AEP's carrying amount of goodwill for the years ended December 31, 2023 and 2022 by operating segment are as follows:

&
Marketing

 Balance as of December 31, 2021
 $
 37.1
 $
 15.4
 $
 52.5

 Impairment Losses
 —
 —
 —

 Balance as of December 31, 2022
 37.1
 15.4
 52.5

 Impairment Losses
 —
 —
 —

 Balance as of December 31, 2023
 $
 37.1
 $
 15.4
 $
 52.5

 In the fourth quarters of 2023 and 2022, annual impairment tests were performed. The fair values of the reporting units with goodwill were estimated using cash flow projections and other market value indicators. There were no goodwill impairment losses. AEP does not have any accumulated impairment on existing goodwill.

&
Marketing

 Balance as of December 31, 2021
 $
 37.1
 $
 15.4
 $
 52.5

 Impairment Losses
 —
 —
 —

 Balance as of December 31, 2022
 37.1
 15.4
 52.5

 Impairment Losses
 —
 —
 —

 Balance as of December 31, 2023
 $
 37.1
 $
 15.4
 $
 52.5

37.115.452.5———37.115.452.5———37.115.452.5 SUBSEQUENT EVENTS Planned Disposition of the Competitive Contracted Renewables Portfolio (Generation & Marketing Segment) (Applies to AEP)

 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.

 As of December 31, 2023, 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.
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 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, 2023
 or
 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the transition period from __________ to_________

 Commission

 Registrants;

 I.R.S. Employer

 File Number

 Address and Telephone Number
 States of Incorporation

 Identification Nos.

 1-3525

 AMERICAN ELECTRIC POWER CO INC.
 New York

 13-4922640

 333-221643
 AEP TEXAS INC.
 Delaware
 51-0007707

 333-217143

 AEP TRANSMISSION COMPANY, LLC
 Delaware

 46-1125168

 1-3457

 APPALACHIAN POWER COMPANY

 54-0124790

 1-3570

 INDIANA MICHIGAN POWER COMPANY

 35-0410455

 1-6543

 OHIO POWER COMPANY
 Ohio

 31-4271000

 0-343

 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

 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, Public Service Company of Oklahoma and Southwestern Electric Power Company, are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.
 Yes
 x
 No

 Indicate by check mark if the registrant Indiana Michigan Power Company is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
 Yes

 No
 x

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

 No
 x

 Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
 Yes
 x
 No

 Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
 Yes
 x
 No

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

 Large Accelerated filer
 x
 Accelerated filer

 Non-accelerated filer

 Smaller reporting company

 Emerging growth company

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

 Large Accelerated filer

 Accelerated filer

 Non-accelerated filer
 x

 Smaller reporting company

 Emerging growth company

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

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

 x

 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

 No
 x

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

 Aggregate Market Value of Voting and Non-Voting Common Equity Held by Nonaffiliates of the Registrants as of June 30, 2023 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, 2023

 American Electric Power Company, Inc.
 $ 44,304,742,057
 526,184,585

 ($6.50 par value)

 AEP Texas Inc.
 None

 ($0.01 par value)

 AEP Transmission Company, LLC (a)
 None
 NA

 Appalachian Power Company
 None
 13,499,500

 (no par value)

 Indiana Michigan Power Company
 None
 1,400,000

 (no par value)

 Ohio Power Company
 None
 27,952,473

 (no par value)

 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.

 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 2024 Annual Meeting of Shareholders.

 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.

 Item

 Page

 Glossary of Terms
 i

 Forward-Looking Information
 vi

 Business

 Business Segments

 Executive Officers of AEP

 1A
 Risk Factors

 1B
 Unresolved Staff Comments

 1C
 Cybersecurity

 Properties

 Generation Facilities

 Transmission and Distribution Facilities

 Title to Property

 System Transmission Lines and Facility Siting

 Construction Program

 Potential Uninsured Losses

 Legal Proceedings

 Mine Safety Disclosure

 Market for Registrants' Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 Reserved

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

 7A
 Quantitative and Qualitative Disclosures about Market Risk

 Financial Statements and Supplementary Data

 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 9A
 Controls and Procedures

 9B
 Other Information

 9C
 Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

 Directors, Executive Officers and Corporate Governance

 Executive Compensation

 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 Certain Relationships and Related Transactions and Director Independence

 Principal Accounting Fees and Services

 Exhibits and Financial Statement Schedules

 Financial Statements

 Form 10-K Summary

 Signatures

 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

 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 Inc., an AEP electric utility subsidiary. AEP Texas engages in the transmission and distribution of electric power to retail customers in west, central and southern Texas.

 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.

 AEPSC

 American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.

 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. APCo engages in the generation, transmission and distribution of electric power to retail customers in the southwestern portion of Virginia and southern West Virginia.

 Appalachian Consumer Rate Relief Funding
 Appalachian Consumer Rate Relief Funding LLC, a wholly-owned subsidiary of APCo and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to the under-recovered ENEC deferral balance.

 APTCo
 AEP Appalachian Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.

 APSC
 Arkansas Public Service Commission.

 ARO
 Asset Retirement Obligations.

 ASU
 Accounting Standards Update.

 ATM
 At-the-Market.

 i

 Term

 BHE
 Berkshire Hathaway Energy.

 CAA

 Clean Air Act.

 CCR
 Coal Combustion Residual.

 CLECO
 Central Louisiana Electric Company, a nonaffiliated utility company.

 CO2

 Carbon dioxide and other greenhouse gases.

 Cook Plant

 Donald C. Cook Nuclear Plant, a two-unit, 2,296 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.

 CWIP
 Construction Work in Progress.

 DCC Fuel
 DCC Fuel XIII, DCC Fuel XIV, DCC Fuel XV, DCC Fuel XVI, DCC Fuel XVII, DCC Fuel XVIII and DCC Fuel XIX consolidated VIEs formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.

 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.

 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. I&M engages in the generation, transmission and distribution of electric power to retail customers in northern and eastern Indiana and southwestern Michigan.

 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).

 IRP
 Integrated Resource Plan.

 ii

 Term

 IRS
 Internal Revenue Service.

 ITC
 Investment Tax Credit.

 IURC

 Indiana Utility Regulatory Commission.

 KGPCo

 Kingsport Power Company, an AEP electric utility subsidiary. KGPCo provides electric service to retail customers in Kingsport, Tennessee and eight neighboring communities in northeastern Tennessee.

 KPCo

 Kentucky Power Company, an AEP electric utility subsidiary. KPCo engages in the generation, transmission and distribution of electric power to retail customers in eastern Kentucky.

 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.

 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.

 NERC
 North American Electric Reliability Corporation.

 NMRD
 New Mexico Renewable Development, LLC.

 Nonutility Money Pool

 Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.

 NOL
 Net operating losses.

 NOLC
 Net operating loss carryforwards.

 NOx

 Nitrogen oxide.

 NRC

 Nuclear Regulatory Commission.

 OATT

 Open Access Transmission Tariff.

 OCC

 Corporation Commission of the State of Oklahoma.

 OHTCo
 AEP Ohio Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.

 OKTCo
 AEP Oklahoma Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.

 OPCo

 Ohio Power Company, an AEP electric utility subsidiary. OPCo engages in the transmission and distribution of electric power to retail customers in Ohio.

 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.

 iii

 Term

 Parent
 American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.

 PCA
 Power Coordination Agreement among APCo, I&M, KPCo and WPCo.

 PJM

 Pennsylvania – New Jersey – Maryland regional transmission organization.

 PM
 Particulate Matter.

 PPA
 Purchase Power and Sale Agreement.

 PSA
 Purchase and Sale Agreement.

 PSO

 Public Service Company of Oklahoma, an AEP electric utility subsidiary. PSO engages in the generation, transmission and distribution of electric power to retail customers in eastern and southwestern Oklahoma.

 PTC
 Production Tax Credit.

 PUCO

 Public Utilities Commission of Ohio.

 PUCT

 Public Utility Commission of Texas.

 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.

 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.

 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.

 Southwestern Electric Power Company, an AEP electric utility subsidiary. SWEPCo engages in the generation, transmission and distribution of electric power to retail customers in northeastern and panhandle of Texas, northwestern Louisiana and western Arkansas.

 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.

 iv

 Term

 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.

 Turk Plant
 John W. Turk, Jr. Plant, a 650 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.

 UMWA
 United Mine Workers of America.

 UPA
 Unit Power Agreement.

 Utility Money Pool

 Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.

 VIE
 Variable Interest Entity.

 Virginia SCC

 Virginia State Corporation Commission.

 WPCo

 Wheeling Power Company, an AEP electric utility subsidiary. WPCo provides electric service to retail customers in northern West Virginia.

 WVPSC

 Public Service Commission of West Virginia.

 WVTCo
 AEP West Virginia Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.

 v

 FORWARD-LOOKING INFORMATION

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

 •
 Changes in economic conditions, electric market demand and demographic patterns in AEP service territories.

 •
 The economic impact of increased global trade tensions including the conflicts in Ukraine and the Middle East, 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 or instability in the banking industry; 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, subsidiaries and tax credits and anticipated securitizations 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.

 •
 Limitations or restrictions on the amounts and types of insurance available to cover losses that might arise in connection with natural disasters or operations.

 •
 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, cost caps imposed by regulators and other operational commitments to regulatory commissions and customers for renewable generation projects, and to recover all related costs.

 •
 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.

 •
 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 or regulatory proceedings or investigations.

 •
 The ability to efficiently manage operation and maintenance costs.

 •
 Prices and demand for power generated and sold at wholesale.

 •
 Changes in technology, particularly with respect to energy storage and new, developing, alternative or distributed sources of generation.

 •
 The ability to recover through rates any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives.

 •
 Volatility and changes in markets for coal and other energy-related commodities, particularly changes in the price of natural gas.

 vi

 •
 The impact of changing expectations and demands of customers, regulators, investors and stakeholders, including focus 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, wildfires, cybersecurity 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.
 vii

 ITEM 1. BUSINESS

 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 AEP have contractual, financial and other business relationships with the other member companies, such as participation in AEP savings and retirement plans and tax returns, sales of electricity and transportation and handling of fuel. The member companies of AEP 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, 2023, the subsidiaries of AEP had a total of 17,250 employees. Because it is a holding company rather than an operating company, AEP has no employees.

 Information related to AEP subsidiary operating companies as of December 31, 2023 is shown in the table below:

 APCo
 I&M
 KGPCo (a)
 KPCo
 OPCo (b)
 PSO
 WPCo

 State of Incorporation
 Delaware, 1925
 Delaware, 2006
 Virginia, 1926
 Indiana, 1907
 Virginia, 1917
 Kentucky, 1919
 Ohio,
 1907
 Oklahoma, 1913
 Delaware, 1912
 West Virginia, 1883

 AEP Reportable Segment

 RTO Affiliation
 ERCOT
 (c)
 PJM
 PJM
 PJM
 PJM
 PJM
 SPP
 SPP
 PJM

 Approximate Number of Retail Customers
 1,111,000
 (c)
 967,000
 613,000
 49,000
 163,000
 1,527,000
 578,000
 548,000
 41,000

 Number of Employees
 1,646
 (c)
 1,679
 2,110
 1,752
 1,062
 1,344

 Overhead Circuit Miles of Transmission and Distribution Lines
 46,673
 4,188
 51,558
 20,584
 1,405
 11,210
 44,519
 18,156
 26,233
 1,722

 (a)KGPCo does not own any generating facilities and purchases electric power from APCo for distribution to its customers.
 (b)OPCo purchases energy and capacity at auction to serve generation service customers who have not switched to a competitive generation supplier.
 (c)AEPTCo is a holding company for the State Transcos. Five State Transcos are members of PJM and two State Transcos are members of SPP. Neither AEPTCo nor its subsidiaries have any employees. Instead, AEPSC and certain AEP utility subsidiaries provide services to these entities.

 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, 2023, AEPSC had 6,736 employees.

 Principal Industries Served

 The following table illustrates the principal industries and wholesale electric markets served by AEP's public utility subsidiaries.

 APCo
 I&M
 KGPCo
 KPCo
 OPCo
 PSO
 WPCo

 Principal Industries Served:

 Petroleum and Coal Products Manufacturing
 X
 X
 X
 X
 X

 Chemical Manufacturing
 X
 X
 X
 X
 X
 X
 X
 X

 Oil and Gas Extraction
 X
 X
 X
 X

 Pipeline Transportation
 X
 X
 X
 X
 X
 X

 Primary Metal Manufacturing
 X
 X
 X
 X
 X
 X

 Data Processing (a)
 X
 X

 Coal-Mining
 X
 X
 X

 Paper Manufacturing
 X
 X
 X
 X

 Transportation Equipment
 X
 X

 Plastics and Rubber Products
 X
 X
 X
 X

 Fabricated Metals Product Manufacturing
 X

 Food Manufacturing
 X

 Supply and Market Electric Power at Wholesale to:

 Other Electric Utility Companies
 X
 X
 X
 X
 X
 X

 Rural Electric Cooperatives
 X
 X
 X

 Municipalities
 X
 X
 X
 X
 X

 Other Market Participants
 X
 X
 X
 X
 X
 X

 (a)Primarily includes data centers and cryptocurrency operations.

 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)

 Arkansas
 9.50
 %

 FERC
 AEPTCo - PJM
 10.35
 %
 (b)

 AEPTCo - SPP
 10.50
 %

 I&M
 9.70
 %

 Kentucky
 KPCo
 9.75
 %
 (c)

 9.50
 %

 Michigan
 I&M
 9.86
 %

 Ohio
 OPCo
 9.70
 %

 PSO
 9.30
 %

 Tennessee
 KGPCo
 9.50
 %

 Texas
 9.40
 %

 9.25
 %
 (d)

 APCo
 9.50
 %

 APCo
 9.75
 %

 WPCo
 9.75
 %

 (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)The KPSC issued an order approving a 9.75% ROE, effective January 2024. See "2023 Kentucky Base Rate and Securitization Case" section of Note 4 for additional information.
 (d)In February 2022, as part of the 2020 Texas Base Rate Case, SWEPCo filed a motion for rehearing with the PUCT alleging 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. See "2020 Texas Base Rate Case" section of Note 4 for additional information.

 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

 AEP subsidiaries 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 from operations, AEP's commercial paper program and term loan issuances. 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 2023 Annual Report for additional information.

 AEP's revolving credit agreements (which backstop the commercial paper program) include covenants and events of default typical for these types of facilities, 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 agreements. As of December 31, 2023, 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 applicable 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 2023 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.

 ENVIRONMENTAL AND OTHER MATTERS

 AEP subsidiaries are currently subject to regulation by federal, state and local authorities with regard to air and water-quality control, solid and hazardous waste disposal and other environmental matters, and are subject to zoning and other regulation by local authorities. The current and proposed environmental laws and regulations discussed below will have an impact on AEP's operations. Management continues to monitor developments in these regulations and evaluate the economic feasibility and refine cost estimates for compliance. For additional information on the laws and regulations discussed below, see "Environmental Issues" section of Management's Discussion and Analysis of Financial Condition and Results of Operations included in the 2023 Annual Report.

 Clean Air Act Requirements (CAA)

 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.

 Clean Water Act Requirements

 The Federal EPA's ELG rule for generation facilities establishes limits for FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater, which are implemented through each facility's wastewater discharge permit. In March 2023, the Federal EPA proposed further revisions to the ELG rule which, if finalized, would establish a zero discharge standard for FGD wastewater and bottom ash transport water, and more stringent discharge limits for combustion residual leachate. Management cannot predict whether the Federal EPA will actually finalize further revisions but will continue to monitor this issue and its potential impact to operations.

 Coal Ash Regulation

 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 May 2023, the Federal EPA proposed revisions to the CCR Rule to expand the scope of the rule to include inactive impoundments at inactive facilities ("legacy CCR surface impoundments") as well as to establish requirements for currently exempt solid waste management units that involve the direct placement of CCR on the land ("CCR management units"). The Federal EPA is proposing that owners and operators of legacy surface impoundments comply with all of the existing CCR Rule requirements applicable to inactive CCR surface impoundments at active facilities, except for the location restrictions and liner design criteria. The proposal establishes accelerated compliance deadlines for legacy surface impoundments to meet regulatory requirements, including a requirement to initiate closure within one year after the effective date of the final rule. The Federal EPA's proposal would require evaluations to be completed at both active facilities and inactive facilities with one or more legacy surface impoundments. If finalized, AEP may incur material, additional costs complying with the Federal EPA's proposal, including costs to upgrade or close and replace legacy CCR surface impoundments and to conduct any required remedial actions including removal of coal ash. In addition, AEP would need to seek cost recovery through regulated rates, including proposing new regulatory mechanisms for cost recovery, for which regulatory approval cannot be assured. The proposed rule, if finalized, could have a material adverse impact on net income, cash flows and financial condition if AEP cannot ultimately recover any additional costs of compliance.

 Climate Change, CO2 Regulation and Energy Policy

 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. In May 2023, the Federal EPA proposed greenhouse gas standards and guidelines for new and existing fossil-fuel fired sources. The proposal relies heavily on carbon capture and sequestration and natural gas co-firing as means to reduce CO2 emissions from coal fired plants and hydrogen co-firing and carbon capture and sequestration to reduce CO2 emissions from gas turbines. Management is evaluating the proposed rule.

 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 2023 Annual Report for additional information.

 Electric Industry Transformation

 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 routinely submits IRPs in various regulatory jurisdictions to address future generation and capacity needs. These IRPs take into account economics, customer demand, grid reliability and resilience, regulations and RTO capacity requirements. The objective of the IRPs is to recommend future generation and capacity resources that provide the most cost-efficient and reliable power to customers. Based on the results of the IRPs, 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.

 As of December 31, 2023, AEP's generating capacity included owned and PPA capacity of approximately 23,300 MWs and 5,200 MWs, respectively. In 2023, owned and PPA coal capacity represented 42% of AEP's generating capacity compared with 70% in 2005.

 The graph below summarizes AEP's generating capacity by resource type for the years 1999, 2005 and 2023:

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

 In addition, certain states AEP subsidiaries serve 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, 2023, 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, as of December 31, 2023, AEP's regulated utilities own and operate 1,639 MWs of wind, 816 MWs of hydro and 41 MWs of solar power.

 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 10.5 million MWhs and peak demand by approximately 3,600 MWs. Management estimates that its operating companies spent approximately $1.7 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. In 2023, AEP also established a Climate Change Executive Group to ensure appropriate management and accountability concerning climate-related impacts, risks and opportunities.

 AEP routinely submits IRPs in various regulatory jurisdictions to address future generation and capacity needs. These IRPs take into account economics, customer demand, grid reliability and resilience, regulations and RTO capacity requirements. The objective of the IRPs is to recommend future generation and capacity resources that provide the most cost-efficient and reliable power to customers. Based on the output of the company's IRPs, in October 2022, AEP announced new intermediate and long-term CO2 emission reduction goals. 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 for Scope 1 and Scope 2 emissions. AEP's total Scope 1 GHG estimated emissions in 2023 were approximately 42.8 million metric tons, a 68% reduction according to the GHG Protocol, which excludes emission reductions that result from assets that have been sold, or a 72% 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 over the long-term. AEP also expects Scope 1 GHG emissions to vary annually depending on the mix of its own generation and purchased power used to serve customers. AEP's ability to achieve these goals is dependent upon a number of factors including the ability to execute on renewable resource plans, evolving RTO requirements, constructive regulatory support, the advancement of carbon-free generation technologies, customer demand for carbon-free energy, potential tariffs, carbon policy and regulation, operational performance of renewable generation and supply chain costs and constraints, all while continuing to provide the most cost-efficient and reliable power to customers.

 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, 2023:

 Subsidiary
 Number of Employees

 AEPSC
 6,736

 1,646

 APCo
 1,679

 I&M
 2,110

 OPCo
 1,752

 PSO
 1,062

 1,344

 Other

 Total AEP
 17,250

 Of AEP's 17,250 employees, less than 0.1% are Traditionalists (born before 1946), approximately 17% are Baby Boomers (born 1946-1964), approximately 36% are Generation X (born 1965-1980), approximately 39% are Millennials (born 1981-1996) and approximately 7% are Generation Z (born after 1996).

 Safety

 Safety is deeply embedded in our culture and is one of AEP's core values because we care that everyone goes home at the end of each work day. We have policies, procedures, programs, training and proactive initiatives in place to help ensure a safe mindset and work environment. Unfortunately, in 2023, we suffered three devastating losses as two employees and one contractor lost their lives. The loss of a single life is unacceptable and we are determined to learn from each event, independently, so we can take action to better protect our employees and all those who support us. These events reinforce the importance of our endless commitment to a strong safety culture and the work it takes to operate safely. We are committed to taking bold steps to fundamentally embed layers of protection in the work we do. This includes focusing our efforts to prevent serious injuries and fatalities, strengthening pre-job briefing effectiveness, learning from significant incidents, providing appropriate training and education and improving proactive safety initiatives and data analysis to identify and address potential performance gaps. 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 and divided by total YTD hours worked) that describes the number of injuries per 100 full-time employees. In 2023, AEP's employee DART rate performance improved to 0.384 as compared to 0.424 in 2022.

 Culture and Inclusion

 Culture serves as the foundation for success at AEP. An engaged, collaborative, inclusive and appreciated workforce is an empowered workforce – one that is more likely to embrace change, drive continuous improvement, take ownership, and value personal and professional growth. AEP views a culture of inclusion as a core business value that creates understanding, sparks innovation and allows us to better serve our customers. We are committed to building a work culture that champions respect and belonging, that leverages our differences as a strength. Inclusion is important to ensuring that AEP has the best talent to move our company forward and achieve business objectives. Our inclusion efforts are guided by four principles:

 • Establishing leadership accountability around culture and inclusion outcomes.
 • Building and maintaining a workforce that generally 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 generally should re ect 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, 2023, women comprised approximately 20% of AEP's total workforce. As of December 31, 2023, approximately 21% of AEP's total workforce was represented by racially or ethnically diverse employees.

 Our progress is tied to enterprise, business unit and operating company annual incentive compensation objectives, which is measured through our annual employee culture survey. 2023 marks our tenth consecutive year of formally surveying employees about their experiences with culture at AEP. In 2023, 94% of our organization participated in the survey, and we continued to improve our performance remaining in the top decile compared to Gallup's overall company database. The culture survey provides a process for leaders to share results with their teams, facilitate discussions to improve employee engagement and take actions toward that improvement throughout the year. AEP's Human Resources Committee of the Board reviews the culture and employee engagement results annually, providing additional oversight. In addition, the Human Resources Committee of the Board provides oversight of our compensation and human resources policies and practices, including an annual review of our culture and inclusion strategy, and compliance with equal opportunity laws. In 2023, AEP received the Gallup Exceptional Workplace Award for the fourth consecutive year. This award recognizes organizations with engaged workplace cultures.

 To support a culture of inclusion, AEP launched the Culture and Inclusion Council, which consists of decision makers from across the company to help lead our culture strategy. A key focus for the council will be prioritizing our Culture & Inclusion guiding principles. In addition, AEP launched the Access to Opportunity standards to enhance female and minority representation within AEP's leadership and conducted 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 initiatives to demonstrate our commitment to advancing a culture of 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. This five-year, $5 million initial investment supports nonprofit organizations that are working to dismantle systemic racism and injustices in our communities.

 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, the Women at Work ERG and the Empowered Parents and Caregivers ERG. Encouraging engagement through one of our nine ERGs creates meaningful connections through shared experiences and learning about different cultures and lived experiences for deeper understanding and knowledge. Their strategic priorities include recruiting and retaining diverse employees, identifying and participating in community volunteerism opportunities, building cultural competency among our employees and positively impacting the business.

 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 a growing co-op and internship program for high school and college students. Our alliances with community colleges, universities and vocational and technical schools across our 11-state service territory support the development of our talent pipeline. We work with these institutions to develop academic programs that will prepare students for new jobs and career opportunities 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 2023, AEP employees completed more than 806,000 hours of training in programs for which we track participation. In addition, AEP invested more than $2 million in employee education, supporting approximately 560 employees through our tuition reimbursement program.

 Compensation and Benefits

 AEP is committed to the well-being of our employees and we offer programs to foster employee financial security; physical and emotional health; and social connectedness. We provide market competitive compensation and benefits that support 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 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 paid time off in the form of vacation, holidays, sick time and parental leave. The company's employee assistance plan, medical and dental coverage, life insurance and well-being program 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 relationship 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 2023 Annual Report for additional information on AEP's segments.

 Seasonality

 The consumption and delivery of electric power is generally seasonal which impacts the results of operations of AEP's reportable segments. 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 and delivered 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. In Texas, 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.

 VERTICALLY INTEGRATED UTILITIES

 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, 2023, AEP's vertically integrated public utility subsidiaries owned approximately 23,000 MWs of 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:

 2023
 2022
 2021

 Coal and Lignite
 37%
 43%
 50%

 Nuclear
 22%
 21%
 22%

 22%
 19%
 16%

 Renewables
 19%
 17%
 12%

 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 2023 fossil fuel costs for the Vertically Integrated Utilities decreased 28.3% on a dollar per MMBtu basis from 2022.

 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 23.9% in 2023 (exclusive of fuel oil) from 2022 due to a combination of the retirement of the Pirkey Power Plant in March 2023 and lower generation at the coal fired power plants due to a significant decline in natural gas prices. AEP's Vertically Integrated Utilities operations no longer use lignite as a fuel source after the retirement of the Pirkey Power Plant.

 Management projects that the Vertically Integrated Utilities will be able to secure and transport coal of adequate quality and quantities to operate their coal fired units. As of December 31, 2023, through subsidiaries, AEP owns, leases or controls 3,180 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.

 The market price for coal began 2023 elevated as compared to recent years, but declined and stabilized as the year progressed. Although the price of coal in 2023 was lower as compared to 2021 and 2022, the price of coal in 2023 is still higher than historical prices prior to 2021. Coal prices are currently projected to remain at these levels due to increased mining costs experienced over the last few years. AEP's strategy for purchasing coal includes layering in supplies over time to help with reducing price volatility. The price impact of this process is reflected in subsequent years when the coal is delivered. The price paid for coal and lignite delivered in 2023 increased approximately 14.5% from 2022 mainly due to the increase in coal prices contracted in prior years. With the elevated prices for coal contracted in 2021 and 2022, management anticipates that delivered coal prices will continue to be higher over the next few years.

 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:

 2023
 2022
 2021

 Total coal and lignite delivered to the plants (in millions of tons)
 20.9
 20.4
 18.2

 Average cost per ton of coal and lignite delivered
 $
 64.31
 $
 56.16
 $
 50.76

 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, coal consumption rates, labor issues, supplier outages and issues and weather conditions, all of which may interrupt or slow production, consumption or deliveries. As of December 31, 2023, the Vertically Integrated Utilities' coal inventory was approximately 82 days of full load burn. Inventory levels grew significantly in 2023 due to mild weather conditions, lower demand for electric power and a decline in natural gas prices. Management expects inventory levels to remain elevated in 2024 due to many of these same factors. While inventory targets vary by plant and are changed as necessary, the current coal inventory target for the Vertically Integrated Utilities is approximately 34 days of full load burn.

 The Vertically Integrated Utilities consumed approximately 146 billion cubic feet of natural gas during 2023 for generating power. This represents an increase of 15.8% from 2022. 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. From a natural gas supply perspective, the Vertically Integrated Utilities utilize daily spot market purchases, as well as longer-term arrangements including monthly baseload, forward month baseload, seasonal baseload and long-term firm purchases. From a natural gas transportation perspective, the Vertically Integrated Utilities utilize firm and interruptible transportation capacity. AEP's natural gas supply, transportation and storage transactions are competitively bid and are based on current 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:

 2023
 2022
 2021

 Total natural gas delivered to the plants (in billions cubic feet)
 146.0
 126.0
 108.0

 Average delivered price per MMBtu of purchased natural gas
 $
 2.69
 $
 6.94
 $
 8.92

 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, 2023 and 2022, the total decommissioning trust fund balance for the Cook Plant was approximately $3.5 billion and $3 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 2023 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, 2023, counterparties posted approximately $36 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 $200 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 2023 Annual Report for additional information.

 Certain Power Agreements

 I&M

 A UPA between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant unless it is sold to another utility. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) net of amounts received by AEGCo from any other sources, sufficient to enable AEGCo to pay all of its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by the FERC. The UPA 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. Prior to the termination of the lease, I&M assigned 30% of the power to KPCo. 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. See the "Unit Power Agreements" section of Note 16 - Related Party Transactions for additional information.

 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 environmental controls in-service. See Note 17 - Variable Interest Entities and Equity Method Investments for additional information.

 ELECTRIC DELIVERY

 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

 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 2023 Annual Report for more information regarding pending rate matters.

 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 respective fuel and purchased power recovery mechanisms.

 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.

 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.

 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, purchased power costs and transmission expenses through the ENEC which trues-up to actual expenses. See "ENEC Filings" section of Note 4 - Rate Matters included in the 2023 Annual Report for additional information. 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 mandatory reliability standards promulgated by the NERC, with the approval of the FERC, which standards protect the nation's bulk power system against potential disruptions from cyber and physical security breaches.

 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.

TRANSMISSION AND DISTRIBUTION UTILITIES

 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.

 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 and DCRF filings semi-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 mandatory reliability standards as set forth by the NERC, with the approval of the FERC, which standards protect the nation's bulk power system against potential disruptions from cyber and physical security breaches.

AEP TRANSMISSION HOLDCO

 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 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. 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. 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. SWTCo does not currently own or operate transmission assets.

 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. As of December 31, 2023, the State Transcos had $14.2 billion of transmission and other assets in-service, excluding CWIP, with plans to construct approximately $3.4 billion of additional transmission assets through 2026.

 AEPTHCO JOINT VENTURE INITIATIVES

 AEP has established joint ventures with non-affiliated 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

 ETT
 Texas
 (a)
 BHE (50%)
 $
 5,000.0
 (a)
 9.6
 %

 (ERCOT)

 AEP (50%)

 Prairie Wind
 Kansas
 2014
 Evergy, Inc. (50%)
 158.0
 12.8
 %

 BHE (25%)

 AEP (25%)

 Pioneer
 2018
 Duke Energy (50%)
 191.0
 10.52
 %
 (b)

 AEP (50%)

 Missouri
 2016
 310.1
 11.1
 %
 (c)

 Missouri

 West
 2019
 84.3
 10.5
 %

 Maryland
 2027
 27.6
 (e)
 10.4
 %

 Maryland

 Pennsylvania
 2027
 243.6
 (e)
 10.4
 %

 Pennsylvania

 2026
 127.9
 (f)
 10.3
 %

 Pennsylvania
 2027
 104.1
 (g)
 10.4
 %

 Energy

 (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 $5.0 billion by 2030. 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. In December 2023, the North Delta project was expanded with additional scope and approved by the PJM Board of Managers. The project is expected to go in-service in 2027. The project was originally expected to go in-service in 2029.

 In April 2023, AEP initiated a strategic evaluation for its ownership in Pioneer Transmission, LLC, Prairie Wind Transmission, LLC and Transource Energy. In July 2023, AEP made a decision to initiate a sales process for its investment in Pioneer Transmission, LLC and Prairie Wind Transmission, LLC. In February 2024, AEP management determined it would retain its ownership of its investment in Pioneer Transmission, LLC and Prairie Wind Transmission, LLC.

 As of December 31, 2023, the net book value of Transource Energy was $289 million inclusive of $39 million related to noncontrolling interest on AEP's balance sheet. AEP management recently completed its strategic review and determined it would retain this business due to its fit within the goals and objectives of AEP and its overall leadership role in the U.S. electric transmission space.

 Transource Energy, and its subsidiaries 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 2023, approximately 494 AEPSC employees and 317 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 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 mandatory reliability standards promulgated by the NERC, with the approval of the FERC, which standards protect the nation's bulk power system against potential disruptions from cyber and physical security breaches. Management monitors pending matters before the FERC, including inquiries and challenges related to ROEs and transmission formula rates, that have the potential to reduce AEP's future transmission formula rates and/or the transmission ROE methodology.

 In the annual rate base filings described above, the State Transcos in aggregate filed rate base totals of $10.7 billion, $9.9 billion and $8.4 billion for 2023, 2022 and 2021, respectively. The total filed transmission revenue requirements, including prior year over/under-recovery of revenue and associated carrying charges were $1.8 billion, $1.7 billion and $1.4 billion for 2023, 2022 and 2021, 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

 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 Energy, AEP OnSite Partners, AEPEP and AGR. AEP Energy Supply, LLC also included AEP Renewables prior to its sale in August 2023. For more information on the sale of AEP Renewables, see the "Contracted Renewable Generation Facilities" section of Management's Discussion and Analysis.

 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, 2023, AEP OnSite Partners owned projects located in 22 states, including approximately 195 MWs of installed solar capacity, and approximately 4 MWs of solar projects under construction.

 AEP Energy is a retail energy supplier and energy management business 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 929,000 customer accounts as of December 31, 2023.

 In April 2023, AEP announced the initiation of a sales process for its ownership in AEP Onsite Partners and AEP Energy. The timing of the completion of the sales process is dependent upon a number of factors, but AEP is targeting the completion of the sales process in the first half of 2024. For more information, see the "2023 Significant Developments and Transactions" section of Management's Discussion and Analysis.

 AEP Energy Partners enters into short-term and long-term transactions to buy or sell capacity, energy and ancillary services in ERCOT, SPP, MISO and PJM. In addition, AEP Energy Partners sells power into the market and engages 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.

 The Generation & Marketing segment also includes AGR which holds the rights to Cardinal Plant Unit 1's power and capacity through 2028 through a PPA with a nonaffiliated electric cooperative.

 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.

 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 AEP Onsite Partner's competitiveness. The costs of photovoltaic solar cells in particular have continued to become increasingly competitive.

 AEP Energy provides 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.

 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, 2023, counterparties posted approximately $117 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 $155 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 2023 Annual Report for additional information.

 INFORMATION ABOUT OUR EXECUTIVE OFFICERS

 The following persons are executive officers of AEP. Their ages are given as of February 26, 2024. The officers are appointed annually for a one-year term by the board of directors of AEP.

 Benjamin G.S. Folke, III
 Interim Chief Executive Officer and President
 Age 65
 Interim Chief Executive Officer and President since February 2024. Director since February 2022. Chairman of the board of directors of Xcel Energy Inc. from August 2011 to December 2021. Chief Executive Officer of Xcel Energy Inc. from August 2011 to August 2021. President of Xcel from August 2011 to March 2020. Chief Executive Officer of Xcel's utility subsidiaries Northern States Power Company, Public Service Company of Colorado and Southwestern Public Service Co. from January 2015 to August 2021.

 Christian T. Beam
 Executive Vice President - Energy Services
 Age 55
 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 54
 Executive Vice President since January 2013. General Counsel and Secretary since January 2012.

 Greg B. Hall
 Executive Vice President and Chief Commercial Officer
 Age 51
 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.

 Therace M. Risch
 Executive Vice President and Chief Information & Technology Officer
 Age 50
 Executive Vice President since July 2021. Chief Information & Technology Officer since May 2020. Senior Vice President from April 2020 to July 2021. Executive Vice President, Chief Information Officer of JCPenney from December 2015 to May 2020.

 Peggy I. Simmons
 Executive Vice President - Utilities
 Age 46
 Executive Vice President - Utilities since September 2022. President and Chief Operating Officer of PSO from September 2018 to September 2022.

 Antonio P. Smyth
 Executive Vice President - Grid Solutions & Government Affairs
 Age 47
 Executive Vice President - Grid Solutions & Government Affairs since April 2023. Senior Vice President - Grid Solutions from January 2021 to April 2023. Senior Vice President - Transmission Ventures, Strategy & Policy from October 2018 to December 2020.

 Phillip R. Ulrich
 Executive Vice President and Chief Human Resources Officer
 Age 53
 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.

 Executive Vice President - Chief Financial Officer
 Age 63
 Executive Vice President and Chief Financial Officer since September 2023. Executive Vice President - Portfolio Optimization from July 2021 to September 2023. 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.

 In addition, regulators have initiated and may initiate additional proceedings to investigate the prudence of costs in the AEP regulated utility businesses and in base rates and examine, among other things, the reasonableness or prudence of operation and maintenance practices, level of expenditures (including storm costs and costs associated with capital projects), allowed rates of return and rate base, proposed resource acquisitions, and previously incurred capital expenditures that the regulated utility businesses seek to place in rates. The regulators may disallow costs subject to their jurisdiction found not to have been prudently incurred or found not to have been incurred in compliance with applicable tariffs, creating some risk to the ultimate recovery of those costs. Regulatory proceedings relating to rates and other matters typically involve multiple parties seeking to limit or reduce rates. Traditional base rate proceedings, as opposed to formula rate plans, generally have long timelines, are primarily based on historical costs, and may or may not be limited in scope or duration by statute. The length of these base rate proceedings can cause the regulated utility businesses to experience regulatory lag in recovering costs through rates, such that they may not fully recover all costs during the rate effective period and may, therefore, earn less than their allowed returns. Decisions are typically subject to appeal, further exacerbating the regulatory lag and leading to additional uncertainty associated with rate case proceedings.

 The AEP regulated utility businesses have large customer and stakeholder bases and, as a result, could be the subject of public criticism or adverse publicity focused on issues including the operation and maintenance of their assets and infrastructure, their preparedness for major storms or other extreme weather events and/or the time it takes to restore service after such events, or the quality of their service or the reasonableness of the cost of their service. Criticism or adverse publicity of this nature could render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view the applicable operating company in a favorable light and could potentially negatively affect legislative or regulatory processes or outcomes, as well as lead to increased regulatory oversight or more stringent legislative or regulatory requirements or other legislation or regulatory actions that adversely affect the regulated utility businesses.

 The regulated utility businesses, and the energy industry as a whole, have experienced a period of rising costs and investments and an upward trend in spending, especially with respect to infrastructure investments, which is likely to continue in the foreseeable future and could result in more frequent rate cases and requests for, and the continuation of, cost recovery mechanisms, all of which could face resistance from customers and other stakeholders especially in a rising cost environment, whether due to inflation or high fuel prices or otherwise, and/or in periods of economic decline or hardship. Significant increases in costs could increase financing needs and otherwise adversely affect AEP's business, financial position, results of operation, or cash flows. See Note 4 – Rate Matters included in the 2023 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, small modular reactors 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, including providing service to new large load customers, involves a number of risks, including incomplete or inaccurate forecasting, planning and procurement, 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 interconnection and service agreements, equipment purchase orders and construction contracts and incur engineering and design service costs in advance of receiving necessary regulatory approvals, cost recovery and/or siting or environmental permits. If any of these projects are canceled for any reason, including shifts in large customer needs, preferences or financial stability, failure to receive necessary regulatory approvals, cost recovery and/or siting or environmental permits, significant unrecoverable costs or 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 as of December 31, 2023. 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 unless the NRC specifies a lesser amount 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, 2023, AEP Texas did business with approximately 124 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 2023, AEP Texas' two largest REPs accounted for 41% 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 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 had previously plead guilty and, in March 2023, a federal jury convicted the Ohio legislator and another individual of participating in the racketeering conspiracy. 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 cybersecurity 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, tornadoes, 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 subsidiaries, there has been no material impact on business or operations from these attacks to date. Similarly, some of AEP's third-party vendors have experienced cybersecurity incidents, though such incidents have not, to AEP's knowledge, resulted in a material impact to AEP to date. However, AEP cannot guarantee that security efforts will detect or prevent future 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. While AEP maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damages experienced. Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures.

 AEP is subject to standards enacted by the North American Electric Reliability Corporation and enforced by FERC regarding protection of critical infrastructure assets required for operating North America's bulk electric system. While AEP believes it is in compliance with such standards and regulations, AEP has been, and may in the future be, found to be in violation of such standards and regulations. To date, such violations have not resulted in material financial penalties; however, management can give no assurance that compliance efforts will not result in material penalties in the future. In addition, compliance with or changes in the applicable standards and regulations may subject AEP to higher operating costs and/or increased capital expenditures as well as substantial fines for non-compliance.

 The failure of AEP or third-party vendor information technology systems, or the failure to enhance existing information technology systems and implement new technology, could adversely affect AEP. (Applies to all Registrants)

 AEP's operations are dependent upon the proper functioning of its internal systems, including the information technology systems that support our underlying business processes. Any significant failure or malfunction of such information technology systems may result in disruptions of our operations. In the ordinary course of business, we rely on information technology systems, including the internet and third-party hosted services, to support a variety of business processes and activities and to store sensitive data, including (i) intellectual property, (ii) proprietary business information, (iii) personally identifiable information of our customers, employees, retirees and shareholders and (iv) data with respect to invoicing and the collection of payments, accounting, procurement, and supply chain activities. Our information technology systems are dependent upon global communications and cloud service providers, as well as their respective vendors, many of whom have at some point experienced significant system failures and outages in the past and may experience such failures and outages in the future. These providers' systems are susceptible to cybersecurity and data breaches, outages from fire, floods, power loss, telecommunications failures, break-ins and similar events. Failure to prevent or mitigate data loss from system failures or outages could materially affect AEP's results of operations, financial position and cash flows.

 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 or portions thereof, 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. In addition, AEP has exposure to international banks, including those in Europe, Canada, and Asia. Disruptions in these markets could reduce or restrict the AEP's ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2023, approximately 10%, 17%, and 16% of the Registrants' available credit facilities were with European, Canadian, and Asian banks, respectively.

 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. If AEP is not able to access debt or equity at competitive rates or at all, the ability to finance its operations and implement its strategy and business plan as scheduled could be adversely affected. An inability to access debt and equity may limit AEP's ability to pursue improvements or acquisitions that it may otherwise rely on for future growth.

 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 April 2023, AEP initiated a sales process for its ownership in AEP Energy and AEP Onsite Partners. AEP Onsite Partners also owns a 50% interest in NM Renewable Development, LLC, (NMRD). Separate from the remainder of AEP Onsite Partners, AEP and the joint owner have signed an agreement in December 2023 to sell NMRD to a non-affiliated third-party.

 Any planned sale of assets and investments, including subsidiaries, may not occur for any number of reasons beyond our control, including regulatory approval. If AEP is unable to recover the net book value or carrying value of these assets as part of the sale process, it could reduce future net income 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 that 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 them 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 and impact AEP's strategy to transition its generation fleet. 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 wind patterns or in precipitation resulting in droughts, water shortages or floods could adversely affect operations, principally wind generation facilities for changes in wind patterns and the fossil fuel generating units for changes in precipitation. A change in wind patterns or 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 AEP's service territories. Climate change may impact the economy, which could impact our sales and revenues. The cost of additional regulatory requirements, such as regulation of carbon dioxide emissions, could impact the availability of goods and prices charged by AEP's suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and carbon dioxide emissions as a financial risk, this could negatively affect AEP's ability to access capital markets or cause AEP to receive less than ideal terms and conditions in capital markets.

 The generation, transmission and distribution of electricity are dangerous and involve inherent risks of damage to private property and injury to AEP's workforce and the general public. (Applies to all Registrants)

 Electricity poses hazards for AEP's workforce and the general public in the event that either comes in contact with electrical current or equipment, including through energized downed power lines or through equipment malfunctions. In addition, the risks associated with the operation of transmission and distribution assets and power generation and storage facilities include public and workforce safety issues and the risk of utility assets causing or contributing to wildfires. Deaths, injuries and property damage caused by such events can subject AEP to liability that, despite the existence of insurance coverage, can be significant. In addition, AEP may be held responsible for the actions of its contractors. No assurance can be given that future losses will not exceed the limits of AEP's or its contractors' insurance coverage.

 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 2023 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 severe winter weather in Texas in February 2021. (Applies to AEP and AEP Texas)

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

 AEP Parent and AEP Texas are named in approximately 100 lawsuits alleging multiple claims of wrongful death, personal injury, property damage and other injuries and damages. Certain wind farms formerly owned by AEP have also been named as defendants in up to approximately 125 lawsuits, along with other Texas energy companies and transmission and distribution utilities. Most of the lawsuits contain hundreds of plaintiffs and one of the suits is a purported class action on behalf of all customers in ERCOT. The complaints seek monetary damages among other forms of relief.

 The litigation has been consolidated into a multi-district litigation (MDL) proceeding in Texas state court. The judge overseeing the MDL issued an initial case management order and stayed all proceedings and discovery. 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 AEP affiliates for a substantial portion of its revenues. (Applies to AEPTCo)

 AEPTCo's principal transmission service customers are AEP affiliates. 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, 2023, AEP 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 subsidiary 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 subsidiary utility affiliates will continue to be affiliates of AEPTCo, (b) suitable replacement arrangements can be obtained in the event that the relevant AEP subsidiary 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 AEP subsidiaries 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 and/or voluntary climate goals 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 routinely submits IRPs in various regulatory jurisdictions to address future generation and capacity needs. These IRPs take into account economics, customer demand, grid reliability and resilience, regulations and RTO capacity requirements. The objective of the IRPs is to recommend future generation and capacity resources that provide the most cost-efficient and reliable power to customers. Based on the output of the company's IRPs, in October 2022, AEP announced new intermediate and long-term CO2 emission reduction goals. 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 for Scope 1 and Scope 2 emissions. Risks to achieving these goals include, among other things, the ability to execute on renewable resource plans, evolving RTO requirements, regulatory approvals, customer demand for carbon-free energy, potential tariffs, carbon policy and regulation, operational performance of renewable generation and supply chain costs and constraints, all while continuing to provide the most cost-efficient and reliable power to customers. Technology research and development, innovation, and advancements in carbon-free generation are also critical to AEP's ability to achieve its 2045 goal.

 AEP's results of operations could be materially adversely affected to the extent that new federal or state laws or regulations or voluntary climate goals 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. Further, real or alleged violations of environmental regulations, including those related to climate change, or an inability to meet AEP's voluntary climate goals, could adversely impact AEP's reputation.

 AEP may be constrained by the ability to procure resources or labor needed to build new generation at a reasonable price as well as to construct projects on time. In addition, new technologies that are not yet commercially available or are unproven at utility scale will likely be needed including new resources such as advanced nuclear, hydrogen and long-duration storage. If these technologies are not developed or are not available at reasonable prices, or if AEP invests in early-stage technologies that are then supplanted by technological breakthroughs, AEP's ability to achieve a net-zero target by 2045 at a cost-effective price could be at risk. Achieving our carbon reduction goals will require continued operation of our existing carbon-free technologies

 including nuclear and renewables. The rapid transition to and expansion of certain low-carbon resources, such as renewables without cost-effective storage, may challenge our ability to meet customer expectations of reliability in a carbon constrained environment. AEP cannot predict the ultimate impact of achieving these objectives, or the various implementation aspects, on its system reliability, or its results of operations, financial condition, or liquidity.

 AEP may be unable to procure or construct generation capacity when needed or to recover the costs of such generation capacity. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

 AEP's capacity obligations are subject to a number of factors including load growth, requirements that can be imposed by the states, RTOs and other jurisdictions in which it operates or participates as a member and the retirement of existing generating facilities. AEP must obtain new and replacement generation to comply with prevailing capacity needs and reserve obligations. AEP's ability to acquire, retrofit and/or construct power generation facilities in a timely manner and within budget is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise, escalating costs for capital, materials, labor, and environmental compliance, reliance on suppliers for timely and satisfactory performance, continued pandemic-related delays and cost increases, and supply chains and material constraints, including those that may result from major storm events. Delays in obtaining permits, challenges in securing suitable land for the siting, shortages in materials and qualified labor, levels of public support or opposition, suppliers and contractors not performing as expected or required under their contracts and/or experiencing financial problems that inhibit their ability to fulfill their obligations under contracts, changes in the scope and timing of projects, poor quality initial cost estimates from contractors, the inability to raise capital on favorable terms, changes in commodity prices affecting revenue, fuel costs, or materials costs, downward changes in the economy, changes in law or regulation, including environmental compliance requirements, further direct and indirect trade and tariff issues, supply chain delays or disruptions, and other events beyond AEP's control may occur that may materially affect the schedule, cost, and performance of needed acquisitions or construction projects. If these projects or other capital improvements are significantly delayed or become subject to cost overruns or cancellation, AEP could incur additional costs and termination payments or face increased risk of potential write-off of the investment in the project. In addition, AEP could be exposed to higher costs, penalties and market volatility, which could affect cash flow and cost recovery, should one or more applicable regulator decline to approve the acquisition or construction of the project or new generation needed to meet the reliability needs of customers at the lowest reasonable cost.

 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, 2023, OVEC has outstanding indebtedness of approximately $1.1 billion, of which APCo, I&M, and OPCo are collectively responsible for $465 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 1C. CYBERSECURITY

 The electric utility industry is an identified critical infrastructure function with mandatory cybersecurity requirements under the authority of FERC. The NERC, which FERC certified as the nation's Electric Reliability Organization, developed mandatory critical infrastructure protection cybersecurity 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 refine 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 has a primary and a back-up NERC Critical Infrastructure Protection Senior Manager, who is responsible for 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 cybersecurity controls and authentication. Cyber hackers and other malicious actors have caused material disruption by successfully breaching a number of very secure facilities of entities across the spectrum of industries, including federal agencies and financial institutions. As understanding of these events develop, AEP has adopted a defense in depth approach to cybersecurity and continually assesses its cybersecurity 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 is not aware of any occurrence from cybersecurity threats, including as a result of any previous cybersecurity incidents, that has materially affected or is reasonably likely to materially affect AEP's business strategy, results of operations, cash flows or financial condition.

 AEP has undertaken a variety of actions to monitor and address cyber-related risks. Cybersecurity and the effectiveness of AEP's cybersecurity 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 Chief Security Officer and/or Chief Information & Technology Officer 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 generally consistent 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 maintains dedicated cybersecurity and physical security teams which are responsible for the design, implementation and execution of AEP's security risk management strategy, which includes cybersecurity. AEP's cybersecurity team operates a 24/7 Cybersecurity Intelligence and Response Center responsible for monitoring the AEP System for cyber risks and threats. The cybersecurity team constantly scans the AEP System for cyber risks and threats. In addition, the cybersecurity 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.

 AEP also continually reviews its business continuity plan to develop an effective recovery strategy that seeks to decrease response times, limit financial impacts and maintain customer confidence during any business interruption. AEP 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, internal audit services, information technology and operational technology functions critical to the power grid.

 The cybersecurity 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 participates in classified briefings to maintain an awareness of current cybersecurity threats and vulnerabilities. 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. See "Risk Factors - Risks Related to Market, Economic or Financial Volatility and Other Risks - Physical attacks or hostile cyber intrusions could severely impair operations, lead to the disclosure of confidential information and damage AEP's reputation".

 ITEM 2. PROPERTIES

 GENERATION FACILITIES

 The tables below summarize the net maximum capacity of AEP's owned generation plants as of December 31, 2023. AEP subsidiaries serve customer electricity needs from these facilities and from purchased power in the PJM and SPP markets based on demand and other economic conditions. AEP's regulated subsidiaries have approved recovery mechanisms in retail jurisdictions that recover the cost of prudently incurred fuel, purchased power and other expenses.

 Vertically Integrated Utilities Segment

 AEGCo

 Units
 State

 Rockport (a)
 IN
 1,310
 1984

 (a)AEGCo owns a 50% interest in the Rockport Plant units. I&M owns the remaining 50%. Figures presented reflect only the portion owned by AEGCo.

 APCo

 Units
 State

 Ceredo
 WV
 2001

 Dresden
 OH
 2012

 Smith Mountain
 VA
 Pumped Storage
 1965

 Amos
 WV
 2,950
 1971

 Mountaineer
 WV
 1,320
 1980

 Clinch River
 VA
 1958

 Hydro (Various Plants)
 Various
 VA
 Hydro
 1906-1964

 Hydro (Various Plants)
 Various
 WV
 Hydro
 1935-1938

 Solar
 NA
 VA
 Solar
 2023

 6,717

 I&M

 Units
 State

 Rockport (a)
 IN
 1,310
 1984

 Cook
 MI
 Steam - Nuclear
 2,296
 1975

 Hydro (Various Plants)
 Various
 IN
 Hydro
 1904-1913

 Hydro (Various Plants)
 Various
 MI
 Hydro
 1908-1923

 Solar (Various Plants)
 NA
 IN
 Solar
 2016-2021

 Solar (Various Plants)
 NA
 MI
 Solar
 2016

 3,662

 (a)I&M owns a 50% interest in the Rockport Plant units. AEGCo owns the remaining 50%. Figures presented reflect only the portion owned by I&M.

 KPCo

 Units
 State

 Mitchell (a)
 WV
 1971

 Big Sandy
 KY
 1963

 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.

 PSO

 Units
 State

 Comanche
 OK
 1973

 Northeastern, Unit 1
 OK
 1961

 Riverside, Units 3 and 4
 OK
 2008

 Southwestern, Units 4 and 5
 OK
 2008

 Weleetka
 OK
 1975

 Northeastern, Unit 3
 OK
 1979

 Northeastern, Unit 2
 OK
 1961

 Riverside, Units 1 and 2
 OK
 1974

 Southwestern, Units 1, 2 and 3
 OK
 1952

 Tulsa
 OK
 1956

 North Central Wind Energy Facilities (a)
 NA
 OK
 Wind
 2021-2022

 Rock Falls
 NA
 OK
 Wind
 2023

 4,515

 (a)PSO owns a 45.5% interest and SWEPCo owns the remaining 54.5% interest in Sundance, Maverick and Traverse. Figures presented reflect only the portion owned by PSO.

 Units
 State

 Mattison
 AR
 2007

 Stall
 LA
 2010

 Flint Creek (a)
 AR
 1978

 Turk (a)
 AR
 2012

 Welsh (b)
 TX
 1,053
 1977

 Arsenal Hill
 LA
 1960

 Knox Lee
 TX
 1950

 Lieberman
 LA
 1947

 Wilkes
 TX
 1964

 North Central Wind Energy Facilities (c)
 NA
 OK
 Wind
 2021-2022

 5,009

 (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)SWEPCo owns a 54.5% interest and PSO owns the remaining 45.5% interest in Sundance, Maverick and Traverse. Figures presented reflect only the portion owned by SWEPCo.

 WPCo

 Units
 State

 Mitchell (a)
 WV
 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

 195 MW
 AEP OnSite Partners (a)
 Solar
 Seventeen states (b)
 In-service

 4 MW
 AEP OnSite Partners (a)
 Solar
 Two states (c)
 Under Construction

 (a) In April 2023, AEP made a decision to include AEP Onsite Partners in a sales process that is currently targeted to be completed in the first half of 2024. See the "Planned Sale of AEP Energy and AEP Onsite Partners" section of Executive Overview included in the 2023 Annual Report for additional information.
 (b) California, Colorado, Florida, Hawaii, Illinois, Iowa, Minnesota, Nebraska, New Hampshire, New Jersey, New Mexico, New York, Ohio, Rhode Island, Texas, Vermont and Wisconsin.
 (c) Ohio and Wisconsin.

 TRANSMISSION AND DISTRIBUTION FACILITIES

 The AEP System has significant investments in transmission and distribution lines across its Vertically Integrated Utilities, Transmission and Distribution Utilities and AEP Transmission Holdco Segments. See Item 1 for additional information relating to the total overhead circuit miles of transmission and distribution lines by operating company.

 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, AEP subsidiaries continuously assess the adequacy of their transmission, distribution, generation and other facilities to plan and provide for the reliable supply of electric power and energy to its customers. In this assessment process, assumptions are continually being reviewed as new information becomes available and assessments and plans are modified, as appropriate. AEP forecasts approximately $7.5 billion of construction expenditures for 2024. 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, inflation 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 2023 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 subsidiaries. For risks related to owning a nuclear generating unit, see the "Nuclear Contingencies" section of Note 6 - Commitments, Guarantees and Contingencies included in the 2023 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 2023 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. Prior to October 1, 2023, SWEPCo, through its ownership of DHLC, a wholly-owned lignite mining subsidiary of SWEPCo, was subject to the provisions of the Mine Act. Effective as of October 1, 2023, the U.S. Department of Labor's Mine Safety and Health Administration put DHLC in Abandoned Mine Status. As a result of this designation, DHLC is no longer subject to the Mine Act or Section 1503 of The Dodd-Frank Wall Street Reform and Consumer Protection Act.

 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 2023 Annual Report.

 During the quarter ended December 31, 2023, 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 2023 Annual Report.

 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, 2023, AEP had 49,023 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, 2018 and that all dividends were reinvested.

 Source: S&P Dow Jones Indices LLC. Data as of December 31, 2023. 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 2023 Annual Report. Year-to-year comparisons between 2022 and 2021 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, 2022, which specific discussion is incorporated herein by reference.

 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 2023 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 2023 Annual Report.

 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 2023 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
 Southwestern Electric Power Company Consolidated

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

 INDEX OF ANNUAL REPORTS

 Page

 American Electric Power Company, Inc. and Subsidiary Companies:

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

 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:

 Financial Statements

 Southwestern Electric Power Company Consolidated:

 Index of Notes to Financial Statements of Registrant s

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

 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 23,000 MWs of regulated owned generating capacity as of December 31, 2023, one of the largest complements of generation in the United States.

 AEP CONSOLIDATED RESULTS OF OPERATIONS

 Earnings Attributable to AEP Common Shareholders decreased from $2.3 billion in 2022 to $2.2 billion in 2023 primarily due to:

 • A decrease in weather-related sales volumes.
 • An increase in interest expense due to higher interest rates and debt balances.
 • Unfavorable mark-to-market economic hedge activity driven by a decrease in commodity prices.
 • A loss on the sale of the competitive contracted renewables portfolio in 2023.
 • Unfavorable regulatory decisions in Texas, West Virginia and at FERC.
 • A gain on the sale of mineral rights in 2022.

 • Favorable rate proceedings in AEP's various jurisdictions.
 • Investment in transmission assets, which resulted in higher revenues and income.
 • A loss related to the expected sale of the Kentucky Operations in 2022. The expected sale was terminated in April 2023.
 • An impairment of AEP's equity investment in Flat Ridge 2 in 2022.

 See "Results of Operations" section for additional information by operating segment.

 Customer Demand

 AEP's weather-normalized retail sales volumes for the year ended December 31, 2023 increased by 2.5% from the year ended December 31, 2022. Weather-normalized residential sales decreased 0.9% for the year ended December 31, 2023 compared to the year ended December 31, 2022. Weather-normalized commercial sales increased by 7.8% in 2023 compared to 2022. The increase in commercial sales was primarily due to new data center loads and economic development. AEP's 2023 industrial sales volumes increased 1.6% compared to 2022. The growth in industrial sales was spread across many industries.

 In 2024, AEP anticipates weather-normalized retail sales volumes will increase by 1.5%. Weather-normalized residential sales volumes are projected to decrease by 0.4% in 2024, while weather-normalized commercial sales volumes are projected to increase by 4.5%. The projected increase in commercial sales volumes is driven by new loads associated with data centers and cryptocurrency operations. Finally, AEP projects the industrial sales volumes to increase by 0.6% in 2024.

 (a)Percentage change for the year ended December 31, 2023 as compared to the year ended December 31, 2022.
 (b)Forecasted percentage change for the year ended December 31, 2024 compared to the year ended December 31, 2023.

 Supply Chain Disruption and Inflation

 The Registrants have experienced certain supply chain disruptions driven by several factors including international tensions and 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 the pace of inflation will continue to moderate. 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.

 2023 SIGNIFICANT DEVELOPMENTS AND TRANSACTIONS

 Disposition of the Competitive Contracted Renewables Portfolio

 In February 2022, AEP management announced the initiation of a process to sell all or a portion of AEP Renewables' competitive contracted renewables portfolio (the portfolio) within the Generation & Marketing segment. 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 portfolio and AEP signed an agreement with a nonaffiliated party.

 In August 2023, AEP completed the sale of the entire portfolio to the nonaffiliated party and received cash proceeds of approximately $1.2 billion, net of taxes and transaction costs. AEP recorded a pretax loss of approximately $93 million ($73 million after-tax) for the year ended December 31, 2023 related to the sale. See the "Disposition of the Competitive Contracted Renewables Portfolio" section of Note 7 for additional information.

 Planned Sale of AEP Energy and AEP Onsite Partners

 AEP management has continued a strategic evaluation of AEP's portfolio of businesses with a focus on core regulated utility operations, risk mitigation and simplification. As a result of these efforts, the following decisions have been made with respect to AEP Energy and AEP Onsite Partners.

 AEP Energy

 In October 2022, AEP initiated a strategic evaluation for its ownership in AEP Energy, a wholly-owned retail energy supplier that supplies electricity and/or natural gas on a price risk managed basis 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 929,000 customer accounts as of December 31, 2023. In April 2023, AEP management completed the strategic evaluation of AEP Energy and initiated a sales process. The timing of the completion of the sales process is dependent upon a number of factors. AEP is currently targeting the sales process to be completed in the first half of 2024. Depending on the outcome of the sales process, it could reduce future net income and impact financial condition.

 AEP Onsite Partners

 In April 2023, AEP also made a decision to include AEP Onsite Partners in a sales process. 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. As of December 31, 2023, AEP OnSite Partners owned projects located in 22 states, including approximately 195 MWs of installed solar capacity and two solar projects under construction totaling approximately 4 MWs. As of December 31, 2023, the net book value of these assets was $352 million. The timing of the completion of the sales process is dependent upon a number of factors. AEP is currently targeting the sales process to be completed in the first half of 2024. If AEP is unable to recover the net book value of these assets as part of the sale process, it could reduce future net income and impact financial condition.

 AEP Onsite Partners also owns a 50% interest in NMRD totaling $101 million accounted for as an equity method investment. The NMRD portfolio consists of 9 operating solar projects totaling 185 MWs and 6 projects totaling 440 MWs in development. Separate from the remainder of AEP Onsite Partners, AEP and the joint owner agreed to a joint sales process for their respective interests in NMRD.

 In December 2023, AEP and the joint owner signed an agreement to sell NMRD to a nonaffiliated third party for $230 million. AEP expects to receive cash proceeds of $104 million, net of taxes, transaction fees and other customary closing adjustments. AEP recorded a pretax loss of $19 million in the fourth quarter of 2023 as a result of entering into the sales agreement. The transaction has received all required regulatory approvals and is expected to close in the first quarter of 2024. See the "NMRD" section of Note 7 for additional information.

 Planned Sale and Strategic Evaluation of Certain Transmission Joint Ventures

 In April 2023, AEP also initiated a strategic evaluation for its ownership in certain transmission joint ventures in the AEP Transmission Holdco segment including Pioneer Transmission, LLC, Prairie Wind Transmission, LLC and Transource Energy. In July 2023, AEP made a decision to initiate a sales process for its investment in Pioneer Transmission, LLC and Prairie Wind Transmission, LLC. In February 2024, AEP management determined it would retain its ownership of its investment in Pioneer Transmission, LLC and Prairie Wind Transmission, LLC. As of December 31, 2023, AEP's investment in Pioneer Transmission, LLC and Prairie Wind Transmission, LLC was $46 million and $19 million, respectively.

 As of December 31, 2023, the net book value of Transource Energy was $289 million inclusive of $39 million related to noncontrolling interest on AEP's balance sheet. AEP management recently completed its strategic review and determined it would retain this business due to its fit within the goals and objectives of AEP and its overall leadership role in the U.S. electric transmission space.

 Termination of Planned 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. The SPA was subsequently amended in September 2022 to reduce the purchase price to approximately $2.646 billion. An impairment of $363 million was recorded for the year ended December 31, 2022. The sale required approval from the KPSC and from the FERC under Section 203 of the Federal Power Act. The SPA contained certain termination rights if the closing of the sale did not occur by April 26, 2023.

 In May 2022, the KPSC approved the sale of KPCo to Liberty subject to certain 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 an adverse effect on rates. In February 2023, a new filing for approval under Section 203 of the Federal Power Act was submitted. In March 2023, the KPSC and other intervenors made filings recommending the FERC reject AEP and Liberty's new Section 203 application seeking approval of the sale.

 As a result of delays in the anticipated timing of the closing of the transaction and other factors, AEP recorded a $363 million pretax loss on the expected sale of the Kentucky Operations for the year ended December 31, 2022. In April 2023, AEP, AEPTCo and Liberty entered into a Mutual Termination Agreement (Termination Agreement) terminating the SPA. The parties entered into the Termination Agreement as all of the conditions precedent to closing the sale could not be satisfied prior to April 26, 2023. Upon termination of the sale and reverting to a held and used model, in the first quarter of 2023, AEP reversed $28 million of expected transaction costs included in the $363 million pretax loss and was required to present its investment in the Kentucky Operations at the lower of fair value or historical carrying value which resulted in a $335 million reduction recorded in Property, Plant and Equipment. The reduced investment in KPCo's assets is being amortized over the 30-year average useful life of the KPCo assets.

 Renewable Generation

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

 Significant Renewable Generation Placed Into Service

 In 2023, AEP acquired and placed into service 159 MWs of owned renewable generation facilities totaling approximately $155 million.

 Significant Approved Renewable Generation Filings

 AEP has received regulatory approvals from various state regulatory commissions to acquire approximately 2,811 MWs of owned renewable generation facilities, totaling approximately $6.6 billion, in addition to 377 MWs of renewable purchase power agreements, as included in the following table:

 Generation Type
 Expected Commercial Operation
 Owned/PPA
 Generating Capacity

 (in MWs)

 APCo
 Solar
 Year End 2024 through Year End 2026
 PPA

 APCo
 Wind
 Year End 2025 through Year End 2026
 Owned

 I&M
 Solar
 Year End 2025
 PPA

 I&M
 Solar
 Year End 2026
 Owned

 PSO
 Solar
 Year End 2025
 Owned

 PSO
 Wind
 Year End 2025 through Year End 2026
 Owned

 SWEPCo (a)
 Solar
 Year End 2025 through Year End 2027
 Owned/PPA

 SWEPCo (a)
 Wind
 Year End 2024 through Year End 2025
 Owned

 Total Approved Renewable Projects
 3,188

 (a)Includes approvals by the APSC and LPSC for 999 MWs of owned projects. Additionally, the LPSC approved the flex-up option, allowing SWEPCo to provide additional service to Louisiana customers and recover the portion of the projects denied by the PUCT.

 Significant Renewable Generation Requests for Proposal (RFP)

 As part of AEP's transition to diversify the company's regulated generation resources and build its renewable generation portfolio, RFPs have been issued in order to satisfy the need for additional capacity resources. The table below includes RFPs recently issued for both owned and purchased power generation. Unless otherwise noted, RFPs issued are all-source solicitations for accredited capacity with consideration made for renewable projects. Projects selected will be subject to regulatory approval.

 Issuance Date
 Projected
In-Service Dates
 Generating Capacity

 (in MWs)

 I&M (a)
 March 2023
 Year End 2027
 2,505

 APCo (b)
 April 2023
 Year End 2026

 KPCo (c)
 September 2023
 Year End 2026/2027
 1,300

 PSO
 November 2023
 Year End 2027/2028
 1,500

 Year End 2028
 2,100

 Total Significant RFPs
 8,205

 (a)RFP is seeking nameplate capacity proposals from various types of generation. Actual MWs by technology type depends on the portfolio of projects selected and individual contribution toward meeting I&M's overall capacity need.
 (b)RFP is seeking nameplate capacity proposals for up to 600 MWs of owned wind or solar and 200 MWs of wind or solar PPAs. Also includes an option for battery storage.
 (c)RFP is seeking proposals for PPAs only.

 Regulatory Matters - Utility Rates and Rate Proceedings

 The Registrants are involved in rate cases and other proceedings 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. Depending on the outcomes, these rate cases and 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.

 The following tables show the Registrants' completed and pending base rate case proceedings in 2023. See Note 4 - Rate Matters for additional information.

 Completed Base Rate Case Proceedings

 Annual

 Base Revenue
 Approved
 New Rates

 Jurisdiction
 Increase
 ROE
 Effective

 $
 21.0
 (a)
 9.5%
 February 2023

 PSO
 131.0
 9.3%

 APCo
 127.0
 9.5%

 KPCo
 Kentucky
 60.0
 9.75%

 (a)See "2020 Louisiana Base Rate Case" section of Note 4 for additional information.

 Pending Base Rate Case Proceedings

 Annual

 Filing
 Base Revenue
 Requested

 Jurisdiction
 Date
 Increase Request
 ROE

 I&M
 August 2023
 $
 116.0
 10.5%

 I&M
 Michigan
 September 2023
 34.0
 10.5%

 PSO
 218.0
 10.8%

 Other Significant Regulatory Matters

 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 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. In November 2021, SWEPCo and the PUCT submitted Petitions for Review with the Texas Supreme Court. 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. In June 2023, the Texas Supreme Court denied SWEPCo's request for rehearing and the case was remanded to the PUCT for future proceedings. In October 2023, SWEPCo filed testimony with the PUCT in the remanded proceeding recommending no refund or disallowance.

 On December 14, 2023, the PUCT approved a preliminary order stating the PUCT will not address SWEPCo's request that would allow the PUCT to find cause to allow SWEPCo to exceed the Texas jurisdictional capital cost cap in the current remand proceeding. As a result of the PUCT's approval of the preliminary order, SWEPCo believes it is probable the PUCT will disallow capitalized AFUDC in excess of the Texas jurisdictional capital cost cap and recorded a pretax, non-cash disallowance of $86 million in the fourth quarter of 2023. Such determination may reduce SWEPCo's future revenues by approximately $15 million on an annual basis. On December 21, 2023, SWEPCo filed a motion with the PUCT for reconsideration of the preliminary order. In January 2024, the PUCT denied the motion for reconsideration of the preliminary order.

 The PUCT's December 2023 approval of the preliminary order determined that it will address, in the ongoing PUCT remand proceeding, any potential revenue refunds to customers that may be required by future PUCT orders. In January 2024, the PUCT established a procedural schedule for the remand proceeding. Supplemental testimony from SWEPCo is due in March 2024, intervenor and staff testimony is due in April 2024 and a hearing is scheduled for May 2024. Although SWEPCo does not currently believe any refunds are probable of occurring, SWEPCo estimates it could be required to make customer refunds, including interest, ranging from $0 to $200 million related to revenues collected from February 2013 through December 2023.

 FERC 2021 PJM and SPP Transmission Formula Rate Challenge

 The Registrants transitioned to stand-alone treatment of NOLCs in its PJM and SPP transmission formula rates beginning with the 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 annual revenue requirements for years 2023, 2022 and 2021 by $60 million, $69 million and $78 million, respectively.

 In March 2023 and May 2023, certain joint customers submitted a complaint and a formal challenge at the FERC related to the 2022 Annual Update of the 2021 Transmission Formula Rates of the AEP transmission owning subsidiaries within PJM and SPP, respectively. These challenges primarily relate to stand-alone treatment of NOLCs in the transmission formula rates of the AEP transmission owning subsidiaries. AEPSC, on behalf of the AEP transmission owning subsidiaries within PJM and SPP, filed answers to the joint formal challenge and complaint with the FERC in the second quarter of 2023.

 In January 2024, the FERC issued two orders, granting the joint customers' challenges related to stand-alone treatment of NOLCs in the 2021 Transmission Formula Rates of the AEP transmission owning subsidiaries within PJM and SPP. The FERC directed the AEP transmission owning subsidiaries within PJM and SPP to provide refunds with interest on all amounts collected for the 2021 rate year, and for such refunds to be reflected in the annual update for the next rate year. In February 2024, AEPSC on behalf of the AEP transmission owning subsidiaries within PJM and SPP filed requests with the FERC that it grant rehearing and reverse findings in its January 2024 orders or establish hearing procedures to address outstanding factual issues.

 As a result of the January 2024 FERC orders, the Registrants' 2022 and 2023 income statements cumulatively reflect a provision for refund for the probable refund of all NOLC revenues included in transmission formula rates for years 2023, 2022 and 2021. The probable refunds to affiliated and nonaffiliated customers are reflected as Deferred Credits and Other Noncurrent Liabilities on the balance sheets. Refunds probable to be received by affiliated companies, resulting in a reduction to affiliated transmission expense, were deferred as an increase to Regulatory Liabilities or a reduction to Regulatory Assets on

 the balance sheets where management expects that refunds would be returned to retail customers through authorized retail jurisdiction rider mechanisms. The FERC directed cash refunds with interest related to the 2021 rate year to occur through the annual update for the next rate year, which will be invoiced by PJM and SPP primarily in 2025. The Registrants have not yet been directed to make cash refunds related to the 2022 or 2023 rate years.

 The FERC's January 2024 orders reduced AEP and AEPTCo's 2023 pretax net income by approximately $76 million and $74 million, respectively. The impact of the FERC's orders on the pretax net income of AEP's remaining Registrant Subsidiaries was not material.

 Kentucky Securitization Case

 In conjunction with KPCo's June 2023 base rate case filing, KPCo requested to finance, through the issuance of securitization bonds, approximately $471 million of regulatory assets recorded as of June 2023 including: (a) $289 million of plant retirement costs, (b) $79 million of deferred storm costs related to 2020, 2021, 2022 and 2023 major storms, (c) $52 million of deferred purchased power expenses and (d) $51 million of under-recovered purchased power rider costs.

 In January 2024, the KPSC issued a financing order approving KPCo's securitization request and concluding that costs requested for recovery were prudently incurred. The KPSC's financing order includes certain additional requirements related to securitization bond structuring, marketing, placement, and issuance that were not reflected in KPCo's proposal. As a result, in January 2024, KPCo filed a request for rehearing with the KPSC to clarify certain aspects of these additional requirements. In February 2024, the KPSC denied KPCo's rehearing requests. In accordance with Kentucky statutory requirements and the financing order, the issuance of the securitized bonds is subject to final review by the KPSC after bond pricing. KPCo expects to proceed with the securitized bond issuance process and to complete the securitization process in the second half of 2024, subject to market conditions. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

 Deferred Fuel Costs

 Increases in fuel and purchased power costs in excess of amounts included in fuel-related revenues has led to an increase in the under collection of fuel costs from customers in several jurisdictions in recent years. To help ease the burden on customers, certain state commissions have issued orders allowing recovery of these costs over periods exceeding the traditional jurisdictional FAC terms. The table below illustrates the current and noncurrent under-recovered fuel regulatory asset balances, by jurisdiction, impacted by these orders. If any of these deferred fuel costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See Note 4 - Rate Matters and Note 5 - Effects of Regulation for additional information.

 Expected/Authorized
 As of
 As of
 Increase/

 Jurisdiction
 Recovery Period
 (Decrease)

 APCo
 2025
 $
 254.4
 (a)
 $
 407.9
 $
 (153.5)

 APCo
 2034
 162.2
 (b)
 288.5
 (126.3)

 PSO
 2024
 118.3
 (c)
 431.5
 (313.2)

 Texas
 2035
 80.9
 (d)
 80.7
 0.2

 WPCo
 2034
 181.3
 (b)
 231.1
 (49.8)

 Total
 $
 797.1
 $
 1,439.7
 $
 (642.6)

 (a)In September 2023, APCo submitted a filing with the Virginia SCC requesting to extend the previously authorized recovery period through October 2024 to October 2025. Interim Virginia FAC rates were implemented in November 2023. An order from the Virginia SCC is expected in the first quarter of 2024.
 (b)In January 2024, the WVPSC issued a final order which resulted in a December 2023 write-off of $222 million ($127 million attributable to APCo and $95 million attributable to WPCo) of under-recovered ENEC regulatory assets as of February 28, 2023. The order approved the recovery of $321 million ($174 million attributable to APCo and $147 million attributable to WPCo) of under-recovered ENEC regulatory assets as of February 28, 2023 over 10 years beginning September 1, 2024. The recovery of the remaining under-recovered ENEC regulatory assets as of December 31, 2023 will be addressed in APCo and WPCo's 2024 ENEC filing. In February 2024, the Companies filed briefs with the West Virginia Supreme Court to initiate an appeal of this order.
 (c)In September 2022, the Director of the Public Utility Division of the OCC approved a Fuel Cost Adjustment rate designed to collect a $402 million deferred fuel balance through December 2024. PSO's fuel and purchased power expenses are subject to an annual prudency review by the OCC.
 (d)In September 2023, the PUCT issued an order approving an unopposed settlement agreement that provides recovery of $81 million of Oxbow mine and Sabine related fuel costs through 2035.

 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 SWEPCo's portion 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. In April 2023, intervenors filed testimony recommending the APSC deny the Certificate of Public Convenience and Necessity on the basis that the Turk Plant is not the least cost alternative. In June 2023, SWEPCo filed rebuttal testimony with the APSC. In July 2023, additional intervenor testimony was filed with the APSC by the Attorney General of Arkansas and the APSC staff with recommendations consistent with the previously filed April 2023 intervenor testimony. A hearing was held in October 2023 and an order is expected in the first quarter of 2024. As of December 31, 2023, 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.

 Litigation Related to Ohio House Bill 6 (HB 6)

 In July 2019, 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 had previously plead guilty and, in March 2023, a federal jury convicted Larry Householder and another individual of participating in the racketeering conspiracy. 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.

 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.

 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. 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 in April 2022. In June 2022, the Ohio state court entered an order continuing the stays of that case until the final resolution of the consolidated derivative actions pending in Ohio federal district court. In September 2022, the New York state court granted the forum-based motion to dismiss with prejudice and the plaintiff subsequently filed a notice of appeal with the New York appellate court. In January 2023, the New York plaintiff filed a motion to intervene in the pending Ohio federal court action and withdrew his appeal in New York. 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 and subsequently filed a brief in opposition to the New York plaintiffs' motion to intervene in the consolidated action in Ohio. In March 2023, the federal district court issued an order granting the motion to dismiss with prejudice and denying the New York plaintiffs' motion to intervene. In April 2023, one of the plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Sixth Circuit of the Ohio federal district court order dismissing the consolidated action and denying the intervention. 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 was directed to the Board of Directors of AEP (AEP Board) and contained factual allegations involving HB 6 that were generally consistent with those in the derivative litigation filed in state and federal court. The shareholder that sent the letter has since withdrawn the litigation demand, which is now terminated and of no further effect. In April 2023, AEP received a litigation demand from counsel representing the purported AEP shareholder who filed the dismissed derivative action in New York state court and unsuccessfully tried to intervene in the consolidated derivative actions in Ohio federal court. The litigation demand letter is directed to the AEP Board 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 certain current and former directors and officers, and that AEP commence a civil action for breaches of fiduciary duty and related claims against any individuals who allegedly

 harmed AEP. The AEP Board considered the 2023 litigation demand letter and formed a committee of the Board (the "Demand Review Committee") to investigate, review, monitor and analyze the allegations in the letter and make a recommendation to the AEP Board regarding a reasonable and appropriate response to the same. The AEP Board will act in response to the letter as appropriate. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

 In May 2021, AEP received a subpoena from the SEC's Division of Enforcement seeking various documents, including documents relating to the 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 and inquiries regarding Empowering Ohio's Economy, Inc., which is a 501(c)(4) social welfare organization, and related disclosures. The SEC staff has advanced its discussions with certain parties involved in the investigation, including AEP, concerning the staff's intentions regarding potential claims under the securities laws. AEP and the SEC are engaged in discussions about a possible resolution of the SEC's investigation and potential claims under the securities laws. Any resolution or filed claims, the outcome of which cannot be predicted, may subject AEP to civil penalties and other remedial measures. Discussions are continuing and management is unable to determine a range of potential losses that is reasonably possible of occurring, but management does not believe the results of this investigation or a possible resolution thereof will have a material impact on results of operations, cash flows or financial condition.

 Claims for Indemnification Made by Owners of the Gavin Power Station

 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 assertions related to the CCR Rule (see "CCR Rule" section below for additional information), including an assertion 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 these claims, including any future enforcement or litigation resulting from any determinations of noncompliance by the Federal EPA with various aspects of the CCR Rule consistent with the Gavin Denial. The owners of the Gavin Power Station have also sought indemnification for landowner claims for property damage allegedly caused by modifications to the FAR. 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. Gavin Power LLC has also filed a complaint with the United States District Court for the Southern District of Ohio, alleging various violations of the Administrative Procedure Act and asserting that the Federal EPA, through its prior inaction, has waived and is estopped from raising certain objections raised in the Gavin Denial. Management cannot predict the outcome of that litigation.

 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's operations. Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance. As of December 31, 2023, AEP owned generating capacity of approximately 23,300 MWs, of which approximately 10,700 MWs were coal-fired. Management continues to evaluate the economic feasibility of environmental investments on AEP's fossil

 generation fleet and to refine the cost estimates of complying with these rules and evaluate other impacts of the environmental proposals on fossil generation.

 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.

 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 February 2024, the Federal EPA finalized a new more stringent annual primary PM2.5 standard.

 Areas with air quality that does not meet the new standard will be designated by the Federal EPA as "nonattainment," which will trigger an obligation for states to revise their SIPs to obtain further emission reductions to ensure that the new standard will be met. Areas around some of AEP's generating facilities may be deemed nonattainment, which may subject those facilities to additional pollution controls or operational constraints. The nonattainment designations by the Federal EPA and the subsequent SIP revisions by the affected states will take some time to complete, therefore, it is too soon to predict how SIP requirements may impact AEP's operations. Management will continue to monitor the issue.

 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. Petitions for review of the final rule revisions have been filed in the U.S. Court of Appeals for the District of Columbia Circuit.

 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 that the Federal EPA began implementing in 2015, which was designed to address interstate transport of emissions that contribute significantly to non-attainment and interfere with maintenance of the 1997 ozone NAAQS and the 1997 and 2006 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. The Federal EPA has revised, or updated, the CSAPR trading programs several times since they were established.

 In January 2021, the Federal EPA finalized a revised CSAPR, which substantially reduced the ozone season NOX budgets for several states, including states where AEP operates, beginning in ozone season 2021. Management believes it can meet the

 requirements of the rule in the near term, and is evaluating its compliance options for later years, when the budgets are further reduced.

 In addition, in February 2023, the Federal EPA Administrator finalized the disapproval of interstate transport SIPs submitted by 19 states addressing the 2015 Ozone NAAQS. Disapproval of the SIPs provides the Federal EPA with authority to impose a FIP for those states, replacing the SIPs that were disapproved. In August 2023, a FIP went into effect that further revises the ozone season NOX budgets under the existing CSAPR program in states to which the FIP applies. The disapproval of SIPs and implementation of FIPs continues to be subject to extensive litigation. Management will continue to monitor the outcome of this litigation and any potential impact to operations.

 Climate Change, CO2 Regulation and Energy Policy

 In May 2023, the Federal EPA proposed greenhouse gas standards and guidelines for new and existing fossil-fuel fired sources. The proposal relies heavily on carbon capture and sequestration and natural gas co-firing as means to reduce CO2 emissions from coal fired plants and hydrogen co-firing and carbon capture and sequestration to reduce CO2 emissions from gas turbines. Management is evaluating the proposed rule.

 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.

 AEP routinely submits IRPs in various regulatory jurisdictions to address future generation and capacity needs. These IRPs take into account economics, customer demand, grid reliability and resilience, regulations and RTO capacity requirements. The objective of the IRPs is to recommend future generation and capacity resources that provide the most cost-efficient and reliable power to customers. Based on the output of the company's IRPs, in October 2022, AEP announced new intermediate and long-term CO2 emission reduction goals. 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 for Scope 1 and Scope 2 emissions. AEP's total Scope 1 GHG estimated emissions in 2023 were approximately 42.8 million metric tons, a 68% reduction according to the GHG Protocol, which excludes emission reductions that result from assets that have been sold, or a 72% 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 over the long-term. AEP also expects Scope 1 GHG emissions to vary annually depending on the mix of its own generation and purchased power used to serve customers. AEP's ability to achieve these goals is dependent upon a number of factors including the ability to execute on renewable resource plans, evolving RTO requirements, constructive regulatory support, the advancement of carbon-free generation technologies, customer demand for carbon-free energy, potential tariffs, carbon policy and regulation, operational performance of renewable generation and supply chain costs and constraints, all while continuing to provide the most cost-efficient and reliable power to 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.

 MATS Rule

 In April 2023, the Federal EPA issued a proposed rule that would revise the MATS for power plants. The proposed rule includes a more stringent standard for emissions of filterable PM for coal-fired electric generating units, as well as a new mercury standard for lignite-fired electric generating units. The proposed rule also requires the installation and operation of continuous emissions monitors for PM. Management is evaluating the impacts of the rule as proposed and will continue to monitor the rulemaking.

 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 requires 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 various plants.

 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 Gavin Denial, discussed above). The Federal EPA's allegations of noncompliance rely on new interpretations of the CCR Rule requirements. The January Actions of the Federal EPA and the Gavin Denial 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 or how it may impact the Federal EPA's interpretation of the CCR Rule.

 In July 2022, the Federal EPA proposed conditional approval of the pending extension request for APCo's 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. In addition, AEP ceased receiving ash in the other ponds subject to the extension requests, completed construction of new, CCR Rule compliant facilities and withdrew all of the remaining applications for additional time to develop alternative disposal capacity.

 Under the second option for obtaining an extension of the April 11, 2021 deadline to cease operation of unlined impoundments, a generating facility may 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 had 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. In March 2023, the Pirkey Plant was retired. To date, the Federal EPA has not taken any action on the pending extension request for the Welsh Plant.

 Closure and post-closure estimated 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.

 In May 2023, the Federal EPA proposed revisions to the CCR Rule to expand the scope of the rule to include inactive impoundments at inactive facilities ("legacy CCR surface impoundments") as well as to establish requirements for currently exempt solid waste management units that involve the direct placement of CCR on the land ("CCR management units"). The Federal EPA is proposing that owners and operators of legacy surface impoundments comply with all of the existing CCR Rule requirements applicable to inactive CCR surface impoundments at active facilities, except for the location restrictions and liner design criteria. The proposal establishes accelerated compliance deadlines for legacy surface impoundments to meet regulatory requirements, including a requirement to initiate closure within one year after the effective date of the final rule. The Federal EPA's proposal would require evaluations to be completed at both active facilities and inactive facilities with one or more legacy surface impoundments. If finalized, AEP may incur material, additional costs complying with the Federal EPA's proposal, including costs to upgrade or close and replace legacy CCR surface impoundments and to conduct any required remedial actions including removal of coal ash. In addition, AEP would need to seek cost recovery through regulated rates, including proposing new regulatory mechanisms for cost recovery, for which regulatory approval cannot be assured. The proposed rule, if finalized, could have a material adverse impact on net income, cash flows and financial condition if AEP cannot ultimately recover any additional costs of compliance.

 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, established additional options for reusing and discharging small volumes of bottom ash transport water, provided an exception for retiring units and extended 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 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. In March 2023, the Federal EPA proposed further revisions to the ELG rule which, if finalized, would establish a zero discharge standard for FGD wastewater and bottom ash transport water, and more stringent discharge limits for combustion residual leachate. Management is evaluating the impacts of the proposed rule to operations. Management cannot predict whether the Federal EPA will actually finalize further revisions, but will continue to monitor this issue and will participate in further rulemaking activities as they arise.

 The definition of "waters of the United States" has been subject to rule making and litigation which has led to inconsistent scope among the states. Management will continue to monitor developments in rule making and litigation for any potential impact to operations.

 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.

 The table below summarizes the net book value, as of December 31, 2023, of generating facilities retired or planned for early retirement in advance of the retirement date currently authorized for ratemaking purposes:

 Plant
 Net
Investment (a)
 Accelerated Depreciation Regulatory Asset
 Actual/Projected
Retirement
Date
 Current Authorized
 Annual Depreciation (b)

 PSO
 Northeastern Plant, Unit 3
 $
 104.5
 $
 164.2
 2026
 (c)
 $
 15.0

 Pirkey Plant
 —
 114.4
 (d)
 2023
 (e)
 —

 Welsh Plant, Units 1 and 3
 352.0
 125.6
 2028
 (f)
 (g)
 38.6

 (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)Represents Arkansas and Texas jurisdictional share.
 (e)As part of the 2021 Arkansas Base Rate Case, the APSC granted SWEPCo regulatory asset treatment. SWEPCo will request recovery including a weighted average cost of capital carrying charge through a future proceeding. The Texas share of the Pirkey Plant will be addressed in SWEPCo's next base rate case. See the "Coal-Fired Generation Plants" section of Note 5 for additional information.
 (f)In November 2020, management announced it will cease using coal at the Welsh Plant in 2028. Management is evaluating a potential conversion to natural gas after 2028 for both units.
 (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.

 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.

 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 are presented as Corporate and Other, which is not considered a reportable segment. See Note 9 - Business Segments for additional information on AEP's segments.

 The following discussion of AEP's results of operations by operating segment provides a comparison of Earnings Attributable to AEP Common Shareholders for the year ended December 31, 2023 as compared to the year ended December 31, 2022. For AEP's Vertically Integrated Utilities and Transmission and Distribution Utilities segment and subsidiary registrants within these segments, the results include revenues from rate rider mechanisms designed to recover fuel, purchased power and other recoverable expenses such that the revenues and expenses associated with these items generally offset and do not affect Earnings Attributable to AEP Common Shareholders. For additional information regarding the financial results for the years ended December 31, 2023 and 2022 see the discussions of Results of Operations by Subsidiary Registrant.

 A detailed discussion of AEP's 2022 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 2022 Annual Report on Form 10-K filed with the SEC on February 23, 2023.

 The following tables present Earnings (Loss) Attributable to AEP Common Shareholders by segment:

 2023
 2022
 2021

 $
 1,090.4
 $
 1,292.0
 $
 1,113.6

 698.7
 595.7
 543.4

 702.9
 673.5
 677.8

 (26.3)
 283.6
 217.5

 (257.6)
 (537.6)
 (64.2)

 Earnings Attributable to AEP Common Shareholders
 $
 $
 $

 Revenues
 $
 11,449.5
 $
 5,713.3
 $
 1,728.5
 $
 1,632.2

 Fuel, Purchased Electricity and Other
 4,150.3
 1,214.8
 —
 1,487.8

 3,211.1
 1,947.8
 141.6
 132.9

 85.6
 —
 —
 —

 —
 —
 —
 92.7

 1,876.4
 784.7
 402.6
 42.7

 512.5
 668.0
 290.1
 6.6

 Operating Income (Loss)
 1,613.6
 1,098.0
 894.2
 (130.5)

 25.6
 2.8
 8.9
 44.8

 46.3
 45.5
 83.1
 —

 126.3
 56.2
 6.2
 26.2

 (764.5)
 (363.6)
 (202.6)
 (76.0)

 Income (Loss) Before Income Tax Expense (Benefit) and
 Equity Earnings (Loss)

 1,047.3
 838.9
 789.8
 (135.5)

 (45.2)
 140.2
 166.0
 (122.9)

 Equity Earnings (Loss) of Unconsolidated Subsidiary
 1.4
 —
 82.9
 (16.5)

 1,093.9
 698.7
 706.7
 (29.1)

 Net Income (Loss) Attributable to Noncontrolling Interests
 3.5
 —
 3.8
 (2.8)

 Earnings (Loss) Attributable to AEP Common Shareholders
 $
 1,090.4
 $
 698.7
 $
 702.9
 $
 (26.3)

 Revenues
 $
 11,477.5
 $
 5,512.0
 $
 1,677.0
 $
 2,466.9

 Fuel, Purchased Electricity and Other
 4,007.9
 1,287.3
 —
 1,984.3

 3,287.2
 1,864.2
 165.7
 118.7

 24.9
 —
 —
 —

 (37.0)
 —
 —
 —

 Gain on Sale of Mineral Rights
 —
 —
 —
 (116.3)

 2,007.2
 746.7
 355.0
 93.0

 504.9
 659.9
 277.6
 11.1

 Operating Income
 1,682.4
 953.9
 878.7
 376.1

 30.2
 4.9
 2.0
 38.9

 29.5
 33.6
 70.6
 —

 109.8
 47.6
 5.0
 20.6

 (650.9)
 (328.0)
 (169.3)
 (51.8)

 Income Before Income Tax Expense (Benefit) and Equity Earnings (Loss)
 1,201.0
 712.0
 787.0
 383.8

 (93.8)
 116.9
 193.6
 (83.1)

 Equity Earnings (Loss) of Unconsolidated Subsidiary
 1.4
 0.6
 83.4
 (192.4)

 1,296.2
 595.7
 676.8
 274.5

 Net Income (Loss) Attributable to Noncontrolling Interests
 4.2
 —
 3.3
 (9.1)

 Earnings Attributable to AEP Common Shareholders
 $
 1,292.0
 $
 595.7
 $
 673.5
 $
 283.6

 Revenues
 $
 9,998.5
 $
 4,492.9
 $
 1,526.2
 $
 2,163.7

 Fuel, Purchased Electricity and Other
 3,144.2
 729.9
 —
 1,806.8

 3,043.1
 1,573.9
 132.3
 97.5

 11.6
 —
 —
 —

 1,747.6
 690.3
 306.0
 80.9

 497.3
 640.9
 245.0
 10.5

 Operating Income
 1,554.7
 857.9
 842.9
 168.0

 13.5
 2.6
 0.7
 4.2

 40.2
 32.3
 67.2
 —

 67.9
 29.0
 2.1
 15.4

 (574.2)
 (300.9)
 (146.3)
 (15.6)

 Income Before Income Tax Expense (Benefit) and Equity Earnings (Loss)
 1,102.1
 620.9
 766.6
 172.0

 (11.2)
 77.5
 159.6
 (48.8)

 Equity Earnings (Loss) of Unconsolidated Subsidiary
 3.4
 —
 75.0
 (10.6)

 1,116.7
 543.4
 682.0
 210.2

 Net Income (Loss) Attributable to Noncontrolling Interests
 3.1
 —
 4.2
 (7.3)

 Earnings Attributable to AEP Common Shareholders
 $
 1,113.6
 $
 543.4
 $
 677.8
 $
 217.5

 VERTICALLY INTEGRATED UTILITIES

 Summary of KWh Energy Sales for Vertically Integrated Utilities

 2023
 2022
 2021

 30,290
 32,835
 32,149

 23,481
 23,770
 22,833

 34,148
 34,532
 33,181

 2,229
 2,316
 2,214

 90,148
 93,453
 90,377

 Wholesale (a)
 13,401
 16,099
 19,025

 103,549
 109,552
 109,402

 (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

 2023
 2022
 2021

 Eastern Region

 1,992
 2,709
 2,438

 2,719
 2,717
 2,720

 1,003
 1,187
 1,268

 1,119
 1,106
 1,110

 Western Region

 1,068
 1,523
 1,241

 1,464
 1,455
 1,461

 2,590
 2,695
 2,370

 2,277
 2,247
 2,246

 Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities

 $
 1,292.0

 (12.8)

 56.7

 (51.3)

 (20.6)

 (28.0)

 (142.4)

 76.1

 (60.7)

 (37.0)

 130.8

 (7.6)

 (4.6)

 16.8

 Non-Service Cost Components of Net Periodic Pension Cost
 16.5

 (113.6)

 (125.7)

 (48.6)

 Net Income Attributable to Noncontrolling Interests
 0.7

 $
 1,090.4

The major components of the decrease in Revenues were as follows:

 • Retail Revenues decreased $13 million primarily due to the following:
 • A $182 million decrease in weather-related usage primarily in the residential class driven by a 28% decrease in heating degree days and a 7% decrease in cooling degree days.
 • An $80 million decrease in fuel revenues primarily due to decreases at I&M, SWEPCo and KPCo, partially offset by increases at APCo and PSO.
 • A $54 million decrease in rider revenues at I&M.
 • A $71 million increase in base rate revenues at PSO.
 • A $70 million increase at SWEPCo primarily due to base rate revenue increases in Louisiana and Arkansas and rider increases in all retail jurisdictions.
 • A $68 million increase at APCo and WPCo due to rider revenues in Virginia and West Virginia.
 • A $41 million increase in weather-normalized retail margins primarily in the commercial and residential classes.
 • A $34 million increase at APCo due to lower customer refunds related to Tax Reform.
 • A $20 million increase at APCo due to a base rate increase in Virginia implemented in October 2022 following the Virginia Supreme Court remand.
 • Off-system Sales increased $57 million primarily due to an increase at I&M primarily due to economic hedging activity and Rockport Plant, Unit 2 merchant sales. This increase was partially offset by decreases at APCo and SWEPCo.
 • Transmission Revenues decreased $51 million primarily due to the following:
 • A $33 million decrease in transmission formula rate true-up activity.
 • A $13 million decrease due to a FERC order which denied stand-alone treatment of NOLCs in transmission formula rates.
 • Other Revenues decreased $21 million primarily due to a decrease in pole attachment revenue at APCo and WPCo.

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

 • Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $142 million primarily due to increases at APCo, PSO and WPCo, partially offset by decreases at I&M, SWEPCo and KPCo. The increase at APCo and WPCo includes the disallowance of under-recovered ENEC regulatory assets in West Virginia.
 • Other Operation and Maintenance expenses decreased $76 million primarily due to the following:
 • A $76 million decrease in transmission services.
 • A $67 million decrease in employee-related expenses.
 • A $40 million decrease due to a charitable contribution to the AEP Foundation in 2022.
 • A $34 million increase in Demand Side Management expenses at I&M.
 • A $33 million increase in accounts receivable factoring expenses as a result of increased interest rates.
 • A $21 million increase at APCo due to the amortization of the regulatory asset established in accordance with the August 2022 Virginia Supreme Court opinion related to under-earnings during the 2017-2019 Triennial Review.
 • A $20 million increase due to a FERC order which denied stand-alone treatment of NOLCs in transmission formula rates.
 • Asset Impairments and Other Related Charges increased $61 million primarily due to the following:
 • An $86 million increase at SWEPCo due to the probable disallowance of Turk Plant capitalized AFUDC in excess of the Texas jurisdictional capital cost cap as a result of the PUCT's December 2023 preliminary order in the 2012 Texas Base Rate Case.
 • A $25 million decrease at APCo due to a prior year 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 decreased $37 million at APCo due to a prior year 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 decreased $131 million primarily due to a $170 million decrease at AEGCo and I&M due to the expiration of the Rockport Plant, Unit 2 lease in December 2022, partially offset by an increase in depreciation expense due to the acquisition of Rockport Plant, Unit 2 at the end of the lease.
 • Taxes Other Than Income Taxes increased $8 million primarily due to the following:
 • A $15 million increase at PSO and SWEPCo primarily due to increased property taxes driven by the investment in NCWF.
 • A $5 million increase at APCo primarily due to an increase in Virginia state minimum taxes.
 • A $13 million decrease at I&M primarily due to the repeal of the Indiana Utility Receipts Tax in July 2022.
 • Allowance for Equity Funds Used During Construction increased $17 million primarily due to higher AFUDC equity rates and CWIP at PSO and SWEPCo.
 • Non-Service Cost Components of Net Periodic Benefit Cost decreased $17 million primarily due to the change in loss amortization for the plans and an increase in the expected return on asset assumption, partially offset by higher interest costs due to increased discount rates.
 • Interest Expense increased $114 million primarily due to higher long-term debt balances and interest rates.
 • Income Tax Benefit decreased $49 million primarily due to the following:
 • A $29 million increase in state taxes.
 • A $27 million decrease due to a decrease in amortization of Excess ADIT.
 • A $19 million decrease related to tax return to provision adjustments.
 • A $27 million increase due to PTCs.

 TRANSMISSION AND DISTRIBUTION UTILITIES

 Summary of KWh Energy Sales for Transmission and Distribution Utilities

 2023
 2022
 2021

 26,099
 27,479
 26,830

 30,419
 27,448
 25,514

 26,571
 25,435
 23,919

 Total Retail (a)
 83,834
 81,115
 77,000

 Wholesale (b)
 1,922
 2,198
 2,018

 85,756
 83,313
 79,018

 (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. In general, degree day changes in the eastern region have a larger effect on revenues than changes in the western region due to the relative size of the two regions and the number of customers within each region.

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

 2023
 2022
 2021

 Eastern Region

 2,380
 3,116
 2,815

 3,185
 3,185
 3,190

 1,121
 1,222

 1,026
 1,011
 1,016

 Western Region

 Actual – Cooling (d)
 3,208
 2,984
 2,653

 2,737
 2,714
 2,712

 (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.

 Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities

 $
 595.7

 186.2

 (86.4)

 56.6

 44.9

 201.3

 Purchased Electricity for Resale

 149.4

 (77.0)

 (83.6)

 (38.0)

 (8.1)

 (2.1)

 11.9

 8.6

 (35.6)

 (74.5)

 (23.3)

 (0.6)

 $
 698.6

 • Retail Revenues increased $186 million primarily due to the following:
 • A $225 million increase in Ohio rider revenues.
 • A $25 million increase in interim rates driven by increased distribution investment in Texas.
 • A $59 million decrease in weather-related usage primarily due to a 28% decrease in heating degree days.
 • A $13 million decrease in weather-normalized revenues in all retail classes in Texas.
 • A $7 million decrease in revenue from rate riders in Texas.
 • Off-system Sales decreased $86 million primarily due to decreased sales at OVEC driven by lower market prices and volume.
 • Transmission Revenues increased $57 million primarily due to the following:
 • A $28 million increase in load in Texas.
 • A $27 million increase in interim rates primarily due to transmission investments in Texas.
 • Other Revenues increased $45 million primarily due to refundable sales of renewable energy credits in Ohio.

 • Purchased Electricity for Resale expenses decreased $149 million primarily due to the following:
 • A $129 million increase in deferrals of OVEC costs.
 • A $69 million decrease in auction volumes primarily due to decreased load, partially offset by higher prices in Ohio.
 • A $36 million increase in recoverable expenses due to creation, consumption and liquidation of renewable energy credits and recoverable renewable energy purchase agreement expenses.
 • Purchased Electricity from AEP Affiliates expenses increased $77 million due to increased affiliated auction volumes driven by AEP Energy auctions won in June 2023 in Ohio.

 • Other Operation and Maintenance expenses increased $84 million primarily due to the following:
 • A $96 million increase due to an energy assistance program for qualified Ohio customers.
 • A $34 million increase in transmission expenses due to an increase in recoverable PJM expenses driven by additional transmission investment.
 • A $23 million increase in recoverable distribution expenses primarily related to vegetation management in Ohio.
 • A $13 million increase in distribution-related expenses in Texas.
 • A $32 million decrease due to legislation passed in Texas in May 2023 allowing employee financially based incentives to be recovered in Texas.
 • A $22 million decrease in employee-related expenses.
 • An $18 million decrease due to a charitable contribution to the AEP Foundation in 2022.
 • An $11 million decrease in recoverable transmission expenses in Texas.
 • Depreciation and Amortization expenses increased $38 million primarily due to a higher depreciable base, partially offset by a decrease in recoverable rider depreciable expenses in Ohio.
 • Taxes Other Than Income Taxes increased $8 million primarily due to an increase in Ohio in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
 • Allowance for Equity Funds Used During Construction increased $12 million due to a higher AFUDC base.
 • Non-Service Cost Components of Net Period Benefit Cost decreased $9 million primarily due to the change in loss amortization for the plans and an increase in the expected return on asset assumption, partially offset by higher interest costs due to increased discount rates.
 • Interest Expense increased $36 million primarily due to a $58 million increase related to higher debt balances and interest rates, partially offset by a $19 million decrease related to higher AFUDC base and rates.
 • Income Tax Expense increased $23 million primarily due to an increase in pretax book income.

 AEP TRANSMISSION HOLDCO

 Summary of Investment in Transmission Assets for AEP Transmission Holdco

 2023
 2022

 Plant in Service
 $
 14,630.2
 $
 13,217.3

 1,733.8
 1,667.5

 1,332.8
 1,062.5

 Total Transmission Property, Net
 $
 15,031.2
 $
 13,822.3

 Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco

 $
 673.5

 Changes in Transmission Revenues:

 51.5

 Total Change in Transmission Revenues
 51.5

 24.1

 (47.6)

 (12.5)

 Interest and Investment Income
 6.9

 12.5

 Non-Service Cost Components of Net Periodic Pension Cost
 1.2

 (33.3)

 (48.7)

 27.6

 Equity Earnings of Unconsolidated Subsidiary
 (0.5)

 Net Income Attributable to Noncontrolling Interests
 (0.5)

 $
 702.9

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

 • Transmission Revenues increased $52 million primarily due to a $172 million increase driven by continued investment in transmission assets, partially offset by a $120 million decrease due to a FERC order which denied stand-alone treatment of NOLCs in transmission formula rates.

 • Other Operation and Maintenance expenses decreased $24 million primarily due to the following:
 • A $13 million decrease in employee-related expenses.
 • An $11 million decrease due to a charitable contribution to the AEP Foundation in 2022.
 • Depreciation and Amortization expenses increased $48 million primarily due to a higher depreciable base.
 • Taxes Other Than Income Taxes increased $13 million primarily due to higher property taxes as a result of increased transmission investments, partially offset by lower property tax rates.
 • Interest and Investment Income increased $7 million primarily due to higher advances to affiliates and interest rates.
 • Allowance for Equity Funds Used During Construction increased $13 million primarily due to higher CWIP balances throughout 2023.
 • Interest Expense increased $33 million primarily due to higher long-term debt balances and interest rates.
 • Income Tax Expense decreased $28 million primarily due to a decrease in state taxes primarily driven by tax adjustments and deferred state tax remeasurements.

 GENERATION & MARKETING

 Earnings Attributable to AEP Common Shareholders from Generation & Marketing

 $
 283.6

 Merchant Generation
 (162.9)

 Renewable Generation
 (55.3)

 Retail, Trading and Marketing
 (616.5)

 (834.7)

 496.5

 (14.2)

 (92.7)

 Gain on Sale of Mineral Rights
 (116.3)

 50.3

 4.5

 Interest and Investment Income
 5.9

 5.6

 (24.2)

 315.4

 39.8

 175.9

 Net Loss Attributable to Noncontrolling Interests
 (6.3)

 $
 (26.3)

 The major components of the decrease in Revenues were as follows:

 • Merchant Generation decreased $163 million primarily due to lower market prices in 2023.
 • Renewable Generation decreased $55 million primarily due to the sale of competitive contracted renewables portfolio in August 2023.
 • Retail, Trading and Marketing decreased $617 million primarily due to a $314 million unrealized loss on economic hedge activity in 2023 and an $87 million unrealized gain on economic hedge activity in 2022 driven by changes in commodity prices.

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

 • Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $497 million primarily due to a reduction in energy costs in 2023.
 • Other Operation and Maintenance expenses increased $14 million primarily due to a decrease in land sales and a prior year sale of renewable development projects.
 • Loss on the Sale of the Competitive Contracted Renewables Portfolio increased $93 million due to the pretax loss on the sale in 2023.
 • Gain on Sale of Mineral Rights decreased $116 million due to the prior year sale of mineral rights.
 • Depreciation and Amortization expenses decreased $50 million primarily due to the ceasing of depreciation on the competitive contracted renewables portfolio as a result of held for sale classification and subsequent sale in 2023.
 • Interest and Investment Income increased $6 million primarily due to higher interest rates on advances to affiliates.
 • Non-Service Cost Components of Net Periodic Benefit Cost decreased $6 million primarily due to the elimination of loss amortization for the Qualified plan and an increase in the Qualified expected return on asset assumption from 5.25% for 2022 to 7.50% for 2023.
 • Interest Expense increased $24 million primarily due to higher interest rates in 2023.

 • Income Tax Benefit increased $40 million primarily due to:
 • A $74 million increase due to a decrease in pretax book income.
 • A $19 million decrease due to the remeasurement of deferred state taxes.
 • A $9 million decrease due to a decrease in tax credits.
 • Equity Earnings of Unconsolidated Subsidiaries increased $176 million primarily due to:
 • A $182 million impairment of AEP's investment in Flat Ridge 2 Wind LLC in 2022.
 • A $19 million impairment of AEP's investment in New Mexico Renewable Development joint venture in 2023.
 • Net Loss Attributable to Noncontrolling Interests increased $6 million primarily due to the sale of the competitive contracted renewables portfolio in August 2023.

 CORPORATE AND OTHER

 Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $538 million in 2022 to a loss of $258 million in 2023 primarily due to:

 • A $363 million pretax loss in 2022 related to the anticipated sale of the Kentucky Operations which was terminated in 2023.
 • An $81 million increase in interest income, primarily due to higher interest rates on advances to affiliates.
 • A $56 million decrease in corporate expenses, primarily due to adjustments driven by the termination of the sale of the Kentucky Operations.
 • A $49 million increase in factoring revenues from the affiliates.
 • A $30 million increase at EIS, primarily due to higher returns on investments.
 • A $24 million increase due to asset impairments and other related charges in 2022.
 These increases in earnings were partially offset by:
 • A $286 million increase in interest expense due to higher interest rates and an increase in debt balances.
 • A $46 million increase in Income Tax Expense primarily due to the following:
 • A $66 million increase due to the loss on the anticipated sale of the Kentucky Operations in 2022.
 • A $15 million decrease due to favorable permanent tax adjustments in the current year and unfavorable permanent tax adjustments in 2022.

 AEP CONSOLIDATED INCOME TAXES

 • Income Tax Expense increased $49 million primarily due to the following:
 • A $58 million increase in state tax expense primarily driven by consolidated tax adjustments and deferred state tax remeasurements.
 • A $22 million decrease in amortization of Excess ADIT.
 • A $22 million decrease in PTCs.
 These increases in Income Tax Expense were partially offset by:
 • A $36 million increase in amortization of deferred ITCs resulting from the sale of the competitive contracted renewables portfolio.
 • A $16 million decrease due to favorable permanent tax adjustments in the current year and unfavorable permanent tax adjustments in 2022.

 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 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 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, 2023, 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.

 AEP subsidiaries have 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, 2023, AEP expected to make contributions to the pension plans totaling $7 million in 2024. Estimated contributions of $110 million in 2025 and $6 million in 2026 may vary significantly based on market returns, changes in actuarial assumptions and other factors. Based upon the projected benefit obligation and fair value of assets available to pay pension benefits, the pension plans were 99% funded as of December 31, 2023. 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.

 LIQUIDITY AND CAPITAL RESOURCES

 Debt and Equity Capitalization

 2023
 2022

 Long-term Debt, including amounts due within one year
 $
 40,143.2
 58.8
 %
 $
 36,801.0
 56.6
 %

 Short-term Debt
 2,830.2
 4.2
 4,112.2
 6.3

 Total Debt
 42,973.4
 63.0
 40,913.2
 62.9

 AEP Common Equity
 25,246.7
 37.0
 23,893.4
 36.7

 Noncontrolling Interests
 39.2
 —
 229.0
 0.4

 Total Debt and Equity Capitalization
 $
 68,259.3
 100.0
 %
 $
 65,035.6
 100.0
 %

 AEP's ratio of debt-to-total capital increased slightly from 62.9% to 63.0% as of December 31, 2022 and December 31, 2023, respectively, primarily due to an increase in Long-term Debt to support distribution, transmission and renewable investment growth in addition to working capital needs. This was partially offset by the issuance of common equity in connection with the settlement of the forward equity purchase contracts related to the 2020 Equity Units and the utilization of cash proceeds received from the sale of the competitive contracted renewables portfolio to reduce Short-term Debt.

 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, 2023, 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 there is an increase in interest rates, it could reduce future net income and cash flows and impact financial condition.

 Market volatility 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. AEP is also monitoring the current bank environment and any impacts thereof. AEP was not materially impacted by these conditions during the year ended December 31, 2023.

 In August 2023, AEP completed the sale of the entire Competitive Contracted Renewables Portfolio to a nonaffiliated party and received cash proceeds of approximately $1.2 billion, net of taxes and transaction costs. The proceeds were used to pay down debt balances and support AEP's overall capital expenditure plans. See the "Dispositions" section of Note 7 for additional information.

 AEP continues to address the cash flow implications of increased fuel and purchased power costs, see "Deferred Fuel Costs" section of Executive Overview for additional information. In January 2024, AEP made a capital contribution to APCo and WPCo, totaling $100 million and $75 million, respectively. These contributions were made to help address the impact of the January 2024 WVPSC order that resulted in the December write-off of $222 million ($127 million attributable to APCo and $95 million attributable to WPCo) of under-recovered ENEC regulatory assets. See "ENEC (Expanded Net Energy Cost) Filings" of Note 4 for additional information.

 Net Available Liquidity

 AEP manages liquidity by maintaining adequate external financing commitments. As of December 31, 2023, available liquidity was approximately $3.4 billion as illustrated in the table below:

 Maturity

 Commercial Paper Backup:

 Revolving Credit Facility
 $
 4,000.0
 March 2027

 Revolving Credit Facility
 1,000.0
 March 2025

 330.1

 Total Liquidity Sources
 5,330.1

 Less: AEP Commercial Paper Outstanding

 Net Available Liquidity
 $
 3,392.2

 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 2023 was $3.2 billion. The weighted-average interest rate for AEP's commercial paper during 2023 was 5.38%.

 Other Credit Facilities

 An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. As of December 31, 2023, AEP issued letters of credit on behalf of subsidiaries under six uncommitted facilities with a total capacity of $450 million. The Registrants' maximum future payments for letters of credit issued under the uncommitted facilities, as of December 31, 2023, was $257 million with maturities ranging from January 2024 to November 2024.

 Financing Plan

 As of December 31, 2023, AEP had $2.5 billion of long-term debt due within one year. This included $510 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 $205 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 $900 million from bank conduits to purchase receivables. The agreement was amended in August 2023 to increase the commitment from $750 million and expires in September 2025. As of December 31, 2023, the affiliated utility subsidiaries were in compliance with all requirements under the agreement.

 Debt Covenants and Borrowing Limitations

 AEP's credit agreements contain certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5%. The method for calculating outstanding debt and capitalization is contractually-defined in AEP's credit agreements. Debt as defined in the revolving credit agreement excludes securitization bonds and debt of AEP Credit. As of December 31, 2023, this contractually-defined percentage was 59.9%. Non-performance under these covenants could result in an event of default under these credit agreements. In addition, the acceleration of AEP's payment obligations, or the obligations of certain of AEP's major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements. This condition also applies in a majority of AEP's non-exchange-traded commodity contracts and would similarly allow lenders and counterparties to declare the outstanding amounts payable. However, a default under AEP's non-exchange-traded commodity contracts would not cause an event of default under its credit agreements.

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

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

 ATM Program

 AEP participates in an ATM offering program that allows AEP to issue, from time to time, up to an aggregate of $1.7 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, 2023. As of December 31, 2023, approximately $1.7 billion 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 settled after three years in August 2023. The proceeds were used to support AEP's overall capital expenditure plans.

 In June 2023, AEP successfully remarketed the Junior Subordinated Notes on behalf of holders of the corporate units. AEP did not receive any proceeds from the remarketing which were used to purchase a portfolio of treasury securities that matured on August 14, 2023. On August 15, 2023, the proceeds from the treasury portfolio were used to settle the forward equity purchase contract with AEP. The interest rate on the Junior Subordinated Notes was reset to 5.699% with the maturity remaining in 2025. In August 2023, AEP issued 10,048,668 shares of AEP common stock and received proceeds totaling $850 million under the settlement of the forward equity purchase contracts. AEP common stock held in treasury was used to settle the forward equity purchase contracts. The proceeds were used to pay down debt balances and support AEP's overall capital expenditure plans. See Note 14 - Financing Activities for additional information.

 Dividend Policy and Restrictions

 The Board of Directors declared a quarterly dividend of $0.88 per share in January 2024. 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.

 2023
 2022
 2021

 Cash, Cash Equivalents and Restricted Cash at Beginning of Period
 $
 556.5
 $
 451.4
 $
 438.3

 5,012.2
 5,288.0
 3,839.9

 (6,266.7)
 (7,751.8)
 (6,433.9)

 1,077.0
 2,568.9
 2,607.1

 Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash
 (177.5)
 105.1
 13.1

 Cash, Cash Equivalents and Restricted Cash at End of Period
 $
 379.0
 $
 556.5
 $
 451.4

 Operating Activities

 2023
 2022
 2021

 $
 $
 $

 Non-Cash Adjustments to Net Income (a)
 3,394.5
 3,461.6
 3,025.9

 8.8
 15.5
 112.3

 Property Taxes
 (41.1)
 (41.2)
 (68.0)

 Deferred Fuel Over/Under Recovery, Net
 892.8
 (319.2)
 (1,647.9)

 Change in Other Noncurrent Assets (b)
 (780.9)
 (234.4)
 (365.5)

 29.0
 337.8
 206.4

 Change in Certain Components of Working Capital
 (703.5)
 (237.7)
 88.6

 $
 5,012.2
 $
 5,288.0
 $
 3,839.9

 (a)Includes Depreciation and Amortization, Rockport Plant, Unit 2 Lease Amortization, Deferred Income Taxes, Loss on the Expected Sale of the Kentucky Operations, Loss on the Sale of the Competitive Contracted Renewables Portfolio, 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.
 (b)Includes Change in Regulatory Assets.

 Net Cash Flows from Operating Activities decreased by $276 million primarily due to the following:
 • A $547 million decrease in cash from Change in Other Noncurrent Assets primarily due to incremental other operation and maintenance storm restoration expenses incurred in several jurisdictions in addition to timing differences in collections from customers under rate rider mechanisms. See Note 4 - Rate Matters and Note 5 - Effects of Regulation for additional information.
 • A $466 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, the return of margin deposits from PJM in 2022 and the timing of accounts payable. These decreases were partially offset by the timing of accounts receivable.
 • A $309 million decrease in cash from Changes in Other Noncurrent Liabilities. The decrease is primarily due to changes in provisions for refunds and regulatory liabilities driven by timing differences in refunds to customers under rate rider mechanisms in addition to an increase in ARO settlements in 2023. See Note 5 - Effects of Regulation and Note 18 - Property, Plant and Equipment for additional information.
 • A $160 million decrease in cash from Net Income, after non-cash adjustments. See Results of Operations for further detail.
 These decreases in cash were offset by:
 • A $1.2 billion increase in cash primarily due to the timing of fuel and purchased power revenues and expenses. See the "Deferred Fuel Costs" section of Executive Overview for additional information.

 Investing Activities

 2023
 2022
 2021

 $
 (7,378.3)
 $
 (6,671.7)
 $
 (5,659.6)

 Acquisitions of Nuclear Fuel
 (128.2)
 (100.7)
 (104.5)

 Acquisition of Renewable Energy Facilities
 (155.2)
 (1,207.3)
 (767.2)

 Proceeds on Sale of Assets
 1,341.4
 218.0
 118.9

 Other
 53.6
 9.9
 (21.5)

 $
 (6,266.7)
 $
 (7,751.8)
 $
 (6,433.9)

 Net Cash Flows Used for Investing Activities decreased by $1.5 billion primarily due to the following:
 • A $1.1 billion decrease due to the 2022 acquisition of Traverse, partially offset by the 2023 acquisition of the Rock Falls Wind Facility. See "Acquisitions" section of Note 7 for additional information.
 • A $1.1 billion increase in Proceeds from Sale of Assets, primarily due to the sale of the competitive contracted renewables portfolio in 2023, partially offset by the sale of certain mineral rights in 2022. See "Dispositions" section of Note 7 for additional information.
 These decreases in cash used were partially offset by:
 • A $707 million increase in Construction Expenditures, primarily due to increases in Vertically Integrated Utilities of $374 million and Transmission and Distribution Utilities of $290 million.

 Financing Activities

 2023
 2022
 2021

 Issuance of Common Stock
 $
 999.6
 $
 826.5
 $
 600.5

 Issuance/Retirement of Debt, Net
 1,984.7
 3,802.5
 3,631.7

 (1,760.4)
 (1,645.2)
 (1,519.5)

 (68.3)
 (309.5)
 (64.0)

 Other
 (78.6)
 (105.4)
 (41.6)

 $
 1,077.0
 $
 2,568.9
 $
 2,607.1

 Net Cash Flows from Financing Activities decreased by $1.5 billion primarily due to the following:
 • A $2.8 billion decrease due to changes in short-term debt. See Note 14 - Financing Activities for additional information.
 • A $115 million decrease due to an increase in dividends paid on common stock.
 These decreases in cash were partially offset by:
 • An $813 million increase in issuances of long-term debt. See Note 14 - Financing Activities for additional information.
 • A $241 million increase due to a decrease in Principal Payments for Finance Lease Obligations primarily driven by Rockport Plant, Unit 2 final lease payments in 2022.
 • A $173 million increase in issuances of common stock primarily due to the settlement of the 2020 equity units. See "Equity Units" section of Note 14 for additional information.
 • A $149 million increase due to decreased retirements of long-term debt. See Note 14 - Financing Activities for additional information.

 The following financing activities occurred during 2023:

 AEP Common Stock:

 • During 2023, AEP issued 2.3 million shares of common stock under the incentive compensation, employee saving and dividend reinvestment plans. Additionally in 2023, AEP reissued 10 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 $1 billion related to these issuances.

 Debt:

 • During 2023, AEP issued approximately $5.5 billion of long-term debt, including $5.1 billion of senior unsecured notes at interest rates ranging from 5% to 7%, $296 million of other debt at various interest rates and $125 million of pollution control bonds at interest rates ranging from 4.25% to 4.7%. The proceeds from these issuances were primarily used to fund long-term debt maturities, construction programs and to help address working capital needs.
 • During 2023, AEP entered into interest rate derivatives with notional amounts totaling $1.9 billion that were designated as cash flow hedges. During 2023, settlements of AEP's interest rate derivatives resulted in net cash paid of $44 million for derivatives designated as fair value hedges and net cash received of $20 million designated as cash flow hedges. As of December 31, 2023, AEP had a total notional amount of $950 million of outstanding interest rate derivatives designated as fair value hedges and $350 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, 2023 through February 26, 2024, the date that the 10-K was issued.

 BUDGETED CAPITAL EXPENDITURES

 Management forecasts approximately $7.5 billion of capital expenditures in 2024. For the four year period, 2025 through 2028, management forecasts capital expenditures of $35 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, inflation and the ability to access capital. Management expects to fund these capital expenditures through cash flows from operations, proceeds from the strategic sale of assets 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 estimated capital expenditures by Business Segment are as follows:

 2024 Budgeted Capital Expenditures
 2025-2028

 Segment
 Environmental
 Renewables
 Other (a)
 Total
 Total

 $
 $
 $
 $
 $
 1,311
 $
 $
 3,580
 $
 20,407

 —
 —
 —
 1,272
 1,087
 2,567
 9,201

 —
 —
 —
 1,313
 —
 1,338
 4,902

 Generation & Marketing (b)
 —
 —
 —
 —
 —
 —
 —
 —

 —
 —
 —
 —
 —

 Total
 $
 $
 $
 $
 3,575
 $
 2,398
 $
 $
 7,544
 $
 35,011

 (a)Amount primarily consists of facilities, software and telecommunications.
 (b)No capital expenditures expected based on the anticipated sale of AEP Energy and AEP Onsite Partners in 2024.

 The 2024 estimated capital expenditures by Registrant Subsidiary are as follows:

 2024 Budgeted Capital Expenditures

 Environmental
 Renewables
 Other (a)
 Total

 $
 —
 $
 —
 $
 —
 $
 $
 $
 $
 1,533

 —
 —
 —
 1,313
 —
 1,338

 APCo

 I&M
 —

 OPCo
 —
 —
 —
 1,034

 PSO
 —

 1,176

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

 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

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

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

 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.

 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.

 Revenue Recognition – Unbilled Revenues

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

 Accrued unbilled revenues for the Vertically Integrated Utilities segment were $288 million and $354 million as of December 31, 2023 and 2022, respectively. The changes in unbilled electric utility revenues for AEP's Vertically Integrated Utilities segment were $(66) million, $108 million and $(42) million for the years ended December 31, 2023, 2022 and 2021, 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 $191 million and $221 million as of December 31, 2023 and 2022, respectively. The changes in unbilled electric utility revenues for AEP's Transmission and Distribution Utilities segment were $(30) million, $49 million and $1 million for the years ended December 31, 2023, 2022 and 2021, 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 $111 million and $109 million as of December 31, 2023 and 2022, respectively. The changes in unbilled electric utility revenues for AEP's Generation & Marketing segment were $2 million, $(1) million and $24 million for the years ended December 31, 2023, 2022 and 2021, respectively.

 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.

 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.

 Accounting for Derivative Instruments

 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.

 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.

 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.

 Long-Lived Assets

 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.

 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.

 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.

 Pension and OPEB

 AEPSC 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). AEPSC 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:

 Net Periodic Cost (Credit)
 2023
 2022
 2021

 $
 (24.3)
 $
 80.9
 $
 138.2

 OPEB
 (107.1)
 (144.8)
 (122.0)

 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 2024, 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 7.25% for the Qualified Plan and 6.75% for the OPEB plans.

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

 OPEB

 Assumed/Expected
 Assumed/Expected

 2024 Target
 Long-Term
 2024 Target
 Long-Term

 Asset Allocation
 Rate of Return
 Asset Allocation
 Rate of Return

 %
 8.77
 %
 %
 7.76
 %

 Fixed Income
 %
 6.02
 %
 %
 5.77
 %

 Other Investments
 %
 9.39
 %
 —
 —

 %
 3.79
 %
 %
 3.79
 %

 Total
 %
 %

 Management regularly reviews the actual asset allocation and periodically rebalances the investments to the targeted allocation. Management believes that 7.25% for the Qualified Plan and 6.75% for the OPEB plans are reasonable estimates of the long-term rate of return on the Plans' assets. The Pension Plans' assets had an actual gain of 9.50% and a loss of 16.88% for the years ended December 31, 2023 and 2022, respectively. The OPEB plans' assets had an actual gain of 15.48% and a loss of 19.53% for the years ended December 31, 2023 and 2022, 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.

 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, 2023, AEP had cumulative gains of approximately $526 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, 2023 under this method was 5.15% for the Qualified Plan, 5.2% for the Nonqualified Plans and 5.15% for the OPEB plans. Due to the effect of the unrecognized net actuarial losses and based on an expected rate of return, discount rates and various other assumptions, management estimates costs (credits) for the Pension Plans will approximate $(6) million, $39 million and $77 million in 2024, 2025 and 2026, respectively. Based on an expected rate of return discount rate and various other assumptions, management estimates OPEB plan credits will approximate $72 million, $60 million and $66 million in 2024, 2025 and 2026, 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 is $4.1 billion as of December 31, 2023 and $4.1 billion as of December 31, 2022. During 2023, the Qualified Plan paid $361 million and the Nonqualified Plans paid $8 million in benefits to plan participants. The value of AEP's OPEB plans' assets increased to $1.7 billion as of December 31, 2023 from $1.5 billion as of December 31, 2022 primarily due to positive investment returns. During 2023, the OPEB plans paid $138 million in benefits to plan participants.

 AEPSC 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.

 The critical assumptions used in developing the required estimates includes discount rate, compensation increase rate, cash balance crediting rate, health care cost trend rate and expected return on plan assets. Other assumptions, such as retirement, mortality and turnover, are evaluated periodically and updated to reflect actual experience.

 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:

 OPEB

 +0.5%
 -0.5%
 +0.5%
 -0.5%

 Effect on December 31, 2023 Benefit Obligations

 Discount Rate
 $
 (177.9)
 $
 193.7
 $
 (36.2)
 $
 39.3

 Compensation Increase Rate
 226.0
 (21.1)
 NA
 NA

 Cash Balance Crediting Rate
 60.2
 (56.9)
 NA
 NA

 Health Care Cost Trend Rate
 NA
 NA
 5.1
 (4.4)

 Effect on 2023 Periodic Cost

 Discount Rate
 $
 (9.3)
 $
 10.1
 $
 1.6
 $
 (1.7)

 Compensation Increase Rate
 4.9
 (4.5)
 NA
 NA

 Cash Balance Crediting Rate
 11.1
 (10.5)
 NA
 NA

 Health Care Cost Trend Rate
 NA
 NA
 0.5
 (0.3)

 (22.6)
 22.6
 (7.6)
 7.6

 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.

 In June 2023, the IRS issued temporary regulations related to the transfer of tax credits. In the third and fourth quarter of 2023, AEP, on behalf of PSO, SWEPCo and AEP Energy Supply, LLC, entered into transferability agreements with nonaffiliated parties to sell 2023 generated PTCs resulting in cash proceeds of approximately $102 million received in the fourth quarter of 2023 and an additional $76 million expected in early 2024. AEP expects to continue to explore the ability to efficiently monetize its tax credits through third party transferability agreements. See Note 12 - Income Taxes for additional information.

 ACCOUNTING STANDARDS

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

 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 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.

 The following table summarizes the reasons for changes in total MTM value as compared to December 31, 2022:

 MTM Risk Management Contract Net Assets (Liabilities)

 Vertically
Integrated
Utilities
and
Utilities
&
Marketing
 Total

 Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2022
 $
 134.7
 $
 (40.0)
 $
 360.5
 $
 455.2

 (Gain)/Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period
 (158.8)
 2.0
 (170.1)
 (326.9)

 Fair Value of New Contracts at Inception When Entered During the Period (a)
 —
 —
 3.9
 3.9

 Changes in Fair Value Due to Market Fluctuations During the Period (b)
 24.5
 —
 (101.9)
 (77.4)

 Changes in Fair Value Allocated to Regulated Jurisdictions (c)
 16.5
 (13.0)
 —
 3.5

 Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2023
 $
 16.9
 $
 (51.0)
 $
 92.4
 $
 58.3

 Commodity Cash Flow Hedge Contracts
 133.1

 Interest Rate Cash Flow Hedge Contracts
 (9.0)

 Fair Value Hedge Contracts
 (98.4)

 Collateral Deposits
 (16.7)

 Total MTM Derivative Contract Net Assets as of December 31, 2023
 $
 67.3

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

 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, 2023, credit exposure net of collateral to sub investment grade counterparties was approximately 7.2%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss).

 As of December 31, 2023, 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
Before
Credit
Collateral
 Credit
Collateral
 Net
 Number of
Counterparties
>10% of
Net Exposure
 Net Exposure
of
Counterparties
>10%

 (in millions, except number of counterparties)

 Investment Grade
 $
 395.4
 $
 48.7
 $
 346.7
 $
 126.9

 Split Rating
 25.1
 —
 25.1
 25.1

 Noninvestment Grade
 0.2
 0.2
 —
 —
 —

 No External Ratings:

 Internal Investment Grade
 34.9
 —
 34.9
 23.4

 Internal Noninvestment Grade
 80.4
 48.7
 31.7
 27.4

 Total as of December 31, 2023
 $
 536.0
 $
 97.6
 $
 438.4

 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, 2023, a near term typical change in commodity prices is not expected to materially impact net income, cash flows or financial condition.

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

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

 VaR Model
 Trading Portfolio

 Twelve Months Ended
 Twelve Months Ended

 End
 High
 Low
 End
 High
 Low

 $
 0.2
 $
 0.9
 $
 0.2
 $
 0.1
 $
 0.5
 $
 4.5
 $
 0.7
 $
 0.1

 VaR Model
 Non-Trading Portfolio

 Twelve Months Ended
 Twelve Months Ended

 End
 High
 Low
 End
 High
 Low

 $
 17.7
 $
 32.7
 $
 16.4
 $
 6.1
 $
 17.7
 $
 76.9
 $
 24.7
 $
 6.7

 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 several rate increases for a cumulative total of 4.25% increase. During 2023, the Federal Reserve approved another four rate increases for a cumulative total of 1.0% rate increase. 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, 2023, 2022 and 2021, a 100 basis point change in the benchmark rate on AEP's variable rate debt would impact pretax interest expense annually by $40 million, $47 million and $33 million, respectively.

 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, 2023 and 2022 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, 2023, 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, 2023, 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, 2023 and 2022 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 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, 2023, 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.

 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.

 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.

 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, 2023, there were $5.6 billion of deferred costs included in regulatory assets, $0.8 billion of which were pending final regulatory approval, and $8.2 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.

 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 assets and liabilities, which totaled $294 million and $155 million, as of December 31, 2023, 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.

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

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

 Management assessed the effectiveness of AEP's internal control over financial reporting as of December 31, 2023. 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, 2023.

 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, 2023. The Report of Independent Registered Public Accounting Firm appears on the previous page.

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

 2023
 2022
 2021

 $
 11,303.7
 $
 11,292.8
 $
 9,852.2

 5,677.2
 5,489.6
 4,464.1

 1,543.3
 2,448.9
 2,108.3

 458.1
 408.2
 367.4

 18,982.3
 19,639.5
 16,792.0

 6,578.3
 7,097.9
 5,466.3

 2,810.5
 2,878.1
 2,547.7

 1,276.3
 1,249.4
 1,121.8

 —
 363.3
 —

 85.6
 48.8
 11.6

 —
 —

 Gain on the Sale of Mineral Rights
 —
 ( 116.3)
 —

 92.7
 —
 —

 3,090.4
 3,202.8
 2,825.7

 1,492.3
 1,469.8
 1,407.6

 15,426.1
 16,156.8
 13,380.7

 3,556.2
 3,482.7
 3,411.3

 63.4
 11.6
 41.4

 174.9
 133.7
 139.7

 221.1
 188.5
 118.6

 ( 1,806.9)
 ( 1,396.1)
 ( 1,199.1)

 INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS (LOSS)
 2,208.7
 2,420.4
 2,511.9

 54.6
 5.4
 115.5

 Equity Earnings (Loss) of Unconsolidated Subsidiaries
 58.5
 ( 109.4)
 91.7

 Net Income (Loss) Attributable to Noncontrolling Interests
 4.5
 —

 EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 $
 $
 $

 WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING

 518,903,682
 511,841,946
 500,522,177

 TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS

 $
 4.26
 $
 4.51
 $
 4.97

 WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING
 520,206,258
 513,484,609
 501,784,032

 TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS

 $
 4.24
 $
 4.49
 $
 4.96

 2023
 2022
 2021

 $
 $
 $

 Cash Flow Hedges, Net of Tax of $( 33.8), $ 21.6 and $ 66.6 in 2023, 2022 and 2021, Respectively

 ( 127.0)
 81.4
 250.5

 Amortization of Pension and OPEB Deferred Costs, Net of Tax of $( 3.4), $( 2.8) and $( 2.2) in 2023, 2022 and 2021, Respectively

 Pension and OPEB Funded Status, Net of Tax of $( 4.3), $( 41.3) and $ 7.3 in 2023, 2022 and 2021, Respectively

 ( 155.4)
 27.5

 Reclassifications of KPCo Pension and OPEB Regulatory Assets, Net of Tax of $ 4.4, $( 4.4) and $ 0 in 2023, 2022 and 2021, Respectively

 16.7
 ( 16.7)
 —

 ( 139.2)
 ( 101.1)
 269.9

 2,073.4
 2,204.5
 2,758.0

 Total Comprehensive Income (Loss) Attributable To Noncontrolling Interests
 4.5
 —

 TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 $
 2,068.9
 $
 2,206.1
 $
 2,758.0

 CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

 AEP Common Shareholders

 Common Stock
Other

 Shares
 Noncontrolling
Interests
 Total

 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

 ( 1,507.7)
 (a)
 ( 1,519.5)

 Other Changes in Equity
 32.6
 16.3
 47.8

 Acquisition of Dry Lake Solar Project
 18.9
 18.9

 —

 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

 ( 1,628.7)
 (a)
 ( 16.5)
 ( 1,645.2)

 Other Changes in Equity
 56.3
 0.1
 56.4

 ( 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

 Issuance of Common Stock
 2.3
 14.8
 984.8
 999.6

 ( 1,752.3)
 (a)
 ( 1,760.4)

 Other Changes in Equity
 38.1
 0.2
 37.3

 Disposition of Competitive Contracted Renewables Portfolio
 ( 186.4)
 ( 186.4)

 4.5

 ( 139.2)
 ( 139.2)

 TOTAL EQUITY – DECEMBER 31, 2023
 527.4
 $
 3,427.9
 $
 9,073.9
 $
 12,800.4
 $
 ( 55.5)
 $
 39.2
 $
 25,285.9

 (a) Cash dividends declared per AEP common share were $ 3.37, $ 3.17 and $ 3.00 for the years ended December 31, 2023, 2022 and 2021, respectively.

 2023
 2022

 $
 330.1
 $
 509.4

 (December 31, 2023 and 2022 Amounts Include $ 48.9 and $ 47.1, Respectively, Related to Transition Funding, Restoration Funding and Appalachian Consumer Rate Relief Funding)

 48.9
 47.1

 Other Temporary Investments
 (December 31, 2023 and 2022 Amounts Include $ 205 and $ 182.9, Respectively, Related to EIS and Transource Energy)

 214.3
 187.6

 1,029.9
 1,145.1

 179.5
 322.9

 Pledged Accounts Receivable – AEP Credit
 1,249.4
 1,207.4

 48.7
 49.7

 ( 60.1)
 ( 57.1)

 2,447.4
 2,668.0

 Fuel
 853.7
 435.1

 1,025.8
 915.1

 217.5
 348.8

 Accrued Tax Benefits
 156.2
 99.4

 514.0
 1,310.0

 274.2
 255.0

 6,082.1
 6,775.5

 24,329.5
 25,834.2

 35,934.1
 33,266.9

 28,989.9
 27,138.8

 Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)
 6,484.9
 5,971.8

 5,508.0
 4,809.7

 101,246.4
 97,021.4

 24,553.0
 23,682.3

 76,693.4
 73,339.1

 5,092.4
 4,762.0

 336.3
 446.0

 Goodwill
 52.5
 52.5

 321.2
 284.1

 620.2
 645.5

 3,625.7
 3,757.4

 13,908.5
 13,288.7

 $
 96,684.0
 $
 93,403.3

 2023
 2022

 $
 2,032.5
 $
 2,670.8

 Short-term Debt:

 Securitized Debt for Receivables – AEP Credit
 888.0
 750.0

 Other Short-term Debt
 1,942.2
 3,362.2

 Total Short-term Debt
 2,830.2
 4,112.2

 Long-term Debt Due Within One Year
 (December 31, 2023 and 2022 Amounts Include $ 207.2 and $ 218.2, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)

 2,490.5
 2,486.4

 229.6
 145.2

 423.7
 408.8

 1,800.1
 1,714.6

 410.2
 336.5

 115.7
 113.6

 1,251.1
 1,278.2

 11,583.6
 13,266.3

 (December 31, 2023 and 2022 Amounts Include $ 556.3 and $ 755.3, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)

 37,652.7
 34,314.6

 241.8
 345.2

 9,415.7
 8,896.9

 8,182.4
 8,115.6

 2,972.5
 2,879.3

 Employee Benefits and Pension Obligations
 241.7
 257.3

 519.4
 552.5

 545.8
 607.3

 59,772.0
 55,968.7

 71,355.6
 69,235.0

 MEZZANINE EQUITY

 Contingently Redeemable Performance Share Awards
 42.5
 45.9

 TOTAL MEZZANINE EQUITY
 42.5
 45.9

 EQUITY

 Common Stock – Par Value – $ 6.50 Per Share:

 2023
 2022

 Shares Authorized
 600,000,000
 600,000,000

 Shares Issued
 527,369,157
 525,099,321

 ( 1,184,572 and 11,233,240 Shares were Held in Treasury as of December 31, 2023 and 2022, Respectively)

 3,427.9
 3,413.1

 9,073.9
 8,051.0

 12,800.4
 12,345.6

 ( 55.5)
 83.7

 TOTAL AEP COMMON SHAREHOLDERS' EQUITY
 25,246.7
 23,893.4

 Noncontrolling Interests
 39.2
 229.0

 TOTAL EQUITY
 25,285.9
 24,122.4

 TOTAL LIABILITIES, MEZZANINE EQUITY AND EQUITY
 $
 96,684.0
 $
 93,403.3

 2023
 2022
 2021

 $
 $
 $

 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:

 3,090.4
 3,202.8
 2,825.7

 Rockport Plant, Unit 2 Lease Amortization
 —
 —
 135.4

 185.1
 ( 137.2)
 107.6

 —
 363.3
 —

 92.7
 —
 —

 85.6
 48.8
 11.6

 Impairment of Equity Method Investment
 19.0
 188.0
 —

 ( 174.9)
 ( 133.7)
 ( 139.7)

 8.8
 15.5
 112.3

 Amortization of Nuclear Fuel
 96.6
 82.9
 85.3

 Property Taxes
 ( 41.1)
 ( 41.2)
 ( 68.0)

 892.8
 ( 319.2)
 ( 1,647.9)

 Gain on the Sale of Mineral Rights
 —
 ( 116.3)
 —

 —
 —

 Change in Regulatory Assets
 ( 315.8)
 ( 46.7)
 ( 238.9)

 ( 465.1)
 ( 187.7)
 ( 126.6)

 29.0
 337.8
 206.4

 236.5
 ( 681.7)
 ( 119.7)

 ( 504.0)
 ( 313.9)
 300.2

 ( 253.2)
 489.2
 200.6

 22.5
 105.4
 218.7

 Rockport Plant, Unit 2 Operating Lease Payments
 —
 —
 ( 147.7)

 ( 43.9)
 109.0
 ( 151.3)

 ( 161.4)
 54.3
 ( 212.2)

 5,012.2
 5,288.0
 3,839.9

 ( 7,378.3)
 ( 6,671.7)
 ( 5,659.6)

 Purchases of Investment Securities
 ( 2,863.6)
 ( 2,784.2)
 ( 1,955.1)

 Sales of Investment Securities
 2,795.1
 2,743.8
 1,901.4

 Acquisitions of Nuclear Fuel
 ( 128.2)
 ( 100.7)
 ( 104.5)

 Acquisitions of Renewable Energy Facilities
 ( 155.2)
 ( 1,207.3)
 ( 767.2)

 Proceeds from Sales of Assets
 1,341.4
 218.0
 118.9

 122.1
 50.3
 32.2

 ( 6,266.7)
 ( 7,751.8)
 ( 6,433.9)

 Issuance of Common Stock, Net
 999.6
 826.5
 600.5

 Issuance of Long-term Debt
 5,462.8
 4,649.7
 6,486.3

 Issuance of Short-term Debt with Original Maturities greater than 90 Days
 1,069.9
 833.9
 1,393.3

 Change in Short-term Debt with Original Maturities less than 90 Day, Net
 ( 1,223.1)
 1,650.4
 ( 487.3)

 Retirement of Long-term Debt
 ( 2,196.1)
 ( 2,345.4)
 ( 2,989.3)

 Redemption of Short-term Debt with Original Maturities greater than 90 Days
 ( 1,128.8)
 ( 986.1)
 ( 771.3)

 ( 68.3)
 ( 309.5)
 ( 64.0)

 ( 1,760.4)
 ( 1,645.2)
 ( 1,519.5)

 ( 78.6)
 ( 105.4)
 ( 41.6)

 1,077.0
 2,568.9
 2,607.1

 Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash
 ( 177.5)
 105.1
 13.1

 Cash, Cash Equivalents and Restricted Cash at Beginning of Period
 556.5
 451.4
 438.3

 Cash, Cash Equivalents and Restricted Cash at End of Period
 $
 379.0
 $
 556.5
 $
 451.4

 2023
 2022
 2021

 12,659
 13,049
 12,284

 13,549
 11,435
 10,477

 12,672
 11,347
 9,598

 39,516
 36,474
 32,984

 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.

 2023
 2022
 2021

 3,208
 2,984
 2,653

 2,737
 2,714
 2,712

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

 AEP Texas Inc. and Subsidiaries

 $
 307.9

 (3.6)

 55.2

 3.5

 55.1

 54.2

 (16.1)

 (3.3)

 (1.3)

 8.7

 2.5

 (24.0)

 20.7

 (13.3)

 $
 370.4

 • Retail Revenues decreased $4 million primarily due to the following:
 • A $13 million decrease in weather-normalized revenues in all retail classes.
 • A $10 million decrease in weather-related usage primarily due to a 56% decrease in heating degree days offset by an 8% increase in cooling degree days.
 • A $7 million decrease in revenue from rate riders.
 • A $25 million increase in interim rates driven by increased distribution investment.
 • Transmission Revenues increased $55 million due to the following:
 • A $28 million increase due to increased load.
 • A $27 million increase in interim rates driven by increased transmission investments.

 • Other Operation and Maintenance expenses decreased $54 million primarily due to the following:
 • A $32 million decrease due to legislation passed in Texas in May 2023 allowing employee financially based incentives to be recovered.
 • A $12 million decrease in employee-related expenses.
 • A $12 million decrease in recoverable transmission expenses.
 • A $10 million decrease due to a charitable contribution to the AEP Foundation in 2022.
 • A $13 million increase in distribution-related expenses.
 • Depreciation and Amortization expenses increased $16 million primarily due to a higher depreciable base partially offset by a decrease in recoverable advanced metering system depreciable expenses.
 • Allowance for Equity Funds Used During Construction increased $9 million due to a higher AFUDC base.
 • Interest Expense increased $24 million primarily due to an increase of $38 million driven by higher debt balances and interest rates, partially offset by a $12 million decrease due to an increased AFUDC base.
 • Income Tax Expense increased $13 million primarily due to an increase in pretax book income.

 AEP Texas Inc.

 We have audited the accompanying consolidated balance sheets of AEP Texas Inc. and its subsidiaries (the "Company") as of December 31, 2023 and 2022 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, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 in conformity with accounting principles generally accepted in the United States of America.

 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.

 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.

 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, 2023, there were $315 million of deferred costs included in regulatory assets, $64 million of which were pending final regulatory approval, and $1,261 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.

 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.

 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.

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

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

 Management assessed the effectiveness of AEP Texas' internal control over financial reporting as of December 31, 2023. 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, 2023.

 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.

 2023
 2022
 2021

 Electric Transmission and Distribution
 $
 1,892.0
 $
 1,839.7
 $
 1,586.4

 4.9
 3.5
 3.9

 5.0
 3.6
 3.5

 1,901.9
 1,846.8
 1,593.8

 541.6
 594.2
 489.5

 91.9
 93.5
 86.2

 468.5
 452.4
 387.0

 160.8
 157.5
 155.1

 1,262.8
 1,297.6
 1,117.8

 639.1
 549.2
 476.0

 2.3
 3.6
 0.8

 28.4
 19.7
 21.5

 19.2
 16.7
 11.1

 ( 232.7)
 ( 208.7)
 ( 176.5)

 INCOME BEFORE INCOME TAX EXPENSE
 456.3
 380.5
 332.9

 85.9
 72.6
 43.1

 $
 370.4
 $
 307.9
 $
 289.8

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

 2023
 2022
 2021

 $
 370.4
 $
 307.9
 $
 289.8

 Cash Flow Hedges, Net of Tax of $ 0.2, $ 0.3 and $ 0.3 in 2023, 2022 and 2021, Respectively

 0.8
 1.0
 1.0

 Amortization of Pension and OPEB Deferred Costs, Net of Tax of $( 0.2), $ 0 and $ 0 in 2023, 2022 and 2021, Respectively

 0.1
 0.2

 Pension and OPEB Funded Status, Net of Tax of $ 0, $( 0.9) and $ 0.3 in 2023, 2022 and 2021, Respectively

 1.2

 —
 2.4

 $
 370.4
 $
 305.8
 $
 292.2

 CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S EQUITY

Other
 Total

 $
 1,457.9
 $
 1,757.0
 $
 ( 8.9)
 $
 3,206.0

 96.0
 96.0

 289.8
 289.8

 2.4
 2.4

 1,553.9
 2,046.8
 ( 6.5)
 3,594.2

 4.3
 4.3

 307.9
 307.9

 1,558.2
 2,354.7
 3,904.3

 527.0
 527.0

 370.4
 370.4

 $
 2,079.6
 $
 2,725.1
 $
 $
 4,796.1

 2023
 2022

 $
 0.1
 $
 0.1

 (December 31, 2023 and 2022 Amounts Include $ 34 and $ 32.7, Respectively, Related to Transition Funding and Restoration Funding)

 34.0
 32.7

 7.1
 6.9

 176.5
 150.9

 23.8
 11.9

 82.3
 91.4

 0.8
 0.2

 278.5
 250.2

 190.4
 138.8

 10.0
 18.2

 520.1
 446.9

 6,812.6
 6,301.5

 5,798.8
 5,312.8

 1,145.9
 1,022.8

 904.6
 805.2

 14,661.9
 13,442.3

 1,887.9
 1,760.7

 12,774.0
 11,681.6

 315.3
 298.3

 (December 31, 2023 and 2022 Amounts Include $ 202.9 and $ 286.4, Respectively, Related to Transition Funding and Restoration Funding)

 202.9
 286.4

 178.4
 179.0

 696.6
 763.7

 $
 13,990.7
 $
 12,892.2

 2023

 2022

 $
 103.7
 $
 96.5

 192.3
 331.0

 27.7
 34.7

 (December 31, 2023 and 2022 Amounts Include $ 95.9 and $ 93.5, Respectively, Related to Transition Funding and Restoration Funding)

 96.0
 278.5

 99.1
 95.5

 (December 31, 2023 and 2022 Amounts Include $ 2 and $ 2.2, Respectively, Related to Transition Funding and Restoration Funding)

 49.2
 48.3

 28.7
 28.6

 152.7
 130.7

 749.4
 1,043.8

 (December 31, 2023 and 2022 Amounts Include $ 125.9 and $ 221, Respectively, Related to Transition Funding and Restoration Funding)

 5,793.8
 5,379.3

 1,227.8
 1,144.2

 1,261.4
 1,259.6

 50.9
 67.8

 111.3
 93.2

 8,445.2
 7,944.1

 9,194.6
 8,987.9

 2,079.6
 1,558.2

 2,725.1
 2,354.7

 4,796.1
 3,904.3

 $
 13,990.7
 $
 12,892.2

 2023
 2022
 2021

 $
 370.4
 $
 307.9
 $
 289.8

 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:

 468.5
 452.4
 387.0

 64.1
 42.2
 43.0

 ( 28.4)
 ( 19.7)
 ( 21.5)

 0.4
 —

 ( 96.5)
 ( 36.2)
 ( 78.2)

 24.3
 57.6
 26.4

 ( 28.3)
 ( 21.6)

 ( 51.6)
 ( 64.9)

 ( 24.1)
 25.0
 8.9

 11.8
 14.8
 7.0

 3.0
 2.2

 ( 53.9)
 ( 39.4)

 659.7
 731.9
 596.6

 ( 1,477.1)
 ( 1,305.0)
 ( 1,033.3)

 —
 0.2

 69.3
 35.1
 32.3

 ( 1,408.0)
 ( 1,269.9)
 ( 1,000.8)

 527.0
 4.3
 96.0

 —
 —

 505.4
 1,188.6
 444.2

 7.2
 69.6
 ( 40.2)

 ( 278.5)
 ( 716.0)
 ( 88.7)

 ( 6.8)
 ( 6.7)

 1.5
 0.6
 1.3

 749.6
 540.3
 405.9

 Net Increase in Cash, Cash Equivalents and Restricted Cash
 1.3
 2.3
 1.7

 Cash, Cash Equivalents and Restricted Cash at Beginning of Period
 32.8
 30.5
 28.8

 Cash, Cash Equivalents and Restricted Cash at End of Period
 $
 34.1
 $
 32.8
 $
 30.5

 $
 225.6
 $
 198.9
 $
 168.9

 Net Cash Paid for Income Taxes

 11.5
 11.0
 5.7

 4.8
 6.1
 4.4

 112.2
 235.4
 230.0

 Summary of Investment in Transmission Assets for AEPTCo

 As of December 31,

 2023
 2022

 Plant In Service
 $
 14,225.3
 $
 12,812.2

 CWIP
 1,563.7
 1,554.7

 Accumulated Depreciation
 1,291.3
 1,027.0

 Total Transmission Property, Net
 $
 14,497.7
 $
 13,339.9

 AEP Transmission Company, LLC and Subsidiaries

 $
 594.2

 Changes in Transmission Revenues:

 47.5

 Total Change in Transmission Revenues
 47.5

 24.1

 (47.6)

 (12.1)

 Interest Income - Affiliated
 5.4

 12.5

 (31.8)

 (49.5)

 22.0

 $
 614.2

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

 • Transmission Revenues increased $48 million primarily due to a $168 million increase driven by continued investment in transmission assets, partially offset by a $120 million decrease due to a FERC order which denied stand-alone treatment of NOLCs in transmission formula rates.

 • Other Operation and Maintenance expenses decreased $24 million primarily due to the following:
 • A $12 million decrease in employee-related expenses.
 • An $11 million decrease due to a charitable contribution to the AEP Foundation in 2022.
 • Depreciation and Amortization expenses increased $48 million primarily due to a higher depreciable base.
 • Taxes Other Than Income Taxes increased $12 million primarily due to higher property taxes as a result of increased transmission investments, partially offset by lower property tax rates.
 • Interest Income - Affiliated increased $5 million primarily due to higher advances to affiliates and interest rates.
 • Allowance for Equity Funds Used During Construction increased $13 million primarily due to higher CWIP balances throughout 2023.
 • Interest Expense increased $32 million primarily due to higher long-term debt balances and interest rates.
 • Income Tax Expense decreased $22 million primarily due to a decrease in state taxes primarily driven by tax adjustments and deferred state tax remeasurements.

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

 We have audited the accompanying consolidated balance sheets of AEP Transmission Company, LLC and its subsidiaries (the "Company") as of December 31, 2023 and 2022 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, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 in conformity with accounting principles generally accepted in the United States of America.

 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.

 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.

 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, 2023, there were $3 million of deferred costs included in regulatory assets and $784 million of regulatory liabilities awaiting potential refund or future rate reduction, $9 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.

 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.

 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.

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

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

 Management assessed the effectiveness of AEPTCo's internal control over financial reporting as of December 31, 2023. 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, 2023.

 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.

 2023
 2022
 2021

 $
 363.3
 $
 354.9
 $
 317.8

 1,463.4
 1,354.5
 1,171.5

 Provision for Refund – Affiliated
 ( 145.6)
 ( 70.7)
 ( 17.6)

 Provision for Refund – Nonaffiliated
 ( 14.2)

 1,672.0
 1,624.5
 1,469.3

 109.0
 136.3
 105.5

 20.4
 17.2
 18.4

 393.8
 346.2
 297.3

 283.2
 271.1
 238.8

 806.4
 770.8
 660.0

 865.6
 853.7
 809.3

 Interest Income - Affiliated
 7.0
 1.6
 0.5

 83.2
 70.7
 67.2

 ( 194.5)
 ( 162.7)
 ( 141.2)

 INCOME BEFORE INCOME TAX EXPENSE
 761.3
 763.3
 735.8

 147.1
 169.1
 144.1

 $
 614.2
 $
 594.2
 $
 591.7

 AEPTCo is wholly-owned by AEP Transmission Holdco.

 CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY

 Total Member's Equity

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

 Capital Contribution from Member
 184.0
 184.0

 ( 112.5)
 ( 112.5)

 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

 ( 170.0)
 ( 170.0)

 594.2
 594.2

 TOTAL MEMBER'S EQUITY - DECEMBER 31, 2022
 3,022.3
 2,850.7
 5,873.0

 Capital Contribution from Member
 29.7
 29.7

 Return of Capital to Member

 614.2
 614.2

 TOTAL MEMBER'S EQUITY - DECEMBER 31, 2023
 $
 3,043.4
 $
 3,289.9
 $
 6,333.3

 2023
 2022

 $
 67.1
 $
 4.4

 82.2
 46.9

 125.5
 119.5

 207.7
 166.4

 —
 10.7

 4.0
 7.2

 278.8
 188.7

 TRANSMISSION PROPERTY

 Transmission Property
 13,723.9
 12,335.4

 501.4
 476.8

 1,563.7
 1,554.7

 Total Transmission Property
 15,789.0
 14,366.9

 1,291.3
 1,027.0

 TOTAL TRANSMISSION PROPERTY – NET

 14,497.7
 13,339.9

 3.1
 7.2

 Deferred Property Taxes
 286.4
 266.6

 6.5
 11.8

 296.0
 285.6

 $
 15,072.5
 $
 13,814.2

 LIABILITIES AND MEMBER'S EQUITY

 2023
 2022

 $
 174.3
 $
 229.3

 274.7
 427.8

 107.9
 82.7

 95.0
 60.0

 568.6
 529.8

 39.6
 28.8

 1.3
 1.3

 24.7
 8.3

 1,286.1
 1,368.0

 5,319.4
 4,722.8

 1,147.7
 1,056.5

 Regulatory Liabilities
 783.7
 723.3

 1.4
 1.5

 200.9
 69.1

 7,453.1
 6,573.2

 8,739.2
 7,941.2

 MEMBER'S EQUITY

 3,043.4
 3,022.3

 3,289.9
 2,850.7

 TOTAL MEMBER'S EQUITY
 6,333.3
 5,873.0

 TOTAL LIABILITIES AND MEMBER'S EQUITY
 $
 15,072.5
 $
 13,814.2

 2023
 2022
 2021

 $
 614.2
 $
 594.2
 $
 591.7

 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:

 393.8
 346.2
 297.3

 44.1
 62.3
 68.5

 ( 83.2)
 ( 70.7)
 ( 67.2)

 Property Taxes
 ( 19.8)
 ( 20.9)
 ( 25.6)

 8.6
 7.5

 134.2
 68.7
 3.7

 ( 41.3)
 ( 46.3)
 ( 16.0)

 10.7

 22.8
 18.5

 42.9
 50.2
 67.2

 10.8
 —
 4.8

 1.2

 3.0

 1,137.6
 995.3
 925.7

 ( 1,496.2)
 ( 1,458.5)
 ( 1,424.8)

 ( 62.7)
 22.8
 81.9

 Acquisitions of Assets
 ( 17.9)

 8.1
 6.3
 1.8

 ( 1,557.7)
 ( 1,439.2)
 ( 1,359.0)

 Capital Contribution from Member
 29.7
 72.7
 184.0

 Return of Capital to Member
 —
 —

 689.0
 540.8
 443.7

 ( 55.0)
 104.4
 ( 31.9)

 ( 60.0)
 ( 104.0)
 ( 50.0)

 ( 170.0)
 ( 112.5)

 420.1
 443.9
 433.3

 Net Change in Cash and Cash Equivalents
 —
 —
 —

 —
 —
 —

 $
 —
 $
 —
 $
 —

 $
 179.9
 $
 158.8
 $
 132.9

 Net Cash Paid for Income Taxes
 87.6
 95.5
 65.7

 177.6
 320.7
 358.7

 2023
 2022
 2021

 10,126
 11,159
 11,207

 5,728
 6,066
 5,949

 8,710
 8,849
 8,879

 25,368
 26,917
 26,845

 Wholesale
 2,191
 1,585
 4,285

 27,559
 28,502
 31,130

 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.

 2023
 2022
 2021

 1,537
 2,182
 1,969

 2,208
 2,209
 2,210

 1,145
 1,314
 1,389

 1,251
 1,238
 1,242

 Appalachian Power Company and Subsidiaries

 $
 394.2

 236.1

 (4.6)

 (4.7)

 (26.0)

 200.8

 (260.7)

 1.8

 Asset Impairments and Other Related Charges - Coal Fired Generation
 24.9

 (37.0)

 4.0

 (4.9)

 (0.7)

 0.2

 3.5

 (35.7)

 (304.6)

 4.0

 $
 294.4

 • Retail Revenues increased $236 million primarily due to the following:
 • A $199 million increase in fuel revenue primarily due to authorized fuel rate increases in Virginia.
 • A $65 million increase in rider revenues in Virginia and West Virginia.
 • A $34 million increase due to lower customer refunds related to Tax Reform.
 • A $20 million increase due to a base rate increase in Virginia implemented in October 2022 following the Virginia Supreme Court remand.
 • A $77 million decrease in weather-related usage driven by a 30% decrease in heating degree days and a 13% decrease in cooling degree days.
 • A $10 million decrease in weather-normalized margins primarily due to decreases in the industrial class.
 • Other Revenues decreased $26 million primarily due to the following:
 • A $16 million decrease in refundable sales of renewable energy credits.
 • A $10 million decrease in pole attachment revenue.

 • Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $261 million primarily due to the following:
 • A $153 million increase due to the current year recovery of prior period under-recovered fuel expenses as a result of authorized fuel rate increases in Virginia.
 • A $127 million increase due to a disallowance of under-recovered ENEC regulatory assets in West Virginia.
 • Other Operation and Maintenance expenses decreased $2 million primarily due to the following:
 • A $19 million decrease in employee-related expenses.
 • A $13 million decrease in distribution expenses primarily due to vegetation management costs.
 • A $13 million decrease due to a charitable contribution to the AEP Foundation in 2022.

 • A $21 million increase due to the amortization of the regulatory asset established in accordance with the August 2022 Virginia Supreme Court opinion related to under-earnings during the 2017-2019 Triennial Review.
 • A $14 million increase due to gains from the sale of land in 2022.
 • An $8 million increase in accounts receivable factoring expense as a result of increased interest rates.
 • Asset Impairments and Other Related Charges - Coal Fired Generation decreased $25 million due to a prior year 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 decreased $37 million due to a prior year 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 Expense decreased $4 million primarily due to the following:
 • A $28 million decrease due to the implementation of updated Virginia depreciation rates in 2023.
 This decrease was partially offset by:
 • A $23 million increase due to a higher depreciable base.
 • Interest Expense increased $36 million primarily due to higher long-term debt balances and interest rates.
 • Income Tax Expense decreased $4 million primarily due to a $22 million decrease as a result of lower pretax book income partially offset by a $15 million increase in state taxes.

 Appalachian Power Company

 We have audited the accompanying consolidated balance sheets of Appalachian Power Company and its subsidiaries (the "Company") as of December 31, 2023 and 2022 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, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 in conformity with accounting principles generally accepted in the United States of America.

 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.

 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.

 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, 2023, there were $1,311 million of deferred costs included in regulatory assets, $126 million of which were pending final regulatory approval, and $1,082 million of regulatory liabilities awaiting potential refund or future rate reduction, $28 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.

 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.

 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.

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

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

 Management assessed the effectiveness of APCo's internal control over financial reporting as of December 31, 2023. 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, 2023.

 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.

 2023
 2022
 2021

 Electric Generation, Transmission and Distribution
 $
 3,464.1
 $
 3,245.5
 $
 2,895.5

 239.3
 256.1
 197.9

 17.3
 18.3
 11.8

 3,720.7
 3,519.9
 3,105.2

 1,434.6
 1,173.9
 979.9

 748.4
 724.1
 610.0

 271.7
 297.8
 265.5

 Asset Impairments and Other Related Charges - Coal Fired Generation
 —
 24.9
 —

 —
 —

 571.9
 575.9
 546.2

 163.1
 158.2
 154.2

 3,189.7
 2,917.8
 2,555.8

 531.0
 602.1
 549.4

 2.8
 3.5
 1.0

 11.9
 11.7
 15.6

 32.5
 29.0
 19.0

 ( 269.6)
 ( 233.9)
 ( 214.0)

 INCOME BEFORE INCOME TAX EXPENSE
 308.6
 412.4
 371.0

 14.2
 18.2
 22.1

 $
 294.4
 $
 394.2
 $
 348.9

 The common stock of APCo is wholly-owned by Parent.

 2023
 2022
 2021

 $
 294.4
 $
 394.2
 $
 348.9

 Cash Flow Hedges, Net of Tax of $( 0.2), $( 0.2) and $ 2.2 in 2023, 2022 and 2021, Respectively

 8.3

 Amortization of Pension and OPEB Deferred Costs, Net of Tax of $( 0.8), $( 1.1) and $( 1.1) in 2023, 2022 and 2021, Respectively

 ( 3.0)
 ( 4.3)

 Pension and OPEB Funded Status, Net of Tax of $ 1.3, $( 6.4) and $ 3.5 in 2023, 2022 and 2021, Respectively

 4.9
 ( 24.1)
 13.1

 1.1
 17.2

 $
 295.5
 $
 365.0
 $
 366.1

 CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S EQUITY

Stock
Other
 Total

 $
 260.4
 $
 1,828.7
 $
 2,248.0
 $
 7.2
 $
 4,344.3

 ( 62.5)
 ( 62.5)

 348.9
 348.9

 17.2
 17.2

 260.4
 1,828.7
 2,534.4
 24.4
 4,647.9

 ( 37.5)
 ( 37.5)

 394.2
 394.2

 260.4
 1,828.7
 2,891.1
 4,975.4

 6.5
 6.5

 294.4
 294.4

 1.1
 1.1

 $
 260.4
 $
 1,834.5
 $
 3,185.5
 $
 $
 5,276.7

 2023
 2022

 $
 5.0
 $
 7.5

 14.9
 14.4

 18.9
 19.8

 170.3
 168.9

 98.8
 94.0

 70.8
 91.3

 0.6
 0.3

 ( 1.7)

 338.5
 352.8

 Fuel
 315.0
 158.9

 148.4
 130.6

 22.4
 69.1

 155.4
 473.1

 40.5
 33.4

 1,059.0
 1,259.6

 7,041.3
 6,776.8

 4,711.8
 4,482.8

 5,176.6
 4,933.0

 981.3
 883.3

 709.2
 705.3

 18,620.2
 17,781.2

 5,688.7
 5,402.0

 12,931.5
 12,379.2

 1,155.1
 1,058.6

 133.4
 159.6

 Employee Benefits and Pension Assets
 171.7
 152.9

 73.7
 73.6

 187.5
 138.7

 1,721.4
 1,583.4

 $
 15,711.9
 $
 15,222.2

 2023
 2022

 $
 339.6
 $
 182.2

 280.4
 451.2

 121.3
 142.7

 Long-term Debt Due Within One Year - Nonaffiliated
 538.8
 251.8

 80.0
 75.1

 117.6
 101.0

 14.6
 15.0

 193.6
 171.2

 1,685.9
 1,390.2

 5,049.5
 5,158.7

 2,011.9
 1,992.2

 1,081.9
 1,143.6

 442.5
 419.2

 Employee Benefits and Pension Obligations
 32.8
 34.2

 59.8
 59.1

 70.9
 49.6

 8,749.3
 8,856.6

 10,435.2
 10,246.8

 Common Stock – No Par Value:

 Authorized – 30,000,000 Shares

 Outstanding – 13,499,500 Shares

 260.4
 260.4

 1,834.5
 1,828.7

 3,185.5
 2,891.1

 5,276.7
 4,975.4

 $
 15,711.9
 $
 15,222.2

 2023
 2022
 2021

 $
 294.4
 $
 394.2
 $
 348.9

 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:

 571.9
 575.9
 546.2

 ( 54.3)
 79.6
 15.0

 Asset Impairments and Other Related Charges - Coal Fired Generation
 —
 24.9
 —

 ( 11.9)
 ( 11.7)
 ( 15.6)

 65.6
 ( 24.4)
 ( 22.3)

 279.7
 ( 501.8)
 ( 196.0)

 —
 —

 ( 115.3)
 ( 75.2)
 ( 68.8)

 ( 1.9)
 31.4
 35.6

 17.5
 ( 8.5)
 ( 53.3)

 ( 173.9)
 ( 113.5)
 116.1

 Margin Deposits
 ( 16.1)
 64.4
 ( 70.0)

 ( 125.9)
 190.1
 36.8

 25.2
 6.7
 ( 16.2)

 0.4
 0.2

 ( 32.3)
 5.9
 ( 42.3)

 723.1
 601.2
 611.7

 ( 1,053.0)
 ( 1,048.6)
 ( 841.6)

 0.9
 1.0
 0.6

 42.4
 14.5

 ( 1,054.9)
 ( 1,005.2)
 ( 826.5)

 6.5
 —
 —

 —
 —

 200.0
 698.0
 494.0

 157.4
 ( 17.1)
 180.7

 ( 26.6)
 ( 230.4)
 ( 393.0)

 ( 8.3)
 ( 7.7)

 —
 ( 37.5)
 ( 62.5)

 1.5
 0.7
 0.7

 329.8
 405.8
 212.2

 Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash for Securitized Funding
 1.8

 Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period
 21.9
 20.1
 22.7

 Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period
 $
 19.9
 $
 21.9
 $
 20.1

 $
 259.7
 $
 215.1
 $
 207.5

 Net Cash Paid (Received) for Income Taxes
 47.4
 ( 88.6)
 32.8

 5.0
 1.6
 1.7

 100.7
 164.6
 139.1

 2023
 2022
 2021

 5,169
 5,507
 5,463

 4,971
 4,740
 4,600

 7,309
 7,492
 7,373

 17,504
 17,795
 17,494

 Wholesale
 5,215
 6,772
 6,618

 22,719
 24,567
 24,112

 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.

 2023
 2022
 2021

 2,917
 3,804
 3,396

 3,734
 3,725
 3,730

 1,055

 Indiana Michigan Power Company and Subsidiaries

 $
 324.7

 (197.4)

 72.5

 (19.3)

 10.5

 (133.7)

 124.2

 60.6

 (53.3)

 57.2

 12.8

 3.2

 6.1

 (11.5)

 199.3

 (54.4)

 $
 335.9

 The major components of the decrease in Revenues were as follows:

 • Retail Revenues decreased $197 million primarily due to the following:
 • A $178 million decrease in fuel revenues primarily due to lower spot market energy prices.
 • A $54 million decrease in rider revenues.
 • A $45 million decrease in weather-related usage due to a 23% decrease in heating degree days and a 20% decrease in cooling degree days.
 • A $64 million increase in weather-normalized margins in all retail classes, partially offset by the wholesale class.
 • A $17 million increase due to a reduction in provision for refund, partially offset by lower wholesale true-ups.
 • Off-system Sales increased $73 million primarily due to economic hedging activity and Rockport Plant, Unit 2 merchant sales.
 • Transmission Revenues decreased $19 million primarily due to the following:
 • An $11 million decrease due to transmission formula rate true-up activity.
 • A $2 million decrease due to lower PJM rates for certain point-to-point transmission service resulting from a December 2022 FERC approved settlement agreement.
 • Other Revenues increased $11 million primarily due to an increase in sales of renewable energy credits.

 • Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $124 million primarily due to lower spot market energy prices and a decrease in generation, partially offset by an increase in average cost of fuel.
 • Purchased Electricity from AEP Affiliates decreased $61 million primarily due to a decrease in purchases from AEGCo driven by a decrease in demand for power from the Rockport Plant.

 • Other Operation and Maintenance expenses increased $53 million primarily due to the following:
 • A $34 million increase in Demand Side Management expenses.
 • A $10 million increase in River Transportation Division and merchant operation expenses.
 • A $9 million increase due to a decreased Nuclear Electric Insurance Limited distribution in 2023.
 • An $8 million increase in nuclear expenses at Cook Plant primarily due to refueling outage expenses.
 • An $8 million increase in vegetation management expenses.
 • A $7 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.
 • A $15 million decrease in employee-related expenses.
 • An $11 million decrease due to a charitable contribution to the AEP Foundation in 2022.
 • Depreciation and Amortization expenses decreased $57 million primarily due to the expiration of the Rockport Plant, Unit 2 lease in December 2022, partially offset by an increase in depreciation expense due to the acquisition of Rockport Plant, Unit 2 at the end of the lease and a higher depreciable base.
 • Taxes Other Than Income Taxes decreased $13 million primarily due to the repeal of the Indiana Utility Receipts Tax in July 2022.
 • Non-Service Cost Components of Net Periodic Benefit Cost decreased $6 million primarily due to the change in loss amortization for the plans and an increase in the expected return on asset assumption, partially offset by higher interest costs due to increased discount rates.
 • Interest Expense increased $12 million primarily due to higher long-term debt balances and interest rates.
 • Income Tax Expense increased $54 million primarily due to the following:
 • A $24 million increase due to a decrease in amortization of Excess ADIT.
 • A $14 million increase due to an increase in pretax book income.
 • An $8 million increase due to an increase in state taxes.

 Indiana Michigan Power Company

 We have audited the accompanying consolidated balance sheets of Indiana Michigan Power Company and its subsidiaries (the "Company") as of December 31, 2023 and 2022 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, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 in conformity with accounting principles generally accepted in the United States of America.

 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.

 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.

 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, 2023, there were $421 million of deferred costs included in regulatory assets, $136 million of which were pending final regulatory approval, and $2,076 million of net regulatory liabilities awaiting potential refund or future rate reduction, $23 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.

 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.

 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.

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

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

 Management assessed the effectiveness of I&M's internal control over financial reporting as of December 31, 2023. 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, 2023.

 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.

 2023
 2022
 2021

 Electric Generation, Transmission and Distribution
 $
 2,465.8
 $
 2,588.3
 $
 2,261.2

 9.3
 17.8
 3.8

 Provision for Refund - Affiliated
 ( 10.5)
 —

 Other Revenues – Affiliated
 59.0
 54.3
 54.0

 Other Revenues – Nonaffiliated
 12.3
 11.7
 7.7

 2,535.9
 2,669.6
 2,326.7

 411.3
 535.5
 338.9

 181.2
 241.8
 217.9

 662.8
 621.0
 645.2

 238.7
 227.2
 210.0

 470.0
 527.2
 446.0

 84.2
 97.0
 110.8

 2,048.2
 2,249.7
 1,968.8

 487.7
 419.9
 357.9

 12.5
 9.3
 11.7

 31.0
 24.9
 16.4

 ( 136.7)
 ( 125.2)
 ( 116.8)

 INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)
 394.5
 328.9
 269.2

 58.6
 4.2

 $
 335.9
 $
 324.7
 $
 279.8

 The common stock of I&M is wholly-owned by Parent.

 2023
 2022
 2021

 $
 335.9
 $
 324.7
 $
 279.8

 Cash Flow Hedges, Net of Tax of $( 0.1), $ 0.4 and $ 0.4 in 2023, 2022 and 2021, Respectively

 1.6
 1.6

 Amortization of Pension and OPEB Deferred Costs, Net of Tax of $( 0.2), $( 0.1) and $ 0 in 2023, 2022 and 2021, Respectively

 Pension and OPEB Funded Status, Net of Tax of $ 0.3, $( 0.1) and $ 1.1 in 2023, 2022 and 2021, Respectively

 1.0
 4.2

 1.0
 5.7

 $
 335.6
 $
 325.7
 $
 285.5

 CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S EQUITY

Stock
Other
 Total

 $
 56.6
 $
 980.9
 $
 1,718.7
 $
 $
 2,749.2

 ( 250.0)
 ( 250.0)

 279.8
 279.8

 5.7
 5.7

 56.6
 980.9
 1,748.5
 2,784.7

 7.9
 7.9

 ( 110.0)
 ( 110.0)

 324.7
 324.7

 1.0
 1.0

 56.6
 988.8
 1,963.2
 3,008.3

 8.8
 8.8

 ( 212.5)
 ( 212.5)

 335.9
 335.9

 $
 56.6
 $
 997.6
 $
 2,086.6
 $
 $
 3,140.2

 2023
 2022

 $
 2.1
 $
 4.2

 —
 23.0

 66.9
 96.6

 65.0
 104.0

 0.2
 0.6

 8.2
 4.7

 —

 140.3
 205.8

 Fuel
 88.1
 46.5

 208.2
 188.1

 27.8
 15.2

 14.8
 47.1

 46.7
 41.9

 528.0
 571.8

 5,646.8
 5,585.1

 1,906.4
 1,842.2

 3,254.0
 3,024.7

 Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)
 898.5
 839.3

 301.7
 253.0

 12,007.4
 11,544.3

 Accumulated Depreciation, Depletion and Amortization
 4,378.4
 4,132.8

 7,629.0
 7,411.5

 406.3
 459.6

 53.8
 64.3

 330.7
 270.5

 4,651.0
 4,135.6

 $
 12,808.0
 $
 12,118.9

 2023
 2022

 $
 63.3
 $
 249.9

 225.8
 173.4

 107.3
 121.5

 (December 31, 2023 and 2022 Amounts Include $ 81.4 and $ 89.6, Respectively, Related to DCC Fuel)

 83.7
 341.8

 72.2
 48.6

 104.7
 103.2

 41.3
 36.9

 16.8
 16.0

 Regulatory Liability for Over-Recovered Fuel Costs
 23.2
 —

 91.9
 105.8

 830.2
 1,197.1

 3,415.7
 2,919.0

 1,169.9
 1,157.0

 2,052.3
 1,702.2

 2,104.3
 2,027.6

 37.7
 48.9

 57.7
 58.8

 8,837.6
 7,913.5

 9,667.8
 9,110.6

 Common Stock – No Par Value:

 Authorized – 2,500,000 Shares

 Outstanding – 1,400,000 Shares

 56.6
 56.6

 997.6
 988.8

 2,086.6
 1,963.2

 3,140.2
 3,008.3

 $
 12,808.0
 $
 12,118.9

 2023
 2022
 2021

 $
 335.9
 $
 324.7
 $
 279.8

 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:

 470.0
 527.2
 446.0

 Rockport Plant, Unit 2 Operating Lease Amortization
 —
 —
 62.4

 ( 54.1)
 ( 45.1)
 ( 38.0)

 Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net
 25.6
 7.5

 ( 12.8)

 ( 22.2)
 ( 16.9)
 5.2

 Amortization of Nuclear Fuel
 96.6
 82.9
 85.3

 55.5
 ( 42.2)
 ( 20.2)

 ( 80.3)
 ( 47.3)
 ( 54.1)

 47.6
 62.4
 7.5

 71.4
 ( 82.7)
 ( 22.3)

 ( 61.4)
 30.1

 22.5
 37.3
 42.3

 1.5
 9.4
 1.6

 Rockport Plant, Unit 2 Operating Lease Payments
 —
 —
 ( 73.9)

 19.5
 ( 15.2)

 ( 11.6)
 ( 46.9)
 2.5

 879.9
 720.7
 733.7

 ( 550.3)
 ( 557.8)
 ( 500.9)

 23.0
 ( 8.2)

 Purchases of Investment Securities
 ( 2,845.1)
 ( 2,765.4)
 ( 1,928.2)

 Sales of Investment Securities
 2,787.5
 2,713.6
 1,886.4

 Acquisitions of Nuclear Fuel
 ( 128.2)
 ( 100.7)
 ( 104.5)

 6.1
 10.3
 22.3

 ( 707.0)
 ( 701.5)
 ( 633.1)

 8.8
 7.9
 —

 Issuance of Long-term Debt - Nonaffiliated
 565.3
 142.7
 546.7

 ( 186.6)
 156.6
 ( 9.7)

 Retirement of Long-term Debt - Nonaffiliated
 ( 343.3)
 ( 83.4)
 ( 383.5)

 ( 130.7)
 ( 6.8)

 ( 212.5)
 ( 110.0)
 ( 250.0)

 0.7
 0.6
 0.7

 Net Cash Flows Used for Financing Activities
 ( 102.6)

 2.9

 4.2
 1.3
 3.3

 $
 2.1
 $
 4.2
 $
 1.3

 $
 131.6
 $
 120.9
 $
 110.9

 Net Cash Paid for Income Taxes
 109.0
 10.1
 29.3

 4.8
 2.2
 132.3

 67.8
 71.9
 87.8

 Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,
 24.2
 —
 —

 2023
 2022
 2021

 13,440
 14,430
 14,547

 16,870
 16,013
 15,036

 13,899
 14,088
 14,321

 Total Retail (a)
 44,318
 44,641
 44,016

 Wholesale (b)
 1,922
 2,198
 2,018

 46,240
 46,839
 46,034

 (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.

 2023
 2022
 2021

 2,380
 3,116
 2,815

 3,185
 3,185
 3,190

 1,121
 1,222

 1,026
 1,011
 1,016

 Ohio Power Company and Subsidiaries

 $
 287.8

 186.1

 (86.4)

 1.4

 45.2

 146.3

 Purchased Electricity for Resale
 149.4

 (77.0)

 (135.7)

 (21.9)

 (4.9)

 (0.9)

 3.2

 3.9

 (11.3)

 (95.2)

 (10.1)

 (0.6)

 $
 328.2

 • Retail Revenues increased $186 million primarily due to a $225 million increase in rider revenues, partially offset by a $49 million decrease in weather-related usage driven by a 24% decrease in heating degree days and a 25% decrease in cooling degree days.
 • Off-system Sales decreased $86 million due to decreased sales at OVEC driven by lower market prices and volume.
 • Other Revenue increased $45 million due to refundable sales of renewable energy credits.

 • Purchased Electricity for Resale expenses decreased $149 million primarily due to the following:
 • A $129 million increase in deferrals of OVEC costs.
 • A $69 million decrease due to lower auction volumes driven by decreased load, partially offset by higher prices.
 • A $36 million increase in recoverable expenses due to creation, consumption and liquidation of renewable energy credits and recoverable renewable energy purchase agreement expenses.
 • Purchased Electricity from AEP Affiliates expenses increased $77 million due to increased affiliated auction volumes driven by AEP Energy auctions won in June 2023.
 • Other Operation and Maintenance expenses increased $136 million primarily due to the following:
 • A $96 million increase related to an energy assistance program for qualified Ohio customers.
 • A $34 million increase in transmission expenses due to an increase in recoverable PJM expenses driven by additional transmission investment.
 • A $23 million increase in recoverable distribution expenses primarily related to vegetation management.
 • A $10 million decrease in employee-related expenses.
 • Depreciation and Amortization expenses increased $22 million primarily due to a higher depreciable base, partially offset by a decrease in recoverable rider depreciable expenses.
 • Interest Expense increased $11 million primarily due to an increase of $20 million driven by higher debt balances and interest rates, partially offset by a decrease of $7 million due to increased AFUDC base and rates.
 • Income Tax Expense increased $10 million primarily due to an increase in pretax book income.

 Ohio Power Company

 We have audited the accompanying consolidated balance sheets of Ohio Power Company and its subsidiaries (the "Company") as of December 31, 2023 and 2022 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, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 in conformity with accounting principles generally accepted in the United States of America.

 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.

 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.

 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, 2023, there were $455 million of deferred costs included in regulatory assets, $24 million of which were pending final regulatory approval, and $1,004 million of regulatory liabilities awaiting potential refund or future rate reduction, $57 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.

 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.

 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 $51 million, as of December 31, 2023.

 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.

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

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

 Management assessed the effectiveness of OPCo's internal control over financial reporting as of December 31, 2023. 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, 2023.

 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.

 2023
 2022
 2021

 Electricity, Transmission and Distribution
 $
 3,768.0
 $
 3,635.3
 $
 2,863.7

 31.1
 18.8
 24.8

 12.3
 11.0
 10.6

 3,811.4
 3,665.1
 2,899.1

 Purchased Electricity for Resale
 1,128.0
 1,277.4
 678.0

 86.8
 9.8
 51.9

 1,091.7
 982.0
 836.8

 211.5
 185.5
 158.2

 316.2
 294.3
 303.3

 507.3
 502.4
 485.7

 3,341.5
 3,251.4
 2,513.9

 469.9
 413.7
 385.2

 0.4
 1.3
 1.8

 17.1
 13.9
 10.8

 26.0
 22.1
 14.6

 ( 130.9)
 ( 119.6)
 ( 124.4)

 INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS
 382.5
 331.4
 288.0

 54.3
 44.2
 34.4

 —
 0.6
 —

 $
 328.2
 $
 287.8
 $
 253.6

 The common stock of OPCo is wholly-owned by Parent.

 CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S EQUITY

Stock
 Total

 $
 321.2
 $
 838.8
 $
 1,532.7
 $
 2,692.7

 ( 100.0)
 ( 100.0)

 253.6
 253.6

 321.2
 838.8
 1,686.3
 2,846.3

 1.0
 1.0

 287.8
 287.8

 321.2
 837.8
 1,929.1
 3,088.1

 175.0
 175.0

 328.2
 328.2

 $
 321.2
 $
 1,012.8
 $
 2,237.3
 $
 3,571.3

 2023
 2022

 $
 6.4
 $
 9.6

 39.2
 119.9

 129.2
 100.9

 —
 17.8

 2.3
 0.1

 —

 170.7
 238.6

 175.0
 109.5

 Renewable Energy Credits
 8.9
 35.0

 16.8
 21.7

 377.8
 414.4

 3,395.1
 3,198.6

 6,839.4
 6,450.3

 1,125.0
 1,051.4

 654.0
 474.3

 12,013.5
 11,174.6

 2,713.6
 2,565.3

 9,299.9
 8,609.3

 455.0
 327.3

 69.9
 73.8

 641.1
 578.3

 1,166.0
 979.4

 $
 10,843.7
 $
 10,003.1

 2023
 2022

 $
 110.5
 $
 172.9

 320.7
 337.3

 154.2
 126.1

 —
 0.1

 6.8
 1.8

 62.0
 96.5

 763.3
 733.1

 13.5
 13.5

 183.3
 154.2

 1,614.3
 1,635.5

 2,970.2

 43.9
 37.9

 1,152.7
 1,101.1

 1,003.6
 1,044.0

 56.7
 60.3

 34.4
 66.0

 5,658.1
 5,279.5

 7,272.4
 6,915.0

 Common Stock – No Par Value:

 Authorized – 40,000,000 Shares

 Outstanding – 27,952,473 Shares

 321.2
 321.2

 1,012.8
 837.8

 2,237.3
 1,929.1

 3,571.3
 3,088.1

 $
 10,843.7
 $
 10,003.1

 2023
 2022
 2021

 $
 328.2
 $
 287.8
 $
 253.6

 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:

 316.2
 294.3
 303.3

 7.9
 71.5
 30.7

 ( 17.1)
 ( 13.9)
 ( 10.8)

 11.0
 ( 52.8)
 ( 17.8)

 Property Taxes
 ( 11.5)
 ( 35.3)

 Change in Regulatory Assets
 ( 90.9)
 30.4
 38.3

 ( 137.5)
 ( 87.1)
 ( 40.7)

 91.1
 6.9

 72.8
 ( 83.7)

 ( 23.4)

 23.6
 112.7
 19.1

 27.5
 27.8
 78.2

 0.4
 11.2
 ( 15.7)

 ( 61.0)
 40.2
 ( 19.9)

 462.3
 686.1
 575.6

 ( 990.4)
 ( 872.4)
 ( 732.8)

 —
 42.0
 ( 42.0)

 41.0
 27.9
 21.5

 ( 949.4)
 ( 802.5)
 ( 753.3)

 175.0
 1.0
 —

 —
 —

 395.0
 —
 1,037.1

 ( 62.4)
 172.9
 ( 259.2)

 ( 500.1)

 ( 5.0)

 ( 100.0)

 1.9
 1.1
 0.4

 483.9
 123.0
 173.3

 6.6

 9.6
 3.0
 7.4

 $
 6.4
 $
 9.6
 $
 3.0

 $
 124.1
 $
 113.4
 $
 119.5

 Net Cash Paid (Received) for Income Taxes
 38.9
 ( 19.7)

 4.1
 3.0
 2.5

 97.7
 109.7
 97.1

 2023
 2022
 2021

 6,138
 6,618
 6,243

 5,190
 5,153
 4,911

 5,932
 6,073
 5,830

 1,255
 1,297
 1,222

 18,515
 19,141
 18,206

 Wholesale

 18,695
 19,875
 18,875

 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.

 2023
 2022
 2021

 1,405
 1,893
 1,499

 1,750
 1,736
 1,742

 2,330
 2,559
 2,198

 2,190
 2,161
 2,165

 $
 167.6

 Retail Revenues (a)
 109.2

 (2.7)

 (4.2)

 102.3

 (63.8)

 47.0

 (25.4)

 (6.6)

 (5.6)

 Allowance for Funds Used During Construction
 6.9

 1.8

 (19.8)

 (65.5)

 4.4

 $
 208.8

 (a)Includes firm wholesale sales to municipals and cooperatives.

 • Retail Revenues increased $109 million primarily due to the following:
 • A $71 million increase in base rate revenues.
 • A $71 million increase in fuel revenue primarily due to authorized fuel rate increases in Oklahoma.
 • A $19 million decrease in weather-related usage due to a 26% decrease in heating degree days and a 9% decrease in cooling degree days.
 • A $10 million decrease in weather-normalized margins primarily in the residential class.

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

 • Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $64 million primarily due to the current year amortization of under-recovered fuel regulatory assets due to authorized fuel rate increases in Oklahoma.
 • Other Operation and Maintenance expenses decreased $47 million primarily due to the following:
 • A $26 million decrease in transmission expenses primarily due to an $11 million decrease in recoverable SPP expenses and a $14 million decrease due to a FERC order which denied stand-alone treatment of NOLCs in transmission formula rates.
 • A $10 million decrease in employee-related expenses.
 • A $6 million decrease due to a charitable contribution to the AEP Foundation in 2022.
 • A $6 million decrease due to the pre-construction costs associated with various renewable projects.
 • Depreciation and Amortization expenses increased $25 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 $7 million primarily due to increased property taxes driven by the investment in NCWF and a new infrastructure fee implemented by the City of Tulsa in March 2022.
 • Interest Income decreased $6 million primarily due to decreased carrying charges on regulatory assets resulting from the February 2021 severe winter weather event.

 • Allowance for Funds Used During Construction increased $7 million primarily due to an increase in AFUDC base and equity rates.
 • Interest Expense increased $20 million primarily due to higher long-term debt balances and interest rates.
 • Income Tax Benefit increased $4 million primarily due to the following:
 • A $17 million increase in PTCs.
 • An $8 million decrease due to an increase in pretax book income.
 • A $2 million decrease due to a decrease in amortization of Excess ADIT.

 We have audited the accompanying balance sheets of Public Service Company of Oklahoma (the "Company") as of December 31, 2023 and 2022 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, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 in conformity with accounting principles generally accepted in the United States of America.

 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.

 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.

 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, 2023, there were $641 million of deferred costs included in regulatory assets, $89 million of which were pending final regulatory approval, and $766 million of regulatory liabilities awaiting potential refund or future rate reduction, $1 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.

 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.

 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.

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

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

 Management assessed the effectiveness of PSO's internal control over financial reporting as of December 31, 2023. 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, 2023.

 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.

 STATEMENTS OF INCOME

 2023
 2022
 2021

 Electric Generation, Transmission and Distribution
 $
 1,968.4
 $
 1,865.6
 $
 1,465.3

 1.2
 2.9
 4.2

 7.4
 6.2
 4.9

 1,977.0
 1,874.7
 1,474.4

 955.3
 891.5
 584.3

 355.8
 400.4
 353.8

 112.0
 114.4
 97.2

 255.5
 230.1
 196.6

 64.1
 57.5
 49.6

 1,742.7
 1,693.9
 1,281.5

 234.3
 180.8
 192.9

 1.8
 7.4
 4.3

 8.4
 1.5
 2.4

 14.3
 12.5
 8.5

 ( 103.6)
 ( 83.8)
 ( 62.9)

 INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)
 155.2
 118.4
 145.2

 ( 53.6)
 4.1

 $
 208.8
 $
 167.6
 $
 141.1

 The common stock of PSO is wholly-owned by Parent.

 STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

 2023
 2022
 2021

 $
 208.8
 $
 167.6
 $
 141.1

 Cash Flow Hedges, Net of Tax of $( 0.4), $ 0.3 and $ 0 in 2023, 2022 and 2021, Respectively

 1.3

 $
 207.3
 $
 168.9
 $
 141.0

 STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S EQUITY

Stock
Other
 Total

 $
 157.2
 $
 414.0
 $
 974.3
 $
 0.1
 $
 1,545.6

 625.0
 625.0

 141.1
 141.1

 157.2
 1,039.0
 1,095.4
 —
 2,291.6

 3.6
 3.6

 167.6
 167.6

 1.3
 1.3

 157.2
 1,042.6
 1,218.0
 1.3
 2,419.1

 0.6
 0.6

 ( 52.5)
 ( 52.5)

 208.8
 208.8

 $
 157.2
 $
 1,039.3
 $
 1,374.3
 $
 $
 2,570.6

 BALANCE SHEETS

 2023
 2022

 $
 2.5
 $
 4.0

 107.6
 70.1

 31.0
 52.2

 0.8
 0.8

 139.4
 123.1

 Fuel
 33.7
 11.6

 106.9
 111.1

 19.0
 25.3

 Accrued Tax Benefits
 31.0
 16.1

 118.3
 178.7

 18.7
 21.6

 469.5
 491.5

 2,695.5
 2,394.8

 1,228.3
 1,164.4

 3,450.8
 3,216.4

 505.9
 469.3

 313.7
 219.3

 8,194.2
 7,464.2

 2,081.9
 1,837.7

 6,112.3
 5,626.5

 522.7
 653.7

 Employee Benefits and Pension Assets
 68.4
 67.3

 112.8
 106.1

 49.2
 20.8

 753.1
 847.9

 $
 7,334.9
 $
 6,965.9

 BALANCE SHEETS

 2023
 2022

 $
 54.4
 $
 364.2

 159.3
 202.9

 56.7
 76.7

 0.6
 0.5

 28.9
 1.6

 81.4
 59.0

 30.7
 28.7

 30.7
 18.2

 10.1
 8.9

 106.2
 82.0

 559.0
 842.7

 2,384.0
 1,912.3

 831.2
 788.6

 765.6
 809.1

 83.9
 73.5

 106.8
 99.3

 33.8
 21.3

 4,205.3
 3,704.1

 4,764.3
 4,546.8

 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

 1,039.3
 1,042.6

 1,374.3
 1,218.0

 1.3

 2,570.6
 2,419.1

 $
 7,334.9
 $
 6,965.9

 STATEMENTS OF CASH FLOWS

 2023
 2022
 2021

 $
 208.8
 $
 167.6
 $
 141.1

 Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:

 255.5
 230.1
 196.6

 7.9
 ( 59.4)
 113.9

 ( 8.4)

 33.0
 ( 13.7)
 1.9

 313.2
 442.4
 ( 843.8)

 Change in Other Regulatory Assets
 ( 108.3)
 4.7
 ( 3.5)

 ( 71.3)
 ( 40.1)

 8.2
 29.9
 4.4

 ( 46.0)
 ( 28.7)

 ( 16.8)
 ( 51.1)
 1.4

 ( 58.2)
 57.5
 34.2

 ( 12.9)
 3.2
 ( 6.5)

 10.7

 45.4
 30.4
 ( 20.8)

 Net Cash Flows from (Used for) Operating Activities
 590.5
 747.7
 ( 433.3)

 ( 562.3)
 ( 447.0)
 ( 332.1)

 Acquisitions of Renewable Energy Facilities
 ( 145.7)
 ( 549.3)
 ( 297.0)

 15.2
 4.3
 2.4

 ( 692.8)
 ( 992.0)
 ( 626.7)

 0.6
 3.6
 625.0

 —
 —

 469.8
 499.7
 1,290.0

 ( 309.8)
 291.9
 ( 83.1)

 ( 500.5)
 ( 750.5)

 ( 3.3)

 ( 52.5)

 0.4
 0.5
 0.5

 100.8
 247.0
 1,058.7

 2.7

 4.0
 1.3
 2.6

 $
 2.5
 $
 4.0
 $
 1.3

 $
 87.3
 $
 79.7
 $
 57.0

 Net Cash Paid (Received) for Income Taxes
 ( 12.5)
 ( 102.9)

 Cash Received from the Sale of Transferable Tax Credits
 ( 34.6)
 —
 —

 2.1
 2.8
 3.6

 72.9
 69.8
 56.8

 2023
 2022
 2021

 6,138
 6,538
 6,205

 5,538
 5,732
 5,489

 5,147
 5,174
 4,682

 16,894
 17,519
 16,453

 Wholesale
 5,429
 6,714
 6,704

 22,323
 24,233
 23,157

 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.

 2023
 2022
 2021

 1,149

 1,174
 1,170
 1,177

 2,853
 2,833
 2,543

 2,365
 2,333
 2,328

 Earnings Attributable to SWEPCo Common Shareholder

 $
 290.1

 Retail Revenues (a)
 (86.2)

 (13.6)

 (6.7)

 4.9

 (101.6)

 82.4

 53.4

 (85.6)

 (18.0)

 (8.3)

 1.2

 6.6

 1.1

 (9.8)

 23.0

 8.1

 Net Income Attributable to Noncontrolling Interest
 0.7

 $
 220.3

 (a)Includes firm wholesale sales to municipals and cooperatives.

 The major components of the decrease in Revenues were as follows:

 • Retail Revenues decreased $86 million primarily due to the following:
 • A $125 million decrease in fuel revenue primarily due to lower natural gas and spot market energy prices, partially offset by authorized fuel rate increases in Arkansas and Texas designed to recover previously under-recovered fuel regulatory asset balances.
 • A $20 million decrease in weather-related usage due to a 37% decrease in heating degree days.
 • An $11 million decrease in weather-normalized margins primarily in the residential class.
 • A $70 million increase primarily due to base rate revenue increases in Louisiana and Arkansas and rider increases in all retail jurisdictions.
 • Off-system Sales decreased $14 million primarily due to reduced Turk Plant merchant sales.
 • Transmission Revenues decreased $7 million primarily due to the following:
 • A $13 million decrease due to a FERC order which denied stand-alone treatment of NOLCs in transmission formula rates.
 • An $8 million decrease in transmission formula rate true-up activity.
 • A $12 million increase in transmission investment.

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

 • Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $82 million primarily due to lower natural gas and spot market energy prices, partially offset by the current year amortization of under-recovered fuel regulatory assets due to authorized fuel rate increases in Arkansas and Texas.
 • Other Operation and Maintenance expenses decreased $53 million primarily due to the following:
 • A $19 million decrease in transmission expenses primarily due to the following:
 • A $13 million decrease in transmission formula rate true-up activity and decreased third-party expenses.
 • A $7 million decrease due to a FERC order which denied stand-alone treatment of NOLCs in transmission formula rates.
 • An $11 million decrease due to pre-construction costs associated with various renewable projects.
 • A $10 million decrease in administrative and general expenses primarily due to regulatory fees and employee-related expenses.
 • A $9 million decrease due to a prior year charitable contribution to the AEP Foundation.
 • Asset Impairments and Other Related Charges increased $86 million due to the probable disallowance of Turk Plant capitalized AFUDC in excess of the Texas jurisdictional capital cost cap as a result of the PUCT's December 2023 preliminary order in the 2012 Texas Base Rate Case.
 • Depreciation and Amortization expenses increased $18 million primarily due to an increase in amortization of regulatory assets.
 • Taxes Other Than Income Taxes increased $8 million primarily due to increased property taxes driven by the investment in the NCWF.
 • Allowance for Equity Funds Used During Construction increased $7 million primarily due to higher AFUDC equity rates and CWIP.
 • Interest Expense increased $10 million primarily due to higher long-term debt balances and interest rates.
 • Income Tax Benefit increased $8 million primarily due to the following:
 • A $17 million increase due to a decrease in pretax book income.
 • A $10 million increase in PTCs.
 • A $12 million decrease due to the probable disallowance of Turk Plant capitalized AFUDC in excess of the Texas jurisdictional capital cost cap.
 • A $3 million decrease in depletion benefit.
 • A $2 million decrease due to a decrease in amortization of Excess ADIT.

 Southwestern Electric Power Company

 We have audited the accompanying consolidated balance sheets of Southwestern Electric Power Company and its subsidiaries (the "Company") as of December 31, 2023 and 2022 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, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 in conformity with accounting principles generally accepted in the United States of America.

 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.

 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.

 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, 2023, there were $1,303 million of deferred costs included in regulatory assets, $408 million of which were pending final regulatory approval, and $759 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.

 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.

 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.

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

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

 Management assessed the effectiveness of SWEPCo's internal control over financial reporting as of December 31, 2023. 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, 2023.

 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.

 2023
 2022
 2021

 Electric Generation, Transmission and Distribution
 $
 2,133.6
 $
 2,228.6
 $
 2,088.9

 81.6
 59.5
 41.4

 Provision for Refund - Affiliated
 ( 34.8)

 2.4
 1.9
 1.9

 2,182.8
 2,284.4
 2,131.8

 807.1
 889.5
 871.0

 360.5
 424.7
 360.3

 159.4
 148.6
 136.7

 85.6
 —
 11.6

 342.8
 324.8
 295.0

 135.1
 126.8
 117.7

 1,890.5
 1,914.4
 1,792.3

 292.3
 370.0
 339.5

 18.9
 17.7
 9.2

 11.5
 4.9
 7.0

 13.6
 12.5
 8.3

 ( 147.2)
 ( 137.4)
 ( 125.9)

 INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS
 189.1
 267.7
 238.1

 ( 33.3)
 ( 25.2)

 Equity Earnings of Unconsolidated Subsidiary
 1.4
 1.4
 3.4

 223.8
 294.3
 242.1

 Net Income Attributable to Noncontrolling Interest
 3.5
 4.2
 3.1

 EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER
 $
 220.3
 $
 290.1
 $
 239.0

 The common stock of SWEPCo is wholly-owned by Parent.

 2023
 2022
 2021

 $
 223.8
 $
 294.3
 $
 242.1

 Cash Flow Hedges, Net of Tax of $ 0, $ 0 and $ 0.4 in 2023, 2022 and 2021, Respectively

 0.2
 1.5

 Amortization of Pension and OPEB Deferred Costs, Net of Tax of $( 0.3), $( 0.4) and $( 0.4) in 2023, 2022 and 2021, Respectively

 Pension and OPEB Funded Status, Net of Tax of $ 0.5, $( 2.5) and $ 1.3 in 2023, 2022 and 2021, Respectively

 1.9
 ( 9.2)
 4.9

 0.8
 4.8

 224.6
 283.4
 246.9

 Total Comprehensive Income Attributable to Noncontrolling Interest
 3.5
 4.2
 3.1

 TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER

 $
 221.1
 $
 279.2
 $
 243.8

 CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

 SWEPCo Common Shareholder

Stock
Other
 Noncontrolling
Interest
 Total

 TOTAL EQUITY – DECEMBER 31, 2020
 $
 0.1
 $
 812.2
 $
 1,811.9
 $
 1.9
 $
 1.6
 $
 2,627.7

 280.0
 280.0

 Common Stock Dividends – Nonaffiliated

 239.0
 3.1
 242.1

 4.8
 4.8

 TOTAL EQUITY – DECEMBER 31, 2021
 0.1
 1,092.2
 2,050.9
 6.7
 3,149.8

 350.0
 350.0

 ( 105.0)
 ( 105.0)

 Common Stock Dividends – Nonaffiliated

 290.1
 4.2
 294.3

 TOTAL EQUITY – DECEMBER 31, 2022
 0.1
 1,442.2
 2,236.0
 0.7
 3,674.8

 50.0
 50.0

 Common Stock Dividends – Nonaffiliated

 220.3
 3.5
 223.8

 0.8
 0.8

 TOTAL EQUITY – DECEMBER 31, 2023
 $
 0.1
 $
 1,492.2
 $
 2,281.3
 $
 $
 0.2
 $
 3,770.4

 2023
 2022

 (December 31, 2023 and 2022 Amounts Include $ 0 and $ 84.2, Respectively, Related to Sabine)

 $
 2.4
 $
 88.4

 2.2
 2.1

 39.0
 38.8

 47.2
 65.4

 8.3
 10.4

 94.5
 114.6

 Fuel
 (December 31, 2023 and 2022 Amounts Include $ 0 and $ 14.2, Respectively, Related to Sabine)

 113.8
 81.3

 (December 31, 2023 and 2022 Amounts Include $ 3.9 and $ 4.2, Respectively, Related to Sabine)

 88.4
 92.1

 11.6
 16.4

 Accrued Tax Benefits
 28.4
 16.5

 170.8
 353.0

 29.2
 47.8

 541.3
 812.2

 4,790.7
 5,476.2

 2,660.6
 2,479.8

 2,824.1
 2,659.6

 (December 31, 2023 and 2022 Amounts Include $ 182.7 and $ 219.8, Respectively, Related to Sabine)

 814.4
 804.4

 555.8
 369.5

 11,645.6
 11,789.5

 (December 31, 2023 and 2022 Amounts Include $ 182.7 and $ 212.5, Respectively, Related to Sabine)

 3,087.2
 3,527.3

 8,558.4
 8,262.2

 1,131.8
 1,042.4

 326.1
 262.0

 1,457.9
 1,304.4

 $
 10,557.6
 $
 10,378.8

 2023
 2022

 $
 88.7
 $
 310.7

 198.9
 213.1

 45.9
 81.7

 Short-term Debt – Nonaffiliated
 4.3
 —

 —
 6.2

 14.4
 1.4

 72.5
 65.4

 58.7
 52.8

 39.9
 36.0

 9.0
 8.4

 154.6
 172.0

 686.9
 947.7

 3,385.4

 1,179.3
 1,089.7

 756.1
 825.7

 258.6
 237.2

 Employee Benefits and Pension Obligations
 43.1
 29.7

 122.5
 120.2

 93.8
 68.4

 6,100.3
 5,756.3

 6,787.2
 6,704.0

 Rate Matters (Notes 4)

 EQUITY

 Common Stock – Par Value – $ 18 Per Share:

 Authorized – 3,680 Shares

 Outstanding – 3,680 Shares

 0.1
 0.1

 1,492.2
 1,442.2

 2,281.3
 2,236.0

 3,770.2
 3,674.1

 Noncontrolling Interest
 0.2
 0.7

 TOTAL EQUITY
 3,770.4
 3,674.8

 TOTAL LIABILITIES AND EQUITY
 $
 10,557.6
 $
 10,378.8

 2023
 2022
 2021

 $
 223.8
 $
 294.3
 $
 242.1

 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:

 342.8
 324.8
 295.0

 54.0
 9.4
 16.6

 85.6
 —
 11.6

 ( 11.5)

 19.1
 ( 7.3)

 184.3
 ( 86.4)
 ( 546.4)

 Change in Regulatory Assets
 ( 60.8)
 7.6
 ( 95.6)

 ( 40.5)
 42.9
 41.9

 11.0
 18.3

 20.1
 ( 28.2)
 ( 21.5)

 ( 31.4)
 126.5

 ( 8.4)
 34.1
 22.0

 ( 4.5)
 9.8
 15.4

 20.2

 8.2

 803.0
 586.6
 96.8

 ( 780.5)
 ( 586.4)
 ( 414.6)

 153.8
 ( 153.8)

 Acquisition of the North Central Wind Energy Facilities
 —
 ( 658.0)
 ( 355.8)

 3.9
 5.5
 3.5

 ( 776.7)
 ( 1,085.1)
 ( 920.7)

 50.0
 350.0
 280.0

 346.8
 —
 1,137.6

 Change in Short-term Debt – Nonaffiliated
 4.3
 —
 ( 35.0)

 ( 222.0)
 310.7
 ( 124.6)

 ( 94.1)
 ( 381.2)

 ( 19.1)
 ( 10.8)

 ( 105.0)
 —

 Dividends Paid on Common Stock – Nonaffiliated

 0.8
 0.4
 0.8

 Net Cash Flows from (Used for) Financing Activities
 ( 112.3)
 535.7
 861.9

 ( 86.0)
 37.2
 38.0

 88.4
 51.2
 13.2

 $
 2.4
 $
 88.4
 $
 51.2

 $
 128.9
 $
 131.2
 $
 116.5

 Net Cash Paid (Received) for Income Taxes
 ( 41.0)
 ( 29.1)
 ( 28.8)

 Cash Received from the Sale of Transferable Tax Credits
 ( 41.4)
 —
 —

 7.1
 3.6
 4.8

 63.7
 105.6
 69.0

 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

 Organization and Summary of Significant Accounting Policies

 New Accounting Standards

 Comprehensive Income
 AEP

 Rate Matters

 Effects of Regulation

 Commitments, Guarantees and Contingencies

 Acquisitions, Dispositions and Impairments
 AEP, AEPTCo, PSO, SWEPCo

 Benefit Plans
 AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo

 Business Segments

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

 Fair Value Measurements
 AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo

 Income Taxes

 Leases

 Financing Activities

 Stock-based Compensation
 AEP

 Related Party Transactions

 Variable Interest Entities and Equity Method Investments

 Property, Plant and Equipment

 Revenue from Contracts with Customers

 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 operated competitive wind and solar farms prior to the sale of AEP Renewables' competitive contracted renewables portfolio in August 2023. I&M provides barging services to both affiliated and nonaffiliated companies.

 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.

 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 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 (a consolidated VIE) 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.

 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.

 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 include temporary cash investments with original maturities of three months or less.

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

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

 Reconciliation of Cash, Cash Equivalents and Restricted Cash

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

 AEP
 APCo

 $
 330.1
 $
 0.1
 $
 5.0

 48.9
 34.0
 14.9

 Total Cash, Cash Equivalents and Restricted Cash
 $
 379.0
 $
 34.1
 $
 19.9

 AEP
 APCo

 $
 509.4
 $
 0.1
 $
 7.5

 47.1
 32.7
 14.4

 Total Cash, Cash Equivalents and Restricted Cash
 $
 556.5
 $
 32.8
 $
 21.9

 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 and Allowance for Uncollectible Accounts

 Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities.

 Revenue is recognized over time as the performance obligations of delivering energy to customers are satisfied. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing.

 AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo's accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for a portion of its interests in the billed and unbilled receivables acquired from the affiliated utility subsidiaries. See "Securitized Accounts Receivable – AEP Credit" section of Note 14 for additional information.

 Generally, AEP Credit recognizes 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 for each participating AEP subsidiary, which inherently contemplates any differences in geographical risk characteristics for the allowance for uncollectible accounts. From January 2022 through August 2023, KPCo ceased selling accounts receivable to AEP Credit due to the planned sale of KPCo to Liberty. During this time period, KPCo recognized an allowance for uncollectible accounts on its balance sheet for its accounts receivables using the same assessment methodology used for AEP Credit's receivables. In September 2023, KPCo resumed selling accounts receivable to AEP Credit, due to the termination of the sale to Liberty. For receivables related to APCo's West Virginia operations, the allowance for uncollectible accounts 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 receivable are reviewed for potential credit losses at a specific counterparty level basis. For AEP Texas, allowances for uncollectible accounts 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 recognized based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable, unless specifically identified.

 In addition to these processes, management contemplates available current information, as well as any reasonable and supportable forecast information, to determine if allowances for uncollectible accounts should be further adjusted in accordance with the accounting guidance for "Credit Losses." Management's assessments contemplate expected losses over the life of the accounts receivable.

 Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries)

 APCo, I&M, OPCo, PSO and SWEPCo do not have any significant customers that comprise 10 % or more of their operating revenues. AEP Texas had significant customers which 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:

 NRG Energy and TXU Energy

 2023

 2022

 2021

 Percentage of Total Revenues

 %

 %

 %

 Percentage of Accounts Receivable – Customers

 %

 %

 %

 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
 2023

 2022
 2021

 Percentage of Total Revenues
 %
 %
 %

 Percentage of Total Accounts Receivable
 %
 %
 %

 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 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 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 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 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 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 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. Certain derivatives that economically hedge future commodity risk are recorded in the same line item on the statements of income as that of the associated risk being hedged. Realized gains and losses on cash flow hedges are recorded in Total Revenues or Purchased Electricity depending on the nature of the risk being hedged. Derivative purchases elected normal used to serve accrual based obligations are recorded in Purchased Electricity 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 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.

 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.

 Transferable tax credits established by the IRA are accounted for in accordance with the accounting guidance for "Income Taxes" by the Registrants. Proceeds from sales of transferable tax credits are included as a component of Operating Activities on the statement of cash flows and presented as gross within the Supplementary Cash Flow Information.

 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.

 AEP and subsidiaries join in the filing of a consolidated federal income tax return. The benefit of current tax loss of the parent company (Parent Company Loss Benefit) to the AEP System subsidiaries is accounted for as an allocation through equity. 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.

 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 discounts, premiums 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.

 Pension and OPEB Plans (Applies to all Registrants except AEPTCo)

 AEPSC sponsors a qualified pension plan and two unfunded non-qualified pension plans. Substantially all AEP subsidiary employees are covered by the qualified plan or both the qualified and a non-qualified pension plan. AEPSC also sponsors OPEB plans to provide health and life insurance benefits for retired employees. The Registrant Subsidiaries account for their participation in the AEPSC sponsored pension and OPEB plans using multiple-employer accounting. See Note 8 - Benefit Plans for additional information including significant accounting policies associated with the plans.

 Investments Held in Trust for Future Liabilities (Applies to all Registrants except AEPTCo)

 AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits, nuclear decommissioning and SNF disposal. All of the trust funds' investments are diversified and managed in compliance with all laws and regulations. The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities. To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers. Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate. Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. The investments are reported at fair value under the "Fair Value Measurements and Disclosures" accounting guidance.

 Benefit Plans

 All benefit plan assets are invested in accordance with each plan's investment policy. The investment policy outlines the investment objectives, strategies and target asset allocations by plan.

 The investment philosophies for AEP's benefit plans support the allocation of assets to minimize risks and optimize net returns. Strategies used include:

 • Maintaining a long-term investment horizon.
 • Diversifying assets to help control volatility of returns at acceptable levels.
 • Managing fees, transaction costs and tax liabilities to maximize investment earnings.
 • Using active management of investments where appropriate risk/return opportunities exist.
 • Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks.
 • Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification.

 The objective of the investment policy for the pension fund is to maintain the funded status of the plan while providing for growth in the plan assets to offset the growth in the plan liabilities. The current target asset allocations are as follows:

 Pension Plan Assets
 Target

 %

 Fixed Income
 %

 Other Investments
 %

 %

 OPEB Plans Assets
 Target

 %

 Fixed Income
 %

 %

 The investment policy for each benefit plan contains various investment limitations. The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies or certain commingled funds). However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law.

 For equity investments, the concentration limits are generally as follows:

 • No security in excess of 5% of all equities.
 • Cash equivalents must be less than 10% of an investment manager's equity portfolio.
 • No individual stock may be more than 10% and 7% for pension and OPEB investments, respectively, of each manager's equity portfolio.
 • No securities may be bought or sold on margin or other use of leverage.

 For fixed income investments, each investment manager's portfolio is compared to investment grade, diversified long and intermediate benchmark indices.

 A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation. Real estate properties are illiquid, difficult to value and not actively traded. The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties. To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type and risk classification. Real estate holdings include core, value-added and opportunistic classifications.

 A portion of the pension assets is invested in private equity. Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance. Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded. The pension plan uses limited partnerships to invest across the private equity investment spectrum. The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise. The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investments.

 AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses. AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral. All loans are collateralized by at least 102% of the loaned asset's market value and the collateral is invested. The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security. The securities lending program's objective is to provide modest incremental income with a limited increase in risk. As of December 31, 2023 and 2022, the fair value of securities on loan as part of the program was $ 62 million and $ 83 million, respectively. Cash and securities obtained as collateral exceeded the fair value of the securities loaned as of December 31, 2023 and 2022.

 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.

 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 AEP only)

 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, 2023, 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. The impact of AEP's stock-based compensation plan is 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. Prior to June 2022, these stock units were payable in cash to directors after their service ended and are now payable in AEP common stock.

 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, 2023, 2022 and 2021 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, 2023, 2022 and 2021, compensation costs are included in Net Income for the performance shares, career shares, restricted stock units, the non-employee director stock units and other qualified and non-qualified deferred compensation plans that provide an investment in or an investment return equivalent to that of AEP common stock. 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.

 As of December 31, 2023, AEP's significant equity method investments include ETT and DHLC. In August 2023, AEP disposed of four joint venture interests as a part of the sale of AEP Renewables' competitive contracted renewables portfolio. Prior to the sale, these joint venture interests were accounted for as equity method investments. See the "Disposition of the Competitive Contracted Renewables Portfolio" section of Note 7 and the "AEP Wind Holdings, LLC " section of Note 17 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:

 2023
 2022
 2021

 (in millions, except per-share data)

 $/share
 $/share
 $/share

 Earnings Attributable to AEP Common Shareholders
 $
 $
 $

 Weighted-Average Number of Basic AEP Common Shares Outstanding
 518.9
 $
 4.26
 511.8
 $
 4.51
 500.5
 $
 4.97

 Weighted-Average Dilutive Effect of Stock-Based Awards
 1.3
 ( 0.02)
 1.7
 ( 0.02)
 1.3
 ( 0.01)

 Weighted-Average Number of Diluted AEP Common Shares Outstanding
 520.2
 $
 4.24
 513.5
 $
 4.49
 501.8
 $
 4.96

 There were no antidilutive shares outstanding as of December 31, 2023, 2022 and 2021.

 Supplementary Income Statement Information

 The following tables provide the components of Depreciation and Amortization for the years ended December 31, 2023, 2022 and 2021:

 2023

 AEP
 APCo
 I&M
 OPCo
 PSO

 Depreciation and Amortization of Property, Plant and Equipment

 $
 2,927.5
 $
 380.0
 $
 393.8
 $
 571.1
 $
 439.8
 $
 315.8
 $
 240.3
 $
 323.4

 Amortization of Certain Securitized Assets

 91.9
 91.9
 —
 —
 —
 —
 —
 —

 Amortization of Regulatory Assets and Liabilities

 71.0
 —
 0.8
 30.2
 0.4
 15.2
 19.4

 Total Depreciation and Amortization

 $
 3,090.4
 $
 468.5
 $
 393.8
 $
 571.9
 $
 470.0
 $
 316.2
 $
 255.5
 $
 342.8

 2022

 AEP
 APCo
 I&M
 OPCo
 PSO

 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
 —
 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

 AEP
 APCo
 I&M
 OPCo
 PSO

 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
 —
 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

 Supplementary Cash Flow Information (Applies to AEP)

 Cash Flow Information
 2023
 2022
 2021

 Cash Paid (Received) for:

 Interest, Net of Capitalized Amounts
 $
 1,673.5
 $
 1,286.3
 $
 1,137.2

 Income Taxes
 78.4
 116.8
 13.2

 Sale of Transferable Tax Credits
 ( 102.0)
 —
 —

 Noncash Investing and Financing Activities:

 Acquisitions Under Finance Leases
 48.7
 31.8
 287.6

 842.4
 1,258.9
 1,180.4

 Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,
 24.2
 —
 —

 Noncash Contribution of Assets to Cedar Creek Project
 —
 —

 Noncontrolling Interest Assumed - Dry Lake Solar Project
 —
 —
 35.3

 Noncash Increase in Noncurrent Assets from the Sale of the Competitive
 Contracted Renewables Portfolio

 74.7
 —
 —

 2. NEW ACCOUNTING STANDARDS

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

 During the FASB's standard-setting process and upon issuance of final standards, management reviews the new accounting literature to determine its relevance, if any, to the Registrants' business. The following standards will impact the Registrants' financial statements.

 ASU 2023-09 "Improvements to Income Tax Disclosures" (ASU 2023-09)

 In December 2023, the FASB issued ASU 2023-09, to address investors' suggested enhancements to (a) better understand an entity's exposure to potential changes in jurisdictional tax legislation and the ensuing risks and opportunities, (b) assess income tax information that affects cash flow forecasts and capital allocation decisions and (c) identify potential opportunities to increase future cash flows.

 The new standard requires an annual rate reconciliation disclosure of the following categories regardless of materiality: state and local income tax net of federal income tax effect, foreign tax effects, effect of changes in tax laws or rates enacted in the current period, effect of cross-border tax laws, tax credits, changes in valuation allowances, nontaxable or nondeductible items and changes in unrecognized tax benefits.

 The new standard also requires an annual disclosure of the amount of income taxes paid (net of refunds received) disaggregated by federal, state and foreign taxes and by individual jurisdictions that are equal to or greater than 5 percent of total income taxes paid. Disclosure of income (loss) from continuing operations before income tax expense (benefit) disaggregated between domestic and foreign jurisdictions and income tax expense (benefit) from continuing operations disaggregated by federal, state and foreign jurisdictions is required.

 The new standard removes the requirement to disclose the cumulative amount of each type of temporary difference when a deferred tax liability is not recognized because of the exceptions to comprehensive recognition of deferred taxes related to subsidiaries and corporate joint ventures.

 The amendments in the new standard may be applied on either a prospective or retrospective basis for public business entities for fiscal years beginning after December 15, 2024 with early adoption permitted. Management has not yet made a decision to early adopt the amendments to this standard or how to apply them.

 ASU 2023-07 "Improvements to Reportable Segment Disclosures" (ASU 2023-07)

 In November 2023, the FASB issued ASU 2023-07, to address investors' observations that there is limited information disclosed about segment expenses and to better understand expense categories and amounts included in segment profit or loss. The new standard requires annual and interim disclosure of (a) the categories and amounts of significant segment expenses (determined by management using both qualitative and quantitative factors) that are regularly provided to the chief operating decision maker (CODM) and included within each reported measure of segment profit or loss, (b) the amounts and a qualitative description of "other segment items", defined as the difference between reported segment revenues less the significant segment expenses and each reported measure of segment profit or loss disclosed, (c) reportable segment profit or loss and assets that are currently only required annually, (d) the CODM's title and position, and an explanation of how the CODM uses the reported measure(s) of segment profit or loss in assessing segment performance and deciding how to allocate resources and (e) a requirement that entities with a single reportable segment provide all disclosures required by ASU 2023-07 and all existing segment disclosures in Topic 280. Additionally, this new standard allows disclosure of one or more of additional profit or loss measures if the CODM uses more than one measure provided that at least one of the disclosed measures is determined in a manner "most consistent with the measurement principles under GAAP". If multiple measures are presented, additional disclosure is required about how the CODM uses each measure to assess performance and decide how to allocate resources.

 The amendments in the new standard are effective on a retrospective basis for all entities for fiscal years beginning after December 15, 2023 and interim periods within fiscal periods beginning after December 15, 2024 with early adoption permitted. Management does not plan to early adopt the amendments to this standard.

 3. COMPREHENSIVE INCOME

 The disclosures in this note apply to AEP only. The impact of AOCI is not material to the financial statements of the Registrant Subsidiaries.

 Presentation of Comprehensive Income

 The following tables provide AEP's components of changes in AOCI and details of reclassifications from AOCI for the years ended December 31, 2023, 2022 and 2021. 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.

 Cash Flow Hedges
 Pension and OPEB

 For the Year Ended December 31, 2023
 Amortization of Deferred Costs
 Changes in Funded Status
 Total

 Balance in AOCI as of December 31, 2022
 $
 223.5
 $
 0.3
 $
 105.2
 $
 ( 245.3)
 $
 83.7

 Change in Fair Value Recognized in AOCI, Net of Tax
 ( 175.8)
 —
 ( 198.5)

 Amount of (Gain) Loss Reclassified from AOCI

 Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)

 72.2
 —
 —
 —
 72.2

 Interest Expense (a)

 —
 —
 —

 Amortization of Prior Service Cost (Credit)

 —
 —
 ( 21.2)
 —
 ( 21.2)

 Amortization of Actuarial (Gains) Losses

 —
 —
 5.2
 —
 5.2

 Reclassifications from AOCI, before Income Tax (Expense) Benefit

 72.2
 ( 16.0)
 —
 53.8

 15.0
 —
 11.2

 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit

 57.2
 —
 42.6

 Reclassifications of KPCo Pension and OPEB Regulatory Assets from AOCI, before Income Tax (Expense) Benefit
 —
 —
 —
 21.1
 21.1

 —
 —
 —
 4.4
 4.4

 Reclassifications of KPCo Pension and OPEB Regulatory Assets from AOCI, Net of Income Tax (Expense) Benefit
 —
 —
 —
 16.7
 16.7

 Net Current Period Other Comprehensive Income (Loss)

 ( 118.6)
 ( 8.4)
 0.4
 ( 139.2)

 Balance in AOCI as of December 31, 2023
 $
 104.9
 $
 $
 92.6
 $
 ( 244.9)
 $
 ( 55.5)

 Cash Flow Hedges
 Pension and OPEB

 For the Year Ended December 31, 2022
 Amortization of Deferred Costs
 Changes in Funded Status
 Total

 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
 —
 ( 155.4)
 340.3

 Amount of (Gain) Loss Reclassified from AOCI

 Generation & Marketing Revenues (a)
 0.1
 —
 —
 —
 0.1

 Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)

 ( 528.6)
 —
 —
 —
 ( 528.6)

 Interest Expense (a)

 —
 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)

 ( 111.0)
 0.8
 —
 ( 113.0)

 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit

 ( 417.5)
 3.2
 —
 ( 424.7)

 Reclassifications of KPCo Pension and OPEB Regulatory Assets to AOCI, before Income Tax (Expense) Benefit
 —
 —
 —
 ( 21.1)
 ( 21.1)

 —
 —
 —

 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
 ( 172.1)
 ( 101.1)

 Balance in AOCI as of December 31, 2022
 $
 223.5
 $
 0.3
 $
 105.2
 $
 ( 245.3)
 $
 83.7

 Cash Flow Hedges
 Pension and OPEB

 For the Year Ended December 31, 2021
 Amortization of Deferred Costs
 Changes in Funded Status
 Total

 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
 —
 27.5
 536.8

 Amount of (Gain) Loss Reclassified from AOCI

 Generation & Marketing Revenues (a)
 0.7
 —
 —
 —
 0.7

 Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)

 ( 334.8)
 —
 —
 —
 ( 334.8)

 Interest Expense (a)

 —
 6.5
 —
 —
 6.5

 Amortization of Prior Service Cost (Credit)

 —
 —
 —

 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)

 ( 70.2)
 1.4
 —
 ( 71.0)

 Reclassifications from AOCI, Net of Income Tax (Expense) Benefit

 ( 263.9)
 5.1
 —
 ( 266.9)

 Net Current Period Other Comprehensive Income (Loss)

 224.3
 26.2
 27.5
 269.9

 Balance in AOCI as of December 31, 2021
 $
 163.7
 $
 ( 21.3)
 $
 115.6
 $
 ( 73.2)
 $
 184.8

 (a) Amounts reclassified to the referenced line item on the statements of income.

 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, 2023, AEP Texas' cumulative revenues from interim base rate increases that are subject to a prudency review is approximately $ 987 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)

 2020-2022 Virginia Triennial Review

 In March 2023, APCo submitted its 2020-2022 Virginia triennial review filing and base rate case with the Virginia SCC as required by state law. APCo requested a $ 213 million annual increase in Virginia base rates based upon a proposed 10.6 % return on common equity. The requested annual increase includes $ 47 million related to vegetation management and a $ 35 million increase in depreciation expense. The requested increase in depreciation expense reflects, among other things, the impacts of incremental investments made since APCo's last depreciation study using property balances as of December 31, 2022. Effective January 1, 2023 and in accordance with past Virginia SCC directives, APCo implemented updated Virginia depreciation rates. APCo's proposed revenue requirement also includes the recovery of certain costs incurred that partially contributed to APCo's calculated earnings shortfall for the 2020-2022 triennial 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 certain categories of costs, including system restoration costs for severe weather events.

 In August 2023, APCo, Virginia Staff and intervening parties reached a settlement agreement that included the following: (a) a $ 127 million annual increase in Virginia base rates, (b) a 9.5 % ROE, (c) updated depreciation rates that reflect a 2040 Amos Plant retirement date, (d) approval of a regulatory asset, including tax gross-up, to be recovered over three years starting in 2024 related to major storm expenses incurred during the 2020-2022 triennial period when APCo under-earned in Virginia, (e) approval of the revenue requirement impact of net operating loss carryforward related to income taxes and approval of deferral authority for corporate alternative minimum taxes incurred and (f) approval of the revenue requirement impact of an increase in vegetation management costs with certain costs subject to over-/under-recovery accounting. In November 2023, the Virginia SCC issued a final order approving the settlement agreement as described above with new rates taking effect in January 2024.

 ENEC (Expanded Net Energy Cost) Filings

 In April 2023, APCo and WPCo (the Companies) submitted their 2023 annual ENEC filing with the WVPSC, proposing two alternatives to increase ENEC rates effective September 1, 2023 and to resolve the Companies' open 2021 and 2022 ENEC filings. The first alternative was a $ 293 million annual increase in ENEC rates comprised of an $ 89 million increase for current year ENEC expense and a $ 200 million annual increase for the recovery of the Companies' February 28, 2023 ENEC under-recovery balances over three years, including debt and equity carrying costs. The second alternative was an $ 89 million annual increase in ENEC rates with the Companies securitizing approximately $ 1.9 billion of assets, including: (a) $ 553 million relating to ENEC under-recoveries as of February 28, 2023, (b) $ 88 million relating to major storm expense deferrals and (c) $ 1.2 billion relating to APCo's West Virginia jurisdictional book values of the Amos and Mountaineer Plants and forecasted CCR and ELG investments at these generating facilities.

 In September 2023, the WVPSC issued an order on the 2023 ENEC filing approving an $ 89 million annual increase in ENEC surcharge rates for the Companies' forecasted costs for the period September 2023 through August 2024.

 In January 2024, the WVPSC issued an order resolving the Companies' 2021-2023 ENEC cases. In the order, the WVPSC: (a) disallowed $ 232 million in ENEC under-recovered costs as of February 28, 2023 ($ 136 million related to APCo) and (b) approved the recovery of $ 321 million of ENEC under-recovered costs as of February 28, 2023 ($ 174 million related to APCo) plus a 4 % carrying charge rate over a ten-year recovery period starting September 1, 2024. As of December 31, 2023, the Companies' financial statements reflect the impact of the disallowance. In February 2024, the Companies filed briefs with the

 West Virginia Supreme Court to initiate an appeal of this order. The Companies will submit their annual ENEC update filing with the WVPSC in the second quarter of 2024 proposing that updated ENEC rates become effective September 1, 2024.

 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, 2023, AEP's share of ETT's cumulative revenues that are subject to a prudency review is approximately $ 1.7 billion. A base rate review could produce a refund to customers if ETT incurs a disallowance of the transmission investment on which an interim increase was based. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. ETT is required to file for a comprehensive rate review no later than February 1, 2025, during which the $ 1.7 billion of cumulative revenues above will be subject to review.

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

 Michigan Power Supply Cost Recovery (PSCR)

 In April 2023, I&M received intervenor testimony in I&M's 2021 PSCR Reconciliation for the 12-month period ending December 31, 2021, recommending disallowances of purchased power costs of $ 18 million associated with the OVEC Inter-Company Power Agreement (ICPA) and the UPA with AEGCo that were alleged to be above market in applying the MPSC's Code of Conduct rules. Michigan staff submitted testimony in I&M's 2021 PSCR Reconciliation with no recommended disallowances for PSCR costs incurred, including those associated with the OVEC ICPA and the AEGCo UPA. Michigan staff also recommended several options to address I&M's shortfall in achieving Michigan's annual one percent energy waste reduction savings level, resulting in potential future disallowed costs of up to approximately $ 14 million. In June 2023, Michigan staff submitted rebuttal testimony to update their calculation of the 2021 market proxy price resulting in a recommended disallowance of approximately $ 1 million related to the OVEC ICPA.

 In January 2024, I&M received staff testimony in I&M's 2022 PSCR Reconciliation for the 12-month period ending December 31, 2022 recommending disallowances of purchased power costs of $ 2 million associated with the OVEC ICPA that were alleged to be above market in applying the MPSC's Code of Conduct rules. Similar to the 2021 PSCR Reconciliation, Michigan staff also recommended several options to address I&M's shortfall in achieving Michigan's annual one percent energy waste reduction savings level, resulting in potential future disallowed costs of up to approximately $ 6 million.

 MPSC orders on I&M's 2021 and 2022 PSCR Reconciliations are expected in the first half of 2024. If any PSCR costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

 2023 Indiana Base Rate Case

 In August 2023, I&M filed a request with the IURC for a $ 116 million annual increase in Indiana base rates based upon a 2024 forecasted test year, a proposed 10.5 % ROE and a proposed capital structure of 48.8 % debt and 51.2 % common equity. I&M proposed that the annual increase in base rates be implemented in two steps, with the first increase effective in mid-2024, following an IURC order, and the second increase effective in January 2025. The proposed annual increase includes a $ 41 million increase related to depreciation expense, driven by increased depreciation rates and increased capital investments, and a $ 15 million increase related to storm expenses. I&M's Indiana base case filing requests recovery of certain historical period regulatory asset balances and proposes deferral accounting for certain future investments and tax related issues, including corporate alternative minimum tax expense and PTCs related to the Cook Plant.

 In December 2023, I&M and intervenors reached a settlement agreement that was submitted to the IURC recommending a two-step increase in Indiana rates with a $ 28 million annual increase effective upon an IURC order and the remaining $ 34 million annual increase effective in January 2025. The recommended revenue increase includes: (a) a 9.85 % ROE, (b) a two-step update of I&M's capital structure with a capital structure of 50 % for both debt and common equity effective upon an IURC order and I&M will submit an updated capital structure in January 2025 with the common equity component adjusted to no more than 51.2 %, (c) a $ 25 million increase related to depreciation expense and (d) an $ 11 million increase related to storm expenses.

 A hearing was held in January 2024 and an order is expected in the second quarter of 2024. If any costs included in this filing are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

 2023 Michigan Base Rate Case

 In September 2023, I&M filed a request with the MPSC for a $ 34 million annual increase in Michigan base rates based upon a 2024 forecasted test year, a proposed 10.5 % ROE and a capital structure of 49.4 % debt and 50.6 % common equity. The proposed annual increase includes an $ 11 million annual increase in depreciation expense driven by increased capital investment. I&M's Michigan base case filing requests recovery of certain historical period regulatory asset balances and proposes deferral accounting for certain future investments and tax related issues, including corporate alternative minimum tax expense and PTCs related to the Cook Plant.

 In January 2024, Michigan Staff and various intervenors submitted testimony recommending changes in base rates ranging from a $ 6 million annual decrease to a $ 19 million annual increase. These changes are based on ROEs ranging from 9.7 % to 9.9 % and capital structures ranging from 49.4 % debt and 50.6 % equity to 52 % debt and 48 % equity. Intervenors also proposed in testimony certain disallowances related to existing regulatory assets totaling approximately $ 5 million, the exclusion of CAMT from any future deferrals and the prospective inclusion of PTCs related to the Cook Plant in I&M's PSCR.

 A hearing was held in February 2024. If any costs included in this filing are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

 KPCo Rate Matters (Applies to AEP)

 Investigation of the Service, Rates and Facilities of KPCo

 In June 2023, the KPSC issued an order directing KPCo to show cause why it should not be subject to Kentucky statutory remedies, including fines and penalties, for failure to provide adequate service in its service territory. The KPSC's show cause order did not make any determination regarding the adequacy of KPCo's service. In July 2023, KPCo filed a response to the show cause order demonstrating that it has provided adequate service. In December 2023 and February 2024, KPCo and certain intervenors filed testimony with the KPSC. In February 2024, KPCo filed a motion to strike and exclude intervenor testimony in its entirety on the grounds that issues raised are outside the scope of the proceeding and because the testimony is largely unreasoned, unsupported, and provides no evidentiary value. A hearing is expected in 2024. If any fines or penalties are levied against KPCo relating to the show cause order, it could reduce net income and cash flows and impact financial condition.

 2023 Kentucky Base Rate and Securitization Case

 In June 2023, KPCo filed a request with the KPSC for a $ 94 million net annual increase in base rates based upon a proposed 9.9 % ROE with the increase to be implemented no earlier than January 2024. The filing proposes no changes in depreciation rates and an annual level of storm restoration expense in base rates of approximately $ 1 million. KPCo also proposed to discontinue tracking of PJM transmission costs through a rider, and to instead collect an annual level of costs through base rates. In addition, KPCo has proposed a rider to recover certain distribution reliability investments and related incremental operation and maintenance expenses. KPCo also requested a prudency determination and recovery mechanism for approximately $ 16 million of purchased power costs not recoverable through its FAC since its last base case. KPCo's proposal did not address the disposition of its 50 % interest in Mitchell Plant, which will be addressed in the future. As of December 31, 2023, the net book value of KPCo's share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $ 553 million. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

 In conjunction with its June 2023 filing, KPCo further requested to finance, through the issuance of securitization bonds, approximately $ 471 million of regulatory assets recorded as of June 2023 including: (a) $ 289 million of plant retirement costs, (b) $ 79 million of deferred storm costs related to 2020, 2021, 2022 and 2023 major storms, (c) $ 52 million of deferred purchased power expenses and (d) $ 51 million of under-recovered purchased power rider costs. Plant retirement costs and deferred purchased power expenses have been deemed prudent in prior KPSC decisions. KPCo has requested a prudency determination in this proceeding for the deferred storm costs and under-recovered purchase power rider costs since the last base case.

 In November 2023, KPCo filed an uncontested settlement agreement with the KPSC, that included an annual base rate increase of $ 75 million, based upon a 9.75 % ROE. Settlement parties agreed that the KPSC should approve KPCo's securitization request, and that the approximately $ 471 million regulatory assets requested for securitization are comprised of prudently incurred costs. The settlement does not modify KPCo's proposal to discontinue tracking of PJM transmission costs through a

 rider, and to instead collect an annual level of costs through base rates. The settlement approved KPCo's request to implement a rider to recover certain distribution reliability investments. Under the terms of the settlement, KPCo agreed to forgo recovery of approximately $ 16 million of purchased power costs not recoverable through the FAC since KPCo's last base case and excluded a return on its stand-alone NOLC deferred tax asset from the base rate revenue requirement while it seeks a private letter ruling from the IRS. Other differences between KPCo's requested annual base rate increase and the uncontested settlement agreement are primarily due to exclusion of certain employee-related expenses from the revenue requirement.

 In January 2024, consistent with the November 2023 uncontested settlement agreement, the KPSC issued a financing order approving KPCo's securitization request and concluding that costs requested for recovery were prudently incurred. The KPSC's financing order includes certain additional requirements related to securitization bond structuring, marketing, placement, and issuance that were not reflected in KPCo's proposal. As a result, in January 2024, KPCo filed a request for rehearing with the KPSC to clarify certain aspects of these additional requirements. In February 2024, the KPSC denied KPCo's rehearing requests. In accordance with Kentucky statutory requirements and the financing order, the issuance of the securitized bonds is subject to final review by the KPSC after bond pricing. KPCo expects to proceed with the securitized bond issuance process and to complete the securitization process in the second half of 2024, subject to market conditions. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

 In January 2024, the KPSC issued an order modifying the November 2023 uncontested settlement agreement and approving an annual base rate increase of $ 60 million based upon a 9.75 % ROE effective with billing cycles mid-January 2024. The order reduced KPCo's base rate revenue requirement by $ 14 million to allow recovery of actual test year PJM transmission costs instead of KPCo's requested annual level of costs based on PJM 2023 projected transmission revenue requirements. The KPSC denied implementation of a rider to recover certain distribution reliability investments. In February 2024, KPCo filed an appeal with the Commonwealth of Kentucky Franklin Circuit Court, challenging among other aspects of the order the $ 14 million base rate revenue requirement reduction.

 Fuel Adjustment Clause (FAC) Review

 In December 2023, KPCo received intervenor testimony in its FAC review for the two-year period ending October 31, 2022, recommending a disallowance ranging from $ 44 million to $ 60 million of its total $ 432 million purchased power cost recoveries as a result of proposed modifications to the ratemaking methodology that limits purchased power costs recoverable through the FAC. A hearing was held in February 2024. If any fuel costs are not recoverable or refunds are ordered, it could reduce future net income and cash flows and impact financial condition.

 Rockport Offset Recovery

 In January 2024, KPCo filed an application with the KPSC seeking to recover an allowed cost (Rockport Offset) of $ 41 million in accordance with the terms of the settlement agreement in the 2017 Kentucky Base Rate Case permitting KPCo to use the level of non-fuel, non-environmental Rockport Plant UPA expense included in base rates to earn its authorized ROE in 2023 since the Rockport UPA ended in December 2022. An estimated Rockport Offset of $ 23 million was recovered through a rider, subject to true-up, during the 12-months ended December 2023. KPCo is requesting to recover the remaining $ 18 million Rockport Offset true-up over a 12-month period beginning March 2024, also through a rider. The Rockport Offset true-up is not yet reflected in revenue, as KPCo has not met the requirements of alternative revenue recognition in accordance with the accounting guidance for "Regulated Operations". In February 2024, the KPSC issued an order allowing KPCo to collect the remaining $ 18 million through interim rates, subject to refund, over twelve months starting in March 2024. Intervenor testimony is expected in April 2024 and an order is expected in the second quarter of 2024. If the Rockport Offset is not recoverable or refunds are ordered, it could reduce future net income and cash flows and impact financial condition.

 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.

 In May 2023, as part of the OVEC cost recovery audits pending before the PUCO, intervenors filed positions claiming that costs incurred by OPCo during the 2020 audit period were imprudent and should be disallowed. A hearing was held in November 2023.

 Management disagrees with these claims and is unable to predict the impact of these disputes. If any costs are disallowed or refunds are ordered, 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. In June 2023, intervenors filed testimony opposing OPCo's plan for various new riders and modifications to existing riders, including the DIR. In September 2023, OPCo and certain intervenors filed a settlement agreement with the PUCO addressing the ESP application. The settlement included a four year term from June 2024 through May 2028, an ROE of 9.7 % and continuation of a number of riders including the DIR subject to revenue caps. An order from the PUCO is expected in the first quarter of 2024. 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 an annual base rate increase of $ 294 million based upon a 10.4 % ROE with a capital structure of 45.4 % debt and 54.6 % common equity. The requested $ 294 million annual base rate increase, net of existing rider revenues and certain incremental renewable facility benefits expected to be provided to customers through riders, represented a requested annual increase in rates of $ 173 million and included 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 included recovery of the 155 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 November 2023, the OCC issued a final order approving an annual base rate increase of $ 131 million based upon a 9.3 % ROE. As a result of the final order, PSO is required to exclude Rock Falls Wind Facility from recovery through base rates until a future base case since the facility was placed into service for PSO customers after the conclusion of the customary six-month post-test year period for ratemaking adjustments. In addition, PSO must provide Rock Falls Wind Facility benefits in excess of $ 21 million on an annual basis to customers through a rider. The order also stipulates PSO's proposals related to inclusion of a stand-alone NOLC deferred tax asset in rate base will be addressed in a future proceeding, upon receipt of a private letter ruling from the IRS. Effective January 2024, interim rates implemented in May 2023 concluded and updated rates and tariffs were implemented in accordance with the final order. In January 2024, refund of the $ 18 million interim rate over collection began and will be competed no later than April 2024, in compliance with the final order. In December 2023, PSO appealed certain elements of the OCC's final order to the Supreme Court of the State of Oklahoma.

 2024 Oklahoma Base Rate Case

 In January 2024, PSO filed a request with the OCC for a $ 218 million annual base rate increase based upon a 10.8 % ROE with a capital structure of 48.9 % debt and 51.1 % common equity. PSO requested an expanded transmission cost recovery rider and a mechanism to recover generation costs necessary to comply with SPP's 2023 increased capacity planning reserve margin requirements. PSO's request reflects recovery of Northeastern Plant, Unit 3 through 2040.

 SWEPCo Rate Matters (Applies to AEP and SWEPCo)

 2012 Texas Base Rate Case

 In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant's Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo's recovery of AFUDC in addition to limits on its recovery of cash construction costs.

 Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant's Texas jurisdictional capital cost cap. As a result, SWEPCo reversed $ 114 million of a previously recorded regulatory disallowance in 2013. In 2017, the Texas District Court upheld the PUCT's 2014 order and intervenors filed appeals with the Texas Third Court of Appeals.

 In 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. In November 2021, SWEPCo and the PUCT submitted Petitions for Review with the Texas Supreme Court. 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. In June 2023, the Texas Supreme Court denied SWEPCo's request for rehearing and the case was remanded to the PUCT for future proceedings. In October 2023, SWEPCo filed testimony with the PUCT in the remanded proceeding recommending no refund or disallowance.

 On December 14, 2023, the PUCT approved a preliminary order stating the PUCT will not address SWEPCo's request that would allow the PUCT to find cause to allow SWEPCo to exceed the Texas jurisdictional capital cost cap in the current remand proceeding. As a result of the PUCT's approval of the preliminary order, SWEPCo believes it is probable the PUCT will disallow capitalized AFUDC in excess of the Texas jurisdictional capital cost cap and recorded a pretax, non-cash disallowance of $ 86 million in the fourth quarter of 2023. Such determination may reduce SWEPCo's future revenues by approximately $ 15 million on an annual basis. On December 21, 2023, SWEPCo filed a motion with the PUCT for reconsideration of the preliminary order. In January 2024, the PUCT denied the motion for reconsideration of the preliminary order.

 The PUCT's December 2023 approval of the preliminary order determined that it will address, in the ongoing PUCT remand proceeding, any potential revenue refunds to customers that may be required by future PUCT orders. In January 2024, the PUCT established a procedural schedule for the remand proceeding. Supplemental testimony from SWEPCo is due in March 2024, intervenor and staff testimony is due in April 2024 and a hearing is scheduled for May 2024. Although SWEPCo does not currently believe any refunds are probable of occurring, SWEPCo estimates it could be required to make customer refunds, including interest, ranging from $ 0 to $ 200 million related to revenues collected from February 2013 through December 2023.

 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. 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.

 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) 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 Louisiana 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. In September 2023, an order was received from the LPSC directing SWEPCo to seek a private letter ruling from the IRS to address the matter.

 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 March 2023, SWEPCo and the LPSC staff filed a joint stipulation and settlement agreement with the LPSC which confirmed the prudency of $ 150 million of deferred incremental storm restoration expenses. The agreement also authorized an interim carrying charge at a rate of 3.125 % until the recovery mechanism is determined in phase two of this proceeding. In April 2023, the LPSC issued an order approving the stipulation and settlement agreement. In July 2023, SWEPCo submitted additional information in phase two of this proceeding to obtain a financing order and prudency review of capital investment. The procedural schedule for this case states that a hearing will take place in the second quarter of 2024.

 February 2021 Severe Winter Weather Impacts in SPP

 In February 2021, 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 shown in the table below:

 Approved
 Approved

 Jurisdiction
 2023
 2022
 Recovery Period
 Carrying Charge

 Arkansas
 $
 54.2
 $
 74.9
 6 years
 (a)

 97.2
 121.7
 (b)
 (b)

 Texas
 101.9
 132.4
 1.65 %

 Total
 $
 253.3
 $
 329.0

 (a)SWEPCo is permitted to record carrying costs on the unrecovered balance of fuel costs at a weighted-cost of capital approved by the APSC. The APSC will conclude an audit of these costs in 2024. A hearing is scheduled for May 2024.
 (b)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 equal to the prime rate. The special order states the fuel and purchased power costs incurred will be subject to a future LPSC audit.

 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.

 FERC Rate Matters

 FERC 2019 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 granting the formal challenge on several issues and denying the formal challenge on other issues. Management has determined that the result of the order had an immaterial impact to the financial statements of AEP, AEPTCo, PSO and SWEPCo. In November 2022, certain joint customers appealed the FERC denial of issues to the U.S. Court of Appeals for the District of Columbia Circuit. In January 2024, the court agreed with the FERC's order and denied the certain joint customers petition for review.

 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 as to state law claims. In December 2023, the United States District Court for the Middle District of Pennsylvania granted summary judgment in favor of Transource Energy, finding that the PAPUC decision violated federal law and the United States Constitution. In January 2024, the PAPUC filed an appeal with the United States Court of Appeals for the Third Circuit. Additional regulatory proceedings before the PAPUC are expected to resume in 2024.

 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, 2023, AEP's share of IEC capital expenditures was approximately $ 93 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 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. In February 2023, in compliance with the FERC's December 2022 order, AEPSC submitted a filing to the FERC to update OPCo and OHTCo 2023 transmission formula rates to exclude the 50 basis point RTO incentive and provide refunds with interest. In April 2023, the FERC approved the updated transmission formula rates for OPCo and OHTCo and issued an Order on Rehearing affirming its December 2022 decision. During 2023, in compliance with FERC's December 2022 order, OPCo and OHTCo provided refunds including interest of $ 5 million and $ 13 million, respectively. This decision has been appealed to the U.S. Court of Appeals for the Sixth Circuit.

 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 the UPA between AEGCo and 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. In August 2023, AEGCo reached a settlement agreement with the FERC Trial Staff that resolves all issues set for hearing. In September 2023, the settlement agreement was certified to the FERC as uncontested. An order from the FERC on this settlement agreement is expected in 2024. If the FERC finalizes the settlement agreement as proposed, management anticipates the results of the order will not have a material impact on financial condition, results of operations or cash flows.

 FERC 2021 PJM and SPP Transmission Formula Rate Challenge (Applies to AEP, AEPTCo, APCo, I&M, PSO and SWEPCo)

 The Registrants transitioned to stand-alone treatment of NOLCs in its PJM and SPP transmission formula rates beginning with the 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 annual revenue requirements for years 2023, 2022 and 2021 by $ 60 million, $ 69 million and $ 78 million, respectively.

 In March 2023 and May 2023, certain joint customers submitted a complaint and a formal challenge at the FERC related to the 2022 Annual Update of the 2021 Transmission Formula Rates of the AEP transmission owning subsidiaries within PJM and SPP, respectively. These challenges primarily relate to stand-alone treatment of NOLCs in the transmission formula rates of the AEP transmission owning subsidiaries. AEPSC, on behalf of the AEP transmission owning subsidiaries within PJM and SPP, filed answers to the joint formal challenge and complaint with the FERC in the second quarter of 2023.

 In January 2024, the FERC issued two orders, granting the joint customers' challenges related to stand-alone treatment of NOLCs in the 2021 Transmission Formula Rates of the AEP transmission owning subsidiaries within PJM and SPP. The FERC directed the AEP transmission owning subsidiaries within PJM and SPP to provide refunds with interest on all amounts collected for the 2021 rate year, and for such refunds to be reflected in the annual update for the next rate year. In February 2024, AEPSC on behalf of the AEP transmission owning subsidiaries within PJM and SPP filed requests with the FERC that it grant rehearing and reverse findings in its January 2024 orders or establish hearing procedures to address outstanding factual issues.

 As a result of the January 2024 FERC orders, the Registrants' 2022 and 2023 income statements cumulatively reflect a provision for refund for the probable refund of all NOLC revenues included in transmission formula rates for years 2023, 2022 and 2021. The probable refunds to affiliated and nonaffiliated customers are reflected as Deferred Credits and Other Noncurrent Liabilities on the balance sheets. Refunds probable to be received by affiliated companies, resulting in a reduction to affiliated transmission expense, were deferred as an increase to Regulatory Liabilities or a reduction to Regulatory Assets on the balance sheets where management expects that refunds would be returned to retail customers through authorized retail jurisdiction rider mechanisms. The FERC directed cash refunds with interest related to the 2021 rate year to occur through the annual update for the next rate year, which will be invoiced by PJM and SPP primarily in 2025. The Registrants have not yet been directed to make cash refunds related to the 2022 or 2023 rate years.

 The FERC's January 2024 orders reduced AEP and AEPTCo's 2023 pretax net income by approximately $ 76 million and $ 74 million, respectively. The impact of the FERC's orders on the pretax net income of AEP's remaining Registrant Subsidiaries was not material.

 Request to Update SWEPCo Generation Depreciation Rates (Applies to AEP and SWEPCo)

 In October 2023, SWEPCo filed an application to revise its generation wholesale customer's contracts to reflect an increase in the annual revenue requirement of approximately $ 5 million for updated depreciation rates and allow for the return on and of FERC customers jurisdictional share of regulatory assets associated with retired plants. In November 2023, certain intervenors filed a motion with the FERC protesting and recommending the rejection of SWEPCo's filings. In December 2023, the FERC issued an order approving the proposed rates effective January 1, 2024, subject to further review and refund and established hearing and settlement proceedings. If SWEPCo is unable to recover the remaining regulatory assets associated with retired plants, it could reduce future net income and cash flows and impact financial condition.

 5. EFFECTS OF REGULATION

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

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

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

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

 Regulated Generating Units that have been Retired

 In 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" and "2020 Louisiana Base Rate Case" sections of Note 4 for additional information.

 In March 2023, the Pirkey Plant was retired. As part of the 2020 Louisiana Base Rate Case, the LPSC authorized the recovery of SWEPCo's Louisiana jurisdictional share of the Pirkey Plant, through a separate rider, through 2032. As part of the 2021 Arkansas Base Rate Case, the APSC granted SWEPCo regulatory asset treatment. SWEPCo will request recovery including a weighted average cost of capital carrying charge through a future proceeding. In July 2023, Texas ALJs issued a proposal for decision that concluded the decision to retire the Pirkey Plant was prudent. In September 2023, the PUCT rejected the ALJs proposal for decision concluding the retirement of the Pirkey Plant was prudent. In the open meeting, the commissioners expressed their concerns that the analysis in support of SWEPCo's decision to retire the Pirkey Plant was not robust enough and that SWEPCo should have re-evaluated the decision following Winter Storm Uri. The treatment of the cost of recovery of the Pirkey Plant is expected to be addressed in a future rate case. As of December 31, 2023, the Texas jurisdictional share of the net book value of the Pirkey Plant was $ 67 million. To the extent any portion of the Texas jurisdictional share of the net book value of the Pirkey Plant is not recoverable, it could reduce future net income and cash flows and impact financial condition.

 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 2022 Oklahoma Base Rate Case, PSO will continue to recover Northeastern Plant, Unit 3 through 2040.

 In November 2020, management announced 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, 2023, 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)

 Northeastern Plant, Unit 3
 $
 104.5
 $
 164.2
 $
 20.5
 (b)
 2026
 (c)
 $
 15.0

 Welsh Plant, Units 1 and 3
 352.0
 125.6
 58.2
 (d)
 2028
 (e)
 (f)
 38.6

 (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 the removal of Northeastern Plant, Unit 3, after retirement.
 (c) Northeastern Plant, Unit 3 is currently being recovered through 2040.
 (d) Includes Welsh Plant, Unit 2, which was retired in 2016. Removal of Welsh Plant, Unit 2, will be performed with the removal of Welsh Plant, Units 1 and 3, after retirement.
 (e) Represents projected retirement date of coal assets, units are being evaluated for conversion to natural gas after 2028.
 (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)

 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, 2023, SWEPCo's share of the net investment in the Dolet Hills Power Station was $ 103 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, 2023, SWEPCo had a net under-recovered fuel balance of $ 77 million, inclusive of costs related to the 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 $ 35 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 up to $ 55 million, including denial of recovery of the $ 35 million deferral, with refunds to customers over five years. In February 2024, an ALJ issued a final recommendation which included a proposed $ 55 million refund to customers and the denial of recovery of the $ 35 million deferral. SWEPCo filed a motion to present oral arguments with the LPSC to dispute the ALJ's recommendations. Management believes its financial statements adequately address the impact of the LPSC staff and ALJ recommendations. A decision from the LPSC is expected in the first quarter of 2024.

 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 September 2023, the PUCT approved an unopposed settlement agreement that provides recovery of $ 48 million of Oxbow mine related costs through 2035.

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

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

 In March 2023, the Pirkey Plant was retired. SWEPCo is recovering, or will seek recovery of, the remaining net book value of Pirkey Plant non-fuel costs. As of December 31, 2023, SWEPCo's share of the net investment in the Pirkey Plant was $ 182 million, including materials and supplies, net of cost of removal. See the "Regulated Generating Units that have been Retired" section above for additional information. Fuel costs are recovered through active fuel clauses and are subject to prudency determinations by the various commissions. As of March 31, 2023, SWEPCo fuel deliveries, including billings of all fixed costs, from Sabine ceased. Additionally, as of December 31, 2023, SWEPCo had a net under-recovered fuel balance of $ 77 million, inclusive of costs related to the Pirkey Plant billed by Sabine, but excluding impacts of the February 2021 severe winter weather event. Remaining operational, reclamation and other land-related costs incurred by Sabine will be billed to SWEPCo and included in existing fuel clauses.

 In July 2023, the LPSC ordered that a separate proceeding be established to review the prudence of the decision to retire the Pirkey Plant, including the costs included in fuel for years starting in 2019 and after. In September 2023, the PUCT approved an unopposed settlement agreement that provides recovery of $ 33 million of Sabine related fuel costs through 2035.

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

 Regulatory Assets and Liabilities

 Regulatory assets and liabilities are comprised of the following items:

 AEP

 Remaining Recovery Period

 2023
 2022

 Under-recovered Fuel Costs - earns a return
 $
 357.4
 $
 625.7

 Under-recovered Fuel Costs - does not earn a return
 62.7
 588.5

 Unrecovered Winter Storm Fuel Costs - earns a return (a)
 93.9
 95.8

 $
 514.0
 $
 1,310.0

 Welsh Plant, Units 1 and 3 Accelerated Depreciation
 $
 125.6
 $
 85.6

 Pirkey Plant Accelerated Depreciation
 114.4
 116.5

 Unrecovered Winter Storm Fuel Costs (a)
 60.1
 84.6

 49.8
 68.9

 349.9
 355.6

 408.9
 407.1

 2020-2022 Virginia Triennial Under-Earnings
 —
 37.9

 78.5
 81.5

 487.4
 526.5

 837.3
 882.1

 Plant Retirement Costs - Unrecovered Plant (b)
 664.2
 689.9
 23 years

 Long-term Under-recovered Fuel Costs - West Virginia
 291.5
 —
 11 years

 170.9
 8.4

 Plant Retirement Costs - Asset Retirement Obligation Costs
 110.8
 110.6
 19 years

 Long-term Under-recovered Fuel Costs - Virginia
 107.0
 223.3

 Unrecovered Winter Storm Fuel Costs (a)
 99.3
 148.6

 Fuel Mine Closure Costs - Texas
 74.3
 —

 Pirkey Plant Accelerated Depreciation - Louisiana
 65.8
 63.0

 Rockport Plant Dry Sorbent Injection System and Selective Catalytic Reduction
 46.9
 56.6

 Kentucky Deferred Purchased Power Expenses
 43.5
 53.0

 Ohio Basic Transmission Cost Rider
 42.2
 14.3

 Plant Retirement Costs - Unrecovered Plant, Dolet Hills Power Station, Louisiana
 40.8
 45.1

 Texas Mobile Temporary Emergency Electric Energy Facilities Rider
 33.4
 —

 Environmental Control Projects
 31.4
 33.9
 17 years

 Meter Replacement Costs
 23.5
 34.2

 Long-term Under-recovered Fuel Costs - Oklahoma
 —
 252.7

 101.4
 125.0

 1,946.9
 1,858.6

 1,054.1
 975.4

 Plant Retirement Costs - Asset Retirement Obligation Costs
 330.2
 308.5
 19 years

 131.4
 40.1

 Unamortized Loss on Reacquired Debt
 97.2
 104.1
 25 years

 Fuel and Purchased Power Adjustment Rider
 68.3
 76.3

 Cook Plant Nuclear Refueling Outage Levelization
 55.7
 81.2

 OVEC Purchased Power
 50.1
 —

 Plant Retirement Costs - Unrecovered Plant, Texas
 48.7
 51.7
 23 years

 38.5
 11.9

 2020-2022 Virginia Triennial Under Earnings
 37.4
 —

 Ohio Enhanced Service Reliability Plan
 35.3
 33.3

 Ohio Distribution Investment Rider
 35.3
 2.3

 Postemployment Benefits
 30.6
 32.1

 Peak Demand Reduction/Energy Efficiency
 23.9
 41.7

 271.5
 262.7

 2,308.2
 2,021.3

 4,255.1
 3,879.9

 $
 5,092.4
 $
 4,762.0

 (a) See "February 2021 Severe Winter Weather Impacts in SPP" section of SWEPCo Rate Matters in Note 4 for additional information.
 (b) 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.

 AEP

 2023
 2022
 Refund Period

 Current Regulatory Liabilities

 Over-recovered Fuel Costs - pays a return
 $
 3.3
 $
 1.4

 Over-recovered Fuel Costs - does not pay a return
 23.2
 —

 Total Current Regulatory Liabilities
 $
 26.5
 $
 1.4

 $
 103.1
 $
 149.7

 103.1
 149.7

 103.1
 —

 Other Regulatory Liabilities Pending Final Regulatory Determination
 1.7
 4.1

 104.8
 4.1

 207.9
 153.8

 3,563.5
 3,392.4
 (b)

 2,179.7
 2,504.5
 (c)

 Rockport Plant, Unit 2 Accelerated Depreciation for Leasehold Improvements
 44.9
 53.8

 35.0
 32.7

 5,823.1
 5,983.4

 Excess Nuclear Decommissioning Funding
 1,721.9
 1,318.5
 (d)

 154.5
 237.3
 31 years

 Spent Nuclear Fuel
 47.6
 45.8
 (d)

 2017-2019 Virginia Triennial Revenue Provision
 37.1
 39.1
 26 years

 Demand Side Management
 31.3
 15.7

 Over-recovered Fuel Costs - Ohio
 26.1
 32.2

 PJM Transmission Enhancement Refund
 22.8
 34.1

 PJM Costs and Off-system Sales Margin Sharing - Indiana
 14.1
 34.2

 OVEC Purchased Power
 —
 47.1

 Unrealized Gain on Forward Commitments
 —
 45.2

 96.0
 129.2

 2,151.4
 1,978.4

 7,974.5
 7,961.8

 $
 8,182.4
 $
 8,115.6

 (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 $ 228 million and $ 277 million for the years ended December 31, 2023 and 2022, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2023 is to be refunded over 5 years.
 (d) Relieved when plant is decommissioned.

 2023
 2022

 Texas Mobile Generation Lease Payments
 $
 —
 $
 17.6

 —
 17.6

 37.7
 26.7

 Line Inspection Costs
 5.7
 4.5

 Vegetation Management Program
 5.2
 5.2

 Texas Retail Electric Provider Bad Debt Expense
 4.0
 4.1

 11.7
 8.9

 64.3
 49.4

 64.3
 67.0

 Texas Mobile Temporary Emergency Electric Energy Facilities Rider
 33.4
 —

 Meter Replacement Costs
 9.4
 16.1

 0.7
 1.4

 43.5
 17.5

 183.2
 173.2

 Peak Demand Reduction/Energy Efficiency
 9.2
 11.9

 Vegetation Management Program
 6.8
 12.1

 4.3
 8.5

 4.0
 8.1

 207.5
 213.8

 251.0
 231.3

 $
 315.3
 $
 298.3

 2023
 2022

 $
 13.0
 $
 13.0

 13.0
 13.0

 Other Regulatory Liabilities Pending Final Regulatory Determination
 1.5
 1.8

 1.5
 1.8

 14.5
 14.8

 797.1
 766.8
 (b)

 412.0
 431.6
 (c)

 3.8
 4.3

 1,212.9
 1,202.7

 Transition and Restoration Charges
 26.6
 29.4
 6 years

 7.4
 12.7

 34.0
 42.1

 1,246.9
 1,244.8

 $
 1,261.4
 $
 1,259.6

 (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.

 2023
 2022

 PJM/SPP Annual Formula Rate True-up
 $
 3.1
 $
 7.2

 3.1
 7.2

 $
 3.1
 $
 7.2

 2023
 2022

 Noncurrent Regulatory Liabilities

 $
 8.7
 $
 8.7

 8.7
 8.7

 466.3
 358.8
 (b)

 308.7
 355.8
 (c)

 775.0
 714.6

 Total Noncurrent Regulatory Liabilities
 $
 783.7
 $
 723.3

 (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 $ 13 million and $ 16 million for the years ended December 31, 2023 and 2022, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2023 is to be refunded over 5 years.

 APCo

 2023
 2022

 Under-recovered Fuel Costs - earns a return
 $
 147.4
 $
 180.7

 Under-recovered Fuel Costs - does not earn a return
 8.0
 292.4

 $
 155.4
 $
 473.1

 $
 0.6
 $
 7.0

 0.6
 7.0

 Storm-Related Costs - West Virginia
 91.5
 72.6

 Plant Retirement Costs - Asset Retirement Obligation Costs
 25.9
 25.9

 2020-2022 Virginia Triennial Under-Earnings
 —
 37.9

 7.5
 1.1

 124.9
 137.5

 125.5
 144.5

 Long-term Under-recovered Fuel Costs - West Virginia
 154.2
 —
 11 years

 Long-term Under-recovered Fuel Costs - Virginia
 107.0
 223.3

 Plant Retirement Costs - Unrecovered Plant
 72.0
 75.6
 20 years

 7.1
 0.4

 340.3
 299.3

 Plant Retirement Costs - Asset Retirement Obligation Costs
 324.7
 303.1
 15 years

 115.8
 108.3

 Unamortized Loss on Reacquired Debt
 70.7
 74.4
 22 years

 2020-2022 Virginia Triennial Under-Earnings
 37.4
 —

 Virginia Transmission Rate Adjustment Clause
 25.5
 18.7

 21.9
 —

 Peak Demand Reduction/Energy Efficiency
 15.0
 15.8

 Postemployment Benefits
 14.9
 13.7

 Vegetation Management Program - West Virginia
 12.9
 13.7

 Excess SO2 Allowance Inventory - Virginia

 11.8
 —

 Virginia Generation Rate Adjustment Clause
 10.9
 8.0

 Virginia Clean Economy Act
 8.0
 16.7

 2017-2019 Virginia Triennial Under-Earnings
 2.3
 30.1

 17.5
 12.3

 689.3
 614.8

 1,029.6
 914.1

 $
 1,155.1
 $
 1,058.6

 APCo

 2023
 2022

 $
 7.9
 $
 30.5

 7.9
 30.5

 19.7
 —

 19.7
 —

 27.6
 30.5

 759.6
 713.5
 (b)

 240.1
 291.3
 (c)

 0.3
 0.3
 30 years

 1,000.0
 1,005.1

 2017-2019 Virginia Triennial Revenue Provision
 37.1
 39.1
 26 years

 Over-recovered Deferred Wind Power Costs - Virginia
 2.6
 13.6

 Unrealized Gain on Forward Commitments
 —
 34.5

 14.6
 20.8

 54.3
 108.0

 1,054.3
 1,113.1

 $
 1,081.9
 $
 1,143.6

 (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 $ 35 million and $ 19 million for the years ended December 31, 2023 and 2022, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2023 is to be refunded over 5 years.

 I&M

 2023
 2022

 Under-recovered Fuel Costs, Michigan - earns a return
 $
 14.8
 $
 9.0

 Under-recovered Fuel Costs, Indiana - does not earn a return
 —
 38.1

 $
 14.8
 $
 47.1

 $
 0.2
 $
 0.1

 0.2
 0.1

 Storm-Related Costs - Indiana
 29.7
 21.6

 3.3
 2.0

 33.0
 23.6

 33.2
 23.7

 Plant Retirement Costs - Unrecovered Plant
 122.5
 147.0

 Rockport Plant Dry Sorbent Injection System and Selective Catalytic Reduction
 46.9
 56.6

 Cook Plant Uprate Project
 22.9
 25.3
 10 years

 Deferred Cook Plant Life Cycle Management Project Costs - Michigan, FERC
 11.1
 12.1
 11 years

 Cook Plant Turbine - Indiana
 8.4
 9.0
 15 years

 17.5
 20.6

 229.3
 270.6

 Cook Plant Nuclear Refueling Outage Levelization
 55.7
 81.2

 25.4
 26.9

 Excess SO2 Allowance Inventory - Indiana

 14.8
 —

 Unamortized Loss on Reacquired Debt
 11.8
 12.9
 25 years

 Environmental Cost Rider - Indiana
 8.1
 6.6

 Postemployment Benefits
 7.0
 7.7

 Demand Side Management - Indiana
 —
 10.3

 21.0
 19.7

 143.8
 165.3

 373.1
 435.9

 $
 406.3
 $
 459.6

 I&M

 2023
 2022

 Current Regulatory Liabilities

 Over-recovered Fuel Costs, Indiana - does not pay a return
 $
 23.2
 $
 —

 Total Current Regulatory Liabilities
 $
 23.2
 $
 —

 Income Taxes, Net (a) (b)
 $
 ( 103.0)
 $
 ( 87.7)

 ( 103.0)
 ( 87.7)

 22.8
 —

 22.8
 —

 ( 80.2)
 ( 87.7)

 168.1
 170.7
 (c)

 116.8
 168.6
 (d)

 Renewable Energy Surcharge - Michigan
 26.6
 23.2

 0.1
 3.0

 311.6
 365.5

 Excess Nuclear Decommissioning Funding
 1,721.9
 1,318.5
 (e)

 Spent Nuclear Fuel
 47.6
 45.8
 (e)

 Demand Side Management - Indiana
 16.7
 —

 15.8
 17.4
 27 years

 PJM Costs and Off-system Sales Margin Sharing - Indiana
 14.1
 34.2

 4.8
 8.5

 1,820.9
 1,424.4

 2,132.5
 1,789.9

 $
 2,052.3
 $
 1,702.2

 (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 $ 25 million and $ 42 million for the years ended December 31, 2023 and 2022, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2023 is to be refunded over 5 years.
 (e) Relieved when plant is decommissioned.

 OPCo

 2023
 2022

 Under-recovered Fuel Costs - does not earn a return
 $
 —
 $
 3.8

 $
 —
 $
 3.8

 $
 23.6
 $
 33.8

 23.6
 33.8

 Ohio Basic Transmission Cost Rider
 42.2
 14.3

 Ohio Distribution Decoupling
 1.8
 19.5

 Ohio Economic Development Rider
 —
 1.1

 44.0
 34.9

 147.1
 142.7

 50.8
 40.0

 OVEC Purchased Power
 50.1
 —

 Ohio Enhanced Service Reliability Plan
 35.3
 33.3

 Ohio Distribution Investment Rider
 35.3
 2.3

 30.9
 —

 Smart Grid Costs
 26.3
 25.4

 11.6
 14.9

 387.4
 258.6

 431.4
 293.5

 $
 455.0
 $
 327.3

 OPCo

 2023
 2022

 $
 57.0
 $
 —

 Other Regulatory Liabilities Pending Final Regulatory Determination
 0.2
 0.2

 57.2
 0.2

 475.5
 466.5
 (a)

 Income Taxes, Net (b)
 408.2
 451.9
 (c)

 883.7
 918.4

 Over-recovered Fuel Costs
 26.1
 32.2

 Peak Demand Reduction/Energy Efficiency
 23.2
 23.6

 PJM Transmission Enhancement Refund
 9.8
 14.7

 OVEC Purchased Power
 —
 47.1

 3.6
 7.8

 62.7
 125.4

 946.4
 1,043.8

 $
 1,003.6
 $
 1,044.0

 (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 $ 132 million and $ 162 million for the years ended December 31, 2023 and 2022, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2023 is to be refunded over 5 years.

 PSO

 2023
 2022

 Under-recovered Fuel Costs - earns a return
 $
 118.3
 $
 178.7

 $
 118.3
 $
 178.7

 $
 88.5
 $
 25.5

 0.2
 0.1

 88.7
 25.6

 Plant Retirement Costs - Unrecovered Plant (a)
 254.1
 240.6
 23 years

 26.2
 8.4

 Environmental Control Projects
 22.5
 23.9
 17 years

 Meter Replacement Costs
 14.1
 18.1

 Long-term Under-recovered Fuel Costs - Oklahoma
 —
 252.7

 8.4
 9.1

 325.3
 552.8

 62.6
 55.2

 29.9
 —

 16.2
 20.1

 108.7
 75.3

 434.0
 628.1

 $
 522.7
 $
 653.7

 (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.

 PSO

 2023
 2022

 $
 —
 $
 51.3

 —
 51.3

 1.2
 —

 1.2
 —

 1.2
 51.3

 395.7
 380.1
 (b)

 317.5
 316.3
 (c)

 713.2
 696.4

 47.2
 48.2
 18 years

 4.0
 13.2

 51.2
 61.4

 764.4
 757.8

 $
 765.6
 $
 809.1

 (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 $ 51 million and $ 21 million for the years ended December 31, 2023 and 2022, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2023 is to be refunded over 1 year.
 (c) Relieved as removal costs are incurred.

 2023
 2022

 Under-recovered Fuel Costs - earns a return (a)
 $
 76.9
 $
 257.2

 Unrecovered Winter Storm Fuel Costs - earns a return (b)
 93.9
 95.8

 $
 170.8
 $
 353.0

 Welsh Plant, Units 1 and 3 Accelerated Depreciation
 $
 125.6
 $
 85.6

 Pirkey Plant Accelerated Depreciation
 114.4
 116.5

 Unrecovered Winter Storm Fuel Costs (b)
 60.1
 84.6

 Dolet Hills Power Station Accelerated Depreciation (c)
 12.0
 9.7

 26.0
 34.5

 338.1
 330.9

 Storm-Related Costs - Louisiana, Texas
 56.0
 151.5

 Asset Retirement Obligation - Louisiana
 —
 11.8

 13.7
 16.0

 69.7
 179.3

 407.8
 510.2

 Storm-Related Costs - Louisiana
 144.7
 —

 Unrecovered Winter Storm Fuel Costs (b)
 99.3
 148.6

 Fuel Mine Closure Costs - Texas
 74.3
 —

 Pirkey Plant Accelerated Depreciation - Louisiana
 65.8
 63.0

 Plant Retirement Costs - Unrecovered Plant, Arkansas
 44.4
 13.1
 19 years

 Plant Retirement Costs - Unrecovered Plant, Dolet Hills Power Station - Louisiana
 40.8
 45.1

 Environmental Controls Projects
 8.9
 10.0

 Plant Retirement Costs - Unrecovered Plant, Welsh Plant, Unit 2 - Louisiana
 —
 35.2

 4.9
 6.8

 483.1
 321.8

 109.2
 96.2

 Plant Retirement Costs - Unrecovered Plant, Texas
 48.7
 51.7
 23 years

 North Central Wind Rider
 20.2
 6.4

 Plant Retirement Costs - Unrecovered Plant, Arkansas
 17.3
 21.1

 15.4
 —

 30.1
 35.0

 240.9
 210.4

 724.0
 532.2

 $
 1,131.8
 $
 1,042.4

 (a) Amounts include Arkansas and Texas jurisdictions.
 (b) See "February 2021 Severe Winter Weather Impacts in SPP" section of SWEPCo Rate Matters in Note 4 for additional information.
 (c) Amounts include the FERC jurisdiction.

 2023
 2022

 Current Regulatory Liabilities

 Over-recovered Fuel Costs - pays a return (a)
 $
 3.3
 $
 1.4

 Total Current Regulatory Liabilities
 $
 3.3
 $
 1.4

 Income Taxes, Net (b)
 $
 7.0
 $
 7.0

 7.0
 7.0

 443.2
 481.2
 (c)

 Income Taxes, Net (b)
 292.4
 327.6
 (d)

 4.4
 2.2

 740.0
 811.0

 9.1
 7.7

 9.1
 7.7

 749.1
 818.7

 $
 756.1
 $
 825.7

 (a) Amounts include 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.

 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)

 AEP subsidiaries have 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, 2023:

 Contractual Commitments - AEP
 After
 Total

 $
 1,126.7
 $
 1,260.7
 $
 313.5
 $
 256.1
 $
 2,957.0

 186.4
 412.3
 308.8
 419.8
 1,327.3

 Total
 $
 1,313.1
 $
 1,673.0
 $
 622.3
 $
 675.9
 $
 4,284.3

 Contractual Commitments - APCo
 After
 Total

 $
 595.2
 $
 626.1
 $
 99.5
 $
 —
 $
 1,320.8

 40.1
 80.2
 65.5
 75.9
 261.7

 Total
 $
 635.3
 $
 706.3
 $
 165.0
 $
 75.9
 $
 1,582.5

 Contractual Commitments - I&M
 After
 Total

 $
 144.4
 $
 232.3
 $
 130.8
 $
 241.6
 $
 749.1

 127.0
 253.8
 236.6
 182.2
 799.6

 Total
 $
 271.4
 $
 486.1
 $
 367.4
 $
 423.8
 $
 1,548.7

 Contractual Commitments - OPCo
 After
 Total

 $
 33.4
 $
 66.6
 $
 66.3
 $
 102.6
 $
 268.9

 Contractual Commitments - PSO
 After
 Total

 $
 31.5
 $
 36.6
 $
 —
 $
 —
 $
 68.1

 56.6
 139.3
 88.0
 56.3
 340.2

 Total
 $
 88.1
 $
 175.9
 $
 88.0
 $
 56.3
 $
 408.3

 Contractual Commitments - SWEPCo
 After
 Total

 $
 109.2
 $
 48.1
 $
 —
 $
 —
 $
 157.3

 16.4
 26.2
 2.2
 —
 44.8

 Total
 $
 125.6
 $
 74.3
 $
 2.2
 $
 —
 $
 202.1

 (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, AEP Texas, APCo and I&M)

 Standby letters of credit are entered into with third-parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.

 AEP has $ 4 billion and $ 1 billion revolving credit facilities due in March 2027 and 2025, respectively, under which up to $ 1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of December 31, 2023, no letters of credit were issued under the revolving credit facility.

 An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under six uncommitted facilities totaling $ 450 million. The Registrants' maximum future payments for letters of credit issued under the uncommitted facilities as of December 31, 2023 were as follows:

 Maturity

 AEP
 $
 257.0
 January 2024 to November 2024

 1.8
 July 2024

 APCo
 6.3
 September 2024

 I&M
 2.9
 September 2024

 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, 2023, 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" section 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, 2023, 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. 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, 2023, 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, $ 2 million and $ 4 million for the years ended December 31, 2023, 2022 and 2021, respectively. Decommissioning costs recovered from customers are deposited in external trusts.

 As of December 31, 2023 and 2022, the total decommissioning trust fund balances were $ 3.5 billion and $ 3.0 billion, respectively. The increase in the trust fund balance was driven by favorable investment performance in 2023. 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, 2023 and 2022, fees and related interest of $ 300 million and $ 286 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 $ 348 million and $ 330 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 $ 21 million, $ 3 million and $ 14 million in 2023, 2022 and 2021, respectively, to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2023. The proceeds reduced costs for dry cask storage. As of December 31, 2023 and 2022, I&M deferred $ 12 million and $ 21 million, respectively, in Prepayments and Other Current Assets and $ 9 million and $ 3 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 $ 42 million for I&M, which is assessable if the insurer's financial resources would be inadequate to pay for industry losses.

 The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public nuclear liability arising from a nuclear incident of $ 16.3 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 $ 500 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 $ 332 million per nuclear incident on Cook Plant's reactors payable in annual installments of $ 49 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 $ 500 million through commercially available insurance. The next level of liability coverage of up to $ 15.8 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.

 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 cybersecurity 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 cybersecurity 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.

 Litigation Related to Ohio House Bill 6 (HB 6) (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 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. 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 in April 2022. In June 2022, the Ohio state court entered an order continuing the stays of that case until the final resolution of the consolidated derivative actions pending in Ohio federal district court. In September 2022, the New York state court granted the forum-based motion to dismiss with prejudice and the plaintiff subsequently filed a notice of appeal with the New York appellate court. In January 2023, the New York plaintiff filed a motion to intervene in the pending Ohio federal court action and withdrew his appeal in New York. 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 and subsequently filed a brief in opposition to the New York plaintiffs' motion to intervene in the consolidated action in Ohio. In March 2023, the federal district court issued an order granting the motion to dismiss with prejudice and denying the New York plaintiffs' motion to intervene. In April 2023, one of the plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Sixth Circuit of the Ohio federal district court order dismissing the consolidated action and denying the intervention. 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 was directed to the Board of Directors of AEP (AEP Board) and contained factual allegations involving HB 6 that were generally consistent with those in the derivative litigation filed in state and federal court. The shareholder that sent the letter has since withdrawn the litigation demand, which is now terminated and of no further effect. In April 2023, AEP received a litigation demand from counsel representing the purported AEP shareholder who filed the dismissed derivative action in New York state court and unsuccessfully tried to intervene in the consolidated derivative actions in Ohio federal court. The litigation demand letter is directed to the AEP Board 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 certain current and former directors and officers, and that AEP commence a civil action for breaches of fiduciary duty and related claims against any individuals who allegedly harmed AEP. The AEP Board considered the 2023 litigation demand letter and formed a committee of the Board (the "Demand Review Committee") to investigate, review, monitor and analyze the allegations in the letter and make a recommendation to the

 AEP Board regarding a reasonable and appropriate response to the same. The AEP Board will act in response to the letter as appropriate. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

 In May 2021, AEP received a subpoena from the SEC's Division of Enforcement seeking various documents, including documents relating to the 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 and inquiries regarding Empowering Ohio's Economy, Inc., which is a 501(c)(4) social welfare organization, and related disclosures. The SEC staff has advanced its discussions with certain parties involved in the investigation, including AEP, concerning the staff's intentions regarding potential claims under the securities laws. AEP and the SEC are engaged in discussions about a possible resolution of the SEC's investigation and potential claims under the securities laws. Any resolution or filed claims, the outcome of which cannot be predicted, may subject AEP to civil penalties and other remedial measures. Discussions are continuing and management is unable to determine a range of potential losses that is reasonably possible of occurring, but management does not believe the results of this investigation or a possible resolution thereof will have a material impact on results of operations, cash flows or financial condition.

 Claims for Indemnification Made by Owners of the Gavin Power Station (Applies to AEP)

 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 assertions related to the CCR Rule (see "Environmental Issues - CCR Rule" section of Management's Discussion and Analysis of Financial Condition and Results of Operations for additional information), including an assertion 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 these claims, including any future enforcement or litigation resulting from any determinations of noncompliance by the Federal EPA with various aspects of the CCR Rule consistent with the Gavin Denial. The owners of the Gavin Power Station have also sought indemnification for landowner claims for property damage allegedly caused by modifications to the FAR. 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. Gavin Power LLC has also filed a complaint with the United States District Court for the Southern District of Ohio, alleging various violations of the Administrative Procedure Act and asserting that the Federal EPA, through its prior inaction, has waived and is estopped from raising certain objections raised in the Gavin Denial. Management cannot predict the outcome of that litigation.

 7. ACQUISITIONS, DISPOSITIONS AND IMPAIRMENTS

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

 ACQUISITIONS

 Dry Lake Solar Project (Generation & Marketing Segment) (Applies to AEP)

 In March 2021, AEP acquired a 75 % ownership interest in the Dry Lake Solar Project located in southern Nevada for approximately $ 114 million and the project was placed in-service in May 2021. In August 2023, Dry Lake was included in the sale of the competitive contracted renewables portfolio. See the "Disposition of the Competitive Contracted Renewables Portfolio" section below and 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. 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. Maverick was placed in-service in September 2021. In March 2022, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Traverse during its development and construction for $ 1.2 billion. Traverse was placed in-service in March 2022. Immediately following the acquisitions, PSO and SWEPCo liquidated the entities and simultaneously distributed the assets in proportion to their undivided ownership interests. PSO and SWEPCo apply the joint plant accounting model to account for their respective undivided interests in the assets, liabilities, revenues and expenses of the NCWF projects.

 Rock Falls Wind Facility (Vertically Integrated Utilities Segment) (Applies to AEP and PSO)

 In 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. In March 2023, PSO acquired an ownership interest in the entity that owned Rock Falls during its development and construction for $ 146 million. In accordance with the guidance for "Business Combinations," AEP management determined that the acquisition of the Rock Falls Wind Facility represents an asset acquisition. The lease obligations related to Rock Falls were not material at the time of acquisition. See the "2022 Oklahoma Base Rate Case" section of Note 4 for additional information.

 DISPOSITIONS

 Termination of Planned Disposition of KPCo and KTCo (Vertically Integrated Utilities and AEP Transmission Holdco Segments) (Applies to AEP and AEPTCo)

 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. The SPA was subsequently amended in September 2022 to reduce the purchase price to approximately $ 2.646 billion. The sale required approval from the KPSC and from the FERC under Section 203 of the Federal Power Act. The SPA contained certain termination rights if the closing of the sale did not occur by April 26, 2023.

 In May 2022, the KPSC approved the sale of KPCo to Liberty subject to certain 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 an adverse effect on rates. In February 2023, a new filing for approval under Section 203 of the Federal Power Act was submitted. In March 2023, the KPSC and other intervenors made filings recommending the FERC reject AEP and Liberty's new Section 203 application seeking approval of the sale.

 As a result of delays in the anticipated timing of the closing of the transaction and other factors, AEP recorded a $ 363 million pretax loss on the expected sale of the Kentucky Operations for the year ended December 31, 2022. In April 2023, AEP, AEPTCo and Liberty entered into a Mutual Termination Agreement (Termination Agreement) terminating the SPA. The parties entered into the Termination Agreement as all of the conditions precedent to closing the sale could not be satisfied prior to April 26, 2023. Upon termination of the sale and reverting to a held and used model, in the first quarter of 2023, AEP reversed $ 28 million of expected transaction costs included in the $ 363 million pretax loss and was required to present its investment in the Kentucky Operations at the lower of fair value or historical carrying value which resulted in a $ 335 million reduction recorded in Property, Plant and Equipment. The reduced investment in KPCo's assets is being amortized over the 30-year average useful life of the KPCo assets.

 Disposition of the Competitive Contracted Renewables Portfolio (Generation & Marketing Segment) (Applies to AEP)

 In February 2022, AEP management announced the initiation of a process to sell all or a portion of AEP Renewables' competitive contracted renewables portfolio (the portfolio) within the Generation & Marketing segment. 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 portfolio and AEP signed an agreement with a nonaffiliated party.

 In August 2023, AEP completed the sale of the entire portfolio to the nonaffiliated party and received cash proceeds of approximately $ 1.2 billion, net of taxes and transaction costs. AEP recorded a pretax loss of $ 93 million ($ 73 million after-tax) for the year ended December 31, 2023 related to the sale.

 Disposition of Mineral Rights (Generation & Marketing Segment) (Applies to AEP)

 In June 2022, AEP closed on the sale of certain mineral rights to a nonaffiliated third-party and received $ 120 million of proceeds. The sale resulted in a pretax gain of $ 116 million in the second quarter of 2022.

 IMPAIRMENTS

 2012 Texas Base Rate Case (Vertically Integrated Utilities Segment) (Applies to AEP and SWEPCo)

 In December 2023, SWEPCo recorded a pretax, non-cash disallowance of $ 86 million in Asset Impairments and Other Related Charges on the statements of income due to regulatory disallowance of recovery of AFUDC on Turk Plant in the 2012 Texas Base Rate case. See the "2012 Texas Base Rate Case" section of Note 4 for additional information.

 NMRD (Generation & Marketing Segment) (Applies to AEP)

 In December 2023, as a result of sale negotiations AEP determined a decline in the fair value of AEP's investment in New Mexico Renewable Development (NMRD) was other than temporary. In accordance with the accounting guidance for "Investment - Equity Method and Joint Ventures", in the fourth quarter of 2023 AEP recorded a pretax other than temporary impairment charge of $ 19 million which is presented in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP's Statement 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 non-affiliate. The carrying value of the investment in NMRD was not material to AEP as of December 31, 2023.

 Flat Ridge 2 Wind LLC (Generation & Marketing Segment) (Applies to AEP)

 In 2019, AEP acquired a 50 % ownership interest in five non-consolidated joint ventures, including Flat Ridge 2 Wind LLC (Flat Ridge 2), and two tax equity partnerships. The five non-consolidated joint ventures are jointly owned and operated by BP Wind Energy. Flat Ridge 2 sells electricity to three counterparties through long-term PPAs.

 Regarding AEP's investment in Flat Ridge 2, in June 2022, as a result of Flat Ridge 2's 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. In accordance with the accounting guidance for "Investments - Equity Method and Joint Ventures", in the second quarter of 2022 AEP recorded a pretax other than temporary impairment charge of $ 186 million which is presented in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP's Statement 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 non-affiliate. In the third quarter of 2022, AEP recorded an additional $ 2 million pretax other than temporary impairment charge which is presented in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP's Statement of Income. 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.

 2020 Texas Base Rate Case (Vertically Integrated Utilities Segment) (Applies to AEP and SWEPCo)

 In January 2022, the PUCT issued a final order which included a return of investment only for the recovery of the Dolet Hills Power Station. As a result of the final order, SWEPCo recorded a disallowance of $ 12 million 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 denial of a reasonable return or carrying costs on the Dolet Hills Power Station among other items. 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. See "2020 Texas Base Rate Case" section of Note 4 for additional information.

 8. BENEFIT PLANS

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

 For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see "Fair Value Measurements of Assets and Liabilities" and "Investments Held in Trust for Future Liabilities" sections of Note 1.

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

 Due to the Registrant Subsidiaries' participation in AEP's benefit plans, the assumptions used by the actuary, with the exception of the rate of compensation increase, and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant.

 The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the "Compensation – Retirement Benefits" accounting guidance. The Registrants recognize an asset for a plan's overfunded status or a liability for a plan's underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for rate-making purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.

 Actuarial Assumptions for Benefit Obligations

 The weighted-average assumptions used in the measurement of the Registrants' benefit obligations are shown in the following tables:

 OPEB

 Assumption
 2023
 2022
 2023
 2022

 Discount Rate
 5.15
 %
 5.50
 %
 5.15
 %
 5.50
 %

 Interest Crediting Rate
 4.00
 %
 4.25
 %
 NA
 NA

 Assumption – Rate of Compensation Increase (a) - Pension Plans

 AEP
 APCo
 I&M
 OPCo
 PSO

 5.05
 %
 5.20
 %
 4.95
 %
 5.05
 %
 5.45
 %
 5.20
 %
 5.00
 %

 5.05
 %
 5.15
 %
 4.90
 %
 5.00
 %
 5.35
 %
 5.15
 %
 5.00
 %

 (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.

 A duration-based method is used to determine the discount rate for the plans. A hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan. The discount rate is the same for each Registrant.

 For 2023, the rate of compensation increase assumed varies with the age of the employee, ranging from 3 % per year to 11.5 % per year, with the average increase shown in the table above. The compensation increase rates reflect variations in each Registrants' population participating in the pension plan.

 Actuarial Assumptions for Net Periodic Benefit Costs

 The weighted-average assumptions used in the measurement of each Registrants' benefit costs are shown in the following tables:

 OPEB

 Year Ended December 31,

 Assumption
 2023
 2022
 2021
 2023
 2022
 2021

 Discount Rate
 5.50
 %
 2.90
 %
 2.50
 %
 5.50
 %
 2.90
 %
 2.55
 %

 Interest Crediting Rate
 4.25
 %
 4.00
 %
 4.00
 %
 NA
 NA
 NA

 7.50
 %
 5.25
 %
 4.75
 %
 7.25
 %
 5.50
 %
 4.75
 %

 Assumption – Rate of Compensation Increase (a) - Pension Plans

 AEP
 APCo
 I&M
 OPCo
 PSO

 5.05
 %
 5.20
 %
 4.95
 %
 5.05
 %
 5.45
 %
 5.20
 %
 5.00
 %

 5.05
 %
 5.15
 %
 4.90
 %
 5.00
 %
 5.35
 %
 5.15
 %
 5.00
 %

 December 31, 2021
 5.10
 %
 5.10
 %
 4.85
 %
 5.00
 %
 5.30
 %
 5.10
 %
 4.95
 %

 (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.

 The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation, third-party forecasts and current prospects for economic growth. The expected return on plan assets is the same for each Registrant.

 The health care trend rate assumptions used for OPEB plans measurement purposes are shown below:

 Health Care Trend Rates

 Initial
 7.00
 %

 7.50
 %

 Ultimate
 4.50
 %

 4.50
 %

 Year Ultimate Reached
 2030

 2029

 Significant Concentrations of Risk within Plan Assets

 In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets. The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits. The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment. Management monitors the plans to control security diversification and ensure compliance with the investment policy. As of December 31, 2023, the assets were invested in compliance with all investment limits. See "Investments Held in Trust for Future Liabilities" section of Note 1 for limit details.

 Benefit Plan Obligations, Plan Assets, Funded Status and Amounts Recognized on the Balance Sheets

 For the year ended December 31, 2023, the pension plans had an actuarial loss primarily due to a decrease in the discount rate, and to a lesser extent the effect of demographic experience (updated census data on January 1, 2023). These losses were partially offset by decreasing the cash balance account interest crediting rate. For the year ended December 31, 2023, the OPEB plans had an actuarial loss primarily due to discount rates, as well as actual net benefit payments above expected. These losses were partially offset by updated per capita cost assumptions. For the year ended December 31, 2022, the pension plans had an actuarial gain primarily due to an increase in the discount rate and was partially offset by increases in the assumed lump sum conversion rate and cash balance account interest crediting rate. For the year ended December 31, 2022, the OPEB plans had an actuarial gain primarily due to an increase in the discount rate and updated per capita cost assumptions. The OPEB plans gains were partially offset by a projected reduction in the Employer Group Waiver Program catastrophic reinsurance offset provided to AEP, resulting from the Inflation Reduction Act as well as an increase in the health care cost trend assumption. The following tables provide a reconciliation of the changes in the plans' benefit obligations, fair value of plan assets, funded status and the presentation on the balance sheets. The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively.

 2023
 AEP
 APCo
 I&M
 OPCo
 PSO

 Change in Benefit Obligation

 Benefit Obligation as of January 1,
 $
 4,072.7
 $
 334.1
 $
 485.7
 $
 466.8
 $
 363.6
 $
 192.3
 $
 250.7

 94.3
 8.2
 9.1
 11.9
 8.4
 5.5
 7.7

 219.2
 18.3
 26.4
 24.9
 19.8
 10.7
 13.9

 Actuarial Loss
 144.0
 20.1
 23.2
 8.5
 17.5
 13.6
 16.8

 ( 368.6)
 ( 37.6)
 ( 40.3)
 ( 35.1)
 ( 30.9)
 ( 19.9)
 ( 27.9)

 Benefit Obligation as of December 31,
 $
 4,161.6
 $
 343.1
 $
 504.1
 $
 477.0
 $
 378.4
 $
 202.2
 $
 261.2

 Change in Fair Value of Plan Assets

 Fair Value of Plan Assets as of January 1,
 $
 4,124.7
 $
 335.1
 $
 531.7
 $
 533.7
 $
 406.4
 $
 218.5
 $
 231.3

 Actual Gain on Plan Assets
 353.8
 34.8
 58.4
 51.5
 44.0
 24.0
 23.9

 Company Contributions (a)
 8.3
 0.4
 —
 0.5
 —
 0.1
 0.2

 ( 368.6)
 ( 37.6)
 ( 40.3)
 ( 35.1)
 ( 30.9)
 ( 19.9)
 ( 27.9)

 Fair Value of Plan Assets as of December 31,
 $
 4,118.2
 $
 332.7
 $
 549.8
 $
 550.6
 $
 419.5
 $
 222.7
 $
 227.5

 Funded (Underfunded) Status as of December 31,
 $
 ( 43.4)
 $
 $
 45.7
 $
 73.6
 $
 41.1
 $
 20.5
 $

 2022
 AEP
 APCo
 I&M
 OPCo
 PSO

 Change in Benefit Obligation

 Benefit Obligation as of January 1,
 $
 5,187.0
 $
 419.8
 $
 621.7
 $
 612.1
 $
 470.7
 $
 252.6
 $
 317.7

 123.1
 11.1
 11.4
 16.2
 11.2
 7.4
 10.6

 148.2
 12.1
 17.5
 17.0
 13.3
 7.0
 9.1

 Actuarial Gain
 ( 983.4)
 ( 67.8)
 ( 123.1)
 ( 138.0)
 ( 97.9)
 ( 52.9)
 ( 57.9)

 ( 402.2)
 ( 41.1)
 ( 41.8)
 ( 40.5)
 ( 21.8)
 ( 28.8)

 Benefit Obligation as of December 31,
 $
 4,072.7
 $
 334.1
 $
 485.7
 $
 466.8
 $
 363.6
 $
 192.3
 $
 250.7

 Change in Fair Value of Plan Assets

 Fair Value of Plan Assets as of January 1,
 $
 5,352.9
 $
 444.9
 $
 683.3
 $
 681.5
 $
 524.8
 $
 286.2
 $
 308.3

 Actual (Loss) on Plan Assets
 ( 833.7)
 ( 69.2)
 ( 109.8)
 ( 107.4)
 ( 84.8)
 ( 46.0)
 ( 48.3)

 Company Contributions (a)
 7.7
 0.5
 —
 0.1
 0.1
 0.1
 0.1

 ( 402.2)
 ( 41.1)
 ( 41.8)
 ( 40.5)
 ( 21.8)
 ( 28.8)

 Fair Value of Plan Assets as of December 31,
 $
 4,124.7
 $
 335.1
 $
 531.7
 $
 533.7
 $
 406.4
 $
 218.5
 $
 231.3

 Funded (Underfunded) Status as of December 31,
 $
 52.0
 $
 1.0
 $
 46.0
 $
 66.9
 $
 42.8
 $
 26.2
 $

 (a)No contributions were made to the qualified pension plan for the years ended December 31, 2023 and 2022, respectively. Contributions to the non-qualified pension plans were $ 8 million and $ 8 million for the years ended December 31, 2023 and 2022, respectively.

 OPEB

 2023
 AEP
 APCo
 I&M
 OPCo
 PSO

 Change in Benefit Obligation

 Benefit Obligation as of January 1,
 $
 872.6
 $
 68.6
 $
 140.7
 $
 101.9
 $
 88.9
 $
 45.7
 $
 55.1

 4.6
 0.3
 0.5
 0.6
 0.4
 0.3
 0.4

 46.2
 3.6
 7.4
 5.4
 4.7
 2.4
 2.9

 Actuarial Loss
 19.8
 1.2
 0.9
 3.2
 2.2
 0.4
 1.2

 ( 137.8)
 ( 10.7)
 ( 21.6)
 ( 15.0)
 ( 7.6)

 Participant Contributions
 43.6
 3.4
 6.6
 6.0
 4.7
 2.5
 2.9

 Medicare Subsidy
 0.5
 —
 0.1
 —
 —
 —
 —

 Benefit Obligation as of December 31,
 $
 849.5
 $
 66.4
 $
 134.6
 $
 98.8
 $
 85.9
 $
 43.7
 $
 53.7

 Change in Fair Value of Plan Assets

 Fair Value of Plan Assets as of January 1,
 $
 1,549.3
 $
 128.3
 $
 228.6
 $
 190.5
 $
 166.2
 $
 85.4
 $
 103.0

 Actual Gain on Plan Assets
 213.2
 16.5
 28.1
 26.4
 21.9
 9.9
 14.0

 Company Contributions
 5.0
 —
 1.3
 —
 —
 —
 —

 Participant Contributions
 43.6
 3.4
 6.6
 6.0
 4.7
 2.5
 2.9

 ( 137.8)
 ( 10.7)
 ( 21.6)
 ( 15.0)
 ( 7.6)

 Fair Value of Plan Assets as of December 31,
 $
 1,673.3
 $
 137.5
 $
 243.0
 $
 204.6
 $
 177.8
 $
 90.2
 $
 111.1

 Funded Status as of December 31,
 $
 823.8
 $
 71.1
 $
 108.4
 $
 105.8
 $
 91.9
 $
 46.5
 $
 57.4

 2022
 AEP
 APCo
 I&M
 OPCo
 PSO

 Change in Benefit Obligation

 Benefit Obligation as of January 1,
 $
 1,041.3
 $
 80.5
 $
 167.3
 $
 118.6
 $
 104.9
 $
 54.4
 $
 65.2

 7.4
 0.5
 0.8
 0.9
 0.6
 0.4
 0.6

 29.2
 2.2
 4.7
 3.4
 3.0
 1.5
 1.8

 Actuarial Gain
 ( 109.8)
 ( 7.1)
 ( 16.2)
 ( 8.7)
 ( 8.9)
 ( 5.2)
 ( 6.6)

 ( 140.1)
 ( 23.0)

 Participant Contributions
 44.1
 3.4
 7.0
 6.0
 4.8
 2.5
 2.9

 Medicare Subsidy
 0.5
 —
 0.1
 —
 —
 —
 —

 Benefit Obligation as of December 31,
 $
 872.6
 $
 68.6
 $
 140.7
 $
 101.9
 $
 88.9
 $
 45.7
 $
 55.1

 Change in Fair Value of Plan Assets

 Fair Value of Plan Assets as of January 1,
 $
 2,044.3
 $
 168.8
 $
 302.3
 $
 248.7
 $
 220.0
 $
 114.0
 $
 136.6

 Actual Loss on Plan Assets
 ( 403.6)
 ( 33.0)
 ( 59.3)
 ( 45.9)
 ( 43.1)
 ( 23.2)
 ( 27.7)

 Company Contributions
 4.6
 —
 1.6
 —
 —
 —
 —

 Participant Contributions
 44.1
 3.4
 7.0
 6.0
 4.8
 2.5
 2.9

 ( 140.1)
 ( 23.0)

 Fair Value of Plan Assets as of December 31,
 $
 1,549.3
 $
 128.3
 $
 228.6
 $
 190.5
 $
 166.2
 $
 85.4
 $
 103.0

 Funded Status as of December 31,
 $
 676.7
 $
 59.7
 $
 87.9
 $
 88.6
 $
 77.3
 $
 39.7
 $
 47.9

 Amounts Included on the Balance Sheets Related to Funded Status

 AEP
 APCo
 I&M
 OPCo
 PSO

 Other Noncurrent Assets - Employee Benefits and Pension Assets
 $
 17.3
 $
 0.1
 $
 46.0
 $
 74.8
 $
 41.4
 $
 21.8
 $
 —

 Other Current Liabilities – Accrued Short-term Benefit Liability
 ( 6.7)
 —
 —
 —

 Other Noncurrent Liabilities – Accrued Long-term Benefit Liability
 ( 54.0)
 ( 10.2)
 ( 33.6)

 Funded (Underfunded) Status
 $
 ( 43.4)
 $
 $
 45.7
 $
 73.6
 $
 41.1
 $
 20.5
 $

 AEP
 APCo
 I&M
 OPCo
 PSO

 Other Noncurrent Assets - Employee Benefits and Pension Assets
 $
 113.4
 $
 3.7
 $
 46.6
 $
 68.5
 $
 43.1
 $
 27.6
 $
 —

 Other Current Liabilities – Accrued Short-term Benefit Liability
 —
 —

 Other Noncurrent Liabilities – Accrued Long-term Benefit Liability
 ( 55.1)
 ( 19.3)

 Funded (Underfunded) Status
 $
 52.0
 $
 1.0
 $
 46.0
 $
 66.9
 $
 42.8
 $
 26.2
 $

 OPEB

 AEP
 APCo
 I&M
 OPCo
 PSO

 Other Noncurrent Assets - Employee Benefits and Pension Assets
 $
 838.0
 $
 71.1
 $
 125.6
 $
 105.8
 $
 91.9
 $
 46.5
 $
 57.4

 Other Current Liabilities – Accrued Short-term Benefit Liability
 —
 —
 —
 —
 —

 Other Noncurrent Liabilities – Accrued Long-term Benefit Liability
 —
 ( 15.6)
 —
 —
 —
 —

 Funded Status
 $
 823.8
 $
 71.1
 $
 108.4
 $
 105.8
 $
 91.9
 $
 46.5
 $
 57.4

 AEP
 APCo
 I&M
 OPCo
 PSO

 Other Noncurrent Assets - Employee Benefits and Pension Assets
 $
 699.5
 $
 59.7
 $
 106.3
 $
 88.6
 $
 77.3
 $
 39.7
 $
 47.9

 Other Current Liabilities – Accrued Short-term Benefit Liability
 —
 —
 —
 —
 —

 Other Noncurrent Liabilities – Accrued Long-term Benefit Liability
 ( 20.3)
 —
 ( 16.8)
 —
 —
 —
 —

 Funded Status
 $
 676.7
 $
 59.7
 $
 87.9
 $
 88.6
 $
 77.3
 $
 39.7
 $
 47.9

 Amounts Included in Regulatory Assets, Deferred Income Taxes and AOCI

 The following tables show the components of the plans included in Regulatory Assets, Deferred Income Taxes and AOCI and the items attributable to the change in these components:

 AEP
 APCo
 I&M
 OPCo
 PSO

 Net Actuarial (Gain) Loss
 $
 1,063.4
 $
 175.2
 $
 104.9
 $
 ( 5.8)
 $
 131.9
 $
 46.7
 $
 89.6

 Prior Service Cost
 0.2
 —
 —
 —
 —
 —
 —

 Recorded as

 $
 938.6
 $
 163.4
 $
 102.6
 $
 6.4
 $
 131.9
 $
 46.7
 $
 89.7

 26.4
 2.7
 0.4
 —
 —
 —

 Net of Tax AOCI
 98.6
 9.1
 1.9
 ( 9.6)
 —
 —

 AEP
 APCo
 I&M
 OPCo
 PSO

 Actuarial Loss During the Year
 $
 129.2
 $
 13.4
 $
 9.3
 $
 1.2
 $
 7.6
 $
 7.9
 $
 12.1

 Amortization of Actuarial Loss
 —
 —
 —

 Change for the Year Ended December 31,
 $
 127.8
 $
 13.3
 $
 9.3
 $
 1.1
 $
 7.6
 $
 7.9
 $
 12.0

 AEP
 APCo
 I&M
 OPCo
 PSO

 Net Actuarial (Gain) Loss
 $
 935.6
 $
 161.9
 $
 95.6
 $
 $
 124.3
 $
 38.8
 $
 77.6

 Prior Service Cost
 0.2
 —
 —
 —
 —
 —
 —

 Recorded as

 $
 841.8
 $
 151.2
 $
 93.6
 $
 4.8
 $
 124.3
 $
 38.8
 $
 77.6

 19.9
 2.4
 0.4
 —
 —
 —

 Net of Tax AOCI
 74.1
 8.3
 1.6
 —
 —
 —

 AEP
 APCo
 I&M
 OPCo
 PSO

 Actuarial Loss During the Year
 $
 103.9
 $
 22.4
 $
 19.1
 $
 1.8
 $
 11.7
 $
 6.7
 $
 5.0

 Amortization of Actuarial Loss
 ( 63.0)
 ( 5.2)
 ( 7.1)
 ( 5.5)
 ( 2.9)
 ( 3.8)

 Change for the Year Ended December 31,
 $
 40.9
 $
 17.2
 $
 11.7
 $
 ( 5.3)
 $
 6.2
 $
 3.8
 $
 1.2

 OPEB

 AEP
 APCo
 I&M
 OPCo
 PSO

 Net Actuarial Loss
 $
 201.5
 $
 22.1
 $
 27.1
 $
 28.7
 $
 18.1
 $
 17.5
 $
 18.4

 Prior Service Credit
 ( 27.4)
 ( 2.9)

 Recorded as

 $
 106.1
 $
 19.8
 $
 13.2
 $
 19.0
 $
 15.2
 $
 15.9
 $
 10.2

 14.3
 —
 2.0
 1.3
 —
 —
 1.3

 Net of Tax AOCI
 53.7
 —
 7.7
 4.7
 —
 —
 4.8

 AEP
 APCo
 I&M
 OPCo
 PSO

 Actuarial Gain During the Year
 $
 ( 83.7)
 $
 $
 ( 11.1)
 $
 ( 9.6)
 $
 $
 $

 Amortization of Actuarial Loss
 ( 1.9)

 63.1
 5.3
 9.2
 8.7
 6.3
 4.0
 4.9

 Change for the Year Ended December 31,
 $
 ( 35.4)
 $
 $
 $
 $
 $
 $
 ( 1.7)

 AEP
 APCo
 I&M
 OPCo
 PSO

 Net Actuarial Loss
 $
 300.0
 $
 29.7
 $
 40.5
 $
 40.2
 $
 27.6
 $
 22.0
 $
 25.0

 Prior Service Credit
 ( 90.5)
 ( 7.6)
 ( 13.4)
 ( 12.4)
 ( 9.2)

 Recorded as

 $
 126.0
 $
 22.0
 $
 14.7
 $
 22.1
 $
 18.4
 $
 16.4
 $
 11.2

 17.5
 0.1
 2.5
 1.2
 —
 —
 1.5

 Net of Tax AOCI
 66.0
 —
 9.9
 4.5
 —
 —
 5.3

 AEP
 APCo
 I&M
 OPCo
 PSO

 Actuarial Loss During the Year
 $
 403.6
 $
 34.9
 $
 59.4
 $
 50.9
 $
 46.1
 $
 24.1
 $
 28.5

 71.4
 6.1
 10.4
 9.7
 7.1
 4.4
 5.3

 Change for the Year Ended December 31,
 $
 475.0
 $
 41.0
 $
 69.8
 $
 60.6
 $
 53.2
 $
 28.5
 $
 33.8

 Determination of Pension Expense

 The determination of pension expense or income is based on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return.

 Pension and OPEB Assets

 The fair value tables within Pension and OPEB Assets present the classification of assets for AEP within the fair value hierarchy. All Level 1, 2, 3 and Other amounts can be allocated to the Registrant Subsidiaries using the percentages in the table below:

 Pension Plan
 OPEB

 2023
 2022
 2023
 2022

 8.1
 %
 8.1
 %
 8.2
 %
 8.3
 %

 APCo
 13.4
 %
 12.9
 %
 14.5
 %
 14.8
 %

 I&M
 13.4
 %
 12.9
 %
 12.2
 %
 12.3
 %

 OPCo
 10.2
 %
 9.9
 %
 10.6
 %
 10.7
 %

 PSO
 5.4
 %
 5.3
 %
 5.4
 %
 5.5
 %

 5.5
 %
 5.6
 %
 6.6
 %
 6.6
 %

 The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2023:

 Asset Class
 Other
 Total
 Year End
Allocation

 Equities (a):

 Domestic
 $
 411.3
 $
 —
 $
 —
 $
 —
 $
 411.3
 10.0
 %

 International
 389.8
 —
 —
 —
 389.8
 9.5
 %

 Common Collective Trusts (b)
 —
 —
 —
 420.9
 420.9
 10.2
 %

 Subtotal – Equities
 801.1
 —
 —
 420.9
 1,222.0
 29.7
 %

 Fixed Income (a):

 United States Government and Agency Securities
 8.3
 1,099.2
 —
 —
 1,107.5
 26.9
 %

 —
 894.8
 —
 —
 894.8
 21.7
 %

 Foreign Debt
 —
 167.1
 —
 —
 167.1
 4.1
 %

 —
 38.7
 —
 —
 38.7
 0.9
 %

 Other – Asset Backed
 —
 1.3
 —
 —
 1.3
 —
 %

 Subtotal – Fixed Income
 8.3
 2,201.1
 —
 —
 2,209.4
 53.6
 %

 Infrastructure (b)
 —
 —
 —
 101.4
 101.4
 2.5
 %

 Real Estate (b)
 —
 —
 —
 239.3
 239.3
 5.8
 %

 Alternative Investments (b)
 —
 —
 —
 241.8
 241.8
 5.8
 %

 Cash and Cash Equivalents (b)
 —
 51.0
 —
 33.8
 84.8
 2.1
 %

 Other – Pending Transactions and Accrued Income (c)
 —
 —
 0.1
 19.4
 19.5
 0.5
 %

 Total
 $
 809.4
 $
 2,252.1
 $
 0.1
 $
 1,056.6
 $
 4,118.2
 100.0
 %

 (a) Includes investment securities loaned to borrowers under the securities lending program. See the "Investments Held in Trust for Future Liabilities" section of Note 1 for additional information.
 (b) Amounts in "Other" column represent investments for which fair value is measured using net asset value per-share.
 (c) Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending settlement.

 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2023:

 Asset Class
 Other
 Total
 Year End
Allocation

 Equities:

 Domestic
 $
 540.6
 $
 —
 $
 —
 $
 —
 $
 540.6
 32.3
 %

 International
 288.4
 —
 —
 —
 288.4
 17.2
 %

 Common Collective Trusts (a)
 —
 —
 —
 131.6
 131.6
 7.9
 %

 Subtotal – Equities
 829.0
 —
 —
 131.6
 960.6
 57.4
 %

 Fixed Income:

 Common Collective Trust – Debt (a)
 —
 —
 —
 146.7
 146.7
 8.8
 %

 United States Government and Agency Securities
 1.4
 163.3
 —
 —
 164.7
 9.8
 %

 —
 149.0
 —
 —
 149.0
 8.9
 %

 Foreign Debt
 —
 28.6
 —
 —
 28.6
 1.7
 %

 41.5
 7.8
 —
 —
 49.3
 3.0
 %

 Other – Asset Backed
 —
 0.2
 —
 —
 0.2
 —
 %

 Subtotal – Fixed Income
 42.9
 348.9
 —
 146.7
 538.5
 32.2
 %

 Trust Owned Life Insurance:

 International Equities
 —
 22.3
 —
 —
 22.3
 1.3
 %

 United States Bonds
 —
 130.0
 —
 —
 130.0
 7.8
 %

 Subtotal – Trust Owned Life Insurance
 —
 152.3
 —
 —
 152.3
 9.1
 %

 Cash and Cash Equivalents (a)
 25.9
 —
 —
 2.9
 28.8
 1.7
 %

 Other – Pending Transactions and Accrued Income (b)
 —
 —
 —
 %

 Total
 $
 897.8
 $
 501.2
 $
 —
 $
 274.3
 $
 1,673.3
 100.0
 %

 (a) Amounts in "Other" column represent investments for which fair value is measured using net asset value per-share.
 (b) Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending settlement.

 The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2022:

 Asset Class
 Other
 Total
 Year End
Allocation

 Equities (a):

 Domestic
 $
 347.6
 $
 —
 $
 —
 $
 —
 $
 347.6
 8.4
 %

 International
 398.4
 —
 —
 —
 398.4
 9.7
 %

 Common Collective Trusts (b)
 —
 —
 —
 379.9
 379.9
 9.2
 %

 Subtotal – Equities
 746.0
 —
 —
 379.9
 1,125.9
 27.3
 %

 Fixed Income (a):

 United States Government and Agency Securities
 1,071.4
 —
 —
 1,070.8
 26.0
 %

 —
 891.7
 —
 —
 891.7
 21.6
 %

 Foreign Debt
 —
 140.2
 —
 —
 140.2
 3.4
 %

 —
 37.0
 —
 —
 37.0
 0.9
 %

 Other – Asset Backed
 —
 0.8
 —
 —
 0.8
 —
 %

 Subtotal – Fixed Income
 2,141.1
 —
 —
 2,140.5
 51.9
 %

 Infrastructure (b)
 —
 —
 —
 109.2
 109.2
 2.6
 %

 Real Estate (b)
 —
 —
 —
 276.9
 276.9
 6.7
 %

 Alternative Investments (b)
 —
 —
 —
 319.7
 319.7
 7.8
 %

 Cash and Cash Equivalents (b)
 —
 64.9
 —
 58.3
 123.2
 3.0
 %

 Other – Pending Transactions and Accrued Income (c)
 —
 —
 —
 29.3
 29.3
 0.7
 %

 Total
 $
 745.4
 $
 2,206.0
 $
 —
 $
 1,173.3
 $
 4,124.7
 100.0
 %

 (a)Includes investment securities loaned to borrowers under the securities lending program. See the "Investments Held in Trust for Future Liabilities" section of Note 1 for additional information.
 (b)Amounts in "Other" column represent investments for which fair value is measured using net asset value per-share.
 (c)Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending settlement.

 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2022:

 Asset Class
 Other
 Total
 Year End
Allocation

 Equities:

 Domestic
 $
 414.1
 $
 —
 $
 —
 $
 —
 $
 414.1
 26.7
 %

 International
 265.0
 —
 —
 —
 265.0
 17.1
 %

 Common Collective Trusts (a)
 —
 —
 —
 169.1
 169.1
 10.9
 %

 Subtotal – Equities
 679.1
 —
 —
 169.1
 848.2
 54.7
 %

 Fixed Income:

 Common Collective Trust – Debt (a)
 —
 —
 —
 120.3
 120.3
 7.8
 %

 United States Government and Agency Securities
 0.1
 155.8
 —
 —
 155.9
 10.1
 %

 —
 141.5
 —
 —
 141.5
 9.1
 %

 Foreign Debt
 —
 21.0
 —
 —
 21.0
 1.4
 %

 62.9
 7.8
 —
 —
 70.7
 4.6
 %

 Subtotal – Fixed Income
 63.0
 326.1
 —
 120.3
 509.4
 33.0
 %

 Trust Owned Life Insurance:

 International Equities
 —
 46.7
 —
 —
 46.7
 3.0
 %

 United States Bonds
 —
 110.3
 —
 —
 110.3
 7.1
 %

 Subtotal – Trust Owned Life Insurance
 —
 157.0
 —
 —
 157.0
 10.1
 %

 Cash and Cash Equivalents (a)
 23.2
 —
 —
 6.7
 29.9
 1.9
 %

 Other – Pending Transactions and Accrued Income (b)
 —
 —
 —
 4.8
 4.8
 0.3
 %

 Total
 $
 765.3
 $
 483.1
 $
 —
 $
 300.9
 $
 1,549.3
 100.0
 %

 (a)Amounts in "Other" column represent investments for which fair value is measured using net asset value per-share.
 (b)Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending settlement.

 The accumulated benefit obligation for the pension plans is as follows:

 AEP
 APCo
 I&M
 OPCo
 PSO

 Qualified Pension Plan
 $
 3,878.7
 $
 321.1
 $
 485.6
 $
 450.3
 $
 354.0
 $
 186.6
 $
 241.9

 Nonqualified Pension Plans
 54.8
 2.1
 0.1
 0.7
 0.1
 1.2
 1.0

 Total as of December 31, 2023
 $
 3,933.5
 $
 323.2
 $
 485.7
 $
 451.0
 $
 354.1
 $
 187.8
 $
 242.9

 AEP
 APCo
 I&M
 OPCo
 PSO

 Qualified Pension Plan
 $
 3,827.4
 $
 315.4
 $
 470.1
 $
 443.8
 $
 344.1
 $
 179.1
 $
 234.0

 Nonqualified Pension Plans
 55.6
 2.5
 0.3
 1.2
 0.1
 1.2
 1.1

 Total as of December 31, 2022
 $
 3,883.0
 $
 317.9
 $
 470.4
 $
 445.0
 $
 344.2
 $
 180.3
 $
 235.1

 Obligations in Excess of Fair Values

 The tables below show the underfunded pension plans that had obligations in excess of plan assets.

 Projected Benefit Obligation

 AEP
 APCo
 I&M
 OPCo
 PSO

 Projected Benefit Obligation
 $
 60.7
 $
 343.1
 $
 0.4
 $
 1.2
 $
 0.3
 $
 1.4
 $
 261.2

 Fair Value of Plan Assets
 —
 332.7
 —
 —
 —
 —
 227.5

 Underfunded Projected Benefit Obligation as of December 31, 2023

 $
 ( 60.7)
 $
 $
 $
 $
 $
 $

 AEP
 APCo
 I&M
 OPCo
 PSO

 Projected Benefit Obligation
 $
 61.5
 $
 2.7
 $
 0.6
 $
 1.6
 $
 0.3
 $
 1.5
 $
 250.7

 Fair Value of Plan Assets
 —
 —
 —
 —
 —
 —
 231.3

 Underfunded Projected Benefit Obligation as of December 31, 2022

 $
 ( 61.5)
 $
 ( 2.7)
 $
 $
 $
 $
 $

 AEP
 APCo
 I&M
 OPCo
 PSO

 $
 54.8
 $
 2.1
 $
 0.1
 $
 0.7
 $
 0.1
 $
 1.2
 $
 242.9

 Fair Value of Plan Assets
 —
 —
 —
 —
 —
 —
 227.5

 Underfunded Accumulated Benefit Obligation as of December 31, 2023

 $
 ( 54.8)
 $
 $
 $
 $
 $
 $
 ( 15.4)

 AEP
 APCo
 I&M
 OPCo
 PSO

 $
 55.6
 $
 2.5
 $
 0.3
 $
 1.2
 $
 0.1
 $
 1.2
 $
 235.1

 Fair Value of Plan Assets
 —
 —
 —
 —
 —
 —
 231.3

 Underfunded Accumulated Benefit Obligation as of December 31, 2022

 $
 ( 55.6)
 $
 $
 $
 $
 $
 $
 ( 3.8)

 Estimated Future Benefit Payments and Contributions

 The estimated pension benefit payments and contributions to the trust are at least the minimum amount required by the Employee Retirement Income Security Act plus payment of unfunded non-qualified benefits. For the qualified pension plan, additional discretionary contributions may also be made to maintain the funded status of the plan. For OPEB plans, expected payments include the payment of unfunded benefits. The following table provides the estimated contributions and payments by Registrant for 2024:

 AEP
 APCo
 I&M
 OPCo
 PSO

 $
 6.7
 $
 0.3
 $
 —
 $
 —
 $
 —
 $
 0.1
 $
 0.1

 OPEB
 3.0
 —
 1.6
 —
 —
 —
 —

 The tables below reflect the total benefits expected to be paid from the plan or from the Registrants' assets. The payments include the participants' contributions to the plan for their share of the cost. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results. The estimated payments for the pension benefits and OPEB are as follows:

 AEP
 APCo
 I&M
 OPCo
 PSO

 2024
 $
 369.5
 $
 36.7
 $
 43.9
 $
 39.0
 $
 32.6
 $
 19.7
 $
 24.4

 2025
 361.8
 34.3
 43.3
 39.7
 32.7
 19.2
 25.8

 2026
 365.7
 34.5
 44.1
 39.7
 32.5
 19.4
 26.1

 2027
 361.9
 32.2
 42.6
 39.8
 32.4
 19.3
 25.3

 2028
 357.8
 32.2
 43.5
 39.4
 31.3
 19.0
 23.7

 Years 2029 to 2033, in Total
 1,657.6
 133.5
 200.0
 189.4
 144.5
 81.0
 105.6

 OPEB Benefit Payments
 AEP
 APCo
 I&M
 OPCo
 PSO

 2024
 $
 117.2
 $
 9.4
 $
 18.8
 $
 15.2
 $
 12.6
 $
 6.7
 $
 7.8

 2025
 122.6
 10.0
 19.4
 15.7
 13.0
 7.1
 8.3

 2026
 122.4
 10.2
 19.3
 15.7
 12.8
 7.0
 8.3

 2027
 121.5
 10.2
 19.1
 15.4
 12.7
 6.8
 8.1

 2028
 120.2
 9.9
 19.0
 15.0
 12.5
 6.5
 8.2

 Years 2029 to 2033, in Total
 566.1
 45.2
 88.3
 69.7
 57.6
 30.2
 38.8

 OPEB Medicare
Subsidy Receipts
 AEP
 APCo
 I&M
 OPCo
 PSO

 2024
 $
 0.3
 $
 —
 $
 0.1
 $
 —
 $
 —
 $
 —
 $
 —

 2025
 0.3
 —
 0.1
 —
 —
 —
 —

 2026
 0.3
 —
 0.1
 —
 —
 —
 —

 2027
 0.3
 —
 0.1
 —
 —
 —
 —

 2028
 0.3
 —
 0.1
 —
 —
 —
 —

 Years 2029 to 2033, in Total
 1.5
 —
 0.5
 —
 —
 —
 —

 Components of Net Periodic Benefit Cost

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

 2023
 AEP
 APCo
 I&M
 OPCo
 PSO

 $
 94.3
 $
 8.2
 $
 9.1
 $
 11.9
 $
 8.4
 $
 5.5
 $
 7.7

 219.2
 18.3
 26.4
 24.9
 19.8
 10.7
 13.9

 ( 339.2)
 ( 28.1)
 ( 44.6)
 ( 44.2)
 ( 34.0)

 Amortization of Net Actuarial Loss
 1.4
 0.1
 —
 0.1
 —
 —
 0.1

 Net Periodic Benefit Cost (Credit)
 ( 24.3)
 ( 7.3)
 ( 5.8)
 2.3

 ( 43.6)
 ( 4.7)
 ( 4.7)
 ( 3.0)

 Net Periodic Benefit Credit Recognized in Expense
 $
 ( 67.9)
 $
 $
 ( 13.3)
 $
 $
 ( 10.5)
 $
 ( 4.6)
 $

 2022
 AEP
 APCo
 I&M
 OPCo
 PSO

 $
 123.1
 $
 11.1
 $
 11.4
 $
 16.2
 $
 11.2
 $
 7.4
 $
 10.6

 148.2
 12.1
 17.5
 17.0
 13.3
 7.0
 9.1

 ( 253.4)
 ( 21.0)
 ( 32.3)
 ( 32.4)
 ( 24.8)
 ( 13.4)
 ( 14.6)

 Amortization of Net Actuarial Loss
 63.0
 5.2
 7.4
 7.1
 5.5
 2.9
 3.8

 Net Periodic Benefit Cost
 80.9
 7.4
 4.0
 7.9
 5.2
 3.9
 8.9

 ( 53.8)
 ( 5.0)
 ( 4.6)

 Net Periodic Benefit Cost (Credit) Recognized in Expense
 $
 27.1
 $
 1.2
 $
 $
 3.3
 $
 $
 0.7
 $
 4.9

 2021
 AEP
 APCo
 I&M
 OPCo
 PSO

 $
 129.2
 $
 11.8
 $
 11.9
 $
 17.5
 $
 11.4
 $
 8.0
 $
 11.2

 137.2
 11.2
 16.4
 16.2
 12.5
 6.7
 8.5

 ( 229.7)
 ( 19.5)
 ( 29.1)
 ( 28.9)
 ( 22.3)
 ( 12.3)
 ( 13.5)

 Amortization of Net Actuarial Loss
 101.5
 8.3
 12.0
 11.7
 9.1
 4.9
 6.2

 Net Periodic Benefit Cost
 138.2
 11.8
 11.2
 16.5
 10.7
 7.3
 12.4

 ( 55.7)
 ( 6.6)
 ( 5.2)
 ( 4.1)

 Net Periodic Benefit Cost Recognized in Expense
 $
 82.5
 $
 5.2
 $
 6.0
 $
 11.6
 $
 4.5
 $
 3.9
 $
 8.3

 OPEB

 2023
 AEP
 APCo
 I&M
 OPCo
 PSO

 $
 4.6
 $
 0.3
 $
 0.5
 $
 0.6
 $
 0.4
 $
 0.3
 $
 0.4

 46.2
 3.6
 7.4
 5.4
 4.7
 2.4
 2.9

 ( 109.6)
 ( 9.0)
 ( 16.1)
 ( 13.5)
 ( 5.9)
 ( 7.2)

 ( 63.1)
 ( 5.3)
 ( 9.2)
 ( 8.7)

 Amortization of Net Actuarial Loss
 14.8
 1.2
 2.3
 1.9
 1.6
 0.8
 1.0

 Net Periodic Benefit Credit
 ( 107.1)
 ( 9.2)
 ( 15.1)
 ( 14.3)
 ( 11.4)
 ( 7.8)

 Net Periodic Benefit Credit Recognized in Expense
 $
 ( 109.2)
 $
 ( 9.4)
 $
 ( 15.3)
 $
 ( 14.5)
 $
 ( 11.6)
 $
 ( 6.5)
 $
 ( 8.0)

 2022
 AEP
 APCo
 I&M
 OPCo
 PSO

 $
 7.4
 $
 0.5
 $
 0.8
 $
 0.9
 $
 0.6
 $
 0.4
 $
 0.6

 29.2
 2.2
 4.7
 3.4
 3.0
 1.5
 1.8

 ( 110.0)
 ( 13.7)
 ( 12.0)
 ( 7.3)

 ( 71.4)
 ( 9.7)
 ( 7.1)
 ( 5.3)

 Net Periodic Benefit Credit
 ( 144.8)
 ( 12.5)
 ( 21.2)
 ( 19.1)
 ( 10.2)

 Net Periodic Benefit Credit Recognized in Expense
 $
 ( 148.0)
 $
 ( 12.8)
 $
 ( 21.6)
 $
 $
 ( 15.8)
 $
 $

 2021
 AEP
 APCo
 I&M
 OPCo
 PSO

 $
 9.5
 $
 0.7
 $
 1.0
 $
 1.3
 $
 0.8
 $
 0.6
 $
 0.8

 30.5
 2.4
 4.9
 3.5
 3.0
 1.6
 1.9

 ( 91.1)
 ( 7.5)
 ( 13.5)
 ( 11.1)
 ( 9.7)
 ( 5.0)

 ( 70.9)
 ( 6.0)
 ( 10.3)
 ( 9.6)
 ( 7.2)
 ( 5.3)

 Net Periodic Benefit Credit
 ( 122.0)
 ( 17.9)
 ( 15.9)
 ( 13.1)
 ( 7.2)
 ( 8.7)

 ( 4.1)

 Net Periodic Benefit Credit Recognized in Expense
 $
 ( 126.1)
 $
 ( 10.8)
 $
 $
 $
 ( 13.5)
 $
 ( 7.5)
 $
 ( 9.0)

 American Electric Power System Retirement Savings Plan

 AEPSC sponsors the American Electric Power System Retirement Savings Plan, a defined contribution retirement savings plan for substantially all AEP subsidiary employees who are not covered by a retirement savings plan of the UMWA. This qualified plan offers participants an opportunity to contribute a portion of their pay, includes features under Section 401(k) of the Internal Revenue Code and provides for company matching contributions. The matching contributions to the plan are 100 % of the first 1 % of eligible employee contributions and 70 % of the next 5 % of contributions.

 The following table provides the cost for matching contributions to the retirement savings plans by Registrant:

 Year Ended December 31,
 AEP
 APCo
 I&M
 OPCo
 PSO

 2023
 $
 87.9
 $
 7.1
 $
 8.4
 $
 11.0
 $
 8.2
 $
 5.3
 $
 6.7

 2022
 81.9
 6.5
 7.8
 11.1
 7.7
 4.7
 6.4

 2021
 79.9
 6.4
 7.6
 10.9
 7.2
 4.6
 6.4

 UMWA Benefits

 Health and Welfare Benefits (Applies to AEP and APCo)

 AEP provides health and welfare benefits negotiated with the UMWA for certain unionized employees, retirees and their survivors who meet eligibility requirements. APCo also provides the same UMWA health and welfare benefits for certain unionized mining retirees and their survivors who meet eligibility requirements. AEP and APCo administer the health and welfare benefits and pay them from their general assets.

 Multiemployer Pension Benefits (Applies to AEP)

 UMWA pension benefits are provided through the United Mine Workers of America 1974 Pension Plan (Employer Identification Number: 52-1050282, Plan Number 002), a multiemployer plan. The UMWA pension benefits are administered by a board of trustees appointed in equal numbers by the UMWA and the Bituminous Coal Operators' Association (BCOA), an industry bargaining association. AEP makes contributions to the United Mine Workers of America 1974 Pension Plan based on provisions in its labor agreement and the plan documents. The UMWA pension plan is different from single-employer plans as an employer's contributions may be used to provide benefits to employees of other participating employers. A withdrawing employer may be subject to a withdrawal liability, which is calculated based upon that employer's share of the plan's unfunded benefit obligations. If an employer fails to make required contributions or if its payments in connection with its withdrawal liability fall short of satisfying its share of the plan's unfunded benefit obligations, the remaining employers may be allocated a greater share of the remaining unfunded plan obligations. Under the Pension Protection Act of 2006 (PPA), the UMWA pension plan is in Critical Status for the plan year beginning July 1, 2023 and was in Critical Status for the plan year beginning July 1, 2022. As required under the PPA, the Plan adopted a Rehabilitation Plan in 2015. The Rehabilitation Plan has been updated annually, most recently in April 2023.

 AEP affiliates contributed $ 396 thousand, $ 329 thousand and $ 339 thousand to the United Mine Workers of America 1974 Pension Plan for the years ended December 31, 2023, 2022 and 2021, respectively. The contributions did not include surcharges. An AEP affiliate, Cook Coal Terminal (CCT), was listed in the plan's 2021 Form 5500 as providing more than 5 percent of the total contributions for the plan year ending June 30, 2022. The plan's 2022 Form 5500 is expected to be filed in the second quarter of 2024.

 Under the terms of the UMWA pension plan, contributions will be required to continue beyond the January 25, 2025 expiration of the current collective bargaining agreement between the CCT facility and the UMWA, whether or not the term of that agreement is extended or a subsequent agreement is entered, so long as both the UMWA pension plan remains in effect and an AEP affiliate continues to operate the facility covered by the current collective bargaining agreement. The contribution rate applicable would be determined in accordance with the terms of the UMWA pension plan by reference to the National Bituminous Coal Wage Agreement, subject to periodic revisions, between the UMWA and the BCOA. If the UMWA pension plan would terminate or an AEP affiliate would cease operation of the facility without arranging for a successor operator to assume its liability, the withdrawal liability obligation would be triggered.

 AEP records a UMWA pension withdrawal liability on the balance sheet that is re-measured annually and is the estimated value of the company's anticipated contributions toward its proportionate share of the plan's unfunded vested liabilities. As of December 31, 2023 and 2022, the liability balance was $ 13 million and $ 12 million, respectively. AEP recovers the estimated value of its UMWA pension withdrawal liability through fuel clauses in certain regulated jurisdictions. AEP records a regulatory asset on the balance sheets when the UMWA pension withdrawal liability exceeds the cumulative billings collected and a regulatory liability on the balance sheets when the cumulative billings collected exceed the withdrawal liability. If any portion of the UMWA pension withdrawal liability is not recoverable, it could reduce future net income and cash flows and impact financial condition.

 9. BUSINESS SEGMENTS

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

 AEP's Reportable Segments

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

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

 • 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 of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo.
 • OPCo purchases energy and capacity to serve standard service offer customers and provides transmission and distribution services for all connected load.

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

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

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

 AEP's Chief Operating Decision Maker makes operating decisions, allocates resources to and assesses performance based on these operating segments. AEP measures segment profit or loss based on net income (loss). Net income (loss) includes intercompany revenues and expenses that are eliminated on the Consolidated Financial Statements. In addition, direct interest expense and income taxes are included in net income (loss).

 The tables below present AEP's reportable segment income statement information for the years ended December 31, 2023, 2022 and 2021 and reportable segment balance sheet information as of December 31, 2023 and 2022.

 Corporate and Other (a)

 2023

 $
 11,303.7
 $
 5,677.2
 $
 397.4
 $
 1,543.3
 $
 60.7
 $
 —
 $
 18,982.3

 Other Operating Segments

 145.8
 36.1
 1,331.1
 88.9
 107.3
 ( 1,709.2)
 (b)
 —

 $
 11,449.5
 $
 5,713.3
 $
 1,728.5
 $
 1,632.2
 $
 168.0
 $
 ( 1,709.2)
 $
 18,982.3

 $
 85.6
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —
 $
 85.6

 —
 —
 —
 92.7
 —
 —
 92.7

 1,876.4
 784.7
 402.6
 42.7
 ( 16.0)
 —
 3,090.4

 764.5
 363.6
 202.6
 76.0
 594.7
 ( 194.5)
 1,806.9

 ( 45.2)
 140.2
 166.0
 ( 122.9)
 ( 83.5)
 —
 54.6

 Equity Earnings (Loss) of Unconsolidated Subsidiaries
 1.4
 —
 82.9
 ( 16.5)
 —
 58.5

 $
 1,093.9
 $
 698.7
 $
 706.7
 $
 ( 29.1)
 $
 ( 257.6)
 $
 —
 $

 $
 3,486.8
 $
 2,467.4
 $
 1,528.7
 $
 12.6
 $
 36.6
 $
 1.4
 $
 7,533.5

 $
 51,802.1
 $
 24,838.4
 $
 16,575.6
 $
 2,598.5
 $
 5,194.0
 (c)
 $
 ( 4,324.6)
 (d)
 $
 96,684.0

 Investments in Equity Method Investees
 $
 10.0
 $
 3.0
 $
 905.8
 $
 100.6
 $
 54.2
 $
 —
 $
 1,073.6

 Corporate and Other (a)

 2022

 $
 11,292.8
 $
 5,489.6
 $
 357.5
 $
 2,448.9
 $
 50.7
 $
 —
 $
 19,639.5

 Other Operating Segments

 184.7
 22.4
 1,319.5
 18.0
 59.2
 ( 1,603.8)
 (b)
 —

 $
 11,477.5
 $
 5,512.0
 $
 1,677.0
 $
 2,466.9
 $
 109.9
 $
 ( 1,603.8)
 $
 19,639.5

 $
 —
 $
 —
 $
 —
 $
 —
 $
 363.3
 $
 —
 $
 363.3

 24.9
 —
 —
 —
 23.9
 —
 48.8

 —
 —
 —
 —
 —

 Gain on Sale of Mineral Rights
 —
 —
 —
 ( 116.3)
 —
 —
 ( 116.3)

 2,007.2
 746.7
 355.0
 93.0
 0.9
 —
 3,202.8

 650.9
 328.0
 169.3
 51.8
 308.9
 ( 112.8)
 1,396.1

 ( 93.8)
 116.9
 193.6
 ( 83.1)
 ( 128.2)
 —
 5.4

 Equity Earnings (Loss) of Unconsolidated Subsidiaries
 1.4
 0.6
 83.4
 ( 192.4)
 —
 ( 109.4)

 $
 1,296.2
 $
 595.7
 $
 676.8
 $
 274.5
 $
 ( 537.6)
 $
 —
 $

 $
 4,164.6
 $
 2,177.3
 $
 1,470.8
 $
 69.2
 $
 25.9
 $
 ( 28.8)
 $
 7,879.0

 $
 49,761.8
 $
 22,920.2
 $
 15,215.8
 $
 4,520.1
 $
 6,768.4
 (c)
 $
 ( 5,783.0)
 (d)
 $
 93,403.3

 Investments in Equity Method Investees

 $
 10.1
 $
 3.0
 $
 858.3
 $
 337.6
 $
 67.7
 $
 —
 $
 1,276.7

 Corporate and Other (a)

 2021

 $
 9,852.2
 $
 4,464.1
 $
 351.1
 $
 2,108.3
 $
 16.3
 $
 —
 $
 16,792.0

 Other Operating Segments

 146.3
 28.8
 1,175.1
 55.4
 55.9
 ( 1,461.5)
 (b)
 —

 $
 9,998.5
 $
 4,492.9
 $
 1,526.2
 $
 2,163.7
 $
 72.2
 $
 ( 1,461.5)
 $
 16,792.0

 $
 11.6
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —
 $
 11.6

 1,747.6
 690.3
 306.0
 80.9
 0.9
 —
 2,825.7

 574.2
 300.9
 146.3
 15.6
 180.8
 ( 18.7)
 1,199.1

 ( 11.2)
 77.5
 159.6
 ( 48.8)
 ( 61.6)
 —
 115.5

 Equity Earnings (Loss) of Unconsolidated Subsidiaries
 3.4
 —
 75.0
 23.9
 —
 91.7

 $
 1,116.7
 $
 543.4
 $
 682.0
 $
 210.2
 $
 ( 64.2)
 $
 —
 $

 $
 2,963.1
 $
 1,766.0
 $
 1,468.6
 $
 232.8
 $
 25.5
 $
 $
 6,426.8

 Investments in Equity Method Investees

 $
 33.5
 $
 2.5
 $
 830.4
 $
 487.8
 $
 93.3
 $
 —
 $
 1,447.5

 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent's guarantee revenue received from affiliates, investment income, interest income, interest expense and other nonallocated costs.
 (b) Represents inter-segment revenues.
 (c) Includes elimination of AEP Parent's investments in wholly-owned subsidiary companies.
 (d) Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable.

 Registrant Subsidiaries' Reportable Segments (Applies to all Registrant Subsidiaries except AEPTCo)

 The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an integrated electricity transmission and distribution business for AEP Texas and OPCo. Other activities are insignificant. The Registrant Subsidiaries' operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.

 AEPTCo's Reportable Segments

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

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

 The tables below present AEPTCo's reportable segment income statement information for the years ended December 31, 2023, 2022 and 2021 and reportable segment balance sheet information as of December 31, 2023 and 2022.

 State Transcos
 AEPTCo Parent

 2023

 $
 354.2
 $
 —
 $
 —
 $
 354.2

 1,317.8
 —
 —
 1,317.8

 $
 1,672.0
 $
 —
 $
 —
 $
 1,672.0

 $
 393.8
 $
 —
 $
 —
 $
 393.8

 3.8
 218.0
 ( 214.8)
 (a)
 7.0

 83.2
 —
 —
 83.2

 194.2
 215.1
 ( 214.8)
 (a)
 194.5

 145.7
 1.4
 —
 147.1

 $
 612.9
 $
 1.3
 (b)
 $
 —
 $
 614.2

 $
 1,503.1
 $
 —
 $
 —
 $
 1,503.1

 $
 15,120.6
 $
 5,486.6
 (c)
 $
 ( 5,534.7)
 (d)
 $
 15,072.5

 State Transcos
 AEPTCo Parent

 2022

 $
 340.9
 $
 —
 $
 —
 $
 340.9

 1,283.8
 —
 —
 1,283.8

 —
 —

 $
 1,624.5
 $
 —
 $
 —
 $
 1,624.5

 $
 346.2
 $
 —
 $
 —
 $
 346.2

 0.7
 177.8
 ( 176.9)
 (a)
 1.6

 70.7
 —
 —
 70.7

 162.5
 177.1
 ( 176.9)
 (a)
 162.7

 169.1
 —
 —
 169.1

 $
 594.2
 $
 —
 (b)
 $
 —
 $
 594.2

 $
 1,468.3
 $
 —
 $
 —
 $
 1,468.3

 $
 13,875.6
 $
 4,817.4
 (c)
 $
 ( 4,878.8)
 (d)
 $
 13,814.2

 State Transcos
 AEPTCo Parent

 2021

 $
 315.1
 $
 —
 $
 —
 $
 315.1

 1,153.9
 —
 —
 1,153.9

 0.3
 —
 —
 0.3

 $
 1,469.3
 $
 —
 $
 —
 $
 1,469.3

 $
 297.3
 $
 —
 $
 —
 $
 297.3

 0.1
 158.1
 ( 157.7)
 (a)
 0.5

 67.2
 —
 —
 67.2

 141.2
 157.7
 ( 157.7)
 (a)
 141.2

 144.1
 —
 —
 144.1

 $
 591.5
 $
 0.2
 (b)
 $
 —
 $
 591.7

 $
 1,442.7
 $
 —
 $
 —
 $
 1,442.7

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

 10. DERIVATIVES AND HEDGING

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

 OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

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

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

 STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

 Risk Management Strategies

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

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

 The following table represents the gross notional volume of the Registrants' outstanding derivative contracts:

 Notional Volume of Derivative Instruments

 Primary Risk
 AEP
 APCo
 I&M
 OPCo
 PSO
 AEP
 APCo
 I&M
 OPCo
 PSO

 Commodity:

 Power (MWhs)
 246.8
 —
 16.8
 5.9
 2.2
 4.1
 2.9
 226.8
 —
 17.9
 4.2
 2.5
 2.9
 2.2

 Natural Gas (MMBtus)
 151.6
 —
 37.3
 —
 —
 34.9
 17.9
 77.1
 —
 1.9
 —
 —
 1.9
 2.1

 Heating Oil and Gasoline (Gallons)
 6.5
 1.8
 1.0
 0.6
 1.2
 0.7
 0.9
 6.9
 1.9
 1.0
 0.7
 1.4
 0.9
 1.0

 Interest Rate (USD)
 $
 80.1
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —
 $
 99.9
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —

 Interest Rate on Long-term Debt (USD)
 $
 1,300.0
 $
 150.0
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —
 $
 1,650.0
 $
 —
 $
 —
 $
 —
 $
 —
 $
 200.0
 $
 —

 Fair Value Hedging Strategies (Applies to AEP)

 Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating-rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges.

 Cash Flow Hedging Strategies

 The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power ("Commodity") in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk.

 The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure.

 ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

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

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

 According to the accounting guidance for "Derivatives and Hedging," the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third-party contractual agreements and risk profiles. AEP netted cash collateral received from third-parties against short-term and long-term risk management assets in the amounts of $ 46 million and $ 481 million as of December 31, 2023 and 2022, respectively. There was no cash collateral received from third-parties netted against short-term and long-term risk management assets for the Registrant Subsidiaries as of December 31, 2023 and 2022. The amount of cash collateral paid to third-parties netted against short-term and long-term risk management liabilities was not material for the Registrants as of December 31, 2023 and 2022.

 Location and Fair Value of Derivative Assets and Liabilities Recognized In the Balance Sheet

 The following tables represent the gross fair value of the Registrants' derivative activity on the balance sheets. The derivative instruments are disclosed as gross. They are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." Unless shown as a separate line on the balance sheets due to materiality, Current Risk Management Assets are included in Prepayments and Other Current Assets, Long-term Risk Management Assets are included in Deferred Charges and Other Noncurrent Assets, Current Risk Management Liabilities are included in Other Current Liabilities and Long-term Risk Management Liabilities are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets.

 AEP
 APCo
 I&M
 OPCo
 PSO

 Current Risk Management Assets

 $
 555.1
 $
 —
 $
 24.6
 $
 30.1
 $
 —
 $
 19.7
 $
 12.0

 56.7
 —
 —
 —
 —
 —
 —

 —
 —
 —
 —
 —
 —
 —

 Total Current Risk Management Assets
 611.8
 —
 24.6
 30.1
 —
 19.7
 12.0

 468.8
 —
 0.3
 12.0
 —
 —
 0.5

 86.8
 —
 —
 —
 —
 —
 —

 —
 —
 —
 —
 —
 —
 —

 Total Long-term Risk Management Assets
 555.6
 —
 0.3
 12.0
 —
 —
 0.5

 $
 1,167.4
 $
 —
 $
 24.9
 $
 42.1
 $
 —
 $
 19.7
 $
 12.5

 Current Risk Management Liabilities

 $
 588.0
 $
 0.2
 $
 18.5
 $
 5.4
 $
 6.9
 $
 29.7
 $
 14.9

 8.2
 —
 —
 —
 —
 —
 —

 50.5
 2.7
 —
 —
 —
 —
 —

 Total Current Risk Management Liabilities
 646.7
 2.9
 18.5
 5.4
 6.9
 29.7
 14.9

 377.6
 —
 6.9
 0.2
 43.9
 1.0
 1.7

 2.2
 —
 —
 —
 —
 —
 —

 56.9
 —
 —
 —
 —
 —
 —

 Total Long-term Risk Management Liabilities
 436.7
 —
 6.9
 0.2
 43.9
 1.0
 1.7

 Total Liabilities
 $
 1,083.4
 $
 2.9
 $
 25.4
 $
 5.6
 $
 50.8
 $
 30.7
 $
 16.6

 Total MTM Derivative Contract Net Assets (Liabilities) Recognized
 $
 84.0
 $
 ( 2.9)
 $
 $
 36.5
 $
 ( 50.8)
 $
 ( 11.0)
 $
 ( 4.1)

 AEP
 APCo
 I&M
 OPCo
 PSO

 Current Risk Management Assets

 $
 965.4
 $
 —
 $
 69.3
 $
 16.0
 $
 —
 $
 24.1
 $
 16.8

 212.2
 —
 —
 —
 —
 —
 —

 1.8
 —
 —
 —
 —
 1.6
 —

 Total Current Risk Management Assets
 1,179.4
 —
 69.3
 16.0
 —
 25.7
 16.8

 565.6
 —
 0.7
 0.5
 —
 —
 —

 148.9
 —
 —
 —
 —
 —
 —

 14.3
 —
 —
 —
 —
 —
 —

 Total Long-term Risk Management Assets
 728.8
 —
 0.7
 0.5
 —
 —
 —

 $
 1,908.2
 $
 —
 $
 70.0
 $
 16.5
 $
 —
 $
 25.7
 $
 16.8

 Current Risk Management Liabilities

 $
 663.8
 $
 —
 $
 4.1
 $
 0.9
 $
 2.1
 $
 2.1
 $
 2.0

 60.4
 —
 —
 —
 —
 —
 —

 41.4
 —
 —
 —
 —
 —
 —

 Total Current Risk Management Liabilities
 765.6
 —
 4.1
 0.9
 2.1
 2.1
 2.0

 412.0
 —
 0.7
 0.3
 37.9
 —
 —

 17.4
 —
 —
 —
 —
 —
 —

 91.1
 —
 —
 —
 —
 —
 —

 Total Long-term Risk Management Liabilities
 520.5
 —
 0.7
 0.3
 37.9
 —
 —

 Total Liabilities
 $
 1,286.1
 $
 —
 $
 4.8
 $
 1.2
 $
 40.0
 $
 2.1
 $
 2.0

 Total MTM Derivative Contract Net Assets (Liabilities) Recognized
 $
 622.1
 $
 —
 $
 65.2
 $
 15.3
 $
 ( 40.0)
 $
 23.6
 $
 14.8

 Offsetting Assets and Liabilities

 The following tables show the net amounts of assets and liabilities presented on the balance sheets. The gross amounts offset include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with accounting guidance for "Derivatives and Hedging." All derivative contracts subject to a master netting arrangement or similar agreement are offset on the balance sheets.

 AEP
 APCo
 I&M
 OPCo
 PSO

 Current Risk Management Assets

 $
 611.8
 $
 —
 $
 24.6
 $
 30.1
 $
 —
 $
 19.7
 $
 12.0

 ( 394.3)
 —
 —

 217.5
 —
 22.4
 27.8
 —
 19.0
 11.6

 555.6
 —
 0.3
 12.0
 —
 —
 0.5

 ( 234.4)
 —
 —
 —

 321.2
 —
 —
 11.8
 —
 —
 —

 $
 538.7
 $
 —
 $
 22.4
 $
 39.6
 $
 —
 $
 19.0
 $
 11.6

 Current Risk Management Liabilities

 $
 646.7
 $
 2.9
 $
 18.5
 $
 5.4
 $
 6.9
 $
 29.7
 $
 14.9

 ( 417.1)

 229.6
 2.7
 15.9
 2.0
 6.8
 28.9
 14.4

 436.7
 —
 6.9
 0.2
 43.9
 1.0
 1.7

 ( 194.9)
 —
 —
 —

 241.8
 —
 6.6
 —
 43.9
 1.0
 1.2

 Total Liabilities
 $
 471.4
 $
 2.7
 $
 22.5
 $
 2.0
 $
 50.7
 $
 29.9
 $
 15.6

 Total MTM Derivative Contract Net Assets (Liabilities)
 $
 67.3
 $
 ( 2.7)
 $
 $
 37.6
 $
 ( 50.7)
 $
 $

 AEP
 APCo
 I&M
 OPCo
 PSO

 Current Risk Management Assets

 $
 1,179.4
 $
 —
 $
 69.3
 $
 16.0
 $
 —
 $
 25.7
 $
 16.8

 ( 830.6)
 —
 —

 348.8
 —
 69.1
 15.2
 —
 25.3
 16.4

 728.8
 —
 0.7
 0.5
 —
 —
 —

 ( 444.7)
 —
 —
 —
 —

 284.1
 —
 —
 0.2
 —
 —
 —

 $
 632.9
 $
 —
 $
 69.1
 $
 15.4
 $
 —
 $
 25.3
 $
 16.4

 Current Risk Management Liabilities

 $
 765.6
 $
 —
 $
 4.1
 $
 0.9
 $
 2.1
 $
 2.1
 $
 2.0

 ( 620.4)
 —

 145.2
 —
 3.6
 —
 1.8
 1.6
 1.4

 520.5
 —
 0.7
 0.3
 37.9
 —
 —

 ( 175.3)
 —
 —
 —
 —

 345.2
 —
 0.1
 —
 37.9
 —
 —

 Total Liabilities
 $
 490.4
 $
 —
 $
 3.7
 $
 —
 $
 39.7
 $
 1.6
 $
 1.4

 Total MTM Derivative Contract Net Assets (Liabilities)
 $
 142.5
 $
 —
 $
 65.4
 $
 15.4
 $
 ( 39.7)
 $
 23.7
 $
 15.0

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

 Amount of Gain (Loss) Recognized on Risk Management Contracts

 Location of Gain (Loss)
 AEP
 APCo
 I&M
 OPCo
 PSO

 Vertically Integrated Utilities Revenues
 $
 24.6
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —

 Generation & Marketing Revenues
 ( 423.8)
 —
 —
 —
 —
 —
 —

 Electric Generation, Transmission and Distribution Revenues
 —
 —
 0.1
 24.5
 —
 —
 —

 2.5
 —
 2.3
 0.1
 —
 —
 —

 —
 —
 —
 —
 —

 Regulatory Assets (a)
 ( 94.8)
 ( 21.9)
 ( 3.1)
 ( 14.0)
 ( 29.8)

 Regulatory Liabilities (a)
 169.7
 —
 1.0
 7.8
 —
 88.7
 70.7

 Total Gain (Loss) on Risk Management Contracts
 $
 ( 322.8)
 $
 $
 ( 18.6)
 $
 29.2
 $
 ( 14.1)
 $
 58.8
 $
 55.0

 Location of Gain (Loss)
 AEP
 APCo
 I&M
 OPCo
 PSO

 Vertically Integrated Utilities Revenues
 $
 11.1
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —

 Generation & Marketing Revenues
 313.8
 —
 —
 —
 —
 —
 —

 Electric Generation, Transmission and Distribution Revenues
 —
 —
 0.5
 10.6
 —
 —
 —

 5.0
 —
 4.5
 0.1
 —
 0.2
 —

 4.8
 1.5
 0.4
 0.5
 0.8
 0.6
 0.8

 6.7
 1.8
 0.9
 0.6
 1.2
 0.8
 1.1

 Regulatory Assets (a)
 52.6
 0.1
 52.1
 3.6

 Regulatory Liabilities (a)
 299.7
 82.4
 8.6
 3.7
 98.5
 77.9

 Total Gain on Risk Management Contracts
 $
 693.7
 $
 2.8
 $
 88.6
 $
 19.6
 $
 57.8
 $
 103.7
 $
 77.7

 Location of Gain (Loss)
 AEP
 APCo
 I&M
 OPCo
 PSO

 Vertically Integrated Utilities Revenues
 $
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —
 $
 —

 Generation & Marketing Revenues
 169.1
 —
 —
 —
 —
 —
 —

 Electric Generation, Transmission and Distribution Revenues
 —
 —
 —
 —
 —

 2.0
 —
 1.8
 —
 —
 —
 —

 2.8
 0.8
 0.3
 0.3
 0.5
 0.3
 0.4

 3.4
 1.0
 0.5
 0.3
 0.6
 0.4
 0.5

 Regulatory Assets (a)
 —
 ( 2.7)
 10.0
 3.6

 Regulatory Liabilities (a)
 156.4
 0.2
 55.9
 —
 48.9
 37.0

 Total Gain (Loss) on Risk Management Contracts
 $
 324.0
 $
 2.0
 $
 55.3
 $
 ( 18.2)
 $
 11.1
 $
 46.0
 $
 41.5

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

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

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

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

 Accounting for Fair Value Hedging Strategies (Applies to AEP)

 For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts net income during the period of change.

 AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income.

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

 Carrying Amount of the Hedged Liabilities
 Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Liabilities

 Long-term Debt (a) (b)
 $
 ( 878.2)
 $
 ( 855.5)
 $
 68.4
 $
 89.7

 (a) Amounts included within Noncurrent Liabilities line item Long-term Debt on the Balance Sheet.
 (b) Amounts include $( 30) million and $( 38) million as of December 31, 2023 and 2022, respectively, for the fair value hedge adjustment of hedged debt obligations for which hedge accounting has been discontinued.

 The pretax effects of fair value hedge accounting on income were as follows:

 2023
 2022
 2021

 Gain (Loss) on Interest Rate Contracts:

 Fair Value Hedging Instruments (a)
 $
 29.0
 $
 ( 90.4)
 $
 ( 35.5)

 Fair Value Portion of Long-term Debt (a)
 ( 29.0)
 90.4
 35.5

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

 Accounting for Cash Flow Hedging Strategies (Applies to AEP, AEP Texas, APCo, I&M, PSO and SWEPCo)

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

 Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity, Fuel and Other Consumables Used for Electric Generation on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the years ended 2023, 2022 and 2021, AEP applied cash flow hedging to outstanding power derivatives and the Registrant Subsidiaries did not.

 The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the year ended 2023, AEP, AEP Texas, I&M, PSO and SWEPCo applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not. During the year ended 2022, AEP and PSO applied cash flow hedging to outstanding interest rate derivatives. During the year ended 2021, AEP and APCo applied cash flow hedging to outstanding interest rate derivatives.

 For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 - Comprehensive Income.

 Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were:

 Impact of Cash Flow Hedges on the Registrants' Balance Sheets

 Portion Expected to
 Portion Expected to

 AOCI
 be Reclassed to
 AOCI
 be Reclassed to

 Gain (Loss)
 Net Income During
 Gain (Loss)
 Net Income During

 Net of Tax
 the Next Twelve Months
 Net of Tax
 the Next Twelve Months

 AEP
 $
 104.9
 $
 $
 38.3
 $
 3.2
 $
 223.5
 $
 0.3
 $
 119.9
 $
 0.3

 —
 0.5
 —
 0.2
 —
 —

 APCo
 —
 5.9
 —
 0.8
 —
 6.7
 —
 0.8

 I&M
 —
 ( 5.5)
 —
 —
 ( 5.1)
 —

 PSO
 —
 —
 —
 —
 1.3
 —
 0.1

 —
 1.3
 —
 0.3
 —
 1.1
 —
 0.2

 As of December 31, 2023 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 87 months.

 The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.

 Credit Risk

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

 Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP's credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required.

 Credit-Risk-Related Contingent Features

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

 A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these collateral triggering events in contracts. The Registrants have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. AEP had derivative contracts with collateral triggering events in a net liability position with a total exposure of $ 0 and $ 2 million as of December 31, 2023 and 2022, respectively. The Registrant Subsidiaries had no derivative contracts with collateral triggering events in a net liability position as of December 31, 2023 and 2022.

 Cross-Acceleration Triggers

 Certain interest rate derivative contracts contain cross-acceleration provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-acceleration provisions could be triggered if there was a non-performance event by the Registrants under any of their outstanding debt of at least $ 50 million and the lender on that debt has accelerated the entire repayment obligation. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these cross-acceleration provisions in contracts. AEP had derivative contracts with cross-acceleration provisions in a net liability position of $ 107 million and $ 127 million and no cash collateral posted as of December 31, 2023 and 2022, respectively. If a cross-acceleration provision would have been triggered, settlement at fair value would have been required. The Registrant Subsidiaries' derivative contracts with cross-acceleration provisions outstanding as of December 31, 2023 and 2022 were not material.

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

 In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third-party obligation that is $ 50 million or greater. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these cross-default provisions in the contracts. AEP had derivative contracts with cross-default provisions in a net liability position of $ 242 million and $ 217 million and no cash collateral posted as of December 31, 2023 and 2022, respectively, after considering contractual netting arrangements. If a cross-default provision would have been triggered, settlement at fair value would have been required. APCo, PSO and SWEPCo had derivative contracts with cross-default provisions in a net liability position of $22 million, $29 million and $15 million, respectively, and no cash collateral posted as of December 31, 2023. The other Registrant Subsidiaries had no derivative contracts with cross-default provisions outstanding as of December 31, 2023. The Registrant Subsidiaries' derivative contracts with cross-default provisions outstanding as of December 31, 2022 were not material.

 11. FAIR VALUE MEASUREMENTS

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

 Fair Value Measurements of Long-term Debt (Applies to all Registrants)

 The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The fair value of AEP's Equity Units (Level 1) are valued based on publicly-traded securities issued by AEP.

 The book values and fair values of Long-term Debt are summarized in the following table:

 2023
 2022

 Book Value
 Fair Value
 Book Value
 Fair Value

 AEP (a)
 $
 40,143.2
 $
 37,325.7
 $
 36,801.0
 $
 35,915.9

 5,889.8
 5,400.7
 5,657.8
 5,045.8

 5,414.4
 4,796.9
 4,782.8
 3,940.5

 APCo
 5,588.3
 5,390.1
 5,410.5
 5,079.2

 I&M
 3,499.4
 3,291.6
 3,260.8
 2,929.0

 OPCo
 2,992.1
 2,970.3
 2,516.6

 PSO
 2,384.6
 2,154.3
 1,912.8
 1,635.8

 3,209.7
 3,391.6
 2,870.9

 (a) The fair value amounts include debt related to AEP's Equity Units and had a fair value of $ 0 million and $ 877 million as of December 31, 2023 and 2022, respectively. See "Equity Units" section of Note 14 for additional information.

 Fair Value Measurements of Other Temporary Investments (Applies to AEP)

 Other Temporary Investments include marketable securities that management intends to hold for less than one year and investments by AEP's protected cell of EIS. See "Other Temporary Investments" section of Note 1 for additional information.

 The following is a summary of Other Temporary Investments and Restricted Cash:

 Gross
 Gross

 Fair

 Other Temporary Investments and Restricted Cash
 Cost
 Gains
 Losses
 Value

 Restricted Cash (a)
 $
 48.9
 $
 —
 $
 —
 $
 48.9

 Other Cash Deposits
 13.9
 —
 —
 13.9

 Fixed Income Securities – Mutual Funds (b)
 165.9
 —
 159.7

 Equity Securities – Mutual Funds
 14.8
 25.9
 —
 40.7

 Total Other Temporary Investments and Restricted Cash
 $
 243.5
 $
 25.9
 $
 $
 263.2

 Gross
 Gross

 Fair

 Other Temporary Investments and Restricted Cash
 Cost
 Gains
 Losses
 Value

 Restricted Cash (a)
 $
 47.1
 $
 —
 $
 —
 $
 47.1

 Other Cash Deposits
 9.0
 —
 —
 9.0

 Fixed Income Securities – Mutual Funds (b)
 152.4
 —
 ( 8.3)
 144.1

 Equity Securities – Mutual Funds
 15.1
 19.4
 —
 34.5

 Total Other Temporary Investments and Restricted Cash
 $
 223.6
 $
 19.4
 $
 ( 8.3)
 $
 234.7

 (a) Primarily represents amounts held for the repayment of debt.
 (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates.

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

 2023
 2022
 2021

 Proceeds from Investment Sales
 $
 7.6
 $
 30.2
 $
 15.0

 Purchases of Investments
 18.5
 18.8
 26.9

 Gross Realized Gains on Investment Sales
 1.1
 6.1
 3.6

 Gross Realized Losses on Investment Sales
 0.3
 1.3
 —

 Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M)

 Securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF are recorded at fair value. See "Nuclear Trust Funds" section of Note 1 for additional information.

 The following is a summary of nuclear trust fund investments:

 2023
 2022

 Gross
 Gross
 Other-Than-
 Gross
 Gross
 Other-Than-

 Fair
 Temporary
 Fair
 Temporary

 Value
 Gains
 Losses
 Impairments
 Value
 Gains
 Losses
 Impairments

 $
 16.8
 $
 —
 $
 —
 $
 —
 $
 21.2
 $
 —
 $
 —
 $
 —

 28.6
 ( 33.2)
 11.8
 ( 14.9)
 ( 18.8)

 132.1
 4.8
 ( 5.2)
 61.6
 0.7
 ( 7.7)
 ( 9.6)

 1.7
 —
 —
 —
 3.3
 0.1
 —

 33.4
 ( 41.8)
 12.6
 ( 22.6)
 ( 28.5)

 Equity Securities - Domestic
 1,869.5
 —
 1,483.7
 —

 $
 $
 1,902.9
 $
 ( 10.0)
 $
 ( 41.8)
 $
 $
 1,496.3
 $
 ( 29.0)
 $
 ( 28.5)

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

 2023
 2022
 2021

 Proceeds from Investment Sales
 $
 2,787.5
 $
 2,713.6
 $
 1,886.4

 Purchases of Investments
 2,845.1
 2,765.4
 1,928.2

 Gross Realized Gains on Investment Sales
 99.0
 52.4
 103.2

 Gross Realized Losses on Investment Sales
 26.6
 42.6
 16.5

 The base cost of fixed income securities was $ 1.4 billion and $ 1.2 billion as of December 31, 2023 and 2022, respectively. The base cost of equity securities was $ 568 million and $ 654 million as of December 31, 2023 and 2022, respectively.

 The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2023 was as follows:

 Fair Value of Fixed

 Income Securities

 Within 1 year
 $
 359.6

 After 1 year through 5 years
 597.6

 After 5 years through 10 years
 180.7

 After 10 years
 268.9

 Total
 $

 Fair Value Measurements of Financial Assets and Liabilities

 For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the "Fair Value Measurements of Assets and Liabilities" section of Note 1.

 The following tables set forth, by level within the fair value hierarchy, the Registrants' financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for "Fair Value Measurements and Disclosures," financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management's valuation techniques.

 AEP

 Other
 Total

 Other Temporary Investments and Restricted Cash

 $
 48.9
 $
 —
 $
 —
 $
 —
 $
 48.9

 Other Cash Deposits (a)
 —
 —
 —
 13.9
 13.9

 Fixed Income Securities – Mutual Funds
 159.7
 —
 —
 —
 159.7

 Equity Securities – Mutual Funds (b)
 40.7
 —
 —
 —
 40.7

 Total Other Temporary Investments and Restricted Cash
 249.3
 —
 —
 13.9
 263.2

 Risk Management Commodity Contracts (c) (d)
 9.7
 736.9
 274.3
 ( 617.0)
 403.9

 Commodity Hedges (c)
 —
 123.5
 19.8
 ( 8.5)
 134.8

 Total Risk Management Assets
 9.7
 860.4
 294.1
 ( 625.5)
 538.7

 Cash and Cash Equivalents (e)
 7.8
 —
 —
 9.0
 16.8

 —
 —
 —

 —
 132.1
 —
 —
 132.1

 —
 1.7
 —
 —
 1.7

 —
 —
 —

 Equity Securities – Domestic (b)
 —
 —
 —

 Total Spent Nuclear Fuel and Decommissioning Trusts
 2,444.4
 —
 9.0

 $
 2,703.4
 $
 2,267.2
 $
 294.1
 $
 ( 602.6)
 $
 4,662.1

 Risk Management Commodity Contracts (c) (d)
 $
 24.7
 $
 783.8
 $
 154.1
 $
 ( 600.3)
 $
 362.3

 Commodity Hedges (c)
 —
 9.6
 0.6
 ( 8.5)
 1.7

 Interest Rate Hedges
 —
 9.0
 —
 —
 9.0

 Fair Value Hedges
 —
 98.4
 —
 —
 98.4

 Total Risk Management Liabilities
 $
 24.7
 $
 900.8
 $
 154.7
 $
 ( 608.8)
 $
 471.4

 AEP

 Other
 Total

 Other Temporary Investments and Restricted Cash

 $
 47.1
 $
 —
 $
 —
 $
 —
 $
 47.1

 Other Cash Deposits (a)
 —
 —
 —
 9.0
 9.0

 Fixed Income Securities – Mutual Funds
 144.1
 —
 —
 —
 144.1

 Equity Securities – Mutual Funds (b)
 34.5
 —
 —
 —
 34.5

 Total Other Temporary Investments and Restricted Cash
 225.7
 —
 —
 9.0
 234.7

 Risk Management Commodity Contracts (c) (f)
 15.0
 1,197.5
 314.4
 ( 1,211.5)
 315.4

 Commodity Hedges (c)
 —
 332.6
 26.7
 ( 52.8)
 306.5

 Interest Rate Hedges
 —
 11.0
 —
 —
 11.0

 Total Risk Management Assets
 15.0
 1,541.1
 341.1
 ( 1,264.3)
 632.9

 Cash and Cash Equivalents (e)
 11.3
 —
 —
 9.9
 21.2

 —
 —
 —

 —
 61.6
 —
 —
 61.6

 —
 3.3
 —
 —
 3.3

 —
 —
 —

 Equity Securities – Domestic (b)
 —
 —
 —

 Total Spent Nuclear Fuel and Decommissioning Trusts
 2,142.6
 —
 9.9

 $
 2,383.3
 $
 2,729.8
 $
 341.1
 $
 ( 1,245.4)
 $
 4,208.8

 Risk Management Commodity Contracts (c) (f)
 $
 21.8
 $
 870.9
 $
 179.0
 $
 ( 731.9)
 $
 339.8

 Commodity Hedges (c)
 —
 74.3
 1.7
 ( 52.8)
 23.2

 Fair Value Hedges
 —
 127.4
 —
 —
 127.4

 Total Risk Management Liabilities
 $
 21.8
 $
 1,072.6
 $
 180.7
 $
 ( 784.7)
 $
 490.4

 Other
 Total

 $
 34.0
 $
 —
 $
 —
 $
 —
 $
 34.0

 $
 —
 $
 0.2
 $
 —
 $
 $
 —

 Interest Rate Hedges
 —
 2.7
 —
 —
 2.7

 Total Risk Management Liabilities
 $
 —
 $
 2.9
 $
 —
 $
 $
 2.7

 Other
 Total

 $
 32.7
 $
 —
 $
 —
 $
 —
 $
 32.7

 APCo

 Other
 Total

 $
 14.9
 $
 —
 $
 —
 $
 —
 $
 14.9

 —
 1.1
 23.5
 22.4

 $
 14.9
 $
 1.1
 $
 23.5
 $
 $
 37.3

 $
 —
 $
 24.0
 $
 1.1
 $
 $
 22.5

 Other
 Total

 $
 14.4
 $
 —
 $
 —
 $
 —
 $
 14.4

 —
 0.7
 69.4
 69.1

 $
 14.4
 $
 0.7
 $
 69.4
 $
 $
 83.5

 $
 —
 $
 4.6
 $
 0.3
 $
 $
 3.5

 I&M

 Other
 Total

 $
 —
 $
 37.4
 $
 4.5
 $
 $
 39.6

 Cash and Cash Equivalents (e)
 7.8
 —
 —
 9.0
 16.8

 —
 —
 —

 —
 132.1
 —
 —
 132.1

 —
 1.7
 —
 —
 1.7

 —
 —
 —

 Equity Securities - Domestic (b)
 —
 —
 —

 Total Spent Nuclear Fuel and Decommissioning Trusts
 2,444.4
 —
 9.0

 $
 2,444.4
 $
 1,444.2
 $
 4.5
 $
 6.7
 $
 3,899.8

 $
 —
 $
 3.7
 $
 1.7
 $
 $
 2.0

 Other
 Total

 $
 —
 $
 11.3
 $
 5.3
 $
 $
 15.4

 Cash and Cash Equivalents (e)
 11.3
 —
 —
 9.9
 21.2

 —
 —
 —

 —
 61.6
 —
 —
 61.6

 —
 3.3
 —
 —
 3.3

 —
 —
 —

 Equity Securities - Domestic (b)
 —
 —
 —

 Total Spent Nuclear Fuel and Decommissioning Trusts
 2,142.6
 —
 9.9

 $
 2,142.6
 $
 1,200.0
 $
 5.3
 $
 8.7
 $
 3,356.6

 $
 —
 $
 0.6
 $
 0.7
 $
 $
 —

 OPCo

 Other
 Total

 $
 —
 $
 0.2
 $
 50.6
 $
 $
 50.7

 Other
 Total

 $
 —
 $
 —
 $
 40.0
 $
 $
 39.7

 PSO

 Other
 Total

 $
 —
 $
 —
 $
 19.7
 $
 $
 19.0

 $
 —
 $
 29.6
 $
 1.1
 $
 $
 29.9

 Other
 Total

 $
 —
 $
 —
 $
 24.0
 $
 1.3
 $
 25.3

 Interest Rate Hedges
 —
 1.6
 —
 —

 $
 —
 $
 1.6
 $
 24.0
 $
 $
 25.3

 $
 —
 $
 1.7
 $
 0.3
 $
 $
 1.6

 Other
 Total

 $
 —
 $
 0.5
 $
 12.0
 $
 $
 11.6

 $
 —
 $
 15.7
 $
 0.9
 $
 $
 15.6

 Other
 Total

 $
 —
 $
 2.2
 $
 14.6
 $
 $
 16.4

 $
 —
 $
 1.6
 $
 0.4
 $
 $
 1.4

 (a) Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or third-parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.
 (b) Amounts represent publicly-traded equity securities and equity-based mutual funds.
 (c) Amounts in "Other" column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for "Derivatives and Hedging."
 (d) The December 31, 2023 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $( 11) million in 2024 and $( 4) million in 2025-2027; Level 2 matures $( 99) million in 2024, $( 44) million in periods 2025-2027, $ 7 million in periods 2028-2029 and $ 2 million in periods 2030-2033; Level 3 matures $ 74 million in 2024, $ 43 million in periods 2025-2027, $ 18 million in periods 2028-2029 and $( 16) million in periods 2030-2033. Risk management commodity contracts are substantially comprised of power contracts.
 (e) Amounts in "Other" column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
 (f) The December 31, 2022 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $( 7) million in 2023; Level 2 matures $ 182 million in 2023, $ 134 million in periods 2024-2026; $ 10 million in periods 2027-2028 and $ 1 million in periods 2029-2033; Level 3 matures $ 128 million in 2023, $ 6 million in periods 2024-2026, $ 6 million in periods 2027-2028 and $( 5) million in periods 2029-2033. Risk management commodity contracts are substantially comprised of power contracts.

 The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:

 AEP
 APCo
 I&M
 OPCo
 PSO

 Balance as of December 31, 2022
 $
 160.4
 $
 69.1
 $
 4.6
 $
 ( 40.0)
 $
 23.7
 $
 14.2

 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 52.1
 ( 11.7)
 4.2
 29.8
 20.0

 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
 71.1
 —
 —
 —
 —
 —

 Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)
 ( 17.4)
 —
 —
 —
 —
 —

 Settlements
 ( 172.2)
 ( 57.3)
 5.6
 ( 53.4)
 ( 34.2)

 Transfers into Level 3 (d) (e)
 —
 —
 —
 —
 —

 Transfers out of Level 3 (e)
 3.8
 —
 —
 —
 —
 —

 Changes in Fair Value Allocated to Regulated Jurisdictions (f)
 47.7
 22.3
 2.8
 18.5
 11.1

 Balance as of December 31, 2023
 $
 139.4
 $
 22.4
 $
 2.8
 $
 ( 50.6)
 $
 18.6
 $
 11.1

 AEP
 APCo
 I&M
 OPCo
 PSO

 Balance as of December 31, 2021
 $
 103.1
 $
 41.7
 $
 $
 ( 92.5)
 $
 12.1
 $
 10.9

 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 69.5
 3.0
 3.7
 6.5
 24.2
 35.8

 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
 ( 34.9)
 —
 —
 —
 —
 —

 Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)
 9.6
 —
 —
 —
 —
 —

 Settlements
 ( 154.6)
 ( 44.7)
 ( 3.0)
 0.3
 ( 36.3)

 Transfers into Level 3 (d) (e)
 1.7
 —
 —
 —
 —
 —

 Transfers out of Level 3 (e)
 0.1
 —
 —
 —
 —
 6.9

 Changes in Fair Value Allocated to Regulated Jurisdictions (f)
 165.9
 69.1
 4.6
 45.7
 23.7
 5.6

 Balance as of December 31, 2022
 $
 160.4
 $
 69.1
 $
 4.6
 $
 ( 40.0)
 $
 23.7
 $
 14.2

 AEP
 APCo
 I&M
 OPCo
 PSO

 Balance as of December 31, 2020
 $
 113.3
 $
 19.3
 $
 2.1
 $
 ( 110.3)
 $
 10.3
 $
 1.6

 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 48.6
 8.3
 2.4
 16.1
 9.5

 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
 ( 45.2)
 —
 —
 —
 —
 —

 Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)
 24.2
 —
 —
 —
 —
 —

 Settlements
 ( 89.0)
 ( 28.0)
 6.3
 ( 26.4)

 Transfers into Level 3 (d) (e)
 ( 3.8)
 —
 —
 —
 —
 —

 Transfers out of Level 3 (e)
 ( 34.4)
 —
 —
 —
 —
 —

 Changes in Fair Value Allocated to Regulated Jurisdictions (f)

 89.4
 42.1
 9.1
 12.1
 15.3

 Balance as of December 31, 2021
 $
 103.1
 $
 41.7
 $
 $
 ( 92.5)
 $
 12.1
 $
 10.9

 (a) Included in revenues on the statements of income.
 (b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
 (c) Included in cash flow hedges on the statements of comprehensive income.
 (d) Represents existing assets or liabilities that were previously categorized as Level 2.
 (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
 (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These changes in fair value are recorded as regulatory liabilities for net gains and as regulatory assets for net losses or accounts payable.

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

 Significant Unobservable Inputs

 Significant
 Input/Range

 Type of
 Fair Value
 Valuation
 Unobservable
 Weighted

 Input
 Assets
 Technique
 Input
 Low
 High
 Average (c)

 AEP
 Energy Contracts
 $
 225.5
 $
 144.9

 $
 5.21
 $
 153.77
 $
 45.05

 AEP
 Natural Gas Contracts
 —
 0.5

 Forward Market Price (b)

 3.11
 3.11
 3.11

 AEP
 FTRs
 68.6
 9.3

 ( 25.45)
 17.07
 —

 APCo
 FTRs
 23.5
 1.1

 ( 1.04)
 6.45
 1.36

 I&M
 FTRs
 4.5
 1.7

 ( 1.48)
 8.40
 0.85

 OPCo
 Energy Contracts
 —
 50.6

 22.92
 67.53
 42.85

 PSO
 FTRs
 19.7
 1.1

 ( 25.45)
 4.80
 ( 4.33)

 Natural Gas Contracts
 —
 0.5

 Forward Market Price (b)

 3.11
 3.11
 3.11

 FTRs
 12.0
 0.4

 ( 25.45)
 4.80
 ( 4.33)

 Significant
 Input/Range

 Type of
 Fair Value
 Valuation
 Unobservable
 Weighted

 Input
 Assets
 Technique
 Input (a)
 Low
 High
 Average (c)

 AEP
 Energy Contracts
 $
 204.0
 $
 167.4

 $
 2.91
 $
 187.34
 $
 49.14

 AEP
 FTRs
 137.1
 13.3

 ( 36.45)
 20.72
 1.18

 APCo
 FTRs
 69.4
 0.3

 ( 2.82)
 18.88
 3.89

 I&M
 FTRs
 5.3
 0.7

 0.16
 18.79
 1.23

 OPCo
 Energy Contracts
 —
 40.0

 2.91
 187.34
 48.76

 PSO
 FTRs
 24.0
 0.3

 ( 36.45)
 3.40
 ( 7.55)

 FTRs
 14.6
 0.4

 ( 36.45)
 3.40
 ( 7.55)

 (a) Represents market prices in dollars per MWh.
 (b) Represents market prices in dollars per MMBtu.
 (c) The weighted-average is the product of the forward market price of the underlying commodity and volume weighted by term.

 The following table provides the measurement uncertainty of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts, Natural Gas Contracts, FTRs and Other Investments for the Registrants as of December 31, 2023 and 2022:

 Uncertainty of Fair Value Measurements

 Significant Unobservable Input
 Position
 Change in Input
 Impact on Fair Value
Measurement

 Buy
 Increase (Decrease)
 Higher (Lower)

 Sell
 Increase (Decrease)
 Lower (Higher)

 12. INCOME TAXES

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

 The details of the Registrants' Income Tax Expense (Benefit) as reported are as follows:

 AEP
 APCo
 I&M
 OPCo
 PSO

 Federal:

 $
 ( 116.7)
 $
 19.8
 $
 93.9
 $
 62.2
 $
 93.2
 $
 46.6
 $
 ( 60.8)
 $
 ( 88.1)

 115.9
 63.5
 52.3
 ( 60.5)
 ( 56.9)
 2.8
 2.9
 59.9

 Total Federal
 83.3
 146.2
 1.7
 36.3
 49.4
 ( 57.9)
 ( 28.2)

 State and Local:

 69.0
 2.7
 9.1
 6.3
 21.1
 0.3
 1.0

 ( 13.6)
 ( 8.2)
 6.2
 1.2
 5.2
 4.0

 Total State and Local
 55.4
 2.6
 0.9
 12.5
 22.3
 4.9
 4.3
 ( 5.1)

 $
 54.6
 $
 85.9
 $
 147.1
 $
 14.2
 $
 58.6
 $
 54.3
 $
 ( 53.6)
 $
 ( 33.3)

 AEP
 APCo
 I&M
 OPCo
 PSO

 Federal:

 $
 113.1
 $
 29.0
 $
 98.0
 $
 ( 61.0)
 $
 43.4
 $
 ( 27.0)
 $
 ( 3.3)
 $
 ( 32.3)

 ( 88.8)
 41.4
 46.0
 86.6
 ( 51.3)
 73.3
 ( 50.5)
 13.4

 Total Federal
 24.3
 70.4
 144.0
 25.6
 46.3
 ( 53.8)
 ( 18.9)

 State and Local:

 26.6
 2.2
 8.8
 10.9
 —

 ( 45.5)
 —
 16.3
 1.2
 4.6
 ( 4.5)

 Total State and Local
 ( 18.9)
 2.2
 25.1
 12.1
 4.6

 $
 5.4
 $
 72.6
 $
 169.1
 $
 18.2
 $
 4.2
 $
 44.2
 $
 $
 ( 25.2)

 AEP
 APCo
 I&M
 OPCo
 PSO

 Federal:

 $
 ( 27.8)
 $
 $
 69.8
 $
 5.0
 $
 26.9
 $
 6.8
 $
 ( 109.6)
 $
 ( 16.7)

 182.6
 40.5
 54.1
 14.9
 ( 35.5)
 25.2
 105.6
 26.2

 Total Federal
 154.8
 39.3
 123.9
 19.9
 32.0
 9.5

 State and Local:

 6.0
 3.0
 5.8
 2.2
 ( 3.1)
 —
 0.4

 ( 45.3)
 0.8
 14.4
 —
 5.5
 8.1
 ( 10.5)

 Total State and Local
 ( 39.3)
 3.8
 20.2
 2.2
 2.4
 8.1
 ( 10.1)

 $
 115.5
 $
 43.1
 $
 144.1
 $
 22.1
 $
 $
 34.4
 $
 4.1
 $

 The following are reconciliations for the Registrants between the federal income taxes computed by multiplying pretax income by the federal statutory tax rate and the income taxes reported:

 AEP
 APCo
 I&M
 OPCo
 PSO

 $
 $
 370.4
 $
 614.2
 $
 294.4
 $
 335.9
 $
 328.2
 $
 208.8
 $
 223.8

 Less: Equity Earnings
 —
 —
 —
 —
 —
 —

 54.6
 85.9
 147.1
 14.2
 58.6
 54.3
 ( 53.6)
 ( 33.3)

 Pretax Income
 $
 2,265.8
 $
 456.3
 $
 761.3
 $
 308.6
 $
 394.5
 $
 382.5
 $
 155.2
 $
 189.1

 Income Taxes on Pretax Income at Statutory Rate ( 21 %)

 $
 475.8
 $
 95.8
 $
 159.9
 $
 64.8
 $
 82.8
 $
 80.3
 $
 32.6
 $
 39.7

 Increase (Decrease) in Income Taxes Resulting from the Following Items:

 Reversal of Origination Flow-Through
 26.0
 0.6
 2.4
 9.9
 6.4
 2.6
 0.4
 2.1

 Investment Tax Credit Amortization
 ( 50.3)
 —
 —
 —

 Production Tax Credits
 ( 175.2)
 —
 —
 —
 —
 ( 64.3)
 ( 67.1)

 State and Local Income Taxes, Net
 43.7
 2.1
 0.7
 9.9
 17.5
 3.9
 3.5

 Removal Costs
 ( 22.0)
 —
 —
 ( 5.1)
 —
 —
 —

 AFUDC
 ( 39.8)
 ( 6.0)
 ( 17.5)
 ( 5.5)

 Tax Reform Excess ADIT Reversal
 ( 151.1)
 ( 6.0)
 1.7
 ( 17.3)
 ( 30.0)
 ( 28.9)
 ( 23.3)

 Remeasurement of Excess ADIT
 ( 46.0)
 —
 —
 ( 46.0)
 —
 —
 —
 —

 Federal Return to Provision
 —
 —
 3.4
 0.6
 1.0

 Disallowance Cost
 —
 —
 —
 —
 —
 —
 —
 12.0

 Other
 ( 6.5)
 0.2
 0.2
 0.1
 0.4
 0.1

 $
 54.6
 $
 85.9
 $
 147.1
 $
 14.2
 $
 58.6
 $
 54.3
 $
 ( 53.6)
 $
 ( 33.3)

 Effective Income Tax Rate
 2.4
 %
 18.8
 %
 19.3
 %
 4.6
 %
 14.9
 %
 14.2
 %
 ( 34.5)
 %
 ( 17.6)
 %

 AEP
 APCo
 I&M
 OPCo
 PSO

 $
 $
 307.9
 $
 594.2
 $
 394.2
 $
 324.7
 $
 287.8
 $
 167.6
 $
 294.3

 Less: Equity Earnings
 —
 —
 —
 —
 —

 5.4
 72.6
 169.1
 18.2
 4.2
 44.2
 ( 25.2)

 Pretax Income
 $
 2,309.6
 $
 380.5
 $
 763.3
 $
 412.4
 $
 328.9
 $
 331.4
 $
 118.4
 $
 267.7

 Income Taxes on Pretax Income at Statutory Rate ( 21 %)

 $
 485.0
 $
 79.9
 $
 160.3
 $
 86.6
 $
 69.1
 $
 69.6
 $
 24.9
 $
 56.2

 Increase (Decrease) in Income Taxes Resulting from the Following Items:

 Reversal of Origination Flow-Through
 17.1
 —
 —
 4.7
 2.9
 3.0
 —
 2.3

 Investment Tax Credit Amortization
 ( 14.3)
 —
 —
 —
 ( 3.1)
 —
 —

 Production Tax Credits
 ( 197.1)
 —
 —
 —
 —
 —
 ( 47.7)
 ( 57.1)

 State and Local Income Taxes, Net
 ( 14.0)
 1.7
 19.8
 ( 5.9)
 9.6
 4.3

 Removal Costs
 ( 26.5)
 —
 —
 ( 12.4)
 —
 —
 —

 AFUDC
 ( 29.3)
 ( 4.1)
 ( 2.9)
 —
 —

 Tax Reform Excess ADIT Reversal
 ( 214.5)
 ( 5.5)
 —
 ( 50.9)
 ( 54.0)
 ( 27.5)
 ( 25.4)

 Federal Return to Provision
 ( 17.4)
 —
 —
 3.5
 —

 Other
 16.4
 0.6
 3.8
 —
 0.4
 0.1
 —

 $
 5.4
 $
 72.6
 $
 169.1
 $
 18.2
 $
 4.2
 $
 44.2
 $
 $
 ( 25.2)

 Effective Income Tax Rate
 0.2
 %
 19.1
 %
 22.2
 %
 4.4
 %
 1.3
 %
 13.3
 %
 ( 41.6)
 %
 ( 9.4)
 %

 AEP
 APCo
 I&M
 OPCo
 PSO

 $
 $
 289.8
 $
 591.7
 $
 348.9
 $
 279.8
 $
 253.6
 $
 141.1
 $
 242.1

 Less: Equity Earnings
 —
 —
 —
 —
 —
 —

 115.5
 43.1
 144.1
 22.1
 34.4
 4.1

 Pretax Income
 $
 2,600.2
 $
 332.9
 $
 735.8
 $
 371.0
 $
 269.2
 $
 288.0
 $
 145.2
 $
 238.1

 Income Taxes on Pretax Income at Statutory Rate ( 21 %)

 $
 546.0
 $
 69.9
 $
 154.5
 $
 77.9
 $
 56.5
 $
 60.5
 $
 30.5
 $
 50.0

 Increase (Decrease) in Income Taxes Resulting from the Following Items:

 Reversal of Origination Flow-Through
 25.9
 —
 —
 11.7
 3.5
 2.2
 —
 1.8

 Investment Tax Credit Amortization
 ( 22.0)
 —
 —
 —
 —
 —

 Production Tax Credits
 ( 98.8)
 —
 —
 —
 —
 —
 ( 6.0)
 ( 7.2)

 State and Local Income Taxes, Net
 39.4
 2.4
 19.8
 2.1
 —
 6.4
 ( 8.0)

 Removal Costs
 —
 —
 ( 7.3)
 ( 9.7)
 —
 —
 —

 AFUDC
 ( 30.6)
 ( 4.5)
 ( 14.1)
 ( 4.6)
 ( 2.7)
 —
 —

 Parent Company Loss Benefit
 —
 —
 —
 —
 —

 Tax Adjustments (a)
 ( 55.1)
 —
 —
 4.5
 —
 8.9
 —
 —

 Tax Reform Excess ADIT Reversal
 ( 255.6)
 ( 21.3)
 —
 ( 60.5)
 ( 46.3)
 ( 32.6)
 ( 25.4)
 ( 31.1)

 Federal Return to Provision
 —
 —
 0.7
 —

 Other
 ( 12.1)
 2.2

 $
 115.5
 $
 43.1
 $
 144.1
 $
 22.1
 $
 $
 34.4
 $
 4.1
 $

 Effective Income Tax Rate
 4.4
 %
 12.9
 %
 19.6
 %
 6.0
 %
 %
 11.9
 %
 2.8
 %

 (a) 2021 amount represents an out of period adjustment related to Deferred Income Taxes and Income Tax Expense (Benefit). Management concluded the misstatement and subsequent correction was not material to the 2021 or prior period financial statements.

 Net Deferred Tax Liability

 The following tables show elements of the net deferred tax liability and significant temporary differences for each Registrant:

 AEP
 APCo
 I&M
 OPCo
 PSO

 Deferred Tax Assets
 $
 3,216.1
 $
 173.6
 $
 188.1
 $
 473.0
 $
 1,014.1
 $
 271.4
 $
 282.3
 $
 441.5

 Deferred Tax Liabilities
 ( 12,631.8)
 ( 1,401.4)
 ( 1,335.8)
 ( 2,484.9)
 ( 2,184.0)
 ( 1,424.1)
 ( 1,113.5)
 ( 1,620.8)

 Net Deferred Tax Liabilities
 $
 ( 9,415.7)
 $
 ( 1,227.8)
 $
 ( 1,147.7)
 $
 ( 2,011.9)
 $
 ( 1,169.9)
 $
 ( 1,152.7)
 $
 ( 831.2)
 $
 ( 1,179.3)

 Property Related Temporary Differences
 $
 ( 7,779.7)
 $( 1,227.1)
 $( 1,134.6)
 $( 1,556.0)
 $
 ( 298.1)
 $( 1,162.1)
 $
 ( 817.2)
 $
 ( 1,087.2)

 Amounts Due to Customers for Future Income Taxes
 900.1
 109.3
 119.0
 143.4
 103.2
 104.5
 88.6
 142.5

 Deferred State Income Taxes
 ( 1,222.8)
 ( 41.5)
 ( 155.4)
 ( 308.4)
 ( 238.1)
 ( 68.8)
 ( 122.6)
 ( 238.6)

 ( 79.9)
 ( 45.6)
 —
 —
 ( 5.1)
 —
 —

 ( 768.9)
 ( 57.6)
 ( 7.6)
 ( 257.4)
 32.3
 ( 83.5)
 ( 83.8)
 ( 143.4)

 Accrued Nuclear Decommissioning
 ( 776.5)
 —
 —
 —
 ( 776.5)
 —
 —
 —

 Net Operating Loss Carryforward
 148.0
 —
 3.9
 —
 —
 2.6
 25.3
 47.5

 Tax Credit Carryforward
 321.9
 13.7
 —
 0.1
 7.2
 41.0
 53.8
 68.6

 Operating Lease Liability
 131.1
 16.6
 0.3
 15.1
 10.8
 14.6
 23.6
 26.3

 Investment in Partnership
 ( 293.1)
 —
 —
 —
 —

 All Other, Net
 4.1
 4.4
 26.7
 ( 10.7)
 4.8
 1.1
 6.3

 Net Deferred Tax Liabilities
 $
 ( 9,415.7)
 $
 ( 1,227.8)
 $
 ( 1,147.7)
 $
 ( 2,011.9)
 $
 ( 1,169.9)
 $
 ( 1,152.7)
 $
 ( 831.2)
 $
 ( 1,179.3)

 AEP
 APCo
 I&M
 OPCo
 PSO

 Deferred Tax Assets
 $
 3,567.4
 $
 177.0
 $
 165.0
 $
 510.3
 $
 933.7
 $
 218.8
 $
 225.0
 $
 374.9

 Deferred Tax Liabilities
 ( 12,464.3)
 ( 1,321.2)
 ( 1,221.5)
 ( 2,502.5)
 ( 2,090.7)
 ( 1,319.9)
 ( 1,013.6)
 ( 1,464.6)

 Net Deferred Tax Liabilities
 $
 ( 8,896.9)
 $
 ( 1,144.2)
 $
 ( 1,056.5)
 $
 ( 1,992.2)
 $
 ( 1,157.0)
 $
 ( 1,101.1)
 $
 ( 788.6)
 $
 ( 1,089.7)

 Property Related Temporary Differences
 $
 ( 7,788.1)
 $
 ( 1,130.7)
 $
 ( 1,081.5)
 $
 ( 1,509.8)
 $
 ( 398.0)
 $
 ( 1,133.8)
 $
 ( 763.3)
 $
 ( 1,053.8)

 Amounts Due to Customers for Future Income Taxes
 962.7
 111.0
 118.5
 163.0
 114.3
 112.6
 96.0
 146.2

 Deferred State Income Taxes
 ( 1,049.3)
 ( 36.6)
 ( 108.1)
 ( 318.5)
 ( 227.0)
 ( 59.6)
 ( 81.9)
 ( 208.7)

 ( 98.9)
 ( 65.0)
 —
 ( 33.9)
 —
 —
 —
 —

 ( 865.2)
 ( 48.9)
 ( 301.2)
 ( 29.5)
 ( 57.6)
 ( 140.2)
 ( 114.1)

 Accrued Nuclear Decommissioning
 ( 632.7)
 —
 —
 —
 ( 632.7)
 —
 —
 —

 Net Operating Loss Carryforward
 132.4
 —
 5.5
 —
 —
 —
 25.8
 42.7

 Tax Credit Carryforward
 612.0
 —
 0.2
 —
 —
 —
 54.3
 66.0

 Operating Lease Liability
 142.9
 20.3
 0.3
 15.6
 13.6
 15.5
 —
 —

 Investment in Partnership
 ( 338.9)
 —
 —
 —
 —
 —
 —
 —

 Valuation Allowance
 ( 28.2)
 —
 —
 —
 —
 —
 —

 Deferred Revenues
 7.1
 —
 —
 —
 —
 —
 —
 —

 Postretirement Benefits
 2.5
 —
 —
 —
 —
 —
 —
 —

 All Other, Net
 44.8
 5.7
 9.8
 2.3
 21.8
 20.7
 32.0

 Net Deferred Tax Liabilities
 $
 ( 8,896.9)
 $
 ( 1,144.2)
 $
 ( 1,056.5)
 $
 ( 1,992.2)
 $
 ( 1,157.0)
 $
 ( 1,101.1)
 $
 ( 788.6)
 $
 ( 1,089.7)

 Federal and State Income Tax Audit Status

 The statute of limitations for the IRS to examine AEP and subsidiaries originally filed federal return has expired for tax years 2016 and earlier. AEP has agreed to extend the statute of limitations on the 2017-2019 tax returns to October 31, 2024, to allow time for our refund claim to be approved by the Congressional Joint Committee on Taxation. The statute of limitations for the 2020 return is set to naturally expire in October 2024 as well.

 The current IRS audit and associated refund claim evolved from a net operating loss carryback to 2015 that originated in the 2017 return. AEP has received and agreed to immaterial IRS proposed adjustments on the 2017 tax return. The IRS exam is complete, and AEP is currently waiting on the IRS to submit the refund claim to the Congressional Joint Committee on Taxation for resolution and final approval.

 AEP and subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns, and AEP and subsidiaries are currently under examination in several state and local jurisdictions. Generally, the statutes of limitations have expired for tax years prior to 2017. In addition, management is monitoring and continues to evaluate the potential impact of federal legislation and corresponding state conformity.

 Net Income Tax Operating Loss Carryforward

 As of December 31, 2023, AEP, OPCo, PSO and SWEPCo have state net income tax operating loss carryforwards as indicated in the table below:

 State Net Income

 Tax Operating Loss
 Years of

 State/Municipality
 Carryforward
 Expiration

 AEP
 Arkansas
 $
 259.3
 2024
 -
 2033

 AEP
 Colorado
 80.8
 2041

 AEP
 Illinois
 54.4
 2039
 -
 2041

 AEP
 Kentucky
 204.1
 2030
 -
 2037

 AEP
 629.2
 NA

 AEP
 Michigan
 45.6
 2030
 -
 2032

 AEP
 Ohio Municipal
 1,954.8
 2024
 -
 2028

 AEP
 877.9
 2037

 AEP
 Pennsylvania
 47.8
 2030
 -
 2043

 AEP
 Tennessee
 47.7
 2032
 -
 2038

 OPCo
 Ohio Municipal
 152.3
 2024
 -
 2028

 PSO
 947.1
 2037

 Arkansas
 258.9
 2024
 -
 2033

 619.1
 NA

 Tax Credit Carryforward

 Federal and state net income tax operating losses sustained in 2017, 2019 and 2021 resulted in unused federal and state income tax credits. As of December 31, 2023, the Registrants have federal tax credit carryforwards and AEP and PSO have state tax credit carryforwards as indicated in the table below. If these credits are not utilized, federal general business tax credits will expire in the years 2036 through 2041 and state tax credits will remain available indefinitely.

 Total Federal
 Total State

 Tax Credit
 Tax Credit

 Carryforward
 Carryforward

 AEP
 $
 321.9
 $
 40.0

 13.7
 —

 APCo
 0.1
 —

 I&M
 7.2
 —

 OPCo
 41.0
 —

 PSO
 53.8
 40.0

 68.6
 —

 The Registrants anticipate future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused.

 Valuation Allowance

 AEP assesses the available positive and negative evidence to estimate whether sufficient future taxable income of the appropriate tax character will be generated to realize the benefits of existing deferred tax assets. When the evaluation of the evidence indicates that it is more-likely-than-not that AEP will not be able to realize the benefits of existing deferred tax assets, a valuation allowance is recorded to reduce existing deferred tax assets to the net realizable amount. Objective evidence evaluated includes whether AEP has a history of recognizing income, future reversals of existing temporary differences and tax planning strategies.

 Valuation allowance activity for the years ended December 31, 2023, 2022 and 2021 were not material.

 Uncertain Tax Positions

 The amount and activity of unrecognized tax benefits was not material for the Registrants for the years ended December 31, 2023, 2022 and 2021. Management believes that there will be no significant net increase or decrease in unrecognized benefits within 12 months of the reporting date. The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for AEP as of December 31, 2023, 2022 and 2021 were $ 13 million, $ 23 million, and $ 14 million, respectively.

 Federal 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. 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.

 In December 2022, the IRS released Notice 2023-7, which provided initial CAMT guidance that AEP can begin to rely on in 2023. Notably, the interim guidance in Notice 2023-7 confirmed the CAMT depreciation adjustment includes tax depreciation that is capitalized to inventory under §263A and recovered as part of cost of goods sold, providing significant relief to AEP's potential CAMT exposure. In September 2023, the IRS released Notice 2023-64, which clarifies and supplements items in Notice 2023-7 and stated that additional guidance in the form of proposed regulations is expected. AEP will continue to monitor and assess any additional guidance.

 AEP and subsidiaries expect to be applicable corporations for purposes of the CAMT beginning in 2023. CAMT cash taxes are expected to be partially 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 are presented in the operating section of the statements of cash flows consistent with the presentation of cash taxes paid. AEP presents the loss on sale of tax credits through income tax expense.

 In June 2023, the IRS issued temporary regulations related to the transfer of tax credits. In the third and fourth quarter of 2023, AEP, on behalf of PSO, SWEPCo and AEP Energy Supply, LLC, entered into transferability agreements with nonaffiliated parties to sell 2023 generated PTCs resulting in cash proceeds of approximately $ 102 million received in the fourth quarter of 2023 and an additional $76 million expected in early 2024. AEP expects to continue to explore the ability to efficiently monetize its tax credits through third party transferability agreements.

 13. LEASES

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

 The Registrants lease property, plant and equipment including, but not limited to, fleet, information technology and real estate leases. These leases require payments of non-lease components, including related property taxes, operating and maintenance costs. AEP does not separate non-lease components from associated lease components. Many of these leases have purchase or renewal options. Leases not renewed are often replaced by other leases. Options to renew or purchase a lease are included in the measurement of lease assets and liabilities if it is reasonably certain the Registrant will exercise the option.

 Lease obligations are measured using the discount rate implicit in the lease when that rate is readily determinable. AEP has visibility into the rate implicit in the lease when assets are leased from selected financial institutions under master leasing agreements. When the implicit rate is not readily determinable, the Registrants measure their lease obligation using their estimated secured incremental borrowing rate. Incremental borrowing rates are comprised of an underlying risk-free rate and a secured credit spread relative to the lessee on a matched maturity basis.

 Operating lease rentals and finance lease amortization costs are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. The amortization costs related to the Rockport finance lease were charged to Depreciation and Amortization. Interest on finance lease liabilities is generally charged to Interest Expense. Lease costs associated with capital projects are included in Property, Plant and Equipment on the balance sheets. For regulated operations with finance leases, a finance lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Finance leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs were as follows:

 AEP
 APCo
 I&M
 OPCo
 PSO

 Operating Lease Cost

 $
 149.9
 $
 34.0
 $
 1.3
 $
 18.5
 $
 19.6
 $
 17.3
 $
 13.5
 $
 17.5

 Finance Lease Cost:

 Amortization of Right-of-Use Assets

 69.1
 7.4
 —
 8.3
 7.3
 5.0
 3.3
 19.9

 Interest on Lease Liabilities

 11.9
 1.4
 —
 1.8
 2.5
 0.9
 0.7
 1.4

 Total Lease Rental Costs (a)
 $
 230.9
 $
 42.8
 $
 1.3
 $
 28.6
 $
 29.4
 $
 23.2
 $
 17.5
 $
 38.8

 AEP
 APCo
 I&M
 OPCo
 PSO

 Operating Lease Cost

 $
 157.5
 $
 18.4
 $
 1.1
 $
 17.9
 $
 29.5
 $
 16.9
 $
 11.8
 $
 15.3

 Finance Lease Cost:

 Amortization of Right-of-Use Assets

 205.5
 6.8
 —
 7.9
 78.7
 4.9
 3.2
 10.8

 Interest on Lease Liabilities

 13.4
 1.3
 —
 2.0
 3.1
 0.8
 0.6
 2.1

 Total Lease Rental Costs (a)
 $
 376.4
 $
 26.5
 $
 1.1
 $
 27.8
 $
 111.3
 $
 22.6
 $
 15.6
 $
 28.2

 AEP
 APCo
 I&M
 OPCo
 PSO

 Operating Lease Cost

 $
 275.3
 $
 18.4
 $
 1.7
 $
 19.3
 $
 90.2
 $
 19.0
 $
 8.7
 $
 12.1

 Finance Lease Cost:

 Amortization of Right-of-Use Assets

 74.7
 6.7
 —
 7.7
 12.9
 4.9
 3.2
 11.0

 Interest on Lease Liabilities

 14.4
 1.4
 —
 2.4
 3.0
 0.8
 0.6
 2.5

 Total Lease Rental Costs (a)
 $
 364.4
 $
 26.5
 $
 1.7
 $
 29.4
 $
 106.1
 $
 24.7
 $
 12.5
 $
 25.6

 (a) Excludes variable and short-term lease costs, which were immaterial.

 Supplemental information related to leases are shown in the tables below:

 AEP
 APCo
 I&M
 OPCo
 PSO

 Weighted-Average Remaining Lease Term (years):

 12.58
 3.99
 2.76
 6.01
 4.53
 5.36
 23.85
 22.50

 4.63
 5.13
 0.00
 4.16
 4.95
 4.97
 5.76
 4.78

 Weighted-Average Discount Rate:

 3.73
 %
 4.23
 %
 3.61
 %
 3.50
 %
 3.89
 %
 3.93
 %
 3.72
 %
 3.53
 %

 6.19
 %
 5.27
 %
 —
 %
 7.04
 %
 8.62
 %
 5.32
 %
 5.14
 %
 5.22
 %

 AEP
 APCo
 I&M
 OPCo
 PSO

 Weighted-Average Remaining Lease Term (years):

 12.69
 4.33
 2.05
 5.29
 5.79
 5.98
 23.90
 23.55

 4.61
 5.39
 0.00
 4.25
 4.76
 5.27
 6.02
 4.13

 Weighted-Average Discount Rate:

 3.54
 %
 4.15
 %
 1.96
 %
 3.61
 %
 3.62
 %
 3.73
 %
 3.43
 %
 3.41
 %

 5.76
 %
 4.75
 %
 —
 %
 7.09
 %
 8.99
 %
 4.53
 %
 4.63
 %
 4.80
 %

 AEP
 APCo
 I&M
 OPCo
 PSO

 Cash paid for amounts included in the measurement of lease liabilities:

 Operating Cash Flows Used for Operating Leases

 $
 146.8
 $
 33.6
 $
 1.3
 $
 18.3
 $
 19.5
 $
 17.0
 $
 12.5
 $
 16.5

 Operating Cash Flows Used for Finance Leases

 11.9
 1.4
 —
 1.8
 2.5
 0.9
 0.7
 1.4

 Financing Cash Flows Used for Finance Leases

 68.3
 7.4
 —
 8.3
 7.4
 5.0
 3.3
 19.1

 Non-cash Acquisitions Under Operating Leases
 $
 99.8
 $
 12.4
 $
 1.2
 $
 15.7
 $
 7.9
 $
 10.2
 $
 15.5
 $
 14.3

 AEP
 APCo
 I&M
 OPCo
 PSO

 Cash paid for amounts included in the measurement of lease liabilities:

 Operating Cash Flows Used for Operating Leases

 $
 155.1
 $
 18.3
 $
 1.0
 $
 17.9
 $
 29.7
 $
 17.5
 $
 10.5
 $
 13.7

 Operating Cash Flows Used for Finance Leases

 13.6
 1.3
 —
 2.0
 3.2
 0.8
 0.6
 2.1

 Financing Cash Flows Used for Finance Leases

 309.5
 6.8
 —
 7.9
 130.7
 4.9
 3.2
 10.8

 Non-cash Acquisitions Under Operating Leases
 $
 191.4
 $
 36.7
 $
 1.7
 $
 23.1
 $
 19.1
 $
 8.4
 $
 46.0
 $
 53.6

 The following tables show property, plant and equipment under finance leases and noncurrent assets under operating leases and related obligations recorded on the balance sheets. Unless shown as a separate line on the balance sheets due to materiality, net operating lease assets are included in Deferred Charges and Other Noncurrent Assets, current finance lease obligations are included in Other Current Liabilities and long-term finance lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets. Lease obligations are not recognized on the balance sheets for lease agreements with a lease term of less than twelve months.

 AEP
 APCo
 I&M
 OPCo
 PSO

 Property, Plant and Equipment Under Finance Leases:

 $
 120.1
 $
 —
 $
 —
 $
 41.0
 $
 28.2
 $
 —
 $
 0.6
 $
 25.3

 305.9
 53.9
 —
 22.1
 42.3
 33.7
 25.5
 32.0

 426.0
 53.9
 —
 63.1
 70.5
 33.7
 26.1
 57.3

 Accumulated Amortization
 221.5
 26.3
 —
 37.1
 39.0
 15.5
 12.3
 28.3

 Net Property, Plant and Equipment Under Finance Leases

 $
 204.5
 $
 27.6
 $
 —
 $
 26.0
 $
 31.5
 $
 18.2
 $
 13.8
 $
 29.0

 Obligations Under Finance Leases:

 Noncurrent Liability
 $
 139.9
 $
 20.6
 $
 —
 $
 17.8
 $
 20.8
 $
 13.2
 $
 10.7
 $
 18.8

 Liability Due Within One Year
 65.7
 7.0
 —
 8.2
 10.7
 5.0
 3.1
 11.3

 Total Obligations Under Finance Leases

 $
 205.6
 $
 27.6
 $
 —
 $
 26.0
 $
 31.5
 $
 18.2
 $
 13.8
 $
 30.1

 AEP
 APCo
 I&M
 OPCo
 PSO

 Property, Plant and Equipment Under Finance Leases:

 $
 120.9
 $
 —
 $
 —
 $
 41.1
 $
 28.0
 $
 —
 $
 0.6
 $
 25.9

 321.4
 53.7
 —
 20.1
 40.6
 32.7
 25.2
 58.3

 442.3
 53.7
 —
 61.2
 68.6
 32.7
 25.8
 84.2

 Accumulated Amortization
 229.6
 23.6
 —
 31.9
 34.8
 13.8
 10.8
 54.6

 Net Property, Plant and Equipment Under Finance Leases

 $
 212.7
 $
 30.1
 $
 —
 $
 29.3
 $
 33.8
 $
 18.9
 $
 15.0
 $
 29.6

 Obligations Under Finance Leases:

 Noncurrent Liability
 $
 168.4
 $
 23.1
 $
 —
 $
 21.6
 $
 27.1
 $
 14.2
 $
 11.7
 $
 31.3

 Liability Due Within One Year
 57.3
 7.0
 —
 7.7
 6.9
 4.7
 3.3
 10.9

 Total Obligations Under Finance Leases

 $
 225.7
 $
 30.1
 $
 —
 $
 29.3
 $
 34.0
 $
 18.9
 $
 15.0
 $
 42.2

 AEP
 APCo
 I&M
 OPCo
 PSO

 $
 620.2
 $
 77.6
 $
 2.6
 $
 73.7
 $
 53.8
 $
 69.9
 $
 112.8
 $
 126.3

 Obligations Under Operating Leases:

 Noncurrent Liability
 $
 519.4
 $
 50.9
 $
 1.4
 $
 59.8
 $
 37.7
 $
 56.7
 $
 106.8
 $
 122.5

 Liability Due Within One Year
 115.7
 28.7
 1.3
 14.6
 16.8
 13.5
 10.1
 9.0

 Total Obligations Under Operating Leases

 $
 635.1
 $
 79.6
 $
 2.7
 $
 74.4
 $
 54.5
 $
 70.2
 $
 116.9
 $
 131.5

 AEP
 APCo
 I&M
 OPCo
 PSO

 $
 645.5
 $
 94.7
 $
 2.7
 $
 73.6
 $
 64.3
 $
 73.8
 $
 106.1
 $
 123.4

 Obligations Under Operating Leases:

 Noncurrent Liability
 $
 552.5
 $
 67.8
 $
 1.5
 $
 59.1
 $
 48.9
 $
 60.3
 $
 99.3
 $
 120.2

 Liability Due Within One Year
 113.6
 28.6
 1.3
 15.0
 16.0
 13.5
 8.9
 8.4

 Total Obligations Under Operating Leases

 $
 666.1
 $
 96.4
 $
 2.8
 $
 74.1
 $
 64.9
 $
 73.8
 $
 108.2
 $
 128.6

 Future minimum lease payments consisted of the following as of December 31, 2023:

 AEP
 APCo
 I&M
 OPCo
 PSO

 2024
 $
 76.8
 $
 8.3
 $
 —
 $
 9.9
 $
 12.8
 $
 5.8
 $
 3.7
 $
 12.6

 2025
 48.6
 6.6
 —
 8.5
 7.2
 4.3
 2.9
 4.6

 2026
 33.0
 5.1
 —
 3.5
 4.5
 3.1
 2.5
 3.9

 2027
 26.2
 4.0
 —
 2.3
 4.0
 2.5
 2.0
 3.5

 2028
 19.2
 2.8
 —
 1.9
 3.3
 2.0
 1.7
 3.0

 35.4
 5.1
 —
 3.4
 7.3
 3.2
 3.3
 7.2

 Total Future Minimum Lease Payments

 239.2
 31.9
 —
 29.5
 39.1
 20.9
 16.1
 34.8

 Less: Imputed Interest

 33.6
 4.3
 —
 3.5
 7.6
 2.7
 2.3
 4.7

 Estimated Present Value of Future Minimum Lease Payments
 $
 205.6
 $
 27.6
 $
 —
 $
 26.0
 $
 31.5
 $
 18.2
 $
 13.8
 $
 30.1

 AEP
 APCo
 I&M
 OPCo
 PSO

 2024
 $
 141.6
 $
 32.1
 $
 1.4
 $
 17.8
 $
 18.9
 $
 16.9
 $
 12.2
 $
 16.2

 2025
 103.3
 15.7
 0.7
 14.8
 10.6
 15.3
 11.1
 15.0

 2026
 92.0
 13.3
 0.4
 13.3
 9.7
 14.1
 10.3
 12.9

 2027
 82.6
 10.7
 0.2
 12.1
 8.9
 12.8
 9.3
 11.5

 2028
 67.4
 7.8
 0.1
 10.0
 7.0
 10.6
 7.9
 9.5

 327.6
 8.1
 —
 16.8
 4.8
 9.1
 129.1
 135.6

 Total Future Minimum Lease Payments

 814.5
 87.7
 2.8
 84.8
 59.9
 78.8
 179.9
 200.7

 Less: Imputed Interest
 179.4
 8.1
 0.1
 10.4
 5.4
 8.6
 63.0
 69.2

 Estimated Present Value of Future Minimum Lease Payments
 $
 635.1
 $
 79.6
 $
 2.7
 $
 74.4
 $
 54.5
 $
 70.2
 $
 116.9
 $
 131.5

 Master Lease Agreements (Applies to all Registrants except AEPTCo)

 The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the amount guaranteed. As of December 31, 2023, the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows:

Potential Loss

 AEP
 $
 45.3

 10.9

 APCo
 5.8

 I&M
 4.1

 OPCo
 7.2

 PSO
 4.7

 5.4

 Lessor Activity

 The Registrants' lessor activity was immaterial as of and for the twelve months ended December 31, 2023 and December 31, 2022, respectively.

 14. FINANCING ACTIVITIES

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

 Common Stock (Applies to AEP)

 The following table is a reconciliation of common stock share activity:

 Shares of AEP Common Stock
 Issued
 Held in Treasury

 Balance, December 31, 2020
 516,808,354
 20,204,160

 Issued
 7,607,821
 —

 Balance, December 31, 2021
 524,416,175
 20,204,160

 Issued
 683,146
 —

 Treasury Stock Reissued
 —
 ( 8,970,920)
 (a)

 Balance, December 31, 2022
 525,099,321
 11,233,240

 Issued
 2,269,836
 —

 Treasury Stock Reissued
 —
 ( 10,048,668)
 (a)

 Balance, December 31, 2023
 527,369,157
 1,184,572

 (a) Reissued Treasury Stock used to fulfill share commitments related to AEP's Equity Units. See "Equity Units" section below for additional information.

 ATM Program

 In 2023, AEP filed a prospectus supplement and executed an Equity Distribution Agreement, pursuant to which AEP may sell, from time to time, up to an aggregate of $ 1.7 billion of its common stock through an ATM offering program, including an equity forward sales component. The compensation paid to the selling agents by AEP may be up to 2 % of the gross offering proceeds of the shares. There were no issuances under the ATM program for the year ended December 31, 2023.

 The following table details long-term debt outstanding:

 Weighted-Average
 Interest Rate Ranges as of
 Outstanding as of

 Interest Rate as of

 Maturity
 2023
 2022
 2023
 2022

 AEP

 2024-2053
 4.23 %
 1.00%-8.13%
 0.75%-8.13%
 $
 33,779.4
 $
 30,174.8

 Pollution Control Bonds (a)
 2024-2036 (b)
 2.98 %
 0.63%-4.90%
 0.63%-4.55%
 1,771.6
 1,770.2

 Notes Payable – Nonaffiliated (c)
 2024-2028
 4.67 %
 0.93%-6.59%
 0.93%-6.37%
 193.3
 269.7

 Securitization Bonds
 2024-2029 (d)
 2.97 %
 2.06%-3.77%
 2.01%-3.77%
 368.9
 487.8

 Spent Nuclear Fuel Obligation (e)
 300.4
 285.6

 Junior Subordinated Notes (f)
 2024-2027
 3.90 %
 2.03%-5.70%
 1.30%-3.88%
 2,388.1
 2,381.3

 2024-2059
 6.58 %
 3.00%-13.72%
 1.15%-13.72%
 1,341.5
 1,431.6

 $
 40,143.2
 $
 36,801.0

 2025-2052
 4.20 %
 2.10%-6.76%
 2.10%-6.76%
 $
 5,027.2
 $
 4,702.7

 Pollution Control Bonds
 2029-2030 (b)
 3.88 %
 2.60%-4.55%
 0.90%-4.55%
 440.3
 440.2

 Securitization Bonds
 2024-2029 (d)
 2.43 %
 2.06%-2.84%
 2.06%-2.84%
 221.8
 314.4

 2025-2059
 6.70 %
 4.50%-6.71%
 4.50%-5.67%
 200.5
 200.5

 $
 5,889.8
 $
 5,657.8

 2024-2053
 4.02 %
 2.75%-5.52%
 2.75%-5.52%
 $
 5,414.4
 $
 4,782.8

 $
 5,414.4
 $
 4,782.8

 APCo

 2025-2050
 4.68 %
 2.70%-7.00%
 2.70%-7.00%
 $
 4,584.9
 $
 4,581.4

 Pollution Control Bonds (a)
 2024-2036 (b)
 2.89 %
 0.63%-4.90%
 0.63%-3.80%
 430.0
 429.4

 Securitization Bonds
 2028 (d)
 3.77 %
 3.77%
 2.01%-3.77%
 147.0
 173.3

 2024-2026
 6.53 %
 6.46%-13.72%
 4.84%-13.72%
 426.4
 226.4

 $
 5,588.3
 $
 5,410.5

 I&M

 2028-2053
 4.52 %
 3.25%-6.05%
 3.20%-6.05%
 $
 2,843.6
 $
 2,597.3

 Pollution Control Bonds (a)
 2025 (b)
 2.49 %
 0.75%-3.05%
 0.75%-3.05%
 189.4
 189.0

 Notes Payable – Nonaffiliated (c)
 2024-2028
 5.08 %
 0.93%-6.59%
 0.93%-5.93%
 163.3
 183.8

 Spent Nuclear Fuel Obligation (e)
 300.4
 285.6

 2025
 6.00 %
 6.00%
 6.00%
 2.7
 5.1

 $
 3,499.4
 $
 3,260.8

 OPCo

 2030-2051
 4.00 %
 1.63%-6.60%
 1.63%-6.60%
 $
 $
 2,969.7

 — %
 —%
 1.15%
 —
 0.6

 $
 $
 2,970.3

 PSO

 2025-2051
 4.05 %
 2.20%-6.63%
 2.20%-6.63%
 $
 2,257.8
 $
 1,785.6

 2025-2027
 6.65 %
 3.00%-6.71%
 3.00%-5.75%
 126.8
 127.2

 $
 2,384.6
 $
 1,912.8

 2026-2051
 3.73 %
 1.65%-6.20%
 1.65%-6.20%
 $
 $
 3,297.6

 Notes Payable – Nonaffiliated (c)
 — %
 —%
 4.58%-6.37%
 —
 55.9

 — %
 —%
 4.68%
 —
 38.1

 $
 $
 3,391.6

 (a) For certain series of Pollution Control Bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets.
 (b) Certain Pollution Control Bonds are subject to redemption earlier than the maturity date.
 (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates.
 (d) Dates represent the scheduled final payment dates for the securitization bonds. The legal maturity date is one to two years later. These bonds have been classified for maturity and repayment purposes based on the scheduled final payment date.
 (e) Spent Nuclear Fuel Obligation consists of a liability along with accrued interest for disposal of SNF. See "Spent Nuclear Fuel Disposal" section of Note 6 for additional information.
 (f) See "Equity Units" section below for additional information.

 As of December 31, 2023, outstanding long-term debt was payable as follows:

 AEP
 APCo
 I&M
 OPCo
 PSO

 2024
 $
 2,490.5
 $
 96.0
 $
 95.0
 $
 538.8
 $
 83.7
 $
 —
 $
 0.6
 $
 —

 2025
 3,308.5
 524.5
 90.0
 673.3
 241.2
 —
 250.6
 —

 2026
 1,780.5
 75.0
 425.0
 30.9
 26.3
 —
 50.6
 900.0

 2027
 2,215.9
 25.6
 —
 355.6
 4.1
 —
 0.3
 —

 2028
 2,326.6
 526.2
 60.0
 31.8
 350.8
 —
 —
 575.0

 28,349.7
 4,690.2
 4,806.0
 4,000.0
 2,825.4
 3,400.0
 2,100.0
 2,200.0

 Principal Amount
 40,471.7
 5,937.5
 5,476.0
 5,630.4
 3,531.5
 3,400.0
 2,402.1
 3,675.0

 Unamortized Discount, Net and Debt Issuance Costs

 ( 328.5)
 ( 47.7)
 ( 61.6)
 ( 42.1)
 ( 32.1)
 ( 33.2)
 ( 17.5)
 ( 28.1)

 $
 40,143.2
 $
 5,889.8
 $
 5,414.4
 $
 5,588.3
 $
 3,499.4
 $
 $
 2,384.6
 $

 Long-term Debt Subsequent Events

 In January and February 2024, I&M retired $ 8 million and $ 8 million, respectively, of Notes Payable related to DCC Fuel.

 In January and February 2024, Transource Energy issued $ 16 million and $ 2 million, respectively, of variable rate Other Long-term Debt due in 2025.

 In February 2024, AEP Texas retired $ 12 million of Securitization Bonds.

 In February 2024, APCo retired $ 13 million of Securitization Bonds.

 Equity Units (Applies to AEP)

 2020 Equity Units

 In August 2020, AEP issued 17 million Equity Units initially in the form of corporate units, at a stated amount of $ 50 per unit, for a total stated amount of $ 850 million. Net proceeds from the issuance were approximately $ 833 million. The proceeds were used to support AEP's overall capital expenditure plans.

 Each corporate unit represents a 1/20 undivided beneficial ownership interest in $ 1,000 principal amount of AEP's 1.30 % Junior Subordinated Notes due in 2025 and a forward equity purchase contract which settled after three years in August 2023. In June 2023, AEP successfully remarketed the Junior Subordinated Notes on behalf of holders of the corporate units. AEP did not receive any proceeds from the remarketing which were used to purchase a portfolio of treasury securities that matured on August 14, 2023. On August 15, 2023, the proceeds from the treasury portfolio were used to settle the forward equity purchase contract with AEP. The interest rate on the Junior Subordinated Notes was reset to 5.699 % with the maturity remaining in 2025. In August 2023, AEP issued 10,048,668 shares of AEP common stock and received proceeds totaling $ 850 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. The proceeds were used to pay down debt balances and support AEP's overall capital expenditure plans.

 Debt Covenants (Applies to AEP and AEPTCo)

 Covenants in AEPTCo's note purchase agreements and indenture limit the amount of contractually-defined priority debt (which includes a further sub-limit of $ 50 million of secured debt) to 10 % of consolidated tangible net assets. AEPTCo's contractually-defined priority debt was 1.3 % of consolidated tangible net assets as of December 31, 2023. The method for calculating the consolidated tangible net assets is contractually-defined in the note purchase agreement.

 Dividend Restrictions

 Utility Subsidiaries' Restrictions

 Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends.

 All of the dividends declared by AEP's utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act requirement that prohibits the payment of dividends out of capital accounts in certain circumstances; payment of dividends is generally allowed out of retained earnings. The Federal Power Act also creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to APCo and I&M.

 Certain AEP subsidiaries have credit agreements that contain covenants that limit their debt to capitalization ratio to 67.5 %. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements.

 The most restrictive dividend limitation for certain AEP subsidiaries is through the Federal Power Act restriction, while for other AEP subsidiaries the most restrictive dividend limitation is through the credit agreements. As of December 31, 2023, the maximum amount of restricted net assets of AEP's subsidiaries that may not be distributed to the Parent in the form of a loan, advance or dividend was $ 16.6 billion.

 The Federal Power Act restriction limits the ability of the AEP subsidiaries owning hydroelectric generation to pay dividends out of retained earnings. Additionally, the credit agreement covenant restrictions can limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. As of December 31, 2023, the amount of any such restrictions were as follows:

 AEP
 APCo
 I&M
 OPCo
 PSO

 Restricted Retained Earnings

 $
 3,003.4
 (a)
 $
 737.1
 $
 —
 $
 721.5
 $
 702.6
 $
 —
 $
 1.3
 $
 337.3

 (a) Includes the restrictions of consolidated and non-consolidated subsidiaries.

 Parent Restrictions (Applies to AEP)

 The holders of AEP's common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent's income primarily derives from common stock equity in the earnings of its utility subsidiaries.

 Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5 %. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements. As of December 31, 2023, AEP had $ 7.6 billion of available retained earnings to pay dividends to common shareholders. AEP paid $ 1.8 billion, $ 1.6 billion and $ 1.5 billion of dividends to common shareholders for the years ended December 31, 2023, 2022 and 2021, respectively.

 Lines of Credit and Short-term Debt (Applies to AEP)

 AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries. The program funds a Utility Money Pool, which funds AEP's utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and the short-term debt requirements of subsidiaries that are not participating in either money pool for regulatory or operational reasons, as direct borrowers. As of December 31, 2023, AEP had $ 5 billion in revolving credit facilities to support its commercial paper program. Securitized Debt for Receivables, for the year ended 2023, had a weighted-average interest rate of 5.33 % and a maximum amount outstanding of $ 900 million. The commercial paper program, for the year ended 2023, had a weighted-average interest rate of 5.38 % and a maximum amount outstanding of $ 3.2 billion. AEP's outstanding short-term debt was as follows:

 2023
 2022

 Type of Debt
 Outstanding
 Interest
Rate (a)
 Outstanding
 Interest
Rate (a)

 AEP
 Securitized Debt for Receivables (b)
 $
 888.0
 5.65
 %
 $
 750.0
 4.67
 %

 AEP
 Commercial Paper
 5.69
 %
 2,862.2
 4.80
 %

 AEP
 —
 —
 %
 125.0
 5.17
 %

 AEP
 —
 —
 %
 150.0
 5.17
 %

 AEP
 —
 —
 %
 100.0
 5.23
 %

 AEP
 —
 —
 %
 125.0
 4.87
 %

 Notes Payable
 4.3
 7.71
 %
 —
 —
 %

 Total Short-term Debt
 $
 2,830.2
 $
 4,112.2

 (a) Weighted-average rate as of December 31, 2023 and 2022, respectively.
 (b) Amount of securitized debt for receivables as accounted for under the "Transfers and Servicing" accounting guidance.

 Corporate Borrowing Program (Applies to Registrant Subsidiaries)

 AEP subsidiaries use a corporate borrowing program to meet the short-term borrowing needs of AEP's subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP's utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and direct borrowing from AEP. The AEP Utility Money Pool operates in accordance with the terms and conditions of its agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of December 31, 2023 and 2022 are included in Advances to Affiliates and Advances from Affiliates, respectively, on the Registrant Subsidiaries' balance sheets. The Utility Money Pool participants' money pool activity and corresponding authorized borrowing limits are described in the following tables:

 Year Ended December 31, 2023:

 Net Loans to

 (Borrowings from)
 Authorized

 from the
 Loans to the
 from the
 Loans to the
 the Utility Money
 Short-term

 Pool as of
 Borrowing

 Limit

 $
 477.5
 $
 42.0
 $
 216.8
 $
 12.9
 $
 ( 103.7)
 $
 600.0

 471.3
 309.4
 135.6
 70.5
 ( 62.8)
 820.0
 (a)

 APCo
 388.6
 19.8
 283.5
 19.0
 ( 320.7)
 750.0

 I&M
 475.3
 112.2
 84.0
 44.2
 ( 63.3)
 500.0

 OPCo
 485.7
 64.7
 183.0
 40.2
 ( 110.5)
 500.0

 PSO
 375.0
 121.5
 92.5
 49.6
 ( 54.4)
 750.0

 401.6
 25.8
 150.7
 16.5
 ( 88.7)
 750.0

 Year Ended December 31, 2022:

 Net Loans to

 (Borrowings from)
 Authorized

 from the
 Loans to the
 from the
 Loans to the
 the Utility Money
 Short-term

 Pool as of
 Borrowing

 Limit

 $
 348.8
 $
 652.3
 $
 173.3
 $
 247.8
 $
 ( 96.5)
 $
 500.0

 480.2
 137.0
 189.4
 28.9
 ( 195.5)
 820.0
 (a)

 APCo
 438.4
 214.2
 181.7
 45.4
 ( 162.4)
 500.0

 I&M
 318.6
 23.0
 105.2
 22.3
 ( 226.9)
 500.0

 OPCo
 262.5
 246.1
 101.3
 86.9
 ( 172.9)
 500.0

 PSO
 364.2
 432.5
 224.5
 402.8
 ( 364.2)
 400.0

 358.4
 156.6
 219.3
 109.7
 ( 310.7)
 400.0

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

 The activity in the above tables does not include short-term lending activity of certain AEP nonutility subsidiaries. AEP Texas' wholly-owned subsidiary, AEP Texas North Generation Company, LLC and SWEPCo's wholly-owned subsidiary, Mutual Energy SWEPCo, LLC participate in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of December 31, 2023 and 2022 are included in Advances to Affiliates on each subsidiaries' balance sheets. The Nonutility Money Pool participants' money pool activity is described in the following tables:

 Year Ended December 31, 2023:

 Maximum Loans
 Average Loans
 Loans to the Nonutility

 to the Nonutility
 to the Nonutility
 Money Pool as of

 $
 7.1
 $
 6.9
 $
 7.1

 2.8
 2.4
 2.2

 Year Ended December 31, 2022:

 Maximum Loans
 Average Loans
 Loans to the Nonutility

 to the Nonutility
 to the Nonutility
 Money Pool as of

 $
 7.0
 $
 6.8
 $
 6.9

 2.1
 2.1
 2.1

 AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of outstanding loans to and borrowings from AEP as of December 31, 2023 and 2022 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo's balance sheets. AEPTCo's direct financing activities with AEP and corresponding authorized borrowing limits are described in the following tables:

 Year Ended December 31, 2023:

 Borrowings from
 Loans to
 Authorized

 Loans
 Loans
 AEP as of
 AEP as of
 Short-term

 from AEP
 to AEP
 from AEP
 to AEP
 Borrowing Limit

 $
 44.4
 $
 158.1
 $
 3.9
 $
 64.2
 $
 44.4
 $
 —
 $
 50.0
 (a)

 Year Ended December 31, 2022:

 Borrowings from
 Loans to
 Authorized

 Loans
 Loans
 AEP as of
 AEP as of
 Short-term

 from AEP
 to AEP
 from AEP
 to AEP
 Borrowing Limit

 $
 52.4
 $
 141.8
 $
 6.7
 $
 57.5
 $
 29.4
 $
 —
 $
 50.0
 (a)

 (a) Amount represents the authorized short-term borrowing limit from FERC or state regulatory agencies not otherwise included in the utility money pool above.

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

 2023
 2022
 2021

 Maximum Interest Rate
 5.81
 %
 5.28
 %
 0.48
 %

 Minimum Interest Rate
 4.66
 %
 0.10
 %
 0.02
 %

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

 Average Interest Rate for Funds Borrowed
from the Utility Money Pool for the
 Average Interest Rate for Funds Loaned
to the Utility Money Pool for the

 2023
 2022
 2021
 2023
 2022
 2021

 5.46
 %
 1.08
 %
 0.33
 %
 5.71
 %
 1.99
 %
 0.26
 %

 5.41
 %
 1.81
 %
 0.32
 %
 5.56
 %
 2.47
 %
 0.10
 %

 APCo
 5.54
 %
 2.34
 %
 0.41
 %
 5.54
 %
 2.39
 %
 0.25
 %

 I&M
 5.14
 %
 2.57
 %
 0.33
 %
 5.57
 %
 2.20
 %
 0.23
 %

 OPCo
 5.43
 %
 3.51
 %
 0.27
 %
 5.60
 %
 1.22
 %
 0.14
 %

 PSO
 5.51
 %
 2.65
 %
 0.34
 %
 5.35
 %
 0.75
 %
 0.07
 %

 5.34
 %
 2.80
 %
 0.26
 %
 5.72
 %
 0.55
 %
 0.18
 %

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

 Maximum Interest Rate

 Minimum Interest Rate

 Average Interest Rate

 Year Ended

 for Funds Loaned to

 for Funds Loaned to

 for Funds Loaned to

 the Nonutility Money Pool

 the Nonutility Money Pool

 the Nonutility Money Pool

 2023

 5.81
 %
 4.66
 %
 5.54
 %

 2023

 5.81
 %
 4.66
 %
 5.56
 %

 2022
 5.28
 %
 0.46
 %
 2.23
 %

 2022
 5.28
 %
 0.46
 %
 2.23
 %

 2021
 0.58
 %
 0.21
 %
 0.37
 %

 2021
 0.58
 %
 0.21
 %
 0.37
 %

 AEPTCo's maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table:

 Minimum

 Minimum

 Year Ended

 Borrowed from

 Borrowed from

 Loaned to

 Loaned to

 Borrowed from

 Loaned to

 AEP

 AEP
 AEP

 AEP

 AEP

 AEP

 2023

 5.81
 %
 4.53
 %
 5.81
 %
 4.53
 %
 5.56
 %
 5.51
 %

 2022

 5.28
 %
 0.46
 %
 5.28
 %
 0.46
 %
 2.08
 %
 2.07
 %

 2021
 0.86
 %
 0.25
 %
 0.86
 %
 0.25
 %
 0.38
 %
 0.35
 %

 Interest expense related to short-term borrowing activities with the Utility Money Pool, Nonutility Money Pool and direct borrowing financing relationship are included in Interest Expense on each of the Registrant Subsidiaries' statements of income. The Registrant Subsidiaries incurred interest expense for all short-term borrowing activities as follows:

 2023
 2022
 2021

 $
 10.8
 $
 0.9
 $
 0.3

 7.6
 3.5
 0.6

 APCo
 16.8
 5.6
 0.1

 I&M
 3.2
 2.9
 0.2

 OPCo
 9.7
 2.3
 0.1

 PSO
 2.3
 5.5
 0.3

 7.9
 4.9
 0.3

 Interest income related to short-term lending activities with the Utility Money Pool, Nonutility Money Pool and direct borrowing financing relationship are included in Interest Income, unless shown as Other Income due to materiality, on each of the Registrant Subsidiaries' statements of income. The Registrant Subsidiaries earned interest income for all short-term lending activities as follows:

 2023
 2022
 2021

 $
 0.1
 $
 2.6
 $
 0.1

 7.0
 1.6
 0.4

 APCo
 1.1
 2.8
 0.3

 I&M
 2.4
 0.5
 0.2

 OPCo
 0.1
 0.4
 0.1

 PSO
 1.5
 0.3
 —

 0.2
 0.2
 0.1

 Credit Facilities

 See "Letters of Credit" section of Note 6 for additional information.

 Securitized Accounts Receivables – AEP Credit (Applies to AEP)

 AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies' receivables and accelerate AEP Credit's cash collections.

 AEP Credit's receivables securitization agreement provides a commitment of $ 900 million from bank conduits to purchase receivables. The agreement was amended in August 2023 to increase the commitment from $ 750 million and expires in September 2025. As of December 31, 2023, the affiliated utility subsidiaries were in compliance with all requirements under the agreement.

 Accounts receivable information for AEP Credit was as follows:

 2023
 2022
 2021

 Effective Interest Rates on Securitization of Accounts Receivable
 5.33
 %
 1.84
 %
 0.19
 %

 Net Uncollectible Accounts Receivable Written Off
 $
 30.7
 $
 29.5
 $
 26.5

 2023
 2022

 Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts
 $
 1,207.4
 $
 1,167.7

 Short-term – Securitized Debt of Receivables

 888.0
 750.0

 Delinquent Securitized Accounts Receivable
 52.2
 44.2

 Bad Debt Reserves Related to Securitization
 42.0
 39.7

 Unbilled Receivables Related to Securitization
 409.8
 360.9

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

 Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries, except AEP Texas and AEPTCo)

 Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit's financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary's receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. KPCo ceased selling accounts receivable to AEP Credit in the first quarter of 2022, based on the expected sale to Liberty. As a result, 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. In the third quarter of 2023, KPCo resumed selling accounts receivable to AEP Credit, due to the termination of the sale to Liberty, and the balance in KPCo's allowance for uncollectible accounts was reversed. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries' statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder.

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

 2023
 2022

 APCo
 $
 184.6
 $
 194.4

 I&M
 156.4
 166.9

 OPCo
 541.7
 478.6

 PSO
 134.6
 155.5

 168.3
 194.0

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

 2023
 2022
 2021 (a)

 APCo
 $
 16.9
 $
 9.4
 $
 4.9

 I&M
 16.3
 9.7
 7.0

 OPCo
 29.5
 29.8
 8.3

 PSO
 15.3
 7.4
 3.4

 18.5
 9.4
 5.4

 (a) In 2021, due to the successful collection of accounts receivable balances during the COVID-19 pandemic, the allowance for doubtful accounts was reduced, resulting in the issuance of credits to offset the higher fees previously paid and to lower subsequent fees paid.

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

 2023
 2022
 2021

 APCo
 $
 1,819.8
 $
 1,552.9
 $
 1,324.1

 I&M
 2,054.8
 2,045.6
 1,927.0

 OPCo
 3,339.3
 3,101.3
 2,458.5

 PSO
 1,944.5
 1,809.5
 1,406.4

 1,866.4
 1,858.4
 1,636.1

 15. STOCK-BASED COMPENSATION

 The disclosures in this note apply to AEP only. The impact of AEP's share-based compensation plans is insignificant to the financial statements of the Registrant Subsidiaries.

 Awards under the American Electric Power System 2015 Long-Term Incentive Plan (2015 LTIP), which replaced prior long-term incentive plans effective April 2015, may be granted to employees and directors. The 2015 LTIP was subsequently amended in September 2016. The 2015 LTIP provides for a maximum of 10 million AEP common shares to be available for grant to eligible employees and directors. As of December 31, 2023, 3,698,144 shares remained available for issuance under the 2015 LTIP. No new awards may be granted under the Prior Plan. Awards granted under the 2015 LTIP awards may be made in the form of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock-based awards. Shares issued pursuant to a stock option or a stock appreciation right reduce the shares remaining available for grants under the 2015 LTIP by 0.286 of a share. Each share issued for any other award that settles in AEP stock reduces the shares remaining available for grants under the 2015 LTIP by one share. Cash settled awards do not reduce the number of shares remaining available under the 2015 LTIP. The following sections provide further information regarding each type of stock-based compensation award granted under these plans.

 Performance Shares

 Performance units granted prior to 2017 were settled in cash rather than AEP common stock and did not reduce the number of shares remaining available under the 2015 LTIP. Those performance units had a fair value upon vesting equal to the average closing market price of AEP common stock for the last 20 trading days of the performance period. Performance shares granted in and after 2017 are settled in AEP common stock and reduce the aggregate share authorization. In all cases the number of performance shares held at the end of the three-year performance period is multiplied by the performance score for such period to determine the actual number of performance shares that participants realize. The performance score can range from 0 % to 200 % and is determined at the end of the performance period based on performance measures, which include both performance and market conditions, established for each grant at the beginning of the performance period by the Human Resources Committee of AEP's Board of Directors (HR Committee).

 Certain employees must satisfy a minimum stock ownership requirement. If those employees have not met their stock ownership requirement, a portion or all of their performance shares are mandatorily deferred upon vesting into AEP career shares to the extent needed to meet their stock ownership requirement. AEP career shares are a form of non-qualified deferred compensation that has a value equivalent to a share of AEP common stock. AEP career shares are settled in AEP common stock after the participant's termination of employment.

 AEP career shares are recorded in Paid-in Capital on the balance sheets. Amounts equivalent to cash dividends on both performance shares and AEP career shares accrue as additional shares. Management records compensation cost for performance shares over an approximately three-year vesting period. Performance shares are recorded as mezzanine equity on the balance sheets until the vesting date and compensation cost is calculated at fair value based on the performance metrics for each grant. Performance shares granted in 2023, 2022 and 2021 have three performance metrics: (a) three-year cumulative operating earnings per-share with a 50% weight, (b) relative total shareholder return with a 40% weight and (c) renewable generation additions (2023 grants) or non-emitting generation capacity as a percentage of total owned and purchased capacity (2022 and 2021 grants) with a 10% weight. The three-year cumulative operating earnings per-share and renewable generation additions or non-emitting generating capacity metrics are adjusted quarterly for changes in performance relative to the metric approved by the HR Committee. The total shareholder return metric is measured relative to a peer group of similar companies and is based on a third-party Monte Carlo valuation. The value related to this metric does not change over the three-year vesting period.

 The HR Committee awarded performance shares and reinvested dividends on outstanding performance shares and AEP career shares as follows:

 Performance Shares
 2023
 2022
 2021

 Awarded Shares (in thousands)
 486.7
 530.3
 565.0

 Weighted-Average Share Fair Value at Grant Date
 $
 98.63
 $
 97.61
 $
 81.02

 Vesting Period (in years)

 Performance Shares and AEP Career Shares
(Reinvested Dividends Portion)

 2023
 2022
 2021

 Awarded Shares (in thousands)
 81.3
 63.3
 74.5

 Weighted-Average Fair Value at Grant Date
 $
 82.02
 $
 98.73
 $
 84.48

 Vesting Period (in years)
 (a)
 (a)
 (a)

 (a) The vesting period for the reinvested dividends on performance shares is equal to the remaining life of the related performance shares. Dividends on AEP career shares vest immediately when the dividend is awarded but are not settled in AEP common stock until after the participant's AEP employment ends.

 Performance scores and final awards are determined and approved by the HR Committee in accordance with the pre-established performance measures within approximately two months after the end of the performance period.

 The certified performance scores and shares earned for the three-year periods were as follows:

 Performance Shares
 2023
 2022
 2021

 Certified Performance Score
 106.1
 %
 131.1
 %
 102.9
 %

 Performance Shares Earned
 540,863
 512,660
 537,166

 Performance Shares Mandatorily Deferred as AEP Career Shares
 70,377
 28,282
 14,613

 Performance Shares Voluntarily Deferred into the Incentive Compensation Deferral Program
 22,716
 23,609
 22,915

 Performance Shares to be Settled (a)
 447,770
 460,769
 499,638

 (a) Performance shares settled in AEP common stock in the quarter following the end of the year shown.

 The settlements were as follows:

 Performance Shares and AEP Career Shares
 2023
 2022
 2021

 AEP Common Stock Settlements for Performance Shares
 $
 41.8
 $
 43.2
 $
 54.7

 AEP Common Stock Settlements for Career Share Distributions
 8.3
 5.1
 4.0

 A summary of the status of AEP's nonvested Performance Shares as of December 31, 2023 and changes during the year ended December 31, 2023 were as follows:

 Nonvested Performance Shares
 Shares
 Weighted Average
Grant Date Fair Value

 (in thousands)

 Nonvested as of January 1, 2023
 1,012.2
 $
 90.27

 Awarded
 486.7
 98.63

 Dividends
 59.8
 82.02

 Vested (a)
 ( 514.6)
 82.33

 Forfeited
 ( 154.2)
 86.73

 Nonvested as of December 31, 2023
 889.9
 99.49

 (a) The vested Performance Shares will be converted to 448 thousand shares based on the closing share price on the day before settlement.

 Monte Carlo Valuation

 AEP engages a third-party for a Monte Carlo valuation to calculate the fair value of the total shareholder return metric for the performance shares awarded during and after 2017. The valuations use a lattice model and the expected volatility assumptions used were the historical volatilities for AEP and the members of their peer group. The assumptions used in the Monte Carlo valuations were as follows:

 Assumptions
 2023
 2022
 2021

 Valuation Period (in years) (a)
 2.87
 2.86
 2.88

 Expected Volatility Minimum
 21.23
 %
 25.92
 %
 25.87
 %

 Expected Volatility Maximum
 39.00
 %
 40.82
 %
 39.90
 %

 Expected Volatility Average
 25.35
 %
 31.09
 %
 31.01
 %

 Dividend Rate (b)
 —
 %
 —
 %
 —
 %

 Risk Free Rate
 4.32
 %
 1.64
 %
 0.19
 %

 (a) Period from award date to vesting date.
 (b) Equivalent to reinvesting dividends.

 Restricted Stock Units

 The HR Committee grants restricted stock units (RSUs), which generally vest, subject to the participant's continued AEP employment, over at least three years in approximately equal annual increments. The RSUs accrue dividends as additional RSUs. The additional RSUs granted as dividends vest on the same date, subject to the participant's continued AEP employment, as the underlying RSUs. RSUs are converted into shares of AEP common stock upon vesting. Executive officers are those officers who are subject to the disclosure requirements set forth in Section 16 of the Securities Exchange Act of 1934. The RSU compensation cost is measured at fair value on the grant date and recorded over the vesting period. Fair value is determined by multiplying the number of RSUs granted by the grant date market closing price. The maximum contractual term of outstanding RSUs is approximately 40 months from the grant date.

 The HR Committee awarded RSUs, including additional units awarded as dividends, as follows:

 Restricted Stock Units
 2023
 2022
 2021

 Awarded Units (in thousands)
 268.4
 290.4
 280.0

 Weighted-Average Grant Date Fair Value
 $
 88.52
 $
 90.48
 $
 80.39

 The total fair value and total intrinsic value of restricted stock units vested were as follows:

 Restricted Stock Units
 2023
 2022
 2021

 Fair Value of Restricted Stock Units Vested
 $
 18.8
 $
 17.8
 $
 20.5

 Intrinsic Value of Restricted Stock Units Vested (a)
 19.0
 20.3
 22.0

 (a) Intrinsic value is calculated as market price at the vesting date.

 A summary of the status of AEP's nonvested RSUs as of December 31, 2023 and changes during the year ended December 31, 2023 were as follows:

 Nonvested Restricted Stock Units
 Shares/Units
 Weighted Average
Grant Date Fair Value

 (in thousands)

 Nonvested as of January 1, 2023
 459.6
 $
 88.05

 Awarded
 268.4
 88.52

 Vested
 ( 212.4)
 88.47

 Forfeited
 ( 84.5)
 86.84

 Nonvested as of December 31, 2023
 431.1
 88.57

 The total aggregate intrinsic value of nonvested RSUs as of December 31, 2023 was $ 33 million and the weighted-average remaining contractual life was 1.5 years.

 Other Stock-Based Plans

 AEP also has a Stock Unit Accumulation Plan (SUAP) for Non-Employee Directors providing each non-employee director with AEP stock units as a substantial portion of the compensation for their services as a director. The number of stock units provided is based on the closing price of AEP common stock on the last trading day of the quarter for which the stock units were earned. Amounts equivalent to cash dividends on the stock units accrue as additional AEP stock units. The stock units granted to non-employee directors are fully vested on their grant date. Stock units are paid to directors upon termination of their board service or up to 10 years later if the participant so elects. Cash settlements for stock units were calculated based on the average closing price of AEP common stock for the last 20 trading days prior to the distribution date. Effective June 30, 2022, the SUAP was amended to pay stock units in AEP common stock rather than cash.

 Management records compensation costs for stock units when the units are awarded and prior to June 2022 adjusted the liability for changes in value based on the current 20-day average closing price of AEP common stock on the valuation date.

 After five years of service on the Board of Directors, non-employee directors receive subsequent AEP stock units as contributions to an AEP stock fund under the Stock Unit Accumulation Plan. Such amounts may be exchanged into other market-based investment options available to employees that participate in AEP's Incentive Compensation Deferral Plan. These balances are paid in cash upon termination of board service or up to 10 years later if the participant so elects.

 AEP common stock and cash settlements for stock unit distributions were immaterial for the years ended December 31, 2023, 2022 and 2021.

 The Board of Directors awarded stock units, including units awarded for dividends, as follows:

 Stock Unit Accumulation Plan for Non-Employee Directors
 2023
 2022
 2021

 Awarded Units (in thousands)
 19.8
 14.5
 12.6

 Weighted-Average Grant Date Fair Value
 $
 82.14
 $
 95.16
 $
 84.54

 Share-based Compensation Plans

 For share-based payment arrangements the compensation cost, the actual tax benefit from the tax deductions for compensation cost recognized in income and the total compensation cost capitalized were as follows:

 Share-based Compensation Plans
 2023
 2022
 2021

 Compensation Cost for Share-based Payment Arrangements (a)
 $
 50.9
 $
 63.3
 $
 61.1

 Actual Tax Benefit
 6.4
 8.0
 8.7

 Total Compensation Cost Capitalized
 15.3
 16.0
 16.9

 (a) Compensation cost for share-based payment arrangements is included in Other Operation and Maintenance expenses on the statements of income.

 As of December 31, 2023, there was $ 66 million of total unrecognized compensation cost related to unvested share-based compensation arrangements granted under the 2015 LTIP. Unrecognized compensation cost related to unvested share-based arrangements will change as the fair value of performance shares is adjusted each period and as forfeitures for all award types are realized. AEP's unrecognized compensation cost will be recognized over a weighted-average period of 1.4 years.

 Under the 2015 LTIP, AEP is permitted to use authorized but unissued shares, treasury shares, shares acquired in the open market specifically for distribution under these plans, or any combination thereof to fulfill share commitments. AEP's current practice is to use authorized but unissued shares to fulfill share commitments. The number of shares used to fulfill share commitments is generally reduced to offset tax withholding obligations.

 16. RELATED PARTY TRANSACTIONS

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

 For other related party transactions, also see "Income Taxes and Investment and Production Tax Credits" section of Note 1 in addition to "Corporate Borrowing Program" and "Securitized Accounts Receivables – AEP Credit" sections of Note 14.

 Intercompany Billings

 The Registrant Subsidiaries and other AEP subsidiaries perform certain utility services for each other when necessary or practical. The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable basis of proration for services that benefit multiple companies. The billings for services are made at cost and include no compensation for the use of equity capital.

 Power Coordination Agreement (Applies to all Registrant Subsidiaries except AEP Texas and AEPTCo)

 Effective January 1, 2014, the FERC approved the PCA. Under the PCA, APCo, I&M, KPCo and WPCo are individually responsible for planning their respective capacity obligations. The PCA allows, but does not obligate, APCo, I&M, KPCo and WPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective Off-system Sales and purchase activities.

 AEPSC conducts power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other risk management activities on behalf of APCo, I&M, KPCo, PSO, SWEPCo and WPCo. Certain power and natural gas risk management activities for APCo, I&M, KPCo and WPCo are allocated based on the four member companies' respective equity positions, while power and natural gas risk management activities for PSO and SWEPCo are allocated based on the Operating Agreement. AEPSC conducts only gasoline, diesel fuel, energy procurement and risk management activities on OPCo's behalf.

 Joint License Agreement (Applies to all Registrant Subsidiaries except AEP Texas and SWEPCo)

 AEPTCo entered into a 50-year joint license agreement with APCo, I&M, KPCo, OPCo and PSO, respectively, allowing either party to occupy the granting party's facilities or real property. In addition, AEPTCo entered into a 5-year joint license agreement with APCo and WPCo. After the expiration of these agreements, the term shall automatically renew for successive one-year terms unless either party provides notice. The joint license billing provides compensation to the granting party for the cost of carrying assets, including depreciation expense, property taxes, interest expense, return on equity and income taxes. AEPTCo recorded the costs related to these agreements in Other Operation expense on the statements of income. APCo, I&M, KPCo, OPCo, PSO and WPCo recorded income related to these agreements in Sales to AEP Affiliates on the statements of income. The impact of the joint license agreement for the years ended December 31, 2023, 2022 and 2021 was not material.

 Unit Power Agreements (Applies to I&M)

 A UPA between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant unless it is sold to another utility. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) net of amounts received by AEGCo from any other sources, sufficient to enable AEGCo to pay all of its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by the FERC. The UPA 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). I&M's direct purchases from AEGCo were $ 181 million, $ 242 million and $ 218 million for the years ended December 31, 2023, 2022 and 2021, respectively. These direct purchases are presented as Purchased Electricity from AEP Affiliates on I&M's statements of income.

 Ohio Auctions (Applies to OPCo)

 In connection with OPCo's June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015. AEP Energy and AEPEP participate in the auction process and have been awarded tranches of OPCo's SSO load. OPCo's auction purchases were $ 87 million, $ 10 million and $ 52 million for the years ended December 31, 2023, 2022 and 2021, respectively. These direct purchases are presented as Purchased Electricity from AEP Affiliates on OPCo's statements of income.

 Sales and Purchases of Property

 Certain AEP subsidiaries had affiliated sales and purchases of electric property individually amounting to $100 thousand or more, sales and purchases of meters and transformers, and sales and purchases of transmission property. There were no gains or losses recorded on the transactions and the net book value of all sales and purchases for the years ended December 31, 2023, 2022 and 2021 were not material. These sales and purchases are recorded in Property, Plant and Equipment on the balance sheets.

 Charitable Contributions to AEP Foundation

 The American Electric Power Foundation is funded by American Electric Power and its utility operating units. The Foundation provides a permanent, ongoing resource for charitable initiatives and multi-year commitments in the communities served by AEP and initiatives outside of AEP's 11-state service area. Charitable contributions to the AEP Foundation were not made in 2023 or 2021. Charitable contributions were recorded in Other Operation expenses on the statements of income as follows for the year ended December 31, 2022:

 AEP
 APCo
 I&M
 OPCo
 PSO

 Contributions to AEP Foundation
 $
 75.0
 $
 9.9
 $
 11.1
 $
 12.5
 $
 11.0
 $
 8.1
 $
 5.8
 $
 8.8

 I&M Barging, Urea Transloading and Other Services (Applies to APCo and I&M)

 I&M provides barging, urea transloading and other transportation services to affiliates. Urea is a chemical used to control NOx emissions at certain generation plants in the AEP System. I&M recorded revenues from barging, transloading and other services in Other Revenues – Affiliated on the statements of income. The affiliated companies recorded these costs paid to I&M as fuel expenses or other operation expenses. The amounts of affiliated expenses were:

 2023
 2022
 2021

 AEGCo
 $
 9.3
 $
 11.3
 $
 7.6

 APCo
 39.2
 36.1
 40.1

 KPCo
 —
 2.0
 3.1

 WPCo
 10.6
 4.7
 3.2

 AEP Wind Holdings LLC PPAs (Applies to I&M, OPCo and SWEPCo)

 Prior to acquisition, Fowler Ridge 2 had PPAs with I&M and OPCo and Flat Ridge 2 had a PPA with SWEPCo for a portion of their energy production. The following table shows the amounts of purchased electricity by I&M, PSO and SWEPCo:

 2023
 2022
 2021

 I&M
 $
 8.0
 $
 11.8
 $
 9.9

 OPCo
 16.1
 23.6
 19.6

 —
 13.7
 14.5

 See Note 7 - Acquisitions, Dispositions and Impairments for additional information related to the disposal of the 50% interests in Fowler Ridge 2 which was included in the August 2023 sale of the Competitive Contracted Renewables Portfolio and Flat Ridge 2 which was sold in November 2022.

 Transmission Service Charges

 The AEP East Companies are parties to the TA, which defines how transmission costs through the PJM OATT are allocated among the AEP East Companies on a 12-month average coincident peak basis. Additional costs for transmission services provided by AEPTCo and other transmission affiliates are billed to AEP East Companies through the PJM OATT. PSO, SWEPCo and AEPSC are parties to the TCA in connection with the operation of the transmission assets of PSO and

 SWEPCo. Under the TCA, AEPSC is responsible for monitoring the reliability of their transmission systems and administering the OATT. Additional costs for transmission services provided by AEPTCo and other transmission affiliates are billed to PSO and SWEPCo through the SPP OATT. Pursuant to an order from the PUCT, ETT bills AEP Texas for its ERCOT wholesale transmission services.

 The charges discussed above are recorded in Other Operation expenses on the statements of income. AEPTCo recorded affiliated transmission revenues in Sales to AEP Affiliates on the statements of income. Refer to the Affiliated Revenues section below for amounts related to these transactions.

 The following table shows the net transmission service charges recorded by the Registrant Subsidiaries:

 2023
 2022
 2021

 $
 28.7
 $
 28.5
 $
 28.0

 APCo
 365.1
 345.1
 302.0

 I&M
 226.2
 220.8
 186.7

 OPCo
 665.3
 608.2
 508.9

 PSO
 100.1
 110.8
 94.7

 49.2
 62.1
 56.2

 Affiliated Revenues

 The tables below represent revenues from affiliates, net of respective provisions for refund, by type of revenue for the Registrant Subsidiaries. Related party revenues are shown in Sales to AEP Affiliates, Provision for Refund - Affiliated and Other Revenues - Affiliated, respectively, on the Registrant Subsidiaries' statements of income.

 Related Party Revenues
 APCo
 I&M
 OPCo
 PSO

 Direct Sales to East Affiliates
 $
 —
 $
 —
 $
 158.7
 $
 —
 $
 —
 $
 —
 $
 —

 —
 1,304.0
 70.9
 ( 11.1)
 3.2
 —
 45.3

 Barging, Urea Transloading and Other Transportation Services
 —
 —
 —
 59.0
 —
 —
 —

 4.9
 13.8
 9.7
 9.9
 27.9
 1.2
 1.5

 Total Affiliated Revenues
 $
 4.9
 $
 1,317.8
 $
 239.3
 $
 57.8
 $
 31.1
 $
 1.2
 $
 46.8

 Related Party Revenues
 APCo
 I&M
 OPCo
 PSO

 Direct Sales to East Affiliates
 $
 —
 $
 —
 $
 169.7
 $
 —
 $
 —
 $
 —
 $
 —

 Direct Sales to West Affiliates
 —
 —
 —
 —
 —
 —
 1.3

 —
 1,276.4
 77.5
 7.7
 —
 51.5

 Barging, Urea Transloading and Other Transportation Services
 —
 —
 —
 54.1
 —
 —
 —

 3.5
 7.4
 8.9
 7.8
 22.4
 2.9
 1.1

 Total Affiliated Revenues
 $
 3.5
 $
 1,283.8
 $
 256.1
 $
 69.6
 $
 18.8
 $
 2.9
 $
 53.9

 Related Party Revenues
 APCo
 I&M
 OPCo
 PSO

 Direct Sales to East Affiliates
 $
 —
 $
 —
 $
 128.6
 $
 —
 $
 —
 $
 —
 $
 —

 —
 1,136.1
 60.3
 —
 39.6

 Barging, Urea Transloading and Other Transportation Services
 —
 —
 —
 54.0
 —
 —
 —

 3.9
 17.8
 9.0
 6.3
 25.9
 4.2
 1.4

 Total Affiliated Revenues
 $
 3.9
 $
 1,153.9
 $
 197.9
 $
 57.8
 $
 24.8
 $
 4.2
 $
 41.0

 17. VARIABLE INTEREST ENTITIES AND EQUITY METHOD INVESTMENTS

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

 The accounting guidance for "Variable Interest Entities" is a consolidation model that considers if a company has a variable interest in a VIE. A VIE is a legal entity that possesses any of the following conditions: the entity's equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity's economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity's expected losses or the right to receive the legal entity's expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for "Variable Interest Entities." In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently.

 AEP holds ownership interests in businesses with varying ownership structures. Partnership interests and other variable interests are evaluated to determine if each entity is a VIE, and if so, whether or not the VIE should be consolidated into AEP's financial statements. AEP has not provided material financial or other support that was not previously contractually required to any of its consolidated VIEs. If an entity is determined not to be a VIE, or if the entity is determined to be a VIE and AEP is not deemed to be the primary beneficiary, the entity is accounted for under the equity method of accounting.

 Consolidated Variable Interests Entities

 Sabine (Applies to AEP and SWEPCo)

 Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine's only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo's total billings from Sabine for the years ended December 31, 2023, 2022 and 2021 were $ 101 million, $ 168 million and $ 162 million, respectively. As of March 31, 2023, SWEPCo fuel deliveries, including billings of all fixed costs, from Sabine ceased, which resulted in a decrease in billings in 2023 as compared to 2022. See "Pirkey Plant and Related Fuel Operations" section of Note 5 for additional information. See the tables below for the classification of Sabine's assets and liabilities on SWEPCo's balance sheets.

 As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $ 155 million. Since SWEPCo uses self-bonding, the guarantee commits SWEPCo to complete the reclamation, in the event, Sabine does not complete the work. This guarantee ends upon completion of reclamation. Pirkey Plant was retired in March 2023 and the mine end-of-life has been adjusted accordingly. Reclamation is expected to be complete by 2037 at an estimated cost of $ 144 million. Actual reclamation costs could vary due to inflation and scope changes to the mine reclamation. SWEPCo recovers these costs through its fuel clauses. As of December 31, 2023, SWEPCo has recorded $ 134 million of mine reclamation costs in ARO and $ 34 million in Accounts Payable - Affiliated Companies for collected reclamation costs that have been billed to SWEPCo. SWEPCo has collected $ 92 million through a rider for reclamation costs. The remaining ARO of $ 76 million is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo's balance sheets.

 DCC Fuel (Applies to AEP and I&M)

 I&M has nuclear fuel lease agreements with DCC Fuel, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the years ended December 31, 2023, 2022 and 2021 were $ 97 million, $ 84 million and $ 91 million, respectively. The leases were recorded as finance leases on I&M's balance sheets as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months. Based on I&M's control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The finance leases are eliminated upon consolidation. See the tables below for the classification of DCC Fuel's assets and liabilities on I&M's balance sheets.

 Transition Funding (Applies to AEP and AEP Texas)

 Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to restructuring legislation in Texas. Management has concluded that AEP Texas is the primary beneficiary of Transition Funding because AEP Texas has the power to direct the most significant activities of the VIE and AEP Texas' equity interest could potentially be significant. Therefore, AEP Texas is required to consolidate Transition Funding. As of December 31, 2023 and 2022, $ 72 million and $ 70 million of the securitized bonds were included in Long-term Debt Due Within One Year - Nonaffiliated, respectively, on the balance sheets. The securitized bonds included in Long-term Debt - Nonaffiliated were immaterial and $ 71 million as of December 31, 2023 and 2022, respectively, on the balance sheets. Transition Funding has securitized transition assets of $ 64 million and $ 125 million as of December 31, 2023 and 2022, respectively, which are presented separately on the face of the balance sheets. The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from AEP Texas under-recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to AEP Texas or any other AEP entity. AEP Texas acts as the servicer for Transition Funding's securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Transition Funding's assets and liabilities on the balance sheets.

 Restoration Funding (Applies to AEP and AEP Texas)

 Restoration Funding was formed for the sole purpose of issuing and servicing securitization bonds related to storm restoration of AEP Texas' distribution system primarily due to damage caused by Hurricane Harvey. Management has concluded that AEP Texas is the primary beneficiary of Restoration Funding because AEP Texas has the power to direct the most significant activities of the VIE and AEP Texas' equity interest could potentially be significant. Therefore, AEP Texas is required to consolidate Restoration Funding. As of December 31, 2023 and 2022, $ 24 million and $ 24 million of the securitized bonds were included in Long-term Debt Due Within One Year - Nonaffiliated, respectively, and $ 126 million and $ 150 million were included in Long-term Debt - Nonaffiliated, respectively, on the balance sheets. Restoration Funding has securitized assets of $ 139 million and $ 161 million as of December 31, 2023 and 2022, respectively, which are presented separately on the face of the balance sheets. The securitized restoration assets represent the right to impose and collect Texas storm restoration costs from customers receiving electric transmission or distribution service from AEP Texas under-recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to AEP Texas or any other AEP entity. AEP Texas acts as the servicer for Restoration Funding's securitized assets and remits all related amounts collected from customers to Restoration Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Restoration Funding's assets and liabilities on the balance sheets.

 Appalachian Consumer Rate Relief Funding (Applies to AEP and APCo)

 Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo's under-recovered ENEC deferral balance. Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo's equity interest could potentially be significant. Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding. As of December 31, 2023 and 2022, $ 27 million and $ 26 million of the securitized bonds were included in Long-term Debt Due Within One Year - Nonaffiliated, respectively, and $ 120 million and $ 147 million were included in Long-term Debt - Nonaffiliated, respectively, on the balance sheets. Appalachian Consumer Rate Relief Funding has securitized assets of $ 133 million and $ 160 million as of December 31, 2023 and 2022, respectively, which are presented separately on the face of the balance sheets. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding's securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Appalachian Consumer Rate Relief Funding's assets and liabilities on APCo's balance sheets.

 AEP Credit (Applies to AEP)

 AEP Credit is a wholly-owned subsidiary of Parent. AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements. AEP provides a minimum of 5 % equity and up to 35 % of AEP Credit's short-term borrowing needs in excess of third-party financings. Any third-party financing of AEP Credit only has recourse to the receivables securitized for such financing. Based on AEP's control of AEP Credit, management concluded that

 AEP is the primary beneficiary and is required to consolidate AEP Credit. See the tables below for the classification of AEP Credit's assets and liabilities on the balance sheets. See "Securitized Accounts Receivables - AEP Credit" section of Note 14.

 EIS (Applies to AEP)

 AEP's subsidiaries participate in one protected cell of EIS for seven lines of insurance. EIS has multiple protected cells. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP System is essentially this EIS cell's only participant, but allows certain third-parties access to this insurance. AEP's subsidiaries and any allowed third-parties share in the insurance coverage, premiums and risk of loss from claims. Based on AEP's control and the structure of the protected cell of EIS, management concluded that AEP is the primary beneficiary of the protected cell and is required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the years ended December 31, 2023, 2022 and 2021 was $ 34 million, $ 31 million and $ 30 million, respectively. See the tables below for the classification of the protected cell's assets and liabilities on the balance sheets. The amount reported as equity is the protected cell's policy holders' surplus.

 Transource Energy (Applies to AEP)

 Transource Energy was formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates. AEP has equity and voting ownership of 86.5 % with the other owner having 13.5 % interest. Management has concluded that Transource Energy is a VIE and that AEP is the primary beneficiary because AEP has the power to direct the most significant activities of the entity and AEP's equity interest could potentially be significant. Therefore, AEP is required to consolidate Transource Energy. Transource Energy's activities consist of the development, construction and operation of FERC-regulated transmission assets in Missouri, West Virginia, Pennsylvania, Maryland and Oklahoma. Transource Energy has a credit facility agreement where borrowings are loaned through intercompany lending agreements to its subsidiaries. The creditor to the agreement has no recourse to the general credit of AEP. Transource Energy's credit facility agreement contains certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5 %. See the tables below for the classification of Transource Energy's assets and liabilities on the balance sheets.

 Competitive Contracted Renewables (Applies to AEP)

 As of December 31, 2023, Apple Blossom, Black Oak, Santa Rita East and Dry Lake are no longer consolidated VIEs due to the sale of the Competitive Contracted Renewables Portfolio. See the table below for the classification of assets and liabilities on the balance sheets. As of December 31, 2022, nonaffiliated interests in Apple Blossom and Black Oak, Santa Rita East and Dry Lake were $ 94 million, $ 58 million and $ 34 million, respectively, presented in Noncontrolling Interests on the balance sheets. The results of operations for these interests for the years ended December 31, 2023, 2022 and 2021 were not material to the AEP statements of income.

 The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation.

 Consolidated VIEs

Sabine
 I&M
DCC Fuel
 AEP Texas Transition Funding
 AEP Texas Restoration Funding
 APCo
Appalachian
Consumer
Rate
Relief Funding
 AEP Credit
 Protected
Cell
of EIS
 Transource Energy

 Current Assets
 $
 4.2
 $
 81.9
 $
 25.5
 $
 27.5
 $
 13.3
 $
 1,208.8
 $
 205.3
 $
 36.9

 Net Property, Plant and Equipment
 —
 153.8
 —
 —
 —
 —
 —
 533.4

 Other Noncurrent Assets
 150.7
 81.7
 71.4
 (a)
 145.6
 (b)
 138.2
 (c)
 9.6
 —
 5.1

 $
 154.9
 $
 317.4
 $
 96.9
 $
 173.1
 $
 151.5
 $
 1,218.4
 $
 205.3
 $
 575.4

 Current Liabilities
 $
 19.9
 $
 81.7
 $
 75.5
 $
 36.8
 $
 29.9
 $
 1,155.0
 $
 49.2
 $
 45.3

 Noncurrent Liabilities
 134.8
 235.7
 17.0
 135.1
 119.7
 0.9
 91.7
 241.5

 0.2
 —
 4.4
 1.2
 1.9
 62.5
 64.4
 288.6

 Total Liabilities and Equity
 $
 154.9
 $
 317.4
 $
 96.9
 $
 173.1
 $
 151.5
 $
 1,218.4
 $
 205.3
 $
 575.4

 (a) Includes an intercompany item eliminated in consolidation of $ 8 million.
 (b) Includes an intercompany item eliminated in consolidation of $ 6 million.
 (c) Includes an intercompany item eliminated in consolidation of $ 2 million.

 American Electric Power Company, Inc. and Subsidiary Companies

 Variable Interest Entities

 Registrant Subsidiaries

Sabine
 I&M
DCC Fuel
 AEP Texas Transition Funding
 AEP Texas Restoration Funding
 APCo
Appalachian
Consumer
Rate
Relief Funding

 Current Assets
 $
 108.3
 $
 90.2
 $
 27.0
 $
 21.1
 $
 13.5

 Net Property, Plant and Equipment
 7.2
 179.1
 —
 —
 —

 Other Noncurrent Assets
 130.0
 94.0
 140.9
 (a)
 168.8
 (b)
 164.6
 (c)

 $
 245.5
 $
 363.3
 $
 167.9
 $
 189.9
 $
 178.1

 Current Liabilities
 $
 25.4
 $
 90.0
 $
 73.2
 $
 31.3
 $
 29.3

 Noncurrent Liabilities
 219.4
 273.3
 90.4
 157.4
 146.9

 0.7
 —
 4.3
 1.2
 1.9

 Total Liabilities and Equity
 $
 245.5
 $
 363.3
 $
 167.9
 $
 189.9
 $
 178.1

 (a) Includes an intercompany item eliminated in consolidation of $ 16 million.
 (b) Includes an intercompany item eliminated in consolidation of $ 7 million.
 (c) Includes an intercompany item eliminated in consolidation of $ 2 million.

 American Electric Power Company, Inc. and Subsidiary Companies

 Variable Interest Entities

 Other Consolidated VIEs

 AEP Credit
 Protected
Cell
of EIS
 Transource Energy
 Apple Blossom and Black Oak
 Santa Rita East
 Dry Lake

 Current Assets
 $
 1,181.0
 $
 194.5
 $
 23.5
 $
 8.3
 $
 21.3
 $
 4.0

 Net Property, Plant and Equipment
 —
 —
 482.3
 216.5
 421.6
 142.6

 Other Noncurrent Assets
 9.0
 0.3
 2.7
 13.6
 0.1
 0.3

 $
 1,190.0
 $
 194.8
 $
 508.5
 $
 238.4
 $
 443.0
 $
 146.9

 Current Liabilities
 $
 1,087.8
 $
 46.4
 $
 22.8
 $
 4.5
 $
 9.6
 $
 1.0

 Noncurrent Liabilities
 0.9
 79.1
 218.6
 5.4
 7.3
 0.7

 101.3
 69.3
 267.1
 228.5
 426.1
 145.2

 Total Liabilities and Equity
 $
 1,190.0
 $
 194.8
 $
 508.5
 $
 238.4
 $
 443.0
 $
 146.9

 Non-Consolidated Significant Variable Interests

 DHLC (Applies to AEP and SWEPCo)

 DHLC is a mining operator which previously sold 50 % of the lignite produced to SWEPCo and 50 % to CLECO. The operations of DHLC are governed by the lignite mining agreement among SWEPCo, CLECO and DHLC. SWEPCo and CLECO share the executive board seats and voting rights equally. In accordance with the lignite mining agreement, each entity is responsible for 50 % of DHLC's obligations, including debt. SWEPCo and CLECO equally approve DHLC's annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100 % of the management fee earned by DHLC. In April 2020, SWEPCo and CLECO jointly filed a notification letter to the LPSC providing notice of the cessation of lignite mining. SWEPCo's total billings from DHLC for the years ended December 31, 2023 and 2022 were not material, and for the year ended December 31, 2021 was $ 47 million. DHLC paid dividends of $ 1 million, $ 25 million, and $ 0 to SWEPCo for the years ended December 31, 2023, 2022 and 2021, respectively. SWEPCo does not have the power to control decision making that significantly impacts the economic performance of DHLC because such power is shared with CLECO. As a result, SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although it holds a significant variable interest in DHLC. SWEPCo's equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo's balance sheets.

 SWEPCo's investment in DHLC was:

 2023
 2022

 Capital Contribution from SWEPCo
 $
 7.6
 $
 7.6
 $
 7.6
 $
 7.6

 0.4
 0.4
 0.4
 0.4

 SWEPCo's Share of Obligations
 —
 19.2
 —
 36.8

 Total Investment in DHLC
 $
 8.0
 $
 27.2
 $
 8.0
 $
 44.8

 OVEC (Applies to AEP and OPCo)

 AEP and several nonaffiliated utility companies jointly own OVEC. As of December 31, 2023, AEP's ownership in OVEC was 43.47 %. Parent owns 39.17 % and OPCo owns 4.3 %. APCo, I&M and OPCo are members to an intercompany power agreement. The Registrants' power participation ratios are 15.69 % for APCo, 7.85 % for I&M and 19.93 % for OPCo. Participants of this agreement are entitled to receive and are obligated to pay for all OVEC generating capacity, approximately 2,400 MWs, in proportion to their respective power participation ratios. The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs, including outstanding indebtedness, and provide a return on capital. The intercompany power agreement ends in June 2040.

 AEP and other nonaffiliated owners authorized environmental investments related to their ownership interests. OVEC financed capital expenditures in connection with the engineering and construction of FGD projects and the associated waste disposal landfills at its two generation plants. These environmental projects were funded through debt issuances. As of December 31, 2023 and 2022, OVEC's outstanding indebtedness was approximately $ 1.1 billion and $ 1.1 billion, respectively. Although they are not an obligor or guarantor, the Registrants' are responsible for their respective ratio of OVEC's outstanding debt through the intercompany power agreement. Principal and interest payments related to OVEC's outstanding indebtedness are disclosed in accordance with the accounting guidance for "Commitments." See the "Commitments" section of Note 6 for additional information.

 AEP is not required to consolidate OVEC as it is not the primary beneficiary, although AEP and its subsidiary each hold a significant variable interest in OVEC. Power to control decision making that significantly impacts the economic performance of OVEC is shared amongst the owners through their representation on the Board of Directors of OVEC and the representation of the sponsoring companies on the Operating Committee under the intercompany power agreement.

 AEP's investment in OVEC was:

 2023
 2022

 Maximum Exposure

 Capital Contribution from AEP
 $
 4.4
 $
 4.4
 $
 4.4
 $
 4.4

 AEP's Share of OVEC Debt (a)
 —
 465.3
 —
 478.2

 Total Investment in OVEC
 $
 4.4
 $
 469.7
 $
 4.4
 $
 482.6

 (a) Based on the Registrants' power participation ratios, APCo, I&M and OPCo's share of OVEC debt was $ 168 million, $ 84 million and $ 213 million as of December 31, 2023, respectively and $ 173 million, $ 86 million and $ 219 million as of December 31, 2022, respectively.

 Power purchased by the Registrant Subsidiaries from OVEC is included in Purchased Electricity, Fuel and Other Consumables Used for Electric Generation and Purchased Electricity for Resale on the statements of income and is shown in the table below:

 2023
 2022
 2021

 APCo
 $
 121.8
 $
 119.3
 $
 104.3

 I&M
 60.9
 59.7
 52.2

 OPCo
 154.7
 151.8
 133.0

 AEPSC (Applies to Registrant Subsidiaries)

 AEPSC provides certain managerial and professional services to AEP's subsidiaries. Parent is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct-charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC's cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC's cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP.

 Total AEPSC billings to the Registrant Subsidiaries were as follows:

 2023
 2022
 2021

 $
 228.5
 $
 236.8
 $
 206.9

 269.9
 286.6
 267.1

 APCo
 324.9
 347.5
 313.3

 I&M
 178.4
 192.4
 200.9

 OPCo
 269.5
 272.5
 234.9

 PSO
 138.6
 142.3
 123.7

 185.1
 192.5
 168.6

 The carrying amount and classification of variable interest in AEPSC's accounts payable were as follows:

 2023
 2022

 $
 15.1
 $
 15.1
 $
 27.8
 $
 27.8

 17.9
 17.9
 31.6
 31.6

 APCo
 21.1
 21.1
 41.5
 41.5

 I&M
 14.3
 14.3
 27.7
 27.7

 OPCo
 19.0
 19.0
 31.1
 31.1

 PSO
 10.6
 10.6
 17.7
 17.7

 12.7
 12.7
 23.8
 23.8

 AEGCo (Applies to I&M)

 AEGCo, a wholly-owned subsidiary of Parent, is consolidated by AEP. AEGCo owns a 50 % ownership interest in Rockport Plant, Units 1 and 2. AEGCo sells its portion of the output from the Rockport Plant to I&M. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligations of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M, this financing would be provided by AEP. Total billings to I&M from AEGCo for the years ended December 31, 2023, 2022 and 2021 were $ 181 million, $ 242 million and $ 218 million, respectively. The carrying amounts of I&M's liabilities associated with AEGCo as of December 31, 2023 and 2022 were $ 15 million and $ 17 million, respectively. Management estimates the maximum exposure of loss to be equal to the amount of such liability.

 Significant Equity Method Investment in Unconsolidated Entities (Applies to AEP)

 For a discussion of the equity method of accounting, see the "Equity Method Investments in Unconsolidated Entities" section of Note 1.

 AEP Wind Holdings, LLC

 As of December 31, 2023, AEP no longer owns interests in four joint ventures due to the sale of the Competitive Contracted Renewables Portfolio. Previously held by AEP Wind Holdings, LLC, the interests were accounted for under the equity method. As of December 31, 2022, AEP's carrying value of the investment in the joint ventures was $ 247 million and the difference between AEP's carrying value and the amount of underlying equity in net assets was $ 62 million. The investment included amounts recognized in AOCI related to interest rate cash flow hedges. AEP's equity losses associated with the joint venture wind farms were $ 278 thousand, $ 194 million and $ 12 million for the years ended December 31, 2023, 2022 and 2021, respectively. The PTCs attributable to the joint ventures for the years ended December 31, 2023, 2022 and 2021 were not material, which were recorded in Income Tax Expense (Benefit) on the statements of income. See the "Disposition of the Competitive Contracted Renewables Portfolio" and "Impairments" sections of Note 7 for additional information.

 ETT

 ETT designs, acquires, constructs, owns and operates certain transmission facilities in ERCOT. BHE, a nonaffiliated entity, holds a 50 % membership interest in ETT and AEP Transmission Holdco holds a 50 % membership interest in ETT. As a result, AEP, through its wholly-owned subsidiary, holds a 50 % membership interest in ETT. As of December 31, 2023 and 2022, AEP's investment in ETT was $ 811 million and $ 762 million, respectively. AEP's equity earnings associated with ETT were $ 74 million, $ 74 million and $ 66 million for the years ended December 31, 2023, 2022 and 2021, respectively.

 18. PROPERTY, PLANT AND EQUIPMENT

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

 Property, Plant and Equipment is shown functionally on the face of the balance sheets. The following tables include the total plant balances as of December 31, 2023 and 2022:

 AEP
 APCo
 I&M
 OPCo
 PSO

 Regulated Property, Plant and Equipment

 $
 23,862.7
 (a)
 $
 —
 $
 —
 $
 7,041.3
 $
 5,588.7
 $
 —
 $
 2,695.5
 $
 4,790.7
 (a)

 35,903.6
 6,812.6
 13,723.9
 4,711.8
 1,906.4
 3,395.1
 1,228.3
 2,660.6

 28,989.9
 5,798.8
 —
 5,176.6
 3,254.0
 6,839.4
 3,450.8
 2,824.1

 Other
 5,986.1
 1,142.9
 501.2
 943.7
 856.8
 1,114.4
 502.7
 544.1

 CWIP
 5,480.6
 (a)
 904.6
 1,563.7
 709.2
 294.1
 654.0
 313.7
 555.8
 (a)

 Less: Accumulated Depreciation

 24,093.8
 1,886.7
 1,291.4
 5,684.0
 4,353.7
 2,712.7
 2,083.6
 2,840.8

 Total Regulated Property, Plant and Equipment - Net

 76,129.1
 12,772.2
 14,497.4
 12,898.6
 7,546.3
 9,290.2
 6,107.4
 8,534.5

 Nonregulated Property, Plant and Equipment - Net

 564.3
 1.8
 0.3
 32.9
 82.7
 9.7
 4.9
 23.9

 Total Property, Plant and Equipment - Net

 $
 76,693.4
 $
 12,774.0
 $
 14,497.7
 $
 12,931.5
 $
 7,629.0
 $
 9,299.9
 $
 6,112.3
 $
 8,558.4

 AEP
 APCo
 I&M
 OPCo
 PSO

 Regulated Property, Plant and Equipment

 $
 23,759.7
 (a)
 $
 —
 $
 —
 $
 6,776.8
 $
 5,534.6
 $
 —
 $
 2,394.8
 $
 5,476.2
 (a)

 33,221.7
 6,301.5
 12,335.4
 4,482.8
 1,842.2
 3,198.6
 1,164.4
 2,479.8

 27,138.8
 5,312.8
 —
 4,933.0
 3,024.7
 6,450.3
 3,216.4
 2,659.6

 Other
 5,528.9
 1,020.4
 476.6
 849.2
 796.1
 1,040.6
 466.0
 582.6

 CWIP
 4,776.4
 (a)
 805.2
 1,554.7
 705.3
 253.0
 474.3
 219.3
 369.5
 (a)

 Less: Accumulated Depreciation

 23,118.0
 1,759.5
 1,027.1
 5,397.3
 4,117.8
 2,564.3
 1,839.4
 3,314.8

 Total Regulated Property, Plant and Equipment - Net

 71,307.5
 11,680.4
 13,339.6
 12,349.8
 7,332.8
 8,599.5
 5,621.5
 8,252.9

 Nonregulated Property, Plant and Equipment - Net

 2,031.6
 1.2
 0.3
 29.4
 78.7
 9.8
 5.0
 9.3

 Total Property, Plant and Equipment - Net

 $
 73,339.1
 $
 11,681.6
 $
 13,339.9
 $
 12,379.2
 $
 7,411.5
 $
 8,609.3
 $
 5,626.5
 $
 8,262.2

 (a) AEP and SWEPCo's regulated generation and regulated CWIP include amounts related to SWEPCo's Arkansas jurisdictional share of the Turk Plant.

 Depreciation, Depletion and Amortization

 The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. The following tables provide total regulated annual composite depreciation rates and depreciable lives for the Registrants:

 AEP

 2023
 2022
 2021

 2.7 %
 -
 4.7 %
 -
 2.7 %
 -
 7.6 %
 -
 2.7 %
 -
 7.8 %
 -

 2.0 %
 -
 2.7 %
 -
 2.0 %
 -
 2.7 %
 -
 2.0 %
 -
 2.6 %
 -

 2.9 %
 -
 3.6 %
 -
 2.7 %
 -
 3.6 %
 -
 2.8 %
 -
 3.6 %
 -

 Other
 3.8 %
 -
 9.1 %
 -
 3.1 %
 -
 14.4 %
 -
 3.0 %
 -
 12.5 %
 -

 2023
 2022
 2021

 2.2 %
 -
 2.2 %
 -
 2.2 %
 -

 2.9 %
 -
 2.9 %
 -
 2.9 %
 -

 Other
 6.0 %
 -
 6.2 %
 -
 5.8 %
 -

 2023
 2022
 2021

 2.6 %
 -
 2.6 %
 -
 2.5 %
 -

 Other
 7.0 %
 -
 6.6 %
 -
 6.7 %
 -

 APCo

 2023
 2022
 2021

 3.3 %
 -
 3.6 %
 -
 3.6 %
 -

 2.3 %
 -
 2.2 %
 -
 2.1 %
 -

 3.6 %
 -
 3.6 %
 -
 3.5 %
 -

 Other
 7.4 %
 -
 7.3 %
 -
 8.5 %
 -

 I&M

 2023
 2022
 2021

 4.7 %
 -
 4.9 %
 -
 4.7 %
 -

 2.5 %
 -
 2.5 %
 -
 2.4 %
 -

 2.9 %
 -
 3.1 %
 -
 3.4 %
 -

 Other
 9.1 %
 -
 10.1 %
 -
 9.0 %
 -

 OPCo

 2023
 2022
 2021

 2.3 %
 -
 2.3 %
 -
 2.3 %
 -

 3.1 %
 -
 2.7 %
 -
 2.9 %
 -

 Other
 6.4 %
 -
 6.1 %
 -
 6.1 %
 -

 PSO

 2023
 2022
 2021

 3.0 %
 -
 3.1 %
 -
 2.8 %
 -

 2.6 %
 -
 2.5 %
 -
 2.4 %
 -

 2.9 %
 -
 2.9 %
 -
 2.9 %
 -

 Other
 6.8 %
 -
 6.8 %
 -
 6.1 %
 -

 2023
 2022
 2021

 2.9 %
 -
 2.7 %
 -
 2.7 %
 -

 2.2 %
 -
 2.3 %
 -
 2.4 %
 -

 2.9 %
 -
 2.9 %
 -
 2.8 %
 -

 Other
 8.5 %
 -
 9.0 %
 -
 8.6 %
 -

 The following table includes the nonregulated annual composite depreciation rate ranges and nonregulated depreciable life ranges for AEP. The Registrants' depreciation rate ranges and depreciable life ranges are not meaningful for nonregulated property for 2023, 2022 and 2021.

 2023
 2022
 2021

 4.8 %
 -
 6.7 %
 -
 3.8 %
 -
 8.7 %
 -
 3.8 %
 -
 10.4 %
 -

 2.5 %
 2.8 %
 -
 2.6 %
 -

 NA
 NA
 NA
 NA
 NA
 NA

 Other
 10.6 %
 -
 (a)
 25.2 %
 -
 (a)
 16.5 %
 -
 (a)

 (a) In 2020, management announced plans to retire the Pirkey Plant in 2023 and the related depreciable lives have been adjusted accordingly. Pirkey Plant was retired in March 2023. See "Coal-Fired Generation Plants" of Note 5 for additional information.

 For regulated operations, the composite depreciation rate generally includes a component for non-ARO removal costs, which is credited to Accumulated Depreciation and Amortization on the balance sheets. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred.

 Asset Retirement Obligations (Applies to all Registrants except AEPTCo)

 The Registrants recorded the following revisions to ARO estimates as of December 31, 2023 and 2022:

 • As of December 31, 2023 and 2022, I&M's ARO liability for nuclear decommissioning of the Cook Plant was $ 2.11 billion and $ 2 billion, respectively. These liabilities are reflected in Asset Retirement Obligations on I&M's balance sheets. As of December 31, 2023 and 2022, the fair value of I&M's assets that are legally restricted for purposes of settling decommissioning liabilities totaled $ 3.51 billion and $ 3.01 billion, respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M's balance sheets.
 • In September 2022, APCo recorded a $ 14 million revision due to an increase in estimated ash pond closure costs at the Amos Plant.
 • In March 2022, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Traverse during its development and construction. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Traverse assets in proportion to their undivided ownership interests. Traverse was placed in-service in March 2022. As a result, PSO and SWEPCo incurred additional ARO liabilities of $ 13 million and $ 15 million, respectively. See the "North Central Wind Energy Facilities" section of Note 7 for additional information.
 • In March 2022, SWEPCo recorded a $ 13 million revision due to an increase in estimated ash pond closure costs at the Pirkey Plant and the Welsh Plant. In June 2022, SWEPCo recorded a $ 16 million revision due to an increase in estimated reclamation costs at Sabine. In September 2022, SWEPCo recorded a $ 14 million revision due to an

 increase in estimated landfill closure costs at Pirkey Plant. In November 2022, SWEPCo recorded an additional $ 7 million revision related to an increase in estimated reclamation costs at Sabine.
 • In August 2023, AEP completed the sale of its competitive contracted renewables portfolio to a nonaffiliated party and settled ARO liabilities of $ 31 million. See "Disposition of the Competitive Contracted Renewables Portfolio" section of Note 7 for additional information.
 • In December 2023, SWEPCo recorded a $ 32 million revision related to an increase in estimated reclamation costs at Sabine. Additionally in 2023, SWEPCo settled $ 50 million of costs related to closure/reclamation work performed due to the recent retirements of the Pirkey Plant and Dolet Hills Power Station. See "Coal-Fired Generation Plants" section of Note 5 for additional information.
 • In 2023, APCo recorded revisions of $ 27 million primarily due to an increase in estimated asbestos costs at several plants.

 The following is a reconciliation of the 2023 and 2022 aggregate carrying amounts of ARO by Registrant:

 ARO as of December 31, 2022
 Accretion
Expense
Incurred
Settled
 Revisions in
Cash Flow
Estimates (a)
 ARO as of December 31, 2023

 AEP(b)(c)(d)(e)(f)(g)
 $
 2,943.6
 $
 116.3
 $
 38.9
 $
 ( 130.6)
 $
 63.0
 $
 3,031.2

 AEP Texas (b)(e)
 4.5
 0.2
 —
 0.1
 4.5

 APCo (b)(e)
 427.7
 16.8
 16.1
 ( 23.1)
 26.5
 464.0

 I&M (b)(c)(e)
 2,028.1
 74.8
 4.8
 2.0
 2,106.0

 OPCo (e)
 5.0
 0.2
 —
 ( 3.1)
 —
 2.1

 PSO (b)(e)(g)
 75.7
 4.7
 5.8
 84.2

 SWEPCo (b)(d)(e)(g)
 280.9
 13.7
 7.5
 ( 55.0)
 34.5
 281.6

 ARO as of December 31, 2021
 Accretion
Expense
Incurred
Settled
 Revisions in
Cash Flow
Estimates (a)
 ARO as of December 31, 2022

 AEP (b)(c)(d)(e)(f)(g)
 $
 2,741.7
 $
 111.2
 $
 37.4
 $
 ( 47.0)
 $
 100.3
 $
 2,943.6

 AEP Texas (b)(e)
 4.4
 0.3
 —
 —
 4.5

 APCo (b)(e)
 404.6
 15.8
 3.0
 ( 12.7)
 17.0
 427.7

 I&M (b)(c)(e)
 1,946.3
 71.5
 3.2
 7.7
 2,028.1

 OPCo (e)
 1.9
 0.2
 3.0
 —
 5.0

 PSO (b)(e)(g)
 57.6
 4.1
 12.8
 1.9
 75.7

 SWEPCo (b)(d)(e)(g)
 222.7
 11.9
 15.4
 ( 25.8)
 56.7
 280.9

 (a) Unless discussed above, primarily related to ash ponds, landfills and mine reclamation, generally due to changes in estimated closure area, volumes and/or unit costs.
 (b) Includes ARO related to ash disposal facilities.
 (c) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $ 2.11 billion and $ 2 billion as of December 31, 2023 and 2022, respectively.
 (d) Includes ARO related to Sabine and DHLC.
 (e) Includes ARO related to asbestos removal.
 (f) Includes ARO related to solar farms.
 (g) Includes ARO related to wind farms.

 Allowance for Funds Used During Construction and Interest Capitalization

 The Registrants' amounts of Allowance for Equity Funds Used During Construction are summarized in the following table:

 2023
 2022
 2021

 AEP
 $
 174.9
 $
 133.7
 $
 139.7

 28.4
 19.7
 21.5

 83.2
 70.7
 67.2

 APCo
 11.9
 11.7
 15.6

 I&M
 10.9
 9.8
 12.8

 OPCo
 17.1
 13.9
 10.8

 PSO
 8.4
 1.5
 2.4

 11.5
 4.9
 7.0

 The Registrants' amounts of allowance for borrowed funds used during construction, including capitalized interest, are summarized in the following table:

 2023
 2022
 2021

 AEP
 $
 117.3
 $
 63.0
 $
 53.8

 23.4
 11.5
 10.5

 31.4
 22.4
 21.0

 APCo
 14.1
 6.5
 7.5

 I&M
 7.7
 5.7
 5.1

 OPCo
 14.0
 6.7
 4.7

 PSO
 5.2
 2.7
 0.7

 9.8
 4.3
 3.0

 Jointly-owned Electric Facilities (Applies to AEP, I&M, PSO and SWEPCo)

 The Registrants have electric facilities that are jointly-owned with affiliated and nonaffiliated companies. Using its own financing, each participating company is obligated to pay its share of the costs of these jointly-owned facilities in the same proportion as its ownership interest. Each Registrant's proportionate share of the operating costs associated with these facilities is included in its statements of income and the investments and accumulated depreciation are reflected in its balance sheets under Property, Plant and Equipment as follows:

 Registrant's Share as of December 31, 2023

 Fuel
Type
 Percent of
Ownership
 Utility Plant
in Service
 Construction
Work in
Progress
Depreciation

 AEP

 Flint Creek Generating Station, Unit 1 (a)
 Coal
 50.0
 %
 $
 402.8
 $
 1.6
 $
 167.5

 Pirkey Plant, Unit 1 (a)(f)
 Lignite
 85.9
 %
 —
 —
 —

 Turk Generating Plant (a)(g)
 Coal
 73.3
 %
 1,504.0
 10.1
 323.3

 Total

 $
 1,906.8
 $
 11.7
 $
 490.8

 I&M

 Rockport Generating Plant (b)(c)
 Coal
 50.0
 %
 $
 1,341.4
 $
 7.9
 $
 1,018.9

 PSO

 North Central Wind Energy Facilities (d)(e)
 Wind
 45.5
 %
 $
 906.3
 $
 2.4
 $
 54.1

 Flint Creek Generating Station, Unit 1 (a)
 Coal
 50.0
 %
 $
 402.8
 $
 1.6
 $
 167.5

 Pirkey Plant, Unit 1 (a)(f)
 Lignite
 85.9
 %
 —
 —
 —

 Turk Generating Plant (a)(g)
 Coal
 73.3
 %
 1,504.0
 10.1
 323.3

 North Central Wind Energy Facilities (d)(e)
 Wind
 54.5
 %
 1,086.3
 2.9
 67.9

 Total
 $
 2,993.1
 $
 14.6
 $
 558.7

 Registrant's Share as of December 31, 2022

 Fuel
Type
 Percent of
Ownership
 Utility Plant
in Service
 Construction
Work in
Progress
Depreciation

 AEP

 Flint Creek Generating Station, Unit 1 (a)
 Coal
 50.0
 %
 $
 382.9
 $
 16.4
 $
 149.4

 Pirkey Plant, Unit 1 (a)
 Lignite
 85.9
 %
 632.0
 —
 632.0

 Turk Generating Plant (a)
 Coal
 73.3
 %
 1,611.1
 5.1
 314.7

 Total

 $
 2,626.0
 $
 21.5
 $
 1,096.1

 I&M

 Rockport Generating Plant (b)(c)
 Coal
 50.0
 %
 $
 1,357.4
 $
 9.2
 $
 905.1

 PSO

 North Central Wind Energy Facilities (d)(e)
 Wind
 45.5
 %
 $
 889.3
 $
 9.1
 $
 28.1

 Flint Creek Generating Station, Unit 1 (a)
 Coal
 50.0
 %
 $
 382.9
 $
 16.4
 $
 149.4

 Pirkey Plant, Unit 1 (a)
 Lignite
 85.9
 %
 632.0
 —
 632.0

 Turk Generating Plant (a)
 Coal
 73.3
 %
 1,611.1
 5.1
 314.7

 North Central Wind Energy Facilities (d)(e)
 Wind
 54.5
 %
 1,066.8
 10.1
 35.2

 Total

 $
 3,692.8
 $
 31.6
 $
 1,131.3

 (a) Operated by SWEPCo.
 (b) Operated by I&M.
 (c) AEGCo owns 50 %.
 (d) Operated by PSO.
 (e) PSO and SWEPCo own undivided interests of 45.5 % and 54.5 % of the NCWF, respectively.
 (f) Pirkey Plant was retired in March 2023. See "Coal-Fired Generation Plants" of Note 5 for additional information.
 (g) Includes impact of regulatory disallowance of AFUDC. See "2012 Texas Base Rate Case" section of Note 4 for additional information.

 19. REVENUE FROM CONTRACTS WITH CUSTOMERS

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

 Disaggregated Revenues from Contracts with Customers
 The table below represents AEP's reportable segment revenues from contracts with customers, net of respective provisions for refund, by type of revenue:

 $
 4,479.3
 $
 2,609.1
 $
 —
 $
 —
 $
 —
 $
 —
 $
 7,088.4

 2,678.8
 1,497.2
 —
 —
 —
 —
 4,176.0

 Industrial Revenues (a)
 2,748.2
 642.1
 —
 —
 —
 3,389.4

 242.7
 50.7
 —
 —
 —
 —
 293.4

 10,149.0
 4,799.1
 —
 —
 —
 14,947.2

 Wholesale and Competitive Retail Revenues:

 Generation Revenues
 662.5
 —
 —
 111.3
 —
 —
 773.8

 Transmission Revenues (b)
 444.0
 701.6
 1,748.9
 —
 —
 ( 1,418.3)
 1,476.2

 Renewable Generation Revenues (a)
 —
 —
 —
 80.6
 —
 ( 6.7)
 73.9

 Retail, Trading and Marketing Revenues (c)
 —
 —
 —
 1,836.2
 0.6
 ( 82.2)
 1,754.6

 Total Wholesale and Competitive Retail Revenues

 1,106.5
 701.6
 1,748.9
 2,028.1
 0.6
 ( 1,507.2)
 4,078.5

 Other Revenues from Contracts with Customers (d)
 204.4
 208.1
 16.8
 8.6
 151.5
 ( 160.3)
 429.1

 11,459.9
 5,708.8
 1,765.7
 2,036.7
 152.1
 ( 1,668.4)
 19,454.8

 Alternative Revenue Programs (e)
 ( 35.0)
 ( 19.5)
 ( 37.1)
 —
 —
 ( 25.5)
 ( 117.1)

 Other Revenues (a) (f)
 24.6
 24.0
 ( 404.5)
 15.9
 ( 15.3)
 ( 355.4)

 4.5
 ( 37.2)
 ( 404.5)
 15.9
 ( 40.8)
 ( 472.5)

 $
 11,449.5
 $
 5,713.3
 $
 1,728.5
 $
 1,632.2
 $
 168.0
 $
 ( 1,709.2)
 $
 18,982.3

 (a) Amounts include affiliated and nonaffiliated revenues.
 (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $ 1.5 billion and Vertically Integrated Utilities was $ 205 million. The remaining affiliated amounts were immaterial.
 (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $ 82 million. The remaining affiliated amounts were immaterial.
 (d) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Corporate and Other was $ 100 million. The remaining affiliated amounts were immaterial.
 (e) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.
 (f) Generation & Marketing includes economic hedge activity.

 $
 4,498.6
 $
 2,497.3
 $
 —
 $
 —
 $
 —
 $
 —
 $
 6,995.9

 2,576.5
 1,365.2
 —
 —
 —
 —
 3,941.7

 Industrial Revenues (a)
 2,543.8
 711.3
 —
 —
 —
 3,254.2

 212.2
 49.1
 —
 —
 —
 —
 261.3

 9,831.1
 4,622.9
 —
 —
 —
 14,453.1

 Wholesale and Competitive Retail Revenues:

 Generation Revenues
 958.3
 —
 —
 271.2
 —
 —
 1,229.5

 Transmission Revenues (b)
 442.8
 650.0
 1,700.6
 —
 —
 ( 1,413.2)
 1,380.2

 Renewable Generation Revenues (a)
 —
 —
 —
 129.1
 —
 ( 8.0)
 121.1

 Retail, Trading and Marketing Revenues (a)
 —
 —
 —
 1,713.2
 6.9
 ( 10.1)
 1,710.0

 Total Wholesale and Competitive Retail Revenues

 1,401.1
 650.0
 1,700.6
 2,113.5
 6.9
 ( 1,431.3)
 4,440.8

 Other Revenues from Contracts with Customers (c)
 241.1
 247.3
 8.2
 12.1
 93.9
 ( 104.8)
 497.8

 11,473.3
 5,520.2
 1,708.8
 2,125.6
 100.8
 ( 1,537.0)
 19,391.7

 Alternative Revenue Programs (d)
 3.8
 ( 26.8)
 ( 31.8)
 —
 —
 ( 57.7)
 ( 112.5)

 Other Revenues (a) (e)
 0.4
 18.6
 —
 341.3
 9.1
 360.3

 4.2
 ( 8.2)
 ( 31.8)
 341.3
 9.1
 ( 66.8)
 247.8

 $
 11,477.5
 $
 5,512.0
 $
 1,677.0
 $
 2,466.9
 $
 109.9
 $
 ( 1,603.8)
 $
 19,639.5

 (a) Amounts include affiliated and nonaffiliated revenues.
 (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $ 1.3 billion. The remaining affiliated amounts were immaterial.
 (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Corporate and Other was $ 59 million. The remaining affiliated amounts were immaterial.
 (d) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.
 (e) Generation & Marketing includes economic hedge activity.

 $
 3,952.6
 $
 2,138.2
 $
 —
 $
 —
 $
 —
 $
 —
 $
 6,090.8

 2,208.5
 1,081.2
 —
 —
 —
 —
 3,289.7

 Industrial Revenues
 2,168.2
 395.2
 —
 —
 —
 2,562.6

 170.6
 43.9
 —
 —
 —
 —
 214.5

 8,499.9
 3,658.5
 —
 —
 —
 12,157.6

 Wholesale and Competitive Retail Revenues:

 Generation Revenues
 942.6
 —
 —
 137.9
 —
 —
 1,080.5

 Transmission Revenues (a)
 355.5
 572.4
 1,456.4
 —
 —
 ( 1,206.0)
 1,178.3

 Renewable Generation Revenues (b)
 —
 —
 —
 86.9
 —
 83.3

 Retail, Trading and Marketing Revenues (c)
 —
 —
 —
 1,722.6
 1.4
 ( 51.6)
 1,672.4

 Total Wholesale and Competitive Retail Revenues

 1,298.1
 572.4
 1,456.4
 1,947.4
 1.4
 ( 1,261.2)
 4,014.5

 Other Revenues from Contracts with Customers (b)
 187.5
 194.2
 17.1
 7.2
 60.1
 ( 115.2)
 350.9

 9,985.5
 4,425.1
 1,473.5
 1,954.6
 61.5
 ( 1,377.2)
 16,523.0

 Alternative Revenue Programs (d)
 13.5
 48.8
 52.7
 —
 —
 ( 73.6)
 41.4

 Other Revenues (b) (e)
 19.0
 —
 209.1
 10.7
 ( 10.7)
 227.6

 13.0
 67.8
 52.7
 209.1
 10.7
 ( 84.3)
 269.0

 $
 9,998.5
 $
 4,492.9
 $
 1,526.2
 $
 2,163.7
 $
 72.2
 $
 ( 1,461.5)
 $
 16,792.0

 (a) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $ 1.1 billion. The remaining affiliated amounts were immaterial.
 (b) Amounts include affiliated and nonaffiliated revenues.
 (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $ 52 million. The remaining affiliated amounts were immaterial.
 (d) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.
 (e) Generation & Marketing includes economic hedge activity.

 The table below represents revenues from contracts with customers, net of respective provisions for refund, by type of revenue for the Registrant Subsidiaries:

 APCo
 I&M
 OPCo
 PSO

 $
 655.5
 $
 —
 $
 1,612.9
 $
 841.9
 $
 1,953.7
 $
 831.2
 $
 799.5

 415.2
 —
 699.6
 575.2
 1,082.0
 538.8
 609.4

 Industrial Revenues (a)
 145.0
 —
 778.4
 614.2
 497.1
 423.1
 415.9

 35.5
 —
 106.3
 5.0
 15.1
 112.8
 10.1

 1,251.2
 —
 3,197.2
 2,036.3
 3,547.9
 1,905.9
 1,834.9

 Wholesale Revenues:

 Generation Revenues (b)
 —
 —
 288.2
 327.1
 —
 11.7
 176.9

 Transmission Revenues (c)
 619.0
 1,703.9
 181.0
 38.6
 82.6
 37.5
 150.8

 Total Wholesale Revenues
 619.0
 1,703.9
 469.2
 365.7
 82.6
 49.2
 327.7

 Other Revenues from Contracts with Customers (d)
 35.9
 16.7
 74.2
 120.3
 172.3
 21.5
 29.5

 1,906.1
 1,720.6
 3,740.6
 2,522.3
 3,802.8
 1,976.6
 2,192.1

 Alternative Revenue Programs (e)
 ( 48.6)
 ( 20.1)
 ( 15.3)
 0.5
 ( 9.4)

 Other Revenues (a)
 —
 —
 0.2
 24.5
 23.9
 0.1

 ( 48.6)
 ( 19.9)
 13.6
 8.6
 0.4

 $
 1,901.9
 $
 1,672.0
 $
 3,720.7
 $
 2,535.9
 $
 3,811.4
 $
 1,977.0
 $
 2,182.8

 (a) Amounts include affiliated and nonaffiliated revenues.
 (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $ 159 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
 (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $ 1.4 billion, APCo was $ 93 million and SWEPCo was $ 73 million. The remaining affiliated amounts were immaterial.
 (d) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $ 68 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
 (e) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.

 APCo
 I&M
 OPCo
 PSO

 $
 667.2
 $
 —
 $
 1,558.7
 $
 852.4
 $
 1,830.2
 $
 816.3
 $
 820.7

 417.5
 —
 643.4
 550.2
 947.7
 489.2
 612.3

 Industrial Revenues (a)
 139.6
 —
 664.0
 602.9
 571.7
 372.5
 393.5

 35.3
 —
 87.1
 5.0
 13.9
 102.9
 10.1

 1,259.6
 —
 2,953.2
 2,010.5
 3,363.5
 1,780.9
 1,836.6

 Wholesale Revenues:

 Generation Revenues (b)
 —
 —
 299.9
 490.0
 —
 26.5
 273.2

 Transmission Revenues (c)
 563.8
 1,643.5
 167.0
 36.8
 86.2
 39.2
 148.7

 Total Wholesale Revenues
 563.8
 1,643.5
 466.9
 526.8
 86.2
 65.7
 421.9

 Other Revenues from Contracts with Customers (d)
 24.6
 8.2
 100.6
 122.4
 222.4
 29.1
 24.7

 1,848.0
 1,651.7
 3,520.7
 2,659.7
 3,672.1
 1,875.7
 2,283.2

 Alternative Revenue Programs (e)
 ( 27.2)
 10.0
 ( 25.6)
 1.2

 Other Revenues (a)
 —
 —
 0.5
 18.6
 —
 —

 ( 27.2)
 9.9
 1.2

 $
 1,846.8
 $
 1,624.5
 $
 3,519.9
 $
 2,669.6
 $
 3,665.1
 $
 1,874.7
 $
 2,284.4

 (a) Amounts include affiliated and nonaffiliated revenues.
 (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $ 170 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
 (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $ 1.3 billion, APCo was $ 78 million and SWEPCo was $ 51 million. The remaining affiliated amounts were immaterial.
 (d) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $ 62 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
 (e) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.

 APCo
 I&M
 OPCo
 PSO

 $
 550.3
 $
 —
 $
 1,379.6
 $
 805.4
 $
 1,587.9
 $
 651.9
 $
 709.5

 358.5
 —
 556.3
 507.2
 722.7
 378.9
 529.3

 Industrial Revenues
 108.9
 —
 584.3
 557.0
 286.3
 274.1
 344.4

 31.3
 —
 70.8
 5.2
 12.6
 77.7
 10.0

 1,049.0
 —
 2,591.0
 1,874.8
 2,609.5
 1,382.6
 1,593.2

 Wholesale Revenues:

 Generation Revenues (a)
 —
 —
 302.7
 318.1
 —
 22.9
 386.6

 Transmission Revenues (b)
 497.5
 1,393.9
 128.8
 33.7
 74.9
 37.5
 122.7

 Total Wholesale Revenues
 497.5
 1,393.9
 431.5
 351.8
 74.9
 60.4
 509.3

 Other Revenues from Contracts with Customers (c)
 41.2
 17.0
 70.4
 104.1
 153.1
 31.3
 23.5

 1,587.7
 1,410.9
 3,092.9
 2,330.7
 2,837.5
 1,474.3
 2,126.0

 Alternative Revenue Programs (d)
 6.1
 58.4
 12.3
 42.6
 0.1
 5.8

 Other Revenues (e)
 —
 —
 —
 —
 19.0
 —
 —

 6.1
 58.4
 12.3
 61.6
 0.1
 5.8

 $
 1,593.8
 $
 1,469.3
 $
 3,105.2
 $
 2,326.7
 $
 2,899.1
 $
 1,474.4
 $
 2,131.8

 (a) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $ 129 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
 (b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $ 1.1 billion. The remaining affiliated amounts were immaterial.
 (c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $ 60 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
 (d) Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.
 (e) Amounts include affiliated and nonaffiliated revenues.

 Performance Obligations

 AEP has performance obligations as part of its normal course of business. A performance obligation is a promise to transfer a distinct good or service, or a series of distinct goods or services that are substantially the same and have the same pattern of transfer to a customer. The invoice practical expedient within the accounting guidance for "Revenue from Contracts with Customers" allows for the recognition of revenue from performance obligations in the amount of consideration to which there is a right to invoice the customer and when the amount for which there is a right to invoice corresponds directly to the value transferred to the customer.

 The purpose of the invoice practical expedient is to depict an entity's measure of progress toward completion of the performance obligation within a contract and can only be applied to performance obligations that are satisfied over time and when the invoice is representative of services provided to date. AEP subsidiaries elected to apply the invoice practical expedient to recognize revenue for performance obligations satisfied over time as the invoices from the respective revenue streams are representative of services or goods provided to date to the customer. Performance obligations for AEP's subsidiaries are summarized as follows:

 AEP's subsidiaries within the Vertically Integrated Utilities and Transmission and Distribution Utilities segments have performance obligations to generate, transmit and distribute electricity for sale to rate-regulated retail customers. The performance obligation to deliver electricity is satisfied over time as the customer simultaneously receives and consumes the benefits provided. Revenues are variable as they are subject to the customer's usage requirements.

 Rate-regulated retail customers typically have the right to discontinue receiving service at will, therefore these contracts between AEP's subsidiaries and their customers for rate-regulated services are generally limited to the services requested and received to date for such arrangements. Retail customers are generally billed on a monthly basis, and payment is typically due within 15 to 20 days after the issuance of the invoice. Payments from REPs are due to AEP Texas within 35 days.

 Wholesale Revenues - Generation

 AEP's subsidiaries within the Vertically Integrated Utilities and Generation & Marketing segments have performance obligations to sell electricity to wholesale customers from generation assets in PJM, SPP and ERCOT. The performance obligation to deliver electricity from generation assets is satisfied over time as the customer simultaneously receives and consumes the benefits provided. Wholesale generation revenues are variable as they are subject to the customer's usage requirements.

 AEP's subsidiaries within the Vertically Integrated Utilities and Generation & Marketing segments also have performance obligations to stand ready in order to promote grid reliability. Stand ready services are sold into PJM's RPM capacity market. RPM entails a base auction and at least three incremental auctions for a specific PJM delivery year, with the incremental auctions spanning three years. The performance obligation to stand ready is satisfied over time and the consideration for which is variable until the occurrence of the final incremental auction, at which point the performance obligation becomes fixed.

 Payments from the RTO for stand ready services are typically received within one week from the issuance of the invoice, which is typically issued weekly. Gross margin resulting from generation sales within the Vertically Integrated Utilities segment are primarily subject to margin sharing agreements with customers and vary by state, where the revenues are reflected gross in the disaggregated revenues tables above.

 APCo has a performance obligation to supply wholesale electricity to KGPCo through a PPA. The FERC regulates the cost-based wholesale power transactions between APCo and KGPCo. The purchased power agreement includes a component for the recovery of transmission costs under the FERC OATT. The transmission cost component of purchased power is cost-based and regulated by the Tennessee Regulatory Authority. APCo's performance obligation under the purchased power agreement is satisfied over time as KGPCo simultaneously receives and consumes the wholesale electricity. APCo's revenues from the purchased power agreement are presented within the Generation Revenues line in the disaggregated revenues tables above.

 Wholesale Revenues - Transmission

 AEP's subsidiaries within the Vertically Integrated Utilities, Transmission and Distribution Utilities and AEP Transmission Holdco segments have performance obligations to transmit electricity to wholesale customers through assets owned and operated by AEP subsidiaries. The performance obligation to provide transmission services in PJM, SPP and ERCOT is partially fixed for a period of one year or less. Payments from the RTO for transmission services are typically received within one week from the issuance of the invoice, which is issued monthly for SPP and ERCOT and weekly for PJM.

 AEP subsidiaries within the PJM and SPP regions collect revenues through transmission formula rates. The FERC-approved rates establish the annual transmission revenue requirement (ATRR) and transmission service rates for transmission owners. The formula rates establish rates for a one year period and also include a true-up calculation for the prior year's billings, allowing for over/under-recovery of the transmission owner's ATRR. The annual true-ups meet the definition of alternative revenues in accordance with the accounting guidance for "Regulated Operations," and are therefore presented as such in the disaggregated revenues tables above. AEP subsidiaries within the ERCOT region collect revenues through a combination of base rates and interim Transmission Costs of Services filings that are approved by the PUCT.

 The AEP East Companies are parties to the TA, which defines how transmission costs are allocated among the AEP East Companies on a 12-month average coincident peak basis. PSO, SWEPCo and AEPSC are parties to the TCA by and among PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two AEP utility subsidiaries. AEPTCo is a transmission owner within the PJM and SPP regions providing transmission services to affiliates in accordance with the OATT, TA and TCA. Affiliate revenues as a result of the respective TA and the TCA are reflected as Transmission Revenues in the disaggregated revenues tables above.

 Marketing, Competitive Retail and Renewable Revenues

 AEP's subsidiaries within the Generation & Marketing segment have performance obligations to deliver electricity to competitive retail and wholesale customers. Performance obligations for marketing, competitive retail and renewable offtake sales are satisfied over time as the customer simultaneously receives and consumes the benefits provided. Revenues are primarily variable as they are subject to customer's usage requirements; however, certain contracts mandate a delivery of a set quantity of electricity at a predetermined price, resulting in a fixed performance obligation.

 Payment terms under marketing arrangements typically follow standard Edison Electric Institute and International Swaps and Derivatives Association terms, which call for payment in 20 days. Payments for competitive retail and offtake arrangements for renewable assets range from 15 to 60 days and are dependent on the product sold, location and the creditworthiness of customer. Invoices for marketing arrangements, competitive retail and offtake arrangements for renewable assets are issued monthly.

 Fixed Performance Obligations (Applies to AEP, APCo and I&M)

 The following table represents the Registrants' remaining fixed performance obligations satisfied over time as of December 31, 2023. Fixed performance obligations primarily include electricity sales for fixed amounts of energy and stand ready services into PJM's RPM market. The Registrants elected to apply the exemption to not disclose the value of unsatisfied performance obligations for contracts with an original expected term of one year or less. Due to the annual establishment of revenue requirements, transmission revenues are excluded from the table below. The Registrant Subsidiaries amounts shown in the table below include affiliated and nonaffiliated revenues.

 2024
 2025-2026
 2027-2028
 Total

 AEP
 $
 84.4
 $
 167.2
 $
 84.4
 $
 27.3
 $
 363.3

 APCo
 16.1
 32.2
 23.2
 11.7
 83.2

 I&M
 4.4
 8.8
 8.8
 4.5
 26.5

 Contract Assets and Liabilities

 Contract assets are recognized when the Registrants have a right to consideration that is conditional upon the occurrence of an event other than the passage of time, such as future performance under a contract. The Registrants did not have any material contract assets as of December 31, 2023 and 2022.

 When the Registrants receive consideration, or such consideration is unconditionally due from a customer prior to transferring goods or services to the customer under the terms of a sales contract, they recognize a contract liability on the balance sheet in the amount of that consideration. Revenue for such consideration is subsequently recognized in the period or periods in which the remaining performance obligations in the contract are satisfied. The Registrants' contract liabilities typically arise from services provided under joint use agreements for utility poles. The Registrants did not have any material contract liabilities as of December 31, 2023 and 2022.

 Accounts Receivable from Contracts with Customers

 Accounts receivable from contracts with customers are presented on the Registrants' balance sheets within the Accounts Receivable - Customers line item. The Registrants' balances for receivables from contracts that are not recognized in accordance with the accounting guidance for "Revenue from Contracts with Customers" included in Accounts Receivable - Customers were not material as of December 31, 2023 and 2022. See "Securitized Accounts Receivable - AEP Credit" section of Note 14 for additional information.

 The following table represents the amount of affiliated accounts receivable from contracts with customers included in Accounts Receivable - Affiliated Companies on the Registrant Subsidiaries' balance sheets:

 APCo
 I&M
 OPCo
 PSO

 2023
 $
 —
 $
 123.2
 $
 71.7
 $
 44.0
 $
 70.1
 $
 12.4
 $
 27.4

 2022
 0.1
 113.8
 64.5
 75.3
 49.9
 18.8
 19.1

 Contract Costs

 Contract costs to obtain or fulfill a contract for AEP subsidiaries within the Generation & Marketing segment are accounted for under the guidance for "Other Assets and Deferred Costs" and presented as a single asset and are neither bifurcated nor reclassified between current and noncurrent assets on the Registrants' balance sheets. Contract costs to acquire a contract are amortized in a manner consistent with the transfer of goods or services to the customer in Other Operation on the Registrants' income statements. The Registrants did not have material contract costs as of December 31, 2023 and 2022.

 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

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

 Information required by this item is set forth under the caption Proposal to Ratify the Appointment of the Independent Registered Public Accounting Firm in the 2024 Proxy Statement, which is incorporated by reference into this item.

 ITEM 9A. CONTROLS AND PROCEDURES

 Disclosure Controls and Procedures

 During 2023, management, including the principal executive officer and principal financial officer of each of the Registrants evaluated each respective Registrant's disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrant that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to each Registrant's management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

 As of December 31, 2023, the principal executive officer and financial officer of each of the Registrants concluded that the disclosure controls and procedures in place were effective at the reasonable assurance level. The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting and to maintain dynamic systems that change as events warrant.

 Changes in Internal Control over Financial Reporting

 There have been no changes in the Registrants' internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth quarter 2023 that materially affected, or are reasonably likely to materially affect, the Registrants' internal control over financial reporting.

 Internal Control over Financial Reporting

 See Management's Report on Internal Control over Financial Reporting for each Registrant under Item 8. As discussed in that report, management assessed and reported on the effectiveness of each Registrant's internal control over financial reporting as of December 31, 2023. As a result of that assessment, management concluded that each Registrant's internal control over financial reporting was effective as of December 31, 2023.

 ITEM 9B. OTHER INFORMATION

 During the three months ended December 31, 2023, none of the Company's directors or officers (as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934) adopted, terminated or modified a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K of the Securities Act of 1933).

 ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

 None.

 ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

 AEP

 Directors, Director Nomination Process and Audit Committee

 Certain of the information called for in this Item 10, including the information relating to directors, is incorporated herein by reference to AEP's definitive proxy information statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2024 Annual Meeting of Shareholders (the 2024 Annual Meeting) including under the captions "Election of Directors," "AEP's Board of Directors and Committees," "Directors" and "Nominees for Directors."

 Executive Officers

 Reference also is made under the caption "Information About our Executive Officers" in Part I, Item 1 of this report.

 Code of Ethics

 AEP's Principles of Business Conduct is the code of ethics that applies to AEP's Chief Executive Officer, Chief Financial Officer and principal accounting officer. The Principles of Business Conduct is available on AEP's website at www.aep.com. The Principles of Business Conduct will be made available, without charge, in print to any shareholder who requests such document from Investor Relations, American Electric Power Company, Inc., 1 Riverside Plaza, Columbus, Ohio 43215.

 If any substantive amendments to the Principles of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Principles of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or principal accounting officer, AEP will disclose the nature of such amendment or waiver on AEP's website, www.aep.com, or in a report on Form 8-K.

 Delinquent Section 16(a) Reports

 None.

 Omitted pursuant to Instruction I(2)(c).

 ITEM 11. EXECUTIVE COMPENSATION

 AEP

 The information called for by this Item 11 is incorporated herein by reference to AEP's definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2024 Annual Meeting including under the captions "Compensation Discussion and Analysis," "Executive Compensation", "Director Compensation" and "2023 Director Compensation Table". The information set forth under the subcaption "Human Resources Committee Report" and "Audit Committee Report" should not be deemed filed nor should it be incorporated by reference into any other filing under the Securities Act of 1933, as amended, or the Exchange Act except to the extent AEP specifically incorporates such report by reference therein.

 Omitted pursuant to Instruction I(2)(c).

 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

 AEP

 The information relating to Security Ownership of Certain Beneficial Owners is incorporated herein by reference to AEP's definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to 2024 Annual Meeting under the caption "Share Ownership of Certain Beneficial Owners" and "Share Ownership of Directors and Executive Officers."

 EQUITY COMPENSATION PLAN INFORMATION

 The following table summarizes the ability of AEP to issue common stock pursuant to equity compensation plans as of December 31, 2023:

 Plan Category
 Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights (a)
 Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b)
 Number of Securities Remaining
Available for Future Issuance under Equity Compensation Plans

 Equity Compensation Plans Approved by Security Holders
 2,500,803
 —
 3,698,144

 Equity Compensation Plans Not Approved by Security Holders
 —
 —
 —

 Total
 2,500,803
 —
 3,698,144

 (a)The balance includes unvested performance shares and restricted stock units as well as vested performance shares deferred as AEP career shares and stock units payable to outside directors after their service to the Company ends, all of which will be settled and paid in shares of AEP common stock. For performance shares, the total includes the target number of shares that could be granted if performance meets target objectives. The number of securities that would be granted, with respect to performance shares, if performance meets the maximum payout level, is two times the amount included in this total.
 (b)No consideration is required from participants for the exercise or vesting of any outstanding AEP equity compensation awards.

 Omitted pursuant to Instruction I(2)(c).

 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

 AEP

 The information called for by this Item 13 is incorporated herein by reference to AEP's definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2024 Annual Meeting under the captions "Transactions with Related Persons" and "Director Independence."

 Omitted pursuant to Instruction I(2)(c).

 ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

 AEP

 The information called for by this Item 14 is incorporated herein by reference to AEP's definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2024 Annual Meeting under the captions "Audit and Non-Audit Fees," "Audit Committee Report" and "Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of the Independent Auditor."

 Each of the above is a wholly-owned subsidiary of AEP and does not have a separate audit committee. A description of the AEP Audit Committee pre-approval policies, which apply to these companies, is contained in the definitive proxy statement of AEP for the 2024 Annual Meeting of shareholders. The following table presents directly billed fees for professional services rendered by PricewaterhouseCoopers LLP for the audit of these companies' annual financial statements for the years ended December 31, 2023 and 2022, and fees directly billed for other services rendered by PricewaterhouseCoopers LLP during those periods. PricewaterhouseCoopers LLP also provides additional professional and other services to AEP subsidiaries, the cost of which may ultimately be allocated to these companies though not billed directly to them. For a description of these fees and services, see the description of principal accounting fees and services for AEP above.

 APCo

 2023
 2022
 2023
 2022
 2023
 2022

 Audit Fees
 $
 1,465,285
 $
 1,309,196
 $
 1,633,905
 $
 1,492,709
 $
 1,702,568
 $
 1,682,664

 Audit-Related Fees
 38,333
 65,222
 —
 —
 44,250
 70,294

 Total
 $
 1,503,618
 $
 1,374,418
 $
 1,633,905
 $
 1,492,709
 $
 1,746,818
 $
 1,752,958

 I&M
 OPCo
 PSO

 2023
 2022
 2023
 2022
 2023
 2022

 Audit Fees
 $
 1,459,950
 $
 1,453,010
 $
 1,191,662
 $
 1,053,853
 $
 770,975
 $
 861,937

 Audit-Related Fees
 15,833
 11,009
 15,833
 11,009
 44,250
 160,294

 Total
 $
 1,475,783
 $
 1,464,019
 $
 1,207,495
 $
 1,064,862
 $
 815,225
 $
 1,022,231

 2023
 2022

 Audit Fees
 $
 1,123,641
 $
 1,012,800

 Audit-Related Fees
 27,667
 26,821

 Total
 $
 1,151,308
 $
 1,039,621

 ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 The following documents are filed as a part of this report:

 (a)(1) FINANCIAL STATEMENTS:

 The following financial statements have been incorporated herein by reference pursuant to Item 8.

 AEP and Subsidiary Companies:
 Report of Independent Registered Public Accounting Firm; Management's Report on Internal Control over Financial Reporting; Consolidated Statements of Income for the years ended December 31, 2023, 2022 and 2021; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2023, 2022 and 2021; Consolidated Statements of Changes in Equity for the years ended December 31, 2023, 2022 and 2021; Consolidated Balance Sheets as of December 31, 2023 and 2022; Consolidated Statements of Cash Flows for the years ended December 31, 2023, 2022 and 2021; Notes to Financial Statements of Registrants.

 AEP Texas, APCo and I&M:
 Report of Independent Registered Public Accounting Firm; Management's Report on Internal Control over Financial Reporting; Consolidated Statements of Income for the years ended December 31, 2023, 2022 and 2021; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2023, 2022 and 2021; Consolidated Statements of Changes in Common Shareholder's Equity for the years ended December 31, 2023, 2022 and 2021; Consolidated Balance Sheets as of December 31, 2023 and 2022; Consolidated Statements of Cash Flows for the years ended December 31, 2023, 2022 and 2021; Notes to Financial Statements of Registrants.

 AEPTCo:
 Report of Independent Registered Public Accounting Firm; Management's Report on Internal Control over Financial Reporting; Consolidated Statements of Income for the years ended December 31, 2023, 2022 and 2021; Consolidated Statements of Changes in Member's Equity for the years ended December 31, 2023, 2022 and 2021; Consolidated Balance Sheets as of December 31, 2023 and 2022; Consolidated Statements of Cash Flows for the years ended December 31, 2023, 2022 and 2021; Notes to Financial Statements of Registrants.

 OPCo:
 Report of Independent Registered Public Accounting Firm; Management's Report on Internal Control over Financial Reporting; Consolidated Statements of Income for the years ended December 31, 2023, 2022 and 2021; Consolidated Statements of Changes in Common Shareholder's Equity for the years ended December 31, 2023, 2022 and 2021; Consolidated Balance Sheets as of December 31, 2023 and 2022; Consolidated Statements of Cash Flows for the years ended December 31, 2023, 2022 and 2021; Notes to Financial Statements of Registrants.

 PSO:
 Report of Independent Registered Public Accounting Firm; Management's Report on Internal Control over Financial Reporting; Statements of Income for the years ended December 31, 2023, 2022 and 2021; Statements of Comprehensive Income (Loss) for the years ended December 31, 2023, 2022 and 2021; Statements of Changes in Common Shareholder's Equity for the years ended December 31, 2023, 2022 and 2021; Balance Sheets as of December 31, 2023 and 2022; Statements of Cash Flows for the years ended December 31, 2023, 2022 and 2021; Notes to Financial Statements of Registrants.

 SWEPCo:
 Report of Independent Registered Public Accounting Firm; Management's Report on Internal Control over Financial Reporting; Consolidated Statements of Income for the years ended December 31, 2023, 2022 and 2021; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2023, 2022 and 2021; Consolidated Statements of Changes in Equity for the years ended December 31, 2023, 2022 and 2021; Consolidated Balance Sheets as of December 31, 2023 and 2022; Consolidated Statements of Cash Flows for the years ended December 31, 2023, 2022 and 2021; Notes to Financial Statements of Registrants.

 (a)(2) FINANCIAL STATEMENT SCHEDULES:
 Page Number

 Schedule I

 Condensed Financial Information of American Electric Power Company, Inc. (Parent)

 Condensed Statements of Income and Comprehensive Income- Years Ended
 December 31, 2023, 2022 and 2021

 S- 2

 Condensed Balance Sheets - December 31, 2023 and 2022
 S- 3

 Condensed Statements of Cash Flows - Years Ended December 31, 2023, 2022 and 2021
 S- 5

 Condensed Notes to Condensed Financial Information
 S- 6

 Schedule II

 AEP

 Valuation and Qualifying Accounts and Reserves - Years Ended
 December 31, 2023, 2022 and 2021

 S- 9

 Schedule I

 Condensed Financial Information of AEP Transmission Company, LLC (AEPTCo Parent)

 Condensed Statements of Income - Years Ended December 31, 2023, 2022 and 2021
 S- 11

 Condensed Balance Sheets - December 31, 2023 and 2022
 S- 12

 Condensed Statements of Cash Flows - Years Ended December 31, 2023, 2022 and 2021
 S- 14

 Condensed Notes to Condensed Financial Information
 S- 15

 Certain schedules have been omitted because the required information is contained in the notes to financial statements or because such schedules are not required or are not applicable.

 (a)(3) EXHIBITS:

 Exhibits for AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo are listed in the Exhibit Index beginning on page E-1 and are incorporated herein by reference.
 E- 1

 ITEM 16. FORM 10-K SUMMARY

 None.

 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 American Electric Power Company, Inc.

 By:

 (Charles E. Zebula, Executive Vice President

 and Chief Financial Officer)

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 Title

 Date

 (i)

 Interim Chief Executive Officer and President

 (ii)

 Executive Vice President and Chief Financial Officer

 (iii)

 Senior Vice President, Controller and Chief Accounting Officer

 (iv)

 *J. Barnie Beasley, Jr.

 *Benjamin G.S. Fowke, III

 *Art A. Garcia

 *Hunter C. Gary

 *Linda A. Goodspeed

 *Donna A. James

 *Sandra Beach Lin

 *Henry P. Linginfelter

 *Margaret M. McCarthy

 *Daryl Roberts

 *Daniel G. Stoddard

 *Sara Martinez Tucker

 *Lewis Von Thaer

 *By:

 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

 AEP Texas Inc.

 By:

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

 Title

 Date

 (i)

 (ii)

 (iii)

 (iv)

 *Judith E. Talavera

 *By:

 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

 AEP Transmission Company, LLC

 By:

 (Charles E. Zebula, Vice President

 and Chief Financial Officer)

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

 Title

 Date

 (i)

 Chair of the Board, Interim Chief Executive Officer and Manager

 (ii)

 Vice President, Chief Financial Officer and Manager

 (iii)

 (iv)
 A Majority of the Managers:

 *By:

 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

 Appalachian Power Company

 By:

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

 Title

 Date

 (i)

 (ii)

 (iii)

 (iv)

 *Antonio P. Smyth

 *Aaron D. Walker

 *By:

 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

 Indiana Michigan Power Company

 By:

 (Charles E. Zebula, Vice President,

 and Chief Financial Officer)

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

 Title

 Date

 (i)

 (ii)

 (iii)

 (iv)

 *Steven F. Baker

 *Katherine K. Davis

 *Nicholas M. Elkins

 *David S. Isaacson

 *Andrew J. Williamson

 *By:

 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

 Ohio Power Company

 By:

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

 Title

 Date

 (i)

 (ii)

 (iii)

 (iv)

 *Marc D. Reitter

 *Antonio P. Smyth

 *By:

 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

 By:

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

 Title

 Date

 (i)

 (ii)

 (iii)

 (iv)

 *Antonio P. Smyth

 *Leigh Anne Strahler

 *By:

 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

 Southwestern Electric Power Company

 By:

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

 Title

 Date

 (i)

 (ii)

 (iii)

 (iv)

 *D. Brett Mattison

 *Antonio P. Smyth

 *By:

 INDEX OF FINANCIAL STATEMENT SCHEDULES

 Page

 The following financial statement schedules are included in this report on the pages indicated:

 American Electric Power Company, Inc. (Parent):

 Schedule I – Condensed Financial Information

 S- 2

 Schedule I – Condensed Notes to Condensed Financial Information

 S- 6

 American Electric Power Company, Inc. and Subsidiary Companies:

 Schedule II – Valuation and Qualifying Accounts and Reserves

 S- 9

 S-1

 AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
 CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
 (in millions, except per-share and share amounts)

 2023
 2022
 2021

 Revenues
 $
 5.1
 $
 5.1
 $
 6.7

 5.1
 5.1
 6.7

 16.7
 84.9
 42.7

 —
 363.3
 —

 0.5
 0.4
 0.4

 Amortization of KPCo Basis Difference
 (16.5)
 —
 —

 0.7
 448.6
 43.1

 OPERATING INCOME (LOSS)
 4.4
 (443.5)
 (36.4)

 181.0
 80.3
 18.9

 (526.3)
 (275.5)
 (169.3)

 LOSS BEFORE INCOME TAX BENEFIT AND EQUITY EARNINGS
 (340.9)
 (638.7)
 (186.8)

 (80.8)
 (136.3)
 (73.5)

 2,468.2
 2,809.6
 2,601.4

 Other Comprehensive Income (Loss)
 (139.2)
 (101.1)
 269.9

 $
 2,068.9
 $
 2,206.1
 $
 2,758.0

 WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING
 518,903,682
 511,841,946
 500,522,177

 TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 $
 4.26
 $
 4.51
 $
 4.97

 WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING
 520,206,258
 513,484,609
 501,784,032

 TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 $
 4.24
 $
 4.49
 $
 4.96

 See Condensed Notes to Condensed Financial Information beginning on page S- 6.

 S-2

 AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
 CONDENSED BALANCE SHEETS

 2023
 2022

 $
 197.8
 $
 254.2

 Other Temporary Investments
 2.6
 2.5

 2,004.5
 4,012.1

 47.7
 78.6

 2.7
 0.5

 50.4
 79.1

 Accrued Tax Benefits
 77.7
 39.3

 11.6
 17.7

 2,344.6
 4,404.9

 3.1
 2.7

 3.1
 2.7

 Accumulated Depreciation, Depletion and Amortization
 1.4
 1.2

 1.7
 1.5

 Investments in Unconsolidated Subsidiaries
 33,598.6
 31,183.7

 Affiliated Notes Receivable
 295.0
 85.0

 137.0
 196.5

 34,030.6
 31,465.2

 $
 36,376.9
 $
 35,871.6

 See Condensed Notes to Condensed Financial Information beginning on page S- 6.

 S-3

 AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
 CONDENSED BALANCE SHEETS

 2023
 2022

 $
 728.3
 $
 919.9

 11.1
 5.1

 12.3
 34.2

 Short-term Debt
 3,362.2

 1,104.0
 1,050.0

 137.7
 126.3

 3,931.3
 5,497.7

 7,086.9
 6,322.5

 69.5
 112.1

 7,156.4
 6,434.6

 11,087.7
 11,932.3

 MEZZANINE EQUITY

 Contingently Redeemable Performance Share Awards
 42.5
 45.9

 COMMON SHAREHOLDERS' EQUITY

 Common Stock – Par Value – $6.50 Per Share:

 2023
 2022

 Shares Authorized
 600,000,000
 600,000,000

 Shares Issued
 527,369,157
 525,099,321

 (1,184,572 and 11,233,240 Shares were Held in Treasury as of December 31, 2023 and 2022, Respectively)
 3,427.9
 3,413.1

 9,073.9
 8,051.0

 12,800.4
 12,345.6

 (55.5)
 83.7

 TOTAL AEP COMMON SHAREHOLDERS' EQUITY
 25,246.7
 23,893.4

 TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY
 $
 36,376.9
 $
 35,871.6

 See Condensed Notes to Condensed Financial Information beginning on page S- 6.

 S-4

 AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
 CONDENSED STATEMENTS OF CASH FLOWS

 2023
 2022
 2021

 $
 $
 $

 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:

 0.5
 0.4
 0.4

 Amortization of KPCo Basis Difference
 (16.5)
 —
 —

 59.7
 (63.3)
 (63.9)

 —
 363.3
 —

 (2,468.2)
 (2,809.6)
 (2,601.4)

 Cash Dividends Received from Unconsolidated Subsidiaries
 686.3
 603.9
 787.2

 (28.4)
 (5.0)
 (3.5)

 92.3
 83.5
 94.0

 28.7
 (61.0)
 18.4

 (15.9)
 1.1
 27.2

 (3.6)
 (6.0)
 (0.5)

 (14.5)
 (76.6)
 77.9

 528.5
 337.9
 823.9

 (0.8)
 (0.7)
 (0.5)

 2,007.6
 (1,411.3)
 562.9

 Capital Contributions to Unconsolidated Subsidiaries
 (789.9)
 (568.3)
 (1,185.0)

 Return of Capital Contributions from Unconsolidated Subsidiaries
 56.6
 24.5
 —

 Issuance of Notes Receivable to Unconsolidated Subsidiaries
 (210.0)
 (20.0)
 —

 Repayment of Notes Receivable from Unconsolidated Subsidiaries
 —
 —
 92.3

 —
 (0.2)
 —

 Net Cash Flows from (Used for) Investing Activities
 1,063.5
 (1,976.0)
 (530.3)

 Issuance of Common Stock, Net
 999.6
 826.5
 600.5

 Issuance of Long-term Debt
 1,829.8
 986.6
 915.0

 Issuance of Short-term Debt with Original Maturities Greater Than 90 Days
 1,069.9
 833.9
 1,393.3

 Change in Short-term Debt with Original Maturities Less Than 90 Day, Net
 (1,365.4)
 1,650.4
 (610.3)

 Retirement of Long-term Debt
 (1,050.0)
 (300.0)
 (400.0)

 (191.6)
 336.9
 135.8

 Redemption of Short-term Debt with Original Maturities Greater Than 90 Days
 (1,128.8)
 (986.1)
 (771.3)

 (1,752.3)
 (1,628.7)
 (1,507.7)

 (59.6)
 (74.5)
 (101.3)

 Net Cash Flows from (Used for) Financing Activities
 (1,648.4)
 1,645.0
 (346.0)

 (56.4)
 6.9
 (52.4)

 254.2
 247.3
 299.7

 $
 197.8
 $
 254.2
 $
 247.3

 See Condensed Notes to Condensed Financial Information beginning on page S- 6.

 S-5

 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 Basis of Presentation

 The condensed financial information of Parent is required as a result of the restricted net assets of AEP consolidated subsidiaries exceeding 25% of AEP consolidated net assets as of December 31, 2023. Parent is a public utility holding company that owns all of the outstanding common stock of its public utility subsidiaries and varying percentages of other subsidiaries, including joint ventures and equity investments. The primary source of income for Parent is equity in its subsidiaries' earnings. Its major source of cash is dividends from the subsidiaries, which are evaluated for cash flow presentation based on the nature of the distribution. Parent borrows the funds for the money pool that is used by the subsidiaries for their short-term cash needs. Parent financial statements should be read in conjunction with the AEP consolidated financial statements and the accompanying notes thereto. For purposes of these condensed financial statements, AEP wholly-owned and majority-owned subsidiaries are recorded based upon its proportionate share of the subsidiaries' net assets (similar to presenting them on the equity method).

 Income Taxes

 Parent files a consolidated federal income tax return with its subsidiaries. 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 Subsidiaries' financial statements. The consolidated NOL of the AEP System is allocated to each company in the consolidated group with taxable income. 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.

 Termination of Planned 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. The SPA was subsequently amended in September 2022 to reduce the purchase price to approximately $2.646 billion. The sale required approval from the KPSC and from the FERC under Section 203 of the Federal Power Act. The SPA contained certain termination rights if the closing of the sale did not occur by April 26, 2023.

 In May 2022, the KPSC approved the sale of KPCo to Liberty subject to certain 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 an adverse effect on rates. In February 2023, a new filing for approval under Section 203 of the Federal Power Act was submitted. In March 2023, the KPSC and other intervenors made filings recommending the FERC reject AEP and Liberty's new Section 203 application seeking approval of the sale.

 In April 2023, AEP, AEPTCo and Liberty entered into a Mutual Termination Agreement (Termination Agreement) terminating the SPA. The parties entered into the Termination Agreement as all of the conditions precedent to closing the sale could not be satisfied prior to April 26, 2023.

 Upon reverting to a held and used model, AEP Parent was required to present its investment in the Kentucky Operations at the lower of fair value or historical carrying value. As a result, AEP Parent's December 31, 2022 balance sheets reflect a $363 million pretax reduction in the basis of its investment in KPCo's assets which is recorded in Investments in Unconsolidated Subsidiaries. In 2023, the $363 million was reduced by $28 million to remove the impact of estimated costs to sell KPCo and KTCo which was included in the Loss on the Expected Sale of the Kentucky Operations in 2022. The reduced investment in KPCo's assets is being amortized over the 30-year average useful life of the KPCo assets.

 2. COMMITMENTS, GUARANTEES AND CONTINGENCIES

 Parent and its subsidiaries are parties to environmental and other legal matters. For further discussion, see Note 6 - Commitments, Guarantees and Contingencies included in the 2023 Annual Report.
 S-6

 3. FINANCING ACTIVITIES

 The following details long-term debt outstanding as of December 31, 2023 and 2022:

 Weighted-Average
 Interest Rate Ranges as of
 Outstanding as of

 Interest Rate as of

 Type of Debt
 Maturity
 2023
 2022
 2023
 2022

 2025-2050
 4.29%
 1.00%-5.95%
 0.75%-5.95%
 $
 5,265.0
 $
 4,454.0

 Pollution Control Bonds
 2024-2029 (a)
 2.26%
 1.90%-2.60%
 1.90%-2.60%
 537.8
 537.2

 Junior Subordinated Notes
 2024-2027
 3.90%
 2.03%-5.70%
 1.30%-3.88%
 2,388.1
 2,381.3

 8,190.9
 7,372.5

 Long-term Debt Due Within One Year
 1,104.0
 1,050.0

 $
 7,086.9
 $
 6,322.5

 (a)Certain Pollution Control Bonds are subject to redemption earlier than the maturity date.

 Long-term debt outstanding as of December 31, 2023 is payable as follows:

 2024
 2025
 2026
 2027
 2028
 Total

 Principal Amount (a)
 $
 1,104.0
 $
 1,264.1
 $
 —
 $
 1,717.6
 $
 775.0
 $
 3,389.9
 $
 8,250.6

 Unamortized Discount, Net and Debt Issuance Costs

 (59.7)

 $
 8,190.9

 (a)Amounts reflect the impact of fair value hedge accounting. See "Accounting for Fair Value Hedging Strategies" section of Note 10 included in the 2023 Annual Report for additional information.

 Short-term Debt

 Parent's outstanding short-term debt was as follows:

 Type of Debt
 Outstanding
 Weighted-Average
 Outstanding
 Weighted-Average

 Commercial Paper
 $
 5.69
 %
 $
 2,862.2
 4.80
 %

 —
 —
 %
 125.0
 5.17
 %

 —
 —
 %
 150.0
 5.17
 %

 —
 —
 %
 100.0
 5.23
 %

 —
 —
 %
 125.0
 4.87
 %

 Total Short-term Debt
 $
 $
 3,362.2

 S-7

 4. RELATED PARTY TRANSACTIONS

 Payments on Behalf of Subsidiaries

 Due to occasional time sensitivity and complexity of payments, Parent makes certain insurance, tax and benefit payments on behalf of subsidiary companies. Parent is then fully reimbursed by the subsidiary companies.

 Short-term Lending to Subsidiaries

 Parent uses a commercial paper program to meet the short-term borrowing needs of subsidiaries. The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds certain nonutility subsidiaries. In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. The program also allows some direct borrowers to invest excess cash with Parent.

 Interest expense related to Parent's short-term borrowing is included in Interest Expense on Parent's statements of income. Parent incurred interest expense for amounts borrowed from subsidiaries of $33 million, $30 million and $2 million for the years ended December 31, 2023, 2022 and 2021, respectively.

 Interest income related to Parent's short-term lending is included in Interest Income on Parent's statements of income. Parent earned interest income for amounts advanced to subsidiaries of $164 million, $71 million and $15 million for the years ended December 31, 2023, 2022 and 2021, respectively.

 Affiliated Notes

 Parent issued long-term debt, portions of which were loaned to its subsidiaries. Parent pays interest on the affiliated notes, but the subsidiaries accrue interest for their share of the affiliated borrowing and remit the interest to Parent. Interest income related to Parent's loans to subsidiaries is included in Interest Income on Parent's statements of income. Parent earned interest income on loans to subsidiaries of $6 million, $3 million and $2 million for the years ended December 31, 2023, 2022 and 2021, respectively.

 S-8

 SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

 AEP

 Additions

 Description
 Balance at
 Beginning
of Period
 Charged to
Costs and
Expenses
 Charged to Other
Accounts (a)
 Deductions (b)
 Balance at
End of

 Deducted from Assets:

 Accumulated Provision for Uncollectible Accounts:

 $
 57.1
 $
 15.0
 $
 —
 $
 12.0
 $
 60.1

 55.4
 41.2
 0.8
 40.3
 57.1

 71.1
 20.3
 0.6
 36.6
 55.4

 (a)Recoveries offset by reclasses to other assets and liabilities.
 (b)Uncollectible accounts written off.

 Schedule II for the Registrant Subsidiaries is not presented because the amounts are not material.
 S-9

 INDEX OF AEP TRANSMISSION COMPANY, LLC (AEPTCO PARENT)
 FINANCIAL STATEMENT SCHEDULES

 Page

 The following financial statement schedules are included in this report on the pages indicated:

 AEP Transmission Company, LLC (AEPTCo Parent):

 Schedule I – Condensed Financial Information

 S- 11

 Schedule I – Condensed Notes to Condensed Financial Information

 S- 15

 S-10

 AEP TRANSMISSION COMPANY, LLC (AEPTCo Parent)
 CONDENSED STATEMENTS OF INCOME

 2023
 2022
 2021

 $
 0.2
 $
 0.7
 $
 0.2

 0.2
 0.7
 0.2

 OPERATING LOSS
 (0.2)
 (0.7)
 (0.2)

 Interest Income - Affiliated
 218.0
 177.8
 158.1

 (215.1)
 (177.1)
 (157.7)

 INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS OF UNCONSOLIDATED SUBSIDIARIES
 2.7
 —
 0.2

 1.4
 —
 —

 612.9
 594.2
 591.5

 $
 614.2
 $
 594.2
 $
 591.7

 See Condensed Notes to Condensed Financial Information beginning on page S- 15.

 S-11

 AEP TRANSMISSION COMPANY, LLC (AEPTCo Parent)
 CONDENSED BALANCE SHEETS

 2023
 2022

 $
 28.1
 $
 —

 44.0
 34.6

 72.1
 34.6

 Notes Receivable - Affiliated
 95.0
 60.0

 167.1
 94.6

 Notes Receivable - Affiliated
 5,319.4
 4,722.8

 Investments in Unconsolidated Subsidiaries
 6,476.2
 6,021.2

 11,795.6
 10,744.0

 $
 11,962.7
 $
 10,838.6

 See Condensed Notes to Condensed Financial Information beginning on page S- 15.

 S-12

 AEP TRANSMISSION COMPANY, LLC (AEPTCo Parent)
 CONDENSED BALANCE SHEETS

 2023
 2022

 $
 42.7
 $
 27.8

 35.4
 78.1

 81.5
 42.2

 95.0
 60.0

 39.6
 28.8

 15.8
 5.9

 310.0
 242.8

 5,319.4
 4,722.8

 5,319.4
 4,722.8

 5,629.4
 4,965.6

 MEMBER'S EQUITY

 3,043.4
 3,022.3

 3,289.9
 2,850.7

 TOTAL MEMBER'S EQUITY
 6,333.3
 5,873.0

 TOTAL LIABILITIES AND MEMBER'S EQUITY
 $
 11,962.7
 $
 10,838.6

 See Condensed Notes to Condensed Financial Information beginning on page S- 15.

 S-13

 AEP TRANSMISSION COMPANY, LLC (AEPTCo Parent)
 CONDENSED STATEMENTS OF CASH FLOWS

 2023
 2022
 2021

 $
 614.2
 $
 594.2
 $
 591.7

 Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:

 (612.9)
 (594.2)
 (591.5)

 3.8
 —
 —

 11.5
 9.1
 6.2

 (37.5)
 (2.2)
 (5.9)

 36.6
 (0.6)
 4.8

 10.8
 —
 4.9

 (30.5)
 (0.8)
 12.3

 Net Cash Flows from (Used for) Operating Activities
 (4.0)
 5.5
 22.5

 —
 12.7
 96.3

 Repayment of Notes Receivable from Affiliated Companies
 60.0
 104.0
 50.0

 Issuance of Notes Receivable to Affiliated Companies
 (700.0)
 (550.0)
 (450.0)

 Return of Capital Contributions from Unconsolidated Subsidiaries
 183.7
 130.0
 —

 Capital Contributions to Subsidiaries
 (29.7)
 (69.5)
 (184.0)

 (486.0)
 (372.8)
 (487.7)

 Capital Contributions from Member
 29.7
 72.7
 184.0

 Return of Capital to Member
 (8.6)
 —
 —

 689.0
 540.8
 443.7

 (60.0)
 (104.0)
 (50.0)

 14.9
 27.8
 —

 (175.0)
 (170.0)
 (112.5)

 490.0
 367.3
 465.2

 Net Change in Cash and Cash Equivalents
 —
 —
 —

 —
 —
 —

 $
 —
 $
 —
 $
 —

 See Condensed Notes to Condensed Financial Information beginning on page S- 15.

 S-14

 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 Basis of Presentation

 The condensed financial information of AEPTCo Parent is required as a result of the restricted net assets of AEPTCo consolidated subsidiaries exceeding 25% of AEPTCo consolidated net assets as of December 31, 2023. AEPTCo Parent is the direct holding company for the seven State Transcos. The primary source of income for AEPTCo Parent is equity in its subsidiaries' earnings. AEPTCo Parent financial statements should be read in conjunction with the AEPTCo consolidated financial statements and the accompanying notes thereto. For purposes of these condensed financial statements, AEPTCo wholly-owned and majority-owned subsidiaries are recorded based upon its proportionate share of the subsidiaries' net assets (similar to presenting them on the equity method).

 Income Taxes

 AEPTCo Parent joins in the filing of a consolidated federal income tax return with its affiliates in the AEP System. 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 Subsidiaries' financial statements. The consolidated NOL of the AEP System is allocated to each company in the consolidated group with taxable income. 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.

 Termination of Planned 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. The SPA was subsequently amended in September 2022 to reduce the purchase price to approximately $2.646 billion. The sale required approval from the KPSC and from the FERC under Section 203 of the Federal Power Act. The SPA contained certain termination rights if the closing of the sale did not occur by April 26, 2023.

 In May 2022, the KPSC approved the sale of KPCo to Liberty subject to certain 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 an adverse effect on rates. In February 2023, a new filing for approval under Section 203 of the Federal Power Act was submitted. In March 2023, the KPSC and other intervenors made filings recommending the FERC reject AEP and Liberty's new Section 203 application seeking approval of the sale.

 In April 2023, AEP, AEPTCo and Liberty entered into a Mutual Termination Agreement (Termination Agreement) terminating the SPA. The parties entered into the Termination Agreement as all of the conditions precedent to closing the sale could not be satisfied prior to April 26, 2023.

 2. COMMITMENTS, GUARANTEES AND CONTINGENCIES

 AEPTCo Parent and its subsidiaries are parties to legal matters. For further discussion, see Note 6 - Commitments, Guarantees and Contingencies included in the 2023 Annual Report.

 3. FINANCING ACTIVITIES

 For discussion of Financing Activities, see Note 14 - Financing Activities to AEPTCo's audited consolidated financial statements included in the 2023 Annual Report.

 4. RELATED PARTY TRANSACTIONS

 Payments on Behalf of Subsidiaries

 Due to occasional time sensitivity and complexity of payments, Parent makes certain insurance, tax and other payments on behalf of subsidiary companies. Parent is then fully reimbursed by the subsidiary companies. AEPTCo Parent also makes convenience payments on behalf of its State Transcos. AEPTCo Parent is then fully reimbursed by its State Transcos.

 S-15

 Long-term Lending to Subsidiaries

 AEPTCo Parent enters into debt arrangements with nonaffiliated entities. AEPTCo Parent has long-term debt of $5.4 billion and $4.8 billion as of December 31, 2023 and 2022, respectively. AEPTCo Parent uses the proceeds from these nonaffiliated debt arrangements to make affiliated loans to its State Transcos using the same interest rates and maturity dates as the nonaffiliated debt arrangements. AEPTCo Parent has recorded Notes Receivable – Affiliated of $5.4 billion and $4.8 billion as of December 31, 2023 and 2022, respectively. Related to these nonaffiliated and affiliated debt arrangements, AEPTCo Parent has recorded Accrued Interest of $40 million and $29 million as of December 31, 2023 and 2022, respectively. AEPTCo Parent has also recorded Accounts Receivable – Affiliated Companies of $44 million and $35 million as of December 31, 2023 and 2022, respectively. AEPTCo Parent has recorded Interest Income – Affiliated of $215 million, $177 million and $158 million for the years ended December 31, 2023, 2022 and 2021, respectively, related to the Notes Receivable – Affiliated. AEPTCo Parent has recorded Interest Expense of $215 million, $177 million and $158 million for the years ended December 31, 2023, 2022 and 2021, respectively, related to the nonaffiliated debt arrangements.

 Short-term Lending to Subsidiaries

 Parent uses a commercial paper program to meet the short-term borrowing needs of subsidiaries. The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds certain nonutility subsidiaries. In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. The program also allows some direct borrowers to invest excess cash with Parent.

 Interest expense related to AEPTCo Parent's short-term borrowing is included in Interest Expense on AEPTCo Parent's statements of income. AEPTCo Parent incurred immaterial interest expense for amounts borrowed from AEP affiliates for the years ended December 31, 2023, 2022 and 2021.

 Interest income related to AEPTCo Parent's short-term lending is included in Interest Income – Affiliated on AEPTCo Parent's statements of income. AEPTCo Parent earned interest income for amounts advanced to AEP affiliates of $3 million, $915 thousand and $400 thousand for the year ended December 31, 2023, 2022 and 2021, respectively.
 S-16

 EXHIBIT INDEX

 The documents listed below are being filed or have previously been filed on behalf of the Registrants shown and are incorporated herein by reference to the documents indicated and made a part hereof. Exhibits ("Ex") not identified as previously filed are filed herewith. Exhibits designated with a dagger () are management contracts or compensatory plans or arrangements required to be filed as an Exhibit to this Form. Exhibits designated with an asterisk (*) are filed herewith.

 AEP File No. 1-3525

 3(a)
 Composite of the Restated Certificate of Incorporation of AEP, dated April 26, 2022.
 2023 Form 10-K, Ex 3(a)

 3(b)
 Composite By-Laws of AEP amended as of April 25, 2023.
 Form 8-K, Ex 3(b) dated April 28, 2023

 4(a)
 Indenture (for unsecured debt securities), dated as of May 1, 2001, between AEP and The Bank of New York, as Trustee.
 Registration Statement No. 333-86050, Ex 4 (a)(b)(c)
 Registration Statement No. 333-105532, Ex 4 (d)(e)(f)
 Registration Statement No. 333-200956, Ex 4(b)
 Registration Statement No. 333-222068, Ex 4(b) Registration Statement No. 333-249918, Ex 4 (b)(c)
 Registration Statement No. 333-275345, Ex 4 (b)(c)(d)

 4(a)1
 Company Order and Officer's Certificate between AEP and The Bank of New York Mellon Trust Company, N.A. as Trustee dated December 8, 2023 establishing terms of the 5.20% Senior Notes, Series R due 2029.
 Form 8-K, Ex. 4(a) dated December 8, 2023

 4(b)
 Junior Subordinated Indenture, dated March 1, 2008, between AEP and The Bank of New York Mellon Trust Company, N.A., as Trustee for the Junior Subordinated Debentures.
 Registration Statement No. 333-156387, Ex 4(c) (d)
 Registration Statement No. 333-249918, Ex 4(f)(g)

 4(c)
 Purchase Contract and Pledge Agreement, dated as of March 19, 2019, between AEP and The Bank of New York Mellon Trust Company, N.A., as purchase contract agent, collateral agent, custodial agent and securities intermediary.
 Registration Statement No. 333-249918, Ex 4(h)

 4(c)1
 Purchase Contract and Pledge Agreement dated as of August 14, 2020, between AEP and The Bank of New York Mellon Trust Company, N.A., as purchase contract agent, collateral agent, custodial agent and securities intermediary.
 Registration Statement No. 333-249918, Ex 4(i)

 4(d)
 $4,000,000,000 Credit Agreement dated March 31, 2021 among the Company, Initial Lenders and Wells Fargo Bank National Association as Administrative Agent.
 Form 10-Q Ex 4.2 dated March 31, 2021

 4(d)1
 April 7, 2022 Amendment and extension to $4,000,000,000 Credit Agreement dated March 31, 2021 among AEP, Initial Lenders and Wells Fargo Bank National Association as Administrative Agent.
 Form 10-Q Ex 4(a) dated March 31, 2022

 4(e)
 $1,000,000,000 Credit Agreement dated March 31, 2021 among AEP, Initial Lenders and Wells Fargo Bank National Association as Administrative Agent.
 Form 10-Q Ex 4.3 dated March 31, 2021

 E-1

 4(e)1
 April 7, 2022 Amendment and extension to $1,000,000,000 Credit Agreement dated March 31, 2021 among AEP, Initial Lenders and Wells Fargo Bank National Association as Administrative Agent.
 Form 10-Q Ex 4(b) dated March 31, 2022

 4(e)2
 March 31, 2023 Amendment and extension to $1,000,000,000 Credit Agreement dated March 31, 2021 among AEP, Initial Lenders and Wells Fargo Bank National Association as Administrative Agent.
 Form 10-Q Ex 4(b) dated March 31, 2023

 4(f)
 Distribution Agreement, dated November 6, 2020, between AEP and Credit Suisse Securities (USA) LLC, Barclays Capital Inc., BofA Securities, Inc., BNY Mellon Capital Markets, LLC, Citigroup Global Markets Inc., Scotia Capital (USA) Inc., Credit Suisse Capital LLC, Barclays Bank PLC, Bank of America, N.A. and Citibank, N.A.
 Form 8-K, Ex 1.1, November 6, 2020

 4(g)
 Description of Securities.
 2020 Form 10-K, Ex 4(c)

 10(a)
 Consent Decree with U.S. District Court dated October 9, 2007, as modified July 17, 2019.
 Form 8-K, Ex. 10 dated October 9, 2007
 Form 10-Q, Ex 10, June 30, 2013
 Form 10-Q, Ex 10, June 30, 2019

 10(b)
 AEP Retainer Deferral Plan for Non-Employee Directors, as Amended and Restated effective October 1, 2020.
 Form 10-Q, Ex 10.2, September 30, 2020

 10(c)
 AEP Stock Unit Accumulation Plan for Non-Employee Directors as amended October 1, 2020.
 Form 10-Q, Ex 10.3, September 30, 2020

 10(c)1
 AEP Stock Unit Accumulation Plan for Non-Employee Directors as amended June 1, 2022.
 2021 Form 10-K, Ex 10(d)1

 10(d)
 AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2020.
 2019 Form 10-K, Ex 10(e)

 10(d)1
 Guaranty by AEP of AEPSC Excess Benefits Plan.
 1990 Form 10-K, Ex 10(h)(1)(B)

 10(e)
 AEP System Supplemental Retirement Savings Plan, Amended and Restated as of October 6, 2021 (Non-Qualified).
 2022 Form 10-K, Ex 10(e)

 10(f)
 AEPSC Umbrella Trust for Executives.
 1993 Form 10-K, Ex 10(g)(3)

 10(f)1A
 First Amendment to AEPSC Umbrella Trust for Executives.
 2008 Form 10-K, Ex 10(l)(3)(A)

 10(f)2A
 Second Amendment to AEPSC Umbrella Trust for Executives.
 2018 Form 10-K, Ex 10(g)(2)(A)

 10(g)
 AEP System Incentive Compensation Deferral Plan Amended and Restated as of June 1, 2019.
 Form 10-Q, Ex 10(1), September 30, 2019

 10(h)
 AEP Change In Control Agreement, as Revised Effective January 1, 2017.
 Form 10-Q, Ex 10(c), September 30, 2016

 10(i)
 Amended and Restated AEP System Long-Term Incentive Plan as of September 21, 2016.
 Form 10-Q, Ex 10(a), September 30, 2016

 E-2

 10(i)1A
 Performance Share Award Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.
 Form 10-Q, Ex 10(a), March 30, 2018

 10(i)2A
 Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan as Amended and Restated effective January 1, 2022.
 2022 Form 10-K, Ex 10(i)2A

 10(j)
 AEP System Stock Ownership Requirement Plan Amended and Restated effective October 1, 2020.
 Form 10-Q, Ex 10.1, September 30, 2020

 10(k)
 Central and South West System Special Executive Retirement Plan Amended and Restated effective January 1, 2020.
 2019 Form 10-K, Ex 10(l)

 10(l)
 AEP Executive Severance Plan Amended effective January 4, 2021.
 2020 Form 10-K, Ex 10(n)

 10(l)(1)
 AEP Executive Severance Plan Amended and Restated effective February 20, 2023.
 2022 Form 10-K, Ex 10(l)(1)

 10(m)
 Severance, Release of All Claims, and Non-competition Agreement between American Electric Power Company, Inc. and Ann P. Kelly.
 Form 10-Q, Ex 10, dated September 30, 2023

 * 10(n)

 AEP Aircraft Timesharing Agreement dated January 1, 2023 between American Electric Power Service Corporation and Julia A. Sloat.

 10(o)
 Stock Purchase Agreement dated as of October 26, 2021 among AEP, AEPTCo and Liberty Utilities Co.
 Form 10-Q, Ex 10, dated September 30, 2021

 10(o)1A
 First Amendment to Stock Purchase Agreement dated September 29, 2022 among AEP, AEPTCo and Liberty Utilities Co.
 Form 10-Q, Ex 10, dated September 30, 2022

 10(o)2A
 Second Amendment to Stock Purchase Agreement dated January 16, 2023 among AEP, AEPTCo and Liberty Utilities Co.
 2022 Form 10-K, Ex 10(o)2A

 10(o)3
 Mutual Termination Agreement dated and effective April 17, 2023 among AEP, AEPTCo and Liberty Utilities Co. terminating the Stock Purchase Agreement dated October 26, 2021 the First Amendment to the Stock Purchase Agreement, dated as of September 29, 2022, and the Second Amendment to the Stock Purchase Agreement, dated as of January 16, 2023.
 Form 10-Q, Ex 10 dated June 30, 2023

 * 10(p)

 Director Appointment and Nomination Agreement.

 *21

 List of subsidiaries of AEP.

 *23

 *24

 Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 E-3

 Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

 Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

 *97

 AEP Policy on Recouping Incentive Compensation

 AEP TEXAS File No. 333-221643

 3(a)
 Composite of the Restated Certificate of Incorporation, as amended.
 Registration Statement No. 333-221643, Ex 3(a)

 3(b)
 Bylaws.
 Registration Statement No. 333-221643, Ex 3(b)

 4(a)
 Indenture, dated as of September 1, 2017, between AEP Texas Inc. and The Bank of New York Mellon Trust Company, N.A., as Trustee.
 Registration Statement No. 333-221643, Ex 4(a)-1, 4(a)-2
 Registration Statement No. 333-228657, Ex 4(a)-4, 4(a)-5
 Registration Statement No. 333-230613, Ex 4(a)(b)
 Registration Statement No. 333-253585, Ex 4(b)(c)(d)

 4(b)
 Company Order and Officer's Certificate between AEP Texas Inc. and The Bank of New York Mellon Trust Company, N.A. as Trustee dated May 6, 2021 establishing terms of the 3.45% Senior Notes, Series J, due 2051.
 Form 8-K, Ex 4(a) dated May 6, 2021

 4(c)
 Company Order and Officer's Certificate between AEP Texas Inc. and The Bank of New York Mellon Trust Company, N.A. as Trustee dated May 18, 2022 establishing terms of the 4.70% Senior Notes, Series K, due 2032 and the 5.25% Senior Notes, Series L, due 2052.
 Form 10-Q, Ex 4 dated June 30, 2022

 E-4

 4(d)
 Company Order and Officer's Certificate between AEP Texas Inc. and The Bank of New York Mellon Trust Company, N.A. as Trustee dated May 24, 2023 establishing terms of the 5.40% Senior Notes, Series M, due 2033.
 Form 8-K, Ex 4(a) dated May 24, 2023

 *23

 *24

 Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

 Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

 AEPTCo File No. 333-217143

 3(a)
 Limited Liability Company Agreement of AEP Transmission Company, LLC dated as of January 27, 2006.
 Registration Statement No. 333-217143, Ex 3(a)

 3(b)
 First Amendment to Limited Liability Company Agreement of AEPTCo dated as of May 21, 2013.
 Registration Statement No. 333-217143, Ex 3(b)

 4(a)
 Indenture, dated as of November 1, 2016, between AEPTCo and The Bank of New York Mellon Trust Company, N.A., as Trustee.
 Registration Statement No. 333-217143, Ex 4(a)-1, 4(a)-2
 Registration Statement No. 333-225325, Ex 4 (b)(c)(d)
 Registration Statement No. 333-255605, Ex 4 (b)(c)(d)(e)

 E-5

 4(b)
 Company Order and Officer's Certificate between AEPTCo and The Bank of New York Mellon Trust Company, N.A. as Trustee dated August 4, 2021 establishing terms of the 2.75% Senior Notes, Series N, due 2051.

 Form 8-K, Ex 4(a) dated August 4, 2021

 4(c)
 Company Order and Officer's Certificate between AEPTCo and The Bank of New York Mellon Trust Company, N.A. as Trustee dated June 9, 2022 establishing terms of the 4.50% Senior Notes, Series O, due 2052.
 Form 10-Q, Ex 4 dated June 30, 2022

 4(d)
 Company Order and Officer's Certificate between AEPTCo and The Bank of New York Mellon Trust Company, N.A. as Trustee dated March 13, 2023 establishing terms of the 5.40% Senior Notes, Series P, due 2053.
 Form 8-K, Ex 4(a) dated March 13, 2023

 4(e)
 Note Purchase Agreement, dated as of October 18, 2012 between AEPTCo and the Initial Purchasers.
 Registration Statement No. 333-217143, Ex 4(c)-1

 4(f)1
 Supplement to Note Purchase Agreement, dated as of November 7, 2013 between AEPTCo and the Initial Purchasers.
 Registration Statement No. 333-217143, Ex 4(c)-2

 4(f)2
 Supplement to Note Purchase Agreement, dated as of November 14, 2014 between AEP Transmission Company, LLC and the Initial Purchasers.
 Registration Statement No. 333-217143, Ex 4(c)-3

 Stock Purchase Agreement dated as of October 26, 2021 among AEP, AEPTCo and Liberty Utilities Co.
 Form 10-Q, Ex 10, dated September 30, 2021

 10(1)A
 First Amendment to Stock Purchase Agreement dated September 29, 2022 among AEP, AEPTCo and Liberty Utilities Co.
 Form 10-Q, Ex 10, dated September 30, 2022

 10(2)A
 Second Amendment to Stock Purchase Agreement dated January 16, 2023 among AEP, AEPTCo and Liberty Utilities Co.
 2023 Form 10-K, Ex 10(2)A

 10(3)
 Mutual Termination Agreement dated and effective April 17, 2023 among AEP, AEPTCo and Liberty Utilities Co. terminating the Stock Purchase Agreement dated October 26, 2021 the First Amendment to the Stock Purchase Agreement, dated as of September 29, 2022, and the Second Amendment to the Stock Purchase Agreement, dated as of January 16, 2023.
 Form 10-Q, Ex 10 dated June 30, 2023

 *23

 *24

 Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 E-6

 Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

 Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

 APCo File No. 1-3457

 3(a)
 Composite of the Restated Articles of Incorporation of APCo, amended as of March 7, 1997.
 1996 Form 10-K, Ex 3(d)

 3(b)
 Composite By-Laws of APCo, amended as of February 26, 2008.
 2007 Form 10-K, Ex 3(b)

 4(a)
 Indenture (for unsecured debt securities), dated as of January 1, 1998, between APCo and The Bank of New York, As Trustee.
 Registration Statement No. 333-45927, Ex 4(a)(b)
 Registration Statement No. 333-49071, Ex 4(b)
 Registration Statement No. 333-84061, Ex 4(b)(c)
 Registration Statement No. 333-100451, Ex 4(b)
 Registration Statement No. 333-116284, Ex 4 (b)(c)
 Registration Statement No. 333-123348, Ex 4 (b)(c)
 Registration Statement No. 333-136432, Ex 4 (b)(c)(d)
 Registration Statement No. 333-161940, Ex 4 (b)(c)(d)
 Registration Statement No. 333-182336, Ex 4 (b)(c)
 Registration Statement No. 333-200750, Ex 4 (b)(c)
 Registration Statement No. 333-214448, Ex 4(b)
 Registration Statement No. 333-236613, Ex 4 (b)(c)
 Registration Statement No 333-268874, Ex 4 (b)(c)(d)(e)

 10(a)
 Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended September 10, 2010.
 2013 Form 10-K, Ex 10(a)

 10(b)
 Consent Decree with U.S. District Court dated October 9, 2007, as modified July 17, 2019.
 Form 8-K, Ex. 10 dated October 9, 2007
 Form 10-Q, Ex 10, June 30, 2013
 Form 10-Q, Ex 10, June 30, 2019

 E-7

 *23

 *24

 Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

 Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

 I&M File No. 1-3570

 3(a)
 Composite of the Amended Articles of Acceptance of I&M, dated of March 7, 1997.
 1996 Form 10-K, Ex 3(c)

 3(b)
 Composite By-Laws of I&M, amended as of February 26, 2008.
 2007 Form 10-K, Ex 3(b)

 Indenture (for unsecured debt securities), dated as of October 1, 1998, between I&M and The Bank of New York, as Trustee.
 Registration Statement No. 333-88523, Ex 4(a)(b)(c)
Registration Statement No. 333-58656, Ex 4( b)( c)
Registration Statement No. 333-108975, Ex 4( b)( c)( d)
Registration Statement No. 333-136538, Ex 4( b)( c)
 Registration Statement No. 333-156182, Ex 4(b)
Registration Statement No. 333-185087, Ex 4(b)
 Registration Statement No. 333-207836, Ex 4(b)
 Registration Statement No. 333-225103, Ex 4( b)( c)( d)
 Registration Statement No. 333-268880 Ex. 4 (b)(c)

 4(a)
 Company Order and Officer's Certificate between I&M and The Bank of New York Mellon Trust Company, N.A. as Trustee dated March 23, 2023 establishing terms of the 5.625% Senior Notes, Series P, due 2053.
 Form 8-K, Ex 4(a) dated March 23, 2023.

 E-8

 10(a)
 Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended September 10, 2010.
 2013 Form 10-K, Ex 10(a)

 10(b)
 Unit Power Agreement dated as of March 31, 1982 between AEGCo and I&M, as amended.
 Registration Statement No. 33-32752, Ex 28(b)(1)(A)(B)

 10(c)
 Consent Decree with U.S. District Court dated October 9, 2007, as modified July 17, 2019.
 Form 8-K, Ex. 10 dated October 9, 2007
 Form 10-Q, Ex 10, June 30, 2013
 Form 10-Q, Ex 10, June 30, 2019

 *23

 *24

 Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

 Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

 OPCo File No. 1-6543

 3(a)
 Composite of the Amended Articles of Incorporation of OPCo, dated June 3, 2002.
 Form 10-Q, Ex 3(e), June 30, 2002

 3(b)
 Amended Code of Regulations of OPCo.
 Form 10-Q, Ex 3(b), June 30, 2008

 E-9

 4(a)
 Indenture (for unsecured debt securities), dated as of September 1, 1997, between OPCo and Bankers Trust Company (now The Bank of New York Mellon Trust Company, N.A. as assignee of Deutsche Bank Trust Company Americas), as Trustee.
 Registration Statement No. 333-49595, Ex 4(a)(b)(c)
Registration Statement No. 333-106242, Ex 4( b)( c)( d)
Registration Statement No. 333-127913, Ex 4( b)( c)
Registration Statement No. 333-139802, Ex 4( b)( c)( d)
Registration Statement No. 333-161537, Ex 4( b)( c)( d)
 Registration Statement No. 333-211192, Ex 4(b)
 Registration Statement No. 333-230094, Ex 4(b)
 Registration Statement No. 333-255600, Ex 4 (b)(c)(d)
 Registration Statement No. 333-275801, Ex 4 (b)

 4(a)1
 Resignation of Deutsche Bank Trust Company Americas, as Trustee and appointment of The Bank of New York Mellon Trust Company, N.A. as Trustee of Indenture with OPCo dated as of September 1, 1997.
 Form 8-K, Item 8.01 dated October 8, 2018

 4(a)2
 Company Order and Officer's Certificate between Ohio Power Company and The Bank of New York Mellon Trust Company, N.A. as Trustee dated September 9, 2021 establishing terms of the 2.90% Senior Notes, Series R, due 2051.
 Form 8-K, Ex 4(a) dated September 13, 2021

 4(b)
 Indenture (for unsecured debt securities), dated as of February 1, 2003, between OPCo and Bank One, N.A., as Trustee.
 Registration Statement No. 333-127913, Ex 4( d)( e)( f)

 4(c)
 Indenture (for unsecured debt securities), dated as of September 1, 1997, between CSPCo (predecessor in interest to OPCo) and Bankers Trust Company, as Trustee.
 Registration Statement No. 333-54025, Ex 4(a)(b)(c)(d)
Registration Statement No. 333-128174, Ex 4( b)( c)( d)
 Registration Statement No. 333-150603, Ex 4(b)

 4(d)
 Indenture (for unsecured debt securities), dated as of February 1, 2003, between CSPCo (predecessor in interest to OPCo) and Bank One, N.A., as Trustee.
 Registration Statement No. 333-128174, Ex 4( e)( f)( g)
 Registration Statement No. 333-150603, Ex 4(b)

 4(e)
 First Supplemental Indenture, dated as of December 31, 2011, by and between OPCo and The Bank of New York Mellon Trust Company, N.A., as trustee, supplementing the Indenture dated as of September 1, 1997 between CSPCo (predecessor in interest to OPCo) and the trustee.
 Form 8-K, Ex 4.1 dated January 6, 2012

 4(f)
 Third Supplemental Indenture, dated as of December 31, 2011, by and between OPCo and The Bank of New York Mellon Trust Company, N.A., as trustee, supplementing the Indenture dated as of February 14, 2003 between CSPCo (predecessor in interest to OPCo) and the trustee.
 Form 8-K, Ex 4.2 dated January 6, 2012

 10(a)
 Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring Companies, as amended September 10, 2010.
 2013 Form 10-K, Ex 10(a)

 10(b)
 Consent Decree with U.S. District Court dated October 9, 2007, as modified July 17, 2019.
 Form 8-K, Ex. 10 dated October 9, 2007
 Form 10-Q, Ex 10, June 30, 2013
 Form 10-Q, Ex 10, June 30, 2019

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 *24

 E-10

 Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

 Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

 PSO File No. 0-343

 3(a)
 Certificate of Amendment to Restated Certificate of Incorporation of PSO.
 Form 10-Q, Ex 3(a), June 30, 2008

 3(b)
 Composite By-Laws of PSO amended as of February 26, 2008.
 2007 Form 10-K, Ex 3 (b)

 4(a)
 Indenture (for unsecured debt securities), dated as of November 1, 2000, between PSO and The Bank of New York, as Trustee.
 Registration Statement No. 333-100623, Ex 4( a)( b)
Registration Statement No. 333-114665, Ex 4( b)( c)
Registration Statement No. 333-133548, Ex 4( b)( c)
Registration Statement No. 333-156319, Ex 4( b)( c)
 Registration Statement No. 333-251378, Ex 4 (b)(c)

 4(b)
 Tenth Supplemental Indenture between PSO and The Bank of New York Mellon Trust Company, N.A. as Trustee dated August 1, 2021 establishing terms of the 2.20% Senior Notes, Series J, due 2031 and the 3.15% Senior Notes Series K, due 2051.
 Form 8-K, Ex 4(a) dated August 12, 2021

 4(c)
 Eleventh Supplemental Indenture dated as of January 1, 2023 between PSO and The Bank of New York Mellon Trust Company, N.A.as Trustee establishing terms of 5.25% Senior Notes Series L due 2033.
 Form 8-K, Ex 4(a) dated January 5, 2023

 E-11

 4(d)
 Credit Agreement dated as of January 19, 2021 among PSO as Borrower, Initial Lenders and Sumitomo Mitsui Banking Corporation as Administrative Agent.

 2020 Form 10-K, Ex 4(d)

 4(d)A
 April 19, 2022 Amendment and extension to $500,000,000 Credit Agreement dated January 19, 2021 among PSO, Initial Lenders and Sumitomo Mitsui Banking Corporation as Administrative Agent.
 Form 10-Q Ex 4(c) dated March 31, 2022

 *24

 Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

 Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

 SWEPCo File No. 1-3146

 3(a)
 Composite of Amended Restated Certificate of Incorporation of SWEPCo.
 2008 Form 10-K, Ex 3(a)

 3(a)(A)
 Amendment to Amended Restated Certificate of Incorporation.
 Form 8-K Ex 3.1 dated September 1, 2020

 3(b)
 Composite By-Laws of SWEPCo amended as of February 26, 2008.
 2007 Form 10-K, Ex 3(b)

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 4(a)
 Indenture (for unsecured debt securities), dated as of February 4, 2000, between SWEPCo and The Bank of New York, as Trustee.
 Registration Statement No. 333-96213
 Registration Statement No. 333-87834, Ex 4( a)( b)
 Registration Statement No. 333-100632, Ex 4(b)
Registration Statement No. 333-108045, Ex 4(b)
 Registration Statement No. 333-145669, Ex 4( c)( d)
Registration Statement No. 333-161539, Ex 4( b)( c)
Registration Statement No. 333-194991, Ex 4( b)( c)
Registration Statement No. 333-208535, Ex 4( b)( c)
 Registration Statement No. 333-226856, Ex 4( b)( c)
 Registration Statement No. 333-238159, Ex 4(b) Registration Statement No. 333-258961, Ex 4(a)(b)

 4(b)
 Fifteenth Supplemental Indenture dated November 1, 2021 between SWEPCo and The Bank of New York Mellon Trust Company, N.A. as Trustee establishing terms of 3.25% Senior Notes Series O due 2051.
 Form 8-K, Ex 4(a) dated November 3, 2021

 4(c)
 Sixteenth Supplemental Indenture dated March 1, 2023 between SWEPCo and The Bank of New York Mellon Trust Company, N.A. as Trustee establishing terms of 5.30% Senior Notes Series P due 2033.
 Form 8-K, Ex 4(a) dated March 28, 2023

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 *24

 Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

 Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

 Certain instruments defining the rights of holders of long-term debt of the registrants included in the financial statements of registrants filed herewith have been omitted because the total amount of securities authorized thereunder does not exceed 10% of the total assets of registrants. The registrants hereby agree to furnish a copy of any such omitted instrument to the SEC upon request.

 E-13

 The agreements and other documents filed as exhibits to this report are not intended to provide factual information or other disclosure other than with respect to the terms of the agreements or other documents themselves, and you should not rely on them for that purpose. In particular, any representations and warranties made by us in these agreements or other documents were made solely within the specific context of the relevant agreement or document and may not describe the actual state of affairs as of the date they were made or at any other time.
 E-14