AMERICAN ELECTRIC POWER CO INC - Annual Report: 2022 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2022

☐ 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

AEPPZ

The NASDAQ Stock Market LLC

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

Indicate by check mark if the registrant American Electric Power Company, Inc., AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Ohio Power Company and Southwestern Electric Power Company, are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.

Yes

Indicate by check mark if the registrants Indiana Michigan Power Company and Public Service Company of Oklahoma, are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.

Yes

Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.

Yes

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

Yes

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

Yes

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

Large Accelerated filer

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

Large Accelerated filer

☐

Accelerated filer

☐

Non-accelerated filer

Smaller reporting company

☐

Emerging growth company

☐

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

☐

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

☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b).

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

Yes

☐

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

Aggregate Market Value of Voting and Non-Voting Common Equity Held by Nonaffiliates of the Registrants as of June 30, 2022 the Last Trading Date of the Registrants' Most Recently Completed Second Fiscal Quarter

Number of Shares of Common Stock Outstanding of the Registrants as of December 31, 2022

American Electric Power Company, Inc.

$49,300,311,811

513,866,081

($6.50 par value)

AEP Texas Inc.

None

100

($0.01 par value)

AEP Transmission Company, LLC (a)

None

Appalachian Power Company

None

13,499,500

(no par value)

Indiana Michigan Power Company

None

1,400,000

(no par value)

Ohio Power Company

None

27,952,473

(no par value)

Public Service Company of Oklahoma

None

9,013,000

($15 par value)

Southwestern Electric Power Company

None

3,680

($18 par value)

(a)100% interest is held by AEP Transmission Holdco.

NA Not applicable.

Note on Market Value of Common Equity Held by Nonaffiliates

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

Documents Incorporated By Reference


Description						Part of Form 10-K into which Document is Incorporated

Portions of Proxy Statement of American Electric Power Company, Inc. for 2023 Annual Meeting of Shareholders.						Part III

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

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

TABLE OF CONTENTS


Item Number		Page Number
	Glossary of Terms	i
	Forward-Looking Information	vii

PART I
1	Business
	General	1
	Business Segments	15
	Vertically Integrated Utilities	15
	Transmission and Distribution Utilities	22
	AEP Transmission Holdco	24
	Generation & Marketing	27
	Executive Officers of AEP	30
1A	Risk Factors	32
1B	Unresolved Staff Comments	45
2	Properties	45
	Generation Facilities	45
	Transmission and Distribution Facilities	51
	Title to Property	51
	System Transmission Lines and Facility Siting	52
	Construction Program	52
	Potential Uninsured Losses	52
3	Legal Proceedings	52
4	Mine Safety Disclosure	52

PART II
5	Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	54
6	Reserved	55
7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	55
7A	Quantitative and Qualitative Disclosures about Market Risk	55
8	Financial Statements and Supplementary Data	55
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	428
9A	Controls and Procedures	428
9B	Other Information	428
9C	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	428

	PART III
10	Directors, Executive Officers and Corporate Governance	429
11	Executive Compensation	429
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	430
13	Certain Relationships and Related Transactions and Director Independence	430
14	Principal Accounting Fees and Services	431

PART IV
15	Exhibits and Financial Statement Schedules
	Financial Statements	432
16	Form 10-K Summary	433
	Signatures	434
	Index of Financial Statement Schedules	S-1
	Exhibit Index	E-1

GLOSSARY OF TERMS

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


Term						Meaning

AEGCo						AEP Generating Company, an AEP electric utility subsidiary.
AEP						American Electric Power Company, Inc., an investor-owned electric public utility holding company which includes American Electric Power Company, Inc. (Parent) and majority-owned consolidated subsidiaries and consolidated affiliates.
AEP Credit						AEP Credit, Inc., a consolidated VIE of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP East Companies						APCo, I&M, KGPCo, KPCo, OPCo and WPCo.
AEP Energy						AEP Energy, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States.
AEP Energy Supply, LLC						A nonregulated holding company for AEP’s competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP.
AEP OnSite Partners						A division of AEP Energy Supply, LLC that builds, owns, operates and maintains customer solutions utilizing existing and emerging distributed technologies.
AEP Renewables						A division of AEP Energy Supply, LLC that develops and/or acquires large scale renewable projects that are backed with long-term contracts with creditworthy counter parties.
AEP System						American Electric Power System, an electric system, owned and operated by AEP subsidiaries.
AEP Texas						AEP Texas Inc., an AEP electric utility subsidiary.
AEP Transmission Holdco						AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of AEP.
AEP Wind Holdings, LLC						Acquired in April 2019 as Sempra Renewables LLC, develops, owns and operates, or holds interests in, wind generation facilities in the United States.
AEPEP						AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, hedging activities, asset management and commercial and industrial sales in deregulated markets.
AEPRO						AEP River Operations, LLC, a commercial barge operation sold in November 2015.
AEPSC						American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AEPTCo						AEP Transmission Company, LLC, a wholly-owned subsidiary of AEP Transmission Holdco, is an intermediate holding company that owns the State Transcos.
AEPTCo Parent						AEP Transmission Company, LLC, the holding company of the State Transcos within the AEPTCo consolidation.
AEPTHCo						AEP Transmission Holding Company, LLC, a subsidiary of AEP, an intermediate holding company that owns transmission operations joint ventures and AEPTCo.
AFUDC						Allowance for Equity Funds Used During Construction.
AGR						AEP Generation Resources Inc., a competitive AEP subsidiary in the Generation & Marketing segment.
ALJ						Administrative Law Judge.


AOCI						Accumulated Other Comprehensive Income.
APCo						Appalachian Power Company, an AEP electric utility subsidiary.
Appalachian Consumer Rate Relief Funding						Appalachian Consumer Rate Relief Funding LLC, a wholly-owned subsidiary of APCo and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to the under-recovered ENEC deferral balance.
APTCo						AEP Appalachian Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.


Term						Meaning

APSC						Arkansas Public Service Commission.
ARAM						Average Rate Assumption Method, an IRS approved method used to calculate the reversal of Excess ADIT for rate-making purposes.
ARO						Asset Retirement Obligations.
ASU						Accounting Standards Update.
ATM						At-the-Market.
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.
CO2e						Carbon dioxide equivalent.
Conesville Plant						A retired, single unit coal-fired generation plant totaling 651 MW located in Conesville, Ohio. The plant was jointly-owned by AGR and a nonaffiliate.
Cook Plant						Donald C. Cook Nuclear Plant, a two-unit, 2,296 MW nuclear plant owned by I&M.
COVID-19						Coronavirus 2019, a highly infectious respiratory disease. In March 2020, the World Health Organization declared COVID-19 a worldwide pandemic.
CRES provider						Competitive Retail Electric Service providers under Ohio law that target retail customers by offering alternative generation service.
CSAPR						Cross-State Air Pollution Rule.
CSPCo						Columbus Southern Power Company, a former AEP electric utility subsidiary that was merged into OPCo effective December 31, 2011.
CWA						Clean Water Act.
CWIP						Construction Work in Progress.
DCC Fuel						DCC Fuel XI, DCC Fuel XII, DCC Fuel XIII, DCC Fuel XIV, DCC Fuel XV, DCC Fuel XVI, DCC Fuel XVII and DCC Fuel XVIII consolidated VIEs formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
Desert Sky						Desert Sky Wind Farm LLC, a 170 MW wind electricity generation facility located on Indian Mesa in Pecos County, Texas in which AEP owns a 100% interest.
DHLC						Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.
DIR						Distribution Investment Rider.
DOE						U. S. Department of Energy.
EIS						Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated VIE of AEP.
ELG						Effluent Limitation Guidelines.
ENEC						Expanded Net Energy Cost.
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.


Term						Meaning

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.
GHG						Greenhouse gas.
I&M						Indiana Michigan Power Company, an AEP electric utility subsidiary.
IMTCo						AEP Indiana Michigan Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.
IRA						On August 16, 2022 President Biden signed into law legislation commonly referred to as the “Inflation Reduction Act” (IRA).
IRS						Internal Revenue Service.
ITC						Investment Tax Credit.
IURC						Indiana Utility Regulatory Commission.
KGPCo						Kingsport Power Company, an AEP electric utility subsidiary.
KPCo						Kentucky Power Company, an AEP electric utility subsidiary.
KPSC						Kentucky Public Service Commission.
KTCo						AEP Kentucky Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.
kV						Kilovolt.
KWh						Kilowatt-hour.
Liberty						Liberty Utilities Co., a subsidiary of Algonquin Power & Utilities Corporation.
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.
Mitchell Plant						A two unit, 1,560 MW coal-fired power plant located in Moundsville, West Virginia. The plant is jointly owned by KPCo and WPCo.
MMBtu						Million British Thermal Units.
MPSC						Michigan Public Service Commission.
MTM						Mark-to-Market.
MW						Megawatt.
MWh						Megawatt-hour.
NAAQS						National Ambient Air Quality Standards.
NERC						North American Electric Reliability Corporation.
Nonutility Money Pool						Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
NCWF						North Central Wind Energy Facilities, a joint PSO and SWEPCo project, which includes three Oklahoma wind facilities totaling approximately 1,484 MWs of wind generation.

NOL						Net operating losses.
NOLC						Net operating loss carryforwards.
NOx						Nitrogen oxide.
NPDES						National Pollutant Discharge Elimination System.
NRC						Nuclear Regulatory Commission.
NSR						New Source Review.

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Term						Meaning

OATT						Open Access Transmission Tariff.
OCC						Corporation Commission of the State of Oklahoma.
ODFA						Oklahoma Development Finance Authority.

OHTCo						AEP Ohio Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.
Oklaunion Power Station						A retired, single unit coal-fired generation plant totaling 650 MW located in Vernon, Texas. The plant was jointly-owned by AEP Texas, PSO and certain nonaffiliated entities.
OKTCo						AEP Oklahoma Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.
OPCo						Ohio Power Company, an AEP electric utility subsidiary.
OPEB						Other Postretirement Benefits.
Operating Agreement						Agreement, dated January 1, 1997, as amended, by and among PSO and SWEPCo governing generating capacity allocation, energy pricing, and revenues and costs of third-party sales. AEPSC acts as the agent.
OTC						Over-the-counter.
OVEC						Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
Parent						American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.
PATH-WV						PATH West Virginia Transmission Company, LLC, a joint venture-owned 50% by FirstEnergy and 50% by AEP.
PCA						Power Coordination Agreement among APCo, I&M, KPCo and WPCo.
PFD						Proposal for Decision.
PJM						Pennsylvania – New Jersey – Maryland regional transmission organization.
PM						Particulate Matter.
PPA						Purchase Power and Sale Agreement.

PSA						Purchase and Sale Agreement.
PSO						Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PTC						Production Tax Credit.
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 formerly owned by AGR. Racine was sold to a nonaffiliate in December 2021.

Registrant Subsidiaries						AEP subsidiaries which are SEC registrants: AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
Registrants						SEC registrants: AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
REP						Texas Retail Electric Provider.
Restoration Funding						AEP Texas Restoration Funding LLC, a wholly-owned subsidiary of AEP Texas and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to storm restoration in Texas primarily caused by Hurricane Harvey.
Risk Management Contracts						Trading and non-trading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant						A generation plant, jointly-owned by AEGCo and I&M, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana.
ROE						Return on Equity.
RPM						Reliability Pricing Model.
RTO						Regional Transmission Organization, responsible for moving electricity over large interstate areas.


Term						Meaning

Sabine						Sabine Mining Company, a lignite mining company that is a consolidated VIE for AEP and SWEPCo.
Santa Rita East						Santa Rita East Wind Holdings, LLC, a consolidated VIE whose sole purpose is to own and operate a 302 MW wind generation facility in west Texas in which AEP owns an 85% interest.
SEC						U.S. Securities and Exchange Commission.
Sempra Renewables LLC						Sempra Renewables LLC, acquired in April 2019 (subsequently renamed as AEP Wind Holdings LLC), consists of 724 MWs of wind generation and battery assets in the United States.
SIA						System Integration Agreement, effective June 15, 2000, as amended, provides contractual basis for coordinated planning, operation and maintenance of the power supply sources of the combined AEP.
SIP						State Implementation Plan.
SNF						Spent Nuclear Fuel.
SO2						Sulfur dioxide.
SPP						Southwest Power Pool regional transmission organization.
SSO						Standard service offer.
State Transcos						AEPTCo’s seven wholly-owned, FERC regulated, transmission only electric utilities, which are geographically aligned with AEP's existing utility operating companies.
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.
SWTCo						AEP Southwestern Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.
TA						Transmission Agreement, effective November 2010, among APCo, I&M, KGPCo, KPCo, OPCo and WPCo with AEPSC as agent.
Tax Reform						On December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal Revenue Code of 1986, including a reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018.
TCA						Transmission Coordination Agreement dated January 1, 1997, by and among, PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two public utility subsidiaries.
Transition Funding						AEP Texas Central Transition Funding III LLC, a wholly-owned subsidiary of AEP Texas and consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to restructuring legislation in Texas.
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 998 MWs of wind generation in Oklahoma.
Trent						Trent Wind Farm LLC, a 156 MW wind electricity generation facility located in west Texas in which AEP owns a 100% interest.
Turk Plant						John W. Turk, Jr. Plant, a 650 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.
UMWA						United Mine Workers of America.
UPA						Unit Power Agreement.
Utility Money Pool						Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
VIE						Variable Interest Entity.
Virginia SCC						Virginia State Corporation Commission.


Term						Meaning

WPCo						Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC						Public Service Commission of West Virginia.
WVTCo						AEP West Virginia Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.

FORWARD-LOOKING INFORMATION

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


•			Changes in economic conditions, electric market demand and demographic patterns in AEP service territories.
•			The impact of pandemics and any associated disruption of AEP’s business operations due to impacts on economic or market conditions, costs of compliance with potential government regulations, electricity usage, supply chain issues, customers, service providers, vendors and suppliers.
•			The economic impact of increased global trade tensions including the conflict between Russia and Ukraine, and the adoption or expansion of economic sanctions or trade restrictions.
•			Inflationary or deflationary interest rate trends.
•			Volatility and disruptions in financial markets precipitated by any cause, including failure to make progress on federal budget or debt ceiling matters; 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 (i) if expected sources of capital, such as proceeds from the sale of assets or subsidiaries, do not materialize or do not materialize at the level anticipated, and (ii) 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 transition from fossil generation and 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 or 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.
•			The impact of federal tax legislation on results of operations, financial condition, cash flows or credit ratings.
•			The risks before, during and after generation of electricity associated with the fuels used or the byproducts and wastes of such fuels, including coal ash and SNF.
•			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.

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•			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.
•			The impact of changing expectations and demands of customers, regulators, investors and stakeholders, including heightened emphasis on environmental, social and governance concerns.
•			Changes in utility regulation and the allocation of costs within RTOs including ERCOT, PJM and SPP.
•			Changes in the creditworthiness of the counterparties with contractual arrangements, including participants in the energy trading market.
•			Actions of rating agencies, including changes in the ratings of debt.
•			The impact of volatility in the capital markets on the value of the investments held by the pension, OPEB, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements.
•			Accounting standards periodically issued by accounting standard-setting bodies.
•			Other risks and unforeseen events, including wars and military conflicts, the effects of terrorism (including increased security costs), embargoes, naturally occurring and human-caused fires, cyber-security threats and other catastrophic events.
•			The ability to attract and retain the requisite work force and key personnel.

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

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

Company Website and Availability of SEC Filings

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

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PART I

ITEM 1. BUSINESS

GENERAL

Overview and Description of Major Subsidiaries

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

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

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

As of December 31, 2022, the subsidiaries of AEP had a total of 16,974 employees. Because it is a holding company rather than an operating company, AEP has no employees. The material subsidiaries of AEP are as follows:

AEP Texas

Organized in Delaware in 1925, AEP Texas is engaged in the transmission and distribution of electric power to approximately 1,094,000 retail customers through REPs in west, central and southern Texas. As of December 31, 2022, AEP Texas had 1,594 employees. Among the principal industries served by AEP Texas are petroleum and coal products manufacturing, chemical manufacturing, oil and gas extraction, pipeline transportation and support activities for mining. The territory served by AEP Texas also includes several military installations. AEP Texas is a member of ERCOT. AEP Texas is part of AEP’s Transmission and Distribution Utilities segment.

AEPTCo

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

APCo

Organized in Virginia in 1926, APCo is engaged in the generation, transmission and distribution of electric power to approximately 965,000 retail customers in the southwestern portion of Virginia and southern West Virginia, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. APCo owns 6,681 MWs of generating capacity. APCo uses its generation to serve its retail and other customers. As of December 31, 2022, APCo had 1,650 employees. Among the principal industries served by APCo are coal-mining, primary metals, pipeline transportation, chemical manufacturing and paper manufacturing. APCo is a member of PJM. APCo is part of AEP’s Vertically Integrated Utilities segment.

I&M

Organized in Indiana in 1907, I&M is engaged in the generation, transmission and distribution of electric power to approximately 609,000 retail customers in northern and eastern Indiana and southwestern Michigan, and in supplying and marketing electric power at wholesale to other electric utility companies, rural electric cooperatives, municipalities and other market participants. I&M owns or leases 3,662 MWs of generating capacity, which it uses to serve its retail and other customers. In December 2022, the Rockport Plant, Unit 2 lease ended and I&M and AEGCo acquired 100% of the interests in the Rockport Plant. AEGCo’s 50% ownership share of Rockport Plant, Unit 2 is being billed to I&M under a FERC-approved UPA. I&M’s purchased power from AEGCo and I&M’s 50% ownership share of Rockport Plant, Unit 2 electricity generated represents a merchant resource for I&M until Rockport Plant, Unit 2 is retired in 2028. As of December 31, 2022, I&M had 2,016 employees. Among the principal industries served are primary metals, transportation equipment, chemical manufacturing, plastics and rubber products and fabricated metal product manufacturing. I&M is a member of PJM. I&M is part of AEP’s Vertically Integrated Utilities segment.

KPCo

Organized in Kentucky in 1919, KPCo is engaged in the generation, transmission and distribution of electric power to approximately 163,000 retail customers in eastern Kentucky, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. KPCo owns 1,075 MWs of generating capacity. KPCo uses its generation to serve its retail and other customers. As of December 31, 2022, KPCo had 285 employees. Among the principal industries served are petroleum and coal products manufacturing, chemical manufacturing, coal-mining, oil and gas extraction and pipeline transportation. KPCo is a member of PJM. KPCo is part of AEP’s Vertically Integrated Utilities segment. In October 2021, AEP entered into a Stock Purchase Agreement to sell KPCo to Liberty Utilities Co. The closing of the sale is subject to receipt of FERC authorization under Section 203 of the Federal Power Act and clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.

KGPCo

Organized in Virginia in 1917, KGPCo provides electric service to approximately 49,000 retail customers in Kingsport and eight neighboring communities in northeastern Tennessee. KGPCo does not own any generating facilities and is a member of PJM. It purchases electric power from APCo for distribution to its customers. As of December 31, 2022, KGPCo had 53 employees. KGPCo is part of AEP’s Vertically Integrated Utilities segment.

OPCo

Organized in Ohio in 1907 and re-incorporated in 1924, OPCo is engaged in the transmission and distribution of electric power to approximately 1,521,000 retail customers in Ohio. OPCo purchases energy and capacity at auction to serve generation service customers who have not switched to a competitive generation supplier. As of December 31, 2022, OPCo had 1,713 employees. Among the principal industries served by OPCo are primary metals, petroleum and coal products manufacturing, plastics and rubber products, chemical manufacturing, pipeline transportation and data centers. OPCo is a member of PJM. OPCo is part of AEP’s Transmission and Distribution Utilities segment.

PSO

Organized in Oklahoma in 1913, PSO is engaged in the generation, transmission and distribution of electric power to approximately 575,000 retail customers in eastern and southwestern Oklahoma, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. PSO owns 4,380 MWs of generating capacity, which it uses to serve its retail and other customers. As of December 31, 2022, PSO had 1,030 employees. Among the principal industries served by PSO are paper manufacturing, oil and gas extraction, petroleum and coal products manufacturing, plastics and rubber products and pipeline transportation. PSO is a member of SPP. PSO is part of AEP’s Vertically Integrated Utilities segment.

SWEPCo

Organized in Delaware in 1912, SWEPCo is engaged in the generation, transmission and distribution of electric power to approximately 551,000 retail customers in northeastern and panhandle of Texas, northwestern Louisiana and western Arkansas, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. SWEPCo owns 5,585 MWs of generating capacity, which it uses to serve its retail and other customers. As of December 31, 2022, SWEPCo had 1,372 employees. Among the principal industries served by SWEPCo are petroleum and coal products manufacturing, food manufacturing, paper manufacturing, oil and gas extraction and chemical manufacturing. The territory served by SWEPCo includes several military installations, colleges and universities. SWEPCo also owns and operates a lignite coal-mining operation. SWEPCo is a member of SPP. SWEPCo is part of AEP’s Vertically Integrated Utilities segment.

WPCo

Organized in West Virginia in 1883 and re-incorporated in 1911, WPCo provides electric service to approximately 41,000 retail customers in northern West Virginia and in supplying and marketing electric power at wholesale to other market participants. WPCo owns 780 MWs of generating capacity which it uses to serve its retail and other customers. As of December 31, 2022, WPCo had 220 employees. Among the principal industries served by WPCo are coal-mining, primary metals, pipeline transportation, chemical manufacturing and paper manufacturing. WPCo is a member of PJM. WPCo is part of AEP’s Vertically Integrated Utilities segment.

Service Company Subsidiary

AEPSC is a service company subsidiary that provides accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost to AEP subsidiaries. The executive officers of AEP and certain of the executive officers of its public utility subsidiaries are employees of AEPSC. As of December 31, 2022, AEPSC had 6,572 employees.

Public Utility Subsidiaries by Jurisdiction

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


Principal Jurisdiction	AEP Utility Subsidiaries Operating in that Jurisdiction	Authorized Return on Equity (a)
FERC	AEPTCo - PJM	10.35	%	(b)
	AEPTCo - SPP	10.50	%

Ohio	OPCo	9.70	%

West Virginia	APCo	9.75	%
	WPCo	9.75	%

Virginia	APCo	9.20	%

Indiana	I&M	9.70	%

Michigan	I&M	9.86	%

Texas	AEP Texas	9.40	%
	SWEPCo	9.25	%	(c)

Tennessee	KGPCo	9.50	%

Kentucky	KPCo	9.30	%

Louisiana	SWEPCo	9.50	%

Arkansas	SWEPCo	9.50	%

Oklahoma	PSO	9.40	%

(a)Identifies the predominant current authorized ROE, and may not include other, less significant, permitted recovery. Actual ROE varies from authorized ROE.

(b)In December 2022, the FERC issued an order removing the 50 basis point RTO incentive from OHTCo transmission formula rates effective February 2022, reducing OHTCo’s authorized ROE to 9.85%.

(c)In February 2022, SWEPCo filed a motion for rehearing with the PUCT challenging several errors in the final order, which included a challenge of the approved ROE. In April 2022, the PUCT denied the motion for rehearing. In May 2022, SWEPCo filed a petition for review with the Texas District Court seeking a judicial review of the several errors challenged in the PUCT’s final order.

(a)Pretax income does not include intercompany eliminations.

(b)Excludes $363 million loss on expected sale of the Kentucky Operations.

CLASSES OF SERVICE

AEP and subsidiaries recognize revenues from customers for retail and wholesale electricity sales and electricity transmission and distribution delivery services. AEP’s subsidiaries within the Vertically Integrated Utilities, Transmission and Distribution Utilities, AEP Transmission Holdco and Generation & Marketing segments derive revenue from the following sources: Retail Revenues, Wholesale and Competitive Retail Revenues, Other Revenues from Contracts with Customers and Alternative Revenues. For further information relating to the sources of revenue for the Registrants, see Note 19 - Revenues from Contracts with Customers for additional information.

FINANCING

General

Companies within the AEP System generally use short-term debt to finance working capital needs. Short-term debt may also be used to finance acquisitions, construction and redemption or repurchase of outstanding securities until such needs can be financed with long-term debt. In recent history, short-term funding needs have been provided for by cash on hand, term loan issuances and AEP’s commercial paper program. Funds are made available to subsidiaries under the AEP corporate borrowing program. Certain public utility subsidiaries of AEP also sell accounts receivable to provide liquidity. See “Financial Condition” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2022 Annual Report for additional information.

AEP’s revolving credit agreement (which backstops the commercial paper program) includes covenants and events of default typical for this type of facility, including a maximum debt/capital test. In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of its major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under the credit agreement. As of December 31, 2022, AEP was in compliance with its debt covenants. With the exception of a voluntary bankruptcy or insolvency, any event of default has either or both a cure period or notice requirement before termination of the agreement. A voluntary bankruptcy or insolvency of AEP or one of its significant subsidiaries would be considered an immediate termination event. See “Financial Condition” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2022 Annual Report for additional information.

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

ENVIRONMENTAL AND OTHER MATTERS

General

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

Clean Water Act Requirements

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

In November 2015, the Federal EPA issued a final rule revising ELG for electricity generating facilities. The rule established limits on FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater to be imposed in NPDES permits as soon as possible after November 2018 and no later than December 2023. The Federal EPA further revised the rule in August 2020 for FGD wastewater and bottom ash transport water extending the compliance date to December 2025 and establishing additional options.

In January 2020, the Federal EPA issued a final rule revising the scope of the “waters of the United States” subject to CWA regulation. In August 2021, this rule was vacated by a federal court and shortly thereafter, in December 2021, the Federal EPA proposed a rule that would roll back the definition of “waters of the United States” to the pre-2015 definition. That rule was finalized in January 2023 and becomes effective in March 2023. See “Environmental Issues - Clean Water Act Regulations” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2022 Annual Report for additional information.

Coal Ash Regulation

AEP’s operations produce a number of different coal combustion by-products, including fly ash, bottom ash, gypsum and other materials. A rule by the Federal EPA regulates the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at coal-fired electric generating units. The rule requires certain standards for location, groundwater monitoring and dam stability to be met at landfills and certain surface impoundments at operating facilities. If existing disposal facilities cannot meet these standards, they will be required to close. 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 for seeking an extension of that date. AEP filed extension requests for seven facilities, to date, the Federal EPA has not finalized any of those requests. In July 2022, the Federal EPA proposed a conditional approval of the extension request for AEP’s Mountaineer facility, but that request has since been withdrawn. See “Environmental Issues - Coal Combustion Residual (CCR) Rule” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2022 Annual Report for additional information.

Clean Air Act Requirements

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

The Acid Rain Program

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

National Ambient Air Quality Standards

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

Each state identifies the areas within its boundaries that meet the NAAQS (attainment areas) and those that do not (non-attainment areas). Each state must develop a SIP to bring non-attainment areas into compliance with the NAAQS and maintain good air quality in attainment areas. All SIPs are submitted to the Federal EPA for approval. If a state fails to develop adequate plans, the Federal EPA develops and implements a plan. As the Federal EPA reviews the NAAQS and establishes new concentration levels, the attainment status of areas can change and states may be required to develop new SIPs. See “Environmental Issues - Clean Air Act Requirements” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2022 Annual Report for additional information.

Hazardous Air Pollutants (HAP)

The CAA also requires the Federal EPA to investigate HAP emissions from the electric utility sector and submit a report to Congress to determine whether those emissions should be regulated. In 2011, the Federal EPA issued a rule setting Maximum Achievable Control Technology standards for new and existing coal and oil-fired utility units and New Source Performance Standards for emissions from new and modified power plants. In 2014, the U.S. Supreme Court determined that the Federal EPA acted unreasonably in refusing to consider costs in determining if it was appropriate and necessary to regulate HAP emissions from electric generating units. The Federal EPA has engaged in additional rulemaking activity but the 2011 rule remains in effect.

Regional Haze

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

Cross State Air Pollution

CSAPR is a regional trading program designed to address interstate transport of emissions that contribute significantly to non-attainment and maintenance of the ozone and PM NAAQS in downwind states. 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 basis. In January 2021, the Federal EPA finalized a revised CSAPR rule, which substantially reduces the ozone season NOX budgets in 2021-2024. Several utilities and other entities potentially subject to the Federal EPA’s NOX regulations have challenged that final rule in the U.S. Court of Appeals for the District of Columbia Circuit and oral arguments were held in September 2022. Management cannot predict the outcome of that litigation, but 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. In addition, in February 2023, the EPA Administrator finalized the denial of 2015 Ozone NAAQS SIPs for 19 states. A FIP that further revises the ozone season NOX budgets under the existing CSAPR program in those states is expected to be finalized in the spring of 2023 and will likely take effect for the 2023 ozone season. Management is evaluating the impacts of the rule changes.

Climate Change

In October 2022, AEP announced new intermediate and long-term CO2 emission reduction goals, based on the output of AEP’s integrated resource plans. See “Corporate Governance” section for additional information.

To date, the Federal EPA has twice taken action to regulate CO2 emissions from new and existing fossil fueled electric generating units under the existing provisions of the CAA and both attempts have been struck down by the courts. The Federal EPA has announced it expects to propose a new rule in 2023. Management expects emissions to continue to decline over time as AEP diversifies generating sources and operates fewer coal units. The projected decline in coal-fired generation is due to a number of factors, including the ongoing cost of operating older units, the relative cost of coal and natural gas as fuel sources, increasing environmental regulations requiring significant capital investments and changing commodity market fundamentals.

Transforming AEP’s Generation Fleet

The electric utility industry is in the midst of an historic transformation, driven by changing customer needs, evolving public policies, stakeholder demands, demographics, competitive offerings, technologies and commodity prices. AEP is also transforming to be more agile and customer-focused as a valued provider of energy solutions. AEP’s long-term commitment to reduce CO2 emissions reflects the current direction of the company’s resource plans to meet those needs. As of December 31, 2022, the AEP System owned generating capacity of approximately 25,000 MWs. In 2022, coal represented 41% of AEP’s generating capacity compared with 70% in 2005. Transforming AEP’s generation portfolio to include, where there is regulatory support, more renewable energy and focusing on the efficient use of energy, demand response, distributed resources and technology solutions to more efficiently manage the grid over time is part of this strategy.

The graph below summarizes AEP’s generation capacity by resource type for the years 1999, 2005 and 2022:

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

Renewable Sources of Energy

The states AEP serves, other than Kentucky, Oklahoma, West Virginia and Tennessee, have established mandatory or voluntary programs to increase the use of energy efficiency, alternative energy or renewable energy sources. Management actively monitors AEP’s compliance position and is on pace to meet the relevant requirements or benchmarks in each applicable jurisdiction.

As of December 31, 2022, AEP’s regulated utilities had long-term contracts for 2,750 MWs of wind, 80 MWs of hydro and 65 MWs of solar power. Additionally, AEP’s regulated utilities own and operate 1,484 MWs of wind, 805 MWs of hydro and 36 MWs of solar power delivering renewable energy to the companies’ customers.

I&M owns four solar projects that make up I&M’s 15 MW Clean Energy Solar Pilot Project and its 20 MW St. Joseph solar facility went into operation in 2021. 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 1,484 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 owns 45.5% and SWEPCo owns 54.5% of the project, which cost approximately $2 billion. The 199 MW Sundance wind facility was acquired and placed in service in April 2021 and the 287 MW Maverick wind facility was acquired and placed in service in September 2021. The 998 MW Traverse wind facility was acquired and placed in service in March 2022.

AEP’s regulated utilities have significant plans to add new renewable generation. SWEPCo is seeking approval from state regulators to acquire three renewable energy projects totaling 999 MWs. PSO is seeking approval from its state regulator to acquire 996 MW of new renewable projects. Additionally, AEP’s regulated utilities issued RFPs in 2022 seeking additional owned renewable energy projects totaling 4,800 MWs.

The growth of AEP’s renewable generation portfolio reflects the company’s strategy to diversify generation resources to provide clean energy options to customers that meet both their energy and capacity needs. In addition to gradually reducing AEP’s reliance on coal-fueled generating units, the growth of renewables and natural gas helps AEP to maintain a diversity of generation resources.

The integrated resource plans submitted to state regulatory commissions by AEP’s regulated utility subsidiaries reflect AEP’s strategy to balance reliability and cost with customers’ desire for clean energy in a carbon-constrained world. AEP has committed significant capital investments to modernize the electric grid and integrate these new resources. Transmission assets of the AEP System interconnect approximately 22,600 MWs of renewable generation.

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

AEP Renewables develops, owns and operates utility scale renewable projects backed with long-term contracts with creditworthy counterparties throughout the United States. In February 2022, AEP management announced the beginning of a process to sell all or a portion of AEP Renewables’ competitive contracted renewables portfolio. During November 2022, the 235 MW Flat Ridge 2 wind facility was sold. For more information on the pending sale of the competitive contracted renewables portfolio, see the “Contracted Renewable Generation Facilities” section of Management’s Discussion and Analysis. As of December 31, 2022, AEP Renewables owned projects operating in 11 states, including approximately 1,200 MWs of installed wind capacity and 165 MWs of installed solar capacity.

AEP OnSite Partners works directly with wholesale and large retail customers to provide tailored solutions to reduce their energy costs based upon market knowledge, innovative applications of technology and deal structuring capabilities. AEP OnSite Partners targets opportunities in distributed solar, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other energy solutions that create value for customers. AEP OnSite Partners pursues and develops behind the meter projects with creditworthy customers. As of December 31, 2022, AEP OnSite Partners owned projects located in 22 states, including approximately 168 MWs of installed solar capacity, and approximately 26 MWs of solar projects under construction.

End Use Energy Efficiency

Beginning in 2008, AEP ramped up efforts to reduce energy consumption and peak demand through the introduction of additional energy efficiency and demand response programs. These programs, commonly and collectively referred to as demand side management, were implemented in jurisdictions where appropriate cost recovery was available. Since that time, AEP operating company programs have reduced annual consumption by over 10 million MWhs and peak demand by approximately 3,313 MWs. Management estimates that its operating companies spent approximately $1.6 billion since 2008 to achieve these levels.

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

Management believes its experience providing robust energy efficiency programs in several states positions AEP to be a cost-effective provider of these programs as states develop their implementation plans.

Corporate Governance

In response to environmental issues and in connection with its assessment of AEP’s strategic plan, the Board of Directors continually reviews the risks posed by new environmental rules and requirements that could alter the retirement date of coal-fired generation assets. The Board of Directors is informed of new environmental regulations and proposed environmental regulations or legislation that would significantly affect AEP. In addition, the Board holds extended meetings twice a year to provide extra time for a more robust review of the Company’s strategy, including discussions about carbon and carbon risk. The Board’s Committee on Directors and Corporate Governance oversees AEP’s annual Corporate Sustainability Report, which includes information about AEP’s environmental, social, governance and financial performance.

AEP originally set CO2 emission reduction goals in 2018 after considering input from its annual corporate governance outreach effort with shareholders.

In October 2022, AEP announced new intermediate and long-term CO2 emission reduction goals, based on the output of the AEP’s integrated resource plans, which take into account economics, customer demand, grid reliability and resiliency, regulations and the company’s current business strategy. AEP adjusted its near-term CO2 emission reduction target from a 2000 baseline to a 2005 baseline, upgraded its 80% reduction by 2030 target to include full Scope 1 emissions and accelerated its net-zero goal by five years to 2045. AEP’s total Scope 1 GHG estimated emissions in 2022 were approximately 52.5 million metric tons, a 65% reduction from AEP’s 2005 Scope 1 GHG emissions (inclusive of emission reductions that result from plants that have been sold). AEP has made significant progress in reducing CO2 emissions from its power generation fleet and expects its emissions to continue to decline. Technological advances, including advanced energy storage, advanced nuclear reactors, hydrogen production and public policies are among the factors that will determine how quickly AEP can achieve net-zero emissions while continuing to provide reliable, affordable power for customers.

Other Environmental Issues and Matters

The Comprehensive Environmental Response, Compensation and Liability Act of 1980 imposes costs for environmental remediation upon owners and previous owners of sites, as well as transporters and generators of hazardous material disposed of at such sites. See “The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation” section of Note 6 included in the 2022 Annual Report for additional information.

Environmental Investments

Investments related to improving AEP System plants’ environmental performance and compliance with environmental quality standards during 2020, 2021 and 2022 and the current estimate for 2023 are shown below. Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends and the ability to access capital. In addition to the amounts set forth below, AEP expects to make investments in future years in connection with the modification and addition at generation plants’ facilities for environmental quality controls. Such future investments are needed in order to comply with environmental standards that have been adopted and have deadlines for compliance after 2022 or have been proposed and may be adopted. Future investments could be significantly greater if emissions reduction requirements are accelerated or otherwise become more stringent or in response to rules governing the beneficial use and disposal of coal combustion by-products. The cost of complying with applicable environmental laws, regulations and rules is expected to be significant to the AEP System. AEP typically recovers costs of complying with environmental standards from customers through rates in regulated jurisdictions. Failure to recover these costs could reduce future net income and cash flows and possibly harm AEP’s financial condition. See “Environmental Issues” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 6 - Commitments, Guarantees and Contingencies included in the 2022 Annual Report for additional information.


Historical and Projected Environmental Performance and Compliance Investments

	2020		2021		2022		2023
	Actual		Actual		Actual		Estimate (a)
	(in millions)
AEP (b)	$	102.2	$	94.3	$	225.9	$	150.7
APCo	21.3		60.0		129.0		65.9
I&M	31.8		7.2		5.0		—
PSO	—		—		—		0.2
SWEPCo	(3.6)		3.9		18.2		4.8

(a)Estimated amounts are exclusive of debt AFUDC.

(b)Includes expenditures of the subsidiaries shown and other subsidiaries not shown. The figures reflect construction expenditures, not investments in subsidiary companies.

Management currently estimates investments related to improving AEP System plants’ environmental performance and compliance with environmental quality standards will be less than $100 million annually for the years 2024 through 2026. These cost estimates could 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, (g) compliance with the Federal EPA’s revised coal combustion residual rules and (h) timing of implementation.

HUMAN CAPITAL MANAGEMENT

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

The following table shows AEP’s number of employees by subsidiary as of December 31, 2022:


Subsidiary						Number of Employees
AEPSC						6,572
AEP Texas						1,594
APCo						1,650
I&M						2,016
OPCo						1,713
PSO						1,030
SWEPCo						1,372
Other						1,027
Total AEP						16,974

Of AEP’s 16,974 employees, less than 0.1% are Traditionalists (born before 1946), approximately 20% are Baby Boomers (born 1946-1964), approximately 37% are Generation X (born 1965-1980), approximately 38% are Millennials (born 1981-1996) and approximately 5% are Generation Z (born after 1996).

Safety

Achieving Zero Harm means every employee returns home at the end of their shift in the same condition as when they came to work. Zero Harm is what we value most and commit to wholeheartedly. It is hard work, as it requires full focus every moment of every day. We hold ourselves accountable and we are always striving to be better. AEP has put tools, training and processes in place to strengthen our safety-first culture and mindset. AEP’s focus is on learning from events and has proactive programs to prevent harm. One common industry safety metric utilized by AEP to track incidents is the Days Away/Restricted or Transferred (DART) rate. A DART event is an event that results in one or more lost days, one or more restricted days or results in an employee transferring to a different job within the company. The DART rate is a mathematical calculation (number of DART events multiplied by 200,000 work hours and divided by total YTD hours worked) that describes the number of recordable injuries per 100 full-time employees. In 2022, AEP’s employee DART Rate performance improved to 0.424 as compared to 0.430 in 2021.

Diversity, Equity and Inclusion (DEI)

AEP is committed to cultivating a diverse and inclusive environment that supports the development and advancement of all. We foster an inclusive workplace that encourages diversity of thought, culture and background and actively work to eliminate unconscious biases. DEI is a strategic priority for AEP and our efforts are guided by four principles:

•Establishing leadership accountability around DEI outcomes.

•Building and maintaining a workforce that reflects the communities we serve.

•Promoting an inclusive culture where all employees can thrive.

•Supporting the communities we serve so they will prosper.

We believe our workforce should generally reﬂect the diversity of our customers and the communities we serve so that we may better understand how to tailor our services to meet their expectations. As of December 31, 2022, women comprised approximately 20% of AEP’s workforce and 20% was represented by racially or ethnically diverse employees.

Our DEI progress is tied to enterprise, business unit and operating company annual incentive compensation objectives, which is measured through our annual employee culture survey. In addition, the Human Resources Committee of the Board of Directors provides oversight of our compensation and human resources policies and practices, including an annual review of our diversity, equity and inclusion strategy, results of our culture survey and compliance with equal opportunity laws.

AEP has taken actions to denounce all forms of racism in the wake of the racial and social unrest across the country in recent years. To accelerate our diversity and inclusion strategy, AEP facilitates “Community Conversations” for employees to discuss how race and equity issues impact the individual and the workplace and provide tools to take action; provides "Mitigating Bias in Candidate Selection" training for all supervisors with a direct report and employees involved in the interview process; created dedicated faith or meditation rooms; developed affirmative action plans for all AEP sites with more than 50 employees; and, conducts pay equity studies to identify and address pay variances for female and minority employees. We are also signatories of the CEO Action for Diversity and Inclusion pledge, Paradigm for Parity and several other local and industry DEI initiatives to demonstrate our commitment to advancing diversity and inclusion within the workplace.

In addition, we’re committed to working with the communities we serve to advance equity for our employees, customers and neighbors of color. The American Electric Power Foundation created the Delivering on the Dream grant program to help dismantle systemic racism and prejudice while prioritizing diversity, equity and inclusion. This five-year, $5 million initial investment funds organizations with programs dedicated to advancing social justice in the communities we serve.

Culture

AEP believes in doing the right thing every time for our customers, each other and our future. AEP leaders at all levels are responsible for fostering an environment that supports a positive culture and for acting in a manner that positively models it. A high-performance culture forms the foundation for long-term success. An engaged, collaborative and empowered workforce is more likely to embrace a change mindset, drive continuous improvement, accept accountability, meet expectations, take ownership, and value personal growth. AEP is committed to driving our culture forward. Employees are given an opportunity to share their perspectives by participating in the Employee Culture Survey, administered by Gallup, Inc., that measures the progress we are making in improving our culture. In addition to engagement, the survey measures well-being and inclusiveness. In 2022, 86% of our organization participated in the survey and we continued to improve our grand mean score to remain in the top decile compared to Gallup’s overall company database. Additionally, in 2022, AEP received the Gallup Exceptional Workplace Award for the third consecutive year. The award recognizes organizations with engaged workplace cultures. Company executives also have candid meetings with employees to discuss our challenges, opportunities, what is going well and what can be even better.

Employee Resource Groups

One of the best ways for AEP to demonstrate our commitment to a trusting and inclusive work environment is to empower employees to form and participate in Employee Resource Groups (ERG). The ERGs at AEP include Abled and Differently-Abled Partnering Together, the Black ERG, the Asian-American Employee Partnership ERG, the Hispanic Origin Latin American ERG, the Military Veteran ERG, the Native American Tribes Interacting, Observing and Networking ERG, the Pride Partnership and the Women at Work ERG. Our ERGs reflect the diverse makeup of our workforce and enable us to gain valuable insight into the diverse communities we serve. They also help increase engagement across AEP by providing employees with a safe space to discuss work-related issues and to develop innovative solutions. ERGs play an active role in AEP’s diversity and inclusion efforts, including recruitment of new employees.

Training and Professional Development

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

In 2022, AEP employees completed more than 950,000 hours of training in programs for which we track participation. In addition, AEP invested more than $3 million in employee education, supporting approximately 1,000 employees through our tuition reimbursement program.

Compensation and Benefits

AEP cares about the wellbeing of our employees and we recognize their importance to our success. We provide market competitive compensation and benefits, including health, wellness and assistance programs to our employees and their families to help them thrive at home and work. We ensure the pay we offer is competitive in the marketplace by market pricing many of our positions using robust compensation survey information. Nearly all AEP employees participate in an annual incentive program that rewards individual performance and achievement of business goals, which fosters a high-performance culture. AEP also offers employees physical and mental health programs, including medical, dental and life insurance, along with a health and well-being program to help employees and their families stay healthy and feeling their best. Additionally, AEP’s retirement programs position our employees for financial stability in retirement.

Labor Relations

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

BUSINESS SEGMENTS

AEP’s Reportable Segments

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

•Vertically Integrated Utilities

•Transmission and Distribution Utilities

•AEP Transmission Holdco

•Generation & Marketing

The remainder of AEP’s activities is presented as Corporate and Other, which is not considered a reportable segment. See Note 9 - Business Segments included in the 2022 Annual Report for additional information on AEP’s segments.

VERTICALLY INTEGRATED UTILITIES

GENERAL

AEP’s vertically integrated utility operations are engaged in the generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. AEPSC, as agent for AEP’s public utility subsidiaries, performs marketing, generation dispatch, fuel procurement and power-related risk management and trading activities on behalf of each of these subsidiaries.

ELECTRIC GENERATION

Facilities

As of December 31, 2022, AEP’s vertically integrated public utility subsidiaries owned approximately 23,500 MWs of domestic generation. See Item 2 – Properties for more information regarding the generation capacity of vertically integrated public utility subsidiaries.

Fuel Supply

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


	2022	2021	2020
Coal and Lignite	43%	50%	45%
Nuclear	21%	22%	24%
Natural Gas	19%	16%	18%
Renewables	17%	12%	13%

An increase/decrease in one or more generation types relative to previous years reflects the addition of renewable resources, retirement of traditional fossil fuel units and price changes in one or more fuel commodity sources relative to the pricing of other fuel commodity sources. AEP’s overall 2022 fossil fuel costs for the Vertically Integrated Utilities increased 1.1% on a dollar per MMBtu basis from 2021.

Coal and Lignite

AEP’s Vertically Integrated Utilities procure coal and lignite under a combination of purchasing arrangements including long-term contracts, affiliate operations and spot agreements with various producers, marketers and coal trading firms. Coal and lignite consumption decreased 11% in 2022 from 2021 due to a combination of the retirement of Dolet Hills Power Plant, lower amounts of lignite inventory available due to the planned retirement of the Pirkey Power Plant in March 2023 and lower generation at the coal fired power plants.

Management projects that the Vertically Integrated Utilities will be able to secure and transport coal and lignite of adequate quality and quantities to operate their coal and lignite-fired units; however, with current global dynamics and demand, supplies could be a challenge. As of December 31, 2022, through subsidiaries, AEP owns, leases or controls 3,000 railcars, 319 barges, 4 towboats and a coal handling terminal with approximately 18 million tons of annual capacity to move and store coal for use in AEP generating facilities. AEP will procure additional railcar and barge/towboat capacity as needed based on demand.

Spot coal prices strengthened significantly in the back half of 2021 and continued to increase throughout 2022 for all coal basins to all-time highs, with the exception of Powder River Basin coal which somewhat stabilized in 2022 to more historical levels. These price increases were primarily due to increases in global and domestic demand for coal. AEP’s strategy for purchasing coal includes layering in supplies over time. The price impact of this process is reflected in subsequent periods and with the current elevated prices will drive delivered coal prices up over the next few years for purchases made in 2021 and 2022. The price paid for coal and lignite delivered in 2022 increased approximately 10.6% from 2021 primarily due to the increase in coal prices from all coal basins.

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


	2022		2021		2020
Total coal and lignite delivered to the plants (in millions of tons)	20.4		18.2		19.4
Average cost per ton of coal and lignite delivered	$	56.16	$	50.76	$	53.95

The coal supplies at the Vertically Integrated Utilities plants vary from time to time depending on various factors, including, but not limited to, demand for electric power, unit outages, transportation infrastructure limitations, space limitations, plant coal consumption rates, availability of acceptable coals, labor issues and weather conditions, which may interrupt production or deliveries. As of December 31, 2022, the Vertically Integrated Utilities’ coal inventory was approximately 35 days of full load burn. While inventory targets vary by plant and are changed as necessary, the current coal inventory target for the Vertically Integrated Utilities is approximately 27 days of full load burn.

Natural Gas

The Vertically Integrated Utilities consumed approximately 126 billion cubic feet of natural gas during 2022 for generating power. This represents an increase of 16.5% from 2021. Several of AEP’s natural gas-fired power plants are connected to at least two pipelines which allow greater access to competitive supplies and improve delivery reliability. A portfolio of term, seasonal, monthly and daily natural gas supply agreements and term natural gas transportation agreements provide natural gas requirements for each plant, as appropriate. AEP’s natural gas supply transactions are based on market prices.

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


	2022		2021		2020
Total natural gas delivered to the plants (in billions cubic feet)	126.0		108.0		113.1
Average delivered price per MMBtu of purchased natural gas	$	6.94	$	8.92	$	2.14

Nuclear

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

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

Nuclear Waste and Decommissioning

As the owner of the Cook Plant, I&M has a significant future financial commitment to dispose of SNF and decommission and decontaminate the plant safely. The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program. The most recent decommissioning cost study was completed in 2021. The estimated cost of decommissioning and disposal of low-level radioactive waste for the Cook Plant was $2.2 billion in 2021 non-discounted dollars, with additional ongoing estimated costs of $7 million per year for post decommissioning storage of SNF and an eventual estimated cost of $33 million for the subsequent decommissioning of the spent fuel storage facility, also in 2021 non-discounted dollars. As of December 31, 2022 and 2021, the total decommissioning trust fund balance for the Cook Plant was approximately $3 billion and $3.5 billion, respectively. The balance of funds available to eventually decommission Cook Plant will differ based on contributions and investment returns. The ultimate cost of retiring the Cook Plant may be materially different from estimates and funding targets as a result of the:

•Escalation of various cost elements (including, but not limited to, general inflation and the cost of energy).

•Further development of regulatory requirements governing decommissioning.

•Technology available at the time of decommissioning differing significantly from that assumed in studies.

•Availability of nuclear waste disposal facilities.

•Availability of a United States Department of Energy facility for permanent storage of SNF.

Accordingly, management is unable to provide assurance that the ultimate cost of decommissioning the Cook Plant will not be significantly different than current projections. AEP will seek recovery from customers through regulated rates if actual decommissioning costs exceed projections. See the “Nuclear Contingencies” section of Note 6 - Commitments, Guarantees and Contingencies included in the 2022 Annual Report for additional information with respect to nuclear waste and decommissioning.

Low-Level Radioactive Waste

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

Counterparty Risk Management

The Vertically Integrated Utilities segment also sells power and enters into related energy transactions with wholesale customers and other market participants. As a result, counterparties and exchanges may require cash or cash related instruments to be deposited on transactions as margin against open positions. As of December 31, 2022, counterparties posted approximately $14 million in cash, cash equivalents or letters of credit with AEPSC for the benefit of AEP’s public utility subsidiaries (while, as of that date, AEP’s public utility subsidiaries posted approximately $207 million with counterparties and exchanges). Since open trading contracts are valued based on market prices of various commodities, exposures change daily. See the “Quantitative and Qualitative Disclosures About Market Risk” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2022 Annual Report for additional information.

Certain Power Agreements

I&M

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

In April 2021, AEGCo and I&M executed an agreement to purchase 100% of the interests in Rockport Plant, Unit 2 effective at the end of the lease term on December 7, 2022. Beginning December 8, 2022, AEGCo and I&M applied the joint plant accounting model to their respective 50% undivided interests in the jointly owned Rockport Plant, Unit 2 as well as any future investments made prior to the current estimated retirement date of December 2028.

Prior to the termination of the lease, I&M assigned 30% of the power to KPCo. See the “UPA between AEGCo and KPCo” section of Note 16 - Related Party Transactions for additional information. Beginning December 8, 2022, AEGCo billed 100% of its share of the Rockport Plant to I&M and ceased billing to KPCo. KPCo reached an agreement with I&M, from the end of the lease through May 2024, to buy capacity from Rockport Plant, Unit 2 through the PCA at a rate equal to PJM’s RPM clearing price.

OVEC

AEP and several nonaffiliated utility companies jointly own OVEC. The aggregate equity participation of AEP in OVEC is 43.47%. Parent owns 39.17% and OPCo owns 4.3%. Under the Inter-Company Power Agreement (ICPA), which defines the rights of the owners and sets the power participation ratio of each, the sponsoring companies are entitled to receive and are obligated to pay for all OVEC capacity (approximately 2,400 MWs) in proportion to their respective power participation ratios. The aggregate power participation ratio of APCo, I&M and OPCo is 43.47%. The ICPA terminates in June 2040. The proceeds from charges by OVEC to sponsoring companies under the ICPA based on their power participation ratios are designed to be sufficient for OVEC to meet its operating expenses and fixed costs. OVEC’s Board of Directors, as elected by AEP and nonaffiliated owners, has authorized environmental investments related to their ownership interests, with resulting expenses (including for related debt and interest thereon) included in charges under the ICPA. OVEC financed capital expenditures in excess of $1 billion in connection with flue gas desulfurization projects and the associated scrubber waste disposal landfills at its two generation plants through debt issuances, including tax-advantaged debt issuances. Both OVEC generation plants are operating with the new environmental controls in-service. See Note 17 - Variable Interest Entities and Equity Method Investments for additional information.

ELECTRIC DELIVERY

General

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

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

Transmission Agreement

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

Transmission Coordination Agreement and Open Access Transmission Tariff

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

Regional Transmission Organizations

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

REGULATION

General

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

Rates

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

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

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

The following state-by-state analysis summarizes the regulatory environment of certain major jurisdictions in which AEP’s vertically integrated public utility subsidiaries operate. Several public utility subsidiaries operate in more than one jurisdiction. See Note 4 - Rate Matters included in the 2022 Annual Report for more information regarding pending rate matters.

Indiana

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

Oklahoma

PSO provides retail electric service in Oklahoma at bundled rates approved by the OCC. PSO’s rates are set on a cost-of-service basis. Fuel and purchased energy costs are recovered or refunded through a fuel adjustment clause.

Virginia

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

West Virginia

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

FERC

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

The FERC oversees RTOs, entities created to operate, plan and control utility transmission assets. AEGCo, APCo, I&M, KGPCo, KPCo and WPCo are members of PJM. PSO and SWEPCo are members of SPP.

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

COMPETITION

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

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

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

SEASONALITY

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

TRANSMISSION AND DISTRIBUTION UTILITIES

GENERAL

This segment consists of the transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo. OPCo is engaged in the transmission and distribution of electric power to approximately 1,521,000 retail customers in Ohio. OPCo purchases energy and capacity to serve standard service offer customers and provides transmission and distribution services for all connected load. AEP Texas is engaged in the transmission and distribution of electric power to approximately 1,094,000 retail customers through REPs in west, central and southern Texas.

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

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

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

Transmission Agreement

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

Regional Transmission Organizations

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

REGULATION

OPCo provides distribution and transmission services to retail customers within its service territory at cost-based rates approved by the PUCO or by the FERC. AEP Texas sets its rates through a combination of base rate cases and interim Transmission Cost of Services (TCOS) and Distribution Cost Recovery Factor (DCRF) filings. AEP Texas may file interim TCOS filings semi-annually and DCRF filings annually to update its rates to reflect changes in its net invested capital. Transmission and distribution rates are established on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service. The cost-of-service generally reflects operating expenses, including operation and maintenance expense, depreciation expense and taxes. Utility commissions periodically adjust rates pursuant to a review of: (a) a utility’s adjusted revenues and expenses during a defined test period and (b) such utility’s level of investment.

FERC

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

SEASONALITY

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

AEP TRANSMISSION HOLDCO

GENERAL

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

AEPTCo

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

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

The State Transcos are regulated for rate-making purposes exclusively by the FERC and earn revenues through tariff rates charged for the use of their electric transmission systems. The State Transcos establish transmission rates each year through formula rate filings with the FERC. The rate filings calculate the revenue requirement needed to cover the costs of operation and debt service and to earn an allowed ROE. These rates are then included in an OATT for PJM, MISO and SPP.

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

The State Transcos provide the capability to build, replace and upgrade existing facilities. As of December 31, 2022, the State Transcos had $12.8 billion of transmission and other assets in-service with plans to construct approximately $3.3 billion of additional transmission assets, excluding CWIP, through 2025. Additional investment in transmission infrastructure is needed within PJM and SPP to maintain the required level of grid reliability, resiliency, security and efficiency and to address an aging transmission infrastructure. Additional transmission facilities will be needed based on changes in generating resources, such as wind or solar projects, generation additions or retirements and additional new customer interconnections. The State Transcos will continue their investment to enhance physical and cyber security of assets, and are also investing in improving the telecommunication network that supports the operation and control of the grid.

In October 2021, AEP entered into a Stock Purchase Agreement to sell KTCo to Liberty Utilities. The closing of the sale is subject to receipt of FERC authorization under Section 203 of the Federal Power Act and clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.

AEPTHCO JOINT VENTURE INITIATIVES

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

Joint Venture Name

Location

Projected or Actual Completion Date

Owners
(Ownership %)

Total Estimated/Actual Project Costs at Completion

Approved Return on Equity

(in millions)

ETT

Texas

(a)

Berkshire Hathaway

4,100.0

(a)

9.6

(ERCOT)

Energy (50%)

AEP (50%)

Prairie Wind

Kansas

2014

Evergy, Inc. (50%)

158.0

12.8

Berkshire Hathaway

Energy (25%)

AEP (25%)

Pioneer

Indiana

2018

Duke Energy (50%)

191.0

10.52

(b)

AEP (50%)

Transource

Missouri

2016

Evergy, Inc.

310.5

11.1

(c)

Missouri

(13.5%) (d)

AEP (86.5%) (d)

Transource

West

2019

Evergy, Inc.

86.0

10.5

West Virginia

Virginia

(13.5%) (d)

AEP (86.5%) (d)

Transource

Maryland

2023

Evergy, Inc.

27.6

(e)

10.4

Maryland

(13.5%) (d)

AEP (86.5%) (d)

Transource

Pennsylvania

2023

Evergy, Inc.

243.6

(e)

10.4

Pennsylvania

(13.5%) (d)

AEP (86.5%) (d)

Transource

Oklahoma

2026

Evergy, Inc.

111.0

(f)

10.0

Oklahoma

(13.5%)(d)

AEP (86.5%) (d)

Transource

Pennsylvania

2029

Evergy, Inc.

76.3

(g)

10.4

Energy

(13.5%) (d)

AEP (86.5%) (d)

(a)ETT is undertaking multiple projects and the completion dates will vary for those projects. ETT’s investment in completed and active projects in ERCOT is expected to be $4.1 billion. Future projects will be evaluated on a case-by-case basis.

(b)In May 2020, Pioneer received FERC approval authorizing an ROE of 10.02% (10.52% inclusive of the RTO incentive adder of 0.5%).

(c)The ROE represents the weighted-average approved ROE based on the costs of two projects developed by Transource Missouri; the $64 million Iatan-Nashua project (10.3%) and the $247 million Sibley-Nebraska City project (11.3%).

(d)AEP owns 86.5% of Transource Missouri, Transource West Virginia, Transource Maryland, Transource Pennsylvania and Transource Oklahoma through its ownership interest in Transource Energy, LLC (Transource). Transource is a joint venture with AEPTHCo and Evergy, Inc. formed to pursue competitive transmission projects. AEPTHCo and Evergy, Inc. own 86.5% and 13.5% of Transource, respectively.

(e)See “Independence Energy Connection Project” section of Note 4 for additional information.

(f)In 2016, Transource Kansas received approval from the FERC authorizing an ROE of 9.8% (10.3% inclusive of the RTO incentive adder of 0.5%) for future competitive transmission projects in SPP. In October 2020, Transource was awarded the Sooner-Wekiwa project by SPP and the project was assigned to Transource Kansas. In November 2020, Transource Kansas was renamed Transource Oklahoma. The project is expected to go in-service in 2026.

(g)In October 2022, Transource Energy’s North Delta A proposal was awarded by the New Jersey Board of Public Utilities. The project is expected to go in-service in 2029. The project consists of a new transmission substation with two transformers and nine breakers and will connect to existing transmission lines.

Transource Missouri, Transource West Virginia, Transource Maryland, Transource Pennsylvania and Transource Oklahoma are consolidated joint ventures by AEP. All other joint ventures in the table above are not consolidated by AEP. AEP’s joint ventures do not have employees. Business services for the joint ventures are provided by AEPSC and other AEP subsidiaries and the joint venture partners. In 2022, approximately 461 AEPSC employees and 294 operating company employees provided service to one or more joint ventures.

REGULATION

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

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

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

Management continues to monitor the FERC’s 2019 Notice of Inquiry regarding base ROE policy, the FERC’s 2020 and 2021 supplemental Notice of Proposed Rulemaking (NOPR) regarding transmission incentives policy, and various other matters pending before the FERC with the potential to affect the transmission ROE methodology.

In April 2021, the FERC issued a supplemental 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. AEP is awaiting a final rule from the FERC.

In the annual rate base filings described above, the State Transcos in aggregate filed rate base totals of $9.9 billion, $8.4 billion and $7 billion for 2022, 2021 and 2020, respectively. The total filed transmission revenue requirements, including prior year over/under-recovery of revenue and associated carrying charges were $1.7 billion, $1.4 billion and $1.2 billion for 2022, 2021 and 2020, respectively.

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

GENERATION & MARKETING

GENERAL

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

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

AEP Renewables develops, owns and operates utility scale renewable projects backed with long-term contracts with creditworthy counterparties throughout the United States. AEP Renewables works directly with stakeholders to ensure that customers have clean, sustainable renewable energy to meet their environmental goals. As of December 31, 2022, AEP Renewables owned projects operating in 11 states, including approximately 1,200 MWs of installed wind capacity and 165 MWs of installed solar capacity. In October 2019, AEP Renewables entered into an agreement to construct Flat Ridge 3, a wind farm in Kansas. The 128 MW facility was placed into service in December 2021. In November 2020, AEP Renewables signed a Purchase and Sale Agreement to acquire 75% of the Dry Lake Solar Project, a 100 MW solar facility in southern Nevada. This facility was placed into service in May 2021. In February 2022, AEP management announced the beginning of a process to sell all or a portion of AEP Renewables’ competitive contracted renewables portfolio. For more information on the pending sale of the competitive contracted renewables portfolio, see the “Contracted Renewable Generation Facilities” section of Management’s Discussion and Analysis.

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

With respect to the retail supply and energy management business, AEP Energy is a retail energy supplier that supplies electricity and/or natural gas to residential, commercial, and industrial customers. AEP Energy provides various energy solutions in Illinois, Pennsylvania, Delaware, Maryland, New Jersey, Ohio and Washington, D.C. AEP Energy had approximately 736,000 customer accounts as of December 31, 2022. AEP has initiated a strategic evaluation of its ownership in AEP Energy. Potential alternatives may include, but are not limited to, continued ownership or a sale of all or a part of AEP Energy. Management has not made a decision regarding the potential alternatives, but expects to complete the strategic evaluation in the first half of 2023.

The primary fossil generation subsidiary in the Generation & Marketing segment has historically been AGR. However, in the third quarter 2022, AGR sold the 595 MW Cardinal Plant, its last remaining fossil generation. Other subsidiaries in this segment own or have the right to receive power from additional generation assets. See Item 2 – Properties for more information regarding the generation assets of the Generation & Marketing segment.

REGULATION

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

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

COMPETITION

The AEP Generation & Marketing segment subsidiaries face competition for the sale of available power, capacity and ancillary services. The principal factors of impact are electricity and fuel prices, new market entrants, construction or retirement of generating assets by others and technological advances in power generation. Other factors impacting competitiveness include environmental regulation, transmission congestion or transportation constraints at or near generation facilities, inoperability or inefficiencies, outages and deactivations and retirements at generation facilities.

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

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

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

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

SEASONALITY

Fuel Supply

The following table shows the generation sources by type, on an actual net generation (MWhs) basis, used by the Generation & Marketing segment:


	2022	2021	2020
Coal	41%	38%	46%

Renewables	59%	62%	54%

Counterparty Risk Management

Counterparties and exchanges may require cash or cash related instruments to be deposited on these transactions as margin against open positions. As of December 31, 2022, counterparties posted approximately $498 million in cash, cash equivalents or letters of credit with AEP for the benefit of AEP’s Generation & Marketing segment subsidiaries (while, as of that date, AEP’s Generation & Marketing segment subsidiaries posted approximately $115 million with counterparties and exchanges). Since open trading contracts are valued based on market prices of various commodities, exposures change daily. See the “Quantitative and Qualitative Disclosures About Market Risk” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2022 Annual Report for additional information.

Certain Power Agreements

As of December 31, 2022, the assets utilized in this segment included approximately 1,200 MWs of company-owned domestic wind power facilities and 177 MWs of domestic wind power from long-term purchase power agreements. Additional long term purchased power agreements have been entered into for 77 MWs of wind that are operating and an additional 640 MWs of wind and 1,659 MWs of solar capacity which are all seeking permits or under construction. These agreements are all contingent on completion of construction which is expected by the end of 2025.

In March 2022, AGR entered into an Asset Purchase agreement with a nonaffiliated electric cooperative to sell Cardinal Plant, Unit 1, a competitive generation asset totaling 595 MWs. The FERC approved the sale in May 2022 and the sale closed in the third quarter of 2022. The proceeds from the sale were not material. Concurrent with the closing of the sale, AGR executed a PPA with the nonaffiliated electric cooperative for rights to Unit 1’s power and capacity through 2028. AGR also retained certain obligations related to environmental remediation.

INFORMATION ABOUT OUR EXECUTIVE OFFICERS

The following persons are executive officers of AEP. Their ages are given as of February 23, 2023. The officers are appointed annually for a one-year term by the board of directors of AEP.

Julia A. Sloat

President and Chief Executive Officer

Age 53

President since August 2022 and Chief Executive Officer since January 2023. Executive Vice President from January 2021 to August 2022, Chief Financial Officer from January 2021 to November 2022. Senior Vice President, Treasury & Risk and Treasurer from January 2019 to December 2020. President and Chief Operating Officer of OPCo from May 2016 to December 2018.

Nicholas K. Akins

Executive Chair of the Board of Directors

Age 62

Chairman of the Board from January 2014 to December 2022, President from January 2011 to August 2022 and Chief Executive Officer from November 2011 to December 2022.

Christian T. Beam

Executive Vice President - Energy Services

Age 54

Executive Vice President - Energy Services since September 2022. President and Chief Operating Officer of APCo from January 2017 to September 2022. Vice President, Projects Controls & Construction from January 2013 to December 2016.

David M. Feinberg

Executive Vice President, General Counsel and Secretary

Age 53

Executive Vice President since January 2013. General Counsel and Secretary since January 2012.

Greg B. Hall

Executive Vice President and Chief Commercial Officer

Age 50

Executive Vice President and Chief Commercial Officer since September 2022. Executive Vice President - Energy Supply from July 2021 to September 2022. President and Chief Operating Officer of AEP Energy Supply LLC since July 2021. President of AEP Energy, Inc. since May 2017. President of AEP Energy Partners, Inc. since June 2007.

Ann P. Kelly

Executive Vice President and Chief Financial Officer

Age 52

Executive Vice President and Chief Financial Officer since November 2022. Vice President - Finance and Chief Financial Officer of AmeriGas Propane, Inc., a subsidiary of UGI Corporation since February 2019. Corporate Controller and Chief Accounting Officer of UGI Corporation from March 2018 to February 2019. Assistant Treasurer of UGI Corporation from May 2016 to March 2018.

Therace M. Risch

Executive Vice President and Chief Information & Technology Officer

Age 49

Executive Vice President since July 2021. Chief Information & Technology Officer since May 2020. Senior Vice President from April 2020 to July 2021.

Peggy I. Simmons

Executive Vice President - Utilities

Age 45

Executive Vice President - Utilities since September 2022. President and Chief Operating Officer of PSO from September 2018 to September 2022.

Raja Sundararajan

Executive Vice President - External Affairs

Age 48

Executive Vice President - External Affairs since July 2022. Senior Vice President - Regulatory and Customer Solutions from July 2021 to July 2022. President and Chief Operating Officer of AEP Ohio from January 2019 to July 2021. Vice President-Regulatory Services September 2016 to December 2018.

Phillip R. Ulrich

Executive Vice President and Chief Human Resources Officer

Age 52

Executive Vice President since January 2023. Chief Human Resources Officer since August 2021. Senior Vice President from August 2021 to December 2022. Chief Human Resources Officer of Flex, LTD from May 2019 to July 2021. Senior Vice President, Human Resources, Electrical Sector of Eaton from August 2016 to May 2019.

Charles E. Zebula

Executive Vice President - Portfolio Optimization

Age 62

Executive Vice President - Portfolio Optimization since July 2021. Executive Vice President - Energy Supply from January 2013 to July 2021.

ITEM 1A. RISK FACTORS

GENERAL RISKS OF REGULATED OPERATIONS

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

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

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

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

If regulated utility earnings exceed the returns established by the relevant commissions, retail electric rates may be subject to review and possible reduction by the commissions, which may decrease future earnings. Additionally, if regulatory bodies do not allow recovery of costs incurred in providing service on a timely basis, it could reduce future net income and cash flows and negatively impact financial condition. Similarly, if recovery or other rate relief authorized in the past is overturned or reversed on appeal, future earnings could be negatively impacted. Any regulatory action or litigation outcome that triggers a reversal of a regulatory asset or deferred cost generally results in an impairment to the balance sheet and a charge to the income statement of the company involved. See Note 4 – Rate Matters included in the 2022 Annual Report for additional information.

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

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

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

AEP provides transmission service under rates regulated by the FERC. The FERC has approved the cost-based formula rate templates used by AEP to calculate its respective annual revenue requirements, but it has not expressly approved the amount of actual capital and operating expenditures to be used in the formula rates. All aspects of AEP’s rates accepted or approved by the FERC, including the formula rate templates, the rates of return on the

actual equity portion of its respective capital structures and the approved targeted capital structures, are subject to challenge by interested parties at the FERC, or by the FERC on its own initiative. In addition, interested parties may challenge the annual implementation and calculation by AEP of its projected rates and formula rate true-up pursuant to its approved formula rate templates under AEP’s formula rate implementation protocols. If a challenger can establish that any of these aspects are unjust, unreasonable, unduly discriminatory or preferential, then the FERC can make appropriate prospective adjustments to them and/or disallow any of AEP’s inclusion of those aspects in the rate setting formula.

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

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

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

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

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

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

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

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

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

I&M owns the Cook Plant, which consists of two nuclear generating units for a rated capacity of 2,296 MWs, or about a tenth of the regulated generating capacity in the AEP System. AEP and I&M are, therefore, subject to the risks of nuclear generation, which include the following:

•The potential harmful effects on the environment and human health due to an adverse incident/event resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials such as SNF.

•Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations.

•Uncertainties with respect to contingencies and assessment amounts triggered by a loss event (federal law requires owners of nuclear units to purchase the maximum available amount of nuclear liability insurance and potentially contribute to the coverage for losses of others).

•Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.

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

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

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

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

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

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

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

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

AEP Texas collects receivables from the distribution of electricity from REPs that supply the electricity it distributes to its customers. As of December 31, 2022, AEP Texas did business with approximately 127 REPs. Adverse economic conditions, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for these services or could cause them to delay such payments. AEP Texas depends on these REPs to remit payments on a timely basis. Applicable regulatory provisions require that customers be shifted to another REP or a provider of last resort if a REP cannot make timely payments. Applicable PUCT regulations significantly limit the extent to which AEP Texas can apply normal commercial terms or otherwise seek credit protection from firms desiring to provide retail electric service in its service territory, and AEP Texas thus remains at risk for payments related to services provided prior to the shift to another REP or the provider of last resort. In 2022, AEP Texas’ two largest REPs accounted for 45% of its operating revenue. Any delay or default in payment by REPs could adversely affect cash flows, financial condition and results of operations. If a REP were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations, and claims might be made by creditors involving payments AEP Texas had received from such REP.

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

In 2019, Ohio adopted and implemented HB 6 which benefits OPCo by authorizing rate recovery for certain costs including renewable energy contracts, OVEC’s coal-fired generating units and energy efficiency measures. AEP and OPCo engaged in lobbying efforts and provided testimony during the legislative process in connection with HB 6. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of an Ohio legislator and associates in connection with an alleged racketeering conspiracy involving the adoption of HB

6. The outcome of the U.S. Attorney’s Office investigation and its impact on HB 6 is not known. If certain provisions of HB 6 were to be eliminated, it is unclear whether new legislation addressing similar issues would be adopted. To the extent that OPCo is unable to recover the costs currently authorized by HB 6, it could reduce future net income and cash flows and impact financial condition. In addition, the impact of continued public scrutiny of HB 6 is not known, and may have an adverse impact on AEP and OPCo, including their relationship with regulatory and legislative authorities, customers and other stakeholders. AEP is a defendant in current litigation relating to HB 6 and AEP or OPCo may be involved in future litigation.

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

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

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

•Operator error and breakdown or failure of equipment or processes.

•Operating limitations that may be imposed by environmental or other regulatory requirements.

•Labor disputes.

•Compliance with mandatory reliability standards, including mandatory cyber security standards.

•Information technology failure that impairs AEP’s information technology infrastructure or disrupts normal business operations.

•Information technology failure that affects AEP’s ability to access customer information or causes loss of confidential or proprietary data that materially and adversely affects AEP’s reputation or exposes AEP to legal claims.

•Supply chain disruptions and inflation.

•Fuel or water supply interruptions caused by transportation constraints, adverse weather such as drought, non-performance by suppliers and other factors.

•Catastrophic events such as fires, earthquakes, explosions, hurricanes, tornados, ice storms, terrorism (including cyber-terrorism), floods or other similar occurrences.

•Fuel costs and related requirements triggered by financial stress in the coal industry.

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

AEP and its regulated utility businesses face physical security and cybersecurity risks as the owner-operators of generation, transmission and/or distribution facilities and as participants in commodities trading. AEP and its regulated utility businesses own assets deemed as critical infrastructure, the operation of which is dependent on information technology systems. Further, the computer systems that run these facilities are not completely isolated from external networks. Parties that wish to disrupt the U.S. bulk power system or AEP operations could view these computer systems, software or networks as targets for cyber-attack. The Federal government has notified the owners and operators of critical infrastructure, such as AEP, that the conflict between Russia and Ukraine has increased the likelihood of a cyber-attack on such systems. In addition, the electric utility business requires the collection of sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss.

A security breach of AEP or its regulated utility businesses’ physical assets or information systems, interconnected entities in RTOs, or regulators could impact the operation of the generation fleet and/or reliability of the transmission and distribution system. AEP and its regulated utility businesses could be subject to financial harm associated with ransomware theft or inappropriate release of certain types of information, including sensitive customer, vendor, employee, trading or other confidential data. A successful cyber-attack on the systems that control generation, transmission, distribution or other assets could severely disrupt business operations, preventing service to customers or collection of revenues. The breach of certain business systems could affect the ability to

correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to AEP’s reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data could lead to significant breach notification expenses and mitigation expenses such as credit monitoring. AEP and its third-party vendors have been subject, and will likely continue to be subject, to attempts to gain unauthorized access to their technology systems and confidential data or to attempts to disrupt utility and related business operations. While there have been immaterial incidents of phishing, unauthorized access to technology systems, financial fraud, and disruption of remote access across the AEP System, there has been no material impact on business or operations from these attacks. However, AEP cannot guarantee that security efforts will detect or prevent breaches, operational incidents, or other breakdowns of technology systems and network infrastructure and cannot provide any assurance that such incidents will not have a material adverse effect in the future.

The amount 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, including tax incentives and credits designed to support the sale of energy from utility scale renewable energy facilities. While management believes AEP complies with current prevailing laws, one or more taxing jurisdictions could seek to impose incremental or new taxes on the company. In addition, any adverse developments in tax laws, incentives, credits or regulations, including legislative changes, judicial holdings or administrative interpretations, could have a material and adverse effect on financial condition and results of operations.

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

AEP relies on access to capital markets as a significant source of liquidity for capital requirements not satisfied by operating cash flows or proceeds from the strategic sale of assets and investments, including subsidiaries such as the planned sale of KPCo and KTCo and AEP Renewables’ competitive contracted renewable portfolio, and insurance markets to assist in managing its risk and liability profile. Volatility, increased interest rates and reduced liquidity in the financial markets could affect AEP’s ability to raise capital on reasonable terms to fund capital needs, including construction costs and refinancing maturing indebtedness. Certain sources of insurance and debt and equity capital have expressed increasing unwillingness to procure insurance for or to invest in companies, such as AEP, that rely on fossil fuels. The public holds diverse and often conflicting views on the use of fossil fuels. AEP has multiple stakeholders, including our shareholders, customers, associates, federal and state regulatory authorities, and the communities in which AEP operates, and these stakeholders will often have differing priorities and expectations regarding issues related to the use of fossil fuels. Any adverse publicity in connection with AEP’s use of fossil fuels could curtail availability from certain sources of capital. If sources of capital for AEP are reduced and/or expected sale proceeds do not become available, capital costs could increase materially. Restricted access to capital or insurance markets and/or increased borrowing costs or insurance premiums could reduce future net income and cash flows and negatively impact financial condition.

Our financial position may be adversely impacted if announced dispositions do not occur as planned or if assets under strategic evaluation lose value. (Applies to AEP)

In October 2021, AEP entered into an agreement to sell KPCo and KTCo for approximately a $2.85 billion enterprise value. In September 2022, the agreement was amended to reduce the purchase price to approximately $2.646 billion, among other terms. The sale remains subject to regulatory approval and if it is not approved on terms acceptable to AEP or if the sale does not occur for any reason, it could reduce future net income and cash flow and impact financial condition. In February 2023, AEP signed an agreement to sell the AEP Renewables’ competitive contracted renewables portfolio to a nonaffiliated party for $1.5 billion including the assumption of project debt. The sale is subject to regulatory approval. Any announced sale of assets and investments, including subsidiaries, may not occur for any number of reasons beyond our control, including regulatory approval on terms that are acceptable.

AEP has initiated a strategic evaluation for its ownership in AEP Energy, a wholly-owned retail energy supplier that supplies electricity and/or natural gas to residential, commercial and industrial customers. AEP has not made a decision regarding the potential alternatives and expects to complete the evaluation in the first half of 2023. Certain of these alternatives could result in a loss which could reduce future net income and cash flow and impact financial condition.

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

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

Downgrades in AEP’s credit ratings could negatively affect its ability to access capital. (Applies to all Registrants)

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

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

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

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

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

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

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

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

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

Supply chain disruptions and inflation could negatively impact our operations and corporate strategy. (Applies to all Registrants)

AEP’s operations and business plans depend on the global supply chain to procure the equipment, materials and other resources necessary to build and provide services in a safe and reliable manner. The delivery of components, materials, equipment and other resources that are critical to AEP’s business operations and corporate strategy has been restricted by domestic and global supply chain upheaval. This has resulted in the shortage of critical items. International tensions, including the ramifications of regional conflict, could further exacerbate the global supply chain upheaval. These disruptions and shortages could adversely impact business operations and corporate strategy. The constraints in the supply chain could restrict the availability and delay the construction, maintenance or repair of items that are needed to support normal operations or are required to execute on AEP’s corporate strategy for continued capital investment in utility equipment. These disruptions and constraints could reduce future net income and cash flows and possibly harm AEP’s financial condition.

Supply chain disruptions have contributed to higher prices of components, materials, equipment and other needed commodities and these inflationary increases may continue in the future. The economy in the United States has encountered a material level of inflation compared to the recent past and that has contributed to increased uncertainty in the outlook of near-term economic activity, including the level of future inflation and the possibility of a recession. AEP typically recovers increases in capital expenses from customers through rates in regulated jurisdictions. Failure to recover increased capital costs could reduce future net income and cash flows and possibly harm AEP’s financial condition. Increases in inflation raises our costs for labor, materials and services, and failure to secure these on reasonable terms may adversely impact our financial condition.

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

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

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

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

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

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

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

Prices for coal, natural gas and emission allowances have shown material swings in the past. Changes in the cost of purchased power, fuel or emission allowances and changes in the relationship between such costs and the market prices of power could reduce future net income and cash flows and negatively impact financial condition.

In addition, actual power prices and fuel costs will differ from those assumed in financial projections used to value trading and marketing transactions, and those differences may be material. As a result, as those transactions are marked-to-market, they may impact future results of operations and cash flows and impact financial condition.

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

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

Increased energy use due to weather changes may require AEP to invest in additional generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes may affect financial condition through decreased revenues. Extreme weather conditions in general require more system

backup, adding to costs, and can contribute to increased system stress, including service interruptions. Weather conditions outside of the AEP service territory could also have an impact on revenues. AEP buys and sells electricity depending upon system needs and market opportunities. Extreme weather conditions creating high energy demand on AEP’s own and/or other systems may raise electricity prices as AEP buys short-term energy to serve AEP’s own system, which would increase the cost of energy AEP provides to customers.

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

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

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

AEP is involved in legal proceedings, claims and litigation arising out of its business operations, the most significant of which are summarized in Note 6 - Commitments, Guarantees and Contingencies included in the 2022 Annual Report. Adverse outcomes in these proceedings could require significant expenditures that could reduce future net income and cash flows and negatively impact financial condition.

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

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

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

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

AEP Texas and other AEP entities are named in approximately 100 lawsuits generally alleging the failure to exercise reasonable care in maintaining and updating their generation, transmission and distribution facilities in order to prevent cold weather failures and other related negligence. The complaints seek monetary damages among other forms of relief. In February 2021, AEP Texas received a Civil Investigative Demand from the Office of the Attorney General of Texas requesting, among other data, information about its communications to and from ERCOT, PUCT, retail electric providers, utilities, or power generation companies, concerning power outages related to the February 2021 winter storm. The company responded to the Civil Investigative Demand in March 2021. Management is unable to predict the course or outcome of these or any future litigation or investigations or their impact, if any, on future results of operations, financial condition and cash flows.

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

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

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

AEPTCo’s principal transmission service customers are its affiliates in the AEP System. Management expects that these affiliates will continue to be AEPTCo’s principal transmission service customers for the foreseeable future. For the year ended December 31, 2022, its affiliates were responsible for approximately 79% of the consolidated transmission revenues of AEPTCo.

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

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

Compliance with legislative and regulatory requirements may lead to increased costs and result in penalties. (Applies to all Registrants)

Business activities of electric utilities and related companies are heavily regulated, primarily through national and state laws and regulations of general applicability, including laws and regulations related to working conditions, health and safety, equal employment opportunity, employee benefit and other labor and employment matters, laws and regulations related to competition and antitrust matters. Many agencies employ mandatory civil penalty structures for regulatory violations. Registrants are subject to the jurisdiction of many federal and state agencies, including the FERC, NERC, Commodities Futures Trading Commission, Federal EPA, NRC, Occupational Safety and Health Administration, the SEC and the United States Department of Justice which may impose significant civil and criminal penalties to enforce compliance requirements relative to AEP’s business, which could have a material adverse effect on financial operating results including earnings, cash flow and liquidity.

The impact of new laws, regulations and policies and the related interpretations, as well as changes in enforcement practices or regulatory scrutiny generally cannot be predicted, and changes in applicable laws, regulations and policies and the related interpretations and enforcement practices may require extensive system and operational changes, be difficult to implement, increase AEP’s operating costs, require significant capital expenditures, or adversely impact the cost or attractiveness of the products or services AEP offers, or result in adverse publicity and harm AEP’s reputation.

RISKS RELATED TO OWNING AND OPERATING GENERATION ASSETS AND SELLING POWER

Costs of compliance with existing and evolving environmental laws are significant. (Applies to all Registrants except AEPTCo)

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

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

Federal or state laws or regulations may be adopted that would impose new or additional limits on the emissions of greenhouse gases, including, but not limited to, carbon dioxide and methane, from electric generation units using fossil fuels like coal. The potential effects of greenhouse gas emission limits on AEP's electric generation units are subject to significant uncertainties based on, among other things, the timing of the implementation of any new requirements, the required levels of emission reductions, the nature of any market-based or tax-based mechanisms adopted to facilitate reductions, the relative availability of greenhouse gas emission reduction offsets, the development of cost-effective, commercial-scale carbon capture and storage technology and supporting regulations and liability mitigation measures, and the range of available compliance alternatives.

AEP’s results of operations could be materially adversely affected to the extent that new federal or state laws or regulations impose any new greenhouse gas emission limits. Any future limits on greenhouse gas emissions could create substantial additional costs in the form of taxes or emissions allowances, require significant capital investment in carbon capture and storage technology, fuel switching, or the replacement of high-emitting generation facilities with lower-emitting generation facilities and/or could cause AEP to retire generating capacity prior to the end of its estimated useful life. Although AEP typically recovers environmental expenditures, there can be no assurance in the future that AEP can recover such costs which could reduce future net income and cash flows and possibly harm financial condition.

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

In the past, there have been several cases seeking damages based on allegations of federal and state common law nuisance in which AEP, among others, were defendants. In general, the actions allege that emissions from the defendants’ power plants constitute a public nuisance. The plaintiffs in these actions generally seek recovery of damages and other relief. If future actions are resolved against AEP, substantial modifications or retirement of AEP’s existing coal-fired power plants could be required, and AEP might be required to purchase power from third-parties to fulfill AEP’s commitments to supply power to AEP customers. This could have a material impact on revenues. In addition, AEP could be required to invest significantly in additional emission control equipment, accelerate the timing of capital expenditures, pay damages or penalties and/or halt operations. Unless recovered, those costs could reduce future net income and cash flows and harm financial condition. Moreover, results of operations and financial position could be reduced due to the timing of recovery of these investments and the expense of ongoing litigation.

Commodity trading and marketing activities are subject to inherent risks which can be reduced and controlled but not eliminated. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

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

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

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

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

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

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

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

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

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

AEP and several nonaffiliated utility companies own OVEC. The Inter-Company Power Agreement (ICPA) defines the rights and obligations and sets the power participation ratio of the parties to it. Under the ICPA, parties are entitled to receive and are obligated to pay for all OVEC capacity (approximately 2,400 MWs) in proportion to their respective power participation ratios. The aggregate power participation ratio of APCo, I&M and OPCo is 43.47%. If a party fails to make payments owed by it under the ICPA, OVEC may not have sufficient funds to honor its payment obligations, including its ongoing operating expenses as well as its indebtedness. As of December 31, 2022, OVEC has outstanding indebtedness of approximately $1.1 billion, of which APCo, I&M, and OPCo are collectively responsible for $478 million through the ICPA. Although they are not an obligor or guarantor, APCo, I&M, and OPCo are responsible for their respective ratio of OVEC’s outstanding debt through the ICPA and if OVEC’s indebtedness is accelerated for any reason, there is risk that APCo, I&M and/or OPCo may be required to pay some or all of such accelerated indebtedness in amounts equal to their aggregate power participation ratio of 43.47%.

New climate disclosure rules proposed by the U.S. Securities and Exchange Commission may increase our costs of compliance and adversely impact our business. (Applies to all Registrants)

On March 21, 2022, the SEC proposed new rules relating to the disclosure of a range of climate-related risks. AEP is currently assessing the proposed rule, but at this time AEP cannot predict the costs of implementation or any potential adverse impacts resulting from the rule. To the extent this rule is finalized as proposed, AEP could incur increased costs relating to the assessment and disclosure of climate-related risks. AEP may also face increased litigation risks related to disclosures made pursuant to the rule if finalized as proposed. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon-intensive sectors.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

GENERATION FACILITIES

As of December 31, 2022, the AEP System owned (or leased where indicated) generation plants, with locations and net maximum power capabilities (winter rating), are shown in the following tables:

Vertically Integrated Utilities Segment

AEGCo

Plant Name

Units

State

Fuel Type

Net Maximum
Capacity (MWs)

Year Plant
or First Unit Commissioned

Rockport, Units 1 and 2 – 50% of each (a)

Steam - Coal

1,310

1984

(a)Rockport Plant, Unit 2 was subject to a finance lease with a nonaffiliated company. In December 2022, the lease expired at which point I&M and AEGCo acquired 100% of the interests in Unit 2. See the “Rockport Plant Litigation” section of Note 6 included in the 2022 Annual Report for additional information.


APCo
Plant Name	Units	State	Fuel Type	Net Maximum Capacity (MWs)	Year Plant or First Unit Commissioned
Buck	3	VA	Hydro	11	1912
Byllesby	4	VA	Hydro	19	1912
Claytor	4	VA	Hydro	76	1939
Leesville	2	VA	Hydro	50	1964
London	3	WV	Hydro	14	1935
Marmet	3	WV	Hydro	14	1935
Niagara	2	VA	Hydro	1	1906
Winfield	3	WV	Hydro	15	1938
Ceredo	6	WV	Natural Gas	516	2001
Dresden	3	OH	Natural Gas	665	2012
Smith Mountain	5	VA	Pumped Storage	585	1965
Amos	3	WV	Steam - Coal	2,930	1971
Mountaineer	1	WV	Steam - Coal	1,320	1980
Clinch River	2	VA	Steam - Natural Gas	465	1958
Total MWs				6,681


I&M
Plant Name	Units	State	Fuel Type	Net Maximum Capacity (MWs)	Year Plant or First Unit Commissioned
Berrien Springs	12	MI	Hydro	7	1908
Buchanan	10	MI	Hydro	3	1919
Constantine	4	MI	Hydro	1	1921
Elkhart	3	IN	Hydro	3	1913
Mottville	4	MI	Hydro	2	1923
Twin Branch Hydro	8	IN	Hydro	4	1904
Deer Creek Solar Farm	NA	IN	Solar	3	2016
Olive Solar Farm	NA	IN	Solar	5	2016
St. Joseph	NA	IN	Solar	20	2021
Twin Branch Solar Farm	NA	IN	Solar	3	2016
Watervliet	NA	MI	Solar	5	2016
Rockport (Units 1 and 2, 50% of each) (a)	2	IN	Steam - Coal	1,310	1984
Cook	2	MI	Steam - Nuclear	2,296	1975
Total MWs				3,662

NA Not applicable.

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


	Cook Plant
	Unit 1		Unit 2
Year Placed in Operation	1975		1978
Year of Expiration of NRC License	2034		2037
Nominal Net Electrical Rating in MWs	1,084		1,212
Annual Capacity Utilization
2022	79.4	%	86.6	%
2021	96.0	%	84.2	%
2020	87.2	%	94.2	%

KPCo

Plant Name

Units

State

Fuel Type

Net Maximum
Capacity (MWs)

Year Plant
or First Unit Commissioned

Mitchell (a)(b)

Steam - Coal

780

1971

Big Sandy

Steam - Natural Gas

295

1963

Total MWs

1,075

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

(b)In September 2022, pursuant to resolutions under the existing Mitchell Plant agreement, WPCo replaced KPCo as the operator of Mitchell Plant. See the “Disposition of KPCo and KTCo” section of Note 7 included in the 2022 Annual Report for additional information.


PSO
Plant Name	Units	State	Fuel Type	Net Maximum Capacity (MWs)	Year Plant or First Unit Commissioned
Comanche	3	OK	Natural Gas	248	1973
Northeastern, Unit 1	1	OK	Natural Gas	470	1961
Riverside, Units 3 and 4	2	OK	Natural Gas	160	2008
Southwestern, Units 4 and 5	2	OK	Natural Gas	168	2008
Weleetka	2	OK	Natural Gas	100	1975
Northeastern, Unit 3	1	OK	Steam - Coal	465	1979
Northeastern, Unit 2	1	OK	Steam - Natural Gas	434	1961
Riverside, Units 1 and 2	2	OK	Steam - Natural Gas	896	1974
Southwestern, Units 1, 2 and 3	3	OK	Steam - Natural Gas	446	1952
Tulsa	2	OK	Steam - Natural Gas	318	1956
Maverick (a)	NA	OK	Wind	131	2021
Sundance (a)	NA	OK	Wind	90	2021
Traverse (a)	NA	OK	Wind	454	2022
Total MWs				4,380

(a)SWEPCo owns a 54.5% interest and PSO owns the remaining 45.5% interest in Sundance, Maverick and Traverse.

NA Not applicable.


SWEPCo
Plant Name	Units	State	Fuel Type	Net Maximum Capacity (MWs)	Year Plant or First Unit Commissioned
Mattison	4	AR	Natural Gas	314	2007
Stall	3	LA	Natural Gas	534	2010
Flint Creek (a)	1	AR	Steam - Coal	258	1978
Turk (a)	1	AR	Steam - Coal	477	2012
Welsh (b)	2	TX	Steam - Coal	1,053	1977
Pirkey (a)(c)	1	TX	Steam - Lignite	580	1985
Arsenal Hill	1	LA	Steam - Natural Gas	110	1960
Knox Lee	1	TX	Steam - Natural Gas	344	1950
Lieberman	3	LA	Steam - Natural Gas	217	1947
Wilkes	3	TX	Steam - Natural Gas	889	1964
Maverick (d)	NA	OK	Wind	156	2021
Sundance (d)	NA	OK	Wind	109	2021
Traverse (d)	NA	OK	Wind	544	2022
Total MWs				5,585

(a)Jointly-owned with nonaffiliated entities. Figures presented reflect only the portion owned by SWEPCo. The Arkansas jurisdictional portion of SWEPCo’s interest in Turk Plant is not in rate base.

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

(c)In November 2020, management announced plans to retire the plant in 2023.

(d)SWEPCo owns a 54.5% interest and PSO owns the remaining 45.5% interest in Sundance, Maverick and Traverse.

NA Not applicable.

WPCo

Plant Name

Units

State

Fuel Type

Net Maximum
Capacity (MWs)

Year Plant
or First Unit Commissioned

Mitchell (a)(b)

Steam - Coal

780

1971

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

Generation & Marketing Segment

Renewable Power

Size of Energy Resource

AEP Energy Supply, LLC Division

Renewable
Energy Resource

Location

In-Service or
Under Construction

1,200 MW

AEP Renewables

Wind

Eight states (a)

In-service

20 MW

AEP Renewables

Solar

California

In-service

20 MW

AEP Renewables

Solar

Utah

In-service

125 MW

AEP Renewables

Solar

Nevada

In-service

168 MW

AEP OnSite Partners

Solar

Seventeen states (b)

In-service

26 MW

AEP OnSite Partners

Solar

Two states (c)

Under Construction

(a) Colorado, Hawaii, Indiana, Kansas, Michigan, Minnesota, Pennsylvania and Texas.

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

TRANSMISSION AND DISTRIBUTION FACILITIES

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

Vertically Integrated Utilities Segment


						Total Overhead Circuit Miles of Transmission and Distribution Lines
APCo						51,620
I&M						20,852
KGPCo						1,406
KPCo						11,182
PSO						18,177
SWEPCo						26,174
WPCo						1,736
Total Circuit Miles						131,147

Transmission and Distribution Utilities Segment


						Total Overhead Circuit Miles of Transmission and Distribution Lines
OPCo						44,576
AEP Texas						46,492
Total Circuit Miles						91,068

AEP Transmission Holdco Segment

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


						Total Overhead Circuit Miles of Transmission Lines
ETT						1,884
IMTCo						1,115
OHTCo						1,215
OKTCo						1,061
WVTCo						344
Pioneer						43
Prairie Wind Transmission						216
Transource Missouri						167
Transource West Virginia						27
Total Circuit Miles						6,072

TITLE TO PROPERTY

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

SYSTEM TRANSMISSION LINES AND FACILITY SITING

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

CONSTRUCTION PROGRAM

With input from its state utility commissions, the AEP System continuously assesses the adequacy of its transmission, distribution, generation and other facilities to plan and provide for the reliable supply of electric power and energy to its customers. In this assessment process, assumptions are continually being reviewed as new information becomes available and assessments and plans are modified, as appropriate. AEP forecasts approximately $6.8 billion of construction expenditures for 2023. Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, supply chain issues, weather, legal reviews and the ability to access capital. See the “Budgeted Capital Expenditures” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2022 Annual Report for additional information.

POTENTIAL UNINSURED LOSSES

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including liabilities relating to damage to AEP’s generation plants and costs of replacement power. Unless allowed to be recovered through rates, future losses or liabilities which are not completely insured could reduce net income and impact the financial conditions of AEP and other AEP System companies. For risks related to owning a nuclear generating unit, see the “Nuclear Contingencies” section of Note 6 - Commitments, Guarantees and Contingencies included in the 2022 Annual Report for additional information.

ITEM 3. LEGAL PROCEEDINGS

For a discussion of material legal proceedings, see Note 6 - Commitments, Guarantees and Contingencies included in the 2022 Annual Report for additional information.

ITEM 4. MINE SAFETY DISCLOSURE

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

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act. Exhibit 95 “Mine Safety Disclosure Exhibit” contains the notices of violation and proposed assessments received by DHLC under the Mine Act for the quarter ended December 31, 2022.

PART II

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

AEP

In addition to the AEP Common Stock Information section below, the remaining information required by this item is incorporated herein by reference to the material under the “Dividend Policy and Restrictions” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2022 Annual Report.

During the quarter ended December 31, 2022, neither AEP nor its publicly-traded subsidiaries purchased equity securities that are registered by AEP or its publicly-traded subsidiaries pursuant to Section 12 of the Exchange Act.

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

The common stock of these companies is held solely by AEP. For more information see the “Dividend Restrictions” section of Note 14 - Financing Activities included in the 2022 Annual Report.

AEPTCo

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

AEP COMMON STOCK INFORMATION

AEP common stock is principally traded using the trading symbol “AEP” on the NASDAQ Stock Market. As of December 31, 2022, AEP had 51,279 registered shareholders. The performance graph below compares the cumulative total return among AEP, the S&P 500 Index and the S&P Electric Utilities (SP833) Index over a five year period. The performance graph assumes an initial investment of $100 on December 31, 2017 and that all dividends were reinvested.

Source: S&P Dow Jones Indices LLC. Data as of December 31, 2022. Past performance is no guarantee of future results. Chart provided for illustrative purposes.

ITEM 6. RESERVED

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

AEP

The information required by this item is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2022 Annual Report. Year-to-year comparisons between 2021 and 2020 have been omitted from this Form 10-K but may be found in "Management's Discussion and Analysis of Financial Condition" in Part II, Item 7 of our Form 10-K for the fiscal year ended December 31, 2021, which specific discussion is incorporated herein by reference.

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

Omitted pursuant to Instruction I(2)(a). Management’s narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2022 Annual Report.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

The information required by this item is incorporated herein by reference to the material under the “Quantitative and Qualitative Disclosures About Market Risk” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2022 Annual Report.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

2022 Annual Reports

American Electric Power Company, Inc. and Subsidiary Companies

AEP Texas Inc. and Subsidiaries

AEP Transmission Company, LLC and Subsidiaries

Appalachian Power Company and Subsidiaries

Indiana Michigan Power Company and Subsidiaries

Ohio Power Company and Subsidiaries

Public Service Company of Oklahoma

Southwestern Electric Power Company Consolidated

Audited Financial Statements and

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

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

INDEX OF ANNUAL REPORTS


		Page Number
American Electric Power Company, Inc. and Subsidiary Companies:

	Management’s Discussion and Analysis of Financial Condition and Results of Operations	58
	Report of Independent Registered Public Accounting Firm (PCAOB ID 238)	127
	Management’s Report on Internal Control Over Financial Reporting	131
	Consolidated Financial Statements	132

AEP Texas Inc. and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	139
	Report of Independent Registered Public Accounting Firm (PCAOB ID 238)	142
	Management’s Report on Internal Control Over Financial Reporting	144
	Consolidated Financial Statements	145

AEP Transmission Company, LLC and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	152
	Report of Independent Registered Public Accounting Firm (PCAOB ID 238)	154
	Management’s Report on Internal Control Over Financial Reporting	157
	Consolidated Financial Statements	158

Appalachian Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	164
	Report of Independent Registered Public Accounting Firm (PCAOB ID 238)	167
	Management’s Report on Internal Control Over Financial Reporting	169
	Consolidated Financial Statements	170

Indiana Michigan Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	177
	Report of Independent Registered Public Accounting Firm (PCAOB ID 238)	180
	Management’s Report on Internal Control Over Financial Reporting	182
	Consolidated Financial Statements	183

Ohio Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	190
	Report of Independent Registered Public Accounting Firm (PCAOB ID 238)	193
	Management’s Report on Internal Control Over Financial Reporting	196
	Consolidated Financial Statements	197

Public Service Company of Oklahoma:
	Management’s Narrative Discussion and Analysis of Results of Operations	203
	Report of Independent Registered Public Accounting Firm (PCAOB ID 238)	206
	Management’s Report on Internal Control Over Financial Reporting	208
	Financial Statements	209

Southwestern Electric Power Company Consolidated:
	Management’s Narrative Discussion and Analysis of Results of Operations	216
	Report of Independent Registered Public Accounting Firm (PCAOB ID 238)	219
	Management’s Report on Internal Control Over Financial Reporting	221
	Consolidated Financial Statements	222

Index of Notes to Financial Statements of Registrants		228

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

RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Company Overview

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

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

•Approximately 225,000 circuit miles of distribution lines that deliver electricity to 5.6 million customers.

•Approximately 40,000 circuit miles of transmission lines, including approximately 2,200 circuit miles of 765 kV lines, the backbone of the electric interconnection grid in the eastern United States.

•Approximately 23,500 MWs of regulated owned generating capacity as of December 31, 2022, one of the largest complements of generation in the United States.

Customer Demand

AEP’s weather-normalized retail sales volumes for the year ended December 31, 2022 increased by 2.8% from the year ended December 31, 2021. Weather-normalized residential sales increased 0.1% for the year ended December 31, 2022 compared to the year ended December 31, 2021. Weather-normalized commercial sales increased by 4.2% in 2022 compared to 2021. The increase in commercial sales was spread across many sectors. AEP’s 2022 industrial sales volumes increased 4.5% compared to 2021. The growth in industrial sales was spread across many industries.

In 2023, AEP anticipates weather-normalized retail sales volumes will increase by 0.7%. Weather-normalized residential sales volumes are projected to decrease by 0.5% in 2023, while weather-normalized commercial sales volumes are projected to increase by 0.6%. Finally, AEP projects the industrial class to increase by 2.1% in 2023.

(a)Percentage change for the year ended December 31, 2022 as compared to the year ended December 31, 2021.

(b)Forecasted percentage change for the year ended December 31, 2023 compared to the year ended December 31, 2022.

Supply Chain Disruption and Inflation

The Registrants have experienced certain supply chain disruptions driven by several factors including staffing and travel issues caused by the COVID-19 pandemic, international tensions including the ramifications of regional conflict, increased demand due to the economic recovery from the pandemic, inflation, 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 and have contributed to higher prices for fuel, materials, labor, equipment and other needed commodities. Management has implemented risk mitigation strategies in an attempt to mitigate the impacts of these supply chain disruptions.

The United States economy has experienced a significant level of inflation that has contributed to increased uncertainty in the outlook of near-term economic activity, including whether inflation will continue and at what rate. A prolonged continuation or a further increase in the severity of supply chain and inflationary disruptions could result in additional increases in the cost of certain goods, services and cost of capital and further extend lead times which could reduce future net income and cash flows and impact financial condition.

Strategic Evaluation of AEP Energy

AEP has initiated a strategic evaluation for its ownership in AEP Energy, a wholly-owned retail energy supplier that supplies electricity and/or natural gas to residential, commercial and industrial customers. AEP Energy provides various energy solutions in Illinois, Pennsylvania, Delaware, Maryland, New Jersey, Ohio and Washington, D.C. AEP Energy had approximately 736,000 customer accounts as of December 31, 2022. Potential alternatives may include, but are not limited to, continued ownership or a sale of all or a part of AEP Energy. Management has not made a decision regarding the potential alternatives, but expects to complete the strategic evaluation in the first half of 2023.

Regulatory Matters

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

•2017-2019 Virginia Triennial Review - In 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 statutory 140 basis point band (8.5% bottom, 9.2% midpoint, 9.9% top). APCo appealed this order and a similar order on reconsideration to the Virginia Supreme Court in March 2021, alleging the Virginia SCC erred in finding that costs associated with asset impairments related to APCo early retirement determinations for certain generation facilities should not be attributed to the 2017-2019 test periods under review and deemed fully recovered in the period recorded. In August 2022, the Virginia Supreme Court agreed with this portion of APCo’s appeal and remanded this issue regarding the retired coal-fired plants back to the Virginia SCC for further proceedings. In September 2022, as a result of the Virginia Supreme Court ruling, APCo expensed the remaining $25 million closed coal plant regulatory asset that was previously ordered by the Virginia SCC and recorded a $37 million regulatory asset for previously incurred costs that APCo is expecting to recover as a result of earning below its 2017-2019 authorized ROE band.

October 2022 and (c) approved a rider to recover approximately $48 million related to this APCo Virginia base rate increase for the period January 2021 through September 2022. APCo’s 2022 financial statements reflect the impact of the Virginia SCC’s December 2022 order.

•2020-2022 Virginia Triennial Review - In March 2023, APCo will submit its required Virginia earnings test calculation to the Virginia SCC for the 2020-2022 Triennial Review period. For Triennial Review periods in which a Virginia utility earns below its authorized ROE band, the utility may file to recover expenses incurred, up to the bottom of the authorized ROE band, related to major storms, the early retirement of fossil fuel generating assets and certain projects necessary to comply with state and federal environmental legislation. As of December 2022, APCo has deferred approximately $38 million related to previously incurred costs as a result of the current estimate that APCo will earn below the bottom of its authorized ROE band during the 2020-2022 Triennial Review period.

APCo is also required to submit a depreciation study as part of its 2020-2022 Triennial Review filing based on plant in service balances as of December 31, 2022. APCo is required to implement the impacts of this depreciation study effective January 1, 2023 without a corresponding adjustment in customer rates until the first quarter of 2024. While subject to review as part of APCo’s 2020-2022 Virginia Triennial Review, a significant change in depreciation rates (either an increase or a decrease) without a corresponding adjustment in Virginia retail rates would impact future net income and cash flows and impact financial condition.

•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. 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 judgment 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. SWEPCo and the PUCT submitted Petitions for Review with the Texas Supreme Court in November 2021. In October 2022, the Texas Supreme Court denied the Petitions for Review submitted by SWEPCo and the PUCT. In December 2022, SWEPCo and the PUCT filed requests for rehearing with the Texas Supreme Court. The Texas Supreme Court requested comments on rehearing by March 1, 2023. If SWEPCo’s request for rehearing is denied, the case will be remanded to the PUCT for future proceedings.

Management does not believe a disallowance of capitalized Turk Plant costs or a revenue refund is probable as of December 31, 2022. However, if SWEPCo is ultimately unable to recover AFUDC in excess of the Texas jurisdictional capital cost cap, it would be expected to result in a pretax net disallowance ranging from $80 million to $90 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 $185 million related to revenues collected from February 2013 through December 2022 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 terminated energy efficiency programs as of December 31, 2020, including OPCo’s shared savings revenues of $26 million annually and phased out renewable mandates after 2026. HB 6 also provided for continued recovery of existing renewable energy contracts on a bypassable basis through 2032 and included a provision for continued recovery of OVEC costs through 2030 which is allocated to all electric distribution utility customers in Ohio 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 and a criminal trial is proceeding against the other. In 2021, four AEP shareholders filed derivative actions purporting to assert claims on behalf of AEP against certain AEP officers and directors. 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, repealed 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 in May 2021 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 the law changes or 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 derivative actions, it could reduce future net income and cash flows and impact financial condition.

•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. AEP is awaiting a final rule from the FERC.

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

If the FERC modifies its RTO Incentive policy, it would be applied, as applicable, to AEP’s PJM, SPP and MISO transmission owning subsidiaries on a prospective basis, and could affect future net income and cash flows and impact financial condition. Based on management’s preliminary estimates, if a final rule is adopted consistent with the April 2021 supplemental NOPR, it could reduce AEP’s pretax income by approximately $35 million to $50 million on an annual basis.

•FERC RTO Incentive Complaint - In February 2022, the Office of the Ohio Consumers’ Counsel (OCC) filed a complaint against AEPSC, American Transmission Systems, Inc. and Duke Energy Ohio, alleging the 50-basis point RTO incentive included in Ohio Transmission Owners’ respective transmission formula rates is not just and reasonable and therefore should be eliminated on the basis that RTO participation is not voluntary, but rather is required by Ohio law. In March 2022, AEPSC filed a motion to dismiss the OCC’s February 2022 complaint with the FERC on the basis of certain deficiencies, including that the complaint fails to request relief that can be granted under FERC regulations because AEPSC is not a public utility nor does it have a transmission rate on file with the FERC. In December 2022, the FERC issued an order removing the 0.5 basis point RTO incentive from OPCo and OHTCo transmission formula rates effective the date of the February 2022 complaint filing and directed OPCo and OHTCo to provide refunds, with interest, within sixty days of the date of its order. In January 2023, both AEPSC and the OCC filed requests for rehearing with the FERC. A FERC order on rehearing is expected in 2023. Based on management’s preliminary estimates, the December 2022 FERC order is expected to reduce AEP’s pretax income by approximately $20 million on an annual basis.

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. This precedent could have an adverse impact on AEP’s Ohio transmission owning subsidiaries. In its February 2022 order on rehearing, the FERC affirmed the decision in its July 2021 order. The case is currently pending appeal at the U.S. Court of Appeals for the Sixth Circuit. In May 2022, the U.S. Court of Appeals for the Sixth Circuit issued an order to hold the appeal in abeyance pending resolution of FERC proceedings on the Office of the Ohio Consumers’ Counsels’ February 2022 RTO Incentive Complaint.

•2021 Louisiana Storm Cost Filing - In 2020, Hurricanes Laura and Delta caused power outages and extensive damage to the SWEPCo service territories, primarily impacting the Louisiana jurisdiction. Following both hurricanes, the LPSC issued orders allowing Louisiana utilities, including SWEPCo, to establish regulatory assets to track and defer expenses associated with these storms. In February 2021, severe winter weather impacted the Louisiana jurisdiction and in March 2021, the LPSC approved the deferral of incremental storm restoration expenses related to the winter storm. In October 2021, SWEPCo filed a request with the LPSC for recovery of $145 million in deferred storm costs associated with the three storms. As part of the filing, SWEPCo requested recovery of the carrying charges on the deferred regulatory asset at a weighted average cost of capital through a rider beginning in January 2022. In May 2022, LPSC staff testimony was submitted to the LPSC. In July 2022, SWEPCo filed rebuttal testimony which agreed to make a request for securitization as the LPSC staff had recommended in their testimony. An order is expected in the first quarter of 2023. If any of the storm costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

•In February 2021, severe winter weather had a significant impact in SPP, resulting in the declaration of Energy Emergency Alert Levels 2 and 3 for the first time in SPP’s history. The winter storm increased the demand for natural gas and restricted the available natural gas supply resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system. As a result of the severe winter weather, PSO and SWEPCo incurred approximately $1.1 billion of extraordinary fuel costs and purchases of electricity, which were deferred as regulatory assets.

In April 2021, the OCC approved a waiver for PSO allowing the deferral of the extraordinary fuel and purchases of electricity as regulatory assets, 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 permitting securitized financing of qualified costs from extreme weather events. This legislation provides certain authority to the OCC to approve amounts to be recovered from the issuance of ratepayer-backed securitized bonds issued by the ODFA, an Oklahoma governmental agency. In January 2022, PSO, OCC staff and certain intervenors filed a joint stipulation and settlement agreement with the OCC to approve the securitization of PSO’s extraordinary fuel costs and purchases of electricity. In February 2022, the OCC approved the joint stipulation and settlement agreement which included a determination that all of PSO’s extraordinary fuel costs and purchases of electricity were prudent and reasonable and also provided a 0.75% carrying charge related to those costs, subject to true-up based on actual financing costs.

In September 2022, PSO received proceeds of $687 million from the ODFA which issued ratepayer-backed securitization bonds for the purpose of reimbursing PSO for extraordinary fuel costs and purchases of electricity incurred during the February 2021 severe winter weather event, which were previously recorded as Regulatory Assets on PSO’s balance sheet. The securitization bonds are the obligation of the ODFA and there is no recourse against PSO in the event of a bond default, and therefore are not recorded as Long-term Debt on PSO’s balance sheet. PSO will serve as the servicing agent of the bonds and is responsible for the routine billing and collection of the securitization charges and remitting those collections back to the ODFA. The securitization charges billed to and collected from customers are not included as revenue on PSO’s statement of income. The collections from customers will occur over 20 years.

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. Subsequently, SWEPCo began recovery of these fuel costs. In April 2021, SWEPCo filed testimony supporting a five-year recovery with a carrying charge of 6.05%. In June 2022, the APSC ordered SWEPCo to recover the Arkansas jurisdictional share of the fuel costs over six years with a carrying charge equal to its weighted average cost of capital, subject to a prudency review and true-up.

In March 2021, the LPSC approved a special order granting a temporary modification to the FAC and shortly after SWEPCo began recovery of its Louisiana jurisdictional share of these fuel costs based on a five-year recovery period inclusive of 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 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 requested a five-year recovery with a carrying charge of 7.18%. In March 2022, the PUCT ordered SWEPCo to recover the Texas jurisdictional share of the fuel costs over five years with a carrying charge of 1.65% and ordered SWEPCo to file a fuel reconciliation addressing fuel costs from January 1, 2020 through December 31, 2021.

If SWEPCo is unable to recover any of the costs relating to the extraordinary fuel and purchases of electricity, or obtain authorization of a reasonable carrying charge on these costs, it could reduce future net income and cash flows and impact financial condition.

•AEP transitioned to stand-alone treatment of NOLC in its PJM and SPP transmission formula rates beginning with 2022 projected transmission revenue requirements and 2021 true-up to actual transmission revenue requirements, and provided notice of this change in informational filings made with the FERC. Stand-alone treatment of the NOLCs for transmission formula rates increased the 2021 and 2022 annual revenue requirements by $78 million and $60 million, respectively. Through year-end 2022, the Registrants’ financial statements reflect a provision for refund for certain NOLC revenues billed by PJM and SPP. Also, a certain portion of the impact of inclusion of the NOLC in the 2021 annual formula rate true-up not yet billed by PJM and SPP is not reflected in the Registrants’ revenues and expenses as the Registrants have not met the requirements of alternative revenue recognition in accordance with the accounting guidance for “Regulated Operations”.

AEP is also transitioning to stand-alone treatment of NOLC in retail jurisdiction base rate case filings. As a result of retail jurisdiction base rate cases in Arkansas, Indiana, Oklahoma and Texas, inclusion of NOLCs in rates in those jurisdictions is contingent upon a supportive private letter ruling from the IRS. If the Registrant Subsidiaries are successful in transitioning to stand-alone treatment of NOLC, it could have a material, favorable impact on future net income.

•SPP Capacity Planning Reserve Margin - In July 2022, SPP approved a plan to increase its capacity planning reserve margin from 12% to 15% starting in the summer of 2023. Compliance filings were made with SPP in February 2023 and any deficiencies are required to be remedied by May 2023. SPP’s annual

non-compliance charge as a result of not meeting capacity requirements could range from approximately $86 thousand per MW to approximately $171 thousand per MW under the current SPP tariff. Non-compliance could also result in a failure to meet NERC criteria. As of December 31, 2022, the increase in the capacity planning reserve margin for PSO and SWEPCo to comply with this new SPP requirement was approximately 265 MWs.

Management has been taking actions and expects to comply with SPP’s 2023 capacity planning reserve margin requirement. If PSO or SWEPCo incur charges or are unable to recover, or experience delays in recovering, the costs of complying with SPP’s rule, it could reduce future net income and cash flows and impact financial condition.

Utility Rates and Rate Proceedings

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

The following tables show the Registrants’ completed and pending base rate case proceedings in 2022. 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)

SWEPCo

Texas

39.4

9.25%

March 2021

I&M

Indiana

61.4

(a)

9.7%

February 2022

SWEPCo

Arkansas

48.7

9.5%

July 2022

KGPCo

Tennessee

5.8

9.5%

August 2022

SWEPCo

Louisiana

21.0

9.5%

February 2023

(a)See “2021 Indiana Base Rate Case” section of Note 4 - Rate Matters in the 2021 Annual Report for additional information.

Pending Base Rate Case Proceedings

Requested Revenue

Commission Staff/

Filing

Requirement

Requested

Intervenor Range of

Company

Jurisdiction

Date

Increase

ROE

Recommended ROE

(in millions)

PSO

Oklahoma

November 2022

173.0

10.4%

(a)

(a)Intervenor testimony is expected to be filed in the first quarter of 2023.

Deferred Fuel Costs

Increased fuel and purchased power prices in excess of amounts included in fuel-related revenues has led to an increase in the under collection of fuel costs from customers in most jurisdictions. The table below illustrates the increase (decrease) in the deferred fuel regulatory assets by company and jurisdiction, excluding the impacts of the February 2021 severe winter weather event. See the “February 2021 Severe Winter Weather Impacts in SPP” sections in Note 4 for additional information.


		Traditional FAC	As of		As of		Increase/
Company	Jurisdiction	Recovery Reset	December 31, 2022		December 31, 2021		(Decrease)
APCo	Virginia (a)	Annually	$	407.9	$	128.6	$	279.3
APCo	West Virginia	Annually	288.5		72.7		215.8
I&M	Indiana	Bi-Annually	38.1		—		38.1
I&M	Michigan	Annually	9.0		6.4		2.6
PSO	Oklahoma (b)	Annually	431.5		194.6		236.9
SWEPCo	Arkansas	Annually	65.8		23.1		42.7
SWEPCo	Louisiana	Monthly	—		11.1		(11.1)
SWEPCo	Texas	Tri-Annually	191.4		47.0		144.4
KPCo	Kentucky	Monthly	23.2		8.2		15.0
WPCo	West Virginia	Annually	231.1		101.6		129.5
		Total (c)	$	1,686.5	$	593.3	$	1,093.2

(a)Includes $223 million of noncurrent deferred fuel classified as a Regulatory Asset on APCo’s balance sheets as of December 31, 2022.

(b)Includes $253 million of noncurrent deferred fuel classified as a Regulatory Asset on PSO’s balance sheets as of December 31, 2022.

(c)Includes $23 million and $8 million as of December 31, 2022 and December 31, 2021, respectively, of deferred fuel classified as Assets Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.

The AEP utility subsidiaries are working with various state commissions on the timing of recovering deferred fuel balances and have made the following recent filings:

In April 2022, APCo and WPCo submitted their 2022 annual ENEC filing with the WVPSC requesting a $297 million annual increase in ENEC revenues, effective September 1, 2022. In February 2023, the WVPSC issued an order stating that the commission will not grant additional rate increases for fuel costs until the WVPSC staff completes its prudency review. See “2021 and 2022 ENEC Filings” section of Note 4 for additional information.

In August 2022, PSO requested an interim update to its annual Fuel Cost Adjustment (FCA) rates in accordance with the terms of the established tariff which allows PSO or the OCC staff to request an interim FCA adjustment in the event that the annual FCA over/under-recovered balance is $50 million or more on a cumulative basis. In September 2022, the Director of the Public Utility Division of the OCC approved a FCA rate designed to collect a $402 million deferred fuel balance over a 27-month period, effective with the first billing cycle of October 2022. PSO’s fuel and purchased power expenses are subject to an annual prudency review by the OCC.

In September 2022, APCo submitted a request to the Virginia SCC to increase its annual fuel factor by approximately $279 million. APCo implemented interim FAC rates effective November 2022 subject to Virginia SCC review. To help mitigate the impact of rising fuel costs on customer bills, APCo proposed to recover its deferred fuel balance as of October 31, 2022 over two years. An order from the Virginia SCC is expected in the first quarter of 2023.

In September 2022, SWEPCo filed a request with the APSC for an interim increase to its current Energy Cost Rate (ECR) to recover $44 million of additional fuel costs incurred from April 2022 through August 2022, subsequent to the last annual ECR rate change. The interim rate was effective with the first billing cycle of October 2022 and will be in effect for six months until the ECR is reset in April 2023.

In October 2022, SWEPCo filed a request with the PUCT for an interim fuel surcharge to recover $83 million of additional fuel costs incurred through August 2022. An interim rate is effective February 2023, subject to final approval by the PUCT.

Dolet Hills Power Station and Related Fuel Operations

In 2020, management of SWEPCo and CLECO determined DHLC would not develop additional Oxbow Lignite Company (Oxbow) mining areas for future lignite extraction and ceased extraction of lignite at the mine in May 2020. In April 2020, SWEPCo and CLECO jointly filed a notification letter to the LPSC providing notice of the cessation of lignite mining. In December 2021, the Dolet Hills Power Station was retired. While in operation, DHLC provided 100% of the fuel supply to Dolet Hills Power Station.

The remaining book value of Dolet Hills Power Station non-fuel related assets are recoverable by SWEPCo through rate riders. As of December 31, 2022, SWEPCo’s share of the net investment in the Dolet Hills Power Station is $112 million, including materials and supplies, net of cost of removal collected in rates.

Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses and are subject to prudency determinations by the various commissions. After closure of the DHLC mining operations and the Dolet Hills Power Station, additional reclamation and other land-related costs incurred by DHLC and Oxbow will continue to be billed to SWEPCo and included in existing fuel clauses. As of December 31, 2022, SWEPCo had a net under-recovered fuel balance of $257 million, inclusive of costs related to Dolet Hills Power Station billed by DHLC, but excluding impacts of the February 2021 severe winter weather event.

In March 2021, the LPSC issued an order allowing SWEPCo to recover up to $20 million of fuel costs in 2021 and defer approximately $32 million of additional costs with a recovery period to be determined at a later date. In August 2022, the LPSC staff filed testimony recommending fuel disallowances of $72 million, including denial of recovery of the $32 million deferral, with refunds to customers over five years. In September 2022, SWEPCo filed rebuttal testimony addressing the LPSC staff recommendations.

In March 2021, the APSC approved fuel rates that provide recovery of $20 million for the Arkansas share of the 2021 Dolet Hills Power Station fuel costs over five years through the existing fuel clause.

In August 2022, SWEPCo filed a fuel reconciliation with the PUCT covering the fuel period of January 1, 2020 through December 31, 2021. Intervenor testimony is due in the first quarter of 2023 and a decision from the PUCT is expected in the third quarter of 2023.

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

Pirkey Plant and Related Fuel Operations

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 $43 million as of December 31, 2022. As of December 31, 2022, SWEPCo had a net under-recovered fuel balance of $257 million, inclusive of costs related to Pirkey Plant billed by Sabine, but excluding impacts of the February 2021 severe winter weather event. Upon cessation of lignite deliveries by Sabine to the Pirkey Plant, additional operational, reclamation and other land-related costs incurred by Sabine will be billed to SWEPCo and included in existing fuel clauses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Renewable Generation

Contracted Renewable Generation Facilities

In recent years, AEP has developed its renewable portfolio within the Generation & Marketing segment. Activities have included 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 developed and/or acquired large scale renewable generation projects that are backed with long-term contracts with creditworthy counterparties.

In February 2022, AEP management announced the initiation of a process to sell all or a portion of AEP Renewables’ competitive contracted renewables portfolio within the Generation & Marketing segment. Subsequently, AEP’s investment in Flat Ridge 2 Wind LLC was removed from the competitive contracted renewables sale portfolio. In June 2022, as a result of deteriorating financial performance, sale negotiations and AEP’s ongoing evaluation and ultimate decision to exit the investment in the near term, AEP determined a decline in the fair value of AEP’s investment in Flat Ridge 2 was other than temporary and recorded a pretax other than temporary impairment charge of $186 million in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP’s statements of income. In the third quarter of 2022, in accordance with the accounting guidance for “Investments - Equity Method and Joint Ventures”, AEP recorded an additional $2 million pretax other than temporary impairment charge in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP’s statements of income. AEP has recorded a $188 million other than temporary impairment in its investment in Flat Ridge 2 for the year ended December 31, 2022 in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP’s statements of income. AEP’s determination of fair value utilized the accounting guidance for Fair Value Measurement market approach to valuation and was based on negotiations to sell the investment to a nonaffiliate. In September 2022, AEP signed a Purchase and Sale Agreement with a nonaffiliate for AEP’s interest in Flat Ridge 2. The transaction closed in the fourth quarter of 2022 and had an immaterial impact on the financial statements at closing.

As of December 31, 2022, the competitive contracted renewable portfolio assets totaled 1.4 gigawatts of generation resources representing consolidated solar and wind assets, with a net book value of $1.2 billion, and a 50% interest in four joint venture wind farms, totaling $247 million, accounted for as equity method investments.

In late January 2023, AEP received final bids from interested parties. In February 2023, AEP’s Board of Directors approved management’s plan to sell the competitive contracted renewables portfolio and AEP signed an agreement to sell the competitive contracted renewables portfolio to a nonaffiliated party for $1.5 billion including the assumption of project debt. As part of the sale agreement, AEP provided the acquirer an indemnification related to certain losses, not to exceed $70 million, which could result from one of the joint venture wind farm’s inability to meet certain minimum performance requirements.

The sale is subject to FERC approval, clearance from the Committee on Foreign Investment in the United States and approval under applicable competition laws. AEP expects to close on the sale in the second quarter of 2023 and

receive cash proceeds, net of taxes, transaction fees and other customary closing adjustments, of approximately $1.2 billion.

Management concluded the consolidated assets within the competitive contracted renewables portfolio met the accounting requirements to be presented as Held for Sale in the first quarter of 2023 based on the receipt of final bids, Board of Director approval to consummate a sale transaction and the signing of the sale agreement. AEP anticipates recording an estimated pretax loss ranging from $175 million to $225 million ($100 million to $150 million after-tax), in the first quarter of 2023 as a result of reaching Held for Sale status. Management concluded the impact of any other than temporary decline in the fair value of the four joint venture wind farms was not material to AEP’s December 31, 2022 financial statements. Any changes to the book value or carrying value of these assets, or the anticipated sale price, could further reduce future net income and impact financial condition.

Regulated Renewable Generation Facilities

North Central Wind Facilities

In 2020, PSO and SWEPCo received regulatory approvals to acquire the NCWF, comprised of three Oklahoma wind facilities totaling 1,484 MWs. PSO and SWEPCo own undivided interests of 45.5% and 54.5% of the NCWF, respectively. Output from the NCWF serves 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. The Arkansas portion of the NCWF revenue requirement was approved for recovery through base rates in the 2021 Arkansas base rate case. The table below provides a summary of the facilities as of December 31, 2022:


Project	In-Service Date	Net Book Value		Federal PTC Qualification % (a)			Generating Capacity
		(in millions)					(in MWs)
Sundance	April 2021	$	282.3	100	%		199
Maverick	September 2021	398.3		80	%		287
Traverse	March 2022	1,255.0		100	%	(b)	998

(a)PTC benefits are available for a ten year period following the in-service date.

(b)The PTC for Traverse was increased to 100% in the third quarter of 2022 as a result of the IRA legislation.

See “North Central Wind Energy Facilities” section of Note 7 for additional information.

Recent Renewable Generation Filings

In December 2021 and January 2022, APCo filed petitions with the Virginia SCC and WVPSC, respectively, for prudency and cost recovery of several renewable projects. In July 2022, the Virginia SCC approved APCo’s December 2021 petition for prudency and cost recovery. In January 2023, the WVPSC issued an order approving the remaining projects included in the petition. The table below provides a list of all remaining projects from the APCo petitions.

Generation Type

Expected Commercial Operation

Owned/PPA

Generating Capacity

(in MWs)

Solar

Second Quarter 2023

Owned

Solar

Fourth Quarter 2025

PPA

Solar

In Operation

PPA

Wind

Third Quarter 2025

Owned

204

Total Renewable Projects

244

In May 2022, SWEPCo submitted filings before the APSC, LPSC and PUCT requesting approval to acquire three renewable energy projects totaling 999 MWs. In October 2022, SWEPCo also submitted the necessary filings with the FERC. The projects are comprised of two wind facilities, totaling 799 MWs, and one solar facility, totaling 200 MWs. One of the wind facilities, totaling approximately 201 MWs, is expected to reach commercial operation in December 2024 with the remaining facilities expected to reach commercial operation in December 2025. In January 2023, a hearing was held at the PUCT. Additionally in January 2023, SWEPCo filed an unopposed joint settlement agreement with the APSC that supported approval of the projects. An order from the APSC is expected in the second quarter of 2023. In December, 2022, an intervenor filed suit seeking injunctive relief to effectively halt SWEPCo’s regulatory proceedings, among other relief; however, the magistrate judge for the United States District Court for the Eastern District of Texas has recommended denial of intervenor’s request for injunctive relief.

In November 2022, PSO submitted filings with the OCC requesting approval of its fuel-free power plan to purchase three new wind farms, totaling approximately 553 MWs, and three new solar facilities, totaling approximately 443 MWs. These projects are expected to reach commercial operation in 2025. This proposed plan will help meet projected power needs while protecting customers from volatility in energy costs driven by high natural gas and power prices. In addition, PSO has recently executed an agreement to purchase the 154 MW Rock Falls Wind Facility, and has requested cost recovery in the 2022 Oklahoma Base Rate Case. In February 2023, the FERC approved PSO’s acquisition of the Rock Falls Wind Facility under Section 203 of the Federal Power Act. See “2022 Oklahoma Base Rate Case” section of Note 4 for additional information.

Significant Renewable Generation Requests for Proposal (RFP)

As part of AEP’s transition to diversify the company’s generation resources and build its renewable generation portfolio, the Registrants file RFPs in an effort to identify potential wind and solar projects. The table below includes RFPs recently issued for owned generation. These projects would be subject to regulatory approval.

Company

Issuance Date

Generation Type

Generating Capacity

(in MWs)

APCo

January 2022

Wind

1,000

APCo

January 2022

Solar (a)

100

I&M

March 2022

Wind (a)(b)

800

I&M

March 2022

Solar (a)(b)

500

SWEPCo

September 2022

Wind (a)

1,900

SWEPCo

September 2022

Solar (a)

500

Total Significant RFPs

4,800

(a)Includes an option for battery storage.

(b)Includes solicitation of bids for both owned projects and PPAs.

Disposition of KPCo and KTCo

In October 2021, AEP entered into a Stock Purchase Agreement (SPA) 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. In May 2022, the KPSC approved the transfer of KPCo to Liberty subject to certain conditions contingent upon the closing of the sale. AEP has received clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR) and the Committee on Foreign Investment in the United States during 2022. Clearance under the HSR expired in January 2023. AEP and Liberty refiled a joint application seeking HSR clearance in February 2023. The sale is also contingent upon FERC approval under Section 203 of the Federal Power Act. The parties to the SPA have certain termination rights if the closing of the sale does not occur by April 26, 2023.

Transfer of Ownership

FERC Proceedings

In December 2021, Liberty, KPCo and KTCo (the applicants) requested FERC approval of the sale under Section 203 of the Federal Power Act. In February 2022, several intervenors in the case filed protests related to whether the sale will negatively impact the wholesale transmission rates of applicants. In April 2022, the FERC issued a deficiency letter stating that the Section 203 application is deficient and that additional information is required to process it. In May 2022, Liberty, KPCo and KTCo supplemented the application. In December 2022, the FERC issued an order denying, without prejudice, authorization of the proposed sale stating the applicants failed to demonstrate the proposed transaction will not have an adverse effect on rates.

In January 2023, AEP, AEPTCo, and Liberty entered into an amendment to the SPA that specified the applicants will submit a new filing for approval under Section 203 of the Federal Power Act. The new filing was submitted to the FERC on February 14, 2023. The applicants requested expedited treatment of the new filing, including an accelerated comment period. In response, the FERC granted a shortened 45 day comment period. The applicants believe the new Section 203 application addresses the concerns raised in the FERC’s December 2022 order. The application contains several additional commitments by Liberty to mitigate potential adverse impacts on FERC jurisdictional rates over the next five years, including: a) maintaining the current return on equity; b) maintaining the current cost cap on equity; c) financing future investments at the current credit rating; and d) capping certain operating and administrative costs. The sale remains subject to FERC approval. The statute requires an order from the FERC within 180 days of the February 14, 2023 filing date in accordance with Section 203 of the Federal Power Act.

KPSC Proceedings

In May 2022, the KPSC approved the transfer of KPCo to Liberty subject to conditions contingent upon the closing of the sale, including establishment of regulatory liabilities to subsidize retail customer transmission and distribution expenses, a fuel adjustment clause bill credit, and a three-year Big Sandy decommissioning rider rate holiday during which KPCo’s carrying charge is reduced by 50%.

Mitchell Plant Operations and Maintenance Agreement and Ownership Agreement

KPCo and WPCo each own a 50% undivided interest in the 1,560 MW coal-fired Mitchell Plant. As of December 31, 2022 and 2021, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $577 million and $586 million, respectively. The SPA includes a condition precedent to closing requiring the issuance of regulatory orders approving new Mitchell Plant agreements.

The KPSC and WVPSC issued orders proposing materially different modifications to the Mitchell Plant agreements filed by AEP such that the new agreements could not be executed by the parties. In lieu of new agreements, in July 2022, KPCo and WPCo confirmed with the KPSC and WVPSC, respectively, that they will continue operating under the existing Mitchell Agreement, utilizing the Mitchell Agreement Operating Committee’s authority under that agreement to issue appropriate resolutions so the parties can operate in accordance with each state commission’s directives related to CCR and ELG investment. In September 2022, pursuant to resolutions under the existing Mitchell Plant agreement, WPCo replaced KPCo as the Operator of Mitchell Plant.

Summary

As a result of the conditions imposed by the KPSC’s May 2022 order, in the second quarter of 2022, AEP recorded a $69 million loss on the expected sale of the Kentucky Operations in accordance with accounting guidance for Fair Value Measurement.

In September 2022, AEP, AEPTCo and Liberty entered into an amendment to the SPA which reduced the purchase price to approximately $2.646 billion and Liberty agreed to waive, upon FERC approval of the sale, the SPA condition precedent to closing requiring the issuance of regulatory orders approving new proposed Mitchell Plant agreements. Further, as a result of the reduced purchase price from the September Amendment and the change to the anticipated timing of the completion of the transaction, AEP recorded an additional $194 million pretax loss ($149 million net of tax) on the expected sale of the Kentucky Operations in the third quarter of 2022 in accordance with the accounting guidance for Fair Value Measurement.

As a result of the December 2022 FERC order and resulting delay in the anticipated timing of the closing of the transaction, AEP recorded an additional $100 million pretax loss ($79 million net of tax) on the expected sale of the Kentucky Operations in December 2022 in accordance with the accounting guidance for Fair Value Measurement. In total, AEP recorded a $363 million pretax loss of ($297 million net of tax) on the expected sale of the Kentucky Operations for the twelve months ended December 31, 2022.

Management believes it is probable that FERC authorization under Section 203 of the Federal Power Act will be received and closing will occur after receipt of the order. Therefore, the assets and liabilities of KPCo and KTCo were classified as Held for Sale in the December 31, 2022 balance sheets of AEP and AEPTCo. Upon closing, Liberty will acquire the assets and assume 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 cash proceeds, net of taxes and transaction fees, from the sale of approximately $1.2 billion. AEP plans to use the proceeds from the sale to fund its continued investment in regulated businesses, including transmission and regulated renewables projects. If additional reductions in the fair value of the Kentucky Operations occur, it would reduce future net income and cash flows.

Merchant Portion of Turk Plant

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

Approximately 20% of the Turk Plant output is currently not subject to cost-based rate recovery in Arkansas. This portion of the plant’s output is being sold into the wholesale market. Approximately 80% of the Turk Plant investment is recovered under retail cost-based rate recovery in Texas, Louisiana and through SWEPCo’s wholesale customers under FERC-approved rates. In November 2022, SWEPCo filed a Certificate of Public Convenience and Necessity with the APSC for approval to operate the Turk plant to serve Arkansas customers and recover the associated costs through a cost recovery rider. Cost-based recovery of the Turk Plant would aid SWEPCo’s near-term capacity needs and support compliance with SPP’s 2023 increased capacity planning reserve margin requirements. As of December 31, 2022, the net book value of the Turk Plant was $1.4 billion, before cost of removal including CWIP and inventory. If SWEPCo cannot ultimately recover its investment and expenses related to the Arkansas retail portion of the Turk Plant, it could reduce future net income and cash flows and impact financial condition.

Winter Storm Elliott

In December 2022, severe winter weather and extreme cold temperatures resulted in an unusually high demand for electricity and the declaration of an Energy Emergency Alert (EEA) in the PJM region. The EEA was in effect from December 23, 2022 through December 25, 2022. During this time, all electric generating units located within the PJM region were directed to operate up to their maximum generation output levels. The issuance of the EEA also triggered PJM Performance Assessment Intervals (PAI) for each committed generation capacity resource. During a PAI event, PJM evaluates the performance of each committed capacity resource against PJM performance standards. Generating units that underperform during a PAI event are subject to non-performance charges while generating units that perform above expectations are awarded performance bonuses. PJM awards and allocates the bonus performance payments from the pool of non-performance charges collected during the PAI event. PJM provided preliminary performance standards for each generating resource in January 2023 and additional preliminary generating unit performance data was released by PJM in February 2023. PJM currently expects to invoice non-performance charges and bonus payments in the month-end bill for March 2023 issued in early April 2023. As of December 31, 2022, based on preliminary PJM performance standards and internal generation estimates, OPCo and APCo recorded $7 million and $2 million, respectively, of non-performance charges from the December PAI event in Electricity, Transmission and Distribution revenues and Purchased Electricity, Fuel and Other Consumables Used for Electric Generation, respectively, on the statements of income. The Registrants did not record estimated bonus performance payments as of December 31, 2022 as those amounts were not reasonably estimable.

LITIGATION

In the ordinary course of business, AEP is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases that have a probable likelihood of loss if the loss can be estimated. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition. See Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies for additional information.

Rockport Plant Litigation

In 2013, the Wilmington Trust Company filed 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 appellate court, in April 2021, I&M and AEGCo reached an agreement to acquire 100% of the interests in Rockport Plant, Unit 2 for $116 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. The transaction closed at the expiration of the Rockport Plant, Unit 2 lease in December 2022 and also resulted in a final settlement of, and release of claims in, the lease litigation.

Subsequent to the end of the Rockport Plant, Unit 2 lease in December 2022, AEGCo’s 50% ownership share of Rockport Plant, Unit 2 is being billed to I&M under a FERC-approved UPA. I&M’s purchased power from AEGCo and I&M’s 50% ownership share of Rockport Plant, Unit 2 electricity generated represent a merchant resource for I&M until Rockport Plant, Unit 2 is retired in 2028. A 2021 IURC order approved a settlement agreement addressing the future use of Rockport Plant, Unit 2 as a short-term capacity resource through the June 2023 - May 2024 PJM planning year. The MPSC issued an order in February 2023 approving the settlement agreement on I&M’s 2022 Integrated Resource Plan (IRP) filing, which included certain cost recovery for the remaining net book value of leasehold improvements made during the term of the Rockport Plant, Unit 2 lease and future use of Rockport Plant, Unit 2 as a capacity resource. If I&M cannot recover its future investment and expenses related to the merchant share of Rockport Plant Unit 2, it could reduce future net income and cash flows and impact financial condition.

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

Four participants in The American Electric Power System Retirement Plan (the Plan) filed a class action complaint in December 2021 in the U.S. District Court for the Southern District of Ohio against AEPSC and the Plan. 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 plaintiffs assert a number of claims on behalf of themselves and the purported class, including 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) AEP failed to provide required notice regarding the changes to the Plan. Among other relief, the Complaint seeks reformation of the Plan to provide additional benefits and the recovery of plan benefits for former employees under such reformed plan. The plaintiffs previously had submitted claims for additional plan benefits to AEP, which were denied. On February 15, 2022, AEPSC and the Plan filed a motion to

dismiss the complaint for failure to state a claim. On August 16, 2022, the district court granted the motion to dismiss the complaint without prejudice. The plaintiffs filed a motion for leave to file an amended complaint, which the Court denied on December 1, 2022. The plaintiffs did not file an appeal by the deadline of January 3, 2023.

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, AEP, with assistance from outside advisors, conducted a review of the circumstances surrounding the passage of the bill. Management does 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 U.S. District Court for the Southern District of Ohio against AEP and certain of its officers for alleged violations of securities laws. The amended complaint alleged 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 sought monetary damages, among other forms of relief. In December 2021, the district court issued an opinion and order dismissing the securities litigation complaint with prejudice, determining that the complaint failed to plead any actionable misrepresentations or omissions. The plaintiffs did not appeal the ruling.

In January 2021, an AEP shareholder filed a derivative action in the U.S. 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 court entered a scheduling order in the New York state court derivative action staying the case other than with respect to briefing the motion to dismiss. AEP filed substantive and forum-based motions to dismiss on April 29, 2022. On September 13, 2022, the New York state court granted the forum-based motion to dismiss with prejudice and the plaintiffs subsequently filed a notice of appeal with the New York appellate court. On January 20, 2023, the New York plaintiff filed a motion to intervene in the pending Ohio federal court action and withdrew his appeal in New York on January 24, 2023. AEP filed a brief in opposition to intervention on February 3, 2023. The two derivative actions pending in federal district court in Ohio have been consolidated and the plaintiffs in the consolidated action filed an amended complaint. AEP filed a motion to dismiss the amended complaint on May 3, 2022 and briefing on the motion to dismiss has been completed. Discovery remains stayed pending the district court’s ruling on the motion to dismiss. The plaintiff in the Ohio state court case advised that they no longer agreed to stay the proceedings, therefore, AEP filed a motion to continue the stays of proceedings on May 20, 2022 and the plaintiff filed an amended complaint on June 2, 2022. On June 15, 2022, the Ohio state court entered an order continuing the stays of that case until the resolution of the consolidated derivative actions pending in Ohio federal district court. The defendants will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

In March 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, AEP 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 since withdrawn the litigation demand, which is now terminated and of no further effect.

In May 2021, AEP received a subpoena from the SEC’s Division of Enforcement seeking various documents, including documents relating to the passage of HB 6 and documents relating to AEP’s policies and financial processes and controls. In August 2022, AEP received a second subpoena from the SEC seeking various additional documents relating to its ongoing investigation. AEP is cooperating fully with the SEC’s investigation, which has included taking testimony from certain individuals. Although the outcome of the SEC’s investigation cannot be predicted, management does not believe the results of this investigation will have a material impact on financial condition, results of operations or cash flows.

Claims for Indemnification Related to Damages Resulting from the Federal EPA’s Denial of Alternative Closure Deadline for Gavin Plant and Associated Findings of Compliance

In November 2022, the Federal EPA issued a final decision denying Gavin Power LLC’s requested extension to allow a CCR surface impoundment at the Gavin Power Station to continue to receive CCR and non-CCR waste streams after April 11, 2021 until May 4, 2023 (the Gavin Denial). As part of the Gavin Denial, the Federal EPA made several determinations related to the CCR Rule (see “Coal Combustion Residual (CCR) Rule” section below for additional information), including a determination that the closure of the 300 acre unlined fly ash reservoir (FAR) is noncompliant with the CCR Rule in multiple respects. The Gavin Power Station was formerly owned and operated by AEP and was sold to Gavin Power LLC and Lightstone Generation LLC in 2017. Pursuant to the PSA, AEP maintained responsibility to complete closure of the FAR in accordance with the closure plan approved by the Ohio EPA which was completed in July 2021. The PSA contains indemnification provisions, pursuant to which the owners of the Gavin Power Station have notified AEP they believe they are entitled to indemnification for any damages that may result from the Gavin Denial, as well as any future enforcement or litigation resulting from the Federal EPA’s determinations of noncompliance with various aspects of the CCR Rule as part of the Gavin Denial. Management does not believe that the owners of the Gavin Power Station have any valid claim for indemnity or otherwise against AEP under the PSA. In addition, Gavin Power LLC, several AEP subsidiaries, and other parties have filed Petitions for Review of the Gavin Denial with the U.S. Court of Appeals for the District of Columbia Circuit. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

ENVIRONMENTAL ISSUES

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

AEP is engaged in litigation about environmental issues, was notified of potential responsibility for the clean-up of contaminated sites and incurred costs for disposal of SNF and future decommissioning of the nuclear units. Management is engaged in the development of possible future requirements including the items discussed below.

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

Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed below will have a material impact on AEP System generating units. Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance. As of December 31, 2022, the AEP System owned generating capacity of approximately 25,000 MWs, of which approximately 11,300 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 $125 million to $200 million through 2026.

The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in finalizing proposed rules or revising certain existing requirements. The cost estimates will also change based on: (a) potential state rules that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) actual performance of the pollution control technologies installed, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity, (g) compliance with the Federal EPA’s revised coal combustion residual rules and (h) 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 seven times, for various reasons, most recently in 2022. 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 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. In January 2023, the Federal EPA announced its proposed decision to strengthen the primary (health-based) annual PM2.5 standard. The Biden administration has previously indicated that it is likely to revisit the NAAQS for ozone, which were left unchanged by the prior administration following its review. Management cannot currently predict if any changes to either standard are likely to be finalized 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 postponed 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 contribute significantly to non-attainment and maintenance of the 1997 ozone and PM NAAQS in downwind states. 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 basis.

In January 2021, the Federal EPA finalized a revised CSAPR rule, which substantially reduces the ozone season NOX budgets in 2021-2024. Several utilities and other entities potentially subject to the Federal EPA’s NOX regulations have challenged that final rule in the U.S. Court of Appeals for the District of Columbia Circuit and oral arguments were held in September 2022. Management cannot predict the outcome of that litigation, but 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. In addition, in February 2023, the EPA Administrator finalized the denial of 2015 Ozone NAAQS SIPs for 19 states. A FIP that further revises the ozone season NOX budgets under the existing CSAPR program in those states is expected to be finalized in the spring of 2023 and will likely take effect for the 2023 ozone season. Management is evaluating the impacts of the rule changes.

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 District of Columbia Circuit vacated the ACE rule and remanded it to the Federal EPA. In October 2021, the United States Supreme Court granted certiorari and combined four separate petitions seeking review of the District of Columbia Circuit Court decisions. Oral arguments were held in February 2022 and on June 30, 2022, the United States Supreme Court reversed the District of Columbia Circuit Court’s decision and remanded for further proceedings. The Federal EPA must take some action before anything is required of the utilities as a result of this decision. At a minimum, if the Federal EPA intends to implement the ACE rule, it must conduct additional rulemaking to update its applicable deadlines, which have all passed. Alternatively, the Federal EPA may abandon the ACE rule and proceed to regulate greenhouse gases through a new rule, the scope of which is unknown. The Federal EPA has announced it expects to propose a new rule in 2023. 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. The Federal EPA has indicated that it intends to conduct a comprehensive review of the existing standards and, if appropriate, amend the emission standards for new fossil fuel-fired generating units. A proposed rule is expected in 2023. 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 (RGGI), require the retirement of all fossil-fueled generation by 2045 and require 100% renewable energy to be provided to Virginia customers by 2050. Management is taking steps to comply with these requirements, including increasing wind and solar installations, purchasing renewable power and broadening AEP System’s portfolio of energy efficiency programs. In early 2022, Virginia’s governor issued an executive order directing his administration to end Virginia’s participation in RGGI. In December 2022, the Virginia Air Pollution Control Board voted in support of the proposed regulations to withdraw Virginia from RGGI. These regulations have not been finalized. Management will continue to monitor these rulemaking activities.

In October 2022, 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. AEP adjusted its near-term carbon dioxide emission reduction target from a 2000 baseline to a 2005 baseline, upgraded its 80% reduction by 2030 target to include full Scope 1 emissions and accelerated its net-zero goal by five years to 2045. AEP’s total Scope 1 GHG emissions in 2022 were approximately 52.5 million metric tons CO2e, approximately a 65% reduction from AEP’s 2005 Scope 1 GHG emissions (inclusive of emission reductions that result from plants that have been sold). 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 (CCR) 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 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	Generating Capacity	Net Book Value (a)			Projected Retirement Date
		(in MWs)	(in millions)
AEGCo	Rockport Plant, Unit 1	655	$	226.0		2028
APCo	Amos	2,930	2,140.2			2040
APCo	Mountaineer	1,320	980.8			2040
I&M	Rockport Plant, Unit 1	655	449.2		(b)	2028
KPCo	Mitchell Plant	780	576.7			2040
SWEPCo	Flint Creek Plant	258	265.4			2038
WPCo	Mitchell Plant	780	638.3			2040

(a)Net book value as of December 31, 2022, before cost of removal including CWIP and inventory.

(b)Amount includes a $147 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 January 2022, the Federal EPA proposed to deny several extension requests filed by the other utilities based on allegations that those utilities are not in compliance with the CCR Rule (the January Actions). In November 2022, the Federal EPA finalized one of these denials. The Federal EPA’s allegations of noncompliance rely on new interpretations of the CCR Rule requirements. The January Actions of the Federal EPA have been challenged in the U.S. Court of Appeals for the District of Columbia Circuit as unlawful rulemaking that revises the existing CCR Rule requirements without proper notice and without opportunity for comment. Management is unable to predict the outcome of that litigation.

In July 2022, the Federal EPA proposed conditional approval of the pending extension request for the Mountaineer Plant. The Federal EPA alleged that the Mountaineer Plant was not fully compliant with the CCR Rule. In December 2022, AEP withdrew the pending extension request for the Mountaineer Plant as work to construct new CCR disposal facilities was completed and the extension was no longer needed. The Federal EPA has not yet proposed any action on the other pending extension requests submitted by AEP. However, statements made by the Federal EPA in the context of the proposed and final decisions on extension requests issued to date indicate that there is a risk that the Federal EPA may conclude that AEP is not eligible for an extension of time to cease use of those CCR impoundments for which extension requests are pending and/or that one or more of AEP’s facilities is not in compliance with the CCR Rule. If that occurs, AEP may incur material additional costs to change its plans for complying with the CCR Rule, including the potential to have to temporarily cease operation of one or more facilities until an acceptable compliance alternative can be implemented. Such temporary cessation of operation could materially impact the cost of serving customers of the affected utility. Further, actions by the Federal EPA could require AEP to remove coal ash from CCR units that have already been closed in accordance with state law programs or could require AEP to incur costs related to CCR units at various active and legacy facilities.

Closure and post-closure costs have been included in ARO in accordance with the requirements in the Federal EPA’s final CCR 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. AEP may incur significant additional costs complying with the Federal EPA’s CCR Rule, including costs to upgrade or close and replace surface impoundments and landfills used to manage CCR and to conduct any required remedial actions including removal of coal ash. If additional costs are incurred and AEP is unable to obtain cost recovery, it would reduce future net income and cash flows and impact financial condition. Management will continue to participate in rulemaking activities and make adjustments based on new federal and state requirements affecting its ash disposal units.

The second option to obtain an extension of the April 11, 2021 deadline to cease operation of unlined impoundments allows a generating facility to continue operating its existing impoundments without developing alternative CCR disposal, provided the facility commits to cease combustion of coal by a date certain. Under this option, a generating facility would have until October 17, 2023 to cease coal-fired operations 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 Plant and cease using coal at the Welsh Plant. The table below summarizes the net book value of the Pirkey Plant and Welsh Plant, Units 1 and 3 as of December 31, 2022.


Company	Plant Name and Unit	Generating Capacity	Net Investment (a)		Accelerated Depreciation Regulatory Asset		Projected Retirement Date
		(in MWs)	(in millions)
SWEPCo	Pirkey Plant	580	$	35.1	$	179.5	2023	(b)
SWEPCo	Welsh Plant, Units 1 & 3	1,053	416.8		85.6		2028	(c)(d)

(a)Net book value as of December 31, 2022, including CWIP and excluding cost of removal and materials and supplies.

(b)In January 2023, the LPSC authorized the recovery of SWEPCo’s Louisiana share of the Pirkey Plant through a separate rider through 2032. See Note 4 - Rate Matters for additional information. The Pirkey Plant is currently being recovered 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.

To date, the Federal EPA has not taken any action on these pending extension requests. Under the second option above, AEP may need to recover remaining depreciation and estimated closure costs associated with these 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 these plants in a timely manner, it would reduce future net income and cash flows and impact financial condition.

Clean Water Act Regulations

The Federal EPA’s ELG rule for generating facilities establishes limits for 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 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. For affected facilities that must install additional technologies to meet the ELG rule limits, permit modifications were filed in January 2021 that reflect the outcome of that assessment. AEP continues to work with state agencies to finalize permit terms and conditions. Other facilities opted to file Notices of Planned Participation (NOPP), pursuant to which the facilities are not required to install additional controls to meet ELG limits provided they make commitments to cease coal combustion by a date certain. The Federal EPA has announced its intention to reconsider the 2020 rule and to further revise limits applicable to discharges of landfill and impoundment leachate. A proposed rule is expected in 2023. Management cannot predict whether the Federal EPA will actually finalize further revisions or what such revisions might be, but will continue to monitor this issue and will participate in further rulemaking activities as they arise.

In January 2023, the Federal EPA finalized a new rule revising the definition of “waters of the United States,” which will become effective in March 2023. The new rule expands the scope of the definition, which means that permits may be necessary where none were previously required and issued permits may need to be reopened to impose additional obligations. Management is evaluating what impacts the revised rule will have on operations.

In October 2022, the United States Supreme Court heard an appeal related to the scope of “waters of the United States,” specifically which wetlands can be regulated as waters of the United States. Management cannot predict the outcome of that litigation.

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, remediation 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 Plant, Unit 2, Dolet Hills Power Station and Northeastern Plant, Unit 3.

The table below summarizes the net book value, as of December 31, 2022, of generating facilities retired or planned for early retirement in advance of the retirement date currently authorized for ratemaking purposes:


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	$	136.3	$	145.8	2026			(c)	$	14.9

SWEPCo	Dolet Hills Power Station	—		54.8		2021			(d)	—
SWEPCo	Pirkey Plant	35.1		179.5		2023			(e)	11.7
SWEPCo	Welsh Plant, Units 1 and 3	416.8		85.6		2028	(f)		(g)	37.9
SWEPCo	Welsh Plant, Unit 2	—		35.2		2016			(h)	—

(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)In January 2023, the LPSC authorized the recovery of SWEPCo’s Louisiana share of the Dolet Hills Power Station through a separate rider through 2032. In May 2022, the APSC authorized recovery of SWEPCo’s Arkansas jurisdictional share of the Dolet Hills Power Station through 2027, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $2 million. In December 2021, the PUCT authorized the recovery of SWEPCo’s Texas jurisdictional share of the Dolet Hills Power Station through 2046 without providing a return on the investment which resulted in a disallowance of $12 million. See Note 4 - Rate Matters for additional information.

(e)In January 2023, the LPSC authorized the recovery of SWEPCo’s Louisiana share of the Pirkey Plant through a separate rider through 2032. See Note 4 - Rate Matters for additional information. The Pirkey Plant is currently being recovered through 2045 in the Arkansas and Texas jurisdictions.

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

(g)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.

(h)In January 2023, the LPSC approved a settlement agreement which provided recovery of Welsh Plant, Unit 2 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 is not deemed recoverable, it could materially reduce future net income, cash flows and impact financial condition.

RESULTS OF OPERATIONS

SEGMENTS

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

Vertically Integrated Utilities

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

Transmission and Distribution Utilities

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

•OPCo purchases energy and capacity 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.

A detailed discussion of AEP’s 2021 results of operations by operating segment can be found in Management’s Discussion and Analysis of Financial Condition and Results of Operation section included in the 2021 Annual Report on Form 10-K filed with the SEC on February 24, 2022.

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


	Years Ended December 31,
	2022		2021		2020
	(in millions)
Vertically Integrated Utilities	$	1,292.0	$	1,113.6	$	1,061.6
Transmission and Distribution Utilities	595.7		543.4		496.4
AEP Transmission Holdco	673.5		677.8		504.8
Generation & Marketing	283.6		217.5		226.9
Corporate and Other	(537.6)		(64.2)		(89.6)
Earnings Attributable to AEP Common Shareholders	$	2,307.2	$	2,488.1	$	2,200.1

Note: 2022 Earnings Attributable to AEP Common Shareholders by Segment excludes Corporate and Other which is not considered a reportable segment.

AEP CONSOLIDATED

2022 Compared to 2021

Earnings Attributable to AEP Common Shareholders decreased from $2.5 billion in 2021 to $2.3 billion in 2022.

AEP’s Earnings Attributable to AEP Common Shareholders in 2022 were positively impacted by favorable rate proceedings in various jurisdictions, higher earnings driven by continued transmission investment and increased sales volumes driven by favorable weather and load. In June 2022, AEP also recognized a gain on the sale of mineral rights which contributed to AEP’s Earnings Attributable to AEP Common Shareholders.

The favorable items discussed above were more than offset by a loss on the expected sale of the Kentucky Operations, an impairment of AEP’s equity investment in Flat Ridge 2, increases in interest expense due to higher interest rates and debt balances and a charitable contribution to the AEP Foundation.

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

VERTICALLY INTEGRATED UTILITIES

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


	Years Ended December 31,
Vertically Integrated Utilities	2022		2021		2020
	(in millions)
Revenues	$	11,477.5	$	9,998.5	$	8,879.4
Fuel and Purchased Electricity	4,007.9		3,144.2		2,544.9
Gross Margin	7,469.6		6,854.3		6,334.5
Other Operation and Maintenance	3,287.2		3,043.1		2,754.3
Asset Impairments and Other Related Charges	24.9		11.6		—
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset	(37.0)		—		—
Depreciation and Amortization	2,007.2		1,747.6		1,600.5
Taxes Other Than Income Taxes	504.9		497.3		472.6
Operating Income	1,682.4		1,554.7		1,507.1


Other Income	30.2		13.5		2.4
Allowance for Equity Funds Used During Construction	29.5		40.2		42.2
Non-Service Cost Components of Net Periodic Benefit Cost	109.8		67.9		67.9
Interest Expense	(650.9)		(574.2)		(565.0)
Income Before Income Tax Benefit and Equity Earnings	1,201.0		1,102.1		1,054.6
Income Tax Benefit	(93.8)		(11.2)		(7.0)
Equity Earnings of Unconsolidated Subsidiary	1.4		3.4		2.9
Net Income	1,296.2		1,116.7		1,064.5
Net Income Attributable to Noncontrolling Interests	4.2		3.1		2.9
Earnings Attributable to AEP Common Shareholders	$	1,292.0	$	1,113.6	$	1,061.6


Summary of KWh Energy Sales for Vertically Integrated Utilities

	Years Ended December 31,
	2022	2021	2020
	(in millions of KWhs)
Retail:
Residential	32,835	32,149	31,526
Commercial	23,770	22,833	22,225
Industrial	34,532	33,181	32,860
Miscellaneous	2,316	2,214	2,185
Total Retail	93,453	90,377	88,796

Wholesale (a)	16,099	19,025	16,987

Total KWhs	109,552	109,402	105,783

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

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


Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities

	Years Ended December 31,
	2022	2021	2020
	(in degree days)
Eastern Region
Actual – Heating (a)	2,709	2,438	2,295
Normal – Heating (b)	2,717	2,720	2,727

Actual – Cooling (c)	1,187	1,268	1,222
Normal – Cooling (b)	1,106	1,110	1,104

Western Region
Actual – Heating (a)	1,523	1,241	1,160
Normal – Heating (b)	1,455	1,461	1,464

Actual – Cooling (c)	2,695	2,370	2,117
Normal – Cooling (b)	2,247	2,246	2,253

(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.

2022 Compared to 2021

Reconciliation of Year Ended December 31, 2021 to Year Ended December 31, 2022

Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities

(in millions)


Year Ended December 31, 2021	$	1,113.6

Changes in Gross Margin:
Retail Margins	492.6
Margins from Off-system Sales	9.6
Transmission Revenues	81.9
Other Revenues	31.2
Total Change in Gross Margin	615.3

Changes in Expenses and Other:
Other Operation and Maintenance	(244.1)
Asset Impairments and Other Related Charges	(13.3)
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset	37.0
Depreciation and Amortization	(259.6)
Taxes Other Than Income Taxes	(7.6)


Other Income	16.7
Allowance for Equity Funds Used During Construction	(10.7)
Non-Service Cost Components of Net Periodic Pension Cost	41.9
Interest Expense	(76.7)
Total Change in Expenses and Other	(516.4)

Income Tax Benefit	82.6
Equity Earnings of Unconsolidated Subsidiary	(2.0)
Net Income Attributable to Noncontrolling Interests	(1.1)

Year Ended December 31, 2022	$	1,292.0

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 $493 million primarily due to the following:

•A $127 million increase at APCo and WPCo due to an increase in rider revenues in Virginia and West Virginia. This increase was partially offset in other expense items below.

•A $110 million increase at PSO due to a $61 million increase in base rate revenues and a $49 million increase in rider revenues. These increases were partially offset in other expense items below.

•A $102 million increase at SWEPCo primarily due to base rate revenue increases in Texas and Arkansas and rider increases in all retail jurisdictions. These increases were partially offset in other expense items below.

•An $87 million increase in rider revenues at I&M partially offset by lower wholesale true-ups. This increase was partially offset in other expense items below.

•A $69 million increase in weather-related usage primarily in the residential class.

•A $30 million increase in weather-normalized retail margins primarily in the commercial class.

•A $17 million increase at APCo due to a base rate increase in Virginia implemented in October 2022 following the Virginia Supreme Court remand. This increase was partially offset in Other Operation and Maintenance expense below.

These increases were partially offset by:

•A $73 million decrease at PSO and SWEPCo due to the NCWF PTC benefits provided to customers through fuel clause mechanisms. This decrease was partially offset in Income Tax Benefit below.

•A $6 million decrease in municipal and cooperative revenues at SWEPCo primarily due to the February 2021 severe winter weather event.

•Margins from Off-system Sales increased $10 million primarily due to the following:

•A $32 million increase at I&M primarily due to Rockport Plant, Unit 2 Merchant sales beginning in December 2022 in addition to higher market prices driven by winter storm Elliott.

These increases were partially offset by:

•An $11 million decrease at SWEPCo due to a decrease in Turk Plant merchant sales primarily driven by the February 2021 severe winter weather event.

•A $9 million decrease at KPCo due to a change in the OSS sharing arrangement.

•A $4 million decrease at APCo due to decreased generation.

•Transmission Revenues increased $82 million primarily due to the following:

•A $61 million increase due to continued investment in transmission assets and increased load.

•A $16 million increase in formula rate true-up activity.

•Other Revenues increased $31 million primarily due to the following:

•A $12 million increase due to pole attachment revenue primarily at APCo. This increase was partially offset in Other Operation and Maintenance Expense below.

•A $10 million increase due to business development revenue primarily at APCo. This increase was partially offset in Other Operation and Maintenance Expense below.

•A $4 million increase due to a gain on sale of allowances primarily at I&M. The gain on sale of allowances was partially offset in Retail Margins above.

•A $4 million increase at I&M due to an increase in barging revenues by River Transportation Division (RTD). The increase in barging revenues was partially offset in Other Operation and Maintenance expenses below.

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

•Other Operation and Maintenance expenses increased $244 million primarily due to the following:

•A $131 million increase in PJM transmission services. This increase was partially offset in Retail Margins above.

•A $69 million increase in generation expenses primarily due to outages and maintenance at APCo, I&M and PSO.

•A $40 million increase due to a charitable contribution to the AEP Foundation.

•A $29 million increase in storm restoration expenses.

•A $25 million increase in distribution expenses primarily related to vegetation management, pole inspections and distribution overhead costs.

•A $22 million increase in SPP transmission services. This increase was partially offset in Retail Margins above.

•A $17 million increase in Energy Efficiency/Demand Response expenses. This increase was offset in Retail Margins above.

•A $14 million increase in accounts receivable factoring expenses as a result of increased interest rates.

These increases were partially offset by:

•A $132 million decrease due to the modification of the Rockport Plant, Unit 2 lease which resulted in a change in lease classification from an operating lease to a finance lease in December 2021 at AEGCo and I&M. This decrease was offset in Depreciation and Amortization expense below.

•Asset Impairments and Other Related Charges increased $13 million primarily due to:

•A $25 million increase at APCo due to the write-off of a regulatory asset in accordance with the August 2022 Virginia Supreme Court opinion related to the 2017-2019 Virginia Triennial review.

This increase was partially offset by:

•A $12 million decrease due to a partial regulatory disallowance of SWEPCo’s investment in the Dolet Hills Power Station as a result of an order received in the 2020 Texas Base Rate Case.

•Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset increased $37 million at APCo due to the establishment of a regulatory asset in accordance with the August 2022 Virginia Supreme Court opinion and resulting from under-earning during the 2017-2019 Triennial Review.

•Depreciation and Amortization expenses increased $260 million primarily due to the following:

•A $132 million increase due to the modification of the Rockport Plant, Unit 2 lease which resulted in a change in lease classification from an operating lease to a finance lease in December 2021 at AEGCo and I&M. This increase was partially offset in Other Operation and Maintenance expenses above.

•A $128 million increase due to a higher depreciable base primarily at APCo, I&M, PSO and SWEPCo, the implementation of new rates and the timing of refunds to customers under rate rider mechanisms at PSO and in Arkansas and Texas for SWEPCo. The increase due to implementation of new rates and the timing of refunds to customers under rate rider mechanisms at PSO was partially offset in Retail Margins above.

•Taxes Other Than Income Taxes increased $8 million primarily due to the following:

•A $17 million increase at PSO and SWEPCo primarily due to increased property taxes and a new infrastructure fee at PSO implemented by the City of Tulsa in March 2022. This increase was partially offset in Retail Margins above.

•A $4 million increase at APCo primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.

These increases were partially offset by:

•A $14 million decrease at I&M primarily due to the repeal of the Indiana Utility Receipts Tax in July 2022. This decrease was partially offset in Retail Margins above.

•Other Income increased $17 million primarily due to carrying charges on regulatory assets resulting from the February 2021 severe winter weather event at PSO and SWEPCo.

•Allowance for Equity Funds Used During Construction decreased $11 million primarily due to a lower AFUDC base at APCo and SWEPCo and a decrease in AFUDC equity rates primarily at APCo and I&M.

•Non-Service Cost Components of Net Periodic Benefit Cost decreased $42 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.

•Interest Expense increased $77 million primarily due to higher long-term debt balances at APCo, PSO and SWEPCo, higher interest rates at APCo and increased Advances from Affiliates at PSO and SWEPCo.

•Income Tax Benefit increased $83 million primarily due to the following:

•A $92 million increase in PTCs related to enacted legislation under the IRA and additional capital investment in tax-credit eligible property. This increase was partially offset in Retail Margins above.

•A $16 million increase due to favorable tax return to provision adjustments recorded in the current year.

•A $15 million increase due to a decrease in flow through depreciation expense.

•A $7 million increase due to an unfavorable out of period adjustment recorded in the prior year related to deferred income taxes.

These increases were partially offset by:

•A $21 million decrease due to an increase in pretax book income.

•A $19 million decrease due to a decrease in amortization of Excess ADIT. The decrease in amortization of Excess ADIT was partially offset in Gross Margin above.

TRANSMISSION AND DISTRIBUTION UTILITIES

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


	Years Ended December 31,
Transmission and Distribution Utilities	2022		2021		2020
	(in millions)
Revenues	$	5,512.0	$	4,492.9	$	4,345.9
Purchased Electricity	1,287.3		729.9		682.7


Gross Margin	4,224.7		3,763.0		3,663.2
Other Operation and Maintenance	1,864.2		1,573.9		1,575.4

Depreciation and Amortization	746.7		690.3		751.1
Taxes Other Than Income Taxes	659.9		640.9		586.7
Operating Income	953.9		857.9		750.0



Other Income	4.9		2.6		4.0
Allowance for Equity Funds Used During Construction	33.6		32.3		31.9
Non-Service Cost Components of Net Periodic Benefit Cost	47.6		29.0		29.4
Interest Expense	(328.0)		(300.9)		(289.2)
Income Before Income Tax Expense and Equity Earnings	712.0		620.9		526.1
Income Tax Expense	116.9		77.5		29.7
Equity Earnings of Unconsolidated Subsidiary	0.6		—		—
Net Income	595.7		543.4		496.4
Net Income Attributable to Noncontrolling Interests	—		—		—
Earnings Attributable to AEP Common Shareholders	$	595.7	$	543.4	$	496.4


Summary of KWh Energy Sales for Transmission and Distribution Utilities

	Years Ended December 31,
	2022	2021	2020
	(in millions of KWhs)
Retail:
Residential	27,479	26,830	26,518
Commercial	27,448	25,514	23,998
Industrial	25,435	23,919	22,432
Miscellaneous	753	737	749
Total Retail (a)	81,115	77,000	73,697

Wholesale (b)	2,198	2,018	1,859

Total KWhs	83,313	79,018	75,556

(a)Represents energy delivered to distribution customers.

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


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

	Years Ended December 31,
	2022	2021	2020
	(in degree days)
Eastern Region
Actual – Heating (a)	3,116	2,815	2,743
Normal – Heating (b)	3,185	3,190	3,202

Actual – Cooling (c)	1,121	1,222	1,140
Normal – Cooling (b)	1,011	1,016	1,006

Western Region
Actual – Heating (a)	450	341	189
Normal – Heating (b)	312	310	313

Actual – Cooling (d)	2,984	2,653	2,846
Normal – Cooling (b)	2,714	2,712	2,711

(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.

2022 Compared to 2021

Reconciliation of Year Ended December 31, 2021 to Year Ended December 31, 2022

Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities

(in millions)


Year Ended December 31, 2021	$	543.4

Changes in Gross Margin:
Retail Margins	362.3
Margins from Off-system Sales	61.9
Transmission Revenues	72.6
Other Revenues	(35.1)
Total Change in Gross Margin	461.7

Changes in Expenses and Other:
Other Operation and Maintenance	(290.3)

Depreciation and Amortization	(56.4)
Taxes Other Than Income Taxes	(19.0)


Other Income	2.3
Allowance for Equity Funds Used During Construction	1.3
Non-Service Cost Components of Net Periodic Benefit Cost	18.6
Interest Expense	(27.1)
Total Change in Expenses and Other	(370.6)

Income Tax Expense	(39.4)
Equity Earnings of Unconsolidated Subsidiaries	0.6

Year Ended December 31, 2022	$	595.7

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 $362 million primarily due to the following:

•A $111 million increase in Basic Transmission Cost Rider revenues and recoverable PJM expenses in Ohio. This increase was partially offset in Other Operation and Maintenance expenses below.

•A $105 million increase due to interim rate increases driven by increased distribution and transmission investment in Texas.

•A $42 million increase due 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 $30 million increase due to prior year refunds of Excess ADIT to customers in Texas. This increase was partially offset in Income Tax Expense below.

•A $23 million increase in weather-related usage in Texas primarily due to a 12% increase in cooling degree days and a 32% increase in heating degree days.

•A $19 million increase in revenue from rate riders in Texas. This increase was partially offset in other expense items below.

•An $18 million increase in weather-normalized margins primarily in the commercial and industrial classes, partially offset by the residential class.

•A $10 million increase in weather-related usage in Ohio primarily due to the end of decoupling.

•Margins from Off-system Sales increased $62 million primarily due to the following:

•A $52 million increase in off-system sales at OVEC due to higher market prices and volume, partially offset by an increase in PJM expenses driven by winter storm Elliott. This increase was offset in Retail Margins above and Other Revenues below.

•A $10 million increase in deferrals of OVEC costs. This increase was offset in Retail Margins above and Other Revenues below.

•Transmission Revenues increased $73 million primarily due to the following:

•A $65 million increase due to interim rate increases driven by increased transmission investment.

•A $7 million increase due to prior year refunds to customers in Texas associated with the last base rate case. This increase was offset in Other Revenues below.

•Other Revenues decreased $35 million primarily due to the following:

•A $38 million decrease in Ohio primarily due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs. This decrease was offset in Retail Margins and Margins from Off-system Sales above.

•A $12 million decrease in Texas due to the prior year amortization of a provision for refund recorded associated with the last base rate case. This decrease was offset in Retail Margins and Transmission Revenues above.

•A $7 million decrease in energy efficiency revenues in Texas.

These decreases were partially offset by:

•A $26 million increase in securitization revenues primarily due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020 and final refunds that were completed in 2021. This increase was offset in Depreciation and Amortization expenses and Interest Expense below.

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

•Other Operation and Maintenance expenses increased $290 million primarily due to the following:

•An $87 million increase in transmission expenses in Ohio primarily due to the following:

•An $88 million increase in recoverable PJM expenses. This increase was offset in Retail Margins above.

•A $3 million increase in transmission vegetation management expenses.

These increases were partially offset by:

•A $6 million decrease in transmission formula rate true-up activity.

•A $76 million increase in ERCOT transmission expenses. This increase was partially offset in Retail Margins and Transmission Revenues above.

•A $21 million increase in bad debt related expenses in Ohio, including $8 million in 2022 related to Bad Debt Rider over-recovery. This increase was offset in Retail Margins above.

•A $19 million increase in remitted Universal Service Fund surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset in Retail Margins above.

•An $18 million increase due to a charitable contribution to the AEP Foundation.

•A $17 million increase in recoverable distribution expenses in Ohio primarily related to vegetation management. This increase was offset in Retail Margins above.

•A $17 million increase in employee-related expenses.

•An $11 million increase in distribution-related expenses in Texas.

•Depreciation and Amortization expenses increased $56 million primarily due to the following:

•A $29 million increase due to a higher depreciable base in Texas.

•A $27 million increase in securitization amortizations in Texas primarily related to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020 and final refunds that were completed in 2021. This increase was offset in Other Revenues above.

•A $7 million increase in recoverable advanced metering system depreciable expenses in Texas.

These increases were partially offset by:

•A $9 million decrease in recoverable smart grid and Distribution Investment Rider depreciable expenses in Ohio. This decrease was offset in Retail Margins above.

•Taxes Other Than Income Taxes increased $19 million primarily due to an increase in Ohio in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.

•Non-Service Cost Components of Net Period Benefit Cost decreased $19 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.

•Interest Expense increased $27 million primarily due to the following:

•A $32 million increase in Texas primarily due to higher long-term debt balances and higher interest rates.

This increase was partially offset by:

•A $5 million decrease in Ohio primarily due to the retirement of a higher rate bond, partially offset by the issuance of a lower rate bond in 2021.

•Income Tax Expense increased $39 million primarily due to the following:

•A $21 million decrease in amortization of Excess ADIT. This decrease was partially offset in Gross Margin above.

•A $19 million increase due to an increase in pretax book income.

•A $4 million increase due to a current year change in the accounting policy for the parent company loss benefit.

These increases were partially offset by:

•A $9 million decrease due to an unfavorable out of period adjustment recorded in the prior year related to deferred income taxes.

AEP TRANSMISSION HOLDCO

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


	Years Ended December 31,
AEP Transmission Holdco	2022		2021		2020
	(in millions)
Transmission Revenues	$	1,677.0	$	1,526.2	$	1,198.8
Other Operation and Maintenance	165.7		132.3		119.0
Depreciation and Amortization	355.0		306.0		257.6
Taxes Other Than Income Taxes	277.6		245.0		211.0
Operating Income	878.7		842.9		611.2


Interest and Investment Income	2.0		0.7		2.9
Allowance for Equity Funds Used During Construction	70.6		67.2		74.0
Non-Service Cost Components of Net Periodic Benefit Cost	5.0		2.1		2.0
Interest Expense	(169.3)		(146.3)		(133.2)
Income Before Income Tax Expense and Equity Earnings	787.0		766.6		556.9
Income Tax Expense	193.6		159.6		130.8
Equity Earnings of Unconsolidated Subsidiary	83.4		75.0		82.4
Net Income	676.8		682.0		508.5
Net Income Attributable to Noncontrolling Interests	3.3		4.2		3.7
Earnings Attributable to AEP Common Shareholders	$	673.5	$	677.8	$	504.8

Summary of Investment in Transmission Assets for AEP Transmission Holdco


	December 31,
	2022		2021		2020
	(in millions)
Plant in Service	$	13,040.2	$	11,718.0	$	10,327.5
Construction Work in Progress	1,659.9		1,495.0		1,499.7
Accumulated Depreciation and Amortization	1,047.6		801.8		595.7
Total Transmission Property, Net	$	13,652.5	$	12,411.2	$	11,231.5

2022 Compared to 2021

Reconciliation of Year Ended December 31, 2021 to Year Ended December 31, 2022

Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco

(in millions)


Year Ended December 31, 2021	$	677.8

Changes in Transmission Revenues:
Transmission Revenues	150.8
Total Change in Transmission Revenues	150.8

Changes in Expenses and Other:
Other Operation and Maintenance	(33.4)
Depreciation and Amortization	(49.0)
Taxes Other Than Income Taxes	(32.6)


Interest and Investment Income	1.3
Allowance for Equity Funds Used During Construction	3.4
Non-Service Cost Components of Net Periodic Pension Cost	2.9
Interest Expense	(23.0)
Total Change in Expenses and Other	(130.4)

Income Tax Expense	(34.0)
Equity Earnings of Unconsolidated Subsidiary	8.4
Net Income Attributable to Noncontrolling Interests	0.9

Year Ended December 31, 2022	$	673.5

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

•Transmission Revenues increased $151 million primarily due to the following:

•A $180 million increase due to continued investment in transmission assets.

This increase was partially offset by:

•A $14 million decrease due to affiliated transmission formula rate true-up activity. This decrease was offset in Other Operation and Maintenance expense across the other Registrant Subsidiaries.

•A $5 million decrease due to nonaffiliated transmission formula rate true-up activity.

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

•Other Operation and Maintenance expenses increased $33 million primarily due to the following:

•A $12 million increase in employee-related expenses.

•An $11 million increase due to a charitable contribution to the AEP Foundation.

•A $5 million increase due to cancelled capital projects.

•Depreciation and Amortization expenses increased $49 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $33 million primarily due to higher property taxes as a result of increased transmission investment.

•Allowance for Equity Funds Used During Construction increased $3 million primarily due to higher CWIP.

•Interest Expense increased $23 million primarily due to higher long-term debt balances.

•Income Tax Expense increased $34 million primarily due to the following:

•A $21 million increase due to a current year change in the accounting policy for the parent company loss benefit.

•A $7 million increase due to an increase in pretax book income.

•Equity Earnings of Unconsolidated Subsidiary increased $8 million primarily due to higher pretax equity earnings for ETT and PATH-WV, partially offset by lower pretax equity earnings for Pioneer.

GENERATION & MARKETING

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


	Years Ended December 31,
Generation & Marketing	2022		2021		2020
	(in millions)
Revenues	$	2,466.9	$	2,163.7	$	1,725.6
Fuel, Purchased Electricity and Other	1,984.3		1,806.8		1,403.6
Gross Margin	482.6		356.9		322.0
Other Operation and Maintenance	118.7		97.5		124.9

Gain on Sale of Mineral Rights	(116.3)		—		—
Depreciation and Amortization	93.0		80.9		72.8
Taxes Other Than Income Taxes	11.1		10.5		13.2
Operating Income	376.1		168.0		111.1
Interest and Investment Income	38.9		4.2		3.2

Non-Service Cost Components of Net Periodic Benefit Cost	20.6		15.4		15.4
Interest Expense	(51.8)		(15.6)		(24.0)
Income Before Income Tax Benefit and Equity Earnings (Loss)	383.8		172.0		105.7
Income Tax Benefit	(83.1)		(48.8)		(108.0)
Equity Earnings (Loss) of Unconsolidated Subsidiaries	(192.4)		(10.6)		3.2
Net Income	274.5		210.2		216.9
Net Loss Attributable to Noncontrolling Interests	(9.1)		(7.3)		(10.0)
Earnings Attributable to AEP Common Shareholders	$	283.6	$	217.5	$	226.9


Summary of MWhs Generated for Generation & Marketing

	Years Ended December 31,
	2022	2021	2020
	(in millions of MWhs)
Fuel Type:
Coal	4	3	4

Renewables	4	4	3
Total MWhs	8	7	7

100

2022 Compared to 2021

Reconciliation of Year Ended December 31, 2021 to Year Ended December 31, 2022

Earnings Attributable to AEP Common Shareholders from Generation & Marketing

(in millions)


Year Ended December 31, 2021	$	217.5

Changes in Gross Margin:
Merchant Generation	31.6
Renewable Generation	38.7
Retail, Trading and Marketing	55.4
Total Change in Gross Margin	125.7

Changes in Expenses and Other:
Other Operation and Maintenance	(21.2)

Gain on Sale of Mineral Rights	116.3
Depreciation and Amortization	(12.1)
Taxes Other Than Income Taxes	(0.6)
Interest and Investment Income	34.7

Non-Service Cost Components of Net Periodic Benefit Cost	5.2
Interest Expense	(36.2)
Total Change in Expenses and Other	86.1

Income Tax Benefit	34.3
Equity Earnings of Unconsolidated Subsidiaries	(181.8)
Net Loss Attributable to Noncontrolling Interests	1.8

Year Ended December 31, 2022	$	283.6

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

•Merchant Generation increased $32 million primarily due to higher market prices.

•Renewable Generation increased $39 million primarily due to higher market prices at Texas wind facilities and new solar projects placed in service.

•Retail, Trading and Marketing increased $55 million primarily due to higher retail power and gas margins.

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

•Other Operation and Maintenance expenses increased $21 million primarily due to the following:

•A $39 million increase due to the sale of Racine Hydro in 2021.

•A $14 million increase due to newly placed in service renewable projects in 2022.

These increases were partially offset by:

•A $33 million decrease due to higher land sales and sale of renewable development projects in 2022.

•Gain on Sale of Mineral Rights increased $116 million due to the current year sale of mineral rights.

•Depreciation and Amortization expenses increased $12 million primarily due to a higher depreciable base from increased investments in renewable energy assets.

•Interest and Investment Income increased $35 million primarily due to an increase in advances to affiliates and higher interest rates in 2022.

•Non-Service Cost Components of Net Periodic Benefit Cost decreased $5 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.

101

•Interest Expense increased $36 million primarily due to higher interest rates in 2022.

•Income Tax Benefit increased $34 million primarily due to the following:

•A $22 million increase due to a change in state apportionment impacting deferred state taxes.

•A $14 million increase due to an unfavorable out of period adjustment recorded in the prior year related to deferred income taxes.

•A $10 million increase due to a decrease in state taxes.

•A $7 million increase due to an increase in PTCs related to enacted legislation under the IRA and additional capital investment in tax-credit eligible property.

These increases were partially offset by:

•A $10 million decrease due to a current year change in the accounting policy for the parent company loss benefit.

•An $8 million decrease due to an increase in pretax book income.

•Equity Earnings of Unconsolidated Subsidiaries decreased $182 million primarily due to the impairment of AEP’s investment in Flat Ridge 2 Wind LLC.

102

CORPORATE AND OTHER

2022 Compared to 2021

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $64 million in 2021 to a loss of $538 million in 2022 primarily due to:

•A $363 million pretax loss related to the anticipated sale of Kentucky operations.

•A $128 million increase in interest expense due to higher interest rates on short-term debt, an increase in advances from affiliates and an increase in long-term debt outstanding.

•A $42 million decrease at EIS, primarily due to lower returns on investments and an increase in reserves.

•A $26 million decrease in equity earnings.

•A $24 million decrease due to asset impairments and other related charges.

•An $18 million decrease due to unfavorable changes in gains and losses from AEP’s investment in ChargePoint. As of August 2022, AEP no longer has a direct investment in ChargePoint.

These items were partially offset by:

•A $60 million increase in interest income, primarily due to higher interest income from affiliates.

•A $67 million decrease in Income Tax Expense primarily due to the following:

•A $66 million decrease due to a loss on the anticipated sale of Kentucky operations.

•A $40 million decrease due to a current year change in the accounting policy for the parent company loss benefit.

•A $38 million decrease due to a change in pretax book income.

These items were partially offset by:

•A $79 million increase due to an out of period adjustment related to deferred taxes in 2021.

AEP SYSTEM INCOME TAXES

2022 Compared to 2021

•Income Tax Expense decreased $110 million primarily due to the following:

•An $88 million increase in tax credits primarily due to an increase in PTCs related to enacted legislation under the IRA and additional capital investment in tax-credit eligible property.

•A $61 million decrease due to a decrease in pretax book income.

•A $42 million decrease due to a change in state apportionment and statutory rates related to deferred taxes.

•A $17 million decrease in state income taxes primarily due to state return to provision adjustments.

These decreases were partially offset by:

•A $55 million increase due to an out of period adjustment recorded in 2021 related to deferred taxes.

•A $41 million decrease in the amortization of Excess ADIT.

103

FINANCIAL CONDITION

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

SIGNIFICANT CASH REQUIREMENTS

AEP’s contractual cash obligations include amounts reported on the balance sheets and other obligations disclosed in the footnotes. It is anticipated that these obligations will be satisfied through a combination of cash flows from operations, long-term debt issuances, short-term debt through AEP’s Commercial Paper Program or bank term loans, proceeds from the Kentucky operations sale, proceeds from the sale of competitive contracted renewables and the use of the ATM Program or other equity issuances.

Capital Expenditures

Continued capital investments reflect AEP’s commitment to enhance service and deliver reliable, clean energy and advanced technologies that exceed customer expectations. See “Budgeted Capital Expenditures” herein, for additional information.

Long-term Debt

Long-term debt maturities, including interest, represent a significant cash requirement for AEP and the Registrant Subsidiaries. See Note 14 - Financing Activities for additional information relating to the Registrant Subsidiaries’ long-term debt outstanding as of December 31, 2022, the weighted-average interest rate applicable to each debt category and a schedule of debt maturities over the next five years.

Other Significant Cash Requirements

Operating and finance leases represent a significant component of funding requirements for AEP and the Registrant Subsidiaries. See Note 13 - Leases for additional information.

The AEP System has substantial commitments for fuel, energy and capacity contracts as part of the normal course of business. See Note 6 - Commitments, Guarantees and Contingencies for additional information.

As of December 31, 2022, AEP expected to make contributions to the pension plans totaling $6 million in 2023. Based upon the projected benefit obligation and fair value of assets available to pay pension benefits, the pension plans were 101% funded as of December 31, 2022. See “Estimated Future Benefit Payments and Contributions” section of Note 8 for additional information.

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 security reserves. There is no collateral held in relation to any guarantees in excess of the ownership percentages. In the event any letters of credit are drawn, there is no recourse to third-parties. See “Letters of Credit” section of Note 6 for additional information.

104

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization


	December 31,
	2022				2021
	(dollars in millions)
Long-term Debt, including amounts due within one year (a)	$	35,622.6	55.8	%	$	33,454.5	57.0	%
Short-term Debt	4,112.2		6.4		2,614.0		4.4
Total Debt	39,734.8		62.2		36,068.5		61.4
AEP Common Equity	23,893.4		37.4		22,433.2		38.2
Noncontrolling Interests	229.0		0.4		247.0		0.4
Total Debt and Equity Capitalization	$	63,857.2	100.0	%	$	58,748.7	100.0	%

(a) Amount excludes $1.2 billion and $1.1 billion of Total Long-term Debt Outstanding classified as Liabilities Held for Sale on the balance sheet as of December 31, 2022 and 2021, respectively. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.

AEP’s ratio of debt-to-total capital increased from 61.4% to 62.2% as of December 31, 2021 and 2022, respectively, primarily due to an increase in debt to support distribution, transmission and renewable investment growth in addition to working capital needs due to an increase in deferred fuel costs.

Liquidity

Liquidity, or access to cash, is an important factor in determining AEP’s financial stability. Management believes AEP has adequate liquidity under its existing credit facilities. As of December 31, 2022, AEP had $5 billion in 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. AEP and its utilities finance its operations with commercial paper and other variable rate instruments that are subject to fluctuations in interest rates. To the extent that the Federal Reserve continues to raise short-term interest rates, it could reduce future net income and cash flows and impact financial condition. In February 2021, severe winter weather impacted certain AEP service territories resulting in disruptions to SPP market conditions. See Note 4 - Rate Matters for additional information. 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. In August 2022, AEP paid off the $500 million Term Loan. In 2022, increased fuel and purchased power prices continue to lead to an increase in under collection of fuel costs. As a result, in July 2022, APCo and KPCo entered into term loans of $100 million and $75 million, respectively, to help address the cash flow implications of the increased fuel and purchased power costs. See “Deferred Fuel Costs” section of Executive Overview for additional information on how the registrants are addressing the increase in deferred fuel regulatory assets. In September 2022, the ODFA issued ratepayer-backed securitization bonds for the purpose of reimbursing PSO for $687 million of extraordinary fuel costs and purchases of electricity incurred during the February 2021 severe winter weather event. See Note 4 - Rate Matters for additional information. In December 2022, AEP entered into four individual Term Loans, including three 364-day Term Loans, totaling $500 million to further address the cash flow implications of increased fuel and purchased power prices. In February 2023, AEP entered into a $500 million term loan to address short-term liquidity needs, made a capital contribution to SWEPCo, totaling $25 million, for general corporate business purposes and made a capital contribution to AEPTCo, totaling $25 million, to manage short-term borrowing capacity under the Money Pool.

105

Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments. As of December 31, 2022, available liquidity was approximately $2.6 billion as illustrated in the table below:

Amount

Maturity

(in millions)

Commercial Paper Backup:

Revolving Credit Facility

4,000.0

March 2027

(a)

Revolving Credit Facility

1,000.0

March 2024

(a)

Cash and Cash Equivalents

509.4

Total Liquidity Sources

5,509.4

Less: AEP Commercial Paper Outstanding

2,862.2

Net Available Liquidity

2,647.2

(a)In April 2022, AEP extended the maturity dates of the Revolving Credit Facilities from March 2026 to March 2027 and from March 2023 to March 2024, respectively.

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 2022 was $2.9 billion. The weighted-average interest rate for AEP’s commercial paper during 2022 was 2.74%.

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, as of December 31, 2022, $400 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities, as of December 31, 2022, was $287 million with maturities ranging from January 2023 to December 2023.

Financing Plan

As of December 31, 2022, AEP had $2 billion of long-term debt due within one year, excluding $490 million classified as Liabilities Held for Sale on the balance sheet. This also included $250 million of Pollution Control Bonds with mandatory tender dates and credit support for variable interest rates that requires the debt be classified as current and $210 million of securitization bonds and DCC Fuel notes. Management plans to refinance the majority of the maturities due within one year on a long-term basis.

Securitized Accounts Receivables

AEP 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. The $125 million facility was renewed in September 2022 and amended to extend the expiration date to September 2024. The $625 million facility also expires in September 2024. As of December 31, 2022, the affiliated utility subsidiaries, with the exception of SWEPCo, were in compliance with all requirements under the agreement. SWEPCo temporarily eased credit policies from August 2022 through October 2022 to assist customers with higher than normal bills driven by increased fuel costs and, in turn, experienced higher than normal aged receivables. In response, in January 2023, AEP Credit amended its receivables securitization agreement to increase the eligibility criteria related to their aged receivables requirements to bring SWEPCo back into compliance.

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Debt Covenants and Borrowing Limitations

AEP’s credit agreements contain certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5%. The method for calculating outstanding debt and capitalization is contractually-defined in AEP’s credit agreements. Debt as defined in the revolving credit agreement excludes securitization bonds and debt of AEP Credit. As of December 31, 2022, this contractually-defined percentage was 59.1%. Non-performance under these covenants could result in an event of default under these credit agreements. In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of AEP’s major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements. This condition also applies in a majority of AEP’s non-exchange-traded commodity contracts and would similarly allow lenders and counterparties to declare the outstanding amounts payable. However, a default under AEP’s non-exchange-traded commodity contracts would not cause an event of default under its credit agreements.

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

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

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. There were no issuances under the ATM program for the year ended December 31, 2022. As of December 31, 2022, approximately $511 million of equity is available for issuance under the ATM offering program. See Note 14 - 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 August 2023. The proceeds were used to support AEP’s overall capital expenditure plan.

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 settled 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. In January 2022, AEP successfully remarketed the notes on behalf of holders of the corporate units and did not directly receive any proceeds therefrom. Instead, the holders of the corporate units used the debt remarketing proceeds to settle the forward equity purchase contract with AEP. The interest rate on the notes was reset to 2.031% with the maturity remaining in 2024. In March 2022, AEP issued 8,970,920 shares of AEP common stock and received proceeds totaling $805 million under the settlement of the forward equity purchase contract. AEP common stock held in treasury was used to settle the forward equity purchase contract.

See Note 14 - Financing Activities for additional information.

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Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.83 per share in January 2023. Future dividends may vary depending upon AEP’s profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. Management does not believe these restrictions will have any significant impact on its ability to access cash to meet the payment of dividends on its common stock. See “Dividend Restrictions” section of Note 14 for additional information.

Credit Ratings

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

CASH FLOW

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


	Years Ended December 31,
	2022		2021		2020
	(in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	$	451.4	$	438.3	$	432.6
Net Cash Flows from Operating Activities	5,288.0		3,839.9		3,832.9
Net Cash Flows Used for Investing Activities	(7,751.8)		(6,433.9)		(6,233.9)
Net Cash Flows from Financing Activities	2,568.9		2,607.1		2,406.7

Net Increase in Cash, Cash Equivalents and Restricted Cash	105.1		13.1		5.7
Cash, Cash Equivalents and Restricted Cash at End of Period	$	556.5	$	451.4	$	438.3

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Operating Activities


	Years Ended December 31,
	2022		2021		2020
	(in millions)
Net Income	$	2,305.6	$	2,488.1	$	2,196.7
Non-Cash Adjustments to Net Income (a)	3,461.6		3,025.9		2,954.8
Mark-to-Market of Risk Management Contracts	15.5		112.3		66.5
Pension Contributions to Qualified Plan Trust	—		—		(110.3)
Property Taxes	(41.2)		(68.0)		(43.3)
Deferred Fuel Over/Under Recovery, Net	(319.2)		(1,647.9)		(31.8)
Change in Regulatory Assets	(46.7)		(238.9)		(337.9)


Change in Other Noncurrent Assets	(187.7)		(126.6)		(151.0)
Change in Other Noncurrent Liabilities	337.8		206.4		(54.5)
Change in Certain Components of Working Capital	(237.7)		88.6		(656.3)
Net Cash Flows from Operating Activities	$	5,288.0	$	3,839.9	$	3,832.9

(a)Non-Cash Adjustments to Net Income includes Depreciation and Amortization, Rockport Plant, Unit 2 Lease Amortization, Deferred Income Taxes, Loss on the Expected Sale of the Kentucky Operations, Asset Impairments and Other Related Charges, Impairment of Equity Method Investment, Allowance for Equity Funds Used During Construction, Amortization of Nuclear Fuel, Gain on Sale of Mineral Rights and Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset.

2022 Compared to 2021

Net Cash Flows from Operating Activities increased by $1.4 billion primarily due to the following:

•A $1.3 billion increase in cash primarily due to the timing of fuel and purchased power revenues and expenses. PSO and SWEPCo were impacted by the February 2021 severe winter weather event in SPP which led to significantly higher fuel and purchased power expenses which were deferred as regulatory assets in 2021. In September 2022, the ODFA issued ratepayer-backed securitization bonds and provided PSO proceeds of $687 million as reimbursement of the extraordinary fuel costs and purchased electricity incurred during the severe winter weather event. See Note 4 - Rate Matters for additional information. In 2022, increased fuel and purchased power prices in excess of amounts included in fuel-related revenues has resulted in an increase in the under collection of fuel costs in most jurisdictions, offsetting the proceeds received by PSO in September 2022. See the “Deferred Fuel Costs” section of Executive Overview for additional information.

•A $253 million increase in cash from Net Income, after non-cash adjustments. See Results of Operations for further detail.

•A $192 million increase in cash from Changes in Regulatory Assets primarily due to incremental other operation and maintenance storm restoration expenses incurred in 2021 by APCo, SWEPCo and KPCo as a result of the February 2021 severe winter weather event. The increase due to the February 2021 severe winter weather event was partially offset by the deferral of incremental other operation and maintenance storm restoration expenses incurred in June 2022 by APCo, KPCo, OPCo and WPCo. See Note 4 - Rate Matters for additional information.

•A $131 million increase in cash from Changes in Other Noncurrent Liabilities. The increase is primarily due to changes in provisions for refunds and regulatory liabilities driven by timing differences between collections from and refunds to customers under rate rider mechanisms. See Note 5 - Effects of Regulation for additional information.

•A $97 million increase primarily due to collateral held against risk management contracts due to pricing movement in the commodities market.

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These increases in cash were offset by:

•A $326 million decrease in cash from the Change in Certain Components of Working Capital. The decrease is primarily due to fuel, material and supplies driven by current year increases in coal inventory and material and supplies in addition to prior year decreases in coal and lignite inventory on hand, an increase in estimated federal income taxes paid and the timing of accounts receivables. These decreases were partially offset by the timing of accounts payable and a return of margin deposits from PJM originally paid in 2021.

Investing Activities


	Years Ended December 31,
	2022		2021		2020
	(in millions)
Construction Expenditures	$	(6,671.7)	$	(5,659.6)	$	(6,246.3)
Acquisitions of Nuclear Fuel	(100.7)		(104.5)		(69.7)

Acquisition of the Dry Lake Solar Project	—		(114.4)		—
Acquisition of the North Central Wind Energy Facilities	(1,207.3)		(652.8)		—
Proceeds on Sale of Assets	218.0		118.9		71.1
Other	9.9		(21.5)		11.0
Net Cash Flows Used for Investing Activities	$	(7,751.8)	$	(6,433.9)	$	(6,233.9)

2022 Compared to 2021

Net Cash Flows Used for Investing Activities increased by $1.3 billion primarily due to the following:

•A $1 billion increase in construction expenditures, primarily due to increases in Vertically Integrated and Transmission and Distribution segments of $647 million and $411 million, respectively.

•A $440 million increase due to the 2022 acquisition of Traverse, partially offset by the 2021 acquisitions of the Dry Lake Solar Project, Sundance and Maverick. See Note 7 - Acquisitions, Assets and Liabilities Held for Sale, Dispositions and Impairments for additional information.

These increases in cash used were partially offset by:

•A $99 million increase in Proceeds from Sale of Assets, primarily due to the 2022 sale of certain mineral rights. See Note 7 - Acquisitions, Assets and Liabilities Held for Sale, Dispositions and Impairments for additional information.

Financing Activities


	Years Ended December 31,
	2022		2021		2020
	(in millions)
Issuance of Common Stock	$	826.5	$	600.5	$	155.0
Issuance/Retirement of Debt, Net	3,802.5		3,631.7		3,927.3

Dividends Paid on Common Stock	(1,645.2)		(1,519.5)		(1,424.9)
Principal Payments for Finance Lease Obligations	(309.5)		(64.0)		(61.7)
Redemption of Noncontrolling Interests	—		—		(100.2)
Other	(105.4)		(41.6)		(88.8)
Net Cash Flows from Financing Activities	$	2,568.9	$	2,607.1	$	2,406.7

2022 Compared to 2021

Net Cash Flows from Financing Activities decreased by $38 million primarily due to the following:

•A $1.8 billion decrease in issuances of long-term debt. See Note 14 - Financing Activities for additional information.

•A $246 million decrease due to an increase in Principal Payments for Finance Lease Obligations primarily driven by Rockport Plant, Unit 2 final lease payments.

•A $126 million decrease due to an increase in dividends paid on common stock.

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These decreases in cash were partially offset by:

•A $1.4 billion increase in short-term debt primarily due to increased draws under the commercial paper program. See Note 14 - Financing Activities for additional information.

•A $644 million increase due to decreased retirements of long-term debt. See Note 14 - Financing Activities for additional information.

•A $226 million increase in issuances of common stock primarily due to the settlement of the 2019 equity units. See “Equity Units” section of Note 14 for additional information.

The following financing activities occurred during 2022:

AEP Common Stock:

•During 2022, AEP issued 683 thousand shares of common stock under the incentive compensation, employee saving and dividend reinvestment plans. Additionally in 2022, AEP reissued 9 million shares of treasury stock to fulfill share commitments related to AEP’s Equity Units. See “Common Stock” and “Equity Units” section of Note 14 for additional information. AEP received net proceeds of $827 million related to these issuances.

Debt:

•During 2022, AEP issued approximately $4.7 billion of long-term debt, including $3.1 billion of senior unsecured notes at interest rates ranging from 4.5% to 5.95%, $1.3 billion of other debt at various interest rates and $214 million of pollution control bonds at interest rates ranging from 3% to 3.75%. The proceeds from these issuances were primarily used to fund long-term debt maturities, construction programs and to help address working capital needs.

•During 2022, AEP entered into interest rate derivatives with notional amounts totaling $700 million that were designated as cash flow hedges. During 2022, settlements of AEP’s interest rate derivatives resulted in net cash paid of $7 million for derivatives designated as fair hedges. As of December 31, 2022, AEP had a total notional amount of $950 million of outstanding interest rate derivatives designated as fair value hedges and $700 million designated as cash flow hedges.

See “Long-term Debt Subsequent Events” section of Note 14 for Long-term debt and other securities issued, retired and principal payments made after December 31, 2022 through February 23, 2023, the date that the 10-K was issued.

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BUDGETED CAPITAL EXPENDITURES

Management forecasts approximately $6.8 billion of capital expenditures in 2023. For the four year period, 2024 through 2027, management forecasts capital expenditures of $32.9 billion. The expenditures are generally for transmission, generation, distribution, regulated 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, supply chain issues, weather, legal reviews and the ability to access capital. Management expects to fund these capital expenditures through cash flows from operations, proceeds from the sale of Kentucky operations, proceeds from the sale of competitive contracted renewables and financing activities. Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged. The 2023 estimated capital expenditures include generation, transmission and distribution related investments, as well as expenditures for compliance with environmental regulations as follows:


	2023 Budgeted Capital Expenditures
Segment	Environmental		Generation		Renewables		Transmission		Distribution		Other (a)		Total
	(in millions)
Vertically Integrated Utilities	$	150.7	$	345.5	$	106.1	$	817.3	$	1,310.7	$	426.3	$	3,156.6	(b)
Transmission and Distribution Utilities	—		—		—		999.0		993.1		287.5		2,279.6
AEP Transmission Holdco	—		—		—		1,290.6		—		19.1		1,309.7		(b)
Generation & Marketing	—		43.9		4.7		—		—		21.5		70.1
Corporate and Other	—		—		—		—		—		30.6		30.6
Total	$	150.7	$	389.4	$	110.8	$	3,106.9	$	2,303.8	$	785.0	$	6,846.6

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

(b)2023 budgeted capital expenditures do not include any amounts for KPCo or KTCo.

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The table below represents estimated capital investments by business segment for the years 2024 to 2027:


Segment	2024		2025		2026		2027

Vertically Integrated Utilities (a)	$	5,103.6	$	6,417.2	$	3,824.9	$	3,306.3
Transmission and Distribution Utilities	2,509.8		2,280.0		2,289.3		2,226.5
AEP Transmission Holdco (a)	1,225.5		964.5		1,107.1		1,246.4
Generation & Marketing	76.6		72.4		76.4		103.6
Corporate and Other	27.4		14.0		15.4		2.1
Total	$	8,942.9	$	9,748.1	$	7,313.1	$	6,884.9

(a) 2024-2027 estimated capital investments do not include any amounts for KPCo or KTCo.

The 2023 estimated capital expenditures by Registrant Subsidiary include distribution, transmission and generation-related investments, as well as expenditures for compliance with environmental regulations as follows:


	2023 Budgeted Capital Expenditures
Company	Environmental		Generation		Renewables		Transmission		Distribution		Other (a)		Total
	(in millions)
AEP Texas	$	—	$	—	$	—	$	683.3	$	509.1	$	125.6	$	1,318.0
AEPTCo	—		—		—		1,290.6		—		19.1		1,309.7
APCo	65.9		122.8		25.3		324.9		432.8		146.7		1,118.4
I&M	—		100.8		2.0		74.6		297.1		105.5		580.0
OPCo	—		—		—		315.7		484.0		161.9		961.6
PSO	0.2		27.4		57.7		119.2		305.7		54.1		564.3
SWEPCo	4.8		48.1		21.2		290.0		221.3		110.4		695.8

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

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CYBER SECURITY

The electric utility industry is an identified critical infrastructure function with mandatory cyber security requirements under the authority of FERC. The NERC, which FERC certified as the nation’s Electric Reliability Organization, developed mandatory critical infrastructure protection cyber security reliability standards. AEP’s service territory covers multiple NERC regions and is audited at least annually by one or more of the regions. AEP has participated in the NERC grid security and emergency response exercises, GridEx, for the past ten years and continues to participate in the bi-yearly exercises. These NERC-led efforts test and further develop the coordination, threat sharing and interaction between utilities and various government agencies relative to potential cyber and physical threats against the nation’s electric grid. AEP also conducts internal exercises to test and further develop AEP’s cyber response plans. These internal scenarios are chosen based on real world events and often include coordination with and communication to AEP’s Chief Executive Officer and executive team.

The operations of AEP’s electric utility subsidiaries are subject to extensive and rigorous mandatory cyber and physical security requirements that are developed and enforced by NERC to protect grid security and reliability. AEP’s enterprise-wide security program includes cyber and physical security and incorporates many of the guidelines set forth in the National Institute of Standards and Technology Cybersecurity Framework. AEP’s Chief Security Officer (CSO) is also its NERC Critical Infrastructure Protection Senior Manager, ensuring alignment of compliance with the enterprise-wide security program.

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

AEP has undertaken a variety of actions to monitor and address cyber-related risks. Cyber security and the effectiveness of AEP’s cyber security processes are reviewed annually with the Board of Directors and at several meetings throughout the year with the Technology Committee of the Board, the principal committee that exercises oversight with respect to these matters. AEP’s Chief Executive Officer and executive team participate in interactive threat briefings from AEP’s CSO and the security leadership team on a regular basis. AEP’s strategy and procedure for managing cyber-related risks is integrated within its enterprise risk management processes. These procedures are designed to ensure that any material information regarding potentially relevant cyber incidents is elevated in a timely manner both to the appropriate leadership and, where applicable, to our external financial reporting and disclosure team. AEP’s enterprise-wide security program continually adjusts staff and resources in response to the evolving threat landscape. The costs for such investments are material and have remained constant over time, a pattern that is expected to continue. In addition, AEP maintains cyber liability insurance to cover certain damages caused by cyber incidents.

AEP’s CSO leads the cyber security and physical security teams and is responsible for the design, implementation and execution of AEP’s security risk management strategy, which includes cyber security. AEP’s cyber security team operates a 24/7 Cyber Security Intelligence and Response Center responsible for monitoring the AEP System for cyber risks and threats. The cyber security team constantly scans the AEP System for risks and threats. In addition, under the direction of the CSO, the cyber security team actively monitors best practices, performs penetration testing, leads response exercises and internal awareness campaigns and provides training and communication across the organization. AEP’s security awareness training is mandatory for all employees and includes regular phish email testing to train employees to identify malicious emails that could put AEP at risk.

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

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

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING STANDARDS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

•It requires assumptions to be made that were uncertain at the time the estimate was made; and

•Changes in the estimate or different estimates that could have been selected could have a material effect on net income or financial condition.

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

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

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

Regulatory Accounting

Nature of Estimates Required

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

Assumptions and Approach Used

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

Effect if Different Assumptions Used

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

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Revenue Recognition – Unbilled Revenues

Nature of Estimates Required

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

Accrued unbilled revenues for the Vertically Integrated Utilities segment were $354 million and $246 million as of December 31, 2022 and 2021, respectively. The changes in unbilled electric utility revenues for AEP’s Vertically Integrated Utilities segment were $108 million, $(42) million and $40 million for the years ended December 31, 2022, 2021 and 2020, respectively. The changes in unbilled electric revenues are primarily due to changes in weather and rates.

Accrued unbilled revenues for the Transmission and Distribution Utilities segment were $221 million and $172 million as of December 31, 2022 and 2021, respectively. The changes in unbilled electric utility revenues for AEP’s Transmission and Distribution Utilities segment were $49 million, $1 million and $5 million for the years ended December 31, 2022, 2021 and 2020, respectively. The changes in unbilled electric revenues are primarily due to changes in weather and rates.

Accrued unbilled revenues for the Generation & Marketing segment were $109 million and $110 million as of December 31, 2022 and 2021, respectively. The changes in unbilled electric utility revenues for AEP’s Generation & Marketing segment were $(1) million, $24 million and $11 million for the years ended December 31, 2022, 2021 and 2020, respectively.

Assumptions and Approach Used

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

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

Effect if Different Assumptions Used

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

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Accounting for Derivative Instruments

Nature of Estimates Required

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

Assumptions and Approach Used

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

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

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

Effect if Different Assumptions Used

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

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

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

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Long-Lived Assets

Nature of Estimates Required

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

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

Assumptions and Approach Used

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

Effect if Different Assumptions Used

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

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Pension and OPEB

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

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

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


	Years Ended December 31,
Net Periodic Cost (Credit)	2022		2021		2020
	(in millions)
Pension Plans	$	80.9	$	138.2	$	108.6
OPEB	(144.8)		(122.0)		(109.7)

The net periodic benefit cost is calculated based upon a number of actuarial assumptions, including expected long-term rates of return on the Plans’ assets. In developing the expected long-term rate of return assumption for 2023, management evaluated input from actuaries and investment consultants, including their reviews of asset class return expectations as well as long-term inflation assumptions. Management also considered historical returns of the investment markets and tax rates which affect a portion of the OPEB plans’ assets. Management anticipates that the investment managers employed for the Plans will invest the assets to generate future returns averaging 7.5% for the Qualified Plan and 7.25% for the OPEB plans.

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


	Pension Plans				OPEB
			Assumed/				Assumed/
	2023		Expected		2023		Expected
	Target		Long-Term		Target		Long-Term
	Asset		Rate of		Asset		Rate of
	Allocation		Return		Allocation		Return
Equity	30	%	9.28	%	59	%	8.30	%
Fixed Income	54		5.92		40		5.71
Other Investments	15		9.06		—		—
Cash and Cash Equivalents	1		2.67		1		2.67
Total	100	%			100	%

Management regularly reviews the actual asset allocation and periodically rebalances the investments to the targeted allocation. Management believes that 7.5% for the Qualified Plan and 7.25% for the OPEB plans are reasonable estimates of the long-term rate of return on the Plans’ assets. The Pension Plans’ assets had an actual loss of 16.88% and a gain of 5.41% for the years ended December 31, 2022 and 2021, respectively. The OPEB plans’ assets had an actual loss of 19.53% and a gain of 8.67% for the years ended December 31, 2022 and 2021, respectively. Management will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the assumptions as necessary.

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AEP bases the determination of pension expense or income on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded. As of December 31, 2022, AEP had cumulative gains of approximately $523 million for the Qualified Plan that remain to be recognized in the calculation of the market-related value of assets. These unrecognized market-related net actuarial gains may result in decreases in the future pension costs depending on several factors, including whether such gains at each measurement date exceed the corridor in accordance with “Compensation – Retirement Benefits” accounting guidance.

The method used to determine the discount rate that AEP utilizes for determining future obligations is a duration-based method in which a hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan. The discount rate as of December 31, 2022 under this method was 5.5% for the Qualified Plan, 5.6% for the Nonqualified Plans and 5.5% for the OPEB plans. Due to the effect of the unrecognized net actuarial losses and based on an expected rate of return on the Pension Plans’ assets of 7.5%, discount rates of 5.5% and 5.6% and various other assumptions, management estimates credits for the Pension Plans will approximate $24 million and $20 million in 2023 and 2024, respectively. Management estimates that the pension costs for the Pension Plans will approximate $8 million in 2025. Based on an expected rate of return on the OPEB plans’ assets of 7.25%, a discount rate of 5.5% and various other assumptions, management estimates OPEB plan credits will approximate $107 million, $65 million and $62 million in 2023, 2024 and 2025, respectively. Future actual costs will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the Plans. The actuarial assumptions used may differ materially from actual results. The effects of a 50 basis point change to selective actuarial assumptions are included in the “Effect if Different Assumptions Used” section below.

The value of AEP’s Pension Plans’ assets decreased to $4.1 billion as of December 31, 2022 from $5.4 billion as of December 31, 2021 primarily due to negative investment returns. During 2022, the Qualified Plan paid $395 million and the Nonqualified Plans paid $7 million in benefits to plan participants. The value of AEP’s OPEB plans’ assets decreased to $1.5 billion as of December 31, 2022 from $2.0 billion as of December 31, 2021 primarily due to negative investment returns. During 2022, the OPEB plans paid $140 million in benefits to plan participants.

Nature of Estimates Required

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

Assumptions and Approach Used

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

•Discount rate

•Compensation increase rate

•Cash balance crediting rate

•Health care cost trend rate

•Expected return on plan assets

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Other assumptions, such as retirement, mortality and turnover, are evaluated periodically and updated to reflect actual experience.

Effect if Different Assumptions Used

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


	Pension Plans				OPEB
	+0.5%		-0.5%		+0.5%		-0.5%
	(in millions)
Effect on December 31, 2022 Benefit Obligations
Discount Rate	$	(170.2)	$	184.9	$	(37.1)	$	40.3
Compensation Increase Rate	19.7		(18.3)		NA		NA
Cash Balance Crediting Rate	57.2		(54.2)		NA		NA
Health Care Cost Trend Rate	NA		NA		6.1		(5.4)

Effect on 2022 Periodic Cost
Discount Rate	$	(12.7)	$	14.0	$	3.0	$	(2.9)
Compensation Increase Rate	7.4		(6.8)		NA		NA
Cash Balance Crediting Rate	14.3		(13.4)		NA		NA
Health Care Cost Trend Rate	NA		NA		0.6		(0.2)
Expected Return on Plan Assets	(24.1)		24.1		(10.1)		10.1

NA Not applicable.

SIGNIFICANT TAX LEGISLATION

In August 2022, President Biden signed H.R. 5376 into law, commonly known as the Inflation Reduction Act of 2022 or IRA. Most notably this budget reconciliation legislation creates a 15% minimum tax on adjusted financial statement income (Corporate Alternative Minimum Tax or CAMT), extends and increases the value of PTCs and ITCs, adds a nuclear and clean hydrogen PTC, an energy storage ITC and allows the sale or transfer of tax credits to third parties for cash. The IRS has since released interim guidance in the form of Notices addressing the Prevailing Wage and Apprenticeship Requirements tied to full value PTCs and ITCs for projects that begin construction on or after January 29, 2023, and time-sensitive issues related to the CAMT. As further significant guidance from Treasury and the IRS is expected on the tax provisions in the IRA, AEP will continue to monitor any issued guidance and evaluate the impact on future net income, cash flows and financial condition.

The enactment of the IRA will have future cash flow and income tax reporting considerations. AEP and subsidiaries expect to be applicable CAMT corporations beginning in 2023 and AEP expects to have CAMT cash tax payments beginning in 2024. CAMT cash taxes are expected to be offset by regulatory recovery, the utilization of tax credits and additionally, the cash inflow generated by the sale of tax credits. The sale of tax credits will be presented in the operating section of the cash flow statement consistent with the presentation of cash taxes paid. AEP will present the gain or loss on sale of tax credits through income tax expense on the statement of income. Management believes this presentation provides consistency in financial statement reporting as it matches the originating income tax benefit of the tax credit.

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.

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

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

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

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

Management employs risk management contracts including physical forward and financial forward purchase-and-sale contracts. Management engages in risk management of power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. As a result, AEP is subject to price risk. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the 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 Commercial Officer, Executive Vice President Utilities, Senior Vice President of Regulated Commercial Operations, 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, Chief Commercial Officer, Senior Vice President of Treasury and Risk, Senior Vice President of Competitive Commercial Operations and Chief Risk Officer. 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.

Due to multiple defaults of market participants, ERCOT had a large outstanding unpaid balance associated with the February 2021 winter storm. A certain portion of this balance has been securitized and disbursed to impacted market participants. A recovery plan has been reached by ERCOT for the remaining portion of the outstanding balance. In both cases, financial costs are allocated to certain market participants and in the 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, 2021:


MTM Risk Management Contract Net Assets (Liabilities)
Year Ended December 31, 2022

	Vertically Integrated Utilities		Transmission and Distribution Utilities		Generation & Marketing		Total
	(in millions)
Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2021	$	59.8	$	(91.4)	$	275.9	$	244.3
(Gain)/Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period	(75.5)		5.7		(66.0)		(135.8)
Fair Value of New Contracts at Inception When Entered During the Period (a)	—		—		0.9		0.9
Changes in Fair Value Due to Market Fluctuations During the Period (b)	10.7		—		149.7		160.4
Changes in Fair Value Allocated to Regulated Jurisdictions (c)	133.7		45.7		—		179.4
MTM Risk Management Contract Net Assets Held for Sale Related to KPCo (d)	(2.5)		—		—		(2.5)
Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2022	$	126.2	$	(40.0)	$	360.5	446.7
Commodity Cash Flow Hedge Contracts							283.3
Interest Rate Cash Flow Hedge Contracts							11.0
Fair Value Hedge Contracts							(127.4)
Collateral Deposits							(479.6)

Total MTM Derivative Contract Net Assets as of December 31, 2022							$	134.0

(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 on the balance sheet.

(d)MTM risk management contract net assets relating to KPCo are classified as Assets Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.

See Note 10 – Derivatives and Hedging and Note 11 – Fair Value Measurements for additional information related to risk management contracts. The following tables and discussion provide information on credit risk and market volatility risk.

Credit Risk

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

AEP has risk management contracts (includes non-derivative contracts) with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, exposures change daily. As of December 31, 2022, credit exposure net of collateral to sub investment grade counterparties was approximately 0.6%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss).

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As of December 31, 2022, 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	$	691.0	$	236.7	$	454.3	2	$	131.2


Split Rating	9.0		—		9.0		1	9.0
Noninvestment Grade	2.3		2.2		0.1		1	0.1
No External Ratings:
Internal Investment Grade	41.2		—		41.2		2	24.8
Internal Noninvestment Grade	5.2		2.5		2.7		3	2.5
Total as of December 31, 2022	$	748.7	$	241.4	$	507.3

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

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

Value at Risk (VaR) Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates VaR, to measure AEP’s commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, as of December 31, 2022, 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.

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

VaR Model

Trading Portfolio


Twelve Months Ended								Twelve Months Ended
December 31, 2022								December 31, 2021
End		High		Average		Low		End		High		Average		Low
(in millions)								(in millions)
$	0.5	$	4.5	$	0.7	$	0.1	$	0.4	$	3.6	$	0.4	$	0.1

VaR Model

Non-Trading Portfolio


Twelve Months Ended								Twelve Months Ended
December 31, 2022								December 31, 2021
End		High		Average		Low		End		High		Average		Low
(in millions)								(in millions)
$	17.7	$	76.9	$	24.7	$	6.7	$	8.3	$	14.9	$	3.7	$	0.7

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. Prior to 2022, interest rates remained at low levels and the Federal Reserve maintained the federal funds target range at 0.0% to 0.25% for much of 2021. However, during 2022, the Federal Reserve approved rate increases totaling 4.25%. The Federal Reserve has indicated that, in light of continued signs of inflation, it foresees further increases in interest rates in 2023. AEP has outstanding short and long-term debt which is subject to variable rates. 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 twelve months ended December 31, 2022, 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 $47 million, $33 million and $32 million, respectively.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

American Electric Power Company, Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of American Electric Power Company, Inc. and its subsidiaries (the “Company”) as of December 31, 2022 and 2021 and the related consolidated statements of income, of comprehensive income (loss), of changes in equity and of cash flows for each of the three years in the period ended December 31, 2022, including the related notes and financial statement schedules listed in the index appearing under Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis for Opinions

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

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

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

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Definition and Limitations of Internal Control over Financial Reporting

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

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

Critical Audit Matters

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

Accounting for the Effects of Cost-Based Regulation

As described in Notes 1 and 5 to the consolidated financial statements, the Company's consolidated financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. As of December 31, 2022, there were $5.6 billion of deferred costs included in regulatory assets, $0.8 billion of which were pending final regulatory approval, and $8.0 billion of regulatory liabilities awaiting potential refund or future rate reduction, $0.2 billion of which were pending final regulatory determination. Regulatory assets (deferred expenses) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation.

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

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assets and refund of regulatory liabilities. These procedures also included, among others, evaluating the reasonableness of management's assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities. Testing of regulatory assets and liabilities, involved evaluating the provisions and formulas outlined in rate orders, other regulatory correspondence, application of relevant regulatory precedents, and other relevant evidence.

Valuation of Level 3 Risk Management Commodity Contracts

As described in Notes 1, 10 and 11 to the consolidated financial statements, the Company employs risk management commodity contracts including physical and financial forward purchase and sale contracts and, to a lesser extent, over-the-counter swaps and options to accomplish its risk management strategies. Certain over-the-counter and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. As disclosed by management, the fair value of these risk management commodity contracts is estimated based on the best market information available, including valuation models that estimate future energy prices based on existing market and broker quotes, and other assumptions. Fair value estimates, based upon the best market information available, involve uncertainties and matters of significant judgment including forward market price assumptions. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. Management utilized such unobservable pricing inputs to value its Level 3 risk management commodity contract assets and liabilities, which totaled $332.5 million and $180.6 million, as of December 31, 2022, respectively.

The principal considerations for our determination that performing procedures relating to the valuation of Level 3 risk management commodity contracts is a critical audit matter are the significant judgment by management when developing the fair value of the commodity contracts; this in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence relating to the forward market price assumptions used in management's valuation models. In addition, the audit effort involved the use of professionals with specialized skill and knowledge.

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

Classification of the Assets and Liabilities of KPCo and KTCo as Held for Sale

As described in Note 7 to the consolidated financial statements, in October 2021 the Company entered into a Stock Purchase Agreement (SPA) to sell Kentucky Power Company (KPCo) and Kentucky Transmission Company (KTCo) to Liberty Utilities Co. (Liberty) for $2.85 billion. In September 2022, the Company and Liberty entered into an amendment to the SPA which reduced the purchase price to approximately $2.646 billion. The sale is subject to several regulatory approvals, including approval from the Kentucky Public Service Commission (KPSC) and from the Federal Energy Regulatory Commission (FERC). In May 2022, the KPSC approved the transfer of KPCo to Liberty subject to conditions contingent upon the closing of the sale. In December 2022, the FERC issued an order denying, without prejudice, authorization of the proposed sale stating the applicants failed to demonstrate the proposed transaction will not have adverse effect on rates. In January 2023, the Company and Liberty entered into an amendment to the SPA that specified the applicants will submit a new filing for approval under Section 203 of the Federal Power Act. The new filing was submitted to the FERC on February 14, 2023. Management believes it is probable that FERC authorization under Section 203 of the Federal Power Act will be received and closing will

129

occur in 2023. Therefore, the assets and liabilities of KPCO and KTCo will continue to be classified as held for sale as of December 31, 2022.

The principal considerations for our determination that performing procedures relating to the classification of the assets and liabilities of KPCo and KTCo is a critical audit matter are the significant judgment by management in determining the classification of the assets and liabilities as held for sale, and in assessing the impact of regulatory orders and other relevant evidence; this in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence related to the probability that a sale of the assets and liabilities of KPCO and KTCo will occur resulting in held for sale classification as of December 31, 2022.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management's determination of the classification of the assets and liabilities of KPCo and KTCo as held for sale. These procedures also included, among others, evaluating management’s determination of the classification of KPCo and KTCo as held for sale which involved i) evaluating the reasonableness of management's assessment of probability of the sale to occur resulting in held for sale classification as of the balance sheet date ii) evaluating the commitment of both parties to the sale as supported by public statements and other representations, iii) evaluating guidance in applicable regulatory orders and other regulatory correspondence, iv) consideration of relevant regulatory and legal precedents, and v) reviewing written agreements in place between the parties related to the sale.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio

February 23, 2023

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

130

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

Management assessed the effectiveness of AEP’s internal control over financial reporting as of December 31, 2022. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework (2013). Based on management’s assessment, management concluded AEP’s internal control over financial reporting was effective as of December 31, 2022.

PricewaterhouseCoopers LLP, AEP’s independent registered public accounting firm has issued an audit report on the effectiveness of AEP’s internal control over financial reporting as of December 31, 2022. The Report of Independent Registered Public Accounting Firm appears on the previous page.

131

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2022, 2021 and 2020

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


	Years Ended December 31,
	2022		2021		2020
REVENUES
Vertically Integrated Utilities	$	11,292.8	$	9,852.2	$	8,753.2
Transmission and Distribution Utilities	5,489.6		4,464.1		4,238.7
Generation & Marketing	2,448.9		2,108.3		1,621.0
Other Revenues	408.2		367.4		305.6
TOTAL REVENUES	19,639.5		16,792.0		14,918.5
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	7,097.9		5,466.3		4,369.7

Other Operation	2,878.1		2,547.7		2,572.4
Maintenance	1,249.4		1,121.8		1,010.4
Loss on the Expected Sale of the Kentucky Operations	363.3		—		—
Asset Impairments and Other Related Charges	48.8		11.6		—
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset	(37.0)		—		—
Gain on Sale of Mineral Rights	(116.3)		—		—
Depreciation and Amortization	3,202.8		2,825.7		2,682.8
Taxes Other Than Income Taxes	1,469.8		1,407.6		1,295.5
TOTAL EXPENSES	16,156.8		13,380.7		11,930.8

OPERATING INCOME	3,482.7		3,411.3		2,987.7

Other Income (Expense):


Other Income	11.6		41.4		57.0
Allowance for Equity Funds Used During Construction	133.7		139.7		148.1
Non-Service Cost Components of Net Periodic Benefit Cost	188.5		118.6		119.0

Interest Expense	(1,396.1)		(1,199.1)		(1,165.7)

INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS (LOSS)	2,420.4		2,511.9		2,146.1

Income Tax Expense	5.4		115.5		40.5
Equity Earnings (Loss) of Unconsolidated Subsidiaries	(109.4)		91.7		91.1





NET INCOME	2,305.6		2,488.1		2,196.7

Net Income (Loss) Attributable to Noncontrolling Interests	(1.6)		—		(3.4)

EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	2,307.2	$	2,488.1	$	2,200.1

WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING	511,841,946		500,522,177		495,718,223



TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	4.51	$	4.97	$	4.44

WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING	513,484,609		501,784,032		497,226,867



TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	4.49	$	4.96	$	4.42

See Notes to Financial Statements of Registrants beginning on page 228.

132

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	Years Ended December 31,
	2022		2021		2020
Net Income	$	2,305.6	$	2,488.1	$	2,196.7

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $21.6, $66.6 and $1.8 in 2022, 2021 and 2020, Respectively	81.4		250.5		6.9

Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(2.8), $(2.2) and $(1.9) in 2022, 2021 and 2020, Respectively	(10.4)		(8.1)		(7.0)
Pension and OPEB Funded Status, Net of Tax of $(41.3), $7.3 and $16.7 in 2022, 2021 and 2020, Respectively	(155.4)		27.5		62.7
Reclassifications of KPCo Pension and OPEB Regulatory Assets, Net of Tax of $(4.4), $0 and $0 in 2022, 2021 and 2020, Respectively	(16.7)		—		—

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(101.1)		269.9		62.6

TOTAL COMPREHENSIVE INCOME	2,204.5		2,758.0		2,259.3

Total Comprehensive Loss Attributable To Noncontrolling Interests	(1.6)		—		(3.4)

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	2,206.1	$	2,758.0	$	2,262.7

See Notes to Financial Statements of Registrants beginning on page 228.

133

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


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

Issuance of Common Stock	2.4	15.9		139.1										155.0
Common Stock Dividends							(1,415.0)		(a)			(9.9)		(1,424.9)
Other Changes in Equity				(85.8)		(b)						(0.4)		(86.2)
ASU 2016-13 Adoption							1.8							1.8
Acquisition of Incremental Interest in Santa Rita East												(43.7)		(43.7)
Net Income (Loss)							2,200.1					(3.4)		2,196.7
Other Comprehensive Income										62.6				62.6
TOTAL EQUITY – DECEMBER 31, 2020	516.8	3,359.3		6,588.9			10,687.8			(85.1)		223.6		20,774.5

Issuance of Common Stock	7.6	49.4		551.1										600.5
Common Stock Dividends							(1,507.7)		(a)			(11.8)		(1,519.5)
Other Changes in Equity				32.6			(1.1)					16.3		47.8

Acquisition of Dry Lake Solar Project												18.9		18.9
Net Income							2,488.1					—		2,488.1
Other Comprehensive Income										269.9				269.9
TOTAL EQUITY – DECEMBER 31, 2021	524.4	3,408.7		7,172.6			11,667.1			184.8		247.0		22,680.2

Issuance of Common Stock	0.7	4.4		822.1										826.5
Common Stock Dividends							(1,628.7)		(a)			(16.5)		(1,645.2)
Other Changes in Equity				56.3								0.1		56.4


Net Income (Loss)							2,307.2					(1.6)		2,305.6
Other Comprehensive Loss										(101.1)				(101.1)
TOTAL EQUITY – DECEMBER 31, 2022	525.1	$	3,413.1	$	8,051.0		$	12,345.6		$	83.7	$	229.0	$	24,122.4

(a) Cash dividends declared per AEP common share were $3.17, $3.00 and $2.84 for the years ended December 31, 2022, 2021 and 2020, respectively.

(b) Includes $(121) million related to a forward equity purchase contract associated with the issuance of Equity Units. See “Equity Units” section of Note 14 for additional information.


See Notes to Financial Statements of Registrants beginning on page 228.

134

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2022 and 2021

(in millions)


	December 31,
	2022		2021
CURRENT ASSETS
Cash and Cash Equivalents	$	509.4	$	403.4
Restricted Cash (December 31, 2022 and 2021 Amounts Include $47.1 and $48, Respectively, Related to Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Santa Rita East)	47.1		48.0
Other Temporary Investments (December 31, 2022 and 2021 Amounts Include $182.9 and $214.8, Respectively, Related to EIS and Transource Energy)	187.5		220.4
Accounts Receivable:
Customers	1,081.5		720.9
Accrued Unbilled Revenues	287.9		204.4
Pledged Accounts Receivable – AEP Credit	1,207.4		1,038.0
Miscellaneous	49.6		33.9
Allowance for Uncollectible Accounts	(56.1)		(55.6)
Total Accounts Receivable	2,570.3		1,941.6
Fuel	413.2		307.9
Materials and Supplies	888.9		681.3
Risk Management Assets	340.4		194.4
Accrued Tax Benefits	99.4		121.5
Regulatory Asset for Under-Recovered Fuel Costs	1,286.8		647.8
Margin Deposits	81.9		193.4
Assets Held for Sale	2,823.5		2,919.7
Prepayments and Other Current Assets	170.3		129.8
TOTAL CURRENT ASSETS	9,418.7		7,809.2

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	24,597.7		23,088.1
Transmission	32,312.9		29,911.1
Distribution	26,077.2		24,440.0
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	6,142.1		5,682.9
Construction Work in Progress	4,664.1		3,684.3
Total Property, Plant and Equipment	93,794.0		86,806.4
Accumulated Depreciation and Amortization	22,511.1		20,805.1
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	71,282.9		66,001.3

OTHER NONCURRENT ASSETS
Regulatory Assets	4,281.2		4,142.3
Securitized Assets	446.0		552.8
Spent Nuclear Fuel and Decommissioning Trusts	3,341.2		3,867.0
Goodwill	52.5		52.5
Long-term Risk Management Assets	284.1		267.0
Operating Lease Assets	645.0		578.3
Deferred Charges and Other Noncurrent Assets	3,717.8		4,398.3
TOTAL OTHER NONCURRENT ASSETS	12,767.8		13,858.2

TOTAL ASSETS	$	93,469.4	$	87,668.7

See Notes to Financial Statements of Registrants beginning on page 228.

135

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

December 31, 2022 and 2021

(dollars in millions)


			December 31,
			2022		2021
CURRENT LIABILITIES
Accounts Payable			$	2,613.0	$	2,054.6
Short-term Debt:
Securitized Debt for Receivables – AEP Credit			750.0		750.0
Other Short-term Debt			3,362.2		1,864.0
Total Short-term Debt			4,112.2		2,614.0
Long-term Debt Due Within One Year (December 31, 2022 and 2021 Amounts Include $218.2 and $190.5, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)			1,996.4		2,153.8
Risk Management Liabilities			145.2		75.4
Customer Deposits			370.0		321.6
Accrued Taxes			1,672.8		1,586.4
Accrued Interest			327.6		273.2
Obligations Under Operating Leases			113.4		97.6

Liabilities Held for Sale			1,955.7		1,880.9
Other Current Liabilities			1,261.1		1,369.2
TOTAL CURRENT LIABILITIES			14,567.4		12,426.7

NONCURRENT LIABILITIES
Long-term Debt (December 31, 2022 and 2021 Amounts Include $755.3 and $840.5, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)			33,626.2		31,300.7
Long-term Risk Management Liabilities			345.3		230.3
Deferred Income Taxes			8,493.3		8,202.5
Regulatory Liabilities and Deferred Investment Tax Credits			7,999.6		8,686.3
Asset Retirement Obligations			2,860.8		2,676.2
Employee Benefits and Pension Obligations			257.3		328.4
Obligations Under Operating Leases			552.1		492.8
Deferred Credits and Other Noncurrent Liabilities			599.1		601.3
TOTAL NONCURRENT LIABILITIES			54,733.7		52,518.5

TOTAL LIABILITIES			69,301.1		64,945.2

Rate Matters (Note 4)
Commitments and Contingencies (Note 6)

MEZZANINE EQUITY

Contingently Redeemable Performance Share Awards			45.9		43.3
TOTAL MEZZANINE EQUITY			45.9		43.3

EQUITY
Common Stock – Par Value – $6.50 Per Share:
	2022	2021
Shares Authorized	600,000,000	600,000,000
Shares Issued	525,099,321	524,416,175
(11,233,240 and 20,204,160 Shares were Held in Treasury as of December 31, 2022 and 2021, Respectively)			3,413.1		3,408.7
Paid-in Capital			8,051.0		7,172.6
Retained Earnings			12,345.6		11,667.1
Accumulated Other Comprehensive Income (Loss)			83.7		184.8
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY			23,893.4		22,433.2

Noncontrolling Interests			229.0		247.0

TOTAL EQUITY			24,122.4		22,680.2

TOTAL LIABILITIES, MEZZANINE EQUITY AND EQUITY			$	93,469.4	$	87,668.7

See Notes to Financial Statements of Registrants beginning on page 228.

136

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	Years Ended December 31,
	2022		2021		2020
OPERATING ACTIVITIES
Net Income	$	2,305.6	$	2,488.1	$	2,196.7


Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	3,202.8		2,825.7		2,682.8
Rockport Plant, Unit 2 Lease Amortization	—		135.4		136.5
Deferred Income Taxes	(137.2)		107.6		196.1

Loss on the Expected Sale of the Kentucky Operations	363.3		—		—
Asset Impairments and Other Related Charges	48.8		11.6		—

Impairment of Equity Method Investment	188.0		—		—
Allowance for Equity Funds Used During Construction	(133.7)		(139.7)		(148.1)
Mark-to-Market of Risk Management Contracts	15.5		112.3		66.5
Amortization of Nuclear Fuel	82.9		85.3		87.5

Pension Contributions to Qualified Plan Trust	—		—		(110.3)
Property Taxes	(41.2)		(68.0)		(43.3)
Deferred Fuel Over/Under-Recovery, Net	(319.2)		(1,647.9)		(31.8)




Gain on Sale of Mineral Rights	(116.3)		—		—
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset	(37.0)		—		—
Change in Regulatory Assets	(46.7)		(238.9)		(337.9)
Change in Other Noncurrent Assets	(187.7)		(126.6)		(151.0)
Change in Other Noncurrent Liabilities	337.8		206.4		(54.5)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(681.7)		(119.7)		(129.3)
Fuel, Materials and Supplies	(313.9)		300.2		(142.9)
Accounts Payable	489.2		200.6		(35.3)
Accrued Taxes, Net	105.4		218.7		20.1
Rockport Plant, Unit 2 Operating Lease Payments	—		(147.7)		(147.7)
Other Current Assets	109.0		(151.3)		34.3
Other Current Liabilities	54.3		(212.2)		(255.5)
Net Cash Flows from Operating Activities	5,288.0		3,839.9		3,832.9

INVESTING ACTIVITIES
Construction Expenditures	(6,671.7)		(5,659.6)		(6,246.3)

Purchases of Investment Securities	(2,784.2)		(1,955.1)		(1,678.8)
Sales of Investment Securities	2,743.8		1,901.4		1,644.3
Acquisitions of Nuclear Fuel	(100.7)		(104.5)		(69.7)

Acquisition of the Dry Lake Solar Project	—		(114.4)		—
Acquisition of the North Central Wind Energy Facilities	(1,207.3)		(652.8)		—
Proceeds from Sales of Assets	218.0		118.9		71.1
Other Investing Activities	50.3		32.2		45.5
Net Cash Flows Used for Investing Activities	(7,751.8)		(6,433.9)		(6,233.9)

FINANCING ACTIVITIES
Issuance of Common Stock, Net	826.5		600.5		155.0
Issuance of Long-term Debt	4,649.7		6,486.3		5,626.1
Issuance of Short-term Debt with Original Maturities greater than 90 Days	833.9		1,393.3		1,396.5
Change in Short-term Debt with Original Maturities less than 90 Day, Net	1,650.4		(487.3)		(448.4)
Retirement of Long-term Debt	(2,345.4)		(2,989.3)		(1,339.8)
Redemption of Short-term Debt with Original Maturities greater than 90 Days	(986.1)		(771.3)		(1,307.1)


Principal Payments for Finance Lease Obligations	(309.5)		(64.0)		(61.7)
Dividends Paid on Common Stock	(1,645.2)		(1,519.5)		(1,424.9)
Redemption of Noncontrolling Interests	—		—		(100.2)
Other Financing Activities	(105.4)		(41.6)		(88.8)
Net Cash Flows from Financing Activities	2,568.9		2,607.1		2,406.7





Net Increase in Cash, Cash Equivalents and Restricted Cash	105.1		13.1		5.7
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	451.4		438.3		432.6
Cash, Cash Equivalents and Restricted Cash at End of Period	$	556.5	$	451.4	$	438.3

See Notes to Financial Statements of Registrants beginning on page 228.

137

AEP TEXAS INC.

AND SUBSIDIARIES

138

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

	Years Ended December 31,
	2022	2021	2020
	(in millions of KWhs)
Retail:
Residential	13,049	12,284	12,163
Commercial	11,435	10,477	10,065
Industrial	11,347	9,598	9,085
Miscellaneous	643	625	636
Total Retail	36,474	32,984	31,949

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


Summary of Heating and Cooling Degree Days

	Years Ended December 31,
	2022	2021	2020
	(in degree days)
Actual – Heating (a)	450	341	189
Normal – Heating (b)	312	310	313

Actual – Cooling (c)	2,984	2,653	2,846
Normal – Cooling (b)	2,714	2,712	2,711

(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.

139

2022 Compared to 2021

AEP Texas Inc. and Subsidiaries

Reconciliation of Year Ended December 31, 2021 to Year Ended December 31, 2022

Net Income

(in millions)


Year Ended December 31, 2021	$	289.8

Changes in Revenues:
Retail Revenues	184.3

Transmission Revenues	66.3
Other Revenues	2.4
Total Change in Revenues	253.0

Changes in Expenses and Other:
Other Operation and Maintenance	(112.0)

Depreciation and Amortization	(65.4)
Taxes Other Than Income Taxes	(2.4)
Interest Income	2.8
Allowance for Equity Funds Used During Construction	(1.8)
Non-Service Cost Components of Net Periodic Benefit Cost	5.6
Interest Expense	(32.2)
Total Change in Expenses and Other	(205.4)

Income Tax Expense	(29.5)


Year Ended December 31, 2022	$	307.9

The major components of the increase in revenues were as follows:

•Retail Revenues increased $184 million primarily due to the following:

•A $72 million increase due to interim rate increases driven by increased transmission investment.

•A $33 million increase in interim rate due to increased distribution investment.

•A $30 million increase due to prior year refunds of Excess ADIT to customers. This increase was partially offset in Income Tax Expense below.

•A $23 million increase in weather-related usage primarily due to a 12% increase in cooling degree days and a 32% increase in heating degree days.

•A $19 million increase in revenue from rate riders. This increase was partially offset in other expense items below.

•An $8 million increase in weather-normalized revenues in all retail classes.

•Transmission Revenues increased $66 million primarily due to the following:

•A $59 million increase due to interim rate increases driven by increased transmission investment.

•A $7 million increase due to prior year refunds to customers associated with the last base rate case. This impact was offset in Other Revenues below.

140

•Other Revenues increased $2 million primarily due to the following:

•A $26 million increase primarily due to securitization revenues driven by the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020 and final refunds that were completed in 2021. This increase was offset in Depreciation and Amortization expenses and Interest Expense below.

This increase was partially offset by:

•A $12 million decrease due to the prior year amortization of a provision for refund recorded associated with the last base rate case. This decrease was offset in Retail Revenues and Transmission Revenues above.

•A $7 million decrease in energy efficiency revenues.

•A $4 million decrease in pole attachment revenue primarily due to provision for refund.

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

•Other Operation and Maintenance expenses increased $112 million primarily due to the following:

•A $76 million increase in ERCOT transmission expenses. This increase was partially offset in Retail Revenues and Transmission Revenues above.

•An $11 million increase in distribution-related expenses.

•A $10 million increase due to a charitable contribution to the AEP Foundation.

•A $7 million increase in employee-related expenses.

•A $5 million increase in vegetation management expenses.

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

•A $29 million increase due to a higher depreciable base.

•A $27 million increase in securitization amortizations primarily due to prior year AEP Texas Central Transition Funding II LLC bonds that matured in July 2020 and final refunds that were completed in 2021. This increase was offset in Other Revenues above.

•A $7 million increase in recoverable advanced metering system depreciable expenses.

•Non-Service Cost Components of Net Periodic Benefit Cost decreased $6 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.

•Interest Expense increased $32 million primarily due to higher long-term debt balances and higher interest rates.

•Income Tax Expense increased $30 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 in Retail Revenues above.

141

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

AEP Texas Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of AEP Texas Inc and its subsidiaries (the “Company”) as of December 31, 2022 and 2021 and the related consolidated statements of income, of comprehensive income (loss), of changes in common shareholder’s equity and of cash flows for each of the three years in the period ended December 31, 2022, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

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

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

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

Critical Audit Matters

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

142

Accounting for the Effects of Cost-Based Regulation

As described in Notes 1 and 5 to the consolidated financial statements, the Company's consolidated financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. As of December 31, 2022, there were $298 million of deferred costs included in regulatory assets, $67 million of which were pending final regulatory approval, and $1,260 million of regulatory liabilities awaiting potential refund or future rate reduction, $15 million of which were pending final regulatory determination. Regulatory assets (deferred expenses) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management's evaluation of new events, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation, including the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, evaluating the reasonableness of management's assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities. Testing of regulatory assets and liabilities, involved evaluating the provisions and formulas outlined in rate orders, other regulatory correspondence, application of relevant regulatory precedents, and other relevant evidence.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio

February 23, 2023

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

143

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

Management assessed the effectiveness of AEP Texas’ internal control over financial reporting as of December 31, 2022. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework (2013). Based on management’s assessment, management concluded AEP Texas’ internal control over financial reporting was effective as of December 31, 2022.

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

144

AEP TEXAS INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	Years Ended December 31,
	2022		2021		2020
REVENUES
Electric Transmission and Distribution	$	1,839.7	$	1,586.4	$	1,524.9
Sales to AEP Affiliates	3.5		3.9		90.8
Other Revenues	3.6		3.5		3.2
TOTAL REVENUES	1,846.8		1,593.8		1,618.9

EXPENSES
Fuel and Other Consumables Used for Electric Generation	—		—		13.7
Other Operation	594.2		489.5		488.9
Maintenance	93.5		86.2		80.5

Depreciation and Amortization	452.4		387.0		529.8
Taxes Other Than Income Taxes	157.5		155.1		136.4
TOTAL EXPENSES	1,297.6		1,117.8		1,249.3

OPERATING INCOME	549.2		476.0		369.6

Other Income (Expense):
Interest Income	3.6		0.8		1.4

Allowance for Equity Funds Used During Construction	19.7		21.5		19.4

Non-Service Cost Components of Net Periodic Benefit Cost	16.7		11.1		11.2
Interest Expense	(208.7)		(176.5)		(171.8)

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	380.5		332.9		229.8

Income Tax Expense (Benefit)	72.6		43.1		(11.2)

NET INCOME	$	307.9	$	289.8	$	241.0

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

See Notes to Financial Statements of Registrants beginning on page 228.

145

AEP TEXAS INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	Years Ended December 31,
	2022		2021		2020
Net Income	$	307.9	$	289.8	$	241.0

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $0.3, $0.3 and $0.3 in 2022, 2021 and 2020, Respectively	1.0		1.0		1.1
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0, $0 and $0 in 2022, 2021 and 2020, Respectively	0.1		0.2		0.2
Pension and OPEB Funded Status, Net of Tax of $(0.9), $0.3 and $0.7 in 2022, 2021 and 2020, Respectively	(3.2)		1.2		2.6

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(2.1)		2.4		3.9

TOTAL COMPREHENSIVE INCOME	$	305.8	$	292.2	$	244.9

See Notes to Financial Statements of Registrants beginning on page 228.

146

AEP TEXAS INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	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			241.0				241.0
Other Comprehensive Income					3.9		3.9
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020	1,457.9		1,757.0		(8.9)		3,206.0

Capital Contribution from Parent	96.0						96.0


Net Income			289.8				289.8
Other Comprehensive Income					2.4		2.4
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2021	1,553.9		2,046.8		(6.5)		3,594.2

Capital Contribution from Parent	4.3						4.3

Net Income			307.9				307.9
Other Comprehensive Loss					(2.1)		(2.1)
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2022	$	1,558.2	$	2,354.7	$	(8.6)	$	3,904.3

See Notes to Financial Statements of Registrants beginning on page 228.

147

AEP TEXAS INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2022 and 2021

(in millions)


	December 31,
	2022		2021
CURRENT ASSETS
Cash and Cash Equivalents	$	0.1	$	0.1
Restricted Cash (December 31, 2022 and 2021 Amounts Include $32.7 and $30.4, Respectively, Related to Transition Funding and Restoration Funding)	32.7		30.4
Advances to Affiliates	6.9		6.9
Accounts Receivable:
Customers	150.9		123.4
Affiliated Companies	11.9		7.9
Accrued Unbilled Revenues	91.4		77.9
Miscellaneous	0.2		—
Allowance for Uncollectible Accounts	(4.2)		(4.0)
Total Accounts Receivable	250.2		205.2

Materials and Supplies	138.8		73.9

Accrued Tax Benefits	12.2		24.8
Prepayments and Other Current Assets	6.0		5.9
TOTAL CURRENT ASSETS	446.9		347.2

PROPERTY, PLANT AND EQUIPMENT
Electric:

Transmission	6,301.5		5,849.9
Distribution	5,312.8		4,917.2
Other Property, Plant and Equipment	1,022.8		961.1
Construction Work in Progress	805.2		551.3
Total Property, Plant and Equipment	13,442.3		12,279.5
Accumulated Depreciation and Amortization	1,760.7		1,644.1
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	11,681.6		10,635.4

OTHER NONCURRENT ASSETS
Regulatory Assets	298.3		275.2
Securitized Assets (December 31, 2022 and 2021 Amounts Include $286.4 and $367.6, Respectively, Related to Transition Funding and Restoration Funding)	286.4		367.6

Deferred Charges and Other Noncurrent Assets	179.0		211.3
TOTAL OTHER NONCURRENT ASSETS	763.7		854.1

TOTAL ASSETS	$	12,892.2	$	11,836.7

See Notes to Financial Statements of Registrants beginning on page 228.

148

AEP TEXAS INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

December 31, 2022 and 2021

(in millions)


	December 31,
	2022		2021
CURRENT LIABILITIES
Advances from Affiliates	$	96.5	$	26.9
Accounts Payable:
General	331.0		306.3
Affiliated Companies	34.7		32.5
Long-term Debt Due Within One Year – Nonaffiliated (December 31, 2022 and 2021 Amounts Include $93.5 and $91, Respectively, Related to Transition Funding and Restoration Funding)	278.5		716.0


Accrued Taxes	95.5		93.3
Accrued Interest (December 31, 2022 and 2021 Amounts Include $2.2 and $2.3, Respectively, Related to Transition Funding and Restoration Funding)	48.3		44.7

Obligations Under Operating Leases	28.6		14.0

Other Current Liabilities	130.7		78.0
TOTAL CURRENT LIABILITIES	1,043.8		1,311.7

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated (December 31, 2022 and 2021 Amounts Include $221 and $313.7, Respectively, Related to Transition Funding and Restoration Funding)	5,379.3		4,464.8

Deferred Income Taxes	1,144.2		1,088.9
Regulatory Liabilities and Deferred Investment Tax Credits	1,259.6		1,242.0

Obligations Under Operating Leases	67.8		61.3
Deferred Credits and Other Noncurrent Liabilities	93.2		73.8
TOTAL NONCURRENT LIABILITIES	7,944.1		6,930.8

TOTAL LIABILITIES	8,987.9		8,242.5

Rate Matters (Note 4)
Commitments and Contingencies (Note 6)

COMMON SHAREHOLDER’S EQUITY



Paid-in Capital	1,558.2		1,553.9
Retained Earnings	2,354.7		2,046.8
Accumulated Other Comprehensive Income (Loss)	(8.6)		(6.5)
TOTAL COMMON SHAREHOLDER’S EQUITY	3,904.3		3,594.2

TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY	$	12,892.2	$	11,836.7

See Notes to Financial Statements of Registrants beginning on page 228.

149

AEP TEXAS INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	Years Ended December 31,
	2022		2021		2020
OPERATING ACTIVITIES
Net Income	$	307.9	$	289.8	$	241.0
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	452.4		387.0		529.8
Deferred Income Taxes	42.2		43.0		(15.2)

Allowance for Equity Funds Used During Construction	(19.7)		(21.5)		(19.4)

Pension Contributions to Qualified Plan Trust	—		—		(11.3)


Change in Other Noncurrent Assets	(36.2)		(78.2)		(74.0)
Change in Other Noncurrent Liabilities	57.6		26.4		(24.7)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(45.0)		(21.6)		9.8
Fuel, Materials and Supplies	(64.9)		(3.9)		(7.4)
Accounts Payable	25.0		8.9		30.2

Accrued Taxes, Net	14.8		7.0		42.7

Other Current Assets	2.2		(0.9)		0.8
Other Current Liabilities	(4.4)		(39.4)		(88.1)
Net Cash Flows from Operating Activities	731.9		596.6		614.2

INVESTING ACTIVITIES
Construction Expenditures	(1,305.0)		(1,033.3)		(1,295.0)
Change in Advances to Affiliates, Net	—		0.2		200.1

Other Investing Activities	35.1		32.3		29.5
Net Cash Flows Used for Investing Activities	(1,269.9)		(1,000.8)		(1,065.4)

FINANCING ACTIVITIES
Capital Contribution from Parent	4.3		96.0		—
Issuance of Long-term Debt – Nonaffiliated	1,188.6		444.2		652.7
Change in Advances from Affiliates, Net	69.6		(40.2)		67.1
Retirement of Long-term Debt – Nonaffiliated	(716.0)		(88.7)		(392.1)
Principal Payments for Finance Lease Obligations	(6.8)		(6.7)		(6.3)

Other Financing Activities	0.6		1.3		0.8
Net Cash Flows from Financing Activities	540.3		405.9		322.2

Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	2.3		1.7		(129.0)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	30.5		28.8		157.8
Cash, Cash Equivalents and Restricted Cash at End of Period	$	32.8	$	30.5	$	28.8

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	198.9	$	168.9	$	153.2
Net Cash Paid (Received) for Income Taxes	11.0		5.7		(42.9)
Noncash Acquisitions Under Finance Leases	6.1		4.4		5.6
Construction Expenditures Included in Current Liabilities as of December 31,	235.4		230.0		177.8

See Notes to Financial Statements of Registrants beginning on page 228.

150

AEP TRANSMISSION COMPANY, LLC

AND SUBSIDIARIES

151

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 December 31,
	2022		2021		2020
	(in millions)
Plant In Service	$	12,635.1	$	11,313.7	$	9,923.0
CWIP	1,547.1		1,394.8		1,422.6
Accumulated Depreciation	1,012.1		772.8		572.8
Total Transmission Property, Net	$	13,170.1	$	11,935.7	$	10,772.8

2022 Compared to 2021

AEP Transmission Company, LLC and Subsidiaries

Reconciliation of Year Ended December 31, 2021 to Year Ended December 31, 2022

Net Income

(in millions)


Year Ended December 31, 2021	$	591.7

Changes in Transmission Revenues:
Transmission Revenues	155.2
Total Change in Transmission Revenues	155.2

Changes in Expenses and Other:
Other Operation and Maintenance	(29.6)
Depreciation and Amortization	(48.9)
Taxes Other Than Income Taxes	(32.3)
Interest Income - Affiliated	1.1
Allowance for Equity Funds Used During Construction	3.5
Interest Expense	(21.5)
Total Change in Expenses and Other	(127.7)

Income Tax Expense	(25.0)


Year Ended December 31, 2022	$	594.2

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

•Transmission Revenues increased $155 million primarily due to the following:

•A $185 million increase due to continued investment in transmission assets.

This increase was partially offset by:

•A $14 million decrease due to affiliated transmission formula rate true-up activity. This decrease was offset in Other Operation and Maintenance expense across the other Registrant Subsidiaries.

•A $5 million decrease due to non-affiliated transmission formula rate true-up activity.

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

•Other Operation and Maintenance expenses increased $30 million primarily due to:

•An $11 million increase due to a charitable contribution to the AEP Foundation.

•A $9 million increase in employee-related expenses.

•A $5 million increase due to cancelled capital projects.

152

•Depreciation and Amortization expenses increased $49 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $32 million primarily due to higher property taxes as a result of increased transmission investment.

•Allowance for Equity Funds Used During Construction increased $4 million primarily due to higher CWIP.

•Interest Expense increased $22 million primarily due to higher long-term debt balances.

•Income Tax Expense increased $25 million primarily due to the following:

•An $18 million increase due to a current year change in the accounting policy for the parent company loss benefit.

•A $6 million increase due to an increase in pretax book income.

153

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Member of

AEP Transmission Company, LLC

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of AEP Transmission Company, LLC and its subsidiaries (the “Company”) as of December 31, 2022 and 2021 and the related consolidated statements of income, of changes in member's equity and of cash flows for each of the three years in the period ended December 31, 2022, including the related notes and financial statement schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

Critical Audit Matters

154

Accounting for the Effects of Cost-Based Regulation

As described in Notes 1 and 5 to the consolidated financial statements, the Company's consolidated financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. As of December 31, 2022, there were $6.8 million of deferred costs included in regulatory assets and $715 million of regulatory liabilities awaiting potential refund or future rate reduction, $8.7 million of which were pending final regulatory determination. Regulatory assets (deferred expenses) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management's evaluation of new events, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation, including the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, evaluating the reasonableness of management's assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities. Testing of regulatory assets and liabilities, involved evaluating the provisions and formulas outlined in rate orders, other regulatory correspondence, application of relevant regulatory precedents, and other relevant evidence.

Classification of the Assets and Liabilities of KTCo as Held For Sale

The principal considerations for our determination that performing procedures relating to the classification of the assets and liabilities of KTCo is a critical audit matter are the significant judgment by management in determining the classification of the assets and liabilities as held for sale, and in assessing the impact of regulatory orders and other relevant evidence; this in turn led to a high degree of auditor judgment, subjectivity and effort in performing

155

procedures and evaluating audit evidence related to the probability that a sale of the assets and liabilities of KTCo will occur resulting in held for sale classification as of December 31, 2022.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management's determination of the classification of the assets and liabilities of KTCo as held for sale. These procedures also included, among others, evaluating management’s determination of the classification of KTCo as held for sale which involved i) evaluating the reasonableness of management's assessment of probability of the sale to occur resulting in held for sale classification as of the balance sheet date ii) evaluating the commitment of both parties to the sale as supported by public statements and other representations, iii) evaluating guidance in applicable regulatory orders and other regulatory correspondence, iv) consideration of relevant regulatory and legal precedents, and v) reviewing written agreements in place between the parties related to the sale.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio

February 23, 2023

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

156

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

Management assessed the effectiveness of AEPTCo’s internal control over financial reporting as of December 31, 2022. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework (2013). Based on management’s assessment, management concluded AEPTCo’s internal control over financial reporting was effective as of December 31, 2022.

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

157

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	Years Ended December 31,
	2022		2021		2020
REVENUES
Transmission Revenues	$	354.9	$	317.8	$	265.4
Sales to AEP Affiliates	1,354.5		1,171.5		954.6
Provision for Refund – Affiliated	(70.7)		(17.6)		(58.3)
Provision for Refund – Nonaffiliated	(14.2)		(2.4)		(16.0)

TOTAL REVENUES	1,624.5		1,469.3		1,145.7

EXPENSES
Other Operation	136.3		105.5		99.8
Maintenance	17.2		18.4		10.2
Depreciation and Amortization	346.2		297.3		249.0
Taxes Other Than Income Taxes	271.1		238.8		205.2
TOTAL EXPENSES	770.8		660.0		564.2

OPERATING INCOME	853.7		809.3		581.5

Other Income (Expense):
Interest Income - Affiliated	1.6		0.5		2.4
Allowance for Equity Funds Used During Construction	70.7		67.2		74.0
Interest Expense	(162.7)		(141.2)		(127.8)

INCOME BEFORE INCOME TAX EXPENSE	763.3		735.8		530.1

Income Tax Expense	169.1		144.1		106.7

NET INCOME	$	594.2	$	591.7	$	423.4

AEPTCo is wholly-owned by AEP Transmission Holdco.

See Notes to Financial Statements of Registrants beginning on page 228.

158

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


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

Capital Contribution from Member	335.0				335.0
Capital Distribution of Radial Assets to Member	(50.0)				(50.0)
Dividends Paid to Member			(5.0)		(5.0)
Net Income			423.4		423.4
TOTAL MEMBER'S EQUITY - DECEMBER 31, 2020	2,765.6		1,947.3		4,712.9

Capital Contribution from Member	184.0				184.0

Dividends Paid to Member			(112.5)		(112.5)
Net Income			591.7		591.7
TOTAL MEMBER'S EQUITY - DECEMBER 31, 2021	2,949.6		2,426.5		5,376.1

Capital Contribution from Member	72.7				72.7

Dividends Paid to Member			(170.0)		(170.0)
Net Income			594.2		594.2
TOTAL MEMBER'S EQUITY - DECEMBER 31, 2022	$	3,022.3	$	2,850.7	$	5,873.0

See Notes to Financial Statements of Registrants beginning on page 228.

159

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2022 and 2021

(in millions)


	December 31,
	2022		2021
CURRENT ASSETS
Advances to Affiliates	$	—	$	27.2
Accounts Receivable:
Customers	46.7		22.5
Affiliated Companies	117.9		96.1

Total Accounts Receivable	164.6		118.6
Materials and Supplies	10.7		9.3
Accrued Tax Benefits	4.2		5.6
Assets Held for Sale	178.0		167.9
Prepayments and Other Current Assets	3.0		2.7
TOTAL CURRENT ASSETS	360.5		331.3

TRANSMISSION PROPERTY
Transmission Property	12,183.2		10,886.3
Other Property, Plant and Equipment	451.9		427.4
Construction Work in Progress	1,547.1		1,394.8
Total Transmission Property	14,182.2		12,708.5
Accumulated Depreciation and Amortization	1,012.1		772.8
TOTAL TRANSMISSION PROPERTY – NET	13,170.1		11,935.7

OTHER NONCURRENT ASSETS

Regulatory Assets	6.8		8.5
Deferred Property Taxes	266.6		245.7
Deferred Charges and Other Noncurrent Assets	10.2		3.2
TOTAL OTHER NONCURRENT ASSETS	283.6		257.4

TOTAL ASSETS	$	13,814.2	$	12,524.4

See Notes to Financial Statements of Registrants beginning on page 228.

160

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND MEMBER’S EQUITY

December 31, 2022 and 2021


	December 31,
	2022		2021
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	229.3	$	124.0
Accounts Payable:
General	427.0		460.1
Affiliated Companies	81.9		69.9
Long-term Debt Due Within One Year – Nonaffiliated	60.0		104.0
Accrued Taxes	528.3		479.0
Accrued Interest	28.4		28.4
Obligations Under Operating Leases	1.3		0.9
Liabilities Held for Sale	28.6		27.6
Other Current Liabilities	8.4		3.0
TOTAL CURRENT LIABILITIES	1,393.2		1,296.9

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	4,722.8		4,239.9
Deferred Income Taxes	1,040.4		962.9
Regulatory Liabilities	715.0		644.1
Obligations Under Operating Leases	1.5		1.3
Deferred Credits and Other Noncurrent Liabilities	68.3		3.2
TOTAL NONCURRENT LIABILITIES	6,548.0		5,851.4

TOTAL LIABILITIES	7,941.2		7,148.3

Rate Matters (Note 4)
Commitments and Contingencies (Note 6)

MEMBER’S EQUITY
Paid-in Capital	3,022.3		2,949.6
Retained Earnings	2,850.7		2,426.5
TOTAL MEMBER’S EQUITY	5,873.0		5,376.1

TOTAL LIABILITIES AND MEMBER’S EQUITY	$	13,814.2	$	12,524.4

See Notes to Financial Statements of Registrants beginning on page 228.

161

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	Years Ended December 31,
	2022		2021		2020
OPERATING ACTIVITIES
Net Income	$	594.2	$	591.7	$	423.4
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	346.2		297.3		249.0
Deferred Income Taxes	62.3		68.5		81.6
Allowance for Equity Funds Used During Construction	(70.7)		(67.2)		(74.0)
Property Taxes	(20.9)		(25.6)		(26.6)

Change in Other Noncurrent Assets	(7.4)		7.5		(8.2)
Change in Other Noncurrent Liabilities	68.7		3.7		8.3
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(46.3)		(16.0)		(19.0)
Materials and Supplies	(1.4)		(0.8)		5.3
Accounts Payable	18.5		(2.2)		77.8
Accrued Taxes, Net	50.2		67.2		62.7

Other Current Assets	(1.1)		6.0		5.4
Other Current Liabilities	3.0		(4.4)		(14.5)
Net Cash Flows from Operating Activities	995.3		925.7		771.2

INVESTING ACTIVITIES
Construction Expenditures	(1,458.5)		(1,424.8)		(1,615.9)
Change in Advances to Affiliates, Net	22.8		81.9		(23.7)
Acquisitions of Assets	(9.8)		(17.9)		(6.0)

Other Investing Activities	6.3		1.8		5.2
Net Cash Flows Used for Investing Activities	(1,439.2)		(1,359.0)		(1,640.4)

FINANCING ACTIVITIES
Capital Contribution from Member	72.7		184.0		335.0
Issuance of Long-term Debt – Nonaffiliated	540.8		443.7		519.5
Change in Advances from Affiliates, Net	104.4		(31.9)		19.7
Retirement of Long-term Debt – Nonaffiliated	(104.0)		(50.0)		—
Dividends Paid to Member	(170.0)		(112.5)		(5.0)

Net Cash Flows from Financing Activities	443.9		433.3		869.2

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	$	158.8	$	132.9	$	119.7
Net Cash Paid for Income Taxes	95.5		65.7		22.9

Construction Expenditures Included in Current Liabilities as of December 31,	320.7		358.7		311.9
Noncash Distribution of Radial Assets to Member	—		—		(50.0)

See Notes to Financial Statements of Registrants beginning on page 228.

162

APPALACHIAN POWER COMPANY

AND SUBSIDIARIES

163

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

	Years Ended December 31,
	2022	2021	2020
	(in millions of KWhs)
Retail:
Residential	11,159	11,207	10,916
Commercial	6,066	5,949	5,887
Industrial	8,849	8,879	8,873
Miscellaneous	843	810	794
Total Retail	26,917	26,845	26,470

Wholesale	1,585	4,285	3,281

Total KWhs	28,502	31,130	29,751

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


Summary of Heating and Cooling Degree Days

	Years Ended December 31,
	2022	2021	2020
	(in degree days)
Actual – Heating (a)	2,182	1,969	1,764
Normal – Heating (b)	2,209	2,210	2,216

Actual – Cooling (c)	1,314	1,389	1,379
Normal – Cooling (b)	1,238	1,242	1,236

(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.

164

2022 Compared to 2021

Appalachian Power Company and Subsidiaries

Reconciliation of Year Ended December 31, 2021 to Year Ended December 31, 2022

Net Income

(in millions)


Year Ended December 31, 2021	$	348.9

Changes in Gross Margin:
Retail Margins	183.3
Margins from Off-system Sales	(4.4)
Transmission Revenues	26.2
Other Revenues	15.6
Total Change in Gross Margin	220.7

Changes in Expenses and Other:
Other Operation and Maintenance	(146.4)
Asset Impairments and Other Related Charges - Coal Fired Generation	(24.9)
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset	37.0

Depreciation and Amortization	(29.7)
Taxes Other Than Income Taxes	(4.0)
Interest Income	2.5

Allowance for Equity Funds Used During Construction	(3.9)
Non-Service Cost Components of Net Periodic Benefit Cost	10.0
Interest Expense	(19.9)
Total Change in Expenses and Other	(179.3)

Income Tax Expense	3.9

Year Ended December 31, 2022	$	394.2

•Retail Margins increased $183 million primarily due to the following:

•A $121 million increase due to rider revenues in Virginia and West Virginia. This increase was partially offset in other expense items below.

•A $29 million increase in weather-normalized margins primarily driven by increases in the residential and commercial classes.

•An $18 million increase due to lower customer refunds related to Tax Reform. This increase was offset in Income Tax Expense below.

•A $17 million increase due to a base rate increase in Virginia implemented in October 2022 following the Virginia Supreme Court remand. This increase was partially offset in Other Operation and Maintenance expense below.

•A $9 million increase in weather-related usage primarily driven by a 11% increase in heating degree days partially offset by a 5% decrease in cooling degree days.

•Margins from Off-system Sales decreased $4 million due to decreased generation.

•Transmission Revenues increased $26 million primarily due to the following:

•A $17 million increase due to continued investment in transmission assets.

•A $9 million increase due to transmission formula rate true-up activity.

•Other Revenues increased $16 million primarily due to the following:

•An $8 million increase due to pole attachment revenue. This increase was partially offset in Other Operation and Maintenance Expense below.

•A $7 million increase due to business development revenue. This increase was partially offset in Other Operation and Maintenance Expense below.

165

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

•Other Operation and Maintenance expenses increased $146 million primarily due to the following:

•A $75 million increase in transmission expenses primarily due to:

•A $95 million increase in recoverable PJM expenses. This increase was offset in Retail Margins above.

This increase was partially offset by:

•A $12 million decrease in vegetation management expenses.

•A $9 million decrease in transmission formula rate true-up activity. This decrease was partially offset in Retail Margins above.

•A $33 million increase in distribution expenses primarily related to storm restoration costs.

•A $20 million increase in maintenance expenses at various generation plants.

•A $12 million increase due to a charitable contribution to the AEP Foundation.

•A $9 million increase in employee-related expenses.

•A $7 million increase due to the amortization of the regulatory asset established in the current year in accordance with the August 2022 Virginia Supreme Court opinion related to under-earnings during the 2017-2019 Triennial Review. This increase was offset in Retail Margins above.

These increases were partially offset by:

•A $14 million decrease due to gains from the sale of land in 2022.

•Asset Impairments and Other Related Charges - Coal Fired Generation increased $25 million due to a write-off of a regulatory asset in accordance with the August 2022 Virginia Supreme Court opinion related to the 2017-2019 Virginia Triennial Review.

•Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset increased $37 million due to the establishment of a regulatory asset in accordance with the August 2022 Virginia Supreme Court opinion related to under-earning during the 2017-2019 Triennial Review.

•Depreciation and Amortization expenses increased $30 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $4 million primarily due to the following:

•A $4 million increase in Virginia state minimum taxes primarily due to prior year refunds and increased projected minimum tax liability.

•A $4 million increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.

These increases were partially offset by:

•A $5 million decrease due to regulatory fees that are now required to be recorded to Other Operation and Maintenance Expense.

•Allowance for Equity Funds Used During Construction decreased $4 million primarily due to a lower AFUDC base and a decrease in AFUDC equity rates.

•Non-Service Cost Components of Net Periodic Benefit Cost decreased $10 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.

•Interest Expense increased $20 million primarily due to higher long-term debt balances and higher interest rates.

•Income Tax Expense decreased $4 million primarily due to the following:

•A $10 million decrease in flow through depreciation expense.

•An $8 million decrease in state taxes.

•A $5 million decrease due to an unfavorable out of period adjustment recorded in the prior year related to deferred income taxes.

These decreases were partially offset by:

•A $10 million decrease in amortization of Excess ADIT. This decrease was partially offset by a decrease in Retail Margins.

•A $9 million increase due to an increase in pretax book income.

166

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Appalachian Power Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Appalachian Power Company and its subsidiaries (the “Company”) as of December 31, 2022 and 2021 and the related consolidated statements of income, of comprehensive income (loss), of changes in common shareholder’s equity and of cash flows for each of the three years in the period ended December 31, 2022, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

Critical Audit Matters

167

Accounting for the Effects of Cost-Based Regulation

As described in Notes 1 and 5 to the consolidated financial statements, the Company's consolidated financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. As of December 31, 2022, there were $1,532 million of deferred costs included in regulatory assets, $145 million of which were pending final regulatory approval, and $1,144 million of regulatory liabilities awaiting potential refund or future rate reduction, $31 million of which were pending final regulatory determination. Regulatory assets (deferred expenses) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management's evaluation of new events, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation, including the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, evaluating the reasonableness of management's assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities. Testing of regulatory assets and liabilities, involved evaluating the provisions and formulas outlined in rate orders, other regulatory correspondence, application of relevant regulatory precedents, and other relevant evidence.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio

February 23, 2023

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

168

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

Management assessed the effectiveness of APCo’s internal control over financial reporting as of December 31, 2022. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework (2013). Based on management’s assessment, management concluded APCo’s internal control over financial reporting was effective as of December 31, 2022.

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

169

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	Years Ended December 31,
	2022		2021		2020
REVENUES
Electric Generation, Transmission and Distribution	$	3,245.5	$	2,895.5	$	2,610.9
Sales to AEP Affiliates	256.1		197.9		174.7
Other Revenues	18.3		11.8		10.6
TOTAL REVENUES	3,519.9		3,105.2		2,796.2

EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	1,173.9		979.9		873.6


Other Operation	724.1		610.0		530.5
Maintenance	297.8		265.5		226.8
Asset Impairments and Other Related Charges - Coal Fired Generation	24.9		—		—
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset	(37.0)		—		—
Re-Establishment of Regulatory Asset - Coal Fired Generation	—		—		(49.0)
Depreciation and Amortization	575.9		546.2		507.5
Taxes Other Than Income Taxes	158.2		154.2		150.2
TOTAL EXPENSES	2,917.8		2,555.8		2,239.6

OPERATING INCOME	602.1		549.4		556.6

Other Income (Expense):
Interest Income	3.5		1.0		1.6

Allowance for Equity Funds Used During Construction	11.7		15.6		14.6
Non-Service Cost Components of Net Periodic Benefit Cost	29.0		19.0		18.8
Interest Expense	(233.9)		(214.0)		(217.6)

INCOME BEFORE INCOME TAX EXPENSE	412.4		371.0		374.0

Income Tax Expense	18.2		22.1		4.3

NET INCOME	$	394.2	$	348.9	$	369.7

The common stock of APCo is wholly-owned by Parent.

See Notes to Financial Statements of Registrants beginning on page 228.

170

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	Years Ended December 31,
	2022		2021		2020
Net Income	$	394.2	$	348.9	$	369.7

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $(0.2), $2.2 and $(0.5) in 2022, 2021 and 2020, Respectively	(0.8)		8.3		(1.7)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(1.1), $(1.1) and $(1.0) in 2022, 2021 and 2020, Respectively	(4.3)		(4.2)		(3.8)
Pension and OPEB Funded Status, Net of Tax of $(6.4), $3.5 and $2.0 in 2022, 2021 and 2020, Respectively	(24.1)		13.1		7.7

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(29.2)		17.2		2.2

TOTAL COMPREHENSIVE INCOME	$	365.0	$	366.1	$	371.9

See Notes to Financial Statements of Registrants beginning on page 228.

171

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	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					(200.0)				(200.0)

Net Income					369.7				369.7
Other Comprehensive Income							2.2		2.2
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020	260.4		1,828.7		2,248.0		7.2		4,344.3

Common Stock Dividends					(62.5)				(62.5)
Net Income					348.9				348.9
Other Comprehensive Income							17.2		17.2
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2021	260.4		1,828.7		2,534.4		24.4		4,647.9

Common Stock Dividends					(37.5)				(37.5)
Net Income					394.2				394.2
Other Comprehensive Loss							(29.2)		(29.2)
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2022	$	260.4	$	1,828.7	$	2,891.1	$	(4.8)	$	4,975.4

See Notes to Financial Statements of Registrants beginning on page 228.

172

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2022 and 2021

(in millions)


	December 31,
	2022		2021
CURRENT ASSETS
Cash and Cash Equivalents	$	7.5	$	2.5
Restricted Cash for Securitized Funding	14.4		17.6
Advances to Affiliates	19.8		20.8
Accounts Receivable:
Customers	168.9		158.5
Affiliated Companies	94.0		129.9
Accrued Unbilled Revenues	91.3		54.0
Miscellaneous	0.3		0.2
Allowance for Uncollectible Accounts	(1.7)		(1.6)
Total Accounts Receivable	352.8		341.0
Fuel	158.9		67.1
Materials and Supplies	130.6		109.8
Risk Management Assets	69.1		42.0

Regulatory Asset for Under-Recovered Fuel Costs	473.1		201.3
Margin Deposits	7.4		71.8
Prepayments and Other Current Assets	26.0		51.4
TOTAL CURRENT ASSETS	1,259.6		925.3

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	6,776.8		6,683.9
Transmission	4,482.8		4,322.4
Distribution	4,933.0		4,683.3
Other Property, Plant and Equipment	883.3		696.6
Construction Work in Progress	705.3		469.9
Total Property, Plant and Equipment	17,781.2		16,856.1
Accumulated Depreciation and Amortization	5,402.0		5,051.8
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	12,379.2		11,804.3

OTHER NONCURRENT ASSETS
Regulatory Assets	1,058.6		757.6
Securitized Assets	159.6		185.1

Employee Benefits and Pension Assets	152.9		220.5
Operating Lease Assets	73.6		66.9
Deferred Charges and Other Noncurrent Assets	138.7		129.2
TOTAL OTHER NONCURRENT ASSETS	1,583.4		1,359.3

TOTAL ASSETS	$	15,222.2	$	14,088.9

See Notes to Financial Statements of Registrants beginning on page 228.

173

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

December 31, 2022 and 2021


	December 31,
	2022		2021
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	182.2	$	199.3
Accounts Payable:
General	451.2		262.2
Affiliated Companies	142.7		118.6
Long-term Debt Due Within One Year - Nonaffiliated	251.8		480.7


Customer Deposits	75.1		73.9

Accrued Taxes	101.0		119.7

Obligations Under Operating Leases	15.0		15.1

Other Current Liabilities	171.2		146.4
TOTAL CURRENT LIABILITIES	1,390.2		1,415.9

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	5,158.7		4,458.2


Deferred Income Taxes	1,992.2		1,804.7
Regulatory Liabilities and Deferred Investment Tax Credits	1,143.6		1,238.8
Asset Retirement Obligations	419.2		394.9
Employee Benefits and Pension Obligations	34.2		41.5
Obligations Under Operating Leases	59.1		52.4
Deferred Credits and Other Noncurrent Liabilities	49.6		34.6
TOTAL NONCURRENT LIABILITIES	8,856.6		8,025.1

TOTAL LIABILITIES	10,246.8		9,441.0

Rate Matters (Note 4)
Commitments and Contingencies (Note 6)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 30,000,000 Shares
Outstanding – 13,499,500 Shares	260.4		260.4
Paid-in Capital	1,828.7		1,828.7
Retained Earnings	2,891.1		2,534.4
Accumulated Other Comprehensive Income (Loss)	(4.8)		24.4
TOTAL COMMON SHAREHOLDER’S EQUITY	4,975.4		4,647.9

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	15,222.2	$	14,088.9

See Notes to Financial Statements of Registrants beginning on page 228.

174

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	Years Ended December 31,
	2022		2021		2020
OPERATING ACTIVITIES
Net Income	$	394.2	$	348.9	$	369.7
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	575.9		546.2		507.5
Deferred Income Taxes	79.6		15.0		(26.2)
Asset Impairments and Other Related Charges - Coal Fired Generation	24.9		—		—


Allowance for Equity Funds Used During Construction	(11.7)		(15.6)		(14.6)
Mark-to-Market of Risk Management Contracts	(24.4)		(22.3)		18.8
Pension Contributions to Qualified Plan Trust	—		—		(7.0)
Deferred Fuel Over/Under-Recovery, Net	(501.8)		(196.0)		37.2

Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset	(37.0)		—		—
Re-Establishment of Regulatory Asset - Coal Fired Generation	—		—		(49.0)
Change in Other Noncurrent Assets	(75.2)		(68.8)		(40.4)
Change in Other Noncurrent Liabilities	31.4		35.6		11.2
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(8.5)		(53.3)		(30.2)

Fuel, Materials and Supplies	(113.5)		116.1		(38.2)
Margin Deposits	64.4		(70.0)		2.8
Accounts Payable	190.1		36.8		(48.1)
Accrued Taxes, Net	6.7		(16.2)		31.3
Other Current Assets	0.2		(2.4)		15.5
Other Current Liabilities	5.9		(42.3)		(28.3)
Net Cash Flows from Operating Activities	601.2		611.7		712.0

INVESTING ACTIVITIES
Construction Expenditures	(1,048.6)		(841.6)		(767.4)
Change in Advances to Affiliates, Net	1.0		0.6		0.7

Other Investing Activities	42.4		14.5		8.8
Net Cash Flows Used for Investing Activities	(1,005.2)		(826.5)		(757.9)

FINANCING ACTIVITIES

Issuance of Long-term Debt – Nonaffiliated	698.0		494.0		606.9
Change in Advances from Affiliates, Net	(17.1)		180.7		(218.1)
Retirement of Long-term Debt – Nonaffiliated	(230.4)		(393.0)		(140.3)


Principal Payments for Finance Lease Obligations	(7.9)		(7.7)		(7.4)
Dividends Paid on Common Stock	(37.5)		(62.5)		(200.0)
Other Financing Activities	0.7		0.7		0.7
Net Cash Flows from Financing Activities	405.8		212.2		41.8

Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash for Securitized Funding	1.8		(2.6)		(4.1)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period	20.1		22.7		26.8
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period	$	21.9	$	20.1	$	22.7

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	215.1	$	207.5	$	207.1
Net Cash Paid (Received) for Income Taxes	(88.6)		32.8		—
Noncash Acquisitions Under Finance Leases	1.6		1.7		7.2

Construction Expenditures Included in Current Liabilities as of December 31,	164.6		139.1		105.6



See Notes to Financial Statements of Registrants beginning on page 228.

175

INDIANA MICHIGAN POWER COMPANY

AND SUBSIDIARIES

176

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

	Years Ended December 31,
	2022	2021	2020
	(in millions of KWhs)
Retail:
Residential	5,507	5,463	5,464
Commercial	4,740	4,600	4,475
Industrial	7,492	7,373	7,225
Miscellaneous	56	58	67
Total Retail	17,795	17,494	17,231

Wholesale	6,772	6,618	7,135

Total KWhs	24,567	24,112	24,366

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


Summary of Heating and Cooling Degree Days

	Years Ended December 31,
	2022	2021	2020
	(in degree days)
Actual – Heating (a)	3,804	3,396	3,352
Normal – Heating (b)	3,725	3,730	3,742

Actual – Cooling (c)	935	1,055	928
Normal – Cooling (b)	857	861	854

(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.

177

2022 Compared to 2021

Indiana Michigan Power Company and Subsidiaries

Reconciliation of Year Ended December 31, 2021 to Year Ended December 31, 2022

Net Income

(in millions)


Year Ended December 31, 2021	$	279.8

Changes in Gross Margin:
Retail Margins	65.2

Margins from Off-system Sales	32.2
Transmission Revenues	17.1
Other Revenues	7.9
Total Change in Gross Margin	122.4

Changes in Expenses and Other:
Other Operation and Maintenance	7.0

Depreciation and Amortization	(81.2)
Taxes Other Than Income Taxes	13.8
Other Income	(2.4)


Non-Service Cost Components of Net Periodic Benefit Cost	8.5
Interest Expense	(8.4)
Total Change in Expenses and Other	(62.7)

Income Tax Expense	(14.8)

Year Ended December 31, 2022	$	324.7

•Retail Margins increased $65 million primarily due to the following:

•An $87 million increase in rider revenues partially offset by lower wholesale true-ups. This increase was partially offset in other expense items below.

•An $8 million decrease in costs for power acquired under the Unit Power Agreement between AEGCo and I&M, primarily due to the expiration of the Rockport Plant, Unit 2 lease in December 2022.

These increases were partially offset by:

•A $29 million decrease in weather-normalized retail margins in all retail classes.

•Margins from Off-system Sales increased $32 million primarily due to Rockport Plant, Unit 2 Merchant sales beginning in December 2022 in addition to higher market prices driven by winter storm Elliott.

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

•A $10 million increase due to transmission formula rate true-up activity.

•A $7 million increase due to continued investment in transmission assets.

• Other Revenues increased $8 million primarily due to the following:

•A $4 million increase due to a gain on sale of allowances. The gain on sale of allowances was partially offset in Retail Margins above.

•A $4 million increase in barging revenues by River Transportation Division (RTD). The increase in barging revenues was partially offset in Other Operation and Maintenance expenses below.

178

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

•Other Operation and Maintenance expenses decreased $7 million primarily due to the following:

•A $66 million decrease in steam generation expenses primarily due to the modification of the Rockport Plant, Unit 2 lease, which resulted in a change in lease classification from an operating lease to a finance lease in December 2021. This decrease was partially offset in Depreciation and Amortization expenses below.

•A $4 million decrease due to an increased Nuclear Electric Insurance Limited distribution in 2022.

These decreases were partially offset by:

•A $25 million increase in transmission expenses primarily due to the following:

•A $42 million increase in recoverable PJM expenses. These expenses were offset in Retail Margins above.

This increase was partially offset by:

•A $7 million decrease in transmission vegetation management expenses.

•A $7 million decrease in transmission formula rate true-up activity.

•A $22 million increase in nuclear expenses at Cook Plant primarily due to refueling outage expenses.

•An $11 million increase due to a charitable contribution to the AEP Foundation.

•A $6 million increase in vegetation management expenses.

•Depreciation and Amortization expenses increased $81 million primarily due to the modification of the Rockport Plant, Unit 2 lease, which resulted in a change in lease classification from an operating lease to a finance lease in December 2021, and a higher depreciable base. The increase resulting from the lease modification was partially offset in Other Operation and Maintenance expenses above.

•Taxes Other Than Income Taxes decreased $14 million primarily due to the repeal of the Indiana Utility Receipts Tax in July 2022. This decrease was partially offset in Retail Margins above.

•Non-Service Cost Components of Net Periodic Benefit Cost decreased $9 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.

•Interest Expense increased $8 million primarily due to a debt issuance in April 2021.

•Income Tax Expense increased $15 million primarily due to the following:

•A $13 million increase due to an increase in pretax book income.

•An $11 million increase in state taxes.

These increases were partially offset by:

•An $8 million increase in amortization of Excess ADIT.

179

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Indiana Michigan Power Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Indiana Michigan Power Company and its subsidiaries (the “Company”) as of December 31, 2022 and 2021 and the related consolidated statements of income, of comprehensive income (loss), of changes in common shareholder’s equity and of cash flows for each of the three years in the period ended December 31, 2022, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

Critical Audit Matters

180

Accounting for the Effects of Cost-Based Regulation

As described in Notes 1 and 5 to the consolidated financial statements, the Company's consolidated financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. As of December 31, 2022, there were $507 million of deferred costs included in regulatory assets, $111 million of which were pending final regulatory approval, and $1,702 million of net regulatory liabilities awaiting potential refund or future rate reduction. Regulatory assets (deferred expenses) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management's evaluation of new events, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation, including the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, evaluating the reasonableness of management's assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities. Testing of regulatory assets and liabilities, involved evaluating the provisions and formulas outlined in rate orders, other regulatory correspondence, application of relevant regulatory precedents, and other relevant evidence.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio

February 23, 2023

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

181

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

Management assessed the effectiveness of I&M’s internal control over financial reporting as of December 31, 2022. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework (2013). Based on management’s assessment, management concluded I&M’s internal control over financial reporting was effective as of December 31, 2022.

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

182

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	Years Ended December 31,
	2022		2021		2020
REVENUES
Electric Generation, Transmission and Distribution	$	2,588.3	$	2,261.2	$	2,165.3
Sales to AEP Affiliates	15.3		3.8		10.5
Other Revenues – Affiliated	54.3		54.0		60.8
Other Revenues – Nonaffiliated	11.7		7.7		5.2
TOTAL REVENUES	2,669.6		2,326.7		2,241.8

EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	535.5		338.9		344.2

Purchased Electricity from AEP Affiliates	241.8		217.9		172.8
Other Operation	621.0		645.2		650.0
Maintenance	227.2		210.0		193.2

Depreciation and Amortization	527.2		446.0		411.6
Taxes Other Than Income Taxes	97.0		110.8		107.1
TOTAL EXPENSES	2,249.7		1,968.8		1,878.9

OPERATING INCOME	419.9		357.9		362.9

Other Income (Expense):
Other Income	9.3		11.7		10.0



Non-Service Cost Components of Net Periodic Benefit Cost	24.9		16.4		16.7
Interest Expense	(125.2)		(116.8)		(112.3)

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	328.9		269.2		277.3

Income Tax Expense (Benefit)	4.2		(10.6)		(7.5)

NET INCOME	$	324.7	$	279.8	$	284.8

The common stock of I&M is wholly-owned by Parent.

See Notes to Financial Statements of Registrants beginning on page 228.

183

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	Years Ended December 31,
	2022		2021		2020
Net Income	$	324.7	$	279.8	$	284.8

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $0.4, $0.4 and $0.4 in 2022, 2021 and 2020, Respectively	1.6		1.6		1.6
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1), $0 and $0 in 2022, 2021 and 2020, Respectively	(0.3)		(0.1)		(0.1)
Pension and OPEB Funded Status, Net of Tax of $(0.1), $1.1 and $0.8 in 2022, 2021 and 2020, Respectively	(0.3)		4.2		3.1

TOTAL OTHER COMPREHENSIVE INCOME	1.0		5.7		4.6

TOTAL COMPREHENSIVE INCOME	$	325.7	$	285.5	$	289.4

See Notes to Financial Statements of Registrants beginning on page 228.

184

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	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					(85.0)				(85.0)
ASU 2016-13 Adoption					0.4				0.4
Net Income					284.8				284.8
Other Comprehensive Income							4.6		4.6
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020	56.6		980.9		1,718.7		(7.0)		2,749.2

Common Stock Dividends					(250.0)				(250.0)

Net Income					279.8				279.8
Other Comprehensive Income							5.7		5.7
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2021	56.6		980.9		1,748.5		(1.3)		2,784.7

Capital Contribution from Parent			7.9						7.9
Common Stock Dividends					(110.0)				(110.0)

Net Income					324.7				324.7
Other Comprehensive Income							1.0		1.0
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2022	$	56.6	$	988.8	$	1,963.2	$	(0.3)	$	3,008.3

See Notes to Financial Statements of Registrants beginning on page 228.

185

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2022 and 2021

(in millions)


	December 31,
	2022		2021
CURRENT ASSETS
Cash and Cash Equivalents	$	4.2	$	1.3
Advances to Affiliates	23.0		21.5
Accounts Receivable:
Customers	96.6		40.6
Affiliated Companies	104.0		78.2
Accrued Unbilled Revenues	0.6		—
Miscellaneous	4.7		2.5
Allowance for Uncollectible Accounts	(0.1)		(0.1)
Total Accounts Receivable	205.8		121.2
Fuel	46.5		56.8
Materials and Supplies	188.1		175.2
Risk Management Assets	15.2		3.3


Regulatory Asset for Under-Recovered Fuel Costs	47.1		6.4

Prepayments and Other Current Assets	41.9		53.7
TOTAL CURRENT ASSETS	571.8		439.4

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	5,585.1		5,531.8
Transmission	1,842.2		1,783.1
Distribution	3,024.7		2,800.1
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	839.3		792.9
Construction Work in Progress	253.0		302.8
Total Property, Plant and Equipment	11,544.3		11,210.7
Accumulated Depreciation, Depletion and Amortization	4,132.8		3,899.8
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	7,411.5		7,310.9

OTHER NONCURRENT ASSETS
Regulatory Assets	459.6		410.9
Spent Nuclear Fuel and Decommissioning Trusts	3,341.2		3,867.0

Operating Lease Assets	64.3		63.5
Deferred Charges and Other Noncurrent Assets	270.5		316.5
TOTAL OTHER NONCURRENT ASSETS	4,135.6		4,657.9

TOTAL ASSETS	$	12,118.9	$	12,408.2

See Notes to Financial Statements of Registrants beginning on page 228.

186

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

December 31, 2022 and 2021

(dollars in millions)


	December 31,
	2022		2021
CURRENT LIABILITIES
Advances from Affiliates	$	249.9	$	93.3
Accounts Payable:
General	173.4		174.4
Affiliated Companies	121.5		94.9
Long-term Debt Due Within One Year – Nonaffiliated (December 31, 2022 and 2021 Amounts Include $89.6 and $65 Respectively, Related to DCC Fuel)	341.8		67.0
Risk Management Liabilities	—		5.0
Customer Deposits	48.6		45.2
Accrued Taxes	103.2		106.5
Accrued Interest	36.9		37.0
Obligations Under Finance Leases	6.9		130.5
Obligations Under Operating Leases	16.0		15.5
Regulatory Liability for Over-Recovered Fuel Costs	—		1.5
Other Current Liabilities	98.9		123.2
TOTAL CURRENT LIABILITIES	1,197.1		894.0

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	2,919.0		3,128.0

Deferred Income Taxes	1,157.0		1,100.2
Regulatory Liabilities and Deferred Investment Tax Credits	1,702.2		2,447.9
Asset Retirement Obligations	2,027.6		1,946.2
Obligations Under Operating Leases	48.9		48.9
Deferred Credits and Other Noncurrent Liabilities	58.8		58.3
TOTAL NONCURRENT LIABILITIES	7,913.5		8,729.5

TOTAL LIABILITIES	9,110.6		9,623.5

Rate Matters (Note 4)
Commitments and Contingencies (Note 6)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 2,500,000 Shares
Outstanding – 1,400,000 Shares	56.6		56.6
Paid-in Capital	988.8		980.9
Retained Earnings	1,963.2		1,748.5
Accumulated Other Comprehensive Income (Loss)	(0.3)		(1.3)
TOTAL COMMON SHAREHOLDER’S EQUITY	3,008.3		2,784.7

TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY	$	12,118.9	$	12,408.2

See Notes to Financial Statements of Registrants beginning on page 228.

187

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	Years Ended December 31,
	2022		2021		2020
OPERATING ACTIVITIES
Net Income	$	324.7	$	279.8	$	284.8
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	527.2		446.0		411.6
Rockport Plant, Unit 2 Operating Lease Amortization	—		62.4		69.2
Deferred Income Taxes	(45.1)		(38.0)		(16.2)
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net	(49.2)		7.5		24.4


Allowance for Equity Funds Used During Construction	(9.8)		(12.8)		(11.5)
Mark-to-Market of Risk Management Contracts	(16.9)		5.2		5.9
Amortization of Nuclear Fuel	82.9		85.3		87.5
Pension Contributions to Qualified Plan Trust	—		—		(6.4)
Deferred Fuel Over/Under-Recovery, Net	(42.2)		(20.2)		12.4

Change in Other Noncurrent Assets	(47.3)		(54.1)		6.1
Change in Other Noncurrent Liabilities	62.4		7.5		45.0
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(82.7)		(22.3)		14.5
Fuel, Materials and Supplies	(2.6)		30.1		(34.7)
Accounts Payable	37.3		42.3		(10.8)

Accrued Taxes, Net	9.4		1.6		(20.2)

Rockport Plant, Unit 2 Operating Lease Payments	—		(73.9)		(73.9)
Other Current Assets	19.5		(15.2)		14.3
Other Current Liabilities	(46.9)		2.5		(25.7)
Net Cash Flows from Operating Activities	720.7		733.7		776.3

INVESTING ACTIVITIES
Construction Expenditures	(557.8)		(500.9)		(544.7)
Change in Advances to Affiliates, Net	(1.5)		(8.2)		(0.1)
Purchases of Investment Securities	(2,765.4)		(1,928.2)		(1,637.2)
Sales of Investment Securities	2,713.6		1,886.4		1,593.4
Acquisitions of Nuclear Fuel	(100.7)		(104.5)		(69.7)

Other Investing Activities	10.3		22.3		9.4
Net Cash Flows Used for Investing Activities	(701.5)		(633.1)		(648.9)

FINANCING ACTIVITIES
Capital Contribution from Parent	7.9		—		—
Issuance of Long-term Debt - Nonaffiliated	142.7		546.7		69.5
Change in Advances from Affiliates, Net	156.6		(9.7)		(11.4)
Retirement of Long-term Debt - Nonaffiliated	(83.4)		(383.5)		(93.2)

Principal Payments for Finance Lease Obligations	(130.7)		(6.8)		(6.5)
Dividends Paid on Common Stock	(110.0)		(250.0)		(85.0)
Other Financing Activities	0.6		0.7		0.5
Net Cash Flows Used for Financing Activities	(16.3)		(102.6)		(126.1)

Net Increase (Decrease) in Cash and Cash Equivalents	2.9		(2.0)		1.3
Cash and Cash Equivalents at Beginning of Period	1.3		3.3		2.0
Cash and Cash Equivalents at End of Period	$	4.2	$	1.3	$	3.3

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	120.9	$	110.9	$	107.6
Net Cash Paid for Income Taxes	10.1		29.3		42.1
Noncash Acquisitions Under Finance Leases	2.2		132.3		3.0
Construction Expenditures Included in Current Liabilities as of December 31,	71.9		87.8		62.8
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,	—		—		33.4


See Notes to Financial Statements of Registrants beginning on page 228.

188

OHIO POWER COMPANY AND SUBSIDIARIES

189

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

	Years Ended December 31,
	2022	2021	2020
	(in millions of KWhs)
Retail:
Residential	14,430	14,547	14,355
Commercial	16,013	15,036	13,933
Industrial	14,088	14,321	13,347
Miscellaneous	110	112	113
Total Retail (a)	44,641	44,016	41,748

Wholesale (b)	2,198	2,018	1,859

Total KWhs	46,839	46,034	43,607

(a)Represents energy delivered to distribution customers.

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

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


Summary of Heating and Cooling Degree Days

	Years Ended December 31,
	2022	2021	2020
	(in degree days)
Actual – Heating (a)	3,116	2,815	2,743
Normal – Heating (b)	3,185	3,190	3,202

Actual – Cooling (c)	1,121	1,222	1,140
Normal – Cooling (b)	1,011	1,016	1,006

(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.

190

2022 Compared to 2021

Ohio Power Company and Subsidiaries

Reconciliation of Year Ended December 31, 2021 to Year Ended December 31, 2022

Net Income

(in millions)


Year Ended December 31, 2021	$	253.6

Changes in Gross Margin:
Retail Margins	177.9
Margins from Off-system Sales	61.9
Transmission Revenues	6.4
Other Revenues	(37.5)
Total Change in Gross Margin	208.7

Changes in Expenses and Other:
Other Operation and Maintenance	(172.5)
Depreciation and Amortization	9.0
Taxes Other Than Income Taxes	(16.7)
Interest Income	0.3

Allowance for Equity Funds Used During Construction	3.1
Non-Service Cost Components of Net Periodic Benefit Cost	7.5
Other Income	(0.8)
Interest Expense	4.8
Total Change in Expenses and Other	(165.3)

Income Tax Expense	(9.8)
Equity Earnings of Unconsolidated Subsidiaries	0.6

Year Ended December 31, 2022	$	287.8

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 $178 million primarily due to the following:

•A $111 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 $42 million increase due to various rider revenues. This increase was partially offset in Margins from Off-system Sales, Other Revenues and other expense items below.

•A $10 million increase in weather-normalized margins primarily from the industrial and commercial classes, partially offset by the residential class.

•A $10 million increase in weather-related usage primarily due to the end of decoupling.

•Margins from Off-system Sales increased $62 million primarily due to the following:

•A $10 million increase in deferrals of OVEC costs. This increase was offset in Retail Margins above and Other Revenues below.

•Transmission Revenues increased $6 million primarily due to continued investment in transmission assets.

•Other Revenues decreased $38 million primarily due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs. This decrease was offset in Retail Margins and Margins from Off-system Sales above.

191

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

•Other Operation and Maintenance expenses increased $173 million primarily due to the following:

•An $87 million increase in transmission expenses, primarily due to an $88 million increase in recoverable PJM expenses and a $3 million increase in vegetation management, partially offset by a $6 million decrease in transmission formula rate true-up activity. The recoverable PJM expenses are offset in Retail Margins above.

•A $21 million increase in bad debt related expenses including $8 million in 2022 related to Bad Debt Rider over-recovery. This increase was offset in Retail Margins above.

•A $17 million increase in recoverable distribution expenses primarily related to vegetation management. This increase was offset in Retail Margins above.

•A $10 million increase in employee-related expenses.

•An $8 million increase due to a charitable contribution to the AEP Foundation.

•Depreciation and Amortization expenses decreased $9 million primarily due to a decrease in recoverable smart grid and Distribution Investment Rider depreciable expenses. This decrease was offset in Retail Margins above.

•Taxes Other Than Income Taxes increased $17 million primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.

•Allowance for Equity Funds Used During Construction increased $3 million primarily due to an increase in AFUDC base.

•Non-Service Cost Components of Net Periodic Benefit Cost decreased $8 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.

•Interest Expense decreased $5 million primarily due to the retirement of a higher rate bond partially offset by the issuance of a lower rate bond in 2021.

•Income Tax Expense increased $10 million primarily due to the following:

•A $9 million increase due to an increase in pretax book income.

•A $5 million decrease in amortization of Excess ADIT.

•A $5 million increase due to 2021 return to provision adjustments.

These increases were partially offset by:

•A $9 million decrease due to an unfavorable out of period adjustment recorded in the prior year related to deferred income taxes.

192

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Ohio Power Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Ohio Power Company and its subsidiaries (the “Company”) as of December 31, 2022 and 2021 and the related consolidated statements of income, of changes in common shareholder’s equity and of cash flows for each of the three years in the period ended December 31, 2022, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

Critical Audit Matters

193

Accounting for the Effects of Cost-Based Regulation

As described in Notes 1 and 5 to the consolidated financial statements, the Company's consolidated financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. As of December 31, 2022, there were $331 million of deferred costs included in regulatory assets, $34 million of which were pending final regulatory approval, and $1,044 million of regulatory liabilities awaiting potential refund or future rate reduction. Regulatory assets (deferred expenses) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management's evaluation of new events, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation, including the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, evaluating the reasonableness of management's assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities. Testing of regulatory assets and liabilities, involved evaluating the provisions and formulas outlined in rate orders, other regulatory correspondence, application of relevant regulatory precedents, and other relevant evidence.

Valuation of Level 3 Risk Management Commodity Contracts

As described in Notes 1, 10 and 11 to the consolidated financial statements, the Company employs risk management commodity contracts including physical and financial forward purchase and sale contracts and, to a lesser extent, over-the-counter swaps and options to accomplish its risk management strategies. Certain over-the-counter and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. As disclosed by management, the fair value of these risk management commodity contracts is estimated based on the best market information available, including valuation models that estimate future energy prices based on existing market and broker quotes, and other assumptions. Fair value estimates, based upon the best market information available, involve uncertainties and matters of significant judgment including forward market price assumptions. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. Management utilized such unobservable pricing inputs to value its Level 3 risk management commodity contract liabilities, which totaled $40 million, as of December 31, 2022.

The principal considerations for our determination that performing procedures relating to the valuation of Level 3 risk management commodity contracts is a critical audit matter are the significant judgment by management when developing the fair value of the commodity contracts; this in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence relating to the forward market price assumptions used in management’s valuation models. In addition, the audit effort involved the use of professionals with specialized skill and knowledge.

194

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

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio

February 23, 2023

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

195

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

Management assessed the effectiveness of OPCo’s internal control over financial reporting as of December 31, 2022. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework (2013). Based on management’s assessment, management concluded OPCo’s internal control over financial reporting was effective as of December 31, 2022.

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

196

OHIO POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	Years Ended December 31,
	2022		2021		2020
REVENUES
Electricity, Transmission and Distribution	$	3,635.3	$	2,863.7	$	2,698.6
Sales to AEP Affiliates	18.8		24.8		41.5
Other Revenues	11.0		10.6		9.0
TOTAL REVENUES	3,665.1		2,899.1		2,749.1

EXPENSES
Purchased Electricity for Resale	1,277.4		678.0		549.2
Purchased Electricity from AEP Affiliates	9.8		51.9		119.7


Other Operation	982.0		836.8		822.6
Maintenance	185.5		158.2		127.1
Depreciation and Amortization	294.3		303.3		276.6
Taxes Other Than Income Taxes	502.4		485.7		450.2
TOTAL EXPENSES	3,251.4		2,513.9		2,345.4

OPERATING INCOME	413.7		385.2		403.7

Other Income (Expense):
Interest Income	0.9		0.6		1.0

Allowance for Equity Funds Used During Construction	13.9		10.8		12.5
Non-Service Cost Components of Net Periodic Benefit Cost	22.1		14.6		15.0

Interest Expense	(119.6)		(124.4)		(117.2)
Other Income	0.4		1.2		1.6
INCOME BEFORE INCOME TAX EXPENSE	331.4		288.0		316.6

Income Tax Expense	44.2		34.4		45.2
Equity Earnings of Unconsolidated Subsidiaries	0.6		—		—

NET INCOME	$	287.8	$	253.6	$	271.4

The common stock of OPCo is wholly-owned by Parent.

See Notes to Financial Statements of Registrants beginning on page 228.

197

OHIO POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	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					(87.5)		(87.5)
ASU 2016-13 Adoption					0.3		0.3
Net Income					271.4		271.4

TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020	321.2		838.8		1,532.7		2,692.7

Common Stock Dividends					(100.0)		(100.0)

Net Income					253.6		253.6

TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2021	321.2		838.8		1,686.3		2,846.3

Capital Contribution from Parent			1.0				1.0
Return of Capital to Parent			(2.0)				(2.0)
Common Stock Dividends					(45.0)		(45.0)
Net Income					287.8		287.8

TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2022	$	321.2	$	837.8	$	1,929.1	$	3,088.1

See Notes to Financial Statements of Registrants beginning on page 228.

198

OHIO POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2022 and 2021

(in millions)


	December 31,
	2022		2021
CURRENT ASSETS
Cash and Cash Equivalents	$	9.6	$	3.0

Advances to Affiliates	—		42.0
Accounts Receivable:
Customers	119.9		71.6
Affiliated Companies	100.9		71.8
Accrued Unbilled Revenues	17.8		1.3
Miscellaneous	0.1		5.9
Allowance for Uncollectible Accounts	(0.1)		(0.6)
Total Accounts Receivable	238.6		150.0
Materials and Supplies	109.5		74.1
Renewable Energy Credits	35.0		30.5


Prepayments and Other Current Assets	21.7		27.9
TOTAL CURRENT ASSETS	414.4		327.5

PROPERTY, PLANT AND EQUIPMENT
Electric:
Transmission	3,198.6		2,992.8
Distribution	6,450.3		6,070.6
Other Property, Plant and Equipment	1,051.4		992.9
Construction Work in Progress	474.3		365.0
Total Property, Plant and Equipment	11,174.6		10,421.3
Accumulated Depreciation and Amortization	2,565.3		2,458.3
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	8,609.3		7,963.0

OTHER NONCURRENT ASSETS
Regulatory Assets	327.3		293.0


Operating Lease Assets	73.8		81.2
Deferred Charges and Other Noncurrent Assets	578.3		601.1
TOTAL OTHER NONCURRENT ASSETS	979.4		975.3

TOTAL ASSETS	$	10,003.1	$	9,265.8

See Notes to Financial Statements of Registrants beginning on page 228.

199

OHIO POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

December 31, 2022 and 2021

(dollars in millions)


	December 31,
	2022		2021
CURRENT LIABILITIES
Advances from Affiliates	$	172.9	$	—
Accounts Payable:
General	337.3		213.5
Affiliated Companies	126.1		125.4
Long-term Debt Due Within One Year – Nonaffiliated	0.1		0.1
Risk Management Liabilities	1.8		6.7
Customer Deposits	96.5		66.4
Accrued Taxes	733.1		702.4

Obligations Under Operating Leases	13.5		13.1
Other Current Liabilities	154.2		118.1
TOTAL CURRENT LIABILITIES	1,635.5		1,245.7

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	2,970.2		2,968.4
Long-term Risk Management Liabilities	37.9		85.8
Deferred Income Taxes	1,101.1		1,000.9
Regulatory Liabilities and Deferred Investment Tax Credits	1,044.0		1,020.9

Obligations Under Operating Leases	60.3		68.6
Deferred Credits and Other Noncurrent Liabilities	66.0		29.2
TOTAL NONCURRENT LIABILITIES	5,279.5		5,173.8

TOTAL LIABILITIES	6,915.0		6,419.5

Rate Matters (Note 4)
Commitments and Contingencies (Note 6)

COMMON SHAREHOLDER'S EQUITY
Common Stock – No Par Value:
Authorized – 40,000,000 Shares
Outstanding – 27,952,473 Shares	321.2		321.2
Paid-in Capital	837.8		838.8
Retained Earnings	1,929.1		1,686.3

TOTAL COMMON SHAREHOLDER’S EQUITY	3,088.1		2,846.3

TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY	$	10,003.1	$	9,265.8

See Notes to Financial Statements of Registrants beginning on page 228.

200

OHIO POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	Years Ended December 31,
	2022		2021		2020
OPERATING ACTIVITIES
Net Income	$	287.8	$	253.6	$	271.4
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	294.3		303.3		276.6


Deferred Income Taxes	71.5		30.7		77.2

Allowance for Equity Funds Used During Construction	(13.9)		(10.8)		(12.5)
Mark-to-Market of Risk Management Contracts	(52.8)		(17.8)		6.7

Property Taxes	(20.0)		(35.3)		(16.6)



Change in Regulatory Assets	30.4		38.3		(69.4)
Change in Other Noncurrent Assets	(87.1)		(40.7)		(49.4)
Change in Other Noncurrent Liabilities	91.1		6.9		(66.4)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(83.7)		(11.8)		4.2
Materials and Supplies	(23.4)		(2.5)		(23.9)
Accounts Payable	112.7		19.1		10.3
Accrued Taxes, Net	27.8		78.2		43.3
Other Current Assets	11.2		(15.7)		1.9
Other Current Liabilities	40.2		(19.9)		(42.5)
Net Cash Flows from Operating Activities	686.1		575.6		410.9

INVESTING ACTIVITIES
Construction Expenditures	(872.4)		(732.8)		(813.2)
Change in Advances to Affiliates, Net	42.0		(42.0)		—
Other Investing Activities	27.9		21.5		22.2
Net Cash Flows Used for Investing Activities	(802.5)		(753.3)		(791.0)

FINANCING ACTIVITIES
Capital Contribution from Parent	1.0		—		—
Return of Capital to Parent	(2.0)		—		—
Issuance of Long-term Debt – Nonaffiliated	—		1,037.1		347.0
Change in Advances from Affiliates, Net	172.9		(259.2)		128.2
Retirement of Long-term Debt – Nonaffiliated	(0.1)		(500.1)		(0.1)

Principal Payments for Finance Lease Obligations	(4.9)		(4.9)		(4.7)
Dividends Paid on Common Stock	(45.0)		(100.0)		(87.5)
Other Financing Activities	1.1		0.4		0.9
Net Cash Flows from Financing Activities	123.0		173.3		383.8

Net Increase (Decrease) in Cash and Cash Equivalents	6.6		(4.4)		3.7
Cash and Cash Equivalents at Beginning of Period	3.0		7.4		3.7
Cash and Cash Equivalents at End of Period	$	9.6	$	3.0	$	7.4

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	113.4	$	119.5	$	111.2
Net Cash Paid (Received) for Income Taxes	(19.7)		(7.9)		(26.9)
Noncash Acquisitions Under Finance Leases	3.0		2.5		6.1
Construction Expenditures Included in Current Liabilities as of December 31,	109.7		97.1		76.7

See Notes to Financial Statements of Registrants beginning on page 228.

201

PUBLIC SERVICE COMPANY OF OKLAHOMA

202

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

	Years Ended December 31,
	2022	2021	2020
	(in millions of KWhs)
Retail:
Residential	6,618	6,243	6,117
Commercial	5,153	4,911	4,673
Industrial	6,073	5,830	5,713
Miscellaneous	1,297	1,222	1,199
Total Retail	19,141	18,206	17,702

Wholesale	734	669	345

Total KWhs	19,875	18,875	18,047

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


Summary of Heating and Cooling Degree Days

	Years Ended December 31,
	2022	2021	2020
	(in degree days)
Actual – Heating (a)	1,893	1,499	1,454
Normal – Heating (b)	1,736	1,742	1,744

Actual – Cooling (c)	2,559	2,198	2,069
Normal – Cooling (b)	2,161	2,165	2,174

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

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

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

203

2022 Compared to 2021

Public Service Company of Oklahoma

Reconciliation of Year Ended December 31, 2021 to Year Ended December 31, 2022

Net Income

(in millions)


Year Ended December 31, 2021	$	141.1

Changes in Gross Margin:
Retail Margins (a)	91.6

Transmission Revenues	(0.1)
Other Revenues	1.6
Total Change in Gross Margin	93.1

Changes in Expenses and Other:
Other Operation and Maintenance	(63.8)
Depreciation and Amortization	(33.5)
Taxes Other Than Income Taxes	(7.9)
Interest Income	3.1
Allowance for Funds Used During Construction	(0.9)
Non-Service Cost Components of Net Periodic Benefit Cost	4.0
Interest Expense	(20.9)
Total Change in Expenses and Other	(119.9)

Income Tax Expense	53.3

Year Ended December 31, 2022	$	167.6

(a)Includes firm wholesale sales to municipals and cooperatives.

•Retail Margins increased $92 million primarily due to the following:

•A $110 million increase due to a $61 million increase in base rate revenues and a $49 million increase in rider revenues. These increases were partially offset in other expense items below.

•A $26 million increase in weather-related usage due to a 16% increase in cooling degree days and a 26% increase in heating degree days.

•A $9 million increase in weather-normalized margins primarily in the commercial class.

These increases were partially offset by:

•A $54 million decrease due to the NCWF PTC benefits provided to customers through fuel clause mechanisms. This decrease was partially offset in Income Tax Expense below.

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

•Other Operation and Maintenance expenses increased $64 million primarily due to the following:

•An $18 million increase in generating expenses primarily due to an increase in maintenance expenses at the NCWF and Northeastern.

•A $12 million increase in transmission expenses primarily due to the following:

•A $103 million increase due to a change in rider recovery, increased transmission investment and load.

This increase was partially offset by:

•An $82 million decrease in recoverable SPP transmission expenses. This decrease was offset in Retail Margins above.

•A $7 million decrease in transmission formula rate true-up activity. This decrease was partially offset in Retail Margins above.

204

•A $14 million increase in distribution expenses primarily due to an increase in overhead line maintenance.

•A $6 million increase due to a charitable contribution to the AEP Foundation.

•A $4 million increase due to pre-construction costs associated with various renewable projects.

•Depreciation and Amortization expenses increased $34 million primarily due to a higher depreciable base, implementation of new rates and the timing of refunds to customers under rate rider mechanisms.

•Taxes Other Than Income Taxes increased $8 million primarily due to a new infrastructure fee implemented by the City of Tulsa in March 2022 and increased property taxes. This increase was partially offset in Retail Margins above.

•Non-Service Cost Components of Net Periodic Benefit Cost decreased $4 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.

•Interest Expense increased $21 million primarily due to an increase in long-term debt balances and Advances from Affiliates.

•Income Tax Expense decreased $53 million primarily due to a $42 million increase in PTCs related to enacted legislation under the IRA and additional capital investment in tax-credit eligible property and a $6 million decrease due to a decrease in pretax book income. The increase in PTCs was partially offset in Retail Margins above.

205

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Public Service Company of Oklahoma

Opinion on the Financial Statements

We have audited the accompanying balance sheets of Public Service Company of Oklahoma (the “Company”) as of December 31, 2022 and 2021 and the related statements of income, of comprehensive income (loss), of changes in common shareholder’s equity and of cash flows for each of the three years in the period ended December 31, 2022, including the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

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

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

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

Critical Audit Matters

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

206

Accounting for the Effects of Cost-Based Regulation

As described in Notes 1 and 5 to the financial statements, the Company's financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. As of December 31, 2022, there were $832 million of deferred costs included in regulatory assets, $26 million of which were pending final regulatory approval, and $809 million of regulatory liabilities awaiting potential refund or future rate reduction, $51 million of which were pending final regulatory determination. Regulatory assets (deferred expenses) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial statements. These procedures included testing the effectiveness of controls relating to management's evaluation of new events, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation, including the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, evaluating the reasonableness of management's assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities. Testing of regulatory assets and liabilities, involved evaluating the provisions and formulas outlined in rate orders, other regulatory correspondence, application of relevant regulatory precedents, and other relevant evidence.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio

February 23, 2023

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

207

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

Management assessed the effectiveness of PSO’s internal control over financial reporting as of December 31, 2022. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework (2013). Based on management’s assessment, management concluded PSO’s internal control over financial reporting was effective as of December 31, 2022.

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

208

PUBLIC SERVICE COMPANY OF OKLAHOMA

STATEMENTS OF INCOME

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	Years Ended December 31,
	2022		2021		2020
REVENUES
Electric Generation, Transmission and Distribution	$	1,865.6	$	1,465.3	$	1,246.1
Sales to AEP Affiliates	2.9		4.2		5.2
Other Revenues	6.2		4.9		14.8
TOTAL REVENUES	1,874.7		1,474.4		1,266.1

EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	891.5		584.3		443.5


Other Operation	400.4		353.8		327.3
Maintenance	114.4		97.2		98.4
Depreciation and Amortization	230.1		196.6		173.5
Taxes Other Than Income Taxes	57.5		49.6		47.5
TOTAL EXPENSES	1,693.9		1,281.5		1,090.2

OPERATING INCOME	180.8		192.9		175.9

Other Income (Expense):
Interest Income	7.4		4.3		0.1

Allowance for Equity Funds Used During Construction	1.5		2.4		4.0
Non-Service Cost Components of Net Periodic Benefit Cost	12.5		8.5		8.5
Interest Expense	(83.8)		(62.9)		(60.3)

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	118.4		145.2		128.2

Income Tax Expense (Benefit)	(49.2)		4.1		5.2

NET INCOME	$	167.6	$	141.1	$	123.0

The common stock of PSO is wholly-owned by Parent.

See Notes to Financial Statements of Registrants beginning on page 228.

209

PUBLIC SERVICE COMPANY OF OKLAHOMA

STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	Years Ended December 31,
	2022		2021		2020
Net Income	$	167.6	$	141.1	$	123.0

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $0.3, $0 and $(0.3) in 2022, 2021 and 2020, Respectively	1.3		(0.1)		(1.0)

TOTAL COMPREHENSIVE INCOME	$	168.9	$	141.0	$	122.0

See Notes to Financial Statements of Registrants beginning on page 228.

210

PUBLIC SERVICE COMPANY OF OKLAHOMA

STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	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

Capital Contribution of Radial Assets from Parent			50.0						50.0
ASU 2016-13 Adoption					0.3				0.3

Net Income					123.0				123.0
Other Comprehensive Loss							(1.0)		(1.0)
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020	157.2		414.0		974.3		0.1		1,545.6

Capital Contribution from Parent			625.0						625.0

Common Stock Dividends					(20.0)				(20.0)
Net Income					141.1				141.1
Other Comprehensive Loss							(0.1)		(0.1)
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2021	157.2		1,039.0		1,095.4		—		2,291.6

Capital Contribution from Parent			3.6						3.6
Common Stock Dividends					(45.0)				(45.0)

Net Income					167.6				167.6
Other Comprehensive Income							1.3		1.3
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2022	$	157.2	$	1,042.6	$	1,218.0	$	1.3	$	2,419.1

See Notes to Financial Statements of Registrants beginning on page 228.

211

PUBLIC SERVICE COMPANY OF OKLAHOMA

BALANCE SHEETS

ASSETS

December 31, 2022 and 2021

(in millions)


	December 31,
	2022		2021
CURRENT ASSETS
Cash and Cash Equivalents	$	4.0	$	1.3

Accounts Receivable:
Customers	70.1		41.5
Affiliated Companies	52.2		35.0
Miscellaneous	0.8		0.6

Total Accounts Receivable	123.1		77.1
Fuel	11.6		14.5
Materials and Supplies	111.1		56.2
Risk Management Assets	25.3		12.1
Accrued Tax Benefits	16.1		17.6
Regulatory Asset for Under-Recovered Fuel Costs	178.7		194.6
Prepayments and Other Current Assets	21.6		13.4
TOTAL CURRENT ASSETS	491.5		386.8

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	2,394.8		1,802.4
Transmission	1,164.4		1,107.7
Distribution	3,216.4		3,004.9
Other Property, Plant and Equipment	469.3		437.0
Construction Work in Progress	219.3		156.0
Total Property, Plant and Equipment	7,464.2		6,508.0
Accumulated Depreciation and Amortization	1,837.7		1,705.2
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	5,626.5		4,802.8

OTHER NONCURRENT ASSETS
Regulatory Assets	653.7		1,037.4

Employee Benefits and Pension Assets	67.3		95.2
Operating Lease Assets	106.1		68.9
Deferred Charges and Other Noncurrent Assets	20.8		7.9
TOTAL OTHER NONCURRENT ASSETS	847.9		1,209.4

TOTAL ASSETS	$	6,965.9	$	6,399.0

See Notes to Financial Statements of Registrants beginning on page 228.

212

PUBLIC SERVICE COMPANY OF OKLAHOMA

BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

December 31, 2022 and 2021


	December 31,
	2022		2021
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	364.2	$	72.3
Accounts Payable:
General	202.9		157.4
Affiliated Companies	76.7		51.0
Long-term Debt Due Within One Year – Nonaffiliated	0.5		125.5

Customer Deposits	59.0		56.2
Accrued Taxes	28.7		27.0

Obligations Under Operating Leases	8.9		6.9


Other Current Liabilities	101.8		66.4
TOTAL CURRENT LIABILITIES	842.7		562.7

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	1,912.3		1,788.0
Deferred Income Taxes	788.6		782.3
Regulatory Liabilities and Deferred Investment Tax Credits	809.1		835.3
Asset Retirement Obligations	73.5		57.5

Obligations Under Operating Leases	99.3		62.2
Deferred Credits and Other Noncurrent Liabilities	21.3		19.4
TOTAL NONCURRENT LIABILITIES	3,704.1		3,544.7

TOTAL LIABILITIES	4,546.8		4,107.4

Rate Matters (Note 4)
Commitments and Contingencies (Note 6)

COMMON SHAREHOLDER’S EQUITY
Common Stock – Par Value – $15 Per Share:
Authorized – 11,000,000 Shares
Issued – 10,482,000 Shares
Outstanding – 9,013,000 Shares	157.2		157.2
Paid-in Capital	1,042.6		1,039.0
Retained Earnings	1,218.0		1,095.4
Accumulated Other Comprehensive Income (Loss)	1.3		—
TOTAL COMMON SHAREHOLDER’S EQUITY	2,419.1		2,291.6

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	6,965.9	$	6,399.0

See Notes to Financial Statements of Registrants beginning on page 228.

213

PUBLIC SERVICE COMPANY OF OKLAHOMA

STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	Years Ended December 31,
	2022		2021		2020
OPERATING ACTIVITIES
Net Income	$	167.6	$	141.1	$	123.0
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	230.1		196.6		173.5
Deferred Income Taxes	(59.4)		113.9		17.0

Allowance for Equity Funds Used During Construction	(1.5)		(2.4)		(4.0)
Mark-to-Market of Risk Management Contracts	(13.7)		1.9		5.5


Deferred Fuel Over/Under-Recovery, Net	442.4		(843.8)		(94.0)


Change in Other Noncurrent Assets	(35.4)		(18.3)		(17.9)
Change in Other Noncurrent Liabilities	29.9		4.4		1.6
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(46.0)		(28.7)		1.4
Fuel, Materials and Supplies	(51.1)		1.4		(14.1)
Accounts Payable	57.5		34.2		(29.5)
Accrued Taxes, Net	3.2		(6.5)		3.6
Other Current Assets	(6.3)		(6.3)		4.6
Other Current Liabilities	30.4		(20.8)		(13.7)
Net Cash Flows from (Used for) Operating Activities	747.7		(433.3)		157.0

INVESTING ACTIVITIES
Construction Expenditures	(447.0)		(332.1)		(337.9)
Change in Advances to Affiliates, Net	—		—		38.8
Acquisition of the North Central Wind Energy Facilities	(549.3)		(297.0)		—
Other Investing Activities	4.3		2.4		4.0
Net Cash Flows Used for Investing Activities	(992.0)		(626.7)		(295.1)

FINANCING ACTIVITIES
Capital Contribution from Parent	3.6		625.0		—
Issuance of Long-term Debt – Nonaffiliated	499.7		1,290.0		—
Change in Advances from Affiliates, Net	291.9		(83.1)		155.4
Retirement of Long-term Debt – Nonaffiliated	(500.5)		(750.5)		(13.2)

Principal Payments for Finance Lease Obligations	(3.2)		(3.2)		(3.5)
Dividends Paid on Common Stock	(45.0)		(20.0)		—
Other Financing Activities	0.5		0.5		0.5
Net Cash Flows from Financing Activities	247.0		1,058.7		139.2

Net Increase (Decrease) in Cash and Cash Equivalents	2.7		(1.3)		1.1
Cash and Cash Equivalents at Beginning of Period	1.3		2.6		1.5
Cash and Cash Equivalents at End of Period	$	4.0	$	1.3	$	2.6

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	79.7	$	57.0	$	59.1
Net Cash Paid (Received) for Income Taxes	(12.5)		(102.9)		(11.8)
Noncash Acquisitions Under Finance Leases	2.8		3.6		3.2
Construction Expenditures Included in Current Liabilities as of December 31,	69.8		56.8		35.5
Noncash Contribution of Radial Assets from Parent	—		—		50.0

See Notes to Financial Statements of Registrants beginning on page 228.

214

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

215

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

	Years Ended December 31,
	2022	2021	2020
	(in millions of KWhs)
Retail:
Residential	6,538	6,205	5,988
Commercial	5,732	5,489	5,296
Industrial	5,174	4,682	4,891
Miscellaneous	75	77	79
Total Retail	17,519	16,453	16,254

Wholesale	6,714	6,704	5,838

Total KWhs	24,233	23,157	22,092

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


Summary of Heating and Cooling Degree Days

	Years Ended December 31,
	2022	2021	2020
	(in degree days)
Actual – Heating (a)	1,149	981	862
Normal – Heating (b)	1,170	1,177	1,181

Actual – Cooling (c)	2,833	2,543	2,165
Normal – Cooling (b)	2,333	2,328	2,333

(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.

216

2022 Compared to 2021

Reconciliation of Year Ended December 31, 2021 to Year Ended December 31, 2022

Earnings Attributable to SWEPCo Common Shareholder

(in millions)


Year Ended December 31, 2021	$	239.0

Changes in Gross Margin:
Retail Margins (a)	122.5
Margins from Off-system Sales	(10.5)
Transmission Revenues	21.6
Other Revenues	0.5
Total Change in Gross Margin	134.1

Changes in Expenses and Other:
Other Operation and Maintenance	(76.3)
Asset Impairments and Other Related Charges	11.6
Depreciation and Amortization	(29.8)
Taxes Other Than Income Taxes	(9.1)
Interest Income	8.5
Allowance for Equity Funds Used During Construction	(2.1)
Non-Service Cost Components of Net Periodic Benefit Cost	4.2
Interest Expense	(11.5)
Total Change in Expenses and Other	(104.5)

Income Tax Benefit	24.6
Equity Earnings of Unconsolidated Subsidiary	(2.0)
Net Income Attributable to Noncontrolling Interest	(1.1)

Year Ended December 31, 2022	$	290.1

(a)Includes firm wholesale sales to municipals and cooperatives.

•Retail Margins increased $123 million primarily due to the following:

•A $102 million increase primarily due to base rate revenue increases in Texas and Arkansas and rider increases in all retail jurisdictions. These increases were partially offset in other expense items below.

•A $31 million increase in weather-related usage primarily due to an 11% increase in cooling degree days and a 17% increase in heating degree days.

•A $15 million increase in weather-normalized margins primarily in the residential and commercial classes, partially offset by the industrial class.

These increases were partially offset by:

•A $19 million decrease due to the NCWF PTC benefits provided to customers through fuel clause mechanisms. This decrease was partially offset in Income Tax Benefit below.

•A $6 million decrease in municipal and cooperative revenues primarily due to the February 2021 severe winter weather event.

•Margins from Off-system Sales decreased $11 million due to a decrease in Turk Plant merchant sales primarily driven by the February 2021 severe winter weather event.

•Transmission Revenues increased $22 million primarily due to continued investment in transmission assets and increased load.

217

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

•Other Operation and Maintenance expenses increased $76 million primarily due to the following:

•A $12 million increase in transmission expenses primarily due to the following:

•A $13 million increase due to increased transmission investment and load.

•A $9 million increase in recoverable SPP transmission expenses. This increase was offset in Retail Margins above.

•A $3 million increase in employee-related expenses.

These increases were partially offset by:

•An $8 million decrease due to the implementation of a rider mechanism in Arkansas.

•A $5 million decrease in transmission formula rate true-up activity.

•A $12 million increase in generation expenses primarily driven by the NCWF.

•A $10 million increase in distribution expenses primarily due to vegetation management and storm restoration expenses.

•A $9 million increase due to a charitable contribution to the AEP Foundation.

•An $8 million increase in administrative and general expenses primarily due to regulatory fees and employee-related expenses.

•A $7 million increase due to pre-construction costs associated with various renewable projects.

•A $6 million increase due to energy efficiency programs. This increase was offset in Retail Margins above.

•Asset Impairments and Other Related Charges decreased $12 million due to the prior year partial regulatory disallowance of SWEPCo’s investment in the Dolet Hills Power Station as a result of an order received in the 2020 Texas Base Rate Case.

•Depreciation and Amortization expenses increased $30 million primarily due to the implementation of new rates in Arkansas and Texas and a higher depreciable base. This increase was partially offset in Retail Margins above.

•Taxes Other Than Income Taxes increased $9 million primarily due to increased property taxes driven by the investment in the NCWF.

•Interest Income increased $9 million primarily related to carrying charges on regulatory assets resulting from the February 2021 severe winter weather event.

•Interest Expense increased $12 million primarily due to an increase in long-term debt balances and Advances from Affiliates.

•Income Tax Benefit increased $25 million primarily due to the following:

•A $50 million increase in PTCs related to enacted legislation under the IRA and additional capital investment in tax-credit eligible property. This increase was partially offset in Retail Margins above.

These increases were partially offset by:

•A $16 million decrease in amortization of Excess ADIT.

•A $6 million decrease due to an increase in pretax book income.

218

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Southwestern Electric Power Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Southwestern Electric Power Company and its subsidiaries (the “Company”) as of December 31, 2022 and 2021 and the related consolidated statements of income, of comprehensive income (loss), of changes in equity and of cash flows for each of the three years in the period ended December 31, 2022, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

Critical Audit Matters

219

Accounting for the Effects of Cost-Based Regulation

As described in Notes 1 and 5 to the consolidated financial statements, the Company's consolidated financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. As of December 31, 2022, there were $1,395 million of deferred costs included in regulatory assets, $510 million of which were pending final regulatory approval, and $827 million of regulatory liabilities awaiting potential refund or future rate reduction, $7 million of which were pending final regulatory determination. Regulatory assets (deferred expenses) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management's evaluation of new events, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation, including the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, evaluating the reasonableness of management's assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities. Testing of regulatory assets and liabilities, involved evaluating the provisions and formulas outlined in rate orders, other regulatory correspondence, application of relevant regulatory precedents, and other relevant evidence.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio

February 23, 2023

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

220

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

Management assessed the effectiveness of SWEPCo’s internal control over financial reporting as of December 31, 2022. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework (2013). Based on management’s assessment, management concluded SWEPCo’s internal control over financial reporting was effective as of December 31, 2022.

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

221

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	Years Ended December 31,
	2022		2021		2020
REVENUES
Electric Generation, Transmission and Distribution	$	2,228.6	$	2,088.9	$	1,696.6
Sales to AEP Affiliates	59.5		41.4		41.0
Provision for Refund - Affiliated	(5.6)		(0.4)		(2.0)
Other Revenues	1.9		1.9		2.9
TOTAL REVENUES	2,284.4		2,131.8		1,738.5

EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	889.5		871.0		604.5


Other Operation	424.7		360.3		338.3
Maintenance	148.6		136.7		129.7
Asset Impairments and Other Related Charges	—		11.6		—
Depreciation and Amortization	324.8		295.0		272.7
Taxes Other Than Income Taxes	126.8		117.7		102.8
TOTAL EXPENSES	1,914.4		1,792.3		1,448.0

OPERATING INCOME	370.0		339.5		290.5

Other Income (Expense):
Interest Income	17.7		9.2		2.1
Allowance for Equity Funds Used During Construction	4.9		7.0		7.7
Non-Service Cost Components of Net Periodic Benefit Cost	12.5		8.3		8.4
Interest Expense	(137.4)		(125.9)		(118.5)

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS	267.7		238.1		190.2

Income Tax Expense (Benefit)	(25.2)		(0.6)		9.4
Equity Earnings of Unconsolidated Subsidiary	1.4		3.4		2.9

NET INCOME	294.3		242.1		183.7

Net Income Attributable to Noncontrolling Interest	4.2		3.1		2.9





EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER	$	290.1	$	239.0	$	180.8

The common stock of SWEPCo is wholly-owned by Parent.

See Notes to Financial Statements of Registrants beginning on page 228.

222

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	Years Ended December 31,
	2022		2021		2020
Net Income	$	294.3	$	242.1	$	183.7

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $0, $0.4 and $0.4 in 2022, 2021 and 2020, Respectively	(0.1)		1.5		1.5
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.4), $(0.4) and $(0.4) in 2022, 2021 and 2020, Respectively	(1.6)		(1.6)		(1.5)
Pension and OPEB Funded Status, Net of Tax of $(2.5), $1.3 and $0.9 in 2022, 2021 and 2020, Respectively	(9.2)		4.9		3.2

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(10.9)		4.8		3.2

TOTAL COMPREHENSIVE INCOME	283.4		246.9		186.9

Total Comprehensive Income Attributable to Noncontrolling Interest	4.2		3.1		2.9

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER	$	279.2	$	243.8	$	184.0

See Notes to Financial Statements of Registrants beginning on page 228.

223

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	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

Reverse Common Stock Split (a)	(135.6)		135.6								—

Common Stock Dividends – Nonaffiliated									(1.9)		(1.9)
ASU 2016-03 Adoption					1.6						1.6

Net Income					180.8				2.9		183.7
Other Comprehensive Income							3.2				3.2

TOTAL EQUITY – DECEMBER 31, 2020	0.1		812.2		1,811.9		1.9		1.6		2,627.7


Capital Contribution from Parent			280.0								280.0

Common Stock Dividends – Nonaffiliated									(4.8)		(4.8)

Net Income					239.0				3.1		242.1
Other Comprehensive Income							4.8				4.8
TOTAL EQUITY – DECEMBER 31, 2021	0.1		1,092.2		2,050.9		6.7		(0.1)		3,149.8


Capital Contribution from Parent			350.0								350.0
Common Stock Dividends					(105.0)						(105.0)
Common Stock Dividends – Nonaffiliated									(3.4)		(3.4)

Net Income					290.1				4.2		294.3
Other Comprehensive Loss							(10.9)				(10.9)
TOTAL EQUITY – DECEMBER 31, 2022	$	0.1	$	1,442.2	$	2,236.0	$	(4.2)	$	0.7	$	3,674.8

(a) In August 2020, SWEPCo executed a reverse stock split with each 2,048 shares of common stock issued and outstanding being combined into one share of common stock. The common stock of SWEPCo is wholly-owned by Parent.

See Notes to Financial Statements of Registrants beginning on page 228.

224

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2022 and 2021

(in millions)


	December 31,
	2022		2021
CURRENT ASSETS
Cash and Cash Equivalents (December 31, 2022 and 2021 Amounts Include $84.2 and $49.9, Respectively, Related to Sabine)	$	88.4	$	51.2
Advances to Affiliates	2.1		155.9
Accounts Receivable:
Customers	38.8		35.8
Affiliated Companies	65.4		38.3
Miscellaneous	10.4		12.3

Total Accounts Receivable	114.6		86.4
Fuel (December 31, 2022 and 2021 Amounts Include $14.2 and $13.1, Respectively, Related to Sabine)	81.3		82.2
Materials and Supplies (December 31, 2022 and 2021 Amounts Include $4.2 and $12, Respectively, Related to Sabine)	92.1		81.9
Risk Management Assets	16.4		9.8

Accrued Tax Benefits	16.5		17.8
Regulatory Asset for Under-Recovered Fuel Costs	353.0		143.9
Prepayments and Other Current Assets	47.8		39.4
TOTAL CURRENT ASSETS	812.2		668.5

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	5,476.2		4,734.5
Transmission	2,479.8		2,316.9
Distribution	2,659.6		2,514.3
Other Property, Plant and Equipment (December 31, 2022 and 2021 Amounts Include $219.8 and $219.9, Respectively, Related to Sabine)	804.4		764.0
Construction Work in Progress	369.5		240.7
Total Property, Plant and Equipment	11,789.5		10,570.4
Accumulated Depreciation and Amortization (December 31, 2022 and 2021 Amounts Include $212.5 and $168.1, Respectively, Related to Sabine)	3,527.3		3,170.3
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	8,262.2		7,400.1

OTHER NONCURRENT ASSETS
Regulatory Assets	1,042.4		1,005.3
Deferred Charges and Other Noncurrent Assets	262.0		251.8
TOTAL OTHER NONCURRENT ASSETS	1,304.4		1,257.1

TOTAL ASSETS	$	10,378.8	$	9,325.7

See Notes to Financial Statements of Registrants beginning on page 228.

225

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

December 31, 2022 and 2021


	December 31,
	2022		2021
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	310.7	$	—
Accounts Payable:
General	213.1		163.6
Affiliated Companies	81.7		61.4

Long-term Debt Due Within One Year – Nonaffiliated	6.2		6.2
Risk Management Liabilities	1.4		2.1
Customer Deposits	65.4		62.4
Accrued Taxes	52.8		44.3
Accrued Interest	36.0		36.0

Obligations Under Operating Leases	8.4		8.1

Other Current Liabilities	172.0		154.6
TOTAL CURRENT LIABILITIES	947.7		538.7

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	3,385.4		3,389.0

Deferred Income Taxes	1,089.7		1,087.6
Regulatory Liabilities and Deferred Investment Tax Credits	825.7		806.9
Asset Retirement Obligations	237.2		192.7
Employee Benefits and Pension Obligations	29.7		20.3

Obligations Under Operating Leases	120.2		77.7
Deferred Credits and Other Noncurrent Liabilities	68.4		63.0
TOTAL NONCURRENT LIABILITIES	5,756.3		5,637.2

TOTAL LIABILITIES	6,704.0		6,175.9

Rate Matters (Notes 4)
Commitments and Contingencies (Note 6)

EQUITY
Common Stock – Par Value – $18 Per Share:
Authorized – 3,680 Shares
Outstanding – 3,680 Shares	0.1		0.1
Paid-in Capital	1,442.2		1,092.2
Retained Earnings	2,236.0		2,050.9
Accumulated Other Comprehensive Income (Loss)	(4.2)		6.7
TOTAL COMMON SHAREHOLDER’S EQUITY	3,674.1		3,149.9

Noncontrolling Interest	0.7		(0.1)

TOTAL EQUITY	3,674.8		3,149.8

TOTAL LIABILITIES AND EQUITY	$	10,378.8	$	9,325.7

See Notes to Financial Statements of Registrants beginning on page 228.

226

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2022, 2021 and 2020

(in millions)


	Years Ended December 31,
	2022		2021		2020
OPERATING ACTIVITIES
Net Income	$	294.3	$	242.1	$	183.7
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	324.8		295.0		272.7
Deferred Income Taxes	9.4		16.6		32.4
Asset Impairments and Other Related Charges	—		11.6		—
Allowance for Equity Funds Used During Construction	(4.9)		(7.0)		(7.7)
Mark-to-Market of Risk Management Contracts	(6.2)		(7.3)		(0.1)
Pension Contributions to Qualified Plan Trust	—		—		(8.9)
Deferred Fuel Over/Under-Recovery, Net	(86.4)		(546.4)		26.3
Change in Regulatory Assets	7.6		(95.6)		(108.4)
Change in Other Noncurrent Assets	42.9		41.9		16.1
Change in Other Noncurrent Liabilities	18.3		(1.1)		25.2
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(28.2)		(21.5)		7.3
Fuel, Materials and Supplies	(9.3)		126.5		(46.4)
Accounts Payable	34.1		22.0		11.1
Accrued Taxes, Net	9.8		15.4		(23.1)
Other Current Assets	(9.8)		(3.6)		(2.8)
Other Current Liabilities	(9.8)		8.2		(21.1)
Net Cash Flows from Operating Activities	586.6		96.8		356.3

INVESTING ACTIVITIES
Construction Expenditures	(586.4)		(414.6)		(402.7)
Change in Advances to Affiliates, Net	153.8		(153.8)		—
Acquisition of the North Central Wind Energy Facilities	(658.0)		(355.8)		—


Other Investing Activities	5.5		3.5		10.1
Net Cash Flows Used for Investing Activities	(1,085.1)		(920.7)		(392.6)

FINANCING ACTIVITIES
Capital Contribution from Parent	350.0		280.0		—
Issuance of Long-term Debt – Nonaffiliated	—		1,137.6		—
Change in Short-term Debt – Nonaffiliated	—		(35.0)		16.7
Change in Advances from Affiliates, Net	310.7		(124.6)		64.7
Retirement of Long-term Debt – Nonaffiliated	(6.2)		(381.2)		(21.2)


Principal Payments for Finance Lease Obligations	(10.8)		(10.9)		(10.9)
Dividends Paid on Common Stock	(105.0)		—		—
Dividends Paid on Common Stock – Nonaffiliated	(3.4)		(4.8)		(1.9)

Other Financing Activities	0.4		0.8		0.5
Net Cash Flows from Financing Activities	535.7		861.9		47.9

Net Increase in Cash and Cash Equivalents	37.2		38.0		11.6
Cash and Cash Equivalents at Beginning of Period	51.2		13.2		1.6
Cash and Cash Equivalents at End of Period	$	88.4	$	51.2	$	13.2

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	131.2	$	116.5	$	110.7
Net Cash Paid (Received) for Income Taxes	(29.1)		(28.8)		4.3
Noncash Acquisitions Under Finance Leases	3.6		4.8		8.9
Construction Expenditures Included in Current Liabilities as of December 31,	105.6		69.0		46.0



See Notes to Financial Statements of Registrants beginning on page 228.

227

INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANTS

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

Note

Registrant

Page
Number

Organization and Summary of Significant Accounting Policies

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

229

New Accounting Standards

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

246

Comprehensive Income

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

247

Rate Matters

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

254

Effects of Regulation

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

265

Commitments, Guarantees and Contingencies

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

284

Acquisitions, Assets and Liabilities Held for Sale, Dispositions and Impairments

AEP, AEP Texas, AEPTCo, PSO, SWEPCo

292

Benefit Plans

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

299

Business Segments

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

322

Derivatives and Hedging

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

327

Fair Value Measurements

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

342

Income Taxes

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

357

Leases

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

369

Financing Activities

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

375

Stock-based Compensation

AEP

386

Related Party Transactions

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

391

Variable Interest Entities and Equity Method Investments

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

399

Property, Plant and Equipment

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

410

Revenue from Contracts with Customers

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

417

Goodwill

AEP

426

Subsequent Events

AEP

427

228

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

ORGANIZATION

The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions.

AEP provides competitive electric and gas supply for residential, commercial and industrial customers in deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier.

The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, AEP operates competitive wind and solar farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through Sabine, conducts lignite mining operations to fuel the Pirkey Plant.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Rates and Service Regulation

AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over certain issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system.

The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued-up to actual costs annually.

The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers continue to pay for certain legacy deferred generation-related costs through PUCO approved riders. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by REPs. AEP has one active REP in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind assets, the power from which is marketed and sold in ERCOT.

229

The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. Retail transmission rates are based on formula rates included in the PJM OATT that are cost-based and are unbundled in Ohio for OPCo, in Virginia for APCo and in Michigan for I&M. AEP Texas’ retail transmission rates in Texas are unbundled but the retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEPTCo’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based.

In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis.

In addition, the FERC regulates the SIA, Operating Agreement, TA and TCA, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. The FERC also regulates the PCA. See Note 16 - Related Party Transactions for additional information.

Principles of Consolidation

AEP’s consolidated financial statements include its wholly-owned subsidiaries and VIEs, of which AEP is the primary beneficiary. The consolidated financial statements for AEP Texas include the Registrant Subsidiary, its wholly-owned subsidiaries, Transition Funding (consolidated VIEs) and Restoration Funding (a consolidated VIE). The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a consolidated VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (consolidated VIEs). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a consolidated VIE). Intercompany items are eliminated in consolidation.

The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings or losses is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income.

AEP, I&M, PSO and SWEPCo have undivided ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included on the income statements and the assets and liabilities are reflected on the balance sheets. See Note 17 - Variable Interest Entities and Equity Method Investments and Note 18 - Property, Plant and Equipment for additional information. In October 2020, AEP Texas, PSO and a nonaffiliated joint-owner executed an Environmental Liability and Property Transfer and Asset Purchase Agreement with a nonaffiliated third-party related to the Oklaunion Power Station site. See “Oklaunion Power Station” section of Note 7 for additional information.

Accounting for the Effects of Cost-Based Regulation

The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.

230

Use of Estimates

The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.

Cash and Cash Equivalents

Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.

AEP System Tax Allocation

AEP and subsidiaries join in the filing of a consolidated federal income tax return. Historically, the allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocated the benefit of current tax loss of the parent company (Parent Company Loss Benefit) to the AEP System subsidiaries through a reduction of current tax expense. In the first quarter of 2022, AEP and subsidiaries changed accounting for the Parent Company Loss Benefit from a reduction of current tax expense to an allocation through equity. The impact of this change was immaterial to the Registrant Subsidiaries’ financial statements. The consolidated NOL of the AEP System is allocated to each company in the consolidated group with taxable loss. With the exception of the allocation of the consolidated AEP System NOL, the loss of the Parent and tax credits, the method of allocation reflects a separate return result for each company in the consolidated group.

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

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

Reconciliation of Cash, Cash Equivalents and Restricted Cash

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


	December 31, 2022
	AEP		AEP Texas		APCo
	(in millions)
Cash and Cash Equivalents	$	509.4	$	0.1	$	7.5
Restricted Cash	47.1		32.7		14.4
Total Cash, Cash Equivalents and Restricted Cash	$	556.5	$	32.8	$	21.9


	December 31, 2021
	AEP		AEP Texas		APCo
	(in millions)
Cash and Cash Equivalents	$	403.4	$	0.1	$	2.5
Restricted Cash	48.0		30.4		17.6
Total Cash, Cash Equivalents and Restricted Cash	$	451.4	$	30.5	$	20.1

231

Other Temporary Investments (Applies to AEP)

Other Temporary Investments primarily include marketable securities and investments by its protected cell of EIS. These securities have readily determinable fair values and are carried at fair value with changes in fair value recognized in net income. The cost of securities sold is based on the specific identification or weighted-average cost method. See “Fair Value Measurements of Other Temporary Investments” section of Note 11 for additional information.

Inventory

Fossil fuel inventories are carried at average cost with the exception of AGR, which carries these inventories at the lower of average cost or net realizable value. Materials and supplies inventories are carried at average cost.

Accounts Receivable

Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities.

Revenue is recognized over time as the performance obligations of delivering energy to customers are satisfied. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing.

AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables they acquire from affiliated utility subsidiaries. See “Securitized Accounts Receivable – AEP Credit” section of Note 14 for additional information.

Allowance for Uncollectible Accounts

Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. The assessment is performed separately by each participating AEP subsidiary, which inherently contemplates any differences in geographical risk characteristics for the allowance. KPCo terminated selling accounts receivable to AEP Credit in the first quarter of 2022, based on the pending sale to Liberty. As a result of the termination, in the first quarter of 2022, KPCo recorded an allowance for uncollectible accounts on its balance sheet for those receivables no longer sold to AEP Credit. For receivables related to KPCo and APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For AEP Texas, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable, unless specifically identified. In addition to these processes, management contemplates available current information, as well as any reasonable and supportable forecast information, to determine if allowances for uncollectible accounts should be further adjusted in accordance with the accounting guidance for “Credit Losses.” Management’s assessments contemplate expected losses over the life of the accounts receivable.

232

Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries)

APCo, I&M, OPCo, PSO and SWEPCo do not have any significant customers that comprise 10% or more of their operating revenues. AEP Texas had significant transactions with REPs which on a combined basis account for the following percentages of Total Revenues for the years ended December 31 and Accounts Receivable – Customers as of December 31:


Significant Customers of AEP Texas:
Reliant Energy, Direct Energy and TXU Energy (a)	2022		2021		2020
Percentage of Total Revenues	45	%	43	%	46	%
Percentage of Accounts Receivable – Customers	42	%	41	%	40	%

(a)In January 2021, NRG Energy, parent company of Reliant Energy, completed a deal to purchase Direct Energy from Centrica.

AEPTCo had significant transactions with AEP Subsidiaries which on a combined basis account for the following percentages of Total Revenues for the years ended December 31 and Total Accounts Receivable as of December 31:


Significant Customers of AEPTCo:
AEP Subsidiaries	2022		2021		2020
Percentage of Total Revenues	79	%	79	%	78	%
Percentage of Total Accounts Receivable	72	%	81	%	78	%

The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuous basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements.

Renewable Energy Credits (Applies to all Registrants except AEP Texas and AEPTCo)

In regulated jurisdictions, the Registrants record renewable energy credits (RECs) at cost. For AEP’s competitive generation business, management records RECs at the lower of cost or net realizable value. The Registrants follow the inventory model for these RECs. RECs expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. RECs with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of RECs are reported in the Operating Activities section of the statements of cash flows. RECs that are consumed to meet applicable state renewable portfolio standards are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of RECs affects the determination of deferred fuel and REC costs.

Property, Plant and Equipment

Regulated

Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs accrued are typically recorded as regulatory liabilities when the revenue received for

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removal costs accrued exceeds actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. A regulatory asset balance will occur if actual removal costs incurred exceed accumulated removal costs accrued.

The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses.

Nuclear fuel, including nuclear fuel in the fabrication phase, is included in Other Property, Plant and Equipment on the balance sheets.

Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in-service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed or is not probable, the cost of that asset shall be written down to its then current estimated fair value, with the change charged to expense, and the asset is removed from plant-in-service or CWIP. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.

Nonregulated

Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense.

Allowance for Funds Used During Construction and Interest Capitalization

For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense on the statements of income. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.”

Asset Retirement Obligations (Applies to all Registrants except AEPTCo)

The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, wind farms, solar farms and certain coal-mining facilities. I&M records ARO for the decommissioning of the Cook Plant. AROs are computed as the present value of the estimated costs associated with the future retirement of an asset and are recorded in the period in which the liability is incurred. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be decommissioned, inflation, and discount rate, which may change significantly over time. The estimated costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since

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the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected.

Valuation of Nonderivative Financial Instruments

The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments.

Fair Value Measurements of Assets and Liabilities (Applies to all Registrants except AEPTCo)

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.

For commercial activities, exchange-traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange-traded derivatives where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket-based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility.

AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes.

Assets in the benefits and nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities

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compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Investments classified as Other are valued using Net Asset Value as a practical expedient. Items classified as Other are primarily cash equivalent funds, common collective trusts, commingled funds, structured products, private equity, real estate, infrastructure and alternative credit investments. These investments do not have a readily determinable fair value or they contain redemption restrictions which may include the right to suspend redemptions under certain circumstances. Redemption restrictions may also prevent certain investments from being redeemed at the reporting date for the underlying value.

Deferred Fuel Costs (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

The cost of purchased electricity, fuel and related emission allowances and emission control chemicals/consumables is charged to Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily using the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is an expectation that refunds or recoveries will extend beyond a one year period, based on a company’s filing with a commission or a commission directive. These deferrals are incorporated into the development of future fuel rates billed to or refunded to customers. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. The Registrants share the majority of their Off-system Sales margins to customers either through an active FAC or other rate mechanisms. Where the FAC or Off-system Sales sharing mechanism is capped, frozen, non-existent or not applicable to merchant operations, changes in fuel costs or sharing of Off-system Sales impact earnings.

Revenue Recognition

Regulatory Accounting

The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses or alternative revenues recognized in accordance with the guidance for “Regulated Operations”) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching revenue with its passage to customers in cost-based regulated rates.

When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are reviewed for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is derecognized as a charge against income.

Retail and Wholesale Supply and Delivery of Electricity

The Registrants recognize revenues from customers for retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize such revenues on the statements of income as the performance obligations of delivering energy to customers are satisfied. Recognized revenues include both billed and unbilled amounts. In accordance with the applicable state commission’s regulatory

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treatment, PSO and SWEPCo do not include the fuel portion in unbilled revenue, but rather recognize such revenues when billed to customers.

Wholesale transmission revenue is based on FERC-approved formula rate filings made for each calendar year using estimated costs. Revenues initially recognized per the annual rate filing are compared to actual costs, resulting in the subsequent recognition of an over or under-recovered amount, with interest, that is refunded or recovered, respectively, in a future year’s rates. These annual true-ups meet the definition of alternative revenues in accordance with the accounting guidance for “Regulated Operations”. An estimated annual true-up is recorded by the Registrants in the fourth quarter of each calendar year and a final annual true-up is recognized by the Registrants in the second quarter of each calendar year following the filing of annual FERC reports. Any portion of the true-ups applicable to an affiliated company is recorded as Accounts Receivable - Affiliated Companies or Accounts Payable - Affiliated Companies on the balance sheets. Any portion of the true-ups applicable to third-parties is recorded as Regulatory Assets or Regulatory Liabilities on the balance sheets. See Note 19 - Revenue from Contracts with Customers for additional information.

Gross versus Net Presentation of Certain Electricity Supply and Delivery Activities

Most of the power produced at the generation plants is sold to PJM or SPP. The Registrants also purchase power from PJM and SPP to supply power to customers. Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income. However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity for Resale on the statements of income. With the exception of certain dedicated load bilateral power supply contracts, the transactions of AEP’s nonregulated subsidiaries are reported as gross purchases or sales.

Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Purchased Electricity for Resale on the statements of income. Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s facts and circumstances. Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Purchased Electricity for Resale on the statements of income. All other non-trading derivative purchases are recorded net in revenues.

In general, the Registrants record expenses when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated. In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).

Energy Marketing and Risk Management Activities (Applies to all Registrants except AEPTCo)

The Registrants engage in power, capacity and, to a lesser extent, natural gas marketing as major power producers and participants in electricity and natural gas markets. The Registrants also engage in power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity risk management activities focused on markets where the AEP System owns assets and on adjacent markets. These activities include the purchase-and-sale of energy under forward contracts at fixed and variable prices. These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options. Certain energy marketing and risk management transactions are with RTOs.

The Registrants recognize revenues from marketing and risk management transactions that are not derivatives as the performance obligation of delivering the commodity is satisfied. Expenses from marketing and risk management transactions that are not derivatives are also recognized upon delivery of the commodity.

The Registrants use MTM accounting for marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or elected normal under the normal purchase normal sale election. Unrealized MTM gains and losses are included on the balance sheets as Risk

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Management Assets or Liabilities, as appropriate, and on the statements of income in Total Revenues. Realized gains and losses on marketing and risk management transactions are included in revenues or expenses based on the transaction’s facts and circumstances. However, in regulated jurisdictions subject to cost-based regulation, unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).

Certain qualifying marketing and risk management derivatives transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge). In the event the Registrants designate a cash flow hedge, the cash flow hedge’s gain or loss is initially recorded as a component of AOCI. When the forecasted transaction is realized and affects net income, the Registrants subsequently reclassify the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their statements of income. See “Accounting for Cash Flow Hedging Strategies” section of Note 10 for additional information.

Levelization of Nuclear Refueling Outage Costs (Applies to AEP and I&M)

In accordance with regulatory orders, I&M defers incremental operation and maintenance costs associated with periodic refueling outages at its Cook Plant and amortizes the costs over approximately 18 months, beginning with the month following the start of each unit’s refueling outage and lasting until the end of the month in which the same unit’s next scheduled refueling outage begins.

Maintenance

The Registrants expense maintenance costs as incurred. If it becomes probable that the Registrants will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues. In certain regulated jurisdictions, the Registrants defer costs above the level included in base rates and amortize those deferrals commensurate with recovery through rate riders.

Income Taxes and Investment and Production Tax Credits

The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled.

When the flow-through method of accounting for temporary differences is required by a regulator to be reflected in regulated revenues (that is, when deferred taxes are not included in the cost-of-service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense.

AEP and subsidiaries apply the deferral methodology for the recognition of ITCs. Deferred ITCs are amortized to income tax expense over the life of the asset that generated the credit. Amortization of deferred ITCs begins when the asset is placed in-service, except where regulatory commissions reflect ITCs in the rate-making process, then amortization begins when the utility is able to utilize the ITC on a stand-alone basis. Alternatively, PTCs reduce income tax expense as they are earned. PTCs are earned when electricity is produced.

The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense on the statements of income.

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Excise Taxes (Applies to all Registrants except AEPTCo)

As agents for some state and local governments, the Registrants collect from customers certain excise taxes levied by those state or local governments on customers. The Registrants do not record these taxes as revenue or expense.

Debt

Gains and losses from the reacquisition of debt used to finance regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates. Operations not subject to cost-based rate regulation report gains and losses on the reacquisition of debt in Interest Expense on the statements of income upon reacquisition.

Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt. The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations. The net amortization expense is included in Interest Expense on the statements of income.

Goodwill (Applies to AEP)

When the Registrants acquire a business, as defined by the accounting guidance for “Business Combinations,” management recognizes all acquired assets and liabilities at their fair value. To the extent that consideration exceeds the net fair value of the identified assets and liabilities, goodwill is recognized on the balance sheets. Goodwill is not amortized. Management tests acquired goodwill at the reporting unit level for impairment at least annually at its estimated fair value. Fair value is the amount at which an asset or liability could be bought or sold in a current transaction between willing parties other than in a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, management estimates fair value using various internal and external valuation methods.

Pension and OPEB Plans (Applies to all Registrants except AEPTCo)

AEP sponsors a qualified pension plan and two unfunded non-qualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a non-qualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. The Registrant Subsidiaries account for their participation in the AEP sponsored pension and OPEB plans using multiple-employer accounting. See Note 8 - Benefit Plans for additional information including significant accounting policies associated with the plans.

Investments Held in Trust for Future Liabilities (Applies to all Registrants except AEPTCo)

AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits, nuclear decommissioning and SNF disposal. All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations. The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities. To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers. Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate. Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance.

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Benefit Plans

All benefit plan assets are invested in accordance with each plan’s investment policy. The investment policy outlines the investment objectives, strategies and target asset allocations by plan.

The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimize net returns. Strategies used include:

•Maintaining a long-term investment horizon.

•Diversifying assets to help control volatility of returns at acceptable levels.

•Managing fees, transaction costs and tax liabilities to maximize investment earnings.

•Using active management of investments where appropriate risk/return opportunities exist.

•Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks.

•Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification.

The objective of the investment policy for the pension fund is to maintain the funded status of the plan while providing for growth in the plan assets to offset the growth in the plan liabilities. The current target asset allocations are as follows:


Pension Plan Assets	Target
Equity	30	%
Fixed Income	54	%
Other Investments	15	%
Cash and Cash Equivalents	1	%

OPEB Plans Assets	Target
Equity	59	%
Fixed Income	40	%
Cash and Cash Equivalents	1	%

The investment policy for each benefit plan contains various investment limitations. The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies or certain commingled funds). However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law.

For equity investments, the concentration limits are generally as follows:

•No security in excess of 5% of all equities.

•Cash equivalents must be less than 10% of an investment manager’s equity portfolio.

•No individual stock may be more than 10% and 7% for pension and OPEB investments, respectively, of each manager’s equity portfolio.

•No securities may be bought or sold on margin or other use of leverage.

For fixed income investments, each investment manager’s portfolio is compared to investment grade, diversified long and intermediate benchmark indices.

A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation. Real estate properties are illiquid, difficult to value and not actively traded. The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties. To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are

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diversified by region, property type and risk classification. Real estate holdings include core, value-added and opportunistic classifications.

A portion of the pension assets is invested in private equity. Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance. Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded. The pension plan uses limited partnerships to invest across the private equity investment spectrum. The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise. The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investments.

AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses. AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral. All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested. The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security. The securities lending program’s objective is to provide modest incremental income with a limited increase in risk. As of December 31, 2022 and 2021, the fair value of securities on loan as part of the program was $83 million and $137 million, respectively. Cash and securities obtained as collateral exceeded the fair value of the securities loaned as of December 31, 2022 and 2021.

Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts. The strategy for holding life insurance contracts in the taxable Voluntary Employees’ Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust. Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid. Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities. With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds. A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges. The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities.

Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal. The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities. The cash funds are valued each business day and provide daily liquidity.

Nuclear Trust Funds (Applies to AEP and I&M)

Nuclear decommissioning and SNF trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and SNF disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include:

•Acceptable investments (rated investment grade or above when purchased).

•Maximum percentage invested in a specific type of investment.

•Prohibition of investment in obligations of AEP, I&M or their affiliates.

•Withdrawals permitted only for payment of decommissioning costs and trust expenses.

I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by an external investment manager that must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.

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

Other-than-temporary impairments for investments in debt securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains, unrealized losses and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. See the “Nuclear Contingencies” section of Note 6 for additional discussion of nuclear matters. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts.

Comprehensive Income (Loss) (Applies to all Registrants except AEPTCo and OPCo)

Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).

Stock-Based Compensation Plans

As of December 31, 2022, AEP had performance shares and restricted stock units outstanding under the American Electric Power System 2015 Long-Term Incentive Plan (2015 LTIP). Upon vesting, all outstanding performance shares and restricted stock units settle in AEP common stock. All performance units awarded prior to 2017 and restricted stock units granted after January 1, 2013 and prior to January 1, 2017 that vested to executive officers were settled in cash. During 2019, all of the remaining performance units and restricted stock units that settle in cash were settled. The impact of AEP’s stock-based compensation plans are insignificant to the financial statements of the Registrant Subsidiaries.

AEP maintains a variety of tax qualified and non-qualified deferred compensation plans for employees and non-employee directors that include, among other options, an investment in or an investment return equivalent to that of AEP common stock. This includes AEP career shares maintained under the American Electric Power System Stock Ownership Requirement Plan (SORP), which facilitates executives in meeting minimum stock ownership requirements assigned to them by the Human Resources Committee of the Board of Directors. AEP career shares are derived from vested performance shares granted to employees under the 2015 LTIP and previous long-term incentive plans. AEP career shares accrue additional dividend shares in an amount equal to dividends paid on AEP common shares at the closing market price on the dividend payments date. All AEP career shares are settled in shares of AEP common stock after the executive’s service with AEP ends.

Performance shares awarded after January 1, 2017 are classified as temporary equity in the Mezzanine Equity section of the balance sheets until the awards vest. Upon vesting, the performance shares are classified as permanent equity. These awards may be settled in cash upon an employee’s qualifying termination due to a change in control. Because such event is not solely within the control of the company, these awards are classified outside of permanent equity until the awards vest.

AEP compensates their non-employee directors, in part, with stock units under the American Electric Power Company, Inc. Stock Unit Accumulation Plan for Non-Employee Directors. These stock units were payable in cash

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to directors after their service ends. Effective in June 2022, these stock units became payable in AEP common stock rather than cash.

Management measures and recognizes compensation expense for all share-based payment awards to employees and directors based on estimated fair values. For share-based payment awards with service only vesting conditions, management recognizes compensation expense on a straight-line basis. Stock-based compensation expense recognized on the statements of income for the years ended December 31, 2022, 2021 and 2020 is based on the number of outstanding awards at the end of each period without a reduction for estimated forfeitures. AEP accounts for forfeitures in the period in which they occur.

For the years ended December 31, 2022, 2021 and 2020, compensation costs are included in Net Income for the performance shares, career shares, restricted stock units and the non-employee director stock units. Compensation costs may also be capitalized. See Note 15 - Stock-based Compensation for additional information.

Equity Method Investments in Unconsolidated Entities (Applies to AEP and SWEPCo)

The equity method of accounting is used for equity investments where either AEP or SWEPCo exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings or losses is included in Equity Earnings (Loss) of Unconsolidated Subsidiaries on the statements of income. AEP and SWEPCo regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recognized when the investment has experienced a loss in value that is other-than-temporary in nature.

AEP’s significant equity method investments include ETT, DHLC and four joint venture interests which own distinct wind generation facilities. See Note 17 - Variable Interest Entities and Equity Method Investments for additional information.

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:


	Years Ended December 31,
	2022				2021				2020
	(in millions, except per-share data)
			$/share				$/share				$/share


Earnings Attributable to AEP Common Shareholders	$	2,307.2			$	2,488.1			$	2,200.1

Weighted-Average Number of Basic AEP Common Shares Outstanding	511.8		$	4.51	500.5		$	4.97	495.7		$	4.44
Weighted-Average Dilutive Effect of Stock-Based Awards	1.7		(0.02)		1.3		(0.01)		1.5		(0.02)
Weighted-Average Number of Diluted AEP Common Shares Outstanding	513.5		$	4.49	501.8		$	4.96	497.2		$	4.42

Equity Units are potentially dilutive securities but were excluded from the calculation of diluted EPS for the years ended December 31, 2022, 2021 and 2020, as the dilutive stock price thresholds were not met. See Note 14 - Financing Activities for additional information related to Equity Units.

243

There were no antidilutive shares outstanding as of December 31, 2022 and 2021. There were 128 thousand antidilutive shares outstanding as of December 31, 2020.

Supplementary Income Statement Information

The following tables provide the components of Depreciation and Amortization for the years ended December 31, 2022, 2021 and 2020:


2022

Depreciation and Amortization	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Depreciation and Amortization of Property, Plant and Equipment	$	3,072.8	$	363.5	$	346.2	$	576.1	$	511.9	$	293.1	$	226.2	$	319.3
Amortization of Certain Securitized Assets	93.3		93.3		—		—		—		—		—		—
Amortization of Regulatory Assets and Liabilities	36.7		(4.4)		—		(0.2)		15.3		1.2		3.9		5.5
Total Depreciation and Amortization	$	3,202.8	$	452.4	$	346.2	$	575.9	$	527.2	$	294.3	$	230.1	$	324.8


2021

Depreciation and Amortization	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Depreciation and Amortization of Property, Plant and Equipment	$	2,717.1	$	327.2	$	297.3	$	547.0	$	424.9	$	301.1	$	185.9	$	292.9
Amortization of Certain Securitized Assets	64.2		64.2		—		—		—		—		—		—
Amortization of Regulatory Assets and Liabilities	44.4		(4.4)		—		(0.8)		21.1		2.2		10.7		2.1
Total Depreciation and Amortization	$	2,825.7	$	387.0	$	297.3	$	546.2	$	446.0	$	303.3	$	196.6	$	295.0


2020

Depreciation and Amortization	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Depreciation and Amortization of Property, Plant and Equipment	$	2,487.5	$	364.2	$	249.0	$	507.8	$	393.3	$	275.0	$	171.9	$	271.2
Amortization of Certain Securitized Assets	171.3		171.3		—		—		—		—		—		—
Amortization of Regulatory Assets and Liabilities	24.0		(5.7)		—		(0.3)		18.3		1.6		1.6		1.5
Total Depreciation and Amortization	$	2,682.8	$	529.8	$	249.0	$	507.5	$	411.6	$	276.6	$	173.5	$	272.7

244

Supplementary Cash Flow Information (Applies to AEP)


	Years Ended December 31,
Cash Flow Information	2022		2021		2020
	(in millions)
Cash Paid (Received) for:
Interest, Net of Capitalized Amounts	$	1,286.3	$	1,137.2	$	1,029.1
Income Taxes	116.8		13.2		(49.1)
Noncash Investing and Financing Activities:
Acquisitions Under Finance Leases	31.8		287.6		44.2
Construction Expenditures Included in Current Liabilities as of December 31,	1,258.9		1,180.4		975.4
Construction Expenditures Included in Noncurrent Liabilities as of December 31,	—		—		5.5

Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,	—		—		33.4


Noncash Contribution of Assets to Cedar Creek Project	—		(9.3)		—
Noncontrolling Interest Assumed - Dry Lake Solar Project	—		35.3		—


Forward Equity Purchase Contracts Included in Current and Noncurrent Liabilities as of December 31,	—		—		110.6

245

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.

246

3. COMPREHENSIVE INCOME

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

Presentation of Comprehensive Income

The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the years ended December 31, 2022, 2021 and 2020. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 8 - Benefit Plans for additional information.


AEP

	Cash Flow Hedges					Pension and OPEB
For the Year Ended December 31, 2022	Commodity		Interest Rate			Amortization of Deferred Costs		Changes in Funded Status		Total
	(in millions)
Balance in AOCI as of December 31, 2021	$	163.7	$	(21.3)		$	115.6	$	(73.2)	$	184.8
Change in Fair Value Recognized in AOCI, Net of Tax	477.3		18.4		(a)	—		(155.4)		340.3
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (b)	0.1		—			—		—		0.1
Purchased Electricity for Resale (b)	(528.6)		—			—		—		(528.6)
Interest Expense (b)	—		4.0			—		—		4.0
Amortization of Prior Service Cost (Credit)	—		—			(21.8)		—		(21.8)
Amortization of Actuarial (Gains) Losses	—		—			8.6		—		8.6
Reclassifications from AOCI, before Income Tax (Expense) Benefit	(528.5)		4.0			(13.2)		—		(537.7)
Income Tax (Expense) Benefit	(111.0)		0.8			(2.8)		—		(113.0)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	(417.5)		3.2			(10.4)		—		(424.7)
Reclassifications of KPCo Pension and OPEB Regulatory Assets to AOCI	—		—			—		(21.1)		(21.1)
Income Tax (Expense) Benefit	—		—			—		(4.4)		(4.4)
Reclassifications of KPCo Pension and OPEB Regulatory Assets to AOCI, Net of Income Tax (Expense) Benefit	—		—			—		(16.7)		(16.7)
Net Current Period Other Comprehensive Income (Loss)	59.8		21.6			(10.4)		(172.1)		(101.1)
Balance in AOCI as of December 31, 2022	$	223.5	$	0.3		$	105.2	$	(245.3)	$	83.7

247


AEP

	Cash Flow Hedges					Pension and OPEB
For the Year Ended December 31, 2021	Commodity		Interest Rate			Amortization of Deferred Costs		Changes in Funded Status		Total
	(in millions)
Balance in AOCI as of December 31, 2020	$	(60.6)	$	(47.5)		$	123.7	$	(100.7)	$	(85.1)
Change in Fair Value Recognized in AOCI, Net of Tax	488.2		21.1		(a)	—		27.5		536.8
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (b)	0.7		—			—		—		0.7
Purchased Electricity for Resale (b)	(334.8)		—			—		—		(334.8)
Interest Expense (b)	—		6.5			—		—		6.5
Amortization of Prior Service Cost (Credit)	—		—			(19.4)		—		(19.4)
Amortization of Actuarial (Gains) Losses	—		—			9.1		—		9.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit	(334.1)		6.5			(10.3)		—		(337.9)
Income Tax (Expense) Benefit	(70.2)		1.4			(2.2)		—		(71.0)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	(263.9)		5.1			(8.1)		—		(266.9)
Net Current Period Other Comprehensive Income (Loss)	224.3		26.2			(8.1)		27.5		269.9


Balance in AOCI as of December 31, 2021	$	163.7	$	(21.3)		$	115.6	$	(73.2)	$	184.8


	Cash Flow Hedges					Pension and OPEB
For the Year Ended December 31, 2020	Commodity		Interest Rate			Amortization of Deferred Costs		Changes in Funded Status		Total
	(in millions)
Balance in AOCI as of December 31, 2019	$	(103.5)	$	(11.5)		$	130.7	$	(163.4)	$	(147.7)
Change in Fair Value Recognized in AOCI, Net of Tax	(89.2)		(39.9)		(a)	—		62.7		(66.4)
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (b)	(0.4)		—			—		—		(0.4)
Purchased Electricity for Resale (b)	167.6		—			—		—		167.6
Interest Expense (b)	—		4.9			—		—		4.9
Amortization of Prior Service Cost (Credit)	—		—			(19.2)		—		(19.2)
Amortization of Actuarial (Gains) Losses	—		—			10.3		—		10.3
Reclassifications from AOCI, before Income Tax (Expense) Benefit	167.2		4.9			(8.9)		—		163.2
Income Tax (Expense) Benefit	35.1		1.0			(1.9)		—		34.2
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	132.1		3.9			(7.0)		—		129.0
Net Current Period Other Comprehensive Income (Loss)	42.9		(36.0)			(7.0)		62.7		62.6


Balance in AOCI as of December 31, 2020	$	(60.6)	$	(47.5)		$	123.7	$	(100.7)	$	(85.1)

248


AEP Texas

				Pension and OPEB
				Amortization		Changes in
		Cash Flow Hedge –		of Deferred		Funded
For the Year Ended December 31, 2022		Interest Rate		Costs		Status		Total
	(in millions)
Balance in AOCI as of December 31, 2021		$	(1.3)	$	5.3	$	(10.5)	$	(6.5)
Change in Fair Value Recognized in AOCI, Net of Tax		—		—		(3.2)		(3.2)
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)		1.3		—		—		1.3
Amortization of Prior Service Cost (Credit)		—		(0.1)		—		(0.1)
Amortization of Actuarial (Gains) Losses		—		0.2		—		0.2
Reclassifications from AOCI, before Income Tax (Expense) Benefit		1.3		0.1		—		1.4
Income Tax (Expense) Benefit		0.3		—		—		0.3
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		1.0		0.1		—		1.1
Net Current Period Other Comprehensive Income (Loss)		1.0		0.1		(3.2)		(2.1)
Balance in AOCI as of December 31, 2022		$	(0.3)	$	5.4	$	(13.7)	$	(8.6)


				Pension and OPEB
				Amortization		Changes in
		Cash Flow Hedge –		of Deferred		Funded
For the Year Ended December 31, 2021		Interest Rate		Costs		Status		Total
	(in millions)
Balance in AOCI as of December 31, 2020		$	(2.3)	$	5.1	$	(11.7)	$	(8.9)
Change in Fair Value Recognized in AOCI, Net of Tax		0.1		—		1.2		1.3
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)		1.2		—		—		1.2
Amortization of Prior Service Cost (Credit)		—		(0.1)		—		(0.1)
Amortization of Actuarial (Gains) Losses		—		0.3		—		0.3
Reclassifications from AOCI, before Income Tax (Expense) Benefit		1.2		0.2		—		1.4
Income Tax (Expense) Benefit		0.3		—		—		0.3
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.9		0.2		—		1.1
Net Current Period Other Comprehensive Income (Loss)		1.0		0.2		1.2		2.4

Balance in AOCI as of December 31, 2021		$	(1.3)	$	5.3	$	(10.5)	$	(6.5)


				Pension and OPEB
				Amortization		Changes in
		Cash Flow Hedge –		of Deferred		Funded
For the Year Ended December 31, 2020		Interest Rate		Costs		Status		Total
	(in millions)
Balance in AOCI as of December 31, 2019		$	(3.4)	$	4.9	$	(14.3)	$	(12.8)
Change in Fair Value Recognized in AOCI, Net of Tax		0.1		—		2.6		2.7
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)		1.3		—		—		1.3
Amortization of Prior Service Cost (Credit)		—		(0.1)		—		(0.1)
Amortization of Actuarial (Gains) Losses		—		0.3		—		0.3
Reclassifications from AOCI, before Income Tax (Expense) Benefit		1.3		0.2		—		1.5
Income Tax (Expense) Benefit		0.3		—		—		0.3
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		1.0		0.2		—		1.2
Net Current Period Other Comprehensive Income (Loss)		1.1		0.2		2.6		3.9

Balance in AOCI as of December 31, 2020		$	(2.3)	$	5.1	$	(11.7)	$	(8.9)

249


APCo

				Pension and OPEB
				Amortization		Changes in
		Cash Flow Hedge –		of Deferred		Funded
For the Year Ended December 31, 2022		Interest Rate		Costs		Status		Total
	(in millions)
Balance in AOCI as of December 31, 2021		$	7.5	$	1.2	$	15.7	$	24.4
Change in Fair Value Recognized in AOCI, Net of Tax		—		—		(24.1)		(24.1)
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)		(1.0)		—		—		(1.0)
Amortization of Prior Service Cost (Credit)		—		(5.4)		—		(5.4)

Reclassifications from AOCI, before Income Tax (Expense) Benefit		(1.0)		(5.4)		—		(6.4)
Income Tax (Expense) Benefit		(0.2)		(1.1)		—		(1.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.8)		(4.3)		—		(5.1)
Net Current Period Other Comprehensive Income (Loss)		(0.8)		(4.3)		(24.1)		(29.2)
Balance in AOCI as of December 31, 2022		$	6.7	$	(3.1)	$	(8.4)	$	(4.8)


			Pension and OPEB
			Amortization		Changes in
	Cash Flow Hedges -		of Deferred		Funded
For the Year Ended December 31, 2021	Interest Rate		Costs		Status		Total
	(in millions)
Balance in AOCI as of December 31, 2020	$	(0.8)	$	5.4	$	2.6	$	7.2
Change in Fair Value Recognized in AOCI, Net of Tax	9.2		—		13.1		22.3
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)	(1.1)		—		—		(1.1)
Amortization of Prior Service Cost (Credit)	—		(5.3)		—		(5.3)

Reclassifications from AOCI, before Income Tax (Expense) Benefit	(1.1)		(5.3)		—		(6.4)
Income Tax (Expense) Benefit	(0.2)		(1.1)		—		(1.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	(0.9)		(4.2)		—		(5.1)
Net Current Period Other Comprehensive Income (Loss)	8.3		(4.2)		13.1		17.2

Balance in AOCI as of December 31, 2021	$	7.5	$	1.2	$	15.7	$	24.4


			Pension and OPEB
			Amortization		Changes in
	Cash Flow Hedges -		of Deferred		Funded
For the Year Ended December 31, 2020	Interest Rate		Costs		Status		Total
	(in millions)
Balance in AOCI as of December 31, 2019	$	0.9	$	9.2	$	(5.1)	$	5.0
Change in Fair Value Recognized in AOCI, Net of Tax	(0.7)		—		7.7		7.0
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)	(1.3)		—		—		(1.3)
Amortization of Prior Service Cost (Credit)	—		(5.3)		—		(5.3)
Amortization of Actuarial (Gains) Losses	—		0.5		—		0.5
Reclassifications from AOCI, before Income Tax (Expense) Benefit	(1.3)		(4.8)		—		(6.1)
Income Tax (Expense) Benefit	(0.3)		(1.0)		—		(1.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	(1.0)		(3.8)		—		(4.8)
Net Current Period Other Comprehensive Income (Loss)	(1.7)		(3.8)		7.7		2.2

Balance in AOCI as of December 31, 2020	$	(0.8)	$	5.4	$	2.6	$	7.2

250


I&M

			Pension and OPEB
			Amortization		Changes in
	Cash Flow Hedge –		of Deferred		Funded
For the Year Ended December 31, 2022	Interest Rate		Costs		Status		Total
	(in millions)
Balance in AOCI as of December 31, 2021	$	(6.7)	$	4.7	$	0.7	$	(1.3)
Change in Fair Value Recognized in AOCI, Net of Tax	—		—		(0.3)		(0.3)
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)	2.0		—		—		2.0
Amortization of Prior Service Cost (Credit)	—		(0.8)		—		(0.8)
Amortization of Actuarial (Gains) Losses	—		0.4		—		0.4
Reclassifications from AOCI, before Income Tax (Expense) Benefit	2.0		(0.4)		—		1.6
Income Tax (Expense) Benefit	0.4		(0.1)		—		0.3
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	1.6		(0.3)		—		1.3
Net Current Period Other Comprehensive Income (Loss)	1.6		(0.3)		(0.3)		1.0
Balance in AOCI as of December 31, 2022	$	(5.1)	$	4.4	$	0.4	$	(0.3)


			Pension and OPEB
			Amortization		Changes in
	Cash Flow Hedge –		of Deferred		Funded
For the Year Ended December 31, 2021	Interest Rate		Costs		Status		Total
	(in millions)
Balance in AOCI as of December 31, 2020	$	(8.3)	$	4.8	$	(3.5)	$	(7.0)
Change in Fair Value Recognized in AOCI, Net of Tax	—		—		4.2		4.2
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)	2.0		—		—		2.0
Amortization of Prior Service Cost (Credit)	—		(0.8)		—		(0.8)
Amortization of Actuarial (Gains) Losses	—		0.7		—		0.7
Reclassifications from AOCI, before Income Tax (Expense) Benefit	2.0		(0.1)		—		1.9
Income Tax (Expense) Benefit	0.4		—		—		0.4
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	1.6		(0.1)		—		1.5
Net Current Period Other Comprehensive Income (Loss)	1.6		(0.1)		4.2		5.7

Balance in AOCI as of December 31, 2021	$	(6.7)	$	4.7	$	0.7	$	(1.3)


			Pension and OPEB
			Amortization		Changes in
	Cash Flow Hedge –		of Deferred		Funded
For the Year Ended December 31, 2020	Interest Rate		Costs		Status		Total
	(in millions)
Balance in AOCI as of December 31, 2019	$	(9.9)	$	4.9	$	(6.6)	$	(11.6)
Change in Fair Value Recognized in AOCI, Net of Tax	—		—		3.1		3.1
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)	2.0		—		—		2.0
Amortization of Prior Service Cost (Credit)	—		(0.8)		—		(0.8)
Amortization of Actuarial (Gains) Losses	—		0.7		—		0.7
Reclassifications from AOCI, before Income Tax (Expense) Benefit	2.0		(0.1)		—		1.9
Income Tax (Expense) Benefit	0.4		—		—		0.4
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	1.6		(0.1)		—		1.5
Net Current Period Other Comprehensive Income (Loss)	1.6		(0.1)		3.1		4.6

Balance in AOCI as of December 31, 2020	$	(8.3)	$	4.8	$	(3.5)	$	(7.0)

251

PSO




	Cash Flow Hedge –
For the Year Ended December 31, 2022	Interest Rate
	(in millions)
Balance in AOCI as of December 31, 2021	$	—
Change in Fair Value Recognized in AOCI, Net of Tax	1.3
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)	1.3
Balance in AOCI as of December 31, 2022	$	1.3




	Cash Flow Hedge –
For the Year Ended December 31, 2021	Interest Rate
	(in millions)
Balance in AOCI as of December 31, 2020	$	0.1
Change in Fair Value Recognized in AOCI, Net of Tax	—
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 December 31, 2021	$	—




	Cash Flow Hedge –
For the Year Ended December 31, 2020	Interest Rate
	(in millions)
Balance in AOCI as of December 31, 2019	$	1.1
Change in Fair Value Recognized in AOCI, Net of Tax	—
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)	(1.3)


Reclassifications from AOCI, before Income Tax (Expense) Benefit	(1.3)
Income Tax (Expense) Benefit	(0.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	(1.0)
Net Current Period Other Comprehensive Income (Loss)	(1.0)

Balance in AOCI as of December 31, 2020	$	0.1

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SWEPCo

			Pension and OPEB
			Amortization		Changes in
	Cash Flow Hedge –		of Deferred		Funded
For the Year Ended December 31, 2022	Interest Rate		Costs		Status		Total
	(in millions)
Balance in AOCI as of December 31, 2021	$	1.2	$	(4.4)	$	9.9	$	6.7
Change in Fair Value Recognized in AOCI, Net of Tax	—		—		(9.2)		(9.2)
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)	(0.1)		—		—		(0.1)
Amortization of Prior Service Cost (Credit)	—		(2.0)		—		(2.0)

Reclassifications from AOCI, before Income Tax (Expense) Benefit	(0.1)		(2.0)		—		(2.1)
Income Tax (Expense) Benefit	—		(0.4)		—		(0.4)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	(0.1)		(1.6)		—		(1.7)
Net Current Period Other Comprehensive Income (Loss)	(0.1)		(1.6)		(9.2)		(10.9)
Balance in AOCI as of December 31, 2022	$	1.1	$	(6.0)	$	0.7	$	(4.2)


			Pension and OPEB
			Amortization		Changes in
	Cash Flow Hedge –		of Deferred		Funded
For the Year Ended December 31, 2021	Interest Rate		Costs		Status		Total
	(in millions)
Balance in AOCI as of December 31, 2020	$	(0.3)	$	(2.8)	$	5.0	$	1.9
Change in Fair Value Recognized in AOCI, Net of Tax	—		—		4.9		4.9
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)	1.9		—		—		1.9
Amortization of Prior Service Cost (Credit)	—		(2.0)		—		(2.0)

Reclassifications from AOCI, before Income Tax (Expense) Benefit	1.9		(2.0)		—		(0.1)
Income Tax (Expense) Benefit	0.4		(0.4)		—		—
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	1.5		(1.6)		—		(0.1)
Net Current Period Other Comprehensive Income (Loss)	1.5		(1.6)		4.9		4.8

Balance in AOCI as of December 31, 2021	$	1.2	$	(4.4)	$	9.9	$	6.7


			Pension and OPEB
			Amortization		Changes in
	Cash Flow Hedge –		of Deferred		Funded
For the Year Ended December 31, 2020	Interest Rate		Costs		Status		Total
	(in millions)
Balance in AOCI as of December 31, 2019	$	(1.8)	$	(1.3)	$	1.8	$	(1.3)
Change in Fair Value Recognized in AOCI, Net of Tax	—		—		3.2		3.2
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)	1.9		—		—		1.9
Amortization of Prior Service Cost (Credit)	—		(2.0)		—		(2.0)
Amortization of Actuarial (Gains) Losses	—		0.1		—		0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit	1.9		(1.9)		—		—
Income Tax (Expense) Benefit	0.4		(0.4)		—		—
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	1.5		(1.5)		—		—
Net Current Period Other Comprehensive Income (Loss)	1.5		(1.5)		3.2		3.2

Balance in AOCI as of December 31, 2020	$	(0.3)	$	(2.8)	$	5.0	$	1.9

(a)The change in fair value includes $(10) million, $(7) million and $6 million for the years ended December 31, 2022, 2021 and 2020, respectively, 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.

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4. RATE MATTERS

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

The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrants’ recent significant rate orders and pending rate filings are addressed in this note.

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

AEP Texas Interim Transmission and Distribution Rates

Through December 31, 2022, AEP Texas’ cumulative revenues from interim base rate increases that are subject to review is approximately $614 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 statutory 140 basis point band (8.5% bottom, 9.2% midpoint, 9.9% top). APCo appealed this order and a similar order on reconsideration to the Virginia Supreme Court in March 2021, alleging the Virginia SCC erred in finding that costs associated with asset impairments related to APCo early retirement determinations for certain generation facilities should not be attributed to the 2017-2019 test periods under review and deemed fully recovered in the period recorded. In August 2022, the Virginia Supreme Court agreed with this portion of APCo’s appeal and remanded this issue regarding the retired coal-fired plants back to the Virginia SCC for further proceedings. In September 2022, as a result of the Virginia Supreme Court ruling, APCo expensed the remaining $25 million closed coal plant regulatory asset that was previously ordered by the Virginia SCC and recorded a $37 million regulatory asset for previously incurred costs that APCo is expecting to recover as a result of earning below its 2017-2019 authorized ROE band.

In response to the Virginia Supreme Court’s August 2022 opinion, the Virginia SCC initiated remand proceedings and, in December 2022, issued an order that: (a) approved APCo’s requested $37 million regulatory asset related to previously incurred costs as a result of APCo earning below its 2017-2019 authorized ROE band, (b) authorized a $28 million annual increase in APCo Virginia base rates effective October 2022 and (c) approved a rider to recover approximately $48 million related to this APCo Virginia base rate increase for the period January 2021 through September 2022. APCo’s 2022 financial statements reflect the impact of the Virginia SCC’s December 2022 order.

2020-2022 Virginia Triennial Review

In March 2023, APCo will submit its required Virginia earnings test calculation to the Virginia SCC for the 2020-2022 Triennial Review period. For Triennial Review periods in which a Virginia utility earns below its authorized ROE band, the utility may file to recover expenses incurred, up to the bottom of the authorized ROE band, related to major storms, the early retirement of fossil fuel generating assets and certain projects necessary to comply with state and federal environmental legislation. As of December 31, 2022, APCo has deferred approximately $38 million related to previously incurred costs as a result of the current estimate that APCo will earn below the bottom of its authorized ROE band during the 2020-2022 Triennial Review period. If it is determined

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that APCo has earned above the bottom of its authorized ROE band for the 2020-2022 Triennial Review period it could reduce future net income and cash flows and impact financial condition.

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. In August 2021, the Virginia SCC issued an order approving recovery of CCR-related operation and maintenance expenses and investments at the Amos and Mountaineer Plants through an active rider. The order also denied APCo’s request to recover the cost of ELG investments and denied recovery of previously incurred ELG costs, but did not preclude APCo from refiling for approval. 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 March 2022, APCo refiled for approval to recover the Virginia jurisdictional share of ELG investments at the Amos and Mountaineer Plants. The Virginia SCC issued a November 2022 order approving this request.

2021 and 2022 ENEC (Expanded Net Energy Cost) Filings

In April 2021, APCo and WPCo (the Companies) requested a $73 million annual increase in ENEC rates based on a cumulative combined $55 million ENEC under-recovery as of February 28, 2021 and a combined $18 million increase in projected ENEC costs for the period September 2021 through August 2022. In September 2021, the WVPSC issued an order approving a $7 million overall increase in ENEC rates, including an approval for recovery of the Companies’ cumulative $55 million ENEC under-recovery balance and a $48 million reduction in projected costs for the period September 2021 through August 2022. Subsequently, the Companies submitted a request for reconsideration of this order, identifying flaws in the WVPSC’s calculation of forecasted future year fuel expense and purchased power costs.

In March 2022, the WVPSC issued an order granting the Companies’ request for reconsideration, in part, and approving $31 million in projected costs for the period September 2021 through August 2022. The order also reopened the 2021 ENEC case to require the Companies to explain the significant growth in the reported under-recovery of ENEC costs and to provide various other information including revised projected costs for the period March 2022 through August 2022. Also, in March 2022, the Companies filed testimony providing the information requested in the WVPSC’s order and requested a $155 million annual increase in ENEC rates effective May 1, 2022. In May 2022, the WVPSC issued an order approving a $93 million overall increase to ENEC rates to recover projected annual ENEC costs. However, the WVPSC stated that actual and projected ENEC costs are still subject to a prudency review.

In April 2022, the Companies submitted their 2022 annual ENEC filing with the WVPSC requesting a $297 million annual increase in ENEC revenues, inclusive of the previously requested $155 million increase, effective September 1, 2022.

In September 2022, following an agreed upon delay in the proceedings of the Companies’ 2022 ENEC case, certain intervenors submitted testimony recommending disallowances of at least $83 million to the Companies’ historical period ENEC under-recovery balance along with proposals to either securitize the Companies’ remaining ENEC balance or defer recovery of this balance beyond the traditional one-year period. West Virginia Staff recommended a $13 million increase in ENEC rates pending the outcome of the ENEC prudency review. In February 2023, the WVPSC issued an order stating that the commission will not grant additional rate increases for fuel costs until the WVPSC staff completes its prudency review. As of December 31, 2022, the Companies’ cumulative ENEC under-recovery was $520 million. If any deferred ENEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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June 2022 West Virginia Storm Costs

In June 2022, the West Virginia service territories of APCo and WPCo (the Companies) were impacted by strong winds from multiple storms resulting in system damages and power outages. As of December 31, 2022, the Companies incurred and deferred an estimated $17 million in incremental distribution operation and maintenance expenses related to service restoration efforts. The Companies will seek recovery of these deferrals in future filings. If any of the storm restoration costs are not recoverable, it could 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 December 31, 2022, AEP’s share of ETT’s cumulative revenues that are subject to review is approximately $1.5 billion. A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring.

In December 2022, ETT and various intervenors filed a stipulation and settlement agreement with the PUCT. The agreement maintains ETT’s previously allowed ROE and capital structure and includes: (a) a $14 million decrease to the current annual revenue requirement effective February 1, 2023, (b) a provision that ETT must make an interim transmission cost of service filing by June 1, 2023, (c) a $2 million line item decrease to the revenue requirement determined in each interim transmission cost of service filing until the filing of the next comprehensive base rate review and (d) no determination of prudence on any transmission investment added since ETT’s last comprehensive base rate review, which would leave the $1.5 billion of cumulative revenues above subject to review in the next comprehensive base rate review. In February 2023, the PUCT approved the stipulation and settlement agreement. As part of the approved agreement, new rates will be implemented in February 2023 and ETT is required to file for a comprehensive base rate review no later than February 1, 2025.

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

Michigan Power Supply Cost Recovery (PSCR) Reconciliation

In April 2022, an ALJ issued a PFD for I&M’s PSCR reconciliation for the 12-month period ending December 31, 2020, recommending the MPSC disallow approximately $8 million of purchased power costs that I&M incurred under the Inter-Company Power Agreement with OVEC and the Unit Power Agreement with AEGCo. In February 2023, the MPSC issued an order resulting in a $1 million disallowance of 2020 OVEC costs.

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 August 2022, I&M submitted its FAC filing and earnings test evaluation for the period ended May 2022, which calculated a credit due to customers of $14 million. In October 2022, the IURC approved the FAC filing and earnings test evaluation, with the credit to customers starting in November 2022 through the FAC. As of December 31, 2022, I&M’s financial statements adequately reflect the estimated impact of I&M’s upcoming Indiana earnings test filings. If it is determined that I&M’s over-earnings exceed what has been recorded, it could reduce future net income and cash flows and impact financial condition.

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2022 Michigan Integrated Resource Plan (IRP) Filing

In February 2022, I&M filed a request with the MPSC for approval of its 2022 IRP. Included in that filing were requests for approval and deferral of costs associated with resources commencing construction within three years of the Commission’s order in the filing. These resources include the new generation resources expected to be in-service by 2028 and demand-side resources, including load management programs and conservation voltage reduction investments. I&M is also requesting MPSC approval of I&M’s Rockport Plant, Unit 2 transition plan consistent with that approved by the IURC, including certain cost recovery related to remaining net book value of leasehold improvements made during the term of the Rockport Unit 2 lease and future use of Rockport Plant, Unit 2 as a capacity resource. In addition, I&M has made requests for approval of a financial incentive on certain power purchase agreements and load management programs. As of December 31, 2022, I&M’s total net book value for these Rockport Plant, Unit 2 leasehold improvements was approximately $17 million on a Michigan jurisdictional basis.

In November 2022, I&M filed a settlement agreement, which included a Rockport Plant, Unit 2 transition plan. Under this plan, I&M Michigan ratepayers will receive a jurisdictional share of post-lease revenues in excess of costs from Rockport Plant, Unit 2’s operations as a merchant facility. In addition, I&M will continue to recover the remaining net book value of Rockport Plant, Unit 2 leasehold improvements through 2028, including a pretax return. In February 2023, the MPSC issued an order approving the settlement agreement without modification.

KPCo Rate Matters (Applies to AEP)

CCR/ELG Compliance Plan Filings

KPCo and WPCo each own a 50% interest in the Mitchell Plant. As of December 31, 2022, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $577 million. 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 May 2022, the KPSC approved recovery of the Kentucky jurisdictional share of ELG costs incurred at the Mitchell Plant prior to July 15, 2021.

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 also ordered that WPCo will be given the opportunity to recover, from its customers, the ELG and 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. The WVPSC’s order further states that unless KPCo pays for its share of costs for ELG improvements and costs necessary to continue operations beyond 2028, the benefit of the capacity and energy made possible by those improvements and operating Mitchell Plant beyond 2028 should benefit only West Virginia jurisdictional customers who have shared in paying for those costs.

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OPCo Rate Matters (Applies to AEP and OPCo)

OVEC Cost Recovery Audits

In December 2021, as part of OVEC cost recovery audits pending before the PUCO, intervenors filed positions claiming that costs incurred by OPCo during the 2018-2019 audit period were imprudent and should be disallowed. In May 2022, intervenors filed for rehearing on the 2016-2017 OVEC cost recovery audit period claiming the PUCO’s April 2022 order to adopt the findings of the audit report were unjust, unlawful and unreasonable for multiple reasons, including the position that OPCo recovered imprudently incurred costs. In June 2022, the PUCO granted rehearing on the 2016-2017 audit period for purposes of further consideration. Management disagrees with these claims and is unable to predict the impact of these disputes; however, if any costs are disallowed or refunds are ordered it could reduce future net income and cash flows and impact financial condition. See "OVEC" section of Note 17 for additional information on AEP and OPCo’s investment in OVEC.

June 2022 Storm Costs

In June 2022, the service territory of OPCo was impacted by strong winds from multiple storms resulting in power outages and damage to the transmission and distribution infrastructures. As of December 31, 2022, OPCo had incurred approximately $20 million in incremental operation and maintenance costs related to service restoration efforts. The incremental storm restoration costs have been deferred as regulatory assets and OPCo is expected to seek recovery in a future filing. In July 2022, intervenors filed a motion requesting the PUCO open a formal investigation into the power outages that occurred as a result of the June storms and determine if OPCo was negligent and liable to consumers for damages incurred as a result of the power outages. Separately, in July 2022, the PUCO directed its staff to conduct an after-action review to examine the circumstances of the event and OPCo’s response to determine if OPCo adhered to the laws and rules in the state, followed its PUCO-approved emergency plan and responded appropriately to the event in an effort to mitigate the negative effects. In January 2023, the PUCO Staff issued a report which concluded OPCo was required to proactively shut down parts of its distribution system in order to avoid damages to the system and further outages and that OPCo adhered to its emergency plan. The report also directed OPCo to revise its vegetation programs around high voltage transmission lines and recommended that it make improvements to its emergency communications procedures. If any of the storm restoration costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Ohio ESP Filings

In January 2023, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments, proposed new riders and the continuation and modification of certain existing riders, including the DIR, effective June 2024 through May 2030. The proposal includes a return on common equity of 10.65% on capital costs for certain riders. If OPCo is ultimately not permitted to fully collect its ESP rates it could reduce future net income and cash flows and impact financial condition.

PSO Rate Matters (Applies to AEP and PSO)

2022 Oklahoma Base Rate Case

In November 2022, PSO filed a request with the OCC for a $173 million annual increase in rates based upon a 10.4% ROE with a capital structure of 45.4% debt and 54.6% common equity, net of existing rider revenues and certain incremental renewable facility benefits expected to be provided to customers through riders. The requested annual revenue increase includes a $47 million annual depreciation expense increase related to the accelerated depreciation recovery of the Northeastern Plant, Unit 3 through 2026, and a $16 million annual amortization expense increase to recover intangible plant over a 5-year useful life instead of a 10-year useful life. PSO’s request also includes recovery of the 154 MW Rock Falls Wind Facility through base rates to aid PSO’s near-term capacity needs and support compliance with SPP’s 2023 increased capacity planning reserve margin requirements. In

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November 2022, PSO entered into an agreement to acquire the Rock Falls Wind Facility. In February 2023, the FERC approved PSO’s acquisition of the Rock Falls Wind Facility under Section 203 of the Federal Power Act. PSO expects to close on the acquisition and place the Rock Falls Wind Facility in-service during the first quarter of 2023. OCC approval is not a condition precedent to closing on the acquisition of the Rock Falls Wind Facility. In addition, PSO requested an annual formula based rate tariff, with an initial one-year pilot term. In the event the requested formula based rate tariff is denied, PSO has requested an expanded rider to recover certain distribution investments and related expenses as well as an expanded transmission cost recovery rider. If any of these 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

In February 2021, severe winter weather 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.

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.

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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 judgment 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. SWEPCo and the PUCT submitted Petitions for Review with the Texas Supreme Court in November 2021. In October 2022, the Texas Supreme Court denied the Petitions for Review submitted by SWEPCo and the PUCT. In December 2022, SWEPCo and the PUCT filed requests for rehearing with the Texas Supreme Court. The Texas Supreme Court requested comments on rehearing by March 1, 2023. If SWEPCo’s request for rehearing is denied, the case will be remanded to the PUCT for future proceedings.

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 related to limiting SWEPCo’s recovery of AFUDC on Turk Plant and recovery of Welsh Plant, Unit 2. 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.

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. 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.

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In January 2022, the PUCT issued a final order approving an annual revenue increase of $39 million based upon a 9.25% ROE. The order also includes: (a) rates implemented retroactively back to March 18, 2021, (b) $5 million of the proposed increase related to vegetation management, (c) $2 million annually to establish a storm catastrophe reserve and (d) the creation of a rider to 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 to be recovered as a regulatory asset through 2046. As a result of the final order, SWEPCo recorded a disallowance of $12 million in 2021 associated with the lack of return on the Dolet Hills Power Station. In February 2022, SWEPCo filed a motion for rehearing with the PUCT challenging several errors in the order, which include challenges of the approved ROE, the denial of a reasonable return or carrying costs on the Dolet Hills Power Station and the calculation of the Texas jurisdictional share of the storm catastrophe reserve. In April 2022, the PUCT denied the motion for rehearing. In May 2022, SWEPCo filed a petition for review with the Texas District Court seeking a judicial review of the several errors challenged in the PUCT’s final order.

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. SWEPCo’s requested annual increase includes accelerated depreciation related to the Dolet Hills Power Station, Pirkey Power Plant and Welsh Plant, all of which were or are expected to be retired early. SWEPCo also included recovery of Welsh Plant, Unit 2 over the blended useful life of Welsh Plant, Units 1 and 3. SWEPCo subsequently revised the requested annual increase to $95 million to reflect removing hurricane storm restoration costs from the base case filing, to modify the proposed recovery of the Dolet Hills Power Station and revisions to various proposed amortizations. The hurricane costs have been requested in a separate storm filing. See “2021 Louisiana Storm Cost Filing” below for more information.

In January 2023, the LPSC approved a settlement which provides for an annual revenue increase of $27 million based upon a 9.5% ROE and includes: (a) a $21 million increase in base rates effective February 2023, (b) a $14 million rider to recover costs of the Dolet Hills Power Station and Pirkey Plant including a return, (c) an $8 million reduction in fuel rates, (d) an adoption of a 3-year formula rate term subject to an earnings band and (e) the recovery of certain incremental SPP charges net of associated revenue and the LA jurisdictional share of the return on and of projected transmission capital investment outside of the earnings band. The settlement agreement did not rule on the prudency of the early retirement of the Dolet Hills Power Station, which is being addressed in a separate proceeding.

The primary differences between SWEPCo’s requested annual rate increase and the agreed upon settlement increase are primarily due to: (a) a reduction in the requested ROE, (b) recovery of the Dolet Hills Power Station and Pirkey Plant over ten years in a separate rider mechanism as opposed to base rates with accelerated depreciation rates, (c) maintaining existing depreciation rates for Welsh Plant, Units 1 and 3 and (d) the severing of SWEPCo’s proposed adjustment to include a stand-alone NOLC deferred tax asset in rate base. In January 2023, a hearing was held related to the inclusion of a stand-alone NOLC deferred tax asset in rate base and an order from the LPSC is expected in 2023.

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 with a capital structure of 48.7% debt and 51.3% common equity. 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. In January 2022, SWEPCo filed testimony revising the requested annual increase in Arkansas base rates to $81 million. SWEPCo requested that rates become effective in June 2022.

In May 2022, the APSC issued a final order approving an annual revenue increase of $49 million based upon a 9.5% ROE. The order also includes: (a) a capital structure of 55% debt and 45% common equity, (b) approval to recover the Dolet Hills Power Station as a regulatory asset over five years without a return on this investment

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resulting in an immaterial disallowance in the second quarter of 2022, (c) the denial of accelerated depreciation for Pirkey Plant and Welsh Plant, Units 1 and 3 and (d) approval of a rider to recover SPP costs and revenues. The final order also denied the inclusion of the stand-alone NOLC in SWEPCo’s deferred tax assets, but included approval of the deferral of the forgone revenue requirement associated with the NOLC and excess NOLC, with recovery of the deferral contingent upon receipt of a supportive private letter ruling from the IRS. Rates were implemented with the first billing cycle of July 2022.

2021 Louisiana Storm Cost Filing

In 2020, Hurricanes Laura and Delta caused power outages and extensive damage to the SWEPCo service territories, primarily impacting the Louisiana jurisdiction. Following both hurricanes, the LPSC issued orders allowing Louisiana utilities, including SWEPCo, to establish regulatory assets to track and defer expenses associated with these storms. In February 2021, severe winter weather impacted the Louisiana jurisdiction and in March 2021, the LPSC approved the deferral of incremental storm restoration expenses related to the winter storm. In October 2021, SWEPCo filed a request with the LPSC for recovery of $145 million in deferred storm costs associated with the three storms. As part of the filing, SWEPCo requested recovery of the carrying charges on the deferred regulatory asset at a weighted average cost of capital through a rider beginning in January 2022. In May 2022, LPSC staff testimony was submitted to the LPSC. In July 2022, SWEPCo filed rebuttal testimony which agreed to make a request for securitization as the LPSC staff had recommended in their testimony. An order is expected in 2023. If any of the storm costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

February 2021 Severe Winter Weather Impacts in SPP

As discussed in the “PSO Rate Matters” section above, severe winter weather had a significant impact in SPP, resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system. For the time period of February 9, 2021, to February 20, 2021, SWEPCo’s natural gas expenses and purchases of electricity still to be recovered from customers are $329 million as of December 31, 2022, of which $75 million, $122 million and $132 million is related to the Arkansas, Louisiana and Texas jurisdictions, respectively.

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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. In March 2022, the FERC issued an order on the formal challenge which ruled in favor of the joint customers on several issues. Management has determined that the result of the order will have an immaterial impact to the financial statements of AEP, AEPTCo, PSO and SWEPCo. In November 2022, certain joint customers appealed the FERC decision to the U.S. Court of Appeals for the District of Columbia Circuit.

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 has an ownership interest in 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 (PAPUC) denied the IEC certificate for siting and construction of the portion in Pennsylvania. Transource Energy appealed the PAPUC ruling in Pennsylvania state court and challenged the ruling before the United States District Court for the Middle District of Pennsylvania. In May 2022, the Pennsylvania state court issued an order affirming the PAPUC decision. The PAPUC decision remains subject to the jurisdiction and review of the United States District Court for the Middle District of Pennsylvania, which had stayed review of the PAPUC decision until the Pennsylvania state court had ordered. The procedural schedule for this case states that a decision by the United States District Court for the Middle of Pennsylvania will not be reached until 2023.

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. At that time, PJM stated that the IEC has not been cancelled and remains necessary to alleviate congestion. PJM continues to evaluate reliability and market efficiency in the area. As of December 31, 2022, AEP’s share of IEC capital expenditures was approximately $87 million, located in Total Property, Plant and Equipment - Net on AEP’s balance sheets. 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.

FERC RTO Incentive Complaint (Applies to AEP, AEPTCo and OPCo)

In February 2022, the Office of the Ohio Consumers’ Counsel (OCC) filed a complaint against AEPSC, American Transmission Systems, Inc. and Duke Energy Ohio, alleging the 50 basis point RTO incentive included in Ohio Transmission Owners’ respective transmission formula rates is not just and reasonable and therefore should be eliminated on the basis that RTO participation is not voluntary, but rather is required by Ohio law. In March 2022, AEPSC filed a motion to dismiss the OCC’s February 2022 complaint with the FERC on the basis of certain deficiencies, including that the complaint fails to request relief that can be granted under FERC regulations because AEPSC is not a public utility nor does it have a transmission rate on file with the FERC. In December 2022, the FERC issued an order removing the 50 basis point RTO incentive from OPCo and OHTCo transmission formula rates effective the date of the February 2022 complaint filing and directed OPCo and OHTCo to provide refunds, with interest, within sixty days of the date of its order. In January 2023, both AEPSC and the OCC filed requests for rehearing with the FERC. A FERC order on rehearing is expected in 2023. Based on management’s preliminary estimates, the December 2022 FERC order is expected to reduce AEP’s pretax income by approximately $20 million on an annual basis.

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Request to Update AEGCo Depreciation Rates (Applies to AEP and I&M)

In October 2022, AEP, on behalf of AEGCo, submitted proposed revisions to AEGCo’s depreciation rates for its 50% ownership interest in Rockport Plant, Unit 1 and Unit 2, reflected in AEGCo’s unit power agreement with I&M. The proposed depreciation rates for these assets reflect an estimated 2028 retirement date for the Rockport Plant. AEGCo’s previous FERC-approved depreciation rates for Rockport Plant, Unit 1 were based upon a December 31, 2028 estimated retirement date while AEGCo’s previous FERC-approved depreciation rates for Rockport Plant, Unit 2 leasehold improvements were based upon a December 31, 2022 estimated retirement date in conjunction with the termination of the Rockport Plant, Unit 2 lease.

In December 2022, the FERC issued an order approving the proposed AEGCo Rockport depreciation rates effective January 1, 2023, subject to further review and a potential refund. The FERC established a separate proceeding to review: (a) AEGCo’s acquisition value for the Rockport Plant, Unit 2 base generating asset (original cost and accumulated depreciation), (b) the appropriateness of including future capital additions as stated components in proposed depreciation rates, in light of the UPA’s formula rate mechanism, (c) the appropriateness of applying two different depreciation rates to a single asset common to both units and (d) the accounting and regulatory treatment of Rockport Plant, Unit 2 costs of removal and related AROs. It is expected that the FERC will issue an order on this review in the second half of 2023. This FERC review and subsequent order on these issues could reduce future net income and cash flows and impact financial conditions.

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5. EFFECTS OF REGULATION

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

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

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

Regulated Generating Units that have been Retired

SWEPCo

In April 2016, Welsh Plant, Unit 2 was retired. As part of the 2016 Texas Base Rate Case, the PUCT authorized recovery of SWEPCo’s Texas jurisdictional share of Welsh Plant, Unit 2, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $7 million in 2017. See “2016 Texas Base Rate Case” section of Note 4 for additional information. As part of the 2019 Arkansas Base Rate Case, SWEPCo received approval from the APSC to recover the Arkansas jurisdictional share of Welsh Plant, Unit 2. In December 2020, SWEPCo filed a request with the LPSC to recover the Louisiana jurisdictional share of Welsh Plant, Unit 2. In January 2023, the LPSC approved a settlement agreement which provided recovery of Welsh Plant, Unit 2 as requested. See “2020 Louisiana Base Rate Case” section of Note 4 for additional information.

In December 2021, the Dolet Hills Power Station was retired. As part of the 2020 Texas Base Rate Case, the PUCT authorized recovery of SWEPCo’s Texas jurisdictional share of the Dolet Hills Power Station through 2046, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $12 million in 2021. As part of the 2021 Arkansas Base Rate Case, the APSC authorized recovery of SWEPCo’s Arkansas jurisdictional share of the Dolet Hills Power Station through 2027, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $2 million in the second quarter of 2022. Also, the APSC did not rule on the prudency of the early retirement of the Dolet Hills Power Station, which will be addressed in a future proceeding. As part of the 2020 Louisiana Base Rate Case, the LPSC authorized the recovery of SWEPCo’s Louisiana share of the Dolet Hills Power Station, through a separate rider, through 2032, but did not rule on the prudency of the early retirement of the plant, which is being addressed in a separate proceeding. See “2020 Texas Base Rate Case”, “2020 Louisiana Base Rate Case” and “2021 Arkansas Base Rate Case” sections of Note 4 for additional information.

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. As part of the 2021 Oklahoma Base Rate Case, PSO will continue to recover Northeastern Plant, Unit 3 through 2040.

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SWEPCo

In November 2020, management announced plans to retire Pirkey 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 December 31, 2022, 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	$	136.3	$	145.8	$	20.2	(b)	2026	(c)	$	14.9
Pirkey Plant	35.1		179.5		39.8			2023	(d)	11.7
Welsh Plant, Units 1 and 3	416.8		85.6		58.3		(e)	2028	(f)	37.9

(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)Pirkey Plant is currently being recovered through 2032 in the Louisiana jurisdiction and through 2045 in the Arkansas and Texas jurisdictions.

(e)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.

(f)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)

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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 Plant in 2023. The Pirkey Plant non-fuel costs are recoverable by SWEPCo through base rates and rate riders. As part of the 2020 Louisiana Base Rate Case, the LPSC authorized recovery of SWEPCo’s Louisiana share of the Pirkey Plant through a separate rider. Fuel costs are recovered through active fuel clauses and are subject to prudency determinations by the various commissions. As of December 31, 2022, SWEPCo’s share of the net investment in the Pirkey Plant is $215 million, including CWIP, before cost of removal. Sabine is a mining operator providing mining services to the Pirkey 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 $43 million as of December 31, 2022. As of December 31, 2022, SWEPCo had a net under-recovered fuel balance of $257 million, inclusive of costs related to Pirkey Plant billed by Sabine, but excluding impacts of the February 2021 severe winter weather event. Upon cessation of lignite deliveries by Sabine to the Pirkey Plant, additional operational, reclamation and other land-related costs incurred by Sabine will be billed to SWEPCo and included in existing 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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Regulatory Assets and Liabilities

Regulatory assets and liabilities are comprised of the following items:


	AEP
	December 31,				Remaining Recovery Period
	2022		2021
Current Regulatory Assets	(in millions)
Under-recovered Fuel Costs - earns a return	$	625.7	$	409.4	1 year
Under-recovered Fuel Costs - does not earn a return	565.3		175.7		1 year
Unrecovered Winter Storm Fuel Costs - earns a return (a)	95.8		62.7		1 year
Total Current Regulatory Assets (b)	$	1,286.8	$	647.8

Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:

Regulatory Assets Currently Earning a Return

Pirkey Plant Accelerated Depreciation	$	116.5	$	87.0
Welsh Plant, Units 1 and 3 Accelerated Depreciation	85.6		45.9
Unrecovered Winter Storm Fuel Costs	84.6		367.5

Dolet Hills Power Station Fuel Costs - Louisiana	32.0		30.9





Dolet Hills Power Station Accelerated Depreciation (c)	9.7		72.3
Plant Retirement Costs - Unrecovered Plant, Louisiana	—		35.2
Other Regulatory Assets Pending Final Regulatory Approval	27.2		9.2
Total Regulatory Assets Currently Earning a Return	355.6		648.0
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	332.7		241.8
2020-2022 Virginia Triennial Under-Earnings	37.9		15.1
Plant Retirement Costs - Asset Retirement Obligation Costs	25.9		25.9








Other Regulatory Assets Pending Final Regulatory Approval	53.9		55.1
Total Regulatory Assets Currently Not Earning a Return	450.4		337.9

Total Regulatory Assets Pending Final Regulatory Approval	806.0		985.9

Regulatory assets approved for recovery:

Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant (d)	511.4		522.2		24 years
Long-term Under-recovered Fuel Costs - Oklahoma	252.7		—		2 years
Long-term Under-recovered Fuel Costs - Virginia	223.3		—		2 years
Unrecovered Winter Storm Fuel Costs (e)	148.6		679.3		5 years
Pirkey Plant Accelerated Depreciation - Louisiana	63.0		—		10 years
Rockport Plant Dry Sorbent Injection System and Selective Catalytic Reduction	56.6		66.6		6 years
Plant Retirement Costs - Unrecovered Plant, Dolet Hills Power Station, Louisiana	45.1		—		10 years
Meter Replacement Costs	34.2		44.9		5 years
Environmental Control Projects	33.9		36.2		18 years
Cook Plant Uprate Project	25.3		27.7		11 years
Ohio Distribution Decoupling	19.5		41.6		2 years












Other Regulatory Assets Approved for Recovery	99.5		116.6		various
Total Regulatory Assets Currently Earning a Return	1,513.1		1,535.1
Regulatory Assets Currently Not Earning a Return
Pension and OPEB Funded Status	975.4		677.0		12 years
Plant Retirement Costs - Asset Retirement Obligation Costs	303.2		293.2		20 years
Unamortized Loss on Reacquired Debt	103.8		111.2		26 years
Cook Plant Nuclear Refueling Outage Levelization	81.2		32.0		3 years
Plant Retirement Costs - Unrecovered Plant, Texas	51.7		51.9		24 years
Peak Demand Reduction/Energy Efficiency	41.7		40.8		4 years
Unrealized Loss on Forward Commitments	40.1		100.8		10 years
Fuel and Purchased Power Adjustment Rider	38.1		12.1		2 years
Ohio Enhanced Service Reliability Plan	33.3		9.5		2 years
2017-2019 Virginia Triennial Under-Earnings	30.1		—		2 years
Postemployment Benefits	27.7		29.1		3 years
Vegetation Management	25.8		29.3		3 years
Smart Grid Costs	25.4		19.3		2 years
Plant Retirement Costs - Unrecovered Plant, Arkansas	21.1		—		5 years
PJM/SPP Annual Formula Rate True-up	20.3		17.6		2 years
Virginia Transmission Rate Adjustment Clause	18.7		37.2		2 years

Storm-Related Costs	11.9		25.4		2 years
Texas Transmission Cost Recovery Factor	3.8		30.6		2 years













Other Regulatory Assets Approved for Recovery	108.8		104.3		various
Total Regulatory Assets Currently Not Earning a Return	1,962.1		1,621.3

Total Regulatory Assets Approved for Recovery	3,475.2		3,156.4

Total Noncurrent Regulatory Assets (f)	$	4,281.2	$	4,142.3

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(a)In 2022, Unrecovered Winter Storm Costs in the Arkansas and Texas jurisdictions were approved for recovery by the APSC and PUCT. As of December 31, 2022, Unrecovered Winter Storm Fuel Costs in the Louisiana jurisdiction are pending final regulatory approval with the LPSC. The current asset balance represents amounts expected to be recovered in the Arkansas, Louisiana and Texas jurisdiction over the next 12 months. See “February 2021 Severe Winter Weather Impacts in SPP” section of SWEPCo Rate Matters in Note 4 for additional information.

(b)Amounts exclude $23 million and $8 million as of December 31, 2022 and 2021, respectively, of Regulatory Asset for Under-Recovered Fuel Costs assets classified as Assets Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.

(d)Northeastern Plant, Unit 3 is approved for recovery through 2040, but expected to retire in 2026. PSO records a regulatory asset for accelerated depreciation. See “Regulated Generating Units to be Retired” section above for additional information.

(e)In February 2022, the OCC approved PSO’s securitization of the Unrecovered Winter Storm Fuel Costs. In September 2022, PSO received proceeds of $687 million from the ODFA which issued ratepayer-backed securitization bonds for the purpose of reimbursing PSO for extraordinary fuel costs and purchases of electricity incurred during the February 2021 severe winter weather event, which were previously recorded as Regulatory Assets on PSO’s balance sheet. See “February 2021 Severe Winter Weather Impacts in SPP” section of PSO Rate Matters in Note 4 for additional information.

(f)Amounts exclude $481 million and $477 million as of December 31, 2022 and 2021, respectively, of Regulatory Assets classified as Assets Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.

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	AEP
	December 31,				Remaining
	2022		2021		Refund Period
Current Regulatory Liabilities	(in millions)
Over-recovered Fuel Costs - pays a return	$	1.4	$	—	1 year
Over-recovered Fuel Costs - does not pay a return	—		1.5
Total Current Regulatory Liabilities	$	1.4	$	1.5

Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
Regulatory liabilities pending final regulatory determination:

Regulatory Liabilities Currently Paying a Return
Income Taxes, Net (a)	$	148.6	$	262.2

Total Regulatory Liabilities Currently Paying a Return	148.6		262.2
Regulatory Liabilities Currently Not Paying a Return

Other Regulatory Liabilities Pending Final Regulatory Determination	2.0		0.2
Total Regulatory Liabilities Currently Not Paying a Return	2.0		0.2

Total Regulatory Liabilities Pending Final Regulatory Determination	150.6		262.4

Regulatory liabilities approved for payment:

Regulatory Liabilities Currently Paying a Return
Asset Removal Costs	3,315.3		3,172.1		(b)
Income Taxes, Net (a)	2,479.3		2,711.4		(c)
Rockport Plant, Unit 2 Accelerated Depreciation for Leasehold Improvements	53.8		4.2		6 years
Renewable Energy Surcharge - Michigan	23.2		14.9		2 years





Other Regulatory Liabilities Approved for Payment	9.5		16.1		various
Total Regulatory Liabilities Currently Paying a Return	5,881.1		5,918.7
Regulatory Liabilities Currently Not Paying a Return
Excess Nuclear Decommissioning Funding	1,318.5		1,939.7		(d)
Deferred Investment Tax Credits	237.3		248.5		34 years
OVEC Purchased Power	47.1		14.8		2 years
Spent Nuclear Fuel	45.8		49.5		(d)
Unrealized Gain on Forward Commitments	41.2		37.2		2 years
2017-2019 Virginia Triennial Revenue Provision	39.1		41.6		26 years
PJM Costs and Off-system Sales Margin Sharing - Indiana	34.2		—		2 years
Over-recovered Fuel Costs - Ohio	32.2		15.2		10 years
PJM Transmission Enhancement Refund	32.1		42.9		3 years
Transition and Restoration Charges - Texas	29.4		26.3		7 years
Peak Demand Reduction/Energy Efficiency	28.6		28.6		2 years








Other Regulatory Liabilities Approved for Payment	82.4		60.9		various
Total Regulatory Liabilities Currently Not Paying a Return	1,967.9		2,505.2

Total Regulatory Liabilities Approved for Payment	7,849.0		8,423.9

Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits (e)	$	7,999.6	$	8,686.3

(a)Predominately pays a return due to the inclusion of Excess ADIT in rate base.

(b)Relieved as removal costs are incurred.

(c)Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $237 million and $387 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 6 years.

(d)Relieved when plant is decommissioned.

(e)Amounts exclude $116 million and $148 million as of December 31, 2022 and 2021, respectively, of Regulatory Liabilities and Deferred Investment Tax Credits classified as Liabilities Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.

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	AEP Texas
	December 31,				Remaining Recovery Period
Regulatory Assets:	2022		2021
	(in millions)
Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:

Regulatory Assets Currently Earning a Return
Texas Mobile Generation Lease Payments	$	17.6	$	—


Total Regulatory Assets Currently Earning a Return	17.6		—
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	26.7		22.4
Vegetation Management Program	5.2		5.2
Texas Retail Electric Provider Bad Debt Expense	4.1		4.1


Other Regulatory Assets Pending Final Regulatory Approval	13.4		9.5
Total Regulatory Assets Currently Not Earning a Return	49.4		41.2

Total Regulatory Assets Pending Final Regulatory Approval	67.0		41.2

Regulatory assets approved for recovery:

Regulatory Assets Currently Earning a Return
Meter Replacement Costs	16.1		22.7		4 years
Advanced Metering System	—		10.6
Other Regulatory Assets Approved for Recovery	1.4		2.1		various
Total Regulatory Assets Currently Earning a Return	17.5		35.4
Regulatory Assets Currently Not Earning a Return
Pension and OPEB Funded Status	173.2		119.0		12 years

Vegetation Management Program	12.1		17.4		3 years
Peak Demand Reduction/Energy Efficiency	11.9		14.5		2 years
Storm-Related Costs	8.5		12.8		2 years
Texas Transmission Cost Recovery Factor	3.8		30.6		2 years





Other Regulatory Assets Approved for Recovery	4.3		4.3		various
Total Regulatory Assets Currently Not Earning a Return	213.8		198.6

Total Regulatory Assets Approved for Recovery	231.3		234.0

Total Noncurrent Regulatory Assets	$	298.3	$	275.2

271


	AEP Texas
	December 31,				Remaining Refund Period
Regulatory Liabilities:	2022		2021
	(in millions)

Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
Regulatory liabilities pending final regulatory determination:

Regulatory Liabilities Currently Paying a Return
Income Taxes, Net (a)	$	13.0	$	13.0

Total Regulatory Liabilities Currently Paying a Return	13.0		13.0
Regulatory Liabilities Currently Not Paying a Return
Other Regulatory Liabilities Pending Final Regulatory Determination	1.8		—
Total Regulatory Liabilities Currently Not Paying a Return	1.8		—

Total Regulatory Liabilities Pending Final Regulatory Determination	14.8		13.0

Regulatory liabilities approved for payment:

Regulatory Liabilities Currently Paying a Return
Asset Removal Costs	766.8		744.7		(b)
Income Taxes, Net (a)	431.6		445.3		(c)


Other Regulatory Liabilities Approved for Payment	4.3		4.8		various
Total Regulatory Liabilities Currently Paying a Return	1,202.7		1,194.8
Regulatory Liabilities Currently Not Paying a Return
Transition and Restoration Charges	29.4		26.3		7 years



Other Regulatory Liabilities Approved for Payment	12.7		7.9		various
Total Regulatory Liabilities Currently Not Paying a Return	42.1		34.2

Total Regulatory Liabilities Approved for Payment	1,244.8		1,229.0

Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits	$	1,259.6	$	1,242.0

(a)Predominately pays a return due to the inclusion of Excess ADIT in rate base.

(b)Relieved as removal costs are incurred.

272


	AEPTCo
	December 31,				Remaining Recovery Period
Regulatory Assets:	2022		2021
	(in millions)
Noncurrent Regulatory Assets
Regulatory assets approved for recovery:




Regulatory Assets Currently Not Earning a Return
PJM/SPP Annual Formula Rate True-up	$	6.8	$	8.5	2 years
Total Regulatory Assets Approved for Recovery	6.8		8.5

Total Noncurrent Regulatory Assets (a)	$	6.8	$	8.5


	AEPTCo
	December 31,				Remaining Refund Period
Regulatory Liabilities:	2022		2021
	(in millions)
Noncurrent Regulatory Liabilities
Regulatory liabilities pending final regulatory determination:

Regulatory Liabilities Currently Paying a Return

Income Taxes, Net (b)	$	8.7	$	8.7

Total Regulatory Liabilities Pending Final Regulatory Determination	8.7		8.7

Regulatory liabilities approved for payment:

Regulatory Liabilities Currently Paying a Return
Asset Removal Costs	356.1		271.4		(c)
Income Taxes, Net (b)	350.2		364.0		(d)


Total Regulatory Liabilities Approved for Payment	706.3		635.4



Total Noncurrent Regulatory Liabilities (e)	$	715.0	$	644.1

(a)Amounts exclude $346 thousand and $0 as of December 31, 2022 and 2021, respectively, of Regulatory Assets classified as Assets Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.

(b)Predominately pays a return due to the inclusion of Excess ADIT in rate base.

(c)Relieved as removal costs are incurred.

(d)Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $16 million and $26 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 6 years.

(e)Amounts exclude $8 million and $8 million as of December 31, 2022 and 2021, respectively, of Regulatory Liabilities classified as Liabilities Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.

273


	APCo
	December 31,				Remaining Recovery Period
Regulatory Assets:	2022		2021
	(in millions)
Current Regulatory Assets
Under-recovered Fuel Costs - earns a return	$	180.7	$	127.2	1 year
Under-recovered Fuel Costs - does not earn a return	292.4		74.1		1 year
Total Current Regulatory Assets	$	473.1	$	201.3

Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:

Regulatory Assets Currently Earning a Return
COVID-19 - Virginia	$	7.0	$	6.8

Total Regulatory Assets Currently Earning a Return	7.0		6.8
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs - West Virginia	72.6		53.7
2020-2022 Virginia Triennial Under-Earnings	37.9		15.1
Plant Retirement Costs - Asset Retirement Obligation Costs	25.9		25.9



Other Regulatory Assets Pending Final Regulatory Approval	1.1		3.6



Total Regulatory Assets Currently Not Earning a Return	137.5		98.3

Total Regulatory Assets Pending Final Regulatory Approval	144.5		105.1

Regulatory assets approved for recovery:

Regulatory Assets Currently Earning a Return
Long-term Under-recovered Fuel Costs - Virginia	223.3		—		2 years
Plant Retirement Costs - Unrecovered Plant	75.6		110.0		21 years



Other Regulatory Assets Approved for Recovery	0.4		0.4		various
Total Regulatory Assets Currently Earning a Return	299.3		110.4
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs - Asset Retirement Obligation Costs	303.1		293.1		15 years
Pension and OPEB Funded Status	108.3		62.7		12 years
Unamortized Loss on Reacquired Debt	74.4		78.2		23 years

2017-2019 Virginia Triennial Under-Earnings	30.1		—		2 years
Virginia Transmission Rate Adjustment Clause	18.7		37.2		2 years
Virginia Clean Economy Act	16.7		—		2 years
Peak Demand Reduction/Energy Efficiency	15.8		17.8		4 years

Postemployment Benefits	13.7		13.3		3 years
Vegetation Management Program - West Virginia	13.7		11.9		2 years
Environmental Compliance Costs	4.3		13.7		2 years












Other Regulatory Assets Approved for Recovery	16.0		14.2		various
Total Regulatory Assets Currently Not Earning a Return	614.8		542.1

Total Regulatory Assets Approved for Recovery	914.1		652.5

Total Noncurrent Regulatory Assets	$	1,058.6	$	757.6

274


	APCo
	December 31,				Remaining Refund Period
Regulatory Liabilities:	2022		2021
	(in millions)
Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
Regulatory liabilities pending final regulatory determination:

Regulatory Liabilities Currently Paying a Return

Income Taxes, Net (a)	$	30.5	$	4.5

Total Regulatory Liabilities Pending Final Regulatory Determination	30.5		4.5

Regulatory liabilities approved for payment:

Regulatory Liabilities Currently Paying a Return
Asset Removal Costs	713.5		703.3		(b)
Income Taxes, Net (a)	291.3		432.9		(c)
Deferred Investment Tax Credits	0.3		0.3		31 years
Total Regulatory Liabilities Currently Paying a Return	1,005.1		1,136.5
Regulatory Liabilities Currently Not Paying a Return
2017-2019 Virginia Triennial Revenue Provision	39.1		41.6		26 years
Unrealized Gain on Forward Commitments	34.5		28.2		2 years
Over-recovered Deferred Wind Power Costs - Virginia	13.6		8.4		2 years
PJM Transmission Enhancement Refund	9.8		13.0		3 years



Other Regulatory Liabilities Approved for Payment	11.0		6.6		various
Total Regulatory Liabilities Currently Not Paying a Return	108.0		97.8

Total Regulatory Liabilities Approved for Payment	1,113.1		1,234.3

Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits	$	1,143.6	$	1,238.8

(a)Predominately pays a return due to the inclusion of Excess ADIT in rate base.

(b)Relieved as removal costs are incurred.

(c)Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $19 million and $84 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 6 years.

275


	I&M
	December 31,				Remaining Recovery Period
Regulatory Assets:	2022		2021
	(in millions)
Current Regulatory Assets
Under-recovered Fuel Costs, Michigan - earns a return	$	9.0	$	6.4	1 year
Under-recovered Fuel Costs, Indiana - does not earn a return	38.1		—		1 year
Total Current Regulatory Assets	$	47.1	$	6.4

Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:

Regulatory Assets Currently Earning a Return

Other Regulatory Assets Pending Final Regulatory Approval	$	0.1	$	0.1
Total Regulatory Assets Currently Earning a Return	0.1		0.1
Regulatory Assets Currently Not Earning a Return








Storm-Related Costs - Indiana	21.6		—
Other Regulatory Assets Pending Final Regulatory Approval	2.0		3.6
Total Regulatory Assets Currently Not Earning a Return	23.6		3.6

Total Regulatory Assets Pending Final Regulatory Approval	23.7		3.7

Regulatory assets approved for recovery:

Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant	147.0		170.8		6 years
Rockport Plant Dry Sorbent Injection System and Selective Catalytic Reduction	56.6		66.6		6 years
Cook Plant Uprate Project	25.3		27.7		11 years
Deferred Cook Plant Life Cycle Management Project Costs - Michigan, FERC	12.1		13.1		12 years
Cook Plant Turbine - Indiana	9.0		9.7		16 years
Cook Plant Study Costs	8.7		9.4		13 years


Other Regulatory Assets Approved for Recovery	11.9		6.0		various
Total Regulatory Assets Currently Earning a Return	270.6		303.3
Regulatory Assets Currently Not Earning a Return
Cook Plant Nuclear Refueling Outage Levelization	81.2		32.0		3 years
Pension and OPEB Funded Status	26.9		—		12 years
Unamortized Loss on Reacquired Debt	12.9		14.2		26 years
Peak Demand Energy Efficiency	10.3		2.8		2 years
Postemployment Benefits	7.7		9.0		3 years
Storm-Related Costs - Indiana	3.4		12.6		2 years

PJM Costs and Off-system Sales Margin Sharing - Indiana	—		15.1













Other Regulatory Assets Approved for Recovery	22.9		18.2		various
Total Regulatory Assets Currently Not Earning a Return	165.3		103.9

Total Regulatory Assets Approved for Recovery	435.9		407.2

Total Noncurrent Regulatory Assets	$	459.6	$	410.9

276


	I&M
	December 31,				Remaining Refund Period
Regulatory Liabilities:	2022		2021
	(in millions)
Current Regulatory Liabilities

Over-recovered Fuel Costs, Indiana - does not pay a return	$	—	$	1.5
Total Current Regulatory Liabilities	$	—	$	1.5

Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
Regulatory liabilities pending final regulatory determination:

Regulatory Liabilities Currently Paying a Return
Income Taxes, Net (a) (b)	$	(87.7)	$	—
Total Regulatory Liabilities Pending Final Regulatory Determination	(87.7)		—

Regulatory liabilities approved for payment:

Regulatory Liabilities Currently Paying a Return
Asset Removal Costs	170.7		179.7		(c)
Income Taxes, Net (a)	168.6		182.6		(d)
Renewable Energy Surcharge - Michigan	23.2		14.9		2 years
Other Regulatory Liabilities Approved for Payment	3.0		7.0		various
Total Regulatory Liabilities Currently Paying a Return	365.5		384.2
Regulatory Liabilities Currently Not Paying a Return
Excess Nuclear Decommissioning Funding	1,318.5		1,939.7		(e)

Spent Nuclear Fuel	45.8		49.5		(e)
PJM Costs and Off-system Sales Margin Sharing - Indiana	34.2		—		2 years
Deferred Investment Tax Credits	17.4		22.4		28 years

Pension OPEB Funded Status	—		27.6
Environmental Cost Rider - Indiana	—		10.6






Other Regulatory Liabilities Approved for Payment	8.5		13.9		various
Total Regulatory Liabilities Currently Not Paying a Return	1,424.4		2,063.7

Total Regulatory Liabilities Approved for Payment	1,789.9		2,447.9

Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits	$	1,702.2	$	2,447.9

(a)Predominately pays a return due to the inclusion of Excess ADIT in rate base.

(b)Represents an income tax related regulatory asset, which is presented within net regulatory liabilities on the balance sheet.

(c)Relieved as removal costs are incurred.

(d)Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $42 million and $90 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 6 years.

(e)Relieved when plant is decommissioned.

277


	OPCo
	December 31,				Remaining Recovery Period
Regulatory Assets:	2022		2021
	(in millions)
Current Regulatory Assets

Under-recovered Fuel Costs - does not earn a return	$	3.8	$	—	1 year
Total Current Regulatory Assets	$	3.8	$	—

Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:



Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	$	33.8	$	3.8


Total Regulatory Assets Pending Final Regulatory Approval	33.8		3.8

Regulatory assets approved for recovery:

Regulatory Assets Currently Earning a Return
Ohio Distribution Decoupling	19.5		41.6		2 years
Ohio Basic Transmission Cost Rider	14.3		5.2		2 years
Ohio Economic Development Rider	1.1		10.1		2 years

Total Regulatory Assets Currently Earning a Return	34.9		56.9
Regulatory Assets Currently Not Earning a Return
Pension and OPEB Funded Status	142.7		83.3		12 years
Unrealized Loss on Forward Commitments	40.0		92.1		10 years
Ohio Enhanced Service Reliability Plan	33.3		9.5		2 years
Smart Grid Costs	25.4		19.3		2 years
Postemployment Benefits	6.2		6.2		3 years

PJM Load Service Entity Formula Rate True-up	—		7.5




Other Regulatory Assets Approved for Recovery	11.0		14.4		various
Total Regulatory Assets Currently Not Earning a Return	258.6		232.3

Total Regulatory Assets Approved for Recovery	293.5		289.2

Total Noncurrent Regulatory Assets	$	327.3	$	293.0

278


	OPCo
	December 31,				Remaining Refund Period
	2022		2021
Regulatory Liabilities:	(in millions)





Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
Regulatory liabilities pending final regulatory determination:



Regulatory Liabilities Currently Not Paying a Return
Other Regulatory Liabilities Pending Final Regulatory Determination	$	0.2	$	0.2







Total Regulatory Liabilities Pending Final Regulatory Determination	0.2		0.2

Regulatory liabilities approved for payment:

Regulatory Liabilities Currently Paying a Return
Asset Removal Costs	466.5		467.6		(a)
Income Taxes, Net (b)	451.9		480.6		(c)


Total Regulatory Liabilities Currently Paying a Return	918.4		948.2
Regulatory Liabilities Currently Not Paying a Return

OVEC Purchased Power	47.1		14.8		2 years
Over-recovered Fuel Costs	32.2		15.2		10 years
Peak Demand Reduction/Energy Efficiency	23.6		22.5		2 years
PJM Transmission Enhancement Refund	14.7		19.6		3 years








Other Regulatory Liabilities Approved for Payment	7.8		0.4		various
Total Regulatory Liabilities Currently Not Paying a Return	125.4		72.5

Total Regulatory Liabilities Approved for Payment	1,043.8		1,020.7

Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits	$	1,044.0	$	1,020.9

(a)Relieved as removal costs are incurred.

(b)Predominately pays a return due to the inclusion of Excess ADIT in rate base.

(c)Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $162 million and $191 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 6 years.

279


	PSO
	December 31,				Remaining Recovery Period
	2022		2021
Regulatory Assets:	(in millions)

Current Regulatory Assets
Under-recovered Fuel Costs - earns a return	$	178.7	$	194.6	1 year
Total Current Regulatory Assets	$	178.7	$	194.6

Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:






Regulatory Assets Currently Not Earning a Return


Storm-Related Costs	$	25.5	$	13.9
Other Regulatory Assets Pending Final Regulatory Approval	0.1		0.3

Total Regulatory Assets Pending Final Regulatory Approval	25.6		14.2



Regulatory assets approved for recovery:

Regulatory Assets Currently Earning a Return
Long-term Under-recovered Fuel Costs - Oklahoma	252.7		—		2 years
Plant Retirement Costs - Unrecovered Plant (a)	240.6		227.6		24 years
Environmental Control Projects	23.9		25.2		18 years
Meter Replacement Costs	18.1		22.2		5 years
Storm-Related Costs	8.4		17.4		2 years

Unrecovered Winter Storm Fuel Costs	—		679.3		(b)
Other Regulatory Assets Approved for Recovery	9.1		9.8		various
Total Regulatory Assets Currently Earning a Return	552.8		981.5
Regulatory Assets Currently Not Earning a Return
Pension and OPEB Funded Status	55.2		22.9		12 years








Other Regulatory Assets Approved for Recovery	20.1		18.8		various
Total Regulatory Assets Currently Not Earning a Return	75.3		41.7

Total Regulatory Assets Approved for Recovery	628.1		1,023.2

Total Noncurrent Regulatory Assets	$	653.7	$	1,037.4

(a)Northeastern Plant, Unit 3 is approved for recovery through 2040, but expected to retire in 2026. PSO records a regulatory asset for accelerated depreciation. See “Regulated Generating Units to be Retired” section above for additional information.

(b)In February 2022, the OCC approved PSO’s securitization of the Unrecovered Winter Storm Fuel Costs. In September 2022, PSO received proceeds of $687 million from the ODFA which issued ratepayer-backed securitization bonds for the purpose of reimbursing PSO for extraordinary fuel costs and purchases of electricity incurred during the February 2021 severe winter weather event, which were previously recorded as Regulatory Assets on PSO’s balance sheet. See “February 2021 Severe Winter Weather Impacts in SPP” section of PSO Rate Matters in Note 4 for additional information.

280


	PSO
	December 31,				Remaining Refund Period
	2022		2021
Regulatory Liabilities:	(in millions)





Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
Regulatory liabilities pending final regulatory determination:

Regulatory Liabilities Currently Paying a Return

Income Taxes, Net (a)	$	51.3	$	56.2

Total Regulatory Liabilities Pending Final Regulatory Determination	51.3		56.2

Regulatory liabilities approved for payment:

Regulatory Liabilities Currently Paying a Return
Income Taxes, Net (a)	380.1		423.8		(b)
Asset Removal Costs	316.3		300.2		(c)
Total Regulatory Liabilities Currently Paying a Return	696.4		724.0
Regulatory Liabilities Currently Not Paying a Return

Deferred Investment Tax Credits	48.2		50.8		22 years

Other Regulatory Liabilities Approved for Payment	13.2		4.3		various
Total Regulatory Liabilities Currently Not Paying a Return	61.4		55.1

Total Regulatory Liabilities Approved for Payment	757.8		779.1

Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits	$	809.1	$	835.3

(a)Predominately pays a return due to the inclusion of Excess ADIT in rate base.

(b)Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $21 million and $46 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 2 years.

(c)Relieved as removal costs are incurred.

281


	SWEPCo
	December 31,				Remaining Recovery Period
	2022		2021
Regulatory Assets:	(in millions)

Current Regulatory Assets
Under-recovered Fuel Costs - earns a return (a)	$	257.2	$	81.2	1 year
Unrecovered Winter Storm Fuel Costs - earns a return (b)	95.8		62.7		1 year
Total Current Regulatory Assets	$	353.0	$	143.9

Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:

Regulatory Assets Currently Earning a Return
Pirkey Plant Accelerated Depreciation	$	116.5	$	87.0
Welsh Plant, Units 1 and 3 Accelerated Depreciation	85.6		45.9
Unrecovered Winter Storm Fuel Costs (b)	84.6		367.5

Dolet Hills Power Station Fuel Costs - Louisiana	32.0		30.9
Dolet Hills Power Station Accelerated Depreciation (c)	9.7		72.3
Plant Retirement Costs - Unrecovered Plant, Louisiana	—		35.2
Other Regulatory Assets Pending Final Regulatory Approval	2.5		2.4
Total Regulatory Assets Currently Earning a Return	330.9		641.2
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs - Louisiana	151.5		148.0
Asset Retirement Obligation - Louisiana	11.8		10.3



Other Regulatory Assets Pending Final Regulatory Approval	16.0		18.4
Total Regulatory Assets Currently Not Earning a Return	179.3		176.7

Total Regulatory Assets Pending Final Regulatory Approval	510.2		817.9

Regulatory assets approved for recovery:

Regulatory Assets Currently Earning a Return
Unrecovered Winter Storm Fuel Costs (b)	148.6		—		5 years
Pirkey Plant Accelerated Depreciation - Louisiana	63.0		—		10 years
Plant Retirement Costs - Unrecovered Plant, Dolet Hills Power Station - Louisiana	45.1		—		10 years
Plant Retirement Costs - Unrecovered Plant, Welsh Plant, Unit 2 - Louisiana	35.2		—		10 years
Plant Retirement Costs - Unrecovered Plant, Arkansas	13.1		13.7		20 years
Environmental Controls Projects	10.0		11.0		10 years
Other Regulatory Assets Approved for Recovery	6.8		5.2		various
Total Regulatory Assets Currently Earning a Return	321.8		29.9
Regulatory Assets Currently Not Earning a Return
Pension and OPEB Funded Status	96.2		73.8		12 years
Plant Retirement Costs - Unrecovered Plant, Texas	51.7		51.9		24 years
Plant Retirement Costs - Unrecovered Plant, Arkansas	21.1		—		5 years
Dolet Hills Power Station Fuel Costs - Arkansas	8.9		13.0		4 years








Other Regulatory Assets Approved for Recovery	32.5		18.8		various
Total Regulatory Assets Currently Not Earning a Return	210.4		157.5

Total Regulatory Assets Approved for Recovery	532.2		187.4

Total Noncurrent Regulatory Assets	$	1,042.4	$	1,005.3

(a)2022 amount includes Arkansas and Texas jurisdictions. 2021 amount includes Arkansas, Louisiana and Texas jurisdictions.

(b)In 2022, Unrecovered Winter Storm Costs in the Arkansas and Texas jurisdictions were approved for recovery by the APSC and PUCT. As of December 31, 2022, Unrecovered Winter Storm Fuel Costs in the Louisiana jurisdiction are pending final regulatory approval with the LPSC. The current asset balance represents amounts expected to be recovered in the Arkansas, Louisiana and Texas jurisdiction over the next 12 months. See “February 2021 Severe Winter Weather Impacts in SPP” section of SWEPCo Rate Matters in Note 4 for additional information.

282


	SWEPCo
	December 31,				Remaining Refund Period
	2022		2021
Regulatory Liabilities:	(in millions)

Current Regulatory Liabilities
Over-recovered Fuel Costs - pays a return (a)	$	1.4	$	—
Total Current Regulatory Liabilities	$	1.4	$	—

Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
Regulatory liabilities pending final regulatory determination:

Regulatory Liabilities Currently Paying a Return
Income Taxes, Net (b)	$	7.0	$	—


Total Regulatory Liabilities Pending Final Regulatory Determination	7.0		—

Regulatory liabilities approved for payment:

Regulatory Liabilities Currently Paying a Return
Asset Removal Costs	481.2		461.3		(c)
Income Taxes, Net (b)	327.6		330.2		(d)


Other Regulatory Liabilities Approved for Payment	2.2		2.4		various
Total Regulatory Liabilities Currently Paying a Return	811.0		793.9
Regulatory Liabilities Currently Not Paying a Return





Other Regulatory Liabilities Approved for Payment	7.7		13.0		various
Total Regulatory Liabilities Currently Not Paying a Return	7.7		13.0

Total Regulatory Liabilities Approved for Payment	818.7		806.9

Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits	$	825.7	$	806.9

(a)2022 amount includes Louisiana jurisdiction.

(b)Predominately pays a return due to the inclusion of Excess ADIT in rate base.

(c)Relieved as removal costs are incurred.

(d)Refunded over the period for which the related deferred income tax reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $7 million and $7 million for the years ended December 31, 2022 and 2021, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2022 is to be refunded over 1 year.

283

6. COMMITMENTS, GUARANTEES AND CONTINGENCIES

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

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

For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements.

COMMITMENTS (Applies to all Registrants except AEP Texas and AEPTCo)

The AEP System has substantial commitments for fuel, energy and capacity contracts as part of the normal course of business. Certain contracts contain penalty provisions for early termination.

In accordance with the accounting guidance for “Commitments”, the following tables summarize the Registrants’ actual contractual commitments as of December 31, 2022:


Contractual Commitments - AEP	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Fuel Purchase Contracts (a)	$	1,499.8	$	1,711.8	$	345.4	$	252.0	$	3,809.0
Energy and Capacity Purchase Contracts	167.8		377.7		349.1		570.5		1,465.1
Total	$	1,667.6	$	2,089.5	$	694.5	$	822.5	$	5,274.1


Contractual Commitments - APCo	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Fuel Purchase Contracts (a)	$	840.9	$	1,102.9	$	263.2	$	9.2	$	2,216.2
Energy and Capacity Purchase Contracts	40.5		82.7		79.9		127.0		330.1
Total	$	881.4	$	1,185.6	$	343.1	$	136.2	$	2,546.3


Contractual Commitments - I&M	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Fuel Purchase Contracts (a)	$	200.9	$	235.2	$	53.3	$	222.4	$	711.8
Energy and Capacity Purchase Contracts	140.9		290.0		273.8		276.8		981.5
Total	$	341.8	$	525.2	$	327.1	$	499.2	$	1,693.3


Contractual Commitments - OPCo	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Energy and Capacity Purchase Contracts	$	34.4	$	66.5	$	63.7	$	169.8	$	334.4

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Contractual Commitments - PSO	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Fuel Purchase Contracts (a)	$	35.8	$	14.5	$	—	$	—	$	50.3
Energy and Capacity Purchase Contracts	47.1		116.3		122.8		91.4		377.6
Total	$	82.9	$	130.8	$	122.8	$	91.4	$	427.9


Contractual Commitments - SWEPCo	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Fuel Purchase Contracts (a)	$	133.7	$	84.7	$	—	$	—	$	218.4
Energy and Capacity Purchase Contracts	10.1		31.6		13.2		—		54.9
Total	$	143.8	$	116.3	$	13.2	$	—	$	273.3

(a)Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel.

GUARANTEES

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

Letters of Credit (Applies to AEP and AEP Texas)

AEP has $4 billion and $1 billion revolving credit facilities due in March 2027 and 2024, respectively, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of December 31, 2022, no letters of credit were issued under the revolving credit facility.

Company

Amount

Maturity

(in millions)

AEP

287.4

January 2023 to December 2023

AEP Texas

1.8

July 2023

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Guarantees of Equity Method Investees (Applies to AEP)

In 2019, AEP acquired a 50% ownership interest in five non-consolidated renewable joint ventures and two renewable tax equity partnerships. Parent 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. In September 2022, AEP signed a PSA with a nonaffiliate for AEP’s interest in Flat Ridge 2, one of the five non-consolidated joint ventures. The transaction closed in the fourth quarter of 2022. As of December 31, 2022, the maximum potential amount of future payments associated with the remaining guarantees was $59 million, with the last guarantee expiring in December 2035. The non-contingent liability recorded associated with these guarantees was $5 million, with an additional $1 million expected credit loss liability for the contingent portion of the guarantees. In accordance with the accounting guidance for guarantees, the initial recognition of the non-contingent liabilities increased AEP’s carrying values of the respective equity method investees. 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 December 31, 2022, there were no material liabilities recorded for any indemnifications.

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

Lease Obligations

Certain Registrants lease equipment under master lease agreements. See “Master Lease Agreements” and “AEPRO Boat and Barge Leases” sections of Note 13 for additional information.

ENVIRONMENTAL CONTINGENCIES (Applies to All Registrants except AEPTCo)

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

By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and non-hazardous materials. The Registrants currently incur costs to dispose of these substances safely.

Superfund addresses clean-up of hazardous substances that are released to the environment. The Federal EPA administers the clean-up programs. Several states enacted similar laws. As of December 31, 2022, AGR, APCo, OPCo and SWEPCo are named as a Potentially Responsible Party (PRP) for one, one, two and one sites, respectively, by the Federal EPA for which alleged liability is unresolved. There are 11 additional sites for which APCo, I&M, KPCo, OPCo and SWEPCo received information requests which could lead to PRP designation. I&M

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has also been named potentially liable at two sites under state law and AEP Texas and SWEPCo share potential liability under state law at another site. In those instances where a PRP or defendant has been named, disposal or recycling activities were in accordance with the then-applicable laws and regulations. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. Liability has been resolved for a number of sites with no significant effect on net income.

Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability. Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often non-hazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. As of December 31, 2022, management’s estimates do not anticipate material clean-up costs for identified Superfund sites.

NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M)

I&M owns and operates the two-unit 2,296 MW Cook Plant under licenses granted by the NRC. I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. Management is currently evaluating applying for license extensions for both units. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.

Decommissioning and Low-Level Waste Accumulation Disposal

The costs to decommission a nuclear plant are affected by NRC regulations and the SNF disposal program. Decommissioning costs are accrued over the service life of Cook Plant. The most recent decommissioning cost study was performed in 2021. According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste was $2.2 billion in 2021 non-discounted dollars, with additional ongoing costs of $7 million per year for post decommissioning storage of SNF and an eventual cost of $33 million for the subsequent decommissioning of the SNF storage facility, also in 2021 non-discounted dollars. I&M recovers estimated decommissioning costs for the Cook Plant in its rates. The amounts recovered in rates were $2 million, $4 million and $4 million for the years ended December 31, 2022, 2021 and 2020, respectively. Decommissioning costs recovered from customers are deposited in external trusts.

As of December 31, 2022 and 2021, the total decommissioning trust fund balances were $3 billion and $3.5 billion, respectively. The decrease in the trust fund balance was driven by unfavorable investment performance in 2022. Trust fund earnings increase the fund assets and may decrease the amount remaining to be recovered from customers. Trust fund losses decrease the fund assets and may increase the amount remaining to be recovered from customers. The decommissioning costs (including unrealized gains and losses, interest and trust funds expenses) increase or decrease the recorded liability.

I&M continues to work with regulators and customers to establish rates designed to collect the estimated costs of decommissioning the Cook Plant. However, future net income and cash flows would be reduced and financial condition could be impacted if the cost of SNF disposal and decommissioning increases and cannot be recovered.

Spent Nuclear Fuel Disposal

The federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal. A fee of one-mill per KWh for fuel consumed after April 6, 1983 at the Cook Plant was collected from customers and remitted to the DOE through May 14, 2014. In May 2014, pursuant to court order from the U.S Court of Appeals for the District of Columbia Circuit, the DOE adjusted the fee to $0. As of December 31, 2022

287

and 2021, fees and related interest of $286 million and $281 million, respectively, for fuel consumed prior to April 7, 1983 were recorded as Long-term Debt and funds collected from customers along with related earnings totaling $330 million and $329 million, respectively, to pay the fee, were recorded as part of Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program.

In 2011, I&M signed a settlement agreement with the federal government which permits I&M to make annual filings to recover certain SNF storage costs incurred as a result of the government’s delay in accepting SNF for permanent storage. Under the settlement agreement, I&M received $3 million, $14 million and $24 million in 2022, 2021 and 2020, respectively, to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2022. The proceeds reduced costs for dry cask storage. As of December 31, 2022 and 2021, I&M deferred $21 million and $3 million, respectively, in Prepayments and Other Current Assets and $3 million and $21 million, respectively, in Deferred Charges and Other Noncurrent Assets on the balance sheets for dry cask storage and related operation and maintenance costs for recovery under this agreement. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for additional information.

Nuclear Insurance

I&M carries nuclear property insurance of $2.7 billion to cover a nuclear incident at Cook Plant including coverage for decontamination and stabilization, as well as premature decommissioning caused by a nuclear incident. Insurance coverage for a nonnuclear property incident at Cook Plant is $500 million. Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage. I&M utilizes industry mutual insurers for the placement of this insurance coverage. Coverage from these industry mutual insurance programs require a contingent financial obligation of up to $41 million for I&M, which is assessable if the insurer’s financial resources would be inadequate to pay for industry losses.

The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public nuclear liability arising from a nuclear incident of $13.7 billion and applies to any incident at a licensed reactor in the U.S. Commercially available insurance, which must be carried for each licensed reactor, provides $450 million of primary coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $275 million per nuclear incident on Cook Plant’s reactors payable in annual installments of $41 million. The number of incidents for which payments could be required is not limited.

In the event of an incident of a catastrophic nature, I&M is covered for public nuclear liability for the first $450 million through commercially available insurance. The next level of liability coverage of up to $13.2 billion would be covered by claim premium assessments made under the Price-Anderson Act. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds, I&M would seek recovery of those amounts from customers through a rate increase. If recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition.

288

OPERATIONAL CONTINGENCIES

Insurance and Potential Losses

The Registrants maintain insurance coverage normal and customary for electric utilities, subject to various deductibles. The Registrants also maintain property and casualty insurance that may cover certain physical damage or third-party injuries caused by cyber security incidents. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. The insurance programs also generally provide coverage against loss arising from certain claims made by third-parties and are in excess of retentions absorbed by the Registrants. Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers. See “Nuclear Contingencies” section above for additional information.

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cyber security incident or damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition.

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

289

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

Litigation Related to Ohio House Bill 6 (HB 6) (Applies to AEP and OPCo)

290

brief in opposition to intervention on February 3, 2023. The two derivative actions pending in federal district court in Ohio have been consolidated and the plaintiffs in the consolidated action filed an amended complaint. AEP filed a motion to dismiss the amended complaint on May 3, 2022 and briefing on the motion to dismiss has been completed. Discovery remains stayed pending the district court’s ruling on the motion to dismiss. The plaintiff in the Ohio state court case advised that they no longer agreed to stay the proceedings, therefore, AEP filed a motion to continue the stays of proceedings on May 20, 2022 and the plaintiff filed an amended complaint on June 2, 2022. On June 15, 2022, the Ohio state court entered an order continuing the stays of that case until the resolution of the consolidated derivative actions pending in Ohio federal district court. The defendants will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

Claims for Indemnification Related to Damages Resulting from the Federal EPA’s Denial of Alternative Closure Deadline for Gavin Plant and Associated Findings of Compliance

In November 2022, the Federal EPA issued a final decision denying Gavin Power LLC’s requested extension to allow a CCR surface impoundment at the Gavin Power Station to continue to receive CCR and non-CCR waste streams after April 11, 2021 until May 4, 2023 (the Gavin Denial). As part of the Gavin Denial, the Federal EPA made several determinations related to the CCR Rule (see “Environmental Issues - Coal Combustion Residual (CCR) Rule” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information), including a determination that the closure of the 300 acre unlined fly ash reservoir (FAR) is noncompliant with the CCR Rule in multiple respects. The Gavin Power Station was formerly owned and operated by AEP and was sold to Gavin Power LLC and Lightstone Generation LLC in 2017. Pursuant to the PSA, AEP maintained responsibility to complete closure of the FAR in accordance with the closure plan approved by the Ohio EPA which was completed in July 2021. The PSA contains indemnification provisions, pursuant to which the owners of the Gavin Power Station have notified AEP they believe they are entitled to indemnification for any damages that may result from the Gavin Denial, as well as any future enforcement or litigation resulting from the Federal EPA’s determinations of noncompliance with various aspects of the CCR Rule as part of the Gavin Denial. Management does not believe that the owners of the Gavin Power Station have any valid claim for indemnity or otherwise against AEP under the PSA. In addition, Gavin Power LLC, several AEP subsidiaries, and other parties have filed Petitions for Review of the Gavin Denial with the U.S. Court of Appeals for the District of Columbia Circuit. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

291

7. ACQUISITIONS, ASSETS AND LIABILITIES HELD FOR SALE, DISPOSITIONS AND IMPAIRMENTS

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

ACQUISITIONS

2021

Dry Lake Solar Project (Generation & Marketing Segment) (Applies to AEP)

In November 2020, AEP signed a Purchase and Sale Agreement with a nonaffiliate to acquire a 75% ownership interest in the entity that owns the 100 MW Dry Lake Solar Project (collectively referred to as 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. See Note 17 - Variable Interest Entities and Equity Method Investments for additional information.

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 1,484 MWs, on a fixed cost turn-key basis. PSO and SWEPCo own undivided interests of 45.5% and 54.5% of the NCWF, respectively. In total, the three wind facilities cost approximately $2 billion and consist of Traverse (998 MW), Maverick (287 MW) and Sundance (199 MW). Output from the NCWF serves 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 until the amounts are reflected in base rates. Recovery of the Arkansas portion of the NCWF revenue requirement through base rates was approved by the APSC in May 2022. 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.

292