0000004904aep:OhioPowerCoMemberaep:A2020OhioBaseRateCaseMember2021-01-012021-06-300000004904us-gaap:FairValueInputsLevel3Membersrt:WeightedAverageMemberaep:EnergyContractsMember2021-06-300000004904aep:OhioPowerCoMemberaep:IndustrialMember2020-01-012020-06-30







UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549
FORM 10-Q
[X]
☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended March 31, 2018June 30, 2021
ORor
[ ]☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from ____ to ____
CommissionRegistrants; States of Incorporation;I.R.S. Employer
File NumberAddress and Telephone NumberIdentification Nos.
1-3525AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation)13-4922640
333-221643AEP TEXAS INC. (A Delaware Corporation)51-0007707
333-217143AEP TRANSMISSION COMPANY, LLC (A Delaware Limited Liability Company)46-1125168
1-3457APPALACHIAN POWER COMPANY (A Virginia Corporation)54-0124790
1-3570INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation)35-0410455
1-6543OHIO POWER COMPANY (An Ohio Corporation)31-4271000
0-343PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation)73-0410895
1-3146SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation)72-0323455
1 Riverside Plaza, Columbus, Ohio 43215-2373
Telephone (614) 716-1000
CommissionRegistrants;I.R.S. Employer
File NumberAddress and Telephone Number States of IncorporationIdentification Nos.
1-3525AMERICAN ELECTRIC POWER CO INC.New York13-4922640
333-221643AEP TEXAS INC.Delaware51-0007707
333-217143AEP TRANSMISSION COMPANY, LLCDelaware46-1125168
1-3457APPALACHIAN POWER COMPANYVirginia54-0124790
1-3570INDIANA MICHIGAN POWER COMPANYIndiana35-0410455
1-6543OHIO POWER COMPANYOhio31-4271000
0-343PUBLIC SERVICE COMPANY OF OKLAHOMAOklahoma73-0410895
1-3146SOUTHWESTERN ELECTRIC POWER COMPANYDelaware72-0323455
1 Riverside Plaza,Columbus,Ohio43215-2373
Telephone(614)716-1000
Securities registered pursuant to Section 12(b) of the Act:
RegistrantTitle of each classTrading SymbolName of Each Exchange on Which Registered
American Electric Power Company Inc.Common Stock, $6.50 par valueAEPThe 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 and posted on their corporate websites, if any, every Interactive Data File required to be submitted and posted 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 and post such files).
YesxNo¨☐
Indicate by check mark whether American Electric Power Company, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large Accelerated filer
xAccelerated filer¨☐Non-accelerated filer¨   (Do not check if a smaller reporting company)☐
Smaller reporting company¨
☐
Emerging growth company¨
☐
Indicate by check mark whether AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, non-accelerated filers, smaller reporting companies, or emerging growth companies.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large Accelerated filer ¨             Accelerated filer ¨             Non-accelerated filer x   (Do not check if a smaller reporting company)
Smaller reporting company ¨
Emerging growth company ¨
Large Accelerated filer☐Accelerated filer☐Non-accelerated filerx
Smaller reporting company☐Emerging growth company☐
If an emerging growth company, indicate by check mark if the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.¨
☐
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).
Yes¨☐Nox
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 26, 2018
American Electric Power Company, Inc.492,523,470
($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 Company7,536,640
($18 par value)

(a)100% interest is held by AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of American Electric Power Company, Inc.
NANot applicable.



Number of shares
of common stock
outstanding of the
Registrants as of
July 22, 2021
American Electric Power Company, Inc.500,251,339 
($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, 2018June 30, 2021
Page
Number
Glossary of Terms
i
Forward-Looking Information
v
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
1
Condensed Consolidated Financial Statements
4651
AEP Texas Inc. and Subsidiaries:
Management’s Narrative Discussion and Analysis of Results of Operations
5358
Condensed Consolidated Financial Statements
5663
AEP Transmission Company, LLC and Subsidiaries:
Management’s Narrative Discussion and Analysis of Results of Operations
6370
Condensed Consolidated Financial Statements
6573
Appalachian Power Company and Subsidiaries:
Management’s Narrative Discussion and Analysis of Results of Operations
7179
Condensed Consolidated Financial Statements
7483
Indiana Michigan Power Company and Subsidiaries:
Management’s Narrative Discussion and Analysis of Results of Operations
8190
Condensed Consolidated Financial Statements
8495
Ohio Power Company and Subsidiaries:
Management’s Narrative Discussion and Analysis of Results of Operations
91102
Condensed Consolidated Financial Statements
94107
Public Service Company of Oklahoma:
Management’s Narrative Discussion and Analysis of Results of Operations
101114
Condensed Financial Statements
104119
Southwestern Electric Power Company Consolidated:
Management’s Narrative Discussion and Analysis of Results of Operations
111126
Condensed Consolidated Financial Statements
114131
Index of Condensed Notes to Condensed Financial Statements of Registrants
120137
Controls and Procedures
202236








Part II.  OTHER INFORMATION
Item 1.  Legal Proceedings
203237
Item 1A.  Risk Factors
203237
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds
204237
Item 3.  Defaults Upon Senior Securities
237
Item 4.  Mine Safety Disclosures
204237
Item 5.  Other Information
204237
Item 6.  Exhibits:  Exhibits
205238
Exhibit 10(a)
SIGNATUREExhibit 10(b)
Exhibit 12
Exhibit 31(a)
Exhibit 31(b)
Exhibit 32(a)
Exhibit 32(b)
Exhibit 95
Exhibit 101.INS
Exhibit 101.SCH
Exhibit 101.CAL
Exhibit 101.DEF
Exhibit 101.LAB
Exhibit 101.PRE
SIGNATURE
206239
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 variable interest entityVIE 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.
AEPEP
AEPEPAEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, hedging activities, asset management and commercial and industrial sales in the deregulated Ohio and Texas 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 seven wholly-owned transmission companies.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.
ALJAdministrative Law Judge.
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 variable interest entityVIE formed for the purpose of issuing and servicing securitization bonds related to the under-recovered ENECExpanded Net Energy Cost deferral balance.
APSCArkansas Public Service Commission.
ARAMAverage Rate Assumption Method, an IRS approved method used to calculate the reversal of Excess Accumulated Deferred Income Taxes for ratemaking purposes.
ASCAROAccounting Standard Codification.Asset Retirement Obligations.
ASUAccounting Standards Update.
CAAClean Air Act.
CAIRClean Air Interstate Rule.
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, 2,2782,288 MW nuclear plant owned by I&M.
i




TermMeaning
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 VI LLC,X, DCC Fuel VII,XI, DCC Fuel VIII,XII, DCC Fuel IX,XIII, DCC Fuel XXIV, DCC Fuel XV and DCC Fuel XIXVI, consolidated variable interest entitiesVIEs formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
Desert SkyDesert Sky Wind Farm, a 160.5 MW wind electricity generation facility located on Indian Mesa in Pecos County, Texas.
DHLC Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.

i


TermMeaning
DHLC is a non-consolidated VIE of SWEPCo.
DIRDistribution Investment Rider.
EISEnergy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated variable interest entityVIE of AEP.
ENECELGExpanded Net Energy Cost.Effluent 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.
ETREffective tax rates.
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.
Global SettlementIn February 2017, the PUCO approved a settlement agreement filed by OPCo in December 2016 which resolved all remaining open issues on remand from the Supreme Court of Ohio in OPCo’s 2009 - 2011 and June 2012 - May 2015 ESP filings. It also resolved all open issues in OPCo’s 2009, 2014 and 2015 SEET filings and 2009, 2012 and 2013 Fuel Adjustment Clause Audits.
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.
KPSC
KPSCKentucky Public Service Commission.
kVKilovolt.
KWhKilowatthour.Kilowatt-hour.
LPSC Louisiana Public Service Commission.
Market Based MechanismMATSAn order fromMercury and Air Toxic Standards.
MaverickMaverick, part of the LPSC established to evaluate proposals to construct or acquire generating capacity. The LPSC directs that the market based mechanism shall be a request for proposal competitive solicitation process.North Central Wind Energy Facilities, consists of 287 MWs of wind generation in Oklahoma.
MISO Midcontinent Independent System Operator.
ii




TermMeaning
MMBtu Million British Thermal Units.
MPSCMichigan Public Service Commission.
MTM Mark-to-Market.
MW Megawatt.
MWh Megawatthour.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.
NO2x
Nitrogen dioxide.
NOx
Nitrogen oxide.
NSR New Source Review.
OATTOpen Access Transmission Tariff.
OCC Corporation Commission of the State of Oklahoma.

ii


TermOklaunion Power StationMeaning
Ohio Phase-in-Recovery FundingOhio Phase-in-Recovery Funding LLC, a wholly-owned subsidiary of OPCoA retired, single unit coal-fired generation plant totaling 650 MW located in Vernon, Texas. The plant was jointly-owned by AEP Texas, PSO and a consolidated variable interest entity formed for the purpose of issuing and servicing securitization bonds related to phase-in recovery property.certain nonaffiliated entities.
OPCo Ohio Power Company, an AEP electric utility subsidiary.
OPEB Other Postretirement Benefit Plans.Benefits.
OTC Over the counter.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 nontradingnon-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.
iii




TermMeaning
ROEReturn on Equity.
RPMReliability Pricing Model.
RSRRetail Stability Rider.
RTO Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine Sabine Mining Company, a lignite mining company that is a consolidated variable interest entityVIE for AEP and SWEPCo.
SCR
Selective Catalytic Reduction, NOx reduction technology at Rockport Plant.
SECU.S. Securities and Exchange Commission.
SEETSempra Renewables LLCSignificantly Excessive Earnings Test.Sempra 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.
SSOStandard service offer.
State TranscosAEPTCo’s seven wholly-owned, FERC regulated, transmission only electric utilities, each of which isare geographically aligned with AEPAEP’s existing utility operating companies.
SundanceSundance, acquired in April 2021 as part of the North Central Wind Energy Facilities, consists of 199 MWs of wind generation in Oklahoma.
SWEPCo Southwestern Electric Power Company, an AEP electric utility subsidiary.
Tax ReformOn December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal Revenue Code of 1986, including a reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018.
TCCFormerly AEP Texas Central Company, now a division of AEP Texas.
Texas Restructuring LegislationLegislation enacted in 1999 to restructure the electric utility industry in Texas.
TNCFormerly Texas North Company, now a division of AEP Texas.
TRATennessee Regulatory Authority.
Transition Funding AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated variable interest entitiesVIE formed for the purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation.

iii


TermMeaning
In July 2020, the final AEP Texas Central Transition Funding II securitization bond matured.
Transource EnergyTransource Energy, LLC, a consolidated variable interest entityVIE formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates.
TrentTraverseTrentTraverse, part of the North Central Wind Farm, a 150 MWEnergy Facilities, consists of 999 MWs of wind electricity generation facility located between Abilene and Sweetwater in West Texas.Oklahoma.
Turk Plant John W. Turk, Jr. Plant, a 600650 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.
UMWAUnited Mine Workers of America.
UPAUnit Power Agreement.
Utility Money Pool Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
VIEVariable Interest Entity.
Virginia SCC Virginia State Corporation Commission.
Wind Catcher ProjectWind Catcher Energy Connection Project, a joint PSO and SWEPCo project which includes the acquisition of a wind generation facility, totaling approximately 2,000 MW of wind generation, and the construction of a generation interconnection tie-line totaling approximately 350 miles.
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 “Item 7“Part I – Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the 2017 Annual Report,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:
Ÿ•Economic growth or contraction within and changesChanges in economic conditions, electric market demand and demographic patterns in AEP service territories.
Ÿ•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.
Ÿ•Volatility in the financial markets, particularly developments affecting the availability or cost of capital to finance new capital projects and refinance existing debt.
Ÿ•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.
Ÿ•Electric load and customer growth.Decreased demand for electricity.
Ÿ•Weather conditions, including storms and drought conditions, and the ability to recover significant storm restoration costs.
Ÿ•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 spent nuclear fuel.SNF.
Ÿ•AvailabilityThe availability of fuel and necessary generation capacity and the performance of generation plants and the availability of fuel, including processed nuclear fuel, parts and service from reliable vendors.plants.
Ÿ•The ability to recover fuel and other energy costs through regulated or competitive electric rates.
Ÿ•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.
Ÿ•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 particulate matterPM and other substances that could impact the continued operation, cost recovery and/or profitability of generation plants and related assets.
Ÿ•Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including coal ash and nuclear fuel.
Ÿ•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 and excess accumulated deferred income taxes.compliance.
Ÿ•Resolution of litigation.
Ÿ•The ability to constrain operation and maintenance costs.
Ÿ•Prices and demand for power generated and sold at wholesale.
Ÿ•Changes in technology, particularly with respect to energy storage and new, developing, alternative or distributed sources of generation.
Ÿ•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.
Ÿ•Volatility and changes in markets for capacity and electricity, coal and other energy-related commodities, particularly changes in the price of natural gas.
Ÿ•Changes in utility regulation and the allocation of costs within regional transmission organizations,RTOs including ERCOT, PJM and SPP.
v




Ÿ•Changes in the creditworthiness of the counterparties with contractual arrangements, including participants in the energy trading market.
Ÿ•Actions of rating agencies, including changes in the ratings of debt.
Ÿ•The impact of volatility in the capital markets on the value of the investments held by the pension, other postretirement benefit plans,OPEB, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements.

v


•
ŸAccounting pronouncementsstandards periodically issued by accounting standard-setting bodies.
Ÿ•Impact of federal tax reform on customer rates, income tax expense and cash flows.
ŸOther risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cybernaturally 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.information, except as required by law.  For a more detailed discussion of these factors, see “Risk Factors” in Part I of the 20172020 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 RegistrantsThe Company may use its website as a distribution channel for material company information. Financial and other important information regarding the Investors section of AEP’sCompany is routinely posted on and accessible through the Company’s website (www.aep.com) to communicate with investors about the Registrants. It is possible that the financialat www.aep.com/investors/. In addition, you may automatically receive email alerts and other information posted there could be deemed to be material information. The information on AEP’s website is not part of this report.about the Company when you enroll your email address by visiting the “Email Alerts” section at www.aep.com/investors/.

vi










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


EXECUTIVE OVERVIEW


Customer DemandImpacts of Severe Winter Weather


AEP’s weather-normalizedIn 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 June 30, 2021, an estimated $65 million of capital expenditures and $144 million of restoration expenses have been incurred related to the severe winter weather. Approximately $138 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. KPCo intends to seek recovery of these incremental storm restoration costs in their next base rate case while APCo and SWEPCo are expected to seek recovery in separate filings. 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 June 30, 2021, PSO and SWEPCo have deferred regulatory assets of $669 million and $453 million, respectively, relating to natural gas expenses and purchases of electricity incurred from February 9, 2021, to February 20, 2021, as a result of severe winter weather. SWEPCo’s deferred regulatory asset consists of $116 million, $161 million and $176 million related to the Arkansas, Louisiana and Texas jurisdictions, respectively. 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 sales volumescustomer 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% which has been supported by APSC staff. Various other parties have recommended recovery periods ranging from 5-20 years with a pretax rate of return of 1.65%. In July 2021, the APSC ordered more testimony regarding the option of utilizing securitization to recover the fuel costs. Once testimony concludes, a hearing will be scheduled. The prudency of these fuel costs is expected to be addressed in a separate proceeding.

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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 these retail fuel costs over a longer period than what the FAC traditionally allows. In April 2021, SWEPCo began recovery of its Louisiana jurisdictional share of these fuel costs based on a five year recovery 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 at an interim rate of 0.75%, over a longer time period than what the FAC traditionally allows. Also in April 2021, legislation was enacted in Oklahoma to securitize the extraordinary fuel and purchase of electricity costs impacting the utilities within the state. Under the legislation, the OCC has the authority to determine, after receiving an application from a rate-regulated utility, if the extraordinary fuel and purchase of electricity costs incurred in February 2021 may be mitigated through securitization to reduce the impact on customer bills. PSO has filed an application for a financing order to pursue securitization.

SWEPCo expects to make a filing with the PUCT in the third 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

During the first quarter of 2018 increased by 1.5%2021, SWEPCo billed wholesale customers $104 million resulting from the firstsevere winter weather events. SWEPCo worked with wholesale customers to establish payment terms for the outstanding accounts receivable. As of June 30, 2021, $63 million of accounts receivable from wholesale customers are outstanding. 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 and six months ended June 30, 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.

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. In 2021, weather-normalized customer demand has improved from the pandemic levels experienced in 2020. Management expects continued improvement during the remainder of 2021 as additional vaccinations occur and economic activity improves.

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 June 30, 2021, AEP’s electric operating companies have resumed customary disconnection practices in all regulated jurisdictions with the exception of Virginia. AEP continues to work with regulators and stakeholders in Virginia and management currently anticipates resuming customary disconnection practices in the third quarter of 2017. AEP’s first quarter 2018 industrial sales volumes increased 2.5% compared2021.
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AEP has been and continues to be proactive in engaging with customers to collect payments or establish payment arrangements for outstanding balances. As of June 30, 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.

The Registrants continue to take steps to mitigate the potential risks to customers, suppliers and employees posed by the spread of COVID-19. As of June 30, 2021, there has been no material adverse impact to the firstRegistrants’ business operations and customer service as a result of the current remote work model. In the second quarter of 2017. The growth2021, management announced a Future of Work model designating employees as: (a) On-Site employees, (b) Hybrid employees and (c) Remote employees. Management currently expects to begin transitioning On-Site employees back to their AEP workplace and Hybrid employees with set schedules back to their AEP workplace in industrial sales was spread across most industriesAugust 2021. Remote employees will begin transitioning back to their AEP workplace in September 2021 on an as-needed basis. Management will continue to review and most operating companies. Weather-normalized residentialmodify plans as conditions change.

In 2021, the Registrants have experienced certain supply chain disruptions driven by several factors including staffing and commercial sales increased 1.4%travel issues caused by the COVID-19 pandemic, the economic recovery from the pandemic, labor shortages and 0.5%shortages in the first quarteravailability of 2018, respectively, from the first quarter of 2017.

Federal Tax Reform

In December 2017, legislation referred to as Tax Reform was signed into law. Tax Reform includes significant changes to the Internal Revenue Code of 1986, as amended, (the Code) andcertain raw materials. These supply chain disruptions have not had a material impact on the Registrants financial statements in the reporting period of its enactment. Tax Reform lowered the corporate federal income tax rate from 35% to 21%. Tax Reform provisions related to regulated public utilities generally allow for the continued deductibility of interest expense, eliminate bonus depreciation for certain property acquired after September 27, 2017 and continue certain rate normalization requirements for accelerated depreciation benefits.

The Registrants expect the mechanism and time period to provide the benefits of Tax Reform to customers will continue to vary by jurisdiction. Tax Reform did not have a material impact on net income in the first quarter of 2018 and is not expected to have a material impact on future net income. However, the Registrants anticipate a decrease in future cash flows primarily due to the elimination of bonus depreciation, the reduction in the federal tax rate from 35% to 21% and the flow back of excess accumulated deferred income taxes (Excess ADIT). Further, the Registrants expect that access to capital markets will be sufficient to satisfy any liquidity needs that result from any such decrease in future cash flows.

Provisional Amounts

The Registrants applied Staff Accounting Bulletin 118 (SAB 118), issued by the SEC staff in December 2017, and made reasonable estimates for the measurement and accounting of the effects of Tax Reform which are reflected in the financial statements as provisional amounts based on the best information available. While the Registrants were able to make reasonable estimates of the impact of Tax Reform in 2017, the final impact may differ from the recorded provisional amounts to the extent refinements are made to the estimated cumulative differences or as a result of additional guidance or technical corrections that may be issued by the IRS that may impact management’s interpretation and assumptions utilized. The Registrants expect to complete the analysis of the provisional items during the second half of 2018.

Reduction in the Corporate Federal Income Tax Rate - Pending Rate Reductions

State utility commissions have issued orders or instructions requiring public utilities, including the Registrants, to record liabilities to reflect the impact of the reduction in the corporate federal income tax rate in excess of the enacted corporate federal income tax rate of 21% beginning in 2018. During the first quarter of 2018, AEP recorded estimated provisions for revenue refunds totaling $120 million as a result of the reduction in the corporate federal tax rate.



Excess Accumulated Deferred Income Taxes - Pending Rate Reductions

As of March 31, 2018, the Registrants have approximately $4.4 billion of Excess ADIT, as well as an incremental liability of $1.2 billion to reflect the $4.4 billion Excess ADIT on a pre-tax basis, presented in Regulatory Liabilities and Deferred Investment Tax Credits on the balance sheets.  The Excess ADIT is reflected on a pretax basis to appropriately contemplate future tax consequences in the periods when the regulatory liability is settled.  As of March 31, 2018, approximately $3.4 billion of the Excess ADIT relates to temporary differences associated with depreciable property subject to rate normalization requirements.

As reflected in the Registrants’ respective estimated annual ETR for 2018, AEP’s regulated public utilities began amortizing the Excess ADIT associated with certain depreciable property subject to rate normalization requirements using the ARAM during the first quarter of 2018. This amortization resulted in a $17 million reduction in Income Tax Expense in the first quarter of 2018. As a result of state utility commission orders or instructions, the Registrants recorded estimated provisions for revenue refund offsetting the amortization of the Excess ADIT totaling $17 million in the first quarter of 2018.

In addition, with respect to the remaining $1 billion of Excess ADIT recorded in Regulatory Liabilities and Deferred Investment Tax Credits that are not subject to rate normalization requirements, the Registrants continue to work with the various state utility commissions to determine the appropriate mechanism and time period to provide these benefits of Tax Reform to customers. The corresponding reduction in Income Tax Expense will be reported in the interim period in which these benefits of Tax Reform are provided to customers.

Merchant Generation Assets

In September 2016, AEP signed an agreement to sell Darby, Gavin, Lawrenceburg and Waterford Plants totaling 5,329 MWs of competitive generation to a nonaffiliated party. The sale closed in January 2017 for approximately $2.2 billion. The net proceeds from the transaction were approximately $1.2 billion in cash after taxes, repayment of debt associated with these assets and transaction fees, which resulted in an after tax gain of approximately $129 million. AEP primarily used these proceeds to reduce outstanding debt and invest in its regulated businesses including transmission, and contracted renewable projects. See “Dispositions” section of Note 6 for additional information.

In February 2017, AEP signed an agreement to sell its 25.4% ownership share of Zimmer Plant to Dynegy Corporation. Simultaneously, AEP signed an agreement to purchase Dynegy Corporation’s 40% ownership share of Conesville Plant, Unit 4. The transactions closed in the second quarter of 2017 and did not have a material impact on net income, cash flows orand financial condition.

In December 2017, AEP signedcondition, but have extended lead times for certain goods and services. Management has implemented risk mitigation strategies in an amendmentattempt to mitigate the Cardinal Station Agreement with Buckeye Power Incorporated, which terminates certain commercial arrangements between the parties and transitions management oversight and administrative supportimpacts of the Cardinal facility from AEP to Buckeye Power Incorporated.  The amendment required approval from Rural Utilities Service and the FERC, which were obtained in February 2018. The new amendment became effective March 2018 and did not havethese supply chain disruptions. However, a material impact on net income, cash flows or financial condition.

Management continues to evaluate potential alternatives for its remaining merchant generation assets. These potential alternatives may include, but are not limited to, transfer or sale of AEP’s ownership interestsprolonged continuation or a wind downfuture increase in the severity of merchant coal-fired generation fleet operations. Management has not set a specific time frame for a decision on these assets. These alternativessupply chain disruptions could result in additional lossesimpact the cost of certain goods and services and extend lead times which could reduce future net income and cash flows and impact financial condition.


Customer Demand

AEP’s weather-normalized retail sales volumes for the second quarter of 2021 increased by 6.3% from the second quarter of 2020. Weather-normalized residential sales decreased by 3.1% in the second quarter of 2021 from the second quarter of 2020. AEP’s second quarter 2021 industrial sales volumes increased by 12.8% compared to the second quarter of 2020. The increase in industrial sales was spread across many industries. Weather-normalized commercial sales increased 10% in the second quarter of 2021 from the second quarter of 2020.

AEP’s weather-normalized retail sales volumes for the six months ended June 30, 2021 increased by 1.9% compared to the six months ended June 30, 2020. Weather-normalized residential sales decreased by 0.5% for the six months ended June 30, 2021 compared to the six months ended June 30, 2020. AEP’s industrial sales volumes for the six months ended June 30, 2021 increased by 2.8% compared to the six months ended June 30, 2020. The recovery in industrial sales volumes was spread across many industries. Weather-normalized commercial sales increased 3.9% for the six months ended June 30, 2021 compared to the six months ended June 30, 2020.

The increase in industrial and commercial sales volumes is primarily the result of the COVID-19 pandemic’s impact on the second quarter of 2020 when public health restrictions significantly disrupted economic activity and demand for energy in AEP’s service territory. Similarly, the decline in weather-normalized residential sales volumes is driven by the cessation of stay at home restrictions that were in place in 2020 and the gradual return of customers to the workplace.


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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 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. In May 2021, the Virginia Supreme Court denied APCo’s petition for an interim rate increase and denied the request for an expedited schedule on APCo’s appeals.

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. The initial negative impact for the write-off of closed coal-fired plant asset balances would potentially be partially offset by an increase in base rates for earning below APCo’s 2017-2019 authorized ROE band.
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•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 took place with the PUCO in May 2021 and initial briefs were filed in June 2021 followed by reply briefs in July 2021. An order from the PUCO is expected by the end of 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 June 30, 2021, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $83 million ($81 million of which has been deferred as a regulatory asset related to the Louisiana jurisdiction) and incremental capital expenditures of $30 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 and agreeing with the PUCT’s judgment affirming the prudence of the Turk Plant.No parties filed a motion for rehearing with the Texas Supreme Court. As of June 30, 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, 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 OPCo’s 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 an alleged racketeering 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. On May 10, 2021, the defendants filed a motion to dismiss the securities litigation for failure to state a claim, and under the Court’s briefing schedule the motion will be fully briefed by July 26, 2021. In addition, four AEP shareholders have filed derivative actions purporting
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to assert claims on behalf of AEP against certain AEP officers and directors. See Litigation Related to Ohio House Bill 6 section of Litigation below for additional information.

In March 2021, the Governor of Ohio signed legislation that, among other things, 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, went 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 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 July 2021, the WVPSC issued an order approving the investment tracker mechanism with an initial annual revenue requirement of $44 million ($35 million related to APCo) effective September 2021 based on a 9.25% ROE. Under the conditions of the order, APCo and WPCo would not be permitted to file a base rate case before June 30, 2024. The order also allows APCo and WPCo to request future year investment tracker increases for assets placed in service during the most recent 12-month period ending September 30th, subject to an annual three percent rider increase cap on base year total retail revenues. APCo and WPCo filed a petition for reconsideration with the WVPSC to reconsider and modify certain parts of the order, including the condition that APCo and WPCo will not file a base rate case before June 30, 2024. The companies request certain exceptions to be recognized that allow for base rate case filings in certain circumstances.

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

In July 2021, the FERC issued an order denying Dayton Power and Light’s request for a 50 basis point RTO incentive on the basis that its RTO participation was not voluntary, but rather is required by Ohio law. This precedent could have an impact on AEP’s transmission owning subsidiaries whose RTO membership is not voluntary, including OPCo and AEP Ohio Transmission Company.
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If the FERC modifies its RTO Incentive policy, it would be applied, as applicable, to AEP’s PJM, SPP and MISO transmission owning subsidiaries on a prospective basis, and could affect future net income and cash flows and impact financial condition. Based on management’s preliminary estimates, if a final rule is adopted consistent with the April 2021 supplemental NOPR, it could reduce AEP’s pretax income by approximately $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 2020114.0 10.35%9.1%-9.8%(d)
PSOOklahomaApril 2021172.4 10%(e)
I&MIndianaJuly 2021104.0 (f)10%(g)

(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 intervenors recommended base rate increases ranged from $20 million to $70 million.
(d)Staff recommended a base rate increase of $6 million.
(e)Intervenor testimony is expected in the third quarter of 2021.
(f)Proposed to be phased-in with a $73 million annual increase effective May 2022 and the remaining $31 million annual increase effective January 2023.
(g)Intervenor testimony is expected in the fourth quarter of 2021.
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Renewable Generation Portfolio


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.  contracts with creditworthy counterparties.

As of March 31, 2018,June 30, 2021, subsidiaries within AEP’s Generation & Marketing segment havehad approximately 4001,633 MWs of contracted renewable generation projects in operation.in-service.  In addition, as of March 31, 2018,June 30, 2021, these subsidiaries havehad approximately 10155 MWs of new renewable generation projects under construction with total estimated capital costs of $26$221 million related to these projects.


In January 2018, AEP admitted a nonaffiliate as a member of Desert Sky Wind Farm LLC and Trent Wind Farm LLC (collectively the “LLCs”) to own and repower Desert Sky and Trent, which is expected to be completed in 2018.  The nonaffiliated member contributed full turbine sets to each project in exchange for a 20.1% interest in the LLCs. AEP’s 79.9% share of the LLCs, or 248 MWs, represents $232 million of additional estimated capital, of which $131 million has been incurred and recorded in CWIP as of March 31, 2018. AEP is subject to a put and a call option after certain conditions are met, either of which would liquidate the nonaffiliated member’s interest. See Note 13 - Variable Interest Entities for additional information.

Regulated Renewable Generation Facilities


In July 2017, APCo submitted filings with2020, PSO received approval from the Virginia SCCOCC and SWEPCo received approval from the WVPSC requesting regulatory approval to acquire two wind generation facilities totaling approximately 225 MWs of wind generation. The wind generating facilities are located in West VirginiaAPSC and Ohio and, if approved, are anticipated to be in-service in the second half of 2019. APCo will assume ownership of the facilities at or near the anticipated in-service date. APCo currently plans to sell the Renewable Energy Certificates associated with the generation from these facilities. In December 2017, the WVPSC staff and an industrial intervenor filed testimony in West Virginia and the Virginia SCC staff filed testimony in Virginia arguing that APCo’s forecast of natural gas and energy prices was too high and, with the exception of the WVPSC staff’s recommended approval of the facility located in West Virginia, did not support approval of APCo’s acquisition of the facilities. In January 2018, APCo filed supplemental testimony with the WVPSC to address changes in the economics of the wind projects as a result of Tax Reform. A hearing at the WVPSC was held in March 2018 and briefs were filed in April 2018. The WVPSC staff, the industrial intervenor and the Consumer Advocate Division of the Public Service Commission all recommended that the WVPSC deny APCO’s request for approval of the wind farms. Also in April 2018, the Virginia SCC denied APCo’s applicationLPSC to acquire the twoNorth Central Wind Energy Facilities, comprised of three Oklahoma wind generation facilities. APCo filedfacilities totaling 1,485 MWs, on a petition for reconsideration withfixed cost turn-key basis at completion. Both the Virginia SCC,APSC and LPSC approved the flex-up option, agreeing to acquire the Texas portion, which wasthe PUCT denied. PSO will own 45.5% and SWEPCo will own 54.5% of the project, which will cost approximately $2 billion.


In July 2017,June 2021, the IRS issued a notice extending the “Continuity Safe Harbor” deadlines for qualifying renewable energy projects. Under the June 2021 IRS notice, the Continuity Safe Harbor for qualifying renewable energy projects that began construction in calendar years 2016 through 2019 is extended to six years. Additionally, the Continuity Safe Harbor is extended to five years for qualifying projects that began construction in calendar year 2020. Provided that each facility does satisfy the Continuity Safe Harbor, under the current IRS guidance, the Sundance wind facility will qualify for 100% of the federal PTC, and the Maverick and Traverse wind facilities will qualify for 80% of the federal PTC.

In April 2021, PSO and SWEPCo submitted filings withacquired respective undivided ownership interests in the OCC, LPSC, APSCentity that owned Sundance during its development and PUCT requesting various regulatory approvals neededconstruction for $270 million, the companies to proceed withfirst of the Wind Catcher Project. The Wind Catcher Project includesthree NCWF acquisitions. Immediately following the acquisition, of a wind generation facility, totaling approximately 2,000 MWs of wind generation,PSO and SWEPCo liquidated the construction of a generation interconnection tie-line totaling approximately 380 miles. Totalentity and simultaneously distributed the Sundance assets in proportion to their undivided ownership interests. Sundance was placed in-service in April 2021. The total investment for the projectin Sundance is estimated to be $4.5$291 million inclusive of previously capitalized pre-construction costs. The Maverick wind facility is targeted to be acquired and placed in-service in December 2021 and the Traverse wind facility is targeted to be acquired and placed in-service between December 2021 and April 2022. See Note 6 - Acquisitions for additional information.

In June 2021, SWEPCo issued requests for proposals to acquire up to 3,000 MWs of wind and 300 MWs of solar generation resources. The wind and solar generation projects would be subject to regulatory approval.

Strategic Evaluation of KPCo and AEP Kentucky Transmission Company, Inc. (KTCo)

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 and KTCo, an AEPTCo wholly-owned regulated transmission only utility. Potential alternatives may include continued ownership or a sale of KPCo and KTCo. Management is currently evaluating the potential alternatives and expects a decision will be made during 2021. As of June 30, 2021, KPCo has total assets of approximately $2.8 billion and will serve both retailtotal equity of approximately $847 million and KTCo has total assets of approximately $157 million and total equity of approximately $73 million.
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Racine

In February 2021, AEP signed an agreement to sell Racine to a nonaffiliated party. As of June 30, 2021, the net book value of Racine was $45 million. The sale of Racine requires approval from the FERC wholesale load. PSO and the U.S. Army Corps of Engineers. The sale is expected to close in the third 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

DHLC provides 100% of the fuel supply to Dolet Hills Power Station. During the second quarter of 2019, the Dolet Hills Power Station initiated a seasonal operating schedule. In 2020, management of SWEPCo will haveand 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. In addition, 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 April 2020, SWEPCo and CLECO jointly filed a 30% and 70% ownership share, respectively, in these assets. The wind generating facility is located in Oklahoma and, if approved by all state commissions, is anticipatednotification letter to be in-service by the end of 2020. In July 2017, the LPSC approved SWEPCo’s request for an exemption to the Market Based Mechanism. In August 2017 and December 2017, the OCC denied the Oklahoma Attorney General’s respective August and December 2017 motions to dismiss. Also in December 2017, the companies filed a request at the FERC to transfer the wind generation facility to PSO and SWEPCo upon its construction by a third party, which was approved in April 2018. The transfer remains subject to the approvalproviding notice of the project at the respective state commissions. Parties’ testimony filed in the Oklahoma, Texas and Louisiana dockets generally opposes the companies’ request. In February 2018, the ALJ in Oklahoma recommended that PSO’s request for preapprovalcessation of future recovery of Wind Catcher Projectlignite mining.

The Dolet Hills Power Station non-fuel costs be denied. In March 2018, oral arguments were held before three Oklahoma Commissioners regarding the ALJ report and parties agreed to waive the 240 day statutory deadline for an order to continue the discussions. A non-unanimous settlement agreement was filed in Arkansas in


February 2018, a unanimous settlement was filed in April 2018 in Louisiana and a non-unanimous settlement was filed in April 2018 in Oklahoma, with further settlement discussion continuing. The settlement agreements and the companies’ rebuttal testimony filed in Oklahoma, Texas, Arkansas and Louisiana, generally contain certain commitments of PSO andare recoverable by SWEPCo including a most favored nation clause, a cap on the cost of the investment, guarantees of qualification for production tax credits, minimum annual production from the project and a net benefits guarantee for ten years. In addition, PSO and SWEPCo committed in each jurisdiction to the timely filing of a base rate case to shorten the duration of cost recovery through a temporary mechanism.

Hurricane Harvey

In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. As rebuilding efforts continue, AEP Texas’ total costs related to this storm are not yet final. AEP Texas’ current estimated cost is approximately $325 million to $375 million, including capital expenditures. AEP Texas has a PUCT approved catastrophe reserve which allows for the deferral of incremental storm expenses as a regulatory asset, and currently recovers approximately $1 million annually through base rates. AsSWEPCo’s share of March 31, 2018, the total balancenet investment in the Dolet Hills Power Station is $147 million, including CWIP and materials and supplies, before cost of AEP Texas’ catastrophe reserve deferral is $129removal.

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 $119 million inclusiveas of approximately $105 million of net incremental storm expenses related to Hurricane Harvey. As of March 31, 2018, AEP Texas has recorded approximately $186 million of capital expenditures related to Hurricane Harvey.June 30, 2021. Also, as of March 31, 2018, AEP Texas has received $10June 30, 2021, SWEPCo had a net over-recovered fuel balance of $17 million, excluding impacts of the February 2021 severe winter weather event, which includes fuel consumed at the Dolet Hills Power Station. Additional operational, reclamation and other land-related costs incurred by DHLC and Oxbow will be billed to SWEPCo and included in insurance proceeds, which were applied to the regulatory asset and property, plant and equipment. Management, in conjunctionfuture fuel clauses.

In June 2020, SWEPCo filed a fuel reconciliation with the insurance adjusters, is reviewing all damages to determine the extent of coveragePUCT for additional insurance reimbursement. Any future insurance recoveries received will also be applied to, and will offset, the regulatory asset and property, plant and equipment, as applicable. Management believes the amount recorded as a regulatory asset is probable of recovery and AEPits retail operations in Texas, is currently evaluating recovery optionsincluding Dolet Hills, for the regulatory asset, including securitization. The standard process for storm cost recovery in Texas requires two filings with the PUCT. Management expects the first filing by the endreconciliation period of third quarter of 2018. If the ultimate costs of the incident are not recovered by insurance or through the regulatory process, it would have an adverse effect on future net income, cash flows and financial condition.

June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024

In March 2016, a contested stipulation agreement related1, 2017 to the PPA rider application was modified and approved by the PUCO. The approved PPA rider is subject to audit and review by the PUCO. Consistent with the terms of the modified and approved stipulation agreement, and based upon a September 2016 PUCO order, in November 2016, OPCo refiled its amended ESP extension application and supporting testimony. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Renewable Resource Rider.

In August 2017, OPCo and various intervenors filed a stipulation agreement with the PUCO. The stipulation extends the term of the ESP through May 2024 and includes: (a) an extension of the OVEC PPA rider, (b) a proposed 10% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) rate caps related to OPCo’s DIR ranging from $215 million to $290 million for the periods 2018 through 2021, (e) the addition of various new riders, including a Smart City Rider and a Renewable Generation Rider, (f) a decrease in annual depreciation rates based on a depreciation study using data through December 2015 and (g) amortization of approximately $24 million annually beginning January 2018 of OPCo’s excess distribution accumulated depreciation reserve, which was $239 million as of December 31, 2015. Upon PUCO approval of the stipulation, OPCo will cease recording $39 million in annual amortization previously approved to end in December 2018 in accordance with PUCO’s December 2011 OPCo distribution base rate case order. In the stipulation, OPCo and intervenors agree that OPCo can request in future proceedings a change in meter depreciation rates due to retired meters pursuant to the smart grid Phase 2 project. DIR rate caps will be reset in OPCo’s next distribution base rate case which must be filed by June 2020.



In October 2017, intervenor testimony opposing the stipulation agreement was filed recommending: (a) a return on common equity to not exceed 9.3% for riders earning a return on capital investments, (b) that OPCo should file a base distribution case concurrent with the conclusion of the current ESP in May 2018 and (c) denial of certain new riders proposed in OPCo’s ESP extension. The stipulation was reviewed by the PUCO at a hearing in November 2017.

In April 2018, the PUCO issued an order approving the stipulation agreement, with no significant changes.

2016 SEET Filing

In December 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings.

In May 2017, OPCo submitted its 2016 SEET filing with the PUCO in which management indicated that OPCo did not have significantly excessive earnings in 2016 based upon actual earnings data for the comparable utilities risk group.

In January 2018, the PUCO staff filed testimony that OPCo did not have significantly excessive earnings. Also in January 2018, an intervenor filed testimony recommending a $53 million refund to customers. In February 2018, OPCo and PUCO staff filed a stipulation agreement in which both parties agreed that OPCo did not have significantly excessive earnings in 2016.

A 2016 SEET hearing was held in April 2018 and management expects to receive an order in the second half of 2018. While management believes that OPCo’s adjusted 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s proposed SEET adjustments, including treatment of the Global Settlement issues described above, adjust the comparable risk group or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could negatively affect future SEET filings, reduce future net income and cash flows and impact financial condition.2019. See “2016 SEET Filing”“2020 Texas Fuel Reconciliation” section of Note 4 for additional information.


Rockport Plant, Unit 2 SCRIn 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 October 2016, I&M filed an application withMarch 2021, the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NOx from Rockport Plant, Unit 2 in order for I&M to continue to operateAPSC approved fuel rates that unit under current environmental requirements. The estimated costprovide recovery of the SCR project is $274 million, excluding AFUDC, to be shared equally between I&M and AEGCo.  As of March 31, 2018, total costs incurred related to this project, including AFUDC, were approximately $28 million.  The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. The AEGCo ownershipArkansas share of the proposed SCR project will be billable under2021 Dolet Hills Power Station fuel costs over five years through the Rockport UPA to I&M and KPCo and will be subject to future regulatory approval for recovery.existing fuel clause.


In March 2018, the IURC issued an order approving: (a) the CPCN, (b) the $274 million estimated cost of the SCR, excluding AFUDC, (c) deferral accounting for the Indiana jurisdictional ownership share of costs, including investment carrying costs, (d) depreciation of the SCR asset over 10 years and (e) recovery of these costs using I&M’s existing Indiana Clean Coal Technology Rider.

In April 2018, a group of intervenors filed a Petition for Reconsideration and Rehearing of the March 2018 IURC order.  The intervenors requested that the IURC reopen the proceeding primarily to address whether allowing I&M any cost recovery for the SCR would constitute a cross-subsidization issue and to reverse its finding approving cost recovery for the Rockport Plant, Unit 2 SCR project.  Also in April 2018, I&M filed a response to the intervenors’ petition.


2017 Indiana Base Rate Case

In July 2017, I&M filed a request with the IURC for a $263 million annual increase in Indiana rates based upon a proposed 10.6% return on common equity with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increase would be subject to a temporary offsetting $23 million annual reduction to customer bills through December 2018 for a credit adjustment rider related to the timing of estimated in-service dates of certain capital expenditures.  The proposed annual increase includes $78 million related to increased annual depreciation rates and an $11 million increase related to the amortization of certain Cook Plant and Rockport Plant regulatory assets. The increase in depreciation rates includes a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant, including the Cook Plant Life Cycle Management Project.

In November 2017, various intervenors filed testimony that included annual revenue increase recommendations ranging from $125 million to $152 million. The recommended returns on common equity ranged from 8.65% to 9.1%. In addition, certain parties recommended longer recovery periods than I&M proposed for recovery of regulatory assets and depreciation expenses related to Rockport Plant, Units 1 and 2. In January 2018, in response to a January 2018 IURC request related to the impact of Tax Reform on I&M’s pending base rate case, I&M filed updated schedules supporting a $191 million annual increase in Indiana base rates if the effect of Tax Reform was included in the cost of service.

In February 2018, I&M and all parties to the case, except one industrial customer, filed a Stipulation and Settlement Agreement for a $97 million annual increase in Indiana rates effective July 1, 2018 subject to a temporary offsetting reduction to customer bills through December 2018 for a credit rider related to the timing of estimated in-service dates of certain capital expenditures.  The one industrial customer agreed to not oppose the Stipulation and Settlement Agreement. The difference between I&M’s requested $263 million annual increase and the $97 million annual increase in the Stipulation and Settlement Agreement is primarily a result of: (a) the reduction in the federal income tax rate due to Tax Reform, (b) the feedback of credits for excess deferred income taxes, (c) a 9.95% return on equity, (d) longer recovery periods of regulatory assets, (e) lower depreciation expense primarily for meters and (f) an increase in the sharing of off-system sales margins with customers from 50% to 95%.  If the Stipulation and Settlement is approved, I&M will also refund $4 million from July through December 2018 for the impact of Tax Reform for the period January through June 2018.  A hearing at the IURC was held in March 2018 and an IURC order is expected in the second quarter of 2018. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
2017 Michigan Base Rate Case


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Pirkey Power Plant and Related Fuel Operations

In May 2017, I&M filed a request with2020, management announced plans to retire the MPSC for a $52 million annual increasePirkey Power Plant in Michigan2023. The Pirkey Power Plant non-fuel costs are recoverable by SWEPCo through base rates based upon a proposed 10.6% return on common equity with the increase to be implemented no later than April 2018. The proposed annual increase includes $23 million related to increased annual depreciation rates and a $4 million increase related to the amortization of certain Cook Plant regulatory assets. The increase in depreciation rates is primarily due to the proposed change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant related to the Life Cycle Management Project.

In February 2018, an MPSC ALJ issued a Proposal for Decision and recommended an annual revenue increase of $49 million, including an intervenors’ proposed capacity rate based on PJM’s net cost of new entry value of $289/MW-day and MPSC staff’s recommended calculation of depreciation expense for both units of Rockport Plantfuel costs are recovered through 2028 and a return on common equity of 9.8%.  If the maximum 10% of customers choose an alternate supplier starting in February 2019, the estimated annual pretax loss due to the reduced capacity rate would be approximately $9 million until adjusted in the next base rate case. 

In April 2018, the MPSC issued an order that generally approved the ALJ proposal resulting in an annual revenue increase of $49 million, effective April 2018 based on a 9.9% return on common equity.  The MPSC also approved the ALJ’s recommendation related to the capacity rate.



Merchant Portion of Turk Plant

SWEPCo constructed the Turk Plant, a base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012 and is included in the Vertically Integrated Utilities segment. SWEPCo owns 73% (440 MWs) of the Turk Plant and operates the facility.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictionalactive fuel clauses. SWEPCo’s share of the Turknet investment in the Pirkey Power Plant (approximately 20%). Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN. In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN. This share of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the wholesale market. Approximately 80% of the Turk Plant investment is recovered under cost-based rate recovery in Texas, Louisiana and through SWEPCo’s wholesale customers under FERC-based rates. As of March 31, 2018, the net book value of Turk Plant was $1.5 billion,$206 million, including CWIP, before cost of removal,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 materialsbillings of all fixed and suppliesoperating costs, from Sabine to cease during the first quarter of 2023. Under the fuel agreements, SWEPCo’s fuel inventory and CWIP. Ifunbilled fuel costs from mining related activities were $148 million as of June 30, 2021. Also, as of June 30, 2021, SWEPCo cannot ultimately recover its investment and expenses related to the Turk Plant, it could reduce future net income and cash flows and impact financial condition.

2017 Louisiana Formula Rate Filing

In April 2017, the LPSC approved an uncontested stipulation agreement that SWEPCo filed for its formula rate plan for test year 2015.  The filing includedhad a net annual increase not to exceed $31over-recovered fuel balance of $17 million, excluding impacts of the February 2021 severe winter weather event, which was effective May 2017 and includes SWEPCo’s Louisiana jurisdictional share of Welsh Plant and Flint Creek Plant environmental controls which were placed in service in 2016. The net annual increase is subject to refund. In October 2017, SWEPCo filed testimony in Louisiana supporting the prudence of its environmental control investment for Welsh Plant, Units 1 and 3 and Flint Creek power plants. These environmental costs are subject to prudence review. A hearingfuel consumed at the LPSC is scheduled for May 2018.Pirkey Power Plant. Additional operational, reclamation and other land-related costs incurred by Sabine will be billed to SWEPCo and included in future fuel clauses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.


2018 Louisiana Formula Rate Filing

In April 2018, SWEPCo filed its formula rate plan for test year 2017 with the LPSC.  The filing included a net $28 million annual increase, which will be effective August 2018.  The filing included a reduction in the federal income tax rate due to Tax Reform. The return of excess deferred income tax benefits to customers will be addressed in a supplemental filing and will reduce the $28 million annual increase. The increase includes SWEPCo’s jurisdictional share of Welsh Plant and Flint Creek Plant environmental controls, whose prudence review hearing is scheduled for May 2018. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2017 Kentucky Base Rate Case

In January 2018, the KPSC issued an order approving a non-unanimous settlement agreement with certain modifications resulting in an annual revenue increase of $12 million, effective January 2018, based on a 9.7% return on equity. The KPSC’s primary revenue requirement modification to the settlement agreement was a $14 million annual revenue reduction for the decrease in the corporate federal income tax rate due to Tax Reform. The KPSC approved: (a) the deferral of a total of $50 million of Rockport Plant UPA expenses for the years 2018 through 2022, with the manner and timing of recovery of the deferral to be addressed in KPCo’s next base rate case, (b) the recovery/return of 80% of certain annual PJM OATT expenses above/below the corresponding level recovered in base rates, (c) KPCo’s commitment to not file a base rate case for three years with rates effective no earlier than 2021 and (d) increased depreciation expense based upon updated Big Sandy Plant, Unit 1 depreciation rates using a 20-year depreciable life.

In February 2018, KPCo filed with the KPSC for rehearing of the January 2018 base case order and requested an additional $2.3 million of annual revenue increases related to: (a) the calculation of federal income tax expense, (b) recovery of purchased power costs associated with forced outages and (c) capital structure adjustments.  Also in


February 2018, an intervenor filed for rehearing recommending that the reduced corporate federal income tax rate be reflected in lower purchased power expense related to the Rockport UPA. In February 2018, the KPSC issued an order granting rehearing of these items, with an exception for the capital structure adjustments, which was denied by the KPSC.

2016 Texas Base Rate Case

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

As a result of the final order, in 2017 SWEPCo (a) recorded an impairment charge of $19 million, which includes $7 million associated with the lack of return on Welsh Plant, Unit 2 and $12 million related to other disallowed plant investments, (b) recognized $32 million of additional revenues, for the period of May 2017 through December 2017, that will be surcharged to customersand (c) recognized an additional $7 million of expenses consisting primarily of depreciation expense and vegetation management expense, offset by the deferral of rate case expenses. SWEPCo implemented new rates in February 2018 billings. The $32 million of additional 2017 revenues will be collected by the end of 2018. In March 2018, the PUCT clarified and corrected portions of the final order, without changing the overall decision or amounts of the rate change. This order is subject to appeal as early as the second quarter of 2018. In April 2018, SWEPCo made an income tax rate refund tariff filing which includes an annual revenue reduction of approximately $18 million to reflect the difference between rates collected under the final order and the rates that would be collected under Tax Reform. The filing did not address the return of excess deferred income tax benefits to customers.

Virginia Legislation Affecting Earnings Reviews

In 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates were frozen until after the Virginia SCC ruled on APCo’s next biennial review. These amendments also precluded the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017.

In March 2018, new Virginia legislation impacting investor-owned utilities was enacted, effective July 1, 2018, that will: (a) on a one-time basis, require APCo to exclude $10 million of fuel expenses from the July 2018 over/under calculation, (b) reduce APCo’s base rates by $50 million annually no later than July 30, 2018, on an interim basis and subject to true-up, to reflect the lower federal income tax rate due to Tax Reform, (c) require APCo to file its next generation and distribution base rate case by March 31, 2020 using 2017, 2018 and 2019 test years (“triennial review”), (d) require an adjustment in APCo’s base rates on April 1, 2019 to reflect actual annual reductions in corporate income taxes due to Tax Reform, (e) require APCo to obtain approval from the Virginia SCC for energy efficiency programs with projected costs in the aggregate of at least $140 million over the 10-year period from July 1, 2018 through July 1, 2028 and (f) require APCo to construct and/or acquire solar generation facilities in Virginia of at least 200 MW of aggregate capacity. Triennial reviews are subject to an earnings test which provides that any over earnings may be reinvested in approved energy distribution grid transformation projects. The Virginia SCC’s triennial review of 2017-2019 APCo earnings could reduce future net income and cash flows and impact financial condition.

FERC Transmission Complaint - AEP’s PJM Participants

In October 2016, seven parties filed a complaint at the FERC that alleged the base return on common equity used by AEP’s transmission owning subsidiaries within PJM in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint.  In November 2017, a FERC order set the matter for hearing and settlement procedures.  In March 2018, AEP’s transmission owning


subsidiaries within PJM and six of the complainants filed a settlement agreement with the FERC (the seventh complainant abstained).  If approved by the FERC the settlement agreement (a) establishes a base ROE for AEP’s transmission owning subsidiaries within PJM of 9.85% (10.35% inclusive of the RTO incentive adder of 0.5%), effective January 1, 2018, (b) requires AEP’s transmission owning subsidiaries within PJM to provide a one-time refund of $50 million, attributable from the date of the complaint through December 31, 2017, to be credited to customer bills in the second quarter of 2018 and (c) increases the cap on the equity portion of the capital structure to 55% from 50%.  As part of the settlement agreement, AEP’s transmission owning subsidiaries within PJM also filed updated transmission formula rates incorporating the reduction in the corporate federal income tax rate due to Tax Reform, effective January 1, 2018 and providing for the amortization of the portion of the excess accumulated deferred income taxes that are not subject to the normalization method of accounting, ratably over a ten year period through credits to the federal income tax expense component of the revenue requirement. In April 2018, an ALJ accepted the interim settlement rates, pending the FERC’s consideration of the settlement, and the rates are subject to refund or surcharge, with interest.

In April 2018, certain intervenors filed comments at the FERC recommending a base ROE of 8.48% and a one-time refund of $184 million. In addition, the FERC trial staff filed comments recommending a base ROE of 8.41% and one-time refund of $175 million. Also in April 2018, another intervenor recommended the refund be calculated in accordance with the base ROE that will ultimately be approved by the FERC. Management intends to file reply comments providing further support for the 9.85% base ROE agreed to in the settlement agreement.

Management believes the $50 million refund in the settlement agreement is the best estimate of the probable liability.  If the FERC orders revenue reductions in excess of the terms of the settlement agreement, it could reduce future net income and cash flows and impact financial condition.  A decision from the FERC is pending.

Modifications to AEP’s PJM Transmission Rates

In November 2016, AEP’s transmission owning subsidiaries within PJM filed an application at the FERC to modify the PJM OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to projected expenses. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. The modified PJM OATT formula rates are based on projected calendar year financial activity and projected plant balances. In December 2017, AEP’s transmission owning subsidiaries within PJM filed an uncontested settlement agreement with the FERC resolving all outstanding issues. In April 2018, the FERC approved the uncontested settlement agreement and rates were implemented effective January 1, 2018.

FERC Transmission Complaint - AEP’s SPP Participants

In June 2017, several parties filed a complaint at the FERC that states the base return on common equity used by AEP’s transmission owning subsidiaries within SPP in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36%, effective upon the date of the complaint. In November 2017, a FERC order set the matter for hearing and settlement procedures. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.

Modifications to AEP’s SPP Transmission Rates

In October 2017, AEP’s transmission owning subsidiaries within SPP filed an application at the FERC to modify the SPP OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to projected expenses.  The modified SPP OATT formula rates are based on projected 2018 calendar year financial activity and projected plant balances. In December 2017, the FERC accepted the proposed modifications effective January 1, 2018, subject to refund, and set this matter for hearing and settlement procedures. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.



FERC SWEPCo Power Supply Agreements Complaint - East Texas Electric Cooperative, Inc. (ETEC) and Northeast Texas Electric Cooperative, Inc. (NTEC)

In September 2017, ETEC and NTEC filed a complaint at the FERC that states the base return on common equity used by SWEPCo in calculating their power supply formula rates is excessive and should be reduced from 11.1% to 8.41%, effective upon the date of the complaint. In November 2017, a FERC order set the matter for hearing and settlement procedures. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.

Welsh Plant - Environmental Impact

Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could total approximately $850 million, excluding AFUDC. As of March 31, 2018, SWEPCo had incurred costs of $399 million, including AFUDC, related to these projects.  Management continues to evaluate the impact of environmental rules and related project cost estimates. As of March 31, 2018, the total net book value of Welsh Plant, Units 1 and 3 was $625 million, before cost of removal, including materials and supplies inventory and CWIP. 

In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas filed base rate proceeding. In April 2017, the LPSC approved recovery of $131 million in investments related to its Louisiana jurisdictional share of environmental controls installed at Welsh Plant, effective May 2017. SWEPCo’s approved Louisiana jurisdictional share of Welsh Plant deferrals: (a) are $11 million, excluding $6 million of unrecognized equity as of March 31, 2018, (b) is subject to review by the LPSC, and (c) includes a WACC return on environmental investments and the related depreciation expense and taxes. In January 2018, SWEPCo received written approval from the PUCT to recover its project costs from retail customers in its 2016 Texas base rate case and is recovering these costs from wholesale customers through SWEPCo’s FERC-approved agreements. See “2016 Texas Base Rate Case” and “2017 Louisiana Formula Rate Filing” disclosures above.

If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See “Welsh Plant - Environmental Impact” section of Note 4 for additional information.

Westinghouse Electric Company Bankruptcy Filing

In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the U.S. Bankruptcy Code. Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuel fabrication and ongoing engineering projects.  The most significant of these relate to Cook Plant fuel fabrication.  As part of the reorganization, the bankruptcy court approved Westinghouse’s sale of its nuclear business to Brookfield WEC Holdings, a nonaffiliated third party. Pursuant to the sale, Brookfield will assume all of I&M’s contracts with Westinghouse. The sale is subject to regulatory approvals and is expected to close in the third quarter of 2018.

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.  For details on the regulatory proceedings and pending litigation see Note 4 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies. 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 July 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 willwould 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 further allege that the defendants’ actions constitute breach of the lease and participation agreement.  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. In October 2013, a motion to dismiss the case was filed on behalf of

AEGCo and I&M.

In January 2015,&M sought and were granted dismissal by the court issued an opinion and order grantingU.S. District Court for the motion in part and denying the motion in part. The court dismissedSouthern District of Ohio of certain of the plaintiffs’ claims, including the dismissal without prejudice of plaintiffs’ claims seeking compensatory damages. Several claims remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. In November 2015, AEGCo and I&M filed a motion to strike the plaintiffs’ motion for partial judgment and filed a motion to dismiss the case for failure to state a claim.

In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for compensatory damages, breach of contract, and dismissing claims for breach of the implied covenant of good faith and fair dealing and further dismissing plaintiffs’ claim for indemnification of costs. ByPlaintiffs voluntarily dismissed the same order, the court permitted plaintiffs to move forward with their claimsurviving claims that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice, and the court subsequently enteredissued a final judgment. In May 2016,The plaintiffs subsequently filed an appeal in the U.S. Court of Appeals for the Sixth Circuit on whether AEGCo and I&M are in breach of certain contract provisions that plaintiffs allege operate to protect the plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing.Circuit.


In April 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion reversing the district court’s decisions which had dismissed certain of plaintiffs’ claims for breach of contract and remanding the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. In April 2017, AEGCo and I&M filed a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit, which was granted. In June 2017, the U.S. Court of Appeals for the Sixth Circuit issued an amended opinion and judgment which reverses the district court’s dismissal of certain of the owners’ claims under the lease agreements, vacates the denial of the owners’ motion for partial summary judgment and remands the case to the district court for further proceedings.  The amended opinion and judgment also affirmsaffirming the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims, and removes the instruction toreversing the district court in the original opinion to enter summary judgment in favorcourt’s dismissal of the owners.breach of contract claims and remanding the case for further proceedings.


In July 2017,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 to eliminate the obligation to install certain future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that Unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. In November 2017, theThe 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. See “Proposed ModificationThe consent decree was modified based on an agreement among the parties in July 2019. The district court’s stay of the NSRlease litigation expired in August 2020. Upon expiration of the stay, plaintiffs filed a motion for partial summary judgment, 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
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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, in May 2021, at the parties request, the district court entered a stipulation and order dismissing the case without prejudice to plaintiffs asserting their claims in a re-filed action or a new action. The 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.  Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, managementManagement is unable to determine a range of potential losses that areis reasonably possible of occurring.


Litigation Related to Ohio House Bill 6 (HB 6)

In 2019, Ohio adopted and implemented HB 6 which benefits OPCo by authorizing rate recovery for certain costs including renewable energy contracts and OVEC’s coal-fired generating units. OPCo engaged in lobbying efforts and provided testimony during the legislative process in connection with HB 6. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of an Ohio legislator and associates in connection with an alleged racketeering conspiracy involving the adoption of HB 6. After AEP learned of the criminal allegations against the Ohio legislator and others relating to HB 6, the Company, with assistance from outside advisors, conducted a review of the circumstances surrounding the passage of the bill. We do not believe that AEP was involved in any wrongful conduct in connection with the passage of HB 6.

In August 2020, an AEP shareholder filed a putative class action lawsuit in the United States District Court for the Southern District of Ohio against AEP and certain of its officers for alleged violations of securities laws. The amended complaint 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. On May 10, 2021, the defendants filed a motion to dismiss the securities litigation for failure to state a claim, and under the Court’s briefing schedule the motion will be fully briefed by July 26, 2021. 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 and a fourth AEP shareholder filed a similar derivative action in the
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Supreme Court for the State of New York, Nassau County. These derivative complaints allege the officers and directors made misrepresentations and omissions similar to those alleged in the putative securities class action lawsuit filed against AEP. The derivative complaints together assert claims for: (a) breach of fiduciary duty, (b) waste of corporate assets, (c) unjust enrichment, (d) breach of duty for insider trading and (e) contribution for violations of sections 10(b) and 21D of the Securities Exchange Act of 1934; and seek monetary damages and changes to AEP’s corporate governance and internal policies among other forms of relief. The first three derivative actions have been stayed pending the resolution of the motion to dismiss the securities litigation. The fourth has been stayed until such time as the court determines to lift the stay. 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.

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 shareholder that sent the letter has agreed that AEP and the AEP Board may defer consideration of the litigation demand until the resolution of the motion to dismiss the securities litigation. The AEP Board will act in response to the letter as appropriate. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

In May 2021, AEP received a subpoena from the SEC’s Division of Enforcement seeking various documents, including documents relating to the benefits to AEP from the passage of HB 6 and documents relating to AEP’s financial processes and controls. AEP is cooperating fully with the SEC’s subpoena. Although we cannot predict the outcome of the SEC’s investigation, we do not believe the results of this inquiry will have a material impact on our financial condition, results of operations, or cash flows.

ENVIRONMENTAL ISSUES


AEP has a substantial capital investment program and is incurringincurs additional operational costs to comply with environmental control requirements.  Additional investments and operational changes will need to be made in response to existing and anticipated requirements such as new CAA requirements to reduce emissions from fossil fuel-fired power plants,generation and in response to rules governing the beneficial use and disposal of coal combustion by-products, clean water rules 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 various industry groups, affected states and other parties challenged some of the Federal EPA requirements in court.  Management is also 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 is unable tocannot 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 theAEP System generating units in the AEP System.units.  Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of March 31, 2018,June 30, 2021, the AEP System had a totalowned generating capacity of approximately 25,60024,700 MWs, of which approximately 13,50012,100 MWs arewere coal-fired.  Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on the fossil generating facilities.generation. Based upon management estimates, AEP’s future investment to meet these existing and proposed requirements ranges from approximately $2.1 billion$350 million to $2.7 billion$700 million through 2025.2027.


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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) the states’ implementation of these regulatory programs, including the potential for state implementation plans (SIPs) or federal implementation plans (FIPs)rules that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed, on the units, (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 is continuingcontinues to evaluate the economic feasibility of environmental investments on both regulated and competitive plants.




The table below representsObligations under the plants or units of plants retired in 2016 and 2015 with a remaining net book value. As of March 31, 2018, the net book value before cost of removal, including related materials and supplies inventory and CWIP balances, of the units listed below was approved for recovery, except for $218 million. Management is seeking or will seek recovery of the remaining net book value of $218 million in future rate proceedings.
    Generating Amounts Pending
Company Plant Name and Unit Capacity Regulatory Approval
    (in MWs)  (in millions)
APCo Kanawha River Plant 400
 $44.8
APCo Clinch River Plant, Unit 3 235
 32.6
APCo (a) Clinch River Plant, Units 1 and 2 470
 31.8
APCo Sporn Plant, Units 1 and 3 300
 17.2
APCo Glen Lyn Plant 335
 13.4
I&M (b) Tanners Creek Plant 995
 27.7
SWEPCo Welsh Plant, Unit 2 528
 50.6
Total   3,263
 $218.1

(a)APCo obtained permits following the Virginia SCC’s and WVPSC’s approval to convert its 470 MW Clinch River Plant, Units 1 and 2 to natural gas. In 2015, APCo retired the coal-related assets of Clinch River Plant, Units 1 and 2. Clinch River Plant, Unit 1 and Unit 2 began operations as natural gas units in February 2016 and April 2016, respectively.
(b)I&M requested recovery of the Indiana (approximately 65%) and Michigan (approximately 14%) jurisdictional shares of the remaining retirement costs of Tanners Creek Plant in the 2017 Indiana and Michigan base rate cases. In April 2018, a final order was received in Michigan which approved I&M’s request for a return of and on its jurisdictional share of the remaining retirement costs of Tanners Creek Plant. See “2017 Indiana Base Rate Case” and “2017 Michigan Base Rate Case” sections of Note 4 for additional information.

In January 2017, Dayton Power and Light Company announced the future retirement of the 2,308 MW Stuart Plant, Units 1-4. The retirement is scheduled for June 2018. Stuart Plant, Units 1-4 are operated by Dayton Power and Light Company and are jointly owned by AGR and nonaffiliated entities. AGR owns 600 MWs of the Stuart Plant, Units 1-4. As of March 31, 2018, AGR’s net book value of the Stuart Plant, Units 1-4 was zero.

To the extent existing generation assets are not recoverable, it could materially reduce future net income and cash flows and impact financial condition.

Proposed Modification of the NSRNew Source Review Litigation Consent Decree


In 2007, the U.S. District Court for the Southern District of Ohio approved a consent decree between the 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 NOxX emissions from the AEP System and various mitigation projects.

In July 2017, AEP filed a motion with The consent decree has been modified six times, for various reasons, most recently in 2020. All of the U.S. District Court for the Southern District of Ohio seeking to modifyenvironmental control equipment required by the consent decree to eliminate an obligation to install future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree.  The district court granted AEP’s request to delay the deadline to install SCR technology at Rockport Plant, Unit 2 until June 2020.  AEP also proposed to retire Conesville Plant, Units 5 and 6 by December 31, 2022 and to retire one unit at Rockport Plant by December 31, 2028. Plaintiffs opposed AEP’s motion.has been installed.


In January 2018, AEP filed a supplemental motion proposing to install the SCR at Rockport Plant, Unit 2 and achieve the final SO2 emission cap applicable to the plant under the consent decree by the end of 2020, before the expiration of the initial lease term. Responsive filings were filed in February 2018 by parties opposing AEP’s proposed


modifications to the consent decree. AEP was directed to file a detailed statement of the specific relief requested to address the changed circumstances at Rockport, and the opposing parties were provided with an opportunity to respond thereto. The motion remains pending and a decision from the court is expected in 2018.

AEP is seeking to modify the consent decree as a means to resolve or substantially narrow the issues in pending litigation with the owners of Rockport Plant, Unit 2. See “Rockport Plant Litigation” in Management’s Discussion and Analysis of Financial Condition and Results of Operations and in Note 5 - Commitments, Guarantees and Contingencies for additional information.

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 the National Ambient Air Quality Standards (NAAQS)NAAQS and the development of SIPs to achieve any more stringent standards;standards, (b) implementation of the regional haze program by the states and the Federal EPA;EPA, (c) regulation of hazardous air pollutant emissions under the Mercury and Air Toxics Standards (MATS) Rule;MATS, (d) implementation and review of the Cross-State Air Pollution Rule (CSAPR), a FIP designed to eliminate significant contributions from sources in upwind states to nonattainment or maintenance areas in downwind statesCSAPR and (e) the Federal EPA’s regulation of greenhouse gas emissions from fossil-fueled electric generating unitsfossil generation under Section 111 of the CAA.

In March 2017, President Trump issued a series of executive orders designed to allow the Federal EPA to review and take appropriate action to revise or rescind regulatory requirements that place undue burdens on affected entities, including specific orders directing the Federal EPA to review rules that unnecessarily burden the production and use of energy. The Federal EPA published notice and an opportunity to comment on how to identify such requirements and what steps can be taken to reduce or eliminate such burdens. Future changes that result from this effort may affect AEP’s compliance plans.

Notable developments in significant CAA regulatory requirements affecting AEP’s operations are discussed in the following sections.


NAAQSNational Ambient Air Quality Standards


The Federal EPA issued new, more stringentperiodically reviews and revises the NAAQS for SO2criteria pollutants under the CAA. Revisions tend to increase the stringency of the standards, which in 2010,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, in 2012 and ozone in 2015; the existing standards for NO2which were retained after reviewleft unchanged by the Federal EPA in 2018. Implementation of these standards is underway. States are still in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the 2010 SO2 NAAQS. In December 2017, the Federal EPA published final designations for certain areas’ compliance with the 2010 SO2 NAAQS. States may develop additional requirements for AEP’s facilities as a result of these designations. In April 2017, the Federal EPA requested a stay of proceedings in the U.S. Court of Appeals for the District of Columbia Circuit where challenges to the 2015 ozone standard are pending, to allow reconsideration of that standard by the new administration. The Federal EPA initially announced a one-year delay in the designation of ozone non-attainment areas, but withdrew that decision. In December 2017, the Federal EPA issued a notice of data availability and requested public comment on recommended designations for compliance with the 2015 ozone standard. In March 2018, the Federal EPA responded to additional data regarding certain areas submitted by Texas. The Federal EPA anticipates completing the designations process within 120 days of providing notice to the states. The Federal EPA has also issued information to assist the states in developing plans that address their obligations under the interstate transport provisions of the CAA. State implementation plans for the 2015 ozone standard are due in October 2018.prior administration following its review. Management cannot currently predict the nature, stringencyif any changes to either standard are likely or timing of additional requirements for AEP’s facilities based on the outcome of these activities.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), detailing how the CAA’s requirement that certain in 2005, which could require power plants and other facilities to install best available retrofit technology (BART) willto address regional haze in federal parks and other protected areas. BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants.  CAVR will beis implemented by the states, through SIPs, or if SIPs are not adequate or are not developed on schedule,by the Federal EPA, through FIPs. In January 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.


The Federal EPA proposed disapproval ofArkansas has an approved regional haze SIPsSIP and all of SWEPCo's affected units are in a few states, including Arkansas and Texas.  In March 2012, the Federal EPA disapproved certain portions of the Arkansas regional haze SIP. In April 2015, the Federal EPA published a proposed FIP to replace the disapproved portions, including revised BART determinations for the Flint Creek Plant that were consistentcompliance with the environmental controls under construction. relevant requirements.

In September 2016, the Federal EPA published a final FIP that retains its BART determinations, but accelerates the schedule for implementation of certain required controls. The final rule is being challenged in the courts. In March 2017, the Federal EPA filed a motion that was granted by the U.S. Court of Appeals for the Eighth Circuit to hold the case in abeyance for 90 days to allow the parties to engage in settlement negotiations. Arkansas issued a proposed SIP revision to allow sources to participate in the CSAPR ozone season program in lieu of the source-specific NOx BART requirements in the FIP, and the Federal EPA has approved that SIP revision. Arkansas issued a second proposal to revise the SO2 BART determinations, and the public comment period on that action has closed. The Federal EPA has asked the Eighth Circuit to continue to hold litigation in abeyance to facilitate settlement discussions. Arkansas and other affected parties filed motions to stay the compliance deadlines pending further action from the Federal EPA and the motion was granted. Management cannot predict the outcome of these proceedings.

In January 2016,Texas, the Federal EPA disapproved portions of the Texas regional haze SIP and promulgated a final FIP that did not include any BART determinations. That rule was challenged and stayed by the U.S. Court of Appeals for the Fifth Circuit. The parties engaged in a settlement discussion but were unable to reach an agreement. In March 2017, the U.S. Court of Appeals for the Fifth Circuit granted partial remand of the final rule. In January 2017, the Federal EPA proposed source-specific BART requirements for SO2 from sources in Texas, including Welsh Plant, Unit 1. Management submitted comments on the proposal and engaged in discussions with the Texas Commission on Environmental Quality (TCEQ) regarding the development of an alternative to source-specific BART. In September 2017, the Federal EPA issued a final rule withdrawing Texas from the annual CSAPR budget programs and reaffirming CSAPR as a BART alternative. The Federal EPA then issued a separate rule finalizing the regional haze requirements for electric generating units in Texas and confirmed TCEQ’s determination that no new PM limitations are required for regional haze. The Federal EPA also finalized a FIP that allows participation in the CSAPR ozone season program to satisfy the NOx Xregional haze obligations for electric
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generating units.units in Texas. Additionally, the Federal EPA finalized an intrastate SO2 emissions trading program based on CSAPR allowance allocations as an alternativeallocations. Legal challenges to source-specific SO2 requirements. The proposed source-specific approach called for a wet FGD system to be installed on Welsh Plant, Unit 1. The opportunity to use emissions trading to satisfy the regional haze requirements for NOx and SO2 at AEP’s affected generating units provides greater flexibility and lower cost compliance options than the original proposal. A challenge to the FIP has been filedthese various rulemakings are pending in both the U.S. Court of Appeals for the Fifth Circuit by various intervenors. The Federal EPA and petitioners filed a joint motion to hold the case in abeyance pending the Federal EPA’s review of challengers’ petition for reconsideration. In March 2018, that motion was granted. Management supports the intrastate trading program contained in the FIP as a compliance alternative to source-specific controls.

In June 2012, the Federal EPA published revisions to the regional haze rules to allow states participating in the CSAPR trading programs to use those programs in place of source-specific BART for SO2 and NOx emissions based on its determination that CSAPR results in greater visibility improvements than source-specific BART in the CSAPR states.  The rule was challenged in the U.S. Court of Appeals for the District of Columbia Circuit. In March 2018,Management cannot predict the U.S. Courtoutcome of Appeals forthat litigation, although management supports the Districtintrastate trading program as a compliance alternative to source-specific controls and has intervened in the litigation in support of Columbia Circuit affirmed the Federal EPA rule.EPA.



Cross-State Air Pollution Rule


CSAPR

In 2011, the Federal EPA issued CSAPR as a replacement for the CAIR,is a regional trading program designed to address interstate transport of emissions that contributed significantly to downwind nonattainmentnon-attainment with the 1997 ozone and PM NAAQS.  Certain revisions to the rule were finalized in 2012.  CSAPR relies on newly-created SO2 and NOx Xallowances 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.


Numerous affected entities,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 and other parties filed petitions to review the CSAPRadopt standards of performance for utility boilers based on heat rate improvements for such boilers. However, in January 2021, the U.S. Court of Appeals for the District of Columbia Circuit. The court stayed implementation ofD.C. Circuit vacated the rule.  Following extended proceedings in the U.S. Court of Appeals for the District of Columbia CircuitACE rule and the U.S. Supreme Court, but while the litigation was still pending, the U.S. Court of Appeals for the District of Columbia Circuit grantedremanded it to the Federal EPA’s motionEPA. Management is unable to lift the stay and allow Phase I of CSAPR to take effect on January 1, 2015 and Phase II to take effect on January 1, 2017. In July 2015, the U.S. Court of Appeals for the District of Columbia Circuit found thatpredict how the Federal EPA over-controlled the SO2 and/or NOx budgets of 14 states. The U.S. Court of Appeals for the District of Columbia Circuit remanded the rulewill respond to the Federal EPA to timely revise the rule consistent with the court’s opinion while CSAPR remains in place.remand.


In October 2016, a final rule was issued to address the remand and to incorporate additional changes necessary to address the 2008 ozone standard. The final rule significantly reduces ozone season budgets in many states and discounts the value of banked CSAPR ozone season allowances beginning with the 2017 ozone season. The rule has been challenged in the courts and petitions for administrative reconsideration have been filed. In March 2018, the U.S. Court of Appeals for the District of Columbia Circuit denied the petitions and other challenges to the rule. Management has been complying with the more stringent ozone season budgets while these petitions were pending. In a related case, other parties challenged in the U.S. Court of Appeals for the District of Columbia Circuit a final rule withdrawing Texas from the CSAPR annual program and reaffirming that compliance with CSAPR remained better than compliance with BART. The U.S. Court of Appeals for the District of Columbia Circuit granted a motion in March 2018 to hold the case in abeyance until completion of the Federal EPA’s review of pending petitions for reconsideration of the Texas regional haze rule discussed above.

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

In 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants.  The rule establishes unit-specific emission rates for units burning coal on a 30-day rolling average basis for mercury, PM (as a surrogate for particles of nonmercury metals) and hydrogen chloride (as a surrogate for acid gases).  In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans.  Compliance was required within three years. Management obtained administrative extensions for up to one year at several units to facilitate the installation of controls or to avoid a serious reliability problem.

In April 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied all of the petitions for review of the April 2012 final rule. Industry trade groups and several states filed petitions for further review in the U.S. Supreme Court and the court granted those petitions in November 2014.

In June 2015, the U.S. Supreme Court reversed the decision of the U.S. Court of Appeals for the District of Columbia Circuit. The U.S. Court of Appeals for the District of Columbia Circuit remanded the MATS rule for further proceedings consistent with the U.S. Supreme Court’s decision that the Federal EPA was unreasonable in refusing to consider costs in its determination whether to regulate emissions of HAPs from power plants. The Federal EPA issued notice of a supplemental finding concluding that it is appropriate and necessary to regulate HAP emissions from coal-fired and oil-fired units. Management submitted comments on the proposal. In April 2016, the Federal EPA affirmed its determination that regulation of HAPs from electric generating units is necessary and appropriate. Petitions for review of the Federal EPA’s April 2016 determination have been filed in the U.S. Court of Appeals for the District of Columbia Circuit. Oral argument was scheduled for May 2017, but in April 2017 the Federal EPA requested that oral argument be postponed to facilitate its review of the rule. The rule remains in effect.



Climate Change, CO2 Regulation and Energy Policy

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.  Management is taking steps to comply with these requirements, including increasing wind and solar installations and power purchases and broadening the AEP System’s portfolio of energy efficiency programs.

In October 2015, the Federal EPA published the final standards for new, modified and reconstructed fossil fuel fired steam generating units and combustion turbines, and final guidelines for the development of state plans to regulate CO2 emissions from existing sources. The final standard for new combustion turbines is 1,000 pounds of CO2 per MWh and the final standard for new fossil steam units is 1,400 pounds of CO2 per MWh. Reconstructed turbines are subject to the same standard as new units and no standard for modified combustion turbines was issued. Reconstructed fossil steam units are subject to a standard of 1,800 pounds of CO2 per MWh for larger units and 2,000 pounds of CO2 per MWh for smaller units. Modified fossil steam units will be subject to a site specific standard no lower than the standards that would be applied if the units were reconstructed.

The final emissions guidelines for existing sources, known as the Clean Power Plan (CPP), are based on a series of declining emission rates that are implemented beginning in 2022 through 2029. The final emission rate is 771 pounds of CO2 per MWh for existing natural gas combined cycle units and 1,305 pounds of CO2 per MWh for existing fossil steam units in 2030 and thereafter. The Federal EPA also developed a set of rate-based and mass-based state goals.

The Federal EPA also published proposed “model” rules that could be adopted by the states that would allow sources within “trading ready” state programs to trade, bank or sell allowances or credits issued by the states. These rules would also be the basis for any federal plan issued by the Federal EPA in a state that fails to submit or receive approval for a state plan. In June 2016, the Federal EPA issued a separate proposal for the Clean Energy Incentive Program (CEIP) that was included in the model rules.

The final rules are being challenged in the courts. In February 2016, the U.S. Supreme Court issued a stay on the final CPP, including all of the deadlines for submission of initial or final state plans. The stay will remain in effect until a final decision is issued by the U.S. Court of Appeals for the District of Columbia Circuit and the U.S. Supreme Court considers any petition for review. In April 2017, the Federal EPA withdrew its previously issued proposals for model trading rules and a CEIP.

In March 2017, the Federal EPA filed in the U.S. Court of Appeals for the District of Columbia Circuit notice of: (a) an Executive Order from the President of the United States titled “Promoting Energy Independence and Economic Growth” directing the Federal EPA to review the CPP and related rules; (b) the Federal EPA’s initiation of a review of the CPP and (c) a forthcoming rulemaking related to the CPP consistent with the Executive Order, if the Federal EPA determines appropriate. In this same filing, the Federal EPA also presented a motion to hold the litigation in abeyance until 30 days after the conclusion of review of any resulting rulemaking. The District of Columbia Circuit granted the Federal EPA’s motion in part and has requested periodic status reports. In October 2017, the Federal EPA issued a proposed rule repealingrevising the CPPstandards for new sources and withdrawingdetermined that partial carbon capture and storage is not the legal memoranda issued in connection with the rule. The Federal EPA has re-examined its legal interpretation of the “bestbest system of emission reduction”reduction because it is not available throughout the U.S. and found that based on the statutory text, legislative history, use of similar terms elsewhereis 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 the CAA and its own historic implementation of Section 111 that a narrower interpretation of the term limits it to those designs, processes, control technologies and other systems that can be applied directly to or at the source. Since the primary systems relied on in the CPP are not consistent with that interpretation, the Federal EPA proposes that the rule be withdrawn. The comment period on the proposed repeal has been extended to April 2018. In December 2017, the Federal EPA issued an advanced notice of proposed rulemaking seeking information that should be considered by the Federal EPA in developing guidelines for state programs. Management is actively monitoring these rulemakings and participating in the development of any new guidelines.

place, AEP has taken action to reduce and offset CO2 emissions from its generating fleet andfleet. 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 2018,2021, 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, regulations, and grid reliability and resiliency, regulations and reflect the company’s current business strategy. The intermediate goal is a 60%an 80% reduction from 2000 CO2 emission levels from AEP generating facilities by 2030; the long-term goal is an 80% reduction ofnet-zero CO2 emissions from AEP generating facilities from 2000 levels by 2050. AEP’s total projectedestimated CO2 emissions in 2018 are2020 were approximately 9044 million metric tons, a 46%73% reduction from AEP’s 2000 CO2 emissions. AEP has made significant progress in reducing CO2 emissions of approximately 167 million metric tons.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.


Federal and state legislation or regulations that mandate limits on the emission of CO2 could result in significant increases in capital expenditures and operating costs, which in turn, could lead to increased liquidity needs and higher financing costs.  Excessive costs to comply with future legislation or regulations mighthave led to the announcement of early plant closures and could force AEP to close someadditional coal-fired generation facilities earlier than their estimated useful life. If AEP is unable to recover the costs of its investments, it would reduce future net income and could lead to possible impairment of assets.cash flows and impact financial condition.


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Coal Combustion Residual Rule


In April 2015, theThe Federal EPA published a finalEPA’s CCR rule to regulateregulates the disposal and beneficial re-use of coal combustion residuals (CCR),CCR, including fly ash and bottom ash generated atcreated from coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants.  The final rule has been challenged in the courts.

The final rule became effective in October 2015. CCR are regulated as non-hazardous solid wastes and facilities managing CCR must meet new minimum federal solid waste management standards. The rule applies to newactive and existing activeinactive CCR landfills and CCR surface impoundments at operatingfacilities of active electric utility or independent power production facilities.producers.

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 imposes constructionprovides two options that allow facilities to extend the date by which they must cease receipt of coal ash and operating obligations,close the ponds.

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

CompanyPlant Name and UnitGenerating
Capacity		Net Book Value (a)Projected
 Retirement Date
(in MWs)(in millions)
AEGCoRockport Plant, Unit 1655$237.1 2028
APCoAmos2,9302,128.5 2040
APCoMountaineer1,320966.4 2040
I&MRockport Plant, Unit 1655541.6 (b)2028
KPCoMitchell Plant780591.9 2040
SWEPCoFlint Creek Plant258271.9 2038
WPCoMitchell Plant780594.4 2040

(a)Net book value before cost of removal including CWIP and additional groundwater monitoring requirementsinventory.
(b)Amount includes a $181 million regulatory asset related to be implemented on a schedule spanning an approximate four year implementation period. Certain records must be posted to a publicly available internet site.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 2016,2020, APCo filed requests with the U.S. Congress passed legislation authorizing statesVirginia SCC and WVPSC to submit programsobtain the regulatory approvals necessary to regulateimplement CCR and ELG compliance plans and seek recovery of the estimated $240 million investment for the Amos and Mountaineer plants. In July 2021, a Virginia Senior Hearing Examiner recommended that the Virginia SCC deny, at this time, APCo’s request for approval of the ELG investments at the Amos and Mountaineer Plants. The judge also recommended that if the Virginia SCC ultimately does not grant APCo approval of the ELG investments, the Virginia SCC should delay consideration of the reasonableness and prudency of previously incurred ELG costs until a future case. Intervenors in Virginia and West Virginia along with the Virginia Senior Hearing Examiner recommended that only the CCR-related investments be constructed at Amos and Mountaineer, which could cause APCo to close these generating facilities at the end of 2028. If any of APCo’s CCR/ELG costs are not approved for recovery, it would reduce future net income and cash flows and impact financial condition. See “APCo and WPCo Rate Matters” section of Note 4 for additional information.

In December 2020 and February 2021, WPCo and KPCo filed requests with the WVPSC and KPSC, respectively, to obtain the regulatory approvals necessary to implement CCR and ELG compliance plans and seek recovery of the estimated $132 million investment for the Mitchell Plant that would allow the plant to continue operating through 2040. Within those requests, WPCo and KPCo also filed a $25 million alternative to implement only the CCR-related investments with the WVPSC and KPSC, respectively, which would allow the Mitchell Plant to continue operating only through 2028. In May 2021, intervenors in Kentucky and West Virginia submitted testimony with recommendations that only the CCR-related investments be constructed at the Mitchell Plant. In July 2021, the KPSC issued an order approving the CCR only alternative and rejecting the full CCR and ELG compliance plan. As of June 30, 2021, the total of the Mitchell Plant CCR and ELG investment balances in CWIP, was $2 million and $4 million, respectively, split equally between KPCo and WPCo. If any of the CCR and ELG compliance plan costs are not approved for recovery and/or the retirement date of the Mitchell Plant is accelerated to 2028 without
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commensurate cost recovery, it would reduce future net income and cash flows and impact financial condition. See “KPCo Rate Matters” section of Note 4 for additional information.

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 approve such programs if they are no less stringent thanretire the minimum federal standards. The Federal EPAPirkey 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$157.1 $49.4 2023 (b)
SWEPCoWelsh Plants, Units 1 and 31,053511.2 24.9 2028 (c)(d)

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

AEP may also enforce compliance with the minimum standards until a state program is approved or if states fail to adopt their own programs. In September 2017, the Federal EPA granted industry petitions to reconsider the CCR rule and asked that litigation regarding the rule be held in abeyance. The U.S. Court of Appeals for the District of Columbia Circuit heard oral argument in November 2017. In March 2018, the Federal EPA issued a proposed rule to modify certain provisions of the solid waste management standards and provide additional flexibility to facilities regulated under approved state programs. The comment period is open until the end of April 2018. Management supports the adoption of more flexible compliance alternatives subject to the Federal EPA or state oversight.

Other utilities and industrial sources have been engaged in litigation with environmental advocacy groups who claim that releases of contaminants from wells, CCR units, pipelines and other facilities to ground waters that have a hydrologic connection to a surface water body represents an “unpermitted discharge” under the Clean Water Act. The Federal EPA has opened a rulemaking docket to solicit information to determine whether it should provide additional clarification of the scope of Clean Water Act permitting requirements for discharges to ground water. Comments are due in May 2018. Management is unable to predict the outcome of these cases on the Federal EPA’s rulemaking, but they could impose significant additional costs on AEP’s facilities.

Because AEP currently uses surface impoundments and landfills to manage CCR materials at generating facilities,incur significant costs will be incurred to upgrade or close and replace these existing facilities at some pointsurface 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.

Closure and post-closure costs have been included in ARO in accordance with the requirements in the future as the new rulefinal 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 implemented. Management recorded a $95 million increaserequired without providing similar assurances of cost recovery in asset retirement obligationsregulated jurisdictions, it would impose significant additional operating costs on AEP, which could lead to increased financing costs and liquidity needs. Other units in 2015 primarily due to the publication of the final rule.Virginia, Ohio, West Virginia and Kentucky have already been closed in place in accordance with state law programs. Management will continue to evaluate the rule’s impactparticipate in rulemaking activities and make adjustments based on operations.new federal and state requirements affecting its ash disposal units.




Clean Water Act (CWA) Regulations


In 2014, theThe Federal EPA issued a finalEPA’s ELG rule setting forth standards for existing power plants that is intended to reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water.  Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress.  The final rule affects all plants withdrawing more than two million gallons of cooling water per day. The rule offers seven technology options to comply with the impingement standard and requires site-specific studies to determine appropriate entrainment compliance measures atgenerating facilities withdrawing more than 125 million gallons per day. Additional requirements may be imposed as a result of consultation with other federal agencies to protect threatened and endangered species and their habitats. Facilities with existing closed cycle recirculating cooling systems, as defined in the rule, are not expected to require any technology changes. Facilities subject to both the impingement standard and site-specific entrainment studies will typically be given at least three years to conduct and submit the results of those studies to the permit agency. Compliance timeframes will then be established by the permit agency through each facility’s NPDES permit for installation of any required technology changes, as those permits are renewed over the next five to eight years. Petitions for review of the final rule were filed by industry and environmental groups and are currently pending in the U.S. Court of Appeals for the Second Circuit.

In addition, the Federal EPA developed revised effluent limitation guidelines for electricity generating facilities.  A final rule was issued in November 2015. The final rule establishes limits on FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater, which are to be imposed as soon as possible after November 2018 and no later than December 2023. These new requirements will be implemented through each facility’s wastewater discharge permit. TheA recent revision to the ELG rule, has been challengedpublished in the U.S. CourtOctober 2020, establishes additional options for reusing and discharging small volumes of Appeals for the Fifth Circuit. In March 2017, industry associations filed a petition for reconsideration of the rule with the Federal EPA. In April 2017, the Federal EPA granted reconsideration of the rule and issued a stay of the rule’s future compliance deadlines, which has now expired. In April 2017, the U.S. Court of Appeals for the Fifth Circuit granted a stay of the litigation for 120 days. In June 2017, the Federal EPA also issued a proposal to temporarily postpone certain compliance deadlines in the rule. A final rule revising the compliance deadlines for FGD wastewater and bottom ash transport water, provides an exception for retiring units and extends the compliance deadline to bea date as soon as possible beginning one year after the rule was published but no earlierlater than 2020 was issued in September 2017.December 2025. Management submitted comments supporting the proposed postponement. Management continues to assesshas 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. 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. We continue to work with state agencies to finalize permit terms and conditions.

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Impact of Environmental Regulation on Coal-Fired Generation

Compliance with extensive environmental regulations requires significant capital investment in environmental monitoring, installation of pollution control equipment, emission fees, disposal 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.

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

The table below summarizes the net book value, as of June 30, 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)
PSONortheastern Plant, Unit 3$183.2 $119.2 2026(c)$14.9 
PSOOklaunion Power Station— 33.5 2020(d)1.9 
SWEPCoDolet Hills Power Station27.3 114.3 2021(e)7.8 
SWEPCoPirkey Power Plant138.5 49.4 2023(f)13.6 
SWEPCoWelsh Plant, Units 1 and 3500.6 24.9 2028 (g)(h)33.2 
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)Northeastern Plant, Unit 3 is currently being recovered through 2040.
(d)Oklaunion Power Station is currently being recovered through 2046.
(e)Dolet Hills Power Station is currently being recovered through 2026 in the Louisiana jurisdiction and through 2046 in the Arkansas and Texas jurisdictions.
(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 actively participating inseeking or will seek regulatory recovery, as necessary, for any net book value remaining when the reconsideration proceedings.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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In June 2015, the Federal EPA and the U.S. Army Corps of Engineers jointly issued a final rule to clarify the scope of the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases. The CWA provides for federal jurisdiction over “navigable waters” defined as “the waters of the United States.” This jurisdictional definition applies to all CWA programs, potentially impacting generation, transmission and distribution permitting and compliance requirements. Among those programs are permits for wastewater and storm water discharges, permits for impacts to wetlands and water bodies and oil spill prevention planning. The final definition continues to recognize traditional navigable waters of the U.S. as jurisdictional as well as certain exclusions. The rule also contains a number of new specific definitions and criteria for determining whether certain other waters are jurisdictional because of a “significant nexus.” Management believes that clarity and efficiency in the permitting process is needed. Management remains concerned that the rule introduces new concepts and could subject more of AEP’s operations to CWA jurisdiction, thereby increasing the time and complexity of permitting. The final rule is being challenged in both courts of appeal and district courts. The U.S. Court of Appeals for the Sixth Circuit granted a nationwide stay of the rule pending jurisdictional determinations. In February 2016, the U.S. Court of Appeals for the Sixth Circuit issued a decision holding that it has exclusive jurisdiction to decide the challenges to the “waters of the United States” rule. Industry, state and related associations filed petitions for a rehearing of the jurisdictional decision. In April 2016, the U.S. Court of Appeals for the Sixth Circuit denied the petitions. In January 2017, the decision was appealed to the U.S. Supreme Court, which granted certiorari to review the jurisdictional issue. Oral argument was heard in October 2017. In January 2018, the U.S. Supreme Court ruled that challenges to the definition of “waters of the United States” must be filed in the federal district court, and remanded the case to the U.S. Court of Appeals for the Sixth Circuit with directions to dismiss the petitions for review for lack of jurisdiction. The stay has been lifted and the Sixth Circuit case has been dismissed. Challenges to the rule will proceed in federal district courts.







In March 2017, the Federal EPA published a notice of intent to review the rule and provide an advanced notice of a proposed rulemaking consistent with the Executive Order of the President of the United States directing the Federal EPA and U.S. Army Corps of Engineers to review and rescind or revise the rule. In June 2017, the agencies signed a notice of proposed rule to rescind the definition of “waters of the United States” that was adopted in June 2015, and to re-codify the definition of that phrase as it existed immediately prior to that action. This action would effectively retain the status quo until a new rule is adopted by the agencies. The Federal EPA and U.S. Army Corps of Engineers also finalized a new rule to extend the applicability date of the 2015 rule by two years before the nationwide stay issued by the U.S. Court of Appeals for the Sixth Circuit was lifted. Challenges to the applicability date rule have been filed by third parties in several federal district courts. Management will participate in further rulemaking activities.


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 SSOstandard 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 returns on equity.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 returns on equity.ROE.


Generation & Marketing


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


The remainder of AEP’s activities isare 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 RegistrantsRegistrants’ statements of income as applicable. Under the various state utility rate making processes, these expenses are generally reimbursable directly from and billed to customers. As a result, they do not typically impact Operating Income or Earnings Attributable to AEP Common Shareholders. Management believes that Gross Margin provides a useful measure for investors and other financial statement users to analyze AEP’s financial performance in that it excludes the effect on Total Revenues caused by volatility in these expenses. Operating Income, which is presented in accordance with GAAP in AEP’s statements of income, is the most directly comparable GAAP financial measure to the presentation of Gross Margin. AEP’s definition of Gross Margin may not be directly comparable to similarly titled financial measures used by other companies.



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The following table presents Earnings (Loss) Attributable to AEP Common Shareholders by segment:
Three Months EndedSix Months Ended
June 30,June 30,
 2021202020212020
 (in millions)
Vertically Integrated Utilities$228.2 $255.9 $498.6 $501.2 
Transmission and Distribution Utilities153.7 139.5 268.1 255.7 
AEP Transmission Holdco168.7 91.5 340.7 232.1 
Generation & Marketing52.4 65.9 89.0 94.3 
Corporate and Other(24.8)(32.0)(43.2)(67.3)
Earnings Attributable to AEP Common Shareholders$578.2 $520.8 $1,153.2 $1,016.0 
 Three Months Ended March 31,
 2018 2017
 (in millions)
Vertically Integrated Utilities$231.2
 $219.5
Transmission and Distribution Utilities125.4
 119.1
AEP Transmission Holdco104.0
 71.8
Generation & Marketing18.2
 186.2
Corporate and Other(24.4) (4.4)
Earnings Attributable to AEP Common Shareholders$454.4
 $592.2


AEP CONSOLIDATED


FirstSecond Quarter of 20182021 Compared to FirstSecond Quarter of 20172020


Earnings Attributable to AEP Common Shareholders decreasedincreased from $592$521 million in 20172020 to $454$578 million in 20182021 primarily due to:


A decrease•Favorable rate proceedings in earnings in the Generation & Marketing segment primarily due to the 2017 gain resulting from the sale of certain merchant generation assets.AEP’s various jurisdictions.

This decrease was partially offset by:

•An increase in transmission investment, primarily at AEP Transmission Holdco, which resulted in higher revenues and income.
•Unrealized gains on AEP’s investment in ChargePoint.

These increases were partially offset by:

•An increase in weather-related usage.Other Operation and Maintenance expenses driven by the COVID-19 pandemic which resulted in lower expenses in the second quarter of 2020.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020

Earnings Attributable to AEP Common Shareholders increased from $1,016 million in 2020 to $1,153 million in 2021 primarily due to:

•Favorable rate proceedings in AEP’s various jurisdictions.

•An increase in weather-related usage.
•An increase in transmission investment, which resulted in higher revenues and income.
•Unrealized gains on AEP’s results of operationsinvestment in ChargePoint.

These increases were partially offset by:

•An increase in Other Operation and Maintenance expenses driven by operating segment are discussed below.the COVID-19 pandemic which resulted in lower expenses in 2020.

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VERTICALLY INTEGRATED UTILITIES
Three Months EndedSix Months Ended
June 30,June 30,
 Vertically Integrated Utilities2021202020212020
 (in millions)
Revenues$2,260.6 $2,092.0 $4,797.9 $4,318.7 
Fuel and Purchased Electricity650.4 582.1 1,509.4 1,253.3 
Gross Margin1,610.2 1,509.9 3,288.5 3,065.4 
Other Operation and Maintenance703.5 624.6 1,443.7 1,315.9 
Depreciation and Amortization433.8 393.3 865.9 775.0 
Taxes Other Than Income Taxes128.0 117.5 251.5 234.6 
Operating Income344.9 374.5 727.4 739.9 
Other Income5.1 1.4 5.8 3.0 
Allowance for Equity Funds Used During Construction10.8 9.0 20.7 17.2 
Non-Service Cost Components of Net Periodic Benefit Cost17.0 17.1 34.0 34.0 
Interest Expense(141.6)(141.8)(281.2)(286.3)
Income Before Income Tax Expense and Equity Earnings236.2 260.2 506.7 507.8 
Income Tax Expense8.2 4.6 8.0 6.7 
Equity Earnings of Unconsolidated Subsidiary0.8 0.7 1.5 1.5 
Net Income228.8 256.3 500.2 502.6 
Net Income Attributable to Noncontrolling Interests0.6 0.4 1.6 1.4 
Earnings Attributable to AEP Common Shareholders$228.2 $255.9 $498.6 $501.2 
  Three Months Ended March 31,
Vertically Integrated Utilities 2018 2017
  (in millions)
Revenues $2,408.0
 $2,290.4
Fuel and Purchased Electricity 857.8
 788.4
Gross Margin 1,550.2
 1,502.0
Other Operation and Maintenance 740.0
 660.1
Depreciation and Amortization 313.3
 278.3
Taxes Other Than Income Taxes 109.9
 101.1
Operating Income 387.0
 462.5
Interest and Investment Income 2.6
 3.1
Carrying Costs Income 2.8
 4.1
Allowance for Equity Funds Used During Construction 7.4
 6.2
Non-Service Cost Components of Net Periodic Benefit Cost 18.1
 5.9
Interest Expense (137.9) (134.9)
Income Before Income Tax Expense and Equity Earnings 280.0
 346.9
Income Tax Expense 47.7
 127.7
Equity Earnings of Unconsolidated Subsidiaries 0.5
 1.3
Net Income 232.8
 220.5
Net Income Attributable to Noncontrolling Interests 1.6
 1.0
Earnings Attributable to AEP Common Shareholders $231.2
 $219.5


Summary of KWh Energy Sales for Vertically Integrated Utilities
Three Months EndedSix Months Ended
June 30,June 30,
2021202020212020
 (in millions of KWhs)
Retail:    
Residential6,525 6,976 16,006 15,238 
Commercial5,670 5,150 10,928 10,516 
Industrial8,611 7,699 16,313 16,174 
Miscellaneous549 511 1,068 1,041 
Total Retail21,355 20,336 44,315 42,969 
Wholesale (a)4,487 4,924 9,129 8,542 
Total KWhs25,842 25,260 53,444 51,511 
 Three Months Ended March 31,
 2018 2017
 (in millions of KWhs)
Retail: 
  
Residential9,572
 8,239
Commercial5,868
 5,689
Industrial8,497
 8,264
Miscellaneous553
 536
Total Retail24,490
 22,728
    
Wholesale (a)5,738
 6,507
    
Total KWhs30,228
 29,235

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







20




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


Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities
Three Months EndedSix Months Ended
June 30,June 30,
2021202020212020
 (in degree days)
Eastern Region    
Actual – Heating (a)
170 212 1,709 1,453 
Normal – Heating (b)
138 137 1,738 1,748 
Actual – Cooling (c)
359 324 362 337 
Normal – Cooling (b)
339 337 343 342 
Western Region    
Actual – Heating (a)
35 49 993 698 
Normal – Heating (b)
34 34 900 901 
Actual – Cooling (c)
652 673 678 724 
Normal – Cooling (b)
699 700 727 728 

(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.

21




 Three Months Ended March 31,
 2018 2017
 (in degree days)
Eastern Region 
  
Actual – Heating (a)
1,637
 1,181
Normal – Heating (b)
1,602
 1,615
    
Actual – Cooling (c)
6
 1
Normal – Cooling (b)
5
 5
    
Western Region 
  
Actual – Heating (a)
881
 530
Normal – Heating (b)
875
 892
    
Actual – Cooling (c)
36
 82
Normal – Cooling (b)
27
 24
Second Quarter of 2021 Compared to Second Quarter of 2020

(a)Heating degree days are calculated on a 55 degree temperature base.Reconciliation of Second Quarter of 2020 to Second Quarter of 2021
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
(b)Second Quarter of 2020Normal Heating/Cooling represents the thirty-year average of degree days.$255.9 
Changes in Gross Margin:
Retail Margins96.4 
Margins from Off-system Sales5.6 
Transmission Revenues0.9 
Other Revenues(2.6)
Total Change in Gross Margin100.3 
Changes in Expenses and Other:
Other Operation and Maintenance(78.9)
(c)Depreciation and AmortizationCooling degree days are calculated on a 65 degree temperature base.(40.5)
Taxes Other Than Income Taxes(10.5)
Other Income3.7 
Allowance for Equity Funds Used During Construction1.8 
Non-Service Cost Components of Net Periodic Pension Cost(0.1)
Interest Expense0.2 
Total Change in Expenses and Other(124.3)
Income Tax Expense(3.6)
Equity Earnings of Unconsolidated Subsidiary0.1 
Net Income Attributable to Noncontrolling Interests(0.2)
Second Quarter of 2021$228.2 



First Quarter of 2018 Compared to First Quarter of 2017
Reconciliation of First Quarter of 2017 to First Quarter of 2018
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
   
First Quarter of 2017 $219.5
   
Changes in Gross Margin:  
Retail Margins 49.5
Off-system Sales 1.0
Transmission Revenues 2.7
Other Revenues (5.0)
Total Change in Gross Margin 48.2
   
Changes in Expenses and Other:  
Other Operation and Maintenance (79.9)
Depreciation and Amortization (35.0)
Taxes Other Than Income Taxes (8.8)
Interest and Investment Income (0.5)
Carrying Costs Income (1.3)
Allowance for Equity Funds Used During Construction 1.2
Non-Service Cost Components of Net Periodic Pension Cost 12.2
Interest Expense (3.0)
Total Change in Expenses and Other (115.1)
   
Income Tax Expense 80.0
Equity Earnings (0.8)
Net Income Attributable to Noncontrolling Interests (0.6)
   
First Quarter of 2018 $231.2


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


•Retail Margins increased $50$96 million primarily due to the following:
An $89•A $36 million increase at I&M due to wholesale true-up, increase in rider revenues and the Indiana base rate case. This increase was partially offset in other expense items below.
•A $17 million increase in weather-related usage primarilyrevenue from rate riders at PSO. This increase was partially offset in the eastern region.other expense items below.
The effect of rate proceedings in AEP’s service territories which included:
•A $25$12 million increase for I&M from rate proceedings primarily in Indiana.
A $22 million increase for SWEPCoat KPCo due to rider revenues. This increase was partially offset in other expense items below.
•A $9 million increase at APCo and WPCo due to rider revenue primarily in West Virginia. This increase was partially offset in other expense items below.
•An $8 million increase in weather-normalized retail margins driven by a $34 million increase in the commercial and industrial customer classes partially offset by a $27 million decrease in the residential customer class.
•A $5 million increase at KPCo due to base rate revenue increases in Texas and Louisiana.
An $11 million increase for APCo primarily due to increases from rate riders in Virginia.
A $4 million increase for PSO due to new ratescase revenues implemented in March 2018, inclusive of a $2 million decrease due to the change in the corporate federal tax rate.
For the rate increases described above, $26 million relate to riders/trackers, which have corresponding increases in expense items below.January 2021.
These increases were partially offset by:
•A $71$7 million decrease due toin weather-normalized wholesale margins, including the 2018 provisions for customer refunds primarily related to Tax Reform. This decrease is offset in Income Tax Expense below.loss of a significant wholesale contract at I&M.
A $16 million decrease due to lower weather-normalized margins, primarily due to SWEPCo and I&M wholesale customer load loss•Margins from contracts that expired at the end of 2017.
A $4 million decrease primarily due toOff-system Sales increased fuel and other variable production costs not recovered through fuel clauses or other trackers.
A $4 million decrease for I&M in FERC generation wholesale municipal and cooperative revenues primarily due to changes to the annual formula rate.


Transmission Revenues increased $3$6 million primarily due to anfavorable market prices in both PJM and SPP.
22




•Transmission Revenues increased $1 million due to a $10 million increase in transmission investments in SPP.
Other Revenues decreased $5investment primarily at APCo offset by a $9 million primarily due to reduced rates for KPCo Demand Side Management programs beginning in 2018.decrease as a result of the annual formula rate true-up. This decreaseincrease is partially offset in Other OperationDepreciation and Maintenance expenseAmortization expenses below.


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


•Other Operation and Maintenance expenses increased $80$79 million primarily due to the following:
•A $45$47 million increase in recoverable expenses, primarily fuel support and PJM expenses fully recovered intransmission services including the annual formula rate recovery riders/trackers in Gross Margins above.true-up.
•A $15$25 million increase in plant maintenance primarily for I&M, KPCo and SWEPCo.SPP transmission services including the annual formula rate true-up.
•A $14 million increase due to the Wind Catcher Project for SWEPCo and PSO.
A $10$23 million increase in transmission services primarily in SPP.
A $9 million increase due to an increase in estimated expense for claims related to asbestos exposure.employee-related expenses.
These increases were partially offset by:
•A $7 million decrease due to an increased Nuclear Electric Insurance Limited distribution in 2018.
A $6$20 million decrease in distribution expensesstorms primarily due to distribution system improvements in 2017.at KPCo, APCo and PSO.
•Depreciation and Amortization expenses increased $35$41 millionprimarily due to a higher depreciable base.
base and an increase in depreciation rates at APCo. This increase was partially offset in Gross Margin above.
•Taxes Other Than Income Taxes increased $9$11 million primarily due to:
to the following:
•A $5 million increase in property taxes at SWEPCo resulting from the expiration of the Louisiana Industrial Tax Exemption related to the Stall Plant.
•A $4 million increase in state gross receipts taxat I&M primarily due to a prior period refund.
A $3 million increase in property taxtaxes driven by an increase in utility plant.
Non-Service Cost Components of Net Periodic Benefit Cost decreased $12•Other Income increased $4 millionprimarily due to favorable asset returns forincreased interest income related the funded Pension and OPEB plans and by movingFebruary 2021 severe winter weather event at SWEPCo.
•Income Tax Expense increased $4 million primarily due to a Medicare Advantage arrangement for post-65 retireesdecrease in the Non-UMWA OPEB plan.  Additionally, theamortization of Excess ADIT. The decrease wasin amortization of Excess ADIT is partially due to the implementation of ASU 2017-07offset above in 2018, which eliminated AEP’s ability to capitalize a portion of its non-service cost components.Retail Margins.

23
Income TaxExpense decreased $80




Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020
Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30, 2021
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
Six Months Ended June 30, 2020$501.2 
Changes in Gross Margin:
Retail Margins194.5 
Margins from Off-system Sales23.8 
Transmission Revenues11.2 
Other Revenues(6.4)
Total Change in Gross Margin223.1 
Changes in Expenses and Other:
Other Operation and Maintenance(127.8)
Depreciation and Amortization(90.9)
Taxes Other Than Income Taxes(16.9)
Other Income2.8 
Allowance for Equity Funds Used During Construction3.5 
Interest Expense5.1 
Total Change in Expenses and Other(224.2)
Income Tax Expense(1.3)
Net Income Attributable to Noncontrolling Interests(0.2)
Six Months Ended June 30, 2021$498.6 

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

•Retail Margins increased $195 million primarily due to the changefollowing:
•A $59 million increase in weather-related usage primarily in the corporate federal income taxresidential class.
•A $48 million increase at I&M due to wholesale true-up, Indiana and Michigan base rate cases and increases in rider revenues. This increase was partially offset in other expense items below.
•A $27 million increase at KPCo due to rider revenues. This increase was partially offset in other expense items below.
•A $22 million increase at APCo and WPCo due to rider revenue primarily in West Virginia. This increase was partially offset in other expense items below.
•A $19 million increase in revenue from 35%rate riders at PSO. This increase was partially offset in 2017other expense items below.
•An $11 million increase at KPCo due to 21%base rate case revenues implemented in 2018January 2021.
•A $10 million increase in weather-normalized wholesale margins at SWEPCo.
•An $8 million increase in recoverable fuel costs at SWEPCo primarily due to timing of recovery.
•A $5 million increase in municipal and cooperative revenues at SWEPCo primarily due to the annual generation formula rate true-up.
These increases were partially offset by:
•A $23 million decrease in weather-normalized margins for wholesale contracts, including the loss of a significant wholesale contract at I&M.
•A $17 million decrease in weather-normalized retail margins driven by a $10 million decrease in the residential class and a $7 million decrease in the industrial customer class.
•Margins from Off-system Sales increased $24 million primarily due to Turk Plant merchant sales as a result of the February 2021 severe winter weather event at SWEPCo.
24




•Transmission Revenues increased $11 million due to an increase in transmission investment primarily at APCo, partially offset by a $9 million decrease as a result of the transmission formula rate true-up. This increase is partially offset in Depreciation and Amortization expenses below.
•Other Revenues decreased $6 million primarily due to business development revenue at PSO. This decrease was partially offset in Other Operation and Maintenance expenses below.

Expenses and Other and Income Tax Reform, amortizationExpense changed between years as follows:

•Other Operation and Maintenance expenses increased $128 million primarily due to the following:
•A $78 million increase in PJM transmission services including the annual formula rate true-up.
•A $31 million increase in SPP transmission services including the annual formula rate true-up.
•A $29 million increase in employee-related expenses.
•A $9 million increase primarily due to an increase in vegetation management expenses.
These increases were partially offset by:
•A $15 million decrease due to storms primarily at KPCo, APCo and PSO.
•A $9 million decrease in factoring expenses.
•Depreciation and Amortization expenses increased $91 millionprimarily due to a higher depreciable base and increased depreciation rates at APCo and I&M. This increase was partially offset in Gross Margin above.
•Taxes Other Than Income Taxes increased $17 million primarily due to the following:
•A $10 million increase at SWEPCo primarily due to increased property taxes resulting from the expiration of excess accumulated deferred incomethe Louisiana Industrial Tax Exemption related to Stall Plant.
•A $4 million increase at I&M primarily due to property taxes associated with certain depreciable property anddriven by an increase in utility plant.
•Interest Expense decreased $5 million primarily due to the following:
•A $3 million decrease at PSO primarily due to lower borrowing costs in 2021.
•A $2 million decrease at I&M primarily due to a decrease in pretax book income.carrying charges and a decreased interest rate on variable rate notes.

25







TRANSMISSION AND DISTRIBUTION UTILITIES
Three Months EndedSix Months Ended
June 30,June 30,
Transmission and Distribution Utilities2021202020212020
 (in millions)
Revenues$1,103.4 $1,034.5 $2,191.5 $2,141.4 
Purchased Electricity168.0 147.5 373.5 338.9 
Gross Margin935.4 887.0 1,818.0 1,802.5 
Other Operation and Maintenance360.8 351.9 726.0 719.1 
Depreciation and Amortization178.5 207.0 351.2 421.5 
Taxes Other Than Income Taxes158.4 141.8 316.0 288.0 
Operating Income237.7 186.3 424.8 373.9 
Interest and Investment Income0.3 0.4 0.7 1.1 
Carrying Costs Income0.5 0.6 1.0 1.0 
Allowance for Equity Funds Used During Construction6.2 7.7 13.0 14.7 
Non-Service Cost Components of Net Periodic Benefit Cost7.2 7.4 14.5 14.7 
Interest Expense(77.0)(72.2)(151.5)(143.6)
Income Before Income Tax Expense (Benefit)174.9 130.2 302.5 261.8 
Income Tax Expense (Benefit)21.2 (9.3)34.4 6.1 
Net Income153.7 139.5 268.1 255.7 
Net Income Attributable to Noncontrolling Interests— — — — 
Earnings Attributable to AEP Common Shareholders$153.7 $139.5 $268.1 $255.7 
  Three Months Ended March 31,
Transmission and Distribution Utilities 2018 2017
  (in millions)
Revenues $1,162.4
 $1,086.4
Purchased Electricity 244.6
 223.4
Amortization of Generation Deferrals 58.6
 60.9
Gross Margin 859.2
 802.1
Other Operation and Maintenance 352.7
 287.9
Depreciation and Amortization 172.6
 156.2
Taxes Other Than Income Taxes 137.4
 126.9
Operating Income 196.5
 231.1
Interest and Investment Income 1.4
 3.5
Carrying Costs Income 0.7
 1.9
Allowance for Equity Funds Used During Construction 8.0
 4.2
Non-Service Cost Components of Net Periodic Benefit Cost 8.2
 2.2
Interest Expense (60.1) (60.0)
Income Before Income Tax Expense 154.7
 182.9
Income Tax Expense 29.3
 63.8
Net Income 125.4
 119.1
Net Income Attributable to Noncontrolling Interests —
 —
Earnings Attributable to AEP Common Shareholders $125.4
 $119.1


Summary of KWh Energy Sales for Transmission and Distribution Utilities
Three Months EndedSix Months Ended
June 30,June 30,
2021202020212020
 (in millions of KWhs)
Retail:    
Residential6,065 6,299 12,989 12,599 
Commercial6,488 5,559 12,064 11,432 
Industrial6,338 5,148 11,619 11,056 
Miscellaneous185 180 351 362 
Total Retail (a)19,076 17,186 37,023 35,449 
Wholesale (b)445 455 1,048 845 
Total KWhs19,521 17,641 38,071 36,294 
 Three Months Ended March 31,
 2018 2017
 (in millions of KWhs)
Retail: 
  
Residential6,797
 5,894
Commercial5,864
 5,753
Industrial5,514
 5,476
Miscellaneous153
 160
Total Retail (a)18,328
 17,283
    
Wholesale (b)667
 798
    
Total KWhs18,995
 18,081


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

26






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


Summary of Heating and Cooling Degree Days for Transmission and Distribution Utilities
Three Months EndedSix Months Ended
June 30,June 30,
2021202020212020
 (in degree days)
Eastern Region    
Actual – Heating (a)
215 292 1,992 1,765 
Normal – Heating (b)
183 182 2,066 2,080 
Actual – Cooling (c)
361 314 361 317 
Normal – Cooling (b)
304 301 307 304 
Western Region    
Actual – Heating (a)
4 6 319 97 
Normal – Heating (b)
3 3 188 188 
Actual – Cooling (d)
833 936 970 1,167 
Normal – Cooling (b)
931 933 1,057 1,058 
 Three Months Ended March 31,
 2018 2017
 (in degree days)
Eastern Region 
  
Actual – Heating (a)
1,884
 1,403
Normal – Heating (b)
1,884
 1,899
    
Actual – Cooling (c)
4
 3
Normal – Cooling (b)
3
 3
    
Western Region 
  
Actual – Heating (a)
230
 102
Normal – Heating (b)
191
 195
    
Actual – Cooling (d)
196
 258
Normal – Cooling (b)
119
 113


(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.



27



First

Second Quarter of 20182021 Compared to FirstSecond Quarter of 20172020
Reconciliation of Second Quarter of 2020 to Second Quarter of 2021
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
Second Quarter of 2020$139.5 
Changes in Gross Margin:
Retail Margins76.5 
Margins from Off-system Sales(18.7)
Transmission Revenues30.0 
Other Revenues(39.4)
Total Change in Gross Margin48.4 
Changes in Expenses and Other:
Other Operation and Maintenance(8.9)
Depreciation and Amortization28.5 
Taxes Other Than Income Taxes(16.6)
Interest and Investment Income(0.1)
Carrying Costs Income(0.1)
Allowance for Equity Funds Used During Construction(1.5)
Non-Service Cost Components of Net Periodic Benefit Cost(0.2)
Interest Expense(4.8)
Total Change in Expenses and Other(3.7)
Income Tax Expense(30.5)
Second Quarter of 2021$153.7 
Reconciliation of First Quarter of 2017 to First Quarter of 2018
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
   
First Quarter of 2017 $119.1
   
Changes in Gross Margin:  
Retail Margins 53.8
Off-System Sales 5.5
Transmission Revenues (4.0)
Other Revenues 1.8
Total Change in Gross Margin 57.1
   
Changes in Expenses and Other:  
Other Operation and Maintenance (64.8)
Depreciation and Amortization (16.4)
Taxes Other Than Income Taxes (10.5)
Interest and Investment Income (2.1)
Carrying Costs Income (1.2)
Allowance for Equity Funds Used During Construction 3.8
Non-Service Cost Components of Net Periodic Benefit Cost 6.0
Interest Expense (0.1)
Total Change in Expenses and Other (85.3)
   
Income Tax Expense 34.5
   
First Quarter of 2018 $125.4


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


•Retail Margins increased $54$77 million primarily due to the following:
•A $39$30 million net increase in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset by a corresponding increase in Other Operation and Maintenance below.
A $21 million increase in Ohio revenues associated with the Universal Service Fund (USF). This increase was offset by a corresponding increase in Other Operation and Maintenance expenses below.
•A $10$19 million increase in Texas weather-related usage in Ohio primarily driven by a 125% increase in heating degree days partially offset by a 24% decrease in cooling degree days.from the commercial and residential classes of $11 million and $6 million, respectively.
•A $10$19 million increase in weather-normalized margins in Texas primarily in the residential and commercial classes.
•A $9$16 million increase from interim rate increases driven by increased transmission investment in Texas.
•A $12 million increase in Texasrider revenues associated with the Transmission Cost Recovery Factor revenue rider. This increase was partially offset by an increase in Other Operation and Maintenance expenses below.
A $7 million increase in Texas revenues associated with the Distribution Cost Recovery Factor revenue rider.
A $6 million increase in Ohio rider revenues associated with the DIR. This increase was partially offset in variousother expense items below.
•An $11 million increase from interim rate increases driven by increased distribution investment in Texas.
•An $8 million increase due to a PUCO order to refund unused 2018 major storm reserve collections to customers in the prior period. This decrease was offset in Other Operation and Maintenance expenses below.
•A $4$7 million net increase in Ohio RSRthe Legacy Generation Resource Rider (LGRR) in Ohio. This increase was offset in Margins from Off-system Sales and Other Revenues below.
•A $5 million increase in revenues less associated amortizations.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 $21$19 million decrease due to the 2018 provisions for customer refunds primarily related to Tax Reform. This decrease is offset in Income Tax Expense below.
An $11 million decrease inending of the Energy Efficiency/Efficiency and Peak Demand Reduction rider revenuesRider in Ohio.Ohio in December 2020. This decrease was partially offset by a corresponding decrease in Other Operation and Maintenance expenses below.
A $10
28




•An $11 million decrease in margin forrevenues in Ohio associated with the Ohio Phase-In-Recovery Rider including associated amortizations.Universal Service Fund (USF). This decrease was offset in Other Operation and Maintenance expenses below.
•A $7$6 million decrease in weather-related usage in Texas primarily due to an 11% decrease in cooling degree days.
•A $4 million decrease due to refunds in Texas of Excess ADIT and excess federal income taxes collected as a result of Tax Reform.
•Margins from Off-system Sales decreased $19 million primarily due to the following:
•A $13 million decrease in Ohio due to the recovery of lower current year losses from a power contract with OVEC. This decrease was offset by a corresponding increase in Margins from Off-system Sales below.


A $7 million decrease in Ohio revenues associated with smart grid riders. This decrease was partially offset by a corresponding decrease in various expenses below.
Margins from Off-system Sales increased $6 million primarily due to lower current year losses from a power contract withunfavorable deferrals of OVEC in Ohio whichcosts. This decrease was offset in Retail Margins above as a resultand Other Revenues below.
•A $5 million decrease in Texas primarily due to the retirement of the OVEC PPA rider beginningOklaunion Power Station in January 2017.
September 2020. This decrease was partially offset in Depreciation and Amortization expenses below.
•Transmission Revenues decreased $4 increased $30 million primarily due to the following:
An $11•A $20 million decrease mainlyincrease from interim rate increases driven by increased transmission investment in Texas.
•A $14 million increase due to a prior year one-time credit to transmission customers in Texas as a result of Tax Reform and the 2018 provisions for customer refunds primarily due to Tax Reform.most recent base rate case. This decrease isincrease was offset in Income Tax Expense below.
These increases were 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 $39 million primarily due to the following:
•A $47 million decrease primarily due to securitization revenues 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 Interest Expense.
This decrease was partially offset by:
A $7•An $8 million increase primarily due to third-party LGRR revenue related to the recovery of increased transmission investmentOVEC costs in ERCOT.Ohio. This increase was offset in Retail Margins and Margins from Off-system Sales above.


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


•Other Operation and Maintenance expenses increased $65$9 million primarily due to the following:
•A $44$26 million increase in transmissionrecoverable PJM expense in Ohio. This increase was partially offset in Retail Margins above.
•A $17 million increase due to the prior year revision of the Oklaunion Power Station ARO. This increase was offset in Margins from Off-system Sales above.
•A $9 million increase in PJM expenses thatin Ohio primarily related to the annual formula rate true-up.
•An $8 million increase in distribution maintenance expenses in Ohio related to the annual major storm reserve true-up. This increase was offset in Retail Margins above.
These increases were fully recoveredpartially offset by:
•A $19 million decrease in rate recovery riders/trackers withinTexas due to the Oklaunion Power Station retirement in September 2020 and its sale to a nonaffiliated third-party in October 2020. This decrease was offset in Gross MarginsMargin above.
A $21•An $11 million increasedecrease in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increasedecrease was offset by a corresponding increase in Retail Margins above.
These increases were partially offset by:
•A $9 million decrease in Ohio Energy Efficiency/Peak Demand Reductionenergy efficiency/demand side management expenses that were fully recovered in rate recovery riders/trackers withinOhio. This decrease was partially offset in Retail Margins above.
•A $7 million decrease in factored customer accounts receivable expenses in Ohio primarily due to bad debt expenses and a current year adjustment to allowance for doubtful accounts.
•Depreciation and Amortization expenses increased $16decreased $29 million primarily due to the following:
•A $7$49 million decrease in securitization amortizations in Texas primarily related to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset in Other Revenues above.
These decreases were partially offset by:
•A $9 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
29




•A $6 million increase in recoverable DIR depreciationdepreciable expense in Ohio. This increase was partially offset in Retail Margins above.
•A $5 million increase due to securitization amortizationsin amortization primarily related to Texas securitized transition funding. This increase was offsetcapitalized software in Other Revenues above and in Interest Expense below.Ohio.
•Taxes Other Than Income Taxes increased $11$17 million primarily due to the following:
A $6 million increase inincreased property taxes due todriven by additional investments in transmission and distribution assets and higher tax rates.
•Interest Expense increased $5 million primarily due to higher long-term debt balances.
•Income Tax Expense increased $31 million primarily due to a decrease in amortization of Excess ADIT and an increase in pretax book income. The decrease in amortization of Excess ADIT is partially offset above in Gross Margin.

30




Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020
Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30, 2021
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
Six Months Ended June 30, 2020$255.7 
Changes in Gross Margin:
Retail Margins101.2 
Margins from Off-system Sales(56.1)
Transmission Revenues42.5 
Other Revenues(72.1)
Total Change in Gross Margin15.5 
Changes in Expenses and Other:
Other Operation and Maintenance(6.9)
Depreciation and Amortization70.3 
Taxes Other Than Income Taxes(28.0)
Interest and Investment Income(0.4)
Allowance for Equity Funds Used During Construction(1.7)
Non-Service Cost Components of Net Periodic Benefit Cost(0.2)
Interest Expense(7.9)
Total Change in Expenses and Other25.2 
Income Tax Expense(28.3)
Six Months Ended June 30, 2021$268.1 

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

•Retail Margins increased $101 million primarily due to the following:
•An $88 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 $4$21 million increase from interim rate increases driven by increased transmission investment in Texas.
•A $21 million increase from interim rate increases driven by increased distribution investment in Texas.
•A $19 million increase in state exciseusage in Ohio from the commercial and residential classes of $11 million and $8 million, respectively.
•A $17 million increase in rider revenues in Ohio associated with the DIR. This increase was partially offset in other expense items below.
•A $15 million increase in the LGRR in Ohio. This increase was offset in Margins from Off-system Sales and Other Revenues below.
•A $13 million increase in weather-related usage in Texas primarily due to a 229% increase in heating degree days, partially offset by a 17% decrease in cooling degree days.
•A $10 million increase in revenues associated with a vegetation management rider in Ohio. This increase was partially offset in Other Operation and Maintenance expenses below.
•An $8 million increase due to a PUCO order to refund unused 2018 major storm reserve collections to customers in the prior period. This increase was offset in Other Operation and Maintenance expenses below.


31




These increases were partially offset by:
•A $46 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 $27 million decrease in revenues in Ohio associated with the USF. This decrease was offset in Other Operation and Maintenance expenses below.
•A $19 million decrease due to refunds in Texas of Excess ADIT and excess federal income taxes due tocollected as a result of Tax Reform. This decrease was partially offset in Income Tax Expense below.
•A $6 million decrease in weather-normalized margins in Texas primarily in the industrial and residential classes, partially offset by an increase in metered KWhs.the commercial class.
•Margins from Off-system Sales decreased $56 million primarily due to the following:
•A $29 million decrease in Texas primarily due to the retirement of the Oklaunion Power Station in September 2020. This decrease was partially offset in Depreciation and Amortization expenses below.
•A $27 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 $43 million primarily due to the following:
•A $39 million increase from interim rate increases driven by increased transmission investment in Texas.
•A $14 million increase due to a prior year one-time credit to transmission customers in Texas as a result of Tax Reform and the most recent base rate case. This increase was offset in Income Tax Expense below.
These increases were partially offset by:
•A $9 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 $72 million primarily due to the following:
•A $98 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.
This decrease was partially offset by:
•A $13 million increase in Ohio primarily due to third-party LGRR revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins and Margins from Off-system Sales above.
Allowance for Equity Funds Used During Construction increased $4•A $10 million increase due to increased transmission projectsrefunds in Texas.
Non-Service Cost Components of Net Periodic Benefit Cost decreased $6 million primarily dueTexas to favorable asset returns forcustomers associated with the funded Pension and OPEB plans and by moving to a Medicare Advantage arrangement for post-65 retirees in the Non-UMWA OPEB plan.  Additionally, the decreasemost recent base rate case. This increase was partially due to the implementation of ASU 2017-07offset in 2018, which eliminated AEP’s ability to capitalize a portion of its non-service cost components.
Retail Margins and Transmission Revenues above.

Expenses and Other and Income TaxExpense decreased $35 changed between years as follows:

•Other Operation and Maintenance expenses increased $7 million primarily due to the changefollowing:
•A $78 million increase in recoverable PJM expenses in Ohio. This increase was partially offset in Retail Margins above.
•A $17 million increase due to the prior year revision of the Oklaunion Power Station ARO. This increase was offset in Margins from Off-system Sales above.
•A $10 million increase in recoverable distribution expenses related to vegetation management in Ohio. This increase was offset in Retail Margins above.
•A $9 million increase in PJM expenses in Ohio primarily related to the annual formula rate true-up.
•An $8 million increase in distribution maintenance expenses in Ohio related to the annual major storm reserve true-up. This increase was offset in Retail Margins above.
These increases were partially offset by:
•A $39 million decrease in Texas due to the Oklaunion Power Station retirement in September 2020 and its sale to a nonaffiliated third-party in October 2020. This decrease was offset in Gross Margin above.
•A $30 million decrease in energy efficiency/demand side management expenses in Ohio. This decrease was partially offset in Retail Margins above.
•A $27 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 $14 million decrease in factored customer accounts receivable expenses in Ohio primarily due to bad debt expenses and a current year adjustment to allowance for doubtful accounts.
32




•A $6 million decrease primarily related to distribution related expenses in Texas.
•Depreciation and Amortization expenses decreased $70 million primarily due to the following:
•A $93 million decrease in securitization amortizations in Texas primarily related to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset in Other Revenues above.
These decreases were partially offset by:
•A $13 million increase in depreciation expense due to an increase in the corporate federal incomedepreciable base of transmission and distribution assets.
•A $6 million increase in recoverable DIR depreciable expense in Ohio. This increase was partially offset in Retail Margins above.
•A $6 million increase in amortization primarily related to capitalized software in Ohio.
•Taxes Other Than Income Taxes increased $28 million primarily due to property taxes driven by additional investments in transmission and distribution assets and higher tax rate from 35% in 2017rates.
•Interest Expense increased $8 million primarily due to 21% in 2018 as a result ofhigher long-term debt balances.
•Income Tax Reform andExpense increased $28 million primarily due to a decrease in amortization of Excess ADIT and an increase in pretax book income. The decrease in amortization of Excess ADIT is partially offset above in Gross Margin.
33







AEP TRANSMISSION HOLDCO
Three Months EndedSix Months Ended
June 30,June 30,
AEP Transmission Holdco2021202020212020
 (in millions)
Transmission Revenues$378.2 $249.7 $755.2 $559.9 
Other Operation and Maintenance29.4 25.9 56.6 55.8 
Depreciation and Amortization74.7 61.1 147.4 119.2 
Taxes Other Than Income Taxes61.5 51.8 120.7 103.7 
Operating Income212.6 110.9 430.5 281.2 
Interest and Investment Income0.2 1.5 0.4 2.4 
Allowance for Equity Funds Used During Construction16.5 18.4 33.2 34.6 
Non-Service Cost Components of Net Periodic Benefit Cost0.6 0.5 1.1 1.0 
Interest Expense(35.5)(34.2)(70.8)(65.0)
Income Before Income Tax Expense and Equity Earnings194.4 97.1 394.4 254.2 
Income Tax Expense43.4 24.7 89.2 63.1 
Equity Earnings of Unconsolidated Subsidiary18.6 19.8 37.6 42.7 
Net Income169.6 92.2 342.8 233.8 
Net Income Attributable to Noncontrolling Interests0.9 0.7 2.1 1.7 
Earnings Attributable to AEP Common Shareholders$168.7 $91.5 $340.7 $232.1 
  Three Months Ended March 31,
AEP Transmission Holdco 2018 2017
  (in millions)
Transmission Revenues $205.5
 $156.1
Other Operation and Maintenance 21.9
 14.1
Depreciation and Amortization 31.8
 24.6
Taxes Other Than Income Taxes 32.7
 28.0
Operating Income 119.1
 89.4
Interest and Investment Income 0.3
 0.2
Allowance for Equity Funds Used During Construction 15.3
 10.8
Non-Service Cost Components of Net Periodic Benefit Cost 0.7
 0.1
Interest Expense (21.1) (17.3)
Income Before Income Tax Expense and Equity Earnings 114.3
 83.2
Income Tax Expense 27.5
 36.4
Equity Earnings of Unconsolidated Subsidiaries 18.0
 26.0
Net Income 104.8
 72.8
Net Income Attributable to Noncontrolling Interests 0.8
 1.0
Earnings Attributable to AEP Common Shareholders $104.0
 $71.8


Summary of Investment in Transmission Assets for AEP Transmission Holdco
June 30,
20212020
(in millions)
Plant in Service$11,065.2 $9,333.7 
Construction Work in Progress1,486.3 1,660.5 
Accumulated Depreciation and Amortization703.1 508.2 
Total Transmission Property, Net$11,848.4 $10,486.0 
34




  As of March 31,
  2018 2017
  (in millions)
Plant in Service $5,912.8
 $4,476.5
Construction Work in Progress 1,533.7
 1,188.8
Accumulated Depreciation and Amortization 200.0
 120.6
Total Transmission Property, Net $7,246.5
 $5,544.7


FirstSecond Quarter of 20182021 Compared to FirstSecond Quarter of 20172020
 
Reconciliation of FirstSecond Quarter of 20172020 to FirstSecond Quarter of 20182021
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
Second Quarter of 2020$91.5 
Changes in Transmission Revenues:
Transmission Revenues128.5 
Total Change in Transmission Revenues128.5 
Changes in Expenses and Other:
Other Operation and Maintenance(3.5)
Depreciation and Amortization(13.6)
Taxes Other Than Income Taxes(9.7)
Interest Income(1.3)
Allowance for Equity Funds Used During Construction(1.9)
Non-Service Cost Components of Net Periodic Pension Cost0.1 
Interest Expense(1.3)
Total Change in Expenses and Other(31.2)
Income Tax Expense(18.7)
Equity Earnings of Unconsolidated Subsidiary(1.2)
Net Income Attributable to Noncontrolling Interests(0.2)
Second Quarter of 2021$168.7 
First Quarter of 2017 $71.8
   
Changes in Transmission Revenues:  
Transmission Revenues 49.4
Total Change in Transmission Revenues 49.4
   
Changes in Expenses and Other:  
Other Operation and Maintenance (7.8)
Depreciation and Amortization (7.2)
Taxes Other Than Income Taxes (4.7)
Interest and Investment Income 0.1
Allowance for Equity Funds Used During Construction 4.5
Non-Service Cost Components of Net Periodic Pension Cost 0.6
Interest Expense (3.8)
Total Change in Expenses and Other (18.3)
   
Income Tax Expense 8.9
Equity Earnings of Unconsolidated Subsidiaries (8.0)
Net Income Attributable to Noncontrolling Interests 0.2
   
First Quarter of 2018 $104.0


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


•Transmission Revenuesincreased $49$129 million primarily due to the following:
Formula rate increases of•A $68 million driven byincrease due to continued investment in transmission assets.
This•A $45 million increase was partially offset by:
A $19 million decrease due toas a result of the 2018 provisions for customer refunds primarily related to Tax Reform. This decreaseaffiliated annual transmission formula rate true-up which is offset in Income Tax Expense below.Other Operation and Maintenance expense across the other Registrant Subsidiaries.

•A $16 million increase as a result of the non-affiliated annual transmission formula rate true-up.
Expenses and Other and Income Tax Expense and Equity Earnings of Unconsolidated Subsidiaries changed between years as follows:


•Other Operation and Maintenance expenses increased $8$4 million primarily due to increased transmission investment.
vegetation management expenses.
•Depreciation and Amortization expenses increased $7$14 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxes increased $5$10 million primarily due to higher property taxes as a result of increased transmission investment.
•Income Tax Expense increased $19 million primarily due to an increase in pretax book income.
35




Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020
Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30, 2021
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
Six Months Ended June 30, 2020$232.1 
Changes in Transmission Revenues:
Transmission Revenues195.3 
Total Change in Transmission Revenues195.3 
Changes in Expenses and Other:
Other Operation and Maintenance(0.8)
Depreciation and Amortization(28.2)
Taxes Other Than Income Taxes(17.0)
Interest Income(2.0)
Allowance for Equity Funds Used During Construction(1.4)
Non-Service Cost Components of Net Periodic Pension Cost0.1 
Interest Expense(5.8)
Total Change in Expenses and Other(55.1)
Income Tax Expense(26.1)
Equity Earnings of Unconsolidated Subsidiary(5.1)
Net Income Attributable to Noncontrolling Interests(0.4)
Six Months Ended June 30, 2021$340.7 

The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and nonaffiliates, were as follows:
•Transmission Revenues increased $195 million primarily due to the following:
•A $134 million increase due to continued investment in transmission assets.
•A $45 million increase as a result of the affiliated annual transmission formula rate true-up which is offset in Other Operation and Maintenance expense across the other Registrant Subsidiaries.
•A $16 million increase as a result of the non-affiliated annual transmission formula rate true-up.
Expenses and Other, Income Tax Expense and Equity Funds Used During ConstructionEarnings of Unconsolidated Subsidiary changed between years as follows:
•Depreciation and Amortization expenses increased $28 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxes increased $17 million primarily due to higher property taxes as a result of increased transmission investment.
•Interest Expense increased $6 million primarily due to higher long-term debt balances.
•Income Tax Expense increased $26 million primarily due to an increase in pretax book income.
•Equity Earnings of Unconsolidated Subsidiary decreased $5 million primarily due to increased transmission investment resulting in a higher CWIP balance.
Interest Expense increased $4 million primarily due to higher outstanding long-term debt balances.
Income Tax Expense decreased $9 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, partially offset by an increase inlower pretax book income.
Equity Earnings of Unconsolidated Subsidiaries decreased $8 million primarily due to lowerequity earnings at ETT resulting from decreased revenues driven by Tax ReformPATH-WV and by an ETT rate reduction that went into effect in March 2017, increased operating expenses, decreased AFUDC and increased interest expense.ETT.
36






GENERATION & MARKETING
Three Months EndedSix Months Ended
June 30,June 30,
Generation & Marketing2021202020212020
 (in millions)
Revenues$436.6 $376.9 $1,070.8 $815.5 
Fuel, Purchased Electricity and Other358.1 298.5 924.0 658.8 
Gross Margin78.5 78.4 146.8 156.7 
Other Operation and Maintenance32.4 16.5 60.6 57.9 
Depreciation and Amortization20.0 17.9 38.6 35.6 
Taxes Other Than Income Taxes2.9 3.7 5.5 7.1 
Operating Income23.2 40.3 42.1 56.1 
Interest and Investment Income0.6 1.2 1.1 2.2 
Non-Service Cost Components of Net Periodic Benefit Cost3.9 3.8 7.7 7.7 
Interest Expense(3.8)(8.2)(7.1)(16.7)
Income Before Income Tax Benefit and Equity Earnings (Loss)23.9 37.1 43.8 49.3 
Income Tax Benefit(24.2)(21.0)(39.3)(33.4)
Equity Earnings (Loss) of Unconsolidated Subsidiaries(1.6)0.4 1.6 6.3 
Net Income46.5 58.5 84.7 89.0 
Net Loss Attributable to Noncontrolling Interests(5.9)(7.4)(4.3)(5.3)
Earnings Attributable to AEP Common Shareholders$52.4 $65.9 $89.0 $94.3 
  Three Months Ended March 31,
Generation & Marketing 2018 2017
  (in millions)
Revenues $505.1
 $591.4
Fuel, Purchased Electricity and Other 408.8
 405.2
Gross Margin 96.3
 186.2
Other Operation and Maintenance 67.6
 99.8
Gain on Sale of Merchant Generation Assets —
 (226.5)
Depreciation and Amortization 6.9
 5.7
Taxes Other Than Income Taxes 3.2
 2.0
Operating Income 18.6
 305.2
Interest and Investment Income 2.5
 2.2
Non-Service Cost Components of Net Periodic Benefit Cost 3.9
 2.3
Interest Expense (3.9) (6.5)
Income Before Income Tax Expense 21.1
 303.2
Income Tax Expense 3.0
 117.0
Net Income 18.1
 186.2
Net Loss Attributable to Noncontrolling Interests (0.1) —
Earnings Attributable to AEP Common Shareholders $18.2
 $186.2


Summary of MWhs Generated for Generation & Marketing
Three Months EndedSix Months Ended
June 30,June 30,
2021202020212020
 (in millions of MWhs)
Fuel Type:    
Coal1 1 2 2 
Renewables1 1 2 2 
Total MWhs2 2 4 4 
37




 Three Months Ended March 31,
 2018 2017
 (in millions of MWhs)
Fuel Type: 
  
Coal4
 6
Natural Gas—
 2
Total MWhs4
 8



FirstSecond Quarter of 20182021 Compared to FirstSecond Quarter of 20172020
Reconciliation of Second Quarter of 2020 to Second Quarter of 2021
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
Second Quarter of 2020$65.9 
Changes in Gross Margin:
Merchant Generation5.1 
Renewable Generation3.1 
Retail, Trading and Marketing(8.1)
Total Change in Gross Margin0.1 
Changes in Expenses and Other:
Other Operation and Maintenance(15.9)
Depreciation and Amortization(2.1)
Taxes Other Than Income Taxes0.8 
Interest and Investment Income(0.6)
Non-Service Cost Components of Net Periodic Benefit Cost0.1 
Interest Expense4.4 
Total Change in Expenses and Other(13.3)
Income Tax Benefit3.2 
Equity Earnings of Unconsolidated Subsidiaries(2.0)
Net Loss Attributable to Noncontrolling Interests(1.5)
Second Quarter of 2021$52.4 

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

•Merchant Generation increased $5 million primarily due to higher market prices in PJM which drove increased generation at Cardinal Plant.
•Renewable Generation increased $3 million primarily due to higher solar and wind production.
•Retail, Trading and Marketing decreased $8 million due to lower wholesale marketing activity.

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

•Other Operation and Maintenance expenses increased $16 million primarily due to the following:
•A $17 million increase related to the Oklaunion PPA with AEP Texas primarily due to an ARO revision in 2020.
•An $8 million increase due to gains recorded in 2020 on the sale of land.
These increases were partially offset by:
•A $9 million decrease in expenses related to the retirements of Conesville Plant Unit 4 and Oklaunion Plant in 2020.
•Interest Expense decreased $4 million due to lower borrowing costs in 2021.
•Income Tax Benefit increased $3 million due to an increase in PTCs.

38
Reconciliation of First Quarter of 2017 to First Quarter of 2018
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
   
First Quarter of 2017 $186.2
   
Changes in Gross Margin:  
Generation (53.6)
Retail, Trading and Marketing (37.7)
Other 1.4
Total Change in Gross Margin (89.9)
   
Changes in Expenses and Other:  
Other Operation and Maintenance 32.2
Gain on Sale of Merchant Generation Assets (226.5)
Depreciation and Amortization (1.2)
Taxes Other Than Income Taxes (1.2)
Interest and Investment Income 0.3
Non-Service Cost Components of Net Periodic Benefit Cost 1.6
Interest Expense 2.6
Total Change in Expenses and Other (192.2)
   
Income Tax Expense 114.0
Net Loss Attributable to Noncontrolling Interests 0.1
   
First Quarter of 2018 $18.2





Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020
Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30, 2021
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
Six Months Ended June 30, 2020$94.3 
Changes in Gross Margin:
Merchant Generation9.1 
Renewable Generation8.4 
Retail, Trading and Marketing(27.4)
Total Change in Gross Margin(9.9)
Changes in Expenses and Other:
Other Operation and Maintenance(2.7)
Depreciation and Amortization(3.0)
Taxes Other Than Income Taxes1.6 
Interest and Investment Income(1.1)
Interest Expense9.6 
Total Change in Expenses and Other4.4 
Income Tax Benefit5.9 
Equity Earnings of Unconsolidated Subsidiaries(4.7)
Net Loss Attributable to Noncontrolling Interests(1.0)
Six Months Ended June 30, 2021$89.0 

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 $9 million primarily due to higher market prices in PJM which drove increased generation at Cardinal Plant.
•Renewable Generation increased $8 million primarily due to increased solar and wind production in the ERCOT region and higher market revenues from wind assets in the ERCOT region.
•Retail, Trading and Marketing decreased $54$27 million due to lower trading and retail margins due to unprecedented cold temperatures and record ERCOT market prices in February 2021.

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

•Other Operation and Maintenance expenses increased $3 million primarily due to the reductionfollowing:
•A $17 million increase related to the Oklaunion PPA with AEP Texas primarily due to an ARO revision in 2020.
This increase was partially offset by:
•A $9 million decrease due to the retirement of revenues associated with the sale of certain merchant generation assetsConesville Plant Unit 4 in 2017.
2020.
•A $4 million decrease due to a planned outage at Cardinal Plant in 2020.
Retail, Trading•Depreciation and Marketing Amortization expenses increased $3 million due to a higher depreciable base from increased investments in renewable energy sources.
•Interest Expense decreased $38$10 million due to lower borrowing costs in 2021.
•Income Tax Benefit increased $6 million primarily due to reduced wholesale trading and marketing revenues, mark-to-market hedge losses and lower retail margins.
an increase in PTCs.

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

Other Operation and Maintenance expenses •Equity Earnings of Unconsolidated Subsidiaries decreased $32$5 million primarily due to the following:
•A $21 million decrease in expenseslower revenues due to the sale of certain merchant generation assets in 2017.
•An $11 million decrease in expenses due to an impairment of certain merchant generation assets in 2017.lower wind production from jointly owned assets.
Gain on Sale of Merchant Generation Assets decreased $227 million due to the sale of certain merchant generation assets in 2017.
39
Income Tax Expense decreased $114 million primarily due to a reduction in pretax book income due to the gain on sale of certain merchant generation assets in 2017 and the change in corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform.






CORPORATE AND OTHER


FirstSecond Quarter of 20182021 Compared to FirstSecond Quarter of 20172020


Earnings Attributable to AEP Common Shareholders from Corporate and Other decreasedincreased from a loss of $4$32 million in 20172020 to a loss of $24$25 million in 2018. The2021 primarily due to:

•A $21 million gain from an investment in ChargePoint, of which $16 million is unrealized.
•A $14 million increase in equity earnings.
•A $4 million decrease in interest expense.

These items were partially offset by:

•A $19 million increase in general corporate expenses.
•A $14 million decrease in interest income due to a lower return on investments held by EIS and lower interest income from affiliates.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020

Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $67 million in 20182020 to a loss of $43 million in 2021 primarily due to:

•A $38 million gain from an investment in ChargePoint, of which $33 million is unrealized.
•A $20 million increase in equity earnings.
•A $16 million decrease in interest expense.

These items were partially offset by:

•A $28 million increase in general corporate expenses.
•A $15 million decrease in interest income primarily due to a $20 million impairment of an equity investment and related assets and a $12lower interest income from affiliates.
•A $7 million increase in interest expenseIncome Tax Expense due to the recognition of a $19 million remeasurement of state deferred taxes as a result of newly enacted West Virginia state legislation in 2021 partially offset by a $9 million decrease in general corporate expenses.consolidating tax adjustments.


AEP SYSTEM INCOME TAXES


FirstSecond Quarter of 20182021 Compared to FirstSecond Quarter of 20172020


Income Tax Expense decreased $241increased $49 million primarily due to a decrease in amortization of Excess ADIT, an increase in pretax book income and the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018remeasurement of state deferred taxes as a result of newly enacted West Virginia and Oklahoma state legislation in 2021.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020

Income Tax Reform, the amortization of excess accumulated deferredExpense increased $57 million primarily due to an increase in pretax book income, taxes associated with certain depreciable property in 2018 and a decrease in pretax book income.amortization of Excess ADIT and the remeasurement of state deferred taxes as a result of newly enacted West Virginia and Oklahoma state legislation in 2021, partially offset by an increase in PTCs.






40




FINANCIAL CONDITION


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


LIQUIDITY AND CAPITAL RESOURCES


Debt and Equity Capitalization
 June 30, 2021December 31, 2020
 (dollars in millions)
Long-term Debt, including amounts due within one year$33,117.8 57.2 %$31,072.5 57.2 %
Short-term Debt3,128.0 5.4 2,479.3 4.6 
Total Debt36,245.8 62.6 33,551.8 61.8 
AEP Common Equity21,378.7 37.0 20,550.9 37.8 
Noncontrolling Interests251.2 0.4 223.6 0.4 
Total Debt and Equity Capitalization$57,875.7 100.0 %$54,326.3 100.0 %
 March 31, 2018 December 31, 2017
 (dollars in millions)
Long-term Debt, including amounts due within one year$21,461.0
 50.3% $21,173.3
 51.5%
Short-term Debt2,658.8
 6.2
 1,638.6
 4.0
Total Debt24,119.8
 56.5
 22,811.9
 55.5
AEP Common Equity18,483.3
 43.4
 18,287.0
 44.4
Noncontrolling Interests28.3
 0.1
 26.6
 0.1
Total Debt and Equity Capitalization$42,631.4
 100.0% $41,125.5
 100.0%


AEP’s ratio of debt-to-total capital increased from 55.5%61.8% as of December 31, 20172020 to 56.5%62.6% as of March 31, 2018June 30, 2021 primarily due to an increase in short-term debt due to increasing construction expenditures forhelp address the cash flow implications resulting from the February 2021 severe winter weather event in addition to supporting distribution, transmission and transmission investments.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, 2018,June 30, 2021, AEP had a $3$5 billion of revolving credit facility commitmentfacilities to support its operations.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, sale-leaseback or 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

Commercial Paper Credit Facilities


AEP manages liquidity by maintaining adequate external financing commitments.  As of March 31, 2018,June 30, 2021, available liquidity was approximately $1.3$3.3 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 Equivalents312.7 
Total Liquidity Sources5,812.7 
Less:AEP Commercial Paper Outstanding2,049.8 
364-Day Term Loan500.0 
Net Available Liquidity$3,262.9 
  Amount Maturity
  (in millions)  
Commercial Paper Backup: 
  
 Revolving Credit Facility$3,000.0
 June 2021
Cash and Cash Equivalents183.4
  
Total Liquidity Sources3,183.4
  
Less:AEP Commercial Paper Outstanding1,886.2
  
     
Net Available Liquidity$1,297.2
  


AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries.  The program is used to fund bothfunds a Utility Money Pool, which funds theAEP’s utility subsidiaries, andsubsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries.  In addition, the program also funds, as direct borrowers,subsidiaries; and the short-term debt requirements of other subsidiaries that are not participantsparticipating in either money pool for regulatory or operational reasons.reasons, as direct borrowers.  The maximum amount of commercial paper outstanding during the first threesix months of 20182021 was $2.2$2.5 billion.  The weighted-average interest rate for AEP’s commercial paper during 20182021 was 2.07%0.25%.

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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 foursix uncommitted facilities totaling $305 million. In March 2018, one of the uncommitted credit facilities was reduced by $40$425 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of March 31, 2018June 30, 2021 was $81$187 millionwith maturities ranging from May 2018July 2021 to March 2019.July 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. In June 2019.2021, AEP Credit entered into a waiver for both APCo and SWEPCo to waive certain triggers through August 2021 due to the continuing impact of the COVID-19 pandemic. As of June 30, 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. The receivables that are ineligible under the receivables securitization agreement are financed with short-term debt at AEP Credit.


Debt Covenants and Borrowing Limitations


AEP’s credit agreements contain certain covenants and require it to maintain a percentage of debt to totaldebt-to-total capitalization at a level that does not exceed 67.5%.  The method for calculating outstanding debt and capitalization is contractually definedcontractually-defined in AEP’s credit agreements.  Debt as defined in the revolving credit agreementsagreement excludes securitization bonds and debt of AEP Credit. As of March 31, 2018,June 30, 2021,this contractually-defined percentage was 54.8%59.7%. NonperformanceNon-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 tradednon-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 tradednon-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 June 30, 2021, approximately $803 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.
42





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 $0.62$0.74 per share in April 2018.July 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.



43




CASH FLOW


AEP relies primarily on cash flows from operations, debt issuances and its existing cash and cash equivalents to fund its liquidity and investing activities. AEP’s investing and capital requirements are primarily capital expenditures, repaying of long-term debt and paying dividends to shareholders. AEP uses short-term debt, including commercial paper, as a bridge to long-term debt financing. The levels of borrowing may vary significantly due to the timing of long-term debt financings and the impact of fluctuations in cash flows.

Six Months Ended 
June 30,
 20212020
 (in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period$438.3 $432.6 
Net Cash Flows from Operating Activities1,043.9 1,746.2 
Net Cash Flows Used for Investing Activities(3,229.8)(3,247.6)
Net Cash Flows from Financing Activities2,107.3 1,573.5 
Net Increase (Decrease) in Cash and Cash Equivalents(78.6)72.1 
Cash, Cash Equivalents and Restricted Cash at End of Period$359.7 $504.7 
 Three Months Ended 
 March 31,
 2018 2017
 (in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period$412.6
 $403.5
Net Cash Flows from Operating Activities802.2
 806.8
Net Cash Flows from (Used for) Investing Activities(1,927.8) 776.2
Net Cash Flows from (Used for) Financing Activities1,029.5
 (1,687.1)
Net Decrease in Cash, Cash Equivalents and Restricted Cash(96.1) (104.1)
Cash, Cash Equivalents and Restricted Cash at End of Period$316.5
 $299.4




Operating Activities
Six Months Ended 
June 30,
20212020
(in millions)
Net Income$1,152.6 $1,013.8 
Non-Cash Adjustments to Net Income (a)1,530.6 1,459.1 
Mark-to-Market of Risk Management Contracts26.1 13.7 
Property Taxes167.3 173.6 
Deferred Fuel Over/Under-Recovery, Net(1,218.2)76.0 
Change in Other Noncurrent Assets(291.9)(143.9)
Change in Other Noncurrent Liabilities163.5 (50.0)
Change in Certain Components of Working Capital(486.1)(796.1)
Net Cash Flows from Operating Activities$1,043.9 $1,746.2 
 Three Months Ended 
 March 31,
 2018 2017
 (in millions)
Net Income$456.7
 $594.2
Non-Cash Adjustments to Net Income (a)623.7
 405.5
Mark-to-Market of Risk Management Contracts(0.7) 6.0
Property Taxes(63.7) (44.4)
Deferred Fuel Over/Under Recovery, Net(61.2) 19.3
Recovery of Ohio Capacity Costs, Net18.0
 30.2
Provision for Refund - Global Settlement, Net(5.4) —
Change in Other Noncurrent Assets(59.8) (99.1)
Change in Other Noncurrent Liabilities133.3
 45.0
Change in Certain Components of Working Capital(238.7) (149.9)
Net Cash Flows from Operating Activities$802.2
 $806.8


(a)Non-Cash Adjustments to Net Income includes Depreciation and Amortization, Deferred Income Taxes, Allowance for Equity Funds Used During Construction, Amortization of Nuclear Fuel and Gain on Sale of Merchant Generation Assets.
(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 Operating Activities decreased by $5$702 million primarily due to the following:
An $89•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 $1.1 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 $138 million decrease in cash from Changes in Certain Components of Working Capital. This decrease is primarily due to changesincremental 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. KPCo intends to seek recovery of these incremental storm restoration costs in accrued federal taxestheir next base rate case while APCO and timing of receivables and payables, partially offset by lower employee-related payments.
An $81 million decreaseSWEPCo are expected to seek recovery in cash from Deferred Fuel Over/Under Recovery, Net, primarily due to fluctuations of fuel and purchase power costs at APCo.separate filings. See Note 4 - Rate Matters for additional information.
These decreases in cash were partially offset by:
An $88
44




•A $310 million increase in cash from the Change in Certain Components of Working Capital. The increase is primarily due to timing of accounts receivables and payables and a decrease in fuel, material and supplies balances primarily driven by changes in power prices.
•A $214million increase in cash from Change in Other Noncurrent LiabilitiesLiabilities. The increase is primarily due to increased Accumulated Provisions for Rate Refunds as a result of Tax Reform.changes in regulatory liabilities driven by timing differences between collections from and refunds to customers under rate rider mechanisms.
An $81•A $210 million increase in cash from Net Income, after non-cash adjustments. See Results of Operations for additional information.further detail.



Investing Activities
Six Months Ended 
June 30,
 20212020
 (in millions)
Construction Expenditures$(2,784.8)$(3,244.9)
Acquisitions of Nuclear Fuel(63.0)(37.7)
Acquisition of the North Central Wind Energy Facilities(270.0)— 
Acquisition of the Dry Lake Solar Project(114.3)— 
Other2.3 35.0 
Net Cash Flows Used for Investing Activities$(3,229.8)$(3,247.6)
 Three Months Ended 
 March 31,
 2018 2017
 (in millions)
Construction Expenditures$(1,905.8) $(1,365.8)
Acquisitions of Nuclear Fuel(23.8) (3.7)
Proceeds from Sale of Merchant Generation Assets—
 2,159.6
Other1.8
 (13.9)
Net Cash Flows from (Used for) Investing Activities$(1,927.8) $776.2

Net Cash Flows from (Used for)Used for Investing Activities decreased by $2.7 billion$18 million primarily due to the following:
•A $2.2 billion decrease in cash due to the sale of certain merchant generation assets in 2017. See Note 6 - Dispositions and Impairments for additional information.
A $540$460 million decrease in cash due to increased construction expenditures, primarily due to increasesdecreases in Transmission and Distribution Utilities of $343$194 million, Vertically Integrated Utilities of $173 million and AEP Transmission Holdco of $168$90 million.
This decrease in the use of cash was partially offset by:

•A $384 million increase due to the acquisition of the North Central Wind Energy Facilities and the Dry Lake Solar Project. See Note 6 - Acquisitions and Dispositions for additional information.


Financing Activities
Six Months Ended 
June 30,
 20212020
 (in millions)
Issuance of Common Stock$256.9 $111.0 
Issuance/Retirement of Debt, Net2,705.7 2,236.4 
Dividends Paid on Common Stock(746.5)(704.6)
Other(108.8)(69.3)
Net Cash Flows from Financing Activities$2,107.3 $1,573.5 
 Three Months Ended 
 March 31,
 2018 2017
 (in millions)
Issuance of Common Stock, Net$32.2
 $—
Issuance/Retirement of Debt, Net1,317.2
 (1,336.4)
Dividends Paid on Common Stock(306.1) (291.4)
Other(13.8) (59.3)
Net Cash Flows from (Used for) Financing Activities$1,029.5
 $(1,687.1)

Net Cash Flows from (Used for) Financing Activities increased by $2.7 billion$534 million primarily due to the following:
•A $1.2 billion increase in cash from short-term debt primarily due to increased borrowings of commercial paper. See Note 12 - Financing Activities for additional information.
A $758$624 million increase in cash due to increased issuances of long-term debt. See Note 12 - Financing Activities for additional information.
•A $698$410 million increase in cashshort-term debt primarily due to decreasedincreased draws on commercial paper. See Note 12 - Financing Activities for additional information.
•A $146 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.
These increases in cash were partially offset by:
45




•A $565 million increase in retirements of long-term debt. See Note 12 - Financing Activities for additional information.

A $32 million increaseSee “Long-term Debt Subsequent Events” section of Note 12 for Long-term debt and other securities issued, retired and principal payments made after June 30, 2021 through July 22, 2021, the date that the second quarter 10-Q was issued.

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 dueflows from operations and financing activities.  Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to increased proceeds from issuances of common stock.
These increases in cash were partially offset by:
A $15 million decrease due to increased common stock dividend payments primarily due to increased dividends per share from 2017 to 2018.

In April 2018, AEP Texas retired $30 million of 5.89% Senior Unsecured Notes due in 2018.

In April 2018, I&M retired $2 million of Notes Payable related to DCC Fuel.

OFF-BALANCE SHEET ARRANGEMENTS

AEP’s current guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements that AEP enters in the normal course of business.  The following identifies significant off-balance sheet arrangements:
 March 31,
2018		 December 31,
2017
 (in millions)
Rockport Plant, Unit 2 Future Minimum Lease Payments$738.4
 $738.4
Railcars Maximum Potential Loss from Lease Agreement15.4
 17.9

fund these expenditures until long-term funding is arranged. For complete information on each of these off-balance sheet arrangements,forecasted capital expenditures, see the “Off-balance Sheet Arrangements”“Budgeted Capital Expenditures” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 20172020 Annual Report.


CONTRACTUAL OBLIGATION INFORMATION


A summary of contractual obligations is included in the 20172020 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.


CYBER SECURITY

The electric utility industry is an identified critical infrastructure function with mandatory cyber security requirements under the authority of FERC. The North American Electric Reliability Corporation (NERC), which FERC certified as the nation’s Electric Reliability Organization, developed mandatory critical infrastructure protection cyber security reliability standards. AEP began participating in the NERC grid security and emergency response exercises, GridEx,


in 2013 and continues to participate in the bi-yearly exercises. These efforts, led by NERC, test and further develop the coordination, threat sharing and interaction between utilities and various government agencies relative to potential cyber and physical threats against the nation’s electric grid. In 2014, the U.S. Department of Energy published an Energy Sector Cyber Security Framework Implementation Guide for utilities to use in adopting and implementing the National Institute of Standards and Technology framework. AEP continues to be actively engaged in the framework process. In addition to these enterprise-wide initiatives, the operations of AEP’s electric utility subsidiaries are subject to extensive and rigorous mandatory cyber security requirements that are developed and enforced by NERC to protect grid security and reliability.

Critical cyber assets, such as data centers, power plants, transmission operations centers and business networks are protected using multiple layers of cyber security and authentication. Cyber hackers have been successful in breaching a number of very secure facilities, including federal agencies, banks and retailers. As these events become known and develop, AEP continually assesses its cyber security tools and processes to determine where to strengthen its defenses.

AEP has undertaken a variety of actions to monitor and address cyber-related risks. Cyber security and the effectiveness of AEP’s cyber security processes are discussed at Board and Audit Committee meetings. AEP’s strategy for managing cyber-related risks is integrated within its enterprise risk management processes.

AEP’s Chief Security Officer (CSO) leads the cyber security and physical security teams and is responsible for the design, implementation, and execution of AEP’s security risk management strategy, including cyber security. AEP operates a Cyber Security Intelligence and Response Center (cyber security team) responsible for monitoring the AEP System for cyber threats. Among other things, the CSO and the cyber security team actively monitor best practices, perform penetration testing, lead response exercises and internal campaigns, and provide training and communication across the organization.

The cyber security team constantly scans the AEP System for risks and threats. It also continually reviews its business continuity plan to develop an effective recovery strategy that seeks to decrease response times, limit financial impacts and maintain customer confidence during any business interruption. The cyber security team works closely with a broad range of departments, including legal, regulatory, corporate communications and audit services and information technology.

The cyber security team collaborates with partners from both industry and government, and routinely participates in industry-wide programs that exchange knowledge of threats with utility peers, industry and federal agencies. AEP is a member of a number of industry specific threat and information sharing communities including the Department of Homeland Security and the Electricity Information Sharing and Analysis Center.

AEP has partnered in the past with a major defense contractor with significant cyber security experience and technical capabilities developed through their work with the U.S. Department of Defense. AEP continues to work with a nonaffiliated entity to conduct several discussions each year about recognizing and investigating cyber vulnerabilities.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING PRONOUNCEMENTSSTANDARDS


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 20172020 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 pronouncements.standards.


ACCOUNTING PRONOUNCEMENTSSTANDARDS


See Note 2 - New Accounting PronouncementsStandards for information related to accounting pronouncements adopted in 2018 and pronouncements effective instandards. There are no new standards expected to have a material impact to the future.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. In addition, this segment is exposed to foreign currency exchange risk from occasionally procuring various services and materials used in its energy business from foreign suppliers. 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.



46




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 major power producer and through transactions in wholesale electricity, natural gas and marketing contracts.


Management employs risk management contracts including physical forward and financial forward purchase-and-sale contracts.  Management engages in risk management of power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business.  As a result, AEP is subject to price risk.  The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors.  AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the 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, Chief Operating Officer, Executive Vice
President of Generation, Senior Vice President of Commercial OperationsGrid 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 continue to be monitored, and while markets have shown improvement, credit risks remain as counterparties encounter business and supply chain disruptions.


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.
47





The following table summarizes the reasons for changes in total MTM value as compared to December 31, 2017:2020:
MTM Risk Management Contract Net Assets (Liabilities)
Six Months Ended June 30, 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(20.7)(4.6)(6.8)(32.1)
Fair Value of New Contracts at Inception When Entered During the Period (a)— — 0.4 0.4 
Changes in Fair Value Due to Market Fluctuations During the Period (b)— — 30.0 30.0 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)61.7 10.6 — 72.3 
Total MTM Risk Management Contract Net Assets (Liabilities) as of June 30, 2021$82.2 $(103.5)$191.7 170.4 
Commodity Cash Flow Hedge Contracts
 139.7 
Fair Value Hedge Contracts  (25.2)
Collateral Deposits  (93.0)
Total MTM Derivative Contract Net Assets as of June 30, 2021  $191.9 
MTM Risk Management Contract Net Assets (Liabilities)
Three Months Ended March 31, 2018
        
 
Vertically
Integrated
Utilities
 
Transmission
and
Distribution
Utilities
 
Generation
&
Marketing
 Total
 (in millions)
Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2017$42.1
 $(131.3) $163.9
 $74.7
Gain from Contracts Realized/Settled During the Period and Entered in a Prior Period(30.5) (1.1) (9.2) (40.8)
Fair Value of New Contracts at Inception When Entered During the Period (a)—
 —
 6.1
 6.1
Changes in Fair Value Due to Market Fluctuations During the Period (b)—
 —
 (22.4) (22.4)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)5.8
 34.8
 —
 40.6
Total MTM Risk Management Contract Net Assets (Liabilities) as of March 31, 2018$17.4
 $(97.6) $138.4
 58.2
Commodity Cash Flow Hedge Contracts
   
  
 (33.4)
Fair Value Hedge Contracts   
  
 (20.6)
Collateral Deposits   
  
 16.8
Total MTM Derivative Contract Net Assets as of March 31, 2018   
  
 $21.0


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

(b)Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(c)Relates to the net gains (losses) of those contracts that are not reflected on the statements of income.  These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable.

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 Moody’s Investors Service Inc., S&P Global Inc.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, 2018,June 30, 2021, credit exposure net of collateral to sub investment grade counterparties was approximately 7%3.1%, 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).
48




As of March 31, 2018,June 30, 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$397.5 $0.1 $397.4 2 $156.5 
Split Rating0.2 — 0.2 1 0.2 
No External Ratings:    
Internal Investment Grade98.4 — 98.4 3 72.9 
Internal Noninvestment Grade17.0 1.4 15.6 2 9.4 
Total as of June 30, 2021$513.1 $1.5 $511.6 


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.
Counterparty Credit Quality 
Exposure
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 $502.5
 $—
 $502.5
 3
 $273.6
Split Rating 3.5
 —
 3.5
 1
 3.5
Noninvestment Grade 0.8
 0.8
 —
 —
 —
No External Ratings:  
  
 

  
  
Internal Investment Grade 114.7
 —
 114.7
 3
 72.3
Internal Noninvestment Grade 57.3
 10.5
 46.8
 2
 30.6
Total as of March 31, 2018 $678.8
 $11.3
 $667.5
 

 



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, 2018,June 30, 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 Ended Twelve Months Ended
March 31, 2018 December 31, 2017
Six Months EndedSix Months EndedTwelve Months Ended
June 30, 2021June 30, 2021December 31, 2020
EndEnd High Average Low End High Average LowEndHighAverageLowEndHighAverageLow
(in millions)(in millions) (in millions)(in millions)(in millions)
$0.2
 $1.8
 $0.4
 $0.1
 $0.2
 $0.5
 $0.2
 $0.1
0.2 $3.6 $0.2 $0.1 $0.1 $0.3 $0.1 $— 
VaR Model
Non-Trading Portfolio
Six Months EndedTwelve Months Ended
June 30, 2021December 31, 2020
EndHighAverageLowEndHighAverageLow
(in millions)(in millions)
$1.8 $3.7 $1.7 $0.7 $2.2 $2.9 $1.0 $0.1 

49
Three Months Ended Twelve Months Ended
March 31, 2018 December 31, 2017
End High Average Low End High Average Low
(in millions) (in millions)
$1.4
 $6.9
 $2.8
 $1.0
 $4.1
 $6.5
 $1.0
 $0.3





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-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 threesix months ended March 31, 2018June 30, 2021 and 2017,2020, a 100 basis point change in the benchmark rate on AEP’s variable rate debt would impact pre-taxpretax interest expense annually by $25$38 million and $35$17 million, respectively.

50







AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended March 31, 2018June 30, 2021 and 20172020
(in millions, except per-share and share amounts)
(Unaudited)
Three Months EndedSix Months Ended
June 30,June 30,
2021202020212020
REVENUES
Vertically Integrated Utilities$2,224.6 $2,062.3 $4,729.1 $4,255.3 
Transmission and Distribution Utilities1,089.6 1,009.4 2,171.9 2,084.6 
Generation & Marketing422.5 350.2 1,024.2 758.6 
Other Revenues89.8 72.1 182.4 143.0 
TOTAL REVENUES3,826.5 3,494.0 8,107.6 7,241.5 
EXPENSES    
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation1,124.0 964.9 2,684.7 2,115.9 
Other Operation566.9 566.0 1,159.3 1,168.1 
Maintenance264.3 243.4 539.2 492.9 
Depreciation and Amortization707.3 679.5 1,403.6 1,351.7 
Taxes Other Than Income Taxes354.1 317.5 700.6 638.6 
TOTAL EXPENSES3,016.6 2,771.3 6,487.4 5,767.2 
OPERATING INCOME809.9 722.7 1,620.2 1,474.3 
Other Income (Expense):    
Other Income33.1 14.3 54.8 9.9 
Allowance for Equity Funds Used During Construction33.5 35.1 66.9 66.5 
Non-Service Cost Components of Net Periodic Benefit Cost29.7 29.8 59.3 59.5 
Interest Expense(301.6)(294.0)(591.8)(586.1)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS604.6 507.9 1,209.4 1,024.1 
Income Tax Expense61.2 12.6 115.7 59.1 
Equity Earnings of Unconsolidated Subsidiaries30.4 19.2 58.9 48.8 
NET INCOME573.8 514.5 1,152.6 1,013.8 
Net Loss Attributable to Noncontrolling Interests(4.4)(6.3)(0.6)(2.2)
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$578.2 $520.8 $1,153.2 $1,016.0 
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING499,916,640 495,655,053 498,495,532 495,125,961 
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$1.16 $1.05 $2.31 $2.05 
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING500,983,778 497,337,980 499,581,893 496,973,449 
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$1.15 $1.05 $2.31 $2.04 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
51
  Three Months Ended March 31,
  2018 2017
REVENUES    
Vertically Integrated Utilities $2,381.5
 $2,269.8
Transmission and Distribution Utilities 1,141.2
 1,066.4
Generation & Marketing 477.5
 558.8
Other Revenues 48.1
 38.3
TOTAL REVENUES 4,048.3
 3,933.3
     
EXPENSES  
  
Fuel and Other Consumables Used for Electric Generation 501.8
 635.6
Purchased Electricity for Resale 990.3
 769.6
Other Operation 726.4
 623.7
Maintenance 298.5
 303.5
Gain on Sale of Merchant Generation Assets —
 (226.5)
Depreciation and Amortization 539.7
 481.9
Taxes Other Than Income Taxes 285.6
 259.8
TOTAL EXPENSES 3,342.3
 2,847.6
     
OPERATING INCOME 706.0
 1,085.7
     
Other Income (Expense):  
  
Interest and Investment Income 2.1
 8.0
Carrying Costs Income 3.4
 5.9
Allowance for Equity Funds Used During Construction 30.7
 21.2
Non-Service Cost Components of Net Periodic Benefit Cost 32.0
 11.4
Interest Expense (234.0) (221.8)
     
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS 540.2
 910.4
     
Income Tax Expense 102.0
 343.2
Equity Earnings of Unconsolidated Subsidiaries 18.5
 27.0
     
NET INCOME 456.7
 594.2
     
Net Income Attributable to Noncontrolling Interests 2.3
 2.0
     
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $454.4
 $592.2
     
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING 492,267,402
 491,712,042
     
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $0.92
 $1.20
     
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING 493,127,300
 492,031,975
     
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $0.92
 $1.20
     
CASH DIVIDENDS DECLARED PER SHARE $0.62
 $0.59


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended March 31, 2018June 30, 2021 and 20172020
(in millions)
(Unaudited)
Three Months EndedSix Months Ended
June 30,June 30,
2021202020212020
Net Income$573.8 $514.5 $1,152.6 $1,013.8 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES    
Cash Flow Hedges, Net of Tax of $34.5 and $12.0 for the Three Months Ended June 30, 2021 and 2020, Respectively, and $49.5 and $(5.8) for the Six Months Ended June 30, 2021 and 2020, Respectively129.9 45.3 186.2 (21.7)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.6) and $(0.4) for the Three Months Ended June 30, 2021 and 2020, Respectively, and $(1.1) and $(0.9) for the Six Months Ended June 30, 2021 and 2020, Respectively(2.1)(1.7)(4.1)(3.5)
    
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)127.8 43.6 182.1 (25.2)
TOTAL COMPREHENSIVE INCOME701.6 558.1 1,334.7 988.6 
Total Comprehensive Loss Attributable To Noncontrolling Interests(4.4)(6.3)(0.6)(2.2)
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$706.0 $564.4 $1,335.3 $990.8 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
52
  Three Months Ended March 31,
  2018 2017
Net Income $456.7
 $594.2
     
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES  
  
Cash Flow Hedges, Net of Tax of $0.7 and $(8.7) in 2018 and 2017, Respectively 2.7
 (16.1)
Securities Available for Sale, Net of Tax of $0 and $0.6 in 2018 and 2017, Respectively —
 1.2
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.4) and $0.1 in 2018 and 2017, Respectively (1.4) 0.2
     
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) 1.3
 (14.7)
     
TOTAL COMPREHENSIVE INCOME 458.0
 579.5
     
Total Comprehensive Income Attributable to Noncontrolling Interests 2.3
 2.0
     
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $455.7
 $577.5


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.





AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the ThreeSix Months Ended March 31, 2018June 30, 2021 and 20172020
(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 
Issuance of Common Stock0.8 5.2 49.7    54.9 
Common Stock Dividends   (337.7)(a) (3.2)(340.9)
Other Changes in Equity  (2.6) 1.0 (1.6)
Net Income (Loss)   520.8  (6.3)514.5 
Other Comprehensive Income    43.6  43.6 
TOTAL EQUITY – JUNE 30, 2020516.2 $3,355.4 $6,603.0 $10,221.9 $(172.9)$270.8 $20,278.2 
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)(b)(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 
Issuance of Common Stock0.9 6.3 66.0 72.3 
Common Stock Dividends(371.8)(b)(2.7)(374.5)
Other Changes in Equity(0.2)(0.4)11.1 10.5 
Net Income (Loss)578.2 (4.4)573.8 
Other Comprehensive Income127.8 127.8 
TOTAL EQUITY – JUNE 30, 2021520.4 $3,382.7 $6,800.3 $11,098.7 $97.0 $251.2 $21,629.9 
 AEP Common Shareholders    
 Common Stock     
Accumulated
Other
Comprehensive
Income (Loss)
    
 Shares Amount 
Paid-in
Capital
 
Retained
Earnings
  
Noncontrolling
Interests
 Total
TOTAL EQUITY – DECEMBER 31, 2016512.0
 $3,328.3
 $6,332.6
 $7,892.4
 $(156.3) $23.1
 $17,420.1
              
Common Stock Dividends 
  
  
 (290.3)  
 (1.1) (291.4)
Other Changes in Equity 
  
 2.9
 

  
 0.6
 3.5
Net Income      592.2
  
 2.0
 594.2
Other Comprehensive Loss 
  
  
  
 (14.7)  
 (14.7)
TOTAL EQUITY – MARCH 31, 2017512.0
 $3,328.3
 $6,335.5
 $8,194.3
 $(171.0) $24.6
 $17,711.7
              
TOTAL EQUITY – DECEMBER 31, 2017512.2
 $3,329.4
 $6,398.7
 $8,626.7
 $(67.8) $26.6
 $18,313.6
              
Issuance of Common Stock0.5
 3.3
 28.9
  
  
  
 32.2
Common Stock Dividends 
  
  
 (305.5)  
 (0.6) (306.1)
Other Changes in Equity    16.9
     

 16.9
ASU 2018-02 Adoption      14.0
 (17.0)   (3.0)
ASU 2016-01 Adoption      11.9
 (11.9)   —
Net Income      454.4
  
 2.3
 456.7
Other Comprehensive Income 
  
  
  
 1.3
  
 1.3
TOTAL EQUITY – MARCH 31, 2018512.7
 $3,332.7
 $6,444.5
 $8,801.5
 $(95.4) $28.3
 $18,511.6

(a)    Cash dividends declared per AEP common share were $0.70.
(b)    Cash dividends declared per AEP common share were $0.74.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120137.

53






AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2018June 30, 2021 and December 31, 20172020
(in millions)
(Unaudited)
 June 30,December 31,
 20212020
CURRENT ASSETS  
Cash and Cash Equivalents$312.7 $392.7 
Restricted Cash
(June 30, 2021 and December 31, 2020 Amounts Include $47 and $45.6, Respectively, Related to Transition Funding, Restoration Funding and Appalachian Consumer Rate Relief Funding)
47.0 45.6 
Other Temporary Investments
(June 30, 2021 and December 31, 2020 Amounts Include $204.9 and $194.6, Respectively, Related to EIS and Transource Energy)
221.7 200.8 
Accounts Receivable:  
Customers794.8 613.6 
Accrued Unbilled Revenues259.6 248.7 
Pledged Accounts Receivable – AEP Credit1,003.1 1,018.4 
Miscellaneous66.6 33.1 
Allowance for Uncollectible Accounts(50.3)(71.1)
Total Accounts Receivable2,073.8 1,842.7 
Fuel512.2 629.4 
Materials and Supplies676.2 680.6 
Risk Management Assets214.7 94.7 
Accrued Tax Benefits189.8 185.3 
Regulatory Asset for Under-Recovered Fuel Costs180.3 90.7 
Margin Deposits43.5 62.0 
Prepayments and Other Current Assets133.9 127.0 
TOTAL CURRENT ASSETS4,605.8 4,351.5 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation23,687.3 23,133.9 
Transmission29,213.7 27,886.7 
Distribution24,704.6 23,972.1 
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)5,571.4 5,294.6 
Construction Work in Progress3,879.3 4,025.7 
Total Property, Plant and Equipment87,056.3 84,313.0 
Accumulated Depreciation and Amortization21,391.8 20,411.4 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET65,664.5 63,901.6 
OTHER NONCURRENT ASSETS  
Regulatory Assets5,048.2 3,527.0 
Securitized Assets608.0 657.0 
Spent Nuclear Fuel and Decommissioning Trusts3,612.4 3,306.7 
Goodwill52.5 52.5 
Long-term Risk Management Assets241.3 242.2 
Operating Lease Assets797.6 866.4 
Deferred Charges and Other Noncurrent Assets3,727.9 3,852.3 
TOTAL OTHER NONCURRENT ASSETS14,087.9 12,504.1 
TOTAL ASSETS$84,358.2 $80,757.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
54
  March 31, December 31,
  2018 2017
CURRENT ASSETS  
  
Cash and Cash Equivalents $183.4
 $214.6
Restricted Cash
(March 31, 2018 and December 31, 2017 Amounts Relate to Transition Funding, Ohio Phase-in-Recovery Funding and Appalachian Consumer Rate Relief Funding)
 133.1
 198.0
Other Temporary Investments
(March 31, 2018 and December 31, 2017 Amounts Include $155.8 and $155.4, Respectively, Related to EIS, Transource Energy and Sabine)
 167.9
 161.7
Accounts Receivable:  
  
Customers 635.6
 643.9
Accrued Unbilled Revenues 213.4
 230.2
Pledged Accounts Receivable – AEP Credit 975.3
 954.2
Miscellaneous 66.5
 101.2
Allowance for Uncollectible Accounts (39.3) (38.5)
Total Accounts Receivable 1,851.5
 1,891.0
Fuel 359.6
 387.7
Materials and Supplies 563.2
 565.5
Risk Management Assets 89.6
 126.2
Regulatory Asset for Under-Recovered Fuel Costs 352.3
 292.5
Margin Deposits 154.2
 105.5
Prepayments and Other Current Assets 280.2
 310.4
TOTAL CURRENT ASSETS 4,135.0
 4,253.1
     
PROPERTY, PLANT AND EQUIPMENT  
  
Electric:  
  
Generation 20,824.0
 20,760.5
Transmission 19,239.9
 18,972.5
Distribution 20,160.5
 19,868.5
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) 3,812.5
 3,706.3
Construction Work in Progress 4,759.4
 4,120.7
Total Property, Plant and Equipment 68,796.3
 67,428.5
Accumulated Depreciation and Amortization 17,431.2
 17,167.0
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 51,365.1
 50,261.5
     
OTHER NONCURRENT ASSETS  
  
Regulatory Assets 3,516.9
 3,587.6
Securitized Assets 1,146.6
 1,211.2
Spent Nuclear Fuel and Decommissioning Trusts 2,510.6
 2,527.6
Goodwill 52.5
 52.5
Long-term Risk Management Assets 271.2
 282.1
Deferred Charges and Other Noncurrent Assets 2,611.6
 2,553.5
TOTAL OTHER NONCURRENT ASSETS 10,109.4
 10,214.5
     
TOTAL ASSETS $65,609.5
 $64,729.1


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.





AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
March 31, 2018June 30, 2021 and December 31, 20172020
(dollars in millions)millions, except per-share and share amounts)
(Unaudited)
   June 30,December 31,
 20212020
CURRENT LIABILITIES  
Accounts Payable$1,641.6 $1,709.7 
Short-term Debt:  
Securitized Debt for Receivables – AEP Credit578.2 592.0 
Other Short-term Debt2,549.8 1,887.3 
Total Short-term Debt3,128.0 2,479.3 
Long-term Debt Due Within One Year
(June 30, 2021 and December 31, 2020 Amounts Include $210.2 and $198.3, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)
2,458.5 2,086.1 
Risk Management Liabilities47.8 78.8 
Customer Deposits350.1 335.6 
Accrued Taxes1,243.5 1,476.4 
Accrued Interest274.0 267.6 
Obligations Under Operating Leases242.7 241.3 
Regulatory Liability for Over-Recovered Fuel Costs32.7 52.6 
Other Current Liabilities1,009.7 1,199.3 
TOTAL CURRENT LIABILITIES10,428.6 9,926.7 
NONCURRENT LIABILITIES  
Long-term Debt
(June 30, 2021 and December 31, 2020 Amounts Include $922.5 and $950.1, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)
30,659.3 28,986.4 
Long-term Risk Management Liabilities216.3 232.8 
Deferred Income Taxes8,382.1 8,240.9 
Regulatory Liabilities and Deferred Investment Tax Credits8,767.5 8,378.7 
Asset Retirement Obligations2,576.2 2,469.2 
Employee Benefits and Pension Obligations340.1 336.4 
Obligations Under Operating Leases568.4 638.4 
Deferred Credits and Other Noncurrent Liabilities724.9 728.0 
TOTAL NONCURRENT LIABILITIES52,234.8 50,010.8 
TOTAL LIABILITIES62,663.4 59,937.5 
Rate Matters (Note 4)00
Commitments and Contingencies (Note 5)00
MEZZANINE EQUITY
Contingently Redeemable Performance Share Awards64.9 45.2 
TOTAL MEZZANINE EQUITY64.9 45.2 
EQUITY  
Common Stock – Par Value – $6.50 Per Share:  
20212020  
Shares Authorized600,000,000600,000,000  
Shares Issued520,422,130516,808,354  
(20,204,160 Shares were Held in Treasury as of June 30, 2021 and December 31, 2020, Respectively)3,382.7 3,359.3 
Paid-in Capital6,800.3 6,588.9 
Retained Earnings11,098.7 10,687.8 
Accumulated Other Comprehensive Income (Loss)97.0 (85.1)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY21,378.7 20,550.9 
Noncontrolling Interests251.2 223.6 
TOTAL EQUITY21,629.9 20,774.5 
TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY$84,358.2 $80,757.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
55
       March 31, December 31,
       2018 2017
CURRENT LIABILITIES    
Accounts Payable      $1,449.6
 $2,065.3
Short-term Debt:         
Securitized Debt for Receivables – AEP Credit    750.0
 718.0
Other Short-term Debt      1,908.8
 920.6
Total Short-term Debt      2,658.8
 1,638.6
Long-term Debt Due Within One Year
(March 31, 2018 and December 31, 2017 Amounts Include $406.5 and $406.9, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and Sabine)
  2,616.1
 1,753.7
Risk Management Liabilities      57.1
 61.6
Customer Deposits      365.5
 357.0
Accrued Taxes      1,081.4
 1,115.5
Accrued Interest      273.1
 234.5
Regulatory Liability for Over-Recovered Fuel Costs    9.8
 11.9
Other Current Liabilities      960.0
 1,033.2
TOTAL CURRENT LIABILITIES      9,471.4
 8,271.3
          
NONCURRENT LIABILITIES    
Long-term Debt
(March 31, 2018 and December 31, 2017 Amounts Include $1,253 and $1,410.5, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, Transource Energy and Sabine)
  18,844.9
 19,419.6
Long-term Risk Management Liabilities      282.7
 322.0
Deferred Income Taxes      6,943.9
 6,813.9
Regulatory Liabilities and Deferred Investment Tax Credits  8,394.5
 8,422.3
Asset Retirement Obligations      1,933.7
 1,925.5
Employee Benefits and Pension Obligations      330.9
 398.1
Deferred Credits and Other Noncurrent Liabilities  808.2
 830.9
TOTAL NONCURRENT LIABILITIES      37,538.8
 38,132.3
          
TOTAL LIABILITIES      47,010.2
 46,403.6
          
Rate Matters (Note 4)      
 
Commitments and Contingencies (Note 5)      
 
          
MEZZANINE EQUITY    
Redeemable Noncontrolling Interest      70.7
 —
Contingently Redeemable Performance Share Awards      17.0
 11.9
TOTAL MEZZANINE EQUITY      87.7
 11.9
          
EQUITY    
Common Stock – Par Value – $6.50 Per Share:         
  2018 2017     
Shares Authorized 600,000,000 600,000,000     
Shares Issued 512,716,170 512,210,644     
(20,204,160 and 20,205,046 Shares were Held in Treasury as of March 31, 2018 and December 31, 2017, Respectively)  3,332.7
 3,329.4
Paid-in Capital      6,444.5
 6,398.7
Retained Earnings      8,801.5
 8,626.7
Accumulated Other Comprehensive Income (Loss)  (95.4) (67.8)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY  18,483.3
 18,287.0
          
Noncontrolling Interests      28.3
 26.6
          
TOTAL EQUITY      18,511.6
 18,313.6
          
TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY    $65,609.5
 $64,729.1


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the ThreeSix Months Ended March 31, 2018June 30, 2021 and 20172020
(in millions)
(Unaudited)
 Six Months Ended June 30,
 20212020
OPERATING ACTIVITIES  
Net Income$1,152.6 $1,013.8 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and Amortization1,403.6 1,351.7 
Rockport Plant, Unit 2 Operating Lease Amortization66.8 68.3 
Deferred Income Taxes86.7 60.0 
Allowance for Equity Funds Used During Construction(66.9)(66.5)
Mark-to-Market of Risk Management Contracts26.1 13.7 
Amortization of Nuclear Fuel40.4 45.6 
Property Taxes167.3 173.6 
Deferred Fuel Over/Under-Recovery, Net(1,218.2)76.0 
Change in Other Noncurrent Assets(291.9)(143.9)
Change in Other Noncurrent Liabilities163.5 (50.0)
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net(215.5)(80.7)
Fuel, Materials and Supplies132.3 (120.3)
Accounts Payable97.5 (64.7)
Accrued Taxes, Net(237.4)(164.4)
Rockport Plant, Unit 2 Operating Lease Payments(73.9)(73.9)
Other Current Assets10.4 18.8 
Other Current Liabilities(199.5)(310.9)
Net Cash Flows from Operating Activities1,043.9 1,746.2 
INVESTING ACTIVITIES  
Construction Expenditures(2,784.8)(3,244.9)
Purchases of Investment Securities(1,162.8)(988.4)
Sales of Investment Securities1,131.8 971.3 
Acquisitions of Nuclear Fuel(63.0)(37.7)
Acquisition of the Dry Lake Solar Project(114.3)0 
Acquisition of the North Central Wind Energy Facilities(270.0)0 
Other Investing Activities33.3 52.1 
Net Cash Flows Used for Investing Activities(3,229.8)(3,247.6)
FINANCING ACTIVITIES  
Issuance of Common Stock256.9 111.0 
Issuance of Long-term Debt3,055.1 2,431.3 
Issuance of Short-term Debt with Original Maturities greater than 90 Days1,178.5 1,304.5 
Change in Short-term Debt with Original Maturities less than 90 Days, Net(437.8)(766.2)
Retirement of Long-term Debt(998.1)(433.2)
Redemption of Short-term Debt with Original Maturities Greater than 90 Days(92.0)(300.0)
Principal Payments for Finance Lease Obligations(30.3)(31.3)
Dividends Paid on Common Stock(746.5)(704.6)
Other Financing Activities(78.5)(38.0)
Net Cash Flows from Financing Activities2,107.3 1,573.5 
Net Increase (Decrease) in Cash and Cash Equivalents(78.6)72.1 
Cash, Cash Equivalents and Restricted Cash at Beginning of Period438.3 432.6 
Cash, Cash Equivalents and Restricted Cash at End of Period$359.7 $504.7 
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts$559.9 $481.2 
Net Cash Paid for Income Taxes8.6 3.1 
Noncash Acquisitions Under Finance Leases16.3 26.8 
Construction Expenditures Included in Current Liabilities as of June 30,789.3 833.3 
Construction Expenditures Included in Noncurrent Liabilities as of June 30,0 8.3 
Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30,0 22.3 
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage0.2 2.2 
Noncontrolling Interest Assumed - Dry Lake Solar Project33.4 0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
56
  Three Months Ended March 31,
  2018 2017
OPERATING ACTIVITIES  
  
Net Income $456.7
 $594.2
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
Depreciation and Amortization 539.7
 481.9
Deferred Income Taxes 87.3
 136.2
Allowance for Equity Funds Used During Construction (30.7) (21.2)
Mark-to-Market of Risk Management Contracts (0.7) 6.0
Amortization of Nuclear Fuel 27.4
 35.1
Property Taxes (63.7) (44.4)
Deferred Fuel Over/Under-Recovery, Net (61.2) 19.3
Gain on Sale of Merchant Generation Assets —
 (226.5)
Recovery of Ohio Capacity Costs 18.0
 30.2
Provision for Refund - Global Settlement, Net (5.4) —
Change in Other Noncurrent Assets (59.8) (99.1)
Change in Other Noncurrent Liabilities 133.3
 45.0
Changes in Certain Components of Working Capital:    
Accounts Receivable, Net 39.7
 235.8
Fuel, Materials and Supplies 28.5
 13.4
Accounts Payable (129.3) (250.7)
Accrued Taxes, Net (74.3) 186.8
Other Current Assets (40.1) (45.9)
Other Current Liabilities (63.2) (289.3)
Net Cash Flows from Operating Activities 802.2
 806.8
     
INVESTING ACTIVITIES    
Construction Expenditures (1,905.8) (1,365.8)
Purchases of Investment Securities (525.9) (506.0)
Sales of Investment Securities 508.6
 487.9
Acquisitions of Nuclear Fuel (23.8) (3.7)
Proceeds from Sale of Merchant Generation Assets —
 2,159.6
Other Investing Activities 19.1
 4.2
Net Cash Flows from (Used for) Investing Activities (1,927.8) 776.2
     
FINANCING ACTIVITIES    
Issuance of Common Stock, Net 32.2
 —
Issuance of Long-term Debt 841.0
 82.9
Commercial Paper and Credit Facility Borrowings 205.6
 —
Change in Short-term Debt, Net 814.6
 (177.0)
Retirement of Long-term Debt (544.0) (1,242.3)
Make Whole Payment on Extinguishment of Long-term Debt —
 (44.9)
Principal Payments for Capital Lease Obligations (16.8) (16.6)
Dividends Paid on Common Stock (306.1) (291.4)
Other Financing Activities 3.0
 2.2
Net Cash Flows from (Used for) Financing Activities 1,029.5
 (1,687.1)
     
Net Decrease in Cash, Cash Equivalents and Restricted Cash (96.1) (104.1)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period 412.6
 403.5
Cash, Cash Equivalents and Restricted Cash at End of Period $316.5
 $299.4
     
SUPPLEMENTARY INFORMATION    
Cash Paid for Interest, Net of Capitalized Amounts $188.0
 $205.9
Net Cash Paid (Received) for Income Taxes (0.9) (88.8)
Noncash Acquisitions Under Capital Leases 21.4
 11.4
Construction Expenditures Included in Current Liabilities as of March 31, 799.9
 515.6
Noncash Contribution of Assets by Noncontrolling Interest 84.0
 —
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage 0.1
 1.0


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.





AEP TEXAS INC.
AND SUBSIDIARIES



57




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


RESULTS OF OPERATIONS


KWh Sales/Degree Days


Summary of KWh Energy Sales
 Three Months EndedSix Months Ended
June 30,June 30,
 2021202020212020
 (in millions of KWhs)
Retail:  
Residential3,006 3,158 5,824 5,624 
Commercial2,819 2,402 4,893 4,759 
Industrial2,604 2,216 4,484 4,581 
Miscellaneous159 150 296 302 
Total Retail8,588 7,926 15,497 15,266 
 Three Months Ended March 31,
 2018 2017
 (in millions of KWhs)
Retail: 
  
Residential2,664
 2,201
Commercial2,312
 2,325
Industrial1,960
 1,907
Miscellaneous122
 128
Total Retail7,058
 6,561


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


Summary of Heating and Cooling Degree Days
 Three Months EndedSix Months Ended
June 30,June 30,
 2021202020212020
 (in degree days)
Actual – Heating (a)4 6 319 97 
Normal – Heating (b)3 3 188 188 
Actual – Cooling (c)833 936 970 1,167 
Normal – Cooling (b)931 933 1,057 1,058 
 Three Months Ended March 31,
 2018 2017
 (in degree days)
Actual – Heating (a)230
 102
Normal – Heating (b)191
 195
    
Actual – Cooling (c)196
 258
Normal – Cooling (b)119
 113


(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 6570 degree temperature base.




First

58




Second Quarter of 20182021 Compared to FirstSecond Quarter of 20172020
AEP Texas Inc. and Subsidiaries
Reconciliation of Second Quarter of 2020 to Second Quarter of 2021
Net Income
(in millions)
Second Quarter of 2020$66.9 
Changes in Gross Margin:
Retail Margins30.7 
Margins from Off-system Sales(12.9)
Transmission Revenues29.5 
Other Revenues(47.1)
Total Change in Gross Margin0.2 
Changes in Expenses and Other:
Other Operation and Maintenance(12.3)
Depreciation and Amortization63.6 
Taxes Other Than Income Taxes(5.5)
Interest Income0.1 
Allowance for Equity Funds Used During Construction(1.5)
Non-Service Cost Components of Net Periodic Benefit Cost(0.1)
Interest Expense(3.1)
Total Change in Expenses and Other41.2 
Income Tax Expense(28.5)
Second Quarter of 2021$79.8 
Reconciliation of First Quarter of 2017 to First Quarter of 2018
Net Income
(in millions)
 
First Quarter of 2017 $33.3
   
Changes in Gross Margin:  
Retail Margins 18.6
Off-system Sales (1.6)
Transmission Revenues 2.4
Other Revenues 2.7
Total Change in Gross Margin 22.1
   
Changes in Expenses and Other:  
Other Operation and Maintenance (11.3)
Depreciation and Amortization (7.2)
Taxes Other Than Income Taxes (4.1)
Interest Income (0.5)
Allowance for Equity Funds Used During Construction 3.7
Non-Service Cost Components of Net Periodic Benefit Cost 2.2
Interest Expense —
Total Change in Expenses and Other (17.2)
   
Income Tax Expense 8.6
   
First Quarter of 2018 $46.8


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


•Retail Margins increased $19$31 million primarily due to the following:
•A $10$19 million increase in weather-related usageweather-normalized margins primarily in the residential and commercial classes.
•A $16 million increase from interim rate increases driven by a 125% increase in heating degree days partially offset by a 24% decrease in cooling degree days.increased transmission investment.
A $9•An $11 million increase in revenues associated with the Transmission Cost Recovery Factor revenue rider. This increase was partially offsetfrom interim rate increases driven by an increase in Other Operation and Maintenance expenses below.
A $7 million increase in revenues associated with the Distribution Cost Recovery Factor revenue rider.increased distribution investment.
These increases were partially offset by:
•A $5$6 million decrease in weather-related usage primarily due to an 11% decrease in cooling degree days.
•A $4 million decrease due to the 2018 provisions for customer refunds primarily related toof Excess ADIT and excess federal income taxes collected as a result of Tax Reform. This decrease iswas partially offset in Income Tax Expense below.
Transmission Revenues increased by $2•Margins from Off-system Sales decreased $13 million primarily due to the following:
retirement of the Oklaunion Power Station in September 2020. This decrease was partially offset in Depreciation and Amortization expenses below.
•Transmission Revenues increased $30 million primarily due to:
•A $7$20 million increase from interim rate increases driven by increased transmission investment.
•A $14 million increase due to recoverya prior year one-time credit to transmission customers as a result of increased transmission investment in ERCOT.
Tax Reform and the most recent base rate case. This increase was partially offset by:
A $5 million decrease due to the 2018 provisions for customer refunds primarily due to Tax Reform.  This decrease is offset in Income Tax Expense below.
These increases were 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 increased $3 below.
•Other Revenues decreased $47 million primarily due to securitization revenue relatedrevenues due to the AEP Texas Central Transition Funding.Funding II LLC bonds that matured in July 2020. This increasedecrease was offset below in Depreciation and Amortization expenses and in Interest Expense below.Expense.
59






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


•Other Operation and Maintenance expenses increased $11$12 million primarily due to the following:
•A $17 million increase due to the prior year revision of the Oklaunion Power Station ARO. This increase was offset in Margins from Off-system Sales above.
This increase was partially offset by:
•A $4 million decrease primarily related to distribution-related expenses.
•Depreciation and Amortization expenses decreased $64 million primarily due to the following:
•A $49 million decrease in securitization amortizations primarily related to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This 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.
•Taxes Other Than Income Taxes expenses increased $6 million primarily due to property taxes as a result of increased distribution and transmission investment.
•Interest Expense increased$3 million primarily due to higher long-term debt balances.
•Income Tax Expense increased $29 million primarily due to a decrease in amortization of excess ADIT and an increase in ERCOTpretax book income. The decrease in amortization of excess ADIT is partially offset above in Gross Margin.
60




Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020
AEP Texas Inc. and Subsidiaries
Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30, 2021
Net Income
(in millions)
Six Months Ended June 30, 2020$114.5 
Changes in Gross Margin:
Retail Margins24.4 
Margins from Off-system Sales(43.1)
Transmission Revenues44.8 
Other Revenues(85.3)
Total Change in Gross Margin(59.2)
Changes in Expenses and Other:
Other Operation and Maintenance(15.5)
Depreciation and Amortization128.6 
Taxes Other Than Income Taxes(7.8)
Interest Income(0.3)
Allowance for Equity Funds Used During Construction(2.5)
Non-Service Cost Components of Net Periodic Benefit Cost(0.1)
Interest Expense(3.6)
Total Change in Expenses and Other98.8 
Income Tax Expense(28.2)
Six Months Ended June 30, 2021$125.9 
The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals were as follows:

•Retail Margins increased $24 million primarily due to the following:
•A $21 million increase from interim rate increases driven by increased transmission investment.
•A $21 million increase from interim rate increases driven by increased distribution investment.
•A $13 million increase in weather-related usage primarily due to a 229% increase in heating degree days partially offset by a 17% decrease in cooling degree days.
These increases were partially offset by:
•A $19 million decrease due to refunds of Excess ADIT and excess federal income taxes collected as a result of Tax Reform. This decrease was partially offset in Income Tax Expense below.
•A $6 million decrease in weather-normalized margins primarily in the industrial and residential classes, partially offset by an increase in the commercial class.
•Margins from Off-system Sales decreased $43 million primarily due to the retirement of the Oklaunion Power Station in September 2020. This decrease was partially offset in Depreciation and Amortization expenses below.
•Transmission Revenues increased $45 million primarily due to the following:
•A $39 million increase from interim rate increases driven by increased transmission investment.
•A $14 million increase due to a prior year one-time credit to transmission customers as a result of Tax Reform and the most recent base rate case. This increase was offset in Income Tax Expense below.
These increases were partially offset by:
•A $9 million decrease due to refunds to customers associated with the most recent base rate case. This decrease was offset in Other Revenues below.
61





•Other Revenues decreased $85 million primarily due to the following:
•A $98 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.
This decrease was partially offset by:
•A $10 million increase due to refunds to customers associated with the most recent base rate case. This increase was partially offset in Retail Margins and Transmission Revenues above.

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

•Other Operation and Maintenance expenses increased $16 million primarily due to the following:
•A $17 million increase due to the prior year revision of the Oklaunion Power Station ARO. This increase was offset in Margins from Off-System Sales above.
•A $3 million increase in transmission expenses. This increase was partially offset by an increase in Retail MarginsGross Margin above.

These increases were partially offset by:

•A $6 million decrease primarily related to distribution-related expenses.
•Depreciation and Amortization expenses increased $7decreased $129 million primarily due to the following:
•A $93 million decrease in securitization amortizations primarily related to the AEP Texas Central Transition Funding. Funding II LLC bonds that matured in July 2020. This increasedecrease was offset in Other Revenues above.
•A $32 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 in Interest Expense below.
Other Operation and Maintenance expenses.
•Taxes Other Than Income Taxesincreased $8 million primarily due to property taxes as a result of increased distribution and transmission investment.
•Interest Expense increased $4 million primarily due to increased property taxes as a result of additional capital investment and increased tax rates.
Interest Expense was unchanged primarily due to:
A $3 million decrease in securitization assets related to Transition Funding. This decrease was offset above in Other Revenues and in Depreciation and Amortization.
A $2 million decrease due to higher debt component of AFUDC from increased transmission projects.
These decreases were offset by:
A $5 million increase in interest due to the issuance of long-term debt in September 2017.balances.
Allowance for Equity Funds Used During Construction increased $4 million due to increased transmission projects.
•Income Tax Expense decreased $9 increased $28 million primarily due to the changea decrease in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and amortization of excess accumulated deferred income taxes associated with certain depreciable property, partially offset byADIT and an increase in pretax book income.The decrease in amortization of excess ADIT is partially offset above in Gross Margin.
62








AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended March 31, 2018June 30, 2021 and 20172020
(in millions)
(Unaudited)
  Three Months EndedSix Months Ended
June 30,June 30,
  2021 202020212020
REVENUES    
Electric Transmission and Distribution $396.6 $383.5 $758.3 $775.1 
Sales to AEP Affiliates 1.0 16.9 2.0 48.0 
Other Revenues 0.9 1.1 2.4 2.0 
TOTAL REVENUES 398.5 401.5 762.7 825.1 
 
EXPENSES     
Fuel and Other Consumables Used for Electric Generation0 3.2 0 3.2 
Other Operation 109.6 92.9 231.8 210.4 
Maintenance 18.7 23.1 37.8 43.7 
Depreciation and Amortization 102.0 165.6 199.5 328.1 
Taxes Other Than Income Taxes 39.5 34.0 75.8 68.0 
TOTAL EXPENSES 269.8 318.8 544.9 653.4 
 
OPERATING INCOME 128.7 82.7 217.8 171.7 
 
Other Income (Expense):     
Interest Income 0.2 0.1 0.4 0.7 
Allowance for Equity Funds Used During Construction3.4 4.9 7.5 10.0 
Non-Service Cost Components of Net Periodic Benefit Cost2.7 2.8 5.5 5.6 
Interest Expense (45.3)(42.2)(88.3)(84.7)
 
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 89.7 48.3 142.9 103.3 
 
Income Tax Expense (Benefit) 9.9 (18.6)17.0 (11.2)
NET INCOME $79.8 $66.9 $125.9 $114.5 
The common stock of AEP Texas is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
63
  Three Months Ended March 31,
  2018 2017
REVENUES    
Electric Transmission and Distribution $352.4
 $328.9
Sales to AEP Affiliates 18.2
 14.1
Other Revenues 1.0
 0.6
TOTAL REVENUES 371.6
 343.6
     
EXPENSES  
  
Fuel and Other Consumables Used for Electric Generation 8.9
 3.0
Other Operation 117.0
 108.8
Maintenance 21.5
 18.4
Depreciation and Amortization 110.0
 102.8
Taxes Other Than Income Taxes 32.4
 28.3
TOTAL EXPENSES 289.8
 261.3
     
OPERATING INCOME 81.8
 82.3
     
Other Income (Expense):  
  
Interest Income 0.5
 1.0
Allowance for Equity Funds Used During Construction 5.5
 1.8
Non-Service Cost Components of Net Periodic Benefit Cost 3.1
 0.9
Interest Expense (35.0) (35.0)
     
INCOME BEFORE INCOME TAX EXPENSE 55.9
 51.0
     
Income Tax Expense 9.1
 17.7
     
NET INCOME $46.8
 $33.3


The common stock of AEP Texas Inc. is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.





AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended March 31, 2018June 30, 2021 and 20172020
(in millions)
(Unaudited)
 Three Months EndedSix Months Ended
June 30,June 30,
2021202020212020
Net Income$79.8 $66.9 $125.9 $114.5 
 
OTHER COMPREHENSIVE INCOME, NET OF TAXES  
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2021 and 2020, Respectively, and $0.1 and $0.1 for the Six Months Ended June 30, 2021 and 2020, Respectively0.2 0.2 0.5 0.5 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2021 and 2020, Respectively, and $0 and $0 for the Six Months Ended June 30, 2021 and 2020, Respectively0.1 0.1 0.1 0.1 
TOTAL OTHER COMPREHENSIVE INCOME0.3 0.3 0.6 0.6 
TOTAL COMPREHENSIVE INCOME$80.1 $67.2 $126.5 $115.1 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.

64
 Three Months Ended March 31,
 2018 2017
Net Income$46.8
 $33.3
    
OTHER COMPREHENSIVE INCOME, NET OF TAXES   
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 in 2018 and 2017, Respectively0.2
 0.2
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 in 2018 and 2017, Respectively0.1
 0.1
    
TOTAL OTHER COMPREHENSIVE INCOME0.3
 0.3
    
TOTAL COMPREHENSIVE INCOME$47.1
 $33.6


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.





AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the ThreeSix Months Ended March 31, 2018June 30, 2021 and 20172020
(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, 20201,457.9 1,563.6 (12.5)3,009.0 
Net Income 66.9  66.9 
Other Comprehensive Income  0.3 0.3 
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2020$1,457.9 $1,630.5 $(12.2)$3,076.2 
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020$1,457.9 $1,757.0 $(8.9)$3,206.0 
Net Income46.1 46.1 
Other Comprehensive Income0.3 0.3 
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 20211,457.9 1,803.1 (8.6)3,252.4 
Net Income 79.8 79.8 
Other Comprehensive Income 0.3 0.3 
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2021$1,457.9 $1,882.9 $(8.3)$3,332.5 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.

65
  
Paid-in
Capital
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2016 $857.9
 $814.1
 $(14.9) $1,657.1
         
Capital Contribution from Parent 200.0
    
 200.0
Net Income  
 33.3
  
 33.3
Other Comprehensive Income  
  
 0.3
 0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2017 $1,057.9
 $847.4
 $(14.6) $1,890.7
         
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017 $1,057.9
 $1,124.6
 $(12.6) $2,169.9
         
Capital Contribution from Parent 100.0
     100.0
ASU 2018-02 Adoption   1.8
 (2.7) (0.9)
Net Income  
 46.8
   46.8
Other Comprehensive Income  
   0.3
 0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018 $1,157.9
 $1,173.2
 $(15.0) $2,316.1


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.





AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2018June 30, 2021 and December 31, 20172020
(in millions)
(Unaudited)
  June 30,December 31,
  2021 2020
CURRENT ASSETS    
Cash and Cash Equivalents$0.1 $0.1 
Restricted Cash
(June 30, 2021 and December 31, 2020 Amounts Include $27.9 and $28.7, Respectively, Related to Transition Funding and Restoration Funding)		27.9 28.7 
Advances to Affiliates54.3 7.1 
Accounts Receivable:   
Customers 141.7 112.8 
Affiliated Companies 6.9 5.1 
Accrued Unbilled Revenues82.9 65.8 
Miscellaneous 0.1 0 
Allowance for Uncollectible Accounts(4.2)(0.1)
Total Accounts Receivable 227.4 183.6 
Materials and Supplies 69.5 70.0 
Accrued Tax Benefits4.5 16.8 
Prepayments and Other Current Assets 4.3 4.6 
TOTAL CURRENT ASSETS 388.0 310.9 
 
PROPERTY, PLANT AND EQUIPMENT   
Electric:   
Transmission 5,571.9 5,279.6 
Distribution 4,750.8 4,580.8 
Other Property, Plant and Equipment 908.9 868.4 
Construction Work in Progress 510.0 614.1 
Total Property, Plant and Equipment 11,741.6 11,342.9 
Accumulated Depreciation and Amortization 1,588.9 1,529.3 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 10,152.7 9,813.6 
 
OTHER NONCURRENT ASSETS   
Regulatory Assets 292.0 266.8 
Securitized Assets
(June 30, 2021 and December 31, 2020 Amounts Include $410.4 and $446.8, Respectively, Related to Transition Funding and Restoration Funding)
410.4 446.8 
Deferred Charges and Other Noncurrent Assets 240.7 192.1 
TOTAL OTHER NONCURRENT ASSETS 943.1 905.7 
 
TOTAL ASSETS $11,483.8 $11,030.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
66
  March 31, December 31,
  2018 2017
CURRENT ASSETS    
Cash and Cash Equivalents $0.1
 $2.0
Restricted Cash for Securitized Transition Funding 107.1
 155.2
Advances to Affiliates 8.1
 111.9
Accounts Receivable:    
Customers 117.7
 105.3
Affiliated Companies 9.0
 12.3
Accrued Unbilled Revenues 65.7
 75.8
Miscellaneous 0.3
 1.3
Allowance for Uncollectible Accounts (0.5) (0.7)
Total Accounts Receivable 192.2
 194.0
Fuel 6.4
 3.6
Materials and Supplies 49.4
 52.0
Risk Management Assets 0.3
 0.5
Accrued Tax Benefits 66.4
 41.0
Prepayments and Other Current Assets 5.8
 3.6
TOTAL CURRENT ASSETS 435.8
 563.8
     
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Generation 350.9
 350.7
Transmission 3,097.6
 3,053.6
Distribution 3,854.2
 3,718.6
Other Property, Plant and Equipment 475.4
 461.0
Construction Work in Progress 951.6
 835.7
Total Property, Plant and Equipment 8,729.7
 8,419.6
Accumulated Depreciation and Amortization 1,617.4
 1,594.5
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 7,112.3
 6,825.1
     
OTHER NONCURRENT ASSETS    
Regulatory Assets 379.4
 378.7
Securitized Transition Assets
(March 31, 2018 and December 31, 2017 Amounts Include $819.2 and $869.5, Respectively, Related to Transition Funding)
 838.9
 891.2
Deferred Charges and Other Noncurrent Assets 134.0
 114.8
TOTAL OTHER NONCURRENT ASSETS 1,352.3
 1,384.7
     
TOTAL ASSETS $8,900.4
 $8,773.6


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.





AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
March 31, 2018June 30, 2021 and December 31, 20172020
(in millions)
(Unaudited)
  June 30,December 31,
  2021 2020
CURRENT LIABILITIES 
Advances from Affiliates $0 $67.1 
Accounts Payable: 
General 185.8 231.7 
Affiliated Companies 31.1 44.0 
Long-term Debt Due Within One Year – Nonaffiliated
(June 30, 2021 and December 31, 2020 Amounts Include $89.8 and $88.7, Respectively, Related to Transition Funding and Restoration Funding)
289.9 88.7 
Accrued Taxes 113.4 78.3 
Accrued Interest
(June 30, 2021 and December 31, 2020 Amounts Include $2.4 and $2.5, Respectively, Related to Transition Funding and Restoration Funding)
46.2 43.9 
Obligations Under Operating Leases14.2 14.5 
Other Current Liabilities 78.5 108.6 
TOTAL CURRENT LIABILITIES 759.1 676.8 
 
NONCURRENT LIABILITIES   
Long-term Debt – Nonaffiliated
(June 30, 2021 and December 31, 2020 Amounts Include $362.3 and $403.9, Respectively, Related to Transition Funding and Restoration Funding)
4,936.1 4,731.7 
Deferred Income Taxes 1,045.9 1,016.7 
Regulatory Liabilities and Deferred Investment Tax Credits 1,273.6 1,270.8 
Obligations Under Operating Leases67.7 71.0 
Deferred Credits and Other Noncurrent Liabilities 68.9 57.2 
TOTAL NONCURRENT LIABILITIES 7,392.2 7,147.4 
 
TOTAL LIABILITIES 8,151.3 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 1,882.9 1,757.0 
Accumulated Other Comprehensive Income (Loss)(8.3)(8.9)
TOTAL COMMON SHAREHOLDER’S EQUITY 3,332.5 3,206.0 
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $11,483.8 $11,030.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
67
  March 31, December 31,
  2018 2017
CURRENT LIABILITIES    
Advances from Affiliates $232.7
 $—
Accounts Payable:    
General 209.0
 379.4
Affiliated Companies 22.7
 30.2
Long-term Debt Due Within One Year – Nonaffiliated
(March 31, 2018 and December 31, 2017 Amounts Include $243.1 and $236.1, Respectively, Related to Transition Funding)
 273.1
 266.1
Accrued Taxes 89.7
 77.2
Accrued Interest
(March 31, 2018 and December 31, 2017 Amounts Include $10.2 and $15.9, Respectively, Related to Transition Funding)
 48.0
 42.2
Other Current Liabilities 70.7
 76.4
TOTAL CURRENT LIABILITIES 945.9
 871.5
     
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated
(March 31, 2018 and December 31, 2017 Amounts Include $686.8 and $790.1, Respectively, Related to Transition Funding)
 3,280.2
 3,383.2
Deferred Income Taxes 913.1
 913.1
Regulatory Liabilities and Deferred Investment Tax Credits 1,320.2
 1,320.5
Oklaunion Purchase Power Agreement 51.8
 52.0
Deferred Credits and Other Noncurrent Liabilities 73.1
 63.4
TOTAL NONCURRENT LIABILITIES 5,638.4
 5,732.2
     
TOTAL LIABILITIES 6,584.3
 6,603.7
     
Rate Matters (Note 4) 
 
Commitments and Contingencies (Note 5) 
 
     
COMMON SHAREHOLDER’S EQUITY    
Paid-in Capital 1,157.9
 1,057.9
Retained Earnings 1,173.2
 1,124.6
Accumulated Other Comprehensive Income (Loss) (15.0) (12.6)
TOTAL COMMON SHAREHOLDER’S EQUITY 2,316.1
 2,169.9
     
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $8,900.4
 $8,773.6


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.





AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the ThreeSix Months Ended March 31, 2018June 30, 2021 and 20172020
(in millions)
(Unaudited)
  Six Months Ended June 30,
  2021 2020
OPERATING ACTIVITIES    
Net Income $125.9 $114.5 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:   
Depreciation and Amortization 199.5 328.1 
Deferred Income Taxes 14.0 (33.9)
Allowance for Equity Funds Used During Construction(7.5)(10.0)
Mark-to-Market of Risk Management Contracts 0 0.1 
Property Taxes(49.7)(43.2)
Change in Other Noncurrent Assets (42.0)(54.1)
Change in Other Noncurrent Liabilities 17.2 (2.5)
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net (43.8)(54.1)
Fuel, Materials and Supplies 0.5 (11.4)
Accounts Payable (10.3)22.1 
Accrued Taxes, Net47.4 79.3 
Other Current Assets 0.7 1.6 
Other Current Liabilities (29.3)(38.7)
Net Cash Flows from Operating Activities 222.6 297.8 
 
INVESTING ACTIVITIES   
Construction Expenditures (531.2)(662.0)
Change in Advances to Affiliates, Net(47.2)200.0 
Other Investing Activities21.3 17.1 
Net Cash Flows Used for Investing Activities (557.1)(444.9)
 
FINANCING ACTIVITIES   
Issuance of Long-term Debt – Nonaffiliated444.3 0 
Change in Short-term Debt, Net – Nonaffiliated0 2.0 
Change in Advances from Affiliates, Net (67.1)320.4 
Retirement of Long-term Debt – Nonaffiliated (40.9)(193.8)
Principal Payments for Finance Lease Obligations (3.3)(3.1)
Other Financing Activities0.7 0.5 
Net Cash Flows from Financing Activities 333.7 126.0 
Net Decrease in Cash, Cash Equivalents and Restricted Cash (0.8)(21.1)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period 28.8 157.8 
Cash, Cash Equivalents and Restricted Cash at End of Period $28.0 $136.7 
 
SUPPLEMENTARY INFORMATION   
Cash Paid for Interest, Net of Capitalized Amounts $82.0 $74.3 
Net Cash Paid (Received) for Income Taxes (9.2)(24.9)
Noncash Acquisitions Under Finance Leases 2.4 4.3 
Construction Expenditures Included in Current Liabilities as of June 30, 125.5 192.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
68
  Three Months Ended March 31,
  2018 2017
OPERATING ACTIVITIES  
  
Net Income $46.8
 $33.3
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
Depreciation and Amortization 110.0
 102.8
Deferred Income Taxes (4.4) 40.8
Allowance for Equity Funds Used During Construction (5.5) (1.8)
Mark-to-Market of Risk Management Contracts 0.2
 0.1
Property Taxes (56.1) (46.2)
Change in Other Noncurrent Assets (12.7) (12.7)
Change in Other Noncurrent Liabilities 6.5
 4.8
Changes in Certain Components of Working Capital:  
  
Accounts Receivable, Net 1.8
 3.7
Fuel, Materials and Supplies (0.2) 0.4
Accounts Payable (25.9) (13.4)
Accrued Taxes, Net 25.2
 (3.5)
Other Current Assets (1.6) (0.3)
Other Current Liabilities (5.1) (25.9)
Net Cash Flows from Operating Activities 79.0
 82.1
     
INVESTING ACTIVITIES  
  
Construction Expenditures (481.6) (200.2)
Change in Advances to Affiliates, Net 103.8
 0.3
Other Investing Activities 13.4
 4.6
Net Cash Flows Used for Investing Activities (364.4) (195.3)
     
FINANCING ACTIVITIES  
  
Capital Contribution from Parent 100.0
 200.0
Change in Advances from Affiliates, Net 232.7
 (43.0)
Retirement of Long-term Debt – Nonaffiliated (96.5) (89.9)
Principal Payments for Capital Lease Obligations (1.1) (0.9)
Other Financing Activities 0.3
 0.6
Net Cash Flows from Financing Activities 235.4
 66.8
     
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding (50.0) (46.4)
Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding at Beginning of Period 157.2
 146.9
Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding at End of Period $107.2
 $100.5
     
SUPPLEMENTARY INFORMATION    
Cash Paid for Interest, Net of Capitalized Amounts $27.8
 $33.7
Noncash Acquisitions Under Capital Leases 4.0
 2.0
Construction Expenditures Included in Current Liabilities as of March 31, 169.3
 65.5




See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.





AEP TRANSMISSION COMPANY, LLC
AND SUBSIDIARIES

69






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


RESULTS OF OPERATIONS


Summary of Investment in Transmission Assets for AEPTCo
As of June 30,
20212020
(in millions)
Plant In Service$10,660.2 $8,931.5 
Construction Work in Progress1,393.4 1,613.9 
Accumulated Depreciation and Amortization677.1 488.3 
Total Transmission Property, Net$11,376.5 $10,057.1 
  As of March 31,
  2018 2017
  (in millions)
Plant In Service $5,595.4
 $4,162.3
Construction Work in Progress 1,512.6
 1,184.4
Accumulated Depreciation and Amortization 192.7
 117.8
Total Transmission Property, Net $6,915.3
 $5,228.9


FirstSecond Quarter of 20182021 Compared to FirstSecond Quarter of 20172020
AEP Transmission Company, LLC and Subsidiaries
Reconciliation of Second Quarter of 2020 to Second Quarter of 2021
Net Income
(in millions)
Second Quarter of 2020$73.7 
Changes in Transmission Revenues:
Transmission Revenues127.4 
Total Change in Transmission Revenues127.4 
Changes in Expenses and Other:
Other Operation and Maintenance(4.7)
Depreciation and Amortization(13.5)
Taxes Other Than Income Taxes(9.9)
Interest Income(1.2)
Allowance for Equity Funds Used During Construction(1.9)
Interest Expense(1.5)
Total Change in Expenses and Other(32.7)
Income Tax Expense(19.8)
Second Quarter of 2021$148.6 
Reconciliation of First Quarter of 2017 to First Quarter of 2018
Net Income
(in millions)
 
First Quarter of 2017 $57.0
   
Changes in Transmission Revenues:  
Transmission Revenues 40.8
Total Change in Transmission Revenues 40.8
   
Changes in Expenses and Other:  
Other Operation and Maintenance (7.0)
Depreciation and Amortization (7.3)
Taxes Other Than Income Taxes (4.3)
Interest Income 0.2
Allowance for Equity Funds Used During Construction 4.4
Interest Expense (3.9)
Total Change in Expenses and Other (17.9)
   
Income Tax Expense 6.0
   
First Quarter of 2018 $85.9


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


•Transmission Revenues increased $41$127 million primarily due to the following:
Formula rate increases of $60•A $68 million driven byincrease due to continued investment in transmission assets.
This•A $45 million increase was partially offset by:
A $19 million decrease due toas a result of the 2018 provisions for customer refunds primarily related to Tax Reform.
This decreaseaffiliated annual transmission formula rate true-up which is offset in Income Tax Expense below.Other Operation and Maintenance expense across the other Registrant Subsidiaries.

•A $14 million increase as a result of the non-affiliated annual transmission formula rate true-up.

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


•Other Operation and Maintenance expenses increased $7$5 million primarily due to increased transmission investment.
to:
•A $3 million increase in vegetation management expenses.
•A $2 million increase in employee-related expenses.
•Depreciation and Amortization expenses increased $7$14 million primarily due to a higher depreciable base.
70






•Taxes Other Than Income Taxes increased $4$10 million primarily due to higher property taxes as a result of increased transmission investment.
Allowance for Equity Funds Used During Construction•Income Tax Expense increased $4$20 million primarily due to an increase in pretax book income.
71




Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020
AEP Transmission Company, LLC and Subsidiaries
Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30, 2021
Net Income
(in millions)
Six Months Ended June 30, 2020$191.5 
Changes in Transmission Revenues:
Transmission Revenues193.5 
Total Change in Transmission Revenues193.5 
Changes in Expenses and Other:
Other Operation and Maintenance(2.4)
Depreciation and Amortization(28.1)
Taxes Other Than Income Taxes(17.3)
Interest Income(1.9)
Allowance for Equity Funds Used During Construction(1.4)
Interest Expense(6.0)
Total Change in Expenses and Other(57.1)
Income Tax Expense(27.6)
Six Months Ended June 30, 2021$300.3 

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

•Transmission Revenues increased $194 million primarily due to the following:
•A $135 million increase due to continued investment in transmission investment resultingassets.
•A $45 million increase as a result of the affiliated annual transmission formula rate true-up which is offset in Other Operation and Maintenance expense across the other Registrant Subsidiaries.
•A $14 million increase as a result of the non-affiliated annual transmission formula rate true-up.

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

•Depreciation and Amortization expenses increased $28 million primarily due to a higher CWIP balance.
depreciable base.
Interest Expense•Taxes Other Than Income Taxes increased $4$17 million primarily due to higher outstanding long-term debt balances.
property taxes as a result of increased transmission investment.
Income Tax•Interest Expense decreased increased $6 million primarily due to the change in the corporate federal income tax rate from 35% in 2017higher long-term debt balances.
•Income Tax Expense increased $28 million primarily due to 21% in 2018 as a result of Tax Reform, partially offset by an increase in pretax book income.

72









AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended March 31, 2018June 30, 2021 and 20172020
(in millions)
(Unaudited)
Three Months EndedSix Months Ended
June 30,June 30,
2021 2020 2021 2020
REVENUES
Transmission Revenues$84.1 $60.4 $160.1 $121.7 
Sales to AEP Affiliates281.4 177.7 567.0 411.4 
Other Revenues0 0 0.1 0.6 
TOTAL REVENUES365.5 238.1 727.2 533.7 
EXPENSES    
Other Operation24.4 22.9 45.5 46.7 
Maintenance3.3 0.1 6.9 3.3 
Depreciation and Amortization72.4 58.9 143.0 114.9 
Taxes Other Than Income Taxes60.1 50.2 117.9 100.6 
TOTAL EXPENSES160.2 132.1 313.3 265.5 
OPERATING INCOME205.3 106.0 413.9 268.2 
Other Income (Expense):    
Interest Income - Affiliated0.1 1.3 0.2 2.1 
Allowance for Equity Funds Used During Construction16.6 18.5 33.3 34.7 
Interest Expense(34.3)(32.8)(68.4)(62.4)
INCOME BEFORE INCOME TAX EXPENSE187.7 93.0 379.0 242.6 
Income Tax Expense39.1 19.3 78.7 51.1 
NET INCOME$148.6 $73.7 $300.3 $191.5 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
73
  Three Months Ended March 31,
  2018 2017
REVENUES    
Transmission Revenues $31.3
 $19.2
Sales to AEP Affiliates 162.1
 133.4
Other Revenues 0.1
 0.1
TOTAL REVENUES 193.5
 152.7
     
EXPENSES    
Other Operation 16.6
 9.1
Maintenance 2.6
 3.1
Depreciation and Amortization 30.6
 23.3
Taxes Other Than Income Taxes 31.1
 26.8
TOTAL EXPENSES 80.9
 62.3
     
OPERATING INCOME 112.6
 90.4
     
Other Income (Expense):    
Interest Income 0.4
 0.2
Allowance for Equity Funds Used During Construction 15.3
 10.9
Interest Expense (19.9) (16.0)
     
INCOME BEFORE INCOME TAX EXPENSE 108.4
 85.5
     
Income Tax Expense 22.5
 28.5
     
NET INCOME $85.9
 $57.0


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.




AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
MEMBER’S EQUITY
For the ThreeSix Months Ended March 31, 2018June 30, 2021 and 20172020
(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, 20202,665.6 1,646.7 4,312.3 
Dividends Paid to Member(5.0)(5.0)
Net Income73.7 73.7 
TOTAL MEMBER'S EQUITY – JUNE 30, 2020$2,665.6 $1,715.4 $4,381.0 
  
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, 20212,889.6 2,099.0 4,988.6 
  
Capital Contribution from Member60.0 60.0 
Net Income148.6 148.6 
TOTAL MEMBER'S EQUITY – JUNE 30, 2021$2,949.6 $2,247.6 $5,197.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
74
  
Paid-in
Capital
 
Retained
Earnings
 Total Member’s Equity
TOTAL MEMBER’S EQUITY – DECEMBER 31, 2016 $1,455.0
 $502.6
 $1,957.6
       
Capital Contributions from Member 125.5
   125.5
Net Income   57.0
 57.0
TOTAL MEMBER’S EQUITY – MARCH 31, 2017 $1,580.5
 $559.6
 $2,140.1
       
TOTAL MEMBER’S EQUITY – DECEMBER 31, 2017 $1,816.6
 $788.7
 $2,605.3
       
Capital Contributions from Member 65.0
   65.0
Net Income   85.9
 85.9
TOTAL MEMBER’S EQUITY – MARCH 31, 2018 $1,881.6
 $874.6
 $2,756.2


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.




AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2018June 30, 2021 and December 31, 20172020
(in millions)
(Unaudited)
  June 30, December 31,
  2021 2020
CURRENT ASSETS    
Advances to Affiliates $113.6 $109.1 
Accounts Receivable: 
Customers 29.7 22.9 
Affiliated Companies 96.6 81.2 
Total Accounts Receivable 126.3 104.1 
Materials and Supplies 9.0 8.5 
Prepayments and Other Current Assets 14.6 14.1 
TOTAL CURRENT ASSETS 263.5 235.8 
 
TRANSMISSION PROPERTY   
Transmission Property 10,278.7 9,593.5 
Other Property, Plant and Equipment 381.5 329.5 
Construction Work in Progress 1,393.4 1,422.6 
Total Transmission Property 12,053.6 11,345.6 
Accumulated Depreciation and Amortization 677.1 572.8 
TOTAL TRANSMISSION PROPERTY – NET 11,376.5 10,772.8 
 
OTHER NONCURRENT ASSETS   
Regulatory Assets 14.8 15.1 
Deferred Property Taxes 126.8 220.1 
Deferred Charges and Other Noncurrent Assets 8.7 2.2 
TOTAL OTHER NONCURRENT ASSETS 150.3 237.4 
 
TOTAL ASSETS $11,790.3 $11,246.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
75
  March 31, December 31,
  2018 2017
CURRENT ASSETS    
Advances to Affiliates $32.1
 $146.3
Accounts Receivable:    
Customers 20.5
 19.1
Affiliated Companies 102.0
 93.2
Miscellaneous 1.2
 1.3
Total Accounts Receivable 123.7
 113.6
Materials and Supplies 15.5
 13.6
Accrued Tax Benefits 40.1
 46.6
Prepayments and Other Current Assets 2.8
 7.6
TOTAL CURRENT ASSETS 214.2
 327.7
     
TRANSMISSION PROPERTY    
Transmission Property 5,458.3
 5,336.1
Other Property, Plant and Equipment 137.1
 131.4
Construction Work in Progress 1,512.6
 1,312.7
Total Transmission Property 7,108.0
 6,780.2
Accumulated Depreciation and Amortization 192.7
 170.4
TOTAL TRANSMISSION PROPERTY – NET
 6,915.3
 6,609.8
     
OTHER NONCURRENT ASSETS    
Regulatory Assets 8.9
 11.7
Deferred Property Taxes 100.5
 117.8
Deferred Charges and Other Noncurrent Assets 1.0
 1.1
TOTAL OTHER NONCURRENT ASSETS 110.4
 130.6
     
TOTAL ASSETS $7,239.9
 $7,068.1


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.




AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND MEMBER’S EQUITY
March 31, 2018June 30, 2021 and December 31, 20172020
(in millions)
(Unaudited)
  June 30, December 31,
  2021 2020
CURRENT LIABILITIES    
Advances from Affiliates $265.3 $156.7 
Accounts Payable:  
General 368.4 380.4 
Affiliated Companies 70.7 97.3 
Long-term Debt Due Within One Year – Nonaffiliated50.0 50.0 
Accrued Taxes 313.4 418.1 
Accrued Interest 23.9 23.9 
Obligations Under Operating Leases0.9 1.2 
Other Current Liabilities 10.5 9.9 
TOTAL CURRENT LIABILITIES 1,103.1 1,137.5 
 
NONCURRENT LIABILITIES   
Long-term Debt – Nonaffiliated 3,899.3 3,898.5 
Deferred Income Taxes 958.9 906.9 
Regulatory Liabilities 620.4 581.8 
Obligations Under Operating Leases0.7 0.4 
Deferred Credits and Other Noncurrent Liabilities 10.7 8.0 
TOTAL NONCURRENT LIABILITIES 5,490.0 5,395.6 
 
TOTAL LIABILITIES 6,593.1 6,533.1 
 
Rate Matters (Note 4) 00
Commitments and Contingencies (Note 5) 00
 
MEMBER’S EQUITY   
Paid-in Capital2,949.6 2,765.6 
Retained Earnings 2,247.6 1,947.3 
TOTAL MEMBER’S EQUITY 5,197.2 4,712.9 
 
TOTAL LIABILITIES AND MEMBER’S EQUITY $11,790.3 $11,246.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
76
  March 31, December 31,
  2018 2017
   
CURRENT LIABILITIES    
Advances from Affiliates $282.1
 $15.7
Accounts Payable:    
General 210.5
 473.2
Affiliated Companies 41.3
 52.9
Long-term Debt Due Within One Year – Nonaffiliated 50.0
 50.0
Accrued Taxes 185.3
 225.4
Accrued Interest 38.3
 15.0
Provision for Refund 47.6
 —
Other Current Liabilities 2.6
 4.1
TOTAL CURRENT LIABILITIES 857.7
 836.3
     
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated 2,500.7
 2,500.4
Deferred Income Taxes 621.3
 601.7
Regulatory Liabilities 497.2
 493.7
Deferred Credits and Other Noncurrent Liabilities 6.8
 30.7
TOTAL NONCURRENT LIABILITIES 3,626.0
 3,626.5
     
TOTAL LIABILITIES 4,483.7
 4,462.8
     
Rate Matters (Note 4) 

 

Commitments and Contingencies (Note 5) 

 

     
MEMBER’S EQUITY    
Paid-in Capital 1,881.6
 1,816.6
Retained Earnings 874.6
 788.7
TOTAL MEMBER’S EQUITY 2,756.2
 2,605.3
     
TOTAL LIABILITIES AND MEMBER’S EQUITY $7,239.9
 $7,068.1


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.




AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the ThreeSix Months Ended March 31, 2018June 30, 2021 and 20172020
(in millions)
(Unaudited)
  Six Months Ended June 30,
  20212020
OPERATING ACTIVITIES 
Net Income $300.3 $191.5 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: 
Depreciation and Amortization 143.0 114.9 
Deferred Income Taxes 55.5 22.6 
Allowance for Equity Funds Used During Construction (33.3)(34.7)
Property Taxes 93.3 84.3 
Change in Other Noncurrent Assets (4.5)(2.6)
Change in Other Noncurrent Liabilities 10.5 30.6 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net (22.2)(74.7)
Materials and Supplies(0.5)0.4 
Accounts Payable 0.1 10.5 
Accrued Taxes, Net (106.2)(54.7)
Other Current Assets 0.7 0.5 
Other Current Liabilities (1.5)4.5 
Net Cash Flows from Operating Activities 435.2 293.1 
 
INVESTING ACTIVITIES   
Construction Expenditures (719.7)(825.4)
Change in Advances to Affiliates, Net (4.5)(35.9)
Other Investing Activities (3.4)1.8 
Net Cash Flows Used for Investing Activities (727.6)(859.5)
 
FINANCING ACTIVITIES  
Capital Contributions from Member 184.0 185.0 
Issuance of Long-term Debt – Nonaffiliated0 519.4 
Change in Advances from Affiliates, Net 108.6 (133.0)
Dividends Paid to Member0 (5.0)
Other Financing Activities(0.2)0 
Net Cash Flows from Financing Activities 292.4 566.4 
 
Net Change in Cash and Cash Equivalents 0 0 
Cash and Cash Equivalents at Beginning of Period 0 0 
Cash and Cash Equivalents at End of Period $0 $0 
 
SUPPLEMENTARY INFORMATION   
Cash Paid for Interest, Net of Capitalized Amounts $66.6 $55.8 
Net Cash Paid for Income Taxes 21.6 13.5 
Construction Expenditures Included in Current Liabilities as of June 30, 267.9 263.8 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
77
  Three Months Ended March 31,
  2018 2017
OPERATING ACTIVITIES    
Net Income $85.9
 $57.0
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
Depreciation and Amortization 30.6
 23.3
Deferred Income Taxes 15.7
 74.1
Allowance for Equity Funds Used During Construction (15.3) (10.9)
Property Taxes 17.3
 16.8
Change in Other Noncurrent Assets 2.7
 2.2
Change in Other Noncurrent Liabilities 23.9
 8.3
Changes in Certain Components of Working Capital:    
Accounts Receivable, Net (10.1) (39.0)
Materials and Supplies (1.9) (3.8)
Accounts Payable (12.3) (8.2)
Accrued Taxes, Net (33.6) (79.1)
Accrued Interest 23.3
 17.6
Other Current Assets 0.3
 0.2
Other Current Liabilities 0.6
 —
Net Cash Flows from Operating Activities 127.1
 58.5
     
INVESTING ACTIVITIES    
Construction Expenditures (571.8) (390.4)
Change in Advances to Affiliates, Net 114.2
 56.9
Acquisitions of Assets (1.8) (0.6)
Other Investing Activities 1.0
 —
Net Cash Flows Used for Investing Activities (458.4) (334.1)
     
FINANCING ACTIVITIES    
Capital Contributions from Member 65.0
 125.5
Change in Advances from Affiliates, Net 266.4
 150.9
Other Financing Activities (0.1) (0.8)
Net Cash Flows from Financing Activities 331.3
 275.6
     
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    
Net Cash Paid (Received) for Income Taxes $—
 $(0.6)
Construction Expenditures Included in Current Liabilities as of March 31, 210.6
 189.2




See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.




APPALACHIAN POWER COMPANY
AND SUBSIDIARIES

78





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


RESULTS OF OPERATIONS


KWh Sales/Degree Days


Summary of KWh Energy Sales
 Three Months EndedSix Months Ended
 June 30,June 30,
2021202020212020
 (in millions of KWhs)
Retail:    
Residential2,172 2,288 5,867 5,457 
Commercial1,430 1,321 2,887 2,798 
Industrial2,289 2,077 4,367 4,314 
Miscellaneous196 175 396 382 
Total Retail6,087 5,861 13,517 12,951 
Wholesale1,274 1,235 2,222 1,707 
Total KWhs7,361 7,096 15,739 14,658 
 Three Months Ended March 31,
 2018 2017
 (in millions of KWhs)
Retail: 
  
Residential3,845
 3,250
Commercial1,694
 1,591
Industrial2,377
 2,299
Miscellaneous224
 210
Total Retail8,140
 7,350
    
Wholesale495
 806
    
Total KWhs8,635
 8,156


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


Summary of Heating and Cooling Degree Days
 Three Months EndedSix Months Ended
 June 30,June 30,
2021202020212020
 (in degree days)
Actual – Heating (a)113 144 1,397 1,097 
Normal – Heating (b)87 87 1,402 1,411 
Actual – Cooling (c)381 346 385 366 
Normal – Cooling (b)377 377 383 383 
 Three Months Ended March 31,
 2018 2017
 (in degree days)
Actual – Heating (a)1,389
 955
Normal – Heating (b)1,317
 1,328
    
Actual – Cooling (c)8
 2
Normal – Cooling (b)7
 7


(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.



79

First


Second Quarter of 20182021 Compared to FirstSecond Quarter of 20172020
Appalachian Power Company and Subsidiaries
Reconciliation of Second Quarter of 2020 to Second Quarter of 2021
Net Income
(in millions)
Second Quarter of 2020$81.3 
Changes in Gross Margin:
Retail Margins21.4 
Margins from Off-system Sales1.3 
Transmission Revenues7.2 
Other Revenues0.8 
Total Change in Gross Margin30.7 
Changes in Expenses and Other:
Other Operation and Maintenance(13.6)
Depreciation and Amortization(14.8)
Taxes Other Than Income Taxes(1.7)
Interest Income(0.2)
Allowance for Equity Funds Used During Construction1.9 
Non-Service Cost Components of Net Periodic Benefit Cost0.1 
Interest Expense1.2 
Total Change in Expenses and Other(27.1)
Income Tax Expense(18.6)
Second Quarter of 2021$66.3 
Reconciliation of First Quarter of 2017 to First Quarter of 2018
Net Income
(in millions)
 
First Quarter of 2017 $110.6
   
Changes in Gross Margin:  
Retail Margins 15.0
Off-system Sales (0.2)
Transmission Revenues (1.9)
Other Revenues (2.2)
Total Change in Gross Margin 10.7
   
Changes in Expenses and Other:  
Other Operation and Maintenance (25.1)
Depreciation and Amortization (7.9)
Taxes Other Than Income Taxes (3.6)
Carrying Costs Income 0.2
Allowance for Equity Funds Used During Construction 1.1
Non-Service Cost Components of Net Periodic Benefit Cost 3.2
Interest Expense 0.7
Total Change in Expenses and Other (31.4)
   
Income Tax Expense 35.6
   
First Quarter of 2018 $125.5


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 $15$21 million primarily due to the following:
•A $50$12 million increase in weather-related usage primarily due to a 45% increaseweather-normalized margins driven by increases in heating degree days.
An $11 million increase primarily due to increases from rate riders in Virginia. This increase isthe commercial and industrial classes, partially offset by a corresponding increase in Other Operation and Maintenance expenses.
These increases were partially offset by:
A $32 million decrease due to the 2018 provisions for customer refunds primarily related to Tax Reform.  This decrease is offset in Income Tax Expense below.
A $5 million decrease in weather-normalized margins occurring primarily in the residential and industrial classes.class.
•A $4$9 million decreaseincrease due to rider revenues primarily in West Virginia. This increase was partially offset in other expense items below.
•Transmission Revenuesincreased fuel$7 million primarily due to an increase in transmission investment. This increase was partially offset in Depreciation and other variable production costs not recovered through fuel or other trackers.Amortization expenses below.





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


•Other Operation and Maintenance expenses increased $25$14 million primarily due to the following:
•A $12$13 million increase in PJM transmission expenses as a result of the annual transmission formula rate true-up. This increase was partially offset in Retail Margins above.
•A $3 million increase in recoverable PJM transmission expenses. This increase iswas partially offset withinin Retail Margins above.
•A $5$2 million increase in estimatedtransmission vegetation management expenses.
These increases were partially offset by:
•A $6 million decrease in accretion expense for claims relateddue to asbestos exposure.the deferral of incremental Glen Lyn ash pond ARO expense.
A $4•Depreciation and Amortization expenses increased $15 million primarily due to an increase in employee-related expenses.depreciation rates in Virginia and a higher depreciable base. This increase was partially offset in Transmission Revenues above.
Depreciation and Amortization expenses •Income Tax Expense increased $8$19 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $4 million primarily due to the following:
A $2 milliondecrease in amortization of Excess ADIT. This increase in property taxes driven by an increase in utility plant.
A $2 million increase in state gross receipts tax due to a prior period refund.
Non-Service Cost Components of Net Periodic Cost decreased $3 million primarily due to favorable asset returns for the funded Pension and OPEB plans and by moving to a Medicare Advantage arrangement for post-65 retirees in the Non-UMWA OPEB plan. Additionally, the decrease was partially due to the implementation of ASU 2017-07offset in 2018, which eliminated APCo’s ability to capitalize a portion of its non-service cost components.Gross Margin above.
80
Income Tax Expense decreased $36 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and a decrease in pretax book income.







APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the ThreeSix Months Ended March 31, 2018 and 2017
(in millions)
(Unaudited)
  Three Months Ended March 31,
  2018 2017
REVENUES    
Electric Generation, Transmission and Distribution $767.5
 $745.0
Sales to AEP Affiliates 49.4
 42.4
Other Revenues 3.5
 5.4
TOTAL REVENUES 820.4
 792.8
     
EXPENSES  
  
Fuel and Other Consumables Used for Electric Generation 69.0
 167.2
Purchased Electricity for Resale 205.9
 90.8
Other Operation 138.2
 113.9
Maintenance 72.0
 71.2
Depreciation and Amortization 108.5
 100.6
Taxes Other Than Income Taxes 33.8
 30.2
TOTAL EXPENSES 627.4
 573.9
     
OPERATING INCOME 193.0
 218.9
     
Other Income (Expense):  
  
Interest Income 0.3
 0.3
Carrying Costs Income 0.5
 0.3
Allowance for Equity Funds Used During Construction 2.6
 1.5
Non-Service Cost Components of Net Periodic Benefit Cost 4.5
 1.3
Interest Expense (47.4) (48.1)
     
INCOME BEFORE INCOME TAX EXPENSE 153.5
 174.2
     
Income Tax Expense 28.0
 63.6
     
NET INCOME $125.5
 $110.6
June 30, 2021 Compared to Six Months Ended June 30, 2020
The common stock of APCo is wholly-owned by Parent.Appalachian Power Company and Subsidiaries
Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30, 2021
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.
Net Income




APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2018 and 2017
(in millions)
(Unaudited)
 Three Months Ended March 31,
 2018 2017
Net Income$125.5
 $110.6
    
OTHER COMPREHENSIVE LOSS, NET OF TAXES 
  
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) in 2018 and 2017, Respectively(0.2) (0.2)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.2) and $(0.2) in 2018 and 2017, Respectively(0.8) (0.3)
    
TOTAL OTHER COMPREHENSIVE LOSS(1.0) (0.5)
    
TOTAL COMPREHENSIVE INCOME$124.5
 $110.1
(in millions)
Six Months Ended June 30, 2020$196.6 
Changes in Gross Margin:
Retail Margins62.3 
Margins from Off-system Sales2.2 
Transmission Revenues14.2 
Other Revenues(0.8)
Total Change in Gross Margin77.9 
Changes in Expenses and Other:
Other Operation and Maintenance(44.9)
Depreciation and Amortization(28.4)
Taxes Other Than Income Taxes(1.5)
Interest Income(0.2)
Allowance for Equity Funds Used During Construction3.0 
See Condensed Notes to Condensed Financial StatementsNon-Service Cost Components of Registrants beginning on page 120.




APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Three Months Ended March 31, 2018 and 2017
(in millions)
(Unaudited)
  
Common
Stock
 
Paid-in
Capital
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2016 $260.4
 $1,828.7
 $1,502.8
 $(8.4) $3,583.5
           
Common Stock Dividends  
  
 (30.0)  
 (30.0)
Net Income  
  
 110.6
  
 110.6
Other Comprehensive Loss  
  
  
 (0.5) (0.5)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2017 $260.4
 $1,828.7
 $1,583.4
 $(8.9) $3,663.6
           
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017 $260.4
 $1,828.7
 $1,714.1
 $1.3
 $3,804.5
           
Common Stock Dividends  
  
 (40.0)  
 (40.0)
ASU 2018-02 Adoption     0.1
 0.3
 0.4
Net Income  
  
 125.5
  
 125.5
Other Comprehensive Loss  
  
  
 (1.0) (1.0)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018 $260.4
 $1,828.7
 $1,799.7
 $0.6
 $3,889.4
Net Periodic Benefit Cost0.1 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.





APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2018 and December 31, 2017
(in millions)
(Unaudited)
  March 31, December 31,
  2018 2017
CURRENT ASSETS    
Cash and Cash Equivalents $1.2
 $2.9
Restricted Cash for Securitized Funding 10.1
 16.3
Advances to Affiliates 23.5
 23.5
Accounts Receivable:    
Customers 137.9
 123.1
Affiliated Companies 67.6
 69.3
Accrued Unbilled Revenues 75.1
 74.1
Miscellaneous 1.0
 1.1
Allowance for Uncollectible Accounts (3.5) (3.7)
Total Accounts Receivable 278.1
 263.9
Fuel 72.1
 89.3
Materials and Supplies 97.4
 99.5
Risk Management Assets 8.0
 24.9
Regulatory Asset for Under-Recovered Fuel Costs 179.5
 88.8
Margin Deposits 32.1
 14.4
Prepayments and Other Current Assets 11.2
 12.7
TOTAL CURRENT ASSETS 713.2
 636.2
     
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Generation 6,466.9
 6,446.9
Transmission 3,032.5
 3,019.9
Distribution 3,795.8
 3,763.8
Other Property, Plant and Equipment 440.2
 427.9
Construction Work in Progress 558.8
 483.0
Total Property, Plant and Equipment 14,294.2
 14,141.5
Accumulated Depreciation and Amortization 3,956.8
 3,896.4
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 10,337.4
 10,245.1
     
OTHER NONCURRENT ASSETS    
Regulatory Assets 552.3
 573.9
Securitized Assets 276.4
 282.3
Long-term Risk Management Assets 2.6
 1.1
Deferred Charges and Other Noncurrent Assets 195.1
 190.0
TOTAL OTHER NONCURRENT ASSETS 1,026.4
 1,047.3
     
TOTAL ASSETS $12,077.0
 $11,928.6
Interest Expense(0.6)
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.




APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
March 31, 2018 and December 31, 2017
(Unaudited)
  March 31, December 31,
  2018 2017
  (in millions)
CURRENT LIABILITIES    
Advances from Affiliates $245.9
 $186.0
Accounts Payable:  
  
General 218.1
 264.9
Affiliated Companies 88.1
 92.7
Long-term Debt Due Within One Year – Nonaffiliated 249.5
 249.2
Risk Management Liabilities 0.6
 1.3
Customer Deposits 86.5
 86.1
Accrued Taxes 119.0
 94.5
Accrued Interest 62.9
 40.5
Other Current Liabilities 111.3
 109.0
TOTAL CURRENT LIABILITIES 1,181.9
 1,124.2
     
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated 3,719.8
 3,730.9
Long-term Risk Management Liabilities 0.4
 0.2
Deferred Income Taxes 1,586.0
 1,565.7
Regulatory Liabilities and Deferred Investment Tax Credits 1,444.3
 1,454.9
Asset Retirement Obligations 98.4
 100.2
Employee Benefits and Pension Obligations 68.6
 73.3
Deferred Credits and Other Noncurrent Liabilities 88.2
 74.7
TOTAL NONCURRENT LIABILITIES 7,005.7
 6,999.9
     
TOTAL LIABILITIES 8,187.6
 8,124.1
     
Rate Matters (Note 4) 
 
Commitments and Contingencies (Note 5) 
 
     
COMMON SHAREHOLDER’S EQUITY    
Common Stock – No Par Value:    
Authorized – 30,000,000 Shares  
  
Outstanding – 13,499,500 Shares 260.4
 260.4
Paid-in Capital 1,828.7
 1,828.7
Retained Earnings 1,799.7
 1,714.1
Accumulated Other Comprehensive Income (Loss) 0.6
 1.3
TOTAL COMMON SHAREHOLDER’S EQUITY 3,889.4
 3,804.5
     
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $12,077.0
 $11,928.6
Total Change in Expenses and Other(72.5)
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2018 and 2017
(in millions)
(Unaudited)
  Three Months Ended March 31,
  2018 2017
OPERATING ACTIVITIES  
  
Net Income $125.5
 $110.6
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
Depreciation and Amortization 108.5
 100.6
Deferred Income Taxes 11.0
 52.2
Allowance for Equity Funds Used During Construction (2.6) (1.5)
Mark-to-Market of Risk Management Contracts 14.9
 6.8
Deferred Fuel Over/Under-Recovery, Net (90.7) 1.1
Change in Other Noncurrent Assets 3.9
 1.0
Change in Other Noncurrent Liabilities 37.9
 (3.7)
Changes in Certain Components of Working Capital:  
  
Accounts Receivable, Net (14.2) (2.2)
Fuel, Materials and Supplies 19.3
 (6.9)
Accounts Payable (21.6) (12.7)
Accrued Taxes, Net 17.8
 9.4
Other Current Assets (15.8) 7.8
Other Current Liabilities 5.6
 (3.5)
Net Cash Flows from Operating Activities 199.5
 259.0
     
INVESTING ACTIVITIES  
  
Construction Expenditures (218.5) (223.7)
Change in Advances to Affiliates, Net —
 0.4
Other Investing Activities 4.4
 1.4
Net Cash Flows Used for Investing Activities (214.1) (221.9)
     
FINANCING ACTIVITIES  
  
Change in Advances from Affiliates, Net 59.9
 102.8
Retirement of Long-term Debt – Nonaffiliated (11.7) (115.9)
Principal Payments for Capital Lease Obligations (1.7) (1.8)
Dividends Paid on Common Stock (40.0) (30.0)
Other Financing Activities 0.2
 0.3
Net Cash Flows from (Used for) Financing Activities 6.7
 (44.6)
     
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding (7.9) (7.5)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period 19.2
 18.5
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period $11.3
 $11.0
     
SUPPLEMENTARY INFORMATION  
  
Cash Paid for Interest, Net of Capitalized Amounts $23.4
 $23.8
Noncash Acquisitions Under Capital Leases 1.8
 0.5
Construction Expenditures Included in Current Liabilities as of March 31, 94.5
 63.7
Income Tax Expense(13.2)
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.
Six Months Ended June 30, 2021$188.8 




INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES


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,
 2018 2017
 (in millions of KWhs)
Retail: 
  
Residential1,623
 1,492
Commercial1,176
 1,157
Industrial1,904
 1,896
Miscellaneous20
 20
Total Retail4,723
 4,565
    
Wholesale2,926
 2,954
    
Total KWhs7,649
 7,519

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,
 2018 2017
 (in degree days)
Actual – Heating (a)2,157
 1,648
Normal – Heating (b)2,168
 2,185
    
Actual – Cooling (c)—
 —
Normal – Cooling (b)2
 2

(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.



First Quarter of 2018 Compared to First Quarter of 2017
Reconciliation of First Quarter of 2017 to First Quarter of 2018
Net Income
(in millions)
   
First Quarter of 2017 $68.4
   
Changes in Gross Margin:  
Retail Margins 3.2
Off-system Sales 0.4
Transmission Revenues 2.8
Other Revenues (2.7)
Total Change in Gross Margin 3.7
   
Changes in Expenses and Other:  
Other Operation and Maintenance (12.1)
Depreciation and Amortization (9.3)
Taxes Other Than Income Taxes (2.1)
Interest Income (0.9)
Carrying Cost Income (1.0)
Allowance for Equity Funds Used During Construction (0.3)
Non-Service Cost Components of Net Periodic Benefit Cost 3.0
Interest Expense (2.0)
Total Change in Expenses and Other (24.7)
   
Income Tax Expense 16.8
   
First Quarter of 2018 $64.2


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


•Retail Margins increased $3$62 million primarily due to the following:
•A $25 million increase from rate proceedings in the I&M service territory. The increase in Retail Margins relating to riders has corresponding increases in other items below.
A $14$33 million increase in weather-related usage primarily due todriven by a 31%27% increase in heating degree days and 5% increase in cooling degree days.
These increases were•A $22 million increase due to rider revenue primarily in West Virginia. This increase was partially offset by:in other expense items below.
A $16•Transmission Revenues increased $14 million decrease related to the 2018 provisions for customer refunds primarily related to Tax Reform. This decrease is offset in Income Tax Expense below.
An $8 million decrease related to over/under recovery of riders.
A $4 million decrease due to lower weather-normalized margins primarily due to wholesale customer load loss from contracts that expired at the end of 2017.an increase in transmission investment. This increase was partially offset in Depreciation and Amortization expenses below.
A $4 million decrease in FERC generation wholesale municipal and cooperative revenues primarily due to changes to the annual formula rate.
A $3 million decrease due to increased fuel and other variable production costs not recovered through fuel clauses or other trackers.


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


•Other Operation and Maintenance expenses increased $12$45 million primarily due to the following:
•A $12$23 million increase in transmission expenses primarily due to an increase in recoverable PJMdistribution vegetation management expenses. This increase was partially offset withinin Retail Margins above.
•A $4$13 million increase in Cook Plant refueling outage amortization expense, primarilyPJM transmission expenses as a result of the annual transmission formula rate true-up. This increase was partially offset in Retail Margins above.
•An $11 million increase in recoverable PJM transmission expenses. This increase was partially offset in Retail Margins above.
•A $5 million increase in transmission vegetation management expenses.
•A $5 million increase due to increased coststhe current year amortization of outages.regulatory assets related to the 2017-2019 Virginia triennial review which authorized regulatory recovery of previously retired coal-fired generation assets.

81




These increases were partially offset by:
•A $7 million decrease in distribution expenses related to storm restoration costs.
•A $4 million decrease in accretion expense primarily due to the deferral of incremental Glen Lyn ash pond ARO expense.
•Depreciation and Amortization expenses increased $28 million primarily due to an increase in depreciation rates in Virginia and a higher depreciable base. This increase was partially offset in Transmission Revenues above.
•Income Tax Expenseincreased Nuclear Electric Insurance Limited distribution in 2018.


Depreciation and Amortization expensesincreased $9$13 million primarily due to a higher depreciable base.
Non-Service Cost Componentsdecrease in amortization of Net Periodic Benefit Cost decreased $3 million primarily due to favorable asset returns for the funded Pension and OPEB plans and by moving to a Medicare Advantage arrangement for post-65 retirees in the Non-UMWA OPEB plan. Additionally, the decreaseExcess ADIT. This increase was partially due to the implementation of ASU 2017-07offset in 2018, which eliminated I&M’s ability to capitalize a portion of its non-service cost components.Gross Margin above.




82




Income Tax Expense decreased $17 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and a decrease in pretax book income.





INDIANA MICHIGANAPPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended March 31, 2018June 30, 2021 and 20172020
(in millions)
(Unaudited)
 Three Months EndedSix Months Ended
 June 30,June 30,
 2021202020212020
REVENUES    
Electric Generation, Transmission and Distribution$636.5 $604.0 $1,400.7 $1,301.0 
Sales to AEP Affiliates38.1 30.8 88.2 80.5 
Other Revenues2.4 2.7 5.1 5.4 
TOTAL REVENUES677.0 637.5 1,494.0 1,386.9 
EXPENSES    
Fuel and Other Consumables Used for Electric Generation137.2 153.9 301.1 264.9 
Purchased Electricity for Resale75.9 50.4 166.0 173.0 
Other Operation118.7 108.8 269.1 242.8 
Maintenance50.1 46.4 115.3 96.7 
Depreciation and Amortization135.4 120.6 271.2 242.8 
Taxes Other Than Income Taxes39.2 37.5 76.9 75.4 
TOTAL EXPENSES556.5 517.6 1,199.6 1,095.6 
OPERATING INCOME120.5 119.9 294.4 291.3 
Other Income (Expense):    
Interest Income0.3 0.5 0.6 0.8 
Allowance for Equity Funds Used During Construction4.3 2.4 7.8 4.8 
Non-Service Cost Components of Net Periodic Benefit Cost4.8 4.7 9.5 9.4 
Interest Expense(52.9)(54.1)(107.8)(107.2)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)77.0 73.4 204.5 199.1 
Income Tax Expense (Benefit)10.7 (7.9)15.7 2.5 
NET INCOME$66.3 $81.3 $188.8 $196.6 
The common stock of APCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
83
  Three Months Ended March 31,
  2018 2017
REVENUES    
Electric Generation, Transmission and Distribution $553.9
 $538.5
Sales to AEP Affiliates 4.7
 0.6
Other Revenues – Affiliated 13.2
 18.1
Other Revenues – Nonaffiliated 5.0
 3.3
TOTAL REVENUES 576.8
 560.5
     
EXPENSES  
  
Fuel and Other Consumables Used for Electric Generation 77.5
 90.7
Purchased Electricity for Resale 55.6
 37.3
Purchased Electricity from AEP Affiliates 61.4
 53.9
Other Operation 146.1
 137.1
Maintenance 54.5
 51.4
Depreciation and Amortization 59.3
 50.0
Taxes Other Than Income Taxes 25.0
 22.9
TOTAL EXPENSES 479.4
 443.3
     
OPERATING INCOME 97.4
 117.2
     
Other Income (Expense):  
  
Interest Income 0.2
 1.1
Carrying Costs Income 2.4
 3.4
Allowance for Equity Funds Used During Construction 1.8
 2.1
Non-Service Cost Components of Net Periodic Benefit Cost 4.5
 1.5
Interest Expense (29.7) (27.7)
     
INCOME BEFORE INCOME TAX EXPENSE 76.6
 97.6
     
Income Tax Expense 12.4
 29.2
     
NET INCOME $64.2
 $68.4




The common stock of I&M is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.



INDIANA MICHIGANAPPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended March 31, 2018June 30, 2021 and 20172020
(in millions)
(Unaudited)
 Three Months EndedSix Months Ended
 June 30,June 30,
2021202020212020
Net Income$66.3 $81.3 $188.8 $196.6 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES  
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.2) for the Three Months Ended June 30, 2021 and 2020, Respectively, and $2.3 and $(1.3) for Six Months Ended June 30, 2021 and 2020, Respectively(0.2)(0.8)8.8 (5.0)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.3) and $(0.2) for the Three Months Ended June 30, 2021 and 2020, Respectively, and $(0.6) and $(0.5) for the Six Months Ended June 30, 2021 and 2020, Respectively(1.0)(1.0)(2.1)(1.9)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)(1.2)(1.8)6.7 (6.9)
TOTAL COMPREHENSIVE INCOME$65.1 $79.5 $195.5 $189.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
84
 Three Months Ended March 31,
 2018 2017
Net Income$64.2
 $68.4
    
OTHER COMPREHENSIVE INCOME, NET OF TAXES 
  
Cash Flow Hedges, Net of Tax of $0.1 and $0.2 in 2018 and 2017, Respectively0.4
 0.3
    
TOTAL COMPREHENSIVE INCOME$64.6
 $68.7




See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.


INDIANA MICHIGANAPPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the ThreeSix Months Ended March 31, 2018June 30, 2021 and 20172020
(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, 2020260.4 1,828.7 2,143.6 (0.1)4,232.6 
Common Stock Dividends  (50.0) (50.0)
Net Income  81.3  81.3 
Other Comprehensive Loss   (1.8)(1.8)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2020$260.4 $1,828.7 $2,174.9 $(1.9)$4,262.1 
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2020$260.4 $1,828.7 $2,248.0 $7.2 $4,344.3 
Common Stock Dividends(12.5)(12.5)
Net Income122.5 122.5 
Other Comprehensive Income7.9 7.9 
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2021260.4 1,828.7 2,358.0 15.1 4,462.2 
Common Stock Dividends(12.5)(12.5)
Net Income66.3 66.3 
Other Comprehensive Loss(1.2)(1.2)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2021$260.4 $1,828.7 $2,411.8 $13.9 $4,514.8 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.

85
  Common
Stock		 Paid-in
Capital		 Retained
Earnings		 Accumulated
Other
Comprehensive
Income (Loss)		 Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2016 $56.6
 $980.9
 $1,130.5
 $(16.2) $2,151.8
           
Common Stock Dividends  
  
 (31.3)  
 (31.3)
Net Income  
  
 68.4
  
 68.4
Other Comprehensive Income  
  
  
 0.3
 0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2017 $56.6
 $980.9
 $1,167.6
 $(15.9) $2,189.2
   
  
  
  
  
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017 $56.6
 $980.9
 $1,192.2
 $(12.1) $2,217.6
           
Common Stock Dividends  
  
 (33.5)  
 (33.5)
ASU 2018-02 Adoption     0.3
 (2.7) (2.4)
Net Income  
  
 64.2
  
 64.2
Other Comprehensive Income  
  
  
 0.4
 0.4
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018 $56.6
 $980.9
 $1,223.2
 $(14.4) $2,246.3




See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.


INDIANA MICHIGANAPPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2018June 30, 2021 and December 31, 20172020
(in millions)
(Unaudited)
June 30,December 31,
20212020
CURRENT ASSETS  
Cash and Cash Equivalents$3.9 $5.8 
Restricted Cash for Securitized Funding19.1 16.9 
Advances to Affiliates91.7 21.4 
Accounts Receivable:  
Customers149.7 142.8 
Affiliated Companies63.8 64.3 
Accrued Unbilled Revenues48.9 80.1 
Miscellaneous2.2 0.3 
Allowance for Uncollectible Accounts(2.3)(3.1)
Total Accounts Receivable262.3 284.4 
Fuel145.3 193.6 
Materials and Supplies102.5 99.6 
Risk Management Assets37.1 22.4 
Regulatory Asset for Under-Recovered Fuel Costs26.4 5.3 
Prepayments and Other Current Assets59.6 24.7 
TOTAL CURRENT ASSETS747.9 674.1 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation6,653.9 6,633.7 
Transmission4,004.8 3,900.5 
Distribution4,563.2 4,464.3 
Other Property, Plant and Equipment663.7 627.2 
Construction Work in Progress529.7 484.6 
Total Property, Plant and Equipment16,415.3 16,110.3 
Accumulated Depreciation and Amortization4,888.8 4,716.2 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET11,526.5 11,394.1 
OTHER NONCURRENT ASSETS  
Regulatory Assets830.4 686.3 
Securitized Assets197.6 210.1 
Employee Benefits and Pension Assets154.5 150.1 
Operating Lease Assets74.0 78.8 
Deferred Charges and Other Noncurrent Assets115.8 121.7 
TOTAL OTHER NONCURRENT ASSETS1,372.3 1,247.0 
TOTAL ASSETS$13,646.7 $13,315.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
86
  March 31, December 31,
  2018 2017
CURRENT ASSETS    
Cash and Cash Equivalents $0.6
 $1.3
Advances to Affiliates 12.5
 12.4
Accounts Receivable:    
Customers 48.7
 56.4
Affiliated Companies 49.9
 50.0
Accrued Unbilled Revenues 8.1
 7.3
Miscellaneous 5.4
 2.0
Allowance for Uncollectible Accounts —
 (0.1)
Total Accounts Receivable 112.1
 115.6
Fuel 35.2
 31.4
Materials and Supplies 161.6
 160.6
Risk Management Assets 3.3
 7.6
Accrued Tax Benefits 65.0
 58.4
Regulatory Asset for Under-Recovered Fuel Costs 12.4
 15.0
Accrued Reimbursement of Spent Nuclear Fuel Costs 6.2
 10.8
Margin Deposits 25.6
 11.5
Prepayments and Other Current Assets 13.6
 9.4
TOTAL CURRENT ASSETS 448.1
 434.0
     
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Generation 4,464.5
 4,445.9
Transmission 1,523.5
 1,504.0
Distribution 2,097.3
 2,069.3
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) 610.9
 595.2
Construction Work in Progress 503.5
 460.2
Total Property, Plant and Equipment 9,199.7
 9,074.6
Accumulated Depreciation, Depletion and Amortization 3,073.1
 3,024.2
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 6,126.6
 6,050.4
     
OTHER NONCURRENT ASSETS    
Regulatory Assets 589.2
 579.4
Spent Nuclear Fuel and Decommissioning Trusts 2,510.6
 2,527.6
Long-term Risk Management Assets 2.0
 0.7
Deferred Charges and Other Noncurrent Assets 168.4
 179.9
TOTAL OTHER NONCURRENT ASSETS 3,270.2
 3,287.6
     
TOTAL ASSETS $9,844.9
 $9,772.0




See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.


INDIANA MICHIGANAPPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
March 31, 2018June 30, 2021 and December 31, 2017
(dollars in millions)2020
(Unaudited)
 June 30,December 31,
 20212020
 (in millions)
CURRENT LIABILITIES  
Advances from Affiliates$0 $18.6 
Accounts Payable:  
General219.0 212.0 
Affiliated Companies81.4 97.1 
Long-term Debt Due Within One Year – Nonaffiliated380.4 518.3 
Customer Deposits72.0 77.8 
Accrued Taxes109.3 109.9 
Accrued Interest48.8 49.9 
Obligations Under Operating Leases15.1 14.9 
Other Current Liabilities108.8 119.2 
TOTAL CURRENT LIABILITIES1,034.8 1,217.7 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated4,569.4 4,315.8 
Deferred Income Taxes1,739.4 1,749.9 
Regulatory Liabilities and Deferred Investment Tax Credits1,251.3 1,224.7 
Asset Retirement Obligations385.8 304.8 
Employee Benefits and Pension Obligations43.7 44.0 
Obligations Under Operating Leases59.5 64.4 
Deferred Credits and Other Noncurrent Liabilities48.0 49.6 
TOTAL NONCURRENT LIABILITIES8,097.1 7,753.2 
TOTAL LIABILITIES9,131.9 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 Earnings2,411.8 2,248.0 
Accumulated Other Comprehensive Income (Loss)13.9 7.2 
TOTAL COMMON SHAREHOLDER’S EQUITY4,514.8 4,344.3 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$13,646.7 $13,315.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
87
  March 31, December 31,
  2018 2017
CURRENT LIABILITIES    
Advances from Affiliates $314.1
 $211.6
Accounts Payable:    
General 164.8
 154.5
Affiliated Companies 81.4
 98.3
Long-term Debt Due Within One Year – Nonaffiliated
(March 31, 2018 and December 31, 2017 Amounts Include $88.1 and $96.3, Respectively, Related to DCC Fuel)
 941.5
 474.7
Risk Management Liabilities 3.8
 3.5
Customer Deposits 38.0
 37.7
Accrued Taxes 89.6
 81.3
Accrued Interest 14.8
 37.5
Obligations Under Capital Leases 5.8
 5.8
Other Current Liabilities 102.7
 106.4
TOTAL CURRENT LIABILITIES 1,756.5
 1,211.3
     
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated 1,775.7
 2,270.4
Long-term Risk Management Liabilities 0.2
 0.1
Deferred Income Taxes 978.3
 953.8
Regulatory Liabilities and Deferred Investment Tax Credits 1,660.2
 1,708.7
Asset Retirement Obligations 1,336.0
 1,321.6
Deferred Credits and Other Noncurrent Liabilities 91.7
 88.5
TOTAL NONCURRENT LIABILITIES 5,842.1
 6,343.1
     
TOTAL LIABILITIES 7,598.6
 7,554.4
     
Rate Matters (Note 4) 
 
Commitments and Contingencies (Note 5) 
 
     
COMMON SHAREHOLDER’S EQUITY    
Common Stock – No Par Value:    
Authorized – 2,500,000 Shares    
Outstanding – 1,400,000 Shares 56.6
 56.6
Paid-in Capital 980.9
 980.9
Retained Earnings 1,223.2
 1,192.2
Accumulated Other Comprehensive Income (Loss) (14.4) (12.1)
TOTAL COMMON SHAREHOLDER’S EQUITY 2,246.3
 2,217.6
     
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $9,844.9
 $9,772.0




See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.


INDIANA MICHIGANAPPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the ThreeSix Months Ended March 31, 2018June 30, 2021 and 20172020
(in millions)
(Unaudited)
 Six Months Ended June 30,
 20212020
OPERATING ACTIVITIES  
Net Income$188.8 $196.6 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and Amortization271.2 242.8 
Deferred Income Taxes4.0 (11.8)
Allowance for Equity Funds Used During Construction(7.8)(4.8)
Mark-to-Market of Risk Management Contracts(16.8)1.5 
Deferred Fuel Over/Under-Recovery, Net(21.1)30.9 
Change in Other Noncurrent Assets(70.2)(11.1)
Change in Other Noncurrent Liabilities12.5 (21.3)
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net23.7 (37.3)
Fuel, Materials and Supplies45.4 (2.2)
Accounts Payable(3.9)(69.6)
Accrued Taxes, Net(26.6)8.9 
Other Current Assets(8.8)18.8 
Other Current Liabilities(23.0)(29.7)
Net Cash Flows from Operating Activities367.4 311.7 
INVESTING ACTIVITIES  
Construction Expenditures(374.8)(400.2)
Change in Advances to Affiliates, Net(70.3)(60.2)
Other Investing Activities11.1 3.9 
Net Cash Flows Used for Investing Activities(434.0)(456.5)
FINANCING ACTIVITIES  
Issuance of Long-term Debt – Nonaffiliated494.0 492.2 
Change in Advances from Affiliates, Net(18.6)(236.7)
Retirement of Long-term Debt – Nonaffiliated(380.0)(12.2)
Principal Payments for Finance Lease Obligations(3.9)(3.6)
Dividends Paid on Common Stock(25.0)(100.0)
Other Financing Activities0.4 0.1 
Net Cash Flows from Financing Activities66.9 139.8 
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash for Securitized Funding0.3 (5.0)
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$23.0 $21.8 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$104.7 $101.8 
Net Cash Paid for Income Taxes35.8 7.4 
Noncash Acquisitions Under Finance Leases0.9 2.2 
Construction Expenditures Included in Current Liabilities as of June 30,98.0 97.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
88
  Three Months Ended March 31,
  2018 2017
OPERATING ACTIVITIES  
  
Net Income $64.2
 $68.4
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
Depreciation and Amortization 59.3
 50.0
Deferred Income Taxes 13.7
 48.8
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net (12.3) 16.6
Allowance for Equity Funds Used During Construction (1.8) (2.1)
Mark-to-Market of Risk Management Contracts 3.4
 2.3
Amortization of Nuclear Fuel 27.4
 35.1
Deferred Fuel Over/Under-Recovery, Net 3.4
 19.6
Change in Other Noncurrent Assets (13.4) (17.6)
Change in Other Noncurrent Liabilities 33.7
 13.5
Changes in Certain Components of Working Capital:  
  
Accounts Receivable, Net 3.5
 3.0
Fuel, Materials and Supplies (4.5) (8.5)
Accounts Payable 1.3
 (22.5)
Accrued Taxes, Net 8.2
 (6.9)
Other Current Assets (11.1) 15.8
Other Current Liabilities (27.8) (41.2)
Net Cash Flows from Operating Activities 147.2
 174.3
     
INVESTING ACTIVITIES  
  
Construction Expenditures (148.9) (159.7)
Change in Advances to Affiliates, Net (0.1) —
Purchases of Investment Securities (525.3) (505.5)
Sales of Investment Securities 508.6
 487.9
Acquisitions of Nuclear Fuel (23.8) (3.7)
Other Investing Activities 4.2
 2.0
Net Cash Flows Used for Investing Activities (185.3) (179.0)
     
FINANCING ACTIVITIES  
  
Issuance of Long-term Debt – Nonaffiliated —
 76.7
Change in Advances from Affiliates, Net 102.5
 71.6
Retirement of Long-term Debt – Nonaffiliated (29.4) (109.5)
Principal Payments for Capital Lease Obligations (2.7) (2.9)
Dividends Paid on Common Stock (33.5) (31.3)
Other Financing Activities 0.5
 0.1
Net Cash Flows from Financing Activities 37.4
 4.7
     
Net Decrease in Cash and Cash Equivalents (0.7) —
Cash and Cash Equivalents at Beginning of Period 1.3
 1.2
Cash and Cash Equivalents at End of Period $0.6
 $1.2
     
SUPPLEMENTARY INFORMATION  
  
Cash Paid for Interest, Net of Capitalized Amounts $50.6
 $44.3
Net Cash Paid for Income Taxes —
 0.6
Noncash Acquisitions Under Capital Leases 1.7
 1.5
Construction Expenditures Included in Current Liabilities as of March 31, 77.2
 75.9
Acquisition of Nuclear Fuel Included in Current Liabilities as of March 31, 0.1
 —
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage 0.1
 1.0




See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.




OHIOINDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES

89



OHIO


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 EndedSix Months Ended
 June 30,June 30,
 2021202020212020
 (in millions of KWhs)
Retail:    
Residential1,181 1,244 2,713 2,699 
Commercial1,136 1,021 2,214 2,143 
Industrial1,887 1,630 3,689 3,475 
Miscellaneous12 15 29 33 
Total Retail4,216 3,910 8,645 8,350 
Wholesale1,500 2,323 3,445 4,016 
Total KWhs5,716 6,233 12,090 12,366 
 Three Months Ended March 31,
 2018 2017
 (in millions of KWhs)
Retail: 
  
Residential4,133
 3,693
Commercial3,552
 3,428
Industrial3,554
 3,569
Miscellaneous31
 32
Total Retail (a)11,270
 10,722
    
Wholesale (b)667

674
    
Total KWhs11,937
 11,396

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


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


Summary of Heating and Cooling Degree Days
 Three Months EndedSix Months Ended
 June 30,June 30,
 2021202020212020
 (in degree days)
Actual – Heating (a)285 343 2,341 2,179 
Normal – Heating (b)238 237 2,408 2,419 
Actual – Cooling (c)325 286 325 286 
Normal – Cooling (b)266 263 267 265 
 Three Months Ended March 31,
 2018 2017
 (in degree days)
Actual – Heating (a)1,884
 1,403
Normal – Heating (b)1,884
 1,899
    
Actual – Cooling (c)4
 3
Normal – Cooling (b)3
 3


(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.

90





First
Second Quarter of 20182021 Compared to FirstSecond Quarter of 2017
Reconciliation of First Quarter of 2017 to First Quarter of 2018
Net Income
(in millions)
   
First Quarter of 2017 $86.2
   
Changes in Gross Margin:  
Retail Margins 31.8
Off-system Sales 7.2
Transmission Revenues (6.4)
Other Revenues (0.9)
Total Change in Gross Margin 31.7
   
Changes in Expenses and Other:  
Other Operation and Maintenance (49.9)
Depreciation and Amortization (7.5)
Taxes Other Than Income Taxes (6.6)
Interest Income (1.6)
Carrying Costs Income (1.2)
Allowance for Equity Funds Used During Construction 0.1
Non-Service Cost Components of Net Periodic Benefit Cost 2.8
Interest Expense (0.2)
Total Change in Expenses and Other (64.1)
   
Income Tax Expense 25.8
   
First Quarter of 2018 $79.6

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

Retail Margins increased $32 million primarily due to the following:
A $39 million net increase in Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset by a corresponding increase in Other Operation and Maintenance below.
A $21 million increase in revenues associated with the Universal Service Fund (USF). This increase was offset by a corresponding increase in Other Operation and Maintenance expenses below.
A $9 million increase in usage primarily in the residential class.
A $6 million increase in rider revenues associated with the DIR. This increase was partially offset in various expenses below.
A $4 million net increase in RSR revenues less associated amortizations.
These increases were partially offset by:
A $16 million decrease due to the 2018 provisions for customer refunds primarily related to Tax Reform. This decrease is offset in Income Tax Expense below.
An $11 million decrease in Energy Efficiency/Peak Demand Reduction rider revenues. This decrease was partially offset by a corresponding decrease in Other Operation and Maintenance expenses below.
A $10 million decrease in margin for the Phase-In-Recovery Rider including associated amortizations.
A $7 million decrease due to the recovery of lower current year losses from a power contract with OVEC. This decrease was offset by a corresponding increase in Margins from Off-system Sales below.
A $7 million decrease in revenues associated with smart grid riders. This decrease was partially offset by a corresponding decrease in various expenses below.


Margins from Off-system Sales increased $7 million primarily due to lower current year losses from a power contract with OVEC which was offset in Retail Margins above as a result of the OVEC PPA rider beginning in January 2017.
Transmission Revenues decreased $6 million mainly due to the 2018 provisions for customer refunds primarily due to Tax Reform. This decrease is offset in Income Tax Expense below.

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

Other Operation and Maintenance expenses increased $50 million primarily due to the following:
A $35 million increase in recoverable PJM expenses. This increase was offset by a corresponding increase in Retail Margins above.
A $21 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset by a corresponding increase in Retail Margins above.
These increases were partially offset by:
A $10 million decrease in Energy Efficiency/Peak Demand Reduction rider costs and associated deferrals. This decrease was offset by a decrease in Retail Margins above.
Depreciation and Amortization expensesincreased $8 million primarily due to the following:
A $6 million increase in recoverable DIR depreciation expense. This increase was offset in Retail Margins above.
A $3 million increase in depreciation expense due to an increase in depreciable base of transmission and distribution assets.
A $2 million increase primarily due to amortization of capitalized software costs.
These increases were partially offset by:
A $3 million decrease in recoverable smart grid depreciation expenses. This decrease was offset in Retail Margins above.
Taxes Other Than Income Taxes increased by $7 million primarily due to the following:
A $4 million increase in property taxes due to additional investments in transmission and distribution assets and higher tax rates.
A $3 million increase in state excise taxes due to an increase in metered KWh. This increase was offset by a corresponding increase in Retail Margins above.
Income Tax Expense decreased $26 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and a decrease in pretax book income.



OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2018 and 2017
(in millions)
(Unaudited)
  Three Months Ended March 31,
  2018 2017
REVENUES    
Electricity, Transmission and Distribution $786.3
 $738.4
Sales to AEP Affiliates 3.1
 5.7
Other Revenues 1.5
 2.0
TOTAL REVENUES 790.9
 746.1
     
EXPENSES  
  
Purchased Electricity for Resale 205.5
 188.3
Purchased Electricity from AEP Affiliates 30.2
 32.0
Amortization of Generation Deferrals 58.6
 60.9
Other Operation 172.2
 122.3
Maintenance 37.2
 37.2
Depreciation and Amortization 64.8
 57.3
Taxes Other Than Income Taxes 105.1
 98.5
TOTAL EXPENSES 673.6
 596.5
     
OPERATING INCOME 117.3
 149.6
     
Other Income (Expense):  
  
Interest Income 0.9
 2.5
Carrying Costs Income 0.7
 1.9
Allowance for Equity Funds Used During Construction 2.5
 2.4
Non-Service Cost Components of Net Periodic Benefit Cost 3.9
 1.1
Interest Expense (25.2) (25.0)
     
INCOME BEFORE INCOME TAX EXPENSE 100.1
 132.5
     
Income Tax Expense 20.5
 46.3
     
NET INCOME $79.6
 $86.2
2020
The common stock of OPCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2018 and 2017
(in millions)
(Unaudited)
 Three Months Ended March 31,
 2018 2017
Net Income$79.6
 $86.2
    
OTHER COMPREHENSIVE LOSS, NET OF TAXES   
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) in 2018 and 2017, Respectively(0.3) (0.2)
  
  
TOTAL COMPREHENSIVE INCOME$79.3
 $86.0
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Three Months Ended March 31, 2018 and 2017
(in millions)
(Unaudited)
  Common
Stock		 Paid-in
Capital		 Retained
Earnings		 Accumulated
Other
Comprehensive
Income (Loss)		 Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2016 $321.2
 $838.8
 $954.5
 $3.0
 $2,117.5
           
Common Stock Dividends  
  
 (65.0)  
 (65.0)
Net Income  
  
 86.2
  
 86.2
Other Comprehensive Loss  
  
  
 (0.2) (0.2)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2017 $321.2
 $838.8
 $975.7
 $2.8
 $2,138.5
   
  
  
  
  
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017 $321.2
 $838.8
 $1,148.4
 $1.9
 $2,310.3
           
Common Stock Dividends  
  
 (112.5)  
 (112.5)
ASU 2018-02 Adoption       0.4
 0.4
Net Income  
  
 79.6
  
 79.6
Other Comprehensive Loss  
  
  
 (0.3) (0.3)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018 $321.2
 $838.8
 $1,115.5
 $2.0
 $2,277.5
See Condensed NotesIndiana Michigan Power Company and Subsidiaries
Reconciliation of Second Quarter of 2020 to Condensed Financial StatementsSecond Quarter of Registrants beginning on page 120.2021


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2018 and December 31, 2017
(in millions)
(Unaudited)
  March 31, December 31,
  2018 2017
CURRENT ASSETS    
Cash and Cash Equivalents $1.4
 $3.1
Restricted Cash for Securitized Funding 15.9
 26.6
Advances to Affiliates 200.4
 —
Accounts Receivable:    
Customers 42.0
 67.8
Affiliated Companies 60.4
 70.2
Accrued Unbilled Revenues 27.2
 29.7
Miscellaneous 1.2
 1.9
Allowance for Uncollectible Accounts (0.6) (0.6)
Total Accounts Receivable 130.2
 169.0
Materials and Supplies 41.2
 41.9
Renewable Energy Credits 24.8
 25.0
Risk Management Assets 0.4
 0.6
Regulatory Asset for Under-Recovered Fuel Costs 89.3
 115.9
Prepayments and Other Current Assets 27.1
 15.8
TOTAL CURRENT ASSETS 530.7
 397.9
     
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Transmission 2,440.5
 2,419.2
Distribution 4,669.3
 4,626.4
Other Property, Plant and Equipment 518.9
 495.9
Construction Work in Progress 432.0
 410.1
Total Property, Plant and Equipment 8,060.7
 7,951.6
Accumulated Depreciation and Amortization 2,205.7
 2,184.8
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 5,855.0
 5,766.8
     
OTHER NONCURRENT ASSETS    
Regulatory Assets 597.6
 652.8
Securitized Assets 31.4
 37.7
Deferred Charges and Other Noncurrent Assets 342.0
 406.5
TOTAL OTHER NONCURRENT ASSETS 971.0
 1,097.0
     
TOTAL ASSETS $7,356.7
 $7,261.7
Net Income
(in millions)
Second Quarter of 2020$63.8 
Changes in Gross Margin:
Retail Margins28.8 
Margins from Off-system Sales0.1 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.
Transmission Revenues		(4.4)


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
March 31, 2018 and December 31, 2017
(dollars in millions)
(Unaudited)
  March 31, December 31,
  2018 2017
CURRENT LIABILITIES    
Advances from Affiliates $—
 $87.8
Accounts Payable:  
  
General 159.9
 205.8
Affiliated Companies 105.5
 118.2
Long-term Debt Due Within One Year – Nonaffiliated
(March 31, 2018 and December 31, 2017 Amounts Include $47.5 and $47, Respectively, Related to Ohio Phase-in-Recovery Funding)
 397.5
 397.0
Risk Management Liabilities 5.3
 6.4
Customer Deposits 76.5
 69.2
Accrued Taxes 418.5
 512.5
Accrued Interest 38.7
 31.0
Other Current Liabilities 161.2
 165.9
TOTAL CURRENT LIABILITIES 1,363.1
 1,593.8
     
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated
(March 31, 2018 and December 31, 2017 Amounts Include $24.3 and $47.5, Respectively, Related to Ohio Phase-in-Recovery Funding)
 1,692.2
 1,322.3
Long-term Risk Management Liabilities 93.2
 126.0
Deferred Income Taxes 759.0
 762.9
Regulatory Liabilities and Deferred Investment Tax Credits 1,120.8
 1,100.2
Deferred Credits and Other Noncurrent Liabilities 50.9
 46.2
TOTAL NONCURRENT LIABILITIES 3,716.1
 3,357.6
     
TOTAL LIABILITIES 5,079.2
 4,951.4
     
Rate Matters (Note 4) 
 
Commitments and Contingencies (Note 5) 
 
     
COMMON SHAREHOLDER’S EQUITY    
Common Stock – No Par Value:    
Authorized – 40,000,000 Shares  
  
Outstanding – 27,952,473 Shares 321.2
 321.2
Paid-in Capital 838.8
 838.8
Retained Earnings 1,115.5
 1,148.4
Accumulated Other Comprehensive Income (Loss) 2.0
 1.9
TOTAL COMMON SHAREHOLDER’S EQUITY 2,277.5
 2,310.3
     
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $7,356.7
 $7,261.7
Other Revenues(2.1)
Total Change in Gross Margin22.4 
Changes in Expenses and Other:
Other Operation and Maintenance(30.9)
Depreciation and Amortization(3.7)
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.
Taxes Other Than Income Taxes		(4.1)


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2018 and 2017
(in millions)
(Unaudited)
  Three Months Ended March 31,
  2018 2017
OPERATING ACTIVITIES  
  
Net Income $79.6
 $86.2
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
Depreciation and Amortization 64.8
 57.3
Amortization of Generation Deferrals 58.6
 60.9
Deferred Income Taxes (4.9) 36.7
Carrying Costs Income (0.7) (1.9)
Allowance for Equity Funds Used During Construction (2.5) (2.4)
Mark-to-Market of Risk Management Contracts (33.7) 5.7
Property Taxes 62.9
 58.4
Provision for Refund – Global Settlement (5.4) —
Change in Other Noncurrent Assets 14.3
 (45.8)
Change in Other Noncurrent Liabilities 40.6
 30.6
Changes in Certain Components of Working Capital:  
  
Accounts Receivable, Net 38.8
 30.2
Materials and Supplies (1.9) (1.8)
Accounts Payable (22.5) (34.9)
Accrued Taxes, Net (92.8) (107.2)
Other Current Assets (7.5) (0.3)
Other Current Liabilities (2.9) (31.2)
Net Cash Flows from Operating Activities 184.8
 140.5
     
INVESTING ACTIVITIES  
  
Construction Expenditures (168.2) (108.4)
Change in Advances to Affiliates, Net (200.4) 24.2
Other Investing Activities 1.7
 2.0
Net Cash Flows Used for Investing Activities (366.9) (82.2)
     
FINANCING ACTIVITIES  
  
Issuance of Long-term Debt – Nonaffiliated 393.3
 —
Change in Advances from Affiliates, Net (87.8) 18.3
Retirement of Long-term Debt – Nonaffiliated (22.9) (22.5)
Principal Payments for Capital Lease Obligations (0.9) (1.0)
Dividends Paid on Common Stock (112.5) (65.0)
Other Financing Activities 0.5
 0.6
Net Cash Flows from (Used for) Financing Activities 169.7
 (69.6)
     
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding (12.4) (11.3)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period 29.7
 30.3
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period $17.3
 $19.0
     
SUPPLEMENTARY INFORMATION  
  
Cash Paid for Interest, Net of Capitalized Amounts $17.0
 $17.2
Net Cash Paid for Income Taxes —
 1.7
Noncash Acquisitions Under Capital Leases 1.4
 1.3
Construction Expenditures Included in Current Liabilities as of March 31, 52.3
 28.3
Other Income0.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.


PUBLIC SERVICE COMPANY OF OKLAHOMA


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

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 Three Months Ended March 31,
 2018 2017
 (in millions of KWhs)
Retail: 
  
Residential1,493
 1,312
Commercial1,162
 1,130
Industrial1,340
 1,306
Miscellaneous276
 273
Total Retail4,271
 4,021
    
Wholesale157
 81
    
Total KWhs4,428
 4,102

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,
 2018 2017
 (in degree days)
Actual – Heating (a)1,032
 670
Normal – Heating (b)1,041
 1,062
    
Actual – Cooling (c)12
 59
Normal – Cooling (b)17
 14

(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.



First Quarter of 2018 Compared to First Quarter of 2017
Reconciliation of First Quarter of 2017 to First Quarter of 2018
Net Income (Loss)
(in millions)
   
First Quarter of 2017 $4.8
   
Changes in Gross Margin:  
Retail Margins (a) (0.2)
Off-system Sales 0.1
Other Revenues (0.4)
Total Change in Gross Margin (0.5)
   
Changes in Expenses and Other:  
Other Operation and Maintenance (11.2)
Depreciation and Amortization (3.3)
Taxes Other Than Income Taxes (1.0)
Non-Service Cost Components of Net Periodic Benefit Cost 1.3
Other Income (0.5)
Interest Expense (1.1)
Total Change in Expenses and Other (15.8)
   
Income Tax Expense 4.3
   
First Quarter of 2018 $(7.2)

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

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 were consistent with the prior year due to the following:
A $5 million increase in revenue from rate riders. This increase in Retail Margins is partially offset by a corresponding increase to riders/trackers recognized in other expense items below.
A $4 million increase due to new rates implemented in March 2018, inclusive of a $2 million decrease due to the change in the corporate federal tax rate.
A $3 million increase in weather-related usage due to a 54% increase in heating degree days.
These increases were partially offset by:
A $6 million decrease due to 2018 provisions for customer refunds primarily related to Tax Reform. This decrease is offset in Income Tax Expense below.
A $5 million decrease related to the System Reliability Rider (SRR) that ended in August 2017. This decrease is partially offset by a corresponding decrease recognized in other expense items below.
A $1 million decrease due to lower weather-normalized margins.
Expenses and Other and Income Tax Expense changed between years as follows:

Other Operation and Maintenance expenses increased $11 million primarily due to the following:
A $9 million increase in transmission expenses primarily due to increased SPP transmission services.
A $4 million increase due to the Wind Catcher Project.
A $3 million increase in Energy Efficiency program costs. This increase was offset by an increase from rate riders in Retail Margins above.




These increases were partially offset by:
A $6 million decrease in the amortization of previously deferred vegetation management costs collected through the SRR. This decrease was partially offset by a corresponding decrease in Retail Margins above.
Depreciation and Amortization expenses increased $3 million primarily due to the following:
A $2 million increase due to a higher depreciable base.
A $1 million increase due to amortization of capitalized software costs.
Income Tax Expense decreased $4 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, amortization of excess accumulated deferred income taxes associated with certain depreciable property and a decrease in pretax book income.



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF OPERATIONS
For the Three Months Ended March 31, 2018 and 2017
(in millions)
(Unaudited)
  Three Months Ended March 31,
  2018 2017
REVENUES    
Electric Generation, Transmission and Distribution $335.1
 $301.9
Sales to AEP Affiliates 1.1
 1.1
Other Revenues 0.6
 1.1
TOTAL REVENUES 336.8
 304.1
     
EXPENSES  
  
Fuel and Other Consumables Used for Electric Generation 48.4
 12.3
Purchased Electricity for Resale 122.4
 125.3
Other Operation 86.8
 68.3
Maintenance 26.9
 34.2
Depreciation and Amortization 36.8
 33.5
Taxes Other Than Income Taxes 11.6
 10.6
TOTAL EXPENSES 332.9
 284.2
     
OPERATING INCOME 3.9
 19.9
     
Other Income (Expense):  
  
Other Income —
 0.5
Non-Service Cost Components of Net Periodic Benefit Cost

 2.2
 0.9
Interest Expense (14.7) (13.6)
     
INCOME (LOSS) BEFORE INCOME TAX EXPENSE (CREDIT) (8.6) 7.7
     
Income Tax Expense (Credit) (1.4) 2.9
     
NET INCOME (LOSS) $(7.2) $4.8
The common stockNon-Service Cost Components of PSO is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2018 and 2017
(in millions)
(Unaudited)
 Three Months Ended March 31,
 2018 2017
Net Income (Loss)$(7.2) $4.8
    
OTHER COMPREHENSIVE LOSS, NET OF TAXES 
  
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) in 2018 and 2017, Respectively(0.2) (0.2)
  
  
TOTAL COMPREHENSIVE INCOME (LOSS)$(7.4) $4.6
Net Periodic Benefit Cost(0.1)
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Three Months Ended March 31, 2018 and 2017
(in millions)
(Unaudited)
  Common
Stock		 Paid-in
Capital		 Retained
Earnings		 Accumulated
Other
Comprehensive
Income (Loss)		 Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2016 $157.2
 $364.0
 $689.5
 $3.4
 $1,214.1
           
Common Stock Dividends  
  
 (17.5)  
 (17.5)
Net Income  
  
 4.8
  
 4.8
Other Comprehensive Loss  
  
  
 (0.2) (0.2)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2017 $157.2
 $364.0
 $676.8
 $3.2
 $1,201.2
   
  
  
  
  
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017 $157.2
 $364.0
 $691.5
 $2.6
 $1,215.3
           
Common Stock Dividends  
  
 (12.5)  
 (12.5)
ASU 2018-02 Adoption       0.5
 0.5
Net Loss  
  
 (7.2)  
 (7.2)
Other Comprehensive Loss  
  
  
 (0.2) (0.2)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018 $157.2
 $364.0
 $671.8
 $2.9
 $1,195.9
Interest Expense(1.0)
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
March 31, 2018 and December 31, 2017
(in millions)
(Unaudited)
  March 31, December 31,
  2018 2017
CURRENT ASSETS    
Cash and Cash Equivalents $0.6
 $1.6
Accounts Receivable:    
Customers 30.9
 32.5
Affiliated Companies 27.7
 32.9
Miscellaneous 3.9
 4.1
Allowance for Uncollectible Accounts —
 (0.1)
Total Accounts Receivable 62.5
 69.4
Fuel 13.0
 12.5
Materials and Supplies 43.2
 42.0
Risk Management Assets 2.9
 6.4
Accrued Tax Benefits 30.2
 28.1
Regulatory Asset for Under-Recovered Fuel Costs 22.7
 36.7
Prepayments and Other Current Assets 7.5
 8.6
TOTAL CURRENT ASSETS 182.6
 205.3
     
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Generation 1,572.4
 1,577.2
Transmission 862.0
 858.8
Distribution 2,475.5
 2,445.1
Other Property, Plant and Equipment 297.0
 287.4
Construction Work in Progress 110.3
 111.3
Total Property, Plant and Equipment 5,317.2
 5,279.8
Accumulated Depreciation and Amortization 1,415.5
 1,393.6
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 3,901.7
 3,886.2
     
OTHER NONCURRENT ASSETS    
Regulatory Assets 366.8
 368.1
Employee Benefits and Pension Assets 40.4
 40.0
Deferred Charges and Other Noncurrent Assets 34.2
 8.7
TOTAL OTHER NONCURRENT ASSETS 441.4
 416.8
     
TOTAL ASSETS $4,525.7
 $4,508.3
Total Change in Expenses and Other(39.5)
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
March 31, 2018 and December 31, 2017
(Unaudited)
  March 31, December 31,
  2018 2017
  (in millions)
CURRENT LIABILITIES    
Advances from Affiliates $179.1
 $149.6
Accounts Payable:  
  
General 88.7
 102.4
Affiliated Companies 51.5
 48.0
Long-term Debt Due Within One Year – Nonaffiliated 0.5
 0.5
Customer Deposits 54.5
 54.1
Accrued Taxes 42.1
 22.6
Accrued Interest 19.3
 14.1
Other Current Liabilities 34.8
 44.7
TOTAL CURRENT LIABILITIES 470.5
 436.0
     
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated 1,286.2
 1,286.0
Deferred Income Taxes 639.6
 642.0
Regulatory Liabilities and Deferred Investment Tax Credits 851.5
 853.5
Asset Retirement Obligations 53.7
 53.0
Deferred Credits and Other Noncurrent Liabilities 28.3
 22.5
TOTAL NONCURRENT LIABILITIES 2,859.3
 2,857.0
     
TOTAL LIABILITIES 3,329.8
 3,293.0
     
Rate Matters (Note 4) 
 
Commitments and Contingencies (Note 5) 
 
     
COMMON SHAREHOLDER’S EQUITY    
Common Stock – Par Value – $15 Per Share:    
Authorized – 11,000,000 Shares  
  
Issued – 10,482,000 Shares  
  
Outstanding – 9,013,000 Shares 157.2
 157.2
Paid-in Capital 364.0
 364.0
Retained Earnings 671.8
 691.5
Accumulated Other Comprehensive Income (Loss) 2.9
 2.6
TOTAL COMMON SHAREHOLDER’S EQUITY 1,195.9
 1,215.3
     
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $4,525.7
 $4,508.3
Income Tax Expense10.5 
See Condensed Notes to Condensed Financial Statements
Second Quarter of Registrants beginning on page 120.2021$57.2 


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2018 and 2017
(in millions)
(Unaudited)
  Three Months Ended March 31,
  2018 2017
OPERATING ACTIVITIES  
  
Net Income (Loss) $(7.2) $4.8
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from (Used for) Operating Activities:  
  
Depreciation and Amortization 36.8
 33.5
Deferred Income Taxes (4.5) 27.4
Allowance for Equity Funds Used During Construction 0.1
 (0.4)
Mark-to-Market of Risk Management Contracts 3.5
 0.3
Property Taxes (30.1) (29.8)
Deferred Fuel Over/Under-Recovery, Net 14.6
 (13.1)
Change in Other Noncurrent Assets —
 (9.3)
Change in Other Noncurrent Liabilities 5.7
 (1.9)
Changes in Certain Components of Working Capital:  
  
Accounts Receivable, Net 6.9
 16.6
Fuel, Materials and Supplies (1.7) 3.4
Accounts Payable (10.9) (27.7)
Accrued Taxes, Net 22.4
 (0.3)
Other Current Assets 0.9
 0.3
Other Current Liabilities (1.3) (22.3)
Net Cash Flows from (Used for) Operating Activities 35.2
 (18.5)
     
INVESTING ACTIVITIES  
  
Construction Expenditures (54.4) (75.7)
Other Investing Activities 2.0
 0.9
Net Cash Flows Used for Investing Activities (52.4) (74.8)
     
FINANCING ACTIVITIES  
  
Change in Advances from Affiliates, Net 29.5
 111.7
Retirement of Long-term Debt – Nonaffiliated (0.1) (0.1)
Principal Payments for Capital Lease Obligations (1.0) (1.1)
Dividends Paid on Common Stock (12.5) (17.5)
Other Financing Activities 0.3
 0.1
Net Cash Flows from Financing Activities 16.2
 93.1
     
Net Decrease in Cash and Cash Equivalents (1.0) (0.2)
Cash and Cash Equivalents at Beginning of Period 1.6
 1.5
Cash and Cash Equivalents at End of Period $0.6
 $1.3
     
SUPPLEMENTARY INFORMATION  
  
Cash Paid for Interest, Net of Capitalized Amounts $10.3
 $15.9
Net Cash Paid (Received) for Income Taxes —
 (2.6)
Noncash Acquisitions Under Capital Leases 0.9
 0.7
Construction Expenditures Included in Current Liabilities as of March 31, 25.4
 22.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED



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

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 Three Months Ended March 31,
 2018 2017
 (in millions of KWhs)
Retail: 
  
Residential1,558
 1,310
Commercial1,288
 1,305
Industrial1,199
 1,222
Miscellaneous19
 20
Total Retail4,064
 3,857
    
Wholesale1,908
 2,439
    
Total KWhs5,972
 6,296

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,
 2018 2017
 (in degree days)
Actual – Heating (a)729
 388
Normal – Heating (b)707
 720
    
Actual – Cooling (c)60
 106
Normal – Cooling (b)38
 34

(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.




First Quarter of 2018 Compared to First Quarter of 2017
Reconciliation of First Quarter of 2017 to First Quarter of 2018
Earnings Attributable to SWEPCo Common Shareholder
(in millions)
   
First Quarter of 2017 $16.3
   
Changes in Gross Margin:  
Retail Margins (a) 10.2
Off-system Sales (1.1)
Transmission Revenues 2.7
Other Revenues 0.1
Total Change in Gross Margin 11.9
   
Changes in Expenses and Other:  
Other Operation and Maintenance (14.8)
Depreciation and Amortization (6.6)
Taxes Other Than Income Taxes (1.7)
Interest Income 0.9
Allowance for Equity Funds Used During Construction 1.5
Non-Service Cost Components of Net Periodic Benefit Cost 1.4
Interest Expense (2.3)
Total Change in Expenses and Other (21.6)
   
Income Tax Expense 6.6
Equity Earnings of Unconsolidated Subsidiary (0.8)
Net Income Attributable to Noncontrolling Interest (0.6)
   
First Quarter of 2018 $11.8

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


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


•Retail Margins increased $10$29 million primarily due to the following:
•A $22$36 million increase due to wholesale true-up, increase in rider revenues and the Indiana base rate case. This increase was partially offset in other expense items below.
•A $3 million decrease in fuel related expenses due to timing of recovery related to wholesale contracts.
These increases were partially offset by:
•A $10 million decrease in weather-normalized retail margins.
•A $7 million decrease in weather-normalized wholesale margins, including the loss of a significant wholesale contract.
•Transmission Revenues decreased $4 million primarily due to riderthe annual transmission formula rate true-up.

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

•Other Operation and Maintenance expenses increased $31 million primarily due to the following:
•A $17 million increase in transmission expenses primarily due to an $11 million increase in vegetation management expenses and a $6 million increase as a result of the annual transmission formula rate true up.
•A $9 million increase in recoverable PJM expenses. This increase was partially offset in Retail Margins above.
•A $6 million increase in distribution expenses primarily due to an increase in vegetation management 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.
91




•Depreciation and Amortization expensesincreased $4 million primarily due to a higher depreciable base. This increase was partially offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $4 million primarily due to property taxes driven by an increase in utility plant and higher tax rates.
•Income Tax Expense decreased $11 million primarily due to a decrease in pretax book income, an increase in flow through tax benefits and a decrease in state tax expense.
92




Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020
Indiana Michigan Power Company and Subsidiaries
Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30, 2021
Net Income
(in millions)
Six Months Ended June 30, 2020$156.1 
Changes in Gross Margin:
Retail Margins26.2 
Margins from Off-system Sales(0.2)
Transmission Revenues(5.0)
Other Revenues(0.1)
Total Change in Gross Margin20.9 
Changes in Expenses and Other:
Other Operation and Maintenance(40.7)
Depreciation and Amortization(19.0)
Taxes Other Than Income Taxes(3.9)
Other Income0.8 
Non-Service Cost Components of Net Periodic Benefit Cost(0.2)
Interest Expense2.4 
Total Change in Expenses and Other(60.6)
Income Tax Expense11.6 
Six Months Ended June 30, 2021$128.0 

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

•Retail Margins increased $26 million primarily due to the following:
•A $48 million increase due to wholesale true-up, Indiana and Michigan base rate revenuecases and increases in Texas and Louisiana.rider revenues. This increase was partially offset in other expense items below.
•A $14$10 million increase in weather-related usage primarily due to an 88%a 12% increase in heating degree days and a 14% increase in cooling degree days.
•A $3 million decrease in fuel related expenses due to timing of recovery related to wholesale contracts.
These increases were partially offset by:
•A $15$23 million decrease due to lowerin weather-normalized wholesale margins, including the loss of a significant wholesale contract.
•A $17 million decrease in weather-normalized retail margins.
•Transmission Revenues decreased $5 million primarily due to wholesale customer load loss from contracts that expired at the end of 2017.annual transmission formula rate true-up.
A $12 million decrease due to the 2018 provisions for customer refunds primarily related to Tax Reform. This decrease is offset in Income Tax Expense below.

Transmission Revenues increased $3 million primarily due to an increase in transmission investments in SPP.
93




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


•Other Operation and Maintenance expenses increased $15$41 million primarily due to the following:
•An $18 million increase in recoverable PJM expenses. This increase was partially offset in Retail Margins above.
•A $10$17 million increase in transmission expenses primarily due to an $11 million increase in vegetation management expenses and a $6 million increase as a result of the annual transmission formula rate true-up.
•A $6 million increase in employee-related expenses.
•A $6 million increase in distribution expenses primarily due to an increase in vegetation management expenses.
•A $4 million increase due to the Wind Catcher Project.
A $5 million increasea decreased Nuclear Electric Insurance Limited distribution in SPP transmission services.
A $3 million increase in employee-related expenses.2021.
These increases were partially offset by:
•A $10 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 $6 million decrease in Cook Plant refueling outage expenses.
•Depreciation and Amortization expensesincreased $19 million primarily due to a higher depreciable base and an increase in depreciation rates. This increase was partially offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $4 million primarily due to property taxes driven by an increase in utility plant and higher tax rates.
•Income Tax Expense decreased $12 million primarily due to a decrease in pretax book income and a decrease in state tax expense.
94





INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
 Three Months EndedSix Months Ended
 June 30,June 30,
 2021202020212020
REVENUES    
Electric Generation, Transmission and Distribution$569.2 $524.9 $1,116.9 $1,078.3 
Sales to AEP Affiliates0.7 4.9 1.5 7.8 
Other Revenues – Affiliated12.2 15.8 26.5 28.3 
Other Revenues – Nonaffiliated1.7 1.0 3.4 2.5 
TOTAL REVENUES583.8 546.6 1,148.3 1,116.9 
EXPENSES    
Fuel and Other Consumables Used for Electric Generation49.9 48.4 86.2 101.6 
Purchased Electricity for Resale39.7 40.5 87.0 90.6 
Purchased Electricity from AEP Affiliates57.8 43.7 109.4 79.9 
Other Operation160.3 149.5 314.9 294.2 
Maintenance64.4 44.3 113.4 93.4 
Depreciation and Amortization108.9 105.2 218.1 199.1 
Taxes Other Than Income Taxes29.8 25.7 56.0 52.1 
TOTAL EXPENSES510.8 457.3 985.0 910.9 
OPERATING INCOME73.0 89.3 163.3 206.0 
Other Income (Expense):    
Other Income3.4 3.1 6.4 5.6 
Non-Service Cost Components of Net Periodic Benefit Cost4.1 4.2 8.2 8.4 
Interest Expense(29.1)(28.1)(56.4)(58.8)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)51.4 68.5 121.5 161.2 
Income Tax Expense (Benefit)(5.8)4.7 (6.5)5.1 
NET INCOME$57.2 $63.8 $128.0 $156.1 
The common stock of I&M is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
95




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
 Three Months EndedSix Months Ended
 June 30,June 30,
2021202020212020
Net Income$57.2 $63.8 $128.0 $156.1 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES   
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended June 30, 2021 and 2020, Respectively, and $0.2 and $0.2 for the Six Months Ended June 30, 2021 and 2020, Respectively0.4 0.4 0.9 0.8 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2021 and 2020, Respectively, and $0 and $0 for the Six Months Ended June 30, 2021 and 2020, Respectively(0.1)0 (0.1)0 
TOTAL OTHER COMPREHENSIVE INCOME0.3 0.4 0.8 0.8 
TOTAL COMPREHENSIVE INCOME$57.5 $64.2 $128.8 $156.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
96




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Six Months Ended June 30, 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, 202056.6 980.9 1,589.9 (11.2)2,616.2 
Common Stock Dividends(21.2)(21.2)
Net Income63.8 63.8 
Other Comprehensive Income0.4 0.4 
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2020$56.6 $980.9 $1,632.5 $(10.8)$2,659.2 
     
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, 202156.6 980.9 1,764.5 (6.5)2,795.5 
Common Stock Dividends  (75.0) (75.0)
Net Income  57.2  57.2 
Other Comprehensive Income   0.3 0.3 
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2021$56.6 $980.9 $1,746.7 $(6.2)$2,778.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
97




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2021 and December 31, 2020
(in millions)
(Unaudited)
June 30,December 31,
 20212020
CURRENT ASSETS  
Cash and Cash Equivalents$2.5 $3.3 
Advances to Affiliates99.9 13.3 
Accounts Receivable:  
Customers50.7 44.0 
Affiliated Companies43.5 51.3 
Accrued Unbilled Revenues2.5 0 
Miscellaneous1.9 2.0 
Allowance for Uncollectible Accounts(0.2)(0.3)
Total Accounts Receivable98.4 97.0 
Fuel63.8 86.0 
Materials and Supplies171.0 175.8 
Risk Management Assets7.7 3.6 
Accrued Tax Benefits6.6 10.3 
Regulatory Asset for Under-Recovered Fuel Costs5.6 5.4 
Prepayments and Other Current Assets20.8 24.1 
TOTAL CURRENT ASSETS476.3 418.8 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation5,324.7 5,264.7 
Transmission1,727.0 1,696.4 
Distribution2,680.8 2,594.6 
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)699.4 686.7 
Construction Work in Progress368.4 362.4 
Total Property, Plant and Equipment10,800.3 10,604.8 
Accumulated Depreciation, Depletion and Amortization3,726.9 3,552.5 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET7,073.4 7,052.3 
OTHER NONCURRENT ASSETS  
Regulatory Assets433.1 404.8 
Spent Nuclear Fuel and Decommissioning Trusts3,612.4 3,306.7 
Operating Lease Assets175.9 218.1 
Deferred Charges and Other Noncurrent Assets226.5 237.6 
TOTAL OTHER NONCURRENT ASSETS4,447.9 4,167.2 
TOTAL ASSETS$11,997.6 $11,638.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
98




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
June 30, 2021 and December 31, 2020
(dollars in millions)
(Unaudited)
 June 30,December 31,
 20212020
CURRENT LIABILITIES  
Advances from Affiliates$0 $103.0 
Accounts Payable:  
General143.3 153.2 
Affiliated Companies74.2 80.5 
Long-term Debt Due Within One Year – Nonaffiliated
   (June 30, 2021 and December 31, 2020 Amounts Include $60.9 and $75.7,
   Respectively, Related to DCC Fuel)
140.2 369.6 
Risk Management Liabilities1.1 0.1 
Customer Deposits39.9 41.7 
Accrued Taxes93.5 102.5 
Accrued Interest37.7 35.6 
Obligations Under Operating Leases86.5 85.6 
Regulatory Liability for Over-Recovered Fuel Costs15.2 20.8 
Other Current Liabilities88.6 111.9 
TOTAL CURRENT LIABILITIES720.2 1,104.5 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated3,114.8 2,660.3 
Deferred Income Taxes1,093.4 1,064.4 
Regulatory Liabilities and Deferred Investment Tax Credits2,251.4 2,041.9 
Asset Retirement Obligations1,849.3 1,812.9 
Obligations Under Operating Leases91.9 135.9 
Deferred Credits and Other Noncurrent Liabilities98.6 69.2 
TOTAL NONCURRENT LIABILITIES8,499.4 7,784.6 
TOTAL LIABILITIES9,219.6 8,889.1 
Rate Matters (Note 4)00
Commitments and Contingencies (Note 5)00
COMMON SHAREHOLDER’S EQUITY  
Common Stock – NaN Par Value:  
Authorized – 2,500,000 Shares  
Outstanding – 1,400,000 Shares56.6 56.6 
Paid-in Capital980.9 980.9 
Retained Earnings1,746.7 1,718.7 
Accumulated Other Comprehensive Income (Loss)(6.2)(7.0)
TOTAL COMMON SHAREHOLDER’S EQUITY2,778.0 2,749.2 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$11,997.6 $11,638.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
99




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
 Six Months Ended June 30,
 20212020
OPERATING ACTIVITIES  
Net Income$128.0 $156.1 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: 
Depreciation and Amortization218.1 199.1 
Rockport Plant, Unit 2 Operating Lease Amortization33.9 34.6 
Deferred Income Taxes(8.2)(47.1)
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net(14.3)28.4 
Allowance for Equity Funds Used During Construction(7.0)(4.8)
Mark-to-Market of Risk Management Contracts(3.1)3.2 
Amortization of Nuclear Fuel40.4 45.6 
Deferred Fuel Over/Under-Recovery, Net(5.7)26.9 
Change in Other Noncurrent Assets11.7 16.1 
Change in Other Noncurrent Liabilities26.2 33.2 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net(0.4)(18.1)
Fuel, Materials and Supplies27.1 (26.9)
Accounts Payable16.4 (33.7)
Accrued Taxes, Net(5.3)2.7 
Rockport Plant, Unit 2 Operating Lease Payments(36.9)(36.9)
Other Current Assets2.0 9.7 
Other Current Liabilities(29.1)(44.5)
Net Cash Flows from Operating Activities393.8 343.6 
INVESTING ACTIVITIES  
Construction Expenditures(241.0)(267.6)
Change in Advances to Affiliates, Net(86.6)(0.1)
Purchases of Investment Securities(1,149.7)(971.4)
Sales of Investment Securities1,122.7 940.5 
Acquisitions of Nuclear Fuel(63.0)(37.7)
Other Investing Activities4.5 6.2 
Net Cash Flows Used for Investing Activities(413.1)(330.1)
FINANCING ACTIVITIES  
Issuance of Long-term Debt – Nonaffiliated507.0 0 
Change in Advances from Affiliates, Net(103.0)79.7 
Retirement of Long-term Debt – Nonaffiliated(282.7)(47.6)
Principal Payments for Finance Lease Obligations(3.3)(3.3)
Dividends Paid on Common Stock(100.0)(42.5)
Other Financing Activities0.5 0.2 
Net Cash Flows from (Used for) Financing Activities18.5 (13.5)
Net Decrease in Cash and Cash Equivalents(0.8)0 
Cash and Cash Equivalents at Beginning of Period3.3 2.0 
Cash and Cash Equivalents at End of Period$2.5 $2.0 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$52.1 $55.6 
Net Cash Paid for Income Taxes4.1 48.0 
Noncash Acquisitions Under Finance Leases2.8 1.6 
Construction Expenditures Included in Current Liabilities as of June 30,59.9 69.9 
Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30,0 22.3 
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage0.2 2.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
100






OHIO POWER COMPANY AND SUBSIDIARIES

101




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

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 Three Months EndedSix Months Ended
 June 30,June 30,
2021202020212020
 (in millions of KWhs)
Retail:    
Residential3,059 3,141 7,165 6,975 
Commercial3,668 3,157 7,170 6,673 
Industrial3,735 2,932 7,136 6,475 
Miscellaneous26 30 55 60 
Total Retail (a)10,488 9,260 21,526 20,183 
Wholesale (b)445 455 1,048 845 
Total KWhs10,933 9,715 22,574 21,028 

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

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

Summary of Heating and Cooling Degree Days
 Three Months EndedSix Months Ended
 June 30,June 30,
2021202020212020
 (in degree days)
Actual – Heating (a)215 292 1,992 1,765 
Normal – Heating (b)183 182 2,066 2,080 
Actual – Cooling (c)361 314 361 317 
Normal – Cooling (b)304 301 307 304 

(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.
102




Second Quarter of 2021 Compared to Second Quarter of 2020
Ohio Power Company and Subsidiaries
Reconciliation of Second Quarter of 2020 to Second Quarter of 2021
Net Income
(in millions)
Second Quarter of 2020$80.9 
Changes in Gross Margin:
Retail Margins45.8 
Margins from Off-system Sales(13.3)
Transmission Revenues0.5 
Other Revenues7.7 
Total Change in Gross Margin40.7 
Changes in Expenses and Other:
Other Operation and Maintenance(18.1)
Depreciation and Amortization(16.8)
Taxes Other Than Income Taxes(10.9)
Interest Income(0.1)
Carrying Costs Income(0.1)
Allowance for Equity Funds Used During Construction0.1 
Non-Service Cost Components of Net Periodic Benefit Cost(0.1)
Interest Expense(1.6)
Total Change in Expenses and Other(47.6)
Income Tax Expense— 
Second Quarter of 2021$74.0 

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

•Retail Margins increased $46 million primarily due to the following:
•A $30 million net increase in Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset in Other Operation and Maintenance expenses below.
•A $19 million increase in usage primarily from the commercial and residential classes of $11 million and $6 million, respectively.
•A $12 million increase in rider revenues associated with the DIR. This increase was partially offset in other expense items below.
•An $8 million increase due to a PUCO order to refund unused 2018 major storm reserve collections to customers in the prior period. This decrease was offset in Other Operation and Maintenance expenses below.
•A $7 million increase in the Legacy Generation Resource Rider (LGRR). This increase was offset in Margins from Off-system Sales and Other Revenues below.
•A $5 million increase in revenues associated with a vegetation management rider. This increase was partially offset in Other Operation and Maintenance expenses below.
These increases were partially offset by:
•A $19 million decrease due to the ending of the Energy Efficiency and Peak Demand Rider in December 2020. This decrease was partially offset in Other Operation and Maintenance expenses below.
•An $11 million decrease in revenues associated with the Universal Service Fund (USF). This decrease was offset in Other Operation and Maintenance expenses below.
•Margins from Off-system Sales decreased $13 million primarily due to unfavorable deferrals of OVEC costs. This decrease was offset in Retail Margins above and Other Revenues below.
103




•Other Revenues increased $8 million primarily due to third-party LGRR revenue related to the recovery of OVEC costs. 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 increased $18 million primarily due to the following:
•A $26 million increase in recoverable PJM expense. This increase was partially offset in Retail Margins above.
•A $9 million increase in PJM expenses primarily related to the annual formula rate true-up.
•An $8 million increase in distribution maintenance expenses related to the annual major storm reserve true-up. This increase was offset in retail margins.
•A $5 million increase in recoverable distribution expenses primarily related to vegetation management. This increase was offset in Retail Margins above.
These increases were partially offset by:
•An $11 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 $9 million decrease in energy efficiency/demand side management expenses. This decrease was partially offset within Retail Margins above.
•A $7 million decrease in factored customer accounts receivable expenses primarily due to bad debt expenses and a current year adjustment to allowance for doubtful accounts.
•Depreciation and Amortization expensesincreased $17 million primarily due to the following:
•A $6 million increase in recoverable DIR depreciable expense. This increase was partially offset in Retail Margins above.
•A $5 million increase in amortization of plant primarily related to capitalized software.
•A $3 million increase in depreciation expense due to a higher depreciable base of transmission and distribution assets.
•Taxes Other Than Income Taxes increased $11 million primarily due to property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
104




Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020
Ohio Power Company and Subsidiaries
Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30, 2021
Net Income
(in millions)
Six Months Ended June 30, 2020$156.0 
Changes in Gross Margin:
Retail Margins76.9 
Margins from Off-system Sales(27.3)
Transmission Revenues(2.3)
Other Revenues13.1 
Total Change in Gross Margin60.4 
Changes in Expenses and Other:
Other Operation and Maintenance(32.5)
Depreciation and Amortization(21.4)
Taxes Other Than Income Taxes(20.2)
Interest Income(0.1)
Allowance for Equity Funds Used During Construction0.9 
Non-Service Cost Components of Net Periodic Benefit Cost(0.2)
Interest Expense(4.3)
Total Change in Expenses and Other(77.8)
Income Tax Expense3.6 
Six Months Ended June 30, 2021$142.2 

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

•Retail Margins increased $77 million primarily due to the following:
•An $88 million net increase in Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset in Other Operation and Maintenance expenses below.
•A $19 million increase in usage from the commercial and residential classes of $11 million and $8 million, respectively.
•A $17 million increase in rider revenues associated with the DIR. This increase was partially offset in other expense items below.
•A $15 million increase in the LGRR. This increase was offset in Margins from Off-system Sales and Other Revenues below.
•A $10 million increase in revenues associated with a vegetation management rider. This increase was partially offset in Other Operation and Maintenance expenses below.
•An $8 million increase due to a PUCO order to refund unused 2018 major storm reserve collections to customers in the prior period. This increase was offset in Other Operation and Maintenance expenses below.
These increases were partially offset by:
•A $46 million decrease due to the ending of the Energy Efficiency and Peak Demand Rider in December 2020. This decrease was partially offset in Other Operation and Maintenance expenses below.
•A $27 million decrease in revenues associated with the USF. This decrease was offset in Other Operation and Maintenance expenses below.
•Margins from Off-system Sales decreased $27 million primarily due to unfavorable deferrals of OVEC costs. This decrease was offset in Retail Margins above and Other Revenues below.
•Other Revenues increased $13 million primarily due to third-party LGRR revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins and Margins from Off-system Sales above.
105





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

•Other Operation and Maintenance expenses increased $33 million primarily due to the following:
•A $78 million increase in recoverable PJM expense. This increase was partially offset in Retail Margins above.
•A $10 million increase in recoverable distribution expenses related to vegetation management. This increase was offset in Retail Margins above.
•A $9 million increase in PJM expenses primarily related to the annual formula rate true-up.
•An $8 million increase in distribution maintenance expenses related to the annual major storm reserve true-up. This increase was offset in retail margins.
These increases were partially offset by:
•A $30 million decrease in energy efficiency/demand side management expenses. This decrease was partially offset within Retail Margins above.
•A $27 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 $14 million decrease in factored customer accounts receivable expenses primarily due to bad debt expenses and a current year adjustment to allowance for doubtful accounts.
•Depreciation and Amortization expensesincreased $21 million primarily due to the following:
•An $8 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
•A $6 million increase in recoverable DIR depreciation expense. This increase was partially offset in Retail Margins above.
•A $6 million increase in amortization of plant primarily related to capitalized software.
•Taxes Other Than Income Taxes increased $20 million primarily due to property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
•Interest Expense increased $4 million primarily due to higher long-term debt balances.
•Income Tax Expense decreased $4 million due to a decrease in pretax book income.
106





OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
 Three Months EndedSix Months Ended
 June 30,June 30,
 2021202020212020
REVENUES    
Electricity, Transmission and Distribution$690.1 $621.8 $1,406.8 $1,301.0 
Sales to AEP Affiliates12.8 16.3 17.6 24.7 
Other Revenues2.0 2.3 4.4 5.0 
TOTAL REVENUES704.9 640.4 1,428.8 1,330.7 
EXPENSES    
Purchased Electricity for Resale153.6 113.9 328.9 263.0 
Purchased Electricity from AEP Affiliates14.4 30.3 44.5 72.7 
Other Operation193.2 186.6 377.8 363.9 
Maintenance38.4 26.9 77.1 58.5 
Depreciation and Amortization76.6 59.8 151.7 130.3 
Taxes Other Than Income Taxes118.9 108.0 240.2 220.0 
TOTAL EXPENSES595.1 525.5 1,220.2 1,108.4 
OPERATING INCOME109.8 114.9 208.6 222.3 
Other Income (Expense):    
Interest Income0.1 0.2 0.3 0.4 
Carrying Costs Income0.5 0.6 1.0 1.0 
Allowance for Equity Funds Used During Construction2.9 2.8 5.6 4.7 
Non-Service Cost Components of Net Periodic Benefit Cost3.6 3.7 7.3 7.5 
Interest Expense(31.7)(30.1)(63.3)(59.0)
INCOME BEFORE INCOME TAX EXPENSE85.2 92.1 159.5 176.9 
Income Tax Expense11.2 11.2 17.3 20.9 
NET INCOME$74.0 $80.9 $142.2 $156.0 
The common stock of OPCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
107




OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Three Months EndedSix Months Ended
June 30,June 30,
2021202020212020
Net Income$74.0 $80.9 $142.2 $156.0 
OTHER COMPREHENSIVE LOSS, NET OF TAXES    
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2021 and 2020, Respectively, and $0 and $0 for the Six Months Ended June 30, 2021 and 2020, Respectively0 0 0 0 
TOTAL COMPREHENSIVE INCOME$74.0 $80.9 $142.2 $156.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
108




OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Six Months Ended June 30, 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$321.2 $838.8 $1,348.5 $0 $2,508.5 
Common Stock Dividends(21.9)(21.9)
ASU 2016-13 Adoption0.3 0.3 
Net Income75.1 75.1 
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2020321.2 838.8 1,402.0 0 2,562.0 
Common Stock Dividends  (21.9) (21.9)
Net Income  80.9  80.9 
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2020$321.2 $838.8 $1,461.0 $0 $2,621.0 
     
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020$321.2 $838.8 $1,532.7 $0 $2,692.7 
Common Stock Dividends(21.9)(21.9)
Net Income68.2 68.2 
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2021321.2 838.8 1,579.0 0 2,739.0 
Common Stock Dividends  (21.9) (21.9)
Net Income  74.0  74.0 
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2021$321.2 $838.8 $1,631.1 $0 $2,791.1 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
109




OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2021 and December 31, 2020
(in millions)
(Unaudited)
 June 30,December 31,
 20212020
CURRENT ASSETS  
Cash and Cash Equivalents$5.8 $7.4 
Accounts Receivable:  
Customers86.1 50.0 
Affiliated Companies74.7 65.1 
Accrued Unbilled Revenues16.4 14.8 
Miscellaneous7.1 3.9 
Allowance for Uncollectible Accounts(0.7)(0.6)
Total Accounts Receivable183.6 133.2 
Materials and Supplies68.8 66.9 
Renewable Energy Credits31.7 29.5 
Prepayments and Other Current Assets23.7 19.3 
TOTAL CURRENT ASSETS313.6 256.3 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Transmission2,901.5 2,831.9 
Distribution5,889.8 5,708.3 
Other Property, Plant and Equipment959.8 899.6 
Construction Work in Progress341.1 362.3 
Total Property, Plant and Equipment10,092.2 9,802.1 
Accumulated Depreciation and Amortization2,416.0 2,350.0 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET7,676.2 7,452.1 
OTHER NONCURRENT ASSETS  
Regulatory Assets399.7 385.8 
Operating Lease Assets86.6 92.0 
Deferred Charges and Other Noncurrent Assets383.9 524.2 
TOTAL OTHER NONCURRENT ASSETS870.2 1,002.0 
TOTAL ASSETS$8,860.0 $8,710.4 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
110




OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
June 30, 2021 and December 31, 2020
(Unaudited)
 June 30,December 31,
 20212020
(in millions)
CURRENT LIABILITIES  
Advances from Affiliates$56.3 $259.2 
Accounts Payable:  
General186.9 181.0 
Affiliated Companies95.6 118.4 
Long-term Debt Due Within One Year – Nonaffiliated500.1 500.1 
Risk Management Liabilities7.3 8.7 
Customer Deposits76.7 55.1 
Accrued Taxes413.9 631.0 
Obligations Under Operating Leases13.1 13.1 
Other Current Liabilities131.0 139.6 
TOTAL CURRENT LIABILITIES1,480.9 1,906.2 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated2,376.7 1,930.1 
Long-term Risk Management Liabilities98.2 101.6 
Deferred Income Taxes994.5 955.1 
Regulatory Liabilities and Deferred Investment Tax Credits999.3 1,005.2 
Obligations Under Operating Leases74.1 79.5 
Deferred Credits and Other Noncurrent Liabilities45.2 40.0 
TOTAL NONCURRENT LIABILITIES4,588.0 4,111.5 
TOTAL LIABILITIES6,068.9 6,017.7 
Rate Matters (Note 4)00
Commitments and Contingencies (Note 5)00
COMMON SHAREHOLDER’S EQUITY  
Common Stock –NaN Par Value:  
Authorized – 40,000,000 Shares  
Outstanding – 27,952,473 Shares321.2 321.2 
Paid-in Capital838.8 838.8 
Retained Earnings1,631.1 1,532.7 
TOTAL COMMON SHAREHOLDER’S EQUITY2,791.1 2,692.7 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$8,860.0 $8,710.4 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
111




OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
 Six Months Ended June 30,
 20212020
OPERATING ACTIVITIES  
Net Income$142.2 $156.0 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and Amortization151.7 130.3 
Deferred Income Taxes21.5 21.6 
Allowance for Equity Funds Used During Construction(5.6)(4.7)
Mark-to-Market of Risk Management Contracts(4.8)13.9 
Property Taxes154.2 151.4 
Change in Other Noncurrent Assets(45.8)(103.2)
Change in Other Noncurrent Liabilities7.2 (45.4)
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net(47.9)(14.1)
Materials and Supplies(3.0)(16.8)
Accounts Payable(13.6)(23.1)
Accrued Taxes, Net(222.8)(150.8)
Other Current Assets0.8 3.1 
Other Current Liabilities13.9 (25.7)
Net Cash Flows from Operating Activities148.0 92.5 
INVESTING ACTIVITIES  
Construction Expenditures(353.3)(416.7)
Other Investing Activities6.6 10.3 
Net Cash Flows Used for Investing Activities(346.7)(406.4)
FINANCING ACTIVITIES  
Issuance of Long-term Debt – Nonaffiliated445.8 347.0 
Change in Advances from Affiliates, Net(202.9)12.1 
Retirement of Long-term Debt – Nonaffiliated(0.1)0 
Principal Payments for Finance Lease Obligations(2.4)(2.4)
Dividends Paid on Common Stock(43.8)(43.8)
Other Financing Activities0.5 0.6 
Net Cash Flows from Financing Activities197.1 313.5 
Net Decrease in Cash and Cash Equivalents(1.6)(0.4)
Cash and Cash Equivalents at Beginning of Period7.4 3.7 
Cash and Cash Equivalents at End of Period$5.8 $3.3 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$58.4 $54.1 
Net Cash Paid for Income Taxes1.3 2.4 
Noncash Acquisitions Under Finance Leases0.9 4.9 
Construction Expenditures Included in Current Liabilities as of June 30,70.9 74.1 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
112






PUBLIC SERVICE COMPANY OF OKLAHOMA
113




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

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 Three Months EndedSix Months Ended
 June 30,June 30,
2021202020212020
 (in millions of KWhs)
Retail:    
Residential1,312 1,457 2,889 2,819 
Commercial1,255 1,136 2,305 2,191 
Industrial1,513 1,401 2,817 2,838 
Miscellaneous310 293 580 565 
Total Retail4,390 4,287 8,591 8,413 
Wholesale121 78 188 131 
Total KWhs4,511 4,365 8,779 8,544 

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

Summary of Heating and Cooling Degree Days
 Three Months EndedSix Months Ended
 June 30,June 30,
2021202020212020
 (in degree days)
Actual – Heating (a)45 74 1,195 873 
Normal – Heating (b)44 43 1,077 1,077 
Actual – Cooling (c)577 672 584 705 
Normal – Cooling (b)658 659 675 676 

(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.
114




Second Quarter of 2021 Compared to Second Quarter of 2020
Public Service Company of Oklahoma
Reconciliation of Second Quarter of 2020 to Second Quarter of 2021
Net Income
(in millions)
Second Quarter of 2020$46.4 
Changes in Gross Margin:
Retail Margins (a)13.1 
Margins from Off-system Sales(0.2)
Transmission Revenues2.2 
Other Revenues(5.8)
Total Change in Gross Margin9.3 
Changes in Expenses and Other:
Other Operation and Maintenance(9.6)
Depreciation and Amortization(5.2)
Taxes Other Than Income Taxes(0.1)
Interest Income1.6 
Allowance for Equity Funds Used During Construction(0.3)
Non-Service Cost Components of Net Periodic Benefit Cost0.1 
Interest Expense1.4 
Total Change in Expenses and Other(12.1)
Income Tax Expense2.5 
Second Quarter of 2021$46.1 

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

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

•Retail Margins increased $13 million primarily due to the following:
•A $17 million increase in revenue from rate riders. This increase was partially offset in other expense items below.
•A $5 million increase in weather-normalized retail margins.
These increases were partially offset by:
•A $6 million decrease in weather-related usage primarily due to a 14% decrease in cooling degree days and a 39% decrease in heating degree days.
•A $3 million increase in fuel expense due to production tax credits passed back to customers. This increase is offset in Income Tax Expense.
•Other Revenues decreased $6 million primarily due to business development revenue. This decrease was partially offset in Other Operation and Maintenance expenses below.

Expenses and Other changed between years as follows:

•Other Operation and Maintenance expenses increased $10 million primarily due to the following:
•A $10 million increase in transmission expenses primarily due to a $6 million increase as a result of the annual transmission formula rate true-up and a $4 million increase in recoverable SPP expense. These increases were partially offset in Retail Margins above.
•A $4 million increase due to the prior year capitalization of previously expensed North Central Wind Energy Facilities costs.
115





These increases were partially offset by:
•A $4 million decrease in business development expenses. This decrease was partially offset in Other Revenues above.
•A $3 million decrease in distribution expenses primarily due to distribution system improvementsa decrease in 2017.overhead line maintenance.
•Depreciation and Amortization increased $5 million primarily due to a higher depreciable base and the timing of refunds to customers under rate rider mechanisms.
116




Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020
Public Service Company of Oklahoma
Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30, 2021
Net Income
(in millions)
Six Months Ended June 30, 2020$36.1 
Changes in Gross Margin:
Retail Margins (a)17.2 
Margin from Off-system Sales(0.3)
Transmission Revenues3.2 
Other Revenues(5.6)
Total Change in Gross Margin14.5 
Changes in Expenses and Other:
Other Operation and Maintenance(1.5)
Depreciation and Amortization(10.4)
Taxes Other Than Income Taxes(1.3)
Interest Income1.6 
Allowance for Equity Funds Used During Construction(0.9)
Non-Service Cost Components of Net Periodic Benefit Cost0.1 
Interest Expense2.8 
Total Change in Expenses and Other(9.6)
Income Tax Expense2.4 
Six Months Ended June 30, 2021$43.4 
(a)Includes firm wholesale sales to municipals and cooperatives.

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

•Retail Margins increased $17 million primarily due to the following:
•A $19 million increase in revenue from rate riders. This increase was partially offset in other expense items below.
•A $4 million increase in weather-normalized retail margins.
These increases were partially offset by:
•A $3 million decrease in weather-related usage primarily due to a 17% decrease in cooling degree days partially offset by a 37% increase in heating degree days.
•A $3 million increase in fuel expense due to production tax credits passed back to customers. This increase is offset in Income Tax Expense.
•Transmission Revenues increased $3 million primarily due to the annual transmission formula rate true-up.
•Other Revenues decreased $6 million primarily due to business development revenue. This decrease was partially offset in Other Operation and Maintenance expenses below.

Expenses and Other changed between years as follows:

•Other Operation and Maintenance expenses increased $2 million primarily due to the following:
•A $9 million increase in transmission expenses primarily due to a $6 million increase as a result of the annual transmission formula rate true-up and a $3 million increase in recoverable SPP expense. These increases were partially offset in Retail Margins above.
•A $3 million increase due to the prior year capitalization of previously expensed North Central Wind Energy Facilities costs.

117




These increases were partially offset by:
•An $8 million decrease in distribution expenses primarily due to a decrease in overhead line maintenance.
•A $4 million decrease in business development expenses. This decrease was partially offset in Other Revenues above.
•Depreciation and Amortization expenses increased $10 million primarily due to a higher depreciable base and the timing of refunds to customers under rate rider mechanisms.
118





PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
 Three Months EndedSix Months Ended
 June 30,June 30,
 2021202020212020
REVENUES    
Electric Generation, Transmission and Distribution$342.5 $301.1 $636.1 $596.5 
Sales to AEP Affiliates1.1 1.3 2.1 2.4 
Other Revenues0.9 6.2 2.4 7.0 
TOTAL REVENUES344.5 308.6 640.6 605.9 
EXPENSES    
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation124.0 97.4 244.9 224.7 
Other Operation81.3 69.6 160.4 156.8 
Maintenance22.5 24.6 46.9 49.0 
Depreciation and Amortization50.2 45.0 100.1 89.7 
Taxes Other Than Income Taxes12.5 12.4 25.0 23.7 
TOTAL EXPENSES290.5 249.0 577.3 543.9 
OPERATING INCOME54.0 59.6 63.3 62.0 
Other Income (Expense):    
Interest Income1.6 0 1.7 0.1 
Allowance for Equity Funds Used During Construction0.6 0.9 1.0 1.9 
Non-Service Cost Components of Net Periodic Benefit Cost2.2 2.1 4.3 4.2 
Interest Expense(14.1)(15.5)(28.5)(31.3)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)44.3 47.1 41.8 36.9 
Income Tax Expense (Benefit)(1.8)0.7 (1.6)0.8 
NET INCOME$46.1 $46.4 $43.4 $36.1 
The common stock of PSO is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
119




PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
 Three Months EndedSix Months Ended
 June 30,June 30,
2021202020212020
Net Income$46.1 $46.4 $43.4 $36.1 
OTHER COMPREHENSIVE LOSS, NET OF TAXES    
Cash Flow Hedges, Net of Tax of $0 and $(0.1) for the Three Months Ended June 30, 2021 and 2020, Respectively, and $0 and $(0.2) for the Six Months Ended June 30, 2021 and 2020, Respectively.0 (0.3)(0.1)(0.5)
    
TOTAL COMPREHENSIVE INCOME$46.1 $46.1 $43.3 $35.6 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
120




PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Six Months Ended June 30, 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$157.2 $364.0 $851.0 $1.1 $1,373.3 
ASU 2016-13 Adoption0.30.3 
Net Loss(10.3)(10.3)
Other Comprehensive Loss(0.2)(0.2)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2020157.2 364.0 841.0 0.9 1,363.1 
Net Income  46.4  46.4 
Other Comprehensive Loss   (0.3)(0.3)
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2020$157.2 $364.0 $887.4 $0.6 $1,409.2 
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020$157.2 $414.0 $974.3 $0.1 $1,545.6 
Capital Contribution from Parent425.0425.0 
Net Loss(2.7)(2.7)
Other Comprehensive Loss(0.1)(0.1)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2021157.2 839.0 971.6 0 1,967.8 
Capital Contribution from Parent200.0 200.0 
Common Stock Dividends  (10.0) (10.0)
Net Income  46.1  46.1 
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2021$157.2 $1,039.0 $1,007.7 $0 $2,203.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
121




PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
June 30, 2021 and December 31, 2020
(in millions)
(Unaudited)
 June 30,December 31,
 20212020
CURRENT ASSETS  
Cash and Cash Equivalents$2.6 $2.6 
Accounts Receivable:  
Customers38.6 30.8 
Affiliated Companies31.9 15.6 
Miscellaneous0 2.0 
Total Accounts Receivable70.5 48.4 
Fuel10.6 17.9 
Materials and Supplies52.8 54.0 
Risk Management Assets23.0 10.3 
Accrued Tax Benefits0.2 10.9 
Regulatory Asset for Under-Recovered Fuel Costs84.8 30.1 
Prepayments and Other Current Assets11.5 7.1 
TOTAL CURRENT ASSETS256.0 181.3 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation1,609.3 1,480.7 
Transmission1,088.1 1,069.9 
Distribution2,927.2 2,853.0 
Other Property, Plant and Equipment420.2 393.3 
Construction Work in Progress106.9 128.7 
Total Property, Plant and Equipment6,151.7 5,925.6 
Accumulated Depreciation and Amortization1,653.2 1,605.6 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET4,498.5 4,320.0 
OTHER NONCURRENT ASSETS  
Regulatory Assets1,054.0 375.0 
Employee Benefits and Pension Assets66.1 65.8 
Operating Lease Assets54.1 42.6 
Deferred Charges and Other Noncurrent Assets29.7 6.0 
TOTAL OTHER NONCURRENT ASSETS1,203.9 489.4 
TOTAL ASSETS$5,958.4 $4,990.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
122




PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
June 30, 2021 and December 31, 2020
(Unaudited)
 June 30,December 31,
 20212020
 (in millions)
CURRENT LIABILITIES  
Advances from Affiliates$135.1 $155.4 
Accounts Payable:  
General117.1 107.0 
Affiliated Companies41.6 43.4 
Long-term Debt Due Within One Year – Nonaffiliated0.5 0.5 
Customer Deposits54.1 54.8 
Accrued Taxes75.3 26.8 
Obligations Under Operating Leases6.7 6.5 
Other Current Liabilities61.8 84.2 
TOTAL CURRENT LIABILITIES492.2 478.6 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated1,623.3 1,373.3 
Deferred Income Taxes668.4 688.5 
Regulatory Liabilities and Deferred Investment Tax Credits852.6 802.2 
Asset Retirement Obligations49.7 45.7 
Obligations Under Operating Leases47.5 36.2 
Deferred Credits and Other Noncurrent Liabilities20.8 20.6 
TOTAL NONCURRENT LIABILITIES3,262.3 2,966.5 
TOTAL LIABILITIES3,754.5 3,445.1 
Rate Matters (Note 4)00
Commitments and Contingencies (Note 5)00
COMMON SHAREHOLDER’S EQUITY  
Common Stock – Par Value – $15 Per Share:  
Authorized – 11,000,000 Shares  
Issued – 10,482,000 Shares  
Outstanding – 9,013,000 Shares157.2 157.2 
Paid-in Capital1,039.0 414.0 
Retained Earnings1,007.7 974.3 
Accumulated Other Comprehensive Income (Loss)0 0.1 
TOTAL COMMON SHAREHOLDER’S EQUITY2,203.9 1,545.6 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$5,958.4 $4,990.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
123




PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
 Six Months Ended June 30,
 20212020
OPERATING ACTIVITIES  
Net Income$43.4 $36.1 
Adjustments to Reconcile Net Loss to Net Cash Flows from (Used for) Operating Activities:  
Depreciation and Amortization100.1 89.7 
Deferred Income Taxes25.7 (9.2)
Allowance for Equity Funds Used During Construction(1.0)(1.9)
Mark-to-Market of Risk Management Contracts(12.7)(7.9)
Property Taxes(21.8)(21.2)
Deferred Fuel Over/Under-Recovery, Net(724.1)(17.1)
Change in Other Noncurrent Assets(16.6)(4.8)
Change in Other Noncurrent Liabilities0.4 1.3 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net(22.1)(24.3)
Fuel, Materials and Supplies8.5 (18.1)
Accounts Payable11.7 (1.5)
Accrued Taxes, Net59.2 38.5 
Other Current Assets(4.4)1.8 
Other Current Liabilities(22.0)(10.0)
Net Cash Flows from (Used for) Operating Activities(575.7)51.4 
INVESTING ACTIVITIES  
Construction Expenditures(145.9)(184.8)
Change in Advances to Affiliates, Net0 38.8 
Acquisition of the North Central Wind Energy Facilities(122.8)0 
Other Investing Activities1.3 2.0 
Net Cash Flows Used for Investing Activities(267.4)(144.0)
FINANCING ACTIVITIES  
Capital Contributions from Parent625.0 0 
Issuance of Long-term Debt – Nonaffiliated500.0 0 
Change in Advances from Affiliates, Net(20.3)106.9 
Retirement of Long-term Debt – Nonaffiliated(250.3)(12.9)
Principal Payments for Finance Lease Obligations(1.7)(1.8)
Dividends Paid on Common Stock(10.0)0 
Other Financing Activities0.4 0.3 
Net Cash Flows from Financing Activities843.1 92.5 
Net Decrease in Cash and Cash Equivalents0 (0.1)
Cash and Cash Equivalents at Beginning of Period2.6 1.5 
Cash and Cash Equivalents at End of Period$2.6 $1.4 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$32.2 $30.6 
Net Cash Paid (Received) for Income Taxes(65.0)(2.7)
Noncash Acquisitions Under Finance Leases2.3 2.6 
Construction Expenditures Included in Current Liabilities as of June 30,27.9 25.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
124






SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

125




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

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
Three Months EndedSix Months Ended
 June 30,June 30,
 2021202020212020
 (in millions of KWhs)
Retail:    
Residential1,274 1,346 2,974 2,752 
Commercial1,396 1,236 2,605 2,464 
Industrial1,294 1,187 2,265 2,429 
Miscellaneous21 20 39 40 
Total Retail3,985 3,789 7,883 7,685 
Wholesale1,392 1,184 2,933 2,510 
Total KWhs5,377 4,973 10,816 10,195 

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

Summary of Heating and Cooling Degree Days
Three Months EndedSix Months Ended
 June 30,June 30,
 2021202020212020
 (in degree days)
Actual – Heating (a)26 25 789 522 
Normal – Heating (b)25 25 722 723 
Actual – Cooling (c)728 674 773 743 
Normal – Cooling (b)739 741 779 780 

(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.

126




Second Quarter of 2021 Compared to Second Quarter of 2020
Reconciliation of Second Quarter of 2020 to Second Quarter of 2021
Earnings Attributable to SWEPCo Common Shareholder
(in millions)
Second Quarter of 2020$58.8 
Changes in Gross Margin:
Retail Margins (a)5.9 
Margins from Off-system Sales1.0 
Transmission Revenues(4.9)
Other Revenues1.2 
Total Change in Gross Margin3.2 
Changes in Expenses and Other:
Other Operation and Maintenance(17.7)
Depreciation and Amortization(4.9)
Taxes Other Than Income Taxes(5.1)
Interest Income2.6 
Allowance for Equity Funds Used During Construction1.0 
Non-Service Cost Components of Net Periodic Benefit Cost(0.1)
Interest Expense(1.7)
Total Change in Expenses and Other(25.9)
Income Tax Expense0.8 
Equity Earnings of Unconsolidated Subsidiary0.1 
Net Income Attributable to Noncontrolling Interest(0.2)
Second Quarter of 2021$36.8 

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

•Retail Margins increased $6 million primarily due to the following:
•A $3 million increase in weather-related usage primarily due to an 8% increase in cooling degree days.
•A $3 million increase in municipal and cooperative revenues primarily due to the annual generation formula rate true-up.
•Transmission Revenues decreased $5 million primarily due to the following:
•An $8 million decrease due to the annual transmission formula rate true-up.
This decrease was partially offset by:
•A $3 million increase due to an increase in transmission investment.
Expenses and Other and Income Tax Expense changed between years as follows:

•Other Operation and Maintenance expenses increased $18 million primarily due to the following:
•A $14 million increase in transmission related expenses primarily due to a $10 million increase as a result of the annual formula rate true-up.
•A $6 million increase due to the prior year capitalization of previously expensed North Central Wind Energy Facilities costs.
•A $4 million increase in regulatory and rate case related expenses.
These increases were partially offset by:
•A $6 million decrease in overhead line maintenance primarily related to storm restoration.
•Depreciation and Amortization expenses increased $5 million primarily due to a higher depreciable base.
127




•Taxes Other Than Income Taxes increased $5 million primarily due to increased property taxes resulting from the expiration of the Louisiana Industrial Tax Exemption related to the Stall Plant.
•Income Tax Expense decreased $1 million primarily due to a decrease in pretax book income partially offset by a decrease in amortization of Excess ADIT. The decrease in amortization of Excess ADIT was partially offset in Retail Margins above.
128




Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020
Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30, 2021
Earnings Attributable to SWEPCo Common Shareholder
(in millions)
Six Months Ended June 30, 2020$73.9 
Changes in Gross Margin:
Retail Margins (a)46.1 
Margins from Off-system Sales21.2 
Transmission Revenues(2.7)
Other Revenues1.2 
Total Change in Gross Margin65.8 
Changes in Expenses and Other:
Other Operation and Maintenance(16.0)
Depreciation and Amortization(7.2)
Taxes Other Than Income Taxes(9.8)
Interest Income3.0 
Allowance for Equity Funds Used During Construction1.7 
Non-Service Cost Components of Net Periodic Benefit Cost(0.1)
Interest Expense(0.9)
Total Change in Expenses and Other(29.3)
Income Tax Expense(11.0)
Net Income Attributable to Noncontrolling Interest(0.2)
Six Months Ended June 30, 2021$99.2 

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

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

•Retail Margins increased $46 million primarily due to the following:
•A $13 million increase in weather-related usage primarily due to a 51% increase in heating degree days.
•A $10 million increase in weather-normalized wholesale margins.
•An $8 million increase in recoverable fuel costs primarily due to timing of recovery.
•A $5 million increase in municipal and cooperative revenues primarily due to the annual generation formula rate true-up.
•A $5 million increase due to a decrease in the return of Excess ADIT benefits to customers. This increase was offset in Income Tax Expense below.
•A $4 million increase in weather-normalized retail margins.
•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.
•Transmission Revenues decreased $3 million primarily due to the following:
•An $8 million decrease due to the annual transmission formula rate true-up.
This decrease was partially offset by:
•A $5 million increase due to an increase in transmission investment.
129




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

•Other Operation and Maintenance expenses increased $16 million primarily due to the following:
•A $15 million increase in transmission related expenses primarily due to a $10 million increase as a result of the annual formula rate true-up.
•A $5 million increase due to the prior year capitalization of previously expensed North Central Wind Energy Facilities costs.
•Depreciation and Amortization expenses increased $7 million primarily due to a higher depreciable base.


•Taxes Other Than Income Tax Expense decreased $7Taxes increased $10 million primarily due to increased property taxes resulting from the changeexpiration of the Louisiana Industrial Tax Exemption related to Stall Plant.
•Interest Income increased $3 million primarily related to carrying charges on regulatory assets resulting from the February 2021 severe winter weather event.
•Income Tax Expense increased $11 million primarily due to an increase in the corporate federalpretax book income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, amortization of excess accumulated deferred income taxes associated with certain depreciable property and a decrease in pretax book income.amortization of Excess ADIT. The decrease in amortization of Excess ADIT was partially offset in Retail Margins above.
130








SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended March 31, 2018June 30, 2021 and 20172020
(in millions)
(Unaudited)
Three Months EndedSix Months Ended
 Three Months Ended March 31, June 30,June 30,
 2018 2017 2021202020212020
REVENUES    REVENUES    
Electric Generation, Transmission and Distribution $413.0
 $396.3
Electric Generation, Transmission and Distribution$418.8 $401.0 $1,026.5 $778.6 
Sales to AEP Affiliates 6.1
 4.6
Sales to AEP Affiliates10.9 13.1 18.7 20.6 
Other Revenues 0.3
 0.4
Other Revenues0.4 0.9 1.0 1.7 
TOTAL REVENUES 419.4
 401.3
TOTAL REVENUES430.1 415.0 1,046.2 800.9 
    
EXPENSES  
  
EXPENSES    
Fuel and Other Consumables Used for Electric Generation 126.8
 130.9
Purchased Electricity for Resale 42.7
 32.4
Purchased Electricity, Fuel and Other Consumables Used for Electric GenerationPurchased Electricity, Fuel and Other Consumables Used for Electric Generation138.5 126.6 438.3 258.8 
Other Operation 94.9
 78.9
Other Operation88.6 70.0 178.9 162.2 
Maintenance 31.0
 32.2
Maintenance31.8 32.7 65.8 66.5 
Depreciation and Amortization 57.4
 50.8
Depreciation and Amortization73.0 68.1 142.6 135.4 
Taxes Other Than Income Taxes 25.0
 23.3
Taxes Other Than Income Taxes30.1 25.0 60.1 50.3 
TOTAL EXPENSES 377.8
 348.5
TOTAL EXPENSES362.0 322.4 885.7 673.2 
    
OPERATING INCOME 41.6
 52.8
OPERATING INCOME68.1 92.6 160.5 127.7 
    
Other Income (Expense):  
  
Other Income (Expense):   
Interest Income 1.8
 0.9
Interest Income3.1 0.5 4.1 1.1 
Allowance for Equity Funds Used During Construction 2.3
 0.8
Allowance for Equity Funds Used During Construction1.9 0.9 4.0 2.3 
Non-Service Cost Components of Net Periodic Benefit Cost 2.3
 0.9
Non-Service Cost Components of Net Periodic Benefit Cost2.0 2.1 4.1 4.2 
Interest Expense (32.2) (29.9)Interest Expense(31.4)(29.7)(60.7)(59.8)
    
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS 15.8
 25.5
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS43.7 66.4 112.0 75.5 
    
Income Tax Expense 2.9
 9.5
Income Tax Expense7.1 7.9 12.7 1.7 
Equity Earnings of Unconsolidated Subsidiary 0.5
 1.3
Equity Earnings of Unconsolidated Subsidiary0.8 0.7 1.5 1.5 
    
NET INCOME 13.4
 17.3
NET INCOME37.4 59.2 100.8 75.3 
    
Net Income Attributable to Noncontrolling Interest 1.6
 1.0
Net Income Attributable to Noncontrolling Interest0.6 0.4 1.6 1.4 
    
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER $11.8
 $16.3
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER$36.8 $58.8 $99.2 $73.9 
The common stock of SWEPCo is wholly-owned by Parent.The common stock of SWEPCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
The common stock of SWEPCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.
131






SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended March 31, 2018June 30, 2021 and 20172020
(in millions)
(Unaudited)
 Three Months EndedSix Months Ended
 June 30,June 30,
 2021202020212020
Net Income$37.4 $59.2 $100.8 $75.3 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES    
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended June 30, 2021 and 2020, Respectively, and $0.2 and $0.2 for the Six Months Ended June 30, 2021 and 2020, Respectively0.4 0.3 0.8 0.7 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended June 30, 2021 and 2020, Respectively, and $(0.2) and $(0.2) for the Six Months Ended June 30, 2021 and 2020, Respectively(0.4)(0.3)(0.8)(0.7)
TOTAL OTHER COMPREHENSIVE INCOME0 0 0 0 
TOTAL COMPREHENSIVE INCOME37.4 59.2 100.8 75.3 
Total Comprehensive Income Attributable to Noncontrolling Interest0.6 0.4 1.6 1.4 
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER$36.8 $58.8 $99.2 $73.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
132
 Three Months Ended March 31,
 2018 2017
Net Income$13.4
 $17.3
    
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES 
  
Cash Flow Hedges, Net of Tax of $0.1 and $0.2 in 2018 and 2017, Respectively0.4
 0.5
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) in 2018 and 2017, Respectively(0.3) (0.2)
    
TOTAL OTHER COMPREHENSIVE INCOME0.1
 0.3
    
TOTAL COMPREHENSIVE INCOME13.5
 17.6
    
Total Comprehensive Income Attributable to Noncontrolling Interest1.6
 1.0
  
  
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER$11.9
 $16.6


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the ThreeSix Months Ended March 31, 2018June 30, 2021 and 20172020
(in millions)
(Unaudited)
   SWEPCo Common Shareholder    
 Common
Stock		 Paid-in
Capital		 Retained
Earnings		 Accumulated
Other
Comprehensive
Income (Loss)		 
Noncontrolling
Interest
 Total
TOTAL EQUITY – DECEMBER 31, 2016$135.7
 $676.6
 $1,411.9
 $(9.4) $0.4
 $2,215.2
            
Common Stock Dividends    (27.5)     (27.5)
Common Stock Dividends – Nonaffiliated 
  
  
  
 (1.1) (1.1)
Net Income 
  
 16.3
  
 1.0
 17.3
Other Comprehensive Income 
  
  
 0.3
  
 0.3
TOTAL EQUITY – MARCH 31, 2017$135.7
 $676.6
 $1,400.7
 $(9.1) $0.3
 $2,204.2
            
TOTAL EQUITY – DECEMBER 31, 2017$135.7
 $676.6
 $1,426.6
 $(4.0) $(0.4) $2,234.5
            
Common Stock Dividends 
  
 (20.0)  
  
 (20.0)
Common Stock Dividends – Nonaffiliated 
  
  
  
 (0.8) (0.8)
ASU 2018-02 Adoption    (0.4) (0.9)   (1.3)
Net Income 
  
 11.8
  
 1.6
 13.4
Other Comprehensive Income 
  
  
 0.1
  
 0.1
TOTAL EQUITY – MARCH 31, 2018$135.7
 $676.6
 $1,418.0
 $(4.8) $0.4
 $2,225.9
SWEPCo Common Shareholder  
Common
Stock		Paid-in
Capital		Retained
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Noncontrolling
Interest		Total
TOTAL EQUITY – DECEMBER 31, 2019$135.7 $676.6 $1,629.5 $(1.3)$0.6 $2,441.1 
Common Stock Dividends – Nonaffiliated(0.7)(0.7)
ASU 2016-13 Adoption1.6 1.6 
Net Income15.1 1.0 16.1 
TOTAL EQUITY – MARCH 31, 2020135.7 676.6 1,646.2 (1.3)0.9 2,458.1 
Common Stock Dividends – Nonaffiliated    (1.2)(1.2)
Net Income  58.8  0.4 59.2 
TOTAL EQUITY – JUNE 30, 2020$135.7 $676.6 $1,705.0 $(1.3)$0.1 $2,516.1 
TOTAL EQUITY – DECEMBER 31, 2020$0.1 $812.2 $1,811.9 $1.9 $1.6 $2,627.7 
Capital Contribution from Parent100.0100.0 
Common Stock Dividends – Nonaffiliated(1.0)(1.0)
Net Income62.4 1.0 63.4 
TOTAL EQUITY – MARCH 31, 20210.1 912.2 1,874.3 1.9 1.6 2,790.1 
Capital Contribution from Parent75.075.0 
Common Stock Dividends – Nonaffiliated    (0.6)(0.6)
Net Income  36.8  0.6 37.4 
TOTAL EQUITY – JUNE 30, 2021$0.1 $987.2 $1,911.1 $1.9 $1.6 $2,901.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120137.

133





SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2018June 30, 2021 and December 31, 20172020
(in millions)
(Unaudited)
 June 30,December 31,
 20212020
CURRENT ASSETS  
Cash and Cash Equivalents
(June 30, 2021 and December 31, 2020 Amounts Include $24.9 and $10.1, Respectively, Related to Sabine)
$28.0 $13.2 
Advances to Affiliates29.7 2.1 
Accounts Receivable:  
Customers102.2 27.1 
Affiliated Companies30.1 25.1 
Miscellaneous14.6 12.7 
Total Accounts Receivable146.9 64.9 
Fuel
(June 30, 2021 and December 31, 2020 Amounts Include $20.3 and $35.2, Respectively, Related to Sabine)
179.1 191.1 
Materials and Supplies
(June 30, 2021 and December 31, 2020 Amounts Include $18.2 and $23.3, Respectively, Related to Sabine)
88.1 95.8 
Risk Management Assets14.0 3.2 
Accrued Tax Benefits14.5 29.9 
Regulatory Asset for Under-Recovered Fuel Costs0 2.6 
Prepayments and Other Current Assets16.4 25.2 
TOTAL CURRENT ASSETS516.7 428.0 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation4,839.4 4,681.4 
Transmission2,260.0 2,165.7 
Distribution2,475.7 2,382.5 
Other Property, Plant and Equipment
(June 30, 2021 and December 31, 2020 Amounts Include $219.9 and $223.7, Respectively, Related to Sabine)
809.0 788.8 
Construction Work in Progress159.8 228.3 
Total Property, Plant and Equipment10,543.9 10,246.7 
Accumulated Depreciation and Amortization
(June 30, 2021 and December 31, 2020 Amounts Include $144.6 and $126.5, Respectively, Related to Sabine)
3,375.4 3,158.5 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET7,168.5 7,088.2 
OTHER NONCURRENT ASSETS  
Regulatory Assets1,006.2 403.1 
Long-term Risk Management Assets0.6 0 
Deferred Charges and Other Noncurrent Assets283.2 234.8 
TOTAL OTHER NONCURRENT ASSETS1,290.0 637.9 
TOTAL ASSETS$8,975.2 $8,154.1 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
134
  March 31, December 31,
  2018 2017
CURRENT ASSETS    
Cash and Cash Equivalents

 $0.7
 $1.6
Advances to Affiliates 2.0
 2.0
Accounts Receivable:    
Customers 67.0
 70.9
Affiliated Companies 18.0
 30.2
Miscellaneous 13.2
 25.8
Allowance for Uncollectible Accounts (0.5) (1.3)
Total Accounts Receivable 97.7
 125.6
Fuel
(March 31, 2018 and December 31, 2017 Amounts Include $37.7 and $41.5, Respectively, Related to Sabine)
 120.5
 123.6
Materials and Supplies 68.8
 67.9
Risk Management Assets 1.7
 6.4
Regulatory Asset for Under-Recovered Fuel Costs 16.5
 14.1
Prepayments and Other Current Assets 40.2
 39.2
TOTAL CURRENT ASSETS 348.1
 380.4
     
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Generation 4,622.6
 4,624.9
Transmission 1,715.0
 1,679.8
Distribution 2,108.1
 2,095.8
Other Property, Plant and Equipment
(March 31, 2018 and December 31, 2017 Amounts Include $264.9 and $266.7, Respectively, Related to Sabine)
 704.4
 684.1
Construction Work in Progress 266.9
 233.2
Total Property, Plant and Equipment 9,417.0
 9,317.8
Accumulated Depreciation and Amortization
(March 31, 2018 and December 31, 2017 Amounts Include $167.4 and $165.9, Respectively, Related to Sabine)
 2,724.7
 2,685.8
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 6,692.3
 6,632.0
     
OTHER NONCURRENT ASSETS    
Regulatory Assets 217.9
 220.6
Deferred Charges and Other Noncurrent Assets 165.5
 109.9
TOTAL OTHER NONCURRENT ASSETS 383.4
 330.5
     
TOTAL ASSETS $7,423.8
 $7,342.9


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
March 31, 2018June 30, 2021 and December 31, 20172020
(Unaudited)
 June 30,December 31,
 20212020
 (in millions)
CURRENT LIABILITIES  
Advances from Affiliates$149.6 $124.6 
Accounts Payable:  
General121.8 135.9 
Affiliated Companies50.1 43.0 
Short-term Debt – Nonaffiliated0 35.0 
Long-term Debt Due Within One Year – Nonaffiliated381.2 106.2 
Risk Management Liabilities0 0.7 
Customer Deposits60.7 61.3 
Accrued Taxes108.3 41.0 
Accrued Interest36.0 34.6 
Obligations Under Operating Leases8.3 7.9 
Other Current Liabilities130.5 173.4 
TOTAL CURRENT LIABILITIES1,046.5 763.6 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated2,749.5 2,530.2 
Long-term Risk Management Liabilities0 1.0 
Deferred Income Taxes1,040.3 1,017.6 
Regulatory Liabilities and Deferred Investment Tax Credits874.8 863.4 
Asset Retirement Obligations191.6 193.7 
Employee Benefits and Pension Obligations22.9 18.6 
Obligations Under Operating Leases58.5 44.1 
Deferred Credits and Other Noncurrent Liabilities89.2 94.2 
TOTAL NONCURRENT LIABILITIES5,026.8 4,762.8 
TOTAL LIABILITIES6,073.3 5,526.4 
Rate Matters (Note 4)00
Commitments and Contingencies (Note 5)00
EQUITY  
Common Stock – Par Value – $18 Per Share:  
Authorized – 3,680 Shares  
Outstanding – 3,680 Shares0.1 0.1 
Paid-in Capital987.2 812.2 
Retained Earnings1,911.1 1,811.9 
Accumulated Other Comprehensive Income (Loss)1.9 1.9 
TOTAL COMMON SHAREHOLDER’S EQUITY2,900.3 2,626.1 
Noncontrolling Interest1.6 1.6 
TOTAL EQUITY2,901.9 2,627.7 
TOTAL LIABILITIES AND EQUITY$8,975.2 $8,154.1 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
135
  March 31, December 31,
  2018 2017
  (in millions)
CURRENT LIABILITIES    
Advances from Affiliates $148.6
 $118.7
Accounts Payable:    
General 118.5
 160.4
Affiliated Companies 60.7
 63.7
Short-term Debt – Nonaffiliated 22.6
 22.0
Long-term Debt Due Within One Year – Nonaffiliated 457.2
 3.7
Risk Management Liabilities 0.1
 0.2
Customer Deposits 62.9
 62.1
Accrued Taxes 91.1
 39.0
Accrued Interest 25.9
 38.9
Obligations Under Capital Leases 11.3
 11.2
Other Current Liabilities 60.4
 78.7
TOTAL CURRENT LIABILITIES 1,059.3
 598.6
     
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated 2,046.5
 2,438.2
Long-term Risk Management Liabilities 0.5
 —
Deferred Income Taxes 924.2
 917.7
Regulatory Liabilities and Deferred Investment Tax Credits 895.2
 896.4
Asset Retirement Obligations 160.8
 160.3
Employee Benefits and Pension Obligations 18.1
 19.5
Obligations Under Capital Leases 56.9
 57.8
Deferred Credits and Other Noncurrent Liabilities 36.4
 19.9
TOTAL NONCURRENT LIABILITIES 4,138.6
 4,509.8
     
TOTAL LIABILITIES 5,197.9
 5,108.4
     
Rate Matters (Note 4) 
 
Commitments and Contingencies (Note 5) 
 
     
EQUITY    
Common Stock – Par Value – $18 Per Share:    
Authorized – 7,600,000 Shares    
Outstanding – 7,536,640 Shares 135.7
 135.7
Paid-in Capital 676.6
 676.6
Retained Earnings 1,418.0
 1,426.6
Accumulated Other Comprehensive Income (Loss) (4.8) (4.0)
TOTAL COMMON SHAREHOLDER’S EQUITY 2,225.5
 2,234.9
     
Noncontrolling Interest 0.4
 (0.4)
     
TOTAL EQUITY 2,225.9
 2,234.5
     
TOTAL LIABILITIES AND EQUITY $7,423.8
 $7,342.9


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the ThreeSix Months Ended March 31, 2018June 30, 2021 and 20172020
(in millions)
(Unaudited)
 Six Months Ended June 30,
 20212020
OPERATING ACTIVITIES  
Net Income$100.8 $75.3 
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:  
Depreciation and Amortization142.6 135.4 
Deferred Income Taxes8.1 (12.4)
Allowance for Equity Funds Used During Construction(4.0)(2.3)
Mark-to-Market of Risk Management Contracts(13.1)(1.8)
Property Taxes(41.7)(33.0)
Deferred Fuel Over/Under-Recovery, Net(470.6)31.1 
Change in Regulatory Assets(50.6)(4.3)
Change in Other Noncurrent Assets17.3 2.7 
Change in Other Noncurrent Liabilities34.1 13.5 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net(82.0)(5.8)
Fuel, Materials and Supplies29.1 (60.4)
Accounts Payable(5.2)2.9 
Accrued Taxes, Net82.7 52.0 
Other Current Assets9.8 0.2 
Other Current Liabilities(37.9)(32.6)
Net Cash Flows from (Used for) Operating Activities(280.6)160.5 
INVESTING ACTIVITIES  
Construction Expenditures(182.5)(228.5)
Change in Advances to Affiliates, Net(27.6)0 
Acquisition of the North Central Wind Energy Facilities(147.1)0 
Other Investing Activities1.0 4.3 
Net Cash Flows Used for Investing Activities(356.2)(224.2)
FINANCING ACTIVITIES  
Capital Contribution from Parent175.0 0 
Issuance of Long-term Debt – Nonaffiliated496.4 0 
Change in Short-term Debt – Nonaffiliated(35.0)18.7 
Change in Advances from Affiliates, Net25.0 70.5 
Retirement of Long-term Debt – Nonaffiliated(3.1)(18.1)
Principal Payments for Finance Lease Obligations(5.4)(5.5)
Dividends Paid on Common Stock – Nonaffiliated(1.6)(1.9)
Other Financing Activities0.3 0.2 
Net Cash Flows from Financing Activities651.6 63.9 
Net Increase in Cash and Cash Equivalents14.8 0.2 
Cash and Cash Equivalents at Beginning of Period13.2 1.6 
Cash and Cash Equivalents at End of Period$28.0 $1.8 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$55.6 $57.0 
Net Cash Paid (Received) for Income Taxes(12.8)8.1 
Noncash Acquisitions Under Finance Leases3.2 4.3 
Construction Expenditures Included in Current Liabilities as of June 30,41.9 33.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
136
  Three Months Ended March 31,
  2018 2017
OPERATING ACTIVITIES  
  
Net Income $13.4
 $17.3
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
Depreciation and Amortization 57.4
 50.8
Deferred Income Taxes 1.0
 43.1
Allowance for Equity Funds Used During Construction (2.3) (0.8)
Mark-to-Market of Risk Management Contracts 5.1
 0.4
Property Taxes (48.8) (45.3)
Deferred Fuel Over/Under-Recovery, Net (4.6) (3.4)
Change in Other Noncurrent Assets 1.3
 (0.6)
Change in Other Noncurrent Liabilities 18.8
 (12.1)
Changes in Certain Components of Working Capital:    
Accounts Receivable, Net 27.9
 23.1
Fuel, Materials and Supplies 2.2
 12.5
Accounts Payable (24.6) (33.5)
Accrued Taxes, Net 55.2
 11.8
Accrued Interest (13.0) (20.3)
Other Current Assets (0.8) 3.2
Other Current Liabilities (12.5) (19.1)
Net Cash Flows from Operating Activities 75.7
 27.1
     
INVESTING ACTIVITIES    
Construction Expenditures (139.7) (75.6)
Change in Advances to Affiliates, Net —
 167.8
Other Investing Activities (5.4) (4.4)
Net Cash Flows from (Used for) Investing Activities (145.1) 87.8
     
FINANCING ACTIVITIES    
Issuance of Long-term Debt – Nonaffiliated 444.6
 —
Change in Short-term Debt, Net – Nonaffiliated 0.6
 —
Change in Advances from Affiliates, Net 29.9
 167.9
Retirement of Long-term Debt – Nonaffiliated (383.4) (251.7)
Principal Payments for Capital Lease Obligations (2.8) (2.8)
Dividends Paid on Common Stock (20.0) (27.5)
Dividends Paid on Common Stock – Nonaffiliated (0.8) (1.1)
Other Financing Activities 0.4
 0.3
Net Cash Flows from (Used for) Financing Activities 68.5
 (114.9)
     
Net Decrease in Cash and Cash Equivalents (0.9) —
Cash and Cash Equivalents at Beginning of Period 1.6
 10.3
Cash and Cash Equivalents at End of Period $0.7
 $10.3
     
SUPPLEMENTARY INFORMATION    
Cash Paid for Interest, Net of Capitalized Amounts $43.7
 $50.6
Net Cash Paid (Received) for Income Taxes (0.1) —
Noncash Acquisitions Under Capital Leases 1.9
 1.3
Construction Expenditures Included in Current Liabilities as of March 31, 50.3
 31.8


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120.




INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANTS


The condensed notes to condensed financial statements are a combined presentation for the Registrants. The following list indicates Registrants to which the notes apply. Specific disclosures within each note apply to all Registrants unless indicated otherwise.
otherwise:
NoteRegistrantPage
Number
NoteRegistrant
Page
Number
Significant Accounting MattersAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
121138
New Accounting PronouncementsStandardsAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
123140
Comprehensive IncomeAEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo
126141
Rate MattersAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
133152
Commitments, Guarantees and ContingenciesAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
144167
DispositionsAcquisitions and ImpairmentsDispositionsAEP, APCoPSO, SWEPCo
149173
Benefit PlansAEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo
150175
Business SegmentsAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
152179
Derivatives and HedgingAEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo
157184
Fair Value MeasurementsAEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo
167
Income TaxesAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
184198
Financing ActivitiesIncome TaxesAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
188215
Variable Interest EntitiesFinancing ActivitiesAEP
195
Revenue From Contracts With CustomersAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
197218
Property, Plant and EquipmentAEP, APCo
226
Revenue from Contracts with CustomersAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
227

137






1.  SIGNIFICANT ACCOUNTING MATTERS


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


General


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


In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentationstatement of the net income, financial position and cash flows for the interim periods for each Registrant.  Net income for the three and six months ended March 31, 2018June 30, 2021 is not necessarily indicative of results that may be expected for the year ending December 31, 2018.2021.  The condensed financial statements are unaudited and should be read in conjunction with the audited 20172020 financial statements and notes thereto, which are included in the Registrants’ Annual Reports on Form 10-K as filed with the SEC on February 22, 2018.25, 2021.


Earnings Per Share (EPS) (Applies to AEP)


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


The following table presents AEP’s basic and diluted EPS calculations included on the statements of income:
Three Months Ended June 30,
20212020
(in millions, except per share data)
 $/share$/share
Earnings Attributable to AEP Common Shareholders$578.2  $520.8  
Weighted-Average Number of Basic AEP Common Shares Outstanding499.9 $1.16 495.7 $1.05 
Weighted-Average Dilutive Effect of Stock-Based Awards1.1 (0.01)1.6 0 
Weighted-Average Number of Diluted AEP Common Shares Outstanding501.0 $1.15 497.3 $1.05 
Six Months Ended June 30,
20212020
(in millions, except per share data)
 $/share$/share
Earnings Attributable to AEP Common Shareholders$1,153.2  $1,016.0  
Weighted-Average Number of Basic AEP Common Shares Outstanding498.5 $2.31 495.1 $2.05 
Weighted-Average Dilutive Effect of Stock-Based Awards1.1 0 1.9 (0.01)
Weighted-Average Number of Diluted AEP Common Shares Outstanding499.6 $2.31 497.0 $2.04 

Equity Units are potentially dilutive securities but were excluded from the calculation of diluted EPS for the three and six months ended June 30, 2021 and 2020, as the dilutive stock price thresholds were not met. See Note 12 - Financing Activities for more information related to Equity Units.

138
 Three Months Ended March 31,
 2018 2017
 (in millions, except per share data)
  
 $/share   $/share
Earnings Attributable to AEP Common Shareholders$454.4
  
 $592.2

 
        
Weighted Average Number of Basic Shares Outstanding492.3
 $0.92
 491.7
 $1.20
Weighted Average Dilutive Effect of Stock-Based Awards0.8
 —
 0.3
 —
Weighted Average Number of Diluted Shares Outstanding493.1
 $0.92
 492.0
 $1.20





There were no0 and 156 thousand antidilutive shares outstanding as of March 31, 2018June 30, 2021 and 2017.2020, respectively. The

antidilutive shares were excluded from the calculation of diluted EPS.

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


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


Reconciliation of Cash, Cash Equivalents and Restricted Cash

The following tables provide a reconciliation of Cash, Cash Equivalents and Restricted Cash reported within the balance sheetsheets that sum to the total of the same amounts shown on the statementstatements of cash flows:
June 30, 2021
AEPAEP TexasAPCo
(in millions)
Cash and Cash Equivalents$312.7 $0.1 $3.9 
Restricted Cash47.0 27.9 19.1 
Total Cash, Cash Equivalents and Restricted Cash$359.7 $28.0 $23.0 

December 31, 2020
AEPAEP TexasAPCo
(in millions)
Cash and Cash Equivalents$392.7 $0.1 $5.8 
Restricted Cash45.6 28.7 16.9 
Total Cash, Cash Equivalents and Restricted Cash$438.3 $28.8 $22.7 


139
  March 31, 2018
  AEP AEP Texas APCo OPCo
  (in millions)
Cash and Cash Equivalents $183.4
 $0.1
 $1.2
 $1.4
Restricted Cash 133.1
 107.1
 10.1
 15.9
Total Cash, Cash Equivalents and Restricted Cash $316.5
 $107.2
 $11.3
 $17.3






  December 31, 2017
  AEP AEP Texas APCo OPCo
  (in millions)
Cash and Cash Equivalents $214.6
 $2.0
 $2.9
 $3.1
Restricted Cash 198.0
 155.2
 16.3
 26.6
Total Cash, Cash Equivalents and Restricted Cash $412.6
 $157.2
 $19.2
 $29.7


2. NEW ACCOUNTING PRONOUNCEMENTSSTANDARDS


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


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

ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09)

In May 2014, the FASB issued ASU 2014-09 changing the method usedThere are no new standards expected to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts.

Management adopted ASU 2014-09 effective January 1, 2018, by means of the modified retrospective approach for all contracts. The adoption of ASU 2014-09 did not have a material impact on results of operations, financial position or cash flows. In that regard, the application of the new standard did not cause any significant differences in any individual financial statement line items had those line items been presented in accordance with the guidance that was in effect prior to the adoption of the new standard. Further, given the lack of material impact to the financial statements, the adoption of the new standard did not give rise to any material changes in the Registrants’ previously established accounting policies for revenue. See Note 14 - Revenue from Contracts with Customers for additional disclosures required by the new standard.

ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01)

In January 2016, the FASB issued ASU 2016-01 revising the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. For equity investments that do not have a readily determinable fair value, entities are permitted to elect a practicality exception and measure the investment at cost, less impairment, plus or minus observable price changes. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheets or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets.

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted for certain provisions. Management adopted ASU 2016-01 effective January 1, 2018, by means of a cumulative-effect adjustment to the balance sheet. The adoption of ASU 2016-01 resulted in an immaterial impact on results of operations and financial position of AEP, and no impact to results of operations or financial position of the Registrant Subsidiaries. There was no impact on cash flows of the Registrants.

ASU 2016-02 “Accounting for Leases” (ASU 2016-02)

In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheets and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard.



The new accounting guidance is effective for annual periods beginning after December 15, 2018, with early adoption permitted. Initial decisions were made to apply the guidance by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented; however, the FASB is currently evaluating draft guidance which would provide an optional expedient to adopt the new lease requirements through a cumulative-effect adjustment in the period of adoption. Management continues to monitor these standard-setting activities that may impact the transition requirements of the lease standard.

During 2016 and 2017, lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Multiple lease system options were also evaluated. Management plans to elect certain of the following practical expedients upon adoption:
Practical ExpedientDescription
Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package)Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases.
Lease and Non-lease Components (elect by class of underlying asset)Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component.
Short-term Lease (elect by class of underlying asset)Elect as an accounting policy to not apply the recognition requirements to short-term leases.
Lease termElect to use hindsight to determine the lease term.
Existing and expired land easements not previously accounted for as leasesElect optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840.

Evaluation of new lease contracts continues and the process of implementing a compliant lease system solution began in the third quarter of 2017. Management expects the new standard to impact financial position and, at this time, cannot estimate the impact. Management expects no impact to results of operations or cash flows.

Management continues to monitor industry implementation issues as well as FASB’s ongoing standard-setting activities that may result in the issuance of additional targeted improvements to the new lease guidance. Management plans to adopt ASU 2016-02 effective January 1, 2019.

ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13)

In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination.

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020.



ASU 2017-07 “Compensation - Retirement Benefits” (ASU 2017-07)

In March 2017, the FASB issued ASU 2017-07 requiring that an employer report the service cost component of pension and postretirement benefits in the same line item or items as other compensation costs. The other components of net benefit cost are required to be presented on the statements of income separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor.

Management adopted ASU 2017-07 effective January 1, 2018. Presentation of the non-service components on a separate line outside of operating income was applied on a retrospective basis, using the amounts disclosed in the benefit plan note for the estimation basis as a practical expedient. Capitalization of only the service cost component was applied on a prospective basis.

ASU 2017-12 “Derivatives and Hedging” (ASU 2017-12)

In August 2017, the FASB issued ASU 2017-12 amending the recognition and presentation requirements for hedge accounting activities. The objectives are to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and reduce the complexity of applying hedge accounting. Under the new standard, the concept of recognizing hedge ineffectiveness within the statements of income for cash flow hedges, which has historically been immaterial to AEP, will be eliminated. In addition, certain required tabular disclosures relating to fair value and cash flow hedges will be modified.

The accounting guidance is effective for interim and annual periods beginning after December 15, 2018, with early adoption permitted for any interim or annual period after August 2017. Management is analyzing the impact of this new standard, including the possibility of early adoption, and at this time, cannot estimate the impact of adoption on results of operations, financial position or cash flows.

ASU 2018-02 “Reclassification of Certain Tax Effects from AOCI” (ASU 2018-02)

In February 2018, the FASB issued ASU 2018-02 allowing a reclassification from AOCI to Retained Earnings for stranded tax effects resulting from Tax Reform. The accounting guidance for “Income Taxes” requires deferred tax assets and liabilities to be adjusted for the effect of a change in tax law or rates with the effect included in income from continuing operations in the reporting period that includes the enactment date of the tax change. This guidance is applicable for the tax effects of items in AOCI that were originally recognized in Other Comprehensive Income. As a result and absent the new guidance in this ASU, the tax effects of items within AOCI would not reflect the newly enacted corporate tax rate.

Management adopted ASU 2018-02 effective January 1, 2018, electing to reclassify the effects of the change in the federal corporate tax rate due to Tax Reform from AOCI to Retained Earnings. A portion of the reclassification was recorded to Regulatory Liabilities to adjust the tax effects of certain interest rate hedges in AEP's regulated jurisdictions that were previously deferred as a part of the accounting for Tax Reform. There were no other effects from Tax Reform that impacted AOCI. Management applied the new guidance at the beginning of the period of adoption. The adoption of the new standard did not have a material impact on the statement ofRegistrants’ financial position and did not impact results of operations or cash flows.statements.



140




3.  COMPREHENSIVE INCOME


The disclosures in this note apply to all Registrants except for AEPTCo. AEPTCo does not have any components of other comprehensive income for any period presented in the financial statements.and OPCo unless indicated otherwise.


Presentation of Comprehensive Income


The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three months ended March 31, 2018 and 2017.AOCI.  The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 - Benefit Plans for additional details.information.


AEP

 Cash Flow HedgesPension 
Three Months Ended June 30, 2021CommodityInterest Rateand OPEBTotal
 (in millions)
Balance in AOCI as of March 31, 2021$(18.5)$(33.3)$21.0 $(30.8)
Change in Fair Value Recognized in AOCI136.4 (0.4)(a)0 136.0 
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (b)(0.1)0 0 (0.1)
Purchased Electricity for Resale (b)(9.5)0 0 (9.5)
Interest Expense (b)0 1.8 0 1.8 
Amortization of Prior Service Cost (Credit)0 0 (4.9)(4.9)
Amortization of Actuarial (Gains) Losses0 0 2.2 2.2 
Reclassifications from AOCI, before Income Tax (Expense) Benefit(9.6)1.8 (2.7)(10.5)
Income Tax (Expense) Benefit(2.0)0.3 (0.6)(2.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit(7.6)1.5 (2.1)(8.2)
Net Current Period Other Comprehensive Income (Loss)128.8 1.1 (2.1)127.8 
Balance in AOCI as of June 30, 2021$110.3 $(32.2)$18.9 $97.0 
Changes in Accumulated Other Comprehensive Income (Loss) by Component
 Cash Flow HedgesPension 
Three Months Ended June 30, 2020CommodityInterest Rateand OPEBTotal
 (in millions)
Balance in AOCI as of March 31, 2020$(128.5)$(53.5)$(34.5)$(216.5)
Change in Fair Value Recognized in AOCI6.5 (2.8)(a)0 3.7 
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (b)(0.1)0 0 (0.1)
Purchased Electricity for Resale (b)51.3 0 0 51.3 
Interest Expense (b)0 1.4 0 1.4 
Amortization of Prior Service Cost (Credit)0 0 (4.6)(4.6)
Amortization of Actuarial (Gains) Losses0 0 2.5 2.5 
Reclassifications from AOCI, before Income Tax (Expense) Benefit51.2 1.4 (2.1)50.5 
Income Tax (Expense) Benefit10.6 0.4 (0.4)10.6 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit40.6 1.0 (1.7)39.9 
Net Current Period Other Comprehensive Income (Loss)47.1 (1.8)(1.7)43.6 
Balance in AOCI as of June 30, 2020$(81.4)$(55.3)$(36.2)$(172.9)
For the Three Months Ended March 31, 2018
 Cash Flow Hedges      
 Commodity Interest Rate 
Securities
Available for Sale
 
Pension
and OPEB
 Total
 (in millions)
Balance in AOCI as of December 31, 2017$(28.4) $(13.0) $11.9
 $(38.3) $(67.8)
Change in Fair Value Recognized in AOCI12.8
 —
 —
 —
 12.8
Amount of (Gain) Loss Reclassified from AOCI         
Purchased Electricity for Resale(13.1) —
 —
 —
 (13.1)
Interest Expense—
 0.3
 —
 —
 0.3
Amortization of Prior Service Cost (Credit)—
 —
 —
 (5.0) (5.0)
Amortization of Actuarial (Gains)/Losses—
 —
 —
 3.2
 3.2
Reclassifications from AOCI, before Income Tax (Expense) Credit(13.1) 0.3
 —
 (1.8) (14.6)
Income Tax (Expense) Credit(2.8) 0.1
 —
 (0.4) (3.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit(10.3) 0.2
 —
 (1.4) (11.5)
Net Current Period Other Comprehensive Income (Loss)2.5
 0.2
 —
 (1.4) 1.3
ASU 2018-02 Adoption (a)(6.1) (2.7) —
 (8.2) (17.0)
ASU 2016-01 Adoption (a)—
 —
 (11.9) —
 (11.9)
Balance in AOCI as of March 31, 2018$(32.0) $(15.5) $—
 $(47.9) $(95.4)

(a)See Note 2 - New Accounting Pronouncements for additional information.

AEP


Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 2017
141




 Cash Flow Hedges      
 Commodity Interest Rate 
Securities
Available for Sale
 
Pension
and OPEB
 Total
 (in millions)
Balance in AOCI as of December 31, 2016$(23.1) $(15.7) $8.4
 $(125.9) $(156.3)
Change in Fair Value Recognized in AOCI(21.8) —
 1.2
 —
 (20.6)
Amount of (Gain) Loss Reclassified from AOCI        

Generation & Marketing Revenues(4.7) —
 —
 —
 (4.7)
Purchased Electricity for Resale12.8
 —
 —
 —
 12.8
Interest Expense—
 0.5
 —
 —
 0.5
Amortization of Prior Service Cost (Credit)—
 —
 —
 (4.9) (4.9)
Amortization of Actuarial (Gains)/Losses—
 —
 —
 5.3
 5.3
Reclassifications from AOCI, before Income Tax (Expense) Credit8.1
 0.5
 —
 0.4
 9.0
Income Tax (Expense) Credit2.8
 0.1
 —
 0.2
 3.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit5.3
 0.4
 —
 0.2
 5.9
Net Current Period Other Comprehensive Income (Loss)(16.5) 0.4
 1.2
 0.2
 (14.7)
Balance in AOCI as of March 31, 2017$(39.6) $(15.3) $9.6
 $(125.7) $(171.0)
AEP
 Cash Flow HedgesPension 
Six Months Ended June 30, 2021CommodityInterest Rateand OPEBTotal
 (in millions)
Balance in AOCI as of December 31, 2020$(60.6)$(47.5)$23.0 $(85.1)
Change in Fair Value Recognized in AOCI313.7 12.7 (a)0 326.4 
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (b)0.7 0 0 0.7 
Purchased Electricity for Resale (b)(181.5)0 0 (181.5)
Interest Expense (b)0 3.3 0 3.3 
Amortization of Prior Service Cost (Credit)0 0 (9.7)(9.7)
Amortization of Actuarial (Gains) Losses0 0 4.5 4.5 
Reclassifications from AOCI, before Income Tax (Expense) Benefit(180.8)3.3 (5.2)(182.7)
Income Tax (Expense) Benefit(38.0)0.7 (1.1)(38.4)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit(142.8)2.6 (4.1)(144.3)
Net Current Period Other Comprehensive Income (Loss)170.9 15.3 (4.1)182.1 
Balance in AOCI as of June 30, 2021$110.3 $(32.2)$18.9 $97.0 

 Cash Flow HedgesPension 
Six Months Ended June 30, 2020CommodityInterest Rateand OPEBTotal
 (in millions)
Balance in AOCI as of December 31, 2019$(103.5)$(11.5)$(32.7)$(147.7)
Change in Fair Value Recognized in AOCI(58.8)(45.5)(a)0 (104.3)
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (b)(0.2)— 0 (0.2)
Purchased Electricity for Resale (b)102.4 0 0 102.4 
Interest Expense (b)0 2.3 0 2.3 
Amortization of Prior Service Cost (Credit)0 0 (9.5)(9.5)
Amortization of Actuarial (Gains) Losses0 0 5.1 5.1 
Reclassifications from AOCI, before Income Tax (Expense) Benefit102.2 2.3 (4.4)100.1 
Income Tax (Expense) Benefit21.3 0.6 (0.9)21.0 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit80.9 1.7 (3.5)79.1 
Net Current Period Other Comprehensive Income (Loss)22.1 (43.8)(3.5)(25.2)
Balance in AOCI as of June 30, 2020$(81.4)$(55.3)$(36.2)$(172.9)


142




AEP Texas

Cash Flow Hedge –Pension
Three Months Ended June 30, 2021Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of March 31, 2021$(2.0)$(6.6)$(8.6)
Change in Fair Value Recognized in AOCI(0.1)0 (0.1)
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)0.3 0 0.3 
Amortization of Actuarial (Gains) Losses0 0.1 0.1 
Reclassifications from AOCI, before Income Tax (Expense) Benefit0.3 0.1 0.4 
Income Tax (Expense) Benefit0 0 0 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0.3 0.1 0.4 
Net Current Period Other Comprehensive Income (Loss)0.2 0.1 0.3 
Balance in AOCI as of June 30, 2021$(1.8)$(6.5)$(8.3)
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Cash Flow Hedge –Pension
Three Months Ended June 30, 2020Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of March 31, 2020$(3.1)$(9.4)$(12.5)
Change in Fair Value Recognized in AOCI0 0 0 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)0.2 0 0.2 
Amortization of Actuarial (Gains) Losses0 0.1 0.1 
Reclassifications from AOCI, before Income Tax (Expense) Benefit0.2 0.1 0.3 
Income Tax (Expense) Benefit0 0 0 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0.2 0.1 0.3 
Net Current Period Other Comprehensive Income (Loss)0.2 0.1 0.3 
Balance in AOCI as of June 30, 2020$(2.9)$(9.3)$(12.2)
For the Three Months Ended March 31, 2018
143




       
  Cash Flow Hedge - Interest Rate 
Pension
and OPEB
 Total
 (in millions)
Balance in AOCI as of December 31, 2017 $(4.5) $(8.1) $(12.6)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense 0.3
 —
 0.3
Amortization of Prior Service Cost (Credit) —
 —
 —
Amortization of Actuarial (Gains)/Losses —
 0.1
 0.1
Reclassifications from AOCI, before Income Tax (Expense) Credit 0.3
 0.1
 0.4
Income Tax (Expense) Credit 0.1
 —
 0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.2
 0.1
 0.3
Net Current Period Other Comprehensive Income (Loss) 0.2
 0.1
 0.3
ASU 2018-02 Adoption (a) (0.9) (1.8) (2.7)
Balance in AOCI as of March 31, 2018 $(5.2) $(9.8) $(15.0)
AEP Texas

Cash Flow Hedge –Pension
Six Months Ended June 30, 2021Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2020$(2.3)$(6.6)$(8.9)
Change in Fair Value Recognized in AOCI0 0 0 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)0.6 0 0.6 
Amortization of Actuarial (Gains) Losses0 0.1 0.1 
Reclassifications from AOCI, before Income Tax (Expense) Benefit0.6 0.1 0.7 
Income Tax (Expense) Benefit0.1 0 0.1 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0.5 0.1 0.6 
Net Current Period Other Comprehensive Income (Loss)0.5 0.1 0.6 
Balance in AOCI as of June 30, 2021$(1.8)$(6.5)$(8.3)
Cash Flow Hedge –Pension
Six Months Ended June 30, 2020Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2019$(3.4)$(9.4)$(12.8)
Change in Fair Value Recognized in AOCI0 0 0 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)0.6 0 0.6 
Amortization of Actuarial (Gains) Losses0 0.1 0.1 
Reclassifications from AOCI, before Income Tax (Expense) Benefit0.6 0.1 0.7 
Income Tax (Expense) Benefit0.1 0 0.1 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0.5 0.1 0.6 
Net Current Period Other Comprehensive Income (Loss)0.5 0.1 0.6 
Balance in AOCI as of June 30, 2020$(2.9)$(9.3)$(12.2)


144




APCo
Cash Flow Hedge –Pension
Three Months Ended June 30, 2021Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of March 31, 2021$8.2 $6.9 $15.1 
Change in Fair Value Recognized in AOCI(0.2)0 (0.2)
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)0 0 0 
Amortization of Prior Service Cost (Credit)0 (1.3)(1.3)
Reclassifications from AOCI, before Income Tax (Expense) Benefit0 (1.3)(1.3)
Income Tax (Expense) Benefit0 (0.3)(0.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0 (1.0)(1.0)
Net Current Period Other Comprehensive Income (Loss)(0.2)(1.0)(1.2)
Balance in AOCI as of June 30, 2021$8.0 $5.9 $13.9 
Cash Flow Hedge –Pension
Three Months Ended June 30, 2020Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of March 31, 2020$(3.3)$3.2 $(0.1)
Change in Fair Value Recognized in AOCI(0.6)0 (0.6)
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)(0.2)0 (0.2)
Amortization of Prior Service Cost (Credit)0 (1.4)(1.4)
Amortization of Actuarial (Gains) Losses0 0.2 0.2 
Reclassifications from AOCI, before Income Tax (Expense) Benefit(0.2)(1.2)(1.4)
Income Tax (Expense) Benefit0 (0.2)(0.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit(0.2)(1.0)(1.2)
Net Current Period Other Comprehensive Income (Loss)(0.8)(1.0)(1.8)
Balance in AOCI as of June 30, 2020$(4.1)$2.2 $(1.9)
145





APCo
Cash Flow Hedge –Pension
Six Months Ended June 30, 2021Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2020$(0.8)$8.0 $7.2 
Change in Fair Value Recognized in AOCI9.1 0 9.1 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)(0.4)0 (0.4)
Amortization of Prior Service Cost (Credit)0 (2.7)(2.7)
Reclassifications from AOCI, before Income Tax (Expense) Benefit(0.4)(2.7)(3.1)
Income Tax (Expense) Benefit(0.1)(0.6)(0.7)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit(0.3)(2.1)(2.4)
Net Current Period Other Comprehensive Income (Loss)8.8 (2.1)6.7 
Balance in AOCI as of June 30, 2021$8.0 $5.9 $13.9 
Cash Flow Hedge –Pension
Six Months Ended June 30, 2020Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2019$0.9 $4.1 $5.0 
Change in Fair Value Recognized in AOCI(4.5)0 (4.5)
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)(0.6)0 (0.6)
Amortization of Prior Service Cost (Credit)0 (2.7)(2.7)
Amortization of Actuarial (Gains) Losses0 0.3 0.3 
Reclassifications from AOCI, before Income Tax (Expense) Benefit(0.6)(2.4)(3.0)
Income Tax (Expense) Benefit(0.1)(0.5)(0.6)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit(0.5)(1.9)(2.4)
Net Current Period Other Comprehensive Income (Loss)(5.0)(1.9)(6.9)
Balance in AOCI as of June 30, 2020$(4.1)$2.2 $(1.9)

146




I&M
Cash Flow Hedge –Pension
Three Months Ended June 30, 2021Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of March 31, 2021$(7.8)$1.3 $(6.5)
Change in Fair Value Recognized in AOCI0 0 0 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)0.5 0 0.5 
Amortization of Prior Service Cost (Credit)0 (0.2)(0.2)
Amortization of Actuarial (Gains) Losses0 0.1 0.1 
Reclassifications from AOCI, before Income Tax (Expense) Benefit0.5 (0.1)0.4 
Income Tax (Expense) Benefit0.1 0 0.1 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0.4 (0.1)0.3 
Net Current Period Other Comprehensive Income (Loss)0.4 (0.1)0.3 
Balance in AOCI as of June 30, 2021$(7.4)$1.2 $(6.2)
Cash Flow Hedge –Pension
Three Months Ended June 30, 2020Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of March 31, 2020$(9.5)$(1.7)$(11.2)
Change in Fair Value Recognized in AOCI0 0 0 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)0.5 0 0.5 
Amortization of Prior Service Cost (Credit)0 (0.1)(0.1)
Amortization of Actuarial (Gains) Losses0 0.1 0.1 
Reclassifications from AOCI, before Income Tax (Expense) Benefit0.5 0 0.5 
Income Tax (Expense) Benefit0.1 0 0.1 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0.4 0 0.4 
Net Current Period Other Comprehensive Income (Loss)0.4 0 0.4 
Balance in AOCI as of June 30, 2020$(9.1)$(1.7)$(10.8)
147





I&M
Cash Flow Hedge –Pension
Six Months Ended June 30, 2021Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2020$(8.3)$1.3 $(7.0)
Change in Fair Value Recognized in AOCI0 0 0 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)1.1 0 1.1 
Amortization of Prior Service Cost (Credit)0 (0.4)(0.4)
Amortization of Actuarial (Gains) Losses0 0.3 0.3 
Reclassifications from AOCI, before Income Tax (Expense) Benefit1.1 (0.1)1.0 
Income Tax (Expense) Benefit0.2 0 0.2 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0.9 (0.1)0.8 
Net Current Period Other Comprehensive Income (Loss)0.9 (0.1)0.8 
Balance in AOCI as of June 30, 2021$(7.4)$1.2 $(6.2)
Cash Flow Hedge –Pension
Six Months Ended June 30, 2020Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2019$(9.9)$(1.7)$(11.6)
Change in Fair Value Recognized in AOCI0 0 0 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)1.0 0 1.0 
Amortization of Prior Service Cost (Credit)0 (0.3)(0.3)
Amortization of Actuarial (Gains) Losses0 0.3 0.3 
Reclassifications from AOCI, before Income Tax (Expense) Benefit1.0 0 1.0 
Income Tax (Expense) Benefit0.2 0 0.2 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0.8 0 0.8 
Net Current Period Other Comprehensive Income (Loss)0.8 0 0.8 
Balance in AOCI as of June 30, 2020$(9.1)$(1.7)$(10.8)

(a)See Note 2 - New Accounting Pronouncements for additional information.

AEP Texas

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 2017
       
  Cash Flow Hedge - Interest Rate 
Pension
and OPEB
 Total
 (in millions)
Balance in AOCI as of December 31, 2016 $(5.4) $(9.5) $(14.9)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense 0.3
 —
 0.3
Amortization of Actuarial (Gains)/Losses —
 0.1
 0.1
Reclassifications from AOCI, before Income Tax (Expense) Credit 0.3
 0.1
 0.4
Income Tax (Expense) Credit 0.1
 —
 0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.2
 0.1
 0.3
Net Current Period Other Comprehensive Income (Loss) 0.2
 0.1
 0.3
Balance in AOCI as of March 31, 2017 $(5.2) $(9.4) $(14.6)



APCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 2018
  Cash Flow Hedges   
  Commodity Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of December 31, 2017 $—
 $2.2
 $(0.9) $1.3
Change in Fair Value Recognized in AOCI (0.7) —
 —
 (0.7)
Amount of (Gain) Loss Reclassified from AOCI   

 

 

Purchased Electricity for Resale 0.9
 —
 —
 0.9
Interest Expense —
 (0.3) —
 (0.3)
Amortization of Prior Service Cost (Credit) —
 —
 (1.3) (1.3)
Amortization of Actuarial (Gains)/Losses —
 —
 0.3
 0.3
Reclassifications from AOCI, before Income Tax (Expense) Credit 0.9
 (0.3) (1.0) (0.4)
Income Tax (Expense) Credit 0.2
 (0.1) (0.2) (0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7
 (0.2) (0.8) (0.3)
Net Current Period Other Comprehensive Income (Loss) —
 (0.2) (0.8) (1.0)
ASU 2018-02 Adoption (a) —
 0.5
 (0.2) 0.3
Balance in AOCI as of March 31, 2018 $—
 $2.5
 $(1.9) $0.6

(a)See Note 2 - New Accounting Pronouncements for additional information.

APCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 2017
       
  Cash Flow Hedge - Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of December 31, 2016 $2.9
 $(11.3) $(8.4)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI 

 

 

Interest Expense (0.3) —
 (0.3)
Amortization of Prior Service Cost (Credit) —
 (1.3) (1.3)
Amortization of Actuarial (Gains)/Losses —
 0.8
 0.8
Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3) (0.5) (0.8)
Income Tax (Expense) Credit (0.1) (0.2) (0.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2) (0.3) (0.5)
Net Current Period Other Comprehensive Income (Loss) (0.2) (0.3) (0.5)
Balance in AOCI as of March 31, 2017 $2.7
 $(11.6) $(8.9)





I&M

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 2018
       
  Cash Flow Hedge - Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of December 31, 2017 $(10.7) $(1.4) $(12.1)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense 0.5
 —
 0.5
Amortization of Prior Service Cost (Credit) —
 (0.2) (0.2)
Amortization of Actuarial (Gains)/Losses —
 0.2
 0.2
Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5
 —
 0.5
Income Tax (Expense) Credit 0.1
 —
 0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4
 —
 0.4
Net Current Period Other Comprehensive Income (Loss) 0.4
 —
 0.4
ASU 2018-02 Adoption (a) (2.4) (0.3) (2.7)
Balance in AOCI as of March 31, 2018 $(12.7) $(1.7) $(14.4)

(a)See Note 2 - New Accounting Pronouncements for additional information.

I&M

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 2017
       
  Cash Flow Hedge - Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of December 31, 2016 $(12.0) $(4.2) $(16.2)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense 0.5
 —
 0.5
Amortization of Prior Service Cost (Credit) —
 (0.2) (0.2)
Amortization of Actuarial (Gains)/Losses —
 0.2
 0.2
Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5
 —
 0.5
Income Tax (Expense) Credit 0.2
 —
 0.2
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3
 —
 0.3
Net Current Period Other Comprehensive Income (Loss) 0.3
 —
 0.3
Balance in AOCI as of March 31, 2017 $(11.7) $(4.2) $(15.9)



OPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 2018
   
  Cash Flow Hedge - Interest Rate
  (in millions)
Balance in AOCI as of December 31, 2017 $1.9
Change in Fair Value Recognized in AOCI —
Amount of (Gain) Loss Reclassified from AOCI 

Interest Expense (0.4)
Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4)
Income Tax (Expense) Credit (0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3)
Net Current Period Other Comprehensive Income (Loss) (0.3)
ASU 2018-02 Adoption (a) 0.4
Balance in AOCI as of March 31, 2018 $2.0
(a)See Note 2 - New Accounting Pronouncements for additional information.

OPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 2017
   
  Cash Flow Hedge - Interest Rate
 (in millions)
Balance in AOCI as of December 31, 2016 $3.0
Change in Fair Value Recognized in AOCI —
Amount of (Gain) Loss Reclassified from AOCI  
Interest Expense (0.4)
Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4)
Income Tax (Expense) Credit (0.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2)
Net Current Period Other Comprehensive Income (Loss) (0.2)
Balance in AOCI as of March 31, 2017 $2.8



PSO

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 2018
   
  Cash Flow Hedge - Interest Rate
  (in millions)
Balance in AOCI as of December 31, 2017 $2.6
Change in Fair Value Recognized in AOCI —
Amount of (Gain) Loss Reclassified from AOCI 

Interest Expense (0.3)
Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3)
Income Tax (Expense) Credit (0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2)
Net Current Period Other Comprehensive Income (Loss) (0.2)
ASU 2018-02 Adoption (a) 0.5
Balance in AOCI as of March 31, 2018 $2.9
(a)See Note 2 - New Accounting Pronouncements for additional information.

PSO

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 2017
   
  Cash Flow Hedge - Interest Rate
  (in millions)
Balance in AOCI as of December 31, 2016 $3.4
Change in Fair Value Recognized in AOCI —
Amount of (Gain) Loss Reclassified from AOCI 

Interest Expense (0.3)
Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3)
Income Tax (Expense) Credit (0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2)
Net Current Period Other Comprehensive Income (Loss) (0.2)
Balance in AOCI as of March 31, 2017 $3.2




SWEPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 2018
       
  Cash Flow Hedge - Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of December 31, 2017 $(6.0) $2.0
 $(4.0)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI 

 

 

Interest Expense 0.5
 —
 0.5
Amortization of Prior Service Cost (Credit) —
 (0.5) (0.5)
Amortization of Actuarial (Gains)/Losses —
 0.1
 0.1
Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5
 (0.4) 0.1
Income Tax (Expense) Credit 0.1
 (0.1) —
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4
 (0.3) 0.1
Net Current Period Other Comprehensive Income (Loss) 0.4
 (0.3) 0.1
ASU 2018-02 Adoption (a) (1.3) 0.4
 (0.9)
Balance in AOCI as of March 31, 2018 $(6.9) $2.1
 $(4.8)

(a)See Note 2 - New Accounting Pronouncements for additional information.

SWEPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 2017
148




       
  Cash Flow Hedge - Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of December 31, 2016 $(7.4) $(2.0) $(9.4)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense 0.7
 —
 0.7
Amortization of Prior Service Cost (Credit) —
 (0.5) (0.5)
Amortization of Actuarial (Gains)/Losses —
 0.2
 0.2
Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7
 (0.3) 0.4
Income Tax (Expense) Credit 0.2
 (0.1) 0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.5
 (0.2) 0.3
Net Current Period Other Comprehensive Income (Loss) 0.5
 (0.2) 0.3
Balance in AOCI as of March 31, 2017 $(6.9) $(2.2) $(9.1)

PSO
Cash Flow Hedge –
Three Months Ended June 30, 2021Interest Rate
(in millions)
Balance in AOCI as of March 31, 2021$0 
Change in Fair Value Recognized in AOCI0 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)0 
Reclassifications from AOCI, before Income Tax (Expense) Benefit0 
Income Tax (Expense) Benefit0 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0 
Net Current Period Other Comprehensive Income (Loss)0 
Balance in AOCI as of June 30, 2021$0 

Cash Flow Hedge –
Three Months Ended June 30, 2020Interest Rate
(in millions)
Balance in AOCI as of March 31, 2020$0.9 
Change in Fair Value Recognized in AOCI0 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)(0.4)
Reclassifications from AOCI, before Income Tax (Expense) Benefit(0.4)
Income Tax (Expense) Benefit(0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit(0.3)
Net Current Period Other Comprehensive Income (Loss)(0.3)
Balance in AOCI as of June 30, 2020$0.6 
Cash Flow Hedge –
Six Months Ended June 30, 2021Interest Rate
(in millions)
Balance in AOCI as of December 31, 2020$0.1 
Change in Fair Value Recognized in AOCI0 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)(0.1)
Reclassifications from AOCI, before Income Tax (Expense) Benefit(0.1)
Income Tax (Expense) Benefit0 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit(0.1)
Net Current Period Other Comprehensive Income (Loss)(0.1)
Balance in AOCI as of June 30, 2021$0 
Cash Flow Hedge –
Six Months Ended June 30, 2020Interest Rate
(in millions)
Balance in AOCI as of December 31, 2019$1.1 
Change in Fair Value Recognized in AOCI0 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)(0.7)
Reclassifications from AOCI, before Income Tax (Expense) Benefit(0.7)
Income Tax (Expense) Benefit(0.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit(0.5)
Net Current Period Other Comprehensive Income (Loss)(0.5)
Balance in AOCI as of June 30, 2020$0.6 
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SWEPCo
Cash Flow Hedge –Pension
Three Months Ended June 30, 2021Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of March 31, 2021$0.1 $1.8 $1.9 
Change in Fair Value Recognized in AOCI0 0 0 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)0.5 0 0.5 
Amortization of Prior Service Cost (Credit)0 (0.5)(0.5)
Reclassifications from AOCI, before Income Tax (Expense) Benefit0.5 (0.5)0 
Income Tax (Expense) Benefit0.1 (0.1)0 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0.4 (0.4)0 
Net Current Period Other Comprehensive Income (Loss)0.4 (0.4)0 
Balance in AOCI as of June 30, 2021$0.5 $1.4 $1.9 
Cash Flow Hedge –Pension
Three Months Ended June 30, 2020Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of March 31, 2020$(1.4)$0.1 $(1.3)
Change in Fair Value Recognized in AOCI0 0 0 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)0.4 0 0.4 
Amortization of Prior Service Cost (Credit)0 (0.5)(0.5)
Amortization of Actuarial (Gains) Losses0 0.1 0.1 
Reclassifications from AOCI, before Income Tax (Expense) Benefit0.4 (0.4)0 
Income Tax (Expense) Benefit0.1 (0.1)0 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0.3 (0.3)0 
Net Current Period Other Comprehensive Income (Loss)0.3 (0.3)0 
Balance in AOCI as of June 30, 2020$(1.1)$(0.2)$(1.3)
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SWEPCo
Cash Flow Hedge –Pension
Six Months Ended June 30, 2021Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2020$(0.3)$2.2 $1.9 
Change in Fair Value Recognized in AOCI0 0 0 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)1.0 0 1.0 
Amortization of Prior Service Cost (Credit)0 (1.0)(1.0)
Reclassifications from AOCI, before Income Tax (Expense) Benefit1.0 (1.0)0 
Income Tax (Expense) Benefit0.2 (0.2)0 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0.8 (0.8)0 
Net Current Period Other Comprehensive Income (Loss)0.8 (0.8)0 
Balance in AOCI as of June 30, 2021$0.5 $1.4 $1.9 
Cash Flow Hedge –Pension
Six Months Ended June 30, 2020Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2019$(1.8)$0.5 $(1.3)
Change in Fair Value Recognized in AOCI0 0 0 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)0.9 0 0.9 
Amortization of Prior Service Cost (Credit)0 (1.0)(1.0)
Amortization of Actuarial (Gains) Losses0 0.1 0.1 
Reclassifications from AOCI, before Income Tax (Expense) Benefit0.9 (0.9)0 
Income Tax (Expense) Benefit0.2 (0.2)0 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0.7 (0.7)0 
Net Current Period Other Comprehensive Income (Loss)0.7 (0.7)0 
Balance in AOCI as of June 30, 2020$(1.1)$(0.2)$(1.3)
(a)The change in fair value includes $4 million and $2 million, respectively, for the three months ended June 30, 2021 and 2020 and $0 million and $7 million, respectively, for the six months ended June 30, 2021 and 2020 related to AEP's investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC.
(b)Amounts reclassified to the referenced line item on the statements of income.

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4.  RATE MATTERS


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


As discussed in the 20172020 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 20172020 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 20182021 and updates the 20172020 Annual Report.


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

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

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

Regulated Generating Units that have been Retired

PSO

In September 2020, the Oklaunion Power Station was retired. As of June 30, 2021, PSO has a regulatory asset for accelerated depreciation pending approval recorded on its balance sheet of $34 million. PSO is seeking accelerated recovery of the Oklaunion Power Station through 2026 in its 2021 Oklahoma base rate case. See “2021 Oklahoma Base Rate Case” section below for additional information. In October 2020, the Oklaunion Power Station site was sold to a nonaffiliated third-party.

SWEPCo

In April 2016, Welsh Plant, Unit 2 was retired. As part of the 2016 Texas Base Rate Case, SWEPCo received approval from the PUCT to recover the Texas jurisdictional share of Welsh Plant, Unit 2. See “2016 Texas Base Rate Case” section below for additional information. As part of the 2019 Arkansas Base Rate Case, SWEPCo received approval from the APSC to recover the Arkansas jurisdictional share of Welsh Plant, Unit 2. In December 2020, SWEPCo filed a request with the LPSC to recover the Louisiana jurisdictional share of Welsh Plant, Unit 2. As of June 30, 2021, SWEPCo has a regulatory asset for plant retirement costs pending approval recorded on its balance sheet of $35 million related to the Louisiana jurisdictional share of Welsh Plant, Unit 2. See “2020 Louisiana Base Rate Case” section below for additional information.

Regulated Generating Units to be Retired

PSO

In 2014, PSO received final approval from the Federal EPA to close Northeastern Plant, Unit 3, in 2026. The plant was originally scheduled to close in 2040. As a result of the early retirement date, PSO revised the useful life of Northeastern Plant, Unit 3, to the projected retirement date of 2026 and the incremental depreciation is being deferred as a regulatory asset. As part of its 2021 Oklahoma base rate case, PSO is seeking to accelerate the recovery of Northeastern Plant, Unit 3 from the original retirement date of 2040 to the projected retirement date of 2026. See “2021 Oklahoma Base Rate Case” section below for additional information.
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SWEPCo

In January 2020, as part of the 2019 Arkansas Base Rate Case, management announced that the Dolet Hills Power Station was probable of abandonment and was to be retired by December 2026. As a result of the announcement, SWEPCo began recording a regulatory asset for accelerated depreciation. In March 2020, management announced plans to retire the plant in 2021.

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

The table below summarizes the net book value including CWIP, before cost of removal and materials and supplies, as of June 30, 2021, of generating facilities planned for early retirement:
PlantNet
Investment		Accelerated Depreciation Regulatory AssetCost of Removal
Regulatory Liability		Projected
Retirement Date		Current Authorized
Recovery Period		Annual
Depreciation (a)
(dollars in millions)
Northeastern Plant, Unit 3$183.2 $119.2 $19.9 (b)2026(c)$14.9 
Dolet Hills Power Station27.3 114.3 24.2 2021(d)7.8 
Pirkey Power Plant157.1 49.4 38.9 2023(e)13.6 
Welsh Plant, Units 1 and 3511.2 24.9 57.8 (f)2028(g)33.2 
(a)Represents the amount of annual depreciation that has been collected from customers over the prior 12-month period.
(b)Includes Northeastern Plant, Unit 4, which was retired in 2016. Removal of Northeastern Plant, Unit 4, will be performed with Northeastern Plant, Unit 3, after retirement.
(c)Northeastern Plant, Unit 3 is currently being recovered through 2040. Accelerated recovery has been requested in the 2021 Oklahoma base rate case.
(d)Dolet Hills Power Station is currently being recovered through 2026 in the Louisiana jurisdiction and through 2046 in the Arkansas and Texas jurisdictions.
(e)Pirkey Power Plant is currently being recovered through 2025 in the Louisiana jurisdiction and through 2045 in the Arkansas and Texas jurisdictions.
(f)Includes Welsh Plant, Unit 2, which was retired in 2016. Removal of Welsh Plant, Unit 2, will be performed with Welsh Plant, Units 1 and 3, after retirement.
(g)Unit 1 is being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.

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

DHLC provides 100% of the fuel supply to Dolet Hills Power Station. During the second quarter of 2019, the Dolet Hills Power Station initiated a seasonal operating schedule. In 2020, management of SWEPCo and CLECO determined DHLC would not proceed developing additional Oxbow Lignite Company (Oxbow) mining areas for future lignite extraction and ceased extraction of lignite at the mine in May 2020. 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. In addition, 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 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 non-fuel costs are recoverable by SWEPCo through base rates. SWEPCo’s share of the net investment in the Dolet Hills Power Station is $147 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 $119 million as of June 30, 2021. Also, as of June 30, 2021, SWEPCo had a net over-recovered fuel balance of $17 million, excluding impacts of the February 2021 severe winter weather event, which includes fuel consumed at the Dolet Hills Power Station. Additional operational, reclamation and other land-related costs incurred by DHLC and Oxbow will be billed to SWEPCo and included in future fuel clauses.
153




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 below for additional information.

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.

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

In 2020, management announced plans to retire the Pirkey Power Plant in 2023. The Pirkey Power Plant non-fuel costs are recoverable by SWEPCo through base rates and fuel costs are recovered through active fuel clauses. SWEPCo’s share of the net investment in the Pirkey Power Plant is $206 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 $148 millionas of June 30, 2021. Also, as of June 30, 2021, SWEPCo had a net over-recovered fuel balance of $17 million, excluding impacts of the February 2021 severe winter weather event, which includes fuel consumed at the Pirkey Power Plant. Additional operational, reclamation and other land-related costs incurred by Sabine will be billed to SWEPCo and included in future fuel clauses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2020 Texas Fuel Reconciliation (Applies to AEP and SWEPCo)

In June 2020, SWEPCo filed a fuel reconciliation with the PUCT for its retail operations in Texas for the reconciliation period of March 1, 2017 to December 31, 2019. The fuel reconciliation included total fuel costs of $1.7 billion ($616 million of which is related to the Texas jurisdiction). In January 2021, various parties filed testimony recommending fuel cost disallowances totaling $125 million relating to the Texas jurisdiction. Also in January 2021, SWEPCo filed rebuttal testimony disputing the recommended disallowances. In February 2021, SWEPCo and various parties reached a settlement in principle which resulted in a $10 million reduction in recoverable fuel costs for the reconciliation period, which was recognized in SWEPCo’s 2020 financial statements. In June 2021, the settlement was filed and approved by the PUCT. If additional costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
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Regulatory Assets Pending Final Regulatory Approval (Applies to all Registrants except AEPTCoAEPTCo)
AEP
June 30,December 31,
20212020
 Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Earning a Return  
Unrecovered Winter Storm Fuel Costs (a)$1,122.4 $0 
Dolet Hills Power Station Accelerated Depreciation114.3 71.2 
Pirkey Power Plant Accelerated Depreciation49.4 12.2 
Kentucky Deferred Purchase Power Expenses44.4 41.3 
Plant Retirement Costs – Unrecovered Plant, Louisiana35.2 35.2 
Oklaunion Power Station Accelerated Depreciation33.5 34.4 
Welsh Plant, Units 1 and 3 Accelerated Depreciation24.9 3.6 
Other Regulatory Assets Pending Final Regulatory Approval26.8 22.8 
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs301.0 134.2 
Plant Retirement Costs – Asset Retirement Obligation Costs25.9 25.9 
COVID-1917.4 24.9 
Environmental Expense Deferral - Virginia13.6 9.3 
Other Regulatory Assets Pending Final Regulatory Approval37.2 27.2 
Total Regulatory Assets Pending Final Regulatory Approval$1,846.0 $442.2 

(a)PSO and OPCo)SWEPCo have active fuel clauses that allow for the recovery of prudently incurred fuel and purchased power expenses. However, the recovery of these costs from customers may be extended over longer than usual time periods to mitigate the impact on customer bills. See “Impacts of Severe Winter Weather” section below for additional information.

AEP Texas
June 30,December 31,
20212020
Noncurrent Regulatory Assets(in millions)
Regulatory Assets Currently Earning a Return
Advanced Metering System$16.6 $16.3 
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs13.7 0.8 
COVID-196.5 10.5 
Vegetation Management Program5.2 3.8 
Texas Retail Electric Provider Bad Debt Expense4.1 0 
Other Regulatory Assets Pending Final Regulatory Approval4.3 1.5 
Total Regulatory Assets Pending Final Regulatory Approval$50.4 $32.9 

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  AEP
  March 31, December 31,
  2018 2017
 Noncurrent Regulatory Assets (in millions)
     
Regulatory Assets Currently Earning a Return    
Plant Retirement Costs - Unrecovered Plant $50.3
 $50.3
Other Regulatory Assets Pending Final Regulatory Approval 12.5
 9.6
Regulatory Assets Currently Not Earning a Return  
  
Storm Related Costs (a) 130.3
 128.0
Plant Retirement Costs - Asset Retirement Obligation Costs 39.7
 39.7
Cook Plant Uprate Project 31.1
 36.3
Cook Plant Turbine 11.2
 15.9
Other Regulatory Assets Pending Final Regulatory Approval 32.6
 42.2
Total Regulatory Assets Pending Final Regulatory Approval (b)$307.7
 $322.0
APCo
June 30,December 31,
20212020
Noncurrent Regulatory Assets(in millions)
Regulatory Assets Currently Earning a Return
COVID-19 – Virginia$4.8 $3.7 
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs55.2 3.4 
Plant Retirement Costs – Asset Retirement Obligation Costs25.9 25.9 
Environmental Expense Deferral - Virginia13.6 9.3 
COVID-19 – West Virginia1.9 1.5 
Other Regulatory Assets Pending Final Regulatory Approval0.1 0 
Total Regulatory Assets Pending Final Regulatory Approval$101.5 $43.8 

(a)As of March 31, 2018, AEP Texas has deferred $105 million related to Hurricane Harvey and is currently exploring recovery options, including securitization.
(b)In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. APCo’s recovery of the remaining Virginia net book value for the retired plants will be considered in the Virginia SCC’s 2020 triennial review of APCo’s generation and distribution base rates. The Virginia SCC staff has requested that APCo prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018.



 I&M
June 30,December 31,
20212020
Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval$0 $0.5 
Regulatory Assets Currently Not Earning a Return  
COVID-191.6 3.8 
Other Regulatory Assets Pending Final Regulatory Approval0.6 0 
Total Regulatory Assets Pending Final Regulatory Approval$2.2 $4.3 



 OPCo
June 30,December 31,
20212020
Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs$6.7 $4.0 
COVID-191.8 4.4 
Other Regulatory Assets Pending Final Regulatory Approval0.1 0 
Total Regulatory Assets Pending Final Regulatory Approval$8.6 $8.4 

 PSO
June 30,December 31,
20212020
Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Earning a Return  
Unrecovered Winter Storm Fuel Costs (a)$669.4 $0 
Oklaunion Power Station Accelerated Depreciation33.5 34.4 
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs28.0 15.8 
Other Regulatory Assets Pending Final Regulatory Approval0.8 0.3 
Total Regulatory Assets Pending Final Regulatory Approval$731.7 $50.5 

(a)PSO has an active fuel clause that allows for the recovery of prudently incurred fuel and purchased power expenses. However, the recovery of these costs from customers may be extended over longer than usual time periods to mitigate the impact on customer bills. See “Impacts of Severe Winter Weather” section below for additional information.

156




  AEP Texas
  March 31, December 31,
  2018 2017
Noncurrent Regulatory Assets (in millions)
     
Regulatory Assets Currently Not Earning a Return    
Storm-Related Costs (a) $128.7
 $123.3
Rate Case Expense 0.2
 0.1
Total Regulatory Assets Pending Final Regulatory Approval $128.9
 $123.4


(a)As of March 31, 2018, AEP Texas has deferred $105 million related to Hurricane Harvey and is currently exploring recovery options, including securitization.
SWEPCo
June 30,December 31,
20212020
Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Earning a Return  
Unrecovered Winter Storm Fuel Costs (a)$453.0 $0 
Dolet Hills Power Station Accelerated Depreciation114.3 71.2 
Pirkey Power Plant Accelerated Depreciation49.4 12.2 
Plant Retirement Costs – Unrecovered Plant, Louisiana
35.2 35.2 
Welsh Plant, Units 1 and 3 Accelerated Depreciation24.9 3.6 
Other Regulatory Assets Pending Final Regulatory Approval5.4 2.2 
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs144.3 99.3 
Asset Retirement Obligation - Louisiana9.7 9.1 
Other Regulatory Assets Pending Final Regulatory Approval16.4 14.5 
Total Regulatory Assets Pending Final Regulatory Approval$852.6 $247.3 
  APCo
  March 31, December 31,
  2018 2017
Noncurrent Regulatory Assets (in millions)
     
Regulatory Assets Currently Earning a Return    
Plant Retirement Costs - Materials and Supplies $9.0
 $9.1
Regulatory Assets Currently Not Earning a Return    
Plant Retirement Costs - Asset Retirement Obligation Costs 39.7
 39.7
Other Regulatory Assets Pending Final Regulatory Approval 0.6
 0.6
Total Regulatory Assets Pending Final Regulatory Approval (a) $49.3
 $49.4


(a)In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. APCo’s recovery of the remaining Virginia net book value for the retired plants will be considered in the Virginia SCC’s 2020 triennial review of APCo’s generation and distribution base rates. The Virginia SCC staff has requested that APCo prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018.
(a)SWEPCo has an active fuel clause that allows for the recovery of prudently incurred fuel and purchased power expenses. However, the recovery of these costs from customers may be extended over longer than usual time periods to mitigate the impact on customer bills. See “Impacts of Severe Winter Weather” section below for additional information.
  I&M
  March 31, December 31,
  2018 2017
Noncurrent Regulatory Assets (in millions)
     
Regulatory Assets Currently Not Earning a Return    
Cook Plant Uprate Project $31.1
 $36.3
Deferred Cook Plant Life Cycle Management Project Costs - Michigan —
 14.7
Cook Plant Turbine 11.2
 15.9
Rockport Dry Sorbent Injection System - Indiana 11.3
 10.4
Other Regulatory Assets Pending Final Regulatory Approval 4.5
 2.0
Total Regulatory Assets Pending Final Regulatory Approval $58.1
 $79.3
  PSO
  March 31, December 31,
  2018 2017
Noncurrent Regulatory Assets (in millions)
     
Regulatory Assets Currently Not Earning a Return  
  
Storm Related Costs $—
 $3.2
Other Regulatory Assets Pending Final Regulatory Approval 0.1
 0.1
Total Regulatory Assets Pending Final Regulatory Approval $0.1
 $3.3



  SWEPCo
  March 31, December 31,
  2018 2017
Noncurrent Regulatory Assets (in millions)
     
Regulatory Assets Currently Earning a Return    
Plant Retirement Costs - Unrecovered Plant $50.3
 $50.3
Other Regulatory Assets Pending Final Regulatory Approval 0.5
 0.5
Regulatory Assets Currently Not Earning a Return  
  
Rate Case Expense - Texas 4.4
 4.3
Asset Retirement Obligation - Arkansas, Louisiana 4.3
 4.0
Shipe Road Transmission Project - FERC 3.3
 3.3
Other Regulatory Assets Pending Final Regulatory Approval 2.8
 2.5
Total Regulatory Assets Pending Final Regulatory Approval $65.6
 $64.9


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


ImpactImpacts of Tax ReformSevere Winter Weather


RateStorm Restoration Costs (Applies to AEP, APCo and SWEPCo)

In February 2021, severe winter weather impacted the service territories of APCo, KPCo and SWEPCo resulting in power outages and extensive damage to transmission and distribution infrastructures. As a result, incremental restoration expenses have been deferred related to the severe winter weather. The current estimate of storm restoration costs are as follows:

June 30, 2021
CompanyJurisdictionCapitalO&MRegulatory AssetTotal
(in millions)
APCoVirginia$8.0 $2.2 $6.6 $16.8 
APCoWest Virginia22.3 0 42.7 65.0 
SWEPCoLouisiana5.7 0 45.7 51.4 
KPCoKentucky28.6 4.2 42.6 75.4 
Total$64.6 $6.4 $137.6 $208.6 

The amounts in the table above represent estimates as of June 30, 2021, and are subject to true-up as additional information becomes available. In March 2021, the LPSC approved the deferral of incremental other operation and maintenance storm restoration expenses related to the Louisiana jurisdiction for SWEPCo. Similarly, in April 2021, the KPSC approved deferral of KPCo’s incremental other operation and maintenance storm restoration expenses. KPCo intends to seek recovery of these incremental storm restoration costs in their next base rate case while APCo and SWEPCo are expected to seek recovery in separate filings. If any of the restoration costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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February 2021 Severe Winter Weather Impacts in SPP (Applies to AEP, PSO and SWEPCo)

The February 2021 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. From February 9, 2021, to February 20, 2021, PSO’s and SWEPCo’s natural gas expenses and purchases of electricity still to be recovered from customers are as follows:
PSOSWEPCoTotal
(in millions)
Retail Customers (a)$669.4 $453.0 (b)$1,122.4 
Wholesale Customers0 62.8 62.8 
Total$669.4 $515.8 $1,185.2 

(a)These costs were deferred as regulatory mattersassets as of June 30, 2021.
(b)SWEPCo’s balance consists of $116 million, $161 million and $176 million related to the Arkansas, Louisiana and Texas jurisdictions, respectively.

Retail Customers

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 impactedprobable 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 federal income tax implications.the APSC. Also in April 2021, SWEPCo filed testimony supporting a five-year recovery with a pretax rate of return of 6.05% which has been supported by APSC staff. Various other parties have recommended recovery periods ranging from 5-20 years with a pretax rate of return of 1.65%. In December 2017, Tax ReformJuly 2021, the APSC ordered more testimony regarding the option of utilizing securitization to recover the fuel costs. Once testimony concludes, a hearing will be scheduled. The prudency of these fuel costs is expected to be addressed in a separate proceeding.

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 these retail fuel costs over a longer period than what the FAC traditionally allows. In April 2021, SWEPCo began recovery of its Louisiana jurisdictional share of these fuel costs based on a five year recovery 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 at an interim rate of 0.75%, over a longer time period than what the FAC traditionally allows. Also in April 2021, legislation was enacted which will impact outstanding ratein Oklahoma to securitize the extraordinary fuel and regulatory matters. For additional details onpurchase of electricity costs impacting the utilities within the state. Under the legislation, the OCC has the authority to determine, after receiving an application from a rate-regulated utility, if the extraordinary fuel and purchase of electricity costs incurred in February 2021 may be mitigated through securitization to reduce the impact on customer bills. PSO has filed an application for a financing order to pursue securitization.

SWEPCo expects to make a filing with the PUCT in the third quarter of Tax Reform, see Note 11 - Income Taxes.2021 to seek a recovery mechanism and an appropriate carrying charge for the Texas jurisdictional share of the retail fuel costs.


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Wholesale Customers

During the first quarter of 2021, SWEPCo billed wholesale customers $104 million resulting from the severe winter weather events. SWEPCo worked with wholesale customers to establish payment terms for the outstanding accounts receivable. As of June 30, 2021, $63 million of accounts receivable from wholesale customers are outstanding. 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 and six months ended June 30, 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.

COVID-19 Pandemic

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 June 30, 2021, AEP’s electric operating companies have resumed customary disconnection practices in all regulated jurisdictions with the exception of Virginia. 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. If any costs related to COVID-19 are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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


AEP Texas Interim Transmission and Distribution Rates


As of March 31, 2018,Through June 30, 2021, AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2017,that are subject to review are estimated to be $830is approximately $171 million. A base rate review could produceresult in a refund to customers if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition.

In March 2018, AEP Texas filed an application to reduce its transmission rates by $24 million to reflect the lower federal income tax rate due to Tax Reform. The filing did not address the return of excess deferred income tax benefits to customers.

In April 2018, AEP Texas filed an application to amend its Distribution Cost Recovery Factor (DCRF). The filing sought to increase revenues by approximately $3 million, which includes capital investment additions of $24 million offset by a reduction of $21 million due to a lower federal income tax rate as a result of Tax Reform. The filing did not address the return of excess deferred income tax benefits to customers. New rates will be effective September 1, 2018.

In April 2018, the PUCT adopted a rule requiring investor-owned utilities operating solely inside ERCOT to make periodic filings for rate proceedings. The proposal requires AEP Texasis required to file for a comprehensive rate review no later than May 1, 2019.April 3, 2024.


Hurricane Harvey

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

2017-2019 Virginia Triennial Review

In AugustNovember 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 Hurricane Harvey hit– 2019 earnings test and (c) the coastreasonableness and prudency of Texas, causingAPCo’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, an intervenor filed its assignments of error with the Virginia Supreme Court related to the appeal of the November 2020 order in which it stated the Virginia SCC erred: (a) in determining that Virginia law did not apply to its determination to permit amortization for recovery of costs associated with retired coal-fired generation assets, (b) in establishing a new regulatory asset for a cost incurred outside of the triennial review period due to its failure to apply a threshold earnings test before approving deferred cost recovery and (c) in misapplying the requirement that APCo bear the burden of demonstrating that power outagespurchases made by APCo from its affiliate, OVEC, were priced at the lower of OVEC’s cost or the market price for nonaffiliated power.

In March 2021, APCo filed its assignments of error with the Virginia Supreme Court related to its appeal of the November 2020 order in which it stated the Virginia SCC erred: (a) in finding that costs associated with asset impairments related to early retirement determinations made by APCo for certain generation facilities should not be attributed to the test periods under review and deemed fully recovered in the AEP Texas service territory. AEP Texas hasperiod recorded, (b) in finding that it was permitted to evaluate the reasonableness of APCo’s decision to record, per books for financial reporting purposes, asset impairments related to early retirement determinations for certain generation facilities, (c) as a PUCT approved catastrophe reserveresult of the errors described in (a) and (b), in denying APCo an increase in rates, (d) in failing to review and make any findings regarding whether APCo’s rates would allow it to earn a fair rate of return going forward, (e) in denying APCo an increase in base rates by failing to ensure that APCo has an opportunity to recover its costs and can defer incremental storm expenses. AEP Texas currently recovers approximately $1 millionearn a fair rate of stormreturn, thereby resulting in a taking of private property for public use without just compensation and (f) in retroactively adjusting APCo’s depreciation expense for purposes of calculating APCo’s earnings for the 2017-2019 triennial period.

In 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 annually through base rates. Asincurred 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 31, 2018,


2021, APCo filed a notice of appeal of the total balance of AEP Texas’ deferred storm costs is approximately $129 million, inclusive of approximately $105 millionof incremental storm expenses recorded as a regulatory asset related to Hurricane Harvey. As of March 31, 2018, AEP Texas has recorded approximately $186 millionof capital expenditures related to Hurricane Harvey. Also, as of March 31, 2018, AEP Texas has received $10 million in insurance proceeds, which were applied to the regulatory asset and property, plant and equipment. Management, in conjunctionreconsideration order with the insurance adjusters, is reviewing all damagesVirginia Supreme Court. APCo expects to determinesubmit its brief before the extent of coverage for additional insurance reimbursement. Any future insurance recoveries received will be applied to and will offset the regulatory asset and property, plant and equipment, as applicable. Management believes the amount recorded as a regulatory asset is probable of recovery and AEP Texas is currently evaluating recovery options for the regulatory asset, including securitization. The standard process for storm cost recoveryVirginia Supreme Court in Texas requires two filings with the PUCT. Management expects the first filing by the end of the third quarter of 2018. If2021.

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In April 2021, and in conjunction with APCo’s November 2020 and March 2021 appeals with the ultimate costsVirginia 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. In May 2021, the Virginia Supreme Court denied APCo’s petition for an interim rate increase and denied the request for an expedited schedule on APCo’s appeals.

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 incidentclosed 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 not recoveredgranted by insurance or through the regulatory process,Virginia Supreme Court, it would have an adverse effect oncould initially reduce future net income cash flows and impact financial condition. The initial negative impact for the write-off of closed coal-fired plant asset balances would potentially be partially offset by an increase in base rates for earning below APCo’s 2017-2019 authorized ROE band.


APCo Rate Matters (Applies to AEP and APCo)CCR/ELG Compliance Plan Filings

Virginia Legislation Affecting Earnings Reviews


In 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates were frozen until afterDecember 2020, APCo submitted filings with the Virginia SCC ruled on APCo’s next biennial review. These amendments also precludedand WVPSC requesting approvals necessary to implement CCR/ELG compliance plans at the Amos and Mountaineer Plants. Intervenors in Virginia and West Virginia recommended that only the CCR-related investments be constructed at Amos and Mountaineer and, as a consequence, APCo close these generating facilities at the end of 2028. In July 2021, a Virginia Senior Hearing Examiner recommended that the Virginia SCC from performing biennial reviewsdeny, at this time, APCo’s request for approval of APCo’s earnings for the years 2014 through 2017.

In March 2018, new Virginia legislation impacting investor-owned utilities was enacted, effective July 1, 2018,ELG investments at the Amos and Mountaineer Plants. The examiner also recommended that will: (a) on a one-time basis, require APCo to exclude $10 million of fuel expenses from the July 2018 over/under calculation, (b) reduce APCo’s base rates by $50 million annually no later than July 30, 2018, on an interim basis and subject to true-up, to reflect the lower federal income tax rate due to Tax Reform, (c) require APCo to file its next generation and distribution base rate case by March 31, 2020 using 2017, 2018 and 2019 test years (“triennial review”), (d) require an adjustment in APCo’s base rates on April 1, 2019 to reflect actual annual reductions in corporate income taxes due to Tax Reform, (e) require APCo to obtain approval fromif the Virginia SCC ultimately does not grant APCo approval of the ELG investments, the Virginia SCC should delay consideration of the reasonableness and prudency of previously incurred ELG costs until a future case.

APCo’s current estimate of its total CCR/ELG cost of investment for energy efficiency programs with projectedthe Amos and Mountaineer plants, including AFUDC, is approximately $240 million. As of June 30, 2021, APCo’s total company CCR and ELG investment balances in CWIP for these plants were $8 million and $28 million, respectively.

If any of APCo’s CCR/ELG costs in the aggregate of at least $140 million over the 10-year period from July 1, 2018 through July 1, 2028 and (f) require APCo to construct and/or acquire solar generation facilities in Virginia of at least 200 MW of aggregate capacity. Triennial reviews are subject to an earnings test which provides that any over earnings may be reinvested innot approved energy distribution grid transformation projects. The Virginia SCC’s triennial review of 2017-2019 APCo earnings couldfor recovery, it would reduce future net income and cash flows and impact financial condition.


ETT Rate Matters (Applies to AEP)


ETT Interim Transmission Rates


AEP has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. Through March 31, 2018,June 30, 2021, AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $781 million.approximately $1.3 billion.A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring.

In February 2018, ETT filed an application to reduce its transmission rates by $27 million to reflect the lower federal income tax rate due to Tax Reform. The filing did not address the return of excess deferred income tax benefits to customers.

In April 2018, the PUCT adopted a rule requiring investor-owned utilities operating solely inside ERCOT to make periodic filings for rate proceedings. The rule requires ETTis required to file for a comprehensive rate review no later than February 1, 2021.2023, during which the $1.3 billion of cumulative revenues above will be subject to review.

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


2017Indiana Earnings Test Filings

I&M is required by Indiana law to submit an earnings test evaluation for the most recent one-year and five-year periods as part of I&M’s semi-annual Indiana FAC filings. These earnings test evaluations require I&M to include a credit in the FAC factor computation for periods in which I&M earned above its authorized return for both the one-year and five-year periods. The credit is determined as 50% of the lower of the one-year or five-year earnings above the authorized level. In July 2021, I&M will submit its FAC filing and earnings test evaluation for the period ended May 2021. As of June 30, 2021, I&M’s financial statements adequately reflect the estimated impact of I&M’s upcoming Indiana earnings test filings. If it is determined that I&M’s over-earnings exceed what has been recorded, it could reduce future net income and cash flows and impact financial condition.

2021 Indiana Base Rate Case


In July 2017,2021, I&M filed a request with the IURC for a $263 million annual increase in Indiana rates based upon a proposed 10.6% return on common equity with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increase would be subject to a temporary offsetting $23 million annual reduction to customer bills through December 2018 for a credit adjustment rider related to the timing of estimated in-service dates of certain capital expenditures.  The proposed annual increase includes $78 million related to increased annual depreciation rates and an $11 million increase related to the amortization of certain Cook Plant and Rockport Plant regulatory assets. The increase in depreciation rates includes a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant, including the Cook Plant Life Cycle Management Project.

In November 2017, various intervenors filed testimony that included annual revenue increase recommendations ranging from $125 million to $152 million. The recommended returns on common equity ranged from 8.65% to 9.1%. In addition, certain parties recommended longer recovery periods than I&M proposed for recovery of regulatory assets and depreciation expenses related to Rockport Plant, Units 1 and 2. In January 2018, in response to a January 2018 IURC request related to the impact of Tax Reform on I&M’s pending base rate case, I&M filed updated schedules supporting a $191$104 million annual increase in Indiana base rates ifbased upon a proposed 10% ROE. I&M proposed a phased-in annual increase in rates of $73 million effective in May 2022 with the effect of Tax Reform was included in the cost of service.

In February 2018, I&M and all parties to the case, except one industrial customer, filed a Stipulation and Settlement Agreement for a $97remaining $31 million annual increase in Indiana rates to be effective January 2023. The proposed annual increase includes $7 million related to an annual increase in depreciation expense, driven by increased depreciation rates and proposed investments. The request also includes a new AMI rider for proposed meter projects. Intervenor testimony is expected in the fourth quarter of 2021. If any costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

KPCo Rate Matters (Applies to AEP)

CCR/ELG Compliance Plan Filings

KPCo and WPCo each own a 50% interest in the Mitchell Plant. In December 2020 and February 2021, WPCo and KPCo filed requests with the WVPSC and KPSC, respectively, to obtain the regulatory approvals necessary to implement CCR and ELG compliance plans and seek recovery of the estimated $132 million investment for the Mitchell Plant that would allow the plant to continue operating through 2040. Within those requests, WPCo and KPCo also filed a $25 million alternative to implement only the CCR-related investments with the WVPSC and KPSC, respectively, which would allow the Mitchell Plant to continue operating only through 2028.

In May 2021, intervenors in Kentucky and West Virginia submitted testimony with recommendations that only the CCR-related investments be constructed at the Mitchell Plant. In July 1, 2018 subject2021, the KPSC issued an order approving the CCR only alternative and rejecting the full CCR and ELG compliance plan. As of June 30, 2021, the total of the Mitchell Plant CCR and ELG investment balances in CWIP, was $2 million and $4 million, respectively, split equally between KPCo and WPCo. As of June 30, 2021, the net book value of the Mitchell Plant, before cost of removal including CWIP and inventory, was $1.2 billion, split equally between KPCo and WPCo.

If any of the CCR and ELG compliance plan costs are not approved for recovery and/or the retirement date of the Mitchell Plant is accelerated to 2028 without commensurate cost recovery, it would reduce future net income and cash flows and impact financial condition.

OPCo Rate Matters (Applies to AEP and OPCo)

2020 Ohio Base Rate Case

In June 2020, OPCo filed a temporary offsetting reduction to customer bills through December 2018request with the PUCO for a credit rider related to the timing of estimated in-service dates of certain capital expenditures.  The one industrial customer agreed to not oppose the Stipulation and Settlement Agreement. The difference between I&M’s requested $263 million annual increase and the $97$42 million annual increase in base rates based upon a proposed 10.15% ROE net of existing riders. Additionally, OPCo filed a request with the StipulationPUCO for a 60-day temporary delay of the normal rate case proceeding due to the COVID-19 pandemic with rates expected to be effective approximately mid-2021.
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In November 2020, the PUCO staff filed testimony supporting an annual revenue decrease ranging from $102 million to $123 million based upon an ROE of 8.76% to 9.78%. The difference between OPCo’s request and Settlement Agreementthe staff testimony are primarily due to reductions in: (a) demand-side management programs of $40 million, (b) ROE ranging from $9 million to $30 million, (c) employee-related expenses of $23 million, (d) rate base of $19 million, (e) property taxes of $17 million, (f) other various expenses of $15 million, (g) depreciation expense of $11 million and (h) vegetation management programs of $10 million which is subject to over/under-recovery through a rider. The staff’s proposed disallowance of plant in service could also result in a write-off of up to $27 million. In addition, the staff recommended that capitalized incentives be excluded from base rates prospectively and also recommended annual revenue caps for the DIR of $57 million in 2021, $78 million in 2022, $96 million in 2023 and $46 million for the first five months of 2024. In December 2020, OPCo and intervenors filed objections.

In March 2021, OPCo, the PUCO staff and various intervenors filed a joint stipulation and settlement agreement with the PUCO. The agreement includes a $68 million annual decrease in base rates based on 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 result of: (a) the reduction in the federal income tax rate duerequested ROE, the removal of proposed future energy efficiency costs and a decrease in vegetation management expenses moved to Tax Reform,recovery in riders. Additionally, the agreement includes: (a) an increased fixed monthly residential customer charge, (b) the feedbackdiscontinuation of creditsrate decoupling and (c) 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 excess deferredthe first five months of 2024. Annual revenue caps for the DIR can be increased if OPCo achieves certain reliability standards. If the joint stipulation and settlement agreement is approved by the PUCO, new base rates will go into effect 14 days after such approval. A hearing took place with the PUCO in May 2021 and initial briefs were filed in June 2021 followed by reply briefs in July 2021. An order from the PUCO is expected by the end of 2021. If the joint stipulation and settlement agreement is denied by the PUCO, it could reduce future net income taxes, (c)and cash flows and impact financial condition.

2019 Ohio DIR Audit

OPCo conducts business under an ESP as approved by the PUCO which subjects the DIR to annual audits. In August 2020, a 9.95% return on equity, (d) longer recovery periodsthird-party consulting company filed an audit report with the PUCO indicating that OPCo exceeded its 2019 authorized revenue limit by $17 million. Management disagrees with the audit results and believes that OPCo was below its authorized revenue limit in 2019. The PUCO has not yet issued a procedural schedule to address the audit results. If the results of regulatory assets, (e) lowerthe audit are upheld by the PUCO and any refunds to customers or revenue reductions are ordered, it could reduce future net income and cash flows and impact financial condition.

PSO Rate Matters (Applies to AEP and PSO)

2021 Oklahoma Base Rate Case

In April 2021, PSO filed a request with the OCC for a $172 million net annual increase in Oklahoma base rates based upon a 10% ROE. The proposed net annual increase includes: (a) a $57 million annual depreciation expense primarily for metersincrease, of which $45 million is related to the accelerated depreciation recovery of the Oklaunion Power Station and (f) an increaseNortheastern Plant, Unit 3 through 2026 and (b) $31 million related to increased SPP expenses. PSO also requested the continuation of its SPP Transmission Tariff that tracks transmission costs as well as continuation and expansion of its Distribution and Safety Reliability Rider to recover projects in the sharing of off-system sales margins with customers from 50% to 95%.  If the Stipulationits proposed grid transformation and Settlement is approved, I&M will also refund $4revitalization plan, which includes $100 million from July through December 2018 for the impact of Tax Reform for the period January through June 2018.  A hearing at the IURC was held in March 2018 and an IURC orderannual capital spend over a 5 year period. Intervenor testimony is expected in the secondthird quarter of 2018.2021. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
2017 Michigan Base
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SWEPCo Rate Case

In May 2017, I&M filed a request with the MPSC for a $52 million annual increase in Michigan base rates based upon a proposed 10.6% return on common equity with the increase to be implemented no later than April 2018. The proposed annual increase includes $23 million related to increased annual depreciation rates and a $4 million increase related to the amortization of certain Cook Plant regulatory assets. The increase in depreciation rates is primarily due to the proposed change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant related to the Life Cycle Management Project.

In February 2018, an MPSC ALJ issued a Proposal for Decision and recommended an annual revenue increase of $49 million, including an intervenors’ proposed capacity rate based on PJM’s net cost of new entry value of $289/MW-day and MPSC staff’s recommended calculation of depreciation expense for both units of Rockport Plant through 2028 and a return on common equity of 9.8%.  If the maximum 10% of customers choose an alternate supplier starting in February 2019, the estimated annual pretax loss due to the reduced capacity rate would be approximately $9 million until adjusted in the next base rate case. 

In April 2018, the MPSC issued an order that generally approved the ALJ proposal resulting in an annual revenue increase of $49 million, effective April 2018 based on a 9.9% return on common equity.  The MPSC also approved the ALJ’s recommendation related to the capacity rate.



Rockport Plant, Unit 2 SCR

In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NOx from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million, excluding AFUDC, to be shared equally between I&M and AEGCo.  As of March 31, 2018, total costs incurred related to this project, including AFUDC, were approximately $28 million.  The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport UPA to I&M and KPCo and will be subject to future regulatory approval for recovery.

In March 2018, the IURC issued an order approving: (a) the CPCN, (b) the $274 million estimated cost of the SCR, excluding AFUDC, (c) deferral accounting for the Indiana jurisdictional ownership share of costs, including investment carrying costs, (d) depreciation of the SCR asset over 10 years and (e) recovery of these costs using I&M’s existing Indiana Clean Coal Technology Rider.

In April 2018, a group of intervenors filed a Petition for Reconsideration and Rehearing of the March 2018 IURC order.  The intervenors requested that the IURC reopen the proceeding primarily to address whether allowing I&M any cost recovery for the SCR would constitute a cross-subsidization issue and to reverse its finding approving cost recovery for the Rockport Plant, Unit 2 SCR project.  Also in April 2018, I&M filed a response to the intervenors’ petition.

KPCo Rate Matters (Applies to AEP)

2017 Kentucky Base Rate Case

In January 2018, the KPSC issued an order approving a non-unanimous settlement agreement with certain modifications resulting in an annual revenue increase of $12 million, effective January 2018, based on a 9.7% return on equity. The KPSC’s primary revenue requirement modification to the settlement agreement was a $14 million annual revenue reduction for the decrease in the corporate federal income tax rate due to Tax Reform. The KPSC approved: (a) the deferral of a total of $50 million of Rockport Plant UPA expenses for the years 2018 through 2022, with the manner and timing of recovery of the deferral to be addressed in KPCo’s next base rate case, (b) the recovery/return of 80% of certain annual PJM OATT expenses above/below the corresponding level recovered in base rates, (c) KPCo’s commitment to not file a base rate case for three years with rates effective no earlier than 2021 and (d) increased depreciation expense based upon updated Big Sandy Plant, Unit 1 depreciation rates using a 20-year depreciable life.

In February 2018, KPCo filed with the KPSC for rehearing of the January 2018 base case order and requested an additional $2.3 million of annual revenue increases related to: (a) the calculation of federal income tax expense, (b) recovery of purchased power costs associated with forced outages and (c) capital structure adjustments.  Also in February 2018, an intervenor filed for rehearing recommending that the reduced corporate federal income tax rate be reflected in lower purchased power expense related to the Rockport UPA. In February 2018, the KPSC issued an order granting rehearing of these items, with an exception for the capital structure adjustments, which was denied by the KPSC.



OPCo Rate Matters (Applies to AEP and OPCo)SWEPCo)

Ohio Electric Security Plan Filings

June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024

In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the DIR, effective June 2015 through May 2018. The proposal also involved a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA.

In 2015 and 2016, the PUCO issued orders in this proceeding. As part of the issued orders, the PUCO approved (a) the DIR with modified rate caps, (b) recovery of OVEC-related net margin incurred beginning June 2016, (c) potential additional contingent customer credits of up to $15 million to be included in the PPA rider over the final four years of the PPA rider and (d) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions. In April 2017, the PUCO rejected all pending rehearing requests. In June 2017, intervenors filed appeals to the Supreme Court of Ohio stating that the PUCO’s approval of the OVEC PPA was unlawful and does not provide customers with rate stability.

In November 2016, OPCo refiled its amended ESP extension application and supporting testimony, consistent with the terms of the modified and approved stipulation agreement and based upon a 2016 PUCO order. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Renewable Resource Rider.

In August 2017, OPCo and various intervenors filed a stipulation agreement with the PUCO. The stipulation extends the term of the ESP through May 2024 and includes: (a) an extension of the OVEC PPA rider, (b) a proposed 10% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) rate caps related to OPCo’s DIR ranging from $215 million to $290 million for the periods 2018 through 2021 and (e) the addition of various new riders, including a Smart City Rider and a Renewable Generation Rider. DIR rate caps will be reset in OPCo’s next distribution base rate case which must be filed by June 2020.

In October 2017, intervenor testimony opposing the stipulation agreement was filed recommending: (a) a return on common equity to not exceed 9.3% for riders earning a return on capital investments, (b) that OPCo should file a base distribution case concurrent with the conclusion of the current ESP in May 2018 and (c) denial of certain new riders proposed in OPCo’s ESP extension. The stipulation was reviewed by the PUCO at a hearing in November 2017.

In April 2018, the PUCO issued an order approving the stipulation agreement, with no significant changes.

2016 SEET Filing

Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk.



In December 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement that was filed at the PUCO in December 2016 and subsequently approved in February 2017: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings.

In May 2017, OPCo submitted its 2016 SEET filing with the PUCO in which management indicated that OPCo did not have significantly excessive earnings in 2016 based upon actual earnings data for the comparable utilities risk group.

In January 2018, PUCO staff filed testimony that OPCo did not have significantly excessive earnings. Also in January 2018, an intervenor filed testimony recommending a $53 million refund to customers. In February 2018, OPCo and PUCO staff filed a stipulation agreement in which both parties agreed that OPCo did not have significantly excessive earnings in 2016.

A 2016 SEET hearing was held in April 2018 and management expects to receive an order in the second half of 2018. While management believes that OPCo’s adjusted 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s proposed SEET adjustments, including treatment of the Global Settlement issues described above, adjust the comparable risk group or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could negatively affect future SEET filings, reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters (Applies to AEP and SWEPCo)


2012 Texas Base Rate Case


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


Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, SWEPCo reversed $114 million of a previously recorded regulatory disallowancesdisallowance in 2013. The resulting annual base rate increase was approximately $52 million. In June 2017, the Texas District Court upheld the PUCT’s 2014 order. In July 2017,order and intervenors filed appeals with the Texas Third Court of Appeals.

In AprilJuly 2018, oral arguments were heard bythe Texas Third Court of Appeals reversed the PUCT’s judgment affirming the prudence of the Turk Plant and remanded the issue back to the PUCT. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court. In March 2021, the Texas Supreme Court issued an opinion reversing the July 2018 judgment of the Texas Third Court of Appeals and agreeing with the PUCT’s judgment affirming the prudence of the Turk Plant. In addition, the Texas Supreme Court remanded the AFUDC dispute back to the Texas Third Court of Appeals. No parties filed a motion for rehearing with the Texas Supreme Court. SWEPCo awaits a decision on the AFUDC dispute from the Texas Third Court of Appeals.


As of June 30, 2021, the net book value of Turk Plant was $1.4 billion, before cost of removal, including materials and supplies inventory and CWIP. If certain parts of the PUCT order are overturned and if SWEPCo cannot ultimately fully recover its approximate 33% Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition.


2016 Texas Base Rate Case


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




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

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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 June 30, 2021, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $83 million ($81 million of which has been deferred as a regulatory asset related to the Louisiana jurisdiction) and incremental capital expenditures of $30 million, all of which is subjectrelated to appealthe Louisiana jurisdiction. Management expects to request recovery of these storm costs, in addition to the Hurricane Delta and February 2021 winter storm costs, in a future filing. If any costs related to Hurricane Laura are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Hurricane Delta

In October 2020, Hurricane Delta hit the coast of Louisiana, causing power outages to more than 23,000 customers in SWEPCo’s Louisiana jurisdiction. In November 2020, the LPSC issued an order allowing Louisiana utilities, including SWEPCo, to establish a regulatory asset to track and defer expenses associated with Hurricane Delta. As of June 30, 2021, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $17 million, which has been deferred as early asa regulatory asset. Also, management estimates that SWEPCo has incurred incremental capital expenditures of $3 million. Management expects to request recovery of these storm costs, in addition to the second quarter 2018. Hurricane Laura and February 2021 winter storm costs, in a future filing. If any costs related to Hurricane Delta are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2020 Texas Base Rate Case

In April 2018,October 2020, SWEPCo made an income taxfiled a request with the PUCT for a $105 million annual increase in Texas base rates based upon a proposed 10.35% ROE. The request would move transmission and distribution interim revenues recovered through riders into base rates. Eliminating these riders would result in a net annual requested base rate refund tariff filingincrease of $90 million primarily due to increased investments. The proposed net annual increase: (a) includes $5 million related to vegetation management to maintain and improve the reliability of SWEPCo’s Texas jurisdictional distribution system, (b) requests a $10 million annual depreciation increase and (c) seeks $2 million annually to establish a storm catastrophe reserve. In addition, SWEPCo requested recovery of the Texas jurisdictional share of the Dolet Hills Power Station of $45 million which includesis expected to be retired by the end of 2021. In March 2021, intervenor testimony was filed supporting an annual revenue reduction of approximately $18increase ranging from $20 million to reflect the difference between rates collected under the final order and the rates that would be collected under Tax Reform. The filing did not address the return$70 million based upon an ROE of excess deferred income tax benefits9% to customers.

2015 Louisiana Formula Rate Filing

9.15%. In April 2015, SWEPCo2021, staff testimony was filed its formula rate plan for test year 2014 with the LPSC.  The filing includedsupporting a $14$45 million annual increase which was effective August 2015.  In February 2018, LPSC staff filed a report approving the increase as filed. This increase is subject to refund pending commission approval.in base rates based upon an ROE of 9.22%. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.


20172020 Louisiana FormulaBase Rate FilingCase


In April 2017,December 2020, SWEPCo filed a request with the LPSC approved an uncontested stipulation agreement thatfor a $134 million annual increase in Louisiana base rates based upon a proposed 10.35% ROE. In March 2021, SWEPCo filed for itsa revised request with the LPSC to remove hurricane storm costs from the base rate case filing and seek recovery of those costs in a separate filing. SWEPCo’s revised filing requested an annual increase in Louisiana base rates of $114 million. The request would extend the formula rate plan for test year 2015.five years and includes modifications to the formula rate plan to allow for forward-looking transmission costs, reflects the impact of net operating losses associated with the acceleration of certain tax benefits and incorporates future federal corporate income tax changes. The filing included aproposed net annual increase notrequests a $32 million annual depreciation increase to exceed $31 million, which was effective May 2017 and includes SWEPCo’s Louisiana jurisdictionalrecover Louisiana’s share of the Dolet Hills Power Station, Pirkey Power Plant and Welsh Plant, all of which are expected to be retired early. In April 2021, the LPSC approved
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SWEPCo’s request to remove the hurricane storm costs from the base rate case filing. Management expects to request recovery of the $144 million of storm costs associated with Hurricanes Delta, Laura and Flint Creek Plant environmental controls which were placedthe February 2021 winter storm in service in 2016. The net annual increase is subject to refund. a separate filing.

In October 2017, SWEPCoJuly 2021, the LPSC staff filed testimony in Louisiana supporting the prudence of its environmental control investment for Welsh Plant, Units 1 and 3 and Flint Creek power plants. These environmental costs are subject to prudence review. A hearing at the LPSC is scheduled for May 2018. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2018 Louisiana Formula Rate Filing

In April 2018, SWEPCo filed its formula rate plan for test year 2017 with the LPSC.  The filing included a net $28$6 million annual increase which will be effective August 2018.in base rates based upon an ROE of 9.1% while other intervenors recommended an ROE ranging from 9.35% to 9.8%. The filing includedprimary differences between SWEPCo’s requested annual increase in base rates and the LPSC staff’s recommendation include: (a) a reduction in depreciation expense, (b) recovery of Dolet Hills Power Station and Pirkey Power Plant in a separate rider mechanism, (c) the rejection of SWEPCo’s proposed adjustment to include a stand-alone net operating loss carryforward deferred tax asset in rate base and (d) a reduction in the federal income tax rate dueproposed ROE. SWEPCo expects to Tax Reform. The return of excess deferred income tax benefits to customers will be addressed in a supplemental filing and will reduce the $28 million annual increase. The increase includes SWEPCo’s jurisdictional share of Welsh Plant and Flint Creek Plant environmental controls, whose prudence review hearing is scheduled for May 2018. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Welsh Plant - Environmental Impact

Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could total approximately $850 million, excluding AFUDC. As of March 31, 2018, SWEPCo had incurred costs of $399 million, including AFUDC, related to these projects.  Management continues to evaluate the impact of environmental rules and related project cost estimates. As of March 31, 2018, the total net book value of Welsh Plant, Units 1 and 3 was $625 million, before cost of removal, including materials and supplies inventory and CWIP. 

In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence reviewfile rebuttal testimony in the next Arkansas filed base rate proceeding. In April 2017, the LPSC approved recoverythird quarter of $131 million in investments related to its Louisiana jurisdictional share of2021.


environmental controls installed at Welsh Plant, effective May 2017. SWEPCo’s approved Louisiana jurisdictional share of Welsh Plant deferrals: (a) are $11 million, excluding $6 million of unrecognized equity as of March 31, 2018, (b) is subject to review by the LPSC, and (c) includes a WACC return on environmental investments and the related depreciation expense and taxes. In January 2018, SWEPCo received written approval from the PUCT to recover its project costs from retail customers in its 2016 Texas base rate case and is recovering these costs from wholesale customers through SWEPCo’s FERC-approved agreements. See “2016 Texas Base Rate Case” and “2017 Louisiana Formula Rate Filing” disclosures above.


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


FERC Rate Matters

PJM Transmission Rates (Applies to AEP, AEPTCo, APCo, I&M and OPCo)

In June 2016, PJM transmission owners, including AEP’s transmission owning subsidiaries within PJM, and various state commissions filed a settlement agreement at the FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. In July 2016, certain parties filed comments at the FERC contesting the settlement agreement. Upon final FERC approval, PJM would implement a transmission enhancement charge adjustment through the PJM OATT, billable through 2025. Management expects that any refunds received would generally be returned to retail customers through existing state rider mechanisms.


FERC SPP Transmission Complaint - AEP’s PJM Participants (Applies to AEP, AEPTCo, APCo, I&M and OPCo)

In October 2016, seven parties filed a complaint at the FERC that alleged the base return on common equity used by AEP’s transmission owning subsidiaries within PJM in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint.  In November 2017, a FERC order set the matter for hearing and settlement procedures.  In March 2018, AEP’s transmission owning subsidiaries within PJM and six of the complainants filed a settlement agreement with the FERC (the seventh complainant abstained).  If approved by the FERC the settlement agreement (a) establishes a base ROE for AEP’s transmission owning subsidiaries within PJM of 9.85% (10.35% inclusive of the RTO incentive adder of 0.5%), effective January 1, 2018, (b) requires AEP’s transmission owning subsidiaries within PJM to provide a one-time refund of $50 million, attributable from the date of the complaint through December 31, 2017, to be credited to customer bills in the second quarter of 2018 and (c) increases the cap on the equity portion of the capital structure to 55% from 50%.  As part of the settlement agreement, AEP’s transmission owning subsidiaries within PJM also filed updated transmission formula rates incorporating the reduction in the corporate federal income tax rate due to Tax Reform, effective January 1, 2018 and providing for the amortization of the portion of the excess accumulated deferred income taxes that are not subject to the normalization method of accounting, ratably over a ten year period through credits to the federal income tax expense component of the revenue requirement. In April 2018, an ALJ accepted the interim settlement rates, pending the FERC’s consideration of the settlement, and the rates are subject to refund or surcharge, with interest.

In April 2018, certain intervenors filed comments at the FERC recommending a base ROE of 8.48% and a one-time refund of $184 million. In addition, the FERC trial staff filed comments recommending a base ROE of 8.41% and one-time refund of $175 million. Also in April 2018, another intervenor recommended the refund be calculated in accordance with the base ROE that will ultimately be approved by the FERC. Management intends to file reply comments providing further support for the 9.85% base ROE agreed to in the settlement agreement.

Management believes the $50 million refund in the settlement agreement is the best estimate of the probable liability. If the FERC orders revenue reductions in excess of the terms of the settlement agreement, it could reduce future net income and cash flows and impact financial condition.  A decision from the FERC is pending.



Modifications to AEP’s PJM Transmission Rates (Applies to AEP, AEPTCo, APCo, I&M and OPCo)

In November 2016, AEP’s transmission owning subsidiaries within PJM filed an application at the FERC to modify the PJM OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to projected expenses. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. The modified PJM OATT formula rates are based on projected calendar year financial activity and projected plant balances. In December 2017, AEP’s transmission owning subsidiaries within PJM filed an uncontested settlement agreement with the FERC resolving all outstanding issues. In April 2018, the FERC approved the uncontested settlement agreement and rates were implemented effective January 1, 2018.

FERC Transmission Complaint - AEP’s SPP ParticipantsFormula Rate Challenge (Applies to AEP, AEPTCo, PSO and SWEPCo)


In June 2017, several parties filedMay 2021, certain joint customers submitted a complaintformal challenge at the FERC that statesrelated to the base return on common equity used by AEP’s2020 Annual Update of the 2019 SPP Transmission Formula Rates of the AEP transmission owning subsidiaries within SPP in calculating formula transmission rates underSPP. Management is currently reviewing the SPP OATT is excessiveformal challenge and should be reduced from 10.7%responses are due to 8.36%, effective upon the dateFERC at the end of the complaint. In November 2017, a FERC order set the matter for hearing and settlement procedures. Management believes its financial statements adequately address the impact of the complaint.July 2021. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing,or reductions, it could reduce future net income and cash flows and impact financial condition.


Modifications to AEP’s SPP Transmission RatesIndependence Energy Connection Project (Applies to AEP, AEPTCo, PSO and SWEPCo)AEP)


In October 2017,2016, PJM approved the Independence Energy Connection Project (IEC) and included it in its Regional Transmission Expansion Plan (RTEP) to alleviate congestion. Transource Energy owns the IEC, which is located in Maryland and Pennsylvania. In June 2020, the Maryland Public Service Commission approved a Certificate of Public Convenience and Necessity to construct the portion of the IEC in Maryland. In May 2021, the Pennsylvania Public Utility Commission (PA PUC) denied the IEC certificate for siting and construction of the portion in Pennsylvania. Transource Energy has appealed the PA PUC ruling in Pennsylvania state court and challenged the ruling before the United States District Court for the Middle District of Pennsylvania, which is currently pending. The IEC currently remains in the PJM RTEP and as of June 30, 2021, AEP’s transmission owning subsidiaries within SPP filed an application atshare of IEC capital expenditures is approximately $77 million. The FERC has previously granted abandonment benefits for this project, allowing the FERC to modifyfull recovery of prudently incurred costs if the SPP OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to projected expenses.  The modified SPP OATT formula rates are based on projected 2018 calendar year financial activity and projected plant balances. In December 2017,project is cancelled for reasons outside the FERC accepted the proposed modifications effective January 1, 2018, subject to refund, and set this matter for hearing and settlement procedures.control of Transource Energy. If the FERC determines that any of thesethe IEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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FERC SWEPCo Power Supply Agreements Complaint - East Texas Electric Cooperative, Inc. (ETEC) and Northeast Texas Electric Cooperative, Inc. (NTEC)



In September 2017, ETEC and NTEC filed a complaint at the FERC that states the base return on common equity used by SWEPCo in calculating their power supply formula rates is excessive and should be reduced from 11.1% to 8.41%, effective upon the date of the complaint. In November 2017, a FERC order set the matter for hearing and settlement procedures. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.






5.  COMMITMENTS, GUARANTEES AND CONTINGENCIES


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


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


For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 20172020 Annual Report should be read in conjunction with this report.


GUARANTEES


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


Letters of Credit (Applies to AEP and OPCo)AEP Texas)


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


AEP has a $3$4 billion and $1 billion revolving credit facilityfacilities due in June 2021,March 2026 and 2023, respectively, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of March 31, 2018,June 30, 2021, no letters of credit were issued under the $3 billion revolving credit facility.


An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility.  AEP issues letters of credit on behalf of subsidiaries under foursix uncommitted facilities totaling $305 million. In March 2018, one of the uncommitted credit facilities was reduced by $40$425 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of March 31, 2018June 30, 2021 were as follows:
CompanyAmountMaturity
(in millions)
AEP$186.5 July 2021 to July 2022
AEP Texas (a)2.2 July 2022
Company Amount Maturity
  (in millions)  
AEP $81.3
 May 2018 to March 2019
OPCo 0.6
 September 2018
(a)    In July 2021, the maturity date was extended from July 2021 to July 2022.

AEP has $45 million of variable rate Pollution Control Bonds supported by $46 million of bilateral letters of credit maturing in July 2019.


Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo)

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $140 million.  Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine.  This guarantee ends upon depletion of reserves and completion of final reclamation.  It is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of $77 million.  Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation.  As of March 31, 2018, SWEPCo has collected $72 million through a rider for final mine closure and reclamation costs, of which $77 million is recorded in Asset Retirement Obligations, offset by $5 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheet.

Sabine charges SWEPCo, its only customer, all of its costs.  SWEPCo passes these costs to customers through its fuel clause.


Guarantees of Equity Method Investees (Applies to AEP)


In December 2016,2019, AEP issued a performance guarantee foracquired Sempra Renewables LLC. The transaction resulted in the acquisition of a 50% ownedownership interest in five non-consolidated joint venture which is accounted for as anventures and the acquisition of two tax equity method investment.partnerships. Parent has issued guarantees over the performance of the joint ventures. If thea joint venture were to default on payments or performance, AEPParent would be required to make payments on behalf of the joint venture. As of March 31, 2018,June 30, 2021, the
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maximum potential amount of future payments associated with thisthese guarantees was $148 million, with the last guarantee was $75 million, which expiresexpiring in December 2019.2037. The non-contingent liability recorded associated with these guarantees was $29 million, with an additional $1 million expected credit loss liability for the contingent portion of the guarantees. Management considered historical losses, economic conditions and reasonable and supportable forecasts in the calculation of the expected credit loss. As the joint ventures generate cash flows through PPAs, the measurement of the contingent portion of the guarantee liability is based upon assessments of the credit quality and default probabilities of the respective PPA counterparties.


Indemnifications and Other Guarantees


Contracts


The Registrants enter into certain types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, exposure generally does not exceed the sale price.  As of March 31, 2018,June 30, 2021, there were no material liabilities recorded for any indemnifications.


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


Master Lease Agreements (Applies to all Registrants except AEPTCo)


The Registrants lease certain equipment under master lease agreements.  Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee.  Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.amount guaranteed.  As of March 31, 2018,June 30, 2021, the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term iswas as follows:
CompanyMaximum
Potential Loss
(in millions)
AEP$48.6 
AEP Texas11.4 
APCo6.3 
I&M4.2 
OPCo7.6 
PSO4.7 
SWEPCo5.3 
Company 
Maximum
Potential Loss
  (in millions)
AEP $43.4
AEP Texas 10.5
APCo 8.8
I&M 3.1
OPCo 6.3
PSO 3.7
SWEPCo 3.7



RailcarRockport Lease (Applies to AEP and I&M)

AEGCo and I&M and SWEPCo)

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an agreementunrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant).  The Owner Trustee was capitalized with BTM Capital Corporation, as lessor,equity from six owner participants with no relationship to lease 875 coal-transporting aluminum railcars.AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors.

The Owner Trustee owns the Plant and leases equal portions to AEGCo and I&M.  The lease is accounted for as an operating lease.  In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars).  The assignments are accounted for as operating leases for I&M and SWEPCo.  The initial lease term was fiveis for 33 years with three consecutive five-year renewal periods for a maximum lease term of twenty years.  I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options.  The future minimum lease obligations are $7 million and $8 million for I&M and SWEPCo, respectively, for the remaining railcars as of March 31, 2018.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% of the projected fair value of the equipment under the current five year lease term to 77% at the end of the 20-year term.lease term, AEGCo and I&M and SWEPCo have assumed the guarantee underoption to renew the return-and-sale option.  The maximum potential losses related tolease at a rate that approximates fair value.  In November 2020, management announced that AEP will not renew the guarantee are $8 millionlease when it expires in 2022. AEP, AEGCo and $9 million for I&M have no ownership interest in the Owner
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Trustee and SWEPCo, respectively,do not guarantee its debt.  The future minimum lease payments for this sale-and-leaseback transaction as of March 31, 2018, assuming the fair value of the equipment is zero at the end of the current five-yearJune 30, 2021 were as follows:
Future Minimum Lease PaymentsAEP (a)I&M
(in millions)
2021$74.0 $37.0 
2022147.6 73.8 
Total Future Minimum Lease Payments$221.6 $110.8 

(a)AEP’s future minimum lease term.  However, management believes that the fair value would produce a sufficient sales price to avoid any loss.payments include equal shares from AEGCo and I&M.


AEPRO Boat and Barge Leases (Applies to AEP)


In October 2015, AEP signed a Purchase and Sale Agreement to sellsold its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. The sale closed in November 2015. Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor,respective lessors, ensuring future payments under such leases with maturities up to 2027. As of March 31, 2018,June 30, 2021, the maximum potential amount of future payments required under the guaranteed leases was $49$45 million. InUnder the terms of certain instances, AEP has no recourse againstof the arrangements, upon the lessors exercising their rights after an event of default by the nonaffiliated party, if requiredAEP is entitled to payenter into new lease arrangements as a lessee that would have substantially the same terms as the existing leases. Alternatively, for the arrangements with one of the lessors, upon an event of default by the nonaffiliated party and the lessor under a guarantee, butexercising its rights, payment to the lessor would allow AEP to step into the lessor’s rights as well as obtaining title to the assets. Under either situation, AEP would have accessthe ability to utilize the assets in the normal course of barging operations. AEP would also have the right to sell the leasedacquired assets in order to recover payments made by AEP under the guarantee.for which it obtained title. As of March 31, 2018,June 30, 2021, AEP’s boat and barge lease guarantee liability was $7$3 million, of which $2$1 million was recorded in Other Current Liabilities and $5$2 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheet.sheets.


In January 2018, S&P Global Inc. downgraded the ratings ofFebruary 2020, the nonaffiliated party filed Chapter 11 bankruptcy. The party entered into a restructuring support agreement and sethas announced it expected to continue their outlook to negative.operations as normal. In March 2020, the bankruptcy court approved the party’s recapitalization plan. In April 2018, Moody’s Investors Service Inc. also downgraded their ratings and set their outlook to negative. It2020, the nonaffiliated party emerged from bankruptcy. Management has determined that it is reasonably possible that enforcement of AEP’s liability for future payments under these leases couldwill be exercised whichwithin the next twelve months. In such an event, if AEP is unable to sell or incorporate any of the acquired assets into its fleet operations, it could reduce future net income and cash flows and impact financial condition.


ENVIRONMENTAL CONTINGENCIES (Applies to all Registrants except AEPTCo)


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


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



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NUCLEAR CONTINGENCIES (Applies to AEP and I&M)


I&M owns and operates the two-unit 2,278 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission.  I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant.  The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037.  The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements.  By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.


Westinghouse Electric Company Bankruptcy Filing

In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the U.S. Bankruptcy Code. Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuel fabrication and ongoing engineering projects.  The most significant of these relate to Cook Plant fuel fabrication.  As part of the reorganization, the bankruptcy court approved Westinghouse’s sale of its nuclear business to Brookfield WEC Holdings, a nonaffiliated third party. Pursuant to the sale, Brookfield will assume all of I&M’s contracts with Westinghouse. The sale is subject to regulatory approvals and is expected to close in the third quarter of 2018.

OPERATIONAL CONTINGENCIES


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


In July 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 willwould 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 further allege that the defendants’ actions constitute breach of the lease and participation agreement.  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.  In October 2013, a motion to dismiss the case was filed on behalf of

AEGCo and I&M.

In January 2015,&M sought and were granted dismissal by the court issued an opinion and order grantingU.S. District Court for the motion in part and denying the motion in part. The court dismissedSouthern District of Ohio of certain of the plaintiffs’ claims, including the dismissal without prejudice of plaintiffs’ claims seeking compensatory damages. Several claims remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. In November 2015, AEGCo and I&M filed a motion to strike the plaintiffs’ motion for partial judgment and filed a motion to dismiss the case for failure to state a claim.

In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for compensatory damages, breach of contract, and dismissing claims for breach of the implied covenant of good faith and fair dealing and further dismissing plaintiffs’ claim for indemnification of costs. ByPlaintiffs voluntarily dismissed the same order, the court permitted plaintiffs to move forward with their claimsurviving claims that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice, and the court subsequently enteredissued a final judgment. In May 2016,The plaintiffs subsequently filed an appeal in the U.S. Court of Appeals for the Sixth Circuit on whether AEGCo and I&M are in breach of certain contract provisions that plaintiffs allege operate to protect the plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing.Circuit.



In April 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion reversing the district court’s decisions which had dismissed certain of plaintiffs’ claims for breach of contract and remanding the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. In April 2017, AEGCo and I&M filed a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit, which was granted. In June 2017, the U.S. Court of Appeals for the Sixth Circuit issued an amended opinion and judgment which reverses the district court’s dismissal of certain of the owners’ claims under the lease agreements, vacates the denial of the owners’ motion for partial summary judgment and remands the case to the district court for further proceedings.  The amended opinion and judgment also affirmsaffirming the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims, and removes the instruction toreversing the district court in the original opinion to enter summary judgment in favorcourt’s dismissal of the owners.breach of contract claims and remanding the case for further proceedings.


In July 2017,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 to eliminate the obligation to install certain future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that Unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. In November 2017, theThe 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, 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.


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, in May 2021, at the parties request, the district court entered a stipulation and order dismissing the case without prejudice to plaintiffs asserting their claims in a re-filed action or a new action. The 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.
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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.  Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, managementManagement is unable to determine a range of potential losses that areis reasonably possible of occurring.


Gavin Landfill Litigation (AppliesRelated to Ohio House Bill 6 (HB 6)

In 2019, Ohio adopted and implemented HB 6 which benefits OPCo by authorizing rate recovery for certain costs including renewable energy contracts and OVEC’s coal-fired generating units. OPCo engaged in lobbying efforts and provided testimony during the legislative process in connection with HB 6. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of an Ohio legislator and associates in connection with an alleged racketeering conspiracy involving the adoption of HB 6. After AEP learned of the criminal allegations against the Ohio legislator and OPCo)others relating to HB 6, the Company, with assistance from outside advisors, conducted a review of the circumstances surrounding the passage of the bill. We do not believe that AEP was involved in any wrongful conduct in connection with the passage of HB 6.


In August 2014,2020, an AEP shareholder filed a complaint was filedputative class action lawsuit in the Mason County, West Virginia CircuitUnited States District Court for the Southern District of Ohio against AEP AEPSC, OPCo and an individual supervisor alleging wrongful deathcertain 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 personal injury/illness claims arising out(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 purported exposure to coal combustion by-product waste atrelief. On May 10, 2021, the Gavin Plant landfill.  As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint became the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors.  Twelve of the family members pursued personal injury/illness claims (non-working direct claims) and the remainder pursued loss of consortium claims.  The plaintiffs sought compensatory and punitive damages, as well as medical monitoring.  In September 2014, defendants filed a motion to dismiss the complaint, contendingsecurities litigation for failure to state a claim, and under the case shouldCourt’s briefing schedule the motion will be fully briefed by July 26, 2021. 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 August 2015,April 2021, a third AEP shareholder filed a similar derivative action in the court deniedU.S. District Court for the motion. Defendants appealed that decisionSouthern District of Ohio and a fourth AEP shareholder filed a similar derivative action in the Supreme Court for the State of New York, Nassau County. These derivative complaints allege the officers and directors made misrepresentations and omissions similar to those alleged in the West Virginia Supreme Court. In February 2016, a decision was issued byputative 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 court denyingSecurities Exchange Act of 1934; and seek monetary damages and changes to AEP’s corporate governance and internal policies among other forms of relief. The first three derivative actions have been stayed pending the appeal and remandingresolution of the case to the West Virginia Mass Litigation Panel (WVMLP), rather than back to the Mason County, West Virginia Circuit Court. Defendants subsequently filed a motion to dismiss the twelve non-working directsecurities litigation. The fourth has been stayed until such time as the court determines to lift the stay. 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.

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
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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 under Ohio law.and take appropriate disciplinary action against those individuals who allegedly harmed the company. The WVMLP deniedshareholder that sent the letter has agreed that AEP and the AEP Board may defer consideration of the litigation demand until the resolution of the motion and defendants again appealedto dismiss the securities litigation. The AEP Board will act in response to the West Virginia Supreme Court. letter as appropriate. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

In June 2017,May 2021, AEP received a subpoena from the West Virginia Supreme Court reversedSEC’s Division of Enforcement seeking various documents, including documents relating to the WVMLP decisionbenefits to AEP from the passage of HB 6 and dismisseddocuments relating to AEP’s financial processes and controls. AEP is cooperating fully with the claimsSEC’s subpoena. Although we cannot predict the outcome of the twelve non-working direct claim plaintiffs. In April 2018,SEC’s investigation, we do not believe the results of this inquiry will have a settlement in principle was reached. This settlement, once finalized, will be subject to court approval. Management believes the provision recorded for this case is adequate.

material impact on our financial condition, results of operations, or cash flows.

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6. DISPOSITIONSACQUISITIONS AND IMPAIRMENTSDISPOSITIONS


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


DISPOSITIONSACQUISITIONS


Zimmer PlantDry Lake Solar Project (Generation & Marketing Segment)


In February 2017, AEP signed an agreement to sell its 25.4% ownership share of Zimmer Plant to a nonaffiliated party.  The transaction closed in the second quarter of 2017 and did not have a material impact on net income, cash flows or financial condition.  The Income before Income Tax Expense and Equity Earnings of Zimmer Plant was immaterial for the three months ended March 31, 2017.

Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)

In September 2016,November 2020, AEP signed a Purchase and Sale Agreement with a nonaffiliate to sell AGR’s Gavin, Waterfordacquire a 75% interest in the 100 MW Dry Lake Solar Project (Dry Lake) located in southern Nevada for approximately $114 million. In March 2021, AEP closed the transaction and Darby Plantsthe solar project was placed in-service in May 2021. Approximately $103 million of the purchase price was paid upon closing of the transaction and the remaining $11 million was paid when the project was placed in-service. In accordance with the accounting guidance for “Business Combinations,” management determined that the acquisition of Dry Lake represents an asset acquisition. Additionally, and in accordance with the accounting guidance for “Consolidation,” management concluded that Dry Lake is a VIE and that AEP is the primary beneficiary based on its power as well as AEGCo’s Lawrenceburg Plant totaling 5,329 MWsmanaging member to direct the activities that most significantly impact Dry Lake’s economic performance. As the primary beneficiary of competitive generation assetsDry Lake, AEP consolidates Dry Lake into its financial statements. As a result, to a nonaffiliated party. The sale closed in January 2017account for $2.2 billion, which was recorded in Investing Activitiesthe initial consolidation of Dry Lake, management applied the acquisition method by allocating the purchase price based on the statementrelative fair value of cash flows.the assets acquired and noncontrolling interest assumed.  The net proceeds fromfair value of the primary assets acquired and the noncontrolling interest assumed was determined using the market approach.  The key input assumptions were the transaction were $1.2 billionprice paid for AEP’s interest in cash after taxes, repayment of debt associated with these assets including a make whole payment relatedDry Lake and recent third-party market transactions for similar solar generation facilities. The nonaffiliated interest in Dry Lake is presented in Noncontrolling Interests on the balance sheets. Subsequent to the debt, payment of a coal contract associated with oneclose of the plantstransaction, the noncontrolling interest made additional asset contributions of $14 million. As of June 30, 2021, AEP recognized approximately $146 million of Property, Plant and transaction fees. The sale resulted in a pretax gainEquipment and approximately $33 million of $227 million that was recorded in GainNoncontrolling Interest on Sale of Merchant Generation Assets on AEP’s statement of income for the three months ended March 31, 2017.balance sheets.


IMPAIRMENTS

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


In 2020, PSO and SWEPCo received regulatory approvals to acquire the North Central Wind Energy Facilities (NCWF), comprised of three Oklahoma wind facilities totaling 1,485 MWs, on a fixed cost turn-key basis at completion. PSO and SWEPCo will own undivided interests of 45.5% and 54.5% of the NCWF, respectively. In total, the three wind facilities will cost approximately $2 billion and consist of Traverse (999 MW), Maverick (287 MW) and Sundance (199 MW). Output from the NCWF will serve retail load in PSO’s Oklahoma service territory and both retail and FERC wholesale load in SWEPCo’s service territories in Arkansas and Louisiana. The Oklahoma and Louisiana portions of the NCWF revenue requirement, net of PTC benefit, are recoverable through authorized riders beginning at commercial operation and until such time as amounts are reflected in base rates. The mechanism to recover the Arkansas portion of the NCWF revenue requirement will be addressed in a future regulatory proceeding. The NCWF are subject to various regulatory performance requirements. If these performance requirements are not met, PSO and SWEPCo would recognize a regulatory liability to refund retail customers.

In April 2021, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Sundance during its development and construction for $270 million, the first quarter of 2018,the three NCWF acquisitions. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Sundance assets in proportion to their undivided ownership interests. Sundance was placed in-service in April 2021. The total investment in Sundance is estimated to be $291 million inclusive of previously capitalized pre-construction costs.

In accordance with the guidance for “Business Combinations,” management determined that the acquisition of Sundance represents an asset acquisition. The initial consolidation of Sundance and subsequent distribution of its assets resulted in the recognition and initial measurement of acquisition costs of $123 million and $147 million in
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Property, Plant and Equipment on the balance sheets of PSO and SWEPCo, respectively.  On an ongoing basis, management further determined that PSO and SWEPCo should apply the joint plant accounting model to account for their respective undivided interests in the assets, liabilities, revenues and expenses of Sundance.

The Purchase and Sale Agreement (PSA) includes collective interests in numerous land contracts, as originally executed between the nonaffiliated party and the respective owners of the properties as defined in the contracts. These contracts provide for easement and access rights to the land that Sundance was built upon. These interests as lessee in each of the land contracts were transferred to Sundance (and subsequently to PSO and SWEPCo) as a part of the closing of the PSA. As of June 30, 2021, the Noncurrent Obligations Under Operating Leases are $13 million and $15 million on the balance sheets for PSO and SWEPCo, respectively.

DISPOSITIONS

Conesville Plant (Generation & Marketing Segment)

In June 2020, AEP was notified byand a nonaffiliated joint-owner executed an equity investee that it had ceased operations.Environmental Liability and Property Transfer and Asset Purchase Agreement with a nonaffiliated third-party related to the merchant Conesville Plant site. The purchaser took ownership of the assets and assumed responsibility for environmental liabilities, including ash pond closure, asbestos abatement and decommissioning and demolition of the Conesville Plant site. In consideration of the transfer of the acquired assets to the purchaser and the purchaser’s assumption of liabilities, AEP will pay a total of approximately $98 million over three years, derecognized $106 million in ARO and recorded a pretax impairment of $21 millionan immaterial gain on the transaction which is recorded in Other Operation on the statementstatements of income related to the equity investmentincome. AEP paid approximately $26 million at closing in June 2020 and related assets. The impairment also had an immaterial impact to APCo.

Merchant Generating Assets (Generation & Marketing Segment)

In the first quarter of 2017, AEP recorded a pretax impairment of $4made additional payments totaling $28 million in Other Operation on the statement of income relatedquarterly installments from October 2020 to the Merchant Coal-fired Generation Assets. In addition,April 2021. AEP recorded a $7will make additional payments totaling $44 million pretax impairment in Other Operation on the statement of income relatedquarterly installments from July 2021 to the sale of Zimmer Plant.

July 2022.

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7.  BENEFIT PLANS


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


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


Components of Net Periodic Benefit Cost


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


AEP
Pension PlansOPEB
Three Months Ended June 30,Three Months Ended June 30,
 2021202020212020
 (in millions)
Service Cost$32.3 $28.0 $2.4 $2.5 
Interest Cost34.3 41.9 7.6 10.0 
Expected Return on Plan Assets(57.4)(66.2)(22.8)(24.0)
Amortization of Prior Service Credit0 0 (17.7)(17.5)
Amortization of Net Actuarial Loss25.4 23.4 0 1.5 
Net Periodic Benefit Cost (Credit)$34.6 $27.1 $(30.5)$(27.5)
Pension PlansOPEB
Six Months Ended June 30,Six Months Ended June 30,
 2021202020212020
 (in millions)
Service Cost$64.6 $56.0 $4.8 $5.0 
Interest Cost68.6 83.9 15.2 19.9 
Expected Return on Plan Assets(114.9)(132.4)(45.6)(47.9)
Amortization of Prior Service Credit0 0 (35.4)(34.9)
Amortization of Net Actuarial Loss50.8 46.8 0 3.0 
Net Periodic Benefit Cost (Credit)$69.1 $54.3 $(61.0)$(54.9)


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 Pension Plans OPEB
 Three Months Ended March 31, Three Months Ended March 31,
 2018 2017 2018 2017
 (in millions)
Service Cost$24.4
 $24.1
 $2.9
 $2.8
Interest Cost46.9
 50.8
 11.8
 14.8
Expected Return on Plan Assets(72.5) (71.2) (25.5) (25.3)
Amortization of Prior Service Cost (Credit)—
 0.3
 (17.3) (17.3)
Amortization of Net Actuarial Loss21.3
 20.7
 2.6
 9.2
Net Periodic Benefit Cost (Credit)$20.1
 $24.7
 $(25.5) $(15.8)





AEP Texas
Pension PlansOPEB
Three Months Ended June 30,Three Months Ended June 30,
 2021202020212020
 (in millions)
Service Cost$2.9 $2.4 $0.1 $0.2 
Interest Cost2.8 3.5 0.6 0.8 
Expected Return on Plan Assets(4.8)(5.7)(1.8)(2.0)
Amortization of Prior Service Credit0 0 (1.5)(1.6)
Amortization of Net Actuarial Loss2.0 2.0 0 0.2 
Net Periodic Benefit Cost (Credit)$2.9 $2.2 $(2.6)$(2.4)
Pension PlansOPEB
Six Months Ended June 30,Six Months Ended June 30,
 2021202020212020
 (in millions)
Service Cost$5.9 $5.0 $0.3 $0.4 
Interest Cost5.6 7.0 1.2 1.6 
Expected Return on Plan Assets(9.7)(11.4)(3.7)(4.0)
Amortization of Prior Service Credit0 0 (3.0)(3.0)
Amortization of Net Actuarial Loss4.1 3.9 0 0.3 
Net Periodic Benefit Cost (Credit)$5.9 $4.5 $(5.2)$(4.7)
 Pension Plans OPEB
 Three Months Ended March 31, Three Months Ended March 31,
 2018 2017 2018 2017
 (in millions)
Service Cost$2.3
 $2.1
 $0.3
 $0.2
Interest Cost4.0
 4.3
 0.9
 1.2
Expected Return on Plan Assets(6.4) (6.3) (2.1) (2.2)
Amortization of Prior Service Credit—
 —
 (1.5) (1.4)
Amortization of Net Actuarial Loss1.8
 1.8
 0.2
 0.8
Net Periodic Benefit Cost (Credit)$1.7
 $1.9
 $(2.2) $(1.4)


APCo
Pension PlansOPEB
Three Months Ended June 30,Three Months Ended June 30,
 2021202020212020
 (in millions)
Service Cost$2.9 $2.6 $0.2 $0.2 
Interest Cost4.1 5.1 1.2 1.7 
Expected Return on Plan Assets(7.2)(8.4)(3.3)(3.7)
Amortization of Prior Service Credit0 0 (2.6)(2.6)
Amortization of Net Actuarial Loss3.0 2.8 0 0.3 
Net Periodic Benefit Cost (Credit)$2.8 $2.1 $(4.5)$(4.1)
Pension PlansOPEB
Six Months Ended June 30,Six Months Ended June 30,
 2021202020212020
 (in millions)
Service Cost$5.9 $5.2 $0.5 $0.5 
Interest Cost8.2 10.2 2.4 3.3 
Expected Return on Plan Assets(14.5)(16.8)(6.7)(7.3)
Amortization of Prior Service Credit0 0 (5.2)(5.1)
Amortization of Net Actuarial Loss6.0 5.6 0 0.5 
Net Periodic Benefit Cost (Credit)$5.6 $4.2 $(9.0)$(8.1)
176
 Pension Plans OPEB
 Three Months Ended March 31, Three Months Ended March 31,
 2018
2017 2018 2017
 (in millions)
Service Cost$2.3
 $2.3
 $0.3
 $0.3
Interest Cost5.9
 6.4
 2.0
 2.6
Expected Return on Plan Assets(9.1) (8.9) (4.0) (4.1)
Amortization of Prior Service Cost (Credit)—
 0.1
 (2.5) (2.5)
Amortization of Net Actuarial Loss2.6
 2.6
 0.5
 1.6
Net Periodic Benefit Cost (Credit)$1.7
 $2.5
 $(3.7) $(2.1)







I&M
Pension PlansOPEB
Three Months Ended June 30,Three Months Ended June 30,
 2021202020212020
 (in millions)
Service Cost$4.3 $3.8 $0.3 $0.4 
Interest Cost4.1 4.9 0.9 1.1 
Expected Return on Plan Assets(7.2)(8.3)(2.8)(2.9)
Amortization of Prior Service Credit0 0 (2.4)(2.4)
Amortization of Net Actuarial Loss3.0 2.7 0 0.2 
Net Periodic Benefit Cost (Credit)$4.2 $3.1 $(4.0)$(3.6)
Pension PlansOPEB
Six Months Ended June 30,Six Months Ended June 30,
 2021202020212020
 (in millions)
Service Cost$8.7 $7.7 $0.6 $0.7 
Interest Cost8.1 9.8 1.8 2.3 
Expected Return on Plan Assets(14.4)(16.6)(5.6)(5.8)
Amortization of Prior Service Credit0 0 (4.8)(4.8)
Amortization of Net Actuarial Loss5.9 5.4 0 0.4 
Net Periodic Benefit Cost (Credit)$8.3 $6.3 $(8.0)$(7.2)
 Pension Plans OPEB
 Three Months Ended March 31, Three Months Ended March 31,
 2018 2017 2018 2017
 (in millions)
Service Cost$3.4
 $3.5
 $0.4
 $0.4
Interest Cost5.5
 6.1
 1.4
 1.7
Expected Return on Plan Assets(8.9) (8.6) (3.1) (3.1)
Amortization of Prior Service Credit—
 —
 (2.4) (2.3)
Amortization of Net Actuarial Loss2.5
 2.4
 0.3
 1.1
Net Periodic Benefit Cost (Credit)$2.5
 $3.4
 $(3.4) $(2.2)


OPCo
Pension PlansOPEB
Three Months Ended June 30,Three Months Ended June 30,
 2021202020212020
 (in millions)
Service Cost$2.8 $2.4 $0.2 $0.3 
Interest Cost3.1 3.8 0.8 1.1 
Expected Return on Plan Assets(5.5)(6.5)(2.5)(2.7)
Amortization of Prior Service Credit0 0 (1.8)(1.7)
Amortization of Net Actuarial Loss2.3 2.2 0 0.1 
Net Periodic Benefit Cost (Credit)$2.7 $1.9 $(3.3)$(2.9)
Pension PlansOPEB
Six Months Ended June 30,Six Months Ended June 30,
 2021202020212020
 (in millions)
Service Cost$5.7 $4.8 $0.4 $0.5 
Interest Cost6.2 7.7 1.6 2.1 
Expected Return on Plan Assets(11.1)(13.1)(4.9)(5.3)
Amortization of Prior Service Credit0 0 (3.6)(3.5)
Amortization of Net Actuarial Loss4.5 4.3 0 0.3 
Net Periodic Benefit Cost (Credit)$5.3 $3.7 $(6.5)$(5.9)


177
 Pension Plans OPEB
 Three Months Ended March 31, Three Months Ended March 31,
 2018 2017 2018 2017
 (in millions)
Service Cost$2.0
 $1.9
 $0.2
 $0.2
Interest Cost4.4
 4.8
 1.3
 1.7
Expected Return on Plan Assets(7.2) (7.0) (3.0) (3.0)
Amortization of Prior Service Credit—
 —
 (1.7) (1.7)
Amortization of Net Actuarial Loss2.0
 2.0
 0.3
 1.1
Net Periodic Benefit Cost (Credit)$1.2
 $1.7
 $(2.9) $(1.7)





PSO
Pension PlansOPEB
Three Months Ended June 30,Three Months Ended June 30,
 2021202020212020
 (in millions)
Service Cost$2.1 $1.8 $0.1 $0.1 
Interest Cost1.6 2.2 0.4 0.5 
Expected Return on Plan Assets(3.1)(3.7)(1.2)(1.3)
Amortization of Prior Service Credit0 0 (1.1)(1.1)
Amortization of Net Actuarial Loss1.2 1.2 0 0.1 
Net Periodic Benefit Cost (Credit)$1.8 $1.5 $(1.8)$(1.7)
Pension PlansOPEB
Six Months Ended June 30,Six Months Ended June 30,
 2021202020212020
 (in millions)
Service Cost$4.0 $3.6 $0.3 $0.3 
Interest Cost3.3 4.3 0.8 1.0 
Expected Return on Plan Assets(6.2)(7.3)(2.5)(2.6)
Amortization of Prior Service Credit0 0 (2.2)(2.2)
Amortization of Net Actuarial Loss2.5 2.4 0 0.2 
Net Periodic Benefit Cost (Credit)$3.6 $3.0 $(3.6)$(3.3)
 Pension Plans OPEB
 Three Months Ended March 31, Three Months Ended March 31,
 2018 2017 2018 2017
 (in millions)
Service Cost$1.8
 $1.6
 $0.2
 $0.2
Interest Cost2.4
 2.7
 0.6
 0.8
Expected Return on Plan Assets(4.0) (3.9) (1.4) (1.4)
Amortization of Prior Service Credit—
 —
 (1.0) (1.1)
Amortization of Net Actuarial Loss1.1
 1.1
 0.1
 0.5
Net Periodic Benefit Cost (Credit)$1.3
 $1.5
 $(1.5) $(1.0)


SWEPCo
Pension PlansOPEB
Three Months Ended June 30,Three Months Ended June 30,
 2021202020212020
 (in millions)
Service Cost$2.8 $2.4 $0.2 $0.2 
Interest Cost2.1 2.6 0.5 0.7 
Expected Return on Plan Assets(3.4)(3.9)(1.5)(1.7)
Amortization of Prior Service Credit0 0 (1.3)(1.3)
Amortization of Net Actuarial Loss1.6 1.4 0 0.1 
Net Periodic Benefit Cost (Credit)$3.1 $2.5 $(2.1)$(2.0)
Pension PlansOPEB
Six Months Ended June 30,Six Months Ended June 30,
 2021202020212020
 (in millions)
Service Cost$5.7 $4.9 $0.3 $0.4 
Interest Cost4.2 5.1 1.0 1.3 
Expected Return on Plan Assets(6.8)(7.8)(3.0)(3.2)
Amortization of Prior Service Credit0 0 (2.6)(2.6)
Amortization of Net Actuarial Loss3.1 2.8 0 0.2 
Net Periodic Benefit Cost (Credit)$6.2 $5.0 $(4.3)$(3.9)
178
 Pension Plans OPEB
 Three Months Ended March 31, Three Months Ended March 31,
 2018 2017 2018 2017
 (in millions)
Service Cost$2.3
 $2.2
 $0.3
 $0.2
Interest Cost2.9
 3.1
 0.7
 0.9
Expected Return on Plan Assets(4.4) (4.2) (1.6) (1.6)
Amortization of Prior Service Credit—
 —
 (1.3) (1.3)
Amortization of Net Actuarial Loss1.3
 1.2
 0.1
 0.6
Net Periodic Benefit Cost (Credit)$2.1
 $2.3
 $(1.8) $(1.2)







8.  BUSINESS SEGMENTS


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


AEP’s Reportable Segments


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


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


Vertically Integrated Utilities


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


Transmission and Distribution Utilities


•Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo.
•OPCo purchases energy and capacity to serve SSOstandard 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 returns on equity.ROEs.
•Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity.ROEs.


Generation & Marketing


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


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

179





The tables below present AEP’s reportable segment income statement information for the three and six months ended March 31, 2018June 30, 2021 and 20172020 and reportable segment balance sheet information as of March 31, 2018June 30, 2021 and December 31, 2017.2020.
Three Months Ended June 30, 2021
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing		Corporate and Other (a)Reconciling AdjustmentsConsolidated
 (in millions)
Revenues from:      
External Customers$2,224.6 $1,089.6 $86.4 $422.5 $3.4 $0 $3,826.5 
Other Operating Segments36.0 13.8 291.8 14.1 12.1 (367.8)0 
Total Revenues$2,260.6 $1,103.4 $378.2 $436.6 $15.5 $(367.8)$3,826.5 
Net Income (Loss)$228.8 $153.7 $169.6 $46.5 $(24.8)$0 $573.8 
Three Months Ended June 30, 2020
 Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing		Corporate and Other (a)Reconciling AdjustmentsConsolidated
 (in millions)
Revenues from:      
External Customers$2,062.3 $1,009.4 $69.2 $350.2 $2.9 $0 $3,494.0 
Other Operating Segments29.7 25.1 180.5 26.7 16.6 (278.6)0 
Total Revenues$2,092.0 $1,034.5 $249.7 $376.9 $19.5 $(278.6)$3,494.0 
Net Income (Loss)$256.3 $139.5 $92.2 $58.5 $(32.0)$0 $514.5 
Six Months Ended June 30, 2021
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing		Corporate and Other (a)Reconciling AdjustmentsConsolidated
(in millions)
Revenues from:
External Customers$4,729.1 $2,171.9 $174.3 $1,024.2 $8.1 $0 $8,107.6 
Other Operating Segments68.8 19.6 580.9 46.6 20.3 (736.2)0 
Total Revenues$4,797.9 $2,191.5 $755.2 $1,070.8 $28.4 $(736.2)$8,107.6 
Net Income (Loss)$500.2 $268.1 $342.8 $84.7 $(43.2)$0 $1,152.6 
Six Months Ended June 30, 2020
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing		Corporate and Other (a)Reconciling AdjustmentsConsolidated
(in millions)
Revenues from:
External Customers$4,255.3 $2,084.6 $142.3 $758.6 $0.7 $0 $7,241.5 
Other Operating Segments63.4 56.8 417.6 56.9 38.7 (633.4)0 
Total Revenues$4,318.7 $2,141.4 $559.9 $815.5 $39.4 $(633.4)$7,241.5 
Net Income (Loss)$502.6 $255.7 $233.8 $89.0 $(67.3)$0 $1,013.8 
180




 Three Months Ended March 31, 2018
 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing		 Corporate and Other (a) Reconciling Adjustments Consolidated
 (in millions)
Revenues from: 
  
  
  
  
    
External Customers$2,381.5
 $1,141.2
 $41.1
 $477.5
 $7.0
 $—
 $4,048.3
Other Operating Segments26.5
 21.2
 164.4
 27.6
 17.0
 (256.7) —
Total Revenues$2,408.0
 $1,162.4
 $205.5
 $505.1
 $24.0
 $(256.7) $4,048.3
              
Net Income (Loss)$232.8
 $125.4
 $104.8
 $18.1
 $(24.4) $—
 $456.7
              
 Three Months Ended March 31, 2017
 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing		 Corporate and Other (a) Reconciling Adjustments Consolidated
 (in millions)
Revenues from: 
 ��
  
  
  
    
External Customers$2,269.8
 $1,066.4
 $27.7
 $558.8
 $10.6
 $—
 $3,933.3
Other Operating Segments20.6
 20.0
 128.4
 32.6
 15.9
 (217.5) —
Total Revenues$2,290.4
 $1,086.4
 $156.1
 $591.4
 $26.5
 $(217.5) $3,933.3
              
Net Income (Loss)$220.5
 $119.1
 $72.8
 $186.2
 $(4.4) $—
 $594.2




June 30, 2021
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing		Corporate and Other (a)Reconciling
Adjustments		Consolidated
 (in millions)
Total Property, Plant and Equipment$50,135.7 $21,833.8 $12,551.5 $2,122.5 $412.8 $0 $87,056.3 
Accumulated Depreciation and Amortization16,293.8 4,004.9 703.1 202.7 187.3 0 21,391.8 
Total Property Plant and Equipment - Net$33,841.9 $17,828.9 $11,848.4 $1,919.8 $225.5 $0 $65,664.5 
Total Assets$45,225.0 $20,369.0 $13,231.7 $3,963.1 $5,766.8 (b)$(4,197.4)(c)$84,358.2 
Long-term Debt Due Within One Year:
Nonaffiliated$1,205.3 $789.9 $52.4 $0 $410.9 (d)$0 $2,458.5 
Long-term Debt:
Affiliated65.0 0 0 0 0 (65.0)0 
Nonaffiliated13,400.6 7,312.8 4,093.2 0 5,852.7 (d)0 30,659.3 
Total Long-term Debt$14,670.9 $8,102.7 $8,238.8 $0 $6,263.6 (d)$(65.0)$33,117.8 
December 31, 2020
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing		Corporate and Other (a)Reconciling
Adjustments		Consolidated
 (in millions)
Total Property, Plant and Equipment$49,023.3 $21,145.0 $11,827.2 $1,910.2 $407.3 $0 $84,313.0 
Accumulated Depreciation and Amortization15,586.2 3,879.3 595.7 166.1 184.1 0 20,411.4 
Total Property Plant and Equipment - Net$33,437.1 $17,265.7 $11,231.5 $1,744.1 $223.2 $0 $63,901.6 
Total Assets$42,752.7 $19,765.9 $12,627.3 $3,585.9 $5,987.1 (b)$(3,961.7)(c)$80,757.2 
Long-term Debt Due Within One Year:
Nonaffiliated$1,034.6 $588.8 $52.3 $0 $410.4 (d)$0 $2,086.1 
Long-term Debt:
Affiliated65.0 0 0 0 0 (65.0)0 
Nonaffiliated12,375.6 6,661.9 4,075.7 0 5,873.2 (d)0 28,986.4 
Total Long-term Debt$13,475.2 $7,250.7 $4,128.0 $0 $6,283.6 (d)$(65.0)$31,072.5 

(a)Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and other nonallocated costs.
(b)Includes elimination of AEP Parent’s investments in wholly-owned subsidiary companies.
(c)Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable.
(d)Amounts are inclusive of the impact of fair value hedge accounting. See “Accounting for Fair Value Hedging Strategies” section of Note 10 for additional information.


181
  March 31, 2018
  Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing		 Corporate and Other (a) Reconciling
Adjustments		 Consolidated
  (in millions)
Total Property, Plant and Equipment $43,749.8
 $16,790.4
 $7,446.6
 $786.9
 $377.7
 $(355.1)(b)$68,796.3
Accumulated Depreciation and Amortization 13,355.3
 3,809.8
 200.1
 70.1
 182.9
 (187.0)(b)17,431.2
Total Property Plant and Equipment - Net $30,394.5
 $12,980.6
 $7,246.5
 $716.8
 $194.8
 $(168.1)(b)$51,365.1
               
               
Total Assets $37,913.3
 $16,272.6
 $8,340.5
 $2,123.7
 $4,552.9
(c)$(3,593.5)(b) (d)$65,609.5
               
Long-term Debt Due Within One Year:              
Nonaffiliated $1,893.7
 $670.6
 $50.0
 $0.1
 $1.7
 $—
 $2,616.1
               
Long-term Debt:              
Affiliated 50.0
 —
 —
 32.2
 —
 (82.2) —
Nonaffiliated 9,969.2
 4,972.4
 2,635.0
 (0.3) 1,268.6
 —
 18,844.9
               
Total Long-term Debt $11,912.9
 $5,643.0
 $2,685.0
 $32.0
 $1,270.3
 $(82.2) $21,461.0
               
  December 31, 2017
  Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing		 Corporate and Other (a) Reconciling
Adjustments		 Consolidated
  (in millions)
Total Property, Plant and Equipment $43,294.4
 $16,371.2
 $7,110.2
 $644.6
 $374.5
 $(366.4)(b)$67,428.5
Accumulated Depreciation and Amortization 13,153.4
 3,768.3
 176.6
 75.0
 180.6
 (186.9)(b)17,167.0
Total Property Plant and Equipment - Net $30,141.0
 $12,602.9
 $6,933.6
 $569.6
 $193.9
 $(179.5)(b)$50,261.5
               
Total Assets $37,579.7
 $16,060.7
 $8,141.8
 $2,009.8
 $3,959.1
(c)$(3,022.0)(b) (d)$64,729.1
               
Long-term Debt Due Within One Year:              
Nonaffiliated $1,038.1
 $663.1
 $50.0
 $—
 $2.5
 $—
 $1,753.7
               
Long-term Debt:              
Affiliated 50.0
 —
 —
 32.2
 —
 (82.2) —
Nonaffiliated 10,801.4
 4,705.4
 2,631.3
 (0.3) 1,281.8
 —
 19,419.6
               
Total Long-term Debt $11,889.5
 $5,368.5
 $2,681.3
 $31.9
 $1,284.3
 $(82.2) $21,173.3
               


(a)Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
(b)Includes eliminations due to an intercompany capital lease.
(c)Includes elimination of AEP Parent’s investments in wholly-owned subsidiary companies.
(d)Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable.






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


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


AEPTCo’s Reportable Segments


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


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


The tables below present AEPTCo’s reportable segment income statement information for the three and six months ended March 31, 2018June 30, 2021 and 20172020 and reportable segment balance sheet information as of March 31, 2018June 30, 2021 and December 31, 2017.2020.
Three Months Ended June 30, 2021
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Revenues from:
External Customers$84.1 $0 $0 $84.1 
Sales to AEP Affiliates281.4 0 0 281.4 
Total Revenues$365.5 $0 $0 $365.5 
Interest Income$0 $38.4 $(38.3)(a)$0.1 
Interest Expense34.3 38.2 (38.2)(a)34.3 
Income Tax Expense39.1 0 0 39.1 
Net Income$148.5 $0.1 (b)$0 $148.6 
Three Months Ended June 30, 2020
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Revenues from:
External Customers$60.4 $0 $0 $60.4 
Sales to AEP Affiliates177.7 0 0 177.7 
Total Revenues$238.1 $0 $0 $238.1 
Interest Income$0.7 $38.9 $(38.3)(a)$1.3 
Interest Expense32.8 38.3 (38.3)(a)32.8 
Income Tax Expense19.2 0.1 0 19.3 
Net Income$73.2 $0.5 (b)$0 $73.7 
182




Three Months Ended March 31, 2018Six Months Ended June 30, 2021
State Transcos AEPTCo Parent Reconciling Adjustments 
AEPTCo
Consolidated
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo Consolidated
(in millions)(in millions)
Revenues from:       Revenues from:
External Customers$31.3
 $—
 $—
 $31.3
External Customers$160.1 $0 $0 $160.1 
Sales to AEP Affiliates162.1
 —
 —
 162.1
Sales to AEP Affiliates567.00 0 567.0 
Other Revenues0.1
 —
 —
 0.1
Other Revenues0.1 0 0 0.1 
Total Revenues$193.5
 $—
 $—
 $193.5
Total Revenues$727.2 $0 $0 $727.2 
       
Interest Income$0.2
 $25.0
 $(24.8)(a)$0.4
Interest Income$0 $76.7 $(76.5)(a)$0.2 
Interest Expense19.9
 24.8
 (24.8)(a)19.9
Interest Expense68.4 76.4 (76.4)(a)68.4 
Income Tax Expense22.3
 0.2
 —
 22.5
Income Tax Expense78.7 0 0 78.7 
       
Net Income (Loss)$86.0
 $(0.1)(b)$—
 $85.9
Net IncomeNet Income$300.2 $0.1 (b)$0 $300.3 
Six Months Ended June 30, 2020
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo Consolidated
(in millions)
Revenues from:Revenues from:
External CustomersExternal Customers$121.7 $0 $0 $121.7 
Sales to AEP AffiliatesSales to AEP Affiliates411.40 0 411.4 
Other RevenuesOther Revenues0.6 0 0 0.6 
Total RevenuesTotal Revenues$533.7 $0 $0 $533.7 
Interest IncomeInterest Income$0.9 $72.9 $(71.7)(a)$2.1 
Interest ExpenseInterest Expense62.471.7(71.7)(a)62.4
Income Tax ExpenseIncome Tax Expense51.0 0.1 0 51.1 
Net IncomeNet Income$190.5 $1.0 (b)$0 $191.5 
June 30, 2021
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Total Transmission Property$12,053.6 $0 $0 $12,053.6 
Accumulated Depreciation and Amortization677.1 0 0 677.1 
Total Transmission Property – Net$11,376.5 $0 $0 $11,376.5 
Notes Receivable - Affiliated$0 $3,899.3 $(3,899.3)(c)$0 
Total Assets$11,730.6 $4,083.6 (d)$(4,023.9)(e)$11,790.3 
Total Long-term Debt$3,990.0 $3,949.3 $(3,990.0)(c)$3,949.3 
December 31, 2020
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Total Transmission Property$11,345.6 $0 $0 $11,345.6 
Accumulated Depreciation and Amortization572.8 0 0 572.8 
Total Transmission Property – Net$10,772.8 $0 $0 $10,772.8 
Notes Receivable - Affiliated$0 $3,948.5 $(3,948.5)(c)$0 
Total Assets$11,185.1 $4,084.0 (d)$(4,023.1)(e)$11,246.0 
Total Long-term Debt$3,990.0 $3,948.5 $(3,990.0)(c)$3,948.5 

(a)Elimination of intercompany interest income/interest expense on affiliated debt arrangement.
(b)Includes the elimination of AEPTCo Parent’s equity earnings in the State Transcos.
(c)Elimination of intercompany debt.
(d)Includes the elimination of AEPTCo Parent’s investments in State Transcos.
(e)Primarily relates to the elimination of Notes Receivable from the State Transcos.
183
 Three Months Ended March 31, 2017
 State Transcos AEPTCo Parent Reconciling Adjustments 
AEPTCo
Consolidated
 (in millions)
Revenues from:       
External Customers$19.2
 $—
 $—
 $19.2
Sales to AEP Affiliates133.4
 —
 —
 133.4
    Other Revenues0.1
 —
 —
 0.1
Total Revenues$152.7
 $—
 $—
 $152.7
        
Interest Income$0.1
 $19.1
 $(19.0)(a)$0.2
Interest Expense15.8
 19.2
 (19.0)(a)16.0
Income Tax Expense28.4
 0.1
 —
 28.5
        
Net Income$56.8
 $0.2
(b)$—
 $57.0







 March 31, 2018
 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated
 (in millions)
Total Transmission Property$7,108.0
 $—
 $—
 $7,108.0
Accumulated Depreciation and Amortization192.7
 —
 —
 192.7
Total Transmission Property – Net$6,915.3
 $—
 $—
 $6,915.3
        
Notes Receivable - Affiliated$—
 $2,550.7
 $(2,550.7)(c)$—
        
Total Assets$7,220.0
 $2,637.3
(d)$(2,617.4)(e)$7,239.9
        
Total Long-term Debt$2,575.0
 $2,550.7
 $(2,575.0)(c)$2,550.7
 December 31, 2017
 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated
 (in millions)
Total Transmission Property$6,780.2
 $—
 $—
 $6,780.2
Accumulated Depreciation and Amortization170.4
 —
 —
 170.4
Total Transmission Property – Net$6,609.8
 $—
 $—
 $6,609.8
        
Notes Receivable - Affiliated$—
 $2,550.4
 $(2,550.4)(c)$—
        
Total Assets$7,072.9
 $2,590.1
(d)$(2,594.9)(e)$7,068.1
        
Total Long-term Debt$2,575.0
 $2,550.4
 $(2,575.0)(c)$2,550.4

(a)Elimination of intercompany interest income/interest expense on affiliated debt arrangement.
(b)Includes the elimination of AEPTCo Parent’s equity earnings in the State Transcos.
(c)Elimination of intercompany debt.
(d)Includes the elimination of AEPTCo Parent’s investments in State Transcos.
(e)Primarily relates to the elimination of Notes Receivable from the State Transcos.


9.  DERIVATIVES AND HEDGING


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


OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS


AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries.


The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets.  These risks include commodity price risks which may be subject to capacity risk, interest rate risk credit risk and foreign currency exchangecredit risk.  These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates.  Management utilizes derivative instruments to manage these risks.


STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES


Risk Management Strategies


The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.


The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors.



184




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


Notional Volume of Derivative Instruments
March 31, 2018June 30, 2021
Primary Risk
Exposure
 
Unit of
Measure
 AEP AEP Texas APCo I&M OPCo PSO SWEPCo
    (in millions)
Commodity:          
  
  
  
Power MWhs 298.4
 —
 43.2
 33.0
 8.3
 4.0
 8.1
Coal Tons 1.2
 —
 —
 1.2
 —
 —
 —
Natural Gas MMBtus 78.2
 —
 6.2
 3.7
 —
 —
 18.0
Heating Oil and Gasoline Gallons 5.0
 1.1
 1.0
 0.5
 1.2
 0.5
 0.6
Interest Rate USD $49.8
 $—
 $—
 $—
 $—
 $—
 $—
                 
Interest Rate and Foreign Currency USD $500.0
 $—
 $—
 $—
 $—
 $—
 $—

Notional Volume of Derivative Instruments
Primary Risk
Exposure		Unit of
Measure		AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Commodity:      
PowerMWhs412.5 0 77.9 32.4 2.8 26.8 7.2 
Natural GasMMBtus24.3 0 0 0 0 0 6.1 
Heating Oil and GasolineGallons9.7 2.5 1.5 0.9 1.9 1.1 1.3 
Interest RateUSD$123.6 $0 $0 $0 $0 $0 $0 
Interest Rate on Long-term DebtUSD$950.0 $0 $0 $0 $0 $0 $0 
December 31, 20172020
Primary Risk
Exposure		Unit of
Measure		AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Commodity:      
PowerMWhs331.3 0 46.9 19.7 3.0 11.9 4.0 
Natural GasMMBtus26.9 0 0 0 0 0 7.9 
Heating Oil and GasolineGallons6.9 1.8 1.1 0.6 1.4 0.7 0.9 
Interest RateUSD$129.8 $0 $0 $0 $0 $0 $0 
Interest Rate on Long-term DebtUSD$1,150.0 $0 $200.0 $0 $0 $0 $0 
Primary Risk
Exposure
 
Unit of
Measure
 AEP AEP Texas APCo I&M OPCo PSO SWEPCo
    (in millions)
Commodity:          
  
  
  
Power MWhs 358.7
 —
 57.4
 38.5
 10.4
 10.3
 22.7
Coal Tons 2.0
 —
 —
 2.0
 —
 —
 —
Natural Gas MMBtus 53.7
 —
 1.1
 0.7
 —
 —
 18.3
Heating Oil and Gasoline Gallons 6.9
 1.4
 1.3
 0.7
 1.6
 0.7
 0.8
Interest Rate USD $50.7
 $—
 $—
 $—
 $—
 $—
 $—
                 
Interest Rate and Foreign Currency USD $500.0
 $—
 $—
 $—
 $—
 $—
 $—


Fair Value Hedging Strategies (Applies to AEP)


Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate.floating-rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges.


Cash Flow Hedging Strategies


The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk.


The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure.

185

At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure.




ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS


The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes supply and demand market data andother assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality.


Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts.


According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third partythird-party contractual agreements and risk profiles. AEPThe Registrants netted cash collateral received from third parties against short-term and long-term risk management assets in the amounts of $1 million and $9.4 million as of March 31, 2018 and December 31, 2017, respectively. AEP netted cash collateral paid to third parties against short-term and long-term risk management liabilities in the amounts of $18 millionas follows:

June 30, 2021December 31, 2020
Cash CollateralCash CollateralCash CollateralCash Collateral
ReceivedPaidReceivedPaid
Netted AgainstNetted AgainstNetted AgainstNetted Against
Risk ManagementRisk ManagementRisk ManagementRisk Management
CompanyAssetsLiabilitiesAssetsLiabilities
(in millions)
AEP$105.4 $12.4 $3.4 $6.8 
APCo0.7 5.3 0.4 0 
I&M0.3 4.5 1.7 0 

Amounts for AEP Texas, OPCo, PSO and $9 millionSWEPCo are immaterial as of March 31, 2018June 30, 2021 and December 31, 2017,2020, respectively. The netted cash collateral from third parties against short-term and long-term risk management assets and netted cash collateral paid to third parties against short-term and long-term risk management liabilities were immaterial for the other Registrants as of March 31, 2018 and December 31, 2017.

186





The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets:


AEP

June 30, 2021
Risk
Management
Contracts		Hedging ContractsGross Amounts
of Risk
Management
Assets/
Liabilities
Recognized		Gross
Amounts
Offset in the
Statement of
Financial
Position (b)		Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet LocationCommodity (a)Commodity (a)Interest Rate (a)
 (in millions)
Current Risk Management Assets$441.7 $128.3 $3.2 $573.2 $(358.5)$214.7 
Long-term Risk Management Assets276.6 52.8 0 329.4 (88.1)241.3 
Total Assets718.3 181.1 3.2 902.6 (446.6)456.0 
Current Risk Management Liabilities318.2 23.4 0 341.6 (293.8)47.8 
Long-term Risk Management Liabilities229.7 18.0 28.4 276.1 (59.8)216.3 
Total Liabilities547.9 41.4 28.4 617.7 (353.6)264.1 
Total MTM Derivative Contract Net Assets (Liabilities)$170.4 $139.7 $(25.2)$284.9 $(93.0)$191.9 
Fair Value of Derivative Instruments
March 31, 2018
December 31, 2020
Risk
Management
Contracts		Hedging ContractsGross Amounts
of Risk
Management
Assets/
Liabilities
Recognized		Gross
Amounts
Offset in the
Statement of
Financial
Position (b)		Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet LocationCommodity (a)Commodity (a)Interest Rate (a)
(in millions)
Current Risk Management Assets$239.1 $21.1 $5.0 $265.2 $(170.5)$94.7 
Long-term Risk Management Assets275.9 18.0 0 293.9 (51.7)242.2 
Total Assets515.0 39.1 5.0 559.1 (222.2)336.9 
Current Risk Management Liabilities193.0 54.4 3.4 250.8 (172.0)78.8 
Long-term Risk Management Liabilities222.2 60.1 4.1 286.4 (53.6)232.8 
Total Liabilities415.2 114.5 7.5 537.2 (225.6)311.6 
Total MTM Derivative Contract Net Assets (Liabilities)$99.8 $(75.4)$(2.5)$21.9 $3.4 $25.3 

187
  
Risk
Management
Contracts
 Hedging Contracts 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a)   
  (in millions)
Current Risk Management Assets $257.0
 $20.1
 $1.7
 $278.8
 $(189.2) $89.6
Long-term Risk Management Assets 319.6
 5.1
 —
 324.7
 (53.5) 271.2
Total Assets 576.6
 25.2
 1.7
 603.5
 (242.7) 360.8
             
Current Risk Management Liabilities 246.8
 10.1
 —
 256.9
 (199.8) 57.1
Long-term Risk Management Liabilities 271.6
 48.5
 22.3
 342.4
 (59.7) 282.7
Total Liabilities 518.4
 58.6
 22.3
 599.3
 (259.5) 339.8
             
Total MTM Derivative Contract Net Assets (Liabilities) $58.2
 $(33.4) $(20.6) $4.2
 $16.8
 $21.0



Fair Value of Derivative Instruments
December 31, 2017
  
Risk
Management
Contracts
 Hedging Contracts 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a)   
  (in millions)
Current Risk Management Assets $389.0
 $17.5
 $2.5
 $409.0
 $(282.8) $126.2
Long-term Risk Management Assets 300.9
 6.3
 —
 307.2
 (25.1) 282.1
Total Assets 689.9
 23.8
 2.5
 716.2
 (307.9) 408.3
             
Current Risk Management Liabilities 334.6
 9.0
 —
 343.6
 (282.0) 61.6
Long-term Risk Management Liabilities 280.6
 58.3
 8.6
 347.5
 (25.5) 322.0
Total Liabilities 615.2
 67.3
 8.6
 691.1
 (307.5) 383.6
             
Total MTM Derivative Contract Net Assets (Liabilities) $74.7
 $(43.5) $(6.1) $25.1
 $(0.4) $24.7




AEP Texas
Fair Value of Derivative Instruments
June 30, 2021
Risk ManagementGross Amounts OffsetNet Amounts of Assets/Liabilities
Contracts –in the Statement ofPresented in the Statement of
Balance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)
(in millions)
Current Risk Management Assets$1.0 $(1.0)$0 
Long-term Risk Management Assets0.1 (0.1)0 
Total Assets1.1 (1.1)0 
Current Risk Management Liabilities0 0 0 
Long-term Risk Management Liabilities0 0 0 
Total Liabilities0 0 0 
Total MTM Derivative Contract Net Assets (Liabilities)$1.1 $(1.1)$0 
March 31, 2018
December 31, 2020
Risk ManagementGross Amounts OffsetNet Amounts of Assets/Liabilities
Contracts –in the Statement ofPresented in the Statement of
Balance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)
(in millions)
Current Risk Management Assets$0.4 $(0.4)$0 
Long-term Risk Management Assets0 0 0 
Total Assets0.4 (0.4)0 
Current Risk Management Liabilities0 0 0 
Long-term Risk Management Liabilities0 0 0 
Total Liabilities0 0 0 
Total MTM Derivative Contract Net Assets (Liabilities)$0.4 $(0.4)$0 

188




Balance Sheet Location 
Risk Management
Contracts -
Commodity (a)
 
Gross Amounts Offset in the Statement of
Financial Position (b)
 
Net Amounts of Assets/Liabilities
Presented in the Statement of
Financial Position (c)
  (in millions)
Current Risk Management Assets $0.4
 $(0.1) $0.3
Long-term Risk Management Assets —
 —
 —
Total Assets 0.4
 (0.1) 0.3
       
Current Risk Management Liabilities —
 —
 —
Long-term Risk Management Liabilities —
 —
 —
Total Liabilities —
 —
 —
       
Total MTM Derivative Contract Net Assets (Liabilities) $0.4
 $(0.1) $0.3
Fair Value of Derivative Instruments
December 31, 2017
Balance Sheet Location 
Risk Management
Contracts -
Commodity (a)
 
Gross Amounts Offset in the Statement of
Financial Position (b)
 
Net Amounts of Assets/Liabilities
Presented in the Statement of
Financial Position (c)
  (in millions)
Current Risk Management Assets $0.5
 $—
 $0.5
Long-term Risk Management Assets —
 —
 —
Total Assets 0.5
 —
 0.5
       
Current Risk Management Liabilities —
 —
 —
Long-term Risk Management Liabilities —
 —
 —
Total Liabilities —
 —
 —
       
Total MTM Derivative Contract Net Assets $0.5
 $—
 $0.5

APCo
Fair Value of Derivative Instruments
June 30, 2021
Risk ManagementGross Amounts OffsetNet Amounts of Assets/Liabilities
Contracts –in the Statement ofPresented in the Statement
Balance Sheet LocationCommodity (a)Financial Position (b)of Financial Position (c)
(in millions)
Current Risk Management Assets$64.2 $(27.1)$37.1 
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets0.1 (0.1)0 
Total Assets64.3 (27.2)37.1 
Other Current Liabilities - Current Risk Management Liabilities33.2 (31.8)1.4 
Deferred Credits and Other Noncurrent Liabilities - Long-term Risk Management Liabilities0 0 0 
Total Liabilities33.2 (31.8)1.4 
Total MTM Derivative Contract Net Assets$31.1 $4.6 $35.7 
March 31, 2018
December 31, 2020
Gross Amounts
Riskof RiskGross AmountsNet Amounts of Assets/
ManagementHedgingManagementOffset in theLiabilities Presented in
Contracts –Contracts –Assets/LiabilitiesStatement ofthe Statement of
Balance Sheet LocationCommodity (a)Interest Rate (a)RecognizedFinancial Position (b)Financial Position (c)
(in millions)
Current Risk Management Assets$38.8 $2.4 $41.2 $(18.8)$22.4 
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets0.7 0 0.7 (0.6)0.1 
Total Assets39.5 2.4 41.9 (19.4)22.5 
Other Current Liabilities - Current Risk Management Liabilities19.7 3.4 23.1 (18.5)4.6 
Deferred Credits and Other Noncurrent Liabilities - Long-term Risk Management Liabilities0.6 0 0.6 (0.5)0.1 
Total Liabilities20.3 3.4 23.7 (19.0)4.7 
Total MTM Derivative Contract Net Assets (Liabilities)$19.2 $(1.0)$18.2 $(0.4)$17.8 
189
Balance Sheet Location 
Risk Management
Contracts -
Commodity (a)
 
Gross Amounts Offset in the Statement of
Financial Position (b)
 
Net Amounts of Assets/Liabilities
Presented in the Statement of
Financial Position (c)
  (in millions)
Current Risk Management Assets $35.8
 $(27.8) $8.0
Long-term Risk Management Assets 11.2
 (8.6) 2.6
Total Assets 47.0
 (36.4) 10.6
       
Current Risk Management Liabilities 28.4
 (27.8) 0.6
Long-term Risk Management Liabilities 9.1
 (8.7) 0.4
Total Liabilities 37.5
 (36.5) 1.0
       
Total MTM Derivative Contract Net Assets $9.5
 $0.1
 $9.6


Fair Value of Derivative Instruments
December 31, 2017

Balance Sheet Location 
Risk Management
Contracts -
Commodity (a)
 
Gross Amounts Offset in the Statement of
Financial Position (b)
 
Net Amounts of Assets/Liabilities
Presented in the Statement of
Financial Position (c)
  (in millions)
Current Risk Management Assets $75.6
 $(50.7) $24.9
Long-term Risk Management Assets 2.4
 (1.3) 1.1
Total Assets 78.0
 (52.0) 26.0
       
Current Risk Management Liabilities 50.6
 (49.3) 1.3
Long-term Risk Management Liabilities 1.4
 (1.2) 0.2
Total Liabilities 52.0
 (50.5) 1.5
       
Total MTM Derivative Contract Net Assets (Liabilities) $26.0
 $(1.5) $24.5




I&M
Fair Value of Derivative Instruments
June 30, 2021
Risk ManagementGross Amounts OffsetNet Amounts of Assets/Liabilities
Contracts –in the Statement ofPresented in the Statement of
Balance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)
(in millions)
Current Risk Management Assets$25.9 $(18.2)$7.7 
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets0 0 0 
Total Assets25.9 (18.2)7.7 
Current Risk Management Liabilities23.5 (22.4)1.1 
Deferred Credits and Other Noncurrent Liabilities - Long-term Risk Management Liabilities0 0 0 
Total Liabilities23.5 (22.4)1.1 
Total MTM Derivative Contract Net Assets$2.4 $4.2 $6.6 
March 31, 2018
December 31, 2020
Risk ManagementGross Amounts OffsetNet Amounts of Assets/Liabilities
Contracts –in the Statement ofPresented in the Statement of
Balance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)
(in millions)
Current Risk Management Assets$17.2 $(13.6)$3.6 
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets0.5 (0.4)0.1 
Total Assets17.7 (14.0)3.7 
Current Risk Management Liabilities12.1 (12.0)0.1 
Deferred Credits and Other Noncurrent Liabilities - Long-term Risk Management Liabilities0.4 (0.3)0.1 
Total Liabilities12.5 (12.3)0.2 
Total MTM Derivative Contract Net Assets (Liabilities)$5.2 $(1.7)$3.5 
Balance Sheet Location 
Risk Management
Contracts -
Commodity (a)
 
Gross Amounts Offset in the Statement of
Financial Position (b)
 
Net Amounts of Assets/Liabilities
Presented in the Statement of
Financial Position (c)
  (in millions)
Current Risk Management Assets $24.0
 $(20.7) $3.3
Long-term Risk Management Assets 8.0
 (6.0) 2.0
Total Assets 32.0
 (26.7) 5.3
       
Current Risk Management Liabilities 24.6
 (20.8) 3.8
Long-term Risk Management Liabilities 6.1
 (5.9) 0.2
Total Liabilities 30.7
 (26.7) 4.0
       
Total MTM Derivative Contract Net Assets $1.3
 $—
 $1.3

Fair Value of Derivative Instruments
December 31, 2017
Balance Sheet Location 
Risk Management
Contracts -
Commodity (a)
 
Gross Amounts Offset in the Statement of
Financial Position (b)
 
Net Amounts of Assets/Liabilities
Presented in the Statement of
Financial Position (c)
  (in millions)
Current Risk Management Assets $47.2
 $(39.6) $7.6
Long-term Risk Management Assets 1.6
 (0.9) 0.7
Total Assets 48.8
 (40.5) 8.3
       
Current Risk Management Liabilities 48.5
 (45.0) 3.5
Long-term Risk Management Liabilities 0.9
 (0.8) 0.1
Total Liabilities 49.4
 (45.8) 3.6
       
Total MTM Derivative Contract Net Assets (Liabilities) $(0.6) $5.3
 $4.7

OPCo
Fair Value of Derivative Instruments
June 30, 2021
Risk ManagementGross Amounts OffsetNet Amounts of Assets/Liabilities
Contracts –in the Statement ofPresented in the Statement of
Balance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)
(in millions)
Current Risk Management Assets$0.7 $(0.7)$0 
Long-term Risk Management Assets0.1 (0.1)0 
Total Assets0.8 (0.8)0 
Current Risk Management Liabilities7.3 0 7.3 
Long-term Risk Management Liabilities98.2 0 98.2 
Total Liabilities105.5 0 105.5 
Total MTM Derivative Contract Net Liabilities$(104.7)$(0.8)$(105.5)
March 31, 2018
December 31, 2020
Risk ManagementGross Amounts OffsetNet Amounts of Assets/Liabilities
Contracts –in the Statement ofPresented in the Statement of
Balance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)
(in millions)
Current Risk Management Assets$0.3 $(0.3)$0 
Long-term Risk Management Assets0 0 0 
Total Assets0.3 (0.3)0 
Current Risk Management Liabilities8.7 0 8.7 
Long-term Risk Management Liabilities101.6 0 101.6 
Total Liabilities110.3 0 110.3 
Total MTM Derivative Contract Net Liabilities$(110.0)$(0.3)$(110.3)
190
Balance Sheet Location 
Risk Management
Contracts -
Commodity (a)
 
Gross Amounts Offset in the Statement of
Financial Position (b)
 
Net Amounts of Assets/Liabilities
Presented in the Statement of
Financial Position (c)
  (in millions)
Current Risk Management Assets $0.5
 $(0.1) $0.4
Long-term Risk Management Assets —
 —
 —
Total Assets 0.5
 (0.1) 0.4
       
Current Risk Management Liabilities 5.3
 —
 5.3
Long-term Risk Management Liabilities 93.2
 —
 93.2
Total Liabilities 98.5
 —
 98.5
       
Total MTM Derivative Contract Net Liabilities $(98.0) $(0.1) $(98.1)


Fair Value of Derivative Instruments
December 31, 2017
Balance Sheet Location 
Risk Management
Contracts -
Commodity (a)
 
Gross Amounts Offset in the Statement of
Financial Position (b)
 
Net Amounts of Assets/Liabilities
Presented in the Statement of
Financial Position (c)
  (in millions)
Current Risk Management Assets $0.6
 $—
 $0.6
Long-term Risk Management Assets —
 —
 —
Total Assets 0.6
 —
 0.6
       
Current Risk Management Liabilities 6.4
 —
 6.4
Long-term Risk Management Liabilities 126.0
 —
 126.0
Total Liabilities 132.4
 —
 132.4
       
Total MTM Derivative Contract Net Liabilities $(131.8) $—
 $(131.8)


PSO
Fair Value of Derivative Instruments
June 30, 2021
Risk ManagementGross Amounts OffsetNet Amounts of Assets/Liabilities
Contracts –in the Statement ofPresented in the Statement of
Balance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)
(in millions)
Current Risk Management Assets$23.5 $(0.5)$23.0 
Long-term Risk Management Assets0 0 0 
Total Assets23.5 (0.5)23.0 
Other Current Liabilities - Current Risk Management Liabilities0.2 (0.1)0.1 
Long-term Risk Management Liabilities0 0 0 
Total Liabilities0.2 (0.1)0.1 
Total MTM Derivative Contract Net Assets (Liabilities)$23.3 $(0.4)$22.9 
March 31, 2018

December 31, 2020
Risk ManagementGross Amounts OffsetNet Amounts of Assets/Liabilities
Contracts –in the Statement ofPresented in the Statement of
Balance Sheet Location 
Risk Management
Contracts -
Commodity (a)
 
Gross Amounts Offset in the Statement of
Financial Position (b)
 
Net Amounts of Assets/Liabilities
Presented in the Statement of
Financial Position (c)
Balance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)
 (in millions)(in millions)
Current Risk Management Assets $2.9
 $—
 $2.9
Current Risk Management Assets$10.5 $(0.2)$10.3 
Long-term Risk Management Assets —
 —
 —
Long-term Risk Management Assets0 0 0 
Total Assets 2.9
 —
 2.9
Total Assets10.5 (0.2)10.3 
      
Current Risk Management Liabilities —
 —
 —
Other Current Liabilities - Current Risk Management LiabilitiesOther Current Liabilities - Current Risk Management Liabilities0 0 0 
Long-term Risk Management Liabilities —
 —
 —
Long-term Risk Management Liabilities0 0 0 
Total Liabilities —
 —
 —
Total Liabilities0 0 0 
      
Total MTM Derivative Contract Net Assets $2.9
 $—
 $2.9
Total MTM Derivative Contract Net Assets (Liabilities)Total MTM Derivative Contract Net Assets (Liabilities)$10.5 $(0.2)$10.3 
Fair Value of Derivative Instruments
December 31, 2017
Balance Sheet Location 
Risk Management
Contracts -
Commodity (a)
 
Gross Amounts Offset in the Statement of
Financial Position (b)
 
Net Amounts of Assets/Liabilities
Presented in the Statement of
Financial Position (c)
  (in millions)
Current Risk Management Assets $6.6
 $(0.2) $6.4
Long-term Risk Management Assets —
 —
 —
Total Assets 6.6
 (0.2) 6.4
       
Current Risk Management Liabilities 0.2
 (0.2) —
Long-term Risk Management Liabilities —
 —
 —
Total Liabilities 0.2
 (0.2) —
       
Total MTM Derivative Contract Net Assets $6.4
 $—
 $6.4

SWEPCo
Fair Value
June 30, 2021
Risk ManagementGross Amounts OffsetNet Amounts of Assets/Liabilities
Contracts –in the Statement ofPresented in the Statement of
Balance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)
(in millions)
Current Risk Management Assets$14.9 $(0.9)$14.0 
Long-term Risk Management Assets0.7 (0.1)0.6 
Total Assets15.6 (1.0)14.6 
Current Risk Management Liabilities0.4 (0.4)0 
Long-term Risk Management Liabilities0 0 0 
Total Liabilities0.4 (0.4)0 
Total MTM Derivative Contract Net Assets (Liabilities)$15.2 $(0.6)$14.6 

December 31, 2020
Risk ManagementGross Amounts OffsetNet Amounts of Assets/Liabilities
Contracts –in the Statement ofPresented in the Statement of
Balance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)
(in millions)
Current Risk Management Assets$3.4 $(0.2)$3.2 
Long-term Risk Management Assets0 0 0 
Total Assets3.4 (0.2)3.2 
Current Risk Management Liabilities0.7 0 0.7 
Long-term Risk Management Liabilities1.0 0 1.0 
Total Liabilities1.7 0 1.7 
Total MTM Derivative Contract Net Assets (Liabilities)$1.7 $(0.2)$1.5 

(a)Derivative instruments within these categories are reported gross.  These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.”
(b)Amounts include counterparty netting of Derivative Instrumentsrisk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”
March 31, 2018(c)All derivative contracts subject to a master netting arrangement or similar agreement are offset in the statement of financial position.
191
Balance Sheet Location 
Risk Management
Contracts -
Commodity (a)
 
Gross Amounts Offset in the Statement of
Financial Position (b)
 
Net Amounts of Assets/Liabilities
Presented in the Statement of
Financial Position (c)
  (in millions)
Current Risk Management Assets $2.8
 $(1.1) $1.7
Long-term Risk Management Assets —
 —
 —
Total Assets 2.8
 (1.1) 1.7
       
Current Risk Management Liabilities 1.2
 (1.1) 0.1
Long-term Risk Management Liabilities 0.5
 —
 0.5
Total Liabilities 1.7
 (1.1) 0.6
       
Total MTM Derivative Contract Net Assets $1.1
 $—
 $1.1


Fair Value of Derivative Instruments
December 31, 2017
Balance Sheet Location 
Risk Management
Contracts -
Commodity (a)
 
Gross Amounts Offset in the Statement of
Financial Position (b)
 
Net Amounts of Assets/Liabilities
Presented in the Statement of
Financial Position (c)
  (in millions)
Current Risk Management Assets $7.0
 $(0.6) $6.4
Long-term Risk Management Assets —
 —
 —
Total Assets 7.0
 (0.6) 6.4
       
Current Risk Management Liabilities 0.8
 (0.6) 0.2
Long-term Risk Management Liabilities —
 —
 —
Total Liabilities 0.8
 (0.6) 0.2
       
Total MTM Derivative Contract Net Assets $6.2
 $—
 $6.2

(a)Derivative instruments within these categories are reported gross.  These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.”
(b)Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”
(c)There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.


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


Amount of Gain (Loss) Recognized on
Risk Management Contracts
Three Months Ended March 31, 2018
Three Months Ended June 30, 2021
Location of Gain (Loss)AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Vertically Integrated Utilities Revenues$0.1 $0 $0 $0 $0 $0 $0 
Generation & Marketing Revenues16.5 0 0 0 0 0 0 
Electric Generation, Transmission and Distribution Revenues0 0 0.1 0 0 0 0 
Purchased Electricity for Resale0.6 0 0.5 0.1 0 0 0 
Other Operation0.7 0.2 0.1 0.1 0.1 0.1 0.1 
Maintenance0.8 0.3 0.1 0 0.1 0 0.1 
Regulatory Assets (a)(7.0)0 0 (5.1)(1.2)0 0.5 
Regulatory Liabilities (a)55.1 0.2 11.3 3.4 2.2 15.0 19.6 
Total Gain (Loss) on Risk Management Contracts$66.8 $0.7 $12.1 $(1.5)$1.2 $15.1 $20.3 

Three Months Ended June 30, 2020
Location of Gain (Loss)AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Vertically Integrated Utilities Revenues$(0.1)$0 $0 $0 $0 $0 $0 
Generation & Marketing Revenues9.9 0 0 0 0 0 0 
Electric Generation, Transmission and Distribution Revenues0 0 (0.1)0 0 0 0.1 
Purchased Electricity for Resale0.8 0 0.7 0 0 0 0 
Other Operation(0.8)(0.2)(0.1)(0.1)(0.1)(0.1)(0.1)
Maintenance(1.2)(0.3)(0.1)(0.1)(0.2)(0.2)(0.2)
Regulatory Assets (a)17.5 0.7 8.4 0.3 4.1 0.3 1.3 
Regulatory Liabilities (a)52.7 0 19.7 3.0 3.2 12.7 9.5 
Total Gain on Risk Management Contracts$78.8 $0.2 $28.5 $3.1 $7.0 $12.7 $10.6 

Six Months Ended June 30, 2021
Location of Gain (Loss)AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Vertically Integrated Utilities Revenues$0.3 $0 $0 $0 $0 $0 $0 
Generation & Marketing Revenues16.1 0 0 0 0 0 0 
Electric Generation, Transmission and Distribution Revenues0 0 0.3 0 0 0 0 
Purchased Electricity for Resale1.0 0 0.9 0.1 0 0 0 
Other Operation1.0 0.3 0.1 0.1 0.2 0.1 0.1 
Maintenance1.3 0.4 0.2 0.1 0.2 0.1 0.2 
Regulatory Assets (a)(0.6)0 0 (6.0)5.4 0 1.3 
Regulatory Liabilities (a)77.1 0.6 14.7 0.2 5.1 26.2 25.8 
Total Gain (Loss) on Risk Management Contracts$96.2 $1.3 $16.2 $(5.5)$10.9 $26.4 $27.4 
192




Six Months Ended June 30, 2020
Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCoLocation of Gain (Loss)AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
 (in millions)(in millions)
Vertically Integrated Utilities Revenues $(5.5) $—
 $—
 $—
 $—
 $—
 $—
Vertically Integrated Utilities Revenues$0.3 $0 $0 $0 $0 $0 $0 
Generation & Marketing Revenues (15.1) —
 —
 —
 —
 —
 —
Generation & Marketing Revenues(0.4)0 0 0 0 0 0 
Electric Generation, Transmission and Distribution Revenues —
 —
 (0.3) (5.1) —
 —
 —
Electric Generation, Transmission and Distribution Revenues0 0 0.1 0.1 0 0 0.1 
Purchased Electricity for Resale 4.9
 —
 4.6
 0.2
 —
 —
 —
Purchased Electricity for Resale0.9 0 0.8 0 0 0 0 
Other Operation 0.3
 0.1
 —
 —
 0.1
 —
 —
Other Operation(1.0)(0.3)(0.1)(0.1)(0.2)(0.1)(0.1)
Maintenance 0.4
 0.1
 0.1
 —
 0.1
 —
 —
Maintenance(1.4)(0.4)(0.2)(0.1)(0.2)(0.2)(0.2)
Regulatory Assets (a) 37.3
 —
 —
 6.2
 31.4
 —
 (0.3)Regulatory Assets (a)(16.4)(0.5)(0.5)(0.4)(14.3)(0.2)(0.7)
Regulatory Liabilities (a) 87.0
 (0.1) 64.1
 0.2
 —
 12.1
 (0.8)Regulatory Liabilities (a)63.9 0 12.4 6.2 6.7 20.8 12.8 
Total Gain (Loss) on Risk Management Contracts $109.3
 $0.1
 $68.5
 $1.5
 $31.6
 $12.1
 $(1.1)Total Gain (Loss) on Risk Management Contracts$45.9 $(1.2)$12.5 $5.7 $(8.0)$20.3 $11.9 


Amount of Gain (Loss) Recognized(a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Risk Management Contracts
Three Months Ended March 31, 2017
Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo
  (in millions)
Vertically Integrated Utilities Revenues $5.5
 $—
 $—
 $—
 $—
 $—
 $—
Generation & Marketing Revenues 10.5
 —
 —
 —
 —
 —
 —
Electric Generation, Transmission and Distribution Revenues —
 —
 0.4
 5.2
 —
 —
 0.1
Purchased Electricity for Resale 2.4
 —
 0.8
 0.1
 —
 —
 —
Other Operation 0.2
 —
 —
 —
 —
 —
 —
Maintenance 0.2
 —
 —
 —
 —
 —
 —
Regulatory Assets (a) (14.9) —
 (5.8) (0.2) (8.6) —
 (0.2)
Regulatory Liabilities (a) 25.2
 (0.2) 10.9
 6.8
 —
 2.4
 4.6
Total Gain (Loss) on Risk Management Contracts $29.1
 $(0.2) $6.3
 $11.9
 $(8.6) $2.4
 $4.5

(a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.


Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis.


The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge.


For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”



Accounting for Fair Value Hedging Strategies (Applies to AEP)


For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Incomenet income during the period of change.


AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income.


193




The following table shows the resultsimpacts recognized on the balance sheets related to the hedged items in fair value hedging relationships:
Carrying Amount of the Hedged LiabilitiesCumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Liabilities
June 30, 2021December 31, 2020June 30, 2021December 31, 2020
(in millions)
Long-term Debt (a) (b)$(967.4)$(995.9)$(24.2)$(51.7)

(a)Amounts included on the balance sheets within Long-term Debt Due within One Year and Long-term Debt, respectively.
(b)Amounts include $(49) million and $(53) million as of June 30, 2021 and December 31, 2020, respectively, for the fair value hedge adjustment of hedged debt obligations for which hedge accounting has been discontinued.

The pretax effects of fair value hedge accounting on income were as follows:
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
(in millions)
Gain (Loss) on Interest Rate Contracts:
Fair Value Hedging Instruments (a)$9.5 $0.1 $(23.7)$42.6 
Fair Value Portion of Long-term Debt (a)(9.5)(0.1)23.7 (42.6)

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

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

 Three Months Ended March 31,
 2018 2017
 (in millions)
Loss on Fair Value Hedging Instruments$(14.5) $(0.5)
Gain on Fair Value Portion of Long-term Debt14.2
 0.5

During the three months ended March 31, 2018 and 2017, hedge ineffectiveness was immaterial.


Accounting for Cash Flow Hedging Strategies


For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable.net income.


Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three and six months ended March 31, 2018June 30, 2021 and 2017,2020, AEP applied cash flow hedging to outstanding power derivatives. During the three and six months ended March 31, 2018June 30, 2021 and 2017,2020, the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives.


The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three and six months ended March 31, 2018June 30, 2021 and 2017, the Registrants did not apply2020, AEP and APCo applied cash flow hedging to outstanding interest rate derivatives.derivatives and the other Registrant Subsidiaries did not.

The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three months ended March 31, 2018 and 2017, the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives.



During the three months ended March 31, 2018 and 2017, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.


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



194




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


Impact of Cash Flow Hedges on AEP’s Balance Sheets
June 30, 2021December 31, 2020
CommodityInterest RateCommodityInterest Rate
(in millions)
AOCI Gain (Loss) Net of Tax$110.3 $(32.2)$(60.6)$(47.5)
Portion Expected to be Reclassed to Net Income During the Next Twelve Months82.9 (4.7)(27.1)(5.7)
  March 31, 2018 December 31, 2017
  Commodity Interest Rate Commodity Interest Rate
  (in millions)
Hedging Assets (a) $25.5
 $—
 $22.0
 $—
Hedging Liabilities (a) 58.9
 —
 65.5
 —
AOCI Loss Net of Tax (32.0) (15.5) (28.4) (13.0)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months 3.1
 (1.0) 5.5
 (0.8)

(a)Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets.


As of March 31, 2018June 30, 2021 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 117 months.months and 114 months for commodity and interest rate hedges, respectively.


Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets
June 30, 2021December 31, 2020
Interest Rate
Expected to beExpected to be
Reclassified toReclassified to
Net Income DuringNet Income During
AOCI Gain (Loss)the NextAOCI Gain (Loss)the Next
CompanyNet of TaxTwelve MonthsNet of TaxTwelve Months
(in millions)
AEP Texas$(1.8)$(1.1)$(2.3)$(1.1)
APCo8.0 0.8 (0.8)0.4 
I&M(7.4)(1.6)(8.3)(1.6)
PSO0 0 0.1 0.1 
SWEPCo0.5 (0.8)(0.3)(1.5)
  March 31, 2018 December 31, 2017
  Interest Rate
Company 
AOCI Gain (Loss)
Net of Tax
 
Expected to be Reclassified to
Net Income During the Next
Twelve Months
 
AOCI Gain (Loss)
Net of Tax
 
Expected to be Reclassified to
Net Income During the Next
Twelve Months
  (in millions)
AEP Texas $(5.2)—
$(1.1) $(4.5) $(0.9)
APCo 2.5
 0.9
 2.2
 0.7
I&M (12.7) (1.6) (10.7) (1.3)
OPCo 2.0
 1.3
 1.9
 1.1
PSO 2.9
 1.0
 2.6
 0.8
SWEPCo (6.9) (1.7) (6.0) (1.4)


Amounts for OPCo are immaterial as of June 30, 2021 and December 31, 2020, respectively.

The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.


Credit Risk


Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s Investors Service Inc., S&P Global Inc.credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.


Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination
and liquidation of all positions in the event of a default including a failure or inability to post collateral when required.




195




Collateral Triggering Events


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


A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts.  The Registrants have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral.  The RegistrantsAEP had immaterialsix derivative contracts with collateral triggering events in a net liability position as of March 31, 2018 andJune 30, 2021, with a total exposure of $8 million. The Registrant Subsidiaries had no derivative contracts with collateral triggering events in a net liability position as of June 30, 2021. The Registrants had no derivative contracts with collateral triggering events in a net liability position as of December 31, 2017, respectively.2020.


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


In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third partythird-party obligation that is $50 million or greater.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following table represents:tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount that the exposure has been reduced by cash collateral posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering contractual netting arrangements:
June 30, 2021
Liabilities forAdditional
Contracts with CrossSettlement
Default ProvisionsLiability if Cross
Prior to ContractualAmount of CashDefault Provision
CompanyNetting ArrangementsCollateral Postedis Triggered
(in millions)
AEP$118.4 $0 $70.2 
APCo0.6 0 0 
I&M0.4 0 0 
SWEPCo0 0 0 
December 31, 2020
Liabilities forAdditional
Contracts with CrossSettlement
Default ProvisionsLiability if Cross
Prior to ContractualAmount of CashDefault Provision
CompanyNetting ArrangementsCollateral Postedis Triggered
(in millions)
AEP$188.4 $0 $169.2 
APCo4.3 0 3.5 
I&M0.5 0 0.1 
SWEPCo1.8 0 1.8 


196




  AEP
  
Liabilities for
Contracts with Cross
Default Provisions
Prior to Contractual
Netting Arrangements
 
Amount of Cash
Collateral Posted
 
Additional
Settlement
Liability if Cross
Default Provision
is Triggered
  (in millions)
March 31, 2018 $272.7
 $1.0
 $202.4
December 31, 2017 243.6
 1.3
 223.1
Warrants Held in Investee (Applies to AEP)


AmountsAEP holds an investment in ChargePoint, which completed an initial public offering (IPO) in February 2021 via a reverse merger with a public special purpose acquisition company. Before the IPO, AEP’s interests in ChargePoint consisted of a noncontrolling equity interest of preferred shares, which were accounted for APCo, I&M and SWEPCo are immaterialat their historical cost of $8 million as of MarchDecember 31, 20182020, and common share warrants. After the IPO, AEP’s interests in ChargePoint consisted of a noncontrolling equity interest of common shares, which were accounted for at their fair value of $46 million as of June 30, 2021, and common share warrants. AEP recorded an unrealized gain of $11 million and $38 million associated with the common shares for the three and six months ended June 30, 2021, respectively, presented in Other Income (Expense) on AEP’s statements of income.

Management has determined the common share warrants are derivative instruments based on the accounting guidance for “Derivatives and Hedging”. As of June 30, 2021 and December 31, 2017, respectively.2020, the warrants were valued at $26 million and $32 million, respectively, and were recorded in Deferred Charges and Other Noncurrent Assets on AEP’s balance sheets. AEP recognized an unrealized gain (loss) of $4 million and $(6) million associated with the warrants for the three and six months ended June 30, 2021, respectively, presented in Other Income (Expense) on AEP’s statements of income.

Management utilized a Black-Scholes options pricing model to value the warrants as of June 30, 2021 and December 31, 2020. The valuation contemplated a liquidity adjustment that resulted in the overall fair value of the warrants being categorized as Level 3 in the fair value hierarchy as of December 31, 2020. After the IPO, there was an observable publicly traded stock price to use in the Black-Scholes options pricing model, which resulted in the warrants being categorized as Level 2 as of June 30, 2021. The common shares are also categorized as Level 2 as management applied a discount to the shares due to a six month lock-up agreement post IPO. After the six month lock-up period, the common shares will be valued as Level 1 based on the publicly traded share prices. See “Fair Value Measurements of Financial Assets and Liabilities” section of Note 10 for additional information.
197




10.  FAIR VALUE MEASUREMENTS


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


Fair Value Hierarchy and Valuation Techniques


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


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


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


Assets in the nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods.  Equities are classified as Level 1 holdings if they are actively traded on exchanges.  Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities.  They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets.  Items classified as Level 2 are primarily investments in individual fixed income securities.  Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data.  Pricing vendors calculate bond valuations using financial models and matrices.  The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation.  Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.

198





Fair Value Measurements of Long-term Debt (Applies to all Registrants)


The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs.  These instruments are not marked-to-market.  The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The fair value of AEP’s Equity Units (Level 1) are valued based on publicly traded securities issued by AEP.


The book values and fair values of Long-term Debt are summarized in the following table:
June 30, 2021December 31, 2020
CompanyBook ValueFair ValueBook ValueFair Value
(in millions)
AEP (a)$33,117.8 $37,826.2 $31,072.5 $37,457.0 
AEP Texas5,226.0 5,809.5 4,820.4 5,682.6 
AEPTCo3,949.3 4,667.9 3,948.5 4,984.3 
APCo4,949.8 6,129.7 4,834.1 6,391.8 
I&M3,255.0 3,850.6 3,029.9 3,775.3 
OPCo2,876.8 3,419.0 2,430.2 3,154.9 
PSO1,623.8 1,883.6 1,373.8 1,732.1 
SWEPCo3,130.7 3,563.5 2,636.4 3,210.1 
  March 31, 2018 December 31, 2017
Company Book Value Fair Value Book Value Fair Value
  (in millions)
AEP $21,461.0
 $23,039.8
 $21,173.3
 $23,649.6
AEP Texas 3,553.3
 3,818.3
 3,649.3
 3,964.8
AEPTCo 2,550.7
 2,620.6
 2,550.4
 2,782.9
APCo 3,969.3
 4,532.0
 3,980.1
 4,782.6
I&M 2,717.2
 2,869.5
 2,745.1
 3,014.7
OPCo 2,089.7
 2,367.9
 1,719.3
 2,064.3
PSO 1,286.7
 1,400.3
 1,286.5
 1,457.1
SWEPCo 2,503.7
 2,587.3
 2,441.9
 2,645.9


(a)The fair value amounts include debt related to AEP’s Equity Units and had a fair value of $1.7 billion and $1.7 billion as of June 30, 2021 and December 31, 2020, respectively. See “Equity Units” section of Note 12 for additional information.

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


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


The following is a summary of Other Temporary Investments:
June 30, 2021
GrossGross
UnrealizedUnrealizedFair
Other Temporary InvestmentsCostGainsLossesValue
(in millions)
Restricted Cash and Other Cash Deposits (a)$80.2 $0 $0 $80.2 
Fixed Income Securities – Mutual Funds (b)129.0 2.1 0 131.1 
Equity Securities – Mutual Funds22.7 34.7 0 57.4 
Total Other Temporary Investments$231.9 $36.8 $0 $268.7 
December 31, 2020
GrossGross
UnrealizedUnrealizedFair
Other Temporary InvestmentsCostGainsLossesValue
(in millions)
Restricted Cash and Other Cash Deposits (a)$68.3 $0 $0 $68.3 
Fixed Income Securities – Mutual Funds (b)120.7 2.8 0 123.5 
Equity Securities – Mutual Funds25.9 28.7 0 54.6 
Total Other Temporary Investments$214.9 $31.5 $0 $246.4 

(a)Primarily represents amounts held for the repayment of debt.
(b)Primarily short and intermediate maturities which may be sold and do not contain maturity dates.
199




  March 31, 2018
Other Temporary Investments Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
  (in millions)
Restricted Cash and Other Cash Deposits (a) $162.0
 $—
 $—
 $162.0
Fixed Income Securities – Mutual Funds (b) 104.8
 —
 (2.2) 102.6
Equity Securities – Mutual Funds
 17.2
 19.2
 —
 36.4
Total Other Temporary Investments $284.0
 $19.2
 $(2.2) $301.0
  December 31, 2017
Other Temporary Investments Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
  (in millions)
Restricted Cash and Other Cash Deposits (a) $220.1
 $—
 $—
 $220.1
Fixed Income Securities – Mutual Funds (b)
 104.3
 —
 (1.4) 102.9
Equity Securities – Mutual Funds
 17.0
 19.7
 —
 36.7
Total Other Temporary Investments $341.4
 $19.7
 $(1.4) $359.7

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



The following table provides the activity for fixed income and equity securities within Other Temporary Investments:
 Three Months Ended June 30,Six Months Ended June 30,
 2021202020212020
(in millions)
Proceeds from Investment Sales$3.6 $7.6 $9.1 $30.8 
Purchases of Investments12.4 10.3 13.1 17.0 
Gross Realized Gains on Investment Sales1.1 0.2 1.2 2.2 
Gross Realized Losses on Investment Sales0 0.1 0 0.2 
 Three Months Ended March 31,
 2018 2017
 (in millions)
Proceeds from Investment Sales$—
 $—
Purchases of Investments0.6
 0.5
Gross Realized Gains on Investment Sales—
 —
Gross Realized Losses on Investment Sales—
 —

For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three months ended March 31, 2017, see Note 3 - Comprehensive Income.


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


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


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


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


I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets.  I&M records these securities at fair value.  I&M classifies debt securities in the trust funds as available-for-sale due to their long-term purpose. Upon adoption of ASU 2016-01 in first quarter 2018, equity securities are now recorded with changes in fair value recognized in earnings. Effective January 2018 available for sale classification only applies to investment in debt securities.

Other-than-temporary impairments for investments in debt securities are considered realized losses as a result of securities being managed by an external investment management firm.  The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy.  Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment.  I&M records unrealized gains, unrealized losses and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates.  Consequently, changes in fair value of trust assets do not affect earnings or AOCI.

200






The following is a summary of nuclear trust fund investments:
 June 30, 2021December 31, 2020
GrossOther-Than-GrossOther-Than-
FairUnrealizedTemporaryFairUnrealizedTemporary
ValueGainsImpairmentsValueGainsImpairments
(in millions)
Cash and Cash Equivalents$35.6 $0 $0 $25.8 $0 $0 
Fixed Income Securities:
United States Government1,155.8 68.9 (12.5)1,025.6 98.5 (7.1)
Corporate Debt87.3 7.1 (2.6)86.3 9.6 (1.7)
State and Local Government58.9 0.2 (0.6)114.3 0.9 (0.4)
Subtotal Fixed Income Securities1,302.0 76.2 (15.7)1,226.2 109.0 (9.2)
Equity Securities - Domestic (a)2,274.8 1,648.2 0 2,054.7 1,400.8 0 
Spent Nuclear Fuel and Decommissioning Trusts$3,612.4 $1,724.4 $(15.7)$3,306.7 $1,509.8 $(9.2)
 March 31, 2018 December 31, 2017
 
Fair
Value
 
Gross Unrealized
Gains
 
Other-Than-Temporary
Impairments
 
Fair
Value
 
Gross Unrealized
Gains
 Other-Than-Temporary Impairments
 (in millions)
Cash and Cash Equivalents$16.4
 $—
 $—
 $17.2
 $—
 $—
Fixed Income Securities:   
  
  
  
  
United States Government974.6
 19.0
 (8.4) 981.2
 29.7
 (3.6)
Corporate Debt57.8
 2.0
 (1.7) 58.7
 3.8
 (1.2)
State and Local Government8.6
 0.6
 (0.2) 8.8
 0.8
 (0.2)
Subtotal Fixed Income Securities1,041.0
 21.6
 (10.3) 1,048.7
 34.3
 (5.0)
Equity Securities – Domestic (a)1,453.2
 850.3
 —
 1,461.7
 868.2
 (75.5)
Spent Nuclear Fuel and Decommissioning Trusts$2,510.6
 $871.9
 $(10.3) $2,527.6
 $902.5
 $(80.5)


(a)Amount reported as Gross Unrealized Gains includes unrealized gains of $1.7 billion and $1.4 billion and unrealized losses of $3 million and $9 million as of June 30, 2021 and December 31, 2020, respectively.
(a)Amount reported as Gross Unrealized Gains includes unrealized gains of $855 million and unrealized losses of $4.7 million. AEP adopted ASU 2016-01 during the first quarter of 2018 by means of a modified retrospective approach. Due to the adoption of the ASU, Other-Than-Temporary Impairments are no longer applicable to Equity Securities with readily determinable fair values.


The following table provides the securities activity within the decommissioning and SNF trusts:
Three Months Ended June 30,Six Months Ended June 30,
 2021202020212020
 (in millions)
Proceeds from Investment Sales$802.7 $328.1 $1,122.7 $940.5 
Purchases of Investments812.8 345.4 1,149.7 971.4 
Gross Realized Gains on Investment Sales83.3 11.1 88.7 22.0 
Gross Realized Losses on Investment Sales1.3 7.7 5.5 24.7 
 Three Months Ended March 31,
 2018 2017
 (in millions)
Proceeds from Investment Sales$508.6
 $487.9
Purchases of Investments525.3
 505.5
Gross Realized Gains on Investment Sales12.0
 11.3
Gross Realized Losses on Investment Sales10.9
 8.1


The base cost of fixed income securities was $1$1.2 billion and $1$1.1 billion as of March 31, 2018June 30, 2021 and December 31, 2017,2020, respectively.  The base cost of equity securities was $603$627 million and $594$654 million as of March 31, 2018June 30, 2021 and December 31, 2017,2020, respectively.


The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of March 31, 2018June 30, 2021 was as follows:
Fair Value of Fixed
Income Securities
(in millions)
Within 1 year$331.4 
After 1 year through 5 years415.7 
After 5 years through 10 years263.0 
After 10 years291.9 
Total$1,302.0 
201
 Fair Value of Fixed Income Securities
 (in millions)
Within 1 year$355.7
After 1 year through 5 years315.3
After 5 years through 10 years205.8
After 10 years164.2
Total$1,041.0







Fair Value Measurements of Financial Assets and Liabilities


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


AEP


Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31, 2018June 30, 2021
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Other Temporary Investments
Restricted Cash and Other Cash Deposits (a)$59.1 $0 $0 $21.1 $80.2 
Fixed Income Securities – Mutual Funds131.1 0 0 0 131.1 
Equity Securities – Mutual Funds (b)57.4 0 0 0 57.4 
Total Other Temporary Investments247.6 0 0 21.1 268.7 
Risk Management Assets
Risk Management Commodity Contracts (c) (d)4.8 478.1 224.3 (400.1)307.1 
Cash Flow Hedges:
Commodity Hedges (c)0 158.7 16.9 (29.9)145.7 
Fair Value Hedges0 3.2 0 0 3.2 
Total Risk Management Assets4.8 640.0 241.2 (430.0)456.0 
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)28.0 0 0 7.6 35.6 
Fixed Income Securities:
United States Government0 1,155.8 0 0 1,155.8 
Corporate Debt0 87.3 0 0 87.3 
State and Local Government0 58.9 0 0 58.9 
Subtotal Fixed Income Securities0 1,302.0 0 0 1,302.0 
Equity Securities – Domestic (b)2,274.8 0 0 0 2,274.8 
Total Spent Nuclear Fuel and Decommissioning Trusts2,302.8 1,302.0 0 7.6 3,612.4 
Other Investments (h)0 72.5 0 0 72.5 
Total Assets$2,555.2 $2,014.5 $241.2 $(401.3)$4,409.6 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (d)$2.5 $395.2 $139.1 $(307.1)$229.7 
Cash Flow Hedges:
Commodity Hedges (c)0 35.0 0.9 (29.9)6.0 
Fair Value Hedges0 28.4 0 0 28.4 
Total Risk Management Liabilities$2.5 $458.6 $140.0 $(337.0)$264.1 
202
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Other Temporary Investments          
Restricted Cash and Other Cash Deposits (a) $144.8
 $—
 $—
 $17.2
 $162.0
Fixed Income Securities – Mutual Funds
 102.6
 —
 —
 —
 102.6
Equity Securities – Mutual Funds (b)
 36.4
 —
 —
 —
 36.4
Total Other Temporary Investments
 283.8
 —
 —
 17.2
 301.0
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (d) 3.0
 265.0
 243.3
 (177.7) 333.6
Cash Flow Hedges:  
  
  
  
  
Commodity Hedges (c) —
 11.6
 3.1
 10.8
 25.5
Fair Value Hedges —
 1.7
 —
 —
 1.7
Total Risk Management Assets 3.0
 278.3
 246.4
 (166.9) 360.8
           
Spent Nuclear Fuel and Decommissioning Trusts  
  
  
  
  
Cash and Cash Equivalents (e) 9.1
 —
 —
 7.3
 16.4
Fixed Income Securities:  
  
  
  
  
United States Government —
 974.6
 —
 —
 974.6
Corporate Debt —
 57.8
 —
 —
 57.8
State and Local Government —
 8.6
 —
 —
 8.6
Subtotal Fixed Income Securities —
 1,041.0
 —
 —
 1,041.0
Equity Securities – Domestic (b)
 1,453.2
 —
 —
 —
 1,453.2
Total Spent Nuclear Fuel and Decommissioning Trusts
 1,462.3
 1,041.0
 —
 7.3
 2,510.6
           
Total Assets $1,749.1
 $1,319.3
 $246.4
 $(142.4) $3,172.4
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (d) $3.6
 $284.7
 $164.8
 $(194.5) $258.6
Cash Flow Hedges:  
  
  
  
  
Commodity Hedges (c) —
 28.5
 19.6
 10.8
 58.9
Fair Value Hedges —
 22.3
 —
 —
 22.3
Total Risk Management Liabilities $3.6
 $335.5
 $184.4
 $(183.7) $339.8






AEP


Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 20172020
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Other Temporary Investments
Restricted Cash and Other Cash Deposits (a)$57.8 $0 $0 $10.5 $68.3 
Fixed Income Securities – Mutual Funds123.5 0 0 0 123.5 
Equity Securities – Mutual Funds (b)54.6 0 0 0 54.6 
Total Other Temporary Investments235.9 0 0 10.5 246.4 
Risk Management Assets
Risk Management Commodity Contracts (c) (f)0.9 258.8 252.4 (190.0)322.1 
Cash Flow Hedges:
Commodity Hedges (c)0 34.4 3.9 (28.5)9.8 
Interest Rate Hedges0 2.4 0 0 2.4 
Fair Value Hedges0 2.6 0 0 2.6 
Total Risk Management Assets0.9 298.2 256.3 (218.5)336.9 
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)16.8 0 0 9.0 25.8 
Fixed Income Securities:
United States Government0 1,025.6 0 0 1,025.6 
Corporate Debt0 86.3 0 0 86.3 
State and Local Government0 114.3 0 0 114.3 
Subtotal Fixed Income Securities0 1,226.2 0 0 1,226.2 
Equity Securities – Domestic (b)2,054.7 0 0 0 2,054.7 
Total Spent Nuclear Fuel and Decommissioning Trusts2,071.5 1,226.2 0 9.0 3,306.7 
Other Investments (h)0 0 31.8 0 31.8 
Total Assets$2,308.3 $1,524.4 $288.1 $(199.0)$3,921.8 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (f)$0.9 $244.2 $167.2 $(193.4)$218.9 
Cash Flow Hedges:
Commodity Hedges (c)0 106.1 7.6 (28.5)85.2 
Interest Rate Hedges0 3.4 0 0 3.4 
Fair Value Hedges0 4.1 0 0 4.1 
Total Risk Management Liabilities$0.9 $357.8 $174.8 $(221.9)$311.6 

203
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Other Temporary Investments          
Restricted Cash and Other Cash Deposits (a) $183.2
 $—
 $—
 $36.9
 $220.1
Fixed Income Securities – Mutual Funds
 102.9
 —
 —
 —
 102.9
Equity Securities – Mutual Funds (b)
 36.7
 —
 —
 —
 36.7
Total Other Temporary Investments
 322.8
 —
 —
 36.9
 359.7
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (f) 3.9
 391.2
 274.1
 (285.4) 383.8
Cash Flow Hedges:  
  
  
  
  
Commodity Hedges (c) —
 17.3
 4.7
 —
 22.0
Fair Value Hedges —
 2.5
 —
 —
 2.5
Total Risk Management Assets 3.9
 411.0
 278.8
 (285.4) 408.3
           
Spent Nuclear Fuel and Decommissioning Trusts  
  
  
  
  
Cash and Cash Equivalents (e) 7.5
 —
 —
 9.7
 17.2
Fixed Income Securities:  
  
  
  
  
United States Government —
 981.2
 —
 —
 981.2
Corporate Debt —
 58.7
 —
 —
 58.7
State and Local Government —
 8.8
 —
 —
 8.8
Subtotal Fixed Income Securities —
 1,048.7
 —
 —
 1,048.7
Equity Securities – Domestic (b)
 1,461.7
 —
 —
 —
 1,461.7
Total Spent Nuclear Fuel and Decommissioning Trusts
 1,469.2
 1,048.7
 —
 9.7
 2,527.6
           
Total Assets $1,795.9
 $1,459.7
 $278.8
 $(238.8) $3,295.6
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (f) $5.1
 $392.5
 $196.9
 $(285.0) $309.5
Cash Flow Hedges:  
  
  
  
  
Commodity Hedges (c) —
 23.9
 41.6
 —
 65.5
Fair Value Hedges —
 8.6
 —
 —
 8.6
Total Risk Management Liabilities $5.1
 $425.0
 $238.5
 $(285.0) $383.6







AEP Texas

Assets and Liabilities Measured at Fair Value on a Recurring Basis
MarchJune 30, 2021
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$27.9 $0 $0 $0 $27.9 
Risk Management Assets     
Risk Management Commodity Contracts (c)0 1.1 0 (1.1)0 
Total Assets$27.9 $1.1 $0 $(1.1)$27.9 

December 31, 20182020
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$28.7 $0 $0 $0 $28.7 
Risk Management Assets     
Risk Management Commodity Contracts (c)0 0.4 0 (0.4)0 
Total Assets$28.7 $0.4 $0 $(0.4)$28.7 


204




  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Restricted Cash for Securitized Funding $107.1
 $—
 $—
 $—
 $107.1
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) —
 0.4
 —
 (0.1) 0.3
           
Total Assets $107.1
 $0.4
 $—
 $(0.1) $107.4

AEP Texas

APCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2021
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$19.1 0$0 $0 $19.1 
Risk Management Assets
Risk Management Commodity Contracts (c) (g)0 27.0 37.3 (27.2)37.1 
Total Assets$19.1 $27.0 $37.3 $(27.2)$56.2 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$0 $32.5 $0.7 $(31.8)$1.4 

December 31, 20172020
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$16.9 $0 $0 $0 $16.9 
Risk Management Assets
Risk Management Commodity Contracts (c) (g)0 19.4 19.9 (19.2)20.1 
Cash Flow Hedges:
Interest Rate Hedges0 2.4 0 0 2.4 
Total Risk Management Assets0 21.8 19.9 (19.2)22.5 
Total Assets$16.9 $21.8 $19.9 $(19.2)$39.4 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$0 $19.5 $0.6 $(18.8)$1.3 
Cash Flow Hedges:
Interest Rate Hedges0 3.4 0 0 3.4 
Total Risk Management Liabilities$0 $22.9 $0.6 $(18.8)$4.7 

205




  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Restricted Cash for Securitized Funding $155.2
 $—
 $—
 $—
 $155.2
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) —
 0.5
 —
 —
 0.5
           
Total Assets $155.2
 $0.5
 $—
 $—
 $155.7


APCo

I&M
Assets and Liabilities Measured at Fair Value on a Recurring Basis
MarchJune 30, 2021
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)$0 $17.0 $8.9 $(18.2)$7.7 
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)28.0 0 0 7.6 35.6 
Fixed Income Securities:
United States Government0 1,155.8 0 0 1,155.8 
Corporate Debt0 87.3 0 0 87.3 
State and Local Government0 58.9 0 0 58.9 
Subtotal Fixed Income Securities0 1,302.0 0 0 1,302.0 
Equity Securities - Domestic (b)2,274.8 0 0 0 2,274.8 
Total Spent Nuclear Fuel and Decommissioning Trusts2,302.8 1,302.0 0 7.6 3,612.4 
Total Assets$2,302.8 $1,319.0 $8.9 $(10.6)$3,620.1 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$0 $21.9 $1.6 $(22.4)$1.1 

December 31, 20182020
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)$0 $15.1 $2.5 $(13.9)$3.7 
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)16.8 0 0 9.0 25.8 
Fixed Income Securities:
United States Government0 1,025.6 0 0 1,025.6 
Corporate Debt0 86.3 0 0 86.3 
State and Local Government0 114.3 0 0 114.3 
Subtotal Fixed Income Securities0 1,226.2 0 0 1,226.2 
Equity Securities - Domestic (b)2,054.7 0 0 0 2,054.7 
Total Spent Nuclear Fuel and Decommissioning Trusts2,071.5 1,226.2 0 9.0 3,306.7 
Total Assets$2,071.5 $1,241.3 $2.5 $(4.9)$3,310.4 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$0 $12.0 $0.4 $(12.2)$0.2 
206




  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Restricted Cash for Securitized Funding $10.1
 $—
 $—
 $—
 $10.1
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) 0.6
 27.0
 10.4
 (27.4) 10.6
           
Total Assets $10.7
 $27.0
 $10.4
 $(27.4) $20.7
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $0.6
 $26.6
 $1.3
 $(27.5) $1.0

APCo

OPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2021
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets     
Risk Management Commodity Contracts (c) (g)$0 $0.7 $0 $(0.7)$0 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$0 $0 $105.4 $0.1 $105.5 

December 31, 20172020
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)$0 $0.3 $0 $(0.3)$0 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$0 $0 $110.3 $0 $110.3 
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Restricted Cash for Securitized Funding $16.3
 $—
 $—
 $—
 $16.3
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) —
 52.5
 25.1
 (51.6) 26.0
           
Total Assets $16.3
 $52.5
 $25.1
 $(51.6) $42.3
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $51.2
 $0.4
 $(50.1) $1.5



I&M

PSO
Assets and Liabilities Measured at Fair Value on a Recurring Basis
MarchJune 30, 2021
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)$0 $0.4 $23.1 $(0.5)$23.0 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$0 $0 $0.2 $(0.1)$0.1 

December 31, 20182020
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)$0 $0.2 $10.3 $(0.2)$10.3 
207




  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $0.3
 $19.4
 $5.1
 $(19.5) $5.3
           
Spent Nuclear Fuel and Decommissioning Trusts  
  
  
  
  
Cash and Cash Equivalents (e) 9.1
 —
 —
 7.3
 16.4
Fixed Income Securities:  
  
  
  
  
United States Government —
 974.6
 —
 —
 974.6
Corporate Debt —
 57.8
 —
 —
 57.8
State and Local Government —
 8.6
 —
 —
 8.6
Subtotal Fixed Income Securities —
 1,041.0
 —
 —
 1,041.0
Equity Securities - Domestic (b) 1,453.2
 —
 —
 —
 1,453.2
Total Spent Nuclear Fuel and Decommissioning Trusts
 1,462.3
 1,041.0
 —
 7.3
 2,510.6
           
Total Assets $1,462.6
 $1,060.4
 $5.1
 $(12.2) $2,515.9
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $0.3
 $21.0
 $2.2
 $(19.5) $4.0

I&M

SWEPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2021
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)$0 $0.6 $15.0 $(1.0)$14.6 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$0 $0 $0.4 $(0.4)$0 

December 31, 20172020
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)$0 $0.1 $3.3 $(0.2)$3.2 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$0 $0 $1.7 $0 $1.7 
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $39.4
 $9.1
 $(40.2) $8.3
           
Spent Nuclear Fuel and Decommissioning Trusts  
  
  
  
  
Cash and Cash Equivalents (e) 7.5
 —
 —
 9.7
 17.2
Fixed Income Securities:  
  
  
  
 

United States Government —
 981.2
 —
 —
 981.2
Corporate Debt —
 58.7
 —
 —
 58.7
State and Local Government —
 8.8
 —
 —
 8.8
Subtotal Fixed Income Securities —
 1,048.7
 —
 —
 1,048.7
Equity Securities - Domestic (b) 1,461.7
 —
 —
 —
 1,461.7
Total Spent Nuclear Fuel and Decommissioning Trusts
 1,469.2
 1,048.7
 —
 9.7
 2,527.6
           
Total Assets $1,469.2
 $1,088.1
 $9.1
 $(30.5) $2,535.9
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $47.6
 $1.5
 $(45.5) $3.6



OPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31, 2018
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Restricted Cash for Securitized Funding $15.9
 $—
 $—
 $—
 $15.9
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) —
 0.5
 —
 (0.1) 0.4
           
Total Assets $15.9
 $0.5
 $—
 $(0.1) $16.3
           
Liabilities:          
           
Risk Management Liabilities          
Risk Management Commodity Contracts (c) (g) $—
 $—
 $98.5
 $—
 $98.5

OPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2017
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $0.6
 $—
 $—
 $0.6
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $—
 $132.4
 $—
 $132.4



PSO

Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31, 2018
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $0.1
 $2.9
 $(0.1) $2.9
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $—
 $0.1
 $(0.1) $—

PSO

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2017
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $0.2
 $6.4
 $(0.2) $6.4
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $—
 $0.2
 $(0.2) $—


SWEPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31, 2018
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $0.2
 $2.6
 $(1.1) $1.7
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $—
 $1.7
 $(1.1) $0.6

SWEPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2017
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $0.3
 $6.7
 $(0.6) $6.4
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $—
 $0.8
 $(0.6) $0.2

(a)Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or third parties.  Level 1 and Level 2 amounts primarily represent investments in money market funds.
(b)Amounts represent publicly traded equity securities and equity-based mutual funds.
(c)Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.”
(d)The March 31, 2018 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(19) million in 2018, $(3) million in periods 2019-2021 and $2 million in periods 2022-2023; Level 3 matures $24 million in 2018, $38 million in periods 2019-2021, $21 million in periods 2022-2023 and $(5) million in periods 2024-2032.  Risk management commodity contracts are substantially comprised of power contracts.
(e)Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions.  Level 1 amounts primarily represent investments in money market funds.
(f)The December 31, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(1) million in 2018;  Level 2 matures $(3) million in 2018 and $2 million in periods 2022-2023; Level 3 matures $59 million in 2018, $33 million in periods 2019-2021, $14 million in periods 2022-2023 and $(29) million in periods 2024-2032.  Risk management commodity contracts are substantially comprised of power contracts.
(g)Substantially comprised of power contracts.

There were no transfers between(a)Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or third-parties.  Level 1 and Level 2 duringamounts primarily represent investments in money market funds.
(b)Amounts represent publicly traded equity securities and equity-based mutual funds.
(c)Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the three months ended Marchaccounting guidance for “Derivatives and Hedging.’’
(d)The June 30, 2021 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $2 million in periods 2022-2024; Level 2 matures $11 million in 2021, $37 million in periods 2022-2024, $22 million in periods 2025-2026 and $13 million in periods 2027-2033; Level 3 matures $96 million in 2021, $12 million in periods 2022-2024, $4 million in periods 2025-2026 and $(27) million in periods 2027-2033.  Risk management commodity contracts are substantially comprised of power contracts.
(e)Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions.  Level 1 amounts primarily represent investments in money market funds.
(f)The December 31, 20182020 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 2 matures $3 million in periods 2022-2024, $11 million in periods 2025-2026 and 2017.$1 million in periods 2027-2033; Level 3 matures $47 million in 2021, $37 million in periods 2022-2024, $14 million in periods 2025-2026 and $(13) million in periods 2027-2033.  Risk management commodity contracts are substantially comprised of power contracts.

(g)Substantially comprised of power contracts for the Registrant Subsidiaries.

(h)See “Warrants Held in Investee” section of Note 9 for additional information.

208




The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:
Three Months Ended June 30, 2021AEPAPCoI&MOPCoPSOSWEPCo
 (in millions)
Balance as of March 31, 2021$41.8 $6.6 $0.7 $(104.0)$5.5 $0.5 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)18.6 6.2 0.4 1.7 4.8 3.1 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)(10.6)0 0 0 0 0 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)15.4 0 0 0 0 0 
Settlements(34.5)(13.0)(1.2)0.6 (10.3)(4.5)
Transfers into Level 3 (d) (e)(0.8)0 0 0 0 0 
Transfers out of Level 3 (e)(19.1)0 0 0 0 0 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)90.4 36.8 7.4 (3.7)22.9 15.5 
Balance as of June 30, 2021$101.2 $36.6 $7.3 $(105.4)$22.9 $14.6 
Three Months Ended June 30, 2020AEPAPCoI&MOPCoPSOSWEPCo
 (in millions)
Balance as of March 31, 2020$42.5 $6.6 $2.1 $(120.9)$6.3 $(2.5)
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)39.1 23.5 2.8 0 3.9 0.8 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)(17.2)0 0 0 0 0 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)22.0 0 0 0 0 0 
Settlements(54.7)(28.9)(4.1)2.6 (10.2)(2.4)
Transfers out of Level 3 (e)(0.2)0 0 0 0 0 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)80.1 35.3 3.7 0.9 23.8 7.4 
Balance as of June 30, 2020$111.6 $36.5 $4.5 $(117.4)$23.8 $3.3 
Six Months Ended June 30, 2021AEPAPCoI&MOPCoPSOSWEPCo
 (in millions)
Balance as of December 31, 2020$113.3 $19.3 $2.1 $(110.3)$10.3 $1.6 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)78.3 38.9 0.4 0.1 16.1 9.5 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)(66.8)0 0 0 0 0 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)18.5 0 0 0 0 0 
Settlements(110.6)(58.4)(2.6)4.9 (26.4)(12.0)
Transfers into Level 3 (d) (e)(0.2)0 0 0 0 0 
Transfers out of Level 3 (e)(25.6)0 0 0 0 0 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)94.3 36.8 7.4 (0.1)22.9 15.5 
Balance as of June 30, 2021$101.2 $36.6 $7.3 $(105.4)$22.9 $14.6 
209




Three Months Ended March 31, 2018 AEP APCo I&M OPCo PSO SWEPCo
  (in millions)
Balance as of December 31, 2017 $40.3
 $24.7
 $7.6
 $(132.4) $6.2
 $5.9
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 97.3
 68.1
 3.0
 0.3
 11.4
 0.6
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 2.0
 —
 —
 —
 —
 —
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 17.9
 —
 —
 —
 —
 —
Settlements (129.8) (85.4) (7.4) 1.1
 (16.1) (3.9)
Transfers into Level 3 (c) (d) 2.1
 —
 —
 —
 —
 —
Transfers out of Level 3 (d) (2.0) —
 (0.3) —
 —
 —
Changes in Fair Value Allocated to Regulated Jurisdictions (e) 34.2
 1.7
 —
 32.5
 1.3
 (1.7)
Balance as of March 31, 2018 $62.0
 $9.1
 $2.9
 $(98.5) $2.8
 $0.9
Six Months Ended June 30, 2020AEPAPCoI&MOPCoPSOSWEPCo
 (in millions)
Balance as of December 31, 2019$109.9 $37.7 $5.8 $(103.6)$15.8 $1.4 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)38.2 12.9 2.3 (0.9)11.9 2.8 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)(6.4)0 0 0 0 0 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)18.3 0 0 0 0 0 
Settlements(113.7)(50.8)(8.1)5.1 (27.6)(7.6)
Transfers into Level 3 (d) (e)(0.6)0 0 0 0 0 
Transfers out of Level 3 (e)4.3 0.7 0.4 0 0 0 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)61.6 36.0 4.1 (18.0)23.7 6.7 
Balance as of June 30, 2020$111.6 $36.5 $4.5 $(117.4)$23.8 $3.3 

(a)Included in revenues on the statements of income.
(b)Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(c)Included in cash flow hedges on the statements of comprehensive income.
(d)Represents existing assets or liabilities that were previously categorized as Level 2.
(e)Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
(f)Relates to the net gains (losses) of those contracts that are not reflected on the statements of income.  These net gains (losses) are recorded as regulatory assets/liabilities or accounts payable.

210
Three Months Ended March 31, 2017 AEP APCo I&M OPCo PSO SWEPCo
  (in millions)
Balance as of December 31, 2016 $2.5
 $1.4
 $2.8
 $(119.0) $0.7
 $0.7
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 17.8
 5.7
 2.0
 (0.5) 2.2
 4.5
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 16.1
 —
 —
 —
 —
 —
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (17.2) —
 —
 —
 —
 —
Settlements (28.8) (12.2) (4.3) 2.1
 (2.6) (4.9)
Transfers into Level 3 (c) (d) 5.2
 —
 —
 —
 —
 —
Transfers out of Level 3 (d) (8.3) —
 —
 —
 —
 —
Changes in Fair Value Allocated to Regulated Jurisdictions (e) (5.8) (0.7) 1.5
 (7.2) 0.1
 0.2
Balance as of March 31, 2017 $(18.5) $(5.8) $2.0
 $(124.6) $0.4
 $0.5


(a)Included in revenues on the statements of income.
(b)Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(c)Represents existing assets or liabilities that were previously categorized as Level 2.
(d)Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
(e)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 assets/liabilities.






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


AEP
Significant Unobservable Inputs
MarchJune 30, 2021
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInputLowHighAverage
(in millions)
Energy Contracts$141.7 $134.8 Discounted Cash FlowForward Market Price (a) (c)$0.05 $96.20 $31.99 
Natural Gas Contracts3.1 0 Discounted Cash FlowForward Market Price (b) (c)2.28 3.82 3.14 
FTRs96.4 5.2 Discounted Cash FlowForward Market Price (a) (c)(18.06)12.15 0.22 
Total$241.2 $140.0 

December 31, 20182020
AEP
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInputLowHighAverage
(in millions)
Energy Contracts$213.5 $169.7 Discounted Cash FlowForward Market Price (a) (c)$5.33 $100.47 $32.73 
Natural Gas Contracts0 1.7 Discounted Cash FlowForward Market Price (b) (c)2.18 2.77 2.40 
FTRs42.8 3.4 Discounted Cash FlowForward Market Price (a) (c)(15.08)9.66 0.19 
Other Investments31.8 0 Black-Scholes ModelLiquidity Adjustment (d)10 %20 %15 %
Total$288.1 $174.8 
211




     Significant Input/Range
 Fair ValueValuation Unobservable     Weighted
 Assets LiabilitiesTechnique Input Low High Average
 (in millions)          
Energy Contracts$226.0
 $178.3
 Discounted Cash Flow  Forward Market Price (a)  $8.54
 $202.55
 $34.74
       Counterparty Credit Risk (b)  9
 501
 179
Natural Gas Contracts—
 0.6
 Discounted Cash Flow Forward Market Price (c) 2.33
 2.96
 2.59
FTRs20.4
 5.5
 Discounted Cash Flow  Forward Market Price (a)  (9.68) 8.81
 0.28
Total$246.4
 $184.4
      
  
  

APCo
Significant Unobservable Inputs
June 30, 2021
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (c)
(in millions)
Energy Contracts$0.3 $0.7 Discounted Cash FlowForward Market Price$16.26 $55.49 $32.70 
FTRs37.0 0 Discounted Cash FlowForward Market Price(0.22)9.04 1.05 
Total$37.3 $0.7 

December 31, 20172020
AEP
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (c)
(in millions)
Energy Contracts$1.0 $0.6 Discounted Cash FlowForward Market Price$10.84 $41.09 $25.08 
FTRs18.9 0 Discounted Cash FlowForward Market Price0.04 5.61 1.13 
Total$19.9 $0.6 

     Significant Input/Range
 Fair ValueValuation Unobservable     Weighted
 Assets LiabilitiesTechnique Input Low High Average
 (in millions)          
Energy Contracts$225.1
 $233.7
 Discounted Cash Flow  Forward Market Price (a)  $(0.05) $263.00
 $36.32
       Counterparty Credit Risk (b)  8
 456
 180
Natural Gas Contracts—
 0.2
 Discounted Cash Flow Forward Market Price (c) 2.37
 2.96
 2.62
FTRs53.7
 4.6
 Discounted Cash Flow  Forward Market Price (a)  (55.62) 54.88
 0.41
Total$278.8
 $238.5
      
  
  



I&M
Significant Unobservable Inputs
MarchJune 30, 2021
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (c)
(in millions)
Energy Contracts$0.1 $0.4 Discounted Cash FlowForward Market Price$16.26 $55.49 $32.70 
FTRs8.8 1.2 Discounted Cash FlowForward Market Price(1.03)5.56 0.55 
Total$8.9 $1.6 

December 31, 20182020
APCo
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (c)
(in millions)
Energy Contracts$0.6 $0.3 Discounted Cash FlowForward Market Price$10.84 $41.09 $25.08 
FTRs1.9 0.1 Discounted Cash FlowForward Market Price(1.96)3.69 0.33 
Total$2.5 $0.4 
212




     Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
Energy Contracts$2.5
 $0.3
 Discounted Cash Flow  Forward Market Price  $20.56
 $46.25
 $33.30
FTRs7.9
 1.0
 Discounted Cash Flow  Forward Market Price  (0.30) 6.36
 1.14
Total$10.4
 $1.3
      
  
  

OPCo
Significant Unobservable Inputs
June 30, 2021
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (c)
(in millions)
Energy Contracts$0 $105.4 Discounted Cash FlowForward Market Price$10.58 $49.85 $27.10 

December 31, 20172020
APCo
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (c)
(in millions)
Energy Contracts$0 $110.3 Discounted Cash FlowForward Market Price$16.19 $46.98 $28.30 

     Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
Energy Contracts$0.8
 $0.4
 Discounted Cash Flow  Forward Market Price  $20.52
 $195.00
 $33.80
FTRs24.3
 —
 Discounted Cash Flow  Forward Market Price  (0.36) 7.15
 1.62
Total$25.1
 $0.4
      
  
  

PSO
Significant Unobservable Inputs
MarchJune 30, 2021
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (c)
(in millions)
FTRs$23.1 $0.2 Discounted Cash FlowForward Market Price$(10.36)$0.62 $(2.03)

December 31, 20182020
I&M
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (c)
(in millions)
FTRs$10.3 $0 Discounted Cash FlowForward Market Price$(6.93)$0.48 $(1.93)
213




       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
Energy Contracts$1.5
 $1.3
 Discounted Cash Flow  Forward Market Price  $20.56
 $46.25
 $33.30
FTRs3.6
 0.9
 Discounted Cash Flow  Forward Market Price  (0.35) 5.74
 0.77
Total$5.1
 $2.2
      
  
  

SWEPCo
Significant Unobservable Inputs
June 30, 2021
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInputLowHighAverage (c)
(in millions)
Natural Gas Contracts$3.1 $0 Discounted Cash FlowForward Market Price (b)$2.70 $3.82 $3.15 
FTRs11.9 0.4 Discounted Cash FlowForward Market Price (a)(10.36)0.62 (2.03)
Total$15.0 $0.4 

December 31, 20172020
I&M
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInputLowHighAverage (c)
(in millions)
Natural Gas Contracts$0 $1.7 Discounted Cash FlowForward Market Price (b)$2.18 $2.77 $2.41 
FTRs3.3 0 Discounted Cash FlowForward Market Price (a)(6.93)0.48 (1.93)
Total$3.3 $1.7 

       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
Energy Contracts$0.5
 $0.3
 Discounted Cash Flow  Forward Market Price  $20.52
 $195.00
 $33.80
FTRs8.6
 1.2
 Discounted Cash Flow  Forward Market Price  (0.36) 5.75
 0.86
Total$9.1
 $1.5
      
  
  
(a)Represents market prices in dollars per MWh.

(b)Represents market prices in dollars per MMBtu.

(c)The weighted average is the product of the forward market price of the underlying commodity and volume weighted by term.

(d)Represents percentage discount applied to the publically available share price.
Significant Unobservable Inputs
March 31, 2018
OPCo
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input Low High Average
 (in millions)          
Energy Contracts$—
 $98.5
 Discounted Cash Flow  Forward Market Price (a) $27.42
 $62.16
 $43.76
       Counterparty Credit Risk (b)  9
 202
 144
Total$—
 $98.5
          

Significant Unobservable Inputs
December 31, 2017
OPCo
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input Low High Average
 (in millions)          
Energy Contracts$—
 $132.4
 Discounted Cash Flow  Forward Market Price (a) $30.52
 $170.43
 $44.62
 

 

   Counterparty Credit Risk (b)  8
 190
 136
Total$—
 $132.4
      
  
  

Significant Unobservable Inputs
March 31, 2018
PSO
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
FTRs$2.9
 $0.1
 Discounted Cash Flow  Forward Market Price  $(9.68) $1.39
 $(0.76)

Significant Unobservable Inputs
December 31, 2017
PSO
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
FTRs$6.4
 $0.2
 Discounted Cash Flow  Forward Market Price  $(6.62) $1.41
 $(0.76)



Significant Unobservable Inputs
March 31, 2018
SWEPCo
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input Low High Average
 (in millions)          
Natural Gas Contracts$—
 $0.6
 Discounted Cash Flow Forward Market Price (c) $2.33
 $2.96
 $2.59
FTRs2.6
 1.1
 Discounted Cash Flow  Forward Market Price (a) (9.68) 1.39
 (0.76)
Total$2.6
 $1.7
          

Significant Unobservable Inputs
December 31, 2017
SWEPCo
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input Low High Average
 (in millions)          
Natural Gas Contracts$—
 $0.2
 Discounted Cash Flow Forward Market Price (c) $2.37
 $2.96
 $2.62
FTRs6.7
 0.6
 Discounted Cash Flow  Forward Market Price (a) (6.62) 1.41
 (0.76)
Total$6.7
 $0.8
          

(a)Represents market prices in dollars per MWh.
(b)Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points.
(c)Represents market prices in dollars per MMBtu.


The following table provides sensitivitythe measurement uncertainty of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts, Natural Gas Contracts, FTRs and FTRsOther Investments for the Registrants as of March 31, 2018June 30, 2021 and December 31, 2017:2020:


SensitivityUncertainty of Fair Value Measurements
Significant Unobservable InputPositionChange in Input
Impact on Fair Value

Measurement
Forward Market PriceBuyIncrease (Decrease)Higher (Lower)
Forward Market PriceSellIncrease (Decrease)Lower (Higher)
Counterparty Credit RiskLiquidity AdjustmentLossBuyIncrease (Decrease)Higher (Lower)
Counterparty Credit RiskGainIncrease (Decrease)Lower (Higher)

214





11.  INCOME TAXES


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

Federal Tax Reform

In December 2017, legislation referred to as Tax Reform was signed into law. Tax Reform includes significant changes to the Internal Revenue Code of 1986, as amended, (the Code) and had a material impact on the Registrants’ financial statements in the reporting period of its enactment. Tax Reform lowered the corporate federal income tax rate from 35% to 21%. Tax Reform provisions related to regulated public utilities generally allow for the continued deductibility of interest expense, eliminate bonus depreciation for certain property acquired after September 27, 2017 and continue certain rate normalization requirements for accelerated depreciation benefits.

Provisional Amounts

The Registrants applied Staff Accounting Bulletin 118 (SAB 118), issued by the SEC staff in December 2017, and made reasonable estimates for the measurement and accounting of the effects of Tax Reform which are reflected in the financial statements as provisional amounts based on the best information available. SAB 118 provides for up to a one year period to complete the required analysis and accounting for Tax Reform referred to as the measurement period. While the Registrants were able to make reasonable estimates of the impact of Tax Reform in 2017, the final impact may differ from the recorded provisional amounts to the extent refinements are made to the estimated cumulative differences or as a result of additional guidance or technical corrections that may be issued by the IRS that may impact management’s interpretation and assumptions utilized. The measurement period adjustments recorded during the first quarter of 2018 to the provisional amounts were immaterial. The Registrants expect to complete the analysis of the provisional items during the second half of 2018.

Reduction in the Corporate Federal Income Tax Rate - Pending Rate Reductions

State utility commissions have issued orders or instructions requiring public utilities, including the Registrants, to record liabilities to reflect the impact of the reduction in the corporate federal income tax rate in excess of the enacted corporate federal income tax rate of 21% beginning in 2018. The following table provides a summary of the estimated provisions for revenue refund recorded by the Registrants related to the reduction in the corporate federal tax rate as of and for the three months ended March 31, 2018:
  AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
  (in millions)
Decrease in Total Revenues $(119.5) $(7.6) $(19.0) $(35.4) $(17.8) $(21.3) $(3.8) $(11.0)
Increase in Current Liabilities 33.9
 —
 16.2
 7.8
 3.0
 6.2
 —
 —
Increase in Deferred Credits and Other Noncurrent Liabilities 85.6
 7.6
 2.8
 27.6
 14.8
 15.1
 3.8
 11.0

Excess Accumulated Deferred Income Taxes - Pending Rate Reductions

As of March 31, 2018, the Registrants have approximately $4.4 billion of Excess ADIT, as well as an incremental liability of $1.2 billion to reflect the $4.4 billion Excess ADIT on a pre-tax basis, presented in Regulatory Liabilities and Deferred Investment Tax Credits on the balance sheets.  The Excess ADIT is reflected on a pretax basis to appropriately contemplate future tax consequences in the periods when the regulatory liability is settled.  As of March 31, 2018, approximately $3.4 billion of the Excess ADIT relates to temporary differences associated with depreciable property subject to rate normalization requirements.

As reflected in the Registrants’ respective estimated annual ETR for 2018, AEP’s regulated public utilities began amortizing the excess accumulated deferred income taxes (Excess ADIT) associated with certain depreciable property subject to rate normalization requirements using the ARAM during the first quarter of 2018. The amortization resulted in a reduction in the Excess ADIT balance recorded in Regulatory Liabilities and Deferred Investment Tax Credits and a reduction in Income Tax Expense. As a result of state utility commission orders or instructions, in the first quarter


of 2018 the Registrants recorded estimated provisions for revenue refund offsetting the amortization of the Excess ADIT as shown in the table below:
  AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
  (in millions)
Decrease in Total Revenues $(17.2) $(2.1) $(0.1) $(4.6) $(1.7) $(1.4) $(2.2) $(3.5)
Increase in Deferred Credits and Other Noncurrent Liabilities 17.2
 2.1
 0.1
 4.6
 1.7
 1.4
 2.2
 3.5

In addition, with respect to the remaining $1 billion of Excess ADIT recorded in Regulatory Liabilities and Deferred Investment Tax Credits that are not subject to rate normalization requirements, the Registrants continue to work with the various state utility commissions to determine the appropriate mechanism and time period to provide these benefits of Tax Reform to customers. The corresponding reduction in Income Tax Expense will be reported in the interim period in which these benefits of Tax Reform are provided to customers.


Effective Tax Rates (ETR)


The Registrants’ interim ETR reflect the estimated annual ETR for 20182021 and 2017,2020, adjusted for tax expense associated with certain discrete items. As previously mentioned, effective January 1, 2018, Tax Reform lowered the corporate tax rate from 35% to 21%.

The interim ETR differ from the federal statutory tax rate of 21% and 35% in 2018 and 2017, respectively, primarily due to state income taxes,Registrants include the amortization of Excess ADIT not subject to normalization requirements in the excess accumulated deferredannual estimated ETR when regulatory proceedings instruct the Registrants to provide the benefits of Tax Reform to customers over multiple interim periods.  Certain regulatory proceedings instruct the Registrants to provide the benefits of Tax Reform to customers in a single period (e.g. by applying the Excess ADIT not subject to normalization requirements against an existing regulatory asset balance) and in these circumstances, the Registrants recognize the tax benefit discretely in the period recorded. The annual amount of Excess ADIT approved by the Registrant’s regulatory commissions may not impact the ETR ratably during each interim period due to the variability of pretax book income taxes associated with certain depreciable property usingbetween interim periods and the ARAM, tax credits and other book/tax differences which are accounted for on a flow-through basis.application of an annual estimated ETR.


The ETR for each of the Registrants are included in the following table. Significant variances in the ETR are described below.tables:
Three Months Ended June 30, 2021
AEPAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
U.S. Federal Statutory Rate21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %
Increase (decrease) due to:
State Income Tax, net of Federal Benefit0.8 %(0.4)%2.6 %0.9 %1.6 %0.7 %4.4 %1.9 %
Tax Reform Excess ADIT Reversal(9.1)%(7.9)%0.3 %(11.8)%(20.4)%(8.6)%(20.1)%(1.9)%
Production and Investment Tax Credits(4.7)%(0.3)%0 %0 %(3.3)%0 %(6.8)%(1.4)%
Flow Through0.4 %0.4 %0.4 %3.3 %(5.8)%1.0 %0.8 %0.5 %
AFUDC Equity(1.2)%(0.9)%(1.7)%(0.5)%(2.2)%(0.9)%(0.7)%(0.8)%
Parent Company Loss Benefit0 %(0.7)%(1.7)%1.0 %(1.7)%0 %0 %(1.9)%
Discrete Tax Adjustments2.9 %0 %0 %0 %0 %0 %(2.6)%0 %
Other(0.5)%(0.2)%(0.1)%0 %(0.5)%(0.1)%(0.1)%(1.2)%
Effective Income Tax Rate9.6 %11.0 %20.8 %13.9 %(11.3)%13.1 %(4.1)%16.2 %
Three Months Ended June 30, 2020
AEPAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
U.S. Federal Statutory Rate21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %
Increase (decrease) due to:
State Income Tax, net of Federal Benefit2.7 %1.8 %2.9 %3.2 %3.6 %0.7 %4.6 %2.1 %
Tax Reform Excess ADIT Reversal(16.4)%(57.9)%0.4 %(32.5)%(12.6)%(9.3)%(20.9)%(6.3)%
Production and Investment Tax Credits(4.6)%(0.5)%0 %0 %(1.2)%0 %(1.2)%(0.4)%
Flow Through0.5 %0.2 %0.5 %1.9 %0.1 %0.9 %0.3 %(1.2)%
AFUDC Equity(1.5)%(3.3)%(2.6)%(1.3)%(0.7)%(0.8)%(0.6)%(0.3)%
Parent Company Loss Benefit0 %0.2 %(0.8)%(2.9)%(3.3)%(0.4)%(1.8)%(1.7)%
Other0.7 %0 %(0.6)%(0.2)%0 %0.1 %0.1 %(1.3)%
Effective Income Tax Rate2.4 %(38.5)%20.8 %(10.8)%6.9 %12.2 %1.5 %11.9 %
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  Three Months Ended 
 March 31,
Company 2018 2017
AEP 18.3% 36.7%
AEP Texas 16.3% 34.7%
AEPTCo 20.8% 33.3%
APCo 18.2% 36.5%
I&M 16.2% 29.9%
OPCo 20.5% 34.9%
PSO 16.3% 37.7%
SWEPCo 18.4% 37.3%
Six Months Ended June 30, 2021
AEPAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
U.S. Federal Statutory Rate21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %
Increase (decrease) due to:
State Income Tax, net of Federal Benefit1.6 %0.3 %2.7 %2.4 %1.4 %0.7 %4.4 %0.3 %
Tax Reform Excess ADIT Reversal(9.1)%(7.9)%0.3 %(15.7)%(19.0)%(9.1)%(19.9)%(4.3)%
Production and Investment Tax Credits(5.1)%(0.3)%0 %0 %(2.3)%0 %(6.6)%(3.7)%
Flow Through0.3 %0.3 %0.3 %2.2 %(3.0)%1.1 %0.8 %(0.2)%
AFUDC Equity(1.1)%(1.1)%(1.7)%(0.9)%(1.0)%(1.0)%(0.7)%(0.6)%
Parent Company Loss Benefit0 %(0.4)%(1.8)%(1.4)%(2.1)%0 %0 %(0.8)%
Discrete Tax Adjustments1.7 %0 %0 %0 %0 %(1.8)%(2.8)%0 %
Other(0.2)%0 %0 %0.1 %(0.3)%(0.1)%0 %(0.4)%
Effective Income Tax Rate9.1 %11.9 %20.8 %7.7 %(5.3)%10.8 %(3.8)%11.3 %

Six Months Ended June 30, 2020
AEPAEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
U.S. Federal Statutory Rate21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %
Increase (decrease) due to:
State Income Tax, net of Federal Benefit2.6 %1.7 %2.9 %3.1 %3.4 %0.7 %4.6 %2.2 %
Tax Reform Excess ADIT Reversal(12.8)%(30.4)%0.4 %(20.2)%(16.7)%(9.7)%(20.3)%(17.0)%
Production and Investment Tax Credits(4.4)%(0.4)%0 %0 %(1.6)%0 %(1.1)%(0.4)%
Flow Through0.5 %0.1 %0.5 %1.6 %0.2 %0.9 %0.2 %(1.1)%
AFUDC Equity(1.5)%(2.9)%(2.6)%(1.1)%(0.9)%(0.9)%(0.6)%(0.3)%
Parent Company Loss Benefit0 %0 %(0.9)%(3.1)%(3.7)%(0.3)%(1.7)%(1.8)%
Discrete Tax Adjustments0 %0 %0 %0 %1.6 %0 %0 %0 %
Other0.1 %0.1 %(0.2)%0 %(0.1)%0.1 %0.1 %(0.3)%
Effective Income Tax Rate5.5 %(10.8)%21.1 %1.3 %3.2 %11.8 %2.2 %2.3 %
AEP

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

The decrease in the ETR is primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and increased 2018 amortization of Excess ADIT associated with certain depreciable property using the ARAM.

AEP Texas

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

The decrease in the ETR is primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and increased 2018 amortization of Excess ADIT associated with certain depreciable property using the ARAM.



AEPTCo

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

The decrease in the ETR is primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform.

APCo

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

The decrease in the ETR is primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and increased 2018 amortization of Excess ADIT associated with certain depreciable property using the ARAM.

I&M

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

The decrease in the ETR is primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, increased 2018 amortization of excess accumulated deferred income taxes associated with certain depreciable property using the ARAM, and decreased state income taxes resulting from elimination of bonus depreciation for certain property acquired after September 27, 2017.  These decreases were partially offset by an increase in book/tax differences which are accounted for on a flow-through basis resulting from a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028.

OPCo

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

The decrease in the ETR is primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform.

PSO

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

The decrease in the ETR is primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and increased 2018 amortization of Excess ADIT associated with certain depreciable property using the ARAM.

SWEPCo

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

The decrease in the ETR is primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and increased 2018 amortization of Excess ADIT associated with certain depreciable property using the ARAM.



Federal and State Income Tax Audit Status


The statute of limitations for the IRS to examine AEP and subsidiaries are no longer subject to U.S.originally filed federal examinationreturn has expired for tax years before 2011.  The IRS examination2016 and earlier. In the third quarter of years 2011 through 2013 started in April 2014.2019, AEP and subsidiaries received a Revenue Agents Reportelected to amend the 2014 and 2015 federal returns. In the first quarter of 2020, the IRS notified AEP that it was beginning an examination of these amended returns, including the net operating losses (NOL) carryback to 2015 that originated in April 2016, completing the 2011 through 20132017 return. As of June 30, 2021, the IRS has not challenged any items on these returns and the IRS is limited in their proposed adjustments to the amount AEP claimed on the amended returns. AEP has agreed to extend the statute of limitations on the 2017 tax return to December 31, 2022 to allow time for the audit cycle indicating an agreed upon audit.  The 2011 through 2013 audit was submitted to be completed and the Congressional Joint Committee on Taxation for approval. The Joint Committee referredto approve the audit back to the IRS exam team for further consideration.  To resolve the issue under consideration, AEP and subsidiaries and the IRS exam team agreed to utilize the Fast Track Settlement Program in December 2017. The program was completed in March 2018 and tax years 2014 and 2015 were added to the IRS examination to reflect the impact of the Fast Track changes that were carried forward to 2014 and 2015.associated refund claim.

Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters.  In addition, the Registrants accrue interest on these uncertain tax positions.  Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income.


AEP and subsidiaries file income tax returns in various state and local or foreign jurisdictions. These taxing authorities routinely examine the tax returns.returns, and AEP and subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities.  Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income.  The Registrants are no longer subject to state local or non-U.S. income taxlocal examinations by tax authorities for years before 2009.2012. In addition, management is monitoring and continues to evaluate the potential impact of federal legislation and corresponding state conformity.

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Federal Legislation

In March 2020, the CARES Act was signed into law. The CARES Act includes tax relief provisions including a 5-year NOL carryback from years 2018-2020. In the third quarter of 2020, AEP requested a $95 million refund of taxes paid in 2014 under the 5-year NOL carryback provision of the CARES Act. AEP carried back a NOL generated on the 2019 Federal income tax return at a 21% federal corporate income tax rate to the 2014 Federal income tax return at a 35% corporate income tax rate. As a result of the change in the corporate income tax rates between the two periods, AEP realized a tax benefit of $48 million primarily at the Generation & Marketing segment in 2020. Management expects to receive the $95 million refund in the third quarter of 2021.

State Tax Legislation (Applies to AEP, AEPTCo, I&M and OPCo)


In April 2018, the Kentucky legislature2021, West Virginia enacted House Bill 366 (HB 366) adopting significant(H.B.) 2026. H.B. 2026 changes to Kentucky's corporatethe state income tax code.  HB 366 amended and reduced the corporate tax rate from a graduated rate with a maximum 6% rate to a single 5% corporate tax rate.  HB 366 also modified the apportionment formula from a traditional three-factor formula ofratio that includes property, payroll and double weighted sales to a single sales factor apportionment.  The corporate income tax changes under HB 366 areapportionment regime effective for tax years beginning on or after January 1, 2018.2022. H.B. 2026 also eliminates the “throw out” rule related to sales of tangible personal property for sales factor apportionment calculation purposes and introduces a market-based sourcing for sales of services and intangible property. In the second quarter of 2021, AEP recorded $20 million in Income Tax Expense as a result of remeasuring West Virginia deferred taxes under the new apportionment methodology. The enacted legislation isdoes not expectedimpact AEP Texas, PSO or SWEPCo.

In May 2021, Oklahoma enacted House Bill (H.B.) 2960. H.B. 2960 reduces the Oklahoma corporate income tax rate from 6% to materially4%. In the second quarter of 2021, AEP recorded a $1 million Income Tax Benefit as a result of remeasuring Oklahoma deferred taxes at the lowered statutory tax rate of 4%. The enacted legislation does not impact net income, cash flowsAPCo, I&M or financial condition.OPCo.

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12.  FINANCING ACTIVITIES


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


Common Stock (Applies to AEP)

At-the-Market (ATM) Program

In 2020, AEP filed a prospectus supplement and executed an Equity Distribution Agreement, pursuant to which AEP may sell, from time to time, up to an aggregate of $1 billion of its common stock through an ATM offering program, including an equity forward sales component. The compensation paid to the selling agents by AEP may be up to 2% of the gross offering proceeds of the shares. For the six months ended June 30, 2021, AEP issued 2,355,305 shares of common stock and received net cash proceeds of $195 million under the ATM program.

Long-term Debt Outstanding (Applies to AEP)


The following table details long-term debt outstanding:outstanding, net of issuance costs and premiums or discounts:
Type of DebtJune 30, 2021December 31, 2020
 (in millions)
Senior Unsecured Notes$26,778.5 $25,116.1 
Pollution Control Bonds1,880.2 1,936.7 
Notes Payable260.7 239.1 
Securitization Bonds663.7 716.4 
Spent Nuclear Fuel Obligation (a)281.2 281.2 
Junior Subordinated Notes (b)1,628.0 1,624.1 
Other Long-term Debt1,625.5 1,158.9 
Total Long-term Debt Outstanding33,117.8 31,072.5 
Long-term Debt Due Within One Year2,458.5 2,086.1 
Long-term Debt$30,659.3 $28,986.4 
Type of Debt March 31, 2018 December 31, 2017
  (in millions)
Senior Unsecured Notes $17,004.6
 $16,478.3
Pollution Control Bonds 1,540.4
 1,621.7
Notes Payable 230.2
 260.8
Securitization Bonds 1,285.9
 1,416.5
Spent Nuclear Fuel Obligation (a) 269.5
 268.6
Other Long-term Debt 1,130.4
 1,127.4
Total Long-term Debt Outstanding 21,461.0
 21,173.3
Long-term Debt Due Within One Year 2,616.1
 1,753.7
Long-term Debt $18,844.9
 $19,419.6


(a)Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for SNF disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $327 million and $324 million as of June 30, 2021 and December 31, 2020, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.
(a)Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal.  The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983.  Trust fund assets related to this obligation were $313 million and $312 million as of March 31, 2018 and December 31, 2017, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.

(b)See “Equity Units” section below for additional information.

Long-term Debt Activity


Long-term debt and other securities issued, retired and principal payments made during the first threesix months of 20182021 are shown in the tables below:following tables:
PrincipalInterest
CompanyType of DebtAmount (a)RateDue Date
Issuances: (in millions)(%)
AEP TexasSenior Unsecured Notes$450.0 3.452051
APCoSenior Unsecured Notes500.0 2.702031
I&MNotes Payable64.9 0.932025
I&MSenior Unsecured Notes450.0 3.252051
OPCoSenior Unsecured Notes450.0 1.632031
PSOOther Long-term Debt500.0 Variable2022
SWEPCoSenior Unsecured Notes500.0 1.652026
Non-Registrant:
KPCoOther Long-term Debt150.0 Variable2023
Transource EnergyOther Long-term Debt17.8 Variable2023
Total Issuances$3,082.7 

(a)Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
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Company Type of Debt Principal Amount (a) Interest Rate Due Date
Issuances:   (in millions) (%)  
OPCo Senior Unsecured Notes $400.0
 4.15 2048
SWEPCo Senior Unsecured Notes 450.0
 3.85 2048
         
Non-Registrant:        
Transource Energy Other Long-term Debt 3.4
 Variable 2020
Total Issuances   $853.4
    


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

PrincipalInterest
CompanyType of DebtAmount PaidRateDue Date
Retirements and Principal Payments:(in millions)(%)
AEP TexasSecuritization Bonds$29.7 2.852024
AEP TexasSecuritization Bonds11.2 2.062025
APCoSenior Unsecured Notes350.0 4.602021
APCoPollution Control Bonds17.5 4.632021
APCoSecuritization Bonds12.5 2.012023
I&MNotes Payable1.9 Variable2021
I&MOther Long-term Debt200.0 Variable2021
I&MPollution Control Bonds40.0 2.052021
I&MNotes Payable3.0 Variable2022
I&MNotes Payable4.2 Variable2022
I&MNotes Payable9.6 Variable2023
I&MNotes Payable9.0 Variable2024
I&MOther Long-term Debt1.0 6.002025
I&MNotes Payable13.0 Variable2025
I&MNotes Payable1.0 0.932025
OPCoOther Long-term Debt0.1 1.152028
PSOSenior Unsecured Notes250.0 4.402021
PSOOther Long-term Debt0.3 3.002027
SWEPCoOther Long-term Debt1.5 4.682028
SWEPCoNotes Payable1.6 4.582032
Non-Registrant:
KPCoSenior Unsecured Notes39.8 7.252021
Transource EnergySenior Unsecured Notes1.2 2.752050
Total Retirements and Principal Payments$998.1 

Company Type of Debt  Principal Amount Paid Interest Rate Due Date
Retirements and Principal Payments:   (in millions) (%)  
AEP Texas Securitization Bonds $70.0
 5.17 2018
AEP Texas Securitization Bonds 26.5
 5.306 2020
APCo Securitization Bonds 11.7
 2.008 2023
I&M Notes Payable 0.8
 Variable 2019
I&M Notes Payable 7.9
 Variable 2019
I&M Notes Payable 4.8
 Variable 2020
I&M Notes Payable 8.5
 Variable 2021
I&M Notes Payable 7.0
 Variable 2022
I&M Other Long-term Debt 0.4
 6.00 2025
OPCo Securitization Bonds 22.9
 2.049 2019
PSO Other Long-term Debt 0.1
 3.00 2027
SWEPCo Pollution Control Bonds 81.7
 4.95 2018
SWEPCo Senior Unsecured Notes 300.0
 5.875 2018
SWEPCo Other Long-term Debt 0.1
 3.50 2023
SWEPCo Notes Payable 1.6
 4.58 2032
Total Retirements and Principal Payments   $544.0
    


As of March 31, 2018,June 30, 2021, trustees held, on behalf of AEP, $678I&M, $40 million of theirits reacquired Pollution Control Bonds. Of this total, $104 million and $345 million related to APCo and OPCo, respectively.


Long-term Debt Subsequent Events

In April 2018, AEP Texas retired $30 million of 5.89% Senior Unsecured Notes due in 2018.

In April 2018,July 2021, I&M retired $2$8 million of Notes Payable related to DCC Fuel.



Equity Units (Applies to AEP)

2020 Equity Units

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

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

Each forward equity purchase contract obligates the holder to purchase, and AEP to sell, for $50 a number of shares in common stock in accordance with the conversion ratios set forth below (subject to an anti-dilution adjustment):
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•If the AEP common stock market price is equal to or greater than $99.95: 0.5003 shares per contract.
•If the AEP common stock market price is less than $99.95 but greater than $83.29: a number of shares per contract equal to $50 divided by the applicable market price. The holder receives a variable number of shares at $50.
•If the AEP common stock market price is less than or equal to $83.29: 0.6003 shares per contract.

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

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

2019 Equity Units

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

Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 3.40% Junior Subordinated Notes (notes) due in 2024 and a forward equity purchase contract which settles after three years in 2022. The notes are expected to be remarketed in 2022, at which time the interest rate will reset at the then current market rate. Investors may choose to remarket their notes to receive the remarketing proceeds and use those funds to settle the forward equity purchase contract, or accept the remarketed debt and use other funds for the equity purchase. If the remarketing is unsuccessful, investors have the right to put their notes to AEP at a price equal to the principal. The Equity Units carry an annual distribution rate of 6.125%, which is comprised of a quarterly coupon rate of interest of 3.40% and a quarterly forward equity purchase contract payment of 2.725%.

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

•If the AEP common stock market price is equal to or greater than $99.58: 0.5021 shares per contract.
•If the AEP common stock market price is less than $99.58 but greater than $82.98: a number of shares per contract equal to $50 divided by the applicable market price. The holder receives a variable number of shares at $50.
•If the AEP common stock market price is less than or equal to $82.98: 0.6026 shares per contract.

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

At the time of issuance, the $805 million of notes were recorded within Long-term Debt on the balance sheets. The present value of the purchase contract payments of $62 million were recorded in Deferred Credits and Other
220




Noncurrent Liabilitieswith a current portion in Other Current Liabilities at the time of issuance, representing the obligation to make forward equity contract payments, with an offsetting reduction to Paid-in Capital. The difference between the face value and present value of the purchase contract payments will be accreted to Interest Expense on the statements of income over the three year period ending in 2022. The liability recorded for the contract payments is considered non-cash and excluded from the statements of cash flows. Until settlement of the forward equity purchase contract, earnings per share dilution resulting from the equity unit issuance will be determined under the treasury stock method. The maximum amount of shares AEP will be required to issue to settle the purchase contract is 9,701,860 shares (subject to an anti-dilution adjustment).

Debt Covenants (Applies to AEP and AEPTCo)


Covenants in AEPTCo’s note purchase agreements and indenture limit the amount of contractually-defined priority debt (which includes a further sub-limit of $50 million of secured debt) to 10% of consolidated tangible net assets. AEPTCo’s contractually-defined priority debt was 4.5%2.5% of consolidated tangible net assets as of March 31, 2018.June 30, 2021. The method for calculating the consolidated tangible net assets is contractually definedcontractually-defined in the note purchase agreements.


Dividend Restrictions


Utility Subsidiaries’ Restrictions


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


All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, theThe Federal Power Act also creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M.


Certain AEP subsidiaries have credit agreements that contain covenants that limit their debt to capitalization ratio to 67.5%. The method for calculating outstanding debt and capitalization is contractually definedcontractually-defined in the credit agreements.


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


Parent Restrictions (Applies to AEP)


The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries.


Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The method for calculating outstanding debt and capitalization is contractually definedcontractually-defined in the credit agreements.

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


The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries,subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries,subsidiaries; and direct borrowing from AEP. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Poolits agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of March 31, 2018June 30, 2021 and December 31, 20172020 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and corresponding authorized borrowing limits for the threesix months ended March 31, 2018June 30, 2021 are described in the following table:
MaximumAverageNet Loans to
BorrowingsMaximumBorrowingsAverage(Borrowings) fromAuthorized
from theLoans to thefrom theLoans to thethe Utility MoneyShort-term
UtilityUtilityUtilityUtilityPool as ofBorrowing
CompanyMoney PoolMoney PoolMoney PoolMoney PoolJune 30, 2021Limit
 (in millions)
AEP Texas$355.5 $104.7 $234.7 $73.1 $47.4 $500.0 
AEPTCo357.7 10.6 260.7 1.9 (257.8)820.0 (a)
APCo27.8 616.9 13.2 136.0 91.7 500.0 
I&M166.5 368.2 117.5 58.1 99.9 500.0 
OPCo259.2 222.4 59.5 102.6 (56.3)500.0 
PSO267.7 210.1 156.1 122.0 (135.1)300.0 
SWEPCo280.3 156.4 170.6 142.0 (122.0)350.0 
Company 
Maximum
Borrowings
from the
Utility
Money Pool
 
Maximum
Loans to the
Utility
Money Pool
 
Average
Borrowings
from the
Utility
Money Pool
 
Average
Loans to the
Utility
Money Pool
 
Net Loans to
(Borrowings from)
the Utility Money
Pool as of
March 31, 2018
 
Authorized
Short-term
Borrowing
Limit
 
  (in millions)
AEP Texas $307.2
 $103.6
 $219.2
 $50.4
 $(232.7) $500.0
 
AEPTCo 337.3
 123.9
 188.2
 26.3
 (272.8) 795.0
(a)
APCo 285.6
 23.7
 223.6
 23.5
 (222.4) 600.0
 
I&M 314.1
 12.5
 240.6
 12.5
 (301.6) 500.0
 
OPCo 229.1
 216.4
 104.9
 179.5
 200.4
 400.0
 
PSO 179.1
 —
 143.3
 —
 (179.1) 300.0
 
SWEPCo 169.1
 296.5
 143.7
 273.2
 (148.6) 350.0
 


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


The activity in the above table does not include short-term lending activity of certain AEP nonutility subsidiaries. AEP Texas’ wholly-owned subsidiary, AEP Texas North Generation Company, LLC and SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LP are participantsLLC participate in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of March 31, 2018June 30, 2021 and December 31, 20172020 are included in Advances to Affiliates on eachthe subsidiaries’ balance sheets. The Nonutility Money Pool participants’ money pool activity for the threesix months ended March 31, 2018June 30, 2021 is described in the following table:
Maximum Loans Average Loans Loans to the Nonutility
to the Nonutility to the Nonutility Money Pool as of
CompanyMoney PoolMoney PoolJune 30, 2021
(in millions)
AEP Texas$7.1 $6.9 $6.9 
SWEPCo2.1 2.1 2.1 
  Maximum Maximum Average Average Loans to the
  Borrowings from Loans to the Borrowings from Loans to the Nonutility
  the Nonutility Nonutility the Nonutility Nonutility Money Pool as of
Company Money Pool Money Pool Money Pool Money Pool March 31, 2018
  (in millions)
AEP Texas $—
 $8.4
 $—
 $8.2
 $8.1
SWEPCo —
 2.0
 —
 2.0
 2.0


AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of outstanding loans to (borrowings from)and borrowings from AEP as of March 31, 2018June 30, 2021 and December 31, 20172020 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct borrowing and lending activity with AEP and corresponding authorized borrowing limit for the threesix months ended March 31, 2018 isJune 30, 2021 are described in the following table:
Maximum Maximum Average Average Borrowings from Loans toAuthorized
Borrowings Loans Borrowings Loans AEP as of AEP as ofShort-term
from AEP to AEP from AEP to AEP June 30, 2021June 30, 2021Borrowing Limit
(in millions)
$1.5 $224.2 $1.2 $148.5 $1.4 $107.5 $50.0 (a)

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

222
            Authorized 
Maximum Maximum Average Average Borrowings from Loans to Short-term 
Borrowings Loans Borrowings Loans AEP as of AEP as of Borrowing 
from AEP to AEP from AEP to AEP March 31, 2018 March 31, 2018 Limit 
(in millions)
$1.1
 $104.7
 $1.1
 $51.1
 $1.1
 $23.9
 $75.0
(a)


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





The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows:are summarized in the following table:
 Six Months Ended June 30,
20212020
Maximum Interest Rate0.40 %2.70 %
Minimum Interest Rate0.25 %0.33 %
  Three Months Ended March 31,
  2018 2017
Maximum Interest Rate 2.42% 1.27%
Minimum Interest Rate 1.83% 0.92%


The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized for all Registrant Subsidiaries in the following table:
Average Interest Rate for FundsAverage Interest Rate for Funds
Borrowed from the Utility Money PoolLoaned to the Utility Money Pool
for Six Months Ended June 30,for Six Months Ended June 30,
Company2021202020212020
AEP Texas0.33 %1.55 %0.36 %1.97 %
AEPTCo0.33 %1.94 %0.34 %2.06 %
APCo0.28 %2.14 %0.36 %1.62 %
I&M0.32 %1.80 %0.35 %1.87 %
OPCo0.34 %1.80 %0.29 %2.06 %
PSO0.34 %1.71 %0.28 %1.95 %
SWEPCo0.32 %1.87 %0.38 %0 %
  Average Interest Rate Average Interest Rate
  for Funds Borrowed for Funds Loaned
  from the Utility Money Pool for to the Utility Money Pool for
  Three Months Ended March 31, Three Months Ended March 31,
Company 2018 2017 2018 2017
AEP Texas 2.07% 1.02% 1.90% —%
AEPTCo 2.06% 1.08% 1.92% 0.99%
APCo 2.00% 1.04% 2.00% 1.03%
I&M 2.02% 1.04% 2.00% 1.03%
OPCo 2.00% 1.10% 2.40% 0.98%
PSO 2.01% 1.06% —% —%
SWEPCo 2.10% 1.06% 1.88% 0.98%


Maximum, minimum and average interest rates for funds either borrowed from or loaned to the Nonutility Money Pool are summarized in the following tables:table:

Six Months Ended June 30, 2021Six Months Ended June 30, 2020
  Maximum Minimum AverageMaximum Minimum Average
  Interest Rate Interest Rate Interest RateInterest Rate Interest Rate Interest Rate
  for Funds for Funds for Fundsfor Funds for Funds for Funds
 Loaned to Loaned to Loaned toLoaned to Loaned to Loaned to
 the Nonutility the Nonutility the Nonutilitythe Nonutility the Nonutility the Nonutility
Company Money Pool Money Pool Money PoolMoney Pool Money Pool Money Pool
AEP Texas 0.40 %0.25 %0.33 %2.70 %0.33 %1.87 %
SWEPCo 0.40 %0.25 %0.33 %2.70 %0.33 %1.87 %
Three Months Ended March 31, 2018:
  Maximum Minimum Maximum Minimum Average Average
  Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate
  for Funds for Funds for Funds for Funds for Funds for Funds
  Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to
  the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility
Company Money Pool Money PoolMoney Pool Money Pool Money Pool Money Pool
AEP Texas —% —% 2.42% 1.83% —% 2.00%
SWEPCo —% —% 2.42% 1.83% —% 2.00%

Three Months Ended March 31, 2017:
  Maximum Minimum Maximum Minimum Average Average
  Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate
  for Funds for Funds for Funds for Funds for Funds for Funds
  Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to
  the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility
Company Money Pool Money PoolMoney Pool Money Pool Money Pool Money Pool
AEP Texas —% —% 1.27% 0.92% —% 1.03%
SWEPCo —% —% 1.27%.0.92% —% 1.03%


AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table:
 MaximumMinimumMaximumMinimumAverageAverage
 Interest RateInterest RateInterest RateInterest RateInterest RateInterest Rate
Six Months for Fundsfor Fundsfor Fundsfor Fundsfor Fundsfor Funds
Ended BorrowedBorrowedLoanedLoanedBorrowedLoaned
June 30, from AEP from AEPto AEP to AEP from AEP to AEP
2021 0.86 %0.25 %0.86 %0.25 %0.33 %0.33 %
2020 2.70 %0.50 %2.70 %0.50 %1.88 %1.86 %


223
  Maximum Minimum Maximum Minimum Average Average
  Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate
Three Months for Funds for Funds for Funds for Funds for Funds for Funds
Ended Borrowed Borrowed Loaned Loaned Borrowed Loaned
March 31, from AEP from AEPto AEP to AEP from AEP to AEP
2018 2.42% 1.83% 2.42% 1.83% 2.00% 2.02%
2017 1.27% 0.92% 1.27% 0.92% 1.03% 1.04%






Short-term Debt (Applies to AEP and SWEPCo)


Outstanding short-term debt was as follows:
 June 30, 2021December 31, 2020
OutstandingInterestOutstandingInterest
CompanyType of DebtAmountRate (a)AmountRate (a)
 (dollars in millions)
AEPSecuritized Debt for Receivables (b)$578.2 0.20 %$592.0 0.85 %
AEPCommercial Paper2,049.8 0.27 %1,852.3 0.29 %
AEP364-Day Term Loan500.0 0.74 %0 0 %
SWEPCoNotes Payable0 0 %35.0 2.55 %
Total Short-term Debt$3,128.0  $2,479.3  
    March 31, 2018 December 31, 2017
Company Type of Debt 
Outstanding
Amount
 
Interest
Rate (a)
 Outstanding
Amount		 Interest
Rate (a)
    (in millions)  
 (in millions)  
AEP Securitized Debt for Receivables (b) $750.0
 1.74% $718.0
 1.22%
AEP Commercial Paper 1,886.2
 2.41% 898.6
 1.85%
SWEPCo Notes Payable 22.6
 3.20% 22.0
 2.92%
  Total Short-term Debt $2,658.8
  
 $1,638.6
  


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

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

Credit Facilities


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


Securitized Accounts ReceivableReceivables – AEP Credit (Applies to AEP)


AEP Credit has a receivables securitization agreement withthat provides a commitment of $750 million from bank conduits.conduits to purchase receivables and expires in September 2022. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections.


In March 2021, AEP Credit’sCredit amended its receivables securitization agreement providesto extend trigger levels established in October 2020 and to also provide a commitmentstep 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. In June 2021, AEP Credit entered into a waiver for both APCo and SWEPCo to waive certain triggers through August 2021 due to the continuing impact of $750 million from bank conduitsthe COVID-19 pandemic. As of June 30, 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 purchaserely on additional sources of funding for operation and working capital, which may adversely impact liquidity. The receivables and expires in June 2019.that are ineligible under the receivables securitization agreement are financed with short-term debt at AEP Credit.


Accounts receivable information for AEP Credit iswas as follows:
Three Months EndedSix Months Ended
June 30,June 30,
2021202020212020
(dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable0.19 %1.06 %0.20 %1.40 %
Net Uncollectible Accounts Receivable Written-Off$5.8 $3.4 $15.1 $7.6 
 Three Months Ended March 31,
 2018 2017
 (dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable1.74% 1.00%
Net Uncollectible Accounts Receivable Written Off$4.2
 $5.9
June 30, 2021December 31, 2020
(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts$965.0 $958.4 
Short-term – Securitized Debt of Receivables578.2 592.0 
Delinquent Securitized Accounts Receivable62.7 62.3 
Bad Debt Reserves Related to Securitization38.1 60.0 
Unbilled Receivables Related to Securitization304.1 296.8 
  March 31, 2018 December 31, 2017
  (in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $944.5
 $925.5
Short-term – Securitized Debt of Receivables 750.0
 718.0
Delinquent Securitized Accounts Receivable 55.1
 41.1
Bad Debt Reserves Related to Securitization 30.8
 28.7
Unbilled Receivables Related to Securitization 249.9
 303.2


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

224





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


Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder.


The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreements were:
CompanyJune 30, 2021December 31, 2020
 (in millions)
APCo$117.8 $136.0 
I&M164.6 170.5 
OPCo375.8 398.8 
PSO117.6 85.0 
SWEPCo169.0 158.6 
Company March 31, 2018 December 31, 2017
  (in millions)
APCo $139.2
 $136.2
I&M 147.8
 136.5
OPCo 386.2
 367.4
PSO 109.2
 115.1
SWEPCo 130.6
 138.2


The fees paid to AEP Credit for customer accounts receivable sold were:
 Three Months Ended June 30,Six Months Ended June 30,
Company2021 (a)20202021 (a)2020
 (in millions)
APCo$1.2 $1.3 $2.4 $3.0 
I&M1.6 2.6 3.2 5.4 
OPCo(2.4)5.0 (1.1)9.8 
PSO0.6 1.0 1.3 2.3 
SWEPCo1.3 1.9 2.8 4.0 
  Three Months Ended March 31,
Company 2018 2017
  (in millions)
APCo $1.7
 $1.4
I&M 2.1
 1.5
OPCo 5.6
 5.7
PSO 1.8
 1.5
SWEPCo 1.9
 1.6
(a)In 2020, an increase in allowance for doubtful accounts was recognized in response to the anticipated impact of COVID-19 on the collectability of accounts receivable, which caused an increase in fees paid by the registrants. In 2021, due to higher than expected collections of accounts receivables, allowance for doubtful accounts was adjusted resulting in the issuance of credits to offset the higher fees previously paid.


The proceeds on the sale of receivables to AEP Credit were:
 Three Months Ended June 30,Six Months Ended June 30,
Company2021202020212020
(in millions)
APCo$276.0 $285.7 $638.4 $638.3 
I&M463.3 439.9 942.1 911.3 
OPCo597.8 556.7 1,199.1 1,127.0 
PSO323.8 297.3 608.7 592.2 
SWEPCo392.6 381.4 777.0 747.0 

225
  Three Months Ended March 31,
Company 2018 2017
  (in millions)
APCo $400.2
 $369.7
I&M 459.1
 418.2
OPCo 680.0
 632.3
PSO 332.6
 286.8
SWEPCo 397.6
 341.2






13. VARIABLE INTEREST ENTITIESPROPERTY, PLANT AND EQUIPMENT


The disclosuresdisclosure in this note applyapplies to AEP only.and APCo.


Asset Retirement Obligations

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a variable interestRegistrants record ARO in a VIE.  A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined byaccordance with the accounting guidance for “Variable Interest Entities.” In determining whether AEP is“Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the primary beneficiaryretirement of a VIE, management considers whether AEP has the power to direct the mostcertain ash disposal facilities, wind farms, solar farms and certain coal mining facilities. The discussion below summarizes significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significantchanges to the VIE. Management believes that significant assumptionsRegistrants ARO recorded in 2021 and judgments were applied consistently.

Desert Sky Wind Farm LLC (Desert Sky) and Trent Wind Farm LLC (Trent) (collectively “the LLCs”) were established forshould be read in conjunction with the purpose of repowering, owning and operating approximately 310.5 MW of wind-powered electric energy generation facilities in Texas. In January 2018, AEP admitted a non-affiliate as a member of the LLCs to own and repower Desert Sky and Trent, which is expected to be completed in 2018. The non-affiliate contributed full turbine sets to each project in exchange for a 20.1% interest in the LLCs. The non-affiliates’ contribution of $84 million was recorded as Net Property, Plant and Equipment note within the 2020 Annual Report.

In 2020, Virginia’s Governor signed House Bill 443 (HB 443) requiring APCo to close certain ash disposal units at the retired Glen Lyn Station by removal of all coal combustion material. In June 2020, APCo recorded a revision to increase estimated Glen Lyn Station ash disposal ARO liabilities by $199 million due to the enactment of HB 443. In June 2021, management completed fully designed and costed project plans for the Glen Lyn Station site and increased ash disposal ARO liabilities by an additional $79 million. HB 443 provides for the recovery of all costs associated with closure by removal through the Virginia environmental rate adjustment clause. APCo is permitted to record carrying costs on the unrecovered balance sheets, which wasof closure costs at a weighted-average cost of capital approved by the fair valueVirginia SCC.

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

CompanyARO as of December 31, 2020Accretion
Expense		Liabilities
Incurred		Liabilities
Settled		Revisions in
Cash Flow
Estimates		ARO as of June 30, 2021
(in millions)
AEP (a)(b)(c)(d)$2,516.7 $51.1 $7.6 $(18.1)$66.4 $2,623.7 
APCo (a)(d)313.1 6.1 0 (3.7)78.6 394.1 

(a)Includes ARO related to ash disposal facilities.
(b)Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.83 billion and $1.80 billion as of the contribution date determined based on key input assumptions of the original cost of the full turbine setsJune 30, 2021 and the discounted cash flow benefit associated with the production tax credits available from repowering Desert Sky and Trent based on their expected net capacity, capacity factor and the operational availability. AEP owns 79.9% of the LLCs. As a result, management has concluded that Desert Sky and Trent, collectively, are VIE’s and that AEP is the primary beneficiary based on its power to direct the activities that most significantly impact Desert Sky and Trent’s economic performance. Also in January 2018, Desert Sky and Trent entered into a forward PPA for the sale of power to AEPEPDecember 31, 2020, respectively.
(c)Includes ARO related to deliveries of electricity beginning January 1, 2021 for a 12 year period. PriorSabine and DHLC.
(d)Includes ARO related to the effective date of the PPA, Desert Sky and Trent will sell power at market rates into ERCOT. AEP and the non-affiliate will share tax attributes including production tax credits and cash distributions from the operation of the LLCs generally consistent with the ownership percentages. See the table below for the classification of Desert Sky and Trent’s assets and liabilities on the balance sheets:asbestos removal.





226
American Electric Power Company, Inc.
Variable Interest Entities
March 31, 2018
  
 Desert Sky and Trent
 (in millions)
ASSETS 
Current Assets$41.1
Net Property, Plant and Equipment255.4
Other Noncurrent Assets0.7
Total Assets$297.2
  
LIABILITIES AND EQUITY 
Current Liabilities$41.4
Noncurrent Liabilities8.3
Equity247.5
Total Liabilities and Equity$297.2







AEP has a call right, which if exercised, would require the non-affiliate to sell its noncontrolling interest in the LLCs to AEP. The exercise period is for ninety days, beginning two years after the repowering completion. The non-affiliates’ interest in the LLCs is presented as redeemable noncontrolling interest on the balance sheets.  The non-affiliate holds redemption rights, which if exercised, would require AEP to purchase the non-affiliates’ noncontrolling interest in the LLCs.  The exercise price for both the call and redemption right are determined using a discounted cash flow model with agreed input assumptions as well as potential updates to certain assumptions reasonably expected based on the actual results of the LLCs.  As of March 31, 2018, AEP recorded $71 million of Redeemable Noncontrolling Interest in Mezzanine Equity on the balance sheets.


14. REVENUE FROM CONTRACTS WITH CUSTOMERS


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


Disaggregated Revenues from Contracts with Customers

The tabletables below representsrepresent AEP’s reportable segment revenues from contracts with customers, net of respective provisions for refund, by type of revenue:
Three Months Ended June 30, 2021
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration & MarketingCorporate and OtherReconciling AdjustmentsAEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues$825.8 $495.1 $0 $0 $0 $0 $1,320.9 
Commercial Revenues536.9 285.0 0 0 0 0 821.9 
Industrial Revenues552.5 102.9 0 0 0 (0.2)655.2 
Other Retail Revenues40.6 11.3 0 0 0 0 51.9 
Total Retail Revenues1,955.8 894.3 0 0 0 (0.2)2,849.9 
Wholesale and Competitive Retail Revenues:
Generation Revenues170.7 0 0 31.1 0 0 201.8 
Transmission Revenues (a)78.5 139.6 355.9 0 0 (284.8)289.2 
Renewable Generation Revenues (b)0 0 0 20.2 0 (0.4)19.8 
Retail, Trading and Marketing Revenues (c)0 0 0 358.7 (0.7)(13.6)344.4 
Total Wholesale and Competitive Retail Revenues249.2 139.6 355.9 410.0 (0.7)(298.8)855.2 
Other Revenues from Contracts with Customers (b)44.4 43.0 2.8 2.0 14.0 (26.6)79.6 
Total Revenues from Contracts with Customers2,249.4 1,076.9 358.7 412.0 13.3 (325.6)3,784.7 
Other Revenues:
Alternative Revenues (b)10.9 22.5 19.5 0 0 (40.2)12.7 
Other Revenues (b)0.3 4.0 0 24.6 2.2 (2.0)29.1 
Total Other Revenues11.2 26.5 19.5 24.6 2.2 (42.2)41.8 
Total Revenues$2,260.6 $1,103.4 $378.2 $436.6 $15.5 $(367.8)$3,826.5 
  Three Months Ended March 31, 2018
  Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other Reconciling Adjustments AEP Consolidated
  (in millions)
Retail Revenues:              
Residential Revenues $1,001.2
 $567.9
 $—
 $—
 $—
 $—
 $1,569.1
Commercial Revenues 515.8
 300.3
 —
 —
 —
 —
 816.1
Industrial Revenues 518.9
 113.2
 —
 —
 —
 —
 632.1
Other Retail Revenues 43.8
 9.5
 —
 —
 —
 —
 53.3
Total Retail Revenues 2,079.7
 990.9
 —
 —
 —
 —
 3,070.6
               
Wholesale and Competitive Retail Revenues:              
Generation Revenues 214.0
 —
 —
 145.1
 —
 —
 359.1
Generation Revenues – Affiliated 3.0
 —
 —
 27.1
 —
 (30.1) —
Transmission Revenues 57.9
 94.1
 56.8
 —
 —
 —
 208.8
Transmission Revenues – Affiliated 17.1
 —
 162.7
 —
 —
 (179.8) —
Marketing, Competitive Retail and Renewable Revenues —
 —
 —
 309.7
 —
 —
 309.7
Total Wholesale and Competitive Retail Revenues 292.0
 94.1
 219.5
 481.9
 —
 (209.9) 877.6
               
Other Revenues from Contracts with Customers 34.7
 49.0
 0.3
 1.7
 5.0
 —
 90.7
Other Revenues from Contracts with Customers - Affiliated 5.2
 0.7
 1.7
 0.5
 17.0
 (25.1) —
               
Total Revenues from Contracts with Customers 2,411.6
 1,134.7
 221.5
 484.1
 22.0
 (235.0) 4,038.9
               
Other Revenues:              
Alternative Revenues (9.1) 6.0
 (16.0) —
 —
 —
 (19.1)
Other Revenues 5.5
 —
 —
 21.0
 2.0
 —
 28.5
Other Revenues - Affiliated —
 21.7
 —
 —
 —
 (21.7) —
Total Other Revenues (3.6) 27.7
 (16.0) 21.0
 2.0
 (21.7) 9.4
               
Total Revenues $2,408.0
 $1,162.4
 $205.5
 $505.1
 $24.0
 $(256.7) $4,048.3



(a)Amounts include affiliated and nonaffiliated revenues. The table below represents revenues from contracts with customers, net of respective provisions for refund, by type ofaffiliated revenue for the Registrant Subsidiaries:AEP Transmission Holdco was $276 million. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues.
  Three Months Ended March 31, 2018
  AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCO
  (in millions)
Retail Revenues:              
Residential Revenues $131.6
 $—
 $414.0
 $189.0
 $436.8
 $141.1
 $140.1
Commercial Revenues 105.4
 —
 147.1
 110.8
 194.7
 88.0
 110.1
Industrial Revenues 25.8
 —
 146.8
 130.8
 87.7
 65.4
 75.4
Other Retail Revenues 6.2
 —
 19.6
 2.2
 3.2
 18.3
 2.1
Total Retail Revenues 269.0
 —
 727.5
 432.8
 722.4
 312.8
 327.7
               
Wholesale Revenues:              
Generation Revenues —
 —
 22.3
 111.1
 —
 5.9
 59.9
Generation Revenues – Affiliated —
 —
 40.5
 2.9
 —
 —
 —
Transmission Revenues 78.0
 48.3
 16.9
 6.8
 16.0
 10.6
 20.2
Transmission Revenues – Affiliated —
 160.1
 7.9
 —
 —
 —
 5.8
Total Wholesale Revenues 78.0
 208.4
 87.6
 120.8
 16.0
 16.5
 85.9
               
Other Revenues from Contracts with Customers 6.7
 0.1
 10.2
 7.7
 42.3
 3.1
 5.8
Other Revenues from Contracts with Customers - Affiliated 0.4
 2.0
 1.0
 15.0
 —
 1.1
 0.3
               
Total Revenues from Contracts with Customers 354.1
 210.5
 826.3
 576.3
 780.7
 333.5
 419.7
               
Other Revenues:              
Alternative Revenues (0.3) (17.0) (5.9) (5.0) 6.3
 3.3
 (0.3)
Other Revenues —
 —
 —
 5.5
 0.8
 —
 —
Other Revenues - Affiliated 17.8
 —
 —
 —
 3.1
 —
 —
Total Other Revenues 17.5
 (17.0) (5.9) 0.5
 10.2
 3.3
 (0.3)
               
Total Revenues $371.6
 $193.5
 $820.4
 $576.8
 $790.9
 $336.8
 $419.4

Performance Obligations

AEP has performance obligations as part of its normal course of business. A performance obligation is a promise to transfer a distinct good or service, or a series of distinct goods or services that are substantially the same(c)Amounts include affiliated and have the same pattern of transfer to a customer.nonaffiliated revenues. The invoice practical expedient within the accounting guidance for “Revenue from Contracts with Customers” allows for the recognition of revenue from performance obligations in the amount of consideration to which there is a right to invoice the customer and when the amount for which there is a right to invoice corresponds directly to the value transferred to the customer.

The purpose of the invoice practical expedient is to depict an entity’s measure of progress toward completion of the performance obligation within a contract and can only be applied to performance obligations that are satisfied over time and when the invoice is representative of services provided to date. AEP subsidiaries elected to apply the invoice practical expedient to recognizeaffiliated revenue for performance obligations satisfied over time as the invoices from the respective revenue streams are representative of services or goods provided to date to the customer. Performance obligations for AEP’s subsidiaries are summarized as follows:

Retail Revenues

AEP’s subsidiaries within the Vertically Integrated Utilities and Transmission and Distribution Utilities segments have performance obligations to generate, transmit and distribute electricity for sale to rate-regulated retail customers. The performance obligation to deliver electricity is satisfied over time as the customer simultaneously receives and consumes the benefits provided. Revenues are variable as they are subject to the customer’s usage requirements.



Rate-regulated retail customers typically have the right to discontinue receiving service at will, therefore these contracts between AEP’s subsidiaries and their customers for rate-regulated services are generally limited to the services requested and received to date for such arrangements. Retail customers are generally billed on a monthly basis, and payment is typically due within 15 to 20 days after the issuance of the invoice. Payments from Retail Electric Providers are due to AEP Texas within 35 days.

Wholesale Revenues - Generation

AEP’s subsidiaries within the Vertically Integrated Utilities and Generation & Marketing segments have performance obligations to sell electricity to wholesale customers from generation assets in PJM, SPPwas $13 million. The remaining affiliated amounts were immaterial.



227




Three Months Ended June 30, 2020
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration & MarketingCorporate and OtherReconciling AdjustmentsAEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues$820.7 $494.5 $0 $0 $0 $0 $1,315.2 
Commercial Revenues474.5 256.3 0 0 0 0 730.8 
Industrial Revenues486.0 98.7 0 0 0 (0.2)584.5 
Other Retail Revenues36.9 10.3 0 0 0 0 47.2 
Total Retail Revenues1,818.1 859.8 0 0 0 (0.2)2,677.7 
Wholesale and Competitive Retail Revenues:
Generation Revenues148.6 0 0 31.5 0 0 180.1 
Transmission Revenues (a)84.1 108.4 310.2 0 0 (201.8)300.9 
Renewable Generation Revenues (b)0 0 0 17.7 0 (0.3)17.4 
Retail, Trading and Marketing Revenues (c)0 0 0 327.6 (0.6)(26.5)300.5 
Total Wholesale and Competitive Retail Revenues232.7 108.4 310.2 376.8 (0.6)(228.6)798.9 
Other Revenues from Contracts with Customers (b)46.4 33.1 11.4 0.7 22.4 (31.4)82.6 
Total Revenues from Contracts with Customers2,097.2 1,001.3 321.6 377.5 21.8 (260.2)3,559.2 
Other Revenues:
Alternative Revenues (b)(5.2)20.6 (71.9)0 0 (7.6)(64.1)
Other Revenues (b)0 12.6 0 (0.6)(2.3)(10.8)(1.1)
Total Other Revenues(5.2)33.2 (71.9)(0.6)(2.3)(18.4)(65.2)
Total Revenues$2,092.0 $1,034.5 $249.7 $376.9 $19.5 $(278.6)$3,494.0 

(a)Amounts include affiliated and ERCOT.nonaffiliated revenues. The performance obligation to deliver electricity from generation assets is satisfied over time as the customer simultaneously receivesaffiliated revenue for AEP Transmission Holdco was $240 million. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and consumes the benefits provided. Wholesale generation revenues are variable as they are subject to the customer’s usage requirements.nonaffiliated revenues.

AEP’s subsidiaries within the Vertically Integrated Utilities(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing segments also have performance obligationswas $27 million. The remaining affiliated amounts were immaterial.




228




Three Months Ended June 30, 2021
AEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Retail Revenues:
Residential Revenues$128.5 $0 $268.0 $179.1 $366.8 $142.8 $149.9 
Commercial Revenues95.4 0 132.4 127.0 189.6 93.2 127.1 
Industrial Revenues29.7 0 147.7 143.7 73.2 68.6 91.1 
Other Retail Revenues8.1 0 16.2 1.2 3.1 19.1 2.6 
Total Retail Revenues261.7 0 564.3 451.0 632.7 323.7 370.7 
Wholesale Revenues:
Generation Revenues (a)0 0 75.1 88.3 0 6.7 20.5 
Transmission Revenues (b)121.0 339.9 24.7 8.3 18.6 8.8 28.5 
Total Wholesale Revenues121.0 339.9 99.8 96.6 18.6 15.5 49.0 
Other Revenues from Contracts with Customers (c)12.4 2.9 8.0 37.0 30.5 3.9 5.2 
Total Revenues from Contracts with Customers395.1 342.8 672.1 584.6 681.8 343.1 424.9 
Other Revenues:
Alternative Revenues (d)3.4 22.7 5.1 (0.8)19.1 1.4 5.2 
Other Revenues (d)0 0 (0.2)0 4.0 0 0 
Total Other Revenues3.4 22.7 4.9 (0.8)23.1 1.4 5.2 
Total Revenues$398.5 $365.5 $677.0 $583.8 $704.9 $344.5 $430.1 

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $28 million primarily relating to stand ready in order to promote grid reliability. Stand ready services are sold into PJM’s Reliability Pricing Model (RPM) capacity market. RPM entails a base auction and at least three incremental auctions for a specific PJM delivery year,the PPA with the incremental auctions spanning three years. The performance obligation to stand ready is satisfied over time and the consideration for which is variable until the occurrence of the third incremental auction, at which point the performance obligation becomes fixed.

Payments from the RTO for stand ready services are typically received within one week from the issuance of the invoice, which is typically issued weekly. Gross margin resulting from generation sales within the Vertically Integrated Utilities segment are primarily subject to margin sharing agreements with customers and vary by state, where the revenues are reflected gross in the disaggregated revenue tables above.

Wholesale Revenues - Generation Affiliated

APCo has a performance obligation to supply wholesale electricity to KGPCo through a purchased power agreement. The FERC regulates the cost-based wholesale power transactions between APCo and KGPCo. The purchased power agreement includes a componentremaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $272 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $13 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.



229




Three Months Ended June 30, 2020
AEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Retail Revenues:
Residential Revenues$149.6 $0 $272.7 $186.9 $344.8 $139.2 $147.7 
Commercial Revenues94.4 0 119.9 118.0 162.1 77.3 110.6 
Industrial Revenues31.3 0 134.5 130.7 67.3 54.5 82.3 
Other Retail Revenues7.0 0 15.4 1.6 3.3 16.2 2.3 
Total Retail Revenues282.3 0 542.5 437.2 577.5 287.2 342.9 
Wholesale Revenues:
Generation Revenues (a)0 0 60.9 75.6 0 2.2 30.3 
Transmission Revenues (b)91.7 298.7 30.3 7.3 16.8 3.9 33.4 
Total Wholesale Revenues91.7 298.7 91.2 82.9 16.8 6.1 63.7 
Other Revenues from Contracts with Customers (c)10.3 11.1 13.5 21.9 22.7 13.7 9.7 
Total Revenues from Contracts with Customers384.3 309.8 647.2 542.0 617.0 307.0 416.3 
Other Revenues:
Alternative Revenues (d)1.1 (71.7)(9.7)4.6 19.6 1.6 (1.3)
Other Revenues (d)16.1 0 0 0 3.8 0 0 
Total Other Revenues17.2 (71.7)(9.7)4.6 23.4 1.6 (1.3)
Total Revenues$401.5 $238.1 $637.5 $546.6 $640.4 $308.6 $415.0 

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $24 million primarily relating to the recovery of transmission costs under the FERC OATT.PPA with KGPCo. The transmission cost component of purchased power is cost-basedremaining affiliated amounts were immaterial.
(b)Amounts include affiliated and regulated by the TRA. APCo’s performance obligation under the purchased power agreement is satisfied over time as KGPCo simultaneously receivesnonaffiliated revenues. The affiliated revenue for AEPTCo was $237 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and consumes the wholesale electricity. APCo’s revenues from the purchased power agreement are presented within the Generation Revenues - Affiliated line in the disaggregatednonaffiliated revenues. The affiliated revenue tables above.for I&M was $18 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.

(d)Amounts include affiliated and nonaffiliated revenues.
Wholesale Revenues - Transmission

230

AEP’s subsidiaries within the Vertically Integrated Utilities, Transmission


Six Months Ended June 30, 2021
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration & MarketingCorporate and OtherReconciling AdjustmentsAEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues$1,871.9 $1,043.2 $0 $0 $0 $0 $2,915.1 
Commercial Revenues1,023.1 524.2 0 0 0 0 1,547.3 
Industrial Revenues1,036.5 188.6 0 0 0 (0.4)1,224.7 
Other Retail Revenues78.4 21.3 0 0 0 0 99.7 
Total Retail Revenues4,009.9 1,777.3 0 0 0 (0.4)5,786.8 
Wholesale and Competitive Retail Revenues:
Generation Revenues523.3 0 0 71.6 0 0 594.9 
Transmission Revenues (a)167.5 270.1 716.3 0 0 (584.1)569.8 
Renewable Generation Revenues (b)0 0 0 42.6 0 (1.1)41.5 
Retail, Trading and Marketing Revenues (c)0 0 0 928.5 0.5 (45.4)883.6 
Total Wholesale and Competitive Retail Revenues690.8 270.1 716.3 1,042.7 0.5 (630.6)2,089.8 
Other Revenues from Contracts with Customers (b)86.7 95.1 7.4 3.5 22.6 (47.8)167.5 
Total Revenues from Contracts with Customers4,787.4 2,142.5 723.7 1,046.2 23.1 (678.8)8,044.1 
Other Revenues:
Alternative Revenues (b)10.2 39.7 31.5 0 0 (51.8)29.6 
Other Revenues (b)0.3 9.3 0 24.6 5.3 (5.6)33.9 
Total Other Revenues10.5 49.0 31.5 24.6 5.3 (57.4)63.5 
Total Revenues$4,797.9 $2,191.5 $755.2 $1,070.8 $28.4 $(736.2)$8,107.6 

(a)Amounts include affiliated and Distribution Utilities andnonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco segments have performance obligations to transmit electricity to wholesale customers through assets ownedwas $549 million. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and operated by AEP subsidiaries.nonaffiliated revenues.
(c)Amounts include affiliated and nonaffiliated revenues. The performance obligation to provide transmission services in PJM, SPP and ERCOT encompass a time frame greater than a year, where the performance obligation within each RTO is partially fixedaffiliated revenue for a period of one year or less. Payments from the RTO for transmission services are typically received within one week from the issuance of the invoice, which is issued monthly for SPP and ERCOT and weekly for PJM.

AEP subsidiaries within the PJM and SPP regions collect revenues through Transmission Formula Rates. The FERC-approved rates establish the annual transmission revenue requirement (ATRR) and transmission service rates for transmission owners. The formula rates establish rates for a one year period and also include a true-up calculation for the prior year’s billings, allowing for over/under-recovery of the transmission owner’s ATRR. The annual true-ups meet the definition of alternative revenues in accordance with the accounting guidance for “Regulated Operations,” and are therefore presented as such in the disaggregated revenue tables above. AEP subsidiaries within the ERCOT region collect revenues through a combination of base rates and interim Transmission Costs of Services filings that are approved by the PUCT.


Wholesale Revenues - Transmission Affiliated

APCo, I&M, KGPCo, KPCo, OPCo and WPCo (AEP East Companies) are parties to the Transmission Agreement (TA), which defines how transmission costs are allocated among the AEP East Companies on a 12-month average coincident peak basis. PSO, SWEPCO and AEPSC are parties to the Transmission Coordination Agreement (TCA) by and among PSO, SWEPCO and AEPSC, in connection with the operation of the transmission assets of the two AEP utility subsidiaries. AEPTCo is a load serving entity within the PJM and SPP regions providing transmission services to affiliates in accordance with the OATT, TA and TCA. Affiliate revenues as a result of the respective TA and the TCA are reflected as Transmission Revenues - Affiliated in the disaggregated revenue tables above.

Marketing, Competitive Retail and Renewable Revenues

AEP’s subsidiaries within the Generation & Marketing segment have performance obligationswas $45 million. The remaining affiliated amounts were immaterial.
231




Six Months Ended June 30, 2020
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration & MarketingCorporate and OtherReconciling AdjustmentsAEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues$1,735.8 $1,015.8 $0 $0 $0 $0 $2,751.6 
Commercial Revenues963.9 533.2 0 0 0 0 1,497.1 
Industrial Revenues1,004.2 196.5 0 0 0 (0.4)1,200.3 
Other Retail Revenues76.8 22.1 0 0 0 0 98.9 
Total Retail Revenues3,780.7 1,767.6 0 0 0 (0.4)5,547.9 
Wholesale and Competitive Retail Revenues:
Generation Revenues289.0 0 0 75.6 0 0 364.6 
Transmission Revenues (a)164.0 222.5 620.0 0 0 (464.8)541.7 
Renewable Generation Revenues (b)0 0 0 34.9 0 (0.9)34.0 
Retail, Trading and Marketing Revenues (c)0 0 0 686.3 (6.6)(55.9)623.8 
Total Wholesale and Competitive Retail Revenues453.0 222.5 620.0 796.8 (6.6)(521.6)1,564.1 
Other Revenues from Contracts with Customers (b)90.0 69.5 15.1 1.0 50.5 (72.0)154.1 
Total Revenues from Contracts with Customers4,323.7 2,059.6 635.1 797.8 43.9 (594.0)7,266.1 
Other Revenues:
Alternative Revenues (b)(5.0)39.9 (75.2)0 0 (3.1)(43.4)
Other Revenues (b)0 41.9 0 17.7 (4.5)(36.3)18.8 
Total Other Revenues(5.0)81.8 (75.2)17.7 (4.5)(39.4)(24.6)
Total Revenues$4,318.7 $2,141.4 $559.9 $815.5 $39.4 $(633.4)$7,241.5 

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $479 million. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $62 million. The remaining affiliated amounts were immaterial.



232




Six Months Ended June 30, 2021
AEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Retail Revenues:
Residential Revenues$251.2 $0 $684.9 $392.7 $792.1 $279.6 $316.2 
Commercial Revenues176.1 0 262.6 240.6 348.1 165.9 240.0 
Industrial Revenues56.2 0 278.6 272.1 132.4 125.0 161.7 
Other Retail Revenues14.9 0 33.1 2.6 6.3 34.8 4.9 
Total Retail Revenues498.4 0 1,259.2 908.0 1,278.9 605.3 722.8 
Wholesale Revenues:
Generation Revenues (a)0 0 147.5 167.9 0 (0.4)249.1 
Transmission Revenues (b)233.0 685.1 58.9 16.6 37.1 18.2 57.4 
Total Wholesale Revenues233.0 685.1 206.4 184.5 37.1 17.8 306.5 
Other Revenues from Contracts with Customers (c)28.6 7.5 21.1 57.7 66.5 16.5 11.6 
Total Revenues from Contracts with Customers760.0 692.6 1,486.7 1,150.2 1,382.5 639.6 1,040.9 
Other Revenues:
Alternative Revenues (d)2.7 34.6 7.3 (1.9)37.0 1.0 5.3 
Other Revenues (d)0 0 0 0 9.3 0 0 
Total Other Revenues2.7 34.6 7.3 (1.9)46.3 1.0 5.3 
Total Revenues$762.7 $727.2 $1,494.0 $1,148.3 $1,428.8 $640.6 $1,046.2 

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $60 million primarily relating to deliver electricitythe PPA with KGPCo. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $542 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $29 million primarily relating to competitive retailbarging, urea transloading and wholesale customers. Performance obligationsother transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.
233




Six Months Ended June 30, 2020
AEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Retail Revenues:
Residential Revenues$282.5 $0 $630.2 $388.2 $733.2 $267.7 $279.3 
Commercial Revenues207.2 0 252.2 240.2 326.1 153.4 216.2 
Industrial Revenues66.5 0 275.6 268.5 130.0 115.8 162.1 
Other Retail Revenues15.4 0 33.3 3.4 6.7 32.8 4.3 
Total Retail Revenues571.6 0 1,191.3 900.3 1,196.0 569.7 661.9 
Wholesale Revenues:
Generation Revenues (a)0 0 115.0 154.0 0 4.1 64.4 
Transmission Revenues (b)188.6 596.9 60.7 14.7 33.9 11.7 58.8 
Total Wholesale Revenues188.6 596.9 175.7 168.7 33.9 15.8 123.2 
Other Revenues from Contracts with Customers (c)18.2 14.5 30.7 42.9 51.3 18.4 15.5 
Total Revenues from Contracts with Customers778.4 611.4 1,397.7 1,111.9 1,281.2 603.9 800.6 
Other Revenues:
Alternative Revenues (d)0.4 (77.7)(10.8)5.0 39.6 2.0 0.3 
Other Revenues (d)46.3 0 0 0 9.9 0 0 
Total Other Revenues46.7 (77.7)(10.8)5.0 49.5 2.0 0.3 
Total Revenues$825.1 $533.7 $1,386.9 $1,116.9 $1,330.7 $605.9 $800.9 

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for marketing, competitive retailAPCo was $57 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and renewable offtake sales are satisfied over time as the customer simultaneously receivesnonaffiliated revenues. The affiliated revenue for AEPTCo was $472 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and consumes the benefits provided. Revenues arenonaffiliated revenues. The affiliated revenue for I&M was $34 million primarily variable as they are subjectrelating to customer’s usage requirements; however, certain contracts mandate a delivery of a set quantity of electricity at a predetermined price, resulting in a fixed performance obligation.barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.

(d)Amounts include affiliated and nonaffiliated revenues.
Payment terms under marketing arrangements typically follow standard Edison Electric Institute and International Swaps and Derivatives Association terms, which call for payment in 20 days. Payments for competitive retail and offtake arrangements for renewable assets range from 15 to 60 days and are dependent on the product sold, location and the creditworthiness of customer. Invoices for marketing arrangements, competitive retail and offtake arrangements for renewable assets are issued monthly.

234




Fixed Performance Obligations


The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of March 31, 2018.June 30, 2021. Fixed performance obligations primarily include wholesale transmission services, electricity sales for fixed amounts of energy and stand ready services into PJM’s RPM market.
Company (a) Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total
  (in millions)
AEP $748.7
 $256.1
 $164.1
 $348.7
 $1,517.6
AEP Texas 233.4
 —
 —
 —
 233.4
AEPTCo 536.2
 —
 —
 —
 536.2
APCo 92.0
 31.8
 22.7
 11.4
 157.9
I&M 20.6
 8.7
 8.7
 4.3
 42.3
OPCo 42.1
 —
 —
 —
 42.1
PSO 11.9
 —
 —
 —
 11.9
SWEPCo 24.9
 —
 —
 —
 24.9

(a)Amounts The Registrant Subsidiaries amounts shown in the table below include affiliated and nonaffiliated revenues except for AEP.revenues.

Company20212022-20232024-2025After 2025Total
(in millions)
AEP$618.3 $198.4 $160.4 $161.4 $1,138.5 
AEP Texas254.5 0 0 0 254.5 
AEPTCo663.3 0 0 0 663.3 
APCo89.8 34.6 25.5 11.6 161.5 
I&M20.0 11.5 8.8 4.5 44.8 
OPCo44.5 10.1 0 0.1 54.7 
PSO7.0 0 0 0 7.0 
SWEPCo20.1 0 0 0 20.1 

Contract Assets and Liabilities


Contract assets are recognized when the Registrants have a right to consideration that is conditional upon the occurrence of an event other than the passage of time, such as future performance under a contract. The Registrants dodid not have any material contract assets as of MarchJune 30, 2021 and December 31, 2018.2020.


When the Registrants receive consideration, or such consideration is unconditionally due from a customer prior to transferring goods or services to the customer under the terms of a sales contract, they recognize a contract liability on the balance sheetsheets in the amount of that consideration. Revenue for such consideration is subsequently recognized in the period or periods in which the remaining performance obligations in the contract are satisfied. The Registrants’ contract liabilities typically arise from services provided under joint use agreements for utility poles. The Registrants dodid not have any material contract liabilities as of MarchJune 30, 2021 and December 31, 2018.2020.



Accounts Receivable from Contracts with Customers


Accounts receivable from contracts with customers are presented on the Registrants’Registrant Subsidiaries’ balance sheets within the Accounts Receivable - Customers line item. The Registrants’Registrant Subsidiaries’ balances for receivables from contracts that are not recognized in accordance with the accounting guidance for “Revenue from Contracts with Customers” included in Accounts Receivable - Customers arewere not material as of MarchJune 30, 2021 and December 31, 2018.2020. See “Securitized Accounts Receivable - AEP Credit” section of Note 12 for additional information related to AEP Credit’s securitized accounts receivable.information.


The following table represents the amount of affiliated accounts receivable from contracts with customers included in Accounts Receivable - Affiliated Companies on the Registrant Subsidiaries’ balance sheets:
CompanyJune 30, 2021December 31, 2020
(in millions)
AEPTCo$93.9 $81.0 
APCo48.5 52.7 
I&M28.8 34.8 
OPCo45.7 45.9 
PSO13.0 7.8 
SWEPCo21.6 11.2 

235
Company March 31, 2018 January 1, 2018
  (in millions)
AEP Texas $—
 $—
AEPTCo 60.6
 47.1
APCo 36.3
 35.6
I&M 14.8
 15.1
OPCo 27.1
 26.1
PSO 6.2
 6.1
SWEPCo 11.4
 11.0



Contract Costs


Contract costs to obtain or fulfill a contract for AEP subsidiaries within the Generation & Marketing segment are accounted for under the guidance for “Other Assets and Deferred Costs” and presented as a single asset and neither bifurcated nor reclassified between current and noncurrent assets on the Registrants’ balance sheets. Contract costs to acquire a contract are amortized in a manner consistent with the transfer of goods or services to the customer in Other Operation on the Registrants’ income statements. The Registrants do not have material contract costs as of March 31, 2018.


CONTROLS AND PROCEDURES


During the firstsecond quarter of 2018,2021, management, including the principal executive officer and principal financial officer of each of the Registrants, evaluated the Registrants’ disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. As of March 31, 2018,June 30, 2021, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives.


There was no change in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the firstsecond quarter of 20182021 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

236






PART II.  OTHER INFORMATION


Item 1.  Legal Proceedings


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


Item 1A.  Risk Factors


The Annual Report on Form 10-K for the year ended December 31, 20172020 includes a detailed discussion of risk factors. As of March 31, 2018,June 30, 2021, the risk factorfactors appearing in the 2017AEP’s 2020 Annual Report on Form 10-K under the heading set forth below isare supplemented and updated as follows:


Certain elementsThe rate of AEP’s transmission formula rates have been challenged, whichtaxes imposed on AEP could result in lowered rates and/or refunds of amounts previously collected and thus have an adverse effect on AEP’s business, financial condition, results of operations and cash flows.change. (Applies to all Registrants other than AEP Texas)Registrants)


AEP provides transmission service under rates regulated by the FERC. The FERC has approved the cost-based formula rate templates used by AEP to calculate its respective annual revenue requirements, but it has not expressly approved the amount of actual capital and operating expenditures to be used in the formula rates. All aspects of AEP’s rates accepted or approved by the FERC, including the formula rate templates, the rates of return on the actual equity portion of its respective capital structures and the approved targeted capital structures, are subject to challenge by interested parties at the FERC, or by the FERC on its own initiative. In addition, interested parties may challenge the annual implementation and calculation by AEP of its projected rates and formula rate true up pursuant to its approved formula rate templates under AEP’s formula rate implementation protocols. If a challenger can establish that any of these aspects are unjust, unreasonable, unduly discriminatory or preferential, then the FERC will make appropriate prospective adjustments to them and/or disallow any of AEP’s inclusion of those aspects in the rate setting formula.

In October 2016, seven parties filed a complaint at the FERC that alleged the base return on common equity used by AEP’s transmission owning subsidiaries within PJM in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint.  In November 2017, a FERC order set the matter for hearing and settlement procedures.  In March 2018, AEP’s transmission owning subsidiaries within PJM and six of the complainants filed a settlement agreement with the FERC (the seventh complainant abstained). 

In April 2018, certain intervenors filed comments at the FERC recommending a base ROE of 8.48% and a one-time refund of $184 million. In addition, the FERC trial staff filed comments recommending a base ROE of 8.41% and one-time refund of $175 million. Also in April 2018, another intervenor recommended the refund be calculated in accordance with the approved base ROE. Management believes its financial statements adequately address the impact of the settlement agreement.  If the FERC orders revenue reductions in excess of the terms of the settlement agreement, it could reduce future net income and cash flows and impact financial condition.  A decision from the FERC is pending.

In June 2017, a similar complaint was filed with the FERC claiming that the base ROE used by certain AEP subsidiaries that operate in SPP, including the West Transcos, in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36%, effective upon the date of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.

End-use consumers and entities supplying electricity to end-use consumers may also attempt to influence government and/or regulators to change the rate setting methodologies that apply to AEP, particularly if rates for delivered electricity increase substantially.



OVEC may require additional liquidity and other capital support.  (Applies to AEP, APCo, I&M and OPCo)

AEP and several nonaffiliated utility companies own OVEC. The Inter-Company Power Agreement (ICPA) defines the rights and obligations and sets the power participation ratio of the parties to it.  Under the ICPA, parties are entitled to receive and are obligated to pay for all OVEC capacity (approximately 2,400 MWs) in proportion to their respective power participation ratios. The aggregate power participation ratio of APCo, I&M and OPCo is 43.47%. If a party fails to make payments owed by it under the ICPA, OVEC may not have sufficient funds to honor its payment obligations, including its ongoing operating expenses as well as its indebtedness. OVEC has outstanding indebtedness of approximately $1.4 billion, of which APCo, I&M, and OPCo are collectively responsible for $622 million through the ICPA. Although they are not an obligor or guarantor, APCo, I&M, and OPCo are responsible for their respective ratio of OVEC’s outstanding debt through the ICPA.

A nonaffiliated party, whose aggregate power participation ratio is 4.85% under the ICPA, has filed a petition seeking protection under bankruptcy law.  Bankruptcy filings typically trigger review of the petitioner’s contractual obligations, including, in this instance, the ICPA.  Because the ICPA is subject to FERC approvalincome taxation at the federal level and jurisdiction, priorby certain states and municipalities. In determining AEP’s income tax liability for these jurisdictions, management monitors changes to the bankruptcy petition OVEC made a filing at FERC seeking, among other objectives,applicable tax laws and related regulations. While management believes it is in compliance with current prevailing laws, one or more taxing jurisdictions could seek to confirm FERC’s jurisdiction.  Litigation related to these filings continues.impose incremental or new taxes on the company. In addition, as a result of the most recent presidential and congressional elections in the United States, there could be significant changes in tax law and regulations that could result in additional federal income taxes being imposed on AEP. Any adverse developments in these laws or regulations, including legislative changes, judicial holdings or administrative interpretations, could have a material and prior related developments, OVEC’s credit ratings have been impacted.adverse effect on financial condition and results of operations.


If OVEC does not have sufficient funds to honor its payment obligations, there is risk that APCo, I&M and/or OPCo may need to make payments in addition to their power participation ratio payments.  Further, if OVEC’s indebtedness is accelerated for any reason, there is risk that APCo, I&M and/or OPCo may be required to pay some or all of such accelerated indebtedness in amounts equal to their aggregate power participation ratio of 43.47%.  Also, as a result of the credit rating agencies’ actions, OVEC’s ability to access capital markets on terms as favorable as previously may diminish and its financing costs will increase.

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


None


Item 3.  Defaults Upon Senior Securities


None


Item 4.  Mine Safety Disclosures


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


The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act. Exhibit 95 “Mine Safety Disclosure Exhibit” contains the notices of violation and proposed assessments received by DHLC under the Mine Act for the quarter ended March 31, 2018.June 30, 2021.


Item 5.  Other Information


None.




237




Item 6.  Exhibits


The documents designated with an (*) below have previously been filed on behalf of the Registrants shown and are incorporated herein by reference to the documents indicated and made a part hereof.
ExhibitDescriptionPreviously Filed as Exhibit to:
AEP TEXAS‡  File No. 333-221643
4Company Order and Officer’s Certificate between AEP Texas Inc. and The Bank of New York Mellon Trust Company, N.A. as Trustee dated May 6, 2021 establishing terms of the 3.45% Senior Notes, Series J, due 2051
I&M‡ File No. 1-3570
4Company Order and Officer’s Certificate between Indiana Michigan Power Company and The Bank of New York Mellon Trust Company, N.A. as Trustee dated April 27, 2021 establishing terms of the 3.25% Senior Notes, Series O due 2051

The exhibits designated with an (X) in the table below are being filed on behalf of the Registrants.
ExhibitDescriptionAEP
AEP

Texas
AEPTCoAPCoI&MOPCoPSOSWEPCo
10(a)10Performance ShareGeneral Severance, Stock Award and Release Agreement furnished to participants of the AEP System AEP Long-Term Incentive Plan, as amendedbetween American Electric Power Company, Inc. and Brian X. Tierney
X
10(b)31(a)Restricted Stock Unit Agreement furnished to participants of the AEP System AEP-Long Term Incentive Plan, as Amended and Restated
X
12Computation of Consolidated Ratio of Earnings to Fixed Charges
X
X
X
X
X
X
X
X
31(a)Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
X
X
X
X
X
X
X
X
31(b)Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
X
X
X
X
X
X
X
X
32(a)Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
X
X
X
X
X
X
X
X
32(b)Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
X
X
X
X
X
X
X
X
95Mine Safety Disclosures
X
101.INSXBRL Instance DocumentXXXXXXXXThe instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCHXBRL Taxonomy Extension SchemaXXXXXXXX
101.CALXBRL Taxonomy Extension Calculation LinkbaseXXXXXXXX
101.DEFXBRL Taxonomy Extension Definition LinkbaseXXXXXXXX
101.LABXBRL Taxonomy Extension Label LinkbaseXXXXXXXX
101.PREXBRL Taxonomy Extension Presentation LinkbaseXXXXXXXX
104Cover Page Interactive Data FileFormatted as Inline XBRL and contained in Exhibit 101.

238






SIGNATURE




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




AMERICAN ELECTRIC POWER COMPANY, INC.






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






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






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






Date:  April 26, 2018


July 22, 2021
206
239