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Appalachian Power

Filed: 27 Jul 22, 7:07am
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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 June 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 OKLAHOMAOklahoma 73-0410895
1-3146 SOUTHWESTERN ELECTRIC POWER COMPANYDelaware 72-0323455
  1 Riverside Plaza,Columbus,Ohio43215-2373  
  Telephone(614)716-1000  
Securities registered pursuant to Section 12(b) of the Act:
Registrant Title of each class Trading SymbolName of Each Exchange on Which Registered
American Electric Power Company Inc. Common Stock, $6.50 par value AEPThe NASDAQ Stock Market LLC
American Electric Power Company Inc.6.125% Corporate UnitsAEPPZThe NASDAQ Stock Market LLC
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
YesxNo
Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit such files).
YesxNo
Indicate by check mark whether American Electric Power Company, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
 
Large Accelerated filerxAccelerated filerNon-accelerated filer
      
Smaller reporting companyEmerging growth company
Indicate by check mark whether AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, non-accelerated filers, smaller reporting companies, or emerging growth companies.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
 
Large Accelerated filerAccelerated filerNon-accelerated filerx
      
Smaller reporting companyEmerging growth company 
If an emerging growth company, indicate by check mark if the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).YesNox
AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.




Number of shares
of common stock
outstanding of the
Registrants as of
July 27, 2022
 
American Electric Power Company, Inc.513,733,984 
 ($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
June 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. 
TermMeaning
   
AEGCo AEP Generating Company, an AEP electric utility subsidiary.
AEP American Electric Power Company, Inc., an investor-owned electric public utility holding company which includes American Electric Power Company, Inc. (Parent) and majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit AEP Credit, Inc., a consolidated VIE of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP RenewablesA division of AEP Energy Supply, LLC that develops and/or acquires large scale renewable projects that are backed with long-term contracts with creditworthy counter parties.
AEP System American Electric Power System, an electric system, owned and operated by AEP subsidiaries.
AEP TexasAEP Texas Inc., an AEP electric utility subsidiary.
AEP Transmission Holdco AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of AEP.
AEPEPAEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, hedging activities, asset management and commercial and industrial sales in deregulated markets.
AEPROAEP 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.
AEPTCoAEP Transmission Company, LLC, a wholly-owned subsidiary of AEP Transmission Holdco, is an intermediate holding company that owns the State Transcos.
AEPTCo ParentAEP Transmission Company, LLC, the holding company of the State Transcos within the AEPTCo consolidation.
AFUDCAllowance for Equity Funds Used During Construction.
AGRAEP 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 FundingAppalachian Consumer Rate Relief Funding LLC, a wholly-owned subsidiary of APCo and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to the under-recovered Expanded Net Energy Cost deferral balance.
APSCArkansas Public Service Commission.
AROAsset Retirement Obligations.
ATMAt-the-Market
CAAClean Air Act.
CCRCoal Combustion Residual.
CLECOCentral Louisiana Electric Company, a nonaffiliated utility company.
CO2
 Carbon dioxide and other greenhouse gases.
Cook Plant Donald C. Cook Nuclear Plant, a two-unit, 2,296 MW nuclear plant owned by I&M.
COVID-19Coronavirus 2019, a highly infectious respiratory disease. In March 2020, the World Health Organization declared COVID-19 a worldwide pandemic.
CSAPRCross-State Air Pollution Rule.
i



TermMeaning
   
CWIP Construction Work in Progress.
DCC FuelDCC Fuel X, 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.
EISEnergy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated VIE of AEP.
ELGEffluent Limitation Guidelines.
Energy SupplyAEP Energy Supply LLC, a nonregulated holding company for AEP’s competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP.
Equity UnitsAEP’s Equity Units issued in August 2020 and March 2019.
ERCOT Electric Reliability Council of Texas regional transmission organization.
ETTElectric Transmission Texas, LLC, an equity interest joint venture between AEP Transmission Holdco and Berkshire Hathaway Energy Company formed to own and operate electric transmission facilities in ERCOT.
Excess ADITExcess accumulated deferred income taxes.
FACFuel Adjustment Clause.
FASB Financial Accounting Standards Board.
Federal EPAUnited States Environmental Protection Agency.
FERC Federal Energy Regulatory Commission.
FGD Flue Gas Desulfurization or scrubbers.
FIPFederal Implementation Plan.
FTR Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP Accounting Principles Generally Accepted in the United States of America.
I&M Indiana Michigan Power Company, an AEP electric utility subsidiary.
IRS Internal Revenue Service.
IURCIndiana Utility Regulatory Commission.
KGPCoKingsport Power Company, an AEP electric utility subsidiary.
KPCo Kentucky Power Company, an AEP electric utility subsidiary.
KPSCKentucky Public Service Commission.
KTCoAEP Kentucky Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.
KWhKilowatt-hour.
LPSC Louisiana Public Service Commission.
MATSMercury and Air Toxic Standards.
MaverickMaverick, part of the North Central Wind Energy Facilities, consists of 287 MWs of wind generation in Oklahoma.
MISO Midcontinent Independent System Operator.
Mitchell PlantA two unit, 1,560 MW coal-fired power plant located in Moundsville, West Virginia. The plant is jointly owned by KPCo and WPCo.
MMBtu Million British Thermal Units.
MPSCMichigan Public Service Commission.
ii



TermMeaning
   
MTM Mark-to-Market.
MW Megawatt.
MWh Megawatt-hour.
NAAQSNational Ambient Air Quality Standards.
Nonutility Money Pool Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
NCWFNorth Central Wind Energy Facilities, a joint PSO and SWEPCo project, which includes three Oklahoma wind facilities totaling approximately 1,484 MWs of wind generation.
NOLCNet Operating Loss Carryforwards.
NOx
Nitrogen oxide.
NSR New Source Review.
OCC Corporation Commission of the State of Oklahoma.
OPCo Ohio Power Company, an AEP electric utility subsidiary.
OPEB Other Postretirement Benefits.
OTC Over-the-counter.
OVEC Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
ParentAmerican Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.
PJM Pennsylvania – New Jersey – Maryland regional transmission organization.
PM Particulate Matter.
PPAPurchase Power and Sale Agreement.
PSO Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PTCProduction Tax Credits.
PUCO Public Utilities Commission of Ohio.
PUCT Public Utility Commission of Texas.
Registrant Subsidiaries AEP subsidiaries which are SEC registrants: AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
RegistrantsSEC registrants: AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
Restoration FundingAEP Texas Restoration Funding LLC, a wholly-owned subsidiary of AEP Texas and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to storm restoration in Texas primarily caused by Hurricane Harvey.
Risk Management Contracts Trading and non-trading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport PlantA 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.
ROEReturn on Equity.
RPMReliability Pricing Model.
RTO Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine Sabine Mining Company, a lignite mining company that is a consolidated VIE for AEP and SWEPCo.
SECU.S. Securities and Exchange Commission.
iii



TermMeaning
   
Sempra Renewables LLCSempra Renewables LLC, acquired in April 2019, consists of 724 MWs of wind generation and battery assets in the United States.
SIPState Implementation Plan.
SNF Spent Nuclear Fuel.
SO2
 Sulfur dioxide.
SPP Southwest Power Pool regional transmission organization.
State TranscosAEPTCo’s seven wholly-owned, FERC regulated, transmission only electric utilities, which are geographically aligned with AEP’s existing utility operating companies.
SundanceSundance, acquired in April 2021 as part of the North Central Wind Energy Facilities, consists of 199 MWs of wind generation in Oklahoma.
SWEPCo Southwestern Electric Power Company, an AEP electric utility subsidiary.
Tax ReformOn December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal Revenue Code of 1986, including a reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018.
Transition Funding AEP Texas Central Transition Funding III LLC, a wholly-owned subsidiary of TCC and consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation.
Transource EnergyTransource Energy, LLC, a consolidated VIE formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates.
TraverseTraverse, part of the North Central Wind Energy Facilities, consists of 998 MWs of wind generation in Oklahoma.
Turk Plant John W. Turk, Jr. Plant, a 650 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.
Utility Money Pool Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
VIEVariable Interest Entity.
Virginia SCC Virginia State Corporation Commission.
WPCo Wheeling Power Company, an AEP electric utility subsidiary.
WVPSCPublic Service Commission of West Virginia.
iv



FORWARD-LOOKING INFORMATION

This report made by the Registrants contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.  Many forward-looking statements appear in “Part I – Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this quarterly report, but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook.  These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected.  Forward-looking statements in this document are presented as of the date of this document.  Except to the extent required by applicable law, management undertakes no obligation to update or revise any forward-looking statement.  Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:
Changes in economic conditions, electric market demand and demographic patterns in AEP service territories.
The impact of pandemics, including COVID-19, 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 risks associated with fuels used before, during and after the generation of electricity, including coal ash and nuclear fuel.
Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance.
Resolution of litigation.
The ability to constrain operation and maintenance costs.
Prices and demand for power generated and sold at wholesale.
Changes in technology, particularly with respect to energy storage and new, developing, alternative or distributed sources of generation.
The ability to recover through rates any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives.
v



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.
vi





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 second quarter of 2022 increased by 3.5% from the second quarter of 2021. Weather-normalized residential sales increased by 1.2% in the second quarter of 2022 from the second quarter of 2021. AEP’s second quarter 2022 industrial sales volumes increased by 5% compared to the second quarter of 2021. The increase in industrial sales was spread across many industries. Weather-normalized commercial sales increased 4.1% in the second quarter of 2022 from the second quarter of 2021.

AEP’s weather-normalized retail sales volumes for the six months ended June 30, 2022 increased by 3.3% compared to the six months ended June 30, 2021. Weather-normalized residential sales increased by 1% for the six months ended June 30, 2022 compared to the six months ended June 30, 2021. AEP’s industrial sales volumes for the six months ended June 30, 2022 increased by 5.3% compared to the six months ended June 30, 2021. The increase in industrial sales was spread across many industries. Weather-normalized commercial sales increased 4.1% for the six months ended June 30, 2022 compared to the six months ended June 30, 2021.

COVID-19

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

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

1



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

In March 2021, the Virginia SCC issued an order confirming certain decisions from the November 2020 order and rejecting the various requests for reconsideration from APCo and an intervenor. In March 2021, APCo filed a notice of appeal of the reconsideration order with the Virginia Supreme Court. In September 2021, APCo submitted its brief before the Virginia Supreme Court. The brief was in alignment with the previous items of appeal filed by APCo in March 2021. 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 and APCo is currently awaiting the Virginia Supreme Court’s decision.

APCo ultimately seeks an increase in base rates through its appeal to the Virginia Supreme Court. Among other issues, this appeal includes APCo’s request for proper treatment of the closed coal-fired plant assets in APCo’s 2017-2019 triennial period, reducing APCo’s earnings below the bottom of its authorized ROE band. If APCo’s appeal regarding treatment of the closed coal plants is granted by the Virginia Supreme Court, it could initially reduce future net income and impact financial condition as a consequence of expensing the closed coal-fired plant regulatory asset established as a result of the Virginia SCC’s decision in the 2017-2019 Triennial Review. A Virginia Supreme Court decision in favor of APCo’s original expensing of the closed coal-fired plant asset balances would likely result in a remand to the Virginia SCC. Upon a subsequent Virginia SCC order, the initial negative impact for the write-off of the closed coal-fired plant asset balances could potentially be offset by an increase in base rates for earning below APCo’s 2017-2019 authorized ROE band.

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

In March 2021, the Texas Supreme Court issued an opinion reversing the July 2018 judgment of the Texas Third Court of Appeals and agreeing with the PUCT’s judgment affirming the prudence of the Turk Plant. In addition, the Texas Supreme Court remanded the AFUDC dispute back to the Texas Third Court of Appeals. In August 2021, the Texas Third Court of Appeals reversed the Texas District Court affirming the PUCT’s order on AFUDC, concluding that the language of the PUCT’s original 2008 order intended to include AFUDC in the Texas jurisdictional capital cost cap, and remanded the case to the PUCT for future proceedings. SWEPCo disagrees with the Court of Appeals decision and submitted a Petition for Review with the Texas Supreme Court in November 2021. In June 2022, SWEPCo and the PUCT filed replies to the responses of the Petition for Review.

2



If SWEPCo is ultimately unable to recover capitalized Turk Plant costs including 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 June 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 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
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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 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 of June 30, 2022, PSO and SWEPCo have deferred regulatory assets of $684 million and $375 million, respectively, relating to natural gas expenses and purchases of electricity incurred from February 9, 2021, to February 20, 2021, as a result of severe winter weather. SWEPCo’s deferred regulatory asset consists of $95 million, $134 million and $146 million related to the Arkansas, Louisiana and Texas jurisdictions, respectively.

In April 2021, the OCC approved a waiver for PSO allowing the deferral of the extraordinary fuel and purchases of electricity, including a carrying charge at an interim rate of 0.75%, over a longer time period than what the FAC traditionally allows. In January 2022, PSO, OCC staff and certain intervenors filed a joint stipulation and settlement agreement with the OCC to approve PSO’s securitization of the extraordinary fuel and purchases of electricity. The agreement includes a determination that all of PSO’s extraordinary fuel and purchases of electricity were prudent and reasonable and a 0.75% carrying charge, subject to true-up based on actual financing costs. In February 2022, the OCC approved the joint
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stipulation and settlement agreement in its financing order. In May 2022, the Supreme Court of Oklahoma approved the issuance of the securitization bonds. PSO expects to complete the securitization process in 2022, subject to market conditions.

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

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

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

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

AEP transitioned to stand-alone treatment of NOLC in its PJM and SPP transmission formula rates beginning with 2022 projected transmission revenue requirements and 2021 true-up to actual transmission revenue requirements, and provided notice of this change in informational filings made with the FERC. Stand-alone treatment of the NOLCs for transmission formula rates increased the 2021 and 2022 annual revenue requirements by $78 million and $60 million, respectively. Through the second 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 is not yet 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”. Stand-alone treatment of NOLCs in transmission formula rates is consistent with AEP’s recent 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.

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.
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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

(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%
KGPCoTennesseeNovember 20216.9 10.2%7.35%

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 June 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 June 30, 2022, SWEPCo had a net under-recovered fuel balance of $187 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 November 2021, the LPSC issued a directive which deferred the issues regarding modification of the level and timing of recovery of the Dolet Hills Power Station from SWEPCo’s pending rate case to a separate existing docket. In addition, the recovery of the deferred fuel costs are planned to be addressed.

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.

If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
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Pirkey Power Plant and Related Fuel Operations

In 2020, management announced plans to retire the Pirkey Power Plant in 2023. The Pirkey Power Plant non-fuel costs are recoverable by SWEPCo through base rates and fuel costs are recovered through active fuel clauses and are subject to prudency determinations by the various commissions. As of June 30, 2022, SWEPCo’s share of the net investment in the Pirkey Power Plant was $204 million, including CWIP, before cost of removal. Sabine is a mining operator providing mining services to the Pirkey Power Plant. Under the provisions of the mining agreement, SWEPCo is required to pay, as part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. SWEPCo expects fuel deliveries, including billings of all fixed and operating costs, from Sabine to cease during the first quarter of 2023. Under the fuel agreements, SWEPCo’s fuel inventory and unbilled fuel costs from mining related activities were $79 million as of June 30, 2022. As of June 30, 2022, SWEPCo had a net under-recovered fuel balance of $187 million, inclusive of costs related to the Pirkey Power 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 Power 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. 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. Regarding AEP’s investment in Flat Ridge 2 Wind LLC, 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. See “Impairments” section of Note 6 for additional information. As of June 30, 2022, the competitive contracted renewable portfolio assets totaled 1.6 gigawatts, inclusive of 235 MWs related to Flat Ridge 2, 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 $256 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 June 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.

Regulated Renewable Generation 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. Recovery of the Arkansas portion of the NCWF revenue requirement is requested in
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SWEPCo’s pending 2021 Arkansas Base Rate Case. The table below provides a summary of the facilities as of June 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 80 %998 

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

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

In November 2021, PSO issued requests for proposals to acquire up to 2,800 MWs of wind and up to 1,350 MWs of solar generation resources. The wind and solar generation projects would be subject to regulatory approval.

In December 2021 and January 2022, APCo filed a petition 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 third quarter of 2022 related to the remaining items in APCo’s January 2022 petition. 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 addition, APCo has issued requests for proposal for the following renewable generation resources:

Issuance DateGeneration TypeOwned/
PPA
Generating Capacity
(in MWs)
January 2022WindOwned1,000 
January 2022SolarOwned100 
February 2022SolarOwned150 
June 2022Solar/WindPPA100 

In March 2022, I&M issued requests for proposals to acquire or contract for resources pursuant to meeting I&M’s Integrated Resource Plans, which includes approximately 800 MWs of wind generation resources, 500 MWs of solar generation resources and other supplemental capacity resources, including, but not limited to, standalone storage, emerging technologies, thermal and other capacity resources. These projects would be subject to regulatory approval.

In May 2022, SWEPCo submitted filings before the APSC, LPSC and PUCT requesting approval to acquire three renewable energy projects totaling 999 MWs. The projects are comprised of two wind facilities, totaling 799 MWs, and one solar facility, totaling 200 MWs. One of the wind facilities, totaling 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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Disposition of KPCo and KTCo

In October 2021, AEP entered into a Stock Purchase Agreement to sell KPCo and KTCo to Liberty Utilities Co., a subsidiary of Algonquin Power & Utilities Corp. (Liberty), for approximately a $2.85 billion enterprise value. In May 2022, the KPSC approved the transfer of KPCo to Liberty subject to certain conditions contingent upon the closing of the sale. Clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and clearance from the Committee on Foreign Investment in the United States has also been received. The sale remains subject to FERC approval and to the satisfaction or waiver of the Stock Purchase Agreement condition precedent requiring the issuance of orders by the KPSC, WVPSC and FERC approving a new proposed Mitchell Plant Operations and Maintenance Agreement and Mitchell Plant Ownership Agreement between KPCo and WPCo.

Mitchell Plant Operations and Maintenance Agreement and Ownership Agreement

KPCo currently operates and owns a 50% undivided interest in the 1,560 MW coal-fired Mitchell Plant with the remaining 50% owned by WPCo. As of June 30, 2022, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $584 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 approved agreements that differ in material respects. In July 2022, KPCo and WPCo made filings with the KPSC and WVPSC, respectively, informing the respective commissions that until consistent new agreements are approved by the two state jurisdictions and the FERC, the new proposed agreements cannot be entered into by KPCo and WPCo. The existing Mitchell Plant agreement remains in place in accordance with its terms as the document governing operations and the contractual relationship between the two owners, including CCR and ELG investments in accordance with each state commission’s directives.

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 on the matter in the third 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 fifty percent. As a result of the conditions imposed by the KPSC, in the second quarter of 2022, AEP recorded a $69 million loss on the expected sale of the Kentucky Operations in accordance with the accounting guidance for Fair Value Measurement. AEP expects cash proceeds, net of taxes and transaction fees, from the sale of approximately $1.4 billion.

Subject to receipt of FERC authorization under Section 203 of the Federal Power Act and satisfaction or waiver of certain conditions precedent in the Stock Purchase Agreement, including the approval of the proposed new Mitchell agreements mentioned above, the sale is expected to close in the third quarter of 2022 with Liberty acquiring the assets and assuming the liabilities of KPCo and KTCo, excluding pension and other post-retirement benefit plan assets and liabilities. AEP expects to provide customary transition services to Liberty for a period of time after closing of the transaction. AEP plans to use the proceeds to eliminate forecasted equity needs in 2022 as the company invests in regulated renewables, transmission and other 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. The IURC order approved a settlement agreement addressing the future use of Rockport Plant, Unit 2 as a capacity resource and associated adjustments to I&M’s Indiana retail rates, along with certain other matters. Management believes its financial statements appropriately reflect the resolution of the litigation.

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

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 and briefing on the motion to dismiss has been completed. AEP will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.


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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 has 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 and briefing on the motion to dismiss has been completed. 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 stay 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 benefits to AEP from the passage of HB 6 and documents relating to AEP’s financial processes and controls. AEP is cooperating fully with the SEC’s subpoena. Although the outcome of the SEC’s investigation cannot be predicted, management does not believe the results of this inquiry will have a material impact on financial condition, results of operations or cash flows.
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ENVIRONMENTAL ISSUES

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

AEP is engaged in litigation about environmental issues, was notified of potential responsibility for the clean-up of contaminated sites and incurred costs for disposal of SNF and future decommissioning of the nuclear units.  Management is engaged in the development of possible future requirements including the items discussed below.  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 June 30, 2022, the AEP System owned generating capacity of approximately 25,800 MWs, of which approximately 11,900 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 $325 million to $550 million through 2028.

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

Obligations under the New Source Review Litigation Consent Decree

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


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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 February 2021, AEP announced new intermediate and long-term CO2 emission reduction goals, based on the output of the company’s integrated resource plans, which take into account economics, customer demand, grid reliability and resiliency, regulations and the company’s current business strategy. The intermediate goal is an 80% reduction from 2000 CO2 emission levels from AEP generating facilities by 2030; the long-term goal is net-zero CO2 emissions from AEP generating facilities by 2050. AEP’s total estimated CO2 emissions in 2021 were approximately 50 million metric tons, a 70% reduction from AEP’s 2000 CO2 emissions. AEP has made significant progress in reducing CO2 emissions from its power generation fleet and expects its emissions to continue to decline. Technological advances, including energy storage, will determine how quickly AEP can achieve zero emissions while continuing to provide reliable, affordable power for customers.

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

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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$223.1 2028
APCoAmos2,9302,106.5 2040
APCoMountaineer1,320972.2 2040
I&MRockport Plant, Unit 1655476.6 (b)2028
KPCoMitchell Plant780584.2 2040
SWEPCoFlint Creek Plant258262.2 2038
WPCoMitchell Plant780587.9 2040

(a)Net book value before cost of removal including CWIP and inventory.
(b)Amount includes a $159 million regulatory asset related to the retired Tanners Creek Plant. The IURC and MPSC authorized recovery of the Tanners Creek Plant regulatory asset over the useful life of Rockport Plant, Unit 1 in 2015 and 2014, respectively.

In addition, AGR owns Cardinal Plant, Unit 1 a competitive generation unit. A nonaffiliated electric cooperative owns Cardinal Plant, Unit 2 and Unit 3 and operates all three units at the Cardinal Plant. The nonaffiliate filed an application for additional time to develop alternative disposal capacity for the Cardinal Plant. As of June 30, 2022, the net book value of Cardinal Plant, Unit 1, including materials and supplies and CWIP, was approximately $48 million. In the second quarter of 2022, AGR filed and FERC approved an application requesting authorization of the sale of Cardinal Plant, Unit 1 to the nonaffiliated electric cooperative previously discussed. The sale is expected to close in the third quarter of 2022 with AGR concurrently executing a PPA with the nonaffiliated electric cooperative for rights to power and capacity through 2028 and retaining certain obligations related to environmental remediation. The transaction is not expected to have a material effect on AEP’s financial statements.

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
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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 impoundments in Kentucky, Ohio, Virginia and West Virginia that have already been closed in accordance with state law programs or could require AEP to incur costs related to CCR impoundments at various 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 related to competitive units or in regulated jurisdictions without providing similar assurances of cost recovery, it would impose significant additional operating costs on AEP, which could reduce future net income and cash flows and impact financial condition. Management will continue to participate in rulemaking activities and make adjustments based on new federal and state requirements affecting its ash disposal units.

The second option to obtain an extension of the April 11, 2021 deadline to cease operation of unlined impoundments allows a generating facility to continue operating its existing impoundments without developing alternative CCR disposal, provided the facility commits to cease combustion of coal by a date certain. Under this option, a generating facility would have until October 17, 2023 to cease coal-fired operations and to close CCR storage ponds 40 acres or less in size, or through October 17, 2028 for facilities with CCR storage ponds greater than 40 acres in size. Pursuant to this option, AEP informed the Federal EPA of its intent to retire the Pirkey Power 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 Power Plant580$75.1 $129.3 2023(b)
SWEPCoWelsh Plants, Units 1 and 31,053449.4 65.9 2028(c)(d)

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

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
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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. 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 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 January 2022, the U.S. Supreme Court announced that it would hear an appeal related to the scope of “waters of the United States,” specifically whether 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 June 30, 2022, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $584 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’s order further states WPCo will not share capacity and energy from the plant with KPCo customers if those customers are not paying for ELG compliance costs, or for any new capital investment or continuing operations costs incurred, to allow the plant to operate beyond 2028 or prevent downgrades prior to 2028. The WVPSC also ordered that WPCo will be given the opportunity to recover, from its customers, the new capital and operating costs arising solely from the WVPSC's directive to operate the plant beyond 2028 if the WVPSC finds that the costs are reasonably and prudently incurred.


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Amos and Mountaineer Plants (Applies to AEP and APCo)

In December 2020, APCo submitted filings with the Virginia SCC and WVPSC requesting regulatory approvals necessary to implement CCR and ELG compliance plans and seek recovery of the estimated $240 million investment for the Amos and Mountaineer plants. In August 2021, the Virginia SCC issued an order approving APCo’s request to construct CCR-related investments at the Amos and Mountaineer Plants and approved recovery of CCR-related other operation and maintenance expenses and investments through an active rider. The order denied APCo’s request to construct the ELG investments and denied recovery of previously incurred ELG costs. In March 2022, APCo refiled for approval of the ELG investments and previously incurred ELG costs. A hearing is scheduled to take place in September 2022 and an order is anticipated 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 the 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 October 2021 order further states that APCo will not share capacity and energy from the plants with customers from Virginia if those customers are not paying for ELG compliance costs, or for any new capital investment or continuing operations costs incurred, to allow the plants to operate beyond 2028 or prevent downgrades prior to 2028. The WVPSC also ordered that APCo will be given the opportunity to recover, from West Virginia customers, the new capital and operating costs arising solely from the WVPSC's directive to operate the plants beyond 2028 if the WVPSC finds that the costs are reasonably and prudently incurred.

APCo expects total Amos and Mountaineer Plant ELG investment, excluding AFUDC, to be approximately $197 million. As of June 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 $56 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 June 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$151.3 $136.9 2026(c)$14.9 
SWEPCoDolet Hills Power Station— 52.8 2021(d)— 
SWEPCoPirkey Power Plant75.1 129.3 2023(e)13.2 
SWEPCoWelsh Plant, Units 1 and 3449.4 65.9 2028(f)(g)38.4 
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 Power 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.

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The following table presents Earnings (Loss) Attributable to AEP Common Shareholders by segment:
Three Months EndedSix Months Ended
June 30,June 30,
 2022202120222021
 (in millions)
Vertically Integrated Utilities$301.2 $228.2 $599.4 $498.6 
Transmission and Distribution Utilities164.8 153.7 317.6 268.1 
AEP Transmission Holdco141.8 168.7 314.9 340.7 
Generation & Marketing72.6 52.4 186.8 89.0 
Corporate and Other(155.9)(24.8)(179.5)(43.2)
Earnings Attributable to AEP Common Shareholders$524.5 $578.2 $1,239.2 $1,153.2 

AEP CONSOLIDATED

Second Quarter of 2022 Compared to Second Quarter of 2021

Earnings Attributable to AEP Common Shareholders decreased from $578 million in 2021 to $525 million in 2022 primarily due to:

An impairment of AEP’s equity investment in Flat Ridge 2.
A loss related to the expected sale of the Kentucky Operations.
Unrealized losses on AEP’s investment in ChargePoint. See “Warrants Held in Investee” section of Note 9 for additional information.

This decrease was 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.

Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021

Earnings Attributable to AEP Common Shareholders increased from $1,153 million in 2021 to $1,239 million in 2022 primarily due to:

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.

These increases were partially offset by:

An impairment of AEP’s equity investment in Flat Ridge 2.
A loss related to the expected sale of the Kentucky Operations.
Unrealized losses on AEP’s investment in ChargePoint.

AEP’s results of operations by operating segment are discussed below.
21



VERTICALLY INTEGRATED UTILITIES
Three Months EndedSix Months Ended
June 30,June 30,
 Vertically Integrated Utilities2022202120222021
 (in millions)
Revenues$2,648.5 $2,260.6 $5,335.9 $4,797.9 
Fuel and Purchased Electricity837.8 650.4 1,703.9 1,509.4 
Gross Margin1,810.7 1,610.2 3,632.0 3,288.5 
Other Operation and Maintenance779.9 703.5 1,549.1 1,443.7 
Depreciation and Amortization504.4 433.8 1,004.4 865.9 
Taxes Other Than Income Taxes128.6 128.0 253.8 251.5 
Operating Income397.8 344.9 824.7 727.4 
Other Income10.7 5.1 15.9 5.8 
Allowance for Equity Funds Used During Construction6.3 10.8 14.4 20.7 
Non-Service Cost Components of Net Periodic Benefit Cost27.4 17.0 55.0 34.0 
Interest Expense(157.3)(141.6)(308.3)(281.2)
Income Before Income Tax Expense (Benefit) and Equity Earnings284.9 236.2 601.7 506.7 
Income Tax Expense (Benefit)(18.0)8.2 (0.1)8.0 
Equity Earnings of Unconsolidated Subsidiary0.4 0.8 0.7 1.5 
Net Income303.3 228.8 602.5 500.2 
Net Income Attributable to Noncontrolling Interests2.1 0.6 3.1 1.6 
Earnings Attributable to AEP Common Shareholders$301.2 $228.2 $599.4 $498.6 

Summary of KWh Energy Sales for Vertically Integrated Utilities
Three Months EndedSix Months Ended
June 30,June 30,
2022202120222021
 (in millions of KWhs)
Retail:    
Residential7,039 6,525 16,264 16,006 
Commercial5,911 5,670 11,429 10,928 
Industrial8,906 8,611 17,068 16,313 
Miscellaneous578 549 1,122 1,068 
Total Retail22,434 21,355 45,883 44,315 
Wholesale (a)3,660 4,487 8,134 9,129 
Total KWhs26,094 25,842 54,017 53,444 

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



22



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 EndedSix Months Ended
June 30,June 30,
2022202120222021
 (in degree days)
Eastern Region    
Actual Heating (a)
152 170 1,742 1,709 
Normal Heating (b)
140 138 1,744 1,738 
Actual Cooling (c)
393 359 395 362 
Normal Cooling (b)
333 339 337 343 
Western Region    
Actual Heating (a)
15 35 930 993 
Normal Heating (b)
35 34 906 900 
Actual Cooling (c)
885 652 905 678 
Normal Cooling (b)
693 699 721 727 

(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.

23



Second Quarter of 2022 Compared to Second Quarter of 2021
Reconciliation of Second Quarter of 2021 to Second Quarter of 2022
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
 
Second Quarter of 2021$228.2 
  
Changes in Gross Margin: 
Retail Margins172.7 
Margins from Off-system Sales(10.1)
Transmission Revenues31.0 
Other Revenues6.9 
Total Change in Gross Margin200.5 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(76.4)
Depreciation and Amortization(70.6)
Taxes Other Than Income Taxes(0.6)
Other Income5.6 
Allowance for Equity Funds Used During Construction(4.5)
Non-Service Cost Components of Net Periodic Pension Cost10.4 
Interest Expense(15.7)
Total Change in Expenses and Other(151.8)
  
Income Tax Expense26.2 
Equity Earnings of Unconsolidated Subsidiary(0.4)
Net Income Attributable to Noncontrolling Interests(1.5)
Second Quarter of 2022$301.2 

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 $173 million primarily due to the following:
A $43 million increase at APCo and WPCo due to rider revenues in Virginia and West Virginia. This increase was partially offset in other expense items below.
A $32 million increase in weather-related usage primarily in the residential class.
A $30 million increase at SWEPCo primarily due to a base rate revenue increase in Texas and rider increases in all retail jurisdictions. These increases were partially offset in other expense items below.
A $21 million increase at PSO due to a $13 million increase in base rate revenues and an $8 million increase in rider revenues. These increases were partially offset in other expense items below.
A $15 million increase at SWEPCo in municipal and cooperative revenues primarily due to SPP billing adjustments from the February 2021 severe winter weather event.
A $10 million increase in weather-normalized retail margins primarily in the residential class partially offset by a decrease in the industrial class.
An $8 million increase due to lower customer refunds related to Tax Reform primarily at APCo and WPCo. This increase was partially offset in Income Tax Expense below.
An $8 million increase at I&M primarily due to an increase in rider revenues offset by lower wholesale true-ups. This increase was partially offset in other expense items below.
These increases were partially offset by:
24



An $11 million increase in fuel expense at PSO due to NCWF PTC benefits provided to customers. This increase in fuel expense was partially offset in Income Tax Expense below.
Margins from Off-system Sales decreased $10 million primarily due to the following:
A $5 million decrease at KPCo due to a change in the OSS sharing arrangement in Kentucky.
A $4 million decrease due to SPP billing adjustments at SWEPCo related to the February 2021 severe winter weather event.
Transmission Revenues increased $31 million primarily due to the following:
A $17 million increase in continued investment in transmission assets and increased load.
A $14 million increase in formula rate true-up activity.
Other Revenues increased $7 million primarily due to the following:
A $4 million increase in business development revenue primarily at APCo. This increase was partially offset in Other Operation and Maintenance expenses below.

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

Other Operation and Maintenance expenses increased $76 million primarily due to the following:
A $43 million increase in generation expenses primarily due to outages and maintenance at APCo, I&M and PSO.
A $34 million increase in PJM transmission services. This increase was partially offset in Retail Margins above.
A $12 million increase in employee-related expenses.
A $9 million increase in storm restoration expenses across all operating companies.
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.
Depreciation and Amortization expenses increased $71 million primarily due to the following:
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.
A $23 million increase due to a higher depreciable base at APCo, I&M and SWEPCo and the implementation of increased Texas depreciation rates at SWEPCo.
Other Income increased $6 million primarily due to carrying charges on regulatory assets at SWEPCo resulting from the February 2021 severe winter weather event.
Allowance for Equity Funds Used During Construction decreased $5 million primarily due to a lower AFUDC base primarily at APCo and a decrease in AFUDC equity rates.
Non-Service Cost Components of Net Periodic Benefit Cost decreased $10 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.
Interest Expense increased $16 million primarily due to higher long-term debt balances primarily at PSO.
Income Tax Expense decreased $26 million primarily due to an increase in PTCs, a decrease in state income taxes and an increase in amortization of Excess ADIT, partially offset by an increase in pretax book income. The increase in amortization of Excess ADIT was partially offset in Retail Margins above.

25



Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021
Reconciliation of Six Months Ended June 30, 2021 to Six Months Ended June 30, 2022
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
 
Six Months Ended June 30, 2021$498.6 
  
Changes in Gross Margin: 
Retail Margins311.9 
Margins from Off-system Sales(27.2)
Transmission Revenues45.0 
Other Revenues13.8 
Total Change in Gross Margin343.5 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(105.4)
Depreciation and Amortization(138.5)
Taxes Other Than Income Taxes(2.3)
Other Income10.1 
Allowance for Equity Funds Used During Construction(6.3)
Non-Service Cost Components of Net Periodic Pension Cost21.0 
Interest Expense(27.1)
Total Change in Expenses and Other(248.5)
  
Income Tax Expense8.1 
Equity Earnings of Unconsolidated Subsidiary(0.8)
Net Income Attributable to Noncontrolling Interests(1.5)
Six Months Ended June 30, 2022$599.4 

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 $312 million primarily due to the following:
A $91 million increase at APCo and WPCo due to rider revenue in Virginia and West Virginia. This increase was partially offset in other expense items below.
A $48 million increase at PSO due to a $25 million increase in base rate revenues and a $23 million increase in rider revenues. These increases were partially offset in other expense items below.
A $45 million increase in weather-normalized retail margins primarily in the residential and commercial classes.
A $40 million increase at SWEPCo primarily due to a base rate revenue increase in Texas and rider increases in all retail jurisdictions. These increases were partially offset in other expense items below.
A $30 million increase in weather-related usage primarily in the residential class.
A $28 million increase at I&M due to increased rider revenues offset by lower wholesale true-ups. This increase was partially offset in other expense items below.
A $12 million increase due to lower customer refunds related to Tax Reform primarily at APCo and WPCo. This increase was partially offset in Income Tax Expense below.
26



These increases were partially offset by:
A $10 million increase in fuel expense at PSO due to NCWF PTC benefits provided to customers. This increase in fuel expense was partially offset in Income Tax Expense below.
A $7 million decrease in municipal and cooperative revenues at SWEPCo primarily due to the February 2021 severe winter weather event.
Margins from Off-system Sales decreased $27 million primarily due to the following:
A $17 million decrease due to Turk Plant merchant sales as a result of the February 2021 severe winter weather event at SWEPCo.
A $6 million decrease at KPCo due to a change in the OSS sharing arrangement in Kentucky.
A $4 million decrease at APCo primarily due to favorable hedging activity in the first quarter of 2021 as well as available generation at above average locational marginal pricing in February 2021.
Transmission Revenues increased $45 million primarily due to the following:
A $31 million increase in continued investment in transmission assets and increased load.
A $14 million increase in formula rate true-up activity.
Other Revenues increased $14 million primarily due to the following:
A $5 million increase at I&M primarily due to the sale of allowances. This amount is partially offset in Retail Margins above.
A $5 million increase at APCo primarily due to business development revenue. This increase was partially offset in Other Operation and Maintenance expenses below.

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

Other Operation and Maintenance expenses increased $105 million primarily due to the following:
An $83 million increase in PJM transmission services. This increase was partially offset in Retail Margins above.
A $51 million increase in Generation expenses primarily due to outages and maintenance at APCo, I&M and PSO.
A $14 million increase in employee-related expenses.
A $10 million increase in storms across all operating companies.
A $10 million increase in SPP transmission services.
A $7 million increase in Energy Efficiency/Demand Response.
These increases were partially offset by:
A $71 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.
A $9 million decrease in vegetation management expenses.
Depreciation and Amortization expenses increased $139 million primarily due to the following:
A $78 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 $43 million increase due to a higher depreciable base at APCo, I&M, PSO and SWEPCo and the implementation of increased Texas depreciation rates at SWEPCo.
Other Income increased $10 million primarily due to carrying charges on regulatory assets resulting from the February 2021 severe winter weather event at SWEPCo.
Allowance for Equity Funds Used During Construction decreased $6 million primarily due to a lower AFUDC base primarily at APCo and a decrease in AFUDC equity rates.
Non-Service Cost Components of Net Periodic Benefit Cost decreased $21 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.
Interest Expense increased $27 million primarily due to higher long-term debt balances at PSO and SWEPCo and a debt issuance in April 2021 at I&M.
Income Tax Expense decreased $8 million primarily due to an increase in PTCs partially offset by an increase in pretax book income.
27



TRANSMISSION AND DISTRIBUTION UTILITIES
Three Months EndedSix Months Ended
June 30,June 30,
Transmission and Distribution Utilities2022202120222021
 (in millions)
Revenues$1,301.6 $1,103.4 $2,548.4 $2,191.5 
Purchased Electricity252.7 168.0 485.3 373.5 
Gross Margin1,048.9 935.4 2,063.1 1,818.0 
Other Operation and Maintenance441.1 360.8 869.6 726.0 
Depreciation and Amortization187.6 178.5 371.2 351.2 
Taxes Other Than Income Taxes163.8 158.4 328.2 316.0 
Operating Income256.4 237.7 494.1 424.8 
Other Income2.0 0.8 2.3 1.7 
Allowance for Equity Funds Used During Construction7.0 6.2 14.3 13.0 
Non-Service Cost Components of Net Periodic Benefit Cost11.9 7.2 23.8 14.5 
Interest Expense(82.0)(77.0)(156.8)(151.5)
Income Before Income Tax Expense and Equity Earnings195.3 174.9 377.7 302.5 
Income Tax Expense31.3 21.2 60.9 34.4 
Equity Earnings of Unconsolidated Subsidiary0.8 — 0.8 — 
Net Income164.8 153.7 317.6 268.1 
Net Income Attributable to Noncontrolling Interests— — — — 
Earnings Attributable to AEP Common Shareholders$164.8 $153.7 $317.6 $268.1 

Summary of KWh Energy Sales for Transmission and Distribution Utilities
Three Months EndedSix Months Ended
June 30,June 30,
2022202120222021
 (in millions of KWhs)
Retail:    
Residential6,589 6,065 13,566 12,989 
Commercial6,941 6,488 12,940 12,064 
Industrial6,647 6,338 12,577 11,619 
Miscellaneous197 185 368 351 
Total Retail (a)20,374 19,076 39,451 37,023 
Wholesale (b)565 445 1,136 1,048 
Total KWhs20,939 19,521 40,587 38,071 

(a)Represents energy delivered to distribution customers.
(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold to PJM.
28



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 EndedSix Months Ended
June 30,June 30,
2022202120222021
 (in degree days)
Eastern Region    
Actual Heating (a)
206 215 2,070 1,992 
Normal Heating (b)
186 183 2,072 2,066 
Actual Cooling (c)
359 361 360 361 
Normal Cooling (b)
298 304 301 307 
Western Region    
Actual Heating (a)
— 278 319 
Normal Heating (b)
193 188 
Actual Cooling (d)
1,135 833 1,223 970 
Normal Cooling (b)
925 931 1,051 1,057 

(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.

29



Second Quarter of 2022 Compared to Second Quarter of 2021
Reconciliation of Second Quarter of 2021 to Second Quarter of 2022
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
  
Second Quarter of 2021$153.7 
  
Changes in Gross Margin: 
Retail Margins104.1 
Margins from Off-system Sales13.3 
Transmission Revenues14.5 
Other Revenues(18.4)
Total Change in Gross Margin113.5 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(80.3)
Depreciation and Amortization(9.1)
Taxes Other Than Income Taxes(5.4)
Other Income1.2 
Allowance for Equity Funds Used During Construction0.8 
Non-Service Cost Components of Net Periodic Benefit Cost4.7 
Interest Expense(5.0)
Total Change in Expenses and Other(93.1)
  
Income Tax Expense(10.1)
Equity Earnings of Unconsolidated Subsidiary0.8 
  
Second Quarter of 2022$164.8 

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

Retail Margins increased $104 million primarily due to the following:
A $25 million increase from interim rate increases driven by increased distribution and transmission investment in Texas.
A $23 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 $14 million increase due to prior year refunds of Excess ADIT to customers in Texas. This increase was offset in Income Tax Expense below.
A $13 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 $12 million increase in weather-related usage in Texas primarily due to a 36% increase in cooling degree days.
An $8 million increase in revenue from rate riders in Texas. This increase was partially offset in other expense items below.
A $5 million increase in weather-related usage in Ohio primarily due to the end of decoupling.
Margins from Off-system Sales increased $13 million primarily due to the following:
A $26 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.
This increase was partially offset by:
A $13 million decrease in deferrals of OVEC costs in Ohio. This decrease was offset in Retail Margins above and Other Revenues below.
30



Transmission Revenues increased $15 million primarily due to the following:
An $18 million increase due to interim rate increases driven by increased transmission investment in Texas.
A $5 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.
These increases were partially offset by:
An $11 million decrease due to formula rate true-up activity in Ohio.
Other Revenues decreased $18 million primarily due to the following:
An $8 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 $5 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 $3 million decrease in energy efficiency revenues in Texas.

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

Other Operation and Maintenance expenses increased $80 million primarily due to the following:
A $23 million increase in ERCOT transmission expenses. This increase was partially offset in Retail Margins and Transmission Revenues above.
A $19 million increase in transmission expenses in Ohio primarily due to the following:
A $17 million increase in recoverable PJM expenses. This increase was offset in Retail Margins above.
A $6 million increase in vegetation management expenses.
These increases were partially offset by:
A $5 million decrease in transmission formula rate true-up activity.
A $10 million increase in bad debt-related expenses including $7 million in 2022 due to Bad Debt Rider over-recovery in Ohio. The Bad Debt Rider over-recovery was offset in Retail Margins above.
A $10 million increase in employee-related expenses.
A $7 million increase in distribution-related expenses in Texas.
Depreciation and Amortization expenses increased $9 million primarily due to the following:
A $10 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 $3 million decrease in recoverable smart grid depreciable expenses in Ohio. This decrease was offset in Retail Margins above.
Taxes Other Than Income Taxes increased $5 million primarily due to property taxes as a result of increased distribution and transmission investment in Texas.
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 $5 million primarily due to higher long-term debt balances in Texas.
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 partially offset in Gross Margin above.
31



Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021
Reconciliation of Six Months Ended June 30, 2021 to Six Months Ended June 30, 2022
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
 
Six Months Ended June 30, 2021$268.1 
  
Changes in Gross Margin: 
Retail Margins215.0 
Margins from Off-system Sales26.0 
Transmission Revenues38.6 
Other Revenues(34.5)
Total Change in Gross Margin245.1 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(143.6)
Depreciation and Amortization(20.0)
Taxes Other Than Income Taxes(12.2)
Other Income0.6 
Allowance for Equity Funds Used During Construction1.3 
Non-Service Cost Components of Net Periodic Benefit Cost9.3 
Interest Expense(5.3)
Total Change in Expenses and Other(169.9)
  
Income Tax Expense(26.5)
Equity Earnings of Unconsolidated Subsidiary0.8 
  
Six Months Ended June 30, 2022$317.6 

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

Retail Margins increased $215 million primarily due to the following:
A $64 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 $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 $29 million increase in weather-normalized margins primarily from the commercial and residential classes, partially offset by the industrial 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 from interim rate increases driven by increased transmission investment in Texas.
A $19 million increase from interim rate increases driven by increased distribution investment in Texas.
A $14 million increase in revenue from rate riders in Texas. This increase was partially offset in other expense items below.
An $8 million increase in weather-related usage in Texas primarily due to a 26% increase in cooling degree days, partially offset by a 13% decrease in heating degree days.
Margins from Off-system Sales increased $26 million primarily due to the following:
A $37 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.
This increase was partially offset by:
32



An $11 million decrease in deferrals of OVEC costs in Ohio. This decrease was offset in Retail Margins above and Other Revenues below.
Transmission Revenues increased $39 million primarily due to the following:
A $35 million increase due to interim rate increases driven by increased transmission investment in Texas.
A $9 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 $5 million increase due to continued investment in transmission assets in Ohio.
These increases were partially offset by:
An $11 million decrease due to formula rate true-up activity in Ohio.
Other Revenues decreased $35 million primarily due to the following:
A $16 million decrease in Ohio primarily due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs. This decrease was offset in Retail Margins and Margins from Off-system Sales above.
A $12 million decrease 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 $6 million decrease in energy efficiency revenues in Texas.

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

Other Operation and Maintenance expenses increased $144 million primarily due to the following:
A $53 million increase in transmission expenses in Ohio primarily due to the following:
A $53 million increase in recoverable PJM expenses. This increase was offset in Retail Margins above.
A $6 million increase in vegetation management expenses.
These increases were partially offset by:
A $7 million decrease in transmission formula rate true-up activity.
A $23 million increase in ERCOT transmission expenses. This increase was partially offset in Retail Margins and Transmission Revenues above.
An $18 million increase in employee-related expenses.
A $16 million increase in bad debt-related expenses including $7 million in 2022 due to Bad Debt Rider over-recovery in Ohio. The Bad Debt Rider over-recovery was offset in Retail Margins above.
A $10 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.
An $8 million increase in distribution-related expenses in Texas.
Depreciation and Amortization expenses increased $20 million primarily due to the following:
An $18 million increase due to a higher depreciable base of transmission and distribution assets in Texas.
A $7 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.
Taxes Other Than Income Taxes increased $12 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 $9 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.
Interest Expense increased $5 million primarily due to the following:
A $10 million increase in Texas primarily due to higher long-term debt balances.
This increase was partially offset by:
A $4 million decrease in Ohio primarily due to lower long-term debt interest rates.
Income Tax Expense increased $27 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 EndedSix Months Ended
June 30,June 30,
AEP Transmission Holdco2022202120222021
 (in millions)
Transmission Revenues$378.8 $378.2 $790.2 $755.2 
Other Operation and Maintenance36.2 29.4 67.9 56.6 
Depreciation and Amortization87.9 74.7 173.2 147.4 
Taxes Other Than Income Taxes70.1 61.5 137.4 120.7 
Operating Income184.6 212.6 411.7 430.5 
Interest and Investment Income0.3 0.2 0.4 0.4 
Allowance for Equity Funds Used During Construction15.3 16.5 30.9 33.2 
Non-Service Cost Components of Net Periodic Benefit Cost1.2 0.6 2.5 1.1 
Interest Expense(40.7)(35.5)(79.8)(70.8)
Income Before Income Tax Expense and Equity Earnings160.7 194.4 365.7 394.4 
Income Tax Expense39.4 43.4 89.8 89.2 
Equity Earnings of Unconsolidated Subsidiary21.4 18.6 40.5 37.6 
Net Income142.7 169.6 316.4 342.8 
Net Income Attributable to Noncontrolling Interests0.9 0.9 1.5 2.1 
Earnings Attributable to AEP Common Shareholders$141.8 $168.7 $314.9 $340.7 

Summary of Investment in Transmission Assets for AEP Transmission Holdco
June 30,
20222021
(in millions)
Plant in Service$12,061.3 $11,065.2 
Construction Work in Progress1,787.3 1,486.3 
Accumulated Depreciation and Amortization920.0 703.1 
Total Transmission Property, Net$12,928.6 $11,848.4 
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Second Quarter of 2022 Compared to Second Quarter of 2021
 
Reconciliation of Second Quarter of 2021 to Second Quarter of 2022
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
Second Quarter of 2021$168.7 
Changes in Transmission Revenues:
Transmission Revenues0.6 
Total Change in Transmission Revenues0.6 
Changes in Expenses and Other:
Other Operation and Maintenance(6.8)
Depreciation and Amortization(13.2)
Taxes Other Than Income Taxes(8.6)
Interest and Investment Income0.1 
Allowance for Equity Funds Used During Construction(1.2)
Non-Service Cost Components of Net Periodic Pension Cost0.6 
Interest Expense(5.2)
Total Change in Expenses and Other(34.3)
Income Tax Expense4.0 
Equity Earnings of Unconsolidated Subsidiary2.8 
Second Quarter of 2022$141.8 

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

Transmission Revenues increased $1 million primarily due to the following:
A $43 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 and Income Tax Expense changed between years as follows:

Other Operation and Maintenance expenses increased $7 million primarily due to an increase in employee-related expenses.
Depreciation and Amortization expenses increased $13 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $9 million primarily due to higher property taxes as a result of increased transmission investment.
Interest Expense increased $5 million primarily due to higher long-term debt balances.
Income Tax Expense decreased $4 million primarily due to a decrease in pretax book income and a decrease in state income taxes, partially offset by a decrease in parent company loss benefit.
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Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021
 
Reconciliation of Six Months Ended June 30, 2021 to Six Months Ended June 30, 2022
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
Six Months Ended June 30, 2021$340.7 
Changes in Transmission Revenues:
Transmission Revenues35.0 
Total Change in Transmission Revenues35.0 
Changes in Expenses and Other:
Other Operation and Maintenance(11.3)
Depreciation and Amortization(25.8)
Taxes Other Than Income Taxes(16.7)
Allowance for Equity Funds Used During Construction(2.3)
Non-Service Cost Components of Net Periodic Pension Cost1.4 
Interest Expense(9.0)
Total Change in Expenses and Other(63.7)
Income Tax Expense(0.6)
Equity Earnings of Unconsolidated Subsidiary2.9 
Net Income Attributable to Noncontrolling Interests0.6 
Six Months Ended June 30, 2022$314.9 

The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and nonaffiliates, were as follows:
Transmission Revenues increased $35 million primarily due to the following:
A $78 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 changed between years as follows:
Other Operation and Maintenance expenses increased $11 million primarily due to an increase in employee-related expenses.
Depreciation and Amortization expenses increased $26 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $17 million primarily due to higher property taxes as a result of increased transmission investment.
Interest Expense increased $9 million primarily due to higher long-term debt balances.


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GENERATION & MARKETING
Three Months EndedSix Months Ended
June 30,June 30,
Generation & Marketing2022202120222021
 (in millions)
Revenues$659.6 $436.6 $1,278.9 $1,070.8 
Fuel, Purchased Electricity and Other519.8 358.1 967.9 924.0 
Gross Margin139.8 78.5 311.0 146.8 
Other Operation and Maintenance(6.0)32.4 26.5 60.6 
Gain on Sale of Mineral Rights(116.3)— (116.3)— 
Depreciation and Amortization22.4 20.0 45.7 38.6 
Taxes Other Than Income Taxes3.1 2.9 6.2 5.5 
Operating Income236.6 23.2 348.9 42.1 
Interest and Investment Income6.8 0.6 8.9 1.1 
Non-Service Cost Components of Net Periodic Benefit Cost5.2 3.9 10.3 7.7 
Interest Expense(9.0)(3.8)(14.0)(7.1)
Income Before Income Tax Benefit and Equity Earnings (Loss)239.6 23.9 354.1 43.8 
Income Tax Benefit(13.5)(24.2)(20.2)(39.3)
Equity Earnings (Loss) of Unconsolidated Subsidiaries(187.2)(1.6)(192.4)1.6 
Net Income65.9 46.5 181.9 84.7 
Net Loss Attributable to Noncontrolling Interests(6.7)(5.9)(4.9)(4.3)
Earnings Attributable to AEP Common Shareholders$72.6 $52.4 $186.8 $89.0 

Summary of MWhs Generated for Generation & Marketing
Three Months EndedSix Months Ended
June 30,June 30,
2022202120222021
 (in millions of MWhs)
Fuel Type:    
Coal
Renewables
Total MWhs
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Second Quarter of 2022 Compared to Second Quarter of 2021
Reconciliation of Second Quarter of 2021 to Second Quarter of 2022
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
  
Second Quarter of 2021$52.4 
  
Changes in Gross Margin: 
Merchant Generation8.6 
Renewable Generation7.5 
Retail, Trading and Marketing45.2 
Total Change in Gross Margin61.3 
  
Changes in Expenses and Other: 
Other Operation and Maintenance38.4 
Gain on Sale of Mineral Rights116.3 
Depreciation and Amortization(2.4)
Taxes Other Than Income Taxes(0.2)
Interest and Investment Income6.2 
Non-Service Cost Components of Net Periodic Benefit Cost1.3 
Interest Expense(5.2)
Total Change in Expenses and Other154.4 
  
Income Tax Benefit(10.7)
Equity Earnings (Loss) of Unconsolidated Subsidiaries(185.6)
Net Income Attributable to Noncontrolling Interests0.8 
  
Second Quarter of 2022$72.6 

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

Merchant Generation increased $9 million primarily due to higher market prices.
Renewable Generation increased $8 million primarily due to new wind and solar projects placed in service.
Retail, Trading and Marketing increased $45 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 $38 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.
Interest and Investment Income increased $6 million primarily due to an increase in Advances to Affiliates.
Interest Expense increased $5 million due to higher borrowing costs in 2022.
Income Tax Benefit decreased $11 million primarily due to an increase in pretax book income and an increase in state income taxes.
Equity Earnings (Loss) of Unconsolidated Subsidiaries decreased $186 million due to the impairment of AEP’s investment in Flat Ridge 2 Wind LLC.
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Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021
Reconciliation of Six Months Ended June 30, 2021 to Six Months Ended June 30, 2022
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
  
Six Months Ended June 30, 2021$89.0 
  
Changes in Gross Margin: 
Merchant Generation(10.6)
Renewable Generation6.6 
Retail, Trading and Marketing168.2 
Total Change in Gross Margin164.2 
  
Changes in Expenses and Other: 
Other Operation and Maintenance34.1 
Gain on Sale of Mineral Rights116.3 
Depreciation and Amortization(7.1)
Taxes Other Than Income Taxes(0.7)
Interest and Investment Income7.8 
Non-Service Cost Components of Net Periodic Benefit Cost2.6 
Interest Expense(6.9)
Total Change in Expenses and Other146.1 
  
Income Tax Benefit(19.1)
Equity Earnings (Loss) of Unconsolidated Subsidiaries(194.0)
Net Loss Attributable to Noncontrolling Interests0.6 
  
Six Months Ended June 30, 2022$186.8 

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

Merchant Generation decreased $11 million primarily due to more Cardinal plant outage days in 2022 and the sale of Racine partially offset by higher market prices.
Renewable Generation increased $7 million primarily due to new wind and solar projects placed in service.
Retail, Trading and Marketing increased $168 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 $34 million primarily due to higher land sales and the sale of renewable development projects partially offset by increased Cardinal Unit 1 expenses.
Gain on Sale of Mineral Rights increased $116 million due to the current year sale of mineral rights.
Depreciation and Amortization expenses increased $7 million due to a higher depreciable base from increased investments in renewable energy assets.
Interest and Investment Income increased $8 million primarily due to an increase in Advances to Affiliates.
Interest Expense increased $7 million due to higher borrowing costs in 2022.
Income Tax Benefit decreased $19 million primarily due to an increase in pretax book income partially offset by a one-time benefit recorded 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

Second Quarter of 2022 Compared to Second Quarter of 2021

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $25 million in 2021 to a loss of $156 million in 2022 primarily due to:

A $69 million loss related to the anticipated sale of the Kentucky operations.
A $35 million decrease primarily due to unfavorable changes in unrealized gains and losses from AEP’s investment in ChargePoint.
A $13 million decrease in equity earnings.
A $10 million increase in interest expense due to higher long-term balances and advances from affiliates.
A $6 million decrease in other income, primarily due to a lower return on investments held by EIS.
A $4 million increase in transaction costs due to the anticipated sale of the Kentucky operations.
A $2 million increase in Income Tax Expense primarily due to the following:
A $31 million increase due to a consolidating tax adjustment.
A $6 million increase in permanent tax adjustments.
These increases were partially offset by:
A $19 million decrease due to the remeasurement of state deferred taxes as a result of newly enacted West Virginia state legislation in the second quarter of 2021.
A $13 million decrease due to a decrease in pretax book income.

Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $43 million in 2021 to a loss of $180 million in 2022 primarily due to:

A $69 million loss related to the anticipated sale of the Kentucky operations.
A $50 million decrease primarily due to unfavorable changes in unrealized gains and losses from AEP’s investment in ChargePoint.
A $19 million decrease primarily due to a favorable bad debt expense adjustment in 2021.
A $19 million increase in interest expense due to higher long-term debt balances and higher interest rates on short-term debt.
A $17 million decrease in equity earnings.
A $14 million decrease in other income, primarily due to a lower return on investments held by EIS.
A $7 million increase in transaction costs due to the anticipated sale of the Kentucky operations.

These items were partially offset by:

A $47 million decrease in Income Tax Expense primarily due to the following:
A $24 million decrease due to a decrease in pretax book income.
A $19 million decrease due to the remeasurement of state deferred taxes as a result of newly enacted West Virginia state legislation in the second quarter of 2021.
An $18 million decrease due to parent company loss benefit.
These decreases were partially offset by:
A $5 million increase due to a consolidating tax adjustment.
A $4 million increase due to increase in permanent tax adjustments.

AEP SYSTEM INCOME TAXES

Second Quarter of 2022 Compared to Second Quarter of 2021

Income Tax Expense decreased $7 million primarily due to:
A $19 million decrease due to the remeasurement of state deferred taxes as a result of newly enacted West Virginia state legislation in the second quarter of 2021.
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An $8 million decrease due to an increase in PTC.
A $3 million decrease in investment tax credit amortization.
These decreases were partially offset by:
A $17 million increase due to a decrease in amortization of Excess ADIT.
A $7 million increase due to unfavorable permanent tax adjustments.
A $2 million increase due to an increase in state income taxes.

Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021

Income Tax Expense decreased $9 million primarily due to:
A $34 million decrease due to an increase in PTC.
A $19 million decrease due to the remeasurement of state deferred taxes as a result of newly enacted West Virginia state legislation in second quarter of 2021.
An $8 million decrease due to favorable discrete tax adjustments booked in 2022.
These decreases were partially offset by:
A $24 million increase due to a decrease in amortization of Excess ADIT.
A $31 million increase due to an increase in pretax book income.


41



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
 June 30, 2022December 31, 2021
 (dollars in millions)
Long-term Debt, including amounts due within one year$35,459.4 57.3 %$33,454.5 57.0 %
Short-term Debt2,130.0 3.4 2,614.0 4.4 
Total Debt37,589.4 60.7 36,068.5 61.4 
AEP Common Equity24,056.0 38.9 22,433.2 38.2 
Noncontrolling Interests241.0 0.4 247.0 0.4 
Total Debt and Equity Capitalization$61,886.4 100.0 %$58,748.7 100.0 %

AEP’s ratio of debt-to-total capital decreased from 61.4% as of December 31, 2021 to 60.7% as of June 30, 2022 primarily due to an increase in earnings in 2022 in addition 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 June 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 raises 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 February 2022, AEP entered into a $250 million Term Loan for general corporate business purposes, including the pay down of short-term debt. In March 2022, AEP extended the maturity date of the original 364-Day Term Loan to August 2022. In June 2022, AEP paid off the $250 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.



42



Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments.  As of June 30, 2022, available liquidity was approximately $4.7 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)
 Term Loan (b)500.0 August 2022
Cash and Cash Equivalents575.3  
Total Liquidity Sources6,075.3  
Less:AEP Commercial Paper Outstanding880.0  
 Term Loan (b)500.0  
Net Available Liquidity$4,695.3  
(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.
(b)In March 2022, AEP extended the maturity date of the original 364-Day Term Loan to August 2022.

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 six months of 2022 was $2.4 billion.  The weighted-average interest rate for AEP’s commercial paper during 2022 was 0.99%.

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 June 30, 2022 was $324 million with maturities ranging from July 2022 to June 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 which expire in September 2023 and 2024, respectively. As of June 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 June 30, 2022, this contractually-defined percentage was 57.8%. 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.
43



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

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

ATM Program

AEP participates in an ATM offering program that allows AEP to issue, from time to time, up to an aggregate of $1 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 six months ended June 30, 2022. As of June 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 $0.78 per share in July 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
44



subject AEP to additional collateral demands under adequate assurance clauses under its derivative and non-derivative energy contracts.

CASH FLOW

AEP relies primarily on cash flows from operations, debt issuances and its existing cash and cash equivalents to fund its liquidity and investing activities. AEP’s investing and capital requirements are primarily capital expenditures, repaying of long-term debt and paying dividends to shareholders. AEP uses short-term debt, including commercial paper, as a bridge to long-term debt financing. The levels of borrowing may vary significantly due to the timing of long-term debt financings and the impact of fluctuations in cash flows.
Six Months Ended 
June 30,
 20222021
 (in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period$451.4 $438.3 
Net Cash Flows from Operating Activities2,990.7 1,043.9 
Net Cash Flows Used for Investing Activities(4,199.0)(3,229.8)
Net Cash Flows from Financing Activities1,378.1 2,107.3 
Net Increase (Decrease) in Cash and Cash Equivalents169.8 (78.6)
Cash, Cash Equivalents and Restricted Cash at End of Period$621.2 $359.7 

Operating Activities
Six Months Ended 
June 30,
20222021
(in millions)
Net Income$1,238.9 $1,152.6 
Non-Cash Adjustments to Net Income (a)1,694.8 1,423.4 
Mark-to-Market of Risk Management Contracts431.4 26.1 
Property Taxes191.6 167.3 
Deferred Fuel Over/Under-Recovery, Net(599.5)(1,218.2)
Change in Other Noncurrent Assets(49.3)(184.7)
Change in Other Noncurrent Liabilities144.5 163.5 
Change in Certain Components of Working Capital(61.7)(486.1)
Net Cash Flows from Operating Activities$2,990.7 $1,043.9 

(a)Non-Cash Adjustments to Net Income includes Depreciation and Amortization, Deferred Income Taxes, Loss on the Expected Sale of the Kentucky Operations, Impairment of Equity Method Investment, AFUDC and Gain on Sale of Mineral Rights.

Net Cash Flows from Operating Activities increased by $1.9 billion primarily due to the following:
A $619 million increase in cash primarily due to the timing of fuel and purchase power revenues and expenses. In 2021, 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. PSO and SWEPCo are working with their respective regulatory commissions to determine the recovery period from customers as well as the appropriate carrying charge on the regulatory assets. See Note 4 - Rate Matters for additional information. In 2022, increased fuel and purchased power prices continue to lead to an increase in the under collection of fuel costs, primarily at APCo and PSO. As of June 30, 2022, APCo and PSO have recognized an increase in cash outflows related to under-recovered fuel of $312 million and $127 million, respectively.
45



A $424 million increase in cash from the Change in Certain Components of Working Capital. The increase is primarily due to cash margin collateral held in relation to auction supply driven by increases in power prices, a return of margin deposits from PJM originally paid in 2021 and the timing of accounts payable. These increases were partially offset by a decrease in cash from fuel, material and supplies balances driven by an increase in coal inventory on hand and the timing of accounts receivable.
A $405 million increase primarily due to collateral held against risk management contracts due to pricing movement in the commodities market.
A $358 million increase in cash from Net Income, after non-cash adjustments. See Results of Operations for further detail.
A $135 million increase in cash from changes in 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, OPCo and WPCo. Recovery of the June 2022 storm costs will be requested in future filings. See Note 4 - Rate Matters for additional information.

Investing Activities
Six Months Ended 
June 30,
 20222021
 (in millions)
Construction Expenditures$(3,138.1)$(2,784.8)
Acquisitions of Nuclear Fuel(67.7)(63.0)
Acquisition of the Dry Lake Solar Project— (114.3)
Acquisition of the North Central Wind Energy Facilities(1,207.3)(270.0)
Proceeds from Sale of Assets208.5 13.2 
Other5.6 (10.9)
Net Cash Flows Used for Investing Activities$(4,199.0)$(3,229.8)

Net Cash Flows Used for Investing Activities increased by $969 million primarily due to the following:
An $823 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.
A $353 million increase in Construction Expenditures, primarily due to increases in Vertically Integrated Utilities of $255 million and Transmission and Distribution Utilities of $140 million.
These increases in cash used were partially offset by:
A $195 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.


46



Financing Activities
Six Months Ended 
June 30,
 20222021
 (in millions)
Issuance of Common Stock$812.7 $256.9 
Issuance/Retirement of Debt, Net1,572.7 2,705.7 
Dividends Paid on Common Stock(803.5)(746.5)
Other(203.8)(108.8)
Net Cash Flows from Financing Activities$1,378.1 $2,107.3 

Net Cash Flows from Financing Activities decreased by $729 million primarily due to the following:
A $1.1 billion decrease due to changes in short-term debt. See Note 12 - Financing Activities for additional information.
A $416 million decrease in issuances of long-term debt. See Note 12 - Financing Activities for additional information.
These decreases in cash were partially offset by:
A $556 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 $416 million decrease in retirements of long-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 June 30, 2022 through July 27, 2022, the date that the second 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 $30.7 billion. The expenditures are generally for transmission, generation, distribution, regulated renewables and required environmental investment to comply with the Federal EPA rules.  Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, supply chain issues, weather, legal reviews and the ability to access capital.  Management expects to fund these capital expenditures through cash flows from operations, proceeds from the sale of Kentucky operations, proceeds from the sale of competitive contracted renewables and financing activities.  Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged. 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.


47



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

The effects of COVID-19 continue to be monitored, and while markets have shown improvement, credit risks remain as counterparties encounter business and supply chain disruptions.
48



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. Financial costs associated with securitization are allocated to certain market participants and in that role AEPEP is exposed, but not materially. If the market rules were to change on how socialized losses are allocated this could affect AEPEP’s exposure. Regardless of the approach of how socialized losses are allocated there are potential downstream impacts that could push counterparties into financial distress and or bankruptcy, affecting AEPEP, AEP Texas and ETT.

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)
Six Months Ended June 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(62.8)2.9 (28.7)(88.6)
Fair Value of New Contracts at Inception When Entered During the Period (a)— — 2.6 2.6 
Changes in Fair Value Due to Market Fluctuations During the Period (b)— — 216.0 216.0 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)223.2 42.8 — 266.0 
MTM Risk Management Contract Net Assets Held for Sale Related to KPCo (d)(7.7)— — (7.7)
Total MTM Risk Management Contract Net Assets (Liabilities) as of June 30, 2022$212.5 $(45.7)$465.8 632.6 
Commodity Cash Flow Hedge Contracts
 675.8 
Interest Rate Cash Flow Hedge Contracts
  4.2 
Fair Value Hedge Contracts  (99.4)
Collateral Deposits  (1,086.5)
Total MTM Derivative Contract Net Assets as of June 30, 2022  $126.7 

(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.
(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.


49



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 June 30, 2022, credit exposure net of collateral to sub investment grade counterparties was approximately 1.1%, 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 June 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$832.5 $550.2 $282.3 $104.5 
Split Rating1.8 — 1.8 1.8 
Noninvestment Grade3.1 3.0 0.1 0.1 
No External Ratings:    
Internal Investment Grade48.6 8.2 40.4 28.8 
Internal Noninvestment Grade8.2 4.7 3.5 3.3 
Total as of June 30, 2022$894.2 $566.1 $328.1 

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 June 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.
50




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

VaR Model
Trading Portfolio
Six Months EndedTwelve Months Ended
June 30, 2022December 31, 2021
EndHighAverageLowEndHighAverageLow
(in millions)(in millions)
$0.6 $4.5 $0.8 $0.1 $0.4 $3.6 $0.4 $0.1 

VaR Model
Non-Trading Portfolio
Six Months EndedTwelve Months Ended
June 30, 2022December 31, 2021
EndHighAverageLowEndHighAverageLow
(in millions)(in millions)
$41.4 $76.9 $25.2 $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. AEP has outstanding short and long-term debt which is subject to a variable rate. AEP manages interest rate risk by limiting variable-rate exposures to a percentage of total debt, by entering into interest rate derivative instruments and by monitoring the effects of market changes in interest rates. For the six months ended June 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 $38 million and $38 million, respectively.
51




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2022 and 2021
(in millions, except per-share and share amounts)
(Unaudited)
Three Months EndedSix Months Ended
June 30,June 30,
2022202120222021
REVENUES
Vertically Integrated Utilities$2,595.0 $2,224.6 $5,241.8 $4,729.1 
Transmission and Distribution Utilities1,296.8 1,089.6 2,539.0 2,171.9 
Generation & Marketing654.4 422.5 1,263.9 1,024.2 
Other Revenues93.5 89.8 187.6 182.4 
TOTAL REVENUES4,639.7 3,826.5 9,232.3 8,107.6 
EXPENSES    
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation1,564.4 1,124.0 3,065.1 2,684.7 
Other Operation619.8 566.9 1,282.0 1,159.3 
Maintenance326.5 264.3 611.5 539.2 
Loss on the Expected Sale of the Kentucky Operations68.8 — 68.8 — 
Gain on Sale of Mineral Rights(116.3)— (116.3)— 
Depreciation and Amortization802.6 707.3 1,595.0 1,403.6 
Taxes Other Than Income Taxes369.5 354.1 733.7 700.6 
TOTAL EXPENSES3,635.3 3,016.6 7,239.8 6,487.4 
OPERATING INCOME1,004.4 809.9 1,992.5 1,620.2 
Other Income (Expense):    
Other Income (Expense)(12.7)33.1 (10.4)54.8 
Allowance for Equity Funds Used During Construction28.6 33.5 59.6 66.9 
Non-Service Cost Components of Net Periodic Benefit Cost47.1 29.7 94.3 59.3 
Interest Expense(327.6)(301.6)(641.0)(591.8)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS (LOSS)739.8 604.6 1,495.0 1,209.4 
Income Tax Expense54.0 61.2 106.8 115.7 
Equity Earnings (Loss) of Unconsolidated Subsidiaries(165.0)30.4 (149.3)58.9 
NET INCOME520.8 573.8 1,238.9 1,152.6 
Net Loss Attributable to Noncontrolling Interests(3.7)(4.4)(0.3)(0.6)
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$524.5 $578.2 $1,239.2 $1,153.2 
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING513,623,431 499,916,640 509,857,710 498,495,532 
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$1.02 $1.16 $2.43 $2.31 
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING515,162,210 500,983,778 511,391,735 499,581,893 
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$1.02 $1.15 $2.42 $2.31 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.
52



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2022 and 2021
(in millions)
(Unaudited)
Three Months EndedSix Months Ended
June 30,June 30,
2022202120222021
Net Income$520.8 $573.8 $1,238.9 $1,152.6 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES    
Cash Flow Hedges, Net of Tax of $35.2 and $34.5 for the Three Months Ended June 30, 2022 and 2021, Respectively, and $101.1 and $49.5 for the Six Months Ended June 30, 2022 and 2021, Respectively132.4 129.9 380.4 186.2 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(3.1) and $(0.6) for the Three Months Ended June 30, 2022 and 2021 and $(3.7) and $(1.1) for the Six Months Ended June 30, 2022 and 2021, Respectively(11.6)(2.1)(13.8)(4.1)
    
TOTAL OTHER COMPREHENSIVE INCOME120.8 127.8 366.6 182.1 
TOTAL COMPREHENSIVE INCOME641.6 701.6 1,605.5 1,334.7 
Total Comprehensive Loss Attributable To Noncontrolling Interests(3.7)(4.4)(0.3)(0.6)
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$645.3 $706.0 $1,605.8 $1,335.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.
53



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Six Months Ended June 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 
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 

(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 138.
54



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2022 and December 31, 2021
(in millions)
(Unaudited)
 June 30,December 31,
 20222021
CURRENT ASSETS  
Cash and Cash Equivalents$575.3 $403.4 
Restricted Cash
(June 30, 2022 and December 31, 2021 Amounts Include $45.9 and $48, Respectively, Related to Transition Funding, Restoration Funding and Appalachian Consumer Rate Relief Funding)
45.9 48.0 
Other Temporary Investments
(June 30, 2022 and December 31, 2021 Amounts Include $182.8 and $214.8, Respectively, Related to EIS and Transource Energy)
192.0 220.4 
Accounts Receivable:  
Customers930.3 720.9 
Accrued Unbilled Revenues259.3 204.4 
Pledged Accounts Receivable – AEP Credit1,155.9 1,038.0 
Miscellaneous57.2 33.9 
Allowance for Uncollectible Accounts(53.4)(55.6)
Total Accounts Receivable2,349.3 1,941.6 
Fuel353.7 307.9 
Materials and Supplies748.6 681.3 
Risk Management Assets453.5 194.4 
Accrued Tax Benefits97.6 121.5 
Regulatory Asset for Under-Recovered Fuel Costs1,324.8 647.8 
Assets Held for Sale2,945.7 2,919.7 
Prepayments and Other Current Assets284.6 323.2 
TOTAL CURRENT ASSETS9,371.0 7,809.2 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation24,465.9 23,088.1 
Transmission30,757.2 29,911.1 
Distribution25,118.9 24,440.0 
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)5,839.9 5,682.9 
Construction Work in Progress4,289.1 3,684.3 
Total Property, Plant and Equipment90,471.0 86,806.4 
Accumulated Depreciation and Amortization21,762.8 20,805.1 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET68,708.2 66,001.3 
OTHER NONCURRENT ASSETS  
Regulatory Assets4,157.7 4,142.3 
Securitized Assets502.5 552.8 
Spent Nuclear Fuel and Decommissioning Trusts3,280.8 3,867.0 
Goodwill52.5 52.5 
Long-term Risk Management Assets164.9 267.0 
Operating Lease Assets630.6 578.3 
Deferred Charges and Other Noncurrent Assets3,993.1 4,398.3 
TOTAL OTHER NONCURRENT ASSETS12,782.1 13,858.2 
TOTAL ASSETS$90,861.3 $87,668.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.
55



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
June 30, 2022 and December 31, 2021
(in millions, except per-share and share amounts)
(Unaudited)
   June 30,December 31,
 20222021
CURRENT LIABILITIES  
Accounts Payable$2,198.2 $2,054.6 
Short-term Debt:  
Securitized Debt for Receivables – AEP Credit750.0 750.0 
Other Short-term Debt1,380.0 1,864.0 
Total Short-term Debt2,130.0 2,614.0 
Long-term Debt Due Within One Year
(June 30, 2022 and December 31, 2021 Amounts Include $266.1 and $190.5, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)
2,476.7 2,153.8 
Risk Management Liabilities179.7 75.4 
Customer Deposits483.1 321.6 
Accrued Taxes1,350.2 1,586.4 
Accrued Interest295.4 273.2 
Obligations Under Operating Leases94.1 97.6 
Liabilities Held for Sale1,900.3 1,880.9 
Other Current Liabilities1,340.3 1,369.2 
TOTAL CURRENT LIABILITIES12,448.0 12,426.7 
NONCURRENT LIABILITIES  
Long-term Debt
(June 30, 2022 and December 31, 2021 Amounts Include $744.7 and $840.5, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)
32,982.7 31,300.7 
Long-term Risk Management Liabilities312.0 230.3 
Deferred Income Taxes8,481.0 8,202.5 
Regulatory Liabilities and Deferred Investment Tax Credits8,057.2 8,686.3 
Asset Retirement Obligations2,789.6 2,676.2 
Employee Benefits and Pension Obligations290.7 328.4 
Obligations Under Operating Leases549.6 492.8 
Deferred Credits and Other Noncurrent Liabilities589.9 601.3 
TOTAL NONCURRENT LIABILITIES54,052.7 52,518.5 
TOTAL LIABILITIES66,500.7 64,945.2 
Rate Matters (Note 4)00
Commitments and Contingencies (Note 5)00
MEZZANINE EQUITY
Contingently Redeemable Performance Share Awards63.6 43.3 
TOTAL MEZZANINE EQUITY63.6 43.3 
EQUITY  
Common Stock – Par Value – $6.50 Per Share:  
20222021  
Shares Authorized600,000,000600,000,000  
Shares Issued524,921,200524,416,175  
(11,233,240 Shares and 20,204,160 Shares were Held in Treasury as of June 30, 2022 and December 31, 2021, Respectively)3,412.0 3,408.7 
Paid-in Capital7,984.0 7,172.6 
Retained Earnings12,108.6 11,667.1 
Accumulated Other Comprehensive Income (Loss)551.4 184.8 
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY24,056.0 22,433.2 
Noncontrolling Interests241.0 247.0 
TOTAL EQUITY24,297.0 22,680.2 
TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY$90,861.3 $87,668.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.
56



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2022 and 2021
(in millions)
(Unaudited)
 Six Months Ended June 30,
 20222021
OPERATING ACTIVITIES  
Net Income$1,238.9 $1,152.6 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and Amortization1,595.0 1,403.6 
Deferred Income Taxes21.4 86.7 
Loss on the Expected Sale of the Kentucky Operations68.8 — 
Impairment of Equity Method Investment185.5 — 
Allowance for Equity Funds Used During Construction(59.6)(66.9)
Mark-to-Market of Risk Management Contracts431.4 26.1 
Property Taxes191.6 167.3 
Deferred Fuel Over/Under-Recovery, Net(599.5)(1,218.2)
Gain on Sale of Mineral Rights(116.3)— 
Change in Other Noncurrent Assets(49.3)(184.7)
Change in Other Noncurrent Liabilities144.5 163.5 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net(445.8)(215.5)
Fuel, Materials and Supplies(110.5)132.3 
Accounts Payable484.8 97.5 
Accrued Taxes, Net(218.2)(237.4)
Other Current Assets69.9 10.4 
Other Current Liabilities158.1 (273.4)
Net Cash Flows from Operating Activities2,990.7 1,043.9 
INVESTING ACTIVITIES  
Construction Expenditures(3,138.1)(2,784.8)
Purchases of Investment Securities(1,254.8)(1,162.8)
Sales of Investment Securities1,244.9 1,131.8 
Acquisitions of Nuclear Fuel(67.7)(63.0)
Acquisition of the Dry Lake Solar Project— (114.3)
Acquisition of the North Central Wind Energy Facilities(1,207.3)(270.0)
Proceeds from Sales of Assets208.5 13.2 
Other Investing Activities15.5 20.1 
Net Cash Flows Used for Investing Activities(4,199.0)(3,229.8)
FINANCING ACTIVITIES  
Issuance of Common Stock812.7 256.9 
Issuance of Long-term Debt2,639.1 3,055.1 
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, Net(268.9)(437.8)
Retirement of Long-term Debt(582.4)(998.1)
Redemption of Short-term Debt with Original Maturities Greater than 90 Days(486.1)(92.0)
Principal Payments for Finance Lease Obligations(106.2)(30.3)
Dividends Paid on Common Stock(803.5)(746.5)
Other Financing Activities(97.6)(78.5)
Net Cash Flows from Financing Activities1,378.1 2,107.3 
Net Increase (Decrease) in Cash and Cash Equivalents169.8 (78.6)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period451.4 438.3 
Cash, Cash Equivalents and Restricted Cash at End of Period$621.2 $359.7 
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts$591.2 $559.9 
Net Cash Paid for Income Taxes95.5 8.6 
Noncash Acquisitions Under Finance Leases13.7 16.3 
Construction Expenditures Included in Current Liabilities as of June 30,849.1 789.3 
Noncontrolling Interest Assumed - Dry Lake Solar Project— 33.4 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.
57



AEP TEXAS INC.
AND SUBSIDIARIES

58



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 EndedSix Months Ended
June 30,June 30,
 2022202120222021
 (in millions of KWhs)
Retail:  
Residential3,531 3,006 6,374 5,824 
Commercial3,091 2,819 5,239 4,893 
Industrial3,023 2,604 5,450 4,484 
Miscellaneous173 159 314 296 
Total Retail9,818 8,588 17,377 15,497 

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 EndedSix Months Ended
June 30,June 30,
 2022202120222021
 (in degree days)
Actual – Heating (a)— 278 319 
Normal – Heating (b)193 188 
Actual – Cooling (c)1,135 833 1,223 970 
Normal – Cooling (b)925 931 1,051 1,057 

(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.




59



Second Quarter of 2022 Compared to Second Quarter of 2021
AEP Texas Inc. and Subsidiaries
Reconciliation of Second Quarter of 2021 to Second Quarter of 2022
Net Income
(in millions)
Second Quarter of 2021$79.8 
  
Changes in Revenues:
Retail Revenues67.8 
Transmission Revenues22.8 
Other Revenues(10.3)
Total Change in Revenues80.3 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(38.5)
Depreciation and Amortization(14.2)
Taxes Other Than Income Taxes(3.5)
Interest Income1.1 
Allowance for Equity Funds Used During Construction0.3 
Non-Service Cost Components of Net Periodic Benefit Cost1.4 
Interest Expense(7.0)
Total Change in Expenses and Other(60.4)
  
Income Tax Expense(9.7)
  
Second Quarter of 2022$90.0 

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

Retail Revenues increased $68 million primarily due to the following:
A $14 million increase due to prior year refunds of Excess ADIT to customers. This increase was offset in Income Tax Expense below.
A $14 million increase due to interim rate increases driven by increased transmission investment.
A $12 million increase in weather-related usage primarily due to a 36% increase in cooling degree days.
An $11 million increase due to interim rate increases driven by increased distribution investment.
A $9 million increase in weather-normalized revenues in all retail classes.
An $8 million increase in revenue from rate riders. This increase was partially offset in other expense items below.
Transmission Revenues increased $23 million primarily due to the following:
An $18 million increase due to interim rate increases driven by increased transmission investment.
A $5 million increase due to prior year refunds to customers associated with the most recent base rate case. This increase was offset in Other Revenues below.
Other Revenues decreased $10 million primarily due to the following:
A $5 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 $3 million decrease in energy efficiency revenues.
60


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

Other Operation and Maintenance expenses increased $39 million primarily due to the following:
A $23 million increase in ERCOT transmission expenses. This increase was partially offset in Retail Revenues and Transmission Revenues above.
A $7 million increase in distribution-related expenses.
A $5 million increase in employee-related expenses.
Depreciation and Amortization expenses increased $14 million primarily due to the following:
A $10 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.
Interest Expense increased $7 million primarily due to higher long-term debt balances.
Income Tax Expense increased $10 million primarily due to a decrease in amortization of Excess ADIT and an increase in pretax book income. The decrease in amortization of Excess ADIT is offset in Retail Revenues above.
61



Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021
AEP Texas Inc. and Subsidiaries
Reconciliation of Six Months Ended June 30, 2021 to Six Months Ended June 30, 2022
Net Income
(in millions)
Six Months Ended June 30, 2021$125.9 
  
Changes in Revenues:
Retail Revenues107.2 
Transmission Revenues43.9 
Other Revenues(18.3)
Total Change in Revenues132.8 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(45.6)
Depreciation and Amortization(25.5)
Taxes Other Than Income Taxes(4.5)
Interest Income1.0 
Allowance for Equity Funds Used During Construction0.5 
Non-Service Cost Components of Net Periodic Benefit Cost2.8 
Interest Expense(9.5)
Total Change in Expenses and Other(80.8)
  
Income Tax Expense(18.3)
  
Six Months Ended June 30, 2022$159.6 
The major components of the increase in revenues were as follows:

Retail Revenues increased $107 million primarily due to the following:
A $31 million increase due to prior year refunds of Excess ADIT to customers. This increase was offset in Income Tax Expense below.
A $20 million increase due to interim rate increases driven by increased transmission investment.
A $19 million increase due to interim rate increases driven by increased distribution investment.
A $15 million increase in weather-normalized revenues in all retail classes.
A $14 million increase in revenue from rate riders. This increase was partially offset in other expense items below.
An $8 million increase in weather-related usage primarily due to a 26% increase in cooling degree days partially offset by a 13% decrease in heating degree days.
Transmission Revenues increased $44 million primarily due to the following:
A $35 million increase due to interim rate increases driven by increased transmission investment.
A $9 million increase due to prior year refunds to customers associated with the most recent base rate case. This increase was offset in Other Revenues below.
Other Revenues decreased $18 million primarily due to:
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 $6 million decrease in energy efficiency revenues.

62



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 $23 million increase in ERCOT transmission expenses. This increase was partially offset in Retail Revenues and Transmission Revenues above.
An $8 million increase in distribution-related expenses.
An $8 million increase in employee-related expenses.
A $4 million increase in vegetation management expenses.
Depreciation and Amortization expenses increased $26 million primarily due to the following:
An $18 million increase due to a higher depreciable base of transmission and distribution assets.
A $7 million increase in recoverable advanced metering system depreciable expenses.
Taxes Other Than Income Taxes increased $5 million primarily due to property taxes as a result of increased distribution and transmission investment.
Interest Expense increased $10 million primarily due to higher long-term debt balances.
Income Tax Expense increased $18 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 offset in Retail Revenues above.

63




AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2022 and 2021
(in millions)
(Unaudited)
  Three Months EndedSix Months Ended
June 30,June 30,
  2022 202120222021
REVENUES    
Electric Transmission and Distribution $476.9 $396.6 $891.6 $758.3 
Sales to AEP Affiliates 0.8 1.0 1.7 2.0 
Other Revenues 1.1 0.9 2.2 2.4 
TOTAL REVENUES 478.8 398.5 895.5 762.7 
 
EXPENSES     
Other Operation 142.0 109.6 267.8 231.8 
Maintenance 24.8 18.7 47.4 37.8 
Depreciation and Amortization 116.2 102.0 225.0 199.5 
Taxes Other Than Income Taxes 43.0 39.5 80.3 75.8 
TOTAL EXPENSES 326.0 269.8 620.5 544.9 
 
OPERATING INCOME 152.8 128.7 275.0 217.8 
 
Other Income (Expense):     
Interest Income 1.3 0.2 1.4 0.4 
Allowance for Equity Funds Used During Construction3.7 3.4 8.0 7.5 
Non-Service Cost Components of Net Periodic Benefit Cost4.1 2.7 8.3 5.5 
Interest Expense (52.3)(45.3)(97.8)(88.3)
 
INCOME BEFORE INCOME TAX EXPENSE 109.6 89.7 194.9 142.9 
 
Income Tax Expense 19.6 9.9 35.3 17.0 
NET INCOME $90.0 $79.8 $159.6 $125.9 
The common stock of AEP Texas is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.
64



AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2022 and 2021
(in millions)
(Unaudited)
 Three Months EndedSix Months Ended
June 30,June 30,
2022202120222021
Net Income$90.0 $79.8 $159.6 $125.9 
 
OTHER COMPREHENSIVE INCOME, NET OF TAXES  
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2022 and 2021, Respectively, and $0.1 and $0.1 for the Six Months Ended June 30, 2022 and 2021, Respectively0.2 0.2 0.5 0.5 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2022 and 2021, Respectively, and $0 and $0 for the Six Months Ended June 30, 2022 and 2021, Respectively— 0.1 — 0.1 
TOTAL OTHER COMPREHENSIVE INCOME0.2 0.3 0.5 0.6 
TOTAL COMPREHENSIVE INCOME$90.2 $80.1 $160.1 $126.5 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.

65



AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Six Months Ended June 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, 20211,457.9 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 
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, 20221,553.9 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 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.

66



AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2022 and December 31, 2021
(in millions)
(Unaudited)
  June 30,December 31,
  2022 2021
CURRENT ASSETS    
Cash and Cash Equivalents$0.1 $0.1 
Restricted Cash
(June 30, 2022 and December 31, 2021 Amounts Include $29.7 and $30.4, Respectively, Related to Transition Funding and Restoration Funding)
29.7 30.4 
Advances to Affiliates640.9 6.9 
Accounts Receivable:   
Customers 167.8 123.4 
Affiliated Companies 9.8 7.9 
Accrued Unbilled Revenues101.9 77.9 
Miscellaneous 0.1 — 
Allowance for Uncollectible Accounts(4.1)(4.0)
Total Accounts Receivable 275.5 205.2 
Materials and Supplies 98.0 73.9 
Risk Management Assets0.2 — 
Accrued Tax Benefits25.1 24.8 
Prepayments and Other Current Assets 7.1 5.9 
TOTAL CURRENT ASSETS 1,076.6 347.2 
 
PROPERTY, PLANT AND EQUIPMENT   
Electric:   
Transmission 6,109.5 5,849.9 
Distribution 5,075.7 4,917.2 
Other Property, Plant and Equipment 996.6 961.1 
Construction Work in Progress 581.3 551.3 
Total Property, Plant and Equipment 12,763.1 12,279.5 
Accumulated Depreciation and Amortization 1,707.8 1,644.1 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 11,055.3 10,635.4 
 
OTHER NONCURRENT ASSETS   
Regulatory Assets 269.4 275.2 
Securitized Assets
(June 30, 2022 and December 31, 2021 Amounts Include $330.2 and $367.6, Respectively, Related to Transition Funding and Restoration Funding)
330.2 367.6 
Deferred Charges and Other Noncurrent Assets 264.4 211.3 
TOTAL OTHER NONCURRENT ASSETS 864.0 854.1 
 
TOTAL ASSETS $12,995.9 $11,836.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.
67



AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
June 30, 2022 and December 31, 2021
(in millions)
(Unaudited)
  June 30,December 31,
  2022 2021
CURRENT LIABILITIES 
Advances from Affiliates $— $26.9 
Accounts Payable: 
General 224.9 306.3 
Affiliated Companies 37.1 32.5 
Long-term Debt Due Within One Year – Nonaffiliated
(June 30, 2022 and December 31, 2021 Amounts Include $92.2 and $91, Respectively, Related to Transition Funding and Restoration Funding)
642.2 716.0 
Accrued Taxes 127.6 93.3 
Accrued Interest
(June 30, 2022 and December 31, 2021 Amounts Include $2.3 and $2.3, Respectively, Related to Transition Funding and Restoration Funding)
50.5 44.7 
Obligations Under Operating Leases14.1 14.0 
Other Current Liabilities 141.4 78.0 
TOTAL CURRENT LIABILITIES 1,237.8 1,311.7 
 
NONCURRENT LIABILITIES   
Long-term Debt – Nonaffiliated
(June 30, 2022 and December 31, 2021 Amounts Include $270.8 and $313.7, Respectively, Related to Transition Funding and Restoration Funding)
5,486.0 4,464.8 
Deferred Income Taxes 1,117.9 1,088.9 
Regulatory Liabilities and Deferred Investment Tax Credits 1,256.2 1,242.0 
Obligations Under Operating Leases56.2 61.3 
Deferred Credits and Other Noncurrent Liabilities 86.2 73.8 
TOTAL NONCURRENT LIABILITIES 8,002.5 6,930.8 
 
TOTAL LIABILITIES 9,240.3 8,242.5 
 
Rate Matters (Note 4)00
Commitments and Contingencies (Note 5) 00
 
COMMON SHAREHOLDER’S EQUITY   
Paid-in Capital 1,555.2 1,553.9 
Retained Earnings 2,206.4 2,046.8 
Accumulated Other Comprehensive Income (Loss)(6.0)(6.5)
TOTAL COMMON SHAREHOLDER’S EQUITY 3,755.6 3,594.2 
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $12,995.9 $11,836.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.
68



AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2022 and 2021
(in millions)
(Unaudited)
  Six Months Ended June 30,
  2022 2021
OPERATING ACTIVITIES    
Net Income $159.6 $125.9 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:   
Depreciation and Amortization 225.0 199.5 
Deferred Income Taxes 24.6 14.0 
Allowance for Equity Funds Used During Construction(8.0)(7.5)
Mark-to-Market of Risk Management Contracts (0.2)— 
Property Taxes(54.8)(49.7)
Change in Other Noncurrent Assets (25.9)(42.0)
Change in Other Noncurrent Liabilities 32.1 17.2 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net (70.3)(43.8)
Materials and Supplies (24.1)0.5 
Accounts Payable 17.9 (10.3)
Accrued Taxes, Net34.0 47.4 
Other Current Assets (0.8)0.7 
Other Current Liabilities 31.9 (29.3)
Net Cash Flows from Operating Activities 341.0 222.6 
 
INVESTING ACTIVITIES   
Construction Expenditures (647.6)(531.2)
Change in Advances to Affiliates, Net(634.0)(47.2)
Other Investing Activities22.3 21.3 
Net Cash Flows Used for Investing Activities (1,259.3)(557.1)
 
FINANCING ACTIVITIES   
Capital Contribution from Parent1.3 — 
Issuance of Long-term Debt – Nonaffiliated1,188.6 444.3 
Change in Advances from Affiliates, Net (26.9)(67.1)
Retirement of Long-term Debt – Nonaffiliated (242.0)(40.9)
Principal Payments for Finance Lease Obligations (3.4)(3.3)
Other Financing Activities— 0.7 
Net Cash Flows from Financing Activities 917.6 333.7 
Net Decrease in Cash, Cash Equivalents and Restricted Cash (0.7)(0.8)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period 30.5 28.8 
Cash, Cash Equivalents and Restricted Cash at End of Period $29.8 $28.0 
 
SUPPLEMENTARY INFORMATION   
Cash Paid for Interest, Net of Capitalized Amounts $88.8 $82.0 
Net Cash Paid (Received) for Income Taxes 5.9 (9.2)
Noncash Acquisitions Under Finance Leases 3.0 2.4 
Construction Expenditures Included in Current Liabilities as of June 30, 135.9 125.5 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.
69





AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
70



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 June 30,
20222021
(in millions)
Plant In Service$11,656.7 $10,660.2 
Construction Work in Progress1,680.3 1,393.4 
Accumulated Depreciation and Amortization887.8 677.1 
Total Transmission Property, Net$12,449.2 $11,376.5 

Second Quarter of 2022 Compared to Second Quarter of 2021
AEP Transmission Company, LLC and Subsidiaries
Reconciliation of Second Quarter of 2021 to Second Quarter of 2022
Net Income
(in millions)
Second Quarter of 2021$148.6 
Changes in Transmission Revenues:
Transmission Revenues(1.1)
Total Change in Transmission Revenues(1.1)
Changes in Expenses and Other:
Other Operation and Maintenance(5.7)
Depreciation and Amortization(13.3)
Taxes Other Than Income Taxes(8.6)
Interest Income0.1 
Allowance for Equity Funds Used During Construction(1.3)
Interest Expense(5.0)
Total Change in Expenses and Other(33.8)
Income Tax Expense4.8 
Second Quarter of 2022$118.5 

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

Transmission Revenues decreased $1 million primarily due to the following:
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.
These decreases were partially offset by:
A $42 million increase due to continued investment in transmission assets.


71



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

Other Operation and Maintenance expenses increased $6 million primarily due to an increase in employee-related expenses.
Depreciation and Amortization expenses increased $13 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $9 million primarily due to higher property taxes as a result of increased transmission investment.
Interest Expense increased $5 million primarily due to higher long-term debt balances.
Income Tax Expense decreased $5 million primarily due to a decrease in pretax book income partially offset by a decrease in parent company loss benefit.
72



Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021
AEP Transmission Company, LLC and Subsidiaries
Reconciliation of Six Months Ended June 30, 2021 to Six Months Ended June 30, 2022
Net Income
(in millions)
Six Months Ended June 30, 2021$300.3 
  
Changes in Transmission Revenues: 
Transmission Revenues37.6 
Total Change in Transmission Revenues37.6 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(9.8)
Depreciation and Amortization(25.8)
Taxes Other Than Income Taxes(16.4)
Interest Income0.1 
Allowance for Equity Funds Used During Construction(2.4)
Interest Expense(8.6)
Total Change in Expenses and Other(62.9)
  
Income Tax Expense(1.1)
  
Six Months Ended June 30, 2022$273.9 

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

Transmission Revenues increased $38 million primarily due to the following:
An $81 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 changed between years as follows:

Other Operation and Maintenance expenses increased $10 million primarily due to an increase in employee-related expenses.
Depreciation and Amortization expenses increased $26 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $16 million primarily due to higher property taxes as a result of increased transmission investment.
Interest Expense increased $9 million primarily due to higher long-term debt balances.


73




AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2022 and 2021
(in millions)
(Unaudited)
Three Months EndedSix Months Ended
June 30,June 30,
2022 2021 2022 2021
REVENUES
Transmission Revenues$85.6 $86.1 $172.6 $162.4 
Sales to AEP Affiliates333.9 299.0 658.9 584.6 
Provision for Refund – Affiliated(46.8)(17.6)(56.4)(17.6)
Provision for Refund – Nonaffiliated(8.3)(2.0)(10.3)(2.3)
Other Revenues— — — 0.1 
TOTAL REVENUES364.4 365.5 764.8 727.2 
EXPENSES    
Other Operation29.6 24.4 55.1 45.5 
Maintenance3.8 3.3 7.1 6.9 
Depreciation and Amortization85.7 72.4 168.8 143.0 
Taxes Other Than Income Taxes68.7 60.1 134.3 117.9 
TOTAL EXPENSES187.8 160.2 365.3 313.3 
OPERATING INCOME176.6 205.3 399.5 413.9 
Other Income (Expense):    
Interest Income - Affiliated0.2 0.1 0.3 0.2 
Allowance for Equity Funds Used During Construction15.3 16.6 30.9 33.3 
Interest Expense(39.3)(34.3)(77.0)(68.4)
INCOME BEFORE INCOME TAX EXPENSE152.8 187.7 353.7 379.0 
Income Tax Expense34.3 39.1 79.8 78.7 
NET INCOME$118.5 $148.6 $273.9 $300.3 
AEPTCo is wholly-owned by AEP Transmission Holdco.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.
74



AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY
For the Six Months Ended June 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, 2021$2,949.6 $2,247.6 $5,197.2 
  
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, 2022$2,952.4 $2,610.4 $5,562.8 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.
75



AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2022 and December 31, 2021
(in millions)
(Unaudited)
  June 30, December 31,
  2022 2021
CURRENT ASSETS    
Advances to Affiliates $134.8 $27.2 
Accounts Receivable: 
Customers 43.8 22.5 
Affiliated Companies 111.1 96.1 
Total Accounts Receivable 154.9 118.6 
Materials and Supplies 11.5 9.3 
Accrued Tax Benefits 12.0 5.6 
Assets Held for Sale171.5 167.9 
Prepayments and Other Current Assets 1.8 2.7 
TOTAL CURRENT ASSETS 486.5 331.3 
 
TRANSMISSION PROPERTY   
Transmission Property 11,225.7 10,886.3 
Other Property, Plant and Equipment 431.0 427.4 
Construction Work in Progress 1,680.3 1,394.8 
Total Transmission Property 13,337.0 12,708.5 
Accumulated Depreciation and Amortization 887.8 772.8 
TOTAL TRANSMISSION PROPERTY – NET 12,449.2 11,935.7 
 
OTHER NONCURRENT ASSETS   
Regulatory Assets 4.6 8.5 
Deferred Property Taxes 144.3 245.7 
Deferred Charges and Other Noncurrent Assets 5.2 3.2 
TOTAL OTHER NONCURRENT ASSETS 154.1 257.4 
 
TOTAL ASSETS $13,089.8 $12,524.4 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.
76



AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND MEMBER’S EQUITY
June 30, 2022 and December 31, 2021
(in millions)
(Unaudited)
  June 30, December 31,
  2022 2021
CURRENT LIABILITIES    
Advances from Affiliates $56.7 $124.0 
Accounts Payable:  
General 314.0 460.1 
Affiliated Companies 80.6 69.9 
Long-term Debt Due Within One Year – Nonaffiliated104.0 104.0 
Accrued Taxes 378.5 479.0 
Accrued Interest 29.5 28.4 
Obligations Under Operating Leases1.2 0.9 
Liabilities Held for Sale27.6 27.6 
Other Current Liabilities 20.1 3.0 
TOTAL CURRENT LIABILITIES 1,012.2 1,296.9 
 
NONCURRENT LIABILITIES   
Long-term Debt – Nonaffiliated 4,781.6 4,239.9 
Deferred Income Taxes 1,006.2 962.9 
Regulatory Liabilities 679.1 644.1 
Obligations Under Operating Leases1.9 1.3 
Deferred Credits and Other Noncurrent Liabilities 46.0 3.2 
TOTAL NONCURRENT LIABILITIES 6,514.8 5,851.4 
 
TOTAL LIABILITIES 7,527.0 7,148.3 
 
Rate Matters (Note 4) 00
Commitments and Contingencies (Note 5) 00
 
MEMBER’S EQUITY   
Paid-in Capital2,952.4 2,949.6 
Retained Earnings 2,610.4 2,426.5 
TOTAL MEMBER’S EQUITY 5,562.8 5,376.1 
 
TOTAL LIABILITIES AND MEMBER’S EQUITY $13,089.8 $12,524.4 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.
77



AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2022 and 2021
(in millions)
(Unaudited)
  Six Months Ended June 30,
  20222021
OPERATING ACTIVITIES 
Net Income $273.9 $300.3 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: 
Depreciation and Amortization 168.8 143.0 
Deferred Income Taxes 37.3 55.5 
Allowance for Equity Funds Used During Construction (30.9)(33.3)
Property Taxes 101.4 93.3 
Change in Other Noncurrent Assets 1.8 (4.5)
Change in Other Noncurrent Liabilities 44.3 10.5 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net (36.7)(22.2)
Materials and Supplies(2.2)(0.5)
Accounts Payable 13.1 0.1 
Accrued Taxes, Net (107.6)(106.2)
Other Current Assets 0.9 0.7 
Other Current Liabilities (0.9)(1.5)
Net Cash Flows from Operating Activities 463.2 435.2 
 
INVESTING ACTIVITIES   
Construction Expenditures (730.9)(719.7)
Change in Advances to Affiliates, Net (109.8)(4.5)
Other Investing Activities (8.0)(3.4)
Net Cash Flows Used for Investing Activities (848.7)(727.6)
 
FINANCING ACTIVITIES  
Capital Contributions from Member 2.8 184.0 
Issuance of Long-term Debt – Nonaffiliated540.9 — 
Change in Advances from Affiliates, Net (68.2)108.6 
Dividends Paid to Member(90.0)— 
Other Financing Activities— (0.2)
Net Cash Flows from Financing Activities 385.5 292.4 
 
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 $74.0 $66.6 
Net Cash Paid for Income Taxes 39.7 21.6 
Construction Expenditures Included in Current Liabilities as of June 30, 228.7 267.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138.
78





APPALACHIAN POWER COMPANY
AND SUBSIDIARIES
79



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 EndedSix Months Ended
 June 30,June 30,
2022202120222021
 (in millions of KWhs)
Retail:    
Residential2,223 2,172 5,755 5,867 
Commercial1,460 1,430 2,979 2,887 
Industrial2,225 2,289 4,444 4,367 
Miscellaneous205 196 418 396 
Total Retail6,113 6,087 13,596 13,517 
Wholesale262 1,274 625 2,222 
Total KWhs6,375 7,361 14,221 15,739 

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 EndedSix Months Ended
 June 30,June 30,
2022202120222021
 (in degree days)
Actual – Heating (a)94 113 1,368 1,397 
Normal – Heating (b)89 87 1,408 1,402 
Actual – Cooling (c)421 381 423 385 
Normal – Cooling (b)372 377 378 383 

(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.

80



Second Quarter of 2022 Compared to Second Quarter of 2021
Appalachian Power Company and Subsidiaries
Reconciliation of Second Quarter of 2021 to Second Quarter of 2022
Net Income
(in millions)
Second Quarter of 2021$66.3 
  
Changes in Gross Margin: 
Retail Margins49.6 
Margins from Off-system Sales(2.4)
Transmission Revenues13.7 
Other Revenues3.1 
Total Change in Gross Margin64.0 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(49.5)
Depreciation and Amortization(7.5)
Taxes Other Than Income Taxes(0.1)
Allowance for Equity Funds Used During Construction(1.7)
Non-Service Cost Components of Net Periodic Benefit Cost2.4 
Interest Expense(2.2)
Total Change in Expenses and Other(58.6)
  
Income Tax Expense18.5 
  
Second Quarter of 2022$90.2 

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 $50 million primarily due to the following:
A $41 million increase due to rider revenues in Virginia and West Virginia. This increase was partially offset in other expense items below.
An $8 million increase due to lower customer refunds related to Tax Reform. This increase was offset in Income Tax Expense below.
Transmission Revenues increased $14 million primarily due to the following:
A $10 million increase in formula rate true-up activity.
A $4 million increase in continued investment in transmission assets.
Other Revenues increased $3 million primarily due to business development revenue. This increase was partially offset in Other Operation and Maintenance expenses below.

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

Other Operation and Maintenance expenses increased $50 million primarily due to the following:
A $27 million increase in transmission expenses, primarily due to a $31 million increase in recoverable PJM expenses, partially offset by a $5 million decrease in transmission formula rate true-up activity. These items were primarily offset in Retail Margins above.
A $17 million increase in maintenance expenses at various generation plants.
A $6 million increase in distribution expenses primarily due to storm restoration expenses.
A $6 million increase in employee-related expenses.
81



These increases were partially offset by:
A $13 million decrease due to gains from the sale of land in 2022.
Depreciation and Amortization expenses increased $8 million primarily due to a higher depreciable base.
Income Tax Expense decreased $19 million primarily due to an increase in amortization of Excess ADIT, an increase in flow through tax benefits and a favorable one-time adjustment recognized in 2022. This increase was partially offset in Retail Margins above.

82



Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021
Appalachian Power Company and Subsidiaries
Reconciliation of Six Months Ended June 30, 2021 to Six Months Ended June 30, 2022
Net Income
(in millions)
Six Months Ended June 30, 2021$188.8 
 
Changes in Gross Margin: 
Retail Margins119.6 
Margins from Off-system Sales(4.0)
Transmission Revenues17.7 
Other Revenues4.5 
Total Change in Gross Margin137.8 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(92.9)
Depreciation and Amortization(16.9)
Taxes Other Than Income Taxes(2.6)
Interest Income(0.2)
Allowance for Equity Funds Used During Construction(3.2)
Non-Service Cost Components of Net Periodic Benefit Cost5.0 
Interest Expense(1.6)
Total Change in Expenses and Other(112.4)
  
Income Tax Expense(3.8)
  
Six Months Ended June 30, 2022$210.4 

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 $120 million primarily due to the following:
An $86 million increase due to rider revenues in Virginia and West Virginia. This increase was partially offset in other expense items below.
A $19 million increase in weather-normalized margins primarily driven by increases in the residential and commercial classes.
An $18 million increase due to lower customer refunds related to Tax Reform. This increase was offset in Income Tax Expense below.
Margins from Off-system Sales decreased $4 million primarily due to favorable hedging activity and available generation at above average pricing in the first quarter of 2021.
Transmission Revenues increased $18 million primarily due to the following:
A $10 million increase due to formula rate true-up activity.
An $8 million increase due to continued investment in transmission assets.
Other Revenues increased $5 million primarily due to business development revenue. This increase was partially offset in Other Operation and Maintenance expenses below.


83



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

Other Operation and Maintenance expenses increased $93 million primarily due to the following:
A $63 million increase in transmission expenses primarily due to a $74 million increase in recoverable PJM expenses, partially offset by an $8 million decrease in 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 $10 million increase in distribution expenses primarily related to storm restoration costs.
An $8 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.
Depreciation and Amortization expenses increased $17 million primarily due to a higher depreciable base.
Allowance for Equity Funds Used During Construction decreased $3 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 $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.
Income Tax Expense increased $4 million primarily due to an increase in pretax book income and a decrease in amortization of Excess ADIT, partially offset by an increase in flow through tax benefits and a favorable one-time adjustment recognized in 2022. The decrease in amortization of Excess ADIT was partially offset in Retail Margins above.




84





APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2022 and 2021
(in millions)
(Unaudited)
 Three Months EndedSix Months Ended
 June 30,June 30,
 2022202120222021
REVENUES    
Electric Generation, Transmission and Distribution$704.9 $636.5