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

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended September 30, 2022
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 OKLAHOMA Oklahoma 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 filer xAccelerated 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
October 27, 2022
 
American Electric Power Company, Inc.513,863,678 
 ($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
September 30, 2022
   
  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. 
Term
Meaning
 
 
 
AEGCo
 
AEP Generating Company, an AEP electric utility subsidiary.
AEP
 
American Electric Power Company, Inc., an investor-owned electric public utility holding company which includes American Electric Power Company, Inc. (Parent) and majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit
 
AEP Credit, Inc., a consolidated VIE of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP Renewables
A division of AEP Energy Supply, LLC that develops and/or acquires large scale renewable projects that are backed with long-term contracts with creditworthy counter parties.
AEP System
 
American Electric Power System, an electric system, owned and operated by AEP subsidiaries.
AEP TexasAEP Texas Inc., an AEP electric utility subsidiary.
AEP Transmission Holdco
 
AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of AEP.
AEPEP
AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, hedging activities, asset management and commercial and industrial sales in deregulated markets.
AEPRO
AEP River Operations, LLC, a commercial barge operation sold in November 2015.
AEPSC
 
American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AEPTCo
AEP Transmission Company, LLC, a wholly-owned subsidiary of AEP Transmission Holdco, is an intermediate holding company that owns the State Transcos.
AEPTCo Parent
AEP Transmission Company, LLC, the holding company of the State Transcos within the AEPTCo consolidation.
AFUDC
Allowance for Equity Funds Used During Construction.
AGR
AEP Generation Resources Inc., a competitive AEP subsidiary in the Generation & Marketing segment.
AOCI
 
Accumulated Other Comprehensive Income.
APCo
 
Appalachian Power Company, an AEP electric utility subsidiary.
Appalachian Consumer Rate Relief Funding
Appalachian Consumer Rate Relief Funding LLC, a wholly-owned subsidiary of APCo and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to the under-recovered Expanded Net Energy Cost deferral balance.
APSC
Arkansas Public Service Commission.
ARO
Asset Retirement Obligations.
ATMAt-the-Market.
CAA
Clean Air Act.
CCRCoal Combustion Residual.
CLECOCentral Louisiana Electric Company, a nonaffiliated utility company.
CO2
 
Carbon dioxide and other greenhouse gases.
CO2e
Carbon dioxide equivalent.
Cook Plant
 
Donald C. Cook Nuclear Plant, a two-unit, 2,296 MW nuclear plant owned by I&M.
COVID-19
Coronavirus 2019, a highly infectious respiratory disease. In March 2020, the World Health Organization declared COVID-19 a worldwide pandemic.
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Term
Meaning
 
 
 
CSAPR
Cross-State Air Pollution Rule.
CWIP
 
Construction Work in Progress.
DCC Fuel
DCC Fuel XI, DCC Fuel XII, DCC Fuel XIII, DCC Fuel XIV, DCC Fuel XV, DCC Fuel XVI and DCC Fuel XVII, 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.
EIS
Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated VIE of AEP.
ELGEffluent Limitation Guidelines.
Energy Supply
AEP Energy Supply LLC, a nonregulated holding company for AEP’s competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP.
Equity Units
AEP’s Equity Units issued in August 2020 and March 2019.
ERCOT
 
Electric Reliability Council of Texas regional transmission organization.
ETT
Electric Transmission Texas, LLC, an equity interest joint venture between AEP Transmission Holdco and Berkshire Hathaway Energy Company formed to own and operate electric transmission facilities in ERCOT.
Excess ADIT
Excess accumulated deferred income taxes.
FACFuel Adjustment Clause.
FASB
 
Financial Accounting Standards Board.
Federal EPA
United States Environmental Protection Agency.
FERC
 
Federal Energy Regulatory Commission.
FGD
 
Flue Gas Desulfurization or scrubbers.
FIP
Federal Implementation Plan.
FTR
 
Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP
 
Accounting Principles Generally Accepted in the United States of America.
GHGGreenhouse gas.
I&M
 
Indiana Michigan Power Company, an AEP electric utility subsidiary.
IRA
On August 16, 2022 President Biden signed into law legislation commonly referred to as the “Inflation Reduction Act” (IRA).
IRS
 
Internal Revenue Service.
ITCInvestment Tax Credit.
IURC
Indiana Utility Regulatory Commission.
KGPCo
Kingsport Power Company, an AEP electric utility subsidiary.
KPCo
 
Kentucky Power Company, an AEP electric utility subsidiary.
KPSCKentucky Public Service Commission.
KTCoAEP Kentucky Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.
KWh
Kilowatt-hour.
LPSC
 
Louisiana Public Service Commission.
MATS
Mercury and Air Toxic Standards.
Maverick
Maverick, part of the North Central Wind Energy Facilities, consists of 287 MWs of wind generation in Oklahoma.
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Term
Meaning
 
 
 
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.
MPSC
Michigan Public Service Commission.
MTM
 
Mark-to-Market.
MW
 
Megawatt.
MWh
 
Megawatt-hour.
NAAQS
National Ambient Air Quality Standards.
Nonutility Money Pool
 
Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
NCWF
North Central Wind Energy Facilities, a joint PSO and SWEPCo project, which includes three Oklahoma wind facilities totaling approximately 1,484 MWs of wind generation.
NOLCNet Operating Loss Carryforwards.
NOx
Nitrogen oxide.
NSR
 
New Source Review.
OCC
 
Corporation Commission of the State of Oklahoma.
ODFAOklahoma Development Finance Authority.
OPCo
 
Ohio Power Company, an AEP electric utility subsidiary.
OPEB
 
Other Postretirement Benefits.
OTC
 
Over-the-counter.
OVEC
 
Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
Parent
American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.
PJM
 
Pennsylvania – New Jersey – Maryland regional transmission organization.
PM
 
Particulate Matter.
PPA
Purchase Power and Sale Agreement.
PSO
 
Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PTC
Production Tax Credit.
PUCO
 
Public Utilities Commission of Ohio.
PUCT
 
Public Utility Commission of Texas.
Registrant Subsidiaries
 
AEP subsidiaries which are SEC registrants: AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
Registrants
SEC registrants: AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
Restoration Funding
AEP Texas Restoration Funding LLC, a wholly-owned subsidiary of AEP Texas and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to storm restoration in Texas primarily caused by Hurricane Harvey.
Risk Management Contracts
 
Trading and non-trading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant
A generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana. AEGCo and I&M jointly-own Unit 1. In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2.
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Term
Meaning
 
 
 
ROE
Return on Equity.
RPM
Reliability Pricing Model.
RTO
 
Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine
 
Sabine Mining Company, a lignite mining company that is a consolidated VIE for AEP and SWEPCo.
SECU.S. Securities and Exchange Commission.
Sempra Renewables LLC
Sempra Renewables LLC, acquired in April 2019, consists of 724 MWs of wind generation and battery assets in the United States.
SIP
State Implementation Plan.
SNF
 
Spent Nuclear Fuel.
SO2
 
Sulfur dioxide.
SPP
 
Southwest Power Pool regional transmission organization.
State Transcos
AEPTCo’s seven wholly-owned, FERC regulated, transmission only electric utilities, which are geographically aligned with AEP’s existing utility operating companies.
Sundance
Sundance, acquired in April 2021 as part of the North Central Wind Energy Facilities, consists of 199 MWs of wind generation in Oklahoma.
SWEPCo
 
Southwestern Electric Power Company, an AEP electric utility subsidiary.
Tax Reform
On December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal Revenue Code of 1986, including a reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018.
Transition Funding
 
AEP Texas Central Transition Funding 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 Energy
Transource Energy, LLC, a consolidated VIE formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates.
Traverse
Traverse, part of the North Central Wind Energy Facilities, consists of 998 MWs of wind generation in Oklahoma.
Turk Plant
 
John W. Turk, Jr. Plant, a 650 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.
Utility Money Pool
 
Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
VIE
Variable Interest Entity.
Virginia SCC
 
Virginia State Corporation Commission.
WPCo
 
Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC
Public Service Commission of West Virginia.
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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 and employees’ reactions to those regulations, electricity usage, supply chain issues, customers, service providers, vendors and suppliers.
The economic impact of escalating global trade tensions including the conflict between Russia and Ukraine, and the adoption or expansion of economic sanctions or trade restrictions.
Inflationary or deflationary interest rate trends.
Volatility in the financial markets, particularly developments affecting the availability or cost of capital to finance new capital projects and refinance existing debt.
The availability and cost of funds to finance working capital and capital needs, particularly (i) if expected sources of capital, such as proceeds from the sale of assets or subsidiaries, do not materialize, and (ii) during periods when the time lag between incurring costs and recovery is long and the costs are material.
Decreased demand for electricity.
Weather conditions, including storms and drought conditions, and the ability to recover significant storm restoration costs.
The cost of fuel and its transportation, the creditworthiness and performance of fuel suppliers and transporters and the cost of storing and disposing of used fuel, including coal ash and SNF.
The availability of fuel and necessary generation capacity and the performance of generation plants.
The ability to recover fuel and other energy costs through regulated or competitive electric rates.
The ability to transition from fossil generation and the ability to build or acquire renewable generation, transmission lines and facilities (including the ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms, including favorable tax treatment, and to recover those costs.
New legislation, litigation and government regulation, including changes to tax laws and regulations, oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or PM and other substances that could impact the continued operation, cost recovery and/or profitability of generation plants and related assets.
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 spent nuclear fuel.
Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance.
Resolution of litigation.
The ability to constrain operation and maintenance costs.
Prices and demand for power generated and sold at wholesale.
Changes in technology, particularly with respect to energy storage and new, developing, alternative or distributed sources of generation.
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The ability to recover through rates any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives.
Volatility and changes in markets for coal and other energy-related commodities, particularly changes in the price of natural gas.
Changes in utility regulation and the allocation of costs within RTOs including ERCOT, PJM and SPP.
Changes in the creditworthiness of the counterparties with contractual arrangements, including participants in the energy trading market.
Actions of rating agencies, including changes in the ratings of debt.
The impact of volatility in the capital markets on the value of the investments held by the pension, OPEB, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements.
Accounting standards periodically issued by accounting standard-setting bodies.
Other risks and unforeseen events, including wars and military conflicts, the effects of terrorism (including increased security costs), embargoes, naturally occurring and human-caused fires, cyber-security threats and other catastrophic events.
The ability to attract and retain the requisite work force and key personnel.

The forward-looking statements of the Registrants speak only as of the date of this report or as of the date they are made.  The Registrants expressly disclaim any obligation to update any forward-looking information, except as required by law.  For a more detailed discussion of these factors, see “Risk Factors” in Part I of the 2021 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.
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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Customer Demand

AEP’s weather-normalized retail sales volumes for the third quarter of 2022 increased by 2.6% from the third quarter of 2021. Weather-normalized residential sales decreased by 0.8% in the third quarter of 2022 from the third quarter of 2021. AEP’s third quarter 2022 industrial sales volumes increased by 6.0% compared to the third quarter of 2021. The increase in industrial sales was spread across many industries. Weather-normalized commercial sales increased 3.4% in the third quarter of 2022 from the third quarter of 2021. The increase in commercial sales was spread across many sectors.

AEP’s weather-normalized retail sales volumes for the nine months ended September 30, 2022 increased by 3.1% compared to the nine months ended September 30, 2021. Weather-normalized residential sales increased by 0.3% for the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021. AEP’s industrial sales volumes for the nine months ended September 30, 2022 increased by 5.5% compared to the nine months ended September 30, 2021. The increase in industrial sales was spread across many industries. Weather-normalized commercial sales increased 3.8% for the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021. The increase in commercial 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. The United States economy has encountered a significant level of inflation that has contributed to increased uncertainty in the outlook of near-term economic activity, including whether inflation will continue and at what rate. A prolonged continuation or a further increase in the severity of supply chain and inflationary disruptions could result in additional increases in the cost of certain goods and services and further extend lead times which could reduce future net income and cash flows and impact financial condition.

Strategic Evaluation of AEP Energy

AEP has initiated a strategic evaluation for its ownership in AEP Energy, a wholly-owned retail energy supplier that supplies electricity and/or natural gas to residential, commercial and industrial customers. AEP Energy provides various energy solutions in Illinois, Pennsylvania, Delaware, Maryland, New Jersey, Ohio and Washington, D.C. AEP Energy had approximately 672,000 customer accounts as of September 30, 2022. Potential alternatives may include, but are not limited to, continued ownership or a sale of all or a part of AEP Energy. Management has not made a decision regarding the potential alternatives, but expects to complete the strategic evaluation in the first half of 2023.

Federal Tax Legislation

On August 16, 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
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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. With the exception of PTCs and ITCs, this legislation is prospective and has no material impact on the current period financial statements. As 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.

Regulatory Matters

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

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

In August 2022, the Virginia Supreme Court issued its opinion on submitted appeals of APCo’s 2017-2019 Virginia Triennial Review concluding that the Virginia SCC: a) erred in finding it was not reasonable for APCo to record all remaining costs associated with early retirement of certain coal-fired generating plants in the 2017-2019 earnings test period, b) did not err by ordering APCo to retroactively implement depreciation rates for the years 2018 and 2019 and c) did not err in finding that APCo’s affiliate costs from OVEC were reasonable. The Virginia Supreme Court then remanded the issue regarding the retired coal-fired plants back to the Virginia SCC for further proceedings.

In September 2022, and in response to the Virginia Supreme Court opinion and subsequent Virginia SCC order initiating a remand proceeding, APCo submitted to the Virginia SCC: (a) an updated 2017-2019 Virginia earnings calculation resulting in a proposed $37 million regulatory asset related to previously incurred costs that APCo is expecting to recover as a result of earning below its 2017-2019 authorized ROE band, (b) an updated requested annual base rate increase of $41 million effective October 2022 and (c) a requested rider to recover, over the period October 2022 through January 2024, approximately $72 million related to an APCo Virginia base rate increase for the period January 2021 through September 2022. APCo’s requested $41 million annual base rate increase includes approximately $12 million related to the recovery of APCo’s regulatory asset for previously incurred costs as a result of earning below its 2017-2019 authorized ROE band. APCo implemented interim base rate and rider rate increases effective October 2022, both of which are subject to refund and review by the Virginia SCC. An order from the Virginia SCC in the remand proceeding is expected in the fourth quarter of 2022.

In September 2022, APCo expensed the remaining $25 million closed coal plant regulatory asset that was previously ordered by the Virginia SCC and recorded a $37 million regulatory asset for previously incurred costs that APCo is expecting to recover as a result of earning below its 2017-2019 authorized ROE band. APCo’s October 2022 through January 2024 net income, cash flows and financial condition is expected to be positively impacted pending the Virginia SCC’s order on APCo’s requested base rate and rider rate increases.

2020-2022 Virginia Triennial Review - In March 2023, APCo will submit its required Virginia earnings test calculation for the 2020-2022 Triennial Review period. For Triennial Review periods in which a Virginia utility earns below its authorized ROE band, the utility may file to recover expenses incurred, up to the bottom of the authorized ROE band, related to major storms, the early retirement of fossil fuel generating
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assets and certain projects necessary to comply with state and federal environmental legislation. As of September 2022, APCo has deferred approximately $25 million related to previously incurred costs as a result of the current estimate that APCo will earn below the bottom of its authorized ROE band during the 2020-2022 Triennial Review period. If it is determined that APCo has earned above the bottom of its authorized ROE band for the 2020-2022 Triennial Review period it could reduce future net income and cash flows and impact financial conditions.

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

In March 2021, the Texas Supreme Court issued an opinion reversing the July 2018 judgment of the Texas Third Court of Appeals and agreeing with the PUCT’s judgment affirming the prudence of the Turk Plant. In addition, the Texas Supreme Court remanded the AFUDC dispute back to the Texas Third Court of Appeals. No parties filed a motion for rehearing with the Texas Supreme Court. In August 2021, the Texas Third Court of Appeals reversed the Texas District Court judgment affirming the PUCT’s order on AFUDC, concluding that the language of the PUCT’s original 2008 order intended to include AFUDC in the Texas jurisdictional capital cost cap, and remanded the case to the PUCT for future proceedings. SWEPCo disagrees with the Court of Appeals decision. SWEPCo and the PUCT submitted Petitions for Review with the Texas Supreme Court in November 2021. In October 2022, the Texas Supreme Court denied the Petitions for Review submitted by SWEPCo and the PUCT. SWEPCo plans to file a request for rehearing. If SWEPCo’s request for rehearing is denied, the case will be remanded to the PUCT for future proceedings.

Management does not believe a disallowance of capitalized Turk Plant costs or a revenue refund is probable as of September 30, 2022. However, if SWEPCo is ultimately unable to recover AFUDC in excess of the Texas jurisdictional capital cost cap it would be expected to result in a pretax net disallowance ranging from $80 million to $90 million. In addition, if AFUDC is ultimately determined to be included in the Texas jurisdictional capital cost cap, SWEPCo estimates it may be required to make customer refunds ranging from $0 to $180 million related to revenues collected from February 2013 through September 2022 and such determination may reduce SWEPCo’s future revenues by approximately $15 million on an annual basis.

In July 2019, Ohio House Bill 6 (HB 6), which offered incentives for power-generating facilities with zero or reduced carbon emissions, was signed into law by the Ohio Governor. HB 6 terminated energy efficiency programs as of December 31, 2020, including OPCo’s shared savings revenues of $26 million annually and phased out renewable mandates after 2026. HB 6 also provided for continued recovery of existing renewable energy contracts on a bypassable basis through 2032 and included a provision for continued recovery of OVEC costs through 2030 which is allocated to all electric distribution utility customers in Ohio on a non-bypassable basis. OPCo’s Inter-Company Power Agreement for OVEC terminates in June 2040. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of the Speaker of the Ohio House of Representatives, Larry Householder, four other individuals, and Generation Now, an entity registered as a 501(c)(4) social welfare organization, in connection with an alleged racketeering conspiracy involving the adoption of HB 6. Certain defendants in that case have since pleaded guilty. In 2021, four AEP shareholders filed derivative actions purporting to
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assert claims on behalf of AEP against certain AEP officers and directors. See Litigation Related to Ohio House Bill 6 section of Litigation below for additional information.

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

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

In July 2021, the FERC issued an order denying Dayton Power and Light’s request for a 50 basis point RTO incentive on the basis that its RTO participation was not voluntary, but rather is required by Ohio law. This precedent could have an adverse impact on AEP’s Ohio transmission owning subsidiaries. In its February 2022 order on rehearing, the FERC affirmed the decision in its July 2021 order. The case is currently pending appeal at the United States Court of Appeals for the Sixth Circuit. In May 2022, the United States Court of Appeals for the Sixth Circuit issued an order to hold the appeal in abeyance pending resolution of FERC proceedings on the Office of the Ohio Consumers’ Counsel’s February 2022 RTO Incentive Complaint.

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

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

FERC RTO Incentive Complaint - In February 2022, the Office of the Ohio Consumers’ Counsel 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 Ohio Consumers’ Counsel’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. Management believes its financial statements adequately address the impact of the February 2022 complaint. If the
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FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.

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

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

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

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

In March 2021, the APSC issued an order authorizing recovery of the Arkansas jurisdictional share of the retail customer fuel costs over five years, with the appropriate carrying charge to be determined at a later date. Subsequently, SWEPCo began recovery of these fuel costs. In April 2021, SWEPCo filed testimony supporting a five-year recovery with a carrying charge of 6.05%. In June 2022, the APSC ordered SWEPCo to recover the Arkansas jurisdictional share of the fuel costs over six years with a carrying charge equal to its weighted average cost of capital, subject to a prudency review and true-up.

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In March 2021, the LPSC approved a special order granting a temporary modification to the FAC and shortly after SWEPCo began recovery of its Louisiana jurisdictional share of these fuel costs based on a five-year recovery period inclusive of an interim carrying charge of 3.25%. SWEPCo will work with the LPSC to finalize the actual recovery period and determine the appropriate carrying charge in future proceedings.

In August 2021, SWEPCo filed an application with the PUCT to implement a net interim fuel surcharge for the Texas jurisdictional share of these retail fuel costs. The application requested a five-year recovery with a carrying charge of 7.18%. In March 2022, the PUCT ordered SWEPCo to recover the Texas jurisdictional share of the fuel costs over five years with a carrying charge of 1.65% and ordered SWEPCo to file a fuel reconciliation addressing fuel costs from January 1, 2020 through December 31, 2021.

As of September 30, 2022, SWEPCo had regulatory assets of $349 million relating to natural gas expenses and purchases of electricity incurred during the February 2021 severe winter weather event. SWEPCo’s deferred regulatory asset consists of $85 million, $126 million and $138 million related to the Arkansas, Louisiana and Texas jurisdictions, respectively.

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

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

AEP is also transitioning to stand-alone treatment of NOLC in retail jurisdiction base rate case filings. As a result of retail jurisdiction base rate cases in Arkansas, Indiana, Oklahoma and Texas, inclusion of NOLCs in rates in those jurisdictions is contingent upon a supportive private letter ruling from the IRS.

SPP Capacity Planning Reserve Margin - In July 2022, SPP approved a plan to increase its capacity planning reserve margin from 12% to 15% starting in the summer of 2023. Compliance filings are due to SPP in February 2023 and any deficiencies are required to be remedied by May 2023. SPP’s annual non-compliance charge as a result of not meeting capacity requirements could range from approximately $86 thousand per MW to approximately $171 thousand per MW. Non-compliance could also result in a failure to meet NERC criteria and violating SPP’s tariff before FERC. As of September 30, 2022, the increase in the capacity planning reserve margin for PSO and SWEPCo to comply with this new SPP requirement is approximately 265 MWs. Management is currently evaluating options and expects to comply with SPP’s 2023 capacity planning reserve margin requirements. If PSO or SWEPCo incur charges or are unable to recover, or experience delays in recovering, the costs of complying with SPP’s rule, it could reduce future net income and cash flows and impact financial condition.


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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 2022. See Note 4 - Rate Matters for additional information.


Completed Base Rate Case Proceedings

Approved RevenueApprovedNew Rates
CompanyJurisdictionRequirement IncreaseROEEffective
(in millions)
SWEPCoTexas$39.4 9.25%March 2021
I&MIndiana61.4 (a)9.7%February 2022
SWEPCoArkansas48.7 9.5%July 2022
KGPCoTennessee5.8 9.5%August 2022

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


Pending Base Rate Case Proceedings
Commission Staff/
FilingRequested RevenueRequestedIntervenor Range of
CompanyJurisdictionDateRequirement IncreaseROERecommended ROE
(in millions)
SWEPCoLouisianaDecember 2020$94.7 10.35%9.1%-9.8%


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Deferred Fuel Costs

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

Traditional FACAs ofAs of Increase/
CompanyJurisdictionRecovery ResetSeptember 30, 2022December 31, 2021(Decrease)
APCoVirginia (a)Annually$359.5 $128.6 $230.9 
APCoWest VirginiaAnnually235.2 72.7 162.5 
I&MIndianaBi-Annually19.2 — 19.2 
I&MMichiganAnnually6.2 6.4 (0.2)
PSOOklahoma (b)Annually419.9 194.6 225.3 
SWEPCoArkansasAnnually67.7 23.1 44.6 
SWEPCoLouisianaMonthly2.4 11.1 (8.7)
SWEPCoTexasTri-Annually165.9 47.0 118.9 
KPCoKentuckyMonthly24.4 8.2 16.2 
WPCoWest VirginiaAnnually195.2 101.6 93.6 
Total (c)$1,495.6 $593.3 $902.3 

(a)Includes $191 million of noncurrent deferred fuel classified as a Regulatory Asset on APCo’s balance sheets as of September 30, 2022.
(b)Includes $241 million of noncurrent deferred fuel classified as a Regulatory Asset on PSO’s balance sheets as of September 30, 2022.
(c)Includes $24 million and $8 million as of September 30, 2022 and December 31, 2021, respectively, of deferred fuel classified as Assets Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.

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

In April 2022, APCo and WPCo submitted their 2022 annual ENEC filing with the WVPSC requesting a $297 million annual increase in ENEC revenues, effective September 1, 2022. The WVPSC requested West Virginia staff perform a prudency review of APCo and WPCo’s actual and forecasted ENEC costs. Management expects to receive a WVPSC order on the 2022 ENEC filing in the fourth quarter of 2022 and a separate WVPSC order on the prudency review of the ENEC costs in the first quarter of 2023. See “2021 and 2022 ENEC Filings” section of Note 4 for additional information.

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

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

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

Dolet Hills Power Station and Related Fuel Operations

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

The remaining book value of Dolet Hills Power Station non-fuel related assets are recoverable by SWEPCo through a combination of base rates and rate riders. As of September 30, 2022, SWEPCo’s share of the net investment in the Dolet Hills Power Station was $113 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 September 30, 2022, SWEPCo had a net under-recovered fuel balance of $236 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 $30 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 $30 million deferral, with refunds to customers over five years. In September 2022, SWEPCO filed rebuttal testimony addressing the LPSC staff recommendations.

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

In August 2022, SWEPCo filed a fuel reconciliation with the PUCT covering the fuel period of January 1, 2020 through December 31, 2021.

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

Pirkey Plant and Related Fuel Operations

In 2020, management announced plans to retire the Pirkey Plant in 2023. The Pirkey Plant non-fuel costs are recoverable by SWEPCo through base rates and fuel costs are recovered through active fuel clauses and are subject to prudency determinations by the various commissions. As of September 30, 2022, SWEPCo’s share of the net investment in the Pirkey Plant was $216 million, including CWIP, before cost of removal. Sabine is a mining operator providing mining services to the Pirkey Plant. Under the provisions of the mining agreement, SWEPCo is required to pay, as part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. SWEPCo expects fuel deliveries, including billings of all fixed and operating costs, from Sabine to cease during the first quarter of 2023. Under the fuel agreements, SWEPCo’s fuel inventory and unbilled fuel costs from mining
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related activities were $49 million as of September 30, 2022. As of September 30, 2022, SWEPCo had a net under-recovered fuel balance of $236 million, inclusive of costs related to the Pirkey Plant billed by Sabine, but excluding impacts of the February 2021 severe winter weather event. Upon cessation of lignite deliveries by Sabine to the Pirkey Plant, additional operational, reclamation and other land-related costs incurred by Sabine will be billed to SWEPCo and included in existing fuel clauses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Renewable Generation

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

Contracted Renewable Generation Facilities

In recent years, AEP has developed its renewable portfolio within the Generation & Marketing segment. Other activities have included, but are not limited to, working directly with wholesale and large retail customers to provide tailored solutions based upon market knowledge, technology innovations and deal structuring which may include distributed solar, wind, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other forms of cost reducing energy technologies. The Generation & Marketing segment also developed and/or acquired large scale renewable generation projects that are backed with long-term contracts with creditworthy counterparties.

In February 2022, AEP management announced the initiation of a process to sell all or a portion of AEP Renewables’ competitive contracted renewables portfolio within the Generation & Marketing segment. Subsequently, AEP’s investment in Flat Ridge 2 Wind LLC was removed from the competitive contracted renewables sale portfolio. In June 2022, as a result of deteriorating financial performance, sale negotiations and AEP’s ongoing evaluation and ultimate decision to exit the investment in the near term, AEP recorded a pretax other than temporary impairment charge of $186 million in Equity Earnings (Losses) of Unconsolidated Subsidiaries in AEP’s Statement of Income. In the third quarter of 2022, AEP recorded an additional $2 million pretax other than temporary impairment charge. The carrying value of AEP’s investment in Flat Ridge 2 was not material to AEP as of September 30, 2022. In September 2022, AEP signed a Purchase and Sale Agreement with a nonaffiliate for AEP’s interest in Flat Ridge 2, subject to FERC approval. Management expects the transaction to close in the fourth quarter of 2022 and have an immaterial impact on the financial statements. See “Impairments” section of Note 6 for additional information.

As of September 30, 2022, excluding Flat Ridge 2, 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 five joint venture wind farms, totaling $246 million, accounted for as equity method investments. The anticipated disposition of all or a portion of the AEP Renewables’ portfolio has not met the accounting requirements to be presented as Held for Sale as of September 30, 2022. If AEP is unable to recover the book value or carrying value of these assets through a sales process, it could reduce future net income and impact financial condition.


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Regulated Renewable Generation Facilities

North Central Wind Facilities

In 2020, PSO and SWEPCo received regulatory approvals to acquire the NCWF, comprised of three Oklahoma wind facilities totaling 1,484 MWs, on a fixed cost turn-key basis at completion. PSO and SWEPCo own undivided interests of 45.5% and 54.5% of the NCWF, respectively. Output from the NCWF serves retail load in PSO’s Oklahoma service territory and both retail and FERC wholesale load in SWEPCo’s service territories in Arkansas and Louisiana. The Oklahoma and Louisiana portions of the NCWF revenue requirement, net of PTC benefit, are recoverable through authorized riders beginning at commercial operation and until such time as amounts are reflected in base rates. The Arkansas portion of the NCWF revenue requirement was approved for recovery through base rates in the 2021 Arkansas Base Rate Case. The table below provides a summary of the facilities as of September 30, 2022:
ProjectIn-Service DateNet Book ValueFederal PTC Qualification % (a)Generating Capacity
(in millions)(in MWs)
SundanceApril 2021$282.3 100 %199 
MaverickSeptember 2021398.3 80 %287 
TraverseMarch 20221,255.0 100 %(b)998 

(a)PTC benefits are available for a ten year period following the in-service date.
(b)The PTC for Traverse was increased to 100% in the third quarter of 2022 as a result of the IRA legislation.

See “North Central Wind Energy Facilities” section of Note 6 for additional information.

Recent Renewable Generation Filings

In December 2021 and January 2022, APCo filed petitions with the Virginia SCC and WVPSC, respectively, for prudency and cost recovery of: (a) an APCo-owned 204 MW wind generation facility, (b) three APCo-owned solar generation facilities totaling 205 MWs and (c) three solar purchased power agreements (PPAs) totaling 89 MWs. In June 2022, the WVPSC approved APCo’s January 2022 petition for cost recovery of an APCo-owned 50 MW solar generation facility which was included within the 205 MWs requested. In July 2022, the Virginia SCC approved APCo’s December 2021 petition for prudency and cost recovery as submitted. An order from the WVPSC is anticipated in the fourth quarter of 2022 related to the remaining items in APCo’s January 2022 petition. In September 2022, APCo received a notice of termination for a 19 MW Solar PPA due to the developer being unsuccessful in obtaining local permits. The 19 MW Solar PPA was included in the December 2021 and January 2022 petitions filed with the Virginia SCC and WVPSC, respectively. If the WVPSC does not approve one or more of the projects included in APCo’s January 2022 petition, the associated allocation of cost and production of the facilities will be assigned to Virginia retail customers. Under separate, existing APCo Virginia and West Virginia tariffs, APCo is also authorized for cost recovery of an additional 40 MWs of recently completed solar PPAs.

In May 2022, SWEPCo submitted filings before the APSC, LPSC and PUCT requesting approval to acquire three renewable energy projects totaling 999 MWs. In October 2022, SWEPCo also submitted the necessary filings with the FERC. The projects are comprised of two wind facilities, totaling 799 MWs, and one solar facility, totaling 200 MWs. One of the wind facilities, totaling approximately 201 MWs, is expected to reach commercial operation in December 2024 with the remaining facilities expected to reach commercial operation in December 2025.






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Significant Renewable Generation Requests for Proposal (RFP)

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

CompanyIssuance DateGeneration TypeOwned/
PPA
Generating Capacity
(in MWs)
APCoJanuary 2022WindOwned1,000 
APCoJanuary 2022Solar (a)Owned100 
APCoFebruary 2022SolarOwned150 
APCoJune 2022Solar/WindPPA100 
I&MMarch 2022WindOwned800 
I&MMarch 2022Solar (a)Owned500 
PSONovember 2021WindOwned2,800 
PSONovember 2021Solar (a)Owned1,350 
SWEPCoSeptember 2022WindOwned1,900 
SWEPCoSeptember 2022Solar (a)Owned500 
Total Significant RFP’s9,200 
(a)Includes an option for battery storage.

Disposition of KPCo and KTCo

In October 2021, AEP entered into a Stock Purchase Agreement (SPA) to sell KPCo and KTCo to Liberty Utilities Co., a subsidiary of Algonquin Power & Utilities Corp. (Liberty), for approximately a $2.85 billion enterprise value. In May 2022, the KPSC approved the transfer of KPCo to Liberty subject to certain conditions contingent upon the closing of the sale. AEP has received clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and the Committee on Foreign Investment in the United States. The sale remains subject to FERC approval under Section 203 of the Federal Power Act.

In September 2022, AEP, AEPTCo and Liberty entered into an amendment (Amendment) to the SPA which reduced the purchase price to approximately $2.646 billion and Liberty agreed to waive, upon FERC approval of the sale, the SPA condition precedent to closing requiring the issuance of regulatory orders approving a new proposed Mitchell Plant Operations and Maintenance Agreement and Mitchell Plant Ownership Agreement between KPCo and WPCo. The Amendment also provided that the closing shall not occur prior to January 4, 2023, unless mutually agreed to by AEP and Liberty.

Mitchell Plant Operations and Maintenance Agreement and Ownership Agreement

KPCo and WPCo each own a 50% undivided interest in the 1,560 MW coal-fired Mitchell Plant. As of September 30, 2022, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $576 million.

In November 2021, AEP made filings with the KPSC, WVPSC and FERC seeking approval of a new proposed Mitchell Plant Operations and Maintenance Agreement and Mitchell Plant Ownership Agreement. In February 2022, AEP filed a motion to withdraw its filing with the FERC. The KPSC and WVPSC issued orders addressing AEP’s filings in May 2022 and July 2022. Those orders proposed materially different modifications to the Mitchell Plant agreements filed by AEP such that the new agreements could not be executed by the parties. In lieu of new agreements, in July 2022, KPCo and WPCo confirmed with the KPSC and WVPSC, respectively, that they will continue operating under the existing Mitchell Agreement, utilizing the Mitchell Agreement Operating Committee’s authority under that agreement to issue appropriate resolutions so the parties can operate in accordance with each
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state commission’s directives related to CCR and ELG investment. In September 2022, pursuant to resolutions under the existing Mitchell Plant agreement, WPCo replaced KPCo as the Operator of Mitchell Plant.

Transfer of Ownership

FERC Proceedings

In December 2021, Liberty, KPCo and KTCo requested FERC approval of the sale under Section 203 of the Federal Power Act. In February 2022, several intervenors in the case filed protests related to whether the sale will negatively impact the wholesale transmission rates of applicants. In April 2022, the FERC issued a deficiency letter stating that the Section 203 application is deficient and that additional information is required to process it. In May 2022, Liberty, KPCo and KTCo supplemented the application and in June 2022, the FERC issued an order formally notifying AEP that it was exercising its ability to take up to an additional 180 days to act on the application. An order from the FERC is expected in the fourth quarter of 2022.

KPSC Proceedings

In May 2022, the KPSC approved the transfer of KPCo to Liberty subject to conditions contingent upon the closing of the sale, including establishment of regulatory liabilities to subsidize retail customer transmission and distribution expenses, a fuel adjustment clause bill credit, and a three-year Big Sandy decommissioning rider rate holiday during which KPCo’s carrying charge is reduced by 50%. As a result of the conditions imposed by KPSC, in the second quarter of 2022, AEP recorded a $69 million loss on the expected sale of the Kentucky Operations in accordance with accounting guidance for Fair Value Measurement.

Further, as a result of the Amendment and the change to the anticipated timing of the completion of the transaction, AEP recorded an additional $194 million pretax loss ($149 million net of tax) on the expected sale of the Kentucky Operations in the third quarter of 2022 in accordance with the accounting guidance for Fair Value Measurement. AEP recorded a $263 million pretax loss ($218 million net of tax) on the expected sale of the Kentucky Operations for the nine months ended September 30, 2022. AEP expects cash proceeds, net of taxes and transaction fees, from the sale of approximately $1.2 billion.

Subject to receipt of FERC authorization under Section 203 of the Federal Power Act, the sale is expected to close in January 2023 with Liberty acquiring the assets and assuming the liabilities of KPCo and KTCo, excluding pension and other post-retirement benefit plan assets and liabilities. AEP expects to provide customary transition services to Liberty for a period of time after closing of the transaction. AEP plans to use the proceeds from the sale to fund its continued investment in regulated businesses, including transmission and regulated renewables projects. If additional reductions in the fair value of the Kentucky Operations occur, it would reduce future net income and cash flows.
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LITIGATION

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

Rockport Plant Litigation

In 2013, the Wilmington Trust Company filed suit in the U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it would be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022.  The terms of the consent decree allow the installation of environmental emission control equipment, repowering, refueling or retirement of the unit.  The plaintiffs sought a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. See “Obligations under the New Source Review Litigation Consent Decree” section below for additional information.

After the litigation proceeded at the district court and appellate court, in April 2021, I&M and AEGCo reached an agreement to acquire 100% of the interests in Rockport Plant, Unit 2 for $116 million from certain financial institutions that own the unit through trusts established by Wilmington Trust, the nonaffiliated owner trustee of the ownership interests in the unit, with closing to occur as of the end of the Rockport Plant, Unit 2 lease in December 2022. The agreement is subject to customary closing conditions and as of the closing will result in a final settlement of, and release of claims in, the lease litigation. As a result, in May 2021, at the parties’ request, the district court entered a stipulation and order dismissing the case without prejudice to plaintiffs asserting their claims in a re-filed action or a new action. The required regulatory approvals at the IURC and FERC have been obtained that would allow the closing to occur as of the end of the lease in December 2022. Management believes its financial statements appropriately reflect the resolution of the litigation.

Upon the end of the Rockport Unit 2 lease in December 2022, AEGCo’s 50% ownership share of Rockport Unit 2 will be billed 100% to I&M under a FERC-approved unit power agreement. In addition, upon the end of the Rockport Unit 2 lease, I&M’s 50% ownership share of Rockport Unit 2 and I&M’s purchased power from AEGCo related to Rockport Unit 2 will be a merchant resource for I&M until Rockport Unit 2 is retired. A 2021 IURC order approved a settlement agreement addressing the future use of Rockport Unit 2 as a short-term capacity resource through the June 2023 - May 2024 PJM planning year. I&M has a similar proposal pending before the MPSC in I&M’s 2022 Michigan Integrated Resource Plan (IRP) filing. If I&M cannot recover its future investment and expenses related to the merchant share of Rockport Unit 2, it could reduce future net income and cash flows and impact financial condition.

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

Four participants in The American Electric Power System Retirement Plan (the Plan) filed a class action complaint in December 2021 in the U.S. District Court for the Southern District of Ohio against AEPSC and the Plan. When the Plan’s benefit formula was changed in the year 2000, AEP provided a special provision for employees hired before January 1, 2001, allowing them to continue benefit accruals under the then benefit formula for a full 10 years alongside of the new cash balance benefit formula then being implemented.  Employees who were hired on or after January 1, 2001 accrued benefits only under the new cash balance benefit formula.  The plaintiffs assert a number of claims on behalf of themselves and the purported class, including that: (a) the Plan violates the requirements under the Employee Retirement Income Security Act (ERISA) intended to preclude back-loading the accrual of benefits to the end of a participant’s career, (b) the Plan violates the age discrimination prohibitions of ERISA and the Age Discrimination in Employment Act and (c) AEP failed to provide required notice regarding the changes to the Plan. Among other relief, the Complaint seeks reformation of the Plan to provide additional benefits and the recovery of plan benefits for former employees under such reformed plan. The plaintiffs previously had submitted claims for
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additional plan benefits to AEP, which were denied. On February 15, 2022, AEPSC and the Plan filed a motion to dismiss the complaint for failure to state a claim. On August 16, 2022, the district court granted the motion to dismiss the complaint without prejudice. The plaintiffs have filed a motion for leave to file an amended complaint. AEP will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

Litigation Related to Ohio House Bill 6 (HB 6)

In 2019, Ohio adopted and implemented HB 6 which benefits OPCo by authorizing rate recovery for certain costs including renewable energy contracts and OVEC’s coal-fired generating units. OPCo engaged in lobbying efforts and provided testimony during the legislative process in connection with HB 6. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of an Ohio legislator and associates in connection with an alleged racketeering conspiracy involving the adoption of HB 6. After AEP learned of the criminal allegations against the Ohio legislator and others relating to HB 6, 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 United States District Court for the Southern District of Ohio against AEP and certain of its officers for alleged violations of securities laws. The amended complaint alleged misrepresentations or omissions by AEP regarding: (a) its alleged participation in or connection to public corruption with respect to the passage of HB 6 and (b) its regulatory, legislative, political contribution, 501(c)(4) organization contribution and lobbying activities in Ohio. The complaint sought monetary damages, among other forms of relief. In December 2021, the district court issued an opinion and order dismissing the securities litigation complaint with prejudice, determining that the complaint failed to plead any actionable misrepresentations or omissions. The plaintiffs did not appeal the ruling.

In January 2021, an AEP shareholder filed a derivative action in the United States District Court for the Southern District of Ohio purporting to assert claims on behalf of AEP against certain AEP officers and directors. In February 2021, a second AEP shareholder filed a similar derivative action in the Court of Common Pleas of Franklin County, Ohio. In April 2021, a third AEP shareholder filed a similar derivative action in the U.S. District Court for the Southern District of Ohio and a fourth AEP shareholder filed a similar derivative action in the Supreme Court for the State of New York, Nassau County. These derivative complaints allege the officers and directors made misrepresentations and omissions similar to those alleged in the putative securities class action lawsuit filed against AEP. The derivative complaints together assert claims for: (a) breach of fiduciary duty, (b) waste of corporate assets, (c) unjust enrichment, (d) breach of duty for insider trading and (e) contribution for violations of sections 10(b) and 21D of the Securities Exchange Act of 1934; and seek monetary damages and changes to AEP’s corporate governance and internal policies among other forms of relief. The 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 its motion to dismiss on April 29, 2022. On September 13, 2022, the New York state court granted the motion to dismiss with prejudice and plaintiffs have filed a notice of appeal with the New York appellate court. 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 on May 3, 2022 and briefing on the motion to dismiss has been completed. Discovery remains stayed pending the district court’s ruling on the motion to dismiss. The plaintiff in the Ohio state court case advised that they no longer agreed to stay the proceedings, therefore, AEP filed a motion to continue the stays of proceedings on May 20, 2022 and the plaintiff filed an amended complaint on June 2, 2022. On June 15, 2022, the Ohio state court entered an order continuing the stays of that case until the resolution of the consolidated derivative actions pending in Ohio federal district court. The defendants will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

In March 2021, AEP received a litigation demand letter from counsel representing a purported AEP shareholder. The litigation demand letter is directed to the Board of Directors of AEP and contains factual allegations involving HB 6 that are generally consistent with those in the derivative litigation filed in state and federal court. The letter demands, among other things, that the AEP Board undertake an independent investigation into alleged legal violations by directors and officers, and that, following such investigation, AEP commence a civil action for breaches of fiduciary duty and related claims and take appropriate disciplinary action against those individuals who
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allegedly harmed the company. The shareholder that sent the letter has since withdrawn the litigation demand, which is now terminated and of no further effect.

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

ENVIRONMENTAL ISSUES

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

AEP is engaged in litigation about environmental issues, was notified of potential responsibility for the clean-up of contaminated sites and incurred costs for disposal of SNF and future decommissioning of the nuclear units.  Management is engaged in the development of possible future requirements including the items discussed below.  Management believes that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.

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

Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed below will have a material impact on AEP System generating units.  Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of September 30, 2022, the AEP System owned generating capacity of approximately 25,300 MWs, of which approximately 11,300 MWs were coal-fired.  Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on fossil generation. Based upon management estimates, AEP’s future investment to meet these existing and proposed requirements ranges from approximately $300 million to $500 million through 2026.

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

Obligations under the New Source Review Litigation Consent Decree

In 2007, the U.S. District Court for the Southern District of Ohio approved a consent decree between AEP subsidiaries in the eastern area of the AEP System and the Department of Justice, the Federal EPA, eight northeastern states and other interested parties to settle claims that the AEP subsidiaries violated the NSR provisions of the CAA when they undertook various equipment repair and replacement projects over a period of nearly 20 years.  The consent decree’s terms include installation of environmental control equipment on certain generating units, a declining cap on SO2 and NOX emissions from the AEP System and various mitigation projects. The
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consent decree has been modified seven times, for various reasons, most recently in 2022. All of the environmental control equipment required by the consent decree has been installed.

Clean Air Act Requirements

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

National Ambient Air Quality Standards

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

Regional Haze

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

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

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

Cross-State Air Pollution Rule

CSAPR is a regional trading program designed to address interstate transport of emissions that contributed significantly to downwind non-attainment with the 1997 ozone and PM NAAQS.  CSAPR relies on SO2 and NOX allowances and individual state budgets to compel further emission reductions from electric utility generating units.  Interstate trading of allowances is allowed on a restricted sub-regional basis.


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In January 2021, the Federal EPA finalized a revised CSAPR rule, which substantially reduces the ozone season NOX budgets in 2021-2024. Several utilities and other entities potentially subject to the Federal EPA’s NOX regulations have challenged that final rule in the U.S. Court of Appeals for the District of Columbia Circuit and briefing is underway. Management cannot predict the outcome of that litigation, but believes it can meet the requirements of the rule in the near term, and is evaluating its compliance options for later years, when the budgets are further reduced. In addition, in February 2022, the EPA Administrator signed a proposed FIP for 2015 Ozone NAAQS that would further revise the ozone season NOX budgets under the existing CSAPR program. AEP is evaluating the proposed changes.

Climate Change, CO2 Regulation and Energy Policy

In 2019, the Affordable Clean Energy (ACE) rule established a framework for states to adopt standards of performance for utility boilers based on heat rate improvements for such boilers. However, in January 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the ACE rule and remanded it to the Federal EPA. In October 2021 the United States Supreme Court granted certiorari and combined four separate petitions seeking review of the D.C. Circuit Court decisions. Oral arguments were held in February 2022 and on June 30, 2022, the United States Supreme Court reversed the D.C. Circuit Court’s decision and remanded for further proceedings. The Federal EPA must take some action before anything is required of the utilities as a result of this decision. At a minimum, if the Federal EPA intends to implement the ACE rule, it must conduct additional rulemaking to update its applicable deadlines, which have all passed. Alternatively, the Federal EPA may abandon the ACE rule and proceed to regulate greenhouse gases through a new rule, the scope of which is unknown. The Federal EPA has previously announced it expects to propose a new rule by spring of 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. Management continues to actively monitor these rulemaking activities.

While no federal regulatory requirements to reduce CO2 emissions are in place, AEP has taken action to reduce and offset CO2 emissions from its generating fleet. AEP expects CO2 emissions from its operations to continue to decline due to the retirement of some of its coal-fired generation units, and actions taken to diversify the generation fleet and increase energy efficiency where there is regulatory support for such activities. The majority of the states where AEP has generating facilities passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements that can assist in reducing carbon emissions.  In April 2020, Virginia enacted clean energy legislation to allow the state to participate in the Regional Greenhouse Gas Initiative, require the retirement of all fossil-fueled generation by 2045 and require 100% renewable energy to be provided to Virginia customers by 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 October 2022, AEP announced new intermediate and long-term CO2 emission reduction goals, based on the output of the company’s integrated resource plans, which take into account economics, customer demand, grid reliability and resiliency, regulations and the company’s current business strategy. AEP adjusted its near-term carbon dioxide emission reduction target from a 2000 baseline to a 2005 baseline, upgraded its 80% reduction by 2030 target to include full Scope 1 emissions and accelerated its net-zero goal by five years to 2045. AEP’s total Scope 1 GHG emissions in 2021 were approximately 56 million metric tons CO2e, approximately a 63% reduction from AEP’s 2005 Scope 1 GHG emissions. AEP has made significant progress in reducing CO2 emissions from its power generation fleet and expects its emissions to continue to decline. Technological advances, including energy storage, will determine how quickly AEP can achieve zero emissions while continuing to provide reliable, affordable power for customers.

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

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

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

The first option provides an extension to cease receipt of CCR no later than October 15, 2023 for most units, and October 15, 2024 for a narrow subset of units; however, the Federal EPA’s grant of such an extension will be based upon a satisfactory demonstration of the need for additional time to develop alternative ash disposal capacity and will be limited to the soonest timeframe technically feasible to cease receipt of CCR. Additionally, each request must undergo formal review, including public comments, and be approved by the Federal EPA. AEP filed applications for additional time to develop alternative disposal capacity at the following plants:
CompanyPlant Name and UnitGenerating
Capacity
Net Book Value (a)Projected
 Retirement Date
(in MWs)(in millions)
AEGCoRockport Plant, Unit 1655$222.2 2028
APCoAmos Plant2,9302,123.6 2040
APCoMountaineer Plant1,320979.0 2040
I&MRockport Plant, Unit 1655462.9 (b)2028
KPCoMitchell Plant780575.6 2040
SWEPCoFlint Creek Plant258263.6 2038
WPCoMitchell Plant780603.6 2040

(a)Net book value before cost of removal including CWIP and inventory.
(b)Amount includes a $153 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 began responding to applications for extension requests and has proposed to deny several extension requests based on allegations that the utilities that received such responses are not in compliance with the CCR Rule. The Federal EPA’s allegations of noncompliance rely on new interpretations of the CCR Rule requirements. The actions of the Federal EPA have been challenged in the U.S. Court of Appeals for the District of Columbia Circuit as unlawful rulemaking that revises the existing CCR Rule requirements without proper notice and without opportunity for comment. Management is unable to predict the outcome of that litigation. On July 12, 2022, the Federal EPA proposed conditional approval of the pending extension request for the Mountaineer Plant. The Federal EPA has not yet proposed any action on the other pending extension requests submitted by AEP; however, statements made by the Federal EPA in proposed denials of extension requests submitted by other utilities indicate that there is a risk that the Federal EPA may similarly conclude that AEP is not eligible for an extension of time to cease use of those CCR impoundments and/or that one or more of AEP’s facilities is not in compliance with the CCR Rule. If that occurs, AEP may incur material additional costs to change its plans for complying with the CCR Rule, including the potential to have to temporarily cease operation of one or more facilities until an acceptable compliance alternative can be implemented. Such temporary cessation of operation could materially impact the cost of serving customers of the affected utility. Further, actions by the Federal EPA could require AEP to remove coal ash from CCR units that have already been closed in accordance with state law programs or could require AEP to incur costs related to CCR units at various active and legacy facilities.

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

The second option to obtain an extension of the April 11, 2021 deadline to cease operation of unlined impoundments allows a generating facility to continue operating its existing impoundments without developing alternative CCR disposal, provided the facility commits to cease combustion of coal by a date certain. Under this option, a generating facility would have until October 17, 2023 to cease coal-fired operations and to close CCR storage ponds 40 acres or less in size, or through October 17, 2028 for facilities with CCR storage ponds greater than 40 acres in size. Pursuant to this option, AEP informed the Federal EPA of its intent to retire the Pirkey Plant and cease using coal at the Welsh Plant:
CompanyPlant Name and UnitGenerating
Capacity
Net Investment (a)Accelerated Depreciation Regulatory AssetProjected
 Retirement Date
(in MWs)(in millions)
SWEPCoPirkey Plant580$65.0 $150.7 2023(b)
SWEPCoWelsh Plant, Units 1 and 31,053432.3 75.7 2028(c)(d)

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

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

Clean Water Act Regulations

The Federal EPA’s ELG rule for generating facilities establishes limits for FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater, which are to be implemented through each facility’s wastewater discharge permit. A revision to the ELG rule, published in October 2020, establishes additional options for reusing and discharging small volumes of bottom ash transport water, provides an exception for retiring units and extends the compliance deadline to a date as soon as possible beginning one year after the rule was published but no later than December 2025. Management has assessed technology additions and retrofits to comply with the rule and the impacts of the Federal EPA’s recent actions on facilities’ wastewater discharge permitting for FGD wastewater and bottom ash transport water. For affected facilities that must install additional technologies to meet the ELG rule limits, permit modifications were filed in January 2021 that reflect the outcome of that assessment. AEP continues to work with state agencies to finalize permit terms and conditions. Other facilities opted to file Notices of Planned Participation (NOPP), pursuant to which the facilities are not required to install additional controls to meet ELG limits provided they make commitments to cease coal combustion by a date certain. The Federal EPA has announced its intention to reconsider the 2020 rule and to further revise limits applicable to discharges of landfill and impoundment leachate. A proposed rule is expected in late 2022 or early 2023. Management cannot predict whether the Federal EPA will actually finalize further revisions or what such revisions might be, but will continue to monitor this issue and will participate in further rulemaking activities as they arise.

In August 2021, the Federal EPA and the Army Corps of Engineers announced their plan to reconsider and revise the Navigable Waters Protection Rule, which defines “waters of the United States” under the Clean Water Act. Shortly thereafter, the United States District Court for the District of Arizona vacated and remanded the Navigable Waters Protection Rule, which had the effect of reinstating the prior, much broader, version of the rule. Because the scope of waters subject to the Federal EPA and Army Corps of Engineers jurisdictions is broader under the prior rule, permitting decisions made in recent years are subject to reevaluation; permits may now be necessary where
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none were previously required, and issued permits may need to be reopened to impose additional obligations. In December 2021, the Federal EPA proposed a rule that would roll back the definition of “waters of the United States” to the pre-2015 definition. The Federal EPA also announced that it would be considering further changes through a future rulemaking, which would build upon the foundation of the proposed rule. Management will continue to monitor rulemaking on this issue.

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

CCR and ELG Compliance Plan Filings

Mitchell Plant (Applies to AEP)

KPCo and WPCo each own a 50% interest in the Mitchell Plant. As of September 30, 2022, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $576 million. In December 2020 and February 2021, WPCo and KPCo filed requests with the WVPSC and KPSC, respectively, to obtain the regulatory approvals necessary to implement CCR and ELG compliance plans and seek recovery of the estimated $132 million investment for the Mitchell Plant that would allow the plant to continue operating beyond 2028. Within those requests, WPCo and KPCo also filed a $25 million alternative to implement only the CCR-related investments with the WVPSC and KPSC, respectively, which would allow the Mitchell Plant to continue operating only through 2028.

In July 2021, the KPSC issued an order approving the CCR only alternative and rejecting the full CCR and ELG compliance plan. In May 2022, the KPSC approved recovery of the Kentucky jurisdictional share of ELG costs incurred at the Mitchell Plant prior to July 15, 2021.

In August 2021, the WVPSC approved the full CCR and ELG compliance plan for the WPCo share of the Mitchell Plant. In September 2021, WPCo submitted a filing with the WVPSC to reopen the CCR/ELG case that was approved by the WVPSC in August 2021. Due to the rejection by the KPSC of the KPCo share of the ELG investments, WPCo requested the WVPSC consider approving the construction and recovery of all ELG costs at the plant. In October 2021, the WVPSC affirmed its August 2021 order approving the construction of CCR/ELG investments and directed WPCo to proceed with CCR/ELG compliance plans that would allow the plant to continue operating beyond 2028. The WVPSC also ordered that WPCo will be given the opportunity to recover, from its customers, the ELG and new capital and operating costs arising solely from the WVPSC's directive to operate the plant beyond 2028 if the WVPSC finds that the costs are reasonably and prudently incurred. The WVPSC’s order further states that unless KPCo pays for its share of costs for ELG improvements and costs necessary to continue operations beyond 2028, the benefit of the capacity and energy made possible by those improvements and operating Mitchell Plant beyond 2028 should benefit only West Virginia jurisdictional customers who have shared in paying for those costs.

Amos and Mountaineer Plants (Applies to AEP and APCo)

In December 2020, APCo submitted filings with the Virginia SCC and WVPSC requesting regulatory approvals necessary to recover the estimated $240 million investment needed to implement CCR and ELG compliance for the Amos and Mountaineer plants. In August 2021, the Virginia SCC issued an order approving recovery of CCR-related operation and maintenance expenses and investments at the Amos and Mountaineer Plants through an active rider. The order also denied APCo’s request to recover the cost of ELG investments and denied recovery of previously incurred ELG costs, but did not preclude APCo from refiling for approval. In March 2022, APCo refiled for approval to recover the cost of the ELG investments and previously incurred ELG costs. Intervenor testimony was submitted in August 2022 recommending the denial of ELG cost recovery. In October 2022, a Virginia Hearing Examiner recommended that the Virginia SCC approve recovery of APCo’s requested ELG investment
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costs at Amos and Mountaineer Plants. Management expects to receive an order from the Virginia SCC in the fourth quarter of 2022.

Also in August 2021, the WVPSC approved the request to construct CCR/ELG investments at the Amos and Mountaineer Plants and approved recovery of the West Virginia jurisdictional share of these costs through an active rider. In October 2021, due to the Virginia SCC previously rejecting those ELG investments, the WVPSC issued an order directing APCo to proceed with CCR/ELG compliance plans that would allow the plants to continue operating beyond 2028. The WVPSC also ordered that APCo will be given the opportunity to recover, from West Virginia customers, the ELG and new capital and operating costs arising solely from the WVPSC's directive to operate the plants beyond 2028 if the WVPSC finds that the costs are reasonably and prudently incurred. The October 2021 order further states that unless the Virginia jurisdictional customers of APCo pay for their share of costs for ELG improvements and costs necessary to continue operations beyond 2028, the benefit of the capacity and energy made possible by those improvements and operating the Amos and Mountaineer Plants beyond 2028 should benefit only West Virginia and FERC jurisdictional customers who have shared in paying for those costs.

APCo expects the total Amos and Mountaineer Plant ELG investment, excluding AFUDC, to be approximately $162 million. As of September 30, 2022, APCo’s Virginia jurisdictional share of the net book value, before cost of removal including CWIP and inventory, of the Amos and Mountaineer Plants was approximately $1.5 billion and APCo’s Virginia jurisdictional share of its ELG investment balance in CWIP for these plants was $62 million.

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

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Impact of Environmental Regulation on Coal-Fired Generation

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

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

The table below summarizes the net book value, as of September 30, 2022, of generating facilities retired or planned for early retirement in advance of the retirement date currently authorized for ratemaking purposes:
CompanyPlantNet
Investment (a)
Accelerated Depreciation Regulatory AssetActual/Projected
Retirement
Date
Current Authorized
Recovery
Period
Annual Depreciation (b)
(in millions)(in millions)
PSONortheastern Plant, Unit 3$143.7 $141.4 2026(c)$14.9 
SWEPCoDolet Hills Power Station— 54.7 2021(d)— 
SWEPCoPirkey Plant65.0 150.7 2023(e)12.5 
SWEPCoWelsh Plant, Units 1 and 3432.3 75.7 2028(f)(g)39.8 
SWEPCoWelsh Plant, Unit 2— 35.2 2016(h)— 

(a)Net book value including CWIP excluding cost of removal and materials and supplies.
(b)These amounts represent the amount of annual depreciation that has been collected from customers over the prior 12-month period.
(c)Northeastern Plant, Unit 3 is currently being recovered through 2040.
(d)Dolet Hills Power Station is currently being recovered through 2026 in the Louisiana jurisdiction and through 2046 in the Texas jurisdiction. In December 2021, the PUCT authorized the recovery of SWEPCo’s Texas jurisdictional share of the Dolet Hills Power Station through 2046 without providing a return on the investment which resulted in a disallowance of $12 million. In May 2022, the APSC authorized the recovery of SWEPCo’s Arkansas jurisdictional share of the Dolet Hills Power Station through 2027 without providing a return on investment, which resulted in an immaterial disallowance in the second quarter of 2022. See Note 4 - Rate Matters for additional information.
(e)Pirkey Plant is currently being recovered through 2025 in the Louisiana jurisdiction and through 2045 in the Arkansas and Texas jurisdictions.
(f)In November 2020, management announced it will cease using coal at the Welsh Plant in 2028.
(g)Welsh Plant, Unit 1 is being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Welsh Plant, Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.
(h)Welsh Plant, Unit 2 is being recovered over the blended useful life of Welsh Plant, Units 1 and 3.

Management is seeking or will seek regulatory recovery, as necessary, for any net book value remaining when the plants are retired. To the extent the net book value of these generation assets 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 ROE.
Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved ROE.

Generation & Marketing

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

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

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

24



The following table presents Earnings (Loss) Attributable to AEP Common Shareholders by segment:
Three Months EndedNine Months Ended
September 30,September 30,
 2022202120222021
 (in millions)
Vertically Integrated Utilities$476.9 $437.7 $1,076.3 $936.3 
Transmission and Distribution Utilities165.5 155.9 483.1 424.0 
AEP Transmission Holdco170.5 166.8 485.4 507.5 
Generation & Marketing97.5 100.7 284.3 189.7 
Corporate and Other(226.7)(65.1)(406.2)(108.3)
Earnings Attributable to AEP Common Shareholders
$683.7 $796.0 $1,922.9 $1,949.2 

AEP CONSOLIDATED

Third Quarter of 2022 Compared to Third Quarter of 2021

Earnings Attributable to AEP Common Shareholders decreased from $796 million in 2021 to $684 million in 2022 primarily due to:

A loss on the expected sale of the Kentucky Operations.
An increase in depreciation expense due to continued investment.

This decrease was partially offset by:

Favorable rate proceedings in AEP’s various jurisdictions.

Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021

Earnings Attributable to AEP Common Shareholders decreased from $1,949 million in 2021 to $1,923 million in 2022 primarily due to:

A loss on the expected sale of the Kentucky Operations.
An impairment of AEP’s equity investment in Flat Ridge 2.
An increase in depreciation expense due to continued investment.

These decreases were partially offset by:

A gain on the sale of mineral rights.
Favorable rate proceedings in AEP’s various jurisdictions.
Increased sales volumes.
Favorable mark-to-market economic hedge activity driven by higher commodity prices.

AEP’s results of operations by operating segment are discussed below.
25



VERTICALLY INTEGRATED UTILITIES
Three Months EndedNine Months Ended
September 30,September 30,
 Vertically Integrated Utilities2022202120222021
 (in millions)
Revenues$3,226.3 $2,759.3 $8,562.2 $7,557.2 
Fuel and Purchased Electricity1,191.9 855.3 2,895.8 2,364.7 
Gross Margin2,034.4 1,904.0 5,666.4 5,192.5 
Other Operation and Maintenance834.0 796.9 2,383.1 2,240.6 
Asset Impairments and Other Related Charges24.9 — 24.9 — 
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset(37.0)— (37.0)— 
Depreciation and Amortization520.6 436.3 1,525.0 1,302.2 
Taxes Other Than Income Taxes130.1 124.1 383.9 375.6 
Operating Income561.8 546.7 1,386.5 1,274.1 
Other Income9.0 4.1 24.9 9.9 
Allowance for Equity Funds Used During Construction
6.0 9.6 20.4 30.3 
Non-Service Cost Components of Net Periodic Benefit Cost27.4 17.0 82.4 51.0 
Interest Expense(168.8)(144.3)(477.1)(425.5)
Income Before Income Tax Expense (Benefit) and Equity Earnings435.4 433.1 1,037.1 939.8 
Income Tax Expense (Benefit)(41.2)(4.6)(41.3)3.4 
Equity Earnings of Unconsolidated Subsidiary0.3 1.0 1.0 2.5 
Net Income476.9 438.7 1,079.4 938.9 
Net Income Attributable to Noncontrolling Interests— 1.0 3.1 2.6 
Earnings Attributable to AEP Common Shareholders$476.9 $437.7 $1,076.3 $936.3 

Summary of KWh Energy Sales for Vertically Integrated Utilities
Three Months EndedNine Months Ended
September 30,September 30,
2022202120222021
 (in millions of KWhs)
Retail:    
Residential9,115 9,119 25,379 25,125 
Commercial6,640 6,468 18,069 17,396 
Industrial8,862 8,485 25,930 24,798 
Miscellaneous623 604 1,745 1,672 
Total Retail25,240 24,676 71,123 68,991 
Wholesale (a)4,254 5,713 12,388 14,842 
Total KWhs29,494 30,389 83,511 83,833 

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



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 Vertically Integrated Utilities
Three Months EndedNine Months Ended
September 30,September 30,
2022202120222021
 (in degree days)
Eastern Region    
Actual Heating (a)
1,750 1,710 
Normal Heating (b)
1,748 1,742 
Actual Cooling (c)
783 847 1,178 1,209 
Normal Cooling (b)
745 744 1,082 1,087 
Western Region    
Actual Heating (a)
— — 930 993 
Normal Heating (b)
— 906 901 
Actual Cooling (c)
1,653 1,485 2,558 2,163 
Normal Cooling (b)
1,413 1,410 2,134 2,137 

(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.

27



Third Quarter of 2022 Compared to Third Quarter of 2021
Reconciliation of Third Quarter of 2021 to Third Quarter of 2022
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
 
Third Quarter of 2021$437.7 
  
Changes in Gross Margin: 
Retail Margins92.7 
Margins from Off-system Sales8.3 
Transmission Revenues21.9 
Other Revenues7.5 
Total Change in Gross Margin130.4 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(37.1)
Asset Impairments and Other Related Charges(24.9)
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset37.0 
Depreciation and Amortization(84.3)
Taxes Other Than Income Taxes(6.0)
Other Income4.9 
Allowance for Equity Funds Used During Construction(3.6)
Non-Service Cost Components of Net Periodic Pension Cost10.4 
Interest Expense(24.5)
Total Change in Expenses and Other(128.1)
  
Income Tax Benefit36.6 
Equity Earnings of Unconsolidated Subsidiary(0.7)
Net Income Attributable to Noncontrolling Interests1.0 
Third Quarter of 2022$476.9 

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 $93 million primarily due to the following:
A $47 million increase at PSO due to a $26 million increase in base rate revenues and a $21 million increase in rider revenues. These increases were partially offset in other expense items below.
A $40 million increase at SWEPCo primarily due to base rate revenue increases in Texas and Arkansas and an increase in rider revenues in all jurisdictions. These increases were partially offset in other expense items below.
A $22 million increase at APCo and WPCo due to an increase in rider revenues in Virginia and West Virginia. This increase was partially offset in other expense items below.
A $15 million increase at I&M primarily due to an increase in rider revenues. This increase was partially offset in other expense items below.
An $11 million increase in weather-related usage primarily in the residential class.
These increases were partially offset by:
A $47 million decrease at PSO and SWEPCo resulting from the NCWF PTC benefits provided to customers through fuel clause mechanisms. This decrease was partially offset in Income Tax Benefit below.
28



A $10 million decrease in weather-normalized retail margins primarily in the residential class.
Margins from Off-system Sales increased $8 million primarily due to the following:
A $7 million increase due to an increase in Turk Plant merchant sales at SWEPCo.
A $3 million increase at APCo primarily due to increased generation and strong market pricing.
Transmission Revenues increased $22 million primarily due to continued investment in transmission assets and increased load.
Other Revenues increased $8 million primarily due to an increase in pole attachment rental revenue.

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

Other Operation and Maintenance expenses increased $37 million primarily due to the following:
A $15 million increase in PJM transmission services. This increase was partially offset in Retail Margins above.
A $13 million increase in SPP transmission services. This increase was partially offset in Retail Margins above.
An $11 million increase due to the expensing of cancelled capital projects.
An $11 million increase in generation expenses primarily due to plant outages and maintenance at APCo and I&M.
A $6 million increase in storm restoration expenses.
A $5 million increase in distribution system improvements across multiple operating companies.
A $5 million increase in Energy Efficiency/Demand Response expenses. This increase was partially offset in Retail Margins above.
These increases were partially offset by:
A $36 million decrease due to the modification of the Rockport Plant, Unit 2 lease which resulted in a change in lease classification from an operating lease to a finance lease in December 2021 at AEGCo and I&M. This decrease is offset in Depreciation and Amortization expense below.
Asset Impairments and Other Related Charges increased $25 million at APCo due to the write-off of a regulatory asset in accordance with the August 2022 Virginia Supreme Court opinion related to the 2017-2019 Virginia Triennial review.
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset increased $37 million at APCo due to the establishment of a regulatory asset based on an August 2022 Virginia Supreme Court opinion and resulting under-earning during the 2017-2019 Triennial Review.
Depreciation and Amortization expenses increased $84 million primarily due to the following:
A $45 million increase due to a higher depreciable base primarily at APCo, I&M, PSO and SWEPCo and the implementation of new rates and the timing of refunds to customers under rate rider mechanisms at PSO and in Arkansas and Texas for SWEPCo. The increase due to implementation of new rates and the timing of refunds to customers under rate rider mechanisms at PSO was partially offset in Retail Margins above.
A $39 million increase due to the modification of the Rockport Plant, Unit 2 lease which resulted in a change in lease classification from an operating lease to a finance lease in December 2021 at AEGCo and I&M. This increase was partially offset in Other Operation and Maintenance expenses above.
Taxes Other Than Income Taxes increased $6 million due to the following:
A $9 million increase at PSO and SWEPCo primarily due to increased property taxes and a new infrastructure fee at PSO implemented by the City of Tulsa in March 2022. This increase was partially offset in Retail Margins above.
This increase was partially offset by:
A $5 million decrease at I&M primarily due to the repeal of the Indiana Utility Receipts Tax in July 2022. This decrease was partially offset in Retail Margins above.
Other Income increased $5 million at PSO primarily due to carrying charges on regulatory assets resulting from the February 2021 severe winter weather event.
Allowance for Equity Funds Used During Construction decreased $4 million primarily due to a decrease in AFUDC equity rates at APCo.
29



Non-Service Cost Components of Net Periodic Benefit Cost decreased $10 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.
Interest Expense increased $25 million primarily due to higher long-term debt balances at APCo, PSO and SWEPCo, increased Advances from Affiliates at SWEPCo and higher interest rates at APCo.
Income Tax Benefit increased $37 million primarily due to an increase in PTCs partially offset by a decrease in amortization of Excess ADIT. These items were partially offset in Retail Margins above.

30



Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021
Reconciliation of Nine Months Ended September 30, 2021 to Nine Months Ended September 30, 2022
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
 
Nine Months Ended September 30, 2021$936.3 
  
Changes in Gross Margin: 
Retail Margins404.6 
Margins from Off-system Sales(18.9)
Transmission Revenues66.8 
Other Revenues21.4 
Total Change in Gross Margin473.9 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(142.5)
Asset Impairments and Other Related Charges(24.9)
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset37.0 
Depreciation and Amortization(222.8)
Taxes Other Than Income Taxes(8.3)
Other Income15.0 
Allowance for Equity Funds Used During Construction(9.9)
Non-Service Cost Components of Net Periodic Pension Cost31.4 
Interest Expense(51.6)
Total Change in Expenses and Other(376.6)
  
Income Tax Expense44.7 
Equity Earnings of Unconsolidated Subsidiary(1.5)
Net Income Attributable to Noncontrolling Interests(0.5)
Nine Months Ended September 30, 2022$1,076.3 

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

Retail Margins increased $405 million primarily due to the following:
A $111 million increase at APCo and WPCo due to an increase in rider revenues in Virginia and West Virginia. This increase was partially offset in other expense items below.
A $95 million increase at PSO due to a $51 million increase in base rate revenues and a $44 million increase in rider revenues. These increases were partially offset in other expense items below.
An $80 million increase at SWEPCo primarily due to base rate revenue increases in Texas and Arkansas and an increase in rider revenues in all retail jurisdictions. These increases were partially offset in other expense items below.
A $43 million increase at I&M due to an increase in rider revenues offset by lower wholesale true-ups. This increase was partially offset in other expense items below.
A $41 million increase in weather-related usage primarily in the residential class.
A $35 million increase in weather-normalized retail margins primarily in the commercial class.
31



These increases were partially offset by:
A $62 million decrease at PSO and SWEPCo resulting from the NCWF PTC benefits provided to customers through fuel clause mechanisms. This decrease was partially offset in Income Tax Expense below.
Margins from Off-system Sales decreased $19 million primarily due to the following:
A $10 million decrease due to Turk Plant merchant sales as a result of the February 2021 severe winter weather event at SWEPCo.
A $7 million decrease at KPCo due to a change in the OSS sharing arrangement.
Transmission Revenues increased $67 million primarily due to the following:
A $47 million increase in continued investment in transmission assets and increased load.
A $20 million increase in formula rate true-up activity.
Other Revenues increased $21 million primarily due to the following:
A $7 million increase at APCo primarily due to business development revenue. This increase was partially offset in Other Operation and Maintenance expenses below.
A $6 million increase at I&M primarily due to a gain on sale of allowances and economic hedging activities. The gain on the sale of allowances was partially offset in Retail Margins above.
A $3 million increase at KPCo primarily due to rental revenue from pole attachments, a gain on the sale of allowances and business development revenue.

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

Other Operation and Maintenance expenses increased $143 million primarily due to the following:
A $96 million increase in PJM transmission services. This increase was partially offset in Retail Margins above.
A $62 million increase in generation expenses primarily due to outages and maintenance at APCo, I&M and PSO.
A $25 million increase in SPP transmission services. This increase was partially offset in Retail Margins above.
A $16 million increase in storm restoration expenses.
A $12 million increase in Energy Efficiency/Demand Response expenses. This increase was partially offset in Retail Margins above.
An $11 million increase in employee-related expenses.
An $11 million increase due to the expensing of cancelled capital projects.
These increases were partially offset by:
A $108 million decrease due to the modification of the Rockport Plant, Unit 2 lease which resulted in a change in lease classification from an operating lease to a finance lease in December 2021 at AEGCo and I&M. This decrease is offset in Depreciation and Amortization expense below.
Asset Impairments and Other Related Charges increased $25 million at APCo due to the write-off of a regulatory asset in accordance with the August 2022 Virginia Supreme Court opinion related to the 2017-2019 Virginia Triennial review.
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset increased $37 million at APCo due to the establishment of a regulatory asset based on an August 2022 Virginia Supreme Court opinion and resulting under-earning during the 2017-2019 Triennial Review.
Depreciation and Amortization expenses increased $223 million primarily due to the following:
A $117 million increase due to the modification of the Rockport Plant, Unit 2 lease which resulted in a change in lease classification from an operating lease to a finance lease in December 2021 at AEGCo and I&M. This increase was partially offset in Other Operation and Maintenance expenses above.
A $106 million increase due to a higher depreciable base primarily at APCo, I&M, PSO and SWEPCo, the implementation of new rates and the timing of refunds to customers under rate rider mechanisms at PSO and in Arkansas and Texas for SWEPCo. The increase due to implementation of new rates and the timing of refunds to customers under rate rider mechanisms at PSO was partially offset in Retail Margins above.
32



Taxes Other Than Income Taxes increased $8 million primarily due to the following:
A $13 million increase at PSO and SWEPCo primarily due to increased property taxes and a new infrastructure fee at PSO implemented by the City of Tulsa in March 2022. This increase was partially offset in Retail Margins above.
A $4 million increase at APCo primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
These increases were partially offset by:
An $8 million decrease at I&M primarily due to the repeal of the Indiana Utility Receipts Tax in July 2022. This decrease was partially offset in Retail Margins above.
Other Income increased $15 million primarily due to carrying charges on regulatory assets resulting from the February 2021 severe winter weather event at PSO and SWEPCo.
Allowance for Equity Funds Used During Construction decreased $10 million primarily due to a decrease in AFUDC equity rates primarily at APCo.
Non-Service Cost Components of Net Periodic Benefit Cost decreased $31 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.
Interest Expense increased $52 million primarily due to higher long-term debt balances at APCo, PSO and SWEPCo, increased Advances from Affiliates at SWEPCo, higher interest rates at APCo and a debt issuance at I&M in April 2021.
Income Tax Expense decreased $45 million primarily due to the following:
An $81 million increase in PTCs. This increase was partially offset in Retail Margins above.
A $7 million decrease in state taxes.
These decreases were partially offset by:
A $19 million increase due to an increase in pretax book income.
A $14 million decrease in amortization of Excess ADIT. The decrease in amortization of Excess ADIT was partially offset in Gross Margin above.
A $14 million decrease in Parent Company Loss Benefit.
33



TRANSMISSION AND DISTRIBUTION UTILITIES
Three Months EndedNine Months Ended
September 30,September 30,
Transmission and Distribution Utilities2022202120222021
 (in millions)
Revenues$1,530.2 $1,200.3 $4,078.6 $3,391.8 
Purchased Electricity399.5 188.1 884.8 561.6 
Gross Margin1,130.7 1,012.2 3,193.8 2,830.2 
Other Operation and Maintenance503.6 442.6 1,373.2 1,168.6 
Depreciation and Amortization188.3 164.6 559.5 515.8 
Taxes Other Than Income Taxes176.7 167.5 504.9 483.5 
Operating Income262.1 237.5 756.2 662.3 
Other Income
1.4 0.5 3.7 2.2 
Allowance for Equity Funds Used During Construction
9.3 11.3 23.6 24.3 
Non-Service Cost Components of Net Periodic Benefit Cost11.9 7.3 35.7 21.8 
Interest Expense(85.4)(77.3)(242.2)(228.8)
Income Before Income Tax Expense and Equity Earnings199.3 179.3 577.0 481.8 
Income Tax Expense33.8 23.4 94.7 57.8 
Equity Earnings of Unconsolidated Subsidiary— — 0.8 — 
Net Income165.5 155.9 483.1 424.0 
Net Income Attributable to Noncontrolling Interests— — — — 
Earnings Attributable to AEP Common Shareholders
$165.5 $155.9 $483.1 $424.0 

Summary of KWh Energy Sales for Transmission and Distribution Utilities
Three Months EndedNine Months Ended
September 30,September 30,
2022202120222021
 (in millions of KWhs)
Retail:    
Residential8,033 8,093 21,599 21,082 
Commercial7,538 7,125 20,478 19,189 
Industrial6,554 6,048 19,131 17,667 
Miscellaneous210 207 578 558 
Total Retail (a)22,335 21,473 61,786 58,496 
Wholesale (b)587 644 1,723 1,692 
Total KWhs22,922 22,117 63,509 60,188 

(a)Represents energy delivered to distribution customers.
(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold to PJM.
34



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
September 30,September 30,
2022202120222021
 (in degree days)
Eastern Region    
Actual Heating (a)
2,078 1,993 
Normal Heating (b)
2,077 2,071 
Actual Cooling (c)
755 787 1,115 1,148 
Normal Cooling (b)
688 689 989 996 
Western Region    
Actual Heating (a)
— — 278 319 
Normal Heating (b)
— — 193 188 
Actual Cooling (d)
1,478 1,308 2,701 2,278 
Normal Cooling (b)
1,382 1,379 2,433 2,436 

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

35



Third Quarter of 2022 Compared to Third Quarter of 2021
Reconciliation of Third Quarter of 2021 to Third Quarter of 2022
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
  
Third Quarter of 2021$155.9 
  
Changes in Gross Margin: 
Retail Margins74.9 
Margins from Off-system Sales21.8 
Transmission Revenues11.4 
Other Revenues10.4 
Total Change in Gross Margin118.5 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(61.0)
Depreciation and Amortization(23.7)
Taxes Other Than Income Taxes(9.2)
Other Income0.9 
Allowance for Equity Funds Used During Construction(2.0)
Non-Service Cost Components of Net Periodic Benefit Cost4.6 
Interest Expense(8.1)
Total Change in Expenses and Other(98.5)
  
Income Tax Expense(10.4)
  
Third Quarter of 2022$165.5 

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 $75 million primarily due to the following:
A $31 million increase due to interim rate increases driven by increased distribution and transmission investment in Texas.
A $21 million net increase in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset in Other Operation and Maintenance expenses below.
A $7 million increase in weather-related usage in Texas primarily due to a 13% increase in cooling degree days.
A $6 million increase in revenue from rate riders in Texas. This increase was partially offset in other expense items below.
A $4 million increase in weather-related usage in Ohio primarily due to the end of decoupling.
Margins from Off-system Sales increased $22 million primarily due to the following:
A $17 million increase in off-system sales at OVEC in Ohio due to higher market prices. This increase was offset in Retail Margins above and Other Revenues below.
A $5 million increase in deferrals of OVEC costs in Ohio. This increase was offset in Retail Margins above and Other Revenues below.
Transmission Revenues increased $11 million primarily due to interim rate increases driven by increased transmission investment in Texas.


36



Other Revenues increased $10 million primarily due to the following:
A $19 million increase in securitization revenues due to AEP Texas Central Transition Funding II LLC bonds that matured in July 2020 and final refunds that were completed in 2021. This increase was offset in Depreciation and Amortization expenses and Interest Expense below.
This increase was partially offset by:
A $13 million decrease due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs in Ohio. This decrease was offset in Retail Margins and Margins from Off-system Sales above.

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

Other Operation and Maintenance expenses increased $61 million primarily due to the following:
A $21 million increase in ERCOT transmission expenses. This increase was partially offset in Retail Margins and Transmission Revenues above.
A $14 million increase in transmission expenses in Ohio primarily due to an increase in recoverable PJM expenses. This increase was offset in Retail Margins above.
A $6 million increase in distribution-related expenses in Texas.
A $5 million increase in remitted Universal Service Fund surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset in Retail Margins above.
A $5 million increase in recoverable distribution expenses in Ohio primarily related to vegetation management. This increase was offset in Retail Margins above.
Depreciation and Amortization expenses increased $24 million primarily due to the following:
A $19 million increase in securitization amortizations primarily due to prior year AEP Texas Central Transition Funding II LLC bonds that matured in July 2020 and final refunds that were completed in 2021. This increase was offset in Other Revenues above.
A $6 million increase due to a higher depreciable base of transmission and distribution assets in Texas.
A $4 million increase in recoverable advanced metering system depreciable expenses in Texas.
These increases were partially offset by:
A $6 million decrease in recoverable Distribution Investment Rider depreciable expenses in Ohio. This decrease was offset in Retail Margins above.
Taxes Other Than Income Taxes increased $9 million primarily due to property taxes as a result of increased distribution and transmission investment and higher tax rates.
Non-Service Cost Components of Net Periodic Benefit Cost decreased $5 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.
Interest Expense increased $8 million primarily due to the following:
An $11 million increase in Texas primarily due to higher long-term debt balances and higher interest rates.
This increase was partially offset by:
A $3 million decrease in Ohio primarily due to the retirement of a higher rate bond, partially offset by the issuance of a lower rate bond in 2021.
Income Tax Expense increased $10 million primarily due to an increase in pretax book income and a decrease in amortization of Excess ADIT. The decrease in amortization of Excess ADIT was offset in Gross Margin above.
37



Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021
Reconciliation of Nine Months Ended September 30, 2021 to Nine Months Ended September 30, 2022
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
 
Nine Months Ended September 30, 2021$424.0 
  
Changes in Gross Margin: 
Retail Margins290.0 
Margins from Off-system Sales47.8 
Transmission Revenues50.0 
Other Revenues(24.2)
Total Change in Gross Margin363.6 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(204.6)
Depreciation and Amortization(43.7)
Taxes Other Than Income Taxes(21.4)
Other Income1.5 
Allowance for Equity Funds Used During Construction(0.7)
Non-Service Cost Components of Net Periodic Benefit Cost13.9 
Interest Expense(13.4)
Total Change in Expenses and Other(268.4)
  
Income Tax Expense(36.9)
Equity Earnings of Unconsolidated Subsidiary0.8 
  
Nine Months Ended September 30, 2022$483.1 

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 $290 million primarily due to the following:
An $85 million net increase in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset in Other Operation and Maintenance expenses below.
A $70 million increase due to interim rate increases driven by increased distribution and transmission investment in Texas.
A $31 million increase due to prior year refunds of Excess ADIT to customers in Texas. This increase was offset in Income Tax Expense below.
A $28 million increase in weather-normalized margins primarily from the commercial class.
A $25 million increase related to various rider revenues in Ohio. This increase was partially offset in Margins from Off-system Sales, Other Revenues and other expense items below.
A $20 million increase in revenue from rate riders in Texas. This increase was partially offset in other expense items below.
A $15 million increase in weather-related usage in Texas primarily due to a 19% increase in cooling degree days, partially offset by a 13% decrease in heating degree days.
An $8 million increase in weather-related usage in Ohio primarily due to the end of decoupling.
Margins from Off-system Sales increased $48 million primarily due to the following:
A $54 million increase in off-system sales at OVEC in Ohio due to higher market prices and volume. This increase was offset in Retail Margins above and Other Revenues below.

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This increase was partially offset by:
A $6 million decrease in deferrals of OVEC costs in Ohio. This decrease was offset in Retail Margins above and Other Revenues below.
Transmission Revenues increased $50 million primarily due to the following:
A $46 million increase due to interim rate increases driven by increased transmission investment in Texas.
A $7 million increase due to prior year refunds to customers associated with the most recent base rate case in Texas. This increase was offset in Other Revenues below.
A $7 million increase due to continued investment in transmission assets in Ohio.
These increases were partially offset by:
An $11 million decrease due to transmission formula rate true-up activity in Ohio.
Other Revenues decreased $24 million primarily due to the following:
A $29 million decrease primarily due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs in Ohio. This decrease was offset in Retail Margins and Margins from Off-system Sales above.
A $12 million decrease due to prior year refunds to customers associated with the most recent base rate case in Texas. This decrease was partially offset in Retail Margins and Transmission Revenues above.
A $5 million decrease in energy efficiency revenues in Texas.
These decreases were partially offset by:
A $20 million increase in securitization revenues due to AEP Texas Central Transition Funding II LLC bonds that matured in July 2020 and final refunds that were completed in 2021. This increase was offset in Depreciation and Amortization expenses and Interest Expense below.

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

Other Operation and Maintenance expenses increased $205 million primarily due to the following:
A $67 million increase in transmission expenses in Ohio primarily due to the following:
A $67 million increase in recoverable PJM expenses. This increase was offset in Retail Margins above.
A $6 million increase in transmission vegetation management expenses.
These increases were partially offset by:
A $10 million decrease in transmission formula rate true-up activity.
A $46 million increase in ERCOT transmission expenses. This increase was partially offset in Retail Margins and Transmission Revenues above.
A $20 million increase in employee-related expenses.
A $19 million increase in bad debt-related expenses, including $8 million in 2022 due to Bad Debt Rider over-recovery in Ohio. This increase was offset in Retail Margins above.
A $15 million increase in recoverable distribution expenses in Ohio primarily related to vegetation management. This increase was offset in Retail Margins above.
A $14 million increase in remitted Universal Services Fund surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset in Retail Margins above.
A $13 million increase in distribution-related expenses in Texas.
Depreciation and Amortization expenses increased $44 million primarily due to the following:
A $24 million increase due to a higher depreciable base and amortizations of transmission and distribution assets in Texas.
A $19 million increase in securitization amortizations primarily due to prior year AEP Texas Central Transition Funding II LLC bonds that matured in July 2020 and final refunds that were completed in 2021. This increase was offset in Other Revenues above.
An $11 million increase in recoverable advanced metering system depreciable expenses in Texas.
These increases were partially offset by:
A $6 million decrease in recoverable smart grid depreciable expenses in Ohio. This decrease was offset in Retail Margins above.
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A $6 million decrease in recoverable Distribution Investment Rider depreciable expenses in Ohio. This decrease was offset in Retail Margins above.
Taxes Other Than Income Taxes increased $21 million primarily due to increased property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
Non-Service Cost Components of Net Periodic Benefit Cost decreased $14 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.
Interest Expense increased $13 million primarily due to the following:
A $21 million increase in Texas primarily due to higher long-term debt balances and higher interest rates.
This increase was partially offset by:
A $7 million decrease in Ohio primarily due to the retirement of a higher rate bond, partially offset by the issuance of a lower rate bond in 2021.
Income Tax Expense increased $37 million primarily due to an increase in pretax book income and a decrease in amortization of Excess ADIT. The decrease in amortization of Excess ADIT is partially offset in Gross Margin above.
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AEP TRANSMISSION HOLDCO
Three Months EndedNine Months Ended
September 30,September 30,
AEP Transmission Holdco2022202120222021
 (in millions)
Transmission Revenues$430.9 $391.6 $1,221.1 $1,146.8 
Other Operation and Maintenance46.5 40.3 114.4 96.9 
Depreciation and Amortization89.5 78.1 262.7 225.5 
Taxes Other Than Income Taxes70.5 62.7 207.9 183.4 
Operating Income224.4 210.5 636.1 641.0 
Interest and Investment Income
0.7 0.3 1.1 0.7 
Allowance for Equity Funds Used During Construction
20.3 16.1 51.2 49.3 
Non-Service Cost Components of Net Periodic Benefit Cost1.3 0.5 3.8 1.6 
Interest Expense(44.4)(37.6)(124.2)(108.4)
Income Before Income Tax Expense and Equity Earnings202.3 189.8 568.0 584.2 
Income Tax Expense52.1 42.0 141.9 131.2 
Equity Earnings of Unconsolidated Subsidiary21.2 20.1 61.7 57.7 
Net Income171.4 167.9 487.8 510.7 
Net Income Attributable to Noncontrolling Interests0.9 1.1 2.4 3.2 
Earnings Attributable to AEP Common Shareholders$170.5 $166.8 $485.4 $507.5 

Summary of Investment in Transmission Assets for AEP Transmission Holdco
September 30,
20222021
(in millions)
Plant in Service$12,455.2 $11,256.0 
Construction Work in Progress1,752.7 1,609.6 
Accumulated Depreciation and Amortization986.3 758.1 
Total Transmission Property, Net$13,221.6 $12,107.5 
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Third Quarter of 2022 Compared to Third Quarter of 2021
 
Reconciliation of Third Quarter of 2021 to Third Quarter of 2022
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
Third Quarter of 2021$166.8 
Changes in Transmission Revenues:
Transmission Revenues39.3 
Total Change in Transmission Revenues39.3 
Changes in Expenses and Other:
Other Operation and Maintenance(6.2)
Depreciation and Amortization(11.4)
Taxes Other Than Income Taxes(7.8)
Interest and Investment Income0.4 
Allowance for Equity Funds Used During Construction4.2 
Non-Service Cost Components of Net Periodic Pension Cost0.8 
Interest Expense(6.8)
Total Change in Expenses and Other(26.8)
Income Tax Expense(10.1)
Equity Earnings of Unconsolidated Subsidiary1.1 
Net Income Attributable to Noncontrolling Interests0.2 
Third Quarter of 2022$170.5 

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

Transmission Revenues increased $39 million primarily due to continued investment in transmission assets.

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

Other Operation and Maintenance expenses increased $6 million primarily due to cancelled capital projects.
Depreciation and Amortization expenses increased $11 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $8 million primarily due to higher property taxes as a result of increased transmission investment.
Allowance for Equity Funds Used During Construction increased $4 million primarily due to higher CWIP.
Interest Expense increased $7 million primarily due to higher long-term debt balances.
Income Tax Expense increased $10 million primarily due to an increase in pretax book income and a decrease in parent company loss benefit.
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Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021
 
Reconciliation of Nine Months Ended September 30, 2021 to Nine Months Ended September 30, 2022
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
Nine Months Ended September 30, 2021$507.5 
Changes in Transmission Revenues:
Transmission Revenues74.3 
Total Change in Transmission Revenues74.3 
Changes in Expenses and Other:
Other Operation and Maintenance(17.5)
Depreciation and Amortization(37.2)
Taxes Other Than Income Taxes(24.5)
Interest and Investment Income0.4 
Allowance for Equity Funds Used During Construction1.9 
Non-Service Cost Components of Net Periodic Pension Cost2.2 
Interest Expense(15.8)
Total Change in Expenses and Other(90.5)
Income Tax Expense(10.7)
Equity Earnings of Unconsolidated Subsidiary4.0 
Net Income Attributable to Noncontrolling Interests0.8 
Nine Months Ended September 30, 2022$485.4 

The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and nonaffiliates, were as follows:
Transmission Revenues increased $74 million primarily due to the following:
A $117 million increase due to continued investment in transmission assets.
This increase was partially offset by:
A $30 million decrease due to the affiliated annual transmission formula rate true-up. This decrease was offset in Other Operation and Maintenance expense across the other Registrant Subsidiaries.
A $13 million decrease due to the nonaffiliated annual transmission formula rate true-up.
Expenses and Other, Income Tax Expense and Equity Earnings of Unconsolidated Subsidiary changed between years as follows:
Other Operation and Maintenance expenses increased $18 million primarily due to the following:
A $15 million increase in employee-related expenses.
A $5 million increase due to cancelled capital projects.
Depreciation and Amortization expenses increased $37 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $25 million primarily due to higher property taxes as a result of increased transmission investment.
Interest Expense increased $16 million primarily due to higher long-term debt balances.
Income Tax Expense increased $11 million primarily due to a decrease in parent company loss benefit, partially offset by a decrease in pretax book income.
Equity Earnings of Unconsolidated Subsidiary increased $4 million primarily due to higher pretax equity earnings for ETT, partially offset by lower pretax equity earnings for Pioneer.


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GENERATION & MARKETING
Three Months EndedNine Months Ended
September 30,September 30,
Generation & Marketing2022202120222021
 (in millions)
Revenues$735.4 $621.1 $2,014.3 $1,691.9 
Fuel, Purchased Electricity and Other566.1 444.7 1,534.0 1,368.7 
Gross Margin169.3 176.4 480.3 323.2 
Other Operation and Maintenance44.7 38.2 71.2 98.8 
Gain on Sale of Mineral Rights— — (116.3)— 
Depreciation and Amortization23.1 21.1 68.8 59.7 
Taxes Other Than Income Taxes3.1 2.6 9.3 8.1 
Operating Income98.4 114.5 447.3 156.6 
Interest and Investment Income12.5 1.3 21.4 2.4 
Non-Service Cost Components of Net Periodic Benefit Cost5.1 3.8 15.4 11.5 
Interest Expense(16.7)(4.0)(30.7)(11.1)
Income Before Income Tax Expense (Benefit) and Equity Loss99.3 115.6 453.4 159.4 
Income Tax Expense (Benefit)(5.1)8.3 (25.3)(31.0)
Equity Loss of Unconsolidated Subsidiaries(8.2)(7.8)(200.6)(6.2)
Net Income96.2 99.5 278.1 184.2 
Net Loss Attributable to Noncontrolling Interests(1.3)(1.2)(6.2)(5.5)
Earnings Attributable to AEP Common Shareholders
$97.5 $100.7 $284.3 $189.7 

Summary of MWhs Generated for Generation & Marketing
Three Months EndedNine Months Ended
September 30,September 30,
2022202120222021
 (in millions of MWhs)
Fuel Type:    
Coal
Renewables
Total MWhs
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Third Quarter of 2022 Compared to Third Quarter of 2021
Reconciliation of Third Quarter of 2021 to Third Quarter of 2022
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
  
Third Quarter of 2021$100.7 
  
Changes in Gross Margin: 
Merchant Generation 4.5 
Renewable Generation 19.2 
Retail, Trading and Marketing(30.8)
Total Change in Gross Margin(7.1)
  
Changes in Expenses and Other: 
Other Operation and Maintenance(6.5)
Depreciation and Amortization(2.0)
Taxes Other Than Income Taxes(0.5)
Interest and Investment Income11.2 
Non-Service Cost Components of Net Periodic Benefit Cost1.3 
Interest Expense(12.7)
Total Change in Expenses and Other(9.2)
  
Income Tax Expense13.4 
Equity Earnings (Loss) of Unconsolidated Subsidiaries(0.4)
Net Income Attributable to Noncontrolling Interests0.1 
  
Third Quarter of 2022$97.5 

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

Merchant Generation increased $5 million primarily due to higher market prices.
Renewable Generation increased $19 million primarily due to higher market prices at Texas wind facilities and new solar projects placed in service.
Retail, Trading and Marketing decreased $31 million due to lower gains from mark-to-market economic hedging activity.

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

Other Operation and Maintenance expenses increased $7 million primarily due to the installment sale of Amazon substations in 2021.
Interest and Investment Income increased $11 million primarily due to an increase in advances to affiliates.
Interest Expense increased $13 million due to higher interest rates in 2022.
Income Tax Expense decreased $13 million primarily due to a decrease in pretax book income, an increase in PTCs and a decrease in state income taxes.

45



Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021
Reconciliation of Nine Months Ended September 30, 2021 to Nine Months Ended September 30, 2022
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
  
Nine Months Ended September 30, 2021$189.7 
  
Changes in Gross Margin: 
Merchant Generation(6.1)
Renewable Generation35.2 
Retail, Trading and Marketing128.0 
Total Change in Gross Margin157.1 
  
Changes in Expenses and Other: 
Other Operation and Maintenance27.6 
Gain on Sale of Mineral Rights116.3 
Depreciation and Amortization(9.1)
Taxes Other Than Income Taxes(1.2)
Interest and Investment Income19.0 
Non-Service Cost Components of Net Periodic Benefit Cost3.9 
Interest Expense(19.6)
Total Change in Expenses and Other136.9 
  
Income Tax Benefit(5.7)
Equity Earnings (Loss) of Unconsolidated Subsidiaries(194.4)
Net Loss Attributable to Noncontrolling Interests0.7 
  
Nine Months Ended September 30, 2022$284.3 

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

Merchant Generation decreased $6 million primarily due to additional Cardinal plant outage days in 2022 and the sale of Racine, partially offset by higher market prices.
Renewable Generation increased $35 million primarily due to higher market prices at Texas wind facilities and new solar projects placed in service.
Retail, Trading and Marketing increased $128 million due to higher mark-to-market economic hedge activity driven by higher 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 decreased $28 million primarily due to higher land sales and the sale of renewable development projects.
Gain on Sale of Mineral Rights increased $116 million due to the current year sale of mineral rights.
Depreciation and Amortization expenses increased $9 million due to a higher depreciable base from increased investments in renewable energy assets.
Interest and Investment Income increased $19 million primarily due to an increase in advances to affiliates.
Non-Service Cost Components of Net Periodic Benefit Cost decreased $4 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.
Interest Expense increased $20 million due to higher interest rates in 2022.
46



Income Tax Benefit decreased $6 million primarily due to an increase in pretax book income partially offset by an increase in PTCs and a favorable discrete tax adjustment in 2022.
Equity Earnings (Loss) of Unconsolidated Subsidiaries decreased $194 million primarily due to the impairment of AEP’s investment in Flat Ridge 2 Wind LLC.
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CORPORATE AND OTHER

Third Quarter of 2022 Compared to Third Quarter of 2021

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $65 million in 2021 to a loss of $227 million in 2022 primarily due to:

A $195 million pretax loss related to the anticipated sale of Kentucky operations.
A $35 million increase in interest expense due to higher interest rates on short-term debt, an increase in advances from affiliates and an increase in long-term debt outstanding.

These items were partially offset by:

A $28 million increase due to favorable changes in gains and losses from AEP’s investment in ChargePoint. As of August 2022, AEP no longer has a direct investment in ChargePoint.
A $56 million decrease in Income Tax Expense primarily due to the following:
A $45 million decrease due to a loss on the anticipated sale of Kentucky operations.
A $15 million decrease due to a change in Parent Company Loss Benefit.

Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $108 million in 2021 to a loss of $406 million in 2022 primarily due to:

A $263 million pretax loss related to the anticipated sale of Kentucky operations.
A $54 million increase in interest expense due to higher long-term debt outstanding and higher interest rates on short-term debt.
A $45 million decrease at EIS, primarily due to lower returns on investments and an increase in reserves.
A $24 million decrease in equity earnings.
A $22 million decrease due to unfavorable changes in gains and losses from AEP’s investment in ChargePoint. As of August 2022, AEP no longer has a direct investment in ChargePoint.

These items were partially offset by:

A $103 million decrease in Income Tax Expense primarily due to the following:
A $45 million decrease due to a loss on the anticipated sale of Kentucky operations.
A $29 million decrease due to a change in pretax book income.
A $33 million decrease due to Parent Company Loss Benefit.

AEP SYSTEM INCOME TAXES

Third Quarter of 2022 Compared to Third Quarter of 2021

Income Tax Expense decreased $86 million primarily due to an increase in benefit from PTCs and a decrease in pretax book income.

Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021

Income Tax Expense decreased $95 million primarily due to:
A $73 million decrease due to an increase in PTCs.
A $25 million decrease due to a decrease in pretax book income.
A $26 million decrease due to discrete adjustments, primarily driven by the remeasurement of state deferred taxes as a result of newly enacted West Virginia and Oklahoma state legislation in 2021.
These decreases were partially offset by:
A $33 million increase due to a decrease in amortization of Excess ADIT.
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FINANCIAL CONDITION

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

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization
 September 30, 2022December 31, 2021
 (dollars in millions)
Long-term Debt, including amounts due within one year (a)$35,050.1 56.3 %$33,454.5 57.0 %
Short-term Debt2,702.3 4.3 2,614.0 4.4 
Total Debt37,752.4 60.6 36,068.5 61.4 
AEP Common Equity24,278.2 39.0 22,433.2 38.2 
Noncontrolling Interests234.1 0.4 247.0 0.4 
Total Debt and Equity Capitalization$62,264.7 100.0 %$58,748.7 100.0 %
(a)Amount excludes $1.2 billion and $1.1 billion as of September 30, 2022 and December 31, 2021, respectively, of Long-term Debt classified as Liabilities Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.

AEP’s ratio of debt-to-total capital decreased from 61.4% as of December 31, 2021 to 60.6% as of September 30, 2022 primarily due to the settlement of the forward equity purchase contracts related to the 2019 Equity Units, partially offset by an increase in debt to support distribution, transmission and renewable investment growth. See “Equity Units” section of Note 12 for additional information.

Liquidity

Liquidity, or access to cash, is an important factor in determining AEP’s financial stability.  Management believes AEP has adequate liquidity.  As of September 30, 2022, AEP had $5 billion of revolving credit facilities to support its commercial paper program.  Additional liquidity is available from cash from operations and a receivables securitization agreement.  Management is committed to maintaining adequate liquidity.  AEP generally uses short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged.  Sources of long-term funding include issuance of long-term debt, leasing agreements, hybrid securities or common stock. AEP and its utilities finance its operations with commercial paper and other variable rate instruments that are subject to fluctuations in interest rates. To the extent that the Federal Reserve continues to raise short-term interest rates, it could reduce future net income and cash flows and impact financial condition. In February 2021, severe winter weather impacted certain AEP service territories resulting in disruptions to SPP market conditions. See Note 4 - Rate Matters for additional information. In March 2021, AEP entered into a $500 million 364-day Term Loan and borrowed the full amount to help address the cash flow implications resulting from the February 2021 severe winter weather event. In March 2022, AEP extended the maturity date of the original 364-Day Term Loan to August 2022. In August 2022, AEP paid off the $500 million Term Loan. In 2022, increased fuel and purchased power prices continue to lead to an increase in under collection of fuel costs. As a result, in July 2022, APCo and KPCo entered into term loans of $100 million and $75 million, respectively, to help address the cash flow implications of the increased fuel and purchased power costs. See “Deferred Fuel Costs” section of Executive Overview for additional information on how the registrants are addressing the increase in deferred fuel regulatory assets. In September 2022, the ODFA issued ratepayer-backed securitization bonds for the purpose of reimbursing PSO for $687 million of extraordinary fuel costs and purchases of electricity incurred during the February 2021 severe winter weather event. See Note 4 - Rate Matters for additional information.


49



Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments.  As of September 30, 2022, available liquidity was approximately $3.6 billion as illustrated in the table below:
AmountMaturity
Commercial Paper Backup:(in millions)
Revolving Credit Facility$4,000.0 March 2027(a)
Revolving Credit Facility1,000.0 March 2024(a)
Cash and Cash Equivalents522.2  
Total Liquidity Sources5,522.2  
Less:AEP Commercial Paper Outstanding1,952.3  
Net Available Liquidity$3,569.9  
(a)In April 2022, AEP extended the maturity dates of the Revolving Credit Facilities from March 2026 to March 2027 and from March 2023 to March 2024, respectively.
AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries.  The program funds a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and the short-term debt requirements of subsidiaries that are not participating in either money pool for regulatory or operational reasons, as direct borrowers.  The maximum amount of commercial paper outstanding during the first nine months of 2022 was $2.4 billion.  The weighted-average interest rate for AEP’s commercial paper during 2022 was 1.82%.

Other Credit Facilities

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under five uncommitted facilities totaling $400 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of September 30, 2022 was $310 million with maturities ranging from October 2022 to August 2023.

Securitized Accounts Receivables

AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and was amended in September 2021 to include a $125 million and a $625 million facility. The $125 million facility was renewed in September 2022 and amended to extend the expiration date to September 2024. The $625 million facility also expires in September 2024. As of September 30, 2022, the affiliated utility subsidiaries are in compliance with all requirements under the agreement.

Debt Covenants and Borrowing Limitations

AEP’s credit agreements contain certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5%.  The method for calculating outstanding debt and capitalization is contractually-defined in AEP’s credit agreements.  Debt as defined in the revolving credit agreement excludes securitization bonds and debt of AEP Credit. As of September 30, 2022, this contractually-defined percentage was 57.7%. Non-performance under these covenants could result in an event of default under these credit agreements.  In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of AEP’s major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements.  This condition also applies in a majority of AEP’s non-exchange-traded commodity contracts and would similarly allow lenders and counterparties to declare the outstanding amounts payable.  However, a default under AEP’s non-exchange-traded commodity contracts would not cause an event of default under its credit agreements.

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

50



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

ATM Program

AEP participates in an ATM offering program that allows AEP to issue, from time to time, up to an aggregate of $1 billion of its common stock, including shares of common stock that may be sold pursuant to an equity forward sales agreement. There were no issuances under the ATM program for the nine months ended September 30, 2022. As of September 30, 2022, 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 settles after three years in 2023. The proceeds were used to support AEP’s overall capital expenditure plans.

In March 2019, AEP issued 16.1 million Equity Units initially in the form of corporate units, at a stated amount of $50 per unit, for a total stated amount of $805 million. Net proceeds from the issuance were approximately $785 million. Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 3.40% Junior Subordinated Notes due in 2024 and a forward equity purchase contract which settled after three years in 2022. The proceeds from this issuance were used to support AEP’s overall capital expenditure plans including the acquisition of Sempra Renewables LLC. In January 2022, AEP successfully remarketed the notes on behalf of holders of the corporate units and did not directly receive any proceeds therefrom. Instead, the holders of the corporate units used the debt remarketing proceeds to settle the forward equity purchase contract with AEP. The interest rate on the notes was reset to 2.031% with the maturity remaining in 2024. In March 2022, AEP issued 8,970,920 shares of AEP common stock and received proceeds totaling $805 million under the settlement of the forward equity purchase contract. AEP common stock held in treasury was used to settle the forward equity purchase contract.

See Note 12 - Financing Activities for additional information.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.83 per share in October 2022. 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.

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CASH FLOW

AEP relies primarily on cash flows from operations, debt issuances and its existing cash and cash equivalents to fund its liquidity and investing activities. AEP’s investing and capital requirements are primarily capital expenditures, repaying of long-term debt and paying dividends to shareholders. AEP uses short-term debt, including commercial paper, as a bridge to long-term debt financing. The levels of borrowing may vary significantly due to the timing of long-term debt financings and the impact of fluctuations in cash flows.
Nine Months Ended 
September 30,
 20222021
 (in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period$451.4 $438.3 
Net Cash Flows from Operating Activities4,733.2 2,973.0 
Net Cash Flows Used for Investing Activities(5,822.5)(4,906.2)
Net Cash Flows from Financing Activities1,215.2 2,921.6 
Net Increase in Cash and Cash Equivalents125.9 988.4 
Cash, Cash Equivalents and Restricted Cash at End of Period$577.3 $1,426.7 

Operating Activities
Nine Months Ended 
September 30,
20222021
(in millions)
Net Income$1,922.2 $1,949.5 
Non-Cash Adjustments to Net Income (a)2,661.1 2,191.1 
Mark-to-Market of Risk Management Contracts162.3 101.0 
Property Taxes459.9 415.1 
Deferred Fuel Over/Under-Recovery, Net(148.7)(1,356.8)
Change in Other Noncurrent Assets(6.0)(108.0)
Change in Other Noncurrent Liabilities324.0 162.7 
Change in Certain Components of Working Capital(641.6)(381.6)
Net Cash Flows from Operating Activities$4,733.2 $2,973.0 

(a)Non-Cash Adjustments to Net Income includes Depreciation and Amortization, Deferred Income Taxes, Loss on the Expected Sale of the Kentucky Operations, Asset Impairments and 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 increased by $1.8 billion primarily due to the following:
A $1.2 billion increase in cash primarily due to the timing of fuel and purchase power revenues and expenses. PSO and SWEPCo were impacted by the February 2021 severe winter weather event in SPP which led to significantly higher fuel and purchased power expenses which were deferred as regulatory assets in 2021. In September 2022, the ODFA issued ratepayer-backed securitization bonds and provided PSO proceeds of $687 million as reimbursement of the extraordinary fuel costs and purchased electricity incurred during the severe winter weather event. See Note 4 - Rate Matters for additional information. In 2022, increased fuel and purchased power prices in excess of amounts included in fuel-related revenues has resulted in an increase in the under collection of fuel costs in most jurisdictions, offsetting the proceeds received by PSO in September 2022. See the “Deferred Fuel Costs” section of Executive Overview for additional information.
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A $443 million increase in cash from Net Income, after non-cash adjustments. See Results of Operations for further detail.
A $161 million increase in cash from the Change in Other Noncurrent Liabilities. The increase is primarily due to changes in regulatory liabilities driven by timing differences between collections from and refunds to customers under rate rider mechanisms.
A $102 million increase in cash from the Change in Other Noncurrent Assets primarily due to incremental other operation and maintenance storm restoration expenses incurred in 2021 by APCo, SWEPCo and KPCo as a result of the February 2021 severe winter weather event. KPCo intends to seek recovery of these incremental storm costs in its next base rate case while APCo is expected to seek recovery in either upcoming rider or base case filings. In October 2021, SWEPCo requested recovery of these storm costs, in addition to storm costs from Hurricanes Delta and Laura, in a filing with the LPSC. The increase due to the February 2021 severe winter weather event was partially offset by the deferral of incremental other operation and maintenance storm restoration expenses incurred in June 2022 by APCo, KPCo, OPCo and WPCo. Recovery of the June 2022 storm costs will be requested in future filings. See Note 4 - Rate Matters for additional information.
These increases in cash were partially offset by:
A $260 million decrease in cash from the Change in Certain Components of Working Capital. The decrease is primarily due to fuel, material and supplies driven by prior year decreases in coal and lignite inventory on hand, an increase in estimated federal income taxes paid and the timing of accounts receivables. These decreases were partially offset by the timing of accounts payable and a return of margin deposits from PJM originally paid in 2021.

Investing Activities
Nine Months Ended 
September 30,
 20222021
 (in millions)
Construction Expenditures$(4,748.5)$(4,087.0)
Acquisitions of Nuclear Fuel(91.9)(63.2)
Acquisition of the Dry Lake Solar Project— (114.4)
Acquisition of the North Central Wind Energy Facilities(1,207.3)(652.8)
Proceeds from Sale of Assets215.7 17.4 
Other9.5 (6.2)
Net Cash Flows Used for Investing Activities$(5,822.5)$(4,906.2)

Net Cash Flows Used for Investing Activities increased by $916 million primarily due to the following:
A $662 million increase in Construction Expenditures, primarily due to increases in Vertically Integrated Utilities of $437 million and Transmission and Distribution Utilities of $271 million.
A $440 million increase due to the 2022 acquisition of Traverse, partially offset by the 2021 acquisitions of the Dry Lake Solar Project and Sundance. See Note 6 - Acquisitions, Assets and Liabilities Held for Sale, Dispositions and Impairments for additional information.
These increases in cash used were partially offset by:
A $198 million increase in Proceeds from Sale of Assets, primarily due to the sale of certain mineral rights. See Note 6 - Acquisitions, Assets and Liabilities Held for Sale, Dispositions and Impairments for additional information.


53



Financing Activities
Nine Months Ended 
September 30,
 20222021
 (in millions)
Issuance of Common Stock$827.2 $548.0 
Issuance/Retirement of Debt, Net1,837.6 3,537.2 
Dividends Paid on Common Stock(1,212.5)(1,122.7)
Other(237.1)(40.9)
Net Cash Flows from Financing Activities$1,215.2 $2,921.6 

Net Cash Flows from Financing Activities decreased by $1.7 billion primarily due to the following:
A $1.6 billion decrease in issuances of long-term debt. See Note 12 - Financing Activities for additional information.
A $129 million increase in retirements of long-term debt. See Note 12 - Financing Activities for additional information.
These decreases in cash were partially offset by:
A $279 million increase in issuances of common stock primarily due to the settlement of the 2019 equity units. See “Equity Units” section of Note 12 for additional information.
A $64 million increase due to changes in short-term debt. See Note 12 - Financing Activities for additional information.

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 September 30, 2022 through October 27, 2022, the date that the third quarter 10-Q was filed.

BUDGETED CAPITAL EXPENDITURES

Management forecasts approximately $7.6 billion of capital expenditures in 2022. For the four year period, 2023 through 2026, 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 sale of Kentucky operations, proceeds from the sale of competitive contracted renewables and financing activities.  Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged. 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 2021 Annual Report.

SIGNIFICANT CASH REQUIREMENTS

A summary of significant cash requirements is included in the 2021 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.


54



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 2021 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting standards.

ACCOUNTING STANDARDS

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

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

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

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

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

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 President & Chief Financial Officer, Chief Operating Officer, Executive Vice President of Generation, Senior Vice President of Grid Solutions, Senior Vice President of Treasury and Risk and Chief Risk Officer.  The Competitive Risk Committee consists of AEPSC’s President & Chief Financial Officer, Senior Vice President of Treasury and Risk and Chief Risk Officer in addition to Chief Commercial Officer and Senior Vice President of Financial and Commercial Operations.  When commercial activities exceed predetermined limits, positions are modified to reduce the risk to be within the limits unless specifically approved by the respective committee.

The effects of COVID-19 continue to be monitored, and while markets have shown improvement, credit risks remain as counterparties encounter business and supply chain disruptions.
55



Due to multiple defaults of market participants, ERCOT had a large outstanding unpaid balance associated with the February 2021 winter storm. A certain portion of this balance has been securitized and disbursed to impacted market participants. A recovery plan has been reached by ERCOT for the remaining portion of the outstanding balance. In both cases, financial costs are allocated to certain market participants and in the role AEPEP is exposed, but not materially. If the market rules were to change on how socialized losses are allocated this could affect AEPEP’s exposure. Regardless of the approach of how socialized losses are allocated there are potential downstream impacts that could push counterparties into financial distress and or bankruptcy, affecting AEPEP, AEP Texas and ETT.

The following table summarizes the reasons for changes in total MTM value as compared to December 31, 2021:
MTM Risk Management Contract Net Assets (Liabilities)
Nine Months Ended September 30, 2022
Vertically
Integrated
Utilities
Transmission
and
Distribution
Utilities
Generation
&
Marketing
Total
 (in millions)
Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2021
$59.8 $(91.4)$275.9 $244.3 
(Gain)/Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period(65.5)3.7 (50.0)(111.8)
Fair Value of New Contracts at Inception When Entered During the Period (a)
— — 0.9 0.9 
Changes in Fair Value Due to Market Fluctuations During the Period (b)1.9 — 265.4 267.3 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)224.5 44.6 — 269.1 
MTM Risk Management Contract Net Assets Held for Sale Related to KPCo (d)(8.4)— — (8.4)
Total MTM Risk Management Contract Net Assets (Liabilities) as of September 30, 2022
$212.3 $(43.1)$492.2 661.4 
Commodity Cash Flow Hedge Contracts
 572.7 
Interest Rate Cash Flow Hedge Contracts
  8.8 
Fair Value Hedge Contracts
  (135.4)
Collateral Deposits
  (847.0)
Total MTM Derivative Contract Net Assets as of September 30, 2022
  $260.5 

(a)Reflects fair value on primarily long-term structured contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location and delivery term. A significant portion of the total volumetric position has been economically hedged.
(b)Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(c)Relates to the net gains (losses) of those contracts that are not reflected on the statements of income.  These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable on the balance sheet.
(d)MTM risk management contract net assets relating to KPCo are classified as Assets Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.

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.


56



Credit Risk

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

AEP has risk management contracts (includes non-derivative contracts) with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, exposures change daily. As of September 30, 2022, credit exposure net of collateral to sub investment grade counterparties was approximately 0.8%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss).

As of September 30, 2022, the following table approximates AEP’s counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:
Counterparty Credit 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)
Investment Grade$830.1 $399.5 $430.6 $186.4 
Split Rating0.8 — 0.8 0.8 
Noninvestment Grade2.5 2.4 0.1 0.1 
No External Ratings:    
Internal Investment Grade32.1 — 32.1 24.7 
Internal Noninvestment Grade16.7 13.2 3.5 3.4 
Total as of September 30, 2022$882.2 $415.1 $467.1 

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 September 30, 2022, a near term typical change in commodity prices is not expected to materially impact net income, cash flows or financial condition.

Management calculates the VaR for both a trading and non-trading portfolio. The trading portfolio consists primarily of contracts related to energy trading and marketing activities. The non-trading portfolio consists primarily of economic hedges of generation and retail supply activities.
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The following tables show the end, high, average and low market risk as measured by VaR for the periods indicated:

VaR Model
Trading Portfolio
Nine Months EndedTwelve Months Ended
September 30, 2022December 31, 2021
EndHighAverageLowEndHighAverageLow
(in millions)(in millions)
$0.4 $4.5 $0.8 $0.1 $0.4 $3.6 $0.4 $0.1 

VaR Model
Non-Trading Portfolio
Nine Months EndedTwelve Months Ended
September 30, 2022December 31, 2021
EndHighAverageLowEndHighAverageLow
(in millions)(in millions)
$16.6 $76.9 $26.0 $6.7 $8.3 $14.9 $3.7 $0.7 

Management back-tests VaR results against performance due to actual price movements. Based on the assumed 95% confidence interval, the performance due to actual price movements would be expected to exceed the VaR at least once every 20 trading days.

As the VaR calculation captures recent price movements, management also performs regular stress testing of the trading portfolio to understand AEP’s exposure to extreme price movements. A historical-based method is employed whereby the current trading portfolio is subjected to actual, observed price movements from the last several years in order to ascertain which historical price movements translated into the largest potential MTM loss. Management then researches the underlying positions, price movements and market events that created the most significant exposure and reports the findings to the Risk Executive Committee, Regulated Risk Committee or Competitive Risk Committee as appropriate.

Interest Rate Risk

AEP is exposed to interest rate market fluctuations in the normal course of business operations. Recently, interest rates have remained at relatively low levels on a historical basis and the Federal Reserve maintained the federal funds target range at 0.0% to 0.25% for much of 2021. However, in March 2022, the Federal Reserve approved a 0.25% rate increase and in each of June, July and September of 2022 approved further 0.75% rate increases. The Federal Reserve has indicated that, in light of increasing signs of inflation, it foresees further increases in interest rates throughout the year and into 2023 and 2024. 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 nine months ended September 30, 2022 and 2021, a 100 basis point change in the benchmark rate on AEP’s variable rate debt would impact pretax interest expense annually by $47 million and $32 million, respectively.
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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2022 and 2021
(in millions, except per-share and share amounts)
(Unaudited)
Three Months EndedNine Months Ended
September 30,September 30,
2022202120222021
REVENUES
Vertically Integrated Utilities$3,174.6 $2,716.8 $8,416.4 $7,445.9 
Transmission and Distribution Utilities1,525.5 1,195.0 4,064.5 3,366.9 
Generation & Marketing733.1 617.4 1,997.0 1,641.6 
Other Revenues92.9 93.8 280.5 276.2 
TOTAL REVENUES5,526.1 4,623.0 14,758.4 12,730.6 
EXPENSES    
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation2,111.9 1,441.4 5,177.0 4,126.1 
Other Operation797.0 735.3 2,079.0 1,894.6 
Maintenance298.1 277.8 909.6 817.0 
Loss on the Expected Sale of the Kentucky Operations194.5 — 263.3 — 
Asset Impairments and Other Related Charges24.9 — 24.9 — 
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset(37.0)— (37.0)— 
Gain on Sale of Mineral Rights— — (116.3)— 
Depreciation and Amortization821.8 700.3 2,416.8 2,103.9 
Taxes Other Than Income Taxes384.8 360.8 1,118.5 1,061.4 
TOTAL EXPENSES4,596.0 3,515.6 11,835.8 10,003.0 
OPERATING INCOME930.1 1,107.4 2,922.6 2,727.6 
Other Income (Expense):    
Other Income (Expense)4.8 (20.6)(5.6)34.2 
Allowance for Equity Funds Used During Construction35.6 37.0 95.2 103.9 
Non-Service Cost Components of Net Periodic Benefit Cost47.2 29.6 141.5 88.9 
Interest Expense(360.7)(303.7)(1,001.7)(895.5)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS)657.0 849.7 2,152.0 2,059.1 
Income Tax Expense (Benefit)(16.1)69.8 90.7 185.5 
Equity Earnings (Loss) of Unconsolidated Subsidiaries10.2 17.0 (139.1)75.9 
NET INCOME683.3 796.9 1,922.2 1,949.5 
Net Income (Loss) Attributable to Noncontrolling Interests(0.4)0.9 (0.7)0.3 
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$683.7 $796.0 $1,922.9 $1,949.2 
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING
513,730,196 501,233,680 511,162,723 499,418,278 
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
$1.33 $1.59 $3.76 $3.90 
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING515,315,994 502,606,836 512,714,006 500,600,237 
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
$1.33 $1.58 $3.75 $3.89 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
Three Months EndedNine Months Ended
September 30,September 30,
2022202120222021
Net Income$683.3 $796.9 $1,922.2 $1,949.5 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES    
Cash Flow Hedges, Net of Tax of $(19.5) and $47.8 for the Three Months Ended September 30, 2022 and 2021, Respectively, and $81.6 and $97.3 for the Nine Months Ended September 30, 2022 and 2021, Respectively
(73.3)179.7 307.1 365.9 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.8) and $(0.5) for the Three Months Ended September 30, 2022 and 2021 and $(4.5) and $(1.6) for the Nine Months Ended September 30, 2022 and 2021, Respectively
(3.2)(2.0)(17.0)(6.1)
    
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)(76.5)177.7 290.1 359.8 
TOTAL COMPREHENSIVE INCOME606.8 974.6 2,212.3 2,309.3 
Total Comprehensive Income (Loss) Attributable To Noncontrolling Interests(0.4)0.9 (0.7)0.3 
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$607.2 $973.7 $2,213.0 $2,309.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
AEP Common Shareholders
Common StockAccumulated
Other
Comprehensive
Income (Loss)
SharesAmountPaid-in
Capital
Retained
Earnings
Noncontrolling
Interests
Total
TOTAL EQUITY – DECEMBER 31, 2020516.8 $3,359.3 $6,588.9 $10,687.8 $(85.1)$223.6 $20,774.5 
Issuance of Common Stock2.7 17.1 167.5  184.6 
Common Stock Dividends(369.5)(a)(2.5)(372.0)
Other Changes in Equity(21.9)(0.6)3.4 (19.1)
Acquisition of Dry Lake Solar Project18.9 18.9 
Net Income   575.0 3.8 578.8 
Other Comprehensive Income    54.3 54.3 
TOTAL EQUITY – MARCH 31, 2021519.5 3,376.4 6,734.5 10,892.7 (30.8)247.2 21,220.0 
Issuance of Common Stock0.9 6.3 66.0    72.3 
Common Stock Dividends   (371.8)(a) (2.7)(374.5)
Other Changes in Equity  (0.2)(0.4) 11.1 10.5 
Net Income (Loss)   578.2  (4.4)573.8 
Other Comprehensive Income    127.8  127.8 
TOTAL EQUITY – JUNE 30, 2021520.4 3,382.7 6,800.3 11,098.7 97.0 251.2 21,629.9 
Issuance of Common Stock3.4 21.8 269.3 291.1 
Common Stock Dividends(371.7)(a)(4.5)(376.2)
Other Changes in Equity6.3 1.5 7.8 
Net Income796.0 0.9 796.9 
Other Comprehensive Income177.7 177.7 
TOTAL EQUITY – SEPTEMBER 30, 2021523.8 $3,404.5 $7,075.9 $11,523.0 $274.7 $249.1 $22,527.2 
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 Stock0.4 2.4 807.1 809.5 
Common Stock Dividends(395.2)(b)(3.6)(398.8)
Other Changes in Equity(15.2)(1.5)(16.7)
Net Income714.7 3.4 718.1 
Other Comprehensive Income245.8 245.8 
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 Stock0.1 0.9 2.3 3.2 
Common Stock Dividends(402.6)(b)(2.1)(404.7)
Other Changes in Equity17.2 1.6 18.8 
Net Income (Loss)524.5 (3.7)520.8 
Other Comprehensive Income120.8 120.8 
TOTAL EQUITY – JUNE 30, 2022524.9 3,412.0 7,984.0 12,108.6 551.4 241.0 24,297.0 
Issuance of Common Stock0.1 0.5 14.0   14.5 
Common Stock Dividends  (402.5)(b) (6.5)(409.0)
Other Changes in Equity  3.0  3.0 
Net Income (Loss)   683.7  (0.4)683.3 
Other Comprehensive Loss    (76.5) (76.5)
TOTAL EQUITY – SEPTEMBER 30, 2022525.0 $3,412.5 $8,001.0 $12,389.8 $474.9 $234.1 $24,512.3 

(a)    Cash dividends declared per AEP common share were $0.74.
(b)    Cash dividends declared per AEP common share were $0.78.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2022 and December 31, 2021
(in millions)
(Unaudited)
 September 30,December 31,
 20222021
CURRENT ASSETS  
Cash and Cash Equivalents$522.2 $403.4 
Restricted Cash
(September 30, 2022 and December 31, 2021 Amounts Include $55.1 and $48, Respectively, Related to Transition Funding, Restoration Funding and Appalachian Consumer Rate Relief Funding)
55.1 48.0 
Other Temporary Investments
(September 30, 2022 and December 31, 2021 Amounts Include $188.4 and $214.8, Respectively, Related to EIS and Transource Energy)
202.2 220.4 
Accounts Receivable:  
Customers885.6 720.9 
Accrued Unbilled Revenues272.2 204.4 
Pledged Accounts Receivable – AEP Credit1,211.9 1,038.0 
Miscellaneous84.8 33.9 
Allowance for Uncollectible Accounts(53.2)(55.6)
Total Accounts Receivable2,401.3 1,941.6 
Fuel332.1 307.9 
Materials and Supplies801.9 681.3 
Risk Management Assets570.2 194.4 
Accrued Tax Benefits150.8 121.5 
Regulatory Asset for Under-Recovered Fuel Costs1,137.1 647.8 
Assets Held for Sale2,830.6 2,919.7 
Prepayments and Other Current Assets316.5 323.2 
TOTAL CURRENT ASSETS9,320.0 7,809.2 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation24,590.7 23,088.1 
Transmission31,271.5 29,911.1 
Distribution25,566.1 24,440.0 
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)6,080.8 5,682.9 
Construction Work in Progress4,596.0 3,684.3 
Total Property, Plant and Equipment92,105.1 86,806.4 
Accumulated Depreciation and Amortization22,292.0 20,805.1 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET69,813.1 66,001.3 
OTHER NONCURRENT ASSETS  
Regulatory Assets3,877.5 4,142.3 
Securitized Assets474.3 552.8 
Spent Nuclear Fuel and Decommissioning Trusts3,130.5 3,867.0 
Goodwill52.5 52.5 
Long-term Risk Management Assets265.8 267.0 
Operating Lease Assets620.0 578.3 
Deferred Charges and Other Noncurrent Assets3,695.7 4,398.3 
TOTAL OTHER NONCURRENT ASSETS12,116.3 13,858.2 
TOTAL ASSETS$91,249.4 $87,668.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
62



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 2022 and December 31, 2021
(in millions, except per-share and share amounts)
(Unaudited)
   September 30,December 31,
 20222021
CURRENT LIABILITIES  
Accounts Payable$2,240.2 $2,054.6 
Short-term Debt:  
Securitized Debt for Receivables – AEP Credit750.0 750.0 
Other Short-term Debt1,952.3 1,864.0 
Total Short-term Debt2,702.3 2,614.0 
Long-term Debt Due Within One Year
(September 30, 2022 and December 31, 2021 Amounts Include $196.4 and $190.5, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)
1,403.5 2,153.8 
Risk Management Liabilities187.3 75.4 
Customer Deposits375.5 321.6 
Accrued Taxes1,116.9 1,586.4 
Accrued Interest375.4 273.2 
Obligations Under Operating Leases91.7 97.6 
Liabilities Held for Sale1,992.0 1,880.9 
Other Current Liabilities1,351.6 1,369.2 
TOTAL CURRENT LIABILITIES11,836.4 12,426.7 
NONCURRENT LIABILITIES  
Long-term Debt
(September 30, 2022 and December 31, 2021 Amounts Include $764 and $840.5, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)
33,646.6 31,300.7 
Long-term Risk Management Liabilities388.2 230.3 
Deferred Income Taxes8,544.8 8,202.5 
Regulatory Liabilities and Deferred Investment Tax Credits7,934.1 8,686.3 
Asset Retirement Obligations2,855.1 2,676.2 
Employee Benefits and Pension Obligations279.9 328.4 
Obligations Under Operating Leases540.0 492.8 
Deferred Credits and Other Noncurrent Liabilities638.7 601.3 
TOTAL NONCURRENT LIABILITIES54,827.4 52,518.5 
TOTAL LIABILITIES66,663.8 64,945.2 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
MEZZANINE EQUITY
Contingently Redeemable Performance Share Awards73.3 43.3 
TOTAL MEZZANINE EQUITY73.3 43.3 
EQUITY  
Common Stock – Par Value – $6.50 Per Share:
  
20222021  
Shares Authorized600,000,000600,000,000  
Shares Issued525,005,433524,416,175  
(11,233,240 Shares and 20,204,160 Shares were Held in Treasury as of September 30, 2022 and December 31, 2021, Respectively)
3,412.5 3,408.7 
Paid-in Capital8,001.0 7,172.6 
Retained Earnings12,389.8 11,667.1 
Accumulated Other Comprehensive Income (Loss)474.9 184.8 
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY24,278.2 22,433.2 
Noncontrolling Interests234.1 247.0 
TOTAL EQUITY24,512.3 22,680.2 
TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY$91,249.4 $87,668.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
63



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20222021
OPERATING ACTIVITIES  
Net Income$1,922.2 $1,949.5 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and Amortization2,416.8 2,103.9 
Deferred Income Taxes16.6 191.1 
Loss on the Expected Sale of the Kentucky Operations263.3 — 
Asset Impairments and Other Related Charges24.9 — 
Impairment of Equity Method Investment188.0 — 
Allowance for Equity Funds Used During Construction(95.2)(103.9)
Mark-to-Market of Risk Management Contracts162.3 101.0 
Property Taxes459.9 415.1 
Deferred Fuel Over/Under-Recovery, Net(148.7)(1,356.8)
Gain on Sale of Mineral Rights(116.3)— 
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset(37.0)— 
Change in Other Noncurrent Assets(6.0)(108.0)
Change in Other Noncurrent Liabilities324.0 162.7 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net(495.7)(199.2)
Fuel, Materials and Supplies(134.6)347.4 
Accounts Payable369.4 107.6 
Accrued Taxes, Net(512.8)(471.1)
Other Current Assets41.2 (33.3)
Other Current Liabilities90.9 (133.0)
Net Cash Flows from Operating Activities4,733.2 2,973.0 
INVESTING ACTIVITIES  
Construction Expenditures(4,748.5)(4,087.0)
Purchases of Investment Securities(1,868.2)(1,612.3)
Sales of Investment Securities1,833.4 1,571.7 
Acquisitions of Nuclear Fuel(91.9)(63.2)
Acquisition of the Dry Lake Solar Project— (114.4)
Acquisition of the North Central Wind Energy Facilities(1,207.3)(652.8)
Proceeds from Sales of Assets215.7 17.4 
Other Investing Activities44.3 34.4 
Net Cash Flows Used for Investing Activities(5,822.5)(4,906.2)
FINANCING ACTIVITIES  
Issuance of Common Stock827.2 548.0 
Issuance of Long-term Debt3,428.4 5,062.3 
Issuance of Short-term Debt with Original Maturities greater than 90 Days271.0 1,178.5 
Change in Short-term Debt with Original Maturities less than 90 Days, Net803.4 (632.5)
Retirement of Long-term Debt(1,679.1)(1,549.8)
Redemption of Short-term Debt with Original Maturities Greater than 90 Days(986.1)(521.3)
Principal Payments for Finance Lease Obligations(120.3)(45.3)
Dividends Paid on Common Stock(1,212.5)(1,122.7)
Other Financing Activities(116.8)4.4 
Net Cash Flows from Financing Activities1,215.2 2,921.6 
Net Increase in Cash and Cash Equivalents125.9 988.4 
Cash, Cash Equivalents and Restricted Cash at Beginning of Period451.4 438.3 
Cash, Cash Equivalents and Restricted Cash at End of Period$577.3 $1,426.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
64





AEP TEXAS INC.
AND SUBSIDIARIES

65



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
September 30,September 30,
 2022202120222021
 (in millions of KWhs)
Retail:  
Residential4,079 3,997 10,453 9,821 
Commercial3,243 3,014 8,482 7,907 
Industrial2,993 2,414 8,443 6,898 
Miscellaneous185 182 499 478 
Total Retail10,500 9,607 27,877 25,104 

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
September 30,September 30,
 2022202120222021
 (in degree days)
Actual – Heating (a)— — 278 319 
Normal – Heating (b)— — 193 188 
Actual – Cooling (c)1,478 1,308 2,701 2,278 
Normal – Cooling (b)1,382 1,379 2,433 2,436 

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




66



Third Quarter of 2022 Compared to Third Quarter of 2021
AEP Texas Inc. and Subsidiaries
Reconciliation of Third Quarter of 2021 to Third Quarter of 2022
Net Income
(in millions)
Third Quarter of 2021$99.5 
  
Changes in Revenues:
Retail Revenues44.0 
Transmission Revenues9.3 
Other Revenues23.0 
Total Change in Revenues76.3 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(29.2)
Depreciation and Amortization(30.1)
Taxes Other Than Income Taxes(3.9)
Interest Income1.1 
Allowance for Equity Funds Used During Construction(4.0)
Non-Service Cost Components of Net Periodic Benefit Cost1.4 
Interest Expense(11.2)
Total Change in Expenses and Other(75.9)
  
Income Tax Expense(6.3)
  
Third Quarter of 2022$93.6 

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

Retail Revenues increased $44 million primarily due to the following:
A $21 million increase due to interim rate increases driven by increased transmission investment.
A $10 million increase due to interim rate increases driven by increased distribution investment.
A $7 million increase in weather-related usage primarily due to a 13% increase in cooling degree days.
A $6 million increase in revenue from rate riders. This increase was partially offset in other expense items below.
Transmission Revenues increased $9 million primarily due to the following:
An $11 million increase due to interim rate increases driven by increased transmission investment.
This increase was partially offset by:
A $2 million decrease due to prior year refunds to customers associated with the most recent base rate case. This decrease was offset in Other Revenues below.
Other Revenues increased $23 million primarily due to the following:
A $19 million increase primarily due to securitization revenues due to AEP Texas Central Transition Funding II LLC bonds that matured in July 2020 and final refunds that were completed in 2021. This increase was offset below in Depreciation and Amortization expenses and Interest Expense.
67


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

Other Operation and Maintenance expenses increased $29 million primarily due to the following:
A $21 million increase in ERCOT transmission expenses. This increase was partially offset in Retail Revenues and Transmission Revenues above.
A $6 million increase in distribution-related expenses.
Depreciation and Amortization expenses increased $30 million primarily due to the following:
A $19 million increase in securitization amortizations primarily due to prior year AEP Texas Central Transition Funding II LLC bonds that matured in July 2020 and final refunds that were completed in 2021. This increase was offset above in Other Revenues above.
A $6 million increase due to a higher depreciable base of transmission and distribution assets.
A $4 million increase in recoverable advanced metering system depreciable expenses.
Taxes Other Than Income Taxes increased $4 million primarily due to property taxes as a result of increased distribution and transmission investment.
Allowance for Equity Funds Used During Construction decreased $4 million due to a prior year rate adjustment.
Interest Expense increased $11 million primarily due to higher long-term debt balances and higher interest rates.
Income Tax Expense increased $6 million primarily due to a decrease in amortization of Excess ADIT. The decrease in amortization of Excess ADIT was offset in Retail Revenues above.
68



Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021
AEP Texas Inc. and Subsidiaries
Reconciliation of Nine Months Ended September 30, 2021 to Nine Months Ended September 30, 2022
Net Income
(in millions)
Nine Months Ended September 30, 2021$225.4 
  
Changes in Revenues:
Retail Revenues151.2 
Transmission Revenues53.2 
Other Revenues4.7 
Total Change in Revenues209.1 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(74.8)
Depreciation and Amortization(55.6)
Taxes Other Than Income Taxes(8.4)
Interest Income2.1 
Allowance for Equity Funds Used During Construction(3.5)
Non-Service Cost Components of Net Periodic Benefit Cost4.2 
Interest Expense(20.7)
Total Change in Expenses and Other(156.7)
  
Income Tax Expense(24.6)
  
Nine Months Ended September 30, 2022$253.2 
The major components of the increase in revenues were as follows:

Retail Revenues increased $151 million primarily due to the following:
A $41 million increase due to interim rate increases driven by increased transmission investment.
A $31 million increase due to prior year refunds of Excess ADIT to customers. This increase was offset in Income Tax Expense below.
A $29 million increase due to interim rate increases driven by increased distribution investment.
A $20 million increase in revenue from rate riders. This increase was partially offset in other expense items below.
A $16 million increase in weather-normalized revenues in all retail classes.
A $15 million increase in weather-related usage primarily due to a 19% increase in cooling degree days partially offset by a 13% decrease in heating degree days.
Transmission Revenues increased $53 million primarily due to the following:
A $46 million increase due to interim rate increases driven by increased transmission investment.
A $7 million increase due to prior year refunds to customers associated with the most recent base rate case. This increase was offset in Other Revenues below.
Other Revenues increased $5 million primarily due to:
A $20 million increase primarily due to securitization revenues driven by the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020 and final refunds that were completed in 2021. This increase was offset below in Depreciation and Amortization expenses and Interest Expense.
A $2 million increase in pole attachment revenues.

69



These increases were partially offset by:
A $12 million decrease due to prior year refunds to customers associated with the most recent base rate case. This decrease was partially offset in Retail Revenues and Transmission Revenues above.
A $5 million decrease in energy efficiency revenues.

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

Other Operation and Maintenance expenses increased $75 million primarily due to the following:
A $46 million increase in ERCOT transmission expenses. This increase was partially offset in Retail Revenues and Transmission Revenues above.
A $13 million increase in distribution-related expenses.
A $10 million increase in employee-related expenses.
A $5 million increase in vegetation management expenses.
Depreciation and Amortization expenses increased $56 million primarily due to the following:
A $24 million increase due to a higher depreciable base and amortizations of transmission and distribution assets.
A $19 million increase in securitization amortizations primarily due to prior year AEP Texas Central Transition Funding II LLC bonds that matured in July 2020 and final refunds that were completed in 2021. This increase was offset above in Other Revenue.
An $11 million increase in recoverable advanced metering system depreciable expenses.
Taxes Other Than Income Taxes increased $8 million primarily due to property taxes as a result of increased distribution and transmission investment.
Allowance for Equity Funds Used During Construction decreased $4 million due to a prior year rate adjustment.
Non-Service Cost Components of Net Periodic Benefit Cost decreased $4 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.
Interest Expense increased $21 million primarily due to higher long-term debt balances and higher interest rates.
Income Tax Expense increased $25 million primarily due to an increase in pretax book income and a decrease in amortization of Excess ADIT. The decrease in amortization of Excess ADIT was offset in Retail Revenues above.

70




AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
  Three Months EndedNine Months Ended
September 30,September 30,
  2022 202120222021
REVENUES    
Electric Transmission and Distribution $507.7 $430.8 $1,399.3 $1,189.1 
Sales to AEP Affiliates 0.9 0.9 2.6 2.9 
Other Revenues 0.3 0.9 2.5 3.3 
TOTAL REVENUES 508.9 432.6 1,404.4 1,195.3 
 
EXPENSES     
Other Operation 163.8 135.3 431.6 367.1 
Maintenance 22.7 22.0 70.1 59.8 
Depreciation and Amortization 117.7 87.6 342.7 287.1 
Taxes Other Than Income Taxes 45.5 41.6 125.8 117.4 
TOTAL EXPENSES 349.7 286.5 970.2 831.4 
 
OPERATING INCOME 159.2 146.1 434.2 363.9 
 
Other Income (Expense):     
Interest Income 1.3 0.2 2.7 0.6 
Allowance for Equity Funds Used During Construction5.2 9.2 13.2 16.7 
Non-Service Cost Components of Net Periodic Benefit Cost4.2 2.8 12.5 8.3 
Interest Expense (55.4)(44.2)(153.2)(132.5)
 
INCOME BEFORE INCOME TAX EXPENSE 114.5 114.1 309.4 257.0 
 
Income Tax Expense 20.9 14.6 56.2 31.6 
NET INCOME $93.6 $99.5 $253.2 $225.4 
The common stock of AEP Texas is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
71



AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
September 30,September 30,
2022202120222021
Net Income$93.6 $99.5 $253.2 $225.4 
 
OTHER COMPREHENSIVE INCOME, NET OF TAXES  
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended September 30, 2022 and 2021, Respectively, and $0.2 and $0.2 for the Nine Months Ended September 30, 2022 and 2021, Respectively
0.3 0.3 0.8 0.8 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2022 and 2021, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2022 and 2021, Respectively
— — — 0.1 
TOTAL OTHER COMPREHENSIVE INCOME0.3 0.3 0.8 0.9 
TOTAL COMPREHENSIVE INCOME$93.9 $99.8 $254.0 $226.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.

72



AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
 Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020
$1,457.9 $1,757.0 $(8.9)$3,206.0 
Net Income46.1 46.1 
Other Comprehensive Income0.3 0.3 
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2021
1,457.9 1,803.1 (8.6)3,252.4 
Net Income 79.8  79.8 
Other Comprehensive Income  0.3 0.3 
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2021
1,457.9 1,882.9 (8.3)3,332.5 
Net Income99.5 99.5 
Other Comprehensive Income0.3 0.3 
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2021
$1,457.9 $1,982.4 $(8.0)$3,432.3 
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2021
$1,553.9 $2,046.8 $(6.5)$3,594.2 
Net Income69.6 69.6 
Other Comprehensive Income0.3 0.3 
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2022
1,553.9 2,116.4 (6.2)3,664.1 
Capital Contribution from Parent1.3 1.3 
Net Income 90.0 90.0 
Other Comprehensive Income 0.2 0.2 
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2022
1,555.2 2,206.4 (6.0)3,755.6 
Capital Contribution from Parent0.5 0.5 
Net Income93.6 93.6 
Other Comprehensive Income0.3 0.3 
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2022
$1,555.7 $2,300.0 $(5.7)$3,850.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.

73



AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2022 and December 31, 2021
(in millions)
(Unaudited)
  September 30,December 31,
  2022 2021
CURRENT ASSETS    
Cash and Cash Equivalents$0.1 $0.1 
Restricted Cash
(September 30, 2022 and December 31, 2021 Amounts Include $47.7 and $30.4, Respectively, Related to Transition Funding and Restoration Funding)
47.7 30.4 
Advances to Affiliates136.3 6.9 
Accounts Receivable:   
Customers 166.0 123.4 
Affiliated Companies 5.9 7.9 
Accrued Unbilled Revenues94.7 77.9 
Miscellaneous 0.2 — 
Allowance for Uncollectible Accounts(4.1)(4.0)
Total Accounts Receivable 262.7 205.2 
Materials and Supplies 113.8 73.9 
Risk Management Assets0.2 — 
Accrued Tax Benefits21.7 24.8 
Prepayments and Other Current Assets 6.5 5.9 
TOTAL CURRENT ASSETS 589.0 347.2 
 
PROPERTY, PLANT AND EQUIPMENT   
Electric:   
Transmission
 6,154.4 5,849.9 
Distribution
 5,192.3 4,917.2 
Other Property, Plant and Equipment 1,013.6 961.1 
Construction Work in Progress 697.7 551.3 
Total Property, Plant and Equipment 13,058.0 12,279.5 
Accumulated Depreciation and Amortization 1,746.3 1,644.1 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 11,311.7 10,635.4 
 
OTHER NONCURRENT ASSETS   
Regulatory Assets 243.9 275.2 
Securitized Assets
(September 30, 2022 and December 31, 2021 Amounts Include $308.3 and $367.6, Respectively, Related to Transition Funding and Restoration Funding)
308.3 367.6 
Long-term Risk Management Assets0.1 — 
Deferred Charges and Other Noncurrent Assets 237.0 211.3 
TOTAL OTHER NONCURRENT ASSETS 789.3 854.1 
 
TOTAL ASSETS $12,690.0 $11,836.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
74



AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2022 and December 31, 2021
(in millions)
(Unaudited)
  September 30,December 31,
  2022 2021
CURRENT LIABILITIES 
Advances from Affiliates $— $26.9 
Accounts Payable: 
General 249.2 306.3 
Affiliated Companies 32.6 32.5 
Long-term Debt Due Within One Year – Nonaffiliated
(September 30, 2022 and December 31, 2021 Amounts Include $92.5 and $91, Respectively, Related to Transition Funding and Restoration Funding)
277.5 716.0 
Accrued Taxes 129.6 93.3 
Accrued Interest
(September 30, 2022 and December 31, 2021 Amounts Include $2.5 and $2.3, Respectively, Related to Transition Funding and Restoration Funding)
72.3 44.7 
Obligations Under Operating Leases14.0 14.0 
Other Current Liabilities 110.5 78.0 
TOTAL CURRENT LIABILITIES 885.7 1,311.7 
 
NONCURRENT LIABILITIES   
Long-term Debt – Nonaffiliated
(September 30, 2022 and December 31, 2021 Amounts Include $259.2 and $313.7, Respectively, Related to Transition Funding and Restoration Funding)
5,416.4 4,464.8 
Long-term Risk Management Liabilities0.1 — 
Deferred Income Taxes 1,132.2 1,088.9 
Regulatory Liabilities and Deferred Investment Tax Credits 1,258.3 1,242.0 
Obligations Under Operating Leases54.3 61.3 
Deferred Credits and Other Noncurrent Liabilities 93.0 73.8 
TOTAL NONCURRENT LIABILITIES 7,954.3 6,930.8 
 
TOTAL LIABILITIES 8,840.0 8,242.5 
 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5) 
 
COMMON SHAREHOLDER’S EQUITY   
Paid-in Capital 1,555.7 1,553.9 
Retained Earnings 2,300.0 2,046.8 
Accumulated Other Comprehensive Income (Loss)(5.7)(6.5)
TOTAL COMMON SHAREHOLDER’S EQUITY 3,850.0 3,594.2 
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $12,690.0 $11,836.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
75



AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
  Nine Months Ended September 30,
  2022 2021
OPERATING ACTIVITIES    
Net Income $253.2 $225.4 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:   
Depreciation and Amortization 342.7 287.1 
Deferred Income Taxes 35.1 45.8 
Allowance for Equity Funds Used During Construction(13.2)(16.7)
Mark-to-Market of Risk Management Contracts (0.2)— 
Change in Other Noncurrent Assets (48.4)(73.4)
Change in Other Noncurrent Liabilities 49.2 17.5 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net (57.5)(40.2)
Materials and Supplies (39.9)(2.5)
Accounts Payable 16.0 (10.9)
Accrued Taxes, Net39.4 29.5 
Other Current Assets 1.0 (2.0)
Other Current Liabilities 12.2 (5.0)
Net Cash Flows from Operating Activities 589.6 454.6 
 
INVESTING ACTIVITIES   
Construction Expenditures (949.8)(742.4)
Change in Advances to Affiliates, Net(129.4)(47.5)
Other Investing Activities26.7 29.6 
Net Cash Flows Used for Investing Activities (1,052.5)(760.3)
 
FINANCING ACTIVITIES   
Capital Contribution from Parent1.8 — 
Issuance of Long-term Debt – Nonaffiliated1,188.7 444.2 
Change in Advances from Affiliates, Net (26.9)(67.1)
Retirement of Long-term Debt – Nonaffiliated (678.6)(52.2)
Principal Payments for Finance Lease Obligations (5.1)(5.0)
Other Financing Activities0.3 1.0 
Net Cash Flows from Financing Activities 480.2 320.9 
Net Change in Cash, Cash Equivalents and Restricted Cash 17.3 15.2 
Cash, Cash Equivalents and Restricted Cash at Beginning of Period 30.5 28.8 
Cash, Cash Equivalents and Restricted Cash at End of Period $47.8 $44.0 
 
SUPPLEMENTARY INFORMATION   
Cash Paid for Interest, Net of Capitalized Amounts $121.1 $110.0 
Net Cash Paid (Received) for Income Taxes 10.0 (8.4)
Noncash Acquisitions Under Finance Leases 4.1 3.3 
Construction Expenditures Included in Current Liabilities as of September 30, 156.0 134.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
76





AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
77



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

RESULTS OF OPERATIONS

Summary of Investment in Transmission Assets for AEPTCo
As of September 30,
20222021
(in millions)
Plant In Service$12,050.4 $10,851.9 
Construction Work in Progress1,644.6 1,507.4 
Accumulated Depreciation and Amortization952.4 730.4 
Total Transmission Property, Net$12,742.6 $11,628.9 

Third Quarter of 2022 Compared to Third Quarter of 2021
AEP Transmission Company, LLC and Subsidiaries
Reconciliation of Third Quarter of 2021 to Third Quarter of 2022
Net Income
(in millions)
Third Quarter of 2021$145.4 
Changes in Transmission Revenues:
Transmission Revenues41.5 
Total Change in Transmission Revenues41.5 
Changes in Expenses and Other:
Other Operation and Maintenance(5.7)
Depreciation and Amortization(11.4)
Taxes Other Than Income Taxes(7.7)
Interest Income0.5 
Allowance for Equity Funds Used During Construction4.3 
Interest Expense(6.6)
Total Change in Expenses and Other(26.6)
Income Tax Expense(7.6)
Third Quarter of 2022$152.7 

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

Transmission Revenues increased $42 million primarily due to continued investment in transmission assets.

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

Other Operation and Maintenance expenses increased $6 million primarily due to cancelled capital projects.
Depreciation and Amortization expenses increased $11 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $8 million primarily due to higher property taxes as a result of increased transmission investment.
Allowance for Equity Funds Used During Construction increased $4 million primarily due to higher CWIP.
Interest Expense increased $7 million primarily due to higher long-term debt balances.
Income Tax Expense increased $8 million primarily due to an increase in pretax book income and a decrease in parent company loss benefit.
78



Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021
AEP Transmission Company, LLC and Subsidiaries
Reconciliation of Nine Months Ended September 30, 2021 to Nine Months Ended September 30, 2022
Net Income
(in millions)
Nine Months Ended September 30, 2021$445.7 
  
Changes in Transmission Revenues: 
Transmission Revenues79.1 
Total Change in Transmission Revenues79.1 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(15.5)
Depreciation and Amortization(37.2)
Taxes Other Than Income Taxes(24.1)
Interest Income0.6 
Allowance for Equity Funds Used During Construction1.9 
Interest Expense(15.2)
Total Change in Expenses and Other(89.5)
  
Income Tax Expense(8.7)
  
Nine Months Ended September 30, 2022$426.6 

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

Transmission Revenues increased $79 million primarily due to the following:
A $122 million increase due to continued investment in transmission assets.
This increase was partially offset by:
A $30 million decrease due to the affiliated annual transmission formula rate true-up. This decrease was offset in Other Operation and Maintenance expense across the other Registrant Subsidiaries.
A $13 million decrease due to the non-affiliated annual transmission formula rate true-up.

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

Other Operation and Maintenance expenses increased $16 million primarily due to the following:
A $12 million increase in employee-related expenses.
A $5 million increase due to cancelled capital projects.
Depreciation and Amortization expenses increased $37 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $24 million primarily due to higher property taxes as a result of increased transmission investment.
Interest Expense increased $15 million primarily due to higher long-term debt balances.
Income Tax Expense increased $9 million primarily due to a decrease in parent company loss benefit, partially offset by a decrease in pretax book income.


79




AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
Three Months EndedNine Months Ended
September 30,September 30,
2022 2021 2022 2021
REVENUES
Transmission Revenues$89.1 $79.2 $261.7 $241.6 
Sales to AEP Affiliates340.6 297.7 999.5 882.3 
Provision for Refund – Affiliated(9.3)(0.1)(65.7)(17.7)
Provision for Refund – Nonaffiliated(1.9)— (12.2)(2.3)
Other Revenues— 0.2 — 0.3 
TOTAL REVENUES418.5 377.0 1,183.3 1,104.2 
EXPENSES    
Other Operation39.6 32.6 94.7 78.1 
Maintenance4.1 5.4 11.2 12.3 
Depreciation and Amortization87.4 76.0 256.2 219.0 
Taxes Other Than Income Taxes68.7 61.0 203.0 178.9 
TOTAL EXPENSES199.8 175.0 565.1 488.3 
OPERATING INCOME218.7 202.0 618.2 615.9 
Other Income (Expense):    
Interest Income - Affiliated0.7 0.2 1.0 0.4 
Allowance for Equity Funds Used During Construction20.3 16.0 51.2 49.3 
Interest Expense(42.7)(36.1)(119.7)(104.5)
INCOME BEFORE INCOME TAX EXPENSE197.0 182.1 550.7 561.1 
Income Tax Expense44.3 36.7 124.1 115.4 
NET INCOME$152.7 $145.4 $426.6 $445.7 
AEPTCo is wholly-owned by AEP Transmission Holdco.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
80



AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY
For the Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
  Paid-in
Capital
Retained
Earnings
Total
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2020 $2,765.6 $1,947.3 $4,712.9 
  
Capital Contribution from Member124.0 124.0 
Net Income 151.7 151.7 
TOTAL MEMBER'S EQUITY – MARCH 31, 20212,889.6 2,099.0 4,988.6 
Capital Contribution from Member60.0 60.0 
Net Income148.6 148.6 
TOTAL MEMBER'S EQUITY – JUNE 30, 20212,949.6 2,247.6 5,197.2 
Dividends Paid to Member(112.5)(112.5)
Net Income 145.4 145.4 
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2021 $2,949.6 $2,280.5 $5,230.1 
  
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2021 $2,949.6 $2,426.5 $5,376.1 
Dividends Paid to Member(40.0)(40.0)
Net Income155.4 155.4 
TOTAL MEMBER'S EQUITY – MARCH 31, 20222,949.6 2,541.9 5,491.5 
  
Capital Contribution from Member2.8 2.8 
Dividends Paid to Member(50.0)(50.0)
Net Income118.5 118.5 
TOTAL MEMBER'S EQUITY – JUNE 30, 20222,952.4 2,610.4 5,562.8 
Capital Contribution from Member 61.4 61.4 
Dividends Paid to Member(40.0)(40.0)
Net Income  152.7 152.7 
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2022 $3,013.8 $2,723.1 $5,736.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
81



AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2022 and December 31, 2021
(in millions)
(Unaudited)
  September 30, December 31,
  2022 2021
CURRENT ASSETS    
Advances to Affiliates $106.7 $27.2 
Accounts Receivable: 
Customers 73.8 22.5 
Affiliated Companies 111.0 96.1 
Total Accounts Receivable 184.8 118.6 
Materials and Supplies 11.7 9.3 
Accrued Tax Benefits 12.3 5.6 
Assets Held for Sale173.7 167.9 
Prepayments and Other Current Assets 3.8 2.7 
TOTAL CURRENT ASSETS 493.0 331.3 
 
TRANSMISSION PROPERTY   
Transmission Property 11,609.8 10,886.3 
Other Property, Plant and Equipment 440.6 427.4 
Construction Work in Progress 1,644.6 1,394.8 
Total Transmission Property 13,695.0 12,708.5 
Accumulated Depreciation and Amortization 952.4 772.8 
TOTAL TRANSMISSION PROPERTY – NET 12,742.6 11,935.7 
 
OTHER NONCURRENT ASSETS   
Regulatory Assets 2.6 8.5 
Deferred Property Taxes 75.7 245.7 
Deferred Charges and Other Noncurrent Assets 5.3 3.2 
TOTAL OTHER NONCURRENT ASSETS 83.6 257.4 
 
TOTAL ASSETS $13,319.2 $12,524.4 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
82



AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND MEMBER’S EQUITY
September 30, 2022 and December 31, 2021
(in millions)
(Unaudited)
  September 30, December 31,
  2022 2021
CURRENT LIABILITIES    
Advances from Affiliates $61.0 $124.0 
Accounts Payable:  
General 332.1 460.1 
Affiliated Companies 121.5 69.9 
Long-term Debt Due Within One Year – Nonaffiliated104.0 104.0 
Accrued Taxes 293.0 479.0 
Accrued Interest 56.0 28.4 
Obligations Under Operating Leases1.3 0.9 
Liabilities Held for Sale27.6 27.6 
Other Current Liabilities 14.8 3.0 
TOTAL CURRENT LIABILITIES 1,011.3 1,296.9 
 
NONCURRENT LIABILITIES   
Long-term Debt – Nonaffiliated 4,782.6 4,239.9 
Deferred Income Taxes 1,032.8 962.9 
Regulatory Liabilities 698.2 644.1 
Obligations Under Operating Leases1.8 1.3 
Deferred Credits and Other Noncurrent Liabilities 55.6 3.2 
TOTAL NONCURRENT LIABILITIES 6,571.0 5,851.4 
 
TOTAL LIABILITIES 7,582.3 7,148.3 
 
Rate Matters (Note 4) 
Commitments and Contingencies (Note 5) 
 
MEMBER’S EQUITY   
Paid-in Capital3,013.8 2,949.6 
Retained Earnings 2,723.1 2,426.5 
TOTAL MEMBER’S EQUITY 5,736.9 5,376.1 
 
TOTAL LIABILITIES AND MEMBER’S EQUITY $13,319.2 $12,524.4 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
83



AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
  Nine Months Ended September 30,
  20222021
OPERATING ACTIVITIES 
Net Income $426.6 $445.7 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: 
Depreciation and Amortization 256.2 219.0 
Deferred Income Taxes 60.6 46.8 
Allowance for Equity Funds Used During Construction (51.2)(49.3)
Property Taxes 170.0 154.0 
Change in Other Noncurrent Assets 4.0 2.3 
Change in Other Noncurrent Liabilities 55.0 8.3 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net (66.4)(23.6)
Materials and Supplies(2.4)(0.5)
Accounts Payable 53.1 (10.7)
Accrued Taxes, Net (194.0)(138.8)
Other Current Assets (1.2)0.5 
Other Current Liabilities 27.2 22.7 
Net Cash Flows from Operating Activities 737.5 676.4 
 
INVESTING ACTIVITIES   
Construction Expenditures (1,059.3)(1,070.8)
Change in Advances to Affiliates, Net (84.1)29.9 
Other Investing Activities (5.3)(7.9)
Net Cash Flows Used for Investing Activities (1,148.7)(1,048.8)
 
FINANCING ACTIVITIES  
Capital Contribution from Member 64.2 184.0 
Issuance of Long-term Debt – Nonaffiliated540.9 443.7 
Change in Advances from Affiliates, Net (63.9)(142.8)
Dividends Paid to Member(130.0)(112.5)
Net Cash Flows from Financing Activities 411.2 372.4 
 
Net Change in Cash and Cash Equivalents — — 
Cash and Cash Equivalents at Beginning of Period — — 
Cash and Cash Equivalents at End of Period $— $— 
 
SUPPLEMENTARY INFORMATION   
Cash Paid for Interest, Net of Capitalized Amounts $88.6 $75.8 
Net Cash Paid for Income Taxes 53.2 37.6 
Construction Expenditures Included in Current Liabilities as of September 30, 240.5 206.8 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
84





APPALACHIAN POWER COMPANY
AND SUBSIDIARIES
85



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
 September 30,September 30,
2022202120222021
 (in millions of KWhs)
Retail:    
Residential2,553 2,657 8,308 8,524 
Commercial1,566 1,596 4,545 4,483 
Industrial2,211 2,223 6,655 6,590 
Miscellaneous206 206 624 602 
Total Retail6,536 6,682 20,132 20,199 
Wholesale644 1,414 1,269 3,636 
Total KWhs7,180 8,096 21,401 23,835 

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
 September 30,September 30,
2022202120222021
 (in degree days)
Actual – Heating (a)— 1,372 1,397 
Normal – Heating (b)1,410 1,404 
Actual – Cooling (c)876 945 1,299 1,330 
Normal – Cooling (b)832 831 1,210 1,214 

(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.

86



Third Quarter of 2022 Compared to Third Quarter of 2021
Appalachian Power Company and Subsidiaries
Reconciliation of Third Quarter of 2021 to Third Quarter of 2022
Net Income
(in millions)
Third Quarter of 2021$86.3 
  
Changes in Gross Margin: 
Retail Margins10.6 
Margins from Off-system Sales3.4 
Transmission Revenues3.4 
Other Revenues2.7 
Total Change in Gross Margin20.1 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(9.2)
Asset Impairments and Other Related Charges - Coal Fired Generation(24.9)
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset37.0 
Depreciation and Amortization(7.5)
Taxes Other Than Income Taxes(1.7)
Interest Income2.4 
Allowance for Equity Funds Used During Construction(2.1)
Non-Service Cost Components of Net Periodic Benefit Cost2.6 
Interest Expense(8.9)
Total Change in Expenses and Other(12.3)
  
Income Tax Expense(1.4)
  
Third Quarter of 2022$92.7 

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

Retail Margins increased $11 million primarily due to the following:
A $20 million increase due to rider revenues in Virginia and West Virginia. This increase was partially offset in other expense items below.
This increase was partially offset by:
A $6 million decrease in weather-normalized margins primarily driven by decreases in the residential and industrial classes.
A $5 million decrease in weather-related usage primarily driven by a 7% decrease in cooling degree days.
Margins from Off-System Sales increased $3 million primarily due to increased generation and strong market pricing.
Transmission Revenues increased $3 million primarily due to continued investment in transmission assets.


87



Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses increased $9 million primarily due to the following:
A $6 million increase in distribution expenses primarily due to storm restoration expenses.
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.
Asset Impairments and Other Related Charges - Coal Fired Generation increased $25 million due to a write-off of a regulatory asset in accordance with the August 2022 Virginia Supreme Court opinion related to the 2017-2019 Virginia Triennial Review.
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset increased $37 million due to the establishment of a regulatory asset in accordance with the August 2022 Virginia Supreme Court opinion and resulting under-earning during the 2017-2019 Triennial Review.
Depreciation and Amortization expenses increased $8 million primarily due to a higher depreciable base.
Interest Expense increased $9 million primarily due to higher long-term debt balances and higher interest rates.

88



Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021
Appalachian Power Company and Subsidiaries
Reconciliation of Nine Months Ended September 30, 2021 to Nine Months Ended September 30, 2022
Net Income
(in millions)
Nine Months Ended September 30, 2021$275.1 
 
Changes in Gross Margin: 
Retail Margins130.2 
Margins from Off-system Sales(0.6)
Transmission Revenues21.1 
Other Revenues7.2 
Total Change in Gross Margin157.9 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(102.1)
Asset Impairments and Other Related Charges - Coal Fired Generation(24.9)
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset37.0 
Depreciation and Amortization(24.4)
Taxes Other Than Income Taxes(4.3)
Interest Income2.2 
Allowance for Equity Funds Used During Construction(5.3)
Non-Service Cost Components of Net Periodic Benefit Cost7.6 
Interest Expense(10.5)
Total Change in Expenses and Other(124.7)
  
Income Tax Expense(5.2)
  
Nine Months Ended September 30, 2022$303.1 

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

Retail Margins increased $130 million primarily due to the following:
A $104 million increase due to rider revenues in Virginia and West Virginia. This increase was partially offset in other expense items below.
An $18 million increase due to lower customer refunds related to Tax Reform. This increase was offset in Income Tax Expense below.
A $13 million increase in weather-normalized margins primarily driven by increases in the residential and commercial classes.
These increases were partially offset by:
A $6 million decrease in weather-related usage primarily driven by a 2% decrease in cooling degree days and a 2% decrease in heating degree days.
Transmission Revenues increased $21 million primarily due to the following:
An $11 million increase due to continued investment in transmission assets.
A $10 million increase due to transmission formula rate true-up activity.
Other Revenues increased $7 million primarily due to business development revenue. This increase was partially offset in Other Operation and Maintenance expenses below.

89



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

Other Operation and Maintenance expenses increased $102 million primarily due to the following:
A $63 million increase in transmission expenses primarily due to an $80 million increase in recoverable PJM expenses, partially offset by an $11 million decrease in transmission formula rate true-up activity. These items were primarily offset in Retail Margins above.
A $24 million increase in maintenance expenses at various generation plants.
A $16 million increase in distribution expenses primarily related to storm restoration costs.
A $7 million increase in employee-related expenses.
These increases were partially offset by:
A $13 million decrease due to gains from the sale of land in 2022.
Asset Impairments and Other Related Charges - Coal Fired Generation increased $25 million due to a write-off of a regulatory asset in accordance with the August 2022 Virginia Supreme Court opinion related to the 2017-2019 Virginia Triennial Review.
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset increased $37 million due to the establishment of a regulatory asset in accordance with the August 2022 Virginia Supreme Court opinion and resulting under-earning during the 2017-2019 Triennial Review.
Depreciation and Amortization expenses increased $24 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $4 million primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
Allowance for Equity Funds Used During Construction decreased $5 million primarily due to a lower AFUDC base and a decrease in AFUDC equity rates.
Non-Service Cost Components of Net Periodic Benefit Cost decreased $8 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.
Interest Expense increased $11 million primarily due to higher long-term debt balances and higher interest rates.
Income Tax Expense increased $5 million primarily due to an increase in pretax book income and a decrease in amortization of Excess ADIT, partially offset by a decrease in state taxes and a favorable one-time adjustment recognized in 2022. The decrease in amortization of Excess ADIT was partially offset in Retail Margins above.





90





APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
 September 30,September 30,
 2022202120222021
REVENUES    
Electric Generation, Transmission and Distribution$818.4 $748.5 $2,370.4 $2,149.2 
Sales to AEP Affiliates67.6 52.4 187.6 140.6 
Other Revenues2.9 3.1 11.8 8.2 
TOTAL REVENUES888.9 804.0 2,569.8 2,298.0 
EXPENSES    
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation318.0 253.2 834.2 720.3 
Other Operation182.0 173.0 514.0 442.1 
Maintenance69.3 69.1 214.6 184.4 
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 Amortization142.9 135.4 431.0 406.6 
Taxes Other Than Income Taxes41.5 39.8 121.0 116.7 
TOTAL EXPENSES741.6 670.5 2,102.7 1,870.1 
OPERATING INCOME147.3 133.5 467.1 427.9 
Other Income (Expense):    
Interest Income2.6 0.2 3.0 0.8 
Allowance for Equity Funds Used During Construction2.2 4.3 6.8 12.1 
Non-Service Cost Components of Net Periodic Benefit Cost7.3 4.7 21.8 14.2 
Interest Expense(61.7)(52.8)(171.1)(160.6)
INCOME BEFORE INCOME TAX EXPENSE97.7 89.9 327.6 294.4 
Income Tax Expense5.0 3.6 24.5 19.3 
NET INCOME $92.7 $86.3 $303.1 $275.1 
The common stock of APCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
91



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
 September 30,September 30,
2022202120222021
Net Income$92.7 $86.3 $303.1 $275.1 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES  
Cash Flow Hedges, Net of Tax of $(0.1) and $0 for the Three Months Ended September 30, 2022 and 2021, Respectively, and $(0.2) and $2.3 for Nine Months Ended September 30, 2022 and 2021, Respectively
(0.2)(0.3)(0.6)8.5 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.3) and $(0.2) for the Three Months Ended September 30, 2022 and 2021, Respectively, and $(0.9) and $(0.8) for the Nine Months Ended September 30, 2022 and 2021, Respectively
(1.1)(1.0)(3.2)(3.1)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)(1.3)(1.3)(3.8)5.4 
TOTAL COMPREHENSIVE INCOME$91.4 $85.0 $299.3 $280.5 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
92



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
Common
Stock
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
TOTAL COMMON SHAREHOLDER’S
   EQUITY - DECEMBER 31, 2020
$260.4 $1,828.7 $2,248.0 $7.2 $4,344.3 
Common Stock Dividends(12.5)(12.5)
Net Income122.5 122.5 
Other Comprehensive Income7.9 7.9 
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2021260.4 1,828.7 2,358.0 15.1 4,462.2 
Common Stock Dividends (12.5) (12.5)
Net Income  66.3  66.3 
Other Comprehensive Loss   (1.2)(1.2)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2021260.4 1,828.7 2,411.8 13.9 4,514.8 
Common Stock Dividends(12.5)(12.5)
Net Income86.3 86.3 
Other Comprehensive Loss(1.3)(1.3)
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2021$260.4 $1,828.7 $2,485.6 $12.6 $4,587.3 
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2021$260.4 $1,828.7 $2,534.4 $24.4 $4,647.9 
Common Stock Dividends(18.8)(18.8)
Net Income120.2 120.2 
Other Comprehensive Loss(1.3)(1.3)
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2022260.4 1,828.7 2,635.8 23.1 4,748.0 
Capital Contribution from Parent2.82.8 
Common Stock Dividends(18.7)(18.7)
Net Income90.2 90.2 
Other Comprehensive Loss(1.2)(1.2)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2022260.4 1,831.5 2,707.3 21.9 4,821.1 
Capital Contribution from Parent1.51.5 
Net Income92.7 92.7 
Other Comprehensive Loss(1.3)(1.3)
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2022$260.4 $1,833.0 $2,800.0 $20.6 $4,914.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.

93



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2022 and December 31, 2021
(in millions)
(Unaudited)
September 30,December 31,
20222021
CURRENT ASSETS  
Cash and Cash Equivalents$6.7 $2.5 
Restricted Cash for Securitized Funding7.4 17.6 
Advances to Affiliates182.1 20.8 
Accounts Receivable:  
Customers133.7 158.5 
Affiliated Companies92.6 129.9 
Accrued Unbilled Revenues49.6 54.0 
Miscellaneous0.3 0.2 
Allowance for Uncollectible Accounts(1.5)(1.6)
Total Accounts Receivable274.7 341.0 
Fuel118.6 67.1 
Materials and Supplies120.4 109.8 
Risk Management Assets106.8 42.0 
Accrued Tax Benefits106.7 38.1 
Regulatory Asset for Under-Recovered Fuel Costs404.0 201.3 
Margin Deposits6.1 71.8 
Prepayments and Other Current Assets17.5 13.3 
TOTAL CURRENT ASSETS1,351.0 925.3 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation6,731.0 6,683.9 
Transmission4,445.2 4,322.4 
Distribution4,849.1 4,683.3 
Other Property, Plant and Equipment853.3 696.6 
Construction Work in Progress617.7 469.9 
Total Property, Plant and Equipment17,496.3 16,856.1 
Accumulated Depreciation and Amortization5,332.7 5,051.8 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET12,163.6 11,804.3 
OTHER NONCURRENT ASSETS  
Regulatory Assets970.3 757.6 
Securitized Assets165.9 185.1 
Employee Benefits and Pension Assets231.6 220.5 
Operating Lease Assets61.2 66.9 
Deferred Charges and Other Noncurrent Assets99.4 129.2 
TOTAL OTHER NONCURRENT ASSETS1,528.4 1,359.3 
TOTAL ASSETS$15,043.0 $14,088.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
94



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2022 and December 31, 2021
(Unaudited)
 September 30,December 31,
 20222021
 (in millions)
CURRENT LIABILITIES  
Advances from Affiliates$— $199.3 
Accounts Payable:  
General374.6 262.2 
Affiliated Companies168.2 118.6 
Long-term Debt Due Within One Year – Nonaffiliated351.8 480.7 
Customer Deposits76.8 73.9 
Accrued Taxes89.4 119.7 
Accrued Interest84.1 47.9 
Obligations Under Operating Leases14.4 15.1 
Other Current Liabilities116.8 98.5 
TOTAL CURRENT LIABILITIES1,276.1 1,415.9 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated5,158.0 4,458.2 
Deferred Income Taxes1,937.0 1,804.7 
Regulatory Liabilities and Deferred Investment Tax Credits1,218.4 1,238.8 
Asset Retirement Obligations418.8 394.9 
Employee Benefits and Pension Obligations40.2 41.5 
Obligations Under Operating Leases47.3 52.4 
Deferred Credits and Other Noncurrent Liabilities33.2 34.6 
TOTAL NONCURRENT LIABILITIES8,852.9 8,025.1 
TOTAL LIABILITIES10,129.0 9,441.0 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY  
Common Stock – No Par Value:
  
Authorized – 30,000,000 Shares
  
 Outstanding – 13,499,500 Shares
260.4 260.4 
Paid-in Capital1,833.0 1,828.7 
Retained Earnings2,800.0 2,534.4 
Accumulated Other Comprehensive Income (Loss)20.6 24.4 
TOTAL COMMON SHAREHOLDER’S EQUITY4,914.0 4,647.9 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$15,043.0 $14,088.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
95



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20222021
OPERATING ACTIVITIES  
Net Income$303.1 $275.1 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and Amortization431.0 406.6 
Deferred Income Taxes70.7 (12.0)
Asset Impairments and Other Related Charges - Coal Fired Generation24.9 — 
Allowance for Equity Funds Used During Construction(6.8)(12.1)
Mark-to-Market of Risk Management Contracts(65.6)(26.8)
Deferred Fuel Over/Under-Recovery, Net(400.2)(43.9)
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset(37.0)— 
Change in Other Noncurrent Assets(15.2)(39.2)
Change in Other Noncurrent Liabilities39.7 20.2 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net68.7 38.1 
Fuel, Materials and Supplies(61.7)126.3 
Margin Deposits65.8 (15.8)
Accounts Payable141.4 26.5 
Accrued Taxes, Net(98.9)(48.0)
Other Current Assets(4.2)(4.9)
Other Current Liabilities42.2 0.5 
Net Cash Flows from Operating Activities497.9 690.6 
INVESTING ACTIVITIES  
Construction Expenditures(707.4)(586.4)
Change in Advances to Affiliates, Net(161.3)(163.8)
Other Investing Activities34.9 12.4 
Net Cash Flows Used for Investing Activities(833.8)(737.8)
FINANCING ACTIVITIES  
Capital Contribution from Parent4.3 — 
Issuance of Long-term Debt – Nonaffiliated698.2 494.0 
Change in Advances from Affiliates, Net(199.3)(18.6)
Retirement of Long-term Debt – Nonaffiliated(130.4)(393.0)
Principal Payments for Finance Lease Obligations(5.9)(5.8)
Dividends Paid on Common Stock(37.5)(37.5)
Other Financing Activities0.5 0.5 
Net Cash Flows from Financing Activities329.9 39.6 
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding(6.0)(7.6)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period20.1 22.7 
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period$14.1 $15.1 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$128.3 $124.2 
Net Cash Paid for Income Taxes14.2 52.6 
Noncash Acquisitions Under Finance Leases1.0 1.3 
Construction Expenditures Included in Current Liabilities as of September 30,160.4 92.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
96





INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES
97



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
 September 30,September 30,
 2022202120222021
 (in millions of KWhs)
Retail:    
Residential1,532 1,531 4,320 4,244 
Commercial1,326 1,267 3,610 3,481 
Industrial1,926 1,853 5,638 5,542 
Miscellaneous12 13 39 42 
Total Retail4,796 4,664 13,607 13,309 
Wholesale1,707 1,610 4,892 5,055 
Total KWhs6,503 6,274 18,499 18,364 

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
 September 30,September 30,
 2022202120222021
 (in degree days)
Actual – Heating (a)17 2,525 2,343 
Normal – Heating (b)2,421 2,417 
Actual – Cooling (c)590 679 934 1,004 
Normal – Cooling (b)580 581 842 848 

(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.
98



Third Quarter of 2022 Compared to Third Quarter of 2021
Indiana Michigan Power Company and Subsidiaries
Reconciliation of Third Quarter of 2021 to Third Quarter of 2022
Net Income
(in millions)
Third Quarter of 2021$104.1 
  
Changes in Gross Margin: 
Retail Margins10.1 
Margins from Off-system Sales0.2 
Transmission Revenues1.2 
Other Revenues1.6 
Total Change in Gross Margin13.1 
  
Changes in Expenses and Other: 
Other Operation and Maintenance1.2 
Depreciation and Amortization(21.0)
Taxes Other Than Income Taxes5.4 
Other Income(0.1)
Non-Service Cost Components of Net Periodic Benefit Cost2.2 
Interest Expense(1.0)
Total Change in Expenses and Other(13.3)
  
Income Tax Expense(9.8)
  
Third Quarter of 2022$94.1 

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

Retail Margins increased $10 million primarily due to the following:
A $15 million increase primarily due to an increase in rider revenues. This increase was partially offset in other expense items below.
This increase was partially offset by:
A $7 million decrease in weather-related usage primarily due to a 13% decrease in cooling degree days.

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

Other Operation and Maintenance expenses decreased $1 million primarily due to the following:
A $17 million decrease in steam generation expenses primarily due to the modification of the Rockport Plant, Unit 2 lease, which resulted in a change in lease classification from an operating lease to a finance lease in December 2021. This decrease was partially offset in Depreciation and Amortization expenses below.

99



This decrease was partially offset by:
A $10 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses. This increase was partially offset in Retail Margins above.
A $6 million increase in nuclear expenses at Cook Plant primarily due to refueling outage expenses.
Depreciation and Amortization expenses increased $21 million primarily due to the modification of the Rockport Plant, Unit 2 lease, which resulted in a change in lease classification from an operating lease to a finance lease in December 2021 and a higher depreciable base. The increase resulting from the lease modification was partially offset in Other Operation and Maintenance expenses above.
Taxes Other Than Income Taxes decreased $5 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 Tax Expense increased $10 million primarily due to a decrease in amortization of Excess ADIT, a decrease in the benefit from investment tax credit amortization, and a decrease in parent company loss benefit.

100



Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021
Indiana Michigan Power Company and Subsidiaries
Reconciliation of Nine Months Ended September 30, 2021 to Nine Months Ended September 30, 2022
Net Income
(in millions)
Nine Months Ended September 30, 2021$232.1 
  
Changes in Gross Margin: 
Retail Margins52.4 
Margins from Off-system Sales0.4 
Transmission Revenues11.3 
Other Revenues6.2 
Total Change in Gross Margin70.3 
  
Changes in Expenses and Other: 
Other Operation and Maintenance29.2 
Depreciation and Amortization(71.5)
Taxes Other Than Income Taxes7.6 
Other Income(1.5)
Non-Service Cost Components of Net Periodic Benefit Cost6.5 
Interest Expense(5.9)
Total Change in Expenses and Other(35.6)
  
Income Tax Expense(16.0)
  
Nine Months Ended September 30, 2022$250.8 

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 $52 million primarily due to the following:
A $43 million increase due to increased rider revenues partially offset by lower wholesale true-ups. This increase was partially offset in other expense items below.
A $6 million increase in weather-normalized retail margins primarily in the commercial class.
Transmission Revenues increased $11 million primarily due to the following:
A $7 million increase due to transmission formula rate true-up activity.
A $4 million increase due to continued investment in transmission assets.
Other Revenues increased $6 million primarily due to a gain on sale of allowances and economic hedging activities. The gain on sale of allowances was partially offset in Retail Margins above.

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

Other Operation and Maintenance expenses decreased $29 million primarily due to the following:
A $54 million decrease in steam generation expenses primarily due to the modification of the Rockport Plant, Unit 2 lease, which resulted in a change in lease classification from an operating lease to a finance lease in December 2021. This decrease was partially offset in Depreciation and Amortization expenses below.
A $4 million decrease due to an increased Nuclear Electric Insurance Limited distribution in 2022.

101



These decreases were partially offset by:
A $14 million increase in nuclear expenses at Cook Plant primarily due to refueling outage expenses.
A $13 million increase in transmission expenses primarily due to the following:
A $31 million increase in recoverable PJM expenses. These expenses were offset in Retail Margins above.
This increase was partially offset by:
A $9 million decrease in transmission vegetation management expenses.
A $7 million decrease in transmission formula rate true-up activity.
Depreciation and Amortization expenses increased $72 million primarily due to the modification of the Rockport Plant, Unit 2 lease, which resulted in a change in lease classification from an operating lease to a finance lease in December 2021, and a higher depreciable base. The increase resulting from the lease modification was partially offset in Other Operation and Maintenance expenses above.
Taxes Other Than Income Taxes decreased $8 million primarily due to the repeal of the Indiana Utility Receipts Tax in July 2022. This decrease was partially offset in Retail Margins above.
Non-Service Cost Components of Net Periodic Benefit Cost decreased $7 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.
Interest Expense increased $6 million primarily due to a debt issuance in April 2021.
Income Tax Expense increased $16 million primarily due to an increase in pretax book income, a decrease in the benefit from investment tax credit amortization, and a decrease in parent company loss benefit.

102




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
 September 30,September 30,
 2022202120222021
REVENUES    
Electric Generation, Transmission and Distribution$695.7 $618.2 $1,912.1 $1,735.1 
Sales to AEP Affiliates2.0 1.1 11.1 2.6 
Other Revenues – Affiliated13.3 14.7 38.4 41.2 
Other Revenues – Nonaffiliated4.4 1.7 10.0 5.1 
TOTAL REVENUES715.4 635.7 1,971.6 1,784.0 
EXPENSES    
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation150.6 88.6 367.2 261.8 
Purchased Electricity from AEP Affiliates67.9 63.3 184.6 172.7 
Other Operation162.4 167.5 450.9 482.4 
Maintenance55.9 52.0 167.7 165.4 
Depreciation and Amortization131.6 110.6 400.2 328.7 
Taxes Other Than Income Taxes22.4 27.8 76.2 83.8 
TOTAL EXPENSES590.8 509.8 1,646.8 1,494.8 
OPERATING INCOME 124.6 125.9 324.8 289.2 
Other Income (Expense):    
Other Income2.4 2.5 7.4 8.9 
Non-Service Cost Components of Net Periodic Benefit Cost6.3 4.1 18.8 12.3 
Interest Expense(31.2)(30.2)(92.5)(86.6)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)102.1 102.3 258.5 223.8 
Income Tax Expense (Benefit)8.0 (1.8)7.7 (8.3)
NET INCOME $94.1 $104.1 $250.8 $232.1 
The common stock of I&M is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
103



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
 Three Months Ended Nine Months Ended
 September 30,September 30,
2022202120222021
Net Income$94.1 $104.1 $250.8 $232.1 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES   
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended September 30, 2022 and 2021, Respectively, and $0.3 and $0.3 for the Nine Months Ended September 30, 2022 and 2021, Respectively
0.4 0.4 1.2 1.3 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $0 for the Three Months Ended September 30, 2022 and 2021, Respectively, and $(0.1) and $0 for the Nine Months Ended September 30, 2022 and 2021, Respectively
(0.1)— (0.3)(0.1)
TOTAL OTHER COMPREHENSIVE INCOME0.3 0.4 0.9 1.2 
TOTAL COMPREHENSIVE INCOME$94.4 $104.5 $251.7 $233.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
104



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
Common
Stock
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2020
$56.6 $980.9 $1,718.7 $(7.0)$2,749.2 
Common Stock Dividends  (25.0) (25.0)
Net Income  70.8  70.8 
Other Comprehensive Income   0.5 0.5 
TOTAL COMMON SHAREHOLDER'S EQUITY -MARCH 31, 202156.6 980.9 1,764.5 (6.5)2,795.5 
Common Stock Dividends(75.0)(75.0)
Net Income57.2 57.2 
Other Comprehensive Income0.3 0.3 
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 202156.6 980.9 1,746.7 (6.2)2,778.0 
Common Stock Dividends(75.0)(75.0)
Net Income104.1 104.1 
Other Comprehensive Income0.4 0.4 
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2021$56.6 $980.9 $1,775.8 $(5.8)$2,807.5 
     
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2021
$56.6 $980.9 $1,748.5 $(1.3)$2,784.7 
Common Stock Dividends(25.0)(25.0)
Net Income89.5 89.5 
Other Comprehensive Income0.3 0.3 
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 202256.6 980.9 1,813.0 (1.0)2,849.5 
Capital Contribution from Parent1.3 1.3 
Common Stock Dividends  (25.0) (25.0)
Net Income  67.2  67.2 
Other Comprehensive Income   0.3 0.3 
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 202256.6 982.2 1,855.2 (0.7)2,893.3 
Capital Contribution from Parent0.60.6 
Common Stock Dividends(20.0)(20.0)
Net Income94.1 94.1 
Other Comprehensive Income0.3 0.3 
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2022$56.6 $982.8 $1,929.3 $(0.4)$2,968.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
105



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2022 and December 31, 2021
(in millions)
(Unaudited)
September 30,December 31,
 20222021
CURRENT ASSETS  
Cash and Cash Equivalents$25.8 $1.3 
Advances to Affiliates22.6 21.5 
Accounts Receivable:  
Customers40.8 40.6 
Affiliated Companies72.7 78.2 
Accrued Unbilled Revenues0.4 — 
Miscellaneous3.4 2.5 
Allowance for Uncollectible Accounts— (0.1)
Total Accounts Receivable117.3 121.2 
Fuel49.5 56.8 
Materials and Supplies179.4 175.2 
Regulatory Asset for Under-Recovered Fuel Costs25.4 6.4 
Prepayments and Other Current Assets50.0 57.0 
TOTAL CURRENT ASSETS470.0 439.4 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation5,601.6 5,531.8 
Transmission1,823.9 1,783.1 
Distribution2,955.9 2,800.1 
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)854.6 792.9 
Construction Work in Progress314.7 302.8 
Total Property, Plant and Equipment11,550.7 11,210.7 
Accumulated Depreciation, Depletion and Amortization4,161.3 3,899.8 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET7,389.4 7,310.9 
OTHER NONCURRENT ASSETS  
Regulatory Assets422.5 410.9 
Spent Nuclear Fuel and Decommissioning Trusts3,130.5 3,867.0 
Operating Lease Assets51.9 63.5 
Deferred Charges and Other Noncurrent Assets278.5 316.5 
TOTAL OTHER NONCURRENT ASSETS3,883.4 4,657.9 
TOTAL ASSETS$11,742.8 $12,408.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
106



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2022 and December 31, 2021
(dollars in millions)
(Unaudited)
 September 30,December 31,
 20222021
CURRENT LIABILITIES  
Advances from Affiliates$104.9 $93.3 
Accounts Payable:  
General187.3 174.4 
Affiliated Companies94.0 94.9 
Long-term Debt Due Within One Year – Nonaffiliated
   (September 30, 2022 and December 31, 2021 Amounts Include $68.8 and $65,
   Respectively, Related to DCC Fuel)
320.9 67.0 
Customer Deposits43.0 45.2 
Accrued Taxes76.9 106.5 
Accrued Interest24.5 37.0 
Obligations Under Finance Leases94.1 130.5 
Obligations Under Operating Leases11.3 15.5 
Regulatory Liability for Over-Recovered Fuel Costs— 1.5 
Other Current Liabilities92.5 128.2 
TOTAL CURRENT LIABILITIES1,049.4 894.0 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated2,885.8 3,128.0 
Deferred Income Taxes1,143.6 1,100.2 
Regulatory Liabilities and Deferred Investment Tax Credits1,577.0 2,447.9 
Asset Retirement Obligations2,009.8 1,946.2 
Obligations Under Operating Leases41.6 48.9 
Deferred Credits and Other Noncurrent Liabilities67.3 58.3 
TOTAL NONCURRENT LIABILITIES7,725.1 8,729.5 
TOTAL LIABILITIES8,774.5 9,623.5 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY  
Common Stock – No Par Value:
  
Authorized – 2,500,000 Shares
  
Outstanding – 1,400,000 Shares
56.6 56.6 
Paid-in Capital982.8 980.9 
Retained Earnings1,929.3 1,748.5 
Accumulated Other Comprehensive Income (Loss)(0.4)(1.3)
TOTAL COMMON SHAREHOLDER’S EQUITY2,968.3 2,784.7 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$11,742.8 $12,408.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
107



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20222021
OPERATING ACTIVITIES  
Net Income$250.8 $232.1 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: 
Depreciation and Amortization400.2 328.7 
Rockport Plant, Unit 2 Operating Lease Amortization— 51.1 
Deferred Income Taxes(15.8)(36.6)
Deferral of Incremental Nuclear Refueling Outage Expenses, Net(35.2)(2.5)
Allowance for Equity Funds Used During Construction(7.9)(9.7)
Mark-to-Market of Risk Management Contracts(13.2)0.5 
Amortization of Nuclear Fuel63.1 61.9 
Deferred Fuel Over/Under-Recovery, Net(20.5)(18.0)
Change in Other Noncurrent Assets12.5 7.3 
Change in Other Noncurrent Liabilities42.1 (10.2)
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net5.3 18.2 
Fuel, Materials and Supplies3.1 43.0 
Accounts Payable19.6 20.1 
Accrued Taxes, Net(17.0)(20.3)
Rockport Plant, Unit 2 Operating Lease Payments— (36.9)
Other Current Assets19.3 (0.7)
Other Current Liabilities(63.6)(28.0)
Net Cash Flows from Operating Activities642.8 600.0 
INVESTING ACTIVITIES  
Construction Expenditures(407.4)(370.2)
Change in Advances to Affiliates, Net(1.1)(67.3)
Purchases of Investment Securities(1,854.8)(1,586.3)
Sales of Investment Securities1,818.4 1,556.6 
Acquisitions of Nuclear Fuel(91.9)(63.2)
Other Investing Activities8.0 12.9 
Net Cash Flows Used for Investing Activities(528.8)(517.5)
FINANCING ACTIVITIES  
Capital Contribution from Parent1.9 — 
Issuance of Long-term Debt – Nonaffiliated72.8 507.0 
Change in Advances from Affiliates, Net11.6 (103.0)
Retirement of Long-term Debt – Nonaffiliated(64.5)(307.2)
Principal Payments for Finance Lease Obligations(41.6)(4.9)
Dividends Paid on Common Stock(70.0)(175.0)
Other Financing Activities0.3 0.5 
Net Cash Flows Used for Financing Activities(89.5)(82.6)
Net Increase (Decrease) in Cash and Cash Equivalents24.5 (0.1)
Cash and Cash Equivalents at Beginning of Period1.3 3.3 
Cash and Cash Equivalents at End of Period$25.8 $3.2 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$101.6 $93.9 
Net Cash Paid (Received) for Income Taxes(4.1)11.8 
Noncash Acquisitions Under Finance Leases0.8 3.1 
Construction Expenditures Included in Current Liabilities as of September 30,68.1 59.0 
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,8.5 0.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
108





OHIO POWER COMPANY AND SUBSIDIARIES

109



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
 September 30,September 30,
2022202120222021
 (in millions of KWhs)
Retail:    
Residential3,954 4,096 11,146 11,261 
Commercial4,295 4,112 11,996 11,282 
Industrial3,561 3,633 10,688 10,769 
Miscellaneous25 25 79 80 
Total Retail (a)11,835 11,866 33,909 33,392 
Wholesale (b)587 643 1,723 1,691 
Total KWhs12,422 12,509 35,632 35,083 

(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
 September 30,September 30,
2022202120222021
 (in degree days)
Actual – Heating (a)2,078 1,993 
Normal – Heating (b)2,077 2,071 
Actual – Cooling (c)755 787 1,115 1,148 
Normal – Cooling (b)688 689 989 996 

(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.
110



Third Quarter of 2022 Compared to Third Quarter of 2021
Ohio Power Company and Subsidiaries
Reconciliation of Third Quarter of 2021 to Third Quarter of 2022
Net Income
(in millions)
Third Quarter of 2021$56.4 
  
Changes in Gross Margin: 
Retail Margins31.0 
Margins from Off-system Sales21.8 
Transmission Revenues2.1 
Other Revenues(12.6)
Total Change in Gross Margin42.3 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(30.7)
Depreciation and Amortization6.2 
Taxes Other Than Income Taxes(5.0)
Carrying Costs Income(0.1)
Allowance for Equity Funds Used During Construction1.9 
Non-Service Cost Components of Net Periodic Benefit Cost1.9 
Interest Expense3.1 
Total Change in Expenses and Other(22.7)
  
Income Tax Expense(4.1)
  
Third Quarter of 2022$71.9 

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

Retail Margins increased $31 million primarily due to the following:
A $21 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 $4 million increase in weather-related usage primarily due to the end of decoupling.
Margins from Off-system Sales increased $22 million primarily due to the following:
A $17 million increase in off-system sales at OVEC due to higher market prices. This increase was offset in Retail Margins above and Other Revenues below.
A $5 million increase in deferrals of OVEC costs. This increase was offset in Retail Margins above and Other Revenues below.
Other Revenues decreased $13 million primarily due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs. This decrease was offset in Retail Margins and Margins from Off-system Sales above.

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

Other Operation and Maintenance expenses increased $31 million primarily due to the following:
A $14 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses. This increase was offset in Retail Margins above.
111



A $5 million increase in remitted Universal Service Fund surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset in Retail Margins above.
A $5 million increase in recoverable distribution expenses primarily related to vegetation management. This increase was offset in Retail Margins above.
Depreciation and Amortization expenses decreased $6 million primarily due to a decrease in recoverable Distribution Investment Rider depreciable expenses. This decrease was offset in Retail Margins above.
Taxes Other Than Income Taxes increased $5 million primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
Interest Expense decreased $3 million primarily due to the retirement of a higher rate bond partially offset by the issuance of a lower rate bond in 2021.
Income Tax Expense increased $4 million primarily due to an increase in pretax book income.
112



Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021
Ohio Power Company and Subsidiaries
Reconciliation of Nine Months Ended September 30, 2021 to Nine Months Ended September 30, 2022
Net Income
(in millions)
Nine Months Ended September 30, 2021$198.6 
  
Changes in Gross Margin: 
Retail Margins138.7 
Margins from Off-system Sales47.8 
Transmission Revenues(3.2)
Other Revenues(28.8)
Total Change in Gross Margin154.5 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(125.6)
Depreciation and Amortization11.7 
Taxes Other Than Income Taxes(12.8)
Interest Income0.3 
Carrying Costs Income(0.9)
Allowance for Equity Funds Used During Construction2.7 
Non-Service Cost Components of Net Periodic Benefit Cost5.6 
Interest Expense7.4 
Total Change in Expenses and Other(111.6)
  
Income Tax Expense(12.4)
Equity Earnings of Unconsolidated Subsidiaries0.8 
  
Nine Months Ended September 30, 2022$229.9 

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

Retail Margins increased $139 million primarily due to the following:
An $85 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 $25 million increase due to various rider revenues. This increase was partially offset in Margins from Off-system Sales, Other Revenues, and other expense items below.
A $12 million increase in weather-normalized margins primarily from the commercial class, partially offset by the residential and industrial classes.
An $8 million increase in weather-related usage primarily due to the end of decoupling.
Margins from Off-system Sales increased $48 million primarily due to the following:
A $54 million increase in off-system sales at OVEC due to higher market prices and volume. This increase was offset in Retail Margins above and Other Revenues below.
This increase was partially offset by:
A $6 million decrease in deferrals of OVEC costs. This decrease was offset in Retail Margins above and Other Revenues below.
Transmission Revenues decreased $3 million primarily due to the following:
An $11 million decrease due to formula rate true-up activity.

113



This decrease was partially offset by:
A $7 million increase due to continued investment in transmission assets.
Other Revenues decreased $29 million primarily due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs. This decrease was offset in Retail Margins and Margins from Off-system Sales above.

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

Other Operation and Maintenance expenses increased $126 million primarily due to the following:
A $67 million increase in transmission expenses primarily due to the following:
A $67 million increase in recoverable PJM expenses. This increase was offset in Retail Margins above.
A $6 million increase in transmission vegetation management expenses.
These increases were partially offset by:
A $10 million decrease in transmission formula rate true-up activity.
A $19 million increase in bad debt-related expenses, including $8 million in 2022 due to Bad Debt Rider over-recovery. This increase was offset in Retail Margins above.
A $15 million increase in recoverable distribution expenses primarily related to vegetation management. This increase was offset in Retail Margins above.
A $14 million increase in remitted Universal Service Fund surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset in Retail Margins above.
A $10 million increase in employee-related expenses.
Depreciation and Amortization expenses decreased $12 million primarily due to the following:
A $6 million decrease in recoverable smart grid depreciable expenses. This decrease was offset in Retail Margins above.
A $6 million decrease in recoverable Distributions Investment Rider depreciable expenses. This decrease was partially offset in Retail Margins above.
Taxes Other Than Income Taxes increased $13 million primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
Non-Service Cost Components of Net Periodic Benefit Cost decreased $6 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.
Interest Expense decreased $7 million primarily due to the retirement of a higher rate bond partially offset by the issuance of a lower rate bond in 2021.
Income Tax Expense increased $12 million primarily due to an increase in pretax book income and a favorable 2021 discrete tax adjustment that did not recur during 2022.

114




OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
 September 30,September 30,
 2022202120222021
REVENUES    
Electricity, Transmission and Distribution$1,015.2 $761.0 $2,656.6 $2,167.8 
Sales to AEP Affiliates4.0 4.3 11.6 21.9 
Other Revenues2.1 2.4 6.0 6.8 
TOTAL REVENUES1,021.3 767.7 2,674.2 2,196.5 
EXPENSES    
Purchased Electricity for Resale399.5 184.7 875.0 513.6 
Purchased Electricity from AEP Affiliates— 3.5 9.8 48.0 
Other Operation267.3 245.1 728.2 622.9 
Maintenance47.8 39.3 136.7 116.4 
Depreciation and Amortization70.7 76.9 216.9 228.6 
Taxes Other Than Income Taxes131.0 126.0 379.0 366.2 
TOTAL EXPENSES916.3 675.5 2,345.6 1,895.7 
OPERATING INCOME105.0 92.2 328.6 300.8 
Other Income (Expense):    
Interest Income0.2 0.2 0.8 0.5 
Carrying Costs Income— 0.1 0.2 1.1 
Allowance for Equity Funds Used During Construction3.9 2.0 10.3 7.6 
Non-Service Cost Components of Net Periodic Benefit Cost5.6 3.7 16.6 11.0 
Interest Expense(29.8)(32.9)(88.8)(96.2)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS84.9 65.3 267.7 224.8 
Income Tax Expense13.0 8.9 38.6 26.2 
Equity Earnings of Unconsolidated Subsidiaries— — 0.8 — 
NET INCOME$71.9 $56.4 $229.9 $198.6 
The common stock of OPCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
115



OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
Common
Stock
Paid-in
Capital
Retained
Earnings
Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020
$321.2 $838.8 $1,532.7 $2,692.7 
Common Stock Dividends(21.9)(21.9)
Net Income68.2 68.2 
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2021
321.2 838.8 1,579.0 2,739.0 
Common Stock Dividends  (21.9)(21.9)
Net Income  74.0 74.0 
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2021
321.2 838.8 1,631.1 2,791.1 
Common Stock Dividends(28.1)(28.1)
Net Income56.4 56.4 
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2021
$321.2 $838.8 $1,659.4 $2,819.4 
    
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2021
$321.2 $838.8 $1,686.3 $2,846.3 
Common Stock Dividends(15.0)(15.0)
Net Income83.2 83.2 
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2022
321.2 838.8 1,754.5 2,914.5 
Capital Contribution from Parent0.7 0.7 
Common Stock Dividends  (15.0)(15.0)
Net Income  74.8 74.8 
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2022
321.2 839.5 1,814.3 2,975.0 
Capital Contribution from Parent0.30.3
Common Stock Dividends(15.0)(15.0)
Net Income71.9 71.9 
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2022
$321.2 $839.8 $1,871.2 $3,032.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
116



OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2022 and December 31, 2021
(in millions)
(Unaudited)
 September 30,December 31,
 20222021
CURRENT ASSETS  
Cash and Cash Equivalents$10.2 $3.0 
Advances to Affiliates— 42.0 
Accounts Receivable:  
Customers60.3 71.6 
Affiliated Companies105.9 71.8 
Accrued Unbilled Revenues14.4 1.3 
Miscellaneous0.2 5.9 
Allowance for Uncollectible Accounts(0.1)(0.6)
Total Accounts Receivable180.7 150.0 
Materials and Supplies97.8 74.1 
Renewable Energy Credits33.6 30.5 
Prepayments and Other Current Assets27.2 27.9 
TOTAL CURRENT ASSETS349.5 327.5 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Transmission3,070.4 2,992.8 
Distribution6,336.9 6,070.6 
Other Property, Plant and Equipment1,038.7 992.9 
Construction Work in Progress491.6 365.0 
Total Property, Plant and Equipment10,937.6 10,421.3 
Accumulated Depreciation and Amortization2,541.6 2,458.3 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET8,396.0 7,963.0 
OTHER NONCURRENT ASSETS  
Regulatory Assets270.8 293.0 
Operating Lease Assets74.4 81.2 
Deferred Charges and Other Noncurrent Assets334.4 601.1 
TOTAL OTHER NONCURRENT ASSETS679.6 975.3 
TOTAL ASSETS$9,425.1 $9,265.8 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
117



OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2022 and December 31, 2021
(Unaudited)
 September 30,December 31,
 20222021
(in millions)
CURRENT LIABILITIES  
Advances from Affiliates$68.8 $— 
Accounts Payable:  
General314.9 213.5 
Affiliated Companies126.6 125.4 
Long-term Debt Due Within One Year – Nonaffiliated0.1 0.1 
Risk Management Liabilities— 6.7 
Customer Deposits103.8 66.4 
Accrued Taxes367.0 702.4 
Obligations Under Operating Leases13.5 13.1 
Other Current Liabilities159.5 118.1 
TOTAL CURRENT LIABILITIES1,154.2 1,245.7 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated2,969.8 2,968.4 
Long-term Risk Management Liabilities45.1 85.8 
Deferred Income Taxes1,053.2 1,000.9 
Regulatory Liabilities and Deferred Investment Tax Credits1,049.3 1,020.9 
Obligations Under Operating Leases60.6 68.6 
Deferred Credits and Other Noncurrent Liabilities60.7 29.2 
TOTAL NONCURRENT LIABILITIES5,238.7 5,173.8 
TOTAL LIABILITIES6,392.9 6,419.5 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY  
Common Stock –No Par Value:
  
Authorized – 40,000,000 Shares
  
Outstanding – 27,952,473 Shares
321.2 321.2 
Paid-in Capital839.8 838.8 
Retained Earnings1,871.2 1,686.3 
TOTAL COMMON SHAREHOLDER’S EQUITY3,032.2 2,846.3 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$9,425.1 $9,265.8 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
118



OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20222021
OPERATING ACTIVITIES  
Net Income$229.9 $198.6 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and Amortization216.9 228.6 
Deferred Income Taxes29.3 29.3 
Allowance for Equity Funds Used During Construction(10.3)(7.6)
Mark-to-Market of Risk Management Contracts(49.6)(19.9)
Property Taxes264.7 234.9 
Change in Other Noncurrent Assets(19.7)(1.1)
Change in Other Noncurrent Liabilities82.5 4.6 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net(27.0)20.7 
Materials and Supplies(11.6)(0.6)
Accounts Payable87.6 (19.1)
Customer Deposits37.4 68.4 
Accrued Taxes, Net(344.5)(289.7)
Other Current Assets11.3 (7.8)
Other Current Liabilities25.7 5.8 
Net Cash Flows from Operating Activities522.6 445.1 
INVESTING ACTIVITIES  
Construction Expenditures(600.6)(536.6)
Change in Advances to Affiliates, Net42.0 (622.9)
Other Investing Activities21.3 10.7 
Net Cash Flows Used for Investing Activities(537.3)(1,148.8)
FINANCING ACTIVITIES  
Capital Contribution from Parent1.0 — 
Issuance of Long-term Debt – Nonaffiliated— 1,037.5 
Change in Advances from Affiliates, Net68.8 (259.2)
Retirement of Long-term Debt – Nonaffiliated(0.1)(0.1)
Principal Payments for Finance Lease Obligations(3.6)(3.7)
Dividends Paid on Common Stock(45.0)(71.9)
Other Financing Activities0.8 0.5 
Net Cash Flows from Financing Activities21.9 703.1 
Net Increase (Decrease) in Cash and Cash Equivalents7.2 (0.6)
Cash and Cash Equivalents at Beginning of Period3.0 7.4 
Cash and Cash Equivalents at End of Period$10.2 $6.8 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$75.8 $78.6 
Net Cash Paid for Income Taxes24.2 0.3 
Noncash Acquisitions Under Finance Leases2.1 1.4 
Construction Expenditures Included in Current Liabilities as of September 30,108.3 66.5 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
119





PUBLIC SERVICE COMPANY OF OKLAHOMA
120



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
 September 30,September 30,
2022202120222021
 (in millions of KWhs)
Retail:    
Residential2,293 2,179 5,320 5,068 
Commercial1,547 1,476 3,976 3,781 
Industrial1,616 1,566 4,567 4,383 
Miscellaneous377 355 993 935 
Total Retail5,833 5,576 14,856 14,167 
Wholesale55 162 660 350 
Total KWhs5,888 5,738 15,516 14,517 

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
 September 30,September 30,
2022202120222021
 (in degree days)
Actual – Heating (a)— — 1,153 1,195 
Normal – Heating (b)— 1,085 1,078 
Actual – Cooling (c)1,678 1,491 2,475 2,075 
Normal – Cooling (b)1,407 1,404 2,074 2,079 

(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.
121



Third Quarter of 2022 Compared to Third Quarter of 2021
Public Service Company of Oklahoma
Reconciliation of Third Quarter of 2021 to Third Quarter of 2022
Net Income
(in millions)
Third Quarter of 2021$93.2 
Changes in Gross Margin:
Retail Margins (a)26.3 
Transmission Revenues0.5 
Other Revenues(0.1)
Total Change in Gross Margin26.7 
Changes in Expenses and Other: 
Other Operation and Maintenance(24.1)
Depreciation and Amortization(10.6)
Taxes Other Than Income Taxes(3.5)
Other Income1.2 
Non-Service Cost Components of Net Periodic Benefit Cost1.0 
Interest Expense(6.2)
Total Change in Expenses and Other(42.2)
  
Income Tax Benefit29.2 
  
Third Quarter of 2022$106.9 

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

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

Retail Margins increased $26 million primarily due to the following:
A $47 million increase due to a $26 million increase in base rate revenues and a $21 million increase in rider revenues. These increases were partially offset in other expense items below.
An $11 million increase in weather-related usage primarily due to a 13% increase in cooling degree days.
These increases were partially offset by:
A $33 million decrease resulting from the NCWF PTC benefits provided to customers through fuel clause mechanisms. This decrease was partially offset in Income Tax Benefit below.

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

Other Operation and Maintenance expenses increased $24 million primarily due to the following:
An $8 million increase in distribution expenses primarily due to an increase in overhead line maintenance.
A $7 million increase in transmission expenses primarily due to the following:
A $36 million increase related to a change in rider recovery, increased transmission investment and increased load.
A $4 million increase in transmission formula rate true-up activity. This increase was partially offset in Retail Margins above.

122



These increases were partially offset by:
A $33 million decrease in recoverable SPP transmission expenses. This decrease was offset in Retail Margins above.
A $3 million increase primarily due to an increase in maintenance expenses at the NCWF.
A $3 million increase due to pre-construction costs associated with various renewable projects.
Depreciation and Amortization increased $11 million primarily due to a higher depreciable base, implementation of new rates and the timing of refunds to customers under rate rider mechanisms.
Taxes Other Than Income Taxes increased $4 million primarily due to a new infrastructure fee implemented by the City of Tulsa in March 2022 and increased property taxes. This increase was partially offset in Retail Margins above.
Interest Expense increased $6 million primarily due to higher long-term debt balances.
Income Tax Benefit increased $29 million primarily due to an increase in PTCs. This increase was partially offset in Retail Margins above.


123



Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021
Public Service Company of Oklahoma
Reconciliation of Nine Months Ended September 30, 2021 to Nine Months Ended September 30, 2022
Net Income
(in millions)
Nine Months Ended September 30, 2021$136.6 
  
Changes in Gross Margin: 
Retail Margins (a)82.0 
Transmission Revenues(1.1)
Total Change in Gross Margin80.9 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(58.2)
Depreciation and Amortization(23.7)
Taxes Other Than Income Taxes(6.5)
Other Income4.0 
Non-Service Cost Components of Net Periodic Benefit Cost3.0 
Interest Expense(17.9)
Total Change in Expenses and Other(99.3)
  
Income Tax Benefit37.5 
  
Nine Months Ended September 30, 2022$155.7 
(a)Includes firm wholesale sales to municipals and cooperatives.

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

Retail Margins increased $82 million primarily due to the following:
A $95 million increase due to a $51 million increase in base rate revenues and a $44 million increase in rider revenues. These increases were partially offset in other expense items below.
A $21 million increase in weather-related usage primarily due to a 19% increase in cooling degree days.
A $12 million increase in weather-normalized margins primarily in the commercial and industrial classes.
These increases were partially offset by:
A $46 million decrease resulting from the NCWF PTC benefits provided to customers through fuel clause mechanisms. This decrease was partially offset in Income Tax Benefit below.

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

Other Operation and Maintenance expenses increased $58 million primarily due to the following:
An $18 million increase in transmission expenses primarily due to the following:
A $79 million increase due to a change in rider recovery, increased transmission investment and increased load.
This increase was partially offset by:
A $58 million decrease in recoverable SPP transmission expenses. This decrease was offset in Retail Margins above.
A $3 million decrease in transmission formula rate true-up activity. This decrease was partially offset in Retail Margins above.
A $16 million increase in distribution expenses primarily due to an increase in overhead line maintenance.
A $15 million increase in generating expenses primarily due to an increase in maintenance expenses at the NCWF and Northeastern.
124



Depreciation and Amortization expenses increased $24 million primarily due to a higher depreciable base, implementation of new rates and the timing of refunds to customers under rate rider mechanisms.
Taxes Other Than Income Taxes increased $7 million primarily due to a new infrastructure fee implemented by the City of Tulsa in March 2022 and increased property taxes. This increase was partially offset in Retail Margins above.
Other Income increased $4 million primarily related to carrying charges on regulatory assets resulting from the February 2021 severe winter weather event.
Interest Expense increased $18 million due to higher long-term debt balances.
Income Tax Benefit increased $38 million primarily due to an increase in PTCs. This increase was partially offset in Retail Margins above.
125




PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
 September 30,September 30,
 2022202120222021
REVENUES    
Electric Generation, Transmission and Distribution$606.5 $481.3 $1,432.9 $1,117.4 
Sales to AEP Affiliates0.7 1.0 2.1 3.1 
Other Revenues1.0 1.5 3.7 3.9 
TOTAL REVENUES608.2 483.8 1,438.7 1,124.4 
EXPENSES    
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation293.6 195.9 674.2 440.8 
Other Operation116.3 102.3 301.0 262.7 
Maintenance31.3 21.2 88.0 68.1 
Depreciation and Amortization59.5 48.9 172.7 149.0 
Taxes Other Than Income Taxes15.6 12.1 43.6 37.1 
TOTAL EXPENSES516.3 380.4 1,279.5 957.7 
OPERATING INCOME91.9 103.4 159.2 166.7 
Other Income (Expense):    
Other Income3.0 1.8 8.5 4.5 
Non-Service Cost Components of Net Periodic Benefit Cost3.1 2.1 9.4 6.4 
Interest Expense(22.4)(16.2)(62.6)(44.7)
INCOME BEFORE INCOME TAX BENEFIT75.6 91.1 114.5 132.9 
Income Tax Benefit(31.3)(2.1)(41.2)(3.7)
NET INCOME$106.9 $93.2 $155.7 $136.6 
The common stock of PSO is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
126



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
 September 30,September 30,
2022202120222021
Net Income$106.9 $93.2 $155.7 $136.6 
OTHER COMPREHENSIVE LOSS, NET OF TAXES    
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2022 and 2021, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2022 and 2021, Respectively
— — — (0.1)
    
TOTAL COMPREHENSIVE INCOME$106.9 $93.2 $155.7 $136.5 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
127



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
Common
Stock
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2020$157.2 $414.0 $974.3 $0.1 $1,545.6 
Capital Contribution from Parent425.0 425.0 
Net Loss(2.7)(2.7)
Other Comprehensive Loss(0.1)(0.1)
TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2021157.2 839.0 971.6 — 1,967.8 
Capital Contribution from Parent200.0200.0 
Common Stock Dividends(10.0)(10.0)
Net Income  46.1  46.1 
TOTAL COMMON SHAREHOLDER'S EQUITY – JUNE 30, 2021157.2 1,039.0 1,007.7 — 2,203.9 
     
Common Stock Dividends(10.0)(10.0)
Net Income93.2 93.2 
TOTAL COMMON SHAREHOLDER'S EQUITY – SEPTEMBER 30, 2021$157.2 $1,039.0 $1,090.9 $— $2,287.1 
TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2021$157.2 $1,039.0 $1,095.4 $— $2,291.6 
Net Income5.8 5.8 
TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2022157.2 1,039.0 1,101.2 — 2,297.4 
Capital Contribution from Parent2.2 2.2 
Net Income  43.0  43.0 
TOTAL COMMON SHAREHOLDER'S EQUITY – JUNE 30, 2022157.2 1,041.2 1,144.2 — 2,342.6 
Capital Contribution from Parent1.11.1 
Common Stock Dividends(20.0)(20.0)
Net Income106.9 106.9 
TOTAL COMMON SHAREHOLDER'S EQUITY – SEPTEMBER 30, 2022$157.2 $1,042.3 $1,231.1 $— $2,430.6 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.

128



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
September 30, 2022 and December 31, 2021
(in millions)
(Unaudited)
 September 30,December 31,
 20222021
CURRENT ASSETS  
Cash and Cash Equivalents$5.5 $1.3 
Accounts Receivable:  
Customers44.2 41.5 
Affiliated Companies93.5 35.0 
Miscellaneous5.7 0.6 
Total Accounts Receivable143.4 77.1 
Fuel8.4 14.5 
Materials and Supplies89.0 56.2 
Risk Management Assets44.5 12.1 
Accrued Tax Benefits66.4 17.6 
Regulatory Asset for Under-Recovered Fuel Costs178.7 194.6 
Prepayments and Other Current Assets32.8 13.4 
TOTAL CURRENT ASSETS568.7 386.8 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation2,386.0 1,802.4 
Transmission1,131.2 1,107.7 
Distribution3,137.3 3,004.9 
Other Property, Plant and Equipment464.8 437.0 
Construction Work in Progress225.4 156.0 
Total Property, Plant and Equipment7,344.7 6,508.0 
Accumulated Depreciation and Amortization1,810.5 1,705.2 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET5,534.2 4,802.8 
OTHER NONCURRENT ASSETS  
Regulatory Assets606.2 1,037.4 
Employee Benefits and Pension Assets97.7 95.2 
Operating Lease Assets107.3 68.9 
Deferred Charges and Other Noncurrent Assets23.0 7.9 
TOTAL OTHER NONCURRENT ASSETS834.2 1,209.4 
TOTAL ASSETS$6,937.1 $6,399.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
129



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2022 and December 31, 2021
(Unaudited)
 September 30,December 31,
 20222021
 (in millions)
CURRENT LIABILITIES  
Advances from Affiliates$223.5 $72.3 
Accounts Payable:  
General249.0 157.4 
Affiliated Companies105.0 51.0 
Long-term Debt Due Within One Year – Nonaffiliated0.5 125.5 
Risk Management Liabilities— 3.7 
Customer Deposits60.5 56.2 
Accrued Taxes54.9 27.0 
Obligations Under Operating Leases8.4 6.9 
Other Current Liabilities75.0 62.7 
TOTAL CURRENT LIABILITIES776.8 562.7 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated1,913.1 1,788.0 
Deferred Income Taxes794.9 782.3 
Regulatory Liabilities and Deferred Investment Tax Credits827.9 835.3 
Asset Retirement Obligations74.6 57.5 
Obligations Under Operating Leases100.3 62.2 
Deferred Credits and Other Noncurrent Liabilities18.9 19.4 
TOTAL NONCURRENT LIABILITIES3,729.7 3,544.7 
TOTAL LIABILITIES4,506.5 4,107.4 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY  
Common Stock – Par Value – $15 Per Share:
  
Authorized – 11,000,000 Shares
  
Issued – 10,482,000 Shares
  
Outstanding – 9,013,000 Shares
157.2 157.2 
Paid-in Capital1,042.3 1,039.0 
Retained Earnings1,231.1 1,095.4 
TOTAL COMMON SHAREHOLDER’S EQUITY2,430.6 2,291.6 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$6,937.1 $6,399.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
130



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20222021
OPERATING ACTIVITIES  
Net Income$155.7 $136.6 
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:  
Depreciation and Amortization172.7 149.0 
Deferred Income Taxes(20.0)109.8 
Mark-to-Market of Risk Management Contracts(36.1)(8.2)
Property Taxes(12.2)(10.9)
Deferred Fuel Over/Under-Recovery, Net454.0 (776.4)
Change in Other Noncurrent Assets(18.1)(14.3)
Change in Other Noncurrent Liabilities15.8 4.5 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net(66.3)(13.4)
Fuel, Materials and Supplies(25.8)9.9 
Accounts Payable150.8 16.4 
Accrued Taxes, Net(20.9)9.3 
Other Current Assets(19.2)(5.9)
Other Current Liabilities11.0 (18.4)
Net Cash Flows from (Used for) Operating Activities741.4 (412.0)
INVESTING ACTIVITIES  
Construction Expenditures(322.6)(219.6)
Change in Advances to Affiliates, Net— (59.5)
Acquisition of the North Central Wind Energy Facilities(549.3)(297.0)
Other Investing Activities2.9 1.9 
Net Cash Flows Used for Investing Activities(869.0)(574.2)
FINANCING ACTIVITIES  
Capital Contribution from Parent3.3 625.0 
Issuance of Long-term Debt – Nonaffiliated499.7 1,290.0 
Change in Advances from Affiliates, Net151.2 (155.4)
Retirement of Long-term Debt – Nonaffiliated(500.4)(750.4)
Principal Payments for Finance Lease Obligations(2.4)(2.5)
Dividends Paid on Common Stock(20.0)(20.0)
Other Financing Activities0.4 0.5 
Net Cash Flows from Financing Activities131.8 987.2 
Net Increase in Cash and Cash Equivalents4.2 1.0 
Cash and Cash Equivalents at Beginning of Period1.3 2.6 
Cash and Cash Equivalents at End of Period$5.5 $3.6 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$63.1 $42.9 
Net Cash Paid (Received) for Income Taxes21.9 (101.2)
Noncash Acquisitions Under Finance Leases1.7 3.1 
Construction Expenditures Included in Current Liabilities as of September 30,50.1 44.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
131





SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

132



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
 September 30,September 30,
 2022202120222021
 (in millions of KWhs)
Retail:    
Residential2,019 1,999 5,157 4,973 
Commercial1,631 1,616 4,385 4,221 
Industrial1,367 1,203 3,876 3,468 
Miscellaneous17 19 55 58 
Total Retail5,034 4,837 13,473 12,720 
Wholesale1,744 2,170 5,312 5,103 
Total KWhs6,778 7,007 18,785 17,823 

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
 September 30,September 30,
 2022202120222021
 (in degree days)
Actual – Heating (a)— — 704 789 
Normal – Heating (b)— 726 723 
Actual – Cooling (c)1,627 1,478 2,642 2,251 
Normal – Cooling (b)1,420 1,416 2,195 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.


133



Third Quarter of 2022 Compared to Third Quarter of 2021
Reconciliation of Third Quarter of 2021 to Third Quarter of 2022
Earnings Attributable to SWEPCo Common Shareholder
(in millions)
Third Quarter of 2021$108.9 
  
Changes in Gross Margin: 
Retail Margins (a)41.6 
Margins from Off-system Sales7.2 
Transmission Revenues7.7 
Other Revenues0.4 
Total Change in Gross Margin56.9 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(21.6)
Depreciation and Amortization(21.0)
Taxes Other Than Income Taxes(5.3)
Interest Income(0.1)
Allowance for Equity Funds Used During Construction(0.4)
Non-Service Cost Components of Net Periodic Benefit Cost1.1 
Interest Expense(3.5)
Total Change in Expenses and Other(50.8)
  
Income Tax Expense24.1 
Equity Earnings of Unconsolidated Subsidiary(0.7)
Net Income Attributable to Noncontrolling Interest1.0 
  
Third Quarter of 2022$139.4 

(a)Includes firm wholesale sales to municipals and cooperatives.
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:

Retail Margins increased $42 million primarily due to the following:
A $40 million increase primarily due to base rate revenue increases in Texas and Arkansas and rider increases in all retail jurisdictions. These increases were partially offset in other expense items below.
A $12 million increase in weather-related usage primarily due to a 10% increase in cooling degree days.
A $6 million increase in weather-normalized margins primarily due to the commercial and industrial classes.
These increases were partially offset by:
A $14 million decrease resulting from the NCWF PTC benefits provided to customers through fuel clause mechanisms. This decrease was partially offset in Income Tax Benefit below.
Margins from Off-system Sales increased $7 million due to an increase in Turk Plant merchant sales.
Transmission Revenues increased $8 million primarily due to continued investment in transmission assets and increased load.


134



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

Other Operation and Maintenance expenses increased $22 million primarily due to the following:
A $7 million increase in transmission expenses primarily due to the following:
A $6 million increase in recoverable SPP transmission expenses. This increase was offset in Retail Margins above.
A $2 million increase in transmission formula rate true-up activity.
A $4 million increase in distribution expenses primarily due to vegetation management expenses.
A $3 million increase related to the assumption of additional Sabine reclamation costs from a joint owner.
A $2 million increase due to energy efficiency programs. This increase was offset in Retail Margins above.
A $2 million increase in administrative and general expenses primarily due to rate case expenses and regulatory fees.
Depreciation and Amortization expenses increased $21 million primarily due to the implementation of new rates in Arkansas and Texas, a higher depreciable base and the NCWF rider. This increase was partially offset in Retail Margins above.
Taxes Other Than Income Taxes increased $5 million primarily due to increased property taxes.
Interest Expense increased $4 million primarily due to an increase in long-term debt balances and Advances from Affiliates.
Income Tax Expense decreased $24 million primarily due to an increase in PTCs. This decrease was partially offset in Retail Margins above.

135



Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021
Reconciliation of Nine Months Ended September 30, 2021 to Nine Months Ended September 30, 2022
Earnings Attributable to SWEPCo Common Shareholder
(in millions)
Nine Months Ended September 30, 2021$208.1 
  
Changes in Gross Margin: 
Retail Margins (a)93.5 
Margins from Off-system Sales(10.3)
Transmission Revenues18.6 
Other Revenues0.4 
Total Change in Gross Margin102.2 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(46.4)
Depreciation and Amortization(34.4)
Taxes Other Than Income Taxes(5.9)
Interest Income7.0 
Allowance for Equity Funds Used During Construction(2.0)
Non-Service Cost Components of Net Periodic Benefit Cost3.2 
Interest Expense(9.6)
Total Change in Expenses and Other(88.1)
  
Income Tax Expense40.0 
Equity Earnings of Unconsolidated Subsidiary(1.5)
Net Income Attributable to Noncontrolling Interest(0.5)
  
Nine Months Ended September 30, 2022$260.2 

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

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

Retail Margins increased $94 million primarily due to the following:
An $80 million increase primarily due to base rate revenue increases in Texas and Arkansas and rider increases in all retail jurisdictions. These increases were partially offset in other expense items below.
A $27 million increase in weather-related usage primarily due to a 17% increase in cooling degree days, partially offset by an 11% decrease in heating degree days.
An $11 million increase in weather-normalized margins primarily due to the commercial and residential classes, partially offset by the industrial class.
These increases were partially offset by:
A $16 million decrease resulting from the NCWF PTC benefits provided to customers through fuel clause mechanisms. This decrease was partially offset in Income Tax Benefit below.
An $8 million decrease in municipal and cooperative revenues primarily due to the February 2021 severe winter weather event.
Margins from Off-system Sales decreased $10 million primarily due to Turk Plant merchant sales as a result of the February 2021 severe winter weather event.
136



Transmission Revenues increased $19 million primarily due to the following:
A $21 million increase due to continued investment in transmission assets and increased load.
This increase was partially offset by:
A $3 million decrease due to formula rate true-up activity.

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

Other Operation and Maintenance expenses increased $46 million primarily due to the following:
A $12 million increase in transmission expenses primarily due to the following:
A $6 million increase in recoverable SPP transmission expenses. This increase was offset in Retail Margins above.
A $4 million increase due to increased transmission investment and load.
A $3 million increase in transmission vegetation management expenses.
These increases were partially offset by:
A $4 million decrease in formula rate true-up activity.
A $6 million increase due to pre-construction costs associated with various renewable projects.
A $6 million increase in generation related expenses.
A $5 million increase in administrative and general expenses primarily due to regulatory fees and employee-related expenses.
A $5 million increase in distribution expenses primarily due to vegetation management expenses.
A $5 million increase due to energy efficiency programs. This increase was offset in Retail Margins above.
A $3 million increase related to the assumption of additional Sabine reclamation costs from a joint owner.
Depreciation and Amortization expenses increased $34 million primarily due to the implementation of new rates in Arkansas and Texas, a higher depreciable base and the NCWF rider. This increase was partially offset in Retail Margins above.
Taxes Other Than Income Taxes increased $6 million primarily due to increased property taxes.
Interest Income increased $7 million primarily related to carrying charges on regulatory assets resulting from the February 2021 severe winter weather event.
Interest Expense increased $10 million primarily due to an increase in long-term debt balances and Advances from Affiliates.
Income Tax Expense decreased $40 million primarily due to an increase in PTCs, partially offset by an increase in pretax book income and an increase in state tax expense. The decrease in Income Tax Expense driven by the increase in PTCs is partially offset in Retail Margins above.


137




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
Three Months EndedNine Months Ended
 September 30,September 30,
 2022202120222021
REVENUES    
Electric Generation, Transmission and Distribution$698.8 $570.1 $1,703.7 $1,596.6 
Sales to AEP Affiliates18.2 13.5 43.7 32.2 
Other Revenues0.5 0.5 1.5 1.5 
TOTAL REVENUES717.5 584.1 1,748.9 1,630.3 
EXPENSES    
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation290.9 214.4 669.1 652.7 
Other Operation114.1 91.7 308.7 270.6 
Maintenance32.9 33.7 107.8 99.5 
Depreciation and Amortization95.8 74.8 251.8 217.4 
Taxes Other Than Income Taxes34.2 28.9 94.9 89.0 
TOTAL EXPENSES567.9 443.5 1,432.3 1,329.2 
OPERATING INCOME149.6 140.6 316.6 301.1 
Other Income (Expense):   
Interest Income2.7 2.8 13.9 6.9 
Allowance for Equity Funds Used During Construction1.0 1.4 3.4 5.4 
Non-Service Cost Components of Net Periodic Benefit Cost3.2 2.1 9.4 6.2 
Interest Expense(35.2)(31.7)(102.0)(92.4)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS121.3 115.2 241.3 227.2 
Income Tax Expense (Benefit)(17.8)6.3 (21.0)19.0 
Equity Earnings of Unconsolidated Subsidiary0.3 1.0 1.0 2.5 
NET INCOME139.4 109.9 263.3 210.7 
Net Income Attributable to Noncontrolling Interest— 1.0 3.1 2.6 
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER
$139.4 $108.9 $260.2 $208.1 
The common stock of SWEPCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
138



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
 September 30,September 30,
 2022202120222021
Net Income$139.4 $109.9 $263.3 $210.7 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES    
Cash Flow Hedges, Net of Tax of $0 and $0.1 for the Three Months Ended September 30, 2022 and 2021, Respectively, and $0 and $0.3 for the Nine Months Ended September 30, 2022 and 2021, Respectively
— 0.3 — 1.1 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2022 and 2021, Respectively, and $(0.3) and $(0.3) for the Nine Months Ended September 30, 2022 and 2021, Respectively
(0.4)(0.4)(1.2)(1.2)
TOTAL OTHER COMPREHENSIVE LOSS(0.4)(0.1)(1.2)(0.1)
TOTAL COMPREHENSIVE INCOME139.0 109.8 262.1 210.6 
Total Comprehensive Income Attributable to Noncontrolling Interest— 1.0 3.1 2.6 
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER
$139.0 $108.8 $259.0 $208.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
139



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
SWEPCo Common Shareholder  
Common
Stock
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Noncontrolling
Interest
Total
TOTAL EQUITY – DECEMBER 31, 2020$0.1 $812.2 $1,811.9 $1.9 $1.6 $2,627.7 
Capital Contribution from Parent100.0100.0 
Common Stock Dividends – Nonaffiliated(1.0)(1.0)
Net Income62.4 1.0 63.4 
TOTAL EQUITY – MARCH 31, 20210.1 912.2 1,874.3 1.9 1.6 2,790.1 
Capital Contribution from Parent75.075.0 
Common Stock Dividends – Nonaffiliated    (0.6)(0.6)
Net Income  36.8  0.6 37.4 
TOTAL EQUITY – JUNE 30, 20210.1 987.2 1,911.1 1.9 1.6 2,901.9 
Capital Contribution from Parent105.0 105.0 
Common Stock Dividends – Nonaffiliated(2.2)(2.2)
Net Income108.9 1.0 109.9 
Other Comprehensive Loss(0.1)(0.1)
TOTAL EQUITY – SEPTEMBER 30, 2021$0.1 $1,092.2 $2,020.0 $1.8 $0.4 $3,114.5 
TOTAL EQUITY – DECEMBER 31, 2021$0.1 $1,092.2 $2,050.9 $6.7 $(0.1)$3,149.8 
Capital Contribution from Parent350.0 350.0 
Common Stock Dividends – Nonaffiliated(0.8)(0.8)
Net Income44.1 1.0 45.1 
Other Comprehensive Loss(0.3)(0.3)
TOTAL EQUITY – MARCH 31, 20220.1 1,442.2 2,095.0 6.4 0.1 3,543.8 
Capital Contribution from Parent2.22.2 
Common Stock Dividends  (12.5)  (12.5)
Common Stock Dividends – Nonaffiliated    (0.7)(0.7)
Net Income  76.7  2.1 78.8 
Other Comprehensive Loss   (0.5) (0.5)
TOTAL EQUITY – JUNE 30, 20220.1 1,444.4 2,159.2 5.9 1.5 3,611.1 
Capital Contribution from Parent1.1 1.1 
Common Stock Dividends(45.0)(45.0)
Common Stock Dividends – Nonaffiliated(1.1)(1.1)
Net Income139.4 — 139.4 
Other Comprehensive Loss(0.4)(0.4)
TOTAL EQUITY – SEPTEMBER 30, 2022$0.1 $1,445.5 $2,253.6 $5.5 $0.4 $3,705.1 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
140



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2022 and December 31, 2021
(in millions)
(Unaudited)
 September 30,December 31,
 20222021
CURRENT ASSETS  
Cash and Cash Equivalents
(September 30, 2022 and December 31, 2021 Amounts Include $79.2 and $49.9, Respectively, Related to Sabine)
$84.4 $51.2 
Advances to Affiliates2.1 155.9 
Accounts Receivable:  
Customers31.9 35.8 
Affiliated Companies53.8 38.3 
Miscellaneous18.6 12.3 
Total Accounts Receivable104.3 86.4 
Fuel
(September 30, 2022 and December 31, 2021 Amounts Include $9.9 and $13.1, Respectively, Related to Sabine)
55.3 82.2 
Materials and Supplies
(September 30, 2022 and December 31, 2021 Amounts Include $7.2 and $12, Respectively, Related to Sabine)
85.3 81.9 
Risk Management Assets36.4 9.8 
Accrued Tax Benefits88.4 17.8 
Regulatory Asset for Under-Recovered Fuel Costs333.8 143.9 
Prepayments and Other Current Assets50.0 39.4 
TOTAL CURRENT ASSETS840.0 668.5 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation5,454.6 4,734.5 
Transmission2,380.3 2,316.9 
Distribution2,622.5 2,514.3 
Other Property, Plant and Equipment
(September 30, 2022 and December 31, 2021 Amounts Include $219.9 and $219.9, Respectively, Related to Sabine)
801.4 764.0 
Construction Work in Progress345.3 240.7 
Total Property, Plant and Equipment11,604.1 10,570.4 
Accumulated Depreciation and Amortization
(September 30, 2022 and December 31, 2021 Amounts Include $201.8 and $168.1, Respectively, Related to Sabine)
3,444.2 3,170.3 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET8,159.9 7,400.1 
OTHER NONCURRENT ASSETS  
Regulatory Assets992.4 1,005.3 
Deferred Charges and Other Noncurrent Assets300.8 251.8 
TOTAL OTHER NONCURRENT ASSETS1,293.2 1,257.1 
TOTAL ASSETS$10,293.1 $9,325.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
141



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 2022 and December 31, 2021
(Unaudited)
 September 30,December 31,
 20222021
 (in millions)
CURRENT LIABILITIES  
Advances from Affiliates$156.3 $— 
Accounts Payable:  
General206.2 163.6 
Affiliated Companies100.5 61.4 
Long-term Debt Due Within One Year – Nonaffiliated6.2 6.2 
Risk Management Liabilities— 2.1 
Customer Deposits65.3 62.4 
Accrued Taxes113.8 44.3 
Accrued Interest30.3 36.0 
Obligations Under Operating Leases8.4 8.1 
Other Current Liabilities129.0 154.6 
TOTAL CURRENT LIABILITIES816.0 538.7 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated3,386.2 3,389.0 
Deferred Income Taxes1,112.0 1,087.6 
Regulatory Liabilities and Deferred Investment Tax Credits818.2 806.9 
Asset Retirement Obligations247.5 192.7 
Employee Benefits and Pension Obligations23.2 20.3 
Obligations Under Operating Leases122.5 77.7 
Deferred Credits and Other Noncurrent Liabilities62.4 63.0 
TOTAL NONCURRENT LIABILITIES5,772.0 5,637.2 
TOTAL LIABILITIES6,588.0 6,175.9 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
EQUITY  
Common Stock – Par Value – $18 Per Share:
  
Authorized – 3,680 Shares
  
Outstanding – 3,680 Shares
0.1 0.1 
Paid-in Capital1,445.5 1,092.2 
Retained Earnings2,253.6 2,050.9 
Accumulated Other Comprehensive Income (Loss)5.5 6.7 
TOTAL COMMON SHAREHOLDER’S EQUITY3,704.7 3,149.9 
Noncontrolling Interest0.4 (0.1)
TOTAL EQUITY3,705.1 3,149.8 
TOTAL LIABILITIES AND EQUITY$10,293.1 $9,325.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
142



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2022 and 2021
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20222021
OPERATING ACTIVITIES  
Net Income$263.3 $210.7 
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
 
 
Depreciation and Amortization251.8 217.4 
Deferred Income Taxes7.5 22.5 
Allowance for Equity Funds Used During Construction(3.4)(5.4)
Mark-to-Market of Risk Management Contracts(27.6)(18.1)
Property Taxes(22.0)(20.0)
Deferred Fuel Over/Under-Recovery, Net(82.0)(506.8)
Change in Regulatory Assets3.1 (91.5)
Change in Other Noncurrent Assets52.0 38.3 
Change in Other Noncurrent Liabilities17.3 40.0 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net(17.9)(70.2)
Fuel, Materials and Supplies23.5 115.1 
Accounts Payable78.9 (21.1)
Accrued Taxes, Net(1.1)72.2 
Other Current Assets(12.0)4.2 
Other Current Liabilities(38.1)(48.2)
Net Cash Flows from (Used for) Operating Activities493.3 (60.9)
INVESTING ACTIVITIES  
Construction Expenditures(397.0)(277.2)
Change in Advances to Affiliates, Net153.8 — 
Acquisition of the North Central Wind Energy Facilities(658.0)(355.8)
Other Investing Activities3.9 2.1 
Net Cash Flows Used for Investing Activities(897.3)(630.9)
FINANCING ACTIVITIES  
Capital Contribution from Parent353.3 280.0 
Issuance of Long-term Debt – Nonaffiliated— 496.4 
Change in Short-term Debt – Nonaffiliated— (35.0)
Change in Advances from Affiliates, Net156.3 (1.7)
Retirement of Long-term Debt – Nonaffiliated(4.7)(4.7)
Principal Payments for Finance Lease Obligations(8.0)(8.1)
Dividends Paid on Common Stock(57.5)— 
Dividends Paid on Common Stock – Nonaffiliated(2.6)(3.8)
Other Financing Activities0.4 0.5 
Net Cash Flows from Financing Activities437.2 723.6 
Net Increase in Cash and Cash Equivalents33.2 31.8 
Cash and Cash Equivalents at Beginning of Period51.2 13.2 
Cash and Cash Equivalents at End of Period$84.4 $45.0 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$102.1 $98.0 
Net Cash Paid (Received) for Income Taxes34.7 (11.3)
Noncash Acquisitions Under Finance Leases3.2 4.4 
Construction Expenditures Included in Current Liabilities as of September 30,71.8 46.8 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144.
143



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 Contingencies
AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Acquisitions, Assets and Liabilities Held for Sale, Dispositions and ImpairmentsAEP, 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
Property, Plant and EquipmentAEP, PSO, SWEPCo
Revenue from Contracts with Customers
AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
144



1.  SIGNIFICANT ACCOUNTING MATTERS

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

General

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

In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair statement of the net income, financial position and cash flows for the interim periods for each Registrant.  Net income for the three and nine months ended September 30, 2022 is not necessarily indicative of results that may be expected for the year ending December 31, 2022.  The condensed financial statements are unaudited and should be read in conjunction with the audited 2021 financial statements and notes thereto, which are included in the Registrants’ Annual Reports on Form 10-K as filed with the SEC on February 24, 2022.

AEP System Tax Allocation

The Registrant Subsidiaries join in the filing of a consolidated tax return. Historically, the allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocated the benefit of current tax loss of the parent company (Parent Company Loss Benefit) to the AEP System subsidiaries through a reduction of current tax expense. In the first quarter of 2022, AEP and subsidiaries changed accounting for the Parent Company Loss Benefit from a reduction of current tax expense to an allocation through equity. The impact of this change was immaterial to the Registrant Subsidiaries’ financial statements.

Deferred Fuel Costs (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

The cost of purchased electricity, fuel and related emission allowances and emission control chemicals/consumables is charged to Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily using the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is an expectation that refunds or recoveries will extend beyond a one year period, based on a company’s filing with a commission or a commission directive. These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. The Registrants share the majority of their Off-system Sales margins to customers either through an active FAC or other rate mechanisms. Where the FAC or Off-system Sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings.

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.
145




The following table presents AEP’s basic and diluted EPS calculations included on the statements of income:
Three Months Ended September 30,
20222021
(in millions, except per share data)
 $/share$/share
Earnings Attributable to AEP Common Shareholders
$683.7  $796.0  
Weighted-Average Number of Basic AEP Common Shares Outstanding513.7 $1.33 501.2 $1.59 
Weighted-Average Dilutive Effect of Stock-Based Awards1.6 — 1.4 (0.01)
Weighted-Average Number of Diluted AEP Common Shares Outstanding515.3 $1.33 502.6 $1.58 

Nine Months Ended September 30,
20222021
(in millions, except per share data)
 $/share$/share
Earnings Attributable to AEP Common Shareholders
$1,922.9  $1,949.2  
Weighted-Average Number of Basic AEP Common Shares Outstanding511.2 $3.76 499.4 $3.90 
Weighted-Average Dilutive Effect of Stock-Based Awards1.5 (0.01)1.2 (0.01)
Weighted-Average Number of Diluted AEP Common Shares Outstanding512.7 $3.75 500.6 $3.89 

Equity Units are potentially dilutive securities and were excluded from the calculation of diluted EPS for the three and nine months ended September 30, 2022 and 2021, as the dilutive stock price threshold was not met. See Note 12 - Financing Activities for more information related to Equity Units.

There were 0 and 377 thousand antidilutive shares outstanding as of September 30, 2022 and 2021, respectively.


146



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

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

Reconciliation of Cash, Cash Equivalents and Restricted Cash

The following tables provide a reconciliation of Cash, Cash Equivalents and Restricted Cash reported within the balance sheets that sum to the total of the same amounts shown on the statements of cash flows:
September 30, 2022
AEPAEP TexasAPCo
(in millions)
Cash and Cash Equivalents
$522.2 $0.1 $6.7 
Restricted Cash
55.1 47.7 7.4 
Total Cash, Cash Equivalents and Restricted Cash
$577.3 $47.8 $14.1 

December 31, 2021
AEPAEP TexasAPCo
(in millions)
Cash and Cash Equivalents
$403.4 $0.1 $2.5 
Restricted Cash
48.0 30.4 17.6 
Total Cash, Cash Equivalents and Restricted Cash
$451.4 $30.5 $20.1 

Supplementary Cash Flow Information (Applies to AEP)

Nine Months Ended September 30,
Cash Flow Information20222021
(in millions)
Cash Paid for:
Interest, Net of Capitalized Amounts$856.8 $775.2 
Income Taxes104.1 9.3 
Noncash Investing and Financing Activities:
Acquisitions Under Finance Leases22.3 23.0 
Construction Expenditures Included in Current Liabilities as of September 30,985.8 764.1 
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,8.5 0.3 
Noncash Contribution of Assets to Cedar Creek Project— (9.3)
Noncontrolling Interest Assumed - Dry Lake Solar Project— 35.0 
147



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.

148



3.  COMPREHENSIVE INCOME

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

Presentation of Comprehensive Income

The following tables provide the components of changes in AOCI and details of reclassifications from AOCI.  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, 2022CommodityInterest Rateand OPEBTotal
 (in millions)
Balance in AOCI as of June 30, 2022$533.6 $(10.8)$28.6 $551.4 
Change in Fair Value Recognized in AOCI94.3 7.4 (a)— 101.7 
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (b)0.2 — — 0.2 
Purchased Electricity for Resale (b)
(222.6)— — (222.6)
Interest Expense (b)
— 0.9 — 0.9 
Amortization of Prior Service Cost (Credit)— — (6.2)(6.2)
Amortization of Actuarial (Gains) Losses— — 2.2 2.2 
Reclassifications from AOCI, before Income Tax (Expense) Benefit
(222.4)0.9 (4.0)(225.5)
Income Tax (Expense) Benefit(46.6)0.1 (0.8)(47.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
(175.8)0.8 (3.2)(178.2)
Net Current Period Other Comprehensive Income (Loss)
(81.5)8.2 (3.2)(76.5)
Balance in AOCI as of September 30, 2022$452.1 $(2.6)$25.4 $474.9 
 Cash Flow HedgesPension 
Three Months Ended September 30, 2021CommodityInterest Rateand OPEBTotal
 (in millions)
Balance in AOCI as of June 30, 2021$110.3 $(32.2)$18.9 $97.0 
Change in Fair Value Recognized in AOCI220.8 4.9 (a)— 225.7 
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity for Resale (b)
(59.7)— — (59.7)
Interest Expense (b)
— 1.5 — 1.5 
Amortization of Prior Service Cost (Credit)
— — (4.8)(4.8)
Amortization of Actuarial (Gains) Losses
— — 2.3 2.3 
Reclassifications from AOCI, before Income Tax (Expense) Benefit
(59.7)1.5 (2.5)(60.7)
Income Tax (Expense) Benefit(12.5)0.3 (0.5)(12.7)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
(47.2)1.2 (2.0)(48.0)
Net Current Period Other Comprehensive Income (Loss)
173.6 6.1 (2.0)177.7 
Balance in AOCI as of September 30, 2021$283.9 $(26.1)$16.9 $274.7 
149



AEP
 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 AOCI629.8 16.2 (a)— 646.0 
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (b)0.2 — — 0.2 
Purchased Electricity for Resale (b)
(432.3)— — (432.3)
Interest Expense (b)
— 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 $474.9 
 Cash Flow HedgesPension 
Nine Months Ended September 30, 2021CommodityInterest Rateand OPEBTotal
 (in millions)
Balance in AOCI as of December 31, 2020$(60.6)$(47.5)$23.0 $(85.1)
Change in Fair Value Recognized in AOCI534.5 17.6 (a)— 552.1 
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (b)0.7 — — 0.7 
Purchased Electricity for Resale (b)
(241.2)— — (241.2)
Interest Expense (b)
— 4.8 — 4.8 
Amortization of Prior Service Cost (Credit)
— — (14.5)(14.5)
Amortization of Actuarial (Gains) Losses
— — 6.8 6.8 
Reclassifications from AOCI, before Income Tax (Expense) Benefit
(240.5)4.8 (7.7)(243.4)
Income Tax (Expense) Benefit(50.5)1.0 (1.6)(51.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
(190.0)3.8 (6.1)(192.3)
Net Current Period Other Comprehensive Income (Loss)
344.5 21.4 (6.1)359.8 
Balance in AOCI as of September 30, 2021$283.9 $(26.1)$16.9 $274.7 

150



AEP Texas
Cash Flow Hedge –Pension
Three Months Ended September 30, 2022Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of June 30, 2022$(0.8)$(5.2)$(6.0)
Change in Fair Value Recognized in AOCI
0.1 — 0.1 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)0.3 — 0.3 
Amortization of Prior Service Cost (Credit)— (0.1)(0.1)
Amortization of Actuarial (Gains) Losses— 0.1 0.1 
Reclassifications from AOCI, before Income Tax (Expense) Benefit
0.3 — 0.3 
Income Tax (Expense) Benefit0.1 — 0.1 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
0.2 — 0.2 
Net Current Period Other Comprehensive Income (Loss)0.3 — 0.3 
Balance in AOCI as of September 30, 2022$(0.5)$(5.2)$(5.7)
Cash Flow Hedge –Pension
Three Months Ended September 30, 2021Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of June 30, 2021$(1.8)$(6.5)$(8.3)
Change in Fair Value Recognized in AOCI
— — — 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)0.4 — 0.4 
Amortization of Prior Service Cost (Credit)— (0.1)(0.1)
Amortization of Actuarial (Gains) Losses— 0.1 0.1 
Reclassifications from AOCI, before Income Tax (Expense) Benefit
0.4 — 0.4 
Income Tax (Expense) Benefit0.1 — 0.1 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
0.3 — 0.3 
Net Current Period Other Comprehensive Income (Loss)0.3 — 0.3 
Balance in AOCI as of September 30, 2021$(1.5)$(6.5)$(8.0)
151



AEP Texas
Cash Flow Hedge –Pension
Nine Months Ended September 30, 2022Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2021$(1.3)$(5.2)$(6.5)
Change in Fair Value Recognized in AOCI
— — — 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)1.0 — 1.0 
Amortization of Prior Service Cost (Credit)— (0.1)(0.1)
Amortization of Actuarial (Gains) Losses— 0.1 0.1 
Reclassifications from AOCI, before Income Tax (Expense) Benefit
1.0 — 1.0 
Income Tax (Expense) Benefit0.2 — 0.2 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
0.8 — 0.8 
Net Current Period Other Comprehensive Income (Loss)0.8 — 0.8 
Balance in AOCI as of September 30, 2022$(0.5)$(5.2)$(5.7)
Cash Flow Hedge –Pension
Nine Months Ended September 30, 2021Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2020$(2.3)$(6.6)$(8.9)
Change in Fair Value Recognized in AOCI
— — — 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)1.0 — 1.0 
Amortization of Prior Service Cost (Credit)— (0.1)(0.1)
Amortization of Actuarial (Gains) Losses— 0.2 0.2 
Reclassifications from AOCI, before Income Tax (Expense) Benefit
1.0 0.1 1.1 
Income Tax (Expense) Benefit0.2 — 0.2 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
0.8 0.1 0.9 
Net Current Period Other Comprehensive Income (Loss)0.8 0.1 0.9 
Balance in AOCI as of September 30, 2021$(1.5)$(6.5)$(8.0)
152




APCo
Cash Flow Hedge –Pension
Three Months Ended September 30, 2022Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of June 30, 2022$7.1 $14.8 $21.9 
Change in Fair Value Recognized in AOCI
— — — 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)(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 September 30, 2022$6.9 $13.7 $20.6 
Cash Flow Hedge –Pension
Three Months Ended September 30, 2021Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of June 30, 2021$8.0 $5.9 $13.9 
Change in Fair Value Recognized in AOCI
0.2 — 0.2 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)(0.6)— (0.6)
Amortization of Prior Service Cost (Credit)— (1.2)(1.2)
Reclassifications from AOCI, before Income Tax (Expense) Benefit
(0.6)(1.2)(1.8)
Income Tax (Expense) Benefit(0.1)(0.2)(0.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
(0.5)(1.0)(1.5)
Net Current Period Other Comprehensive Income (Loss)
(0.3)(1.0)(1.3)
Balance in AOCI as of September 30, 2021$7.7 $4.9 $12.6 
153




APCo
Cash Flow Hedge –Pension
Nine Months Ended September 30, 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
— — — 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)(0.8)— (0.8)
Amortization of Prior Service Cost (Credit)— (4.1)(4.1)
Reclassifications from AOCI, before Income Tax (Expense) Benefit
(0.8)(4.1)(4.9)
Income Tax (Expense) Benefit(0.2)(0.9)(1.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
(0.6)(3.2)(3.8)
Net Current Period Other Comprehensive Income (Loss)
(0.6)(3.2)(3.8)
Balance in AOCI as of September 30, 2022$6.9 $13.7 $20.6 
Cash Flow Hedge –Pension
Nine Months Ended September 30, 2021Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2020$(0.8)$8.0 $7.2 
Change in Fair Value Recognized in AOCI
9.3 — 9.3 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)(1.0)— (1.0)
Amortization of Prior Service Cost (Credit)— (3.9)(3.9)
Reclassifications from AOCI, before Income Tax (Expense) Benefit
(1.0)(3.9)(4.9)
Income Tax (Expense) Benefit(0.2)(0.8)(1.0)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
(0.8)(3.1)(3.9)
Net Current Period Other Comprehensive Income (Loss)
8.5 (3.1)5.4 
Balance in AOCI as of September 30, 2021$7.7 $4.9 $12.6 
154




I&M
Cash Flow Hedge –Pension
Three Months Ended September 30, 2022Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of June 30, 2022$(5.9)$5.2 $(0.7)
Change in Fair Value Recognized in AOCI
— — — 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)0.5 — 0.5 
Amortization of Prior Service Cost (Credit)— (0.3)(0.3)
Amortization of Actuarial (Gains) Losses— 0.1 0.1 
Reclassifications from AOCI, before Income Tax (Expense) Benefit
0.5 (0.2)0.3 
Income Tax (Expense) Benefit0.1 (0.1)— 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
0.4 (0.1)0.3 
Net Current Period Other Comprehensive Income (Loss)
0.4 (0.1)0.3 
Balance in AOCI as of September 30, 2022$(5.5)$5.1 $(0.4)
Cash Flow Hedge –Pension
Three Months Ended September 30, 2021Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of June 30, 2021$(7.4)$1.2 $(6.2)
Change in Fair Value Recognized in AOCI
— — — 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)0.5 — 0.5 
Amortization of Prior Service Cost (Credit)— (0.2)(0.2)
Amortization of Actuarial (Gains) Losses— 0.2 0.2 
Reclassifications from AOCI, before Income Tax (Expense) Benefit
0.5 — 0.5 
Income Tax (Expense) Benefit0.1 — 0.1 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
0.4 — 0.4 
Net Current Period Other Comprehensive Income (Loss)
0.4 — 0.4 
Balance in AOCI as of September 30, 2021$(7.0)$1.2 $(5.8)
155




I&M
Cash Flow Hedge –Pension
Nine Months Ended September 30, 2022Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2021$(6.7)$5.4 $(1.3)
Change in Fair Value Recognized in AOCI
— — — 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)1.5 — 1.5 
Amortization of Prior Service Cost (Credit)— (0.7)(0.7)
Amortization of Actuarial (Gains) Losses— 0.3 0.3 
Reclassifications from AOCI, before Income Tax (Expense) Benefit1.5 (0.4)1.1 
Income Tax (Expense) Benefit0.3 (0.1)0.2 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit1.2 (0.3)0.9 
Net Current Period Other Comprehensive Income (Loss)1.2 (0.3)0.9 
Balance in AOCI as of September 30, 2022$(5.5)$5.1 $(0.4)
Cash Flow Hedge –Pension
Nine Months Ended September 30, 2021Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2020$(8.3)$1.3 $(7.0)
Change in Fair Value Recognized in AOCI
— — — 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)1.6 — 1.6 
Amortization of Prior Service Cost (Credit)— (0.6)(0.6)
Amortization of Actuarial (Gains) Losses— 0.5 0.5 
Reclassifications from AOCI, before Income Tax (Expense) Benefit
1.6 (0.1)1.5 
Income Tax (Expense) Benefit0.3 — 0.3 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
1.3 (0.1)1.2 
Net Current Period Other Comprehensive Income (Loss)
1.3 (0.1)1.2 
Balance in AOCI as of September 30, 2021$(7.0)$1.2 $(5.8)
156




PSO
Cash Flow Hedge –
Three Months Ended September 30, 2022Interest Rate
 (in millions)
Balance in AOCI as of June 30, 2022$— 
Change in Fair Value Recognized in AOCI— 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)— 
Reclassifications from AOCI, before Income Tax (Expense) Benefit
— 
Income Tax (Expense) Benefit— 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
— 
Net Current Period Other Comprehensive Income (Loss)— 
Balance in AOCI as of September 30, 2022$— 
Cash Flow Hedge –
Three Months Ended September 30, 2021Interest Rate
 (in millions)
Balance in AOCI as of June 30, 2021$— 
Change in Fair Value Recognized in AOCI— 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)— 
Reclassifications from AOCI, before Income Tax (Expense) Benefit
— 
Income Tax (Expense) Benefit— 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
— 
Net Current Period Other Comprehensive Income (Loss)— 
Balance in AOCI as of September 30, 2021$— 

Cash Flow Hedge –
Nine Months Ended September 30, 2022Interest Rate
 (in millions)
Balance in AOCI as of December 31, 2021$— 
Change in Fair Value Recognized in AOCI— 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)— 
Reclassifications from AOCI, before Income Tax (Expense) Benefit
— 
Income Tax (Expense) Benefit— 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
— 
Net Current Period Other Comprehensive Income (Loss)— 
Balance in AOCI as of September 30, 2022$— 
Cash Flow Hedge –
Nine Months Ended September 30, 2021Interest Rate
 (in millions)
Balance in AOCI as of December 31, 2020$0.1 
Change in Fair Value Recognized in AOCI— 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)(0.1)
Reclassifications from AOCI, before Income Tax (Expense) Benefit
(0.1)
Income Tax (Expense) Benefit— 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
(0.1)
Net Current Period Other Comprehensive Income (Loss)(0.1)
Balance in AOCI as of September 30, 2021$— 
157




SWEPCo
Cash Flow Hedge –Pension
Three Months Ended September 30, 2022Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of June 30, 2022$1.2 $4.7 $5.9 
Change in Fair Value Recognized in AOCI
— — — 
Amount of (Gain) Loss Reclassified from AOCI
Amortization of Prior Service Cost (Credit)— (0.5)(0.5)
Reclassifications from AOCI, before Income Tax (Expense) Benefit
— (0.5)(0.5)
Income Tax (Expense) Benefit— (0.1)(0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
— (0.4)(0.4)
Net Current Period Other Comprehensive Income (Loss)
— (0.4)(0.4)
Balance in AOCI as of September 30, 2022$1.2 $4.3 $5.5 
Cash Flow Hedge –Pension
Three Months Ended September 30, 2021Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of June 30, 2021$0.5 $1.4 $1.9 
Change in Fair Value Recognized in AOCI
— — — 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)0.4 — 0.4 
Amortization of Prior Service Cost (Credit)— (0.5)(0.5)
Reclassifications from AOCI, before Income Tax (Expense) Benefit
0.4 (0.5)(0.1)
Income Tax (Expense) Benefit0.1 (0.1)— 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
0.3 (0.4)(0.1)
Net Current Period Other Comprehensive Income (Loss)
0.3 (0.4)(0.1)
Balance in AOCI as of September 30, 2021$0.8 $1.0 $1.8 
158



SWEPCo
Cash Flow Hedge –Pension
Nine Months Ended September 30, 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
— — — 
Amount of (Gain) Loss Reclassified from AOCI
Amortization of Prior Service Cost (Credit)— (1.5)(1.5)
Reclassifications from AOCI, before Income Tax (Expense) Benefit
— (1.5)(1.5)
Income Tax (Expense) Benefit— (0.3)(0.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
— (1.2)(1.2)
Net Current Period Other Comprehensive Income (Loss)
— (1.2)(1.2)
Balance in AOCI as of September 30, 2022$1.2 $4.3 $5.5 
Cash Flow Hedge –Pension
Nine Months Ended September 30, 2021
Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2020$(0.3)$2.2 $1.9 
Change in Fair Value Recognized in AOCI
— — — 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)1.4 — 1.4 
Amortization of Prior Service Cost (Credit)— (1.5)(1.5)
Reclassifications from AOCI, before Income Tax (Expense) Benefit
1.4 (1.5)(0.1)
Income Tax (Expense) Benefit0.3 (0.3)— 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
1.1 (1.2)(0.1)
Net Current Period Other Comprehensive Income (Loss)
1.1 (1.2)(0.1)
Balance in AOCI as of September 30, 2021$0.8 $1.0 $1.8 

(a)The change in fair value includes $(4) million and $(1) million, respectively, for the three months ended September 30, 2022 and 2021 and $(9) million and $(5) million, respectively, for the nine months ended September 30, 2022 and 2021 related to AEP's investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC.
(b)Amounts reclassified to the referenced line item on the statements of income.

159



4.  RATE MATTERS

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

As discussed in the 2021 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2021 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 2022 and updates the 2021 Annual Report.

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

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

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

Regulated Generating Units that have been Retired

SWEPCo

In April 2016, Welsh Plant, Unit 2 was retired. As part of the 2016 Texas Base Rate Case, the PUCT authorized recovery of SWEPCo’s Texas jurisdictional share of Welsh Plant, Unit 2, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $7 million in 2017. See “2016 Texas Base Rate Case” section below for additional information. As part of the 2019 Arkansas Base Rate Case, SWEPCo received approval from the APSC to recover the Arkansas jurisdictional share of Welsh Plant, Unit 2. In December 2020, SWEPCo filed a request with the LPSC to recover the Louisiana jurisdictional share of Welsh Plant, Unit 2. See “2020 Louisiana Base Rate Case” section below for additional information. As of September 30, 2022, SWEPCo had a regulatory asset for plant retirement costs pending approval recorded on its balance sheet of $35 million related to the Louisiana jurisdictional share of Welsh Plant, Unit 2.

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, 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 over five years, 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. SWEPCo has requested recovery of the Dolet Hills Power Station in the Louisiana jurisdiction through the 2020 Louisiana Base Rate Case. As of September 30, 2022, SWEPCo had a regulatory asset of $55 million, pending approval, recorded on its balance sheet related to the Louisiana and FERC jurisdictional shares of the Dolet Hills Power Station. The Dolet Hills Power Station is currently being recovered through 2026 in the Louisiana jurisdiction, through 2027 in the Arkansas jurisdiction and through 2046 in the Texas jurisdiction. See “2020 Texas Base Rate Case”, “2020 Louisiana Base Rate Case” and “2021 Arkansas Base Rate Case” sections below for additional information.
160



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.

SWEPCo

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

The table below summarizes the net book value including CWIP, before cost of removal and materials and supplies, as of September 30, 2022, of generating facilities planned for early retirement:
PlantNet Book ValueAccelerated Depreciation Regulatory AssetCost of Removal
Regulatory Liability
Projected
Retirement Date
Current Authorized
Recovery Period
Annual
Depreciation (a)
(dollars in millions)
Northeastern Plant, Unit 3$143.7 $141.4 $20.2 (b)2026(c)$14.9 
Pirkey Plant65.0 150.7 39.6 2023(d)12.5 
Welsh Plant, Units 1 and 3432.3 75.7 58.2 (e)2028(f)39.8 

(a)Represents the amount of annual depreciation that has been collected from customers over the prior 12-month period.
(b)Includes Northeastern Plant, Unit 4, which was retired in 2016. Removal of Northeastern Plant, Unit 4, will be performed with Northeastern Plant, Unit 3, after retirement.
(c)Northeastern Plant, Unit 3 is currently being recovered through 2040.
(d)Pirkey Plant is currently being recovered through 2025 in the Louisiana jurisdiction and through 2045 in the Arkansas and Texas jurisdictions.
(e)Includes Welsh Plant, Unit 2, which was retired in 2016. Removal of Welsh Plant, Unit 2, will be performed with Welsh Plant, Units 1 and 3, after retirement.
(f)Unit 1 is being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.

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

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

The remaining book value of Dolet Hills Power Station non-fuel related assets are recoverable by SWEPCo through a combination of base rates and rate riders. As of September 30, 2022, SWEPCo’s share of the net investment in the Dolet Hills Power Station was $113 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 September 30, 2022, SWEPCo had a net under-recovered fuel balance of $236 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.


161



In March 2021, the LPSC issued an order allowing SWEPCo to recover up to $20 million of fuel costs in 2021 and defer approximately $30 million of additional costs with a recovery period to be determined at a later date. In August 2022, the LPSC staff filed testimony recommending fuel disallowances of $72 million, including denial of recovery of the $30 million deferral, with refunds to customers over five years. In September 2022, SWEPCO filed rebuttal testimony addressing the LPSC staff recommendations.

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

In August 2022, SWEPCo filed a fuel reconciliation with the PUCT covering the fuel period of January 1, 2020 through December 31, 2021.

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

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

In 2020, management announced plans to retire the Pirkey Plant in 2023. The Pirkey Plant non-fuel costs are recoverable by SWEPCo through base rates and fuel costs are recovered through active fuel clauses and are subject to prudency determinations by the various commissions. As of September 30, 2022, SWEPCo’s share of the net investment in the Pirkey Plant was $216 million, including CWIP, before cost of removal. Sabine is a mining operator providing mining services to the Pirkey Plant. Under the provisions of the mining agreement, SWEPCo is required to pay, as part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. SWEPCo expects fuel deliveries, including billings of all fixed and operating costs, from Sabine to cease during the first quarter of 2023. Under the fuel agreements, SWEPCo’s fuel inventory and unbilled fuel costs from mining related activities were $49 million as of September 30, 2022. As of September 30, 2022, SWEPCo had a net under-recovered fuel balance of $236 million, inclusive of costs related to the Pirkey Plant billed by Sabine, but excluding impacts of the February 2021 severe winter weather event. Upon cessation of lignite deliveries by Sabine to the Pirkey Plant, additional operational, reclamation and other land-related costs incurred by Sabine will be billed to SWEPCo and included in existing fuel clauses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.


162



Regulatory Assets Pending Final Regulatory Approval (Applies to all Registrants except AEPTCo)
AEP
September 30,December 31,
20222021
 Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Earning a Return  
Pirkey Plant Accelerated Depreciation$150.7 $87.0 
Unrecovered Winter Storm Fuel Costs (a)126.1 430.2 
Welsh Plant, Units 1 and 3 Accelerated Depreciation75.7 45.9 
Dolet Hills Power Station Accelerated Depreciation 54.7 72.3 
Plant Retirement Costs – Unrecovered Plant, Louisiana35.2 35.2 
Dolet Hills Power Station Fuel Costs - Louisiana31.8 30.9 
Other Regulatory Assets Pending Final Regulatory Approval21.2 9.2 
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs306.5 241.8 
2017-2019 Virginia Triennial Under-Earnings37.0 — 
Plant Retirement Costs – Asset Retirement Obligation Costs25.9 25.9 
2020-2022 Virginia Triennial Under-Earnings25.3 15.1 
COVID-198.7 11.2 
Renewable Energy Portfolio Standards Costs - Virginia— 2.1 
Other Regulatory Assets Pending Final Regulatory Approval42.4 41.8 
Total Regulatory Assets Pending Final Regulatory Approval$941.2 $1,048.6 
(a) Includes $37 million and $63 million of unrecovered winter storm fuel costs recorded as a current regulatory asset as of September 30, 2022 and December 31, 2021, respectively.

AEP Texas
September 30,December 31,
20222021
Noncurrent Regulatory Assets(in millions)
Regulatory Assets Currently Earning a Return
Mobile Generation Lease Payments$9.2 $— 
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs27.0 22.4 
Vegetation Management Program5.2 5.2 
Texas Retail Electric Provider Bad Debt Expense4.1 4.1 
COVID-193.8 2.1 
Other Regulatory Assets Pending Final Regulatory Approval8.2 7.4 
Total Regulatory Assets Pending Final Regulatory Approval$57.5 $41.2 

163



APCo
September 30,December 31,
20222021
Noncurrent Regulatory Assets(in millions)
Regulatory Assets Currently Earning a Return
COVID-19 – Virginia$7.0 $6.8 
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs - West Virginia69.9 53.7 
2017-2019 Virginia Triennial Under-Earnings37.0 — 
Plant Retirement Costs – Asset Retirement Obligation Costs25.9 25.9 
2020-2022 Virginia Triennial Under-Earnings25.3 15.1 
Renewable Energy Portfolio Standards Costs - Virginia— 2.1 
Other Regulatory Assets Pending Final Regulatory Approval1.6 1.5 
Total Regulatory Assets Pending Final Regulatory Approval$166.7 $105.1 

 I&M
September 30,December 31,
20222021
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  
COVID-190.1 1.7 
Other Regulatory Assets Pending Final Regulatory Approval1.7 1.9 
Total Regulatory Assets Pending Final Regulatory Approval$1.9 $3.7 

 OPCo
September 30,December 31,
20222021
Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs$32.5 $3.8 
Other Regulatory Assets Pending Final Regulatory Approval0.1 — 
Total Regulatory Assets Pending Final Regulatory Approval$32.6 $3.8 

 PSO
September 30,December 31,
20222021
Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs$24.3 $13.9 
Other Regulatory Assets Pending Final Regulatory Approval0.1 0.3 
Total Regulatory Assets Pending Final Regulatory Approval$24.4 $14.2 
.
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SWEPCo
September 30,December 31,
20222021
Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Earning a Return  
Pirkey Plant Accelerated Depreciation$150.7 $87.0 
Unrecovered Winter Storm Fuel Costs (a)126.1 430.2 
Welsh Plant, Units 1 and 3 Accelerated Depreciation75.7 45.9 
Dolet Hills Power Station Accelerated Depreciation54.7 72.3 
Plant Retirement Costs Unrecovered Plant, Louisiana
35.2 35.2 
Dolet Hills Power Station Fuel Costs- Louisiana31.8 30.9 
Other Regulatory Assets Pending Final Regulatory Approval4.9 2.4 
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs151.3 148.0 
Asset Retirement Obligation - Louisiana11.3 10.3 
Other Regulatory Assets Pending Final Regulatory Approval14.9 18.4 
Total Regulatory Assets Pending Final Regulatory Approval$656.6 $880.6 
(a) Includes $37 million and $63 million of unrecovered winter storm fuel costs recorded as a current regulatory asset as of September 30, 2022 and December 31, 2021, respectively.

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 September 30, 2022, AEP Texas’ cumulative revenues from interim base rate increases that are subject to review is approximately $524 million. A base rate review could result in a refund to customers if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. AEP Texas is required to file for a comprehensive rate review no later than April 5, 2024.

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

2017-2019 Virginia Triennial Review

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

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

In October 2021, the Virginia SCC and additional intervenors filed briefs with the Virginia Supreme Court disagreeing with the items appealed by APCo in the Triennial Review decision. Additionally, the Virginia SCC and APCo filed briefs disagreeing with the items appealed by an intervenor in a separate appeal of the same decision. In March 2022, oral arguments were held at the Virginia Supreme Court.

In August 2022, the Virginia Supreme Court issued its opinion on submitted appeals of APCo’s 2017-2019 Virginia Triennial Review concluding that the Virginia SCC: a) erred in finding it was not reasonable for APCo to record all remaining costs associated with early retirement of certain coal-fired generating plants in the 2017-2019 earnings test period, b) did not err by ordering APCo to retroactively implement depreciation rates for the years 2018 and 2019 and c) did not err in finding that APCo’s affiliate costs from OVEC were reasonable. The Virginia Supreme Court then remanded the issue regarding the retired coal-fired plants back to the Virginia SCC for further proceedings.

In September 2022, and in response to the Virginia Supreme Court opinion and subsequent Virginia SCC order initiating a remand proceeding, APCo submitted with the Virginia SCC: (a) an updated 2017-2019 Virginia earnings calculation resulting in a proposed $37 million regulatory asset related to previously incurred costs that APCo is expecting to recover as a result of earning below its 2017-2019 authorized ROE band, (b) an updated requested annual base rate increase of $41 million effective October 2022 and (c) a requested rider to recover, over the period October 2022 through January 2024, approximately $72 million related to an APCo Virginia base rate increase for the period January 2021 through September 2022. APCo’s requested $41 million annual base rate increase includes
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approximately $12 million related to the recovery of APCo’s regulatory asset for previously incurred costs as a result of earning below its 2017-2019 authorized ROE band. APCo implemented interim base rate and rider rate increases effective October 2022, both of which are subject to refund and review by the Virginia SCC. An order from the Virginia SCC in the remand proceeding is expected in the fourth quarter of 2022.

In September 2022, APCo expensed the remaining $25 million closed coal plant regulatory asset that was previously ordered by the Virginia SCC and recorded a $37 million regulatory asset for previously incurred costs that APCo is expecting to recover as a result of earning below its 2017-2019 authorized ROE band. APCo’s October 2022 through January 2024 net income, cash flows and financial condition is expected to be positively impacted pending the Virginia SCC’s order on APCo’s requested base rate and rider rate increases.

2020-2022 Virginia Triennial Review

In March 2023, APCo will submit its required Virginia earnings test calculation for the 2020-2022 Triennial Review period. For Triennial Review periods in which a Virginia utility earns below its authorized ROE band, the utility may file to recover expenses incurred, up to the bottom of the authorized ROE band, related to major storms, the early retirement of fossil fuel generating assets and certain projects necessary to comply with state and federal environmental legislation. As of September 2022, APCo has deferred approximately $25 million related to previously incurred costs as a result of the current estimate that APCo will earn below the bottom of its authorized ROE band during the 2020-2022 Triennial Review period. If it is determined that APCo has earned above the bottom of its authorized ROE band for the 2020-2022 Triennial Review period it could reduce future net income and cash flows and impact financial conditions.

CCR/ELG Compliance Plan Filings

In December 2020, APCo submitted filings with the Virginia SCC and WVPSC requesting approvals necessary to implement CCR/ELG compliance plans at the Amos and Mountaineer Plants. In August 2021, the Virginia SCC issued an order approving recovery of CCR-related operation and maintenance expenses and investments at the Amos and Mountaineer Plants through an active rider. The order also denied APCo’s request to recover the cost of ELG investments and denied recovery of previously incurred ELG costs, but did not preclude APCo from refiling for approval. In March 2022, APCo refiled for approval to recover the cost of the ELG investments and previously incurred ELG costs. Intervenor testimony was submitted in August 2022 recommending the denial of ELG cost recovery. In October 2022, a Virginia Hearing Examiner recommended that the Virginia SCC approve recovery of APCo’s requested ELG investment costs at Amos and Mountaineer Plants. Management expects to receive an order from the Virginia SCC in the fourth quarter of 2022.

Also in August 2021, the WVPSC approved the request to construct CCR/ELG investments at the Amos and Mountaineer Plants and approved recovery of the West Virginia jurisdictional share of these costs through an active rider. In October 2021, due to the Virginia SCC previously rejecting those ELG investments, the WVPSC issued an order directing APCo to proceed with CCR/ELG compliance plans that would allow the plants to continue operating beyond 2028. The WVPSC also ordered that APCo will be given the opportunity to recover, from West Virginia customers, the ELG and new capital and operating costs arising solely from the WVPSC's directive to operate the plants beyond 2028 if the WVPSC finds that the costs are reasonably and prudently incurred. The October 2021 order further states that unless the Virginia jurisdictional customers of APCo pay for their share of costs for ELG improvements and costs necessary to continue operations beyond 2028, the benefit of the capacity and energy made possible by those improvements and operating the Amos and Mountaineer Plants beyond 2028 should benefit only West Virginia and FERC jurisdictional customers who have shared in paying for those costs.

APCo expects the total Amos and Mountaineer Plant ELG investment, excluding AFUDC, to be approximately $162 million. As of September 30, 2022, APCo’s Virginia jurisdictional share of the net book value, before cost of removal including CWIP and inventory, of the Amos and Mountaineer Plants was approximately $1.5 billion and APCo’s Virginia jurisdictional share of its ELG investment balance in CWIP for these plants was $62 million.

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

2021 and 2022 ENEC (Expanded Net Energy Cost) Filings

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

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

In April 2022, the Companies submitted their 2022 annual ENEC filing with the WVPSC requesting a $297 million annual increase in ENEC revenues, inclusive of the previously requested $155 million increase, effective September 1, 2022.

In September 2022, following an agreed upon delay in the proceedings of the Companies’ 2022 ENEC case, certain intervenors submitted testimony recommending disallowances of at least $83 million to the Companies’ historical period ENEC under-recovery balance along with proposals to either securitize the Companies’ remaining ENEC balance or defer recovery of this balance beyond the traditional one-year period. West Virginia Staff recommended a $13 million increase in ENEC rates pending the outcome of the ENEC prudency review. Management expects to receive a WVPSC order on the Companies’ 2022 ENEC filing in the fourth quarter of 2022 and a separate WVPSC order on the prudency review of the Companies’ ENEC costs in the first quarter of 2023. As of September 30, 2022, the Companies’ cumulative ENEC under-recovery was $430 million. If any deferred ENEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

June 2022 West Virginia Storm Costs

In June 2022, the West Virginia service territories of APCo and WPCo (the Companies) were impacted by strong winds from multiple storms resulting in system damages and power outages. As of September 30, 2022, the Companies incurred and deferred an estimated $15 million in incremental distribution operation and maintenance expenses related to service restoration efforts. The Companies will seek recovery of these deferrals in future filings. If any of the storm restoration costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.


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ETT Rate Matters (Applies to AEP)

ETT Interim Transmission Rates

AEP has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next base rate proceeding. Through September 30, 2022, AEP’s share of ETT’s cumulative revenues that are subject to review is approximately $1.5 billion. A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. ETT is required to file for a comprehensive rate review no later than February 1, 2023, during which the $1.5 billion of cumulative revenues above will be subject to review.

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

Michigan Power Supply Cost Recovery (PSCR) Reconciliation

In April 2022, an Administrative Law Judge (ALJ) issued a Proposal for Decision (PFD) for I&M’s PSCR reconciliation for the 12-month period ending December 31, 2020, recommending the MPSC disallow approximately $8 million of purchased power costs that I&M incurred under the Inter-Company Power Agreement with OVEC and the Unit Power Agreement with AEGCo. In May 2022, I&M submitted exceptions to the ALJ’s PFD related to the recommended disallowance of purchased power costs described above. I&M anticipates that the MPSC will issue a final decision in the fourth quarter of 2022. Management is unable to predict the impact, if any, that the MPSC’s final decision may have on future results of operations, financial condition and cash flows.

Indiana Earnings Test Filings

I&M is required by Indiana law to submit an earnings test evaluation for the most recent one-year and five-year periods as part of I&M’s semi-annual Indiana FAC filings. These earnings test evaluations require I&M to include a credit in the FAC factor computation for periods in which I&M earned above its authorized return for both the one-year and five-year periods. The credit is determined as 50% of the lower of the one-year or five-year earnings above the authorized level. In August 2022, I&M submitted its FAC filing and earnings test evaluation for the period ended May 2022, which calculated a credit due to customers of $14 million. In October 2022, the IURC approved the FAC filing and earnings test evaluation, with the credit to customers starting in November 2022 through the FAC.

2022 Michigan Integrated Resource Plan (IRP) Filing

In February 2022, I&M filed a request with the MPSC for approval of its 2022 IRP. Included in that filing were requests for approval and deferral of costs associated with resources commencing construction within three years of the Commission’s order in the filing. These resources include the new generation resources expected to be in-service by 2028, and demand-side resources, including load management programs and conservation voltage reduction investments. I&M is also requesting MPSC approval of I&M’s Rockport Unit 2 transition plan consistent with that approved by the IURC, including certain cost recovery related to remaining net book value of leasehold improvements made during the term of the Rockport Unit 2 lease and future use of Rockport Unit 2 as a capacity resource. In addition, I&M has made requests for approval of a financial incentive on certain power purchase agreements and load management programs. As of September 30, 2022, I&M’s total net book value for these Rockport Unit 2 leasehold improvements was $102 million.

In June 2022, intervening parties recommended various adjustments to I&M’s proposals, including the process I&M would use to receive approval of new generation resources, changes to or denial of requested financial incentives and requests for deferral and pre-approval of costs. Specific to I&M’s Rockport Unit 2 transition plan, certain
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intervening parties recommended that the MPSC order I&M to credit back to Michigan ratepayers the jurisdictional share of post-lease revenues in excess of costs from Rockport Unit 2’s operations as a merchant facility and that I&M only receive a post-lease debt return on remaining net book value of Rockport Unit 2 leasehold improvements. A hearing with the MPSC was held in August 2022.

Management currently anticipates that the MPSC will issue an order on I&M’s 2022 Michigan IRP filing in the first quarter of 2023. Any disallowance or reduction in the recovery of the I&M Michigan jurisdictional share of the Rockport Unit 2 leasehold improvements could reduce future net income and cash flows and impact financial condition.    

KPCo Rate Matters (Applies to AEP)

CCR/ELG Compliance Plan Filings

KPCo and WPCo each own a 50% interest in the Mitchell Plant. As of September 30, 2022, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $576 million. In December 2020 and February 2021, WPCo and KPCo filed requests with the WVPSC and KPSC, respectively, to obtain the regulatory approvals necessary to implement CCR and ELG compliance plans and seek recovery of the estimated $132 million investment for the Mitchell Plant that would allow the plant to continue operating beyond 2028. Within those requests, WPCo and KPCo also filed a $25 million alternative to implement only the CCR-related investments with the WVPSC and KPSC, respectively, which would allow the Mitchell Plant to continue operating only through 2028.

In July 2021, the KPSC issued an order approving the CCR only alternative and rejecting the full CCR and ELG compliance plan. In May 2022, the KPSC approved recovery of the Kentucky jurisdictional share of ELG costs incurred at the Mitchell Plant prior to July 15, 2021.

In August 2021, the WVPSC approved the full CCR and ELG compliance plan for the WPCo share of the Mitchell Plant. In September 2021, WPCo submitted a filing with the WVPSC to reopen the CCR/ELG case that was approved by the WVPSC in August 2021. Due to the rejection by the KPSC of the KPCo share of the ELG investments, WPCo requested the WVPSC consider approving the construction and recovery of all ELG costs at the plant. In October 2021, the WVPSC affirmed its August 2021 order approving the construction of CCR/ELG investments and directed WPCo to proceed with CCR/ELG compliance plans that would allow the plant to continue operating beyond 2028. The WVPSC also ordered that WPCo will be given the opportunity to recover, from its customers, the ELG and new capital and operating costs arising solely from the WVPSC's directive to operate the plant beyond 2028 if the WVPSC finds that the costs are reasonably and prudently incurred. The WVPSC’s order further states that unless KPCo pays for its share of costs for ELG improvements and costs necessary to continue operations beyond 2028, the benefit of the capacity and energy made possible by those improvements and operating Mitchell Plant beyond 2028 should benefit only West Virginia jurisdictional customers who have shared in paying for those costs.

OPCo Rate Matters (Applies to AEP and OPCo)

OVEC Cost Recovery Audits

In December 2021, as part of OVEC cost recovery audits pending before the PUCO, intervenors filed positions claiming that costs incurred by OPCo during the 2018-2019 audit period were imprudent and should be disallowed. In May 2022, intervenors filed for rehearing on the 2016-2017 OVEC cost recovery audit period claiming the PUCO’s April 2022 order to adopt the findings of the audit report were unjust, unlawful and unreasonable for multiple reasons, including the position that OPCo recovered imprudently incurred costs. In June 2022, the PUCO granted rehearing on the 2016-2017 audit period for purposes of further consideration. Management disagrees with these claims and is unable to predict the impact, if any, these disputes may have on future results of operations,
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financial condition and cash flows. See "OVEC" section of Note 17 in the 2021 Annual Report for additional information on AEP and OPCo’s investment in OVEC.

June 2022 Storm Costs

In June 2022, the service territory of OPCo was impacted by strong winds from multiple storms resulting in power outages and damage to the transmission and distribution infrastructures. As of September 30, 2022, OPCo had incurred approximately $19 million in incremental operation and maintenance costs related to service restoration efforts. The incremental storm restoration costs have been deferred as regulatory assets and OPCo is expected to seek recovery in a future filing. In July 2022, intervenors filed a motion requesting the PUCO open a formal investigation into the power outages that occurred as a result of the June storms and determine if OPCo was negligent and liable to consumers for damages incurred as a result of the power outages. If any of the storm restoration costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

PSO Rate Matters (Applies to AEP and PSO)

February 2021 Severe Winter Weather Impacts in SPP

In February 2021, severe winter weather had a significant impact in SPP, resulting in the declaration of Energy Emergency Alert Levels 2 and 3 for the first time in SPP’s history. The winter storm increased the demand for natural gas and restricted the available natural gas supply resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system.

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

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

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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. SWEPCo and the PUCT submitted Petitions for Review with the Texas Supreme Court in November 2021. In October 2022, the Texas Supreme Court denied the Petitions for Review submitted by SWEPCo and the PUCT. SWEPCo plans to file a request for rehearing. If SWEPCo’s request for rehearing is denied, the case will be remanded to the PUCT for future proceedings.

Management does not believe a disallowance of capitalized Turk Plant costs or a revenue refund is probable as of September 30, 2022. However, if SWEPCo is ultimately unable to recover AFUDC in excess of the Texas jurisdictional capital cost cap, it would be expected to result in a pretax net disallowance ranging from $80 million to $90 million. In addition, if AFUDC is ultimately determined to be included in the Texas jurisdictional capital cost cap, SWEPCo estimates it may be required to make customer refunds ranging from $0 to $180 million related to revenues collected from February 2013 through September 2022 and such determination may reduce SWEPCo’s future revenues by approximately $15 million on an annual basis.

2016 Texas Base Rate Case

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

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

2020 Texas Base Rate Case

In October 2020, SWEPCo filed a request with the PUCT for a $105 million annual increase in Texas base rates based upon a proposed 10.35% ROE. The request would move transmission and distribution interim revenues recovered through riders into base rates. Eliminating these riders would result in a net annual requested base rate increase of $90 million primarily due to increased investments. SWEPCo subsequently filed a request with the PUCT lowering the requested annual increase in Texas base rates to $100 million which would result in an $85 million net annual base rate increase after moving the proposed riders to rate base.

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 that would recover the Dolet Hills Power Station as if it were in rate base until its retirement at the end of 2021 and starting in 2022 the remaining net book value would be recovered as a regulatory asset through 2046. 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 subsequently revised the requested annual increase to $114 million to reflect removing hurricane storm restoration costs from the base case filing. The hurricane costs have been requested in a separate storm filing. See “2021 Louisiana Storm Cost Filing” below for more information. The base case filing would extend the formula rate plan for five years and includes modifications to the formula rate plan to allow for forward-looking transmission costs, reflects the impact of net operating losses associated with the acceleration of certain tax benefits and incorporates future federal corporate income tax changes. The proposed net annual increase requests a $32 million annual depreciation increase to recover Louisiana’s share of the Dolet Hills Power Station, Pirkey Plant and Welsh Plant, all of which are expected to be retired early.

In July 2021, the LPSC staff filed testimony supporting a $6 million annual increase in base rates based upon a ROE of 9.1% while other intervenors recommended a ROE ranging from 9.35% to 9.8%. The primary differences between SWEPCo’s requested annual increase in base rates and the LPSC staff’s recommendation include: (a) a reduction in depreciation expense, (b) recovery of Dolet Hills Power Station and Pirkey Plant in a separate rider mechanism, (c) the rejection of SWEPCo’s proposed adjustment to include a stand-alone net operating loss carryforward deferred tax asset in rate base and (d) a reduction in the proposed ROE. In August 2022, in a separate proceeding, the LPSC staff recommended recovery of, but no return on, the Dolet Hills Power Station based on a five-year recovery period if the remaining net book value is not recovered utilizing securitization. Additionally, the LPSC staff recommended that the remaining net book value be reduced for depreciation expenses, and operation and maintenance costs in rates since the plant was retired in December 2021.

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

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

2021 Arkansas Base Rate Case

In July 2021, SWEPCo filed a request with the APSC for an $85 million annual increase in Arkansas base rates based upon a proposed 10.35% ROE with a capital structure of 48.7% debt and 51.3% common equity. The proposed annual increase includes: (a) a $41 million revenue requirement for the North Central Wind Facilities, (b) a $14 million annual depreciation increase primarily due to recovery of the Dolet Hills Power Station through 2026 and Pirkey Plant and Welsh Plant, Units 1 and 3 through 2037 and (c) a $6 million increase due to SPP costs. In January 2022, SWEPCo filed testimony revising the requested annual increase in Arkansas base rates to $81 million. SWEPCo requested that rates become effective in June 2022.

In May 2022, the APSC issued a final order approving an annual revenue increase of $49 million based upon a 9.5% ROE. The order also includes: (a) a capital structure of 55% debt and 45% common equity, (b) approval to recover the Dolet Hills Power Station as a regulatory asset over five years without a return on this investment resulting in an immaterial disallowance in the second quarter of 2022, (c) the denial of accelerated depreciation for the Pirkey Plant and Welsh Plant, Units 1 and 3 and (d) approval of a rider to recover SPP costs and revenues. The final order also denied the inclusion of the stand-alone NOLC in SWEPCo’s deferred tax assets, but included approval of the deferral of the forgone revenue requirement associated with the NOLC and excess NOLC, with recovery of the deferral contingent upon receipt of a supportive private letter ruling from the IRS. Rates were implemented with the first billing cycle of July 2022.

2021 Louisiana Storm Cost Filing

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

February 2021 Severe Winter Weather Impacts in SPP

As discussed in the “PSO Rate Matters” section above, severe winter weather had a significant impact in SPP, resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system. For the time period of February 9, 2021, to February 20, 2021, SWEPCo’s natural gas expenses and purchases of electricity still to be recovered from customers are $349 million as of September 30, 2022, of which $85 million, $126 million and $138 million is related to the Arkansas, Louisiana and Texas jurisdictions, respectively.

In March 2021, the APSC issued an order authorizing recovery of the Arkansas jurisdictional share of the retail customer fuel costs over five years, with the appropriate carrying charge to be determined at a later date. Subsequently, SWEPCo began recovery of these fuel costs. In April 2021, SWEPCo filed testimony supporting a
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five-year recovery with a carrying charge of 6.05%. In June 2022, the APSC ordered SWEPCo to recover the Arkansas jurisdictional share of the fuel costs over six years with a carrying charge equal to its weighted average cost of capital, subject to a prudency review and true-up.

In March 2021, the LPSC approved a special order granting a temporary modification to the FAC and shortly after SWEPCo began recovery of its Louisiana jurisdictional share of these fuel costs based on a five-year recovery period inclusive of an interim carrying charge of 3.25%. SWEPCo will work with the LPSC to finalize the actual recovery period and determine the appropriate carrying charge in future proceedings.

In August 2021, SWEPCo filed an application with the PUCT to implement a net interim fuel surcharge for the Texas jurisdictional share of these retail fuel costs. The application requested a five-year recovery with a carrying charge of 7.18%. In March 2022, the PUCT ordered SWEPCo to recover the Texas jurisdictional share of the fuel costs over five years with a carrying charge of 1.65% and ordered SWEPCo to file a fuel reconciliation addressing fuel costs from January 1, 2020 through December 31, 2021.

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

FERC Rate Matters

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

In May 2021, certain joint customers submitted a formal challenge at the FERC related to the 2020 Annual Update of the 2019 SPP Transmission Formula Rates of the AEP transmission owning subsidiaries within SPP. In March 2022, the FERC issued an order on the formal challenge which ruled in favor of the joint customers on several issues. Management has determined that the result of the order will have an immaterial impact to the financial statements of AEP, AEPTCo, PSO and SWEPCo.

Independence Energy Connection Project (Applies to AEP)

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

In September 2021, PJM notified Transource Energy that the IEC was suspended to allow for the regulatory and related appeals process to proceed in an orderly manner without breaching milestone dates in the project agreement. At that time, PJM stated that the IEC has not been cancelled and remains necessary to alleviate congestion. PJM continues to evaluate reliability and market efficiency in the area. As of September 30, 2022, AEP’s share of IEC capital expenditures was approximately $83 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.


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

In February 2022, the Office of the Ohio Consumers’ Counsel 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 Ohio Consumers’ Counsel’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. Management believes its financial statements adequately address the impact of the February 2022 complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, 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 2021 Annual Report should be read in conjunction with this report.

GUARANTEES

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

Letters of Credit (Applies to AEP and AEP Texas)

Standby letters of credit are entered into with third-parties.  These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.

AEP has $4 billion and $1 billion revolving credit facilities due in March 2027 and 2024, respectively, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of September 30, 2022, no letters of credit were issued under the revolving credit facility.

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility.  AEP issues letters of credit on behalf of subsidiaries under five uncommitted facilities totaling $400 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of September 30, 2022 were as follows:
CompanyAmountMaturity
 (in millions) 
AEP$309.9 October 2022 to August 2023
AEP Texas1.8 July 2023


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Guarantees of Equity Method Investees (Applies to AEP)

In 2019, AEP acquired Sempra Renewables LLC. The transaction resulted in the acquisition of a 50% ownership interest in five non-consolidated joint ventures and the acquisition of two tax equity partnerships. Parent has issued guarantees over the performance of the joint ventures. If a joint venture were to default on payments or performance, Parent would be required to make payments on behalf of the joint venture. As of September 30, 2022, the maximum potential amount of future payments associated with these guarantees was $120 million, with the last guarantee expiring in December 2037. The non-contingent liability recorded associated with these guarantees was $5 million, with an additional $395 thousand 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 September 30, 2022, there were no material liabilities recorded for any indemnifications.

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

Master Lease Agreements (Applies to all Registrants except AEPTCo)

The Registrants lease certain equipment under master lease agreements.  Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee.  Historically, at the end of the lease term the fair value has been in excess of the amount guaranteed.  As of September 30, 2022, 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$45.9 
AEP Texas10.9 
APCo6.3 
I&M4.3 
OPCo7.4 
PSO4.8 
SWEPCo5.4 


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Rockport Lease (Applies to AEP and I&M)

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

The trusts own undivided interests in Rockport Plant, Unit 2 and leases equal portions to AEGCo and I&M.  In April 2021, AEGCo and I&M executed an agreement to purchase 100% of the interests in the Rockport Plant, Unit 2 effective at the end of the lease term in December 2022. In December 2021, AEGCo and I&M satisfied the necessary regulatory approvals to complete the acquisition. Upon receipt of the regulatory approval, the addition of the lessee forward purchase obligation resulted in the modified lease changing classification from operating to finance for AEGCo and I&M. The future minimum lease payments as of September 30, 2022, inclusive of the purchase obligation, were as follows:

Future Minimum Lease PaymentsAEP (a)I&M
(in millions)
2022$174.9 $87.4 
Total Future Minimum Lease Payments$174.9 $87.4 

(a)AEP’s future minimum lease payments include equal shares from AEGCo and I&M.

The lease modification also created variable interests in the trusts that own the undivided interests in Rockport Plant, Unit 2 for AEGCo and I&M. Neither AEGCo nor I&M are the primary beneficiaries of the trusts because AEGCo nor I&M has the power to direct the most significant activities of the trusts. AEP and I&M’s maximum exposure to loss associated with the trust is equal to the total future minimum lease payments, inclusive of the purchase obligation, as shown in the table above.

AEPRO Boat and Barge Leases (Applies to AEP)

In 2015, AEP sold its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. Certain boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the respective lessors, ensuring future payments under such leases with maturities up to 2027. As of September 30, 2022, the maximum potential amount of future payments required under the guaranteed leases was $36 million. Under the terms of certain of the arrangements, upon the lessors exercising their rights after an event of default by the nonaffiliated party, AEP is entitled to enter into new lease arrangements as a lessee that would have substantially the same terms as the existing leases. Alternatively, for the arrangements with one of the lessors, upon an event of default by the nonaffiliated party and the lessor exercising its rights, payment to the lessor would allow AEP to step into the lessor’s rights as well as obtaining title to the assets. Under either situation, AEP would have the ability to utilize the assets in the normal course of barging operations. AEP would also have the right to sell the acquired assets for which it obtained title. As of September 30, 2022, AEP’s boat and barge lease guarantee liability was $2 million, of which $1 million was recorded in Other Current Liabilities and $1 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets.

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

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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

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

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

After the litigation proceeded at the district court and appellate court, in April 2021, I&M and AEGCo reached an agreement to acquire 100% of the interests in Rockport Plant, Unit 2 for $116 million from certain financial institutions that own the unit through trusts established by Wilmington Trust, the nonaffiliated owner trustee of the ownership interests in the unit, with closing to occur as of the end of the Rockport Plant, Unit 2 lease in December 2022. The agreement is subject to customary closing conditions and as of the closing will result in a final settlement of, and release of claims in, the lease litigation. As a result, in May 2021, at the parties’ request, the district court entered a stipulation and order dismissing the case without prejudice to plaintiffs asserting their claims in a re-filed action or a new action. The required regulatory approvals at the IURC and FERC have been obtained that would allow the closing to occur as of the end of the lease in December 2022. Management believes its financial statements appropriately reflect the resolution of the litigation.

Upon the end of the Rockport Unit 2 lease in December 2022, AEGCo’s 50% ownership share of Rockport Unit 2 will be billed 100% to I&M under a FERC-approved unit power agreement. In addition, upon the end of the Rockport Unit 2 lease, I&M’s 50% ownership share of Rockport Unit 2 and I&M’s purchased power from AEGCo related to Rockport Unit 2 will be a merchant resource for I&M until Rockport Unit 2 is retired. A 2021 IURC order approved a settlement agreement addressing the future use of Rockport Unit 2 as a short-term capacity resource through the June 2023 - May 2024 PJM planning year. I&M has a similar proposal pending before the MPSC in I&M’s 2022 Michigan Integrated Resource Plan (IRP) filing. If I&M cannot recover its future investment and expenses related to the merchant share of Rockport Unit 2, it could reduce future net income and cash flows and impact financial condition.
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Claims Challenging Transition of American Electric Power System Retirement Plan to Cash Balance Formula 

Four participants in The American Electric Power System Retirement Plan (the Plan) filed a class action complaint in December 2021 in the U.S. District Court for the Southern District of Ohio against AEPSC and the Plan. When the Plan’s benefit formula was changed in the year 2000, AEP provided a special provision for employees hired before January 1, 2001, allowing them to continue benefit accruals under the then benefit formula for a full 10 years alongside of the new cash balance benefit formula then being implemented.  Employees who were hired on or after January 1, 2001 accrued benefits only under the new cash balance benefit formula.  The plaintiffs assert a number of claims on behalf of themselves and the purported class, including that: (a) the Plan violates the requirements under the Employee Retirement Income Security Act (ERISA) intended to preclude back-loading the accrual of benefits to the end of a participant’s career, (b) the Plan violates the age discrimination prohibitions of ERISA and the Age Discrimination in Employment Act and (c) AEP failed to provide required notice regarding the changes to the Plan. Among other relief, the Complaint seeks reformation of the Plan to provide additional benefits and the recovery of plan benefits for former employees under such reformed plan. The plaintiffs previously had submitted claims for additional plan benefits to AEP, which were denied. On February 15, 2022, AEPSC and the Plan filed a motion to dismiss the complaint for failure to state a claim. On August 16, 2022, the district court granted the motion to dismiss the complaint without prejudice. The plaintiffs have filed a motion for leave to file an amended complaint. AEP will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

Litigation Related to Ohio House Bill 6 (HB 6)

In 2019, Ohio adopted and implemented HB 6 which benefits OPCo by authorizing rate recovery for certain costs including renewable energy contracts and OVEC’s coal-fired generating units. OPCo engaged in lobbying efforts and provided testimony during the legislative process in connection with HB 6. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of an Ohio legislator and associates in connection with an alleged racketeering conspiracy involving the adoption of HB 6. After AEP learned of the criminal allegations against the Ohio legislator and others relating to HB 6, 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 United States District Court for the Southern District of Ohio against AEP and certain of its officers for alleged violations of securities laws. The amended complaint alleged misrepresentations or omissions by AEP regarding: (a) its alleged participation in or connection to public corruption with respect to the passage of HB 6 and (b) its regulatory, legislative, political contribution, 501(c)(4) organization contribution and lobbying activities in Ohio. The complaint sought monetary damages, among other forms of relief. In December 2021, the district court issued an opinion and order dismissing the securities litigation complaint with prejudice, determining that the complaint failed to plead any actionable misrepresentations or omissions. The plaintiffs did not appeal the ruling.

In January 2021, an AEP shareholder filed a derivative action in the United States District Court for the Southern District of Ohio purporting to assert claims on behalf of AEP against certain AEP officers and directors. In February 2021, a second AEP shareholder filed a similar derivative action in the Court of Common Pleas of Franklin County, Ohio. In April 2021, a third AEP shareholder filed a similar derivative action in the U.S. District Court for the Southern District of Ohio and a fourth AEP shareholder filed a similar derivative action in the Supreme Court for the State of New York, Nassau County. These derivative complaints allege the officers and directors made misrepresentations and omissions similar to those alleged in the putative securities class action lawsuit filed against AEP. The derivative complaints together assert claims for: (a) breach of fiduciary duty, (b) waste of corporate assets, (c) unjust enrichment, (d) breach of duty for insider trading and (e) contribution for violations of sections 10(b) and 21D of the Securities Exchange Act of 1934; and seek monetary damages and changes to AEP’s corporate governance and internal policies among other forms of relief. The 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 its motion to dismiss on April 29, 2022. On September 13, 2022, the New York state court granted the motion to dismiss with prejudice and plaintiffs have filed a notice of appeal with the New York appellate court. The two derivative actions pending in federal district court in Ohio have been consolidated
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and the plaintiffs in the consolidated action filed an amended complaint. AEP filed a motion to dismiss on May 3, 2022 and briefing on the motion to dismiss has been completed. Discovery remains stayed pending the district court’s ruling on the motion to dismiss. The plaintiff in the Ohio state court case advised that they no longer agreed to stay the proceedings, therefore, AEP filed a motion to continue the stays of proceedings on May 20, 2022 and the plaintiff filed an amended complaint on June 2, 2022. On June 15, 2022, the Ohio state court entered an order continuing the stays of that case until the resolution of the consolidated derivative actions pending in Ohio federal district court. The defendants will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

In March 2021, AEP received a litigation demand letter from counsel representing a purported AEP shareholder. The litigation demand letter is directed to the Board of Directors of AEP and contains factual allegations involving HB 6 that are generally consistent with those in the derivative litigation filed in state and federal court. The letter demands, among other things, that the AEP Board undertake an independent investigation into alleged legal violations by directors and officers, and that, following such investigation, AEP commence a civil action for breaches of fiduciary duty and related claims and take appropriate disciplinary action against those individuals who allegedly harmed the company. The shareholder that sent the letter has since withdrawn the litigation demand, which is now terminated and of no further effect.

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


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6. ACQUISITIONS, ASSETS AND LIABILITIES HELD FOR SALE, DISPOSITIONS AND IMPAIRMENTS

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

ACQUISITIONS

Dry Lake Solar Project (Generation & Marketing Segment) (Applies to AEP)

In November 2020, AEP signed a Purchase and Sale Agreement with a nonaffiliate to acquire a 75% interest in the entity that owns the 100 MW Dry Lake Solar Project (collectively referred to as Dry Lake) located in southern Nevada for approximately $114 million. In March 2021, AEP closed the transaction and the solar project was placed in-service in May 2021. Approximately $103 million of the purchase price was paid upon closing of the transaction and the remaining $11 million was paid when the project was placed in-service. In accordance with the accounting guidance for “Business Combinations,” management determined that the acquisition of Dry Lake represents an asset acquisition. Additionally, and in accordance with the accounting guidance for “Consolidation,” management concluded that Dry Lake is a VIE and that AEP is the primary beneficiary based on its power as managing member to direct the activities that most significantly impact Dry Lake’s economic performance. As the primary beneficiary of Dry Lake, AEP consolidates Dry Lake into its financial statements. As a result, to account for the initial consolidation of Dry Lake, management applied the acquisition method by allocating the purchase price based on the relative fair value of the assets acquired and noncontrolling interest assumed.  The fair value of the primary assets acquired and the noncontrolling interest assumed was determined using the market approach.  The key input assumptions were the transaction price paid for AEP’s interest in Dry Lake and recent third-party market transactions for similar solar generation facilities. The nonaffiliated interest in Dry Lake is presented in Noncontrolling Interests on the balance sheets. Subsequent to close of the transaction, the noncontrolling interest made additional asset contributions of $16 million. As of September 30, 2022, AEP recognized approximately $143 million of Property, Plant and Equipment and approximately $34 million of Noncontrolling Interest on the balance sheets.

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

In 2020, PSO and SWEPCo received regulatory approvals to acquire the NCWF, comprised of three Oklahoma wind facilities totaling 1,484 MWs, on a fixed cost turn-key basis at completion. 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 beginning at commercial operation and until such time as amounts are reflected in base rates. Recovery of the Arkansas portion of the NCWF revenue requirement through base rates was approved by the APSC in May 2022. The NCWF are subject to various regulatory performance requirements. If these performance requirements are not met, PSO and SWEPCo would recognize a regulatory liability to refund retail customers.

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

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

In March 2022, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Traverse during its development and construction for $1.2 billion, 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.

In accordance with the guidance for “Business Combinations,” management determined that the acquisitions of the NCWF projects represent asset acquisitions.  As of September 30, 2022, PSO and SWEPCo had approximately $894 million and $1.1 billion, of gross Property, Plant and Equipment on the balance sheets, respectively, related to the NCWF projects. On an ongoing basis, management further determined that PSO and SWEPCo should apply the joint plant accounting model to account for their respective undivided interests in the assets, liabilities, revenues and expenses of the NCWF projects.

The respective Purchase and Sale Agreements (PSAs) include interests in numerous land contracts, as originally executed between the nonaffiliated party and the respective owners of the properties as defined in the contracts. These contracts provide for easement and access rights to the land that Sundance, Maverick and Traverse were built upon. The lessee interests in the land contracts were transferred to Sundance, Maverick and Traverse (and subsequently to PSO and SWEPCo) as a part of the closings of the respective PSAs. The current Obligations Under Operating Leases related to the NCWF projects were immaterial as of September 30, 2022 and December 31, 2021 for PSO and SWEPCo. See the table below for the noncurrent Obligations Under Operating Leases for the NCWF projects for PSO and SWEPCo:
PSOSWEPCo
September 30, 2022December 31, 2021September 30, 2022December 31, 2021
(in millions)
Project
Sundance$12.6 $12.6 $15.0 $15.1 
Maverick18.0 18.0 21.6 21.6 
Traverse39.7 — 47.7 — 
Total$70.3 $30.6 $84.3 $36.7 

ASSETS AND LIABILITIES HELD FOR SALE

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. In May 2022, the KPSC approved the transfer of KPCo to Liberty subject to certain conditions contingent upon the closing of the sale. AEP has received clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and the Committee on Foreign Investment in the United States. The sale remains subject to FERC approval under Section 203 of the Federal Power Act.

In September 2022, AEP, AEPTCo and Liberty entered into an amendment (Amendment) to the SPA which reduced the purchase price to approximately $2.646 billion and Liberty agreed to waive, upon FERC approval of the sale, the SPA condition precedent to closing requiring the issuance of regulatory orders approving a new proposed Mitchell Plant Operations and Maintenance Agreement and Mitchell Plant Ownership Agreement between KPCo and WPCo. The Amendment also provided that the closing shall not occur prior to January 4, 2023, unless mutually agreed to by AEP and Liberty.

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Mitchell Plant Operations and Maintenance Agreement and Ownership Agreement

KPCo and WPCo each own a 50% undivided interest in the 1,560 MW coal-fired Mitchell Plant. As of September 30, 2022, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $576 million.

In November 2021, AEP made filings with the KPSC, WVPSC and FERC seeking approval of a new proposed Mitchell Plant Operations and Maintenance Agreement and Mitchell Plant Ownership Agreement. In February 2022, AEP filed a motion to withdraw its filing with the FERC. The KPSC and WVPSC issued orders addressing AEP’s filings in May 2022 and July 2022. Those orders proposed materially different modifications to the Mitchell Plant agreements filed by AEP such that the new agreements could not be executed by the parties. In lieu of new agreements, in July 2022, KPCo and WPCo confirmed with the KPSC and WVPSC, respectively, that they will continue operating under the existing Mitchell Agreement, utilizing the Mitchell Agreement Operating Committee’s authority under that agreement to issue appropriate resolutions so the parties can operate in accordance with each state commission’s directives related to CCR and ELG investment. In September 2022, pursuant to resolutions under the existing Mitchell Plant agreement, WPCo replaced KPCo as the Operator of Mitchell Plant.

Transfer of Ownership

FERC Proceedings

In December 2021, Liberty, KPCo and KTCo requested FERC approval of the sale under Section 203 of the Federal Power Act. In February 2022, several intervenors in the case filed protests related to whether the sale will negatively impact the wholesale transmission rates of applicants. In April 2022, the FERC issued a deficiency letter stating that the Section 203 application is deficient and that additional information is required to process it. In May 2022, Liberty, KPCo and KTCo supplemented the application and in June 2022, the FERC issued an order formally notifying AEP that it was exercising its ability to take up to an additional 180 days to act on the application. An order from the FERC is expected in the fourth quarter of 2022.

KPSC Proceedings

In May 2022, the KPSC approved the transfer of KPCo to Liberty subject to conditions contingent upon the closing of the sale, including establishment of regulatory liabilities to subsidize retail customer transmission and distribution expenses, a fuel adjustment clause bill credit, and a three-year Big Sandy decommissioning rider rate holiday during which KPCo’s carrying charge is reduced by 50%. As a result of the conditions imposed by KPSC, in the second quarter of 2022, AEP recorded a $69 million loss on the expected sale of the Kentucky Operations in accordance with accounting guidance for Fair Value Measurement.

Further, as a result of the Amendment and the change to the anticipated timing of the completion of the transaction, AEP recorded an additional $194 million pretax loss ($149 million net of tax) on the expected sale of the Kentucky Operations in the third quarter of 2022 in accordance with the accounting guidance for Fair Value Measurement. AEP recorded a $263 million pretax loss ($218 million net of tax) on the expected sale of the Kentucky Operations for the nine months ended September 30, 2022. AEP expects cash proceeds, net of taxes and transaction fees, from the sale of approximately $1.2 billion.

Subject to receipt of FERC authorization under Section 203 of the Federal Power Act, the sale is expected to close in January 2023 with Liberty acquiring the assets and assuming the liabilities of KPCo and KTCo, excluding pension and other post-retirement benefit plan assets and liabilities. AEP expects to provide customary transition services to Liberty for a period of time after closing of the transaction. AEP plans to use the proceeds from the sale to fund its continued investment in regulated businesses, including transmission and regulated renewables projects. If additional reductions in the fair value of the Kentucky Operations occur, it would reduce future net income and cash flows.

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The Income Before Income Tax Expense (Benefit) of KPCo and KTCo were not material to AEP and AEPTCo on their respective statements of income for the three and nine months ended September 30, 2022 and 2021.

The major classes of KPCo and KTCo’s assets and liabilities presented in Assets Held for Sale and Liabilities Held for Sale on the balance sheets of AEP and AEPTCo are shown in the table below:
AEPAEPTCo
September 30, 2022December 31, 2021September 30, 2022December 31, 2021
(in millions)
ASSETS
Accounts Receivable and Accrued Unbilled Revenues$77.8 $33.2 $1.7 $1.5 
Fuel, Materials and Supplies36.7 30.6 — — 
Property, Plant and Equipment, Net2,387.4 2,302.7 167.0 165.3 
Regulatory Assets508.6 484.7 — — 
Other Classes of Assets that are not Major38.1 68.5 5.0 1.1 
Total Major Classes of Assets Held for Sale3,048.6 2,919.7 173.7 167.9 
Loss on the Expected Sale of Kentucky Operations (net of $45 million of Income Taxes)(218.0)— — — 
Assets Held for Sale$2,830.6 $2,919.7 $173.7 $167.9 
LIABILITIES
Accounts Payable$62.4 $53.4 $0.7 $1.1 
Long-term Debt Due Within One Year215.0 200.0 — — 
Customer Deposits38.0 32.4 — — 
Deferred Income Taxes497.8 441.6 16.4 15.4 
Long-term Debt963.4 903.1 — — 
Regulatory Liabilities and Deferred Investment Tax Credits138.1 148.1 8.0 7.6 
Other Classes of Liabilities that are not Major77.3 102.3 2.5 3.5 
Liabilities Held for Sale$1,992.0 $1,880.9 $27.6 $27.6 

DISPOSITIONS

Disposition of Cardinal Plant (Generation & Marketing Segment) (Applies to AEP)

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

Subsequent to the closing of the sale, AGR continues to recognize Cardinal Plant, Unit 1 on its balance sheet due to continuing involvement through the PPA. As of September 30, 2022, the net book value of Cardinal Plant, Unit 1 was not material.

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.


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IMPAIRMENTS

Flat Ridge 2 Wind LLC (Generation & Marketing Segment) (Applies to AEP)

In April 2019, AEP acquired Sempra Renewables LLC and its ownership interests in 724 MWs of wind generation and battery assets. The acquisition included 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 deteriorating financial performance, sale negotiations and AEP’s ongoing evaluation and ultimate decision to exit the investment in the near term, AEP determined a decline in the fair value of AEP’s investment in Flat Ridge 2 was other than temporary and recorded a pretax other than temporary impairment charge of $186 million in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP’s Statement of Income. In the third quarter of 2022, in accordance with the accounting guidance for “Investments - Equity Method and Joint Ventures”, AEP recorded an additional $2 million pretax other than temporary impairment charge in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP’s Statement of Income. AEP has recorded a $188 million other than temporary impairment in its investment in Flat Ridge 2 for the nine months ended September 30, 2022 in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP’s Statement of Income. AEP’s determination of fair value utilized the accounting guidance for Fair Value Measurement market approach to valuation and was based on Level 2 pricing information from a third-party market participant. In September 2022, AEP signed a Purchase and Sale Agreement with a nonaffiliate for AEP’s interest in Flat Ridge 2, subject to FERC approval. Management expects the transaction to close in the fourth quarter of 2022 and have an immaterial impact on the financial statements. The carrying value of AEP’s investment in Flat Ridge 2 was not material to AEP as of September 30, 2022.

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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

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

AEP
Pension PlansOPEB
Three Months Ended September 30,Three Months Ended September 30,
 2022202120222021
 (in millions)
Service Cost$30.7 $32.3 $1.8 $2.4 
Interest Cost37.1 34.3 7.3 7.7 
Expected Return on Plan Assets(63.4)(57.4)(27.5)(22.8)
Amortization of Prior Service Credit— — (17.9)(17.8)
Amortization of Net Actuarial Loss15.8 25.3 — — 
Net Periodic Benefit Cost (Credit)$20.2 $34.5 $(36.3)$(30.5)
Pension PlansOPEB
Nine Months Ended September 30,Nine Months Ended September 30,
 2022202120222021
 (in millions)
Service Cost$92.3 $96.9 $5.5 $7.2 
Interest Cost111.2 102.9 21.9 22.9 
Expected Return on Plan Assets(190.1)(172.3)(82.5)(68.4)
Amortization of Prior Service Credit— — (53.6)(53.2)
Amortization of Net Actuarial Loss47.3 76.1 — — 
Net Periodic Benefit Cost (Credit)$60.7 $103.6 $(108.7)$(91.5)



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AEP Texas
Pension PlansOPEB
Three Months Ended September 30,Three Months Ended September 30,
 2022202120222021
 (in millions)
Service Cost$2.8 $3.0 $0.1 $0.2 
Interest Cost3.1 2.8 0.6 0.6 
Expected Return on Plan Assets(5.3)(4.9)(2.3)(1.9)
Amortization of Prior Service Credit— — (1.5)(1.5)
Amortization of Net Actuarial Loss1.2 2.1 — — 
Net Periodic Benefit Cost (Credit)$1.8 $3.0 $(3.1)$(2.6)
Pension PlansOPEB
Nine Months Ended September 30,Nine Months Ended September 30,
 2022202120222021
 (in millions)
Service Cost$8.4 $8.9 $0.3 $0.5 
Interest Cost9.1 8.4 1.7 1.8 
Expected Return on Plan Assets(15.8)(14.6)(6.8)(5.6)
Amortization of Prior Service Credit— — (4.5)(4.5)
Amortization of Net Actuarial Loss3.8 6.2 — — 
Net Periodic Benefit Cost (Credit)$5.5 $8.9 $(9.3)$(7.8)

APCo
Pension PlansOPEB
Three Months Ended September 30,Three Months Ended September 30,
 2022202120222021
 (in millions)
Service Cost$2.9 $3.0 $0.2 $0.3 
Interest Cost4.3 4.1 1.2 1.3 
Expected Return on Plan Assets(8.1)(7.3)(4.1)(3.4)
Amortization of Prior Service Credit— — (2.6)(2.6)
Amortization of Net Actuarial Loss1.9 3.0 — — 
Net Periodic Benefit Cost (Credit)$1.0 $2.8 $(5.3)$(4.4)
Pension PlansOPEB
Nine Months Ended September 30,Nine Months Ended September 30,
 2022202120222021
 (in millions)
Service Cost$8.6 $8.9 $0.6 $0.8 
Interest Cost13.1 12.3 3.5 3.7 
Expected Return on Plan Assets(24.3)(21.8)(12.2)(10.1)
Amortization of Prior Service Credit— — (7.8)(7.8)
Amortization of Net Actuarial Loss5.5 9.0 — — 
Net Periodic Benefit Cost (Credit)$2.9 $8.4 $(15.9)$(13.4)
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I&M
Pension PlansOPEB
Three Months Ended September 30,Three Months Ended September 30,
 2022202120222021
 (in millions)
Service Cost$4.0 $4.4 $0.2 $0.4 
Interest Cost4.3 4.0 0.8 0.8 
Expected Return on Plan Assets(8.1)(7.2)(3.3)(2.7)
Amortization of Prior Service Credit— — (2.4)(2.5)
Amortization of Net Actuarial Loss1.8 2.9 — — 
Net Periodic Benefit Cost (Credit)$2.0 $4.1 $(4.7)$(4.0)
Pension PlansOPEB
Nine Months Ended September 30,Nine Months Ended September 30,
 2022202120222021
 (in millions)
Service Cost$12.1 $13.1 $0.7 $1.0 
Interest Cost12.7 12.1 2.5 2.6 
Expected Return on Plan Assets(24.2)(21.6)(10.2)(8.3)
Amortization of Prior Service Credit— — (7.3)(7.3)
Amortization of Net Actuarial Loss5.3 8.8 — — 
Net Periodic Benefit Cost (Credit)$5.9 $12.4 $(14.3)$(12.0)

OPCo
Pension PlansOPEB
Three Months Ended September 30,Three Months Ended September 30,
 2022202120222021
 (in millions)
Service Cost$2.8 $2.9 $0.2 $0.2 
Interest Cost3.4 3.1 0.7 0.7 
Expected Return on Plan Assets(6.2)(5.7)(3.0)(2.4)
Amortization of Prior Service Credit— — (1.8)(1.7)
Amortization of Net Actuarial Loss1.3 2.3 — — 
Net Periodic Benefit Cost (Credit)$1.3 $2.6 $(3.9)$(3.2)
Pension PlansOPEB
Nine Months Ended September 30,Nine Months Ended September 30,
 2022202120222021
 (in millions)
Service Cost$8.4 $8.6 $0.5 $0.6 
Interest Cost10.0 9.3 2.2 2.3 
Expected Return on Plan Assets(18.6)(16.8)(8.9)(7.3)
Amortization of Prior Service Credit— — (5.4)(5.3)
Amortization of Net Actuarial Loss4.1 6.8 — — 
Net Periodic Benefit Cost (Credit)$3.9 $7.9 $(11.6)$(9.7)


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PSO
Pension PlansOPEB
Three Months Ended September 30,Three Months Ended September 30,
 2022202120222021
 (in millions)
Service Cost$1.8 $2.0 $0.2 $0.1 
Interest Cost1.8 1.7 0.4 0.4 
Expected Return on Plan Assets(3.3)(3.0)(1.6)(1.3)
Amortization of Prior Service Credit— — (1.1)(1.1)
Amortization of Net Actuarial Loss0.7 1.2 — — 
Net Periodic Benefit Cost (Credit)$1.0 $1.9 $(2.1)$(1.9)
Pension PlansOPEB
Nine Months Ended September 30,Nine Months Ended September 30,
 2022202120222021
 (in millions)
Service Cost$5.5 $6.0 $0.4 $0.4 
Interest Cost5.3 5.0 1.1 1.2 
Expected Return on Plan Assets(10.1)(9.2)(4.6)(3.8)
Amortization of Prior Service Credit— — (3.3)(3.3)
Amortization of Net Actuarial Loss2.2 3.7 — — 
Net Periodic Benefit Cost (Credit)$2.9 $5.5 $(6.4)$(5.5)

SWEPCo
Pension PlansOPEB
Three Months Ended September 30,Three Months Ended September 30,
 2022202120222021
 (in millions)
Service Cost$2.7 $2.7 $0.1 $0.3 
Interest Cost2.2 2.2 0.5 0.4 
Expected Return on Plan Assets(3.6)(3.3)(1.8)(1.5)
Amortization of Prior Service Credit— — (1.4)(1.4)
Amortization of Net Actuarial Loss0.9 1.5 — — 
Net Periodic Benefit Cost (Credit)$2.2 $3.1 $(2.6)$(2.2)
Pension PlansOPEB
Nine Months Ended September 30,Nine Months Ended September 30,
 2022202120222021
 (in millions)
Service Cost$8.0 $8.4 $0.4 $0.6 
Interest Cost6.8 6.4 1.4 1.4 
Expected Return on Plan Assets(10.9)(10.1)(5.5)(4.5)
Amortization of Prior Service Credit— — (4.0)(4.0)
Amortization of Net Actuarial Loss2.8 4.6 — — 
Net Periodic Benefit Cost (Credit)$6.7 $9.3 $(7.7)$(6.5)

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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, PJM, SPP and MISO.
Competitive generation in PJM.

The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense, income tax expense and other nonallocated costs.
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The tables below represent AEP’s reportable segment income statement information for the three and nine months ended September 30, 2022 and 2021 and reportable segment balance sheet information as of September 30, 2022 and December 31, 2021.
Three 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
$3,174.6 $1,525.5 $81.9 $733.1 $11.0 $— $5,526.1 
Other Operating Segments
51.7 4.7 349.0 2.3 17.3 (425.0)— 
Total Revenues$3,226.3 $1,530.2 $430.9 $735.4 $28.3 $(425.0)$5,526.1 
Net Income (Loss)
$476.9 $165.5 $171.4 $96.2 $(226.7)$— $683.3 
Three Months Ended September 30, 2021
 Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing
Corporate and Other (a)Reconciling AdjustmentsConsolidated
 (in millions)
Revenues from:      
External Customers
$2,716.8 $1,195.0 $90.3 $617.4 $3.5 $— $4,623.0 
Other Operating Segments
42.5 5.3 301.3 3.7 23.2 (376.0)— 
Total Revenues$2,759.3 $1,200.3 $391.6 $621.1 $26.7 $(376.0)$4,623.0 
Net Income (Loss)
$438.7 $155.9 $167.9 $99.5 $(65.1)$— $796.9 
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 Segments
145.8 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 
Nine Months Ended September 30, 2021
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing
Corporate and Other (a)Reconciling AdjustmentsConsolidated
(in millions)
Revenues from:
External Customers
$7,445.9 $3,366.9 $264.6 $1,641.6 $11.6 $— $12,730.6 
Other Operating Segments
111.3 24.9 882.2 50.3 43.5 (1,112.2)— 
Total Revenues$7,557.2 $3,391.8 $1,146.8 $1,691.9 $55.1 $(1,112.2)$12,730.6 
Net Income (Loss)
$938.9 $424.0 $510.7 $184.2 $(108.3)$— $1,949.5 

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September 30, 2022
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing
Corporate and Other (a)Reconciling
Adjustments
Consolidated
 (in millions)
Total Assets (d)$49,056.9 $22,139.7 $14,708.9 $5,376.3 $6,278.3 (b)$(6,310.7)(c)$91,249.4 
December 31, 2021
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing
Corporate and Other (a)Reconciling
Adjustments
Consolidated
 (in millions)
Total Assets (d)$46,974.2 $21,120.2 $13,873.3 $4,263.6 $5,846.5 (b)$(4,409.1)(c) $87,668.7 

(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 “Disposition of KPCo and KTCo” section of Note 6 for additional information.


194



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

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

AEPTCo’s Reportable Segments

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

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

The tables below present AEPTCo’s reportable segment income statement information for the three and nine months ended September 30, 2022 and 2021 and reportable segment balance sheet information as of September 30, 2022 and December 31, 2021.
Three Months Ended September 30, 2022
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Revenues from:
External Customers
$87.2 $— $— $87.2 
Sales to AEP Affiliates
331.3 — — 331.3 
Total Revenues$418.5 $— $— $418.5 
Net Income$152.6 $0.1 (a)$— $152.7 
Three Months Ended September 30, 2021
State Transcos AEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Revenues from:
External Customers
$79.2 $— $— $79.2 
Sales to AEP Affiliates
297.6 — — 297.6 
Other Revenues
0.2 — — 0.2 
Total Revenues$377.0 $— $— $377.0 
Net Income$145.3 $0.1 (a)$— $145.4 
195



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 
Nine Months Ended September 30, 2021
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo Consolidated
(in millions)
Revenues from:
External Customers$239.3 $— $— $239.3 
Sales to AEP Affiliates864.6 — — 864.6 
Other Revenues0.3 — — 0.3 
Total Revenues$1,104.2 $— $— $1,104.2 
Net Income$445.5 $0.2 (a)$— $445.7 
September 30, 2022
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Total Assets (d)$13,359.9 $4,972.4 (b)$(5,013.1)(c)$13,319.2 
December 31, 2021
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Total Assets (d)$12,564.3 $4,389.5 (b)$(4,429.4)(c)$12,524.4 

(a)Includes the elimination of AEPTCo Parent’s equity earnings in the State Transcos.
(b)Includes the elimination of AEPTCo Parent’s investments in State Transcos.
(c)Primarily relates to the elimination of Notes Receivable from the State Transcos.
(d)Amount includes Assets Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.

196



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.

197



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

Notional Volume of Derivative Instruments
September 30, 2022
Primary Risk
Exposure
Unit of
Measure
AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Commodity:
      
PowerMWhs260.6 — 29.0 6.2 2.6 5.7 4.3 
Natural GasMMBtus80.3 — — — — — 1.8 
Heating Oil and GasolineGallons6.4 1.7 0.9 0.6 1.3 0.7 0.9 
Interest Rate
USD$99.9 $— $— $— $— $— $— 
Interest Rate on Long-term Debt
USD$1,150.0 $— $— $— $— $— $— 

December 31, 2021
Primary Risk
Exposure
Unit of
Measure
AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Commodity:
      
PowerMWhs287.9 — 33.1 13.6 2.7 11.9 3.4 
Natural GasMMBtus34.1 — — — — 1.3 5.1 
Heating Oil and GasolineGallons7.4 1.9 1.1 0.7 1.5 0.8 1.0 
Interest RateUSD$116.5 $— $— $— $— $— $— 
Interest Rate on Long-term Debt
USD$950.0 $— $— $— $— $— $— 

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.
198



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 $847 million and $263 million as of September 30, 2022 and December 31, 2021, respectively. AEP netted cash collateral paid to third-parties against short-term and long-term risk management liabilities in the amounts of $0 and $3 million as of September 30, 2022 and December 31, 2021, respectively. The netted cash collateral from third-parties against short-term and long-term risk management assets and netted cash collateral paid to third-parties against short-term and long-term risk management liabilities were immaterial for the Registrant Subsidiaries as of September 30, 2022 and December 31, 2021.
199



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
September 30, 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 (d)$1,482.1 $411.1 $8.8 $1,902.0 $(1,331.8)$570.2 
Long-term Risk Management Assets686.6 177.4 — 864.0 (598.2)265.8 
Total Assets2,168.7 588.5 8.8 2,766.0 (1,930.0)836.0 
Current Risk Management Liabilities (e)1,005.7 10.9 21.3 1,037.9 (850.6)187.3 
Long-term Risk Management Liabilities501.6 4.9 114.1 620.6 (232.4)388.2 
Total Liabilities1,507.3 15.8 135.4 1,658.5 (1,083.0)575.5 
Total MTM Derivative Contract Net Assets (Liabilities) (f)
$661.4 $572.7 $(126.6)$1,107.5 $(847.0)$260.5 

December 31, 2021
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 (d)$513.4 $176.0 $1.2 $690.6 $(496.2)$194.4 
Long-term Risk Management Assets370.5 89.1 — 459.6 (192.6)267.0 
Total Assets883.9 265.1 1.2 1,150.2 (688.8)461.4 
Current Risk Management Liabilities (e)395.7 40.9 — 436.6 (361.2)75.4 
Long-term Risk Management Liabilities243.9 16.7 38.1 298.7 (68.4)230.3 
Total Liabilities639.6 57.6 38.1 735.3 (429.6)305.7 
Total MTM Derivative Contract Net Assets (Liabilities)
$244.3 $207.5 $(36.9)$414.9 $(259.2)$155.7 

200



AEP Texas
September 30, 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$0.1 $0.1 $0.2 
Long-term Risk Management Assets(0.1)0.2 0.1 
Total Assets— 0.3 0.3 
Current Risk Management Liabilities— — — 
Long-term Risk Management Liabilities— 0.1 0.1 
Total Liabilities— 0.1 0.1 
Total MTM Derivative Contract Net Assets$— $0.2 $0.2 

December 31, 2021
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$0.6 $(0.6)$— 
Long-term Risk Management Assets— — — 
Total Assets0.6 (0.6)— 
Current Risk Management Liabilities— — — 
Long-term Risk Management Liabilities— — — 
Total Liabilities— — — 
Total MTM Derivative Contract Net Assets (Liabilities)$0.6 $(0.6)$— 

201



APCo
September 30, 2022
Risk ManagementGross Amounts Offset Net 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$106.8 $— $106.8 
Long-term Risk Management Assets0.7 (0.6)0.1 
Total Assets107.5 (0.6)106.9 
Current Risk Management Liabilities— — — 
Long-term Risk Management Liabilities0.7 (0.7)— 
Total Liabilities0.7 (0.7)— 
Total MTM Derivative Contract Net Assets (f)$106.8 $0.1 $106.9 

December 31, 2021
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$47.5 $(5.5)$42.0 
Long-term Risk Management Assets0.2 (0.2)— 
Total Assets47.7 (5.7)42.0 
Current Risk Management Liabilities7.2 (6.4)0.8 
Long-term Risk Management Liabilities0.2 (0.2)— 
Total Liabilities7.4 (6.6)0.8 
Total MTM Derivative Contract Net Assets$40.3 $0.9 $41.2 
202



I&M
September 30, 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$12.3 $(0.9)$11.4 
Long-term Risk Management Assets0.6 (0.4)0.2 
Total Assets12.9 (1.3)11.6 
Current Risk Management Liabilities0.9 (0.9)— 
Long-term Risk Management Liabilities0.5 (0.5)— 
Total Liabilities1.4 (1.4)— 
Total MTM Derivative Contract Net Assets (f)$11.5 $0.1 $11.6 

December 31, 2021
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$11.1 $(7.8)$3.3 
Long-term Risk Management Assets0.2 (0.2)— 
Total Assets11.3 (8.0)3.3 
Current Risk Management Liabilities14.8 (9.8)5.0 
Long-term Risk Management Liabilities0.2 (0.2)— 
Total Liabilities15.0 (10.0)5.0 
Total MTM Derivative Contract Net Assets (Liabilities)$(3.7)$2.0 $(1.7)


203



OPCo
September 30, 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$2.0 $0.1 $2.1 
Long-term Risk Management Assets(0.1)0.1 — 
Total Assets1.9 0.2 2.1 
Current Risk Management Liabilities— — — 
Long-term Risk Management Liabilities45.1 — 45.1 
Total Liabilities45.1 — 45.1 
Total MTM Derivative Contract Net Assets (Liabilities) (f)$(43.2)$0.2 $(43.0)

December 31, 2021
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$0.5 $(0.5)$— 
Long-term Risk Management Assets— — — 
Total Assets0.5 (0.5)— 
Current Risk Management Liabilities6.7 — 6.7 
Long-term Risk Management Liabilities85.8 — 85.8 
Total Liabilities92.5 — 92.5 
Total MTM Derivative Contract Net Liabilities$(92.0)$(0.5)$(92.5)
204



PSO
September 30, 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$44.4 $0.1 $44.5 
Long-term Risk Management Assets— — — 
Total Assets44.4 0.1 44.5 
Current Risk Management Liabilities— — — 
Long-term Risk Management Liabilities— — — 
Total Liabilities— — — 
Total MTM Derivative Contract Net Assets (f)$44.4 $0.1 $44.5 

December 31, 2021
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$12.4 $(0.3)$12.1 
Long-term Risk Management Assets— — — 
Total Assets12.4 (0.3)12.1 
Current Risk Management Liabilities3.7 — 3.7 
Long-term Risk Management Liabilities— — — 
Total Liabilities3.7 — 3.7 
Total MTM Derivative Contract Net Assets (Liabilities)$8.7 $(0.3)$8.4 


205



SWEPCo
September 30, 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$37.2 $(0.8)$36.4 
Long-term Risk Management Assets— 0.1 0.1 
Total Assets37.2 (0.7)36.5 
Current Risk Management Liabilities0.8 (0.8)— 
Long-term Risk Management Liabilities— — — 
Total Liabilities0.8 (0.8)— 
Total MTM Derivative Contract Net Assets (f)$36.4 $0.1 $36.5 

December 31, 2021
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$10.1 $(0.3)$9.8 
Long-term Risk Management Assets1.1 — 1.1 
Total Assets11.2 (0.3)10.9 
Current Risk Management Liabilities2.1 — 2.1 
Long-term Risk Management Liabilities— — — 
Total Liabilities2.1 — 2.1 
Total MTM Derivative Contract Net Assets (Liabilities)$9.1 $(0.3)$8.8 

(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)Amount excludes Risk Management Assets of $14.4 million and $6 million as of September 30, 2022 and December 31, 2021, respectively, classified as Assets Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
(e)Amount excludes Risk Management Liabilities of $0 and $0.1 million as of September 30, 2022 and December 31, 2021, respectively, classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
(f)Increase in amounts as of September 30, 2022 are primarily due to increases in commodity prices for power and natural gas and an increase in value of FTRs.
206



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

Amount of Gain (Loss) Recognized on
Risk Management Contracts
Three Months Ended September 30, 2022
Location of Gain (Loss)AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Vertically Integrated Utilities Revenues$2.1 $— $— $— $— $— $— 
Generation & Marketing Revenues116.7 — — — — — — 
Electric Generation, Transmission and Distribution Revenues
— — 0.3 — — — — 
Other Revenues - Nonaffiliated— — — 1.9 — — — 
Purchased Electricity for Resale0.9 — 0.9 0.1 — — — 
Other Operation1.4 0.4 0.1 0.1 0.2 0.2 0.2 
Maintenance2.0 0.5 0.2 0.2 0.4 0.2 0.3 
Regulatory Assets (a)4.3 — — 0.1 4.1 — 0.1 
Regulatory Liabilities (a)103.2 (1.5)59.7 3.8 0.9 19.7 7.0 
Total Gain (Loss) on Risk Management Contracts (b)$230.6 $(0.6)$61.2 $6.2 $5.6 $20.1 $7.6 
Three Months Ended September 30, 2021
Location of Gain (Loss)AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Vertically Integrated Utilities Revenues$(0.9)$— $— $— $— $— $— 
Generation & Marketing Revenues128.8 — — — — — — 
Electric Generation, Transmission and Distribution Revenues
— — (0.9)— — — — 
Purchased Electricity for Resale0.2 — 0.1 — — — — 
Other Operation0.9 0.3 0.1 0.1 0.1 0.1 0.2 
Maintenance1.1 0.2 0.2 0.1 0.2 0.1 0.1 
Regulatory Assets (a)(7.2)— (2.9)(16.9)14.9 — 0.1 
Regulatory Liabilities (a)46.5 (0.1)14.2 1.7 0.8 14.0 12.7 
Total Gain (Loss) on Risk Management Contracts$169.4 $0.4 $10.8 $(15.0)$16.0 $14.2 $13.1 
207



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 for Resale3.3 — 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 (b)$703.8 $2.0 $84.3 $8.6 $53.0 $76.2 $64.1 
Nine Months Ended September 30, 2021
Location of Gain (Loss)AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Vertically Integrated Utilities Revenues$(0.6)$— $— $— $— $— $— 
Generation & Marketing Revenues144.9 — — — — — — 
Electric Generation, Transmission and Distribution Revenues— — (0.6)— — — — 
Purchased Electricity for Resale1.2 — 1.0 0.1 — — — 
Other Operation1.9 0.6 0.2 0.2 0.3 0.2 0.3 
Maintenance2.4 0.6 0.4 0.2 0.4 0.2 0.3 
Regulatory Assets (a)(7.9)— (2.9)(22.9)20.3 — 1.4 
Regulatory Liabilities (a)123.6 0.5 28.9 1.9 5.9 40.2 38.5 
Total Gain (Loss) on Risk Management Contracts$265.5 $1.7 $27.0 $(20.5)$26.9 $40.6 $40.5 

(a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
(b)Increase in amounts for the three and nine months ended September 30, 2022 are primarily due to increases in commodity prices for power and natural gas and an increase 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.”


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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
September 30, 2022December 31, 2021September 30, 2022December 31, 2021
(in millions)
Long-term Debt (a) (b)$(849.1)$(952.3)$95.7 $(8.5)

(a)Amounts included on the Balance Sheet within Current and Noncurrent Liabilities line items Long-term Debt Due within One Year and Long-term Debt, respectively.
(b)Amounts include $(40) million and $(46) million as of September 30, 2022 and December 31, 2021, respectively, for the fair value hedge adjustment of hedged debt obligations for which hedge accounting has been discontinued.

The pretax effects of fair value hedge accounting on income were as follows:

Three Months Ended September 30,Nine Months Ended September 30,
2022202120222021
(in millions)
Gain (Loss) on Interest Rate Contracts:
Fair Value Hedging Instruments (a)$(36.0)$(0.1)$(98.4)$(23.8)
Fair Value Portion of Long-term Debt (a)36.0 0.1 98.4 23.8 

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

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

Accounting for Cash Flow Hedging Strategies (Applies to AEP, AEP Texas, APCo, I&M 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 for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2022 and 2021, AEP applied cash flow hedging to outstanding power derivatives and the Registrant Subsidiaries did not.
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The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2022, AEP applied cash flow hedging to outstanding interest rate derivatives and the Registrant Subsidiaries did not. During the three months ended September 30, 2021, AEP applied cash flow hedging to outstanding interest rate derivatives and the Registrant Subsidiaries did not. During the nine months ended September 30, 2021, AEP and APCo applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not.

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

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

Impact of Cash Flow Hedges on AEP’s Balance Sheets
September 30, 2022December 31, 2021
CommodityInterest RateCommodityInterest Rate
(in millions)
AOCI Gain (Loss) Net of Tax$452.1 $(2.6)$163.7 $(21.3)
Portion Expected to be Reclassed to Net Income During the Next Twelve Months
316.2 (1.5)106.7 (3.3)

As of September 30, 2022 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 102 months and 99 months for commodity and interest rate hedges, respectively.

Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets
September 30, 2022December 31, 2021
Interest Rate
Expected to beExpected to be
Reclassified toReclassified to
Net Income DuringNet Income During
AOCI Gain (Loss)the NextAOCI Gain (Loss)the Next
CompanyNet of TaxTwelve MonthsNet of TaxTwelve Months
(in millions)
AEP Texas$(0.5)$(0.4)$(1.3)$(1.1)
APCo6.9 0.8 7.5 0.8 
I&M(5.5)(1.0)(6.7)(1.6)
SWEPCo1.2 0.2 1.2 0.1 

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
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exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required.


Credit-Risk-Related Contingent Features

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

A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts.  The Registrants have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral.  AEP had derivative contracts with collateral triggering events in a net liability position with a total exposure of $10 million and $9 million as of September 30, 2022 and December 31, 2021, respectively. The Registrant Subsidiaries had no derivative contracts with collateral triggering events in a net liability position as of September 30, 2022 and December 31, 2021.

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 $135 million and $40 million as of September 30, 2022 and December 31, 2021, respectively. There was no cash collateral posted as of September 30, 2022 and December 31, 2021, respectively. If a cross-acceleration provision would have been triggered, settlement at fair value would have been required. The Registrant Subsidiaries had no derivative contracts with cross-acceleration provisions outstanding as of September 30, 2022 and December 31, 2021.

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

In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third-party obligation that is $50 million or greater.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. AEP had derivative liabilities subject to cross-default provisions in a net liability position of $260 million and $76 million as of September 30, 2022 and December 31, 2021, respectively, after considering contractual netting arrangements. Cash collateral posted as of September 30, 2022 and December 31, 2021 was not material. 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 September 30, 2022 and December 31, 2021 were not material.
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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:
September 30, 2022December 31, 2021
CompanyBook ValueFair ValueBook ValueFair Value
(in millions)
AEP (a)(b)(c)$35,050.1 $30,352.7 $33,454.5 $37,564.7 
AEP Texas5,693.9 4,889.7 5,180.8 5,663.8 
AEPTCo4,886.6 3,926.3 4,343.9 4,968.2 
APCo5,509.8 4,994.1 4,938.9 6,037.1 
I&M3,206.7 2,846.2 3,195.0 3,748.0 
OPCo2,969.9 2,442.0 2,968.5 3,437.5 
PSO1,913.6 1,616.9 1,913.5 2,163.7 
SWEPCo3,392.4 2,797.3 3,395.2 3,792.9 

(a)The fair value amounts include debt related to AEP’s Equity Units and had a fair value of $842 million and $1.7 billion as of September 30, 2022 and December 31, 2021, respectively. See “Equity Units” section of Note 12 for additional information.
(b)The book value amounts exclude Long-term Debt of $1.2 billion and $1.1 billion as of September 30, 2022 and December 31, 2021, respectively, classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
(c)The fair value amounts exclude Long-term Debt of $1.1 billion and $1.2 billion as of September 30, 2022 and December 31, 2021, respectively, related to KPCo. See “Disposition of KPCo and KTCo” section of Note 6 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:
September 30, 2022
GrossGross
UnrealizedUnrealizedFair
Other Temporary Investments and Restricted CashCostGainsLossesValue
(in millions)
Restricted Cash (a)$55.1 $— $— $55.1 
Other Cash Deposits18.1 — — 18.1 
Fixed Income Securities – Mutual Funds (b)155.1 — (9.7)145.4 
Equity Securities – Mutual Funds20.4 18.6 (0.3)38.7 
Total Other Temporary Investments and Restricted Cash$248.7 $18.6 $(10.0)$257.3 
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December 31, 2021
GrossGross
UnrealizedUnrealizedFair
Other Temporary Investments and Restricted CashCostGainsLossesValue
(in millions)
Restricted Cash (a)$48.0 $— $— $48.0 
Other Cash Deposits10.0 — — 10.0 
Fixed Income Securities – Mutual Funds (b)154.3 0.5 — 154.8 
Equity Securities – Mutual Funds19.7 35.9 — 55.6 
Total Other Temporary Investments and Restricted Cash$232.0 $36.4 $— $268.4 

(a)Primarily represents amounts held for the repayment of debt.
(b)Primarily short and intermediate maturities which may be sold and do not contain maturity dates.

The following table provides the activity for fixed income and equity securities within Other Temporary Investments:
 Three Months Ended September 30,Nine Months Ended September 30,
 2022202120222021
(in millions)
Proceeds from Investment Sales$— $6.0 $15.0 $15.1 
Purchases of Investments11.8 12.9 13.4 26.0 
Gross Realized Gains on Investment Sales— 2.4 3.6 3.6 
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
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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:
 September 30, 2022December 31, 2021
GrossOther-Than-GrossOther-Than-
FairUnrealizedTemporaryFairUnrealizedTemporary
ValueGainsImpairmentsValueGainsImpairments
(in millions)
Cash and Cash Equivalents$20.8 $— $— $84.7 $— $— 
Fixed Income Securities:
United States Government1,115.2 (26.2)(39.8)1,156.4 66.3 (7.9)
Corporate Debt60.9 (7.7)(1.2)76.7 6.7 (2.1)
State and Local Government7.0 — (0.1)7.3 0.4 (0.1)
Subtotal Fixed Income Securities1,183.1 (33.9)(41.1)1,240.4 73.4 (10.1)
Equity Securities - Domestic (a)1,926.6 1,279.1 — 2,541.9 1,901.3 — 
Spent Nuclear Fuel and Decommissioning Trusts
$3,130.5 $1,245.2 $(41.1)$3,867.0 $1,974.7 $(10.1)

(a)Amount reported as Gross Unrealized Gains includes unrealized gains of $1.3 billion and $1.9 billion and unrealized losses of $14 million and $4 million as of September 30, 2022 and December 31, 2021, respectively.

The following table provides the securities activity within the decommissioning and SNF trusts:
Three Months Ended September 30,Nine Months Ended September 30,
 2022202120222021
 (in millions)
Proceeds from Investment Sales$588.5 $433.9 $1,818.4 $1,556.6 
Purchases of Investments601.6 436.6 1,854.8 1,586.3 
Gross Realized Gains on Investment Sales24.6 9.6 41.3 98.3 
Gross Realized Losses on Investment Sales8.4 7.0 33.5 12.5 

The base cost of fixed income securities was $1.2 billion and $1.2 billion as of September 30, 2022 and December 31, 2021, respectively.  The base cost of equity securities was $647 million and $641 million as of September 30, 2022 and December 31, 2021, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2022 was as follows:
Fair Value of Fixed
Income Securities
(in millions)
Within 1 year$369.4 
After 1 year through 5 years393.8 
After 5 years through 10 years229.0 
After 10 years190.9 
Total$1,183.1 
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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
September 30, 2022
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Other Temporary Investments and Restricted Cash
Restricted Cash$55.1 $— $— $— $55.1 
Other Cash Deposits (a)— — — 18.1 18.1 
Fixed Income Securities – Mutual Funds145.4 — — — 145.4 
Equity Securities – Mutual Funds (b)38.7 — — — 38.7 
Total Other Temporary Investments and Restricted Cash239.2 — — 18.1 257.3 
Risk Management Assets
Risk Management Commodity Contracts (c) (d) (i)31.7 1,650.1 467.7 (1,910.8)238.7 
Cash Flow Hedges:
Commodity Hedges (c)— 612.1 45.3 (68.9)588.5 
Interest Rate Hedges— 9.3 — (0.5)8.8 
Total Risk Management Assets31.7 2,271.5 513.0 (1,980.2)836.0 
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)10.4 — — 10.4 20.8 
Fixed Income Securities:
United States Government— 1,115.2 — — 1,115.2 
Corporate Debt— 60.9 — — 60.9 
State and Local Government— 7.0 — — 7.0 
Subtotal Fixed Income Securities— 1,183.1 — — 1,183.1 
Equity Securities – Domestic (b)1,926.6 — — — 1,926.6 
Total Spent Nuclear Fuel and Decommissioning Trusts1,937.0 1,183.1 — 10.4 3,130.5 
Total Assets$2,207.9 $3,454.6 $513.0 $(1,951.7)$4,223.8 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (d) (j)$20.1 $1,227.7 $240.5 $(1,063.9)$424.4 
Cash Flow Hedges:
Commodity Hedges (c)— 83.7 0.9 (68.9)15.7 
Interest Rate Hedges— 0.5 — (0.5)— 
Fair Value Hedges— 135.4 — — 135.4 
Total Risk Management Liabilities$20.1 $1,447.3 $241.4 $(1,133.3)$575.5 
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AEP

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2021
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Other Temporary Investments and Restricted Cash
Restricted Cash$48.0 $— $— $— $48.0 
Other Cash Deposits (a)— — — 10.0 10.0 
Fixed Income Securities – Mutual Funds154.8 — — — 154.8 
Equity Securities – Mutual Funds (b)55.6 — — — 55.6 
Total Other Temporary Investments and Restricted Cash258.4 — — 10.0 268.4 
Risk Management Assets
Risk Management Commodity Contracts (c) (f) (i)7.4 648.5 226.3 (642.4)239.8 
Cash Flow Hedges:
Commodity Hedges (c)— 242.9 19.2 (41.7)220.4 
Fair Value Hedges— 1.2 — — 1.2 
Total Risk Management Assets7.4 892.6 245.5 (684.1)461.4 
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)77.7 — — 7.0 84.7 
Fixed Income Securities:
United States Government— 1,156.4 — — 1,156.4 
Corporate Debt— 76.7 — — 76.7 
State and Local Government— 7.3 — — 7.3 
Subtotal Fixed Income Securities— 1,240.4 — — 1,240.4 
Equity Securities – Domestic (b)2,541.9 — — — 2,541.9 
Total Spent Nuclear Fuel and Decommissioning Trusts2,619.6 1,240.4 — 7.0 3,867.0 
Other Investments (h)28.8 14.9 — — 43.7 
Total Assets$2,914.2 $2,147.9 $245.5 $(667.1)$4,640.5 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (f) (j)$5.3 $485.0 $147.6 $(383.2)$254.7 
Cash Flow Hedges:
Commodity Hedges (c)— 54.0 0.6 (41.7)12.9 
Fair Value Hedges— 38.1 — — 38.1 
Total Risk Management Liabilities$5.3 $577.1 $148.2 $(424.9)$305.7 

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AEP Texas
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2022
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$47.7 $— $— $— $47.7 
Risk Management Assets     
Risk Management Commodity Contracts (c)— 0.1 — 0.2 0.3 
Total Assets$47.7 $0.1 $— $0.2 $48.0 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)$— $0.1 $— $— $0.1 

December 31, 2021
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$30.4 $— $— $— $30.4 
Risk Management Assets     
Risk Management Commodity Contracts (c)— 0.6 — (0.6)— 
Total Assets$30.4 $0.6 $— $(0.6)$30.4 

218




APCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2022
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$7.4 $— $— $— $7.4 
Risk Management Assets
Risk Management Commodity Contracts (c) (g)— 0.9 106.7 (0.8)106.8 
Total Assets$7.4 $0.9 $106.7 $(0.8)$114.2 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$— $0.7 $0.1 $(0.8)$— 

December 31, 2021
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$17.6 $— $— $— $17.6 
Risk Management Assets
Risk Management Commodity Contracts (c) (g)— 5.8 42.0 (5.8)42.0 
Total Assets$17.6 $5.8 $42.0 $(5.8)$59.6 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$— $7.2 $0.3 $(6.7)$0.8 

219



I&M
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2022
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)$— $2.4 $10.3 $(1.1)$11.6 
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)10.4 — — 10.4 20.8 
Fixed Income Securities:
United States Government— 1,115.2 — — 1,115.2 
Corporate Debt— 60.9 — — 60.9 
State and Local Government— 7.0 — — 7.0 
Subtotal Fixed Income Securities— 1,183.1 — — 1,183.1 
Equity Securities - Domestic (b)1,926.6 — — — 1,926.6 
Total Spent Nuclear Fuel and Decommissioning Trusts1,937.0 1,183.1 — 10.4 3,130.5 
Total Assets$1,937.0 $1,185.5 $10.3 $9.3 $3,142.1 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$— $0.5 $0.7 $(1.2)$— 

December 31, 2021
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)$— $3.8 $7.6 $(8.1)$3.3 
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)77.7 — — 7.0 84.7 
Fixed Income Securities:
United States Government— 1,156.4 — — 1,156.4 
Corporate Debt— 76.7 — — 76.7 
State and Local Government— 7.3 — — 7.3 
Subtotal Fixed Income Securities— 1,240.4 — — 1,240.4 
Equity Securities - Domestic (b)2,541.9 — — — 2,541.9 
Total Spent Nuclear Fuel and Decommissioning Trusts2,619.6 1,240.4 — 7.0 3,867.0 
Total Assets$2,619.6 $1,244.2 $7.6 $(1.1)$3,870.3 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$— $6.7 $8.3 $(10.0)$5.0 
220



OPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2022
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets     
Risk Management Commodity Contracts (c) (g)$— $0.1 $— $2.0 $2.1 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$— $0.1 $43.2 $1.8 $45.1 

December 31, 2021
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)$— $0.5 $— $(0.5)$— 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (g)$— $— $92.5 $— $92.5 

PSO
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2022
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)$— $— $45.2 $(0.7)$44.5 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$— $— $0.8 $(0.8)$— 

December 31, 2021
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)$— $0.3 $12.2 $(0.4)$12.1 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$— $3.7 $0.1 $(0.1)$3.7 
221



SWEPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2022
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)$— $0.1 $37.0 $(0.7)$36.4 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$— $— $0.8 $(0.8)$— 

December 31, 2021
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)$— $0.3 $11.0 $(0.4)$10.9 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$— $2.1 $0.1 $(0.1)$2.1 

(a)Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or third-parties.  Level 1 and Level 2 amounts primarily represent investments in money market funds.
(b)Amounts represent publicly traded equity securities and equity-based mutual funds.
(c)Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’
(d)The September 30, 2022 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $2 million in 2022 and $9 million in periods 2023-2025; Level 2 matures $47 million in 2022, $363 million in periods 2023-2025, $10 million in periods 2026-2027 and $3 million in periods 2028-2033; Level 3 matures $87 million in 2022, $139 million in periods 2023-2025, $18 million in periods 2026-2027 and $(2) million in periods 2028-2033.  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, 2021 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $1 million in 2022 and $1 million in periods 2023-2025; Level 2 matures $42 million in 2022, $109 million in periods 2023-2025, $10 million in periods 2026-2027 and $3 million in periods 2028-2033; Level 3 matures $82 million in 2022, $10 million in periods 2023-2025, $9 million in periods 2026-2027 and $(17) million in periods 2028-2033.  Risk management commodity contracts are substantially comprised of power contracts.
(g)Substantially comprised of power contracts for the Registrant Subsidiaries.
(h)See “Warrants Held in Investee” section of Note 10 in the 2021 Annual Report for additional information.
(i)Amount excludes Risk Management Assets of $14.4 million and $6 million as of September 30, 2022 and December 31, 2021, respectively, classified as Assets Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
(j)Amount excludes Risk Management Liabilities of $0 and $0.1 million as of September 30, 2022 and December 31, 2021, respectively, classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
222



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, 2022AEPAPCoI&MOPCoPSOSWEPCo
 (in millions)
Balance as of June 30, 2022$270.4 $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 
Assets and Liabilities Held for Sale related to KPCo (g)
(0.8)— — — — — 
Balance as of September 30, 2022$271.6 $106.6 $9.6 $(43.2)$44.4 $36.2 
Three Months Ended September 30, 2021AEPAPCoI&MOPCoPSOSWEPCo
 (in millions)
Balance as of June 30, 2021$101.2 $36.6 $7.3 $(105.4)$22.9 $14.6 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
27.5 4.0 0.1 0.1 13.5 5.8 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
2.9 — — — — — 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)
17.8 — — — — — 
Settlements(54.5)(10.5)(3.8)0.9 (20.6)(9.8)
Transfers into Level 3 (d) (e)(5.8)— — — — — 
Transfers out of Level 3 (e)(4.1)0.1 — — — — 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)
44.0 15.7 (0.3)14.0 2.7 9.0 
Balance as of September 30, 2021$129.0 $45.9 $3.3 $(90.4)$18.5 $19.6 
223



Nine Months Ended September 30, 2022AEPAPCoI&MOPCoPSOSWEPCo
 (in millions)
Balance as of December 31, 2021$97.3 $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 
Assets and Liabilities Held for Sale related to KPCo (g)(8.5)— — — — — 
Balance as of September 30, 2022$271.6 $106.6 $9.6 $(43.2)$44.4 $36.2 
Nine Months Ended September 30, 2021AEPAPCoI&MOPCoPSOSWEPCo
 (in millions)
Balance as of December 31, 2020$113.3 $19.3 $2.1 $(110.3)$10.3 $1.6 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
68.9 38.8 0.4 0.4 16.1 9.5 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
(64.1)— — — — — 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)
35.5 — — — — — 
Settlements(113.3)(58.2)(2.5)5.8 (26.4)(13.0)
Transfers into Level 3 (d) (e)(0.2)— — — — — 
Transfers out of Level 3 (e)(26.2)— — — — — 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)
115.1 46.0 3.3 13.7 18.5 21.5 
Balance as of September 30, 2021$129.0 $45.9 $3.3 $(90.4)$18.5 $19.6 

(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.
(g)Amount represents Risk Management Assets classified as Assets Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.


224



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

AEP
Significant Unobservable Inputs
September 30, 2022
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInputLowHighAverage (c)
(in millions)
Energy Contracts$292.7 $230.6 Discounted Cash FlowForward Market Price (a)$(4.31)$172.05 $49.58 
Natural Gas Contracts
6.9 — Discounted Cash FlowForward Market Price (b)3.22 7.37 5.92 
FTRs (d) (e)213.4 10.8 Discounted Cash FlowForward Market Price (a)(37.97)27.55 0.99 
Total$513.0 $241.4 

December 31, 2021
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInputLowHighAverage (c)
(in millions)
Energy Contracts (f)$164.4 $135.2 Discounted Cash FlowForward Market Price (a)$10.30 $76.70 $37.11 
Natural Gas Contracts3.6 — Discounted Cash FlowForward Market Price (b)3.11 4.02 3.47 
FTRs (g) (h)77.5 13.0 Discounted Cash FlowForward Market Price (a)(23.93)26.38 0.86 
Total$245.5 $148.2 
225



APCo
Significant Unobservable Inputs
September 30, 2022
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (c)
(in millions)
FTRs$106.7 $0.1 
Discounted Cash Flow
Forward Market Price
$(2.01)$20.64 $3.75 

December 31, 2021
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (c)
(in millions)
Energy Contracts$— $0.3 Discounted Cash FlowForward Market Price$32.20 $56.54 $44.77 
FTRs42.0 — 
Discounted Cash Flow
Forward Market Price
(0.30)26.38 2.63 
Total$42.0 $0.3 

I&M
Significant Unobservable Inputs
September 30, 2022
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (c)
(in millions)
FTRs$10.3 $0.7 
Discounted Cash Flow
Forward Market Price
$0.21 $17.73 $1.61 

December 31, 2021
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (c)
(in millions)
Energy Contracts$— $0.2 Discounted Cash FlowForward Market Price$32.20 $56.54 $44.77 
FTRs7.6 8.1 
Discounted Cash Flow
Forward Market Price
(5.45)17.78 (0.12)
Total$7.6 $8.3 
226



OPCo
Significant Unobservable Inputs
September 30, 2022
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (c)
(in millions)
Energy Contracts$— $43.2 
Discounted Cash Flow
Forward Market Price
$1.65 $143.38 $47.12 

December 31, 2021
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (c)
(in millions)
Energy Contracts$— $92.5 
Discounted Cash Flow
Forward Market Price
$14.26 $52.98 $30.68 

PSO
Significant Unobservable Inputs
September 30, 2022
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (c)
(in millions)
FTRs$45.2 $0.8 
Discounted Cash Flow
Forward Market Price
$(36.83)$5.65 $(7.55)

December 31, 2021
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (c)
(in millions)
FTRs$12.2 $0.1 
Discounted Cash Flow
Forward Market Price
$(18.39)$1.87 $(2.57)
227



SWEPCo
Significant Unobservable Inputs
September 30, 2022
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInputLowHighAverage (c)
(in millions)
Natural Gas Contracts
$6.9 $— Discounted Cash FlowForward Market Price (b)$6.15 $7.37 $6.94 
FTRs30.1 0.8 
Discounted Cash Flow
Forward Market Price (a)
(36.83)5.65 (7.55)
Total$37.0 $0.8 

December 31, 2021
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInputLowHighAverage (c)
(in millions)
Natural Gas Contracts$3.6 $— Discounted Cash FlowForward Market Price (b)$3.11 $4.02 $3.47 
FTRs7.4 0.1 
Discounted Cash Flow
Forward Market Price (a)
(18.39)1.87 (2.57)
Total$11.0 $0.1 

(a)Represents market prices in dollars per MWh.
(b)Represents market prices in dollars per MMBtu.
(c)The weighted average is the product of the forward market price of the underlying commodity and volume weighted by term.
(d)Amount excludes Risk Management Assets of $14.4 million classified as Assets Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
(e)Amount excludes Risk Management Liabilities of $0.1 million classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
(f)Amount excludes Risk Management Liabilities of $0.1 million classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
(g)Amount excludes Risk Management Assets of $6 million classified as Assets Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
(h)Amount excludes Risk Management Liabilities of $0.5 million classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.

The following table provides the measurement uncertainty of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts, Natural Gas Contracts and FTRs for the Registrants as of September 30, 2022 and December 31, 2021:

Uncertainty of Fair Value Measurements
Significant Unobservable InputPositionChange in InputImpact on Fair Value
Measurement
Forward Market Price
Buy
Increase (Decrease)Higher (Lower)
Forward Market PriceSellIncrease (Decrease)Lower (Higher)
228



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 2022 and 2021, adjusted for tax expense associated with certain discrete items.

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

The ETR for each of the Registrants are included in the following tables:
Three Months Ended September 30, 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)%— %— %— %— %— %— %— %
Other
1.0 %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)%
Three Months Ended September 30, 2021
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
0.6 %0.3 %3.0 %(0.3)%1.9 %1.2 %5.0 %(6.9)%
Tax Reform Excess ADIT Reversal
(8.5)%(6.3)%0.3 %(14.2)%(16.1)%(8.9)%(19.8)%(4.2)%
Production and Investment Tax Credits
(4.7)%(0.3)%— %(0.2)%(2.0)%— %(8.9)%(5.4)%
Flow Through
— %0.3 %0.3 %0.4 %(2.8)%0.6 %0.7 %(0.2)%
AFUDC Equity
(1.2)%(1.0)%(2.2)%(1.8)%(1.0)%(0.3)%(0.2)%(0.5)%
Parent Company Loss Benefit
— %(1.1)%(2.3)%(1.2)%(3.6)%— %— %0.7 %
Discrete Tax Adjustments0.2 %— %— %— %— %— %— %1.2 %
Other
0.7 %(0.1)%0.1 %0.3 %0.8 %— %(0.1)%(0.2)%
Effective Income Tax Rate8.1 %12.8 %20.2 %4.0 %(1.8)%13.6 %(2.3)%5.5 %
229



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 Benefit
0.7 %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 %
Other
0.6 %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)%
Nine Months Ended September 30, 2021
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
1.2 %0.3 %2.8 %1.5 %1.6 %0.8 %4.8 %(3.4)%
Tax Reform Excess ADIT Reversal
(8.9)%(7.2)%0.3 %(15.2)%(17.7)%(9.1)%(19.8)%(4.3)%
Production and Investment Tax Credits
(4.9)%(0.3)%— %— %(2.2)%— %(8.1)%(4.6)%
Flow Through
0.2 %0.3 %0.3 %1.7 %(3.0)%0.9 %0.7 %(0.2)%
AFUDC Equity
(1.1)%(1.1)%(1.9)%(1.2)%(1.0)%(0.8)%(0.3)%(0.6)%
Parent Company Loss Benefit
— %(0.7)%(1.9)%(1.3)%(2.8)%— %— %— %
Discrete Tax Adjustments1.1 %— %— %— %— %(1.3)%(0.9)%0.6 %
Other
0.1 %— %— %0.1 %0.4 %0.2 %(0.2)%(0.1)%
Effective Income Tax Rate8.7 %12.3 %20.6 %6.6 %(3.7)%11.7 %(2.8)%8.4 %

Federal and State Income Tax Audit Status

The statute of limitations for the IRS to examine AEP and subsidiaries originally filed federal return has expired for tax years 2016 and earlier. In the third quarter of 2019, AEP and subsidiaries elected to amend the 2014 through 2017 federal returns. In the first quarter of 2020, the IRS notified AEP that it was beginning an examination of these amended returns, including the net operating loss carryback to 2015 that originated in the 2017 return. As of September 30, 2022, the IRS has accepted the 2014-2016 amended tax returns as filed which completes the IRS audit of these tax years. Additionally, AEP has received and agreed to two proposed adjustments on the 2017 tax return, which were immaterial. AEP has agreed to extend the statute of limitations on the 2017 and 2018 tax return to December 31, 2023 to allow time for the audit to be completed and the Congressional Joint Committee on Taxation to approve the associated refund claim.

AEP and subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns, and AEP and subsidiaries are currently under examination in several state and local jurisdictions. 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.

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Federal Legislation

On August 16, 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. With the exception of PTCs and ITCs, this legislation is prospective and has no material impact on the current period financial statements. As 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.
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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 nine months ended September 30, 2022.

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 DebtSeptember 30, 2022December 31, 2021
 (in millions)
Senior Unsecured Notes$28,892.7 $27,497.3 
Pollution Control Bonds1,804.9 1,804.5 
Notes Payable218.0 211.3 
Securitization Bonds524.8 603.5 
Spent Nuclear Fuel Obligation (a)283.2 281.3 
Junior Subordinated Notes (b)2,377.3 2,373.0 
Other Long-term Debt949.2 683.6 
Total Long-term Debt Outstanding35,050.1 33,454.5 
Long-term Debt Due Within One Year (c)1,403.5 2,153.8 
Long-term Debt (d)$33,646.6 $31,300.7 

(a)Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for SNF disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $326 million and $329 million as of September 30, 2022 and December 31, 2021, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.
(b)See “Equity Units” section below for additional information.
(c)Amount excludes $215 million and $200 million as of September 30, 2022 and December 31, 2021, respectively, of Long-term Debt Due Within One Year classified as Liabilities Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
(d)Amount excludes $963 million and $903 million as of September 30, 2022 and December 31, 2021, respectively, of Long-term Debt classified as Liabilities Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.


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Long-term Debt Activity

Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2022 are shown in the following tables:
PrincipalInterest
CompanyType of DebtAmount (a)RateDue Date
Issuances: (in millions)(%)
AEP TexasOther Long-term Debt$200.0 Variable2025
AEP TexasSenior Unsecured Notes500.0 4.702032
AEP TexasSenior Unsecured Notes500.0 5.252052
AEPTCoSenior Unsecured Notes550.0 4.502052
APCoOther Long-term Debt100.0 Variable2023
APCoPollution Control Bonds104.4 3.752025
APCoSenior Unsecured Notes500.0 4.502032
I&MNotes Payable72.8 3.442026
PSOOther Long-term Debt500.0 Variable2022
Non-Registrant:
AEGCoPollution Control Bonds45.0 3.132025
KPCoOther Long-term Debt150.0 Variable2023
Transource EnergyOther Long-term Debt5.0 Variable2023
WPCoOther Long-term Debt165.0 Variable2024
WPCoPollution Control Bonds65.0 3.002027
Total Issuances$3,457.2 

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

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234



PrincipalInterest
CompanyType of DebtAmount PaidRateDue Date
Retirements and Principal Payments:
(in millions)(%)
AEP TexasOther Long-term Debt$200.0 Variable2022
AEP TexasSenior Unsecured Notes400.0 2.402022
AEP TexasSenior Unsecured Notes25.0 3.272022
AEP TexasSecuritization Bonds30.6 2.852024
AEP TexasSecuritization Bonds23.0 2.062025
APCoPollution Control Bonds104.4 2.632022
APCoSecuritization Bonds25.9 2.012023
APCoOther Long-term Debt0.1 13.722026
I&MNotes Payable3.4 Variable2022
I&MNotes Payable1.3 Variable2022
I&MNotes Payable6.7 Variable2023
I&MNotes Payable10.8 Variable2024
I&MNotes Payable18.9 0.932025
I&MNotes Payable13.7 Variable2025
I&MNotes Payable8.0 3.442026
I&MOther Long-term Debt1.7 6.002025
OPCoOther Long-term Debt0.1 1.152028
PSOOther Long-term Debt500.0 Variable2022
PSOOther Long-term Debt0.4 3.002027
SWEPCoOther Long-term Debt1.5 4.682028
SWEPCoNotes Payable3.2 4.582032
Non-Registrant:
AEGCoPollution Control Bonds45.0 1.352022
KPCoOther Long-term Debt75.0 Variable2022
Transource EnergySenior Unsecured Notes2.4 2.752050
WPCoPollution Control Bonds65.0 3.002022
WPCoSenior Unsecured Notes113.0 3.362022
Total Retirements and Principal Payments
$1,679.1 


Long-term Debt Subsequent Event

In October 2022, AEGCo retired $120 million of Other Long-term Debt.

In October 2022, AEGCo issued $80 million of variable rate Other Long-term Debt due in 2024.

In October 2022, AEPTCo retired $104 million of Senior Unsecured Notes.

In October 2022, APCo retired $100 million of Pollution Control Bonds.

In October 2022, I&M retired $7 million of Notes Payable related to DCC Fuel.

In October 2022, Transource Energy issued $64 million of variable rate Other Long-term Debt due in 2025.

In October 2022, Transource Energy retired $64 million of Other Long-term Debt.


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Equity Units (Applies to AEP)

2020 Equity Units

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

Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 1.30% Junior Subordinated Notes (notes) due in 2025 and a forward equity purchase contract which settles after three years in 2023. The notes are expected to be remarketed in 2023, at which time the interest rate will reset at the then current market rate. Investors may choose to remarket their notes to receive the remarketing proceeds and use those funds to settle the forward equity purchase contract, or accept the remarketed debt and use other funds for the equity purchase. If the remarketing is unsuccessful, investors have the right to put their notes to AEP at a price equal to the principal. The Equity Units carry an annual distribution rate of 6.125%, which is comprised of a quarterly coupon rate of interest of 1.30% and a quarterly forward equity purchase contract payment of 4.825%.

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

If the AEP common stock market price is equal to or greater than $99.95: 0.5003 shares per contract.
If the AEP common stock market price is less than $99.95 but greater than $83.29: a number of shares per contract equal to $50 divided by the applicable market price. The holder receives a variable number of shares at $50.
If the AEP common stock market price is less than or equal to $83.29: 0.6003 shares per contract.

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

At the time of issuance, the $850 million of notes were recorded within Long-term Debt on the balance sheets. The present value of the purchase contract payments of $121 million were recorded in Deferred Credits and Other Noncurrent Liabilities with a current portion in Other Current Liabilities at the time of issuance, representing the obligation to make forward equity contract payments, with an offsetting reduction to Paid-in Capital. The difference between the face value and present value of the purchase contract payments will be accreted to Interest Expense on the statements of income over the three year period ending in 2023. The liability recorded for the contract payments is considered non-cash and excluded from the statements of cash flows. Until settlement of the forward equity purchase contract, earnings per share dilution resulting from the equity unit issuance will be determined under the treasury stock method. The maximum amount of shares AEP will be required to issue to settle the purchase contract is 10,205,100 shares (subject to an anti-dilution adjustment).

2019 Equity Units

In March 2019, AEP issued 16.1 million Equity Units initially in the form of corporate units, at a stated amount of $50 per unit, for a total stated amount of $805 million. Net proceeds from the issuance were approximately $785 million. The proceeds were used to support AEP’s overall capital expenditure plans including the acquisition of Sempra Renewables LLC.

Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 3.40% Junior Subordinated Notes (notes) due in 2024 and a forward equity purchase contract which settled after three years in 2022. In January 2022, AEP successfully remarketed the notes on behalf of holders of the corporate units and did not directly receive any proceeds therefrom. Instead, the holders of the corporate units used the debt remarketing proceeds to settle the forward equity purchase contract with AEP. The interest rate on the notes was reset to 2.031% with the maturity remaining in 2024. In March 2022, AEP issued 8,970,920 shares of AEP
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common stock and received proceeds totaling $805 million under the settlement of the forward equity purchase contract. AEP common stock held in treasury was used to settle the forward equity purchase contract.

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 0.5% of consolidated tangible net assets as of September 30, 2022. The method for calculating the consolidated tangible net assets is contractually-defined in the note purchase agreements.

Dividend Restrictions

Utility Subsidiaries’ Restrictions

Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends.

All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act 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.

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.


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

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and direct borrowing from AEP. The AEP System Utility Money Pool operates in accordance with the terms and conditions of its agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of September 30, 2022 and December 31, 2021 are included in Advances to Affiliates and Advances from Affiliates, respectively, on the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ activity and corresponding authorized borrowing limits for the nine months ended September 30, 2022 are described in the following table:
MaximumAverageNet Loans to
BorrowingsMaximumBorrowingsAverage(Borrowings) fromAuthorized
from theLoans to thefrom theLoans to thethe Utility MoneyShort-term
UtilityUtilityUtilityUtilityPool as ofBorrowing
CompanyMoney PoolMoney PoolMoney PoolMoney PoolSeptember 30, 2022Limit
 (in millions)
AEP Texas$348.8 $652.3 $208.1 $319.8 $129.5 $500.0 
AEPTCo480.2 137.0 197.4 31.3 78.7 (a)820.0 (b)
APCo438.4 214.2 180.9 52.8 182.1 500.0 
I&M159.1 22.6 86.0 22.1 (82.3)500.0 
OPCo147.2 246.1 59.9 86.9 (68.8)500.0 
PSO338.3 432.5 200.9 402.8 (223.5)400.0 
SWEPCo261.6 156.6 191.0 109.7 (156.3)400.0 

(a)    Amount excludes $5 million of Advances to Affiliates classified as Assets Held for Sale on the AEPTCo balance sheet. See “Dispositions of KPCo and KTCo” section of Note 6 for additional information.
(b)    Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.

The activity in the above table does not include short-term lending activity of certain AEP nonutility subsidiaries. AEP Texas’ wholly-owned subsidiary, AEP Texas North Generation Company, LLC and SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC participate in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2022 and December 31, 2021 are included in Advances to Affiliates on the subsidiaries’ balance sheets. The Nonutility Money Pool participants’ activity for the nine months ended September 30, 2022 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 PoolSeptember 30, 2022
(in millions)
AEP Texas$6.9 $6.8 $6.8 
SWEPCo2.1 2.1 2.1 



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AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of outstanding loans to and borrowings from AEP as of September 30, 2022 and December 31, 2021 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct borrowing and lending activity with AEP and corresponding authorized borrowing limit for the nine months ended September 30, 2022 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 September 30, 2022September 30, 2022Borrowing Limit
(in millions)
$52.4 $141.8 $7.1 $59.6 $33.0 $— $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:
 Nine Months Ended September 30,
20222021
Maximum Interest Rate3.39 %0.40 %
Minimum Interest Rate0.10 %0.02 %

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 Funds
Borrowed from the Utility Money PoolLoaned to the Utility Money Pool
for Nine Months Ended September 30,for Nine Months Ended September 30,
Company2022202120222021
AEP Texas0.90 %0.33 %1.82 %0.27 %
AEPTCo1.03 %0.32 %2.14 %0.07 %
APCo1.39 %0.28 %2.13 %0.28 %
I&M1.38 %0.32 %1.46 %0.25 %
OPCo1.81 %0.27 %1.22 %0.15 %
PSO1.70 %0.34 %0.75 %0.06 %
SWEPCo1.67 %0.28 %0.55 %0.38 %

Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized in the following table:
Nine Months Ended September 30, 2022Nine Months Ended September 30, 2021
  Maximum Minimum AverageMaximum Minimum Average
  Interest Rate Interest Rate Interest RateInterest Rate Interest Rate Interest Rate
  for Funds for Funds for Fundsfor Funds for Funds for Funds
 Loaned to Loaned to Loaned toLoaned to Loaned to Loaned to
 the Nonutility the Nonutility the Nonutilitythe Nonutility the Nonutility the Nonutility
Company Money Pool Money Pool Money PoolMoney Pool Money Pool Money Pool
AEP Texas 3.39 %0.46 %1.51 %0.41 %0.21 %0.34 %
SWEPCo 3.39 %0.46 %1.52 %0.41 %0.21 %0.34 %


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

 MaximumMinimumMaximumMinimumAverageAverage
 Interest RateInterest RateInterest RateInterest RateInterest RateInterest Rate
Nine Months for Fundsfor Fundsfor Fundsfor Fundsfor Fundsfor Funds
Ended BorrowedBorrowedLoanedLoanedBorrowedLoaned
September 30, from AEP from AEPto AEP to AEP from AEP to AEP
2022 3.39 %0.46 %3.37 %0.46 %1.56 %1.38 %
2021 0.86 %0.25 %0.86 %0.25 %0.35 %0.34 %

Short-term Debt (Applies to AEP)

Outstanding short-term debt was as follows:
 September 30, 2022December 31, 2021
OutstandingInterestOutstandingInterest
CompanyType of DebtAmountRate (a)AmountRate (a)
 (dollars in millions)
AEPSecuritized Debt for Receivables (b)$750.0 1.16 %$750.0 0.19 %
AEPCommercial Paper1,952.3 3.38 %1,364.0 0.34 %
AEPTerm Loan— — %500.0 0.81 %
Total Short-term Debt$2,702.3  $2,614.0  

(a)Weighted-average rate.
(b)Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.

Credit Facilities

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

Securitized Accounts Receivables – AEP Credit (Applies to AEP)

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

AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and was amended in September 2021 to include a $125 million and a $625 million facility. The $125 million facility was renewed in September 2022 and amended to extend the expiration date to September 2024. The $625 million facility also expires in September 2024. As of September 30, 2022, the affiliated utility subsidiaries are in compliance with all requirements under the agreement.

Accounts receivable information for AEP Credit was as follows:
Three Months Ended September 30,Nine Months Ended September 30,
2022202120222021
(dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable
2.25 %0.18 %1.16 %0.19 %
Net Uncollectible Accounts Receivable Written-Off$9.5 $7.5 $23.1 $22.6 

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September 30, 2022December 31, 2021
(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts
$1,172.5 $995.2 
Short-term – Securitized Debt of Receivables750.0 750.0 
Delinquent Securitized Accounts Receivable 57.4 57.9 
Bad Debt Reserves Related to Securitization39.4 42.8 
Unbilled Receivables Related to Securitization252.3 307.1 

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 pending 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. 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:
CompanySeptember 30, 2022December 31, 2021
 (in millions)
APCo$127.5 $153.1 
I&M187.8 156.9 
OPCo476.7 392.7 
PSO188.4 114.5 
SWEPCo217.0 153.0 

The fees paid to AEP Credit for customer accounts receivable sold were:
 Three Months Ended September 30,Nine Months Ended September 30,
Company20222021 (a)20222021 (a)
 (in millions)
APCo$2.8 $1.3 $5.6 $3.7 
I&M2.8 2.1 6.5 5.3 
OPCo7.3 4.6 22.2 3.5 
PSO2.4 1.1 4.6 2.4 
SWEPCo3.2 1.3 6.0 4.1 
(a)In 2020, an increase in allowance for doubtful accounts was recognized in response to the anticipated impact of COVID-19 on the collectability of accounts receivable, which caused an increase in fees paid by the Registrants. In 2021, due to higher than expected collections of accounts receivables, allowance for doubtful accounts was adjusted resulting in the issuance of credits to offset the higher fees previously paid.





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The proceeds on the sale of receivables to AEP Credit were:
 Three Months Ended September 30,Nine Months Ended September 30,
Company2022202120222021
(in millions)
APCo$360.4 $342.2 $1,114.9 $980.6 
I&M558.5 536.8 1,574.3 1,478.9 
OPCo874.1 668.4 2,284.0 1,867.5 
PSO588.5 460.1 1,380.4 1,068.8 
SWEPCo593.6 488.5 1,425.3 1,265.5 
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13. PROPERTY, PLANT AND EQUIPMENT

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

Asset Retirement Obligations

The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, wind farms, solar farms and certain coal mining facilities. The discussion below summarizes significant changes to the Registrants ARO recorded in 2022 and should be read in conjunction with the Property, Plant and Equipment note within the 2021 Annual Report.

In March 2022, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Traverse during its development and construction. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Traverse assets in proportion to their undivided ownership interests. Traverse was placed in-service in March 2022. As a result, PSO and SWEPCo incurred additional ARO liabilities of $13 million and $15 million, respectively. See the “North Central Wind Energy Facilities” section of Note 6 for additional information. Additionally, in March 2022, SWEPCo recorded a $13 million revision due to an increase in estimated ash pond closure costs at the Pirkey Plant and the Welsh Plant. In June 2022, SWEPCo recorded a $16 million revision due to an increase in estimated reclamation costs at Sabine. In September 2022, SWEPCo recorded a $14 million revision due to an increase in estimated landfill closure costs at Pirkey Plant.

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

Company
ARO as of December 31, 2021
Accretion
Expense
Liabilities
Incurred
Liabilities
Settled
Revisions in
Cash Flow
Estimates
ARO as of September 30, 2022
(in millions)
AEP (a)(b)(c)(d)(e)$2,741.7 $82.1 $37.4 $(29.4)$90.9 $2,922.7 
PSO (a)(d)57.6 3.0 12.8 (0.6)1.9 74.7 
SWEPCo (a)(c)(d)222.7 8.3 15.4 (16.9)48.0 277.5 

(a)Includes ARO related to ash disposal facilities.
(b)Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.98 billion and $1.93 billion as of September 30, 2022 and December 31, 2021, respectively.
(c)Includes ARO related to Sabine and DHLC.
(d)Includes ARO related to asbestos removal.
(e)Includes $18 million and $18 million as of September 30, 2022 and December 31, 2021, respectively, of ARO classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.





243



14. REVENUE FROM CONTRACTS WITH CUSTOMERS

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

Disaggregated Revenues from Contracts with Customers

The tables below represent AEP’s reportable segment revenues from contracts with customers, net of respective provisions for refund, by type of revenue:
Three Months Ended September 30, 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 Revenues 299.3 — — 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 Revenues
419.6 162.3 424.9 610.9 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 Customers
3,225.2 1,538.2 424.6 612.6 26.5 (427.4)5,399.7 
Other Revenues:
Alternative Revenues (b)0.9 (13.5)6.3 — — 4.4 (1.9)
Other Revenues (b) (d)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 $18 million. The remaining affiliated amounts were immaterial.
(d)Generation & Marketing includes economic hedge activity.
244



Three Months Ended September 30, 2021
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration & MarketingCorporate and OtherReconciling AdjustmentsAEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues$1,144.3 $598.0 $— $— $— $— $1,742.3 
Commercial Revenues618.9 279.9 — — — — 898.8 
Industrial Revenues566.0 95.2 — — — (0.1)661.1 
Other Retail Revenues47.5 11.1 — — — — 58.6 
Total Retail Revenues2,376.7 984.2 — — — (0.1)3,360.8 
Wholesale and Competitive Retail Revenues:
Generation Revenues 233.8 — — 47.8 — — 281.6 
Transmission Revenues (a)99.8 150.6 375.8 — — (317.4)308.8 
Renewable Generation Revenues (b)— — — 24.1 — (0.6)23.5 
Retail, Trading and Marketing Revenues (c)
— — — 397.1 0.1 (3.1)394.1 
Total Wholesale and Competitive Retail Revenues
333.6 150.6 375.8 469.0 0.1 (321.1)1,008.0 
Other Revenues from Contracts with Customers (b)49.4 54.2 5.1 1.4 23.5 (40.1)93.5 
Total Revenues from Contracts with Customers
2,759.7 1,189.0 380.9 470.4 23.6 (361.3)4,462.3 
Other Revenues:
Alternative Revenues (b)0.5 6.4 10.7 — — (11.7)5.9 
Other Revenues (b) (d)(0.9)4.9 — 150.7 3.1 (3.0)154.8 
Total Other Revenues(0.4)11.3 10.7 150.7 3.1 (14.7)160.7 
Total Revenues$2,759.3 $1,200.3 $391.6 $621.1 $26.7 $(376.0)$4,623.0 

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $286 million. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $4 million. The remaining affiliated amounts were immaterial.
(d)Generation & Marketing includes economic hedge activity.



245



Three Months Ended September 30, 2022
AEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Retail Revenues:
Residential Revenues$204.0 $— $360.5 $238.6 $517.9 $299.6 $285.5 
Commercial Revenues107.1 — 161.1 154.3 266.1 153.4 182.3 
Industrial Revenues35.4 — 163.3 155.6 156.1 98.9 108.3 
Other Retail Revenues11.5 — 20.6 1.2 3.5 30.1 0.6 
Total Retail Revenues358.0 — 705.5 549.7 943.6 582.0 576.7 
Wholesale Revenues:
Generation Revenues (a)— — 107.9 126.3 — 9.4 87.6 
Transmission Revenues (b)140.8 411.7 41.5 8.8 21.5 10.2 42.3 
Total Wholesale Revenues140.8 411.7 149.4 135.1 21.5 19.6 129.9 
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 Customers
508.3 411.4 888.6 715.4 1,029.9 608.0 714.2 
Other Revenues:
Alternative Revenues (d)0.6 7.1 — — (14.1)0.2 3.3 
Other Revenues (d)— — 0.3 — 5.5 — — 
Total Other Revenues0.6 7.1 0.3 — (8.6)0.2 3.3 
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 $44 million primarily related to the PPA with KGPCo.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $339 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $15 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.
246



Three Months Ended September 30, 2021
AEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Retail Revenues:
Residential Revenues$172.5 $— $340.1 $231.7 $425.4 $236.8 $230.9 
Commercial Revenues89.1 — 146.9 143.9 190.8 120.9 145.4 
Industrial Revenues25.4 — 154.8 146.8 69.8 77.1 85.4 
Other Retail Revenues8.2 — 18.6 1.3 3.1 23.4 2.3 
Total Retail Revenues295.2 — 660.4 523.7 689.1 458.2 464.0 
Wholesale Revenues:
Generation Revenues (a)— — 83.7 80.2 — 7.2 77.1 
Transmission Revenues (b)131.5 360.1 35.2 8.7 19.1 10.6 37.1 
Total Wholesale Revenues131.5 360.1 118.9 88.9 19.1 17.8 114.2 
Other Revenues from Contracts with Customers (c)
6.8 5.0 22.5 24.2 47.3 8.3 6.1 
Total Revenues from Contracts with Customers
433.5 365.1 801.8 636.8 755.5 484.3 584.3 
Other Revenues:
Alternative Revenues (d)(0.9)11.9 2.2 (1.1)7.3 (0.5)(0.2)
Other Revenues (d)— — — — 4.9 — — 
Total Other Revenues(0.9)11.9 2.2 (1.1)12.2 (0.5)(0.2)
Total Revenues$432.6 $377.0 $804.0 $635.7 $767.7 $483.8 $584.1 

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $30 million primarily related to the PPA with KGPCo.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $281 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $17 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.
247



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 (b)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 (b)674.8 — — 207.0 — (0.1)881.7 
Transmission Revenues (a)334.4 482.1 1,261.0 — — (1,086.5)991.0 
Renewable Generation Revenues (b)— — — 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 Customers
8,558.5 4,081.5 1,260.7 1,603.8 65.8 (1,176.2)14,394.1 
Other Revenues:
Alternative Revenues (b)3.4 (21.5)(39.6)— — (7.4)(65.1)
Other Revenues (b) (e)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. 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.
(b)Amounts include affiliated and nonaffiliated revenues.
(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)Generation & Marketing includes economic hedge activity.

248



Nine Months Ended September 30, 2021
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration & MarketingCorporate and OtherReconciling AdjustmentsAEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues$3,016.2 $1,641.2 $— $— $— $— $4,657.4 
Commercial Revenues1,642.0 804.1 — — — — 2,446.1 
Industrial Revenues1,602.5 283.8 — — — (0.5)1,885.8 
Other Retail Revenues125.9 32.4 — — — — 158.3 
Total Retail Revenues6,386.6 2,761.5 — — — (0.5)9,147.6 
Wholesale and Competitive Retail Revenues:
Generation Revenues757.1 — — 119.4 — — 876.5 
Transmission Revenues (a)267.3 420.7 1,092.1 — — (901.5)878.6 
Renewable Generation Revenues (b)— — — 66.7 — (1.7)65.0 
Retail, Trading and Marketing Revenues (c)
— — — 1,325.6 0.6 (48.5)1,277.7 
Total Wholesale and Competitive Retail Revenues
1,024.4 420.7 1,092.1 1,511.7 0.6 (951.7)3,097.8 
Other Revenues from Contracts with Customers (b)136.1 149.3 12.5 4.9 46.1 (87.9)261.0 
Total Revenues from Contracts with Customers
7,547.1 3,331.5 1,104.6 1,516.6 46.7 (1,040.1)12,506.4 
Other Revenues:
Alternative Revenues (b)10.7 46.1 42.2 — — (63.5)35.5 
Other Revenues (b) (d)(0.6)14.2 — 175.3 8.4 (8.6)188.7 
Total Other Revenues10.1 60.3 42.2 175.3 8.4 (72.1)224.2 
Total Revenues$7,557.2 $3,391.8 $1,146.8 $1,691.9 $55.1 $(1,112.2)$12,730.6 

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $835 million. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $49 million. The remaining affiliated amounts were immaterial.
(d)Generation & Marketing includes economic hedge activity.

249



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 (d)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 (a)— — 227.6 310.9 — 19.2 206.2 
Transmission Revenues (b)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 (c)
24.4 (0.4)78.6 86.3 169.6 21.4 18.9 
Total Revenues from Contracts with Customers
1,407.3 1,217.7 2,569.3 1,964.4 2,674.2 1,439.4 1,748.2 
Other Revenues:
Alternative Revenues (d)(2.9)(34.4)0.1 7.3 (18.6)(0.7)0.7 
Other Revenues (d)— — 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. The affiliated revenue for APCo was $122 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $992 million. The remaining affiliated amounts were immaterial.
(c)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.
(d)Amounts include affiliated and nonaffiliated revenues.
250



Nine Months Ended September 30, 2021
AEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Retail Revenues:
Residential Revenues$423.7 $— $1,025.0 $624.4 $1,217.5 $516.4 $547.1 
Commercial Revenues265.2 — 409.5 384.5 538.9 286.8 385.4 
Industrial Revenues81.6 — 433.4 418.9 202.2 202.1 247.1 
Other Retail Revenues23.1 — 51.7 3.9 9.4 58.2 7.2 
Total Retail Revenues793.6 — 1,919.6 1,431.7 1,968.0 1,063.5 1,186.8 
Wholesale Revenues:
Generation Revenues (a)— — 231.2 248.1 — 6.8 326.2 
Transmission Revenues (b)364.5 1,045.2 94.1 25.3 56.2 28.8 94.5 
Total Wholesale Revenues364.5 1,045.2 325.3 273.4 56.2 35.6 420.7 
Other Revenues from Contracts with Customers (c)
35.4 12.5 43.6 81.9 113.8 24.8 17.7 
Total Revenues from Contracts with Customers
1,193.5 1,057.7 2,288.5 1,787.0 2,138.0 1,123.9 1,625.2 
Other Revenues:
Alternative Revenues (d)1.8 46.5 9.5 (3.0)44.3 0.5 5.1 
Other Revenues (d)— — — — 14.2 — — 
Total Other Revenues1.8 46.5 9.5 (3.0)58.5 0.5 5.1 
Total Revenues$1,195.3 $1,104.2 $2,298.0 $1,784.0 $2,196.5 $1,124.4 $1,630.3 

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $90 million primarily relating to the PPA with KGPCo.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $823 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $46 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.


251



Fixed Performance Obligations

The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of September 30, 2022. Fixed performance obligations primarily include wholesale transmission services, electricity sales for fixed amounts of energy and stand ready services into PJM’s RPM market. The Registrant Subsidiaries amounts shown in the table below include affiliated and nonaffiliated revenues.
Company20222023-20242025-2026After 2026Total
(in millions)
AEP$318.7 $172.1 $157.8 $96.9 $745.5 
AEP Texas145.8 — — — 145.8 
AEPTCo369.4 — — — 369.4 
APCo50.1 33.7 26.6 11.5 121.9 
I&M9.7 13.6 9.2 4.5 37.0 
OPCo19.2 3.4 — — 22.6 
PSO3.4 — — — 3.4 
SWEPCo10.9 — — — 10.9 

Contract Assets and Liabilities

Contract assets are recognized when the Registrants have a right to consideration that is conditional upon the occurrence of an event other than the passage of time, such as future performance under a contract. The Registrants did not have material contract assets as of September 30, 2022 and December 31, 2021.

When the Registrants receive consideration, or such consideration is unconditionally due from a customer prior to transferring goods or services to the customer under the terms of a sales contract, they recognize a contract liability on the balance sheets in the amount of that consideration. Revenue for such consideration is subsequently recognized in the period or periods in which the remaining performance obligations in the contract are satisfied. The Registrants’ contract liabilities typically arise from services provided under joint use agreements for utility poles. The Registrants did not have material contract liabilities as of September 30, 2022 and December 31, 2021.

Accounts Receivable from Contracts with Customers

Accounts receivable from contracts with customers are presented on the Registrant Subsidiaries’ balance sheets within the Accounts Receivable - Customers line item. The Registrant Subsidiaries’ balances for receivables from contracts that are not recognized in accordance with the accounting guidance for “Revenue from Contracts with Customers” included in Accounts Receivable - Customers were not material as of September 30, 2022 and December 31, 2021. 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:
CompanySeptember 30, 2022December 31, 2021
(in millions)
AEP Texas$— $0.4 
AEPTCo110.6 95.5 
APCo65.8 117.8 
I&M51.1 61.2 
OPCo61.5 51.7 
PSO36.8 18.8 
SWEPCo20.2 24.7 

252



CONTROLS AND PROCEDURES

During the third quarter of 2022, management, including the principal executive officer and principal financial officer of each of the Registrants, evaluated the Registrants’ disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. As of September 30, 2022, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives.

There was no change in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the third quarter of 2022 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.
253



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, 2021 includes a detailed discussion of risk factors. As of September 30, 2022, the risk factors appearing in AEP’s 2021 Annual Report are supplemented and updated as follows:

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

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

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

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

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


254



A security breach of AEP or its regulated utility businesses’ physical assets or information systems, interconnected entities in RTOs, or regulators could impact the operation of the generation fleet and/or reliability of the transmission and distribution system. AEP and its regulated utility businesses could be subject to financial harm associated with ransomware theft or inappropriate release of certain types of information, including sensitive customer, vendor, employee, trading or other confidential data. A successful cyber-attack on the systems that control generation, transmission, distribution or other assets could severely disrupt business operations, preventing service to customers or collection of revenues. The breach of certain business systems could affect the ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to AEP’s reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data could lead to significant breach notification expenses and mitigation expenses such as credit monitoring.  AEP and its third-party vendors have been subject, and will likely continue to be subject, to attempts to gain unauthorized access to their technology systems and confidential data or to attempts to disrupt utility and related business operations. While there have been immaterial incidents of phishing, unauthorized access to technology systems, financial fraud, and disruption of remote access across the AEP System, there has been no material impact on business or operations from these attacks. However, AEP cannot guarantee that security efforts will detect or prevent breaches, operational incidents, or other breakdowns of technology systems and network infrastructure and cannot provide any assurance that such incidents will not have a material adverse effect in the future.

The IRA could change the rate of taxes imposed on AEP. (Applies to all Registrants)

On August 16, 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. Additional guidance on the tax provisions in the IRA is expected from the Treasury and the IRS. The regulatory treatment of the impacts of this legislation will also be subject to the discretion of the FERC and state public utility commissions. Any adverse development in this legislation, including guidance from Treasury and the IRS or unfavorable regulatory treatment, could reduce future cash flows 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 September 30, 2022.

Item 5.  Other Information

None.

255



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:
   
APCo‡   File No. 1-3457
4Company Order and Officer’s Certificate between APCo and The Bank of New York Mellon Trust Company, N.A. as Trustee dated August 1, 2022 establishing terms of the 4.50% Senior Notes, Series BB, due 2032.

The exhibits designated with an (X) in the table below are being filed on behalf of the Registrants.
ExhibitDescriptionAEPAEP
Texas
AEPTCoAPCoI&MOPCoPSOSWEPCo
10Amendment to Stock Purchase Agreement dated September 29, 2022 among AEP, AEPTCo and Liberty Utilities Co.
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
95
Mine Safety Disclosures
101.INS
XBRL Instance Document
The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCH
XBRL Taxonomy Extension Schema
XXXXXXXX
101.CAL
XBRL Taxonomy Extension Calculation Linkbase
XXXXXXXX
101.DEF
XBRL Taxonomy Extension Definition Linkbase
XXXXXXXX
101.LAB
XBRL Taxonomy Extension Label Linkbase
XXXXXXXX
101.PRE
XBRL Taxonomy Extension Presentation Linkbase
XXXXXXXX
104
Cover Page Interactive Data File
Formatted as Inline XBRL and contained in Exhibit 101.
256

SIGNATURE


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


AMERICAN ELECTRIC POWER COMPANY, INC.



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



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



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



Date:  October 27, 2022


FIRST AMENDMENT TO STOCK PURCHASE AGREEMENT
This FIRST AMENDMENT TO THE STOCK PURCHASE AGREEMENT, is made as of September 29, 2022 (this “Amendment”), by and among American Electric Power Company, Inc. (“AEP”), a New York corporation, AEP Transmission Company, LLC (“AEP TransCo”), a Delaware limited liability company (AEP and AEP TransCo are each referred to individually as a “Seller,” and, collectively, as “Sellers”), and Liberty Utilities Co., a Delaware corporation (“Purchaser”). Sellers and Purchaser are each referred to individually in this Amendment as a “Party” and collectively as the “Parties.”
RECITALS:
WHEREAS, the Parties are party to that certain Stock Purchase Agreement, dated as of October 26, 2021, as may be amended, modified or supplemented (the “SPA”).
WHEREAS, the Parties desire to amend the SPA to provide for a reduced Base Purchase Price to reflect a resolution of various matters in connection with the transactions contemplated by the SPA.
WHEREAS, the Parties have filed an application with the KPSC and WVPSC, respectively, seeking approval of the Mitchell Plant Ownership Agreement and Mitchell Plant O&M Agreement in the forms attached to the SPA as Exhibit B and Exhibit C, respectively.
WHEREAS, on May 3, 2022 and July 1, 2022, the KPSC and WVPSC, respectively, issued orders (the “KPSC Order” and the “WVPSC Order”, respectively) that required changes to the proposed forms of the Mitchell Plant Ownership Agreement and Mitchell Plant O&M Agreement submitted to them, which changes diverged in material respects, such that the Mitchell Plant Ownership Agreement and Mitchell Plant O&M Agreement cannot be executed on or prior to the Closing Date in a form that complies with both of the KPSC Order and the WVPSC Order, and, accordingly, the condition to the Parties’ obligations to effect the transactions contemplated by the SPA set forth in Section 7.1(d) of the SPA has not been satisfied.
WHEREAS, in light of the KPSC Order and the WVPSC Order, the Parties desire, among other things, to (a) keep the Existing Mitchell Plant Operating Agreement in effect at the Closing, (b) cause the Operating Committee to approve resolutions as described herein to clarify the implementation of certain provisions of the Existing Mitchell Plant Operating Agreement and (c) make certain agreements with respect to the negotiation of a replacement agreement for the Existing Mitchell Plant Operating Agreement and with respect to the evaluation of potential assignment of the Existing Mitchell Plant Operating Agreement.
WHEREAS, the Parties desire to modify and, subject to the satisfaction of certain conditions as set forth herein, waive certain of the conditions set forth in Article VII of the SPA, and the Parties desire to make certain additional agreements with respect to the timing of the Closing.
WHEREAS, the Parties desire to amend the SPA to provide for the transfer to and retention following the Closing by an Affiliate of AEP of the Retained Disabled Employees (as defined below) and to allow for Continuing Employees on Sick Leave (as defined below) to remain eligible to receive income replacement benefits under the American Electric Power System Long-term Disability Plan (the “AEP LTD Plan”).



WHEREAS, Purchaser desires to consent to the purchase by Kentucky Power of vehicles and personal property covered by Master Leases in an amount in excess of $10,000,000.
NOW, THEREFORE, in consideration of the premises and the agreements, provisions and covenants herein contained, Sellers and Purchaser hereby agree as follows:
1.Definitions. Unless the context shall otherwise require or the express terms of this Amendment shall otherwise provide, capitalized terms used herein and not otherwise defined herein shall have the meanings given to them in the SPA. As used herein, the following terms have the following meanings:
a.ELG Upgrades” means any improvements or upgrades to Mitchell to enable Wheeling to comply with the Steam Electric Reconsideration Rule, 85 Fed. Reg. 64,650 (Oct. 13, 2020), and any regulations thereunder promulgated by the USEPA or the State of West Virginia.
b.Operating Committee” shall have the meaning ascribed thereto in the Existing Mitchell Plant Operating Agreement.
c.Qualified Replacement Operator” shall mean a Person that:
i.has operated for a period of at least three (3) years, and continues to operate, coal and/or natural gas power generation facilities with an aggregate electricity output of at least one thousand (1,000) megawatts and at least one of those facilities is a coal power generation facility with an aggregate electricity output of at least three hundred (300) megawatts (or has engaged a third party to operate Mitchell who satisfies such operation standards); and
ii.either has (a) a credit rating of “BBB-” or higher by S&P Global Ratings and “Baa3” or higher by Moody’s Investor Service or (b) a tangible net worth of at least $500,000,000 (or has a direct or indirect parent who satisfies such financial standards).
d.Transaction Commitments” means any terms, conditions, liabilities, obligations, or commitments contained in the approval order issued in KPSC Case No. 2021-00481, including any other orders arising from, relating to or further implementing such approval order and any modifications or supplements thereto.
2.Amendment to the Base Purchase Price.
a.The definition of Base Purchase Price is hereby deleted in its entirety and replaced with the following:

Base Purchase Price” shall mean $2,646,000,000.

b.The Parties hereby acknowledge and agree that the foregoing amendment to the Base Purchase Price, which has been agreed in respect of the various matters addressed by this Amendment, includes the sole contribution of Sellers and its Affiliates in respect of the Transaction Commitments. Purchaser shall be responsible for the fulfilment of, and shall be solely responsible for any costs of, any and all Transaction Commitments following the Closing. Following the



Closing, each of the Sellers shall, and shall cause its Affiliates to, to the extent requested by Purchaser, reasonably cooperate with Purchaser to provide information, consultation and assistance with analyses in connection with Purchaser’s fulfilment of any and all Transaction Commitments. Purchaser shall indemnify, hold harmless and reimburse the Seller Indemnified Parties (other than the Acquired Companies) for any liabilities and damages, including costs, expenses and penalties, to the extent related to or arising out of any failure of any Acquired Company, Purchaser or its Affiliates or the Sellers to comply with or satisfy the Transaction Commitments, other than as a result of any failure in any material respect of any of the Sellers or their respective Affiliates to reasonably cooperate with Purchaser in accordance with the immediately preceding sentence. Notwithstanding anything to the contrary contained in the SPA, (i) the Transaction Commitments and the financial impact thereof on the Acquired Companies shall not be reflected as reductions (directly or indirectly) to the Purchase Price, even if paid or accrued by the Acquired Companies on or prior to the Closing, whether through reductions to the Closing Cash or Net Working Capital or increases to Closing Indebtedness, or otherwise and (ii) any implementation of the Transaction Commitments that becomes effective prior to the Closing shall be subject to Purchaser’s input and consent (not to be unreasonably withheld, conditioned or delayed).

c.In consideration of the mutual promises stated herein, Purchaser for itself and all of its Affiliates fully, completely, and without reservation, except for (i) any claims associated with this Amendment or enforcement thereof, (ii) any claims associated with any other Contract (other than the SPA) to which a Seller Indemnified Party is a party or (iii) Fraud by a Seller Indemnified Party, IRREVOCABLY, UNCONDITIONALLY, KNOWINGLY AND VOLUNTARILY RELEASES, ACQUITS AND FOREVER DISCHARGES each of the Seller Indemnified Parties from any and all claims Purchaser or its Affiliates (including the Acquired Companies after the Closing) have or may have in the past, now, or in the future against any Seller Indemnified Party related to or arising out of any obligation to comply with the Transaction Commitments, including all claims, causes of action, demands, actions, suits, liabilities of any nature, obligations of any kind, and damages whenever incurred, including interest, costs, expenses, penalties and attorneys’ fees, known and unknown, suspected and unsuspected, past and present or that may arise in the future, foreseen and unforeseen, at common law, statutory, administrative, under the SPA or otherwise, in law or equity, which Purchaser or its Affiliates ever had, now has, or hereafter can or may have or which could have been or may be asserted in the future on their behalf by another person or entity, resulting from or relating to acts or omissions of any kind by any Seller Indemnified Party arising out of or related to any Transaction Commitments.





3.Agreements with Respect to Mitchell.
a.As promptly as reasonably practicable following the Closing, the Parties agree to negotiate, or will cause their respective Affiliates to negotiate, in good faith a replacement of the Existing Mitchell Plant Operating Agreement (the “Replacement Mitchell Plant Agreement”) generally consistent to the greatest extent practicable with the provisions contained in the forms of Mitchell Plant Ownership Agreement and Mitchell Plant O&M Agreement attached to the SPA, giving due regard to the Orders of the KPSC and WVPSC related to the Mitchell Plant Ownership Agreement and Mitchell Plant O&M Agreement and the resolutions of the Operating Committee (as defined in the Existing Mitchell Plant Operating Agreement) that have implemented certain of such substantive provisions. The Replacement Mitchell Plant Agreement will include, among other things, the right of Wheeling (or another Affiliate of Sellers) to acquire the Mitchell Interest on or after December 31, 2028, in a manner reasonably acceptable to both Kentucky Power and Wheeling in the event Wheeling continues operations at Mitchell after December 31, 2028.

b.Without limiting the foregoing or clause (d) below, the Parties will use good faith efforts to agree upon the terms of the Replacement Mitchell Plant Agreement, obtain any requisite approvals related thereto and cause their respective applicable Affiliates to enter into the Replacement Mitchell Plant Agreement by no later than June 30, 2024, as such date may be adjusted for changes in the anticipated bid date with respect to the Mitchell capacity for the 2028/2029 PJM Reliability Pricing Model (RPM) Base Residual Auction (BRA) (the “PJM Auction Bid Date”) or the timing of a potential KP Mitchell Sale (as defined below).

c.Following the Closing, Sellers will cause Wheeling to consent to any direct or indirect sale, assignment or other transfer of all of the Mitchell Interest, including any assignment of the Existing Mitchell Plant Operating Agreement, by Kentucky Power to any third party that assumes Kentucky Power’s obligations under the Existing Mitchell Plant Operating Agreement (in the case of a direct transfer) and satisfies clause (ii) of the definition of Qualified Replacement Operator (such sale, assignment or other transfer, a “KP Mitchell Sale” and such third party, a “Mitchell Interest Acquirer”). In connection with any actual or potential KP Mitchell Sale, if requested by Purchaser, Sellers will use reasonable best efforts to cause Wheeling, and Purchaser will use reasonable best efforts to cause the relevant Mitchell Interest Acquirer, to negotiate and enter into definitive documentation relating to a commercially reasonable arrangement (including in advance of the PJM Auction Bid Date) whereby (i) the Mitchell Interest Acquirer will be permitted to utilize its pro rata share of the energy and capacity of Mitchell following December 31, 2028, in accordance with the terms of the Existing Mitchell Plant Operating Agreement, and in exchange therefor (ii) the Mitchell Interest Acquirer (or a designee thereof) will reimburse Wheeling for its investment in ELG Upgrades and other assets (including capital expenditures with



a useful life that extends beyond December 31, 2028) in which Wheeling’s investment exceeded its otherwise applicable ownership interest in Mitchell (i.e., 50% as of the Closing). In the event that Sellers directly or indirectly (whether through Wheeling or otherwise) sell, assign or otherwise transfer their equity interest in Mitchell to another Person, Sellers shall cause such Person to assume the obligations of Sellers pursuant this Section 3 of this Amendment in connection with such sale, assignment or other transfer. Following the Closing, Purchaser will cause Kentucky Power to consent to assignment of the Existing Mitchell Plant Operating Agreement by Wheeling to an Affiliate of Wheeling in connection with a direct or indirect sale, assignment or other transfer by Wheeling of its equity interest in Mitchell to an Affiliate of Wheeling that assumes Wheeling’s obligations under the Existing Mitchell Plant Operating Agreement (in the case of a direct transfer) and is a Qualified Replacement Operator.

d.The Parties will, and will cause their respective Affiliates to, consult and cooperate with each other Party and use reasonable best efforts to prepare and file any necessary applications, notices, petitions and filings, and obtain any consents, approval and authorizations of Governmental Entities, including to the extent required by Law or which a Party may otherwise reasonably and in good faith elect to file or obtain, to implement the matters contemplated by this Amendment, including any KP Mitchell Sale and the Replacement Mitchell Plant Agreement. In furtherance of the foregoing, each Party shall, and shall cause its Affiliates to, consult and cooperate with the other Parties as to the appropriate time of all such filings and notifications, furnish to the other Parties such necessary information and reasonable assistance in connection with the preparation of such filings, and respond promptly to any requests for additional information with the preparation of such filings, and respond promptly to any requests for additional information made in connection therewith by any Governmental Entity.

e.As promptly as reasonably practicable following the date hereof, but in any event no later than October 3, 2022, Purchaser and Sellers will execute and jointly file a letter in FERC Docket No. EC22-26-000 in the form attached as Annex A to this Amendment, with any such modifications as Purchaser and Sellers may mutually agree. In accordance with ordering paragraph 8 of the KPSC’s May 5, 2022 Order (Case No. 2021-00481), upon issuance of the Section 203 Approval (as defined below), Sellers and Purchaser will jointly inform the KPSC of the issuance of the Section 203 Approval and the date on which the transactions contemplated by the SPA are anticipated to be consummated.

f.At or prior to the Closing, Sellers shall cause the Operating Committee to enact resolutions, effective upon the Closing, in substantially the form attached as Annex B to this Amendment, with such modifications as Purchaser and Sellers may mutually agree (the “Closing Operating Committee Resolutions”). Prior to the Closing, without the written consent of Purchaser, Sellers shall not, and shall cause any of their respective Affiliates and any designee to the Operating



Committee of any of the foregoing not to, revoke, revise, supersede or otherwise modify, or permit the revocation, revision, supersedence or other modification of, the Closing Operating Committee Resolutions or that certain Written Consent Action of the Mitchell Operating Committee, dated as of September 1, 2022 (the “September 1 Operating Committee Written Consent”). Sellers hereby represent and warrant that the September 1 Operating Committee Written Consent has been duly adopted, and is valid and in full force and effect, and has not been revoked, revised, superseded or otherwise modified.

g.Section 1.3(b)(i) of the SPA is hereby amended to add the following subsection (I):

“(I) (x) duly adopted resolutions of the Operating Committee, effective upon or prior to the Closing, in the form attached as Annex B to that certain First Amendment to this Agreement, dated as of September 29, 2022, with such modifications as Purchaser and Sellers may mutually agree, and (y) duly adopted Written Consent Action of the Mitchell Operating Committee, dated as of September 1, 2022, which resolutions and written consent shall be valid and in full force and effect and shall not have been revoked, revised, superseded or otherwise modified, in each case, as of the Closing.”
4.Modification of Conditions; Limited Waiver; Timing of Closing
a.Notwithstanding the requirements of Section 7.1(b) of the SPA, the condition set forth in Section 7.1(b) of the SPA with respect to the Required Regulatory Approval consisting of the approval of FERC under Section 203 of the FPA (the “Section 203 Approval”) shall be deemed fulfilled only if the Section 203 Approval has been duly obtained and is a Final Order that is not subject to rehearing request or appeal (including by judicial review) as a result of any Action by the KPSC; provided, that the Section 203 Approval shall only be deemed to not be subject to rehearing request or appeal (including by judicial review) as a result of Action by the KPSC at 11:59 p.m. Eastern Time on the 30th day following the date on which the Section 203 Approval became a Final Order if KPSC has not filed or otherwise commenced any Action with respect to an appeal or rehearing of the Section 203 Approval with FERC by such 30th day; provided, further, that if the KPSC files or otherwise commences an Action with respect to an appeal or rehearing of the Section 203 Approval with FERC prior to the Closing, then the condition set forth in Section 7.1(b) of the SPA with respect to the Section 203 Approval shall be deemed fulfilled only upon the later of: (1) the Section 203 Approval being a Final Order no longer subject to rehearing request or appeal (including by judicial review) as a result of Action by the KPSC; (2) 31 days after FERC issues a substantive order on the KPSC’s request for rehearing and such order is reasonably acceptable to Purchaser and Sellers; and (3)



completion of any judicial review of an Action by the KPSC, timely filed in accordance with Section 313 of the Federal Power Act.

b.In accordance with Section 10.2 of the SPA, subject to Section 4(d) of this Amendment and further subject to and effective upon the fulfillment of the condition set forth in Section 7.1(b) of the SPA, as amended by Section 4(a) of this Amendment, the Parties hereby waive the following conditions and obligations:

i.The obligation of Sellers set forth in Section 1.3(b)(i)(E) of the SPA to deliver or cause to be delivered, at or prior to the Closing, each of the Mitchell Plant Ownership Agreement and the Mitchell Plant O&M Agreement;
ii.The condition set forth in Section 7.1(d) (Mitchell Plant Approvals) of the SPA, to the extent remaining unfulfilled; and
iii.All obligations of each of the Parties under the SPA (whether to be performed prior to, on or after the date of this Amendment) to pursue or obtain (or otherwise cooperate in pursuing or obtaining) the Mitchell Plant Approvals or to execute and deliver the Mitchell Plant Ownership Agreement and the Mitchell Plant O&M Agreement at or prior to the Closing.
c.The Parties hereby agree that, subject to and effective upon the fulfillment of the condition set forth in Section 7.1(b) of the SPA in accordance with Sections 4(a) and 4(d) of this Amendment in the case of clauses (ii) and (iii) of this Section 4(c), notwithstanding anything to the contrary contained in the SPA, (i) the Transaction Commitments, (ii) the failure to execute and deliver the Mitchell Plant Ownership Agreement or the Mitchell Plant O&M Agreement and (iii) any failure to obtain the Mitchell Plant Approvals or any failure of the Mitchell Plant Approvals to contain the terms or conditions contemplated by the SPA, in each case, shall not be taken into account for purposes of any determination under the SPA as to whether a Burdensome Condition shall have occurred.

d.Notwithstanding anything to the contrary set forth in the foregoing provisions of this Section 4, in the event that on or after the date of this Amendment and prior to the time Section 7.1(b) of the SPA is fulfilled with respect to the Section 203 Approval in accordance with Section 4(a) of this Amendment, the KPSC commences any Action seeking to challenge, enjoin, prevent or materially alter or amend the consummation of the transactions contemplated by the SPA (including as amended by this Amendment) or seeking an Order requiring additional material Transaction Commitments (other than those contained in the KPSC Order) that would be adverse to Purchaser or any of its Affiliates, the waivers of the Purchaser set forth in Section 4(b), Section 4(c)(ii) and Section 4(c)(iii) shall not be effective or valid unless and until such Action is resolved to the reasonable satisfaction of Purchaser (as evidenced by the Purchaser in writing). For the



avoidance of doubt, in no event shall the Termination Fee be payable or Purchaser otherwise be deemed to be in breach or violation of the SPA as a result of the failure of the Closing to occur arising out of any such Action of the KPSC or any of the conditions to Closing not being satisfied as a result thereof.

e.The first sentence of Section 1.3(a) of the SPA is hereby deleted in its entirety and replaced with the following:

“(a)    The Closing shall take place (i) at the offices of Morgan, Lewis & Bockius LLP (“Morgan Lewis”), 101 Park Avenue, New York, NY 10178 at 10:00 a.m., Eastern time, on the third Business Day after the date on which all of the conditions set forth in Article VII are fulfilled or waived (other than those conditions that by their nature are to be fulfilled at the Closing, but subject to the satisfaction of such conditions at the Closing) or (ii) at such other place, time or date as may be mutually agreed upon in writing by Sellers and Purchaser (including virtually via the electronic exchange of signature pages); provided, that the Closing shall not occur prior to 12:01 a.m. Eastern Time on January 4, 2023, unless mutually agreed upon in writing by Sellers and Purchaser.”
5.Agreements with Respect to Disabled Direct Non-Covered Employees.
a.Notwithstanding the requirements of Section 5.2 of the SPA to the contrary, prior to Closing, Sellers shall identify to Purchaser in writing on a list (the “Disabled Direct Employee List”) and shall cause each Acquired Company to transfer, effective prior to the Closing, each Non-Covered Employee who has not been actively at work for at least 1,040 hours of regularly scheduled work due to disability as defined in the AEP LTD Plan (each a “Disabled Direct Non-Covered Employee”) to an Affiliate of AEP that is not an Acquired Company.

b.Notwithstanding the requirements of paragraph (a) of Section 5.3 of the SPA to the contrary, prior to Closing, Sellers shall identify to Purchaser in writing on the Disabled Direct Employee List and shall cause each Acquired Company to transfer, effective prior to the Closing, each Covered Employee who has not been actively at work for at least 1,040 hours of regularly scheduled work due to disability as defined in the AEP LTD Plan (each a “Disabled Direct Covered Employee”) to an Affiliate of AEP that is not an Acquired Company, subject to the condition precedent that the labor union representing such Disabled Direct Covered Employee has acknowledged in writing its agreement to the terms and conditions described herein that are applicable to such Disabled Direct Covered Employees (the “Labor Union Acknowledgement”). Sellers agree to use commercially reasonable efforts to obtain Labor Union Acknowledgement prior to the Closing.

c.The Disabled Direct Non-Covered Employees and the Disabled Direct Covered Employees who are transferred to an Affiliate of AEP that is not an Acquired Company shall be referred to as “Retained Disabled Employees” and shall not



constitute Continuing Non-Covered Employees or Continuing Covered Employees for purposes of the SPA.

d.Purchaser shall, or shall cause an Affiliate of Purchaser to, make a Qualifying Offer of employment to each Retained Disabled Employee as of the date, if any, such Retained Disabled Employee has been cleared to return to active employment, provided that such clearance occurs within 12 months following the Closing Date (or such longer period, if any, as may be required by applicable Law). A “Qualifying Offer” shall mean an offer of employment in a position comparable to that which such Retained Disabled Employee held immediately prior to the commencement of his or her absence from active employment.

e.Any Retained Disabled Employee who accepts a Qualifying Offer shall become an employee of Purchaser (or the applicable Affiliate of Purchaser) effective immediately upon acceptance.

f.Sellers shall retain and be solely responsible for all Liabilities arising from or relating to Sellers’ or any of its Affiliates’ identification and listing of Disabled Direct Non-Covered Employees and Disabled Direct Covered Employees included on the Disabled Direct Employee List (or the omission of any person from the Disabled Direct Employee List).

g.Each Non-Covered Employee and Covered Employee who is absent from work and receiving sick leave benefits due to an illness or injury on the Closing Date (each a “Continuing Employee on Sick Leave”) shall continue employment as a Continuing Non-Covered Employee or Continuing Covered Employee, respectively, following the Closing Date. If there is any such Continuing Employee on Sick Leave, Sellers agree to (i) amend the AEP LTD Plan to make each such Continuing Employee on Sick Leave eligible to apply for income replacement benefits under the AEP LTD Plan that is attributable to a period of disability that commenced prior to the Closing Date, and (ii) otherwise cause the AEP LTD Plan to be administered in accordance with its terms, as amended from time to time, provided that the provisions of the AEP LTD Plan that cause loss of eligibility to participate or for benefits by reason of an end of AEP employment shall not be applicable to such Continuing Employee on Sick Leave.

h.Notwithstanding anything to the contrary contained in the SPA, no liabilities retained by, transferred to or to be borne by AEP, or an Affiliate of AEP that is not an Acquired Company, with respect to benefits provided to Retained Disabled Employees or any Continuing Employee on Sick Leave shall be included in the calculation of Net Working Capital.

i.Nothing in this Section 5, expressed or implied, shall confer upon any Person (including the Disabled Direct Non-Covered Employees, Disabled Direct Covered Employees, Continuing Employees on Sick Leave or any other employees of



Sellers, Purchaser, or any of their respective Affiliates or any of their dependents, beneficiaries or alternate payees) other than the Parties any rights or remedies (including any third-party beneficiary rights, any right to employment or continued employment, or any right to any particular terms of conditions of employment or compensation or benefits for any period) of any nature or kind whatsoever, under or by reason of this Agreement or otherwise, and nothing in this Section 5 shall (i) affect the right of each of Sellers, Purchaser or their respective Affiliates to terminate the employment of any Person for any or no reason at any time, (ii) require Sellers or any of their Affiliates to continue any Seller Benefit Plan or other employee benefit plans or arrangements, (iii) prevent Sellers or any of their Affiliates from amending, modifying or terminating any Seller Benefit Plan or other employee benefit plans or arrangements, (iv) be construed as prohibiting or limiting the ability of Purchaser or any of its Affiliates to amend, modify or terminate any benefit or compensation plan, program, policy, Contract, agreement or arrangement at any time assumed, established, sponsored or maintained by any of them, or (v) be construed as an establishment of, amendment to or termination of any benefit or compensation plan, program, policy, Contract, agreement or arrangement. In addition, the provisions of this Section 5 are for the sole benefit of the Parties and are not for the benefit of any other Person, including any Disabled Direct Non-Covered Employee, Disabled Direct Covered Employee, Continuing Employee on Sick Leave, any other employee of any Sellers, Purchaser or any of their respective Affiliates (including any beneficiary or dependent thereof), or any other third party.

6.Amendment to Conner Run Indemnity.
a.Section 4.20(e) of the SPA is hereby deleted in its entirety and replaced with the following:

“(e)    Concurrently with, and conditioned upon, the occurrence of a “Specified Event” (as defined in Section 4.20(e) of the Sellers Disclosure Letter), Sellers shall cause AEP Generation Resources Inc. to enter into an indemnity agreement for the benefit of Kentucky Power on the terms described on Section 4.20(e) of the Sellers Disclosure Letter.”

b.Section 4.20(e) of the Sellers Disclosure Letter is hereby deleted in its entirety and replaced with Section 4.20(e) attached as Annex C to this Amendment.

7.Amendment to Forecasted Capital Expenditures Amount. Subject to and effective upon the 15th day following the date on which the Section 203 Approval becomes a Final Order (the “Forecast Amendment Date”), Appendix III of the SPA is hereby amended as follows:
a.Each forecasted capital expenditure line item set forth on Appendix III of the SPA for each month occurring after the month in which the Forecast Amendment Date occurs shall be replaced with the corresponding forecasted capital expenditure line item for such month set forth on Annex D to this Amendment.



b.Each forecasted capital expenditure line item amount set forth on Appendix III of the SPA for the month in which the Forecast Amendment Date occurs shall be replaced with a line item in an amount equal to: (i) the corresponding forecasted capital expenditure line item amount for the month in which the Forecast Amendment Date occurs as set forth on Appendix III of the SPA prorated based on the number of days in such month prior to the Forecast Amendment Date divided by the number of days in such month, plus (ii) the corresponding forecasted capital expenditure line item amount for the month in which the Forecast Amendment Date occurs as set forth on Annex D to this Amendment prorated based on the number of days in such month after and including the Forecast Amendment Date divided by the number of days in such month.

c.Notwithstanding anything to the contrary contained in the SPA, solely with respect to the period beginning on the Forecast Amendment Date and ending as of the Reference Time, the Capital Expenditures Amount shall not include any capital expenditure amounts with respect to such period in excess of the Forecasted Capital Expenditures Amount (after giving effect to the amendments to Appendix III set forth in Sections 7(a) and 7(b) of this Amendment) with respect to such period; provided, however, that the Capital Expenditures Amount with respect to such period shall include any capital expenditure amounts that exceed (solely to the extent of such excess) the Forecasted Capital Expenditures Amount (as in effect prior to the amendments to Appendix III set forth in Sections 7(a) and 7(b) of this Amendment) with respect to such period.

8.Consent to Purchases under Master Leases. Purchaser hereby consents to the Sellers causing Kentucky Power to purchase property, plant and equipment leased under Master Leases described in Section 4.19 of the SPA in an amount in excess of $10,000,000 but no greater than $24,000,000. Notwithstanding anything to the contrary and for the avoidance of doubt, Purchaser further agrees that all such amounts up to an aggregate amount equal to $24,000,000 shall be treated as a “Capital Expenditures Amount” for purposes of the SPA.
9.Reference to and Effect on the SPA. Except as modified by the amendments, waivers and agreements set forth herein, all of the terms, provisions and conditions precedent of the SPA shall remain in full force and effect and are hereby ratified and confirmed.
10.Governing Law. This Amendment (as well as any claim or controversy arising out of or relating to this Amendment or the transactions contemplated hereby) shall be governed by and construed in accordance with the Laws of the State of New York.
11.Waiver of Jury Trial; Submission to Jurisdiction; Other Incorporation by Reference. The provisions of Sections 10.1 (Amendment), 10.2 (Waivers and Consents), 10.3 (Notices), 10.4 (Assignment), 10.5 (No Third-Party Beneficiaries), 10.8 (Severability), 10.11 (Waiver of Jury Trial), 10.12 (Submission to Jurisdiction), 10.13 (Specific Performance) and 10.19 (Other Interpretive Matters) of the SPA are hereby incorporated by reference, mutatis mutandis, as if set forth in full herein.




12.Counterparts. This Amendment may be executed in multiple counterparts (each of which shall be deemed an original, but all of which together shall constitute one and the same instrument). Signatures to this Amendment transmitted by facsimile transmission, by electronic mail in “portable document format” (.pdf) form, or by any other electronic means intended to preserve the original graphic and pictorial appearance of a document, shall have the same effect as physical delivery of the paper document bearing the original signature.
[Signature Pages Follow]




IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed and delivered by their respective proper and duly authorized officers as of the day and year first above written.


 AMERICAN ELECTRIC POWER COMPANY, INC.
   
 By:/s/ Charles E. Zebula
  Name:Charles E. Zebula
  Title:Executive Vice President –
   Portfolio Optimization
    
 AEP TRANSMISSION COMPANY, LLC
    
 By:/s/ Charles E. Zebula
  Name:Charles E. Zebula
  Title:Vice President
    
 LIBERTY UTILITIES CO.
   
 By:/s/ Jody Allison
  Name:Jody Allison
  Title:President
   
 By:/s/ Todd Wiley
  Name:Todd Wiley
  Title:Treasurer and Secretary
   
[Signature Page to First Amendment to Stock Purchase Agreement]


ANNEX A

FERC 203 Letter

[Attached]



ANNEX B

Operating Committee Resolutions

[Attached]



ANNEX C

Section 4.20(e)
Conner Run Indemnity

On and after the occurrence of a Specified Event, AEP Generation Resources Inc. (“AEPGR”) shall indemnify, defend and hold harmless Kentucky Power from and against any and all Losses to the extent arising out of or resulting from any Environmental Claims, whether arising prior to, on or after the Specified Event, relating to or arising from Conner Run, excluding any Losses for the funding of costs by Kentucky Power under Section VI of the Joint Use Operating Agreement to the extent that AEPGR is separately funding 50% of the total costs giving rise to such funding by Kentucky Power on a pari passu basis with Kentucky Power.

If a Specified Event does not occur for any reason, including as a result of the permanent cessation of operations of the Mitchell Plant on or prior to December 31, 2028, AEPGR shall not be obligated to enter into the indemnity agreement described herein.

The indemnity agreement shall also contain customary and reasonable terms, including indemnification procedures and provisions regarding the standards and control with respect to remediation, consistent in all material respects with this schedule.
For purposes hereof:

Conner Run” means the real property and operation known as the Conner Run Fly Ash Impoundment and Dam, located in Marshall County, West Virginia, as more specifically described in the maps, boundary surveys and deeds included in Attachment A to the Joint Use Operating Agreement.

Joint Use Operating Agreement” means that certain Conner Run Impoundment Transition and Joint Use Operating Agreement, dated July 2, 2015, between Kentucky Power and Consolidation Coal Company, as in effect on October 26, 2021.

Specified Event” means the first to occur of any of the following:

(a)    the closing of any sale, assignment, transfer or conveyance of the Mitchell Interest to Wheeling on or prior to December 31, 2028; or

(b)    January 1, 2029, only if at such time (i) the Mitchell Plant or any unit thereof has not permanently ceased operations and (ii) Kentucky Power (A) no longer owns an ownership interest in the Mitchell Plant or any unit thereof or (B) has executed a binding instrument to irrevocably relinquish to Wheeling any generation entitlement and dispatch rights with respect to the Mitchell Plant or any unit thereof on and after January 1, 2029.



ANNEX D

Forecasted Capital Expenditures Amount

[Attached]



EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:
1.I have reviewed this report on Form 10-Q of American Electric Power Company, Inc.;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   October 27, 2022By:/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer


EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:
1.I have reviewed this report on Form 10-Q of AEP Transmission Company, LLC;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 27, 2022By:/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer


EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:
1.I have reviewed this report on Form 10-Q of AEP Texas Inc.;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   October 27, 2022By:/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer


EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:
1.I have reviewed this report on Form 10-Q of Appalachian Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   October 27, 2022By:/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer


EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:
1.I have reviewed this report on Form 10-Q of Indiana Michigan Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   October 27, 2022By:/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer


EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:
1.I have reviewed this report on Form 10-Q of Ohio Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   October 27, 2022By:/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer


EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:
1.I have reviewed this report on Form 10-Q of Public Service Company of Oklahoma;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   October 27, 2022By:/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer


EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:
1.I have reviewed this report on Form 10-Q of Southwestern Electric Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   October 27, 2022By:/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer


EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Julia A. Sloat, certify that:

1.I have reviewed this report on Form 10-Q of American Electric Power Company, Inc.;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   October 27, 2022By:/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer


EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Julia A. Sloat, certify that:

1.I have reviewed this report on Form 10-Q of AEP Transmission Company, LLC;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   October 27, 2022By:/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer


EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Julia A. Sloat, certify that:

1.I have reviewed this report on Form 10-Q of AEP Texas Inc.;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   October 27, 2022By:/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer


EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Julia A. Sloat, certify that:

1.I have reviewed this report on Form 10-Q of Appalachian Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   October 27, 2022By:/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer


EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Julia A. Sloat, certify that:

1.I have reviewed this report on Form 10-Q of Indiana Michigan Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   October 27, 2022By:/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer


EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Julia A. Sloat, certify that:

1.I have reviewed this report on Form 10-Q of Ohio Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   October 27, 2022By:/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer


EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Julia A. Sloat, certify that:

1.I have reviewed this report on Form 10-Q of Public Service Company of Oklahoma;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   October 27, 2022By:/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer


EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Julia A. Sloat, certify that:

1.I have reviewed this report on Form 10-Q of Southwestern Electric Power Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   October 27, 2022By:/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer


Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of American Electric Power Company, Inc. (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2022 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer


October 27, 2022

A signed original of this written statement required by Section 906 has been provided to American Electric Power Company, Inc. and will be retained by American Electric Power Company, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.



Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of AEP Transmission Company, LLC (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2022 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer


October 27, 2022

A signed original of this written statement required by Section 906 has been provided to AEP Transmission Company, LLC and will be retained by AEP Transmission Company, LLC and furnished to the Securities and Exchange Commission or its staff upon request.



Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of AEP Texas Inc. (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2022 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer


October 27, 2022

A signed original of this written statement required by Section 906 has been provided to AEP Texas Inc. and will be retained by AEP Texas Inc. and furnished to the Securities and Exchange Commission or its staff upon request.



Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of Appalachian Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2022 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer


October 27, 2022

A signed original of this written statement required by Section 906 has been provided to Appalachian Power Company and will be retained by Appalachian Power Company and furnished to the Securities and Exchange Commission or its staff upon request.



Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of Indiana Michigan Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2022 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer


October 27, 2022

A signed original of this written statement required by Section 906 has been provided to Indiana Michigan Power Company and will be retained by Indiana Michigan Power Company and furnished to the Securities and Exchange Commission or its staff upon request.



Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of Ohio Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2022 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer


October 27, 2022

A signed original of this written statement required by Section 906 has been provided to Ohio Power Company and will be retained by Ohio Power Company and furnished to the Securities and Exchange Commission or its staff upon request.



Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of Public Service Company of Oklahoma (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2022 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer


October 27, 2022

A signed original of this written statement required by Section 906 has been provided to Public Service Company of Oklahoma and will be retained by Public Service Company of Oklahoma and furnished to the Securities and Exchange Commission or its staff upon request.



Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of Southwestern Electric Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2022 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer


October 27, 2022

A signed original of this written statement required by Section 906 has been provided to Southwestern Electric Power Company and will be retained by Southwestern Electric Power Company and furnished to the Securities and Exchange Commission or its staff upon request.



Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of American Electric Power Company, Inc. (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2022 as filed with the Securities and Exchange Commission on the date hereof, I, Julia A. Sloat, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer


October 27, 2022

A signed original of this written statement required by Section 906 has been provided to American Electric Power Company, Inc. and will be retained by American Electric Power Company, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.



Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of AEP Transmission Company, LLC (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2022 as filed with the Securities and Exchange Commission on the date hereof, I, Julia A. Sloat, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer


October 27, 2022

A signed original of this written statement required by Section 906 has been provided to AEP Transmission Company, LLC and will be retained by AEP Transmission Company, LLC and furnished to the Securities and Exchange Commission or its staff upon request.



Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of AEP Texas Inc. (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2022 as filed with the Securities and Exchange Commission on the date hereof, I, Julia A. Sloat, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer


October 27, 2022

A signed original of this written statement required by Section 906 has been provided to AEP Texas Inc. and will be retained by AEP Texas Inc. and furnished to the Securities and Exchange Commission or its staff upon request.



Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of Appalachian Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2022 as filed with the Securities and Exchange Commission on the date hereof, I, Julia A. Sloat, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer


October 27, 2022

A signed original of this written statement required by Section 906 has been provided to Appalachian Power Company and will be retained by Appalachian Power Company and furnished to the Securities and Exchange Commission or its staff upon request.



Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of Indiana Michigan Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2022 as filed with the Securities and Exchange Commission on the date hereof, I, Julia A. Sloat, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer


October 27, 2022

A signed original of this written statement required by Section 906 has been provided to Indiana Michigan Power Company and will be retained by Indiana Michigan Power Company and furnished to the Securities and Exchange Commission or its staff upon request.



Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of Ohio Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2022 as filed with the Securities and Exchange Commission on the date hereof, I, Julia A. Sloat, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer


October 27, 2022

A signed original of this written statement required by Section 906 has been provided to Ohio Power Company and will be retained by Ohio Power Company and furnished to the Securities and Exchange Commission or its staff upon request.



Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of Public Service Company of Oklahoma (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2022 as filed with the Securities and Exchange Commission on the date hereof, I, Julia A. Sloat, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer


October 27, 2022

A signed original of this written statement required by Section 906 has been provided to Public Service Company of Oklahoma and will be retained by Public Service Company of Oklahoma and furnished to the Securities and Exchange Commission or its staff upon request.



Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Quarterly Report of Southwestern Electric Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended September 30, 2022 as filed with the Securities and Exchange Commission on the date hereof, I, Julia A. Sloat, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Julia A. Sloat
Julia A. Sloat
Chief Financial Officer


October 27, 2022

A signed original of this written statement required by Section 906 has been provided to Southwestern Electric Power Company and will be retained by Southwestern Electric Power Company and furnished to the Securities and Exchange Commission or its staff upon request.



Exhibit 95

MINE SAFETY INFORMATION

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

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act. DHLC received the following notices of violation and proposed assessments under the Mine Act for the quarter ended September 30, 2022:

Number of Citations for S&S Violations of Mandatory Health or Safety Standards under 104 *
Number of Orders Issued under 104(b) *
Number of Citations and Orders for Unwarrantable Failure to Comply with Mandatory Health or Safety Standards under 104(d) *
Number of Flagrant Violations under 110(b)(2) *
Number of Imminent Danger Orders Issued under 107(a) *
Total Dollar Value of Proposed Assessments **
$133 
Number of Mining-related Fatalities

*    References to sections under the Mine Act.
**     DHLC received 1 non-S&S citation during the second quarter of 2022. The proposed assessments ($133) for this citation was received during the third quarter of 2022. No citations were issued in the third quarter of 2022.

There are currently no legal actions pending before the Federal Mine Safety and Health Review Commission.