.

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

Pirkey Power Plant and Related Fuel Operations (Applies to AEP and SWEPCo)

In 2020, management announced plans to retire the Pirkey Power Plant in 2023. The Pirkey Power Plant non-fuel costs are recoverable by SWEPCo through base rates and fuel costs are recovered through active fuel clauses. As of September 30, 2021, SWEPCo’s share of the net investment in the Pirkey Power Plant is $203 million, including CWIP, before cost of removal. Sabine is a mining operator providing mining services to the Pirkey Power Plant. Under the provisions of the mining agreement, SWEPCo is required to pay, as part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. SWEPCo expects fuel deliveries, including billings of all fixed and operating costs, from Sabine to cease during the first quarter of 2023. Under the fuel agreements, SWEPCo’s fuel inventory and unbilled fuel costs from mining related activities were $108 million as of September 30, 2021. Also, as of September 30, 2021, SWEPCo had a net under-recovered fuel balance of $39 million, excluding impacts of the February 2021 severe winter weather event, which includes fuel consumed at the Pirkey Power Plant. Additional operational, reclamation and other land-related costs incurred by Sabine will be billed to SWEPCo and included in future fuel clauses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition..

2020 Texas Fuel Reconciliation (Applies to AEP and SWEPCo)

In June 2020, SWEPCo filed a fuel reconciliation with the PUCT for its retail operations in Texas for the reconciliation period of March 1, 2017 to December 31, 2019. The fuel reconciliation included total fuel costs of $1.7 billion ($616 million of which is related to the Texas jurisdiction). In January 2021, various parties filed testimony recommending fuel cost disallowances totaling $125 million relating to the Texas jurisdiction. Also in January 2021, SWEPCo filed rebuttal testimony disputing the recommended disallowances. In February 2021, SWEPCo and various parties reached a settlement in principle which resulted in a $10 million reduction in recoverable fuel costs for the reconciliation period, which was recognized in SWEPCo’s 2020 financial statements. In June 2021, the settlement was filed and is currently awaiting approval from the PUCT. If additional costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
155

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

		AEP	
		September 30,		December 31,	
		2021		2020	
 Noncurrent Regulatory Assets		(in millions)	
		 		 	
Regulatory Assets Currently Earning a Return		 		 	
Unrecovered Winter Storm Fuel Costs (a)		$	1,106.3 			$	— 		
Dolet Hills Power Station Accelerated Depreciation		126.8 			71.2 		
Pirkey Power Plant Accelerated Depreciation		68.0 			12.2 		
Kentucky Deferred Purchase Power Expenses		45.9 			41.3 		
Welsh Plant, Units 1 and 3 Accelerated Depreciation		35.6 			3.6 		
Plant Retirement Costs – Unrecovered Plant, Louisiana		35.2 			35.2 		
Oklaunion Power Station Accelerated Depreciation		33.0 			34.4 		
	
Dolet Hills Power Station Fuel Costs - Louisiana		20.3 			— 		
Other Regulatory Assets Pending Final Regulatory Approval		25.5 			22.8 		
Regulatory Assets Currently Not Earning a Return		 		 	
Storm-Related Costs		325.8 			134.2 		
Plant Retirement Costs – Asset Retirement Obligation Costs		25.9 			25.9 		
COVID-19		14.0 			24.9 		
Asset Retirement Obligation - Louisiana		10.0 			9.1 		

	
Other Regulatory Assets Pending Final Regulatory Approval		32.6 			27.4 		
Total Regulatory Assets Pending Final Regulatory Approval	$	1,904.9 			$	442.2 		

(a)PSO and SWEPCo have active fuel clauses that allow for the recovery of prudently incurred fuel and purchased power expenses. However, the recovery of these costs from customers may be extended over longer than usual time periods to mitigate the impact on customer bills. See “Impacts of Severe Winter Weather” section below for additional information.

		AEP Texas	
		September 30,		December 31,	
		2021		2020	
Noncurrent Regulatory Assets		(in millions)	
					
Regulatory Assets Currently Earning a Return					
Advanced Metering System		$	16.6 			$	16.3 		
Regulatory Assets Currently Not Earning a Return		 		 	
Storm-Related Costs		22.7 			0.8 		
Vegetation Management Program		5.2 			3.8 		
Texas Retail Electric Provider Bad Debt Expense		4.1 			— 		
COVID-19		3.9 			10.5 		
Other Regulatory Assets Pending Final Regulatory Approval		5.3 			1.5 		
Total Regulatory Assets Pending Final Regulatory Approval		$	57.8 			$	32.9 		

156

															
		APCo	
		September 30,		December 31,	
		2021		2020	
Noncurrent Regulatory Assets		(in millions)	
					
Regulatory Assets Currently Earning a Return					
COVID-19 – Virginia		$	6.6 			$	3.7 		
	
Regulatory Assets Currently Not Earning a Return		 		 	
Storm-Related Costs		59.8 			3.4 		
Plant Retirement Costs – Asset Retirement Obligation Costs		25.9 			25.9 		
COVID-19 – West Virginia		0.4 			1.5 		
Environmental Expense Deferral - Virginia		— 			9.3 		
Other Regulatory Assets Pending Final Regulatory Approval		1.2 			— 		
Total Regulatory Assets Pending Final Regulatory Approval		$	93.9 			$	43.8 		

 		I&M	
		September 30,		December 31,	
		2021		2020	
Noncurrent Regulatory Assets		(in millions)	
		 		 	
Regulatory Assets Currently Earning a Return					
Other Regulatory Assets Pending Final Regulatory Approval		$	— 			$	0.5 		
Regulatory Assets Currently Not Earning a Return		 		 	
COVID-19		1.7 			3.8 		

Other Regulatory Assets Pending Final Regulatory Approval		1.7 			— 		
Total Regulatory Assets Pending Final Regulatory Approval		$	3.4 			$	4.3 		

 		OPCo	
		September 30,		December 31,	
		2021		2020	
Noncurrent Regulatory Assets		(in millions)	
		 		 	
Regulatory Assets Currently Not Earning a Return		 		 	

	
Storm-Related Costs		$	5.5 			$	4.0 		
COVID-19		1.9 			4.4 		
Other Regulatory Assets Pending Final Regulatory Approval		0.1 			— 		
Total Regulatory Assets Pending Final Regulatory Approval		$	7.5 			$	8.4 		

 		PSO	
		September 30,		December 31,	
		2021		2020	
Noncurrent Regulatory Assets		(in millions)	
		 		 	
Regulatory Assets Currently Earning a Return		 		 	
Unrecovered Winter Storm Fuel Costs (a)		$	673.2 			$	— 		
Oklaunion Power Station Accelerated Depreciation		33.0 			34.4 		
	
Regulatory Assets Currently Not Earning a Return		 		 	

Storm-Related Costs		29.3 			15.8 		
Other Regulatory Assets Pending Final Regulatory Approval		0.9 			0.3 		
Total Regulatory Assets Pending Final Regulatory Approval		$	736.4 			$	50.5 		

(a)PSO has an active fuel clause that allows for the recovery of prudently incurred fuel and purchased power expenses. However, the recovery of these costs from customers may be extended over longer than usual time periods to mitigate the impact on customer bills. See “Impacts of Severe Winter Weather” section below for additional information.
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		SWEPCo	
		September 30,		December 31,	
		2021		2020	
Noncurrent Regulatory Assets		(in millions)	
		 		 	
Regulatory Assets Currently Earning a Return		 		 	
Unrecovered Winter Storm Fuel Costs (a)		$	433.1 			$	— 		
Dolet Hills Power Station Accelerated Depreciation		126.8 			71.2 		
Pirkey Power Plant Accelerated Depreciation		68.0 			12.2 		
Welsh Plant, Units 1 and 3 Accelerated Depreciation		35.6 			3.6 		
Plant Retirement Costs – Unrecovered Plant, Louisiana		35.2 			35.2 		
Dolet Hills Power Station Fuel Costs- Louisiana		20.3 			— 		
Other Regulatory Assets Pending Final Regulatory Approval		2.3 			2.2 		
Regulatory Assets Currently Not Earning a Return		 		 	
Storm-Related Costs		155.4 			99.3 		
Asset Retirement Obligation - Louisiana		10.0 			9.1 		

	
Other Regulatory Assets Pending Final Regulatory Approval		19.3 			14.5 		
Total Regulatory Assets Pending Final Regulatory Approval		$	906.0 			$	247.3 		

(a)SWEPCo has an active fuel clause that allows for the recovery of prudently incurred fuel and purchased power expenses. However, the recovery of these costs from customers may be extended over longer than usual time periods to mitigate the impact on customer bills. See “Impacts of Severe Winter Weather” section below for additional information.

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

Impacts of Severe Winter Weather

Storm Restoration Costs (Applies to AEP, APCo and SWEPCo)

In February 2021, severe winter weather impacted the service territories of APCo, KPCo and SWEPCo resulting in power outages and extensive damage to transmission and distribution infrastructures. As a result, incremental restoration expenses have been deferred related to the severe winter weather. The storm restoration costs are as follows:

				September 30, 2021	
Company		Jurisdiction		Capital		O&M		Regulatory Asset		Total	
				(in millions)	
APCo		Virginia		$	8.1 			$	2.2 			$	6.6 			$	16.9 		
APCo		West Virginia		23.5 			— 			47.0 			70.5 		
SWEPCo		Louisiana		6.0 			— 			45.4 			51.4 		
KPCo		Kentucky		29.0 			5.0 			42.6 			76.6 		
		Total		$	66.6 			$	7.2 			$	141.6 			$	215.4 		

The amounts in the table above represents costs as of September 30, 2021. In March 2021, the LPSC approved the deferral of incremental other operation and maintenance storm restoration expenses related to the Louisiana jurisdiction for SWEPCo. Similarly, in April 2021, the KPSC approved deferral of KPCo’s incremental other operation and maintenance storm restoration expenses. KPCo intends to seek recovery of these incremental storm restoration costs in their next base rate case while APCo is expected to seek recovery in separate filings. In October 2021, SWEPCo requested recovery of these storm costs, in addition to storm costs from Hurricanes Delta and Laura, in a filing with the LPSC. As part of the filing, SWEPCo requested recovery of the carrying charges on the regulatory asset at a weighted average cost of capital through a rider beginning in January 2022. If any of the
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restoration costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

February 2021 Severe Winter Weather Impacts in SPP (Applies to AEP, PSO and SWEPCo)

The February 2021 severe winter weather also had a significant impact in SPP resulting in the declaration of Energy Emergency Alert Levels 2 and 3 for the first time in SPP’s history. The winter storm increased the demand for natural gas and restricted the available natural gas supply resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system. From February 9, 2021, to February 20, 2021, PSO’s and SWEPCo’s natural gas expenses and purchases of electricity still to be recovered from customers are as follows:
																					
		PSO		SWEPCo		Total	
		(in millions)	
Retail Customers (a)		$	673.2 			$	433.1 		(b)	$	1,106.3 		
Wholesale Customers		— 			55.8 			55.8 		
Total		$	673.2 			$	488.9 			$	1,162.1 		

(a)These costs were deferred as regulatory assets as of September 30, 2021.
(b)SWEPCo’s balance consists of $107 million, $151 million and $175 million related to the Arkansas, Louisiana and Texas jurisdictions, respectively.

Retail Customers

PSO and SWEPCo have active fuel clauses that allow for the recovery of prudently incurred fuel and purchased power expenses. Given the significance of these costs, PSO and SWEPCo expect the costs to be subject to prudency reviews. Management believes these costs are probable of future recovery, but expects the recovery period to be extended to mitigate the impact on customer bills.

In March 2021, the APSC issued an order authorizing recovery of the Arkansas jurisdictional share of the retail customer fuel costs over five years, with the appropriate carrying charge to be determined at a later date. Accordingly, in April 2021, SWEPCo began recovery of its Arkansas jurisdictional share of these fuel costs, which are subject to true-up by the APSC. SWEPCo is recovering these fuel costs at an interim carrying charge of 0.8%. Also in April 2021, SWEPCo filed testimony supporting a five-year recovery with a carrying charge of 6.05% which has been supported by APSC staff. Various other parties have recommended recovery periods ranging from 5-20 years with a carrying charge of 1.65%. The APSC ordered more testimony regarding the option of utilizing securitization to recover the fuel costs. SWEPCo is awaiting a decision from the APSC. The prudency of these fuel costs is expected to be addressed in a separate proceeding.

In March 2021, the LPSC approved a special order granting a temporary modification to the FAC that allows SWEPCo to recover the Louisiana jurisdictional share of these retail fuel costs over a longer period than what the FAC traditionally allows. In April 2021, SWEPCo began recovery of its Louisiana jurisdictional share of these fuel costs based on a five year recovery period. SWEPCo is recovering these fuel costs at an interim carrying charge of 3.25%. SWEPCo will work with the LPSC to finalize the actual recovery period and determine the appropriate carrying charge in future proceedings.

In April 2021, the OCC approved a waiver for PSO allowing the deferral of the extraordinary fuel and purchase of electricity costs, including a carrying charge at an interim rate of 0.75%, over a longer time period than what the FAC traditionally allows. Also in April 2021, legislation was enacted in Oklahoma to permit securitization of the extraordinary fuel and purchase of electricity costs impacting the utilities within the state. Under the legislation, the OCC has the authority to determine, after receiving an application from a rate-regulated utility, if the extraordinary fuel and purchase of electricity costs incurred in February 2021 may be mitigated through securitization to reduce the impact on customer bills. PSO has filed an application for a financing order to pursue securitization. The application requests an order on the prudency of the extraordinary fuel and purchase of electricity costs and a
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carrying charge of the commission authorized weighted average cost of capital until securitization bonds can be issued. In October 2021, OCC staff and intervenors filed testimony supporting securitization of these costs and a carrying charge until costs are securitized ranging from the interim rate of 0.75% to the actual cost of capital used to finance the costs of 2.32%. In addition, OCC staff supported the prudency of PSO's requested costs while one intervenor recommended disallowances of up to $40 million. A procedural schedule has been set with an ALJ report to be filed in January 2022. An order from the OCC is expected in the first quarter of 2022.

In August 2021, SWEPCo filed an application with the PUCT to implement a net interim fuel surcharge for the Texas jurisdictional share of these retail fuel costs. The application supported a five-year recovery at a carrying charge of 7.18%. In October 2021, various intervenors filed testimony supporting a five-year recovery with a carrying charge ranging from 0.082% to 1.625%. A hearing with the PUCT is scheduled for November 2021.

Wholesale Customers

During the first quarter of 2021, SWEPCo billed wholesale customers $104 million resulting from the severe winter weather events. SWEPCo worked with wholesale customers to establish payment terms for the outstanding accounts receivable. As of September 30, 2021, $56 million of accounts receivable from wholesale customers are outstanding. Management believes these receivables are probable of future collection.

PSO and SWEPCo Cash Flow Implications

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

Although the February 2021 severe winter weather did not materially impact AEP’s results of operations for the three and nine months ended September 30, 2021, if either PSO or SWEPCo is unable to recover these fuel and purchased power costs, or obtain authorization of a reasonable carrying charge on these costs, it could reduce future net income and cash flows and impact financial condition.

COVID-19 Pandemic

During 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. As of September 30, 2021, AEP’s electric operating companies have resumed customary disconnection practices in all regulated jurisdictions with the exception of residential customers in Virginia. AEP continues to work with regulators and stakeholders in Virginia and management currently anticipates resuming customary disconnection practices once available relief funds are received from the state. 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. If any costs related to COVID-19 are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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AEP Texas Rate Matters (Applies to AEP and AEP Texas)

AEP Texas Interim Transmission and Distribution Rates

Through September 30, 2021, AEP Texas’ cumulative revenues from interim base rate increases that are subject to review is approximately $229 million. A base rate review could result in a refund to customers if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. AEP Texas is required to file for a comprehensive rate review no later than April 5, 2024.

APCo and WPCo Rate Matters (Applies to AEP and APCo)

2017-2019 Virginia Triennial Review

In November 2020, the Virginia SCC issued an order on APCo’s 2017-2019 Triennial Review filing concluding that APCo earned above its authorized ROE but within its ROE band for the 2017-2019 period, resulting in no refund to customers and no change to APCo base rates on a prospective basis. The Virginia SCC approved a prospective 9.2% ROE for APCo's 2020-2022 triennial review period with the continuation of a 140 basis point band (8.5% bottom, 9.2% midpoint, 9.9% top).

In December 2020, an intervenor filed a petition at the Virginia SCC requesting reconsideration of: (a) the failure of the Virginia SCC to apply a threshold earnings test to the approved regulatory asset for APCo’s closed coal-fired generation assets, (b) the Virginia SCC’s use of a 2011 benchmark study to measure the replacement value of capacity for purposes of APCo’s 2017 – 2019 earnings test and (c) the reasonableness and prudency of APCo’s investments in AMI meters.

In December 2020, APCo filed a petition at the Virginia SCC requesting reconsideration of: (a) certain issues related to APCo’s going-forward rates and (b) the Virginia SCC’s decision to deny APCo tariff changes that align rates with underlying costs. For APCo’s going-forward rates, APCo requested that the Virginia SCC clarify its final order and clarify whether APCo’s current rates will allow it to earn a fair return. If the Virginia SCC’s order did conclude on APCo’s ability to earn a fair return through existing base rates, APCo further requested that the Virginia SCC clarify whether it has the authority to also permit an increase in base rates.

In March 2021, an intervenor filed its assignments of error with the Virginia Supreme Court related to the appeal of the November 2020 order in which it stated the Virginia SCC erred: (a) in determining that Virginia law did not apply to its determination to permit amortization for recovery of costs associated with retired coal-fired generation assets, (b) in establishing a new regulatory asset for a cost incurred outside of the triennial review period due to its failure to apply a threshold earnings test before approving deferred cost recovery and (c) in misapplying the requirement that APCo bear the burden of demonstrating that power purchases made by APCo from its affiliate, OVEC, were priced at the lower of OVEC’s cost or the market price for nonaffiliated power.

In March 2021, APCo filed its assignments of error with the Virginia Supreme Court related to its appeal of the November 2020 order in which it stated the Virginia SCC erred: (a) in finding that costs associated with asset impairments related to early retirement determinations made by APCo for certain generation facilities should not be attributed to the test periods under review and deemed fully recovered in the period recorded, (b) in finding that it was permitted to evaluate the reasonableness of APCo’s decision to record, per books for financial reporting purposes, asset impairments related to early retirement determinations for certain generation facilities, (c) as a result of the errors described in (a) and (b), in denying APCo an increase in rates, (d) in failing to review and make any findings regarding whether APCo’s rates would allow it to earn a fair rate of return going forward, (e) in denying APCo an increase in base rates by failing to ensure that APCo has an opportunity to recover its costs and earn a fair rate of return, thereby resulting in a taking of private property for public use without just compensation and (f) in
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retroactively adjusting APCo’s depreciation expense for purposes of calculating APCo’s earnings for the 2017-2019 triennial period.

In March 2021, the Virginia SCC issued an order confirming certain of its decisions from the November 2020 order and rejecting the various requests for reconsideration from APCo and an intervenor. In confirming its decision to reject an intervenor’s recommendation that APCo’s AMI costs incurred during the triennial period be disallowed, the Virginia SCC clarified that APCo established the need to replace its existing AMR meters, and that based on the uncertainty surrounding the continued manufacturing and support of AMR technology, APCo reasonably chose to replace them with AMI meters. In March 2021, APCo filed a notice of appeal of the reconsideration order with the Virginia Supreme Court. In September 2021, APCo submitted its brief before the Virginia Supreme Court. The brief was in alignment with the assignments of error filed by APCo in March 2021. In October 2021, the Virginia SCC and certain intervenors filed briefs with the Virginia Supreme Court disagreeing with APCo’s assignments of error in its appeal of the Triennial Review decision. Additionally, the Virginia SCC and APCo filed briefs disagreeing with an intervenor’ s assignments of error in a separate appeal of the same decision.

APCo ultimately seeks an increase in base rates through its appeal to the Virginia Supreme Court. Among other issues, this appeal includes APCo’s request for proper treatment of the closed coal-fired plant assets in APCo’s 2017-2019 triennial period, reducing APCo’s earnings below the bottom of its authorized ROE band. If APCo’s appeals regarding treatment of the closed coal plants are granted by the Virginia Supreme Court, it could initially reduce future net income and impact financial condition. The initial negative impact for the write-off of closed coal-fired plant asset balances would potentially be partially offset by an increase in base rates for earning below APCo’s 2017-2019 authorized ROE band.

CCR/ELG Compliance Plan Filings

In December 2020, APCo submitted filings with the Virginia SCC and WVPSC requesting approvals necessary to implement CCR/ELG compliance plans at the Amos and Mountaineer Plants. Intervenors in Virginia and West Virginia recommended that only the CCR-related investments be constructed at Amos and Mountaineer and, as a consequence, that APCo close these generating facilities at the end of 2028.

In August 2021, the Virginia SCC issued an order approving APCo’s request to construct CCR-related investments at the Amos and Mountaineer Plants and approved recovery of CCR-related other operation and maintenance expenses and investments through an active rider. The order denied APCo’s request to construct the ELG investments and denied recovery of previously incurred ELG costs. APCo may refile for approval of the ELG investments and previously incurred ELG costs at a later date.

Also in August 2021, the WVPSC approved the request to construct CCR/ELG investments at the Amos and Mountaineer Plants and approved recovery of the West Virginia jurisdictional share of these costs through an active rider. In September 2021, APCo submitted a filing with the WVPSC to reopen the CCR/ELG case that was approved by the WVPSC in August 2021. Due to the initial rejection by the Virginia SCC of the Virginia jurisdictional share of the ELG investments, APCo requested the WVPSC consider approving the construction and recovery of all ELG costs at the plants. In October 2021, the WVPSC affirmed its August 2021 order approving the construction of CCR/ELG investments and directed APCo to proceed with CCR/ELG compliance plans that would allow the plants to continue operating beyond 2028. The WVPSC’s order further states that APCo will not share capacity and energy from the plants with customers from Virginia if those customers are not paying for ELG compliance costs, or for any new capital investment or continuing operations costs incurred, to allow the plants to operate beyond 2028 or prevent downgrades prior to 2028. The WVPSC also ordered that APCo will be given the opportunity to recover, from West Virginia customers, the new capital and operating costs arising solely from the WVPSC's directive to operate the plants beyond 2028 if the WVPSC finds that the costs are reasonably and prudently incurred. In October 2021, an intervenor filed a petition for reconsideration at the WVPSC requesting clarification on certain aspects of the order, primarily the jurisdictional allocation of future operating expenses and plant costs.
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APCo expects total Amos and Mountaineer Plant ELG investment, including AFUDC, to be approximately $177 million. As of September 30, 2021, APCo’s Virginia jurisdictional share of the net book value, before cost of removal including CWIP and inventory, of the Amos and Mountaineer Plants was approximately $1.5 billion and APCo’s Virginia jurisdictional share of its ELG investment balance in CWIP for these plants was $19 million.

If any of the ELG costs are not approved for recovery and/or the retirement dates of the Amos and Mountaineer plants are accelerated to 2028 without commensurate cost recovery, it would reduce future net income and cash flows and impact financial condition.

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, 2021, AEP’s share of ETT’s cumulative revenues that are subject to review is approximately $1.3 billion. A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. ETT is required to file for a comprehensive rate review no later than February 1, 2023, during which the $1.3 billion of cumulative revenues above will be subject to review.

I&M Rate Matters (Applies to AEP and I&M)

Indiana Earnings Test Filings

I&M is required by Indiana law to submit an earnings test evaluation for the most recent one-year and five-year periods as part of I&M’s semi-annual Indiana FAC filings. These earnings test evaluations require I&M to include a credit in the FAC factor computation for periods in which I&M earned above its authorized return for both the one-year and five-year periods. The credit is determined as 50% of the lower of the one-year or five-year earnings above the authorized level. In July 2021, I&M submitted its FAC filing and earnings test evaluation for the period ended May 2021, which calculated a credit due to customers of $9 million. In September 2021, the IURC approved the FAC filing and earnings test evaluation, with the credit to customers starting in October 2021 through the FAC.

2021 Indiana Base Rate Case

In July 2021, I&M filed a request with the IURC for a $104 million annual increase in Indiana base rates based upon a proposed 10% ROE. I&M proposed a phased-in annual increase in rates of $73 million effective in May 2022 with the remaining $31 million annual increase in rates to be effective January 2023. The proposed annual increase includes $7 million related to an annual increase in depreciation expense, driven by increased depreciation rates and proposed investments. The request also includes a new AMI rider for proposed meter projects.

In October 2021, intervenors submitted testimony recommending an annual decrease in Indiana base rates ranging from $13 million to $68 million based upon a ROE ranging from 9.1% to 9.3%. Among other issues, intervening parties recommended that the IURC reject the following: (a) I&M’s proposed re-allocation of capacity costs related to the 2020 loss of a significant FERC wholesale contract, (b) continued recovery of a return on remaining Rockport Unit 2 leasehold improvements once the related lease ends in December 2022, (c) inclusion of net operating loss in rate base, (d) the proposed new AMI rider and (e) inclusion of prepaid pension and OPEB assets in rate base. I&M rebuttal testimony is due in November 2021. If any costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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KPCo Rate Matters (Applies to AEP)

CCR/ELG Compliance Plan Filings

KPCo and WPCo each own a 50% interest in the Mitchell Plant. In December 2020 and February 2021, WPCo and KPCo filed requests with the WVPSC and KPSC, respectively, to obtain the regulatory approvals necessary to implement CCR and ELG compliance plans and seek recovery of the estimated $132 million investment for the Mitchell Plant that would allow the plant to continue operating beyond 2028. Within those requests, WPCo and KPCo also filed a $25 million alternative to implement only the CCR-related investments with the WVPSC and KPSC, respectively, which would allow the Mitchell Plant to continue operating only through 2028.

In July 2021, the KPSC issued an order approving the CCR only alternative and rejecting the full CCR and ELG compliance plan. In August 2021, the WVPSC approved the full CCR and ELG compliance plan for the WPCo share of the Mitchell Plant. In September 2021, WPCo submitted a filing with the WVPSC to reopen the CCR/ELG case that was approved by the WVPSC in August 2021. Due to the rejection by the KPSC of the KPCo share of the ELG investments, WPCo requested the WVPSC consider approving the construction and recovery of all ELG costs at the plant. In October 2021, the WVPSC affirmed its August 2021 order approving the construction of CCR/ELG investments and directed WPCo to proceed with CCR/ELG compliance plans that would allow the plant to continue operating beyond 2028. The WVPSC’s order further states WPCo will not share capacity and energy from the plant with KPCo customers if those customers are not paying for ELG compliance costs, or for any new capital investment or continuing operations costs incurred, to allow the plant to operate beyond 2028 or prevent downgrades prior to 2028. The WVPSC also ordered that WPCo will be given the opportunity to recover, from its customers, the new capital and operating costs arising solely from the WVPSC's directive to operate the plant beyond 2028 if the WVPSC finds that the costs are reasonably and prudently incurred. In October 2021, an intervenor filed a petition for reconsideration at the WVPSC requesting clarification on certain aspects of the order, primarily the jurisdictional allocation of future operating expenses and plant costs.

As of September 30, 2021, KPCo’s share of the Mitchell Plant’s ELG investment balance in CWIP was $2 million. As of September 30, 2021, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $587 million.

If any of the ELG costs are not approved for recovery and/or the retirement date of the Mitchell Plant is accelerated to 2028 without commensurate cost recovery, it would 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.

In November 2020, the PUCO staff filed testimony supporting an annual revenue decrease ranging from $102 million to $123 million based upon a ROE of 8.76% to 9.78%. The difference between OPCo’s request and the staff testimony are primarily due to reductions in: (a) demand-side management programs of $40 million, (b) ROE ranging from $9 million to $30 million, (c) employee-related expenses of $23 million, (d) rate base of $19 million, (e) property taxes of $17 million, (f) other various expenses of $15 million, (g) depreciation expense of $11 million and (h) vegetation management programs of $10 million which is subject to over/under-recovery through a rider. The staff’s proposed disallowance of plant in service could also result in a write-off of up to $27 million. In addition, the staff recommended that capitalized incentives be excluded from base rates prospectively and also recommended annual revenue caps for the DIR of $57 million in 2021, $78 million in 2022, $96 million in 2023 and $46 million for the first five months of 2024. In December 2020, OPCo and intervenors filed objections.
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In March 2021, OPCo, the PUCO staff and various intervenors filed a joint stipulation and settlement agreement with the PUCO. The agreement includes a $68 million annual decrease in base rates based on an ROE of 9.7%. The difference between OPCo’s requested annual base rate increase and the agreed upon decrease is primarily due to a reduction in the requested ROE, the removal of proposed future energy efficiency costs and a decrease in vegetation management expenses moved to recovery in riders. Additionally, the agreement includes: (a) an increased fixed monthly residential customer charge, (b) the discontinuation of rate decoupling and (c) the continuation of the DIR with annual revenue caps of $57 million in 2021, $91 million in 2022, $116 million in 2023 and $51 million for the first five months of 2024. Annual revenue caps for the DIR can be increased if OPCo achieves certain reliability standards. If the joint stipulation and settlement agreement is approved by the PUCO, new base rates will go into effect 14 days after such approval. A hearing took place with the PUCO in May 2021 and initial briefs were filed in June 2021 followed by reply briefs in July 2021. An order from the PUCO is expected in the fourth quarter of 2021. If the joint stipulation and settlement agreement is denied by the PUCO, it could reduce future net income and cash flows and impact financial condition.

2019 Ohio DIR Audit

OPCo conducts business under an ESP as approved by the PUCO which subjects the DIR to annual audits. In August 2020, a third-party consulting company filed an audit report with the PUCO indicating that OPCo exceeded its 2019 authorized revenue limit by $17 million. In September 2021, the third-party consulting company adjusted its findings in the previous audit, indicating that OPCo exceeded its 2019 authorized revenue limit by $3 million. Management disagrees with the audit results and believes that OPCo was below its authorized revenue limit in 2019. 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.

PSO Rate Matters (Applies to AEP and PSO)

2021 Oklahoma Base Rate Case

In April 2021, PSO filed a request with the OCC for a $172 million net annual increase in Oklahoma base rates based upon a 10% ROE. The proposed net annual increase includes: (a) a $57 million annual depreciation expense increase, of which $45 million is related to the accelerated depreciation recovery of the Oklaunion Power Station and Northeastern Plant, Unit 3 through 2026 and (b) $31 million related to increased SPP expenses. PSO also requested the continuation of its SPP Transmission Tariff that tracks transmission costs as well as continuation and expansion of its Distribution and Safety Reliability Rider to recover projects in its proposed grid transformation and revitalization plan, which includes $100 million annual capital spend over a 5 year period. In August 2021, PSO updated its request for a net annual revenue increase to appropriately reflect certain cost reductions and annualized rider revenues transitioning into base rates. PSO’s updated request filed with the OCC is for a $128 million net annual increase in Oklahoma base rates based upon a 10% ROE.

Also, in August 2021, OCC staff and various intervenors filed testimony supporting net annual revenue changes ranging from a $44 million net decrease to a $74 million net increase based upon a ROE of 9.0% to 9.4%. The difference between PSO’s request and OCC staff and intervenor testimony is primarily due to: (a) disallowance of recovery of Oklaunion Power Station or allowing recovery with a debt-only return over Oklaunion Power Station's original useful life of 2046, (b) rejection of PSO’s request to accelerate the recovery of Northeastern Plant, Unit 3 from its original retirement date of 2040 to its projected retirement date of 2026, (c) disallowance of $41 million in SPP transmission expense and denial of prospective tracking of most SPP transmission costs through the SPP transmission tariff, (d) opposition to PSO’s recommendation to include its deferred tax asset associated with net operating loss on a stand-alone tax basis in rate base, (e) a lower recommended ROE and (f) recommendations to discontinue the Distribution and Safety Reliability Rider.
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In September 2021, PSO, OCC staff and certain intervenors filed a contested joint stipulation and settlement agreement with the OCC that included a net annual revenue increase of $51 million based upon a 9.4% ROE. The agreement also included: (a) recovery of, with a debt return on, the Oklaunion Power Station regulatory asset through 2046 and continued recovery of Northeastern Plant, Unit 3 through 2040, (b) updated depreciation rates for plant in service, not including coal production plant, (c) approval to defer a weighted average cost of capital carrying charge on PSO’s deferred tax asset associated with net operating loss on a stand-alone tax basis beginning in November 2021 and, contingent upon receipt of a supportive private letter ruling from the IRS, approval to collect the deferral through a rider over a 20-month period, (d) modification of the SPP transmission tariff to reduce the scope of tracked transmission expense and (e) modification of the Distribution Reliability and Safety Rider to limit recovery to previously approved projects not in service as of June 2021. In October 2021, a hearing on the merits of the contested joint stipulation and settlement agreement was held at the OCC. PSO will implement interim rates subject to refund starting with the November 2021 billing cycle. An order is expected in December 2021. If any of these costs are not recoverable, 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. In 2017, the Texas District Court upheld the PUCT’s 2014 order and intervenors filed appeals with the Texas Third Court of Appeals.

In July 2018, the Texas Third Court of Appeals reversed the PUCT’s judgment affirming the prudence of the Turk Plant and remanded the issue back to the PUCT. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court. In March 2021, the Texas Supreme Court issued an opinion reversing the July 2018 judgment of the Texas Third Court of Appeals and agreeing with the PUCT’s judgment affirming the prudence of the Turk Plant. In addition, the Texas Supreme Court remanded the AFUDC dispute back to the Texas Third Court of Appeals. No parties filed a motion for rehearing with the Texas Supreme Court. In August 2021, the Texas Third Court of Appeals reversed the Texas District Court judgement affirming the PUCT’s order on AFUDC, concluding that the language of the PUCT’s original 2008 order intended to include AFUDC in the Texas jurisdictional capital cost cap, and remanded the case to the PUCT for future proceedings. SWEPCo disagrees with the Court of Appeals decision and expects to submit a Petition for Review with the Texas Supreme Court in November 2021.

If SWEPCo is ultimately unable to recover capitalized Turk Plant costs including AFUDC in excess of the Texas jurisdictional capital cost cap it would result in a pretax net disallowance ranging from $80 million to $100 million. In addition, if AFUDC is ultimately determined to be included in the Texas jurisdictional capital cost cap, SWEPCo estimates it may be required to make customer refunds ranging from $0 to $160 million related to revenues collected from February 2013 through September 2021 and such determination may reduce SWEPCo’s future revenues by approximately $15 million on an annual basis.

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2016 Texas Base Rate Case

In 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% ROE. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $50 million based upon a ROE of 9.6%, effective May 2017. The final order also included: (a) approval to recover the Texas jurisdictional share of environmental investments placed in-service, as of June 30, 2016, at various plants, including Welsh Plant, Units 1 and 3, (b) approval of recovery of, but no return on, the Texas jurisdictional share of the net book value of Welsh Plant, Unit 2, (c) approval of $2 million in additional vegetation management expenses and (d) the rejection of SWEPCo’s proposed transmission cost recovery mechanism.

As a result of the final order in 2017, SWEPCo: (a) recorded an impairment charge of $19 million, which included $7 million associated with the lack of return on Welsh Plant, Unit 2 and $12 million related to other disallowed plant investments, (b) recognized $32 million of additional revenues, for the period of May 2017 through December 2017, that was surcharged to customers in 2018 and (c) recognized an additional $7 million of expenses consisting primarily of depreciation expense and vegetation management expense, offset by the deferral of rate case expense. SWEPCo implemented new rates in February 2018 billings. The $32 million of additional 2017 revenues was collected during 2018. In March 2018, the PUCT clarified and corrected portions of the final order, without changing the overall decision or amounts of the rate change. The order has been appealed by various intervenors. The appeal will move forward following the conclusion of the 2012 Texas Base Rate Case. If certain parts of the PUCT order are overturned, it could reduce future net income and cash flows and impact financial condition.

Hurricane Laura

In August 2020, Hurricane Laura hit the coasts of Louisiana and Texas, causing power outages to more than 130,000 customers across SWEPCo’s service territories. Prior to Hurricane Laura, SWEPCo did not have a catastrophe reserve or automatic deferral authority within any of its jurisdictions. In October 2020, the LPSC issued an order allowing Louisiana utilities, including SWEPCo, to establish a regulatory asset to track and defer expenses associated with Hurricane Laura. In October 2020, as part of the 2020 Texas Base Rate Case, SWEPCo requested deferral authority of incremental other operation and maintenance expenses. As of September 30, 2021, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $92 million ($89 million of which has been deferred as a regulatory asset related to the Louisiana jurisdiction) and incremental capital expenditures of $18 million, all of which is related to the Louisiana jurisdiction. In October 2021, SWEPCo requested recovery of these storm costs, in addition to Hurricane Delta and February 2021 winter storm costs, in a filing with the LPSC. See “Storm Restoration Costs” above for more information. If any costs related to Hurricane Laura are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Hurricane Delta

In October 2020, Hurricane Delta hit the coast of Louisiana, causing power outages to more than 23,000 customers in SWEPCo’s Louisiana jurisdiction. In November 2020, the LPSC issued an order allowing Louisiana utilities, including SWEPCo, to establish a regulatory asset to track and defer expenses associated with Hurricane Delta. As of September 30, 2021, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $18 million, which has been deferred as a regulatory asset. Also, management estimates that SWEPCo has incurred incremental capital expenditures of $2 million. In October 2021, SWEPCo requested recovery of these storm costs, in addition to Hurricane Laura and February 2021 winter storm costs, in a filing with the LPSC. See “Storm Restoration Costs” above for more information. 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 SWEPCo’s Texas jurisdictional distribution system, (b) requests a $10 million annual depreciation increase and (c) seeks $2 million annually to establish a storm catastrophe reserve. In addition, SWEPCo requested recovery of the Texas jurisdictional share of the Dolet Hills Power Station of $45 million which is expected to be retired by the end of 2021. SWEPCo subsequently filed a request with the PUCT lowering the requested annual increase in Texas base rates to $100 million which would result in an $85 million net annual base rate increase after moving the proposed riders to rate base.

In August 2021, an ALJ issued a Proposal for Decision (PFD) which would provide SWEPCo with an annual revenue increase of $41 million based upon a 9.45% ROE. The PFD also includes: (a) rates implemented retroactively back to March 18, 2021, (b) $5 million of the proposed increase related to vegetation management, (c) a denial of the requested $2 million annually to establish a storm catastrophe reserve and (d) the creation of a rider that would recover the Dolet Hills Power Station as if it were in rate base until its retirement at the end of 2021 and starting in 2022 the remaining net book value would be recovered as a regulatory asset through 2046. An order from the PUCT is expected in the fourth quarter of 2021. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2020 Louisiana Base Rate Case

In December 2020, SWEPCo filed a request with the LPSC for a $134 million annual increase in Louisiana base rates based upon a proposed 10.35% ROE. In March 2021, SWEPCo filed a revised request with the LPSC to remove hurricane storm costs from the base rate case filing and seek recovery of those costs in a separate filing. SWEPCo’s revised filing requested an annual increase in Louisiana base rates of $114 million. The request would extend the formula rate plan for five years and includes modifications to the formula rate plan to allow for forward-looking transmission costs, reflects the impact of net operating losses associated with the acceleration of certain tax benefits and incorporates future federal corporate income tax changes. The proposed net annual increase requests a $32 million annual depreciation increase to recover Louisiana’s share of the Dolet Hills Power Station, Pirkey Power Plant and Welsh Plant, all of which are expected to be retired early. In April 2021, the LPSC approved SWEPCo’s request to remove the hurricane storm costs from the base rate case filing. In October 2021, SWEPCo requested recovery of the $152 million of storm costs associated with Hurricanes Delta, Laura and the February 2021 winter storm in a filing with the LPSC. See “Storm Restoration Costs” above for more information.

In July 2021, the LPSC staff filed testimony supporting a $6 million annual increase in base rates based upon an ROE of 9.1% while other intervenors recommended an ROE ranging from 9.35% to 9.8%. The primary differences between SWEPCo’s requested annual increase in base rates and the LPSC staff’s recommendation include: (a) a reduction in depreciation expense, (b) recovery of Dolet Hills Power Station and Pirkey Power Plant in a separate rider mechanism, (c) the rejection of SWEPCo’s proposed adjustment to include a stand-alone net operating loss carryforward deferred tax asset in rate base and (d) a reduction in the proposed ROE.

In September 2021, SWEPCo filed rebuttal testimony supporting a revised requested annual increase in base rates of $95 million. The primary differences in the rebuttal testimony from the previous revised request of $114 million are modifications to the proposed recovery of the Dolet Hills Power Station and revisions to various proposed amortizations. LPSC staff and intervenor responses to SWEPCo’s rebuttal testimony were filed in October 2021.

If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
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2021 Arkansas Base Rate Case

In July 2021, SWEPCo filed a request with the APSC for an $85 million annual increase in Arkansas base rates based upon a proposed 10.35% ROE. The proposed annual increase includes: (a) a $41 million revenue requirement for the North Central Wind Facilities, (b) a $14 million annual depreciation increase primarily due to recovery of the Dolet Hills Power Station through 2026 and Pirkey Plant and Welsh Plant, Units 1 and 3 through 2037 and (c) a $6 million increase due to SPP costs. SWEPCo requests that rates are effective beginning in June 2022. Staff and intervenor testimony is expected in December 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

FERC SPP Transmission Formula Rate Challenge (Applies to AEP, AEPTCo, PSO and SWEPCo)

In May 2021, certain joint customers submitted a formal challenge at the FERC related to the 2020 Annual Update of the 2019 SPP Transmission Formula Rates of the AEP transmission owning subsidiaries within SPP. Management has reviewed the formal challenge and responses were filed with the FERC at the end of July 2021. If the FERC orders revenue refunds or reductions, it could reduce future net income and cash flows and impact financial condition.

Independence Energy Connection Project (Applies to AEP)

In 2016, PJM approved the Independence Energy Connection Project (IEC) and included it in its Regional Transmission Expansion Plan to alleviate congestion. Transource Energy owns the IEC, which is located in Maryland and Pennsylvania. In June 2020, the Maryland Public Service Commission approved a Certificate of Public Convenience and Necessity to construct the portion of the IEC in Maryland. In May 2021, the Pennsylvania Public Utility Commission (PA PUC) denied the IEC certificate for siting and construction of the portion in Pennsylvania. Transource Energy has appealed the PA PUC ruling in Pennsylvania state court and challenged the ruling before the United States District Court for the Middle District of Pennsylvania. The case before the state court is pending and the case before the United States District Court for the Middle District of Pennsylvania is on hold, pending the outcome of the case in the Pennsylvania state court.

In September 2021, PJM notified Transource Energy that the IEC was suspended to allow for the regulatory and related appeals process to proceed in an orderly manner without breaching milestone dates in the project agreement. PJM stated that the IEC has not been cancelled and remains necessary to alleviate congestion. PJM will reevaluate the need for the IEC at the end of 2021 during its annual reevaluation process. As of September 30, 2021, AEP’s share of IEC capital expenditures was approximately $79 million. The FERC has previously granted abandonment benefits for this project, allowing the full recovery of prudently incurred costs if the project is cancelled for reasons outside the control of Transource Energy. If any of the IEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
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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 2020 Annual Report should be read in conjunction with this report.

GUARANTEES

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

Letters of Credit (Applies to AEP and AEP Texas)

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 $4 billion and $1 billion revolving credit facilities due in March 2026 and 2023, respectively, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of September 30, 2021, 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 five uncommitted facilities totaling $375 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of September 30, 2021 were as follows:

Company		Amount		Maturity	
 		(in millions)		 	
AEP		$	179.5 			October 2021 to August 2022	
AEP Texas		2.2 			July 2022	

Guarantees of Equity Method Investees (Applies to AEP)

In 2019, AEP acquired Sempra Renewables LLC. The transaction resulted in the acquisition of a 50% ownership interest in five non-consolidated joint ventures and the acquisition of two tax equity partnerships. Parent has issued guarantees over the performance of the joint ventures. If a joint venture were to default on payments or performance, Parent would be required to make payments on behalf of the joint venture. As of September 30, 2021, the maximum potential amount of future payments associated with these guarantees was $148 million, with the last
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guarantee expiring in December 2037. The non-contingent liability recorded associated with these guarantees was $29 million, with an additional $2 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.

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, 2021, there were no material liabilities recorded for any indemnifications.

AEPSC conducts power purchase-and-sale activity on behalf of APCo, I&M, KPCo and WPCo, who are jointly and severally liable for activity conducted on their behalf.  AEPSC also conducts power purchase-and-sale activity on behalf of PSO and SWEPCo, who are jointly and severally liable for activity conducted on their behalf.

Master Lease Agreements (Applies to all Registrants except AEPTCo)

The Registrants lease certain equipment under master lease agreements.  Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee.  Historically, at the end of the lease term the fair value has been in excess of the amount guaranteed.  As of September 30, 2021, the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows:

Company		Maximum
Potential Loss	
		(in millions)	
AEP		$	47.8 		
AEP Texas		11.1 		
APCo		6.2 		
I&M		4.1 		
OPCo		7.6 		
PSO		4.7 		
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.  In November 2020, management announced that AEP will not renew the lease when it expires in 2022. AEP, AEGCo and I&M have no ownership interest in the Owner
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Trustee and do not guarantee its debt.  The future minimum lease payments for this sale-and-leaseback transaction as of September 30, 2021 were as follows:

Future Minimum Lease Payments		AEP (a)		I&M	
		(in millions)	
2021		$	74.0 			$	37.0 		
2022		147.6 			73.8 		
Total Future Minimum Lease Payments		$	221.6 			$	110.8 		

(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, 2021, the maximum potential amount of future payments required under the guaranteed leases was $43 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, 2021, AEP’s boat and barge lease guarantee liability was $2 million, of which $1 million was recorded in Other Current Liabilities and $1 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets.

In February 2020, the nonaffiliated party filed Chapter 11 bankruptcy. The party entered into a restructuring support agreement and has announced it expected to continue their operations as normal. In March 2020, the bankruptcy court approved the party’s recapitalization plan. In April 2020, the nonaffiliated party emerged from bankruptcy. Management has determined that it is reasonably possible that enforcement of AEP’s liability for future payments under these leases will be exercised within the next twelve months. In such an event, if AEP is unable to sell or incorporate any of the acquired assets into its fleet operations, it could reduce future net income and cash flows and impact financial condition.

ENVIRONMENTAL CONTINGENCIES (Applies to all Registrants except AEPTCo)

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

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

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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 suit 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 sought a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs.

After the litigation proceeded at the District Court and Circuit Court levels, on April 20, 2021, I&M and AEGCo reached an agreement to acquire 100% of the interests in Rockport Plant, Unit 2 for $115.5 million from certain financial institutions that own the unit through trusts established by Wilmington Trust, the nonaffiliated owner trustee of the ownership interests in the unit, with closing to occur as of the end of the Rockport Plant, Unit 2 lease in December 2022. The agreement is subject to customary closing conditions, including regulatory approvals and as of the closing will result in a final settlement of, and release of claims in, the lease litigation. As a result, in May 2021, at the parties’ request, the district court entered a stipulation and order dismissing the case without prejudice to plaintiffs asserting their claims in a re-filed action or a new action. Management believes its financial statements appropriately reflect the resolution of the litigation.
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Claims Challenging Transition of American Electric Power System Retirement Plan to Cash Balance Formula 

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

Litigation Related to Ohio House Bill 6 (HB 6)

In 2019, Ohio adopted and implemented HB 6 which benefits OPCo by authorizing rate recovery for certain costs including renewable energy contracts and OVEC’s coal-fired generating units. OPCo engaged in lobbying efforts and provided testimony during the legislative process in connection with HB 6. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of an Ohio legislator and associates in connection with an alleged racketeering conspiracy involving the adoption of HB 6. After AEP learned of the criminal allegations against the Ohio legislator and others relating to HB 6, the Company, with assistance from outside advisors, conducted a review of the circumstances surrounding the passage of the bill. We do not believe that AEP was involved in any wrongful conduct in connection with the passage of HB 6.

In August 2020, an AEP shareholder filed a putative class action lawsuit in the United States District Court for the Southern District of Ohio against AEP and certain of its officers for alleged violations of securities laws. The amended complaint alleges misrepresentations or omissions by AEP regarding: (a) its alleged participation in or connection to public corruption with respect to the passage of HB 6 and (b) its regulatory, legislative, political contribution, 501(c)(4) organization contribution and lobbying activities in Ohio. The complaint seeks monetary damages, among other forms of relief. On May 10, 2021, the defendants filed a motion to dismiss the securities litigation for failure to state a claim and the motion was fully briefed as of July 26, 2021. The Court has scheduled oral argument for November 23, 2021 on the motion to dismiss. The company will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

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

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

In May 2021, AEP received a subpoena from the SEC’s Division of Enforcement seeking various documents, including documents relating to the benefits to AEP from the passage of HB 6 and documents relating to AEP’s financial processes and controls. AEP is cooperating fully with the SEC’s subpoena. Although the outcome of the SEC’s investigation cannot be predicted, management does not believe the results of this inquiry will have a material impact on our financial condition, results of operations, or cash flows.
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6. ACQUISITIONS AND DISPOSITIONS

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

ACQUISITIONS

Dry Lake Solar Project (Generation & Marketing Segment)

In November 2020, AEP signed a Purchase and Sale Agreement with a nonaffiliate to acquire a 75% interest in the 100 MW Dry Lake Solar Project (Dry Lake) located in southern Nevada for approximately $114 million. In March 2021, AEP closed the transaction and the solar project was placed in-service in May 2021. Approximately $103 million of the purchase price was paid upon closing of the transaction and the remaining $11 million was paid when the project was placed in-service. In accordance with the accounting guidance for “Business Combinations,” management determined that the acquisition of Dry Lake represents an asset acquisition. Additionally, and in accordance with the accounting guidance for “Consolidation,” management concluded that Dry Lake is a VIE and that AEP is the primary beneficiary based on its power as managing member to direct the activities that most significantly impact Dry Lake’s economic performance. As the primary beneficiary of Dry Lake, AEP consolidates Dry Lake into its financial statements. As a result, to account for the initial consolidation of Dry Lake, management applied the acquisition method by allocating the purchase price based on the relative fair value of the assets acquired and noncontrolling interest assumed.  The fair value of the primary assets acquired and the noncontrolling interest assumed was determined using the market approach.  The key input assumptions were the transaction price paid for AEP’s interest in Dry Lake and recent third-party market transactions for similar solar generation facilities. The nonaffiliated interest in Dry Lake is presented in Noncontrolling Interests on the balance sheets. Subsequent to close of the transaction, the noncontrolling interest made additional asset contributions of $16 million. As of September 30, 2021, AEP recognized approximately $146 million of Property, Plant and Equipment and approximately $35 million of Noncontrolling Interest on the balance sheets.

North Central Wind Energy Facilities (Vertically Integrated Utilities Segment) (Applies to AEP, PSO and SWEPCo)

In 2020, PSO and SWEPCo received regulatory approvals to acquire the NCWF, comprised of three Oklahoma wind facilities totaling 1,485 MWs, on a fixed cost turn-key basis at completion. PSO and SWEPCo will own undivided interests of 45.5% and 54.5% of the NCWF, respectively. In total, the three wind facilities will cost approximately $2 billion and consist of Traverse (999 MW), Maverick (287 MW) and Sundance (199 MW). Output from the NCWF will serve retail load in PSO’s Oklahoma service territory and both retail and FERC wholesale load in SWEPCo’s service territories in Arkansas and Louisiana. The Oklahoma and Louisiana portions of the NCWF revenue requirement, net of PTC benefit, are recoverable through authorized riders beginning at commercial operation and until such time as amounts are reflected in base rates. Recovery of the Arkansas portion of the NCWF revenue requirement is requested in SWEPCo’s pending 2021 Arkansas Base Rate Case. The NCWF are subject to various regulatory performance requirements. If these performance requirements are not met, PSO and SWEPCo would recognize a regulatory liability to refund retail customers.

In April 2021, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Sundance during its development and construction for $270 million, the first of the three NCWF acquisitions. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Sundance assets in proportion to their undivided ownership interests. Sundance was placed in-service in April 2021.

In September 2021, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Maverick during its development and construction for $383 million, the second of the three NCWF acquisitions. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Maverick assets in proportion to their undivided ownership interests. Maverick was placed in-service in September 2021.
176

In accordance with the guidance for “Business Combinations,” management determined that the acquisitions of Sundance and Maverick represent asset acquisitions.  As of September 30, 2021, PSO and SWEPCo had approximately $314 million and $376 million, of Property, Plant and Equipment on the balance sheets, respectively, related to the Sundance and Maverick NCWF projects. On an ongoing basis, management further determined that PSO and SWEPCo should apply the joint plant accounting model to account for their respective undivided interests in the assets, liabilities, revenues and expenses of Sundance and Maverick.

The Purchase and Sale Agreement (PSA) includes collective interests in numerous land contracts, as originally executed between the nonaffiliated party and the respective owners of the properties as defined in the contracts. These contracts provide for easement and access rights to the land that Sundance and Maverick were built upon. These interests as lessee in each of the land contracts were transferred to Sundance and Maverick (and subsequently to PSO and SWEPCo) as a part of the closing of the PSA. As of September 30, 2021, the Noncurrent Obligations Under Operating Leases for Sundance are $13 million and $15 million on the balance sheets for PSO and SWEPCo, respectively, and the Noncurrent Obligations Under Operating Leases for Maverick are $18 million and $22 million on the balance sheets for PSO and SWEPCo, respectively.

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.

DISPOSITIONS

Conesville Plant (Generation & Marketing Segment)

In June 2020, AEP and a nonaffiliated joint-owner executed an Environmental Liability and Property Transfer and Asset Purchase Agreement with a nonaffiliated third-party related to the merchant Conesville Plant site. The purchaser took ownership of the assets and assumed responsibility for environmental liabilities, including ash pond closure, asbestos abatement and decommissioning and demolition of the Conesville Plant site. In consideration of the transfer of the acquired assets to the purchaser and the purchaser’s assumption of liabilities, AEP will pay a total of approximately $98 million over three years, derecognized $106 million in ARO and recorded an immaterial gain on the transaction which is recorded in Other Operation on the statements of income. AEP paid approximately $26 million at closing in June 2020 and made additional payments totaling $38 million in quarterly installments from October 2020 to July 2021. AEP will make additional payments totaling $34 million in quarterly installments from October 2021 to July 2022.
177

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,	
 	2021		2020		2021		2020	
 	(in millions)	
Service Cost	$	32.3 			$	28.0 			$	2.4 			$	2.5 		
Interest Cost	34.3 			42.0 			7.7 			10.0 		
Expected Return on Plan Assets	(57.4)			(66.3)			(22.8)			(23.9)		
Amortization of Prior Service Credit	— 			— 			(17.8)			(17.4)		
Amortization of Net Actuarial Loss	25.3 			23.5 			— 			1.4 		
Net Periodic Benefit Cost (Credit)	$	34.5 			$	27.2 			$	(30.5)			$	(27.4)		
								
	Pension Plans		OPEB	
	Nine Months Ended September 30,		Nine Months Ended September 30,	
 	2021		2020		2021		2020	
 	(in millions)	
Service Cost	$	96.9 			$	84.0 			$	7.2 			$	7.5 		
Interest Cost	102.9 			125.9 			22.9 			29.9 		
Expected Return on Plan Assets	(172.3)			(198.7)			(68.4)			(71.8)		
Amortization of Prior Service Credit	— 			— 			(53.2)			(52.3)		
Amortization of Net Actuarial Loss	76.1 			70.3 			— 			4.4 		
Net Periodic Benefit Cost (Credit)	$	103.6 			$	81.5 			$	(91.5)			$	(82.3)		

178

AEP Texas

	Pension Plans		OPEB	
	Three Months Ended September 30,		Three Months Ended September 30,	
 	2021		2020		2021		2020	
 	(in millions)	
Service Cost	$	3.0 			$	2.6 			$	0.2 			$	0.2 		
Interest Cost	2.8 			3.5 			0.6 			0.8 		
Expected Return on Plan Assets	(4.9)			(5.7)			(1.9)			(2.0)		
Amortization of Prior Service Credit	— 			— 			(1.5)			(1.4)		
Amortization of Net Actuarial Loss	2.1 			1.9 			— 			0.1 		
Net Periodic Benefit Cost (Credit)	$	3.0 			$	2.3 			$	(2.6)			$	(2.3)		
								
	Pension Plans		OPEB	
	Nine Months Ended September 30,		Nine Months Ended September 30,	
 	2021		2020		2021		2020	
 	(in millions)	
Service Cost	$	8.9 			$	7.6 			$	0.5 			$	0.6 		
Interest Cost	8.4 			10.5 			1.8 			2.4 		
Expected Return on Plan Assets	(14.6)			(17.1)			(5.6)			(6.0)		
Amortization of Prior Service Credit	— 			— 			(4.5)			(4.4)		
Amortization of Net Actuarial Loss	6.2 			5.8 			— 			0.4 		
Net Periodic Benefit Cost (Credit)	$	8.9 			$	6.8 			$	(7.8)			$	(7.0)		

APCo

	Pension Plans		OPEB	
	Three Months Ended September 30,		Three Months Ended September 30,	
 	2021		2020		2021		2020	
 	(in millions)	
Service Cost	$	3.0 			$	2.7 			$	0.3 			$	0.3 		
Interest Cost	4.1 			5.0 			1.3 			1.6 		
Expected Return on Plan Assets	(7.3)			(8.4)			(3.4)			(3.6)		
Amortization of Prior Service Credit	— 			— 			(2.6)			(2.5)		
Amortization of Net Actuarial Loss	3.0 			2.8 			— 			0.2 		
Net Periodic Benefit Cost (Credit)	$	2.8 			$	2.1 			$	(4.4)			$	(4.0)		
								
	Pension Plans		OPEB	
	Nine Months Ended September 30,		Nine Months Ended September 30,	
 	2021		2020		2021		2020	
 	(in millions)	
Service Cost	$	8.9 			$	7.9 			$	0.8 			$	0.8 		
Interest Cost	12.3 			15.2 			3.7 			4.9 		
Expected Return on Plan Assets	(21.8)			(25.2)			(10.1)			(10.9)		
Amortization of Prior Service Credit	— 			— 			(7.8)			(7.6)		
Amortization of Net Actuarial Loss	9.0 			8.4 			— 			0.7 		
Net Periodic Benefit Cost (Credit)	$	8.4 			$	6.3 			$	(13.4)			$	(12.1)		
179

I&M

	Pension Plans		OPEB	
	Three Months Ended September 30,		Three Months Ended September 30,	
 	2021		2020		2021		2020	
 	(in millions)	
Service Cost	$	4.4 			$	3.9 			$	0.4 			$	0.4 		
Interest Cost	4.0 			4.9 			0.8 			1.2 		
Expected Return on Plan Assets	(7.2)			(8.3)			(2.7)			(3.0)		
Amortization of Prior Service Credit	— 			— 			(2.5)			(2.3)		
Amortization of Net Actuarial Loss	2.9 			2.7 			— 			0.1 		
Net Periodic Benefit Cost (Credit)	$	4.1 			$	3.2 			$	(4.0)			$	(3.6)		
								
	Pension Plans		OPEB	
	Nine Months Ended September 30,		Nine Months Ended September 30,	
 	2021		2020		2021		2020	
 	(in millions)	
Service Cost	$	13.1 			$	11.6 			$	1.0 			$	1.1 		
Interest Cost	12.1 			14.7 			2.6 			3.5 		
Expected Return on Plan Assets	(21.6)			(24.9)			(8.3)			(8.8)		
Amortization of Prior Service Credit	— 			— 			(7.3)			(7.1)		
Amortization of Net Actuarial Loss	8.8 			8.1 			— 			0.5 		
Net Periodic Benefit Cost (Credit)	$	12.4 			$	9.5 			$	(12.0)			$	(10.8)		

OPCo

	Pension Plans		OPEB	
	Three Months Ended September 30,		Three Months Ended September 30,	
 	2021		2020		2021		2020	
 	(in millions)	
Service Cost	$	2.9 			$	2.4 			$	0.2 			$	0.2 		
Interest Cost	3.1 			3.9 			0.7 			1.0 		
Expected Return on Plan Assets	(5.7)			(6.6)			(2.4)			(2.6)		
Amortization of Prior Service Credit	— 			— 			(1.7)			(1.8)		
Amortization of Net Actuarial Loss	2.3 			2.1 			— 			0.2 		
Net Periodic Benefit Cost (Credit)	$	2.6 			$	1.8 			$	(3.2)			$	(3.0)		
								
	Pension Plans		OPEB	
	Nine Months Ended September 30,		Nine Months Ended September 30,	
 	2021		2020		2021		2020	
 	(in millions)	
Service Cost	$	8.6 			$	7.2 			$	0.6 			$	0.7 		
Interest Cost	9.3 			11.6 			2.3 			3.1 		
Expected Return on Plan Assets	(16.8)			(19.7)			(7.3)			(7.9)		
Amortization of Prior Service Credit	— 			— 			(5.3)			(5.3)		
Amortization of Net Actuarial Loss	6.8 			6.4 			— 			0.5 		
Net Periodic Benefit Cost (Credit)	$	7.9 			$	5.5 			$	(9.7)			$	(8.9)		

180

PSO

	Pension Plans		OPEB	
	Three Months Ended September 30,		Three Months Ended September 30,	
 	2021		2020		2021		2020	
 	(in millions)	
Service Cost	$	2.0 			$	1.9 			$	0.1 			$	0.1 		
Interest Cost	1.7 			2.1 			0.4 			0.6 		
Expected Return on Plan Assets	(3.0)			(3.6)			(1.3)			(1.3)		
Amortization of Prior Service Credit	— 			— 			(1.1)			(1.0)		
Amortization of Net Actuarial Loss	1.2 			1.1 			— 			— 		
Net Periodic Benefit Cost (Credit)	$	1.9 			$	1.5 			$	(1.9)			$	(1.6)		
								
	Pension Plans		OPEB	
	Nine Months Ended September 30,		Nine Months Ended September 30,	
 	2021		2020		2021		2020	
 	(in millions)	
Service Cost	$	6.0 			$	5.5 			$	0.4 			$	0.4 		
Interest Cost	5.0 			6.4 			1.2 			1.6 		
Expected Return on Plan Assets	(9.2)			(10.9)			(3.8)			(3.9)		
Amortization of Prior Service Credit	— 			— 			(3.3)			(3.2)		
Amortization of Net Actuarial Loss	3.7 			3.5 			— 			0.2 		
Net Periodic Benefit Cost (Credit)	$	5.5 			$	4.5 			$	(5.5)			$	(4.9)		

SWEPCo

	Pension Plans		OPEB	
	Three Months Ended September 30,		Three Months Ended September 30,	
 	2021		2020		2021		2020	
 	(in millions)	
Service Cost	$	2.7 			$	2.6 			$	0.3 			$	0.2 		
Interest Cost	2.2 			2.5 			0.4 			0.6 		
Expected Return on Plan Assets	(3.3)			(3.9)			(1.5)			(1.5)		
Amortization of Prior Service Credit	— 			— 			(1.4)			(1.3)		
Amortization of Net Actuarial Loss	1.5 			1.4 			— 			0.1 		
Net Periodic Benefit Cost (Credit)	$	3.1 			$	2.6 			$	(2.2)			$	(1.9)		
								
	Pension Plans		OPEB	
	Nine Months Ended September 30,		Nine Months Ended September 30,	
 	2021		2020		2021		2020	
 	(in millions)	
Service Cost	$	8.4 			$	7.5 			$	0.6 			$	0.6 		
Interest Cost	6.4 			7.6 			1.4 			1.9 		
Expected Return on Plan Assets	(10.1)			(11.7)			(4.5)			(4.7)		
Amortization of Prior Service Credit	— 			— 			(4.0)			(3.9)		
Amortization of Net Actuarial Loss	4.6 			4.2 			— 			0.3 		
Net Periodic Benefit Cost (Credit)	$	9.3 			$	7.6 			$	(6.5)			$	(5.8)		

181

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 		
182

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

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

The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense, income tax expense and other nonallocated costs.
183

The tables below represent AEP’s reportable segment income statement information for the three and nine months ended September 30, 2021 and 2020 and reportable segment balance sheet information as of September 30, 2021 and December 31, 2020.

	Three Months Ended September 30, 2021	
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation
&
Marketing		Corporate and Other (a)		Reconciling Adjustments		Consolidated	
 	(in millions)	
Revenues from:	 		 		 		 		 				 	
External Customers	$	2,716.8 			$	1,195.0 			$	90.3 			$	617.4 			$	3.5 			$	— 			$	4,623.0 		
Other Operating Segments	42.5 			5.3 			301.3 			3.7 			23.2 			(376.0)			— 		
Total Revenues	$	2,759.3 			$	1,200.3 			$	391.6 			$	621.1 			$	26.7 			$	(376.0)			$	4,623.0 		

	
Net Income (Loss)	$	438.7 			$	155.9 			$	167.9 			$	99.5 			$	(65.1)			$	— 			$	796.9 		
														
	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 		

	

	

	

	

	

	

	

	

														
	Nine Months Ended September 30, 2021	
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation
&
Marketing		Corporate and Other (a)		Reconciling Adjustments		Consolidated	
	(in millions)	
Revenues from:														
External Customers	$	7,445.9 			$	3,366.9 			$	264.6 			$	1,641.6 			$	11.6 			$	— 			$	12,730.6 		
Other Operating Segments	111.3 			24.9 			882.2 			50.3 			43.5 			(1,112.2)			— 		
Total Revenues	$	7,557.2 			$	3,391.8 			$	1,146.8 			$	1,691.9 			$	55.1 			$	(1,112.2)			$	12,730.6 		

Net Income (Loss)	$	938.9 			$	424.0 			$	510.7 			$	184.2 			$	(108.3)			$	— 			$	1,949.5 		
														
	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 		
184

																																													
		September 30, 2021	
		Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation
&
Marketing		Corporate and Other (a)		Reconciling
Adjustments		Consolidated	
 		(in millions)	
Total Property, Plant and Equipment		$	50,990.6 			$	22,171.7 			$	12,865.6 			$	2,125.8 			$	414.5 			$	— 			$	88,568.2 		
Accumulated Depreciation and Amortization		16,647.1 			4,059.9 			758.1 			222.8 			189.1 			— 			21,877.0 		
Total Property Plant and Equipment - Net		$	34,343.5 			$	18,111.8 			$	12,107.5 			$	1,903.0 			$	225.4 			$	— 			$	66,691.2 		

Total Assets		$	45,775.5 			$	21,053.1 			$	13,287.6 			$	4,387.6 			$	6,421.4 		(b)	$	(4,588.1)		(c)	$	86,337.1 		
															
Long-term Debt Due Within One Year:															
	
Nonaffiliated		$	1,243.0 			$	815.2 			$	52.4 			$	— 			$	411.2 		(d)	$	— 			$	2,521.8 		
															
Long-term Debt:															
Affiliated		65.0 			— 			— 			— 			— 			(65.0)			— 		
Nonaffiliated		13,616.0 			7,869.0 			4,544.2 			— 			6,027.3 		(d)	— 			32,056.5 		
															
Total Long-term Debt		$	14,924.0 			$	8,684.2 			$	4,596.6 			$	— 			$	6,438.5 		(d)	$	(65.0)			$	34,578.3 		

															
		December 31, 2020	
		Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation
&
Marketing		Corporate and Other (a)		Reconciling
Adjustments		Consolidated	
 		(in millions)	
Total Property, Plant and Equipment		$	49,023.3 			$	21,145.0 			$	11,827.2 			$	1,910.2 			$	407.3 			$	— 			$	84,313.0 		
Accumulated Depreciation and Amortization		15,586.2 			3,879.3 			595.7 			166.1 			184.1 			— 			20,411.4 		
Total Property Plant and Equipment - Net		$	33,437.1 			$	17,265.7 			$	11,231.5 			$	1,744.1 			$	223.2 			$	— 			$	63,901.6 		

															
Total Assets		$	42,752.7 			$	19,765.9 			$	12,627.3 			$	3,585.9 			$	5,987.1 		(b)	$	(3,961.7)		(c)	$	80,757.2 		
															
Long-term Debt Due Within One Year:															
	
Nonaffiliated		$	1,034.6 			$	588.8 			$	52.3 			$	— 			$	410.4 		(d)	$	— 			$	2,086.1 		
															
Long-term Debt:															
Affiliated		65.0 			— 			— 			— 			— 			(65.0)			— 		
Nonaffiliated		12,375.6 			6,661.9 			4,075.7 			— 			5,873.2 		(d)	— 			28,986.4 		
															
Total Long-term Debt		$	13,475.2 			$	7,250.7 			$	4,128.0 			$	— 			$	6,283.6 		(d)	$	(65.0)			$	31,072.5 		

(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.

185

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.

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, 2021 and 2020 and reportable segment balance sheet information as of September 30, 2021 and December 31, 2020.

	Three Months Ended September 30, 2021	
	State Transcos		AEPTCo Parent		Reconciling Adjustments		AEPTCo
Consolidated	
	(in millions)	
Revenues from:								
External Customers	$	79.2 			$	— 			$	— 			$	79.2 		
Sales to AEP Affiliates	297.6 			— 			— 			297.6 		
Other Revenues	0.2 			— 			— 			0.2 		
Total Revenues	$	377.0 			$	— 			$	— 			$	377.0 		
								
Interest Income	$	0.1 			$	40.3 			$	(40.2)		(a)	$	0.2 		
Interest Expense	36.1 			40.2 			(40.2)		(a)	36.1 		
Income Tax Expense	36.7 			— 			— 			36.7 		

Net Income	$	145.3 			$	0.1 		(b)	$	— 			$	145.4 		
								
	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 		
186

																								
	Nine Months Ended September 30, 2021	
	State Transcos		AEPTCo Parent		Reconciling Adjustments		AEPTCo Consolidated	
	(in millions)	
Revenues from:								
External Customers	$	239.3 			$	— 			$	— 			$	239.3 		
Sales to AEP Affiliates	864.6		— 			— 			864.6 		
Other Revenues	0.3 			— 			— 			0.3 		
Total Revenues	$	1,104.2 			$	— 			$	— 			$	1,104.2 		
								
Interest Income	$	0.1 			$	117.0 			$	(116.7)		(a)	$	0.4 		
Interest Expense	104.5 			116.6 			(116.6)		(a)	104.5 		
Income Tax Expense	115.4 			— 			— 			115.4 		

Net Income	$	445.5 			$	0.2 		(b)	$	— 			$	445.7 		
								
	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 		

	

	

	

	

	

	

	

	

	

	

	
	
	September 30, 2021	
	State Transcos		AEPTCo Parent		Reconciling Adjustments		AEPTCo
Consolidated	
	(in millions)	
Total Transmission Property	$	12,359.3 			$	— 			$	— 			$	12,359.3 		
Accumulated Depreciation and Amortization	730.4 			— 			— 			730.4 		
Total Transmission Property – Net	$	11,628.9 			$	— 			$	— 			$	11,628.9 		
								
Notes Receivable - Affiliated	$	— 			$	4,343.5 			$	(4,343.5)		(c)	$	— 		
								
Total Assets	$	11,984.7 			$	4,445.3 		(d)	$	(4,498.9)		(e)	$	11,931.1 		
								
Total Long-term Debt	$	4,440.0 			$	4,393.4 			$	(4,440.0)		(c)	$	4,393.4 		
								
	December 31, 2020	
	State Transcos		AEPTCo Parent		Reconciling Adjustments		AEPTCo
Consolidated	
	(in millions)	
Total Transmission Property	$	11,345.6 			$	— 			$	— 			$	11,345.6 		
Accumulated Depreciation and Amortization	572.8 			— 			— 			572.8 		
Total Transmission Property – Net	$	10,772.8 			$	— 			$	— 			$	10,772.8 		
								
Notes Receivable - Affiliated	$	— 			$	3,948.5 			$	(3,948.5)		(c)	$	— 		
								
Total Assets	$	11,185.1 			$	4,084.0 		(d)	$	(4,023.1)		(e)	$	11,246.0 		
								
Total Long-term Debt	$	3,990.0 			$	3,948.5 			$	(3,990.0)		(c)	$	3,948.5 		

(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.
187

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.

188

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

Notional Volume of Derivative Instruments
September 30, 2021

Primary Risk
Exposure		Unit of
Measure		AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo	
				(in millions)	
Commodity:		 						 		 		 		 		 	
Power		MWhs		341.9 			— 			55.4 			23.1 			2.8 			18.7 			5.4 		
	
Natural Gas		MMBtus		28.1 			— 			— 			— 			— 			— 			5.2 		
Heating Oil and Gasoline		Gallons		7.8 			2.0 			1.2 			0.7 			1.5 			0.9 			1.1 		
Interest Rate		USD		$	116.5 			$	— 			$	— 			$	— 			$	— 			$	— 			$	— 		
																	
Interest Rate on Long-term Debt		USD		$	1,250.0 			$	— 			$	— 			$	— 			$	— 			$	— 			$	— 		

December 31, 2020

Primary Risk
Exposure		Unit of
Measure		AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo	
				(in millions)	
Commodity:		 						 		 		 		 		 	
Power		MWhs		331.3 			— 			46.9 			19.7 			3.0 			11.9 			4.0 		
	
Natural Gas		MMBtus		26.9 			— 			— 			— 			— 			— 			7.9 		
Heating Oil and Gasoline		Gallons		6.9 			1.8 			1.1 			0.6 			1.4 			0.7 			0.9 		
Interest Rate		USD		$	129.8 			$	— 			$	— 			$	— 			$	— 			$	— 			$	— 		
																	
Interest Rate on Long-term Debt		USD		$	1,150.0 			$	— 			$	200.0 			$	— 			$	— 			$	— 			$	— 		

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.
189

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

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

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

According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third-party contractual agreements and risk profiles. The Registrants netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows:

		September 30, 2021		December 31, 2020	
		Cash Collateral		Cash Collateral		Cash Collateral		Cash Collateral	
		Received		Paid		Received		Paid	
		Netted Against		Netted Against		Netted Against		Netted Against	
		Risk Management		Risk Management		Risk Management		Risk Management	
Company		Assets		Liabilities		Assets		Liabilities	
		(in millions)	
AEP		$	309.7 			$	38.3 			$	3.4 			$	6.8 		
APCo		0.6 			10.7 			0.4 			— 		
I&M		0.3 			17.4 			1.7 			— 		

Amounts for AEP Texas, OPCo, PSO and SWEPCo are immaterial as of September 30, 2021 and December 31, 2020, respectively.
190

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

AEP
																																							
		September 30, 2021	
		Risk
Management
Contracts		Hedging Contracts		Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized		Gross
Amounts
Offset in the
Statement of
Financial
Position (b)		Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)	
Balance Sheet Location		Commodity (a)		Commodity (a)		Interest Rate (a)							
 		(in millions)	
Current Risk Management Assets		$	1,005.5 			$	321.1 			$	8.3 			$	1,334.9 			$	(965.7)			$	369.2 		
Long-term Risk Management Assets		337.3 			85.8 			— 			423.1 			(144.8)			278.3 		
Total Assets		1,342.8 			406.9 			8.3 			1,758.0 			(1,110.5)			647.5 		
													
Current Risk Management Liabilities		834.5 			33.1 			— 			867.6 			(761.1)			106.5 		
Long-term Risk Management Liabilities		234.6 			14.3 			28.8 			277.7 			(78.1)			199.6 		
Total Liabilities		1,069.1 			47.4 			28.8 			1,145.3 			(839.2)			306.1 		
													
Total MTM Derivative Contract Net Assets (Liabilities)		$	273.7 			$	359.5 			$	(20.5)			$	612.7 			$	(271.3)			$	341.4 		

		December 31, 2020	
		Risk
Management
Contracts		Hedging Contracts		Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized		Gross
Amounts
Offset in the
Statement of
Financial
Position (b)		Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)	
Balance Sheet Location		Commodity (a)		Commodity (a)		Interest Rate (a)							
		(in millions)	
Current Risk Management Assets		$	239.1 			$	21.1 			$	5.0 			$	265.2 			$	(170.5)			$	94.7 		
Long-term Risk Management Assets		275.9 			18.0 			— 			293.9 			(51.7)			242.2 		
Total Assets		515.0 			39.1 			5.0 			559.1 			(222.2)			336.9 		
													
Current Risk Management Liabilities		193.0 			54.4 			3.4 			250.8 			(172.0)			78.8 		
Long-term Risk Management Liabilities		222.2 			60.1 			4.1 			286.4 			(53.6)			232.8 		
Total Liabilities		415.2 			114.5 			7.5 			537.2 			(225.6)			311.6 		
													
Total MTM Derivative Contract Net Assets (Liabilities)		$	99.8 			$	(75.4)			$	(2.5)			$	21.9 			$	3.4 			$	25.3 		

191

AEP Texas
																					
		September 30, 2021	
		Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities	
		Contracts –		in the Statement of		Presented in the Statement of	
Balance Sheet Location		Commodity (a)		Financial Position (b)		Financial Position (c)	
		(in millions)	
Current Risk Management Assets		$	0.8 			$	(0.8)			$	— 		
Long-term Risk Management Assets		0.1 			(0.1)			— 		
Total Assets		0.9 			(0.9)			— 		
							
Current Risk Management Liabilities		— 			— 			— 		
Long-term Risk Management Liabilities		— 			— 			— 		
Total Liabilities		— 			— 			— 		
							
Total MTM Derivative Contract Net Assets (Liabilities)		$	0.9 			$	(0.9)			$	— 		

		December 31, 2020	
		Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities	
		Contracts –		in the Statement of		Presented in the Statement of	
Balance Sheet Location		Commodity (a)		Financial Position (b)		Financial Position (c)	
		(in millions)	
Current Risk Management Assets		$	0.4 			$	(0.4)			$	— 		
Long-term Risk Management Assets		— 			— 			— 		
Total Assets		0.4 			(0.4)			— 		
							
Current Risk Management Liabilities		— 			— 			— 		
Long-term Risk Management Liabilities		— 			— 			— 		
Total Liabilities		— 			— 			— 		
							
Total MTM Derivative Contract Net Assets (Liabilities)		$	0.4 			$	(0.4)			$	— 		

192

APCo
																					
		September 30, 2021	

		Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities	
		Contracts –		in the Statement of		Presented in the Statement	
Balance Sheet Location		Commodity (a)		Financial Position (b)		of Financial Position (c)	
		(in millions)	
Current Risk Management Assets		$	95.7 			$	(48.7)			$	47.0 		
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets		0.2 			(0.2)			— 		
Total Assets		95.9 			(48.9)			47.0 		
							
Other Current Liabilities - Current Risk Management Liabilities		60.2 			(58.9)			1.3 		
Deferred Credits and Other Noncurrent Liabilities - Long-term Risk Management Liabilities		0.2 			(0.2)			— 		
Total Liabilities		60.4 			(59.1)			1.3 		
							
Total MTM Derivative Contract Net Assets		$	35.5 			$	10.2 			$	45.7 		

		December 31, 2020	
						Gross Amounts					
		Risk				of Risk		Gross Amounts		Net Amounts of Assets/	
		Management		Hedging		Management		Offset in the		Liabilities Presented in	
		Contracts –		Contracts –		Assets/Liabilities		Statement of		the Statement of	
Balance Sheet Location		Commodity (a)		Interest Rate (a)		Recognized		Financial Position (b)		Financial Position (c)	
		(in millions)	
Current Risk Management Assets		$	38.8 			$	2.4 			$	41.2 			$	(18.8)			$	22.4 		
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets		0.7 			— 			0.7 			(0.6)			0.1 		
Total Assets		39.5 			2.4 			41.9 			(19.4)			22.5 		
											
Other Current Liabilities - Current Risk Management Liabilities		19.7 			3.4 			23.1 			(18.5)			4.6 		
Deferred Credits and Other Noncurrent Liabilities - Long-term Risk Management Liabilities		0.6 			— 			0.6 			(0.5)			0.1 		
Total Liabilities		20.3 			3.4 			23.7 			(19.0)			4.7 		
											
Total MTM Derivative Contract Net Assets (Liabilities)		$	19.2 			$	(1.0)			$	18.2 			$	(0.4)			$	17.8 		
193

I&M
																					
		September 30, 2021	
		Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities	
		Contracts –		in the Statement of		Presented in the Statement of	
Balance Sheet Location		Commodity (a)		Financial Position (b)		Financial Position (c)	
		(in millions)	
Current Risk Management Assets		$	37.8 			$	(32.3)			$	5.5 		
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets		0.1 			(0.1)			— 		
Total Assets		37.9 			(32.4)			5.5 		
							
Current Risk Management Liabilities		51.9 			(49.4)			2.5 		
Deferred Credits and Other Noncurrent Liabilities - Long-term Risk Management Liabilities		0.1 			(0.1)			— 		
Total Liabilities		52.0 			(49.5)			2.5 		
							
Total MTM Derivative Contract Net Assets (Liabilities)		$	(14.1)			$	17.1 			$	3.0 		

		December 31, 2020	
		Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities	
		Contracts –		in the Statement of		Presented in the Statement of	
Balance Sheet Location		Commodity (a)		Financial Position (b)		Financial Position (c)	
		(in millions)	
Current Risk Management Assets		$	17.2 			$	(13.6)			$	3.6 		
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets		0.5 			(0.4)			0.1 		
Total Assets		17.7 			(14.0)			3.7 		
							
Current Risk Management Liabilities		12.1 			(12.0)			0.1 		
Deferred Credits and Other Noncurrent Liabilities - Long-term Risk Management Liabilities		0.4 			(0.3)			0.1 		
Total Liabilities		12.5 			(12.3)			0.2 		
							
Total MTM Derivative Contract Net Assets (Liabilities)		$	5.2 			$	(1.7)			$	3.5 		

OPCo
																					
		September 30, 2021	
		Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities	
		Contracts –		in the Statement of		Presented in the Statement of	
Balance Sheet Location		Commodity (a)		Financial Position (b)		Financial Position (c)	
		(in millions)	
Current Risk Management Assets		$	0.6 			$	(0.6)			$	— 		
Long-term Risk Management Assets		0.1 			(0.1)			— 		
Total Assets		0.7 			(0.7)			— 		
							
Current Risk Management Liabilities		3.5 			— 			3.5 		
Long-term Risk Management Liabilities		86.9 			— 			86.9 		
Total Liabilities		90.4 			— 			90.4 		
							
Total MTM Derivative Contract Net Liabilities		$	(89.7)			$	(0.7)			$	(90.4)		

		December 31, 2020	
		Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities	
		Contracts –		in the Statement of		Presented in the Statement of	
Balance Sheet Location		Commodity (a)		Financial Position (b)		Financial Position (c)	
		(in millions)	
Current Risk Management Assets		$	0.3 			$	(0.3)			$	— 		
Long-term Risk Management Assets		— 			— 			— 		
Total Assets		0.3 			(0.3)			— 		
							
Current Risk Management Liabilities		8.7 			— 			8.7 		
Long-term Risk Management Liabilities		101.6 			— 			101.6 		
Total Liabilities		110.3 			— 			110.3 		
							
Total MTM Derivative Contract Net Liabilities		$	(110.0)			$	(0.3)			$	(110.3)		
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PSO
																					
		September 30, 2021	
		Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities	
		Contracts –		in the Statement of		Presented in the Statement of	
Balance Sheet Location		Commodity (a)		Financial Position (b)		Financial Position (c)	
		(in millions)	
Current Risk Management Assets		$	19.0 			$	(0.5)			$	18.5 		
Long-term Risk Management Assets		— 			— 			— 		
Total Assets		19.0 			(0.5)			18.5 		
							
Current Risk Management Liabilities		0.2 			(0.2)			— 		
Long-term Risk Management Liabilities		— 			— 			— 		
Total Liabilities		0.2 			(0.2)			— 		
							
Total MTM Derivative Contract Net Assets (Liabilities)		$	18.8 			$	(0.3)			$	18.5 		

		December 31, 2020	
		Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities	
		Contracts –		in the Statement of		Presented in the Statement of	
Balance Sheet Location		Commodity (a)		Financial Position (b)		Financial Position (c)	
		(in millions)	
Current Risk Management Assets		$	10.5 			$	(0.2)			$	10.3 		
Long-term Risk Management Assets		— 			— 			— 		
Total Assets		10.5 			(0.2)			10.3 		
							
Current Risk Management Liabilities		— 			— 			— 		
Long-term Risk Management Liabilities		— 			— 			— 		
Total Liabilities		— 			— 			— 		
							
Total MTM Derivative Contract Net Assets (Liabilities)		$	10.5 			$	(0.2)			$	10.3 		

SWEPCo
																					
		September 30, 2021	
		Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities	
		Contracts –		in the Statement of		Presented in the Statement of	
Balance Sheet Location		Commodity (a)		Financial Position (b)		Financial Position (c)	
		(in millions)	
Current Risk Management Assets		$	18.1 			$	(0.6)			$	17.5 		
Long-term Risk Management Assets		2.1 			— 			2.1 		
Total Assets		20.2 			(0.6)			19.6 		
							
Current Risk Management Liabilities		0.2 			(0.2)			— 		
Long-term Risk Management Liabilities		— 			— 			— 		
Total Liabilities		0.2 			(0.2)			— 		
							
Total MTM Derivative Contract Net Assets (Liabilities)		$	20.0 			$	(0.4)			$	19.6 		

		December 31, 2020	
		Risk Management		Gross Amounts Offset		Net Amounts of Assets/Liabilities	
		Contracts –		in the Statement of		Presented in the Statement of	
Balance Sheet Location		Commodity (a)		Financial Position (b)		Financial Position (c)	
		(in millions)	
Current Risk Management Assets		$	3.4 			$	(0.2)			$	3.2 		
Long-term Risk Management Assets		— 			— 			— 		
Total Assets		3.4 			(0.2)			3.2 		
							
Current Risk Management Liabilities		0.7 			— 			0.7 		
Long-term Risk Management Liabilities		1.0 			— 			1.0 		
Total Liabilities		1.7 			— 			1.7 		
							
Total MTM Derivative Contract Net Assets (Liabilities)		$	1.7 			$	(0.2)			$	1.5 		

(a)Derivative instruments within these categories are disclosed as 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.
195

The tables below present the Registrants’ amount of gain (loss) recognized on risk management contracts:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
																																													
		Three Months Ended September 30, 2021	
Location of Gain (Loss)		AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Vertically Integrated Utilities Revenues		$	(0.9)			$	— 			$	— 			$	— 			$	— 			$	— 			$	— 		
	
Generation & Marketing Revenues		128.8 			— 			— 			— 			— 			— 			— 		
Electric Generation, Transmission and Distribution Revenues		— 			— 			(0.9)			— 			— 			— 			— 		

Purchased Electricity for Resale		0.2 			— 			0.1 			— 			— 			— 			— 		
Other Operation		0.9 			0.3 			0.1 			0.1 			0.1 			0.1 			0.2 		
Maintenance		1.1 			0.2 			0.2 			0.1 			0.2 			0.1 			0.1 		
Regulatory Assets (a)		(7.2)			— 			(2.9)			(16.9)			14.9 			— 			0.1 		
Regulatory Liabilities (a)		46.5 			(0.1)			14.2 			1.7 			0.8 			14.0 			12.7 		
Total Gain (Loss) on Risk Management Contracts		$	169.4 			$	0.4 			$	10.8 			$	(15.0)			$	16.0 			$	14.2 			$	13.1 		

		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 		

																																													
		Nine Months Ended September 30, 2021	
Location of Gain (Loss)		AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Vertically Integrated Utilities Revenues		$	(0.6)			$	— 			$	— 			$	— 			$	— 			$	— 			$	— 		
	
Generation & Marketing Revenues		144.9 			— 			— 			— 			— 			— 			— 		
Electric Generation, Transmission and Distribution Revenues		— 			— 			(0.6)			— 			— 			— 			— 		

Purchased Electricity for Resale		1.2 			— 			1.0 			0.1 			— 			— 			— 		
Other Operation		1.9 			0.6 			0.2 			0.2 			0.3 			0.2 			0.3 		
Maintenance		2.4 			0.6 			0.4 			0.2 			0.4 			0.2 			0.3 		
Regulatory Assets (a)		(7.8)			— 			(2.9)			(22.9)			20.3 			— 			1.4 		
Regulatory Liabilities (a)		123.6 			0.5 			28.9 			1.9 			5.9 			40.2 			38.5 		
Total Gain (Loss) on Risk Management Contracts		$	265.6 			$	1.7 			$	27.0 			$	(20.5)			$	26.9 			$	40.6 			$	40.5 		
196

																																													
		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 		

(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 line item on the statements of income as that of the associated risk being hedged. 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.

197

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, 2021		December 31, 2020		September 30, 2021		December 31, 2020	
		(in millions)	
Long-term Debt (a) (b)		$	(965.6)			$	(995.9)			$	(22.1)			$	(51.7)		

(a)Amounts included on the balance sheets within Long-term Debt Due within One Year and Long-term Debt, respectively.
(b)Amounts include $(47) million and $(53) million as of September 30, 2021 and December 31, 2020, 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,	
	2021		2020		2021		2020	
	(in millions)	
Gain (Loss) on Interest Rate Contracts:								
Fair Value Hedging Instruments (a)	$	(0.1)			$	— 			$	(23.8)			$	42.6 		
Fair Value Portion of Long-term Debt (a)	0.1 			— 			23.8 			(42.6)		

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

In June 2020, AEP terminated a $500 million notional amount interest rate swap resulting in the discontinuance of the hedging relationship. A gain of $57 million on the fair value of the hedging instrument was settled in cash and recorded within operating activities on the statements of cash flows. Subsequent to the discontinuation of hedge accounting, the remaining adjustment to the carrying amount of the hedged item of $57 million will be amortized on a straight line basis through November 2027 in Interest Expense on the statements of income.

Accounting for Cash Flow Hedging Strategies

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects net income.

Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2021 and 2020, AEP applied cash flow hedging to outstanding power derivatives and the Registrant Subsidiaries did not.

The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three months ended September 30, 2021, AEP applied cash flow hedging to outstanding interest rate derivatives and the Registrant Subsidiaries did not. During the three 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 nine months ended September 30, 2021 and 2020, AEP and APCo applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not.

198

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, 2021		December 31, 2020	
		Commodity		Interest Rate		Commodity		Interest Rate	
		(in millions)	
AOCI Gain (Loss) Net of Tax		$	283.9 			$	(26.1)			$	(60.6)			$	(47.5)		
Portion Expected to be Reclassed to Net Income During the Next Twelve Months		56.5 			(2.6)			(27.1)			(5.7)		

As of September 30, 2021 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 114 months and 111 months for commodity and interest rate hedges, respectively.

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

		September 30, 2021		December 31, 2020	
		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		$	(1.5)			$	(1.1)			$	(2.3)			$	(1.1)		
APCo		7.7 			0.8 			(0.8)			0.4 		
I&M		(7.0)			(1.6)			(8.3)			(1.6)		
	
PSO		— 			— 			0.1 			0.1 		
SWEPCo		0.8 			(0.4)			(0.3)			(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.

199

Collateral Triggering Events

Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo)

A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts.  The Registrants have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral.  AEP had derivative contracts with collateral triggering events in a net liability position as of September 30, 2021, with a total exposure of $25 million. The Registrant Subsidiaries had no derivative contracts with collateral triggering events in a net liability position as of September 30, 2021. The Registrants had no derivative contracts with collateral triggering events in a net liability position as of December 31, 2020.

Cross-Default Triggers (Applies to AEP, APCo, I&M and SWEPCo)

In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third-party obligation that is $50 million or greater.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount that the exposure has been reduced by cash collateral posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering contractual netting arrangements:

		September 30, 2021	
		Liabilities for				Additional	
		Contracts with Cross				Settlement	
		Default Provisions				Liability if Cross	
		Prior to Contractual		Amount of Cash		Default Provision	
Company		Netting Arrangements		Collateral Posted		is Triggered	
		(in millions)	
AEP		$	128.2 			$	— 			$	95.8 		
APCo		1.0 			— 			— 		
I&M		0.6 			— 			— 		

SWEPCo		— 			— 			— 		

		December 31, 2020	
		Liabilities for				Additional	
		Contracts with Cross				Settlement	
		Default Provisions				Liability if Cross	
		Prior to Contractual		Amount of Cash		Default Provision	
Company		Netting Arrangements		Collateral Posted		is Triggered	
		(in millions)	
AEP		$	188.4 			$	— 			$	169.2 		
APCo		4.3 			— 			3.5 		
I&M		0.5 			— 			0.1 		

SWEPCo		1.8 			— 			1.8 		

200

Warrants Held in Investee (Applies to AEP)

AEP holds an investment in ChargePoint, which completed an initial public offering (IPO) in February 2021 via a reverse merger with a public special purpose acquisition company. Before the IPO, AEP’s interests in ChargePoint consisted of a noncontrolling equity interest of preferred shares, which were accounted for at their historical cost of $8 million as of December 31, 2020, and common share warrants. After the IPO, AEP’s interests in ChargePoint consisted of a noncontrolling equity interest of common shares, which were accounted for at their fair value of $30 million as of September 30, 2021, and common share warrants. AEP recorded an unrealized gain (loss) of $(16) million and $22 million associated with the common shares for the three and nine months ended September 30, 2021, respectively, presented in Other Income (Expense) on AEP’s statements of income.

Management has determined the common share warrants are derivative instruments based on the accounting guidance for “Derivatives and Hedging”. As of September 30, 2021 and December 31, 2020, the warrants were valued at $16 million and $32 million, respectively, and were recorded in Deferred Charges and Other Noncurrent Assets on AEP’s balance sheets. AEP recognized an unrealized loss of $10 million and $16 million associated with the warrants for the three and nine months ended September 30, 2021, respectively, presented in Other Income (Expense) on AEP’s statements of income.

Management utilized a Black-Scholes options pricing model to value the warrants as of September 30, 2021 and December 31, 2020. The valuation contemplated a liquidity adjustment that resulted in the overall fair value of the warrants being categorized as Level 3 in the fair value hierarchy as of December 31, 2020. After the IPO, there was an observable publicly traded stock price to use in the Black-Scholes options pricing model, which resulted in the warrants being categorized as Level 2 as of September 30, 2021. The common shares are categorized as Level 1 based on the observable publicly traded stock price. See “Fair Value Measurements of Financial Assets and Liabilities” section of Note 10 for additional information.
201

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 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.
202

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, 2021		December 31, 2020	
Company		Book Value		Fair Value		Book Value		Fair Value	
		(in millions)	
AEP (a)		$	34,578.3 			$	38,925.1 			$	31,072.5 			$	37,457.0 		
AEP Texas		5,216.1 			5,763.9 			4,820.4 			5,682.6 		
AEPTCo		4,393.4 			5,074.5 			3,948.5 			4,984.3 		
APCo		4,937.8 			6,067.0 			4,834.1 			6,391.8 		
I&M		3,231.1 			3,790.5 			3,029.9 			3,775.3 		
OPCo		3,468.1 			3,948.6 			2,430.2 			3,154.9 		
PSO		1,913.3 			2,169.2 			1,373.8 			1,732.1 		
SWEPCo		3,129.9 			3,534.0 			2,636.4 			3,210.1 		

(a)The fair value amounts include debt related to AEP’s Equity Units and had a fair value of $1.6 billion and $1.7 billion as of September 30, 2021 and December 31, 2020, 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, 2021	
				Gross		Gross			
				Unrealized		Unrealized		Fair	
Other Temporary Investments		Cost		Gains		Losses		Value	
		(in millions)	
Restricted Cash and Other Cash Deposits (a)		$	77.3 			$	— 			$	— 			$	77.3 		
Fixed Income Securities – Mutual Funds (b)		141.8 			1.8 			— 			143.6 		
Equity Securities – Mutual Funds		19.4 			32.1 			— 			51.5 		
Total Other Temporary Investments		$	238.5 			$	33.9 			$	— 			$	272.4 		

		December 31, 2020	
				Gross		Gross			
				Unrealized		Unrealized		Fair	
Other Temporary Investments		Cost		Gains		Losses		Value	
		(in millions)	
Restricted Cash and Other Cash Deposits (a)		$	68.3 			$	— 			$	— 			$	68.3 		
Fixed Income Securities – Mutual Funds (b)		120.7 			2.8 			— 			123.5 		
Equity Securities – Mutual Funds		25.9 			28.7 			— 			54.6 		
Total Other Temporary Investments		$	214.9 			$	31.5 			$	— 			$	246.4 		

(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.
203

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,	
 	2021		2020		2021		2020	
	(in millions)	
Proceeds from Investment Sales	$	6.0 			$	5.1 			$	15.1 			$	35.9 		
Purchases of Investments	12.9 			22.5 			26.0 			39.5 		
Gross Realized Gains on Investment Sales	2.4 			0.2 			3.6 			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 an external investment manager that must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.

I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets.  I&M records these securities at fair value.  I&M classifies debt securities in the trust funds as available-for-sale due to their long-term purpose.

Other-than-temporary impairments for investments in debt securities are considered realized losses as a result of securities being managed by an external investment management firm.  The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy.  Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment.  I&M records unrealized gains, unrealized losses and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates.  Consequently, changes in fair value of trust assets do not affect earnings or AOCI.
204

The following is a summary of nuclear trust fund investments:

 	September 30, 2021		December 31, 2020	
			Gross		Other-Than-				Gross		Other-Than-	
	Fair		Unrealized		Temporary		Fair		Unrealized		Temporary	
	Value		Gains		Impairments		Value		Gains		Impairments	
	(in millions)	
Cash and Cash Equivalents	$	63.9 			$	— 			$	— 			$	25.8 			$	— 			$	— 		
Fixed Income Securities:												
United States Government	1,135.3 			66.9 			(6.8)			1,025.6 			98.5 			(7.1)		
Corporate Debt	86.6 			6.9 			(2.0)			86.3 			9.6 			(1.7)		
State and Local Government	36.8 			0.3 			(0.2)			114.3 			0.9 			(0.4)		
Subtotal Fixed Income Securities	1,258.7 			74.1 			(9.0)			1,226.2 			109.0 			(9.2)		
Equity Securities - Domestic (a)	2,287.2 			1,652.8 			— 			2,054.7 			1,400.8 			— 		
Spent Nuclear Fuel and Decommissioning Trusts	$	3,609.8 			$	1,726.9 			$	(9.0)			$	3,306.7 			$	1,509.8 			$	(9.2)		

(a)Amount reported as Gross Unrealized Gains includes unrealized gains of $1.7 billion and $1.4 billion and unrealized losses of $4 million and $9 million as of September 30, 2021 and December 31, 2020, respectively.

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

		Three Months Ended September 30,		Nine Months Ended September 30,	
 		2021		2020		2021		2020	
 		(in millions)	
Proceeds from Investment Sales		$	433.9 			$	316.6 			$	1,556.6 			$	1,257.1 		
Purchases of Investments		436.6 			318.6 			1,586.3 			1,290.0 		
Gross Realized Gains on Investment Sales		9.6 			3.4 			98.3 			25.4 		
Gross Realized Losses on Investment Sales		7.0 			0.5 			12.5 			25.2 		

The base cost of fixed income securities was $1.2 billion and $1.1 billion as of September 30, 2021 and December 31, 2020, respectively.  The base cost of equity securities was $634 million and $654 million as of September 30, 2021 and December 31, 2020, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2021 was as follows:

	Fair Value of Fixed	
	Income Securities	
	(in millions)	
Within 1 year	$	292.9 		
After 1 year through 5 years	433.4 		
After 5 years through 10 years	251.5 		
After 10 years	280.9 		
Total	$	1,258.7 		
205

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, 2021

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

	
Other Temporary Investments											
Restricted Cash and Other Cash Deposits (a)		$	66.1 			$	— 			$	— 			$	11.2 			$	77.3 		
Fixed Income Securities – Mutual Funds		143.6 			— 			— 			— 			143.6 		
Equity Securities – Mutual Funds (b)		51.5 			— 			— 			— 			51.5 		
Total Other Temporary Investments		261.2 			— 			— 			11.2 			272.4 		
											
Risk Management Assets											
Risk Management Commodity Contracts (c) (d)		16.9 			1,090.7 			221.9 			(1,054.0)			275.5 		
Cash Flow Hedges:											
Commodity Hedges (c)		— 			367.3 			31.3 			(34.9)			363.7 		
Interest Rate Hedges		— 			4.9 			— 			— 			4.9 		
Fair Value Hedges		— 			3.4 			— 			— 			3.4 		
Total Risk Management Assets		16.9 			1,466.3 			253.2 			(1,088.9)			647.5 		
											
Spent Nuclear Fuel and Decommissioning Trusts											
Cash and Cash Equivalents (e)		56.0 			— 			— 			7.9 			63.9 		
Fixed Income Securities:											
United States Government		— 			1,135.3 			— 			— 			1,135.3 		
Corporate Debt		— 			86.6 			— 			— 			86.6 		
State and Local Government		— 			36.8 			— 			— 			36.8 		
Subtotal Fixed Income Securities		— 			1,258.7 			— 			— 			1,258.7 		
Equity Securities – Domestic (b)		2,287.2 			— 			— 			— 			2,287.2 		
Total Spent Nuclear Fuel and Decommissioning Trusts		2,343.2 			1,258.7 			— 			7.9 			3,609.8 		
											
Other Investments (h)		30.3 			15.9 			— 			— 			46.2 		
											
Total Assets		$	2,651.6 			$	2,740.9 			$	253.2 			$	(1,069.8)			$	4,575.9 		
											
Liabilities:											
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (d)		$	8.4 			$	923.3 			$	124.1 			$	(782.6)			$	273.2 		
Cash Flow Hedges:											
Commodity Hedges (c)		— 			38.9 			0.1 			(34.9)			4.1 		
	
Fair Value Hedges		— 			28.8 			— 			— 			28.8 		
Total Risk Management Liabilities		$	8.4 			$	991.0 			$	124.2 			$	(817.5)			$	306.1 		
206

AEP

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2020

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

	
Other Temporary Investments											
Restricted Cash and Other Cash Deposits (a)		$	57.8 			$	— 			$	— 			$	10.5 			$	68.3 		
Fixed Income Securities – Mutual Funds		123.5 			— 			— 			— 			123.5 		
Equity Securities – Mutual Funds (b)		54.6 			— 			— 			— 			54.6 		
Total Other Temporary Investments		235.9 			— 			— 			10.5 			246.4 		
											
Risk Management Assets											
Risk Management Commodity Contracts (c) (f)		0.9 			258.8 			252.4 			(190.0)			322.1 		
Cash Flow Hedges:											
Commodity Hedges (c)		— 			34.4 			3.9 			(28.5)			9.8 		
Interest Rate Hedges		— 			2.4 			— 			— 			2.4 		
Fair Value Hedges		— 			2.6 			— 			— 			2.6 		
Total Risk Management Assets		0.9 			298.2 			256.3 			(218.5)			336.9 		
											
Spent Nuclear Fuel and Decommissioning Trusts											
Cash and Cash Equivalents (e)		16.8 			— 			— 			9.0 			25.8 		
Fixed Income Securities:											
United States Government		— 			1,025.6 			— 			— 			1,025.6 		
Corporate Debt		— 			86.3 			— 			— 			86.3 		
State and Local Government		— 			114.3 			— 			— 			114.3 		
Subtotal Fixed Income Securities		— 			1,226.2 			— 			— 			1,226.2 		
Equity Securities – Domestic (b)		2,054.7 			— 			— 			— 			2,054.7 		
Total Spent Nuclear Fuel and Decommissioning Trusts		2,071.5 			1,226.2 			— 			9.0 			3,306.7 		
											
Other Investments (h)		— 			— 			31.8 			— 			31.8 		
											
Total Assets		$	2,308.3 			$	1,524.4 			$	288.1 			$	(199.0)			$	3,921.8 		
											
Liabilities:											
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (f)		$	0.9 			$	244.2 			$	167.2 			$	(193.4)			$	218.9 		
Cash Flow Hedges:											
Commodity Hedges (c)		— 			106.1 			7.6 			(28.5)			85.2 		
Interest Rate Hedges		— 			3.4 			— 			— 			3.4 		
Fair Value Hedges		— 			4.1 			— 			— 			4.1 		
Total Risk Management Liabilities		$	0.9 			$	357.8 			$	174.8 			$	(221.9)			$	311.6 		

207

AEP Texas
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2021

		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	
											
Restricted Cash for Securitized Funding		$	43.9 			$	— 			$	— 			$	— 			$	43.9 		
											
Risk Management Assets		 		 		 		 		 	
Risk Management Commodity Contracts (c)		— 			0.9 			— 			(0.9)			— 		
											
Total Assets		$	43.9 			$	0.9 			$	— 			$	(0.9)			$	43.9 		

	

December 31, 2020

		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	
											
Restricted Cash for Securitized Funding		$	28.7 			$	— 			$	— 			$	— 			$	28.7 		
											
Risk Management Assets		 		 		 		 		 	
Risk Management Commodity Contracts (c)		— 			0.4 			— 			(0.4)			— 		
											
Total Assets		$	28.7 			$	0.4 			$	— 			$	(0.4)			$	28.7 		

	

208

APCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2021

		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	
											
Restricted Cash for Securitized Funding		$	10.1 			$	— 			$	— 			$	— 			$	10.1 		
											
Risk Management Assets											
Risk Management Commodity Contracts (c) (g)		— 			48.9 			47.0 			(48.9)			47.0 		

	
											
Total Assets		$	10.1 			$	48.9 			$	47.0 			$	(48.9)			$	57.1 		
											
Liabilities:											
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (g)		$	— 			$	59.3 			$	1.1 			$	(59.1)			$	1.3 		

	

December 31, 2020

		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	
											
Restricted Cash for Securitized Funding		$	16.9 			$	— 			$	— 			$	— 			$	16.9 		
											
Risk Management Assets											
Risk Management Commodity Contracts (c) (g)		— 			19.4 			19.9 			(19.2)			20.1 		
Cash Flow Hedges:											
Interest Rate Hedges		— 			2.4 			— 			— 			2.4 		
Total Risk Management Assets		— 			21.8 			19.9 			(19.2)			22.5 		
											
Total Assets		$	16.9 			$	21.8 			$	19.9 			$	(19.2)			$	39.4 		
											
Liabilities:											
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (g)		$	— 			$	19.5 			$	0.6 			$	(18.8)			$	1.3 		
Cash Flow Hedges:											
Interest Rate Hedges		— 			3.4 			— 			— 			3.4 		
Total Risk Management Liabilities		$	— 			$	22.9 			$	0.6 			$	(18.8)			$	4.7 		

209

I&M
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2021

		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	
											
Risk Management Assets											
Risk Management Commodity Contracts (c) (g)		$	— 			$	30.9 			$	7.0 			$	(32.4)			$	5.5 		
											
Spent Nuclear Fuel and Decommissioning Trusts											
Cash and Cash Equivalents (e)		56.0 			— 			— 			7.9 			63.9 		
Fixed Income Securities:											
United States Government		— 			1,135.3 			— 			— 			1,135.3 		
Corporate Debt		— 			86.6 			— 			— 			86.6 		
State and Local Government		— 			36.8 			— 			— 			36.8 		
Subtotal Fixed Income Securities		— 			1,258.7 			— 			— 			1,258.7 		
Equity Securities - Domestic (b)		2,287.2 			— 			— 			— 			2,287.2 		
Total Spent Nuclear Fuel and Decommissioning Trusts		2,343.2 			1,258.7 			— 			7.9 			3,609.8 		
											
Total Assets		$	2,343.2 			$	1,289.6 			$	7.0 			$	(24.5)			$	3,615.3 		
											
Liabilities:											
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (g)		$	— 			$	48.3 			$	3.7 			$	(49.5)			$	2.5 		

December 31, 2020

		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	
											
Risk Management Assets											
Risk Management Commodity Contracts (c) (g)		$	— 			$	15.1 			$	2.5 			$	(13.9)			$	3.7 		
											
Spent Nuclear Fuel and Decommissioning Trusts											
Cash and Cash Equivalents (e)		16.8 			— 			— 			9.0 			25.8 		
Fixed Income Securities:											
United States Government		— 			1,025.6 			— 			— 			1,025.6 		
Corporate Debt		— 			86.3 			— 			— 			86.3 		
State and Local Government		— 			114.3 			— 			— 			114.3 		
Subtotal Fixed Income Securities		— 			1,226.2 			— 			— 			1,226.2 		
Equity Securities - Domestic (b)		2,054.7 			— 			— 			— 			2,054.7 		
Total Spent Nuclear Fuel and Decommissioning Trusts		2,071.5 			1,226.2 			— 			9.0 			3,306.7 		
											
Total Assets		$	2,071.5 			$	1,241.3 			$	2.5 			$	(4.9)			$	3,310.4 		
											
Liabilities:											
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (g)		$	— 			$	12.0 			$	0.4 			$	(12.2)			$	0.2 		
210

OPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2021

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

	
Risk Management Assets		 		 		 		 		 	
Risk Management Commodity Contracts (c) (g)		$	— 			$	0.7 			$	— 			$	(0.7)			$	— 		

											
Liabilities:			
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (g)		$	— 			$	— 			$	90.4 			$	— 			$	90.4 		

December 31, 2020

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

	
Risk Management Assets											
Risk Management Commodity Contracts (c) (g)		$	— 			$	0.3 			$	— 			$	(0.3)			$	— 		

	
Liabilities:			
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (g)		$	— 			$	— 			$	110.3 			$	— 			$	110.3 		

PSO
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2021

		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	
											
Risk Management Assets											
Risk Management Commodity Contracts (c) (g)		$	— 			$	0.3 			$	18.7 			$	(0.5)			$	18.5 		
											
Liabilities:											
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (g)		$	— 			$	— 			$	0.2 			$	(0.2)			$	— 		

December 31, 2020

		Level 1		Level 2		Level 3		Other		Total	
Assets:		(in millions)	
											
Risk Management Assets											
Risk Management Commodity Contracts (c) (g)		$	— 			$	0.2 			$	10.3 			$	(0.2)			$	10.3 		

	

211

SWEPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2021

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

	
Risk Management Assets											
Risk Management Commodity Contracts (c) (g)		$	— 			$	0.4 			$	19.8 			$	(0.6)			$	19.6 		

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

December 31, 2020

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

	
Risk Management Assets											
Risk Management Commodity Contracts (c) (g)		$	— 			$	0.1 			$	3.3 			$	(0.2)			$	3.2 		

	
Liabilities:											
											
Risk Management Liabilities											
Risk Management Commodity Contracts (c) (g)		$	— 			$	— 			$	1.7 			$	— 			$	1.7 		

(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, 2021 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $2 million in 2021 and $7 million in periods 2022-2024; Level 2 matures $20 million in 2021, $112 million in periods 2022-2024, $22 million in periods 2025-2026 and $13 million in periods 2027-2033; Level 3 matures $96 million in 2021, $18 million in periods 2022-2024, $5 million in periods 2025-2026 and $(21) million in periods 2027-2033.  Risk management commodity contracts are substantially comprised of power contracts.
(e)Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions.  Level 1 amounts primarily represent investments in money market funds.
(f)The December 31, 2020 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 2 matures $3 million in periods 2022-2024, $11 million in periods 2025-2026 and $1 million in periods 2027-2033; Level 3 matures $47 million in 2021, $37 million in periods 2022-2024, $14 million in periods 2025-2026 and $(13) million in periods 2027-2033.  Risk management commodity contracts are substantially comprised of power contracts.
(g)Substantially comprised of power contracts for the Registrant Subsidiaries.
(h)See “Warrants Held in Investee” section of Note 9 for additional information.
212

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, 2021		AEP		APCo		I&M		OPCo		PSO		SWEPCo	
 		(in millions)	
Balance as of June 30, 2021		$	101.2 			$	36.6 			$	7.3 			$	(105.4)			$	22.9 			$	14.6 		
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)		27.5 			4.0 			0.1 			0.1 			13.5 			5.8 		
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)		17.8 			— 			— 			— 			— 			— 		
Settlements		(54.5)			(10.5)			(3.8)			0.9 			(20.6)			(9.8)		
Transfers into Level 3 (d) (e)		(5.8)			— 			— 			— 			— 			— 		
Transfers out of Level 3 (e)		(4.1)			0.1 			— 			— 			— 			— 		
Changes in Fair Value Allocated to Regulated Jurisdictions (f)		44.0 			15.7 			(0.3)			14.0 			2.7 			9.0 		
Balance as of September 30, 2021		$	129.0 			$	45.9 			$	3.3 			$	(90.4)			$	18.5 			$	19.6 		
													
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 		
													
Nine Months Ended September 30, 2021		AEP		APCo		I&M		OPCo		PSO		SWEPCo	
 		(in millions)	
Balance as of December 31, 2020		$	113.3 			$	19.3 			$	2.1 			$	(110.3)			$	10.3 			$	1.6 		
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)		68.9 			38.8 			0.4 			0.4 			16.1 			9.5 		
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)		(64.1)			— 			— 			— 			— 			— 		
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)		35.5 			— 			— 			— 			— 			— 		
Settlements		(113.3)			(58.2)			(2.5)			5.8 			(26.4)			(13.0)		
Transfers into Level 3 (d) (e)		(0.2)			— 			— 					— 			— 		
Transfers out of Level 3 (e)		(26.2)			— 			— 			— 			— 			— 		
Changes in Fair Value Allocated to Regulated Jurisdictions (f)		115.1 			46.0 			3.3 			13.7 			18.5 			21.5 		
Balance as of September 30, 2021		$	129.0 			$	45.9 			$	3.3 			$	(90.4)			$	18.5 			$	19.6 		
													
213

																																							
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 		

(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.

214

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

AEP
Significant Unobservable Inputs
September 30, 2021

					Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input		Low		High		Average	
	(in millions)											
Energy Contracts	$	145.6 			$	117.3 			Discounted Cash Flow		Forward Market Price (a) (c)		$	0.10 			$	108.40 			$	35.57 		
Natural Gas Contracts	9.0 			— 			Discounted Cash Flow		Forward Market Price (b) (c)		2.92 			6.27 			4.59 		
FTRs	98.6 			6.9 			Discounted Cash Flow		Forward Market Price (a) (c)		(21.95)			13.46 			0.46 		
	
Total	$	253.2 			$	124.2 												

December 31, 2020

					Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input		Low		High		Average	
	(in millions)											
Energy Contracts	$	213.5 			$	169.7 			Discounted Cash Flow		Forward Market Price (a) (c)		$	5.33 			$	100.47 			$	32.73 		
Natural Gas Contracts	— 			1.7 			Discounted Cash Flow		Forward Market Price (b) (c)		2.18 			2.77 			2.40 		
FTRs	42.8 			3.4 			Discounted Cash Flow		Forward Market Price (a) (c)		(15.08)			9.66 			0.19 		
Other Investments	31.8 			— 			Black-Scholes Model		Liquidity Adjustment (d)		10 	%		20 	%		15 	%	
Total	$	288.1 			$	174.8 												
215

APCo
Significant Unobservable Inputs
September 30, 2021

					Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input (a)		Low		High		Average (c)	
	(in millions)											
Energy Contracts	$	0.2 			$	1.1 			Discounted Cash Flow		Forward Market Price		$	26.70 			$	87.14 			$	53.61 		
FTRs	46.8 			— 			Discounted Cash Flow		Forward Market Price		0.35 			13.46 			1.83 		
Total	$	47.0 			$	1.1 												

December 31, 2020

					Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input (a)		Low		High		Average (c)	
	(in millions)											
Energy Contracts	$	1.0 			$	0.6 			Discounted Cash Flow		Forward Market Price		$	10.84 			$	41.09 			$	25.08 		
FTRs	18.9 			— 			Discounted Cash Flow		Forward Market Price		0.04 			5.61 			1.13 		
Total	$	19.9 			$	0.6 												

I&M
Significant Unobservable Inputs
September 30, 2021

							Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input (a)		Low		High		Average (c)	
	(in millions)											
Energy Contracts	$	0.2 			$	0.7 			Discounted Cash Flow		Forward Market Price		$	26.70 			$	87.14 			$	53.61 		
FTRs	6.8 			3.0 			Discounted Cash Flow		Forward Market Price		(1.85)			5.75 			0.37 		
Total	$	7.0 			$	3.7 												

December 31, 2020

							Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input (a)		Low		High		Average (c)	
	(in millions)											
Energy Contracts	$	0.6 			$	0.3 			Discounted Cash Flow		Forward Market Price		$	10.84 			$	41.09 			$	25.08 		
FTRs	1.9 			0.1 			Discounted Cash Flow		Forward Market Price		(1.96)			3.69 			0.33 		
Total	$	2.5 			$	0.4 												
216

OPCo
Significant Unobservable Inputs
September 30, 2021

							Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input (a)		Low		High		Average (c)	
	(in millions)											
Energy Contracts	$	— 			$	90.4 			Discounted Cash Flow		Forward Market Price		$	9.89 			$	81.50 			$	32.40 		

December 31, 2020

							Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input (a)		Low		High		Average (c)	
	(in millions)											
Energy Contracts	$	— 			$	110.3 			Discounted Cash Flow		Forward Market Price		$	16.19 			$	46.98 			$	28.30 		

PSO
Significant Unobservable Inputs
September 30, 2021

							Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input (a)		Low		High		Average (c)	
	(in millions)											
FTRs	$	18.7 			$	0.2 			Discounted Cash Flow		Forward Market Price		$	(18.86)			$	4.10 			$	(2.44)		

December 31, 2020

							Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input (a)		Low		High		Average (c)	
	(in millions)											
FTRs	$	10.3 			$	— 			Discounted Cash Flow		Forward Market Price		$	(6.93)			$	0.48 			$	(1.93)		
217

SWEPCo
Significant Unobservable Inputs
September 30, 2021

							Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input		Low		High		Average (c)	
	(in millions)											
Natural Gas Contracts	$	9.0 			$	— 			Discounted Cash Flow		Forward Market Price (b)		$	3.58 			$	6.27 			$	4.44 		
FTRs	10.8 			0.2 			Discounted Cash Flow		Forward Market Price (a)		(18.86)			4.10 			(2.44)		
Total	$	19.8 			$	0.2 												

December 31, 2020

							Significant		Input/Range	
	Fair Value		Valuation		Unobservable						Weighted	
	Assets		Liabilities		Technique		Input		Low		High		Average (c)	
	(in millions)											
Natural Gas Contracts	$	— 			$	1.7 			Discounted Cash Flow		Forward Market Price (b)		$	2.18 			$	2.77 			$	2.41 		
FTRs	3.3 			— 			Discounted Cash Flow		Forward Market Price (a)		(6.93)			0.48 			(1.93)		
Total	$	3.3 			$	1.7 												

(a)Represents market prices in dollars per MWh.
(b)Represents market prices in dollars per MMBtu.
(c)The weighted average is the product of the forward market price of the underlying commodity and volume weighted by term.
(d)Represents percentage discount applied to the publically available share price.

The following table provides the measurement uncertainty of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts, Natural Gas Contracts, FTRs and Other Investments for the Registrants as of September 30, 2021 and December 31, 2020:

Uncertainty of Fair Value Measurements

Significant Unobservable Input		Position		Change in Input		Impact on Fair Value
Measurement	
Forward Market Price		Buy		Increase (Decrease)		Higher (Lower)	
Forward Market Price		Sell		Increase (Decrease)		Lower (Higher)	
Liquidity Adjustment		Buy		Increase (Decrease)		Lower (Higher)	
218

11.  INCOME TAXES

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

Effective Tax Rates (ETR)

The Registrants’ interim ETR reflect the estimated annual ETR for 2021 and 2020, 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, 2021	
		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		0.6 	%		0.3 	%		3.0 	%		(0.3)	%		1.9 	%		1.2 	%		5.0 	%		(6.9)	%	
Tax Reform Excess ADIT Reversal		(8.5)	%		(6.3)	%		0.3 	%		(14.2)	%		(16.1)	%		(8.9)	%		(19.8)	%		(4.2)	%	
Production and Investment Tax Credits		(4.7)	%		(0.3)	%		— 	%		(0.2)	%		(2.0)	%		— 	%		(8.9)	%		(5.4)	%	
Flow Through		— 	%		0.3 	%		0.3 	%		0.4 	%		(2.8)	%		0.6 	%		0.7 	%		(0.2)	%	
AFUDC Equity		(1.2)	%		(1.0)	%		(2.2)	%		(1.8)	%		(1.0)	%		(0.3)	%		(0.2)	%		(0.5)	%	
Parent Company Loss Benefit		— 	%		(1.1)	%		(2.3)	%		(1.2)	%		(3.6)	%		— 	%		— 	%		0.7 	%	
Discrete Tax Adjustments		0.2 	%		— 	%		— 	%		— 	%		— 	%		— 	%		— 	%		1.2 	%	
Other		0.7 	%		(0.1)	%		0.1 	%		0.3 	%		0.8 	%		— 	%		(0.1)	%		(0.2)	%	
Effective Income Tax Rate		8.1 	%		12.8 	%		20.2 	%		4.0 	%		(1.8)	%		13.6 	%		(2.3)	%		5.5 	%	
																	
		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 (a)		(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 	%	

																	
																	
219

																																																			

		Nine Months Ended September 30, 2021	
		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		1.2 	%		0.3 	%		2.8 	%		1.5 	%		1.6 	%		0.8 	%		4.8 	%		(3.4)	%	
Tax Reform Excess ADIT Reversal		(8.9)	%		(7.2)	%		0.3 	%		(15.2)	%		(17.7)	%		(9.1)	%		(19.8)	%		(4.3)	%	
Production and Investment Tax Credits		(4.9)	%		(0.3)	%		— 	%		— 	%		(2.2)	%		— 	%		(8.1)	%		(4.6)	%	
Flow Through		0.2 	%		0.3 	%		0.3 	%		1.7 	%		(3.0)	%		0.9 	%		0.7 	%		(0.2)	%	
AFUDC Equity		(1.1)	%		(1.1)	%		(1.9)	%		(1.2)	%		(1.0)	%		(0.8)	%		(0.3)	%		(0.6)	%	
Parent Company Loss Benefit		— 	%		(0.7)	%		(1.9)	%		(1.3)	%		(2.8)	%		— 	%		— 	%		— 	%	
Discrete Tax Adjustments		1.1 	%		— 	%		— 	%		— 	%		— 	%		(1.3)	%		(0.9)	%		0.6 	%	
Other		0.1 	%		— 	%		— 	%		0.1 	%		0.4 	%		0.2 	%		(0.2)	%		(0.1)	%	
Effective Income Tax Rate		8.7 	%		12.3 	%		20.6 	%		6.6 	%		(3.7)	%		11.7 	%		(2.8)	%		8.4 	%	

																	
		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 (a)		(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 	%	

(a)The discrete tax expense is primarily attributable to the $48 million benefit recognized as a result of the 5-year net operating losses (NOL) carryback provision of the CARES Act.

Federal and State Income Tax Audit Status

The statute of limitations for the IRS to examine AEP and subsidiaries originally filed federal return has expired for tax years 2016 and earlier. In the third quarter of 2019, AEP and subsidiaries elected to amend the 2014 through 2017 federal returns. In the first quarter of 2020, the IRS notified AEP that it was beginning an examination of these amended returns, including the NOL carryback to 2015 that originated in the 2017 return. As of September 30, 2021, the IRS has not challenged any items on these returns and the IRS is limited in their proposed adjustments to the amount AEP claimed on the amended returns. AEP has agreed to extend the statute of limitations on the 2017 tax return to December 31, 2022 to allow time for the audit to be completed and the Congressional Joint Committee on Taxation to approve the associated refund claim.

AEP and subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns, and AEP and subsidiaries are currently under examination in several state and local jurisdictions. The Registrants are no longer subject to state or local examinations by tax authorities for years before 2012. In addition, management is monitoring and continues to evaluate the potential impact of federal legislation and corresponding state conformity.
220

Federal Legislation

In March 2020, the CARES Act was signed into law. The CARES Act includes tax relief provisions including a 5-year NOL carryback from years 2018-2020. In the third quarter of 2020, AEP requested a $95 million refund of taxes paid in 2014 under the 5-year NOL carryback provision of the CARES Act. AEP carried back a NOL generated on the 2019 Federal income tax return at a 21% federal corporate income tax rate to the 2014 Federal income tax return at a 35% corporate income tax rate. As a result of the change in the corporate income tax rates between the two periods, AEP realized a tax benefit of $48 million primarily at the Generation & Marketing segment in 2020.

State Legislation

In April 2021, West Virginia enacted House Bill (H.B.) 2026. H.B. 2026 changes the state income tax apportionment formula from a ratio that includes property, payroll and sales to a single sales factor apportionment regime effective for tax years beginning on or after January 1, 2022. H.B. 2026 also eliminates the “throw out” rule related to sales of tangible personal property for sales factor apportionment calculation purposes and introduces a market-based sourcing for sales of services and intangible property. In the second quarter of 2021, AEP recorded $20 million in Income Tax Expense as a result of remeasuring West Virginia deferred taxes under the new apportionment methodology. The enacted legislation does not impact AEP Texas, PSO or SWEPCo.

In May 2021, Oklahoma enacted House Bill (H.B.) 2960. H.B. 2960 reduces the Oklahoma corporate income tax rate from 6% to 4%. In the second quarter of 2021, AEP recorded a $1 million Income Tax Benefit as a result of remeasuring Oklahoma deferred taxes at the lowered statutory tax rate of 4%. The enacted legislation does not impact APCo, I&M or OPCo.
221

12.  FINANCING ACTIVITIES

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

Common Stock (Applies to AEP)

At-the-Market (ATM) Program

In 2020, AEP filed a prospectus supplement and executed an Equity Distribution Agreement, pursuant to which AEP may sell, from time to time, up to an aggregate of $1 billion of its common stock through an ATM offering program, including an equity forward sales component. The compensation paid to the selling agents by AEP may be up to 2% of the gross offering proceeds of the shares. For the nine months ended September 30, 2021, AEP issued 5,421,825 shares of common stock and received net cash proceeds of $461 million under the ATM program.

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, 2021		December 31, 2020	
 		(in millions)	
Senior Unsecured Notes		$	28,778.1 			$	25,116.1 		
Pollution Control Bonds		1,881.0 			1,936.7 		
Notes Payable		235.1 			239.1 		
Securitization Bonds		639.7 			716.4 		
Spent Nuclear Fuel Obligation (a)		281.3 			281.2 		
Junior Subordinated Notes (b)		1,629.9 			1,624.1 		
Other Long-term Debt		1,133.2 			1,158.9 		
Total Long-term Debt Outstanding		34,578.3 			31,072.5 		
Long-term Debt Due Within One Year		2,521.8 			2,086.1 		
Long-term Debt		$	32,056.5 			$	28,986.4 		

(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 $327 million and $324 million as of September 30, 2021 and December 31, 2020, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.
(b)See “Equity Units” section below for additional information.

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Long-term Debt Activity

Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2021 are shown in the following tables:

				Principal		Interest			
Company		Type of Debt		Amount (a)		Rate		Due Date	
Issuances:		 		(in millions)		(%)			
	
AEP		Senior Unsecured Notes		$	175.0 			1.80		2028	
AEP Texas		Senior Unsecured Notes		450.0 			3.45		2051	
AEPTCo		Senior Unsecured Notes		450.0 			2.75		2051	
	
APCo		Senior Unsecured Notes		500.0 			2.70		2031	
I&M		Notes Payable		64.9 			0.93		2025	
I&M		Senior Unsecured Notes		450.0 			3.25		2051	
OPCo		Senior Unsecured Notes		450.0 			1.63		2031	
OPCo		Senior Unsecured Notes		600.0 			2.90		2051	
PSO		Other Long-term Debt		500.0 			Variable		2022	
PSO		Senior Unsecured Notes		400.0 			2.20		2031	
PSO		Senior Unsecured Notes		400.0 			3.15		2051	
SWEPCo		Senior Unsecured Notes		500.0 			1.65		2026	
									
Non-Registrant:									
KPCo		Other Long-term Debt		150.0 			Variable		2023	
Transource Energy		Other Long-term Debt		25.9 			Variable		2023	
Total Issuances				$	5,115.8 						

(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.
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				Principal		Interest			
Company		Type of Debt		Amount Paid		Rate		Due Date	
Retirements and Principal Payments:				(in millions)		(%)			

	
	
AEP Texas		Securitization Bonds		$	29.7 			2.85		2024	
AEP Texas		Securitization Bonds		22.5 			2.06		2025	
	
APCo		Senior Unsecured Notes		350.0 			4.60		2021	
APCo		Pollution Control Bonds		17.5 			4.63		2021	
APCo		Securitization Bonds		25.4 			2.01		2023	
APCo		Other Long-term Debt		0.1 			13.72		2026	

	
	
I&M		Other Long-term Debt		200.0 			Variable		2021	
I&M		Pollution Control Bonds		40.0 			2.05		2021	
I&M		Notes Payable		1.9 			Variable		2021	
I&M		Notes Payable		4.5 			Variable		2022	
I&M		Notes Payable		5.4 			Variable		2022	
I&M		Notes Payable		14.3 			Variable		2023	
I&M		Notes Payable		12.6 			Variable		2024	
	
I&M		Notes Payable		19.6 			Variable		2025	
I&M		Notes Payable		7.4 			0.93		2025	
I&M		Other Long-term Debt		1.5 			6.00		2025	

OPCo		Other Long-term Debt		0.1 			1.15		2028	
PSO		Senior Unsecured Notes		250.0 			4.40		2021	
PSO		Other Long-term Debt		500.0 			Variable		2022	
PSO		Other Long-term Debt		0.4 			3.00		2027	
SWEPCo		Other Long-term Debt		1.5 			4.68		2028	
SWEPCo		Notes Payable		3.2 			4.58		2032	
									
Non-Registrant:									
KPCo		Senior Unsecured Notes		39.8 			7.25		2021	
Transource Energy		Senior Unsecured Notes		1.2 			2.75		2050	
Transource Energy		Senior Unsecured Notes		1.2 			2.75		2050	

	

	
	
Total Retirements and Principal Payments				$	1,549.8 						

As of September 30, 2021, trustees held, on behalf of I&M, $40 million of its reacquired Pollution Control Bonds.

Long-term Debt Subsequent Event

In October 2021, I&M retired $8 million of Notes Payable related to DCC Fuel.

In October 2021, OPCo retired $500 million of Senior Unsecured Notes.

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%.
224

Each forward equity purchase contract obligates the holder to purchase, and AEP to sell, for $50 a number of shares in common stock in accordance with the conversion ratios set forth below (subject to an anti-dilution adjustment):

•If the AEP common stock market price is equal to or greater than $99.95: 0.5003 shares per contract.
•If the AEP common stock market price is less than $99.95 but greater than $83.29: a number of shares per contract equal to $50 divided by the applicable market price. The holder receives a variable number of shares at $50.
•If the AEP common stock market price is less than or equal to $83.29: 0.6003 shares per contract.

A holder’s ownership interest in the notes is pledged to AEP to secure the holder’s obligation under the related forward equity purchase contract. If a holder of the forward equity purchase contract chooses at any time to no longer be a holder of the notes, such holder’s obligation under the forward equity purchase contract must be secured by a U.S. Treasury security which must be equal to the aggregate principal amount of the notes.

At the time of issuance, the $850 million of notes were recorded within Long-term Debt on the balance sheets. The present value of the purchase contract payments of $121 million were recorded in Deferred Credits and Other Noncurrent Liabilities with a current portion in Other Current Liabilities at the time of issuance, representing the obligation to make forward equity contract payments, with an offsetting reduction to Paid-in Capital. The difference between the face value and present value of the purchase contract payments will be accreted to Interest Expense on the statements of income over the three year period ending in 2023. The liability recorded for the contract payments is considered non-cash and excluded from the statements of cash flows. Until settlement of the forward equity purchase contract, earnings per share dilution resulting from the equity unit issuance will be determined under the treasury stock method. The maximum amount of shares AEP will be required to issue to settle the purchase contract is 10,205,100 shares (subject to an anti-dilution adjustment).

2019 Equity Units

In March 2019, AEP issued 16.1 million Equity Units initially in the form of corporate units, at a stated amount of $50 per unit, for a total stated amount of $805 million. Net proceeds from the issuance were approximately $785 million. The proceeds were used to support AEP’s overall capital expenditure plans including the acquisition of Sempra Renewables LLC.

Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 3.40% Junior Subordinated Notes (notes) due in 2024 and a forward equity purchase contract which settles after three years in 2022. The notes are expected to be remarketed in 2022, at which time the interest rate will reset at the then current market rate. Investors may choose to remarket their notes to receive the remarketing proceeds and use those funds to settle the forward equity purchase contract, or accept the remarketed debt and use other funds for the equity purchase. If the remarketing is unsuccessful, investors have the right to put their notes to AEP at a price equal to the principal. The Equity Units carry an annual distribution rate of 6.125%, which is comprised of a quarterly coupon rate of interest of 3.40% and a quarterly forward equity purchase contract payment of 2.725%.

Each forward equity purchase contract obligates the holder to purchase, and AEP to sell, for $50 a number of shares in common stock in accordance with the conversion ratios set forth below (subject to an anti-dilution adjustment):

•If the AEP common stock market price is equal to or greater than $99.58: 0.5021 shares per contract.
•If the AEP common stock market price is less than $99.58 but greater than $82.98: a number of shares per contract equal to $50 divided by the applicable market price. The holder receives a variable number of shares at $50.
•If the AEP common stock market price is less than or equal to $82.98: 0.6026 shares per contract.

A holder’s ownership interest in the notes is pledged to AEP to secure the holder’s obligation under the related forward equity purchase contract. If a holder of the forward equity purchase contract chooses at any time to no longer be a holder of the notes, such holder’s obligation under the forward equity purchase contract must be secured by a U.S. Treasury security which must be equal to the aggregate principal amount of the notes.

225

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 0.1% of consolidated tangible net assets as of September 30, 2021. 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.
226

Corporate Borrowing Program - AEP System (Applies to all 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, 2021 and December 31, 2020 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, 2021 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, 2021		Limit		
 		(in millions)	
AEP Texas		$	355.5 			$	104.7 			$	234.7 			$	45.2 			$	47.6 			$	500.0 			
AEPTCo		444.9 			117.3 			225.1 			24.4 			73.9 			820.0 		(a)	
APCo		27.8 			616.9 			13.2 			134.4 			185.2 			500.0 			
I&M		166.5 			368.2 			117.5 			76.3 			80.6 			500.0 			
OPCo		259.2 			622.9 			62.8 			182.5 			622.9 			500.0 			
PSO		267.7 			747.3 			142.8 			184.9 			59.5 			300.0 			
SWEPCo		280.3 			156.4 			148.0 			142.0 			(122.9)			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, 2021 and December 31, 2020 are included in Advances to Affiliates on the subsidiaries’ balance sheets. The Nonutility Money Pool participants’ activity for the nine months ended September 30, 2021 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, 2021	
	(in millions)	
AEP Texas		$	7.1 			$	6.9 			$	7.0 		
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, 2021 and December 31, 2020 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, 2021 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, 2021		September 30, 2021		Borrowing Limit		
(in millions)	
$	14.6 			$	224.2 			$	1.6 			$	139.3 			$	8.6 			$	— 			$	50.0 		(a)	

(a)    Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
227

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,	
		2021		2020	
Maximum Interest Rate		0.40 	%		2.70 	%	
Minimum Interest Rate		0.02 	%		0.33 	%	

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		2021		2020		2021		2020	
AEP Texas		0.33 	%		1.55 	%		0.27 	%		0.87 	%	
AEPTCo		0.32 	%		1.63 	%		0.07 	%		2.00 	%	
APCo		0.28 	%		2.14 	%		0.28 	%		0.99 	%	
I&M		0.32 	%		1.30 	%		0.25 	%		1.44 	%	
OPCo		0.27 	%		1.32 	%		0.15 	%		2.06 	%	
PSO		0.34 	%		1.24 	%		0.06 	%		1.95 	%	
SWEPCo		0.28 	%		1.55 	%		0.38 	%		— 	%	

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, 2021		Nine Months Ended September 30, 2020	
 	 	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	 	0.41 	%		0.21 	%		0.34 	%		2.70 	%		0.33 	%		1.44 	%	
SWEPCo	 	0.41 	%		0.21 	%		0.34 	%		2.70 	%		0.33 	%		1.44 	%	

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	
2021	 	0.86 	%		0.25 	%		0.86 	%		0.25 	%		0.35 	%		0.34 	%	
2020	 	2.70 	%		0.50 	%		2.70 	%		0.50 	%		1.45 	%		1.40 	%	

228

Short-term Debt (Applies to AEP and SWEPCo)

Outstanding short-term debt was as follows:

		 		September 30, 2021		December 31, 2020	
				Outstanding		Interest		Outstanding		Interest	
Company		Type of Debt		Amount		Rate (a)		Amount		Rate (a)	
		 		(dollars in millions)	
AEP		Securitized Debt for Receivables (b)		$	750.0 			0.19 	%		$	592.0 			0.85 	%	
AEP		Commercial Paper		1,254.0 			0.25 	%		1,852.3 			0.29 	%	
AEP		364-Day Term Loan		500.0 			0.72 	%		— 			— 	%	
	
SWEPCo		Notes Payable		— 			— 	%		35.0 			2.55 	%	
		Total Short-term Debt		$	2,504.0 			 		$	2,479.3 			 	

(a)Weighted-average rate.
(b)Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.

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 with bank conduits. 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.

AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and was amended in September 2021 to include a $125 million and a $625 million facility which expire in September 2023 and 2024, respectively. As of September 30, 2021, the affiliated utility subsidiaries are in compliance with all requirements under the agreement.

Accounts receivable information for AEP Credit was as follows:
																											
		Three Months Ended		Nine Months Ended	
		September 30,		September 30,	
		2021		2020		2021		2020	
		(dollars in millions)	
Effective Interest Rates on Securitization of Accounts Receivable		0.18 	%		0.36 	%		0.19 	%		1.05 	%	
Net Uncollectible Accounts Receivable Written-Off		$	7.5 			$	2.9 			$	22.6 			$	10.5 		

		September 30, 2021		December 31, 2020	
		(in millions)	
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts		$	1,031.3 			$	958.4 		
Short-term – Securitized Debt of Receivables		750.0 			592.0 		
Delinquent Securitized Accounts Receivable		60.0 			62.3 		
Bad Debt Reserves Related to Securitization		39.8 			60.0 		
Unbilled Receivables Related to Securitization		224.5 			296.8 		

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

Securitized Accounts Receivables – AEP Credit (Applies to all 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
229

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, 2021		December 31, 2020	
 		(in millions)	
APCo		$	131.0 			$	136.0 		
I&M		173.9 			170.5 		
OPCo		377.3 			398.8 		
PSO		147.1 			85.0 		
SWEPCo		185.6 			158.6 		

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

 		Three Months Ended September 30,		Nine Months Ended September 30,	
Company		2021 (a)		2020		2021 (a)		2020	
 		(in millions)	
APCo		$	1.3 			$	2.0 			$	3.7 			$	5.0 		
I&M		2.1 			3.9 			5.3 			9.3 		
OPCo		4.6 			9.8 			3.5 			19.6 		
PSO		1.1 			1.5 			2.4 			3.8 		
SWEPCo		1.3 			2.8 			4.1 			6.8 		
(a)In 2020, an increase in allowance for doubtful accounts was recognized in response to the anticipated impact of COVID-19 on the collectability of accounts receivable, which caused an increase in fees paid by the registrants. In 2021, due to higher than expected collections of accounts receivables, allowance for doubtful accounts was adjusted resulting in the issuance of credits to offset the higher fees previously paid and to lower subsequent fees paid.

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

 		Three Months Ended September 30,		Nine Months Ended September 30,	
Company		2021		2020		2021		2020	
		(in millions)	
APCo		$	342.2 			$	323.5 			$	980.6 			$	961.8 		
I&M		536.8 			532.3 			1,478.9 			1,443.6 		
OPCo		668.4 			666.0 			1,867.5 			1,793.0 		
PSO		460.1 			369.2 			1,068.8 			961.4 		
SWEPCo		488.5 			478.3 			1,265.5 			1,225.3 		

230

13. PROPERTY, PLANT AND EQUIPMENT

The disclosure in this note applies to AEP and APCo.

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 discussion below summarizes significant changes to the Registrants ARO recorded in 2021 and should be read in conjunction with the Property, Plant and Equipment note within the 2020 Annual Report.

In 2020, Virginia’s Governor signed House Bill 443 (HB 443) requiring APCo to close certain ash disposal units at the retired Glen Lyn Station by removal of all coal combustion material. 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 HB 443. In June 2021, management completed fully designed and costed project plans for the Glen Lyn Station site and increased ash disposal ARO liabilities by an additional $79 million. HB 443 provides for the recovery of all costs associated with closure by removal through the Virginia environmental rate adjustment clause. 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.

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

Company		ARO as of December 31, 2020		Accretion
Expense		Liabilities
Incurred		Liabilities
Settled		Revisions in
Cash Flow
Estimates		ARO as of September 30, 2021	
		(in millions)	
AEP (a)(b)(c)(d)		$	2,516.7 			$	77.6 			$	17.7 			$	(27.6)			$	75.1 			$	2,659.5 		
APCo (a)(d)		313.1 			9.9 			— 			(5.8)			84.7 			401.9 		

(a)Includes ARO related to ash disposal facilities.
(b)Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.85 billion and $1.80 billion as of September 30, 2021 and December 31, 2020, respectively.
(c)Includes ARO related to Sabine and DHLC.
(d)Includes ARO related to asbestos removal.

231

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, 2021	
		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		$	1,144.3 			$	598.0 			$	— 			$	— 			$	— 			$	— 			$	1,742.3 		
Commercial Revenues		618.9 			279.9 			— 			— 			— 			— 			898.8 		
Industrial Revenues		566.0 			95.2 			— 			— 			— 			(0.1)			661.1 		
Other Retail Revenues		47.5 			11.1 			— 			— 			— 			— 			58.6 		
Total Retail Revenues		2,376.7 			984.2 			— 			— 			— 			(0.1)			3,360.8 		
															
Wholesale and Competitive Retail Revenues:															
Generation Revenues		233.8 			— 			— 			47.8 			— 			— 			281.6 		
Transmission Revenues (a)		99.8 			150.6 			375.8 			— 			— 			(317.4)			308.8 		
Renewable Generation Revenues (b)		— 			— 			— 			24.1 			— 			(0.6)			23.5 		
Retail, Trading and Marketing Revenues (c)		— 			— 			— 			397.1 			0.1 			(3.1)			394.1 		
Total Wholesale and Competitive Retail Revenues		333.6 			150.6 			375.8 			469.0 			0.1 			(321.1)			1,008.0 		
															
Other Revenues from Contracts with Customers (b)		49.4 			54.2 			5.1 			1.4 			23.5 			(40.1)			93.5 		
															
Total Revenues from Contracts with Customers		2,759.7 			1,189.0 			380.9 			470.4 			23.6 			(361.3)			4,462.3 		
															
Other Revenues:															
Alternative Revenues (b)		0.5 			6.4 			10.7 			— 			— 			(11.7)			5.9 		
Other Revenues (b) (d)		(0.9)			4.9 			— 			150.7 			3.1 			(3.0)			154.8 		
Total Other Revenues		(0.4)			11.3 			10.7 			150.7 			3.1 			(14.7)			160.7 		
															
Total Revenues		$	2,759.3 			$	1,200.3 			$	391.6 			$	621.1 			$	26.7 			$	(376.0)			$	4,623.0 		

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $286 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 $4 million. The remaining affiliated amounts were immaterial.
(d)Generation & Marketing includes economic hedge activity.

232

																																													
		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) (d)		— 			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.
(d)Generation & Marketing includes economic hedge activity.

233

																																													
		Three Months Ended September 30, 2021	
		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Retail Revenues:															
Residential Revenues		$	172.5 			$	— 			$	340.1 			$	231.7 			$	425.4 			$	236.8 			$	230.9 		
Commercial Revenues		89.1 			— 			146.9 			143.9 			190.8 			120.9 			145.4 		
Industrial Revenues		25.4 			— 			154.8 			146.8 			69.8 			77.1 			85.4 		
Other Retail Revenues		8.2 			— 			18.6 			1.3 			3.1 			23.4 			2.3 		
Total Retail Revenues		295.2 			— 			660.4 			523.7 			689.1 			458.2 			464.0 		
															
Wholesale Revenues:															
Generation Revenues (a)		— 			— 			83.7 			80.2 			— 			7.2 			77.1 		
Transmission Revenues (b)		131.5 			360.1 			35.2 			8.7 			19.1 			10.6 			37.1 		
Total Wholesale Revenues		131.5 			360.1 			118.9 			88.9 			19.1 			17.8 			114.2 		
															
Other Revenues from Contracts with Customers (c)		6.8 			5.0 			22.5 			24.2 			47.3 			8.3 			6.1 		
															
Total Revenues from Contracts with Customers		433.5 			365.1 			801.8 			636.8 			755.5 			484.3 			584.3 		
															
Other Revenues:															
Alternative Revenues (d)		(0.9)			11.9 			2.2 			(1.1)			7.3 			(0.5)			(0.2)		
Other Revenues (d)		— 			— 			— 			— 			4.9 			— 			— 		
Total Other Revenues		(0.9)			11.9 			2.2 			(1.1)			12.2 			(0.5)			(0.2)		
															
Total Revenues		$	432.6 			$	377.0 			$	804.0 			$	635.7 			$	767.7 			$	483.8 			$	584.1 		

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $30 million primarily relating to the PPA with KGPCo.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $281 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $17 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.

234

																																													
		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.

235

																																													
		Nine Months Ended September 30, 2021	
		Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other		Reconciling Adjustments		AEP Consolidated	
		(in millions)	
Retail Revenues:															
Residential Revenues		$	3,016.2 			$	1,641.2 			$	— 			$	— 			$	— 			$	— 			$	4,657.4 		
Commercial Revenues		1,642.0 			804.1 			— 			— 			— 			— 			2,446.1 		
Industrial Revenues		1,602.5 			283.8 			— 			— 			— 			(0.5)			1,885.8 		
Other Retail Revenues		125.9 			32.4 			— 			— 			— 			— 			158.3 		
Total Retail Revenues		6,386.6 			2,761.5 			— 			— 			— 			(0.5)			9,147.6 		
															
Wholesale and Competitive Retail Revenues:															
Generation Revenues		757.1 			— 			— 			119.4 			— 			— 			876.5 		
Transmission Revenues (a)		267.3 			420.7 			1,092.1 			— 			— 			(901.5)			878.6 		
Renewable Generation Revenues (b)		— 			— 			— 			66.7 			— 			(1.7)			65.0 		
Retail, Trading and Marketing Revenues (c)		— 			— 			— 			1,325.6 			0.6 			(48.5)			1,277.7 		
Total Wholesale and Competitive Retail Revenues		1,024.4 			420.7 			1,092.1 			1,511.7 			0.6 			(951.7)			3,097.8 		
															
Other Revenues from Contracts with Customers (b)		136.1 			149.3 			12.5 			4.9 			46.1 			(87.9)			261.0 		
															
Total Revenues from Contracts with Customers		7,547.1 			3,331.5 			1,104.6 			1,516.6 			46.7 			(1,040.1)			12,506.4 		
															
Other Revenues:															
Alternative Revenues (b)		10.7 			46.1 			42.2 			— 			— 			(63.5)			35.5 		
Other Revenues (b) (d)		(0.6)			14.2 			— 			175.3 			8.4 			(8.6)			188.7 		
Total Other Revenues		10.1 			60.3 			42.2 			175.3 			8.4 			(72.1)			224.2 		
															
Total Revenues		$	7,557.2 			$	3,391.8 			$	1,146.8 			$	1,691.9 			$	55.1 			$	(1,112.2)			$	12,730.6 		

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $835 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 $49 million. The remaining affiliated amounts were immaterial.
(d)Generation & Marketing includes economic hedge activity.

236

																																													
		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) (d)		— 			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.
(d)Generation & Marketing includes economic hedge activity.

237

																																													
		Nine Months Ended September 30, 2021	
		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
		(in millions)	
Retail Revenues:															
Residential Revenues		$	423.7 			$	— 			$	1,025.0 			$	624.4 			$	1,217.5 			$	516.4 			$	547.1 		
Commercial Revenues		265.2 			— 			409.5 			384.5 			538.9 			286.8 			385.4 		
Industrial Revenues		81.6 			— 			433.4 			418.9 			202.2 			202.1 			247.1 		
Other Retail Revenues		23.1 			— 			51.7 			3.9 			9.4 			58.2 			7.2 		
Total Retail Revenues		793.6 			— 			1,919.6 			1,431.7 			1,968.0 			1,063.5 			1,186.8 		
															
Wholesale Revenues:															
Generation Revenues (a)		— 			— 			231.2 			248.1 			— 			6.8 			326.2 		
Transmission Revenues (b)		364.5 			1,045.2 			94.1 			25.3 			56.2 			28.8 			94.5 		
Total Wholesale Revenues		364.5 			1,045.2 			325.3 			273.4 			56.2 			35.6 			420.7 		
															
Other Revenues from Contracts with Customers (c)		35.4 			12.5 			43.6 			81.9 			113.8 			24.8 			17.7 		
															
Total Revenues from Contracts with Customers		1,193.5 			1,057.7 			2,288.5 			1,787.0 			2,138.0 			1,123.9 			1,625.2 		
															
Other Revenues:															
Alternative Revenues (d)		1.8 			46.5 			9.5 			(3.0)			44.3 			0.5 			5.1 		
Other Revenues (d)		— 			— 			— 			— 			14.2 			— 			— 		
Total Other Revenues		1.8 			46.5 			9.5 			(3.0)			58.5 			0.5 			5.1 		
															
Total Revenues		$	1,195.3 			$	1,104.2 			$	2,298.0 			$	1,784.0 			$	2,196.5 			$	1,124.4 			$	1,630.3 		

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $90 million primarily relating to the PPA with KGPCo.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $823 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $46 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.
238

																																													
		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.

239

Fixed Performance Obligations

The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of September 30, 2021. Fixed performance obligations primarily include wholesale transmission services, electricity sales for fixed amounts of energy and stand ready services into PJM’s RPM market. The Registrant Subsidiaries amounts shown in the table below include affiliated and nonaffiliated revenues.

Company		2021		2022-2023		2024-2025		After 2025		Total	
		(in millions)	
AEP		$	314.9 			$	199.3 			$	160.3 			$	161.5 			$	836.0 		
AEP Texas		132.7 			— 			— 			— 			132.7 		
AEPTCo		331.7 			— 			— 			— 			331.7 		
APCo		44.9 			34.5 			26.6 			11.6 			117.6 		
I&M		10.0 			11.5 			8.8 			4.5 			34.8 		
OPCo		22.2 			10.1 			— 			— 			32.3 		
PSO		3.5 			— 			— 			— 			3.5 		
SWEPCo		10.1 			— 			— 			— 			10.1 		

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, 2021 and December 31, 2020.

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 sheets 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, 2021 and December 31, 2020.

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, 2021 and December 31, 2020. 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, 2021		December 31, 2020	
		(in millions)	
AEPTCo		$	96.4 			$	81.0 		
APCo		64.1 			52.7 		
I&M		24.6 			34.8 		
OPCo		44.5 			45.9 		
PSO		17.7 			7.8 		
SWEPCo		19.9 			11.2 		

240

15. SUBSEQUENT EVENTS

The disclosure in this note applies to AEP and AEPTCo.

Disposition of KPCo and KTCo

In October 2021, AEP entered into a Stock Purchase Agreement to sell KPCo and KTCo to Liberty Utilities Co., a subsidiary of Algonquin Power & Utilities Corp. (Liberty), for approximately a $2.85 billion enterprise value. The sale is subject to regulatory approvals from the FERC, the KPSC, clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, and clearance from the Committee on Foreign Investment in the United States.

KPCo currently operates and owns a 50% interest in the 1,560 MW coal-fired Mitchell Power Plant (Mitchell Plant) with the remaining 50% owned by WPCo. The Stock Purchase Agreement is further contingent upon approval by the KPSC, WVPSC and FERC of a new proposed Mitchell Plant Operations and Maintenance Agreement and Mitchell Plant Ownership Agreement between KPCo and WPCo pursuant to which WPCo will replace KPCo as the operator of the Mitchell Plant and KPCo employees at the Mitchell Plant will become employees of WPCo at closing of the transaction. Under the proposed Ownership Agreement, WPCo is obligated to purchase KPCo’s 50% interest in the Mitchell Plant on December 31, 2028 unless KPCo and WPCo have agreed to retire the Mitchell Plant earlier or, absent such agreement, if WPCo elects prior to December 31, 2027 to retire the Mitchell Plant on December 31, 2028. The Ownership Agreement provides that the purchase price for KPCo’s 50% ownership interest in the Mitchell Plant will be determined through the mutual agreement of WPCo and KPCo (subject to approval from the KPSC and WVPSC) or through a fair market valuation determination conducted by independent appraisals if KPCo and WPCo are unable to reach agreement as to the purchase price.

The sale is expected to close in the second quarter of 2022 with Liberty acquiring the assets and assuming the liabilities of KPCo and KTCo, excluding pension and other post-retirement benefit plan assets and liabilities. AEP expects to provide customary transition services to Liberty for a period of time after closing of the transaction.

AEP expects to receive approximately $1.45 billion in cash, net of taxes and transaction fees.

The major classes of KPCo and KTCo’s assets and liabilities as presented on the balance sheets of AEP and AEPTCo as of September 30, 2021 are shown in the table below.

241

															
		September 30, 2021	
		AEP		AEPTCo	
		(in millions)	
Assets:					
Accounts Receivable and Accrued Unbilled Revenues		$	24.7 			$	1.6 		
Fuel, Materials and Supplies		26.5 			— 		
Property, Plant and Equipment, Net		2,264.6 			164.5 		
Regulatory Assets		501.7 			— 		
Other Classes of Assets that are not Major		43.8 			0.3 		
Total Assets		$	2,861.3 			$	166.4 		
					
Liabilities:					
Accounts Payable		$	51.2 			$	1.5 		
Long-term Debt Due Within One Year		125.0 			— 		
Customer Deposits		31.9 			— 		
Deferred Income Taxes		448.3 			14.9 		
Long-term Debt		978.0 			— 		
Regulatory Liabilities and Deferred Investment Tax Credits		146.5 			7.5 		
Other Classes of Liabilities that are not Major		93.2 			4.2 		
Total Liabilities		$	1,874.1 			$	28.1 		

242

CONTROLS AND PROCEDURES

During the third quarter of 2021, 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, 2021, 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 2021 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.
243

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 Annual Report on Form 10-K for the year ended December 31, 2020 includes a detailed discussion of risk factors. As of September 30, 2021, the risk factors appearing in AEP’s 2020 Annual Report are supplemented and updated as follows:

The rate of taxes imposed on AEP could change. (Applies to all Registrants)

AEP is subject to income taxation at the federal level and by certain states and municipalities. In determining AEP’s income tax liability for these jurisdictions, management monitors changes to the applicable tax laws and related regulations. While management believes it is in compliance with current prevailing laws, one or more taxing jurisdictions could seek to impose incremental or new taxes on the company. In addition, as a result of the most recent presidential and congressional elections in the United States, there could be significant changes in tax law and regulations that could result in additional federal income taxes being imposed on AEP. Any adverse developments in these laws or regulations, including legislative changes, judicial holdings or administrative interpretations, could have a material and adverse effect on financial condition and results of operations.

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

Certain events, such as an aging workforce without appropriate replacements, employee reaction to comply with potential COVID-19 vaccination mandates, mismatch of skillset or complement to future needs, or unavailability of contract resources may lead to operating challenges and increased costs. The challenges include potential higher rates of existing employee departures, lack of resources, loss of knowledge and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs, safety costs and costs of compliance with COVID-19 vaccination or testing mandates, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate the business. If AEP is unable to successfully attract and retain an appropriately qualified workforce, future net income and cash flows may be reduced.

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.

244

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, 2021.

Item 5.  Other Information

None.

245

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:	

	

	

	
	
AEPTCo‡ File No. 333-217143			
					
4		Company Order and Officer’s Certificate between AEP Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A. as Trustee dated August 4, 2021 establishing terms of the 2.75% Senior Notes, Series N, due 2051		Form 8-K dated August 4, 2021 Exhibit 4(a)	

	

	
	
OPCo‡ File No.1-6543			
					
4		Company Order and Officer’s Certificate between Ohio Power Company and The Bank of New York Mellon Trust Company, N.A. as Trustee dated September 9, 2021 establishing terms of the 2.90% Senior Notes, Series R, due 2051		Form 8-K dated September 13, 2021 Exhibit 4(a)	
PSO‡   File No. 0-343			
					
4		Tenth Supplemental Indenture between Public Service Company of Oklahoma and The Bank of New York Mellon Trust Company, N.A. as Trustee dated August 1, 2021 establishing terms of the 2.20% Senior Notes, Series J, due 2031 and the 3.15% Senior Notes Series K, due 2051		Form 8-K dated August 12, 2021 Exhibit 4(a)	

	

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	
4		Company Order and Officer’s Certificate between American Electric Power Company, Inc. and The Bank of New York Mellon Trust Company, N.A. as Trustee dated August 3, 2021 establishing terms of the 1.80% Senior Notes, Series 2021A due 2028		X															
10		Stock Purchase Agreement by and among American Electric Power Company, Inc., AEP Transmission Company, LLC and Liberty Utilities Co. dated as of October 26, 2021		X				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	
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	
246

																																																									
Exhibit		Description		AEP		AEP
Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo	
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.	
247

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 28, 2021
248

August 3, 2021
Company Order and Officers’ Certificate

1.80% Senior Notes, Series 2021A due 2028

The Bank of New York Mellon Trust Company, N.A., as Trustee
2 North LaSalle Street, 7th Floor
Chicago, Illinois 60602

Ladies and Gentlemen:

Pursuant to Article Two of the Indenture, dated as of May 1, 2001 (as it may be amended or supplemented, the “Indenture”), from American Electric Power Company, Inc. (the “Company”) to The Bank of New York Mellon Trust Company, N.A., as successor to The Bank of New York, as trustee (the “Trustee”), and the Board Resolutions dated July 13, 2021, a copy of which, as certified by the Secretary or an Assistant Secretary of the Company, is being delivered herewith under Section 2.01 of the Indenture, and unless otherwise provided in a subsequent Company Order pursuant to Section 2.04 of the Indenture. Capitalized terms used herein for which no definition is provided herein shall have the meanings set forth in the Indenture.

1.The Company’s 1.80% Senior Notes, Series 2021A due 2028 (the “Notes”) are hereby established. The Notes shall be in substantially the forms attached hereto as Exhibit 1.
2.The terms and characteristics of the Notes shall be as follows (the numbered clauses set forth below corresponding to the numbered subsections of Section 2.01 of the Indenture, with terms used and not defined herein having the meanings specified in the Indenture or in the Notes):        
(i)    The aggregate principal amount of Notes which may be authenticated and delivered under the Indenture initially shall be limited to $175,000,000 for the Notes, except as contemplated in Section 2.01(i) of the Indenture and except that such principal amount may be increased from time to time; all Notes need not be issued at the same time and each such series may be reopened at any time, without the consent of any securityholder, for issuance of additional Notes, which Notes will have the same interest rate, maturity and other terms as those initially issued (other than the date of issuance, the issue price and, in some circumstances, the initial interest accrual date and initial interest payment date);
        
(ii)    The date on which the principal of the Notes shall be payable shall be August 1, 2028;
        
(iii)    Interest shall accrue from the date of issuance of the Notes; the Interest Payment Dates on which such interest will be payable for the Notes shall be February 1 and August 1, and the Regular Record Date for the determination of holders of the Notes to whom interest is payable on any such Interest Payment Date shall be the January 15 or July 15 preceding the relevant Interest Payment Date; provided that the first Interest Payment Date for the Notes shall be February 1, 2022 and interest payable on the Stated Maturity Date or any Redemption Date shall be paid to the Person to whom principal shall be paid;
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(iv)         The interest rate at which the Notes shall bear interest shall be 1.80% per annum.

(v)        The Notes may be redeemed by the Company at its option, in whole at any time or in part from time to time, upon not less than thirty but not more than sixty days’ prior notice delivered to the registered owners of the Notes. At any time prior to June 1, 2028 (the date that is two months prior to maturity (the “Par Call Date”)), the Notes may be redeemed either as a whole or in part at a redemption price calculated by the Independent Investment Banker equal to the greater of (1) 100% of the principal amount of the Notes being redeemed and (2) the sum of the present values of the remaining scheduled payments of principal and interest on the Notes being redeemed that would be due if such Notes matured on the Par Call Date (excluding the portion of any such interest accrued to but excluding the date of redemption) discounted (for purposes of determining present value) to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate (as defined below) plus 15 basis points, plus, in each case, accrued and unpaid interest thereon to but excluding the date of redemption. The Notes to be redeemed in whole or in part will be selected in a manner that complies with the requirements of the DTC.

At any time on or after the Par Call Date, the Company may redeem the Notes in whole or in part at 100% of the principal amount of the Notes being redeemed, plus accrued and unpaid interest thereon to but excluding the date of redemption, upon not less than thirty but not more than sixty days’ prior notice delivered to the registered owners of the Notes.

“Comparable Treasury Issue” means the United States Treasury security selected by an Independent Investment Banker as having a maturity comparable to the remaining term (“remaining life”) of the particular series of Notes to be redeemed (for Notes, assuming, for this purpose, that the Notes would mature on the Par Call Date) that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining life of the applicable series of Notes.

“Comparable Treasury Price” means, with respect to any redemption date, (1) the average of the Reference Treasury Dealer Quotations for such redemption date, after excluding the highest and lowest of such Reference Treasury Dealer Quotations, or (2) if the Company obtains fewer than four of such Reference Treasury Dealer Quotations, the average of all such quotations.

“Independent Investment Banker” means one of the Reference Treasury Dealers appointed by the Company and notified by the Company to the Trustee.

“Reference Treasury Dealer” means a primary U.S. Government securities dealer or dealers selected by the Company and notified by the Company to the Trustee.
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“Reference Treasury Dealer Quotations” means, with respect to each Reference Treasury Dealer and any redemption date, the average, as determined by the Company and notified to the Trustee, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the Company and the Trustee by such Reference Treasury Dealer at or before 3:30 p.m., New York City time, on the third Business Day preceding such redemption date.
    
“Treasury Rate” means, with respect to any redemption, the rate per annum equal to the semiannual equivalent yield to maturity of the Comparable Treasury Issue, calculated using a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such redemption date.
    
“Business Day” means any day that is not a day on which banking institutions in New York City are authorized or required by law or regulation to close.

(vi)	(a) the Notes shall be issued only as registered Global Securities, without coupons, in denominations of $2,000 and any integral multiples of $1,000 in excess thereof. The Notes initially will be represented by one or more Rule 144A Global Notes (as defined below) and Regulation S Global Notes (as defined below) (collectively, the “Global Notes”) registered in the name of The Depository Trust Company, as Depository or its nominee, or a successor depository or its nominee.

(b) The Notes offered and sold in reliance on Rule 144A shall be initially represented by one or more Global Notes (collectively, the “Rule 144A Global Notes”) will be deposited with the Trustee as custodian for the Depository and registered in the name of the Depository or its nominee. The Rule 144A Global Notes (and any notes issued in exchange for the Rule 144A Global Notes, other than Exchange Notes), including beneficial interests in the Rule 144A Global Notes, will be subject to certain restrictions on transfer set forth therein and in the Indenture.

(c) This section shall apply only to a Global Security deposited with or on behalf of the Depository. The Company shall execute and the Trustee shall, in accordance with this section, authenticate and deliver initially one or more Global Securities that (a) shall be registered in the name of the Depository for such Global Security or Global Securities or the nominee of such Depository and (b) shall be delivered by the Trustee to such Depository or pursuant to such Depository’s instructions or held by the Trustee as custodian for the Depository.

Members of, or participants in, the Depository (“Agent Members”) shall have no rights under the Indenture with respect to any Global Security held on their behalf by the Depository or by the Trustee as the custodian of the Depository or under such Global Security, and the Company, the Trustee and any agent of the Company or the Trustee shall be entitled to treat the Depository as the absolute owner of such Global Security for all purposes whatsoever. Notwithstanding the foregoing, nothing herein shall prevent the Company, the Trustee or any agent of the Company or the Trustee from giving effect to any written certification, proxy or other authorization furnished by the Depository or impair, as between the Depository and its Agent Members, the operation of customary	
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	practices of such Depository governing the exercise of the rights of a holder of a beneficial interest in any Global Security.

To the extent a notice or other communication to the beneficial owners of the Notes is required under the Indenture, unless and until Certificated Securities (as defined below) shall have been issued to such owners, the Trustee shall give all such notices and communications specified herein to be given to such owners to the Depository, and shall have no obligations to such owners.

Except as provided in this section, owners of beneficial interests in Global Securities shall not be entitled to receive physical delivery of Certificated Securities.

(d) Global Securities representing the Notes shall be exchangeable for certificated securities of such series, (“Certificated Securities)” if (i) the Depository (x) notifies the Company that it is unwilling or unable to continue as Depository for the Global Securities or (y) shall no longer be registered or in good standing under the Securities Exchange Act of 1934, as amended, or other applicable statute or regulation, and a successor Depository for the Global Securities is not appointed by the Company within 90 days after the Company receives such notice or becomes aware of such condition. Upon surrender to the Trustee of the typewritten certificate or certificates representing the Global Securities by the Depository, accompanied by registration instructions, the Trustee shall execute and authenticate the certificates in accordance with the instructions of the Depository. Neither the Company’s office or agency designated for such purpose in the Borough of Manhattan, the City and State of New York, or such other location designated by the Company a register or registers (the “Security Registrar”) nor the Trustee shall be liable for any delay in delivery of such instructions and may conclusively rely on, and shall be protected in relying on, such instructions. Upon the issuance of Certificated Securities, the Trustee shall recognize the Holders of the Certificated Securities as Holders. The Certificated Securities shall be printed, lithographed or engraved or may be produced in any other manner as is reasonably acceptable to the Company, as evidenced by the execution thereof by the Company, and shall bear the legend set forth on Exhibit 1 hereto unless the Company informs the Trustee that such legend is no longer required.	
		
(vii)	transfers and exchanges of Securities and beneficial interests in a Global Security of the kinds specified in this section shall be made only in accordance with this section.

(a) If, at any time, whether prior to or after the expiration of the holding period with respect to the Notes set forth in Rule 144(d) under the Securities Act of 1933, as amended (the “Securities Act”), an owner of a beneficial interest in a Rule 144A Global Note deposited with the Trustee, as custodian for the Depository, wishes to transfer its interest in such Rule 144A Global Note to a Person who is required or permitted to take delivery thereof in the form of an interest in a Regulation S Global Note, such owner shall, subject to the rules and procedures of the Depository for such Security, Euroclear Bank S.A./N.V. (“Euroclear”) and Clearstream Banking, S.A. (“Clearstream”), in each case to the extent applicable to such transaction and as in effect from time to time (the “Applicable Procedures”), exchange or cause the exchange of such interest for an equivalent beneficial	
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	interest in a Regulation S Global Note as provided in this section. Upon receipt by the Trustee of (1) written instructions given in accordance with the Applicable Procedures from an Agent Member directing the Trustee to credit or cause to be credited a beneficial interest in the Regulation S Global Note in an amount equal to the beneficial interest in the applicable Rule 144A Global Note to be exchanged, (2) a written order given in accordance with the Applicable Procedures containing information regarding the participant account of the Depository and the Euroclear or Clearstream account (if applicable) to be credited with such increase and (3) a certificate substantially in the form of Exhibit 2 hereto given by the owner of such beneficial interest, the Trustee, as Security Registrar, shall instruct the Depository to reduce or cause to be reduced the aggregate principal amount of the applicable Rule 144A Global Note and to increase or cause to be increased the aggregate principal amount of the applicable Regulation S Global Note by the principal amount of the beneficial interest in the Rule 144A Global Note to be exchanged, to credit or cause to be credited to the account of the Person specified in such instructions a beneficial interest in the Regulation S Global Note equal to the reduction in the aggregate principal amount of the applicable Rule 144A Global Note, and to debit, or cause to be debited, from the account of the Person making such exchange or transfer the beneficial interest in the Rule 144A Global Note that is being exchanged or transferred.
 
(b) If, at any time prior to the expiration of one year from the date of the acquisition of the Securities from the Company, an owner of a beneficial interest in a Regulation S Global Note deposited with the Trustee as custodian for the Depository wishes to transfer its interest in such Regulation S Global Note to a Person who is required or permitted to take delivery thereof in the form of an interest in a Rule 144A Global Note, such owner shall, subject to the Applicable Procedures, exchange or cause the exchange of such interest for an equivalent beneficial interest in a Rule 144A Global Note, as provided in this section. Upon receipt by the Trustee of (1) written instructions given in accordance with the Applicable Procedures from an Agent Member, directing the Trustee, as Security Registrar, to credit or cause to be credited a beneficial interest in the Rule 144A Global Note equal to the beneficial interest in the Regulation S Global Note to be exchanged; (2) a written order given in accordance with the Applicable Procedures containing information regarding the participant account of the Depository to be credited with such increase; and (3) a certificate substantially in the form of Exhibit 2 hereto given by the owner of such beneficial interest, the Trustee, as Security Registrar, shall instruct the Depository to reduce or cause to be reduced the aggregate principal amount of such Regulation S Global Note and to increase or cause to be increased the aggregate principal amount of the applicable Rule 144A Global Note by the principal amount of the beneficial interest in the Regulation S Global Note to be exchanged, and the Trustee, as Security Registrar, shall instruct the Depository, concurrently with such reduction, to credit or cause to be credited to the account of the Person specified in such instructions a beneficial interest in the applicable Rule 144A Global Note equal to the reduction in the aggregate principal amount of such Regulations S Global Note and to debit or cause to be debited from the account of the Person making such transfer the beneficial interest in the Regulation S Global Note that is being transferred.	
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	(c) Beneficial interests in a Rule 144A Global Note may be transferred to a Person who takes delivery in the form of an interest in such Rule 144A Global Note without any written certification from the transferor or the transferee, but the transferee will be deemed to make the representations set forth in Exhibit 2 hereto.
 
(d) Beneficial interests in a Regulation S Global Note may be transferred to a Person who takes delivery in the form of an interest in such Regulation S Global Note without any written certification from the transferor or the transferee; provided, however, that prior to the expiration of the Restricted Period, transfers of beneficial interests in the Regulation S Global Note may not be made to a U.S. Person or for the account or benefit of a U.S. Person (other than a distributor (as defined in Regulation S under the Securities Act)).
 
(e) In the event that a Global Security is exchanged for a Certificated Security as provided in this section, such Certificated Security may be exchanged or transferred for one another, subject to Section 2.05 of the Original Indenture, only in accordance with such procedures as are substantially consistent with the provisions of clauses (b)(i) and (ii) of this section and as may be from time to time reasonably adopted by the Company.
 
(f) Upon receipt by the Trustee of a Certificated Security, duly endorsed or accompanied by appropriate instruments of transfer, the Trustee shall cancel such Certificated Security and cause, or direct the Securities Custodian to cause, in accordance with the standing instructions and procedures existing of the Depository and the Securities Custodian, the aggregate principal amount of Notes represented by the Rule 144A Global Note or Regulation S Global Note, as applicable, to be increased by the aggregate principal amount of the Certificated Security to be exchanged and shall credit or cause to be credited to the account of the Person specified in such instructions a beneficial interest in the Rule 144A Global Note or Regulation S Global Note, as applicable, equal to the principal amount of the Certificated Security so canceled. If no Rule 144A Global Notes or Regulation S Global Notes, as applicable, are then outstanding, the Company shall issue and the Trustee shall authenticate, upon written order of the Company in the form of an Officers' Certificate, a new Rule 144A Global Note or Regulation S Global Note, as applicable, in the appropriate principal amount.	
		
(viii)	(a) the Notes shall be issued in the form of book-entry notes represented by Global Notes; (b) the Depositary for such Global Notes shall be The Depository Trust Company; and (c) the procedures with respect to transfer and exchange of Global Notes shall be as set forth in the forms of Note attached hereto;	
     		
(ix)	the title of the Notes shall be “1.80% Senior Notes, Series 2021A due 2028”;	
		
(x)	the forms of the Notes shall be as set forth in Paragraph 1, above;	
		
(xi)	not applicable;	
		
(xii)	the Notes shall not be subject to a Periodic Offering;	
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(xiii)	not applicable;	
		
(xiv)	not applicable;	
		
(xv)	Company will pay the principal of the Notes and any premium and interest payable at redemption, if any, or at maturity in immediately available funds at the office of The Bank of New York Mellon Trust Company, N.A., 2 North LaSalle Street, 7th Floor, Chicago, Illinois 60602;	
		
(xvi)	the Notes shall be issuable in denominations of $2,000 and any integral multiple of $1,000 in excess thereof;	
		
(xvii)	not applicable;	
		
(xviii)	the Notes shall not be issued as Discount Securities;	
		
(xix)	not applicable;	
		
(xx)	not applicable, and	
		
(xxi)	(A) Restrictive Covenants:	

Limitation upon Liens of Certain Subsidiaries

For so long as any Notes remain outstanding, the Company will not create or incur or allow any of its subsidiaries to create or incur any pledge or security interest on any of the capital stock of a Public Utility Subsidiary held by the Company or one of its subsidiaries or a Significant Subsidiary.

For purposes of this covenant:

(i)    Public Utility Subsidiary means, at any particular time, a direct or indirect subsidiary of the Company that, as a substantial part of its business, distributes or transmits electric energy to retail or wholesale customers at rates or tariffs that are regulated by either a state or Federal regulatory authority.

(ii)    Significant Subsidiary means, at any particular time, any direct subsidiary of the Company whose consolidated gross assets or consolidated gross revenues (having regard to the Company’s direct beneficial interest in the shares, or the like, of that subsidiary) represent at least 25% of the Company’s consolidated gross assets or consolidated gross revenues appearing in the most recent audited financial statements of the Company as of the date of determination.

Limitation upon Mergers, Consolidations and Sale of Assets

The provisions of Article Ten of the Indenture shall be applicable to the Notes.
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(B) Waivers:

Waiver of Replacement Capital Covenant

The Notes will not be entitled to benefit in any way from the Replacement Capital Covenant, dated as of March 1, 2008, entered into by the Company in favor of certain holders of the Company’s debt, and subsequently amended by an amendment dated as of February 29, 2012 (as amended, the “Replacement Capital Covenant”). The Notes are not, and will never become, Eligible Debt or Covered Debt (as such terms are defined in the Replacement Capital Covenant), and the holders of the Notes are not, and will never be entitled to become, Covered Debtholders (as defined in the Replacement Capital Covenant). Any person purchasing or otherwise acquiring a Note or any interest in the Notes will be deemed to have agreed to this waiver of the Replacement Capital Covenant.
    
(xx)    Certain Tax Information.

In order to comply with applicable tax laws (inclusive of rules, regulations and interpretations promulgated by competent authorities) related to the Indenture, this Company Order and Officers’ Certificate and the Notes in effect from time to time (“Applicable Law”) that a foreign financial institution, issuer, trustee, paying agent or other party is or has agreed to be subject to, the Company agrees (i) to provide to the Trustee and any paying agent sufficient information about the parties and/or transactions (including any modification to the terms of such transactions) so the Trustee and any paying agent can determine whether it has tax related obligations under Applicable Law and (ii) that the Trustee and any paying agent shall be entitled to make any withholding or deduction from payments to the extent necessary to comply with Applicable Law for which the Trustee and any paying agent shall not have any liability.

3.	You are hereby requested to authenticate on the date hereof $175,000,000 aggregate principal amount of 1.80% Senior Notes, Series 2021A due 2028, executed by the Company and delivered to you concurrently with this Company Order and Officers’ Certificate, in the manner provided by the Indenture, by manual, facsimile or electronic signature, provided that any such electronic signature is a true representation of the signatory’s actual signature.	
		
4.	You are hereby requested to hold the Global Notes as custodian for DTC in accordance with the Blanket Issuer Letter of Representations dated March 14, 2008, from the Company to DTC.	
		
5.	Concurrently with this Company Order and Officers’ Certificate, an Opinion of Counsel under Sections 2.04 and 13.06 of the Indenture is being delivered to you.	
		
6.	The undersigned Renee V. Hawkins and David C. House, the Assistant Treasurer and Assistant Secretary, respectively, of the Company do hereby certify that:	
    
(i)    we have read the relevant portions of the Indenture, including without limitation the conditions precedent provided for therein relating to the action proposed to be taken by the
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Trustee as requested in this Company Order and Officers’ Certificate, and the definitions in the Indenture relating thereto;
        
(ii)    we have read the Board Resolutions of the Company and the Opinion of Counsel referred to above;
        
(iii)    we have conferred with other officers of the Company, have examined such records of the Company and have made such other investigation as we deemed relevant for purposes of this certificate;
        
(iv)    in our opinion, we have made such examination or investigation as is necessary to enable us to express an informed opinion as to whether or not such conditions have been complied with; and
        
(v)    on the basis of the foregoing, we are of the opinion that all conditions precedent provided for in the Indenture relating to the action proposed to be taken by the Trustee as requested herein have been complied with.
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Kindly acknowledge receipt of this Company Order and Officers’ Certificate, including the documents listed herein, and confirm the arrangements set forth herein by signing and returning the copy of this document attached hereto.

IN WITNESS WHEREOF, the Company has caused this Instrument to be executed.

Very truly yours,

	
			
AMERICAN ELECTRIC POWER COMPANY, INC.	

By:	/s/ Renee V. Hawkins	 	
 	Name: Renee V. Hawkins
Title: Assistant Treasurer	

And:	/s/ David C. House	 	
 	Name: David C. House
Title: Assistant Secretary	

Acknowledged by Trustee:	
 	 	 	
THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A., as Trustee	

By:	/s/ Manjari Purkayastha	
 	     Authorized Signatory	
 	     Name: Manjari Purkayastha	
 	     Title: Vice President	

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Exhibit 1
[Rule 144A Global Security]
[Global Securities Legend]
THIS GLOBAL SECURITY IS HELD BY THE DEPOSITORY (AS DEFINED IN THE INDENTURE GOVERNING THIS SECURITY) OR ITS NOMINEE IN CUSTODY FOR THE BENEFIT OF THE BENEFICIAL OWNERS HEREOF, AND IS NOT TRANSFERABLE TO ANY PERSON UNDER ANY CIRCUMSTANCES EXCEPT THAT (I) THE REGISTRAR MAY MAKE SUCH NOTATIONS HEREON AS MAY BE REQUIRED PURSUANT TO SECTIONS 2.04 AND 2.05 OF THE INDENTURE, (II) THIS GLOBAL SECURITY MAY BE EXCHANGED IN WHOLE BUT NOT IN PART PURSUANT TO SECTION 2.05 OF THE INDENTURE AND (III) THIS GLOBAL SECURITY MAY BE DELIVERED TO THE TRUSTEE FOR CANCELLATION PURSUANT TO SECTION 2.08 OF THE INDENTURE.
UNLESS AND UNTIL IT IS EXCHANGED IN WHOLE OR IN PART FOR SECURITIES IN CERTIFICATED FORM, THIS SECURITY MAY NOT BE TRANSFERRED EXCEPT AS A WHOLE BY THE DEPOSITORY TO A NOMINEE OF THE DEPOSITORY OR BY A NOMINEE OF THE DEPOSITORY TO THE DEPOSITORY OR ANOTHER NOMINEE OF THE DEPOSITORY OR BY THE DEPOSITORY OR ANY SUCH NOMINEE TO A SUCCESSOR DEPOSITORY OR A NOMINEE OF SUCH SUCCESSOR DEPOSITORY. UNLESS THIS CERTIFICATE IS PRESENTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY TRUST COMPANY (55 WATER STREET, NEW YORK, NEW YORK) (“DTC”) TO THE COMPANY OR ITS AGENT FOR REGISTRATION OF TRANSFER, EXCHANGE OR PAYMENT, AND ANY CERTIFICATE ISSUED IS REGISTERED IN THE NAME OF CEDE & CO. OR SUCH OTHER NAME AS MAY BE REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF DTC (AND ANY PAYMENT IS MADE TO CEDE & CO. OR SUCH OTHER ENTITY AS MAY BE REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF DTC), ANY TRANSFER, PLEDGE OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY OR TO ANY PERSON IS WRONGFUL INASMUCH AS THE REGISTERED OWNER HEREOF, CEDE & CO., HAS AN INTEREST HEREIN.
[Restricted Securities Legend]
THIS SECURITY HAS NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933, AS AMENDED (THE “SECURITIES ACT”), OR ANY SECURITIES LAWS OF ANY STATE OR OTHER JURISDICTION. NEITHER THIS SECURITY NOR ANY INTEREST OR PARTICIPATION HEREIN MAY BE REOFFERED, SOLD, ASSIGNED, TRANSFERRED, PLEDGED, ENCUMBERED OR OTHERWISE DISPOSED OF IN THE ABSENCE OF SUCH REGISTRATION OR UNLESS SUCH TRANSACTION IS EXEMPT FROM, OR NOT SUBJECT TO, THE REGISTRATION REQUIREMENTS OF THE SECURITIES ACT.
THE HOLDER OF THIS SECURITY BY ITS ACCEPTANCE HEREOF (1) REPRESENTS THAT (A) IT IS A “QUALIFIED INSTITUTIONAL BUYER” (AS DEFINED
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IN RULE 144A UNDER THE SECURITIES ACT (“RULE 144A”)), OR (B) IT IS A NON-U.S. PERSON AND IS ACQUIRING THIS SECURITY IN AN OFFSHORE TRANSACTION WITHIN THE MEANING OF REGULATION S UNDER THE SECURITIES ACT, PURSUANT TO RULE 904 OF REGULATION S, AND (2) AGREES TO OFFER, SELL OR OTHERWISE TRANSFER SUCH SECURITY, PRIOR TO THE RESALE RESTRICTION TERMINATION DATE, ONLY (A) TO AMERICAN ELECTRIC POWER COMPANY, INC. OR ANY OF ITS SUBSIDIARIES (B) PURSUANT TO A REGISTRATION STATEMENT WHICH HAS BEEN DECLARED EFFECTIVE UNDER THE SECURITIES ACT, (C) FOR SO LONG AS THE SECURITIES ARE ELIGIBLE FOR RESALE PURSUANT TO RULE 144A, TO A PERSON IT REASONABLY BELIEVES IS A “QUALIFIED INSTITUTIONAL BUYER’ AS DEFINED IN RULE 144A THAT PURCHASES FOR ITS OWN ACCOUNT OR FOR THE ACCOUNT OF A QUALIFIED INSTITUTIONAL BUYER TO WHOM NOTICE IS GIVEN THAT THE TRANSFER IS BEING MADE IN RELIANCE ON RULE 144A, (D) PURSUANT TO OFFERS AND SALES TO NON-U.S. PERSONS THAT OCCUR OUTSIDE THE UNITED STATES WITHIN THE MEANING OF REGULATION S UNDER THE SECURITIES ACT, PURSUANT TO RULE 904 OF REGULATION S, OR (E) PURSUANT TO ANOTHER AVAILABLE EXEMPTION FROM THE REGISTRATION REQUIREMENTS OF THE SECURITIES ACT AND IN EACH CASE, THE SECURITIES LAWS OF ANY OTHER JURISDICTION, INCLUDING ANY STATE OF THE UNITED STATES SUBJECT TO THE COMPANY’S AND THE TRUSTEE’S RIGHT PRIOR TO ANY SUCH OFFER, SALE OR TRANSFER TO REQUIRE THE DELIVERY OF AN OPINION OF COUNSEL SATISFACTORY TO EACH OF THEM AND/OR A CERTIFICATE OF TRANSFER OR EXCHANGE IN THE FORM PRESCRIBED IN THE INDENTURE. THIS LEGEND WILL BE REMOVED UPON THE REQUEST OF THE HOLDER AFTER THE RESALE RESTRICTION TERMINATION DATE.
[ERISA Legend]
BY ITS ACQUISITION AND HOLDING OF THIS SECURITY THE HOLDER THEREOF WILL BE DEEMED TO HAVE REPRESENTED, WARRANTED AND AGREED THAT EITHER (I) IT IS NOT AND WILL NOT BE FOR SO LONG AS IT HOLDS ANY SECURITY (OR INTEREST IN A SECURITY) AN EMPLOYEE BENEFIT PLAN OR ARRANGEMENT SUBJECT TO TITLE I OF U.S. EMPLOYEE RETIREMENT INCOME SECURITY ACT OF 1974, AS AMENDED “ERISA”), A “PLAN” OR ARRANGEMENT SUBJECT TO SECTION 4975 OF THE U.S. INTERNAL REVENUE CODE OF 1986, AS AMENDED (THE “CODE”), OR AN ENTITY WHOSE UNDERLYING ASSETS INCLUDE PLAN ASSETS BY REASON OF SUCH EMPLOYEE BENEFIT PLAN OR PLAN’S INVESTMENT IN THE ENTITY, OR A GOVERNMENTAL, NON-U.S., CHURCH OR OTHER PLAN WHICH IS SUBJECT TO ANY FEDERAL, STATE, LOCAL, NON-U.S. OR OTHER LAWS OR REGULATIONS THAT ARE SUBSTANTIALLY SIMILAR TO SUCH PROVISIONS OF ERISA OR THE CODE (“SIMILAR LAWS”), OR (II) THE PURCHASE, HOLDING AND DISPOSITION OF THIS SECURITY WILL NOT CONSTITUTE A NONEXEMPT PROHIBITED TRANSACTION UNDER SECTION 406 OF ERISA OR SECTION 4975 OF THE CODE OR, IN THE CASE OF A GOVERNMENTAL, NON-U.S., CHURCH OR OTHER PLAN, A SIMILAR VIOLATION UNDER ANY APPLICABLE SIMILAR LAWS.
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AMERICAN ELECTRIC POWER COMPANY, INC.
1.80% Senior Notes, Series 2021A due 2028
CUSIP:        025537 AT8                Original Issue Date: August 3, 2021
ISIN:        US025537AT89        
Stated Maturity:        August 1, 2028             Interest Rate: 1.80%
Principal Amount:     $
Redeemable:        Yes    X        No
In Whole:        Yes    X        No
In Part:            Yes    X        No
AMERICAN ELECTRIC POWER COMPANY, INC., a corporation duly organized and existing under the laws of the State of New York (herein referred to as the “Company”, which term includes any successor corporation under the Indenture hereinafter referred to), for value received, hereby promises to pay to CEDE & CO. or registered assigns, the principal sum of            DOLLARS ($          ) on the Stated Maturity specified above (or upon earlier redemption); and to pay interest on said Principal Amount from the Original Issue Date specified above or from the most recent interest payment date (each such date, an “Interest Payment Date”) to which interest has been paid or duly provided for, semi-annually in arrears on February 1 and August 1 in each year, commencing on February 1, 2022, at the Interest Rate per annum specified above, until the Principal Amount shall have been paid or duly provided for. Interest shall be computed on the basis of a 360-day year of twelve 30-day months.
The interest so payable, and punctually paid or duly provided for, on any Interest Payment Date, as provided in the Indenture, as hereinafter defined, shall be paid to the Person in whose name this Note (or one or more Predecessor Securities) shall have been registered at the close of business on the Regular Record Date with respect to such Interest Payment Date, which shall be the January 15 or July 15 (whether or not a Business Day), as the case may be, immediately prior to such Interest Payment Date, provided that interest payable on the Stated Maturity or any redemption date shall be paid to the Person to whom principal is paid. Any such interest not so punctually paid or duly provided for shall forthwith cease to be payable to the Holder on such Regular Record Date and shall be paid as provided in said Indenture.
If any Interest Payment Date, any redemption date or Stated Maturity is not a Business Day, then payment of the amounts due on this Note on such date will be made on the next succeeding Business Day, and no interest shall accrue on such amounts for the period from and after such Interest Payment Date, redemption date or Stated Maturity, as the case may be, with the same force and effect as if made on such date. The principal of (and premium, if any) and the interest on this Note shall be payable at the office or agency of the Company maintained for that purpose in the Borough of Manhattan, the City of New York, New York, in any coin or currency of the United States of America which at the time of payment is legal tender for payment of public and private debts; provided, however, that payment of interest (other than interest payable on the Stated Maturity or any redemption date) may be made at the option of the
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Company by check mailed to the registered holder at such address as shall appear in the Security Register or by wire transfer to the account designated by the person entitled thereto.
This Note is one of a duly authorized series of Senior Notes of the Company (herein sometimes referred to as the “Notes”), specified in the Indenture, all issued or to be issued in one or more series under and pursuant to an Indenture dated as of May 1, 2001 duly executed and delivered between the Company and The Bank of New York Mellon Trust Company, N.A., a national banking association formed under the laws of the United States, as successor to The Bank of New York, as Trustee (herein referred to as the “Trustee”) (such Indenture, as originally executed and delivered and as thereafter supplemented and amended being hereinafter referred to as the “Indenture”), to which Indenture and all indentures supplemental thereto or Company Orders reference is hereby made for a description of the rights, limitations of rights, obligations, duties and immunities thereunder of the Trustee, the Company and the holders of the Notes. By the terms of the Indenture, the Notes are issuable in series which may vary as to amount, date of maturity, rate of interest and in other respects as in the Indenture provided. This Note is one of the series of Notes designated on the face hereof as 1.80% Senior Notes, Series 2021A due 2028 initially issued in the aggregate principal amount of $175,000,000.
This Note may be redeemed by the Company at its option, in whole at any time or in part from time to time, upon not less than thirty but not more than sixty days’ prior notice delivered to the registered owners of the Notes. At any time prior to June 1, 2028 (the date that is two months prior to maturity (the “Par Call Date”)), the Notes may be redeemed either as a whole or in part at a redemption price calculated by the Independent Investment Banker equal to the greater of (1) 100% of the principal amount of the Notes being redeemed and (2) the sum of the present values of the remaining scheduled payments of principal and interest on the Notes being redeemed that would be due if such Notes matured on the Par Call Date (excluding the portion of any such interest accrued to but excluding the date of redemption) discounted (for purposes of determining present value) to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate (as defined below) plus 15 basis points, plus, in each case, accrued and unpaid interest thereon to but excluding the date of redemption.
At any time on or after the Par Call Date, the Company may redeem this Note, in whole or in part, at 100% of the principal amount of the Notes being redeemed, plus accrued and unpaid interest thereon to but excluding the date of redemption.
“Comparable Treasury Issue,” means the United States Treasury security selected by an Independent Investment Banker as having a maturity comparable to the remaining term (“remaining life”) of the Notes (assuming, for this purpose, that the Notes would mature on the Par Call Date) that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining life of the Notes.
“Comparable Treasury Price” means, with respect to any redemption date, (1) the average of the Reference Treasury Dealer Quotations for such redemption date,
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after excluding the highest and lowest of such Reference Treasury Dealer Quotations, or (2) if the Company obtains fewer than four of such Reference Treasury Dealer Quotations, the average of all such quotations.
Independent Investment Banker” means one of the Reference Treasury Dealers appointed by the Company and notified by the Company to the Trustee.
“Reference Treasury Dealer” means a primary U.S. Government securities dealer or dealers selected by the Company and notified by the Company to the Trustee.
“Reference Treasury Dealer Quotations” means, with respect to each Reference Treasury Dealer and any redemption date, the average, as determined by the Company and notified to the Trustee, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the Company and the Trustee by such Reference Treasury Dealer at or before 3:30 p.m., New York City time, on the third Business Day preceding such redemption date.
“Treasury Rate” means, with respect to any redemption, the rate per annum equal to the semiannual equivalent yield to maturity of the Comparable Treasury Issue, calculated by using a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such redemption date.
The Company shall not be required to (i) issue, exchange or register the transfer of any Notes during a period beginning at the opening of business 15 days before the day of the mailing of a notice of redemption of less than all the outstanding Notes of the same series and ending at the close of business on the day of such mailing, nor (ii) register the transfer of or exchange of any Notes of any series or portions thereof called for redemption. This Global Note is exchangeable for Notes in definitive registered form only under certain limited circumstances set forth in the Indenture.
In the event of redemption of this Note in part only, a new Note or Notes of this series, of like tenor, for the unredeemed portion hereof will be issued in the name of the Holder hereof upon the surrender of this Note.
In case an Event of Default, as defined in the Indenture, shall have occurred and be continuing, the principal of all of the Notes may be declared, and upon such declaration shall become, due and payable, in the manner, with the effect and subject to the conditions provided in the Indenture.
The Indenture contains provisions for defeasance at any time of the entire indebtedness of this Note upon compliance by the Company with certain conditions set forth therein.
As described in the Company Order and Officers’ Certificate, the Company is subject to a covenant regarding making certain tax information available to the Trustee and, so
5

long as this Note is outstanding, the Company is subject to such other restrictive covenants and waivers as described therein.
The Indenture contains provisions permitting the Company and the Trustee, with the consent of the Holders of not less than a majority in aggregate principal amount of the Notes of each series affected at the time outstanding voting as one class, as defined in the Indenture, to execute supplemental indentures for the purpose of adding any provisions to or changing in any manner or eliminating any of the provisions of the Indenture or of any supplemental indenture or of modifying in any manner the rights of the Holders of the Notes; provided, however, that no such supplemental indenture shall (i) extend the fixed maturity of any Notes of any series, or reduce the principal amount thereof, or reduce the rate or extend the time of payment of interest thereon, or reduce any premium payable upon the redemption thereof, or reduce the amount of the principal of a Discount Security that would be due and payable upon a declaration of acceleration of the maturity thereof pursuant to the Indenture, without the consent of the holder of each Note then outstanding and affected; (ii) reduce the aforesaid percentage of Notes, the holders of which are required to consent to any such supplemental indenture, or reduce the percentage of Notes, the holders of which are required to waive any default and its consequences, without the consent of the holder of each Note then outstanding and affected thereby; or (iii) modify any provision of Section 6.01(c) of the Indenture (except to increase the percentage of principal amount of securities required to rescind and annul any declaration of amounts due and payable under the Notes), without the consent of the holder of each Note then outstanding and affected thereby. The Indenture also contains provisions permitting the Holders of a majority in aggregate principal amount of the Notes of any series at the time outstanding affected thereby, on behalf of the Holders of the Notes of such series, to waive any past default in the performance of any of the covenants contained in the Indenture, or established pursuant to the Indenture with respect to such series, and its consequences, except a default in the payment of the principal of or premium, if any, or interest on any of the Notes of such series. Any such consent or waiver by the registered Holder of this Note (unless revoked as provided in the Indenture) shall be conclusive and binding upon such Holder and upon all future Holders and owners of this Note and of any Note issued in exchange herefor or in place hereof (whether by registration of transfer or otherwise), irrespective of whether or not any notation of such consent or waiver is made upon this Note.
No reference herein to the Indenture and no provision of this Note or of the Indenture shall alter or impair the obligation of the Company, which is absolute and unconditional, to pay the principal of and premium, if any, and interest on this Note at the time and place and at the rate and in the money herein prescribed.
As provided in the Indenture and subject to certain limitations therein set forth, this Note is transferable by the registered holder hereof on the Security Register of the Company, upon surrender of this Note for registration of transfer at the office or agency of the Company as may be designated by the Company accompanied by a written instrument or instruments of transfer in form satisfactory to the Company or the Trustee duly executed by the registered Holder hereof or his or her attorney duly authorized in writing, and thereupon one or more new Notes of authorized denominations and for the same aggregate principal amount and series will be issued to the designated transferee or transferees. No service charge will be made for any such
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transfer, but the Company may require payment of a sum sufficient to cover any tax or other governmental charge payable in relation thereto.
Prior to due presentment for registration of transfer of this Note, the Company, the Trustee, any paying agent and any Security Registrar may deem and treat the registered Holder hereof as the absolute owner hereof (whether or not this Note shall be overdue and notwithstanding any notice of ownership or writing hereon made by anyone other than the Security Registrar) for the purpose of receiving payment of or on account of the principal hereof and premium, if any, and interest due hereon and for all other purposes, and neither the Company nor the Trustee nor any paying agent nor any Security Registrar shall be affected by any notice to the contrary.
No recourse shall be had for the payment of the principal of or the interest on this Note, or for any claim based hereon, or otherwise in respect hereof, or based on or in respect of the Indenture, against any incorporator, stockholder, officer or director, past, present or future, as such, of the Company or of any predecessor or successor corporation, whether by virtue of any constitution, statute or rule of law, or by the enforcement of any assessment or penalty otherwise, all such liability being, by the acceptance hereof and as part of the consideration for the issuance hereof expressly waived and released.
The Notes of this series are issuable only in registered form without coupons in denominations of $2,000 and integral multiples of $1,000 in excess thereof. As provided in the Indenture and subject to certain limitations. Notes of this series are exchangeable for a like aggregate principal amount of Notes of this series of a different authorized denomination, as requested by the Holder surrendering the same.
All terms used in this Note which are defined in the Indenture shall have the meanings assigned to them in the Indenture.
This Note shall not be entitled to any benefit under the Indenture hereinafter referred to, be valid or become obligatory for any purpose until the Certificate of Authentication hereon shall have been signed by or on behalf of the Trustee by manual, facsimile, or electronic signature, provided that the electronic signature is a true representation of the signatory’s actual signature.
IN WITNESS WHEREOF, the Company has caused this Instrument to be executed.
AMERICAN ELECTRIC POWER COMPANY, INC.
By: __________________________________________
Renee V. Hawkins
Assistant Treasurer

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CERTIFICATE OF AUTHENTICATION
This is one of the Notes referred to in the within-mentioned indenture.
THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A.,
as Trustee
Dated:_____________________        By: _____________________________________
Authorized Signatory

8

ABBREVIATIONS
The following abbreviations, when used in the inscription on the face of this instrument, shall be construed as though they were written out in full according to applicable laws or regulations:

TEN COM-
TEN ENT-
JT TEN-	As tenants in common
As tenants by the entireties
As joint tenants with right of survivorship and not as tenants in common		UNIF GIFT MIN ACT-	_____ Custodian _____
(Cust)    (Minor)
Under Uniform Gifts to Minors Act
_______________________
(State)	

Additional abbreviations may also be used
though not on the above list.
FOR VALUE RECEIVED, the undersigned hereby sell(s) and transfer(s) unto _______________ (please insert Social Security or other identifying number of assignee)
_____________________________________________________________________________________
PLEASE PRINT OR TYPEWRITE NAME AND ADDRESS, INCLUDING POSTAL ZIP CODE OF ASSIGNEE
_____________________________________________________________________________________
_____________________________________________________________________________________
the within Note and all rights thereunder, hereby irrevocably constituting and appointing
_____________________________________________________________________________________
agent to transfer said Note on the books of the Company, with full power of substitution in the premises.
Dated:_________ _____________________________________________________________________
_____________________________________________________________________________________

NOTICE: The signature to this assignment must correspond with the name as written upon the face of the within instrument in every particular without alteration or enlargement, or any change whatever.

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In connection with any transfer of any of the Note evidenced by this certificate, the undersigned confirms that such Note is being:
CHECK ONE BOX BELOW

(1)	󠄀☐	exchanged for the undersigned’s own account without transfer; or	
(2)	󠄀☐	transferred to a person whom the undersigned reasonably believes to be a “qualified institutional buyer” as defined in Rule 144A under the Securities Act of 1933 who is purchasing such Notes for such buyer’s own account or the account of a “qualified institutional buyer” in a transaction meeting the requirements of Rule 144A under the Securities Act of 1933 and any applicable securities laws of any state of the United States or any other jurisdiction; or	
(3)	󠄀☐	exchanged or transferred pursuant to and in compliance with Rule 903 or 904 of Regulation S under the Securities Act of 1933; or	
(4)	󠄀☐	transferred to the Company or an “affiliate” (as defined in Rule 144 under the Securities Act) of the Company; or; or	
(5)	󠄀☐	transferred pursuant to another available exemption from the registration requirements of the Securities Act of 1933.	

Unless one of the boxes is checked, the Trustee will refuse to register any Note evidenced by this certificate in the name of any person other than the registered Holder thereof; provided, however, that if box (3), (4) or (5) is checked the Company may require, prior to registering any such transfer of this Note, such legal opinions, certifications and other information as the Company has reasonably requested to confirm that such transfer is being made pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act of 1933, such as the exemption provided by Rule 144 under such Act; provided, further, that if box (2) is checked, the transferee must also certify that it is a qualified institutional buyer as defined in Rule 144A.
_______________________________________
Signature
________________________________________
SIGNATURE GUARANTEE
Date: _________________________
Signatures must be guaranteed by an “eligible guarantor institution” meeting the requirements of the Security Registrar, which requirements include membership or participation in the Security Transfer Agent Medallion Program (“STAMP”) or such other “signature guarantee program” as may be determined by the Security Registrar in addition to, or in substitution for, STAMP, all in accordance with the Securities Exchange Act of 1934, as amended.
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TO BE COMPLETED BY PURCHASER IF (2) ABOVE IS CHECKED.
The undersigned represents and warrants that it is purchasing this Note for its own account or an account with respect to which it exercises sole investment discretion and that it and any such account is a “qualified institutional buyer” within the meaning of Rule 144A under the Securities Act of 1933, as amended, and is aware that the sale to it is being made in reliance on Rule 144A and acknowledges that it has received such information regarding the Company as the undersigned has requested pursuant to Rule 144A or has determined not to request such information and that it is aware that the transferor is relying upon the undersigned’s foregoing representations in order to claim the exemption from registration provided by Rule 144A.
_____________________________________
SIGNATURE GUARANTEE
Date: _________________________
Signatures must be guaranteed by an “eligible guarantor institution’’ meeting the requirements of the Security Registrar, which requirements include membership or participation in the Security Transfer Agent Medallion Program (“STAMP”) or such other “signature guarantee program” as may be determined by the Security Registrar in addition to, or in substitution for, STAMP, all accordance with the Securities Exchange Act of 1934, as amended.
NOTICE: To be executed by an executive officer.

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SCHEDULE A
The initial aggregate principal amount of the Note evidenced by the Certificate to which this Schedule is attached is $          . The notations on the following table evidence decreases and increases in the aggregate principal amount of the Note evidenced by such Certificate.

Decrease in Principal Amount of the Note	Increase in Principal Amount of the Note	Principal Amount of the Note Remaining After Such Decrease or
Increase	Notation by Security Registrar	

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[Regulation S Global Security]
[Global Securities Legend]
THIS GLOBAL SECURITY IS HELD BY THE DEPOSITORY (AS DEFINED IN THE INDENTURE GOVERNING THIS SECURITY) OR ITS NOMINEE IN CUSTODY FOR THE BENEFIT OF THE BENEFICIAL OWNERS HEREOF, AND IS NOT TRANSFERABLE TO ANY PERSON UNDER ANY CIRCUMSTANCES EXCEPT THAT (I) THE REGISTRAR MAY MAKE SUCH NOTATIONS HEREON AS MAY BE REQUIRED PURSUANT TO SECTIONS 2.04 AND 2.05 OF THE INDENTURE, (II) THIS GLOBAL SECURITY MAY BE EXCHANGED IN WHOLE BUT NOT IN PART PURSUANT TO SECTION 2.05 OF THE INDENTURE AND (III) THIS GLOBAL SECURITY MAY BE DELIVERED TO THE TRUSTEE FOR CANCELLATION PURSUANT TO SECTION 2.08 OF THE INDENTURE.
UNLESS AND UNTIL IT IS EXCHANGED IN WHOLE OR IN PART FOR SECURITIES IN CERTIFICATED FORM, THIS SECURITY MAY NOT BE TRANSFERRED EXCEPT AS A WHOLE BY THE DEPOSITORY TO A NOMINEE OF THE DEPOSITORY OR BY A NOMINEE OF THE DEPOSITORY TO THE DEPOSITORY OR ANOTHER NOMINEE OF THE DEPOSITORY OR BY THE DEPOSITORY OR ANY SUCH NOMINEE TO A SUCCESSOR DEPOSITORY OR A NOMINEE OF SUCH SUCCESSOR DEPOSITORY. UNLESS THIS CERTIFICATE IS PRESENTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY TRUST COMPANY (55 WATER STREET, NEW YORK, NEW YORK) (“DTC”) TO THE COMPANY OR ITS AGENT FOR REGISTRATION OF TRANSFER, EXCHANGE OR PAYMENT, AND ANY CERTIFICATE ISSUED IS REGISTERED IN THE NAME OF CEDE & CO. OR SUCH OTHER NAME AS MAY BE REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF DTC (AND ANY PAYMENT IS MADE TO CEDE & CO. OR SUCH OTHER ENTITY AS MAY BE REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF DTC), ANY TRANSFER, PLEDGE OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY OR TO ANY PERSON IS WRONGFUL INASMUCH AS THE REGISTERED OWNER HEREOF, CEDE & CO., HAS AN INTEREST HEREIN.
[Restricted Securities Legend]
THIS SECURITY HAS NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933, AS AMENDED (THE “SECURITIES ACT”), OR ANY SECURITIES LAWS OF ANY STATE OR OTHER JURISDICTION. NEITHER THIS SECURITY NOR ANY INTEREST OR PARTICIPATION HEREIN MAY BE REOFFERED, SOLD, ASSIGNED, TRANSFERRED, PLEDGED, ENCUMBERED OR OTHERWISE DISPOSED OF IN THE ABSENCE OF SUCH REGISTRATION OR UNLESS SUCH TRANSACTION IS EXEMPT FROM, OR NOT SUBJECT TO, THE REGISTRATION REQUIREMENTS OF THE SECURITIES ACT.
THE HOLDER OF THIS SECURITY BY ITS ACCEPTANCE HEREOF (1) REPRESENTS THAT (A) IT IS A “QUALIFIED INSTITUTIONAL BUYER” (AS DEFINED IN RULE 144A UNDER THE SECURITIES ACT (“RULE 144A”)), OR (B) IT IS A NON-U.S.
13

PERSON AND IS ACQUIRING THIS SECURITY IN AN OFFSHORE TRANSACTION WITHIN THE MEANING OF REGULATION S UNDER THE SECURITIES ACT, PURSUANT TO RULE 904 OF REGULATION S, AND (2) AGREES TO OFFER, SELL OR OTHERWISE TRANSFER SUCH SECURITY, PRIOR TO THE RESALE RESTRICTION TERMINATION DATE, ONLY (A) TO AMERICAN ELECTRIC POWER COMPANY, INC. OR ANY OF ITS SUBSIDIARIES (B) PURSUANT TO A REGISTRATION STATEMENT WHICH HAS BEEN DECLARED EFFECTIVE UNDER THE SECURITIES ACT, (C) FOR SO LONG AS THE SECURITIES ARE ELIGIBLE FOR RESALE PURSUANT TO RULE 144A, TO A PERSON IT REASONABLY BELIEVES IS A “QUALIFIED INSTITUTIONAL BUYER’ AS DEFINED IN RULE144A THAT PURCHASES FOR ITS OWN ACCOUNT OR FOR THE ACCOUNT OF A QUALIFIED INSTITUTIONAL BUYER TO WHOM NOTICE IS GIVEN THAT THE TRANSFER IS BEING MADE IN RELIANCE ON RULE 144A, (D) PURSUANT TO OFFERS AND SALES TO NON-U.S. PERSONS THAT OCCUR OUTSIDE THE UNITED STATES WITHIN THE MEANING OF REGULATION S UNDER THE SECURITIES ACT, PURSUANT TO RULE 904 OF REGULATION S, OR (E) PURSUANT TO ANOTHER AVAILABLE EXEMPTION FROM THE REGISTRATION REQUIREMENTS OF THE SECURITIES ACT AND IN EACH CASE, THE SECURITIES LAWS OF ANY OTHER JURISDICTION, INCLUDING ANY STATE OF THE UNITED STATES SUBJECT TO THE COMPANY’S AND THE TRUSTEE’S RIGHT PRIOR TO ANY SUCH OFFER, SALE OR TRANSFER TO REQUIRE THE DELIVERY OF AN OPINION OF COUNSEL SATISFACTORY TO EACH OF THEM AND/OR A CERTIFICATE OF TRANSFER OR EXCHANGE IN THE FORM PRESCRIBED IN THE INDENTURE. THIS LEGEND WILL BE REMOVED UPON THE REQUEST OF THE HOLDER AFTER THE RESALE RESTRICTION TERMINATION DATE.
[ERISA Legend]
BY ITS ACQUISITION AND HOLDING OF THIS SECURITY THE HOLDER THEREOF WILL BE DEEMED TO HAVE REPRESENTED, WARRANTED AND AGREED THAT EITHER (I) IT IS NOT AND WILL NOT BE FOR SO LONG AS IT HOLDS ANY SECURITY (OR INTEREST IN A SECURITY) AN EMPLOYEE BENEFIT PLAN OR ARRANGEMENT SUBJECT TO TITLE I OF U.S. EMPLOYEE RETIREMENT INCOME SECURITY ACT OF 1974, AS AMENDED “ERISA”), A “PLAN” OR ARRANGEMENT SUBJECT TO SECTION 4975 OF THE U.S. INTERNAL REVENUE CODE OF 1986, AS AMENDED (THE “CODE”), OR AN ENTITY WHOSE UNDERLYING ASSETS INCLUDE PLAN ASSETS BY REASON OF SUCH EMPLOYEE BENEFIT PLAN OR PLAN’S INVESTMENT IN THE ENTITY, OR A GOVERNMENTAL, NON-U.S., CHURCH OR OTHER PLAN WHICH IS SUBJECT TO ANY FEDERAL, STATE, LOCAL, NON-U.S. OR OTHER LAWS OR REGULATIONS THAT ARE SUBSTANTIALLY SIMILAR TO SUCH PROVISIONS OF ERISA OR THE CODE (“SIMILAR LAWS”), OR (II) THE PURCHASE, HOLDING AND DISPOSITION OF THIS SECURITY WILL NOT CONSTITUTE A NONEXEMPT PROHIBITED TRANSACTION UNDER SECTION 406 OF ERISA OR SECTION 4975 OF THE CODE OR, IN THE CASE OF A GOVERNMENTAL, NON-U.S., CHURCH OR OTHER PLAN, A SIMILAR VIOLATION UNDER ANY APPLICABLE SIMILAR LAWS.
14

[Temporary Regulation S Global Security Legend]
THE RIGHTS ATTACHING TO THIS REGULATION S TEMPORARY GLOBAL SECURITY, AND THE CONDITIONS AND PROCEDURES GOVERNING ITS EXCHANGE FOR A REGULATION S PERMANENT GLOBAL SECURITY, ARE AS SPECIFIED IN THE INDENTURE (AS DEFINED HEREIN). NEITHER THE HOLDER NOR THE BENEFICIAL OWNERS OF THIS REGULATION S TEMPORARY GLOBAL SECURITY SHALL BE ENTITLED TO RECEIVE PAYMENT OF INTEREST HEREON.

15

AMERICAN ELECTRIC POWER COMPANY, INC.
1.80% Senior Notes, Series 2021A due 2028
CUSIP:        UO2566 AA2                Original Issue Date: August 3, 2021
ISIN:        USUO2566AA29    
Stated Maturity:        August 1, 2028             Interest Rate: 1.80%
Principal Amount:     $
Redeemable:        Yes    X        No
In Whole:         Yes    X        No
In Part:             Yes    X        No
AMERICAN ELECTRIC POWER COMPANY, INC., a corporation duly organized and existing under the laws of the State of New York (herein referred to as the “Company”, which term includes any successor corporation under the Indenture hereinafter referred to), for value received, hereby promises to pay to CEDE & CO. or registered assigns, the principal sum of            DOLLARS ($          ) on the Stated Maturity specified above (or upon earlier redemption); and to pay interest on said Principal Amount from the Original Issue Date specified above or from the most recent interest payment date (each such date, an “Interest Payment Date”) to which interest has been paid or duly provided for, semi-annually in arrears on February 1 and August 1 in each year, commencing on February 1, 2022, at the Interest Rate per annum specified above, until the Principal Amount shall have been paid or duly provided for. Interest shall be computed on the basis of a 360-day year of twelve 30-day months.
The interest so payable, and punctually paid or duly provided for, on any Interest Payment Date, as provided in the Indenture, as hereinafter defined, shall be paid to the Person in whose name this Note (or one or more Predecessor Securities) shall have been registered at the close of business on the Regular Record Date with respect to such Interest Payment Date, which shall be the January 15 or July 15 (whether or not a Business Day), as the case may be, immediately prior to such Interest Payment Date, provided that interest payable on the Stated Maturity or any redemption date shall be paid to the Person to whom principal is paid. Any such interest not so punctually paid or duly provided for shall forthwith cease to be payable to the Holder on such Regular Record Date and shall be paid as provided in said Indenture.
If any Interest Payment Date, any redemption date or Stated Maturity is not a Business Day, then payment of the amounts due on this Note on such date will be made on the next succeeding Business Day, and no interest shall accrue on such amounts for the period from and after such Interest Payment Date, redemption date or Stated Maturity, as the case may be, with the same force and effect as if made on such date. The principal of (and premium, if any) and the interest on this Note shall be payable at the office or agency of the Company maintained for that purpose in the Borough of Manhattan, the City of New York, New York, in any coin or currency of the United States of America which at the time of payment is legal tender for payment of public and private debts; provided, however, that payment of interest (other than interest payable on the Stated Maturity or any redemption date) may be made at the option of the
16

Company by check mailed to the registered holder at such address as shall appear in the Security Register or by wire transfer to the account designated by the person entitled thereto.
This Note is one of a duly authorized series of Senior Notes of the Company (herein sometimes referred to as the “Notes”), specified in the Indenture, all issued or to be issued in one or more series under and pursuant to an Indenture dated as of May 1, 2001 duly executed and delivered between the Company and The Bank of New York Mellon Trust Company, N.A., a national banking association formed under the laws of the United States, as successor to The Bank of New York, as Trustee (herein referred to as the “Trustee”) (such Indenture, as originally executed and delivered and as thereafter supplemented and amended being hereinafter referred to as the “Indenture”), to which Indenture and all indentures supplemental thereto or Company Orders reference is hereby made for a description of the rights, limitations of rights, obligations, duties and immunities thereunder of the Trustee, the Company and the holders of the Notes. By the terms of the Indenture, the Notes are issuable in series which may vary as to amount, date of maturity, rate of interest and in other respects as in the Indenture provided. This Note is one of the series of Notes designated on the face hereof as 1.80% Senior Notes, Series 2021A due 2028 initially issued in the aggregate principal amount of $175,000,000.
This Note may be redeemed by the Company at its option, in whole at any time or in part from time to time, upon not less than thirty but not more than sixty days’ prior notice delivered to the registered owners of the Notes. At any time prior to June 1, 2028 (the date that is two months prior to maturity (the “Par Call Date”)), the Notes may be redeemed either as a whole or in part at a redemption price calculated by the Independent Investment Banker equal to the greater of (1) 100% of the principal amount of the Notes being redeemed and (2) the sum of the present values of the remaining scheduled payments of principal and interest on the Notes being redeemed that would be due if such Notes matured on the Par Call Date (excluding the portion of any such interest accrued to but excluding the date of redemption) discounted (for purposes of determining present value) to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate (as defined below) plus 15 basis points, plus, in each case, accrued and unpaid interest thereon to but excluding the date of redemption.
At any time on or after the Par Call Date, the Company may redeem this Note in whole or in part, at 100% of the principal amount of the Notes being redeemed, plus accrued and unpaid interest thereon to but excluding the date of redemption.
“Comparable Treasury Issue,” means the United States Treasury security selected by an Independent Investment Banker as having a maturity comparable to the remaining term (“remaining life”) of the Notes (assuming, for this purpose, that the Notes would mature on the Par Call Date) that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining life of the Notes.
“Comparable Treasury Price” means, with respect to any redemption date, (1) the average of the Reference Treasury Dealer Quotations for such redemption date,
17

after excluding the highest and lowest of such Reference Treasury Dealer Quotations, or (2) if the Company obtains fewer than four of such Reference Treasury Dealer Quotations, the average of all such quotations.
Independent Investment Banker” means one of the Reference Treasury Dealers appointed by the Company and notified by the Company to the Trustee.
“Reference Treasury Dealer” means a primary U.S. Government securities dealer or dealers selected by the Company and notified by the Company to the Trustee.
“Reference Treasury Dealer Quotations” means, with respect to each Reference Treasury Dealer and any redemption date, the average, as determined by the Company and notified to the Trustee, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the Company and the Trustee by such Reference Treasury Dealer at or before 3:30 p.m., New York City time, on the third Business Day preceding such redemption date.
“Treasury Rate” means, with respect to any redemption, the rate per annum equal to the semiannual equivalent yield to maturity of the Comparable Treasury Issue, calculated by using a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such redemption date.
The Company shall not be required to (i) issue, exchange or register the transfer of any Notes during a period beginning at the opening of business 15 days before the day of the mailing of a notice of redemption of less than all the outstanding Notes of the same series and ending at the close of business on the day of such mailing, nor (ii) register the transfer of or exchange of any Notes of any series or portions thereof called for redemption. This Global Note is exchangeable for Notes in definitive registered form only under certain limited circumstances set forth in the Indenture.
In the event of redemption of this Note in part only, a new Note or Notes of this series, of like tenor, for the unredeemed portion hereof will be issued in the name of the Holder hereof upon the surrender of this Note.
In case an Event of Default, as defined in the Indenture, shall have occurred and be continuing, the principal of all of the Notes may be declared, and upon such declaration shall become, due and payable, in the manner, with the effect and subject to the conditions provided in the Indenture.
The Indenture contains provisions for defeasance at any time of the entire indebtedness of this Note upon compliance by the Company with certain conditions set forth therein.
As described in the Company Order and Officers’ Certificate, the Company is subject to a covenant regarding making certain tax information available to the Trustee and, so
18

long as this Note is outstanding, the Company is subject to such other restrictive covenants and waivers as described therein.
The Indenture contains provisions permitting the Company and the Trustee, with the consent of the Holders of not less than a majority in aggregate principal amount of the Notes of each series affected at the time outstanding voting as one class, as defined in the Indenture, to execute supplemental indentures for the purpose of adding any provisions to or changing in any manner or eliminating any of the provisions of the Indenture or of any supplemental indenture or of modifying in any manner the rights of the Holders of the Notes; provided, however, that no such supplemental indenture shall (i) extend the fixed maturity of any Notes of any series, or reduce the principal amount thereof, or reduce the rate or extend the time of payment of interest thereon, or reduce any premium payable upon the redemption thereof, or reduce the amount of the principal of a Discount Security that would be due and payable upon a declaration of acceleration of the maturity thereof pursuant to the Indenture, without the consent of the holder of each Note then outstanding and affected; (ii) reduce the aforesaid percentage of Notes, the holders of which are required to consent to any such supplemental indenture, or reduce the percentage of Notes, the holders of which are required to waive any default and its consequences, without the consent of the holder of each Note then outstanding and affected thereby; or (iii) modify any provision of Section 6.01(c) of the Indenture (except to increase the percentage of principal amount of securities required to rescind and annul any declaration of amounts due and payable under the Notes), without the consent of the holder of each Note then outstanding and affected thereby. The Indenture also contains provisions permitting the Holders of a majority in aggregate principal amount of the Notes of any series at the time outstanding affected thereby, on behalf of the Holders of the Notes of such series, to waive any past default in the performance of any of the covenants contained in the Indenture, or established pursuant to the Indenture with respect to such series, and its consequences, except a default in the payment of the principal of or premium, if any, or interest on any of the Notes of such series. Any such consent or waiver by the registered Holder of this Note (unless revoked as provided in the Indenture) shall be conclusive and binding upon such Holder and upon all future Holders and owners of this Note and of any Note issued in exchange herefor or in place hereof (whether by registration of transfer or otherwise), irrespective of whether or not any notation of such consent or waiver is made upon this Note.
No reference herein to the Indenture and no provision of this Note or of the Indenture shall alter or impair the obligation of the Company, which is absolute and unconditional, to pay the principal of and premium, if any, and interest on this Note at the time and place and at the rate and in the money herein prescribed.
As provided in the Indenture and subject to certain limitations therein set forth, this Note is transferable by the registered holder hereof on the Security Register of the Company, upon surrender of this Note for registration of transfer at the office or agency of the Company as may be designated by the Company accompanied by a written instrument or instruments of transfer in form satisfactory to the Company or the Trustee duly executed by the registered Holder hereof or his or her attorney duly authorized in writing, and thereupon one or more new Notes of authorized denominations and for the same aggregate principal amount and series will be issued to the designated transferee or transferees. No service charge will be made for any such
19

transfer, but the Company may require payment of a sum sufficient to cover any tax or other governmental charge payable in relation thereto.
Prior to due presentment for registration of transfer of this Note, the Company, the Trustee, any paying agent and any Security Registrar may deem and treat the registered Holder hereof as the absolute owner hereof (whether or not this Note shall be overdue and notwithstanding any notice of ownership or writing hereon made by anyone other than the Security Registrar) for the purpose of receiving payment of or on account of the principal hereof and premium, if any, and interest due hereon and for all other purposes, and neither the Company nor the Trustee nor any paying agent nor any Security Registrar shall be affected by any notice to the contrary.
No recourse shall be had for the payment of the principal of or the interest on this Note, or for any claim based hereon, or otherwise in respect hereof, or based on or in respect of the Indenture, against any incorporator, stockholder, officer or director, past, present or future, as such, of the Company or of any predecessor or successor corporation, whether by virtue of any constitution, statute or rule of law, or by the enforcement of any assessment or penalty otherwise, all such liability being, by the acceptance hereof and as part of the consideration for the issuance hereof expressly waived and released.
The Notes of this series are issuable only in registered form without coupons in denominations of $2,000 and integral multiples of $1,000 in excess thereof. As provided in the Indenture and subject to certain limitations. Notes of this series are exchangeable for a like aggregate principal amount of Notes of this series of a different authorized denomination, as requested by the Holder surrendering the same.
All terms used in this Note which are defined in the Indenture shall have the meanings assigned to them in the Indenture.
This Note shall not be entitled to any benefit under the Indenture hereinafter referred to, be valid or become obligatory for any purpose until the Certificate of Authentication hereon shall have been signed by or on behalf of the Trustee by manual, facsimile, or electronic signature, provided that the electronic signature is a true representation of the signatory’s actual signature.
IN WITNESS WHEREOF, the Company has caused this Instrument to be executed.
AMERICAN ELECTRIC POWER COMPANY, INC.
By: __________________________________________
Renee V. Hawkins
Assistant Treasurer

20

CERTIFICATE OF AUTHENTICATION
This is one of the Notes referred to in the within-mentioned indenture.
THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A.,
as Trustee
Dated: __________________            By: ____________________________________
Authorized Signatory

21

ABBREVIATIONS
The following abbreviations, when used in the inscription on the face of this instrument, shall be construed as though they were written out in full according to applicable laws or regulations:

TEN COM-
TEN ENT-
JT TEN-	As tenants in common
As tenants by the entireties
As joint tenants with right of survivorship and not as tenants in common		UNIF GIFT MIN ACT-	_____ Custodian _____
(Cust)    (Minor)
Under Uniform Gifts to Minors Act
_______________________
(State)	

Additional abbreviations may also be used
though not on the above list.
FOR VALUE RECEIVED, the undersigned hereby sell(s) and transfer(s) unto _______________ (please insert Social Security or other identifying number of assignee)
_____________________________________________________________________________________
PLEASE PRINT OR TYPEWRITE NAME AND ADDRESS, INCLUDING POSTAL ZIP CODE OF ASSIGNEE
_____________________________________________________________________________________
_____________________________________________________________________________________
the within Note and all rights thereunder, hereby irrevocably constituting and appointing
_____________________________________________________________________________________
agent to transfer said Note on the books of the Company, with full power of substitution in the premises.
Dated: __________ __________________________________________________________________
_____________________________________________________________________________________
NOTICE: The signature to this assignment must correspond with the name as written upon the face of the within instrument in every particular without alteration or enlargement, or any change whatever.

22

In connection with any transfer of any of the Note evidenced by this certificate, the undersigned confirms that such Note is being:
CHECK ONE BOX BELOW

(1)	󠄀☐	exchanged for the undersigned’s own account without transfer; or	
(2)	󠄀☐	transferred to a person whom the undersigned reasonably believes to be a “qualified institutional buyer” as defined in Rule 144A under the Securities Act of 1933 who is purchasing such Notes for such buyer’s own account or the account of a “qualified institutional buyer” in a transaction meeting the requirements of Rule 144A under the Securities Act of 1933 and any applicable securities laws of any state of the United States or any other jurisdiction; or	
(3)	󠄀☐	exchanged or transferred pursuant to and in compliance with Rule 903 or 904 of Regulation S under the Securities Act of 1933; or	
(4)	󠄀☐	transferred to the Company or an “affiliate” (as defined in Rule 144 under the Securities Act) of the Company; or; or	
(5)	󠄀☐	transferred pursuant to another available exemption from the registration requirements of the Securities Act of 1933.	

Unless one of the boxes is checked, the Trustee will refuse to register any Note evidenced by this certificate in the name of any person other than the registered Holder thereof; provided, however, that if box (3), (4) or (5) is checked the Company may require, prior to registering any such transfer of this Note, such legal opinions, certifications and other information as the Company has reasonably requested to confirm that such transfer is being made pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act of 1933, such as the exemption provided by Rule 144 under such Act; provided, further, that if box (2) is checked, the transferee must also certify that it is a qualified institutional buyer as defined in Rule 144A.
___________________________________________
Signature
___________________________________________
SIGNATURE GUARANTEE
Date: _________________________
Signatures must be guaranteed by an “eligible guarantor institution” meeting the requirements of the Security Registrar, which requirements include membership or participation in the Security Transfer Agent Medallion Program (“STAMP”) or such other “signature guarantee program” as may be determined by the Security Registrar in addition to, or in substitution for, STAMP, all in accordance with the Securities Exchange Act of 1934, as amended.
23

TO BE COMPLETED BY PURCHASER IF (2) ABOVE IS CHECKED.
The undersigned represents and warrants that it is purchasing this Note for its own account or an account with respect to which it exercises sole investment discretion and that it and any such account is a “qualified institutional buyer” within the meaning of Rule 144A under the Securities Act of 1933, as amended, and is aware that the sale to it is being made in reliance on Rule 144A and acknowledges that it has received such information regarding the Company as the undersigned has requested pursuant to Rule 144A or has determined not to request such information and that it is aware that the transferor is relying upon the undersigned’s foregoing representations in order to claim the exemption from registration provided by Rule 144A.
___________________________________________
SIGNATURE GUARANTEE
Date: _________________________
Signatures must be guaranteed by an “eligible guarantor institution’’ meeting the requirements of the Security Registrar, which requirements include membership or participation in the Security Transfer Agent Medallion Program (“STAMP”) or such other “signature guarantee program” as may be determined by the Security Registrar in addition to, or in substitution for, STAMP, all accordance with the Securities Exchange Act of 1934, as amended.
NOTICE: To be executed by an executive officer.

24

SCHEDULE A
The initial aggregate principal amount of the Note evidenced by the Certificate to which this Schedule is attached is $          . The notations on the following table evidence decreases and increases in the aggregate principal amount of the Note evidenced by such Certificate.

Decrease in Principal Amount of the Note	Increase in Principal Amount of the Note	Principal Amount of the Note Remaining After Such Decrease or
Increase	Notation by Security Registrar	

25

Exhibit 2

FORM OF TRANSFER CERTIFICATE

In connection with any transfer of any of the Notes evidenced by this certificate, the undersigned confirms that such Notes are being:

CHECK ONE BOX BELOW

(1)	󠄀☐	exchanged for the undersigned’s own account without transfer; or	
(2)	󠄀☐	transferred to a person whom the undersigned reasonably believes to be a “qualified institutional buyer” as defined in Rule 144A under the Securities Act of 1933 who is purchasing such Notes for such buyer’s own account or the account of a “qualified institutional buyer” in a transaction meeting the requirements of Rule 144A under the Securities Act of 1933 and any applicable securities laws of any state of the United States or any other jurisdiction; or	
(3)	󠄀☐	exchanged or transferred pursuant to and in compliance with Rule 903 or 904 of Regulation S under the Securities Act of 1933; or	
(4)	󠄀☐	transferred to the Company or an “affiliate” (as defined in Rule 144 under the Securities Act) of the Company; or; or	
(5)	󠄀☐	transferred pursuant to another available exemption from the registration requirements of the Securities Act of 1933.	
Unless one of the boxes is checked, the Trustee will refuse to register any of the Notes evidenced by this certificate in the name of any person other than the registered Holder thereof; provided, however, that if box (3) or (4) is checked, the Company may require, prior to registering any such transfer of the Notes, such legal opinions, certifications and other information as the Company has reasonably requested to confirm that such transfer is being made pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act of 1933, such as the exemption provided by Rule 144 under such Act; provided, further, that if box (2) is checked, the transferee must also certify that it is a qualified institutional buyer as defined in Rule 144A.

______________________________
Signature

______________________________
SIGNATURE GUARANTEE

Date: _____________________

Signatures must be guaranteed by an “eligible guarantor institution” meeting the requirements of the Security Registrar, which requirements include membership or participation in the Security Transfer Agent Medallion Program (“STAMP”) or such other “signature guarantee program” as may be determined by the Security Registrar in addition to, or in substitution for, STAMP, all in accordance with the Securities Exchange Act of 1934, as amended.
1

TO BE COMPLETED BY PURCHASER IF (2) ABOVE IS CHECKED.

The undersigned represents and warrants that it is purchasing this Note for its own account or an account with respect to which it exercises sole investment discretion and that it and any such account is a “qualified institutional buyer” within the meaning of Rule 144A under the Securities Act of 1933, and is aware that the sale to it is being made in reliance on Rule 144A and acknowledges that it has received such information regarding the Company as the undersigned has requested pursuant to Rule 144A or has determined not to request such information and that it is aware that the transferor is relying upon the undersigned’s foregoing representations in order to claim the exemption from registration provided by Rule 144A.

___________________________
SIGNATURE GUARANTEE

Date: _____________________

Signatures must be guaranteed by an “eligible guarantor institution” meeting the requirements of the Security Registrar, which requirements include membership or participation in the Security Transfer Agent Medallion Program (“STAMP”) or such other “signature guarantee program” as may be determined by the Security Registrar in addition to, or in substitution for, STAMP, all in accordance with the Securities Exchange Act of 1934, as amended.

NOTICE: To be executed by an executive officer.
2

Execution Version
STOCK PURCHASE AGREEMENT

by and among

AMERICAN ELECTRIC POWER COMPANY, INC.
AEP TRANSMISSION COMPANY, LLC

and
LIBERTY UTILITIES CO.

Dated as of October 26, 2021

TABLE OF CONTENTS
Page
															
ARTICLE I	PURCHASE AND SALE		1	
					
1.1	Purchase and Sale of the Shares		1	
1.2	Closing Payment Amount		1	
1.3	Closing		1	
1.4	Closing Payment Adjustment		3	
1.5	Post-Closing Statement		3	
1.6	Reconciliation of the Post-Closing Statement		4	
1.7	Post-Closing Adjustment		5	
				
ARTICLE II	REPRESENTATIONS AND WARRANTIES OF SELLERS		6	
					
2.1	Organization and Qualification; No Subsidiaries		6	
2.2	Capitalization of the Acquired Companies		6	
2.3	Authority Relative to this Agreement		7	
2.4	Consents and Approvals; No Violations		7	
2.5	Financial Statements		8	
2.6	Absence of Certain Changes or Events		9	
2.7	Sufficiency of Assets		9	
2.8	Material Contracts		9	
2.9	Intellectual Property		11	
2.10	Legal Proceedings		12	
2.11	Compliance with Laws; Permits		12	
2.12	Real Property; Personal Property		12	
2.13	Employee Benefits Matters		12	
2.14	Labor Matters		14	
2.15	Taxes		15	
2.16	Environmental Matters		16	
2.17	Brokers		17	
2.18	Regulatory Matters		17	
2.19	Insurance		17	
2.20	Anti-Corruption; Trade Compliance and Economic Sanctions		17	
2.21	No Other Representations or Warranties		18	
				
ARTICLE III	REPRESENTATIONS AND WARRANTIES OF PURCHASER		18	
					
3.1	Organization and Qualification		18	
3.2	Authority Relative to this Agreement		19	
3.3	Consents and Approvals; No Violations		19	
3.4	Legal Proceedings		19	
3.5	Trade Compliance and Economic Sanctions		19	
3.6	Brokers		20	
3.7	Financial Capability		20	
3.8	Investment Decision		21	
3.9	Independent Investigation			21	
3.10	No Other Representations or Warranties; No Reliance			21	
					
ARTICLE IV	ADDITIONAL AGREEMENTS			22	
i

TABLE OF CONTENTS
(Continued)
Page
															
4.1	Conduct of Business		22	
4.2	Access to Information		26	
4.3	Confidentiality		26	
4.4	Further Assurances		27	
4.5	Required Actions		28	
4.6	Additional Regulatory Filings and Consents		31	
4.7	Public Announcements		32	
4.8	Intercompany Arrangements, Intercompany Accounts and Shared Contracts		32	
4.9	Support Obligations		33	
4.10	Usage of Seller Marks		34	
4.11	Release		35	
4.12	Indemnification of Directors and Officers		36	
4.13	NSR Consent Decree		37	
4.14	[Reserved]		37	
4.15	R&W Policy; No Subrogation		37	
4.16	Existing Debt Agreements; Senior Notes		38	
4.17	Business Separation Plan		39	
4.18	NERC Registration		40	
4.19	Master Leases		40	
4.20	Transfer of Mitchell Assets and Mitchell Employees to Successor Operator; Mitchell Plant Approvals		40	
4.21	Corporate Offices and Service Centers		42	
4.22	Insurance		42	
4.23	Misdirected Payments		43	
4.24	Misallocated Assets		43	
4.25	Financing Cooperation		43	
				
ARTICLE V	EMPLOYEE, LABOR AND BENEFITS MATTERS COVENANTS		46	
					
5.1	Seller Benefit Plans		46	
5.2	Non-Covered Employees		46	
5.3	Covered Employees Offers and Post-Closing Employment and Benefits		46	
5.4	Post-Closing Employment and Benefits for Non-Covered Employees		46	
5.5	Welfare Plans		47	
5.6	Severance		47	
5.7	COBRA		47	
5.8	Service Credit		48	
5.9	Savings Plans		48	
5.10	Incentive Awards		48	
5.11	Pre-Closing Date Claims under Seller Benefit Plans		48	
5.12	[Reserved]		48	
5.13	Workers Compensation		48	
5.14	WARN Act		49	
5.15	Employee Communications			49	
5.16	No Third-Party Beneficiary Rights			49	
5.17	Non-Solicitation of Business Employees			49	
5.18	Code Section 409A			50	
5.19	Transfer of Certain Employees			50	
ii

TABLE OF CONTENTS
(Continued)
Page
															
ARTICLE VI	TAX MATTERS		51	
				
6.1	Withholding		51	
6.2	Tax Year End		51	
6.3	Tax Proceedings		51	
6.4	Cooperation with Respect to Taxes		51	
6.5	Tax Sharing Agreements		52	
6.6	Transfer Taxes		52	
6.7	Post-Closing Matters		52	
				
ARTICLE VII	CONDITIONS TO CLOSING		53	
				
7.1	Conditions to Each Party’s Closing Obligations		53	
7.2	Conditions to Purchaser’s Closing Obligations		53	
7.3	Conditions to Sellers’ Closing Obligation		54	
7.4	Frustration of Closing Conditions		54	
				
ARTICLE VIII	TERMINATION		54	
				
8.1	Termination		54	
8.2	Notice of Termination		56	
8.3	Termination Fee		56	
8.4	Effect of Termination		57	
8.5	Extension; Waiver		57	
				
ARTICLE IX	SURVIVAL AND REMEDIES		58	
				
9.1	Survival of Representations, Warranties, Covenants and Agreements			58	
9.2	Indemnification		58	
9.3	No Recourse		60	
9.4	Limitation on Consequential Damages		60	
				
ARTICLE X	GENERAL PROVISIONS		60	
				
10.1	Amendment		60	
10.2	Waivers and Consents		61	
10.3	Notices		61	
10.4	Assignment		62	
10.5	No Third-Party Beneficiaries		62	
10.6	Expenses		62	
10.7	Governing Law		62	
10.8	Severability		62	
10.9	Entire Agreement			62	
10.10	Delivery			63	
10.11	Waiver of Jury Trial			63	
10.12	Submission to Jurisdiction			63	
10.13	Specific Performance			63	
10.14	Disclosure Generally			64	
10.15	Provision Respecting Legal Representation			64	
10.16	Privilege			64	
iii

TABLE OF CONTENTS
(Continued)
Page
															
10.17	Disclaimer		65	
10.18	Definitions		65	
10.19	Other Interpretive Matters		65	
iv

Appendices
Appendix I:    Definitions
Appendix II:    Calculation of Net Working Capital1
Appendix III:    Forecasted Capital Expenditures Amount1
Exhibits2
Exhibit A:    Transition Services Agreement
Exhibit B:    Mitchell Plant Ownership Agreement
Exhibit C:    Mitchell Plant O&M Agreement
Exhibit D:    Compliance Agreement

1 These Appendices have been omitted from this filing version of the Agreement.
2 These Exhibits have been omitted from this filing version of the Agreement.
v

STOCK PURCHASE AGREEMENT
This STOCK PURCHASE AGREEMENT (this “Agreement”), dated as of October 26, 2021 (the “Effective Date”), is by and among American Electric Power Company, Inc. (“AEP”), a New York corporation, AEP Transmission Company, LLC (“AEP TransCo”), a Delaware limited liability company (AEP and AEP TransCo are each referred to individually as a “Seller,” and, collectively, as “Sellers”), and Liberty Utilities Co., a Delaware corporation (“Purchaser”). Sellers and Purchaser are each referred to individually in this Agreement as a “Party” and collectively as the “Parties.”
RECITALS
WHEREAS, AEP owns, of record and beneficially, all of the outstanding common shares, $50.00 par value (the “Kentucky Power Shares”), of Kentucky Power Company, a Kentucky corporation (“Kentucky Power”);
WHEREAS, AEP TransCo owns, of record and beneficially, all of the outstanding common shares, no par value (the “Kentucky TransCo Shares,” and, together with the Kentucky Power Shares, the “Shares”), of AEP Kentucky Transmission Company, Inc., a Kentucky corporation (“Kentucky TransCo”; Kentucky TransCo and Kentucky Power are each referred to individually as an “Acquired Company” and, collectively, as the “Acquired Companies”); and
WHEREAS, Sellers desire to sell and transfer, and Purchaser desires to purchase, all of Sellers’ right, title and interest in and to the Shares for the Purchase Price, subject to the terms and conditions of this Agreement.
NOW, THEREFORE, in consideration of the mutual promises hereinafter set forth and for other good and valuable consideration, the receipt and adequacy of which are hereby acknowledged, and intending to be legally bound, the Parties hereby agree as follows:
ARTICLE I
PURCHASE AND SALE

1.1Purchase and Sale of the Shares. Upon the terms and subject to the conditions set forth in this Agreement, at the closing of the transactions contemplated by this Agreement (the “Closing”), Sellers shall transfer, convey, assign and deliver, or cause to be transferred, conveyed, assigned and delivered, to Purchaser, and Purchaser shall purchase and acquire from Sellers, the Shares, for the Closing Payment Amount, subject to the Post-Closing Adjustment (the “Sale”).
1.2Closing Payment Amount. At the Closing, Purchaser shall deliver or cause to be delivered to Sellers (and/or one or more of Sellers’ designees), in immediately available funds, the Closing Payment Amount.
1.3Closing.
(a)The Closing shall take place (i) at the offices of Morgan, Lewis & Bockius LLP (“Morgan Lewis”), 101 Park Avenue, New York, NY 10178 at 10:00 a.m., Eastern time, on the third Business Day after the date on which all of the conditions set forth in Article VII are fulfilled or waived (other than those conditions that by their nature are to be fulfilled at the Closing, but subject to the satisfaction of such conditions at the Closing) or (ii) at such other place, time or date as may be mutually
1

agreed upon in writing by Sellers and Purchaser (including virtually via the electronic exchange of signature pages). The date on which the Closing occurs is referred to as the “Closing Date.” The Closing shall be deemed to occur at 12:01 a.m., Eastern Time, on the Closing Date. All actions to be taken and all documents to be executed and delivered by the Parties at the Closing shall be deemed to have been taken and executed simultaneously.
(b)At or prior to the Closing:
(i)Sellers shall deliver or cause to be delivered to Purchaser:
(A)(1) certificates evidencing all of the Shares represented by certificates, duly endorsed in blank or with stock powers duly executed in proper form for transfer and (2) with respect to all of the Shares not represented by certificates, stock powers or appropriate transfer instruments, duly executed in proper form for transfer;
(B)the certificates required to be delivered pursuant to Section 7.2(c);
(C)certificates of each Seller (or if any Seller is a disregarded entity for U.S. federal income Tax purposes, its regarded owner) satisfying the requirements of Treasury Regulations Section 1.1445-2(b)(2) or IRS Form W-9;
(D)each of the Ancillary Agreements to which any member of the Seller Group is a party, duly executed by the applicable member of the Seller Group;
(E)each of the Mitchell Plant Ownership Agreement and the Mitchell Plant O&M Agreement, duly executed by Kentucky Power and Wheeling or Successor Operator, as applicable;
(F)resignations or other evidence of removal (in a form reasonably acceptable to Purchaser), effective as of the Closing Date, of those directors and officers of the Acquired Companies as Purchaser may request not less than three (3) Business Days prior to the Closing;
(G)with respect to each Intercompany Arrangement and outstanding amount or balance due or owing by or to the Acquired Companies, on the one hand, and Sellers or any of their Affiliates (other than the Acquired Companies), on the other hand, in each case, required to be severed, terminated, cancelled, settled or otherwise eliminated pursuant to Section 4.8, instruments or other evidence, in form reasonably acceptable to Purchaser, reflecting such severance, termination, cancellation, settlement or elimination, as applicable; and
(H)with respect to each Closing Indebtedness that is required to be paid at the Closing pursuant to Section 4.16, true and accurate copies of customary payoff letter and other instruments of discharge for such Closing Indebtedness, in each case in a form reasonably acceptable to Purchaser (a “Payoff Letter”), duly executed by each of the applicable holders (or agents thereof) of such Indebtedness and, as customary or appropriate, the other parties thereto.
(ii)Purchaser shall:
(A)pay or cause to be paid to Sellers (and/or one or more of Sellers’ designees) by wire transfer, to the account or accounts designated by Sellers (or by such designee) in the
2

notice accompanying the Estimated Closing Statement (as defined below), immediately available funds in an amount equal to the Closing Payment Amount;
(B)pay or cause to be paid the Estimated Transaction Expenses, if any are designated to be paid directly at Closing, to the applicable payees, as set forth in the Estimated Closing Statement;
(C)make any payments required to be paid at Closing pursuant to Section 4.16(a) in respect of the Utility Money Pool Agreement and Section 4.16(b) in respect of the TransCo Intercompany Notes;
(D)make, or cause to be paid, any other payments required to be paid at the Closing by or on behalf of the Acquired Companies pursuant to Section 4.16;
(E)deliver to Sellers the certificate required to be delivered pursuant to Section 7.3(c);
(F)deliver or cause to be delivered to Sellers a copy of the R&W Policy, if any, with such terms as specified in Section 4.15 and paid in full by Purchaser as of the time of delivery; and
(G)deliver to Sellers each of the Ancillary Agreements to which Purchaser or its Affiliate is a party, duly executed by Purchaser or its Affiliate as applicable.
1.4Closing Payment Adjustment.
(a)Not less than three (3) Business Days prior to the anticipated Closing Date, Sellers shall provide Purchaser with a written statement, setting forth a good-faith estimate in reasonable detail of each of the following: (i) the Estimated Closing Cash, (ii) the Estimated Net Working Capital, (iii) the Estimated Closing Indebtedness, (iv) the Estimated Capital Expenditures Amount and (v) the Estimated Transaction Expenses (the “Estimated Closing Statement”), which shall be accompanied by a notice that sets forth (A) Sellers’ determination of each of the Closing Payment Adjustment and the Closing Payment Amount and (B) the account or accounts to which Purchaser shall transfer the Closing Payment Amount, the payments in respect of the Utility Money Pool Agreement and the TransCo Intercompany Notes (if any), and the Estimated Transaction Expenses designated to be paid directly at Closing (if any), in each case pursuant to Section 1.3.
(b)The Estimated Closing Statement shall be prepared in accordance with GAAP and FERC Accounting Requirements, as applicable (“Accounting Principles”), and applied in a manner consistent with the principles, methodologies and adjustments used in connection with the preparation of Appendix II.
1.5Post-Closing Statement.
(a)Within sixty (60) days after the Closing Date, Purchaser shall prepare in good faith and deliver to Sellers a written statement of (i) the Final Closing Cash, (ii) the Final Net Working Capital, (iii) the Final Closing Indebtedness, (iv) the Final Capital Expenditures Amount and (v) the Final Transaction Expenses (collectively, the “Initial Closing Statement”), together with a notice that sets forth the proposed Post-Closing Adjustment and Purchase Price, as determined by Purchaser. The Initial Closing Statement shall be prepared in accordance with the Accounting Principles, and applied in a manner
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consistent with the principles, methodologies and adjustments used in connection with the preparation of Appendix II.
(b)Following the Closing through the date that the Final Closing Statement (as defined below) becomes final and binding, Sellers and their Affiliates and Representatives shall be permitted to reasonably access and review, during normal business hours upon reasonable advance notice, the books, records and work papers of the Acquired Companies, and Purchaser shall, and shall cause its Affiliates (including the Acquired Companies) and its and their respective employees, accountants and other Representatives to, cooperate with and assist Sellers and their Affiliates and Representatives in connection with such review, including by providing reasonable access during normal business hours upon reasonable advance notice to such books, records and work papers and making available personnel to the extent reasonably requested.
(c)Purchaser agrees that, following the Closing through the date that the Final Closing Statement becomes final and binding, it shall not take or permit to be taken any actions with respect to any accounting books, records, policies or procedures on which the Acquired Companies’ Financial Statements or the Initial Closing Statement are based, or on which the Final Closing Statement are to be based, that are intended to impede or delay the determination of the Final Closing Cash, Final Net Working Capital, Final Closing Indebtedness, the Final Capital Expenditures Amount or the Final Transaction Expenses or the preparation of any Notice of Disagreement or the Final Closing Statement in the manner and utilizing the methods provided by this Agreement.
1.6Reconciliation of the Post-Closing Statement.
(a)Sellers shall notify Purchaser in writing no later than forty-five (45) days after Sellers’ receipt of the Initial Closing Statement if Sellers disagree with the Initial Closing Statement, which notice shall describe the basis for such disagreement (including reasonable supporting detail for such objection, including the dollar amount of any such objection) (the “Notice of Disagreement”). If no Notice of Disagreement is delivered to Purchaser by such time, then the Initial Closing Statement shall become final and binding upon the Parties in accordance with Section 1.6(c).
(b)During the thirty (30) days immediately following the delivery of a Notice of Disagreement (the “Resolution Period”), Sellers and Purchaser shall seek to resolve any differences that they may have with respect to the matters specified in the Notice of Disagreement.
(c)If, at the end of the Resolution Period, Sellers and Purchaser have been unable to resolve any differences that they may have with respect to the matters specified in the Notice of Disagreement, Sellers and Purchaser shall submit all such matters that remain in dispute with respect to the Notice of Disagreement to KPMG LLP or such other independent public accounting firm that is mutually acceptable to Purchaser and Sellers (the “Independent Accounting Firm”). As promptly as practical, but in any event within sixty (60) days after submission of such matters to the Independent Accounting Firm, the Independent Accounting Firm shall make a final determination in accordance with the Accounting Principles and applied in a manner consistent with the principles, methodologies and adjustments used in connection with the preparation of Appendix II, and the terms and definitions of this Agreement and based solely on the written submissions of the Parties, of the appropriate amount of each of the matters that remain in dispute as indicated in the Notice of Disagreement that Sellers and Purchaser have submitted to the Independent Accounting Firm, and such final determination shall be binding on the Parties. With respect to each disputed matter, such determination, if not in accordance with the position of either Sellers or Purchaser, shall not be in excess of the higher, or less than the lower, of the amounts advocated by Sellers in the Notice of Disagreement or by Purchaser in the Initial Closing Statement with respect to such disputed
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matter. The statements of (i) the Final Closing Cash, (ii) the Final Net Working Capital, (iii) the Final Closing Indebtedness, (iv) the Final Capital Expenditures Amount and (v) the Final Transaction Expenses that are final and binding on the Parties, as determined either through agreement of the Parties pursuant to Section 1.6(a) or Section 1.6(b) or through the findings of the Independent Accounting Firm pursuant to this Section 1.6(c), are referred to as the “Final Closing Statement” and the Closing Payment Amount that would be calculated substituting the Final Closing Cash for the Estimated Closing Cash, the Final Net Working Capital for the Estimated Net Working Capital, the Final Closing Indebtedness for the Estimated Closing Indebtedness, the Final Capital Expenditures Amount for the Estimated Capital Expenditures Amount and the Final Transaction Expenses for the Estimated Transaction Expenses is referred to as the “Final Payment Amount”.
(d)All fees and expenses relating to the work, if any, to be performed by the Independent Accounting Firm shall be borne equally by Sellers, on the one hand, and Purchaser, on the other. During the review by the Independent Accounting Firm, each of Purchaser and Sellers shall, and shall cause their respective Affiliates (including, in the case of Purchaser, the Acquired Companies) and their respective employees, accountants and other Representatives to, each make available to the Independent Accounting Firm (during normal business hours upon reasonable advance notice) interviews with such personnel, and such information, books and records and work papers, as may be reasonably requested by the Independent Accounting Firm to fulfill its obligations under Section 1.6(c); provided, that the accountants of Sellers or Purchaser shall not be obligated to make any work papers available to the Independent Accounting Firm except in accordance with such accountants’ normal disclosure procedures and then only after such Independent Accounting Firm has signed a customary agreement relating to such access to work papers. In acting under this Agreement, the Independent Accounting Firm shall act as an expert and not an arbitrator.
(e)The process set forth in Section 1.5 and this Section 1.6 shall be the sole and exclusive remedy of any of the Parties and their respective Affiliates for any disputes related to the Closing Payment Adjustment, the Post-Closing Adjustment and the calculations and amounts on which they are based or set forth in the related statements and notices delivered in connection therewith. For the avoidance of doubt, the calculations to be made pursuant to Section 1.5 and this Section 1.6 and the Closing Payment Adjustment and Post-Closing Adjustment are not intended to be used to adjust for errors or omissions that may be found with respect to the Acquired Companies’ Financial Statements or any inconsistencies between the Acquired Companies’ Financial Statements and GAAP or FERC Accounting Requirements, as applicable. After the determination of the Final Closing Statement for an Acquired Company, none of the Parties shall have the right to make any claim with respect to such Acquired Company based upon the preparation of the Final Closing Statement or the calculation of Final Closing Cash, Final Net Working Capital, Final Closing Indebtedness, Final Capital Expenditures Amount or Final Transaction Expenses as of the Closing (even if subsequent events or subsequently discovered facts would have affected the determination of the Final Closing Statement or the calculations of Final Closing Cash, Final Net Working Capital, Final Closing Indebtedness, Final Capital Expenditures Amount or Final Transaction Expenses had such subsequent events or subsequently discovered facts been known at the time of the determination of the Final Closing Statement).
1.7Post-Closing Adjustment. The “Post-Closing Adjustment” shall be equal to the difference (which may be a positive or negative amount) of the Final Payment Amount minus the Closing Payment Amount. If the Post-Closing Adjustment is a positive amount, then Purchaser shall pay or cause to be paid in cash to Sellers (or one or more of Sellers’ designees) the amount of such Post-Closing Adjustment. If the Post-Closing Adjustment is a negative amount, then Sellers shall pay or cause to be paid in cash to Purchaser the absolute value of the amount of such Post-Closing Adjustment. Any such payment pursuant to this Section 1.7 shall be made within ten (10) Business Days after the determination of the Final Closing
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Statement by wire transfer of immediately available funds. Any amount paid under this Section 1.7 shall be treated as an adjustment to the Purchase Price for Tax purposes and, except to the extent required by applicable Laws, the Parties agree not to take any position inconsistent with such treatment on any Tax Return.
ARTICLE II
REPRESENTATIONS AND WARRANTIES OF SELLERS

Except as set forth in the disclosure letter delivered to Purchaser in connection with the execution of this Agreement (the “Sellers Disclosure Letter”), Sellers hereby represent and warrant to Purchaser as follows:
2.1Organization and Qualification; No Subsidiaries. AEP is a corporation duly incorporated, validly existing and in good standing under the Laws of the State of New York, and AEP TransCo is a limited liability company duly organized, validly existing and in good standing under the Laws of the State of Delaware. The Acquired Companies are corporations duly incorporated, validly existing and in good standing under the Laws of the State of Kentucky. Each of the Acquired Companies has all requisite corporate power and authority to carry on its respective businesses as now being conducted and to own, lease and operate its properties and assets where such properties or assets are now owned, leased or operated, and is qualified to do business and is in good standing as a foreign corporation or company in each jurisdiction where the conduct of its business or the property or asset owned, leased or operated by it requires such qualification, except for any such failures that would not reasonably be expected to have, individually or in the aggregate, a Material Adverse Effect. None of the Acquired Companies own any equity interests in any Person. Sellers have made available to Purchaser correct and complete copies of the Organizational Documents of each of the Acquired Companies (including all amendments thereto), and each such instrument is in full force and effect.
2.2Capitalization of the Acquired Companies.
(a)The Shares are duly authorized, validly issued, fully paid and nonassessable, and will be transferred, conveyed, assigned and delivered to Purchaser at the Closing, free and clear of all Encumbrances (other than any Encumbrances arising under the Organizational Documents of the Acquired Companies, the Debt Agreements, or applicable securities Laws, in each case, other than as a result of any violation thereof). The Shares were not issued in violation of any Law or any Organizational Document of any of the Acquired Companies, and each of AEP and AEP TransCo has good and valid title to, and ownership, of record and beneficially, of, all of the Kentucky Power Shares and the Kentucky TransCo Shares, respectively. The Shares represent all of the issued and outstanding shares of capital stock and all of the issued and outstanding equity interests of the Acquired Companies. The Kentucky Power Shares are represented by one share certificate and, as of the Effective Date, none of the Kentucky TransCo Shares are represented by any share certificate.
(b)Except for the Shares, there are no shares of common stock, preferred stock or other equity interests of the Acquired Companies issued and outstanding or held in treasury, and there are no preemptive or other outstanding rights, subscriptions, options, warrants, stock appreciation rights, redemption rights, repurchase rights, convertible, exercisable, or exchangeable securities or other agreements, arrangements or commitments of any character relating to the issued or unissued share capital or other equity ownership interest in the Acquired Companies or any other securities or obligations convertible or exchangeable into or exercisable for, or giving any Person a right to subscribe for or acquire, any securities of the Acquired Companies, and no securities evidencing such rights are authorized, issued
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or outstanding. The Acquired Companies have no outstanding bonds, debentures, notes or other obligations, and are not subject to any Contracts, that provide the holders thereof or any other Person the right to vote (or are convertible or exchangeable into or exercisable for securities having the right to vote) with the stockholders or equityholders of either of the Acquired Companies on any matter.
2.3Authority Relative to this Agreement. Each Seller has, and each member of the Seller Group shall have prior to the Closing, all necessary power and authority to execute, deliver and perform this Agreement and the Ancillary Agreements to which it is or shall at Closing be a party and to consummate the transactions contemplated by this Agreement and the Ancillary Agreements to which it is or shall at Closing be a party in accordance with the terms hereof and thereof. The execution, delivery and performance by each Seller and each member of the Seller Group of this Agreement and the Ancillary Agreements to which it is or shall at Closing be a party, and the consummation of the transactions contemplated hereby and thereby, have been, or shall be prior to the Closing, duly and validly authorized by all necessary action on part of such Seller, and no other proceedings on the part of a Seller or any member of the Seller Group are, or shall be as of immediately preceding the Closing, necessary to authorize the execution, delivery and performance, as applicable, of this Agreement or any Ancillary Agreement to which it is or shall at Closing be a party. This Agreement has been duly and validly executed and delivered by each Seller, and, assuming the due authorization, execution and delivery of this Agreement by Purchaser, constitutes, and each Ancillary Agreement to which each Seller or any member of the Seller Group is or shall at Closing be a party, when executed and delivered by the members of the Seller Group party thereto, and, assuming the due authorization, execution and delivery of such Ancillary Agreement by Purchaser or, if applicable, its applicable Affiliate party thereto, shall constitute a valid, legal and binding agreement of the applicable members of the Seller Group, enforceable against each such member in accordance with its terms, subject to the effect of any applicable Laws relating to bankruptcy, reorganization, insolvency, moratorium, fraudulent conveyance or preferential transfers, or similar Laws relating to or affecting creditors’ rights generally, or general principles of equity (collectively, the “Enforceability Exceptions”).
2.4Consents and Approvals; No Violations. No filing with or notice to, and no consent or approval of, any Governmental Entity is required to be obtained or made on the part of Sellers, the Acquired Companies or any member of the Seller Group for the execution, delivery and performance by Sellers or any member of the Seller Group of this Agreement or any Ancillary Agreement to which a Seller or such member of the Seller Group is or shall at Closing be a party or the consummation by Sellers and/or their Affiliates, as applicable, of the transactions contemplated hereby or thereby, other than: (a) the Required Regulatory Approvals, (b) the Mitchell Plant Approvals, (c) the filings, notices or approvals listed on Section 2.4(a) of the Sellers Disclosure Letter (the “Additional Regulatory Filings and Consents”), (d) notice and judicial approval of a modification to the NSR Consent Decree or (e) any permit, declaration, filing, authorization, registration, consent or approval, of which the failure to make or obtain would not reasonably be expected to have, individually or in the aggregate, a Material Adverse Effect. Assuming, solely with respect to clauses (ii) and (iii) hereof, compliance with the items described in clauses (a) through (d) of the preceding sentence and except as set forth on Section 2.4(b) of the Sellers Disclosure Letter, neither the execution, delivery or performance by Sellers or any member of the Seller Group of this Agreement or any Ancillary Agreement to which a Seller or any member of the Seller Group is or shall at Closing be a party, nor the consummation by Sellers and/or any member of the Seller Group, as applicable, of the transactions contemplated hereby or thereby shall (i) conflict with or result in any breach or violation of any provision of its Organizational Documents or the Organizational Documents of the Acquired Companies, (ii) result in a breach or violation of, or constitute (with or without due notice or lapse of time or both) a default (or give rise to the creation of any Encumbrance, except for Permitted Encumbrances, or any right of termination, amendment, cancellation or acceleration) under, any of the terms, conditions or provisions of any Material Contract or material Permit to which any Acquired Company or any of its assets, rights, properties or business is bound or (iii) violate any Law applicable to, or result in the creation of any
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Encumbrance (other than for Permitted Encumbrances) upon, an Acquired Company or any of its rights, properties, business or assets, except, in the case of clauses (ii) or (iii), for breaches, violations, defaults, Encumbrances or rights of termination, amendment, cancellation or acceleration that would not reasonably be expected to have, individually or in the aggregate, a Material Adverse Effect.
2.5Financial Statements.
(a)Section 2.5(a) of the Sellers Disclosure Letter sets forth:
(i)the audited statements of income, comprehensive income, changes in common shareholders’ equity, balance sheets and cash flows and the related notes of Kentucky Power as of and for the annual periods ended December 31, 2019 and December 31, 2020 and the unaudited statements of income, comprehensive income changes in common shareholders’ equity, balance sheets, and cash flows of Kentucky Power as of and for the six-month period ended June 30, 2021 (collectively, the “Kentucky Power Financial Statements”) and
(ii)the audited FERC Form 1 financial statements of Kentucky TransCo as of and for the annual periods ended December 31, 2019 and December 31, 2020, and the unaudited FERC Form 3-Q financial statements of Kentucky TransCo as of and for the six-month period ended June 30, 2021 (collectively, the “Kentucky TransCo Financial Statements”, and together with the Kentucky Power Financial Statements, the “Acquired Companies’ Financial Statements”).
(b)The Kentucky Power Financial Statements (i) have been prepared in accordance with GAAP applied on a consistent basis during the periods involved (except as may be indicated in the notes thereto) and (ii) fairly present in all material respects the financial position, the stockholders’ equity, the results of operations and cash flows of Kentucky Power as of the times and for the periods referred to therein (except as may be indicated in the notes thereto and except that the unaudited quarterly financial statements do not include notes that would be required by GAAP or normal year-end adjustments, which in each case will not be material in nature or amount, taken as a whole). The Kentucky TransCo Financial Statements (x) have been prepared in accordance with FERC Accounting Requirements applied on a consistent basis during the periods involved and (y) fairly present in all material respects the financial position, the stockholders’ equity, the results of operations and cash flows of Kentucky TransCo as of the times and for the periods referred to therein.
(c)Except as set forth on Section 2.5(c) of the Sellers Disclosure Letter, the Acquired Companies have no liabilities or obligations that would be required by GAAP or FERC Accounting Requirements, as applicable, to be reflected or reserved against on the balance sheet of each Acquired Company other than (i) liabilities that are reflected or reserved against in the applicable Acquired Company’s unaudited balance sheet (or the notes thereto) as of June 30, 2021 (“Balance Sheet Date”) included in the Acquired Companies’ Financial Statements, (ii) liabilities or obligations that are incurred in the ordinary course of business since the Balance Sheet Date through the Effective Date or (iii)  liabilities or obligations incurred in accordance with the terms of this Agreement or any Material Contract (in each case, excluding any breach or violation thereof).
(d)Each Acquired Company has devised and maintained systems of internal accounting controls which are sufficient to provide reasonable assurances that (i) all material transactions are executed in accordance with its management’s general or specific authorization, (ii) all material transactions are recorded in the Acquired Companies’ respective books and records as necessary to permit the preparation of financial statements in conformity with GAAP (in the case of Kentucky Power) or FERC Accounting Requirements (in the case of Kentucky Transco) and (iii) the recorded accountability for items
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in the Acquired Companies’ respective books and records is compared with the actual levels thereof at reasonable intervals and appropriate action is taken with respect to any variances. The Acquired Companies’ Financial Statements were derived from and are consistent with such books and records.
2.6Absence of Certain Changes or Events. Except as contemplated by this Agreement, since the Balance Sheet Date, (a) the business of each Acquired Company has been conducted in all material respects in the ordinary course of business and (b) there has not occurred any Material Adverse Effect. The Business is the only business operation carried on by the Acquired Companies, and the assets, rights and properties of the Acquired Companies are being and have been for the last three (3) years operated and maintained in accordance with Good Utility Practice.
2.7Sufficiency of Assets. At Closing, except for (a) Shared Contracts (or replacement arrangements), (b) the assets, rights and properties to which the Acquired Companies have continued access to or use pursuant to the Ancillary Agreements (other than services expressly excluded, or services which Purchaser declines to accept, pursuant to the Transition Services Agreement), the Mitchell Plant O&M Agreement and the Intercompany Arrangements set forth on Section 4.8(a)(ii) of the Sellers Disclosure Letter, and (c) as set forth on Section 2.7(c) of the Sellers Disclosure Letter, the assets, rights and properties of the Acquired Companies constitute all of the material assets, rights and properties required or used to enable each Acquired Company to conduct in all material respects its business as currently being conducted and as conducted in the ordinary course in the preceding twelve (12) months.
2.8Material Contracts.
(a)Section 2.8(a) of the Sellers Disclosure Letter sets forth a list of the following Contracts to which an Acquired Company is a party or otherwise bound, which shall be deemed to constitute “Material Contracts”, true and correct copies of which (including all exhibits, schedules and amendments thereto) have been made available to Purchaser prior to the date hereof:
(i)all Contracts that individually involve expenditures by an Acquired Company in excess of $3,000,000 in any of the three calendar years preceding the date of this Agreement and pursuant to which an Acquired Company has ongoing obligations;
(ii)all Contracts that individually involve the receipt of payments by an Acquired Company in excess of $3,000,000 in any of the three calendar years preceding the date of this Agreement and pursuant to which an Acquired Company has ongoing obligations;
(iii)the Utility Money Pool Agreement, the TransCo Intercompany Notes, the Debt Agreements, the Senior KPCo Notes, the Senior Note Purchase Agreements, and all other Contracts for, or relating to, Indebtedness of an Acquired Company in excess of $3,000,000 in any of the three calendar years preceding the date of this Agreement or under which a security interest has been imposed on any assets, rights or properties of an Acquired Company, which security interest secures outstanding Indebtedness in excess of $3,000,000 in any of the three calendar years preceding the date of this Agreement and pursuant to which an Acquired Company has ongoing obligations;
(iv)all Contracts of guaranty, indemnity or surety by an Acquired Company with outstanding obligations guaranteed or indemnified by such Acquired Company or for which such Acquired Company is a surety in excess of $3,000,000 in any of the three calendar years preceding the date of this Agreement and pursuant to which an Acquired Company has ongoing obligations;
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(v)all Intercompany Arrangements involving payments or receipts by or to an Acquired Company in excess of $500,000 in any of the three calendar years preceding the Effective Date or pursuant to which an Acquired Company or any member of the Seller Group has any ongoing obligations or rights with a value allocable to an Acquired Company in excess of $500,000;
(vi)all Contracts granting to any Person any right or option to purchase or otherwise acquire any assets of an Acquired Company involving consideration over the remaining term of any such Contract in excess of $5,000,000, including rights of first option, rights of first refusal, or other preferential purchase rights;
(vii)all Contracts that (x) limit the ability of an Acquired Company to compete in any activity or line of business or in any geographic area or (y) contain any obligation on an Acquired Company, or that would apply to Purchaser or its Affiliates following the Closing, to use or purchase any material good or material service exclusively from one or more Persons;
(viii)all Contracts relating to the issuance, sale, transfer, disposition, registration, liquidity, granting, encumbering, pledging, voting, repurchase or redemption of any of the Shares or any other equity securities of an Acquired Company or rights in connection therewith (other than the Organizational Documents of the Acquired Companies);
(ix)all settlement, conciliation or similar Contracts with any Governmental Entity or third party that impose any continuing monetary or other ongoing material obligations upon any of the Acquired Companies, except for Contracts filed publicly with FERC or the KPSC in connection with the settlement of a Rate Proceeding;
(x)all Master Leases;
(xi)all Shared Contracts involving payments or receipts in excess of $3,000,000 in value allocated to an Acquired Company in any of the three calendar years preceding the Effective Date;
(xii)all Contracts for Continuing Support Obligations;
(xiii)all Contracts for the procurement of power, energy or capacity, including any power purchase agreement or Contracts committing to the development, purchase or construction of new generation, involving payments by an Acquired Company over the term of such Contract in excess of $3,000,000 and pursuant to which any Acquired Company has any ongoing obligations, other than Contracts for purchases and sales on arm’s-length terms with a delivery term of less than three (3) months ahead;
(xiv)all Contracts relating to fuel supply or transportation involving payments by an Acquired Company over the term of such Contract in excess of $3,000,000 and pursuant to which any Acquired Company has any ongoing obligations;
(xv)all Commercial Hedges having a current market value attributed or allocated to an Acquired Company or any of its assets or involving aggregate consideration or aggregate payment obligations by an Acquired Company over the term of such Contract in excess of $3,000,000;
(xvi)Contracts related to Intellectual Property owned or used by an Acquired Company involving payments or receipts in excess of $3,000,000 in value allocated to an Acquired
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Company in any of the three calendar years preceding the Effective Date (other than non-exclusive licenses (A) for off-the-shelf or otherwise commercially available software or (B) granted by an Acquired Company in the ordinary course of business);
(xvii)all Collective Bargaining Agreements; and
(xviii)all partnership, joint venture and joint ownership Contracts.
(b)(i) Other than any Intercompany Arrangements severed or terminated in accordance with Section 4.8(a), each Material Contract is a legal, valid and binding obligation of the applicable Acquired Company and, to the Knowledge of Sellers, each counterparty, and is in full force and effect, subject to the Enforceability Exceptions, (ii) neither the applicable Acquired Company nor, to the Knowledge of Sellers, any other party thereto is in breach of, or in default under, and no event has occurred which with notice or lapse of time or both would constitute any such breach or default, or permit termination, modification or acceleration by such other parties under, any Material Contract, (iii) no Acquired Company has waived any material right under any Material Contract, and (iv) no party to any Material Contract has notified any Seller or any Acquired Company in writing that it intends to terminate or fail to renew at the end of its term such Material Contract, materially increase rates, costs or fees charged under any Material Contract or materially reduce the level of goods or services provided under any Material Contract, except, in each case, as would not reasonably be expected to have, individually or in the aggregate, a Material Adverse Effect.
2.9Intellectual Property. All registered trademarks and applications to register trademarks and Internet domain names, patents and patent applications and registered copyrights and applications to register copyrights included in the Owned Intellectual Property are set forth on Section 2.9 of the Sellers Disclosure Letter (collectively, the “Company Registered Intellectual Property”). Each of the Acquired Companies owns all of the Company Registered Intellectual Property indicated as being owned by such entity, as well as all other material Owned Intellectual Property, free and clear of all Encumbrances (other than Permitted Encumbrances). The Owned Intellectual Property, together with the Seller Marks, Licensed Intellectual Property, and the Intellectual Property available to the Acquired Companies pursuant the Transition Services Agreement (other than Intellectual Property embedded in services expressly excluded, or services which Purchaser declines to accept, pursuant to the Transition Services Agreement) or the Mitchell Plant O&M Agreement, constitute all of the Intellectual Property necessary to operate the business of the Acquired Companies as operated as of the Effective Date. Except as would not reasonably be expected, individually or in the aggregate, to have a Material Adverse Effect, the operation of the business of the Acquired Companies as of the Effective Date does not infringe, dilute, misappropriate or otherwise violate the Intellectual Property or other rights of any third parties and to the Knowledge of Sellers no third party is infringing, diluting, misappropriating or otherwise violating the Owned Intellectual Property. Except as would not reasonably be expected, individually or in the aggregate, to have a Material Adverse Effect, (i) the Acquired Companies (and Sellers, with respect to the businesses conducted by the Acquired Companies) have taken commercially reasonable measures to ensure the confidentiality and security of all hardware, software, databases, systems, networks, websites, applications and other information technology assets and equipment owned, leased, or controlled by them in connection with their businesses and any information (including personal, personally identifiable, sensitive, regulated and confidential information) stored, transmitted, or otherwise processed thereby (“IT Assets”) from unauthorized or improper access or use, (ii) during the last three (3) years, there has been no breach of or other unauthorized or improper access or use of the IT Assets, and (iii) the IT Assets are adequate for the operation of the Acquired Companies and their respective businesses, and have not experienced any malfunctions or failures.
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2.10Legal Proceedings. Except as set forth on Section 2.10 of the Sellers Disclosure Letter, there are no, and during the last three (3) years there have not been any, Actions existing, pending or, to the Knowledge of Sellers, threatened against an Acquired Company or any of its assets, rights or properties, and there are no, and during the last three (3) years there have not been any, Orders outstanding against, or which are applicable to or bind, an Acquired Company or any of its assets, rights or properties, in each case that would reasonably be expected to have, individually or in the aggregate, a Material Adverse Effect or would reasonably be expected to result in the issuance of an Order restraining, enjoining or otherwise prohibiting the transactions contemplated by this Agreement or any Ancillary Agreement.
2.11Compliance with Laws; Permits. Each Acquired Company is in compliance with all Laws and Permits applicable to it and its assets, rights, properties or business, except for violations which would not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect. Neither Acquired Company has received any written notice of or been charged with the violation of any Laws, except where such violation would not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect.
2.12Real Property; Personal Property.
(a)Except as would not reasonably be expected, individually or in the aggregate, to have a Material Adverse Effect, each Acquired Company has on the Effective Date (and at the Closing shall have) (i) good and valid fee simple title to the Owned Real Property and all improvements thereon and (ii) valid leasehold interests in, or a right to use or occupy, the Leased Real Property and Easements and all improvements thereon (to the extent such improvements are leased by such Acquired Company), both free and clear, in each case, of all Encumbrances except Permitted Encumbrances and the Encumbrances listed on Section 2.12 of the Sellers Disclosure Letter.
(b)Except as would not reasonably be expected, individually or in the aggregate, to have a Material Adverse Effect, (i) each material lease, sublease, Easement and other agreement (each, a “Lease”) under which an Acquired Company or any of its Subsidiaries uses or occupies or has the right to use or occupy any Leased Real Property or Easement at which the operations of an Acquired Company are conducted as of the date hereof is valid, binding and in full force and effect, subject to the Enforceability Exceptions, (ii) no uncured default beyond any applicable notice and cure period thereunder on the part of any Acquired Company or, to the Knowledge of Sellers, the other party thereto exists with respect to any Lease and (iii) neither the execution and delivery of this Agreement nor the consummation of the transactions contemplated hereby will, with or without notice, the passage of time, or both, give rise to any default beyond any applicable notice and cure period thereunder under any Lease. Except as would not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect, there are no condemnation proceedings pending or, to the Knowledge of Sellers, threatened with respect to any Real Property. True and correct copies of each material real property lease have been made available to Purchaser prior to the date hereof.
(c)Except as would not reasonably be expected, individually or in the aggregate, to have a Material Adverse Effect, each Acquired Company owns, leases, licenses or has contractual rights to use all material tangible personal property, including all material machinery, equipment and other personal property necessary for the conduct of the Business, free and clear of all Encumbrances except for Permitted Encumbrances.
2.13Employee Benefits Matters.
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(a)Section 2.13(a) of the Sellers Disclosure Letter sets forth a true and complete list of each material Seller Benefit Plan as of the Effective Date.
(b)True and complete copies have been provided or made available to Purchaser of all material Seller Benefit Plans (or, in the case of an unwritten Seller Benefit Plan, a written description thereof), including any trust instruments and insurance Contracts forming a part of any Seller Benefit Plan.
(c)All Seller Benefit Plans have been administered in compliance with their terms and with the requirements of applicable Law, including ERISA and the Code, except as such non-compliance would not reasonably be expected to have a Material Adverse Effect.
(d)The IRS has issued a valid and favorable determination, opinion or advisory letter with respect to each Seller Benefit Plan that is intended to be a “qualified plan” within the meaning of Section 401(a) of the Code (each, a “Qualified Plan”) and the related trust that has not been revoked and, to the Knowledge of Sellers, no circumstances exist and no events have occurred that would, individually or in the aggregate, reasonably be expected to cause the loss of the qualified status of any Qualified Plan or the related trust. A copy of the most recent determination or opinion letter received from the IRS with respect to each Qualified Plan has been made available to Purchaser.
(e)From the date hereof and through and after the Closing Date, no circumstances shall exist that could result in any Controlled Group Liability of Sellers or any of their ERISA Affiliates (other than the Acquired Companies) becoming a Liability of the Acquired Companies or of Purchaser or its Affiliates.
(f)Except as set forth on Section 2.13(f) of the Sellers Disclosure Letter, neither the execution or delivery of this Agreement nor the consummation of the transactions contemplated by this Agreement would reasonably be expected to, either alone or in conjunction with any other event (whether contingent or otherwise), (i) result in any payment or benefit becoming due or payable, or required to be provided, to any Acquired Company Employee (other than the payment of accrued benefits under a Seller Benefit Plan as a result of an Acquired Company Employee ceasing to be an active participant under such Seller Benefit Plan), (ii) increase the amount or value of any benefit or compensation otherwise payable or required to be provided to any Acquired Company Employee, (iii) result in the acceleration of the time of payment or vesting of any compensation or benefits to any Acquired Company Employee (other than the payment of accrued benefits that were vested immediately prior to (and not as a result of) the consummation of the transactions contemplated by this Agreement under a Seller Benefit Plan as a result of an Acquired Company Employee ceasing to be an active participant under such Seller Benefit Plan) or (iv) result in any amount failing to be deductible by an Acquired Company by reason of Section 280G of the Code.
(g)Except as set forth on Section 2.13(g) of the Sellers Disclosure Letter, none of the Acquired Companies sponsor or make contributions with respect to any Benefit Plan subject to Title IV of ERISA.
(h)Except as set forth on Section 2.13(h) of the Sellers Disclosure Letter, no Acquired Company has any liability or obligation under any plan which provides medical or other welfare or death benefits with respect to any Acquired Company Employees beyond their termination of employment or service (other than coverage mandated by Law at the sole expense of the applicable participant).
(i)With respect to any Seller Benefit Plan, no Actions (other than routine claims for benefits in the ordinary course) are pending or, to the Knowledge of Sellers, threatened.
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(j)No Acquired Company maintains any Seller Benefit Plan outside the jurisdiction of the United States or that cover any Acquired Company Employees residing or working outside of the United States.
(k)This Section 2.13 contains the exclusive representations and warranties of Sellers with respect to employee benefits matters. No other provision of this Agreement shall be construed as constituting a representation or warranty regarding such matters.
2.14Labor Matters.
(a)Section 2.14(a) of the Sellers Disclosure Letter sets forth a list of the Acquired Company Employees as of the Effective Date, which list shall be amended prior to the Closing to reflect the addition of any employee who is hired by, or transferred to, an Acquired Company following the Effective Date and the removal of any individual whose employment with an Acquired Company is terminated prior to the Closing, and any employee of an Acquired Company whose work relates primarily to Mitchell (the “Mitchell Employees”) and whose employment is transferred from an Acquired Company to an Affiliate of the Sellers (other than the Acquired Companies) prior to the Closing Date. Sellers have provided to Purchaser the following information on a confidential basis: each Acquired Company Employee’s current base salary or wage rate and target bonus for the 2021 fiscal year (if any), position, date of hire (and, if different, years of recognized service), status as exempt or non-exempt under the Fair Labor Standards Act, and whether such Acquired Company Employee is on leave status, which information shall be updated prior to Closing to reflect changes made consistent with the first sentence of this Section 2.14(a).
(b)Except as set forth on Section 2.14(b) of the Sellers Disclosure Letter, none of Sellers or any Affiliates nor either Acquired Company is a party to or bound by any collective bargaining agreement or similar labor union Contract with respect to any of the Acquired Company Employees, no such agreement is presently being negotiated, and no Acquired Company Employees are, with respect to their employment, represented by a labor union. To the Knowledge of Sellers, since January 1, 2018, (i) there have been no labor union representation election proceedings, other than as set forth in Section 2.14(b) of the Sellers Disclosure Letter, with respect to Acquired Company Employees pending or threatened to be brought or filed with the National Labor Relations Board, and (ii) there have been no pending or threatened labor union organizing campaigns with respect to Acquired Company Employees. Since January 1, 2018, there have been no labor union strikes, slowdowns, work stoppages or lockouts or other material labor disputes pending or threatened against or affecting the Acquired Companies or involving employees of any Acquired Company.
(c)Except as set forth on Section 2.14(c) of the Sellers Disclosure Letter, since January 1, 2018, none of Sellers or their Affiliates (solely as it relates to the business of the Acquired Companies) or the Acquired Companies has closed any site of employment, effectuated any group layoffs of employees or implemented any early retirement, exit incentive, or other group separation program, nor has any such action or program been planned or announced for the future.
(d)Except as set forth on Section 2.14(d) of the Sellers Disclosure Letter, since January 1, 2018, no officer, director or management level employee of Sellers or their Affiliates (solely as it relates to the business of the Acquired Companies) or the Acquired Companies has been the subject of an allegation in the workplace of sexual harassment or sexual assault, nor, to the Knowledge of Seller, has any officer, director or management level employee of Sellers or their Affiliates (solely as it relates to the business of the Acquired Companies) or the Acquired Companies engaged in sexual harassment or sexual assault. None of Sellers or their Affiliates (solely as it relates to the business of the Acquired Companies)
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or the Acquired Companies has entered into any settlement agreements related to allegations of sexual harassment or misconduct by any employee.
2.15Taxes. Except as set forth on Section 2.15 of the Sellers Disclosure Letter:
(a)All material Tax Returns required to be filed by, or with respect to, each Acquired Company have been filed (taking into account extensions), and all Tax Returns filed by, or with respect to, each Acquired Company are accurate and complete in all material respects.
(b)All material Taxes required to be paid by, or with respect to, each Acquired Company (whether or not shown on any Tax Return) have been paid.
(c)Neither Acquired Company has received any written notice of any currently pending actions for the assessment or collection of any material Taxes.
(d)There are no Encumbrances for material Taxes against any assets of the Acquired Companies or the Shares, other than Permitted Encumbrances.
(e)No claim that is currently unresolved has been made by any Governmental Entity in a jurisdiction where any Acquired Company does not file Tax Returns that such Acquired Company is subject to taxation by such jurisdiction.
(f)No Tax Proceeding with respect to any material Taxes of any Acquired Company is existing, pending or being threatened in writing.
(g)Each Acquired Company has materially complied with its obligations to deduct, withhold and timely pay to the appropriate Governmental Entity all Taxes required to have been deducted, withheld or paid in connection with amounts owing to any employee, former employee, independent contractor, creditor, stockholder or other third party, and each Acquired Company has materially complied with all reporting and record keeping requirements in respect of Taxes.
(h)No Acquired Company (i) currently has in effect a waiver of any statute of limitations in respect of Taxes or (ii) has agreed to any extension of time with respect to a Tax assessment or deficiency which extension is currently in effect (except for automatic extensions of time to file income Tax Returns obtained in the ordinary course of business).
(i)During the past six years, no Acquired Company (i) has been a member of a Tax group filing a consolidated, combined, unitary or similar Tax Return (other than the Seller Affiliated Tax Group), (ii) is a party to, or has an obligation under, any Tax sharing, Tax indemnification, or Tax allocation agreement or similar contract or arrangement (other than any Tax sharing agreement among the members of the Seller Affiliated Tax Group which, with respect to the Acquired Companies, shall be terminated on or before the Closing Date and any customary commercial contract entered into in the ordinary course of business the principal subject of which is not Taxes) and (iii) has liability for the Taxes of any other Person except for a member of the Seller Affiliated Tax Group under Treasury Regulations Section 1.1502-6 (or any similar provision of state, local or foreign Law), as a transferee or successor, or by contract (other than any Tax sharing agreement among the members of the Seller Affiliated Tax Group which, with respect to the Acquired Companies, shall be terminated on or before the Closing Date and any customary commercial contract entered into in the ordinary course of business the principal subject of which is not Taxes).
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(j)No Acquired Company will be required to include any material amounts in income, or exclude any material items of deduction, in a taxable period (or portion thereof) beginning after the Closing Date as a result of (i) a change in (or incorrect method of) accounting occurring prior to the Closing, (ii) an installment sale or open transaction arising in a taxable period (or portion thereof) ending on or before the Closing Date, (iii) a prepaid amount received, or paid, prior to the Closing, (iv) a “closing agreement” as described in Section 7121 of the Code (or any corresponding or similar provision of state or local income Tax Law) executed on or prior to the Closing Date, or (v) any intercompany transactions or any excess loss account described in Treasury Regulations under Section 1502 of the Code (or any corresponding or similar provision of state or local income Tax Law). No Acquired Company has made an election under Section 965 of the Code.
(k)No Acquired Company has participated in nor has any liability or obligation with respect to any “listed transaction” within the meaning of Treasury Regulations Section 1.6011-4.
(l)During the two-year period ending on the date hereof, no Acquired Company has been a “distributing corporation” or a “controlled corporation” within the meaning of Section 355(a)(1)(A).
(m)Each Acquired Company has collected all material sales and use Taxes required to be collected, and has remitted, or will remit on a timely basis, such amounts to the appropriate governmental authorities, or has been furnished properly completed exemption certificates.
2.16Environmental Matters. Except for such matters that would not reasonably be expected to have, individually or in the aggregate, a Material Adverse Effect:
(a)All Environmental Permits that are necessary for the operation of the business of each Acquired Company as it is currently being operated have been obtained or timely applied for and are in full force and effect, and there is no reasonable basis for any revocation, non-issuance, non-renewal or adverse modification of any such Environmental Permit; and each Acquired Company is in compliance with the requirements of all, and since January 1, 2018 has not violated any, applicable Environmental Laws.
(b)Except for matters that have been fully resolved with no further obligation or are set forth on Section 2.16(b) of the Sellers Disclosure Letter, neither Acquired Company is subject to any consent decree, agreement, or Order with any Governmental Entity or any other Person arising under Environmental Laws or regarding any Hazardous Material, and neither Acquired Company has received any written notice from a Governmental Entity regarding any unresolved actual or alleged violation of Environmental Laws.
(c)Except as set forth on Section 2.16(c) of the Sellers Disclosure Letter, there is and has been no Release by any Acquired Company from, in, or on any of the Real Property (except as authorized under Environmental Laws or Environmental Permits) or at any other location for which any Acquired Company may be liable that would reasonably be expected to result in an Environmental Claim against an Acquired Company, require investigation or remediation, or adversely affect the use of any Real Property in a manner consistent with the Acquired Company’s use of that property.
(d)Except as set forth on Section 2.16(d) of the Sellers Disclosure Letter, there are no Environmental Claims existing, pending, threatened in writing or, to the Knowledge of Sellers, threatened orally, against an Acquired Company that have not been fully and finally resolved with no further obligation.
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(e)Except as set forth on Section 2.16(e) of the Sellers Disclosure Letter, no Acquired Company has assumed or retained as a result of any Contract any liability under any Environmental Law or regarding any Hazardous Materials.
(f)Sellers have made available to Purchaser all material reports of any environmental or health and safety audits performed since January 1, 2018, environmental site assessments, environmental investigations, environmental remediation, environmental impact reviews, or other similar documents containing material information regarding any Acquired Company, the Real Property, or any other location for which any Acquired Company may be liable, to the extent within the possession or control of Sellers or any Acquired Company.
2.17Brokers. Except for Barclays Capital Inc. and Goldman Sachs & Co. LLC, no broker, investment banker, financial advisor or other Person is entitled to any broker’s, finder’s, financial advisor’s or other similar fee or commission in connection with the transactions contemplated by this Agreement based upon arrangements made by or on behalf of an Acquired Company or Sellers or any of their respective Affiliates.
2.18Regulatory Matters. Kentucky Power is a “Utility” as defined in Kentucky Revised Statutes KRS Chapter 278.010 and is subject to regulation as a “Utility” pursuant to the rules and regulations promulgated by the KPSC. Each of Kentucky Power and Kentucky TransCo is a “public utility” pursuant to Part II of the FPA and subject to regulation as a “public utility” under the FPA and pursuant to the rules and regulations promulgated by FERC.
2.19Insurance. Section 2.19 of the Sellers Disclosure Letter sets forth a true and complete list of all insurance policies (other than title insurance policies) covering the Acquired Companies or their assets or operations. True and complete copies of all such policies have been made available to Purchaser or will be made available to Purchaser upon request prior to the Closing Date. Except as would not reasonably be likely, individually or in the aggregate, to have a Material Adverse Effect, (i) each Acquired Company is insured with reputable insurers or is self-insured against such risks and in such amounts as Sellers reasonably have determined to be consistent with Good Utility Practice, and the Sellers and each Acquired Company are in compliance in all material respects with each such insurance policy and are not in default under any such policy, (ii) each such policy is in full force and effect, (iii) all premiums have been paid in full when due, (iv) all matters that are the subject of claims under insurance policies covering the Acquired Companies or their assets or operations have been properly notified, asserted and submitted pursuant to the terms of such policies and no insurer has denied coverage for any such claim and (v) no written notice of cancellation, termination or nonrenewal (other than written notice of nonrenewals issued by insurers in the ordinary course of business that would not reasonably be expected to result in any gap in coverage for the Acquired Companies or their assets or operations) has been received by Sellers or an Acquired Company with respect to any such insurance policy.
2.20Anti-Corruption; Trade Compliance and Economic Sanctions.
(a)Each Acquired Company and each of their respective directors, managers, officers, and employees (each, an “Acquired Company Representative”) is and at all times has been, and to such Persons’ knowledge, their agents and other Persons when acting on their behalf pursuant to a legal relationship have been, in compliance in all material respects with the U.S. Foreign Corrupt Practices Act of 1977, as amended, and all other anti-corruption and anti-bribery laws of all jurisdictions in which the Acquired Companies conduct business.
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(b)Each Acquired Company and each Acquired Company Representative is and at all times has been in compliance in all material respects with all applicable Laws pertaining to trade and economic sanctions and export controls, including such laws and regulations administered and enforced by the U.S. Department of the Treasury’s Office of Foreign Assets Control, the U.S. Department of State’s Directorate of Defense Trade Controls, and the U.S. Department of Commerce’s Bureau of Industry and Security (collectively, “U.S. Trade Controls”).
(c)No Acquired Company or any Acquired Company Representative is: (i) located, organized, resident or operating in a country or territory that is currently the target of a comprehensive trade embargo by the U.S. government (currently, Cuba, Iran, North Korea, Syria, and the Crimea region of Ukraine) (each, a “Sanctioned Country”); (ii) the target of restrictions on trade by reason of U.S. Trade Controls, including being identified on a U.S. Government denied, debarred or otherwise prohibited party list, such as, without limitation, the Specially Designated Nationals (“SDN”) and Blocked Persons List, the Entity List, or the Denied Persons List, or is owned 50% or more by any of the foregoing (collectively, a “Prohibited Party”); or (iii) engaged in dealings or transactions in or with a Sanctioned Country or Prohibited Party in violation of U.S. Trade Controls.
2.21No Other Representations or Warranties. Except for the representations and warranties expressly set forth in this Article II or in the Ancillary Agreements, neither Sellers nor any other Person on behalf of Sellers has made or shall be deemed to have made, and Sellers hereby expressly disclaim and negate, any other express or implied representation or warranty whatsoever (whether at Law (including at common law or by statute) or in equity) with respect to Sellers or the Acquired Companies or any matter relating to any of them, including their respective businesses, affairs, assets, liabilities, financial condition or results of operations, or with respect to the accuracy or completeness of any other information made available to Purchaser or any of its Representatives by or on behalf of Sellers, and any such representations or warranties are expressly disclaimed. Each Seller acknowledges and agrees that, except for the representations and warranties contained in Article III or in the Ancillary Agreements, neither Purchaser nor any other Person on behalf of Purchaser has made or makes, and such Seller has not relied upon, any representation or warranty, whether express or implied, with respect to Purchaser or its Affiliates or any matter relating to any of them, including their respective businesses, affairs, assets, liabilities, financial condition or results of operations, or with respect to the accuracy or completeness of any other information made available to such Seller or any of its Representatives by or on behalf of Purchaser, and that any such representations or warranties and rights or claims relating thereto are expressly disclaimed.
ARTICLE III
REPRESENTATIONS AND WARRANTIES
OF PURCHASER

Except as set forth in the disclosure letter delivered to Sellers in connection with the execution of this Agreement (the “Purchaser Disclosure Letter”), Purchaser hereby represents and warrants to each Seller as follows:
3.1Organization and Qualification. Purchaser is an entity duly organized, validly existing and in good standing under the Laws of Delaware. Purchaser has all requisite corporate power and authority to carry on its businesses as now being conducted and is qualified to do business and is in good standing as a legal entity in each jurisdiction where the conduct of its business requires such qualification, except for any such failures that would not reasonably be expected to have, individually or in the aggregate, a Purchaser Material Adverse Effect.
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3.2Authority Relative to this Agreement. Purchaser has all necessary power and authority to execute, deliver and perform this Agreement and the Ancillary Agreements to which it is or shall at Closing be a party and to consummate the transactions contemplated by this Agreement and the Ancillary Agreements to which it is or shall at Closing be a party in accordance with the terms hereof and thereof. The execution, delivery and performance by Purchaser of this Agreement and the Ancillary Agreements to which it is or shall at Closing be a party, and the consummation of the transactions contemplated hereby and thereby, have been, or shall be prior to the Closing, duly and validly authorized by all necessary action on part of Purchaser, and no other proceedings on the part of Purchaser are, or shall be as of immediately preceding the Closing, necessary to authorize the execution, delivery and performance, as applicable, of this Agreement. This Agreement has been duly and validly executed and delivered by Purchaser, and, assuming the due authorization, execution and delivery of this Agreement by Sellers, constitutes, and each Ancillary Agreement to which Purchaser is or shall at Closing be a party, when executed and delivered by Purchaser and/or its applicable Affiliate party thereto, and, assuming the due authorization, execution and delivery of such Ancillary Agreement by the applicable member of the Seller Group, shall constitute, a valid, legal and binding agreement of Purchaser and/or its applicable Affiliates, enforceable against Purchaser and/or such Affiliates in accordance with its terms, subject to the Enforceability Exceptions.
3.3Consents and Approvals; No Violations. No filing with or notice to, and no consent or approval of, any Governmental Entity is required to be obtained or made on the part of Purchaser or any of its Affiliates for the execution, delivery and performance by Purchaser and/or its Affiliates, as applicable, of this Agreement or any Ancillary Agreement to which such Person is or shall at Closing be a party or the consummation by Purchaser and/or its Affiliates, as applicable, of the transactions contemplated hereby or thereby, other than (a) the Required Regulatory Approvals, (b) the Mitchell Plant Approvals, (c) the Additional Regulatory Filings and Consents, (d) notice and judicial approval of a modification to the NSR Consent Decree, or (e) any permit, declaration, filing, authorization, registration, consent or approval, of which the failure to make or obtain would not reasonably be expected to have, individually or in the aggregate, a Purchaser Material Adverse Effect. Assuming compliance with the items described in clauses (a) through (e) of the preceding sentence, neither the execution, delivery or performance by Purchaser and/or their Affiliates, as applicable, of this Agreement or any Ancillary Agreement to which such Person is or shall at Closing be a party, nor the consummation by Purchaser and/or its Affiliates, as applicable, of the transactions contemplated hereby or thereby shall (i) conflict with or result in any breach or violation of any provision of Purchaser’s Organizational Documents, (ii) result in a breach or violation of, or constitute (with or without due notice or lapse of time or both) a default (or give rise to the creation of any Encumbrance, except for Permitted Encumbrances, or any right of termination, amendment, cancellation or acceleration) under, any of the terms, conditions or provisions of any material Contract or material Permit to which Purchaser or any of its assets, rights, properties or business is bound or (iii) violate any Law applicable to, or result in the creation of any Encumbrance (other than for Permitted Encumbrances) upon, Purchaser or any of its rights, properties, business or assets, except, in the case of clauses (ii) or (iii), for breaches, violations, defaults, Encumbrances or rights of termination, amendment, cancellation or acceleration that would not reasonably be expected to have, individually or in the aggregate, a Purchaser Material Adverse Effect.
3.4Legal Proceedings. There is no Action existing, pending or, to the Knowledge of Purchaser, threatened in writing, against Purchaser except as would not reasonably be expected to have, individually or in the aggregate, a Purchaser Material Adverse Effect. No Order has been imposed on Purchaser except as would not reasonably be expected to have, individually or in the aggregate, a Purchaser Material Adverse Effect.
3.5Trade Compliance and Economic Sanctions.
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(a)Purchaser and its directors, managers, officers, employees, resellers, distributors, and any other Persons acting on behalf thereof, are and at all times have been, in compliance with all applicable Laws pertaining to trade and economic sanctions and export controls, including such laws and regulations administered and enforced by the U.S. Department of the Treasury’s Office of Foreign Assets Control, the U.S. Department of State Directorate of Defense Trade Controls, and the U.S. Department of Commerce Bureau of Industry and Security (collectively, “U.S. Trade Controls”).
(b)Neither Purchaser nor any of its directors, managers, officers, employees, nor any other Person acting on behalf thereof, is: (i) located, organized, resident or operating in a country or territory that is or may, from time to time be, the target of a comprehensive trade embargo by the U.S. government (a “Sanctioned Country”); (ii) the target of restrictions on trade by reason of U.S. Trade Controls, including being identified on a U.S. Government denied, debarred or otherwise prohibited party list, such as, without limitation, Specially Designated Nationals (“SDN”) and Blocked Persons List, owned fifty percent or more, in the aggregate, by one or more SDNs, Entity List, Denied Persons List, Nonproliferation Sanctions, Arms Export Control Act Debarred List (collectively, a “Prohibited Party”); or (iii) engaged in dealings or transactions in or with a Sanctioned Country or Prohibited Party in violation of U.S. Trade Controls.
3.6Brokers. Purchaser or one of its Affiliates shall be solely responsible for the fees and expenses of any broker, finder or investment banker entitled to any brokerage, finder’s or other fee or commission in connection with the transactions contemplated by this Agreement based upon arrangements made by or on behalf of Purchaser or any of its Affiliates.
3.7Financial Capability.
(a)Purchaser has available as of the Effective Date (including pursuant to one or more financing commitments), and shall have available on and after the Closing Date, as applicable, funds sufficient to pay the Purchase Price, all expenses and other amounts, payable pursuant to this Agreement and the payments described in Section 4.16, if and when required in accordance with the applicable Debt Agreement, and shall be able to pay all such amounts and otherwise perform the obligations of Purchaser under this Agreement. In no event shall the receipt or availability of any funds or financing by Purchaser or any of its Affiliates or any other financing or other transactions be a condition to any of Purchaser’s obligations hereunder.
(b)Purchaser has delivered to Sellers true, correct and complete copies of an executed, binding guaranty by Algonquin Power & Utilities Corp., a corporation organized under the Laws of Canada (the “Guarantor”), in favor of Sellers, dated as of even date herewith, which provides for a guaranty of certain obligations of Purchaser under this Agreement (the “Purchaser Guaranty”). The Purchaser Guaranty is a legal, valid and binding obligation of the Guarantor, is in full force and effect and is enforceable in accordance with the terms thereof against the Guarantor. The Purchaser Guaranty has not been amended or modified (and no waiver of any provision thereof has been granted), and the obligations and commitments contained in the Purchaser Guaranty have not been withdrawn or rescinded in any respect and no event has occurred that would result in any breach of violation of, or constitute a default under, the Purchaser Guaranty. Each Seller is an express beneficiary of the Purchaser Guaranty and is entitled to enforce the Purchaser Guaranty in accordance with its terms against the Guarantor.
(c)Assuming (1) the representations and warranties contained in Article II of this Agreement are true and correct (for these purposes, without giving effect to any “to the Sellers’ knowledge, “materiality” or “Material Adverse Effect” qualifications or exceptions therein) as of the date hereof and as of the Closing Date as though made on and as of the Closing Date (except to the extent such representations and warranties are made on and as of a specified date, in which case assuming the same continue on the
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Closing Date to be true and correct as of the specified date), (2) the Acquired Companies and Sellers have, prior to the Closing, complied in all material respects with their respective covenants contained in this Agreement, (3) the satisfaction of the conditions set forth in Article VII and (4) immediately prior to giving effect to the transactions contemplated by this Agreement, the Acquired Companies were able to pay their respective liabilities, including contingent and other liabilities, as they mature, after giving effect to the transactions contemplated by this Agreement, Purchaser and the Acquired Companies will, immediately following the Closing, (i) collectively, be able to pay their debts as such debts become due, (ii) have capital sufficient to carry out their respective businesses as now contemplated and (iii) own assets and properties having a value both at fair market valuation and at fair saleable value in the ordinary course of business greater than the amount required to pay their respective Indebtedness and other obligations as the same mature and become due.
3.8Investment Decision. Purchaser is acquiring the Shares for investment and not with a view toward or for the resale in connection with any distribution thereof, or with any present intention of distributing or selling such Shares. Purchaser acknowledges that the Shares have not been registered under the Securities Act or any other federal, state, foreign or local securities Law, and agrees that such Shares may not be sold, transferred, offered for sale, pledged, distributed, hypothecated or otherwise disposed of without registration under the Securities Act, except pursuant to an exemption from such registration available under the Securities Act, and in compliance with any other federal, state, foreign or local securities Law, in each case, to the extent applicable. Purchaser is an “accredited investor” within the meaning of Rule 501(a) of the Securities Act, is able to bear the economic risk of holding the Shares for an indefinite period and has sufficient knowledge and experience in financial and business matters so as to be capable of evaluating the merits and risk of its investment in the Shares.
3.9Independent Investigation. Purchaser has such knowledge and experience in financial and business matters of this type and in the businesses of the Acquired Companies as is required for evaluating the merits and risks of its purchase of the Shares and is capable of such evaluation. Purchaser acknowledges and agrees that it has conducted its own independent review and analysis, and, based thereon, has formed an independent judgment concerning the businesses, affairs, assets, liabilities, conditions, results of operations and prospects of the Acquired Companies. Purchaser acknowledges that it has conducted due diligence that it deems appropriate, including a review of the documents contained in a data room prepared by or on behalf of Sellers and the Acquired Companies, that Sellers have made available to Purchaser such documents, records and books pertaining to the Acquired Companies that Purchaser or its Representatives have requested, and Purchaser has had the opportunity to visit the Acquired Companies, its facilities, plants, offices and other properties and ask questions and receive answers to Purchaser’s satisfaction concerning the Acquired Companies and the terms and conditions of this Agreement.
3.10No Other Representations or Warranties; No Reliance. Except for the representations and warranties expressly set forth in this Article III or in the Ancillary Agreements, none of Purchaser or any other Person on behalf of Purchaser has made or shall be deemed to have made, and Purchaser hereby expressly disclaims and negates any other express or implied representation or warranty whatsoever (whether at law (including at common law or by statute) or in equity) with respect to Purchaser, its Affiliates or any matter relating to any of them, including their respective businesses, affairs, assets, liabilities, financial condition or results of operations, or with respect to the accuracy or completeness of any other information provided to Sellers or any of its Representatives by or on behalf of Purchaser, and any such representations or warranties are expressly disclaimed. In connection with the due diligence investigation of the Acquired Companies by Purchaser, Purchaser has received and may continue to receive from the Acquired Companies certain projections, forecasts, estimates or budgets made available to Purchaser or any of their Representatives of future revenues, future results of operations (or any component thereof), future cash flows or future financial condition (or any component thereof) of Sellers or their Affiliates. Purchaser
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acknowledges and agrees that (a) there are uncertainties inherent in attempting to make such projections and other forecasts and plans, (b) Purchaser is familiar with such uncertainties, (c) Purchaser is taking full responsibility for making its own evaluation of the adequacy and accuracy of all projections and other forecasts and plans so furnished it to it, and (d) except for the representations and warranties contained in Article II or in the Ancillary Agreements, neither Sellers nor any other Person on behalf of Sellers has made or makes, and Purchaser has not relied upon, any representation or warranty, whether express or implied, with respect to the Acquired Companies, Sellers or their Affiliates or any matter relating to any of them, including their respective businesses, affairs, assets, liabilities, financial condition or results of operations, or with respect to the accuracy or completeness of any other information made available to Purchaser or any of its Representatives by or on behalf of Sellers, and that any such representations or warranties and rights or claims relating thereto are expressly disclaimed.
ARTICLE IV
ADDITIONAL AGREEMENTS
4.1Conduct of Business.
(a)Except (1) as contemplated in this Agreement (including, for the avoidance of doubt, the actions described in Section 4.8 and Section 4.20), as required by applicable Law, or as required by a Governmental Entity (including pursuant to an Order issued by FERC, the KPSC or the WVPSC), (2) actions reasonably necessary under emergency circumstances, including operational emergencies, failures of facilities or outages, or other unforeseen operational emergencies (provided that Sellers shall provide notice to Purchaser of any such event (including by providing reasonable details thereof) and action prior to taking any such action as may be reasonably practicable or, if such prior notice is not reasonably practicable, as soon as may be reasonably practicable thereafter), (3) for any COVID-19 Measures (provided, that Sellers shall notify Purchaser (including by providing reasonable details thereof) prior to taking any such COVID-19 Measure as may be reasonably practicable or, if such prior notice is not practicable, as soon as may be reasonably practicable thereafter), or (4) as otherwise described in Section 4.1(a) of the Sellers Disclosure Letter (provided, that any action taken pursuant to clauses (1) through (3) shall be taken in accordance with Good Utility Practice), during the period from the Effective Date through and including the Closing, Sellers shall, and shall cause each Acquired Company to, (x) operate the businesses of each Acquired Company in accordance with Good Utility Practice and in the ordinary course of business in all material respects consistent with past practice, use commercially reasonable efforts to preserve intact the properties, assets and businesses of each Acquired Company and preserve the goodwill and relationships of each Acquired Company with employees, customers, suppliers, and other parties having business dealings with each Acquired Company and (y) not, without the prior written consent of Purchaser (which consent shall not be unreasonably withheld, conditioned or delayed):
(i)sell, lease (as lessor), license (as licensor), assign, transfer, or otherwise dispose of any of the assets, rights or properties of an Acquired Company, other than (A) the use or sale of inventory in the ordinary course of business, (B) the disposal of obsolete assets or non-exclusive licensing of Intellectual Property, in each case, with immaterial book value in the ordinary course of business, (C) pursuant to obligations under Material Contracts with third parties in effect on the Effective Date, (D) sales of customer and credit card receivables to AEP Credit, Inc. in connection with its receivables financing program in the ordinary course of business, (E) in connection with settlements, compromises, consent decrees or settlement agreements otherwise permitted under this Section 4.1(a), (F) the sale, assignment, transfer or conveyance of the Mitchell Assets to Successor Operator pursuant to Section 4.20 or any sale, assignment, transfer or conveyance of the Mitchell Interest to Wheeling in accordance with the Mitchell Plant Ownership Agreement, (G) the disposal of assets of an Acquired Company, in either case,
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having an aggregate value of less than $5,000,000 in the ordinary course of business or (H) the transfer, sale or disposal of spare parts to an Affiliate in compliance with applicable Law in the ordinary course of business in an amount not to exceed $5,000,000 in the aggregate;
(ii)acquire (including by merger, consolidation or acquisition of a material amount of stock or assets or any other business combination) any business, division or all or substantially all of the capital stock (or other equity interests), assets, properties or rights of any Person or otherwise make any investments in any Person;
(iii)enter into, assign, materially amend, grant any material waiver or consent under or voluntarily terminate any Material Contract or any Contract that would, if in effect on the Effective Date, be a Material Contract or that would involve expenditures by an Acquired Company or payments to an Acquired Company in excess of $5,000,000 in the aggregate in any 12-month period that is not terminable by the applicable Acquired Company upon less than 180 days’ notice without penalty, or terminate, assign, relinquish any material rights under, or amend any of the Material Contracts (other than, except with respect to the “Joint Use Operating Agreement” (as defined in Section 4.20(e) of the Seller Disclosure Letter), (A) with respect to terminations, assignments, relinquishments, amendments, or grants of any material waiver or consent in the ordinary course of business, (B) Intercompany Arrangements to be terminated, severed, withdrawn or replaced prior to the Closing pursuant to Section 4.8(a), (C) Contracts that shall be performed prior to the Closing, (D) Contracts entered into in the ordinary course to replace an existing Contract, in whole or in part, on substantially similar terms as such existing Contract at current market prices, (E) Commercial Hedges with a term of less than 18 months that are entered into in the ordinary course of business, (F) any Contract entered into, assigned or amended to the extent strictly necessary to effect any action otherwise expressly permitted pursuant to the other provisions of this Section 4.1(a)) and (G) the Mitchell Plant Ownership Agreement and the Mitchell Plant O&M Agreement in accordance with the terms of this Agreement);
(iv)except as may be required by any Seller Benefit Plan as in effect on the Effective Date or as required by any Collective Bargaining Agreement or as expressly contemplated by Article V, (A) materially increase the compensation or benefits of any Acquired Company Employee (excluding (x) increases in salaries, wages and benefits of, or payments of bonuses or other grants or awards made to, such Acquired Company Employees in the ordinary course of business (including in connection with general merit-based increases) or (y) as expressly contemplated by Article V); (B) hire, terminate or transfer into or out of the Business any Acquired Company Employee at the Vice President level (or its equivalent) or higher or any Acquired Company Employee who performs material services for the Business (other than the Mitchell Employees as contemplated by Section 4.20 or employees set forth on Section 5.2 of the Sellers Disclosure Letter); (C) grant any severance or termination pay to any Acquired Company Employee, other than in the ordinary course of business, or (D) loan or advance any money or any other property to any Acquired Company Employee except pursuant to any Seller Benefit Plan;
(v)[Reserved];
(vi)implement or announce any employment-site closings or reductions-in-workforce involving or relating to the Acquired Companies reasonably expected to result in employment losses among the Acquired Employees sufficient to trigger the notice requirements of the WARN Act;
(vii)(A) amend any Acquired Company’s Organizational Documents (except for immaterial or ministerial amendments), (B) adjust, split, reverse split, combine, subdivide, reclassify, redeem, repurchase or otherwise acquire, directly or indirectly, any capital stock or equity interest in an Acquired Company or make any other change with respect to the capital structure of any Acquired
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Company, or (C) declare, set aside, make or pay any non-cash dividend or non-cash distribution to any Person with respect to an Acquired Company;
(viii)create, incur, assume or guarantee Indebtedness of an Acquired Company, except for borrowings incurred in the ordinary course of business (A) under an Acquired Company’s existing credit facilities up to the current limits thereof, (B) under the Utility Money Pool Agreement, and (C) under the Debt Agreements;
(ix)cancel any third party Indebtedness owed to any Acquired Company or waive any claims or rights with respect to such Indebtedness except in the ordinary course of business in an amount up to $3,000,000 in the aggregate;
(x)issue, sell, grant, encumber, pledge or dispose of, or agree or authorize to issue, sell, grant, encumber, pledge or dispose of, any equity or voting securities or interests, or any options, warrants, securities convertible, exchangeable or exercisable for, or other rights of any kind to acquire, any shares of an Acquired Company’s capital stock, including the Shares, or other equity or voting securities or interests or rights of any kind of any Acquired Company or any debt securities which are convertible into or exchangeable for such capital stock or equity securities or interests of any Acquired Company;
(xi)make any material change in financial accounting methods, principles or practices of an Acquired Company, except (A) as required by any change in GAAP or FERC Accounting Requirements, as applicable (or any interpretation thereof) or (B) for any change required to be made under GAAP or FERC Accounting Requirements, as applicable, or applicable Law to the consolidated financial accounting methods, principles or practices of the Seller Group as a whole;
(xii)make any materially adverse change to the security or operations of the IT Assets;
(xiii)except as required by applicable Law, and other than with respect to items reflected on Tax Returns of the Seller Affiliated Tax Group and Taxes for which Sellers are responsible pursuant to the terms of this Agreement, (A) change any Tax accounting period, (B) adopt or change any method of Tax accounting, (C) make, change or revoke any material Tax election, (D) settle or compromise any audit, Action or assessment in respect of a material amount of Taxes, (E) apply for any Tax ruling, (F) amend, in any material respect, any material Tax Return, (G) request or surrender any right to claim a refund of a material amount of Taxes, or (H) consent to any extension or waiver of the limitation period applicable to any Taxes of the Acquired Companies, in each case, if such action would have a material detrimental effect on Purchaser or, after the Closing, an Acquired Company;
(xiv)dissolve, adopt a plan of complete or partial liquidation, or effect a merger, consolidation, restructuring, reorganization or recapitalization, with respect to an Acquired Company;
(xv)(A) settle, discharge or compromise any Action (except for any Action in connection with obtaining the Mitchell Plant Approvals in accordance with this Agreement or involving monetary damages to be paid by an Acquired Company in excess of $3,000,000 in the aggregate without any admission of guilt, injunctive or other equitable relief) or (B) enter into any material Order, consent decree or settlement agreement with any Governmental Entity, in each case of clauses (A) and (B), in any way relating to the business of an Acquired Company, including with respect to any Rate Proceeding;
(xvi)subject any material asset of an Acquired Company to any Encumbrance, other than Permitted Encumbrances or Encumbrances that shall be released at or prior to the Closing;
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(xvii)engage in any material new line of business;
(xviii)cancel, terminate, cause to lapse or otherwise fail to maintain any insurance policy as in effect on the date hereof covering an Acquired Company unless such insurance policy is replaced with a commercially reasonable replacement insurance policy consistent with Good Utility Practice with no gap in coverage; or
(xix)agree or commit to do or take any action described in this Section 4.1(a).
(b)Nothing contained in this Agreement shall give Purchaser, directly or indirectly, the right to control or direct Sellers’ or any of their Affiliates’ (including, prior to the Closing, an Acquired Company’s) businesses or operations.
(c)Notwithstanding anything herein to the contrary, the Acquired Companies may incur capital expenditures (i) up to the aggregate amount and for the express purposes reflected in the capital plan set forth in Section 4.1(c) of the Sellers Disclosure Letter, plus an amount that is equal to fifteen percent (15%) above such aggregate amount; or (ii) with respect to which the applicable Seller has not received a written objection from Purchaser within ten (10) Business Days after a written request by such Seller for approval of such capital expenditures.
(d)Purchaser acknowledges that certain of the Collective Bargaining Agreements applicable to the Covered Employees may expire prior to the Closing and that such agreements cover employees of companies in the Seller Group in addition to those which are employed by or perform services for the Acquired Companies. Sellers shall keep Purchaser reasonably informed of the status and proposed terms of such negotiations, extensions or renewals, as the case may be (and reasonably consider in good faith Purchaser’s comments in respect thereof, to the extent applicable to any Covered Employees). In the event that (i) any amendment, modification, extension or replacement of any Collective Bargaining Agreements that apply to employees of Sellers or their Affiliates (including the Covered Employees) contains terms and conditions that are reasonably likely to have a material disproportionate and adverse effect on the Acquired Companies with respect to the Covered Employees as compared to similarly situated employees of other Affiliates of the Sellers, or (ii) any material amendment, modification, extension or replacement of any Collective Bargaining Agreement that is applicable solely to Covered Employees (as opposed to Collective Bargaining Agreements that apply to other employees of Sellers or their Affiliates, other than the Covered Employees) contains terms and conditions that differ in any material or adverse respect from the existing Collective Bargaining Agreements applicable to the Covered Employees that are in effect on the Effective Date, any such amendment, modification, extension or replacement described in the foregoing clauses (i) or (ii) shall be subject to Purchaser’s prior written consent, such consent not to be unreasonably withheld, conditioned or delayed.
(e)If the Mitchell Plant Ownership Agreement or the Mitchell Plant O&M Agreement becomes effective prior to Closing, none of Sellers or any of their Affiliates (including any Acquired Company) shall (i) effect or consent to any waiver, amendment or modification thereunder or take any action thereunder that would require the consent of Kentucky Power or the Operating Committee (as defined in the Mitchell Plant Ownership Agreement) and that, in each case, would affect the rights, obligations or operations of Purchaser or its Affiliates (including any Acquired Company) at any time from and after Closing or (ii) adopt or agree to (including in connection with the execution or effectiveness of the Mitchell Plant Ownership Agreement or the Mitchell Plant O&M Agreement) or amend either (A) the Capital Budget, the initial annual operating budget or the initial forecast contemplated by the Mitchell Plant Ownership Agreement or (B) the Budget and Plan contemplated by the Mitchell Plant O&M Agreement,
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in each case of clauses (i) and (ii), without the prior written consent of Purchaser, which consent shall not be unreasonably withheld, conditioned or delayed.
(f)As soon as practicable following the Effective Date and prior to the Closing, the Parties shall negotiate in good faith and take the actions described on Section 4.1(f) of the Sellers Disclosure Letter.
4.2Access to Information.
(a)Sellers shall, and shall cause the Acquired Companies to, during ordinary business hours and upon reasonable advance written notice (i) give Purchaser and its Representatives reasonable access to the personnel, assets, facilities and books and records of each of the Acquired Companies and (ii) permit Purchaser and its Representatives to make such reasonable inspections thereof as Purchaser may reasonably request; provided, however, that (A) any such inspection shall be conducted in such a manner as not to materially interfere with the operations of the Sellers, the applicable Acquired Company or any other member of the Seller Group, and (B) neither Sellers nor an Acquired Company shall be required to take any action which would constitute or result in a waiver of its attorney-client privilege or violate any Contract or applicable Law; provided, further, that if any event set forth in clauses (A) and (B) in the foregoing proviso would be reasonably likely to occur, the Sellers shall collaborate with Purchaser in good faith to make alternative arrangements to allow for such inspection in a manner that does not result in such event. Purchaser shall indemnify and hold harmless Sellers from and against any Losses incurred by Sellers, their Affiliates or its or their Representatives to the extent resulting from any action of Purchaser or its Representatives while present on any premises to which Purchaser is granted access hereunder. Notwithstanding anything in this Section 4.2(a) to the contrary, (x) Purchaser shall not have access to personnel records if such access could, in the applicable Seller’s good-faith judgment, violate applicable Law, including the Health Insurance Portability and Accountability Act of 1996, and (y) any inspection relating to environmental matters by or on behalf of Purchaser shall be strictly limited to visual inspections and site visits commonly included in the scope of “Phase 1” level environmental inspections, and Purchaser shall not have the right to collect any air, soil, surface water or ground water samples or perform any invasive or destructive air sampling on, under, at or from any of the Real Property.
(b)Unless otherwise provided in the Transition Services Agreement, each Seller shall deliver to Purchaser or an Acquired Company the books and records of each Acquired Company in the possession or control of such Seller or any of its Affiliates (and not in the possession of an Acquired Company) as promptly as practicable following the Closing Date (it being agreed that such Seller may retain a copy thereof, at such Seller’s sole cost and expense, subject to its confidentiality obligations in accordance with Section 4.3). For a period of seven (7) years after the Closing Date, each Party and its Representatives shall have reasonable access to all of the books and records relating to the Acquired Companies in the possession of the other Parties, and to the employees of the other Parties, to the extent that such access may reasonably be required by such Party in connection with any Action and to the extent permitted under applicable Law. Such access shall be afforded by the applicable Party upon receipt of reasonable advance notice and during normal business hours and shall be conducted in such a manner as not to materially interfere with the operation of the business of any Party or its respective Affiliates. The Party exercising the right of access hereunder shall be solely responsible for any costs or expenses incurred by any Party in connection therewith. Each Party shall retain such books and records for a period of seven (7) years from the Closing Date.
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4.3Confidentiality.
(a)For a period of two (2) years following the Closing, Purchaser shall, and shall cause its Affiliates and Purchaser’s Representatives to, hold all of Sellers’ Confidential Information in strict confidence and not disclose any of Sellers’ Confidential Information to any Person other than its Affiliates and its and their respective Representatives; provided, however, that upon the Closing, the provisions of (i) this Section 4.3 and (ii) the Confidentiality Agreement shall, in each case, expire with respect to any information to the extent related to the Acquired Companies (“Company Confidential Information”); provided, further, that nothing in this Agreement or the Confidentiality Agreement shall limit the disclosure by Purchaser or its Affiliates or its or their respective Representatives of any information or documents (i) to the extent required by Law, judicial process or the rules or policies of any applicable stock exchange, or requested by any Governmental Entity (provided, that if permitted by Law, Purchaser agrees to give Sellers prior written notice of such disclosure in sufficient time to permit Sellers to obtain a protective order should it so determine and Purchaser, its Affiliates and each of their respective Representatives shall cooperate with Sellers in such effort), (ii) in any Claim brought by a Party in pursuit of its rights or in the exercise of its remedies under this Agreement, (iii) to the extent that such documents or information can be shown to have come within the public domain other than as a result of a disclosure by Purchaser or its Affiliates or its or their respective Representatives in violation of this Agreement, (iv) to the extent that such documents or information can be shown to have become available to Purchaser from a source other than Sellers, their Affiliates or their Representatives that such Purchaser reasonably believes is not prohibited from disclosing such information by a legal, contractual or fiduciary obligation (provided, that such documents or information was not in the possession of Purchaser, its Affiliates or its or their respective Representatives prior to the Closing), (v) developed or derived independently by Purchaser without the aid, application or use of such information or documents or (vi) to the extent permitted in accordance with Section 4.7.
(b)If this Agreement is terminated pursuant to Section 8.1, the Confidentiality Agreement shall automatically be deemed to be amended and restated such that the provisions of the Confidentiality Agreement shall remain in full force and effect for a period of two (2) years after such termination, as if the Parties had never entered into this Agreement.
(c)If the Closing occurs, for a period of two (2) years following the Closing, each Seller will hold, and will cause its Affiliates and its and their Representatives to hold, in strict confidence and not disclose any information or documents relating to any Acquired Company and its business; provided, that nothing in this sentence shall limit the disclosure by any Seller or its Affiliates or its or their Representatives of any information or documents (i) to the extent required by Law, judicial process or the rules or policies of any applicable stock exchange, or requested by any Governmental Entity (provided, that if permitted by Law, such Seller agrees to give Purchaser prior written notice of such disclosure in sufficient time to permit Purchaser to obtain a protective order should it so determine and such Seller, its Affiliates and each of their respective Representatives shall cooperate with Purchaser in such effort), (ii) in any Claim brought by a Party in pursuit of its rights or in the exercise of its remedies under this Agreement, (iii) to the extent that such documents or information can be shown to have come within the public domain other than as a result of a disclosure by any Seller or its Affiliates or its or their respective Representatives in violation of this Agreement, (iv) to the extent that such documents or information can be shown to have become available to Sellers following Closing from a source other than Purchaser, its Affiliates or its or their Representatives that such Seller reasonably believes is not prohibited from disclosing such information by a legal, contractual or fiduciary obligation (provided, that such documents or information was not in the possession of any Seller, its Affiliates or its or their respective Representatives prior to the Closing), (v) developed or derived independently by such Seller without the aid, application or use of such information or documents or (vi) to any Tax authorities or Tax advisors to the extent such information or documents relate to the Seller Affiliated Tax Group.
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4.4Further Assurances. Subject to the terms and conditions of this Agreement, at any time or from time to time after the Closing, Sellers and Purchaser shall, and shall cause their respective Affiliates to, execute and deliver such other documents and instruments, provide such materials and information and take such other actions as may be reasonably requested by the requesting Party as necessary, proper or advisable, to the extent permitted by Law, to fulfill their obligations under this Agreement any Ancillary Agreement and to cause the Sale and other transactions contemplated hereby and thereby (including those contemplated under the Business Separation Plan) to occur.
4.5Required Actions.
(a)Sellers and Purchaser shall, and shall cause their respective Affiliates to, cooperate with each other and use reasonable best efforts to (i) submit to the KPSC and the WVPSC all required petitions, declarations and filings within sixty (60) days following the Effective Date in connection with the execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby, (ii) file with the United States Federal Trade Commission and the United States Department of Justice the Notification and Report Form under the HSR Act required in connection with the execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby within, unless otherwise agreed in writing by Sellers and Purchaser, sixty (60) days of the Effective Date, and as promptly as practicable supply additional information, if any, requested in connection herewith pursuant to the HSR Act, (iii) submit to FERC all filings necessary and required under the FPA pursuant to Section 203 of the FPA within sixty (60) days of the Effective Date in connection with the execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby, (iv) file a joint voluntary notice or declaration in respect of the transactions contemplated by this Agreement pursuant to the DPA within thirty (30) days of the Effective Date, and, after submission of the declaration, if (x) pursuant to 31 C.F.R. 800.407(a)(1), CFIUS requests that the Sellers and Purchaser file a joint voluntary notice or (y) pursuant to 31 C.F.R. 801.407(a)(2), CFIUS informs the Sellers and Purchaser that CFIUS is not able to complete action on the basis of the declaration and, in each case, if the Purchaser in its sole discretion determines to file a joint voluntary notice, then as soon as practicable thereafter but no later than thirty (30) days following the date of such notification from CFIUS, file a joint voluntary notice pursuant to the DPA for the purpose of receiving CFIUS Clearance as soon as practicable, (v) negotiate, prepare and file as promptly as reasonably practicable all other necessary applications, notices, petitions, and filings and execute all agreements and documents, to the extent required by Law in connection with the execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby (including with respect to the Required Regulatory Approvals and the Mitchell Plant Approvals), and (vi) obtain the consents, approvals, and authorizations of all Governmental Entities to the extent required by Law in connection with the execution, delivery and performance of this Agreement and the consummation of the transactions contemplated by this Agreement (including the Required Regulatory Approvals and the Mitchell Plant Approvals). Each Party shall, and shall cause its Affiliates to, consult and cooperate with the other Parties as to the appropriate time of all such filings and notifications, furnish to the other Parties such necessary information and reasonable assistance in connection with the preparation of such filings, and respond promptly to any requests for additional information made in connection therewith by any Governmental Entity. To the extent permitted under applicable Law, each of Sellers and Purchaser shall have the right to review in advance all characterizations of the information relating to it or to the transactions contemplated by this Agreement which appear in any filing made by the other Parties or any of their Affiliates in connection with the transactions contemplated hereby.
(b)Purchaser and Sellers, acting reasonably and in good faith, shall coordinate, and Sellers shall cause the Acquired Companies to coordinate, in the preparation and making of any applications and filings (including the content, terms and conditions of such applications and filings) with any
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Governmental Entity, the resolution of any investigation or other inquiry of any Governmental Entity, the process for obtaining any consents, registrations, approvals, permits and authorizations of any Governmental Entity (including the Required Regulatory Approvals, the Mitchell Plant Approvals and the Additional Regulatory Filings and Consents), and the making or discussing of any and all proposals relating to any regulatory commitments of Purchaser, Sellers, their respective Affiliates or business, or with any Governmental Entity, its staff, intervenors or customers, in each case, in connection with the execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby. Purchaser and Sellers, acting reasonably and in good faith, shall coordinate, and Sellers shall cause the Acquired Companies to coordinate, with respect to the scheduling and conduct of all meetings with Governmental Entities in connection with the transactions contemplated by this Agreement (including the Required Regulatory Approvals, the Mitchell Plant Approvals and the Additional Regulatory Filings and Consents); provided, however, to the fullest extent practicable and permitted by Law, in connection with any communications, meetings, or other contacts, oral or written, with any Governmental Entity in connection with the transactions contemplated by this Agreement (including the Required Regulatory Approvals, the Mitchell Plant Approvals and the Additional Regulatory Filings and Consents), each of Sellers and Purchaser shall (and shall cause its Affiliates to): (i) inform the other Parties in advance of any such communication, meeting, or other contact which such Party or any of its Affiliates proposes or intends to make, including the subject matter, contents, intended agenda, and other aspects of any of the foregoing; (ii) consult and cooperate with the other Parties, and take into account the comments of the other Parties in connection with any of the matters covered by Section 4.5(a); (iii) permit Representatives of the other Parties to participate in any such communications, meetings, or other contacts; (iv) notify the other Parties of any oral communications with any Governmental Entity relating to any of the foregoing; and (v) provide the other Parties with copies of all written communications with any Governmental Entity relating to any of the foregoing; provided, however, that any materials exchanged in connection with this Section 4.5 may be (x) redacted or withheld as necessary to address reasonable privilege or confidentiality concerns (including with respect to other businesses of Purchaser or Sellers or, in each case, their Affiliates), and to remove references concerning the valuation or other competitively sensitive material or (y) provided solely to the outside legal counsel of the other Party, to the extent any Party deems this to be advisable and necessary. Nothing in this Section 4.5 shall require Sellers to expend or relinquish financial resources (including any portion of the sale proceeds of the transactions contemplated herein) to obtain any consent, approval or termination of a waiting period contemplated by this Section 4.5. Purchaser shall take the lead on strategy with respect to the Parties’ efforts to obtain any necessary or advisable consents, clearances, non-objections, expiration or terminations of any waiting periods, authorizations or approvals of any Governmental Entity or under any Laws (including the Required Regulatory Approvals and the Additional Regulatory Filings and Consents), other than the Mitchell Plant Approvals, as contemplated hereby after considering in good faith all reasonable comments and advice of Sellers (and their counsel), and Sellers shall reasonably cooperate with Purchaser in connection therewith, including taking (and causing its Affiliates, including the Acquired Companies, to take) any actions reasonably requested by Purchaser consistent with this Section 4.5; provided, that, strategy and control with respect to the Mitchell Plant Approvals shall be governed by Section 4.20(d). Subject to and without limiting Section 4.1, Sellers shall take the lead on strategy with respect to any Rate Proceedings after considering and reflecting in good faith all reasonable comments and advice of Purchaser (and its counsel), and Purchaser shall reasonably cooperate with Sellers in connection therewith. With respect to the CFIUS submissions, Purchaser shall coordinate those submissions, but Sellers shall exclusively control information submitted with respect to Sellers, and the Parties shall agree upon any language or representations relating to the transactions contemplated by this Agreement before such information is submitted.
(c)Without limiting the foregoing, Purchaser shall not, and shall cause its Affiliates not to, take any action, including (i) acquiring or agreeing to acquire any asset, property, business or Person (by way of merger, consolidation, share exchange, investment, or other business combination, asset, stock
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or equity purchase, or otherwise) from any Person (other than from Sellers or their Affiliates) or agree to, solicit, offer, propose or recommend any of the foregoing, (ii) making any filing or (iii) any other action, that, in each case, could reasonably be expected to adversely affect in any material respect obtaining or making, or the timing of obtaining or making, any consent or approval or expiration or termination of a waiting period contemplated by this Section 4.5. In furtherance of and without limiting any of Purchaser’s covenants and agreements under this Section 4.5, Purchaser shall, and shall cause its Affiliates to use reasonable best efforts to take, or cause to be taken, any and all steps and to make, or cause to be made, any and all undertakings necessary to avoid or eliminate each and every impediment asserted by any Governmental Entity in connection with obtaining the Required Regulatory Approvals and the Mitchell Plant Approvals, in each case, so as to enable the Closing to occur as promptly as practicable, including (A) agreeing to conditions imposed by, or taking any action required by, any Governmental Entity, (B) defending through litigation on the merits any claim asserted in court by any party in order to avoid entry of, or to have vacated or terminated, any Order (whether temporary, preliminary or permanent) that would prevent the Closing from occurring prior to the Outside Date; provided, however, that such litigation in no way limits the obligation of Purchaser to use its reasonable best efforts, and to take any and all steps necessary, to eliminate each and every impediment and obtain all clearances, consents, approvals (including the Required Regulatory Approvals and the Mitchell Plant Approvals) and waivers under any antitrust, competition or trade regulation Law, the rules and regulations promulgated by the KPSC, the WVPSC, FERC or other Governmental Entity or any other applicable requirement of Law that is asserted by any Governmental Entity or any other party so as to enable the Parties hereto to promptly close the transactions contemplated hereby, and Sellers shall use their reasonable best efforts to support Purchaser in connection therewith, (C) proposing, negotiating, committing to and effecting, by consent decree, hold separate order or otherwise, (x) the sale, divestiture, licensing or disposition of any assets or businesses of Purchaser or its Affiliates or the Acquired Companies and entering into customary ancillary agreements relating to such sale, divestiture, licensing or disposition, or (y) the termination, relinquishment, modification, or waiver of existing relationships, ventures, contractual rights, obligations or other arrangements of Purchaser or its subsidiaries, as necessary in order to effect the dissolution of any injunction, temporary restraining order or other Order in any suit or proceeding, which would otherwise have the effect of preventing the consummation of the transactions contemplated by this Agreement prior to the date of termination of this Agreement, (D) entering into any relationships, ventures, contractual rights, obligations or other such arrangements, as necessary in order to effect the dissolution of any injunction, temporary restraining order or other order in any suit or proceeding, which would otherwise have the effect of preventing the consummation of the transactions contemplated by this Agreement prior to the date of termination of this Agreement and (E) agreeing to take any other action as may be required by a Governmental Entity in order to effect each of the following: (1) obtaining all Required Regulatory Approvals and Mitchell Plant Approvals as soon as reasonably practicable and in any event before the Outside Date, (2) avoiding the entry of, or having vacated, lifted, dissolved, reversed or overturned, any Order, whether temporary, preliminary or permanent, that is in effect that prohibits, prevents or restricts consummation of, or impedes, interferes with or delays, the Closing and (3) effecting the expiration or termination of any waiting period, which would otherwise have the effect of preventing, prohibiting or restricting consummation of the Closing or impeding, interfering with or delaying the Closing.
(d)Notwithstanding the foregoing or anything else in this Agreement to the contrary, Purchaser shall not be required to, in connection with obtaining the Required Regulatory Approvals, the Mitchell Plant Approvals or the Additional Regulatory Filings and Consents, take any action (including any of the actions listed in Section 4.5(c)) or agree to or accept any orders, actions, consents, clearances, non-objections, expiration or terminations of any waiting periods, authorizations or approvals or conditions of any Governmental Entity containing terms, conditions, liabilities, obligations, commitments or sanctions that would individually or in the aggregate reasonably be expected to have a material adverse effect on the Acquired Companies, taken as a whole (a “Burdensome Condition”); provided, that neither Sellers nor
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Purchaser shall be required to, and neither Sellers nor Purchaser shall, in connection with obtaining the Required Regulatory Approvals or the Additional Regulatory Filings and Consents, consent to the taking of any action or the imposition of any terms, conditions, limitations or standards of service the effectiveness or consummation of which is not conditional upon the occurrence of the Closing. Without the prior written consent of Purchaser (which consent, in connection with obtaining the Mitchell Plant Approvals, shall not be unreasonably withheld, conditioned or delayed), Sellers shall not, and shall not permit any of the Acquired Companies, in connection with obtaining any actions or non-actions, clearances, approvals, consents, waivers, registrations, permits, authorizations and other confirmations from any Governmental Entity (including the Required Regulatory Approvals, the Mitchell Plant Approvals and the Additional Regulatory Filings and Consents) in connection with this Agreement or the transactions contemplated herein, offer or agree to any undertaking, term, condition, liability, obligation, commitment or sanction that would reasonably be expected to be material and adverse to Purchaser’s ability to obtain the Required Regulatory Approvals, the Mitchell Plant Approvals and the Additional Regulatory Filings and Consents on substantially the terms that Purchaser reasonably expects; provided, that the foregoing limitations on Sellers apply solely to actions taken by Sellers and shall not in any manner impact the obligations of Purchaser pursuant to the remaining provisions of this Section 4.5, including Purchaser’s obligation to agree to any such undertaking, term, condition, liability, obligation, commitment or sanction in connection with the Required Regulatory Approvals and the Mitchell Plant Approvals to the extent required under this Section 4.5, subject in all instances to the limitation provided in the first sentence of this Section 4.5(d).
(e)In furtherance, and not in limitation, of Sections 4.5(a), 4.5(b) and 4.5(c), Sellers and Purchaser shall, and shall cause their respective Affiliates to, cooperate with each other and use reasonable best efforts to cause FERC to accept for filing pursuant to Section 205 of the FPA (“Section 205”) the items listed as subject to Section 205 on Section 2.4(a) of the Sellers Disclosure Schedule.
(f)Without limiting the other provisions of this Section 4.5, Purchaser hereby recognizes and acknowledges that the Acquired Companies and/or their Affiliates are subject to the jurisdiction and regulatory authority of the KPSC, WVPSC and FERC, as applicable, and that the Acquired Companies’ and/or their Affiliates’ business operations that are subject to the jurisdictions of the KPSC, WVPSC and FERC are ongoing and are contemplated to continue to be ongoing before and after the Effective Date and regardless of whether or not the Closing occurs. Notwithstanding anything to the contrary in this Section 4.5, nothing in this Section 4.5 is intended to, or has the meaning and purpose of, preventing in any way or degree the Acquired Companies’ or their Affiliates’ normal and ordinary practices and abilities to meet with or have conversations with the KPSC, WVPSC and FERC, as applicable, concerning the Acquired Companies’ or their Affiliates’ ongoing operations that are subject to the jurisdiction of the KPSC, WVPSC or FERC, respectively, separate and apart from the Required Regulatory Approvals, Mitchell Plant Approvals or the Additional Regulatory Filings and Consents. Without limiting the other provisions of this Section 4.5, Purchaser hereby recognizes and acknowledges that the Acquired Companies and/or their Affiliates, in the normal and ordinary course and scope of their meetings and conversations with the KPSC, WVPSC, and FERC concerning the Acquired Companies’ and/or their Affiliates’ ongoing operations, may be asked to discuss the transactions contemplated by this Agreement (including as to the potential effects of such transactions or the transactions contemplated by the Mitchell Plant Approvals on the ongoing operations under discussion) without Purchaser being present or participating in such discussions. In the event of such inquiries by the KPSC, WVPSC or FERC, without Purchaser’s participation in such discussions, Sellers promptly thereafter shall reasonably apprise Purchaser of such inquiries and related discussions concerning the transactions under this Agreement or the Mitchell Plant Approvals and coordinate on an appropriate response to the extent applicable. Sellers agree to provide Purchaser with timely updates as to the status of, and issues raised in, any such proceedings and consider and reflect any reasonable comments by Purchaser in responding to any material inquiry with respect thereto.
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4.6Additional Regulatory Filings and Consents. Sellers shall, and shall cause their Affiliates (including the Acquired Companies) to, reasonably cooperate with Purchaser to make or obtain the Additional Regulatory Filings and Consents, respectively, or, if applicable, any consents required from third parties in connection with the consummation of the transactions contemplated by this Agreement under Material Contracts or Permits at or prior to the Closing. Subject to such cooperation but otherwise notwithstanding anything to the contrary contained herein, neither Sellers nor Purchaser, nor any of their respective Affiliates, shall have any obligation to make any payments or incur any material Liability to obtain any consents of third parties contemplated by this Section 4.6. For the purposes of this Section 4.6, Sellers’ “reasonable cooperation” shall not include payment of any consideration (monetary or otherwise), the reduction of amounts owed to any such Seller in connection with obtaining any consent required by this Agreement or the concession or provision of any right to, or the amendment or modification in any manner materially adverse to a Seller.
4.7Public Announcements. Purchaser and Sellers shall consult with each other before issuing, and give each other a reasonable opportunity to review and comment upon, any press release or other written public statements with respect to this Agreement or any of the transactions contemplated hereby, including the Sale, and shall not issue any such press release or make any such written public statement prior to such consultation, except (and notwithstanding anything in the Confidentiality Agreement to the contrary) (a) as such party reasonably concludes (after consultation with outside counsel) to be required by applicable Law (including securities Laws, rules or regulations), court process or by obligations pursuant to any listing agreement with, or other applicable rules or regulations of, any national securities exchange or national securities quotation system (including the Toronto Stock Exchange), or (b) for the avoidance of doubt, for any disclosure by a Party or any of its Affiliates to its and their Representatives. For the avoidance of doubt, nothing contained in this Agreement shall limit a Party’s (or its respective Affiliates’) rights to disclose the existence of this Agreement and the general nature of the transaction described herein on any earnings call or in similar discussions with financial media or analysts, stockholders and other members of the investment community, provided that such disclosures are consistent in all material respects with disclosures previously made pursuant to this Section 4.7.
4.8Intercompany Arrangements, Intercompany Accounts and Shared Contracts.
(a)Subject to Section 4.9, Sellers shall, and shall cause their Affiliates to, subject to the receipt of applicable regulatory authorizations set forth on Section 4.8(a)(i) of the Sellers Disclosure Letter, (i) sever and terminate all transactions and Contracts (other than those existing or new Contracts identified on Section 4.8(a)(ii) of the Sellers Disclosure Letter) between any of the Acquired Companies, on the one hand, and each Seller and/or any of its Affiliates (other than the Acquired Companies), on the other hand (collectively, the “Intercompany Arrangements”) effective on or prior to the Closing and with no further Liabilities or obligations to the Acquired Companies or any of their Affiliates from and after the Closing, and (ii) provide any consents or other documentation reasonably required from Sellers or any of their Affiliates to effect the severance or termination of such Intercompany Arrangements. To the extent Sellers are unable to obtain any such applicable regulatory authorizations on or prior to the Closing with respect to any such Contract, the Closing shall not be affected, such Contract shall remain in full force and effect and the Parties shall use reasonable best efforts to obtain any applicable regulatory authorizations with respect to such Contract as soon as practicable after the Closing. Sellers actions with respect to Intercompany Arrangements set forth on Section 4.8(a)(ii) of the Sellers Disclosure Letter shall be as specified for those Intercompany Arrangements identified therein.
(b)In furtherance of the actions specified in Section 4.8(a) of the Sellers Disclosure Letter and as described in Section 4.8(b) of the Sellers Disclosure Letter, on and after the Closing, Purchaser shall cause (i) Kentucky Power to maintain itself as a “Load Serving Entity” under the PJM Market Rules
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until the completion of all remaining “Planning Periods” (as defined in the PJM Market Rules) for which Kentucky Power has committed to jointly participate in a “Fixed Resource Requirement Alternative” (as defined in the PJM Market Rules) with Affiliates of AEP and (ii)  for the period specified in clause (i), Kentucky Power’s transmission assets to remain included in the “AEP Zone” in accordance with Attachment H-14 of the PJM Tariff.
(c)Except as expressly contemplated in Section 4.16 and Section 4.8(a), Sellers shall be required to terminate, cancel, settle or otherwise eliminate any outstanding amounts or balances due or owing by or to the Acquired Companies, on the one hand, and Sellers or any of their Affiliates (other than the Acquired Companies), on the other hand, and any amounts or balances not terminated in accordance with the exception above and outstanding as of the Closing shall be settled following the Closing in the ordinary course of business consistent with the manner and timing in which such intercompany accounts and balances were paid or settled prior to the Closing, and such outstanding amounts or balances shall be reflected in the calculation of Closing Cash, Closing Indebtedness and Net Working Capital, as applicable. To the extent such amounts or balances remain outstanding for more than ninety (90) days after the Closing, the Parties shall cooperate to enter into one or more arrangements to apply reasonable arms’ length third-party terms (including payment terms and timing) to terminate, cancel, settle or otherwise eliminate such amounts or balances.
(d)During the Interim Period and for up to nine (9) months following the Closing, upon the written request of Purchaser, Sellers and Purchaser shall, and shall cause the Acquired Companies and their respective Affiliates to, use reasonable best efforts to replace the Acquired Companies’ interest in any Shared Contract with a stand-alone Contract for the Acquired Companies on comparable terms and conditions (taking into account, among other things, the relative sizes of such companies and their respective purchasing power) as applied to Sellers and their Affiliates and the business of the Acquired Companies, respectively, under the Shared Contract prior to Closing. In furtherance of the foregoing covenant, (i) Sellers shall provide Purchaser upon request with a list of vendors that are parties to Shared Contracts, (ii) at Purchaser’s request, Sellers shall use reasonable best efforts to assist Purchaser with entering into replacement Contracts with any such vendors and (iii) Sellers and Purchaser shall use reasonable best efforts to cooperate to execute and deliver commercially reasonable instruments and documents that are reasonably necessary to carry out the intent of providing the Acquired Companies with the benefits and burdens associated with such Shared Contracts to the extent relating to the business of the Acquired Companies, while simultaneously retaining the benefits and burdens of the Shared Contract for Sellers and their Affiliates relating to their businesses other than those of the Acquired Companies. For purposes of this Section 4.8(d), reasonable best efforts shall not require the payment of any consideration (monetary or otherwise) to, or the concession or provision of any material right to, or the amendment or modification in any manner materially adverse to Purchaser or its Affiliates (including the Acquired Companies for these purposes) or Sellers and its Affiliates of any Shared Contract, and in no event shall Sellers or any of their Affiliates or Purchaser or any of its Affiliates have any obligation to any third party with respect to any Shared Contract other than as described in this Section 4.8(d) or otherwise in this Agreement or any Ancillary Agreements.
4.9Support Obligations. Purchaser shall use its reasonable best efforts to cause itself, one of its Affiliates or, in connection with the Closing and to be effective after the Closing, an Acquired Company, to be substituted in all respects for Sellers and any of their Affiliates, and for Sellers and their Affiliates to be unconditionally released, effective as of the Closing, in respect of, or otherwise terminate (and cause Sellers and their Affiliates to be unconditionally released in respect of), all obligations of Sellers and any of their Affiliates under each of the guarantees, indemnities, letters of credit, letters of comfort, commitments, understandings, agreements and other obligations of such Persons related to an Acquired Company that are set forth on Section 4.9 of the Sellers Disclosure Letter (collectively, the “Substituted
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Support Obligations”). The Substituted Support Obligations shall include any and all new or replacement credit support obligations or any modification or increase in the Substituted Support Obligations set forth on Section 4.9 of the Sellers Disclosure Letter and all of Purchaser’s obligations under this Section 4.9 shall apply with respect thereto, provided that, without Purchaser’s prior written consent, neither Seller nor any of its Affiliates may enter into or execute any new credit support obligation if as a result of such new credit support obligation relating to the business of the Acquired Companies, the aggregate amount of Substituted Support Obligations as of the Closing would be increased by more than $25,000,000 as compared to the amount of Substituted Support Obligations as of the date hereof. For any of the guarantees, indemnities, letters of credit, letters of comfort, commitments, understandings, agreements and other obligations of Sellers and any of their Affiliates related to an Acquired Company for which Purchaser or the Acquired Company, as applicable, is not substituted in all respects for Sellers and their Affiliates (or for which Sellers and their Affiliates are not unconditionally released) effective as of the Closing and that cannot otherwise be terminated effective as of the Closing without causing an adverse effect on an Acquired Company (with Sellers and their Affiliates to be unconditionally released in respect thereof), (a) Sellers shall, or shall cause their applicable Affiliates to, keep in place such Substituted Support Obligations (“Continuing Support Obligations”), (b) Purchaser shall continue to use its reasonable best efforts and shall cause each Acquired Company to use its reasonable best efforts to effect such substitution or termination and unconditional release with respect to the Continuing Support Obligations as promptly as practical after the Closing and (c) Purchaser shall reimburse Sellers for all documented amounts paid or incurred by Sellers or their Affiliates (other than the Acquired Companies) to the extent any guarantees, indemnities, letters of credit, letters of comfort, commitments, understandings, agreements and other obligations are called upon and Sellers or any such Affiliates make any payment or are obligated to reimburse the issuing party thereof. In addition, commencing on the date that is six months after the Closing Date, on the last Business Day of each three-month period ending thereafter, until such time as no Continuing Support Obligations remain outstanding, Purchaser shall pay Sellers or their designees a fee in respect of each Continuing Support Obligation equal to the amount of customary and market fees Sellers or its applicable Affiliate would have reasonably incurred if it posted a letter of credit in respect of the amounts covered by such Continuing Support Obligation for such three-month period (or, with respect to any Continuing Support Obligation outstanding for a portion, but not all, of such three-month period, for such portion of such three-month period). Without limiting the foregoing, neither Purchaser nor any of its Affiliates (including after the Closing the Acquired Companies) shall extend or renew any Contract containing or underlying a Continuing Support Obligation unless, prior to or concurrently with such extension or renewal, Purchaser or one of its Affiliates (including the Acquired Companies) is substituted in all respects for Sellers and any of their Affiliates under such Continuing Support Obligation. For purposes of this Section 4.9, “reasonable best efforts” shall include offering to provide to the applicable beneficiary of a Substituted Support Obligation, and providing such beneficiary, such replacement guarantees, indemnities, letters of credit, letters of comfort, commitments, understandings, agreements and other obligations as are substantially similar in form and substance to the Substituted Support Obligations.
4.9Usage of Seller Marks.
(a)As soon as reasonably practicable following the Closing, and in any case no later than three (3) Business Days following the Closing Date, Purchaser shall cause each Acquired Company to cease to hold itself out as having any affiliation with any Seller or any of its Affiliates. Purchaser shall, and shall cause its Affiliates, the Acquired Companies and their respective Representatives to, within one hundred twenty (120) days after the Closing Date cease using, remove, cover or conceal any name, logo, symbol, trademark, trade name, service mark, or designs incorporating: the words or acronyms [Redacted: Confidential.] (collectively, the “Seller Marks”), from any public-facing properties or assets in the possession or control of the Acquired Companies and, within ninety (90) days after the Closing Date, dispose of any unused stationery and literature containing the Seller Marks. Any use by Purchaser of any
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of the Seller Marks as permitted in this Section 4.10 is subject to Purchaser’s compliance with the quality control requirements and guidelines as provided to Purchaser in advance in writing, and which are in effect for the Seller Marks as of the Closing Date. Purchaser shall not use the Seller Marks in a manner that would reasonably be expected to reflect negatively on such Seller Mark or on any Seller or its Affiliates.
(b)Each Seller, on behalf of itself and its Affiliates as of the Closing Date (other than the Acquired Companies) (the “Seller Covenant Parties”), hereby covenants to Purchaser that none of the Seller Covenant Parties shall bring any Action against Purchaser or its subsidiaries (including the Acquired Companies, the “Purchaser Covenant Parties”) anywhere in the world that alleges that their current and future operation of the business of the Acquired Companies infringes any Intellectual Property (other than Trademarks) (“Inventions”) that in each case are (i) owned by the Seller Covenant Parties as of the Closing Date and (ii) were used in the business of the Acquired Companies as of the Closing Date or at any time during the twelve (12) month period prior to the Closing Date. The foregoing covenant extends to the contractors, distributors, retailers and end-users of the Purchaser Covenant Parties with respect to the business of the Purchaser Covenant Parties, as applicable, but not with respect to other products or services of such third parties. The Parties intend and agree that, for purposes of Section 365(n) of the U.S. Bankruptcy Code (and any amendment thereto) and any equivalent Law in any foreign jurisdiction, the foregoing covenant will be treated as a license to intellectual property (as defined in Section 101(35A) of the U.S. Bankruptcy Code). The foregoing covenant is intended to run with the Inventions subject to such covenant. Any Seller Covenant Party may and must transfer its covenant granted to the Purchaser Covenant Parties, in whole or in part, to the successor or acquirer of any Inventions subject thereto, and such successor or acquirer shall assume its obligations in writing or by operation of law. Further, any such successor or acquirer is deemed automatically bound by such covenant, regardless of whether such successor or acquirer executes such written assumption. Each Purchaser Covenant Party may transfer the covenant granted by the Seller Covenant Parties, in whole or in part, in connection with the sale of any business to which the covenant relates, provided that the covenant will not extend to the acquirer’s other businesses.
4.11Release.
(a)Effective as of the Closing and except as otherwise expressly set forth in this Agreement (including Section 4.11(c)) or in any of the Ancillary Agreements or for Fraud, each Seller, on behalf of itself and each of its Affiliates and each of their respective successors and assigns, hereby irrevocably, unconditionally and completely waives and releases and forever discharges Purchaser and each of its respective Affiliates, and each of their respective heirs, executors, administrators, successors and assigns (such released Persons, the “Releasees”), of and from all debts, demands, Actions, causes of action, suits, accounts, covenants, Contracts, damages, claims and other Liabilities whatsoever of every name and nature, both in law and in equity, arising out of or related to the Acquired Companies or their businesses prior to the Closing Date. Each Seller shall not make, and each Seller shall not permit any of its Affiliates or their respective Representatives to make, any claim or demand, or commence any Action asserting any claim or demand, including any claim of contribution or any indemnification, against any of Purchaser’s or its Affiliates’ or any of their Releasees with respect to any Liabilities or other matters released pursuant to this Section 4.11.
(b)Effective as of the Closing and except as otherwise expressly set forth in this Agreement (including Section 4.11(c)) or in any of the Ancillary Agreements or for Fraud, Purchaser, on behalf of themselves and each of their respective Affiliates (including the Acquired Companies following the Closing) and each of their respective successors and assigns, hereby irrevocably, unconditionally and completely waives and releases and forever discharges each Seller and each of their respective Affiliates, and each of their respective Releasees, of and from all debts, demands, Actions, causes of action, accounts, covenants, Contracts, damages and other Liabilities whatsoever of every name and nature, both in law and
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in equity, arising out of or in connection with any breach by Sellers or any director or officer of an Acquired Company of any fiduciary duty in their capacity as an equity holder, director or officer of such Acquired Company prior to the Closing Date. Purchaser shall not make or permit any of its Affiliates or Representatives to make, any claim or demand, or commence any Action asserting any claim or demand, including any claim of contribution or any indemnification, against any of Sellers or their Affiliates or any of their Releasees with respect to any Liabilities or other matters released pursuant to this Section 4.11.
(c)Notwithstanding the foregoing, Section 4.11(a) and Section 4.11(b) shall not constitute a release from, waiver of, or otherwise apply to the terms of (i) this Agreement, or any Ancillary Agreement, the Mitchell Plant Ownership Agreement, the Mitchell Plant O&M Agreement or any Liability or Contract expressly contemplated by this Agreement or any Ancillary Agreement to be in effect after the Closing, or any enforcement thereof or (ii) any other Contract, arrangement or other matter arising between Purchaser and its Affiliates, on the one hand, and Sellers and their Affiliates, on the other hand, in the ordinary course of their respective businesses.
4.12Indemnification of Directors and Officers.
(a)For a period of six (6) years commencing on the Closing Date, Purchaser shall, and shall cause the Acquired Companies to: (i) indemnify, defend and hold harmless, all of the past and present directors, officers and employees of each Acquired Company (in all of their capacities) (collectively, the “D&O Indemnified Parties”) against any and all Losses incurred in respect of acts or omissions occurring at or prior to the Closing to the fullest extent permitted by Law or provided under such Acquired Company’s Organizational Documents in effect on the Effective Date, (ii) without limitation of clause (i), to the fullest extent permitted by applicable Law, cause to be maintained in effect the provisions regarding elimination of liability of directors, and indemnification of and advancement of expenses to directors, officers and employees contained in the Organizational Documents of each Acquired Company that are no less advantageous to the intended beneficiaries than the corresponding provisions in such Organizational Documents in existence on the Effective Date and (iii) not settle, compromise or consent to the entry of any judgment in any proceeding or threatened proceeding (and in which indemnification could be sought by a D&O Indemnified Party hereunder), unless such settlement, compromise or consent (A) includes an unconditional release of such D&O Indemnified Party from all liability arising out of such proceeding or (B) provides solely for monetary damages to be paid by Purchaser or an Acquired Company pursuant to this Section 4.12(a), or such D&O Indemnified Party otherwise consents in writing to the entry of such judgment, and cooperates in the defense of such proceeding or threatened proceeding.
(b)The obligations of Purchaser and the Acquired Companies under this Section 4.12 shall not be terminated, amended or modified in any manner so as to adversely affect any D&O Indemnified Party (including their successors, heirs and legal Representatives) to whom this Section 4.12 applies without the written consent of such affected D&O Indemnified Party (it being expressly agreed that the D&O Indemnified Parties to whom this Section 4.12 applies shall be third-party beneficiaries of this Section 4.12, and this Section 4.12 shall be enforceable by such D&O Indemnified Parties and their respective successors, heirs and legal Representatives and shall be binding on all successors and assigns of Purchaser and the Acquired Companies).
(c)If Purchaser or, following the Closing, an Acquired Company, or any of their respective successors or assigns (i) shall consolidate with or merge into any other corporation or entity and shall not be the continuing or surviving corporation or entity of such consolidation or merger or (ii) shall transfer all or substantially all of its properties and assets to any Person, then, and in each such case, proper provisions shall be made so that the successors and assigns of Purchaser, the Acquired Company or
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any of their respective successors or assigns, as the case may be, shall assume all of the obligations set forth in this Section 4.12.
(d)The rights of the D&O Indemnified Parties under this Section 4.12 shall be in addition to any rights such D&O Indemnified Parties may have under the Organizational Documents of the Acquired Companies, or under any applicable contracts or Laws, and Purchaser shall, and shall cause the Acquired Companies to, honor and perform under all indemnification agreements entered into by the Acquired Companies that are set forth in Section 4.12 of the Seller Disclosure Letter.
4.13NSR Consent Decree.
(a)Sellers and Purchaser shall use their respective reasonable best efforts to effect an amendment to the NSR Consent Decree as promptly as reasonably practicable after the Effective Date pursuant to paragraphs 192 and 193 of the NSR Consent Decree pursuant to which Purchaser shall assume all obligations under the NSR Consent Decree relating to the Mitchell Interest and Big Sandy, but without (i) allocating in any such amendment any emissions caps under the NSR Consent Decree for Mitchell and Big Sandy separate from the other applicable facilities of Sellers and their applicable Affiliates (in their capacity as “Defendants” under the NSR Consent Decree), or (ii) the release of Sellers and their applicable Affiliates (in their capacity as “Defendants” under the NSR Consent Decree) from joint and several liability with respect to any compliance obligations with respect to Mitchell and Big Sandy. As of the Closing, the Parties shall enter into the Compliance Agreement in the form set forth as Exhibit D.
(b)From and after the Closing, Purchaser shall be responsible for the surrender of any emissions allowances required by the NSR Consent Decree and Compliance Agreement with respect to the Mitchell Interest and Big Sandy in the portion of the calendar year immediately following the Closing and for any periods thereafter.
(c)During the Interim Period, (i) Purchaser and its Representatives shall have the right to consult with Sellers and their applicable Affiliates and, to the extent not prohibited by applicable Law, attend and participate in any substantive meetings, discussions, communications or negotiations with any of the “Plaintiffs” (as defined in the NSR Consent Decree) regarding any modification of or other substantive issue under the NSR Consent Decree with respect to the Mitchell Interest or Big Sandy and related obligations with respect thereto as contemplated under this Section 4.13, and (ii) Sellers shall provide Purchaser and its Representatives with a reasonable opportunity to comment in advance on any material written communication or offer to the Plaintiffs relating to such modification of or other substantive issue with respect to the NSR Consent Decree as contemplated under this Section 4.13 and Sellers shall reasonably consider Purchaser’s comments in submitting such written communications or offers. For the avoidance of doubt, Purchaser shall have no consent right, or right to participate or be consulted, with respect to any amendment, modification or waiver or other obligation under the NSR Consent Decree unrelated to Mitchell or Big Sandy.
4.14[Reserved].
4.15R&W Policy; No Subrogation. Concurrently with execution of this Agreement, Purchaser may procure a customary representation and warranty insurance policy, in substantially the form delivered to Sellers prior to the execution of this Agreement with such changes thereto as may be agreed by Purchaser and the insurer(s) thereunder (consistent with this Section 4.15), issued to Purchaser in connection with this Agreement (the “R&W Policy”) and with Purchaser as the named insured and covering the representations and warranties of Sellers under this Agreement. Any R&W Policy shall expressly provide that (a) the insurer under the R&W Policy has no subrogation rights, and will not pursue any claim, against Sellers or
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any of their respective Affiliates or Representatives, or any of their respective successors and assigns, except in connection with a claim based on Fraud, and (b) Purchaser is not required to pursue remedies against Sellers or any of its respective Affiliates or Representatives, or any of their respective successors and assigns prior to or as a condition to making a claim under the R&W Policy. In furtherance, and not in limitation, of the foregoing, Purchaser shall not, and shall cause its Affiliates not to, grant any right of subrogation or otherwise amend, modify, terminate or waive any terms or conditions of any representation and warranty insurance policy, including the R&W Policy, in a manner that adversely affects a Seller or any of its respective Affiliates or Representatives, or any of their respective successors and assigns, without the prior written consent of Sellers (which may be withheld in their sole discretion). The premium and related costs of the R&W Policy, including any fees, costs, retentions or deductibles associated with the R&W Policy, shall be paid or otherwise borne by Purchaser.
4.16Existing Debt Agreements; Senior Notes.
(a)Purchaser acknowledges that each of the Acquired Companies is party to the Amended and Restated Utility Money Pool Agreement dated as of December 9, 2004 by and among AEP and certain other affiliates (as amended, the “Utility Money Pool Agreement”) pursuant to which, among other things, certain amounts have been, and will continue to be, advanced to the Acquired Companies by Sellers or their Affiliates. At the Closing, Purchaser shall provide the funds necessary to cause the Acquired Companies to repay in full all Closing Indebtedness (including principal, interest, fees, costs and expenses) owed by the Acquired Companies pursuant to the Utility Money Pool Agreement as a result of the removal of the Acquired Companies from the Utility Money Pool Agreement in accordance with Section 4.8(a); provided, that, for the avoidance of doubt, the amount of Estimated Closing Indebtedness and Final Closing Indebtedness shall not be reduced by the amount of such funding by Purchaser necessary to cause the repayment in full of such Indebtedness, which shall be deemed to have taken place on the Closing Date after the Reference Time.
(b)Purchaser acknowledges that Kentucky TransCo has issued the TransCo Intercompany Notes to AEP TransCo. To the extent that all of the TransCo Intercompany Notes are not refinanced with indebtedness provided by unaffiliated third parties during the Interim Period, at the Closing Purchaser shall provide the funds necessary to cause Kentucky TransCo to redeem in full the portion of the Closing Indebtedness (including principal, interest, fees, costs and expenses) represented by the TransCo Intercompany Notes that are outstanding at the Closing; provided, that, for the avoidance of doubt, the amount of Estimated Closing Indebtedness and Final Closing Indebtedness shall not be reduced by the amount of such funding by Purchaser necessary to cause the repayment in full of such Indebtedness, which shall be deemed to have taken place on the Closing Date after the Reference Time. Sellers will cause AEP TransCo to waive any restrictions on redemption prior to the stated maturity date of such TransCo Intercompany Notes.
(c)Purchaser hereby acknowledges that, pursuant to each of the Debt Agreements set forth on Section 4.16 of the Sellers Disclosure Letter, consummation of the transactions contemplated by this Agreement absent the timely receipt of an applicable consent would constitute an event of default by Kentucky Power under each agreement. Unless such consent with respect to such agreements have been obtained at or prior to the Closing, Purchaser shall provide the funds to Kentucky Power that are necessary to cause Kentucky Power to pay all Closing Indebtedness (including principal, interest, costs, fees and expenses) that, as a result of the Closing, are required to be paid with respect to the Debt Agreements as and when such amounts become due and payable; provided, that, for the avoidance of doubt, the amount of Estimated Closing Indebtedness and Final Closing Indebtedness shall not be reduced by the amount of such funding by Purchaser necessary to cause the repayment in full of such Indebtedness, which shall be deemed to have taken place on the Closing Date after the Reference Time.
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(d)Pursuant to the Senior Note Purchase Agreements, within five (5) Business Days (as defined in the Senior Note Purchase Agreements) after (i) the date hereof, Kentucky Power must (A) give notice that this Agreement has been executed to the holders of the Senior KPCo Notes and (B) apply to a Rating Agency for a review of the then applicable credit rating in respect of the Senior KPCo Notes; and (ii)  the occurrence of any Change in Control Prepayment Event, Kentucky Power must offer to prepay all of the Senior KPCo Notes held by the holders thereof pursuant to the terms and conditions in the Senior Note Purchase Agreements. Purchaser hereby consents for all purposes under this Agreement to Sellers causing Kentucky Power to take any such action required to be taken prior to the Closing pursuant to the Senior Note Purchase Agreements.
(e)Purchaser hereby acknowledges that (i) within five (5) Business Days (as defined in the Senior Note Purchase Agreements) of the occurrence of any Change in Control Prepayment Event, Kentucky Power must offer to prepay all of the Senior KPCo Notes held by the holders thereof and (ii) the purchase price for the Senior KPCo Notes payable to holders thereof which have accepted such prepayment in accordance with the Senior Note Purchase Agreements (the “Accepting Noteholders”) is 100% of the principal amount of such Senior KPCo Notes, together with accrued and unpaid interest thereon to the date of prepayment (the “Senior Note Purchase Price”). Purchaser shall provide the funds to Kentucky Power that are necessary to cause Kentucky Power to pay the Senior Note Purchase Price in connection with a Change in Control Prepayment Event occurring after the consummation of the transactions contemplated by this Agreement as and when such amounts become due and payable pursuant to the Senior Note Purchase Agreements; provided, that, for the avoidance of doubt, the amount of Estimated Closing Indebtedness and Final Closing Indebtedness shall not be reduced by the amount of such funding by Purchaser necessary to cause the repayment in full of such Indebtedness, which shall be deemed to have taken place on the Closing Date after the Reference Time.
(f)Notwithstanding anything to the contrary in this Section 4.16, the receipt by Purchaser of any waivers or consents with respect to the Debt Agreements or the absence of the occurrence of a Change in Control Prepayment Event with respect to the Senior KPCo Notes shall not constitute conditions to the obligation of Purchaser to consummate the Closing.
4.17Business Separation Plan. During the Interim Period, in furtherance of the transactions contemplated by this Agreement, the Parties shall, and shall cause their Affiliates to, cooperate in good faith and use their reasonable best efforts to develop, and, to the extent reasonably practicable, implement prior to the Closing, a mutually acceptable plan for the separation of certain assets, properties and contractual arrangements that are intertwined with the businesses of the Acquired Companies and those of the Sellers and certain of their Affiliates (other than the Acquired Companies) (the “Business Separation Plan”). The Business Separation Plan shall address the matters set forth on Section 4.17 of the Sellers Disclosure Letter as well as any other matters mutually agreed to by the Parties. All such activities subject to this Section 4.17 shall be in compliance with applicable Law. For the avoidance of doubt, each Party shall pay its own legal and other costs and expenses incurred in connection with the activities contemplated by this Section 4.17, except to the extent provided otherwise in Section 4.17 of the Sellers Disclosure Letter. Without limiting the foregoing, during the Interim Period, the Parties shall cooperate in good faith and use their reasonable best efforts to begin to readily transition the Business to Purchaser such that Purchaser and the Acquired Companies can operate the Business on a stand-alone basis in the ordinary course in accordance with Good Utility Practices without disruption or interruption, including so as to minimize the Acquired Companies’ reliance post-Closing on the services provided under the Transition Services Agreement. The Parties shall negotiate in good faith during the Interim Period to agree on any appropriate modifications to such services (including the duration thereof, but in no event exceeding 24 months after the Closing Date, and in all cases subject to the provisions of the Transition Services Agreement relating to costs and expenses) to reflect the foregoing or as may otherwise be necessary or advisable to enable
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Purchaser and the Acquired Companies to operate the Business on a stand-alone basis in the ordinary course in accordance with Good Utility Practices without disruption or interruption, but taking into account the Parties’ use of reasonable best efforts to minimize the Acquired Companies’ reliance post-Closing on the services provided under the Transition Services Agreement and the duration thereof; provided that none of Sellers or their Affiliates shall be required to provide any services defined as “Excluded Services” under the Transition Services Agreement.
4.18NERC Registration. Sellers and Purchaser shall, at Purchaser’s sole cost and expense, use reasonable best efforts to implement Purchaser’s selected North American Electricity Reliability Corporation (“NERC”) registration option from the two options set forth in Section 4.18 of the Sellers Disclosure Letter, including certification as a transmission operator, so that Purchaser or an Affiliate of Purchaser is registered with NERC in accordance with 18 C.F.R. § 39.2(c) for all applicable functions for the bulk electric system facilities owned by Kentucky Power and Kentucky Transco in accordance with the NERC Rules of Procedure with a registration effective date of the Closing. Purchaser will notify Seller of its chosen option within thirty (30) days of the Effective Date. Nothing in this Section 4.18 shall constitute a condition to the obligations of either Party to consummate the Closing.
4.19Master Leases. If a counterparty to one or more of the Shared Contracts described on Section 4.19 of the Sellers Disclosure Letter (the “Master Leases”) has not agreed to replace or bifurcate into stand-alone Contracts such Shared Contracts on or before the earlier of (x) the date that is 120 days after the date of this Agreement and (y) the Closing Date, to be effective as of the Closing Date, Sellers shall (and shall cause their Affiliates (including the Acquired Companies) to) use reasonable best efforts to replace the Master Leases with alternative capital lease arrangements from third parties on substantially the same terms or such other terms as are reasonably acceptable to Purchaser. If, despite such reasonable best efforts, Sellers are unable to effect such replacement, Sellers shall cause Kentucky Power to (a) use reasonable best efforts to purchase the property, plant and equipment leased under the applicable Master Lease and used primarily in the business of the Acquired Companies (other than in connection with the operation of Mitchell by Kentucky Power prior to Closing, which property, plant and equipment Sellers and their Affiliates shall use reasonable best efforts to transfer, caused to be leased by or to provide the benefit of to the Successor Operator effective as of the Closing) so that title to such leased property, plant and equipment transfers to Kentucky Power, free and clear of any Encumbrances, other than Permitted Encumbrances and (b) withdraw from, sever, replace or terminate its participation in the applicable Master Lease prior to the Closing; provided, that Purchaser’s prior written consent, not to be unreasonably withheld, conditioned or delayed, shall be required for any action referred to in the foregoing clauses (a) and (b) to the extent that the aggregate purchase price payable for all such property, plant and equipment is in excess of $10,000,000.
4.20Transfer of Mitchell Assets and Mitchell Employees to Successor Operator; Mitchell Plant Approvals.
(a)At or prior to the Closing, Sellers shall cause Kentucky Power to use reasonable best efforts to cause any property, assets, vessels (including the vessel named the W.M. Robinson), Contracts, Permits, Environmental Permits or Claims held by Kentucky Power, in its capacity as the operator of Mitchell, or otherwise to the extent held by Kentucky Power for the benefit of the owners of Mitchell, in each case as set forth in Section 4.20(a) of the Sellers Disclosure Letter (collectively, the “Mitchell Operator Assets” and each, individually, a “Mitchell Operator Asset”), to be assigned, transferred or conveyed to Successor Operator or an Affiliate thereof.
(b)Notwithstanding anything in this Agreement or any Ancillary Agreement to the contrary, this Agreement and the Ancillary Agreements shall not constitute an agreement to transfer or
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assign any Mitchell Operator Asset if an attempted assignment thereof, without the consent of a third party, would constitute a breach or other contravention under any Contract or Law to which any Acquired Company or any member of the Seller Group is a party or by which it is bound, or would in any way adversely affect the rights of any Acquired Company or such member of the Seller Group relating to such Mitchell Operator Asset or any right related thereto that any member of the Seller Group is entitled to retain. To the extent that Sellers are unable, or in their reasonable judgment determine they are unlikely, to obtain any required consent with respect to a Mitchell Operator Asset that is reasonably necessary to be transferred to the Successor Operator to comply with its obligations under the Mitchell Plant O&M Agreement prior to Closing, Sellers and Purchaser shall cooperate to implement any lawful and commercially reasonable arrangement as Sellers and Purchaser shall agree under which Successor Operator or an Affiliate thereof would, to the extent practicable, obtain the rights and benefits under such Mitchell Operator Asset and assume the burdens and obligations with respect thereto, subject to Kentucky Power and Successor Operator (in such capacity or its capacity as the owner of an undivided interest in Mitchell) each bearing its respective allocated share of costs in accordance with the Mitchell Plant Ownership Agreement and the Mitchell Plant O&M Agreement, including by subcontracting, sublicensing, subleasing, delegating or granting a limited power of attorney or similar appointment as agent to Successor Operator or an Affiliate thereof. Sellers and Purchaser shall continue to cooperate on and after the Closing to assign, transfer or convey to Successor Operator or an Affiliate thereof any Mitchell Operator Asset that is reasonably necessary to be transferred to the Successor Operator to comply with its obligations under the Mitchell Plant O&M Agreement that remains held by Kentucky Power and to otherwise arrange for Successor Operator to directly contract with the applicable third party for any renewal Contract upon the expiration or termination of any Contract constituting any such Mitchell Operator Asset.
(c)Sellers shall cause Successor Operator or one or more Affiliates of Sellers (other than the Acquired Companies) to transfer the employment of the Mitchell Employees to such Successor Operator or one or more Affiliates of Seller prior to the Closing Date, to be effective as of the first payroll period in which the Closing Date occurs or, if earlier, the first day of the payroll period following the date that the Mitchell Plant Ownership Agreement and Mitchell Plant O&M Agreement shall become effective after receipt of all applicable regulatory approvals, including the Mitchell Plant Approvals. On or prior to the Closing Date, Successor Operator or such Affiliate shall become the employer of each Mitchell Employee who does not resign their employment in lieu of the transfer prior to the proposed date of the employment transfer.
(d)Sellers shall take the lead on strategy with respect to the Parties’ efforts to obtain the Mitchell Plant Approvals after considering and reflecting in good faith all reasonable comments and advice of Purchaser (and its counsel), and Purchaser shall reasonably cooperate with Sellers in connection therewith. Subject to the last sentence of Section 4.5(d), Sellers shall be entitled to cause Kentucky Power and Wheeling to make such modifications to the Mitchell Plant Ownership Agreement and the Mitchell Plant O&M Agreement as are reasonably necessary to comply with the Mitchell Plant Approvals, including in respect of any settlement of the proceedings related thereto, in each case entered following the Effective Date, and to cause such parties to execute the Mitchell Plant Ownership Agreement and the Mitchell Plant O&M Agreement prior to the Closing, as such agreements shall be so modified, if and to the extent that such agreements have been finalized and the Mitchell Plant Approvals have been obtained and have become Final Orders. For the avoidance of doubt, (i) any change in the form or substance of the forms of the Mitchell Plant Ownership Agreement or Mitchell Plant O&M Agreement, included as Exhibit B and Exhibit C, respectively, to this Agreement, after the Effective Date, to the extent that such change is adverse to the interests of Purchaser or the Acquired Companies and relates to the period on and after the Closing Date and (ii) any other undertaking, term, condition, liability, obligation, commitment or sanction imposed on or agreed to by the Acquired Companies in obtaining the Mitchell Plant Approvals that relates to the period
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on and after the Closing Date, in each case of clauses (i) and (ii), shall be taken into account for purposes of any determination under this Agreement as to whether a Burdensome Condition shall have occurred.
(e)Concurrently with, and conditioned upon, the closing of any sale, assignment, transfer or conveyance of the Mitchell Interest to Wheeling in accordance with the Mitchell Plant Ownership Agreement, Sellers shall cause AEP Generation Resources Inc. to enter into an indemnity agreement for the benefit of Kentucky Power on the terms described on Section 4.20(e) of the Sellers Disclosure Letter.
4.21Corporate Offices and Service Centers. For a period of no less than five years from the Closing Date, Purchaser shall cause Kentucky Power to maintain its existing corporate headquarters in Kentucky and, other than in the ordinary course of its business, maintain its existing offices and service centers in Kentucky.
4.22Insurance. Except as provided herein or in the Ancillary Agreements, Purchaser hereby acknowledges and agrees that effective as of the Closing, each Acquired Company shall cease being covered by, and having the benefit of, any insurance coverage (including any policy issued by any “captive” insurer, together with any insurance-related, self-insurance or similar funds or reserves) for the benefit of any Acquired Companies maintained by Sellers or their Affiliates. Purchaser and its Affiliates shall be solely responsible for providing, or causing to be provided, insurance to each Acquired Company for any claims made after the Closing (subject to the remainder of this Section 4.22 with respect to losses prior to the Closing). For the avoidance of doubt, any amounts recovered prior to the Closing by the Acquired Companies in respect of losses incurred prior to the Closing shall be for the benefit of Sellers, and Purchaser shall promptly remit any such funds received following Closing to the Sellers. If there is any actual or potential loss prior to the Closing which is insured under any insurance policy covering the Acquired Companies or any of their respective assets or liabilities (including any policy issued by any “captive” insurer, together with any insurance-related, self-insurance or similar funds or reserves), Sellers shall use reasonable best efforts to provide notice of such loss to the applicable insurers prior to the Closing, and Sellers shall use reasonable best efforts to ensure the Acquired Companies can file, notice and otherwise continue to pursue such claims and recover proceeds under the terms of such policies (including with respect to any actual or potential loss in respect of the matters set forth on Section 4.22 of the Sellers Disclosure Letter). Sellers shall provide reasonable assistance to the Acquired Companies after the Closing with regard to pursuit of such claims, and Purchaser shall provide reasonable assistance to Seller with regard to investigating, defending and settling such claims. Following the Closing, to the extent that (a) any insurance policies of Sellers or their Affiliates (including any policies issued by any “captive” insurer) cover any loss in respect of any of the Acquired Companies arising out of, relating to or resulting from occurrences prior to the Closing and (b) such policies do not preclude claims from being made thereunder with respect to such losses arising out of, relating to or resulting from occurrences prior to the Closing (“Business Claims”), then, at Purchaser’s sole cost and expense, Sellers or their Affiliates shall reasonably cooperate with Purchaser (upon Purchaser’s written request) in Purchaser’s submission of Business Claims (or Purchaser’s pursuit of claims previously made) on behalf of Purchaser or an Acquired Company, as applicable, under any such policy. To the extent any insurance policies in place for the benefit of the Acquired Companies prior to Closing would preclude claims being made thereunder in accordance with clause (b) above following Closing, including any requirement to obtain consent of any issuer of any such policy, Sellers shall use reasonable best efforts to take any actions necessary in order to permit such claims to be made. With respect to Business Claims, Sellers shall take no action to exclude or remove the Acquired Companies with respect to the period prior to Closing from the insurance policies that were in place for the benefit of the Acquired Companies prior to Closing and shall not take any action following Closing that would reasonably be expected to impair any right or ability of the Acquired Companies to file claims for losses incurred prior to Closing consistent with Section 4.22. For purposes of this Agreement, that certain Claim
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Handling and Funding Agreement, dated May 30, 1996, between AEPSC and Nationwide (as successor to Employers Insurance of Wausau) (the “Claim Handling and Funding Agreement”), and any rights of any Seller or its Affiliates thereunder (including any accruals on behalf of any of the foregoing), shall be deemed to cover losses in respect of any of the Acquired Companies arising out of, relating to or resulting from occurrences prior to Closing and shall be treated as an insurance policy benefiting the Acquired Companies. Without limiting the foregoing, Sellers shall use reasonable best efforts to cause the Acquired Companies to have the same rights and privileges as AEPSC under the Claim Handling and Funding Agreement.
4.23Misdirected Payments.
(a)Each Seller shall, or shall cause its applicable Affiliate to, promptly pay or deliver to Purchaser (or its designated Affiliates) any monies or checks that have been sent to such Seller or any of its Affiliates after the Closing Date by customers, suppliers or other contracting parties of any Acquired Company or any of its businesses to the extent that they are in respect of the businesses of any Acquired Company or otherwise properly payable to any Acquired Company.
(b)Purchaser shall, or shall cause its applicable Affiliate to, promptly pay or deliver to each Seller (or its designated Affiliates) any monies or checks that have been sent to Purchaser or any of its Affiliates (including the Acquired Companies) after the Closing Date to the extent that they are not in respect of any business of any Acquired Company and not otherwise properly payable to any Acquired Company but rather properly payable to such Seller or its Affiliates.
4.24Misallocated Assets. If, within twenty four (24) months following the Closing, any right, property or asset exclusively related to a business of either Seller or any Affiliate thereof (other than any Acquired Company) other than the business of any Acquired Company, or exclusively used by any Seller or an Affiliate thereof (other than any Acquired Company) in a manner unrelated to the business of any Acquired Company prior to the Closing is found to have been transferred to Purchaser through its acquisition of the Acquired Companies in error (and not so contemplated in Section 4.8, Section 4.17, Section 4.20 or in the Ancillary Agreements), Purchaser shall cause the Acquired Companies to transfer, for no consideration (but at no cost to Purchaser or any of its Affiliates), such right, property or asset as soon as practicable (including taking into account any required regulatory approvals or third party consents), to such Seller or an Affiliate thereof designated by such Seller. If, following the Closing, any right, property or asset exclusively related to, or exclusively used in, the business of any Acquired Company prior to the Closing or necessary to conduct the business of any Acquired Company in substantially the same manner as conducted prior to the Closing is found to have been retained by any Seller or any Affiliate thereof in error, such Seller shall transfer, or shall cause such Affiliate to transfer, for no consideration, such right, property or asset as soon as practicable (including taking into account any required regulatory approvals or third party consents) to Purchaser or an Affiliate thereof (including any Acquired Company) designated by Purchaser.
4.25Financing Cooperation.
(a)Prior to Closing (or the earlier termination of this Agreement pursuant to Section 8.1), subject to the limitations set forth in this Section 4.25, and unless otherwise agreed by Purchaser, Sellers will, at Purchaser’s cost and expense (as provided in clause (d) below), use commercially reasonable efforts to (and will use commercially reasonable efforts to cause the Acquired Companies and their Affiliates and Representatives to) cooperate with Purchaser as may be reasonably requested by Purchaser in connection with Purchaser’s or its Affiliates’ arrangement, syndication and obtaining financing in connection with the acquisition of the Acquired Companies (the “Financing”). Such cooperation will include using commercially reasonable efforts to:
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(i)cooperate with the marketing efforts of Purchaser in connection with the Financing, including making appropriate senior officers reasonably available, with appropriate advance notice, for participation in a reasonable number of lender or investor meetings, due diligence sessions, meetings with ratings agencies and road shows, and providing reasonable assistance in the preparation of rating agency presentations, confidential information memoranda, private placement memoranda, offering memoranda, prospectuses, registration statements, filings with the SEC and Canadian securities regulators, lender and investor presentations and similar documents as may be reasonably requested by Purchaser, in each case, with respect to information relating to the Acquired Companies in connection with such marketing efforts;
(ii)prepare and furnish Purchaser and the lenders, underwriters, agents, banks or other financing sources (“Financing Sources”), on a confidential basis, as promptly as reasonably practicable all information with respect to the Acquired Companies as is reasonably requested by Purchaser and is customarily (A) required for the marketing, arrangement and syndication of financings or (B) used in the preparation of customary offering or information documents or rating agency, lender presentations or road shows relating to any financing, provided that such information shall be limited to information and data derived from the Acquired Companies’ historical books and records;
(iii)furnish all documentation and other information required by a Governmental Entity or any Financing Source under applicable “know your customer” and anti-money laundering rules and regulations, including the USA PATRIOT ACT (Title III of Pub. L. 107-56 (signed into law October 26, 2001)) and anti-bribery and anti-corruption rules and regulations to the extent reasonably requested by Purchaser;
(iv)providing reasonable assistance to Purchaser to produce financial statements (including pro forma and audited financial statements of the Acquired Companies) required to be delivered pursuant to any securities laws or any financing arrangements and assisting Purchaser in the preparation of such financial statements; provided, that neither the Sellers nor their Representatives shall be required to provide any such assistance with respect to financial information or statements relating to (A) the determination of the proposed aggregate amount of the Financing, the interest rates thereunder or the fees and expenses relating thereto; (B) the determination of any post-Closing or pro forma cost savings, synergies, capitalization, ownership or other pro forma adjustments desired to be incorporated into any information used in connection with the Financing; or (C) any adjustments that are not directly related to the acquisition of the Acquired Companies; provided further that (x) such assistance shall be limited solely with respect to information and data derived from the Seller’s historical books and records and (y) neither Sellers nor their Representatives shall be required to certify or attest to any such pro forma financial statements or other forecasted information; and
(v)assist with the Financing Sources’ requests for due diligence to the extent customary and reasonable.
provided, further, that (A) nothing in this Section 4.25 shall require Sellers to cause the delivery of legal opinions or reliance letters or any certificate as to solvency or any other certificate necessary for the Financing; and (B) Sellers will use reasonable best efforts to (and will use reasonable best efforts to cause the Acquired Companies and their Affiliates and Representatives to), reasonably promptly update any information in respect of Sellers and the Acquired Companies to be included in any document filed with the SEC or Canadian securities regulators so that such information does not contain, as of the time provided, any untrue statement of material fact or omit to state any material fact necessary in order to make the statements contained therein not misleading.
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(b)Sellers agree to use reasonable best efforts to (and will use reasonable best efforts to cause their Affiliates and Representatives to) provide, reasonable assistance to Purchaser for a period of three months following Closing to produce the financial statements (including pro forma and audited financial statements of the Acquired Companies) required to be delivered pursuant to any securities laws and assisting Purchaser in the preparation of financial statements; provided, that neither the Sellers nor their Representatives shall be required to provide any such assistance with respect to financial information or statements relating to (A) the determination of the proposed aggregate amount of the Financing, the interest rates thereunder or the fees and expenses relating thereto; (B) the determination of any post-Closing or pro forma cost savings, synergies, capitalization, ownership or other pro forma adjustments desired to be incorporated into any information used in connection with the Financing; or (C) any adjustments that are not directly related to the acquisition of the Acquired Companies; provided further that (x) such assistance shall be limited solely with respect to information and data derived from each Seller’s historical books and records and (y) neither Sellers nor their Representatives shall be required to certify or attest to any such pro forma financial statements or other forecasted information.
(c)Purchaser shall indemnify and hold harmless Sellers and their Affiliates and their respective directors, officers and employees from and against any and all Losses suffered or incurred by them in connection with the arrangement and completion of any Financing or related transactions by Purchaser in connection with financing the transactions contemplated hereby and any information utilized in connection therewith. This Section 4.25(c) shall survive the consummation of the Closing and any termination of this Agreement, and is intended to benefit, and may be enforced by, the officers and directors of the Sellers and their Affiliates and their respective heirs, executors, estates and personal representatives who are each third party beneficiaries of this Section 4.25(c).
(d)Nothing in this Section 4.25 shall require any such cooperation to the extent that it would require any Seller or the Acquired Companies to: (i) waive or amend any terms of this Agreement or agree to pay any fees or reimburse any expenses for which it has not received prior reimbursement or is not otherwise indemnified by or on behalf of Purchaser; (ii) enter into any definitive agreement; (iii) give any indemnities in connection with the Financing; (iv) take any action that, in the good faith determination of the Sellers, would unreasonably interfere with the conduct of the business of the Sellers and their Affiliates or create an unreasonable risk of damage or destruction to any property or assets of the Sellers or any of their Affiliates; (v) adopt resolutions (whether by the board of directors of the Sellers or otherwise) approving the agreements, documents and instruments pursuant to which the Financing is obtained, other than those effective on the Closing Date; (vi) provide any assistance or cooperation that (A) would cause any representation or warranty in this Agreement made by any Seller to be breached, or (B) cause any conditions to Closing set forth in this Agreement to fail to be satisfied by the Outside Date or otherwise result in a breach of this Agreement by Sellers that would provide Purchaser the right to terminate this Agreement (unless waived by Purchaser); or (v) cooperate to the extent it would require the disclosure of information which the Sellers or the Acquired Companies reasonably determine would reasonably be expected to jeopardize the attorney-client or other similar privilege of the Sellers or any of the Acquired Companies or violate any Applicable Law to which the Sellers or any of the Acquired Companies is a party.
(e)Purchaser shall promptly upon request by Sellers, reimburse Sellers for all of their reasonable and documented out-of-pocket fees and expenses (including reasonable fees and expenses of counsel and accountants) incurred by Sellers and the Acquired Companies, any of its or their representatives in connection with any cooperation contemplated by this Section 4.25.
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ARTICLE V
EMPLOYEE, LABOR AND BENEFITS MATTERS COVENANTS

5.1Seller Benefit Plans. Effective as of the Closing Date, the Continuing Employees shall cease to accrue further benefits and shall cease to be active participants under any Seller Benefit Plans except as provided by the terms of such plans or applicable Law. As of the Closing Date, all Continuing Employees shall become vested on a prorated basis under the terms of any Restricted Stock Unit Award Agreement issued to such Continuing Employee under the terms of the American Electric Power System Long-Term Incentive Plan as if such employees termination of employment with the Acquired Company had involved a Severance Date (as defined in such agreement).
5.2Non-Covered Employees. All Non-Covered Employees who are employees of an Acquired Company, if still employed by an Acquired Company immediately prior to the Closing Date, shall continue to be employees of such Acquired Company on the Closing Date (such persons, the “Continuing Non-Covered Employees”). Purchaser acknowledges that those employees set forth on Section 5.2 of the Sellers Disclosure Letter will not be employees of the Acquired Company on the Closing Date.
5.3Covered Employees Offers and Post-Closing Employment and Benefits.
(a)All Covered Employees who are employees of an Acquired Company, if still employed by an Acquired Company immediately prior to the Closing Date, shall continue to be employees of such Acquired Company on the Closing Date and shall be deemed a “Continuing Covered Employee.” 
(b)Purchaser acknowledges that any Collective Bargaining Agreement applicable to Continuing Covered Employees and to which an Acquired Company is a party shall continue in effect according to its terms after the Closing.
5.4Post-Closing Employment and Benefits for Non-Covered Employees. Purchaser shall provide, or shall cause one of its Affiliates to provide, to each Continuing Non-Covered Employee during the period from the Closing Date through the second anniversary of the Effective Date (or if shorter, the period during which the Continuing Non-Covered Employee is employed by Purchaser or one of its Affiliates) (the “Continuation Period”):
(a)base salary/wage rate at a rate at least equal to the base salary/wage rate provided to the Non-Covered Employee immediately prior to the Closing, and annual bonus opportunities (including target and maximum payouts, but excluding long-term and equity-based compensation opportunities), which, together with base salary/wage rate, are at least equal, in the aggregate, to the base salary/wage rate and such annual bonus opportunities provided to the Non-Covered Employee immediately prior to Closing;
(b)vacation, sick pay and other paid time off accrued but unused as of the Closing on terms and conditions not less favorable than the terms and conditions in effect immediately prior to the Closing; and
(c)other employee benefits (other than severance benefits, which shall be as provided as set forth in Section 5.6), including any benefits in substitution or replacement for any existing long-term and equity-based compensation opportunities (including, without limitation, cash payments or increased base salary/wage rate) of a Continuing Non-Covered Employee, which are no less favorable in the aggregate to the employee benefits (other than severance benefits) provided to the Non-Covered Employee immediately prior to Closing. Without limiting the generality of the foregoing, Continuing Non-Covered
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Employees who, as of the Closing Date, would have become eligible for retiree medical coverage under any Seller Benefit Plan within two (2) years following the Closing Date had they remained eligible for coverage under the Seller Benefit Plans, shall remain able to become eligible for such retiree medical benefits under substantially similarly terms and conditions under plans maintained by Purchaser or its Affiliates following the Closing.
5.5Welfare Plans. Purchaser or an Affiliate of Purchaser shall cause each Continuing Employee and his or her eligible dependents (including all such employee’s dependents covered immediately prior to the Closing Date by a Seller Benefit Plan that is a welfare benefit plan) coverage under a welfare benefit plan maintained by Purchaser or one of its Affiliates that (A) ensures that no waiting periods, exclusions or limitations with respect to any pre-existing conditions, evidence of insurability or good health or actively-at-work exclusions are applicable to any Continuing Employee or their dependents or beneficiaries under any welfare benefit plans in which such employees may be eligible to participate and (B) credits such Continuing Employee, for the plan year during which the Closing occurs, with any deductibles, co-payments and amounts credited toward out-of-pocket maximums incurred under a Seller Benefit Plan toward satisfying any deductible, co-payment and out-of-pocket maximum requirements under the medical plan of Purchaser or any of its Affiliates in which the Continuing Employee participates during the plan year in which the Closing occurs.
5.6Severance. Purchaser shall, or shall cause one of its Affiliates to, pay to each Continuing Employee who is terminated during the Continuation Period for any reason other than cause or the Continuing Employee’s death or disability (a “Severed Continuing Employee”), subject to the Continuing Employee’s timely executing and not revoking a release of claims, a lump sum payment in cash equal to two weeks’ base pay for each year of service or portion thereof (taking into account, for this purpose, service as a Continuing Employee as well as service that would be credited to the Severed Continuing Employee under Section 5.7), with a minimum of eight (8) weeks’ base pay, with the base pay determined at the then applicable rate. For this purpose, (a) the resignation by a Continuing Employee in lieu of a requirement that such employee transfer to a main work location that is more than 50 miles from his or her main work location as of the Closing Date, and (b) the termination of a Continuing Employee’s employment by reason of such employee’s declining a request for such a transfer shall be considered termination for a reason other than cause. In addition, to the extent a Severed Continuing Employee elects COBRA Continuation Coverage, the amount payable by such Severed Continuing Employee in respect of COBRA premiums during the months that such COBRA Continuation Coverage remains in effect (but only up to the first eighteen (18) months) shall be no more than the active employee premiums payable for the same medical and/or dental coverage covering the Severed Continuing Employee and the Severed Continuing Employee’s spouse and eligible dependents. Notwithstanding the foregoing, if any Continuing Employee is entitled to severance benefits under an individual severance, employment or similar agreement, the terms of such agreement and not this Section 5.6 shall govern, and Continuing Covered Employees shall be entitled to severance benefits only to the extent provided in a Collective Bargaining Agreement or otherwise agreed by the applicable union.
5.7COBRA. Purchaser shall provide, or shall cause one of its Affiliates to provide, continuation health care coverage to Continuing Employees and their qualified beneficiaries who incur a qualifying event, in accordance with the continuation health care coverage requirements of Section 4980B of the Code and Title I, Subtitle B, Part 6 of ERISA (“COBRA”) or any similar provisions of state Law, after the Closing Date. Sellers and their Affiliates shall be solely responsible for any obligations under COBRA with respect to all “M&A qualified beneficiaries” as defined in Treasury Regulation Section 54.4980B-9.
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5.8Service Credit. Purchaser shall, or shall cause one of its Affiliates to, provide full service credit for all purposes including eligibility to participate, vesting and benefit accrual (other than for benefit accrual purposes under any defined benefit pension plan) under all employee benefit plans, policies and arrangements (other than equity or equity-based plans, policies and arrangements) made available to Continuing Employees by Purchaser or any of its Affiliates after the Closing to the same extent such Continuing Employee’s service was recognized under the corresponding Seller Benefit Plans in which such Continuing Employee participated immediately prior to the Closing Date.
5.9Savings Plans. Effective as of the Closing Date, Purchaser or one of its Affiliates shall establish or maintain a defined contribution 401(k) plan (or plans) and trust (or trusts) intended to qualify under Sections 401(a) and 501(a) of the Code in which all Continuing Non-Covered Employees shall be eligible to participate (“Purchaser Savings Plan”) and in which Covered Employees shall be eligible to participate (“Purchaser Union Savings Plan”) following the Closing Date. Continuing Employees shall be eligible to effect a direct rollover (as described in Section 401(a)(31) of the Code) from any Seller Benefit Plans which is a defined contribution 401(k) plan, to the Purchaser Savings Plan and the Purchaser Union Savings Plan, as applicable, and Purchaser or one of its Affiliates shall cause the Purchaser Savings Plan or Purchaser Union Savings Plan, as applicable, to accept such direct rollovers.
5.10Incentive Awards. Purchaser shall, and shall cause its Affiliates, as applicable, to maintain the bonus opportunities provided for under any Seller Benefit Plan that is an annual bonus plan through the end of the fiscal year in which the Closing occurs and will pay any bonuses earned thereunder at such time as Sellers and their Affiliates has historically paid such bonuses. Each Continuing Employee’s bonus in respect of the fiscal year in which the Closing occurs shall be bifurcated as follows: (i) such bonus shall not be less than such Continuing Employee’s target bonus in respect of such fiscal year prior to the Closing under the applicable Seller Benefit Plan and (ii) such bonus shall be based on the actual performance of Purchaser in respect of such fiscal year following the Closing.
5.11Pre-Closing Date Claims under Seller Benefit Plans. To the extent that an Acquired Company Employee was a participant in a Seller Benefit Plan, the Seller Benefit Plans shall be responsible for providing benefits (including medical, hospital, dental, accidental death and dismemberment, life, disability and other similar benefits) to any participating Acquired Company Employees for all Claims incurred prior to the Closing under and subject to the generally applicable terms and conditions of such plans. For purposes of this Section 5.11, a Claim is incurred with respect to (i) accidental death and dismemberment, disability, life and other similar benefits when the event giving rise to such Claim occurred and (ii) medical, hospital, dental and other similar benefits when the services with respect to such Claim are rendered, and in any event as defined by the underlying terms of the Seller Benefit Plans. Purchaser shall, or shall cause one of its Affiliates to, assume and honor all accrued and unused vacation and paid time off balances of the Continuing Employees in accordance with the applicable Seller Benefit Plan in effect at the Closing Date, except to the extent any such balances are paid to such Continuing Employee in connection with the Closing in accordance with any applicable Laws.
5.12[Reserved]
5.13Workers Compensation. Sellers and their Affiliates shall be responsible for and administer all claims for workers compensation benefits that are incurred prior to the Closing by Continuing Employees. Purchaser and its Affiliates shall be responsible for and shall administer all claims for workers compensation benefits that are incurred from and after the Closing by Continuing Employees. A claim for workers compensation benefits shall be deemed to be incurred when the claim for workers compensation benefits is filed by the Continuing Employee with the applicable governmental authority (the “Workers Compensation Event”).
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5.14WARN Act. From the Effective Date until the Closing Date, Sellers shall not, and shall cause their Affiliates not to, terminate the employment of Acquired Company Employees such that a “plant closing” or “mass layoff” (as those terms are defined in the WARN Act) occurs prior to or as of the Closing, except pursuant to Section 4.1(a)(v). Purchaser agrees that the Acquired Companies shall be responsible for providing any notice required under (or otherwise satisfying the requirements of) the WARN Act with respect to any “plant closing” or “mass layoff” affecting Continuing Employees that may occur after the Closing Date. Sellers shall be responsible for providing any notice required under (or otherwise satisfying the requirements of) the WARN Act with respect to any “plant closing” or “mass layoff” affecting any employees of Seller or any of its Affiliates (other than the Acquired Companies) who do not become Continuing Employees.
5.15Employee Communications. Sellers shall use reasonable best efforts to cooperate with Purchaser and its Affiliates in communications with Acquired Companies Employees with respect to employment and employee benefit plan matters arising in connection with the transactions contemplated by this Agreement.
5.16No Third-Party Beneficiary Rights. Nothing in this Article V, expressed or implied, shall confer upon any Person (including the Acquired Companies Employees, Continuing Employees or any other employees of Sellers, Purchaser, or any of their respective Affiliates or any of their dependents, beneficiaries or alternate payees) other than the Parties any rights or remedies (including any third-party beneficiary rights, any right to employment or continued employment, or any right to any particular terms of conditions of employment or compensation or benefits for any period) of any nature or kind whatsoever, under or by reason of this Agreement or otherwise, and nothing in this Article V shall (i) affect the right of each of Sellers, Purchaser or their respective Affiliates to terminate the employment of any Person for any or no reason at any time, (ii) require Sellers or any of their Affiliates to continue any Seller Benefit Plan or other employee benefit plans or arrangements, (iii) prevent Sellers or any of their Affiliates from amending, modifying or terminating any Seller Benefit Plan or other employee benefit plans or arrangements, (iv) be construed as prohibiting or limiting the ability of Purchaser or any of its Affiliates to amend, modify or terminate any benefit or compensation plan, program, policy, Contract, agreement or arrangement at any time assumed, established, sponsored or maintained by any of them, or (v) be construed as an establishment of, amendment to or termination of any benefit or compensation plan, program, policy, Contract, agreement or arrangement. In addition, the provisions of this Section 5.16 are for the sole benefit of the Parties and are not for the benefit of any other Person, including any Acquired Company Employee, Continuing Employee, any other employee of any Sellers, Purchaser or any of their respective Affiliates (including any beneficiary or dependent thereof), or any other third party.
5.17Non-Solicitation of Business Employees. In the event that this Agreement is terminated prior to the Closing pursuant to the terms of this Agreement, until the date that is one (1) year from and after the date of such termination, (i) Purchaser shall not employ, and shall cause its Affiliates not to employ, any Acquired Company Employees or any Mitchell Employees to whom Purchaser or its Representatives had been directly or indirectly introduced or otherwise had contact with as a result of its consideration of the transactions contemplated hereby without Sellers’ prior written consent and (ii) Purchaser shall not, and shall cause its Affiliates not to, directly or indirectly, solicit for hire or employment any officer or employee of Sellers or any of their Affiliates to whom Purchaser or its Representatives had been directly or indirectly introduced or otherwise had contact with as a result of its consideration of the transactions contemplated hereby. From and after Closing, until the date that is one (1) year after the Closing Date, (A) Sellers shall not employ, and shall cause their Affiliates not to employ, any Continuing Employees without Purchaser’s prior written consent and (B) Sellers shall not, and shall cause their Affiliates not to, directly or indirectly, solicit for hire or employment any officer or employee of Purchaser or any of its Affiliates to whom Sellers or their Representatives had been directly or indirectly introduced or otherwise had contact with as a result
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of its consideration of the transactions contemplated hereby. Notwithstanding anything to the contrary in this Section 5.17, the terms of this Section 5.17 shall not apply to (x) any solicitation that consists of a general advertisement or solicitation by Purchaser or Sellers or their Affiliates through the use of media advertisements, the Internet (including Sellers’ or their Affiliates’ internal career websites), or professional search firms that is not targeted at employees of Sellers, Purchaser or their Affiliates, as applicable, or (y) any solicitation (or any hiring as a result of any solicitation) of any person who for a period of at least six (6) months prior to such solicitation (and hiring) has no longer been employed by Sellers, Purchaser or their Affiliates, as applicable, other than as a result of any solicitation otherwise prohibited by this Section 5.17.
5.18Code Section 409A. Contingent upon and effective as of the Closing Date, pursuant to 26 CFR §1.409A-3(j)(4)(ix), the Parties acknowledge and agree that the following Seller Benefit Plans (the “Seller Nonqualified Plans”) shall be considered terminated with respect to each participant that experiences a change in control of the Acquired Companies by reason of the transactions effectuated under this Agreement (the “Affected Participants,” being those plan participants who continue employment with the Acquired Companies (or other affiliates of the Purchaser) immediately after the Closing Date: (i) American Electric Power System Excess Benefit Plan; (ii) Central and South West System Special Executive Retirement Plan; (iii) American Electric Power System Supplemental Retirement Savings Plan; and (iv) American Electric Power System Incentive Compensation Deferral Plan. The Parties acknowledge and agree that contingent upon and effective as of the Closing Date, all of the Affected Participants shall receive all amounts deferred under the Affected Plans within 12 months of the Closing Date.
5.19Transfer of Certain Employees. Sellers and Purchaser shall cooperate to cause an Acquired Company, at least 30 days prior to the reasonably expected Closing Date, to make an offer of employment to each of the Covered Support Employees, which offer shall be based on the terms of the applicable Collective Bargaining Agreement and conditioned upon the occurrence of the Closing and effective as of the Closing Date. Sellers and Purchaser shall cooperate to cause an Acquired Company, at least 30 days prior to the reasonably expected Closing Date, to make a Qualifying Offer of employment to each of the Non-Covered Support Employees, which Qualifying Offer shall be conditioned upon the occurrence of the Closing and effective as of the Closing Date, except in the case of Support Employees who are not actively at work as of the Closing Date due to long-term disability or other approved continuous leave of absence (excluding, without limitation, paid-time off, short-term disability or intermittent leave) (“Delayed Transfer Employees”), in which case such offers (or reemployment) shall be made as of the date, if any, each such Support Employee has been cleared for and returns to active employment within 12 months following the Closing Date or such later date as required by Law and effective immediately following acceptance. At least 30 days prior to the reasonably expected Closing Date, Sellers shall provide Purchaser a list of Delayed Transfer Employees, which list shall be updated as necessary prior to Closing. A “Qualifying Offer” means an offer of employment in a position comparable to that which such Support Employee had immediately prior to the Closing (or, in the case of a Delayed Transfer Employee, commencement of his or her absence from active employment). Sellers shall retain and be solely responsible for all Liabilities arising from or relating to Sellers’ or any of its Affiliates’ identification of Support Employees (or the omission of any person from that list). At least 21 days prior to the reasonably expected Closing Date, Purchaser shall add Section 5.19 to the Purchaser Disclosure Letter to confirm that Purchaser has made a Qualifying Offer of employment to each of the Support Employees as set forth in this section (other than any Delayed Transfer Employees who has not then returned to active employment) and to indicate each Support Employees who has accepted such offer of employment. Sellers shall cause each of such accepting Support Employee to become an employee of Kentucky Power prior to the Closing Date. Any Delayed Transfer Employee who accepts a Qualifying Offer that will not become effective until after the Closing Date pursuant to this Section 5.19 shall become an employee of Purchaser (or an Affiliate of Purchaser effective immediately upon acceptance.
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ARTICLE VI
TAX MATTERS

6.1Withholding. Unless required by a change in Law after the date hereof, Purchaser, its Affiliates, and any of their agents, shall not deduct and withhold from any amount otherwise payable pursuant to this Agreement other than with respect to amounts (a) as a result of a failure to deliver the certificate or applicable tax form described in Section 1.3(b)(i)(C) or (b) which are treated as wages for U.S. federal income tax purposes. If any of Purchaser or its Affiliates or agents proposes to withhold any amounts, such Person shall use its reasonable best efforts to notify Sellers at least five business days in advance of making any such withholding or deduction and use its reasonable best efforts to cooperate with Sellers in reducing or eliminating any such proposed withholding or deduction. If any amount is so withheld, such amount shall be (i) properly and timely paid over to the applicable Governmental Entity and (ii) treated for all purposes of this Agreement as having been paid to the Person with respect to which such deduction or withholding was imposed.
6.2Tax Year End. Purchaser shall cause the Acquired Companies to join Purchaser’s “consolidated group” (as defined in Treasury Regulations Section 1.1502-1(h)) effective on the day after the Closing Date. Following the Closing, Purchaser shall not, and shall cause the Acquired Companies to not, take any action, or permit any action to be taken, that may prevent the taxable year of the Acquired Companies from ending for U.S. federal and (to the extent permitted under applicable Law) state, local or non-U.S. Income Tax purposes at the end of the day on which the Closing occurs and shall, to the extent permitted by applicable Law, elect with the relevant taxing authority to treat for all Income Tax purposes the Closing Date as the last day for which the Acquired Companies are included in the Seller Affiliated Tax Group. For the avoidance of doubt, Sellers shall prepare, or cause to be prepared, and file, or cause to be filed, all Tax Returns of or with respect to the Acquired Companies for Tax periods ending on and before the Closing Date.
6.3Tax Proceedings. Notwithstanding anything in this Agreement to the contrary, Sellers shall have the exclusive right to control in all respects, and neither Purchaser nor any of its Affiliates shall be entitled to participate in, any Tax Proceeding with respect to any Tax Return filed by or with respect to, or Tax matters relating to, the Seller Affiliated Tax Group.
6.4Cooperation with Respect to Taxes.
(a)Each Party shall, and shall cause its Affiliates to, provide to the other Parties such cooperation, documentation and information as either of them reasonably may request in (i) preparing and filing any Tax Return, amended Tax Return or claim for refund, (ii) determining a liability for Taxes or a right to refund of Taxes or (iii) conducting any Tax Proceeding. Such cooperation, documentation and information shall include providing necessary powers of attorney, copies of all relevant portions of relevant Tax Returns, together with all relevant portions of relevant accompanying schedules and relevant work papers, relevant documents relating to rulings or other determinations by taxing authorities and relevant records concerning the ownership and Tax basis of property and other relevant information that any such Party may possess. Each Party shall make its employees reasonably available on a mutually convenient basis at its own cost to provide an explanation of any documents or information so provided.
(b)Notwithstanding anything to the contrary in this Agreement, nothing in this Agreement shall be construed to require any Seller (or any of its Affiliates) (i) to provide cooperation, documentation or information with respect to Taxes or Tax Returns of the Seller Affiliated Tax Group or (ii) to provide Purchaser (or any of its Affiliates, including the Acquired Companies) with access to any
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such documentation, information or records, provided that, in each case, Seller and its Affiliates shall use commercially reasonable efforts to provide Purchaser with reasonable cooperation, documentation, information or records that are in Seller’s possession and that are redacted or are pro forma and relate exclusively to the Acquired Companies. 
6.5Tax Sharing Agreements. On or before the Closing Date, the rights and obligations of the Acquired Companies pursuant to all Tax sharing agreements or arrangements (other than this Agreement), if any, to which any Acquired Company, on the one hand, and any member of the Seller Affiliated Tax Group, on the other hand, are parties, shall terminate, and neither any member of the Seller Affiliated Tax Group, on the one hand, nor such Acquired Company, on the other hand, shall have any rights or obligations to each other after the Closing in respect of such agreements or arrangements.
6.6Transfer Taxes. Notwithstanding anything to the contrary in this Agreement, Purchaser and Seller shall split equally any sales, use, transfer, real property transfer, registration, documentary, stamp, value added or similar Taxes imposed on or payable in connection with the transactions contemplated by this Agreement (“Transfer Taxes”). The Party required by applicable Law to do so shall prepare and file, or cause to be prepared and filed, any Tax Return with respect to such Transfer Taxes.
6.7Post-Closing Matters.
(a)None of Purchaser or any of its Affiliates (including, after the Closing, the Acquired Companies) shall take any of the following actions, without the prior written consent of Sellers (which consent shall not be unreasonably withheld, conditioned or delayed): (i) make any Tax election, or change in Tax accounting period or method, that would have an effective date on or prior to the Closing Date or affect Taxes for any Seller or the Seller Affiliated Tax Group, (ii) amend any Tax Return for a Pre-Closing Tax Period, (iii) initiate or execute any voluntary disclosure agreement or similar agreement with any Tax authority with respect to a Pre-Closing Tax Period, (iv) extend the statute of limitations with respect to any Tax Return filed with respect to the Acquired Companies for any Pre-Closing Tax Period, or (v) engage in any action or transaction that is not in the ordinary course of business on the Closing Date but after the Closing.
(b)Notwithstanding any other provision of this Agreement, Purchaser shall report any transaction in which any Acquired Company engages that is not in the ordinary course of business and occurs on the Closing Date, but after the Closing, on Purchaser’s U.S. federal income Tax Return to the extent permitted by Treasury Regulations Section 1.1502-76(b)(1)(ii)(B).
(c)At Sellers’ request, Purchaser shall cause the Acquired Companies to make and/or join with the Seller Affiliated Tax Group in making any Tax election related to the Seller Affiliated Tax Group; provided, that the making of such election does not have an adverse effect in any material respect on Purchaser or the Acquired Companies for any Tax period beginning on or after the Closing.
(d)The Parties agree that no elections pursuant to Code Sections 336(e), 338(g) or 338(h)(10) shall be made by any Seller, any Affiliate of any Seller, Purchaser, any Affiliate of Purchaser, or the Acquired Companies, with respect to the Sale.
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ARTICLE VII

 CONDITIONS TO CLOSING
7.1Conditions to Each Party’s Closing Obligations. The respective obligations of each Party to effect the transactions contemplated hereby are subject to the fulfillment or, to the extent permitted by applicable Law, joint waiver, by the Parties at or prior to the Closing of each of the following conditions:
(a)No Injunctions. No Governmental Entity of competent authority and jurisdiction shall have issued an Order or enacted a Law that remains in effect that prohibits or makes illegal the consummation of the transactions contemplated hereby (collectively, the “Legal Restraints”).
(b)Regulatory Approvals. The Required Regulatory Approvals shall have been duly obtained, and such approvals shall have become Final Orders or, if applicable, any mandatory waiting period prescribed by Law before the transactions contemplated hereby may be consummated shall have expired or been terminated.
(c)NSR Consent Decree. The amended NSR Consent Decree contemplated by Section 4.13 shall have been duly executed and delivered by all parties thereto, approved and entered by the United States District Court for the Southern District of Ohio and in full force and effect.
(d)Mitchell Plant Approvals. The Mitchell Plant Approvals shall have been duly obtained, and such approvals shall have become Final Orders.
7.2Conditions to Purchaser’s Closing Obligations. Purchaser’s obligations to effect the transactions contemplated hereby are subject to the fulfillment or, to the extent permitted by applicable Law, waiver by Purchaser, at or prior to the Closing of each of the following additional conditions:
(a)Representations and Warranties. (i) The representations and warranties of Sellers set forth in Section 2.1, Section 2.2, Section 2.3, Section 2.4(i) and Section 2.17 shall be true and correct (other than in de minimis respects) as of the Closing, as if made at and as of the Closing (or, if expressly made as of a specific date, as of such date), (ii) the representation and warranty of Sellers set forth in Section 2.6(b) shall be true and correct as of the Closing, as if made at and as of the Closing and (iii) each of the other representations and warranties of Sellers contained in Article II (disregarding all qualifications as to materiality or Material Adverse Effect contained therein) shall be true and correct as of the Closing as if made at and as of the Closing (or, if expressly made as of a specific date, as of such date), except in the case of this clause (iii), where the failure of such representations and warranties to be true and correct would not reasonably be expected to have, individually or in the aggregate, a Material Adverse Effect.
(b)Covenants and Agreements. The covenants and agreements of Sellers to be performed at or before the Closing in accordance with this Agreement shall have been performed in all material respects.
(c)Officer’s Certificates. Purchaser shall have received a certificate from each Seller, signed on its behalf by an executive officer of such Seller and dated the Closing Date, to the effect that the conditions set forth in Section 7.2(a) and Section 7.2(b) have been fulfilled.
(d)Absence of Material Adverse Effect. Since the Effective Date, no Material Adverse Effect shall have occurred.
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(e)Execution and Delivery of Ancillary Documents. Sellers or their applicable Affiliates shall have executed and delivered to Purchaser each of the Ancillary Documents to which they are a party, each of which shall be in full force and effect as of Closing.
(f)Burdensome Condition. No Required Regulatory Approval, Mitchell Plant Approval, Additional Regulatory Filing and Consent, amendment of the NSR Consent Decree contemplated by Section 4.13 shall, individually or in the aggregate, impose, be conditioned upon or contain terms, conditions, liabilities, obligations, commitments or sanctions resulting in, or otherwise create or have created, any Burdensome Condition.
7.3Conditions to Sellers’ Closing Obligation. Sellers’ obligations to effect the transactions contemplated hereby are subject to the fulfillment or, to the extent permitted by applicable Law, waiver by Sellers, at or prior to the Closing of each of the following additional conditions:
(a)Representations and Warranties. (i) The representations and warranties of Purchaser set forth in Section 3.1 and Section 3.2 shall be true and correct (other than de minimis respects) as of the Closing as if made at and as of the Closing (or, if expressly made as of a specific date, as of such date) and (ii) each of the other representations and warranties of Purchaser contained in Article III (disregarding all qualifications as to materiality or Purchaser Material Adverse Effect contained therein) shall be true and correct as of the Closing as if made at and as of the Closing (or, if expressly made as of a specific date, as of such date), except in the case of this clause (ii), where the failure of such representations and warranties to be true and correct would not reasonably be expected to have, individually or in the aggregate, a Purchaser Material Adverse Effect.
(b)Covenants and Agreements. The covenants and agreements of Purchaser to be performed at or before the Closing in accordance with this Agreement shall have been performed in all material respects.
(c)Officer’s Certificate. Sellers shall have received a certificate from Purchaser, signed on Purchaser’s behalf by an executive officer of Purchaser, stating that the conditions specified in Section 7.3(a) and Section 7.3(b) have been fulfilled.
(d)Execution and Delivery of Ancillary Documents. Purchaser or its applicable Affiliate shall have executed and delivered to Sellers each of the Ancillary Documents to which it is a party, each of which shall be in full force and effect as of Closing.
7.4Frustration of Closing Conditions. No Party may rely on the failure of any condition set forth in Section 7.1 or Section 7.3, as the case may be, either as a basis for not consummating the Sale or any of the other transactions contemplated by this Agreement, or as a basis for terminating this Agreement, if such failure was caused by such Person’s or its Affiliates’ failure to act in good faith or to use the efforts to cause the Closing to occur that are required by this Agreement.
ARTICLE VII

 TERMINATION
8.1Termination. This Agreement may be terminated at any time prior to the Closing:
(a)by mutual written consent of Sellers and Purchaser; or
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(b)by either Sellers or Purchaser, if:
(i)the Closing shall not have occurred on or before the date that is twelve (12) months after the date of this Agreement (the “Outside Date”); provided, that the right to terminate this Agreement under this clause (i) shall not be available to (x) any Party whose failure to perform in any material respect any of its covenants or agreements contained in this Agreement has been the cause of, or has resulted in, the failure of the Closing to occur on or before such date or (y) a Party if another Party has filed (and is then pursuing) an Action seeking specific performance as permitted by Section 10.13; provided, further, that if, as of the end of the day on the date that is twelve (12) months after the date of this Agreement, the conditions to the Closing set forth in Section 7.1 have not been fulfilled but all other conditions to the Closing have been fulfilled or are capable of being fulfilled at the Closing, then the Outside Date shall be the date that is eighteen (18) months after the date of this Agreement;
(ii)Sellers (in the case of a termination by Purchaser) or Purchaser (in the case of a termination by Sellers) shall have breached or failed to perform in any material respect any of their respective representations, warranties, covenants or other agreements contained in this Agreement, and such breach or failure to perform (A) would give rise to the failure of a condition set forth in Section 7.2(a) or 7.2(b) (in the case of termination by Purchaser) or Section 7.3(a) or 7.3(b) (in the case of termination by Sellers), and (B) (1) is incapable of being cured prior to the Outside Date or (2) if capable of being cured prior to the Outside Date, has not been cured prior to the earlier of (x) sixty (60) days after the date on which Sellers or Purchaser, as applicable, receives written notice of such alleged breach or failure to perform from the party seeking termination, stating such party’s intention to terminate this agreement pursuant to this Section 8.1(b)(ii) and the basis for such termination and (y) the Outside Date; provided, that the right to terminate this Agreement under this Section 8.1(b)(ii) shall not be available to any Party if such Party is then in breach of any of its respective representations, warranties, covenants or other agreements contained in this Agreement in a manner such that the conditions to the Closing set forth in Section 7.2(a) or Section 7.2(b) (with respect to a breach by any Seller) or Section 7.3(a) or Section 7.3(b) (with respect to a breach by Purchaser), as applicable, would not be satisfied;
(iii)the condition in Section 7.1(a) is not satisfied and the Legal Restraint giving rise to the non-satisfaction shall have become final and non-appealable; provided, that the right to terminate this Agreement under this Section 8.1(b)(iii) shall not be available to any Party whose failure to fulfill any of its covenants or other agreements contained in this Agreement shall have been the primary cause of such Legal Restraint; or
(iv)any Governmental Entity that must grant a Required Regulatory Approval or a Mitchell Plant Approval shall have denied such grant, and such denial shall have become final and non-appealable; provided, that the right to terminate this Agreement under this Section 8.1(b)(iv) shall not be available to any Party whose failure to fulfill any of its covenants or other agreements contained in this Agreement shall have been the primary cause of such denial.
(c)by Sellers, by written notice to Purchaser, if (i) the conditions set forth in Section 7.1 and Section 7.2 are satisfied or waived (other than those conditions that by their nature are to be satisfied at the Closing, but which are capable of being satisfied at the Closing if the Closing were to occur when required pursuant to Section 1.3(a)), (ii) Sellers deliver to Purchaser an irrevocable written notice on or after the date that the Closing is required to occur pursuant to Section 1.3(a) that all conditions set forth in Section 7.3 have been satisfied or waived as of such time (other than those conditions that by their nature are to be satisfied at the Closing but which are capable of being satisfied at the Closing if the Closing were to occur) and each Seller is ready, willing and able to consummate the Closing, and (iii) within
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two (2) Business Days after the delivery of such notice to Purchaser, Purchaser has failed to fulfill its obligation to pay the Closing Payment Amount in accordance with Section 1.2.
8.2Notice of Termination. In the event of termination of this Agreement pursuant to Section 8.1, written notice of such termination shall be given by the terminating Party (or Parties) to the other Parties.
8.3Termination Fee.
(a)In the event that each of: (i) this Agreement is terminated pursuant to (A) Section 8.1(b)(i) at a time when only the conditions (other than those conditions that by their nature are to be satisfied at the Closing, but which conditions would be capable of being satisfied if the Closing Date were the date of such termination) in Section 7.1(a) (but only if the applicable Legal Restraint relates to a Required Regulatory Approval) or Section 7.1(b) have not been satisfied, (B) Section 8.1(b)(iii) (but only if the applicable Legal Restraint relates to a Required Regulatory Approval), (C) Section 8.1(b)(iv) (but only due to a denial of a Required Regulatory Approval) or (D) Section 8.1(c), (ii) the conditions in Section 7.1(a) or 7.1(b) failed to be satisfied other than as a result of Sellers’ failure to perform in any material respect their obligations under Section 4.5 or otherwise under this Agreement, and (iii) at the time of such termination, all conditions set forth in Section 7.2(a) through Section 7.2(e) (inclusive) shall have been satisfied or waived (except for (A) those conditions that by their nature are to be satisfied at the Closing, but which conditions would be capable of being satisfied if the Closing Date were the date of such termination or (B) those conditions that have not been satisfied as a result of a breach of this Agreement by Purchaser), then, subject to Section 8.3(b), Purchaser shall, by way of compensation, pay or cause to be paid to Sellers an aggregate amount equal to $65,000,000 (the “Termination Fee”). If the Termination Fee becomes due and payable in accordance with this Section 8.3(a), then such fee shall be paid in each case by wire transfer (to an account designated by Sellers) of immediately available funds (I) prior to or concurrently with such termination in the event of a termination by Purchaser or (II) no later than three (3) Business Days following such termination in the event of a termination by Sellers. In no event shall Purchaser be required to pay the Termination Fee other than in the circumstances described in this Section 8.3(a). In addition, Purchaser shall not be required to pay the Termination Fee on more than one occasion. The Parties acknowledge that the Termination Fee shall not constitute a penalty but is liquidated damages, in a reasonable amount that shall compensate Sellers for the efforts and resources expended and opportunities foregone while negotiating this Agreement and in reliance on this Agreement, which amount would otherwise be impossible to calculate with precision. The Parties further acknowledge that the right of Sellers to receive the Termination Fee shall not limit or otherwise affect Sellers’ right to seek specific performance of Purchaser prior to the termination of this Agreement as provided in Section 10.13, or their rights as otherwise set forth in this Article VIII, and that Sellers may pursue both a grant of specific performance under Section 10.13 prior to the termination of this Agreement and the payment of the Termination Fee under this Section 8.3(a) and, solely with respect to a Willful Breach by Purchaser, any other remedies available at law or in equity; provided, however, that under no circumstances shall Sellers (whether acting together or separately and whether in one Action or separate Actions) be entitled to receive more than one of (x) a grant of specific performance that results in a Closing, (y) the Termination Fee or (z) receipt of monetary damages relating to any breach of this Agreement prior to the Closing or the termination of this Agreement without achieving the Closing (which in no event shall exceed the Base Purchase Price). Except in the case of Willful Breach and subject to Section 9.2, in any circumstance in which Sellers receive the Termination Fee, as the case may be, pursuant to this Section 8.3(a), together with any applicable costs and expenses described in Section 8.3(b), receipt of such fee and costs shall be the sole and exclusive remedy of Sellers and their Affiliates and their respective Representatives against Purchaser and its Affiliates and Representatives for any loss suffered as a result of any breach of any representation, warranty, covenant or agreement in this Agreement or in connection with the transactions contemplated
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hereby, and upon receipt of the Termination Fee, together with the costs and expenses described in Section 8.3(b), none of the foregoing Persons shall have any further liability or obligation relating to or arising out of this Agreement or the transactions contemplated hereby, whether in equity or at Law, in contract, in tort or otherwise; provided, further, that if at any time any payment of the Termination Fee is rescinded or must otherwise be returned by Sellers upon the insolvency, bankruptcy or reorganization of Purchaser or Guarantor or otherwise, the Termination Fee shall be treated as having not been paid.
(b)In the event Sellers commence a proceeding in order to obtain (i) payment hereunder that results in a judgment against Purchaser for the amounts set forth in Section 8.3(a), or (ii) specific performance or other equitable relief that results in a judgment against Purchaser pursuant to Section 10.13, then in either case Purchaser shall also pay to Sellers their costs and expenses (including reasonable attorneys’ fees and expenses) in connection with such proceeding, together with interest on the amounts due pursuant to Section 8.3(a) from the date such payment was required to be made until the date of payment at the prime lending rate as published in The Wall Street Journal in effect on the date such payment was required to be made.
8..4Effect of Termination. In the event of termination of this Agreement by any Seller or Purchaser pursuant to Section 8.1, this Agreement shall terminate and become void and have no effect, and there shall be no liability on the part of any Party, except as set forth in Section 8.3 and the Confidentiality Agreement; provided, that termination of this Agreement shall not relieve any Party from liability for Willful Breach or Fraud (subject to Section 9.1). For purposes hereof, “Willful Breach” shall mean a breach that is a consequence of a deliberate act or deliberate failure to act undertaken by the breaching Party with the knowledge that the taking of, or failure to take, such act would cause the failure of the transactions contemplated by this Agreement to be consummated; provided that, without limiting the meaning of Willful Breach, the Parties acknowledge and agree that any failure by any Party to consummate the Sale after the applicable conditions to the Closing set forth in Article VII have been satisfied or waived (except for those conditions that by their nature are to be satisfied at the Closing, and which conditions would be capable of being satisfied at the time of such failure to consummate the Sale) shall constitute a Willful Breach of this Agreement by such Party. For the avoidance of doubt, (a) in the event that all applicable conditions to the Closing set forth in Article VII have been satisfied or waived (except for those conditions that by their nature are to be satisfied at the Closing, and which conditions would be capable of being satisfied at the time of such failure to consummate the Sale), but Purchaser or any Seller fails to close for any reason, such failure to close shall be considered a Willful Breach by Purchaser or Sellers, as applicable, and (b) Purchaser acknowledges that the availability or unavailability of financing for the transactions contemplated by this Agreement shall have no effect on Purchaser’s obligations hereunder. Notwithstanding anything to the contrary contained herein, the provisions of Section 2.20, Section 3.10, Section 4.3(b), Section 4.7, Section 8.3, Article IX, Article X, and this Section 8.4 shall survive any termination of this Agreement.
8..5Extension; Waiver. At any time prior to the Closing, either Sellers or Purchaser may (but shall not be required to) (a) extend the time for performance of any of the obligations or other acts of the other Party, (b) waive any inaccuracies in the representations and warranties of another Party contained in this Agreement or in any document delivered by another Party pursuant to this Agreement or (c) subject to applicable Law, waive compliance with any of the agreements or conditions of another Party contained in this Agreement. Any such extension or waiver shall be valid only if set forth in an instrument in writing signed by the Party granting such extension or waiver sent in accordance with Section 10.3 and referencing this Section of the Agreement.
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ARTICLE IX

 SURVIVAL AND REMEDIES
9.1Survival of Representations, Warranties, Covenants and Agreements. The Parties hereto, intending to modify any applicable statute of limitations, agree that (a) subject to Section 9.2(a)(iv), representations and warranties in this Agreement and in any certificate delivered pursuant hereto shall terminate effective as of the Closing and shall not survive the Closing for any purpose, and thereafter there shall be no liability, except for Fraud, on the part of, nor shall any claim be made by, any Party or any of their respective Affiliates in respect thereof, and (b) after the Closing, there shall be no liability on the part of, nor shall any claim be made by, any Party or any of its respective Affiliates in respect of any covenant or agreement to be performed prior to the Closing. The rights provided under the R&W Policy will be Purchaser’s sole recourse (even in the event the R&W Policy is never issued by an insurer, the R&W Policy is revoked, cancelled or modified in any manner after issuance for any reason, a claim is denied in whole or in part by any insurer under the R&W Policy for any reason, including due to exclusions from coverage thereunder) for any breach of any representation or warranty of any Seller contained in this Agreement, and Sellers shall have no liability for any breach of any representation or warranty contained in this Agreement. Sellers’ aggregate liability arising out of or relating to any covenant or agreement in this Agreement shall not exceed an amount equal to the Base Purchase Price, and Purchaser’s aggregate liability arising out of or relating to any covenant or agreement in this Agreement shall not exceed the amount of the Base Purchase Price, provided, that the foregoing shall not limit any liability of Sellers or Purchaser under Section 9.2.
9.2Indemnification.
(a)Subject to the provisions of this Article IX, effective as of and after the Closing, each Seller shall, jointly and not severally, indemnify, defend and hold harmless Purchaser and its Affiliates, and their respective officers, directors, employees, agents, successors and assigns (collectively, the “Purchaser Indemnified Parties”), from and against any and all Losses incurred or suffered by any of the Purchaser Indemnified Parties, arising out of or resulting from any Liabilities of any Seller or any of its current, former or future Affiliates (i) to the extent, and solely to the extent, unrelated to the Business or the Acquired Companies, other than Liabilities to the extent relating to or arising in connection with any Contract between Sellers or any of their current, former or future Affiliates, on the one hand, and any Purchaser Indemnified Party, on the other hand, that is in effect at any time following the Closing, (ii) for any Taxes of any Seller or of any other Person for which the Acquired Companies are liable, including pursuant to Treasury Regulation Section 1.1502-6 or any similar provision of state, local or non-U.S. Law, as a result of having been, prior to the Closing, a member of a consolidated, combined, unitary or similar group to the extent such Taxes relate to an event or transaction occurring before the Closing, (iii) relating to any Seller Benefit Plan or other employee benefit plan of the Seller or any of its Affiliates (other than employee benefit plans sponsored, maintained and contributed to exclusively by the Acquired Companies) and any Liabilities relating to or arising with respect to any pension or other employee benefit plan subject to Title IV of ERISA, (iv) for any failure of the representations and warranties in Section 2.8 to be true and correct in all respects as of the date of this Agreement and as of Closing solely to the extent with respect to the “Joint Use Operating Agreement” (as defined in Section 4.20(e) of the Seller Disclosure Letter), which shall be deemed to be a Material Contract hereunder (and such representations and warranties (solely to the extent with respect to such Joint Use Operating Agreement) shall be deemed to survive the Closing indefinitely) or any failure to comply with Section 4.1(a)(iii) (disregarding the word “materially” therein for these purposes) solely to the extent with respect to such Joint Use Agreement or (v) for any of the matters set forth on Section 9.2(a) of the Sellers Disclosure Letter.
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(b)Subject to the other terms of this Agreement (including the provisions of this Article IX) and of the Ancillary Agreements, effective as of and after the Closing, Purchaser shall indemnify, defend and hold harmless each Seller and their Affiliates (which, for the avoidance of doubt, excludes the Acquired Companies and their respective subsidiaries), and their respective officers, directors, employees, agents, successors and assigns (collectively, the “Seller Indemnified Parties”), from and against any and all Losses incurred or suffered by any of the Seller Indemnified Parties, to the extent arising out of or resulting from any Liabilities of Purchaser or any of its Affiliates (including the Acquired Companies) to the extent, and solely to the extent, exclusively related to the Business (other than Liabilities to the extent relating to or arising in connection with (i) any criminal act of any Seller Indemnified Party, (ii) any criminal act of any Acquired Company or any of its officers, directors, employees, agents, successors or assigns that occurred prior to the Closing, (iii) any Contract between Purchaser or any of the Acquired Companies, on the one hand, and any Seller Indemnified Party, on the other hand, that is in effect at any time following the Closing or (iv) any Person, assets or Liabilities other than an Acquired Company or as otherwise expressly transferred to Purchaser pursuant to this Agreement).
(c)Procedures.
(i)A Person that may be entitled to be indemnified under this Agreement (the “Indemnified Party”) shall promptly notify the Party or Parties liable for such indemnification (the “Indemnifying Party”) in writing of any pending or threatened claim or demand that the Indemnified Party has determined has given or would reasonably be expected to give rise to such right of indemnification (including a pending or threatened claim or demand asserted by a third party against the Indemnified Party, such claim being a “Third Party Claim”), describing in reasonable detail (taking into account the information then available to the Indemnified Party) the facts and circumstances with respect to the subject matter of such claim or demand; provided, that the failure to provide such notice shall not release the Indemnifying Party from any of its obligations under Section 4.12(a) and this Section 9.2 except to the extent that the Indemnifying Party is materially prejudiced by such failure (as determined by a court of competent jurisdiction), it being agreed that notices for claims in respect of a breach of a covenant or agreement must be delivered prior to the expiration of any applicable survival period specified in Section 9.1 for such covenant or agreement.
(ii)Upon receipt of a notice of a Third Party Claim for indemnity from an Indemnified Party pursuant to Section 4.12(a) and this Section 9.2, the Indemnifying Party will be entitled, by notice to the Indemnified Party delivered within twenty (20) Business Days of the receipt of notice of such Third Party Claim, to assume the defense and control of such Third Party Claim (at the expense of such Indemnifying Party); provided, that the Indemnifying Party shall not be entitled to assume the defense and control of such Third Party Claim, if (i) the Third Party Claim relates to or arises in connection with any criminal Action, (ii) the Third Party Claim seeks an injunction or equitable relief against the Indemnified Party or any of its Affiliates, or (iii) defense of the Third Party Claim would reasonably be expected to harm the Indemnified Party’s reputation or business relationships,; provided, further, that if the Indemnifying Party assumes the defense and control of such Third Party Claim, the Indemnifying Party shall allow the Indemnified Party a reasonable opportunity to participate in the defense of such Third Party Claim with its own counsel and at its own expense except that the Indemnifying Party shall pay the reasonable and documented fees and expenses of such external separate counsel if representation of both the Indemnifying Party and the Indemnified Party by the same counsel would create a conflict of interest. If the Indemnifying Party does not assume the defense and control of any Third Party Claim pursuant to this Section 9.2(c)(ii), the Indemnified Party shall be entitled to assume and control such defense and the Indemnifying Party shall pay the reasonable and documented fees and expenses of external counsel retained by the Indemnified Party, but the Indemnifying Party may nonetheless participate in the defense of such Third Party Claim with its own counsel and at its own expense. Purchaser or Sellers, as the case may be,
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shall, and shall cause each of their respective Affiliates and Representatives to, reasonably cooperate with the Indemnifying Party in the defense of any Third Party Claim, including by furnishing books and records, personnel and witnesses, as appropriate for any defense of such Third Party Claim. If the Indemnifying Party has assumed the defense and control of a Third Party Claim, it shall be authorized to consent to a settlement or compromise of, or the entry of any judgment arising from, any Third Party Claim, in its sole discretion and without the consent of any Indemnified Party; provided, that such settlement or judgment does not involve any injunctive or other equitable relief or finding or admission of any violation of Law or admission of any wrongdoing by any Indemnified Party or any of its Affiliates and expressly unconditionally releases the Indemnified Party and its Affiliates from all Liabilities with respect to such Third Party Claim. No Indemnified Party will consent to the entry of any judgment or enter into any settlement or compromise with respect to a Third Party Claim without the prior written consent of the Indemnifying Party.
(d)Each of the parties hereto agrees to use its reasonable best efforts to mitigate its respective Losses to the extent required by applicable Law upon and after becoming aware of any event or condition that would reasonably be expected to give rise to any Losses that are indemnifiable hereunder and calculated after giving effect to any amounts covered by third parties, including insurance proceeds.
9.3No Recourse. Notwithstanding anything that may be expressed or implied in this Agreement or any document or instrument delivered in connection herewith, by its acceptance of the benefits of this Agreement, each Party covenants, agrees and acknowledges that neither Party, its Affiliates nor any of its Representatives have any right of recovery under this Agreement, or any claim based on any liabilities, obligations, commitments created or arising in connection with this Agreement against any Person who is not a party to this Agreement or an Ancillary Agreement, as applicable, including the former, current or future equity holders, controlling persons, directors, officers, employees, agents, Affiliates, members, managers or general or limited partners of any other party to this Agreement or any Ancillary Agreement, as applicable, or any former, current or future stockholder, controlling person, director, officer, employee, general or limited partner, member, manager, Affiliate or agent of any of the foregoing (each, a “Non-Recourse Party”), whether by or through a claim by or on behalf of such Party against any Non-Recourse Party, by the enforcement of any assessment or by any legal or equitable proceeding, by virtue of any statute, regulation or Law, or otherwise; provided, that nothing herein shall limit a Party’s recourse or liability with regard to Fraud or limit Purchaser’s right to enforce each Seller’s obligations under Section 1.4.
9.4Limitation on Consequential Damages. Notwithstanding anything contained in this Agreement or any Ancillary Agreement to the contrary, except with respect to Fraud, no Party shall have any liability pursuant to this Agreement or any Ancillary Agreement for (a) special, punitive, exemplary, incidental, consequential or indirect damages, (b) lost profits or lost business, loss of enterprise value, diminution in value, damage to reputation or loss of goodwill or (c) damages calculated based on a multiple of profits, revenue or any other financial metric hereunder, except, in each case of the foregoing clauses (a) and (b) if such damages, other than punitive or exemplary damages, were the reasonably foreseeable and probable consequence of such breach of this Agreement as of the time of such breach.
ARTICLE X

 GENERAL PROVISIONS
10.1Amendment. This Agreement may be amended, modified, or supplemented only by written agreement of Sellers and Purchaser.
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10.2Waivers and Consents. Except as otherwise provided in this Agreement, any failure of Sellers or Purchaser to comply with any obligation, covenant, agreement or condition herein may be waived by the Person entitled to the benefits thereof only by a written instrument signed by such Person granting such waiver, but such waiver or failure to insist upon strict compliance with such obligation, covenant, agreement, or condition shall not operate as a waiver of, or estoppel with respect to, any subsequent or other failure. All remedies, either under this Agreement or by Law or otherwise afforded, shall be cumulative and not alternative.
10.3Notices. All notices and other communications hereunder shall be in writing and shall be deemed given (a) when received, if delivered personally, (b) when sent, if sent by electronic mail or (c) when received, if mailed by overnight courier or certified mail (return receipt requested), postage prepaid, in each case, to the Party being notified at such Party’s address indicated below (or at such other address for a Party as is specified by like notice):
(a)If to Sellers:
American Electric Power Company, Inc.
1 Riverside Plaza
Columbus, OH 43215
Attention: Charles E. Zebula
 Email: [Redacted: Personal Information.]
AEP Transmission Company, LLC
1 Riverside Plaza
Columbus, OH 43215
Attention: Stephan T. Haynes
 Email: [Redacted: Personal Information.]
with a copy (which shall not constitute notice) to:
Morgan, Lewis & Bockius LLP
Attn: John G. Klauberg
Michael E. Espinoza
101 Park Ave.
New York, NY 10178-0060
Email: [Redacted: Personal Information.]
[Redacted: Personal Information.]
(b)If to Purchaser:
Liberty Utilities Co.
c/o Algonquin Power & Utilities Corp.
354 Davis Road, Suite 100
Oakville, Ontario, Canada L6J 2X1
Attention: Chief Legal Officer
Email: [Redacted: Personal Information.]
    [Redacted: Personal Information.]
with a copy (which shall not constitute notice) to:
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Simpson Thacher & Bartlett LLP 425 Lexington Avenue
New York, NY 10017
Attention: Eli Hunt
Email: [Redacted: Personal Information.]
10.4Assignment. This Agreement and all of the provisions hereof shall be binding upon and inure to the benefit of Sellers and Purchaser and their respective successors and permitted assigns, but neither this Agreement nor any of the rights, interests, or obligations hereunder may be assigned by Sellers or Purchaser, without the prior written consent of Sellers (in the case of an assignment by Purchaser) or of Purchaser (in the case of assignment by Sellers); provided, that Purchaser may assign its rights and obligations hereunder to its lenders for collateral security purposes or, prior to the date any filings or notices are made to Governmental Entities with respect to any Required Regulatory Approval or any Mitchell Plant Approval pursuant to Section 4.5(a) (or otherwise to the extent such assignment would not adversely affect or materially delay any such Required Regulatory Approval or Mitchell Plant Approval), to an Affiliate without the prior written consent of Sellers, but such assignment shall not release Purchaser from its obligations hereunder.
10.5No Third-Party Beneficiaries. Except for Sections 4.11 and 4.13 in each case which are intended to benefit, and to be enforceable by, the parties specified therein, this Agreement, together with the Ancillary Agreements and the Exhibits and Schedules hereto, are not intended to confer in or on behalf of any Person not a Party (and their successors and assigns) any rights, benefits, causes of action or remedies with respect to the subject matter or any provision hereof.
10.6Expenses. Purchaser shall bear sole responsibility for all filing fees incurred in connection with any filings or submissions for obtaining the Required Regulatory Approvals or Additional Regulatory Filings and Consents and Sellers shall bear sole responsibility for all filing fees incurred in connection with any filings or submissions for obtaining the Mitchell Plant Approvals. Except as otherwise set forth in this Agreement, whether the transactions contemplated by this Agreement are consummated or not, all legal and other costs and expenses incurred in connection with this Agreement and the transactions contemplated by this Agreement shall be paid by the Party incurring such costs and expenses described in the immediately preceding sentence unless expressly otherwise contemplated in this Agreement. Any of the foregoing costs and expenses incurred by any Acquired Company prior to the Closing Date shall be a cost and expense of Sellers and, to the extent not paid prior to the Closing, shall be included in the Transaction Expenses.
10.7Governing Law. This Agreement (as well as any claim or controversy arising out of or relating to this Agreement or the transactions contemplated hereby) shall be governed by and construed in accordance with the Laws of the State of New York.
10.8Severability. Any term or provision of this Agreement that is invalid or unenforceable in any situation in any jurisdiction shall not affect the validity or enforceability of the remaining terms and provisions hereof or the validity or enforceability of the offending term or provision in any other situation or in any other jurisdiction.
10.9Entire Agreement. This Agreement shall be a valid and binding agreement of the Parties only if and when it is fully executed and delivered by Sellers and Purchaser, and until such execution and delivery no legal obligation shall be created by virtue hereof. This Agreement, the Confidentiality Agreement and the Ancillary Agreements, together with the Exhibits and Schedules hereto and thereto and the certificates and instruments delivered hereunder or in accordance herewith, embodies the entire agreement and understanding of Sellers and Purchaser in respect of the transactions contemplated by this Agreement. This Agreement, the Confidentiality Agreement and any currently effective Ancillary
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Agreements supersede all prior agreements and understandings between Sellers, on the one hand, and Purchaser, on the other hand, with respect to the matters contemplated hereby. Neither this Agreement, the Confidentiality Agreement nor any Ancillary Agreement shall be deemed to contain or imply any restriction, covenant, representation, warranty, agreement or undertaking of Sellers or Purchaser with respect to the transactions contemplated hereby or thereby other than those expressly set forth herein or therein or in any document required to be delivered hereunder or thereunder.
10.10Delivery. This Agreement, and any certificates and instruments delivered hereunder or in accordance herewith, may be executed in multiple counterparts (each of which shall be deemed an original, but all of which together shall constitute one and the same instrument). Signatures to this Agreement transmitted by facsimile transmission, by electronic mail in “portable document format” (.pdf) form, or by any other electronic means intended to preserve the original graphic and pictorial appearance of a document, shall have the same effect as physical delivery of the paper document bearing the original signature.
10.11Waiver of Jury Trial. EACH OF THE PARTIES HEREBY IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY LAW, ANY AND ALL RIGHT TO TRIAL BY JURY IN ANY ACTION ARISING OUT OF OR RELATED TO THIS AGREEMENT OR THE ANCILLARY AGREEMENTS OR ANY OF THE TRANSACTIONS CONTEMPLATED HEREBY OR THEREBY. EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HERETO HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH PARTY WOULD NOT, IN THE EVENT OF ANY ACTION, SUIT OR PROCEEDING, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVER AND CERTIFICATIONS IN THIS SECTION 10.11.
10.12Submission to Jurisdiction. Sellers and Purchaser irrevocably agree that any Action arising out of or relating to this Agreement brought by a Party (or any of their respective successors or assigns) shall be brought and determined in any state or federal court sitting in the State of New York, within the Borough of Manhattan, City of New York, and Sellers and Purchaser hereby irrevocably submit to the exclusive jurisdiction of the aforesaid courts for themselves and with respect to their property, generally and unconditionally, with regard to any such Action arising out of or relating to this Agreement and the transactions contemplated hereby. Sellers and Purchaser agree not to commence any Action relating thereto except in the courts described above in New York, other than Actions in any court of competent jurisdiction to enforce any judgment, decree or award rendered by any such court in New York as described herein. Sellers and Purchaser further agree that notice as provided herein shall constitute sufficient service of process and Sellers and Purchaser further waive any argument that such service is insufficient. Sellers and Purchaser hereby irrevocably and unconditionally waive, and agree not to assert, by way of motion or as a defense, counterclaim or otherwise, in any Action arising out of or relating to this Agreement or the transactions contemplated hereby, (a) any claim that it is not personally subject to the jurisdiction of the courts in New York as described herein for any reason, (b) that it or its property is exempt or immune from jurisdiction of any such court or from any legal process commenced in such courts (whether through service of notice, attachment prior to judgment, attachment in aid of execution of judgment, execution of judgment or otherwise) and (c) that (i) the Action in any such court is brought in an inconvenient forum, (ii) the venue of such Action is improper or (iii) this Agreement, or the subject matter hereof, may not be enforced in or by such courts.
10.13Specific Performance. Sellers and Purchaser agree that irreparable damage would occur in the event that any of the provisions of this Agreement were not performed in accordance with their specific terms or were otherwise breached. Accordingly, Sellers and Purchaser shall be entitled to specific
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performance of the terms hereof, including an injunction or injunctions to prevent breaches of this Agreement and to enforce specifically the terms and provisions of this Agreement in any state or federal court sitting in the State of New York, this being in addition to any other remedy to which they are entitled at law or in equity. Sellers and Purchaser hereby further waive (a) any defense in any action for specific performance that a remedy at law would be adequate and (b) any requirement under any Law to post security as a prerequisite to obtaining equitable relief.
10.14Disclosure Generally. Notwithstanding anything to the contrary contained in the Sellers Disclosure Letter or in this Agreement, the information and disclosures contained in any Sellers Disclosure Letter shall be deemed to be disclosed and incorporated by reference with respect to any other representation or warranty of Sellers if the applicability of such information and disclosure is reasonably apparent on its face. The fact that any item of information is disclosed in any Sellers Disclosure Letter shall not be construed to mean that such information is required to be disclosed by this Agreement. Such information and the dollar thresholds set forth herein shall not be used as a basis for interpreting the terms “material” or “Material Adverse Effect” or other similar terms in this Agreement. The fact that any item of information is disclosed in any Sellers Disclosure Letter shall not be construed to constitute an admission of any liability or obligation of any party to any third party, nor an admission to any third party against the interests of any or all of the parties.
10.15Provision Respecting Legal Representation. Notwithstanding that Morgan Lewis has acted as legal counsel to the Acquired Companies prior to the Closing in connection with this Agreement and the transactions contemplated by this Agreement (the “Pre-Closing Engagement”), and recognizing that Morgan Lewis intends to act as legal counsel to Sellers and their respective Affiliates after the Closing, Purchaser hereby waives, on its own behalf, and agrees to cause its Affiliates (including the Acquired Companies after the Closing) to waive, any conflicts that may arise in connection with Morgan Lewis representing Sellers or any of their respective Affiliates after the Closing, as such representation may conflict with the Pre-Closing Engagement. In addition, all communications relating to the Pre-Closing Engagement and involving attorney-client confidences between Sellers, their respective Affiliates or the Acquired Companies and Morgan Lewis shall be deemed to be attorney-client confidences that belong solely to Sellers and their respective Affiliates (and not the Acquired Companies). Accordingly, the Acquired Companies shall not, without the Sellers’ consent, have access to the files of Morgan Lewis relating to the Pre-Closing Engagement. Without limiting the generality of the foregoing, upon and after the Closing, (a) Sellers and their respective Affiliates (and not the Acquired Companies) shall be the sole holders of the attorney-client privilege with respect to the Pre-Closing Engagement, and none of the Acquired Companies shall be a holder thereof, (b) to the extent that files of Morgan Lewis in respect of the Pre-Closing Engagement constitute property of the client, only Sellers and their respective Affiliates (and not the Acquired Companies) shall hold such property rights and (c) Morgan Lewis have no duty whatsoever to reveal or disclose any such attorney-client communications or files to any of the Acquired Companies by reason of any attorney-client relationship between Morgan Lewis and the Acquired Companies or otherwise.
10.16Privilege. Purchaser, for itself and its Affiliates, and its and its Affiliates’ respective successors and assigns, hereby irrevocably and unconditionally acknowledges and agrees that all attorney-client privileged communications between Sellers, the Acquired Companies and their respective current or former Affiliates or Representatives and their counsel, including Morgan Lewis, made before the consummation of the Closing to the extent relating to the negotiation, preparation, execution, delivery of this Agreement and the Ancillary Agreements and the consummation of the transactions contemplated hereby and thereby which, immediately before the Closing, would be deemed to be privileged communications and would not be subject to disclosure to Purchaser (or would otherwise not be disclosable to Purchaser without losing any such right of privilege) in connection with any Action arising out of or
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relating to this Agreement or otherwise, shall continue after the Closing to be privileged communications with such counsel and neither Purchaser nor any of its Affiliates (including after the Closing, the Acquired Companies) shall seek to obtain the same by any process on the grounds that the privilege attaching to such communications belongs to Purchaser or the Acquired Companies or on any other grounds.
10.17Disclaimer. EXCEPT AS OTHERWISE EXPRESSLY PROVIDED HEREIN OR IN THE ANCILLARY AGREEMENTS, SELLERS EXPRESSLY DISCLAIM ANY REPRESENTATIONS OR WARRANTIES OF ANY KIND OR NATURE, EXPRESS OR IMPLIED, AS TO THE CONDITION, VALUE OR QUALITY OF THE ASSETS OR OPERATIONS OF THE ACQUIRED COMPANIES OR THE PROSPECTS (FINANCIAL AND OTHERWISE), RISKS AND OTHER INCIDENTS OF THE ACQUIRED COMPANIES AND SELLERS SPECIFICALLY DISCLAIM ANY REPRESENTATION OR WARRANTY OF MERCHANTABILITY, USAGE, SUITABILITY OR FITNESS FOR ANY PARTICULAR PURPOSE WITH RESPECT TO SUCH ASSETS, OR ANY PART THEREOF, OR AS TO THE WORKMANSHIP THEREOF, OR THE ABSENCE OF ANY DEFECTS THEREIN, WHETHER LATENT OR PATENT, OR COMPLIANCE WITH ENVIRONMENTAL REQUIREMENTS, OR AS TO THE CONDITION OF, OR THE RIGHTS OF THE ACQUIRED COMPANIES IN, OR ITS TITLE TO, ANY OF ITS ASSETS, OR ANY PART THEREOF. EXCEPT AS EXPRESSLY PROVIDED HEREIN OR IN THE RELATED AGREEMENTS, NO MATERIAL OR INFORMATION PROVIDED BY OR COMMUNICATIONS MADE BY SELLERS OR THE ACQUIRED COMPANIES OR ANY OF THEIR RESPECTIVE REPRESENTATIVES SHALL CAUSE OR CREATE ANY WARRANTY, EXPRESS OR IMPLIED, AS TO THE CONDITION, VALUE OR QUALITY OF SUCH ASSETS.
10.18Definitions. For purposes of this Agreement, each capitalized term has the meaning given to it, or specified, in Appendix I.
10.19Other Interpretive Matters. Unless otherwise expressly provided, for purposes of this Agreement, the following rules of interpretation apply.
(a)Appendices, Exhibits and Schedules. Unless otherwise expressly indicated, any reference in this Agreement to an “Exhibit” or “Schedule” refers to an Exhibit or Schedule to this Agreement. The Exhibits and Schedules to this Agreement are hereby incorporated and made a part hereof as if set forth in full herein and are an integral part of this Agreement. Any capitalized terms used in any Exhibit or Schedule but not otherwise defined therein are defined as set forth in this Agreement. In the event of conflict or inconsistency, this Agreement shall prevail over any Exhibit or Schedule.
(b)Time Periods. When calculating the period of time before which, within which, following or after which any act is to be done or step taken pursuant to this Agreement, the date that is the reference date in calculating such period shall be excluded. If the last day of such period is a non-Business Day, the period in question shall end on the next succeeding Business Day.
(c)Gender and Number. Whenever the context requires, the gender of all words used in this Agreement includes the masculine, feminine, and neuter, and the singular includes the plural, and the plural includes the singular.
(d)Certain Terms. The words such as “herein,” “hereinafter,” “hereof,” and “hereunder” refer to this Agreement (including the Exhibits and Schedules to this Agreement) as a whole and not merely to a subdivision in which such words appear unless the context otherwise requires. The word “including” or any variation thereof means “including, without limitation” and does not limit any general statement that it follows to the specific or similar items or matters immediately following it. The
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words “to the extent” when used in reference to a liability or other matter, means that the liability or other matter referred to is included in part or excluded in part, with the portion included or excluded determined based on the portion of such liability or other matter exclusively related to the subject or period. The word “or” shall be disjunctive but not exclusive. A reference to any Party or to any party to any other agreement or document shall include such party’s successors and permitted assigns. A reference to any legislation or to any provision of any legislation shall include any amendment to, and any modification or reenactment thereof, any legislative provision substituted therefor and all regulations and statutory instruments issued thereunder or pursuant thereto (provided, that for purposes of any representations and warranties contained in this Agreement that are made as of a specific date, references to any statute shall be deemed to refer to such statute and any rules or regulations promulgated thereunder as amended through such specific date). The phrase “ordinary course of business” refers to the ordinary course of business of the Acquired Companies and not of Sellers and their Affiliates generally. References to “$” shall mean U.S. dollars and references to “written” or “in writing” include in electronic form. Any reference to “days” shall mean calendar days unless Business Days are expressly specified. Any reference to information “made available” or “provided” to Purchaser by Sellers or the Acquired Companies means that such information has been provided to Purchaser, its counsel or other Representatives through access to the “Project Nickel” online data room maintained by Sellers and hosted by Donnelly Financial Solutions in connection with the transactions contemplated by this Agreement, with such information and access provided at least three (3) Business Days prior to the date hereof.
(e)Headings. The division of this Agreement into Articles, Sections, and other subdivisions, and the insertion of headings are for convenience of reference only and do not affect, and shall not be utilized in construing or interpreting, this Agreement. All references in this Agreement to any “Section” are to the corresponding Section of this Agreement unless otherwise specified.
(f)Joint Participation. Each Party acknowledges that it and its attorney have been given an equal opportunity to negotiate the terms and conditions of this Agreement and that any rule of construction to the effect that ambiguities are to be resolved against the drafting Party or any similar rule operating against the drafter of an agreement shall not be applicable to the construction or interpretation of this Agreement.
(g)Accounting Terms. All accounting terms used herein and not expressly defined herein shall have the meanings given to them under GAAP or FERC Accounting Requirements, as applicable.
[Remainder of page intentionally left blank]
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IN WITNESS WHEREOF, this Agreement has been signed by or on behalf of Sellers and Purchaser as of the date first set forth above.

	
				
 	AMERICAN ELECTRIC POWER COMPANY, INC.	
	 	 	 	
 	By:	/s/ Charles E. Zebula	
 	 	Name:	Charles E. Zebula	
 	 	Title:	Executive Vice President – Portfolio	
 	 	 	Optimization	
		
 	AEP TRANSMISSION COMPANY, LLC	
 	 	 	 	
 	By:	/s/ Charles E. Zebula	
 	 	Name:	Charles E. Zebula	
 	 	Title:	Vice President	

 	LIBERTY UTILITIES CO.	
	 	 	 	
 	By:	/s/ Jody Allison	
 	 	Name:	Jody Allison	
 	 	Title:	President	
 	 	 	 	
	By:	/s/ Todd Wiley	
	 	Name:	Todd Wiley	
	 	Title:	Treasurer and Secretary	

[Signature Page to Stock Purchase Agreement]

APPENDIX I
DEFINITIONS

1.Defined Terms. For the purposes of this Agreement, the following terms shall have the following meanings:
“Acquired Company Employees” shall mean (a) all employees of an Acquired Company as of the Effective Date who are included on the list of Acquired Company Employees set forth on Section 2.14(a) of the Sellers Disclosure Letter (b) any current employee of AEPSC or Appalachian Power Company in the positions set forth on Section 5.19 of the Sellers Disclosure Letter (a “Support Employee”) who shall become an employee of Kentucky Power prior to the Closing Date as contemplated by Section 5.19 and (c) any other employee who is hired by, or transferred to, an Acquired Company prior to the Closing Date; provided, however, that “Acquired Company Employees” shall not include any Mitchell Employee.
“Action” shall mean any claim, notice of claim, notice of violation, action, audit, demand, suit, prosecution, arbitration, litigation, proceeding, case, hearing or investigation (including any state regulatory proceeding) by or before any Governmental Entity, whether civil, criminal, administrative, regulatory or otherwise, and whether at law or in equity.
“AEPSC” shall mean American Electric Power Service Corporation, a New York corporation and an Affiliate of Sellers.
“Affiliate” shall mean, with respect to any Person, any other Person that directly or indirectly, controls, is controlled by, or is under common control with such Person. As used in this definition, “control” (including, with its correlative meanings, “controlled by” and “under common control with”) means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of a Person, whether through the ownership of securities or partnership or other ownership interests, by contract or otherwise; provided that, from and after the Closing, (a) neither of the Acquired Companies shall be considered an Affiliate of Sellers or any of Sellers’ Affiliates and (b) none of Sellers nor any of Sellers’ Affiliates shall be considered an Affiliate of either of the Acquired Companies.
“Ancillary Agreements” shall mean the Transition Services Agreement, Purchaser Guaranty, and the Compliance Agreement.
“Base Purchase Price” shall mean $2,846,000,000.
“Benefit Plan” shall mean each “employee benefit plan” as defined in Section 3(3) of ERISA, and all other retirement, pension, deferred compensation, bonus, incentive, severance, stock purchase, stock option, phantom stock, equity, employment, profit sharing, retention, stay bonus, change of control and other benefit plans, programs, agreements or arrangements.
“Big Sandy” shall mean the Big Sandy Power Plant, a natural gas fired power plant, located in Louisa, Kentucky.
“Business” means the business and operations of the Acquired Companies as currently conducted.
“Business Day” shall mean any day other than Saturday, Sunday, or any other day on which the Federal Reserve Bank of New York or banking institutions in Toronto, Ontario are closed.
“Capital Expenditures Amount” shall mean the total amount of all capital expenditures (including external and internal capitalized costs) both paid or payable (and if payable, reflected in Net Working
Appendix I-1

Capital) and incurred by the Acquired Companies during the period beginning on July 1, 2021 and ending as of the Reference Time that are properly characterized as capital expenditures and made in accordance with Good Utility Practice, calculated in accordance with the Accounting Principles, applied in a manner consistent with the principles, methodologies and adjustments used in connection with the preparation of Appendix II. Notwithstanding anything to the contrary in this Agreement, amounts paid or payable or incurred by any Acquired Company to purchase any leased property, plant or equipment, including amounts used to purchase property, plant or equipment under any Master Lease, shall not be deemed a “Capital Expenditures Amount”; provided that any purchase amounts actually paid by Kentucky Power prior to the Reference Time pursuant to Section 4.19 shall be considered capital expenditures for purposes of calculating the “Capital Expenditures Amount.”
“CFIUS” means the Committee on Foreign Investment in the United States.
“CFIUS Clearance” means that that: (a) (i) Purchaser has received written notice from CFIUS that the review period, or, if applicable, investigation period pursuant to the DPA of the transactions contemplated by this Agreement has been concluded, and (ii) CFIUS has determined that there are no unresolved national security concerns with respect to the transactions contemplated by this Agreement and advised that action pursuant to the DPA, and any investigation related thereto, has been concluded with respect to such transactions; (b) Purchaser has received written notice from CFIUS that CFIUS has concluded that the transactions contemplated by this Agreement are not “covered transactions” pursuant to the DPA and not subject to review under applicable Law; (c) CFIUS has sent a report to the President of the United States requesting the President’s decision on the CFIUS notice submitted by the Parties and either (x) the period pursuant to the DPA during which the President may announce his decision to take action to suspend, prohibit or place any limitations on the transactions contemplated hereby has expired without any such action being threatened, announced or taken or (y) the President of the United States has announced a decision not to take any action to suspend, prohibit or place any limitations on the transactions contemplated hereby; or (d) after submission of a declaration by the Parties with respect to the transactions contemplated by this Agreement pursuant to the DPA, that CFIUS, pursuant to 31 C.F.R. § 801.407(a)(2), informs the Parties that CFIUS is not able to complete action on the basis of the declaration and that the Purchaser in its sole discretion may file a written notice to seek written notification from CFIUS that CFIUS has concluded all action under the CFIUS Regulations with respect to the transactions contemplated by this Agreement.
“Change in Control Prepayment Event” shall have the meaning ascribed to it in the Senior Note Purchase Agreements.
“Claim” shall mean any demand, claim, action, legal proceeding (whether at law or in equity), investigation, arbitration, hearing, audit or similar proceeding.
“Closing Cash” shall mean the amount of cash and cash equivalents (including marketable securities) of the Acquired Companies, excluding any restricted cash and any insurance or third party indemnification or similar proceeds held as cash to the extent not yet applied to restore (or reimburse for the restoration) prior to the Reference Time of damage, condemnation, liability or casualty in respect of any asset or liability of the Acquired Companies that would not be included in Net Working Capital, in each case, as of the Reference Time, determined in accordance with the Accounting Principles. For the avoidance of doubt, Closing Cash will be calculated net of issued but uncleared checks and drafts and will include checks, other wire transfers and drafts deposited or available for deposit for the account of the Acquired Companies once cleared.
“Closing Indebtedness” shall mean the aggregate amount of Indebtedness of the Acquired Companies (without duplication), and all accrued and unpaid interest thereon, as of the Reference Time,
Appendix I-2

determined in accordance with the Accounting Principles, excluding trade accounts payable or other liabilities included in Net Working Capital or Transaction Expenses.
“Closing Payment Amount” shall mean the Base Purchase Price plus (a) the amount of the Estimated Closing Cash plus (b) the amount, if any, by which the Estimated Net Working Capital exceeds the Target Net Working Capital minus (c) the amount, if any, by which the Estimated Net Working Capital is less than the Target Net Working Capital minus (d) the amount of the Estimated Closing Indebtedness plus (e) the amount, if any, by which the Estimated Capital Expenditures Amount exceeds the Forecasted Capital Expenditures Amount minus (f) the amount, if any, by which the Estimated Capital Expenditures Amount is less than the Forecasted Capital Expenditures Amount minus (g) the amount of the Estimated Transaction Expenses (the amounts described in (a) through (g) the “Closing Payment Adjustment” ).
“COBRA Continuation Coverage” shall mean the continuation of group health plan coverage required under Sections 601 through 608 of ERISA, and Section 4980B of the Code and any comparable continuation of group health plan coverage required by applicable state or local Law.
“Code” shall mean the U.S. Internal Revenue Code of 1986, as amended.
“Collective Bargaining Agreements” shall mean each collective bargaining agreement with any labor union representing Acquired Company Employees as set forth on Section 2.14(b) of the Sellers Disclosure Letter.
“Commercial Hedge” means any forward, futures, swap, collar, put, call, floor, cap, option, financial transmission right or other Contracts that are intended to benefit from or reduce or eliminate the risk of fluctuations in the price of commodities, including electric power, in any form, including energy, capacity or any ancillary services, gas, coal, oil or other commodities, in each case, which are intended to be settled financially.
“Compliance Agreement” means the compliance agreement to be executed by AEP, Kentucky Power, Successor Operator and Purchaser and dated as of the Closing Date, substantially in the form attached hereto as Exhibit D.
“Confidentiality Agreement” shall mean the Confidentiality and Non-Disclosure Agreement, dated April 26, 2021, by and between AEP and Purchaser.
“Confidential Information” shall have the meaning ascribed to such term in the Confidentiality and Non-Disclosure Agreement.
“Continuing Employees” shall mean Continuing Non-Covered Employee and Continuing Covered Employees.
“Contract” shall mean any written contract, lease, license, evidence of Indebtedness, mortgage, indenture, purchase order, binding bid, letter of credit, security agreement or other written, legally binding agreement.
“Controlled Group Liability” means any and all Liabilities (a) under Title IV of ERISA, (b) under Sections 206(g), 302 or 303 of ERISA, (c) under Sections 412, 430, 431, 436 or 4971 of the Code, and (d) as a result of the failure to comply with the continuation of coverage requirements of Section 601 et seq. of ERISA and Section 4980B of the Code.
“Covered Employees” shall mean each Acquired Company Employee who is covered under a Collective Bargaining Agreement.
Appendix I-3

“COVID-19 Measures” means any reasonable actions or measures taken to comply with any applicable Laws, recommendations, guidelines and directives issued by any applicable Governmental Entity in response to the COVID-19 Pandemic.
“COVID-19 Pandemic” means the epidemic, pandemic or disease outbreak associated with the COVID-19 or SARS-CoV-2 virus (or any mutation or variation thereof).
“Debt Agreements” means the (a) Bond Purchase and Continuing Covenants Agreement between Kentucky Power and Key Government Finance, Inc., dated as of June 1, 2017, (b) Amended and Restated Credit Agreement among Kentucky Power, the lenders party thereto and Fifth Third Bank, dated as of October 26, 2018, (c) Credit Agreement among Kentucky Power, the lenders party thereto and Key Bank National Association, dated as of March 6, 2020, (d) Credit Agreement among Kentucky Power, the lenders party thereto and Canadian Imperial Bank of Commerce, New York Branch, dated as of June 17, 2021, (e) Senior Note Purchase Agreements and Senior KPCo Notes, (f) Utility Money Pool Agreement and (g) TransCo Intercompany Notes.
“Defendants” shall mean the defendants as defined in the NSR Consent Decree.
“DPA” means Section 721 of the Defense Production Act of 1950, as amended (50 U.S.C. §4565), and all rules and regulations thereunder, including those codified at 31 C.F.R. Parts 800 and 802.
“Easements” shall mean all easements, railroad crossing rights, rights-of-way, leases for rights-of-way, and similar use and access rights.
“Encumbrances” shall mean any mortgages, deeds of trust, liens, pledges, claims, charges, encumbrances, easements, servitudes, security interests or limitations on receipt of income.
“Environment” shall mean all or any of the following media: soil, land surface and subsurface strata, surface waters (including navigable waters, streams, ponds, drainage basins, and wetlands), groundwater, drinking water supply, stream sediments, ambient air (including the air within buildings), plant and animal life, and any other natural resource.
“Environmental Claims” shall mean any and all Actions arising under or pursuant to any Environmental Laws or Environmental Permits, or arising from the presence, Release, or threatened Release into the Environment of any Hazardous Materials, including any and all claims by any Governmental Entity or by any Person for enforcement, cleanup, remediation, removal, response, remedial or other actions or damages, contribution, indemnification, cost recovery, compensation, or injunctive relief pursuant to any Environmental Law.
“Environmental Laws” shall mean the Comprehensive Environmental Response, Compensation and Liability Act, 42 U.S.C. § 9601 et seq.; the Resource Conservation and Recovery Act, 42 U.S.C. § 6901 et seq.; the Federal Water Pollution Control Act, 33 U.S.C. § 1251 et seq.; the Clean Air Act, 42 U.S.C. § 7401 et seq.; the Toxic Substances Control Act, 15 U.S.C. §§ 2601 through 2629; the Oil Pollution Act, 33 U.S.C. § 2701 et seq.; the Emergency Planning and Community Right-to-Know Act, 42 U.S.C. § 11001 et seq.; the Safe Drinking Water Act, 42 U.S.C. §§ 300f through 300j; the Hazardous Materials Transportation Act of 1975, 49 U.S.C. § 5101 et seq.; and all other Laws (including implementing regulations) of any Governmental Entity addressing pollution or protection of the environment, or of human health or safety (as affected by any harmful or deleterious substances).
“Environmental Permits” shall mean all permits, registrations, certifications, licenses, franchises, exemptions, approvals, consents, waivers, water rights or other authorizations of Governmental Entities under applicable Environmental Laws.
Appendix I-4

“ERISA” shall mean the Employee Retirement Income Security Act of 1974.
“ERISA Affiliate” shall mean any Person, entity, trade or business that is a member of a group described in Section 414(b), (c), (m) or (o) of the Code or Section 400l(b)(l) of ERISA that includes any Seller, or that is a member of the same “controlled group” as a Seller pursuant to Section 4001(a), or that, together with any Seller would be treated as a single employer under Section 414 of the Code.
“Estimated Capital Expenditures Amount” shall mean the Capital Expenditures Amount reflected on the Estimated Closing Statement prepared in accordance with Section 1.4(b).
“Estimated Closing Cash” shall mean the Closing Cash reflected on the Estimated Closing Statement prepared in accordance with Section 1.4(b).
“Estimated Closing Indebtedness” shall mean the Closing Indebtedness reflected on the Estimated Closing Statement prepared in accordance with Section 1.4(b).
“Estimated Net Working Capital” shall mean an amount, which may be positive or negative, equal to the amount of Net Working Capital set forth in the Estimated Closing Statement prepared in accordance with Section 1.4(b).
“Estimated Transaction Expenses” shall mean the Transaction Expenses reflected on the Estimated Closing Statement prepared in accordance with Section 1.4(b).
“Existing Mitchell Plant Operating Agreement” shall mean that certain operating agreement for the Mitchell Plant, dated as of December 31, 2014, as amended, among Kentucky Power, Wheeling, and AEPSC, as agent.
“FERC” means the Federal Energy Regulatory Commission.
“FERC Accounting Requirements” means the accounting requirements of FERC, including with respect to the Uniform System of Accounts, established by FERC under the FPA.
“Final Capital Expenditures Amount” shall mean the Capital Expenditures Amount, if any, as set forth in the Final Closing Statement as prepared and finalized in accordance with Sections 1.5 and 1.6.
“Final Closing Cash” shall mean, the Closing Cash, if any, as set forth in the Final Closing Statement as prepared and finalized in accordance with Sections 1.5 and 1.6.
“Final Closing Indebtedness” shall mean the Closing Indebtedness, if any, as set forth in the Final Closing Statement as prepared and finalized in accordance with Sections 1.5 and 1.6.
“Final Net Working Capital” shall mean the amount of Net Working Capital, which may be positive or negative, as set forth in the Final Closing Statement as prepared and finalized in accordance with Sections 1.5 and 1.6.
“Final Order” shall mean an Order by the relevant Governmental Entity that (a) has not been reversed, stayed, enjoined, set aside, annulled or suspended and is in full force and effect, (b) with respect to which, if applicable, any mandatory waiting period prescribed by Law before the transactions contemplated hereby may be consummated has expired or been terminated and (c) as to which all conditions to the consummation of the transactions contemplated hereby prescribed by Law have been satisfied.
Appendix I-5

“Final Transaction Expenses” shall mean the Transaction Expenses, if any, as set forth in the Final Closing Statement as prepared and finalized in accordance with Sections 1.5 and 1.6.
“Forecasted Capital Expenditures Amount” shall mean the total amount of all forecasted capital expenditures for the Acquired Companies, as set forth on Appendix III, during the period beginning on July 1, 2021 and ending as of the Reference Time taking the sum of the total consolidated amounts forecast for each month during such period set forth on Appendix III (with the forecasted amount for the month in which the Closing Date occurs being prorated based on the number of days in such month prior to and including the date that includes the Reference Time divided by the number of days in such month).
“FPA” means the Federal Power Act.
“Fraud” shall mean intentional fraud in the making of a representation or warranty contained in Article II or Article III and requires that: (a) the party to be charged with such fraud made a false representation of material fact in Article II or Article III (including any “bringdown” or other confirmation with respect to any such representation or warranty); (b) such party had actual knowledge that such representation was false when made and acted with scienter; (c) the false representation caused the party to whom it was made, in reasonable reliance upon such false representation and with ignorance as to the falsity of such representation, to take or refrain from taking action; and (d) the party to whom the false representation was made suffered any Loss by reason of such reliance. “Fraud” expressly excludes any other claim of fraud that does not include the elements set forth in this definition, including equitable fraud, promissory fraud, unfair dealings fraud, negligent or reckless misrepresentation or any similar theory.
“GAAP” shall mean generally accepted accounting principles in the United States, consistently applied throughout the periods involved.
“Good Utility Practice” shall mean the practices, methods and acts (a) engaged in or approved by a significant portion of the electric generating, transmission or distribution industries in the United States during the relevant time period or (b) that, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, are reasonably expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety, environmental protection, economy and expedition; provided that Good Utility Practice is not intended to be limited to optimum practices, methods or acts to the exclusion of all others but rather is intended to include a spectrum of acceptable practices, methods or acts generally accepted in the geographic location of the performance of such practice, method or act during the relevant period in light of the circumstances.
“Governmental Entity” shall mean any court, tribunal, arbitrator, authority, agency, commission, official or other instrumentality of the United States, Canada or any state, provincial, county, city or other political subdivision or similar governing entity, and including any governmental, quasi-governmental or non-governmental entity administering, regulating or having general oversight over coal, gas or power markets.
“Hazardous Material” shall mean: any chemicals, materials, derivatives, compounds, substances, or wastes which are now or hereafter defined or regulated as, or included in the definition of, a “hazardous substance,” “hazardous material,” “hazardous waste,” “solid waste,” “toxic substance,” “extremely hazardous substance,” “pollutant,” “contaminant,” or any other words of similar import under applicable Environmental Laws or any other words of similar meaning, and including any petroleum or petroleum product, asbestos or asbestos containing material, radon, polychlorinated biphenyls, per- and polyfluoroalkyl substances and 1,4-dioxane.
“HSR Act” shall mean the Hart-Scott-Rodino Antitrust Improvements Act of 1976.
Appendix I-6

“Income Taxes” shall mean any federal, state, local or non-U.S. tax based on or measured by reference to net income.
“Indebtedness” shall mean, with respect to a Person, without duplication: (a) any indebtedness for borrowed money, whether current, short-term or long-term, secured or unsecured, or other Liabilities evidenced by a note, bond, debenture or similar instruments; (b) any Liabilities in respect of commodity, price, currency or interest rate hedging arrangements, or other financial hedging or derivative contracts; (c) any reimbursement Liabilities in respect of letters of credit, performance bonds, bank guarantees, bankers’ acceptances, surety or other similar instruments, that have been drawn; (d) any obligations issued or assumed as the deferred purchase price of any property or services (other than trade credit incurred in the ordinary course of business); (e) any Tax Liability Amount; (f) any dividends declared but not yet paid; (g) any unpaid Liabilities with respect to severance compensation; (h) any Liabilities not incurred in the ordinary course that are secured by any Encumbrance (other than any Permitted Encumbrance); (i) use tax reserves and any additional use tax liability in connection with, and limited to, the sales and use tax audit in Kentucky that is ongoing as of the Effective Date; (k) any accrued interest, premiums (including make-whole premiums), penalties, termination fees or breakage fees or similar Liabilities in respect of any Liabilities of the types described in the foregoing clauses (a) through (i); and (m) any guarantee by such Person of any Liabilities of another Person of the types described in the foregoing clauses (a) through (l).
“Intellectual Property” shall mean any and all of the following in any jurisdiction throughout the United States: (a) trademarks, trade names, service marks and the goodwill connected with the use of any symbolized by the foregoing; (b) patents; (c) copyrights and works of authorship, including rights in software; (d) trade secrets and confidential know-how; (e) rights in databases and compilations of data; (f) all other intellectual and industrial property rights and assets of a similar nature; and (g) any registrations or applications for registration of any of the foregoing.
“Interim Period” shall mean the period beginning on the Effective Date and ending on the Closing Date.
“IRS” shall mean the U.S. Internal Revenue Service.
“Knowledge of Purchaser” shall mean the actual knowledge of the Persons set forth on Section A(i) of the Sellers Disclosure Letter.
“Knowledge of Sellers” shall mean the actual knowledge of the following Persons set forth on Section A(ii) of the Sellers Disclosure Letter.
“KPSC” shall mean the Kentucky Public Service Commission or any subdivision, panel, instrumentality, official or staff member acting on behalf thereof.
“Law” shall mean all laws (including common law), statutes, rules, regulations, ordinances, Orders, Permits and other pronouncements having the effect of law of any Governmental Entity.
“Liability” shall mean all Indebtedness, obligations and other liabilities of any nature, whether absolute, accrued, matured, contingent (or based upon any contingency), known or unknown, fixed or otherwise, or whether due or to become due.
“Licensed Intellectual Property Rights” means all Intellectual Property that is owned by a third Person and that the Acquired Companies use or hold for use pursuant to a Contract set forth on Section 2.8(a)(xvi) of the Sellers Disclosure Letter, whether or not used by the Acquired Companies as of the Closing Date.
Appendix I-7

“Loss” shall mean any and all Liabilities, damages, claims, fines, penalties, deficiencies, losses and expenses (including court costs, reasonable fees of attorneys, accountants and other experts or other reasonable expenses of litigation or other proceedings or any claim, default or assessment), to the extent not subject to recovery in customer rates.
“Material Adverse Effect” shall mean any fact, circumstance, effect, change, event or development (each an “Effect” and, collectively, “Effects”) that, individually or in the aggregate with other Effects, has, or would reasonably be expected to have, a material adverse effect on (a) the business, assets, results or financial condition of the Acquired Companies, taken as a whole or (b) the ability of the Sellers to perform their obligations under this Agreement or consummate the transactions contemplated hereby on a timely basis; provided, however, that in the case of clause (a), none of the following Effects occurring after the date hereof shall be taken into account, individually or in the aggregate, in determining whether there has been a Material Adverse Effect: (i) the announcement or pendency of this Agreement and the transactions contemplated hereby (provided that the exception in this clause (i) shall not be deemed to apply to references to “Material Adverse Effect” in Section 2.4); (ii) any action taken by Purchaser, Sellers or the Acquired Companies in accordance with this Agreement to obtain any Required Regulatory Approval, Mitchell Plant Approval or Additional Regulatory Filing and Consent and the results of such action, including any Effect resulting from any term or condition in any Required Regulatory Approval, Mitchell Plant Approval or Additional Regulatory Filing and Consent or any assertion by a Governmental Entity that any approval (other than the Required Regulatory Approvals and the Mitchell Plant Approvals) is required from such Governmental Entity; (iii) any failure in itself to meet any financial projections or forecasts or estimates of revenues, earnings or other financial metrics for any period, including forecasted electricity demand (provided that the underlying causes for such failure may be taken into account); (iv) any changes, circumstances or effects resulting from or relating to changes or developments in the international, national or regional economies, financial markets, capital markets or commodities markets, including changes in interest rates or exchange rates, or supply markets, including electric power or fuel and water, as applicable, used in connection with the business of the Acquired Companies; (v) any change in international, national, regional or local regulatory, political or legislative conditions generally, including the outbreak or escalation of hostilities or any acts of war, sabotage or terrorism; (vi) any hurricane, tornado, tsunami, flood, earthquake or other natural or manmade disaster or weather-related event, circumstance or development or acts of God; (vii) any epidemic, pandemic or disease outbreak (including the COVID-19 Pandemic); (viii) any change after the Effective Date in applicable Law, regulation or GAAP or FERC Accounting Requirements (or authoritative interpretation thereof); (ix) any Effect arising after the Effective Date generally affecting the electric generating, transmission or distribution industries (including, in each case, any general changes in the operations thereof) or the international, national or regional wholesale or retail markets for electric power, which do not have a disproportionate effect (relative to other industry participants) on the Acquired Companies; and (x) any new power plant entrants and their effect on pricing or transmission; provided, further, that with respect to clauses (iv) through (x), such Event shall not be excluded to the extent it disproportionately affects the Acquired Companies, taken as a whole, as compared to other participants in the electric generating, transmission or distribution industries.
“Mitchell” shall mean the Mitchell Power Generation Facility, a coal fired power plant located in Moundsville, West Virginia, consisting of two (2) coal-fired generating units, each having a nominal nameplate capacity of 800MW, and associated plant, equipment, vehicles, vessels and real estate, and including all electrical or thermal devices, and related structures and connections or common facilities that are located at the plant site and used for the production of power and the transportation and handling of fuel for the benefit of the Owners.
“Mitchell Interest” shall mean the fifty percent (50%) undivided interest in Mitchell owned by Kentucky Power.
Appendix I-8

“Mitchell Plant Approvals” shall mean the approvals set forth on Section A(iv) of the Sellers Disclosure Letter.
“Mitchell Plant O&M Agreement” shall mean the operations and maintenance agreement to be executed by Kentucky Power and Successor Operator and dated as of or prior to the Closing Date, in the form consistent with the Mitchell Plant Approvals, the proposed form of which to be filed with the applications for the Mitchell Plant Approvals is attached hereto as Exhibit C.
“Mitchell Plant Ownership Agreement” shall mean the ownership agreement to be executed by Kentucky Power, Wheeling and AEPSC and dated as of or prior to the Closing Date, in the form consistent with the Mitchell Plant Approvals, the proposed form of which to be filed with the applications for the Mitchell Plant Approvals is attached hereto as Exhibit B.
“Net Working Capital” shall mean the net working capital of the Acquired Companies as of the Reference Time calculated on a consolidated basis in accordance with the methodologies, principles and adjustments as set forth in the illustrative example in Appendix II. For the avoidance of doubt, (i) the Net Working Capital shall be decreased by the aggregate amount of Transaction Expenses, (ii) no Income Tax assets or Income Tax liabilities or deferred Tax liabilities or deferred Tax assets shall be included in the calculation of Net Working Capital and (iii) no item to the extent included in Indebtedness shall be included in the calculation of Net Working Capital.
“Non-Covered Employees” shall mean each Acquired Company Employee that is not a Covered Employee.
“NSR Consent Decree” shall mean the Consent Decree entered in United States, et al. v. American Electric Power Service Corp., et al., Civil Action Nos. C2-99-1182 and C2-99-1250 and United States, et al. v. American Electric Power Service Corp., et al., Civil Action Nos. C2-04-1098 and C2-05-360, and all amendments or modifications thereto.
“Order” shall mean any charge, decree, ruling, determination, directive, award, order, judgment, writ, injunction or stipulation of a Governmental Entity.
“Organizational Documents” shall mean, with respect to any Person, (a) the articles or certificate of formation, incorporation or organization (or the equivalent organizational documents) of such Person and (b) the bylaws or limited liability company agreement (or the equivalent governing documents) of such Person.
“Owned Intellectual Property” shall mean Intellectual Property owned or purported to be owned by the Acquired Companies.
“Permits” shall mean all licenses, permits, franchises, certificates, approvals, registrations, authorizations, consents or Orders of, obtained from, or issued by any Governmental Entity (other than the Required Regulatory Approvals, the Mitchell Plant Approvals and Environmental Permits).
“Permitted Encumbrances” shall mean (a) statutory Encumbrances of landlords’ and mechanics’, carriers’, workmen’s, repairmen’s, warehousemen’s, materialmen’s or other like Encumbrances arising or incurred in the ordinary course of business, (b) Encumbrances arising under original purchase price conditional sales contracts and equipment leases with third parties entered into in the ordinary course of business, (c) Encumbrances for Taxes, assessments or other governmental charges or levies that are not due or payable or that are being contested by appropriate Actions by one or both Sellers or that may thereafter be paid without material penalty and for which adequate reserves have been established, (d) Encumbrances disclosed on or reflected in the Acquired Companies’ Financial Statements, (e) with respect to real property,
Appendix I-9

defects or imperfections of title not materially interfering with the ordinary conduct of the business of the Acquired Companies, as a whole, (f) restrictions under the leases, subleases, Easements and similar agreements with respect to the Real Property, none of which materially interferes with the use or value of the underlying property or are violated in any material respect by the current use of the real property, as a whole, (g) any Easements, covenants, rights-of-way, restrictions of record and other similar charges not materially interfering with the ordinary conduct of the business of the Acquired Companies, taken as a whole, (h) any conditions or Encumbrances that would be shown by a current, accurate survey or physical inspection of any Real Property, (i) zoning, entitlement, land use, environmental, building and other similar restrictions, none of which materially interferes with the ordinary conduct of the business of the Acquired Companies or are violated in any material respect, as a whole, (j) Encumbrances that have been placed by any developer, landlord or other third party on property owned by third parties over which an Acquired Company has easement rights and subordination or similar agreements relating thereto, not materially interfering with the ordinary conduct of the business of the Acquired Companies, as a whole, (k) Encumbrances incurred or deposits made in connection with workers’ compensation, unemployment insurance or other types of social security, (l) all rights of any Person under condemnation, eminent domain or similar proceedings, which are pending or threatened prior to Closing, (m) all Encumbrances arising under approvals obtained by an Acquired Company and related to the business of an Acquired Company that have been issued by any Governmental Entities, (n) Encumbrances arising under any lease or sublease for Leased Real Property, (o) nonexclusive licenses to Intellectual Property granted in the ordinary course of business, (p) recorded Encumbrances of record affecting real property, (q) the rights of the Parties pursuant to this Agreement and any other instruments to be delivered hereunder, (r) all rights of customers, suppliers, subcontractors and other parties to, or third party beneficiaries under, any Contract to which an Acquired Company is a party, in the ordinary course of business under the terms of any such Contract or under general principles of commercial or government contract Law that do not result from a breach, default or violation by such Acquired Company of or under any such Contract, (s) Encumbrances arising under the Debt Agreements, (t) Encumbrances that would not have a Material Adverse Effect, and (u) the matters identified on Section A(iii) of the Sellers Disclosure Letter.
“Person” shall mean an individual, partnership (general or limited), corporation, limited liability company, joint venture, association or other form of business organization (whether or not regarded as a legal entity under applicable Law), trust or other entity or organization, including a Governmental Entity.
“PJM Market Rules” shall have the meaning ascribed to that term in the PJM Tariff.
“PJM Tariff” shall mean that certain PJM Open Access Transmission Tariff relating to PJM Interconnection, L.L.C., including any schedules, appendices or exhibits attached thereto, on file with FERC and as amended from time to time.
“Pre-Closing Tax Period” shall mean any taxable period or portion thereof ending on or prior to the Closing Date.
“Purchase Price” shall mean the Closing Payment Amount, as it may be adjusted by the Post-Closing Adjustment.
“Purchaser Material Adverse Effect” shall mean any Effect that, individually or in the aggregate with other Effects, has, or would reasonably be expected to have, a material adverse effect on the ability of Purchaser to perform its obligations under this Agreement or consummate the transactions contemplated hereby on a timely basis.
“Rate Proceeding” means any rate case, rate update, rate rider or other rate or regulatory accounting proceeding relating to any Acquired Company.
Appendix I-10

“Rating Agency” shall have the meaning ascribed to it in the Senior Note Purchase Agreements.
“Real Property” shall mean the fee interests in real property held by an Acquired Company including all buildings, structures, pipelines, other improvements, and fixtures located thereon and all appurtenances thereto (the “Owned Real Property”), the leasehold and subleasehold interests under the leases and subleases of real property held by an Acquired Company (the “Leased Real Property”), and the Easements in favor of an Acquired Company, including buildings, structures, pipelines, other improvements and fixtures located thereon.
“Reference Time” shall mean 12:01 a.m., Eastern time, on the Closing Date; provided, that for purposes of any determination as of the Reference Time, such determination shall be deemed to occur after giving effect to any subsequent payments, dividends or distributions made or payable to Sellers or any of their Affiliates (other than the Acquired Companies) and any Indebtedness, or non-ordinary course Liabilities, subsequently incurred by any of the Acquired Companies in each case, on or prior to the actual consummation of Closing (but excluding, for the avoidance of doubt, any incurrence of Indebtedness or Liabilities in respect of any Financing of Purchaser, or any receipt or use of the proceeds thereof).
“Release” shall mean any spilling, leaking, pumping, pouring, emitting, emptying, discharging, injecting, escaping, leaching, dumping, or disposing of Hazardous Materials into the Environment.
“Representative” shall mean with respect to a Person, any affiliate, manager, director, officer, member, partner, agent, employee, advisor, consultant, attorney, accountant, banker, financial advisor, rating agency, actual or potential debt or equity financing source, insurance provider, or other representative of such Person.
“Required Regulatory Approvals” shall mean the approvals set forth on Section A(v) of the Sellers Disclosure Letter.
“Sarbanes-Oxley Act” shall mean the Sarbanes-Oxley Act of 2002.
“SEC” shall mean the U.S. Securities and Exchange Commission.
“Securities Act” shall mean the U.S. Securities Act of 1933.
“Seller Affiliated Tax Group” shall mean the affiliated group within the meaning of Section 1504(a) of the Code (or any similar group defined under a similar or comparable provision of state, local or non-U.S. Law) of which the direct or indirect parent of the Acquired Companies is the common parent for any period during which the Acquired Companies are or were members.
“Seller Benefit Plan” shall mean each Benefit Plan that is sponsored, maintained, contributed to or required to be maintained or contributed to by a Seller or any of its Affiliates, in each case providing benefits to any Acquired Company Employee.
“Seller Group” shall mean Sellers and their Affiliates.
“Senior KPCo Notes” means, collectively, the following notes issued by Kentucky Power: (a) $120,000,000 4.18% Senior Notes, Series A, due September 30, 2026, (b) $80,000,000 4.33% Senior Notes, Series B, due December 30, 2026, (c) $65,000,000 3.13% Senior Notes, Series F, due September 12, 2024, (d) $40,000,000 3.35% Senior Notes, Series G, due September 12, 2027, (e) $165,000,000 3.45% Senior Notes, Series H, due September 12, 2029, and (f) $55,000,000 4.12% Senior Notes, Series I, due September 12, 2047.
Appendix I-11

“Senior Note Purchase Agreements” shall mean, collectively, the note purchase agreements governing the Senior KPCo Notes.
“Shared Contracts” shall mean those Contracts to which a Seller or any of its Affiliates (other than an Acquired Company) is a party pursuant to which the counterparty thereto is expected to provide in the twelve month period after the Closing Date, in an individual release or order under the Contract, more than $250,000 of products, services or Intellectual Property to any of the Acquired Companies); provided, that the definition of “Shared Contract” shall exclude any corporate-level services provided (or expressly excluded or services which Purchaser or the Acquired Companies decline to accept) under the Transition Services Agreement.
“Subsidiary” shall mean, with respect to any Person, any other Person, whether incorporated or unincorporated, of which (a) such first Person directly or indirectly owns or controls at least a majority of the securities or other interests having by their terms ordinary voting power to elect a majority of the board of directors or others performing similar functions or (b) such first Person is a general partner or managing member.
“Successor Operator” shall mean Wheeling Power Company, a West Virginia corporation and an Affiliate of Sellers, in its capacity as operator of the Mitchell Plant.
“Target Net Working Capital” shall mean negative thirty-eight million one hundred five thousand U.S. dollars (-$38,105,000).
“Tax” shall mean any tax of any kind, including any federal, state, local or foreign income, profits, license, severance, occupation, windfall profits, capital gains, capital stock, transfer, registration, social security (or similar), production, franchise, gross receipts, payroll, sales, employment, use, property, excise, value added, estimated, stamp, alternative or add-on minimum, environmental or withholding tax, and any other duty, assessment or governmental charge, in each case in the nature of a tax, imposed by any Governmental Entity, together with all interest, penalties and additional amounts imposed with respect to such amounts.
“Tax Liability Amount” shall mean an amount, equal to the sum of (a) the liability for Income Taxes of the Acquired Companies with respect to any Pre-Closing Tax Period in jurisdictions in which the Acquired Companies are currently filing Income Tax Returns on a separate-company basis that is unpaid as of the Closing Date and (b) any payroll, social security, employment or similar Taxes deferred under the CARES Act or similar Law by the Acquired Companies with respect to any wages or compensation paid prior to the Closing; provided that (i) except as otherwise provided herein, such liability for Income Taxes shall be calculated in accordance with the past practice (including reporting positions, jurisdictions, elections and accounting methods) of the Acquired Companies in preparing Tax Returns for Income Taxes, (ii) all deductions of the Acquired Companies relating to Transaction Expenses, and without duplication, amounts included in Indebtedness or Net Working Capital or otherwise taken into account to determine the Purchase Price shall be taken into account to the extent “more likely than not” deductible (or at a higher level of confidence) in the Pre-Closing Tax Period and applying the seventy percent safe-harbor election under Revenue Procedure 2011-29 to any “success based fees,” (iii) any financing or refinancing arrangements entered into at any time by or at the direction of Purchaser or any of its Affiliates or any other transactions entered into by or at the direction of Purchaser or any of its Affiliates in connection with the transactions contemplated hereby shall not be taken into account, (iv) any Income Taxes attributable to transactions outside the ordinary course of business on the Closing Date after the time of the Closing shall be excluded, (v) any liabilities for accruals or reserves established or required to be established under GAAP or FERC Accounting Requirements, as applicable, methodologies that require the accrual for contingent Income Taxes or with respect to uncertain Tax positions and any liabilities arising from any change in
Appendix I-12

accounting methods shall be excluded, (vi) all deferred tax liabilities established for GAAP or FERC Accounting Requirements, as applicable, purposes shall be excluded, (vii) any overpayments of Income Taxes with respect to Pre-Closing Tax Period shall be taken into account as reductions of the liability for Income Taxes (but not below zero) for the tax period (or portion thereof) ending on the Closing Date only to the extent applicable against a Tax liability in the jurisdiction to which the overpayment relates, and (viii) such liability for Income Taxes shall be calculated by including in taxable income on the Closing Date in the Pre-Closing Tax Period the amount of any taxable income associated with deferred revenue, prepaid amounts, or adjustments pursuant to Section 481 of the Code that would otherwise be includable in taxable income after the Closing Date.
“Tax Proceeding” shall mean any audit, examination, contest, litigation or other Action relating to Taxes.
“Tax Return” shall mean any return, declaration, report, election, claim for refund or information return or statement filed or required or permitted to be filed with any taxing authority relating to Taxes, including any schedule or attachment thereto or any amendment thereof.
“Transaction Expenses” means all fees, costs and expenses, solely to the extent that any Acquired Company has or will have any Liability in respect thereof, in each case, to the extent (a) incurred or payable in connection with the negotiation, preparation and execution of this Agreement and the Ancillary Agreements or the consummation of the transactions contemplated hereby or thereby on or prior to Closing and (b) not paid prior to the Reference Time, including, for the avoidance of doubt, (i) amounts payable to legal counsel, accountants, advisors, investment banks, brokers and other Persons advising any Seller or the Acquired Companies in connection with the transactions contemplated hereby or by any Ancillary Agreement, (ii) all bonuses and change in control payments payable in connection with the execution of this Agreement or any Ancillary Agreement or the consummation of the transactions contemplated hereby or by any Ancillary Agreement and (iii) the amount of the employer portion of any payroll, social security, Medicare, unemployment or similar or related Taxes payable with respect to the amounts set forth in the immediately preceding clause (ii).
“TransCo Intercompany Notes” shall mean, collectively, the following notes issued by Kentucky TransCo: (a) $4,000,000 4.05% Senior Notes, Series C, Tranche H, due November 14, 2034; (b) $5,000,000 3.66% Senior Notes, Series C, Tranche D, due March 16, 2025; (c) $2,000,000 $3.76% Senior Notes, Series C, Tranche E, due June 15, 2025; (d) $3,000,000 4.01% Senior Notes, Series C, Tranche G, due June 15, 2030; (e) $21,000,000 3.65% Senior Notes, Series M, due April, 2050; (f) $4,000,000 3.10% Senior Notes, Series D, due December 1, 2026; (g) $12,000,000 4.00% Senior Notes, Series E, due December 1, 2026; (h) $3,000,000 3.10% Senior Notes, Series D, due December 1, 2026 and (i) $10,000,000 3.75% Senior Notes, Series H, due December 1, 2047.
“Transition Services Agreement” shall mean the transition services agreement to be executed by AEPSC and the Acquired Companies and dated as of the Closing Date, substantially in the form attached hereto as Exhibit A.
“United States” or “U.S.” shall mean the United States of America and its territories and possessions.
“WARN Act” shall mean the federal Worker Adjustment Retraining and Notification Act of 1988 and similar state or local Laws related to plant closing, relocations and mass layoffs.
“Wheeling” shall mean Wheeling Power Company, a West Virginia corporation and an Affiliate of Sellers, in its capacity as an owner of an undivided co-tenancy interest in the Mitchell Plant.
Appendix I-13

“WVPSC” shall mean the Public Service Commission of West Virginia or any subdivision, panel, instrumentality, official or staff member acting on behalf thereof.
2.Other Definitions. The following terms shall have the meanings defined in the Section indicated:

Term	Section	
Accepting Noteholders	4.16(e)	
Accounting Principles	1.4(b)	
Acquired Companies’ Financial Statements	2.5(a)	
Acquired Company or Acquired Companies	Recitals	
Additional Regulatory Filings and Consents	2.4	
AEP	Preamble	
AEP TransCo	Preamble	
Agreement	Preamble	
Business Claims	4.22	
Balance Sheet Date	2.5(c)	
Burdensome Condition	4.5(d)	
Business Separation Plan	4.16(f)	
Claim Handling and Funding Agreement	4.22	
Closing	1.1	
Closing Date	1.3(a)	
Closing Payment Adjustment	Definition of Closing Payment Amount	
COBRA	5.7	
Company Confidential Information	4.3(a)	
Company Registered Intellectual Property	2.9	
Continuation Period	5.4	
Continuing Covered Employees	5.3(a)	
Continuing Non-Covered Employees	5.4	
Continuing Support Obligations	4.9	
D&O Indemnified Parties	4.12(a)	
Delayed Transfer Employee	5.19	
Effect	Definition of Material Adverse Effect	
Effective Date	Preamble	
Enforceability Exceptions	2.3	
Estimated Closing Statement	1.4(a)	
Final Closing Statement	1.6(c)	
Guarantor	3.7(b)	
Independent Accounting Firm	1.6(c)	
Initial Closing Statement	1.5(a)	
Intercompany Arrangements	4.8(a)	
Kentucky Power	Recitals	
Kentucky Power Financial Statements	2.5(a)	
Kentucky Power Shares	Recitals	
Kentucky TransCo	Recitals	
Kentucky TransCo Financial Statements	2.5(a)	
Kentucky TransCo Shares	Recitals	
Leased Real Property	Definition of Real Property	
Legal Restraints	7.1(a)	
Appendix I-14

						
Master Leases	4.19	
Material Contracts	2.8(a)	
Mitchell Operator Asset	4.20(a)	
Mitchell Employees	2.14(a)	
Morgan Lewis	1.3(a)	
NERC	4.18	
Non-Recourse Party	9.2	
Notice of Disagreement	1.6(a)	
Outside Date	8.1(b)(i)	
Owned Real Property	Definition of Real Property	
Parties	Preamble	
Party	Preamble	
Post-Closing Adjustment	1.7	
Pre-Closing Engagement	10.15	
Prohibited Party	3.5(b)	
Purchaser	Preamble	
Purchaser Disclosure Letter	Article III	
Purchaser Indemnified Parties	9.1(a)	
Purchaser Guaranty	3.7(b)	
Purchaser Savings Plan	5.9	
Purchaser Union Savings Plan	5.9	
Qualified Plan	2.13(d)	
Qualifying Offer	5.19	
Releasees	4.11(a)	
Resolution Period	1.6(b)	
R&W Policy	4.15	
Sale	1.1	
Sanctioned Country	3.5(b)	
SDN	3.5(b)	
Section 205	4.5(e)	
Seller	Preamble	
Seller Indemnified Parties	9.2(b)	
Seller Marks	4.10	
Sellers’ Disclosure Letter	 Article II	
Senior Note Purchase Price	4.16(e)	
Severed Continuing Employee	5.6	
Shares	Recitals	
Substituted Support Obligations	4.9	
Support Employee	Definition of Acquired Company Employee	
Termination Fee	8.3(a)	
Transfer Taxes	6.6	
U.S. Trade Controls	3.5(a)	
Utility Money Pool Agreement	4.16(a)	
Willful Breach	8.4	
Workers Compensation Event	5.13	

Appendix I-15

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 28, 2021	By:		/s/ Nicholas K. Akins	
			Nicholas K. Akins	
			Chief Executive Officer	

EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:
1.I have reviewed this report on Form 10-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 28, 2021	By:		/s/ Nicholas K. Akins	
			Nicholas K. Akins	
			Chief Executive Officer	

EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:
1.I have reviewed this report on Form 10-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 28, 2021	By:		/s/ Nicholas K. Akins	
			Nicholas K. Akins	
			Chief Executive Officer	

EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:
1.I have reviewed this report on Form 10-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 28, 2021	By:		/s/ Nicholas K. Akins	
			Nicholas K. Akins	
			Chief Executive Officer	

EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:
1.I have reviewed this report on Form 10-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 28, 2021	By:		/s/ Nicholas K. Akins	
			Nicholas K. Akins	
			Chief Executive Officer	

EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:
1.I have reviewed this report on Form 10-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 28, 2021	By:		/s/ Nicholas K. Akins	
			Nicholas K. Akins	
			Chief Executive Officer	

EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:
1.I have reviewed this report on Form 10-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 28, 2021	By:		/s/ Nicholas K. Akins	
			Nicholas K. Akins	
			Chief Executive Officer	

EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:
1.I have reviewed this report on Form 10-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 28, 2021	By:		/s/ Nicholas K. Akins	
			Nicholas K. Akins	
			Chief Executive Officer	

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Julia A. Sloat, certify that:

1.I have reviewed this report on Form 10-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 28, 2021	By:		/s/ Julia A. Sloat	
			Julia A. Sloat	
			Chief Financial Officer	

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Julia A. Sloat, certify that:

1.I have reviewed this report on Form 10-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 28, 2021	By:		/s/ Julia A. Sloat	
			Julia A. Sloat	
			Chief Financial Officer	

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Julia A. Sloat, certify that:

1.I have reviewed this report on Form 10-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 28, 2021	By:		/s/ Julia A. Sloat	
			Julia A. Sloat	
			Chief Financial Officer	

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Julia A. Sloat, certify that:

1.I have reviewed this report on Form 10-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 28, 2021	By:		/s/ Julia A. Sloat	
			Julia A. Sloat	
			Chief Financial Officer	

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Julia A. Sloat, certify that:

1.I have reviewed this report on Form 10-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 28, 2021	By:		/s/ Julia A. Sloat	
			Julia A. Sloat	
			Chief Financial Officer	

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Julia A. Sloat, certify that:

1.I have reviewed this report on Form 10-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 28, 2021	By:		/s/ Julia A. Sloat	
			Julia A. Sloat	
			Chief Financial Officer	

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Julia A. Sloat, certify that:

1.I have reviewed this report on Form 10-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 28, 2021	By:		/s/ Julia A. Sloat	
			Julia A. Sloat	
			Chief Financial Officer	

EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Julia A. Sloat, certify that:

1.I have reviewed this report on Form 10-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 28, 2021	By:		/s/ Julia A. Sloat	
			Julia A. Sloat	
			Chief Financial Officer	

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Quarterly Report of American Electric Power Company, Inc. (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2021 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 28, 2021

A signed original of this written statement required by Section 906 has been provided to American Electric Power Company, Inc. and will be retained by American Electric Power Company, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Quarterly Report of AEP Transmission Company, LLC (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2021 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 28, 2021

A signed original of this written statement required by Section 906 has been provided to AEP Transmission Company, LLC and will be retained by AEP Transmission Company, LLC and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Quarterly Report of AEP Texas Inc. (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2021 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 28, 2021

A signed original of this written statement required by Section 906 has been provided to AEP Texas Inc. and will be retained by AEP Texas Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Quarterly Report of Appalachian Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2021 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 28, 2021

A signed original of this written statement required by Section 906 has been provided to Appalachian Power Company and will be retained by Appalachian Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Quarterly Report of Indiana Michigan Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2021 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 28, 2021

A signed original of this written statement required by Section 906 has been provided to Indiana Michigan Power Company and will be retained by Indiana Michigan Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Quarterly Report of Ohio Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2021 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 28, 2021

A signed original of this written statement required by Section 906 has been provided to Ohio Power Company and will be retained by Ohio Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Quarterly Report of Public Service Company of Oklahoma (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2021 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 28, 2021

A signed original of this written statement required by Section 906 has been provided to Public Service Company of Oklahoma and will be retained by Public Service Company of Oklahoma and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Quarterly Report of Southwestern Electric Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2021 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 28, 2021

A signed original of this written statement required by Section 906 has been provided to Southwestern Electric Power Company and will be retained by Southwestern Electric Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Quarterly Report of American Electric Power Company, Inc. (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2021 as filed with the Securities and Exchange Commission on the date hereof, I, Julia A. Sloat, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer

October 28, 2021

A signed original of this written statement required by Section 906 has been provided to American Electric Power Company, Inc. and will be retained by American Electric Power Company, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Quarterly Report of AEP Transmission Company, LLC (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2021 as filed with the Securities and Exchange Commission on the date hereof, I, Julia A. Sloat, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer

October 28, 2021

A signed original of this written statement required by Section 906 has been provided to AEP Transmission Company, LLC and will be retained by AEP Transmission Company, LLC and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Quarterly Report of AEP Texas Inc. (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2021 as filed with the Securities and Exchange Commission on the date hereof, I, Julia A. Sloat, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer

October 28, 2021

A signed original of this written statement required by Section 906 has been provided to AEP Texas Inc. and will be retained by AEP Texas Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Quarterly Report of Appalachian Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2021 as filed with the Securities and Exchange Commission on the date hereof, I, Julia A. Sloat, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer

October 28, 2021

A signed original of this written statement required by Section 906 has been provided to Appalachian Power Company and will be retained by Appalachian Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Quarterly Report of Indiana Michigan Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2021 as filed with the Securities and Exchange Commission on the date hereof, I, Julia A. Sloat, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer

October 28, 2021

A signed original of this written statement required by Section 906 has been provided to Indiana Michigan Power Company and will be retained by Indiana Michigan Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Quarterly Report of Ohio Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2021 as filed with the Securities and Exchange Commission on the date hereof, I, Julia A. Sloat, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer

October 28, 2021

A signed original of this written statement required by Section 906 has been provided to Ohio Power Company and will be retained by Ohio Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Quarterly Report of Public Service Company of Oklahoma (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2021 as filed with the Securities and Exchange Commission on the date hereof, I, Julia A. Sloat, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer

October 28, 2021

A signed original of this written statement required by Section 906 has been provided to Public Service Company of Oklahoma and will be retained by Public Service Company of Oklahoma and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code

In connection with the Quarterly Report of Southwestern Electric Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2021 as filed with the Securities and Exchange Commission on the date hereof, I, Julia A. Sloat, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer

October 28, 2021

A signed original of this written statement required by Section 906 has been provided to Southwestern Electric Power Company and will be retained by Southwestern Electric Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 95

MINE SAFETY INFORMATION

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

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act. DHLC received the following notices of violation and proposed assessments under the Mine Act for the quarter ended September 30, 2021:

Number of Citations for S&S Violations of Mandatory Health or Safety Standards under 104 *	—	
Number of Orders Issued under 104(b) *	—	
Number of Citations and Orders for Unwarrantable Failure to Comply with Mandatory Health or Safety Standards under 104(d) *	—	
Number of Flagrant Violations under 110(b)(2) *	—	
Number of Imminent Danger Orders Issued under 107(a) *	—	
Total Dollar Value of Proposed Assessments **	$	— 		
Number of Mining-related Fatalities	—	

*    References to sections under the Mine Act.
**     DHLC received no citations during the third quarter of 2021, and there were no proposed assessments received this quarter.

There are currently no legal actions pending before the Federal Mine Safety and Health Review Commission.