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Appalachian Power

Filed: 22 Apr 21, 8:10am


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

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended March 31, 2021
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 UnitsAEPPLThe 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
April 22, 2021
 
American Electric Power Company, Inc.499,750,400 
 ($6.50 par value)
AEP Texas Inc.100 
($0.01 par value)
AEP Transmission Company, LLC (a)NA
Appalachian Power Company13,499,500 
 (no par value)
Indiana Michigan Power Company1,400,000 
 (no par value)
Ohio Power Company27,952,473 
 (no par value)
Public Service Company of Oklahoma9,013,000 
 ($15 par value)
Southwestern Electric Power Company3,680 
 ($18 par value)

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



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF QUARTERLY REPORTS ON FORM 10-Q
March 31, 2021
   
  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. 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 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.
AMIAdvanced Metering Infrastructure.
AMRAutomated Meter Reading.
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.
ASUAccounting Standards Update.
CAAClean Air Act.
CARES ActCoronavirus Aid, Relief, and Economic Security Act signed into law in March 2020.
CCRCoal Combustion Residual.
CLECOCentral Louisiana Electric Company, a nonaffiliated utility company.
CO2
 Carbon dioxide and other greenhouse gases.
Conesville PlantA retired, single unit coal-fired generation plant totaling 651 MW located in Conesville, Ohio. The plant was jointly-owned by AGR and a nonaffiliate.
Cook Plant Donald C. Cook Nuclear Plant, a two-unit, 2,288 MW nuclear plant owned by I&M.
COVID-19Coronavirus 2019, a highly infectious respiratory disease. In March 2020, the World Health Organization declared COVID-19 a worldwide pandemic.
CSAPRCross-State Air Pollution Rule.
CWIP Construction Work in Progress.
DCC FuelDCC Fuel IX, DCC Fuel X, DCC Fuel XI, DCC Fuel XII, DCC Fuel XIII, DCC Fuel XIV and DCC Fuel XV, consolidated VIEs formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
i


TermMeaning
   
DHLC Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo. DHLC is a non-consolidated VIE of SWEPCo.
DIRDistribution Investment Rider.
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.
ESP Electric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO.
ETTElectric Transmission Texas, LLC, an equity interest joint venture between AEP Transmission Holdco and Berkshire Hathaway Energy Company formed to own and operate electric transmission facilities in ERCOT.
Excess ADITExcess accumulated deferred income taxes.
FACFuel Adjustment Clause
FASB Financial Accounting Standards Board.
Federal EPAUnited States Environmental Protection Agency.
FERC Federal Energy Regulatory Commission.
FGD Flue Gas Desulfurization or scrubbers.
FIPFederal Implementation Plan.
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.
KWhKilowatt-hour.
LPSC Louisiana Public Service Commission.
MATSMercury and Air Toxic Standards.
MISO Midcontinent Independent System Operator.
MMBtu Million British Thermal Units.
MPSCMichigan Public Service Commission.
MTM Mark-to-Market.
MW Megawatt.
MWh Megawatt-hour.
NAAQSNational Ambient Air Quality Standards.
Nonutility Money Pool Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
North Central Wind Energy FacilitiesA joint PSO and SWEPCo project, which includes three Oklahoma wind facilities totaling approximately 1,485 MWs of wind generation.
NOx
Nitrogen oxide.
NSR New Source Review.
OCC Corporation Commission of the State of Oklahoma.
Oklaunion Power StationA retired, single unit coal-fired generation plant totaling 650 MW located in Vernon, Texas. The plant was jointly-owned by AEP Texas, PSO and certain nonaffiliated entities.
OPCo Ohio Power Company, an AEP electric utility subsidiary.
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TermMeaning
   
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.
PATH-WVPATH West Virginia Transmission Company, LLC, a joint venture owned 50% by FirstEnergy and 50% by AEP.
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.
RacineA generation plant consisting of two hydroelectric generating units totaling 48 MWs located in Racine, Ohio and owned by AGR.
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.
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.
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.
iii


TermMeaning
   
Transition Funding AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation. In July 2020, the final AEP Texas Central Transition Funding II securitization bond matured.
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.
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 1 – 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, electricity usage, employees, customers, service providers, vendors and suppliers.
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 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 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.
Evolving public perception of 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.
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.
v


Accounting standards periodically issued by accounting standard-setting bodies.
Other risks and unforeseen events, including wars, 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 2020 Annual Report and in Part II of this report.

Investors should note that the Registrants announce material financial information in SEC filings, press releases and public conference calls. Based on guidance from the SEC, the Registrants may use the Investors section of AEP’s website (www.aep.com) to communicate with investors about the Registrants. It is possible that the financial and other information posted there could be deemed to be material information. The information on AEP’s website is not part of this report.
vi




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

EXECUTIVE OVERVIEW

Impacts of Severe Winter Weather

In February 2021, severe winter weather impacted the service territories of APCo, KPCo, PSO and SWEPCo resulting in power outages, extensive damage to infrastructure and disruptions to SPP market conditions. Impacts of the severe winter weather are included below. See Note 4 - Rate Matters for additional information.

Storm Restoration Costs

The impact of the severe winter weather resulted in power outages and extensive damage to transmission and distribution infrastructures across the service territories of APCo, KPCo and SWEPCo. As of March 31, 2021, an estimated $57 million of capital expenditures and $137 million of restoration expenses have been incurred related to the severe winter weather. Approximately $131 million of the expenses represent incremental restoration expenses and have been deferred as regulatory assets. The KPSC and LPSC issued orders authorizing the deferral of incremental restoration expenses as regulatory assets. APCo and KPCo intend to seek recovery of these restoration costs in their next respective base rate cases while SWEPCo is expected to seek recovery in a separate filing. If any of the restoration costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Impacts in SPP

The severe winter weather also 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.

Retail Customers

As of March 31, 2021, PSO and SWEPCo have deferred regulatory assets of $689 million and $496 million, respectively, relating to estimated natural gas expenses and purchases of electricity incurred from February 9, 2021, to February 20, 2021, as a result of severe winter weather. These amounts represent estimates as of March 31, 2021, and are subject to final settlement as additional information becomes available. PSO and SWEPCo have active fuel clauses that allow for the recovery of prudently incurred fuel and purchased power expenses. Given the significance of these costs, PSO and SWEPCo expect the costs to be subject to prudency reviews. Management believes these costs are probable of future recovery, but expects the recovery period to be extended to mitigate the impact on customer bills.

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. Accordingly, in April 2021, SWEPCo began recovery of its Arkansas jurisdictional share of these fuel costs, which are subject to true-up by the APSC. Also in April 2021, SWEPCo filed testimony supporting a five-year recovery with a pretax rate of return of 6.05%. A hearing is expected in the third quarter of 2021. A separate proceeding will address the prudency of the fuel costs.

Also in March 2021, the LPSC approved a special order granting a temporary modification to the FAC that allows SWEPCo to recover the Louisiana jurisdictional share of the retail fuel costs over a longer period. In April 2021, SWEPCo began recovery of its Louisiana jurisdictional share of these fuel costs based on a five year recovery
1


period. SWEPCo will work with the LPSC to finalize the actual recovery period and determine the appropriate carrying charge in future proceedings.

In April 2021, the OCC approved a waiver for PSO allowing the deferral of the extraordinary fuel and purchase of electricity costs, including carrying costs, over a longer time period than what the FAC traditionally allows. A time frame for recovery and the appropriate carrying charge will be decided at a later date. Also in April 2021, legislation was introduced in Oklahoma proposing to securitize the extraordinary fuel and purchase of electricity costs impacting the utilities within the state. Under the proposal, the State of Oklahoma would issue securitization bonds and provide the proceeds to utilities to recover their share of the costs. PSO will continue to evaluate and monitor the advancement of the proposed legislation.

SWEPCo expects to make a filing with the PUCT in the second quarter of 2021 to seek a recovery mechanism and an appropriate carrying charge for the Texas jurisdictional share of the retail fuel costs.

Wholesale Customers

SWEPCo is also working with certain wholesale customers to establish payment terms for $88 million of accounts receivable resulting from the severe winter weather events. Management believes these receivables are probable of future collection.

PSO and SWEPCo Cash Flow Implications

PSO and SWEPCo evaluated financing alternatives to address the timing difference between the payment of the estimated natural gas expenses and purchases of electricity to suppliers and subsequent recovery from customers. In March 2021, PSO drew $100 million on its revolving credit facility and SWEPCo issued $500 million of Senior Unsecured Notes. In March 2021, Parent entered into a $500 million 364-day Term Loan and borrowed the full amount. The proceeds from this loan were used to help fund capital contributions to PSO and SWEPCo totaling $425 million and $100 million, respectively. In April 2021, PSO received an additional capital contribution from Parent of $125 million to further address these costs.

Although the February 2021 severe winter weather did not materially impact AEP’s results of operations for the three months ended March 31, 2021, if either PSO or SWEPCo is unable to recover these fuel and purchased power costs, or obtain authorization of a reasonable carrying charge on these costs, it could reduce future net income and cash flows and impact financial condition.

ERCOT

In response to the extreme winter weather event, the Governor of Texas issued a Declaration of a State of Disaster for all counties in Texas. To assist with a return to normalcy, the PUCT issued an order that placed a temporary moratorium on customer disconnections due to non-payment for transmission and distribution utilities. This moratorium will be in effect until otherwise ordered by the PUCT. If related costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

COVID-19

In 2020, COVID-19 was declared a pandemic by the World Health Organization and the Centers for Disease Control and Prevention. Its rapid spread around the world and throughout the United States prompted many countries, including the United States, to institute restrictions on travel, public gatherings and certain business operations. These restrictions significantly disrupted economic activity in AEP’s service territory and resulted in reduced demand for energy, particularly from commercial and industrial customers. Management expects weather-normalized customer demand to continue to improve during 2021 as additional vaccinations occur and economic activity improves. However, if the severity of the economic disruption increases, AEP’s future results of operations, financial condition, and cash flows could be further adversely impacted.

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During 2020, AEP’s electric operating companies informed both retail customers and state regulators that disconnections for non-payment were temporarily suspended. Shortly thereafter, AEP’s state regulators also imposed temporary moratoria on customary disconnection practices. As of March 31, 2021, AEP’s electric operating companies have resumed customary disconnection practices in all regulated jurisdictions with the exception of Arkansas and Virginia. In March 2021, the APSC issued an order allowing electric utilities in Arkansas to begin disconnections for non-payment beginning on May 3, 2021. AEP continues to work with regulators and stakeholders in Virginia and management currently anticipates resuming customary disconnection practices in the third quarter of 2021. Continuing adverse economic conditions may result in the inability of customers to pay for electric service, which could affect revenue recognition and the collectability of accounts receivable.

The Registrants continue to review current accounts receivable collection experience with historical trends, specifically reviewing metrics such as cash collections, days sales outstanding, daily customer deposits, and aging summaries. In addition, the Registrants reviewed historical loss information generally comprised of a rolling 12-month average, in conjunction with a qualitative assessment of elements that impact the collectability of receivables, such as changes in economic factors, regulatory matters, industry trends, customer credit factors, payment plan options and other programs available to customers. AEP has been and continues to be proactive in engaging with customers to collect payments or establish payment arrangements for outstanding balances. As of March 31, 2021, AEP currently does not expect accounts receivable aging to have a material adverse impact on the Registrants’ allowance for uncollectible accounts based on considerations of the COVID-19 impacts and past trends during times of economic instability. Management continues to monitor developments that could have an impact on customer collections.

Market volatility and delayed customer accounts receivable collections due to the expansion of customer payment arrangements could reduce cash from operations and cause an adverse impact to liquidity. As of March 31, 2021, AEP’s available liquidity was $3.4 billion. Management believes the Registrants have adequate liquidity under existing credit facilities. To the extent that future access to the capital markets or the cost of funding is adversely affected by COVID-19, future results of operations, financial condition, and cash flows may be adversely impacted.

The Registrants continue to take steps to mitigate the potential risks to customers, suppliers and employees posed by the spread of COVID-19. The Registrants have updated and implemented a company-wide pandemic plan to address specific aspects of COVID-19. This plan guides emergency response, business continuity, and the precautionary measures AEP is taking on behalf of its employees and the public. The Registrants continue to take extra precautions for employees who work in the field and for employees who work in their facilities, and have work from home policies where appropriate. The Registrants will continue to monitor developments affecting both their workforce and customers, and will take additional precautions that management determines are necessary in order to mitigate the impacts. AEP continues to focus on providing safe, uninterrupted service to its customers, which includes the implementation of strong physical and cyber-security measures to ensure that its systems remain functional with a partially remote workforce. As of March 31, 2021, there has been no material adverse impact to the Registrants’ business operations and customer service due to remote work. Management will continue to review and modify plans as conditions change. Despite efforts to manage these impacts to the Registrants, the ultimate impact of COVID-19 also depends on factors beyond management’s knowledge or control, including the duration and severity of this outbreak as well as third-party actions taken to contain its spread and mitigate its public health effects. Therefore, management cannot estimate the potential future impact to financial position, results of operations and cash flows, but the impacts could be material.


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Customer Demand

AEP’s weather-normalized retail sales volumes for the first quarter of 2021 decreased by 1.9% from the first quarter of 2020. Weather-normalized residential sales increased by 1.5% in the first quarter of 2021 from the first quarter of 2020. AEP’s first quarter 2021 industrial sales volumes decreased by 6.1% compared to the first quarter of 2020. The decline in industrial sales was spread across many industries. Industrial sales were also negatively impacted by the severe winter event in AEP’s western operating territories in February 2021. Weather-normalized commercial sales decreased 1.6% in the first quarter of 2021 from the first quarter of 2020.

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, (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 and (c) the reasonableness and prudency of APCo’s investments in AMI meters.

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 on APCo’s ability 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 of its decisions from the November 2020 order and rejecting the various requests for reconsideration from APCo and an intervenor. In confirming its decision to reject an intervenor’s recommendation that APCo’s AMI costs incurred during the triennial period be disallowed, the Virginia SCC clarified that APCo established the need to replace its existing AMR meters, and that based on the uncertainty surrounding the continued manufacturing and support of AMR technology, APCo reasonably chose to replace them with AMI meters. In March 2021, APCo filed a notice of appeal of the reconsideration order with the Virginia Supreme Court. APCo expects to submit its brief before the Virginia Supreme Court in the second or third quarter of 2021.

In April 2021, and in conjunction with APCo’s November 2020 and March 2021 appeals with the Virginia Supreme Court, APCo filed a petition for interim rates with the Virginia Supreme Court (subject to refund with interest and supported by a bond issuance) requesting a $40 million increase in annual APCo Virginia base rates. APCo submitted this filing based on Virginia law that allows the Virginia Supreme Court to authorize interim rates until the final disposition on APCo’s appeals. APCo also requested an expedited schedule from the Virginia Supreme Court on APCo’s appeals.

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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 appeals regarding treatment of the closed coal plants are granted by the Virginia Supreme Court, it could initially reduce future net income and impact financial condition.

2020 Ohio Base Rate Case - In June 2020, OPCo filed a request with the PUCO for a $42 million annual increase in base rates based upon a proposed 10.15% ROE net of existing riders. In March 2021, OPCo, the PUCO staff and various intervenors filed a joint stipulation and settlement agreement with the PUCO based upon an annual revenue decrease of $68 million and an ROE of 9.7%. The difference between OPCo’s requested annual base rate increase and the agreed upon decrease is primarily due to a reduction in the requested ROE, the removal of proposed future energy efficiency costs and a decrease in vegetation management expenses moved to recovery in riders. In addition, the joint stipulation and settlement agreement includes an increased fixed monthly residential customer charge, the discontinuation of rate decoupling and the continuation of the DIR with annual revenue caps of $57 million in 2021, $91 million in 2022, $116 million in 2023 and $51 million for the first five months of 2024. Annual revenue caps for the DIR can be increased if OPCo achieves certain reliability standards. A hearing is scheduled with the PUCO in May 2021.

Hurricane Laura - In August 2020, Hurricane Laura hit the coasts of Louisiana and Texas, causing power outages to more than 130,000 customers across SWEPCo’s service territories. Prior to Hurricane Laura, SWEPCo did not have a catastrophe reserve or automatic deferral authority within any of its jurisdictions. In October 2020, the LPSC issued an order allowing Louisiana utilities, including SWEPCo, to establish a regulatory asset to track and defer expenses associated with Hurricane Laura. In October 2020, as part of the 2020 Texas Base Rate Case, SWEPCo requested deferral authority of incremental other operation and maintenance expenses. As of March 31, 2021, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $82 million ($79 million of which has been deferred as a regulatory asset related to the Louisiana jurisdiction) and incremental capital expenditures of $31 million, all of which is related to the Louisiana jurisdiction. Management expects to request recovery of these storm costs in a filing inclusive of SWEPCo’s various other storm costs.

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. 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. The Texas Supreme Court’s opinion agrees with the PUCT’s judgment affirming the prudence of the Turk Plant. Motions for rehearing were due April 12, 2021 and no party filed a timely motion. As of March 31, 2021, the net book value of Turk Plant was $1.4 billion, before cost of removal, including materials and supplies inventory and CWIP. SWEPCo’s Texas jurisdictional share of the Turk Plant investment is approximately 33%.

In July 2019, clean energy legislation from 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 phased out current energy efficiency programs as of December 31, 2020, including shared savings revenues of $26 million annually and renewable mandates after 2026. HB 6 also provided for the recovery of existing renewable energy contracts on a bypassable basis through 2032 and included a provision for recovery of OVEC costs through 2030 which will be allocated to all electric distribution utilities 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 a racketeering
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conspiracy involving the adoption of HB 6. Certain defendants in that case have since pleaded guilty. In August 2020, an AEP shareholder filed a putative class action lawsuit against AEP and certain of its officers for alleged violations of securities laws in connection with HB 6. In January and February 2021, two AEP shareholders filed two derivative actions purporting to assert claims on behalf of AEP against certain AEP officers and directors based on allegations similar to those in the putative securities class action. In April 2021, another similar derivative action asserting claims on behalf of AEP against certain AEP officers and directors was filed. 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, rescinded 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, goes into effect after 90 days 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 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 securities class action or the derivative actions, it could reduce future net income and cash flows and impact financial condition.

In April 2020, the Virginia Clean Economy Act was signed into law by the Virginia Governor and became effective in July 2020. The law includes the following requirements: (a) Virginia electric utilities to retire no later than 2045 all electric generating units located in Virginia that emit carbon as a by-product, (b) APCo to produce 100% of the company’s power to serve Virginia customers from renewable sources by 2050 with increasing percentages of mandatory renewable energy sources each year and (c) Virginia electric utilities to achieve increasing annual energy efficiency savings from 2022-2025 using 2019 as the base year. This law also provides that if the Virginia SCC finds in any triennial review that revenue reductions related to energy efficiency programs approved and deployed since the utility's previous triennial review have caused the utility to earn more than 70 basis points below its authorized rate of return, the Virginia SCC shall order increases to the utility's rates necessary to recover such revenue reductions. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

In December 2020, APCo and WPCo filed a proposal with the WVPSC to implement an investment tracker surcharge mechanism for recovering costs associated with capital investment made between base rate cases. The initial filing requests a total annual increase of $50 million ($41 million related to APCo), which represents recovery of costs associated with infrastructure investments made over an approximate three-year period since the companies’ last base rate case filing in 2018. The filing also proposes that APCo and WPCo could submit annual filings with requested increases capped to a percentage of total retail revenues (3.5% in the first year and 3% in subsequent filings with an overall cap of 9.5%). If a future base rate case is filed, the surcharge would reset to zero on implementation of the new rates. In January 2021, WVPSC staff filed a motion recommending that the WVPSC reject the proposal. The WVPSC deferred ruling on the staff motion and established a procedural schedule, which includes testimony from all parties to be received in May 2021 and a hearing is scheduled for June 2021. If APCo and WPCo do not receive approval to recover these incremental investments through the proposed tracker surcharge mechanism between base rate cases, it could cause a temporary reduction in future net income and cash flows and impact financial condition until APCo and WPCo can seek approval in their next base rate case.

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 requires 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
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compliance filing to eliminate the incentive from its tariff prospectively. The supplemental NOPR is subject to a 30 day comment period followed by a 15 day period for reply comments. A final rule is expected in the fourth quarter of 2021.

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

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

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’ pending base rate case proceedings in 2021. See Note 4 - Rate Matters for additional information.

Completed Base Rate Case Proceedings

Approved RevenueApprovedNew Rates
CompanyJurisdictionRequirement IncreaseROEEffective
(in millions)
KPCoKentucky$52.7 (a)9.3%January 2021

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

Pending Base Rate Case Proceedings
Commission Staff/
FilingRequested RevenueRequestedIntervenor Range of
CompanyJurisdictionDateRequirement IncreaseROERecommended ROE
(in millions)
OPCoOhioJune 2020$42.3 10.15%8.76%-9.78%(a)
SWEPCoTexasOctober 2020105.0 (b)10.35%9%-9.22%(c)
SWEPCoLouisianaDecember 2020134.0 10.35%(d)

(a)In March, 2021 a joint stipulation and settlement agreement was filed with the PUCO which included a $68 million decrease in base rates based upon an ROE of 9.7%.
(b)The request would move transmission and distribution interim revenues recovered through riders into base rates. Eliminating these riders would result in a net annual requested base rate increase of $90 million primarily due to increased investments.
(c)Staff and intervenor recommended base rate increases ranged from $20 million to $70 million.
(d)Awaiting procedural schedule.
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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

AEP continues to develop its renewable portfolio within the Generation & Marketing segment.  Activities include 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 develops and/or acquires large scale renewable generation projects that are backed with long-term contracts with creditworthy counterparties.

In November 2020, AEP signed a Purchase and Sale Agreement with a nonaffiliate to acquire a 75% interest in the 100 MW Dry Lake Solar Project located in southern Nevada for approximately $114 million. The transaction closed in the first quarter of 2021 and the solar project is expected to be in-service in the second quarter of 2021. See Note 6 - Acquisitions for additional information.

As of March 31, 2021, subsidiaries within AEP’s Generation & Marketing segment had approximately 1,549 MWs of contracted renewable generation projects in-service.  In addition, as of March 31, 2021, these subsidiaries had approximately 239 MWs of renewable generation projects under construction with total estimated capital costs of $349 million related to these projects.

Regulated Renewable Generation Facilities

In 2020, PSO received approval from the OCC and SWEPCo received approval from the APSC and LPSC to acquire the North Central Wind Energy Facilities, comprised of three Oklahoma wind facilities totaling 1,485 MWs, on a fixed cost turn-key basis at completion. Both the APSC and LPSC approved the flex-up option, agreeing to acquire the Texas portion, which the PUCT denied. PSO will own 45.5% and SWEPCo will own 54.5% of the project, which will cost approximately $2 billion.

In May 2020, the IRS issued a notice extending the “Continuity Safe Harbor” deadlines for qualifying renewable energy projects that began construction in 2016 and 2017 by one year as many projects are facing supply chain and other project development delays caused by COVID-19. Under the May 2020 IRS notice, qualifying renewable energy projects that began construction in 2016 and 2017 and which are placed in-service by the end of 2021 and 2022, respectively, will satisfy the Continuity Safe Harbor. Provided that each facility does satisfy the Continuity Safe Harbor, under the current IRS guidance, the 199 MW wind facility will qualify for 100% of the federal PTC, and the remaining two wind facilities, totaling 1,286 MWs, will qualify for 80% of the federal PTC.

In April 2021, the 199 MW wind facility was acquired and placed in-service with an estimated investment of $307 million. The 287 MW wind facility is targeted to be acquired and placed in-service in December 2021 and the 999 MW wind facility is targeted to be acquired and placed in-service between December 2021 and April 2022. See Note 6 - Acquisitions for additional information.

Strategic Evaluation of KPCo

AEP has initiated a strategic evaluation for its ownership in KPCo, a wholly-owned regulated generation, transmission and distribution utility with approximately 166,000 retail customers in eastern Kentucky. Potential alternatives may include continued ownership or a sale of KPCo. Management has not made a decision regarding the potential alternatives, but expects a decision will be made during 2021. As of March 31, 2021, KPCo has total assets of approximately $2.7 billion and total equity of approximately $837 million.

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Racine

In February 2021, AEP signed an agreement to sell Racine to a nonaffiliated party. As of March 31, 2021, the net book value of Racine was $45 million. The sale of Racine requires approval from the FERC and the U.S. Army Corps of Engineers. The sale is expected to close in the second quarter of 2021 and result in an immaterial gain. Racine was not presented as Held for Sale on AEP’s balance sheets due to immateriality.

Dolet Hills Power Station and Related Fuel Operations

During the second quarter of 2019, the Dolet Hills Power Station initiated a seasonal operating schedule. In January 2020, in accordance with the terms of SWEPCo’s settlement of its base rate review filed with the APSC, management announced that SWEPCo will seek regulatory approval to retire the Dolet Hills Power Station by the end of 2026. DHLC provides 100% of the fuel supply to Dolet Hills Power Station. After careful consideration of current economic conditions, and particularly for the benefit of their customers, 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. Based on these actions, management revised the estimated useful life of DHLC’s and Oxbow’s assets to coincide with the date at which extraction was discontinued in the second quarter of 2020 and the date at which delivery of lignite is expected to cease in September 2021. Management also revised the useful life of the Dolet Hills Power Station to 2021 based on the remaining estimated fuel supply available for continued seasonal operation. In March 2020, primarily due to the revision in the useful life of DHLC, SWEPCo recorded a revision to increase estimated ARO liabilities by $21 million. In April 2020, SWEPCo and CLECO jointly filed a notification letter to the LPSC providing notice of the cessation of lignite mining.

The Dolet Hills Power Station costs are recoverable by SWEPCo through base rates. SWEPCo’s share of the net investment in the Dolet Hills Power Station is $150 million, including CWIP and materials and supplies, before cost of removal.

Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses. Under the fuel agreements, SWEPCo’s fuel inventory and unbilled fuel costs from mining related activities were $126 million as of March 31, 2021. Also, as of March 31, 2021, SWEPCo had a net over-recovered fuel balance of $20 million, excluding impacts of the February 2021 severe winter weather event, which includes fuel consumed at the Dolet Hills Power Station. Additional operational and land-related costs are expected to be incurred by DHLC and Oxbow and billed to SWEPCo prior to the closure of the Dolet Hills Power Station and recovered through fuel clauses.

In June 2020, SWEPCo filed a fuel reconciliation with the PUCT for its retail operations in Texas, including Dolet Hills, for the reconciliation period of March 1, 2017 to December 31, 2019. See “2020 Texas Fuel Reconciliation” section of Note 4 for additional information.

In October 2020, SWEPCo filed a request with the LPSC seeking approval to close the mines and to recover the Louisiana jurisdictional share of the additional fuel costs. 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 March 2021, the APSC approved fuel rates that provide recovery of 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 November 2020, management announced plans to retire the Pirkey Power Plant in 2023. The Pirkey Power Plant costs are recoverable by SWEPCo through base rates. SWEPCo’s share of the net investment in the Pirkey Power Plant is $209 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 $163 million as of March 31, 2021. Also, as of March 31, 2021, SWEPCo had a net over-recovered fuel balance of $20 million, excluding impacts of the February 2021 severe winter weather event, which includes fuel consumed at the Pirkey Power Plant. Additional operational costs are expected to be incurred by Sabine and billed to SWEPCo, as well as land-related costs incurred by SWEPCo, prior to the closure of the Pirkey Power Plant and recovered through fuel clauses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.


LITIGATION

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

Rockport Plant Litigation

In 2013, the Wilmington Trust Company filed a complaint 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 seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs.  The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio.

AEGCo and I&M sought and were granted dismissal by the U.S. District Court for the Southern District of Ohio of certain of the plaintiffs’ claims, including claims for compensatory damages, breach of contract, breach of the implied covenant of good faith and fair dealing and indemnification of costs. Plaintiffs voluntarily dismissed the surviving claims that AEGCo and I&M failed to exercise prudent utility practices with prejudice, and the court issued a final judgment. The plaintiffs subsequently filed an appeal in the U.S. Court of Appeals for the Sixth Circuit.

In 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion and judgment affirming the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims, reversing the district court’s dismissal of the breach of contract claims and remanding the case for further proceedings.

Thereafter, AEP filed a motion with the U.S. District Court for the Southern District of Ohio in the original NSR litigation, seeking to modify the consent decree. The district court granted the owners’ unopposed motion to stay the lease litigation to afford time for resolution of AEP’s motion to modify the consent decree. The consent decree was modified based on an agreement among the parties in July 2019. The district court’s stay of the lease litigation expired in August 2020. Upon expiration of the stay, plaintiffs filed a motion for partial summary judgment,
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arguing that the consent decree violates the facility lease and the participation agreement and requesting that the district court enter a judgment for the plaintiffs on their breach of contract claim. AEP’s memorandum in opposition to plaintiffs’ motion for partial summary judgment was filed in October 2020. At the parties’ request, the district court stayed the case until April 19, 2021 to provide the parties an opportunity to resolve the case. See “Obligations under the New Source Review Litigation Consent Decree” section below for additional information.

On April 20, 2021, I&M and AEGCo reached an agreement to acquire 100% of the interests in Rockport Plant, Unit 2 for $115.5 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. As a result, the parties have submitted a stipulation and order of dismissal requesting that the district court dismiss the case without prejudice to plaintiffs asserting their claims in a re-filed action or in a new action. The agreement is subject to customary closing conditions, including regulatory approvals, and as of the closing will result in a final settlement of, and release of claims in, the lease litigation. Management believes its financial statements appropriately reflect the expected resolution of the pending litigation.

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

The American Electric Power System Retirement Plan (the Plan) has received a letter written on behalf of four participants (the Claimants) making a claim for additional plan benefits and purporting to advance such claims on behalf of a class. 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 Claimants have asserted claims 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) the company failed to provide required notice regarding the changes to the Plan.  AEP has responded to the Claimants providing a reasoned explanation for why each of their claims have been denied. The denial of those claims was appealed to the AEP System Retirement Plan Appeal Committee and the Committee upheld the denial of claims. Management will continue to defend against the claims.  Management is unable to determine a range of potential losses that is reasonably possible of occurring.

Litigation Related to Ohio House Bill 6 (HB 6)

In 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 alleges 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 seeks monetary damages, among other forms of relief. The company will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

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. 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 company 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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On March 1, 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, the Company 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 AEP Board will act in response to the letter as appropriate. Management is unable to determine a range of potential losses that is reasonably possible of occurring.


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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.  AEP, along with other parties, challenged a portion of the Federal EPA requirements.  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 March 31, 2021, the AEP System owned generating capacity of approximately 24,600 MWs, of which approximately 12,100 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 $350 million to $700 million through 2027.

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 and (g) 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.

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
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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 postpones 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.

In January 2021, the Federal EPA finalized a revised CSAPR rule, which substantially reduces the ozone season NOX budgets in 2021-2024. Management believes it can meet the requirements of the rule in the near term, and is evaluating its compliance options for later years, when the budgets are further reduced.

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. Management is unable to predict how the Federal EPA will respond to the court’s remand.

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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 2020 were approximately 44 million metric tons, a 73% 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 has led to the announcement of early plant closures and could force AEP to close additional coal-fired generation facilities earlier than their estimate useful life. If AEP is unable to recover the costs of its investments, it would reduce future net income and cash flows and impact financial condition.

Coal Combustion Residual 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 CCR landfills and surface impoundments at operating electric utility or independent generation facilities.

In August 2020, the Federal EPA revised the CCR rule to include a requirement that unlined CCR storage ponds cease operations and initiate closure by April 11, 2021. The revised rule provides two options that allow facilities to extend the date by which they must cease receipt of coal ash and close the ponds.
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The first option provides an extension to cease receipt of CCR no later than October 15, 2023 for most units, and October 15, 2024 for a narrow subset of units; however, the Federal EPA’s grant of such an extension will be based 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)
APCoAmos2,930$2,149.4 2040
APCoMountaineer1,320971.2 2040
SWEPCoFlint Creek Plant258275.7 2038
KPCoMitchell Plant780599.9 2040
WPCoMitchell Plant780597.9 2040
AEGCoRockport Plant, Unit 1655242.2 2028
I&MRockport Plant, Unit 1655558.2 (b)2028

(a)Net book value before cost of removal including CWIP and inventory.
(b)Amount includes a $186 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 December 2020, APCo filed requests with the Virginia SCC and WVPSC to obtain the regulatory approvals necessary to implement the compliance plans and seek recovery of the estimated $240 million investment for the Amos and Mountaineer plants. 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 the compliance plans and seek recovery of the estimated $132 million investment for the Mitchell Plant. Within those requests, WPCo and KPCo also filed a $25 million alternative with the WVPSC and KPSC, respectively, which would allow the Mitchell Plant to continue operating only through 2028.

The second option is a retirement option, which provides a generating facility an extended operating time without developing alternative CCR disposal. Under the retirement option, a generating facility would have until October 17, 2023 to cease operation 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$178.3 $30.8 2023 (b)
SWEPCoWelsh Plants, Units 1 and 31,053528.8 14.2 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.

AEP may incur significant costs to upgrade or close and replace surface impoundments and landfills used to manage CCR and to conduct any required remedial actions. Under the retirement option above, AEP may need to recover remaining depreciation and estimated closure costs associated with retiring 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 retiring plants in a timely manner, it would reduce future net income and cash flows and impact financial condition.

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Closure and post-closure costs have been included in ARO in accordance with the requirements in the final 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, which could include costs to remove ash from some unlined units.

If removal of ash is required without providing similar assurances of cost recovery in regulated jurisdictions, it would impose significant additional operating costs on AEP, which could lead to increased financing costs and liquidity needs. Other units in Virginia, Ohio, West Virginia and Kentucky have already been closed in place in accordance with state law programs. Management will continue to participate in rulemaking activities and make adjustments based on new federal and state requirements affecting its ash disposal units.

Clean Water Act Regulations

The Federal EPA’s ELG rule for generating facilities establishes limits on 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 recent 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. Permit modifications for affected facilities were filed in January 2021 that reflect the outcome of that assessment.

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 costs 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.

In addition to the November 2020 announcement related to the Federal EPA’s CCR rules, management also decided not to renew the Rockport Plant, Unit 2 lease when it expires in 2022. Previously, management retired or announced early closure plans for Welsh Unit 2, Oklaunion Power Station, Dolet Hills Power Station and Northeastern Plant Unit 3.


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The table below summarizes the net book value, as of March 31, 2021, of generating facilities retired or planned for early retirement:
CompanyPlantNet
Investment (a)
Accelerated Depreciation Regulatory AssetActual/Projected
Retirement
Date
Current Authorized
Recovery
Period
Annual Depreciation (b)
(in millions)(in millions)
SWEPCoDolet Hills Power Station$51.3 $92.6 2021(c)$7.7 
PSONortheastern Plant, Unit 3190.5 114.8 2026(d)14.9 
PSOOklaunion Power Station— 34.0 2020(e)0.4 
SWEPCoPirkey Power Plant178.3 30.8 2023(f)13.7 
SWEPCoWelsh Plant, Units 1 and 3528.8 14.2 2028 (g)(h)33.3 
SWEPCoWelsh Plant, Unit 2— 35.2 2016(i)— 

(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)Dolet Hills Power Station is currently being recovered through 2026 in the Louisiana jurisdiction and through 2046 in the Arkansas and Texas jurisdictions.
(d)Northeastern Plant, Unit 3 is currently being recovered through 2040.
(e)Oklaunion Power Station is currently being recovered through 2046.
(f)Pirkey Power Plant is currently being recovered through 2025 in the Louisiana jurisdiction and through 2045 in the Arkansas and Texas jurisdictions.
(g)In November 2020, management announced it will cease using coal at the Welsh Plant in 2028.
(h)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.
(i)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 are 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 and Amortization of Generation Deferrals 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 Ended March 31,
 20212020
 (in millions)
Vertically Integrated Utilities$270.4 $245.3 
Transmission and Distribution Utilities114.4 116.2 
AEP Transmission Holdco172.0 140.6 
Generation & Marketing36.6 28.4 
Corporate and Other(18.4)(35.3)
Earnings Attributable to AEP Common Shareholders$575.0 $495.2 

AEP CONSOLIDATED

First Quarter of 2021 Compared to First Quarter of 2020

Earnings Attributable to AEP Common Shareholders increased from $495 million in 2020 to $575 million in 2021 primarily due to:

An increase in weather-related usage in the residential customer class.
Favorable rate proceedings in AEP’s various jurisdictions.

These increases were partially offset by:

A decrease in usage in the commercial and industrial customer classes.

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VERTICALLY INTEGRATED UTILITIES
Three Months Ended
March 31,
 Vertically Integrated Utilities20212020
 (in millions)
Revenues$2,537.3 $2,226.7 
Fuel and Purchased Electricity859.0 671.2 
Gross Margin1,678.3 1,555.5 
Other Operation and Maintenance740.2 691.3 
Depreciation and Amortization432.1 381.7 
Taxes Other Than Income Taxes123.5 117.1 
Operating Income382.5 365.4 
Other Income0.7 1.6 
Allowance for Equity Funds Used During Construction9.9 8.2 
Non-Service Cost Components of Net Periodic Benefit Cost17.0 16.9 
Interest Expense(139.6)(144.5)
Income Before Income Tax Expense (Benefit) and Equity Earnings270.5 247.6 
Income Tax Expense (Benefit)(0.2)2.1 
Equity Earnings of Unconsolidated Subsidiary0.7 0.8 
Net Income271.4 246.3 
Net Income Attributable to Noncontrolling Interests1.0 1.0 
Earnings Attributable to AEP Common Shareholders$270.4 $245.3 

Summary of KWh Energy Sales for Vertically Integrated Utilities
Three Months Ended March 31,
20212020
 (in millions of KWhs)
Retail:  
Residential9,481 8,262 
Commercial5,258 5,366 
Industrial7,702 8,475 
Miscellaneous519 530 
Total Retail22,960 22,633 
Wholesale (a)4,642 3,618 
Total KWhs27,602 26,251 

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



21


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 Ended March 31,
20212020
 (in degree days)
Eastern Region  
Actual Heating (a)
1,539 1,241 
Normal Heating (b)
1,600 1,611 
Actual Cooling (c)
13 
Normal Cooling (b)
Western Region  
Actual Heating (a)
958 649 
Normal Heating (b)
866 867 
Actual Cooling (c)
26 51 
Normal Cooling (b)
28 28 

(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.

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First Quarter of 2021 Compared to First Quarter of 2020
Reconciliation of First Quarter of 2020 to First Quarter of 2021
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
 
First Quarter of 2020$245.3 
  
Changes in Gross Margin: 
Retail Margins95.5 
Margins from Off-system Sales20.8 
Transmission Revenues10.3 
Other Revenues(3.8)
Total Change in Gross Margin122.8 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(48.9)
Depreciation and Amortization(50.4)
Taxes Other Than Income Taxes(6.4)
Other Income(0.9)
Allowance for Equity Funds Used During Construction1.7 
Non-Service Cost Components of Net Periodic Pension Cost0.1 
Interest Expense4.9 
Total Change in Expenses and Other(99.9)
  
Income Tax Expense2.3 
Equity Earnings of Unconsolidated Subsidiary(0.1)
First Quarter of 2021$270.4 

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 $96 million primarily due to the following:
A $61 million increase in weather-related usage primarily in the eastern region and primarily in the residential class.
A $17 million increase in municipal and cooperative revenues at SWEPCo primarily due to the February 2021 severe winter weather event.
A $15 million increase at KPCo due to rider revenues. This increase was partially offset in other expense items below.
A $14 million increase at APCo and WPCo due to revenue from rate riders primarily in West Virginia. This increase was partially offset in other expense items below.
A $2 million increase in revenue from rate riders at PSO. This increase was partially offset in other expense items below.
The effect of rate proceedings in AEP’s service territories which included:
A $12 million increase at I&M due to the Indiana and Michigan base rate cases and rider revenues. This increase was partially offset in other expense items below.
A $6 million increase at KPCo due to base rate case revenues implemented in January 2021.
These increases were partially offset by:
A $23 million decrease in weather-normalized retail margins driven by a $41 million decrease in the commercial and industrial customer classes partially offset by an $18 million increase in the residential customer class.
A $16 million decrease in weather-normalized wholesale margins, including the loss of a significant wholesale contract at I&M.
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A $5 million decrease related to Tax Reform primarily due to an increase in customer refunds at KPCo. This decrease was partially offset in Income Tax Expense below.
Margins from Off-system Sales increased $21 million primarily due to Turk Plant merchant sales as a result of the February 2021 severe winter weather event at SWEPCo.
Transmission Revenues increased $10 million due to an increase in transmission investment.
Other Revenues decreased $4 million primarily due to decreased pole attachment revenue at APCo and a decrease in rental revenue at WPCo and KPCo.

Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses increased $49 million primarily due to the following:
A $37 million increase in transmission services.
A $16 million increase due to distribution reliability primarily related to vegetation management. This increase was offset in Gross Margin above.
A $5 million increase due to storms primarily at KPCo, SWEPCo and I&M.
A $4 million increase due to a decreased Nuclear Electric Insurance Limited distribution in 2021.
These increases were partially offset by:
An $11 million decrease in employee-related expenses.
Depreciation and Amortization expenses increased $50 million primarily due to a higher depreciable base and an increase in depreciation rates at I&M. This increase was partially offset in Gross Margin above.
Taxes Other Than Income Taxes increased $6 million primarily due to increased property taxes at SWEPCo resulting from the expiration of the Louisiana Industrial Tax Exemption related to the Stall Plant.
Interest Expense decreased $5 million primarily due to a decrease in interest rates on variable rate notes at I&M.

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TRANSMISSION AND DISTRIBUTION UTILITIES
Three Months Ended
March 31,
Transmission and Distribution Utilities20212020
 (in millions)
Revenues$1,088.1 $1,106.9 
Purchased Electricity205.5 191.4 
Gross Margin882.6 915.5 
Other Operation and Maintenance365.2 367.2 
Depreciation and Amortization172.7 214.5 
Taxes Other Than Income Taxes157.6 146.2 
Operating Income187.1 187.6 
Interest and Investment Income0.4 0.7 
Carrying Costs Income0.5 0.4 
Allowance for Equity Funds Used During Construction6.8 7.0 
Non-Service Cost Components of Net Periodic Benefit Cost7.3 7.3 
Interest Expense(74.5)(71.4)
Income Before Income Tax Expense127.6 131.6 
Income Tax Expense13.2 15.4 
Net Income114.4 116.2 
Net Income Attributable to Noncontrolling Interests— — 
Earnings Attributable to AEP Common Shareholders$114.4 $116.2 

Summary of KWh Energy Sales for Transmission and Distribution Utilities
Three Months Ended March 31,
20212020
 (in millions of KWhs)
Retail:  
Residential6,924 6,300 
Commercial5,576 5,873 
Industrial5,281 5,908 
Miscellaneous166 182 
Total Retail (a)17,947 18,263 
Wholesale (b)603 390 
Total KWhs18,550 18,653 

(a) Represents energy delivered to distribution customers.
(b) Primarily Ohio’s contractually obligated purchases of OVEC power sold to PJM.
25


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 Ended March 31,
20212020
 (in degree days)
Eastern Region  
Actual Heating (a)
1,777 1,473 
Normal Heating (b)
1,883 1,898 
Actual Cooling (c)
— 
Normal Cooling (b)
Western Region  
Actual Heating (a)
315 91 
Normal Heating (b)
185 185 
Actual Cooling (d)
137 231 
Normal Cooling (b)
126 125 

(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.

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First Quarter of 2021 Compared to First Quarter of 2020
Reconciliation of First Quarter of 2020 to First Quarter of 2021
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
  
First Quarter of 2020$116.2 
  
Changes in Gross Margin: 
Retail Margins24.8 
Margins from Off-system Sales(37.4)
Transmission Revenues12.4 
Other Revenues(32.7)
Total Change in Gross Margin(32.9)
  
Changes in Expenses and Other: 
Other Operation and Maintenance2.0 
Depreciation and Amortization41.8 
Taxes Other Than Income Taxes(11.4)
Interest and Investment Income(0.3)
Carrying Costs Income0.1 
Allowance for Equity Funds Used During Construction(0.2)
Interest Expense(3.1)
Total Change in Expenses and Other28.9 
  
Income Tax Expense2.2 
  
First Quarter of 2021$114.4 

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

Retail Margins increased $25 million primarily due to the following:
A $58 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 $19 million increase in weather-related usage in Texas primarily due to a 246% increase in heating degree days, partially offset by a 41% decrease in cooling degree days.
A $10 million increase from interim rate increases driven by increased distribution investment in Texas.
A $6 million increase in the Legacy Generation Resource Rider (LGRR) in Ohio. This increase was offset in Margins from Off-system Sales and Other Revenues below.
A $6 million increase from interim rate increases driven by increased transmission investment in Texas.
A $5 million increase in rider revenues in Ohio associated with the DIR. This increase was partially offset in other expense items below.
A $5 million increase in revenues associated with a vegetation management rider in Ohio. This increase was partially offset in Other Operation and Maintenance expenses below.
These increases were partially offset by:
A $27 million decrease due to the ending of the Energy Efficiency and Peak Demand Rider in Ohio in December 2020. This decrease was partially offset in Other Operation and Maintenance expenses below.
A $25 million decrease in weather-normalized margins in Texas primarily in the residential and commercial classes.
A $16 million decrease in revenues in Ohio associated with the Universal Service Fund (USF). This decrease was offset in Other Operation and Maintenance expenses below.
A $15 million decrease due to refunds in Texas of Excess ADIT and excess federal income taxes collected as a result of Tax Reform.

27


Margins from Off-system Sales decreased $37 million primarily due to the following:
A $30 million decrease in Texas due to lower Oklaunion Power Station PPA revenues. Oklaunion Power Station was retired in September 2020 and sold to a nonaffiliated third-party in October 2020. This decrease was partially offset in Depreciation and Amortization expenses below.
A $14 million decrease in Ohio primarily due to unfavorable deferrals of OVEC costs. This decrease was offset in Retail Margins above and Other Revenues below.
Transmission Revenues increased $12 million primarily due to the following:
A $19 million increase from interim rate increases driven by increased transmission investment in Texas.
This increase was partially offset by:
A $4 million decrease due to refunds to customers associated with the most recent base rate case in Texas. This decrease was offset in Other Revenues below.
Other Revenues decreased $33 million primarily due to the following:
A $46 million decrease in securitization revenues primarily due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset in Depreciation and Amortization expenses and Interest Expense below.
This decrease was partially offset by:
An $8 million increase in revenues due to the amortization of a provision for refund recorded as part of the most recent base rate case in Texas. This increase was partially offset in Retail Margins and Transmission Revenues above.
A $6 million increase primarily due to third-party LGRR revenue related to the recovery of OVEC costs in Ohio. This increase was offset in Retail Margins and Margins from Off-system Sales above.

Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses decreased $2 million primarily due to the following:
A $22 million decrease in energy efficiency/demand side management expenses in Ohio. This decrease was partially offset in Retail Margins above.
A $20 million decrease in Texas due to lower Oklaunion Power Station PPA expenses. Oklaunion Power Station was retired in September 2020 and sold to a nonaffiliated third-party in October 2020. This decrease was offset in Gross Margin above.
A $16 million decrease in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This decrease was offset in Retail Margins above.
A $7 million decrease in factored Customers Accounts Receivable expenses in Ohio primarily due to a current year adjustment to allowance for doubtful accounts.
These decreases were partially offset by:
A $61 million increase in transmission expenses primarily due to an increase in PJM recoverable expenses. This increase was offset in Gross Margin above.
A $5 million increase in recoverable distribution expenses in Ohio primarily related to vegetation management. This increase was offset in Retail Margins above.
Depreciation and Amortization expenses decreased $42 million primarily due to the following:
A $44 million decrease in securitization amortizations in Texas related primarily to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. The securitization decrease was offset in Other Revenues above.
A $16 million decrease in depreciation expense due to the retirement of the Oklaunion Power Station in September 2020. This decrease was partially offset above in Margins from Off-system Sales and Other Operation and Maintenance expenses.
These decreases were partially offset by:
A $16 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.


28


Taxes Other Than Income Taxes increased $11 million primarily due to increased property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
Interest Expense increased $3 million primarily due to higher long-term debt balances.

29


AEP TRANSMISSION HOLDCO
Three Months Ended
March 31,
AEP Transmission Holdco20212020
 (in millions)
Transmission Revenues$377.0 $310.2 
Other Operation and Maintenance27.2 29.9 
Depreciation and Amortization72.7 58.1 
Taxes Other Than Income Taxes59.2 51.9 
Operating Income217.9 170.3 
Interest and Investment Income0.2 0.9 
Allowance for Equity Funds Used During Construction16.7 16.2 
Non-Service Cost Components of Net Periodic Benefit Cost0.5 0.5 
Interest Expense(35.3)(30.8)
Income Before Income Tax Expense and Equity Earnings200.0 157.1 
Income Tax Expense45.8 38.4 
Equity Earnings of Unconsolidated Subsidiary19.0 22.9 
Net Income173.2 141.6 
Net Income Attributable to Noncontrolling Interests1.2 1.0 
Earnings Attributable to AEP Common Shareholders$172.0 $140.6 

Summary of Investment in Transmission Assets for AEP Transmission Holdco
March 31,
20212020
(in millions)
Plant in Service$10,549.3 $9,086.6 
Construction Work in Progress1,635.9 1,576.3 
Accumulated Depreciation and Amortization648.1 464.0 
Total Transmission Property, Net$11,537.1 $10,198.9 
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First Quarter of 2021 Compared to First Quarter of 2020
 
Reconciliation of First Quarter of 2020 to First Quarter of 2021
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
First Quarter of 2020$140.6 
Changes in Transmission Revenues:
Transmission Revenues66.8 
Total Change in Transmission Revenues66.8 
Changes in Expenses and Other:
Other Operation and Maintenance2.7 
Depreciation and Amortization(14.6)
Taxes Other Than Income Taxes(7.3)
Interest and Investment Income(0.7)
Allowance for Equity Funds Used During Construction0.5 
Interest Expense(4.5)
Total Change in Expenses and Other(23.9)
Income Tax Expense(7.4)
Equity Earnings of Unconsolidated Subsidiary(3.9)
Net Income Attributable to Noncontrolling Interests(0.2)
First Quarter of 2021$172.0 

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

Transmission Revenues increased $67 million primarily due to continued investment in transmission assets.

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

Depreciation and Amortization expenses increased $15 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $7 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 increased $7 million primarily due to an increase in pretax book income.
Equity Earnings of Unconsolidated Subsidiary decreased $4 million primarily due to lower pretax equity earnings for PATH-WV.
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GENERATION & MARKETING
Three Months Ended
March 31,
Generation & Marketing20212020
 (in millions)
Revenues$634.2 $438.6 
Fuel, Purchased Electricity and Other565.9 360.3 
Gross Margin68.3 78.3 
Other Operation and Maintenance28.2 41.4 
Depreciation and Amortization18.6 17.7 
Taxes Other Than Income Taxes2.6 3.4 
Operating Income18.9 15.8 
Interest and Investment Income0.5 1.0 
Non-Service Cost Components of Net Periodic Benefit Cost3.8 3.9 
Interest Expense(3.3)(8.5)
Income Before Income Tax Benefit and Equity Earnings19.9 12.2 
Income Tax Benefit(15.1)(12.4)
Equity Earnings of Unconsolidated Subsidiaries3.2 5.9 
Net Income38.2 30.5 
Net Earnings Attributable to Noncontrolling Interests1.6 2.1 
Earnings Attributable to AEP Common Shareholders$36.6 $28.4 

Summary of MWhs Generated for Generation & Marketing
Three Months Ended 
March 31,
20212020
 (in millions of MWhs)
Fuel Type:  
Coal
Renewables
Total MWhs
32


First Quarter of 2021 Compared to First Quarter of 2020
Reconciliation of First Quarter of 2020 to First Quarter of 2021
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
  
First Quarter of 2020$28.4 
  
Changes in Gross Margin: 
Merchant Generation4.0 
Renewable Generation5.3 
Retail, Trading and Marketing(19.3)
Total Change in Gross Margin(10.0)
  
Changes in Expenses and Other: 
Other Operation and Maintenance13.2 
Depreciation and Amortization(0.9)
Taxes Other Than Income Taxes0.8 
Interest and Investment Income(0.5)
Non-Service Cost Components of Net Periodic Benefit Cost(0.1)
Interest Expense5.2 
Total Change in Expenses and Other17.7 
  
Income Tax Expense2.7 
Equity Earnings of Unconsolidated Subsidiaries(2.7)
Net Earnings Attributable to Noncontrolling Interests0.5 
  
First Quarter of 2021$36.6 

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

Merchant Generation increased $4 million primarily due to lower PPA expenses resulting from the retirement of the Oklaunion Power Station.
Renewable Generation increased $5 million primarily due to higher market revenues from wind assets in the ERCOT region.
Retail, Trading and Marketing decreased $19 million due to lower trading and retail margins due to unprecedented cold temperatures and record market prices in February 2021.

Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses decreased $13 million primarily due to the following:
An $8 million decrease due the retirement of Conesville Plant Unit 4 in 2020.
A $6 million decrease due to gains recorded on the sale of land.
Interest Expense decreased $5 million due to lower borrowing costs in 2021.

33


CORPORATE AND OTHER

First Quarter of 2021 Compared to First Quarter of 2020

Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $35 million in 2020 to a loss of $18 million in 2021 primarily due to:

A $17 million unrealized gain from an investment in ChargePoint.
A $12 million decrease in interest expense.
A $6 million increase in equity earnings.

These items were partially offset by:

A $9 million increase in general corporate expenses.
An $8 million increase in Income Tax Expense due to an increase in pretax income and the recognition of a $4 million prior period adjustment in 2021.


AEP SYSTEM INCOME TAXES

First Quarter of 2021 Compared to First Quarter of 2020

Income Tax Expense increased $8 million primarily due to an increase in pretax book income partially offset with an increase in production tax credits.


34


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
 March 31, 2021December 31, 2020
 (dollars in millions)
Long-term Debt, including amounts due within one year$32,345.0 57.1 %$31,072.5 57.2 %
Short-term Debt3,048.4 5.4 2,479.3 4.6 
Total Debt35,393.4 62.5 33,551.8 61.8 
AEP Common Equity20,972.8 37.1 20,550.9 37.8 
Noncontrolling Interests247.2 0.4 223.6 0.4 
Total Debt and Equity Capitalization$56,613.4 100.0 %$54,326.3 100.0 %

AEP’s ratio of debt-to-total capital increased from 61.8% as of December 31, 2020 to 62.5% as of March 31, 2021 primarily due to an increase in debt to help address the cash flow implications resulting from the February 2021 severe winter weather event in addition to supporting distribution, transmission and renewable investment growth.

Liquidity

Liquidity, or access to cash, is an important factor in determining AEP’s financial stability.  Management believes AEP has adequate liquidity under its existing credit facilities.  As of March 31, 2021, 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. In February 2021, severe winter weather impacted certain AEP service territories resulting in disruptions to SPP market conditions. 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. See Note 4 - Rate Matters for additional information.

Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments.  As of March 31, 2021, available liquidity was approximately $3.4 billion as illustrated in the table below:
AmountMaturity
Commercial Paper Backup:(in millions)
Revolving Credit Facility$4,000.0 March 2026
Revolving Credit Facility1,000.0 March 2023
 364-Day Term Loan500.0 March 2022
Cash and Cash Equivalents273.2  
Total Liquidity Sources5,773.2  
Less:AEP Commercial Paper Outstanding1,874.4  
 364-Day Term Loan500.0  
Net Available Liquidity$3,398.8  

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 three months of 2021 was $2 billion.  The weighted-average interest rate for AEP’s commercial paper during 2021 was 0.24%.
35


Other Credit Facilities

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under six uncommitted facilities totaling $425 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of March 31, 2021 was $183 million with maturities ranging from April 2021 to March 2022.

Securitized Accounts Receivables

AEP’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and expires in September 2022.

In March 2021, AEP Credit amended its receivables securitization agreement to extend trigger levels established in October 2020 and to also provide a step down approach to these levels as management continues to monitor the accounts receivable balances across the affiliated utility subsidiaries in response to the COVID-19 pandemic. As of March 31, 2021, the affiliated utility subsidiaries are in compliance with all requirements under the agreement. To the extent that an affiliated utility subsidiary is deemed ineligible under the agreement, the affiliated utility subsidiary would no longer participate in the receivables securitization agreement and the Registrants would need to rely on additional sources of funding for operation and working capital, which may adversely impact liquidity.

Debt Covenants and Borrowing Limitations

AEP’s credit agreements contain certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5%.  The method for calculating outstanding debt and capitalization is contractually-defined in AEP’s credit agreements.  Debt as defined in the revolving credit agreement excludes securitization bonds and debt of AEP Credit. As of March 31, 2021, this contractually-defined percentage was 59.5%. Non-performance under these covenants could result in an event of default under these credit agreements.  In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of AEP’s major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements.  This condition also applies in a majority of AEP’s non-exchange-traded commodity contracts and would similarly allow lenders and counterparties to declare the outstanding amounts payable.  However, a default under AEP’s non-exchange-traded commodity contracts would not cause an event of default under its credit agreements.

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

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

At-the-Market (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. As of March 31, 2021, approximately $840 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.
36


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 settles 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.

See Note 12 - Financing Activities for additional information.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.74 per share in April 2021. Future dividends may vary depending upon AEP’s profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. Management does not believe these restrictions will have any significant impact on its ability to access cash to meet the payment of dividends on its common stock. See “Dividend Restrictions” section of Note 12 for additional information.

Credit Ratings

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

CASH FLOW

AEP relies primarily on cash flows from operations, debt issuances and its existing cash and cash equivalents to fund its liquidity and investing activities. AEP’s investing and capital requirements are primarily capital expenditures, repaying of long-term debt and paying dividends to shareholders. AEP uses short-term debt, including commercial paper, as a bridge to long-term debt financing. The levels of borrowing may vary significantly due to the timing of long-term debt financings and the impact of fluctuations in cash flows.
Three Months Ended 
March 31,
 20212020
 (in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period$438.3 $432.6 
Net Cash Flows from (Used for) Operating Activities(117.2)615.7 
Net Cash Flows Used for Investing Activities(1,634.2)(1,766.0)
Net Cash Flows from Financing Activities1,637.1 2,388.5 
Net Increase (Decrease) in Cash and Cash Equivalents(114.3)1,238.2 
Cash, Cash Equivalents and Restricted Cash at End of Period$324.0 $1,670.8 

37


Operating Activities
Three Months Ended 
March 31,
20212020
(in millions)
Net Income$578.8 $499.3 
Non-Cash Adjustments to Net Income (a)762.7 726.2 
Mark-to-Market of Risk Management Contracts21.0 57.4 
Property Taxes(74.8)(59.8)
Deferred Fuel Over/Under-Recovery, Net(1,225.1)63.1 
Change in Other Noncurrent Assets(168.9)(84.9)
Change in Other Noncurrent Liabilities83.5 (74.8)
Change in Certain Components of Working Capital(94.4)(510.8)
Net Cash Flows from (Used for) Operating Activities$(117.2)$615.7 

(a)Non-Cash Adjustments to Net Income includes Depreciation and Amortization, Rockport Plant, Unit 2 Operating Lease Amortization, Deferred Income Taxes, AFUDC and Amortization of Nuclear Fuel.

Net Cash Flows from (Used for) Operating Activities decreased by $733 million primarily due to the following:
A $1.3 billion decrease in cash primarily due to fuel and purchased power expenses incurred as a result of the February 2021 severe winter weather event in SPP impacting PSO and SWEPCo. Approximately $1.2 billion of these expenses are attributable to retail customers and are recorded as deferred fuel regulatory assets. 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.
A $131 million decrease in cash due to incremental other operation and maintenance storm restoration expenses incurred by APCo, SWEPCo and KPCo as a result of the February 2021 severe winter weather event. These incremental expenses have been deferred as regulatory assets. APCo and KPCo intend to seek recovery of these costs in their next respective base rate cases while SWEPCo is expected to seek recovery in a separate filing. See Note 4 - Rate Matters for additional information.
These decreases in cash were partially offset by:
A $416 million increase in cash from the Change in Certain Components of Working Capital. The increase is primarily due to timing of accounts payable and a decrease in fuel, material and supplies balances as a result of the cold winter weather.
A $158 million increase in cash from Change in Other Noncurrent Liabilities. Increase is primarily due to changes in regulatory liabilities driven by timing differences between collections from and refunds to customers under rate rider mechanisms.


38


Investing Activities
Three Months Ended 
March 31,
 20212020
 (in millions)
Construction Expenditures$(1,492.7)$(1,792.7)
Acquisitions of Nuclear Fuel(55.9)(1.3)
Acquisition of the Dry Lake Solar Project(102.9)— 
Other17.3 28.0 
Net Cash Flows Used for Investing Activities$(1,634.2)$(1,766.0)

Net Cash Flows Used for Investing Activities decreased by $132 million primarily due to the following:
A $300 million decrease in construction expenditures, primarily due to decreases at Vertically Integrated Utilities of $125 million, Transmission and Distribution Utilities of $87 million and AEP Transmission Holdco of $74 million.
This decrease in the use of cash was partially offset by:
A $103 million increase due to the acquisition of the Dry Lake Solar Project. See Note 6 - Acquisitions for additional information.
A $55 million increase in the acquisition of nuclear fuel.

Financing Activities
Three Months Ended 
March 31,
 20212020
 (in millions)
Issuance of Common Stock$184.6 $56.1 
Issuance/Retirement of Debt, Net1,869.9 2,744.2 
Dividends Paid on Common Stock(372.0)(363.7)
Other(45.4)(48.1)
Net Cash Flows from Financing Activities$1,637.1 $2,388.5 

Net Cash Flows from Financing Activities decreased by $751 million primarily due to the following:
A $1.1 billion decrease in short-term debt primarily due to decreased draws on commercial paper. See Note 12 - Financing Activities for additional information.
A $350 million decrease due to increased retirements of long-term debt. See Note 12 - Financing Activities for additional information.
These decreases in cash were partially offset by:
A $533 million increase in issuances of long-term debt. See Note 12 - Financing Activities for additional information.
A $129 million increase in issuances of common stock primarily due to AEP’s participation in an At-the-Market offering program. See Note 12 - Financing Activities for additional information.

See “Long-term Debt Subsequent Events” section of Note 12 for Long-term debt and other securities issued, retired and principal payments made after March 31, 2021 through April 22, 2021, the date that the first quarter 10-Q was issued.


39


BUDGETED CAPITAL EXPENDITURES

Management forecasts approximately $7.5 billion of capital expenditures in 2021. For the four year period, 2022 through 2025, management forecasts capital expenditures of $29.8 billion. The expenditures are generally for transmission, generation, distribution, regulated and contracted 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, weather, legal reviews and the ability to access capital.  Management expects to fund these capital expenditures through cash flows from operations 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 2020 Annual Report.

CONTRACTUAL OBLIGATION INFORMATION

A summary of contractual obligations is included in the 2020 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING STANDARDS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

See the “Critical Accounting Policies and Estimates” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2020 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.

40


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 Commercial Operations Risk Committee (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, Executive Vice President of Generation, Executive Vice President of Utilities, 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 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 may adversely impact AEP’s risk management contracts on a forward basis. Markets could experience reduced market liquidity as they face potential uncertainties. Credit risk may increase as counterparties encounter business and supply chain disruptions and overall solvency challenges. Also, interest rates could continue to see increased volatility as capital markets confront uncertainty.

Due to multiple defaults of market participants, ERCOT has a large outstanding unpaid balance associated with the February storm. Socialized losses are allocated to load serving entities through their qualified scheduling entities 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.
41



The following table summarizes the reasons for changes in total MTM value as compared to December 31, 2020:
MTM Risk Management Contract Net Assets (Liabilities)
Three Months Ended March 31, 2021
Vertically
Integrated
Utilities
Transmission
and
Distribution
Utilities
Generation
&
Marketing
Total
 (in millions)
Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2020$41.2 $(109.5)$168.1 $99.8 
Gain from Contracts Realized/Settled During the Period and Entered in a Prior Period(21.6)(2.6)(7.5)(31.7)
Changes in Fair Value Due to Market Fluctuations During the Period (a)— — 3.4 3.4 
Changes in Fair Value Allocated to Regulated Jurisdictions (b)(3.4)9.5 — 6.1 
Total MTM Risk Management Contract Net Assets (Liabilities) as of March 31, 2021$16.2 $(102.6)$164.0 77.6 
Commodity Cash Flow Hedge Contracts
 (22.8)
Fair Value Hedge Contracts  (34.7)
Collateral Deposits  4.7 
Total MTM Derivative Contract Net Assets as of March 31, 2021  $24.8 

(a)Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(b)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.

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.

Credit Risk

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

AEP has risk management contracts (includes non-derivative contracts) with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, exposures change daily. As of March 31, 2021, credit exposure net of collateral to sub investment grade counterparties was approximately 4.1%, 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).
42


As of March 31, 2021, 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$373.8 $— $373.8 $190.0 
Split Rating2.2 — 2.2 2.2 
Noninvestment Grade0.4 — 0.4 0.4 
No External Ratings:    
Internal Investment Grade151.0 — 151.0 100.3 
Internal Noninvestment Grade22.7 0.5 22.2 13.1 
Total as of March 31, 2021$550.1 $0.5 $549.6 

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

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

Value at Risk (VaR) Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates VaR, to measure AEP’s commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, as of March 31, 2021, a near term typical change in commodity prices is not expected to materially impact net income, cash flows or financial condition.

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

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

VaR Model
Trading Portfolio
Three Months EndedTwelve Months Ended
March 31, 2021December 31, 2020
EndHighAverageLowEndHighAverageLow
(in millions)(in millions)
$0.1 $3.6 $0.2 $0.1 $0.1 $0.3 $0.1 $— 
VaR Model
Non-Trading Portfolio
Three Months EndedTwelve Months Ended
March 31, 2021December 31, 2020
EndHighAverageLowEndHighAverageLow
(in millions)(in millions)
$1.0 $3.7 $1.9 $1.0 $2.2 $2.9 $1.0 $0.1 
43



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 three months ended March 31, 2021 and 2020, a 100 basis point change in the benchmark rate on AEP’s variable rate debt would impact pretax interest expense annually by $40 million and $24 million, respectively.
44



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2021 and 2020
(in millions, except per-share and share amounts)
(Unaudited)
Three Months Ended March 31,
20212020
REVENUES
Vertically Integrated Utilities$2,504.5 $2,193.0 
Transmission and Distribution Utilities1,082.3 1,075.2 
Generation & Marketing601.7 408.4 
Other Revenues92.6 70.9 
TOTAL REVENUES4,281.1 3,747.5 
EXPENSES  
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation1,560.7 1,151.0 
Other Operation592.4 602.1 
Maintenance274.9 249.5 
Depreciation and Amortization696.3 672.2 
Taxes Other Than Income Taxes346.5 321.1 
TOTAL EXPENSES3,470.8 2,995.9 
OPERATING INCOME810.3 751.6 
Other Income (Expense):  
Other Income (Expense)21.7 (4.4)
Allowance for Equity Funds Used During Construction33.4 31.4 
Non-Service Cost Components of Net Periodic Benefit Cost29.6 29.7 
Interest Expense(290.2)(292.1)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS604.8 516.2 
Income Tax Expense54.5 46.5 
Equity Earnings of Unconsolidated Subsidiaries28.5 29.6 
NET INCOME578.8 499.3 
Net Income Attributable to Noncontrolling Interests3.8 4.1 
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$575.0 $495.2 
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING497,058,635 494,596,869 
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$1.16 $1.00 
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING498,164,219 496,608,918 
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$1.15 $1.00 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
45


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2021 and 2020
(in millions)
(Unaudited)
Three Months Ended March 31,
20212020
Net Income$578.8 $499.3 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES  
Cash Flow Hedges, Net of Tax of $15.0 and $(17.8) in 2021 and 2020, Respectively56.3 (67.0)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.5) and $(0.5) in 2021 and 2020, Respectively(2.0)(1.8)
  
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)54.3 (68.8)
TOTAL COMPREHENSIVE INCOME633.1 430.5 
Total Other Comprehensive Income Attributable To Noncontrolling Interests3.8 4.1 
TOTAL OTHER COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$629.3 $426.4 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
46


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Three Months Ended March 31, 2021 and 2020
(in millions)
(Unaudited)
AEP Common Shareholders
Common StockAccumulated
Other
Comprehensive
Income (Loss)
SharesAmountPaid-in
Capital
Retained
Earnings
Noncontrolling
Interests
Total
TOTAL EQUITY – DECEMBER 31, 2019514.4 $3,343.4 $6,535.6 $9,900.9 $(147.7)$281.0 $19,913.2 
Issuance of Common Stock1.0 6.8 49.3  56.1 
Common Stock Dividends(359.1)(a)(4.6)(363.7)
Other Changes in Equity(29.0)(1.2)(30.2)
ASU 2016-13 Adoption1.8 1.8 
Net Income   495.2 4.1 499.3 
Other Comprehensive Loss    (68.8)(68.8)
TOTAL EQUITY – MARCH 31, 2020515.4 $3,350.2 $6,555.9 $10,038.8 $(216.5)$279.3 $20,007.7 
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 Project18.918.9 
Net Income575.0 3.8 578.8 
Other Comprehensive Income54.3 54.3 
TOTAL EQUITY – MARCH 31, 2021519.5 $3,376.4 $6,734.5 $10,892.7 $(30.8)$247.2 $21,220.0 

(a)    Cash dividends declared per AEP common share were $0.74 and $0.70 for the three months ended March 31, 2021 and 2020.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
47


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2021 and December 31, 2020
(in millions)
(Unaudited)
 March 31,December 31,
 20212020
CURRENT ASSETS  
Cash and Cash Equivalents$273.2 $392.7 
Restricted Cash
(March 31, 2021 and December 31, 2020 Amounts Include $50.8 and $45.6, Respectively, Related to Transition Funding, Restoration Funding and Appalachian Consumer Rate Relief Funding)
50.8 45.6 
Other Temporary Investments
(March 31, 2021 and December 31, 2020 Amounts Include $191.7 and $194.6, Respectively, Related to EIS and Transource Energy)
199.1 200.8 
Accounts Receivable:  
Customers763.0 613.6 
Accrued Unbilled Revenues199.9 248.7 
Pledged Accounts Receivable – AEP Credit919.0 1,018.4 
Miscellaneous36.1 33.1 
Allowance for Uncollectible Accounts(59.6)(71.1)
Total Accounts Receivable1,858.4 1,842.7 
Fuel588.6 629.4 
Materials and Supplies683.3 680.6 
Risk Management Assets72.1 94.7 
Accrued Tax Benefits187.6 185.3 
Regulatory Asset for Under-Recovered Fuel Costs129.8 90.7 
Margin Deposits91.0 62.0 
Prepayments and Other Current Assets124.5 127.0 
TOTAL CURRENT ASSETS4,258.4 4,351.5 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation23,186.5 23,133.9 
Transmission28,359.9 27,886.7 
Distribution24,311.8 23,972.1 
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)5,465.2 5,294.6 
Construction Work in Progress4,289.5 4,025.7 
Total Property, Plant and Equipment85,612.9 84,313.0 
Accumulated Depreciation and Amortization20,916.8 20,411.4 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET64,696.1 63,901.6 
OTHER NONCURRENT ASSETS  
Regulatory Assets4,885.6 3,527.0 
Securitized Assets632.5 657.0 
Spent Nuclear Fuel and Decommissioning Trusts3,414.3 3,306.7 
Goodwill52.5 52.5 
Long-term Risk Management Assets264.8 242.2 
Operating Lease Assets818.9 866.4 
Deferred Charges and Other Noncurrent Assets3,962.0 3,852.3 
TOTAL OTHER NONCURRENT ASSETS14,030.6 12,504.1 
TOTAL ASSETS$82,985.1 $80,757.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
48


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
March 31, 2021 and December 31, 2020
(in millions, except per-share and share amounts)
(Unaudited)
   March 31,December 31,
 20212020
CURRENT LIABILITIES  
Accounts Payable$1,703.9 $1,709.7 
Short-term Debt:  
Securitized Debt for Receivables – AEP Credit669.0 592.0 
Other Short-term Debt2,379.4 1,887.3 
Total Short-term Debt3,048.4 2,479.3 
Long-term Debt Due Within One Year
(March 31, 2021 and December 31, 2020 Amounts Include $192.3 and $198.3, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)
2,130.2 2,086.1 
Risk Management Liabilities39.1 78.8 
Customer Deposits331.0 335.6 
Accrued Taxes1,397.9 1,476.4 
Accrued Interest324.2 267.6 
Obligations Under Operating Leases240.6 241.3 
Regulatory Liability for Over-Recovered Fuel Costs39.1 52.6 
Other Current Liabilities965.7 1,199.3 
TOTAL CURRENT LIABILITIES10,220.1 9,926.7 
NONCURRENT LIABILITIES  
Long-term Debt
(March 31, 2021 and December 31, 2020 Amounts Include $921.1 and $950.1, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)
30,214.8 28,986.4 
Long-term Risk Management Liabilities273.0 232.8 
Deferred Income Taxes8,349.9 8,240.9 
Regulatory Liabilities and Deferred Investment Tax Credits8,466.1 8,378.7 
Asset Retirement Obligations2,483.7 2,469.2 
Employee Benefits and Pension Obligations343.4 336.4 
Obligations Under Operating Leases625.1 638.4 
Deferred Credits and Other Noncurrent Liabilities733.7 728.0 
TOTAL NONCURRENT LIABILITIES51,489.7 50,010.8 
TOTAL LIABILITIES61,709.8 59,937.5 
Rate Matters (Note 4)00
Commitments and Contingencies (Note 5)00
MEZZANINE EQUITY
Contingently Redeemable Performance Share Awards55.3 45.2 
TOTAL MEZZANINE EQUITY55.3 45.2 
EQUITY  
Common Stock – Par Value – $6.50 Per Share:  
20212020  
Shares Authorized600,000,000600,000,000  
Shares Issued519,450,026516,808,354  
(20,204,160 Shares were Held in Treasury as of March 31, 2021 and December 31, 2020, Respectively)3,376.4 3,359.3 
Paid-in Capital6,734.5 6,588.9 
Retained Earnings10,892.7 10,687.8 
Accumulated Other Comprehensive Income (Loss)(30.8)(85.1)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY20,972.8 20,550.9 
Noncontrolling Interests247.2 223.6 
TOTAL EQUITY21,220.0 20,774.5 
TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY$82,985.1 $80,757.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
49


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2021 and 2020
(in millions)
(Unaudited)
 Three Months Ended March 31,
 20212020
OPERATING ACTIVITIES  
Net Income$578.8 $499.3 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: ��
Depreciation and Amortization696.3 672.2 
Rockport Plant, Unit 2 Operating Lease Amortization32.8 34.1 
Deferred Income Taxes44.3 27.9 
Allowance for Equity Funds Used During Construction(33.4)(31.4)
Mark-to-Market of Risk Management Contracts21.0 57.4 
Amortization of Nuclear Fuel22.7 23.4 
Property Taxes(74.8)(59.8)
Deferred Fuel Over/Under-Recovery, Net(1,225.1)63.1 
Change in Other Noncurrent Assets(168.9)(84.9)
Change in Other Noncurrent Liabilities83.5 (74.8)
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net(12.9)(32.6)
Fuel, Materials and Supplies39.5 (35.8)
Accounts Payable171.8 (111.1)
Accrued Taxes, Net(80.8)(93.9)
Other Current Assets(26.3)5.3 
Other Current Liabilities(185.7)(242.7)
Net Cash Flows from (Used for) Operating Activities(117.2)615.7 
INVESTING ACTIVITIES  
Construction Expenditures(1,492.7)(1,792.7)
Purchases of Investment Securities(337.6)(632.7)
Sales of Investment Securities325.5 635.6 
Acquisitions of Nuclear Fuel(55.9)(1.3)
Acquisition of the Dry Lake Solar Project(102.9)
Other Investing Activities29.4 25.1 
Net Cash Flows Used for Investing Activities(1,634.2)(1,766.0)
FINANCING ACTIVITIES  
Issuance of Common Stock184.6 56.1 
Issuance of Long-term Debt1,951.5 1,418.9 
Issuance of Short-term Debt with Original Maturities greater than 90 Days644.2 1,297.5 
Change in Short-term Debt with Original Maturities less than 90 Days, Net16.9 328.3 
Retirement of Long-term Debt(650.7)(300.5)
Redemption of Short-term Debt with Original Maturities Greater than 90 Days(92.0)
Principal Payments for Finance Lease Obligations(15.0)(15.4)
Dividends Paid on Common Stock(372.0)(363.7)
Other Financing Activities(30.4)(32.7)
Net Cash Flows from Financing Activities1,637.1 2,388.5 
Net Increase (Decrease) in Cash and Cash Equivalents(114.3)1,238.2 
Cash, Cash Equivalents and Restricted Cash at Beginning of Period438.3 432.6 
Cash, Cash Equivalents and Restricted Cash at End of Period$324.0 $1,670.8 
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts$220.5 $212.6 
Net Cash Paid (Received) for Income Taxes(0.2)(0.6)
Noncash Acquisitions Under Finance Leases9.0 19.4 
Construction Expenditures Included in Current Liabilities as of March 31,762.7 874.1 
Construction Expenditures Included in Noncurrent Liabilities as of March 31,8.3 
Acquisition of Nuclear Fuel Included in Current Liabilities as of March 31,6.7 
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage0.1 1.3 
Noncontrolling Interest Assumed with the Dry Lake Solar Project Acquisition18.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
50


AEP TEXAS INC.
AND SUBSIDIARIES

51


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

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
Three Months Ended March 31,
 20212020
 (in millions of KWhs)
Retail:  
Residential2,818 2,466 
Commercial2,074 2,357 
Industrial1,880 2,365 
Miscellaneous137 152 
Total Retail6,909 7,340 

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 Ended March 31,
 20212020
 (in degree days)
Actual – Heating (a)315 91 
Normal – Heating (b)185 185 
Actual – Cooling (c)137 231 
Normal – Cooling (b)126 125 

(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.




52


First Quarter of 2021 Compared to First Quarter of 2020
AEP Texas Inc. and Subsidiaries
Reconciliation of First Quarter of 2020 to First Quarter of 2021
Net Income
(in millions)
First Quarter of 2020$47.6 
  
Changes in Gross Margin:
Retail Margins(6.3)
Margins from Off-system Sales(30.2)
Transmission Revenues15.3 
Other Revenues(38.2)
Total Change in Gross Margin(59.4)
  
Changes in Expenses and Other: 
Other Operation and Maintenance(3.2)
Depreciation and Amortization65.0 
Taxes Other Than Income Taxes(2.3)
Interest Income(0.4)
Allowance for Equity Funds Used During Construction(1.0)
Interest Expense(0.5)
Total Change in Expenses and Other57.6 
  
Income Tax Expense0.3 
  
First Quarter of 2021$46.1 

The major components of the decrease in Gross Margin were as follows:

Retail Margins decreased $6 million primarily due to the following:
A $25 million decrease in weather-normalized margins primarily in the residential and commercial classes.
A $15 million decrease due to refunds of Excess ADIT and excess federal income taxes collected as a result of Tax Reform.
These decreases were partially offset by:
A $19 million increase in weather-related usage primarily due to a 246% increase in heating degree days, partially offset by a 41% decrease in cooling degree days.
A $10 million increase from interim rate increases driven by increased distribution investment.
A $6 million increase from interim rate increases driven by increased transmission investment.
Margins from Off-system Sales decreased $30 million due to lower Oklaunion Power Station PPA revenues. Oklaunion Power Station was retired in September 2020 and sold to a nonaffiliated third-party in October 2020. This decrease was partially offset in Depreciation and Amortization expenses below.
Transmission Revenues increased $15 million primarily due to:
A $19 million increase from interim rate increases driven by increased transmission investment.
This increase was partially offset by:
A $4 million decrease due to refunds to customers associated with the most recent base rate case. This decrease was offset in Other Revenues below.
Other Revenues decreased $38 million primarily due to the following:
A $46 million decrease in securitization revenues primarily due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset below in Depreciation and Amortization expenses and in Interest Expense.

53


This decrease was partially offset by:
An $8 million increase in revenues due to the amortization of a provision for refund recorded as part of the most recent base rate case. This increase was partially offset in Retail Margins and Transmission Revenues above.

Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses increased $3 million primarily due to the following:
A $5 million increase in transmission expenses, partially offset in Gross Margin above.
This increase was partially offset by:
A $2 million decrease primarily related to distribution-related expenses.
Depreciation and Amortization expenses decreased $65 million primarily due to the following:
A $44 million decrease in securitization amortizations primarily related to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. The securitization decrease was offset in Other Revenues above.
A $16 million decrease in depreciation expense due to the retirement of the Oklaunion Power Station in September 2020. This decrease was partially offset above in Margins from Off-system Sales and Other Operation and Maintenance expenses.

54



AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2021 and 2020
(in millions)
(Unaudited)
Three Months Ended March 31,
  2021 2020
REVENUES    
Electric Transmission and Distribution $361.7 $391.6 
Sales to AEP Affiliates 1.0 31.1 
Other Revenues 1.5 0.9 
TOTAL REVENUES 364.2 423.6 
 
EXPENSES   
Other Operation 122.2 117.5 
Maintenance 19.1 20.6 
Depreciation and Amortization 97.5 162.5 
Taxes Other Than Income Taxes 36.3 34.0 
TOTAL EXPENSES 275.1 334.6 
 
OPERATING INCOME 89.1 89.0 
 
Other Income (Expense):   
Interest Income 0.2 0.6 
Allowance for Equity Funds Used During Construction4.1 5.1 
Non-Service Cost Components of Net Periodic Benefit Cost2.8 2.8 
Interest Expense (43.0)(42.5)
 
INCOME BEFORE INCOME TAX EXPENSE 53.2 55.0 
 
Income Tax Expense 7.1 7.4 
NET INCOME $46.1 $47.6 
The common stock of AEP Texas is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
55


AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2021 and 2020
(in millions)
(Unaudited)
Three Months Ended March 31,
20212020
Net Income$46.1 $47.6 
 
OTHER COMPREHENSIVE INCOME, NET OF TAXES 
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 in 2021 and 2020, Respectively0.3 0.3 
TOTAL COMPREHENSIVE INCOME$46.4 $47.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

56


AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Three Months Ended March 31, 2021 and 2020
(in millions)
(Unaudited)
 Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019$1,457.9 $1,516.0 $(12.8)$2,961.1 
Net Income47.6 47.6 
Other Comprehensive Income0.3 0.3 
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2020$1,457.9 $1,563.6 $(12.5)$3,009.0 
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020$1,457.9 $1,757.0 $(8.9)$3,206.0 
Net Income46.1 46.1 
Other Comprehensive Income0.3 0.3 
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2021$1,457.9 $1,803.1 $(8.6)$3,252.4 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

57


AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2021 and December 31, 2020
(in millions)
(Unaudited)
  March 31,December 31,
  2021 2020
CURRENT ASSETS    
Cash and Cash Equivalents$0.1 $0.1 
Restricted Cash
(March 31, 2021 and December 31, 2020 Amounts Include $39.3 and $28.7, Respectively, Related to Transition Funding and Restoration Funding)
39.3 28.7 
Advances to Affiliates6.8 7.1 
Accounts Receivable:   
Customers 129.3 112.8 
Affiliated Companies 7.2 5.1 
Accrued Unbilled Revenues58.2 65.8 
Allowance for Uncollectible Accounts(4.3)(0.1)
Total Accounts Receivable 190.4 183.6 
Materials and Supplies 69.8 70.0 
Accrued Tax Benefits11.4 16.8 
Prepayments and Other Current Assets 4.7 4.6 
TOTAL CURRENT ASSETS 322.5 310.9 
 
PROPERTY, PLANT AND EQUIPMENT   
Electric:   
Transmission 5,434.7 5,279.6 
Distribution 4,654.2 4,580.8 
Other Property, Plant and Equipment 885.0 868.4 
Construction Work in Progress 567.8 614.1 
Total Property, Plant and Equipment 11,541.7 11,342.9 
Accumulated Depreciation and Amortization 1,565.9 1,529.3 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 9,975.8 9,813.6 
 
OTHER NONCURRENT ASSETS   
Regulatory Assets 274.5 266.8 
Securitized Assets
(March 31, 2021 and December 31, 2020 Amounts Include $428.6 and $446.8, Respectively, Related to Transition Funding and Restoration Funding)
428.6 446.8 
Deferred Charges and Other Noncurrent Assets 261.6 192.1 
TOTAL OTHER NONCURRENT ASSETS 964.7 905.7 
 
TOTAL ASSETS $11,263.0 $11,030.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
58


AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
March 31, 2021 and December 31, 2020
(in millions)
(Unaudited)
  March 31,December 31,
  2021 2020
CURRENT LIABILITIES 
Advances from Affiliates $284.0 $67.1 
Accounts Payable: 
General 198.8 231.7 
Affiliated Companies 24.4 44.0 
Long-term Debt Due Within One Year – Nonaffiliated
(March 31, 2021 and December 31, 2020 Amounts Include $88.9 and $88.7, Respectively, Related to Transition Funding and Restoration Funding)
88.9 88.7 
Accrued Taxes 107.1 78.3 
Accrued Interest
(March 31, 2021 and December 31, 2020 Amounts Include $3.2 and $2.5, Respectively, Related to Transition Funding and Restoration Funding)
54.7 43.9 
Obligations Under Operating Leases14.5 14.5 
Other Current Liabilities 83.4 108.6 
TOTAL CURRENT LIABILITIES 855.8 676.8 
 
NONCURRENT LIABILITIES   
Long-term Debt – Nonaffiliated
(March 31, 2021 and December 31, 2020 Amounts Include $392.7 and $403.9, Respectively, Related to Transition Funding and Restoration Funding)
4,721.3 4,731.7 
Deferred Income Taxes 1,024.3 1,016.7 
Regulatory Liabilities and Deferred Investment Tax Credits 1,272.0 1,270.8 
Obligations Under Operating Leases68.9 71.0 
Deferred Credits and Other Noncurrent Liabilities 68.3 57.2 
TOTAL NONCURRENT LIABILITIES 7,154.8 7,147.4 
 
TOTAL LIABILITIES 8,010.6 7,824.2 
 
Rate Matters (Note 4)00
Commitments and Contingencies (Note 5) 00
 
COMMON SHAREHOLDER’S EQUITY   
Paid-in Capital 1,457.9 1,457.9 
Retained Earnings 1,803.1 1,757.0 
Accumulated Other Comprehensive Income (Loss)(8.6)(8.9)
TOTAL COMMON SHAREHOLDER’S EQUITY 3,252.4 3,206.0 
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $11,263.0 $11,030.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
59


AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2021 and 2020
(in millions)
(Unaudited)
  Three Months Ended March 31,
  2021 2020
OPERATING ACTIVITIES    
Net Income $46.1 $47.6 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:   
Depreciation and Amortization 97.5 162.5 
Deferred Income Taxes 1.7 (7.6)
Allowance for Equity Funds Used During Construction(4.1)(5.1)
Property Taxes(71.1)(69.3)
Change in Other Noncurrent Assets (14.8)(10.8)
Change in Other Noncurrent Liabilities 14.7 3.2 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net (6.8)(34.3)
Fuel, Materials and Supplies 0.3 (7.6)
Accounts Payable 1.4 2.4 
Accrued Taxes, Net34.1 38.9 
Other Current Assets 0.3 (1.4)
Other Current Liabilities (15.2)(4.6)
Net Cash Flows from Operating Activities 84.1 113.9 
 
INVESTING ACTIVITIES   
Construction Expenditures (295.1)(327.5)
Change in Advances to Affiliates, Net0.3 200.1 
Other Investing Activities17.0 7.4 
Net Cash Flows Used for Investing Activities (277.8)(120.0)
 
FINANCING ACTIVITIES   
Change in Advances from Affiliates, Net 216.9 63.9 
Retirement of Long-term Debt – Nonaffiliated (11.2)(114.3)
Principal Payments for Finance Lease Obligations (1.7)(1.5)
Other Financing Activities0.3 0.4 
Net Cash Flows from (Used for) Financing Activities 204.3 (51.5)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding 10.6 (57.6)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period 28.8 157.8 
Cash, Cash Equivalents and Restricted Cash at End of Period $39.4 $100.2 
 
SUPPLEMENTARY INFORMATION   
Cash Paid for Interest, Net of Capitalized Amounts $30.0 $21.1 
Noncash Acquisitions Under Finance Leases 0.8 3.7 
Construction Expenditures Included in Current Liabilities as of March 31, 120.5 175.1 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
60




AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
61


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

RESULTS OF OPERATIONS

Summary of Investment in Transmission Assets for AEPTCo
As of March 31,
20212020
(in millions)
Plant In Service$10,144.5 $8,684.9 
Construction Work in Progress1,549.5 1,536.3 
Accumulated Depreciation and Amortization623.6 445.8 
Total Transmission Property, Net$11,070.4 $9,775.4 

First Quarter of 2021 Compared to First Quarter of 2020
AEP Transmission Company, LLC and Subsidiaries
Reconciliation of First Quarter of 2020 to First Quarter of 2021
Net Income
(in millions)
First Quarter of 2020$117.8 
Changes in Transmission Revenues:
Transmission Revenues66.1 
Total Change in Transmission Revenues66.1 
Changes in Expenses and Other:
Other Operation and Maintenance2.3 
Depreciation and Amortization(14.6)
Taxes Other Than Income Taxes(7.4)
Interest Income(0.7)
Allowance for Equity Funds Used During Construction0.5 
Interest Expense(4.5)
Total Change in Expenses and Other(24.4)
Income Tax Expense(7.8)
First Quarter of 2021$151.7 

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

Transmission Revenues increased $66 million primarily due to continued investment in transmission assets.

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

Depreciation and Amortization expenses increased $15 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $7 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 increased $8 million primarily due to an increase in pretax book income.
62




AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2021 and 2020
(in millions)
(Unaudited)
Three Months Ended March 31,
 2021 2020
REVENUES
Transmission Revenues$76.0 $61.3 
Sales to AEP Affiliates285.6 233.7 
Other Revenues0.1 0.6 
TOTAL REVENUES361.7 295.6 
EXPENSES  
Other Operation21.1 23.8 
Maintenance3.6 3.2 
Depreciation and Amortization70.6 56.0 
Taxes Other Than Income Taxes57.8 50.4 
TOTAL EXPENSES153.1 133.4 
OPERATING INCOME208.6 162.2 
Other Income (Expense):  
Interest Income - Affiliated0.1 0.8 
Allowance for Equity Funds Used During Construction16.7 16.2 
Interest Expense(34.1)(29.6)
INCOME BEFORE INCOME TAX EXPENSE191.3 149.6 
Income Tax Expense39.6 31.8 
NET INCOME$151.7 $117.8 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
63


AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY
For the Three Months Ended March 31, 2021 and 2020
(in millions)
(Unaudited)
  Paid-in
Capital
Retained
Earnings
Total
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2019 $2,480.6 $1,528.9 $4,009.5 
  
Capital Contribution from Member185.0 185.0 
Net Income 117.8 117.8 
TOTAL MEMBER'S EQUITY – MARCH 31, 2020$2,665.6 $1,646.7 $4,312.3 
  
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2020 $2,765.6 $1,947.3 $4,712.9 
Capital Contribution from Member124.0 124.0 
Net Income151.7 151.7 
TOTAL MEMBER'S EQUITY – MARCH 31, 2021$2,889.6 $2,099.0 $4,988.6 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
64


AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2021 and December 31, 2020
(in millions)
(Unaudited)
  March 31, December 31,
  2021 2020
CURRENT ASSETS    
Advances to Affiliates $106.1 $109.1 
Accounts Receivable: 
Customers 25.6 22.9 
Affiliated Companies 95.0 81.2 
Total Accounts Receivable 120.6 104.1 
Materials and Supplies 8.8 8.5 
Prepayments and Other Current Assets 3.4 14.1 
TOTAL CURRENT ASSETS 238.9 235.8 
 
TRANSMISSION PROPERTY   
Transmission Property 9,788.3 9,593.5 
Other Property, Plant and Equipment 356.2 329.5 
Construction Work in Progress 1,549.5 1,422.6 
Total Transmission Property 11,694.0 11,345.6 
Accumulated Depreciation and Amortization 623.6 572.8 
TOTAL TRANSMISSION PROPERTY – NET 11,070.4 10,772.8 
 
OTHER NONCURRENT ASSETS   
Regulatory Assets 14.0 15.1 
Deferred Property Taxes 190.1 220.1 
Deferred Charges and Other Noncurrent Assets 1.7 2.2 
TOTAL OTHER NONCURRENT ASSETS 205.8 237.4 
 
TOTAL ASSETS $11,515.1 $11,246.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
65


AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND MEMBER’S EQUITY
March 31, 2021 and December 31, 2020
(in millions)
(Unaudited)
  March 31, December 31,
  2021 2020
CURRENT LIABILITIES    
Advances from Affiliates $229.3 $156.7 
Accounts Payable:  
General 325.3 380.4 
Affiliated Companies 72.2 97.3 
Long-term Debt Due Within One Year – Nonaffiliated50.0 50.0 
Accrued Taxes 373.2 418.1 
Accrued Interest 48.2 23.9 
Obligations Under Operating Leases0.8 1.2 
Other Current Liabilities 12.3 9.9 
TOTAL CURRENT LIABILITIES 1,111.3 1,137.5 
 
NONCURRENT LIABILITIES   
Long-term Debt – Nonaffiliated 3,899.0 3,898.5 
Deferred Income Taxes 917.2 906.9 
Regulatory Liabilities 597.1 581.8 
Obligations Under Operating Leases0.4 0.4 
Deferred Credits and Other Noncurrent Liabilities 1.5 8.0 
TOTAL NONCURRENT LIABILITIES 5,415.2 5,395.6 
 
TOTAL LIABILITIES 6,526.5 6,533.1 
 
Rate Matters (Note 4) 00
Commitments and Contingencies (Note 5) 00
 
MEMBER’S EQUITY   
Paid-in Capital2,889.6 2,765.6 
Retained Earnings 2,099.0 1,947.3 
TOTAL MEMBER’S EQUITY 4,988.6 4,712.9 
 
TOTAL LIABILITIES AND MEMBER’S EQUITY $11,515.1 $11,246.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
66


AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2021 and 2020
(in millions)
(Unaudited)
  Three Months Ended March 31,
  20212020
OPERATING ACTIVITIES 
Net Income $151.7 $117.8 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: 
Depreciation and Amortization 70.6 56.0 
Deferred Income Taxes 8.3 13.7 
Allowance for Equity Funds Used During Construction (16.7)(16.2)
Property Taxes 30.0 28.4 
Change in Other Noncurrent Assets 1.4 2.4 
Change in Other Noncurrent Liabilities 0.6 0.6 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net (16.5)(22.0)
Materials and Supplies(0.3)0.4 
Accounts Payable (18.9)22.7 
Accrued Taxes, Net (35.1)(37.8)
Accrued Interest 24.3 19.4 
Other Current Assets 0.9 0.4 
Other Current Liabilities 1.4 1.2 
Net Cash Flows from Operating Activities 201.7 187.0 
 
INVESTING ACTIVITIES   
Construction Expenditures (400.5)(491.5)
Change in Advances to Affiliates, Net 3.0 (43.0)
Other Investing Activities (0.8)2.1 
Net Cash Flows Used for Investing Activities (398.3)(532.4)
 
FINANCING ACTIVITIES  
Capital Contributions from Member 124.0 185.0 
Change in Advances from Affiliates, Net 72.6 160.4 
Net Cash Flows from Financing Activities 196.6 345.4 
 
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 $8.9 $9.3 
Net Cash Paid for Income Taxes 0.1 
Construction Expenditures Included in Current Liabilities as of March 31, 244.5 290.6 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
67




APPALACHIAN POWER COMPANY
AND SUBSIDIARIES
68


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 Ended March 31,
20212020
 (in millions of KWhs)
Retail:  
Residential3,695 3,169 
Commercial1,457 1,477 
Industrial2,078 2,237 
Miscellaneous200 207 
Total Retail7,430 7,090 
Wholesale948 472 
Total KWhs8,378 7,562 

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 Ended March 31,
20212020
 (in degree days)
Actual – Heating (a)1,284 953 
Normal – Heating (b)1,315 1,324 
Actual – Cooling (c)20 
Normal – Cooling (b)

(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.

69


First Quarter of 2021 Compared to First Quarter of 2020
Appalachian Power Company and Subsidiaries
Reconciliation of First Quarter of 2020 to First Quarter of 2021
Net Income
(in millions)
First Quarter of 2020$115.3 
  
Changes in Gross Margin: 
Retail Margins40.9 
Margins from Off-system Sales0.9 
Transmission Revenues7.1 
Other Revenues(1.7)
Total Change in Gross Margin47.2 
  
Changes in Expenses and Other: 
Other Operation and Maintenance(31.3)
Depreciation and Amortization(13.6)
Taxes Other Than Income Taxes0.2 
Allowance for Equity Funds Used During Construction1.1 
Interest Expense(1.8)
Total Change in Expenses and Other(45.4)
  
Income Tax Expense5.4 
  
First Quarter of 2021$122.5 

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

Retail Margins increased $41 million primarily due to the following:
A $33 million increase in weather-related usage primarily driven by a 35% increase in heating degree days.
A $14 million increase due to rider revenues primarily in West Virginia. This increase was partially offset in other expense items below.
These increases were partially offset by:
An $8 million decrease in weather-normalized margins primarily in the commercial and industrial classes, partially offset in the residential class.
Transmission Revenues increased $7 million primarily due to an increase in transmission investment. This increase is partially offset in Depreciation and Amortization expenses below.

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

Other Operation and Maintenance expenses increased $31 million primarily due to the following:
A $13 million increase in distribution expense primarily due to vegetation management expenses. This increase was offset in Retail Margins above.
A $10 million increase in transmission expenses primarily due to an $8 million increase in recoverable PJM expenses. This increase was partially offset in Retail Margins above.
Depreciation and Amortization expenses increased $14 million primarily due to an increase in depreciation rates and a higher depreciable base. This increase is partially offset in Transmission Revenues above.
Income Tax Expense decreased $5 million primarily due to an increase in amortization of Excess ADIT. The increase in amortization of Excess ADIT is partially offset above in Gross Margin.



70




APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2021 and 2020
(in millions)
(Unaudited)
 Three Months Ended
 Three Months Ended March 31,
 20212020
REVENUES  
Electric Generation, Transmission and Distribution$764.2 $697.0 
Sales to AEP Affiliates50.1 49.7 
Other Revenues2.7 2.7 
TOTAL REVENUES817.0 749.4 
EXPENSES  
Fuel and Other Consumables Used for Electric Generation163.9 111.0 
Purchased Electricity for Resale90.1 122.6 
Other Operation150.4 134.0 
Maintenance65.2 50.3 
Depreciation and Amortization135.8 122.2 
Taxes Other Than Income Taxes37.7 37.9 
TOTAL EXPENSES643.1 578.0 
OPERATING INCOME173.9 171.4 
Other Income (Expense):  
Interest Income0.3 0.3 
Allowance for Equity Funds Used During Construction3.5 2.4 
Non-Service Cost Components of Net Periodic Benefit Cost4.7 4.7 
Interest Expense(54.9)(53.1)
INCOME BEFORE INCOME TAX EXPENSE127.5 125.7 
Income Tax Expense5.0 10.4 
NET INCOME$122.5 $115.3 
The common stock of APCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
71


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2021 and 2020
(in millions)
(Unaudited)
 Three Months Ended
 March 31,
20212020
Net Income$122.5 $115.3 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES 
Cash Flow Hedges, Net of Tax of $2.4 and $(1.1) in 2021 and 2020, Respectively9.0 (4.2)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.3) and $(0.3) in 2021 and 2020, Respectively(1.1)(0.9)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)7.9 (5.1)
TOTAL COMPREHENSIVE INCOME$130.4 $110.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
72


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Three Months Ended March 31, 2021 and 2020
(in millions)
(Unaudited)
Common
Stock
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
TOTAL COMMON SHAREHOLDER’S
   EQUITY - DECEMBER 31, 2019
$260.4 $1,828.7 $2,078.3 $5.0 $4,172.4 
Common Stock Dividends(50.0)(50.0)
Net Income115.3 115.3 
Other Comprehensive Loss(5.1)(5.1)
TOTAL COMMON SHAREHOLDER’S
   EQUITY - MARCH 31, 2020
$260.4 $1,828.7 $2,143.6 $(0.1)$4,232.6 
TOTAL COMMON SHAREHOLDER’S
   EQUITY - DECEMBER 31, 2020
$260.4 $1,828.7 $2,248.0 $7.2 $4,344.3 
Common Stock Dividends(12.5)(12.5)
Net Income122.5 122.5 
Other Comprehensive Income7.9 7.9 
TOTAL COMMON SHAREHOLDER’S
   EQUITY - MARCH 31, 2021
$260.4 $1,828.7 $2,358.0 $15.1 $4,462.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.

73


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2021 and December 31, 2020
(in millions)
(Unaudited)
March 31,December 31,
20212020
CURRENT ASSETS  
Cash and Cash Equivalents$4.8 $5.8 
Restricted Cash for Securitized Funding11.6 16.9 
Advances to Affiliates261.1 21.4 
Accounts Receivable:  
Customers146.4 142.8 
Affiliated Companies64.9 64.3 
Accrued Unbilled Revenues50.7 80.1 
Miscellaneous0.3 0.3 
Allowance for Uncollectible Accounts(2.1)(3.1)
Total Accounts Receivable260.2 284.4 
Fuel166.9 193.6 
Materials and Supplies101.2 99.6 
Risk Management Assets6.9 22.4 
Regulatory Asset for Under-Recovered Fuel Costs15.3 5.3 
Prepayments and Other Current Assets24.7 24.7 
TOTAL CURRENT ASSETS852.7 674.1 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation6,643.9 6,633.7 
Transmission3,931.7 3,900.5 
Distribution4,511.5 4,464.3 
Other Property, Plant and Equipment644.2 627.2 
Construction Work in Progress525.9 484.6 
Total Property, Plant and Equipment16,257.2 16,110.3 
Accumulated Depreciation and Amortization4,802.0 4,716.2 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET11,455.2 11,394.1 
OTHER NONCURRENT ASSETS  
Regulatory Assets727.1 686.3 
Securitized Assets203.9 210.1 
Employee Benefits and Pension Assets152.3 150.1 
Operating Lease Assets76.3 78.8 
Deferred Charges and Other Noncurrent Assets130.1 121.7 
TOTAL OTHER NONCURRENT ASSETS1,289.7 1,247.0 
TOTAL ASSETS$13,597.6 $13,315.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
74


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
March 31, 2021 and December 31, 2020
(Unaudited)
 March 31,December 31,
 20212020
 (in millions)
CURRENT LIABILITIES  
Advances from Affiliates$$18.6 
Accounts Payable:  
General247.1 212.0 
Affiliated Companies99.3 97.1 
Long-term Debt Due Within One Year – Nonaffiliated168.5 518.3 
Customer Deposits75.0 77.8 
Accrued Taxes114.4 109.9 
Accrued Interest73.8 49.9 
Obligations Under Operating Leases14.9 14.9 
Other Current Liabilities107.9 119.2 
TOTAL CURRENT LIABILITIES900.9 1,217.7 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated4,797.7 4,315.8 
Deferred Income Taxes1,763.1 1,749.9 
Regulatory Liabilities and Deferred Investment Tax Credits1,215.6 1,224.7 
Asset Retirement Obligations305.5 304.8 
Employee Benefits and Pension Obligations44.0 44.0 
Obligations Under Operating Leases61.9 64.4 
Deferred Credits and Other Noncurrent Liabilities46.7 49.6 
TOTAL NONCURRENT LIABILITIES8,234.5 7,753.2 
TOTAL LIABILITIES9,135.4 8,970.9 
Rate Matters (Note 4)00
Commitments and Contingencies (Note 5)00
COMMON SHAREHOLDER’S EQUITY  
Common Stock – NaN Par Value:  
Authorized – 30,000,000 Shares  
 Outstanding – 13,499,500 Shares260.4 260.4 
Paid-in Capital1,828.7 1,828.7 
Retained Earnings2,358.0 2,248.0 
Accumulated Other Comprehensive Income (Loss)15.1 7.2 
TOTAL COMMON SHAREHOLDER’S EQUITY4,462.2 4,344.3 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$13,597.6 $13,315.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
75


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2021 and 2020
(in millions)
(Unaudited)
 Three Months Ended March 31,
 20212020
OPERATING ACTIVITIES  
Net Income$122.5 $115.3 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and Amortization135.8 122.2 
Deferred Income Taxes(1.7)(5.1)
Allowance for Equity Funds Used During Construction(3.5)(2.4)
Mark-to-Market of Risk Management Contracts12.1 29.6 
Deferred Fuel Over/Under-Recovery, Net(6.4)7.6 
Change in Other Noncurrent Assets(54.3)(24.4)
Change in Other Noncurrent Liabilities6.8 (16.1)
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net25.1 (2.6)
Fuel, Materials and Supplies25.2 (5.5)
Accounts Payable46.0 (86.6)
Accrued Taxes, Net8.2 14.5 
Other Current Assets(3.6)19.2 
Other Current Liabilities3.1 (11.1)
Net Cash Flows from Operating Activities315.3 154.6 
INVESTING ACTIVITIES  
Construction Expenditures(187.5)(219.1)
Change in Advances to Affiliates, Net(239.7)0.3 
Other Investing Activities6.6 1.1 
Net Cash Flows Used for Investing Activities(420.6)(217.7)
FINANCING ACTIVITIES  
Issuance of Long-term Debt – Nonaffiliated494.3 
Change in Advances from Affiliates, Net(18.6)118.6 
Retirement of Long-term Debt – Nonaffiliated(362.5)(12.2)
Principal Payments for Finance Lease Obligations(1.9)(1.8)
Dividends Paid on Common Stock(12.5)(50.0)
Other Financing Activities0.2 0.2 
Net Cash Flows from Financing Activities99.0 54.8 
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding(6.3)(8.3)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period22.7 26.8 
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period$16.4 $18.5 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$28.9 $31.9 
Noncash Acquisitions Under Finance Leases0.4 1.9 
Construction Expenditures Included in Current Liabilities as of March 31,96.1 103.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
76




INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES
77


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

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 Three Months Ended March 31,
 20212020
 (in millions of KWhs)
Retail:  
Residential1,532 1,455 
Commercial1,078 1,122 
Industrial1,802 1,845 
Miscellaneous17 18 
Total Retail4,429 4,440 
Wholesale1,945 1,693 
Total KWhs6,374 6,133 

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 Ended March 31,
 20212020
 (in degree days)
Actual – Heating (a)2,056 1,836 
Normal – Heating (b)2,170 2,182 
Actual – Cooling (c)— — 
Normal – Cooling (b)

(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.
78


First Quarter of 2021 Compared to First Quarter of 2020
Indiana Michigan Power Company and Subsidiaries
Reconciliation of First Quarter of 2020 to First Quarter of 2021
Net Income
(in millions)
First Quarter of 2020$92.3 
  
Changes in Gross Margin: 
Retail Margins(2.6)
Margins from Off-system Sales(0.3)
Transmission Revenues(0.5)
Other Revenues1.9 
Total Change in Gross Margin(1.5)
  
Changes in Expenses and Other: 
Other Operation and Maintenance(9.8)
Depreciation and Amortization(15.3)
Taxes Other Than Income Taxes0.2 
Other Income0.5 
Non-Service Cost Components of Net Periodic Benefit Cost(0.1)
Interest Expense3.4 
Total Change in Expenses and Other(21.1)
  
Income Tax Expense1.1 
  
First Quarter of 2021$70.8 

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

Retail Margins decreased $3 million primarily due to the following:
A $16 million decrease in weather-normalized wholesale margins, including the loss of a significant wholesale contract.
A $7 million decrease in weather-normalized retail margins.
These decreases were partially offset by:
A $12 million increase due to the Indiana and Michigan base rate cases and rider revenues. This increase was partially offset in other expense items below.
An $8 million increase in weather-related usage primarily due to a 12% increase in heating degree days.

Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses increased $10 million primarily due to the following:
A $9 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses. This increase was partially offset in Retail Margins above.
A $4 million increase due to a decreased Nuclear Electric Insurance Limited distribution in 2021.
A $4 million increase in employee-related expenses.
These increases were partially offset by:
A $5 million decrease in customer service and information expenses primarily due to an Indiana order to refund an over collection of Demand Side Management expenses. This decrease was offset in Retail Margins above.
A $3 million decrease in Cook Plant refueling outage expenses.
Depreciation and Amortization expenses increased $15 million primarily due to a higher depreciable base and an increase in depreciation rates. This increase was partially offset in Retail Margins above.
Interest Expense decreased $3 million primarily due to a decrease in interest rates on variable rate notes.
79



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2021 and 2020
(in millions)
(Unaudited)
 Three Months Ended March 31,
 20212020
REVENUES  
Electric Generation, Transmission and Distribution$547.7 $553.4 
Sales to AEP Affiliates0.8 2.9 
Other Revenues – Affiliated14.3 12.5 
Other Revenues – Nonaffiliated1.7 1.5 
TOTAL REVENUES564.5 570.3 
EXPENSES  
Fuel and Other Consumables Used for Electric Generation36.3 53.2 
Purchased Electricity for Resale47.3 50.1 
Purchased Electricity from AEP Affiliates51.6 36.2 
Other Operation154.6 144.7 
Maintenance49.0 49.1 
Depreciation and Amortization109.2 93.9 
Taxes Other Than Income Taxes26.2 26.4 
TOTAL EXPENSES474.2 453.6 
OPERATING INCOME90.3 116.7 
Other Income (Expense):  
Other Income3.0 2.5 
Non-Service Cost Components of Net Periodic Benefit Cost4.1 4.2 
Interest Expense(27.3)(30.7)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)70.1 92.7 
Income Tax Expense (Benefit)(0.7)0.4 
NET INCOME$70.8 $92.3 
The common stock of I&M is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
80


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2021 and 2020
(in millions)
(Unaudited)
 Three Months Ended March 31,
20212020
Net Income$70.8 $92.3 
OTHER COMPREHENSIVE INCOME, NET OF TAXES 
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 in 2021 and 2020, Respectively0.5 0.4 
TOTAL COMPREHENSIVE INCOME$71.3 $92.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
81


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Three Months Ended March 31, 2021 and 2020
(in millions)
(Unaudited)
Common
Stock
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2019$56.6 $980.9 $1,518.5 $(11.6)$2,544.4 
Common Stock Dividends  (21.3) (21.3)
ASU 2016-13 Adoption0.4 0.4 
Net Income  92.3  92.3 
Other Comprehensive Income   0.4 0.4 
TOTAL COMMON SHAREHOLDER’S EQUITY - MARCH 31, 2020$56.6 $980.9 $1,589.9 $(11.2)$2,616.2 
     
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2020$56.6 $980.9 $1,718.7 $(7.0)$2,749.2 
Common Stock Dividends(25.0)(25.0)
Net Income70.8 70.8 
Other Comprehensive Income0.5 0.5 
TOTAL COMMON SHAREHOLDER’S EQUITY - MARCH 31, 2021$56.6 $980.9 $1,764.5 $(6.5)$2,795.5 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
82


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2021 and December 31, 2020
(in millions)
(Unaudited)
March 31,December 31,
 20212020
CURRENT ASSETS  
Cash and Cash Equivalents$2.8 $3.3 
Advances to Affiliates13.3 13.3 
Accounts Receivable:  
Customers32.7 44.0 
Affiliated Companies48.8 51.3 
Accrued Unbilled Revenues0.4 
Miscellaneous1.6 2.0 
Allowance for Uncollectible Accounts(0.4)(0.3)
Total Accounts Receivable83.1 97.0 
Fuel80.2 86.0 
Materials and Supplies172.8 175.8 
Risk Management Assets0.9 3.6 
Accrued Tax Benefits1.0 10.3 
Regulatory Asset for Under-Recovered Fuel Costs3.2 5.4 
Prepayments and Other Current Assets17.9 24.1 
TOTAL CURRENT ASSETS375.2 418.8 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation5,302.4 5,264.7 
Transmission1,696.9 1,696.4 
Distribution2,634.3 2,594.6 
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)707.4 686.7 
Construction Work in Progress369.5 362.4 
Total Property, Plant and Equipment10,710.5 10,604.8 
Accumulated Depreciation, Depletion and Amortization3,647.3 3,552.5 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET7,063.2 7,052.3 
OTHER NONCURRENT ASSETS  
Regulatory Assets403.4 404.8 
Spent Nuclear Fuel and Decommissioning Trusts3,414.3 3,306.7 
Operating Lease Assets196.8 218.1 
Deferred Charges and Other Noncurrent Assets241.3 237.6 
TOTAL OTHER NONCURRENT ASSETS4,255.8 4,167.2 
TOTAL ASSETS$11,694.2 $11,638.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 114.
83


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
March 31, 2021 and December 31, 2020
(dollars in millions)
(Unaudited)
 March 31,December 31,
 20212020
CURRENT LIABILITIES  
Advances from Affiliates