0000004904us-gaap:CorporateDebtSecuritiesMember2023-03-310000004904aep:A23YearsMemberaep:AppalachianPowerCoMember2023-03-31RelatedPartyMember2022-07-012022-09-300000004904aep:UtilityMemberaep:SouthwesternElectricPowerCoMember2023-03-152023-03-15




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

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended March 31,September 30, 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
333-221643AEP TEXAS INC.Delaware51-0007707
333-217143 AEP TRANSMISSION COMPANY, LLCDelaware 46-1125168
1-3457 APPALACHIAN POWER COMPANYVirginia 54-0124790
1-3570 INDIANA MICHIGAN POWER COMPANYIndiana 35-0410455
1-6543 OHIO POWER COMPANYOhio 31-4271000
0-343 PUBLIC SERVICE COMPANY OF OKLAHOMAOklahoma 73-0410895
1-3146 SOUTHWESTERN ELECTRIC POWER COMPANYDelaware 72-0323455
  1 Riverside Plaza,Columbus,Ohio43215-2373  
  Telephone(614)716-1000  

Securities registered pursuant to Section 12(b) of the Act:
Registrant Title of each class Trading SymbolName of Each Exchange on Which Registered
American Electric Power Company Inc. Common Stock, $6.50 par value AEPThe NASDAQ Stock Market LLC
American Electric Power Company Inc.6.125% Corporate UnitsAEPPZThe NASDAQ Stock Market LLC
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
YesxNo
Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit such files).
YesxNo
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 filerxAccelerated filerNon-accelerated filer
      
Smaller reporting companyEmerging 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 filerAccelerated filerNon-accelerated filerx
      
Smaller reporting companyEmerging growth company 
If an emerging growth company, indicate by check mark if the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).YesNox
AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.




Number of shares
of common stock
outstanding of the
Registrants as of
May 4,November 2, 2023
 
American Electric Power Company, Inc.514,790,910525,875,633 
 ($6.50 par value)
AEP Texas Inc.100 
($0.01 par value)
AEP Transmission Company, LLC (a)NA
Appalachian Power Company13,499,500 
 (no par value)
Indiana Michigan Power Company1,400,000 
 (no par value)
Ohio Power Company27,952,473 
 (no par value)
Public Service Company of Oklahoma9,013,000 
 ($15 par value)
Southwestern Electric Power Company3,680 
 ($18 par value)

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




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF QUARTERLY REPORTS ON FORM 10-Q
March 31,September 30, 2023
   
  Page
  Number
Glossary of Terms
   
Forward-Looking Information
   
Part I. FINANCIAL INFORMATION
   
 Items 1, 2, 3 and 4 - Financial Statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosures About Market Risk and Controls and Procedures:
   
American Electric Power Company, Inc. and Subsidiary Companies: 
 Management’s Discussion and Analysis of Financial Condition and Results of Operations
 Condensed Consolidated Financial Statements
   
AEP Texas Inc. and Subsidiaries:
Management’s Narrative Discussion and Analysis of Results of Operations
Condensed Consolidated Financial Statements
AEP Transmission Company, LLC and Subsidiaries: 
 Management’s Narrative Discussion and Analysis of Results of Operations
 Condensed Consolidated Financial Statements
Appalachian Power Company and Subsidiaries: 
 Management’s Narrative Discussion and Analysis of Results of Operations
 Condensed Consolidated Financial Statements
   
Indiana Michigan Power Company and Subsidiaries: 
 Management’s Narrative Discussion and Analysis of Results of Operations
 Condensed Consolidated Financial Statements
   
Ohio Power Company and Subsidiaries: 
 Management’s Narrative Discussion and Analysis of Results of Operations
 Condensed Consolidated Financial Statements
   
Public Service Company of Oklahoma: 
 Management’s Narrative Discussion and Analysis of Results of Operations
 Condensed Financial Statements
   
Southwestern Electric Power Company Consolidated: 
 Management’s Narrative Discussion and Analysis of Results of Operations
 Condensed Consolidated Financial Statements
   
Index of Condensed Notes to Condensed Financial Statements of Registrants
   
Controls and Procedures




Part II.  OTHER INFORMATION 
     
 Item 1.  Legal Proceedings
 Item 1A.  Risk Factors
 Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds
Item 3.  Defaults Upon Senior Securities
 Item 4.  Mine Safety Disclosures
 Item 5.  Other Information
 Item 6.  Exhibits
     
SIGNATURE  
     
     
This combined Form 10-Q is separately filed by American Electric Power Company, Inc., AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company.  Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Except for American Electric Power Company, Inc., each registrant makes no representation as to information relating to the other registrants.




GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below. 
TermMeaning
   
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 Energy Supply LLCA nonregulated holding company for AEP’s competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP.
AEP RenewablesA 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.counterparties.
AEP System American Electric Power System, an electric system, owned and operated by AEP subsidiaries.
AEP TexasAEP Texas Inc., an AEP electric utility subsidiary.
AEP Transmission Holdco AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of AEP.
AEPEPAEP 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.
AEPTCoAEP Transmission Company, LLC, a wholly-owned subsidiary of AEP Transmission Holdco, is an intermediate holding company that owns the State Transcos.
AEPTCo ParentAEP Transmission Company, LLC, the holding company of the State Transcos within the AEPTCo consolidation.
AFUDCAllowance for Equity Funds Used During Construction.
ALJAdministrative Law Judge.
AOCI Accumulated Other Comprehensive Income.
APCo Appalachian Power Company, an AEP electric utility subsidiary.
Appalachian Consumer Rate Relief FundingAppalachian Consumer Rate Relief Funding LLC, a wholly-owned subsidiary of APCo and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to the under-recovered Expanded Net Energy Cost deferral balance.
Apple BlossomApple Blossom Wind Holdings LLC, a consolidated VIE of AEP, and tax equity partnership.
APSCArkansas Public Service Commission.
AROAsset Retirement Obligations.
ATMAt-the-Market.
Black OakBlack Oak Getty Wind Holdings LLC, a consolidated VIE of AEP, and tax equity partnership.
CAAClean Air Act.
CCRCoal Combustion Residual.
CO2
 Carbon dioxide and other greenhouse gases.
CO2e
Carbon dioxide equivalent.
Cook PlantDonald C. Cook Nuclear Plant, a two-unit, 2,296 MW nuclear plant owned by I&M.
i



TermMeaning
   
Cook PlantDonald C. Cook Nuclear Plant, a two-unit, 2,296 MW nuclear plant owned by I&M.
COVID-19Coronavirus 2019, a highly infectious respiratory disease. In March 2020, the World Health Organization declared COVID-19 a worldwide pandemic.
CSAPRCross-State Air Pollution Rule.
CWIP Construction Work in Progress.
DCC FuelDCC Fuel XIII, DCC Fuel XIV, DCC Fuel XV, DCC Fuel XVI, DCC Fuel XVII and DCC Fuel XVIII, consolidated VIEs formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
DHLC Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo. DHLC is a non-consolidated VIE of SWEPCo.
DIRDistribution Investment Rider.
Dry LakeDry Lake Solar Project, a consolidated VIE whose sole purpose is to own and operate a 100 MW solar generation facility in southern Nevada in which AEP owns a 75% interest.
EISEnergy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated VIE of AEP.
ELGEffluent Limitation Guidelines.
ENECExpanded Net Energy Cost.
Energy SupplyAEP Energy Supply LLC, a nonregulated holding company for AEP’s competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP.
Equity UnitsAEP’s Equity Units issued in August 2020.
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.
ETTElectric 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 ADITExcess accumulated deferred income taxes.
FACFuel Adjustment Clause.
FASB Financial Accounting Standards Board.
Federal EPAUnited States Environmental Protection Agency.
FERC Federal Energy Regulatory Commission.
FGD Flue Gas Desulfurization or scrubbers.
FIPFederal Implementation Plan.
FTRFinancial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP Accounting Principles Generally Accepted in the United States of America.
I&M Indiana Michigan Power Company, an AEP electric utility subsidiary.
IRAOn August 16, 2022 President Biden signed into law legislation commonly referred to as the “Inflation Reduction Act” (IRA).
IRS Internal Revenue Service.
ITCInvestment Tax Credit.
IURCIndiana Utility Regulatory Commission.
KGPCoKingsport Power Company, an AEP electric utility subsidiary.
KPCo Kentucky Power Company, an AEP electric utility subsidiary.
KPSCKentucky Public Service Commission.
KTCoAEP Kentucky Transmission Company, Inc., an affiliate of KPCo and a wholly-owned subsidiary of AEP.
KWhKilowatt-hour.
ii



TermMeaning
   
KPSCKentucky Public Service Commission.
KTCoAEP Kentucky Transmission Company, Inc., an affiliate of KPCo and a wholly-owned subsidiary of AEP.
KWhKilowatt-hour.
LPSC Louisiana Public Service Commission.
MATSMercury and Air Toxic Standards.
MaverickMaverick, part of the North Central Wind Energy Facilities, consists of 287 MWs of wind generation in Oklahoma.
MISO Midcontinent Independent System Operator.
Mitchell PlantA 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.
MPSCMichigan Public Service Commission.
MTM Mark-to-Market.
MW Megawatt.
MWh Megawatt-hour.
NAAQSNational Ambient Air Quality Standards.
Nonutility Money Pool Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
NCWFNorth Central Wind Energy Facilities, a joint PSO and SWEPCo project, which includes three Oklahoma wind facilities totaling approximately 1,484 MWs of wind generation.
NOLCNet Operating Loss Carryforward.
NOx
Nitrogen oxide.
OCC Corporation Commission of the State of Oklahoma.
OHTCoAEP Ohio Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.
OPCo Ohio Power Company, an AEP electric utility subsidiary.
OPEB Other Postretirement Benefits.
OTC Over-the-counter.
OVEC Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
ParentAmerican Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.
PJM Pennsylvania – New Jersey – Maryland regional transmission organization.
PM Particulate Matter.
PPAPurchase Power and Sale Agreement.
PSAPurchase and Sale Agreement.
PSO Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PTCProduction 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.
RegistrantsSEC registrants: AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
iii


TermMeaning
Restoration FundingAEP 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.
iii



TermMeaning
Risk Management Contracts Trading and non-trading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport PlantA generation plant, jointly owned by AEGCo and I&M, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana.
ROEReturn on Equity.
RPMReliability 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 EastSanta 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.
SECU.S. Securities and Exchange Commission.
SIPState Implementation Plan.
SNF Spent Nuclear Fuel.
SO2
 Sulfur dioxide.
SPP Southwest Power Pool regional transmission organization.
State TranscosAEPTCo’s seven wholly-owned, FERC regulated, transmission only electric utilities, which are geographically aligned with AEP’s existing utility operating companies.
SundanceSundance, acquired in April 2021 as part of the North Central Wind Energy Facilities, consists of 199 MWs of wind generation in Oklahoma.
SWEPCo Southwestern Electric Power Company, an AEP electric utility subsidiary.
Tax ReformOn December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal Revenue Code of 1986, including a reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018.
Transition Funding AEP Texas Central Transition Funding III LLC, a wholly-owned subsidiary of AEP Texas and consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation.
Transource EnergyTransource 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.
TraverseTraverse, 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.
UPAUnit Power Agreement.
Utility Money Pool Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
VIEVariable Interest Entity.
Virginia SCC Virginia State Corporation Commission.
WPCo Wheeling Power Company, an AEP electric utility subsidiary.
WVPSCPublic Service Commission of West Virginia.

iv



FORWARD-LOOKING INFORMATION

This report made by the Registrants contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.  Many forward-looking statements appear in “Part I – Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this quarterly report, but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook.  These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected.  Forward-looking statements in this document are presented as of the date of this document.  Except to the extent required by applicable law, management undertakes no obligation to update or revise any forward-looking statement.  Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:
Changes in economic conditions, electric market demand and demographic patterns in AEP service territories.
The impact of pandemics and any associated disruption of AEP’s business operations due to impacts on economic or market conditions, costs of compliance with potential government regulations, electricity usage, supply chain issues, customers, service providers, vendors and suppliers.
The economic impact of increased global trade tensions including the conflict between Russiaconflicts in Ukraine and Ukraine,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 or tax credits, 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.
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.litigation or regulatory proceedings or investigations.
The ability to constrain operation and maintenance costs.
v


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



Changes in technology, particularly with respect to energy storage and new, developing, alternative or distributed sources of generation.
The ability to recover through rates any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives.
Volatility and changes in markets for coal and other energy-related commodities, particularly changes in the price of natural gas.
The impact of changing expectations and demands of customers, regulators, investors and stakeholders, including heightened emphasis on environmental, social and governance concerns.
Changes in utility regulation and the allocation of costs within RTOs including ERCOT, PJM and SPP.
Changes in the creditworthiness of the counterparties with contractual arrangements, including participants in the energy trading market.
Actions of rating agencies, including changes in the ratings of debt.
The impact of volatility in the capital markets on the value of the investments held by the pension, OPEB, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements.
Accounting standards periodically issued by accounting standard-setting bodies.
Other risks and unforeseen events, including wars and military conflicts, the effects of terrorism (including increased security costs), embargoes, naturally occurring and human-caused fires,wildfires, cyber-security threats and other catastrophic events.
The ability to attract and retain the requisite work force and key personnel.

The forward-looking statements of the Registrants speak only as of the date of this report or as of the date they are made.  The Registrants expressly disclaim any obligation to update any forward-looking information, except as required by law.  For a more detailed discussion of these factors, see “Risk Factors” in Part I of the 2022 Annual Report and in Part II 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-Q. 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.
vi





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

EXECUTIVE OVERVIEW

AEP Consolidated Earnings Attributable to Common Shareholders

Third Quarter of 2023 Compared to Third Quarter of 2022

Earnings Attributable to AEP Common Shareholders increased from $684 million in 2022 to $954 million in 2023 primarily due to:

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.

These increases were partially offset by:

A decrease in weather-related sales volumes.
An increase in interest expense due to higher interest rates and debt balances.
A gain on the sale of mineral rights in 2022.

Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022

Earnings Attributable to AEP Common Shareholders decreased from $1,923 million in 2022 to $1,872 million 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.
A gain on the sale of mineral rights in 2022.

These decreases were partially offset by:

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.
1


Customer Demand

AEP’s weather-normalized retail sales volumes for the firstthird quarter of 2023 increased by 3.3%2.1% from the firstthird quarter of 2022. Weather-normalized residential sales decreasedincreased by 1.4%0.6% in the firstthird quarter of 2023 from the firstthird quarter of 2022. This increase was primarily due to an increase in the number of residential customers served. Weather-normalized commercial sales increased 7.8%by 7.5% in the firstthird quarter of 2023 fromcompared to the firstthird quarter of 2022. The increase in commercial sales was primarily due to new data center loads.loads and economic development. AEP’s firstthird quarter 2023 industrial sales volumes decreased by 1.1% from the third quarter of 2022. The decrease in industrial sales was primarily due to declines in the non-Oil and Gas sectors.

AEP’s weather-normalized retail sales volumes for the nine months ended September 30, 2023 increased by 5.1%2.3% compared to the first quarter ofnine months ended September 30, 2022. Weather-normalized residential sales decreased by 0.9% for the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022. This decrease was primarily due to a reduction in usage per customer. Weather-normalized commercial sales increased by 7.7% for the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022. The increase in commercial sales was primarily due to new data center loads and economic development. AEP’s industrial sales volumes for the nine months ended September 30, 2023 increased by 1.3% compared to the nine months ended September 30, 2022. The increase in industrial sales was spread across many sectors.

Supply Chain Disruption and Inflation

The Registrants have experienced certain supply chain disruptions driven by several factors including staffing and travel issues caused by the COVID-19 pandemic, international tensions including the ramifications of regional conflict, increased demand due to the economic recovery from the pandemic, inflation, labor shortages in certain trades and shortages in the availability of certain raw materials. These supply chain disruptions have not had a material impact on the Registrants net income, cash flows and financial condition, but have extended lead times for certain goods and services and have contributed to higher prices for fuel, materials, labor, equipment and other needed commodities. Management has implemented risk mitigation strategies in an attempt to mitigate the impacts of these supply chain disruptions.

AEP and its utilities finance its operations with commercial paper and other variable rate instruments thatinstruments. AEP generally uses short-term borrowings to fund working capital needs until long-term funding is arranged. Sources of long-term funding includes the issuance of long-term debt. These financing options to maintain adequate liquidity are subject to fluctuations in interest rates. The United States economy has experienced a significant level of inflation that has contributed to increased uncertainty in the outlook of near-term economic activity, including whether inflation will continue and at what rate. To the extent that the Federal Reserve continuesinterest rates continue to raise short-term interest rates,increase, it could reduce future net income and cash flows and impact financial condition.

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.

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.


1



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.As a result of the March 2023 filings made by intervenors with the FERC and the Termination Agreement, the assets and liabilities of KPCo and KTCo were reclassified out of Held for Sale on the March 31, 2023 and December 31, 2022 balance sheets of AEP and AEPTCo.

The impact of the Termination Agreement did not have a material impact on AEP’s statements of income for the three months ended March 31, 2023. Upon reverting to a held and used model, AEP is required to present its investment in the Kentucky Operations at the lower of fair value or historical carrying value. As a result, AEP’s March 31, 2023 and December 31, 2022 balance sheets reflect a $335 million and $363 million, respectively, pretax reduction in the basis of its investment in KPCo’s assets which is recorded in Property, Plant and Equipment. The change in AEP’s basis of its investment in KPCo’s assets from December 31, 2022 to March 31, 2023 reflects the elimination of the expected costs to sell from the measurement.

Planned 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. As of March 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 towith a nonaffiliated party for $1.5 billion including the assumption of project debt.party. AEP recorded a pretax loss of $112 million ($88 million after-tax), in the first quarter of 2023 as a result ofafter reaching Held for Sale status. Management concludedstatus and determining the impact of any other than temporary decline in the faircarrying value of the four joint venture wind farms was not materialportfolio exceeded the estimated fair value.
In August 2023, AEP completed the sale of the entire portfolio to AEP’s March 31, 2023 financial statements.the nonaffiliated party and received cash proceeds of approximately $1.2 billion, net of taxes and transaction costs. See the "Assets and Liabilities Held for Sale""Disposition of the Competitive Contracted Renewables Portfolio" section of Note 6 for additional information.


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Planned Sale of AEP Energy and AEP Onsite Partners

ManagementAEP management has continued a strategic evaluation of the businessAEP’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 recently 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 752,000900,000 customer accounts as of March 31,September 30, 2023. In April 2023, AEP management completed the strategic evaluation of AEP Energy and initiated a sale process. The timing of the completion of the sales process is dependent upon a number of factors. AEP is currently estimatestargeting the salesales process for these businesses willto be completed byin the first half of 2024. Depending on the outcome of the sales process, it could reduce future net income and impact financial condition.


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AEP Onsite Partners

In April 2023, AEP also made a decision to include AEP Onsite Partners in a sale 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 March 31,September 30, 2023, AEP OnSite Partners owned projects located in 22 states, including approximately 168193 MWs of installed solar capacity and approximately 262 MWs of solar projects under construction. As of March 31,September 30, 2023, the net book value of these assets was $350$353 million. The timing of the completion of the sales process is dependent upon a number of factors. AEP is currently estimatestargeting the salesales process for these businesses willto be completed byin the first half of 2024.

AEP Onsite Partners also owns a 50% interest in NM Renewable Development, LLC, (NMRD) totaling $102$119 million accounted for as an equity method investment. The NMRD owns 8portfolio consists of 9 operating solar projects totaling 135185 MWs one 50 MW project is under construction and has 6 projects totaling 440 MWs in development. Separate from the remainder of AEP Onsite Partners, AEP and the joint owner have agreed to initiate a separatejoint sales process for their respective interests in NMRD. The timing of the completion of the sales process is dependent upon a number of factors. AEP is currently estimatestargeting the salesales process for these businesses willto be completed in the fourth quarter of 2023.2023 or early 2024.

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.

Planned Sale and Strategic Evaluation of Certain Transmission Joint Ventures

In April 2023, AEP also initiated a strategic evaluation for its ownership ofin 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. As of March 31,September 30, 2023, AEP’s investment in Pioneer Transmission, LLC, and Prairie Wind Transmission, LLC was $48 million and $19 million, respectively.

As of September 30, 2023, the net book value of Transource Energy was $272$286 million inclusive of $37$39 million related to noncontrolling interest on AEP’s balance sheet. As of March 31, 2023, AEP held investments in Pioneer Transmission, LLC, and Prairie Wind Transmission, LLC of $48 million and $20 million, respectively.

Potential alternatives may include continued ownership or a sale of all or certain of these joint ventures. Managementsale. AEP management has not made a decision regarding the potential alternatives, but expects to complete the strategic evaluation by the end of 2023.



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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,June 2023, the IRS released Notice 2023-7 addressing time sensitive issuesissued temporary regulations related to the CAMT. The notice provided initial guidance thattransfer of tax credits. In the third quarter of 2023, AEP, can beginon behalf of PSO and SWEPCo, entered into a transferability agreement with a nonaffiliated party to rely onsell PTCs resulting in 2023 and also stated that additional guidance iscash proceeds of approximately $80 million expected in the fourth quarter of which2023. AEP willexpects to continue to monitor and assess. Notably,explore the interim guidance in Notice 2023-7 confirmed the CAMT depreciation adjustment includesability to efficiently monetize its 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.credits through third party transferability agreements. See Note 11 - Income Taxes for additional information.

AEPTermination of Planned Disposition of KPCo 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 will be presented in the operating section of the statements of cash flows consistent with the presentation of cash taxes paid. AEP will present the gain or loss on sale of tax credits through income tax expense.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.
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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.

The impact of the Termination Agreement did not have a material impact on AEP’s statements of income for the three and nine months ended September 30, 2023. Upon reverting to a held and used model in the first quarter of 2023, AEP 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.

Regulatory Matters

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

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 major storm costs for severe weather events. As of March 31, 2023, APCo deferred approximately $38 million related to previously incurred major storm costs as a result of APCo’s calculation of Virginia earnings below the bottom of its authorized ROE band during the 2020-2022 Triennial Review period. Any APCo Virginia jurisdictional costs that are not recoverable or any refunds of revenues collected from customers during the triennial review period that are ordered by the Virginia SCC for the 2020-2022 Triennial Review period could reduce future net income and cash flows and impact financial condition.

2012 Texas Base Rate Case - In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. In 2017, the Texas District Court upheld the PUCT’s 2014 order and intervenors filed appeals with the Texas Third Court of Appeals. In July 2018, the Texas Third Court of Appeals reversed the PUCT’s judgment affirming the prudence of the Turk Plant and remanded the issue back to the PUCT. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court.

In March 2021, the Texas Supreme Court issued an opinion reversing the July 2018 judgment of the Texas Third Court of Appeals and agreeing with the PUCT’s judgment affirming the prudence of the Turk Plant. In addition, the Texas Supreme Court remanded the AFUDC dispute back to the Texas Third Court of Appeals. No parties filed a motion for rehearing with the Texas Supreme Court. In August 2021, the Texas Third Court of Appeals reversed the Texas District Court judgment affirming the PUCT’s order on AFUDC, concluding that the language of the PUCT’s original 2008 order intended to include AFUDC in the Texas jurisdictional capital cost cap, and remanded the case to the PUCT for future proceedings. SWEPCo disagrees with the Court of Appeals decision.In
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November 2021, SWEPCo and the PUCT submitted Petitions for Review with the Texas Supreme Court in November 2021.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 AprilJune 2023, SWEPCo and the PUCT filed replies to parties’ responses to the requests for rehearing. IfTexas Supreme Court denied SWEPCo’s request for rehearing is denied,and the case will bewas remanded to the PUCT for future proceedings.
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In October 2023, SWEPCo filed testimony with the PUCT in the remanded proceeding recommending no refund or disallowance.

Management does not believe a disallowance of capitalized Turk Plant costs or a revenue refund is probable as of March 31,September 30, 2023. However, if SWEPCo is ultimately unable to recover AFUDC in excess of the Texas jurisdictional capital cost cap, it would be expected to result in a pretax net disallowance ranging from $80 million to $90 million. In addition, if AFUDCSWEPCo is ultimately determinedunable to be includedrecover AFUDC in excess of the Texas jurisdictional capital cost cap, SWEPCo estimates it may be required to make customer refunds, including interest, ranging from $0 to $190$200 million related to revenues collected from February 2013 through MarchSeptember 2023 and such determination may reduce SWEPCo’s future revenues by approximately $15 million on an annual basis.

In July 2019,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.

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

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


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

Transmission Formula Rate Challenge2021 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. SWEPCo will submit additional information in phase two of this proceeding to determine whether securitization of the costs is more cost effective than recovery through typical ratemaking. In April 2023, the LPSC issued an order approving the stipulation and settlement agreement.

In MarchMay 2023, certain joint customers submitted a complaint and a formal challenge at the FERC related to the 2022 Annual Update of the 2021 PJM Transmission Formula Rates of the AEP transmission owning subsidiaries within PJM. This challengePJM and SPP, respectively. These challenges primarily relatesrelate to stand-alone treatment of NOLCs in the transmission formula rates of the AEP transmission owning subsidiaries within PJM. In April 2023,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.FERC in the second quarter of 2023.

AEP
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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 NOLCs for transmission formula rates increased the annual revenue requirements for years 2023, 2022 and 2021 by $60 million, $60$69 million and $78 million, respectively (of which $40 million, $53 million, and $56 million relate to PJM transmission formula rates, respectively).respectively. Through the firstthird quarter of 2023, AEP’sthe Registrants’ financial statements reflect a provision for refund for certain NOLC revenues billed by PJM and SPP. Also, a certain portion of the impact of inclusion of NOLCs in the 2021 annual formula rate true-up not yet billed by PJM and SPP is not reflected in the Registrants’ revenues and expenses asIf the Registrants have not met the requirementsare required to make refunds as a result of alternative revenue recognition in accordance with the accounting guidance for “Regulated Operations”.these challenges, it could reduce future net income and cash flows and impact financial condition.

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

Securitization Legislation - In March 2023, Kentucky (Senate Bill 192) and West Virginia (House Bill 3308) both passed legislation that would allow the securitization of certain plant assets. Eligible costs to be securitized in Kentucky include certain retired generation costs with a minimum value of $200 million as well as certain other regulatory assets, including deferred extraordinary storm costs, as long as the cumulative total requested for securitization is at least $275 million. Eligible costs to be securitized in West Virginia include historical, and if deemed appropriate by the commission, projected costs relating to environmental control costs, expanded net energy costs, storm recovery costs and undepreciated generation utility plant balances.

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In April 2023, APCo and WPCo submitted their 2023 annual ENEC filing with the WVPSC proposing two alternatives to increase ENEC rates effective September 1, 2023. One of the alternatives included an option to securitize approximately $1.9 billion of assets. In June 2023, KPCo filed a request with the KPSC requesting to finance, through the issuance of securitization bonds, approximately $471 million of regulatory assets. See Note 4 - Rate Matters for additional information.

In April 2023, the Virginia General Assembly approved the Governor’s proposed changes to House Bill 1777, modifying APCo’s earnings review and base rate process, with a biennial earnings review replacing APCo’s current triennial earnings review. APCo will submit its first biennial review filing in 2024 using only a 2023 test year. Also included in this approved legislation is the option for APCo to securitize deferred fuel costs.

Texas Legislation - In May 2023, legislation (Senate Bill 1016) was passed in Texas allowing certain financially based employee incentive compensation to be recovered. As a result of this law change, in the second quarter of 2023 AEP Texas and SWEPCo recognized a favorable impact to pretax income of approximately $27 million and $6 million, respectively.


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Utility Rates and Rate Proceedings

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

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


Completed Base Rate Case Proceedings

Approved RevenueApprovedNew Rates
CompanyJurisdictionRequirement IncreaseROEEffective
(in millions)
SWEPCoLouisiana$21.0 (a)9.5%February 2023

(a)See “2020 Louisiana Base Rate Case” section of Note 4 in the 2022 Annual Report for additional information.

Pending Base Rate Case Proceedings
Commission Staff/Commission Staff/
FilingRequested RevenueRequestedIntervenor Range ofFilingRequested RevenueRequestedIntervenor Range of
CompanyCompanyJurisdictionDateRequirement IncreaseROERecommended ROECompanyJurisdictionDateRequirement IncreaseROERecommended ROE
(in millions)(in millions)
PSOPSOOklahomaNovember 2022$173.0 10.4%8.6%-9.5%PSOOklahomaNovember 2022$173.0 (a)10.4%8.6%-9.5%
APCoAPCoVirginiaMarch 2023213.0 10.6%(a)APCoVirginiaMarch 2023213.0 10.6%9.5%
KPCoKPCoKentuckyJune 202394.0 9.9%9.3%-9.7%
I&MI&MIndianaAugust 2023116.0 10.5%(b)
I&MI&MMichiganSeptember 202334.0 10.5%(c)
(a)Intervenor testimonyRequested revenue requirement increase, net of existing rider revenues and certain incremental renewable facility benefits expected to be filedprovided to customers through riders. See “2022 Oklahoma Base Rate Case” section of Note 4 for additional information.
(b)Intervenor testimony is due in the third quarter ofNovember 2023.
(c)Intervenor testimony is due in January 2024.


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Deferred Fuel Costs

IncreasedIncreases in fuel and purchased power prices in excess of amounts included in fuel-related revenues has led to an increase in the under collection of fuel costs from customers in most jurisdictions.jurisdictions in recent years. The table below illustrates the increase (decrease) in the deferred fuel regulatory assets by company and jurisdiction, excluding the impacts of the February 2021 severe winter weather event. See the “February 2021 Severe Winter Weather Impacts in SPP” sectionssection in Note 4 for additional information. If any of these deferred fuel costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Traditional FACAs ofAs ofIncrease/Traditional FACAs ofAs ofIncrease/
CompanyCompanyJurisdictionRecovery ResetMarch 31, 2023December 31, 2022(Decrease)CompanyJurisdictionRecovery ResetSeptember 30, 2023December 31, 2022(Decrease)
(in millions)
APCoAPCoVirginia (a)Annually$375.7 $407.9 $(32.2)APCoVirginia (a)Annually$286.9 $407.9 $(121.0)
APCoAPCoWest VirginiaAnnually294.8 288.5 6.3 APCoWest VirginiaAnnually301.3 288.5 12.8 
I&MI&MIndianaBi-Annually33.3 38.1 (4.8)I&MIndianaBi-Annually— 38.1 (38.1)
I&MI&MMichiganAnnually10.0 9.0 1.0 I&MMichiganAnnually13.3 9.0 4.3 
PSOPSOOklahoma (b)Annually382.1 431.5 (49.4)PSOOklahoma (b)Annually168.2 431.5 (263.3)
SWEPCoSWEPCoArkansasAnnually45.7 65.8 (20.1)SWEPCoArkansasAnnually30.0 65.8 (35.8)
SWEPCoSWEPCoTexasTri-Annually186.8 191.4 (4.6)SWEPCoTexas (c)Tri-Annually134.7 191.4 (56.7)
KPCoKPCoKentuckyMonthly5.5 23.2 (17.7)KPCoKentuckyMonthly6.3 23.2 (16.9)
WPCoWPCoWest VirginiaAnnually244.2 231.1 13.1 WPCoWest VirginiaAnnually273.5 231.1 42.4 
Total$1,578.1 $1,686.5 $(108.4)Total$1,214.2 $1,686.5 $(472.3)

(a)Includes $96$146 million and $223 million as of March 31,September 30, 2023 and December 31, 2022, respectively, of noncurrent deferred fuel classified as a Regulatory Asset on APCo’s balance sheets.
(b)Includes $203 million$0 and $253 million as of March 31,September 30, 2023 and December 31, 2022, respectively, of noncurrent deferred fuel classified as a Regulatory Asset on PSO’s balance sheets.
(c)Includes $74 million and $0 as of September 30, 2023 and December 31, 2022, respectively, of noncurrent deferred fuel classified as a Regulatory Asset on SWEPCo’s balance sheets.

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

In April 2022, APCo and WPCo (the Companies) submitted their 2022 annual ENEC filing with the WVPSC requesting a $297 million annual increase in ENEC revenues, effective September 1, 2022. In February 2023, the WVPSC issued an order stating that the commission will not grant additional rate increases for fuel costs until the WVPSC staff completes its prudency review. In April 2023, the Companies submitted their 2023 annual ENEC filing with the WVPSC, proposing two alternatives to increase ENEC rates effective September 1, 2023. The first alternative is a $293 million annual increase in ENEC rates comprised of a $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 is a $89 million annual increase in ENEC rates with the Companies securitizing approximately $553 million relating to ENEC under-recoveries as of February 28, 2023. Additionally, in April 2023, the Staff submitted thea prudency review prepared by an independent consultant retained by the WVPSC Staff of the Companies’ operation of the Amos, Mountaineer and Mitchell coal plants that Staff was directed to conduct by the WVPSC in May 2022 (Consultant’s Report).staff. Adoption of the Consultant’s Report’sconsultant report’s findings by the WVPSC could result in a disallowance of up to $285 million. The Companies disagreeManagement disagrees with the conclusions and recommendations contained in the Consultant’s Reportconsultant’s report and intenda hearing was held with the WVPSC in September 2023. APCo and WPCo are awaiting a WVPSC order addressing: (a) the prudency review requested by the WVPSC regarding 2021 and 2022 ENEC under-recovery balances, (b) potential securitization of ENEC under-recovery balances, Amos and Mountaineer Plant property balances and deferred storm costs and (c) potential further adjustment to dispute themENEC rates. An order is anticipated in the appropriate proceedings beforefourth quarter of 2023. In September 2023, APCo received an order from the WVPSC.WVPSC authorizing an $89 million annual increase in ENEC rates for the Companies’ forecasted costs for the period September 2023 through August 2024. See “ENEC Filings” section of Note 4 for additional information.

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 over a 27-month period, effective with the first billing cycle of October 2022. PSO’s fuel and purchased power expenses are subject to an annual prudency review by the OCC.
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In October 2022,2023, APCo submitted its annual Virginia fuel factor filing with interim FAC rates effective November 2022.  To help mitigate the impact of rising fuel costs on customer bills, APCo proposed recovery of its deferred fuel balance as ofVirginia SCC requesting to recover a projected October 31, 20222023 Virginia fuel under-recovered balance of $273 million over two years. In March 2023,Interim Virginia FAC rates were implemented in November 2023. An order from the Virginia SCC issued an order approving APCo’s request to increase its annual fuel factor by approximately $279 million and APCo’s request to recover its October 31, 2022 deferred fuel balance over two years.  As ordered byis expected in the Virginia SCC, APCo’s historical period fuel and purchased power expenses are subject to a prudency review. first quarter of 2024.

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

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

Dolet Hills Power Station and Related Fuel Operations

In December 2021, the Dolet Hills Power Station was retired. While in operation, DHLC provided 100% of thean interim 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 March 31,surcharge, effective February 2023, SWEPCo’s share of the net investment in the Dolet Hills Power Station was $110 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 March 31, 2023, SWEPCo had a net under-recovered fuel balance of $233 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$83 million of non Sabine and Oxbow mine related fuel costs in 2021 and defer approximately $33through June 2024. In September 2023, an unopposed settlement agreement was approved by the PUCT that allows SWEPCo to recover $81 million of additionalSabine and Oxbow mine related fuel costs with a recovery period to be determined at a later date. In August 2022, the LPSC staff filed testimony recommending fuel disallowances of $72 million, including denial of recovery of the $33 million deferral, with refunds to customers over five years. In September 2022, SWEPCo filed rebuttal testimony addressing the LPSC staff recommendations.

In March 2021, the APSC approved fuel rates that provide recovery of $20 million for the Arkansas share of the 2021 Doletthrough 2035. See “Dolet Hills Power Station fuel costs over five years through the existing fuel clause.

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

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


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Pirkeyand Related Fuel Operations” and “Pirkey Plant and Related Fuel Operations

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 March 31, 2023, SWEPCo’s share of the net investment in the Pirkey Plant was $177 million, including materials and supplies, net of cost of removal. See the “Regulated Generating Units that have been Retired” sectionOperations” sections in Note 4 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 March 31, 2023, SWEPCo had a net under-recovered fuel balance of $233 million, inclusive of costsinformation related to the Pirkey Plant billed by Sabine, but excluding impactsrecovery of the February 2021 severe winter weather event. Remaining operational, reclamationfuel costs in SWEPCo’s Arkansas and other land-related costs incurred by Sabine will be billed to SWEPCo and included in existing fuel clauses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.Louisiana jurisdictions.

Renewable Generation

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

RecentSignificant Renewable Generation FilingsPlaced Into Service

Recently, the Registrants have made filings with various state regulatory commissions seeking approval to acquire 2,607In 2023, AEP acquired and placed into service 159 MWs of owned renewable generation facilities totaling approximately $6.1$154 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 484557 MWs of renewable purchasedpurchase power agreements, as included in the following table:

CompanyGeneration TypeExpected Commercial OperationOwned/PPAGenerating Capacity
(in MWs)
APCo (a)SolarQ2 2024 through Q1 2026PPA204 
APCo (a)WindQ4Q3 2025 through Q1 2026Owned143347 
I&MSolarQ4 2025 through PPA280 
I&M (b)SolarQ2 2026Owned/PPAOwned749469 
PSO (a)SolarQ2 2025 through Q4 2025Owned443 
PSO (a)WindQ2Q1 2025 through Q4 2025Q2 2026Owned553 
SWEPCo (b)(c)SolarQ2 2025 through Q4 2025OwnedOwned/PPA200273 
SWEPCo (b)(c)WindQ4 2024 through Q4 2025Owned799 
Total Approved Renewable Projects3,0913,368 

(a)In AprilSeptember 2023, PSO filedthe Virginia SCC issued an unopposed settlement agreement withorder approving a 143 MW owned project and 204 MWs of PPAs, approval from the OCC that supported approval of the projects. An orderWVPSC is expected in the third quarter 2023.pending.
(b)In January 2023, SWEPCo filed an unopposed joint settlement agreement withProjects fully approved by the IURC and partially approved by the MPSC, final approval pending from the MPSC for 245 MW of owned solar.
(c)Includes approvals by the APSC that supported approvaland LPSC for 999 MWs of owned projects. Additionally, the LPSC approved the flex-up option, allowing SWEPCo to recover the portion of the projects. An order fromprojects denied by the APSC is expected in the second quarter of 2023. In March 2023, SWEPCo filed a joint settlement with the LPSC Staff that supported approval of the projects.PUCT.

In April 2023, the LPSC denied SWEPCo’s application.SWEPCo intends to file a motion for rehearing.In April 2023, administrative law judges in Texas issued a proposal for decision recommending that the certificate of convenience and necessity authorization be granted. An order from the PUCT is expected in the second quarter of 2023.


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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, the Registrants issue RFPs have been issued to identify potential wind and solarrenewable projects.The table below includes RFPs recently issued for owned generation and purchased power generation.These projects would be subject to regulatory approval.

CompanyIssuance DateProjected
In-Service Dates
Generation TypeGenerating Capacity
(in MWs)
SWEPCoSeptember 2022Wind (a)1,900 
SWEPCoSeptember 2022Solar (a)500 
I&MMarch 2023Year End 2027Wind (b)(a)800 
I&MMarch 2023Year End 2027Solar (a)(b)(c)850 
APCoApril 2023Year End 2026Wind and/or Solar (a)(c)(d)800
KPCoSeptember 2023Year end 2027Wind and/or Solar (e)1,300 
Total Significant RFPs4,8503,750 

(a)Includes an option for battery storage.
(b)RFP is an all-source solicitation seeking proposals for both owned projects and PPAs from various types of generation including 315 MWs of storage (a portion of which may derive from solar/storage hybrid projects) and 540 MWs of natural gas.
(c)(b)Includes consideration forof up to 300 MWs of hybrid solar paired with up to 60 MWs of battery storage.
(d)(c)Includes RFP for up to 200 MWs of PPAs.
(d)Includes an option for battery storage.
(e)RFP is an all-source solicitation seeking proposals for PPAs for solar, wind, thermal resources and/or standalone storage for up to approximately 875 MWs of PJM-accredited summer capacity and approximately 1,300 MWs of PJM-accredited winter capacity.

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 at this time.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 fourth quarter of 2023. As of March 31,September 30, 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.
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LITIGATION

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

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 on April 29, 2022. On September 13, 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. On January 20, 2023, the New York plaintiff filed a motion to intervene in the pending Ohio federal court action and withdrew his appeal in New York. 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. On March 20, 2023, the federal district court issued an order granting the motion to dismiss with prejudice and denying the New York plaintiffs’ motion to intervene. On April 20, 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. On June 15, 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. 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.

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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 HB6HB 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 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. Althoughindividuals and inquiries regarding Empowering Ohio’s Economy, Inc., which is a 501(c)(4) social welfare organization, and related disclosures. AEP and the outcomeSEC are engaged in discussions about a possible resolution of the SEC’s investigation and potential claims under the securities laws, the outcome of which cannot be predicted and could subject AEP to civil penalties and other remedial measures. 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 financial condition, results of operations, cash flows or cash flows.financial condition.

Claims for Indemnification Related to Damages Resulting fromMade by Owners of the Federal EPA’s Denial of Alternative Closure Deadline for Gavin Plant and Associated Findings of CompliancePower 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 determinations related to the CCR Rule (see “Coal Combustion Residual (CCR) Rule” section below for additional information), including a determination that the closure of the 300 acre unlined fly ash reservoir (FAR) is noncompliant with the CCR Rule in multiple respects. The Gavin Power Station was formerly owned and operated by AEP and was sold to Gavin Power LLC and Lightstone Generation LLC in 2017. Pursuant to the PSA, AEP maintained responsibility to complete closure of the FAR in accordance with the closure plan approved by the Ohio EPA which was completed in July 2021. The PSA contains indemnification provisions, pursuant to which the owners of the Gavin Power Station have notified AEP they believe they are entitled to indemnification for any damages that may result from the Gavin Denial, as well asthese claims, including any future enforcement or litigation resulting from the Federal EPA’s determinations of noncompliance with various aspects of the CCR Rule as part of the Gavin Denial. 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.


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Claims for Damages Related to Sabine Coal Supply ContractLignite Mining Agreement

In AprilMay 2023, AEP received a letter from North American Coal Corporation (NACC) alleging that SWEPCo breached it’s coal supply contract withand Sabine, a subsidiary of NACC. The letter contendsNACC, filed suit against SWEPCo in Texas state court for breach of the Lignite Mining Agreement (LMA) between Sabine and SWEPCo. NACC and Sabine assert that the terms of the LMA require SWEPCo is obligated to runcontinue operating the Pirkey Plant untiland obtaining coal from the Sabine mine through 2035 and that SWEPCo has breached the agreement by closing the plant. In August 2023, a settlement agreement was reached and the suit was dismissed by the Texas state court. The settlement agreement did not have a material impact on SWEPCo’s net income, cash flows or to pay $85 million in damages representing lost mining fees to Sabine. The letter threatens legal action for unspecified injunctive relief and breach of contract. Management does not believe SWEPCo is obligated to run the Pirkey Plant for any period of time beyond its useful life or that there is a valid claim for breach of contract or damages. Management is unable to determine a range of potential losses that is reasonably possible of occurring.


financial condition.
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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 an impact on AEP System generating units.  Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of March 31,September 30, 2023, the AEP System owned generating capacity of approximately 24,60023,300 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. In addition, management continues to evaluate the economic feasibility of environmental investments on regulated and competitive plants.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions. The states implement and administer many of these programs and could impose additional or more stringent requirements. The primary regulatory programs that continue to drive investments in AEP’s existing generating units include: (a) periodic revisions to NAAQS and the development of SIPs to achieve more stringent standards, (b) implementation of the regional haze program by the states and the Federal EPA, (c) regulation of hazardous air pollutant emissions under MATS, (d) implementation and review of CSAPR and (e) the Federal EPA’s regulation of greenhouse gas emissions from fossil generation under Section 111 of the CAA. Notable developments in significant CAA regulatory requirements affecting AEP’s operations are discussed in the following sections.

National Ambient Air Quality Standards

The Federal EPA periodically reviews and revises the NAAQS for criteria pollutants under the CAA. Revisions tend to increase the stringency of the standards, which in turn may require AEP to make investments in pollution control equipment at existing generating units, or, since most units are already well controlled, to make changes in how units are dispatched and operated. In January 2023, the Federal EPA announced its proposed decision to strengthen the primary (health-based) annual PM2.5 standard. The Biden administration has previously indicated that it is likely to revisit the NAAQS for ozone, which were left unchanged by the prior administration following its review. Management cannot currently predict if any changes to either standardthese standards are likely to be finalized or what such changes may be, but will continue to monitor this issue and any future rulemakings.
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Regional Haze

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

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

In Texas, the Federal EPA disapproved portions of the Texas regional haze SIP and finalized a FIP that allows participation in the CSAPR ozone season program to satisfy the NOX regional haze obligations for electric generating units in Texas. Additionally, the Federal EPA finalized an intrastate SO2 emissions trading program based on CSAPR allowance allocations. Legal challenges to these various rulemakings are pending in both the U.S. Court of Appeals for the Fifth Circuit and the U.S. Court of Appeals for the District of Columbia Circuit. Management cannot predict the outcome of that litigation, although management supports the intrastate trading program as a compliance alternative to source-specific controls and has intervened in the litigation in support of the Federal EPA.

Cross-State Air Pollution Rule

CSAPR is a regional trading program 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. Several utilities and other entities potentially subject to the Federal EPA’s NOX regulations challenged that final rule in the U.S. Court of Appeals for the District of Columbia Circuit and oral argument was held in September 2022. In March 2023, the court rejected the challenge and upheld the rule. 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. Various legal challengesPetitions for review of the SIP disapprovals for several states have been broughtfiled in federal courts of appeals by several states, utilities and other industry parties challengingand the SIP disapproval. SWEPCo filed a petition for reviewfederal courts have stayed the disapprovals of the disapproval of theSIPs submitted by twelve states, including Arkansas, SIP in the U.S. Court of Appeals for the Eighth Circuit on April 14, 2023.Kentucky, Oklahoma, Texas and West Virginia. In March 2023, the Federal EPA finalized a FIP that further revises the ozone season NOX budgets under the existing CSAPR program in states to which the FIP applies. The FIP is expected to takewent into effect during thein August 2023 ozone season. In May 2023,and has also been challenged in the U.S. Court of Appeals for the FifthD.C. Circuit stayedand in several other federal circuits. In light of the various court stays of the SIP disapprovals, the Federal EPA’s disapprovalEPA has issued two interim final rules that adjust or stay certain requirements of the Texas and Louisiana SIPsFIP consistent with the court orders, pending a decision on the meritsresolution of the appeal, calling into questionlitigation. Management continues to monitor the Federal EPA’s ability to enforce the FIP in those states. Management is evaluatingoutcome of various SIP challenges and evaluate the impacts of the FIP and cannot predict the outcome of the litigation.

Climate Change, CO2 Regulation and Energy Policy

In 2019, the Affordable Clean Energy (ACE) rule established a framework for states to adopt standards of performance for utility boilers based on heat rate improvements for such boilers. However, in January 2021, the U.S. Court of Appeals for the District of Columbia Circuit vacated the ACE rule and remanded it toMay 2023, the Federal EPA. In October 2021,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 United States Supreme Court granted certiorari and combined four separate petitions seeking review of the District of Columbia Circuit Court decisions. Oral arguments were held in February 2022 and on June 30, 2022, the United States Supreme Court reversed the District of Columbia Circuit Court’s decision andproposed rule.


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remanded for further proceedings. The Federal EPA must take some action before anything is required of the utilities as a result of this decision. At a minimum, if the Federal EPA intends to implement the ACE rule, it must conduct additional rulemaking to update its applicable deadlines, which have all passed. Alternatively, the Federal EPA may abandon the ACE rule and proceed to regulate greenhouse gases through a new rule, the scope of which is unknown. The Federal EPA has announced it expects to propose a new rule in 2023. Management is unable to predict how the Federal EPA will respond to the Court’s remand.

In 2018, the Federal EPA filed a proposed rule revising the standards for new sources and determined that partial carbon capture and storage is not the best system of emission reduction because it is not available throughout the U.S. and is not cost-effective. That rule has not been finalized. The Federal EPA has indicated that it intends to conduct a comprehensive review of the existing standards and, if appropriate, amend the emission standards for new fossil fuel-fired generating units. A proposed rule is expected in 2023. Management continues to actively monitor these rulemaking activities.

While no federal regulatory requirements to reduce CO2 emissions are in place, AEP has taken action to reduce and offset CO2 emissions from its generating fleet. AEP expects CO2 emissions from its operations to continue to decline due to the retirement of some of its coal-fired generation units, and actions taken to diversify the generation fleet and increase energy efficiency where there is regulatory support for such activities. The majority of the states where AEP has generating facilities passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements that can assist in reducing carbon emissions.  In April 2020, Virginia enacted clean energy legislation to allow the state to participate in the Regional Greenhouse Gas Initiative (RGGI), require the retirement of all fossil-fueled generation by 2045 and require 100% renewable energy to be provided to Virginia customers by 2050. Management is taking steps to comply with these requirements, including increasing wind and solar installations, purchasing renewable power and broadening AEP System’s portfolio of energy efficiency programs. In early 2022, Virginia’s governor issued an executive order directing his administration to end Virginia’s participation in RGGI. In December 2022, the Virginia Air Pollution Control Board voted in support of the proposed regulations to withdraw Virginia from RGGI. These regulations have not been finalized. Management will continue to monitor these rulemaking activities.

In October 2022, AEP announced new intermediate and long-term CO2 emission reduction goals, based on the output of the company’s integrated resource plans, which take into account economics, customer demand, grid reliability and resiliency, regulations and the company’s current business strategy. AEP adjusted its near-term CO2 emission reduction target from a 2000 baseline to a 2005 baseline, upgraded its 80% reduction by 2030 target to include full Scope 1 emissions and accelerated its net-zero goal by five years to 2045. AEP’s total Scope 1 greenhouse gas (GHG) emissions in 2022 were approximately 52.5 million metric tons CO2e, approximately a 65% reduction from AEP’s 2005 Scope 1 GHG emissions (inclusive of emission reductions that result from plants that have been sold). AEP has made significant progress in reducing CO2 emissions from its power generation fleet and expects its emissions to continue to decline. Technological advances, including energy storage, will determine how quickly AEP can achieve zero emissions while continuing to provide reliable, affordable power for customers.

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

Mercury and Air Toxics Standards (MATS)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. Managementproposed and will continue to monitor the rulemaking.


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Coal Combustion Residual (CCR)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.


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

CompanyCompanyPlant Name and UnitGenerating
Capacity
Net Book Value (a)Projected
 Retirement Date
CompanyPlant NameGenerating
Capacity
Net Book Value (a)Projected
 Retirement Date
(in MWs)(in millions)(in MWs)(in millions)
AEGCoAEGCoRockport Plant1,310$304.6 2028AEGCoRockport Plant1,310$291.7 2028
APCoAPCoAmos Plant2,9302,133.4 2040APCoAmos Plant2,9302,136.8 2040
APCoAPCoMountaineer Plant1,320976.3 2040APCoMountaineer Plant1,320963.9 2040
I&MI&MRockport Plant1,310585.9 (b)2028I&MRockport Plant1,310548.2 (b)2028
KPCoKPCoMitchell Plant780571.6 2040KPCoMitchell Plant780557.0 2040
SWEPCoSWEPCoFlint Creek Plant258262.3 2038SWEPCoFlint Creek Plant258256.6 2038
WPCoWPCoMitchell Plant780652.0 2040WPCoMitchell Plant780680.8 2040

(a)Net book value as of March 31,September 30, 2023, before cost of removal including CWIP and inventory.
(b)Amount includes a $141$129 million regulatory asset related to the retired Tanners Creek Plant. The IURC and MPSC authorized recovery of the Tanners Creek Plant regulatory asset over the useful life of Rockport Plant, Unit 1 in 2015 and 2014, respectively.

In January 2022, the Federal EPA proposed to deny several extension requests filed by the other utilities based on allegations that those utilities are not in compliance with the CCR Rule (the January Actions). In November 2022, the Federal EPA finalized one of these denials.denials (the November Denial). 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 November 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.

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

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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.

The
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Under the second option to obtainfor obtaining an extension of the April 11, 2021 deadline to cease operation of unlined impoundments, allows a generating facility tomay continue operating its existing impoundments without developing alternative CCR disposal, provided the facility commits to cease combustion of coal by a date certain. Under this option, a generating facility would havehad 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. The table below summarizes the net book value of Welsh Plant, Units 1 and 3 as of March 31,September 30, 2023.
CompanyCompanyPlant Name and UnitGenerating
Capacity
Net Investment (a)Accelerated Depreciation Regulatory AssetProjected
 Retirement Date
CompanyPlant Name and UnitGenerating
Capacity
Net Investment (a)Accelerated Depreciation Regulatory AssetProjected
 Retirement Date
(in MWs)(in millions)(in MWs)(in millions)
SWEPCoSWEPCoWelsh Plant, Units 1 and 31,053$399.6 $95.5 2028(b)(c)SWEPCoWelsh Plant, Units 1 and 31,053$368.8 $115.5 2028(b)(c)

(a)Net book value as of March 31, 2023, including CWIP excluding cost of removal and materials and supplies.
(b)In November 2020, management announced it will cease using coal at the Welsh Plant in 2028.
(c)Unit 1 is currently being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Unit 3 is currently being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.

To date, the Federal EPA has not taken any action on thesethe pending extension requests.request for the Welsh Plant. Under the second option above, AEP may need to recover remaining depreciation and estimated closure costs associated with these plants over a shorter period. If AEP cannot ultimately recover the costs of environmental compliance and/or the remaining depreciation and estimated closure costs associated with these plants in a timely manner, it would reduce future net income and cash flows and impact financial condition.

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 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.


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In January 2023, the Federal EPA and the Department of the Army finalized a new rule revising the definition of “waters of the United States,” which became effective in March 2023. The new rule expands the scope of the definition, which means that permits may be necessary where none were previously required and issued permits may need to be reopened to impose additional obligations. A number of legal challenges in courts across the country have resulted in the rule being stayed in more than half of the states.states, including Arkansas, Indiana, Louisiana, Ohio, Oklahoma, Virginia and West Virginia. Management is evaluating what impacts the revised rule will have on operations.

In October 2022,May 2023, the United States Supreme Court heard an appeal related toissued a decision that significantly narrowed the scope of “waters of the United States,” specifically which wetlands can be regulated as waters of the United States. Management cannot predictIn August 2023, the outcomeFederal EPA and the Department of that litigation.the Army issued a final rule to amend the January 2023 revised definition of “waters of the United States” to conform to the Supreme Court’s decision, which rendered parts of the January 2023 rule invalid. The conforming rule became effective in September 2023 and applies in those states not subject to the court’s stay of the January 2023 rule.

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 March 31,September 30, 2023, of generating facilities retired or planned for early retirement in advance of the retirement date currently authorized for ratemaking purposes:
CompanyCompanyPlantNet
Investment (a)
Accelerated Depreciation Regulatory AssetActual/Projected
Retirement
Date
Current Authorized
Recovery
Period
Annual Depreciation (b)CompanyPlantNet
Investment (a)
Accelerated Depreciation Regulatory AssetActual/Projected
Retirement
Date
Current Authorized
Recovery
Period
Annual Depreciation (b)
(in millions)(in millions)(in millions)(in millions)
PSOPSONortheastern Plant, Unit 3$128.5 $150.3 2026(c)$14.9 PSONortheastern Plant, Unit 3$112.5 $159.5 2026(c)$15.0 
SWEPCoSWEPCoPirkey Plant— 111.8 (d)2023(e)— SWEPCoPirkey Plant— 113.0 (d)2023(e)— 
SWEPCoSWEPCoWelsh Plant, Units 1 and 3399.6 95.5 2028(f)(g)38.3 SWEPCoWelsh Plant, Units 1 and 3368.8 115.5 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 4 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.
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RESULTS OF OPERATIONS

SEGMENTS

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

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

Vertically Integrated Utilities

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

Transmission and Distribution Utilities

Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo.
OPCo purchases energy and capacity at auction to serve standard service offer customers and provides transmission and distribution services for all connected load.

AEP Transmission Holdco

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

Generation & Marketing

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

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

The following discussion of AEP’s results of operations by operating segment includes an analysis of Gross Margin, which is a non-GAAP financial measure. Gross Margin includes Total Revenues less the costs of Fuel and Other Consumables Used for Electric Generation, as well as Purchased Electricity for Resale, as presented in the Registrants’ statements of income as applicable. Under the various state utility rate making processes, these expenses are generally reimbursable directly from and billed to customers. As a result, they do not typically impact Operating Income or Earnings Attributable to AEP Common Shareholders. Management believes that Gross Margin provides a useful measure for investors and other financial statement users to analyze AEP’s financial performance in that it excludes the effect on Total Revenues caused by volatility in these expenses. Operating Income, which is presented in accordance with GAAP in AEP’s statements of income, is the most directly comparable GAAP financial measure to the presentation of Gross Margin. AEP’s definition of Gross Margin may not be directly comparable to similarly titled financial measures used by other companies.

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The following table presentstables present Earnings (Loss) Attributable to AEP Common Shareholders by segment:
Three Months EndedNine Months Ended
Three Months Ended March 31,September 30,September 30,
20232022 2023202220232022
(in millions) (in millions)
Vertically Integrated UtilitiesVertically Integrated Utilities$261.0 $298.2 Vertically Integrated Utilities$512.5 $476.9 $1,051.6 $1,076.3 
Transmission and Distribution UtilitiesTransmission and Distribution Utilities125.7 152.8 Transmission and Distribution Utilities206.0 165.5 508.4 483.1 
AEP Transmission HoldcoAEP Transmission Holdco181.5 173.1 AEP Transmission Holdco202.9 170.5 580.8 485.4 
Generation & MarketingGeneration & Marketing(157.7)114.2 Generation & Marketing130.7 97.5 (59.3)284.3 
Corporate and OtherCorporate and Other(13.5)(23.6)Corporate and Other(98.4)(226.7)(209.6)(406.2)
Earnings Attributable to AEP Common ShareholdersEarnings Attributable to AEP Common Shareholders$397.0 $714.7 Earnings Attributable to AEP Common Shareholders$953.7 $683.7 $1,871.9 $1,922.9 

AEP CONSOLIDATED

First Quarter of 2023 Compared to First Quarter of 2022

Earnings Attributable to AEP Common Shareholders decreased from $715 million in 2022 to $397 million in 2023 primarily due to:

A loss on the expected sale of the competitive contracted renewable portfolio.
An increase in interest expense due to higher interest rates and debt balances.
A decrease in weather-related sales volumes.
Unfavorable mark-to-market economic hedge activity driven by a decrease in commodity prices.

These decreases were partially offset by:

Favorable rate proceedings in AEP’s various jurisdictions.
Increased weather-normalized sales volumes.

AEP’s results of operations by operating segment are discussed below.
Three Months Ended September 30, 2023
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration & Marketing
(in millions)
Revenues$3,205.4 $1,544.1 $476.7 $566.7 
Fuel, Purchased Electricity and Other1,137.5 298.8 — 406.6 
Gross Margin2,067.9 1,245.3 476.7 160.1 
Other Operation and Maintenance829.4 541.1 39.3 31.2 
Depreciation and Amortization480.7 206.9 101.9 8.3 
Taxes Other Than Income Taxes131.9 181.3 75.5 1.6 
Operating Income625.9 316.0 260.0 119.0 
Other Income5.9 0.6 2.1 11.5 
Allowance for Equity Funds Used During Construction15.0 13.4 22.7 — 
Non-Service Cost Components of Net Periodic Benefit Cost31.6 14.1 1.5 6.6 
Interest Expense(197.1)(93.8)(53.6)(18.7)
Income Before Income Tax Expense (Benefit) and Equity Earnings (Loss)481.3 250.3 232.7 118.4 
Income Tax Expense (Benefit)(32.4)44.3 51.1 (16.2)
Equity Earnings (Loss) of Unconsolidated Subsidiary0.3 — 22.3 (1.8)
Net Income514.0 206.0 203.9 132.8 
Net Income Attributable to Noncontrolling Interests1.5 — 1.0 2.1 
Earnings Attributable to AEP Common Shareholders$512.5 $206.0 $202.9 $130.7 

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Three Months Ended September 30, 2022
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration & Marketing
 (in millions)
Revenues$3,226.3 $1,530.2 $430.9 $735.4 
Fuel, Purchased Electricity and Other1,191.9 399.5 — 566.1 
Gross Margin2,034.4 1,130.7 430.9 169.3 
Other Operation and Maintenance834.0 503.6 46.5 44.7 
Asset Impairments and Other Related Charges24.9 — — — 
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset(37.0)— — — 
Depreciation and Amortization520.6 188.3 89.5 23.1 
Taxes Other Than Income Taxes130.1 176.7 70.5 3.1 
Operating Income561.8 262.1 224.4 98.4 
Other Income9.0 1.4 0.7 12.5 
Allowance for Equity Funds Used During Construction6.0 9.3 20.3 — 
Non-Service Cost Components of Net Periodic Benefit Cost27.4 11.9 1.3 5.1 
Interest Expense(168.8)(85.4)(44.4)(16.7)
Income Before Income Tax Expense (Benefit) and Equity Earnings (Loss)435.4 199.3 202.3 99.3 
Income Tax Expense (Benefit)(41.2)33.8 52.1 (5.1)
Equity Earnings (Loss) of Unconsolidated Subsidiary0.3 — 21.2 (8.2)
Net Income476.9 165.5 171.4 96.2 
Net Income (Loss) Attributable to Noncontrolling Interests— — 0.9 (1.3)
Earnings Attributable to AEP Common Shareholders$476.9 $165.5 $170.5 $97.5 

Nine Months Ended September 30, 2023
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration & Marketing
(in millions)
Revenues$8,737.7 $4,348.5 $1,390.8 $1,225.1 
Fuel, Purchased Electricity and Other2,989.0 970.5 — 1,116.0 
Gross Margin5,748.7 3,378.0 1,390.8 109.1 
Other Operation and Maintenance2,480.7 1,472.7 109.9 130.4 
Loss on the Sale of the Competitive Contracted Renewables Portfolio— — — 112.0 
Depreciation and Amortization1,411.3 576.2 297.9 34.7 
Taxes Other Than Income Taxes390.8 519.1 222.0 6.1 
Operating Income (Loss)1,465.9 810.0 761.0 (174.1)
Other Income20.2 1.9 7.0 32.2 
Allowance for Equity Funds Used During Construction30.5 30.7 62.2 — 
Non-Service Cost Components of Net Periodic Benefit Cost94.9 42.1 4.6 19.7 
Interest Expense(565.1)(270.0)(153.7)(69.2)
Income (Loss) Before Income Tax Expense (Benefit) and Equity Earnings1,046.4 614.7 681.1 (191.4)
Income Tax Expense (Benefit)(7.2)106.3 158.7 (127.3)
Equity Earnings of Unconsolidated Subsidiary1.0 — 61.2 1.9 
Net Income (Loss)1,054.6 508.4 583.6 (62.2)
Net Income (Loss) Attributable to Noncontrolling Interests3.0 — 2.8 (2.9)
Earnings (Loss) Attributable to AEP Common Shareholders$1,051.6 $508.4 $580.8 $(59.3)
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Nine Months Ended September 30, 2022
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration & Marketing
 (in millions)
Revenues$8,562.2 $4,078.6 $1,221.1 $2,014.3 
Fuel, Purchased Electricity and Other2,895.8 884.8 — 1,534.0 
Gross Margin5,666.4 3,193.8 1,221.1 480.3 
Other Operation and Maintenance2,383.1 1,373.2 114.4 71.2 
Asset Impairments and Other Related Charges24.9 — — — 
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset(37.0)— — — 
Gain on Sale of Mineral Rights— — — (116.3)
Depreciation and Amortization1,525.0 559.5 262.7 68.8 
Taxes Other Than Income Taxes383.9 504.9 207.9 9.3 
Operating Income1,386.5 756.2 636.1 447.3 
Other Income24.9 3.7 1.1 21.4 
Allowance for Equity Funds Used During Construction20.4 23.6 51.2 — 
Non-Service Cost Components of Net Periodic Benefit Cost82.4 35.7 3.8 15.4 
Interest Expense(477.1)(242.2)(124.2)(30.7)
Income Before Income Tax Expense (Benefit) and Equity Earnings (Loss)1,037.1 577.0 568.0 453.4 
Income Tax Expense (Benefit)(41.3)94.7 141.9 (25.3)
Equity Earnings (Loss) of Unconsolidated Subsidiary1.0 0.8 61.7 (200.6)
Net Income1,079.4 483.1 487.8 278.1 
Net Income (Loss) Attributable to Noncontrolling Interests3.1 — 2.4 (6.2)
Earnings Attributable to AEP Common Shareholders$1,076.3 $483.1 $485.4 $284.3 

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VERTICALLY INTEGRATED UTILITIES
Three Months Ended March 31,
 Vertically Integrated Utilities20232022
 (in millions)
Revenues$2,857.8 $2,687.4 
Fuel and Purchased Electricity976.2 866.1 
Gross Margin1,881.6 1,821.3 
Other Operation and Maintenance832.2 769.2 
Depreciation and Amortization473.5 500.0 
Taxes Other Than Income Taxes132.4 125.2 
Operating Income443.5 426.9 
Other Income7.2 5.2 
Allowance for Equity Funds Used During Construction5.8 8.1 
Non-Service Cost Components of Net Periodic Benefit Cost31.8 27.6 
Interest Expense(172.9)(151.0)
Income Before Income Tax Expense and Equity Earnings315.4 316.8 
Income Tax Expense53.5 17.9 
Equity Earnings of Unconsolidated Subsidiary0.3 0.3 
Net Income262.2 299.2 
Net Income Attributable to Noncontrolling Interests1.2 1.0 
Earnings Attributable to AEP Common Shareholders$261.0 $298.2 

Summary of KWh Energy Sales for Vertically Integrated Utilities
Three Months EndedNine Months Ended
Three Months Ended March 31,September 30,September 30,
202320222023202220232022
(in millions of KWhs) (in millions of KWhs)
Retail:Retail:  Retail:    
ResidentialResidential8,099 9,225 Residential8,975 9,115 23,406 25,379 
CommercialCommercial5,372 5,518 Commercial6,686 6,640 17,781 18,069 
IndustrialIndustrial8,295 8,162 Industrial8,731 8,862 25,686 25,930 
MiscellaneousMiscellaneous521 544 Miscellaneous618 623 1,684 1,745 
Total RetailTotal Retail22,287 23,449 Total Retail25,010 25,240 68,557 71,123 
Wholesale (a)Wholesale (a)3,260 4,474 Wholesale (a)3,876 4,254 10,620 12,388 
Total KWhsTotal KWhs25,547 27,923 Total KWhs28,886 29,494 79,177 83,511 

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



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

Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities
Three Months EndedNine Months Ended
Three Months Ended March 31,September 30,September 30,
202320222023202220232022
(in degree days) (in degree days)
Eastern RegionEastern Region  Eastern Region    
Actual Heating (a)
Actual Heating (a)
1,131 1,590 
Actual Heating (a)
— 1,253 1,750 
Normal Heating (b)
Normal Heating (b)
1,608 1,604 
Normal Heating (b)
1,750 1,748 
Actual Cooling (c)
Actual Cooling (c)
Actual Cooling (c)
748 783 967 1,178 
Normal Cooling (b)
Normal Cooling (b)
Normal Cooling (b)
751 745 1,095 1,082 
Western RegionWestern Region  Western Region    
Actual Heating (a)
Actual Heating (a)
637 915 
Actual Heating (a)
— — 657 930 
Normal Heating (b)
Normal Heating (b)
881 871 
Normal Heating (b)
— — 916 906 
Actual Cooling (c)
Actual Cooling (c)
58 20 
Actual Cooling (c)
1,634 1,653 2,436 2,558 
Normal Cooling (b)
Normal Cooling (b)
28 28 
Normal Cooling (b)
1,430 1,413 2,162 2,134 

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

2324


Vertically Integrated Utilities
Reconciliation of 2022 to 2023 Earnings Attributable to AEP Common Shareholders
(in millions)
 
Three Months Ended 
September 30,
Nine Months Ended 
September 30,
2022 Earnings Attributable to AEP Common Shareholders$476.9 $1,076.3 
  
Changes in Gross Margin: 
Retail Margins52.2 68.6 
Margins from Off-system Sales(14.4)32.8 
Transmission Revenues(5.5)(11.6)
Other Revenues1.2 (7.5)
Total Change in Gross Margin33.5 82.3 
  
Changes in Expenses and Other: 
Other Operation and Maintenance4.6 (97.6)
Asset Impairments and Other Related Charges24.9 24.9 
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset(37.0)(37.0)
Depreciation and Amortization39.9 113.7 
Taxes Other Than Income Taxes(1.8)(6.9)
Other Income(3.1)(4.7)
Allowance for Equity Funds Used During Construction9.0 10.1 
Non-Service Cost Components of Net Periodic Pension Cost4.2 12.5 
Interest Expense(28.3)(88.0)
Total Change in Expenses and Other12.4 (73.0)
  
Income Tax Benefit(8.8)(34.1)
Net Income Attributable to Noncontrolling Interests(1.5)0.1 
2023 Earnings Attributable to AEP Common Shareholders$512.5 $1,051.6 

FirstThird Quarter of 2023 Compared to FirstThird Quarter of 2022
Reconciliation of First Quarter of 2022 to First Quarter of 2023
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
First Quarter of 2022$298.2 
Changes in Gross Margin:
Retail Margins36.5 
Margins from Off-system Sales26.5 
Transmission Revenues4.5 
Other Revenues(7.2)
Total Change in Gross Margin60.3 
Changes in Expenses and Other:
Other Operation and Maintenance(63.0)
Depreciation and Amortization26.5 
Taxes Other Than Income Taxes(7.2)
Other Income2.0 
Allowance for Equity Funds Used During Construction(2.3)
Non-Service Cost Components of Net Periodic Pension Cost4.2 
Interest Expense(21.9)
Total Change in Expenses and Other(61.7)
Income Tax Expense(35.6)
Net Income Attributable to Noncontrolling Interests(0.2)
First Quarter of 2023$261.0 

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

Retail Margins increased $37$52 million primarily due to the following:
A $33$28 million increase in base rate and rider revenues at PSO. This increase was partially offset in other expense items below.
A $23 million increase at SWEPCo due to a base rate revenue increase in Louisiana and rider increases in Texas and Louisiana. These increases were partially offset in other expense items below.
A $20 million increase in weather-normalized retail margins primarily in the residentialcommercial and commercialindustrial classes.
A $22$19 million increase at APCo due to rider revenues in Virginia and West Virginia. This increase was partially offset in other expense items below.

25


These increases were partially offset by:
An $18 million decrease at PSO and SWEPCo due to an increase in PTC benefits provided to customers. This increase in PTC benefits was offset in Income Tax Benefit below.
A $13 million decrease in weather-related usage primarily in the residential class.
Margins from Off-system Sales decreased $14 million primarily due to reduced Turk Plant merchant sales and Rockport Plant, Unit 2 merchant operations activity.
Transmission Revenues decreased $6 million primarily due to transmission formula rate true-up activity.

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

Asset Impairments and Other Related Charges decreased $25 million at APCo due to the 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 the establishment of a regulatory asset in 2022 based on an August 2022 Virginia Supreme Court opinion and resulting under-earning during the 2017-2019 Virginia Triennial Review.
Depreciation and Amortization expenses decreased $40 millionprimarily due to a $46 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.
Allowance for Equity Funds Used During Construction increased $9 millionprimarily due to higher AFUDC equity rates and CWIP.
Interest Expense increased $28 million primarily due to higher long-term debt balances and interest rates.
Income Tax Benefit decreased $9 million primarily due to the following:
A $10 million decrease due to an increase in pretax book income.
A $10 million increase in state income tax.
A $3 million decrease in amortization of Excess ADIT. This decrease was partially offset in Retail Margins above.
A $3 million decrease due to a lower cost of removal deduction.
These decreases were partially offset by:
An $18 million increase in PTCs. This increase was partially offset in Retail Margins above.

Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022

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

Retail Margins increased $69 million primarily due to the following:
A $58 million increase at SWEPCo primarily due to base rate revenue increases in Arkansas and Louisiana and rider increases in all retail jurisdictions. These increases were partially offset in other expense items below.
An $18A $54 million increase at I&M due to a base rate revenue increase in Indianaweather-normalized margins primarily in the residential and rider increases.commercial classes.
A $15 million increase at APCo due to a base rate increase in Virginia implemented in October 2022 following the Virginia Supreme Court remand. This increase was partially offset in Other Operation and Maintenance expense below.
A $14$47 million increase in deferred fuel at APCo primarily due to the timing of recoverable expenses. This increase was offset in other expense items below.
A $10 million increase inbase rate and rider revenues at PSO. This increase was partially offset in other expense items below.
A $9$44 million increase at APCo due to rider revenues in Virginia and West Virginia. This increase was partially offset in other expense items below.
A $40 million increase due to a reductionlower customer refunds related to Tax Reform. This increase was offset in a provision for refund at I&M.Income Tax Benefit below.
These increases were partially offset by:
An $83A $151 million decrease in weather-related usage primarily in the residential class.
24



A $26 million decrease at PSO and SWEPCo due to an increase in PTC benefits provided to customers. This increase in PTC benefits was offset in Income Tax Benefit below.
Margins from Off-system Sales increased $27$33 million primarily due to Rockport Plant, Unit 2 merchant activity and estimatedoperations including PJM performance incentives for Rockport Plant, Unit 2 merchant operations related to winter storm Elliott in December 2022.2022, partially offset by reduced Turk Plant merchant sales.
Transmission Revenues decreased $12 million primarily due to transmission formula rate true-up activity.
26


Other Revenuesdecreased $7$8 million primarily due to the following:
A $4 million decrease at APCo primarily due to pole attachment revenue. This decrease was partially offset in Other Operation and Maintenance expenses below.
A $4 million decrease at I&M due to a reduction in the sale of allowances. This decrease was partially offset in Retail Margins above.

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

Other Operation and Maintenance expenses increased $63$98 million primarily due to the following:
A $32$30 million increase in generation expenses primarily due to plant outages and maintenance at I&M and APCo.&M.
An $11A $29 million increase in accounts receivable factoring expenses primarily due to increased interest rates.
A $10$27 million increase in distribution storm expenses primarily due to major storms at APCo.
A $21 million increase at APCo due to the amortization of a regulatory asset in accordance with the August 2022 Virginia Supreme Court opinion related to under-earnings during the 2017-2019 Triennial Review. This increase was offset in Retail Margins above.
A $14 million increase at APCo due to gains from the sale of land in 2022.
An $11 million increase in distribution expenses.
These increases were partially offset by:
A $9$43 million increasedecrease in employee-related expenses.
Asset Impairments and Other Related Charges decreased $25 million at APCo due to the 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 Assetdecreased Nuclear Electric Insurance Limited distribution$37 million at I&MAPCo due to the establishment of a regulatory asset in 2023.2022 based on an August 2022 Virginia Supreme Court opinion and resulting under-earning during the 2017-2019 Virginia Triennial Review.
Depreciation and Amortization expenses decreased $27$114 million primarily due to the following:
A $38a $138 million decrease at AEGCo and I&M primarily due to the expiration of the Rockport Plant, Unit 2 lease in December 2022, partially offset by an increase in depreciation expense at I&M due to the acquisition of Rockport Plant, Unit 2 at the end of the lease.
This decrease was partially offset by:
An $8 million increase at PSO 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 millionprimarily due to increasedthe following:
A $16 million increase primarily due to property taxes at SWEPCo and PSO driven by the investment in the NCWF.
A $6 million increase at APCo primarily due to an increase in Virginia state minimum taxes.
These increases were partially offset by:
A $14 million decrease at I&M primarily due to the repeal of the Indiana Utility Receipts Tax in July 2022. This decrease was partially offset in Retail Margins above.
Allowance for Equity Funds Used During Construction increased $10 millionprimarily due to higher AFUDC equity rates and CWIP.
Non-Service Cost Components of Net Periodic Benefit Cost decreased $13 million primarily due to additional loss amortization as the result of unfavorable asset returns during 2022, higher interest costs due to higher discount rates and the expiration of prior service credits from previous plan changes.
Interest Expense increased $22$88 million primarily due to higher long-term debt balances and higher interest rates primarily at APCo and PSO, partially offset by a settlement agreement in Louisiana which provided for $12 million of carrying charges on storm-related regulatory assets at SWEPCo.rates.
Income Tax ExpenseBenefit increased $36decreased $34 million primarily due to athe following:
A $38 million decrease in amortization of Excess ADIT. This decrease was partially offset in Retail Margins above.
A $12 million increase in state income tax.
An $11 million decrease due to unfavorable discrete adjustments.
These decreases were partially offset by:
A $27 million increase in PTC and ITC amortization. This increase was partially offset in Retail Margins above.

2527



TRANSMISSION AND DISTRIBUTION UTILITIES
Three Months Ended March 31,
Transmission and Distribution Utilities20232022
 (in millions)
Revenues$1,464.2 $1,246.8 
Purchased Electricity392.7 232.6 
Gross Margin1,071.5 1,014.2 
Other Operation and Maintenance491.9 428.5 
Depreciation and Amortization186.2 183.6 
Taxes Other Than Income Taxes178.8 164.4 
Operating Income214.6 237.7 
Other Income0.5 0.3 
Allowance for Equity Funds Used During Construction9.1 7.3 
Non-Service Cost Components of Net Periodic Benefit Cost14.0 11.9 
Interest Expense(88.1)(74.8)
Income Before Income Tax Expense150.1 182.4 
Income Tax Expense24.4 29.6 
Net Income125.7 152.8 
Net Income Attributable to Noncontrolling Interests— — 
Earnings Attributable to AEP Common Shareholders$125.7 $152.8 

Summary of KWh Energy Sales for Transmission and Distribution Utilities
Three Months EndedNine Months Ended
Three Months Ended March 31,September 30,September 30,
202320222023202220232022
(in millions of KWhs) (in millions of KWhs)
Retail:Retail:  Retail:    
ResidentialResidential6,266 6,977 Residential8,442 8,033 20,618 21,599 
CommercialCommercial6,744 5,999 Commercial8,574 7,538 22,711 20,478 
IndustrialIndustrial6,526 5,930 Industrial6,601 6,554 19,800 19,131 
MiscellaneousMiscellaneous168 171 Miscellaneous220 210 565 578 
Total Retail (a)Total Retail (a)19,704 19,077 Total Retail (a)23,837 22,335 63,694 61,786 
Wholesale (b)Wholesale (b)453 571 Wholesale (b)485 587 1,366 1,723 
Total KWhsTotal KWhs20,157 19,648 Total KWhs24,322 22,922 65,060 63,509 

(a)Represents energy delivered to distribution customers.
(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold to PJM.
26



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

Summary of Heating and Cooling Degree Days for Transmission and Distribution Utilities
Three Months EndedNine Months Ended
Three Months Ended March 31,September 30,September 30,
202320222023202220232022
(in degree days) (in degree days)
Eastern RegionEastern Region  Eastern Region    
Actual Heating (a)
Actual Heating (a)
1,344 1,864 
Actual Heating (a)
— 1,521 2,078 
Normal Heating (b)
Normal Heating (b)
1,891 1,886 
Normal Heating (b)
2,080 2,077 
Actual Cooling (c)
Actual Cooling (c)
— 
Actual Cooling (c)
625 755 809 1,115 
Normal Cooling (b)
Normal Cooling (b)
Normal Cooling (b)
697 688 1,005 989 
Western RegionWestern Region  Western Region    
Actual Heating (a)
Actual Heating (a)
141 278 
Actual Heating (a)
— — 143 278 
Normal Heating (b)
Normal Heating (b)
194 190 
Normal Heating (b)
— — 197 193 
Actual Cooling (d)
Actual Cooling (d)
271 88 
Actual Cooling (d)
1,719 1,478 2,945 2,701 
Normal Cooling (b)
Normal Cooling (b)
127 126 
Normal Cooling (b)
1,387 1,382 2,454 2,433 

(a)Heating degree days are calculated on a 55 degree temperature base.
(b)Normal Heating/Cooling represents the thirty-year average of degree days.
(c)Eastern Region cooling degree days are calculated on a 65 degree temperature base.
(d)Western Region cooling degree days are calculated on a 70 degree temperature base.

2728


Transmission and Distribution Utilities
Reconciliation of 2022 to 2023 Earnings Attributable to AEP Common Shareholders
(in millions)
  
Three Months Ended 
September 30,
Nine Months Ended 
September 30,
2022 Earnings Attributable to AEP Common Shareholders$165.5 $483.1 
  
Changes in Gross Margin: 
Retail Margins99.3 98.1 
Margins from Off-system Sales(5.5)35.9 
Transmission Revenues16.7 50.3 
Other Revenues4.1 (0.1)
Total Change in Gross Margin114.6 184.2 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(37.5)(99.5)
Depreciation and Amortization(18.6)(16.7)
Taxes Other Than Income Taxes(4.6)(14.2)
Other Income(0.8)(1.8)
Allowance for Equity Funds Used During Construction4.1 7.1 
Non-Service Cost Components of Net Periodic Benefit Cost2.2 6.4 
Interest Expense(8.4)(27.8)
Total Change in Expenses and Other(63.6)(146.5)
  
Income Tax Expense(10.5)(11.6)
Equity Earnings of Unconsolidated Subsidiary— (0.8)
  
2023 Earnings Attributable to AEP Common Shareholders$206.0 $508.4 

FirstThird Quarter of 2023 Compared to FirstThird Quarter of 2022
Reconciliation of First Quarter of 2022 to First Quarter of 2023
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
First Quarter of 2022$152.8 
Changes in Gross Margin:
Retail Margins22.0 
Margins from Off-system Sales24.1 
Transmission Revenues11.5 
Other Revenues(0.3)
Total Change in Gross Margin57.3 
Changes in Expenses and Other:
Other Operation and Maintenance(63.4)
Depreciation and Amortization(2.6)
Taxes Other Than Income Taxes(14.4)
Other Income0.2 
Allowance for Equity Funds Used During Construction1.8 
Non-Service Cost Components of Net Periodic Benefit Cost2.1 
Interest Expense(13.3)
Total Change in Expenses and Other(89.6)
Income Tax Expense5.2 
First Quarter of 2023$125.7 

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

Retail Margins increased $22$99 million primarily due to the following:
A $29$43 million increase due to various rider revenuesin revenue from rate riders in Ohio. This increase was partially offset in Margins from Off-system Sales and other expense items below.
A $24 million increase in weather-normalized revenues in all retail classes.
A $23 million net increase in Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset in Other Operation and Maintenance expenses below.
A $7 million increase in revenue from rate riders in Texas. This increase was partially offset in other expense items below.
Margins from Off-system Sales decreased $6 million due to the following:
A $32 million decrease in off-system sales at OVEC due to lower market prices and volume. This decrease was offset in Retail Margins above.
This decrease was partially offset by:
A $26 million increase in deferrals of OVEC costs. This increase was offset in Retail Margins above.
Transmission Revenues increased $17 million primarily due to the following:
An $18$8 million increase due to interim rate increases driven by increased investmentload in Texas.
A $15$6 million increase in interim rates driven by increased transmission investments in Texas.
29


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

Other Operation and Maintenance expenses increased $38 million primarily due to the following:
A $20 million increase due to an energy assistance program for qualified Ohio customers. This increase was offset in Retail Margins above.
A $19 million increase in transmission expenses primarily due to an increase in recoverable PJM expense. This increase was offset in Retail Margins above.
A $7 million increase in distribution expenses primarily due to vegetation management in Ohio. This increase was offset in Retail Margins above.
These increases were partially offset by:
A $7 million decrease due to employee-related expenses in Texas.
Depreciation and Amortization expenses increased $19 million primarily due to the following:
A $25 million increase in depreciation expense primarily due to an increase in depreciable base.
This increase was partially offset by:
A $9 million decrease in recoverable DIR expense in Ohio. This decrease was offset in Retail Margins above.
Interest Expense increased $8 million primarily due to higher long-term debt balances and interest rates in Texas.
Income Tax Expense increased $11 million primarily due to an increase in pretax book income.

Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022

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

Retail Margins increased $98 million primarily due to the following:
An $86 million increase in revenue from rate riders in Ohio. This increase was partially offset in Margins from Off-system Sales and other expense items below.
A $57 million net increase in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset in Other Operation and Maintenance expenses below.
These increases were partially offset by:
A $25$47 million decrease in weather-related usage in Ohio due to a 27% decrease in heating degree days and a 28% decrease in heatingcooling degree days.days in Ohio.
A $13$9 million decrease in weather-normalized revenues inprimarily due to the residential and commercial classes, partially offset by the industrial class.class in Texas.
Margins from Off-system Sales increased $24$36 million primarily due to the following:
A $34$111 million increase in deferrals of OVEC costs in Ohio.costs. This increase was offset in Retail Margins above.
This increase was partially offset by:
A $10$75 million decrease in off-system sales at OVEC in Ohio due to lower market prices and volume. This decrease was offset in Retail Margins above.
Transmission Revenues increased $12$50 million primarily due to the following:
A $24 million increase in interim rate increasesrates driven by increased transmission investmentinvestments in Texas.
A $22 million increase due to increased load in Texas.

28



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

Other Operation and Maintenance expenses increased $63$100 million primarily due to the following:
A $29$68 million increase relateddue to an energy assistance program for qualified Ohio customers. This increase was offset in Retail Margins above.
A $14 million increase in ERCOT transmission expenses. This increase was partially offset in Retail Margins and Transmission Revenues above.
A $9 million increase in distribution-related expenses in Texas.
A $5$41 million increase in transmission expenses in Ohio primarily due to anto:
A $33 million increase in recoverable PJM expenses. This increase was offset in Retail Margins above.
An $11 million increase in transmission formula rate true-up activity in Ohio.
A $15 million increase in distribution expenses due to vegetation management in Ohio. This increase was offset in Retail Margins above.
30


A $14 million increase in distribution-related expenses in Texas.
These increases were partially offset by:
A $30 million decrease due to legislation passed in Texas in May 2023 allowing employee financially based incentives to be recovered.
A $24 million decrease in employee-related expenses.
A $5 million decrease in transmission expenses in Texas. This decrease was offset in Retail Margins above.
Depreciation and Amortization expenses increased $17 million primarily due to the following:
A $50 million increase in depreciation expense primarily due to an increase in depreciable base.
A $5 million increase in recoverable smart grid depreciable expenses in Ohio. This increase was offset in Retail Margins above.
These increases were partially offset by:
A $30 million decrease in recoverable DIR expense in Ohio. This decrease was offset in Retail Margins above.
An $11 million decrease in recoverable advanced metering system depreciable expenses in Texas.
Taxes Other Than Income Taxes increased $14 million primarily due to higher property taxes asdriven by increased investments in Texas.
Allowance for Equity Funds Used During Construction increased $7 milliondue to a result of increased distribution and transmission investmenthigher AFUDC base in Ohio and Texas and higher tax rates in Ohio.Texas.
Interest Expenseincreased $13$28 million primarily due to:
A $48 million increase primarily due to higher long-term debt balances and higher interest rates.
This increase was partially offset by:
A $16 million decrease due to an increase in AFUDC base.
Income Tax Expense decreased $5increased $12 million primarily due to a decreasean increase in pretax book income.
2931



AEP TRANSMISSION HOLDCO
Three Months Ended March 31,
AEP Transmission Holdco20232022
 (in millions)
Transmission Revenues$455.5 $411.4 
Other Operation and Maintenance36.7 31.7 
Depreciation and Amortization97.5 85.3 
Taxes Other Than Income Taxes76.8 67.3 
Operating Income244.5 227.1 
Interest and Investment Income1.9 0.1 
Allowance for Equity Funds Used During Construction16.4 15.6 
Non-Service Cost Components of Net Periodic Benefit Cost1.6 1.3 
Interest Expense(47.2)(39.1)
Income Before Income Tax Expense and Equity Earnings217.2 205.0 
Income Tax Expense52.3 50.4 
Equity Earnings of Unconsolidated Subsidiary17.5 19.1 
Net Income182.4 173.7 
Net Income Attributable to Noncontrolling Interests0.9 0.6 
Earnings Attributable to AEP Common Shareholders$181.5 $173.1 

Summary of Investment in Transmission Assets for AEP Transmission Holdco
March 31,September 30,
2023202220232022
(in millions)(in millions)
Plant in ServicePlant in Service$13,376.3 $12,042.4 Plant in Service$14,042.9 $12,628.6 
Construction Work in ProgressConstruction Work in Progress1,959.1 1,640.4 Construction Work in Progress2,037.0 1,760.3 
Accumulated Depreciation and AmortizationAccumulated Depreciation and Amortization1,128.2 873.3 Accumulated Depreciation and Amortization1,261.2 1,000.3 
Total Transmission Property, NetTotal Transmission Property, Net$14,207.2 $12,809.5 Total Transmission Property, Net$14,818.7 $13,388.6 
30


AEP Transmission Holdco
Reconciliation of 2022 to 2023 Earnings Attributable to AEP Common Shareholders
(in millions)
Three Months Ended 
September 30,
Nine Months Ended 
September 30,
2022 Earnings Attributable to AEP Common Shareholders$170.5 $485.4 
Changes in Transmission Revenues:
Transmission Revenues45.8 169.7 
Total Change in Transmission Revenues45.8 169.7 
Changes in Expenses and Other:
Other Operation and Maintenance7.2 4.5 
Depreciation and Amortization(12.4)(35.2)
Taxes Other Than Income Taxes(5.0)(14.1)
Interest and Investment Income1.4 5.9 
Allowance for Equity Funds Used During Construction2.4 11.0 
Non-Service Cost Components of Net Periodic Pension Cost0.2 0.8 
Interest Expense(9.2)(29.5)
Total Change in Expenses and Other(15.4)(56.6)
Income Tax Expense1.0 (16.8)
Equity Earnings of Unconsolidated Subsidiary1.1 (0.5)
Net Income Attributable to Noncontrolling Interests(0.1)(0.4)
2023 Earnings Attributable to AEP Common Shareholders$202.9 $580.8 

FirstThird Quarter of 2023 Compared to FirstThird Quarter of 2022
Reconciliation of First Quarter of 2022 to First Quarter of 2023
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
First Quarter of 2022$173.1 
Changes in Transmission Revenues:
Transmission Revenues44.1 
Total Change in Transmission Revenues44.1 
Changes in Expenses and Other:
Other Operation and Maintenance(5.0)
Depreciation and Amortization(12.2)
Taxes Other Than Income Taxes(9.5)
Interest and Investment Income1.8 
Allowance for Equity Funds Used During Construction0.8 
Non-Service Cost Components of Net Periodic Pension Cost0.3 
Interest Expense(8.1)
Total Change in Expenses and Other(31.9)
Income Tax Expense(1.9)
Equity Earnings of Unconsolidated Subsidiary(1.6)
Net Income Attributable to Noncontrolling Interests(0.3)
First Quarter of 2023$181.5 

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

Transmission Revenues increased $44$46 million primarily due to continued investment in transmission assets.

Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses increased $5decreased $7 million primarily due to higher vegetation management expenses, affiliated rent expense and other miscellaneousthe following:
A $5 million decrease due to cancelled capital projects in 2022.
A $3 million decrease in employee-related expenses.
32


Depreciation and Amortization expenses increased $12 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $10$5 million primarily due to higher property taxes as a result ofdriven by increased transmission investment.
Interest Expense increased $8$9 million primarily due to higher long-term debt balances and interest rates.

Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022

The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and nonaffiliates, were as follows:
Transmission Revenues increased $170 million primarily due to the following:
A $131 million increase due to continued investment in transmission assets.
A $33 million increase due to affiliated transmission formula rate true-up activity. This increase was offset in Other Operation and Maintenance expenses across the other Registrant Subsidiaries.
A $6 million increase due to nonaffiliated transmission formula rate true-up activity.
Expenses and Other and Income Tax Expense changed between years as follows:
Depreciation and Amortization expenses increased $35 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $14 million primarily due to higher property taxes driven by increased transmission investment.
Interest and Investment Income increased $6 million primarily due to higher advances to affiliates and higher interest rates.
Allowance for Equity Funds Used During Construction increased $11 million primarily due to higher CWIP and AFUDC equity rates.
Interest Expense increased $30 million primarily due to higher long-term debt balances and interest rates.
Income Tax Expense increased $17 million primarily due to an increase in pretax book income.




31
33



GENERATION & MARKETING
Three Months Ended March 31,
Generation & Marketing20232022
 (in millions)
Revenues$327.0 $619.3 
Fuel, Purchased Electricity and Other382.3 448.1 
Gross Margin(55.3)171.2 
Other Operation and Maintenance43.0 32.5 
Loss on the Expected Sale of the Competitive Contracted Renewable Portfolio112.0 — 
Depreciation and Amortization18.2 23.3 
Taxes Other Than Income Taxes2.8 3.1 
Operating Income (Loss)(231.3)112.3 
Interest and Investment Income9.0 2.1 
Non-Service Cost Components of Net Periodic Benefit Cost6.6 5.1 
Interest Expense(24.3)(5.0)
Income (Loss) Before Income Tax Benefit and Equity Earnings (Loss)(240.0)114.5 
Income Tax Benefit(78.1)(6.7)
Equity Earnings (Loss) of Unconsolidated Subsidiaries5.5 (5.2)
Net Income (Loss)(156.4)116.0 
Net Income Attributable to Noncontrolling Interests1.3 1.8 
Earnings (Loss) Attributable to AEP Common Shareholders$(157.7)$114.2 

Generation & Marketing
Reconciliation of 2022 to 2023 Earnings (Loss) Attributable to AEP Common Shareholders
(in millions)
  
Three Months Ended 
September 30,
Nine Months Ended 
September 30,
2022 Earnings Attributable to AEP Common Shareholders$97.5 $284.3 
  
Changes in Gross Margin: 
Merchant Generation12.5 7.9 
Renewable Generation(26.3)(34.8)
Retail, Trading and Marketing4.6 (344.3)
Total Change in Gross Margin(9.2)(371.2)
  
Changes in Expenses and Other: 
Other Operation and Maintenance13.5 (59.2)
Loss on the Sale of the Competitive Contracted Renewables Portfolio— (112.0)
Gain on Sale of Mineral Rights— (116.3)
Depreciation and Amortization14.8 34.1 
Taxes Other Than Income Taxes1.5 3.2 
Interest and Investment Income(1.0)10.8 
Non-Service Cost Components of Net Periodic Benefit Cost1.5 4.3 
Interest Expense(2.0)(38.5)
Total Change in Expenses and Other28.3 (273.6)
  
Income Tax Benefit11.1 102.0 
Equity Earnings of Unconsolidated Subsidiaries6.4 202.5 
Net Loss Attributable to Noncontrolling Interests(3.4)(3.3)
  
2023 Earnings (Loss) Attributable to AEP Common Shareholders$130.7 $(59.3)

Summary of MWhs Generated for Generation & Marketing
Three Months Ended March 31,
20232022
 (in millions of MWhs)
Fuel Type:  
Coal
Renewables
Total MWhs
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FirstThird Quarter of 2023 Compared to FirstThird Quarter of 2022
Reconciliation of First Quarter of 2022 to First Quarter of 2023
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
First Quarter of 2022$114.2 
Changes in Gross Margin:
Merchant Generation0.1 
Renewable Generation(1.9)
Retail, Trading and Marketing(224.7)
Total Change in Gross Margin(226.5)
Changes in Expenses and Other:
Other Operation and Maintenance(10.5)
Loss on the Expected Sale of the Competitive Contracted Renewable Portfolio(112.0)
Depreciation and Amortization5.1 
Taxes Other Than Income Taxes0.3 
Interest and Investment Income6.9 
Non-Service Cost Components of Net Periodic Benefit Cost1.5 
Interest Expense(19.3)
Total Change in Expenses and Other(128.0)
Income Tax Benefit71.4 
Equity Earnings (Loss) of Unconsolidated Subsidiaries10.7 
Net Income Attributable to Noncontrolling Interests0.5 
First Quarter of 2023$(157.7)

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

Merchant Generation increased $13 million primarily due to higher hedge gains related to the Cardinal Plant.
Renewable Generation decreased $26 million primarily due to lower production in 2023 and the sale of the competitive contracted renewables portfolio in August 2023.

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

Other Operation and Maintenance expenses decreased $14 million primarily due to:
A $7 million decrease due to the sale of the competitive contracted renewables portfolio in August 2023.
A $5 million decrease due to an increase in proceeds received for insurance policy settlements.
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Depreciation and Amortization decreased $15 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.
Income Tax Benefit increased $11 million primarily due to:
A $30 million increase due to favorable discrete adjustments primarily related to the amortization of deferred ITCs from the sale of competitive contracted renewables portfolio.
This increase was partially offset by:
An $11 million decrease in PTCs.
A $5 million decrease due to an increase in pretax book income.
A $3 million increase in state taxes.
Equity Earnings of Unconsolidated Subsidiaries increased $6 million primarily due to the sale of competitive contracted renewables portfolio in August 2023.

Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022

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

Merchant Generation increased $8 million primarily due to higher asset hedge gains.
Renewable Generation decreased $35 million primarily due to lower production in 2023 and the sale of competitive contracted renewables portfolio in August 2023.
Retail, Trading and Marketing decreased $225$344 million primarily due to a $145$222 million unrealized loss on economic hedge activity in 2023 and a $126$208 million unrealized gain on economic hedge activity in 2022 driven by changes in commodity prices.

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

Other Operation and Maintenance expenses increased $11$59 million primarily due to a decrease in land sales.sales and a prior year sale of renewable development projects.
Loss on the Expected Sale of the Competitive Contracted RenewableRenewables Portfolio increased $112 million due to the pre-taxpretax loss on the expected sale recorded in 2023.
Gain on Sale of Mineral Rights decreased $116 million due to the prior year sale of mineral rights.
Depreciation and Amortizationexpenses decreased $5$34 million primarily due to the ceasing of depreciation on the competitive contracted renewablerenewables portfolio assets as a result of held for sale classification and subsequent sale in 2023.
Interest and Investment Incomeincreased $7$11 million primarily due to higher interest rates on advances to affiliates.
Interest Expense increased $19$39 million due to higher borrowing costsinterest rates in 2023.
Income Tax Benefit increased $71$102 million primarily due to:
A $94 million increase due to a decrease in pretax book income.
A $35 million increase due to favorable discrete adjustments primarily related to the amortization of deferred ITCs from the sale of competitive contracted renewables portfolio.
These increases were partially offset by:
A $26 million decrease in PTCs.
Equity Earnings (Loss) of Unconsolidated Subsidiariesincreased $11$203 million primarily due to increased production from renewable assets.the prior year impairment of AEP’s investment in Flat Ridge 2 Wind LLC.
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CORPORATE AND OTHER

FirstThird Quarter of 2023 Compared to FirstThird Quarter of 2022

Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $24$227 million in 2022 to a loss of $14$98 million in 2023 primarily due to:

A $44$195 million pretax loss in 2022 related to the termination of the sale of the Kentucky Operations.
A $21 million increase in interest income, primarily due to higher interest income from affiliates.
An $18 million decrease in corporate expenses.
A $17 million increase in business development income.
A $10 million increase at EIS, primarily due to higher returns on investments.
These increases in earnings were partially offset by:
A $73 million increase in Income Tax Expense primarily due to a $42 million increase driven by increased pretax book income and a $30 million increase due to less favorable consolidating tax adjustments.
A $72 million increase in interest expense due to higher interest rates and an increase in debt balances.


Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022

Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $406 million in 2022 to a loss of $210 million in 2023 primarily due to:

A $263 million pretax loss in 2022 related to the termination of the sale of the Kentucky Operations.
A $96 million increase in interest income, primarily due to higher interest income from affiliates.
A $36$54 million decrease in corporate expenses, primarily due to adjustments driven by the termination of the sale of Kentucky operations.Operations.
A $17$42 million increase in factoring revenues from affiliates.
A $38 million increase at EIS, primarily due to higher returns on investments and a decrease in reserves.

investments.
These itemsincreases in were partially offset by:

A $91$259 million increase in interest expense due to higher interest rates and an increase in short-term and long-term debt outstanding.balances.
A $52 million decrease in Income Tax Benefit primarily due to an increase in pretax book income.


AEP SYSTEM INCOME TAXES

FirstThird Quarter of 2023 Compared to FirstThird Quarter of 2022

Income Tax Expense decreased $42increased $80 million primarily due to:
A $75 million increase due to a decreasean increase in pretax book income,income.
A $23 million decrease in PTCs.
A $20 million increase in state taxes.
These increases in Income Tax Expense were partially offset by aby:
A $41 million decrease due to discrete adjustments in benefit2023 primarily related to the amortization of deferred ITCs from PTCs and athe sale of the competitive contracted renewables portfolio.

Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022

Income Tax Expense increased $12 million primarily due to:
A $38 million decrease in amortization of Excess ADIT.

A $20 million decrease in PTCs.
A $20 million increase in state taxes.
These increases in Income Tax Expense were partially offset by:
A $51 million decrease due to discrete adjustments in 2023 primarily related to the amortization of deferred ITCs from the sale of the competitive contracted renewables portfolio and an outside basis adjustment related to the termination of the sale of the Kentucky Operations.
A $16 million decrease in flow-through depreciation.
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FINANCIAL CONDITION

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

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization
March 31, 2023December 31, 2022 September 30, 2023December 31, 2022
(dollars in millions) (dollars in millions)
Long-term Debt, including amounts due within one yearLong-term Debt, including amounts due within one year$39,144.2 58.7 %$36,801.0 56.6 %Long-term Debt, including amounts due within one year$39,489.1 58.4 %$36,801.0 56.6 %
Short-term DebtShort-term Debt3,622.1 5.4 4,112.2 6.3 Short-term Debt2,730.4 4.0 4,112.2 6.3 
Total DebtTotal Debt42,766.3 64.1 40,913.2 62.9 Total Debt42,219.5 62.4 40,913.2 62.9 
AEP Common EquityAEP Common Equity23,738.2 35.6 23,893.4 36.7 AEP Common Equity25,309.7 37.5 23,893.4 36.7 
Noncontrolling InterestsNoncontrolling Interests229.6 0.3 229.0 0.4 Noncontrolling Interests39.9 0.1 229.0 0.4 
Total Debt and Equity CapitalizationTotal Debt and Equity Capitalization$66,734.1 100.0 %$65,035.6 100.0 %Total Debt and Equity Capitalization$67,569.1 100.0 %$65,035.6 100.0 %

AEP’s ratio of debt-to-total capital increaseddecreased from 62.9% as of December 31, 2022 to 64.1%62.4% as of March 31,September 30, 2023 primarily due to the issuance of common equity in connection with the settlement of the forward equity purchase contracts related to the 2020 Equity Units in addition to the utilization of cash proceeds received from the sale of the competitive contracted renewables portfolio which were used to reduce Short-term Debt, partially offset by an increase in debtLong-term Debt to support distribution, transmission and renewable investment growth in addition to working capital needs.

Liquidity

Liquidity, or access to cash, is an important factor in determining AEP’s financial stability.  Management believes AEP has adequate liquidity.  As of March 31,September 30, 2023, AEP had $5 billion of revolving credit facilities to support its commercial paper program.  Additional liquidity is available from cash from operations and a receivables securitization agreement.  Management is committed to maintaining adequate liquidity.  AEP generally uses short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged.  Sources of long-term funding include issuance of long-term debt, long-term asset securitizations, leasing agreements, hybrid securities or common stock. AEP and its utilities finance its operations with commercial paper and other variable rate instruments that are subject to fluctuations in interest rates. To the extent that the Federal Reserve continuesinterest rates continue to raise short-term interest rates,rise, 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 threenine months ended March 31,September 30, 2023. 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 February 2023, AEP entered into a $500 million term loan. Additionally, in April 2023, AEP made a $125 million capital contribution to AEP Texas and a $125 million capital contribution to OPCo. In May 2023, AEP made an additional $50 million capital contribution to AEP Texas. These contributions were made to address short-term liquidity needs.


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Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments.  As of March 31,September 30, 2023, available liquidity was approximately $3.4$3.5 billion as illustrated in the table below:
AmountMaturity
Commercial Paper Backup:(in millions)
Revolving Credit Facility$4,000.0 March 2027
Revolving Credit Facility1,000.0 March 2025(a)
Cash and Cash Equivalents343.5353.3  
Total Liquidity Sources5,343.55,353.3  
Less:AEP Commercial Paper Outstanding1,981.11,826.5  
Net Available Liquidity$3,362.43,526.8  
(a)In March 2023, AEP extended the maturity date of the $1 billion Revolving Credit Facility from March 2024 to March 2025.
AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries.  The program funds a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and the short-term debt requirements of subsidiaries that are not participating in either money pool for regulatory or operational reasons, as direct borrowers.  The maximum amount of commercial paper outstanding during the first threenine months of 2023 was $3.2 billion.  The weighted-average interest rate for AEP’s commercial paper during 2023 was 5.06%5.31%.

Other Credit Facilities

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under six uncommitted facilities totaling $450 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of March 31,September 30, 2023 was $299$249 million with maturities ranging from AprilOctober 2023 to MarchSeptember 2024.

Securitized Accounts Receivables

AEP Credit’s receivables securitization agreement provides a commitment of $750$900 million from bank conduits to purchase receivables and includes a $125receivables. The agreement was amended in August 2023 to increase the commitment from $750 million and a $625 million facility, both of which expireexpires in September 2024.2025. As of March 31,September 30, 2023, the affiliated utility subsidiaries were in compliance with all requirements under the agreement. SWEPCo temporarily eased credit policies from August 2022 through October 2022 to assist customers with higher than normal bills driven by increased fuel costs and, in turn, experienced higher than normal aged receivables. In response, in January 2023, AEP Credit amended its receivables securitization agreement to increase the eligibility criteria related to their aged receivables requirements to ensure SWEPCo remains in compliance.

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 March 31,September 30, 2023, this contractually-defined percentage was 61.2%59.4%. 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.

36



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.

38


ATM Program

AEP participates in an ATM offering program that allows AEP to issue, from time to time, up to an aggregate of $1 billion of its common stock, including shares of common stock that may be sold pursuant to an equity forward sales agreement. There were no issuances under the ATM program for the threenine months ended March 31,September 30, 2023. As of March 31,September 30, 2023, approximately $511 million of equity is available for issuance under the ATM offering program. See Note 12 - Financing Activities for additional information.

Equity Units

In August 2020, AEP issued 17 million Equity Units initially in the form of corporate units, at a stated amount of $50 per unit, for a total stated amount of $850 million. Net proceeds from the issuance were approximately $833 million. Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 1.30% Junior Subordinated Notes due in 2025 and a forward equity purchase contract which settlessettled 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 12 - Financing Activities for additional information.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.83$0.88 per share in AprilOctober 2023. Future dividends may vary depending upon AEP’s profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. Management does not believe these restrictions will have any significant impact on its ability to access cash to meet the payment of dividends on its common stock. See “Dividend Restrictions” section of Note 12 for additional information.

Credit Ratings

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


3739



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.
Three Months Ended 
March 31,
Nine Months Ended 
September 30,
20232022 20232022
(in millions) (in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of PeriodCash, Cash Equivalents and Restricted Cash at Beginning of Period$556.5 $451.4 Cash, Cash Equivalents and Restricted Cash at Beginning of Period$556.5 $451.4 
Net Cash Flows from Operating ActivitiesNet Cash Flows from Operating Activities717.8 1,622.2 Net Cash Flows from Operating Activities3,675.7 4,733.2 
Net Cash Flows Used for Investing ActivitiesNet Cash Flows Used for Investing Activities(2,245.2)(2,893.2)Net Cash Flows Used for Investing Activities(4,643.5)(5,822.5)
Net Cash Flows from Financing ActivitiesNet Cash Flows from Financing Activities1,364.4 1,545.1 Net Cash Flows from Financing Activities818.4 1,215.2 
Net Increase (Decrease) in Cash and Cash EquivalentsNet Increase (Decrease) in Cash and Cash Equivalents(163.0)274.1 Net Increase (Decrease) in Cash and Cash Equivalents(149.4)125.9 
Cash, Cash Equivalents and Restricted Cash at End of PeriodCash, Cash Equivalents and Restricted Cash at End of Period$393.5 $725.5 Cash, Cash Equivalents and Restricted Cash at End of Period$407.1 $577.3 

Operating Activities
Three Months Ended 
March 31,
Nine Months Ended 
September 30,
2023202220232022
(in millions)(in millions)
Net IncomeNet Income$400.4 $718.1 Net Income$1,874.8 $1,922.2 
Non-Cash Adjustments to Net Income (a)Non-Cash Adjustments to Net Income (a)924.2 743.7 Non-Cash Adjustments to Net Income (a)2,469.5 2,661.1 
Mark-to-Market of Risk Management ContractsMark-to-Market of Risk Management Contracts(82.0)282.3 Mark-to-Market of Risk Management Contracts(82.8)162.3 
Property TaxesProperty Taxes(101.6)(82.0)Property Taxes486.1 459.9 
Deferred Fuel Over/Under-Recovery, NetDeferred Fuel Over/Under-Recovery, Net128.0 (148.8)Deferred Fuel Over/Under-Recovery, Net542.8 (148.7)
Change in Other Noncurrent AssetsChange in Other Noncurrent Assets(96.0)49.4 Change in Other Noncurrent Assets(396.8)(6.0)
Change in Other Noncurrent LiabilitiesChange in Other Noncurrent Liabilities(58.7)36.9 Change in Other Noncurrent Liabilities(21.5)324.0 
Change in Certain Components of Working CapitalChange in Certain Components of Working Capital(396.5)22.6 Change in Certain Components of Working Capital(1,196.4)(641.6)
Net Cash Flows from Operating ActivitiesNet Cash Flows from Operating Activities$717.8 $1,622.2 Net Cash Flows from Operating Activities$3,675.7 $4,733.2 

(a)Non-Cash Adjustments to Net Income includes Depreciation and Amortization, Deferred Income Taxes, Loss on the Expected Sale of the Kentucky Operations, Loss on the Sale of the Competitive Contracted RenewableRenewables Portfolio, Asset Impairments and AFUDC.Other Related Charges, Impairment of Equity Method Investment, AFUDC, Gain on Sale of Mineral Rights and Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset.

Net Cash Flows from Operating Activities decreased by $904 million$1.1 billion primarily due to the following:
A $419 million decrease in cash from the Change in Certain Components of Working Capital. The decrease is primarily due to the timing of accounts payable, increases in fuel, material and supplies driven by coal inventory on hand as a result of the mild winter weather and a decrease in margin deposits due to unfavorable current year pricing variances and the return of deposits from PJM received in the prior year. These decreases were partially offset by the timing of accounts receivable.
A $364 million decrease primarily due to a reduction in collateral held associated with risk management contracts driven by the reduction in commodity prices.
A $241$736 million decrease in cash from Changes in Other Noncurrent Assets and Liabilities. This decrease is primarily due to changes in regulatory assets and liabilities driven by timing differences between collections from and refunds to customers under rate rider mechanisms.
A $137$555 million decrease in cash from the Change in Certain Components of Working Capital. The decrease is primarily due to the timing of accounts payable and property tax payments, increases in fuel, material and supplies driven by coal inventory on hand as a result of the mild current year weather and a decrease in margin deposits held due to unfavorable current year pricing variances. These decreases were partially offset by the timing of accounts receivable collections.
A $245 million decrease primarily due to a reduction in collateral held associated with risk management contracts driven by the reduction in commodity prices.
A $239 million decrease in cash from Net Income, after non-cash adjustments. See Results of Operations for further detail.

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These decreases in cash were partially offset by:
A $277$692 million increase in cash primarily due to the timing of fuel and purchase power revenues and expenses. See the “Deferred Fuel Costs” section of Executive Overview for additional information.

Investing Activities
Three Months Ended 
March 31,
Nine Months Ended 
September 30,
20232022 20232022
(in millions) (in millions)
Construction ExpendituresConstruction Expenditures$(2,090.1)$(1,686.6)Construction Expenditures$(5,767.1)$(4,748.5)
Acquisitions of Nuclear FuelAcquisitions of Nuclear Fuel(1.7)(31.1)Acquisitions of Nuclear Fuel(60.9)(91.9)
Acquisitions of Renewable Energy FacilitiesAcquisitions of Renewable Energy Facilities(145.7)(1,207.3)Acquisitions of Renewable Energy Facilities(154.0)(1,207.3)
Proceeds from Sale of AssetsProceeds from Sale of Assets1,335.6 215.7 
OtherOther(7.7)31.8 Other2.9 9.5 
Net Cash Flows Used for Investing ActivitiesNet Cash Flows Used for Investing Activities$(2,245.2)$(2,893.2)Net Cash Flows Used for Investing Activities$(4,643.5)$(5,822.5)

Net Cash Flows Used for Investing Activities decreased by $648 million$1.2 billion primarily due to the following:
A $1.1 billion decrease primarily due to the 2022 acquisition of Traverse, partially offset by the 2023 acquisition of the Rock Falls Wind Facility. See “Acquisitions” section of Note 6 for additional information.
This decreaseA $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 mineral rights in 2022. See “Dispositions” section of Note 6 for additional information.
These decreases in cash used waswere partially offset by:
A $404 million$1 billion increase in Construction Expenditures, primarily due to increases in Vertically Integrated Utilities of $218$489 million, and Transmission and Distribution Utilities of $167$394 million and AEP Transmission Holdco of $180 million.

Financing Activities
Three Months Ended 
March 31,
Nine Months Ended 
September 30,
20232022 20232022
(in millions) (in millions)
Issuance of Common StockIssuance of Common Stock$41.1 $809.5 Issuance of Common Stock$959.3 $827.2 
Issuance/Retirement of Debt, NetIssuance/Retirement of Debt, Net1,837.7 1,214.9 Issuance/Retirement of Debt, Net1,282.7 1,837.6 
Dividends Paid on Common StockDividends Paid on Common Stock(431.8)(398.8)Dividends Paid on Common Stock(1,293.8)(1,212.5)
OtherOther(82.6)(80.5)Other(129.8)(237.1)
Net Cash Flows from Financing ActivitiesNet Cash Flows from Financing Activities$1,364.4 $1,545.1 Net Cash Flows from Financing Activities$818.4 $1,215.2 

Net Cash Flows from Financing Activities decreased by $181$397 million primarily due to the following:
A $1.3$1.5 billion decrease due to changes in short-term debt. See Note 12 - Financing Activities for additional information.
A $768 millionThis decrease in issuances of common stock primarily due to the prior year settlement of the 2019 equity units.
A $469 million increase in retirements of long-term debt. See Note 12 - Financing Activities for additional information.
These decreases in cash werewas partially offset by:
A $2.3 billion$589 million increase in issuances of long-term debt. See Note 12 - Financing Activities for additional information.
A $326 million decrease in retirements of long-term debt. See Note 12 - Financing Activities for additional information.
A $132 million increase in issuances of common stock primarily due to the current year settlement of the 2020 equity units partially offset by the prior year settlement of the 2019 equity units.

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See the “Long-term Debt Subsequent Events” section of Note 12 for Long-term debt and other securities issued, retired and principal payments made after March 31,September 30, 2023 through May 4,November 2, 2023, the date that the firstthird quarter 10-Q was filed.


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BUDGETED CAPITAL EXPENDITURES

Management forecasts approximately $6.8 billion of capital expenditures of $7.1 billion in 2023. For the four year period, 2024 through 2027, management forecasts capital expenditures of $32.9 billion. The expenditures are generally for transmission, generation, distribution, regulated renewables and required environmental investment to comply with the Federal EPA rules.  Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, supply chain issues, weather, legal reviews, 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 competitive contracted renewablesassets and financing activities.  Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged. For complete information of forecasted capital expenditures, see the “Budgeted Capital Expenditures” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2022 Annual Report.

SIGNIFICANT CASH REQUIREMENTS

A summary of significant cash requirements is included in the 2022 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING STANDARDS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

See the “Critical Accounting Policies and Estimates” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2022 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting standards.

ACCOUNTING STANDARDS

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

4042



QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

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

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

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

Management employs risk management contracts including physical forward and financial forward purchase-and-sale contracts.  Management engages in risk management of power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business.  As a result, AEP is subject to price risk.  The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors.  AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Regulated Risk Committee and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures.  The Regulated Risk Committee consists of AEPSC’s Chief Financial Officer, Chief Commercial Officer, Executive Vice President Utilities, Senior Vice President of Regulated Commercial Operations, Senior Vice President of Grid Solutions, Senior Vice President of Treasury and Risk and Chief Risk Officer.  The Competitive Risk Committee consists of AEPSC’s Chief Financial Officer, Chief Commercial Officer, Senior Vice President of Treasury and Risk, Senior Vice President of Competitive Commercial Operations and Chief Risk Officer.  When commercial activities exceed predetermined limits, positions are modified to reduce the risk to be within the limits unless specifically approved by the respective committee.
4143



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)MTM Risk Management Contract Net Assets (Liabilities)MTM Risk Management Contract Net Assets (Liabilities)
Three Months Ended March 31, 2023
Nine Months Ended September 30, 2023Nine Months Ended September 30, 2023
Vertically
Integrated
Utilities
Transmission
and
Distribution
Utilities
Generation
&
Marketing
TotalVertically
Integrated
Utilities
Transmission
and
Distribution
Utilities
Generation
&
Marketing
Total
(in millions) (in millions)
Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2022Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2022$134.7 $(40.0)$360.5 $455.2 Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2022$134.7 $(40.0)$360.5 $455.2 
Gain from Contracts Realized/Settled During the Period and Entered in a Prior Period(131.5)(0.3)(88.7)(220.5)
(Gain)/Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period(Gain)/Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period(136.6)1.1 (150.6)(286.1)
Fair Value of New Contracts at Inception When Entered During the Period (a)Fair Value of New Contracts at Inception When Entered During the Period (a)— — 0.4 0.4 Fair Value of New Contracts at Inception When Entered During the Period (a)— — 1.5 1.5 
Changes in Fair Value Due to Market Fluctuations During the Period (b)Changes in Fair Value Due to Market Fluctuations During the Period (b)(5.3)— (101.1)(106.4)Changes in Fair Value Due to Market Fluctuations During the Period (b)2.1 — (45.9)(43.8)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)Changes in Fair Value Allocated to Regulated Jurisdictions (c)28.8 (7.2)— 21.6 Changes in Fair Value Allocated to Regulated Jurisdictions (c)111.0 (11.9)— 99.1 
Total MTM Risk Management Contract Net Assets (Liabilities) as of September 30, 2023Total MTM Risk Management Contract Net Assets (Liabilities) as of September 30, 2023$111.2 $(50.8)$165.5 225.9 
Commodity Cash Flow Hedge Contracts
Commodity Cash Flow Hedge Contracts
 127.8 
Total MTM Risk Management Contract Net Assets (Liabilities) as of March 31, 2023$26.7 $(47.5)$171.1 150.3 
Commodity Cash Flow Hedge Contracts
 83.1 
Interest Rate Cash Flow Hedge Contracts
  7.2 
Fair Value Hedge ContractsFair Value Hedge Contracts  (120.5)Fair Value Hedge Contracts  (138.1)
Collateral DepositsCollateral Deposits  (92.7)Collateral Deposits  (92.6)
Total MTM Derivative Contract Net Assets as of March 31, 2023  $27.4 
Total MTM Derivative Contract Net Assets as of September 30, 2023Total MTM Derivative Contract Net Assets as of September 30, 2023  $123.0 

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

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


4244



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 March 31,September 30, 2023, credit exposure net of collateral to sub investment grade counterparties was approximately 0.6%5.25%, 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 March 31,September 30, 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 QualityCounterparty Credit QualityExposure
Before
Credit
Collateral
Credit
Collateral
Net
Exposure
Number of
Counterparties
>10% of
Net Exposure
Net Exposure
of
Counterparties
>10%
Counterparty Credit QualityExposure
Before
Credit
Collateral
Credit
Collateral
Net
Exposure
Number of
Counterparties
>10% of
Net Exposure
Net Exposure
of
Counterparties
>10%
(in millions, except number of counterparties) (in millions, except number of counterparties)
Investment GradeInvestment Grade$490.2 $108.3 $381.9 $120.4 Investment Grade$411.1 $83.6 $327.5 $123.3 
Split RatingSplit Rating10.4 — 10.4 10.4 Split Rating20.6 — 20.6 20.6 
Noninvestment Grade1.3 1.3 — — — 
No External Ratings:No External Ratings:    No External Ratings:    
Internal Investment GradeInternal Investment Grade40.7 — 40.7 25.1 Internal Investment Grade53.3 23.1 30.2 15.3 
Internal Noninvestment GradeInternal Noninvestment Grade3.4 1.0 2.4 2.3 Internal Noninvestment Grade46.7 25.7 21.0 17.5 
Total as of March 31, 2023$546.0 $110.6 $435.4 
Total as of September 30, 2023Total as of September 30, 2023$531.7 $132.4 $399.3 

All exposure in the table above relates to AEPSC and AEPEP as AEPSC is agent for and transacts on behalf of certain AEP subsidiaries, including the Registrant Subsidiaries and AEPEP is agent for and transacts on behalf of other AEP subsidiaries.

In addition, AEP is exposed to credit risk related to participation in RTOs. For each of the RTOs in which AEP participates, this risk is generally determined based on the proportionate share of member gross activity over a specified period of time.

Value at Risk (VaR) Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates VaR, to measure AEP’s commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, as of March 31,September 30, 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.
4345



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

VaR Model
Trading Portfolio
Three Months EndedTwelve Months Ended
March 31, 2023December 31, 2022
Nine Months EndedNine Months EndedTwelve Months Ended
September 30, 2023September 30, 2023December 31, 2022
EndEndHighAverageLowEndHighAverageLowEndHighAverageLowEndHighAverageLow
(in millions)(in millions)(in millions)(in millions)(in millions)
$0.2 $0.9 $0.3 $0.1 $0.5 $4.5 $0.7 $0.1 0.1 $0.9 $0.2 $0.1 $0.5 $4.5 $0.7 $0.1 

VaR Model
Non-Trading Portfolio
Three Months EndedTwelve Months Ended
March 31, 2023December 31, 2022
Nine Months EndedNine Months EndedTwelve Months Ended
September 30, 2023September 30, 2023December 31, 2022
EndEndHighAverageLowEndHighAverageLowEndHighAverageLowEndHighAverageLow
(in millions)(in millions)(in millions)(in millions)(in millions)
$8.7 $24.4 $14.9 $7.9 $17.7 $76.9 $24.7 $6.7 13.1 $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 a 4.25% increase. In the first quarternine months of 2023, the Federal Reserve approved another twofour rate increases for a cumulative total of a 0.5%1.0% rate increase and further increases in interest rates may be authorized during 2023. AEP has outstanding short and long-term debt which is subject to variable rates. AEP manages interest rate risk by limiting variable-rate exposures to a percentage of total debt, by entering into interest rate derivative instruments and by monitoring the effects of market changes in interest rates. For the threenine months ended March 31,September 30, 2023 and 2022, a 100 basis point change in the benchmark rate on AEP’s variable rate debt would impact pretax interest expense annually by $43$45 million and $37$47 million, respectively.
4446




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended March 31,September 30, 2023 and 2022
(in millions, except per-share and share amounts)
(Unaudited)
Three Months EndedNine Months Ended
September 30,September 30,
Three Months Ended March 31,
202320222023202220232022
REVENUESREVENUESREVENUES
Vertically Integrated UtilitiesVertically Integrated Utilities$2,816.3 $2,646.8 Vertically Integrated Utilities$3,158.1 $3,174.6 $8,603.4 $8,416.4 
Transmission and Distribution UtilitiesTransmission and Distribution Utilities1,455.3 1,242.2 Transmission and Distribution Utilities1,535.2 1,525.5 4,321.3 4,064.5 
Generation & MarketingGeneration & Marketing326.9 609.5 Generation & Marketing527.5 733.1 1,172.6 1,997.0 
Other RevenuesOther Revenues92.4 94.1 Other Revenues120.9 92.9 307.8 280.5 
TOTAL REVENUESTOTAL REVENUES4,690.9 4,592.6 TOTAL REVENUES5,341.7 5,526.1 14,405.1 14,758.4 
EXPENSESEXPENSES  EXPENSES    
Purchased Electricity, Fuel and Other Consumables Used for Electric GenerationPurchased Electricity, Fuel and Other Consumables Used for Electric Generation1,706.4 1,500.7 Purchased Electricity, Fuel and Other Consumables Used for Electric Generation1,756.8 2,111.9 4,887.8 5,177.0 
Other OperationOther Operation680.0 662.2 Other Operation719.9 797.0 2,031.1 2,079.0 
MaintenanceMaintenance317.3 285.0 Maintenance325.5 298.1 982.8 909.6 
Loss on the Expected Sale of the Competitive Contracted Renewable Portfolio112.0 — 
Loss on the Expected Sale of the Kentucky OperationsLoss on the Expected Sale of the Kentucky Operations— 194.5 — 263.3 
Loss on the Sale of the Competitive Contracted Renewables PortfolioLoss on the Sale of the Competitive Contracted Renewables Portfolio— — 112.0 — 
Asset Impairments and Other Related ChargesAsset Impairments and Other Related Charges— 24.9 — 24.9 
Establishment of 2017-2019 Virginia Triennial Review Regulatory AssetEstablishment of 2017-2019 Virginia Triennial Review Regulatory Asset— (37.0)— (37.0)
Gain on Sale of Mineral RightsGain on Sale of Mineral Rights— — — (116.3)
Depreciation and AmortizationDepreciation and Amortization775.5 792.4 Depreciation and Amortization792.3 821.8 2,309.4 2,416.8 
Taxes Other Than Income TaxesTaxes Other Than Income Taxes394.9 364.2 Taxes Other Than Income Taxes393.9 384.8 1,149.2 1,118.5 
TOTAL EXPENSESTOTAL EXPENSES3,986.1 3,604.5 TOTAL EXPENSES3,988.4 4,596.0 11,472.3 11,835.8 
OPERATING INCOMEOPERATING INCOME704.8 988.1 OPERATING INCOME1,353.3 930.1 2,932.8 2,922.6 
Other Income (Expense):Other Income (Expense):  Other Income (Expense):    
Other Income14.7 2.3 
Other Income (Expense)Other Income (Expense)11.9 4.8 41.0 (5.6)
Allowance for Equity Funds Used During ConstructionAllowance for Equity Funds Used During Construction31.3 31.0 Allowance for Equity Funds Used During Construction51.1 35.6 123.4 95.2 
Non-Service Cost Components of Net Periodic Benefit CostNon-Service Cost Components of Net Periodic Benefit Cost55.5 47.2 Non-Service Cost Components of Net Periodic Benefit Cost55.2 47.2 165.9 141.5 
Interest ExpenseInterest Expense(415.7)(313.4)Interest Expense(470.3)(360.7)(1,346.0)(1,001.7)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS390.6 755.2 
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)1,001.2 657.0 1,917.1 2,152.0 
Income Tax Expense10.4 52.8 
Equity Earnings of Unconsolidated Subsidiaries20.2 15.7 
Income Tax Expense (Benefit)Income Tax Expense (Benefit)64.2 (16.1)103.2 90.7 
Equity Earnings (Loss) of Unconsolidated SubsidiariesEquity Earnings (Loss) of Unconsolidated Subsidiaries21.3 10.2 60.9 (139.1)
NET INCOMENET INCOME400.4 718.1 NET INCOME958.3 683.3 1,874.8 1,922.2 
Net Income Attributable to Noncontrolling Interests3.4 3.4 
Net Income (Loss) Attributable to Noncontrolling InterestsNet Income (Loss) Attributable to Noncontrolling Interests4.6 (0.4)2.9 (0.7)
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERSEARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$397.0 $714.7 EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$953.7 $683.7 $1,871.9 $1,922.9 
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDINGWEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING514,176,648 506,050,147 WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING520,459,880 513,730,196 516,528,239 511,162,723 
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERSTOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$0.77 $1.41 TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$1.83 $1.33 $3.62 $3.76 
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDINGWEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING515,598,090 507,658,522 WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING521,444,125 515,315,994 517,784,726 512,714,006 
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERSTOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$0.77 $1.41 TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$1.83 $1.33 $3.62 $3.75 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
4547



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
Three Months EndedNine Months Ended
Three Months Ended March 31,September 30,September 30,
202320222023202220232022
Net IncomeNet Income$400.4 $718.1 Net Income$958.3 $683.3 $1,874.8 $1,922.2 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXESOTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES  OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES    
Cash Flow Hedges, Net of Tax of $(40.5) and $65.9 in 2023 and 2022, Respectively(152.4)248.0 
Cash Flow Hedges, Net of Tax of $(0.3) and $(19.5) for the Three Months Ended September 30, 2023 and 2022, Respectively, and $(31.5) and $81.6 for the Nine Months Ended September 30, 2023 and 2022, RespectivelyCash Flow Hedges, Net of Tax of $(0.3) and $(19.5) for the Three Months Ended September 30, 2023 and 2022, Respectively, and $(31.5) and $81.6 for the Nine Months Ended September 30, 2023 and 2022, Respectively(0.9)(73.3)(118.5)307.1 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(4.3) and $(0.6) in 2023 and 2022, Respectively(16.1)(2.2)
Reclassifications of KPCo Pension and OPEB Regulatory Assets, Net of Tax of $4.4 and $0 in 2023 and 2022, Respectively16.7 — 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.8) and $(0.8) for the Three Months Ended September 30, 2023 and 2022, Respectively, and $(5.9) and $(4.5) for the Nine Months Ended September 30, 2023 and 2022, RespectivelyAmortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.8) and $(0.8) for the Three Months Ended September 30, 2023 and 2022, Respectively, and $(5.9) and $(4.5) for the Nine Months Ended September 30, 2023 and 2022, Respectively(3.2)(3.2)(22.4)(17.0)
Reclassifications of KPCo Pension and OPEB Regulatory Assets, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2023 and 2022, Respectively, and $4.4 and $0 for the Nine Months Ended September 30, 2023 and 2022, RespectivelyReclassifications of KPCo Pension and OPEB Regulatory Assets, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2023 and 2022, Respectively, and $4.4 and $0 for the Nine Months Ended September 30, 2023 and 2022, Respectively— — 16.7 — 
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)TOTAL OTHER COMPREHENSIVE INCOME (LOSS)(151.8)245.8 TOTAL OTHER COMPREHENSIVE INCOME (LOSS)(4.1)(76.5)(124.2)290.1 
TOTAL COMPREHENSIVE INCOMETOTAL COMPREHENSIVE INCOME248.6 963.9 TOTAL COMPREHENSIVE INCOME954.2 606.8 1,750.6 2,212.3 
Total Comprehensive Income Attributable To Noncontrolling Interests3.4 3.4 
Total Comprehensive Income (Loss) Attributable To Noncontrolling InterestsTotal Comprehensive Income (Loss) Attributable To Noncontrolling Interests4.6 (0.4)2.9 (0.7)
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERSTOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$245.2 $960.5 TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$949.6 $607.2 $1,747.7 $2,213.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
4648



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the ThreeNine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
AEP Common ShareholdersAEP Common Shareholders
Common StockAccumulated
Other
Comprehensive
Income (Loss)
Common StockAccumulated
Other
Comprehensive
Income (Loss)
SharesAmountPaid-in
Capital
Retained
Earnings
Noncontrolling
Interests
TotalSharesAmountPaid-in
Capital
Retained
Earnings
Noncontrolling
Interests
Total
TOTAL EQUITY – DECEMBER 31, 2021TOTAL EQUITY – DECEMBER 31, 2021524.4 $3,408.7 $7,172.6 $11,667.1 $184.8 $247.0 $22,680.2 TOTAL EQUITY – DECEMBER 31, 2021524.4 $3,408.7 $7,172.6 $11,667.1 $184.8 $247.0 $22,680.2 
Issuance of Common StockIssuance of Common Stock0.4 2.4 807.1  809.5 Issuance of Common Stock0.4 2.4 807.1  809.5 
Common Stock DividendsCommon Stock Dividends(395.2)(a)(3.6)(398.8)Common Stock Dividends(395.2)(a)(3.6)(398.8)
Other Changes in EquityOther Changes in Equity(15.2)(1.5)(16.7)Other Changes in Equity(15.2)(1.5)(16.7)
Net IncomeNet Income   714.7 3.4 718.1 Net Income   714.7 3.4 718.1 
Other Comprehensive IncomeOther Comprehensive Income    245.8 245.8 Other Comprehensive Income    245.8 245.8 
TOTAL EQUITY – MARCH 31, 2022TOTAL EQUITY – MARCH 31, 2022524.8 $3,411.1 $7,964.5 $11,985.1 $430.6 $246.8 $24,038.1 TOTAL EQUITY – MARCH 31, 2022524.8 3,411.1 7,964.5 11,985.1 430.6 246.8 24,038.1 
Issuance of Common StockIssuance of Common Stock0.1 0.9 2.3    3.2 
Common Stock DividendsCommon Stock Dividends   (402.6)(a) (2.1)(404.7)
Other Changes in EquityOther Changes in Equity  17.2 1.6  18.8 
Net Income (Loss)Net Income (Loss)   524.5  (3.7)520.8 
Other Comprehensive IncomeOther Comprehensive Income    120.8  120.8 
TOTAL EQUITY – JUNE 30, 2022TOTAL EQUITY – JUNE 30, 2022524.9 3,412.0 7,984.0 12,108.6 551.4 241.0 24,297.0 
Issuance of Common StockIssuance of Common Stock0.1 0.5 14.0 14.5 
Common Stock DividendsCommon Stock Dividends(402.5)(a)(6.5)(409.0)
Other Changes in EquityOther Changes in Equity3.0 3.0 
Net Income (Loss)Net Income (Loss)683.7 (0.4)683.3 
Other Comprehensive LossOther Comprehensive Loss(76.5)(76.5)
TOTAL EQUITY – SEPTEMBER 30, 2022TOTAL EQUITY – SEPTEMBER 30, 2022525.0 $3,412.5 $8,001.0 $12,389.8 $474.9 $234.1 $24,512.3 
TOTAL EQUITY – DECEMBER 31, 2022TOTAL EQUITY – DECEMBER 31, 2022525.1 $3,413.1 $8,051.0 $12,345.6 $83.7 $229.0 $24,122.4 TOTAL EQUITY – DECEMBER 31, 2022525.1 $3,413.1 $8,051.0 $12,345.6 $83.7 $229.0 $24,122.4 
Issuance of Common StockIssuance of Common Stock0.8 5.1 36.0 41.1 Issuance of Common Stock0.8 5.1 36.0 41.1 
Common Stock DividendsCommon Stock Dividends(428.8)(b)(3.0)(431.8)Common Stock Dividends(428.8)(b)(3.0)(431.8)
Other Changes in EquityOther Changes in Equity(12.7)0.2 (12.5)Other Changes in Equity(12.7)0.2 (12.5)
Net IncomeNet Income397.0 3.4 400.4 Net Income397.0 3.4 400.4 
Other Comprehensive LossOther Comprehensive Loss(151.8)(151.8)Other Comprehensive Loss(151.8)(151.8)
TOTAL EQUITY – MARCH 31, 2023TOTAL EQUITY – MARCH 31, 2023525.9 $3,418.2 $8,074.3 $12,313.8 $(68.1)$229.6 $23,967.8 TOTAL EQUITY – MARCH 31, 2023525.9 3,418.2 8,074.3 12,313.8 (68.1)229.6 23,967.8 
Issuance of Common StockIssuance of Common Stock0.5 3.3 33.2 36.5 
Common Stock DividendsCommon Stock Dividends(429.5)(b)(2.3)(431.8)
Other Changes in EquityOther Changes in Equity3.3 3.3 
Net Income (Loss)Net Income (Loss)521.2 (5.1)516.1 
Other Comprehensive IncomeOther Comprehensive Income31.7 31.7 
TOTAL EQUITY – JUNE 30, 2023TOTAL EQUITY – JUNE 30, 2023526.4 3,421.5 8,110.8 12,405.5 (36.4)222.2 24,123.6 
Issuance of Common StockIssuance of Common Stock0.4 2.8 878.9   881.7 
Common Stock DividendsCommon Stock Dividends  (429.7)(b) (0.5)(430.2)
Other Changes in EquityOther Changes in Equity  6.7  6.7 
Disposition of Competitive Contracted Renewables PortfolioDisposition of Competitive Contracted Renewables Portfolio(186.4)(186.4)
Net IncomeNet Income   953.7  4.6 958.3 
Other Comprehensive LossOther Comprehensive Loss    (4.1) (4.1)
TOTAL EQUITY – SEPTEMBER 30, 2023TOTAL EQUITY – SEPTEMBER 30, 2023526.8 $3,424.3 $8,996.4 $12,929.5 $(40.5)$39.9 $25,349.6 

(a)    Cash dividends declared per AEP common share were $0.78.
(b)    Cash dividends declared per AEP common share were $0.83.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
4749



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31,September 30, 2023 and December 31, 2022
(in millions)
(Unaudited)
March 31,December 31, September 30,December 31,
20232022 20232022
CURRENT ASSETSCURRENT ASSETS  CURRENT ASSETS  
Cash and Cash EquivalentsCash and Cash Equivalents$343.5 $509.4 Cash and Cash Equivalents$353.3 $509.4 
Restricted Cash
(March 31, 2023 and December 31, 2022 Amounts Include $50 and $47.1, Respectively, Related to Transition Funding, Restoration Funding and Appalachian Consumer Rate Relief Funding)
50.0 47.1 
Other Temporary Investments
(March 31, 2023 and December 31, 2022 Amounts Include $187.5 and $182.9, Respectively, Related to EIS and Transource Energy)
194.6 187.6 
Restricted Cash
(September 30, 2023 and December 31, 2022 Amounts Include $53.8 and $47.1, Respectively, Related to Transition Funding, Restoration Funding and Appalachian Consumer Rate Relief Funding)
Restricted Cash
(September 30, 2023 and December 31, 2022 Amounts Include $53.8 and $47.1, Respectively, Related to Transition Funding, Restoration Funding and Appalachian Consumer Rate Relief Funding)
53.8 47.1 
Other Temporary Investments
(September 30, 2023 and December 31, 2022 Amounts Include $202 and $182.9, Respectively, Related to EIS and Transource Energy)
Other Temporary Investments
(September 30, 2023 and December 31, 2022 Amounts Include $202 and $182.9, Respectively, Related to EIS and Transource Energy)
211.0 187.6 
Accounts Receivable:Accounts Receivable:  Accounts Receivable:  
CustomersCustomers949.8 1,145.1 Customers976.8 1,145.1 
Accrued Unbilled RevenuesAccrued Unbilled Revenues239.7 322.9 Accrued Unbilled Revenues270.2 322.9 
Pledged Accounts Receivable – AEP CreditPledged Accounts Receivable – AEP Credit1,133.0 1,207.4 Pledged Accounts Receivable – AEP Credit1,299.2 1,207.4 
MiscellaneousMiscellaneous39.3 49.7 Miscellaneous77.4 49.7 
Allowance for Uncollectible AccountsAllowance for Uncollectible Accounts(58.0)(57.1)Allowance for Uncollectible Accounts(58.6)(57.1)
Total Accounts ReceivableTotal Accounts Receivable2,303.8 2,668.0 Total Accounts Receivable2,565.0 2,668.0 
FuelFuel554.7 435.1 Fuel726.8 435.1 
Materials and SuppliesMaterials and Supplies902.5 915.1 Materials and Supplies993.2 915.1 
Risk Management AssetsRisk Management Assets190.6 348.8 Risk Management Assets262.7 348.8 
Accrued Tax BenefitsAccrued Tax Benefits141.2 99.4 Accrued Tax Benefits160.3 99.4 
Regulatory Asset for Under-Recovered Fuel CostsRegulatory Asset for Under-Recovered Fuel Costs1,380.1 1,310.0 Regulatory Asset for Under-Recovered Fuel Costs1,087.6 1,310.0 
Assets Held for Sale1,396.3 — 
Prepayments and Other Current AssetsPrepayments and Other Current Assets340.9 255.0 Prepayments and Other Current Assets322.9 255.0 
TOTAL CURRENT ASSETSTOTAL CURRENT ASSETS7,798.2 6,775.5 TOTAL CURRENT ASSETS6,736.6 6,775.5 
PROPERTY, PLANT AND EQUIPMENTPROPERTY, PLANT AND EQUIPMENT  PROPERTY, PLANT AND EQUIPMENT  
Electric:Electric:  Electric:  
GenerationGeneration24,034.3 25,834.2 Generation24,178.0 25,834.2 
TransmissionTransmission33,570.2 33,266.9 Transmission34,731.0 33,266.9 
DistributionDistribution27,521.1 27,138.8 Distribution28,444.0 27,138.8 
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)6,056.3 5,971.8 Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)6,251.1 5,971.8 
Construction Work in ProgressConstruction Work in Progress5,526.2 4,809.7 Construction Work in Progress6,394.4 4,809.7 
Total Property, Plant and EquipmentTotal Property, Plant and Equipment96,708.1 97,021.4 Total Property, Plant and Equipment99,998.5 97,021.4 
Accumulated Depreciation and AmortizationAccumulated Depreciation and Amortization23,361.1 23,682.3 Accumulated Depreciation and Amortization24,177.4 23,682.3 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NETTOTAL PROPERTY, PLANT AND EQUIPMENT – NET73,347.0 73,339.1 TOTAL PROPERTY, PLANT AND EQUIPMENT – NET75,821.1 73,339.1 
OTHER NONCURRENT ASSETSOTHER NONCURRENT ASSETS  OTHER NONCURRENT ASSETS  
Regulatory AssetsRegulatory Assets4,578.0 4,762.0 Regulatory Assets4,607.3 4,762.0 
Securitized AssetsSecuritized Assets420.1 446.0 Securitized Assets365.4 446.0 
Spent Nuclear Fuel and Decommissioning TrustsSpent Nuclear Fuel and Decommissioning Trusts3,501.1 3,341.2 Spent Nuclear Fuel and Decommissioning Trusts3,539.7 3,341.2 
GoodwillGoodwill52.5 52.5 Goodwill52.5 52.5 
Long-term Risk Management AssetsLong-term Risk Management Assets318.2 284.1 Long-term Risk Management Assets290.2 284.1 
Operating Lease AssetsOperating Lease Assets631.5 645.5 Operating Lease Assets619.1 645.5 
Deferred Charges and Other Noncurrent AssetsDeferred Charges and Other Noncurrent Assets3,871.3 3,757.4 Deferred Charges and Other Noncurrent Assets3,093.7 3,757.4 
TOTAL OTHER NONCURRENT ASSETSTOTAL OTHER NONCURRENT ASSETS13,372.7 13,288.7 TOTAL OTHER NONCURRENT ASSETS12,567.9 13,288.7 
TOTAL ASSETSTOTAL ASSETS$94,517.9 $93,403.3 TOTAL ASSETS$95,125.6 $93,403.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
4850



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
March 31,September 30, 2023 and December 31, 2022
(in millions, except per-share and share amounts)
(Unaudited)
  March 31,December 31,   September 30,December 31,
20232022 20232022
CURRENT LIABILITIESCURRENT LIABILITIES  CURRENT LIABILITIES  
Accounts PayableAccounts Payable$2,269.3 $2,670.8 Accounts Payable$2,258.6 $2,670.8 
Short-term Debt:Short-term Debt:  Short-term Debt:  
Securitized Debt for Receivables – AEP CreditSecuritized Debt for Receivables – AEP Credit750.0 750.0 Securitized Debt for Receivables – AEP Credit900.0 750.0 
Other Short-term DebtOther Short-term Debt2,872.1 3,362.2 Other Short-term Debt1,830.4 3,362.2 
Total Short-term DebtTotal Short-term Debt3,622.1 4,112.2 Total Short-term Debt2,730.4 4,112.2 
Long-term Debt Due Within One Year
(March 31, 2023 and December 31, 2022 Amounts Include $206.9 and $218.2, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)
2,905.1 2,486.4 
Long-term Debt Due Within One Year
(September 30, 2023 and December 31, 2022 Amounts Include $184.4 and $218.2, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)
Long-term Debt Due Within One Year
(September 30, 2023 and December 31, 2022 Amounts Include $184.4 and $218.2, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)
2,773.6 2,486.4 
Risk Management LiabilitiesRisk Management Liabilities166.0 145.2 Risk Management Liabilities151.5 145.2 
Customer DepositsCustomer Deposits390.0 408.8 Customer Deposits379.6 408.8 
Accrued TaxesAccrued Taxes1,599.9 1,714.6 Accrued Taxes1,201.0 1,714.6 
Accrued InterestAccrued Interest440.5 336.5 Accrued Interest485.9 336.5 
Obligations Under Operating LeasesObligations Under Operating Leases116.4 113.6 Obligations Under Operating Leases117.7 113.6 
Liabilities Held for Sale67.2 — 
Other Current LiabilitiesOther Current Liabilities1,045.2 1,278.2 Other Current Liabilities1,179.8 1,278.2 
TOTAL CURRENT LIABILITIESTOTAL CURRENT LIABILITIES12,621.7 13,266.3 TOTAL CURRENT LIABILITIES11,278.1 13,266.3 
NONCURRENT LIABILITIESNONCURRENT LIABILITIES  NONCURRENT LIABILITIES  
Long-term Debt
(March 31, 2023 and December 31, 2022 Amounts Include $624.2 and $755.3, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)
36,239.1 34,314.6 
Long-term Debt
(September 30, 2023 and December 31, 2022 Amounts Include $553.5 and $755.3, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)
Long-term Debt
(September 30, 2023 and December 31, 2022 Amounts Include $553.5 and $755.3, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)
36,715.5 34,314.6 
Long-term Risk Management LiabilitiesLong-term Risk Management Liabilities315.4 345.2 Long-term Risk Management Liabilities278.4 345.2 
Deferred Income TaxesDeferred Income Taxes8,989.0 8,896.9 Deferred Income Taxes9,267.2 8,896.9 
Regulatory Liabilities and Deferred Investment Tax CreditsRegulatory Liabilities and Deferred Investment Tax Credits8,095.3 8,115.6 Regulatory Liabilities and Deferred Investment Tax Credits7,916.3 8,115.6 
Asset Retirement ObligationsAsset Retirement Obligations2,877.5 2,879.3 Asset Retirement Obligations2,895.2 2,879.3 
Employee Benefits and Pension ObligationsEmployee Benefits and Pension Obligations246.5 257.3 Employee Benefits and Pension Obligations238.3 257.3 
Obligations Under Operating LeasesObligations Under Operating Leases535.9 552.5 Obligations Under Operating Leases514.6 552.5 
Deferred Credits and Other Noncurrent LiabilitiesDeferred Credits and Other Noncurrent Liabilities573.1 607.3 Deferred Credits and Other Noncurrent Liabilities597.3 607.3 
TOTAL NONCURRENT LIABILITIESTOTAL NONCURRENT LIABILITIES57,871.8 55,968.7 TOTAL NONCURRENT LIABILITIES58,422.8 55,968.7 
TOTAL LIABILITIESTOTAL LIABILITIES70,493.5 69,235.0 TOTAL LIABILITIES69,700.9 69,235.0 
Rate Matters (Note 4)Rate Matters (Note 4)Rate Matters (Note 4)
Commitments and Contingencies (Note 5)Commitments and Contingencies (Note 5)Commitments and Contingencies (Note 5)
MEZZANINE EQUITYMEZZANINE EQUITYMEZZANINE EQUITY
Contingently Redeemable Performance Share AwardsContingently Redeemable Performance Share Awards56.6 45.9 Contingently Redeemable Performance Share Awards75.1 45.9 
TOTAL MEZZANINE EQUITYTOTAL MEZZANINE EQUITY56.6 45.9 TOTAL MEZZANINE EQUITY75.1 45.9 
EQUITYEQUITY  EQUITY  
Common Stock – Par Value – $6.50 Per Share:Common Stock – Par Value – $6.50 Per Share:  Common Stock – Par Value – $6.50 Per Share:  
20232022  20232022  
Shares AuthorizedShares Authorized600,000,000600,000,000  Shares Authorized600,000,000600,000,000  
Shares IssuedShares Issued525,883,990525,099,321  Shares Issued526,819,992525,099,321  
(11,233,240 Shares were Held in Treasury as of March 31, 2023 and December 31, 2022, Respectively)3,418.2 3,413.1 
(1,184,572 and 11,233,240 Shares were Held in Treasury as of September 30, 2023 and December 31, 2022, Respectively)(1,184,572 and 11,233,240 Shares were Held in Treasury as of September 30, 2023 and December 31, 2022, Respectively)3,424.3 3,413.1 
Paid-in CapitalPaid-in Capital8,074.3 8,051.0 Paid-in Capital8,996.4 8,051.0 
Retained EarningsRetained Earnings12,313.8 12,345.6 Retained Earnings12,929.5 12,345.6 
Accumulated Other Comprehensive Income (Loss)Accumulated Other Comprehensive Income (Loss)(68.1)83.7 Accumulated Other Comprehensive Income (Loss)(40.5)83.7 
TOTAL AEP COMMON SHAREHOLDERS’ EQUITYTOTAL AEP COMMON SHAREHOLDERS’ EQUITY23,738.2 23,893.4 TOTAL AEP COMMON SHAREHOLDERS’ EQUITY25,309.7 23,893.4 
Noncontrolling InterestsNoncontrolling Interests229.6 229.0 Noncontrolling Interests39.9 229.0 
TOTAL EQUITYTOTAL EQUITY23,967.8 24,122.4 TOTAL EQUITY25,349.6 24,122.4 
TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITYTOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY$94,517.9 $93,403.3 TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY$95,125.6 $93,403.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
4951



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the ThreeNine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
Three Months Ended March 31, Nine Months Ended September 30,
20232022 20232022
OPERATING ACTIVITIESOPERATING ACTIVITIES  OPERATING ACTIVITIES  
Net IncomeNet Income$400.4 $718.1 Net Income$1,874.8 $1,922.2 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and AmortizationDepreciation and Amortization775.5 792.4 Depreciation and Amortization2,309.4 2,416.8 
Deferred Income TaxesDeferred Income Taxes68.0 (17.7)Deferred Income Taxes171.5 16.6 
Loss on the Expected Sale of the Competitive Contracted Renewable Portfolio112.0 — 
Loss on the Expected Sale of the Kentucky OperationsLoss on the Expected Sale of the Kentucky Operations— 263.3 
Loss on the Sale of the Competitive Contracted Renewables PortfolioLoss on the Sale of the Competitive Contracted Renewables Portfolio112.0 — 
Asset Impairments and Other Related ChargesAsset Impairments and Other Related Charges— 24.9 
Impairment of Equity Method InvestmentImpairment of Equity Method Investment— 188.0 
Allowance for Equity Funds Used During ConstructionAllowance for Equity Funds Used During Construction(31.3)(31.0)Allowance for Equity Funds Used During Construction(123.4)(95.2)
Mark-to-Market of Risk Management ContractsMark-to-Market of Risk Management Contracts(82.0)282.3 Mark-to-Market of Risk Management Contracts(82.8)162.3 
Property TaxesProperty Taxes(101.6)(82.0)Property Taxes486.1 459.9 
Deferred Fuel Over/Under-Recovery, NetDeferred Fuel Over/Under-Recovery, Net128.0 (148.8)Deferred Fuel Over/Under-Recovery, Net542.8 (148.7)
Gain on Sale of Mineral RightsGain on Sale of Mineral Rights— (116.3)
Establishment of 2017-2019 Virginia Triennial Review Regulatory AssetEstablishment of 2017-2019 Virginia Triennial Review Regulatory Asset— (37.0)
Change in Other Noncurrent AssetsChange in Other Noncurrent Assets(96.0)49.4 Change in Other Noncurrent Assets(396.8)(6.0)
Change in Other Noncurrent LiabilitiesChange in Other Noncurrent Liabilities(58.7)36.9 Change in Other Noncurrent Liabilities(21.5)324.0 
Changes in Certain Components of Working Capital:Changes in Certain Components of Working Capital:  Changes in Certain Components of Working Capital:  
Accounts Receivable, NetAccounts Receivable, Net348.4 (24.3)Accounts Receivable, Net114.0 (495.7)
Fuel, Materials and SuppliesFuel, Materials and Supplies(115.9)27.6 Fuel, Materials and Supplies(344.4)(134.6)
Accounts PayableAccounts Payable(255.9)(1.0)Accounts Payable(163.0)369.4 
Accrued Taxes, NetAccrued Taxes, Net(150.9)(51.8)Accrued Taxes, Net(566.7)(512.8)
Other Current AssetsOther Current Assets(94.6)133.9 Other Current Assets(91.5)41.2 
Other Current LiabilitiesOther Current Liabilities(127.6)(61.8)Other Current Liabilities(144.8)90.9 
Net Cash Flows from Operating ActivitiesNet Cash Flows from Operating Activities717.8 1,622.2 Net Cash Flows from Operating Activities3,675.7 4,733.2 
INVESTING ACTIVITIESINVESTING ACTIVITIES  INVESTING ACTIVITIES  
Construction ExpendituresConstruction Expenditures(2,090.1)(1,686.6)Construction Expenditures(5,767.1)(4,748.5)
Purchases of Investment SecuritiesPurchases of Investment Securities(537.3)(508.5)Purchases of Investment Securities(2,199.7)(1,868.2)
Sales of Investment SecuritiesSales of Investment Securities517.6 497.4 Sales of Investment Securities2,140.1 1,833.4 
Acquisitions of Nuclear FuelAcquisitions of Nuclear Fuel(1.7)(31.1)Acquisitions of Nuclear Fuel(60.9)(91.9)
Acquisitions of Renewable Energy FacilitiesAcquisitions of Renewable Energy Facilities(145.7)(1,207.3)Acquisitions of Renewable Energy Facilities(154.0)(1,207.3)
Proceeds from Sales of AssetsProceeds from Sales of Assets1,335.6 215.7 
Other Investing ActivitiesOther Investing Activities12.0 42.9 Other Investing Activities62.5 44.3 
Net Cash Flows Used for Investing ActivitiesNet Cash Flows Used for Investing Activities(2,245.2)(2,893.2)Net Cash Flows Used for Investing Activities(4,643.5)(5,822.5)
FINANCING ACTIVITIESFINANCING ACTIVITIES  FINANCING ACTIVITIES  
Issuance of Common StockIssuance of Common Stock41.1 809.5 Issuance of Common Stock959.3 827.2 
Issuance of Long-term DebtIssuance of Long-term Debt2,847.3 499.6 Issuance of Long-term Debt4,017.8 3,428.4 
Issuance of Short-term Debt with Original Maturities greater than 90 DaysIssuance of Short-term Debt with Original Maturities greater than 90 Days97.4 271.0 Issuance of Short-term Debt with Original Maturities greater than 90 Days791.7 271.0 
Change in Short-term Debt with Original Maturities less than 90 Days, NetChange in Short-term Debt with Original Maturities less than 90 Days, Net(433.7)710.3 Change in Short-term Debt with Original Maturities less than 90 Days, Net(1,044.7)803.4 
Retirement of Long-term DebtRetirement of Long-term Debt(519.5)(51.0)Retirement of Long-term Debt(1,353.3)(1,679.1)
Redemption of Short-term Debt with Original Maturities Greater than 90 DaysRedemption of Short-term Debt with Original Maturities Greater than 90 Days(153.8)(215.0)Redemption of Short-term Debt with Original Maturities Greater than 90 Days(1,128.8)(986.1)
Principal Payments for Finance Lease ObligationsPrincipal Payments for Finance Lease Obligations(26.8)(14.7)Principal Payments for Finance Lease Obligations(53.9)(120.3)
Dividends Paid on Common StockDividends Paid on Common Stock(431.8)(398.8)Dividends Paid on Common Stock(1,293.8)(1,212.5)
Other Financing ActivitiesOther Financing Activities(55.8)(65.8)Other Financing Activities(75.9)(116.8)
Net Cash Flows from Financing ActivitiesNet Cash Flows from Financing Activities1,364.4 1,545.1 Net Cash Flows from Financing Activities818.4 1,215.2 
Net Increase (Decrease) in Cash and Cash EquivalentsNet Increase (Decrease) in Cash and Cash Equivalents(163.0)274.1 Net Increase (Decrease) in Cash and Cash Equivalents(149.4)125.9 
Cash, Cash Equivalents and Restricted Cash at Beginning of PeriodCash, Cash Equivalents and Restricted Cash at Beginning of Period556.5 451.4 Cash, Cash Equivalents and Restricted Cash at Beginning of Period556.5 451.4 
Cash, Cash Equivalents and Restricted Cash at End of PeriodCash, Cash Equivalents and Restricted Cash at End of Period$393.5 $725.5 Cash, Cash Equivalents and Restricted Cash at End of Period$407.1 $577.3 
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts$311.9 $233.9 
Net Cash Paid for Income Taxes15.8 6.9 
Noncash Acquisitions Under Finance Leases12.5 7.2 
Construction Expenditures Included in Current Liabilities as of March 31,1,076.1 758.6 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
5052





AEP TEXAS INC. AND SUBSIDIARIES

51



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

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
Three Months EndedNine Months Ended
Three Months Ended March 31,September 30,September 30,
20232022 2023202220232022
(in millions of KWhs) (in millions of KWhs)
Retail:Retail:  Retail:  
ResidentialResidential2,532 2,843 Residential4,681 4,079 10,295 10,453 
CommercialCommercial2,744 2,148 Commercial4,021 3,243 10,208 8,482 
IndustrialIndustrial3,108 2,427 Industrial3,065 2,993 9,344 8,443 
MiscellaneousMiscellaneous138 141 Miscellaneous196 185 487 499 
Total RetailTotal Retail8,522 7,559 Total Retail11,963 10,500 30,334 27,877 

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

Summary of Heating and Cooling Degree Days
Three Months EndedNine Months Ended
Three Months Ended March 31,September 30,September 30,
20232022 2023202220232022
(in degree days) (in degree days)
Actual – Heating (a)Actual – Heating (a)141 278 Actual – Heating (a)— — 143 278 
Normal – Heating (b)Normal – Heating (b)194 190 Normal – Heating (b)— — 197 193 
Actual – Cooling (c)Actual – Cooling (c)271 88 Actual – Cooling (c)1,719 1,478 2,945 2,701 
Normal – Cooling (b)Normal – Cooling (b)127 126 Normal – Cooling (b)1,387 1,382 2,454 2,433 

(a)Heating degree days are calculated on a 55 degree temperature base.
(b)Normal Heating/Cooling represents the thirty-year average of degree days.
(c)Cooling degree days are calculated on a 70 degree temperature base.













5253


First
AEP Texas Inc. and Subsidiaries
Reconciliation of 2022 to 2023 Net Income
(in millions)
Three Months Ended 
September 30,
Nine Months Ended 
September 30,
2022 Net Income$93.6 $253.2 
  
Changes in Revenues:
Retail Revenues32.7 (2.9)
Transmission Revenues13.7 46.3 
Other Revenues(0.7)(2.5)
Total Change in Revenues45.7 40.9 
  
Changes in Expenses and Other: 
Other Operation and Maintenance7.1 30.8 
Depreciation and Amortization(7.9)(8.8)
Taxes Other Than Income Taxes(3.1)(11.1)
Interest Income(0.8)(1.2)
Allowance for Equity Funds Used During Construction2.6 6.2 
Non-Service Cost Components of Net Periodic Benefit Cost0.6 1.9 
Interest Expense(4.5)(19.9)
Total Change in Expenses and Other(6.0)(2.1)
  
Income Tax Expense(7.8)(9.8)
  
2023 Net Income$125.5 $282.2 

Third Quarter of 2023 Compared to FirstThird Quarter of 2022
AEP Texas Inc. and Subsidiaries
Reconciliation of First Quarter of 2022 to First Quarter of 2023
Net Income
(in millions)
First Quarter of 2022$69.6 
Changes in Revenues:
Retail Revenues1.5 
Transmission Revenues12.4 
Other Revenues(1.1)
Total Change in Revenues12.8 
Changes in Expenses and Other:
Other Operation and Maintenance(22.9)
Depreciation and Amortization(2.2)
Taxes Other Than Income Taxes(6.2)
Interest Income0.3 
Allowance for Equity Funds Used During Construction2.0 
Non-Service Cost Components of Net Periodic Benefit Cost0.6 
Interest Expense(11.4)
Total Change in Expenses and Other(39.8)
Income Tax Expense5.0 
First Quarter of 2023$47.6 

The major components of the increase in revenues were as follows:

Retail Revenues increased $2$33 million primarily due to the following:
An $18A $15 million increase due to interim rate increases driven by increased investment.
This increase was partially offset by:
A $13 million decrease in weather-normalized revenues primarily in the residential class.and commercial classes.
A $3$10 million decreaseincrease in weather-related usage primarily due to a 16% increase in cooling degree days.
A $7 million increase in revenue from rate riders. This decreaseincrease was partially offset in other expense items below.
Transmission Revenues increased $12$14 million primarily due to the following:
An $8 million increase due to increased load.
A $6 million increase in interim rate increasesrates driven by increased transmission investment.investments.

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

Other Operation and Maintenance expenses decreased $7 million primarily due to employee-related expenses.
Depreciation and Amortization expenses increased $23$8 million primarily due to a higher depreciable base.
Interest Expense increased $5 million due to higher long term debt balances and interest rates.
Income Tax Expense increased $8 million primarily due to an increase in pretax book income.


54


Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022
The major components of the increase in revenues were as follows:

Retail Revenues decreased $3 million primarily due to the following:
A $14$9 million decrease in weather-normalized revenues due to an unfavorable sales mix.
This decrease was partially offset by:
A $4 million increase in ERCOTrevenue from rate riders. This increase was partially offset in other expense items below.
Transmission Revenues increased $46 million due to the following:
A $24 million increase in interim rates driven by increased transmission investment.
A $22 million increase due to increased load.

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

Other Operation and Maintenance expenses decreased $31 million primarily due to the following:
A $30 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 $5 million decrease in transmission expenses. This increasedecrease was offset in Retail Revenues above.
These decreases were partially offset by:
A $9$14 million increase in distribution-related expenses.
Depreciation and Amortization expenses increased $9 million due to the following:
A $20 million increase due to a higher depreciable base.
This increase was partially offset by:
An $11 million decrease in recoverable advanced metering system depreciable expenses.
Taxes Other Than Income Taxes increased $6$11 million primarily due to higher property taxes asdriven by increased investment.
Allowance for Equity Funds Used During Construction increased $6 million due to a result of increased distribution and transmission investment.higher AFUDC base.
Interest Expense increased $11$20 million primarily due to the following:
A $32 million increase due to higher long-term debt balances and higher interest rates.
This increase was partially offset by:
A $10 million decrease due to an increase in AFUDC base.
Income Tax Expense decreased $5increased $10 million primarily due to a decreasean increase in pretax book income.
5355




AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
Three Months Ended March 31,September 30,September 30,
 2023 2022  2023 202220232022
REVENUESREVENUES    REVENUES    
Electric Transmission and DistributionElectric Transmission and Distribution $427.7 $414.7 Electric Transmission and Distribution $551.6 $507.7 $1,438.7 $1,399.3 
Sales to AEP AffiliatesSales to AEP Affiliates 1.2 0.9 Sales to AEP Affiliates 1.2 0.9 3.7 2.6 
Other RevenuesOther Revenues 0.6 1.1 Other Revenues 1.8 0.3 2.9 2.5 
TOTAL REVENUESTOTAL REVENUES 429.5 416.7 TOTAL REVENUES 554.6 508.9 1,445.3 1,404.4 
  
EXPENSESEXPENSES   EXPENSES     
Other OperationOther Operation 146.9 125.8 Other Operation 154.4 163.8 395.2 431.6 
MaintenanceMaintenance 24.4 22.6 Maintenance 25.0 22.7 75.7 70.1 
Depreciation and AmortizationDepreciation and Amortization 111.0 108.8 Depreciation and Amortization 125.6 117.7 351.5 342.7 
Taxes Other Than Income TaxesTaxes Other Than Income Taxes 43.5 37.3 Taxes Other Than Income Taxes 48.6 45.5 136.9 125.8 
TOTAL EXPENSESTOTAL EXPENSES 325.8 294.5 TOTAL EXPENSES 353.6 349.7 959.3 970.2 
  
OPERATING INCOMEOPERATING INCOME 103.7 122.2 OPERATING INCOME 201.0 159.2 486.0 434.2 
  
Other Income (Expense):Other Income (Expense):   Other Income (Expense):     
Interest IncomeInterest Income 0.4 0.1 Interest Income 0.5 1.3 1.5 2.7 
Allowance for Equity Funds Used During ConstructionAllowance for Equity Funds Used During Construction6.3 4.3 Allowance for Equity Funds Used During Construction7.8 5.2 19.4 13.2 
Non-Service Cost Components of Net Periodic Benefit CostNon-Service Cost Components of Net Periodic Benefit Cost4.8 4.2 Non-Service Cost Components of Net Periodic Benefit Cost4.8 4.2 14.4 12.5 
Interest ExpenseInterest Expense (56.9)(45.5)Interest Expense (59.9)(55.4)(173.1)(153.2)
  
INCOME BEFORE INCOME TAX EXPENSEINCOME BEFORE INCOME TAX EXPENSE 58.3 85.3 INCOME BEFORE INCOME TAX EXPENSE 154.2 114.5 348.2 309.4 
  
Income Tax ExpenseIncome Tax Expense 10.7 15.7 Income Tax Expense 28.7 20.9 66.0 56.2 
NET INCOMENET INCOME $47.6 $69.6 NET INCOME $125.5 $93.6 $282.2 $253.2 
The common stock of AEP Texas is wholly-owned by Parent.The common stock of AEP Texas is wholly-owned by Parent.The common stock of AEP Texas is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
5456



AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
Three Months EndedNine Months Ended
Three Months Ended March 31,September 30,September 30,
202320222023202220232022
Net IncomeNet Income$47.6 $69.6 Net Income$125.5 $93.6 $282.2 $253.2 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXESOTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES  
Cash Flow Hedges, Net of Tax of $0 and $0.1 in 2023 and 2022, Respectively— 0.3 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $0 in 2023 and 2022, Respectively(0.6)— 
Cash Flow Hedges, Net of Tax of $0 and $0.1 for the Three Months Ended September 30, 2023 and 2022, Respectively, and $0.8 and $0.2 for the Nine Months Ended September 30, 2023 and 2022, RespectivelyCash Flow Hedges, Net of Tax of $0 and $0.1 for the Three Months Ended September 30, 2023 and 2022, Respectively, and $0.8 and $0.2 for the Nine Months Ended September 30, 2023 and 2022, Respectively(0.1)0.3 3.1 0.8 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2023 and 2022, Respectively, and $(0.1) and $0 for the Nine Months Ended September 30, 2023 and 2022, RespectivelyAmortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2023 and 2022, Respectively, and $(0.1) and $0 for the Nine Months Ended September 30, 2023 and 2022, Respectively— — (0.6)— 
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)TOTAL OTHER COMPREHENSIVE INCOME (LOSS)(0.6)0.3 TOTAL OTHER COMPREHENSIVE INCOME (LOSS)(0.1)0.3 2.5 0.8 
TOTAL COMPREHENSIVE INCOMETOTAL COMPREHENSIVE INCOME$47.0 $69.9 TOTAL COMPREHENSIVE INCOME$125.4 $93.9 $284.7 $254.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

5557



AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the ThreeNine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2021TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2021$1,553.9 $2,046.8 $(6.5)$3,594.2 TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2021$1,553.9 $2,046.8 $(6.5)$3,594.2 
Net IncomeNet Income69.6 69.6 Net Income69.6 69.6 
Other Comprehensive IncomeOther Comprehensive Income0.3 0.3 Other Comprehensive Income0.3 0.3 
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2022TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2022$1,553.9 $2,116.4 $(6.2)$3,664.1 TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 20221,553.9 2,116.4 (6.2)3,664.1 
Capital Contribution from ParentCapital Contribution from Parent1.3  1.3 
Net IncomeNet Income 90.0  90.0 
Other Comprehensive IncomeOther Comprehensive Income  0.2 0.2 
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2022TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 20221,555.2 2,206.4 (6.0)3,755.6 
Capital Contribution from ParentCapital Contribution from Parent0.5 0.5 
Net IncomeNet Income93.6 93.6 
Other Comprehensive IncomeOther Comprehensive Income0.3 0.3 
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2022TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2022$1,555.7 $2,300.0 $(5.7)$3,850.0 
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2022TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2022$1,558.2 $2,354.7 $(8.6)$3,904.3 TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2022$1,558.2 $2,354.7 $(8.6)$3,904.3 
Capital Contribution from ParentCapital Contribution from Parent100.0 100.0 Capital Contribution from Parent100.0 100.0 
Net IncomeNet Income47.6 47.6 Net Income47.6 47.6 
Other Comprehensive LossOther Comprehensive Loss(0.6)(0.6)Other Comprehensive Loss(0.6)(0.6)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2023TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2023$1,658.2 $2,402.3 $(9.2)$4,051.3 TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 20231,658.2 2,402.3 (9.2)4,051.3 
Capital Contribution from ParentCapital Contribution from Parent175.3 175.3 
Return of Capital to ParentReturn of Capital to Parent(4.3)(4.3)
Net IncomeNet Income 109.1 109.1 
Other Comprehensive IncomeOther Comprehensive Income 3.2 3.2 
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2023TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 20231,829.2 2,511.4 (6.0)4,334.6 
Capital Contribution from ParentCapital Contribution from Parent250.5 250.5 
Net IncomeNet Income125.5 125.5 
Other Comprehensive LossOther Comprehensive Loss(0.1)(0.1)
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2023TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2023$2,079.7 $2,636.9 $(6.1)$4,710.5 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

5658



AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31,September 30, 2023 and December 31, 2022
(in millions)
(Unaudited)
 March 31,December 31,  September 30,December 31,
 2023 2022  2023 2022
CURRENT ASSETSCURRENT ASSETS    CURRENT ASSETS    
Cash and Cash EquivalentsCash and Cash Equivalents$0.1 $0.1 Cash and Cash Equivalents$0.1 $0.1 
Restricted Cash
(March 31, 2023 and December 31, 2022 Amounts Include $42.5 and $32.7, Respectively, Related to Transition Funding and Restoration Funding)
42.5 32.7 
Restricted Cash
(September 30, 2023 and December 31, 2022 Amounts Include $46.9 and $32.7, Respectively, Related to Transition Funding and Restoration Funding)
Restricted Cash
(September 30, 2023 and December 31, 2022 Amounts Include $46.9 and $32.7, Respectively, Related to Transition Funding and Restoration Funding)
46.9 32.7 
Advances to AffiliatesAdvances to Affiliates6.8 6.9 Advances to Affiliates49.0 6.9 
Accounts Receivable:Accounts Receivable:  Accounts Receivable:  
CustomersCustomers 141.3 150.9 Customers 209.6 150.9 
Affiliated CompaniesAffiliated Companies 13.5 11.9 Affiliated Companies 20.1 11.9 
Accrued Unbilled RevenuesAccrued Unbilled Revenues74.7 91.4 Accrued Unbilled Revenues106.6 91.4 
MiscellaneousMiscellaneous 0.2 0.2 Miscellaneous 0.7 0.2 
Allowance for Uncollectible AccountsAllowance for Uncollectible Accounts(4.1)(4.2)Allowance for Uncollectible Accounts(5.0)(4.2)
Total Accounts ReceivableTotal Accounts Receivable 225.6 250.2 Total Accounts Receivable 332.0 250.2 
Materials and SuppliesMaterials and Supplies 139.9 138.8 Materials and Supplies 170.9 138.8 
Accrued Tax Benefits8.3 12.2 
Prepayments and Other Current AssetsPrepayments and Other Current Assets 5.9 6.0 Prepayments and Other Current Assets 25.9 18.2 
TOTAL CURRENT ASSETSTOTAL CURRENT ASSETS 429.1 446.9 TOTAL CURRENT ASSETS 624.8 446.9 
  
PROPERTY, PLANT AND EQUIPMENTPROPERTY, PLANT AND EQUIPMENT   PROPERTY, PLANT AND EQUIPMENT   
Electric:Electric:  Electric:  
TransmissionTransmission 6,373.2 6,301.5 Transmission 6,579.9 6,301.5 
DistributionDistribution 5,419.5 5,312.8 Distribution 5,694.5 5,312.8 
Other Property, Plant and EquipmentOther Property, Plant and Equipment 1,078.7 1,022.8 Other Property, Plant and Equipment 1,119.6 1,022.8 
Construction Work in ProgressConstruction Work in Progress 934.8 805.2 Construction Work in Progress 1,053.9 805.2 
Total Property, Plant and EquipmentTotal Property, Plant and Equipment 13,806.2 13,442.3 Total Property, Plant and Equipment 14,447.9 13,442.3 
Accumulated Depreciation and AmortizationAccumulated Depreciation and Amortization 1,798.2 1,760.7 Accumulated Depreciation and Amortization 1,857.1 1,760.7 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NETTOTAL PROPERTY, PLANT AND EQUIPMENT – NET 12,008.0 11,681.6 TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 12,590.8 11,681.6 
  
OTHER NONCURRENT ASSETSOTHER NONCURRENT ASSETS   OTHER NONCURRENT ASSETS   
Regulatory AssetsRegulatory Assets 299.3 298.3 Regulatory Assets 307.7 298.3 
Securitized Assets
(March 31, 2023 and December 31, 2022 Amounts Include $267.1 and $286.4, Respectively, Related to Transition Funding and Restoration Funding)
267.1 286.4 
Securitized Assets
(September 30, 2023 and December 31, 2022 Amounts Include $225.5 and $286.4, Respectively, Related to Transition Funding and Restoration Funding)
Securitized Assets
(September 30, 2023 and December 31, 2022 Amounts Include $225.5 and $286.4, Respectively, Related to Transition Funding and Restoration Funding)
225.5 286.4 
Deferred Charges and Other Noncurrent AssetsDeferred Charges and Other Noncurrent Assets 268.7 179.0 Deferred Charges and Other Noncurrent Assets 208.9 179.0 
TOTAL OTHER NONCURRENT ASSETSTOTAL OTHER NONCURRENT ASSETS 835.1 763.7 TOTAL OTHER NONCURRENT ASSETS 742.1 763.7 
  
TOTAL ASSETSTOTAL ASSETS $13,272.2 $12,892.2 TOTAL ASSETS $13,957.7 $12,892.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
5759



AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
March 31,September 30, 2023 and December 31, 2022
(in millions)
(Unaudited)
 March 31,December 31,  September 30,December 31,
 2023 2022  2023 2022
CURRENT LIABILITIESCURRENT LIABILITIES CURRENT LIABILITIES 
Advances from AffiliatesAdvances from Affiliates $450.8 $96.5 Advances from Affiliates $— $96.5 
Accounts Payable:Accounts Payable: Accounts Payable: 
GeneralGeneral 288.4 331.0 General 249.3 331.0 
Affiliated CompaniesAffiliated Companies 26.7 34.7 Affiliated Companies 31.5 34.7 
Long-term Debt Due Within One Year – Nonaffiliated
(March 31, 2023 and December 31, 2022 Amounts Include $93.7 and $93.5, Respectively, Related to Transition Funding and Restoration Funding)
153.7 278.5 
Long-term Debt Due Within One Year – Nonaffiliated
(September 30, 2023 and December 31, 2022 Amounts Include $94.9 and $93.5, Respectively, Related to Transition Funding and Restoration Funding)
Long-term Debt Due Within One Year – Nonaffiliated
(September 30, 2023 and December 31, 2022 Amounts Include $94.9 and $93.5, Respectively, Related to Transition Funding and Restoration Funding)
94.9 278.5 
Accrued TaxesAccrued Taxes 136.1 95.5 Accrued Taxes 139.6 95.5 
Accrued Interest
(March 31, 2023 and December 31, 2022 Amounts Include $2.2 and $2.2, Respectively, Related to Transition Funding and Restoration Funding)
72.2 48.3 
Accrued Interest
(September 30, 2023 and December 31, 2022 Amounts Include $2 and $2.2, Respectively, Related to Transition Funding and Restoration Funding)
Accrued Interest
(September 30, 2023 and December 31, 2022 Amounts Include $2 and $2.2, Respectively, Related to Transition Funding and Restoration Funding)
81.4 48.3 
Obligations Under Operating LeasesObligations Under Operating Leases29.4 28.6 Obligations Under Operating Leases30.2 28.6 
Other Current LiabilitiesOther Current Liabilities 122.8 130.7 Other Current Liabilities 153.9 130.7 
TOTAL CURRENT LIABILITIESTOTAL CURRENT LIABILITIES 1,280.1 1,043.8 TOTAL CURRENT LIABILITIES 780.8 1,043.8 
  
NONCURRENT LIABILITIESNONCURRENT LIABILITIES   NONCURRENT LIABILITIES   
Long-term Debt – Nonaffiliated
(March 31, 2023 and December 31, 2022 Amounts Include $209.3 and $221, Respectively, Related to Transition Funding and Restoration Funding)
5,368.3 5,379.3 
Long-term Debt – Nonaffiliated
(September 30, 2023 and December 31, 2022 Amounts Include $165.1 and $221, Respectively, Related to Transition Funding and Restoration Funding)
Long-term Debt – Nonaffiliated
(September 30, 2023 and December 31, 2022 Amounts Include $165.1 and $221, Respectively, Related to Transition Funding and Restoration Funding)
5,831.8 5,379.3 
Deferred Income TaxesDeferred Income Taxes 1,153.2 1,144.2 Deferred Income Taxes 1,220.8 1,144.2 
Regulatory Liabilities and Deferred Investment Tax CreditsRegulatory Liabilities and Deferred Investment Tax Credits 1,258.0 1,259.6 Regulatory Liabilities and Deferred Investment Tax Credits 1,256.7 1,259.6 
Obligations Under Operating LeasesObligations Under Operating Leases64.8 67.8 Obligations Under Operating Leases54.6 67.8 
Deferred Credits and Other Noncurrent LiabilitiesDeferred Credits and Other Noncurrent Liabilities 96.5 93.2 Deferred Credits and Other Noncurrent Liabilities 102.5 93.2 
TOTAL NONCURRENT LIABILITIESTOTAL NONCURRENT LIABILITIES 7,940.8 7,944.1 TOTAL NONCURRENT LIABILITIES 8,466.4 7,944.1 
  
TOTAL LIABILITIESTOTAL LIABILITIES 9,220.9 8,987.9 TOTAL LIABILITIES 9,247.2 8,987.9 
  
Rate Matters (Note 4)Rate Matters (Note 4)Rate Matters (Note 4)
Commitments and Contingencies (Note 5)Commitments and Contingencies (Note 5) Commitments and Contingencies (Note 5) 
  
COMMON SHAREHOLDER’S EQUITYCOMMON SHAREHOLDER’S EQUITY   COMMON SHAREHOLDER’S EQUITY   
Paid-in CapitalPaid-in Capital 1,658.2 1,558.2 Paid-in Capital 2,079.7 1,558.2 
Retained EarningsRetained Earnings 2,402.3 2,354.7 Retained Earnings 2,636.9 2,354.7 
Accumulated Other Comprehensive Income (Loss)Accumulated Other Comprehensive Income (Loss)(9.2)(8.6)Accumulated Other Comprehensive Income (Loss)(6.1)(8.6)
TOTAL COMMON SHAREHOLDER’S EQUITYTOTAL COMMON SHAREHOLDER’S EQUITY 4,051.3 3,904.3 TOTAL COMMON SHAREHOLDER’S EQUITY 4,710.5 3,904.3 
  
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITYTOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $13,272.2 $12,892.2 TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $13,957.7 $12,892.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
5860



AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the ThreeNine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
 Three Months Ended March 31,  Nine Months Ended September 30,
 2023 2022  2023 2022
OPERATING ACTIVITIESOPERATING ACTIVITIES    OPERATING ACTIVITIES    
Net IncomeNet Income $47.6 $69.6 Net Income $282.2 $253.2 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:   Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:   
Depreciation and AmortizationDepreciation and Amortization 111.0 108.8 Depreciation and Amortization 351.5 342.7 
Deferred Income TaxesDeferred Income Taxes 6.4 7.0 Deferred Income Taxes 64.2 35.1 
Allowance for Equity Funds Used During ConstructionAllowance for Equity Funds Used During Construction(6.3)(4.3)Allowance for Equity Funds Used During Construction(19.4)(13.2)
Mark-to-Market of Risk Management ContractsMark-to-Market of Risk Management Contracts 0.4 (0.2)Mark-to-Market of Risk Management Contracts — (0.2)
Property Taxes(88.8)(79.5)
Change in Other Noncurrent AssetsChange in Other Noncurrent Assets (18.3)(17.0)Change in Other Noncurrent Assets (118.0)(48.4)
Change in Other Noncurrent LiabilitiesChange in Other Noncurrent Liabilities (0.8)5.8 Change in Other Noncurrent Liabilities 26.7 49.2 
Changes in Certain Components of Working Capital:Changes in Certain Components of Working Capital:  Changes in Certain Components of Working Capital:  
Accounts Receivable, NetAccounts Receivable, Net 24.6 (20.2)Accounts Receivable, Net (81.8)(57.5)
Materials and SuppliesMaterials and Supplies (1.1)(4.9)Materials and Supplies (32.1)(39.9)
Accounts PayableAccounts Payable 3.6 9.6 Accounts Payable 0.7 16.0 
Accrued Taxes, NetAccrued Taxes, Net44.5 37.9 Accrued Taxes, Net39.7 39.4 
Other Current AssetsOther Current Assets 0.9 0.8 Other Current Assets (0.7)1.0 
Other Current LiabilitiesOther Current Liabilities 13.0 16.5 Other Current Liabilities (9.9)12.2 
Net Cash Flows from Operating ActivitiesNet Cash Flows from Operating Activities 136.7 129.9 Net Cash Flows from Operating Activities 503.1 589.6 
  
INVESTING ACTIVITIESINVESTING ACTIVITIES   INVESTING ACTIVITIES   
Construction ExpendituresConstruction Expenditures (450.4)(356.6)Construction Expenditures (1,175.1)(949.8)
Change in Advances to Affiliates, NetChange in Advances to Affiliates, Net0.1 0.1 Change in Advances to Affiliates, Net(42.1)(129.4)
Other Investing ActivitiesOther Investing Activities7.3 13.7 Other Investing Activities42.2 26.7 
Net Cash Flows Used for Investing ActivitiesNet Cash Flows Used for Investing Activities (443.0)(342.8)Net Cash Flows Used for Investing Activities (1,175.0)(1,052.5)
  
FINANCING ACTIVITIESFINANCING ACTIVITIES   FINANCING ACTIVITIES   
Capital Contribution from ParentCapital Contribution from Parent100.0 — Capital Contribution from Parent525.8 1.8 
Return of Capital to ParentReturn of Capital to Parent(4.3)— 
Issuance of Long-term Debt – NonaffiliatedIssuance of Long-term Debt – Nonaffiliated505.4 1,188.7 
Change in Advances from Affiliates, NetChange in Advances from Affiliates, Net 354.3 235.3 Change in Advances from Affiliates, Net (96.5)(26.9)
Retirement of Long-term Debt – NonaffiliatedRetirement of Long-term Debt – Nonaffiliated (136.7)(11.4)Retirement of Long-term Debt – Nonaffiliated (240.0)(678.6)
Principal Payments for Finance Lease ObligationsPrincipal Payments for Finance Lease Obligations (1.8)(1.7)Principal Payments for Finance Lease Obligations (5.5)(5.1)
Other Financing ActivitiesOther Financing Activities0.3 0.2 Other Financing Activities1.2 0.3 
Net Cash Flows from Financing ActivitiesNet Cash Flows from Financing Activities 316.1 222.4 Net Cash Flows from Financing Activities 686.1 480.2 
Net Increase in Cash, Cash Equivalents and Restricted 9.8 9.5 
Net Increase in Cash, Cash Equivalents and Restricted CashNet Increase in Cash, Cash Equivalents and Restricted Cash 14.2 17.3 
Cash, Cash Equivalents and Restricted Cash at Beginning of PeriodCash, Cash Equivalents and Restricted Cash at Beginning of Period 32.8 30.5 Cash, Cash Equivalents and Restricted Cash at Beginning of Period 32.8 30.5 
Cash, Cash Equivalents and Restricted Cash at End of PeriodCash, Cash Equivalents and Restricted Cash at End of Period $42.6 $40.0 Cash, Cash Equivalents and Restricted Cash at End of Period $47.0 $47.8 
  
SUPPLEMENTARY INFORMATIONSUPPLEMENTARY INFORMATION   SUPPLEMENTARY INFORMATION   
Cash Paid for Interest, Net of Capitalized AmountsCash Paid for Interest, Net of Capitalized Amounts $31.6 $29.9 Cash Paid for Interest, Net of Capitalized Amounts $135.9 $121.1 
Net Cash Paid for Income TaxesNet Cash Paid for Income Taxes 4.3 10.0 
Noncash Acquisitions Under Finance LeasesNoncash Acquisitions Under Finance Leases 1.8 0.6 Noncash Acquisitions Under Finance Leases 3.7 4.1 
Construction Expenditures Included in Current Liabilities as of March 31, 177.5 147.6 
Construction Expenditures Included in Current Liabilities as of September 30,Construction Expenditures Included in Current Liabilities as of September 30, 153.6 156.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
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AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
60



AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

Summary of Investment in Transmission Assets for AEPTCo
As of March 31,As of September 30,
2023202220232022
(in millions)(in millions)
Plant In ServicePlant In Service$12,971.3 $11,637.9 Plant In Service$13,638.0 $12,223.9 
Construction Work in ProgressConstruction Work in Progress1,831.9 1,534.3 Construction Work in Progress1,902.1 1,652.2 
Accumulated Depreciation and AmortizationAccumulated Depreciation and Amortization1,091.2 842.6 Accumulated Depreciation and Amortization1,221.2 966.5 
Total Transmission Property, NetTotal Transmission Property, Net$13,712.0 $12,329.6 Total Transmission Property, Net$14,318.9 $12,909.6 

First
AEP Transmission Company, LLC and Subsidiaries
Reconciliation of 2022 to 2023 Net Income
(in millions)
Three Months Ended 
September 30,
Nine Months Ended 
September 30,
2022 Net Income$152.7 $426.6 
Changes in Transmission Revenues:
Transmission Revenues44.2 165.9 
Total Change in Transmission Revenues44.2 165.9 
Changes in Expenses and Other:
Other Operation and Maintenance7.0 4.6 
Depreciation and Amortization(12.2)(35.0)
Taxes Other Than Income Taxes(5.1)(13.6)
Interest Income0.9 4.7 
Allowance for Equity Funds Used During Construction2.4 11.0 
Interest Expense(8.9)(27.8)
Total Change in Expenses and Other(15.9)(56.1)
Income Tax Expense(1.8)(18.8)
2023 Net Income$179.2 $517.6 

Third Quarter of 2023 Compared to FirstThird Quarter of 2022
AEP Transmission Company, LLC and Subsidiaries
Reconciliation of First Quarter of 2022 to First Quarter of 2023
Net Income
(in millions)
First Quarter of 2022$155.4 
Changes in Transmission Revenues:
Transmission Revenues41.2 
Total Change in Transmission Revenues41.2 
Changes in Expenses and Other:
Other Operation and Maintenance(5.1)
Depreciation and Amortization(12.1)
Taxes Other Than Income Taxes(9.2)
Interest Income1.4 
Allowance for Equity Funds Used During Construction0.8 
Interest Expense(7.5)
Total Change in Expenses and Other(31.7)
Income Tax Expense(2.2)
First Quarter of 2023$162.7 

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

Transmission Revenues increased $41$44 million primarily due to continued investment in transmission assets.

Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses increased $5decreased $7 million primarily due to higher vegetation management expenses, affiliated rent expense and other miscellaneousthe following:
A $5 million decrease due to cancelled capital projects in 2022.
A $3 million decrease in employee-related expenses.
62


Depreciation and Amortization expenses increased $12 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $9$5 million primarily due to higher property taxes as a result ofdriven by increased transmission investment.
Interest Expense increased $8$9 million due to higher long-term debt balances and interest rates.

Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022

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

Transmission Revenues increased $166 million primarily due to the following:
A $127 million increase due to continued investment in transmission assets.
A $33 million increase due to affiliated transmission formula rate true-up activity. This increase was offset in Other Operation and Maintenance expenses across the other Registrant Subsidiaries.
A $6 million increase due to nonaffiliated transmission formula rate true-up activity.

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

Depreciation and Amortization expenses increased $35 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $14 million primarily due to higher property taxes driven by increased transmission investment.
Allowance for Equity Funds Used During Construction increased $11 million primarily due to higher CWIP and AFUDC equity rates.
Interest Expense increased $28 million primarily due to higher long-term debt balances and higher interest rates.
Income Tax Expense increased $19 million primarily due to an increase in pretax book income.


61
63




AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
Three Months EndedNine Months Ended
Three Months Ended March 31,September 30,September 30,
2023 20222023 2022 2023 2022
REVENUESREVENUESREVENUES
Transmission RevenuesTransmission Revenues$90.0 $87.0 Transmission Revenues$93.8 $89.1 $274.0 $261.7 
Sales to AEP AffiliatesSales to AEP Affiliates357.4 325.0 Sales to AEP Affiliates374.7 340.6 1,097.9 999.5 
Provision for Refund – AffiliatedProvision for Refund – Affiliated(4.8)(0.3)Provision for Refund – Affiliated(4.8)(9.3)(17.9)(65.7)
Provision for Refund – NonaffiliatedProvision for Refund – Nonaffiliated(1.0)(11.3)Provision for Refund – Nonaffiliated(1.0)(1.9)(4.8)(12.2)
TOTAL REVENUESTOTAL REVENUES441.6 400.4 TOTAL REVENUES462.7 418.5 1,349.2 1,183.3 
EXPENSESEXPENSES  EXPENSES    
Other OperationOther Operation29.0 25.5 Other Operation31.6 39.6 87.0 94.7 
MaintenanceMaintenance4.9 3.3 Maintenance5.1 4.1 14.3 11.2 
Depreciation and AmortizationDepreciation and Amortization95.2 83.1 Depreciation and Amortization99.6 87.4 291.2 256.2 
Taxes Other Than Income TaxesTaxes Other Than Income Taxes74.8 65.6 Taxes Other Than Income Taxes73.8 68.7 216.6 203.0 
TOTAL EXPENSESTOTAL EXPENSES203.9 177.5 TOTAL EXPENSES210.1 199.8 609.1 565.1 
OPERATING INCOMEOPERATING INCOME237.7 222.9 OPERATING INCOME252.6 218.7 740.1 618.2 
Other Income (Expense):Other Income (Expense):  Other Income (Expense):    
Interest Income - AffiliatedInterest Income - Affiliated1.5 0.1 Interest Income - Affiliated1.6 0.7 5.7 1.0 
Allowance for Equity Funds Used During ConstructionAllowance for Equity Funds Used During Construction16.4 15.6 Allowance for Equity Funds Used During Construction22.7 20.3 62.2 51.2 
Interest ExpenseInterest Expense(45.2)(37.7)Interest Expense(51.6)(42.7)(147.5)(119.7)
INCOME BEFORE INCOME TAX EXPENSEINCOME BEFORE INCOME TAX EXPENSE210.4 200.9 INCOME BEFORE INCOME TAX EXPENSE225.3 197.0 660.5 550.7 
Income Tax ExpenseIncome Tax Expense47.7 45.5 Income Tax Expense46.1 44.3 142.9 124.1 
NET INCOMENET INCOME$162.7 $155.4 NET INCOME$179.2 $152.7 $517.6 $426.6 
AEPTCo is wholly-owned by AEP Transmission Holdco.AEPTCo is wholly-owned by AEP Transmission Holdco.AEPTCo is wholly-owned by AEP Transmission Holdco.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
6264



AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY
For the ThreeNine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
 Paid-in
Capital
Retained
Earnings
Total  Paid-in
Capital
Retained
Earnings
Total
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2021TOTAL MEMBER'S EQUITY – DECEMBER 31, 2021 $2,949.6 $2,426.5 $5,376.1 TOTAL MEMBER'S EQUITY – DECEMBER 31, 2021 $2,949.6 $2,426.5 $5,376.1 
   
Dividends Paid to MemberDividends Paid to Member(40.0)(40.0)Dividends Paid to Member(40.0)(40.0)
Net IncomeNet Income 155.4 155.4 Net Income 155.4 155.4 
TOTAL MEMBER'S EQUITY – MARCH 31, 2022TOTAL MEMBER'S EQUITY – MARCH 31, 2022$2,949.6 $2,541.9 $5,491.5 TOTAL MEMBER'S EQUITY – MARCH 31, 20222,949.6 2,541.9 5,491.5 
Capital Contribution from MemberCapital Contribution from Member2.8 2.8 
Dividends Paid to MemberDividends Paid to Member(50.0)(50.0)
Net IncomeNet Income118.5 118.5 
TOTAL MEMBER'S EQUITY – JUNE 30, 2022TOTAL MEMBER'S EQUITY – JUNE 30, 20222,952.4 2,610.4 5,562.8 
Capital Contribution from MemberCapital Contribution from Member 61.4 61.4 
Dividends Paid to MemberDividends Paid to Member(40.0)(40.0)
Net IncomeNet Income 152.7 152.7 
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2022TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2022 $3,013.8 $2,723.1 $5,736.9 
   
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2022TOTAL MEMBER'S EQUITY – DECEMBER 31, 2022 $3,022.3 $2,850.7 $5,873.0 TOTAL MEMBER'S EQUITY – DECEMBER 31, 2022 $3,022.3 $2,850.7 $5,873.0 
Capital Contribution from MemberCapital Contribution from Member25.0 25.0 Capital Contribution from Member25.0 25.0 
Dividends Paid to MemberDividends Paid to Member(55.0)(55.0)Dividends Paid to Member(55.0)(55.0)
Net IncomeNet Income162.7 162.7 Net Income162.7 162.7 
TOTAL MEMBER'S EQUITY – MARCH 31, 2023TOTAL MEMBER'S EQUITY – MARCH 31, 2023$3,047.3 $2,958.4 $6,005.7 TOTAL MEMBER'S EQUITY – MARCH 31, 20233,047.3 2,958.4 6,005.7 
 
Return of Capital to MemberReturn of Capital to Member(8.6)(8.6)
Dividends Paid to MemberDividends Paid to Member(30.0)(30.0)
Net IncomeNet Income175.7 175.7 
TOTAL MEMBER'S EQUITY – JUNE 30, 2023TOTAL MEMBER'S EQUITY – JUNE 30, 20233,038.7 3,104.1 6,142.8 
Capital Contribution from MemberCapital Contribution from Member 2.9 2.9 
Dividends Paid to MemberDividends Paid to Member(30.0)(30.0)
Net IncomeNet Income  179.2 179.2 
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2023TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2023 $3,041.6 $3,253.3 $6,294.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
6365



AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31,September 30, 2023 and December 31, 2022
(in millions)
(Unaudited)
 March 31, December 31,  September 30, December 31,
 2023 2022  2023 2022
CURRENT ASSETSCURRENT ASSETS    CURRENT ASSETS    
Advances to AffiliatesAdvances to Affiliates $297.5 $4.4 Advances to Affiliates $90.6 $4.4 
Accounts Receivable:Accounts Receivable: Accounts Receivable: 
CustomersCustomers 51.9 46.9 Customers 80.4 46.9 
Affiliated CompaniesAffiliated Companies 127.0 119.5 Affiliated Companies 123.1 119.5 
Total Accounts ReceivableTotal Accounts Receivable 178.9 166.4 Total Accounts Receivable 203.5 166.4 
Materials and SuppliesMaterials and Supplies 14.8 10.7 Materials and Supplies 0.3 10.7 
Prepayments and Other Current AssetsPrepayments and Other Current Assets 2.1 7.2 Prepayments and Other Current Assets 4.1 7.2 
TOTAL CURRENT ASSETSTOTAL CURRENT ASSETS 493.3 188.7 TOTAL CURRENT ASSETS 298.5 188.7 
  
TRANSMISSION PROPERTYTRANSMISSION PROPERTY   TRANSMISSION PROPERTY   
Transmission PropertyTransmission Property 12,486.7 12,335.4 Transmission Property 13,140.5 12,335.4 
Other Property, Plant and EquipmentOther Property, Plant and Equipment 484.6 476.8 Other Property, Plant and Equipment 497.5 476.8 
Construction Work in ProgressConstruction Work in Progress 1,831.9 1,554.7 Construction Work in Progress 1,902.1 1,554.7 
Total Transmission PropertyTotal Transmission Property 14,803.2 14,366.9 Total Transmission Property 15,540.1 14,366.9 
Accumulated Depreciation and AmortizationAccumulated Depreciation and Amortization 1,091.2 1,027.0 Accumulated Depreciation and Amortization 1,221.2 1,027.0 
TOTAL TRANSMISSION PROPERTY – NETTOTAL TRANSMISSION PROPERTY – NET 13,712.0 13,339.9 TOTAL TRANSMISSION PROPERTY – NET 14,318.9 13,339.9 
  
OTHER NONCURRENT ASSETSOTHER NONCURRENT ASSETS   OTHER NONCURRENT ASSETS   
Regulatory AssetsRegulatory Assets 5.8 7.2 Regulatory Assets 4.4 7.2 
Deferred Property TaxesDeferred Property Taxes 232.0 266.6 Deferred Property Taxes 82.2 266.6 
Deferred Charges and Other Noncurrent AssetsDeferred Charges and Other Noncurrent Assets 11.6 11.8 Deferred Charges and Other Noncurrent Assets 8.0 11.8 
TOTAL OTHER NONCURRENT ASSETSTOTAL OTHER NONCURRENT ASSETS 249.4 285.6 TOTAL OTHER NONCURRENT ASSETS 94.6 285.6 
  
TOTAL ASSETSTOTAL ASSETS $14,454.7 $13,814.2 TOTAL ASSETS $14,712.0 $13,814.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
6466



AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND MEMBER’S EQUITY
March 31,September 30, 2023 and December 31, 2022
(Unaudited)
 March 31, December 31,  September 30, December 31,
 2023 2022  2023 2022
(in millions)(in millions)
CURRENT LIABILITIESCURRENT LIABILITIES CURRENT LIABILITIES 
Advances from AffiliatesAdvances from Affiliates $4.4 $229.3 Advances from Affiliates $116.8 $229.3 
Accounts Payable:Accounts Payable:  Accounts Payable:  
GeneralGeneral 421.7 427.8 General 336.1 427.8 
Affiliated CompaniesAffiliated Companies 110.8 82.7 Affiliated Companies 96.1 82.7 
Long-term Debt Due Within One Year – NonaffiliatedLong-term Debt Due Within One Year – Nonaffiliated60.0 60.0 Long-term Debt Due Within One Year – Nonaffiliated60.0 60.0 
Accrued TaxesAccrued Taxes 465.7 529.8 Accrued Taxes 323.5 529.8 
Accrued InterestAccrued Interest 56.8 28.8 Accrued Interest 56.6 28.8 
Obligations Under Operating LeasesObligations Under Operating Leases1.3 1.3 Obligations Under Operating Leases1.3 1.3 
Other Current LiabilitiesOther Current Liabilities 14.1 8.3 Other Current Liabilities 12.8 8.3 
TOTAL CURRENT LIABILITIESTOTAL CURRENT LIABILITIES 1,134.8 1,368.0 TOTAL CURRENT LIABILITIES 1,003.2 1,368.0 
  
NONCURRENT LIABILITIESNONCURRENT LIABILITIES   NONCURRENT LIABILITIES   
Long-term Debt – NonaffiliatedLong-term Debt – Nonaffiliated 5,412.1 4,722.8 Long-term Debt – Nonaffiliated 5,413.7 4,722.8 
Deferred Income TaxesDeferred Income Taxes 1,079.1 1,056.5 Deferred Income Taxes 1,139.1 1,056.5 
Regulatory LiabilitiesRegulatory Liabilities 746.4 723.3 Regulatory Liabilities 784.5 723.3 
Obligations Under Operating LeasesObligations Under Operating Leases1.2 1.5 Obligations Under Operating Leases1.6 1.5 
Deferred Credits and Other Noncurrent LiabilitiesDeferred Credits and Other Noncurrent Liabilities 75.4 69.1 Deferred Credits and Other Noncurrent Liabilities 75.0 69.1 
TOTAL NONCURRENT LIABILITIESTOTAL NONCURRENT LIABILITIES 7,314.2 6,573.2 TOTAL NONCURRENT LIABILITIES 7,413.9 6,573.2 
  
TOTAL LIABILITIESTOTAL LIABILITIES 8,449.0 7,941.2 TOTAL LIABILITIES 8,417.1 7,941.2 
  
Rate Matters (Note 4)Rate Matters (Note 4) Rate Matters (Note 4) 
Commitments and Contingencies (Note 5)Commitments and Contingencies (Note 5) Commitments and Contingencies (Note 5) 
  
MEMBER’S EQUITYMEMBER’S EQUITY   MEMBER’S EQUITY   
Paid-in CapitalPaid-in Capital3,047.3 3,022.3 Paid-in Capital3,041.6 3,022.3 
Retained EarningsRetained Earnings 2,958.4 2,850.7 Retained Earnings 3,253.3 2,850.7 
TOTAL MEMBER’S EQUITYTOTAL MEMBER’S EQUITY 6,005.7 5,873.0 TOTAL MEMBER’S EQUITY 6,294.9 5,873.0 
  
TOTAL LIABILITIES AND MEMBER’S EQUITYTOTAL LIABILITIES AND MEMBER’S EQUITY $14,454.7 $13,814.2 TOTAL LIABILITIES AND MEMBER’S EQUITY $14,712.0 $13,814.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
6567



AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the ThreeNine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
 Three Months Ended March 31,  Nine Months Ended September 30,
 20232022  20232022
OPERATING ACTIVITIESOPERATING ACTIVITIES OPERATING ACTIVITIES 
Net IncomeNet Income $162.7 $155.4 Net Income $517.6 $426.6 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: 
Depreciation and AmortizationDepreciation and Amortization 95.2 83.1 Depreciation and Amortization 291.2 256.2 
Deferred Income TaxesDeferred Income Taxes 20.6 23.1 Deferred Income Taxes 64.2 60.6 
Allowance for Equity Funds Used During ConstructionAllowance for Equity Funds Used During Construction (16.4)(15.6)Allowance for Equity Funds Used During Construction (62.2)(51.2)
Property TaxesProperty Taxes 34.6 31.3 Property Taxes 184.4 170.0 
Change in Other Noncurrent AssetsChange in Other Noncurrent Assets 0.9 2.1 Change in Other Noncurrent Assets 5.8 4.0 
Change in Other Noncurrent LiabilitiesChange in Other Noncurrent Liabilities 6.6 11.8 Change in Other Noncurrent Liabilities 7.7 55.0 
Changes in Certain Components of Working Capital:Changes in Certain Components of Working Capital:  Changes in Certain Components of Working Capital:  
Accounts Receivable, NetAccounts Receivable, Net (12.5)(21.8)Accounts Receivable, Net (37.1)(66.4)
Materials and SuppliesMaterials and Supplies(4.1)(0.8)Materials and Supplies10.4 (2.4)
Accounts PayableAccounts Payable 41.0 3.6 Accounts Payable 25.0 53.1 
Accrued Taxes, NetAccrued Taxes, Net (59.9)(53.7)Accrued Taxes, Net (202.2)(194.0)
Other Current AssetsOther Current Assets 1.0 0.5 Other Current Assets (1.0)(1.2)
Other Current LiabilitiesOther Current Liabilities 29.6 19.8 Other Current Liabilities 21.7 27.2 
Net Cash Flows from Operating ActivitiesNet Cash Flows from Operating Activities 299.3 238.8 Net Cash Flows from Operating Activities 825.5 737.5 
  
INVESTING ACTIVITIESINVESTING ACTIVITIES   INVESTING ACTIVITIES   
Construction ExpendituresConstruction Expenditures (439.7)(417.1)Construction Expenditures (1,224.9)(1,059.3)
Change in Advances to Affiliates, NetChange in Advances to Affiliates, Net (293.1)22.6 Change in Advances to Affiliates, Net (86.2)(84.1)
Other Investing ActivitiesOther Investing Activities (0.8)(1.7)Other Investing Activities 4.8 (5.3)
Net Cash Flows Used for Investing ActivitiesNet Cash Flows Used for Investing Activities (733.6)(396.2)Net Cash Flows Used for Investing Activities (1,306.3)(1,148.7)
  
FINANCING ACTIVITIESFINANCING ACTIVITIES  FINANCING ACTIVITIES  
Capital Contribution from MemberCapital Contribution from Member 25.0 — Capital Contribution from Member 27.9 64.2 
Return of Capital to MemberReturn of Capital to Member(8.6)— 
Issuance of Long-term Debt – NonaffiliatedIssuance of Long-term Debt – Nonaffiliated689.2 — Issuance of Long-term Debt – Nonaffiliated689.0 540.9 
Change in Advances from Affiliates, NetChange in Advances from Affiliates, Net (224.9)197.4 Change in Advances from Affiliates, Net (112.5)(63.9)
Dividends Paid to MemberDividends Paid to Member(55.0)(40.0)Dividends Paid to Member(115.0)(130.0)
Net Cash Flows from Financing ActivitiesNet Cash Flows from Financing Activities 434.3 157.4 Net Cash Flows from Financing Activities 480.8 411.2 
  
Net Change in Cash and Cash EquivalentsNet Change in Cash and Cash Equivalents — — Net Change in Cash and Cash Equivalents — — 
Cash and Cash Equivalents at Beginning of PeriodCash and Cash Equivalents at Beginning of Period — — Cash and Cash Equivalents at Beginning of Period — — 
Cash and Cash Equivalents at End of PeriodCash and Cash Equivalents at End of Period $— $— Cash and Cash Equivalents at End of Period $— $— 
  
SUPPLEMENTARY INFORMATIONSUPPLEMENTARY INFORMATION   SUPPLEMENTARY INFORMATION   
Cash Paid for Interest, Net of Capitalized AmountsCash Paid for Interest, Net of Capitalized Amounts $16.2 $16.4 Cash Paid for Interest, Net of Capitalized Amounts $116.9 $88.6 
Construction Expenditures Included in Current Liabilities as of March 31, 305.4 214.6 
Net Cash Paid for Income TaxesNet Cash Paid for Income Taxes 55.0 53.2 
Construction Expenditures Included in Current Liabilities as of September 30,Construction Expenditures Included in Current Liabilities as of September 30, 219.2 240.5 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
6668





APPALACHIAN POWER COMPANY AND SUBSIDIARIES
67



APPALACHIAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
Three Months EndedNine Months Ended
Three Months Ended March 31, September 30,September 30,
202320222023202220232022
(in millions of KWhs) (in millions of KWhs)
Retail:Retail:  Retail:    
ResidentialResidential3,059 3,532 Residential2,481 2,553 7,527 8,308 
CommercialCommercial1,403 1,519 Commercial1,537 1,566 4,286 4,545 
IndustrialIndustrial2,109 2,219 Industrial2,229 2,211 6,473 6,655 
MiscellaneousMiscellaneous200 213 Miscellaneous205 206 595 624 
Total RetailTotal Retail6,771 7,483 Total Retail6,452 6,536 18,881 20,132 
WholesaleWholesale489 363 Wholesale691 644 1,694 1,269 
Total KWhsTotal KWhs7,260 7,846 Total KWhs7,143 7,180 20,575 21,401 

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

Summary of Heating and Cooling Degree Days
Three Months EndedNine Months Ended
Three Months Ended March 31, September 30,September 30,
202320222023202220232022
(in degree days) (in degree days)
Actual – Heating (a)Actual – Heating (a)859 1,274 Actual – Heating (a)— 928 1,372 
Normal – Heating (b)Normal – Heating (b)1,321 1,319 Normal – Heating (b)1,410 1,410 
Actual – Cooling (c)Actual – Cooling (c)Actual – Cooling (c)873 876 1,106 1,299 
Normal – Cooling (b)Normal – Cooling (b)Normal – Cooling (b)837 832 1,222 1,210 

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

6869


Appalachian Power Company and Subsidiaries
Reconciliation of 2022 to 2023 Net Income
(in millions)
Three Months Ended 
September 30,
Nine Months Ended 
September 30,
2022 Net Income$92.7 $303.1 
  
Changes in Gross Margin: 
Retail Margins46.5 79.7 
Margins from Off-system Sales(4.2)(1.5)
Transmission Revenues3.9 6.5 
Other Revenues1.5 (5.1)
Total Change in Gross Margin47.7 79.6 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(10.9)(63.5)
Asset Impairments and Other Related Charges - Coal Fired Generation24.9 24.9 
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset(37.0)(37.0)
Depreciation and Amortization(0.8)6.2 
Taxes Other Than Income Taxes(2.0)(5.5)
Interest Income(1.8)(0.8)
Allowance for Equity Funds Used During Construction1.4 1.9 
Non-Service Cost Components of Net Periodic Benefit Cost0.8 2.6 
Interest Expense(6.8)(29.6)
Total Change in Expenses and Other(32.2)(100.8)
  
Income Tax Expense(16.3)(34.6)
  
2023 Net Income$91.9 $247.3 

FirstThird Quarter of 2023 Compared to FirstThird Quarter of 2022
Appalachian Power Company and Subsidiaries
Reconciliation of First Quarter of 2022 to First Quarter of 2023
Net Income
(in millions)
First Quarter of 2022$120.2 
Changes in Gross Margin:
Retail Margins13.1 
Margins from Off-system Sales2.2 
Transmission Revenues0.1 
Other Revenues(4.2)
Total Change in Gross Margin11.2 
Changes in Expenses and Other:
Other Operation and Maintenance(5.9)
Depreciation and Amortization2.2 
Taxes Other Than Income Taxes(1.6)
Interest Income0.5 
Allowance for Equity Funds Used During Construction0.4 
Non-Service Cost Components of Net Periodic Benefit Cost0.8 
Interest Expense(11.0)
Total Change in Expenses and Other(14.6)
Income Tax Expense(4.3)
First Quarter of 2023$112.5 

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

Retail Margins increased $13$47 million primarily due to the following:
A $16 million increase in weather-normalized margins primarily driven by an increase in the residential class.
A $15$19 million increase due to a base rate increaserider revenues in Virginia implemented in October 2022 following the Virginia Supreme Court remand.and West Virginia. This increase was partially offset in Other Operation and Maintenanceother expense items below.
A $10$12 million increase driven by salesin deferred fuel primarily related to the timing of renewable energy creditsrecoverable PJM expenses. This increase was offset in Other Operation and lower fuel handling costs in Virginia.Maintenance expenses below.
A $9An $8 million increase due to lower customer refunds related to Tax Reform. This increase was offset in Income Tax Expense below.
A $7 million increase due to a base rate increase in Virginia implemented in October 2022 following the Virginia Supreme Court remand. This increase was partially offset in Other Operations and Maintenance expenses below.
A $4 million increase due to lowerthe prior year amortization expenses related to the Virginia CCR.of costs recovered through Virginia’s environmental rate adjustment clause. This increase was offset in other expense items below.
These increases were partially offset by:
A $43 million decrease in weather-related usage primarily driven by a 33% decrease in heating degree days.
Other Revenues decreased $4 million primarily due to pole attachment revenue. This decrease was partially offset in Other Operation and Maintenance Expense below.
6970



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

Other Operation and Maintenance expenses increased $6$11 million primarily due to the following:
A $7 million increase due to the amortization of the regulatory asset in accordance with the August 2022 Virginia Supreme Court opinion related to under-earnings during the 2017-2019 Triennial Review. This increase was offset in Retail Margins above.
A $7 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses. This increase was partially offset in Retail Margins above.
A $2 million increase in distribution expenses primarily due to storm restoration costs.
A $2 million increase in renewable energy credits and compliance expenses associated with the Virginia Clean Economy Act. This increase was offset in Retail Margins above.
These increases were partially offset by:
A $9 million decrease due to an increase in proceeds received for insurance policy settlements.
Asset Impairments and Other Related Charges - Coal Fired Generation decreased $25 million due to the prior year write-off of a regulatory asset in accordance with the August 2022 Virginia Supreme Court opinion related to the 2017-2019 Triennial Review.
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset decreased $37 million due to the prior year establishment of a regulatory asset in accordance with the August 2022 Virginia Supreme Court opinion and resulting under-earning during the 2017-2019 Triennial Review.
Interest Expense increased $11$7 million primarily due to higher long-term debt balances and higher interest rates.
Income Tax Expense increased $4$16 million primarily due to the following:
A $9 million increase in state taxes.
A $3 million increase due to an increase in pretax book income.
A $2 million increase due to a decrease in amortization of Excess ADIT.

Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022

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

Retail Margins increased $80 million primarily due to the following:
A $44 million increase due to rider revenues in Virginia and West Virginia. This increase was partially offset in other expense items below.
A $25 million increase due to lower customer refunds related to Tax Reform. This increase was offset in Income Tax Expense below.
A $24 million increase in deferred fuel primarily related to the timing of recoverable PJM expenses. This increase was partially offset in Other Operation and Maintenance expenses below.
A $19 million increase due to a base rate increase in Virginia implemented in October 2022 following the Virginia Supreme Court remand. This increase was partially offset in Other Operation and Maintenance expenses below.
A $13 million increase due to the prior year amortization of costs recovered through Virginia’s environmental rate adjustment clause. This increase was offset in other expense items below.
An $8 million increase in weather-normalized margins primarily driven by increases in the residential class.
These increases were partially offset by:
A $63 million decrease in weather-related usage primarily driven by a 32% decrease in heating degree days and a 15% decrease in cooling degree days.
Transmission Revenues increased $7 million primarily due to increased transmission investment.
Other Revenues decreased $5 million primarily due to pole attachment revenue.


71


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

Other Operation and Maintenance expenses increased $64 million primarily due to the following:
A $21 million increase due to the amortization of the regulatory asset in accordance with the August 2022 Virginia Supreme Court opinion related to under-earnings during the 2017-2019 Triennial Review. This increase was offset in Retail Margins above.
A $17 million increase in distribution expenses primarily due to storm restoration costs.
A $14 million increase due to gains from the sale of land in 2022.
A $9 million increase in transmission expenses primarily due to the following:
A $5 million increase in transmission formula rate true-up activity. This increase was partially offset in Retail Margins above.
A $4 million increase in vegetation management expenses.
An $8 million increase in accounts receivable factoring expenses as a result of increased interest rates.
A $6 million increase in renewable energy credits and compliance expenses associated with the Virginia Clean Economy Act. This increase was offset in Retail Margins above.
These increases were partially offset by:
An $11 million decrease in employee-related expenses.
A $3 million decrease due to an increase in proceeds received for insurance policy settlements.
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 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 and resulting under-earning during the 2017-2019 Triennial Review.
Depreciation and Amortization expenses decreased $6 million primarily due to the following:
A $21 million decrease due to the implementation of updated Virginia depreciation rates in 2023.
This decrease was partially offset by:
A $16 million increase due to a higher depreciable base.
Taxes Other Than Income Taxes expenses increased $6 million due to an increase in Virginia state minimum taxes primarily due to an increased projected minimum tax liability.
Interest Expense increased $30 million primarily due to higher long-term debt balances and interest rates.
Income Tax Expense increased $35 million primarily due to the following:
A $19 million decrease in amortization of Excess ADIT. This decrease was partially offset in Retail Margins above.
An $11 million increase due to unfavorable discrete tax adjustments in 2023.
A $10 million increase in state taxes.
These increases were partially offset by:
A $7 million decrease due to an increase in flow through depreciation expense.






7072




APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
Three Months Ended March 31, Three Months EndedNine Months Ended
September 30,September 30,
20232022 2023202220232022
REVENUESREVENUES  REVENUES    
Electric Generation, Transmission and DistributionElectric Generation, Transmission and Distribution$914.5 $847.1 Electric Generation, Transmission and Distribution$896.0 $818.4 $2,573.0 $2,370.4 
Sales to AEP AffiliatesSales to AEP Affiliates69.6 56.9 Sales to AEP Affiliates62.5 67.6 193.2 187.6 
Other RevenuesOther Revenues3.6 3.3 Other Revenues3.3 2.9 9.8 11.8 
TOTAL REVENUESTOTAL REVENUES987.7 907.3 TOTAL REVENUES961.8 888.9 2,776.0 2,569.8 
EXPENSESEXPENSES  EXPENSES    
Purchased Electricity, Fuel and Other Consumables Used for Electric GenerationPurchased Electricity, Fuel and Other Consumables Used for Electric Generation339.7 270.5 Purchased Electricity, Fuel and Other Consumables Used for Electric Generation343.2 318.0 960.8 834.2 
Other OperationOther Operation191.8 184.9 Other Operation187.9 182.0 569.6 514.0 
MaintenanceMaintenance73.1 74.1 Maintenance74.3 69.3 222.5 214.6 
Asset Impairments and Other Related Charges - Coal Fired GenerationAsset Impairments and Other Related Charges - Coal Fired Generation— 24.9 — 24.9 
Establishment of 2017-2019 Virginia Triennial Review Regulatory AssetEstablishment of 2017-2019 Virginia Triennial Review Regulatory Asset— (37.0)— (37.0)
Depreciation and AmortizationDepreciation and Amortization143.0 145.2 Depreciation and Amortization143.7 142.9 424.8 431.0 
Taxes Other Than Income TaxesTaxes Other Than Income Taxes41.8 40.2 Taxes Other Than Income Taxes43.5 41.5 126.5 121.0 
TOTAL EXPENSESTOTAL EXPENSES789.4 714.9 TOTAL EXPENSES792.6 741.6 2,304.2 2,102.7 
OPERATING INCOMEOPERATING INCOME198.3 192.4 OPERATING INCOME169.2 147.3 471.8 467.1 
Other Income (Expense):Other Income (Expense):  Other Income (Expense):    
Interest IncomeInterest Income0.6 0.1 Interest Income0.8 2.6 2.2 3.0 
Allowance for Equity Funds Used During ConstructionAllowance for Equity Funds Used During Construction2.4 2.0 Allowance for Equity Funds Used During Construction3.6 2.2 8.7 6.8 
Non-Service Cost Components of Net Periodic Benefit CostNon-Service Cost Components of Net Periodic Benefit Cost8.1 7.3 Non-Service Cost Components of Net Periodic Benefit Cost8.1 7.3 24.4 21.8 
Interest ExpenseInterest Expense(65.3)(54.3)Interest Expense(68.5)(61.7)(200.7)(171.1)
INCOME BEFORE INCOME TAX EXPENSEINCOME BEFORE INCOME TAX EXPENSE144.1 147.5 INCOME BEFORE INCOME TAX EXPENSE113.2 97.7 306.4 327.6 
Income Tax ExpenseIncome Tax Expense31.6 27.3 Income Tax Expense21.3 5.0 59.1 24.5 
NET INCOMENET INCOME$112.5 $120.2 NET INCOME$91.9 $92.7 $247.3 $303.1 
The common stock of APCo is wholly-owned by Parent.The common stock of APCo is wholly-owned by Parent.The common stock of APCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
7173



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
Three Months Ended September 30,Nine Months Ended September 30,
Three Months Ended March 31,
202320222023202220232022
Net IncomeNet Income$112.5 $120.2 Net Income$91.9 $92.7 $247.3 $303.1 
OTHER COMPREHENSIVE LOSS, NET OF TAXESOTHER COMPREHENSIVE LOSS, NET OF TAXES OTHER COMPREHENSIVE LOSS, NET OF TAXES  
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) in 2023 and 2022, Respectively(0.2)(0.2)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.2) and $(0.3) in 2023 and 2022, Respectively(0.8)(1.1)
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2023 and 2022, Respectively, and $(0.2) and $(0.2) for the Nine Months Ended September 30, 2023 and 2022, RespectivelyCash Flow Hedges, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2023 and 2022, Respectively, and $(0.2) and $(0.2) for the Nine Months Ended September 30, 2023 and 2022, Respectively(0.2)(0.2)(0.6)(0.6)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.2) and $(0.3) for the Three Months Ended September 30, 2023 and 2022, Respectively, and $(0.6) and $(0.9) for the Nine Months Ended September 30, 2023 and 2022, RespectivelyAmortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.2) and $(0.3) for the Three Months Ended September 30, 2023 and 2022, Respectively, and $(0.6) and $(0.9) for the Nine Months Ended September 30, 2023 and 2022, Respectively(0.7)(1.1)(2.3)(3.2)
TOTAL OTHER COMPREHENSIVE LOSSTOTAL OTHER COMPREHENSIVE LOSS(1.0)(1.3)TOTAL OTHER COMPREHENSIVE LOSS(0.9)(1.3)(2.9)(3.8)
TOTAL COMPREHENSIVE INCOMETOTAL COMPREHENSIVE INCOME$111.5 $118.9 TOTAL COMPREHENSIVE INCOME$91.0 $91.4 $244.4 $299.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
7274



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the ThreeNine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
Common
Stock
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
TotalCommon
Stock
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2021TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2021$260.4 $1,828.7 $2,534.4 $24.4 $4,647.9 TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2021$260.4 $1,828.7 $2,534.4 $24.4 $4,647.9 
Common Stock DividendsCommon Stock Dividends(18.8)(18.8)Common Stock Dividends(18.8)(18.8)
Net IncomeNet Income120.2 120.2 Net Income120.2 120.2 
Other Comprehensive LossOther Comprehensive Loss(1.3)(1.3)Other Comprehensive Loss(1.3)(1.3)
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2022TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2022$260.4 $1,828.7 $2,635.8 $23.1 $4,748.0 TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2022260.4 1,828.7 2,635.8 23.1 4,748.0 
Capital Contribution from ParentCapital Contribution from Parent2.8 2.8 
Common Stock DividendsCommon Stock Dividends (18.7) (18.7)
Net IncomeNet Income  90.2  90.2 
Other Comprehensive LossOther Comprehensive Loss   (1.2)(1.2)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2022TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2022260.4 1,831.5 2,707.3 21.9 4,821.1 
Capital Contribution from ParentCapital Contribution from Parent1.51.5 
Net IncomeNet Income92.7 92.7 
Other Comprehensive LossOther Comprehensive Loss(1.3)(1.3)
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2022TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2022$260.4 $1,833.0 $2,800.0 $20.6 $4,914.0 
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2022TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2022$260.4 $1,828.7 $2,891.1 $(4.8)$4,975.4 TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2022$260.4 $1,828.7 $2,891.1 $(4.8)$4,975.4 
Net IncomeNet Income112.5 112.5 Net Income112.5 112.5 
Other Comprehensive LossOther Comprehensive Loss(1.0)(1.0)Other Comprehensive Loss(1.0)(1.0)
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2023TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2023$260.4 $1,828.7 $3,003.6 $(5.8)$5,086.9 TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2023260.4 1,828.7 3,003.6 (5.8)5,086.9 
Capital Contribution from ParentCapital Contribution from Parent4.34.3 
Net IncomeNet Income42.9 42.9 
Other Comprehensive LossOther Comprehensive Loss(1.0)(1.0)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2023TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2023260.4 1,833.0 3,046.5 (6.8)5,133.1 
Capital Contribution from ParentCapital Contribution from Parent2.22.2 
Net IncomeNet Income91.9 91.9 
Other Comprehensive LossOther Comprehensive Loss(0.9)(0.9)
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2023TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2023$260.4 $1,835.2 $3,138.4 $(7.7)$5,226.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

7375



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31,September 30, 2023 and December 31, 2022
(in millions)
(Unaudited)
March 31,December 31,September 30,December 31,
2023202220232022
CURRENT ASSETSCURRENT ASSETS  CURRENT ASSETS  
Cash and Cash EquivalentsCash and Cash Equivalents$7.1 $7.5 Cash and Cash Equivalents$4.5 $7.5 
Restricted Cash for Securitized FundingRestricted Cash for Securitized Funding7.5 14.4 Restricted Cash for Securitized Funding6.9 14.4 
Advances to AffiliatesAdvances to Affiliates18.7 19.8 Advances to Affiliates19.3 19.8 
Accounts Receivable:Accounts Receivable:  Accounts Receivable:  
CustomersCustomers154.0 168.9 Customers142.9 168.9 
Affiliated CompaniesAffiliated Companies91.5 94.0 Affiliated Companies91.7 94.0 
Accrued Unbilled RevenuesAccrued Unbilled Revenues55.4 91.3 Accrued Unbilled Revenues41.9 91.3 
MiscellaneousMiscellaneous0.2 0.3 Miscellaneous0.2 0.3 
Allowance for Uncollectible AccountsAllowance for Uncollectible Accounts(2.0)(1.7)Allowance for Uncollectible Accounts(1.7)(1.7)
Total Accounts ReceivableTotal Accounts Receivable299.1 352.8 Total Accounts Receivable275.0 352.8 
FuelFuel220.5 158.9 Fuel266.5 158.9 
Materials and SuppliesMaterials and Supplies128.4 130.6 Materials and Supplies137.5 130.6 
Risk Management AssetsRisk Management Assets12.4 69.1 Risk Management Assets46.4 69.1 
Regulatory Asset for Under-Recovered Fuel CostsRegulatory Asset for Under-Recovered Fuel Costs574.5 473.1 Regulatory Asset for Under-Recovered Fuel Costs442.0 473.1 
Prepayments and Other Current AssetsPrepayments and Other Current Assets30.8 33.4 Prepayments and Other Current Assets33.7 33.4 
TOTAL CURRENT ASSETSTOTAL CURRENT ASSETS1,299.0 1,259.6 TOTAL CURRENT ASSETS1,231.8 1,259.6 
PROPERTY, PLANT AND EQUIPMENTPROPERTY, PLANT AND EQUIPMENT  PROPERTY, PLANT AND EQUIPMENT  
Electric:Electric:  Electric:  
GenerationGeneration6,886.9 6,776.8 Generation6,919.7 6,776.8 
TransmissionTransmission4,510.3 4,482.8 Transmission4,588.4 4,482.8 
DistributionDistribution4,992.6 4,933.0 Distribution5,126.8 4,933.0 
Other Property, Plant and EquipmentOther Property, Plant and Equipment890.3 883.3 Other Property, Plant and Equipment933.7 883.3 
Construction Work in ProgressConstruction Work in Progress689.4 705.3 Construction Work in Progress877.9 705.3 
Total Property, Plant and EquipmentTotal Property, Plant and Equipment17,969.5 17,781.2 Total Property, Plant and Equipment18,446.5 17,781.2 
Accumulated Depreciation and AmortizationAccumulated Depreciation and Amortization5,463.4 5,402.0 Accumulated Depreciation and Amortization5,621.4 5,402.0 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NETTOTAL PROPERTY, PLANT AND EQUIPMENT – NET12,506.1 12,379.2 TOTAL PROPERTY, PLANT AND EQUIPMENT – NET12,825.1 12,379.2 
OTHER NONCURRENT ASSETSOTHER NONCURRENT ASSETS  OTHER NONCURRENT ASSETS  
Regulatory AssetsRegulatory Assets920.4 1,058.6 Regulatory Assets978.8 1,058.6 
Securitized AssetsSecuritized Assets153.1 159.6 Securitized Assets140.0 159.6 
Employee Benefits and Pension AssetsEmployee Benefits and Pension Assets157.4 152.9 Employee Benefits and Pension Assets166.5 152.9 
Operating Lease AssetsOperating Lease Assets71.2 73.6 Operating Lease Assets64.9 73.6 
Deferred Charges and Other Noncurrent AssetsDeferred Charges and Other Noncurrent Assets149.2 138.7 Deferred Charges and Other Noncurrent Assets102.6 138.7 
TOTAL OTHER NONCURRENT ASSETSTOTAL OTHER NONCURRENT ASSETS1,451.3 1,583.4 TOTAL OTHER NONCURRENT ASSETS1,452.8 1,583.4 
TOTAL ASSETSTOTAL ASSETS$15,256.4 $15,222.2 TOTAL ASSETS$15,509.7 $15,222.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
7476



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
March 31,September 30, 2023 and December 31, 2022
(Unaudited)
March 31,December 31, September 30,December 31,
20232022 20232022
(in millions) (in millions)
CURRENT LIABILITIESCURRENT LIABILITIES  CURRENT LIABILITIES  
Advances from AffiliatesAdvances from Affiliates$310.2 $182.2 Advances from Affiliates$202.5 $182.2 
Accounts Payable:Accounts Payable:  Accounts Payable:  
GeneralGeneral297.6 451.2 General321.8 451.2 
Affiliated CompaniesAffiliated Companies101.0 142.7 Affiliated Companies116.6 142.7 
Long-term Debt Due Within One Year – NonaffiliatedLong-term Debt Due Within One Year – Nonaffiliated252.3 251.8 Long-term Debt Due Within One Year – Nonaffiliated538.8 251.8 
Risk Management LiabilitiesRisk Management Liabilities7.0 3.6 Risk Management Liabilities1.8 3.6 
Customer DepositsCustomer Deposits74.2 75.1 Customer Deposits77.6 75.1 
Accrued TaxesAccrued Taxes112.3 101.0 Accrued Taxes82.4 101.0 
Accrued InterestAccrued Interest83.2 57.9 Accrued Interest85.5 57.9 
Obligations Under Operating LeasesObligations Under Operating Leases14.8 15.0 Obligations Under Operating Leases14.0 15.0 
Other Current LiabilitiesOther Current Liabilities97.5 109.7 Other Current Liabilities103.3 109.7 
TOTAL CURRENT LIABILITIESTOTAL CURRENT LIABILITIES1,350.1 1,390.2 TOTAL CURRENT LIABILITIES1,544.3 1,390.2 
NONCURRENT LIABILITIESNONCURRENT LIABILITIES  NONCURRENT LIABILITIES  
Long-term Debt – NonaffiliatedLong-term Debt – Nonaffiliated5,146.4 5,158.7 Long-term Debt – Nonaffiliated5,048.5 5,158.7 
Deferred Income TaxesDeferred Income Taxes2,006.8 1,992.2 Deferred Income Taxes2,029.6 1,992.2 
Regulatory Liabilities and Deferred Investment Tax CreditsRegulatory Liabilities and Deferred Investment Tax Credits1,109.5 1,143.6 Regulatory Liabilities and Deferred Investment Tax Credits1,100.5 1,143.6 
Asset Retirement ObligationsAsset Retirement Obligations422.5 419.2 Asset Retirement Obligations423.3 419.2 
Employee Benefits and Pension ObligationsEmployee Benefits and Pension Obligations33.1 34.2 Employee Benefits and Pension Obligations34.1 34.2 
Obligations Under Operating LeasesObligations Under Operating Leases56.9 59.1 Obligations Under Operating Leases51.4 59.1 
Deferred Credits and Other Noncurrent LiabilitiesDeferred Credits and Other Noncurrent Liabilities44.2 49.6 Deferred Credits and Other Noncurrent Liabilities51.7 49.6 
TOTAL NONCURRENT LIABILITIESTOTAL NONCURRENT LIABILITIES8,819.4 8,856.6 TOTAL NONCURRENT LIABILITIES8,739.1 8,856.6 
TOTAL LIABILITIESTOTAL LIABILITIES10,169.5 10,246.8 TOTAL LIABILITIES10,283.4 10,246.8 
Rate Matters (Note 4)Rate Matters (Note 4)Rate Matters (Note 4)
Commitments and Contingencies (Note 5)Commitments and Contingencies (Note 5)Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITYCOMMON SHAREHOLDER’S EQUITY  COMMON SHAREHOLDER’S EQUITY  
Common Stock – No Par Value:Common Stock – No Par Value:  Common Stock – No Par Value:  
Authorized – 30,000,000 SharesAuthorized – 30,000,000 Shares  Authorized – 30,000,000 Shares  
Outstanding – 13,499,500 Shares Outstanding – 13,499,500 Shares260.4 260.4  Outstanding – 13,499,500 Shares260.4 260.4 
Paid-in CapitalPaid-in Capital1,828.7 1,828.7 Paid-in Capital1,835.2 1,828.7 
Retained EarningsRetained Earnings3,003.6 2,891.1 Retained Earnings3,138.4 2,891.1 
Accumulated Other Comprehensive Income (Loss)Accumulated Other Comprehensive Income (Loss)(5.8)(4.8)Accumulated Other Comprehensive Income (Loss)(7.7)(4.8)
TOTAL COMMON SHAREHOLDER’S EQUITYTOTAL COMMON SHAREHOLDER’S EQUITY5,086.9 4,975.4 TOTAL COMMON SHAREHOLDER’S EQUITY5,226.3 4,975.4 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITYTOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$15,256.4 $15,222.2 TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$15,509.7 $15,222.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
7577



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the ThreeNine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
Three Months Ended March 31, Nine Months Ended September 30,
20232022 20232022
OPERATING ACTIVITIESOPERATING ACTIVITIES  OPERATING ACTIVITIES  
Net IncomeNet Income$112.5 $120.2 Net Income$247.3 $303.1 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and AmortizationDepreciation and Amortization143.0 145.2 Depreciation and Amortization424.8 431.0 
Deferred Income TaxesDeferred Income Taxes10.3 4.1 Deferred Income Taxes5.2 70.7 
Asset Impairments and Other Related Charges - Coal Fired GenerationAsset Impairments and Other Related Charges - Coal Fired Generation— 24.9 
Allowance for Equity Funds Used During ConstructionAllowance for Equity Funds Used During Construction(2.4)(2.0)Allowance for Equity Funds Used During Construction(8.7)(6.8)
Mark-to-Market of Risk Management ContractsMark-to-Market of Risk Management Contracts60.1 34.3 Mark-to-Market of Risk Management Contracts21.7 (65.6)
Deferred Fuel Over/Under-Recovery, NetDeferred Fuel Over/Under-Recovery, Net26.0 (100.3)Deferred Fuel Over/Under-Recovery, Net108.2 (400.2)
Establishment of 2017-2019 Virginia Triennial Review Regulatory AssetEstablishment of 2017-2019 Virginia Triennial Review Regulatory Asset— (37.0)
Change in Other Noncurrent AssetsChange in Other Noncurrent Assets(5.5)1.4 Change in Other Noncurrent Assets24.4 (15.2)
Change in Other Noncurrent LiabilitiesChange in Other Noncurrent Liabilities(33.0)(20.4)Change in Other Noncurrent Liabilities(29.9)39.7 
Changes in Certain Components of Working Capital:Changes in Certain Components of Working Capital:  Changes in Certain Components of Working Capital:  
Accounts Receivable, NetAccounts Receivable, Net54.5 72.4 Accounts Receivable, Net80.2 68.7 
Fuel, Materials and SuppliesFuel, Materials and Supplies(59.3)19.5 Fuel, Materials and Supplies(114.0)(61.7)
Margin DepositsMargin Deposits(11.1)61.4 Margin Deposits(3.0)65.8 
Accounts PayableAccounts Payable(156.1)33.6 Accounts Payable(129.5)141.4 
Accrued Taxes, NetAccrued Taxes, Net23.6 26.1 Accrued Taxes, Net(12.4)(98.9)
Other Current AssetsOther Current Assets2.9 2.3 Other Current Assets(3.5)(4.2)
Other Current LiabilitiesOther Current Liabilities(1.2)18.3 Other Current Liabilities(0.6)42.2 
Net Cash Flows from Operating ActivitiesNet Cash Flows from Operating Activities164.3 416.1 Net Cash Flows from Operating Activities610.2 497.9 
INVESTING ACTIVITIESINVESTING ACTIVITIES  INVESTING ACTIVITIES  
Construction ExpendituresConstruction Expenditures(287.4)(233.9)Construction Expenditures(813.4)(707.4)
Change in Advances to Affiliates, NetChange in Advances to Affiliates, Net1.1 1.1 Change in Advances to Affiliates, Net0.5 (161.3)
Other Investing ActivitiesOther Investing Activities1.5 9.7 Other Investing Activities(2.9)34.9 
Net Cash Flows Used for Investing ActivitiesNet Cash Flows Used for Investing Activities(284.8)(223.1)Net Cash Flows Used for Investing Activities(815.8)(833.8)
FINANCING ACTIVITIESFINANCING ACTIVITIES  FINANCING ACTIVITIES  
Capital Contribution from ParentCapital Contribution from Parent6.5 4.3 
Issuance of Long-term Debt – NonaffiliatedIssuance of Long-term Debt – Nonaffiliated200.0 698.2 
Change in Advances from Affiliates, NetChange in Advances from Affiliates, Net128.0 (163.8)Change in Advances from Affiliates, Net20.3 (199.3)
Retirement of Long-term Debt – NonaffiliatedRetirement of Long-term Debt – Nonaffiliated(13.0)(12.7)Retirement of Long-term Debt – Nonaffiliated(26.5)(130.4)
Principal Payments for Finance Lease ObligationsPrincipal Payments for Finance Lease Obligations(2.0)(2.0)Principal Payments for Finance Lease Obligations(6.2)(5.9)
Dividends Paid on Common StockDividends Paid on Common Stock— (18.8)Dividends Paid on Common Stock— (37.5)
Other Financing ActivitiesOther Financing Activities0.2 0.2 Other Financing Activities1.0 0.5 
Net Cash Flows from (Used for) Financing Activities113.2 (197.1)
Net Cash Flows from Financing ActivitiesNet Cash Flows from Financing Activities195.1 329.9 
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized FundingNet Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding(7.3)(4.1)Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding(10.5)(6.0)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of PeriodCash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period21.9 20.1 Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period21.9 20.1 
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of PeriodCash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period$14.6 $16.0 Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period$11.4 $14.1 
SUPPLEMENTARY INFORMATIONSUPPLEMENTARY INFORMATION  SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized AmountsCash Paid for Interest, Net of Capitalized Amounts$37.9 $21.0 Cash Paid for Interest, Net of Capitalized Amounts$166.6 $128.3 
Net Cash Paid for Income TaxesNet Cash Paid for Income Taxes40.3 14.2 
Noncash Acquisitions Under Finance LeasesNoncash Acquisitions Under Finance Leases0.6 0.3 Noncash Acquisitions Under Finance Leases4.1 1.0 
Construction Expenditures Included in Current Liabilities as of March 31,122.6 94.9 
Construction Expenditures Included in Current Liabilities as of September 30,Construction Expenditures Included in Current Liabilities as of September 30,138.7 160.4 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
7678





INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
77



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
Three Months EndedNine Months Ended
Three Months Ended March 31, September 30,September 30,
20232022 2023202220232022
(in millions of KWhs) (in millions of KWhs)
Retail:Retail:  Retail:    
ResidentialResidential1,463 1,539 Residential1,421 1,532 3,998 4,320 
CommercialCommercial1,189 1,119 Commercial1,360 1,326 3,756 3,610 
IndustrialIndustrial1,804 1,790 Industrial1,876 1,926 5,501 5,638 
MiscellaneousMiscellaneous16 16 Miscellaneous12 12 39 39 
Total RetailTotal Retail4,472 4,464 Total Retail4,669 4,796 13,294 13,607 
WholesaleWholesale1,417 1,957 Wholesale1,246 1,707 4,210 4,892 
Total KWhsTotal KWhs5,889 6,421 Total KWhs5,915 6,503 17,504 18,499 

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

Summary of Heating and Cooling Degree Days
Three Months EndedNine Months Ended
Three Months Ended March 31, September 30,September 30,
20232022 2023202220232022
(in degree days) (in degree days)
Actual – Heating (a)Actual – Heating (a)1,687 2,240 Actual – Heating (a)— 17 1,914 2,525 
Normal – Heating (b)Normal – Heating (b)2,182 2,171 Normal – Heating (b)2,430 2,421 
Actual – Cooling (c)Actual – Cooling (c)— — Actual – Cooling (c)516 590 722 934 
Normal – Cooling (b)Normal – Cooling (b)Normal – Cooling (b)588 580 857 842 

(a)Heating degree days are calculated on a 55 degree temperature base.
(b)Normal Heating/Cooling represents the thirty-year average of degree days.
(c)Cooling degree days are calculated on a 65 degree temperature base.
7879


Indiana Michigan Power Company and Subsidiaries
Reconciliation of 2022 to 2023 Net Income
(in millions)
Three Months Ended 
September 30,
Nine Months Ended 
September 30,
2022 Net Income$94.1 $250.8 
  
Changes in Gross Margin: 
Retail Margins5.4 55.6 
Margins from Off-system Sales(14.7)8.9 
Transmission Revenues(1.3)(13.9)
Other Revenues3.7 6.5 
Total Change in Gross Margin(6.9)57.1 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(7.9)(63.1)
Depreciation and Amortization14.9 47.3 
Taxes Other Than Income Taxes0.1 13.8 
Other Income2.1 0.7 
Non-Service Cost Components of Net Periodic Benefit Cost1.4 4.6 
Interest Expense(1.8)(9.5)
Total Change in Expenses and Other8.8 (6.2)
  
Income Tax Expense(3.0)(31.1)
  
2023 Net Income$93.0 $270.6 

FirstThird Quarter of 2023 Compared to FirstThird Quarter of 2022
Indiana Michigan Power Company and Subsidiaries
Reconciliation of First Quarter
The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:

Retail Margins increased $5 million primarily due to the following:
A $14 million increase in weather-normalized retail margins in the commercial and industrial classes.
An $8 million increase due to rider revenues. This increase was partially offset in other expense items below.
These increases were partially offset by:
A $10 million decrease in deferred fuel primarily due to the timing of recoverable PJM expenses. This decrease was offset in other expense items below.
A $7 million decrease in weather-related usage primarily due to a 13% decrease in cooling degree days.
Margins from Off-system Sales decreased $15 million primarily due to Rockport Plant, Unit 2 merchant operations activity.

Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses increased $8 million primarily due to the following:
A $12 million increase in Demand Side Management expenses. This increase was offset in Retail Margins above.
This increase was partially offset by:
A $4 million decrease in employee-related expenses.
80


Depreciation and Amortization expensesdecreased $15 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.

Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022 to First Quarter of 2023
Net Income
(in millions)
First Quarter of 2022$89.5 
Changes in Gross Margin:
Retail Margins40.3 
Margins from Off-system Sales14.8 
Transmission Revenues(3.6)
Other Revenues4.8 
Total Change in Gross Margin56.3 
Changes in Expenses and Other:
Other Operation and Maintenance(38.0)
Depreciation and Amortization9.7 
Taxes Other Than Income Taxes5.7 
Other Income(2.0)
Non-Service Cost Components of Net Periodic Benefit Cost1.7 
Interest Expense(2.9)
Total Change in Expenses and Other(25.8)
Income Tax Expense(17.2)
First Quarter of 2023$102.8 

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

Retail Margins increased $40$56 million primarily due to the following:
A $25$39 million increase in weather-normalized margins in all retail margins primarilyclasses, partially offset by a decrease in the residential and commercial classes.wholesale class.
An $18A $25 million increase due to a base rate revenue increase in Indiana and rider increases. This increase was partially offset in other expense items below.
A $9$21 million increase due to a reduction in a provision for refund.refund, partially offset by lower wholesale true-ups.
These increases were partially offset by:
An $18A $39 million decrease in weather-related usage primarily due to a 25%23% decrease in cooling degree days and a 24% decrease in heating degree days.
Margins from Off-system Sales increased $15$9 million primarily due to Rockport Plant, Unit 2 merchant operations activity and estimated PJM performance incentives for Rockport Plant, Unit 2 merchant operations related to winter storm Elliott in December 2022.
Transmission Revenues decreased $4$14 million primarily due to lower PJM rates for certain point-to-point transmission service resulting from a December 2022 FERC approved settlement agreement.formula rate true-up activity.
Other Revenuesincreased $5$7 million primarily due to an $8 million increase in barging revenues by River Transportation Division (RTD), partially offset by a $4 million decrease in the sale of allowances. The. This increase in RTD barging revenues was partially offset in Other Operation and Maintenance expenses below and the decrease due to the sale of allowances was partially offset in Retail Margins above.below.


79



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

Other Operation and Maintenance expenses increased $38$63 million primarily due to the following:
A $29 million increase in Demand Side Management expenses. This increase was offset in Retail Margins above.
A $10 million increase in Non-Utility operation expenses due to an increase in RTD expenses and merchant operation expenses. The RTD expenses are offset in Other Revenues above.
A $10 million increase in nuclear expenses at Cook Plant primarily due to refueling outage expenses.
A $10 million increase in transmission expenses primarily due to a $7 million increase in transmission formula rate true-up activity and a $3 million increase in recoverable PJM expenses. The recoverable PJM expenses were offset in Gross Margin above.
A $9 million increase due to a decreased Nuclear Electric Insurance Limited distribution in 2023.
A $9 million increase in Demand Side Management Rider expenses primarily due to an increase in revenues collected from customers. This increase wasThese increases were partially offset in Retail Margins above.by:
An $8$11 million increasedecrease in nuclear expenses at Cook Plant primarily due to refueling outageemployee-related expenses.
An $8 million increase in nonutility operation expense primarily due to an increase in RTD expenses. This increase was offset in Other Revenues above.
Depreciation and Amortization expenses decreased $10$47 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.lease and an increase in depreciable base.
Taxes Other Than Income Taxes decreased $6$14 million primarily due to the repeal of the Indiana Utility Receipts Tax in July 2022. This decrease was partially offset in Retail Margins above.
Income TaxInterest Expense increased $17$10 million primarily due to higher long-term debt balances and interest rates.
Income Tax Expense increased $31 million primarily due to the following:
A $6$17 million increase due to higher pretax book income.
A $6 milliona decrease in amortization of Excess ADIT.
An $11 million increase due to an increase in pretax book income.
A $3$4 million increase due to an increase in state taxes.

8081




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
Three Months Ended March 31, Three Months EndedNine Months Ended
September 30,September 30,
20232022 2023202220232022
REVENUESREVENUES  REVENUES    
Electric Generation, Transmission and DistributionElectric Generation, Transmission and Distribution$642.8 $612.0 Electric Generation, Transmission and Distribution$656.1 $695.7 $1,879.3 $1,912.1 
Sales to AEP AffiliatesSales to AEP Affiliates1.2 2.0 Sales to AEP Affiliates0.6 2.0 3.7 11.1 
Other Revenues – AffiliatedOther Revenues – Affiliated15.9 8.4 Other Revenues – Affiliated15.4 13.3 45.8 38.4 
Other Revenues – NonaffiliatedOther Revenues – Nonaffiliated3.1 2.8 Other Revenues – Nonaffiliated4.2 4.4 9.7 10.0 
TOTAL REVENUESTOTAL REVENUES663.0 625.2 TOTAL REVENUES676.3 715.4 1,938.5 1,971.6 
EXPENSESEXPENSES  EXPENSES    
Purchased Electricity, Fuel and Other Consumables Used for Electric GenerationPurchased Electricity, Fuel and Other Consumables Used for Electric Generation99.2 105.7 Purchased Electricity, Fuel and Other Consumables Used for Electric Generation129.3 150.6 322.4 367.2 
Purchased Electricity from AEP AffiliatesPurchased Electricity from AEP Affiliates45.1 57.1 Purchased Electricity from AEP Affiliates57.0 67.9 139.2 184.6 
Other OperationOther Operation169.7 139.3 Other Operation168.9 162.4 508.7 450.9 
MaintenanceMaintenance58.6 51.0 Maintenance57.3 55.9 173.0 167.7 
Depreciation and AmortizationDepreciation and Amortization125.2 134.9 Depreciation and Amortization116.7 131.6 352.9 400.2 
Taxes Other Than Income TaxesTaxes Other Than Income Taxes19.5 25.2 Taxes Other Than Income Taxes22.3 22.4 62.4 76.2 
TOTAL EXPENSESTOTAL EXPENSES517.3 513.2 TOTAL EXPENSES551.5 590.8 1,558.6 1,646.8 
OPERATING INCOMEOPERATING INCOME145.7 112.0 OPERATING INCOME124.8 124.6 379.9 324.8 
Other Income (Expense):Other Income (Expense):  Other Income (Expense):    
Other IncomeOther Income0.6 2.6 Other Income4.5 2.4 8.1 7.4 
Non-Service Cost Components of Net Periodic Benefit CostNon-Service Cost Components of Net Periodic Benefit Cost8.0 6.3 Non-Service Cost Components of Net Periodic Benefit Cost7.7 6.3 23.4 18.8 
Interest ExpenseInterest Expense(33.2)(30.3)Interest Expense(33.0)(31.2)(102.0)(92.5)
INCOME BEFORE INCOME TAX EXPENSEINCOME BEFORE INCOME TAX EXPENSE121.1 90.6 INCOME BEFORE INCOME TAX EXPENSE104.0 102.1 309.4 258.5 
Income Tax ExpenseIncome Tax Expense18.3 1.1 Income Tax Expense11.0 8.0 38.8 7.7 
NET INCOMENET INCOME$102.8 $89.5 NET INCOME$93.0 $94.1 $270.6 $250.8 
The common stock of I&M is wholly-owned by Parent.The common stock of I&M is wholly-owned by Parent.The common stock of I&M is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
8182



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
Three Months EndedNine Months Ended
Three Months Ended March 31, September 30,September 30,
202320222023202220232022
Net IncomeNet Income$102.8 $89.5 Net Income$93.0 $94.1 $270.6 $250.8 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXESOTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES   
Cash Flow Hedges, Net of Tax of $(0.2) and $0.1 for 2023 and 2022, Respectively(0.7)0.4 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.5) and $0 for 2023 and 2022, Respectively(1.9)(0.1)
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended September 30, 2023 and 2022, Respectively, and $(0.1) and $0.3 for the Nine Months Ended September 30, 2023 and 2022, RespectivelyCash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended September 30, 2023 and 2022, Respectively, and $(0.1) and $0.3 for the Nine Months Ended September 30, 2023 and 2022, Respectively0.1 0.4 (0.5)1.2 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $(0.1) for the Three Months Ended September 30, 2023 and 2022, Respectively, and $(0.6) and $(0.1) for the Nine Months Ended September 30, 2023 and 2022, RespectivelyAmortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $(0.1) for the Three Months Ended September 30, 2023 and 2022, Respectively, and $(0.6) and $(0.1) for the Nine Months Ended September 30, 2023 and 2022, Respectively(0.2)(0.1)(2.4)(0.3)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)TOTAL OTHER COMPREHENSIVE INCOME (LOSS)(2.6)0.3 TOTAL OTHER COMPREHENSIVE INCOME (LOSS)(0.1)0.3 (2.9)0.9 
TOTAL COMPREHENSIVE INCOMETOTAL COMPREHENSIVE INCOME$100.2 $89.8 TOTAL COMPREHENSIVE INCOME$92.9 $94.4 $267.7 $251.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
8283



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the ThreeNine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
Common
Stock
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
TotalCommon
Stock
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2021TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2021$56.6 $980.9 $1,748.5 $(1.3)$2,784.7 TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2021$56.6 $980.9 $1,748.5 $(1.3)$2,784.7 
Common Stock DividendsCommon Stock Dividends  (25.0) (25.0)Common Stock Dividends  (25.0) (25.0)
Net IncomeNet Income  89.5  89.5 Net Income  89.5  89.5 
Other Comprehensive IncomeOther Comprehensive Income   0.3 0.3 Other Comprehensive Income   0.3 0.3 
TOTAL COMMON SHAREHOLDER'S EQUITY -MARCH 31, 2022TOTAL COMMON SHAREHOLDER'S EQUITY -MARCH 31, 2022$56.6 $980.9 $1,813.0 $(1.0)$2,849.5 TOTAL COMMON SHAREHOLDER'S EQUITY -MARCH 31, 202256.6 980.9 1,813.0 (1.0)2,849.5 
Capital Contribution from ParentCapital Contribution from Parent1.3 1.3 
Common Stock DividendsCommon Stock Dividends(25.0)(25.0)
Net IncomeNet Income67.2 67.2 
Other Comprehensive IncomeOther Comprehensive Income0.3 0.3 
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2022TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 202256.6 982.2 1,855.2 (0.7)2,893.3 
Capital Contribution from ParentCapital Contribution from Parent0.6 0.6 
Common Stock DividendsCommon Stock Dividends(20.0)(20.0)
Net IncomeNet Income94.1 94.1 
Other Comprehensive IncomeOther Comprehensive Income0.3 0.3 
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2022TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2022$56.6 $982.8 $1,929.3 $(0.4)$2,968.3 
          
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2022TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2022$56.6 $988.8 $1,963.2 $(0.3)$3,008.3 TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2022$56.6 $988.8 $1,963.2 $(0.3)$3,008.3 
Common Stock DividendsCommon Stock Dividends(31.2)(31.2)Common Stock Dividends(31.2)(31.2)
Net IncomeNet Income102.8 102.8 Net Income102.8 102.8 
Other Comprehensive LossOther Comprehensive Loss(2.6)(2.6)Other Comprehensive Loss(2.6)(2.6)
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2023TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2023$56.6 $988.8 $2,034.8 $(2.9)$3,077.3 TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 202356.6 988.8 2,034.8 (2.9)3,077.3 
Capital Contribution from ParentCapital Contribution from Parent0.1 0.1 
Common Stock DividendsCommon Stock Dividends  (31.3) (31.3)
Net IncomeNet Income  74.8  74.8 
Other Comprehensive LossOther Comprehensive Loss   (0.2)(0.2)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2023TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 202356.6 988.9 2,078.3 (3.1)3,120.7 
Capital Contribution from ParentCapital Contribution from Parent1.6 1.6 
Common Stock DividendsCommon Stock Dividends(75.0)(75.0)
Net IncomeNet Income93.0 93.0 
Other Comprehensive LossOther Comprehensive Loss(0.1)(0.1)
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2023TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2023$56.6 $990.5 $2,096.3 $(3.2)$3,140.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
8384



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31,September 30, 2023 and December 31, 2022
(in millions)
(Unaudited)
March 31,December 31,September 30,December 31,
20232022 20232022
CURRENT ASSETSCURRENT ASSETS  CURRENT ASSETS  
Cash and Cash EquivalentsCash and Cash Equivalents$8.5 $4.2 Cash and Cash Equivalents$2.7 $4.2 
Advances to AffiliatesAdvances to Affiliates60.0 23.0 Advances to Affiliates21.2 23.0 
Accounts Receivable:Accounts Receivable:  Accounts Receivable:  
CustomersCustomers62.4 96.6 Customers46.2 96.6 
Affiliated CompaniesAffiliated Companies86.6 104.0 Affiliated Companies69.4 104.0 
Accrued Unbilled RevenuesAccrued Unbilled Revenues— 0.6 Accrued Unbilled Revenues3.9 0.6 
MiscellaneousMiscellaneous4.6 4.7 Miscellaneous5.3 4.7 
Allowance for Uncollectible AccountsAllowance for Uncollectible Accounts— (0.1)Allowance for Uncollectible Accounts— (0.1)
Total Accounts ReceivableTotal Accounts Receivable153.6 205.8 Total Accounts Receivable124.8 205.8 
FuelFuel66.5 46.5 Fuel78.6 46.5 
Materials and SuppliesMaterials and Supplies192.2 188.1 Materials and Supplies198.7 188.1 
Risk Management AssetsRisk Management Assets5.9 15.2 Risk Management Assets15.8 15.2 
Regulatory Asset for Under-Recovered Fuel CostsRegulatory Asset for Under-Recovered Fuel Costs43.3 47.1 Regulatory Asset for Under-Recovered Fuel Costs13.3 47.1 
Prepayments and Other Current AssetsPrepayments and Other Current Assets41.4 41.9 Prepayments and Other Current Assets43.9 41.9 
TOTAL CURRENT ASSETSTOTAL CURRENT ASSETS571.4 571.8 TOTAL CURRENT ASSETS499.0 571.8 
PROPERTY, PLANT AND EQUIPMENTPROPERTY, PLANT AND EQUIPMENT  PROPERTY, PLANT AND EQUIPMENT  
Electric:Electric:  Electric:  
GenerationGeneration5,590.1 5,585.1 Generation5,608.1 5,585.1 
TransmissionTransmission1,861.0 1,842.2 Transmission1,881.2 1,842.2 
DistributionDistribution3,054.8 3,024.7 Distribution3,171.8 3,024.7 
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)813.6 839.3 Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)834.3 839.3 
Construction Work in ProgressConstruction Work in Progress288.2 253.0 Construction Work in Progress353.2 253.0 
Total Property, Plant and EquipmentTotal Property, Plant and Equipment11,607.7 11,544.3 Total Property, Plant and Equipment11,848.6 11,544.3 
Accumulated Depreciation, Depletion and AmortizationAccumulated Depreciation, Depletion and Amortization4,190.8 4,132.8 Accumulated Depreciation, Depletion and Amortization4,312.9 4,132.8 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NETTOTAL PROPERTY, PLANT AND EQUIPMENT – NET7,416.9 7,411.5 TOTAL PROPERTY, PLANT AND EQUIPMENT – NET7,535.7 7,411.5 
OTHER NONCURRENT ASSETSOTHER NONCURRENT ASSETS  OTHER NONCURRENT ASSETS  
Regulatory AssetsRegulatory Assets420.8 459.6 Regulatory Assets377.7 459.6 
Spent Nuclear Fuel and Decommissioning TrustsSpent Nuclear Fuel and Decommissioning Trusts3,501.1 3,341.2 Spent Nuclear Fuel and Decommissioning Trusts3,539.7 3,341.2 
Operating Lease AssetsOperating Lease Assets60.9 64.3 Operating Lease Assets56.7 64.3 
Deferred Charges and Other Noncurrent AssetsDeferred Charges and Other Noncurrent Assets271.2 270.5 Deferred Charges and Other Noncurrent Assets257.7 270.5 
TOTAL OTHER NONCURRENT ASSETSTOTAL OTHER NONCURRENT ASSETS4,254.0 4,135.6 TOTAL OTHER NONCURRENT ASSETS4,231.8 4,135.6 
TOTAL ASSETSTOTAL ASSETS$12,242.3 $12,118.9 TOTAL ASSETS$12,266.5 $12,118.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
8485



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
March 31,September 30, 2023 and December 31, 2022
(dollars in millions)
(Unaudited)
March 31,December 31, September 30,December 31,
20232022 20232022
CURRENT LIABILITIESCURRENT LIABILITIES  CURRENT LIABILITIES  
Advances from AffiliatesAdvances from Affiliates$— $249.9 Advances from Affiliates$— $249.9 
Accounts Payable:Accounts Payable:  Accounts Payable:  
GeneralGeneral165.4 173.4 General177.6 173.4 
Affiliated CompaniesAffiliated Companies91.8 121.5 Affiliated Companies89.0 121.5 
Long-term Debt Due Within One Year – Nonaffiliated
(March 31, 2023 and December 31, 2022 Amounts Include $83.8 and $89.6,
Respectively, Related to DCC Fuel)
86.0 341.8 
Long-term Debt Due Within One Year – Nonaffiliated
(September 30, 2023 and December 31, 2022 Amounts Include $59.5 and $89.6,
Respectively, Related to DCC Fuel)
Long-term Debt Due Within One Year – Nonaffiliated
(September 30, 2023 and December 31, 2022 Amounts Include $59.5 and $89.6,
Respectively, Related to DCC Fuel)
61.8 341.8 
Customer DepositsCustomer Deposits46.3 48.6 Customer Deposits54.6 48.6 
Accrued TaxesAccrued Taxes124.3 103.2 Accrued Taxes77.9 103.2 
Accrued InterestAccrued Interest24.8 36.9 Accrued Interest38.7 36.9 
Obligations Under Operating LeasesObligations Under Operating Leases16.7 16.0 Obligations Under Operating Leases16.8 16.0 
Regulatory Liability for Over-Recovered Fuel CostsRegulatory Liability for Over-Recovered Fuel Costs19.1 — 
Other Current LiabilitiesOther Current Liabilities79.5 105.8 Other Current Liabilities88.5 105.8 
TOTAL CURRENT LIABILITIESTOTAL CURRENT LIABILITIES634.8 1,197.1 TOTAL CURRENT LIABILITIES624.0 1,197.1 
NONCURRENT LIABILITIESNONCURRENT LIABILITIES  NONCURRENT LIABILITIES  
Long-term Debt – NonaffiliatedLong-term Debt – Nonaffiliated3,403.0 2,919.0 Long-term Debt – Nonaffiliated3,381.8 2,919.0 
Deferred Income TaxesDeferred Income Taxes1,162.5 1,157.0 Deferred Income Taxes1,192.7 1,157.0 
Regulatory Liabilities and Deferred Investment Tax CreditsRegulatory Liabilities and Deferred Investment Tax Credits1,824.0 1,702.2 Regulatory Liabilities and Deferred Investment Tax Credits1,758.1 1,702.2 
Asset Retirement ObligationsAsset Retirement Obligations2,046.2 2,027.6 Asset Retirement Obligations2,083.6 2,027.6 
Obligations Under Operating LeasesObligations Under Operating Leases45.2 48.9 Obligations Under Operating Leases40.5 48.9 
Deferred Credits and Other Noncurrent LiabilitiesDeferred Credits and Other Noncurrent Liabilities49.3 58.8 Deferred Credits and Other Noncurrent Liabilities45.6 58.8 
TOTAL NONCURRENT LIABILITIESTOTAL NONCURRENT LIABILITIES8,530.2 7,913.5 TOTAL NONCURRENT LIABILITIES8,502.3 7,913.5 
TOTAL LIABILITIESTOTAL LIABILITIES9,165.0 9,110.6 TOTAL LIABILITIES9,126.3 9,110.6 
Rate Matters (Note 4)Rate Matters (Note 4)Rate Matters (Note 4)
Commitments and Contingencies (Note 5)Commitments and Contingencies (Note 5)Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITYCOMMON SHAREHOLDER’S EQUITY  COMMON SHAREHOLDER’S EQUITY  
Common Stock – No Par Value:Common Stock – No Par Value:  Common Stock – No Par Value:  
Authorized – 2,500,000 SharesAuthorized – 2,500,000 Shares  Authorized – 2,500,000 Shares  
Outstanding – 1,400,000 SharesOutstanding – 1,400,000 Shares56.6 56.6 Outstanding – 1,400,000 Shares56.6 56.6 
Paid-in CapitalPaid-in Capital988.8 988.8 Paid-in Capital990.5 988.8 
Retained EarningsRetained Earnings2,034.8 1,963.2 Retained Earnings2,096.3 1,963.2 
Accumulated Other Comprehensive Income (Loss)Accumulated Other Comprehensive Income (Loss)(2.9)(0.3)Accumulated Other Comprehensive Income (Loss)(3.2)(0.3)
TOTAL COMMON SHAREHOLDER’S EQUITYTOTAL COMMON SHAREHOLDER’S EQUITY3,077.3 3,008.3 TOTAL COMMON SHAREHOLDER’S EQUITY3,140.2 3,008.3 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITYTOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$12,242.3 $12,118.9 TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$12,266.5 $12,118.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
8586



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the ThreeNine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
Three Months Ended March 31, Nine Months Ended September 30,
20232022 20232022
OPERATING ACTIVITIESOPERATING ACTIVITIES  OPERATING ACTIVITIES  
Net IncomeNet Income$102.8 $89.5 Net Income$270.6 $250.8 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: 
Depreciation and AmortizationDepreciation and Amortization125.2 134.9 Depreciation and Amortization352.9 400.2 
Deferred Income TaxesDeferred Income Taxes(3.3)(11.5)Deferred Income Taxes(16.4)(15.8)
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, NetAmortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net18.1 (6.5)Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net44.3 (35.2)
Allowance for Equity Funds Used During ConstructionAllowance for Equity Funds Used During Construction(0.5)(2.9)Allowance for Equity Funds Used During Construction(6.6)(7.9)
Mark-to-Market of Risk Management ContractsMark-to-Market of Risk Management Contracts8.8 (2.8)Mark-to-Market of Risk Management Contracts(4.7)(13.2)
Amortization of Nuclear FuelAmortization of Nuclear Fuel25.0 22.9 Amortization of Nuclear Fuel75.7 63.1 
Deferred Fuel Over/Under-Recovery, NetDeferred Fuel Over/Under-Recovery, Net3.8 6.1 Deferred Fuel Over/Under-Recovery, Net52.9 (20.5)
Change in Other Noncurrent AssetsChange in Other Noncurrent Assets(4.3)(5.2)Change in Other Noncurrent Assets3.1 12.5 
Change in Other Noncurrent LiabilitiesChange in Other Noncurrent Liabilities3.7 2.4 Change in Other Noncurrent Liabilities9.0 42.1 
Changes in Certain Components of Working Capital:Changes in Certain Components of Working Capital:  Changes in Certain Components of Working Capital:  
Accounts Receivable, NetAccounts Receivable, Net52.7 25.9 Accounts Receivable, Net82.5 5.3 
Fuel, Materials and SuppliesFuel, Materials and Supplies(24.1)6.3 Fuel, Materials and Supplies(42.7)3.1 
Accounts PayableAccounts Payable(27.8)3.8 Accounts Payable(34.8)19.6 
Accrued Taxes, NetAccrued Taxes, Net21.1 22.3 Accrued Taxes, Net(25.3)(17.0)
Other Current AssetsOther Current Assets(1.9)15.3 Other Current Assets(3.4)19.3 
Other Current LiabilitiesOther Current Liabilities(41.8)(53.6)Other Current Liabilities(22.7)(63.6)
Net Cash Flows from Operating ActivitiesNet Cash Flows from Operating Activities257.5 246.9 Net Cash Flows from Operating Activities734.4 642.8 
INVESTING ACTIVITIESINVESTING ACTIVITIES  INVESTING ACTIVITIES  
Construction ExpendituresConstruction Expenditures(141.7)(129.9)Construction Expenditures(418.4)(407.4)
Change in Advances to Affiliates, NetChange in Advances to Affiliates, Net(37.0)— Change in Advances to Affiliates, Net1.8 (1.1)
Purchases of Investment SecuritiesPurchases of Investment Securities(536.3)(507.7)Purchases of Investment Securities(2,182.8)(1,854.8)
Sales of Investment SecuritiesSales of Investment Securities517.6 493.5 Sales of Investment Securities2,139.3 1,818.4 
Acquisitions of Nuclear FuelAcquisitions of Nuclear Fuel(1.7)(31.1)Acquisitions of Nuclear Fuel(60.9)(91.9)
Other Investing ActivitiesOther Investing Activities3.3 0.3 Other Investing Activities4.9 8.0 
Net Cash Flows Used for Investing ActivitiesNet Cash Flows Used for Investing Activities(195.8)(174.9)Net Cash Flows Used for Investing Activities(516.1)(528.8)
FINANCING ACTIVITIESFINANCING ACTIVITIES  FINANCING ACTIVITIES  
Capital Contribution from ParentCapital Contribution from Parent1.7 1.9 
Issuance of Long-term Debt – NonaffiliatedIssuance of Long-term Debt – Nonaffiliated499.8 — Issuance of Long-term Debt – Nonaffiliated494.8 72.8 
Change in Advances from Affiliates, NetChange in Advances from Affiliates, Net(249.9)(19.7)Change in Advances from Affiliates, Net(249.9)11.6 
Retirement of Long-term Debt – NonaffiliatedRetirement of Long-term Debt – Nonaffiliated(274.3)(23.8)Retirement of Long-term Debt – Nonaffiliated(324.1)(64.5)
Principal Payments for Finance Lease ObligationsPrincipal Payments for Finance Lease Obligations(1.9)(1.6)Principal Payments for Finance Lease Obligations(5.4)(41.6)
Dividends Paid on Common StockDividends Paid on Common Stock(31.2)(25.0)Dividends Paid on Common Stock(137.5)(70.0)
Other Financing ActivitiesOther Financing Activities0.1 0.1 Other Financing Activities0.6 0.3 
Net Cash Flows Used for Financing ActivitiesNet Cash Flows Used for Financing Activities(57.4)(70.0)Net Cash Flows Used for Financing Activities(219.8)(89.5)
Net Increase in Cash and Cash Equivalents4.3 2.0 
Net Increase (Decrease) in Cash and Cash EquivalentsNet Increase (Decrease) in Cash and Cash Equivalents(1.5)24.5 
Cash and Cash Equivalents at Beginning of PeriodCash and Cash Equivalents at Beginning of Period4.2 1.3 Cash and Cash Equivalents at Beginning of Period4.2 1.3 
Cash and Cash Equivalents at End of PeriodCash and Cash Equivalents at End of Period$8.5 $3.3 Cash and Cash Equivalents at End of Period$2.7 $25.8 
SUPPLEMENTARY INFORMATIONSUPPLEMENTARY INFORMATION  SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized AmountsCash Paid for Interest, Net of Capitalized Amounts$44.4 $41.6 Cash Paid for Interest, Net of Capitalized Amounts$100.1 $101.6 
Net Cash Paid for Income Taxes2.4 — 
Net Cash Paid (Received) for Income TaxesNet Cash Paid (Received) for Income Taxes36.2 (4.1)
Noncash Acquisitions Under Finance LeasesNoncash Acquisitions Under Finance Leases2.2 0.3 Noncash Acquisitions Under Finance Leases3.6 0.8 
Construction Expenditures Included in Current Liabilities as of March 31,61.3 60.7 
Construction Expenditures Included in Current Liabilities as of September 30,Construction Expenditures Included in Current Liabilities as of September 30,70.6 68.1 
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,9.5 8.5 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
8687





OHIO POWER COMPANY AND SUBSIDIARIES

87



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

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
Three Months EndedNine Months Ended
Three Months Ended March 31, September 30,September 30,
202320222023202220232022
(in millions of KWhs) (in millions of KWhs)
Retail:Retail:  Retail:    
ResidentialResidential3,734 4,134 Residential3,761 3,954 10,323 11,146 
CommercialCommercial4,000 3,851 Commercial4,553 4,295 12,503 11,996 
IndustrialIndustrial3,418 3,503 Industrial3,536 3,561 10,456 10,688 
MiscellaneousMiscellaneous30 30 Miscellaneous24 25 78 79 
Total Retail (a)Total Retail (a)11,182 11,518 Total Retail (a)11,874 11,835 33,360 33,909 
Wholesale (b)Wholesale (b)453 571 Wholesale (b)485 587 1,366 1,723 
Total KWhsTotal KWhs11,635 12,089 Total KWhs12,359 12,422 34,726 35,632 

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

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

Summary of Heating and Cooling Degree Days
Three Months EndedNine Months Ended
Three Months Ended March 31, September 30,September 30,
202320222023202220232022
(in degree days) (in degree days)
Actual – Heating (a)Actual – Heating (a)1,344 1,864 Actual – Heating (a)— 1,521 2,078 
Normal – Heating (b)Normal – Heating (b)1,891 1,886 Normal – Heating (b)2,080 2,077 
Actual – Cooling (c)Actual – Cooling (c)— Actual – Cooling (c)625 755 809 1,115 
Normal – Cooling (b)Normal – Cooling (b)Normal – Cooling (b)697 688 1,005 989 

(a)Heating degree days are calculated on a 55 degree temperature base.
(b)Normal Heating/Cooling represents the thirty-year average of degree days.
(c)Cooling degree days are calculated on a 65 degree temperature base.
88


Ohio Power Company and Subsidiaries
Reconciliation of 2022 to 2023 Net Income
(in millions)
Three Months Ended 
September 30,
Nine Months Ended 
September 30,
2022 Net Income$71.9 $229.9 
  
Changes in Gross Margin: 
Retail Margins66.8 101.0 
Margins from Off-system Sales(5.5)35.9 
Transmission Revenues2.9 4.0 
Other Revenues4.8 2.4 
Total Change in Gross Margin69.0 143.3 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(44.0)(128.9)
Depreciation and Amortization(10.6)(7.8)
Taxes Other Than Income Taxes(1.5)(3.0)
Other Income(0.1)(0.6)
Allowance for Equity Funds Used During Construction1.7 1.0 
Non-Service Cost Components of Net Periodic Benefit Cost0.9 2.9 
Interest Expense(4.1)(8.1)
Total Change in Expenses and Other(57.7)(144.5)
  
Income Tax Expense(2.7)(1.7)
Equity Earnings of Unconsolidated Subsidiaries— (0.8)
  
2023 Net Income$80.5 $226.2 

FirstThird Quarter of 2023 Compared to FirstThird Quarter of 2022
Ohio Power Company and Subsidiaries
Reconciliation of First Quarter of 2022 to First Quarter of 2023
Net Income
(in millions)
First Quarter of 2022$83.2 
Changes in Gross Margin:
Retail Margins20.6 
Margins from Off-system Sales24.1 
Transmission Revenues(0.9)
Other Revenues0.8 
Total Change in Gross Margin44.6 
Changes in Expenses and Other:
Other Operation and Maintenance(40.1)
Depreciation and Amortization(0.3)
Taxes Other Than Income Taxes(8.3)
Carrying Costs Income(0.1)
Allowance for Equity Funds Used During Construction(0.2)
Non-Service Cost Components of Net Periodic Benefit Cost1.0 
Interest Expense(1.9)
Total Change in Expenses and Other(49.9)
Income Tax Expense0.1 
First Quarter of 2023$78.0 

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

Retail Margins increased $21$67 million primarily due to the following:
A $29$43 million increase due to various rider revenues.in revenue from rate riders. This increase was partially offset in Margins from Off-system Sales and other expense items below.
A $15$23 million net increase in Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset in Other Operation and Maintenance expenses below.
A $9 million increase in weather-normalized margins primarily in the industrial and commercial classes.
These increases were partially offset by:
A $9 million decrease in weather-related usage due to a 17% decrease in cooling degree days.
Margins from Off-system Sales decreased $6 million due to the following:
A $32 million decrease in Off-system sales at OVEC due to lower market prices and volume. This decrease was offset in Retail Margins above.
This decrease was partially offset by:
A $26 million increase in deferrals of OVEC costs. This increase was offset in Retail Margins above.
89


Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses increased $44 million primarily due to the following:
A $20 million increase related to an energy assistance program for qualified Ohio customers. This increase was offset in Retail Margins above.
A $19 million increase in transmission expenses primarily due to an increase in recoverable PJM expense, This increase was offset in Retail Margins above.
A $7 million increase in distribution expenses primarily related to vegetation management. This increase was offset in Retail Margins above.
Depreciation and Amortization expenses increased $11 million primarily due to the following:
A $17 million increase in depreciation expense primarily due to an increase in depreciable base.
This increase was partially offset by:
A $9 million decrease in recoverable DIR expense. This decrease was offset in Retail Margins above.

Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022

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

Retail Margins increased $101 million primarily due to the following:
An $86 million increase in revenue from rate riders. This increase was partially offset in Margins from Off-system Sales and other expense items below.
A $57 million net increase in Basic Transmission RevenuesCost Rider revenues and recoverable PJM expenses. This increase was partially offset in Other Operation and Maintenance expenses below.
These increases were partially offset by:
A $25$47 million decrease in weather-related usage due to a 27% decrease in heating degree days and a 28% decrease in heatingcooling degree days.
Margins from Off-system Salesincreased $24$36 million primarily due to the following:
A $34$111 million increase in deferrals of OVEC costs. This increase was offset in Retail Margins above.
This increase was partially offset by:
A $10$75 million decrease in off-systemOff-system sales at OVEC due to lower market prices and volume. This decrease was offset in Retail Margins above.
89



Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses increased $40$129 million primarily due to the following:
A $29$68 million increase related to an energy assistance program for qualified Ohio customers. This increase was offset in Retail Margins above.
A $5$41 million increase in transmission expenses primarily due to anto:
A $33 million increase in recoverable PJM expenses. This increase was offset in Retail Margins above.
Taxes Other Than Income TaxesAn $11 million increase in transmission formula rate true-up activity.
A $15 million increase in distribution expenses related to vegetation management. This increase was offset in Retail Margins above.
These increases were partially offset by:
A $12 million decrease in employee-related expenses.
Depreciation and Amortization expenses increased $8 million primarily due to the following:
A $30 million increase in depreciation expense primarily due to an increase in property taxes driven by additional investmentsdepreciable base.
A $5 million increase in transmissionsmart grid depreciable expenses. This increase was offset in Retail Margins above.
These increases were partially offset by:
A $30 million decrease in recoverable DIR expense. This decrease was offset in Retail Margins above.
Interest Expense increased $8 million primarily due to the following:
A $16 million increase primarily due to higher debt balances and distribution assets and higher taxinterest rates.
This increase was partially offset by:

A $6 million decrease due to an increase in AFUDC base.
90




OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
Three Months EndedNine Months Ended
Three Months Ended March 31,September 30,September 30,
20232022 2023202220232022
REVENUESREVENUES  REVENUES    
Electricity, Transmission and DistributionElectricity, Transmission and Distribution$1,021.8 $824.2 Electricity, Transmission and Distribution$978.7 $1,015.2 $2,869.3 $2,656.6 
Sales to AEP AffiliatesSales to AEP Affiliates7.6 3.7 Sales to AEP Affiliates7.8 4.0 23.6 11.6 
Other RevenuesOther Revenues5.2 2.1 Other Revenues3.0 2.1 10.3 6.0 
TOTAL REVENUESTOTAL REVENUES1,034.6 830.0 TOTAL REVENUES989.5 1,021.3 2,903.2 2,674.2 
EXPENSESEXPENSES  EXPENSES    
Purchased Electricity for ResalePurchased Electricity for Resale392.6 226.3 Purchased Electricity for Resale260.7 399.5 920.9 875.0 
Purchased Electricity from AEP AffiliatesPurchased Electricity from AEP Affiliates— 6.3 Purchased Electricity from AEP Affiliates38.0 — 49.6 9.8 
Other OperationOther Operation273.8 237.6 Other Operation296.9 267.3 836.1 728.2 
MaintenanceMaintenance44.3 40.4 Maintenance62.2 47.8 157.7 136.7 
Depreciation and AmortizationDepreciation and Amortization75.2 74.9 Depreciation and Amortization81.3 70.7 224.7 216.9 
Taxes Other Than Income TaxesTaxes Other Than Income Taxes135.3 127.0 Taxes Other Than Income Taxes132.5 131.0 382.0 379.0 
TOTAL EXPENSESTOTAL EXPENSES921.2 712.5 TOTAL EXPENSES871.6 916.3 2,571.0 2,345.6 
OPERATING INCOMEOPERATING INCOME113.4 117.5 OPERATING INCOME117.9 105.0 332.2 328.6 
Other Income (Expense):Other Income (Expense):  Other Income (Expense):    
Interest Income0.1 0.1 
Carrying Costs Income— 0.1 
Other IncomeOther Income0.1 0.2 0.4 1.0 
Allowance for Equity Funds Used During ConstructionAllowance for Equity Funds Used During Construction2.8 3.0 Allowance for Equity Funds Used During Construction5.6 3.9 11.3 10.3 
Non-Service Cost Components of Net Periodic Benefit CostNon-Service Cost Components of Net Periodic Benefit Cost6.5 5.5 Non-Service Cost Components of Net Periodic Benefit Cost6.5 5.6 19.5 16.6 
Interest ExpenseInterest Expense(31.1)(29.2)Interest Expense(33.9)(29.8)(96.9)(88.8)
INCOME BEFORE INCOME TAX EXPENSE91.7 97.0 
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGSINCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS96.2 84.9 266.5 267.7 
Income Tax ExpenseIncome Tax Expense13.7 13.8 Income Tax Expense15.7 13.0 40.3 38.6 
Equity Earnings of Unconsolidated SubsidiariesEquity Earnings of Unconsolidated Subsidiaries— — — 0.8 
NET INCOMENET INCOME$78.0 $83.2 NET INCOME$80.5 $71.9 $226.2 $229.9 
The common stock of OPCo is wholly-owned by Parent.The common stock of OPCo is wholly-owned by Parent.The common stock of OPCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
91



OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the ThreeNine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
Common
Stock
Paid-in
Capital
Retained
Earnings
TotalCommon
Stock
Paid-in
Capital
Retained
Earnings
Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2021TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2021$321.2 $838.8 $1,686.3 $2,846.3 TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2021$321.2 $838.8 $1,686.3 $2,846.3 
Common Stock DividendsCommon Stock Dividends(15.0)(15.0)Common Stock Dividends(15.0)(15.0)
Net IncomeNet Income83.2 83.2 Net Income83.2 83.2 
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2022TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2022$321.2 $838.8 $1,754.5 $2,914.5 TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2022321.2 838.8 1,754.5 2,914.5 
Capital Contribution from ParentCapital Contribution from Parent0.7 0.7 
Common Stock DividendsCommon Stock Dividends  (15.0)(15.0)
Net IncomeNet Income  74.8 74.8 
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2022TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2022321.2 839.5 1,814.3 2,975.0 
Capital Contribution from ParentCapital Contribution from Parent0.30.3 
Common Stock DividendsCommon Stock Dividends(15.0)(15.0)
Net IncomeNet Income71.9 71.9 
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2022TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2022$321.2 $839.8 $1,871.2 $3,032.2 
    
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2022TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2022$321.2 $837.8 $1,929.1 $3,088.1 TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2022$321.2 $837.8 $1,929.1 $3,088.1 
Capital Contribution from ParentCapital Contribution from Parent50.050.0Capital Contribution from Parent50.050.0
Net IncomeNet Income78.0 78.0 Net Income78.0 78.0 
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2023TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2023$321.2 $887.8 $2,007.1 $3,216.1 TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2023321.2 887.8 2,007.1 3,216.1 
Capital Contribution from ParentCapital Contribution from Parent125.0 125.0 
Net IncomeNet Income  67.7 67.7 
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2023TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2023321.2 1,012.8 2,074.8 3,408.8 
Net IncomeNet Income80.5 80.5 
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2023TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2023$321.2 $1,012.8 $2,155.3 $3,489.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
92



OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31,September 30, 2023 and December 31, 2022
(in millions)
(Unaudited)
March 31,December 31, September 30,December 31,
20232022 20232022
CURRENT ASSETSCURRENT ASSETS  CURRENT ASSETS  
Cash and Cash EquivalentsCash and Cash Equivalents$9.1 $9.6 Cash and Cash Equivalents$6.8 $9.6 
Accounts Receivable:Accounts Receivable:  Accounts Receivable:  
CustomersCustomers104.9 119.9 Customers104.1 119.9 
Affiliated CompaniesAffiliated Companies113.9 100.9 Affiliated Companies129.3 100.9 
Accrued Unbilled RevenuesAccrued Unbilled Revenues30.0 17.8 Accrued Unbilled Revenues2.9 17.8 
MiscellaneousMiscellaneous0.1 0.1 Miscellaneous1.6 0.1 
Allowance for Uncollectible AccountsAllowance for Uncollectible Accounts(0.1)(0.1)Allowance for Uncollectible Accounts0.1 (0.1)
Total Accounts ReceivableTotal Accounts Receivable248.8 238.6 Total Accounts Receivable238.0 238.6 
Materials and SuppliesMaterials and Supplies110.0 109.5 Materials and Supplies151.8 109.5 
Renewable Energy CreditsRenewable Energy Credits36.7 35.0 Renewable Energy Credits19.9 35.0 
Prepayments and Other Current AssetsPrepayments and Other Current Assets25.6 21.7 Prepayments and Other Current Assets27.2 21.7 
TOTAL CURRENT ASSETSTOTAL CURRENT ASSETS430.2 414.4 TOTAL CURRENT ASSETS443.7 414.4 
PROPERTY, PLANT AND EQUIPMENTPROPERTY, PLANT AND EQUIPMENT  PROPERTY, PLANT AND EQUIPMENT  
Electric:Electric:  Electric:  
TransmissionTransmission3,218.7 3,198.6 Transmission3,320.1 3,198.6 
DistributionDistribution6,535.9 6,450.3 Distribution6,718.3 6,450.3 
Other Property, Plant and EquipmentOther Property, Plant and Equipment1,066.5 1,051.4 Other Property, Plant and Equipment1,071.5 1,051.4 
Construction Work in ProgressConstruction Work in Progress589.1 474.3 Construction Work in Progress720.6 474.3 
Total Property, Plant and EquipmentTotal Property, Plant and Equipment11,410.2 11,174.6 Total Property, Plant and Equipment11,830.5 11,174.6 
Accumulated Depreciation and AmortizationAccumulated Depreciation and Amortization2,602.9 2,565.3 Accumulated Depreciation and Amortization2,670.5 2,565.3 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NETTOTAL PROPERTY, PLANT AND EQUIPMENT – NET8,807.3 8,609.3 TOTAL PROPERTY, PLANT AND EQUIPMENT – NET9,160.0 8,609.3 
OTHER NONCURRENT ASSETSOTHER NONCURRENT ASSETS  OTHER NONCURRENT ASSETS  
Regulatory AssetsRegulatory Assets352.8 327.3 Regulatory Assets413.2 327.3 
Operating Lease AssetsOperating Lease Assets72.5 73.8 Operating Lease Assets68.9 73.8 
Deferred Charges and Other Noncurrent AssetsDeferred Charges and Other Noncurrent Assets489.9 578.3 Deferred Charges and Other Noncurrent Assets262.7 578.3 
TOTAL OTHER NONCURRENT ASSETSTOTAL OTHER NONCURRENT ASSETS915.2 979.4 TOTAL OTHER NONCURRENT ASSETS744.8 979.4 
TOTAL ASSETSTOTAL ASSETS$10,152.7 $10,003.1 TOTAL ASSETS$10,348.5 $10,003.1 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
93



OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
March 31,September 30, 2023 and December 31, 2022
(Unaudited)
March 31,December 31, September 30,December 31,
20232022 20232022
(in millions)(in millions)
CURRENT LIABILITIESCURRENT LIABILITIES  CURRENT LIABILITIES  
Advances from AffiliatesAdvances from Affiliates$414.6 $172.9 Advances from Affiliates$113.3 $172.9 
Accounts Payable:Accounts Payable:  Accounts Payable:  
GeneralGeneral333.5 337.3 General308.5 337.3 
Affiliated CompaniesAffiliated Companies130.0 126.1 Affiliated Companies151.0 126.1 
Long-term Debt Due Within One Year – NonaffiliatedLong-term Debt Due Within One Year – Nonaffiliated0.1 0.1 Long-term Debt Due Within One Year – Nonaffiliated— 0.1 
Risk Management LiabilitiesRisk Management Liabilities6.0 1.8 Risk Management Liabilities5.7 1.8 
Customer DepositsCustomer Deposits73.8 96.5 Customer Deposits59.2 96.5 
Accrued TaxesAccrued Taxes573.4 733.1 Accrued Taxes370.9 733.1 
Obligations Under Operating LeasesObligations Under Operating Leases13.4 13.5 Obligations Under Operating Leases13.5 13.5 
Other Current LiabilitiesOther Current Liabilities145.5 154.2 Other Current Liabilities204.7 154.2 
TOTAL CURRENT LIABILITIESTOTAL CURRENT LIABILITIES1,690.3 1,635.5 TOTAL CURRENT LIABILITIES1,226.8 1,635.5 
NONCURRENT LIABILITIESNONCURRENT LIABILITIES  NONCURRENT LIABILITIES  
Long-term Debt – NonaffiliatedLong-term Debt – Nonaffiliated2,970.7 2,970.2 Long-term Debt – Nonaffiliated3,366.2 2,970.2 
Long-term Risk Management LiabilitiesLong-term Risk Management Liabilities40.9 37.9 Long-term Risk Management Liabilities45.9 37.9 
Deferred Income TaxesDeferred Income Taxes1,109.1 1,101.1 Deferred Income Taxes1,155.5 1,101.1 
Regulatory Liabilities and Deferred Investment Tax CreditsRegulatory Liabilities and Deferred Investment Tax Credits1,014.6 1,044.0 Regulatory Liabilities and Deferred Investment Tax Credits976.8 1,044.0 
Obligations Under Operating LeasesObligations Under Operating Leases59.2 60.3 Obligations Under Operating Leases55.6 60.3 
Deferred Credits and Other Noncurrent LiabilitiesDeferred Credits and Other Noncurrent Liabilities51.8 66.0 Deferred Credits and Other Noncurrent Liabilities32.4 66.0 
TOTAL NONCURRENT LIABILITIESTOTAL NONCURRENT LIABILITIES5,246.3 5,279.5 TOTAL NONCURRENT LIABILITIES5,632.4 5,279.5 
TOTAL LIABILITIESTOTAL LIABILITIES6,936.6 6,915.0 TOTAL LIABILITIES6,859.2 6,915.0 
Rate Matters (Note 4)Rate Matters (Note 4)Rate Matters (Note 4)
Commitments and Contingencies (Note 5)Commitments and Contingencies (Note 5)Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITYCOMMON SHAREHOLDER’S EQUITY  COMMON SHAREHOLDER’S EQUITY  
Common Stock –No Par Value:Common Stock –No Par Value:  Common Stock –No Par Value:  
Authorized – 40,000,000 SharesAuthorized – 40,000,000 Shares  Authorized – 40,000,000 Shares  
Outstanding – 27,952,473 SharesOutstanding – 27,952,473 Shares321.2 321.2 Outstanding – 27,952,473 Shares321.2 321.2 
Paid-in CapitalPaid-in Capital887.8 837.8 Paid-in Capital1,012.8 837.8 
Retained EarningsRetained Earnings2,007.1 1,929.1 Retained Earnings2,155.3 1,929.1 
TOTAL COMMON SHAREHOLDER’S EQUITYTOTAL COMMON SHAREHOLDER’S EQUITY3,216.1 3,088.1 TOTAL COMMON SHAREHOLDER’S EQUITY3,489.3 3,088.1 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITYTOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$10,152.7 $10,003.1 TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$10,348.5 $10,003.1 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
94



OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the ThreeNine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
Three Months Ended March 31, Nine Months Ended September 30,
20232022 20232022
OPERATING ACTIVITIESOPERATING ACTIVITIES  OPERATING ACTIVITIES  
Net IncomeNet Income$78.0 $83.2 Net Income$226.2 $229.9 
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:  
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and AmortizationDepreciation and Amortization75.2 74.9 Depreciation and Amortization224.7 216.9 
Deferred Income TaxesDeferred Income Taxes2.1 9.5 Deferred Income Taxes29.4 29.3 
Allowance for Equity Funds Used During ConstructionAllowance for Equity Funds Used During Construction(2.8)(3.0)Allowance for Equity Funds Used During Construction(11.3)(10.3)
Mark-to-Market of Risk Management ContractsMark-to-Market of Risk Management Contracts7.2 (24.0)Mark-to-Market of Risk Management Contracts11.6 (49.6)
Property TaxesProperty Taxes92.0 87.0 Property Taxes282.4 264.7 
Change in Other Noncurrent AssetsChange in Other Noncurrent Assets(43.2)(1.2)Change in Other Noncurrent Assets(95.5)(19.7)
Change in Other Noncurrent LiabilitiesChange in Other Noncurrent Liabilities(21.7)11.0 Change in Other Noncurrent Liabilities(47.7)82.5 
Changes in Certain Components of Working Capital:Changes in Certain Components of Working Capital:  Changes in Certain Components of Working Capital:  
Accounts Receivable, NetAccounts Receivable, Net(20.3)(28.8)Accounts Receivable, Net4.3 (27.0)
Materials and SuppliesMaterials and Supplies(4.8)(5.0)Materials and Supplies5.3 (11.6)
Accounts PayableAccounts Payable(5.5)4.0 Accounts Payable1.8 87.6 
Customer DepositsCustomer Deposits(22.7)24.1 Customer Deposits(37.3)37.4 
Accrued Taxes, NetAccrued Taxes, Net(157.9)(158.3)Accrued Taxes, Net(367.3)(344.5)
Other Current AssetsOther Current Assets(2.2)13.5 Other Current Assets(2.3)11.3 
Other Current LiabilitiesOther Current Liabilities(7.7)20.3 Other Current Liabilities0.4 25.7 
Net Cash Flows from (Used for) Operating Activities(34.3)107.2 
Net Cash Flows from Operating ActivitiesNet Cash Flows from Operating Activities224.7 522.6 
INVESTING ACTIVITIESINVESTING ACTIVITIES  INVESTING ACTIVITIES  
Construction ExpendituresConstruction Expenditures(262.0)(188.7)Construction Expenditures(769.0)(600.6)
Change in Advances to Affiliates, NetChange in Advances to Affiliates, Net— 42.0 Change in Advances to Affiliates, Net— 42.0 
Other Investing ActivitiesOther Investing Activities4.9 4.2 Other Investing Activities33.9 21.3 
Net Cash Flows Used for Investing ActivitiesNet Cash Flows Used for Investing Activities(257.1)(142.5)Net Cash Flows Used for Investing Activities(735.1)(537.3)
FINANCING ACTIVITIESFINANCING ACTIVITIES  FINANCING ACTIVITIES  
Capital Contribution from ParentCapital Contribution from Parent50.0 — Capital Contribution from Parent175.0 1.0 
Issuance of Long-term Debt – NonaffiliatedIssuance of Long-term Debt – Nonaffiliated395.0 — 
Change in Advances from Affiliates, NetChange in Advances from Affiliates, Net241.7 55.7 Change in Advances from Affiliates, Net(59.6)68.8 
Retirement of Long-term Debt – NonaffiliatedRetirement of Long-term Debt – Nonaffiliated(0.6)(0.1)
Principal Payments for Finance Lease ObligationsPrincipal Payments for Finance Lease Obligations(1.2)(1.2)Principal Payments for Finance Lease Obligations(3.7)(3.6)
Dividends Paid on Common StockDividends Paid on Common Stock— (15.0)Dividends Paid on Common Stock— (45.0)
Other Financing ActivitiesOther Financing Activities0.4 0.2 Other Financing Activities1.5 0.8 
Net Cash Flows from Financing ActivitiesNet Cash Flows from Financing Activities290.9 39.7 Net Cash Flows from Financing Activities507.6 21.9 
Net Increase (Decrease) in Cash and Cash EquivalentsNet Increase (Decrease) in Cash and Cash Equivalents(0.5)4.4 Net Increase (Decrease) in Cash and Cash Equivalents(2.8)7.2 
Cash and Cash Equivalents at Beginning of PeriodCash and Cash Equivalents at Beginning of Period9.6 3.0 Cash and Cash Equivalents at Beginning of Period9.6 3.0 
Cash and Cash Equivalents at End of PeriodCash and Cash Equivalents at End of Period$9.1 $7.4 Cash and Cash Equivalents at End of Period$6.8 $10.2 
SUPPLEMENTARY INFORMATIONSUPPLEMENTARY INFORMATION  SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized AmountsCash Paid for Interest, Net of Capitalized Amounts$20.9 $19.5 Cash Paid for Interest, Net of Capitalized Amounts$76.5 $75.8 
Net Cash Paid for Income TaxesNet Cash Paid for Income Taxes16.0 24.2 
Noncash Acquisitions Under Finance LeasesNoncash Acquisitions Under Finance Leases0.6 0.6 Noncash Acquisitions Under Finance Leases3.3 2.1 
Construction Expenditures Included in Current Liabilities as of March 31,109.9 67.0 
Construction Expenditures Included in Current Liabilities as of September 30,Construction Expenditures Included in Current Liabilities as of September 30,99.6 108.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
95





PUBLIC SERVICE COMPANY OF OKLAHOMA
96



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

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
Three Months EndedNine Months Ended
Three Months Ended March 31, September 30,September 30,
202320222023202220232022
(in millions of KWhs) (in millions of KWhs)
Retail:Retail:  Retail:    
ResidentialResidential1,388 1,558 Residential2,197 2,293 4,943 5,320 
CommercialCommercial1,104 1,120 Commercial1,539 1,547 3,934 3,976 
IndustrialIndustrial1,439 1,386 Industrial1,557 1,616 4,503 4,567 
MiscellaneousMiscellaneous275 283 Miscellaneous373 377 965 993 
Total RetailTotal Retail4,206 4,347 Total Retail5,666 5,833 14,345 14,856 
WholesaleWholesale27 343 Wholesale59 55 132 660 
Total KWhsTotal KWhs4,233 4,690 Total KWhs5,725 5,888 14,477 15,516 

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

Summary of Heating and Cooling Degree Days
Three Months EndedNine Months Ended
Three Months Ended March 31, September 30,September 30,
202320222023202220232022
(in degree days) (in degree days)
Actual – Heating (a)Actual – Heating (a)871 1,134 Actual – Heating (a)— — 899 1,153 
Normal – Heating (b)Normal – Heating (b)1,055 1,040 Normal – Heating (b)— — 1,100 1,085 
Actual – Cooling (c)Actual – Cooling (c)10 11 Actual – Cooling (c)1,554 1,678 2,202 2,475 
Normal – Cooling (b)Normal – Cooling (b)17 17 Normal – Cooling (b)1,425 1,407 2,102 2,074 

(a)Heating degree days are calculated on a 55 degree temperature base.
(b)Normal Heating/Cooling represents the thirty-year average of degree days.
(c)Cooling degree days are calculated on a 65 degree temperature base.
9796



First Quarter of 2023 Compared to First Quarter of 2022
Public Service Company of Oklahoma
Reconciliation of 2022 to 2023 Net Income
(in millions)
Three Months Ended 
September 30,
Nine Months Ended 
September 30,
2022 Net Income$106.9 $155.7 
Changes in Gross Margin:
Retail Margins (a)10.4 26.5 
Transmission Revenues1.1 3.0 
Other Revenues— 0.6 
Total Change in Gross Margin11.5 30.1 
Changes in Expenses and Other: 
Other Operation and Maintenance18.3 22.8 
Depreciation and Amortization(2.3)(15.1)
Taxes Other Than Income Taxes(1.6)(5.9)
Other Income(0.3)(1.8)
Non-Service Cost Components of Net Periodic Benefit Cost0.5 1.3 
Interest Expense(3.1)(14.9)
Total Change in Expenses and Other11.5 (13.6)
  
Income Tax Benefit9.5 15.9 
  
2023 Net Income$139.4 $188.1 
Public Service Company of Oklahoma
Reconciliation of First Quarter of 2022 to First Quarter of 2023
Net Income (Loss)
(in millions)
First Quarter of 2022$5.8 
Changes in Gross Margin:
Retail Margins (a)15.3 
Transmission Revenues1.6 
Other Revenues1.1 
Total Change in Gross Margin18.0 
Changes in Expenses and Other:
Other Operation and Maintenance(6.7)
Depreciation and Amortization(8.4)
Taxes Other Than Income Taxes(3.1)
Interest Income(0.7)
Allowance for Equity Funds Used During Construction0.4 
Non-Service Cost Components of Net Periodic Benefit Cost0.5 
Interest Expense(6.3)
Total Change in Expenses and Other(24.3)
Income Tax Expense(1.8)
First Quarter of 2023$(2.3)

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

Third Quarter of 2023 Compared to Third Quarter of 2022

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

Retail Margins increased $15$10 million primarily due to the following:
A $10$28 million increase in base rate and rider revenues. This increase was partially offset in other expense items below.
This increase was partially offset by:
A $10 million decrease due to an increase in PTC benefits provided to customers. This decrease was offset in Income Tax Benefit below.
An $8 million decrease in weather-related usage primarily due to a 7% decrease in cooling degree days.

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

Other Operation and Maintenance expenses decreased $18 million primarily due to the following:
A $9 million decrease in transmission expenses primarily due to a $5 million decrease in recoverable SPP transmission expense and $4 million decrease in transmission formula rate true-up activity. The decrease in recoverable SPP transmission expense was offset in Retail Margins above.
A $5 million decrease in distribution expenses primarily related to vegetation management.
A $5 million decrease in employee-related expenses.
97


Income Tax Benefit increased $10 million primarily due to a $13 million increase in PTCs, partially offset by a $5 million decrease due to an increase in pretax book income. The increase in PTCs was partially offset in Retail Margins above.

Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022

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

Retail Margins increased $27 million primarily due to the following:
A $47 million increase in base rate and rider revenues. This increase was partially offset in other expense items below.
A $4An $11 million increase in fuel revenuesrevenue due to increased carrying charges on fuel under recoveryunder-recovered balances.
These increases were partially offset by:
A $19 million decrease in weather-related usage primarily due to an 11% decrease in cooling degree days and a 22% decrease in heating degree days.
A $14 million decrease due to an increase in PTC benefits provided to customers. This decrease was offset in Income Tax Benefit below.

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

Other Operation and Maintenance expenses increased $7decreased $23 million primarily due to the following:
A $14 million decrease in transmission expenses due to a $21 million decrease in recoverable SPP transmission expense and $4 million decrease in transmission formula rate true-up activity, offset by an $11 million increase due to a change in generating maintenance expenses driven byrider recovery. The decrease in recoverable SPP transmission expense was offset in Retail Margins above.
An $8 million decrease in employee-related expenses.
A $6 million decrease due to the Northeastern Plant and the NCWF.capitalization of previously expensed renewable generation pre-construction charges.
Depreciation and Amortizationexpenses increased $8$15 million primarily due to a higher depreciable base, implementation of new rates and the timing of refunds to customers under rate rider mechanisms.base.
Taxes Other Than Income Taxes increased $3$6 million primarily due to increased property taxes driven by the investment in the NCWF and a new infrastructure fee implemented by the City of Tulsa in MarchMarch 2022. This increase was partially offset in Retail Margins above.
Interest Expense increased $6$15 million primarily due to higher long-term debt balances.balances and higher interest rates.
Income Tax Benefit increased $16 million primarily due to a $19 million increase in PTCs, partially offset by a $3 million decrease due to an increase in pretax book income. The increase in PTCs was partially offset in Retail Margins above.
98




PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF OPERATIONSINCOME
For the Three and Nine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
Three Months Ended March 31, Three Months EndedNine Months Ended
September 30,September 30,
20232022 2023202220232022
REVENUESREVENUES  REVENUES    
Electric Generation, Transmission and DistributionElectric Generation, Transmission and Distribution$414.8 $386.4 Electric Generation, Transmission and Distribution$642.6 $606.5 $1,529.8 $1,432.9 
Sales to AEP AffiliatesSales to AEP Affiliates0.7 0.6 Sales to AEP Affiliates0.2 0.7 1.0 2.1 
Other RevenuesOther Revenues1.5 0.6 Other Revenues1.4 1.0 5.1 3.7 
TOTAL REVENUESTOTAL REVENUES417.0 387.6 TOTAL REVENUES644.2 608.2 1,535.9 1,438.7 
EXPENSESEXPENSES  EXPENSES    
Purchased Electricity, Fuel and Other Consumables Used for Electric GenerationPurchased Electricity, Fuel and Other Consumables Used for Electric Generation200.1 188.7 Purchased Electricity, Fuel and Other Consumables Used for Electric Generation318.1 293.6 741.3 674.2 
Other OperationOther Operation92.1 88.8 Other Operation103.9 116.3 283.5 301.0 
MaintenanceMaintenance28.8 25.4 Maintenance25.4 31.3 82.7 88.0 
Depreciation and AmortizationDepreciation and Amortization61.1 52.7 Depreciation and Amortization61.8 59.5 187.8 172.7 
Taxes Other Than Income TaxesTaxes Other Than Income Taxes17.3 14.2 Taxes Other Than Income Taxes17.2 15.6 49.5 43.6 
TOTAL EXPENSESTOTAL EXPENSES399.4 369.8 TOTAL EXPENSES526.4 516.3 1,344.8 1,279.5 
OPERATING INCOMEOPERATING INCOME17.6 17.8 OPERATING INCOME117.8 91.9 191.1 159.2 
Other Income (Expense):Other Income (Expense):  Other Income (Expense):    
Interest Income1.0 1.7 
Allowance for Equity Funds Used During Construction1.5 1.1 
Other IncomeOther Income2.7 3.0 6.7 8.5 
Non-Service Cost Components of Net Periodic Benefit CostNon-Service Cost Components of Net Periodic Benefit Cost3.6 3.1 Non-Service Cost Components of Net Periodic Benefit Cost3.6 3.1 10.7 9.4 
Interest ExpenseInterest Expense(25.2)(18.9)Interest Expense(25.5)(22.4)(77.5)(62.6)
INCOME (LOSS) BEFORE INCOME TAX EXPENSE (BENEFIT)(1.5)4.8 
INCOME BEFORE INCOME TAX BENEFITINCOME BEFORE INCOME TAX BENEFIT98.6 75.6 131.0 114.5 
Income Tax Expense (Benefit)0.8 (1.0)
Income Tax BenefitIncome Tax Benefit(40.8)(31.3)(57.1)(41.2)
NET INCOME (LOSS)$(2.3)$5.8 
NET INCOMENET INCOME$139.4 $106.9 $188.1 $155.7 
The common stock of PSO is wholly-owned by Parent.The common stock of PSO is wholly-owned by Parent.The common stock of PSO is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
99



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
 Three Months Ended March 31,
20232022
Net Income (Loss)$(2.3)$5.8 
OTHER COMPREHENSIVE LOSS, NET OF TAXES  
Cash Flow Hedges, Net of Tax of $(0.4) and $0 in 2023 and 2022, Respectively(1.5)— 
  
TOTAL COMPREHENSIVE INCOME (LOSS)$(3.8)$5.8 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
 Three Months EndedNine Months Ended
September 30,September 30,
2023202220232022
Net Income$139.4 $106.9 $188.1 $155.7 
OTHER COMPREHENSIVE LOSS, NET OF TAXES    
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2023 and 2022, Respectively, and $(0.4) and $0 for the Nine Months Ended September 30, 2023 and 2022, Respectively— — (1.5)— 
    
TOTAL COMPREHENSIVE INCOME$139.4 $106.9 $186.6 $155.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
100



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the ThreeNine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
Common
Stock
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
TotalCommon
Stock
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2021TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2021$157.2 $1,039.0 $1,095.4 $— $2,291.6 TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2021$157.2 $1,039.0 $1,095.4 $— $2,291.6 
Net IncomeNet Income5.8 5.8 Net Income5.8 5.8 
TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2022TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2022$157.2 $1,039.0 $1,101.2 $— $2,297.4 TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2022157.2 1,039.0 1,101.2 — 2,297.4 
Capital Contribution from ParentCapital Contribution from Parent2.22.2 
Net IncomeNet Income  43.0  43.0 
TOTAL COMMON SHAREHOLDER'S EQUITY – JUNE 30, 2022TOTAL COMMON SHAREHOLDER'S EQUITY – JUNE 30, 2022157.2 1,041.2 1,144.2 — 2,342.6 
Capital Contribution from ParentCapital Contribution from Parent 1.1   1.1 
Common Stock DividendsCommon Stock Dividends(20.0)(20.0)
Net IncomeNet Income106.9 106.9 
TOTAL COMMON SHAREHOLDER'S EQUITY – SEPTEMBER 30, 2022TOTAL COMMON SHAREHOLDER'S EQUITY – SEPTEMBER 30, 2022$157.2 $1,042.3 $1,231.1 $— $2,430.6 
TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2022TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2022$157.2 $1,042.6 $1,218.0 $1.3 $2,419.1 TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2022$157.2 $1,042.6 $1,218.0 $1.3 $2,419.1 
Common Stock DividendsCommon Stock Dividends(17.5)(17.5)Common Stock Dividends(17.5)(17.5)
Net LossNet Loss(2.3)(2.3)Net Loss(2.3)(2.3)
Other Comprehensive LossOther Comprehensive Loss(1.5)(1.5)Other Comprehensive Loss(1.5)(1.5)
TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2023TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2023$157.2 $1,042.6 $1,198.2 $(0.2)$2,397.8 TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2023157.2 1,042.6 1,198.2 (0.2)2,397.8 
Return of Capital to ParentReturn of Capital to Parent(2.5)(2.5)
Net IncomeNet Income  51.0  51.0 
TOTAL COMMON SHAREHOLDER'S EQUITY – JUNE 30, 2023TOTAL COMMON SHAREHOLDER'S EQUITY – JUNE 30, 2023157.2 1,040.1 1,249.2 (0.2)2,446.3 
Capital Contribution from ParentCapital Contribution from Parent0.60.6 
Common Stock DividendsCommon Stock Dividends(17.5)(17.5)
Net IncomeNet Income139.4 139.4 
TOTAL COMMON SHAREHOLDER'S EQUITY – SEPTEMBER 30, 2023TOTAL COMMON SHAREHOLDER'S EQUITY – SEPTEMBER 30, 2023$157.2 $1,040.7 $1,371.1 $(0.2)$2,568.8 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

101



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
March 31,September 30, 2023 and December 31, 2022
(in millions)
(Unaudited)
March 31,December 31, September 30,December 31,
20232022 20232022
CURRENT ASSETSCURRENT ASSETS  CURRENT ASSETS  
Cash and Cash EquivalentsCash and Cash Equivalents$3.8 $4.0 Cash and Cash Equivalents$3.7 $4.0 
Advances to AffiliatesAdvances to Affiliates9.2 — 
Accounts Receivable:Accounts Receivable:  Accounts Receivable:  
CustomersCustomers61.4 70.1 Customers78.8 70.1 
Affiliated CompaniesAffiliated Companies33.5 52.2 Affiliated Companies31.9 52.2 
MiscellaneousMiscellaneous1.0 0.8 Miscellaneous0.5 0.8 
Total Accounts ReceivableTotal Accounts Receivable95.9 123.1 Total Accounts Receivable111.2 123.1 
FuelFuel14.9 11.6 Fuel20.5 11.6 
Materials and SuppliesMaterials and Supplies95.9 111.1 Materials and Supplies114.9 111.1 
Risk Management AssetsRisk Management Assets9.4 25.3 Risk Management Assets28.2 25.3 
Accrued Tax BenefitsAccrued Tax Benefits27.4 16.1 Accrued Tax Benefits61.3 16.1 
Regulatory Asset for Under-Recovered Fuel CostsRegulatory Asset for Under-Recovered Fuel Costs178.7 178.7 Regulatory Asset for Under-Recovered Fuel Costs168.2 178.7 
Prepayments and Other Current AssetsPrepayments and Other Current Assets23.3 21.6 Prepayments and Other Current Assets35.2 21.6 
TOTAL CURRENT ASSETSTOTAL CURRENT ASSETS449.3 491.5 TOTAL CURRENT ASSETS552.4 491.5 
PROPERTY, PLANT AND EQUIPMENTPROPERTY, PLANT AND EQUIPMENT  PROPERTY, PLANT AND EQUIPMENT  
Electric:Electric:  Electric:  
GenerationGeneration2,658.9 2,394.8 Generation2,683.7 2,394.8 
TransmissionTransmission1,171.8 1,164.4 Transmission1,197.1 1,164.4 
DistributionDistribution3,264.4 3,216.4 Distribution3,357.9 3,216.4 
Other Property, Plant and EquipmentOther Property, Plant and Equipment478.5 469.3 Other Property, Plant and Equipment498.8 469.3 
Construction Work in ProgressConstruction Work in Progress263.8 219.3 Construction Work in Progress337.9 219.3 
Total Property, Plant and EquipmentTotal Property, Plant and Equipment7,837.4 7,464.2 Total Property, Plant and Equipment8,075.4 7,464.2 
Accumulated Depreciation and AmortizationAccumulated Depreciation and Amortization1,973.1 1,837.7 Accumulated Depreciation and Amortization2,050.3 1,837.7 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NETTOTAL PROPERTY, PLANT AND EQUIPMENT – NET5,864.3 5,626.5 TOTAL PROPERTY, PLANT AND EQUIPMENT – NET6,025.1 5,626.5 
OTHER NONCURRENT ASSETSOTHER NONCURRENT ASSETS  OTHER NONCURRENT ASSETS  
Regulatory AssetsRegulatory Assets609.8 653.7 Regulatory Assets477.2 653.7 
Employee Benefits and Pension AssetsEmployee Benefits and Pension Assets68.7 67.3 Employee Benefits and Pension Assets71.4 67.3 
Operating Lease AssetsOperating Lease Assets106.1 106.1 Operating Lease Assets114.0 106.1 
Deferred Charges and Other Noncurrent AssetsDeferred Charges and Other Noncurrent Assets66.4 20.8 Deferred Charges and Other Noncurrent Assets32.1 20.8 
TOTAL OTHER NONCURRENT ASSETSTOTAL OTHER NONCURRENT ASSETS851.0 847.9 TOTAL OTHER NONCURRENT ASSETS694.7 847.9 
TOTAL ASSETSTOTAL ASSETS$7,164.6 $6,965.9 TOTAL ASSETS$7,272.2 $6,965.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
102



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
March 31,September 30, 2023 and December 31, 2022
(Unaudited)
March 31,December 31, September 30,December 31,
20232022 20232022
(in millions) (in millions)
CURRENT LIABILITIESCURRENT LIABILITIES  CURRENT LIABILITIES  
Advances from AffiliatesAdvances from Affiliates$130.7 $364.2 Advances from Affiliates$— $364.2 
Accounts Payable:Accounts Payable:  Accounts Payable:  
GeneralGeneral155.7 202.9 General233.3 202.9 
Affiliated CompaniesAffiliated Companies56.3 76.7 Affiliated Companies46.1 76.7 
Long-term Debt Due Within One Year – NonaffiliatedLong-term Debt Due Within One Year – Nonaffiliated0.5 0.5 Long-term Debt Due Within One Year – Nonaffiliated0.6 0.5 
Customer DepositsCustomer Deposits59.4 59.0 Customer Deposits61.0 59.0 
Accrued TaxesAccrued Taxes64.9 28.7 Accrued Taxes64.4 28.7 
Accrued InterestAccrued Interest25.9 18.2 
Obligations Under Operating LeasesObligations Under Operating Leases9.2 8.9 Obligations Under Operating Leases10.7 8.9 
Other Current LiabilitiesOther Current Liabilities93.7 101.8 Other Current Liabilities75.4 83.6 
TOTAL CURRENT LIABILITIESTOTAL CURRENT LIABILITIES570.4 842.7 TOTAL CURRENT LIABILITIES517.4 842.7 
NONCURRENT LIABILITIESNONCURRENT LIABILITIES  NONCURRENT LIABILITIES  
Long-term Debt – NonaffiliatedLong-term Debt – Nonaffiliated2,383.1 1,912.3 Long-term Debt – Nonaffiliated2,383.6 1,912.3 
Deferred Income TaxesDeferred Income Taxes805.9 788.6 Deferred Income Taxes797.5 788.6 
Regulatory Liabilities and Deferred Investment Tax CreditsRegulatory Liabilities and Deferred Investment Tax Credits808.4 809.1 Regulatory Liabilities and Deferred Investment Tax Credits787.0 809.1 
Asset Retirement ObligationsAsset Retirement Obligations80.3 73.5 Asset Retirement Obligations82.3 73.5 
Obligations Under Operating LeasesObligations Under Operating Leases99.1 99.3 Obligations Under Operating Leases106.6 99.3 
Deferred Credits and Other Noncurrent LiabilitiesDeferred Credits and Other Noncurrent Liabilities19.6 21.3 Deferred Credits and Other Noncurrent Liabilities29.0 21.3 
TOTAL NONCURRENT LIABILITIESTOTAL NONCURRENT LIABILITIES4,196.4 3,704.1 TOTAL NONCURRENT LIABILITIES4,186.0 3,704.1 
TOTAL LIABILITIESTOTAL LIABILITIES4,766.8 4,546.8 TOTAL LIABILITIES4,703.4 4,546.8 
Rate Matters (Note 4)Rate Matters (Note 4)Rate Matters (Note 4)
Commitments and Contingencies (Note 5)Commitments and Contingencies (Note 5)Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITYCOMMON SHAREHOLDER’S EQUITY  COMMON SHAREHOLDER’S EQUITY  
Common Stock – Par Value – $15 Per Share:Common Stock – Par Value – $15 Per Share:  Common Stock – Par Value – $15 Per Share:  
Authorized – 11,000,000 SharesAuthorized – 11,000,000 Shares  Authorized – 11,000,000 Shares  
Issued – 10,482,000 SharesIssued – 10,482,000 Shares  Issued – 10,482,000 Shares  
Outstanding – 9,013,000 SharesOutstanding – 9,013,000 Shares157.2 157.2 Outstanding – 9,013,000 Shares157.2 157.2 
Paid-in CapitalPaid-in Capital1,042.6 1,042.6 Paid-in Capital1,040.7 1,042.6 
Retained EarningsRetained Earnings1,198.2 1,218.0 Retained Earnings1,371.1 1,218.0 
Accumulated Other Comprehensive Income (Loss)Accumulated Other Comprehensive Income (Loss)(0.2)1.3 Accumulated Other Comprehensive Income (Loss)(0.2)1.3 
TOTAL COMMON SHAREHOLDER’S EQUITYTOTAL COMMON SHAREHOLDER’S EQUITY2,397.8 2,419.1 TOTAL COMMON SHAREHOLDER’S EQUITY2,568.8 2,419.1 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITYTOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$7,164.6 $6,965.9 TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$7,272.2 $6,965.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
103



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the ThreeNine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
Three Months Ended March 31, Nine Months Ended September 30,
20232022 20232022
OPERATING ACTIVITIESOPERATING ACTIVITIES  OPERATING ACTIVITIES  
Net Income (Loss)$(2.3)$5.8 
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities:  
Net IncomeNet Income$188.1 $155.7 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and AmortizationDepreciation and Amortization61.1 52.7 Depreciation and Amortization187.8 172.7 
Deferred Income TaxesDeferred Income Taxes12.2 (17.4)Deferred Income Taxes(13.6)(20.0)
Allowance for Equity Funds Used During Construction(1.5)(1.1)
Mark-to-Market of Risk Management ContractsMark-to-Market of Risk Management Contracts13.9 1.8 Mark-to-Market of Risk Management Contracts(0.2)(36.1)
Property TaxesProperty Taxes(45.6)(37.8)Property Taxes(14.0)(12.2)
Deferred Fuel Over/Under-Recovery, NetDeferred Fuel Over/Under-Recovery, Net49.4 (26.4)Deferred Fuel Over/Under-Recovery, Net263.3 454.0 
Change in Other Regulatory AssetsChange in Other Regulatory Assets(66.1)3.7 
Change in Other Noncurrent AssetsChange in Other Noncurrent Assets(9.7)(3.9)Change in Other Noncurrent Assets(33.1)(21.8)
Change in Other Noncurrent LiabilitiesChange in Other Noncurrent Liabilities1.4 6.2 Change in Other Noncurrent Liabilities11.0 15.8 
Changes in Certain Components of Working Capital:Changes in Certain Components of Working Capital:  Changes in Certain Components of Working Capital:  
Accounts Receivable, NetAccounts Receivable, Net27.2 11.5 Accounts Receivable, Net11.9 (66.3)
Fuel, Materials and SuppliesFuel, Materials and Supplies12.9 — Fuel, Materials and Supplies(11.6)(25.8)
Accounts PayableAccounts Payable(62.8)(20.8)Accounts Payable(19.5)150.8 
Accrued Taxes, NetAccrued Taxes, Net24.9 45.2 Accrued Taxes, Net(9.5)(20.9)
Other Current AssetsOther Current Assets0.4 1.9 Other Current Assets(3.0)(19.2)
Other Current LiabilitiesOther Current Liabilities(7.5)(1.8)Other Current Liabilities(10.8)11.0 
Net Cash Flows from Operating ActivitiesNet Cash Flows from Operating Activities74.0 15.9 Net Cash Flows from Operating Activities480.7 741.4 
INVESTING ACTIVITIESINVESTING ACTIVITIES  INVESTING ACTIVITIES  
Construction ExpendituresConstruction Expenditures(146.8)(104.1)Construction Expenditures(401.1)(322.6)
Change in Advances to Affiliates, NetChange in Advances to Affiliates, Net(9.2)— 
Acquisitions of Renewable Energy FacilitiesAcquisitions of Renewable Energy Facilities(145.7)(549.3)Acquisitions of Renewable Energy Facilities(145.7)(549.3)
Other Investing ActivitiesOther Investing Activities0.4 0.4 Other Investing Activities8.8 2.9 
Net Cash Flows Used for Investing ActivitiesNet Cash Flows Used for Investing Activities(292.1)(653.0)Net Cash Flows Used for Investing Activities(547.2)(869.0)
FINANCING ACTIVITIESFINANCING ACTIVITIES  FINANCING ACTIVITIES  
Capital Contribution from ParentCapital Contribution from Parent0.6 3.3 
Return of Capital to ParentReturn of Capital to Parent(2.5)— 
Issuance of Long-term Debt – NonaffiliatedIssuance of Long-term Debt – Nonaffiliated469.9 500.0 Issuance of Long-term Debt – Nonaffiliated469.8 499.7 
Change in Advances from Affiliates, NetChange in Advances from Affiliates, Net(233.5)139.5 Change in Advances from Affiliates, Net(364.2)151.2 
Retirement of Long-term Debt – NonaffiliatedRetirement of Long-term Debt – Nonaffiliated(0.1)(0.1)Retirement of Long-term Debt – Nonaffiliated(0.4)(500.4)
Principal Payments for Finance Lease ObligationsPrincipal Payments for Finance Lease Obligations(0.8)(0.8)Principal Payments for Finance Lease Obligations(2.5)(2.4)
Dividends Paid on Common StockDividends Paid on Common Stock(17.5)— Dividends Paid on Common Stock(35.0)(20.0)
Other Financing ActivitiesOther Financing Activities(0.1)0.1 Other Financing Activities0.4 0.4 
Net Cash Flows from Financing ActivitiesNet Cash Flows from Financing Activities217.9 638.7 Net Cash Flows from Financing Activities66.2 131.8 
Net Increase (Decrease) in Cash and Cash EquivalentsNet Increase (Decrease) in Cash and Cash Equivalents(0.2)1.6 Net Increase (Decrease) in Cash and Cash Equivalents(0.3)4.2 
Cash and Cash Equivalents at Beginning of PeriodCash and Cash Equivalents at Beginning of Period4.0 1.3 Cash and Cash Equivalents at Beginning of Period4.0 1.3 
Cash and Cash Equivalents at End of PeriodCash and Cash Equivalents at End of Period$3.8 $2.9 Cash and Cash Equivalents at End of Period$3.7 $5.5 
SUPPLEMENTARY INFORMATIONSUPPLEMENTARY INFORMATION  SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized AmountsCash Paid for Interest, Net of Capitalized Amounts$22.3 $21.3 Cash Paid for Interest, Net of Capitalized Amounts$67.4 $63.1 
Net Cash Paid (Received) for Income TaxesNet Cash Paid (Received) for Income Taxes(1.6)21.9 
Noncash Acquisitions Under Finance LeasesNoncash Acquisitions Under Finance Leases0.2 0.3 Noncash Acquisitions Under Finance Leases1.9 1.7 
Construction Expenditures Included in Current Liabilities as of March 31,63.4 37.1 
Construction Expenditures Included in Current Liabilities as of September 30,Construction Expenditures Included in Current Liabilities as of September 30,91.0 50.1 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

104





SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

105



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


RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
Three Months EndedNine Months Ended
Three Months Ended March 31, September 30,September 30,
20232022 2023202220232022
(in millions of KWhs) (in millions of KWhs)
Retail:Retail:  Retail:    
ResidentialResidential1,351 1,636 Residential2,180 2,019 4,902 5,157 
CommercialCommercial1,168 1,266 Commercial1,689 1,631 4,269 4,385 
IndustrialIndustrial1,203 1,115 Industrial1,313 1,367 3,876 3,876 
MiscellaneousMiscellaneous17 18 Miscellaneous17 17 53 55 
Total RetailTotal Retail3,739 4,035 Total Retail5,199 5,034 13,100 13,473 
WholesaleWholesale1,270 1,759 Wholesale1,668 1,744 4,226 5,312 
Total KWhsTotal KWhs5,009 5,794 Total KWhs6,867 6,778 17,326 18,785 

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

Summary of Heating and Cooling Degree Days
Three Months EndedNine Months Ended
Three Months Ended March 31, September 30,September 30,
20232022 2023202220232022
(in degree days) (in degree days)
Actual – Heating (a)Actual – Heating (a)401 694 Actual – Heating (a)— — 413 704 
Normal – Heating (b)Normal – Heating (b)705 700 Normal – Heating (b)— — 730 726 
Actual – Cooling (c)Actual – Cooling (c)107 30 Actual – Cooling (c)1,715 1,627 2,673 2,642 
Normal – Cooling (b)Normal – Cooling (b)40 40 Normal – Cooling (b)1,435 1,420 2,223 2,195 

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


106105



First Quarter of 2023 Compared to First Quarter of 2022
Reconciliation of First Quarter of 2022 to First Quarter of 2023
Earnings Attributable to SWEPCo Common Shareholder
(in millions)
First Quarter of 2022$44.1 
Changes in Gross Margin:
Retail Margins (a)4.4 
Margins from Off-system Sales(1.6)
Transmission Revenues7.2 
Total Change in Gross Margin10.0 
Changes in Expenses and Other:
Other Operation and Maintenance(15.3)
Depreciation and Amortization(2.6)
Taxes Other Than Income Taxes(6.3)
Interest Income1.8 
Allowance for Equity Funds Used During Construction(1.1)
Non-Service Cost Components of Net Periodic Benefit Cost0.3 
Interest Expense8.1 
Total Change in Expenses and Other(15.1)
Income Tax Expense1.8 
Net Income Attributable to Noncontrolling Interest(0.2)
First Quarter of 2023$40.6 
Reconciliation of 2022 to 2023
Earnings Attributable to SWEPCo Common Shareholder
(in millions)
Three Months Ended 
September 30,
Nine Months Ended 
September 30,
2022 Earnings Attributable to Common Shareholder$139.4 $260.2 
  
Changes in Gross Margin: 
Retail Margins (a)24.2 23.0 
Margins from Off-system Sales(8.2)(10.5)
Transmission Revenues(1.9)3.1 
Other Revenues(1.3)(1.5)
Total Change in Gross Margin12.8 14.1 
  
Changes in Expenses and Other: 
Other Operation and Maintenance11.7 14.1 
Depreciation and Amortization(4.8)(15.0)
Taxes Other Than Income Taxes(2.0)(9.5)
Interest Income1.4 0.9 
Allowance for Equity Funds Used During Construction3.3 3.9 
Non-Service Cost Components of Net Periodic Benefit Cost0.2 0.8 
Interest Expense(6.9)(5.2)
Total Change in Expenses and Other2.9 (10.0)
  
Income Tax Benefit3.9 14.7 
Net Income Attributable to Noncontrolling Interest(1.5)0.1 
  
2023 Earnings Attributable to Common Shareholder$157.5 $279.1 

(a)Includes firm wholesale sales to municipals and cooperatives.
Third Quarter of 2023 Compared to Third Quarter of 2022

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

Retail Margins increased $4$24 million primarily due to the following:
A $22$23 million increase due to a base rate revenue increase in Louisiana and rider increases in Texas and Louisiana retail jurisdictions. These increases were partially offset in other expense items below.
A $5 million increase in weather-related usage primarily due to a 5% increase in cooling degree days.
These increases were partially offset by:
An $8 million decrease due to an increase in PTC benefits provided to customers. This decrease was offset in Income Tax Benefit.
Margins from Off-System Sales decreased $8 million primarily due to reduced Turk Plant merchant sales.

Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses decreased $12 million primarily due to the following:
A $9 million decrease in transmission expenses primarily due to a $4 million decrease in recoverable SPP transmission expenses and a $4 million decrease in transmission formula rate true-up activity. The decrease in SPP transmission expenses was offset in Retail Margins above.
106


Depreciation and Amortization increased $5 million primarily due to an increase in amortization of regulatory assets. This increase was offset in Retail Margins above.
Interest Expense increased $7 million primarily due to the amortization of carrying charges on storm-related regulatory assets. This increase was offset in Retail Margins above.

Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022

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

Retail Margins increased $23 million primarily due to the following:
A $58 million increase primarily due to base rate revenue increases in Arkansas and Louisiana and rider increases in all retail jurisdictions. These increases were partially offset in other expense items below.
A $4 millionThis increase in fuel revenues due to increased carrying charges on fuel under-recovery balances.
These increases werewas partially offset by:
A $14 million decrease in weather-related usage primarily due to a 41% decrease in heating degree days.
A $12 million decrease due to an increase in PTC benefits provided to customers. This decrease was offset in Income Tax Benefit below.
An $11 million decrease in weather-normalized margins primarily in the residential and commercial classes.wholesale classes, partially offset by an increase in the industrial class.
A $9 million decrease in weather-related usage primarily due to a 42% decrease in heating degree days.
Transmission RevenuesMargins from Off-system Sales increased $7decreased $11 million primarily due to the reversal of a prior period provision for refund.reduced Turk Plant merchant sales.

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

Other Operation and Maintenance expenses increased $15decreased $14 million primarily due to the following:
A $7$10 million increase in generation-related expenses.decrease due to the capitalization of previously expensed renewable generation pre-construction charges.
A $5$7 million increasedecrease due to legislation passed in Texas in May 2023 allowing employee financially based incentives to be recovered.
A $7 million decrease in transmission expenses primarily due to overhead line maintenance.a change in rider recovery.
These decreases were partially offset by:
An $8 million increase in accounts receivable factoring expenses primarily due to increased interest rates.
Depreciation and Amortization expenses increased $15 million primarily due to an increase in amortization of regulatory assets. This increase was offset in Retail Margins above.
Taxes Other Than Income Taxes increased $6$10 million primarily due to increased property taxes driven by the investment in the NCWF.
Interest Expense decreased $8increased $5 million primarily due to a settlement agreement in Louisiana which provided forhigher long-term debt balances and interest rates.
Income Tax Benefit increased $15 million primarily due to the following:
A $12 million of carrying charges on storm-related regulatory assets.increase in PTCs. This increase was offset in Retail Margins above.
A $4 million increase due to a decrease in state tax expense.
107




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
Three Months Ended March 31,
 20232022
REVENUES  
Electric Generation, Transmission and Distribution$503.7 $484.2 
Sales to AEP Affiliates11.7 10.0 
Other Revenues0.5 0.6 
TOTAL REVENUES515.9 494.8 
EXPENSES  
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation209.3 198.2 
Other Operation99.2 91.5 
Maintenance37.7 30.1 
Depreciation and Amortization80.4 77.8 
Taxes Other Than Income Taxes36.1 29.8 
TOTAL EXPENSES462.7 427.4 
OPERATING INCOME53.2 67.4 
Other Income (Expense): 
Interest Income5.4 3.6 
Allowance for Equity Funds Used During Construction0.5 1.6 
Non-Service Cost Components of Net Periodic Benefit Cost3.4 3.1 
Interest Expense(25.0)(33.1)
INCOME BEFORE INCOME TAX BENEFIT AND EQUITY EARNINGS37.5 42.6 
Income Tax Benefit(4.0)(2.2)
Equity Earnings of Unconsolidated Subsidiary0.3 0.3 
NET INCOME41.8 45.1 
Net Income Attributable to Noncontrolling Interest1.2 1.0 
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER$40.6 $44.1 
The common stock of SWEPCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
Three Months EndedNine Months Ended
 September 30,September 30,
 2023202220232022
REVENUES    
Electric Generation, Transmission and Distribution$639.8 $698.8 $1,666.0 $1,703.7 
Sales to AEP Affiliates14.5 18.2 40.7 43.7 
Other Revenues0.5 0.5 1.8 1.5 
TOTAL REVENUES654.8 717.5 1,708.5 1,748.9 
EXPENSES    
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation215.4 290.9 614.6 669.1 
Other Operation96.9 114.1 281.3 308.7 
Maintenance38.4 32.9 121.1 107.8 
Depreciation and Amortization100.6 95.8 266.8 251.8 
Taxes Other Than Income Taxes36.2 34.2 104.4 94.9 
TOTAL EXPENSES487.5 567.9 1,388.2 1,432.3 
OPERATING INCOME167.3 149.6 320.3 316.6 
Other Income (Expense):   
Interest Income4.1 2.7 14.8 13.9 
Allowance for Equity Funds Used During Construction4.3 1.0 7.3 3.4 
Non-Service Cost Components of Net Periodic Benefit Cost3.4 3.2 10.2 9.4 
Interest Expense(42.1)(35.2)(107.2)(102.0)
INCOME BEFORE INCOME TAX BENEFIT AND EQUITY EARNINGS137.0 121.3 245.4 241.3 
Income Tax Benefit(21.7)(17.8)(35.7)(21.0)
Equity Earnings of Unconsolidated Subsidiary0.3 0.3 1.0 1.0 
NET INCOME159.0 139.4 282.1 263.3 
Net Income Attributable to Noncontrolling Interest1.5 — 3.0 3.1 
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER$157.5 $139.4 $279.1 $260.2 
The common stock of SWEPCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
108



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
Three Months EndedNine Months Ended
September 30,September 30,
Three Months Ended March 31,
20232022 2023202220232022
Net IncomeNet Income$41.8 $45.1 Net Income$159.0 $139.4 $282.1 $263.3 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXESOTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES  OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES    
Cash Flow Hedges, Net of Tax of $0.1 and $0 in 2023 and 2022, Respectively0.4 0.1 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) in 2023 and 2022, Respectively(0.3)(0.4)
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2023 and 2022, Respectively, and $0.1 and $0 for the Nine Months Ended September 30, 2023 and 2022, RespectivelyCash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2023 and 2022, Respectively, and $0.1 and $0 for the Nine Months Ended September 30, 2023 and 2022, Respectively— — 0.3 — 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2023 and 2022, Respectively, and $(0.3) and $(0.3) for the Nine Months Ended September 30, 2023 and 2022, RespectivelyAmortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2023 and 2022, Respectively, and $(0.3) and $(0.3) for the Nine Months Ended September 30, 2023 and 2022, Respectively(0.4)(0.4)(1.0)(1.2)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)0.1 (0.3)
TOTAL OTHER COMPREHENSIVE LOSSTOTAL OTHER COMPREHENSIVE LOSS(0.4)(0.4)(0.7)(1.2)
TOTAL COMPREHENSIVE INCOMETOTAL COMPREHENSIVE INCOME41.9 44.8 TOTAL COMPREHENSIVE INCOME158.6 139.0 281.4 262.1 
Total Comprehensive Income Attributable to Noncontrolling InterestTotal Comprehensive Income Attributable to Noncontrolling Interest1.2 1.0 Total Comprehensive Income Attributable to Noncontrolling Interest1.5 — 3.0 3.1 
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDERTOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER$40.7 $43.8 TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER$157.1 $139.0 $278.4 $259.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
109



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the ThreeNine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
SWEPCo Common Shareholder  SWEPCo Common Shareholder  
Common
Stock
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Noncontrolling
Interest
TotalCommon
Stock
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Noncontrolling
Interest
Total
TOTAL EQUITY – DECEMBER 31, 2021TOTAL EQUITY – DECEMBER 31, 2021$0.1 $1,092.2 $2,050.9 $6.7 $(0.1)$3,149.8 TOTAL EQUITY – DECEMBER 31, 2021$0.1 $1,092.2 $2,050.9 $6.7 $(0.1)$3,149.8 
Capital Contribution from ParentCapital Contribution from Parent350.0350.0 Capital Contribution from Parent350.0350.0 
Common Stock Dividends – NonaffiliatedCommon Stock Dividends – Nonaffiliated(0.8)(0.8)Common Stock Dividends – Nonaffiliated(0.8)(0.8)
Net IncomeNet Income44.1 1.0 45.1 Net Income44.1 1.0 45.1 
Other Comprehensive LossOther Comprehensive Loss(0.3)(0.3)Other Comprehensive Loss(0.3)(0.3)
TOTAL EQUITY – MARCH 31, 2022TOTAL EQUITY – MARCH 31, 2022$0.1 $1,442.2 $2,095.0 $6.4 $0.1 $3,543.8 TOTAL EQUITY – MARCH 31, 20220.1 1,442.2 2,095.0 6.4 0.1 3,543.8 
Capital Contribution from ParentCapital Contribution from Parent2.22.2 
Common Stock DividendsCommon Stock Dividends(12.5)(12.5)
Common Stock Dividends – NonaffiliatedCommon Stock Dividends – Nonaffiliated    (0.7)(0.7)
Net IncomeNet Income  76.7  2.1 78.8 
Other Comprehensive LossOther Comprehensive Loss   (0.5) (0.5)
TOTAL EQUITY – JUNE 30, 2022TOTAL EQUITY – JUNE 30, 20220.1 1,444.4 2,159.2 5.9 1.5 3,611.1 
Capital Contribution from ParentCapital Contribution from Parent1.1 1.1 
Common Stock DividendsCommon Stock Dividends(45.0)(45.0)
Common Stock Dividends – NonaffiliatedCommon Stock Dividends – Nonaffiliated(1.1)(1.1)
Net IncomeNet Income139.4 — 139.4 
Other Comprehensive LossOther Comprehensive Loss(0.4)(0.4)
TOTAL EQUITY – SEPTEMBER 30, 2022TOTAL EQUITY – SEPTEMBER 30, 2022$0.1 $1,445.5 $2,253.6 $5.5 $0.4 $3,705.1 
TOTAL EQUITY – DECEMBER 31, 2022TOTAL EQUITY – DECEMBER 31, 2022$0.1 $1,442.2 $2,236.0 $(4.2)$0.7 $3,674.8 TOTAL EQUITY – DECEMBER 31, 2022$0.1 $1,442.2 $2,236.0 $(4.2)$0.7 $3,674.8 
Capital Contribution from ParentCapital Contribution from Parent50.0 50.0 Capital Contribution from Parent50.0 50.0 
Common Stock Dividends – NonaffiliatedCommon Stock Dividends – Nonaffiliated(1.5)(1.5)Common Stock Dividends – Nonaffiliated(1.5)(1.5)
Net IncomeNet Income40.6 1.2 41.8 Net Income40.6 1.2 41.8 
Other Comprehensive IncomeOther Comprehensive Income0.1 0.1 Other Comprehensive Income0.1 0.1 
TOTAL EQUITY – MARCH 31, 2023TOTAL EQUITY – MARCH 31, 2023$0.1 $1,492.2 $2,276.6 $(4.1)$0.4 $3,765.2 TOTAL EQUITY – MARCH 31, 20230.1 1,492.2 2,276.6 (4.1)0.4 3,765.2 
Common Stock DividendsCommon Stock Dividends  (50.0)  (50.0)
Common Stock Dividends – NonaffiliatedCommon Stock Dividends – Nonaffiliated    (0.6)(0.6)
Net IncomeNet Income  81.0  0.3 81.3 
Other Comprehensive LossOther Comprehensive Loss   (0.4) (0.4)
TOTAL EQUITY – JUNE 30, 2023TOTAL EQUITY – JUNE 30, 20230.1 1,492.2 2,307.6 (4.5)0.1 3,795.5 
Common Stock DividendsCommon Stock Dividends(75.0)(75.0)
Common Stock Dividends – NonaffiliatedCommon Stock Dividends – Nonaffiliated(0.3)(0.3)
Net IncomeNet Income157.5 1.5 159.0 
Other Comprehensive LossOther Comprehensive Loss(0.4)(0.4)
TOTAL EQUITY – SEPTEMBER 30, 2023TOTAL EQUITY – SEPTEMBER 30, 2023$0.1 $1,492.2 $2,390.1 $(4.9)$1.3 $3,878.8 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
110



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31,September 30, 2023 and December 31, 2022
(in millions)
(Unaudited)
March 31,December 31, September 30,December 31,
20232022 20232022
CURRENT ASSETSCURRENT ASSETS  CURRENT ASSETS  
Cash and Cash Equivalents
(March 31, 2023 and December 31, 2022 Amounts Include $3.9 and $84.2, Respectively, Related to Sabine)
$8.2 $88.4 
Cash and Cash Equivalents
(September 30, 2023 and December 31, 2022 Amounts Include $0 and $84.2, Respectively, Related to Sabine)
Cash and Cash Equivalents
(September 30, 2023 and December 31, 2022 Amounts Include $0 and $84.2, Respectively, Related to Sabine)
$3.6 $88.4 
Advances to AffiliatesAdvances to Affiliates2.1 2.1 Advances to Affiliates2.7 2.1 
Accounts Receivable:Accounts Receivable:  Accounts Receivable:  
CustomersCustomers33.9 38.8 Customers32.9 38.8 
Affiliated CompaniesAffiliated Companies38.9 65.4 Affiliated Companies43.8 65.4 
MiscellaneousMiscellaneous11.9 10.4 Miscellaneous8.3 10.4 
Allowance for Uncollectible AccountsAllowance for Uncollectible Accounts(0.1)— 
Total Accounts ReceivableTotal Accounts Receivable84.7 114.6 Total Accounts Receivable84.9 114.6 
Fuel
(March 31, 2023 and December 31, 2022 Amounts Include $0 and $14.2, Respectively, Related to Sabine)
90.6 81.3 
Materials and Supplies
(March 31, 2023 and December 31, 2022 Amounts Include $4.2 and $4.2, Respectively, Related to Sabine)
84.5 92.1 
Fuel
(September 30, 2023 and December 31, 2022 Amounts Include $0 and $14.2, Respectively, Related to Sabine)
Fuel
(September 30, 2023 and December 31, 2022 Amounts Include $0 and $14.2, Respectively, Related to Sabine)
94.2 81.3 
Materials and Supplies
(September 30, 2023 and December 31, 2022 Amounts Include $3.9 and $4.2, Respectively, Related to Sabine)
Materials and Supplies
(September 30, 2023 and December 31, 2022 Amounts Include $3.9 and $4.2, Respectively, Related to Sabine)
88.6 92.1 
Risk Management AssetsRisk Management Assets6.3 16.4 Risk Management Assets17.1 16.4 
Accrued Tax BenefitsAccrued Tax Benefits33.7 16.5 Accrued Tax Benefits78.1 16.5 
Regulatory Asset for Under-Recovered Fuel CostsRegulatory Asset for Under-Recovered Fuel Costs326.5 353.0 Regulatory Asset for Under-Recovered Fuel Costs184.4 353.0 
Prepayments and Other Current AssetsPrepayments and Other Current Assets41.9 47.8 Prepayments and Other Current Assets38.9 47.8 
TOTAL CURRENT ASSETSTOTAL CURRENT ASSETS678.5 812.2 TOTAL CURRENT ASSETS592.5 812.2 
PROPERTY, PLANT AND EQUIPMENTPROPERTY, PLANT AND EQUIPMENT  PROPERTY, PLANT AND EQUIPMENT  
Electric:Electric:  Electric:  
GenerationGeneration4,870.3 5,476.2 Generation4,892.8 5,476.2 
TransmissionTransmission2,481.5 2,479.8 Transmission2,557.0 2,479.8 
DistributionDistribution2,691.1 2,659.6 Distribution2,769.9 2,659.6 
Other Property, Plant and Equipment
(March 31, 2023 and December 31, 2022 Amounts Include $187.8 and $219.8, Respectively, Related to Sabine)
785.7 804.4 
Other Property, Plant and Equipment
(September 30, 2023 and December 31, 2022 Amounts Include $185 and $219.8, Respectively, Related to Sabine)
Other Property, Plant and Equipment
(September 30, 2023 and December 31, 2022 Amounts Include $185 and $219.8, Respectively, Related to Sabine)
801.7 804.4 
Construction Work in ProgressConstruction Work in Progress470.4 369.5 Construction Work in Progress598.2 369.5 
Total Property, Plant and EquipmentTotal Property, Plant and Equipment11,299.0 11,789.5 Total Property, Plant and Equipment11,619.6 11,789.5 
Accumulated Depreciation and Amortization
(March 31, 2023 and December 31, 2022 Amounts Include $187.8 and $212.5, Respectively, Related to Sabine)
2,956.4 3,527.3 
Accumulated Depreciation and Amortization
(September 30, 2023 and December 31, 2022 Amounts Include $185 and $212.5, Respectively, Related to Sabine)
Accumulated Depreciation and Amortization
(September 30, 2023 and December 31, 2022 Amounts Include $185 and $212.5, Respectively, Related to Sabine)
3,057.1 3,527.3 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NETTOTAL PROPERTY, PLANT AND EQUIPMENT – NET8,342.6 8,262.2 TOTAL PROPERTY, PLANT AND EQUIPMENT – NET8,562.5 8,262.2 
OTHER NONCURRENT ASSETSOTHER NONCURRENT ASSETS  OTHER NONCURRENT ASSETS  
Regulatory AssetsRegulatory Assets1,040.9 1,042.4 Regulatory Assets1,116.9 1,042.4 
Deferred Charges and Other Noncurrent AssetsDeferred Charges and Other Noncurrent Assets334.6 262.0 Deferred Charges and Other Noncurrent Assets289.2 262.0 
TOTAL OTHER NONCURRENT ASSETSTOTAL OTHER NONCURRENT ASSETS1,375.5 1,304.4 TOTAL OTHER NONCURRENT ASSETS1,406.1 1,304.4 
TOTAL ASSETSTOTAL ASSETS$10,396.6 $10,378.8 TOTAL ASSETS$10,561.1 $10,378.8 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
111



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
March 31,September 30, 2023 and December 31, 2022
(Unaudited)
March 31,December 31, September 30,December 31,
20232022 20232022
(in millions) (in millions)
CURRENT LIABILITIESCURRENT LIABILITIES  CURRENT LIABILITIES  
Advances from AffiliatesAdvances from Affiliates$18.8 $310.7 Advances from Affiliates$48.9 $310.7 
Accounts Payable:Accounts Payable:  Accounts Payable:  
GeneralGeneral188.9 213.1 General232.1 213.1 
Affiliated CompaniesAffiliated Companies51.5 81.7 Affiliated Companies31.3 81.7 
Short-term Debt – NonaffiliatedShort-term Debt – Nonaffiliated16.0 — Short-term Debt – Nonaffiliated3.9 — 
Long-term Debt Due Within One Year – NonaffiliatedLong-term Debt Due Within One Year – Nonaffiliated— 6.2 Long-term Debt Due Within One Year – Nonaffiliated— 6.2 
Customer DepositsCustomer Deposits68.7 65.4 Customer Deposits71.5 65.4 
Accrued TaxesAccrued Taxes132.3 52.8 Accrued Taxes123.8 52.8 
Accrued InterestAccrued Interest27.9 36.0 Accrued Interest38.3 36.0 
Obligations Under Operating LeasesObligations Under Operating Leases8.9 8.4 Obligations Under Operating Leases9.4 8.4 
Asset Retirement ObligationsAsset Retirement Obligations43.7 43.7 Asset Retirement Obligations43.7 43.7 
Other Current LiabilitiesOther Current Liabilities105.7 129.7 Other Current Liabilities97.0 129.7 
TOTAL CURRENT LIABILITIESTOTAL CURRENT LIABILITIES662.4 947.7 TOTAL CURRENT LIABILITIES699.9 947.7 
NONCURRENT LIABILITIESNONCURRENT LIABILITIES  NONCURRENT LIABILITIES  
Long-term Debt – NonaffiliatedLong-term Debt – Nonaffiliated3,644.8 3,385.4 Long-term Debt – Nonaffiliated3,646.2 3,385.4 
Deferred Income TaxesDeferred Income Taxes1,103.7 1,089.7 Deferred Income Taxes1,162.5 1,089.7 
Regulatory Liabilities and Deferred Investment Tax CreditsRegulatory Liabilities and Deferred Investment Tax Credits776.5 825.7 Regulatory Liabilities and Deferred Investment Tax Credits760.3 825.7 
Asset Retirement ObligationsAsset Retirement Obligations236.9 237.2 Asset Retirement Obligations218.1 237.2 
Employee Benefits and Pension ObligationsEmployee Benefits and Pension Obligations29.5 29.7 Employee Benefits and Pension Obligations30.5 29.7 
Obligations Under Operating LeasesObligations Under Operating Leases121.4 120.2 Obligations Under Operating Leases123.8 120.2 
Deferred Credits and Other Noncurrent LiabilitiesDeferred Credits and Other Noncurrent Liabilities56.2 68.4 Deferred Credits and Other Noncurrent Liabilities41.0 68.4 
TOTAL NONCURRENT LIABILITIESTOTAL NONCURRENT LIABILITIES5,969.0 5,756.3 TOTAL NONCURRENT LIABILITIES5,982.4 5,756.3 
TOTAL LIABILITIESTOTAL LIABILITIES6,631.4 6,704.0 TOTAL LIABILITIES6,682.3 6,704.0 
Rate Matters (Note 4)Rate Matters (Note 4)Rate Matters (Note 4)
Commitments and Contingencies (Note 5)Commitments and Contingencies (Note 5)Commitments and Contingencies (Note 5)
EQUITYEQUITY  EQUITY  
Common Stock – Par Value – $18 Per Share:Common Stock – Par Value – $18 Per Share:  Common Stock – Par Value – $18 Per Share:  
Authorized – 3,680 SharesAuthorized – 3,680 Shares  Authorized – 3,680 Shares  
Outstanding – 3,680 SharesOutstanding – 3,680 Shares0.1 0.1 Outstanding – 3,680 Shares0.1 0.1 
Paid-in CapitalPaid-in Capital1,492.2 1,442.2 Paid-in Capital1,492.2 1,442.2 
Retained EarningsRetained Earnings2,276.6 2,236.0 Retained Earnings2,390.1 2,236.0 
Accumulated Other Comprehensive Income (Loss)Accumulated Other Comprehensive Income (Loss)(4.1)(4.2)Accumulated Other Comprehensive Income (Loss)(4.9)(4.2)
TOTAL COMMON SHAREHOLDER’S EQUITYTOTAL COMMON SHAREHOLDER’S EQUITY3,764.8 3,674.1 TOTAL COMMON SHAREHOLDER’S EQUITY3,877.5 3,674.1 
Noncontrolling InterestNoncontrolling Interest0.4 0.7 Noncontrolling Interest1.3 0.7 
TOTAL EQUITYTOTAL EQUITY3,765.2 3,674.8 TOTAL EQUITY3,878.8 3,674.8 
TOTAL LIABILITIES AND EQUITYTOTAL LIABILITIES AND EQUITY$10,396.6 $10,378.8 TOTAL LIABILITIES AND EQUITY$10,561.1 $10,378.8 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
112



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the ThreeNine Months Ended March 31,September 30, 2023 and 2022
(in millions)
(Unaudited)
Three Months Ended March 31, Nine Months Ended September 30,
20232022 20232022
OPERATING ACTIVITIESOPERATING ACTIVITIES  OPERATING ACTIVITIES  
Net IncomeNet Income$41.8 $45.1 Net Income$282.1 $263.3 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and AmortizationDepreciation and Amortization80.4 77.8 Depreciation and Amortization266.8 251.8 
Deferred Income TaxesDeferred Income Taxes10.8 (9.5)Deferred Income Taxes44.9 7.5 
Allowance for Equity Funds Used During ConstructionAllowance for Equity Funds Used During Construction(0.5)(1.6)Allowance for Equity Funds Used During Construction(7.3)(3.4)
Mark-to-Market of Risk Management ContractsMark-to-Market of Risk Management Contracts9.9 (7.0)Mark-to-Market of Risk Management Contracts1.4 (27.6)
Property TaxesProperty Taxes(77.5)(64.5)Property Taxes(24.6)(22.0)
Deferred Fuel Over/Under-Recovery, NetDeferred Fuel Over/Under-Recovery, Net42.9 9.2 Deferred Fuel Over/Under-Recovery, Net134.4 (82.0)
Change in Regulatory AssetsChange in Regulatory Assets(36.7)3.1 
Change in Other Noncurrent AssetsChange in Other Noncurrent Assets7.2 29.9 Change in Other Noncurrent Assets(10.2)52.0 
Change in Other Noncurrent LiabilitiesChange in Other Noncurrent Liabilities(3.3)16.7 Change in Other Noncurrent Liabilities(26.7)17.3 
Changes in Certain Components of Working Capital:Changes in Certain Components of Working Capital:  Changes in Certain Components of Working Capital:  
Accounts Receivable, NetAccounts Receivable, Net29.9 7.6 Accounts Receivable, Net29.7 (17.9)
Fuel, Materials and SuppliesFuel, Materials and Supplies(4.3)(0.6)Fuel, Materials and Supplies(12.0)23.5 
Accounts PayableAccounts Payable(47.8)(35.1)Accounts Payable5.3 78.9 
Accrued Taxes, NetAccrued Taxes, Net62.3 75.7 Accrued Taxes, Net10.8 (1.1)
Other Current AssetsOther Current Assets7.3 3.8 Other Current Assets10.4 (12.0)
Other Current LiabilitiesOther Current Liabilities(48.9)(56.7)Other Current Liabilities(40.6)(38.1)
Net Cash Flows from Operating ActivitiesNet Cash Flows from Operating Activities110.2 90.8 Net Cash Flows from Operating Activities627.7 493.3 
INVESTING ACTIVITIESINVESTING ACTIVITIES  INVESTING ACTIVITIES  
Construction ExpendituresConstruction Expenditures(201.9)(129.5)Construction Expenditures(614.1)(397.0)
Change in Advances to Affiliates, NetChange in Advances to Affiliates, Net— 153.8 Change in Advances to Affiliates, Net(0.6)153.8 
Acquisition of the North Central Wind Energy FacilitiesAcquisition of the North Central Wind Energy Facilities— (658.0)Acquisition of the North Central Wind Energy Facilities— (658.0)
Other Investing ActivitiesOther Investing Activities0.4 1.9 Other Investing Activities1.8 3.9 
Net Cash Flows Used for Investing ActivitiesNet Cash Flows Used for Investing Activities(201.5)(631.8)Net Cash Flows Used for Investing Activities(612.9)(897.3)
FINANCING ACTIVITIESFINANCING ACTIVITIES  FINANCING ACTIVITIES  
Capital Contribution from ParentCapital Contribution from Parent50.0 350.0 Capital Contribution from Parent50.0 353.3 
Issuance of Long-term Debt – NonaffiliatedIssuance of Long-term Debt – Nonaffiliated347.3 — Issuance of Long-term Debt – Nonaffiliated346.8 — 
Change in Short-term Debt – NonaffiliatedChange in Short-term Debt – Nonaffiliated16.0 — Change in Short-term Debt – Nonaffiliated3.9 — 
Change in Advances from Affiliates, NetChange in Advances from Affiliates, Net(291.9)202.9 Change in Advances from Affiliates, Net(261.8)156.3 
Retirement of Long-term Debt – NonaffiliatedRetirement of Long-term Debt – Nonaffiliated(94.1)(1.6)Retirement of Long-term Debt – Nonaffiliated(94.1)(4.7)
Principal Payments for Finance Lease ObligationsPrincipal Payments for Finance Lease Obligations(14.8)(2.7)Principal Payments for Finance Lease Obligations(17.6)(8.0)
Dividends Paid on Common StockDividends Paid on Common Stock(125.0)(57.5)
Dividends Paid on Common Stock – NonaffiliatedDividends Paid on Common Stock – Nonaffiliated(1.5)(0.8)Dividends Paid on Common Stock – Nonaffiliated(2.4)(2.6)
Other Financing ActivitiesOther Financing Activities0.1 0.1 Other Financing Activities0.6 0.4 
Net Cash Flows from Financing Activities11.1 547.9 
Net Cash Flows from (Used for) Financing ActivitiesNet Cash Flows from (Used for) Financing Activities(99.6)437.2 
Net Increase (Decrease) in Cash and Cash EquivalentsNet Increase (Decrease) in Cash and Cash Equivalents(80.2)6.9 Net Increase (Decrease) in Cash and Cash Equivalents(84.8)33.2 
Cash and Cash Equivalents at Beginning of PeriodCash and Cash Equivalents at Beginning of Period88.4 51.2 Cash and Cash Equivalents at Beginning of Period88.4 51.2 
Cash and Cash Equivalents at End of PeriodCash and Cash Equivalents at End of Period$8.2 $58.1 Cash and Cash Equivalents at End of Period$3.6 $84.4 
SUPPLEMENTARY INFORMATIONSUPPLEMENTARY INFORMATION  SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized AmountsCash Paid for Interest, Net of Capitalized Amounts$45.3 $37.7 Cash Paid for Interest, Net of Capitalized Amounts$89.8 $102.1 
Net Cash Paid (Received) for Income TaxesNet Cash Paid (Received) for Income Taxes(23.3)34.7 
Noncash Acquisitions Under Finance LeasesNoncash Acquisitions Under Finance Leases0.9 1.0 Noncash Acquisitions Under Finance Leases4.6 3.2 
Construction Expenditures Included in Current Liabilities as of March 31,113.3 47.8 
Construction Expenditures Included in Current Liabilities as of September 30,Construction Expenditures Included in Current Liabilities as of September 30,69.0 71.8 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
113



INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANTS

The condensed notes to condensed financial statements are a combined presentation for the Registrants. The following list indicates Registrants to which the notes apply. Specific disclosures within each note apply to all Registrants unless indicated otherwise:
NoteRegistrantPage
Number
Significant Accounting MattersAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
New Accounting StandardsAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Comprehensive IncomeAEP AEP Texas, APCo, I&M, PSO, SWEPCo
Rate MattersAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Commitments, Guarantees and ContingenciesAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Acquisitions, Dispositions and Assets and Liabilities Held for SaleImpairmentsAEP, AEPTCo, PSO, SWEPCo
Benefit PlansAEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo
Business SegmentsAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Derivatives and HedgingAEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo
Fair Value MeasurementsAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Income TaxesAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Financing ActivitiesAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Variable Interest EntitiesAEP
Property, Plant and EquipmentAEP, SWEPCo
Revenue from Contracts with CustomersAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
114



1.  SIGNIFICANT ACCOUNTING MATTERS

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

General

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

In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair statement of the net income, financial position and cash flows for the interim periods for each Registrant.  Net income for the three and nine months ended March 31,September 30, 2023 is not necessarily indicative of results that may be expected for the year ending December 31, 2023.  The condensed financial statements are unaudited and should be read in conjunction with the audited 2022 financial statements and notes thereto, which are included in the Registrants’ Annual Reports on Form 10-K as filed with the SEC on February 23, 2023.

Earnings Per Share (EPS) (Applies to AEP)

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

The following table presents AEP’s basic and diluted EPS calculations included on the statements of income:
Three Months Ended March 31,
20232022
(in millions, except per share data)
 $/share$/share
Earnings Attributable to AEP Common Shareholders$397.0  $714.7  
Weighted-Average Number of Basic AEP Common Shares Outstanding514.2 $0.77 506.1 $1.41 
Weighted-Average Dilutive Effect of Stock-Based Awards1.4 — 1.6 — 
Weighted-Average Number of Diluted AEP Common Shares Outstanding515.6 $0.77 507.7 $1.41 

Equity Units are potentially dilutive securities and were excluded from the calculation of diluted EPS for the three months ended March 31, 2023 and 2022, as the dilutive stock price threshold was not met. See Note 12 - Financing Activities for more information related to Equity Units.
Three Months Ended September 30,
20232022
(in millions, except per share data)
 $/share$/share
Earnings Attributable to AEP Common Shareholders$953.7  $683.7  
Weighted-Average Number of Basic AEP Common Shares Outstanding520.5 $1.83 513.7 $1.33 
Weighted-Average Dilutive Effect of Stock-Based Awards0.9 — 1.6 — 
Weighted-Average Number of Diluted AEP Common Shares Outstanding521.4 $1.83 515.3 $1.33 
Nine Months Ended September 30,
20232022
(in millions, except per share data)
 $/share$/share
Earnings Attributable to AEP Common Shareholders$1,871.9  $1,922.9  
Weighted-Average Number of Basic AEP Common Shares Outstanding516.5 $3.62 511.2 $3.76 
Weighted-Average Dilutive Effect of Stock-Based Awards1.3 — 1.5 (0.01)
Weighted-Average Number of Diluted AEP Common Shares Outstanding517.8 $3.62 512.7 $3.75 

There were no antidilutive shares outstanding as of March 31,September 30, 2023 and 2022, respectively.


115



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

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

Reconciliation of Cash, Cash Equivalents and Restricted Cash

The following tables provide a reconciliation of Cash, Cash Equivalents and Restricted Cash reported within the balance sheets that sum to the total of the same amounts shown on the statements of cash flows:
March 31, 2023September 30, 2023
AEPAEP TexasAPCoAEPAEP TexasAPCo
(in millions)(in millions)
Cash and Cash EquivalentsCash and Cash Equivalents$343.5 $0.1 $7.1 Cash and Cash Equivalents$353.3 $0.1 $4.5 
Restricted CashRestricted Cash50.0 42.5 7.5 Restricted Cash53.8 46.9 6.9 
Total Cash, Cash Equivalents and Restricted CashTotal Cash, Cash Equivalents and Restricted Cash$393.5 $42.6 $14.6 Total Cash, Cash Equivalents and Restricted Cash$407.1 $47.0 $11.4 

December 31, 2022
AEPAEP TexasAPCo
(in millions)
Cash and Cash Equivalents$509.4 $0.1 $7.5 
Restricted Cash47.1 32.7 14.4 
Total Cash, Cash Equivalents and Restricted Cash$556.5 $32.8 $21.9 

Supplementary Cash Flow Information (Applies to AEP)

Nine Months Ended September 30,
Cash Flow Information20232022
(in millions)
Cash Paid for:
Interest, Net of Capitalized Amounts$1,148.7 $856.8 
Income Taxes26.7 104.1 
Noncash Investing and Financing Activities:
Acquisitions Under Finance Leases38.5 22.3 
Construction Expenditures Included in Current Liabilities as of September 30,975.0 985.8 
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,9.5 8.5 
Noncash Increase in Noncurrent Assets from the Sale of the Competitive Contracted Renewables Portfolio74.7 — 
116



2. NEW ACCOUNTING STANDARDS

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

During the FASB’s standard-setting process and upon issuance of final standards, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. There are no new standards expected to have a material impact on the Registrants’ financial statements.

117



3.  COMPREHENSIVE INCOME

The disclosures in this note apply to all Registrants except AEPTCo and OPCo.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 theAEP’s components of changes in AOCI and details of reclassifications from AOCI.  The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 - Benefit Plans for additional information.

AEP
 Cash Flow HedgesPension 
Three Months Ended September 30, 2023CommodityInterest Rateand OPEBTotal
 (in millions)
Balance in AOCI as of June 30, 2023$93.5 $12.7 $(142.6)$(36.4)
Change in Fair Value Recognized in AOCI, Net of Tax19.3 (6.9)— 12.4 
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)(15.6)— — (15.6)
Interest Expense (a)— (1.3)— (1.3)
Amortization of Prior Service Cost (Credit)— — (5.3)(5.3)
Amortization of Actuarial (Gains) Losses— — 1.3 1.3 
Reclassifications from AOCI, before Income Tax Benefit(15.6)(1.3)(4.0)(20.9)
Income Tax Benefit(3.4)(0.2)(0.8)(4.4)
Reclassifications from AOCI, Net of Income Tax Benefit(12.2)(1.1)(3.2)(16.5)
Net Current Period Other Comprehensive Income (Loss)7.1 (8.0)(3.2)(4.1)
Balance in AOCI as of September 30, 2023$100.6 $4.7 $(145.8)$(40.5)
 Cash Flow HedgesPension 
Three Months Ended March 31, 2023CommodityInterest Rateand OPEBTotal
 (in millions)
Balance in AOCI as of December 31, 2022$223.5 $0.3 $(140.1)$83.7 
Change in Fair Value Recognized in AOCI, Net of Tax(195.3)5.2 (12.9)(203.0)
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity for Resale (a)47.0 — — 47.0 
Interest Expense (a)— 0.7 — 0.7 
Amortization of Prior Service Cost (Credit)— — (5.3)(5.3)
Amortization of Actuarial (Gains) Losses— — 1.2 1.2 
Reclassifications from AOCI, before Income Tax (Expense) Benefit47.0 0.7 (4.1)43.6 
Income Tax (Expense) Benefit9.9 0.1 (0.9)9.1 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit37.1 0.6 (3.2)34.5 
Reclassifications of KPCo Pension and OPEB Regulatory Assets from AOCI, before Income Tax (Expense) Benefit— — 21.1 21.1 
Income Tax (Expense) Benefit— — 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)(158.2)5.8 0.6 (151.8)
Balance in AOCI as of March 31, 2023$65.3 $6.1 $(139.5)$(68.1)

Cash Flow HedgesPension  Cash Flow HedgesPension 
Three Months Ended March 31, 2022CommodityInterest Rateand OPEBTotal
Three Months Ended September 30, 2022Three Months Ended September 30, 2022CommodityInterest Rateand OPEBTotal
(in millions) (in millions)
Balance in AOCI as of December 31, 2021$163.7 $(21.3)$42.4 $184.8 
Balance in AOCI as of June 30, 2022Balance in AOCI as of June 30, 2022$533.6 $(10.8)$28.6 $551.4 
Change in Fair Value Recognized in AOCI, Net of TaxChange in Fair Value Recognized in AOCI, Net of Tax278.2 6.8 — 285.0 Change in Fair Value Recognized in AOCI, Net of Tax94.3 7.4 — 101.7 
Amount of (Gain) Loss Reclassified from AOCIAmount of (Gain) Loss Reclassified from AOCIAmount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (a)Generation & Marketing Revenues (a)(0.1)— — (0.1)Generation & Marketing Revenues (a)0.2 — — 0.2 
Purchased Electricity for Resale (a)(47.9)— — (47.9)
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)(222.6)— — (222.6)
Interest Expense (a)Interest Expense (a)— 1.1 — 1.1 Interest Expense (a)— 0.9 — 0.9 
Amortization of Prior Service Cost (Credit)Amortization of Prior Service Cost (Credit)— — (4.9)(4.9)Amortization of Prior Service Cost (Credit)— — (6.2)(6.2)
Amortization of Actuarial (Gains) LossesAmortization of Actuarial (Gains) Losses— — 2.1 2.1 Amortization of Actuarial (Gains) Losses— — 2.2 2.2 
Reclassifications from AOCI, before Income Tax (Expense) BenefitReclassifications from AOCI, before Income Tax (Expense) Benefit(48.0)1.1 (2.8)(49.7)Reclassifications from AOCI, before Income Tax (Expense) Benefit(222.4)0.9 (4.0)(225.5)
Income Tax (Expense) BenefitIncome Tax (Expense) Benefit(10.1)0.2 (0.6)(10.5)Income Tax (Expense) Benefit(46.6)0.1 (0.8)(47.3)
Reclassifications from AOCI, Net of Income Tax (Expense) BenefitReclassifications from AOCI, Net of Income Tax (Expense) Benefit(37.9)0.9 (2.2)(39.2)Reclassifications from AOCI, Net of Income Tax (Expense) Benefit(175.8)0.8 (3.2)(178.2)
Net Current Period Other Comprehensive Income (Loss)Net Current Period Other Comprehensive Income (Loss)240.3 7.7 (2.2)245.8 Net Current Period Other Comprehensive Income (Loss)(81.5)8.2 (3.2)(76.5)
Balance in AOCI as of March 31, 2022$404.0 $(13.6)$40.2 $430.6 
Balance in AOCI as of September 30, 2022Balance in AOCI as of September 30, 2022$452.1 $(2.6)$25.4 $474.9 

118



AEP Texas
 Cash Flow HedgesPension 
Nine Months Ended September 30, 2023CommodityInterest Rateand OPEBTotal
 (in millions)
Balance in AOCI as of December 31, 2022$223.5 $0.3 $(140.1)$83.7 
Change in Fair Value Recognized in AOCI, Net of Tax(170.1)5.3 (12.9)(177.7)
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)59.7 — — 59.7 
Interest Expense (a)— (1.1)— (1.1)
Amortization of Prior Service Cost (Credit)— — (15.9)(15.9)
Amortization of Actuarial (Gains) Losses— — 3.9 3.9 
Reclassifications from AOCI, before Income Tax (Expense) Benefit59.7 (1.1)(12.0)46.6 
Income Tax (Expense) Benefit12.5 (0.2)(2.5)9.8 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit47.2 (0.9)(9.5)36.8 
Reclassifications of KPCo Pension and OPEB Regulatory Assets from AOCI— — 21.1 21.1 
Income Tax (Expense) Benefit— — 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)(122.9)4.4 (5.7)(124.2)
Balance in AOCI as of September 30, 2023$100.6 $4.7 $(145.8)$(40.5)

Cash Flow Hedge –Pension
Three Months Ended March 31, 2023Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2022$(0.3)$(8.3)$(8.6)
Change in Fair Value Recognized in AOCI, Net of Tax(0.2)(0.5)(0.7)
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (a)0.3 — 0.3 
Amortization of Prior Service Cost (Credit)— (0.1)(0.1)
Reclassifications from AOCI, before Income Tax (Expense) Benefit0.3 (0.1)0.2 
Income Tax (Expense) Benefit0.1 — 0.1 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0.2 (0.1)0.1 
Net Current Period Other Comprehensive Income (Loss)— (0.6)(0.6)
Balance in AOCI as of March 31, 2023$(0.3)$(8.9)$(9.2)
Cash Flow Hedge –Pension
Three Months Ended March 31, 2022Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2021$(1.3)$(5.2)$(6.5)
Change in Fair Value Recognized in AOCI, Net of Tax— — — 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (a)0.4 — 0.4 
Reclassifications from AOCI, before Income Tax (Expense) Benefit0.4 — 0.4 
Income Tax (Expense) Benefit0.1 — 0.1 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0.3 — 0.3 
Net Current Period Other Comprehensive Income (Loss)0.3 — 0.3 
Balance in AOCI as of March 31, 2022$(1.0)$(5.2)$(6.2)
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APCo
Cash Flow Hedge –Pension
Three Months Ended March 31, 2023Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2022$6.7 $(11.5)$(4.8)
Change in Fair Value Recognized in AOCI, Net of Tax— (0.1)(0.1)
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (a)(0.3)— (0.3)
Amortization of Prior Service Cost (Credit)— (1.2)(1.2)
Amortization of Actuarial (Gains) Losses— 0.3 0.3 
Reclassifications from AOCI, before Income Tax (Expense) Benefit(0.3)(0.9)(1.2)
Income Tax (Expense) Benefit(0.1)(0.2)(0.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit(0.2)(0.7)(0.9)
Net Current Period Other Comprehensive Income (Loss)(0.2)(0.8)(1.0)
Balance in AOCI as of March 31, 2023$6.5 $(12.3)$(5.8)
Cash Flow Hedge –Pension
Three Months Ended March 31, 2022Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2021$7.5 $16.9 $24.4 
Change in Fair Value Recognized in AOCI, Net of Tax— — — 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (a)(0.3)— (0.3)
Amortization of Prior Service Cost (Credit)— (1.4)(1.4)
Reclassifications from AOCI, before Income Tax (Expense) Benefit(0.3)(1.4)(1.7)
Income Tax (Expense) Benefit(0.1)(0.3)(0.4)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit(0.2)(1.1)(1.3)
Net Current Period Other Comprehensive Income (Loss)(0.2)(1.1)(1.3)
Balance in AOCI as of March 31, 2022$7.3 $15.8 $23.1 
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I&M
Cash Flow Hedge –Pension
Three Months Ended March 31, 2023Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2022$(5.1)$4.8 $(0.3)
Change in Fair Value Recognized in AOCI, Net of Tax(1.1)(1.7)(2.8)
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (a)0.5 — 0.5 
Amortization of Prior Service Cost (Credit)— (0.3)(0.3)
Amortization of Actuarial (Gains) Losses— 0.1 0.1 
Reclassifications from AOCI, before Income Tax (Expense) Benefit0.5 (0.2)0.3 
Income Tax (Expense) Benefit0.1 — 0.1 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0.4 (0.2)0.2 
Net Current Period Other Comprehensive Income (Loss)(0.7)(1.9)(2.6)
Balance in AOCI as of March 31, 2023$(5.8)$2.9 $(2.9)
Cash Flow Hedge –Pension
Three Months Ended March 31, 2022Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2021$(6.7)$5.4 $(1.3)
Change in Fair Value Recognized in AOCI, Net of Tax— — — 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (a)0.5 — 0.5 
Amortization of Prior Service Cost (Credit)— (0.2)(0.2)
Amortization of Actuarial (Gains) Losses— 0.1 0.1 
Reclassifications from AOCI, before Income Tax (Expense) Benefit0.5 (0.1)0.4 
Income Tax (Expense) Benefit0.1 — 0.1 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0.4 (0.1)0.3 
Net Current Period Other Comprehensive Income (Loss)0.4 (0.1)0.3 
Balance in AOCI as of March 31, 2022$(6.3)$5.3 $(1.0)
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PSO
Cash Flow Hedge –
Three Months Ended March 31, 2023Interest Rate
(in millions)
Balance in AOCI as of December 31, 2022$1.3 
Change in Fair Value Recognized in AOCI, Net of Tax(1.5)
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (a)— 
Reclassifications from AOCI, before Income Tax (Expense) Benefit— 
Income Tax (Expense) Benefit— 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit— 
Net Current Period Other Comprehensive Income (Loss)(1.5)
Balance in AOCI as of March 31, 2023$(0.2)
Cash Flow Hedge –
Three Months Ended March 31, 2022Interest Rate
(in millions)
Balance in AOCI as of December 31, 2021$— 
Change in Fair Value Recognized in AOCI, Net of Tax— 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (a)— 
Reclassifications from AOCI, before Income Tax (Expense) Benefit— 
Income Tax (Expense) Benefit— 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit— 
Net Current Period Other Comprehensive Income (Loss)— 
Balance in AOCI as of March 31, 2022$— 
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SWEPCo
Cash Flow Hedge –Pension
Three Months Ended March 31, 2023Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2022$1.1 $(5.3)$(4.2)
Change in Fair Value Recognized in AOCI, Net of Tax0.5 — 0.5 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (a)(0.1)— (0.1)
Amortization of Prior Service Cost (Credit)— (0.5)(0.5)
Amortization of Actuarial (Gains) Losses— 0.1 0.1 
Reclassifications from AOCI, before Income Tax (Expense) Benefit(0.1)(0.4)(0.5)
Income Tax (Expense) Benefit— (0.1)(0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit(0.1)(0.3)(0.4)
Net Current Period Other Comprehensive Income (Loss)0.4 (0.3)0.1 
Balance in AOCI as of March 31, 2023$1.5 $(5.6)$(4.1)
Cash Flow Hedge –Pension
Three Months Ended March 31, 2022Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2021$1.2 $5.5 $6.7 
Change in Fair Value Recognized in AOCI, Net of Tax— — — 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (a)0.1 — 0.1 
Amortization of Prior Service Cost (Credit)— (0.5)(0.5)
Reclassifications from AOCI, before Income Tax (Expense) Benefit0.1 (0.5)(0.4)
Income Tax (Expense) Benefit— (0.1)(0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0.1 (0.4)(0.3)
Net Current Period Other Comprehensive Income (Loss)0.1 (0.4)(0.3)
Balance in AOCI as of March 31, 2022$1.3 $5.1 $6.4 
 Cash Flow HedgesPension 
Nine Months Ended September 30, 2022CommodityInterest Rateand OPEBTotal
 (in millions)
Balance in AOCI as of December 31, 2021$163.7 $(21.3)$42.4 $184.8 
Change in Fair Value Recognized in AOCI, Net of Tax629.8 16.2 — 646.0 
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (a)0.2 — — 0.2 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)(432.3)— — (432.3)
Interest Expense (a)— 3.1 — 3.1 
Amortization of Prior Service Cost (Credit)— — (16.5)(16.5)
Amortization of Actuarial (Gains) Losses— — 6.4 6.4 
Reclassifications from AOCI, before Income Tax (Expense) Benefit(432.1)3.1 (10.1)(439.1)
Income Tax (Expense) Benefit(90.7)0.6 (2.1)(92.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit(341.4)2.5 (8.0)(346.9)
Reclassifications of KPCo Pension and OPEB Regulatory Assets to AOCI— — (11.4)(11.4)
Income Tax (Expense) Benefit— — (2.4)(2.4)
Reclassifications of KPCo Pension and OPEB Regulatory Assets to AOCI, Net of Income Tax (Expense) Benefit— — (9.0)(9.0)
Net Current Period Other Comprehensive Income (Loss)288.4 18.7 (17.0)290.1 
Balance in AOCI as of September 30, 2022$452.1 $(2.6)$25.4 $474.9 

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

123119



4.  RATE MATTERS

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

As discussed in the 2022 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2022 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2023 and updates the 2022 Annual Report.

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

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

Management is seeking or will seek regulatory recovery, as necessary, for any net book value remaining when the plants are retired. To the extent the net book value of these generation assets 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

SWEPCo

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 below 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 September 30, 2023, the Texas jurisdictional share of the net book value of the Pirkey Plant will be addressed in SWEPCo’s next base rate case.was $66 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.


120


Regulated Generating Units to be Retired

PSO

In 2014, PSO received final approval from the Federal EPA to close Northeastern Plant, Unit 3, in 2026. The plant was originally scheduled to close in 2040. As a result of the early retirement date, PSO revised the useful life of Northeastern Plant, Unit 3, to the projected retirement date of 2026 and the incremental depreciation is being deferred as a regulatory asset. As part of the 2021 Oklahoma Base Rate Case, PSO will continue to recover Northeastern Plant, Unit 3 through 2040.


124



SWEPCo

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 March 31,September 30, 2023, of generating facilities planned for early retirement:
PlantPlantNet Book ValueAccelerated Depreciation Regulatory AssetCost of Removal
Regulatory Liability
Projected
Retirement Date
Current Authorized
Recovery Period
Annual
Depreciation (a)
PlantNet Book ValueAccelerated Depreciation Regulatory AssetCost of Removal
Regulatory Liability
Projected
Retirement Date
Current Authorized
Recovery Period
Annual
Depreciation (a)
(dollars in millions)(dollars in millions)
Northeastern Plant, Unit 3Northeastern Plant, Unit 3$128.5 $150.3 $20.3 (b)2026(c)$14.9 Northeastern Plant, Unit 3$112.5 $159.5 $20.4 (b)2026(c)$15.0 
Welsh Plant, Units 1 and 3Welsh Plant, Units 1 and 3399.6 95.5 58.1 (d)2028(e)38.3 Welsh Plant, Units 1 and 3368.8 115.5 58.0 (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 March 31,September 30, 2023, SWEPCo’s share of the net investment in the Dolet Hills Power Station was $110$105 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 March 31,September 30, 2023, SWEPCo had a net under-recovered fuel balance of $233$91 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 $33$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 $72 million, including denial of recovery of the $33$35 million deferral, with refunds to customers over five years. In September 2022, SWEPCo filed rebuttal testimony addressing the LPSC staff recommendations.recommendations and a hearing was held in May 2023.

121


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

In August 2022, SWEPCoJune 2023, an unopposed settlement agreement was filed a fuel reconciliation with the PUCT covering the fuel periodthat would provide recovery of January 1, 2020$48 million of Oxbow mine related costs through December 31, 2021. Intervenors submitted testimony and SWEPCo filed rebuttal testimony in the first quarter of2035. In September 2023, and a decision from the PUCT is expected inapproved the third quarter of 2023.settlement agreement.

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


125



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 March 31,September 30, 2023, SWEPCo’s share of the net investment in the Pirkey Plant was $177$180 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 March 31,September 30, 2023, SWEPCo had a net under-recovered fuel balance of $233$91 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 June 2023, an unopposed settlement agreement was filed with the PUCT that would provide recovery of $33 million of Sabine related fuel costs through 2035. In September 2023, the PUCT approved the settlement agreement.

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.

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


122


Regulatory Assets Pending Final Regulatory Approval (Applies to all Registrants except AEPTCo)
AEPAEP
March 31,December 31,September 30,December 31,
2023202220232022
Noncurrent Regulatory Assets Noncurrent Regulatory Assets(in millions) Noncurrent Regulatory Assets(in millions)
    
Regulatory Assets Currently Earning a ReturnRegulatory Assets Currently Earning a Return  Regulatory Assets Currently Earning a Return  
Welsh Plant, Units 1 and 3 Accelerated DepreciationWelsh Plant, Units 1 and 3 Accelerated Depreciation$115.5 $85.6 
Pirkey PlantPirkey Plant113.0 116.5 
Unrecovered Winter Storm Fuel Costs (a)Unrecovered Winter Storm Fuel Costs (a)$115.9 $121.7 Unrecovered Winter Storm Fuel Costs (a)101.4 121.7 
Welsh Plant, Units 1 and 3 Accelerated Depreciation95.5 85.6 
Pirkey Plant Accelerated Depreciation111.8 116.5 
Dolet Hills Power Station Fuel Costs - LouisianaDolet Hills Power Station Fuel Costs - Louisiana33.3 32.0 Dolet Hills Power Station Fuel Costs - Louisiana34.7 32.0 
Texas Mobile Generation Lease Payments24.6 17.6 
Texas Mobile Generation Costs (b)Texas Mobile Generation Costs (b)— 17.6 
Other Regulatory Assets Pending Final Regulatory ApprovalOther Regulatory Assets Pending Final Regulatory Approval21.4 19.3 Other Regulatory Assets Pending Final Regulatory Approval21.0 19.3 
Regulatory Assets Currently Not Earning a ReturnRegulatory Assets Currently Not Earning a Return  Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs (c)(e)Storm-Related Costs (c)(e)265.1 407.2 Storm-Related Costs (c)(e)385.8 407.2 
2020-2022 Virginia Triennial Under-Earnings2020-2022 Virginia Triennial Under-Earnings37.9 37.9 2020-2022 Virginia Triennial Under-Earnings37.4 37.9 
Plant Retirement Costs – Asset Retirement Obligation CostsPlant Retirement Costs – Asset Retirement Obligation Costs25.9 25.9 Plant Retirement Costs – Asset Retirement Obligation Costs25.9 25.9 
Other Regulatory Assets Pending Final Regulatory ApprovalOther Regulatory Assets Pending Final Regulatory Approval43.1 55.6 Other Regulatory Assets Pending Final Regulatory Approval51.6 55.6 
Total Regulatory Assets Pending Final Regulatory ApprovalTotal Regulatory Assets Pending Final Regulatory Approval$774.5 $919.3 Total Regulatory Assets Pending Final Regulatory Approval$886.3 $919.3 
(a)Includes $37 million and $37 million of unrecovered winter storm fuel costs recorded as a current regulatory asset as of March 31,September 30, 2023 and December 31, 2022, respectively. See the “February 2021 Severe Winter Weather Impacts in SPP” section below for additional information.
(b)In AprilOctober 2023, OPCo filedthe PUCT issued an order approving a request withrider to recover deferred Texas Mobile Generation Costs. Recovery of deferred costs through the new rider is updated annually, subject to Commission review.
(c)In October 2023, the PUCO forissued an order approving recovery of $34 million in Ohio storm-related costs.
(c)(d)In April 2023, the LPSC issued an order approving the prudence and future recovery of the Louisiana storm-related costs.regulatory assets. See “2021 Louisiana Storm Cost Filing” section below for additional information.
(e)In June 2023, storms in the Oklahoma, Louisiana and Texas service territories caused power outages and extensive damage resulting in the deferral of $58 million, $29 million and $24 million, respectively. Recovery of these storm costs will be addressed in a future request.

AEP Texas
September 30,December 31,
20232022
Noncurrent Regulatory Assets(in millions)
Regulatory Assets Currently Earning a Return
Texas Mobile Generation Costs (a)$— $17.6 
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs35.9 26.7 
Vegetation Management Program5.2 5.2 
Texas Retail Electric Provider Bad Debt Expense4.1 4.1 
Other Regulatory Assets Pending Final Regulatory Approval16.3 13.4 
Total Regulatory Assets Pending Final Regulatory Approval$61.5 $67.0 

(a)In October 2023, the PUCT issued an order approving a rider to recover deferred Texas Mobile Generation Costs. Recovery of deferred costs through the new rider is updated annually, subject to Commission review.

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AEP TexasAPCo
March 31,December 31,September 30,December 31,
2023202220232022
Noncurrent Regulatory AssetsNoncurrent Regulatory Assets(in millions)Noncurrent Regulatory Assets(in millions)
Regulatory Assets Currently Earning a ReturnRegulatory Assets Currently Earning a ReturnRegulatory Assets Currently Earning a Return
Texas Mobile Generation Lease Payments$24.6 $17.6 
COVID-19 – VirginiaCOVID-19 – Virginia$7.0 $7.0 
Regulatory Assets Currently Not Earning a ReturnRegulatory Assets Currently Not Earning a Return  Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs28.9 26.7 
Vegetation Management Program5.2 5.2 
Texas Retail Electric Provider Bad Debt Expense4.1 4.1 
Storm-Related Costs - West VirginiaStorm-Related Costs - West Virginia72.2 72.6 
2020-2022 Virginia Triennial Under-Earnings2020-2022 Virginia Triennial Under-Earnings37.4 37.9 
Plant Retirement Costs – Asset Retirement Obligation CostsPlant Retirement Costs – Asset Retirement Obligation Costs25.9 25.9 
Other Regulatory Assets Pending Final Regulatory ApprovalOther Regulatory Assets Pending Final Regulatory Approval13.5 13.4 Other Regulatory Assets Pending Final Regulatory Approval5.9 1.1 
Total Regulatory Assets Pending Final Regulatory ApprovalTotal Regulatory Assets Pending Final Regulatory Approval$76.3 $67.0 Total Regulatory Assets Pending Final Regulatory Approval$148.4 $144.5 

APCo I&M
March 31,December 31,September 30,December 31,
2023202220232022
Noncurrent Regulatory AssetsNoncurrent Regulatory Assets(in millions)Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Earning a ReturnRegulatory Assets Currently Earning a ReturnRegulatory Assets Currently Earning a Return
COVID-19 – Virginia$7.1 $7.0 
Other Regulatory Assets Pending Final Regulatory ApprovalOther Regulatory Assets Pending Final Regulatory Approval$0.2 $0.1 
Regulatory Assets Currently Not Earning a ReturnRegulatory Assets Currently Not Earning a Return  
Storm-Related Costs - IndianaStorm-Related Costs - Indiana29.4 21.6 
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs - West Virginia72.1 72.6 
2020-2022 Virginia Triennial Under-Earnings37.9 37.9 
Plant Retirement Costs – Asset Retirement Obligation Costs25.9 25.9 
Other Regulatory Assets Pending Final Regulatory ApprovalOther Regulatory Assets Pending Final Regulatory Approval0.6 1.1 Other Regulatory Assets Pending Final Regulatory Approval2.7 2.0 
Total Regulatory Assets Pending Final Regulatory ApprovalTotal Regulatory Assets Pending Final Regulatory Approval$143.6 $144.5 Total Regulatory Assets Pending Final Regulatory Approval$32.3 $23.7 

 I&M
March 31,December 31,
20232022
Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval$0.1 $0.1 
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs - Indiana23.0 21.6 
Other Regulatory Assets Pending Final Regulatory Approval2.2 2.0 
Total Regulatory Assets Pending Final Regulatory Approval$25.3 $23.7 
 OPCo
September 30,December 31,
20232022
Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs (a)$21.2 $33.8 
Total Regulatory Assets Pending Final Regulatory Approval$21.2 $33.8 
(a)In October 2023, the PUCO issued an order approving recovery of $34 million in storm-related costs.
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OPCo PSO
March 31,December 31,September 30,December 31,
2023202220232022
Noncurrent Regulatory AssetsNoncurrent Regulatory Assets(in millions)Noncurrent Regulatory Assets(in millions)
    
Regulatory Assets Currently Not Earning a ReturnRegulatory Assets Currently Not Earning a Return  Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs (a)Storm-Related Costs (a)$36.3 $33.8 Storm-Related Costs (a)$92.8 $25.5 
Other Regulatory Assets Pending Final Regulatory ApprovalOther Regulatory Assets Pending Final Regulatory Approval0.2 0.1 
Total Regulatory Assets Pending Final Regulatory ApprovalTotal Regulatory Assets Pending Final Regulatory Approval$36.3 $33.8 Total Regulatory Assets Pending Final Regulatory Approval$93.0 $25.6 
(a)In AprilJune 2023, OPCo filedstorms caused power outages and extensive damage to the Oklahoma service territory, resulting in the deferral of $58 million. Recovery for these storm costs will be addressed in a request with the PUCO for recovery of $34 million in storm costs.future request.

 PSO
March 31,December 31,
20232022
Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs$29.2 $25.5 
Other Regulatory Assets Pending Final Regulatory Approval0.1 0.1 
Total Regulatory Assets Pending Final Regulatory Approval$29.3 $25.6 
.
SWEPCoSWEPCo
March 31,December 31,September 30,December 31,
2023202220232022
Noncurrent Regulatory AssetsNoncurrent Regulatory Assets(in millions)Noncurrent Regulatory Assets(in millions)
    
Regulatory Assets Currently Earning a ReturnRegulatory Assets Currently Earning a Return  Regulatory Assets Currently Earning a Return  
Welsh Plant, Units 1 and 3 Accelerated DepreciationWelsh Plant, Units 1 and 3 Accelerated Depreciation$115.5 $85.6 
Pirkey PlantPirkey Plant113.0 116.5 
Unrecovered Winter Storm Fuel Costs (a)Unrecovered Winter Storm Fuel Costs (a)$115.9 $121.7 Unrecovered Winter Storm Fuel Costs (a)101.4 121.7 
Welsh Plant, Units 1 and 3 Accelerated Depreciation95.5 85.6 
Pirkey Plant Accelerated Depreciation111.8 116.5 
Dolet Hills Power Station Fuel Costs - LouisianaDolet Hills Power Station Fuel Costs - Louisiana33.3 32.0 Dolet Hills Power Station Fuel Costs - Louisiana34.7 32.0 
Dolet Hills Power StationDolet Hills Power Station12.1 9.7 Dolet Hills Power Station12.0 9.7 
Other Regulatory Assets Pending Final Regulatory ApprovalOther Regulatory Assets Pending Final Regulatory Approval2.1 2.5 Other Regulatory Assets Pending Final Regulatory Approval1.7 2.5 
Regulatory Assets Currently Not Earning a ReturnRegulatory Assets Currently Not Earning a Return  Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs - Louisiana (b)— 151.5 
Storm-Related Costs (b)(c)Storm-Related Costs (b)(c)53.4 151.5 
Asset Retirement Obligation - LouisianaAsset Retirement Obligation - Louisiana— 11.8 Asset Retirement Obligation - Louisiana— 11.8 
Other Regulatory Assets Pending Final Regulatory ApprovalOther Regulatory Assets Pending Final Regulatory Approval15.4 16.0 Other Regulatory Assets Pending Final Regulatory Approval14.8 16.0 
Total Regulatory Assets Pending Final Regulatory ApprovalTotal Regulatory Assets Pending Final Regulatory Approval$386.1 $547.3 Total Regulatory Assets Pending Final Regulatory Approval$446.5 $547.3 
(a)Includes $37 million and $37 million of unrecovered winter storm fuel costs recorded as a current regulatory asset as of March 31,September 30, 2023 and December 31, 2022, respectively. See the “February 2021 Severe Winter Weather Impacts in SPP” section below for additional information.
(b)In April 2023, the LPSC issued an order approving the prudence and future recovery of the Louisiana storm-related costs.regulatory assets. See “2021 Louisiana Storm Cost Filing” section below for additional information.
(c)In June 2023, additional storms in the Louisiana and Texas service territories caused power outages and extensive damage resulting in the deferral of $29 million and $24 million, respectively. Recovery of these storm costs will be addressed in a future request.

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


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

AEP Texas Interim Transmission and Distribution Rates

Through March 31,September 30, 2023, AEP Texas’ cumulative revenues from interim base rate increases that are subject to review is approximately $702$884 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 major stormsystem restoration costs for severe weather events. As of March 31,

In August 2023, APCo, deferred approximately $38Virginia 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 $50 million regulatory asset, including tax gross-up, to be recovered over three years starting in 2024 related to previously incurred major storm costs as a result of APCo’s calculation of Virginia earnings below the bottom of its authorized ROE bandexpenses incurred during the 2020-2022 Triennial Review period. Anytriennial period when APCo under-earned in Virginia, jurisdictional(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 thatwith certain costs subject to over-/under-recovery accounting.

In September 2023, the hearing examiner issued a report recommending approval of the settlement agreement described above, as filed. The Virginia SCC is expected to issue an order in the fourth quarter of 2023. If any costs included in APCo’s 2020-2022 Virginia triennial review are not recoverable or any refunds of revenues collected from customers during the triennial review period that are ordered by the Virginia SCCapproved for the 2020-2022 Triennial Review periodrecovery, it could reduce future net income and cash flows and impact financial condition.


ENEC (Expanded Net Energy Cost) Filings

In April 2021, APCo and WPCo (the Companies) requested a combined $73 million annual increase in ENEC rates based on a cumulative $55 million ENEC under-recovery as of February 28, 2021 and an $18 million increase in projected ENEC costs for the period September 2021 through August 2022. In September 2021, the WVPSC issued an order approving a $7 million overall increase in ENEC rates, including an approval for recovery of the Companies’ cumulative $55 million ENEC under-recovery balance and a $48 million reduction in projected costs for the period September 2021 through August 2022. Subsequently, the Companies submitted a request for reconsideration of this order, identifying flaws in the WVPSC’s calculation of forecasted future year fuel expense and purchased power costs.

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In March 2022, the WVPSC issued an order granting the Companies’ request for reconsideration, in part, and approving $31 million in projected costs for the period September 2021 through August 2022. The order also reopened the 2021 ENEC case to require the Companies to explain the significant growth in the reported under-recovery of ENEC costs and to provide various other information including revised projected costs for the period March 2022 through August 2022. Also, in March 2022, the Companies filed testimony providing the information requested in the WVPSC’s order and requested a $155 million annual increase in ENEC rates effective May 1, 2022. In May 2022, the WVPSC issued an order approving a $93 million overall increase to ENEC rates to recover projected annual ENEC costs. However, the WVPSC stated that actual and projected ENEC costs are still subject to a prudency review.
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In April 2022, the Companies submitted their 2022 annual ENEC filing with the WVPSC requesting a $297 million annual increase in ENEC revenues, inclusive of the previously requested $155 million increase, effective September 1, 2022.

In September 2022, following an agreed upon delay in the proceedings of the Companies’ 2022 ENEC case, certain intervenors submitted testimony recommending disallowances of at least $83 million to the Companies’ historical period ENEC under-recovery balance along with proposals to either securitize the Companies’ remaining ENEC balance or defer recovery of this balance beyond the traditional one-year period. West Virginia Staffstaff recommended a $13 million increase in ENEC rates pending the outcome of the ENEC prudency review. In February 2023, the WVPSC issued an order stating that the commission will not grant additional rate increases for fuel costs until the WVPSC staff completes its prudency review.

In April 2023, the Companies submitted their 2023 annual ENEC filing with the WVPSC, proposing two alternatives to increase ENEC rates effective September 1, 2023. The first alternative is 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 is 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. The Companies continue to reflect ENEC under-recovery balances as current on their balance sheets since management cannot assert whether the WVPSC will approve recovery of ENEC under-recovery balances over a time frame different from the traditional one-year period.

Additionally, in April 2023, the Staff submitted the prudency review prepared by an independent consultant retained by the WVPSC Staffstaff of the Companies’ operation of the Amos, Mountaineer and Mitchell coal plants that Staff was directed to conduct by the WVPSC in May 2022 (Consultant’s Report). The Consultant’s Report states the opinion of the consultant that the Companies acted imprudently by not taking steps to achieve a 69% capacity factor at their coal-fired plants and recommends applying a disallowance factor of 52.9% to the Companies’ cumulative, September 30, 2022 ENEC under-recovery balance of approximately $430 million. The Consultant’s Report further states the consultant’s opinion that this disallowance factor could also be utilized in future ENEC filings. Adoption of the Consultant’s Report’s findings by the WVPSC could result in a disallowance of up to $285 million of the Companies’ cumulative, March 31, 2023 ENEC under-recovery balance of approximately $539 million. The Companies disagree with the conclusions and recommendations contained in the Consultant’s Report and intenda hearing was held with the WVPSC in September 2023.

In August 2023, the Staff and intervenors submitted testimony recommending, among other items: (a) disallowances of up to dispute them$262 million of historical ENEC under-recovery balances based on alleged lack of prudence, (b) carrying charges on under-recovered balances ranging from 2% to 4% and (c) the recovery of February 28, 2023 ENEC under-recoveries over a period of time ranging from three to five years.In addition, certain intervenors recommended the rejection of the Companies’ proposed securitization and one intervenor recommended that, no later than January 1, 2024, the Companies dispatch their coal fleet at the lower of actual purchase costs or replacement pricing through at least 2026 and that the Companies share 75% of any off-system sales revenues with customers.

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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. An order from the WVPSC on the 2021 and 2022 ENEC cases is expected in the appropriate proceedings beforefourth quarter of 2023.

In October 2023, intervening parties submitted reply briefs. One intervening party amended their recommended disallowance to include the WVPSC.Companies’ full $553 million ENEC under-recovery as of February 28, 2023. The other intervening parties’ recommended disallowances remained consistent with testimony submitted in August 2023.

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

ETT Rate Matters (Applies to AEP)

ETT Interim Transmission Rates

AEP has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next base rate proceeding. Through March 31,September 30, 2023, AEP’s share of ETT’s cumulative revenues that are subject to review is approximately $1.6 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 $1.6 billion of cumulative revenues above will be subject to review.


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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 Unit Power Agreement (UPA) that were alleged to be above market in applying the MPSC’s Code of Conduct rules. Michigan Staffstaff 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. An MPSC order on I&M’s 2021 PSCR Reconciliation is expected in the fourth quarter of 2023. 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. Intervenor testimony is due November 2023 and a hearing is scheduled for January 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.


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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. Intervenor testimony is due January 2024 and a hearing is scheduled for 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)

Fuel Adjustment Clause (FAC) Purchased Power Limitation

In May 2023, KPCo filed an application seeking authority to defer, for future recovery, approximately $12 million of December 2022 purchased power costs not recoverable through its FAC. This requested deferral accounting authority would have enabled KPCo to pursue securitization of these costs. In June 2023, the KPSC denied KPCo’s request for deferral accounting authority. In July 2023, KPCo appealed this decision to the Kentucky state appellate court.

Also in June 2023, following its order denying KPCo’s request for deferral accounting authority, 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. A hearing is scheduled for the first quarter of 2024.

KPCo is requesting a prudency determination and recovery mechanism for these costs in its 2023 base rate. Unless and until KPCo is granted a recovery mechanism for these purchased power costs from the KPSC it will impact cash flows and financial condition. Additionally, 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.

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. Consistent with Kentucky statutory requirements, the present value of the return on accumulated deferred income tax benefits related to plant retirement costs and deferred purchase power expenses were proposed to reduce the amount authorized to be financed through securitization.


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In October 2023, various intervenors filed testimony recommending an annual base rate increase of $63 million based on ROEs ranging from 9.3% to 9.7%. Intervenors supported KPCo’s securitization request, but proposed to include certain tax benefits as a reduction to the base rate revenue requirement. Intervenors also supported 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. Other differences between KPCo’s requested annual base rate increase and the intervenors’ recommendations are primarily due to: (a) proposals to remove certain employee-related expenses from the revenue requirement, (b) opposition to various matters related to accumulated deferred income taxes, including opposition to KPCo’s inclusion of its deferred tax asset associated with net operating loss on a stand-alone tax basis in rate base and a recommendation that KPCo not be permitted to recover a tax-related regulatory asset of approximately $33 million, (c) opposition to recovery of approximately $16 million of purchased power costs not recoverable through its FAC since its last base case and (d) a recommendation that KPCo not earn a return on $42 million of prepaid pension and OPEB assets. In addition, intervenors expressed opposition to KPCo’s proposed rider to recover certain distribution reliability investments and related incremental operation and maintenance expenses. KPCo is scheduled to file rebuttal testimony in November 2023. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

OPCo Rate Matters (Applies to AEP and OPCo)

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 is scheduled for the fourth quarter of 2023.

Management disagrees with these claims and is unable to predict the impact of these disputes, however, ifdisputes. If any costs are disallowed or refunds are ordered, it could reduce future net income and cash flows and impact financial condition. See "OVEC" section of Note 17 in the 2022 Annual Report for additional information on AEP and OPCo’s investment in OVEC.

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. IntervenorIn 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 dueexpected in the secondfirst quarter of 2023 and a hearing is scheduled for the third quarter of 2023.2024. 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.


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PSO Rate Matters (Applies to AEP and PSO)

2022 Oklahoma Base Rate Case

In November 2022, PSO filed a request with the OCC for a $173 million annual increase in rates based upon a 10.4% ROE with a capital structure of 45.4% debt and 54.6% common equity, net of existing rider revenues and certain incremental renewable facility benefits expected to be provided to customers through riders. The requested annual revenue increase includesincluded 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 includesincluded recovery of the 154 MW Rock Falls Wind Facility through base rates to aid PSO’s near-term capacity needs and support compliance with SPP’s 2023 increased capacity planning reserve margin requirements. In November 2022, PSO entered into an agreement to acquire the Rock Falls Wind Facility. In February 2023, the FERC approved PSO’s acquisition of the Rock Falls Wind Facility under Section 203 of the Federal Power Act. PSO closed on the acquisition and placed the Rock Falls Wind Facility in-service on March 31, 2023. In addition, PSO requested an annual formula based rate tariff, with an initial one-year pilot term. In the event the requested formula based rate tariff iswas denied, PSO has requested an expanded rider to recover certain distribution investments and related expenses as well as an expanded transmission cost recovery rider.

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In March 2023, OCC staff and various intervenors filed testimony supporting net annual revenue changes ranging from a $42 million net decrease to a $49 million net increase based upon ROEs ranging from 8.6% to 9.5%. The difference between PSO’s request and OCC staff and intervenor testimony is primarily due to: (a) rejection of PSO’s request to accelerate the recovery of Northeastern Plant, Unit 3 from its original retirement date of 2040 to its projected retirement date of 2026, (b) rejection of PSO’s request to recover intangible plant over a 5-year useful life instead of a 10-year useful life, (c) recommended disallowance of approximately $9 million in certain distribution plant investments, (d) opposition to inclusion of the Rock Falls Wind Facility revenue requirement in customer rates before PSO’s next base rate case, (e) opposition to PSO’s inclusion of its deferred tax asset associated with net operating loss on a stand-alone tax basis in rate base and (f) lower recommended ROEs and recommendations to use certain hypothetical capital structures. Parties also recommended that the OCC reject PSO’s requested formula based rate, and alternate requests for expanded distribution investment and transmission cost recovery riders. A hearing is scheduled

In May 2023, PSO, OCC staff and certain intervenors filed a contested joint stipulation and settlement agreement with the OCC that includes an annual revenue increase of $50 million, based upon a 9.5% ROE with a capital structure of 45.4% debt and 54.6% common equity, net of existing rider revenues and certain incremental renewable facility benefits expected to be provided to customers through riders. The net annual increase includes recovery of the 154 MW Rock Falls Wind Facility through base rates. Northeastern Plant, Unit 3 will continue to be recovered through 2040 and intangible plant will continue to be recovered over a 10-year useful life. The agreement also provides for May 2023. PSO expectscertain rider-related items, including: (a) revision to PSO’s Fuel Clause Adjustment Rider to reflect factor updates to occur on a semi-annual basis, (b) approval to defer a weighted average cost of capital carrying charge on PSO’s deferred tax asset associated with net operating loss on a stand-alone tax basis to a regulatory asset and, contingent upon receipt of a supportive private letter ruling from the IRS, approval to collect the deferral through a rider over a 20-month period and (c) approval to implement an expanded rider to recover certain distribution investments for a three-year term, up to a $6 million annual revenue requirement.

In May 2023, a hearing on the merits of the contested joint stipulation and settlement agreement was held at the OCC and PSO implemented an interim ratesannual base rate increase, subject to refund, startingbased upon the contested joint stipulation and settlement agreement. In July 2023, an ALJ report was filed and included recommendations generally consistent with the Juneintervenor testimony. The ALJ report is not binding on the OCC. Through September 30, 2023, billing cycle.PSO’s cumulative revenue from the interim annual base rate increase, subject to refund, is approximately $80 million. A final order is expected in the thirdfourth quarter of 2023. If the OCC modifies the contested joint stipulation and settlement agreement and PSO is required to refund any of thesethe $80 million of revenue recorded subject to refund or any costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
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SWEPCo Rate Matters (Applies to AEP and SWEPCo)

2012 Texas Base Rate Case

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

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

In July 2018, the Texas Third Court of Appeals reversed the PUCT’s judgment affirming the prudence of the Turk Plant and remanded the issue back to the PUCT. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court. In March 2021, the Texas Supreme Court issued an opinion reversing the July 2018 judgment of the Texas Third Court of Appeals and agreeing with the PUCT’s judgment affirming the prudence of the Turk Plant. In addition, the Texas Supreme Court remanded the AFUDC dispute back to the Texas Third Court of Appeals. No parties filed a motion for rehearing with the Texas Supreme Court. In August 2021, the Texas Third Court of Appeals reversed the Texas District Court judgment affirming the PUCT’s order on AFUDC, concluding that the language of the PUCT’s original 2008 order intended to include AFUDC in the Texas jurisdictional capital cost cap, and remanded the case to the PUCT for future proceedings. SWEPCo disagrees with the Court of Appeals decision.In November 2021, SWEPCo and the PUCT submitted Petitions for Review with the Texas Supreme Court in November 2021.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 AprilJune 2023, SWEPCo and the PUCT filed replies to parties’ responses to the requests for rehearing. IfTexas Supreme Court denied SWEPCo’s request for rehearing is denied,and the case will bewas 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.

Management does not believe a disallowance of capitalized Turk Plant costs or a revenue refund is probable as of March 31,September 30, 2023. However, if SWEPCo is ultimately unable to recover AFUDC in excess of the Texas jurisdictional capital cost cap, it would be expected to result in a pretax net disallowance ranging from $80 million to $90 million. In addition, if AFUDCSWEPCo is ultimately determinedunable to be includedrecover AFUDC in excess of the Texas jurisdictional capital cost cap, SWEPCo estimates it may be required to make customer refunds, including interest, ranging from $0 to $190$200 million related to revenues collected from February 2013 through MarchSeptember 2023 and such determination may reduce SWEPCo’s future revenues by approximately $15 million on an annual basis.

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2016 Texas Base Rate Case

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

As a result of the final order, in 2017 SWEPCo: (a) recorded an impairment charge of $19 million, which included $7 million associated with the lack of return on Welsh Plant, Unit 2 and $12 million related to other disallowed plant investments, (b) recognized $32 million of additional revenues, for the period of May 2017 through December 2017, that was surcharged to customers in 2018 and (c) recognized an additional $7 million of expenses consisting primarily of depreciation expense and vegetation management expense, offset by the deferral of rate case expense. SWEPCo implemented new rates in February 2018 billings. The $32 million of additional 2017 revenues was collected during 2018. In March 2018, the PUCT clarified and corrected portions of the final order, without changing the overall decision or amounts of the rate change. The order has been appealed by various intervenors related to limiting SWEPCo’s recovery of AFUDC on Turk Plant and recovery of Welsh Plant, Unit 2. The appeal will move forward following the conclusion of the 2012 Texas Base Rate Case. If certain parts of the PUCT order are overturned, it could reduce future net income and cash flows and impact financial condition.
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2020 Texas Base Rate Case

In October 2020, SWEPCo filed a request with the PUCT for a $105 million annual increase in Texas base rates based upon a proposed 10.35% ROE. The request would move transmission and distribution interim revenues recovered through riders into base rates. Eliminating these riders would result in a net annual requested base rate increase of $90 million primarily due to increased investments. 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.
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In January 2023, the LPSC approved a settlement which provides for an annual revenue increase of $27 million based upon a 9.5% ROE and includes: (a) a $21 million increase in base rates effective February 2023, (b) a $14 million rider to recover costs of the Dolet Hills Power Station and Pirkey Plant including a return, (c) an $8 million reduction in fuel rates, (d) an adoption of a 3-year formula rate term subject to an earnings band and (e) the recovery of certain incremental SPP charges net of associated revenue and the LALouisiana 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 andbase. In September 2023, an order was received from the LPSC is expected in 2023.directing SWEPCo to seek a private letter ruling from the IRS to address the matter.

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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. SWEPCo will submit additional information in phase two of this proceeding to determine whether securitization of the costs is more cost effective than recovery through typical ratemaking. 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.

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:
JurisdictionJurisdictionMarch 31, 2023December 31, 2022Approved Recovery PeriodApproved Carrying ChargeJurisdictionSeptember 30, 2023December 31, 2022Approved Recovery PeriodApproved Carrying Charge
(in millions)(in millions)
ArkansasArkansas$71.7 $74.9 6 years(a)Arkansas$59.4 $74.9 6 years(a)
LouisianaLouisiana115.9 121.7(b)(b)Louisiana101.4 121.7 (b)(b)
TexasTexas124.5 132.45 years1.65%Texas108.6 132.4 5 years1.65%
TotalTotal$312.1 $329.0 Total$269.4 $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 conduct an audit of these costs in 2024. SWEPCo’s direct testimony in support of the costs is due in December 2023.
(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. SWEPCoThe special order states the fuel and purchased power costs incurred will work with thebe subject to a future LPSC to finalize the actual recovery period and determine the appropriate carrying charge in future proceedings.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.
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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 on the formal challenge which ruled in favor of the joint customers on several 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 decision to the U.S. Court of Appeals for the District of Columbia Circuit.

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Independence Energy Connection Project (Applies to AEP)

In 2016, PJM approved the Independence Energy Connection Project (IEC) and included it in its Regional Transmission Expansion Plan to alleviate congestion. Transource Energy has an ownership interest in the IEC, which is located in Maryland and Pennsylvania. In June 2020, the Maryland Public Service Commission approved a Certificate of Public Convenience and Necessity to construct the portion of the IEC in Maryland. In May 2021, the Pennsylvania Public Utility Commission (PAPUC) denied the IEC certificate for siting and construction of the portion in Pennsylvania. Transource Energy appealed the PAPUC ruling in Pennsylvania state court and challenged the ruling before the United States District Court for the Middle District of Pennsylvania. In May 2022, the Pennsylvania state court issued an order affirming the PAPUC decision. The PAPUC decision remains subject to the jurisdiction and review of the United States District Court for the Middle District of Pennsylvania, which had stayed review of the PAPUC decision until the Pennsylvania state court had ordered. The procedural schedule for this case states that a decision by the United States District Court for the Middle of Pennsylvania will not be reached until the second half of 2023.

In September 2021, PJM notified Transource Energy that the IEC was suspended to allow for the regulatory and related appeals process to proceed in an orderly manner without breaching milestone dates in the project agreement. At that time, PJM stated that the IEC has not been cancelled and remains necessary to alleviate congestion. PJM continues to evaluate reliability and market efficiency in the area. As of March 31,September 30, 2023, AEP’s share of IEC capital expenditures was approximately $90$92 million, located in Total Property, Plant and Equipment - Net on AEP’s balance sheets. The FERC has previously granted abandonment benefits for this project, allowing the full recovery of prudently incurred costs if the project is cancelled for reasons outside the control of Transource Energy. If any of the IEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

FERC RTO Incentive Complaint (Applies to AEP, AEPTCo and OPCo)

In February 2022, the Office of the Ohio Consumers’ CounselOCC 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 FebruaryDecember 2022 decision. This decision has been appealed to the U.S. Court of Appeals for the Sixth Circuit. Management expects the December 2022 FERC order to reduce AEP’s pretax income by approximately $20 million on an annual basis. This decision has been appealed to the U.S. Court of Appeals for the Sixth Circuit.


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Request to Update AEGCo Depreciation Rates (Applies to AEP and I&M)

In October 2022, AEP, on behalf of AEGCo, submitted proposed revisions to AEGCo’s depreciation rates for its 50% ownership interest in Rockport Plant, Unit 1 and Unit 2, reflected in AEGCo’s unit power agreement withthe 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.

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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 Unit Power Agreement’sUPA’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. ItIn 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. An order from the FERC on this settlement agreement is expected thatin the fourth quarter of 2023. If the FERC finalizes the settlement agreement as proposed, management anticipates the results of the order will issue an ordernot have a material impact on this review in the second halffinancial condition, results of 2023. This FERC review and subsequent order on these issues could reduce future net income andoperations or cash flows and impact financial conditions.flows.

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

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 PJM Transmission Formula Rates of the AEP transmission owning subsidiaries within PJM. This challengePJM and SPP, respectively. These challenges primarily relatesrelate to stand-alone treatment of NOLCs in the transmission formula rates of the AEP transmission owning subsidiaries within PJM. In April 2023,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.FERC in the second quarter of 2023.

AEPThe 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, $60$69 million and $78 million, respectively (of which $40 million, $53 million, and $56 million relate to PJM transmission formula rates, respectively).respectively. Through the firstthird quarter of 2023, AEP’sthe Registrants’ financial statements reflect a provision for refund for certain NOLC revenues billed by PJM and SPP. Also, a certain portion of the impact of including NOLCs in the 2021 annual formula rate true-up not yet billed by PJM and SPP is not reflected in the Registrants’ revenues and expenses asIf the Registrants have not met the requirementsare required to make refunds as a result of alternative revenue recognition in accordance with the accounting guidance for “Regulated Operations”.these challenges, it could reduce future net income and cash flows and impact financial condition.
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5.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

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

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

For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2022 Annual Report should be read in conjunction with this report.

GUARANTEES

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

Letters of Credit (Applies to AEP, AEP Texas, APCo and AEP Texas)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 March 31,September 30, 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 March 31,September 30, 2023 were as follows:
CompanyAmountMaturity
 (in millions) 
AEP$299.0249.1 AprilOctober 2023 to MarchSeptember 2024
AEP Texas1.8 July 20232024
APCo6.3 September 2024
I&M2.9 September 2024


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Guarantees of Equity Method Investees (Applies to AEP)

Parent has issued guarantees over the performance of certain non-consolidated joint ventures included within the competitive contracted renewables portfolio and NM Renewable Development, LLC. If a joint venture were to default on payments or performance, Parent would be required to make payments on behalf of the joint venture. As of March 31, 2023, the maximum potential amount of future payments associated with the remaining guarantees was $78 million, with the last guarantee expiring in December 2045. The non-contingent liability recorded associated with these guarantees was $5 million, with an additional $1 million expected credit loss liability for the contingent portion of the guarantees. In accordance with the accounting guidance for guarantees, the initial recognition of the non-contingent liabilities increased AEP’s carrying values of the respective equity method investees. Management considered historical losses, economic conditions and reasonable and supportable forecasts in the calculation of the expected credit loss. As the joint ventures generate cash flows through PPAs, the measurement of the contingent portion of the guarantee liability is based upon assessments of the credit quality and default probabilities of the respective PPA counterparties.

Indemnifications and Other Guarantees

Contracts

The Registrants enter into certain types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, exposure generally does not exceed the sale price.  As of March 31,September 30, 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.

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 March 31,September 30, 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:
CompanyMaximum
Potential Loss
(in millions)
AEP$46.444.8 
AEP Texas11.210.9 
APCo6.05.6 
I&M4.34.2 
OPCo7.46.9 
PSO4.94.7 
SWEPCo5.75.3 


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ENVIRONMENTAL CONTINGENCIES (Applies to all Registrants except AEPTCo)

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

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

NUCLEAR CONTINGENCIES (Applies to AEP and I&M)

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

OPERATIONAL CONTINGENCIES

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 on April 29, 2022. On September 13, 2022, the New York state
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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. On January 20, 2023, the New York plaintiff filed a motion to intervene in the pending Ohio federal court action and withdrew his appeal in New York. 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. On March 20, 2023, the federal district court issued an order granting the motion to dismiss with prejudice and denying the New York plaintiffs’ motion to intervene. On April 20, 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. On June 15, 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. 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 HB6HB 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 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. Althoughindividuals and inquiries regarding Empowering Ohio’s Economy, Inc., which is a 501(c)(4) social welfare organization, and related disclosures. AEP and the outcomeSEC are engaged in discussions about a possible resolution of the SEC’s investigation and potential claims under the securities laws, the outcome of which cannot be predicted and could subject AEP to civil penalties and other remedial measures. 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 financial condition, results of operations, cash flows or cash flows.financial condition.


Claims for Indemnification Related to Damages Resulting fromMade by Owners of the Federal EPA’s Denial of Alternative Closure Deadline for Gavin Plant and Associated Findings of CompliancePower 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 determinations related to the CCR Rule (see “Environmental Issues - Coal Combustion Residual (CCR)CCR Rule” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information), including a determination that the closure of the 300 acre unlined fly ash reservoir (FAR) is noncompliant with the CCR Rule in multiple respects. The Gavin Power Station was formerly owned and operated by AEP and was sold to Gavin Power LLC and Lightstone Generation LLC in 2017. Pursuant to the PSA, AEP maintained responsibility to complete closure of the FAR in accordance with the closure plan approved by the Ohio EPA which was completed in July 2021. The PSA contains indemnification provisions, pursuant to which the owners of the Gavin Power Station have notified AEP they believe they are entitled to indemnification for any damages that may result from the Gavin Denial, as well asthese claims, including any future enforcement or litigation resulting from the Federal EPA’s determinations of noncompliance with various aspects of the CCR Rule as part of the Gavin Denial. The owners of the Gavin Power Station have also sought indemnification for landowner claims for property damage
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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.
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Claims for Damages Related to Sabine Coal Supply ContractLignite Mining Agreement

In AprilMay 2023, AEP received a letter from North American Coal Corporation (NACC) alleging that SWEPCo breached it’s coal supply contract withand Sabine, a subsidiary of NACC. The letter contendsNACC, filed suit against SWEPCo in Texas state court for breach of the Lignite Mining Agreement (LMA) between Sabine and SWEPCo. NACC and Sabine assert that the terms of the LMA require SWEPCo is obligated to runcontinue operating the Pirkey Plant untiland obtaining coal from the Sabine mine through 2035 and that SWEPCo has breached the agreement by closing the plant. In August 2023, a settlement agreement was reached and the suit was dismissed by the Texas state court. The settlement agreement did not have a material impact on SWEPCo’s net income, cash flows or to pay $85 million in damages representing lost mining fees to Sabine. The letter threatens legal action for unspecified injunctive relief and breach of contract. Management does not believe SWEPCo is obligated to run the Pirkey Plant for any period of time beyond its useful life or that there is a valid claim for breach of contract or damages. Management is unable to determine a range of potential losses that is reasonably possible of occurring.financial condition.



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6. ACQUISITIONS, DISPOSITIONS AND ASSETS AND LIABILITIES HELD FOR SALEIMPAIRMENTS

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

ACQUISITIONS

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 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, the third of the three NCWF acquisitions. 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. 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 current and noncurrent Obligations Under Operating Leases related to Rock Falls were not material as of March 31,September 30, 2023. See the “2022 Oklahoma Base Rate Case” section of Note 4 for additional information.

ASSETS AND LIABILITIES HELD FOR SALEDISPOSITIONS

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.

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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.As a result of the March 2023 filings made by intervenors with the FERC and the Termination Agreement, the assets and liabilities of KPCo and KTCo were reclassified out of Held for Sale on the March 31, 2023 and December 31, 2022 balance sheets of AEP and AEPTCo.

The impact of the Termination Agreement did not have a material impact on AEP’s statements of income for the three and nine months ended March 31,September 30, 2023. Upon reverting to a held and used model in the first quarter of 2023, AEP iswas required to present its investment in the Kentucky Operations at the lower of fair value or historical carrying value. As a result, AEP’s March 31, 2023 and December 31, 2022 balance sheets reflectvalue which resulted in a $335 million and $363 million, respectively, pretax reduction in the basis of its investment in KPCo’s assets which is recorded in Property, Plant and Equipment. The change in AEP’s basis of itsreduced investment in KPCo’s assets from December 31, 2022 to March 31, 2023 reflectsis being amortized over the elimination30-year average useful life of the expected costs to sell from the measurement.KPCo assets.

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 (the portfolio) within the Generation & Marketing segment. As of March 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 towith 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 customary closing conditions, including 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.party. AEP recorded a pretax loss of $112 million ($88 million after-tax), in the first quarter of 2023 after reaching Held for Sale status and determining the carrying value of the portfolio exceeded the estimated fair value.

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.

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

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 reaching Held for Sale status. Management concludedFlat Ridge 2’s deteriorating financial performance, sale negotiations and AEP’s ongoing evaluation and ultimate decision to exit the impact of any other than temporaryinvestment 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 four joint venture wind farmsaccounting 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 not materialbased 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 March 31, 2023 financial statements. Any changes toStatement 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 book value or carrying valuefourth quarter of these assets, or the anticipated sale price, could further reduce future net income2022 and had an immaterial impact financial condition.

The Income Before Income Tax Expense (Benefit) of the competitive contracted renewables portfolio was not material to AEP on its statements of income for the three months ended March 31, 2023 and 2022.

In March 2023, AEP ceased recognition of depreciation on the competitive contracted renewable portfolio assets due to their classification as Held for Sale on the balance sheets. The major classes of the assets and liabilities presented in Assets Held for Sale and Liabilities Held for Sale on the balance sheets of AEP are shown in the following table:financial statements at closing.
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March 31, 2023
(in millions)
ASSETS
Accounts Receivable and Accrued Unbilled Revenues$16.9 
Property, Plant and Equipment, Net1,404.7 
Other Classes of Assets that are not Major63.2 
Total Major Classes of Assets Held for Sale1,484.8 
Loss on the Expected Sale of the Competitive Contracted Renewables Portfolio (net of $23.5 million of Income Taxes)(88.5)
Assets Held for Sale$1,396.3 
LIABILITIES
Accounts Payable$6.8 
Asset Retirement Obligations30.6 
Obligations Under Operating Leases20.1 
Other Classes of Liabilities that are not Major9.7 
Liabilities Held for Sale$67.2 

The four joint venture wind farms totaling $247 million as of March 31, 2023, which are included in the plan of sale, continue to be classified as Deferred Charges and Other Noncurrent Assets and $192 million attributable to noncontrolling interests continues to be classified as Noncontrolling Interests on AEP’s consolidated balance sheets.
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7.  BENEFIT PLANS

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

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

Components of Net Periodic Benefit Cost (Credit)

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

AEP
Pension PlansOPEB
Three Months Ended March 31,Three Months Ended March 31,
2023202220232022
Three Months Ended September 30, 2023Three Months Ended September 30, 2023AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)(in millions)
Service CostService Cost$23.6 $30.8 $1.1 $1.8 Service Cost$23.6 $2.1 $2.3 $2.9 $2.1 $1.4 $2.0 
Interest CostInterest Cost54.8 37.0 11.6 7.3 Interest Cost54.8 4.5 6.6 6.3 5.0 2.7 3.4 
Expected Return on Plan AssetsExpected Return on Plan Assets(84.8)(63.4)(27.4)(27.5)Expected Return on Plan Assets(84.8)(7.0)(11.2)(11.0)(8.6)(4.6)(4.8)
Amortization of Prior Service Credit— — (15.8)(17.8)
Amortization of Net Actuarial LossAmortization of Net Actuarial Loss0.3 15.8 3.7 — Amortization of Net Actuarial Loss0.3 — — — — — — 
Net Periodic Benefit Cost (Credit)Net Periodic Benefit Cost (Credit)$(6.1)$20.2 $(26.8)$(36.2)Net Periodic Benefit Cost (Credit)$(6.1)$(0.4)$(2.3)$(1.8)$(1.5)$(0.5)$0.6 

AEP Texas
Pension PlansOPEB
Three Months Ended March 31,Three Months Ended March 31,
2023202220232022
Three Months Ended September 30, 2022Three Months Ended September 30, 2022AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)(in millions)
Service CostService Cost$2.0 $2.8 $0.1 $0.1 Service Cost$30.7 $2.8 $2.9 $4.0 $2.8 $1.8 $2.7 
Interest CostInterest Cost4.6 3.0 0.9 0.6 Interest Cost37.1 3.1 4.3 4.3 3.4 1.8 2.2 
Expected Return on Plan AssetsExpected Return on Plan Assets(7.0)(5.3)(2.3)(2.3)Expected Return on Plan Assets(63.4)(5.3)(8.1)(8.1)(6.2)(3.3)(3.6)
Amortization of Prior Service Credit— — (1.3)(1.5)
Amortization of Net Actuarial LossAmortization of Net Actuarial Loss— 1.3 0.3 — Amortization of Net Actuarial Loss15.8 1.2 1.9 1.8 1.3 0.7 0.9 
Net Periodic Benefit Cost (Credit)$(0.4)$1.8 $(2.3)$(3.1)
Net Periodic Benefit CostNet Periodic Benefit Cost$20.2 $1.8 $1.0 $2.0 $1.3 $1.0 $2.2 

APCo
Nine Months Ended September 30, 2023AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Service Cost$70.8 $6.2 $6.8 $8.9 $6.3 $4.2 $5.8 
Interest Cost164.4 13.7 19.8 18.7 14.9 8.1 10.4 
Expected Return on Plan Assets(254.4)(21.0)(33.5)(33.1)(25.6)(13.8)(14.5)
Amortization of Net Actuarial Loss1.0 — — — — — — 
Net Periodic Benefit Cost (Credit)$(18.2)$(1.1)$(6.9)$(5.5)$(4.4)$(1.5)$1.7 
Pension PlansOPEB
Three Months Ended March 31,Three Months Ended March 31,
 2023202220232022
 (in millions)
Service Cost$2.3 $2.9 $0.1 $0.2 
Interest Cost6.6 4.4 1.8 1.2 
Expected Return on Plan Assets(11.2)(8.1)(4.0)(4.1)
Amortization of Prior Service Credit— — (2.3)(2.6)
Amortization of Net Actuarial Loss— 1.8 0.6 — 
Net Periodic Benefit Cost (Credit)$(2.3)$1.0 $(3.8)$(5.3)

Nine Months Ended September 30, 2022AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Service Cost$92.3 $8.4 $8.6 $12.1 $8.4 $5.5 $8.0 
Interest Cost111.2 9.1 13.1 12.7 10.0 5.3 6.8 
Expected Return on Plan Assets(190.1)(15.8)(24.3)(24.2)(18.6)(10.1)(10.9)
Amortization of Net Actuarial Loss47.3 3.8 5.5 5.3 4.1 2.2 2.8 
Net Periodic Benefit Cost$60.7 $5.5 $2.9 $5.9 $3.9 $2.9 $6.7 

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I&M
Pension PlansOPEB
Three Months Ended March 31,Three Months Ended March 31,
 2023202220232022
 (in millions)
Service Cost$3.0 $4.0 $0.2 $0.2 
Interest Cost6.2 4.2 1.3 0.8 
Expected Return on Plan Assets(11.0)(8.0)(3.4)(3.4)
Amortization of Prior Service Credit— — (2.2)(2.4)
Amortization of Net Actuarial Loss— 1.8 0.5 — 
Net Periodic Benefit Cost (Credit)$(1.8)$2.0 $(3.6)$(4.8)
OPEB

OPCo
Pension PlansOPEB
Three Months Ended March 31,Three Months Ended March 31,
2023202220232022
Three Months Ended September 30, 2023Three Months Ended September 30, 2023AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)(in millions)
Service CostService Cost$2.1 $2.7 $0.1 $0.2 Service Cost$1.1 $0.1 $0.1 $0.1 $0.1 $0.1 $— 
Interest CostInterest Cost4.9 3.4 1.2 0.7 Interest Cost11.6 0.9 1.8 1.3 1.2 0.6 0.8 
Expected Return on Plan AssetsExpected Return on Plan Assets(8.5)(6.2)(2.9)(3.0)Expected Return on Plan Assets(27.4)(2.2)(4.0)(3.3)(2.9)(1.5)(1.8)
Amortization of Prior Service CreditAmortization of Prior Service Credit— — (1.6)(1.8)Amortization of Prior Service Credit(15.8)(1.3)(2.3)(2.2)(1.6)(1.0)(1.3)
Amortization of Net Actuarial LossAmortization of Net Actuarial Loss— 1.4 0.4 — Amortization of Net Actuarial Loss3.7 0.3 0.6 0.5 0.4 0.2 0.3 
Net Periodic Benefit Cost (Credit)$(1.5)$1.3 $(2.8)$(3.9)
Net Periodic Benefit CreditNet Periodic Benefit Credit$(26.8)$(2.2)$(3.8)$(3.6)$(2.8)$(1.6)$(2.0)

PSO
Pension PlansOPEB
Three Months Ended March 31,Three Months Ended March 31,
2023202220232022
Three Months Ended September 30, 2022Three Months Ended September 30, 2022AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)(in millions)
Service CostService Cost$1.4 $1.9 $0.1 $0.1 Service Cost$1.8 $0.1 $0.2 $0.2 $0.2 $0.2 $0.1 
Interest CostInterest Cost2.7 1.8 0.6 0.4 Interest Cost7.3 0.6 1.2 0.8 0.7 0.4 0.5 
Expected Return on Plan AssetsExpected Return on Plan Assets(4.6)(3.4)(1.5)(1.5)Expected Return on Plan Assets(27.5)(2.3)(4.1)(3.3)(3.0)(1.6)(1.8)
Amortization of Prior Service CreditAmortization of Prior Service Credit— — (1.0)(1.1)Amortization of Prior Service Credit(17.9)(1.5)(2.6)(2.4)(1.8)(1.1)(1.4)
Amortization of Net Actuarial Loss— 0.7 0.2 — 
Net Periodic Benefit Cost (Credit)$(0.5)$1.0 $(1.6)$(2.1)
Net Periodic Benefit CreditNet Periodic Benefit Credit$(36.3)$(3.1)$(5.3)$(4.7)$(3.9)$(2.1)$(2.6)

SWEPCo
Nine Months Ended September 30, 2023AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Service Cost$3.4 $0.3 $0.4 $0.5 $0.3 $0.2 $0.2 
Interest Cost34.7 2.7 5.5 4.0 3.5 1.8 2.2 
Expected Return on Plan Assets(82.2)(6.7)(12.0)(10.1)(8.8)(4.4)(5.4)
Amortization of Prior Service Credit(47.3)(4.0)(6.9)(6.5)(4.7)(3.0)(3.7)
Amortization of Net Actuarial Loss11.1 0.9 1.7 1.4 1.2 0.6 0.8 
Net Periodic Benefit Credit$(80.3)$(6.8)$(11.3)$(10.7)$(8.5)$(4.8)$(5.9)
Pension PlansOPEB
Three Months Ended March 31,Three Months Ended March 31,
 2023202220232022
 (in millions)
Service Cost$1.9 $2.6 $0.1 $0.1 
Interest Cost3.5 2.3 0.7 0.5 
Expected Return on Plan Assets(4.8)(3.7)(1.8)(1.9)
Amortization of Prior Service Credit— — (1.2)(1.3)
Amortization of Net Actuarial Loss— 1.0 0.2 — 
Net Periodic Benefit Cost (Credit)$0.6 $2.2 $(2.0)$(2.6)

Nine Months Ended September 30, 2022AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Service Cost$5.5 $0.3 $0.6 $0.7 $0.5 $0.4 $0.4 
Interest Cost21.9 1.7 3.5 2.5 2.2 1.1 1.4 
Expected Return on Plan Assets(82.5)(6.8)(12.2)(10.2)(8.9)(4.6)(5.5)
Amortization of Prior Service Credit(53.6)(4.5)(7.8)(7.3)(5.4)(3.3)(4.0)
Net Periodic Benefit Credit$(108.7)$(9.3)$(15.9)$(14.3)$(11.6)$(6.4)$(7.7)





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8.  BUSINESS SEGMENTS

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

AEP’s Reportable Segments

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

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

Vertically Integrated Utilities

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

Transmission and Distribution Utilities

Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo.
OPCo purchases energy and capacity to serve standard service offer customers and provides transmission and distribution services for all connected load.

AEP Transmission Holdco

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

Generation & Marketing

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

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










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The tables below represent AEP’s reportable segment income statement information for the three and nine months ended March 31,September 30, 2023 and 2022 and reportable segment balance sheet information as of March 31,September 30, 2023 and December 31, 2022.
Three Months Ended March 31, 2023Three Months Ended September 30, 2023
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing
Corporate and Other (a)Reconciling AdjustmentsConsolidatedVertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing
Corporate and Other (a)Reconciling AdjustmentsConsolidated
(in millions) (in millions)
Revenues from:Revenues from:      Revenues from:      
External CustomersExternal Customers$2,816.3 $1,455.3 $90.1 $326.9 $2.3 $— $4,690.9 External Customers$3,158.1 $1,535.2 $94.0 $527.5 $26.9 $— $5,341.7 
Other Operating SegmentsOther Operating Segments41.5 8.9 365.4 0.1 27.8 (443.7)— Other Operating Segments47.3 8.9 382.7 39.2 30.3 (508.4)— 
Total RevenuesTotal Revenues$2,857.8 $1,464.2 $455.5 $327.0 $30.1 $(443.7)$4,690.9 Total Revenues$3,205.4 $1,544.1 $476.7 $566.7 $57.2 $(508.4)$5,341.7 
Net Income (Loss)Net Income (Loss)$262.2 $125.7 $182.4 $(156.4)$(13.5)$— $400.4 Net Income (Loss)$514.0 $206.0 $203.9 $132.8 $(98.4)$— $958.3 
Three Months Ended March 31, 2022Three Months Ended September 30, 2022
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing
Corporate and Other (a)Reconciling AdjustmentsConsolidated Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing
Corporate and Other (a)Reconciling AdjustmentsConsolidated
(in millions) (in millions)
Revenues from:Revenues from:      Revenues from:      
External CustomersExternal Customers$2,646.8 $1,242.2 $83.4 $609.5 $10.7 $— $4,592.6 External Customers$3,174.6 $1,525.5 $81.9 $733.1 $11.0 $— $5,526.1 
Other Operating SegmentsOther Operating Segments40.6 4.6 328.0 9.8 9.2 (392.2)— Other Operating Segments51.7 4.7 349.0 2.3 17.3 (425.0)— 
Total RevenuesTotal Revenues$2,687.4 $1,246.8 $411.4 $619.3 $19.9 $(392.2)$4,592.6 Total Revenues$3,226.3 $1,530.2 $430.9 $735.4 $28.3 $(425.0)$5,526.1 
Net Income (Loss)Net Income (Loss)$299.2 $152.8 $173.7 $116.0 $(23.6)$— $718.1 Net Income (Loss)$476.9 $165.5 $171.4 $96.2 $(226.7)$— $683.3 
Nine Months Ended September 30, 2023
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing
Corporate and Other (a)Reconciling AdjustmentsConsolidated
 (in millions)
Revenues from:      
External Customers$8,603.4 $4,321.3 $272.4 $1,172.6 $35.4 $— $14,405.1 
Other Operating Segments134.3 27.2 1,118.4 52.5 83.9 (1,416.3)— 
Total Revenues$8,737.7 $4,348.5 $1,390.8 $1,225.1 $119.3 $(1,416.3)$14,405.1 
Net Income (Loss)$1,054.6 $508.4 $583.6 $(62.2)$(209.6)$— $1,874.8 
Nine Months Ended September 30, 2022
 Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing
Corporate and Other (a)Reconciling AdjustmentsConsolidated
 (in millions)
Revenues from:      
External Customers$8,416.4 $4,064.5 $244.4 $1,997.0 $36.1 $— $14,758.4 
Other Operating Segments145.8 14.1 976.7 17.3 36.6 (1,190.5)— 
Total Revenues$8,562.2 $4,078.6 $1,221.1 $2,014.3 $72.7 $(1,190.5)$14,758.4 
Net Income (Loss)$1,079.4 $483.1 $487.8 $278.1 $(406.2)$— $1,922.2 

March 31, 2023
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing
Corporate and Other (a)Reconciling
Adjustments
Consolidated
 (in millions)
Total Assets (d)$50,164.1 $23,437.0 $15,883.1 $4,159.8 $6,457.2 (b)$(5,583.3)(c)$94,517.9 



147


September 30, 2023
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing
Corporate and Other (a)Reconciling
Adjustments
Consolidated
 (in millions)
Total Assets$50,940.3 $24,327.9 $16,155.0 $2,517.0 $4,567.2 (b)$(3,381.8)(c)$95,125.6 
December 31, 2022
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing
Corporate and Other (a)Reconciling
Adjustments
Consolidated
 (in millions)
Total Assets$49,761.8 $22,920.2 $15,215.8 $4,520.1 $6,768.4 (b)$(5,783.0)(c)$93,403.3 

(a)Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and other nonallocated costs.
(b)Includes elimination of AEP Parent’s investments in wholly-owned subsidiary companies.
(c)Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable.
(d)Amount includes Assets Held for Sale on the balance sheet. See “Planned Disposition of the Competitive Contracted Renewables Portfolio” section of Note 6 for additional information.


148



Registrant Subsidiaries’ Reportable Segments (Applies to all Registrant Subsidiaries except AEPTCo)

The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an integrated electricity transmission and distribution business for AEP Texas and OPCo.  Other activities are insignificant.  The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.

AEPTCo’s Reportable Segments

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

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

The tables below present AEPTCo’s reportable segment income statement information for the three and nine months ended March 31,September 30, 2023 and 2022 and reportable segment balance sheet information as of March 31,September 30, 2023 and December 31, 2022.
Three Months Ended March 31, 2023
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Revenues from:
External Customers$89.0 $— $— $89.0 
Sales to AEP Affiliates352.6 — — 352.6 
Total Revenues$441.6 $— $— $441.6 
Net Income$161.6 $1.1 (a)$— $162.7 
Three Months Ended March 31, 2022
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Revenues from:
External Customers$75.7 $— $— $75.7 
Sales to AEP Affiliates324.7 — — 324.7 
Total Revenues$400.4 $— $— $400.4 
Net Income$155.4 $— (a)$— $155.4 
149148



March 31, 2023
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Total Assets$14,493.6 $5,581.6 (b)$(5,620.5)(c)$14,454.7 
December 31, 2022
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Total Assets$13,875.6 $4,817.4 (b)$(4,878.8)(c)$13,814.2 
Three Months Ended September 30, 2023
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Revenues from:
External Customers$92.8 $— $— $92.8 
Sales to AEP Affiliates369.9 — — 369.9 
Total Revenues$462.7 $— $— $462.7 
Net Income$178.2 $1.0 (a)$— $179.2 
Three Months Ended September 30, 2022
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Revenues from:
External Customers$87.2 $— $— $87.2 
Sales to AEP Affiliates331.3 — — 331.3 
Total Revenues$418.5 $— $— $418.5 
Net Income$152.6 $0.1 (a)$— $152.7 
Nine Months Ended September 30, 2023
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo Consolidated
(in millions)
Revenues from:
External Customers$269.2 $— $— $269.2 
Sales to AEP Affiliates1,080.0 — — 1,080.0 
Total Revenues$1,349.2 $— $— $1,349.2 
Net Income$514.0 $3.6 (a)$— $517.6 
Nine Months Ended September 30, 2022
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo Consolidated
(in millions)
Revenues from:
External Customers$249.5 $— $— $249.5 
Sales to AEP Affiliates933.8 — — 933.8 
Total Revenues$1,183.3 $— $— $1,183.3 
Net Income$426.4 $0.2 (a)$— $426.6 
September 30, 2023
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Total Assets$14,760.8 $5,561.2 (b)$(5,610.0)(c)$14,712.0 
December 31, 2022
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Total Assets$13,875.6 $4,817.4 (b)$(4,878.8)(c)$13,814.2 

(a)Includes the elimination of AEPTCo Parent’s equity earnings in the State Transcos.
(b)Primarily relates to Notes Receivable from the State Transcos.
(c)Primarily relates to the elimination of Notes Receivable from the State Transcos.


150149



9.  DERIVATIVES AND HEDGING

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

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

AEPSC is agent for and transacts on behalf of 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.

151150



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

Notional Volume of Derivative Instruments
March 31,September 30, 2023
Primary Risk
Exposure
Primary Risk
Exposure
Unit of
Measure
AEPAEP TexasAPCoI&MOPCoPSOSWEPCoPrimary Risk
Exposure
Unit of
Measure
AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)(in millions)
Commodity:Commodity:      Commodity:      
PowerPowerMWhs213.5 — 7.3 4.1 2.4 1.8 1.3 PowerMWhs262.3 — 28.4 9.0 2.3 5.6 4.4 
Natural GasNatural GasMMBtus92.8 — 2.9 — — 3.1 1.8 Natural GasMMBtus149.8 — 27.3 — — 25.3 13.1 
Heating Oil and GasolineHeating Oil and GasolineGallons5.0 1.4 0.8 0.5 1.0 0.7 0.7 Heating Oil and GasolineGallons8.3 2.2 1.3 0.8 1.7 1.1 1.2 
Interest RateInterest RateUSD$91.4 $— $— $— $— $— $— Interest RateUSD$80.1 $— $— $— $— $— $— 
Interest Rate on Long-term DebtInterest Rate on Long-term DebtUSD$1,700.0 $150.0 $— $— $— $— $— Interest Rate on Long-term DebtUSD$950.0 $— $— $— $— $— $— 

December 31, 2022
Primary Risk
Exposure
Unit of
Measure
AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Commodity:      
PowerMWhs226.8 — 17.9 4.2 2.5 2.9 2.2 
Natural GasMMBtus77.1 — 1.9 — — 1.9 2.1 
Heating Oil and GasolineGallons6.9 1.9 1.0 0.7 1.4 0.9 1.0 
Interest RateUSD$99.9 $— $— $— $— $— $— 
Interest Rate on Long-term DebtUSD$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.
152151



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 $108$93 million and $481 million as of March 31,September 30, 2023 and December 31, 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 March 31,September 30, 2023 and December 31, 2022. The amount of cash collateral paid to third-parties netted against short-term and long-term risk management liabilities was immaterial for the Registrants as of March 31,September 30, 2023 and December 31, 2022.
153152



The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets. 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
March 31, 2023September 30, 2023
Risk
Management
Contracts
Hedging ContractsGross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Risk
Management
Contracts
Hedging ContractsGross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet LocationBalance Sheet LocationCommodity (a)Commodity (a)Interest Rate (a)Balance Sheet LocationCommodity (a)Commodity (a)Interest Rate (a)
(in millions) (in millions)
Current Risk Management AssetsCurrent Risk Management Assets$621.1 $85.0 $8.9 $715.0 $(524.4)$190.6 Current Risk Management Assets$595.7 $55.6 $— $651.3 $(388.6)$262.7 
Long-term Risk Management AssetsLong-term Risk Management Assets494.3 117.0 — 611.3 (293.1)318.2 Long-term Risk Management Assets465.3 83.3 — 548.6 (258.4)290.2 
Total AssetsTotal Assets1,115.4 202.0 8.9 1,326.3 (817.5)508.8 Total Assets1,061.0 138.9 — 1,199.9 (647.0)552.9 
Current Risk Management LiabilitiesCurrent Risk Management Liabilities562.5 87.5 39.5 689.5 (523.5)166.0 Current Risk Management Liabilities460.3 9.9 43.2 513.4 (361.9)151.5 
Long-term Risk Management LiabilitiesLong-term Risk Management Liabilities402.6 31.4 82.7 516.7 (201.3)315.4 Long-term Risk Management Liabilities374.8 1.2 94.9 470.9 (192.5)278.4 
Total LiabilitiesTotal Liabilities965.1 118.9 122.2 1,206.2 (724.8)481.4 Total Liabilities835.1 11.1 138.1 984.3 (554.4)429.9 
Total MTM Derivative Contract Net Assets (Liabilities) (d)Total MTM Derivative Contract Net Assets (Liabilities) (d)$150.3 $83.1 $(113.3)$120.1 $(92.7)$27.4 Total MTM Derivative Contract Net Assets (Liabilities) (d)$225.9 $127.8 $(138.1)$215.6 $(92.6)$123.0 

December 31, 2022
Risk
Management
Contracts
Hedging ContractsGross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet LocationCommodity (a)Commodity (a)Interest Rate (a)
(in millions)
Current Risk Management Assets$965.4 $212.2 $1.8 $1,179.4 $(830.6)$348.8 
Long-term Risk Management Assets565.6 148.9 14.3 728.8 (444.7)284.1 
Total Assets1,531.0 361.1 16.1 1,908.2 (1,275.3)632.9 
Current Risk Management Liabilities663.8 60.4 41.4 765.6 (620.4)145.2 
Long-term Risk Management Liabilities412.0 17.4 91.1 520.5 (175.3)345.2 
Total Liabilities1,075.8 77.8 132.5 1,286.1 (795.7)490.4 
Total MTM Derivative Contract Net Assets (Liabilities)$455.2 $283.3 $(116.4)$622.1 $(479.6)$142.5 

154153



AEP Texas
September 30, 2023
March 31, 2023Risk ManagementGross Amounts OffsetNet Amounts of Assets/Liabilities
Risk Management Contracts -Hedging ContractsGross Amounts of Risk Management Assets/Liabilities RecognizedGross Amounts Offset in the Statement of Financial Position (b)Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c)Contracts –in the Statement ofPresented in the Statement of
Balance Sheet LocationBalance Sheet LocationCommodity (a)Interest Rate (a)Balance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)
(in millions)(in millions)
Current Risk Management AssetsCurrent Risk Management Assets$— $0.5 $0.5 $— $0.5 Current Risk Management Assets$0.4 $— $0.4 
Long-term Risk Management AssetsLong-term Risk Management Assets— — — — — Long-term Risk Management Assets— — — 
Total AssetsTotal Assets— 0.5 0.5 — 0.5 Total Assets0.4 — 0.4 
Current Risk Management LiabilitiesCurrent Risk Management Liabilities0.4 0.8 1.2 (0.4)0.8 Current Risk Management Liabilities— — — 
Long-term Risk Management LiabilitiesLong-term Risk Management Liabilities— — — — — Long-term Risk Management Liabilities— — — 
Total LiabilitiesTotal Liabilities0.4 0.8 1.2 (0.4)0.8 Total Liabilities— — — 
Total MTM Derivative Contract Net Assets (Liabilities) (d)$(0.4)$(0.3)$(0.7)$0.4 $(0.3)
Total MTM Derivative Contract Net AssetsTotal MTM Derivative Contract Net Assets$0.4 $— $0.4 

December 31, 2022
Risk ManagementGross Amounts OffsetNet Amounts of Assets/Liabilities
Contracts –in the Statement ofPresented in the Statement of
Balance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)
(in millions)
Current Risk Management Assets$— $— $— 
Long-term Risk Management Assets— — — 
Total Assets— — — 
Current Risk Management Liabilities— — — 
Long-term Risk Management Liabilities— — — 
Total Liabilities— — — 
Total MTM Derivative Contract Net Assets$— $— $— 

155154



APCo
March 31, 2023September 30, 2023
Risk ManagementGross Amounts OffsetNet Amounts of Assets/LiabilitiesRisk ManagementGross Amounts OffsetNet Amounts of Assets/Liabilities
Contracts –in the Statement ofPresented in the Statement ofContracts –in the Statement ofPresented in the Statement of
Balance Sheet LocationBalance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)Balance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)
(in millions)(in millions)
Current Risk Management AssetsCurrent Risk Management Assets$12.8 $(0.4)$12.4 Current Risk Management Assets$48.8 $(2.4)$46.4 
Long-term Risk Management AssetsLong-term Risk Management Assets0.5 (0.5)— Long-term Risk Management Assets0.8 (0.6)0.2 
Total AssetsTotal Assets13.3 (0.9)12.4 Total Assets49.6 (3.0)46.6 
Current Risk Management LiabilitiesCurrent Risk Management Liabilities7.6 (0.6)7.0 Current Risk Management Liabilities4.2 (2.4)1.8 
Long-term Risk Management LiabilitiesLong-term Risk Management Liabilities0.5 (0.5)— Long-term Risk Management Liabilities1.5 (0.6)0.9 
Total LiabilitiesTotal Liabilities8.1 (1.1)7.0 Total Liabilities5.7 (3.0)2.7 
Total MTM Derivative Contract Net Assets (d)Total MTM Derivative Contract Net Assets (d)$5.2 $0.2 $5.4 Total MTM Derivative Contract Net Assets (d)$43.9 $— $43.9 

December 31, 2022
Risk ManagementGross Amounts OffsetNet Amounts of Assets/Liabilities
Contracts –in the Statement ofPresented in the Statement of
Balance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)
(in millions)
Current Risk Management Assets$69.3 $(0.2)$69.1 
Long-term Risk Management Assets0.7 (0.7)— 
Total Assets70.0 (0.9)69.1 
Current Risk Management Liabilities4.1 (0.5)3.6 
Long-term Risk Management Liabilities0.7 (0.6)0.1 
Total Liabilities4.8 (1.1)3.7 
Total MTM Derivative Contract Net Assets$65.2 $0.2 $65.4 
156155



I&M
March 31, 2023September 30, 2023
Risk ManagementGross Amounts OffsetNet Amounts of Assets/LiabilitiesRisk ManagementGross Amounts OffsetNet Amounts of Assets/Liabilities
Contracts –in the Statement ofPresented in the Statement ofContracts –in the Statement ofPresented in the Statement of
Balance Sheet LocationBalance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)Balance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)
(in millions)(in millions)
Current Risk Management AssetsCurrent Risk Management Assets$8.1 $(2.2)$5.9 Current Risk Management Assets$20.2 $(4.4)$15.8 
Long-term Risk Management AssetsLong-term Risk Management Assets5.5 (4.4)1.1 Long-term Risk Management Assets6.6 (1.2)5.4 
Total AssetsTotal Assets13.6 (6.6)7.0 Total Assets26.8 (5.6)21.2 
Current Risk Management LiabilitiesCurrent Risk Management Liabilities2.7 (2.3)0.4 Current Risk Management Liabilities5.3 (4.2)1.1 
Long-term Risk Management LiabilitiesLong-term Risk Management Liabilities4.4 (4.4)— Long-term Risk Management Liabilities1.0 (1.0)— 
Total LiabilitiesTotal Liabilities7.1 (6.7)0.4 Total Liabilities6.3 (5.2)1.1 
Total MTM Derivative Contract Net Assets (d)$6.5 $0.1 $6.6 
Total MTM Derivative Contract Net Assets (Liabilities)Total MTM Derivative Contract Net Assets (Liabilities)$20.5 $(0.4)$20.1 

December 31, 2022
Risk ManagementGross Amounts OffsetNet Amounts of Assets/Liabilities
Contracts –in the Statement ofPresented in the Statement of
Balance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)
(in millions)
Current Risk Management Assets$16.0 $(0.8)$15.2 
Long-term Risk Management Assets0.5 (0.3)0.2 
Total Assets16.5 (1.1)15.4 
Current Risk Management Liabilities0.9 (0.9)— 
Long-term Risk Management Liabilities0.3 (0.3)— 
Total Liabilities1.2 (1.2)— 
Total MTM Derivative Contract Net Assets$15.3 $0.1 $15.4 


157156



OPCo
March 31, 2023September 30, 2023
Risk ManagementGross Amounts OffsetNet Amounts of Assets/LiabilitiesRisk ManagementGross Amounts OffsetNet Amounts of Assets/Liabilities
Contracts –in the Statement ofPresented in the Statement ofContracts –in the Statement ofPresented in the Statement of
Balance Sheet LocationBalance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)Balance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)
(in millions)(in millions)
Current Risk Management AssetsCurrent Risk Management Assets$— $— $— Current Risk Management Assets$0.3 $— $0.3 
Long-term Risk Management AssetsLong-term Risk Management Assets— — — Long-term Risk Management Assets— — — 
Total AssetsTotal Assets— — — Total Assets0.3 — 0.3 
Current Risk Management LiabilitiesCurrent Risk Management Liabilities6.2 (0.2)6.0 Current Risk Management Liabilities5.7 — 5.7 
Long-term Risk Management LiabilitiesLong-term Risk Management Liabilities40.9 — 40.9 Long-term Risk Management Liabilities45.9 — 45.9 
Total LiabilitiesTotal Liabilities47.1 (0.2)46.9 Total Liabilities51.6 — 51.6 
Total MTM Derivative Contract Net Assets (Liabilities) (d)$(47.1)$0.2 $(46.9)
Total MTM Derivative Contract Net LiabilitiesTotal MTM Derivative Contract Net Liabilities$(51.3)$— $(51.3)

December 31, 2022
Risk ManagementGross Amounts OffsetNet Amounts of Assets/Liabilities
Contracts –in the Statement ofPresented in the Statement of
Balance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)
(in millions)
Current Risk Management Assets$— $— $— 
Long-term Risk Management Assets— — — 
Total Assets— — — 
Current Risk Management Liabilities2.1 (0.3)1.8 
Long-term Risk Management Liabilities37.9 — 37.9 
Total Liabilities40.0 (0.3)39.7 
Total MTM Derivative Contract Net Assets (Liabilities)$(40.0)$0.3 $(39.7)
158157



PSO
March 31, 2023September 30, 2023
Risk ManagementGross Amounts OffsetNet Amounts of Assets/LiabilitiesRisk ManagementGross Amounts OffsetNet Amounts of Assets/Liabilities
Contracts –in the Statement ofPresented in the Statement ofContracts –in the Statement ofPresented in the Statement of
Balance Sheet LocationBalance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)Balance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)
(in millions)(in millions)
Current Risk Management AssetsCurrent Risk Management Assets$9.9 $(0.5)$9.4 Current Risk Management Assets$28.3 $(0.1)$28.2 
Long-term Risk Management AssetsLong-term Risk Management Assets— — — Long-term Risk Management Assets0.3 (0.3)— 
Total AssetsTotal Assets9.9 (0.5)9.4 Total Assets28.6 (0.4)28.2 
Current Risk Management LiabilitiesCurrent Risk Management Liabilities1.8 (0.7)1.1 Current Risk Management Liabilities7.2 (0.1)7.1 
Long-term Risk Management LiabilitiesLong-term Risk Management Liabilities— — — Long-term Risk Management Liabilities0.4 (0.3)0.1 
Total LiabilitiesTotal Liabilities1.8 (0.7)1.1 Total Liabilities7.6 (0.4)7.2 
Total MTM Derivative Contract Net Assets (d)Total MTM Derivative Contract Net Assets (d)$8.1 $0.2 $8.3 Total MTM Derivative Contract Net Assets (d)$21.0 $— $21.0 

December 31, 2022
Risk Management Contracts –Hedging ContractsGross Amounts of Risk Management Assets/Liabilities RecognizedGross Amounts Offset in the Statement of Financial Position (b)Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c)
Balance Sheet LocationCommodity (a)Interest Rate (a)
(in millions)
Current Risk Management Assets$24.1 $1.6 $25.7 $(0.4)$25.3 
Long-term Risk Management Assets— — — — — 
Total Assets24.1 1.6 25.7 (0.4)25.3 
Current Risk Management Liabilities2.1 — 2.1 (0.5)1.6 
Long-term Risk Management Liabilities— — — — — 
Total Liabilities2.1 — 2.1 (0.5)1.6 
Total MTM Derivative Contract Net Assets$22.0 $1.6 $23.6 $0.1 $23.7 


159158



SWEPCo
March 31, 2023September 30, 2023
Risk ManagementGross Amounts OffsetNet Amounts of Assets/LiabilitiesRisk ManagementGross Amounts OffsetNet Amounts of Assets/Liabilities
Contracts –in the Statement ofPresented in the Statement ofContracts –in the Statement ofPresented in the Statement of
Balance Sheet LocationBalance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)Balance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)
(in millions)(in millions)
Current Risk Management AssetsCurrent Risk Management Assets$6.4 $(0.1)$6.3 Current Risk Management Assets$17.6 $(0.5)$17.1 
Long-term Risk Management AssetsLong-term Risk Management Assets— — — Long-term Risk Management Assets— — — 
Total AssetsTotal Assets6.4 (0.1)6.3 Total Assets17.6 (0.5)17.1 
Current Risk Management LiabilitiesCurrent Risk Management Liabilities1.4 (0.3)1.1 Current Risk Management Liabilities3.6 (0.5)3.1 
Long-term Risk Management LiabilitiesLong-term Risk Management Liabilities— — — Long-term Risk Management Liabilities0.4 — 0.4 
Total LiabilitiesTotal Liabilities1.4 (0.3)1.1 Total Liabilities4.0 (0.5)3.5 
Total MTM Derivative Contract Net Assets (d)Total MTM Derivative Contract Net Assets (d)$5.0 $0.2 $5.2 Total MTM Derivative Contract Net Assets (d)$13.6 $— $13.6 

December 31, 2022
Risk ManagementGross Amounts OffsetNet Amounts of Assets/Liabilities
Contracts –in the Statement ofPresented in the Statement of
Balance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)
(in millions)
Current Risk Management Assets$16.8 $(0.4)$16.4 
Long-term Risk Management Assets— — — 
Total Assets16.8 (0.4)16.4 
Current Risk Management Liabilities2.0 (0.6)1.4 
Long-term Risk Management Liabilities— — — 
Total Liabilities2.0 (0.6)1.4 
Total MTM Derivative Contract Net Assets$14.8 $0.2 $15.0 

(a)Derivative instruments within these categories are disclosed as gross.  These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.”
(b)Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”
(c)All derivative contracts subject to a master netting arrangement or similar agreement are offset in the statement of financial position.
(d)Decrease in amounts as of March 31, 2023 are primarily due to decreases in commodity prices for power and natural gas and a decrease in value of FTRs.
160159



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

Amount of Gain (Loss) Recognized on Risk Management Contracts
Three Months Ended March 31, 2023Three Months Ended September 30, 2023
Location of Gain (Loss)Location of Gain (Loss)AEPAEP TexasAPCoI&MOPCoPSOSWEPCoLocation of Gain (Loss)AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)(in millions)
Vertically Integrated Utilities RevenuesVertically Integrated Utilities Revenues$(5.3)$— $— $— $— $— $— Vertically Integrated Utilities Revenues$(9.5)$— $— $— $— $— $— 
Generation & Marketing RevenuesGeneration & Marketing Revenues(147.4)— — — — — — Generation & Marketing Revenues(1.4)— — — — — — 
Electric Generation, Transmission and Distribution RevenuesElectric Generation, Transmission and Distribution Revenues— — — (5.3)— — — Electric Generation, Transmission and Distribution Revenues— — 0.1 (9.6)— — — 
Purchased Electricity for Resale0.7 — 0.6 — — — — 
Purchased Electricity, Fuel and Other Consumables Used for Electric GenerationPurchased Electricity, Fuel and Other Consumables Used for Electric Generation0.2 — 0.2 — — — — 
MaintenanceMaintenance0.1 — — — — — — Maintenance(0.4)(0.1)(0.1)— (0.1)(0.1)(0.1)
Regulatory Assets (a)Regulatory Assets (a)(24.8)(0.4)(7.1)(0.5)(12.3)(1.2)(1.5)Regulatory Assets (a)1.2 0.5 1.2 1.7 0.5 (3.5)(1.1)
Regulatory Liabilities (a)Regulatory Liabilities (a)(1.5)— (26.2)1.2 — 18.0 11.9 Regulatory Liabilities (a)43.0 0.4 11.9 1.6 — 12.9 12.7 
Total Gain (Loss) on Risk Management Contracts (b)$(178.2)$(0.4)$(32.7)$(4.6)$(12.3)$16.8 $10.4 
Total Gain (Loss) on Risk Management ContractsTotal Gain (Loss) on Risk Management Contracts$33.1 $0.8 $13.3 $(6.3)$0.4 $9.3 $11.5 
Three Months Ended March 31, 2022Three Months Ended September 30, 2022
Location of Gain (Loss)Location of Gain (Loss)AEPAEP TexasAPCoI&MOPCoPSOSWEPCoLocation of Gain (Loss)AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)(in millions)
Vertically Integrated Utilities RevenuesVertically Integrated Utilities Revenues$2.1 $— $— $— $— $— $— 
Generation & Marketing RevenuesGeneration & Marketing Revenues$152.3 $— $— $— $— $— $— Generation & Marketing Revenues116.7 — — — — — — 
Electric Generation, Transmission and Distribution RevenuesElectric Generation, Transmission and Distribution Revenues— — 0.1 (0.1)— — — Electric Generation, Transmission and Distribution Revenues— — 0.3 — — — — 
Purchased Electricity for Resale1.5 — 1.4 — — — — 
Other Revenues - NonaffiliatedOther Revenues - Nonaffiliated— — `— 1.9 — — — 
Purchased Electricity, Fuel and Other Consumables Used for Electric GenerationPurchased Electricity, Fuel and Other Consumables Used for Electric Generation0.9 — 0.9 0.1 — — — 
Other OperationOther Operation0.6 0.2 — 0.1 0.1 0.1 0.1 Other Operation1.4 0.4 0.1 0.1 0.2 0.2 0.2 
MaintenanceMaintenance0.8 0.2 0.1 0.1 0.1 0.1 0.1 Maintenance2.0 0.5 0.2 0.2 0.4 0.2 0.3 
Regulatory Assets (a)Regulatory Assets (a)23.6 — (0.1)(1.6)23.9 3.6 (2.1)Regulatory Assets (a)4.3 — — 0.1 4.1 — 0.1 
Regulatory Liabilities (a)Regulatory Liabilities (a)36.5 0.9 (1.4)1.7 — 12.7 20.9 Regulatory Liabilities (a)103.2 (1.5)59.7 3.8 0.9 19.7 7.0 
Total Gain on Risk Management Contracts$215.3 $1.3 $0.1 $0.2 $24.1 $16.5 $19.0 
Total Gain (Loss) on Risk Management ContractsTotal Gain (Loss) on Risk Management Contracts$230.6 $(0.6)$61.2 $6.2 $5.6 $20.1 $7.6 
160


Nine Months Ended September 30, 2023
Location of Gain (Loss)AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Vertically Integrated Utilities Revenues$2.2 $— $— $— $— $— $— 
Generation & Marketing Revenues(290.6)— — — — — — 
Electric Generation, Transmission and Distribution Revenues— — 0.1 2.1 — — — 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation2.2 — 2.1 0.1 — — — 
Other Operation(0.1)— — — — — — 
Maintenance(0.6)(0.2)(0.1)— (0.1)(0.1)(0.1)
Regulatory Assets (a)(36.0)— — (0.4)(24.6)(7.0)(3.5)
Regulatory Liabilities (a)143.5 0.4 3.1 6.4 — 73.3 58.2 
Total Gain (Loss) on Risk Management Contracts$(179.4)$0.2 $5.2 $8.2 $(24.7)$66.2 $54.6 
Nine Months Ended September 30, 2022
Location of Gain (Loss)AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Vertically Integrated Utilities Revenues$2.2 $— $— $— $— $— $— 
Generation & Marketing Revenues390.0 — — — — — — 
Electric Generation, Transmission and Distribution Revenues— — 0.4 (0.1)— — — 
Other Revenues - Nonaffiliated— — — 1.9 — — — 
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation3.3 — 3.0 0.1 — 0.1 — 
Other Operation3.7 1.1 0.3 0.4 0.6 0.5 0.6 
Maintenance5.2 1.4 0.7 0.5 0.9 0.6 0.8 
Regulatory Assets (a)49.3 0.1 — (1.2)49.0 3.6 (2.1)
Regulatory Liabilities (a)250.1 (0.6)79.9 7.0 2.5 71.4 64.8 
Total Gain on Risk Management Contracts$703.8 $2.0 $84.3 $8.6 $53.0 $76.2 $64.1 
(a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
(b)Decrease in amounts as of March 31, 2023 are primarily due to decreases in commodity prices for power and natural gas and a decrease in value of FTRs.

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.”


161



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 LiabilitiesCumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Liabilities
March 31, 2023December 31, 2022March 31, 2023December 31, 2022
(in millions)
Long-term Debt (a) (b)$(860.8)$(855.5)$84.7 $89.7 
Carrying Amount of the Hedged LiabilitiesCumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Liabilities
September 30, 2023December 31, 2022September 30, 2023December 31, 2022
(in millions)
Long-term Debt (a) (b)$(840.1)$(855.5)$106.1 $89.7 

(a)Amounts included on the Balance Sheet within Noncurrent Liabilities line item Long-term Debt.
(b)Amounts include $(36)$(32) million and $(38) million as of March 31,September 30, 2023 and December 31, 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:

Three Months Ended March 31,Three Months Ended September 30,Nine Months Ended September 30,
202320222023202220232022
(in millions)(in millions)
Gain (Loss) on Interest Rate Contracts:Gain (Loss) on Interest Rate Contracts:Gain (Loss) on Interest Rate Contracts:
Fair Value Hedging Instruments (a)Fair Value Hedging Instruments (a)$6.9 $(44.8)Fair Value Hedging Instruments (a)$(13.4)$(36.0)$(10.7)$(98.4)
Fair Value Portion of Long-term Debt (a)Fair Value Portion of Long-term Debt (a)(6.9)44.8 Fair Value Portion of Long-term Debt (a)13.4 36.0 10.7 98.4 

(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 ResaleElectric 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 three and nine months ended March 31,September 30, 2023 and 2022, AEP applied cash flow hedging to outstanding power derivatives and the Registrant Subsidiaries did not.

The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three months ended March 31,September 30, 2023, the Registrants did not apply cash flow hedging to outstanding interest rate derivatives. During the nine months ended September 30, 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 three and nine months ended March 31,September 30, 2022, AEP applied cash flow hedging to outstanding interest rate derivatives and the Registrant Subsidiaries did not.

162



For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 - Comprehensive Income.

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were:

Impact of Cash Flow Hedges on AEP’s Balance Sheets
March 31, 2023December 31, 2022September 30, 2023December 31, 2022
CommodityInterest RateCommodityInterest RateCommodityInterest RateCommodityInterest Rate
(in millions)(in millions)
AOCI Gain Net of TaxAOCI Gain Net of Tax$65.3 $6.1 $223.5 $0.3 AOCI Gain Net of Tax$100.6 $4.7 $223.5 $0.3 
Portion Expected to be Reclassed to Net Income During the Next Twelve MonthsPortion Expected to be Reclassed to Net Income During the Next Twelve Months(2.0)1.9 119.9 0.3 Portion Expected to be Reclassed to Net Income During the Next Twelve Months36.1 4.3 119.9 0.3 

As of March 31,September 30, 2023 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 96 months and 93 months for commodity and interest rate hedges, respectively.90 months.

Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets
March 31, 2023December 31, 2022September 30, 2023December 31, 2022
Interest RateInterest Rate
Expected to beExpected to beExpected to beExpected to be
Reclassified toReclassified toReclassified toReclassified to
Net Income DuringNet Income DuringNet Income DuringNet Income During
AOCI Gain (Loss)the NextAOCI Gain (Loss)the NextAOCI Gain (Loss)the NextAOCI Gain (Loss)the Next
CompanyCompanyNet of TaxTwelve MonthsNet of TaxTwelve MonthsCompanyNet of TaxTwelve MonthsNet of TaxTwelve Months
(in millions)(in millions)
AEP TexasAEP Texas$(0.3)$— $(0.3)$(0.2)AEP Texas$2.8 $0.3 $(0.3)$(0.2)
APCoAPCo6.5 0.8 6.7 0.8 APCo6.1 0.8 6.7 0.8 
I&MI&M(5.8)(0.4)(5.1)(0.6)I&M(5.6)(0.4)(5.1)(0.6)
PSOPSO(0.2)— 1.3 0.1 PSO(0.2)— 1.3 0.1 
SWEPCoSWEPCo1.5 0.3 1.1 0.2 SWEPCo1.4 0.3 1.1 0.2 

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.


163



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 March 31,September 30, 2023 and December 31, 2022, respectively. The Registrant Subsidiaries had no derivative contracts with collateral triggering events in a net liability position as of March 31,September 30, 2023 and December 31, 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 $121$138 million and $127 million as of March 31,September 30, 2023 and December 31, 2022, respectively. There was no cash collateral posted as of March 31,September 30, 2023 and December 31, 2022, respectively.2022. If a cross-acceleration provision would have been triggered, settlement at fair value would have been required. AEP Texas’ derivative contracts with cross-acceleration provisions in a net liability position were immaterial as of March 31, 2023 and AEP Texas had no derivative contracts with cross-acceleration provisions in a net liability as of December 31, 2022. The other Registrant Subsidiaries had no derivative contracts with cross-acceleration provisions outstanding as of March 31,September 30, 2023 and December 31, 2022.

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 liabilitiescontracts subject to cross-default provisions in a net liability position of $193$165 million and $217 million as of March 31,September 30, 2023 and December 31, 2022, respectively, after considering contractual netting arrangements. There was no cash collateral posted as of March 31,September 30, 2023 and December 31, 2022. If a cross-default provision would have been triggered, settlement at fair value would have been required. The Registrant Subsidiaries’ derivative contracts with cross-default provisions outstanding as of March 31,September 30, 2023 and December 31, 2022 were not material.
164



10.  FAIR VALUE MEASUREMENTS

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

Fair Value Hierarchy and Valuation Techniques

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.  When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value.  Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.

For commercial activities, exchange-traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange-traded derivatives where there is insufficient market liquidity to warrant inclusion in Level 1.  Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated.  Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace.  When multiple broker quotes are obtained, the quoted bid and ask prices are averaged.  In certain circumstances, a broker quote may be discarded if it is a clear outlier.  Management uses a historical correlation analysis between the broker quoted location and the illiquid locations.  If the points are highly correlated, these locations are included within Level 2 as well.  Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information.  Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket-based inputs.  Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.  The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market.  A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility.

AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the nuclear trusts.  AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value.  AEP’s management performs its own valuation testing to verify the fair values of the securities.  AEP receives audit reports of the trustee’s operating controls and valuation processes.

Assets in the nuclear trusts, cash and cash equivalents, other temporary investments restricted cash for securitized funding are classified using the following methods.  Equities are classified as Level 1 holdings if they are actively traded on exchanges.  Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and equity securities.  They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets.  Items classified as Level 2 are primarily investments in individual fixed income securities.  Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data.  Pricing vendors calculate bond valuations using financial models and matrices.  The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation.  Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.
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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:
March 31, 2023December 31, 2022September 30, 2023December 31, 2022
CompanyCompanyBook ValueFair ValueBook ValueFair ValueCompanyBook ValueFair ValueBook ValueFair Value
(in millions)(in millions)
AEP (a)AEP (a)$39,144.2 $36,126.4 $36,801.0 $32,915.9 AEP (a)$39,489.1 $33,559.8 $36,801.0 $32,915.9 
AEP TexasAEP Texas5,522.0 5,009.5 5,657.8 5,045.8 AEP Texas5,926.7 4,963.8 5,657.8 5,045.8 
AEPTCoAEPTCo5,472.1 4,836.2 4,782.8 3,940.5 AEPTCo5,473.7 4,270.8 4,782.8 3,940.5 
APCoAPCo5,398.7 5,227.7 5,410.5 5,079.2 APCo5,587.3 4,901.4 5,410.5 5,079.2 
I&MI&M3,489.0 3,249.1 3,260.8 2,929.0 I&M3,443.6 2,920.6 3,260.8 2,929.0 
OPCoOPCo2,970.8 2,566.6 2,970.3 2,516.6 OPCo3,366.2 2,645.2 2,970.3 2,516.6 
PSOPSO2,383.6 2,172.6 1,912.8 1,635.8 PSO2,384.2 1,942.5 1,912.8 1,635.8 
SWEPCoSWEPCo3,644.8 3,195.9 3,391.6 2,870.9 SWEPCo3,646.2 2,944.8 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 $856 million$0 and $877 million as of March 31,September 30, 2023 and December 31, 2022, respectively. See “Equity Units” section of Note 12 for additional information.

Fair Value Measurements of Other Temporary Investments and Restricted Cash (Applies to AEP)

Other Temporary Investments include marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS.

The following is a summary of Other Temporary Investments and Restricted Cash:
March 31, 2023September 30, 2023
GrossGrossGrossGross
UnrealizedUnrealizedFairUnrealizedUnrealizedFair
Other Temporary Investments and Restricted CashOther Temporary Investments and Restricted CashCostGainsLossesValueOther Temporary Investments and Restricted CashCostGainsLossesValue
(in millions)(in millions)
Restricted Cash (a)Restricted Cash (a)$50.0 $— $— $50.0 Restricted Cash (a)$53.8 $— $— $53.8 
Other Cash DepositsOther Cash Deposits11.4 — — 11.4 Other Cash Deposits13.4 — — 13.4 
Fixed Income Securities – Mutual Funds (b)Fixed Income Securities – Mutual Funds (b)153.4 — (7.2)146.2 Fixed Income Securities – Mutual Funds (b)170.4 — (10.4)160.0 
Equity Securities – Mutual FundsEquity Securities – Mutual Funds15.2 21.8 — 37.0 Equity Securities – Mutual Funds15.0 22.6 — 37.6 
Total Other Temporary Investments and Restricted CashTotal Other Temporary Investments and Restricted Cash$230.0 $21.8 $(7.2)$244.6 Total Other Temporary Investments and Restricted Cash$252.6 $22.6 $(10.4)$264.8 
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December 31, 2022
GrossGross
UnrealizedUnrealizedFair
Other Temporary Investments and Restricted CashCostGainsLossesValue
(in millions)
Restricted Cash (a)$47.1 $— $— $47.1 
Other Cash Deposits9.0 — — 9.0 
Fixed Income Securities – Mutual Funds (b)152.4 — (8.3)144.1 
Equity Securities – Mutual Funds15.1 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:
Three Months Ended March 31, Three Months Ended September 30,Nine Months Ended September 30,
20232022 2023202220232022
(in millions)(in millions)
Proceeds from Investment SalesProceeds from Investment Sales$— $3.9 Proceeds from Investment Sales$0.8 $— $0.8 $15.0 
Purchases of InvestmentsPurchases of Investments1.0 0.8 Purchases of Investments14.6 11.8 16.9 13.4 
Gross Realized Gains on Investment SalesGross Realized Gains on Investment Sales— 0.3 Gross Realized Gains on Investment Sales0.3 — 0.3 3.6 
Gross Realized Losses on Investment SalesGross Realized Losses on Investment Sales— 0.1 Gross Realized Losses on Investment Sales— — — 0.5 

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M)

Nuclear decommissioning and SNF trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and SNF disposal liabilities.  By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines.  In general, limitations include:

Acceptable investments (rated investment grade or above when purchased).
Maximum percentage invested in a specific type of investment.
Prohibition of investment in obligations of AEP, I&M or their affiliates.
Withdrawals permitted only for payment of decommissioning costs and trust expenses.

I&M maintains trust funds for each regulatory jurisdiction.  Regulatory approval is required to withdraw decommissioning funds.  These funds are managed by an external investment manager that must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.

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

Other-than-temporary impairments for investments in debt securities are considered realized losses as a result of securities being managed by an external investment management firm.  The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy.  Impairments
167



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.

The following is a summary of nuclear trust fund investments:
 March 31, 2023December 31, 2022
GrossGrossOther-Than-GrossGrossOther-Than-
FairUnrealizedUnrealizedTemporaryFairUnrealizedUnrealizedTemporary
ValueGainsLossesImpairmentsValueGainsLossesImpairments
(in millions)
Cash and Cash Equivalents$26.5 $— $— $— $21.2 $— $— $— 
Fixed Income Securities:
United States Government1,207.6 20.9 (6.4)(28.3)1,123.8 11.8 (14.9)(18.8)
Corporate Debt66.0 1.0 (6.1)(2.2)61.6 0.7 (7.7)(9.6)
State and Local Government3.3 — — — 3.3 0.1 — (0.1)
Subtotal Fixed Income Securities1,276.9 21.9 (12.5)(30.5)1,188.7 12.6 (22.6)(28.5)
Equity Securities - Domestic2,197.7 1,565.1 (2.9)— 2,131.3 1,483.7 (6.4)— 
Spent Nuclear Fuel and Decommissioning Trusts$3,501.1 $1,587.0 $(15.4)$(30.5)$3,341.2 $1,496.3 $(29.0)$(28.5)


 September 30, 2023December 31, 2022
GrossGrossOther-Than-GrossGrossOther-Than-
FairUnrealizedUnrealizedTemporaryFairUnrealizedUnrealizedTemporary
ValueGainsLossesImpairmentsValueGainsLossesImpairments
(in millions)
Cash and Cash Equivalents$20.5 $— $— $— $21.2 $— $— $— 
Fixed Income Securities:
United States Government1,204.7 0.6 (30.8)(38.5)1,123.8 11.8 (14.9)(18.8)
Corporate Debt136.8 0.4 (12.4)(5.3)61.6 0.7 (7.7)(9.6)
State and Local Government3.2 — — — 3.3 0.1 — (0.1)
Subtotal Fixed Income Securities1,344.7 1.0 (43.2)(43.8)1,188.7 12.6 (22.6)(28.5)
Equity Securities - Domestic2,174.5 1,620.5 (1.9)— 2,131.3 1,483.7 (6.4)— 
Spent Nuclear Fuel and Decommissioning Trusts$3,539.7 $1,621.5 $(45.1)$(43.8)$3,341.2 $1,496.3 $(29.0)$(28.5)

The following table provides the securities activity within the decommissioning and SNF trusts:
Three Months Ended March 31,Three Months Ended September 30,Nine Months Ended September 30,
20232022 2023202220232022
(in millions) (in millions)
Proceeds from Investment SalesProceeds from Investment Sales$517.6 $493.5 Proceeds from Investment Sales$933.0 $588.5 $2,139.3 $1,818.4 
Purchases of InvestmentsPurchases of Investments536.3 507.7 Purchases of Investments949.5 601.6 2,182.8 1,854.8 
Gross Realized Gains on Investment SalesGross Realized Gains on Investment Sales48.5 5.8 Gross Realized Gains on Investment Sales36.8 24.6 91.6 41.3 
Gross Realized Losses on Investment SalesGross Realized Losses on Investment Sales8.6 7.2 Gross Realized Losses on Investment Sales7.7 8.4 20.0 33.5 

The base cost of fixed income securities was $1.3$1.4 billion and $1.2 billion as of March 31,September 30, 2023 and December 31, 2022, respectively.  The base cost of equity securities was $635$556 million and $654 million as of March 31,September 30, 2023 and December 31, 2022, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of March 31,September 30, 2023 was as follows:
Fair Value of Fixed
Income Securities
(in millions)
Within 1 year$347.8393.6 
After 1 year through 5 years489.1504.4 
After 5 years through 10 years215.6188.6 
After 10 years224.4258.1 
Total$1,276.91,344.7 
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Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis.  As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  There have not been any significant changes in management’s valuation techniques.

AEP

Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31,September 30, 2023
Level 1Level 2Level 3OtherTotalLevel 1Level 2Level 3OtherTotal
Assets:Assets:(in millions)Assets:(in millions)
Other Temporary Investments and Restricted CashOther Temporary Investments and Restricted CashOther Temporary Investments and Restricted Cash
Restricted CashRestricted Cash$50.0 $— $— $— $50.0 Restricted Cash$53.8 $— $— $— $53.8 
Other Cash Deposits (a)Other Cash Deposits (a)— — — 11.4 11.4 Other Cash Deposits (a)— — — 13.4 13.4 
Fixed Income Securities – Mutual FundsFixed Income Securities – Mutual Funds146.2 — — — 146.2 Fixed Income Securities – Mutual Funds160.0 — — — 160.0 
Equity Securities – Mutual Funds (b)Equity Securities – Mutual Funds (b)37.0 — — — 37.0 Equity Securities – Mutual Funds (b)37.6 — — — 37.6 
Total Other Temporary Investments and Restricted CashTotal Other Temporary Investments and Restricted Cash233.2 — — 11.4 244.6 Total Other Temporary Investments and Restricted Cash251.4 — — 13.4 264.8 
Risk Management AssetsRisk Management AssetsRisk Management Assets
Risk Management Commodity Contracts (c) (d)Risk Management Commodity Contracts (c) (d)13.0 861.2 209.2 (720.2)363.2 Risk Management Commodity Contracts (c) (d)11.4 721.3 319.2 (627.4)424.5 
Cash Flow Hedges:Cash Flow Hedges:Cash Flow Hedges:
Commodity Hedges (c)Commodity Hedges (c)— 177.8 20.3 (61.4)136.7 Commodity Hedges (c)— 119.3 19.3 (10.2)128.4 
Interest Rate Hedges— 8.9 — — 8.9 
Total Risk Management AssetsTotal Risk Management Assets13.0 1,047.9 229.5 (781.6)508.8 Total Risk Management Assets11.4 840.6 338.5 (637.6)552.9 
Spent Nuclear Fuel and Decommissioning TrustsSpent Nuclear Fuel and Decommissioning TrustsSpent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)Cash and Cash Equivalents (e)17.1 — — 9.4 26.5 Cash and Cash Equivalents (e)10.0 — — 10.5 20.5 
Fixed Income Securities:Fixed Income Securities:Fixed Income Securities:
United States GovernmentUnited States Government— 1,207.6 — — 1,207.6 United States Government— 1,204.7 — — 1,204.7 
Corporate DebtCorporate Debt— 66.0 — — 66.0 Corporate Debt— 136.8 — — 136.8 
State and Local GovernmentState and Local Government— 3.3 — — 3.3 State and Local Government— 3.2 — — 3.2 
Subtotal Fixed Income SecuritiesSubtotal Fixed Income Securities— 1,276.9 — — 1,276.9 Subtotal Fixed Income Securities— 1,344.7 — — 1,344.7 
Equity Securities – Domestic (b)Equity Securities – Domestic (b)2,197.7 — — — 2,197.7 Equity Securities – Domestic (b)2,174.5 — — — 2,174.5 
Total Spent Nuclear Fuel and Decommissioning TrustsTotal Spent Nuclear Fuel and Decommissioning Trusts2,214.8 1,276.9 — 9.4 3,501.1 Total Spent Nuclear Fuel and Decommissioning Trusts2,184.5 1,344.7 — 10.5 3,539.7 
Total AssetsTotal Assets$2,461.0 $2,324.8 $229.5 $(760.8)$4,254.5 Total Assets$2,447.3 $2,185.3 $338.5 $(613.7)$4,357.4 
Liabilities:Liabilities:Liabilities:
Risk Management LiabilitiesRisk Management LiabilitiesRisk Management Liabilities
Risk Management Commodity Contracts (c) (d)Risk Management Commodity Contracts (c) (d)$33.5 $721.1 $178.5 $(627.5)$305.6 Risk Management Commodity Contracts (c) (d)$24.8 $646.3 $155.0 $(534.9)$291.2 
Cash Flow Hedges:Cash Flow Hedges:Cash Flow Hedges:
Commodity Hedges (c)Commodity Hedges (c)— 109.1 5.9 (61.4)53.6 Commodity Hedges (c)— 10.1 0.7 (10.2)0.6 
Interest Rate Hedges— 1.7 — — 1.7 
Fair Value HedgesFair Value Hedges— 120.5 — — 120.5 Fair Value Hedges— 138.1 — — 138.1 
Total Risk Management LiabilitiesTotal Risk Management Liabilities$33.5 $952.4 $184.4 $(688.9)$481.4 Total Risk Management Liabilities$24.8 $794.5 $155.7 $(545.1)$429.9 
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AEP

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2022
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Other Temporary Investments and Restricted Cash
Restricted Cash$47.1 $— $— $— $47.1 
Other Cash Deposits (a)— — — 9.0 9.0 
Fixed Income Securities – Mutual Funds144.1 — — — 144.1 
Equity Securities – Mutual Funds (b)34.5 — — — 34.5 
Total Other Temporary Investments and Restricted Cash225.7 — — 9.0 234.7 
Risk Management Assets
Risk Management Commodity Contracts (c) (f)15.0 1,197.5 314.4 (1,211.5)315.4 
Cash Flow Hedges:
Commodity Hedges (c)— 332.6 26.7 (52.8)306.5 
Interest Rate Hedges— 11.0 — — 11.0 
Total Risk Management Assets15.0 1,541.1 341.1 (1,264.3)632.9 
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)11.3 — — 9.9 21.2 
Fixed Income Securities:
United States Government— 1,123.8 — — 1,123.8 
Corporate Debt— 61.6 — — 61.6 
State and Local Government— 3.3 — — 3.3 
Subtotal Fixed Income Securities— 1,188.7 — — 1,188.7 
Equity Securities – Domestic (b)2,131.3 — — — 2,131.3 
Total Spent Nuclear Fuel and Decommissioning Trusts2,142.6 1,188.7 — 9.9 3,341.2 
Total Assets$2,383.3 $2,729.8 $341.1 $(1,245.4)$4,208.8 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (f)$21.8 $870.9 $179.0 $(731.9)$339.8 
Cash Flow Hedges:
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 

170



AEP Texas
Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31,September 30, 2023
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$42.5 $— $— $— $42.5 
Risk Management Assets     
Cash Flow Hedges:
Interest Rate Hedges— 0.5 — — 0.5 
Total Assets$42.5 $0.5 $— $— $43.0 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)$— $0.4 $— $(0.4)$— 
Cash Flow Hedges:
Interest Rate Hedges— 0.8 — — 0.8 
Total Liabilities$— $1.2 $— $(0.4)$0.8 
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$46.9 $— $— $— $46.9 
Risk Management Assets     
Risk Management Commodity Contracts (g)— 0.4 — — 0.4 
Total Assets$46.9 $0.4 $— $— $47.3 

December 31, 2022
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$32.7 $— $— $— $32.7 

171



APCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31,September 30, 2023
Level 1Level 2Level 3OtherTotalLevel 1Level 2Level 3OtherTotal
Assets:Assets:(in millions)Assets:(in millions)
Restricted Cash for Securitized FundingRestricted Cash for Securitized Funding$7.5 $— $— $— $7.5 Restricted Cash for Securitized Funding$6.9 $— $— $— $6.9 
Risk Management AssetsRisk Management AssetsRisk Management Assets
Risk Management Commodity Contracts (c) (g)Risk Management Commodity Contracts (c) (g)— 0.4 12.4 (0.4)12.4 Risk Management Commodity Contracts (c) (g)— 3.8 45.2 (2.4)46.6 
Total AssetsTotal Assets$7.5 $0.4 $12.4 $(0.4)$19.9 Total Assets$6.9 $3.8 $45.2 $(2.4)$53.5 
Liabilities:Liabilities:Liabilities:
Risk Management LiabilitiesRisk Management LiabilitiesRisk Management Liabilities
Risk Management Commodity Contracts (c) (g)Risk Management Commodity Contracts (c) (g)$— $0.9 $6.7 $(0.6)$7.0 Risk Management Commodity Contracts (c) (g)$— $5.0 $0.1 $(2.4)$2.7 

December 31, 2022
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$14.4 $— $— $— $14.4 
Risk Management Assets
Risk Management Commodity Contracts (c) (g)— 0.7 69.4 (1.0)69.1 
Total Assets$14.4 $0.7 $69.4 $(1.0)$83.5 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$— $4.6 $0.3 $(1.4)$3.5 

172171



I&M
Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31,September 30, 2023
Level 1Level 2Level 3OtherTotalLevel 1Level 2Level 3OtherTotal
Assets:Assets:(in millions)Assets:(in millions)
Risk Management AssetsRisk Management AssetsRisk Management Assets
Risk Management Commodity Contracts (c) (g)Risk Management Commodity Contracts (c) (g)$— $6.6 $1.6 $(1.2)$7.0 Risk Management Commodity Contracts (c) (g)$— $18.1 $7.9 $(4.8)$21.2 
Spent Nuclear Fuel and Decommissioning TrustsSpent Nuclear Fuel and Decommissioning TrustsSpent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)Cash and Cash Equivalents (e)17.1 — — 9.4 26.5 Cash and Cash Equivalents (e)10.0 — — 10.5 20.5 
Fixed Income Securities:Fixed Income Securities:Fixed Income Securities:
United States GovernmentUnited States Government— 1,207.6 — — 1,207.6 United States Government— 1,204.7 — — 1,204.7 
Corporate DebtCorporate Debt— 66.0 — — 66.0 Corporate Debt— 136.8 — — 136.8 
State and Local GovernmentState and Local Government— 3.3 — — 3.3 State and Local Government— 3.2 — — 3.2 
Subtotal Fixed Income SecuritiesSubtotal Fixed Income Securities— 1,276.9 — — 1,276.9 Subtotal Fixed Income Securities— 1,344.7 — — 1,344.7 
Equity Securities - Domestic (b)Equity Securities - Domestic (b)2,197.7 — — — 2,197.7 Equity Securities - Domestic (b)2,174.5 — — — 2,174.5 
Total Spent Nuclear Fuel and Decommissioning TrustsTotal Spent Nuclear Fuel and Decommissioning Trusts2,214.8 1,276.9 — 9.4 3,501.1 Total Spent Nuclear Fuel and Decommissioning Trusts2,184.5 1,344.7 — 10.5 3,539.7 
Total AssetsTotal Assets$2,214.8 $1,283.5 $1.6 $8.2 $3,508.1 Total Assets$2,184.5 $1,362.8 $7.9 $5.7 $3,560.9 
Liabilities:Liabilities:Liabilities:
Risk Management LiabilitiesRisk Management LiabilitiesRisk Management Liabilities
Risk Management Commodity Contracts (c) (g)Risk Management Commodity Contracts (c) (g)$— $1.3 $0.5 $(1.4)$0.4 Risk Management Commodity Contracts (c) (g)$— $4.2 $1.3 $(4.4)$1.1 

December 31, 2022
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)$— $11.3 $5.3 $(1.2)$15.4 
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)11.3 — — 9.9 21.2 
Fixed Income Securities:
United States Government— 1,123.8 — — 1,123.8 
Corporate Debt— 61.6 — — 61.6 
State and Local Government— 3.3 — — 3.3 
Subtotal Fixed Income Securities— 1,188.7 — — 1,188.7 
Equity Securities - Domestic (b)2,131.3 — — — 2,131.3 
Total Spent Nuclear Fuel and Decommissioning Trusts2,142.6 1,188.7 — 9.9 3,341.2 
Total Assets$2,142.6 $1,200.0 $5.3 $8.7 $3,356.6 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$— $0.6 $0.7 $(1.3)$— 
173172



OPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31,September 30, 2023
Level 1Level 2Level 3OtherTotalLevel 1Level 2Level 3OtherTotal
Assets:Assets:(in millions)Assets:(in millions)
Risk Management AssetsRisk Management Assets     Risk Management Assets     
Risk Management Commodity Contracts (g)Risk Management Commodity Contracts (g)$— $— $— $— $— Risk Management Commodity Contracts (g)$— $0.3 $— $— $0.3 
Liabilities:Liabilities:Liabilities:
Risk Management LiabilitiesRisk Management LiabilitiesRisk Management Liabilities
Risk Management Commodity Contracts (c) (g)$— $0.2 $46.9 $(0.2)$46.9 
Risk Management Commodity Contracts (g)Risk Management Commodity Contracts (g)$— $— $51.6 $— $51.6 

December 31, 2022
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Level 1Level 2Level 3OtherTotal
Risk Management Assets
Risk Management Commodity Contracts (g)$— $— $— $— $— 
Liabilities:Liabilities:Liabilities:(in millions)
Risk Management LiabilitiesRisk Management LiabilitiesRisk Management Liabilities
Risk Management Commodity Contracts (c) (g)Risk Management Commodity Contracts (c) (g)$— $— $40.0 $(0.3)$39.7 Risk Management Commodity Contracts (c) (g)$— $— $40.0 $(0.3)$39.7 

PSO
Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31,September 30, 2023
Level 1Level 2Level 3OtherTotalLevel 1Level 2Level 3OtherTotal
Assets:Assets:(in millions)Assets:(in millions)
Risk Management AssetsRisk Management AssetsRisk Management Assets
Risk Management Commodity Contracts (c) (g)Risk Management Commodity Contracts (c) (g)$— $— $9.9 $(0.5)$9.4 Risk Management Commodity Contracts (c) (g)$— $0.5 $28.1 $(0.4)$28.2 
Liabilities:Liabilities:Liabilities:
Risk Management LiabilitiesRisk Management LiabilitiesRisk Management Liabilities
Risk Management Commodity Contracts (c) (g)Risk Management Commodity Contracts (c) (g)$— $1.2 $0.6 $(0.7)$1.1 Risk Management Commodity Contracts (c) (g)$— $6.6 $0.9 $(0.3)$7.2 

December 31, 2022
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)$— $— $24.0 $1.3 $25.3 
Cash Flow Hedges:
Interest Rate Hedges— 1.6 — (1.6)— 
Total Assets$— $1.6 $24.0 $(0.3)$25.3 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$— $1.7 $0.3 $(0.4)$1.6 
174173



SWEPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31,September 30, 2023
Level 1Level 2Level 3OtherTotalLevel 1Level 2Level 3OtherTotal
Assets:Assets:(in millions)Assets:(in millions)
Risk Management AssetsRisk Management AssetsRisk Management Assets
Risk Management Commodity Contracts (c) (g)Risk Management Commodity Contracts (c) (g)$— $— $6.4 $(0.1)$6.3 Risk Management Commodity Contracts (c) (g)$— $0.2 $17.4 $(0.5)$17.1 
Liabilities:Liabilities:Liabilities:
Risk Management LiabilitiesRisk Management LiabilitiesRisk Management Liabilities
Risk Management Commodity Contracts (c) (g)Risk Management Commodity Contracts (c) (g)$— $0.8 $0.6 $(0.3)$1.1 Risk Management Commodity Contracts (c) (g)$— $3.1 $0.9 $(0.5)$3.5 

December 31, 2022
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)$— $2.2 $14.6 $(0.4)$16.4 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$— $1.6 $0.4 $(0.6)$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 March 31,September 30, 2023 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $(14)$(4) million in 2023 and $(6)$(9) million in periods 2024-2026; Level 2 matures $24 million in 2023, $105$64 million in periods 2024-2026, $9$10 million in periods 2027-2028 and $1 million in periods 2029-2033; Level 3 matures $18$37 million in 2023, $9$118 million in periods 2024-2026, $11$18 million in periods 2027-2028 and $(7)$(9) million in periods 2029-2033.  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.
(g)Substantially comprised of power contracts for the Registrant Subsidiaries.
175174



The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:
Three Months Ended September 30, 2023Three Months Ended September 30, 2023AEPAPCoI&MOPCoPSOSWEPCo
(in millions)
Balance as of June 30, 2023Balance as of June 30, 2023$126.1 $39.4 $6.8 $(54.0)$43.1 $26.0 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)39.7 10.0 2.3 — 14.2 14.0 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)72.7 — — — — — 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)4.9 — — — — — 
SettlementsSettlements(87.1)(16.5)(3.7)1.1 (30.5)(24.8)
Transfers out of Level 3 (e)Transfers out of Level 3 (e)6.6 0.1 (0.1)— — — 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)Changes in Fair Value Allocated to Regulated Jurisdictions (f)19.9 12.1 1.3 1.3 0.4 1.3 
Balance as of September 30, 2023Balance as of September 30, 2023$182.8 $45.1 $6.6 $(51.6)$27.2 $16.5 
Three Months Ended March 31, 2023AEPAPCoI&MOPCoPSOSWEPCo
(in millions)
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)(7.1)(31.9)1.2 (1.3)16.6 12.9 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)14.8 — — — — — 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)(13.9)— — — — — 
Settlements(96.6)(27.3)(4.2)1.0 (34.3)(23.0)
Transfers into Level 3 (d) (e)(6.1)— — — — — 
Transfers out of Level 3 (e)1.0 — — — — — 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)(7.4)(4.2)(0.5)(6.6)3.3 1.7 
Balance as of March 31, 2023$45.1 $5.7 $1.1 $(46.9)$9.3 $5.8 
Three Months Ended March 31, 2022AEPAPCoI&MOPCoPSOSWEPCo
(in millions)
Balance as of December 31, 2021$103.1 $41.7 $(0.7)$(92.5)$12.1 $10.9 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)18.2 (2.9)3.8 0.5 12.1 9.8 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)(19.0)— — — — — 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)19.3 — — — — — 
Settlements(51.6)(32.4)(2.3)1.4 (19.8)(16.2)
Transfers into Level 3 (d) (e)2.5 — — — — — 
Transfers out of Level 3 (e)2.9 — — — — — 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)7.4 0.2 0.2 22.1 2.1 11.2 
Balance as of March 31, 2022$82.8 $6.6 $1.0 $(68.5)$6.5 $15.7 

Three Months Ended September 30, 2022AEPAPCoI&MOPCoPSOSWEPCo
 (in millions)
Balance as of June 30, 2022$283.9 $79.6 $9.8 $(48.4)$64.5 $45.4 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)64.3 20.1 2.1 0.3 23.8 15.4 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)(12.6)— — — — — 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)13.1 — — — — — 
Settlements(138.3)(34.6)(4.8)(1.1)(49.1)(31.6)
Transfers into Level 3 (d) (e)(0.5)— — — — — 
Transfers out of Level 3 (e)3.5 — — — — — 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)72.5 41.5 2.5 6.0 5.2 7.0 
Balance as of September 30, 2022$285.9 $106.6 $9.6 $(43.2)$44.4 $36.2 

175


Nine Months Ended September 30, 2023AEPAPCoI&MOPCoPSOSWEPCo
 (in millions)
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)(41.3)(47.0)(1.7)(2.4)3.5 5.9 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)67.7 — — — — — 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)(10.5)— — — — — 
Settlements(85.9)(22.1)(2.9)3.5 (27.2)(20.0)
Transfers into Level 3 (d) (e)(6.1)— — — — — 
Transfers out of Level 3 (e)3.8 — — — — — 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)94.7 45.1 6.6 (12.7)27.2 16.4 
Balance as of September 30, 2023$182.8 $45.1 $6.6 $(51.6)$27.2 $16.5 

Nine Months Ended September 30, 2022AEPAPCoI&MOPCoPSOSWEPCo
 (in millions)
Balance as of December 31, 2021$103.1 $41.7 $(0.7)$(92.5)$12.1 $10.9 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)69.3 3.0 3.7 4.6 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)(44.6)— — — — — 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)29.4 — — — — — 
Settlements(153.8)(44.7)(3.0)0.2 (36.3)(45.0)
Transfers into Level 3 (d) (e)1.7 — — — — — 
Transfers out of Level 3 (e)13.2 — — — — — 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)267.6 106.6 9.6 44.5 44.4 34.5 
Balance as of September 30, 2022$285.9 $106.6 $9.6 $(43.2)$44.4 $36.2 

(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.

176



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

AEP
Significant Unobservable Inputs
March 31,September 30, 2023
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (b)
(in millions)
Energy Contracts$190.7 $166.5 Discounted Cash FlowForward Market Price$0.74 $101.65 $48.48 
FTRs38.8 17.9 Discounted Cash FlowForward Market Price(55.98)101.82 (0.45)
Total$229.5 $184.4 
SignificantInput/Range
Type ofFair ValueValuationUnobservableWeighted
CompanyInputAssetsLiabilitiesTechniqueInputLowHighAverage (c)
(in millions)
AEPEnergy Contracts$224.3 $147.7 Discounted Cash FlowForward Market Price (a)$5.98 $137.52 $45.43 
AEPNatural Gas Contracts— 0.2 Discounted Cash FlowForward Market Price (b)3.55 3.55 3.55 
AEPFTRs114.2 7.8 Discounted Cash FlowForward Market Price (a)(17.92)17.07 0.29 
APCoFTRs45.2 0.1 Discounted Cash FlowForward Market Price (a)(3.92)9.08 1.63 
I&MFTRs7.9 1.3 Discounted Cash FlowForward Market Price (a)(4.36)9.08 1.08 
OPCoEnergy Contracts— 51.6 Discounted Cash FlowForward Market Price (a)19.89 65.40 41.66 
PSOFTRs28.1 0.9 Discounted Cash FlowForward Market Price (a)(17.92)2.04 (4.42)
SWEPCoNatural Gas Contracts— 0.2 Discounted Cash FlowForward Market Price (b)3.55 3.55 3.55 
SWEPCoFTRs17.4 0.7 Discounted Cash FlowForward Market Price (a)(17.92)2.04 (4.42)

December 31, 2022
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (b)
(in millions)
Energy Contracts$204.0 $167.4 Discounted Cash FlowForward Market Price$2.91$187.34 $49.14 
FTRs137.1 13.3 Discounted Cash FlowForward Market Price(36.45)20.721.18 
Total$341.1 $180.7 
177



APCo
Significant Unobservable Inputs
March 31, 2023
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (b)
(in millions)
FTRs$12.4 $6.7 Discounted Cash FlowForward Market Price$(1.67)$6.59 $0.79 

December 31, 2022
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (b)
(in millions)
FTRs$69.4 $0.3 Discounted Cash FlowForward Market Price$(2.82)$18.88 $3.89 

I&M
Significant Unobservable Inputs
March 31, 2023
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (b)
(in millions)
FTRs$1.6 $0.5 Discounted Cash FlowForward Market Price$0.24 $4.75 $0.78 

December 31, 2022
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (b)
(in millions)
FTRs$5.3 $0.7 Discounted Cash FlowForward Market Price$0.16 $18.79 $1.23 
178



OPCo
Significant Unobservable Inputs
March 31, 2023
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (b)
(in millions)
Energy Contracts$— $46.9 Discounted Cash FlowForward Market Price$14.41 $79.98 $45.92 

December 31, 2022
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (b)
(in millions)
Energy Contracts$— $40.0 Discounted Cash FlowForward Market Price$2.91 $187.34 $48.76 

PSO
Significant Unobservable Inputs
March 31, 2023
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (b)
(in millions)
FTRs$9.9 $0.6 Discounted Cash FlowForward Market Price$(21.10)$3.04 $(4.75)

December 31, 2022
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (b)
(in millions)
FTRs$24.0 $0.3 Discounted Cash FlowForward Market Price$(36.45)$3.40 $(7.55)
179



SWEPCo
Significant Unobservable Inputs
March 31, 2023
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (b)
(in millions)
FTRs$6.4 $0.6 Discounted Cash FlowForward Market Price$(21.10)$3.04 $(4.75)

December 31, 2022
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (b)
(in millions)
FTRs$14.6 $0.4 Discounted Cash FlowForward Market Price$(36.45)$3.40 $(7.55)
SignificantInput/Range
Type ofFair ValueValuationUnobservableWeighted
CompanyInputAssetsLiabilitiesTechniqueInput (a)LowHighAverage (c)
(in millions)
AEPEnergy Contracts$204.0 $167.4 Discounted Cash FlowForward Market Price$2.91 $187.34 $49.14 
AEPFTRs137.1 13.3 Discounted Cash FlowForward Market Price(36.45)20.72 1.18 
APCoFTRs69.4 0.3 Discounted Cash FlowForward Market Price(2.82)18.88 3.89 
I&MFTRs5.3 0.7 Discounted Cash FlowForward Market Price0.16 18.79 1.23 
OPCoEnergy Contracts— 40.0 Discounted Cash FlowForward Market Price2.91 187.34 48.76 
PSOFTRs24.0 0.3 Discounted Cash FlowForward Market Price(36.45)3.40 (7.55)
SWEPCoFTRs14.6 0.4 Discounted Cash FlowForward Market Price(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.


177


The following table provides the measurement uncertainty of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of March 31,September 30, 2023 and December 31, 2022:

Uncertainty of Fair Value Measurements
Significant Unobservable InputPositionChange in InputImpact on Fair Value
Measurement
Forward Market PriceBuyIncrease (Decrease)Higher (Lower)
Forward Market PriceSellIncrease (Decrease)Lower (Higher)
180178



11.  INCOME TAXES

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

Effective Tax Rates (ETR)

The Registrants’ interim ETR reflect the estimated annual ETR for 2023 and 2022, adjusted for tax expense associated with certain discrete items.

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

The ETR for each of the Registrants are included in the following tables:
Three Months Ended March 31, 2023
AEPAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
U.S. Federal Statutory Rate21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %
Increase (decrease) due to:
State Income Tax, net of Federal Benefit1.9 %0.3 %2.6 %2.4 %3.6 %1.0 %3.2 %(0.4)%
Tax Reform Excess ADIT Reversal(6.2)%(1.5)%0.3 %(4.6)%(7.9)%(6.8)%(18.7)%(3.8)%
Production and Investment Tax Credits(9.7)%(0.2)%— %— %(1.1)%— %(55.7)%(26.4)%
Flow Through0.1 %0.2 %0.3 %0.6 %(1.8)%0.5 %0.3 %0.5 %
AFUDC Equity(1.4)%(1.5)%(1.6)%(0.7)%(0.5)%(0.8)%(1.4)%(0.8)%
Discrete Tax Adjustments(3.2)%— %— %3.2 %1.8 %— %— %— %
Other0.1 %0.1 %0.1 %— %— %— %(2.0)%(0.8)%
Effective Income Tax Rate2.6 %18.4 %22.7 %21.9 %15.1 %14.9 %(53.3)%(10.7)%
Three Months Ended March 31, 2022
AEPAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
U.S. Federal Statutory Rate21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %
Increase (decrease) due to:
State Income Tax, net of Federal Benefit1.5 %0.3 %2.6 %2.9 %1.6 %0.7 %0.6 %2.3 %
Tax Reform Excess ADIT Reversal(6.6)%(2.0)%0.3 %(5.8)%(17.3)%(7.8)%(15.3)%(4.9)%
Production and Investment Tax Credits(8.0)%(0.2)%— %— %(1.4)%— %(26.2)%(23.1)%
Flow Through0.3 %0.3 %0.3 %1.7 %(1.9)%0.9 %0.6 %(0.6)%
AFUDC Equity(0.9)%(0.9)%(1.6)%(0.7)%(0.6)%(0.6)%(0.7)%(0.5)%
Discrete Tax Adjustments(0.6)%— %— %(0.6)%— %— %— %— %
Other0.2 %(0.1)%— %— %(0.2)%— %(0.8)%0.6 %
Effective Income Tax Rate6.9 %18.4 %22.6 %18.5 %1.2 %14.2 %(20.8)%(5.2)%

Three Months Ended September 30, 2023
AEPAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
U.S. Federal Statutory Rate21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %
Increase (decrease) due to:
State Income Tax, net of Federal Benefit1.4 %0.5 %2.8 %2.2 %2.1 %0.8 %3.0 %(4.3)%
Tax Reform Excess ADIT Reversal(5.7)%(1.3)%(0.2)%(5.3)%(8.5)%(6.8)%(17.0)%(6.2)%
Production and Investment Tax Credits(5.1)%0.1 %— %(0.1)%(0.7)%— %(46.9)%(25.5)%
Flow Through0.1 %0.2 %0.3 %1.8 %0.7 %0.8 %0.3 %(0.2)%
AFUDC Equity(1.4)%(1.4)%(2.4)%(1.5)%(0.5)%(0.8)%(1.6)%(0.8)%
Discrete Tax Adjustments(4.1)%— %— %— %— %— %— %— %
Other0.1 %(0.5)%(1.0)%0.7 %(3.5)%1.3 %(0.2)%0.2 %
Effective Income Tax Rate6.3 %18.6 %20.5 %18.8 %10.6 %16.3 %(41.4)%(15.8)%

Three Months Ended September 30, 2022
AEPAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
U.S. Federal Statutory Rate21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %
Increase (decrease) due to:
State Income Tax, net of Federal Benefit(0.8)%0.5 %2.6 %(6.2)%2.7 %0.7 %3.0 %(5.3)%
Tax Reform Excess ADIT Reversal(9.7)%(2.0)%0.3 %(8.6)%(13.3)%(6.2)%(21.9)%(4.6)%
Production and Investment Tax Credits(12.0)%(0.4)%— %— %— %— %(43.7)%(24.1)%
Flow Through(0.3)%0.2 %0.3 %(0.7)%(1.5)%0.4 %0.4 %(1.3)%
AFUDC Equity(1.4)%(1.2)%(1.9)%(0.4)%(0.6)%(0.8)%(0.4)%(0.2)%
Discrete Tax Adjustments(0.2)%— %— %— %— %— %— %— %
Other1.0 %0.2 %0.2 %— %(0.5)%0.2 %0.2 %(0.2)%
Effective Income Tax Rate(2.4)%18.3 %22.5 %5.1 %7.8 %15.3 %(41.4)%(14.7)%

181179


Nine Months Ended September 30, 2023
AEPAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
U.S. Federal Statutory Rate21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %
Increase (decrease) due to:
State Income Tax, net of Federal Benefit1.7 %0.5 %2.7 %2.4 %2.3 %0.9 %2.8 %(2.9)%
Tax Reform Excess ADIT Reversal(6.0)%(1.3)%0.1 %(4.8)%(7.6)%(7.3)%(17.1)%(5.3)%
Production and Investment Tax Credits(7.4)%— %— %(0.1)%(0.6)%— %(48.9)%(26.7)%
Flow Through(0.2)%0.2 %0.3 %0.1 %(1.7)%0.8 %0.3 %(0.3)%
AFUDC Equity(1.4)%(1.2)%(2.0)%(1.2)%(0.4)%(0.8)%(1.5)%(0.5)%
Discrete Tax Adjustments(2.8)%— %— %1.5 %0.7 %— %— %— %
Other0.3 %(0.2)%(0.5)%0.4 %(1.2)%0.5 %(0.2)%0.2 %
Effective Income Tax Rate5.2 %19.0 %21.6 %19.3 %12.5 %15.1 %(43.6)%(14.5)%

Nine Months Ended September 30, 2022
AEPAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
U.S. Federal Statutory Rate21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %
Increase (decrease) due to:
State Income Tax, net of Federal Benefit0.7 %0.5 %2.7 %(0.8)%1.3 %0.8 %3.2 %(1.5)%
Tax Reform Excess ADIT Reversal(7.8)%(2.0)%0.3 %(10.3)%(15.7)%(7.3)%(20.8)%(4.8)%
Production and Investment Tax Credits(8.7)%(0.4)%— %— %(1.4)%— %(39.5)%(22.5)%
Flow Through— %0.2 %0.3 %0.2 %(1.6)%0.5 %0.3 %(0.8)%
AFUDC Equity(1.1)%(1.2)%(1.9)%(0.8)%(0.8)%(0.7)%(0.4)%(0.4)%
Discrete Tax Adjustments(0.2)%— %— %(1.8)%— %— %— %0.3 %
Other0.6 %0.1 %0.1 %— %0.2 %0.1 %0.2 %— %
Effective Income Tax Rate4.5 %18.2 %22.5 %7.5 %3.0 %14.4 %(36.0)%(8.7)%

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 and 20182017-2019 tax returns to DecemberOctober 31, 2023,2024, to allow time for the current IRS audit to be completed including a refund claim approval by the Congressional Joint Committee on Taxation. The statute of limitations for the 20192020 return is set to naturally expire in 2023October 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 twoimmaterial IRS proposed adjustments on the 2017 tax return, which were immaterial.return. The exam is nearly complete, and AEP is currently working with 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.


180


Federal 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, addressing time sensitive issues related to the CAMT. The noticewhich provided initial CAMT guidance that AEP can begin to rely on in 2023 and also stated that additional guidance is expected, of which AEP will continue to monitor and assess.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 will beare presented in the operating section of the statements of cash flows consistent with the presentation of cash taxes paid. AEP will presentpresents the gain or 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 quarter of 2023, AEP, on behalf of PSO and SWEPCo, entered into a transferability agreement with a nonaffiliated party to sell PTCs resulting in cash proceeds of approximately $80 million expected in the fourth quarter of 2023. AEP expects to continue to explore the ability to efficiently monetize its tax credits through third party transferability agreements.


182
181



12.  FINANCING ACTIVITIES

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

Common Stock (Applies to AEP)

At-the-Market (ATM) Program

In 2020, AEP filed a prospectus supplement and executed an Equity Distribution Agreement, pursuant to which AEP may sell, from time to time, up to an aggregate of $1 billion of its common stock through an ATM offering program, including an equity forward sales component. The compensation paid to the selling agents by AEP may be up to 2% of the gross offering proceeds of the shares. There were no issuances under the ATM program for the threenine months ended March 31,September 30, 2023.

Long-term Debt Outstanding (Applies to AEP)

The following table details long-term debt outstanding, net of issuance costs and premiums or discounts:
Type of DebtType of DebtMarch 31, 2023December 31, 2022Type of DebtSeptember 30, 2023December 31, 2022
(in millions) (in millions)
Senior Unsecured NotesSenior Unsecured Notes$32,654.3 $30,174.8 Senior Unsecured Notes$32,881.6 $30,174.8 
Pollution Control BondsPollution Control Bonds1,770.4 1,770.2 Pollution Control Bonds1,771.0 1,770.2 
Notes PayableNotes Payable190.0 269.7 Notes Payable141.5 269.7 
Securitization BondsSecuritization Bonds463.4 487.8 Securitization Bonds407.0 487.8 
Spent Nuclear Fuel Obligation (a)Spent Nuclear Fuel Obligation (a)288.8 285.6 Spent Nuclear Fuel Obligation (a)296.3 285.6 
Junior Subordinated Notes (b)Junior Subordinated Notes (b)2,383.3 2,381.3 Junior Subordinated Notes (b)2,386.6 2,381.3 
Other Long-term DebtOther Long-term Debt1,394.0 1,431.6 Other Long-term Debt1,605.1 1,431.6 
Total Long-term Debt OutstandingTotal Long-term Debt Outstanding39,144.2 36,801.0 Total Long-term Debt Outstanding39,489.1 36,801.0 
Long-term Debt Due Within One YearLong-term Debt Due Within One Year2,905.1 2,486.4 Long-term Debt Due Within One Year2,773.6 2,486.4 
Long-term DebtLong-term Debt$36,239.1 $34,314.6 Long-term Debt$36,715.5 $34,314.6 

(a)Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for SNF disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $335$345 million and $330 million as of March 31,September 30, 2023 and December 31, 2022, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.
(b)See “Equity Units” section below for additional information.

183182



Long-term Debt Activity

Long-term debt and other securities issued, retired and principal payments made during the first threenine months of 2023 are shown in the following tables:
PrincipalInterestPrincipalInterest
CompanyCompanyType of DebtAmount (a)RateDue DateCompanyType of DebtAmount (a)RateDue Date
Issuances:Issuances: (in millions)(%)Issuances: (in millions)(%)
AEPAEPSenior Unsecured Notes$850.0 5.632033AEPSenior Unsecured Notes$850.0 5.632033
AEPTCoAEPTCoSenior Unsecured Notes700.0 5.402053AEPTCoSenior Unsecured Notes700.0 5.402053
AEP TexasAEP TexasPollution Control Bonds60.0 4.252030
AEP TexasAEP TexasSenior Unsecured Notes450.0 5.402033
APCoAPCoOther Long-term Debt200.0 Variable2024
I&MI&MSenior Unsecured Notes500.0 5.632053I&MSenior Unsecured Notes500.0 5.632053
OPCoOPCoSenior Unsecured Notes400.0 5.002033
PSOPSOSenior Unsecured Notes475.0 5.252033PSOSenior Unsecured Notes475.0 5.252033
SWEPCoSWEPCoSenior Unsecured Notes350.0 5.302033SWEPCoSenior Unsecured Notes350.0 5.302033
Non-Registrant:Non-Registrant:Non-Registrant:
KPCoKPCoPollution Control Bonds65.0 4.702026
Transource EnergyTransource EnergyOther Long-term Debt1.0 Variable2025Transource EnergyOther Long-term Debt14.0 Variable2025
Total IssuancesTotal Issuances$2,876.0 Total Issuances$4,064.0 

(a)Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.

PrincipalInterestPrincipalInterest
CompanyCompanyType of DebtAmount PaidRateDue DateCompanyType of DebtAmount PaidRateDue Date
Retirements and Principal Payments:Retirements and Principal Payments:(in millions)(%)Retirements and Principal Payments:(in millions)(%)
AEPAEPSenior Unsecured Notes$600.0 Variable2023
AEP TexasAEP TexasPollution Control Bonds60.0 0.902023
AEP TexasAEP TexasSenior Unsecured Notes125.0 3.092023
AEP TexasAEP TexasSenior Unsecured Notes$125.0 3.092023AEP TexasSecuritization Bonds31.5 2.852024
AEP TexasAEP TexasSecuritization Bonds11.7 2.062025AEP TexasSecuritization Bonds23.5 2.062025
APCoAPCoSecuritization Bonds9.7 2.012023APCoSecuritization Bonds9.7 2.012023
APCoAPCoSecuritization Bonds3.3 3.772028APCoSecuritization Bonds16.8 3.772028
I&MI&MSenior Unsecured Notes250.0 3.202023I&MSenior Unsecured Notes250.03.202023
I&MI&MNotes Payable0.6 Variable2023I&MNotes Payable1.8Variable2023
I&MI&MNotes Payable3.7Variable2024
I&MI&MNotes Payable13.8Variable2025
I&MI&MNotes Payable12.00.932025
I&MI&MNotes Payable1.2 Variable2024I&MNotes Payable20.63.442026
I&MI&MNotes Payable4.6 Variable2025I&MNotes Payable20.55.932027
I&MI&MNotes Payable3.9 0.932025I&MOther Long-term Debt1.7 6.002025
I&MNotes Payable6.8 3.442026
I&MNotes Payable6.7 5.932027
I&MOther Long-term Debt0.5 6.002025
OPCoOPCoOther Long-term Debt0.6 1.152028
PSOPSOOther Long-term Debt0.1 3.002027PSOOther Long-term Debt0.4 3.002027
SWEPCoSWEPCoNotes Payable25.0 6.372024SWEPCoNotes Payable25.0 6.372024
SWEPCoSWEPCoNotes Payable30.9 4.582032SWEPCoNotes Payable30.9 4.582032
SWEPCoSWEPCoOther Long-term Debt38.2 4.682028SWEPCoOther Long-Term Debt38.2 4.682028
Non-Registrant:Non-Registrant:Non-Registrant:
KPCoKPCoPollution Control Bonds65.0 2.352023
Transource EnergyTransource EnergySenior Unsecured Notes1.3 2.752050Transource EnergySenior Unsecured Notes2.6 2.752050
Total Retirements and Principal PaymentsTotal Retirements and Principal Payments$519.5 Total Retirements and Principal Payments$1,353.3 
183



Long-term Debt Subsequent Event

In AprilOctober 2023, I&M retired $8$4 million of Notes Payable related to DCC Fuel.


In October 2023, Transource Energy issued $3.5 million of variable rate Other Long-term Debt due in 2025.
184


In November 2023, AEP retired $450 million of Senior Unsecured Notes.

Equity Units (Applies to AEP)

2020 Equity Units

In August 2020, AEP issued 17 million Equity Units initially in the form of corporate units, at a stated amount of $50 per unit, for a total stated amount of $850 million. Net proceeds from the issuance were approximately $833 million. The proceeds were used to support AEP’s overall capital expenditure plans.

Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 1.30% Junior Subordinated Notes (notes) due in 2025 and a forward equity purchase contract which settlessettled after three years in August 2023. The notes are expected to beIn June 2023, AEP successfully remarketed in 2023, at which time the interest rate will reset atJunior Subordinated Notes on behalf of holders of the then current market rate. Investors may choose to remarket their notes tocorporate 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 and use those fundsfrom the treasury portfolio were used to settle the forward equity purchase contract or acceptwith AEP. The interest rate on the remarketed debt and use other funds for the equity purchase. If the remarketing is unsuccessful, investors have the rightJunior Subordinated Notes was reset to put their notes to AEP at a price equal to the principal. The Equity Units carry an annual distribution rate of 6.125%, which is comprised of a quarterly coupon rate of interest of 1.30% and a quarterly forward equity purchase contract payment of 4.825%.

Each forward equity purchase contract obligates the holder to purchase, and AEP to sell, for $50 a number of shares in common stock in accordance5.699% with the conversion ratios set forth below (subject to an anti-dilution adjustment):

If thematurity remaining in 2025. In August 2023, AEP issued 10,048,668 shares of AEP common stock market price is equal to or greater than $99.95: 0.5003 shares per contract.
If the AEP common stock market price is less than $99.95 but greater than $83.29: a number of shares per contract equal to $50 divided by the applicable market price. The holder receives a variable number of shares at $50.
If the AEP common stock market price is less than or equal to $83.29: 0.6003 shares per contract.

A holder’s ownership interest in the notes is pledged to AEP to secure the holder’s obligationand received proceeds totaling $850 million under the related forward equity purchase contract. If a holder of the forward equity purchase contract chooses at any time to no longer be a holder of the notes, such holder’s obligation under the forward equity purchase contract must be secured by a U.S. Treasury security which must be equal to the aggregate principal amount of the notes.

At the time of issuance, the $850 million of notes were recorded within Long-term Debt on the balance sheets. The present value of the purchase contract payments of $121 million were recorded in Deferred Credits and Other Noncurrent Liabilitieswith a current portion in Other Current Liabilities at the time of issuance, representing the obligation to make forward equity contract payments, with an offsetting reduction to Paid-in Capital. The difference between the face value and present value of the purchase contract payments will be accreted to Interest Expense on the statements of income over the three year period ending in 2023. The liability recorded for the contract payments is considered non-cash and excluded from the statements of cash flows. Until settlement of the forward equity purchase contract, earnings per share dilution resulting from the equity unit issuance will be determined under thecontract. AEP common stock held in treasury stock method. The maximum amount of shares AEP will be required to issuewas used to settle the forward equity purchase contract is 10,205,100 shares (subjectcontract. The proceeds were used to an anti-dilution adjustment).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 0.0%0.9% of consolidated tangible net assets as of March 31,September 30, 2023. The method for calculating the consolidated tangible net assets is contractually-defined in the note purchase agreements.


185



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 Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings.
184


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.


186



Corporate Borrowing Program - AEP System (Applies to all Registrant Subsidiaries)

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and direct borrowing from AEP. The AEP System Utility Money Pool operates in accordance with the terms and conditions of its agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of March 31,September 30, 2023 and December 31, 2022 are included in Advances to Affiliates and Advances from Affiliates, respectively, on the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ activity and corresponding authorized borrowing limits for the threenine months ended March 31,September 30, 2023 are described in the following table:
MaximumAverageNet Loans toMaximumAverageNet Loans to
BorrowingsMaximumBorrowingsAverage(Borrowings from)AuthorizedBorrowingsMaximumBorrowingsAverage(Borrowings from)Authorized
from theLoans to thefrom theLoans to thethe Utility MoneyShort-termfrom theLoans to thefrom theLoans to thethe Utility MoneyShort-term
UtilityUtilityUtilityUtilityPool as ofBorrowingUtilityUtilityUtilityUtilityPool as ofBorrowing
CompanyCompanyMoney PoolMoney PoolMoney PoolMoney PoolMarch 31, 2023LimitCompanyMoney PoolMoney PoolMoney PoolMoney PoolSeptember 30, 2023Limit
(in millions) (in millions)
AEP TexasAEP Texas$453.7 $— $285.3 $— $(450.8)$500.0 AEP Texas$477.5 $42.0 $250.4 $42.0 $42.0 $500.0 
AEPTCoAEPTCo471.3 309.4 272.9 45.7 260.5 820.0 (a)AEPTCo471.3 309.4 134.3 76.0 7.2 820.0 (a)
APCoAPCo373.6 19.8 285.3 18.9 (291.5)500.0 APCo388.6 19.8 280.8 19.0 (183.2)500.0 
I&MI&M475.3 82.9 212.5 28.1 60.0 500.0 I&M475.3 112.2 126.0 49.3 21.2 500.0 
OPCoOPCo483.0 — 292.6 — (414.6)500.0 OPCo485.7 64.7 207.1 40.2 (113.3)500.0 
PSOPSO375.0 121.5 321.7 74.8 (130.7)400.0 PSO375.0 121.5 106.3 53.9 9.2 400.0 
SWEPCoSWEPCo401.6 (b)— 353.9 — (18.8)400.0 SWEPCo401.6 (b)25.8 165.3 16.5 (48.9)400.0 

(a)    Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
(b)    SWEPCo’s maximum borrowings from the Utility Money Pool exceeded the authorized short-term borrowing limit by $1.6 million on March 15, 2023. On March 16, 2023, SWEPCo’s borrowings from the Utility Money Pool were reduced below the $400 million authorized limit and borrowings have continued to remain below the authorized limit.

The activity in the above table does not include short-term lending activity of certain AEP nonutility subsidiaries. AEP Texas’ wholly-owned subsidiary, AEP Texas North Generation Company, LLC and SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC participate in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of March 31,September 30, 2023 and December 31, 2022 are included in Advances to Affiliates on the subsidiaries’ balance sheets. The Nonutility Money Pool participants’ activity for the threenine months ended March 31,September 30, 2023 is described in the following table:
Maximum Loans Average Loans Loans to the Nonutility
to the Nonutility to the Nonutility Money Pool as of
CompanyMoney PoolMoney PoolMarch 31, 2023
(in millions)
AEP Texas$6.9 $6.8 $6.8 
SWEPCo2.1 2.1 2.1 


Maximum Loans Average Loans Loans to the Nonutility
to the Nonutility to the Nonutility Money Pool as of
CompanyMoney PoolMoney PoolSeptember 30, 2023
(in millions)
AEP Texas$7.0 $6.9 $7.0 
SWEPCo2.7 2.3 2.7 

187185



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 March 31,September 30, 2023 and December 31, 2022 are included in Advances to Affiliates and Advances from Affiliates respectively, on AEPTCo’s balance sheets. AEPTCo’s direct borrowing and lending activity with AEP and corresponding authorized borrowing limit for the threenine months ended March 31,September 30, 2023 are described in the following table:
Maximum Maximum Average Average Borrowings from Loans toAuthorized
Borrowings Loans Borrowings Loans AEP as of AEP as ofShort-term
from AEP to AEP from AEP to AEP March 31, 2023March 31, 2023Borrowing Limit
(in millions)
$29.4 $158.1 $3.1 $80.2 $1.6 $34.2 $50.0 (a)

Maximum Maximum Average Average Borrowings from Loans toAuthorized
Borrowings Loans Borrowings Loans AEP as of AEP as ofShort-term
from AEP to AEP from AEP to AEP September 30, 2023September 30, 2023Borrowing Limit
(in millions)
$37.9 $158.1 $3.0 $67.5 $33.4 $— $50.0 (a)

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

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool are summarized in the following table:
Three Months Ended March 31, Nine Months Ended September 30,
2023202220232022
Maximum Interest RateMaximum Interest Rate5.42 %1.00 %Maximum Interest Rate5.81 %3.39 %
Minimum Interest RateMinimum Interest Rate4.66 %0.10 %Minimum Interest Rate4.66 %0.10 %

The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized for all Registrant Subsidiaries in the following table:
Average Interest Rate for FundsAverage Interest Rate for FundsAverage Interest Rate for FundsAverage Interest Rate for Funds
Borrowed from the Utility Money PoolLoaned to the Utility Money PoolBorrowed from the Utility Money PoolLoaned to the Utility Money Pool
for Three Months Ended March 31,for Three Months Ended March 31,for Nine Months Ended September 30,for Nine Months Ended September 30,
CompanyCompany2023202220232022Company2023202220232022
AEP TexasAEP Texas5.18 %0.70 %— %— %AEP Texas5.44 %0.90 %5.70 %1.82 %
AEPTCoAEPTCo5.09 %0.66 %5.29 %0.60 %AEPTCo5.29 %1.03 %5.52 %2.14 %
APCoAPCo5.14 %0.55 %5.12 %0.62 %APCo5.47 %1.39 %5.47 %2.13 %
I&MI&M5.12 %0.63 %5.16 %0.62 %I&M5.13 %1.38 %5.54 %1.46 %
OPCoOPCo5.17 %0.77 %— %0.48 %OPCo5.37 %1.81 %5.60 %1.22 %
PSOPSO4.84 %0.69 %5.11 %0.65 %PSO5.48 %1.70 %5.24 %0.75 %
SWEPCoSWEPCo5.12 %0.98 %— %0.55 %SWEPCo5.25 %1.67 %5.72 %0.55 %

Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized in the following table:
Three Months Ended March 31, 2023Three Months Ended March 31, 2022Nine Months Ended September 30, 2023Nine Months Ended September 30, 2022
 Maximum Minimum AverageMaximum Minimum Average  Maximum Minimum AverageMaximum Minimum Average
 Interest Rate Interest Rate Interest RateInterest Rate Interest Rate Interest Rate  Interest Rate Interest Rate Interest RateInterest Rate Interest Rate Interest Rate
 for Funds for Funds for Fundsfor Funds for Funds for Funds  for Funds for Funds for Fundsfor Funds for Funds for Funds
 Loaned to Loaned to Loaned toLoaned to Loaned to Loaned to Loaned to Loaned to Loaned toLoaned to Loaned to Loaned to
 the Nonutility the Nonutility the Nonutilitythe Nonutility the Nonutility the Nonutility the Nonutility the Nonutility the Nonutilitythe Nonutility the Nonutility the Nonutility
CompanyCompany Money Pool Money Pool Money PoolMoney Pool Money Pool Money PoolCompany Money Pool Money Pool Money PoolMoney Pool Money Pool Money Pool
AEP TexasAEP Texas 5.42 %4.66 %5.12 %1.00 %0.46 %0.62 %AEP Texas 5.81 %4.66 %5.47 %3.39 %0.46 %1.51 %
SWEPCoSWEPCo 5.42 %4.66 %5.13 %1.00 %0.46 %0.62 %SWEPCo 5.81 %4.66 %5.49 %3.39 %0.46 %1.52 %


188186



AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table:

 MaximumMinimumMaximumMinimumAverageAverage MaximumMinimumMaximumMinimumAverageAverage
 Interest RateInterest RateInterest RateInterest RateInterest RateInterest Rate Interest RateInterest RateInterest RateInterest RateInterest RateInterest Rate
Three Months for Fundsfor Fundsfor Fundsfor Fundsfor Fundsfor Funds
Nine MonthsNine Months for Fundsfor Fundsfor Fundsfor Fundsfor Fundsfor Funds
EndedEnded BorrowedBorrowedLoanedLoanedBorrowedLoanedEnded BorrowedBorrowedLoanedLoanedBorrowedLoaned
March 31, from AEP from AEPto AEP to AEP from AEP to AEP
September 30,September 30, from AEP from AEPto AEP to AEP from AEP to AEP
20232023 5.38 %4.53 %5.38 %4.53 %5.03 %5.15 %2023 5.81 %4.53 %5.81 %4.53 %5.43 %5.46 %
20222022 1.00 %0.46 %1.00 %0.46 %0.66 %0.60 %2022 3.39 %0.46 %3.37 %0.46 %1.56 %1.38 %

Short-term Debt (Applies to AEP and SWEPCo)

Outstanding short-term debt was as follows:
 March 31, 2023December 31, 2022 September 30, 2023December 31, 2022
OutstandingInterestOutstandingInterestOutstandingInterestOutstandingInterest
CompanyCompanyType of DebtAmountRate (a)AmountRate (a)CompanyType of DebtAmountRate (a)AmountRate (a)
 (dollars in millions) (dollars in millions)
AEPAEPSecuritized Debt for Receivables (b)$750.0 5.05 %$750.0 4.67 %AEPSecuritized Debt for Receivables (b)$900.0 5.60 %$750.0 4.67 %
AEPAEPCommercial Paper1,981.1 5.20 %2,862.2 4.80 %AEPCommercial Paper1,826.5 5.64 %2,862.2 4.80 %
AEPTerm Loan500.0 5.67 %— — %
AEPAEPTerm Loan150.0 5.63 %150.0 5.17 %AEPTerm Loan— — %150.0 5.17 %
AEPAEPTerm Loan125.0 5.64 %125.0 5.17 %AEPTerm Loan— — %125.0 5.17 %
AEPAEPTerm Loan100.0 5.64 %100.0 5.23 %AEPTerm Loan— — %100.0 5.23 %
AEPAEPTerm Loan— — %125.0 4.87 %AEPTerm Loan— — %125.0 4.87 %
SWEPCoSWEPCoNotes Payable16.0 7.27 %— — %SWEPCoNotes Payable3.9 7.67 %— — %
AEPTotal Short-term Debt$3,622.1  $4,112.2  
Total Short-term Debt$2,730.4  $4,112.2  

(a)Weighted-average rate as of March 31,September 30, 2023 and December 31, 2022, respectively.
(b)Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.

Credit Facilities

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

Securitized Accounts Receivables – AEP Credit (Applies to AEP)

AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections.

AEP Credit’s receivables securitization agreement provides a commitment of $750$900 million from bank conduits to purchase receivables and includes a $125receivables. The agreement was amended in August 2023 to increase the commitment from $750 million and a $625 million facility, both of which expireexpires in September 2024.2025. As of March 31,September 30, 2023, the affiliated utility subsidiaries were in compliance with all requirements under the agreement. SWEPCo temporarily eased credit policies from August 2022 through October 2022 to assist customers with higher than normal bills driven by increased fuel costs and, in turn, experienced higher than normal aged receivables. In response, in January 2023, AEP Credit amended its receivables securitization agreement to increase the eligibility criteria related to their aged receivables requirements to ensure SWEPCo remains in compliance.


189187



Accounts receivable information for AEP Credit was as follows:
Three Months Ended March 31,Three Months Ended September 30,Nine Months Ended September 30,
202320222023202220232022
(dollars in millions)(dollars in millions)
Effective Interest Rates on Securitization of Accounts ReceivableEffective Interest Rates on Securitization of Accounts Receivable4.86 %0.31 %Effective Interest Rates on Securitization of Accounts Receivable5.55 %2.25 %5.23 %1.16 %
Net Uncollectible Accounts Receivable Written-OffNet Uncollectible Accounts Receivable Written-Off$6.9 $7.4 Net Uncollectible Accounts Receivable Written-Off$8.8 $9.5 $22.9 $23.1 

March 31, 2023December 31, 2022September 30, 2023December 31, 2022
(in millions)(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible AccountsAccounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts$1,091.8 $1,167.7 Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts$1,257.0 $1,167.7 
Short-term – Securitized Debt of ReceivablesShort-term – Securitized Debt of Receivables750.0 750.0 Short-term – Securitized Debt of Receivables900.0 750.0 
Delinquent Securitized Accounts ReceivableDelinquent Securitized Accounts Receivable49.3 44.2 Delinquent Securitized Accounts Receivable59.5 44.2 
Bad Debt Reserves Related to SecuritizationBad Debt Reserves Related to Securitization41.2 39.7 Bad Debt Reserves Related to Securitization42.2 39.7 
Unbilled Receivables Related to SecuritizationUnbilled Receivables Related to Securitization287.3 360.9 Unbilled Receivables Related to Securitization301.8 360.9 

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

Securitized Accounts Receivables – AEP Credit (Applies to all Registrant Subsidiaries except AEP Texas and AEPTCo)

Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant 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 transferred to AEP Credit. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder.

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreements were:
CompanyCompanyMarch 31, 2023December 31, 2022CompanySeptember 30, 2023December 31, 2022
(in millions) (in millions)
APCoAPCo$195.5 $194.4 APCo$170.5 $194.4 
I&MI&M167.9 166.9 I&M176.2 166.9 
OPCoOPCo457.5 478.6 OPCo479.3 478.6 
PSOPSO134.2 155.5 PSO211.5 155.5 
SWEPCoSWEPCo157.8 194.0 SWEPCo210.2 194.0 

The fees paid to AEP Credit for customer accounts receivable sold were:
 Three Months Ended March 31,
Company20232022
 (in millions)
APCo$4.9 $1.3 
I&M3.9 1.7 
OPCo7.3 7.4 
PSO3.2 0.9 
SWEPCo4.3 1.3 

 Three Months Ended September 30,Nine Months Ended September 30,
Company2023202220232022
 (in millions)
APCo$4.1 $2.8 $13.3 $5.6 
I&M4.4 2.8 12.2 6.5 
OPCo7.4 7.3 22.3 22.2 
PSO4.6 2.4 11.3 4.6 
SWEPCo5.2 3.2 13.9 6.0 

190188



The proceeds on the sale of receivables to AEP Credit were:
 Three Months Ended March 31,
Company20232022
(in millions)
APCo$506.2 $415.5 
I&M525.4 513.4 
OPCo884.4 716.6 
PSO416.3 363.4 
SWEPCo437.6 394.5 

 Three Months Ended September 30,Nine Months Ended September 30,
Company2023202220232022
(in millions)
APCo$451.6 $360.4 $1,372.7 $1,114.9 
I&M553.3 558.5 1,575.9 1,574.3 
OPCo850.3 874.1 2,518.6 2,284.0 
PSO633.8 588.5 1,510.3 1,380.4 
SWEPCo558.4 593.6 1,456.5 1,425.3 
191189



13. VARIABLE INTEREST ENTITIES

The disclosures in this note apply to AEP 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.

AEP holds ownership interests in businesses with varying ownership structures. 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

The Annual Report on Form 10-K for the year ended December 31, 2022 includes a detailed discussion of the Registrants’ consolidated VIEs. There were no reconsideration events with respect to those VIEs in the first quarter of 2023.

The balances below represent the assets and liabilities of consolidated VIEs. These balances include intercompany transactions that are eliminated upon consolidation.

American Electric Power Company, Inc. and Subsidiary CompaniesAmerican Electric Power Company, Inc. and Subsidiary CompaniesAmerican Electric Power Company, Inc. and Subsidiary Companies
Variable Interest EntitiesVariable Interest EntitiesVariable Interest Entities
March 31, 2023
September 30, 2023September 30, 2023
Registrant SubsidiariesRegistrant Subsidiaries
SWEPCo
Sabine
I&M
DCC Fuel
AEP Texas Transition FundingAEP Texas Restoration FundingAPCo
Appalachian
Consumer
Rate
Relief Funding
SWEPCo
Sabine
I&M
DCC Fuel
AEP Texas Transition FundingAEP Texas Restoration FundingAPCo Appalachian Consumer Rate Relief Funding
(in millions)(in millions)
ASSETSASSETSASSETS
Current AssetsCurrent Assets$23.0 $84.3 $43.0 $13.4 $6.1 Current Assets$4.8 $59.9 $49.4 $20.9 $4.7 
Net Property, Plant and EquipmentNet Property, Plant and Equipment— 154.3 — — — Net Property, Plant and Equipment— 104.1— — — 
Other Noncurrent AssetsOther Noncurrent Assets135.1 76.0 125.2 (a)163.0 (b)157.4 (c)Other Noncurrent Assets128.151.890.5(a)151.4 (b)145.3(c)
Total AssetsTotal Assets$158.1 $314.6 $168.2 $176.4 $163.5 Total Assets$132.9 $215.8 $139.9 $172.3 $150.0 
LIABILITIES AND EQUITYLIABILITIES AND EQUITYLIABILITIES AND EQUITY
Current LiabilitiesCurrent Liabilities$33.5 $84.2 $74.3 $30.5 $28.1 Current Liabilities$21.0 $59.8 $75.3 $36.0 $28.5 
Noncurrent LiabilitiesNoncurrent Liabilities124.2 230.4 89.6 144.7 133.5 Noncurrent Liabilities110.6156.060.3135.1119.6
EquityEquity0.4 — 4.3 1.2 1.9 Equity1.3— 4.31.21.9
Total Liabilities and EquityTotal Liabilities and Equity$158.1 $314.6 $168.2 $176.4 $163.5 Total Liabilities and Equity$132.9 $215.8 $139.9 $172.3 $150.0 

(a)Includes an intercompany item eliminated in consolidation of $14$10 million.
(b)Includes an intercompany item eliminated in consolidation of $7 million.$6 million.
(c)Includes an intercompany item eliminated in consolidation of $2 million.
192190



American Electric Power Company, Inc. and Subsidiary CompaniesAmerican Electric Power Company, Inc. and Subsidiary CompaniesAmerican Electric Power Company, Inc. and Subsidiary Companies
Variable Interest EntitiesVariable Interest EntitiesVariable Interest Entities
March 31, 2023
September 30, 2023September 30, 2023
Other Consolidated VIEsOther Consolidated VIEs
AEP CreditProtected
Cell
of EIS
Transource EnergyAEP CreditProtected
Cell
of EIS
Transource Energy
(in millions)(in millions)
ASSETSASSETSASSETS
Current AssetsCurrent Assets$1,092.6 $203.2 $22.1 Current Assets$1,259.0 $202.9 $32.8 
Net Property, Plant and EquipmentNet Property, Plant and Equipment— — 495.1 Net Property, Plant and Equipment— — 499.8
Other Noncurrent AssetsOther Noncurrent Assets8.9 — 6.8 Other Noncurrent Assets9.6 0.7 4.0
Total AssetsTotal Assets$1,101.5 $203.2 $524.0 Total Assets$1,268.6 $203.6 $536.6 
LIABILITIES AND EQUITYLIABILITIES AND EQUITYLIABILITIES AND EQUITY
Current LiabilitiesCurrent Liabilities$1,043.2 $50.2 $33.4 Current Liabilities$1,201.3 $54.1 $21.3 
Noncurrent LiabilitiesNoncurrent Liabilities0.9 78.0 219.0 Noncurrent Liabilities0.984.7 229.4
EquityEquity57.4 75.0 271.6 Equity66.4 64.8 285.9
Total Liabilities and EquityTotal Liabilities and Equity$1,101.5 $203.2 $524.0 Total Liabilities and Equity$1,268.6 $203.6 $536.6 

As of September 30, 2023, Apple Blossom, Black Oak, Santa Rita East and Dry Lake are no longer consolidated VIEs included indue to the plan of sale of the Competitive Contracted Renewables Portfolio. See the “Planned Disposition of the Competitive Contracted Renewables Portfolio”Portfolio section of Note 6 for the assets and liabilities classified Held for Sale as of March 31, 2023 inclusive of the assets and liabilities of the aforementioned consolidated VIEs.additional information.

American Electric Power Company, Inc. and Subsidiary CompaniesAmerican Electric Power Company, Inc. and Subsidiary CompaniesAmerican Electric Power Company, Inc. and Subsidiary Companies
Variable Interest EntitiesVariable Interest EntitiesVariable Interest Entities
December 31, 2022December 31, 2022December 31, 2022
Registrant SubsidiariesRegistrant Subsidiaries
SWEPCo
Sabine
I&M
DCC Fuel
AEP Texas Transition FundingAEP Texas Restoration FundingAPCo
Appalachian
Consumer
Rate
Relief Funding
SWEPCo
Sabine
I&M
DCC Fuel
AEP Texas Transition FundingAEP Texas Restoration FundingAPCo Appalachian Consumer Rate Relief Funding
(in millions)(in millions)
ASSETSASSETSASSETS
Current AssetsCurrent Assets$108.3 $90.2 $27.0 $21.1 $13.5 Current Assets$108.3 $90.2 $27.0 $21.1 $13.5 
Net Property, Plant and EquipmentNet Property, Plant and Equipment7.2 179.1 — — — Net Property, Plant and Equipment7.2 179.1 — — — 
Other Noncurrent AssetsOther Noncurrent Assets130.0 94.0 140.9 (a)168.8 (b)164.6 (c)Other Noncurrent Assets130.0 94.0 140.9 (a)168.8 (b)164.6 (c)
Total AssetsTotal Assets$245.5 $363.3 $167.9 $189.9 $178.1 Total Assets$245.5 $363.3 $167.9 $189.9 $178.1 
LIABILITIES AND EQUITYLIABILITIES AND EQUITYLIABILITIES AND EQUITY
Current LiabilitiesCurrent Liabilities$25.4 $90.0 $73.2 $31.3 $29.3 Current Liabilities$25.4 $90.0 $73.2 $31.3 $29.3 
Noncurrent LiabilitiesNoncurrent Liabilities219.4 273.3 90.4 157.4 146.9 Noncurrent Liabilities219.4 273.3 90.4 157.4 146.9 
EquityEquity0.7 — 4.3 1.2 1.9 Equity0.7 — 4.3 1.2 1.9 
Total Liabilities and EquityTotal Liabilities and Equity$245.5 $363.3 $167.9 $189.9 $178.1 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.




193191



American Electric Power Company, Inc. and Subsidiary Companies
Variable Interest Entities
December 31, 2022
Other Consolidated VIEs
AEP CreditProtected
Cell
of EIS
Transource EnergyApple Blossom and Black OakSanta Rita EastDry Lake
(in millions)
ASSETS
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 Assets9.0 0.3 2.7 13.6 0.1 0.3 
Total Assets$1,190.0 $194.8 $508.5 $238.4 $443.0 $146.9 
LIABILITIES AND EQUITY
Current Liabilities$1,087.8 $46.4 $22.8 $4.5 $9.6 $1.0 
Noncurrent Liabilities0.9 79.1 218.6 5.4 7.3 0.7 
Equity101.3 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 

Significant Variable Interests in Non-Consolidated VIEs and Significant Equity Method Investments

The Annual Report on Form 10-K for the year ended December 31, 2022 includes a detailed discussion of significant variable interests in non-consolidated VIEs and other significant equity method investments. There wereAs of September 30, 2023, AEP no reconsideration events or material changeslonger owns a significant equity method investment in carrying values asfour joint ventures through AEP Wind Holdings, LLC due to the sale of March 31, 2023.the Competitive Contracted Renewables Portfolio. See the “Disposition of the Competitive Contracted Renewables Portfolio” section of Note 6 for additional information.


194192


14. PROPERTY, PLANT AND EQUIPMENT

The disclosure in this note applies to AEP and SWEPCo.

Asset Retirement Obligations

The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, wind farms, solar farms and certain coal mining facilities. The table below summarizes significant changes to the Registrants ARO recorded in 2023 and should be read in conjunction with the Property, Plant and Equipment note within the 2022 Annual Report.

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

CompanyARO as of December 31, 2022Accretion
Expense
Liabilities
Incurred
Liabilities
Settled
Revisions in
Cash Flow
Estimates
ARO as of September 30, 2023
(in millions)
AEP (a)(b)(c)(d)(e)(f)$2,944.9 $86.0 $12.9 $(98.1)$13.8 $2,959.5 
SWEPCo (a)(c)(d)(e)282.2 10.0 7.1 (37.9)0.4 261.8 

(a)Includes ARO related to ash disposal facilities.
(b)Includes ARO related to nuclear decommissioning costs for the Cook Plant of $2.05 billion and $2 billion as of September 30, 2023 and December 31, 2022, respectively.
(c)Includes ARO related to Sabine and DHLC.
(d)Includes ARO related to asbestos removal.
(e)In 2023, SWEPCo settled $35 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 4 for additional information.
(f)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 6 for additional information.





193


14.15. REVENUE FROM CONTRACTS WITH CUSTOMERS

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

Disaggregated Revenues from Contracts with Customers

The tables below represent AEP’s reportable segment revenues from contracts with customers, net of respective provisions for refund, by type of revenue:
Three Months Ended March 31, 2023Three Months Ended September 30, 2023
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration & MarketingCorporate and OtherReconciling AdjustmentsAEP ConsolidatedVertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration & MarketingCorporate and OtherReconciling AdjustmentsAEP Consolidated
(in millions)(in millions)
Retail Revenues:Retail Revenues:Retail Revenues:
Residential RevenuesResidential Revenues$1,170.4 $656.8 $— $— $— $— $1,827.2 Residential Revenues$1,326.7 $772.5 $— $— $— $— $2,099.2 
Commercial RevenuesCommercial Revenues633.4 375.9 — — — — 1,009.3 Commercial Revenues753.3 387.7 — — — — 1,141.0 
Industrial RevenuesIndustrial Revenues670.3 212.9 — — — (0.2)883.0 Industrial Revenues699.9 138.9 — — — (0.3)838.5 
Other Retail RevenuesOther Retail Revenues56.8 12.1 — — — — 68.9 Other Retail Revenues66.6 13.0 — — — — 79.6 
Total Retail RevenuesTotal Retail Revenues2,530.9 1,257.7 — — — (0.2)3,788.4 Total Retail Revenues2,846.5 1,312.1 — — — (0.3)4,158.3 
Wholesale and Competitive Retail Revenues:Wholesale and Competitive Retail Revenues:Wholesale and Competitive Retail Revenues:
Generation RevenuesGeneration Revenues182.8 — — 32.4 — — 215.2 Generation Revenues174.3 — — 31.8 — (0.3)205.8 
Transmission Revenues (a)Transmission Revenues (a)114.7 164.2 450.1 — — (401.8)327.2 Transmission Revenues (a)120.6 176.0 466.1 — — (425.1)337.6 
Renewable Generation Revenues (b)Renewable Generation Revenues (b)— — — 21.3 — (0.1)21.2 Renewable Generation Revenues (b)— — — 19.8 — (2.5)17.3 
Retail, Trading and Marketing Revenues (b)(c)Retail, Trading and Marketing Revenues (b)(c)— — — 413.7 (0.3)0.1 413.5 Retail, Trading and Marketing Revenues (b)(c)— — — 510.8 0.8 (36.7)474.9 
Total Wholesale and Competitive Retail RevenuesTotal Wholesale and Competitive Retail Revenues297.5 164.2 450.1 467.4 (0.3)(401.8)977.1 Total Wholesale and Competitive Retail Revenues294.9 176.0 466.1 562.4 0.8 (464.6)1,035.6 
Other Revenues from Contracts with Customers (c)(d)Other Revenues from Contracts with Customers (c)(d)32.6 42.8 3.6 0.6 29.4 (43.7)65.3 Other Revenues from Contracts with Customers (c)(d)61.3 58.2 4.8 0.9 55.6 (48.5)132.3 
Total Revenues from Contracts with CustomersTotal Revenues from Contracts with Customers2,861.0 1,464.7 453.7 468.0 29.1 (445.7)4,830.8 Total Revenues from Contracts with Customers3,202.7 1,546.3 470.9 563.3 56.4 (513.4)5,326.2 
Other Revenues:Other Revenues:Other Revenues:
Alternative Revenue Programs (d)(3.1)(11.6)1.8 — — 2.9 (10.0)
Alternative Revenue Programs (b) (e)Alternative Revenue Programs (b) (e)0.5 (5.0)5.8 — — 5.7 7.0 
Other Revenues (b) (e)(f)Other Revenues (b) (e)(f)(0.1)11.1 — (141.0)1.0 (0.9)(129.9)Other Revenues (b) (e)(f)2.2 2.8 — 3.4 0.8 (0.7)8.5 
Total Other RevenuesTotal Other Revenues(3.2)(0.5)1.8 (141.0)1.0 2.0 (139.9)Total Other Revenues2.7 (2.2)5.8 3.4 0.8 5.0 15.5 
Total RevenuesTotal Revenues$2,857.8 $1,464.2 $455.5 $327.0 $30.1 $(443.7)$4,690.9 Total Revenues$3,205.4 $1,544.1 $476.7 $566.7 $57.2 $(508.4)$5,341.7 

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $357$366 million. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $37 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Corporate and Other was $32 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.
194


Three Months Ended September 30, 2022
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration & MarketingCorporate and OtherReconciling AdjustmentsAEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues$1,298.0 $721.9 $— $— $— $— $2,019.9 
Commercial Revenues725.1 373.0 — — — — 1,098.1 
Industrial Revenues658.5 191.5 — — — (0.3)849.7 
Other Retail Revenues54.3 15.0 — — — — 69.3 
Total Retail Revenues2,735.9 1,301.4 — — — (0.3)4,037.0 
Wholesale and Competitive Retail Revenues:
Generation Revenues299.3 — — 83.7 — (0.2)382.8 
Transmission Revenues (a)120.3 162.3 424.9 — — (392.7)314.8 
Renewable Generation Revenues (b)— — — 44.3 — (2.5)41.8 
Retail, Trading and Marketing Revenues— — — 482.9 2.2 0.2 485.3 
Total Wholesale and Competitive Retail Revenues419.6 162.3 424.9 610.9 2.2 (395.2)1,224.7 
Other Revenues from Contracts with Customers (c)69.7 74.5 (0.3)1.7 24.3 (31.9)138.0 
Total Revenues from Contracts with Customers3,225.2 1,538.2 424.6 612.6 26.5 (427.4)5,399.7 
Other Revenues:
Alternative Revenue Programs (b) (d)0.9 (13.5)6.3 — — 4.4 (1.9)
Other Revenues (b) (e)0.2 5.5 — 122.8 1.8 (2.0)128.3 
Total Other Revenues1.1 (8.0)6.3 122.8 1.8 2.4 126.4 
Total Revenues$3,226.3 $1,530.2 $430.9 $735.4 $28.3 $(425.0)$5,526.1 

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $342 million. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Corporate and Other was $29$18 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.

195



Three Months Ended March 31, 2022
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration & MarketingCorporate and OtherReconciling AdjustmentsAEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues$1,150.8 $600.6 $— $— $— $— $1,751.4 
Commercial Revenues572.9 289.7 — — — — 862.6 
Industrial Revenues563.0 133.3 — — — (0.4)695.9 
Other Retail Revenues47.4 11.6 — — — — 59.0 
Total Retail Revenues2,334.1 1,035.2 — — — (0.4)3,368.9 
Wholesale and Competitive Retail Revenues:
Generation Revenues187.2 — — 40.3 — — 227.5 
Transmission Revenues (a)105.3 154.9 414.5 — — (361.8)312.9 
Renewable Generation Revenues (b)— — — 22.4 — (0.8)21.6 
Retail, Trading and Marketing Revenues (c)— — — 388.8 3.2 (9.0)383.0 
Total Wholesale and Competitive Retail Revenues292.5 154.9 414.5 451.5 3.2 (371.6)945.0 
Other Revenues from Contracts with Customers (b)61.6 53.8 (0.2)8.6 13.9 (18.6)119.1 
Total Revenues from Contracts with Customers2,688.2 1,243.9 414.3 460.1 17.1 (390.6)4,433.0 
Other Revenues:
Alternative Revenue Programs (d)(0.8)(3.4)(2.9)— — 1.3 (5.8)
Other Revenues (b) (e)— 6.3 — 159.2 2.8 (2.9)165.4 
Total Other Revenues(0.8)2.9 (2.9)159.2 2.8 (1.6)159.6 
Total Revenues$2,687.4 $1,246.8 $411.4 $619.3 $19.9 $(392.2)$4,592.6 

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $327 million. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $9 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.



196



Three Months Ended March 31, 2023Three Months Ended September 30, 2023
AEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCoAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)(in millions)
Retail Revenues:Retail Revenues:Retail Revenues:
Residential RevenuesResidential Revenues$130.7 $— $470.5 $239.6 $526.0 $170.9 $175.9 Residential Revenues$236.2 $— $397.1 $230.7 $536.3 $310.5 $286.5 
Commercial RevenuesCommercial Revenues97.3 — 171.3 138.9 278.5 109.1 143.5 Commercial Revenues112.4 — 181.3 159.2 275.3 171.9 174.9 
Industrial RevenuesIndustrial Revenues39.3 — 185.8 152.6 173.6 98.3 104.2 Industrial Revenues35.4 — 197.1 159.1 103.6 114.1 105.5 
Other Retail RevenuesOther Retail Revenues8.3 — 26.2 1.3 3.8 24.2 2.6 Other Retail Revenues9.2 — 26.8 1.3 3.8 33.8 2.4 
Total Retail RevenuesTotal Retail Revenues275.6 — 853.8 532.4 981.9 402.5 426.2 Total Retail Revenues393.2 — 802.3 550.3 919.0 630.3 569.3 
Wholesale Revenues:Wholesale Revenues:Wholesale Revenues:
Generation Revenues (a)Generation Revenues (a)— — 80.2 104.0 — 0.9 39.6 Generation Revenues (a)— — 79.4 90.2 — (4.9)36.8 
Transmission Revenues (b)Transmission Revenues (b)146.3 438.7 41.4 8.1 17.9 11.3 42.9 Transmission Revenues (b)154.6 454.7 45.5 10.4 21.4 10.8 42.4 
Total Wholesale RevenuesTotal Wholesale Revenues146.3 438.7 121.6 112.1 17.9 12.2 82.5 Total Wholesale Revenues154.6 454.7 124.9 100.6 21.4 5.9 79.2 
Other Revenues from Contracts with Customers (c)Other Revenues from Contracts with Customers (c)9.7 3.7 13.0 21.4 33.2 2.3 7.9 Other Revenues from Contracts with Customers (c)8.8 5.0 35.2 26.2 49.2 5.4 6.0 
Total Revenues from Contracts with CustomersTotal Revenues from Contracts with Customers431.6 442.4 988.4 665.9 1,033.0 417.0 516.6 Total Revenues from Contracts with Customers556.6 459.7 962.4 677.1 989.6 641.6 654.5 
Other Revenues:Other Revenues:Other Revenues:
Alternative Revenue Programs (d)(2.1)(0.8)(0.7)(2.9)(9.5)— (0.7)
Alternative Revenue Programs (d) (e)Alternative Revenue Programs (d) (e)(2.0)3.0 (0.7)(2.9)(3.1)2.6 0.3 
Other Revenues (e)Other Revenues (e)— — — — 11.1 — — Other Revenues (e)— — 0.1 2.1 3.0 — — 
Total Other RevenuesTotal Other Revenues(2.1)(0.8)(0.7)(2.9)1.6 — (0.7)Total Other Revenues(2.0)3.0 (0.6)(0.8)(0.1)2.6 0.3 
Total RevenuesTotal Revenues$429.5 $441.6 $987.7 $663.0 $1,034.6 $417.0 $515.9 Total Revenues$554.6 $462.7 $961.8 $676.3 $989.5 $644.2 $654.8 

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $47$36 million primarily related to the PPA with KGPCo.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $349$363 million, APCo was $22 million and SWEPCo was $17 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $18 million primarily related 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.
197196



Three Months Ended March 31, 2022Three Months Ended September 30, 2022
AEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCoAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)(in millions)
Retail Revenues:Retail Revenues:Retail Revenues:
Residential RevenuesResidential Revenues$141.9 $— $458.0 $231.8 $458.7 $165.9 $175.9 Residential Revenues$204.0 $— $360.5 $238.6 $517.9 $299.6 $285.5 
Commercial RevenuesCommercial Revenues94.9 — 153.9 126.6 194.7 97.5 130.5 Commercial Revenues107.1 — 161.1 154.3 266.1 153.4 182.3 
Industrial RevenuesIndustrial Revenues30.6 — 153.8 136.5 102.7 78.6 84.7 Industrial Revenues35.4 — 163.3 155.6 156.1 98.9 108.3 
Other Retail RevenuesOther Retail Revenues8.2 — 20.6 1.3 3.3 21.2 2.4 Other Retail Revenues11.5 — 20.6 1.2 3.5 30.1 0.6 
Total Retail RevenuesTotal Retail Revenues275.6 — 786.3 496.2 759.4 363.2 393.5 Total Retail Revenues358.0 — 705.5 549.7 943.6 582.0 576.7 
Wholesale Revenues:Wholesale Revenues:Wholesale Revenues:
Generation Revenues (a)Generation Revenues (a)— — 56.2 90.4 — 9.5 61.2 Generation Revenues (a)— — 107.9 126.3 — 9.4 87.6 
Transmission Revenues (b)Transmission Revenues (b)133.1 400.3 41.1 8.8 21.8 9.6 35.2 Transmission Revenues (b)140.8 411.7 41.5 8.8 21.5 10.2 42.3 
Total Wholesale RevenuesTotal Wholesale Revenues133.1 400.3 97.3 99.2 21.8 19.1 96.4 Total Wholesale Revenues140.8 411.7 149.4 135.1 21.5 19.6 129.9 
Other Revenues from Contracts with Customers (c)Other Revenues from Contracts with Customers (c)9.3 (0.3)24.3 29.9 44.6 5.4 5.3 Other Revenues from Contracts with Customers (c)9.5 (0.3)33.7 30.6 64.8 6.4 7.6 
Total Revenues from Contracts with CustomersTotal Revenues from Contracts with Customers418.0 400.0 907.9 625.3 825.8 387.7 495.2 Total Revenues from Contracts with Customers508.3 411.4 888.6 715.4 1,029.9 608.0 714.2 
Other Revenues:Other Revenues:Other Revenues:
Alternative Revenue Programs (d)(1.3)0.4 (0.7)— (2.1)(0.1)(0.4)
Alternative Revenue Programs (d) (e)Alternative Revenue Programs (d) (e)0.6 7.1 — — (14.1)0.2 3.3 
Other Revenues (e)Other Revenues (e)— — 0.1 (0.1)6.3 — — Other Revenues (e)— — 0.3 — 5.5 — — 
Total Other RevenuesTotal Other Revenues(1.3)0.4 (0.6)(0.1)4.2 (0.1)(0.4)Total Other Revenues0.6 7.1 0.3 — (8.6)0.2 3.3 
Total RevenuesTotal Revenues$416.7 $400.4 $907.3 $625.2 $830.0 $387.6 $494.8 Total Revenues$508.9 $418.5 $888.9 $715.4 $1,021.3 $608.2 $717.5 

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $36$44 million primarily related to the PPA with KGPCo.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $323$339 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $10$15 million primarily related 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.


197


Nine Months Ended September 30, 2023
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration & MarketingCorporate and OtherReconciling AdjustmentsAEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues$3,459.1 $2,003.4 $— $— $— $— $5,462.5 
Commercial Revenues2,029.4 1,121.9 — — — — 3,151.3 
Industrial Revenues (a)2,069.1 503.9 — — — (0.6)2,572.4 
Other Retail Revenues182.3 37.4 — — — — 219.7 
Total Retail Revenues7,739.9 3,666.6 — — — (0.6)11,405.9 
Wholesale and Competitive Retail Revenues:
Generation Revenues498.5 — — 83.8 — (0.2)582.1 
Transmission Revenues (b)348.8 524.3 1,372.0 — — (1,229.7)1,015.4 
Renewable Generation Revenues (a)— — — 74.2 — (5.7)68.5 
Retail, Trading and Marketing Revenues (c)— — — 1,332.2 1.7 (46.7)1,287.2 
Total Wholesale and Competitive Retail Revenues847.3 524.3 1,372.0 1,490.2 1.7 (1,282.3)2,953.2 
Other Revenues from Contracts with Customers (d)155.8 157.1 12.7 7.7 113.6 (132.1)314.8 
Total Revenues from Contracts with Customers8,743.0 4,348.0 1,384.7 1,497.9 115.3 (1,415.0)14,673.9 
Other Revenues:
Alternative Revenue Programs (a) (e)(7.5)(19.5)6.1 — — 2.3 (18.6)
Other Revenues (a) (f)2.2 20.0 — (272.8)4.0 (3.6)(250.2)
Total Other Revenues(5.3)0.5 6.1 (272.8)4.0 (1.3)(268.8)
Total Revenues$8,737.7 $4,348.5 $1,390.8 $1,225.1 $119.3 $(1,416.3)$14,405.1 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $1.1 billion. The affiliated revenue for Vertically Integrated Utilities was $125 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $47 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Corporate and Other was $87 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.


198


Nine Months Ended September 30, 2022
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration & MarketingCorporate and OtherReconciling AdjustmentsAEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues$3,428.1 $1,884.1 $— $— $— $— $5,312.2 
Commercial Revenues1,922.8 994.4 — — — — 2,917.2 
Industrial Revenues (a)1,863.3 487.3 — — — (0.7)2,349.9 
Other Retail Revenues154.6 39.4 — — — — 194.0 
Total Retail Revenues7,368.8 3,405.2 — — — (0.7)10,773.3 
Wholesale and Competitive Retail Revenues:
Generation Revenues (a)674.8 — — 207.0 — (0.1)881.7 
Transmission Revenues (b)334.4 482.1 1,261.0 — — (1,086.5)991.0 
Renewable Generation Revenues (a)— — — 104.9 — (6.2)98.7 
Retail, Trading and Marketing Revenues (c)— — — 1,280.0 6.7 (11.1)1,275.6 
Total Wholesale and Competitive Retail Revenues1,009.2 482.1 1,261.0 1,591.9 6.7 (1,103.9)3,247.0 
Other Revenues from Contracts with Customers (d)180.5 194.2 (0.3)11.9 59.1 (71.6)373.8 
Total Revenues from Contracts with Customers8,558.5 4,081.5 1,260.7 1,603.8 65.8 (1,176.2)14,394.1 
Other Revenues:
Alternative Revenue Programs (a) (e)3.4 (21.5)(39.6)— — (7.4)(65.1)
Other Revenues (a) (f)0.3 18.6 — 410.5 6.9 (6.9)429.4 
Total Other Revenues3.7 (2.9)(39.6)410.5 6.9 (14.3)364.3 
Total Revenues$8,562.2 $4,078.6 $1,221.1 $2,014.3 $72.7 $(1,190.5)$14,758.4 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $1 billion. The affiliated revenue for Vertically Integrated Utilities was $120 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $11 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Corporate and Other was $36 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.

199


Nine Months Ended September 30, 2023
AEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Retail Revenues:
Residential Revenues$511.8 $— $1,192.4 $655.5 $1,491.6 $667.9 $647.5 
Commercial Revenues310.3 — 516.2 439.5 811.6 412.7 472.2 
Industrial Revenues (a)109.9 — 575.4 467.6 394.0 320.2 320.3 
Other Retail Revenues26.2 — 78.2 3.8 11.2 86.3 7.6 
Total Retail Revenues958.2 — 2,362.2 1,566.4 2,708.4 1,487.1 1,447.6 
Wholesale Revenues:
Generation Revenues (b)— — 223.8 257.7 — 0.3 120.3 
Transmission Revenues (c)464.0 1,338.1 130.8 28.1 60.3 32.0 123.6 
Total Wholesale Revenues464.0 1,338.1 354.6 285.8 60.3 32.3 243.9 
Other Revenues from Contracts with Customers (d)29.2 12.8 60.0 92.6 127.9 14.9 20.9 
Total Revenues from Contracts with Customers1,451.4 1,350.9 2,776.8 1,944.8 2,896.6 1,534.3 1,712.4 
Other Revenues:
Alternative Revenue Program (a) (e)(6.1)(1.7)(0.9)(8.4)(13.5)1.6 (3.9)
Other Revenues (a)— — 0.1 2.1 20.1 — — 
Total Other Revenues(6.1)(1.7)(0.8)(6.3)6.6 1.6 (3.9)
Total Revenues$1,445.3 $1,349.2 $2,776.0 $1,938.5 $2,903.2 $1,535.9 $1,708.5 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $121 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 $1.1 billion, APCo was $64 million and SWEPCo was $43 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $52 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.
200


Nine Months Ended September 30, 2022
AEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Retail Revenues:
Residential Revenues$520.8 $— $1,131.7 $665.6 $1,363.3 $650.7 $650.0 
Commercial Revenues312.6 — 467.6 419.5 681.9 372.1 458.8 
Industrial Revenues (a)102.6 — 479.0 452.1 384.8 270.0 290.1 
Other Retail Revenues29.2 — 61.4 3.7 10.2 77.1 7.4 
Total Retail Revenues965.2 — 2,139.7 1,540.9 2,440.2 1,369.9 1,406.3 
Wholesale Revenues:
Generation Revenues (b)— — 227.6 310.9 — 19.2 206.2 
Transmission Revenues (c)417.7 1,218.1 123.4 26.3 64.4 28.9 116.8 
Total Wholesale Revenues417.7 1,218.1 351.0 337.2 64.4 48.1 323.0 
Other Revenues from Contracts with Customers (d)24.4 (0.4)78.6 86.3 169.6 21.4 18.9 
Total Revenues from Contracts with Customers1,407.3 1,217.7 2,569.3 1,964.4 2,674.2 1,439.4 1,748.2 
Other Revenues:
Alternative Revenue Program (a) (e)(2.9)(34.4)0.1 7.3 (18.6)(0.7)0.7 
Other Revenues (a)— — 0.4 (0.1)18.6 — — 
Total Other Revenues(2.9)(34.4)0.5 7.2 — (0.7)0.7 
Total Revenues$1,404.4 $1,183.3 $2,569.8 $1,971.6 $2,674.2 $1,438.7 $1,748.9 

(a)Amounts include affiliated and nonaffiliated revenues.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $122 million primarily relating to the PPA with KGPCo.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $992 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $44 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.

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 March 31,September 30, 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.
CompanyCompany20232024-20252026-2027After 2027TotalCompany20232024-20252026-2027After 2027Total
(in millions)(in millions)
AEPAEP$63.4 $160.5 $137.1 $61.0 $422.0 AEP$22.6 $166.2 $141.2 $35.0 $365.0 
APCoAPCo12.1 32.2 24.3 11.7 80.3 APCo4.0 32.2 26.6 11.6 74.4 
I&MI&M3.4 9.2 9.2 4.6 26.4 I&M1.1 8.8 8.8 4.5 23.2 


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Contract Assets and Liabilities

Contract assets are recognized when the Registrants have a right to consideration that is conditional upon the occurrence of an event other than the passage of time, such as future performance under a contract. The Registrants did not have material contract assets as of March 31,September 30, 2023 and December 31, 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 sheets in the amount of that consideration. Revenue for such consideration is subsequently recognized in the period or periods in which the remaining performance obligations in the contract are satisfied. The Registrants’ contract liabilities typically arise from services provided under joint use agreements for utility poles. The Registrants did not have material contract liabilities as of March 31,September 30, 2023 and December 31, 2022.

Accounts Receivable from Contracts with Customers

Accounts receivable from contracts with customers are presented on the Registrant Subsidiaries’ balance sheets within the Accounts Receivable - Customers line item. The Registrant Subsidiaries’ balances for receivables from contracts that are not recognized in accordance with the accounting guidance for “Revenue from Contracts with Customers” included in Accounts Receivable - Customers were not material as of March 31,September 30, 2023 and December 31, 2022. See “Securitized Accounts Receivable - AEP Credit” section of Note 12 for additional information.

The following table represents the amount of affiliated accounts receivable from contracts with customers included in Accounts Receivable - Affiliated Companies on the Registrant Subsidiaries’ balance sheets:
CompanyCompanyMarch 31, 2023December 31, 2022CompanySeptember 30, 2023December 31, 2022
(in millions)(in millions)
AEP TexasAEP Texas$— $0.1 AEP Texas$0.1 $0.1 
AEPTCoAEPTCo122.5 113.8 AEPTCo122.5 113.8 
APCoAPCo65.1 64.5 APCo69.3 64.5 
I&MI&M56.4 75.3 I&M50.1 75.3 
OPCoOPCo57.5 49.9 OPCo67.3 49.9 
PSOPSO12.7 18.8 PSO13.8 18.8 
SWEPCoSWEPCo19.6 19.1 SWEPCo23.7 19.1 

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CONTROLS AND PROCEDURES

During the firstthird quarter of 2023, management, including the principal executive officer and principal financial officer of each of the Registrants, evaluated the Registrants’ disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. As of March 31,September 30, 2023, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives.

There was no change in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the firstthird quarter of 2023 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.
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PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings

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

Item 1A.  Risk Factors

The Annual Report on Form 10-K for the year ended December 31, 2022 includes a detailed discussion of risk factors. As of March 31,September 30, 2023, there have been no material changes to the risk factors previously disclosedappearing in the AEP’s 2022 Annual Report are supplemented and updated as follows:

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

In October 2022, AEP initiated a strategic evaluation for its ownership in AEP Energy. In April 2023, management completed the strategic evaluation of AEP Energy and initiated a sale process. In April 2023, AEP also made a decision to include AEP Onsite Partners in the sale process. 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 agreed to initiate a joint sales process for their respective interests in NMRD.

In July 2023, AEP made a decision to initiate a sales process for its investment in Pioneer Transmission, LLC and Prairie Wind Transmission, LLC.

Any planned sale of assets and investments, including subsidiaries, may not occur for any number of reasons beyond our control, including regulatory approval on Form 10-K.terms that are acceptable. Depending on the outcome of these potential sales, it could reduce future net income and impact financial condition.

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

None

Item 3.  Defaults Upon Senior Securities

None

Item 4.  Mine Safety Disclosures

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

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act. Exhibit 95 “Mine Safety Disclosure Exhibit” contains the notices of violation and proposed assessments received by DHLC under the Mine Act for the quarter ended March 31,September 30, 2023.

Item 5.  Other Information

None.During the three months ended September 30, 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).

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Item 6.  Exhibits

The documents designated with an (*) below have previously been filed on behalf of the Registrants shown and are incorporated herein by reference to the documents indicated and made a part hereof.
Exhibit Description Previously Filed as Exhibit to:
   
AEP‡ File No. 1-3525
4(a)Company Order and Officer’s Certificate between AEP and The Bank of New York Mellon Trust Company, N.A. as Trustee dated March 1, 2023 establishing terms of the 5.625% Senior Notes, Series Q, due 2033.
AEPTCo‡ File No. 333-217143
4Company Order and Officer’s Certificate between AEP Transmission Company 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.
I&M‡ File No. 1-3570
4Company Order and Officer’s Certificate between Indiana Michigan Power Company 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.
SWEPCo‡   File No. 1-3146
4Sixteenth Supplemental Indenture dated as of March 1, 2023 between Southwestern Electric Power Company and The Bank of New York Mellon Trust Company, N.A. as Trustee establishing terms of the 5.30% Senior Notes, Series P, due 2033.
The exhibits designated with an (X) in the table below are being filed on behalf of the Registrants.
ExhibitDescriptionAEPAEP
Texas
AEPTCoAPCoI&MOPCoPSOSWEPCo
4(b)10March 31, 2023 AmendmentSeverance, Release of All Claims and extension to $1,000,000,000 CreditNoncompetition Agreement dated March 31, 2021 amongbetween the Company Initial Lenders and Wells Fargo Bank National Association as Administrative Agent.Ann P. Kelly.
31(a)Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31(b)Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32(a)Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
32(b)Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
95Mine Safety Disclosures
101.INSXBRL Instance DocumentThe instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCHXBRL Taxonomy Extension SchemaXXXXXXXX
101.CALXBRL Taxonomy Extension Calculation LinkbaseXXXXXXXX
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ExhibitDescriptionAEPAEP
Texas
AEPTCoAPCoI&MOPCoPSOSWEPCo
101.DEFXBRL Taxonomy Extension Definition LinkbaseXXXXXXXX
101.LABXBRL Taxonomy Extension Label LinkbaseXXXXXXXX
101.PREXBRL Taxonomy Extension Presentation LinkbaseXXXXXXXX
104Cover Page Interactive Data FileFormatted as Inline XBRL and contained in Exhibit 101.
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SIGNATURE


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


AMERICAN ELECTRIC POWER COMPANY, INC.



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



AEP TEXAS INC.
AEP TRANSMISSION COMPANY, LLC
APPALACHIAN POWER COMPANY
INDIANA MICHIGAN POWER COMPANY
OHIO POWER COMPANY
PUBLIC SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN ELECTRIC POWER COMPANY



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



Date:  May 4,November 2, 2023
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