0000004904aep:RegulatoryAssetsPendingFinalRegulatoryApprovalMemberaep:VirginiaJurisdictionalAMRMetersMember2020-09-300000004904us-gaap:PortionAtOtherThanFairValueFairValueDisclosureMemberaep:IndianaMichiganPowerCoMember2019-12-310000004904aep:WholesaleGenerationMemberaep:AppalachianPowerCoMember2020-01-012020-09-30








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 September 30, 20172020
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
333-217143AEP 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 the 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 ¨
Large Accelerated filerxAccelerated filer☐Non-accelerated filer☐
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
October 26, 2017
American Electric Power Company, Inc.491,883,887
($6.50 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
October 22, 2020
American Electric Power Company, Inc.496,386,252 
($6.50 par value)
AEP Texas Inc.100 
($0.01 par value)
AEP Transmission Company, LLC (a)NA
Appalachian Power Company13,499,500 
(no par value)
Indiana Michigan Power Company1,400,000 
(no par value)
Ohio Power Company27,952,473 
(no par value)
Public Service Company of Oklahoma9,013,000 
($15 par value)
Southwestern Electric Power Company3,680 
($18 par value)

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






AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF QUARTERLY REPORTS ON FORM 10-Q
September 30, 20172020
Page
Number
Glossary of Terms
i
Forward-Looking Information
ivv
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
4850
AEP Transmission Company, LLCTexas Inc. and Subsidiaries:
Management’s Narrative Discussion and Analysis of Results of Operations
5557
Condensed Consolidated Financial Statements
5762
Appalachian PowerAEP Transmission Company, LLC and Subsidiaries:
Management’s Narrative Discussion and Analysis of Results of Operations
6369
Condensed Consolidated Financial Statements
6671
Indiana MichiganAppalachian Power Company and Subsidiaries:
Management’s Narrative Discussion and Analysis of Results of Operations
7377
Condensed Consolidated Financial Statements
7882
OhioIndiana Michigan Power Company and Subsidiaries:
Management’s Narrative Discussion and Analysis of Results of Operations
8589
Condensed Consolidated Financial Statements
9094
Public ServiceOhio Power Company of Oklahoma:and Subsidiaries:
Management’s Narrative Discussion and Analysis of Results of Operations
97101
Condensed Consolidated Financial Statements
101106
Southwestern Electric PowerPublic Service Company Consolidated:of Oklahoma:
Management’s Narrative Discussion and Analysis of Results of Operations
108113
Condensed Financial Statements
117
Southwestern Electric Power Company Consolidated:
Management’s Narrative Discussion and Analysis of Results of Operations
124
Condensed Consolidated Financial Statements
112128
Index of Condensed Notes to Condensed Financial Statements of Registrants
118134
Controls and Procedures
203224









Part II.  OTHER INFORMATION
Item 1.  Legal Proceedings
204225
Item 1A.  Risk Factors
204225
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds
205227
Item 3.  Defaults Upon Senior Securities
205227
Item 4.  Mine Safety Disclosures
205227
Item 5.  Other Information
206227
Item 6.  Exhibits:  Exhibits
206228
Exhibit 12
SIGNATUREExhibit 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
207230
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.
Term Meaning
   
AEGCo AEP Generating Company, an AEP electric utility subsidiary.
AEP American Electric Power Company, Inc., an investor-owned electric public utility holding company which includes American Electric Power Company, Inc. (Parent) and majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit AEP Credit, Inc., a consolidated variable interest entityVIE of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP EnergyAEP Energy, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States.
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.
AEP Wind Holdings LLCAcquired in April 2019 as Sempra Renewables LLC, develops, owns and operates, or holds interests in, wind generation facilities in the United States.
AEPEPAEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, hedging activities, asset management and commercial and industrial sales in deregulated markets.
AEPROAEP River Operations, LLC, a commercial barge operation sold in November 2015.
AEPSC American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AEPTCoAEP Transmission Company, LLC, a wholly-owned subsidiary of AEP Transmission Holdco, andis an intermediate holding company that owns seven wholly-owned transmission companies.the State Transcos.
AEPTCo ParentAEP Transmission Company, LLC, the equity ownerholding company of the State Transcos within the AEPTCo consolidation.
AFUDCAllowance for Equity Funds Used During Construction.
AGRAEP Generation Resources Inc., a competitive AEP subsidiary in the Generation & Marketing segment.
AMIAdvanced Metering Infrastructure.
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 ENEC deferral balance.
APSCArkansas Public Service Commission.
ARAMAverage Rate Assumption Method, an IRS approved method used to calculate the reversal of Excess ADIT for rate-making purposes.
AROAsset Retirement Obligations.
ASUAccounting Standards Update.
CAAClean Air Act.
CAIRCardinal Operating CompanyClean Air Interstate Rule.A jointly-owned organization between AGR and a nonaffiliate. The nonaffiliate operates the three unit Cardinal Plant and wholly-owns Units 2 and 3.
CARES ActCoronavirus Aid, Relief, and Economic Security Act signed into law in March 2020.
CLECOCentral Louisiana Electric Company, a nonaffiliated utility company.
CO2
 Carbon dioxide and other greenhouse gases.
Cook Plant Donald C. Cook Nuclear Plant, a two-unit, 2,2782,288 MW nuclear plant owned by I&M.
COVID-19Coronavirus 2019, a highly infectious respiratory disease. In March 2020, the World Health Organization declared COVID-19 a worldwide pandemic.
CSAPRCross-State Air Pollution Rule.
CWAClean Water Act.
CWIP Construction Work in Progress.
i





TermMeaning
DCC FuelDCC Fuel VI LLC,IX, DCC Fuel VII,X, DCC Fuel VIII,XI, DCC Fuel IXXII, DCC Fuel XIII, DCC Fuel XIV and DCC Fuel X,XV, consolidated variable interest entitiesVIEs formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
Desert SkyDesert Sky Wind Farm LLC, a 170 MW wind electricity generation facility located on Indian Mesa in Pecos County, Texas in which AEP owns a 100% interest.
DHLC Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo. DHLC is a non-consolidated VIE of SWEPCo.
DIRDistribution Investment Rider.
EISEnergy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated variable interest entityVIE of AEP.
ENECExpanded Net Energy Cost.
Energy SupplyAEP Energy Supply LLC, a nonregulated holding company for AEP’s competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP.
Equity UnitsAEP’s Equity Units issued in August 2020 and March 2019.
ERCOT Electric Reliability Council of Texas regional transmission organization.

i


TermMeaning
ESPElectric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO.
ETTElectric Transmission Texas, LLC, an equity interest joint venture between ParentAEP Transmission Holdco and Berkshire Hathaway Energy Company formed to own and operate electric transmission facilities in ERCOT.
Excess ADITExcess accumulated deferred income taxes.
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 from 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.Mercury and Air Toxic Standards.
MISO MidwestMidcontinent Independent Transmission System Operator.
MMBtu Million British Thermal Units.
MPSCMichigan Public Service Commission.
MTM Mark-to-Market.
MW Megawatt.
MWh Megawatthour.Megawatt-hour.
NOx
NAAQS		Nitrogen oxide.National 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.
ii





TermMeaning
NO2
Nitrogen dioxide.
NOx
Nitrogen oxide.
NPDESNational Pollutant Discharge Elimination System.
NSR New Source Review.
OATTOpen Access Transmission Tariff.
OCC Corporation Commission of the State of Oklahoma.
Ohio Phase-in-Recovery FundingOhio Phase-in-Recovery Funding LLC, a wholly-owned subsidiary of OPCo
Oklaunion Power StationA single unit coal-fired generation plant totaling 650 MW located in Vernon, Texas. The plant is 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.

ii


RacineA generation plant consisting of two hydroelectric generating units totaling 48 MWs located in Racine, Ohio and owned by AGR.
Reference Rate Reform
TermMeaning
The global transition away from referencing the London Interbank Offered Rate and other interbank offered rates, and toward new reference rates that are more reliable and robust.
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.
RSRROERetail Stability Rider.Return on Equity.
RPMReliability Pricing Model.
RTO Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine Sabine Mining Company, a lignite mining company that is a consolidated variable interest entityVIE for AEP and SWEPCo.
SECSanta Rita EastU.S.Santa Rita East Wind Holdings, LLC, a consolidated VIE whose sole purpose is to own and operate a 302.4 MW wind generation facility in west Texas in which AEP owns a 75% interest.
SECUnited States Securities and Exchange Commission.
SEETSempra Renewables LLCSempra Renewables LLC, acquired in April 2019, consists of 724 MWs of wind generation and battery assets in the United States.
SIPState Implementation Plan.
iii





Term Significantly Excessive Earnings Test.Meaning
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-onlyFERC regulated, transmission only electric utilities, each of which isare geographically aligned with AEPAEP’s existing utility operating companies.
SWEPCo Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCCTax ReformFormerly AEP Texas Central Company, nowOn 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 division of AEP Texas.reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018.
Texas Restructuring LegislationLegislation enacted in 1999 to restructure the electric utility industry in Texas.
TNCFormerly AEP Texas North Company, now a division of AEP Texas.
Transition Funding AEP Texas Central Transition Funding I LLC, AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated variable interest entitiesVIEs formed for the purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation.
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.
Transource MissouriTrentATrent Wind Farm LLC, a 156 MW wind electricity generation facility located between Abilene and Sweetwater in West Texas in which AEP owns a 100% wholly-owned subsidiary of Transource Energy.interest.
Turk Plant John W. Turk, Jr. Plant, a 600 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.
Utility Money Pool Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
VIEVariable Interest Entity.
Virginia SCC Virginia State Corporation Commission.
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

iii







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 1 – Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the 2016 Annual Report and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in AEPTCo’s 2016 Annual Report included within AEPTCo’s Registration Statement,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 and to recover those costs.
Ÿ•New legislation, litigation and government regulation, including 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•A reduction in the federal statutory tax rate could result in an accelerated return of deferred federal income taxes to customers.
ŸTiming 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.
Ÿ•Resolution of litigation.
Ÿ•The ability to constrain operation and maintenance costs.
Ÿ•The ability to develop and execute a strategy based on a view regarding prices of electricity and gas.
ŸPrices 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.
Ÿ•The ability to successfully and profitably manage competitive generation assets, including the evaluation and execution of strategic alternatives for these assets as some of the alternatives could result in a loss.

iv


ŸChanges 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





Ÿ•Accounting pronouncementsstandards periodically issued by accounting standard-setting bodies.
Ÿ•Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, naturally occurring and human-caused fires, cyber security threats and other catastrophic events.
•The ability to attract and retain the requisite work force and key personnel.


The forward-looking statements of the Registrants speak only as of the date of this report or as of the date they are made.  The Registrants expressly disclaim any obligation to update any forward-looking information.  For a more detailed discussion of these factors, see “Risk Factors” in Part I of the 20162019 Annual Report and in Part II of this report. Additionally, see “Risk Factors” in the AEPTCo 2016 Annual Report included within AEPTCo’s Registration Statement.


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

vi
v











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


EXECUTIVE OVERVIEW


COVID-19

In March 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 could reduce future demand for energy, particularly from commercial and industrial customers. Although AEP cannot predict the severity or duration of the impact of the COVID-19 pandemic, AEP currently anticipates a 2.7% reduction in weather-normalized retail sales volume in 2020 as compared to the prior year. For the nine months ended September 30, 2020, AEP experienced a reduction in weather-normalized retail sales volume of 3.0% as compared to the same period in the prior year primarily driven by a 7.0% decrease in the industrial customer class and a 4.9% decrease in the commercial customer class offset by an increase in demand of 2.6% from the residential customer class. The reduction in weather-normalized retail sales volume of 3.0% did not result in a significant decrease in the corresponding retail margins for the nine months ended 2020 as the increase in higher margin residential sales volumes partially offset the decreases in the industrial and commercial sales volumes. Furthermore, the rate design for certain industrial customers includes demand provisions designed to cover the fixed portion of utility costs minimizing the impact of the fluctuations in usage on revenues. AEP’s load forecast is highly dependent on many factors including, but not limited to, the speed and strength of economic recovery and the extent and duration of the next wave of COVID-19 infection. If the severity of the economic disruption increases, AEP’s future results of operations, financial condition, and cash flows could be further adversely impacted. See Customer Demand for additional information.

During the first quarter of 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. During the third and the fourth quarter of 2020, certain state regulators began to lift restrictions on disconnects. As of September 30, 2020, AEP resumed disconnections in its regulated jurisdictions with the exception of Virginia, West Virginia, Kentucky, Arkansas, Louisiana and Tennessee. AEP’s electric operating companies continue to work with regulators and stakeholders in these states and management currently anticipates resuming customary disconnection practices in the fourth quarter of 2020. However, this timing could change if there is new legislation or other regulatory directives issued in the future. 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. During the third quarter of 2020, the Registrants reviewed current collections experience with historical trends, specifically reviewing metrics such as cash collections, days sales outstanding, daily customer deposits, and aging summaries. In addition, the Registrants reviewed historical loss information generally comprised of a rolling 12-month average, in conjunction with a qualitative assessment of elements that impact the collectability of receivables, such as changes in economic factors, regulatory matters, industry trends, customer credit factors, payment plan options and other programs available to customers. Based on this review, the Registrants’ accounts receivable aging was negatively impacted primarily due to the suspension of customer disconnects. However, as disconnect moratoriums ended or are approaching their end dates, AEP is proactively engaging with customers to collect payments or establish payment arrangements for outstanding balances. As of September 30, 2020, AEP currently does not expect the deterioration in 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 affecting suspensions of disconnections and its impact on customer collections. Further deterioration in AEP’s ability to collect from its customers could significantly impact AEP’s future results of operations, financial conditions, and cash flows.

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In May 2020, AEP Credit amended its receivables securitization agreement to increase the eligibility criteria related to aged receivable requirements for the participating affiliated utility subsidiaries in response to the COVID-19 pandemic. As of September 30, 2020, 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, receivables would no longer be purchased by the bank conduits and the Registrants would need to rely on additional sources of funding for operation and working capital, which may adversely impact liquidity.

The Registrants have worked with their state commissions to achieve deferral authority for incremental expenses incurred due to COVID-19. All of AEP’s regulated jurisdictions have issued initial COVID-19 orders with the exception of Tennessee. If any costs related to COVID-19 are not recoverable, it could reduce future net income and cash flows and impact financial condition.

The effects of the continued COVID-19 pandemic and related government responses could also include extended disruptions to supply chains, reduced labor availability, reduced dispatch for certain generation assets and a prolonged reduction in economic activity. These effects could have a variety of adverse impacts to the Registrants, including their ability to operate their facilities. As of September 30, 2020, there were no material adverse impacts to the Registrants’ operations and supplier contracts due to COVID-19. AEP will continue to monitor developments affecting facility operations and will take additional actions necessary in order to mitigate adverse impacts to the Registrants’ future results of operations, financial condition, and cash flows.

In addition, the economic disruptions caused by COVID-19 could also adversely impact the impairment risks for certain long-lived assets, equity method investments and goodwill. AEP evaluated these impairment considerations and determined that no such impairments existed as of September 30, 2020.

Market volatility and reduction in collections coupled with longer collection periods due to the expansion of customer payment arrangements could reduce cash from operations and cause an adverse impact to liquidity. During the first nine months of 2020, AEP increased its liquidity position to mitigate the market risk and the collections risk due to COVID-19. During the first quarter of 2020, AEP entered into a $1 billion 364–day term loan to reduce reliance on commercial paper and help mitigate potential future liquidity risks. In addition, during the first nine months of 2020, AEP issued approximately $4.0 billion in long-term debt. As of September 30, 2020, AEP’s available liquidity was $3.8 billion. Management believes the Registrants have adequate liquidity under existing credit facilities. In the first quarter of 2020, AEP shifted capital expenditures of $500 million out of 2020 into future periods to further mitigate adverse liquidity impacts. In the second quarter of 2020, AEP reinstated $100 million of capital expenditures back into 2020 that had previously been deferred. To the extent that future access to the capital markets or the cost of funding is adversely affected by COVID-19, future results of operations, financial condition, and cash flows may be adversely impacted.

In March 2020, the CARES Act was signed into law.  The CARES Act includes tax relief provisions such as: (a) an Alternative Minimum Tax (AMT) Credit Refund, (b) a 5-year net operating losses (NOL) carryback from years 2018-2020 and (c) delayed payment of employer payroll taxes. In May 2020, the House passed the "Health and Economic Recovery Omnibus Emergency Solutions Act" (HEROES Act) pending decision by the Senate. If enacted, the HEROES Act would disallow NOL carrybacks to any tax year beginning before January 1, 2018.  Pursuant to the CARES Act, AEP, APCo and OPCo requested and in July received a $20 million, $7 million and $9 million, respectively, refund of AMT credit. In the third quarter of 2020, AEP also requested a $95 million refund of taxes paid in 2014 under the 5-year NOL carryback provision of the CARES Act. AEP carried back an 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 $52 million, recorded discretely, primarily at the Generation & Marketing segment. On October 1, 2020, after AEP filed its request with the IRS, the House passed a revised version of the HEROES Act; which similar to the original legislation would disallow NOL carryback to years prior to 2018. Management will continue to monitor the potential impact of this legislation. The Registrants are currently deferring payments of the employer share of payroll taxes for the period March 27, 2020 through December 31, 2020 and will pay 50% of the obligation by December 31, 2021 and the remaining 50% by December 31, 2022. As of September 30, 2020, the Registrants have deferred $32 million of the employer share of payroll taxes and anticipate to defer approximately $50 million by December 31, 2020.
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The Registrants are taking steps to mitigate the potential risks to customers, suppliers and employees posed by the spread of COVID-19. The Registrants have updated and implemented a company-wide pandemic plan to address specific aspects of COVID-19. This plan guides emergency response, business continuity, and the precautionary measures AEP is taking on behalf of its employees and the public. The Registrants have taken extra precautions for employees who work in the field and for employees who work in their facilities, and have work from home policies where appropriate. The Registrants will continue to monitor developments affecting both their workforce and customers, and will take additional precautions that management determines are necessary in order to mitigate the impacts. AEP continues to focus on providing safe, uninterrupted service to its customers, which includes the implementation of strong physical and cyber-security measures to ensure that its systems remain functional with a partially remote workforce. As of September 30, 2020, there has been no material adverse impact to the Registrants’ business operations and customer service due to remote work. Management will continue to review and modify plans as conditions change. Despite efforts to manage these impacts to the Registrants, the ultimate impact of COVID-19 also depends on factors beyond management’s knowledge or control, including the duration and severity of this outbreak as well as third-party actions taken to contain its spread and mitigate its public health effects. Therefore, management cannot estimate the potential future impact to financial position, results of operations and cash flows, but the impacts could be material.

Customer Demand


AEP’s weather-normalized retail sales volumes for the third quarter of 20172020 decreased by 0.7%2.6% from the third quarter of 2019. Weather-normalized residential sales increased by 3.8% in the third quarter of 2020 from the third quarter of 2019. AEP’s third quarter 2020 industrial sales volumes decreased by 7.8% compared to the third quarter of 2016. AEP’s third quarter 2017 industrial sales increased by 1.7% compared to the third quarter of 2016.2019. The growthdecline in industrial sales was spread across many industries and most operating companies.industries. Weather-normalized residentialcommercial sales decreased 2.4%4.6% in the third quarter of 2017 compared to2020 from the third quarter of 2016. Weather-normalized commercial sales decreased by 1.3% in the third quarter of 2017 compared to the third quarter of 2016.2019.


AEP’s weather-normalized retail sales volumes for the nine months ended September 30, 20172020 decreased by 0.4%3.0% compared to the nine months ended September 30, 2016.2019. Weather-normalized residential sales increased by 2.6% for the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019. AEP’s industrial sales volumes for the nine months ended September 30, 2017 increased 1.6%2020 decreased 7.0% compared to the nine months ended September 30, 2016.2019. The growthdecline in industrial sales was spread across many industries and most operating companies.industries. Weather-normalized residential and commercial sales decreased 1.5% and 1.4%, respectively,4.9% for the nine months ended September 30, 20172020 compared to the nine months ended September 30, 2016.2019.


Merchant Generation Assets

InAs a result of the impact of COVID-19, AEP revised its forecast for 2020 weather-normalized retail sales volumes in April 2020 and September 2016, AEP signed an agreement to sell Darby, Gavin, Lawrenceburg and Waterford Plants (“Disposition 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 proceeds2020 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.

The assets and liabilities includedforecast presented in the sale transaction have been recorded2019 10-K. In 2020, AEP currently anticipates weather-normalized retail sales volumes will decrease by 2.7%. AEP expects industrial class sales volumes to decrease by 6.5% in 2020, while weather-normalized residential sales volumes are projected to increase by 3.1%. Finally, AEP currently projects weather-normalized commercial sales volumes to decrease by 4.8%.

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(a)Percentage change for the year ended December 31, 2019 as Assets Heldcompared to the year ended December 31, 2018.
(b)As presented in the 2019 AEP 10-K: Forecasted percentage change for Salethe year ending December 31, 2020 compared to the year ended December 31, 2019.
(c)Revised for the impact of COVID-19 in April 2020: Forecasted percentage change for the year ending December 31, 2020 compared to the year ended December 31, 2019.
(d)Revised for the impact of COVID-19 in September 2020: Forecasted percentage change for the year ending December 31, 2020 compared to the year ended December 31, 2019.


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Regulatory Matters

AEP’s public utility subsidiaries are involved in rate and Liabilities Held for Sale, respectively,regulatory proceedings at the FERC and their state commissions.  Depending on the balance sheet as of December 31, 2016. See “Assetsoutcomes, these rate and Liabilities Held for Sale” 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 notregulatory proceedings can have a material impact on net income,results of operations, cash flows orand possibly financial condition. AEP is currently involved in the following key proceedings. See Note 4 - Rate Matters for additional information.


Management continues•2017-2019 Virginia Triennial Review - In March 2020, APCo submitted its 2017-2019 Virginia triennial earnings review filing and base rate case with the Virginia SCC as required by state law. APCo requested a $65 million annual increase in base rates based upon a proposed 9.9% ROE. Triennial reviews are subject to evaluate potential alternativesan earnings test, which provides that 70% of any earnings in excess of 70 basis points above APCo’s Virginia SCC authorized ROE would be refunded to customers. In such case, the Virginia SCC could also lower APCo’s Virginia retail base rates on a prospective basis. Virginia law provides that costs associated with asset impairments of retired coal generation assets, or automated meters, or both, which a utility records as an expense, shall be attributed to the test periods under review in a triennial review proceeding, and be deemed recovered. In 2015, APCo retired the Sporn Plant, the Kanawha River Plant, the Glen Lyn Plant, Clinch River Unit 3 and the coal portions of Clinch River Units 1 and 2 (collectively, the retired coal-fired generation assets). The net book value of the Virginia jurisdictional share of these plants was $93 million before cost of removal, including materials and supplies inventory and ARO balances. Based on management’s interpretation of Virginia law and more certainty regarding APCo’s triennial revenues, expenses and resulting earnings upon reaching the end of the three-year review period, APCo recorded a pretax expense of $93 million related to its previously retired coal-fired generation assets in December 2019. As a result, management deems these costs to be substantially recovered by APCo during the triennial review period. Inclusive of the Virginia jurisdictional share of the $93 million expense associated with APCo’s retired coal-fired generation assets, APCo calculated its 2017-2019 Virginia earnings for the remaining merchant generation assets. Thesetriennial period to be below the authorized ROE range. In July 2020, a certain intervenor filed testimony asserting that APCo had a revenue surplus of $23 million for its filed rate year based upon the intervenor’s recommended ROE of 8.75%. In addition, this intervenor submitted corrected testimony contending APCo’s earned return for the Triennial period was 11.12%, which equates to a potential alternatives may include, but are not limitedrefund to transfer or salecustomers of AEP’s ownership interests, or$34 million. See “2017-2019 Virginia Triennial Review” section of Note 4 for a wind downfull listing of merchantproposed adjustments and disallowances by intervenors. In August and September 2020, the Virginia staff filed testimony supporting an annual APCo Virginia jurisdictional revenue deficiency of $17 million based upon an ROE of 8.73%. However, Virginia staff contends APCo’s earned return for the triennial period was 9.55%, which is above the 9.42% midpoint of APCo’s authorized ROE range. Based on Virginia law, a Virginia SCC order finding an earned ROE above the midpoint would prevent APCo from receiving a prospective increase in Virginia retail rates. In addition, the staff recommended that APCo: (a) reverse the pretax Virginia jurisdictional share of the $93 million expense recorded in December 2019 for its retired coal-fired generation fleet operations. Managementassets and instead amortize the retired assets over a 10-year period beginning in 2015, (b) implement 2017 depreciation study rates effective January 2018 which would increase depreciation expense by $13 million and $15 million in 2018 and 2019, respectively, (c) implement 2019 depreciation study rates effective January 2020 which would increase depreciation expense by $18 million annually starting January 1, 2020 and (d) remove $9 million of major storm expenses and $12 million of coal combustion by-product expenses from the requested annual increase in base rates. APCo expects to receive an order in November 2020.

•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 September 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. SWEPCo is currently evaluating recovery options for the storm damage in its Arkansas jurisdiction. As of September 30, 2020, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $69 million ($67 million of which has been
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deferred as a regulatory asset related to the Louisiana jurisdiction) and incremental capital expenditures of $31 million ($30 million related to the Louisiana jurisdiction).

•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 the fourth quarter of 2019 and first quarter of 2020, SWEPCo and various intervenors filed briefs with the Texas Supreme Court. In August 2020, the Texas Supreme Court granted SWEPCo’s petition for review and oral arguments were scheduled for December 2020. As of September 30, 2020, the net book value of Turk Plant was $1.4 billion, before cost of removal, including materials and supplies inventory and CWIP. SWEPCo’s Texas jurisdictional share of the Turk Plant investment is approximately 33%.

•In July 2019, clean energy legislation (HB 6) which offers 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 including lost shared savings revenues of $26 million annually and renewable mandates no later than 2020 and after 2026, respectively.  HB 6 also provided for the recovery of existing renewable energy contracts on a bypassable basis through 2032 and included a provision for recovery of OVEC costs through 2030 which will be allocated to all electric distribution utilities on a non-bypassable basis.  OPCo’s Inter-Company Power Agreement for OVEC terminates in June 2040. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of the Speaker of the Ohio House of Representatives, Larry Householder, four other individuals, and Generation Now, an entity registered as a 501(c)(4) social welfare organization, in connection with a racketeering conspiracy involving the adoption of HB 6. In light of the allegations in the indictment, proposed legislation has been introduced that would repeal HB 6. The outcome of the U.S. Attorney’s Office investigation and its impact on HB 6 is not setknown. If the provisions of HB 6 were to be eliminated, it is unclear whether and in what form the Ohio General Assembly would pass new legislation addressing similar issues. In August 2020, an AEP shareholder filed a specific time frameputative class action lawsuit against AEP and certain of its officers for alleged violations of securities laws. See Litigation Related to Ohio House Bill 6 section of Litigation below for additional information. To the extent that OPCo is unable to recover the costs of renewable energy contracts on a decision on these assets. These alternatives could result in additional losses whichbypassable basis by the end of 2032, recover costs of OVEC after 2030, fully recover energy efficiency costs through 2020 or incurs significant costs defending against the class action lawsuit, it could reduce future net income and cash flows and impact financial condition.


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

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.

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The following tables show the Registrants’ completed and pending base rate case proceedings in 2020. See Note 4 - Rate Matters for additional information.

Completed Base Rate Case Proceedings
Approved RevenueApprovedNew Rates
CompanyJurisdictionRequirement Increase (Decrease)ROEEffective
(in millions)
I&MMichigan$36.4 (a)9.86%February 2020
I&MIndiana77.4 (b)9.7%March 2020
AEP TexasTexas(40.0)9.4%June 2020

(a)In January 2020, the MPSC issued an order approving a stipulation and settlement agreement. See “2019 Michigan Base Rate Case” section of Note 4 Rate Matters in the 2019 Annual Report for additional information.
(b)Will be phased-in through an increase in base rates which includes: (a) an annual increase in base rates of $44 million effective March 2020 and (b) an annual increase in base rates of up to $77 million effective January 2021 based on the IURC-approved forecast of December 31, 2020 Indiana jurisdictional electric plant in service. A compliance filing will be made in January 2021 to adjust the final rate increase to reflect the lower of I&Ms actual or IURC-approved Indiana jurisdictional electric plant in service balance as of December 31, 2020. The order rejected I&M’s proposed re-allocation of capacity costs related to the loss of a significant FERC wholesale contract, which will negatively impact I&M’s annual pretax earnings by approximately $20 million starting June 2020.

Pending Base Rate Case Proceedings
Commission Staff/
FilingRequested RevenueRequestedIntervenor Range of
CompanyJurisdictionDateRequirement IncreaseROERecommended ROE
(in millions)
APCoVirginiaMarch 2020$64.9 9.9%8.73% - 8.75%
OPCoOhioJune 202042.3 10.15%(a)
KPCoKentuckyJune 202065.0 10%8.93% - 9.25%
SWEPCoTexasOctober 2020105.0 (b)10.35%(a)

(a)Awaiting procedural schedule.
(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.

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 utilizes two subsidiariescontinues to develop its renewable portfolio within the Generation & Marketing segment to further develop its renewable portfolio.  AEP OnSite Partners, LLC workssegment.  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.  AEP OnSite Partners, LLC pursues projects where a suitable termed agreement is entered into with a creditworthy counterparty.  AEP Renewables, LLCThe Generation & Marketing segment also develops and/or acquires large scale renewable generation projects that are backed with long-term contracts with creditworthy counterparties.

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As of September 30, 2017, these2020, subsidiaries havewithin AEP’s Generation & Marketing segment had approximately 1481,520 MWs of contracted renewable generation projects in operation and $292 million of capital costs have been incurred related to these projects.in-service.  In addition, as of September 30, 2017,2020, these subsidiaries havehad approximately 42140 MWs of renewable generation projects under construction andwith total estimated capital costs of $54$243 million related to these projects. As of September 30, 2017, total estimated capital costs related to these renewable generation projects were approximately $346 million.


Regulated Renewable Generation Facilities


In July 2017, APCo submitted filings with the Virginia SCC and the WVPSC requesting regulatory approval to acquire two wind generation facilities totaling approximately 225 MW of wind generation. The wind generating facilities are located in West Virginia 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 July 2017,2019, PSO and SWEPCo submitted filingswith the OCC, LPSC, APSC and PUCT requesting various regulatory approvals needed to fully proceed with the Wind Catcher Project. The Wind Catcher Project 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. Total investment before their respective commissions for the project is estimatedapproval to be $4.5 billion andacquire the North Central Wind Energy Facilities, comprised of three Oklahoma wind facilities totaling 1,485 MWs, on a fixed cost turn-key basis at completion.  PSO will serve both retail and FERC wholesale load. PSOown 45.5% and SWEPCo will haveown 54.5% of the project, which will cost approximately $2 billion.  In May 2020, the IRS issued a 30%notice extending the “Continuity Safe Harbor” deadlines for qualifying renewable energy projects that began construction in 2016 and 70% ownership share, respectively,2017 by one year as many projects are facing supply chain and other project development delays caused by COVID-19. Under the May 2020 IRS notice, qualifying renewable energy projects that began construction in these assets. The wind generating facility is located in Oklahoma2016 and if approved by all state commissions, is anticipated to be2017 and which are placed in-service by the end of 2020. 2021 and 2022, respectively, will satisfy the Continuity Safe Harbor. Provided that each facility satisfies the Continuity Safe Harbor, under the current IRS guidance, the 199 MW wind facility will qualify for 100% of the federal PTC, and the remaining two wind facilities, totaling 1,286 MWs, will qualify for 80% of the federal PTC. The 199 MW wind facility is targeted to be placed in-service and acquired in March 2021. The 287 MW wind facility is targeted to be placed in-service and acquired in December 2021 and the 999 MW wind facility is targeted to be placed in-service and acquired between December 2021 and April 2022. All three wind facilities are expected to satisfy the Continuity Safe Harbor.

In July 2017,February 2020, the OCC approved PSO’s settlement agreement. In May 2020, the APSC approved the settlement agreement as filed, with the exception that SWEPCo use its formula rate rider to recover its costs rather than the requested rider. Also in May 2020, the LPSC approved SWEPCo’s request for an exemptionthe settlement agreement as filed. Both the APSC and LPSC approved the flex-up option, agreeing to acquire the Market Based Mechanism. In August 2017,Texas portion, which the Oklahoma Attorney General filed a motion to dismissPUCT denied in July 2020. Having regulatory approval and the IRS extension of the “Continuity Safe Harbor,” PSO and SWEPCo are proceeding with the OCC. full 1,485 MW development of these three projects.

Hydroelectric Generation

Evaluating Sale of Hydroelectric Generation

In August 2017,March 2020, management placed 10 hydroelectric generation plants under study for a potential sale. In April 2020, the motion to dismissVirginia Clean Economy Act was deniedsigned into law by the OCC. Hearings at the APSC, LPSC, OCC and PUCT are scheduled in the first quarter of 2018.

Hurricane Harvey

In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory.Virginia Governor. The new law will provide renewable credits to APCo for its existing hydroelectric generation plants. As restoration efforts are ongoing, AEP Texas’ total costs related to this storm are not yet known. AEP Texas’ current estimated cost is approximately $250 million to $300 million, including capitalized expenditures. AEP Texas currently estimates that it will incur approximately $90 million of operation and maintenance costs related to service restoration efforts. AEP Texas has a PUCT approved catastrophe reserve in base rates and can defer incremental storm expenses. AEP Texas currently recovers approximately $1 million of storm costs annually through base rates. As of September 30, 2017, the total balance of AEP Texas’ deferred storm costs is approximately $97 million including approximately $73 million of incremental storm expenses as a regulatory asset related to Hurricane Harvey. Management is currently in the early stages of analyzing the impact of potential insurance claims and recoveries and, at this time, cannot estimate this amount. Any future insurance recoveries received will be applied to and will offset the regulatory asset and property, plant and equipment, as applicable. AEP Texas is currently evaluating recovery options for the regulatory asset; however, management believes the asset is probable of recovery. The other named hurricanes did not have a material impact on AEP’s operations in the third quarter of 2017. If the ultimate costsresult of the incident are not recovered by insurance or throughnew law, management removed the regulatory process, it could have an adverse effect on future net income, cash flowsthree APCo hydroelectric generation plants (London, Marmet and financial condition.

Merchant PortionWinfield) from the list 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.

plants identified for potential sale. 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 jurisdictional share of the Turk 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 (subject to prudence review) and through SWEPCo’s wholesale customers under FERC-based rates. As of September 30, 2017,table below shows the net book value of Turk Plant was $1.5 billion,each plant, including CWIP and materials and supplies, before cost of removal including materials and supplies inventory and CWIP. In October 2017, the LPSC staff filed a prudence review of the Turk Plant. See “Louisiana Turk Plant Prudence Review” section of Note 4.remaining plants included in the study.

OwnerPlant NameUnitsStateNet Book Value as of September 30, 2020Net Maximum
Capacity (MWs)		Year Plant or First Unit Commissioned
(in millions)
AGRRacine2OH$44.7 48 1982
I&MBerrien Springs12MI6.2 6 1908
I&MBuchanan10MI4.3 3 1919
I&MConstantine4MI2.3 1 1921
I&MElkhart3IN5.2 3 1913
I&MMottville4MI2.7 2 1923
I&MTwin Branch Hydro8IN5.7 5 1904
Total  $71.1 68  

If SWEPCo cannot ultimately recover its investmentmanagement decides to proceed with the sale of these plants, FERC approval would be required. In addition, for all plants, except for Racine, state commission approval would be required. Management currently estimates that any potential sale agreements for these plants would not be entered into until late 2020 at the earliest. There is no assurance that management will be able to sell any of these plants.
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Dolet Hills Power Station and expenses related toRelated Fuel Operations

During the Turk Plant, it could reduce future net income and cash flows and impact financial condition.

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

second quarter of 2019, the Dolet Hills Power Station initiated a seasonal operating schedule. In March 2016, a contested stipulation agreement related 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. ConsistentJanuary 2020, in accordance with the terms of a modified and approved stipulation agreement, and based upon a September 2016 PUCO order, in November 2016, OPCo refiledSWEPCo’s settlement of its amended ESP extension application and supporting testimony. The amended filing proposedbase rate review filed with the APSC, management announced that SWEPCo will seek regulatory approval to extendretire the ESP through May 2024 and included (a) an extensionDolet Hills Power Station by the end of 2026. DHLC provides 100% of the OVEC PPA rider, (b) a proposed 10.41% returnfuel supply to Dolet Hills Power Station. After careful consideration of current economic conditions, and particularly for the benefit of their customers, management of SWEPCo and CLECO determined DHLC would not proceed developing additional Oxbow Lignite Company (Oxbow) mining areas for future lignite extraction and ceased extraction of lignite at the mine in May 2020. Based on common equity on capital costs for certain riders, (c)these actions, management revised the continuationestimated useful life of riders previously approvedDHLC’s and Oxbow’s assets to coincide with the date at which extraction was discontinued in the June 2015 - May 2018 ESP, (d) proposed increasessecond quarter of 2020 and the date at which delivery of lignite is expected to cease in rate caps relatedSeptember 2021. Management also revised the useful life of the Dolet Hills Power Station to OPCo’s DIR2021 based on the remaining estimated fuel supply available for continued seasonal operation. In March 2020, primarily due to the revision in the useful life of DHLC, SWEPCo recorded a revision to increase estimated ARO liabilities by $21 million. In April 2020, SWEPCo and (e) the addition of various new riders, including a Renewable Resource Rider.

In August 2017, OPCo and various intervenorsCLECO jointly filed a stipulation agreement withnotification letter to the PUCO. The stipulation extends the termLPSC providing notice of the ESPcessation of lignite mining.

The Dolet Hills Power Station costs are recoverable by SWEPCo through May 2024 and includes: (a) an extensionbase rates. SWEPCo’s share 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 approvednet investment in the June 2015 - May 2018 ESP, (d) rate caps related to OPCo’s DIR ranging from $215Dolet Hills Power Station is $153 million, to $290 million for the periods 2018 through 2021, (e) the additionincluding CWIP and materials and supplies, before cost 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, effective January 2018, 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.removal.


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 is subject to reviewFuel costs incurred by the PUCO. A hearing atDolet Hills Power Station are recoverable by SWEPCo through active fuel clauses. Under the PUCOLignite Mining Agreement, DHLC bills SWEPCo its proportionate share of incurred lignite extraction and associated mining-related costs as fuel is scheduled for November 2017.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. See “Ohio Electric Security Plan Filings” section of Note 4.

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. Although 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 SEET treatment of the Global Settlement issues described above or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could reduce future net income and cash flows and impact financial condition. See “2016 SEET Filing” section of Note 4.

Rockport Plant, Unit 2 Selective Catalytic Reduction (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.delivered. As of September 30, 2017, total2020, DHLC has unbilled lignite inventory and fixed costs incurred relatedof $36 million that will be billed to this project, including AFUDC, were approximately $17 million.  The filing includedSWEPCo prior to the closure of the Dolet Hills Power Station. In 2009, SWEPCo acquired interests in Oxbow, which owns mineral rights and leases land. Under a request for authorization for I&MJoint Operating Agreement pertaining to deferthe Oxbow mineral rights and land leases, Oxbow bills SWEPCo its Indiana jurisdictional ownershipproportionate share of incurred costs. As of September 30, 2020, Oxbow has unbilled fixed 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$10 million that will be billed to SWEPCo prior to the existing Clean Coal Technology Rider in a future filing subsequent to approvalclosure of the SCR project. The AEGCo ownership shareDolet Hills Power Station. DHLC and Oxbow have billed SWEPCo $111 million for lignite deliveries from April 2020 through September 2020, which primarily includes accelerated depreciation and amortization of fixed costs. Additional operational and land-related costs are expected to be incurred by DHLC and Oxbow and billed to SWEPCo prior to the closure of the proposed SCR project will be billable under the Rockport UnitDolet Hills Power Agreement to I&MStation and KPCo and will be subject to future regulatory approval for recovery. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and limitations on other costs related to legal issues involving the Rockport Plant, Unit 2 lease. A hearing at the IURC was held in March 2017. An order from the IURC is pending. In July 2017, I&M filed a motion with the U.S. District Court for the Southern District of Ohio to remove the requirement to install SCR technology at Rockport Plant, Unit 2. In August 2017, the district court delayed the deadline for installation of the SCR technology until March 2020.through fuel clauses.

2017 Indiana Base Rate Case


In July 2017, I&MOctober 2020, SWEPCo filed a request with the IURCLPSC for a $263 million annual increase in Indiana rates based upon a proposed 10.6% return on common equity withrecovery of 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. A hearing at the IURC is scheduled for January 2018. If anyLouisiana share of these additional fuel costs. SWEPCo’s filing proposes to defer $36 million of fuel costs are not recoverable, it could reduce future net incomein 2021 and cash flows and impact financial condition.recover the deferral plus carrying costs over five years beginning in 2022.

2017 Michigan Base 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. Additionally, the total proposed increase includes incremental costs related to the Cook Plant Life Cycle Management Program and increased vegetation management expenses. In October 2017, the MPSC staff and intervenors filed testimony.  The MPSC staff recommended an annual net revenue increase of $49 million including proposed retirement dates of 2028 for both Rockport Plant, Units 1 (from 2044) and 2 (from 2022) and a return on common equity of 9.8%. The intervenors


proposed certain adjustments to I&M’s request including no change to the current 2044 retirement date of Rockport Plant, Unit 1, but did not propose an annual net revenue increase. Their recommended return on common equity ranged from 9.3% to 9.5%. A hearing at the MPSC is scheduled for November 2017. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Louisiana Turk Plant Prudence Review

Beginning January 2013, SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 33%) of the Turk Plant, have been collected subject to refund pending the outcome of a prudence review of the Turk Plant investment, which was placed into service in December 2012. In October 2017, the LPSC staff filed testimony contending that SWEPCo failed to continue to evaluate the suspension or cancellation of the Turk Plant during its construction period. The testimony also identified five individual items totaling approximately $51 million for potential disallowance relating to Louisiana’s jurisdictional share of Turk Plant. As a result of SWEPCo’s alleged failure to meet its continuing prudence obligations, the LPSC staff recommends one of the following potential unfavorable scenarios: (a) 50/50 sharing of construction cost overruns between SWEPCo and ratepayers, (b) an imposition of a cost cap similar to Texas or (c) approximately a 1% reduction of the rate on common equity for the Turk Plant. As SWEPCo has included the full value of the Turk Plant in rate base since its in-service date, SWEPCo may be required to refund potential over-collections from January 2013 through the date new rates are implemented. As of September 30, 2017, if the LPSC adopts one of these potential scenarios, and disallows the five individual items, pretax write-offs could range from $50 million to $80 million and refund provisions, including interest, could range from $15 million to $27 million. Future annual revenue reductions could range from $3 million to $4 million. Management will continue to vigorously defend against these claims. If the LPSC orders in favor of one of these scenarios, it could reduce future net income and cash flows and impact financial condition. A hearing at the LPSC is scheduled for December 2017.

2017 Oklahoma Base Rate Case

In June 2017, PSO filed an application for a base rate review with the OCC that requested a net increase in annual revenues of $156 million based upon a proposed 10% return on common equity. The proposed base rate increase includes (a) environmental compliance investments, including recovery of previously deferred environmental compliance related costs currently recorded as regulatory assets, (b) Advanced Metering Infrastructure investments, (c) additional capital investments and costs to serve PSO’s customers, and (d) an annual $42 million depreciation rate increase due primarily to shorter service lives and lower net salvage estimates. As part of this filing, consistent with the OCC’s final order in its previous base rate case, PSO requested recovery through 2040 of Northeastern Plant, Unit 3, including the environmental control investment, and the net book value of Northeastern Plant, Unit 4 that was retired in 2016. As of September 30, 2017, the net book value of Northeastern Plant, Unit 4 was $82 million.

In September 2017, various intervenors and the OCC staff filed testimony that included annual net revenue increase recommendations ranging from $28 million to $108 million. The recommended returns on common equity ranged from 8% to 9%. In addition, certain parties recommended investment disallowances that ranged from $27 million to $82 million related to Northeastern Plant, Unit 4 and $38 million associated with capitalized incentives. Also, a party recommended a potential refund of $43 million related to an SPP rider claiming that PSO did not adequately support the related SPP costs. The combined total impact could result in a write-off and refund of up to approximately $163 million. In addition, if similar plant recovery issues would apply to Northeastern Plant, Unit 3, the net book value of plant, including regulatory assets, materials and supplies inventory and CWIP of $346 million as of September 30, 2017, could be adversely impacted. A hearing at the OCC is scheduled to begin in October 2017.


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 CaseFERC Transmission ROE Methodology


Management continues to monitor FERC’s 2019 Notice of Inquiry regarding base ROE policy, FERC’s 2020 Notice of Proposed Rulemaking regarding transmission incentives policy, and various other matters pending before FERC with the potential to affect FERC transmission ROE methodology.

In June 2017, KPCo filed a request with the KPSCsecond quarter of 2019, 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 a $66 million annual increase in KentuckyAEP’s PJM and SPP transmission-owning subsidiaries, respectively. In the second quarter of 2020, FERC Order 569A determined the base rates based upon a proposed 10.31% return on common equity with the increase toROE for MISO’s transmission owning members, including AEP’s MISO transmission-owning subsidiaries, should be implemented no later than January 2018. The proposed increase includes: (a) lost load since KPCo last changed base rates in July 2015, (b) incremental costs


related to OATT charges from PJM not currently recovered from retail ratepayers, (c) increased depreciation expense including updated Big Sandy Plant, Unit 1 depreciation rates using a proposed retirement date of 2031, (d) recovery of other Big Sandy Plant, Unit 1 generation costs currently recovered through a retail rider and (e) incremental purchased power costs. Additionally, KPCo requested a $4 million annual increase in environmental surcharge revenues.

In August 2017, KPCo submitted a supplemental filing with the KPSC that decreased the proposed annual base rate revenue request to $60 million. The modification was due to a lower interest expense related to June 2017 debt refinancings. In October 2017, various intervenors filed testimony that included annual net revenue increase recommendations ranging from $13 million to $40 million. Intervenors recommended returns on common equity ranging from 8.6% to 8.85%. Intervenors also recommended significant delays in KPCo’s proposed recoveries of: (a) depreciation expense related to Big Sandy Plant, Unit 1 (gas unit), proposing a 30-year depreciable life instead of KPCo’s proposed 15-year life and (b) lease expense on Rockport Plant, Unit 2 billed from AEGCo, proposing that the approximate $100 million of lease expense for the period 2018 through 2022 be deferred with a WACC carrying charge for recovery over 10 years beginning 2023. Testimony on behalf10.02% (10.52% inclusive of the Attorney General also discussed that the KPSC could consider disallowing all or a portionRTO incentive adder of the costs currently being recovered over 25 years through the Big Sandy Plant, Unit 2 retirement rider.  As of September 30, 2017, KPCo’s regulatory asset related to the retired Big Sandy Plant, Unit 2 was $289 million. A hearing at the KPSC is scheduled for December 2017.0.5%).

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If FERC makes any of these costs are not recoverable, itchanges to its ROE and incentive policies, they would be applied, as applicable, to AEP’s PJM, SPP and MISO transmission owning subsidiaries on a prospective basis, and could reduceaffect 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. In September 2017, the Administrative Law Judges (ALJs) issued their proposal for decision including an annual net revenue increase of $50 million including recovery of Welsh Plant, Unit 2 environmental investments as of June 30, 2016. The ALJs proposed a return on common equity of 9.6% and recovery of but no return on Welsh Plant, Unit 2. The ALJs rejected SWEPCo’s proposed transmission cost recovery mechanism. The estimated potential write-off associated with the ALJs proposal is approximately $22 million which includes $9 millionassociated with the lack of a return on Welsh Plant, Unit 2.

If any of these costs are not recoverable, including environmental investments and retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. See “2016 Texas Base Rate Case” section of Note 4.

FERC Transmission Complaint - AEP’s PJM Participants

In October 2016, several parties filed a joint complaint at the FERC that states the base return on common equity used by AEP’s eastern transmission subsidiaries 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. 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 PJM Transmission Rates

In November 2016, AEP’s eastern transmission subsidiaries 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. Effective January 1, 2017, the modified PJM OATT formula rates were implemented, subject to refund, based on projected 2017 calendar year financial activity and projected plant balances. 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 Transmission Complaint - AEP’s SPP Participants

In June 2017, several parties filed a joint complaint at the FERC that states the base return on common equity used by AEP’s western transmission subsidiaries 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. 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.

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. 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 September 30, 2017, SWEPCo had incurred costs of $398 million, including AFUDC, related to these projects.  Management continues to evaluate the impact of environmental rules and related project cost estimates. As of September 30, 2017, the total net book value of Welsh Plant, Units 1 and 3 was $626 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 December 2016, the LPSC approved deferral of certain expenses related to the Louisiana jurisdictional share of environmental controls installed at Welsh Plant. In April 2017, the LPSC approved SWEPCo’s recovery of these deferred costs 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 September 30, 2017, (b) is subject to review by the LPSC, and (c) includes a WACC return on environmental investments and the related depreciation expense and taxes. Effective May 2017, SWEPCo began recovering $131 million in investments related to its Louisiana jurisdictional share of environmental costs. SWEPCo has sought recovery of its project costs from retail customers in its current Texas base rate case at the PUCT and is recovering these costs from wholesale customers through SWEPCo’s FERC-approved agreements.

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.

Westinghouse Electric Company Bankruptcy Filing

In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the U.S. Bankruptcy Code.  It intends to reorganize, not cease business operations. However, it is in the early stages of the bankruptcy process and it is unclear whether the company can successfully reorganize.  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.  I&M is evaluating how this reorganization affects these contracts.  Westinghouse has stated that it intends to continue performance on I&M’s contracts, but given the importance of upcoming dates in the fuel fabrication process for Cook Plant, and their vital part in Cook Plant’s ongoing operations, I&M continues to work with Westinghouse in the bankruptcy proceedings to avoid any interruptions to that service. In the unlikely event Westinghouse rejects I&M’s contracts, or is unable to reorganize or sell its profitable businesses in the bankruptcy, Cook Plant’s operations would be significantly impacted and potentially shut down temporarily as I&M seeks other vendors for these services.


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, Note 6 - Commitments, Guarantees and Contingencies and the “Litigation” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2016 Annual Report. Additionally, see Note 4 - Rate Matters and Note 5 - Commitments, Guarantees and Contingencies included herein. 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 eliminatedecree. The district court granted the 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. In October 2017, the owners filed aowners’ unopposed motion to stay their claims until January 2018,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 was filed in October 2020. All deadlines, including discovery, are stayed, pending resolution of the motion. See “Modification of the NSR Litigation Consent Decree” section below for additional information.


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, management cannot determine a range of potential losses that is reasonably possible of occurring.


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Patent Infringement Complaint

In July 2019, Midwest Energy Emissions Corporation and MES Inc. (collectively, the plaintiffs) filed a patent infringement complaint against various parties, including AEP Texas, AGR, Cardinal Operating Company and SWEPCo (collectively, the AEP Defendants). The complaint alleges that the AEP Defendants infringed two patents owned by the plaintiffs by using specific processes for mercury control at certain coal-fired generating stations.  In July 2020, plaintiffs amended the complaint to add three new patents. The amended complaint seeks injunctive relief and damages.  The case is scheduled for trial in January 2023. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

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

The American Electric Power System Retirement Plan (the Plan) has received a letter written on behalf of four participants (the Claimants) making a claim for additional plan benefits and purporting to advance such claims on behalf of a class. When the Plan’s benefit formula was changed in the year 2000, AEP provided a special provision for employees hired before January 1, 2001, allowing them to continue benefit accruals under the then benefit formula for a full 10 years alongside of the new cash balance benefit formula then being implemented.  Employees who were hired on or after January 1, 2001 accrued benefits only under the new cash balance benefit formula.  The Claimants have asserted claims that (a) the Plan violates the requirements under the Employee Retirement Income Security Act (ERISA) intended to preclude back-loading the accrual of benefits to the end of a participant’s career; (b) the Plan violates the age discrimination prohibitions of ERISA and the Age Discrimination in Employment Act; and (c) the company failed to provide required notice regarding the changes to the Plan.  AEP has responded to the Claimants providing a reasoned explanation for why each of their claims have been denied. The denial of those claims was appealed to the AEP System Retirement Plan Appeal Committee and the Committee upheld the denial of claims. Management will continue to defend against the claims.  Management is unable to determine a range of potential losses that are reasonably possible of occurring.


Litigation Related to Ohio House Bill 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 complaint alleges misrepresentations or omissions by AEP regarding: (a) its alleged participation in public corruption with respect to the passage of Ohio House Bill 6, (b) its regulatory, legislative and lobbying activities in Ohio and (c) its clean energy strategy. The complaint seeks monetary damages among other forms of relief. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

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 products,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.requirements.  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.


See a complete discussion of these matters in the “Environmental Issues” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2016 Annual Report.
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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 in the next several sectionsbelow 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 September 30, 2017,2020, the AEP System had a total generating capacity of approximately 25,60024,300 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 $2.2$500 million to $1 billion to $2.8 billion between 2017 and 2025.through 2026.


The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in finalizing proposed rules or reviewing and 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 represents the plants or units of plants retired in 2016 and 2015 with a remaining net book value. As of September 30, 2017, 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 $338 million. Management is seeking or will seek recovery of the remaining net book value associated with these plants in future rate proceedings.
    Generating Amounts Pending
Company Plant Name and Unit Capacity Regulatory Approval
    (in MWs)  (in millions)
APCo Kanawha River Plant 400
 $42.3
APCo Clinch River Plant, Unit 3 235
 32.7
APCo (a) Clinch River Plant, Units 1 and 2 470
 31.8
APCo Sporn Plant 600
 17.2
APCo Glen Lyn Plant 335
 13.4
I&M (b) Tanners Creek Plant 995
 42.6
PSO (c) Northeastern Plant, Unit 4 470
 82.4
SWEPCo (d) Welsh Plant, Unit 2 528
 75.9
Total   4,033
 $338.3

(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.
(c)
For Northeastern Plant, Unit 4, in November and December 2016, the OCC issued orders that provided no determination related to the return of and return on the post-retirement remaining net book value. In June 2017, PSO filed an application for a base rate review with the OCC. As part of this filing, PSO requested recovery of approximately $82 millionthrough 2040 related tothe net book value of Northeastern Plant, Unit 4 that was retired in 2016. This regulatory asset is pending regulatory approval.
(d)SWEPCo requested recovery of the Texas jurisdictional share (approximately 33%) of the net book value of Welsh Plant, Unit 2 in the 2016 Texas Base Rate Case. This regulatory asset is pending regulatory approval.

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 September 30, 2017, AGR’s net book value of the Stuart Plant, Units 1-4 was zero.

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

Proposed Modification of the New Source Review (NSR) 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 itthey undertook various equipment repair and replacement projects over a period of nearly 20 years.  The consent decree’s terms include installation of environmental control equipment on certain generating units, a declining cap on SO2 and NOx emissions from the AEP System and various mitigation projects.


In July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohiodistrict court seeking to modify 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 other parties to the consent decree opposed AEP’s motion. The district court granted AEP’s request to delay the deadline to install SCRSelective Catalytic Reduction (SCR) technology at Rockport Plant, Unit 2 until March 2020, pending resolutionJune 2020. Construction of the motion.  AEP also proposes to retire Conesville Plant, UnitsSCR technology was completed by June 1, 2020, testing was conducted, and the unit was released for dispatch on June 5, and 6 by December 31, 2022 and to retire one Rockport Plant unit by December 31, 2028.2020.



AEP is seekingIn May 2019, the parties filed a proposed order to modify the consent decree as a meansdecree. The proposed order requires AEP to resolve or substantially narrowenhance the issuesdry sorbent injection (DSI) system on both units at the Rockport Plant by the end of 2020, and meet 30-day rolling average emission rates for SO2 and NOx at the combined stack for the Rockport Plant beginning in pending litigation with2021. Total SO2 emissions from the owners ofRockport Plant are limited to 10,000 tons per year beginning in 2021 and reduce to 5,000 tons per year when Rockport Plant, Unit 2. See “Rockport1 retires in 2028. The proposed modification was approved by the district court and became effective in July 2019. As part of the modification to the consent decree, I&M agreed to provide an additional $7.5 million to citizens’ groups and the states for environmental mitigation projects. As joint owners in the Rockport Plant, Litigation” in Management’s Discussionthe $7.5 million payment was shared between AEGCo and Analysis of Financial Condition and Results of Operations and in Note 5 - Commitments, Guarantees and Contingencies for additional information.I&M based on the joint ownership agreement.



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Clean Air Act Requirements


The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions. The states implement and administer many of these programs and could impose additional or more stringent requirements. The primary regulatory programs that continue to drive investments in AEP’s existing generating units include: (a) periodic revisions to 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.


National Ambient Air Quality Standards (NAAQS)


The Federal EPA issued new, more stringent NAAQSreviewed the existing standards for SONO2 and SO2 in 2010, PM in 20122018 and ozone in 2015.2019, respectively, and decided to retain the standards without change. Implementation of these standards is underway. States are stillThe Federal EPA is currently reviewing the existing standards for PM, last revised in 2012, and ozone, last revised in 2015. A proposed rule to retain the existing PM standards was released in April 2020. A proposed rule to retain the existing standards for ozone was released in August 2020.

The Federal EPA finalized non-attainment designations for the 2015 ozone standard in 2018. The Federal EPA confirmed that for states included in the processCSAPR program, there are no additional interstate transport obligations, as all areas of evaluating the attainment status and need for additional control measures in ordercountry are expected to attain and maintain the 2010 SO2 NAAQS2008 ozone standard before 2023. Challenges to the 2015 ozone standard and may develop additional requirements for AEP’s facilities as a result of those evaluations. In April 2017, the Federal EPA requested a stay of proceedingsEPA’s determination that CSAPR satisfies certain states’ interstate transport obligations were filed in the U.S. Court of Appeals for the District of Columbia Circuit where challenges toCircuit. In August 2019, the court upheld the 2015 primary ozone standard, are pending, to allow reconsideration ofbut remanded the secondary welfare-based standard for further review. The court vacated the Federal EPA’s determination that standardCSAPR fulfilled the states’ interstate transport obligations, because the Federal EPA’s modeling analysis did not demonstrate that all significant contributions would be eliminated 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. Final designations were due October 1, 2017, but have not yet been announced.attainment deadlines for downwind states. Any further changes will require additional rulemaking. Management cannot currently predict the nature, stringency or timing of additional requirements for AEP’s facilities based on the outcome of these activities.


Regional Haze


The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA’s requirement that certain facilities install best available retrofit technology (BART) willwould 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 be implemented through SIPs or if SIPs are not adequate or are not developed on schedule, 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 of regional haze SIPs in a few states, including Arkansas and Texas.  In March 2012, the Federal EPAinitially disapproved certain portions of the Arkansas regional haze SIP. In April 2015,SIP, but has approved a revised SIP and all of SWEPCo's affected units are in compliance with the relevant requirements.

The Federal EPA published a proposed FIP to replace the disapproved portions, including revised BART determinations for the Flint Creek Plant that were consistent with the environmental controls currently under construction. 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 Court 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 proposed to approve that SIP revision. Arkansas and the Federal EPA have asked the Eighth Circuit to continue to hold litigation in abeyance until October 31, 2017 to facilitate settlement discussions. Management cannot predict the outcome of these proceedings.

In January 2016, the Federal EPAalso 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 Court. The parties engaged in a settlement discussion but were unable to reach an agreement.SIP. 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 is 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. 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 regional haze obligations for electric generating units.units in Texas. Additionally, the Federal EPA finalized an intrastate SO2 emissions trading program based on CSAPR allowance allocations as an alternative 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.

In June 2012, the Federal EPA published revisionsallocations. A challenge 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.  This rule is being challengedFIP was filed in the U.S. Court of Appeals for the DistrictFifth Circuit and the case is pending the Federal EPA’s reconsideration of Columbia Circuit.the final rule. In August 2018, the Federal EPA proposed to affirm its 2017 FIP approval. In November 2019, in response to comment, the Federal EPA proposed revisions to the intrastate trading program. The Federal EPA finalized the intrastate trading program in July 2020. Management supports the intrastate trading program as a compliance with CSAPR programs as satisfaction of the BART requirements.alternative to source-specific controls.

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Cross-State Air Pollution Rule (CSAPR)


In 2011, the Federal EPA issued CSAPR as a replacement for the CAIR,Clean Air Interstate Rule, 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 NOxallowances 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, states and other parties filed petitionsPetitions to review the CSAPR were filed in the U.S. Court of Appeals for the District of Columbia Circuit. The court stayed implementation of the rule.  Following extended proceedings in the U.S. Court of Appeals for the District of Columbia Circuit 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 granted the Federal EPA’s motion 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 Circuitcourt found that the Federal EPA over-controlled the SO2and/or NOxbudgets of 14 states. The U.S. Court of Appeals for the District of Columbia Circuitcourt remanded the rule to the Federal EPA to timely revise the rulefor revision consistent with the court’s opinion while CSAPR remainsremained in place.


In October 2016, the Federal EPA issued a final rule, was issuedthe CSAPR Update, to address the remand and to incorporate additional changes necessary to address the 2008 ozone standard. The final ruleCSAPR Update significantly reducesreduced ozone season budgets in many states and discountsdiscounted the value of banked CSAPR ozone season allowances beginning with the 2017 ozone season. TheIn 2019, the appeals court remanded the CSAPR Update to the Federal EPA because it determined the Federal EPA had not properly considered the attainment dates for downwind areas in establishing its partial remedy, and should have considered whether there were available measures to control emissions from sources other than generating units. Any further changes to the CSAPR rule has been challenged in the courts and petitions for administrative reconsideration have been filed. The rule remains in effect. Management is complying with the more stringent ozone season budgets while these petitions are being considered.will require additional rulemaking.




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 establishesestablished unit-specific emission rates for units burning coal on a 30-day rolling average basis for mercury, PM (as a surrogate for particles of nonmercurynon-mercury metals) and hydrogen chloride (as a surrogate for acid gases).  In addition, the rule proposesproposed work practice standards such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans.  Compliance wasfurans, with compliance 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 statesVarious intervenors filed petitions for further review in the U.S. Supreme Court and the court granted those petitions in November 2014.Court.


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 Circuitcourt remanded the MATS rule for further proceedings consistent with the U.S. Supreme Court’s decision thatto the Federal EPA was unreasonable in refusing to consider costs in its determinationdetermining whether to regulate emissions of HAPs from power plants. TheIn 2016, the Federal EPA issued notice of a supplemental finding concluding that, after considering the costs of compliance, it iswas appropriate and necessary to regulate HAP emissions from coal-firedcoal 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 beenwere filed in the U.S. Court of Appeals for the District of Columbia Circuit. Oral argument was scheduled for May 2017, but in April 2017In 2018, the Federal EPA requestedreleased a revised finding that oral argument be postponedthe costs of reducing HAP emissions to facilitate its reviewthe level in the current rule exceed the benefits of those HAP emission reductions. The Federal EPA also determined that there are no significant changes in control technologies and the rule.remaining risks associated with HAP emissions do not justify any more stringent standards. Therefore, the Federal EPA proposed to retain the current MATS standards without change. In April 2020, the Federal EPA released a final rule adopting the conclusions set forth in the proposal and retaining the existing MATS standards. The rule remainshas been challenged in effect.the U.S. Court of Appeals for the District of Columbia Circuit.



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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 CO2 emissions standards for new, modified and reconstructed fossil 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 can 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 onof the final CPP, including all of the deadlines for submission of initial or final state plans. The stay will remain in effectplans 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 President issued an Executive Order directing the Federal EPA withdrew its previously issued proposalsto reconsider the CPP and the associated standards for model trading rules and a CEIP.


In March 2017, thenew sources. The Federal EPA filed a motion to hold the challenges to the CPP in abeyance pending reconsideration. In September 2019, following the U.S.Federal EPA’s repeal of the CPP and promulgation of a replacement rule, the Court of Appeals for the District of Columbia Circuit notice of: (a) an Executive Order fromdismissed the President of the United States titled “Promoting Energy Independence and Economic Growth” directingchallenges.

In July 2019, the Federal EPA finalized the Affordable Clean Energy (ACE) rule to reviewreplace the CPP with new emission guidelines for regulating CO2 from existing sources. ACE establishes a framework for states to adopt standards of performance for utility boilers based on heat rate improvements for such boilers. The final rule applies to generating units that commenced construction prior to January 2014, generate greater than 25 MWs, have a baseload rating above 250 MMBtu per hour and related rules; (b) the Federal EPA’s initiation of a reviewburn coal for more than 10% of the CPPannual average heat input over the preceding three calendar years, with certain exceptions. States must establish standards of performance for each affected facility in terms of pounds of CO2 emitted per MWh, based on certain heat rate improvement measures and (c) a forthcomingthe degree of emission reduction achievable through each applicable measure, together with consideration of certain site-specific factors and the unit’s remaining useful life. Information collection and rulemaking relatedactivities are underway in several states. State plans are required to the CPP consistent with the Executive Order, ifbe submitted in 2022, and the Federal EPA determines appropriate. has up to two years to review and approve a plan or disapprove it and adopt a federal plan. The final ACE rule has been challenged in the courts.

In this same filing,2018, the Federal EPA also presented a motion to hold the litigation in abeyance until 30 days after the conclusion of review and 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 issuedfiled 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 foundis not cost-effective. Management continues to actively monitor these rulemaking activities.

AEP has taken action to reduce and offset CO2 emissions from its generating fleet. AEP expects CO2 emissions from its operations to continue to decline due to the retirement of some of its coal-fired generation units, and actions taken to diversify the generation fleet and increase energy efficiency where there is regulatory support for such activities. The majority of the states where AEP has generating facilities passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements that can assist in reducing carbon emissions.  In April 2020, Virginia enacted clean energy legislation to allow the state to participate in the Regional Greenhouse Gas Initiative, require the retirement of all fossil-fueled generation by 2045 and require 100% renewable energy to be provided to Virginia customers by 2050. Management is taking steps to comply with these requirements, including increasing wind and solar installations, purchasing renewable power and broadening AEP System’s portfolio of energy efficiency programs.

In September 2019, AEP announced new intermediate and long-term CO2 emission reduction goals, based on the statutory text, legislative history, use of similar terms elsewhere in the CAA and its own historic implementation of Section 111 that a narrower interpretationoutput of the term limits itcompany’s integrated resource plans, which take into account economics, customer demand, grid reliability and resiliency, regulations and the company’s current business strategy. The intermediate goal is a 70% reduction from 2000 CO2 emission levels from AEP generating facilities by 2030; the long-term goal is to those designs, processes, control technologiessurpass an 80% reduction of CO2 emissions from AEP generating facilities from 2000 levels by 2050. AEP’s total estimated CO2 emissions in 2019 were approximately 58 million metric tons, a 65% reduction from AEP’s 2000 CO2 emissions. AEP has made significant progress in reducing CO2 emissions from its power generation fleet and other systems thatexpects its emissions to continue to decline. AEP’s aspirational emissions goal is zero CO2 emissions by 2050. Technological advances, including energy storage, will determine how quickly AEP can be applied directlyachieve zero emissions while continuing 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. Management does not expect a change in AEP’s overall strategy as a result of the proposed repeal.provide reliable, affordable power for customers.


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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 might force AEP to close some coal-fired facilities, andwhich could possibly lead to possible impairment of assets.


Coal Combustion Residual (CCR) Rule


In April 2015, the Federal EPA published a final rule to regulate 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. The Federal EPA regulates CCR as a non-hazardous solid waste by its issuance of new minimum federal solid waste management standards. The rule applies to new and existing active CCR landfills and CCR surface impoundments at operating electric utility or independent power productiongeneration facilities. The rule imposes new and additional construction and operating obligations, including location restrictions, liner criteria, structural integrity requirements for impoundments, operating criteria and additional groundwater monitoring requirements to be implemented on a schedule spanning an approximate four yearfour-year implementation period. In 2018, some of AEP’s facilities were required to begin monitoring programs to determine if unacceptable groundwater impacts will trigger future corrective measures. Based on additional groundwater data, further studies to design and assess appropriate corrective measures have been undertaken at two facilities.


In December 2016,a challenge to the final 2015 rule, the parties initially agreed to settle some of the issues.  In 2018, the U.S. Congress passed legislation authorizing statesCourt of Appeals for the District of Columbia Circuit addressed or dismissed the remaining issues in its decision vacating and remanding certain provisions of the 2015 rule.  The provisions addressed by the court’s decision, including changes to submit programsthe provisions for unlined impoundments and legacy sites, will be the subject of further rulemaking consistent with the court’s decision.

Prior to regulate CCR facilities, andthe court’s decision, the Federal EPA to approve such programs if they are no less stringent thanissued the minimum federal standards. The Federal EPA may also enforceJuly 2018 rule that modifies certain compliance withdeadlines and other requirements in the minimum standards until2015 rule.  In December 2018, challengers filed a state program is approvedmotion for partial stay or if states fail to adopt their own programs. In September 2017,vacatur of the July 2018 rule. On the same day, the Federal EPA filed a motion for partial remand of the July 2018 rule. The court granted industry petitionsthe Federal EPA’s motion. In November 2019, the Federal EPA proposed revisions to reconsiderimplement the court’s decision regarding the timing for closure of unlined surface impoundments along with impoundments not meeting the required distance from an aquifer. The final rule was published in August 2020. In December 2019, the Federal EPA proposed a federal permit program, implementing the Water Infrastructure Improvements for the Nation Act that would apply in states that do not have an approved CCR program.

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 groundwaters that have a hydrologic connection to a surface water body represent an “unpermitted discharge” under the CWA. Two cases were accepted by the U.S. Supreme Court for further review of the scope of CWA jurisdiction. In April 2020, the Supreme Court issued an opinion remanding one of these cases to the Ninth Circuit based on its determination that discharges from an injection well that make their way to the Pacific Ocean through ground water may require a permit if the distance traveled through ground water, length of time to reach the surface water and other factors make it “functionally equivalent” to a direct discharge from a point source. The second case was also remanded to the lower court. Prior to the Supreme Court’s decision, the Federal EPA opened a rulemaking docket to solicit information to determine whether it should provide additional clarification of the scope of CWA permitting requirements for discharges to groundwater, and issued an interpretive statement finding that discharges to groundwater are not subject to NPDES permitting requirements under the CWA. Management is unable to predict the impact of these developments on AEP’s facilities.

In August 2020, the Federal EPA revised the CCR rule to include a requirement that unlined CCR storage ponds cease operations and askedinitiate closure by April 11, 2021. The revised rule provides two options that litigation regardingallow facilities to extend the ruledate by which they must cease receipt of coal ash and close the ponds. The deadline for seeking an extension under either option is November 30, 2020.


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

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 abeyance. The court has ordered oral argument to proceedsize, or through October 17, 2028 for facilities with CCR storage ponds greater than 40 acres in November 2017 and that the motion for abeyance be addressed during oral argument.size.


Because AEP currently uses surface impoundments and landfills to manage CCR materials at generating facilities, significant costs willmay be incurred to upgrade or close and replace these existing facilities at some pointand conduct any required remedial actions. Management is evaluating various compliance options. 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 asfinal 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.

In March 2020, Virginia’s Governor signed House Bill 443 (HB 443), effective July 2020, requiring APCo to close certain ash disposal units at the new rule is implemented. Managementretired Glen Lyn Station by removal of all coal combustion material.  As a result, in June 2020, APCo recorded a $95$199 million revision to increase in asset retirement obligations inestimated Glen Lyn Station ash disposal ARO liabilities.  The closure is required to be completed within 15 years from the second quarter of 2015 primarily due to the publicationstart of the final rule.excavation process.  HB 443 provides for the recovery of all costs associated with closure by removal through the Virginia environmental rate adjustment clause (E-RAC).  APCo may begin recovering these costs through the E-RAC beginning July 1, 2022. APCo is permitted to record carrying costs on the unrecovered balance of closure costs at a weighted average cost of capital approved by the Virginia SCC. HB 443 also allows any closure costs allocated to non-Virginia jurisdictional customers, but not collected from such non-Virginia jurisdictional customers, to be recovered from Virginia jurisdictional customers through the E-RAC.

If removal of ash is required without providing similar assurances of cost recovery in regulated jurisdictions, it would impose significant additional operating costs on AEP, which could lead to increased financing costs and liquidity needs. Other units in Virginia, Ohio, West Virginia, and Kentucky already have 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, the Federal EPA issued a final 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)impinged 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 withwas upheld on review by the impingement standard and requires site-specific studies to determine appropriate entrainment compliance measures at facilities withdrawing more than


125 million gallons per day. Additional requirements may be imposed as a resultU.S. Court 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 inAppeals for 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.Second Circuit. Compliance timeframes will then beare established by the permit agency through each facility’s National Pollutant Discharge Elimination System (NPDES)NPDES permit for installation of any required technology changes, as those permits are renewed overand have been incorporated into permits at several AEP facilities. AEP facilities that have had their wastewater discharge permits renewed have been asked to monitor intake flows or to enhance monitoring practices to assure the next fivecurrent technology is being properly managed 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.ensure compliance with this rule.


In addition,2015, the Federal EPA developed revisedissued a final rule revising effluent limitation guidelines for electricity generating facilities. A finalThe rule was issued in November 2015. The final rule establishesestablished limits on FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater to be imposed as soon as possible after November 2018 and no later than December 2023. These new
17





requirements willwould be implemented through each facility’s wastewater discharge permit. The rule has beenwas challenged in the U.S. Court 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 ofannounced its intent to reconsider and potentially revise 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 deadlinesstandards for FGD wastewater and bottom ash transport waterwater. The Federal EPA postponed the compliance deadlines for those wastewater categories to be no earlier than 2020, to allow for reconsideration. In April 2019, the Fifth Circuit vacated the standards for landfill leachate and legacy wastewater, and remanded them to the Federal EPA for reconsideration.  In November 2019, the Federal EPA proposed revisions to the guidelines for existing generation facilities. A final rule was issuedsigned by the Federal EPA in September 2017.August 2020 and was published in October 2020. The final rule establishes additional options for reusing and discharging small volumes of bottom ash transport water, provides an exception for retiring units, and extends the compliance deadline to a date as soon as possible beginning one year after the rule was published but no later than December 2025. Management submitted comments supporting the proposed postponement. Management continues to assessis assessing 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.


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. Various parties challenged the 2015 rule in different U.S. District Courts, which resulted in a patchwork of applicability of the 2015 rule and its predecessor. In December 2018, the Federal EPA and the U.S. Army Corps of Engineers proposed a replacement rule. In September 2019, the Federal EPA repealed the 2015 rule. The final replacement rule was published in the Federal Register in April 2020 and became effective in June 2020. The final rule limits the scope of CWA jurisdiction to four categories of waters, and clarifies exclusions for ground water, ephemeral streams, artificial ponds and waste treatment systems. Challenges to the final rule and requests for a preliminary injunction have been brought by states and other groups in multiple U.S. District Courts. At this time, none of the jurisdictions in which AEP operates are impacted by a stay. Management is monitoring these various proceedings but is unable to predict the actions of the various courts.

In April 2020, the U.S. District Court for the District of Montana issued a decision vacating the U.S. Army Corps of Engineers’ (Corps) General Nationwide Permit 12 (NWP 12), which provides for federal jurisdiction over “navigable waters” defined as “thestandard conditions governing linear utility projects in streams, wetlands and other waters of the United States.” This jurisdictional definition appliesStates having minimal adverse environmental impacts. The Court found that in reissuing NWP 12 in 2017, the Corps failed 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 waterscomply with Section 7 of the Endangered Species Act (ESA), which requires the Corps to consult with the U.S. as jurisdictional as well as certain exclusions.Fish and Wildlife Service regarding potential impacts on endangered species. The ruleCourt remanded the permit back to the Corps to complete its ESA consultation, and also containsenjoined the Corps from authorizing any dredge or fill activities under NWP 12 pending completion of the consultation process. The Department of Justice filed a numbermotion to stay the injunction and tailor the remedy imposed by the Court. In May 2020, the Court revised its order lifting the injunction for non-oil and gas pipeline construction activities and routine maintenance, inspection and repair activities on existing NWP 12 projects. The Department 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 inJustice appealed the permitting process is needed. Management remains concerned thatCourt’s decision to 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. Challengers include industry associations of which AEP is a member. The U.S. Court of Appeals for the SixthNinth Circuit granted a nationwideand moved for stay pending appeal, which was denied. In June 2020, the Department 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 have 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 appealedJustice submitted an application to the U.S. Supreme Court which granted certiorari to reviewrequesting a stay of the jurisdictional issue. The U.S. Supreme Court denied the Federal EPA’s motion to hold briefing in abeyance pending further Federal EPA actions on the ruleDistrict Court’s Order, and the appealCourt granted the request with respect to all oil and gas pipelines except the Keystone Pipeline. Management is monitoring the litigation and evaluating other permitting alternatives, but is currently unable to predict the impact of future proceedings on the jurisdictional issue continues.current and planned projects.


In March 2017,September 2020, the Federal EPA published a noticeCorps issued for public comment the proposed renewal of intentall General Nationwide Permits. As part of that proposal the Corps has narrowed the focus of NWP 12 to review the ruleonly oil and provide an advanced noticenatural gas pipeline activities. The Corps is proposing two new Nationwide Permits governing electric utility line and telecommunications activities, and other utility lines (e.g., conveyance of a proposed rulemaking consistent with the Executive Orderpotable water, sewage, other substances), respectively. Management is currently assessing impacts of the President of the United States directing the Federal EPAproposal on current 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.planned projects.
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RESULTS OF OPERATIONS


SEGMENTS


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


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


Vertically Integrated Utilities


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


Transmission and Distribution Utilities


•Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCoAEP Texas and AEP Texas.OPCo.
•OPCo purchases energy and capacity at auction to serve SSOstandard service offer customers and provides transmission and distribution services for all connected load.
With the merger of TCC and TNC into AEP Utilities, Inc. to form AEP Texas, the Transmission and Distribution segment now includes certain activities related to the former AEP Utilities, Inc. that had been included in Corporate and Other.


AEP Transmission Holdco


•Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved returns on equity.
•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.


Generation & Marketing


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


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 Generation Deferrals and Amortization of Generation Deferrals as presented in the Registrants statements of income as applicable. Under the various state utility rate making processes, these expenses are generally reimbursable directly from and billed to customers. As a result, they do not typically impact Operating Income or Earnings Attributable to AEP Common Shareholders. Management believes that Gross Margin provides a useful measure for investors and other financial statement users to analyze AEP’s financial performance in that it excludes the effect on Total Revenues caused by volatility in these expenses. Operating income,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 EndedNine Months Ended
September 30,September 30,
 2020201920202019
 (in millions)
Vertically Integrated Utilities$393.5 $437.6 $894.7 $917.7 
Transmission and Distribution Utilities147.4 133.7 403.1 421.6 
AEP Transmission Holdco138.3 126.1 370.4 404.8 
Generation & Marketing116.7 90.0 211.0 139.5 
Corporate and Other(47.3)(53.9)(114.6)(116.0)
Earnings Attributable to AEP Common Shareholders$748.6 $733.5 $1,764.6 $1,767.6 
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (in millions)
Vertically Integrated Utilities$286.3
 $342.3
 $626.6
 $829.3
Transmission and Distribution Utilities144.0
 155.7
 374.3
 387.8
AEP Transmission Holdco75.5
 69.0
 275.7
 207.5
Generation & Marketing33.7
 (1,369.2) 246.3
 (1,248.8)
Corporate and Other5.2
 36.4
 (11.0) 61.7
Earnings (Loss) Attributable to AEP Common Shareholders$544.7
 $(765.8) $1,511.9
 $237.5


AEP CONSOLIDATED


Third Quarter of 20172020 Compared to Third Quarter of 20162019

Earnings (Loss) Attributable to AEP Common Shareholders increased from a loss of $766 million in 2016 to income of $545 million in 2017 primarily due to:

An increase due to the impairment of certain merchant generation assets in 2016.
An increase in transmission investment primarily at AEP Transmission Holdco which resulted in higher revenues and income.

These increases were partially offset by:

A decrease in generation revenues associated with the sale of certain merchant generation assets.
A decrease in weather-related usage.
The prior year reversal of income tax expense for an unrealized capital loss valuation allowance. AEP effectively settled a 2011 audit issue with the IRS resulting in a change in the valuation allowance.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016


Earnings Attributable to AEP Common Shareholders increased from income of $238$734 million in 20162019 to income of $1.5 billion$749 million in 20172020 to primarily due to:


An increase due to the impairment of certain merchant generation assets in 2016.
An increase due to the current year gain on the sale of certain merchant generation assets.
An increase in transmission investment primarily at AEP Transmission Holdco which resulted in higher revenues and income.
•Favorable rate proceedings in AEP’s various jurisdictions.

•A planned decrease in Other Operation and Maintenance expenses.
•The recognition of a discrete tax adjustment in 2020 which was attributable to the 5-year net operating loss carryback provision of the CARES Act.

These increases were partially offset by:


A decrease in generation revenues associated with the sale of certain merchant generation assets.
•A decrease in weather-related usage.
•A one-time reversal of a regulatory provision in 2019.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

Earnings Attributable to AEP Common Shareholders decreased from $1,768 million in 2019 to $1,765 million in 2020 primarily due to:

•A decrease in weather-normalized sales.weather-related usage.
•A one-time reversal of a regulatory provision in 2019.

These decreases were partially offset by:

•Favorable rate proceedings in AEP’s various jurisdictions.
•A planned decrease in FERC wholesale municipalOther Operation and cooperative revenues.Maintenance expenses.
•The prior year reversalrecognition of incomea discrete tax expense for an unrealized capitaladjustment in 2020 which was attributable to the 5-year net operating loss valuation allowance. AEP effectively settled a 2011 audit issue withcarryback provision of the IRS resulting in a change in the valuation allowance.CARES Act.


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

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VERTICALLY INTEGRATED UTILITIES
Three Months EndedNine Months Ended
September 30,September 30,
 Vertically Integrated Utilities2020201920202019
 (in millions)
Revenues$2,434.8 $2,645.5 $6,753.5 $7,172.6 
Fuel and Purchased Electricity693.7 874.2 1,947.0 2,430.2 
Gross Margin1,741.1 1,771.3 4,806.5 4,742.4 
Other Operation and Maintenance715.9 742.9 2,031.8 2,117.1 
Depreciation and Amortization398.8 364.3 1,173.8 1,079.6 
Taxes Other Than Income Taxes121.0 117.9 355.6 347.1 
Operating Income505.4 546.2 1,245.3 1,198.6 
Other Income (Expense)(0.7)0.9 2.3 4.4 
Allowance for Equity Funds Used During Construction15.9 12.2 33.1 38.9 
Non-Service Cost Components of Net Periodic Benefit Cost16.9 17.0 50.9 50.8 
Interest Expense(140.2)(140.6)(426.5)(422.6)
Income Before Income Tax Expense (Benefit) and
Equity Earnings		397.3 435.7 905.1 870.1 
Income Tax Expense (Benefit)3.8 (1.9)10.5 (48.4)
Equity Earnings of Unconsolidated Subsidiary0.7 0.8 2.2 2.3 
Net Income394.2 438.4 896.8 920.8 
Net Income Attributable to Noncontrolling Interests0.7 0.8 2.1 3.1 
Earnings Attributable to AEP Common Shareholders$393.5 $437.6 $894.7 $917.7 
  Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
 Vertically Integrated Utilities 2017 2016 2017 2016
  (in millions)
Revenues $2,482.2
 $2,556.3
 $6,893.1
 $6,927.8
Fuel and Purchased Electricity 868.6
 858.3
 2,368.9
 2,299.8
Gross Margin 1,613.6
 1,698.0
 4,524.2
 4,628.0
Other Operation and Maintenance 659.1
 673.0
 2,024.5
 1,926.9
Asset Impairments and Other Related Charges —
 10.5
 —
 10.5
Depreciation and Amortization 288.8
 277.7
 845.1
 815.5
Taxes Other Than Income Taxes 105.7
 99.0
 306.2
 295.0
Operating Income 560.0
 637.8
 1,348.4
 1,580.1
Interest and Investment Income 1.3
 0.8
 5.4
 2.4
Carrying Costs Income 2.1
 0.8
 11.3
 8.1
Allowance for Equity Funds Used During Construction 7.5
 10.0
 20.0
 35.4
Interest Expense (134.9) (136.7) (406.5) (399.9)
Income Before Income Tax Expense and Equity Earnings (Loss) 436.0
 512.7
 978.6
 1,226.1
Income Tax Expense 139.1
 172.0
 334.9
 398.4
Equity Earnings (Loss) of Unconsolidated Subsidiaries 0.4
 2.7
 (4.5) 4.9
Net Income 297.3
 343.4
 639.2
 832.6
Net Income Attributable to Noncontrolling Interests 11.0
 1.1
 12.6
 3.3
Earnings Attributable to AEP Common Shareholders $286.3
 $342.3
 $626.6
 $829.3


Summary of KWh Energy Sales for Vertically Integrated Utilities
Three Months Ended September 30,Nine Months Ended 
September 30,
2020201920202019
 (in millions of KWhs)
Retail:    
Residential9,066 9,254 24,304 24,785 
Commercial6,257 6,840 16,773 18,183 
Industrial8,161 9,123 24,335 26,533 
Miscellaneous595 641 1,636 1,734 
Total Retail24,079 25,858 67,048 71,235 
Wholesale (a)4,574 5,864 13,116 16,494 
Total KWhs28,653 31,722 80,164 87,729 

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



21
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (in millions of KWhs)
Retail: 
  
  
  
Residential8,488
 9,575
 23,226
 25,373
Commercial6,701
 7,137
 18,386
 19,207
Industrial8,839
 8,655
 25,792
 25,576
Miscellaneous603
 634
 1,701
 1,740
Total Retail24,631
 26,001
 69,105
 71,896
        
Wholesale (a)6,837
 6,765
 19,262
 17,253
        
Total KWhs31,468
 32,766
 88,367
 89,149
(a)Includes off-system sales, municipalities and cooperatives, unit power and other wholesale customers.








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


Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities
Three Months Ended September 30,Nine Months Ended 
September 30,
2020201920202019
 (in degree days)
Eastern Region    
Actual – Heating (a)
3 — 1,456 1,670 
Normal – Heating (b)
4 5 1,752 1,742 
Actual – Cooling (c)
867 937 1,204 1,316 
Normal – Cooling (b)
739 732 1,081 1,070 
Western Region    
Actual – Heating (a)
1 — 699 967 
Normal – Heating (b)
1 1 902 902 
Actual – Cooling (c)
1,291 1,572 2,015 2,234 
Normal – Cooling (b)
1,416 1,402 2,144 2,129 

(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.

22
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (in degree days)
Eastern Region 
  
  
  
Actual – Heating (a)
—
 —
 1,266
 1,684
Normal – Heating (b)
4
 5
 1,757
 1,775
        
Actual – Cooling (c)
698
 954
 1,034
 1,306
Normal – Cooling (b)
731
 726
 1,060
 1,058
        
Western Region 
  
  
  
Actual – Heating (a)
—
 —
 539
 685
Normal – Heating (b)
1
 1
 926
 927
        
Actual – Cooling (c)
1,281
 1,519
 2,000
 2,262
Normal – Cooling (b)
1,404
 1,400
 2,124
 2,116


(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.








Third Quarter of 20172020 Compared to Third Quarter of 20162019
Reconciliation of Third Quarter of 2019 to Third Quarter of 2020
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
Third Quarter of 2019$437.6 
Changes in Gross Margin:
Retail Margins(14.3)
Margins from Off-system Sales(5.5)
Transmission Revenues(3.1)
Other Revenues(7.3)
Total Change in Gross Margin(30.2)
Changes in Expenses and Other:
Other Operation and Maintenance27.0 
Depreciation and Amortization(34.5)
Taxes Other Than Income Taxes(3.1)
Other Income(1.6)
Allowance for Equity Funds Used During Construction3.7 
Non-Service Cost Components of Net Periodic Pension Cost(0.1)
Interest Expense0.4 
Total Change in Expenses and Other(8.2)
Income Tax Expense(5.7)
Equity Earnings of Unconsolidated Subsidiary(0.1)
Net Income Attributable to Noncontrolling Interests0.1 
Third Quarter of 2020$393.5 
Reconciliation of Third Quarter of 2016 to Third Quarter of 2017
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
   
Third Quarter of 2016 $342.3
   
Changes in Gross Margin:  
Retail Margins (74.1)
Off-system Sales (0.8)
Transmission Revenues (7.6)
Other Revenues (1.9)
Total Change in Gross Margin (84.4)
   
Changes in Expenses and Other:  
Other Operation and Maintenance 13.9
Asset Impairments and Other Related Charges 10.5
Depreciation and Amortization (11.1)
Taxes Other Than Income Taxes (6.7)
Interest and Investment Income 0.5
Carrying Costs Income 1.3
Allowance for Equity Funds Used During Construction (2.5)
Interest Expense 1.8
Total Change in Expenses and Other 7.7
   
Income Tax Expense 32.9
Equity Earnings (Loss) of Unconsolidated Subsidiary (2.3)
Net Income Attributable to Noncontrolling Interest (9.9)
   
Third Quarter of 2017 $286.3


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


•Retail Margins decreased $74$14 million primarily due to the following:
An $80•A $50 million decrease in weather-related usage primarily in the easternwestern region and western regions.primarily in the residential class.
•A $24 million decrease in weather-normalized margins for wholesale customers, including the loss of a significant wholesale contract at I&M.
•A $4 million decrease in revenue from rate riders at PSO. This decrease was partially offset in other expense items below.
•A $3 million decrease in weather-normalized retail margins driven by a $42 million decrease in the commercial and industrial customer classes partially offset by a $41 million increase in the residential customer class.
These decreases were partially offset by:
•The effect of rate proceedings in AEP’s service territories which included:
•A $17$38 million decrease for PSOincrease at I&M primarily due to higherthe Indiana and Michigan base rate cases and an overall increase in revenue from rate riders. This increase was partially offset in other expense items below.
•A $14 million increase at SWEPCo primarily due to a base rate revenue increase in Arkansas.
•A $10 million increase in deferred fuel at APCo and WPCo primarily due to the timing of recoverable PJM expenses. This increase was offset in other expense items below.
•A $5 million increase at APCo and WPCo due to the WVPSC’s approval of the Mitchell Plant surcharge effective January 2020.
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•Margins from Off-system Sales decreased$6 million due to weaker market prices for energy in the RTOs which caused a decrease in sales volume and margins and the historical merchant portion of WPCo’s Mitchell Plant moving to retail rates implementedbeginning in 2016 associated with interim rates.January 2020.
A $6•Other Revenues decreased $7 million decrease primarily due to a decrease at I&M in ratesbarging revenues by River Transportation Division (RTD). This decrease was partially offset in West VirginiaOther Operation and Virginia.Maintenance expenses below.
For
Expenses and Other and Income Tax Expensechanged between years as follows:

•Other Operation and Maintenance expenses decreased $27 million primarily due to the rate decreases described above,following:
•A $23 million decrease in distribution expenses primarily related to vegetation management, storms and other distribution expenses.
•A $13 million decrease in plant outage and maintenance expenses primarily at I&M, SWEPCo, PSO and KPCo.
•An $8 million decrease due to the modification of the NSR consent decree impacting I&M and AEGCo in 2019.
•A $4 million relatedecrease in transmission expenses primarily related to riders/trackers which have corresponding decreasesRTO fees, NERC activities and station/line inspections.
•A $4 million decrease in expense items below.customer-related expenses.
These decreases were partially offset by:
•The effect of rate proceedings in AEP’s service territories which included:
An $11A $30 million increase from rate proceedings in the Indiana service territory.employee-related expenses.
An $11•Depreciation and Amortization expenses increased $35 million increase primarily due to rider revenue increases in Louisiana,a higher depreciable base and increased depreciation rates approved at I&M and SWEPCo. This increase was partially offset in expense items below.Retail Margins above.
For the rate increases described above, $8 millionrelate to riders/trackers which have corresponding increases in expense items below.
An $11 million increase in weather-normalized margins.
A $4 million increase primarily due to reduced fuel and other variable production costs not recovered through fuel clauses or other trackers.



Transmission Revenues decreased $8 million primarily due to the following:
A $6 million decrease primarily due to I&M’s annual formula rate true-up and reduced net PJM Network Integration Transmission Service revenues resulting from increased affiliated transmission-related charges.
A $5 million decrease due to a net favorable accrual for SPP sponsor-funded transmission upgrades in third quarter 2016.

Expenses and Other, •Income Tax Expense and Net Income Attributable to Noncontrolling Interest changed between years as follows:

Other Operation and Maintenance expenses decreased $14 million primarily due to the following:
A $15 million decrease in employee-related expenses.
A $10 million decrease in PJM and SPP transmission services expense not recovered through riders/trackers.
AExpense increased $6 million decrease in storm expenses, primarily in the APCo region.
These decreases were partially offset by:
A $5 million increase due to the Wind Catcher Project for PSO and SWEPCo.
A $5 million increase in nuclear expenses at Cook Plant.
A $3 million increase in vegetation management expenses, primarily at PSO and SWEPCo.
Asset Impairments and Other Related Charges decreased $11 million due to the impairment of I&M’s Price River Coal reserves in 2016.
Depreciation and Amortization expenses increased $11 millionprimarily due to the following:
A $15 million increase primarily due to higher depreciable base.
A $6 million increase due to amortization of capitalized software costs.
These increases were partially offset by:
A $9 million decrease primarily related to prior year higher estimated depreciation expense associated with interim rates at PSO.
Taxes Other Than Income Taxes increased $7 million primarily due to higher property taxes.
Income TaxExpense decreased $33 million primarily due to a decrease in pretax book income and income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine.
Net Income Attributable to Noncontrolling Interest increased $10 million primarily due to income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine. This increase isamortization of Excess ADIT, partially offset by a decrease in Income Tax Expense.pretax book income and an increase in favorable flow-through tax benefits. The decrease in amortization of Excess ADIT is partially offset above in Gross Margin and Other Operation and Maintenance expenses.

24









Nine Months Ended September 30, 20172020 Compared to Nine Months Ended September 30, 20162019
Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
Nine Months Ended September 30, 2019$917.7 
Changes in Gross Margin:
Retail Margins38.5 
Margins from Off-system Sales(14.2)
Transmission Revenues48.7 
Other Revenues(8.9)
Total Change in Gross Margin64.1 
Changes in Expenses and Other:
Other Operation and Maintenance85.3 
Depreciation and Amortization(94.2)
Taxes Other Than Income Taxes(8.5)
Other Income(2.1)
Allowance for Equity Funds Used During Construction(5.8)
Non-Service Cost Components of Net Periodic Pension Cost0.1 
Interest Expense(3.9)
Total Change in Expenses and Other(29.1)
Income Tax Expense(58.9)
Equity Earnings of Unconsolidated Subsidiary(0.1)
Net Income Attributable to Noncontrolling Interests1.0 
Nine Months Ended September 30, 2020$894.7 
Reconciliation of Nine Months Ended September 30, 2016 to Nine Months Ended September 30, 2017
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
   
Nine Months Ended September 30, 2016 $829.3
   
Changes in Gross Margin:  
Retail Margins (123.9)
Off-system Sales 7.4
Transmission Revenues 11.0
Other Revenues 1.7
Total Change in Gross Margin (103.8)
   
Changes in Expenses and Other:  
Other Operation and Maintenance (97.6)
Asset Impairments and Other Related Charges 10.5
Depreciation and Amortization (29.6)
Taxes Other Than Income Taxes (11.2)
Interest and Investment Income 3.0
Carrying Costs Income 3.2
Allowance for Equity Funds Used During Construction (15.4)
Interest Expense (6.6)
Total Change in Expenses and Other (143.7)
   
Income Tax Expense 63.5
Equity Earnings (Loss) of Unconsolidated Subsidiary (9.4)
Net Income Attributable to Noncontrolling Interest (9.3)
   
Nine Months Ended September 30, 2017 $626.6


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


•Retail Margins decreased $124 increased $39 million primarily due to the following:
•A $164$35 million decreaseincrease in weather-related usage in the easterndeferred fuel at APCo and western regions.
A $42 million decrease in FERC generation wholesale municipal and cooperative revenuesWPCo primarily due to an annual formula rate true-upthe timing of recoverable PJM expenses.
•A $16 million increase due to a decrease in customer refunds related to Tax Reform. This increase was partially offset in Income Tax Expense below.
•A $15 million increase at APCo and adjustments at I&MWPCo due to the WVPSC approval of the Mitchell Plant surcharge effective January 1, 2020. Pursuant to the WVPSC approval of the surcharge, this increase was partially offset by the amortization of Excess ADIT not subject to normalization requirements in Income Tax Expense below.
•A $14 million increase due to the impact of the 2019 WVPSC order which required APCo and SWEPCo.WPCo to offset Excess ADIT not subject to normalization requirements against the deferred fuel under-recovery balance in 2019.
•The effect of rate proceedings in AEP’s service territories which included:
•A $14$72 million decreaseincrease at I&M primarily due to prior year recognition of deferred billingthe Indiana and Michigan base rate cases and an overall increase in West Virginia as approved by the WVPSC.revenue from rate riders. This increase was partially offset in other expense items below.
•A $9$35 million net decrease for PSOincrease at SWEPCo primarily due to rider increases in all jurisdictions and a base rate revenue decreases associated with interimincrease in Arkansas. This increase was partially offset in other expense items below.
•A $10 million increase at PSO due to new base rates implemented in 2016.April 2019.
For•A $10 million increase at APCo and WPCo due to a base rate increase in West Virginia. This increase was partially offset in Depreciation and Amortization expenses below.
•A $6 million increase in municipal and cooperative revenues at SWEPCo primarily due to formula rate true-ups.
25





These increases were partially offset by:
•A $95 million decrease in weather-related usage primarily in the rate decreases described above, $1 million relate to riders/trackers which have corresponding decreases in expense items below.residential class.
•A $5$47 million decrease in weather-normalized margins.margins for wholesale contracts, including the loss of a significant wholesale contract at I&M.
These decreases were•A $12 million decrease in weather-normalized retail margins driven by a $93 million decrease in the commercial and industrial classes partially offset by:
The effect of rate proceedings in AEP’s service territories which included:
A $42by an $85 million increase in the residential customer class.
•A $10 million decrease in revenue from rate proceedingsriders at PSO. This decrease was partially offset in other expense items below.
•Margins from Off-system Sales decreased $14 million due to weaker market prices for energy in the Indiana service territory.RTOs which caused a decrease in sales volume and margins and the historical merchant portion of WPCo’s Mitchell Plant moving to retail rates beginning in January 2020.
•Transmission Revenues increased $49 million primarily due to the following:
•A $33$26 million increase due to rider revenue increasescontinued investment in Louisiana, Texas and Arkansas,transmission projects primarily at SWEPCo.
•A $23 million increase as a result of the annual transmission formula rate true-up primarily at SWEPCo. This increase was partially offset by an increase in expense items below.transmission expenses in SPP.
A $6 million increase for KGPCo due to revenue increases from rate riders/trackers.
For the rate increases described above, $37 million relate to riders/trackers which have corresponding increases in expense items below.


A $19 million increase primarily due to reduced fuel and other variable production costs not recovered through fuel clauses or other trackers.
Margins from Off-system Sales increased $7•Other Revenues decreased $9 million primarily due to higher market prices.
Transmission Revenues increased $11 million primarily due the following:
•A $35decrease of $14 million increaseat I&M primarily due to increasesa decrease in formula rates drivenbarging revenues by continued investment in transmission assets.RTD. This increase isdecrease was partially offset in Other Operation and Maintenance expenses below.
These increases wereThis decrease was partially offset by:
•A $23$3 million decreaseincrease at PSO primarily due to I&M’s annual formula rate true-up and reduced net PJM Network Integration Transmission Service revenues resulting from increased affiliated transmission-related charges.business development revenue. This increase was partially offset in other expense items below.
A $5 million net decrease due to a net favorable accrual for SPP sponsor-funded transmission upgrades in third quarter 2016.


Expenses and Other and Income Tax Expense Equity Earnings (Loss) of Unconsolidated Subsidiary and Net Income Attributable to Noncontrolling Interest changed between years as follows:


•Other Operation and Maintenance expenses increased $98decreased $85 million primarily due to the following:
•A $103$53 million increasedecrease in recoverableplant outage and maintenance expenses primarily PJM expensesat APCo, I&M, WPCo, KPCo and energy efficiency expenses fully recovered in rate recovery riders/trackers within Gross Margin above.PSO.
•A $22 million increasedecrease in distribution expenses primarily vegetation management and other distribution expenses.
•A $12 million decrease due to the capitalization of previously expensed North Central Wind Energy Facilities costs at SWEPCo and PSO.
•A $10 million decrease in transmission expenses primarily at PSOrelated to RTO fees, NERC activities and I&M.station/line inspections.
A $6•An $8 million increasedecrease due to a favorable land salethe modification of the NSR consent decree impacting I&M and AEGCo in 20162019.
•A $7 million decrease in PJM transmission services including the APCo region.annual formula rate true-up.
•A $7 million decrease at I&M due to an increased Nuclear Electric Insurance Limited distribution in 2020.
These increasesdecreases were partially offset by:
•A $27$39 million decreaseincrease due to SPP transmission services including the annual formula rate true-up.
•A $10 million increase due to storms primarily at KPCo and PSO.
•A $3 million increase in employee-related expenses.
Asset Impairments•Depreciation and Amortization expenses increased $94 millionprimarily due to a higher depreciable base and increased depreciation rates approved at I&M, APCo and SWEPCo. This increase was partially offset in Retail Margins above.
•Taxes Other Related Charges decreased $11Than Income Taxes increased $9 million primarily due to the impairment of I&M’s Price River Coal reservesfollowing:
•A $6 million increase in 2016.
property taxes due to additional investments in utility plant.
Depreciation•A $3 million increase in state business and Amortization expenses increased $30 millionprimarilyoccupation taxes at APCo due to the following:
reduction of the revitalization tax credit.
A $46 million increase primarily due to higher depreciable base.
A $15 million increase due to amortization of capitalized software costs.
These increases were partially offset by:
A $24 million decrease primarily related to prior year higher estimated depreciation expense associated with interim rates at PSO.
Taxes Other Than Income Taxes increased $11 million primarily due to higher property taxes.
•Allowance for Equity Funds Used During Construction decreased $15 millionprimarily due to completed environmental projects.
Interest Expense increased $7$6 million primarily due to a decrease in the following:
AFUDC base at I&M and the favorable impact of a FERC settlement agreement recorded in 2019.
A $7•Interest Expense increased $4 million increase due to lower AFUDC borrowed funds resulting from completed environmental projects.
A $7 million increase primarily due to higher long-term debt balances at I&M.APCo.
These increases were partially offset by:
A $4 million decrease primarily due to the deferral of the debt component of carrying charges on environmental control costs at PSO.
•Income TaxExpense decreased $64increased $59 million primarily due to a decrease in amortization of Excess ADIT and an increase in pretax book income and income tax benefits attributable to SWEPCo’s noncontrolling interestincome. The decrease in Sabine,amortization of Excess ADIT is partially offset by the recording of favorable stateabove in Gross Margin and federal income tax adjustments in 2016.Other Operation and Maintenance expenses.
26
Equity Earnings (Loss) of Unconsolidated Subsidiary decreased $9 million primarily due to a prior period income tax adjustment for DHLC, a SWEPCo unconsolidated subsidiary.





Net Income Attributable to Noncontrolling Interest increased $9 million primarily due to income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine. This increase is offset by a decrease in Income Tax Expense.




TRANSMISSION AND DISTRIBUTION UTILITIES
Three Months EndedNine Months Ended
September 30,September 30,
Transmission and Distribution Utilities2020201920202019
 (in millions)
Revenues$1,165.3 $1,186.6 $3,306.7 $3,454.3 
Purchased Electricity183.8 210.1 522.7 603.5 
Amortization of Generation Deferrals— 8.8 — 65.3 
Gross Margin981.5 967.7 2,784.0 2,785.5 
Other Operation and Maintenance439.1 405.8 1,158.2 1,222.1 
Depreciation and Amortization163.5 209.3 585.0 586.4 
Taxes Other Than Income Taxes156.4 151.8 444.4 437.2 
Operating Income222.5 200.8 596.4 539.8 
Interest and Investment Income0.9 1.1 2.0 4.2 
Carrying Costs Income0.3 0.3 1.3 0.7 
Allowance for Equity Funds Used During Construction9.0 9.8 23.7 22.3 
Non-Service Cost Components of Net Periodic Benefit Cost7.4 7.7 22.1 22.8 
Interest Expense(74.0)(63.6)(217.6)(170.8)
Income Before Income Tax Expense (Benefit)166.1 156.1 427.9 419.0 
Income Tax Expense (Benefit)18.7 22.4 24.8 (2.6)
Net Income147.4 133.7 403.1 421.6 
Net Income Attributable to Noncontrolling Interests— — — — 
Earnings Attributable to AEP Common Shareholders$147.4 $133.7 $403.1 $421.6 
  Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
Transmission and Distribution Utilities 2017 2016 2017 2016
  (in millions)
Revenues $1,173.3
 $1,275.6
 $3,313.2
 $3,468.5
Purchased Electricity 215.7
 253.6
 626.0
 662.2
Amortization of Generation Deferrals 58.7
 66.1
 172.9
 173.0
Gross Margin 898.9
 955.9
 2,514.3
 2,633.3
Other Operation and Maintenance 303.2
 358.2
 882.5
 1,009.5
Depreciation and Amortization 182.3
 181.4
 502.4
 505.0
Taxes Other Than Income Taxes 133.6
 132.0
 387.1
 373.0
Operating Income 279.8
 284.3
 742.3
 745.8
Interest and Investment Income 1.2
 1.5
 5.6
 5.5
Carrying Costs Income 0.5
 0.9
 3.0
 4.0
Allowance for Equity Funds Used During Construction 0.9
 2.2
 6.3
 10.6
Interest Expense (61.0) (63.2) (182.5) (196.0)
Income Before Income Tax Expense 221.4
 225.7
 574.7
 569.9
Income Tax Expense 77.4
 70.0
 200.4
 182.1
Net Income 144.0
 155.7
 374.3
 387.8
Net Income Attributable to Noncontrolling Interests —
 —
 —
 —
Earnings Attributable to AEP Common Shareholders $144.0
 $155.7
 $374.3
 $387.8


Summary of KWh Energy Sales for Transmission and Distribution Utilities
Three Months Ended 
September 30,		Nine Months Ended 
September 30,
2020201920202019
 (in millions of KWhs)
Retail:    
Residential8,277 8,268 20,876 20,614 
Commercial6,722 7,219 18,154 19,069 
Industrial5,417 5,857 16,473 17,492 
Miscellaneous206 223 568 595 
Total Retail (a)20,622 21,567 56,071 57,770 
Wholesale (b)502 453 1,347 1,531 
Total KWhs21,124 22,020 57,418 59,301 

(a)Represents energy delivered to distribution customers.
(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold to PJM.
27
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (in millions of KWhs)
Retail: 
  
  
  
Residential7,511
 8,325
 19,361
 20,575
Commercial6,941
 7,287
 19,184
 19,676
Industrial5,575
 5,518
 16,992
 16,522
Miscellaneous185
 187
 516
 528
Total Retail (a)20,212
 21,317
 56,053
 57,301
        
Wholesale (b)585
 654
 1,749
 1,389
        
Total KWhs20,797
 21,971
 57,802
 58,690


(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.  In general, degree day changes in the eastern region have a larger effect on revenues than changes in the western region due to the relative size of the two regions and the number of customers within each region.


Summary of Heating and Cooling Degree Days for Transmission and Distribution Utilities
Three Months Ended 
September 30,		Nine Months Ended 
September 30,
2020201920202019
 (in degree days)
Eastern Region    
Actual – Heating (a)
2 — 1,767 2,006 
Normal – Heating (b)
6 6 2,086 2,072 
Actual – Cooling (c)
809 872 1,126 1,176 
Normal – Cooling (b)
682 672 986 973 
Western Region    
Actual – Heating (a)
1 — 98 180 
Normal – Heating (b)
— — 188 190 
Actual – Cooling (d)
1,357 1,587 2,524 2,679 
Normal – Cooling (b)
1,378 1,368 2,436 2,425 

(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.

28
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (in degree days)
Eastern Region 
  
  
  
Actual – Heating (a)
—
 —
 1,500
 1,929
Normal – Heating (b)
6
 7
 2,091
 2,110
        
Actual – Cooling (c)
642
 900
 957
 1,209
Normal – Cooling (b)
670
 664
 960
 956
        
Western Region 
  
  
  
Actual – Heating (a)
—
 —
 103
 123
Normal – Heating (b)
—
 —
 199
 198
        
Actual – Cooling (d)
1,393
 1,534
 2,640
 2,619
Normal – Cooling (b)
1,364
 1,358
 2,396
 2,384


(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.







Third Quarter of 20172020 Compared to Third Quarter of 20162019
Reconciliation of Third Quarter of 2019 to Third Quarter of 2020
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
Third Quarter of 2019$133.7 
Changes in Gross Margin:
Retail Margins54.8 
Margins from Off-system Sales(1.4)
Transmission Revenues15.8 
Other Revenues(55.4)
Total Change in Gross Margin13.8 
Changes in Expenses and Other:
Other Operation and Maintenance(33.3)
Depreciation and Amortization45.8 
Taxes Other Than Income Taxes(4.6)
Interest and Investment Income(0.2)
Allowance for Equity Funds Used During Construction(0.8)
Non-Service Cost Components of Net Periodic Benefit Cost(0.3)
Interest Expense(10.4)
Total Change in Expenses and Other(3.8)
Income Tax Expense3.7 
Third Quarter of 2020$147.4 

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 $55 million primarily due to the following:
•A $52 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.
•An $18 million increase in rider revenues in Ohio associated with the DIR. This increase was partially offset in other expense items below.
•A $9 million increase in weather-normalized margins primarily in the residential class and partially offset in the commercial and industrial classes.
•A $6 million increase from interim rate increases driven by increased distribution investment in Texas.
•A $5 million increase in revenues in Ohio associated with the Universal Service Fund (USF). This increase was offset in Other Operation and Maintenance expenses below.
•A $5 million increase due to new base rates implemented in June 2020 in Texas.
•A $3 million increase in revenues associated with Ohio smart grid riders. This increase was partially offset in other expense items below.
These increases were partially offset by:
•A $19 million decrease due to refunds in Texas of Excess ADIT and excess federal income taxes collected as a result of Tax Reform. This decrease was offset in Income Tax Expense below.
•An $11 million decrease in weather-related usage in Texas primarily due to a 14% decrease in cooling degree days.
•A $6 million decrease due to the OVEC PPA Rider which was replaced by the Legacy Generation Resource Rider (LGRR). This decrease was offset in Margins from Off-system Sales and Other Revenues below.
•A $3 million decrease in revenues associated with a vegetation management rider in Ohio. This decrease was offset in Other Operation and Maintenance expenses below.
•A $3 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.
29





Reconciliation of Third Quarter of 2016 to Third Quarter of 2017
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
   
Third Quarter of 2016 $155.7
   
Changes in Gross Margin:  
Retail Margins (58.7)
Off-system Sales (11.6)
Transmission Revenues 7.6
Other Revenues 5.7
Total Change in Gross Margin (57.0)
   
Changes in Expenses and Other:  
Other Operation and Maintenance 55.0
Depreciation and Amortization (0.9)
Taxes Other Than Income Taxes (1.6)
Interest and Investment Income (0.3)
Carrying Costs Income (0.4)
Allowance for Equity Funds Used During Construction (1.3)
Interest Expense 2.2
Total Change in Expenses and Other 52.7
   
Income Tax Expense (7.4)
   
Third Quarter of 2017 $144.0
•Transmission Revenues increased $16 million primarily due to the following:

•An $11 million increase from interim rate increases driven by increased transmission investment in Texas.
•A $7 million increase in Ohio due to the annual transmission formula rate true-up.
•A $4 million increase primarily due to recovery of increased transmission investment in PJM.
These increases were partially offset by:
•A $7 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 $55 million primarily due to the following:
•A $68 million decrease in securitization revenues due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This increase was offset in Depreciation and Amortization expenses and Interest Expense below.
This decrease was partially offset by:
•An $8 million increase in revenues due to the amortization of a provision for refund recorded in December 2019 as part of the most recent base rate case in Texas. 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 $33 million primarily due to the following:
•A $50 million increase in transmission expenses primarily due to an increase in PJM and ERCOT expenses. This increase was offset in Gross Margin above.
•A $5 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 in Retail Margins above.
These decreases were partially offset by:
•A $16 million decrease in distribution expenses. This decrease was partially offset in Gross Margins above.
•Depreciation and Amortization expenses decreased $46 million primarily due to the following:
•A $63 million decrease in securitization amortizations in Texas due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This increase was offset in Other Revenues above and Interest Expense below.
This decrease was partially offset by:
•A $9 million increase in Ohio recoverable DIR depreciation expense. This increase was partially offset in Retail Margins above.
•A $5 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
•Taxes Other Than Income Taxes increased $5 million primarily due to property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
•Interest Expense increased $10 million primarily due to higher long-term debt balances.
•Income Tax Expense decreased $4 million primarily due to an increase in amortization of Excess ADIT, partially offset by an increase in pretax book income. This decrease was partially offset in Gross Margins and Other Operation and Maintenance Expenses above.
30





Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019
Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
Nine Months Ended September 30, 2019$421.6 
Changes in Gross Margin:
Retail Margins8.7 
Margins from Off-system Sales(17.3)
Transmission Revenues31.7 
Other Revenues(24.6)
Total Change in Gross Margin(1.5)
Changes in Expenses and Other:
Other Operation and Maintenance63.9 
Depreciation and Amortization1.4 
Taxes Other Than Income Taxes(7.2)
Interest and Investment Income(2.2)
Carrying Costs Income0.6 
Allowance for Equity Funds Used During Construction1.4 
Non-Service Cost Components of Net Periodic Benefit Cost(0.7)
Interest Expense(46.8)
Total Change in Expenses and Other10.4 
Income Tax Expense(27.4)
Nine Months Ended September 30, 2020$403.1 

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


•Retail Margins decreased $59 increased $9 million primarily due to the following:
•A $52$74 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 $48 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 revenues associated with Ohio smart grid riders. This increase was partially offset in other expense items below.
•A $15 million increase in revenues in Ohio associated with the USF. This increase was offset in Other Operation and Maintenance expenses below.
•An $8 million increase in weather-normalized margins primarily in the residential class and partially offset in the industrial and commercial classes.
•A $7 million increase from interim rate increases driven by increased transmission investment in Texas.
•A $7 million increase from interim rate increases driven by increased distribution investment in Texas.
•A $7 million increase due to new base rates implemented in June 2020 in Texas.
•A $5 million increase due to the change in the recording of merger savings as authorized by the PUCT in the most recent base rate case.
These increases were partially offset by:
•A $58 million decrease due to a reversal of a regulatory provision in Ohio in the first quarter of 2019.
•A $25 million decrease due to refunds in Texas of Excess ADIT and excess federal income taxes collected as a result of Tax Reform. This decrease was offset in Income Tax Expense below.
•A $23 million decrease in Ohio Deferred Asset Phase-In-Recovery Rider revenues associated withwhich ended in the Universal Service Fund (USF) surcharge rate decrease.second quarter of 2019. This decrease was offset by a corresponding decrease in Other OperatingDepreciation and MaintenanceAmortization expenses below.
An $18
31





•A $21 million decrease due to the OVEC PPA Rider which was replaced by the LGRR. This decrease was offset in Margins from Off-system Sales and Other Revenues below.
•A $17 million net decrease in recoverymargin in Ohio for the Rate Stability Rider including associated amortizations which ended in the third quarter of equity carrying charges related2019.
•A $15 million decrease in weather-related usage in Texas primarily due to the Ohio Phase-In Recovery Rider (PIRR), net of associated amortizations.a 6% decrease in cooling degree days and a 46% decrease in heating degree days.
An $8•A $9 million decrease in revenues associated with smart grid ridersa vegetation management rider in Ohio. This decrease was offset in expense itemsOther Operation and Maintenance expenses below.
A $7 million decrease in weather-related usage in Texas.
•A $5 million decrease in state excise taxes due to a decrease in metered KWh in Ohio.PUCO order to refund unused 2018 major storm reserve collections to customers. This decrease was offset by a correspondingin Other Operation and Maintenance expenses below.
•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.
•Margins from Off-system Sales decreased $17 million primarily due to the following:
•A $20 million decrease in TaxesTexas primarily due to lower Oklaunion Power Station PPA revenues. This decrease was offset in Other Than Income TaxesOperation and Maintenance expenses below.
•A $12 million decrease in sales in Ohio due to lower market prices and decreased sales volumes in 2020. This decrease was offset in Retail Margins above.
These decreases were partially offset by:
A $14•An $18 million increase in AEP Texas revenues associated withOhio due to higher OVEC PPA deferrals. This increase was offset in Retail Margins above.
•Transmission Revenues increased $32 million primarily due to the Distribution Cost Recovery Factor revenue rider.following:
•A $12$30 million favorable impactincrease from interim rate increases driven by increased transmission investment in Texas.
•A $16 million increase in Ohio due to the recoveryannual transmission formula rate true-up.
•A $6 million increase due to additional investment in transmission assets in Ohio.
These increases were partially offset by:
•A $14 million decrease in Texas due to a one-time credit to transmission customers as a result of losses from a power contractTax Reform and the most recent base rate case. This decrease was offset in Income Tax Expense below.
•A $7 million decrease due to refunds to customers associated with OVEC. The PUCO approved a PPA rider beginningthe most recent base rate case in January 2017Texas. This decrease is offset in Other Revenues below.
•Other Revenues decreased $25 million primarily due to recover any net marginthe following:
•A $49 million decrease in securitization revenue due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset in Depreciation and Amortization expenses and Interest Expense below.
This decrease was partially offset by:
•A $12 million increase in Ohio primarily due to third-party LGRR revenue related to the deferralrecovery of OVEC losses starting in June 2016.costs. This increase was offset by a corresponding decrease in Margins from Off-System Sales below.
Margins from Off-system Sales decreased $12 million due to current year losses from a power contract with OVEC which is deferred in Retail Margins aboveabove.
•An $11 million increase in revenues due to the amortization of a provision for refund recorded in December 2019 as a resultpart of the OVEC PPA rider beginningmost recent base rate case in January 2017.
Transmission Revenues increased $8 million primarily due to recovery of increased transmission investment in ERCOT.
Other Revenues increased $6 million primarily due to anTexas. This increase in Texas securitization revenue,was offset in other expense items below.
Retail Margins and Transmission Revenues above.



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


•Other Operation and Maintenance expenses decreased $55$64 million primarily due to the following:
•A $67 million decrease due to prior year partial amortization of the AEP Texas Storm Restoration Securitization regulatory asset as a result of the AEP Texas Storm Cost Securitization financing order issued by the PUCT in June 2019. This decrease was offset in Income Tax Expense below.
•A $17 million decrease due to the revision of the Oklaunion Power Station ARO. This decrease was offset in Margins for Off-System Sales above.
•A $15 million decrease in distribution expenses primarily due to vegetation management. This decrease was partially offset in Retail Margins above.
•A $5 million decrease due to a PUCO order to refund unused 2018 major storm reserve collections to customers. This decrease was offset in Retail Margins above.

32





These decreases were partially offset by:
•A $52$41 million increase in transmission expenses primarily due to a $68 million increase in recoverable PJM and ERCOT expenses partially offset by a $28 million decrease related to the annual PJM transmission formula rate true-up. This increase was offset in Gross Margin above.
•A $15 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This decreaseincrease was offset by a corresponding decrease in Retail Margins above.
•Depreciation and Amortization expenses decreased $1 million primarily due to the following:
•A $5$43 million decrease in employee-related expenses.securitization amortizations due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset in Other Revenues above and Interest Expense below.
•A $3$24 million decrease in recoverable smart grid expensesamortizations associated with the Deferred Asset Phase-In-Recovery Rider in Ohio.Ohio which ended in the second quarter of 2019. This decrease was offset in Retail Margins above.
These decreases were partially offset by:
•A $27 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
•A $16 million increase in Ohio recoverable DIR depreciation expense. This increase was partially offset in Retail Margins above.
•An $11 million increase due to lower deferred equity amortizations associated with the Deferred Asset Phase-In-Recovery Rider in Ohio which ended in the second quarter of 2019.
•A $7 million increase in amortizations primarily due to capitalized software.
•A $6 million increase in storm expenses, primarilyrecoverable smart grid expense in the Texas region.Ohio. This increase was offset in Retail Margins above.
Depreciation and Amortization expenses•Taxes Other Than Income Taxes increased $1$7 million primarily due to the following:
An $11 million increase primarily due to securitization amortizations related to transition funding, offset in Other Revenues above.
•A $2 million increase due to amortization of capitalized software costs.
These increases were partially offset by:
A $5 million decrease in recoverable DIR depreciation expense in Ohio.
A $4 million decrease in amortization expenses for the collection of carrying costs on Ohio deferred capacity charges beginning June 2015.
A $4 million decrease in recoverable smart grid rider depreciation expenses in Ohio. This decrease was offset in Retail Margins above.
Taxes Other Than Income Taxes increased $2 million primarily due to the following:
A $7$13 million increase in property taxes due todriven by additional investments in transmission and distribution assets and higher tax rates.
This increase was partially offset by:
•A $5$4 million decrease in state excise taxes due to a decreaselower demand in metered KWh in Ohio.
Interest Expense decreased $2 million primarily due to a decrease in the Texas securitization transition assets as a result of the final maturity of the first Texas securitization bond. This decrease was offset by a corresponding decrease in Other Revenues above.
Income TaxExpense increased $7 million primarily due to the recording of favorable federal income tax adjustments in 2016 and other book/tax differences which are accounted for on a flow-through basis.


Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016
Reconciliation of Nine Months Ended September 30, 2016 to Nine Months Ended September 30, 2017
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
   
Nine Months Ended September 30, 2016 $387.8
   
Changes in Gross Margin:  
Retail Margins (123.0)
Off-system Sales (26.8)
Transmission Revenues 24.2
Other Revenues 6.6
Total Change in Gross Margin (119.0)
   
Changes in Expenses and Other:  
Other Operation and Maintenance 127.0
Depreciation and Amortization 2.6
Taxes Other Than Income Taxes (14.1)
Interest and Investment Income 0.1
Carrying Costs Income (1.0)
Allowance for Equity Funds Used During Construction (4.3)
Interest Expense 13.5
Total Change in Expenses and Other 123.8
   
Income Tax Expense (18.3)
   
Nine Months Ended September 30, 2017 $374.3

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

Retail Margins decreased $123 million primarily due to the following:
A $140 million decrease in Ohio revenues associated with the USF surcharge rate decrease. This decrease was offset by a corresponding decrease in Other Operating and Maintenance expenses below.
A $14 million decrease in weather-normalized margins, primarily in the residential class.
A $21 million decrease due to a prior year reversal of a regulatory provision resulting from a favorable court decision in Ohio.
A $13 million decrease in revenues associated with smart grid riders in Ohio. This decrease was offset in expense items below.
A $9 million net decrease in recovery of equity carrying charges related to the PIRR, net of associated amortizations.
A $7 million decrease in state excise taxes due to a decrease in metered KWh in Ohio. This decrease was offset by a corresponding decrease in Taxes Other Than Income Taxes.
These decreases were partially offset by:
A $46 million favorable impact in Ohio due to the recovery of losses from a power contract with OVEC. The PUCO approved a PPA rider beginning in January 2017 to recover any net margin related to the deferral of OVEC losses starting in June 2016. This increase was offset by a corresponding decrease in Margins from Off-System Sales below.
A $40 million increase in AEP Texas revenues associated with the Distribution Cost Recovery Factor revenue rider.
A $6 million increase in rider revenues associated with the DIR. This increase is partially offset in other expense items below.


Margins from Off-system Sales decreased $27 million primarily due to the following:
A $46 million decrease in Ohio due to current year losses from a power contract with OVEC, which is deferred in Retail Margins above as a result of the OVEC PPA rider beginning in January 2017.
This decrease was partially offset by:
An $18 million increase in Ohio primarily due to the impact of prior year losses from a power contract with OVEC which was not included in the OVEC PPA rider.
Transmission Revenues increased $24 million primarily due to recovery of increased transmission investment in ERCOT.
Other Revenues increased $7 million primarily due to an increase in Texas securitization revenue, offset in other expense items below.

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

Other Operation and Maintenance expenses decreased $127 million primarily due to the following:
A $140 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 by a corresponding decrease in Retail Margins above.
A $10 million decrease in employee-related expenses.
These decreases were partially offset by:
A $12 million increase in PJM expenses related to the annual formula rate true-up that will be recovered in future periods.
A $6 million increase in storm expenses, primarily in the Texas region.
A $5 million increase in vegetation management expenses.
Depreciation and Amortization expenses decreased $3 million primarily due to the following:
An $11 million decrease in amortization expenses for the collection of carrying costs on Ohio deferred capacity charges beginning June 2015.
An $8 million decrease due to recoveries of transmission cost rider carrying costs in Ohio. This decrease was partially offset in Retail Margins above.
A $7 million decrease in recoverable DIR depreciation expense in Ohio.
A $5 million decrease in recoverable smart grid rider depreciation expenses2020 in Ohio. This decrease was offset in Retail Margins above.
These decreases were partially offset by:
A $16 million increase due to securitization amortizations related to transition funding, offset in Other Revenues above.
A $9 million increase in depreciation expense primarily due to an increase in depreciable base of transmission and distribution assets.
A $6 million increase due to amortization of capitalized software costs.
Taxes Other Than Income Taxes•Interest Expense increased $14$47 million primarily due to the following:
•A $20$24 million increase in property taxes due to additional investmentsthe deferral of previously recorded interest expense approved for recovery as a result of the Texas Storm Cost Securitization financing order issued by the PUCT in transmission and distribution assets andJune 2019.
•A $21 million increase due to higher tax rates.long-term debt balances.
This•A $7 million increase due to due to a decrease in the debt component of AFUDC.
These increases were partially offset by:
•A $7$5 million decrease in state excise taxes due to a decrease in metered KWh in Ohio.
Allowance for Equity Funds Used During Construction decreased $4 millionprimarily due to largerlower short-term debt balances.
Interest•Income Tax Expense decreased $14increased $27 million primarily due to the following:
A $9 million decrease dueprior year amortization of Excess ADIT not subject to the maturity of a senior unsecured note in June 2016 in Ohio.
A $7 million decreasenormalization requirements as approved in the Texas securitization transition assets due toStorm Cost Securitization financing order issued by the final maturity of the first Texas securitization bond. This decrease wasPUCT in 2019 partially offset by a corresponding decreasecurrent year amortization of Excess ADIT and an increase in favorable AFUDC Equity tax benefit. This increase was partially offset in Gross Margins and Other RevenuesOperation and Maintenance Expenses above.
Income TaxExpense increased $18 million primarily due to the recording of favorable state and federal income tax adjustments in 2016 and other book/tax differences which are accounted for on a flow-through basis.
33







AEP TRANSMISSION HOLDCO
Three Months EndedNine Months Ended
September 30,September 30,
AEP Transmission Holdco2020201920202019
 (in millions)
Transmission Revenues$317.9 $273.0 $877.8 $808.3 
Other Operation and Maintenance30.1 31.8 85.9 77.0 
Depreciation and Amortization63.6 47.3 182.8 133.7 
Taxes Other Than Income Taxes53.8 44.3 157.5 130.4 
Operating Income170.4 149.6 451.6 467.2 
Interest and Investment Income0.2 0.8 2.6 2.3 
Allowance for Equity Funds Used During Construction20.3 21.0 54.9 61.1 
Non-Service Cost Components of Net Periodic Benefit Cost0.5 0.7 1.5 2.0 
Interest Expense(34.0)(27.8)(99.0)(73.8)
Income Before Income Tax Expense and Equity Earnings157.4 144.3 411.6 458.8 
Income Tax Expense38.2 35.4 101.3 105.7 
Equity Earnings of Unconsolidated Subsidiary20.1 18.1 62.8 54.5 
Net Income139.3 127.0 373.1 407.6 
Net Income Attributable to Noncontrolling Interests1.0 0.9 2.7 2.8 
Earnings Attributable to AEP Common Shareholders$138.3 $126.1 $370.4 $404.8 
  Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
AEP Transmission Holdco 2017 2016 2017 2016
  (in millions)
Transmission Revenues $178.5
 $132.4
 $581.9
 $382.7
Other Operation and Maintenance 23.1
 12.2
 54.5
 32.7
Depreciation and Amortization 26.1
 17.1
 74.7
 48.4
Taxes Other Than Income Taxes 28.6
 22.7
 85.0
 65.7
Operating Income 100.7
 80.4
 367.7
 235.9
Interest and Investment Income 0.1
 —
 0.5
 —
Carrying Costs Expense —
 —
 (0.1) (0.2)
Allowance for Equity Funds Used During Construction 11.6
 13.5
 35.9
 39.8
Interest Expense (17.9) (12.2) (52.3) (35.4)
Income Before Income Tax Expense and Equity Earnings 94.5
 81.7
 351.7
 240.1
Income Tax Expense 38.6
 35.2
 142.1
 103.2
Equity Earnings of Unconsolidated Subsidiaries 20.6
 23.0
 68.7
 72.6
Net Income 76.5
 69.5
 278.3
 209.5
Net Income Attributable to Noncontrolling Interests 1.0
 0.5
 2.6
 2.0
Earnings Attributable to AEP Common Shareholders $75.5
 $69.0
 $275.7
 $207.5


Summary of Investment in Transmission Assets for AEP Transmission Holdco
September 30,
20202019
(in millions)
Plant in Service$9,644.6 $7,796.9 
Construction Work in Progress1,732.5 1,903.4 
Accumulated Depreciation and Amortization553.1 383.7 
Total Transmission Property, Net$10,824.0 $9,316.6 
34





  September 30,
  2017 2016
  (in millions)
Plant in Service $5,001.4
 $3,330.5
CWIP 1,392.8
 1,565.8
Accumulated Depreciation 156.6
 88.1
Total Transmission Property, Net $6,237.6
 $4,808.2


Third Quarter of 20172020 Compared to Third Quarter of 20162019
 
Reconciliation of Third Quarter of 20162019 to Third Quarter of 20172020
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
Third Quarter of 2019$126.1 
Changes in Transmission Revenues:
Transmission Revenues44.9 
Total Change in Transmission Revenues44.9 
Changes in Expenses and Other:
Other Operation and Maintenance1.7 
Depreciation and Amortization(16.3)
Taxes Other Than Income Taxes(9.5)
Interest and Investment Income(0.6)
Allowance for Equity Funds Used During Construction(0.7)
Non-Service Cost Components of Net Periodic Pension Cost(0.2)
Interest Expense(6.2)
Total Change in Expenses and Other(31.8)
Income Tax Expense(2.8)
Equity Earnings of Unconsolidated Subsidiary2.0 
Net Income Attributable to Noncontrolling Interests(0.1)
Third Quarter of 2020$138.3 
Third Quarter of 2016 $69.0
   
Changes in Transmission Revenues:  
Transmission Revenues 46.1
Total Change in Transmission Revenues 46.1
   
Changes in Expenses and Other:  
Other Operation and Maintenance (10.9)
Depreciation and Amortization (9.0)
Taxes Other Than Income Taxes (5.9)
Interest and Investment Income 0.1
Allowance for Equity Funds Used During Construction (1.9)
Interest Expense (5.7)
Total Change in Expenses and Other (33.3)
   
Income Tax Expense (3.4)
Equity Earnings (2.4)
Net Income Attributable to Noncontrolling Interests (0.5)
   
Third Quarter of 2017 $75.5


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


•Transmission Revenuesincreased $46$45 million primarily due to an increase in formula rates driven by continued investment in transmission assets.


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


Other Operation•Depreciation and MaintenanceAmortization expenses increased $11$16 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxesincreased transmission investment.
Depreciation and Amortization expenses increased $9$10 million primarily due to higher depreciable base.
Taxes Other Than Income Taxes increased $6 million primarily due to increased property taxes as a result of additionalincreased transmission investment.
•Interest Expense increased $6 million primarily due to higher outstanding long-term debt balances.
35
Income Tax Expense increased $3 million primarily due to an increase in pretax book income.







Nine Months Ended September 30, 20172020 Compared to Nine Months Ended September 30, 20162019
 
Reconciliation of Nine Months Ended September 30, 20162019 to Nine Months Ended September 30, 20172020
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
Nine Months Ended September 30, 2019$404.8 
Changes in Transmission Revenues:
Transmission Revenues69.5 
Total Change in Transmission Revenues69.5 
Changes in Expenses and Other:
Other Operation and Maintenance(8.9)
Depreciation and Amortization(49.1)
Taxes Other Than Income Taxes(27.1)
Interest and Investment Income0.3 
Allowance for Equity Funds Used During Construction(6.2)
Non-Service Cost Components of Net Periodic Pension Cost(0.5)
Interest Expense(25.2)
Total Change in Expenses and Other(116.7)
Income Tax Expense4.4 
Equity Earnings of Unconsolidated Subsidiary8.3 
Net Income Attributable to Noncontrolling Interests0.1 
Nine Months Ended September 30, 2020$370.4 
Nine Months Ended September 30, 2016 $207.5
   
Changes in Transmission Revenues:  
Transmission Revenues 199.2
Total Change in Transmission Revenues 199.2
   
Changes in Expenses and Other:  
Other Operation and Maintenance (21.8)
Depreciation and Amortization (26.3)
Taxes Other Than Income Taxes (19.3)
Interest and Investment Income 0.5
Carrying Costs Expense 0.1
Allowance for Equity Funds Used During Construction (3.9)
Interest Expense (16.9)
Total Change in Expenses and Other (87.6)
   
Income Tax Expense (38.9)
Equity Earnings (3.9)
Net Income Attributable to Noncontrolling Interests (0.6)
   
Nine Months Ended September 30, 2017 $275.7


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

•Transmission Revenues increased $199$70 million primarily due to the current year favorable impact of the modification of the PJM OATT formula rates combined with anfollowing:
•A $149 million increase driven bydue to continued investment in transmission assets.

This increase was partially offset by the following:
•A $62 million decrease 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 $17 million decrease as a result of the non-affiliated annual transmission formula rate true-up.
Expenses and Other, Income Tax Expense and Equity Earnings of Unconsolidated Subsidiary changed between years as follows:

•Other Operation and Maintenance expenses increased $22$9 million primarily due to increased transmission investment.
the following:
•A $5 million increase in rent expense.
•A $3 million increase in employee-related expenses.
•Depreciation and Amortization expenses increased $26$49 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxes increased $19$27 million primarily due to increasedhigher property taxes as a result of additionalincreased transmission investment.
•Allowance for Equity Funds Used During Construction decreased $4$6 million primarily due to the following:
•A $12 million decrease driven by the favorable impact of a FERC transmission complaint and ansettlement agreement recorded in 2019.
•An $8 million decrease due to lower CWIP.
These decreases were partially offset by:
•A $13 million increase driven by FERC audit findings recorded in the amount of short-term debt, offset by an increase in the CWIP balance.
2019.
•Interest Expense increased $17$25 million primarily due to higher outstanding long-term debt balances.
•Income Tax Expense increased $39 million primarily due to an increase in pretax book income.
Equity Earnings decreased $4 million primarily due to lower earnings at ETT resulting from increased property taxes, depreciation expense, and decreased AFUDC,pretax book income, partially offset by the recognition of a discrete tax adjustment in 2019.
•Equity Earnings of Unconsolidated Subsidiaryincreased revenues. The revenue increase is$8 million primarily due to interim rate increases in the third quarter of 2016higher pretax equity earnings at PATH-WV and higher loads, partially offset by an ETT rate reduction that went into effect in March 2017.ETT.
36








GENERATION & MARKETING
Three Months EndedNine Months Ended
September 30,September 30,
Generation & Marketing2020201920202019
 (in millions)
Revenues$490.0 $533.7 $1,305.5 $1,428.2 
Fuel, Purchased Electricity and Other391.6 403.8 1,050.4 1,117.8 
Gross Margin98.4 129.9 255.1 310.4 
Other Operation and Maintenance27.2 44.0 85.1 158.0 
Depreciation and Amortization18.5 20.6 54.1 49.1 
Taxes Other Than Income Taxes3.3 4.4 10.4 11.8 
Operating Income49.4 60.9 105.5 91.5 
Interest and Investment Income0.4 1.9 2.6 6.0 
Non-Service Cost Components of Net Periodic Benefit Cost3.9 3.8 11.6 11.2 
Interest Expense(3.8)(10.5)(20.5)(21.5)
Income Before Income Tax Benefit and Equity Earnings (Loss)49.9 56.1 99.2 87.2 
Income Tax Benefit(70.9)(36.4)(104.3)(51.8)
Equity Earnings (Loss) of Unconsolidated Subsidiaries(6.2)(3.8)0.1 (5.9)
Net Income114.6 88.7 203.6 133.1 
Net Loss Attributable to Noncontrolling Interests(2.1)(1.3)(7.4)(6.4)
Earnings Attributable to AEP Common Shareholders$116.7 $90.0 $211.0 $139.5 
  Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
Generation & Marketing 2017 2016 2017 2016
  (in millions)
Revenues $465.5
 $859.4
 $1,467.5
 $2,291.2
Fuel, Purchased Electricity and Other 354.6
 567.4
 1,062.7
 1,490.6
Gross Margin 110.9
 292.0
 404.8
 800.6
Other Operation and Maintenance 56.5
 95.8
 211.4
 290.2
Asset Impairments and Other Related Charges (2.5) 2,254.4
 10.6
 2,254.4
Gain on Sale of Merchant Generation Assets —
 —
 (226.4) —
Depreciation and Amortization 6.2
 50.5
 17.5
 149.8
Taxes Other Than Income Taxes 3.2
 8.7
 8.9
 29.0
Operating Income (Loss) 47.5
 (2,117.4) 382.8
 (1,922.8)
Interest and Investment Income 2.7
 0.3
 7.9
 1.2
Interest Expense (4.0) (9.5) (14.7) (27.1)
Income (Loss) Before Income Tax Expense 46.2
 (2,126.6) 376.0
 (1,948.7)
Income Tax Expense (Credit) 12.5
 (757.4) 129.7
 (699.9)
Net Income (Loss) 33.7
 (1,369.2) 246.3
 (1,248.8)
Net Income Attributable to Noncontrolling Interests —
 —
 —
 —
Earnings (Loss) Attributable to AEP Common Shareholders $33.7
 $(1,369.2) $246.3
 $(1,248.8)


Summary of MWhs Generated for Generation & Marketing
Three Months Ended 
September 30,		Nine Months Ended 
September 30,
2020201920202019
 (in millions of MWhs)
Fuel Type:    
Coal1 2 3 4 
Renewables— 1 2 2 
Total MWhs1 3 5 6 
37
 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
 2017 2016 2017 2016
 (in millions of MWhs)
Fuel Type: 
  
  
  
Coal2
 8
 10
 19
Natural Gas—
 4
 2
 11
Total MWhs2
 12
 12
 30








Third Quarter of 20172020 Compared to Third Quarter of 20162019
Reconciliation of Third Quarter of 2019 to Third Quarter of 2020
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
Third Quarter of 2019$90.0 
Changes in Gross Margin:
Merchant Generation(24.3)
Renewable Generation(4.1)
Retail, Trading and Marketing(3.1)
Total Change in Gross Margin(31.5)
Changes in Expenses and Other:
Other Operation and Maintenance16.8 
Depreciation and Amortization2.1 
Taxes Other Than Income Taxes1.1 
Interest and Investment Income(1.5)
Non-Service Cost Components of Net Periodic Benefit Cost0.1 
Interest Expense6.7 
Total Change in Expenses and Other25.3 
Income Tax Benefit34.5 
Equity Earnings (Loss) of Unconsolidated Subsidiaries(2.4)
Net Loss Attributable to Noncontrolling Interests0.8 
Third Quarter of 2020$116.7 
Reconciliation of Third Quarter of 2016 to Third Quarter of 2017
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
   
Third Quarter of 2016 $(1,369.2)
   
Changes in Gross Margin:  
Generation (175.4)
Retail, Trading and Marketing (10.1)
Other 4.4
Total Change in Gross Margin (181.1)
   
Changes in Expenses and Other:  
Other Operation and Maintenance 39.3
Asset Impairments and Other Related Charges 2,256.9
Depreciation and Amortization 44.3
Taxes Other Than Income Taxes 5.5
Interest and Investment Income 2.4
Interest Expense 5.5
Total Change in Expenses and Other 2,353.9
   
Income Tax Expense (769.9)
   
Third Quarter of 2017 $33.7


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


•Merchant Generation decreased $175$24 million primarily due to the reduction oflower capacity revenues associated with the sale of certain merchant generation assets.
Retail, Trading and Marketing decreased $10 million due to lower retailenergy margins in 2017 partially offset by favorable wholesale trading2020 and marketing performancethe retirement of the Conesville Plant Units 5 and 6 in 2017.
2019 and Unit 4 in 2020.
Other increased•Renewable Generation decreased $4 million primarily due to renewable projects placed in service.
lower wind production.

•Retail, Trading and Marketing decreased $3 million due to lower trading and marketing activity, partially offset by higher retail margins.

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


•Other Operation and Maintenance expenses decreased $39 million primarily due to decreased plant expenses as a result of the sale of certain merchant generation assets.
Asset Impairments and Other Related Charges decreased $2.3 billion due to the asset impairment of certain merchant generation assets in 2016.
Depreciation and Amortization expenses decreased $44$17 million primarily due to the following:
•An $11 million decrease due to a gain recorded on the sale of land.
•An $8 million decrease due to the retirement of Conesville Plant Units 5 and impairment of certain merchant generation assets.
6 in 2019 and Unit 4 in 2020.
•Interest Expense decreased $7 million due to lower borrowing costs in 2020.
Taxes Other Than •Income Taxes decreased $6Tax Benefit increased $35 million primarily due to the salerecognition of certain merchant generation assets.a discrete tax adjustment in 2020, which was attributable to the CARES Act offset by a decrease in PTC.

38





Interest Expense decreased $6 million primarily due to reduced debt as a result of the sale of certain merchant generation assets.

Income Tax Expense increased $770 million primarily due to an increase in pretax book income resulting primarily from the impairment of certain merchant generation assets in 2016.


Nine Months Ended September 30, 20172020 Compared to Nine Months Ended September 30, 20162019
Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
Nine Months Ended September 30, 2019$139.5 
Changes in Gross Margin:
Merchant Generation(78.3)
Renewable Generation17.4 
Retail, Trading and Marketing5.6 
Total Change in Gross Margin(55.3)
Changes in Expenses and Other:
Other Operation and Maintenance72.9 
Depreciation and Amortization(5.0)
Taxes Other Than Income Taxes1.4 
Interest and Investment Income(3.4)
Non-Service Cost Components of Net Periodic Benefit Cost0.4 
Interest Expense1.0 
Total Change in Expenses and Other67.3 
Income Tax Benefit52.5 
Equity Earnings (Loss) of Unconsolidated Subsidiaries6.0 
Net Loss Attributable to Noncontrolling Interests1.0 
Nine Months Ended September 30, 2020$211.0 
Reconciliation of Nine Months Ended September 30, 2016 to Nine Months Ended September 30, 2017
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
   
Nine Months Ended September 30, 2016 $(1,248.8)
   
Changes in Gross Margin:  
Generation (376.2)
Retail, Trading and Marketing (33.6)
Other 14.0
Total Change in Gross Margin (395.8)
   
Changes in Expenses and Other:  
Other Operation and Maintenance 78.8
Asset Impairments and Other Related Charges 2,243.8
Gain on Sale of Merchant Generation Assets 226.4
Depreciation and Amortization 132.3
Taxes Other Than Income Taxes 20.1
Interest and Investment Income 6.7
Interest Expense 12.4
Total Change in Expenses and Other 2,720.5
   
Income Tax Expense (829.6)
   
Nine Months Ended September 30, 2017 $246.3


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 decreased $376$78 million primarily due to the reduction of capacity revenues associated withand energy margins in 2020 and the saleretirement of certain merchant generation assets.
the Conesville Plant Units 5 and 6 in 2019 and Unit 4 in 2020.
•Renewable Generation increased $17 million primarily due to the Sempra Renewables LLC acquisition and other renewable projects placed in-service.
•Retail, Trading and Marketing decreased $34increased $6 million primarily due to lower margins in 2017 combined with the impact of favorable wholesalehigher trading and marketing performance in 2016.
activity, partially offset by lower retail margins.
Other increased $14 million primarily due to renewable projects placed in service.


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


•Other Operation and Maintenance expenses decreased $79 million primarily due to decreased plant expenses as a result of the sale of certain merchant generation assets.
Asset Impairments and Other Related Charges decreased $2.2 billion due to the asset impairment of certain merchant generation assets in 2016.
Gain on Sale of Merchant Generation Assets increased $226$73 million due to the following:
•A $34 million decrease due to the retirement of Conesville Plant Units 5 and 6 in 2019 and Unit 4 in 2020.
•A $26 million decrease due to a gain recorded on the sale of certain merchant generation assets.
land.
•A $16 million decrease related to the Oklaunion PPA with AEP Texas primarily due to an ARO revision.
•Depreciation and Amortizationexpenses increased $5 million due to a higher depreciable base from increased investments in renewable energy sources.
•Interest and Investment Income decreased $132$3 million due to lower returns on investments.
•Income Tax Benefit increased $53 million primarily due the recognition of a discrete tax adjustment in 2020, which was attributable to the CARES Act and an increase in PTC.
•Equity Earnings (Loss) of Unconsolidated Subsidiaries increased $6 million primarily due to the sale and impairment of certain merchant generation assets.Sempra Renewables LLC acquisition.
39
Taxes Other Than Income Taxes decreased $20 million primarily due to the sale of certain merchant generation assets.





Interest and Investment Income increased $7 million primarily due to increased cash invested as a result of the sale of certain merchant generation assets.
Interest Expense decreased $12 million primarily due to reduced debt as a result of the sale of certain merchant generation assets.
Income Tax Expense increased $830 million primarily due to an increase in pretax book income and state income taxes resulting primarily from the impairment of certain merchant generation assets in 2016.


CORPORATE AND OTHER


Third Quarter of 20172020 Compared to Third Quarter of 20162019


Earnings Attributable to AEP Common Shareholders from Corporate and Other decreasedincreased from $36a loss of $54 million in 20162019 to a loss of $47 million in 2020 primarily due to:

•A $12 million decrease in income tax expense due to a decrease in consolidating tax adjustments.
•A $6 million decrease in interest expense as a result of a decrease in debt outstanding.

These items were partially offset by:

•A $5 million increase in 2017 primarily due to the prior year reversal of a capital loss valuation allowance related to the pending sale of certain merchant generation assets as well as tax return adjustments related to the prior year disposition of AEP’s commercial barging operations, partially offset by the gain recognized on the sale of a cost-based investmentgeneral corporate expenses.
•A $6 million decrease in the third quarter of 2017.interest income.


Nine Months Ended September 30, 20172020 Compared to Nine Months Ended September 30, 20162019


Earnings Attributable to AEP Common Shareholders from Corporate and Other decreasedincreased from incomea loss of $62$116 million in 20162019 to a loss of $115 million in 2020 primarily due to:

•An $11 million decrease in 2017 primarilygeneral corporate expenses.
•A $5 million write-off of an equity investment and related assets in 2019.
•A $2 million decrease in income tax expense due to the prior year reversal of capital loss valuation allowances related to effectively settling a 2011 audit issue with the IRS and the impact of the pending sale of certain merchant generation assets as well as 2015 tax return adjustments related to the disposition of AEP’s commercial barging operations,discrete items recorded in 2020, partially offset by the gain recognized on the salean increase in consolidating tax adjustments.

These items were partially offset by:

•An $8 million decrease in interest income.
•An $8 million increase in interest expense as a result of a cost-based investmentan increase in the third quarter of 2017.debt outstanding.


AEP SYSTEM INCOME TAXES


Third Quarter of 20172020 Compared to Third Quarter of 20162019


Income Tax Expense increased $799decreased $42 million primarily due to an increasethe recognition of a $52 million discrete tax adjustment in pretax book income driven by the impairment of certain merchant generation assets in the third quarter of 2016. The increase in Income Tax Expense is also due2020, which was attributable to the third quarter5-year net operating loss carryback provision of 2016 reversal of a $66 million capital loss valuation allowance related to the pending sale of certain merchant generation assets as well as prior year tax return adjustments related to the disposition of AEP’s commercial barging operations.CARES Act.


Nine Months Ended September 30, 20172020 Compared to Nine Months Ended September 30, 20162019


Income Tax Expense increased $932$27 million primarily due to an increasea decrease in pretax book income drivenamortization of Excess ADIT, partially offset by the impairmentrecognition of certain merchant generation assetsthe discrete tax adjustment in the third quarter of 2016. The increase in Income Tax Expense is also due2020, which was attributable to the prior year reversal5-year net operating loss carryback provision of a $56 million unrealized capital loss valuation allowance where AEP effectively settled a 2011 audit issue with the IRS, the prior year reversal of a $66 million capital loss valuation allowance related to the pending sale of certain merchant generation assets as well as prior year tax return adjustments related to the disposition of AEP’s commercial barging operations.

CARES Act.



40





FINANCIAL CONDITION


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


LIQUIDITY AND CAPITAL RESOURCES


Debt and Equity Capitalization
 September 30, 2020December 31, 2019
 (dollars in millions)
Long-term Debt, including amounts due within one year$30,067.1 56.6 %$26,725.5 54.1 %
Short-term Debt2,397.0 4.5 2,838.3 5.7 
Total Debt32,464.1 61.1 29,563.8 59.8 
AEP Common Equity20,365.9 38.4 19,632.2 39.6 
Noncontrolling Interests268.7 0.5 281.0 0.6 
Total Debt and Equity Capitalization$53,098.7 100.0 %$49,477.0 100.0 %
 September 30, 2017 December 31, 2016
 (dollars in millions)
Long-term Debt, including amounts due within one year$20,721.7
 51.9% $20,391.2
(a)51.6%
Short-term Debt1,059.3
 2.7
 1,713.0
 4.3
Total Debt21,781.0
 54.6
 22,104.2
(a)55.9
AEP Common Equity18,069.1
 45.3
 17,397.0
 44.0
Noncontrolling Interests36.4
 0.1
 23.1
 0.1
Total Debt and Equity Capitalization$39,886.5
 100.0% $39,524.3
 100.0%

(a)Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information.


AEP’s ratio of debt-to-total capital decreasedincreased from 55.9%59.8% as of December 31, 20162019 to 54.6%61.1% as of September 30, 20172020 primarily due to a decreasean increase in short-term debt due to the use of proceeds from the sale of Merchant Generation Assets to pay down debt. See “Gavin, Waterford, Darbysupport distribution, transmission and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information.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 September 30, 2017,2020, AEP had a $3$4 billion revolving credit facility commitment to support its operations. In May 2017, the $500 million revolving credit facility due in June 2018 was terminated.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. There was increased volatility in the capital markets during the first quarter of 2020 resulting in higher commercial paper cost and limited access. To address these issues and the uncertainty around COVID-19, in March 2020, AEP entered into a $1 billion 364-day Term Loan and borrowed the full amount.


Commercial Paper Credit FacilitiesNet Available Liquidity


AEP manages liquidity by maintaining adequate external financing commitments.  As of September 30, 2017,2020, available liquidity was approximately $3$3.8 billion as illustrated in the table below:
AmountMaturity
Commercial Paper Backup:(in millions)
Revolving Credit Facility$4,000.0 June 2022
364-Day Term Loan1,000.0 March 2021
Cash and Cash Equivalents409.7 
Total Liquidity Sources5,409.7 
Less:AEP Commercial Paper Outstanding650.0 
364-Day Term Loan1,000.0 
Net Available Liquidity$3,759.7 
  Amount Maturity
  (in millions)  
Commercial Paper Backup: 
  
 Revolving Credit Facility$3,000.0
 June 2021
Total3,000.0
  
Cash and Cash Equivalents343.9
  
Total Liquidity Sources3,343.9
  
Less:AEP Commercial Paper Outstanding295.0
  
     
Net Available Liquidity$3,048.9
  

AEP has a $3 billion revolving credit facility to support its commercial paper program.



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 nine months of 20172020 was $1.6$3 billion.  The weighted-average interest rate for AEP’s commercial paper during 20172020 was 1.19%1.56%.

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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 fivesix uncommitted facilities totaling $445$405 million. In August 2017, AEP executed a $75 million uncommitted letter of credit facility due in August 2018. As of September 30, 2017, theThe Registrants’ maximum future paymentpayments for letters of credit issued under the uncommitted facilities as of September 30, 2020 was $123$197 millionwith maturities ranging from October 20172020 to September 2018.August 2021.


Securitized Accounts ReceivableReceivables


AEP’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables. The agreementreceivables and expires in June 2019.September 2022.


In May 2020, AEP Credit amended its receivables securitization agreement to increase the eligibility criteria related to aged receivable requirements for the participating affiliated utility subsidiaries in response to the COVID-19 pandemic. As of September 30, 2020, 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, receivables would no longer be purchased by the bank conduits and the Registrants would need to rely on additional sources of funding for operation and working capital, which may adversely impact liquidity.

Debt Covenants and Borrowing Limitations


AEP’s credit agreements contain certain covenants and require it to maintain a percentage of debt to 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 September 30, 2017,2020,this contractually-defined percentage was 52.4%57.7%. 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 facility does not permit the lenders to refuse a draw on theany 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.


Equity Units

In August 2020, AEP issued 17 million Equity Units initially in the form of corporate units, at a stated amount of $50 per unit, for a total stated amount of $850 million. Net proceeds from the issuance were approximately $833 million. Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 1.30% Junior Subordinated Notes due in 2025 and a forward equity purchase contract which settles after three years in 2023. The proceeds were used to support AEP’s overall capital expenditure plans.

In March 2019, AEP issued 16.1 million Equity Units initially in the form of corporate units, at a stated amount of $50 per unit, for a total stated amount of $805 million. Net proceeds from the issuance were approximately $785 million. Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 3.40% Junior Subordinated Notes due in 2024 and a forward equity purchase contract which 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.

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Dividend Policy and Restrictions


The Board of Directors declared a quarterly dividend of $0.62$0.74 per share in October 2017.2020. 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 related to AEP’s various financing arrangements and regulatory requirements 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 doesand 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 theirits credit ratings.  In addition, downgrades in AEP’s credit ratings by one of the rating agencies could increase its borrowing costs.  Counterparty concerns about the credit quality of AEP or its utility subsidiaries could subject AEP to additional collateral demands under adequate assurance clauses under its derivative and non-derivative energy contracts.


CASH FLOW


AEP relies primarily on cash flows from operations, debt issuances and its existing cash and cash equivalents to fund its liquidity and investing activities. AEP’s investing and capital requirements are primarily capital expenditures, repaying of long-term debt and paying dividends to shareholders.
 Nine Months Ended 
 September 30,
 2017 2016
 (in millions)
Cash and Cash Equivalents at Beginning of Period$210.5
 $176.4
Net Cash Flows from Continuing Operating Activities3,124.2
 3,421.0
Net Cash Flows Used for Continuing Investing Activities(1,676.6) (3,428.7)
Net Cash Flows from (Used for) Continuing Financing Activities(1,314.2) 46.0
Net Cash Flows Used for Discontinued Operations—
 (2.5)
Net Increase in Cash and Cash Equivalents133.4
 35.8
Cash and Cash Equivalents at End of Period$343.9
 $212.2

AEP uses short-term debt, including commercial paper, as a bridge to long-term debt financing. The levels of borrowing may vary significantly due to the timing of long-term debt financings and the impact of fluctuations in cash flows.

Nine Months Ended 
September 30,
 20202019
 (in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period$432.6 $444.1 
Net Cash Flows from Operating Activities2,922.2 3,349.9 
Net Cash Flows Used for Investing Activities(4,707.3)(5,357.6)
Net Cash Flows from Financing Activities1,816.3 2,053.4 
Net Increase in Cash, Cash Equivalents and Restricted Cash31.2 45.7 
Cash, Cash Equivalents and Restricted Cash at End of Period$463.8 $489.8 

43





Operating Activities
Nine Months Ended 
September 30,
20202019
(in millions)
Net Income$1,762.0 $1,767.1 
Non-Cash Adjustments to Net Income (a)2,094.3 1,838.8 
Mark-to-Market of Risk Management Contracts46.4 (41.6)
Pension Contributions to Qualified Plan Trust(110.3)— 
Property Taxes396.9 341.7 
Deferred Fuel Over/Under-Recovery, Net27.4 93.7 
Recovery of Ohio Capacity Costs— 34.1 
Refund of Global Settlement— (12.4)
Change in Other Noncurrent Assets(219.6)(9.6)
Change in Other Noncurrent Liabilities(25.1)(16.3)
Change in Certain Components of Working Capital(1,049.8)(645.6)
Net Cash Flows from Operating Activities$2,922.2 $3,349.9 
 Nine Months Ended 
 September 30,
 2017 2016
 (in millions)
Income from Continuing Operations$1,527.1
 $245.3
Depreciation and Amortization1,485.9
 1,550.2
Deferred Income Taxes740.9
 (47.0)
Asset Impairments and Other Related Charges10.6
 2,264.9
Gain on Sale of Merchant Generation Assets(226.4) —
Provision for Refund – Global Settlement, Net(93.3) —
Accrued Taxes, Net(310.1) (393.0)
Other(10.5) (199.4)
Net Cash Flows from Continuing Operating Activities$3,124.2
 $3,421.0


(a)Non-Cash Adjustments to Net Income includes Depreciation and Amortization, Deferred Income Taxes, AFUDC and Amortization of Nuclear Fuel.

Net Cash Flows from Continuing Operating Activities decreased by $428 million primarily due to the following:
•A $404 million decrease in cash from the Change in Certain Components of Working Capital. The decrease is primarily due to timing of accounts receivable, an increase in employee-related payments and a decrease in accrued taxes primarily due to increased property tax payments.
•A $210 million decrease in Changes in Other Noncurrent Assets primarily due to a change in regulatory assets as a result of deferred storm costs related to Hurricane Laura in 2020 and the settlement of deferred restoration costs from the Texas Storm Cost Securitization financing order received in 2019. See Note 4 - Rate Matters for additional information.
•A $110 million decrease in cash due to a discretionary contribution to the qualified pension plan. See Note 7 - Benefit Plans for additional information.
These decreases in cash were $3.1 billionpartially offset by:
•A $250 million increase in 2017 consisting primarily ofcash from Income from Continuing Operations, after non-cash adjustments. See Results of $1.5 billion and $1.5 billionOperations for further detail.
•An $88 million increase in fair value of noncash Depreciation and Amortization. In addition, AEP recorded a gain of $226 million on the sale of certain merchant generation assets. AEP also recorded asset impairments of $11 million. See Note 6 - Impairment, Disposition and Assets and Liabilities Held for Sale for a complete discussion of this sale and these impairments. Deferred and Accrued Taxes changed primarilyrisk management contracts due to pricing movement in the income tax impacts associated with the sale of certain merchant generation assets and the receipt of a tax refund related to the U.K. Windfall Tax. AEP refunded $93 million to customers as part of the Ohio Global Settlement reached in 2016. Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.commodities markets.





44

Net Cash Flows from Continuing Operating Activities were $3.4 billion in 2016 consisting primarily of Income from Continuing Operations of $245 million and $1.6 billion of noncash Depreciation and Amortization. AEP also had asset impairments of $2.3 billion during the third quarter of 2016. See Note 6 - Impairment, Disposition and Assets and Liabilities Held for Sale and Impairments for a complete discussion of asset impairments and other related charges. Accrued Taxes decreased primarily due to the impacts of bonus depreciation related to the Protecting Americans from Tax Hikes Act of 2015. Deferred Income Taxes decreased primarily due to the tax effect of the asset impairment partially offset by an increase in tax versus book temporary differences from operations, which includes provisions related to the Protecting Americans from Tax Hikes Act of 2015. Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.




Investing Activities
Nine Months Ended 
September 30,
 20202019
 (in millions)
Construction Expenditures$(4,690.4)$(4,336.0)
Acquisitions of Nuclear Fuel(68.4)(91.9)
Acquisition of Sempra Renewables LLC and Santa Rita East, Net of Cash and Restricted Cash Acquired— (921.3)
Other51.5 (8.4)
Net Cash Flows Used for Investing Activities$(4,707.3)$(5,357.6)
 Nine Months Ended 
 September 30,
 2017 2016
 (in millions)
Construction Expenditures$(3,778.2) $(3,387.0)
Acquisitions of Nuclear Fuel(73.2) (127.6)
Proceeds from Sale of Merchant Generation Assets2,159.6
 —
Other15.2
 85.9
Net Cash Flows Used for Continuing Investing Activities$(1,676.6) $(3,428.7)


Net Cash Flows Used for Continuing Investing Activities were $1.7 billion in 2017 decreased by $650 million primarily due to Construction Expenditures for environmental, distributionthe following:
•A $921 million decrease due to the 2019 acquisition of Sempra Renewables LLC and transmission investments, partially offset by the proceeds received from the saleSanta Rita East. The $921 million represented a cash payment of certain merchant generation assets.$939 million, net of cash acquired of $18 million. See Note 6 - Impairment, DispositionAcquisition and Assets and Liabilities HeldDispositions for Sale for a complete discussionadditional information.
This decrease in the use of this sale.cash was partially offset by:

Net Cash Flows Used for Continuing Investing Activities were $3.4 billion•A $354 million increase in 2016construction expenditures, primarily due to Construction Expenditures for environmental, distributionincreases at AEP Transmission Holdco of $189 million, Generation & Marketing of $76 million and transmission investments.Transmission and Distribution Utilities of $55 million.


Financing Activities
Nine Months Ended 
September 30,
 20202019
 (in millions)
Issuance of Common Stock$136.5 $44.7 
Issuance/Retirement of Debt, Net2,844.0 3,063.9 
Dividends Paid on Common Stock(1,055.7)(1,002.0)
Other(108.5)(53.2)
Net Cash Flows from Financing Activities$1,816.3 $2,053.4 
 Nine Months Ended 
 September 30,
 2017 2016
 (in millions)
Issuance of Common Stock, Net$—
 $34.2
Issuance/Retirement of Debt, Net(338.2) 930.3
Make Whole Premium on Extinguishment of Long-term Debt(46.1) —
Dividends Paid on Common Stock(875.0) (829.8)
Other(54.9) (88.7)
Net Cash Flows from (Used for) Continuing Financing Activities$(1,314.2) $46.0


Net Cash Flows Used for Continuing Financing Activities in 2017 were $1.3 billion. AEP’s net debt retirements were $338 million. The net retirements include retirements of $978 million of senior unsecured notes, $356 million of pollution control bonds, $258 million of securitization bonds, $835 million of other debt notes and repayments of $654 million of short term debt offset by issuances of $2.3 billion of senior unsecured notes, $242 million of pollution control bonds and $254 million of other debt notes. AEP also paid $46 million for a make whole premium on the early extinguishment of debt related to the sale of certain merchant generation assets. See Note 6 - Impairment, Disposition and Assets and Liabilities Held for Sale for a complete discussion of this sale. AEP paid common stock dividends of $875 million. See Note 12 - Financing Activities for a complete discussion of long-term debt issuances and retirements.



Net Cash Flows from Continuing Financing Activities in 2016 were $46 million. AEP’s net debt issuances were $930 million. The net issuances included an increase decreased by $237 million primarily due to the following:
•A $1 billion decrease in short-term borrowingdebt primarily due to increased repayments of $678 million, issuances of $950 million of senior unsecured notes, $191 million of pollution control bonds and $430 million of other debt notes offset by retirements of $507 million of senior unsecured notes, $289 million of securitization bonds, $251 million of pollution control bonds and $261 million of other debt notes. AEP paid common stock dividends of $830 million.commercial paper. See Note 12 - Financing Activities for a complete discussionadditional information.
This decrease in cash was partially offset by:
•A $493 million increase in issuances of long-term debt issuances and retirements.debt. See Note 12 - Financing Activities for additional information.

In October 2017, I&M retired $1•A $323 million of Notes Payable related to DCC Fuel.

In October 2017, AEP Texas retired $41 million of 5.625% Pollution Control Bonds due in 2017.

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 entersdecrease in the normal courseretirement of business.long-term debt. See Note 12 - Financing Activities for additional information.

See “Long-term Debt Subsequent Events” section of Note 12 for Long-term debt and other securities issued, retired and principal payments made after September 30, 2020 through October 22, 2020, the date that the third quarter 10-Q was issued.

BUDGETED CAPITAL EXPENDITURES

Management currently estimates $5.9 billion of capital expenditures for 2020 and forecasts approximately $34.9 billion of capital expenditures for 2020 to 2024. In the second quarter of 2020, management revised the capital expenditure forecast for 2020 to 2024 to include approximately $2 billion of capital expenditures for North Central Wind Energy Facilities. The following identifies significant off-balance sheet arrangements: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,
45





 September 30,
2017		 December 31,
2016
 (in millions)
Rockport Plant, Unit 2 Future Minimum Lease Payments$812.4
 $886.2
Railcars Maximum Potential Loss from Lease Agreement16.9
 18.4

weather, legal reviews and the ability to access capital.  Management expects to fund these capital expenditures through cash flows from operations and financing activities.  Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged. For complete information 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 20162019 Annual Report.


CONTRACTUAL OBLIGATION INFORMATION


A summary of contractual obligations is included in the 20162019 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.


CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING 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 20162019 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 Pronouncements Adopted During 2017

The FASB issued ASU 2015-11 “Simplifying the Measurement of Inventory” simplifying the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first-out or the retail inventory method. Under the new standard, inventory should be at the lower of costStandards for information related to accounting standards adopted in 2020 and net realizable value. The new accounting guidance isstandards effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management adopted ASU 2015-11 prospectively, effective January 1, 2017. There was no impact on results of operations, financial position or cash flows at adoption.

The FASB issued ASU 2016-09 “Compensation – Stock Compensation” simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities


and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income.  Management adopted ASU 2016-09 effective January 1, 2017. As a result of the adoption of this guidance, management made an accounting policy election to recognize the effect of forfeitures in compensation cost when they occur. There was an immaterial impact on results of operations and financial position and no impact on cash flows at adoption.

Pronouncements Effective in the Futurefuture.


The FASB issued ASU 2014-09 “Revenue from Contracts with Customers” clarifying the method used 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. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. Management continues to analyze the impact of the new revenue standard and related ASUs.

During 2016 and 2017, revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expect a material impact to the timing of revenue recognized or net income and plans to elect the modified retrospective transition approach upon adoption.

The evaluation of revenue streams, new contracts and the new revenue standard’s disclosure requirements continues during the fourth quarter of 2017, in particular with respect to various ongoing industry implementation issues. Management will continue to analyze the related impacts to revenue recognition and monitor any new industry implementation issues that arise. Further, given industry conclusions related to implementation issues, including contributions in aid of construction and collectability, management does not anticipate changes to current accounting systems. Management plans to adopt ASU 2014-09 effective January 1, 2018.

The FASB issued ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” enhancing 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. 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. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. 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 2016-01 effective January 1, 2018.

The FASB issued ASU 2016-02 “Accounting for Leases” 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. The guidance will be applied 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. Management continues to analyze the impact of the new 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.

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, but not results of operations or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019.

The FASB issued ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” 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.

The FASB issued ASU 2016-18 “Restricted Cash” clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows. The new accounting guidance is effective for annual periods beginning after December 15, 2017. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report.

The FASB issued ASU 2017-07 “Compensation - Retirement Benefits” 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 in the income statement 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. For 2016, AEP’s actual non-service cost components were a credit of $66 million, of which approximately 37% was capitalized. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Management plans to adopt ASU 2017-07 effective January 1, 2018.


The FASB issued ASU 2017-12 “Derivatives and Hedging” 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 new 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 net income.

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued, management cannot determine the impact on the reporting of operations and financial position that may result from any such future changes.  Future pronouncements issued by the FASB could have an impact on future net income and financial position.

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.


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


Management employs risk management contracts including physical forward and financial forward purchase-and-sale contracts.  Management engages in risk management of power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business.  As a result, AEP is subject to price risk.  The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors.  AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports
46





regarding compliance with policies, limits and procedures.  The Regulated Risk Committee consists of AEPSC’s Chief Financial Officer, Executive Vice President of Generation, Executive Vice President of Utilities, Senior Vice President of Commercial Operations, Senior Vice President of Treasury and Risk and Chief Risk Officer.  The Competitive Risk Committee consists of AEPSC’s Chief Financial Officer, Senior Vice President of Treasury and Risk and Chief Risk Officer in addition to Energy Supply’s President and Vice President.  When commercial activities exceed predetermined limits, positions are modified to reduce the risk to be within the limits unless specifically approved by the respective committee.



The effects of COVID-19 may adversely impact AEP’s risk management contracts on a forward basis. Markets could experience reduced market liquidity as they face potential uncertainties. Credit risk may increase as counterparties encounter business and supply chain disruptions and overall solvency challenges. Also, interest rates could continue to see increased volatility as capital markets confront uncertainty.


The following table summarizes the reasons for changes in total MTM value as compared to December 31, 2016:2019:
MTM Risk Management Contract Net Assets (Liabilities)
Nine Months Ended September 30, 2020
Vertically
Integrated
Utilities		Transmission
and
Distribution
Utilities		Generation
&
Marketing		Total
 (in millions)
Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2019$75.9 $(103.6)$163.4 $135.7 
Gain from Contracts Realized/Settled During the Period and Entered in a Prior Period(43.8)(5.1)(16.6)(65.5)
Fair Value of New Contracts at Inception When Entered During the Period (a)— — 12.0 12.0 
Changes in Fair Value Due to Market Fluctuations During the Period (b)— — 10.7 10.7 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)26.9 (4.9)— 22.0 
Total MTM Risk Management Contract Net Assets (Liabilities) as of September 30, 2020$59.0 $(113.6)$169.5 114.9 
Commodity Cash Flow Hedge Contracts
 (55.6)
Interest Rate Cash Flow Hedge Contracts
  (4.7)
Collateral Deposits  8.7 
Total MTM Derivative Contract Net Assets as of September 30, 2020  $63.3 
MTM Risk Management Contract Net Assets (Liabilities)
Nine Months Ended September 30, 2017
        
 
Vertically
Integrated
Utilities
 
Transmission
and
Distribution
Utilities
 
Generation
&
Marketing
 Total
 (in millions)
Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2016$5.2
 $(118.2) $164.2
 $51.2
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period(7.0) 3.4
 (32.8) (36.4)
Fair Value of New Contracts at Inception When Entered During the Period (a)—
 —
 26.7
 26.7
Changes in Fair Value Due to Market Fluctuations During the Period (b)—
 —
 10.5
 10.5
Changes in Fair Value Allocated to Regulated Jurisdictions (c)64.9
 (23.2) —
 41.7
Total MTM Risk Management Contract Net Assets (Liabilities) as of September 30, 2017$63.1
 $(138.0) $168.6
 93.7
Commodity Cash Flow Hedge Contracts
   
  
 (75.6)
Interest Rate and Foreign Currency Cash Flow Hedge Contracts
   
  
 4.2
Fair Value Hedge Contracts   
  
 (1.4)
Collateral Deposits   
  
 13.5
Total MTM Derivative Contract Net Assets as of September 30, 2017   
  
 $34.4


(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.



47





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 September 30, 2017,2020, credit exposure net of collateral to sub investment grade counterparties was approximately 7.9%7.2%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss). As of September 30, 2017,2020, 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$401.8 $— $401.8 2 $194.8 
Split Rating0.8 — 0.8 1 0.8 
No External Ratings:    
Internal Investment Grade128.0 — 128.0 3 87.1 
Internal Noninvestment Grade51.9 10.5 41.4 2 28.0 
Total as of September 30, 2020$582.5 $10.5 $572.0 
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 $619.6
 $2.2
 $617.4
 3
 $352.2
Split Rating 5.6
 —
 5.6
 2
 5.6
Noninvestment Grade —
 —
 —
 —
 —
No External Ratings:  
  
 

  
  
Internal Investment Grade 119.2
 —
 119.2
 3
 78.7
Internal Noninvestment Grade 75.4
 11.5
 63.9
 3
 40.5
Total as of September 30, 2017 $819.8
 $13.7
 $806.1
 

 



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

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


Value at Risk (VaR) Associated with Risk Management Contracts


Management uses a risk measurement model, which calculates VaR, to measure AEP’s commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, as of September 30, 2017,2020, 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:



48





VaR Model
Trading Portfolio
Nine Months EndedNine Months Ended Twelve Months EndedNine Months EndedTwelve Months Ended
September 30, 2017 December 31, 2016
September 30, 2020September 30, 2020December 31, 2019
EndEnd High Average Low End High Average LowEndHighAverageLowEndHighAverageLow
(in millions)(in millions) (in millions)(in millions)(in millions)
$0.2
 $0.4
 $0.1
 $0.1
 $0.2
 $1.1
 $0.2
 $0.1
0.1 $0.3 $0.1 $— $0.1 $1.2 $0.2 $0.1 
VaR Model
Non-Trading Portfolio
Nine Months EndedTwelve Months Ended
September 30, 2020December 31, 2019
EndHighAverageLowEndHighAverageLow
(in millions)(in millions)
$1.0 $1.5 $0.8 $0.1 $0.2 $8.5 $1.1 $0.2 
Nine Months Ended Twelve Months Ended
September 30, 2017 December 31, 2016
End High Average Low End High Average Low
(in millions) (in millions)
$0.7
 $6.5
 $0.9
 $0.3
 $5.6
 $8.4
 $1.5
 $0.4



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


Management utilizes an Earnings at Risk (EaR) modelAEP is exposed to measure interest rate market fluctuations in the normal course of business operations. AEP has outstanding short and long-term debt which is subject to a variable rate. AEP manages interest rate risk exposure. EaR statistically quantifiesby limiting variable-rate exposures to a percentage of total debt, by entering into interest rate derivative instruments and by monitoring the extent to whicheffects of market changes in interest rates. For the nine months ended September 30, 2020 and 2019, a 100 basis point change in the benchmark rate on AEP’s variable rate debt would impact pretax interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense. The resulting EaR is interpreted as the dollar amountannually by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence. The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months. As calculated on debt outstanding as of September 30, 2017 and December 31, 2016, the estimated EaR on AEP’s debt portfolio for the following twelve months was $30$18 million and $29$24 million, respectively.

49








AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONSINCOME
For the Three and Nine Months Ended September 30, 20172020 and 20162019
(in millions, except per-share and share amounts)
(Unaudited)
Three Months EndedNine Months Ended
September 30,September 30,
2020201920202019
REVENUES
Vertically Integrated Utilities$2,400.1 $2,598.9 $6,655.4 $7,087.6 
Transmission and Distribution Utilities1,124.1 1,147.3 3,208.7 3,328.7 
Generation & Marketing464.8 501.2 1,223.4 1,323.8 
Other Revenues77.4 67.6 220.4 205.3 
TOTAL REVENUES4,066.4 4,315.0 11,307.9 11,945.4 
EXPENSES    
Fuel and Other Consumables Used for Electric Generation459.3 631.2 1,174.9 1,662.5 
Purchased Electricity for Resale741.1 783.9 2,141.4 2,306.4 
Other Operation702.9 708.3 1,871.0 1,981.7 
Maintenance237.6 267.7 730.5 890.9 
Depreciation and Amortization644.6 645.2 1,996.3 1,873.6 
Taxes Other Than Income Taxes337.7 320.5 976.3 932.7 
TOTAL EXPENSES3,123.2 3,356.8 8,890.4 9,647.8 
OPERATING INCOME943.2 958.2 2,417.5 2,297.6 
Other Income (Expense):    
Other Income5.5 3.2 15.4 18.4 
Allowance for Equity Funds Used During Construction45.2 43.0 111.7 122.3 
Non-Service Cost Components of Net Periodic Benefit Cost29.7 30.0 89.2 90.0 
Interest Expense(291.3)(275.1)(877.4)(781.6)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS732.3 759.3 1,756.4 1,746.7 
Income Tax Expense (Benefit)(1.2)40.6 57.9 30.7 
Equity Earnings of Unconsolidated Subsidiaries14.7 15.2 63.5 51.1 
NET INCOME748.2 733.9 1,762.0 1,767.1 
Net Income (Loss) Attributable to Noncontrolling Interests(0.4)0.4 (2.6)(0.5)
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$748.6 $733.5 $1,764.6 $1,767.6 
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING496,177,968 493,839,034 495,479,190 493,579,430 
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$1.51 $1.49 $3.56 $3.58 
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING497,458,523 495,461,509 496,916,187 495,105,986 
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$1.50 $1.48 $3.55 $3.57 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
50
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2017 2016 2017 2016
REVENUES        
Vertically Integrated Utilities $2,453.8
 $2,538.3
 $6,819.3
 $6,864.6
Transmission and Distribution Utilities 1,149.7
 1,245.4
 3,242.7
 3,398.9
Generation & Marketing 441.5
 823.3
 1,386.8
 2,192.5
Other Revenues 59.7
 45.2
 165.7
 134.0
TOTAL REVENUES 4,104.7
 4,652.2
 11,614.5
 12,590.0
         
EXPENSES  
  
  
  
Fuel and Other Consumables Used for Electric Generation 707.4
 880.1
 1,865.3
 2,236.1
Purchased Electricity for Resale 718.1
 774.0
 2,156.9
 2,134.6
Other Operation 636.1
 771.1
 1,842.5
 2,150.7
Maintenance 268.0
 286.3
 859.4
 854.4
Asset Impairments and Other Related Charges (2.5) 2,264.9
 10.6
 2,264.9
Gain on Sale of Merchant Generation Assets —
 —
 (226.4) —
Depreciation and Amortization 518.5
 539.3
 1,485.9
 1,550.2
Taxes Other Than Income Taxes 272.6
 264.4
 792.0
 767.9
TOTAL EXPENSES 3,118.2
 5,780.1
 8,786.2
 11,958.8
         
OPERATING INCOME (LOSS) 986.5
 (1,127.9) 2,828.3
 631.2
         
Other Income (Expense):  
  
  
  
Interest and Investment Income 2.4
 2.0
 12.7
 6.5
Carrying Costs Income 2.6
 1.7
 14.2
 11.9
Allowance for Equity Funds Used During Construction 20.0
 25.6
 62.2
 86.1
Gain on Sale of Equity Investment 12.4
 —
 12.4
 —
Interest Expense (223.3) (225.3) (668.0) (667.2)
         
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS 800.6
 (1,323.9) 2,261.8
 68.5
         
Income Tax Expense (Credit) 264.0
 (534.5) 797.8
 (134.0)
Equity Earnings of Unconsolidated Subsidiaries 20.1
 25.2
 63.1
 42.8
         
INCOME (LOSS) FROM CONTINUING OPERATIONS 556.7
 (764.2) 1,527.1
 245.3
         
LOSS FROM DISCONTINUED OPERATIONS, NET OF TAX —
 —
 —
 (2.5)
         
NET INCOME (LOSS) 556.7
 (764.2) 1,527.1
 242.8
         
Net Income Attributable to Noncontrolling Interests 12.0
 1.6
 15.2
 5.3
         
EARNINGS (LOSS) ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $544.7
 $(765.8) $1,511.9
 $237.5
         
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING 491,840,722
 491,697,809
 491,781,643
 491,422,921
         
BASIC EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS $1.11
 $(1.56) $3.07
 $0.49
BASIC LOSS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM DISCONTINUED OPERATIONS —
 —
 —
 (0.01)
TOTAL BASIC EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $1.11
 $(1.56) $3.07
 $0.48
         
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING 492,986,307
 491,813,858
 492,428,586
 491,596,861
         
DILUTED EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS $1.10
 $(1.56) $3.07
 $0.49
DILUTED LOSS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM DISCONTINUED OPERATIONS —
 —
 —
 (0.01)
TOTAL DILUTED EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $1.10
 $(1.56) $3.07
 $0.48
         
CASH DIVIDENDS DECLARED PER SHARE $0.59
 $0.56
 $1.77
 $1.68


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.





AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20172020 and 20162019
(in millions)
(Unaudited)
Three Months EndedNine Months Ended
September 30,September 30,
2020201920202019
Net Income$748.2 $733.9 $1,762.0 $1,767.1 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES    
Cash Flow Hedges, Net of Tax of $10.5 and $11.8 for the Three Months Ended September 30, 2020 and 2019, Respectively, and $4.7 and $(16.8) for the Nine Months Ended September 30, 2020 and 2019, Respectively39.3 44.2 17.6 (63.3)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.5) and $(0.4) for the Three Months Ended September 30, 2020 and 2019, Respectively, and $(1.4) and $(1.1) for the Nine Months Ended September 30, 2020 and 2019, Respectively(1.8)(1.4)(5.3)(4.2)
    
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)37.5 42.8 12.3 (67.5)
TOTAL COMPREHENSIVE INCOME785.7 776.7 1,774.3 1,699.6 
Total Other Comprehensive Income (Loss) Attributable To Noncontrolling Interests(0.4)0.4 (2.6)(0.5)
TOTAL OTHER COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS$786.1 $776.3 $1,776.9 $1,700.1 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
51
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2017 2016 2017 2016
Net Income (Loss) $556.7
 $(764.2) $1,527.1
 $242.8
         
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES  
  
  
  
Cash Flow Hedges, Net of Tax of $(8.1) and $(15.4) for the Three Months Ended September 30, 2017 and 2016, Respectively, and $(12.2) and $(11.2) for the Nine Months Ended September 30, 2017 and 2016, Respectively (15.0) (28.6) (22.6) (20.8)
Securities Available for Sale, Net of Tax of $0.5 and $0.3 for the Three Months Ended September 30, 2017 and 2016, Respectively, and $1.5 and $1 for the Nine Months Ended September 30, 2017 and 2016, Respectively 0.9
 0.5
 2.7
 1.7
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0.1 and $0.1 for the Three Months Ended September 30, 2017 and 2016, Respectively, and $0.4 and $0.2 for the Nine Months Ended September 30, 2017 and 2016, Respectively 0.3
 0.2
 0.8
 0.4
         
TOTAL OTHER COMPREHENSIVE LOSS (13.8) (27.9) (19.1) (18.7)
         
TOTAL COMPREHENSIVE INCOME (LOSS) 542.9
 (792.1) 1,508.0
 224.1
         
Total Comprehensive Income Attributable to Noncontrolling Interests 12.0
 1.6
 15.2
 5.3
         
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $530.9
 $(793.7) $1,492.8
 $218.8


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.





AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Nine Months Ended September 30, 20172020 and 20162019
(in millions)
(Unaudited)
AEP Common Shareholders
Common StockAccumulated
Other
Comprehensive
Income (Loss)
SharesAmountPaid-in
Capital		Retained
Earnings		Noncontrolling
Interests		Total
TOTAL EQUITY – DECEMBER 31, 2018513.5 $3,337.4 $6,486.1 $9,325.3 $(120.4)$31.0 $19,059.4 
Issuance of Common Stock0.1 1.2 13.3  14.5 
Common Stock Dividends(332.5)(b)(1.1)(333.6)
Other Changes in Equity(56.6)(a)1.0 (55.6)
Net Income   572.8 1.3 574.1 
Other Comprehensive Loss    (30.3)(30.3)
TOTAL EQUITY – MARCH 31, 2019513.6 3,338.6 6,442.8 9,565.6 (150.7)32.2 19,228.5 
Issuance of Common Stock0.4 2.2 15.6    17.8 
Common Stock Dividends   (332.7)(b) (1.8)(334.5)
Other Changes in Equity  (3.1) 0.6 (2.5)
Acquisition of Sempra Renewables LLC134.8 134.8 
Net Income (Loss)   461.3  (2.2)459.1 
Other Comprehensive Loss    (80.0) (80.0)
TOTAL EQUITY – JUNE 30, 2019514.0 3,340.8 6,455.3 9,694.2 (230.7)163.6 19,423.2 
Issuance of Common Stock0.1 1.1 11.3 12.4 
Common Stock Dividends(332.4)(b)(1.5)(333.9)
Other Changes in Equity0.5 0.5 
Acquisition of Santa Rita East118.8 118.8 
Net Income733.5 0.4 733.9 
Other Comprehensive Income42.8 42.8 
TOTAL EQUITY – SEPTEMBER 30, 2019514.1 $3,341.9 $6,467.1 $10,095.3 $(187.9)$281.3 $19,997.7 
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)(c)(4.6)(363.7)
Other Changes in Equity(29.0)(1.2)(30.2)
ASU 2016-13 Adoption1.8 1.8 
Net Income495.2 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)(c)(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 Income43.6 43.6 
TOTAL EQUITY – JUNE 30, 2020516.2 3,355.4 6,603.0 10,221.9 (172.9)270.8 20,278.2 
Issuance of Common Stock0.4 2.2 23.3    25.5 
Common Stock Dividends  (349.1)(c) (2.0)(351.1)
Other Changes in Equity  (104.0)(d) 0.3 (103.7)
Net Income (Loss)   748.6  (0.4)748.2 
Other Comprehensive Income    37.5  37.5 
TOTAL EQUITY – SEPTEMBER 30, 2020516.6 $3,357.6 $6,522.3 $10,621.4 $(135.4)$268.7 $20,634.6 
 AEP Common Shareholders    
 Common Stock     
Accumulated
Other
Comprehensive
Income (Loss)
    
 Shares Amount 
Paid-in
Capital
 
Retained
Earnings
  
Noncontrolling
Interests
 Total
TOTAL EQUITY - DECEMBER 31, 2015511.4
 $3,324.0
 $6,296.5
 $8,398.3
 $(127.1) $13.2
 $17,904.9
              
Issuance of Common Stock0.6
 4.3
 29.9
  
  
  
 34.2
Common Stock Dividends 
  
  
 (826.4)  
 (3.4) (829.8)
Other Changes in Equity 
  
 3.6
    
 6.0
 9.6
Net Income      237.5
  
 5.3
 242.8
Other Comprehensive Loss 
  
  
  
 (18.7)  
 (18.7)
TOTAL EQUITY - SEPTEMBER 30, 2016512.0
 $3,328.3
 $6,330.0
 $7,809.4
 $(145.8) $21.1
 $17,343.0
              
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 
  
  
 (872.3)  
 (2.7) (875.0)
Other Changes in Equity 
  
 51.6
    
 0.8
 52.4
Net Income      1,511.9
  
 15.2
 1,527.1
Other Comprehensive Loss 
  
  
  
 (19.1)  
 (19.1)
TOTAL EQUITY - SEPTEMBER 30, 2017512.0
 $3,328.3
 $6,384.2
 $8,532.0
 $(175.4) $36.4
 $18,105.5

(a)Includes $(62) million related to a forward equity purchase contract associated with the issuance of Equity Units.
(b)Cash dividends declared per AEP common share were $0.67.
(c)Cash dividends declared per AEP common share were $0.70.
(d)Includes $(121) million related to a forward equity purchase contract associated with the issuance of Equity Units.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118134.

52






AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20172020 and December 31, 20162019
(in millions)
(Unaudited)
 September 30,December 31,
 20202019
CURRENT ASSETS  
Cash and Cash Equivalents$409.7 $246.8 
Restricted Cash
(September 30, 2020 and December 31, 2019 Amounts Include $54.1 and $185.8, Respectively, Related to Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Santa Rita East)
54.1 185.8 
Other Temporary Investments
(September 30, 2020 and December 31, 2019 Amounts Include $198 and $187.8, Respectively, Related to EIS and Transource Energy)
209.0 202.7 
Accounts Receivable:  
Customers600.5 625.3 
Accrued Unbilled Revenues212.4 222.4 
Pledged Accounts Receivable – AEP Credit1,055.1 873.9 
Miscellaneous46.1 27.2 
Allowance for Uncollectible Accounts(63.4)(43.7)
Total Accounts Receivable1,850.7 1,705.1 
Fuel586.1 528.5 
Materials and Supplies681.2 640.7 
Risk Management Assets115.2 172.8 
Regulatory Asset for Under-Recovered Fuel Costs61.4 92.9 
Margin Deposits54.1 60.4 
Prepayments and Other Current Assets316.7 242.1 
TOTAL CURRENT ASSETS4,338.2 4,077.8 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation23,036.9 22,762.4 
Transmission26,539.1 24,808.6 
Distribution23,459.8 22,443.4 
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)5,204.7 4,811.5 
Construction Work in Progress4,662.5 4,319.8 
Total Property, Plant and Equipment82,903.0 79,145.7 
Accumulated Depreciation and Amortization20,116.6 19,007.6 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET62,786.4 60,138.1 
OTHER NONCURRENT ASSETS  
Regulatory Assets3,518.8 3,158.8 
Securitized Assets684.0 858.1 
Spent Nuclear Fuel and Decommissioning Trusts3,075.9 2,975.7 
Goodwill52.5 52.5 
Long-term Risk Management Assets242.9 266.6 
Operating Lease Assets881.0 957.4 
Deferred Charges and Other Noncurrent Assets3,109.6 3,407.3 
TOTAL OTHER NONCURRENT ASSETS11,564.7 11,676.4 
TOTAL ASSETS$78,689.3 $75,892.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
53
  September 30, December 31,
  2017 2016
CURRENT ASSETS  
  
Cash and Cash Equivalents $343.9
 $210.5
Other Temporary Investments
(September 30, 2017 and December 31, 2016 Amounts Include $300.5 and $322.5, Respectively, Related to Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, EIS, Transource Energy and Sabine)
 310.7
 331.7
Accounts Receivable:  
  
Customers 522.7
 705.1
Accrued Unbilled Revenues 187.3
 158.7
Pledged Accounts Receivable – AEP Credit 967.6
 972.7
Miscellaneous 99.9
 118.1
Allowance for Uncollectible Accounts (36.6) (37.9)
Total Accounts Receivable 1,740.9
 1,916.7
Fuel 354.2
 423.8
Materials and Supplies 562.3
 543.5
Risk Management Assets 146.1
 94.5
Regulatory Asset for Under-Recovered Fuel Costs 153.5
 156.6
Margin Deposits 105.7
 79.9
Assets Held for Sale —
 1,951.2
Prepayments and Other Current Assets 350.5
 325.5
TOTAL CURRENT ASSETS 4,067.8
 6,033.9
     
PROPERTY, PLANT AND EQUIPMENT  
  
Electric:  
  
Generation 20,739.3
 19,848.9
Transmission 17,785.4
 16,658.7
Distribution 19,589.4
 18,900.8
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) 3,614.1
 3,444.3
Construction Work in Progress 3,710.0
 3,183.9
Total Property, Plant and Equipment 65,438.2
 62,036.6
Accumulated Depreciation and Amortization 17,121.7
 16,397.3
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 48,316.5
 45,639.3
     
OTHER NONCURRENT ASSETS  
  
Regulatory Assets 5,640.0
 5,625.5
Securitized Assets 1,287.8
 1,486.1
Spent Nuclear Fuel and Decommissioning Trusts 2,433.0
 2,256.2
Goodwill 52.5
 52.5
Long-term Risk Management Assets 310.4
 289.1
Deferred Charges and Other Noncurrent Assets 1,856.9
 2,085.1
TOTAL OTHER NONCURRENT ASSETS 11,580.6
 11,794.5
     
TOTAL ASSETS $63,964.9
 $63,467.7


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.





AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 20172020 and December 31, 20162019
(dollars in millions)millions, except per-share and share amounts)
(Unaudited)
       September 30, December 31,
       2017 2016
CURRENT LIABILITIES    
Accounts Payable      $1,537.0
 $1,688.5
Short-term Debt:         
Securitized Debt for Receivables – AEP Credit      750.0
 673.0
Other Short-term Debt      309.3
 1,040.0
Total Short-term Debt      1,059.3
 1,713.0
Long-term Debt Due Within One Year
(September 30, 2017 and December 31, 2016 Amounts Include $393.7 and $427.5, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and Sabine)
  2,359.3
 2,878.0
Risk Management Liabilities      69.4
 53.4
Customer Deposits      346.6
 343.2
Accrued Taxes      716.5
 1,048.0
Accrued Interest      260.3
 227.2
Regulatory Liability for Over-Recovered Fuel Costs    19.7
 8.0
Liabilities Held for Sale      —
 235.9
Other Current Liabilities      953.9
 1,302.8
TOTAL CURRENT LIABILITIES      7,322.0
 9,498.0
        
NONCURRENT LIABILITIES    
Long-term Debt
(September 30, 2017 and December 31, 2016 Amounts Include $1421.5 and $1,737.5, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, Transource Energy, and Sabine)
  18,362.4
 17,378.4
Long-term Risk Management Liabilities      352.7
 316.2
Deferred Income Taxes      12,628.2
 11,884.4
Regulatory Liabilities and Deferred Investment Tax Credits  3,959.6
 3,751.3
Asset Retirement Obligations      1,919.3
 1,830.6
Employee Benefits and Pension Obligations      468.9
 614.1
Deferred Credits and Other Noncurrent Liabilities  837.0
 774.6
TOTAL NONCURRENT LIABILITIES      38,528.1
 36,549.6
          
TOTAL LIABILITIES      45,850.1
 46,047.6
          
Rate Matters (Note 4)      
 
Commitments and Contingencies (Note 5)      
 
          
MEZZANINE EQUITY    
Contingently Redeemable Performance Share Awards      9.3
 —
          
EQUITY    
Common Stock – Par Value – $6.50 Per Share:         
  2017 2016     
Shares Authorized 600,000,000 600,000,000     
Shares Issued 512,048,663 512,048,520     
(20,206,368 and 20,336,592 Shares were Held in Treasury as of September 30, 2017 and December 31, 2016, Respectively)  3,328.3
 3,328.3
Paid-in Capital      6,384.2
 6,332.6
Retained Earnings      8,532.0
 7,892.4
Accumulated Other Comprehensive Income (Loss)  (175.4) (156.3)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY  18,069.1
 17,397.0
          
Noncontrolling Interests      36.4
 23.1
          
TOTAL EQUITY      18,105.5
 17,420.1
          
TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY $63,964.9
 $63,467.7
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.
   September 30,December 31,
 20202019
CURRENT LIABILITIES  
Accounts Payable$1,659.6 $2,085.8 
Short-term Debt:  
Securitized Debt for Receivables – AEP Credit703.0 710.0 
Other Short-term Debt1,694.0 2,128.3 
Total Short-term Debt2,397.0 2,838.3 
Long-term Debt Due Within One Year
(September 30, 2020 and December 31, 2019 Amounts Include $176.6 and $565.1, Respectively, Related to Transition Funding, DCC Fuel, Appalachian Consumer Rate Relief Funding, Transource Energy, Sabine and Restoration Funding)
1,911.6 1,598.7 
Risk Management Liabilities62.4 114.3 
Customer Deposits339.7 366.1 
Accrued Taxes942.7 1,357.8 
Accrued Interest331.0 243.6 
Obligations Under Operating Leases236.5 234.1 
Regulatory Liability for Over-Recovered Fuel Costs82.5 86.6 
Other Current Liabilities1,084.2 1,373.8 
TOTAL CURRENT LIABILITIES9,047.2 10,299.1 
NONCURRENT LIABILITIES  
Long-term Debt
(September 30, 2020 and December 31, 2019 Amounts Include $958.7 and $907, Respectively, Related to Transition Funding, DCC Fuel, Appalachian Consumer Rate Relief Funding, Transource Energy, Sabine and Restoration Funding)
28,155.5 25,126.8 
Long-term Risk Management Liabilities232.4 261.8 
Deferred Income Taxes8,011.4 7,588.2 
Regulatory Liabilities and Deferred Investment Tax Credits8,249.2 8,457.6 
Asset Retirement Obligations2,448.3 2,216.6 
Employee Benefits and Pension Obligations353.1 466.0 
Obligations Under Operating Leases690.5 734.6 
Deferred Credits and Other Noncurrent Liabilities794.6 719.8 
TOTAL NONCURRENT LIABILITIES48,935.0 45,571.4 
TOTAL LIABILITIES57,982.2 55,870.5 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
MEZZANINE EQUITY
Redeemable Noncontrolling Interest0 65.7 
Contingently Redeemable Performance Share Awards72.5 42.9 
TOTAL MEZZANINE EQUITY72.5 108.6 
EQUITY  
Common Stock – Par Value – $6.50 Per Share:  
20202019  
Shares Authorized600,000,000600,000,000  
Shares Issued516,551,408514,373,631  
(20,204,160 Shares were Held in Treasury as of September 30, 2020 and December 31, 2019, Respectively)3,357.6 3,343.4 
Paid-in Capital6,522.3 6,535.6 
Retained Earnings10,621.4 9,900.9 
Accumulated Other Comprehensive Income (Loss)(135.4)(147.7)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY20,365.9 19,632.2 
Noncontrolling Interests268.7 281.0 
TOTAL EQUITY20,634.6 19,913.2 
TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY$78,689.3 $75,892.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
54







AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20172020 and 20162019
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20202019
OPERATING ACTIVITIES  
Net Income$1,762.0 $1,767.1 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and Amortization1,996.3 1,873.6 
Deferred Income Taxes142.5 15.9 
Allowance for Equity Funds Used During Construction(111.7)(122.3)
Mark-to-Market of Risk Management Contracts46.4 (41.6)
Amortization of Nuclear Fuel67.2 71.6 
Pension Contributions to Qualified Plan Trust(110.3)0 
Property Taxes396.9 341.7 
Deferred Fuel Over/Under-Recovery, Net27.4 93.7 
Recovery of Ohio Capacity Costs0 34.1 
Refund of Global Settlement0 (12.4)
Change in Other Noncurrent Assets(219.6)(9.6)
Change in Other Noncurrent Liabilities(25.1)(16.3)
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net(138.9)125.0 
Fuel, Materials and Supplies(97.4)(116.6)
Accounts Payable21.9 (32.4)
Accrued Taxes, Net(502.9)(359.9)
Other Current Assets26.0 60.2 
Other Current Liabilities(358.5)(321.9)
Net Cash Flows from Operating Activities2,922.2 3,349.9 
INVESTING ACTIVITIES  
Construction Expenditures(4,690.4)(4,336.0)
Purchases of Investment Securities(1,329.5)(951.5)
Sales of Investment Securities1,293.0 874.2 
Acquisitions of Nuclear Fuel(68.4)(91.9)
Acquisition of Sempra Renewables LLC and Santa Rita East, Net of Cash and Restricted Cash Acquired0 (921.3)
Other Investing Activities88.0 68.9 
Net Cash Flows Used for Investing Activities(4,707.3)(5,357.6)
FINANCING ACTIVITIES  
Issuance of Common Stock136.5 44.7 
Issuance of Long-term Debt3,985.8 3,492.4 
Issuance of Short-term Debt with Original Maturities greater than 90 Days1,304.5 0 
Change in Short-term Debt with Original Maturities less than 90 Days, Net(1,445.8)600.0 
Retirement of Long-term Debt(700.5)(1,023.5)
Make Whole Premium on Extinguishment of Long-term Debt0 (5.0)
Redemption of Short-term Debt with Original Maturities Greater than 90 Days(300.0)0 
Principal Payments for Finance Lease Obligations(46.3)(44.5)
Dividends Paid on Common Stock(1,055.7)(1,002.0)
Redemption of Noncontrolling Interest in Trent and Desert Sky Windfarms(56.5)0 
Other Financing Activities(5.7)(8.7)
Net Cash Flows from Financing Activities1,816.3 2,053.4 
Net Increase in Cash, Cash Equivalents and Restricted Cash31.2 45.7 
Cash, Cash Equivalents and Restricted Cash at Beginning of Period432.6 444.1 
Cash, Cash Equivalents and Restricted Cash at End of Period$463.8 $489.8 
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts$690.5 $689.7 
Net Cash Paid (Received) for Income Taxes(23.9)22.8 
Noncash Acquisitions Under Finance Leases33.0 66.7 
Construction Expenditures Included in Current Liabilities as of September 30,830.1 1,018.9 
Construction Expenditures Included in Noncurrent Liabilities as of September 30,8.3 0 
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,1.0 0 
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage2.4 0 
Noncontrolling Interest assumed with Sempra Renewable LLC and Santa Rita East Acquisition0 253.4 
Liabilities assumed with Sempra Renewable LLC and Santa Rita East Acquisition0 32.4 
Forward Equity Purchase Contract Included in Current and Noncurrent Liabilities as of September 30,120.6 52.4 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
55
  Nine Months Ended September 30,
  2017 2016
OPERATING ACTIVITIES  
  
Net Income $1,527.1
 $242.8
Loss from Discontinued Operations, Net of Tax —
 (2.5)
Income from Continuing Operations 1,527.1
 245.3
Adjustments to Reconcile Income from Continuing Operations to Net Cash Flows from Continuing Operating Activities:    
Depreciation and Amortization 1,485.9
 1,550.2
Deferred Income Taxes 740.9
 (47.0)
Asset Impairments and Other Related Charges 10.6
 2,264.9
Allowance for Equity Funds Used During Construction (62.2) (86.1)
Mark-to-Market of Risk Management Contracts (56.2) 56.6
Amortization of Nuclear Fuel 104.8
 109.7
Pension Contributions to Qualified Plan Trust (93.3) (84.8)
Property Taxes 291.4
 288.3
Deferred Fuel Over/Under-Recovery, Net 81.0
 (28.5)
Gain on Sale of Merchant Generation Assets (226.4) —
Gain on Sale of Equity Investment (12.4) —
Recovery of Ohio Capacity Costs 65.6
 108.8
Provision for Refund – Global Settlement, Net

 (93.3) —
Change in Other Noncurrent Assets (345.2) (243.4)
Change in Other Noncurrent Liabilities 205.7
 41.3
Changes in Certain Components of Continuing Working Capital:    
Accounts Receivable, Net 201.3
 (240.8)
Fuel, Materials and Supplies 58.5
 11.6
Accounts Payable (91.0) 47.8
Accrued Taxes, Net (310.1) (393.0)
Other Current Assets (98.2) 31.5
Other Current Liabilities (260.3) (211.4)
Net Cash Flows from Continuing Operating Activities 3,124.2
 3,421.0
     
INVESTING ACTIVITIES    
Construction Expenditures (3,778.2) (3,387.0)
Change in Other Temporary Investments, Net 34.5
 109.2
Purchases of Investment Securities (1,855.8) (2,454.5)
Sales of Investment Securities 1,808.6
 2,427.0
Acquisitions of Nuclear Fuel (73.2) (127.6)
Proceeds from Sale of Merchant Generation Assets 2,159.6
 —
Other Investing Activities 27.9
 4.2
Net Cash Flows Used for Continuing Investing Activities (1,676.6) (3,428.7)
     
FINANCING ACTIVITIES    
Issuance of Common Stock —
 34.2
Issuance of Long-term Debt 2,742.7
 1,559.6
Change in Short-term Debt, Net (653.7) 678.3
Retirement of Long-term Debt (2,427.2) (1,307.6)
Make Whole Premium on Extinguishment of Long-term Debt (46.1) —
Principal Payments for Capital Lease Obligations (50.5) (81.9)
Dividends Paid on Common Stock (875.0) (829.8)
Other Financing Activities (4.4) (6.8)
Net Cash Flows from (Used for) Continuing Financing Activities (1,314.2) 46.0
     
Net Cash Flows Used for Discontinued Operating Activities —
 (2.5)
Net Cash Flows from Discontinued Investing Activities —
 —
Net Cash Flows from Discontinued Financing Activities —
 —
     
Net Increase in Cash and Cash Equivalents 133.4
 35.8
Cash and Cash Equivalents at Beginning of Period 210.5
 176.4
Cash and Cash Equivalents at End of Period $343.9
 $212.2





AEP TEXAS INC.
AND SUBSIDIARIES

56





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

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 Three Months EndedNine Months Ended
September 30,September 30,
 2020201920202019
 (in millions of KWhs)
Retail:  
Residential4,112 4,148 9,736 9,580 
Commercial2,941 3,152 7,700 7,997 
Industrial2,037 2,168 6,618 6,556 
Miscellaneous184 197 486 512 
Total Retail9,274 9,665 24,540 24,645 

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

Summary of Heating and Cooling Degree Days
 Three Months EndedNine Months Ended
September 30,September 30,
 2020201920202019
 (in degree days)
Actual – Heating (a)1 — 98 180 
Normal – Heating (b)— — 188 190 
Actual – Cooling (c)1,357 1,587 2,524 2,679 
Normal – Cooling (b)1,378 1,368 2,436 2,425 

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




57





Third Quarter of 2020 Compared to Third Quarter of 2019
See Condensed NotesReconciliation of Third Quarter of 2019 to Condensed Financial StatementsThird Quarter of Registrants beginning on page 118.
2020
Net Income
(in millions)
Third Quarter of 2019$77.0 
Changes in Gross Margin:
Retail Margins(1.4)
Margins from Off-system Sales(0.4)
Transmission Revenues4.3 
Other Revenues(59.0)
Total Change in Gross Margin(56.5)
Changes in Expenses and Other:
Other Operation and Maintenance(4.8)
Depreciation and Amortization62.5 
Taxes Other Than Income Taxes1.1 
Interest Income0.1 
Allowance for Equity Funds Used During Construction(0.7)
Interest Expense(8.7)
Total Change in Expenses and Other49.5 
Income Tax Expense12.6 
Third Quarter of 2020$82.6 



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 decreased $1 million primarily due to the following:
•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.
•An $11 million decrease in weather-related usage primarily due to a 14% decrease in cooling degree days.
•A $3 million decrease due to refunds to customers associated with the most recent base rate case. This decrease was offset in Other Revenues below.
These decreases were partially offset by:
•A $19 million increase in weather-normalized margins primarily in the residential class.
•A $6 million increase from interim rate increases driven by increased distribution investment.
•A $5 million increase due to new base rates implemented in June 2020.
•Transmission Revenues increased $4 million primarily due to:
•An $11 million increase from interim rate increases driven by increased transmission investment.
This increase was partially offset by:
•A $7 million decrease due to refunds to customers associated with the most recent base rate case. This decrease was offset in Other Revenues below.
•Other Revenues decreased $59 million primarily due to the following:
•A $68 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:
•An $8 million increase in revenues due to the amortization of a provision for refund recorded in December 2019 as part of the most recent base rate case. This increase was partially offset in Retail Margins and Transmission Revenues above.
58






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

•Other Operation and Maintenance expenses increased $5 million primarily due to the following:
•A $5 million increase due to the write-off of land associated with the Oklaunion Power Station.
•A $4 million increase in transmission expenses. This increase was partially offset in Gross Margin above.
These increases were partially offset by:
•A $3 million decrease in distribution expenses.
•Depreciation and Amortization expenses decreased $63 million primarily due to a decrease in securitization amortizations due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset in Other Revenues above and in Interest Expense below.
•Interest Expense increased $9 million primarily due to the following:
•A $5 million increase due to higher long-term debt balances.
•A $3 million increase due to the prior year deferral of previously recorded interest expense approved for recovery as a result of the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019.
•Income Tax Expense decreased $13 million primarily due to an increase in amortization of Excess ADIT and the recognition of a discrete tax adjustment in 2020 which was primarily attributable to the 5-year net operating loss carryback provision of the CARES Act. This decrease was partially offset above in Gross Margins and in Other Operation and Maintenance expenses.
59





Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019
Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020
Net Income
(in millions)
Nine Months Ended September 30, 2019$192.0 
Changes in Gross Margin:
Retail Margins2.7 
Margins from Off-system Sales(20.2)
Transmission Revenues8.9 
Other Revenues(36.8)
Total Change in Gross Margin(45.4)
Changes in Expenses and Other:
Other Operation and Maintenance77.3 
Depreciation and Amortization29.0 
Taxes Other Than Income Taxes3.6 
Interest Income(0.3)
Allowance for Equity Funds Used During Construction6.1 
Interest Expense(36.5)
Total Change in Expenses and Other79.2 
Income Tax Expense(28.7)
Nine Months Ended September 30, 2020$197.1 
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 $3 million primarily due to the following:
•A $21 million increase in weather-normalized margins primarily driven by the residential class and partially offset by a decrease in the industrial class.
•A $7 million increase from interim rate increases driven by increased transmission investment.
•A $7 million increase from interim rate increases driven by increased distribution investment.
•A $7 million increase due to new base rates implemented in June 2020.
•A $5 million increase due to the change in the recording of merger savings as authorized by the PUCT in the most recent base rate case.
These increases were partially offset by:
•A $25 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 $15 million decrease in weather-related usage primarily due to a 6% decrease in cooling degree days and a 46% decrease in heating degree days.
•A $4 million decrease due to refunds to customers associated with the most recent base rate case. This decrease was offset in Other Revenues below.
•Margins from Off-system Sales decreased $20 million primarily due to lower Oklaunion Power Station PPA revenues. This decrease was partially offset in Other Operation and Maintenance expenses below.
•Transmission Revenues increased $9 million primarily due to the following:
•A $30 million increase from interim rate increases driven by increased transmission investment.
This increase was partially offset by:
•A $14 million decrease due to a one-time credit to transmission customers as a result of Tax Reform and the most recent base rate case. This decrease was offset in Income Tax Expense below.
•A $7 million decrease due to refunds to customers associated with the most recent base rate case. This decrease was offset in Other Revenues below.
60





•Other Revenues decreased $37 million primarily due to the following:
•A $49 million decrease related to 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:
•An $11 million increase in revenues due to the amortization of a provision for refund recorded in December 2019 as part of the most recent base rate case. This increase was 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 decreased $77 million primarily due to the following:
•A $67 million decrease due to prior year partial amortization of the AEP Texas Storm Restoration Securitization regulatory asset as a result of the AEP Texas Storm Cost Securitization financing order issued by the PUCT in June 2019. This decrease was offset in Income Tax Expense below.
•A $17 million decrease due to the revision of the Oklaunion Power Station ARO. This decrease was offset in Margins from Off-System Sales above.
These decreases were partially offset by:
•A $9 million increase in transmission expenses. This increase was partially offset in Gross Margin above.
•A $5 million increase due to the write-off of land associated with the Oklaunion Power Station.
•Depreciation and Amortization expenses decreased $29 million primarily due to the following:
•A $43 million decrease in securitization amortizations due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This increase was offset in Other Revenues above and in Interest Expense below.
This decrease was partially offset by:
•A $14 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
•Taxes Other Than Income Taxes decreased $4 million primarily due to lower property taxes.
•Allowance for Equity Funds Used During Construction increased $6 million primarily due to an increase in the equity component of AFUDC as a result of lower short-term balances and increased transmission projects.
•Interest Expense increased $37 million primarily due to:
•A $24 million increase due to the prior year deferral of previously recorded interest expense approved for recovery as a result of the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019.
•A $9 million increase due to higher long-term debt balances.
•A $6 million increase due to due to a decrease in the debt component of AFUDC.
These increases were partially offset by:
•A $5 million decrease due to lower short-term debt balances.
•Income Tax Expense increased $29 million primarily due to the prior year amortization of Excess ADIT not subject to normalization requirements as approved in the Texas Storm Cost Securitization financing order issued by the PUCT in 2019 partially offset by current year amortization of Excess ADIT and an increase in favorable AFUDC Equity tax benefit. This increase was partially offset in Gross Margins and Other Operation and Maintenance Expenses above.
61






AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)
  Three Months EndedNine Months Ended
September 30,September 30,
  2020 201920202019
REVENUES    
Electric Transmission and Distribution $390.1 $445.4 $1,165.2 $1,190.3 
Sales to AEP Affiliates 41.4 42.7 89.4 125.1 
Other Revenues 0.5 1.2 2.5 2.6 
TOTAL REVENUES 432.0 489.3 1,257.1 1,318.0 
 
EXPENSES     
Fuel and Other Consumables Used for Electric Generation10.4 11.2 13.6 29.1 
Other Operation 134.3 128.2 344.7 349.2 
Maintenance 20.4 21.7 64.1 136.9 
Depreciation and Amortization 107.7 170.2 435.8 464.8 
Taxes Other Than Income Taxes 38.7 39.8 106.7 110.3 
TOTAL EXPENSES 311.5 371.1 964.9 1,090.3 
 
OPERATING INCOME 120.5 118.2 292.2 227.7 
 
Other Income (Expense):     
Interest Income 0.5 0.4 1.2 1.5 
Allowance for Equity Funds Used During Construction4.4 5.1 14.4 8.3 
Non-Service Cost Components of Net Periodic Benefit Cost2.8 2.8 8.4 8.4 
Interest Expense (44.5)(35.8)(129.2)(92.7)
 
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 83.7 90.7 187.0 153.2 
 
Income Tax Expense (Benefit) 1.1 13.7 (10.1)(38.8)
NET INCOME $82.6 $77.0 $197.1 $192.0 
The common stock of AEP Texas is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
62





AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
September 30,September 30,
2020201920202019
Net Income$82.6 $77.0 $197.1 $192.0 
 
OTHER COMPREHENSIVE INCOME, NET OF TAXES  
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended September 30, 2020 and 2019, Respectively, and $0.2 and $0.2 for the Nine Months Ended September 30, 2020 and 2019, Respectively0.3 0.3 0.8 0.8 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2020 and 2019, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2020 and 2019, Respectively0 0 0.1 0.1 
TOTAL OTHER COMPREHENSIVE INCOME0.3 0.3 0.9 0.9 
TOTAL COMPREHENSIVE INCOME$82.9 $77.3 $198.0 $192.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.

63





AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)
 Paid-in
Capital		Retained
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018$1,257.9 $1,337.7 $(15.1)$2,580.5 
Capital Contribution from Parent200.0 200.0 
Net Income34.4 34.4 
Other Comprehensive Income0.3 0.3 
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 20191,457.9 1,372.1 (14.8)2,815.2 
Net Income 80.6  80.6 
Other Comprehensive Income  0.3 0.3 
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 20191,457.9 1,452.7 (14.5)2,896.1 
Net Income77.0 77.0 
Other Comprehensive Income0.3 0.3 
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2019$1,457.9 $1,529.7 $(14.2)$2,973.4 
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, 20201,457.9 1,630.5 (12.2)3,076.2 
Net Income82.6 82.6 
Other Comprehensive Income0.3 0.3 
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2020$1,457.9 $1,713.1 $(11.9)$3,159.1 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.

64





AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2020 and December 31, 2019
(in millions)
(Unaudited)
  September 30,December 31,
  2020 2019
CURRENT ASSETS    
Cash and Cash Equivalents$0.1 $3.1 
Restricted Cash
(September 30, 2020 and December 31, 2019 Amounts Include $44.8 and $154.7, Respectively, Related to Transition Funding and Restoration Funding)		44.8 154.7 
Advances to Affiliates148.4 207.2 
Accounts Receivable:   
Customers 136.8 116.0 
Affiliated Companies 22.0 10.1 
Accrued Unbilled Revenues74.8 68.8 
Miscellaneous 0 0.3 
Allowance for Uncollectible Accounts0 (1.8)
Total Accounts Receivable 233.6 193.4 
Fuel 0 5.9 
Materials and Supplies 72.0 56.7 
Accrued Tax Benefits9.6 66.1 
Prepayments and Other Current Assets 5.6 5.8 
TOTAL CURRENT ASSETS 514.1 692.9 
 
PROPERTY, PLANT AND EQUIPMENT   
Electric:   
Generation0 351.7 
Transmission 4,943.8 4,466.5 
Distribution 4,486.6 4,215.2 
Other Property, Plant and Equipment 868.2 805.9 
Construction Work in Progress 787.9 763.9 
Total Property, Plant and Equipment 11,086.5 10,603.2 
Accumulated Depreciation and Amortization 1,541.5 1,758.1 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 9,545.0 8,845.1 
 
OTHER NONCURRENT ASSETS   
Regulatory Assets 275.4 280.6 
Securitized Assets
(September 30, 2020 and December 31, 2019 Amounts Include $467.8 and $621.2, Respectively, Related to Transition Funding and Restoration Funding)
467.8 623.4 
Deferred Charges and Other Noncurrent Assets 182.7 147.1 
TOTAL OTHER NONCURRENT ASSETS 925.9 1,051.1 
 
TOTAL ASSETS $10,985.0 $10,589.1 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
65





AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2020 and December 31, 2019
(in millions)
(Unaudited)
  September 30,December 31,
  2020 2019
CURRENT LIABILITIES 
Accounts Payable: 
General $235.3 $256.8 
Affiliated Companies 27.2 35.6 
Short-term Debt – Nonaffiliated2.0 0 
Long-term Debt Due Within One Year – Nonaffiliated
(September 30, 2020 and December 31, 2019 Amounts Include $87.7 and $281.4, Respectively, Related to Transition Funding and Restoration Funding)
87.8 392.1 
Risk Management Liabilities0.1 0 
Accrued Taxes 101.8 84.9 
Accrued Interest
(September 30, 2020 and December 31, 2019 Amounts Include $3.5 and $7.5, Respectively, Related to Transition Funding and Restoration Funding)
54.7 35.7 
Oklaunion Purchase Power Agreement0 22.1 
Obligations Under Operating Leases13.7 12.0 
Provision for Refund31.6 64.7 
Other Current Liabilities 92.2 123.3 
TOTAL CURRENT LIABILITIES 646.4 1,027.2 
 
NONCURRENT LIABILITIES   
Long-term Debt – Nonaffiliated
(September 30, 2020 and December 31, 2019 Amounts Include $440.2 and $495.4, Respectively, Related to Transition Funding and Restoration Funding)
4,766.9 4,166.3 
Deferred Income Taxes 1,004.4 965.4 
Regulatory Liabilities and Deferred Investment Tax Credits 1,282.6 1,316.9 
Obligations Under Operating Leases71.0 71.1 
Deferred Credits and Other Noncurrent Liabilities 54.6 81.1 
TOTAL NONCURRENT LIABILITIES 7,179.5 6,600.8 
 
TOTAL LIABILITIES 7,825.9 7,628.0 
 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5) 
 
COMMON SHAREHOLDER’S EQUITY   
Paid-in Capital 1,457.9 1,457.9 
Retained Earnings 1,713.1 1,516.0 
Accumulated Other Comprehensive Income (Loss)(11.9)(12.8)
TOTAL COMMON SHAREHOLDER’S EQUITY 3,159.1 2,961.1 
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $10,985.0 $10,589.1 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
66





AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)
  Nine Months Ended September 30,
  2020 2019
OPERATING ACTIVITIES    
Net Income $197.1 $192.0 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:   
Depreciation and Amortization 435.8 464.8 
Deferred Income Taxes (11.5)(0.6)
Allowance for Equity Funds Used During Construction(14.4)(8.3)
Mark-to-Market of Risk Management Contracts 0.1 0.2 
Pension Contributions to Qualified Plan Trust(11.3)0 
Change in Other Noncurrent Assets (77.3)0.5 
Change in Other Noncurrent Liabilities (30.0)6.5 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net (40.2)(50.0)
Fuel, Materials and Supplies (9.4)(0.1)
Accounts Payable 24.2 17.8 
Accrued Taxes, Net73.4 (33.4)
Other Current Assets (0.8)(0.7)
Other Current Liabilities (49.8)(12.9)
Net Cash Flows from Operating Activities 485.9 575.8 
 
INVESTING ACTIVITIES   
Construction Expenditures (976.1)(954.5)
Change in Advances to Affiliates, Net58.8 0.3 
Other Investing Activities24.1 18.4 
Net Cash Flows Used for Investing Activities (893.2)(935.8)
 
FINANCING ACTIVITIES   
Capital Contribution from Parent0 200.0 
Issuance of Long-term Debt – Nonaffiliated652.8 627.5 
Change in Short-term Debt, Net – Nonaffiliated2.0 0 
Change in Advances from Affiliates, Net 0 (141.2)
Retirement of Long-term Debt – Nonaffiliated (356.5)(366.8)
Principal Payments for Finance Lease Obligations (4.7)(3.8)
Other Financing Activities0.8 (1.1)
Net Cash Flows from Financing Activities 294.4 314.6 
Net Decrease in Cash, Cash Equivalents and Restricted Cash (112.9)(45.4)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period 157.8 159.8 
Cash, Cash Equivalents and Restricted Cash at End of Period $44.9 $114.4 
 
SUPPLEMENTARY INFORMATION   
Cash Paid for Interest, Net of Capitalized Amounts $102.0 $95.1 
Net Cash Paid (Received) for Income Taxes (55.6)28.7 
Noncash Acquisitions Under Finance Leases 5.1 6.9 
Construction Expenditures Included in Current Liabilities as of September 30, 167.6 183.6 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
67







AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

68






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


RESULTS OF OPERATIONS


Summary of Investment in Transmission Assets for AEPTCo
As of September 30,
20202019
(in millions)
Plant In Service$9,240.4 $7,409.0 
Construction Work in Progress1,680.9 1,858.4 
Accumulated Depreciation and Amortization531.8 368.8 
Total Transmission Property, Net$10,389.5 $8,898.6 
  As of September 30,
  2017 2016
  (in millions)
Plant In Service $4,684.4
 $3,260.7
CWIP 1,383.1
 1,328.6
Accumulated Depreciation 151.5
 86.6
Total Transmission Property, Net $5,916.0
 $4,502.7


Third Quarter of 20172020 Compared to Third Quarter of 20162019
Reconciliation of Third Quarter of 2019 to Third Quarter of 2020
Net Income
(in millions)
Third Quarter of 2019$107.6 
Changes in Transmission Revenues:
Transmission Revenues44.4 
Total Change in Transmission Revenues44.4 
Changes in Expenses and Other:
Other Operation and Maintenance0.4 
Depreciation and Amortization(16.2)
Taxes Other Than Income Taxes(9.3)
Interest Income(0.6)
Allowance for Equity Funds Used During Construction(0.8)
Interest Expense(6.3)
Total Change in Expenses and Other(32.8)
Income Tax Expense(1.6)
Third Quarter of 2020$117.6 
Reconciliation of Third Quarter of 2016 to Third Quarter of 2017
Net Income
(in millions)
   
Third Quarter of 2016 $52.4
   
Changes in Transmission Revenues:  
Transmission Revenues 42.0
Total Change in Transmission Revenues 42.0
   
Changes in Expenses and Other:  
Other Operation and Maintenance (10.4)
Depreciation and Amortization (8.0)
Taxes Other Than Income Taxes (4.9)
Interest Income 0.1
Allowance for Equity Funds Used During Construction (1.6)
Interest Expense (5.9)
Total Change in Expenses and Other (30.7)
   
Income Tax Expense (3.8)
   
Third Quarter of 2017 $59.9


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


•Transmission Revenues increased $42$44 million primarily due to a $40 million increase in formula rates driven by continued investment in transmission assets.


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


Other Operation•Depreciation and MaintenanceAmortization expenses increased $10$16 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxesincreased transmission investment.
Depreciation and Amortization expenses increased $8$9 million primarily due to higher depreciable base.
Taxes Other Than Income Taxes increased $5 million primarily due to increased property taxes as a result of additionalincreased transmission investment.
•Interest Expense increased $6 million primarily due to higher outstanding long-term debt balances.
69
Income Tax Expense increased $4 million primarily due to an increase in pretax book income.







Nine Months Ended September 30, 20172020 Compared to Nine Months Ended September 30, 20162019
Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020
Net Income
(in millions)
Nine Months Ended September 30, 2019$347.9 
Changes in Transmission Revenues:
Transmission Revenues67.7 
Total Change in Transmission Revenues67.7 
Changes in Expenses and Other:
Other Operation and Maintenance(8.2)
Depreciation and Amortization(48.0)
Taxes Other Than Income Taxes(26.6)
Interest Income0.2 
Allowance for Equity Funds Used During Construction(6.2)
Interest Expense(25.6)
Total Change in Expenses and Other(114.4)
Income Tax Expense7.9 
Nine Months Ended September 30, 2020$309.1 
Reconciliation of Nine Months Ended September 30, 2016 to Nine Months Ended September 30, 2017
Net Income
(in millions)
 
Nine Months Ended September 30, 2016 $153.0
   
Changes in Transmission Revenues:  
Transmission Revenues 191.4
Total Change in Transmission Revenues 191.4
   
Changes in Expenses and Other:  
Other Operation and Maintenance (19.8)
Depreciation and Amortization (23.4)
Taxes Other Than Income Taxes (16.6)
Interest Income 0.3
Allowance for Equity Funds Used During Construction (3.7)
Interest Expense (16.3)
Total Change in Expenses and Other (79.5)
   
Income Tax Expense (40.6)
   
Nine Months Ended September 30, 2017 $224.3


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


•Transmission Revenues increased $191$68 million primarily due to the current year favorable impact of the modification of the PJM OATT formula rates combined with anfollowing:
•A $147 million increase driven bydue to continued investment in transmission assets.

This increase was partially offset by:
•A $62 million decrease 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 $17 million decrease 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 $20$8 million primarily due to increased transmission investment.
the following:
•A $5 million increase in rent expense.
•A $3 million increase in employee-related expenses.
•Depreciation and Amortization expenses increased $23$48 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxes increased $17$27 million primarily due to increasedhigher property taxes as a result of additionalincreased transmission investment.
•Allowance for Equity Funds Used During Construction decreased $4$6 millionprimarily due to the following:
•A $12 million decrease driven by the favorable impact of a FERC transmission complaint and ansettlement agreement recorded in 2019.
•An $8 million decrease due to lower CWIP.
These decreases were partially offset by:
•A $13 million increase driven by FERC audit findings recorded in the amount of short term debt, offset by an increase in the CWIP balance.
2019.
•Interest Expense increased $16$26 million primarily due to higher outstanding long-term debt balances.
•Income Tax Expense increased $41 decreased $8 million primarily due to an increase inlower pretax book income.income, partially offset by the recognition of a discrete tax adjustment in 2019.

70











AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20172020 and 20162019
(in millions)
(Unaudited)
Three Months EndedNine Months Ended
September 30,September 30,
2020 2019 2020 2019
REVENUES
Transmission Revenues$62.9 $54.0 $184.6 $162.1 
Sales to AEP Affiliates241.2 205.7 652.6 608.0 
Other Revenues0 0 0.6 0 
TOTAL REVENUES304.1 259.7 837.8 770.1 
EXPENSES    
Other Operation25.3 26.0 72.0 61.7 
Maintenance3.5 3.2 6.8 8.9 
Depreciation and Amortization61.5 45.3 176.4 128.4 
Taxes Other Than Income Taxes52.2 42.9 152.8 126.2 
TOTAL EXPENSES142.5 117.4 408.0 325.2 
OPERATING INCOME161.6 142.3 429.8 444.9 
Other Income (Expense):    
Interest Income - Affiliated0.2 0.8 2.3 2.1 
Allowance for Equity Funds Used During Construction20.2 21.0 54.9 61.1 
Interest Expense(32.7)(26.4)(95.1)(69.5)
INCOME BEFORE INCOME TAX EXPENSE149.3 137.7 391.9 438.6 
Income Tax Expense31.7 30.1 82.8 90.7 
NET INCOME$117.6 $107.6 $309.1 $347.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
71
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2017 2016 2017 2016
REVENUES        
Transmission Revenues $35.9
 $33.5
 $99.2
 $89.6
Sales to AEP Affiliates 131.4
 91.8
 450.2
 268.4
TOTAL REVENUES 167.3
 125.3
 549.4
 358.0
         
EXPENSES  
    
  
Other Operation 18.4
 7.5
 38.8
 21.0
Maintenance 1.4
 1.9
 6.8
 4.8
Depreciation and Amortization 24.8
 16.8
 70.9
 47.5
Taxes Other Than Income Taxes 27.6
 22.7
 82.0
 65.4
TOTAL EXPENSES 72.2
 48.9
 198.5
 138.7
         
OPERATING INCOME 95.1
 76.4
 350.9
 219.3
         
Other Income (Expense):  
    
  
Interest Income 0.2
 0.1
 0.5
 0.2
Allowance for Equity Funds Used During Construction 11.7
 13.3
 36.0
 39.7
Interest Expense (16.9) (11.0) (48.6) (32.3)
         
INCOME BEFORE INCOME TAX EXPENSE 90.1
 78.8
 338.8
 226.9
         
Income Tax Expense 30.2
 26.4
 114.5
 73.9
         
NET INCOME $59.9
 $52.4
 $224.3
 $153.0


See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 118.





AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY
For the Nine Months Ended September 30, 20172020 and 20162019
(in millions)
(Unaudited)
  Paid-in
Capital		Retained
Earnings		Total
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2018 $2,480.6 $1,089.2 $3,569.8 
  
Net Income 104.3 104.3 
TOTAL MEMBER'S EQUITY – MARCH 31, 20192,480.6 1,193.5 3,674.1 
Net Income136.0 136.0 
TOTAL MEMBER'S EQUITY – JUNE 30, 20192,480.6 1,329.5 3,810.1 
Net Income 107.6 107.6 
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2019 $2,480.6 $1,437.1 $3,917.7 
  
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2019 $2,480.6 $1,528.9 $4,009.5 
Capital Contribution from Member185.0 185.0 
Net Income117.8 117.8 
TOTAL MEMBER'S EQUITY – MARCH 31, 20202,665.6 1,646.7 4,312.3 
  
Dividends Paid to AEP Transmission Holdco(5.0)(5.0)
Net Income73.7 73.7 
TOTAL MEMBER'S EQUITY – JUNE 30, 20202,665.6 1,715.4 4,381.0 
Net Income  117.6 117.6 
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2020 $2,665.6 $1,833.0 $4,498.6 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
72
  Paid-in
Capital		 Retained
Earnings		 Total Member’s Equity
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2015 $1,243.0
 $309.9
 $1,552.9
       
Capital Contributions from Member 116.0
   116.0
Net Income  
 153.0
 153.0
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2016 $1,359.0
 $462.9
 $1,821.9
       
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2016 $1,455.0
 $502.6
 $1,957.6
       
Capital Contributions from Member 185.5
   185.5
Net Income  
 224.3
 224.3
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2017 $1,640.5
 $726.9
 $2,367.4


See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 118.





AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20172020 and December 31, 20162019
(in millions)
(Unaudited)
  September 30, December 31,
  2020 2019
CURRENT ASSETS    
Advances to Affiliates $106.7 $85.4 
Accounts Receivable: 
Customers 34.1 19.0 
Affiliated Companies 81.1 66.1 
Total Accounts Receivable 115.2 85.1 
Materials and Supplies 13.6 13.8 
Prepayments and Other Current Assets 5.3 13.1 
TOTAL CURRENT ASSETS 240.8 197.4 
 
TRANSMISSION PROPERTY   
Transmission Property 8,947.4 8,137.9 
Other Property, Plant and Equipment 293.0 269.6 
Construction Work in Progress 1,680.9 1,485.7 
Total Transmission Property 10,921.3 9,893.2 
Accumulated Depreciation and Amortization 531.8 402.3 
TOTAL TRANSMISSION PROPERTY – NET 10,389.5 9,490.9 
 
OTHER NONCURRENT ASSETS   
Regulatory Assets 6.8 4.2 
Deferred Property Taxes 57.2 193.5 
Deferred Charges and Other Noncurrent Assets 4.4 4.8 
TOTAL OTHER NONCURRENT ASSETS 68.4 202.5 
 
TOTAL ASSETS $10,698.7 $9,890.8 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
73
  September 30, December 31,
  2017 2016
CURRENT ASSETS    
Advances to Affiliates $290.9
 $67.1
Accounts Receivable:    
Customers 19.5
 11.3
Affiliated Companies 102.8
 66.6
Total Accounts Receivable 122.3
 77.9
Materials and Supplies 16.0
 5.0
Accrued Tax Benefits 12.7
 26.0
Prepayments and Other Current Assets 8.1
 2.8
TOTAL CURRENT ASSETS 450.0
 178.8
     
TRANSMISSION PROPERTY    
Transmission Property 4,570.9
 3,973.5
Other Property, Plant and Equipment 113.5
 99.4
Construction Work in Progress 1,383.1
 981.3
Total Transmission Property 6,067.5
 5,054.2
Accumulated Depreciation and Amortization 151.5
 99.6
TOTAL TRANSMISSION PROPERTY – NET
 5,916.0
 4,954.6
     
OTHER NONCURRENT ASSETS    
Accounts Receivable - Affiliated Companies 13.8
 —
Regulatory Assets 138.0
 112.3
Deferred Property Taxes 29.8
 102.2
Deferred Charges and Other Noncurrent Assets 1.3
 1.9
TOTAL OTHER NONCURRENT ASSETS 182.9
 216.4
     
TOTAL ASSETS $6,548.9
 $5,349.8


See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 118.





AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND MEMBER’S EQUITY
September 30, 20172020 and December 31, 20162019
(in millions)
(Unaudited)
  September 30, December 31,
  2020 2019
CURRENT LIABILITIES    
Advances from Affiliates $86.8 $137.0 
Accounts Payable:  
General 337.7 493.4 
Affiliated Companies 62.4 71.2 
Accrued Taxes 216.6 355.6 
Accrued Interest 48.2 19.2 
Obligations Under Operating Leases2.3 2.1 
Other Current Liabilities 9.1 14.6 
TOTAL CURRENT LIABILITIES 763.1 1,093.1 
 
NONCURRENT LIABILITIES   
Long-term Debt – Nonaffiliated 3,947.9 3,427.3 
Deferred Income Taxes 892.6 817.8 
Regulatory Liabilities 575.2 540.9 
Obligations Under Operating Leases1.4 1.9 
Deferred Credits and Other Noncurrent Liabilities 19.9 0.3 
TOTAL NONCURRENT LIABILITIES 5,437.0 4,788.2 
 
TOTAL LIABILITIES 6,200.1 5,881.3 
 
Rate Matters (Note 4) 
Commitments and Contingencies (Note 5) 
 
MEMBER’S EQUITY   
Paid-in Capital2,665.6 2,480.6 
Retained Earnings 1,833.0 1,528.9 
TOTAL MEMBER’S EQUITY 4,498.6 4,009.5 
 
TOTAL LIABILITIES AND MEMBER’S EQUITY $10,698.7 $9,890.8 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
74
  September 30, December 31,
  2017 2016
CURRENT LIABILITIES    
Advances from Affiliates $32.8
 $4.1
Accounts Payable:    
General 233.2
 289.7
Affiliated Companies 50.0
 43.1
Accrued Taxes 112.5
 191.8
Accrued Interest 28.9
 10.5
Other Current Liabilities 10.4
 10.9
TOTAL CURRENT LIABILITIES 467.8
 550.1
     
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated 2,550.0
 1,932.0
Deferred Income Taxes 1,073.1
 862.1
Regulatory Liabilities 60.5
 44.0
Deferred Credits and Other Noncurrent Liabilities 30.1
 4.0
TOTAL NONCURRENT LIABILITIES 3,713.7
 2,842.1
     
TOTAL LIABILITIES 4,181.5
 3,392.2
     
Rate Matters (Note 4) 
 
Commitments and Contingencies (Note 5) 
 
     
MEMBER’S EQUITY    
Paid-in Capital 1,640.5
 1,455.0
Retained Earnings 726.9
 502.6
TOTAL MEMBER’S EQUITY 2,367.4
 1,957.6
     
TOTAL LIABILITIES AND MEMBER’S EQUITY $6,548.9
 $5,349.8


See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 118.





AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20172020 and 20162019
(in millions)
(Unaudited)
  Nine Months Ended September 30,
  20202019
OPERATING ACTIVITIES 
Net Income $309.1 $347.9 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: 
Depreciation and Amortization 176.4 128.4 
Deferred Income Taxes 65.4 36.7 
Allowance for Equity Funds Used During Construction (54.9)(61.1)
Property Taxes 136.3 110.7 
Change in Other Noncurrent Assets (1.5)1.0 
Change in Other Noncurrent Liabilities 19.5 (3.8)
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net (30.1)(5.1)
Materials and Supplies0.2 3.9 
Accounts Payable 26.0 4.1 
Accrued Taxes, Net (139.0)(92.8)
Accrued Interest 29.0 23.8 
Other Current Assets 9.1 (1.0)
Other Current Liabilities (10.7)(8.5)
Net Cash Flows from Operating Activities 534.8 484.2 
 
INVESTING ACTIVITIES   
Construction Expenditures (1,163.8)(959.9)
Change in Advances to Affiliates, Net (21.3)(178.3)
Acquisitions of Assets (3.6)(7.6)
Other Investing Activities 4.7 12.0 
Net Cash Flows Used for Investing Activities (1,184.0)(1,133.8)
 
FINANCING ACTIVITIES  
Capital Contributions from Member 185.0 0 
Issuance of Long-term Debt – Nonaffiliated519.4 685.9 
Change in Advances from Affiliates, Net (50.2)(36.3)
Dividends Paid to AEP Transmission Holdco(5.0)0 
Net Cash Flows from Financing Activities 649.2 649.6 
 
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 $63.3 $43.0 
Net Cash Paid for Income Taxes 1.9 29.8 
Construction Expenditures Included in Current Liabilities as of September 30, 283.6 315.1 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
75
  Nine Months Ended September 30,
  2017 2016
OPERATING ACTIVITIES    
Net Income $224.3
 $153.0
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
Depreciation and Amortization 70.9
 47.5
Deferred Income Taxes 193.0
 161.2
Allowance for Equity Funds Used During Construction (36.0) (39.7)
Property Taxes 72.4
 63.5
Long-term Accounts Receivable - Affiliated (13.8) —
Change in Other Noncurrent Assets 7.6
 (6.4)
Change in Other Noncurrent Liabilities 25.7
 0.6
Changes in Certain Components of Working Capital:    
Accounts Receivable, Net (44.4) (43.3)
Materials and Supplies (11.0) (1.5)
Accounts Payable 8.6
 (1.7)
Accrued Taxes, Net (66.0) 61.2
Accrued Interest 18.4
 11.3
Other Current Assets (5.3) (0.1)
Other Current Liabilities 0.5
 0.1
Net Cash Flows from Operating Activities 444.9
 405.7
     
INVESTING ACTIVITIES  
  
Construction Expenditures (1,050.7) (799.8)
Change in Advances to Affiliates, Net (223.8) 83.7
Other Investing Activities (2.9) (4.6)
Net Cash Flows Used for Investing Activities (1,277.4) (720.7)
     
FINANCING ACTIVITIES    
Capital Contributions from Member 185.5
 116.0
Issuance of Long-term Debt - Nonaffiliated 618.3
 —
Change in Advances from Affiliates, Net 28.7
 199.0
Net Cash Flows from Financing Activities 832.5
 315.0
     
Net Change in Cash and Cash Equivalents —
 —
Cash and Cash Equivalents at Beginning of Period —
 —
Cash and Cash Equivalents at End of Period $—
 $—
     
SUPPLEMENTARY INFORMATION  
  
Cash Paid for Interest, Net of Capitalized Amounts $28.6
 $20.0
Net Cash Paid (Received) for Income Taxes (93.4) (209.8)
Construction Expenditures Included in Current Liabilities as of September 30, 239.0
 204.8





See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 118.






APPALACHIAN POWER COMPANY
AND SUBSIDIARIES

76






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


RESULTS OF OPERATIONS


KWh Sales/Degree Days


Summary of KWh Energy Sales
 Three Months EndedNine Months Ended
 September 30,September 30,
2020201920202019
 (in millions of KWhs)
Retail:    
Residential2,772 2,728 8,229 8,401 
Commercial1,612 1,721 4,410 4,812 
Industrial2,193 2,487 6,507 7,180 
Miscellaneous203 216 585 640 
Total Retail6,780 7,152 19,731 21,033 
Wholesale1,187 938 2,894 2,667 
Total KWhs7,967 8,090 22,625 23,700 
 Three Months Ended Nine Months Ended
 September 30, September 30,
 2017 2016 2017 2016
 (in millions of KWhs)
Retail: 
  
  
  
Residential2,488
 2,845
 7,829
 8,743
Commercial1,673
 1,823
 4,805
 5,125
Industrial2,431
 2,391
 7,106
 7,022
Miscellaneous202
 217
 613
 637
Total Retail6,794
 7,276
 20,353
 21,527
        
Wholesale994
 1,029
 2,684
 2,413
        
Total KWhs7,788
 8,305
 23,037
 23,940


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


Summary of Heating and Cooling Degree Days
 Three Months EndedNine Months Ended
 September 30,September 30,
2020201920202019
 (in degree days)
Actual – Heating (a)1 — 1,098 1,295 
Normal – Heating (b)2 3 1,413 1,407 
Actual – Cooling (c)988 1,071 1,354 1,530 
Normal – Cooling (b)825 815 1,208 1,194 

(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.

77
 Three Months Ended Nine Months Ended
 September 30, September 30,
 2017 2016 2017 2016
 (in degree days)
Actual - Heating (a)—
 —
 1,000
 1,433
Normal - Heating (b)2
 2
 1,420
 1,437
        
Actual - Cooling (c)805
 1,049
 1,180
 1,437
Normal - Cooling (b)812
 808
 1,179
 1,177


(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.







Third Quarter of 20172020 Compared to Third Quarter of 20162019
Reconciliation of Third Quarter of 2019 to Third Quarter of 2020
Net Income
(in millions)
Third Quarter of 2019$104.3 
Changes in Gross Margin:
Retail Margins7.9 
Margins from Off-system Sales(1.2)
Transmission Revenues(3.1)
Other Revenues(1.3)
Total Change in Gross Margin2.3 
Changes in Expenses and Other:
Other Operation and Maintenance13.6 
Depreciation and Amortization(4.5)
Taxes Other Than Income Taxes(2.1)
Interest Income0.3 
Allowance for Equity Funds Used During Construction1.9 
Non-Service Cost Components of Net Periodic Benefit Cost0.4 
Interest Expense(3.4)
Total Change in Expenses and Other6.2 
Income Tax Expense (Benefit)3.8 
Third Quarter of 2020$116.6 

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 $8 million primarily due to the following:
•An $8 million increase in deferred fuel primarily due to the timing of recoverable PJM expenses. This increase was offset in other expense items below.
•A $6 million increase due to a decrease in customer refunds related to Tax Reform. This increase was partially offset in Income Tax Expense below.
•A $4 million increase due to the WVPSC approval of the Mitchell Plant surcharge effective January 2020.
These increases were partially offset by:
•An $8 million decrease in weather-related usage primarily driven by an 8% decrease in cooling degree days.
•A $3 million decrease in weather-normalized margins primarily in the commercial and industrial classes, partially offset in the residential class.
•Transmission Revenue decreased $3 million primarily due to an adjustment in July 2019 to the annual transmission formula rate true-up.

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

•Other Operation and Maintenance expenses decreased $14 million primarily due to the following:
•A $6 million decrease in distribution expense primarily due to storm and vegetation management expenses.
•A $3 million decrease in PJM expenses primarily related to the annual transmission formula rate true-up.
•A $3 million decrease in maintenance expense at various generation plants.
•A $2 million decrease in uncollectible accounts expenses.
These decreases were partially offset by:
•A $4 million increase in employee-related expenses.
•Depreciation and Amortization expenses increased $5 million primarily due to a higher depreciable base.
78





Reconciliation of Third Quarter of 2016 to Third Quarter of 2017
Net Income
(in millions)
 
Third Quarter of 2016 $104.1
   
Changes in Gross Margin:  
Retail Margins (40.6)
Off-system Sales (1.0)
Transmission Revenues 1.8
Other Revenues 0.5
Total Change in Gross Margin (39.3)
   
Changes in Expenses and Other:  
Other Operation and Maintenance 12.9
Depreciation and Amortization (4.7)
Taxes Other Than Income Taxes (0.3)
Carrying Costs Income 0.4
Allowance for Equity Funds Used During Construction (1.8)
Interest Expense (0.8)
Total Change in Expenses and Other 5.7
   
Income Tax Expense 15.5
   
Third Quarter of 2017 $86.0
•Interest Expense increased $3 million primarily due to higher long-term debt balances.

•Income Tax Expense (Benefit) decreased $4 million primarily due the recognition of a discrete tax adjustment, which was primarily attributable to the filing of the 2019 Federal Income Tax return in the third quarter of 2020, and an increase in parent company loss benefit, partially offset by a decrease in amortization of Excess ADIT. The decrease in amortization of Excess ADIT is partially offset above in Gross Margin and Other Operation and Maintenance expenses.


79





Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019
Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020
Net Income
(in millions)
Nine Months Ended September 30, 2019$293.5 
Changes in Gross Margin:
Retail Margins35.7 
Margins from Off-system Sales(3.2)
Transmission Revenues(8.9)
Other Revenues(1.3)
Total Change in Gross Margin22.3 
Changes in Expenses and Other:
Other Operation and Maintenance72.7 
Depreciation and Amortization(17.7)
Taxes Other Than Income Taxes(5.7)
Interest Income(0.7)
Allowance for Equity Funds Used During Construction(1.0)
Non-Service Cost Components of Net Periodic Benefit Cost1.3 
Interest Expense(9.7)
Total Change in Expenses and Other39.2 
Income Tax Expense (Benefit)(41.8)
Nine Months Ended September 30, 2020$313.2 

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 $36 million primarily due to the following:
•A $30 million increase due to a decrease in customer refunds related to Tax Reform. This increase was partially offset in Income Tax Expense below.
•A $28 million increase in deferred fuel primarily due to the timing of recoverable PJM expenses offset in line items below.
•A $12 million increase due to the WVPSC approval of the Mitchell Plant surcharge effective January 2020. Pursuant to the WVPSC approval of the surcharge, this increase was partially offset by the amortization of Excess ADIT not subject to normalization requirements in Income Tax Expense below.
•A $12 million increase due to the impact of the 2019 WVPSC order which required APCo to offset Excess ADIT not subject to normalization requirements against the deferred fuel under-recovery balance in 2019.
•An $11 million increase due to a base rate increase in West Virginia.
These increases were partially offset by:
•A $41 million decrease in weather-related usage primarily driven by a 15% decrease in heating degree days and a 12% decrease in cooling degree days.
•A $16 million decrease in weather-normalized margins primarily in the commercial and industrial classes, partially offset in the residential class.
•Margins from Off-system Sales decreased $3 million due to weaker market prices for energy in the RTOs which caused a decrease in sales volume and margins.
•Transmission Revenues decreased $9 million primarily due to the following:
•A $13 million decrease from the annual transmission formula rate true-up.
This decrease was partially offset by:
•A $4 million increase from investment in transmission assets.

80





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

•Other Operation and Maintenance expenses decreased $73 million primarily due to the following:
•A $17 million decrease in transmission expenses primarily related to the annual transmission formula rate true-up.
•A $20 million decrease in maintenance expense at various generation plants.
•A $14 million decrease as a result of prior year contributions to benefit low income West Virginia residential customers as a result of the West Virginia Tax Reform settlement. This decrease was offset in Income Tax Expense below.
•A $10 million decrease in distribution expense primarily due to storm and vegetation management expenses.
•An $8 million decrease in employee-related expenses.
•Depreciation and Amortization expenses increased $18 million primarily due to a higher depreciable base and an increase in West Virginia depreciation rates beginning in March 2019. This increase was partially offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $6 million primarily due to the following:
•A $3 million increase in property taxes due to additional investments in utility plant.
•A $3 million increase in state business and occupation taxes due to the reduction of the revitalization tax credit.
•Interest Expense increased $10 million primarily due to higher long-term debt balances.
•Income Tax Expense (Benefit) increased $42 million primarily due to a decrease in amortization of Excess ADIT. The decrease in amortization of Excess ADIT is partially offset above in Gross Margin and Other Operation and Maintenance expenses.

81






APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
 September 30,September 30,
 2020201920202019
REVENUES    
Electric Generation, Transmission and Distribution$688.9 $696.7 $1,989.9 $2,041.3 
Sales to AEP Affiliates44.4 56.6 124.9 154.6 
Other Revenues2.4 2.2 7.8 8.2 
TOTAL REVENUES735.7 755.5 2,122.6 2,204.1 
EXPENSES    
Fuel and Other Consumables Used for Electric Generation166.0 177.3 430.9 521.8 
Purchased Electricity for Resale67.5 78.3 240.5 253.4 
Other Operation136.3 140.4 379.1 416.2 
Maintenance52.0 61.5 148.7 184.3 
Depreciation and Amortization123.2 118.7 366.0 348.3 
Taxes Other Than Income Taxes38.8 36.7 114.2 108.5 
TOTAL EXPENSES583.8 612.9 1,679.4 1,832.5 
OPERATING INCOME151.9 142.6 443.2 371.6 
Other Income (Expense):    
Interest Income0.6 0.3 1.4 2.1 
Allowance for Equity Funds Used During Construction6.7 4.8 11.5 12.5 
Non-Service Cost Components of Net Periodic Benefit Cost4.7 4.3 14.1 12.8 
Interest Expense(55.0)(51.6)(162.2)(152.5)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)108.9 100.4 308.0 246.5 
Income Tax Expense (Benefit)(7.7)(3.9)(5.2)(47.0)
NET INCOME$116.6 $104.3 $313.2 $293.5 
The common stock of APCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
82





APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
 September 30,September 30,
2020201920202019
Net Income$116.6 $104.3 $313.2 $293.5 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES  
Cash Flow Hedges, Net of Tax of $0.1 and $(0.1) for the Three Months
   Ended September 30, 2020 and 2019, Respectively, and $(1.2) and
   $(0.2) for the Nine Months Ended September 30, 2020 and 2019,
   Respectively
0.6 (0.3)(4.4)(0.7)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of
   $(0.3) and $(0.2) for the Three Months Ended September 30, 2020 and
   2019, Respectively, and $(0.8) and $(0.5) for the Nine Months Ended
   September 30, 2020 and 2019, Respectively
(0.9)(0.6)(2.8)(1.9)
TOTAL OTHER COMPREHENSIVE LOSS(0.3)(0.9)(7.2)(2.6)
TOTAL COMPREHENSIVE INCOME$116.3 $103.4 $306.0 $290.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
83





APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)
Common
Stock		Paid-in
Capital		Retained
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Total
TOTAL COMMON SHAREHOLDER’S
   EQUITY - DECEMBER 31, 2018
$260.4 $1,828.7 $1,922.0 $(5.0)$4,006.1 
Common Stock Dividends(50.0)(50.0)
Net Income133.7 133.7 
Other Comprehensive Loss(0.8)(0.8)
TOTAL COMMON SHAREHOLDER’S
   EQUITY - MARCH 31, 2019
260.4 1,828.7 2,005.7 (5.8)4,089.0 
Common Stock Dividends  (50.0) (50.0)
Net Income  55.5  55.5 
Other Comprehensive Loss   (0.9)(0.9)
TOTAL COMMON SHAREHOLDER’S
   EQUITY - JUNE 30, 2019
260.4 1,828.7 2,011.2 (6.7)4,093.6 
Common Stock Dividends(25.0)(25.0)
Net Income104.3 104.3 
Other Comprehensive Loss(0.9)(0.9)
TOTAL COMMON SHAREHOLDER’S
   EQUITY - SEPTEMBER 30, 2019
$260.4 $1,828.7 $2,090.5 $(7.6)$4,172.0 
TOTAL COMMON SHAREHOLDER’S
   EQUITY - DECEMBER 31, 2019
$260.4 $1,828.7 $2,078.3 $5.0 $4,172.4 
Common Stock Dividends(50.0)(50.0)
Net Income115.3 115.3 
Other Comprehensive Loss(5.1)(5.1)
TOTAL COMMON SHAREHOLDER’S
   EQUITY - MARCH 31, 2020
260.4 1,828.7 2,143.6 (0.1)4,232.6 
Common Stock Dividends(50.0)(50.0)
Net Income81.3 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 
Common Stock Dividends  (50.0) (50.0)
Net Income  116.6  116.6 
Other Comprehensive Loss   (0.3)(0.3)
TOTAL COMMON SHAREHOLDER’S
   EQUITY - SEPTEMBER 30, 2020
$260.4 $1,828.7 $2,241.5 $(2.2)$4,328.4 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.

84





APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2020 and December 31, 2019
(in millions)
(Unaudited)
September 30,December 31,
20202019
CURRENT ASSETS  
Cash and Cash Equivalents$3.9 $3.3 
Restricted Cash for Securitized Funding9.3 23.5 
Advances to Affiliates159.5 22.1 
Accounts Receivable:  
Customers136.6 129.0 
Affiliated Companies60.2 64.3 
Accrued Unbilled Revenues52.6 59.7 
Miscellaneous0.2 0.5 
Allowance for Uncollectible Accounts(3.4)(2.6)
Total Accounts Receivable246.2 250.9 
Fuel144.4 149.7 
Materials and Supplies98.2 105.2 
Risk Management Assets30.7 39.4 
Regulatory Asset for Under-Recovered Fuel Costs3.7 42.5 
Prepayments and Other Current Assets29.7 64.0 
TOTAL CURRENT ASSETS725.6 700.6 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation6,615.9 6,563.7 
Transmission3,811.4 3,584.1 
Distribution4,348.8 4,201.7 
Other Property, Plant and Equipment622.5 571.3 
Construction Work in Progress539.9 593.4 
Total Property, Plant and Equipment15,938.5 15,514.2 
Accumulated Depreciation and Amortization4,652.7 4,432.3 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET11,285.8 11,081.9 
OTHER NONCURRENT ASSETS  
Regulatory Assets659.1 457.2 
Securitized Assets216.2 234.7 
Long-term Risk Management Assets0.1 0.1 
Operating Lease Assets80.3 78.5 
Deferred Charges and Other Noncurrent Assets190.9 215.3 
TOTAL OTHER NONCURRENT ASSETS1,146.6 985.8 
TOTAL ASSETS$13,158.0 $12,768.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
85





APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2020 and December 31, 2019
(Unaudited)
 September 30,December 31,
 20202019
 (in millions)
CURRENT LIABILITIES  
Advances from Affiliates$4.3 $236.7 
Accounts Payable:  
General191.6 307.8 
Affiliated Companies80.0 92.5 
Long-term Debt Due Within One Year – Nonaffiliated518.3 215.6 
Risk Management Liabilities5.6 1.9 
Customer Deposits80.1 85.8 
Accrued Taxes77.3 99.6 
Accrued Interest73.8 47.9 
Obligations Under Operating Leases14.7 15.2 
Other Current Liabilities98.4 123.0 
TOTAL CURRENT LIABILITIES1,144.1 1,226.0 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated4,315.0 4,148.2 
Long-term Risk Management Liabilities0.2 0 
Deferred Income Taxes1,716.5 1,680.8 
Regulatory Liabilities and Deferred Investment Tax Credits1,195.8 1,268.7 
Asset Retirement Obligations298.2 102.1 
Employee Benefits and Pension Obligations38.2 50.9 
Obligations Under Operating Leases66.1 64.0 
Deferred Credits and Other Noncurrent Liabilities55.5 55.2 
TOTAL NONCURRENT LIABILITIES7,685.5 7,369.9 
TOTAL LIABILITIES8,829.6 8,595.9 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
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 Earnings2,241.5 2,078.3 
Accumulated Other Comprehensive Income (Loss)(2.2)5.0 
TOTAL COMMON SHAREHOLDER’S EQUITY4,328.4 4,172.4 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$13,158.0 $12,768.3 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
86





APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20202019
OPERATING ACTIVITIES  
Net Income$313.2 $293.5 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and Amortization366.0 348.3 
Deferred Income Taxes(28.2)(101.9)
Allowance for Equity Funds Used During Construction(11.5)(12.5)
Mark-to-Market of Risk Management Contracts8.0 2.2 
Pension Contributions to Qualified Plan Trust(7.0)0 
Deferred Fuel Over/Under-Recovery, Net38.8 60.8 
Change in Other Noncurrent Assets5.4 6.7 
Change in Other Noncurrent Liabilities(26.0)(29.6)
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net7.2 61.7 
Fuel, Materials and Supplies12.4 (49.2)
Accounts Payable(74.0)40.1 
Accrued Taxes, Net1.9 (30.2)
Other Current Assets10.1 6.8 
Other Current Liabilities(9.7)(25.1)
Net Cash Flows from Operating Activities606.6 571.6 
INVESTING ACTIVITIES  
Construction Expenditures(566.6)(607.1)
Change in Advances to Affiliates, Net(137.4)0.3 
Other Investing Activities4.6 22.8 
Net Cash Flows Used for Investing Activities(699.4)(584.0)
FINANCING ACTIVITIES  
Issuance of Long-term Debt – Nonaffiliated557.2 478.2 
Change in Advances from Affiliates, Net(232.4)(165.2)
Retirement of Long-term Debt – Nonaffiliated(90.3)(180.4)
Principal Payments for Finance Lease Obligations(5.6)(5.0)
Dividends Paid on Common Stock(150.0)(125.0)
Other Financing Activities0.3 0.6 
Net Cash Flows from Financing Activities79.2 3.2 
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding(13.6)(9.2)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period26.8 29.8 
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period$13.2 $20.6 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$130.0 $120.6 
Net Cash Paid (Received) for Income Taxes(10.7)58.7 
Noncash Acquisitions Under Finance Leases3.0 7.1 
Construction Expenditures Included in Current Liabilities as of September 30,90.0 134.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
87







INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES
88





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

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 Three Months EndedNine Months Ended
 September 30,September 30,
 2020201920202019
 (in millions of KWhs)
Retail:    
Residential1,531 1,496 4,230 4,159 
Commercial1,219 1,312 3,362 3,555 
Industrial1,849 1,937 5,324 5,742 
Miscellaneous14 16 47 49 
Total Retail4,613 4,761 12,963 13,505 
Wholesale1,536 2,398 5,552 6,842 
Total KWhs6,149 7,159 18,515 20,347 

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

Summary of Heating and Cooling Degree Days
 Three Months EndedNine Months Ended
 September 30,September 30,
 2020201920202019
 (in degree days)
Actual – Heating (a)7 — 2,186 2,456 
Normal – Heating (b)10 11 2,429 2,412 
Actual – Cooling (c)637 684 923 917 
Normal – Cooling (b)576 573 841 836 

(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.
89





Third Quarter of 2020 Compared to Third Quarter of 2019
Reconciliation of Third Quarter of 2019 to Third Quarter of 2020
Net Income
(in millions)
Third Quarter of 2019$88.8 
Changes in Gross Margin:
Retail Margins9.0 
Margins from Off-system Sales(0.3)
Transmission Revenues2.6 
Other Revenues(6.5)
Total Change in Gross Margin4.8 
Changes in Expenses and Other:
Other Operation and Maintenance7.1 
Depreciation and Amortization(16.4)
Taxes Other Than Income Taxes(2.3)
Other Income(1.3)
Non-Service Cost Components of Net Periodic Benefit Cost(0.4)
Interest Expense1.9 
Total Change in Expenses and Other(11.4)
Income Tax Expense(5.5)
Third Quarter of 2020$76.7 

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

•Retail Margins increased $9 million primarily due to the following:
•A $38 million increase primarily due to the Indiana and Michigan base rate cases and increases in rate riders. This increase was partially offset in other expense items below.
This increase was partially offset by:
•A $20 million decrease in weather-normalized wholesale margins, including the loss of a significant wholesale contract.
•A $6 million decrease in weather-related usage primarily due to a 7% decrease in cooling degree days.
•A $3 million decrease in weather-normalized retail margins.
•Transmission Revenues increased $3 million primarily due to a July 2019 adjustment to the annual transmission formula rate true-up.
•Other Revenues decreased $7 million primarily due to a decrease in barging revenues by River Transportation Division (RTD). This decrease was partially offset in Other Operation and Maintenance expenses below.

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

•Other Operation and Maintenance expenses decreased $7 million primarily due to the following:
•A $10 million decrease in nonutility operation expenses primarily due to a decrease in RTD expenses. This decrease was partially offset in Other Revenues above.
•A $4 million decrease in steam generation expense primarily due to 2019 NSR Consent Decree modifications.
•A $4 million decrease in nuclear generation expenses primarily due to a decrease in maintenance activities.
•A $3 million decrease in administrative and general expenses primarily due to a decrease in rate case and insurance expenses.
These decreases were partially offset by:
•A $12 million increase in employee-related expenses.
•A $2 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.
90





•Depreciation and Amortization expensesincreased $16 million primarily due to a higher depreciable base and an increase in depreciation rates. This increase was partially offset in Retail Margins above.
•Income Tax Expense increased $6 million primarily due to the recognition of a discrete tax adjustment, which was primarily attributable to the filing of the 2019 Federal Income Tax return in the third quarter of 2020, and an increase in state income tax expense.
91





Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019
Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020
Net Income
(in millions)
Nine Months Ended September 30, 2019$248.0 
Changes in Gross Margin:
Retail Margins25.8 
Margins from Off-system Sales(0.3)
Transmission Revenues10.0 
Other Revenues(13.7)
Total Change in Gross Margin21.8 
Changes in Expenses and Other:
Other Operation and Maintenance27.4 
Depreciation and Amortization(42.0)
Taxes Other Than Income Taxes(0.9)
Other Income(7.5)
Non-Service Cost Components of Net Periodic Benefit Cost(0.8)
Interest Expense0.2 
Total Change in Expenses and Other(23.6)
Income Tax Expense(13.4)
Nine Months Ended September 30, 2020$232.8 

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

•Retail Margins increased $26 million primarily due to the following:
•A $72 million increase primarily due to the Indiana and Michigan base rate cases and increases in rider revenues. This increase was partially offset in other expense items below.
This increase was partially offset by:
•A $37 million decrease in weather-normalized wholesale margins, including the loss of a significant wholesale contract.
•An $8 million decrease in weather-related usage primarily due to an 11% decrease in heating degree days.
•A $6 million decrease in weather-normalized retail margins.
•Transmission Revenues increased $10 million primarily due to the following:
•A $6 million increase from the annual transmission formula rate true-up.
•A $4 million increase from investment in transmission assets. This increase was partially offset in Other Operation and Maintenance expenses below.
•Other Revenues decreased $14 million primarily due to a decrease in barging revenues by RTD. This decrease was partially offset in Other Operation and Maintenance expenses below.


92





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

•Other Operation and Maintenance expenses decreased $27 million primarily due to the following:
•An $18 million decrease in nonutility operation expenses primarily due to a decrease in RTD expenses. This decrease was partially offset in Other Revenues above.
•An $8 million decrease in distribution expenses primarily due to a decrease in vegetation management expenses.
•A $7 million decrease due to an increased Nuclear Electric Insurance Limited distribution in 2020.
•A $7 million decrease in Cook Plant refueling outage amortization expense primarily due to decreased costs of outages and various maintenance activities.
•A $4 million decrease in steam generation expense primarily due to 2019 NSR Consent Decree modifications.
These decreases were partially offset by:
•A $12 million increase in transmission expenses primarily due to a $21 million increase in recoverable PJM expenses, partially offset by an $11 million decrease from the annual transmission formula rate true-up. This increase was partially offset in Transmission Revenues above.
•A $5 million increase in employee-related expenses.
•Depreciation and Amortization expensesincreased $42 million primarily due to a higher depreciable base and an increase in depreciation rates. This increase was partially offset in Retail Margins above.
•Other Income decreased $8 million primarily due to a decrease in the AFUDC base and the favorable impact of a FERC settlement agreement recorded in 2019.
•Income Tax Expense increased $13 million primarily due to an increase in state income tax expense and a decrease in favorable flow-through tax benefits.
93






INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
 September 30,September 30,
 2020201920202019
REVENUES    
Electric Generation, Transmission and Distribution$570.1 $589.1 $1,648.4 $1,703.2 
Sales to AEP Affiliates1.3 2.7 9.1 7.3 
Other Revenues – Affiliated14.1 16.2 42.4 50.4 
Other Revenues – Nonaffiliated1.2 3.1 3.7 7.6 
TOTAL REVENUES586.7 611.1 1,703.6 1,768.5 
EXPENSES    
Fuel and Other Consumables Used for Electric Generation44.4 61.2 146.0 161.2 
Purchased Electricity for Resale37.5 44.8 128.1 163.3 
Purchased Electricity from AEP Affiliates55.9 61.0 135.8 172.1 
Other Operation165.5 172.7 459.7 467.7 
Maintenance51.0 50.9 144.4 163.8 
Depreciation and Amortization104.5 88.1 303.6 261.6 
Taxes Other Than Income Taxes27.4 25.1 79.5 78.6 
TOTAL EXPENSES486.2 503.8 1,397.1 1,468.3 
OPERATING INCOME100.5 107.3 306.5 300.2 
Other Income (Expense):    
Other Income2.2 3.5 7.8 15.3 
Non-Service Cost Components of Net Periodic Benefit Cost4.1 4.5 12.5 13.3 
Interest Expense(26.9)(28.8)(85.7)(85.9)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)79.9 86.5 241.1 242.9 
Income Tax Expense (Benefit)3.2 (2.3)8.3 (5.1)
NET INCOME$76.7 $88.8 $232.8 $248.0 
The common stock of I&M is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
94





INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
 September 30,September 30,
2020201920202019
Net Income$76.7 $88.8 $232.8 $248.0 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES   
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended September 30, 2020 and 2019, Respectively, and $0.3 and $0.3 for the Nine Months Ended September 30, 2020 and 2019, Respectively0.4 0.4 1.2 1.2 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2020 and 2019, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2020 and 2019, Respectively(0.1)0 (0.1)(0.1)
TOTAL OTHER COMPREHENSIVE INCOME0.3 0.4 1.1 1.1 
TOTAL COMPREHENSIVE INCOME$77.0 $89.2 $233.9 $249.1 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
95





INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)
Common
Stock		Paid-in
Capital		Retained
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Total
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2018$56.6 $980.9 $1,329.1 $(13.8)$2,352.8 
Common Stock Dividends  (20.0) (20.0)
Net Income  98.9  98.9 
Other Comprehensive Income   0.4 0.4 
TOTAL COMMON SHAREHOLDER’S EQUITY - MARCH 31, 201956.6 980.9 1,408.0 (13.4)2,432.1 
Common Stock Dividends(20.0)(20.0)
Net Income60.3 60.3 
Other Comprehensive Income0.3 0.3 
TOTAL COMMON SHAREHOLDER’S EQUITY - JUNE 30, 201956.6 980.9 1,448.3 (13.1)2,472.7 
Common Stock Dividends(20.0)(20.0)
Net Income88.8 88.8 
Other Comprehensive Income0.4 0.4 
TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2019$56.6 $980.9 $1,517.1 $(12.7)$2,541.9 
     
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 Income92.3 92.3 
Other Comprehensive Income0.4 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 Income  63.8  63.8 
Other Comprehensive Income   0.4 0.4 
TOTAL COMMON SHAREHOLDER’S EQUITY - JUNE 30, 202056.6 980.9 1,632.5 (10.8)2,659.2 
Common Stock Dividends(21.2)(21.2)
Net Income76.7 76.7 
Other Comprehensive Income0.3 0.3 
TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2020$56.6 $980.9 $1,688.0 $(10.5)$2,715.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
96





INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2020 and December 31, 2019
(in millions)
(Unaudited)
September 30,December 31,
 20202019
CURRENT ASSETS  
Cash and Cash Equivalents$2.8 $2.0 
Advances to Affiliates13.3 13.2 
Accounts Receivable:  
Customers34.7 53.6 
Affiliated Companies43.5 53.7 
Accrued Unbilled Revenues0 2.5 
Miscellaneous0.9 0.3 
Allowance for Uncollectible Accounts(0.3)(0.6)
Total Accounts Receivable78.8 109.5 
Fuel71.3 56.2 
Materials and Supplies171.4 171.3 
Risk Management Assets4.1 9.8 
Accrued Tax Benefits29.8 0 
Regulatory Asset for Under-Recovered Fuel Costs4.2 3.0 
Accrued Reimbursement of Spent Nuclear Fuel Costs14.7 24.0 
Prepayments and Other Current Assets17.0 14.0 
TOTAL CURRENT ASSETS407.4 403.0 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation5,239.8 5,099.7 
Transmission1,665.8 1,641.8 
Distribution2,549.5 2,437.6 
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)665.8 632.6 
Construction Work in Progress383.3 382.3 
Total Property, Plant and Equipment10,504.2 10,194.0 
Accumulated Depreciation, Depletion and Amortization3,502.4 3,294.3 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET7,001.8 6,899.7 
OTHER NONCURRENT ASSETS  
Regulatory Assets450.2 482.1 
Spent Nuclear Fuel and Decommissioning Trusts3,075.9 2,975.7 
Long-term Risk Management Assets0 0.1 
Operating Lease Assets228.8 294.9 
Deferred Charges and Other Noncurrent Assets160.7 181.9 
TOTAL OTHER NONCURRENT ASSETS3,915.6 3,934.7 
TOTAL ASSETS$11,324.8 $11,237.4 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
97





INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2020 and December 31, 2019
(dollars in millions)
(Unaudited)
 September 30,December 31,
 20202019
CURRENT LIABILITIES  
Advances from Affiliates$159.1 $114.4 
Accounts Payable:  
General133.3 169.4 
Affiliated Companies79.7 68.4 
Long-term Debt Due Within One Year – Nonaffiliated
   (September 30, 2020 and December 31, 2019 Amounts Include $54.9 and $86.1,
   Respectively, Related to DCC Fuel)
348.7 139.7 
Risk Management Liabilities0.2 0.5 
Customer Deposits40.2 39.4 
Accrued Taxes57.8 112.4 
Accrued Interest19.9 36.2 
Obligations Under Operating Leases83.8 87.3 
Regulatory Liability for Over-Recovered Fuel Costs30.6 6.1 
Other Current Liabilities91.0 109.6 
TOTAL CURRENT LIABILITIES1,044.3 883.4 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated2,633.2 2,910.5 
Long-term Risk Management Liabilities0.1 0 
Deferred Income Taxes1,024.0 979.7 
Regulatory Liabilities and Deferred Investment Tax Credits1,879.6 1,891.4 
Asset Retirement Obligations1,796.1 1,748.6 
Obligations Under Operating Leases165.4 211.6 
Deferred Credits and Other Noncurrent Liabilities67.1 67.8 
TOTAL NONCURRENT LIABILITIES7,565.5 7,809.6 
TOTAL LIABILITIES8,609.8 8,693.0 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
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 Earnings1,688.0 1,518.5 
Accumulated Other Comprehensive Income (Loss)(10.5)(11.6)
TOTAL COMMON SHAREHOLDER’S EQUITY2,715.0 2,544.4 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$11,324.8 $11,237.4 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
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INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20202019
OPERATING ACTIVITIES  
Net Income$232.8 $248.0 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: 
Depreciation and Amortization303.6 261.6 
Rockport Plant, Unit 2 Operating Lease Amortization51.9 58.9 
Deferred Income Taxes(6.1)(29.9)
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net21.3 (11.6)
Allowance for Equity Funds Used During Construction(8.8)(16.4)
Mark-to-Market of Risk Management Contracts5.6 (1.6)
Amortization of Nuclear Fuel67.2 71.6 
Pension Contributions to Qualified Plan Trust(6.4)0 
Deferred Fuel Over/Under-Recovery, Net23.4 (20.0)
Change in Other Noncurrent Assets40.8 46.0 
Change in Other Noncurrent Liabilities30.2 13.8 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net32.2 50.5 
Fuel, Materials and Supplies(15.4)(4.6)
Accounts Payable(0.9)(7.3)
Accrued Taxes, Net(84.4)(49.4)
Rockport Plant, Unit 2 Operating Lease Payments(36.9)(36.9)
Other Current Assets6.6 7.8 
Other Current Liabilities(59.1)(49.7)
Net Cash Flows from Operating Activities597.6 530.8 
INVESTING ACTIVITIES  
Construction Expenditures(409.1)(431.7)
Change in Advances to Affiliates, Net(0.1)(0.5)
Purchases of Investment Securities(1,290.0)(915.7)
Sales of Investment Securities1,257.1 871.4 
Acquisitions of Nuclear Fuel(68.4)(91.9)
Other Investing Activities8.3 10.5 
Net Cash Flows Used for Investing Activities(502.2)(557.9)
FINANCING ACTIVITIES  
Issuance of Long-term Debt – Nonaffiliated0 62.9 
Change in Advances from Affiliates, Net44.7 101.3 
Retirement of Long-term Debt – Nonaffiliated(71.1)(73.6)
Principal Payments for Finance Lease Obligations(4.8)(4.0)
Dividends Paid on Common Stock(63.7)(60.0)
Other Financing Activities0.3 0.6 
Net Cash Flows from (Used for) Financing Activities(94.6)27.2 
Net Increase in Cash and Cash Equivalents0.8 0.1 
Cash and Cash Equivalents at Beginning of Period2.0 2.4 
Cash and Cash Equivalents at End of Period$2.8 $2.5 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$97.5 $98.7 
Net Cash Paid for Income Taxes59.7 40.2 
Noncash Acquisitions Under Finance Leases1.9 8.1 
Construction Expenditures Included in Current Liabilities as of September 30,57.6 76.3 
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,1.0 0 
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage2.4 0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
99







OHIO POWER COMPANY AND SUBSIDIARIES

100





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

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 Three Months EndedNine Months Ended
 September 30,September 30,
2020201920202019
 (in millions of KWhs)
Retail:    
Residential4,165 4,120 11,140 11,034 
Commercial3,781 4,067 10,454 11,072 
Industrial3,380 3,689 9,855 10,936 
Miscellaneous22 26 82 83 
Total Retail (a)11,348 11,902 31,531 33,125 
Wholesale (b)502 453 1,347 1,531 
Total KWhs11,850 12,355 32,878 34,656 

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

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

Summary of Heating and Cooling Degree Days
 Three Months EndedNine Months Ended
 September 30,September 30,
2020201920202019
 (in degree days)
Actual – Heating (a)2 — 1,767 2,006 
Normal – Heating (b)6 6 2,086 2,072 
Actual – Cooling (c)809 872 1,126 1,176 
Normal – Cooling (b)682 672 986 973 

(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.
101





Third Quarter of 2020 Compared to Third Quarter of 2019
Reconciliation of Third Quarter of 2019 to Third Quarter of 2020
Net Income
(in millions)
Third Quarter of 2019$69.1 
Changes in Gross Margin:
Retail Margins56.3 
Margins from Off-system Sales0.5 
Transmission Revenues4.4 
Other Revenues3.5 
Total Change in Gross Margin64.7 
Changes in Expenses and Other:
Other Operation and Maintenance(43.4)
Depreciation and Amortization(16.7)
Taxes Other Than Income Taxes(5.8)
Interest Income(0.4)
Allowance for Equity Funds Used During Construction(0.2)
Non-Service Cost Components of Net Periodic Benefit Cost0.1 
Interest Expense(1.5)
Total Change in Expenses and Other(67.9)
Income Tax Expense(6.9)
Third Quarter of 2020$59.0 

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 $56 million primarily due to the following:
•A $52 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.
•An $18 million increase in rider revenues associated with the DIR. This increase was partially offset in other expense items below.
•A $5 million increase in revenues associated with the Universal Service Fund (USF). This increase was offset in Other Operation and Maintenance expenses below.
•A $3 million increase in revenues associated with smart grid riders. This increase was partially offset in other expense items below.
These increases were partially offset by:
•A $10 million decrease in usage primarily in the commercial and residential classes.
•A $6 million decrease due to the OVEC PPA rider which was replaced by the Legacy Generation Resource Rider (LGRR). This decrease was offset in Margins from Off-system Sales and Other Revenues below.
•A $3 million decrease in revenues associated with a vegetation management rider. This decrease was partially offset in Other Operation and Maintenance expenses below.
•Transmission Revenues increased $4 million primarily due to increased investment in transmission assets.
•Other Revenues increased $4 million primarily due to third-party LGRR revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins above.


102





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

•Other Operation and Maintenance expenses increased $43 million primarily due to the following:
•A $43 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses. This increase was offset in Gross Margin above.
•A $5 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 in Retail Margins above.
These increases were partially offset by:
•A $5 million decrease in recoverable distribution expenses related to vegetation management. This decrease was offset in Retail Margins above.
•Depreciation and Amortization expensesincreased $17 million primarily due to the following:
•A $9 million increase in recoverable DIR depreciation expense. This increase was partially offset in Retail Margins above.
•A $5 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
•Taxes Other Than Income Taxes increased $6 million primarily due to property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
•Income Tax Expense increased $7 million primarily due to the recognition of a discrete tax adjustment which was primarily attributable to the filing of the 2019 Federal Income Tax return in the third quarter of 2020.
103





Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019
Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020
Net Income
(in millions)
Nine Months Ended September 30, 2019$247.7 
Changes in Gross Margin:
Retail Margins6.0 
Margins from Off-system Sales7.3 
Transmission Revenues22.8 
Other Revenues12.2 
Total Change in Gross Margin48.3 
Changes in Expenses and Other:
Other Operation and Maintenance(28.3)
Depreciation and Amortization(27.6)
Taxes Other Than Income Taxes(10.9)
Interest Income(1.9)
Carrying Costs Income0.6 
Allowance for Equity Funds Used During Construction(4.8)
Non-Service Cost Components of Net Periodic Benefit Cost0.3 
Interest Expense(10.3)
Total Change in Expenses and Other(82.9)
Income Tax Expense1.9 
Nine Months Ended September 30, 2020$215.0 

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 $6 million primarily due to the following:
•A $74 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 $48 million increase in rider revenues associated with the DIR. This increase was partially offset in other expense items below.
•A $15 million increase in revenues associated with smart grid riders. This increase was partially offset in other expense items below.
•A $15 million increase in revenues associated with the USF. This increase was offset in Other Operation and Maintenance expenses below.
These increases were partially offset by:
•A $58 million decrease due to a reversal of a regulatory provision in the first quarter of 2019.
•A $23 million decrease in Deferred Asset Phase-In-Recovery Rider revenues which ended in the second quarter of 2019. This decrease was partially offset in Depreciation and Amortization expenses below.
•A $21 million decrease due to the OVEC PPA rider which was replaced by the LGRR. This decrease was offset in Margins from Off-system Sales and Other Revenues below.
•A $17 million net decrease in margin for the Rate Stability Rider including associated amortizations which ended in the third quarter of 2019.
•A $12 million decrease in usage primarily in the commercial class.
•A $9 million decrease in revenues associated with a vegetation management rider. This decrease was partially offset in Other Operation and Maintenance expenses below.
•A $5 million decrease due to a PUCO order to refund unused 2018 major storm reserve collections to customers. This decrease was offset in Other Operation and Maintenance expenses below.

104





•Margins from Off-system Sales increased $7 million primarily due to:
•An $18 million increase due to higher OVEC PPA deferrals. This increase was offset in Retail Margins above.
This increase was partially offset by:
•A $12 million decrease in sales due to lower market prices and decreased sales volumes in 2020. This decrease was offset in Retail Margins above.
•Transmission Revenues increased $23 million primarily due to the following:
•A $16 million increase from the annual transmission formula rate true-up.
•A $6 million increase due to additional investment in transmission assets.
•Other Revenues increased $12 million primarily due to third-party LGRR revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins above.

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

•Other Operation and Maintenance expenses increased $28 million primarily due to the following:
•A $29 million increase in transmission expenses primarily due to a $57 million increase in recoverable PJM expenses partially offset by a $28 million decrease related to the annual transmission formula rate true-up. This increase was offset in Gross Margin above.
•A $15 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 in Retail Margins above.
These increases were partially offset by:
•A $6 million decrease in recoverable distribution expenses related to vegetation management. This decrease was offset in Retail Margins above.
•A $5 million decrease due to a PUCO order to refund unused 2018 major storm reserve collections to customers. This decrease was offset in Retail Margins above.
•Depreciation and Amortization expensesincreased $28 million primarily due to the following:
•A $16 million increase in recoverable DIR depreciation expense. This increase was partially offset in Retail Margins above.
•A $14 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
•An $11 million increase due to lower deferred equity amortizations associated with the Deferred Asset Phase-In-Recovery Rider which ended in the second quarter of 2019.
•A $6 million increase in recoverable smart grid expense. This increase was offset in Retail Margins above.
These increases were partially offset by:
•A $24 million decrease in amortizations associated with the Deferred Asset Phase-In-Recovery Rider which ended in the second quarter of 2019. This decrease was offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $11 million primarily due to the following:
•A $16 million increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
This increase was partially offset by:
•A $4 million decrease in excise taxes due to lower demand in 2020. This decrease was offset in Retail Margins above.
•Allowance for Equity Funds Used During Construction decreased $5 million primarily due to adjustments that resulted from 2019 FERC audit findings and a decrease in AFUDC base.
•Interest Expense increased $10 million primarily due to higher long-term debt balances.
•Income Tax Expense decreased $2 million due to a decrease in pretax book income, partially offset by the recognition of a discrete tax adjustment.
105






OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
 September 30,September 30,
 2020201920202019
REVENUES    
Electricity, Transmission and Distribution$730.4 $698.6 $2,031.4 $2,127.4 
Sales to AEP Affiliates8.3 9.0 33.0 18.2 
Other Revenues2.3 3.0 7.3 8.4 
TOTAL REVENUES741.0 710.6 2,071.7 2,154.0 
EXPENSES    
Purchased Electricity for Resale149.3 158.3 412.3 454.0 
Purchased Electricity from AEP Affiliates24.1 40.6 96.8 120.4 
Amortization of Generation Deferrals0 8.8 0 65.3 
Other Operation244.6 194.9 608.5 565.7 
Maintenance33.7 40.0 92.2 106.7 
Depreciation and Amortization74.1 57.4 204.4 176.8 
Taxes Other Than Income Taxes117.8 112.0 337.8 326.9 
TOTAL EXPENSES643.6 612.0 1,752.0 1,815.8 
OPERATING INCOME97.4 98.6 319.7 338.2 
Other Income (Expense):    
Interest Income0.4 0.8 0.8 2.7 
Carrying Costs Income0.3 0.3 1.3 0.7 
Allowance for Equity Funds Used During Construction4.6 4.8 9.3 14.1 
Non-Service Cost Components of Net Periodic Benefit Cost3.8 3.7 11.3 11.0 
Interest Expense(29.4)(27.9)(88.4)(78.1)
INCOME BEFORE INCOME TAX EXPENSE77.1 80.3 254.0 288.6 
Income Tax Expense18.1 11.2 39.0 40.9 
NET INCOME$59.0 $69.1 $215.0 $247.7 
The common stock of OPCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
106





OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)
Three Months EndedNine Months Ended
September 30,September 30,
2020201920202019
Net Income$59.0 $69.1 $215.0 $247.7 
OTHER COMPREHENSIVE LOSS, NET OF TAXES    
Cash Flow Hedges, Net of Tax of $0 and $(0.1) for the Three Months Ended September 30, 2020 and 2019, Respectively, and $0 and $(0.3) for the Nine Months Ended September 30, 2020 and 2019, Respectively0 (0.3)0 (1.0)
TOTAL COMPREHENSIVE INCOME$59.0 $68.8 $215.0 $246.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
107





OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)
Common
Stock		Paid-in
Capital		Retained
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018$321.2 $838.8 $1,136.4 $1.0 $2,297.4 
Common Stock Dividends(25.0)(25.0)
Net Income128.0 128.0 
Other Comprehensive Loss(0.3)(0.3)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2019321.2 838.8 1,239.4 0.7 2,400.1 
Common Stock Dividends  (60.0) (60.0)
Net Income  50.6  50.6 
Other Comprehensive Loss   (0.4)(0.4)
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2019321.2 838.8 1,230.0 0.3 2,390.3 
Net Income69.1 69.1 
Other Comprehensive Loss(0.3)(0.3)
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2019$321.2 $838.8 $1,299.1 $0 $2,459.1 
     
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, 2020321.2 838.8 1,461.0 0 2,621.0 
Common Stock Dividends(21.8)(21.8)
Net Income59.0 59.0 
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2020$321.2 $838.8 $1,498.2 $0 $2,658.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
108





OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2020 and December 31, 2019
(in millions)
(Unaudited)
 September 30,December 31,
 20202019
CURRENT ASSETS  
Cash and Cash Equivalents$6.6 $3.7 
Accounts Receivable:  
Customers18.4 53.0 
Affiliated Companies61.0 59.3 
Accrued Unbilled Revenues20.1 20.3 
Miscellaneous3.9 0.5 
Allowance for Uncollectible Accounts(0.7)(0.7)
Total Accounts Receivable102.7 132.4 
Materials and Supplies67.0 52.3 
Renewable Energy Credits28.7 30.9 
Accrued Tax Benefits4.3 11.5 
Prepayments and Other Current Assets13.2 7.7 
TOTAL CURRENT ASSETS222.5 238.5 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Transmission2,768.1 2,686.3 
Distribution5,545.8 5,323.5 
Other Property, Plant and Equipment882.4 765.8 
Construction Work in Progress455.9 394.4 
Total Property, Plant and Equipment9,652.2 9,170.0 
Accumulated Depreciation and Amortization2,350.1 2,263.0 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET7,302.1 6,907.0 
OTHER NONCURRENT ASSETS  
Regulatory Assets401.7 351.8 
Deferred Charges and Other Noncurrent Assets340.6 546.3 
TOTAL OTHER NONCURRENT ASSETS742.3 898.1 
TOTAL ASSETS$8,266.9 $8,043.6 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
109





OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2020 and December 31, 2019
(dollars in millions)
(Unaudited)
 September 30,December 31,
 20202019
CURRENT LIABILITIES  
Advances from Affiliates$215.9 $131.0 
Accounts Payable:  
General184.5 233.7 
Affiliated Companies90.7 103.6 
Long-term Debt Due Within One Year – Nonaffiliated0.1 0.1 
Risk Management Liabilities8.2 7.3 
Customer Deposits58.2 70.6 
Accrued Taxes314.5 587.9 
Obligations Under Operating Leases12.5 12.5 
Other Current Liabilities141.1 151.2 
TOTAL CURRENT LIABILITIES1,025.7 1,297.9 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated2,429.8 2,081.9 
Long-term Risk Management Liabilities105.1 96.3 
Deferred Income Taxes904.6 849.4 
Regulatory Liabilities and Deferred Investment Tax Credits1,018.5 1,090.9 
Obligations Under Operating Leases76.7 76.0 
Deferred Credits and Other Noncurrent Liabilities48.3 42.7 
TOTAL NONCURRENT LIABILITIES4,583.0 4,237.2 
TOTAL LIABILITIES5,608.7 5,535.1 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
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 Earnings1,498.2 1,348.5 
TOTAL COMMON SHAREHOLDER’S EQUITY2,658.2 2,508.5 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$8,266.9 $8,043.6 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
110





OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2020 and 2019
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20202019
OPERATING ACTIVITIES  
Net Income$215.0 $247.7 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and Amortization204.4 176.8 
Amortization of Generation Deferrals0 65.3 
Deferred Income Taxes35.6 16.8 
Allowance for Equity Funds Used During Construction(9.3)(14.1)
Mark-to-Market of Risk Management Contracts9.7 13.3 
Property Taxes225.1 197.7 
Refund of Global Settlement0 (12.4)
Reversal of Regulatory Provision0 (56.2)
Change in Other Noncurrent Assets(93.8)(47.5)
Change in Other Noncurrent Liabilities(58.3)(51.1)
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net33.4 90.0 
Materials and Supplies(19.8)(9.6)
Accounts Payable(19.9)(12.3)
Accrued Taxes, Net(266.2)(245.9)
Other Current Assets(2.5)(9.0)
Other Current Liabilities(23.3)(40.0)
Net Cash Flows from Operating Activities230.1 309.5 
INVESTING ACTIVITIES  
Construction Expenditures(604.6)(570.6)
Other Investing Activities14.1 20.0 
Net Cash Flows Used for Investing Activities(590.5)(550.6)
FINANCING ACTIVITIES  
Issuance of Long-term Debt – Nonaffiliated347.0 444.3 
Change in Advances from Affiliates, Net84.9 (96.5)
Retirement of Long-term Debt – Nonaffiliated(0.1)(48.0)
Principal Payments for Finance Lease Obligations(3.5)(2.6)
Dividends Paid on Common Stock(65.6)(85.0)
Other Financing Activities0.6 1.1 
Net Cash Flows from Financing Activities363.3 213.3 
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash for Securitized Funding2.9 (27.8)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period3.7 32.5 
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period$6.6 $4.7 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$69.7 $61.3 
Net Cash Paid (Received) for Income Taxes(6.0)25.7 
Noncash Acquisitions Under Finance Leases5.2 8.6 
Construction Expenditures Included in Current Liabilities as of September 30,75.9 99.9 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
111







PUBLIC SERVICE COMPANY OF OKLAHOMA
112





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

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 Three Months EndedNine Months Ended
 September 30,September 30,
2020201920202019
 (in millions of KWhs)
Retail:    
Residential2,019 2,172 4,838 4,981 
Commercial1,358 1,497 3,549 3,818 
Industrial1,461 1,642 4,299 4,665 
Miscellaneous347 378 912 950 
Total Retail5,185 5,689 13,598 14,414 
Wholesale130 224 261 617 
Total KWhs5,315 5,913 13,859 15,031 

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

Summary of Heating and Cooling Degree Days
 Three Months EndedNine Months Ended
 September 30,September 30,
2020201920202019
 (in degree days)
Actual – Heating (a)1 — 874 1,199 
Normal – Heating (b)1 1 1,078 1,077 
Actual – Cooling (c)1,274 1,593 1,979 2,206 
Normal – Cooling (b)1,412 1,397 2,088 2,072 

(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.
113





Third Quarter of 2020 Compared to Third Quarter of 2019
Reconciliation of Third Quarter of 2019 to Third Quarter of 2020
Net Income
(in millions)
Third Quarter of 2019$100.3 
Changes in Gross Margin:
Retail Margins (a)(20.7)
Margins from Off-system Sales(1.3)
Transmission Revenues(0.5)
Other Revenues(0.2)
Total Change in Gross Margin(22.7)
Changes in Expenses and Other:
Other Operation and Maintenance(2.5)
Depreciation and Amortization(1.0)
Taxes Other Than Income Taxes(1.0)
Interest Income(0.4)
Allowance for Equity Funds Used During Construction0.5 
Interest Expense1.5 
Total Change in Expenses and Other(2.9)
Income Tax Expense5.6 
Third Quarter of 2020$80.3 

(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 decreased $41$21 million primarily due to the following:
A $25•An $18 million decrease in weather-related usage primarily driven bydue to a 23%20% decrease in cooling degree days.degree-days.
An $8•A $4 million decrease in weather-normalized margin occurring across all retail classes.
A $6 million decrease primarily due to a decrease in rates in West Virginia and Virginia.revenue from rate riders. This decrease iswas partially offset by a corresponding decrease in Other Operation and Maintenance expensesother expense items below.


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


•Other Operation and Maintenance expenses decreased $13increased $3 million primarily due to the following:
•A $7$4 million decreaseincrease in storm-relatedtransmission expenses due to an increase in recoverable SPP expenses. This increase was partially offset in Retail Margins above.
•A $2 million increase in customer-related expenses primarily related to energy efficiency programs. This increase was partially offset in Retail Margins above.
These increases were partially offset by:
•A $4 million decrease in generation plant maintenancedistribution expenses.
Depreciation and Amortization expenses increased $5 million primarily due to a higher depreciable base.
•Income Tax Expense decreased $16$6 million primarily due to a decrease in pretax book income and the recording of federal income tax adjustments.income.
114







Nine Months Ended September 30, 20172020 Compared to Nine Months Ended September 30, 20162019
Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020
Net Income
(in millions)
Nine Months Ended September 30, 2019$148.4 
Changes in Gross Margin:
Retail Margins (a)(15.1)
Margin from Off-system Sales(1.7)
Transmission Revenues(0.8)
Other Revenues3.4 
Total Change in Gross Margin(14.2)
Changes in Expenses and Other:
Other Operation and Maintenance(21.3)
Depreciation and Amortization(4.4)
Taxes Other Than Income Taxes(2.8)
Interest Income(0.5)
Allowance for Equity Funds Used During Construction1.7 
Interest Expense4.4 
Total Change in Expenses and Other(22.9)
Income Tax Expense5.1 
Nine Months Ended September 30, 2020$116.4 
Reconciliation of Nine Months Ended September 30, 2016 to Nine Months Ended September 30, 2017
Net Income
(in millions)
 
Nine Months Ended September 30, 2016 $303.8
   
Changes in Gross Margin:  
Retail Margins (93.7)
Off-system Sales (0.1)
Transmission Revenues 25.9
Other Revenues 3.2
Total Change in Gross Margin (64.7)
   
Changes in Expenses and Other:  
Other Operation and Maintenance (8.3)
Depreciation and Amortization (14.1)
Taxes Other Than Income Taxes 0.6
Interest Income 0.3
Carrying Costs Income 0.8
Allowance for Equity Funds Used During Construction (2.9)
Interest Expense (2.8)
Total Change in Expenses and Other (26.4)
   
Income Tax Expense 36.0
   
Nine Months Ended September 30, 2017 $248.7
(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 decreased $94$15 million primarily due to the following:
•A $72$15 million decrease in weather-related usage primarily driven bydue to a 30% decrease in heating degree days and an 18%10% decrease in cooling degree days.degree-days.
•A $14 million decrease primarily due to prior year recognition of deferred billing in West Virginia as approved by the WVPSC.
A $3$10 million decrease in revenue from rate riders. This decrease was partially offset in other expense items below.
•A $7 million decrease due to customer refunds related to Tax Reform. This decrease is partially offset in Income Tax Expense below.
These decreases were partially offset by:
•A $10 million increase due to new base rates implemented in April 2019.
•A $7 million increase in weather-normalized margin primarily driven by the commercial class.margins.
Transmission•Other Revenues increased $26$3 million primarily due to increase in formula rates driven by continued investment in transmission assets.business development revenue. This increase is partiallywas offset in Other Operation and Maintenance expensesother expense items below.


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


•Other Operation and Maintenance expenses increased $8$21 million primarily due to the following:
•A $13 million increase in recoverable PJM transmission expenses. This increase in expense is offset within Gross Margin above.
A $6 million gain on the sale of property in 2016.
These increases were partially offset by:
An $8 million decrease in storm-related expenses.
A $5 million decrease in employee-related expenses.
Depreciation and Amortization expenses increased $14 million primarily due to a higher depreciable base.
Income Tax Expense decreased $36 million primarily due to a decrease in pretax book income and the recording of federal income tax adjustments.



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2017 and 2016
(in millions)
(Unaudited)
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2017 2016 2017 2016
REVENUES        
Electric Generation, Transmission and Distribution $674.4
 $739.0
 $2,045.0
 $2,153.3
Sales to AEP Affiliates 41.9
 36.4
 130.6
 109.0
Other Revenues 3.0
 2.8
 11.8
 9.4
TOTAL REVENUES 719.3
 778.2
 2,187.4
 2,271.7
         
EXPENSES  
    
  
Fuel and Other Consumables Used for Electric Generation 178.6
 190.1
 498.3
 494.1
Purchased Electricity for Resale 61.1
 69.2
 217.1
 240.9
Other Operation 115.7
 117.6
 366.2
 349.4
Maintenance 55.8
 66.8
 187.8
 196.3
Depreciation and Amortization 102.8
 98.1
 304.1
 290.0
Taxes Other Than Income Taxes 32.3
 32.0
 93.3
 93.9
TOTAL EXPENSES 546.3
 573.8
 1,666.8
 1,664.6
         
OPERATING INCOME 173.0
 204.4
 520.6
 607.1
         
Other Income (Expense):  
    
  
Interest Income 0.3
 0.3
 1.1
 0.8
Carrying Costs Income 0.4
 —
 1.0
 0.2
Allowance for Equity Funds Used During Construction 2.7
 4.5
 6.2
 9.1
Interest Expense (47.2) (46.4) (143.5) (140.7)
         
INCOME BEFORE INCOME TAX EXPENSE 129.2
 162.8
 385.4
 476.5
         
Income Tax Expense 43.2
 58.7
 136.7
 172.7
         
NET INCOME $86.0
 $104.1
 $248.7
 $303.8
The common stock of APCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2017 and 2016
(in millions)
(Unaudited)
  
  Three Months Ended
 Nine Months Ended
  September 30, September 30,
  2017 2016 2017 2016
Net Income $86.0
 $104.1
 $248.7
 $303.8
         
OTHER COMPREHENSIVE LOSS, NET OF TAXES    
  
  
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2017 and 2016, Respectively, and $(0.3) and $(0.3) for the Nine Months Ended September 30, 2017 and 2016, Respectively (0.1) (0.2) (0.5) (0.6)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2017 and 2016, Respectively, and $(0.4) and $(0.5) for the Nine Months Ended September 30, 2017 and 2016, Respectively (0.3) (0.3) (0.9) (1.0)
         
TOTAL OTHER COMPREHENSIVE LOSS (0.4) (0.5) (1.4) (1.6)
         
TOTAL COMPREHENSIVE INCOME $85.6
 $103.6
 $247.3
 $302.2
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2017 and 2016
(in millions)
(Unaudited)
  
Common
Stock
 
Paid-in
Capital
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 Total
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2015 $260.4
 $1,828.7
 $1,388.7
 $(2.8) $3,475.0
           
Common Stock Dividends  
  
 (225.0)  
 (225.0)
Net Income  
  
 303.8
  
 303.8
Other Comprehensive Loss  
  
  
 (1.6) (1.6)
TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2016 $260.4
 $1,828.7
 $1,467.5
 $(4.4) $3,552.2
           
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2016 $260.4
 $1,828.7
 $1,502.8
 $(8.4) $3,583.5
           
Common Stock Dividends  
  
 (90.0)  
 (90.0)
Net Income  
  
 248.7
  
 248.7
Other Comprehensive Loss  
  
  
 (1.4) (1.4)
TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2017 $260.4
 $1,828.7
 $1,661.5
 $(9.8) $3,740.8
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2017 and December 31, 2016
(in millions)
(Unaudited)
  September 30, December 31,
  2017 2016
CURRENT ASSETS    
Cash and Cash Equivalents $2.9
 $2.7
Restricted Cash for Securitized Funding 8.3
 15.8
Advances to Affiliates 23.6
 24.1
Accounts Receivable:    
Customers 96.8
 131.4
Affiliated Companies 59.5
 54.4
Accrued Unbilled Revenues 41.1
 52.7
Miscellaneous 1.3
 0.9
Allowance for Uncollectible Accounts (2.7) (3.5)
Total Accounts Receivable 196.0
 235.9
Fuel 96.3
 112.0
Materials and Supplies 100.8
 98.8
Risk Management Assets 30.3
 2.6
Accrued Tax Benefits 0.4
 4.2
Regulatory Asset for Under-Recovered Fuel Costs 63.5
 68.4
Margin Deposits 11.8
 17.5
Prepayments and Other Current Assets 18.2
 9.7
TOTAL CURRENT ASSETS 552.1
 591.7
     
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Generation 6,393.7
 6,332.8
Transmission 2,904.4
 2,796.9
Distribution 3,703.5
 3,569.1
Other Property, Plant and Equipment 409.8
 373.5
Construction Work in Progress 493.5
 390.3
Total Property, Plant and Equipment 13,904.9
 13,462.6
Accumulated Depreciation and Amortization 3,836.7
 3,636.8
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 10,068.2
 9,825.8
     
OTHER NONCURRENT ASSETS    
Regulatory Assets 1,100.1
 1,121.1
Securitized Assets 288.0
 305.3
Long-term Risk Management Assets 0.6
 —
Deferred Charges and Other Noncurrent Assets 113.6
 133.3
TOTAL OTHER NONCURRENT ASSETS 1,502.3
 1,559.7
     
TOTAL ASSETS $12,122.6
 $11,977.2
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2017 and December 31, 2016
(Unaudited)
  September 30, December 31,
  2017 2016
  (in millions)
CURRENT LIABILITIES    
Advances from Affiliates $69.5
 $79.6
Accounts Payable:  
  
General 235.4
 253.7
Affiliated Companies 75.5
 82.6
Long-term Debt Due Within One Year - Nonaffiliated 149.2
 503.1
Risk Management Liabilities 0.9
 0.3
Customer Deposits 84.0
 83.1
Accrued Taxes 64.0
 107.6
Accrued Interest 71.4
 40.6
Other Current Liabilities 99.2
 129.5
TOTAL CURRENT LIABILITIES 849.1
 1,280.1
     
NONCURRENT LIABILITIES    
Long-term Debt - Nonaffiliated 3,830.1
 3,530.8
Long-term Risk Management Liabilities 0.3
 0.9
Deferred Income Taxes 2,796.7
 2,672.3
Regulatory Liabilities and Deferred Investment Tax Credits 634.4
 627.8
Asset Retirement Obligations 101.2
 108.8
Employee Benefits and Pension Obligations 92.2
 108.5
Deferred Credits and Other Noncurrent Liabilities 77.8
 64.5
TOTAL NONCURRENT LIABILITIES 7,532.7
 7,113.6
     
TOTAL LIABILITIES 8,381.8
 8,393.7
     
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 1,661.5
 1,502.8
Accumulated Other Comprehensive Income (Loss) (9.8) (8.4)
TOTAL COMMON SHAREHOLDER’S EQUITY 3,740.8
 3,583.5
     
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $12,122.6
 $11,977.2
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2017 and 2016
(in millions)
(Unaudited)
  Nine Months Ended September 30,
  2017 2016
OPERATING ACTIVITIES  
  
Net Income $248.7
 $303.8
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
Depreciation and Amortization 304.1
 290.0
Deferred Income Taxes 121.7
 100.9
Carrying Costs Income (1.0) (0.2)
Allowance for Equity Funds Used During Construction (6.2) (9.1)
Mark-to-Market of Risk Management Contracts (28.3) 18.4
Pension Contributions to Qualified Plan Trust (10.2) (8.8)
Property Taxes 29.8
 29.2
Deferred Fuel Over/Under-Recovery, Net 4.9
 19.0
Change in Other Noncurrent Assets 8.3
 (5.1)
Change in Other Noncurrent Liabilities 7.9
 (23.0)
Changes in Certain Components of Working Capital:  
  
Accounts Receivable, Net 39.9
 (20.5)
Fuel, Materials and Supplies 14.0
 (1.2)
Accounts Payable 6.2
 4.9
Accrued Taxes, Net (44.2) (13.9)
Other Current Assets (2.5) (0.2)
Other Current Liabilities 9.1
 (4.1)
Net Cash Flows from Operating Activities 702.2
 680.1
     
INVESTING ACTIVITIES  
  
Construction Expenditures (560.0) (472.7)
Change in Restricted Cash for Securitized Funding 7.5
 7.0
Change in Advances to Affiliates, Net 0.5
 1.2
Other Investing Activities 11.8
 10.6
Net Cash Flows Used for Investing Activities (540.2) (453.9)
     
FINANCING ACTIVITIES  
  
Issuance of Long-term Debt - Nonaffiliated 320.9
 314.1
Change in Advances from Affiliates, Net (10.1) (96.9)
Retirement of Long-term Debt - Nonaffiliated (377.9) (213.6)
Principal Payments for Capital Lease Obligations (5.2) (4.7)
Dividends Paid on Common Stock (90.0) (225.0)
Other Financing Activities 0.5
 0.4
Net Cash Flows Used for Financing Activities (161.8) (225.7)
     
Net Increase in Cash and Cash Equivalents 0.2
 0.5
Cash and Cash Equivalents at Beginning of Period 2.7
 2.8
Cash and Cash Equivalents at End of Period $2.9
 $3.3
     
SUPPLEMENTARY INFORMATION  
  
Cash Paid for Interest, Net of Capitalized Amounts $107.1
 $113.2
Net Cash Paid for Income Taxes 24.4
 55.8
Noncash Acquisitions Under Capital Leases 2.9
 2.1
Construction Expenditures Included in Current Liabilities as of September 30, 107.2
 66.8
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.




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 Nine Months Ended
 September 30, September 30,
 2017 2016 2017 2016
 (in millions of KWhs)
Retail: 
  
  
  
Residential1,404
 1,619
 4,015
 4,344
Commercial1,313
 1,405
 3,640
 3,780
Industrial1,978
 1,996
 5,793
 5,876
Miscellaneous16
 15
 50
 50
Total Retail4,711
 5,035
 13,498
 14,050
        
Wholesale2,807
 2,613
 8,567
 7,038
        
Total KWhs7,518
 7,648
 22,065
 21,088

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 Nine Months Ended
 September 30, September 30,
 2017 2016 2017 2016
 (in degree days)
Actual - Heating (a)—
 —
 1,816
 2,196
Normal - Heating (b)11
 10
 2,430
 2,449
        
Actual - Cooling (c)504
 741
 764
 1,011
Normal - Cooling (b)574
 571
 835
 835

(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.


Third Quarter of 2017 Compared to Third Quarter of 2016
Reconciliation of Third Quarter of 2016 to Third Quarter of 2017
Net Income
(in millions)
   
Third Quarter of 2016 $75.4
   
Changes in Gross Margin:  
Retail Margins (a) (4.4)
Transmission Revenues (6.2)
Other Revenues (1.5)
Total Change in Gross Margin (12.1)
   
Changes in Expenses and Other:  
Other Operation and Maintenance (7.4)
Asset Impairments and Other Related Charges 10.5
Depreciation and Amortization (5.9)
Taxes Other Than Income Taxes (1.4)
Other Income 0.1
Interest Expense (0.8)
Total Change in Expenses and Other (4.9)
   
Income Tax Expense 6.5
   
Third Quarter of 2017 $64.9

(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 decreased $4 million primarily due to the following:
An $18 million decrease in weather-related usage primarily due to a 32% decrease in cooling degree days.
A $6 million decrease in weather-normalized margins.
A $5 million decrease in FERC generation wholesale municipal and cooperative revenues primarily due to formula rate adjustments.
A $2 million decrease due to increased costs for power acquired under the Unit Power Agreement between AEGCo and I&M.
These decreases were partially offset by:
A $13 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 $9 million increase related to over/under recovery of riders.
A $2 million decrease in PJM related expenses primarily due to reduced FTRs.
Transmission Revenues decreased $6 million primarily due to an annual formula rate true-up and reduced net PJM Network Integration Transmission Service revenues resulting from increased affiliated transmission-related charges.



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

Other Operation and Maintenance expenses increased $7 million primarily due to the following:
A $9$20 million increase in transmission expenses primarily due to anthe annual transmission formula rate true-up. This increase was partially offset in Retail Margins above.
•A $5 million increase in recoverable PJMcustomer-related expenses primarily related to energy efficiency programs. This increase was partially offset in Retail Margins above.
•A $4 million increase in business development expenses. This increase was partially offset in expense is offset within Retail MarginsOther Revenues above.
•A $3$4 million increase in nuclear expenses primarily due to an increase in refueling outage amortization and refueling outage expenses not deferred, partially offset by a decrease in employee-relatedmaintenance of overhead lines for non-storm related expenses.
These increases were partially offset by:
•A $3$7 million decrease in distribution expenses primarily due to decreased vegetation management.at various generation plants.
Asset Impairments and Other Related Charges decreased $11 million due to the impairment of I&M’s Price River coal reserves in 2016.
Depreciation and Amortization expensesincreased $6 million primarily due to higher depreciable base.
Income Tax Expense decreased $7 million primarily due to a decrease in pretax book income and the regulatory accounting treatment of state income taxes.


Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016
Reconciliation of Nine Months Ended September 30, 2016 to Nine Months Ended September 30, 2017
Net Income
(in millions)
   
Nine Months Ended September 30, 2016 $201.4
   
Changes in Gross Margin:  
Retail Margins (a) (11.2)
Off-system Sales 0.5
Transmission Revenues (23.0)
Other Revenues (2.1)
Total Change in Gross Margin (35.8)
   
Changes in Expenses and Other:  
Other Operation and Maintenance (39.3)
Asset Impairments and Other Related Charges 10.5
Depreciation and Amortization (11.6)
Taxes Other Than Income Taxes 3.2
Other Income (0.4)
Interest Expense (6.7)
Total Change in Expenses and Other (44.3)
   
Income Tax Expense 22.5
   
Nine Months Ended September 30, 2017 $143.8

(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 decreased $11 million primarily due to the following:
A $33 million decrease in FERC generation wholesale municipal and cooperative revenues primarily due to an annual formula rate true-up and other rate adjustments.
A $29 million decrease in weather-related usage primarily due to a 24% decrease in cooling degree days and a 17% decrease in heating degree days.
An $11 million decrease in weather-normalized margins.
•A $5 million decrease due to increased costs for power acquired under the Unit Power Agreement between AEGCo and I&M.
These decreases were partially offset by:
A $47 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 $19 million increase related to over/under recoverycapitalization of riders.
A $2 million decrease in PJM related expenses primarily due to reduced FTRs.previously expensed North Central Wind Energy Facilities costs.
Transmission Revenues decreased $23
115





•Depreciation and Amortization expenses increased $4 million primarily due to an annual formula rate true-up and reduced net PJM Network Integration Transmission Service revenues resulting from increased affiliated transmission-related charges.
a higher depreciable base.


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

Other Operation and Maintenance expenses increased $39decreased $4 million primarily due to the following:
lower interest rates on long-term debt.
A $38 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses. This increase in expense was offset within Retail Margins above.
A $7 million increase in nuclear expenses primarily due to an increase in refueling outage amortization, partially offset by refueling outage expenses not deferred, a decrease in employee-related expenses and material write-off.
A $3 million increase in distribution expenses primarily due to increased vegetation management.
These increases were partially offset by:
An $8 million decrease primarily due to employee-related expenses.
Asset Impairments and Other Related Charges decreased $11 million due to the impairment of I&M’s Price River coal reserves in 2016.
Depreciation and Amortization expensesincreased $12 million primarily due to higher depreciable base.
Taxes Other Than Income Taxes decreased $3 million primarily due to property taxes.
Interest Expense increased $7 million primarily due to higher long-term debt balances.
•Income Tax Expensedecreased $23$5 million primarily due to a decrease in pretax book income, partially offset by the recording of favorable federal income tax adjustments in 2016.



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2017 and 2016
(in millions)
(Unaudited)
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2017 2016 2017 2016
REVENUES        
Electric Generation, Transmission and Distribution $537.0
 $574.7
 $1,527.4
 $1,570.8
Other Revenues – Affiliated 17.1
 19.5
 48.2
 68.7
Other Revenues – Nonaffiliated 3.6
 3.4
 9.9
 13.2
TOTAL REVENUES 557.7
 597.6
 1,585.5
 1,652.7
         
EXPENSES  
    
  
Fuel and Other Consumables Used for Electric Generation 76.4
 91.3
 238.2
 236.8
Purchased Electricity for Resale 32.9
 43.7
 101.2
 134.3
Purchased Electricity from AEP Affiliates 62.4
 64.5
 166.2
 165.9
Other Operation 140.5
 138.9
 434.2
 413.9
Maintenance 51.5
 45.7
 153.6
 134.6
Asset Impairments and Other Related Charges —
 10.5
 —
 10.5
Depreciation and Amortization 55.0
 49.1
 154.8
 143.2
Taxes Other Than Income Taxes 23.9
 22.5
 68.3
 71.5
TOTAL EXPENSES 442.6
 466.2
 1,316.5
 1,310.7
         
OPERATING INCOME 115.1
 131.4
 269.0
 342.0
         
Other Income (Expense):  
    
  
Interest Income 2.4
 1.7
 11.5
 9.1
Allowance for Equity Funds Used During Construction 3.5
 4.1
 8.1
 10.9
Interest Expense (27.5) (26.7) (83.0) (76.3)
         
INCOME BEFORE INCOME TAX EXPENSE 93.5
 110.5
 205.6
 285.7
         
Income Tax Expense 28.6
 35.1
 61.8
 84.3
         
NET INCOME $64.9
 $75.4
 $143.8
 $201.4
The common stock of I&M is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2017 and 2016
(in millions)
(Unaudited)
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2017 2016 2017 2016
Net Income $64.9
 $75.4
 $143.8
 $201.4
         
OTHER COMPREHENSIVE INCOME, NET OF TAXES  
    
  
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended September 30, 2017 and 2016, Respectively, and $0.5 and $0.5 for the Nine Months Ended September 30, 2017 and 2016, Respectively 0.3
 0.3
 1.0
 1.0
         
TOTAL COMPREHENSIVE INCOME $65.2
 $75.7
 $144.8
 $202.4
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2017 and 2016
(in millions)
(Unaudited)
 Common
Stock		 Paid-in
Capital		 Retained
Earnings		 Accumulated
Other
Comprehensive
Income (Loss)		 Total
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2015$56.6
 $980.9
 $1,015.6
 $(16.7) $2,036.4
          
Common Stock Dividends 
  
 (93.8)  
 (93.8)
Net Income 
  
 201.4
  
 201.4
Other Comprehensive Income 
  
  
 1.0
 1.0
TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2016$56.6
 $980.9
 $1,123.2
 $(15.7) $2,145.0
  
  
  
  
  
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2016$56.6
 $980.9
 $1,130.5
 $(16.2) $2,151.8
          
Common Stock Dividends 
  
 (93.7)  
 (93.7)
Net Income 
  
 143.8
  
 143.8
Other Comprehensive Income 
  
  
 1.0
 1.0
TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2017$56.6
 $980.9
 $1,180.6
 $(15.2) $2,202.9
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2017 and December 31, 2016
(in millions)
(Unaudited)
  September 30, December 31,
  2017 2016
CURRENT ASSETS    
Cash and Cash Equivalents $1.3
 $1.2
Advances to Affiliates 12.6
 12.5
Accounts Receivable:    
Customers 42.1
 60.2
Affiliated Companies 42.8
 51.0
Accrued Unbilled Revenues 8.4
 1.5
Miscellaneous 1.1
 0.7
Allowance for Uncollectible Accounts (0.3) —
Total Accounts Receivable 94.1
 113.4
Fuel 32.3
 32.3
Materials and Supplies 156.5
 150.8
Risk Management Assets 11.6
 3.5
Accrued Tax Benefits 34.5
 37.7
Regulatory Asset for Under-Recovered Fuel Costs 12.3
 26.1
Accrued Reimbursement of Spent Nuclear Fuel Costs 11.0
 22.1
Prepayments and Other Current Assets 26.9
 19.9
TOTAL CURRENT ASSETS 393.1
 419.5
     
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Generation 4,399.9
 4,056.1
Transmission 1,491.4
 1,472.8
Distribution 2,000.1
 1,899.3
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) 555.9
 550.2
Construction Work in Progress 478.9
 654.2
Total Property, Plant and Equipment 8,926.2
 8,632.6
Accumulated Depreciation, Depletion and Amortization 3,022.5
 3,005.1
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 5,903.7
 5,627.5
     
OTHER NONCURRENT ASSETS    
Regulatory Assets 941.0
 916.6
Spent Nuclear Fuel and Decommissioning Trusts 2,433.0
 2,256.2
Long-term Risk Management Assets 0.5
 —
Deferred Charges and Other Noncurrent Assets 95.9
 121.5
TOTAL OTHER NONCURRENT ASSETS 3,470.4
 3,294.3
     
TOTAL ASSETS $9,767.2
 $9,341.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2017 and December 31, 2016
(dollars in millions)
(Unaudited)
  September 30, December 31,
  2017 2016
CURRENT LIABILITIES    
Advances from Affiliates $177.5
 $215.2
Accounts Payable:    
General 168.6
 179.0
Affiliated Companies 72.2
 75.6
Long-term Debt Due Within One Year – Nonaffiliated
(September 30, 2017 and December 31, 2016 Amounts Include $83.7 and $130.9, Respectively, Related to DCC Fuel)
 462.1
 209.3
Risk Management Liabilities 2.0
 0.3
Customer Deposits 37.3
 34.3
Accrued Taxes 43.8
 77.2
Accrued Interest 14.3
 31.7
Obligations Under Capital Leases 7.3
 9.4
Other Current Liabilities 114.3
 123.4
TOTAL CURRENT LIABILITIES 1,099.4
 955.4
     
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated 2,196.4
 2,262.1
Long-term Risk Management Liabilities 0.2
 0.8
Deferred Income Taxes 1,681.8
 1,527.4
Regulatory Liabilities and Deferred Investment Tax Credits 1,169.6
 1,065.5
Asset Retirement Obligations 1,307.4
 1,257.9
Deferred Credits and Other Noncurrent Liabilities 109.5
 120.4
TOTAL NONCURRENT LIABILITIES 6,464.9
 6,234.1
     
TOTAL LIABILITIES 7,564.3
 7,189.5
     
Rate Matters (Note 4) 
 
Commitments and Contingencies (Note 5) 
 
     
COMMON SHAREHOLDER’S EQUITY    
Common Stock – No Par Value:    
Authorized – 2,500,000 Shares    
Outstanding – 1,400,000 Shares 56.6
 56.6
Paid-in Capital 980.9
 980.9
Retained Earnings 1,180.6
 1,130.5
Accumulated Other Comprehensive Income (Loss) (15.2) (16.2)
TOTAL COMMON SHAREHOLDER’S EQUITY 2,202.9
 2,151.8
     
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $9,767.2
 $9,341.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2017 and 2016
(in millions)
(Unaudited)
  Nine Months Ended September 30,
  2017 2016
OPERATING ACTIVITIES  
  
Net Income $143.8
 $201.4
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
Depreciation and Amortization 154.8
 143.2
Deferred Income Taxes 132.2
 116.2
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net 15.5
 (17.4)
Asset Impairments and Other Related Charges —
 10.5
Allowance for Equity Funds Used During Construction (8.1) (10.9)
Mark-to-Market of Risk Management Contracts (7.5) 0.5
Amortization of Nuclear Fuel 104.8
 109.7
Pension Contribution to Qualified Plan Trust (13.0) (12.7)
Deferred Fuel Over/Under-Recovery, Net 22.0
 6.1
Change in Other Noncurrent Assets (42.1) —
Change in Other Noncurrent Liabilities 40.9
 30.0
Changes in Certain Components of Working Capital:  
  
Accounts Receivable, Net 19.3
 17.0
Fuel, Materials and Supplies (4.1) (1.1)
Accounts Payable 16.6
 (17.9)
Accrued Taxes, Net (30.2) (16.5)
Other Current Assets 8.0
 6.7
Other Current Liabilities (28.6) (27.8)
Net Cash Flows from Operating Activities 524.3
 537.0
     
INVESTING ACTIVITIES  
  
Construction Expenditures (469.2) (405.1)
Change in Advances to Affiliates, Net (0.1) (0.7)
Purchases of Investment Securities (1,842.2) (2,452.9)
Sales of Investment Securities 1,808.6
 2,427.0
Acquisitions of Nuclear Fuel (73.2) (127.6)
Other Investing Activities 7.3
 7.8
Net Cash Flows Used for Investing Activities (568.8) (551.5)
     
FINANCING ACTIVITIES  
  
Issuance of Long-term Debt – Nonaffiliated 411.1
 482.7
Change in Advances from Affiliates, Net (37.7) (268.0)
Retirement of Long-term Debt – Nonaffiliated (227.1) (76.8)
Principal Payments for Capital Lease Obligations (8.7) (29.8)
Dividends Paid on Common Stock (93.7) (93.8)
Other Financing Activities 0.7
 0.7
Net Cash Flows from Financing Activities 44.6
 15.0
     
Net Increase in Cash and Cash Equivalents 0.1
 0.5
Cash and Cash Equivalents at Beginning of Period 1.2
 1.1
Cash and Cash Equivalents at End of Period $1.3
 $1.6
     
SUPPLEMENTARY INFORMATION  
  
Cash Paid for Interest, Net of Capitalized Amounts $92.0
 $85.6
Net Cash Paid (Received) for Income Taxes (69.6) (36.0)
Noncash Acquisitions Under Capital Leases 5.9
 16.8
Construction Expenditures Included in Current Liabilities as of September 30, 74.5
 83.4
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, 0.6
 0.3
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage 2.8
 0.1
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.




OHIO POWER COMPANY AND SUBSIDIARIES



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 Ended Nine Months Ended
 September 30, September 30,
 2017 2016 2017 2016
 (in millions of KWhs)
Retail: 
  
  
  
Residential3,644
 4,380
 10,198
 11,209
Commercial3,806
 4,114
 10,789
 11,158
Industrial3,708
 3,610
 10,967
 10,671
Miscellaneous28
 27
 87
 89
Total Retail (a)11,186
 12,131
 32,041
 33,127
        
Wholesale (b)585
 654
 1,749
 1,389
        
Total KWhs11,771
 12,785
 33,790
 34,516

(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 Ended Nine Months Ended
  September 30, September 30,
  2017 2016 2017 2016
  (in degree days)
Actual - Heating (a) —
 —
 1,500
 1,929
Normal - Heating (b) 6
 7
 2,091
 2,110
         
Actual - Cooling (c) 642
 900
 957
 1,209
Normal - Cooling (b) 670
 664
 960
 956

(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.


Third Quarter of 2017 Compared to Third Quarter of 2016
Reconciliation of Third Quarter of 2016 to Third Quarter of 2017
Net Income
(in millions)
   
Third Quarter of 2016 $99.9
   
Changes in Gross Margin:  
Retail Margins (74.1)
Off-system Sales (12.0)
Transmission Revenues (1.8)
Other Revenues (2.1)
Total Change in Gross Margin (90.0)
   
Changes in Expenses and Other:  
Other Operation and Maintenance 59.3
Depreciation and Amortization 12.1
Taxes Other Than Income Taxes 1.5
Carrying Costs Income (0.4)
Allowance for Equity Funds Used During Construction 0.6
Interest Expense 1.5
Total Change in Expenses and Other 74.6
   
Income Tax Expense (1.9)
   
Third Quarter of 2017 $82.6

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

Retail Margins decreased $74 million primarily due to the following:
A $52 million decrease in revenues associated with the Universal Service Fund (USF) surcharge rate decrease. This decrease was offset by a corresponding decrease in Other Operation and Maintenance expenses below.
An $18 million net decrease in recovery of equity carrying charges related to the Phase-In Recovery Rider (PIRR), net of associated amortizations.
An $8 million decrease in revenues associated with smart grid riders. This decrease was offset in various expenses below.
A $5 million decrease in state excise taxes due to a decrease in metered KWh. This decrease was offset by a corresponding decrease in Taxes Other Than Income Taxes below.
These decreases were partially offset by:
A $12 million favorable impact due to the recoveryamortization of losses from a power contract with OVEC.Excess ADIT. The PUCO approved a PPA rider beginning in January 2017 to recover any net expense related to the deferral of OVEC losses starting in June 2016. This increase was offset by a corresponding decrease in Margins from Off-System Sales below.
Margins from Off-system Sales decreased $12 million due to 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.



Expenses and Other changed between years as follows:

Other Operation and Maintenance expenses decreased $59 million primarily due to the following:
A $52 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 by a corresponding decrease in Retail Margins above.
A $3 million decrease in recoverable smart grid expenses. This decrease was offset in Retail Margins above.
Depreciation and Amortization expensesdecreased $12 million primarily due to the following:
A $5 million decrease in recoverable DIR depreciation expense in Ohio.
A $4 million decrease in amortization expenses for the collection of carrying costs on deferred capacity charges beginning June 2015.
A $4 million decrease in recoverable smart grid depreciation expenses. This decrease was offset in Retail Margins above.
Taxes Other Than Income Taxes decreased $2 million primarily due to the following:
A $5 million decrease in state excise taxes due to a decrease in metered KWh. This decrease was offset by a corresponding decrease in Retail Margins above.
This decrease was partially offset by:
A $3 million increase in property taxes due to additional investments in transmission and distribution assets and higher tax rates.


Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016
Reconciliation of Nine Months Ended September 30, 2016 to Nine Months Ended September 30, 2017
Net Income
(in millions)
   
Nine Months Ended September 30, 2016 $244.7
   
Changes in Gross Margin:  
Retail Margins (153.8)
Off-system Sales (27.9)
Transmission Revenues (2.9)
Other Revenues (0.3)
Total Change in Gross Margin (184.9)
   
Changes in Expenses and Other:  
Other Operation and Maintenance 144.3
Depreciation and Amortization 23.3
Taxes Other Than Income Taxes (2.1)
Interest Income 1.0
Carrying Costs Income (1.0)
Allowance for Equity Funds Used During Construction 0.4
Interest Expense 10.9
Total Change in Expenses and Other 176.8
   
Income Tax Expense (5.5)
   
Nine Months Ended September 30, 2017 $231.1

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

Retail Margins decreased $154 million primarily due to the following:
A $140 million decrease in revenues associated with the USF surcharge rate decrease. This decrease was offset by a corresponding decrease in Other Operation and Maintenance expenses below.
A $21 million decrease due to a prior year reversal of a regulatory provision resulting from a favorable court decision.
A $13 million decrease in revenues associated with smart grid riders. This decrease was offset in various expenses below.
A $9 million net decrease in recovery of equity carrying charges related to the PIRR, net of associated amortizations.
A $7 million decrease in state excise taxes due to a decrease in metered KWh. This decrease was offset by a corresponding decrease in Taxes Other Than Income Taxes below.
A $3 million decrease in transmission cost recovery rider revenues. This decrease was offset in Depreciation and Amortization below.
These decreases were partially offset by:
A $46 million favorable impact due to the recovery of losses from a power contract with OVEC. The PUCO approved a PPA rider beginning in January 2017 to recover any net expense related to the deferral of OVEC losses starting in June 2016. This increase was offset by a corresponding decrease in Margins from Off-System Sales below.
A $6 million increase in rider revenues associated with the DIR. This increase was partially offset in various expenses below.
Margins from Off-system Sales decreased $28 million primarily due to the following:
A $46 million decrease due to 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.


This decrease was partially offset by:
An $18 million increase primarily due to the impact of prior year losses from a power contract with OVEC which was not included in the OVEC PPA rider.

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

Other Operation and Maintenance expenses decreased $144 million primarily due to the following:
A $140 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 by a corresponding decrease in Retail Margins above.
An $8 million decrease in recoverable smart grid expenses. This decrease was offset in Retail Margins above.
A $7 million decrease in securitized customer accounts receivable expenses.
A $3 million decrease in employee-related expenses.
These decreases were partially offset by:
A $12 million increase in PJM expenses related to the annual formula rate true-up that will be recovered in future periods.
Depreciation and Amortization expenses decreased $23 million primarily due to the following:
An $11 million decrease in amortization expenses for the collection of carrying costs on deferred capacity charges beginning June 2015.
An $8 million decrease in recoveries of transmission cost rider carrying costs. This decrease wasExcess ADIT is partially offset in Retail Margins above.
A $7 million decrease in recoverable DIR depreciation expense in Ohio.
A $5 million decrease in recoverable smart grid depreciation expenses. This decrease was offset in Retail Margins above.
These decreases were partially offset by:
A $5 million increase in depreciation expense due to an increase in depreciable base of transmission and distribution assets.
A $3 million increase due to amortization of capitalized software costs.
Taxes Other Than Income Taxes increased $2 million primarily due to the following:
116
A $9 million increase in property taxes due to additional investments in transmission and distribution assets and higher tax rates.

This increase was partially offset by:
A $7 million decrease in state excise taxes due to a decrease in metered KWh. This decrease was offset by a corresponding decrease in Retail Margins above.

InterestExpense decreased $11 million primarily due to the maturity of a senior unsecured note in June 2016.
Income Tax Expense increased $6 million primarily due to other book/tax differences which are accounted for on a flow-through basis and the recording of federal income tax adjustments, partially offset by a decrease in pretax book income.




OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2017 and 2016
(in millions)
(Unaudited)
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2017 2016 2017 2016
REVENUES        
Electricity, Transmission and Distribution $736.0
 $864.4
 $2,127.8
 $2,349.2
Sales to AEP Affiliates 4.6
 5.5
 19.4
 11.7
Other Revenues 1.4
 1.4
 4.8
 4.8
TOTAL REVENUES 742.0
 871.3
 2,152.0
 2,365.7
         
EXPENSES  
  
  
  
Purchased Electricity for Resale 180.7
 203.4
 525.4
 516.1
Purchased Electricity from AEP Affiliates 26.7
 35.9
 83.4
 121.4
Amortization of Generation Deferrals 58.7
 66.1
 172.9
 173.0
Other Operation 125.8
 184.2
 377.6
 525.9
Maintenance 37.9
 38.8
 108.4
 104.4
Depreciation and Amortization 57.3
 69.4
 165.7
 189.0
Taxes Other Than Income Taxes 100.4
 101.9
 293.8
 291.7
TOTAL EXPENSES 587.5
 699.7
 1,727.2
 1,921.5
         
OPERATING INCOME 154.5
 171.6
 424.8
 444.2
         
Other Income (Expense):  
  
  
  
Interest Income 0.7
 0.7
 4.0
 3.0
Carrying Costs Income 0.5
 0.9
 3.0
 4.0
Allowance for Equity Funds Used During Construction 0.9
 0.3
 4.1
 3.7
Interest Expense (25.7) (27.2) (76.8) (87.7)
         
INCOME BEFORE INCOME TAX EXPENSE 130.9
 146.3
 359.1
 367.2
         
Income Tax Expense 48.3
 46.4
 128.0
 122.5
         
NET INCOME $82.6
 $99.9
 $231.1
 $244.7
The common stock of OPCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2017 and 2016
(in millions)
(Unaudited)
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2017 2016 2017 2016
Net Income $82.6
 $99.9
 $231.1
 $244.7
         
OTHER COMPREHENSIVE LOSS, NET OF TAXES  
  
  
  
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2017 and 2016, Respectively, and $(0.4) and $(0.5) for the Nine Months Ended September 30, 2017 and 2016, Respectively (0.3) (0.2) (0.8) (1.0)
         
TOTAL COMPREHENSIVE INCOME $82.3
 $99.7
 $230.3
 $243.7
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2017 and 2016
(in millions)
(Unaudited)
 Common
Stock		 Paid-in
Capital		 Retained
Earnings		 Accumulated
Other
Comprehensive
Income (Loss)		 Total
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2015$321.2
 $838.8
 $822.3
 $4.3
 $1,986.6
          
Common Stock Dividends 
  
 (150.0)  
 (150.0)
Net Income 
  
 244.7
  
 244.7
Other Comprehensive Loss 
  
  
 (1.0) (1.0)
TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2016$321.2
 $838.8
 $917.0
 $3.3
 $2,080.3
  
  
  
  
  
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2016$321.2
 $838.8
 $954.5
 $3.0
 $2,117.5
          
Common Stock Dividends 
  
 (130.0)  
 (130.0)
Net Income 
  
 231.1
  
 231.1
Other Comprehensive Loss 
  
  
 (0.8) (0.8)
TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2017$321.2
 $838.8
 $1,055.6
 $2.2
 $2,217.8
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2017 and December 31, 2016
(in millions)
(Unaudited)
  September 30, December 31,
  2017 2016
CURRENT ASSETS    
Cash and Cash Equivalents $3.1
 $3.1
Restricted Cash for Securitized Funding 15.6
 27.2
Advances to Affiliates —
 24.2
Accounts Receivable:    
Customers 27.1
 51.1
Affiliated Companies 72.0
 66.3
Accrued Unbilled Revenues 24.2
 21.0
Miscellaneous 1.1
 0.9
Allowance for Uncollectible Accounts (0.4) (0.4)
Total Accounts Receivable 124.0
 138.9
Materials and Supplies 42.8
 45.9
Emission Allowances 23.6
 20.4
Risk Management Assets 0.2
 0.2
Accrued Tax Benefits 15.4
 0.1
Prepayments and Other Current Assets 28.1
 10.9
TOTAL CURRENT ASSETS 252.8
 270.9
     
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Transmission 2,349.5
 2,319.2
Distribution 4,575.0
 4,457.2
Other Property, Plant and Equipment 487.9
 443.7
Construction Work in Progress 350.7
 221.5
Total Property, Plant and Equipment 7,763.1
 7,441.6
Accumulated Depreciation and Amortization 2,182.8
 2,116.0
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 5,580.3
 5,325.6
     
OTHER NONCURRENT ASSETS    
Notes Receivable – Affiliated 32.3
 32.3
Regulatory Assets 1,014.7
 1,107.5
Securitized Assets 43.7
 62.1
Deferred Charges and Other Noncurrent Assets 131.2
 295.5
TOTAL OTHER NONCURRENT ASSETS 1,221.9
 1,497.4
     
TOTAL ASSETS $7,055.0
 $7,093.9
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2017 and December 31, 2016
(dollars in millions)
(Unaudited)
  September 30, December 31,
  2017 2016
CURRENT LIABILITIES    
Advances from Affiliates $167.6
 $—
Accounts Payable:  
  
General 157.8
 175.4
Affiliated Companies 95.3
 95.6
Long-term Debt Due Within One Year – Nonaffiliated
(September 30, 2017 and December 31, 2016 Amounts Include $47 and $46.3, Respectively, Related to Ohio Phase-in-Recovery Funding)
 397.0
 46.4
Risk Management Liabilities 7.6
 5.9
Customer Deposits 62.9
 71.0
Accrued Taxes 251.3
 520.3
Accrued Interest 38.3
 31.2
Other Current Liabilities 166.3
 236.0
TOTAL CURRENT LIABILITIES 1,344.1
 1,181.8
     
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated
(September 30, 2017 and December 31, 2016 Amounts Include $47.5 and $93.9, Respectively, Related to Ohio Phase-in-Recovery Funding)
 1,321.9
 1,717.5
Long-term Risk Management Liabilities 130.9
 113.1
Deferred Income Taxes 1,460.7
 1,346.1
Regulatory Liabilities and Deferred Investment Tax Credits 519.3
 506.2
Employee Benefits and Pension Obligations 19.3
 27.8
Deferred Credits and Other Noncurrent Liabilities 41.0
 83.9
TOTAL NONCURRENT LIABILITIES 3,493.1
 3,794.6
     
TOTAL LIABILITIES 4,837.2
 4,976.4
     
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 1,055.6
 954.5
Accumulated Other Comprehensive Income (Loss) 2.2
 3.0
TOTAL COMMON SHAREHOLDER’S EQUITY 2,217.8
 2,117.5
     
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $7,055.0
 $7,093.9
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2017 and 2016
(in millions)
(Unaudited)
  Nine Months Ended September 30,
  2017 2016
OPERATING ACTIVITIES  
  
Net Income $231.1
 $244.7
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
Depreciation and Amortization 165.7
 189.0
Amortization of Generation Deferrals 172.9
 173.0
Deferred Income Taxes 117.5
 28.6
Carrying Costs Income (3.0) (4.0)
Allowance for Equity Funds Used During Construction (4.1) (3.7)
Mark-to-Market of Risk Management Contracts 19.5
 124.7
Pension Contributions to Qualified Plan Trust (8.2) (7.1)
Property Taxes 175.9
 169.1
Provision for Refund – Global Settlement, Net (93.3) —
Change in Other Noncurrent Assets (126.7) (124.9)
Change in Other Noncurrent Liabilities 43.4
 17.2
Changes in Certain Components of Working Capital:  
  
Accounts Receivable, Net 14.9
 8.8
Materials and Supplies (7.1) 0.5
Accounts Payable (31.2) 2.0
Accrued Taxes, Net (284.3) (291.1)
Other Current Assets (17.3) (5.7)
Other Current Liabilities (34.8) (46.8)
Net Cash Flows from Operating Activities 330.9
 474.3
     
INVESTING ACTIVITIES  
  
Construction Expenditures (362.5) (276.4)
Change in Restricted Cash for Securitized Funding 11.6
 11.6
Change in Advances to Affiliates, Net 24.2
 330.9
Other Investing Activities 6.9
 9.0
Net Cash Flows from (Used for) Investing Activities (319.8) 75.1
     
FINANCING ACTIVITIES  
  
Change in Advances from Affiliates, Net 167.6
 —
Retirement of Long-term Debt – Nonaffiliated (46.4) (395.9)
Principal Payments for Capital Lease Obligations (3.1) (3.1)
Dividends Paid on Common Stock (130.0) (150.0)
Other Financing Activities 0.8
 0.5
Net Cash Flows Used for Financing Activities (11.1) (548.5)
     
Net Increase in Cash and Cash Equivalents —
 0.9
Cash and Cash Equivalents at Beginning of Period 3.1
 3.1
Cash and Cash Equivalents at End of Period $3.1
 $4.0
     
SUPPLEMENTARY INFORMATION  
  
Cash Paid for Interest, Net of Capitalized Amounts $68.1
 $78.2
Net Cash Paid for Income Taxes 69.6
 178.0
Noncash Acquisitions Under Capital Leases 3.6
 2.4
Construction Expenditures Included in Current Liabilities as of September 30, 56.8
 30.0
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.




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 Nine Months Ended
 September 30, September 30,
 2017 2016 2017 2016
 (in millions of KWhs)
Retail: 
  
  
  
Residential1,992
 2,184
 4,662
 4,925
Commercial1,488
 1,529
 3,926
 4,001
Industrial1,472
 1,494
 4,249
 4,162
Miscellaneous353
 369
 942
 955
Total Retail5,305
 5,576
 13,779
 14,043
        
Wholesale82
 113
 309
 226
        
Total KWhs5,387
 5,689
 14,088
 14,269

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 Nine Months Ended
 September 30, September 30,
 2017 2016 2017 2016
 (in degree days)
Actual - Heating (a)—
 —
 682
 782
Normal - Heating (b)1
 1
 1,104
 1,105
        
Actual - Cooling (c)1,313
 1,535
 2,001
 2,247
Normal - Cooling (b)1,395
 1,390
 2,064
 2,055

(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.


Third Quarter of 2017 Compared to Third Quarter of 2016
Reconciliation of Third Quarter of 2016 to Third Quarter of 2017
Net Income
(in millions)
   
Third Quarter of 2016 $52.8
   
Changes in Gross Margin:  
Retail Margins (a) (15.6)
Off-system Sales (0.7)
Transmission Revenues 4.1
Other Revenues (2.0)
Total Change in Gross Margin (14.2)
   
Changes in Expenses and Other:  
Other Operation and Maintenance (2.2)
Depreciation and Amortization 5.5
Taxes Other Than Income Taxes (0.7)
Interest Income (0.2)
Allowance for Equity Funds Used During Construction (1.1)
Interest Expense 1.7
Total Change in Expenses and Other 3.0
   
Income Tax Expense 4.6
   
Third Quarter of 2017 $46.2

(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 decreased $16 million primarily due to the following:
A $17 million decrease primarily due to higher rates implemented in 2016 associated with interim rates.
An $11 million decrease in weather-related usage primarily due to a 14% decrease in cooling degree days.
These decreases were partially offset by:
A $14 million increase due to weather-normalized margins.
Transmission Revenues increased $4 million primarily due to an accrual for SPP sponsor-funded transmission upgrades in third quarter 2016.
Expenses and Other and Income Tax Expense changed between years as follows:

Depreciation and Amortization expenses decreased $6 million primarily due the following:
A $9 million decrease primarily related to prior year higher estimated depreciation expense associated with interim rates.
This decrease was partially offset by:
A $4 million increase primarily related to new depreciation rates implemented in 2017 and a higher depreciable base.
Income Tax Expense decreased $5 million primarily due to a decrease in pretax book income.



Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016
Reconciliation of Nine Months Ended September 30, 2016 to Nine Months Ended September 30, 2017
Net Income
(in millions)
   
Nine Months Ended September 30, 2016 $97.4
   
Changes in Gross Margin:  
Retail Margins (a) (17.6)
Off-system Sales (0.9)
Transmission Revenues 4.8
Other Revenues (4.6)
Total Change in Gross Margin (18.3)
   
Changes in Expenses and Other:  
Other Operation and Maintenance (31.1)
Depreciation and Amortization 12.1
Taxes Other Than Income Taxes (2.2)
Interest Income (0.4)
Allowance for Equity Funds Used During Construction (4.5)
Interest Expense 4.4
Total Change in Expenses and Other (21.7)
   
Income Tax Expense 14.0
   
Nine Months Ended September 30, 2017 $71.4

(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 decreased $18 million primarily due to the following:
A $15 million decrease in weather-related usage primarily due to an 11% decrease in cooling degree days and a 13% decrease in heating degree days.
A $14 million decrease primarily due to higher rates implemented in 2016 associated with interim rates.
These decreases were partially offset by:
A $9 million increase primarily due to higher weather-normalized margins.
A $5 million increase related to new base rates implemented in January 2017.
Transmission Revenues increased $5 million primarily due to an accrual for SPP sponsor-funded transmission upgrades in third quarter 2016 and additional transmission investments in SPP.
Other Revenues decreased $5 million primarily due to the elimination of connection charges for certain customers with advanced metering, effective with the implementation of new base rates in January 2017.


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

Other Operation and Maintenance expenses increased $31 million primarily due to the following:
A $16 million increase in vegetation management expenses.  This increase is partially offset by a corresponding increase in Retail Margins as vegetation management expenses recovered in the prior year under the System Reliability Rider are now recovered as a component of base rates in the current year.
A $15 million increase in transmission expenses primarily due to increased SPP transmission services.
Depreciation and Amortization expenses decreased $12 million primarily due the following:
A $24 million decrease primarily related to prior year higher estimated depreciation expense associated with interim rates.
This decrease was partially offset by:
A $12 million increase primarily related to new depreciation rates implemented in 2017 and a higher depreciable base.
Allowance for Equity Funds Used During Construction decreased $5 million primarily due to the completion of environmental projects.
Interest Expense decreased $4 million primarily due to the deferral of the debt component of carrying charges on environmental control costs for projects at Northeastern Plant, Unit 3 and the Comanche Plant.
Income Tax Expense decreased $14 million primarily due to a decrease in pretax book income.



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20172020 and 20162019
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
 September 30,September 30,
 2020201920202019
REVENUES    
Electric Generation, Transmission and Distribution$379.8 $490.5 $976.3 $1,164.3 
Sales to AEP Affiliates1.4 1.3 3.8 5.0 
Other Revenues1.0 1.2 8.0 4.6 
TOTAL REVENUES382.2 493.0 988.1 1,173.9 
EXPENSES    
Fuel and Other Consumables Used for Electric Generation20.9 98.4 36.2 181.2 
Purchased Electricity for Resale104.7 115.3 314.1 340.7 
Other Operation91.7 87.6 248.5 226.0 
Maintenance19.9 21.5 68.9 70.1 
Depreciation and Amortization40.1 39.1 129.8 125.4 
Taxes Other Than Income Taxes12.1 11.1 35.8 33.0 
TOTAL EXPENSES289.4 373.0 833.3 976.4 
OPERATING INCOME92.8 120.0 154.8 197.5 
Other Income (Expense):    
Interest Income0 0.4 0.1 0.6 
Allowance for Equity Funds Used During Construction1.3 0.8 3.2 1.5 
Non-Service Cost Components of Net Periodic Benefit Cost2.1 2.1 6.3 6.3 
Interest Expense(14.6)(16.1)(45.9)(50.3)
INCOME BEFORE INCOME TAX EXPENSE81.6 107.2 118.5 155.6 
Income Tax Expense1.3 6.9 2.1 7.2 
NET INCOME$80.3 $100.3 $116.4 $148.4 
The common stock of PSO is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
117
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2017 2016 2017 2016
REVENUES        
Electric Generation, Transmission and Distribution $440.6
 $400.9
 $1,085.1
 $971.3
Sales to AEP Affiliates 1.1
 0.1
 3.2
 2.0
Other Revenues 1.1
 0.7
 3.3
 2.9
TOTAL REVENUES 442.8
 401.7
 1,091.6
 976.2
         
EXPENSES  
  
  
  
Fuel and Other Consumables Used for Electric Generation 77.9
 16.4
 115.8
 43.0
Purchased Electricity for Resale 127.8
 130.8
 379.8
 315.3
Purchased Electricity from AEP Affiliates —
 3.2
 —
 3.6
Other Operation 83.6
 81.0
 226.3
 211.8
Maintenance 25.2
 25.6
 88.2
 71.6
Depreciation and Amortization 31.7
 37.2
 97.8
 109.9
Taxes Other Than Income Taxes 9.8
 9.1
 30.0
 27.8
TOTAL EXPENSES 356.0
 303.3
 937.9
 783.0
         
OPERATING INCOME 86.8
 98.4
 153.7
 193.2
         
Other Income (Expense):  
  
  
  
Interest Income —
 0.2
 0.1
 0.5
Allowance for Equity Funds Used During Construction —
 1.1
 0.4
 4.9
Interest Expense (13.2) (14.9) (40.2) (44.6)
         
INCOME BEFORE INCOME TAX EXPENSE 73.6
 84.8
 114.0
 154.0
         
Income Tax Expense 27.4
 32.0
 42.6
 56.6
         
NET INCOME $46.2
 $52.8
 $71.4
 $97.4


The common stock of PSO is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.





PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20172020 and 20162019
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
 September 30,September 30,
2020201920202019
Net Income$80.3 $100.3 $116.4 $148.4 
OTHER COMPREHENSIVE LOSS, NET OF TAXES    
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2020 and 2019, Respectively, and $(0.2) and $(0.2) for the Nine Months Ended September 30, 2020 and 2019, Respectively.(0.3)(0.2)(0.8)(0.7)
    
TOTAL COMPREHENSIVE INCOME$80.0 $100.1 $115.6 $147.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
118
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2017 2016 2017 2016
Net Income $46.2
 $52.8
 $71.4
 $97.4
         
OTHER COMPREHENSIVE LOSS, NET OF TAXES  
    
  
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2017 and 2016, Respectively, and $(0.3) and $(0.3) for the Nine Months Ended September 30, 2017 and 2016, Respectively (0.2) (0.2) (0.6) (0.6)
   
    
  
TOTAL COMPREHENSIVE INCOME $46.0
 $52.6

$70.8
 $96.8


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.





PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 20172020 and 20162019
(in millions)
(Unaudited)
Common
Stock		Paid-in
Capital		Retained
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018$157.2 $364.0 $724.7 $2.1 $1,248.0 
Common Stock Dividends(11.3)(11.3)
Net Income6.2 6.2 
Other Comprehensive Loss(0.2)(0.2)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2019157.2 364.0 719.6 1.9 1,242.7 
Net Income  41.9  41.9 
Other Comprehensive Loss   (0.3)(0.3)
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2019157.2 364.0 761.5 1.6 1,284.3 
     
Net Income100.3 100.3 
Other Comprehensive Loss(0.2)(0.2)
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2019$157.2 $364.0 $861.8 $1.4 $1,384.4 
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019$157.2 $364.0 $851.0 $1.1 $1,373.3 
ASU 2016-13 Adoption0.3 0.3 
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, 2020157.2 364.0 887.4 0.6 1,409.2 
Net Income80.3 80.3 
Other Comprehensive Loss(0.3)(0.3)
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2020$157.2 $364.0 $967.7 $0.3 $1,489.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
119
 Common
Stock		 Paid-in
Capital		 Retained
Earnings		 Accumulated
Other
Comprehensive
Income (Loss)		 Total
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2015$157.2
 $364.0
 $594.5
 $4.2
 $1,119.9
          
Net Income 
  
 97.4
  
 97.4
Other Comprehensive Loss 
  
  
 (0.6) (0.6)
TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2016$157.2
 $364.0
 $691.9
 $3.6
 $1,216.7
  
  
  
  
  
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2016$157.2
 $364.0
 $689.5
 $3.4
 $1,214.1
          
Common Stock Dividends 
  
 (52.5)  
 (52.5)
Net Income 
  
 71.4
  
 71.4
Other Comprehensive Loss 
  
  
 (0.6) (0.6)
TOTAL COMMON SHAREHOLDER’S EQUITY - SEPTEMBER 30, 2017$157.2
 $364.0
 $708.4
 $2.8
 $1,232.4


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.





PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
September 30, 20172020 and December 31, 20162019
(in millions)
(Unaudited)
 September 30,December 31,
 20202019
CURRENT ASSETS  
Cash and Cash Equivalents$3.0 $1.5 
Advances to Affiliates0 38.8 
Accounts Receivable:  
Customers25.2 28.9 
Affiliated Companies27.1 20.6 
Miscellaneous3.1 0.6 
Allowance for Uncollectible Accounts0 (0.3)
Total Accounts Receivable55.4 49.8 
Fuel22.8 12.2 
Materials and Supplies53.4 46.8 
Risk Management Assets16.6 15.8 
Accrued Tax Benefits0.6 11.3 
Prepayments and Other Current Assets11.8 12.0 
TOTAL CURRENT ASSETS163.6 188.2 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation1,474.1 1,574.6 
Transmission981.2 948.5 
Distribution2,799.5 2,684.8 
Other Property, Plant and Equipment381.8 342.1 
Construction Work in Progress147.2 133.4 
Total Property, Plant and Equipment5,783.8 5,683.4 
Accumulated Depreciation and Amortization1,578.3 1,580.1 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET4,205.5 4,103.3 
OTHER NONCURRENT ASSETS  
Regulatory Assets388.9 375.2 
Employee Benefits and Pension Assets44.8 43.9 
Operating Lease Assets40.5 36.8 
Deferred Charges and Other Noncurrent Assets15.9 4.1 
TOTAL OTHER NONCURRENT ASSETS490.1 460.0 
TOTAL ASSETS$4,859.2 $4,751.5 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
120
  September 30, December 31,
  2017 2016
CURRENT ASSETS    
Cash and Cash Equivalents $2.1
 $1.5
Accounts Receivable:    
Customers 17.8
 27.5
Affiliated Companies 31.8
 26.8
Miscellaneous 3.2
 4.4
Allowance for Uncollectible Accounts (0.1) (0.2)
Total Accounts Receivable 52.7
 58.5
Fuel 11.9
 22.9
Materials and Supplies 42.1
 44.6
Risk Management Assets 4.7
 0.8
Accrued Tax Benefits 27.0
 27.3
Regulatory Asset for Under-Recovered Fuel Costs 36.9
 33.8
Prepayments and Other Current Assets 14.4
 6.0
TOTAL CURRENT ASSETS 191.8
 195.4
     
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Generation 1,573.8
 1,559.3
Transmission 852.5
 832.8
Distribution 2,414.1
 2,322.4
Other Property, Plant and Equipment 286.3
 233.2
Construction Work in Progress 114.0
 148.2
Total Property, Plant and Equipment 5,240.7
 5,095.9
Accumulated Depreciation and Amortization 1,382.8
 1,272.7
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 3,857.9
 3,823.2
     
OTHER NONCURRENT ASSETS    
Regulatory Assets 393.6
 340.2
Employee Benefits and Pension Assets 16.0
 10.4
Deferred Charges and Other Noncurrent Assets 19.2
 10.0
TOTAL OTHER NONCURRENT ASSETS 428.8
 360.6
     
TOTAL ASSETS $4,478.5
 $4,379.2


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.





PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 20172020 and December 31, 20162019
(Unaudited)
 September 30,December 31,
 20202019
 (in millions)
CURRENT LIABILITIES  
Advances from Affiliates$77.8 $0 
Accounts Payable:  
General106.7 134.3 
Affiliated Companies41.0 59.3 
Long-term Debt Due Within One Year – Nonaffiliated250.5 13.2 
Risk Management Liabilities0.5 0 
Customer Deposits56.2 58.9 
Accrued Taxes49.1 22.9 
Obligations Under Operating Leases6.2 5.8 
Regulatory Liability for Over-Recovered Fuel Costs17.3 63.9 
Other Current Liabilities72.8 87.5 
TOTAL CURRENT LIABILITIES678.1 445.8 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated1,123.2 1,373.0 
Deferred Income Taxes649.6 628.3 
Regulatory Liabilities and Deferred Investment Tax Credits816.4 837.2 
Asset Retirement Obligations46.4 44.5 
Obligations Under Operating Leases34.3 31.0 
Deferred Credits and Other Noncurrent Liabilities22.0 18.4 
TOTAL NONCURRENT LIABILITIES2,691.9 2,932.4 
TOTAL LIABILITIES3,370.0 3,378.2 
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 Shares157.2 157.2 
Paid-in Capital364.0 364.0 
Retained Earnings967.7 851.0 
Accumulated Other Comprehensive Income (Loss)0.3 1.1 
TOTAL COMMON SHAREHOLDER’S EQUITY1,489.2 1,373.3 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY$4,859.2 $4,751.5 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
121
  September 30, December 31,
  2017 2016
  (in millions)
CURRENT LIABILITIES    
Advances from Affiliates $118.0
 $52.0
Accounts Payable:  
  
General 93.8
 116.3
Affiliated Companies 43.0
 56.2
Long-term Debt Due Within One Year – Nonaffiliated 0.5
 0.5
Customer Deposits 53.1
 49.7
Accrued Taxes 40.8
 21.0
Accrued Interest 19.5
 13.9
Provision for Refund 4.1
 46.1
Other Current Liabilities 38.5
 47.8
TOTAL CURRENT LIABILITIES 411.3
 403.5
     
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated 1,285.9
 1,285.5
Deferred Income Taxes 1,152.5
 1,058.8
Regulatory Liabilities and Deferred Investment Tax Credits 320.9
 339.7
Asset Retirement Obligations 54.5
 52.8
Deferred Credits and Other Noncurrent Liabilities 21.0
 24.8
TOTAL NONCURRENT LIABILITIES 2,834.8
 2,761.6
     
TOTAL LIABILITIES 3,246.1
 3,165.1
     
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 708.4
 689.5
Accumulated Other Comprehensive Income (Loss) 2.8
 3.4
TOTAL COMMON SHAREHOLDER’S EQUITY 1,232.4
 1,214.1
     
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $4,478.5
 $4,379.2


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.





PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20172020 and 20162019
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20202019
OPERATING ACTIVITIES  
Net Income$116.4 $148.4 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and Amortization129.8 125.4 
Deferred Income Taxes(3.2)(9.7)
Allowance for Equity Funds Used During Construction(3.2)(1.5)
Mark-to-Market of Risk Management Contracts(0.3)(12.0)
Property Taxes(10.6)(9.6)
Deferred Fuel Over/Under-Recovery, Net(46.6)49.8 
Change in Other Noncurrent Assets(7.2)4.6 
Change in Other Noncurrent Liabilities6.1 (0.2)
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net(5.6)9.1 
Fuel, Materials and Supplies(17.2)(1.9)
Accounts Payable(26.1)(5.8)
Accrued Taxes, Net36.9 19.0 
Other Current Assets(0.1)(2.4)
Other Current Liabilities(16.4)1.1 
Net Cash Flows from Operating Activities152.7 314.3 
INVESTING ACTIVITIES  
Construction Expenditures(256.4)(198.7)
Change in Advances to Affiliates, Net38.8 (95.1)
Other Investing Activities3.9 2.1 
Net Cash Flows Used for Investing Activities(213.7)(291.7)
FINANCING ACTIVITIES  
Issuance of Long-term Debt – Nonaffiliated0 349.8 
Change in Advances from Affiliates, Net77.8 (105.5)
Retirement of Long-term Debt – Nonaffiliated(13.0)(250.4)
Principal Payments for Finance Lease Obligations(2.7)(2.2)
Dividends Paid on Common Stock0 (11.3)
Other Financing Activities0.4 (2.1)
Net Cash Flows from (Used for) Financing Activities62.5 (21.7)
Net Increase in Cash and Cash Equivalents1.5 0.9 
Cash and Cash Equivalents at Beginning of Period1.5 2.0 
Cash and Cash Equivalents at End of Period$3.0 $2.9 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$45.5 $46.5 
Net Cash Paid (Received) for Income Taxes(9.5)16.0 
Noncash Acquisitions Under Finance Leases3.0 3.4 
Construction Expenditures Included in Current Liabilities as of September 30,23.5 31.5 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
122
  Nine Months Ended September 30,
  2017 2016
OPERATING ACTIVITIES  
  
Net Income $71.4
 $97.4
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
Depreciation and Amortization 97.8
 109.9
Deferred Income Taxes 93.7
 79.5
Allowance for Equity Funds Used During Construction (0.4) (4.9)
Mark-to-Market of Risk Management Contracts (3.9) (0.7)
Pension Contributions to Qualified Plan Trust (5.3) (5.6)
Property Taxes (9.4) (8.0)
Deferred Fuel Over/Under-Recovery, Net (5.6) (80.2)
Provision for Refund, Net (39.4) 13.8
Change in Other Noncurrent Assets (19.8) (18.8)
Change in Other Noncurrent Liabilities (1.4) (3.7)
Changes in Certain Components of Working Capital:  
  
Accounts Receivable, Net 5.8
 4.4
Fuel, Materials and Supplies 13.5
 (2.4)
Accounts Payable (18.5) 23.1
Accrued Taxes, Net 20.1
 45.4
Other Current Assets (8.2) (2.2)
Other Current Liabilities 1.5
 (14.9)
Net Cash Flows from Operating Activities 191.9
 232.1
     
INVESTING ACTIVITIES  
  
Construction Expenditures (203.1) (266.8)
Change in Advances to Affiliates, Net —
 29.5
Other Investing Activities 1.5
 8.7
Net Cash Flows Used for Investing Activities (201.6) (228.6)
     
FINANCING ACTIVITIES  
  
Issuance of Long-term Debt – Nonaffiliated —
 150.0
Change in Advances from Affiliates, Net 66.0
 —
Retirement of Long-term Debt – Nonaffiliated (0.3) (150.3)
Principal Payments for Capital Lease Obligations (3.2) (3.0)
Dividends Paid on Common Stock (52.5) —
Other Financing Activities 0.3
 0.4
Net Cash Flows from (Used for) Financing Activities 10.3
 (2.9)
     
Net Increase in Cash and Cash Equivalents 0.6
 0.6
Cash and Cash Equivalents at Beginning of Period 1.5
 1.4
Cash and Cash Equivalents at End of Period $2.1
 $2.0
     
SUPPLEMENTARY INFORMATION  
  
Cash Paid for Interest, Net of Capitalized Amounts $40.9
 $45.0
Net Cash Paid (Received) for Income Taxes (46.6) (50.3)
Noncash Acquisitions Under Capital Leases 1.0
 2.2
Construction Expenditures Included in Current Liabilities as of September 30, 15.1
 20.2





See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.






SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED




123





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


RESULTS OF OPERATIONS


KWh Sales/Degree Days


Summary of KWh Energy Sales
Three Months EndedNine Months Ended
 September 30,September 30,
 2020201920202019
 (in millions of KWhs)
Retail:    
Residential1,950 2,071 4,702 4,896 
Commercial1,552 1,746 4,016 4,430 
Industrial1,185 1,414 3,614 4,020 
Miscellaneous19 19 59 59 
Total Retail4,706 5,250 12,391 13,405 
Wholesale1,571 1,831 4,081 5,317 
Total KWhs6,277 7,081 16,472 18,722 
 Three Months Ended Nine Months Ended
 September 30, September 30,
 2017 2016 2017 2016
 (in millions of KWhs)
Retail: 
  
  
  
Residential1,887
 2,105
 4,547
 4,879
Commercial1,677
 1,793
 4,466
 4,652
Industrial1,339
 1,254
 3,895
 3,830
Miscellaneous19
 20
 60
 61
Total Retail4,922
 5,172
 12,968
 13,422
        
Wholesale2,105
 2,326
 6,286
 6,056
        
Total KWhs7,027
 7,498
 19,254
 19,478


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


Summary of Heating and Cooling Degree Days
Three Months EndedNine Months Ended
 September 30,September 30,
 2020201920202019
 (in degree days)
Actual – Heating (a)— — 522 732 
Normal – Heating (b)1 1 724 725 
Actual – Cooling (c)1,308 1,552 2,051 2,263 
Normal – Cooling (b)1,420 1,408 2,200 2,187 

(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.

124
 Three Months Ended Nine Months Ended
 September 30, September 30,
 2017 2016 2017 2016
 (in degree days)
Actual - Heating (a)—
 —
 394
 586
Normal - Heating (b)1
 1
 747
 747
        
Actual - Cooling (c)1,248
 1,502
 1,999
 2,277
Normal - Cooling (b)1,414
 1,410
 2,185
 2,177


(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.







Third Quarter of 20172020 Compared to Third Quarter of 20162019
Reconciliation of Third Quarter of 2016 to Third Quarter of 2017
Earnings Attributable to SWEPCo Common Shareholder
(in millions)
   
Third Quarter of 2016 $83.3
   
Changes in Gross Margin:  
Retail Margins (a) (6.9)
Off-system Sales 0.1
Transmission Revenues (8.0)
Other Revenues (0.1)
Total Change in Gross Margin (14.9)
   
Changes in Expenses and Other:  
Other Operation and Maintenance 10.1
Depreciation and Amortization (4.0)
Taxes Other Than Income Taxes (1.6)
Interest Income 0.7
Allowance for Equity Funds Used During Construction 0.3
Interest Expense 0.7
Total Change in Expenses and Other 6.2
   
Income Tax Expense 10.7
Equity Earnings (Loss) of Unconsolidated Subsidiary (2.3)
Net Income Attributable to Noncontrolling Interest (9.9)
   
Third Quarter of 2017 $73.1

(a)Reconciliation of Third Quarter of 2019 to Third Quarter of 2020Includes firm wholesale sales
Earnings Attributable to municipalsSWEPCo Common Shareholder
(in millions)
Third Quarter of 2019$110.5 
Changes in Gross Margin:
Retail Margins (a)(8.9)
Margins from Off-system Sales(0.3)
Transmission Revenues2.5 
Other Revenues(0.6)
Total Change in Gross Margin(7.3)
Changes in Expenses and cooperatives.Other:
Other Operation and Maintenance0.3 
Depreciation and Amortization(5.3)
Taxes Other Than Income Taxes(0.5)
Allowance for Equity Funds Used During Construction1.8 
Interest Expense(0.1)
Total Change in Expenses and Other(3.8)
Income Tax Expense(11.5)
Equity Earnings of Unconsolidated Subsidiary(0.1)
Net Income Attributable to Noncontrolling Interest0.1 
Third Quarter of 2020$87.9 


(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 decreased $7$9 million primarily due to the following:
An $18•A $17 million decrease in weather-related usage primarily due to a 17%16% decrease in cooling degree days.
This•An $8 million decrease wasin weather-normalized margins.
These decreases were partially offset by:
An $11•A $14 million increase due to rider revenue increases in Louisiana, partially offset in expense items below.
Transmission Revenues decreased $8 million primarily due to an accrual for SPP sponsor-funded transmission upgradesa base rate revenue increase in third quarter 2016. This decrease is offset by a corresponding decrease in Other Operation and Maintenance expenses below.
Arkansas.


Expenses and Other and Income Tax Expense and Net Income Attributable to Noncontrolling Interest changed between years as follows:


Other Operation and Maintenance expenses decreased $10 million primarily due to a $12 million accrual for SPP sponsor-funded transmission upgrades in third quarter 2016. This decrease is partially offset by a corresponding decrease in Transmission Revenues above.
•Depreciation and Amortization expenses increased $4$5 million primarily due to a higher depreciable base.
base and an increase in Arkansas depreciation rates beginning in January 2020. This increase was partially offset in Retail Margins above.
•Income Tax Expense decreased $11increased $12 million primarily due to income tax benefits attributable to SWEPCo’s noncontrolling interesta decrease in Sabine. This decrease is offset by an increase in Net Income Attributable to Noncontrolling Interest below.
Net Income Attributable to Noncontrolling Interest increased $10 million primarily due to income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine. This increase isamortization of Excess ADIT, partially offset by a decrease in Income Tax Expensepretax book income. The decrease in amortization of Excess ADIT was partially offset in Retail Margins above.
125







Nine Months Ended September 30, 20172020 Compared to Nine Months Ended September 30, 20162019
Reconciliation of Nine Months Ended September 30, 2016 to Nine Months Ended September 30, 2017
Earnings Attributable to SWEPCo Common Shareholder
(in millions)
   
Nine Months Ended September 30, 2016 $149.9
   
Changes in Gross Margin:  
Retail Margins (a) (8.4)
Off-system Sales 3.8
Transmission Revenues (5.5)
Other Revenues 0.3
Total Change in Gross Margin (9.8)
   
Changes in Expenses and Other:  
Other Operation and Maintenance 6.6
Depreciation and Amortization (10.0)
Taxes Other Than Income Taxes (5.8)
Interest Income 2.0
Allowance For Equity Funds Used During Construction (8.3)
Interest Expense (0.7)
Total Change in Expenses and Other (16.2)
   
Income Tax Expense 8.7
Equity Earnings (Loss) of Unconsolidated Subsidiary (9.4)
Net Income Attributable to Noncontrolling Interest (9.3)
   
Nine Months Ended September 30, 2017 $113.9

(a)Reconciliation of Nine Months Ended September 30, 2019 to Nine Months Ended September 30, 2020Includes firm wholesale sales
Earnings Attributable to municipalsSWEPCo Common Shareholder
(in millions)
Nine Months Ended September 30, 2019$144.5 
Changes in Gross Margin:
Retail Margins (a)4.4 
Margins from Off-system Sales(2.5)
Transmission Revenues55.8 
Other Revenues(2.4)
Total Change in Gross Margin55.3 
Changes in Expenses and cooperatives.Other:
Other Operation and Maintenance(9.7)
Depreciation and Amortization(16.8)
Taxes Other Than Income Taxes(1.0)
Interest Income(0.3)
Allowance for Equity Funds Used During Construction1.2 
Non-Service Cost Components of Net Periodic Benefit Cost(0.1)
Interest Expense0.3 
Total Change in Expenses and Other(26.4)
Income Tax Expense(12.5)
Equity Earnings of Unconsolidated Subsidiary(0.1)
Net Income Attributable to Noncontrolling Interest1.0 
Nine Months Ended September 30, 2020$161.8 


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

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


•Retail Margins decreased $8 increased $4 million primarily due to the following:
•A $29$35 million increase primarily due to rider increases in all jurisdictions and a base rate revenue increase in Arkansas. This increase was partially offset in other expense items below.
•A $6 million increase in municipal and cooperative revenues primarily due to formula rate true-ups.
•A $4 million increase in recoverable fuel costs primarily due to timing of recovery.
These increases were partially offset by:
•A $23 million decrease in weather-related usage primarily due to a 33%9% decrease in cooling degree days and a 29% decrease in heating degree days and a 12% decrease in cooling degree days.
•A $9$17 million decrease in FERC generation wholesale municipal and cooperative revenues due to an annual formula rate true-up.weather-normalized margins.
A $3•Transmission Revenues increased $56 million decrease primarily due to lower fuel cost recovery.the following:
These decreases were•A $36 million increase as a result of the annual transmission formula rate true-up. This increase was partially offset by:by an increase in transmission expenses in SPP.
•A $33$14 million increase due to rider revenue increasescontinued investment in Louisiana, Texas and Arkansas, partially offset in various expenses below.transmission projects.


Margins from Off-System Sales increased $4 million primarily due to higher sales prices.
126
Transmission Revenues decreased $6 million primarily due to an accrual for SPP sponsor-funded transmission upgrades in third quarter 2016. This decrease is offset by a corresponding decrease in Other Operation and Maintenance expenses below.








Expenses and Other and Income Tax Expense Equity Earnings (Loss) of Unconsolidated Subsidiary and Net Income Attributable to Noncontrolling Interest changed between years as follows:


•Other Operation and Maintenance expenses decreased $7 million primarily due to an accrual for SPP sponsor-funded transmission upgrades in third quarter 2016. This decrease is partially offset by a corresponding decrease in Transmission Revenues above.
Depreciation and Amortization expenses increased $10 million primarily due to a higher depreciable base.
the following:
Taxes Other than Income Taxes increased $6•A $20 million primarily due to an increase in property taxes.
Allowance for Equity Funds Used During Construction decreased $8 millionSPP transmission expenses primarily due to the completion of environmental projects.
annual transmission formula rate true-up. This increase was offset in Transmission Revenues above.
Income Tax Expense decreased•A $9 million primarilyincrease in administrative and general expenses and employee-related expenses.
These increases were partially offset by:
•An $8 million decrease due to income tax benefits attributable to SWEPCo’s noncontrolling interestthe capitalization of previously expensed North Central Wind Energy Facilities costs.
•A $6 million decrease in Sabine.generation plant maintenance expenses.
•A $4 million decrease in customer-related expenses primarily in energy efficiency programs. This decrease is offset by an increase in Net Income Attributable to Noncontrolling Interest below.
Retail Margins above.
Equity Earnings (Loss) of Unconsolidated Subsidiary decreased $9•Depreciation and Amortization expenses increased $17 million primarily due to a prior period income tax adjustment for DHLC.
higher depreciable base and an increase in Arkansas depreciation rates beginning in January 2020. This increase was partially offset in Retail Margins above.
Net •Income Attributable to Noncontrolling InterestTax Expense increased $9$13 million primarily due to income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine. This increase is offset by a decrease in Income Tax Expenseamortization of Excess ADIT and an increase in pretax book income. The decrease in amortization of Excess ADIT is partially offset in Retail Margins above.
127









SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20172020 and 20162019
(in millions)
(Unaudited)
 Three Months Ended Nine Months EndedThree Months EndedNine Months Ended
 September 30, September 30, September 30,September 30,
 2017 2016 2017 2016 2020201920202019
REVENUES        
REVENUES    
Electric Generation, Transmission and Distribution $509.5
 $530.5
 $1,321.8
 $1,324.1
Electric Generation, Transmission and Distribution$505.7 $536.5 $1,284.3 $1,344.8 
Sales to AEP Affiliates 7.7
 8.6
 20.4
 20.0
Sales to AEP Affiliates8.5 8.8 33.5 21.6 
Provision for Refund – AffiliatedProvision for Refund – Affiliated2.4 (0.1)(2.0)(25.3)
Other Revenues 0.4
 0.6
 1.4
 1.6
Other Revenues0.7 0.3 2.4 1.0 
TOTAL REVENUES 517.6
 539.7
 1,343.6
 1,345.7
TOTAL REVENUES517.3 545.5 1,318.2 1,342.1 
        
EXPENSES  
  
  
  
EXPENSES    
Fuel and Other Consumables Used for Electric Generation 147.5
 158.8
 389.8
 403.3
Fuel and Other Consumables Used for Electric Generation131.7 148.8 306.4 400.2 
Purchased Electricity for Resale 40.0
 35.9
 118.7
 97.5
Purchased Electricity for Resale41.0 44.8 125.1 110.5 
Other Operation 80.3
 89.2
 232.2
 243.3
Other Operation96.8 91.9 259.0 242.4 
Maintenance 32.6
 33.8
 106.5
 102.0
Maintenance30.7 35.9 97.2 104.1 
Depreciation and Amortization 55.2
 51.2
 158.1
 148.1
Depreciation and Amortization68.5 63.2 203.9 187.1 
Taxes Other Than Income Taxes 25.0
 23.4
 72.6
 66.8
Taxes Other Than Income Taxes26.7 26.2 77.0 76.0 
TOTAL EXPENSES 380.6
 392.3
 1,077.9
 1,061.0
TOTAL EXPENSES395.4 410.8 1,068.6 1,120.3 
        
OPERATING INCOME 137.0
 147.4
 265.7
 284.7
OPERATING INCOME121.9 134.7 249.6 221.8 
        
Other Income (Expense):  
  
  
  
Other Income (Expense):   
Interest Income 0.7
 —
 2.0
 —
Interest Income0.6 0.6 1.7 2.0 
Allowance for Equity Funds Used During Construction 0.4
 0.1
 1.2
 9.5
Allowance for Equity Funds Used During Construction3.4 1.6 5.7 4.5 
Non-Service Cost Components of Net Periodic Benefit CostNon-Service Cost Components of Net Periodic Benefit Cost2.1 2.1 6.3 6.4 
Interest Expense (31.9) (32.6) (92.7) (92.0)Interest Expense(29.3)(29.2)(89.1)(89.4)
        
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS (LOSS) 106.2
 114.9
 176.2
 202.2
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGSINCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS98.7 109.8 174.2 145.3 
        
Income Tax Expense 22.5
 33.2
 45.2
 53.9
Equity Earnings (Loss) of Unconsolidated Subsidiary 0.4
 2.7
 (4.5) 4.9
Income Tax Expense (Benefit)Income Tax Expense (Benefit)10.8 (0.7)12.5 0 
Equity Earnings of Unconsolidated SubsidiaryEquity Earnings of Unconsolidated Subsidiary0.7 0.8 2.2 2.3 
        
NET INCOME 84.1
 84.4
 126.5
 153.2
NET INCOME88.6 111.3 163.9 147.6 
        
Net Income Attributable to Noncontrolling Interest 11.0
 1.1
 12.6
 3.3
Net Income Attributable to Noncontrolling Interest0.7 0.8 2.1 3.1 
        
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER $73.1
 $83.3
 $113.9
 $149.9
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER$87.9 $110.5 $161.8 $144.5 
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 134.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
The common stock of SWEPCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.
128







SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20172020 and 20162019
(in millions)
(Unaudited)
 Three Months EndedNine Months Ended
 September 30,September 30,
 2020201920202019
Net Income$88.6 $111.3 $163.9 $147.6 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES    
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended September 30, 2020 and 2019, Respectively, and $0.3 and $0.3 for the Nine Months Ended September 30, 2020 and 2019, Respectively0.4 0.3 1.1 1.1 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $0 for the Three Months Ended September 30, 2020 and 2019, Respectively, and $(0.3) and $(0.2) for the Nine Months Ended September 30, 2020 and 2019, Respectively(0.4)(0.3)(1.1)(0.9)
TOTAL OTHER COMPREHENSIVE INCOME0 0 0 0.2 
TOTAL COMPREHENSIVE INCOME88.6 111.3 163.9 147.8 
Total Comprehensive Income Attributable to Noncontrolling Interest0.7 0.8 2.1 3.1 
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER$87.9 $110.5 $161.8 $144.7 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
129
 Three Months Ended Nine Months Ended
 September 30, September 30,
 2017 2016 2017 2016
Net Income$84.1
 $84.4
 $126.5
 $153.2
        
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES 
    
  
Cash Flow Hedges, Net of Tax of $0.2 and $0.2 for the Three Months Ended September 30, 2017 and 2016, Respectively, and $0.6 and $0.7 for the Nine Months Ended September 30, 2017 and 2016, Respectively0.4
 0.4
 1.1
 1.3
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2017 and 2016, Respectively, and $(0.3) and $(0.3) for the Nine Months Ended September 30, 2017 and 2016, Respectively(0.2) (0.1) (0.5) (0.5)
        
TOTAL OTHER COMPREHENSIVE INCOME0.2
 0.3
 0.6
 0.8
        
TOTAL COMPREHENSIVE INCOME84.3
 84.7
 127.1
 154.0
        
Total Comprehensive Income Attributable to Noncontrolling Interest11.0
 1.1
 12.6
 3.3
        
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER$73.3
 $83.6
 $114.5
 $150.7


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.





SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Nine Months Ended September 30, 20172020 and 20162019
(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, 2015$135.7
 $676.6
 $1,366.3
 $(9.4) $0.5
 $2,169.7
            
Common Stock Dividends    (90.0)     (90.0)
Common Stock Dividends – Nonaffiliated 
  
  
  
 (3.5) (3.5)
Net Income 
  
 149.9
  
 3.3
 153.2
Other Comprehensive Income 
  
  
 0.8
  
 0.8
TOTAL EQUITY - SEPTEMBER 30, 2016$135.7
 $676.6
 $1,426.2
 $(8.6) $0.3
 $2,230.2
            
TOTAL EQUITY - DECEMBER 31, 2016$135.7
 $676.6
 $1,411.9
 $(9.4) $0.4
 $2,215.2
            
Common Stock Dividends 
  
 (82.5)  
  
 (82.5)
Common Stock Dividends – Nonaffiliated 
  
  
  
 (2.7) (2.7)
Net Income 
  
 113.9
  
 12.6
 126.5
Other Comprehensive Income 
  
  
 0.6
  
 0.6
TOTAL EQUITY - SEPTEMBER 30, 2017$135.7
 $676.6
 $1,443.3
 $(8.8) $10.3
 $2,257.1
SWEPCo Common Shareholder  
Common
Stock		Paid-in
Capital		Retained
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Noncontrolling
Interest		Total
TOTAL EQUITY – DECEMBER 31, 2018$135.7 $676.6 $1,508.4 $(5.4)$0.3 $2,315.6 
Common Stock Dividends(18.7)(18.7)
Common Stock Dividends – Nonaffiliated(1.1)(1.1)
Net Income27.8 1.2 29.0 
Other Comprehensive Income0.1 0.1 
TOTAL EQUITY – MARCH 31, 2019135.7 676.6 1,517.5 (5.3)0.4 2,324.9 
Common Stock Dividends(18.8)(18.8)
Common Stock Dividends – Nonaffiliated    (1.1)(1.1)
Net Income  6.2  1.1 7.3 
Other Comprehensive Income   0.1  0.1 
TOTAL EQUITY – JUNE 30, 2019135.7 676.6 1,504.9 (5.2)0.4 2,312.4 
Common Stock Dividends – Nonaffiliated(1.1)(1.1)
Net Income110.5 0.8 111.3 
TOTAL EQUITY – SEPTEMBER 30, 2019$135.7 $676.6 $1,615.4 $(5.2)$0.1 $2,422.6 
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, 2020135.7 676.6 1,705.0 (1.3)0.1 2,516.1 
Reverse Common Stock Split (a)(135.6)135.6 0 
Common Stock Dividends – Nonaffiliated(0.4)(0.4)
Net Income87.9 0.7 88.6 
TOTAL EQUITY – SEPTEMBER 30, 2020$0.1 $812.2 $1,792.9 $(1.3)$0.4 $2,604.3 
(a)See Note 12 - Financing Activities for additional information.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118134.

130






SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20172020 and December 31, 20162019
(in millions)
(Unaudited)
 September 30,December 31,
 20202019
CURRENT ASSETS  
Cash and Cash Equivalents$25.6 $1.6 
Advances to Affiliates2.1 2.1 
Accounts Receivable:  
Customers12.7 29.0 
Affiliated Companies28.3 34.5 
Miscellaneous24.4 13.5 
Allowance for Uncollectible Accounts0 (1.7)
Total Accounts Receivable65.4 75.3 
Fuel
(September 30, 2020 and December 31, 2019 Amounts Include $48.7 and $47, Respectively, Related to Sabine)
210.5 140.1 
Materials and Supplies
(September 30, 2020 and December 31, 2019 Amounts Include $24 and $23.1, Respectively, Related to Sabine)
99.2 94.0 
Risk Management Assets4.5 6.4 
Regulatory Asset for Under-Recovered Fuel Costs7.0 4.9 
Prepayments and Other Current Assets29.7 29.7 
TOTAL CURRENT ASSETS444.0 354.1 
PROPERTY, PLANT AND EQUIPMENT  
Electric:  
Generation4,674.7 4,691.4 
Transmission2,109.6 2,056.5 
Distribution2,356.6 2,270.7 
Other Property, Plant and Equipment
(September 30, 2020 and December 31, 2019 Amounts Include $216.8 and $212.3, Respectively, Related to Sabine)
792.5 733.4 
Construction Work in Progress272.3 216.9 
Total Property, Plant and Equipment10,205.7 9,968.9 
Accumulated Depreciation and Amortization
(September 30, 2020 and December 31, 2019 Amounts Include $117.4 and $107.5, Respectively, Related to Sabine)
3,092.6 2,873.7 
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET7,113.1 7,095.2 
OTHER NONCURRENT ASSETS  
Regulatory Assets334.8 222.4 
Deferred Charges and Other Noncurrent Assets245.4 160.5 
TOTAL OTHER NONCURRENT ASSETS580.2 382.9 
TOTAL ASSETS$8,137.3 $7,832.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
131
  September 30, December 31,
  2017 2016
CURRENT ASSETS    
Cash and Cash Equivalents
(September 30, 2017 and December 31, 2016 Amounts Include $0 and $8.7, Respectively, Related to Sabine)
 $2.2
 $10.3
Advances to Affiliates 2.0
 169.8
Accounts Receivable:    
Customers 23.5
 48.5
Affiliated Companies 37.6
 29.3
Miscellaneous 20.8
 17.5
Allowance for Uncollectible Accounts (1.5) (1.2)
Total Accounts Receivable 80.4
 94.1
Fuel
(September 30, 2017 and December 31, 2016 Amounts Include $43.2 and $34.3, Respectively, Related to Sabine)
 93.1
 107.1
Materials and Supplies 68.8
 68.4
Risk Management Assets 12.5
 0.9
Accrued Tax Benefits 14.5
 51.5
Regulatory Asset for Under-Recovered Fuel Costs 13.6
 8.4
Prepayments and Other Current Assets 35.5
 35.5
TOTAL CURRENT ASSETS 322.6
 546.0
     
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Generation 4,632.9
 4,607.6
Transmission 1,656.4
 1,584.2
Distribution 2,084.2
 2,020.6
Other Property, Plant and Equipment
(September 30, 2017 and December 31, 2016 Amounts Include $266.6 and $267.5, Respectively, Related to Sabine)
 701.6
 670.4
Construction Work in Progress 145.2
 113.8
Total Property, Plant and Equipment 9,220.3
 8,996.6
Accumulated Depreciation and Amortization
(September 30, 2017 and December 31, 2016 Amounts Include $162.8 and $155.6, Respectively, Related to Sabine)
 2,670.5
 2,567.1
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 6,549.8
 6,429.5
     
OTHER NONCURRENT ASSETS    
Regulatory Assets 566.4
 551.2
Long-term Risk Management Assets 0.7
 —
Deferred Charges and Other Noncurrent Assets 116.4
 99.9
TOTAL OTHER NONCURRENT ASSETS 683.5
 651.1
     
TOTAL ASSETS $7,555.9
 $7,626.6


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.





SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 20172020 and December 31, 20162019
(Unaudited)
 September 30,December 31,
 20202019
 (in millions)
CURRENT LIABILITIES  
Advances from Affiliates$71.8 $59.9 
Accounts Payable:  
General183.3 138.0 
Affiliated Companies80.5 53.6 
Short-term Debt – Nonaffiliated42.0 18.3 
Long-term Debt Due Within One Year – Nonaffiliated6.2 121.2 
Risk Management Liabilities0.1 1.9 
Customer Deposits63.7 65.0 
Accrued Taxes90.1 41.8 
Accrued Interest23.0 34.6 
Obligations Under Operating Leases8.1 6.5 
Regulatory Liability for Over-Recovered Fuel Costs32.0 13.6 
Other Current Liabilities98.7 120.3 
TOTAL CURRENT LIABILITIES699.5 674.7 
NONCURRENT LIABILITIES  
Long-term Debt – Nonaffiliated2,631.1 2,534.4 
Long-term Risk Management Liabilities0.7 3.1 
Deferred Income Taxes965.0 940.9 
Regulatory Liabilities and Deferred Investment Tax Credits877.5 892.3 
Asset Retirement Obligations202.4 196.7 
Obligations Under Operating Leases43.8 34.7 
Deferred Credits and Other Noncurrent Liabilities113.0 114.3 
TOTAL NONCURRENT LIABILITIES4,833.5 4,716.4 
TOTAL LIABILITIES5,533.0 5,391.1 
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
EQUITY  
Common Stock – Par Value – $18 Per Share:  
Authorized – 3,680 Shares  
Outstanding – 3,680 Shares0.1 135.7 
Paid-in Capital812.2 676.6 
Retained Earnings1,792.9 1,629.5 
Accumulated Other Comprehensive Income (Loss)(1.3)(1.3)
TOTAL COMMON SHAREHOLDER’S EQUITY2,603.9 2,440.5 
Noncontrolling Interest0.4 0.6 
TOTAL EQUITY2,604.3 2,441.1 
TOTAL LIABILITIES AND EQUITY$8,137.3 $7,832.2 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
132
  September 30, December 31,
  2017 2016
  (in millions)
CURRENT LIABILITIES    
Advances from Affiliates $48.3
 $—
Accounts Payable:    
General 120.9
 117.5
Affiliated Companies 38.5
 68.5
Short-term Debt – Nonaffiliated 14.3
 —
Long-term Debt Due Within One Year – Nonaffiliated 385.4
 353.7
Risk Management Liabilities 0.1
 0.3
Customer Deposits 61.6
 62.1
Accrued Taxes 73.0
 40.9
Accrued Interest 25.1
 45.1
Obligations Under Capital Leases 11.4
 11.8
Other Current Liabilities 77.5
 83.9
TOTAL CURRENT LIABILITIES 856.1
 783.8
     
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated 2,056.1
 2,325.4
Deferred Income Taxes 1,694.5
 1,606.9
Regulatory Liabilities and Deferred Investment Tax Credits 441.3
 438.9
Asset Retirement Obligations 159.0
 147.1
Employee Benefits and Pension Obligations 19.9
 34.1
Obligations Under Capital Leases 60.2
 65.5
Deferred Credits and Other Noncurrent Liabilities 11.7
 9.7
TOTAL NONCURRENT LIABILITIES 4,442.7
 4,627.6
     
TOTAL LIABILITIES 5,298.8
 5,411.4
     
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 1,443.3
 1,411.9
Accumulated Other Comprehensive Income (Loss) (8.8) (9.4)
TOTAL COMMON SHAREHOLDER’S EQUITY 2,246.8
 2,214.8
     
Noncontrolling Interest 10.3
 0.4
     
TOTAL EQUITY 2,257.1
 2,215.2
     
TOTAL LIABILITIES AND EQUITY $7,555.9
 $7,626.6


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.





SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20172020 and 20162019
(in millions)
(Unaudited)
 Nine Months Ended September 30,
 20202019
OPERATING ACTIVITIES  
Net Income$163.9 $147.6 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
Depreciation and Amortization203.9 187.1 
Deferred Income Taxes(0.3)(15.9)
Allowance for Equity Funds Used During Construction(5.7)(4.5)
Mark-to-Market of Risk Management Contracts(2.3)(2.5)
Pension Contributions to Qualified Plan Trust(8.9)0 
Property Taxes(16.5)(16.1)
Deferred Fuel Over/Under-Recovery, Net16.3 14.1 
Change in Regulatory Assets(64.5)5.7 
Change in Other Noncurrent Assets3.2 (2.2)
Change in Other Noncurrent Liabilities21.0 5.8 
Changes in Certain Components of Working Capital:  
Accounts Receivable, Net8.0 (17.2)
Fuel, Materials and Supplies(70.9)(17.7)
Accounts Payable88.0 (12.8)
Accrued Taxes, Net46.6 54.1 
Other Current Assets1.3 (4.5)
Other Current Liabilities(50.3)(13.9)
Net Cash Flows from Operating Activities332.8 307.1 
INVESTING ACTIVITIES  
Construction Expenditures(319.5)(277.3)
Change in Advances to Affiliates, Net0 74.9 
Other Investing Activities4.8 (1.2)
Net Cash Flows Used for Investing Activities(314.7)(203.6)
FINANCING ACTIVITIES  
Change in Short-term Debt – Nonaffiliated23.7 0 
Change in Advances from Affiliates, Net11.9 0 
Retirement of Long-term Debt – Nonaffiliated(19.7)(58.2)
Principal Payments for Finance Lease Obligations(8.0)(8.1)
Dividends Paid on Common Stock0 (37.5)
Dividends Paid on Common Stock – Nonaffiliated(2.3)(3.3)
Other Financing Activities0.3 0.5 
Net Cash Flows from (Used for) Financing Activities5.9 (106.6)
Net Increase (Decrease) in Cash and Cash Equivalents24.0 (3.1)
Cash and Cash Equivalents at Beginning of Period1.6 24.5 
Cash and Cash Equivalents at End of Period$25.6 $21.4 
SUPPLEMENTARY INFORMATION  
Cash Paid for Interest, Net of Capitalized Amounts$95.2 $95.1 
Net Cash Paid for Income Taxes11.9 7.3 
Noncash Acquisitions Under Finance Leases5.9 4.7 
Construction Expenditures Included in Current Liabilities as of September 30,50.6 52.0 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 134.
133
  Nine Months Ended September 30,
  2017 2016
OPERATING ACTIVITIES  
  
Net Income $126.5
 $153.2
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
Depreciation and Amortization 158.1
 148.1
Deferred Income Taxes 79.8
 141.9
Allowance for Equity Funds Used During Construction (1.2) (9.5)
Mark-to-Market of Risk Management Contracts (12.5) (5.8)
Pension Contributions to Qualified Plan Trust (8.9) (8.3)
Property Taxes (15.4) (13.7)
Deferred Fuel Over/Under-Recovery, Net 2.4
 1.2
Change in Other Noncurrent Assets (2.9) 18.4
Change in Other Noncurrent Liabilities (5.2) (25.8)
Changes in Certain Components of Working Capital:    
Accounts Receivable, Net 12.1
 12.2
Fuel, Materials and Supplies 13.6
 33.4
Accounts Payable (25.7) (17.2)
Accrued Taxes, Net 69.1
 14.1
Accrued Interest (20.0) (20.0)
Other Current Assets 0.7
 (2.4)
Other Current Liabilities (14.6) (24.8)
Net Cash Flows from Operating Activities 355.9
 395.0
     
INVESTING ACTIVITIES    
Construction Expenditures (265.3) (315.3)
Change in Advances to Affiliates, Net 167.8
 (297.4)
Other Investing Activities 3.1
 (1.9)
Net Cash Flows Used for Investing Activities (94.4) (614.6)
     
FINANCING ACTIVITIES    
Issuance of Long-term Debt – Nonaffiliated 114.6
 402.2
Change in Short-term Debt – Nonaffiliated 14.3
 —
Change in Advances from Affiliates, Net 48.3
 (58.3)
Retirement of Long-term Debt – Nonaffiliated (353.6) (3.3)
Principal Payments for Capital Lease Obligations (8.4) (18.6)
Dividends Paid on Common Stock (82.5) (90.0)
Dividends Paid on Common Stock – Nonaffiliated (2.7) (3.5)
Other Financing Activities 0.4
 1.1
Net Cash Flows from (Used for) Financing Activities (269.6) 229.6
     
Net Increase (Decrease) in Cash and Cash Equivalents (8.1) 10.0
Cash and Cash Equivalents at Beginning of Period 10.3
 5.2
Cash and Cash Equivalents at End of Period $2.2
 $15.2
     
SUPPLEMENTARY INFORMATION    
Cash Paid for Interest, Net of Capitalized Amounts $109.4
 $107.6
Net Cash Paid (Received) for Income Taxes (70.5) (66.6)
Noncash Acquisitions Under Capital Leases 2.8
 5.5
Construction Expenditures Included in Current Liabilities as of September 30, 40.7
 54.3


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118.





INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANTS


The condensed notes to condensed financial statements are a combined presentation for the Registrants. The following list indicates Registrants to which the notes apply. Specific disclosures within each note apply to all Registrants unless indicated otherwise:
NoteRegistrantPage
Number
NoteRegistrant
Page
Number
Significant Accounting MattersAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
119135
New Accounting PronouncementsStandardsAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
121138
Comprehensive IncomeAEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo
124139
Rate MattersAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
136148
Commitments, Guarantees and ContingenciesAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
146159
Impairment, Disposition,Acquisitions and Assets and Liabilities Held for SaleImpairmentsAEP, I&MAPCo
152164
Benefit PlansAEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo
154166
Business SegmentsAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
158171
Derivatives and HedgingAEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo
164176
Fair Value MeasurementsAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
176188
Income TaxesAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
193204
Financing ActivitiesAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
195206
Property, Plant and EquipmentAEP, APCo
214
Revenue from Contracts with CustomersAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
215

134






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 nine months ended September 30, 20172020 is not necessarily indicative of results that may be expected for the year ending December 31, 2017.2020.  The condensed financial statements are unaudited and should be read in conjunction with the audited 20162019 financial statements and notes thereto, which are included in the Registrants (except AEPTCo)Registrants’ Annual Reports on Form 10-K as filed with the SEC on February 27, 2017. AEPTCo should20, 2020.

COVID-19

In March 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 could reduce future demand for energy, particularly from commercial and industrial customers.  The Registrants are taking steps to mitigate the potential risks to customers, suppliers and employees posed by the spread of COVID-19. 

As of September 30, 2020 and through the date of this report, the Registrants assessed certain accounting matters that require consideration of forecasted financial information, including, but not limited to, the allowance for credit losses and the carrying value of long-lived assets.  While there were not any impairments or significant increases in credit allowances resulting from these assessments for the three and nine months ended September 30, 2020, the ultimate impact of COVID-19 also depends on factors beyond management’s knowledge or control, including the duration and severity of this outbreak as well as third-party actions taken to contain its spread and mitigate its public health effects. Therefore, management cannot estimate the potential future impact to financial position, results of operations and cash flows, but the impacts could be readmaterial.

Voluntary Retirement Incentive Program

In June 2020, AEP announced a voluntary retirement incentive program. Eligible employees volunteered for retirement from the date of the announcement through July 6, 2020, with most having an effective retirement date of August 1, 2020. Participating employees were eligible to receive up to six months base pay and a medical premium subsidy. Certain participating employees were also eligible to receive a long-term incentive plan grant, with immediate vesting, of AEP common shares. A total of 200 employees participated in conjunction with the audited 2016voluntary retirement program. In August 2020, AEP recorded a charge to expense of $13 million primarily related to lump sum salary payments and cash subsidies. AEP also recorded a charge to expense of $5 million related to the incremental Long-Term Incentive Plan grants issued related to this initiative. Approximately 92% of the expense was within the AEPSC and was allocated among affiliated entities including the Registrant Subsidiaries. The impact of this program was immaterial on the Registrants’ financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 2017.of September 30, 2020.



135





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 tables presenttable presents AEP’s basic and diluted EPS calculations included on the statements of income:
Three Months Ended September 30,
20202019
(in millions, except per share data)
 $/share$/share
Earnings Attributable to AEP Common Shareholders$748.6  $733.5  
Weighted Average Number of Basic Shares Outstanding496.2 $1.51 493.8 $1.49 
Weighted Average Dilutive Effect of Stock-Based Awards1.3 (0.01)1.7 (0.01)
Weighted Average Number of Diluted Shares Outstanding497.5 $1.50 495.5 $1.48 
 Three Months Ended September 30,
 2017 2016
 (in millions, except per share data)
  
 $/share   $/share
Income (Loss) from Continuing Operations$556.7
   $(764.2)  
Less: Net Income Attributable to Noncontrolling Interests12.0
   1.6
  
Earnings (Loss) Attributable to AEP Common Shareholders from Continuing Operations$544.7
  
 $(765.8)  
        
Weighted Average Number of Basic Shares Outstanding491.8
 $1.11
 491.7
 $(1.56)
Weighted Average Dilutive Effect of Stock-Based Awards1.2
 (0.01) 0.1
 —
Weighted Average Number of Diluted Shares Outstanding493.0
 $1.10
 491.8
 $(1.56)

Nine Months Ended September 30,
20202019
(in millions, except per share data)
$/share$/share
Earnings Attributable to AEP Common Shareholders$1,764.6 $1,767.6 
Weighted Average Number of Basic Shares Outstanding495.5 $3.56 493.6 $3.58 
Weighted Average Dilutive Effect of Stock-Based Awards1.4 (0.01)1.5 (0.01)
Weighted Average Number of Diluted Shares Outstanding496.9 $3.55 495.1 $3.57 
 Nine Months Ended September 30,
 2017 2016
 (in millions, except per share data)
  
 $/share   $/share
Income from Continuing Operations$1,527.1
   $245.3
  
Less: Net Income Attributable to Noncontrolling Interests15.2
   5.3
  
Earnings Attributable to AEP Common Shareholders from Continuing Operations$1,511.9
   $240.0
  
        
Weighted Average Number of Basic Shares Outstanding491.8
 $3.07
 491.4
 $0.49
Weighted Average Dilutive Effect of Stock-Based Awards0.6
 —
 0.2
 —
Weighted Average Number of Diluted Shares Outstanding492.4
 $3.07
 491.6
 $0.49


Equity Units are potentially dilutive securities but were excluded from the calculation of diluted EPS for the three and nine months ended September 30, 2020 and 2019, as the dilutive stock price thresholds were not met. See Note 12 - Financing Activities for more information related to Equity Units.

There were no0 antidilutive shares outstanding as of September 30, 20172020 and 2016.2019.



Nonconsolidated Variable Interest EntityRestricted Cash (Applies to AEP, AEP Texas and SWEPCo)APCo)


SWEPCo recorded prior year income tax adjustmentsRestricted Cash primarily included funds held by trustee for the payment of securitization bonds and contractually restricted deposits held for the future payment of the remaining construction activities at Santa Rita East.

Reconciliation of Cash, Cash Equivalents and Restricted Cash

The following tables provide a reconciliation of Cash, Cash Equivalents and Restricted Cash reported within the balance sheets that sum to the total of the same amounts shown on the statements of cash flows:
September 30, 2020
AEPAEP TexasAPCo
(in millions)
Cash and Cash Equivalents$409.7 $0.1 $3.9 
Restricted Cash54.1 44.8 9.3 
Total Cash, Cash Equivalents and Restricted Cash$463.8 $44.9 $13.2 

December 31, 2019
AEPAEP TexasAPCo
(in millions)
Cash and Cash Equivalents$246.8 $3.1 $3.3 
Restricted Cash185.8 154.7 23.5 
Total Cash, Cash Equivalents and Restricted Cash$432.6 $157.8 $26.8 
136






SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Allowance for Uncollectible Accounts

Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. The assessment is performed separately by each participating AEP subsidiary, which inherently contemplates any differences in geographical risk characteristics for the second quarter of 2017allowance. For receivables related to DHLC that impacted Equity Earnings (Loss)APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For AEP Texas, bad debt reserves are calculated using the specific identification of Unconsolidated Subsidiaryreceivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable, unless specifically identified. In addition to these processes, management contemplates available current information, as well as any reasonable and supportable forecast information, to determine if allowances for uncollectible accounts should be further adjusted in accordance with the amountaccounting guidance for “Credit Losses.” Management’s assessments contemplate expected losses over the life of $6 million.

Supplementary Cash Flow Information (Applies to AEP)the accounts receivable.
137
  Nine Months Ended September 30,
Cash Flow Information 2017 2016
  (in millions)
Cash Paid (Received) for:    
Interest, Net of Capitalized Amounts $613.8
 $637.0
Income Taxes, Net (6.8) 32.2
Noncash Investing and Financing Activities:    
Acquisitions Under Capital Leases 44.5
 65.8
Construction Expenditures Included in Current Liabilities as of September 30, 791.6
 604.8
Construction Expenditures Included in Noncurrent Liabilities as of September 30, 71.8
 —
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, 0.6
 0.3
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage 2.8
 —







2. NEW ACCOUNTING PRONOUNCEMENTSSTANDARDS


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


UponDuring 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 final pronouncementsstandards will impact the financial statements.


ASU 2014-09 “Revenue from Contracts with Customers”2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2014-09)2016-13)


In May 2014,June 2016, the FASB issued ASU 2014-09 clarifying2016-13 requiring the method usedrecognition of an allowance for expected credit losses for financial instruments within its scope. Examples of financial instruments that are in scope include trade receivables, certain financial guarantees and held-to-maturity debt securities. The allowance for expected credit losses should be based on historical information, current conditions and reasonable and supportable forecasts. Entities are required to determineevaluate, and if necessary, recognize expected credit losses at the timinginception or initial acquisition of a financial instrument (or pool of financial instruments that share similar risk characteristics) subject to ASU 2016-13, and subsequently as of each reporting date. The new standard also revises the other-than-temporary impairment model for available-for-sale debt securities.

New standard implementation activities included: (a) the identification and evaluation of the population of financial instruments within the AEP system that are subject to the new standard, (b) the development of supporting valuation models to also contemplate appropriate metrics for current and supportable forecasted information and (c) the development of disclosures to comply with the requirements for revenue recognitionof ASU 2016-13. As required by ASU 2016-13, the financial instruments subject to the new standard were evaluated on a pool-basis to the extent such financial instruments shared similar risk characteristics.

Management adopted ASU 2016-13 and its related implementation guidance effective January 1, 2020, by means of an immaterial cumulative-effect adjustment to Retained Earnings on the statementsbalance sheets. The adoption of income.the new standard did not have a material impact to financial position and had no impact on the results of operations or cash flows. Additionally, the adoption of the new standard did not result in any changes to current accounting systems.

ASU 2020-04 “Reference Rate Reform: Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (ASU 2020-04)

In March 2020, the FASB issued ASU 2020-04 providing guidance to ease the potential burden in accounting for Reference Rate Reform on financial reporting. The new standard is elective and applies to all entities, subject to meeting certain criteria, that have contracts, hedging relationships, and other transactions that reference the London Interbank Offered Rate (LIBOR) or another reference rate expected to be discontinued because of Reference Rate Reform. The new standard establishes a general contract modification principle that entities can apply in other areas that may be affected by Reference Rate Reform and certain elective hedge accounting expedients. Under the new standard, an entity must identify the performance obligations inmay make a contract, determine the transaction price and allocate the priceone-time election to specific performance obligationssell or 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.

The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted.

Management continues to analyze the impact of the new revenue standard and related ASUs. During 2016 and 2017, revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expect a material impacttransfer to the timing of revenue recognizedavailable-for-sale or net incometrading classifications (or both sell and plans to elect the modified retrospective transition approach upon adoption.

The evaluation of revenue streams, new contractstransfer), debt securities that both reference an affected rate, and the new revenue standard’s disclosure requirements continues during the fourth quarter of 2017, in particular with respect to various ongoing industry implementation issues. Management will continue to analyze the related impacts to revenue recognition and monitor any new industry implementation issues that arise. Further, given industry conclusions related to implementation issues, including contributions in aid of construction and collectability, management does not anticipate changes to current accounting systems. Management plans to adopt ASU 2014-09 effectivewere classified as held-to-maturity before January 1, 2018.2020.

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

In January 2016, the FASB issued ASU 2016-01 enhancing 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. 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 afterall entities as of March 12, 2020 through December 15, 2017 with early adoption permitted.31, 2022. The amendments willmay be applied by meansto contract modifications as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a cumulative-effect adjustmentdate within an interim period that includes or is subsequent to March 12, 2020, up to the balance sheetdate that the financial statements are available to be issued. The amendments may be applied to eligible hedging relationships existing as of the beginning of the fiscal yearinterim period that includes March 12, 2020 and to new eligible hedging relationships entered into after the beginning of adoption.the interim period that includes March 12, 2020. The one-time election to sell, transfer, or both sell and transfer debt securities classified as held-to-maturity may be made at any time after March 12, 2020 but no later than December 31, 2022. Management has yet to apply the amendments in the new standard to any contract modifications, hedging relationships, or debt securities. 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 2016-01 effective January 1, 2018.



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. The guidance will be applied 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.

Management continues to analyze the impact of the new 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.

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, but not results of operations, financial position or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019.

138
ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09)



In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income.


Management adopted ASU 2016-09 effective January 1, 2017. As a result of the adoption of this guidance, management made an accounting policy election to recognize the effect of forfeitures in compensation cost when they occur. There was an immaterial impact on results of operations and financial position and no impact on cash flows at adoption.



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 2016-18 “Restricted Cash” (ASU 2016-18)

In November 2016, the FASB issued ASU 2016-18 clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows.

The new accounting guidance is effective for annual periods beginning after December 15, 2017. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report.

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 in 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. For 2016, AEP’s actual non-service cost components were a credit of $66 million, of which approximately 37% was capitalized.

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Management plans to adopt ASU 2017-07 effective January 1, 2018.

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 new 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 net income.


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 condensed financial statements.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 and nine months ended September 30, 2017 and 2016.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.


AEP

 Cash Flow HedgesPension 
Three Months Ended September 30, 2020CommodityInterest Rateand OPEBTotal
 (in millions)
Balance in AOCI as of June 30, 2020$(81.4)$(55.3)$(36.2)$(172.9)
Change in Fair Value Recognized in AOCI10.2 1.9 (a)0 12.1 
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (b)(0.1)0 0 (0.1)
Purchased Electricity for Resale (b)33.3 0 0 33.3 
Interest Expense (b)0 1.3 0 1.3 
Amortization of Prior Service Cost (Credit)0 0 (4.9)(4.9)
Amortization of Actuarial (Gains) Losses0 0 2.6 2.6 
Reclassifications from AOCI, before Income Tax (Expense) Benefit33.2 1.3 (2.3)32.2 
Income Tax (Expense) Benefit7.1 0.2 (0.5)6.8 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit26.1 1.1 (1.8)25.4 
Net Current Period Other Comprehensive Income (Loss)36.3 3.0 (1.8)37.5 
Balance in AOCI as of September 30, 2020$(45.1)$(52.3)$(38.0)$(135.4)
Changes in Accumulated Other Comprehensive Income (Loss) by Component
 Cash Flow HedgesPension 
Three Months Ended September 30, 2019CommodityInterest Rateand OPEBTotal
 (in millions)
Balance in AOCI as of June 30, 2019$(127.2)$(15.9)$(87.6)$(230.7)
Change in Fair Value Recognized in AOCI38.4 (0.8)(c)0 37.6 
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (b)(0.1)0 0 (0.1)
Purchased Electricity for Resale (b)8.5 0 0 8.5 
Amortization of Prior Service Cost (Credit)0 0 (4.8)(4.8)
Amortization of Actuarial (Gains) Losses0 0 3.0 3.0 
Reclassifications from AOCI, before Income Tax (Expense) Benefit8.4 0 (1.8)6.6 
Income Tax (Expense) Benefit1.8 0 (0.4)1.4 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit6.6 0 (1.4)5.2 
Net Current Period Other Comprehensive Income (Loss)45.0 (0.8)(1.4)42.8 
Balance in AOCI as of September 30, 2019$(82.2)$(16.7)$(89.0)$(187.9)
For the Three Months Ended September 30, 2017
139





 Cash Flow Hedges      
 Commodity Interest Rate Securities
Available for Sale		 Pension
and OPEB		 Total
 (in millions)
Balance in AOCI as of June 30, 2017$(36.0) $(10.4) $10.2
 $(125.4) $(161.6)
Change in Fair Value Recognized in AOCI(15.8) (2.0) 0.9
 —
 (16.9)
Amount of (Gain) Loss Reclassified from AOCI         
Generation & Marketing Revenues(0.9) —
 —
 —
 (0.9)
Purchased Electricity for Resale4.9
 —
 —
 —
 4.9
Interest Expense—
 0.4
 —
 —
 0.4
Amortization of Prior Service Cost (Credit)—
 —
 —
 (5.0) (5.0)
Amortization of Actuarial (Gains)/Losses—
 —
 —
 5.4
 5.4
Reclassifications from AOCI, before Income Tax (Expense) Credit4.0
 0.4
 —
 0.4
 4.8
Income Tax (Expense) Credit1.4
 0.2
 —
 0.1
 1.7
Reclassifications from AOCI, Net of Income Tax (Expense) Credit2.6
 0.2
 —
 0.3
 3.1
Net Current Period Other Comprehensive Income (Loss)(13.2) (1.8) 0.9
 0.3
 (13.8)
Balance in AOCI as of September 30, 2017$(49.2) $(12.2) $11.1
 $(125.1) $(175.4)


AEP

 Cash Flow HedgesPension 
Nine Months Ended September 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(48.6)(43.6)(a)0 (92.2)
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (b)(0.3)0 0 (0.3)
Purchased Electricity for Resale (b)135.7 0 0 135.7 
Interest Expense (b)0 3.6 0 3.6 
Amortization of Prior Service Cost (Credit)0 0 (14.4)(14.4)
Amortization of Actuarial (Gains) Losses0 0 7.7 7.7 
Reclassifications from AOCI, before Income Tax (Expense) Benefit135.4 3.6 (6.7)132.3 
Income Tax (Expense) Benefit28.4 0.8 (1.4)27.8 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit107.0 2.8 (5.3)104.5 
Net Current Period Other Comprehensive Income (Loss)58.4 (40.8)(5.3)12.3 
Balance in AOCI as of September 30, 2020$(45.1)$(52.3)$(38.0)$(135.4)
Changes in Accumulated Other Comprehensive Income (Loss) by Component
 Cash Flow HedgesPension 
Nine Months Ended September 30, 2019CommodityInterest Rateand OPEBTotal
 (in millions)
Balance in AOCI as of December 31, 2018$(23.0)$(12.6)$(84.8)$(120.4)
Change in Fair Value Recognized in AOCI(92.3)(4.5)(c)0 (96.8)
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (b)(0.1)0 0 (0.1)
Purchased Electricity for Resale (b)42.0 0 0 42.0 
Interest Expense (b)0 0.5 0 0.5 
Amortization of Prior Service Cost (Credit)0 0 (14.3)(14.3)
Amortization of Actuarial (Gains) Losses0 0 9.0 9.0 
Reclassifications from AOCI, before Income Tax (Expense) Benefit41.9 0.5 (5.3)37.1 
Income Tax (Expense) Benefit8.8 0.1 (1.1)7.8 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit33.1 0.4 (4.2)29.3 
Net Current Period Other Comprehensive Income (Loss)(59.2)(4.1)(4.2)(67.5)
Balance in AOCI as of September 30, 2019$(82.2)$(16.7)$(89.0)$(187.9)
For the Three Months Ended September 30, 2016
140





 Cash Flow Hedges      
 Commodity Interest Rate 
Securities
Available for Sale
 
Pension
and OPEB
 Total
 (in millions)
Balance in AOCI as of June 30, 2016$1.9
 $(16.5) $8.3
 $(111.6) $(117.9)
Change in Fair Value Recognized in AOCI(26.7) —
 0.5
 —
 (26.2)
Amount of (Gain) Loss Reclassified from AOCI         
Generation & Marketing Revenues(5.4) —
 —
 —
 (5.4)
Purchased Electricity for Resale1.8
 —
 —
 —
 1.8
Interest Expense—
 0.6
 —
 —
 0.6
Amortization of Prior Service Cost (Credit)—
 —
 —
 (4.8) (4.8)
Amortization of Actuarial (Gains)/Losses—
 —
 —
 5.0
 5.0
Reclassifications from AOCI, before Income Tax (Expense) Credit(3.6) 0.6
 —
 0.2
 (2.8)
Income Tax (Expense) Credit(1.3) 0.2
 —
 —
 (1.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit(2.3) 0.4
 —
 0.2
 (1.7)
Net Current Period Other Comprehensive Income (Loss)(29.0) 0.4
 0.5
 0.2
 (27.9)
Balance in AOCI as of September 30, 2016$(27.1) $(16.1) $8.8
 $(111.4) $(145.8)
AEP Texas

Cash Flow Hedge –Pension
Three Months Ended September 30, 2020Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of June 30, 2020$(2.9)$(9.3)$(12.2)
Change in Fair Value Recognized in AOCI0 0 0 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)0.4 0 0.4 
Amortization of Prior Service Cost (Credit)0 (0.1)(0.1)
Amortization of Actuarial (Gains) Losses0 0.1 0.1 
Reclassifications from AOCI, before Income Tax (Expense) Benefit0.4 0 0.4 
Income Tax (Expense) Benefit0.1 0 0.1 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0.3 0 0.3 
Net Current Period Other Comprehensive Income (Loss)0.3 0 0.3 
Balance in AOCI as of September 30, 2020$(2.6)$(9.3)$(11.9)

Cash Flow Hedge –Pension
Three Months Ended September 30, 2019Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of June 30, 2019$(3.9)$(10.6)$(14.5)
Change in Fair Value Recognized in AOCI0.3 0 0.3 
Amount of (Gain) Loss Reclassified from AOCI
Amortization of Prior Service Cost (Credit)0 (0.1)(0.1)
Amortization of Actuarial (Gains) Losses0 0.1 0.1 
Reclassifications from AOCI, before Income Tax (Expense) Benefit0 0 0 
Income Tax (Expense) Benefit0 0 0 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0 0 0 
Net Current Period Other Comprehensive Income (Loss)0.3 0 0.3 
Balance in AOCI as of September 30, 2019$(3.6)$(10.6)$(14.2)

Cash Flow Hedge –Pension
Nine Months Ended September 30, 2020Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2019$(3.4)$(9.4)$(12.8)
Change in Fair Value Recognized in AOCI0 0 0 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)1.0 0 1.0 
Amortization of Prior Service Cost (Credit)0 (0.1)(0.1)
Amortization of Actuarial (Gains) Losses0 0.2 0.2 
Reclassifications from AOCI, before Income Tax (Expense) Benefit1.0 0.1 1.1 
Income Tax (Expense) Benefit0.2 0 0.2 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0.8 0.1 0.9 
Net Current Period Other Comprehensive Income (Loss)0.8 0.1 0.9 
Balance in AOCI as of September 30, 2020$(2.6)$(9.3)$(11.9)
AEP
Cash Flow Hedge –Pension
Nine Months Ended September 30, 2019Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2018$(4.4)$(10.7)$(15.1)
Change in Fair Value Recognized in AOCI0.3 0 0.3 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)0.6 0 0.6 
Amortization of Prior Service Cost (Credit)0 (0.1)(0.1)
Amortization of Actuarial (Gains) Losses0 0.2 0.2 
Reclassifications from AOCI, before Income Tax (Expense) Benefit0.6 0.1 0.7 
Income Tax (Expense) Benefit0.1 0 0.1 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0.5 0.1 0.6 
Net Current Period Other Comprehensive Income (Loss)0.8 0.1 0.9 
Balance in AOCI as of September 30, 2019$(3.6)$(10.6)$(14.2)

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 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) $(156.3)
Change in Fair Value Recognized in AOCI(39.4) 2.7
 2.7
 —
 (34.0)
Amount of (Gain) Loss Reclassified from AOCI         
Generation & Marketing Revenues(5.6) —
 —
 —
 (5.6)
Purchased Electricity for Resale26.0
 —
 —
 —
 26.0
Interest Expense—
 1.2
 —
 —
 1.2
Amortization of Prior Service Cost (Credit)—
 —
 —
 (14.8) (14.8)
Amortization of Actuarial (Gains)/Losses—
 —
 —
 16.0
 16.0
Reclassifications from AOCI, before Income Tax (Expense) Credit20.4
 1.2
 —
 1.2
 22.8
Income Tax (Expense) Credit7.1
 0.4
 —
 0.4
 7.9
Reclassifications from AOCI, Net of Income Tax (Expense) Credit13.3
 0.8
 —
 0.8
 14.9
Net Current Period Other Comprehensive Income (Loss)(26.1) 3.5
 2.7
 0.8
 (19.1)
Balance in AOCI as of September 30, 2017$(49.2) $(12.2) $11.1
 $(125.1) $(175.4)

AEP

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2016
 Cash Flow Hedges      
 Commodity Interest Rate 
Securities
Available for Sale
 
Pension
and OPEB
 Total
 (in millions)
Balance in AOCI as of December 31, 2015$(5.2) $(17.2) $7.1
 $(111.8) $(127.1)
Change in Fair Value Recognized in AOCI(17.7) —
 1.7
 —
 (16.0)
Amount of (Gain) Loss Reclassified from AOCI         
Generation & Marketing Revenues(20.7) —
 —
 —
 (20.7)
Purchased Electricity for Resale14.2
 —
 —
 —
 14.2
Interest Expense—
 1.7
 —
 —
 1.7
Amortization of Prior Service Cost (Credit)—
 —
 —
 (14.6) (14.6)
Amortization of Actuarial (Gains)/Losses—
 —
 —
 15.2
 15.2
Reclassifications from AOCI, before Income Tax (Expense) Credit(6.5) 1.7
 —
 0.6
 (4.2)
Income Tax (Expense) Credit(2.3) 0.6
 —
 0.2
 (1.5)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit(4.2) 1.1
 —
 0.4
 (2.7)
Net Current Period Other Comprehensive Income (Loss)(21.9) 1.1
 1.7
 0.4
 (18.7)
Balance in AOCI as of September 30, 2016$(27.1) $(16.1) $8.8
 $(111.4) $(145.8)




APCo

Cash Flow Hedge –Pension
Three Months Ended September 30, 2020Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of June 30, 2020$(4.1)$2.2 $(1.9)
Change in Fair Value Recognized in AOCI0.7 0 0.7 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)(0.2)0 (0.2)
Amortization of Prior Service Cost (Credit)0 (1.3)(1.3)
Amortization of Actuarial (Gains) Losses0 0.1 0.1 
Reclassifications from AOCI, before Income Tax (Expense) Benefit(0.2)(1.2)(1.4)
Income Tax (Expense) Benefit(0.1)(0.3)(0.4)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit(0.1)(0.9)(1.0)
Net Current Period Other Comprehensive Income (Loss)0.6 (0.9)(0.3)
Balance in AOCI as of September 30, 2020$(3.5)$1.3 $(2.2)
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Cash Flow Hedge –Pension
Three Months Ended September 30, 2019Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of June 30, 2019$1.4 $(8.1)$(6.7)
Change in Fair Value Recognized in AOCI(0.3)0 (0.3)
Amount of (Gain) Loss Reclassified from AOCI
Amortization of Prior Service Cost (Credit)0 (1.4)(1.4)
Amortization of Actuarial (Gains) Losses0 0.6 0.6 
Reclassifications from AOCI, before Income Tax (Expense) Benefit0 (0.8)(0.8)
Income Tax (Expense) Benefit0 (0.2)(0.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0 (0.6)(0.6)
Net Current Period Other Comprehensive Income (Loss)(0.3)(0.6)(0.9)
Balance in AOCI as of September 30, 2019$1.1 $(8.7)$(7.6)
For the Three Months Ended September 30, 2017
Cash Flow Hedge –Pension
Nine Months Ended September 30, 2020Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2019$0.9 $4.1 $5.0 
Change in Fair Value Recognized in AOCI(3.8)0 (3.8)
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)(0.8)0 (0.8)
Amortization of Prior Service Cost (Credit)0 (4.0)(4.0)
Amortization of Actuarial (Gains) Losses0 0.4 0.4 
Reclassifications from AOCI, before Income Tax (Expense) Benefit(0.8)(3.6)(4.4)
Income Tax (Expense) Benefit(0.2)(0.8)(1.0)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit(0.6)(2.8)(3.4)
Net Current Period Other Comprehensive Income (Loss)(4.4)(2.8)(7.2)
Balance in AOCI as of September 30, 2020$(3.5)$1.3 $(2.2)
Cash Flow Hedge –Pension
Nine Months Ended September 30, 2019Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2018$1.8 $(6.8)$(5.0)
Change in Fair Value Recognized in AOCI(0.3)0 (0.3)
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)(0.5)0 (0.5)
Amortization of Prior Service Cost (Credit)0 (4.0)(4.0)
Amortization of Actuarial (Gains) Losses0 1.6 1.6 
Reclassifications from AOCI, before Income Tax (Expense) Benefit(0.5)(2.4)(2.9)
Income Tax (Expense) Benefit(0.1)(0.5)(0.6)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit(0.4)(1.9)(2.3)
Net Current Period Other Comprehensive Income (Loss)(0.7)(1.9)(2.6)
Balance in AOCI as of September 30, 2019$1.1 $(8.7)$(7.6)

142





  Cash Flow Hedges    
  Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of June 30, 2017 $2.5
 $(11.9) $(9.4)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense (0.2) —
 (0.2)
Amortization of Prior Service Cost (Credit) —
 (1.4) (1.4)
Amortization of Actuarial (Gains)/Losses —
 0.9
 0.9
Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2) (0.5) (0.7)
Income Tax (Expense) Credit (0.1) (0.2) (0.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1) (0.3) (0.4)
Net Current Period Other Comprehensive Loss (0.1) (0.3) (0.4)
Balance in AOCI as of September 30, 2017 $2.4
 $(12.2) $(9.8)

APCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2016
  Cash Flow Hedges    
  Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of June 30, 2016 $3.2
 $(7.1) $(3.9)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense (0.2) —
 (0.2)
Amortization of Prior Service Cost (Credit) —
 (1.2) (1.2)
Amortization of Actuarial (Gains)/Losses —
 0.7
 0.7
Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2) (0.5) (0.7)
Income Tax (Expense) Credit —
 (0.2) (0.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2) (0.3) (0.5)
Net Current Period Other Comprehensive Loss (0.2) (0.3) (0.5)
Balance in AOCI as of September 30, 2016 $3.0
 $(7.4) $(4.4)




APCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2017
  Cash Flow Hedges    
  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 (0.8) —
 (0.8)
Amortization of Prior Service Cost (Credit) —
 (4.0) (4.0)
Amortization of Actuarial (Gains)/Losses —
 2.6
 2.6
Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8) (1.4) (2.2)
Income Tax (Expense) Credit (0.3) (0.5) (0.8)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.5) (0.9) (1.4)
Net Current Period Other Comprehensive Loss (0.5) (0.9) (1.4)
Balance in AOCI as of September 30, 2017 $2.4
 $(12.2) $(9.8)

APCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2016
  Cash Flow Hedges    
  Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of December 31, 2015 $3.6
 $(6.4) $(2.8)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense (0.8) —
 (0.8)
Amortization of Prior Service Cost (Credit) —
 (3.8) (3.8)
Amortization of Actuarial (Gains)/Losses —
 2.2
 2.2
Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8) (1.6) (2.4)
Income Tax (Expense) Credit (0.2) (0.6) (0.8)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6) (1.0) (1.6)
Net Current Period Other Comprehensive Loss (0.6) (1.0) (1.6)
Balance in AOCI as of September 30, 2016 $3.0
 $(7.4) $(4.4)




I&M

Cash Flow Hedge –Pension
Three Months Ended September 30, 2020Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of June 30, 2020$(9.1)$(1.7)$(10.8)
Change in Fair Value Recognized in AOCI0 0 0 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)0.5 0 0.5 
Amortization of Prior Service Cost (Credit)0 (0.3)(0.3)
Amortization of Actuarial (Gains) Losses0 0.2 0.2 
Reclassifications from AOCI, before Income Tax (Expense) Benefit0.5 (0.1)0.4 
Income Tax (Expense) Benefit0.1 0 0.1 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0.4 (0.1)0.3 
Net Current Period Other Comprehensive Income (Loss)0.4 (0.1)0.3 
Balance in AOCI as of September 30, 2020$(8.7)$(1.8)$(10.5)
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Cash Flow Hedge –Pension
Three Months Ended September 30, 2019Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of June 30, 2019$(10.7)$(2.4)$(13.1)
Change in Fair Value Recognized in AOCI0.4 0 0.4 
Amount of (Gain) Loss Reclassified from AOCI
Amortization of Prior Service Cost (Credit)0 (0.2)(0.2)
Amortization of Actuarial (Gains) Losses0 0.2 0.2 
Reclassifications from AOCI, before Income Tax (Expense) Benefit0 0 0 
Income Tax (Expense) Benefit0 0 0 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0 0 0 
Net Current Period Other Comprehensive Income (Loss)0.4 0 0.4 
Balance in AOCI as of September 30, 2019$(10.3)$(2.4)$(12.7)
For the
Cash Flow Hedge –Pension
Nine Months Ended September 30, 2020Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2019$(9.9)$(1.7)$(11.6)
Change in Fair Value Recognized in AOCI0 0 0 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)1.5 0 1.5 
Amortization of Prior Service Cost (Credit)0 (0.6)(0.6)
Amortization of Actuarial (Gains) Losses0 0.5 0.5 
Reclassifications from AOCI, before Income Tax (Expense) Benefit1.5 (0.1)1.4 
Income Tax (Expense) Benefit0.3 0 0.3 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit1.2 (0.1)1.1 
Net Current Period Other Comprehensive Income (Loss)1.2 (0.1)1.1 
Balance in AOCI as of September 30, 2020$(8.7)$(1.8)$(10.5)
Cash Flow Hedge –Pension
Nine Months Ended September 30, 2019Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2018$(11.5)$(2.3)$(13.8)
Change in Fair Value Recognized in AOCI0.4 0 0.4 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)1.0 0 1.0 
Amortization of Prior Service Cost (Credit)0 (0.6)(0.6)
Amortization of Actuarial (Gains) Losses0 0.5 0.5 
Reclassifications from AOCI, before Income Tax (Expense) Benefit1.0 (0.1)0.9 
Income Tax (Expense) Benefit0.2 0 0.2 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0.8 (0.1)0.7 
Net Current Period Other Comprehensive Income (Loss)1.2 (0.1)1.1 
Balance in AOCI as of September 30, 2019$(10.3)$(2.4)$(12.7)

143





OPCo
Cash Flow Hedge –
Three Months Ended September 30, 2020Interest Rate
(in millions)
Balance in AOCI as of June 30, 2020$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 September 30, 2020$0 
Cash Flow Hedge –
Three Months Ended September 30, 2019Interest Rate
(in millions)
Balance in AOCI as of June 30, 2019$0.3 
Change in Fair Value Recognized in AOCI(0.2)
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)(0.3)
Balance in AOCI as of September 30, 2019$0 
Cash Flow Hedge –
Nine Months Ended September 30, 2020Interest Rate
(in millions)
Balance in AOCI as of December 31, 2019$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 September 30, 2020$0 
Cash Flow Hedge –
Nine Months Ended September 30, 2019Interest Rate
(in millions)
Balance in AOCI as of December 31, 2018$1.0 
Change in Fair Value Recognized in AOCI(0.2)
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)(1.0)
Reclassifications from AOCI, before Income Tax (Expense) Benefit(1.0)
Income Tax (Expense) Benefit(0.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit(0.8)
Net Current Period Other Comprehensive Income (Loss)(1.0)
Balance in AOCI as of September 30, 2019$0 
144





PSO
Cash Flow Hedge –
Three Months Ended September 30, 2020Interest Rate
(in millions)
Balance in AOCI as of June 30, 2020$0.6 
Change in Fair Value Recognized in AOCI0 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)(0.3)
Reclassifications from AOCI, before Income Tax (Expense) Benefit(0.3)
Income Tax (Expense) Benefit0 
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 September 30, 2020$0.3 
Cash Flow Hedge –
Three Months Ended September 30, 2019Interest Rate
(in millions)
Balance in AOCI as of June 30, 2019$1.6 
Change in Fair Value Recognized in AOCI(0.3)
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)0.2 
Reclassifications from AOCI, before Income Tax (Expense) Benefit0.2 
Income Tax (Expense) Benefit0.1 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0.1 
Net Current Period Other Comprehensive Income (Loss)(0.2)
Balance in AOCI as of September 30, 2019$1.4 
Cash Flow Hedge –
Nine Months Ended September 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)(1.0)
Reclassifications from AOCI, before Income Tax (Expense) Benefit(1.0)
Income Tax (Expense) Benefit(0.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit(0.8)
Net Current Period Other Comprehensive Income (Loss)(0.8)
Balance in AOCI as of September 30, 2020$0.3 
Cash Flow Hedge –
Nine Months Ended September 30, 2019Interest Rate
(in millions)
Balance in AOCI as of December 31, 2018$2.1 
Change in Fair Value Recognized in AOCI(0.3)
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)(0.5)
Reclassifications from AOCI, before Income Tax (Expense) Benefit(0.5)
Income Tax (Expense) Benefit(0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit(0.4)
Net Current Period Other Comprehensive Income (Loss)(0.7)
Balance in AOCI as of September 30, 2019$1.4 

145





SWEPCo
Cash Flow Hedge –Pension
Three Months Ended September 30, 2020Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of June 30, 2020$(1.1)$(0.2)$(1.3)
Change in Fair Value Recognized in AOCI0 0 0 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)0.5 0 0.5 
Amortization of Prior Service Cost (Credit)0 (0.5)(0.5)
Amortization of Actuarial (Gains) Losses0 0 0 
Reclassifications from AOCI, before Income Tax (Expense) Benefit0.5 (0.5)0 
Income Tax (Expense) Benefit0.1 (0.1)0 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0.4 (0.4)0 
Net Current Period Other Comprehensive Income (Loss)0.4 (0.4)0 
Balance in AOCI as of September 30, 2020$(0.7)$(0.6)$(1.3)
Cash Flow Hedge –Pension
Three Months Ended September 30, 2019Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of June 30, 2019$(2.5)$(2.7)$(5.2)
Change in Fair Value Recognized in AOCI0.3 0 0.3 
Amount of (Gain) Loss Reclassified from AOCI
Amortization of Prior Service Cost (Credit)0 (0.5)(0.5)
Amortization of Actuarial (Gains) Losses0 0.2 0.2 
Reclassifications from AOCI, before Income Tax (Expense) Benefit0 (0.3)(0.3)
Income Tax (Expense) Benefit0 0 0 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0 (0.3)(0.3)
Net Current Period Other Comprehensive Income (Loss)0.3 (0.3)0 
Balance in AOCI as of September 30, 2019$(2.2)$(3.0)$(5.2)
146





SWEPCo
Cash Flow Hedge –Pension
Nine Months Ended September 30, 2020Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2019$(1.8)$0.5 $(1.3)
Change in Fair Value Recognized in AOCI0 0 0 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)1.4 0 1.4 
Amortization of Prior Service Cost (Credit)0 (1.5)(1.5)
Amortization of Actuarial (Gains) Losses0 0.1 0.1 
Reclassifications from AOCI, before Income Tax (Expense) Benefit1.4 (1.4)0 
Income Tax (Expense) Benefit0.3 (0.3)0 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit1.1 (1.1)0 
Net Current Period Other Comprehensive Income (Loss)1.1 (1.1)0 
Balance in AOCI as of September 30, 2020$(0.7)$(0.6)$(1.3)
Cash Flow Hedge –Pension
Nine Months Ended September 30, 2019Interest Rateand OPEBTotal
(in millions)
Balance in AOCI as of December 31, 2018$(3.3)$(2.1)$(5.4)
Change in Fair Value Recognized in AOCI0.3 0 0.3 
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)1.0 0 1.0 
Amortization of Prior Service Cost (Credit)0 (1.5)(1.5)
Amortization of Actuarial (Gains) Losses0 0.4 0.4 
Reclassifications from AOCI, before Income Tax (Expense) Benefit1.0 (1.1)(0.1)
Income Tax (Expense) Benefit0.2 (0.2)0 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit0.8 (0.9)(0.1)
Net Current Period Other Comprehensive Income (Loss)1.1 (0.9)0.2 
Balance in AOCI as of September 30, 2019$(2.2)$(3.0)$(5.2)

(a)The change in fair value includes $(1) million and $6 million related to AEP's investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC for the three and nine months ended September 30, 20172020, respectively.
(b)Amounts reclassified to the referenced line item on the statements of income.
  Cash Flow Hedges    
  Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of June 30, 2017 $(11.3) $(4.2) $(15.5)
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) —
 (0.3) (0.3)
Amortization of Actuarial (Gains)/Losses —
 0.3
 0.3
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 0.3
 —
 0.3
Balance in AOCI as of September 30, 2017 $(11.0) $(4.2) $(15.2)

I&M

Changes(c)The change in Accumulated Other Comprehensive Income (Loss) by Component
Forfair value includes $2 million and $6 million related to AEP’s investment in joint venture wind farms acquired as part of the Three Months Endedpurchase of Sempra Renewables LLC for the three and nine months ended September 30, 20162019, respectively.
147
  Cash Flow Hedges    
  Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of June 30, 2016 $(12.6) $(3.4) $(16.0)
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) —
 (0.2) (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 0.3
 —
 0.3
Balance in AOCI as of September 30, 2016 $(12.3) $(3.4) $(15.7)







I&M

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2017

  Cash Flow Hedges    
  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 1.5
 —
 1.5
Amortization of Prior Service Cost (Credit) —
 (0.7) (0.7)
Amortization of Actuarial (Gains)/Losses —
 0.7
 0.7
Reclassifications from AOCI, before Income Tax (Expense) Credit 1.5
 —
 1.5
Income Tax (Expense) Credit 0.5
 —
 0.5
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.0
 —
 1.0
Net Current Period Other Comprehensive Income 1.0
 —
 1.0
Balance in AOCI as of September 30, 2017 $(11.0) $(4.2) $(15.2)

I&M

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2016
  Cash Flow Hedges    
  Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of December 31, 2015 $(13.3) $(3.4) $(16.7)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense 1.5
 —
 1.5
Amortization of Prior Service Cost (Credit) —
 (0.6) (0.6)
Amortization of Actuarial (Gains)/Losses —
 0.6
 0.6
Reclassifications from AOCI, before Income Tax (Expense) Credit 1.5
 —
 1.5
Income Tax (Expense) Credit 0.5
 —
 0.5
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.0
 —
 1.0
Net Current Period Other Comprehensive Income 1.0
 —
 1.0
Balance in AOCI as of September 30, 2016 $(12.3) $(3.4) $(15.7)



OPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2017
  Cash Flow Hedges
  Interest Rate
  (in millions)
Balance in AOCI as of June 30, 2017 $2.5
Change in Fair Value Recognized in AOCI —
Amount of (Gain) Loss Reclassified from AOCI  
Interest Expense (0.5)
Reclassifications from AOCI, before Income Tax (Expense) Credit (0.5)
Income Tax (Expense) Credit (0.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3)
Net Current Period Other Comprehensive Loss (0.3)
Balance in AOCI as of September 30, 2017 $2.2

OPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2016
  Cash Flow Hedges
  Interest Rate
  (in millions)
Balance in AOCI as of June 30, 2016 $3.5
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 Loss (0.2)
Balance in AOCI as of September 30, 2016 $3.3



OPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2017
  Cash Flow Hedges
  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 (1.3)
Reclassifications from AOCI, before Income Tax (Expense) Credit (1.3)
Income Tax (Expense) Credit (0.5)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.8)
Net Current Period Other Comprehensive Loss (0.8)
Balance in AOCI as of September 30, 2017 $2.2

OPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2016
  Cash Flow Hedges
  Interest Rate
  (in millions)
Balance in AOCI as of December 31, 2015 $4.3
Change in Fair Value Recognized in AOCI —
Amount of (Gain) Loss Reclassified from AOCI  
Interest Expense (1.4)
Reclassifications from AOCI, before Income Tax (Expense) Credit (1.4)
Income Tax (Expense) Credit (0.4)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0)
Net Current Period Other Comprehensive Loss (1.0)
Balance in AOCI as of September 30, 2016 $3.3



PSO

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2017
  Cash Flow Hedges
  Interest Rate
  (in millions)
Balance in AOCI as of June 30, 2017 $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 Loss (0.2)
Balance in AOCI as of September 30, 2017 $2.8
PSO

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2016
  Cash Flow Hedges
  Interest Rate
  (in millions)
Balance in AOCI as of June 30, 2016 $3.8
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 Loss (0.2)
Balance in AOCI as of September 30, 2016 $3.6



PSO

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2017
  Cash Flow Hedges
  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 (1.0)
Reclassifications from AOCI, before Income Tax (Expense) Credit (1.0)
Income Tax (Expense) Credit (0.4)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6)
Net Current Period Other Comprehensive Loss (0.6)
Balance in AOCI as of September 30, 2017 $2.8

PSO

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2016
  Cash Flow Hedges
  Interest Rate
  (in millions)
Balance in AOCI as of December 31, 2015 $4.2
Change in Fair Value Recognized in AOCI —
Amount of (Gain) Loss Reclassified from AOCI  
Interest Expense (0.9)
Reclassifications from AOCI, before Income Tax (Expense) Credit (0.9)
Income Tax (Expense) Credit (0.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6)
Net Current Period Other Comprehensive Loss (0.6)
Balance in AOCI as of September 30, 2016 $3.6



SWEPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2017
  Cash Flow Hedges    
  Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of June 30, 2017 $(6.7) $(2.3) $(9.0)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense 0.6
 —
 0.6
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 0.6
 (0.3) 0.3
Income Tax (Expense) Credit 0.2
 (0.1) 0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4
 (0.2) 0.2
Net Current Period Other Comprehensive Income (Loss) 0.4
 (0.2) 0.2
Balance in AOCI as of September 30, 2017 $(6.3) $(2.5) $(8.8)

SWEPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2016
  Cash Flow Hedges    
  Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of June 30, 2016 $(8.2) $(0.7) $(8.9)
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) —
 (0.4) (0.4)
Amortization of Actuarial (Gains)/Losses —
 0.2
 0.2
Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7
 (0.2) 0.5
Income Tax (Expense) Credit 0.3
 (0.1) 0.2
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4
 (0.1) 0.3
Net Current Period Other Comprehensive Income (Loss) 0.4
 (0.1) 0.3
Balance in AOCI as of September 30, 2016 $(7.8) $(0.8) $(8.6)



SWEPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2017
  Cash Flow Hedges    
  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 1.7
 —
 1.7
Amortization of Prior Service Cost (Credit) —
 (1.5) (1.5)
Amortization of Actuarial (Gains)/Losses —
 0.7
 0.7
Reclassifications from AOCI, before Income Tax (Expense) Credit 1.7
 (0.8) 0.9
Income Tax (Expense) Credit 0.6
 (0.3) 0.3
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.1
 (0.5) 0.6
Net Current Period Other Comprehensive Income (Loss) 1.1
 (0.5) 0.6
Balance in AOCI as of September 30, 2017 $(6.3) $(2.5) $(8.8)

SWEPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2016
  Cash Flow Hedges    
  Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of December 31, 2015 $(9.1) $(0.3) $(9.4)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense 2.0
 —
 2.0
Amortization of Prior Service Cost (Credit) —
 (1.4) (1.4)
Amortization of Actuarial (Gains)/Losses —
 0.6
 0.6
Reclassifications from AOCI, before Income Tax (Expense) Credit 2.0
 (0.8) 1.2
Income Tax (Expense) Credit 0.7
 (0.3) 0.4
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.3
 (0.5) 0.8
Net Current Period Other Comprehensive Income (Loss) 1.3
 (0.5) 0.8
Balance in AOCI as of September 30, 2016 $(7.8) $(0.8) $(8.6)


4.  RATE MATTERS


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


As discussed in AEP’s and AEPTCo’s 2016the 2019 Annual Reports,Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within AEP’s and AEPTCo’s 2016the 2019 Annual ReportsReport 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 20172020 and updates AEP’sthe 2019 Annual Report.

Regulated Generating Units to be Retired (Applies to AEP, PSO and AEPTCo’s 2016 Annual Reports.SWEPCo)


In September 2018, management announced that the Oklaunion Power Station was probable of abandonment and was expected to be retired. The Oklaunion Power Station was retired in September 2020.  PSO will seek recovery of the Oklaunion Power Station in its next base rate case. In October 2020, the Oklaunion Power Station site was sold to a non-affiliated third-party. See “Oklaunion Power Station” section of Note 6 for additional information.

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. In March 2020, management announced plans to retire the plant in 2021.

The table below summarizes the plant investment and their cost of removal, currently being recovered, as well as the regulatory assets for accelerated depreciation for the generating units as of September 30, 2020.
PlantGross
Investment
Including
CWIP		Accumulated
Depreciation		Net
Investment		Accelerated Depreciation Regulatory AssetMaterials and SuppliesCost of
Removal
Regulatory
Liability		Expected
Retirement
Date		Remaining
Recovery
Period
(dollars in millions)
Oklaunion Power Station$0 $0 $0 $38.0 (a)$3.4 $5.2 202027 years
Dolet Hills Power Station346.7 250.0 $96.7 50.4 (b)5.8 24.0 202127 years

(a)In October 2018, PSO changed depreciation rates to utilize the 2020 end-of-life and defer depreciation expense to a regulatory asset for the amount in excess of the previously OCC-approved depreciation rates for Oklaunion Power Station.
(b)In January 2020, SWEPCo changed depreciation rates to utilize the 2026 end-of-life and defer depreciation expense to a regulatory asset for the amount in excess of the previously APSC-approved depreciation rates for Dolet Hills Power Station. In March 2020, SWEPCo changed depreciation rates again to utilize the accelerated 2021 end-of-life.

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

During the second quarter of 2019, the Dolet Hills Power Station initiated a seasonal operating schedule. In January 2020, in accordance with the terms of SWEPCo’s settlement of its base rate review filed with the APSC, management announced that SWEPCo will seek regulatory approval to retire the Dolet Hills Power Station by the end of 2026. DHLC provides 100% of the fuel supply to Dolet Hills Power Station. After careful consideration of current economic conditions, and particularly for the benefit of their customers, management of SWEPCo and CLECO determined DHLC would not proceed developing additional Oxbow Lignite Company (Oxbow) mining areas for future lignite extraction and ceased extraction of lignite at the mine in May 2020. Based on these actions, management revised the estimated useful life of DHLC’s and Oxbow’s assets to coincide with the date at which extraction was discontinued in the second quarter of 2020 and the date at which delivery of lignite is expected to cease in September 2021. Management also revised the useful life of the Dolet Hills Power Station to 2021 based on the remaining estimated fuel supply available for continued seasonal operation. In March 2020, primarily due to the revision in the useful life of DHLC, SWEPCo recorded a revision to increase estimated ARO liabilities by $21 million. In April 2020, SWEPCo and CLECO jointly filed a notification letter to the LPSC providing notice of the cessation of lignite mining.

The Dolet Hills Power Station costs are recoverable by SWEPCo through base rates. SWEPCo’s share of the net investment in the Dolet Hills Power Station is $153 million, including CWIP and materials and supplies, before cost of removal.
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Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses. Under the Lignite Mining Agreement, DHLC bills SWEPCo its proportionate share of incurred lignite extraction and associated mining-related costs as fuel is delivered. As of September 30, 2020, DHLC has unbilled lignite inventory and fixed costs of $36 million that will be billed to SWEPCo prior to the closure of the Dolet Hills Power Station. In 2009, SWEPCo acquired interests in Oxbow, which owns mineral rights and leases land. Under a Joint Operating Agreement pertaining to the Oxbow mineral rights and land leases, Oxbow bills SWEPCo its proportionate share of incurred costs. As of September 30, 2020, Oxbow has unbilled fixed costs of $10 million that will be billed to SWEPCo prior to the closure of the Dolet Hills Power Station. DHLC and Oxbow have billed SWEPCo $111 million for lignite deliveries from April 2020 through September 2020, which primarily includes accelerated depreciation and amortization of fixed costs. Additional operational and land-related costs are expected to be incurred by DHLC and Oxbow and billed to SWEPCo prior to the closure of the Dolet Hills Power Station and recovered through fuel clauses.

In October 2020, SWEPCo filed a request with the LPSC for recovery of the Louisiana share of these additional fuel costs. SWEPCo’s filing proposes to defer $36 million of fuel costs in 2021 and recover the deferral plus carrying costs over five years beginning in 2022.

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

Regulatory Assets Pending Final Regulatory Approval (Applies to all Registrants except AEPTCo)
AEP
September 30,December 31,
20202019
 Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Earning a Return  
Dolet Hills Power Station Accelerated Depreciation$50.4 $0 
Kentucky Deferred Purchase Power Expenses38.5 30.2 
Oklaunion Power Station Accelerated Depreciation38.0 27.4 
Plant Retirement Costs – Unrecovered Plant35.2 35.2 
COVID-192.0 0 
Other Regulatory Assets Pending Final Regulatory Approval2.2 0.7 
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs86.3 7.2 
Plant Retirement Costs – Asset Retirement Obligation Costs25.9 30.1 
COVID-1920.3 0 
Asset Retirement Obligation8.7 7.2 
Vegetation Management Program (a)3.8 29.4 
Cook Plant Study Costs (b)0 7.6 
Other Regulatory Assets Pending Final Regulatory Approval5.3 6.7 
Total Regulatory Assets Pending Final Regulatory Approval (c)$316.6 $181.7 

(a)In April 2020, $26 million of deferred expenses were approved for recovery. See “2019 Texas Base Rate Case” section below for additional information.
(b)Approved for recovery in the first quarter of 2020 in the Indiana Base Rate Case.
(c)APCo is currently in the process of retiring and replacing its Virginia jurisdictional Automated Meter Reading (AMR) meters with AMI meters. As of September 30, 2020 and December 31, 2019, APCo has approximately $52 million and $51 million, respectively, of Virginia jurisdictional AMR meters recorded in Total Property, Plant and Equipment - Net on its balance sheets. APCo is pursuing full recovery of these assets through its Virginia depreciation rates. See “2017-2019 Virginia Triennial Review” section below for additional information.
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  AEP
  September 30, December 31,
  2017 2016
 Noncurrent Regulatory Assets (in millions)
     
Regulatory Assets Currently Earning a Return    
Plant Retirement Costs - Unrecovered Plant (a) $209.1
 $159.9
Storm-Related Costs 97.4
 25.1
Plant Retirement Costs - Materials and Supplies 9.1
 9.1
Ohio Capacity Deferral —
 96.7
Other Regulatory Assets Pending Final Regulatory Approval 1.1
 1.3
Regulatory Assets Currently Not Earning a Return  
  
Storm-Related Costs 42.6
 25.9
Plant Retirement Costs - Asset Retirement Obligation Costs 37.2
 29.6
Cook Plant Uprate Project 36.3
 36.3
Environmental Control Projects 24.3
 24.1
Cook Plant Turbine 15.1
 12.8
Deferred Cook Plant Life Cycle Management Project Costs - Michigan 13.0
 8.1
Other Regulatory Assets Pending Final Regulatory Approval 25.6
 21.2
Total Regulatory Assets Pending Final Regulatory Approval (b) $510.8
 $450.1
AEP Texas
September 30,December 31,
20202019
Noncurrent Regulatory Assets(in millions)
Regulatory Assets Currently Not Earning a Return  
COVID-19$10.9 $0 
Vegetation Management Program (a)3.8 29.4 
Other Regulatory Assets Pending Final Regulatory Approval1.4 1.4 
Total Regulatory Assets Pending Final Regulatory Approval$16.1 $30.8 

(a)In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of September 30, 2017, the unrecovered plant balance related to Northeastern Plant, Unit 3 was $52 million. 
(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. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018.



(a)In April 2020, $26 million of deferred expenses were approved for recovery. See “2019 Texas Base Rate Case” section below for additional information.
APCo
September 30,December 31,
20202019
Noncurrent Regulatory Assets(in millions)
Regulatory Assets Currently Earning a Return
COVID-19 – Virginia$2.0 $0 
Plant Retirement Costs – Materials and Supplies0 0.5 
Regulatory Assets Currently Not Earning a Return  
Plant Retirement Costs – Asset Retirement Obligation Costs25.9 30.1 
COVID-19 – West Virginia0.8 0 
Total Regulatory Assets Pending Final Regulatory Approval (a)$28.7 $30.6 

(a)APCo is currently in the process of retiring and replacing its Virginia jurisdictional Automated Meter Reading (AMR) meters with AMI meters. As of September 30, 2020 and December 31, 2019, APCo has approximately $52 million and $51 million, respectively, of Virginia jurisdictional AMR meters recorded in Total Property, Plant and Equipment - Net on its balance sheets. APCo is pursuing full recovery of these assets through its Virginia depreciation rates. See “2017-2019 Virginia Triennial Review” section below for additional information.
 I&M
September 30,December 31,
20202019
Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Not Earning a Return  
COVID-19$3.1 $0 
Cook Plant Study Costs (a)0 7.6 
Other Regulatory Assets Pending Final Regulatory Approval0 0.1 
Total Regulatory Assets Pending Final Regulatory Approval$3.1 $7.7 

(a)Approved for recovery in the first quarter of 2020 in the Indiana Base Rate Case.
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  APCo
  September 30, December 31,
  2017 2016
Noncurrent Regulatory Assets (in millions)
     
Regulatory Assets Currently Earning a Return    
Plant Retirement Costs - Materials and Supplies $9.1
 $9.1
Regulatory Assets Currently Not Earning a Return    
Plant Retirement Costs - Asset Retirement Obligation Costs 37.2
 29.6
Other Regulatory Assets Pending Final Regulatory Approval 0.6
 0.6
Total Regulatory Assets Pending Final Regulatory Approval (a) $46.9
 $39.3
 OPCo
September 30,December 31,
20202019
Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs$3.6 $0 
COVID-192.9 0 
Other Regulatory Assets Pending Final Regulatory Approval0.1 0.1 
Total Regulatory Assets Pending Final Regulatory Approval$6.6 $0.1 

(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. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018.

  I&M
  September 30, December 31,
  2017 2016
Noncurrent Regulatory Assets (in millions)
     
Regulatory Assets Currently Not Earning a Return    
Cook Plant Uprate Project $36.3
 $36.3
Cook Plant Turbine 15.1
 12.8
Deferred Cook Plant Life Cycle Management Project Costs - Michigan 13.0
 8.1
Rockport Dry Sorbent Injection System - Indiana 9.4
 6.6
Other Regulatory Assets Pending Final Regulatory Approval 1.5
 0.9
Total Regulatory Assets Pending Final Regulatory Approval $75.3
 $64.7
 PSO
September 30,December 31,
20202019
Noncurrent Regulatory Assets(in millions)
  
Regulatory Assets Currently Earning a Return  
Oklaunion Power Station Accelerated Depreciation$38.0 $27.4 
Regulatory Assets Currently Not Earning a Return  
Storm-Related Costs9.4 7.2 
COVID-190.3 0 
Total Regulatory Assets Pending Final Regulatory Approval$47.7 $34.6 

 OPCoSWEPCo
 September 30, December 31,September 30,December 31,
 2017 201620202019
Noncurrent Regulatory Assets (in millions)Noncurrent Regulatory Assets(in millions)
      
Regulatory Assets Currently Earning a Return    Regulatory Assets Currently Earning a Return  
Capacity Deferral $—
 $96.7
Dolet Hills Power Station Accelerated DepreciationDolet Hills Power Station Accelerated Depreciation$50.4 $0 
Plant Retirement Costs – Unrecovered Plant, Louisiana
Plant Retirement Costs – Unrecovered Plant, Louisiana
35.2 35.2 
Other Regulatory Assets Pending Final Regulatory ApprovalOther Regulatory Assets Pending Final Regulatory Approval2.2 0.2 
Regulatory Assets Currently Not Earning a Return  
  
Regulatory Assets Currently Not Earning a Return  
Smart Grid Costs —
 4.1
Storm-Related Costs - LouisianaStorm-Related Costs - Louisiana67.3 0 
Asset Retirement Obligation - LouisianaAsset Retirement Obligation - Louisiana8.5 7.2 
COVID-19COVID-191.7 0 
Other Regulatory Assets Pending Final Regulatory ApprovalOther Regulatory Assets Pending Final Regulatory Approval2.0 3.7 
Total Regulatory Assets Pending Final Regulatory Approval $—
 $100.8
Total Regulatory Assets Pending Final Regulatory Approval$167.3 $46.3 


  PSO
  September 30, December 31,
  2017 2016
Noncurrent Regulatory Assets (in millions)
     
Regulatory Assets Currently Earning a Return    
Plant Retirement Costs - Unrecovered Plant (a) $133.7
 $84.5
Other Regulatory Assets Pending Final Regulatory Approval 0.5
 0.5
Regulatory Assets Currently Not Earning a Return  
  
Storm-Related Costs 36.7
 20.0
Environmental Control Projects 24.3
 13.1
Other Regulatory Assets Pending Final Regulatory Approval 0.4
 —
Total Regulatory Assets Pending Final Regulatory Approval $195.6
 $118.1

(a)In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of September 30, 2017, the unrecovered plant balance related to Northeastern Plant, Unit 3 was $52 million. 
  SWEPCo
  September 30, December 31,
  2017 2016
Noncurrent Regulatory Assets (in millions)
     
Regulatory Assets Currently Earning a Return    
Plant Retirement Costs - Unrecovered Plant $75.4
 $75.4
Other Regulatory Assets Pending Final Regulatory Approval 0.5
 0.8
Regulatory Assets Currently Not Earning a Return    
Rate Case Expense - Texas 4.1
 1.0
Asset Retirement Obligation - Arkansas, Louisiana 3.6
 2.7
Shipe Road Transmission Project - FERC 3.3
 3.1
Environmental Control Projects —
 11.0
Other Regulatory Assets Pending Final Regulatory Approval 2.4
 1.9
Total Regulatory Assets Pending Final Regulatory Approval $89.3
 $95.9


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


COVID-19 Pandemic

During the first quarter of 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. During the third and the fourth quarter of 2020, certain state regulators began to lift restrictions on disconnects. As of September 30, 2020, AEP resumed disconnections in its regulated jurisdictions with the exception of Virginia, West Virginia, Kentucky, Arkansas, Louisiana and Tennessee. AEP’s electric operating companies continue to work with regulators and stakeholders in these states and management currently anticipates resuming customary disconnection practices in the fourth quarter of 2020. However, this timing could change if there is new legislation or other regulatory directives issued in the future. Continuing adverse economic conditions may result in the inability of customers to pay for electric service, which could affect revenue recognition and the collectability of accounts receivable. The
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Registrants have worked with their state commissions to achieve deferral authority for incremental expenses incurred due to COVID-19. All of AEP’s regulated jurisdictions have issued initial COVID-19 orders with the exception of Tennessee. 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)AEP and AEP Texas)


2019 Texas Base Rate Case

In May 2019, AEP Texas filed a request with the PUCT for a $56 million annual increase in rates based upon a proposed 10.5% ROE. The filing included a proposed Income Tax Refund Rider that will refund $21 million annually of Excess ADIT that is primarily not subject to normalization requirements. The rate case also sought a prudence determination on all transmission and distribution capital additions through 2018 included in interim rates from 2008 to December 2019.

In April 2020, the PUCT issued an order approving a stipulation and settlement agreement. The order includes an annual base rate reduction of $40 million based upon a 9.4% ROE with a capital structure of 57.5% debt and 42.5% common equity effective with the first billing cycle in June 2020. The order provides recovery of $26 million in capitalized vegetation management expenses that were incurred through 2018. The order includes disallowances of $23 million related to capital investments recorded through 2018 and $4 million related to rate case expenses. In addition, AEP Texas will refund: (a) $77 million of Excess ADIT and excess federal income taxes collected as a result of Tax Reform to distribution customers over a one year period, (b) $31 million of Excess ADIT and excess federal income taxes collected as a result of Tax Reform to transmission customers as a one-time credit and (c) $30 million of previously collected rates that were subject to reconciliation in this proceeding over a one year period with no carrying costs. The order requires AEP Texas to file its next base rate case within four years of the date of that the final order was issued. The order also states future financially based capital incentives will not be included in interim transmission and distribution rates and contains various ring-fencing provisions. As a result of the final order, AEP Texas will refund $275 million of Excess ADIT associated with certain depreciable property using ARAM to transmission customers. AEP Texas will determine how to refund the remaining Excess ADIT that is not subject to normalization requirements in future proceedings.

In December 2019, as a result of the initial stipulation and settlement agreement, AEP Texas (a) recorded an impairment of $33 million related to capital investments, which included $10 million of 2019 investments, in Asset Impairments and Other Related Charges on the statements of income, (b) recorded a $30 million provision for refund on the statements of income for revenues previously collected through rates and (c) wrote-off $4 million of rate case expenses to Other Operation on the statements of income.

AEP Texas Interim Transmission and Distribution Rates


As ofThrough September 30, 2017,2020, AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2017,that are subject to review areis estimated to be $697$38 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. AEP Texas is required to file for a comprehensive rate review no later than April 3, 2024.


Hurricane Harvey

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

2017-2019 Virginia Triennial Review

Amendments to Virginia law impacting investor-owned utilities were enacted, effective July 1, 2018, that required APCo to file a generation and distribution base rate case by March 31, 2020 using 2017, 2018 and 2019 earnings test years (triennial review). Triennial reviews are subject to an earnings test, which provides that 70% of any earnings in excess of 70 basis points above APCo’s Virginia SCC authorized ROE would be refunded to customers. In such case, the Virginia SCC could also lower APCo’s Virginia retail base rates on a prospective basis. In November 2018, the Virginia SCC authorized a ROE of 9.42% applicable to APCo base rate earnings for the 2017-2019 triennial period.

Virginia law provides that costs associated with asset impairments of retired coal generation assets, or automated meters, or both, which a utility records as an expense, shall be attributed to the test periods under review in a triennial review proceeding, and be deemed recovered.  In 2015, APCo retired the Sporn Plant, the Kanawha River Plant, the Glen Lyn Plant, Clinch River Unit 3 and the coal portions of Clinch River Units 1 and 2 (collectively, the retired coal-fired generation assets). The net book value of the Virginia jurisdictional share of these plants was $93 million before cost of removal, including materials and supplies inventory and ARO balances. Based on management’s interpretation of Virginia law and more certainty regarding APCo’s triennial revenues, expenses and resulting earnings upon reaching the end of the three-year review period, APCo recorded a pretax expense of $93 million related to its previously retired coal-fired generation assets in December 2019.  As a result, management deems these costs to be substantially recovered by APCo during the triennial review period.

In August 2017, Hurricane Harvey hitMarch 2020, APCo submitted its 2017-2019 Virginia triennial earnings review filing and base rate case with the coast of Texas, causing power outages in the AEP Texas service territory. AEP Texas hasVirginia SCC as required by state law. APCo requested a PUCT approved catastrophe reserve$65 million annual increase in base rates based upon a proposed 9.9% ROE. The requested annual increase includes $19 million related to depreciation for updated test year end depreciable balances and can defer incremental storm expenses. AEP Texasa proposed increase in APCo’s Virginia depreciation rates and $8 million related to APCo’s calculated shortfall in 2017-2019 APCo’s Virginia earnings. Inclusive of the Virginia jurisdictional share of the $93 million expense associated with APCo’s retired coal-fired generation assets, APCo calculated its 2017-2019 Virginia earnings for the triennial period to be below the authorized ROE range.

APCo is currently recovers approximately $1 millionin the process of storm costs annually through base rates.retiring and replacing its Virginia jurisdictional Automated Meter Reading (AMR) meters with AMI meters. As of September 30, 2017, the total balance of AEP Texas’ deferred storm costs is2020 and December 31, 2019, APCo has approximately $97$52 million including approximately $73


and $51 million of incremental storm expensesVirginia jurisdictional AMR meters as well as $82 million and $75 million of Virginia jurisdictional AMI meters recorded in Total Property, Plant and Equipment - Net on its balance sheets. APCo is pursuing full recovery of these assets through its Virginia depreciation rates as discussed above.

In July 2020, a regulatory assetcertain intervenor filed testimony asserting that APCo had a revenue surplus of $23 million for its filed rate year based upon the intervenor’s recommended ROE of 8.75%. The intervenor also filed proposed adjustments to APCo’s requested revenue requirement including: (a) a reduction to depreciation expense to reflect a 2040 retirement date for Amos Plant instead of 2032 for Amos Units 1 and 2 and 2033 for Amos Unit 3 as proposed by APCo, (b) removal of AMI meters from rate base along with related depreciation and (c) a reduction of purchased power expense related to Hurricane Harvey. Management is currently inOVEC demand charges. This intervenor, along with one other intervenor, also proposed the early stagesremoval of analyzing the impact of potential insurance claims and recoveries and, atmajor storm expenses.

In addition, this time, cannot estimate this amount. Any future insurance recoveries received will be applied to and will offset the regulatory asset and property, plant and equipment, as applicable. AEP Texas is currently evaluating recovery optionscertain intervenor submitted corrected testimony contending APCo’s earned return for the regulatory asset; however, management believestriennial period was 11.12%, which equates to a potential refund to customers of $34 million. The intervenor also filed a separate legal memorandum opposing the asset is probable of recovery. The other named hurricanes did not have a material impact on AEP’s operations in the third quarter of 2017. If the ultimate costsinclusion of the incident are2019 expensing of the retired coal-fired generation assets from APCo’s 2017-2019 earnings test results. The testimony also removed the related rate base associated with the retired coal units. Another intervenor recommended that APCo not recovered by insurance or through the regulatory process, it would have an adverse effectearn a return on future net income, cash flows$114 million of prepaid pension and financial condition.OPEB assets.


APCo Rate Matters (Applies to AEP and APCo)

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Virginia Legislation Affecting Biennial Reviews




In 2015, amendments toAugust and September 2020, the Virginia staff filed testimony supporting an annual APCo Virginia jurisdictional revenue deficiency of $17 million based upon an ROE of 8.73%. However, Virginia staff contends APCo’s earned return for the triennial period was 9.55%, which is above the 9.42% midpoint of APCo’s authorized ROE range. Based on 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 are frozen until after thea Virginia SCC rules on APCo’s next biennial review, whichorder finding an earned ROE above the midpoint would prevent APCo will filefrom receiving a prospective increase in March 2020 forVirginia retail rates. In addition, the 2018 and 2019 test years. These amendments also precludestaff recommended that APCo: (a) reverse the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo’s financial statements adequately address the impact of these amendments. The amendments provide that APCo will absorb itspretax Virginia jurisdictional share of incrementalthe $93 million expense recorded in December 2019 for its retired coal-fired generation assets and distribution costs incurred from 2014 throughinstead amortize the retired assets over a 10-year period beginning in 2015, (b) implement 2017 that are associated with severe weather events and/or natural disastersdepreciation study rates, effective January 2018, which would increase depreciation expense by $18 million and costs associated with potential asset impairments$20 million in 2018 and 2019, respectively (including $5 million annually related to new carbon emission guidelines issuedtransmission), (c) implement 2019 depreciation study rates, effective January 2020, which would increase depreciation expense by $29 million annually (including $11 million related to transmission) starting January 1, 2020 and (d) remove $9 million of major storm expenses and $12 million of coal combustion by-product expenses from the Federal EPA.requested annual increase in base rates.


In 2016,APCo expects to receive an order in November 2020. If any APCo Virginia jurisdictional costs are not recoverable or if refunds of revenues collected from customers during the triennial review period are ordered by the Virginia SCC, it could reduce future net income and cash flows and impact financial condition.

West Virginia ENEC and Vegetation Management Riders

In June 2020, the WVPSC issued an order directing APCo and WPCo to increase rider rates relating to ENEC and vegetation management by a combined $101 million ($81 million related to APCo) over twelve months beginning September 2020. This increase will be partially offset by a refund of $38 million ($31 million related to APCo) of Excess ADIT that denied the petition of certain APCo industrial customers that requested the issuance of a declaratory order that would find the amendmentsis not subject to Virginia law suspending biennial reviews unconstitutional and, accordingly, direct APConormalization requirements over ten months beginning September 2020. These transactions will result in no overall impact to make biennial review filings beginning in 2016. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. In September 2017, the Supreme Court of Virginia affirmed the Virginia SCC’s 2016 order.net income.


ETT Rate Matters (Applies to AEP)


ETT Interim Transmission Rates


ParentAEP 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 September 30, 2017,2020, AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $709 million.$1.1 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. 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 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 2018, the PUCT adopted a rule requiring investor-owned utilities operating solely inside ERCOT to make periodic filings for base rate proceedings. The rule requires ETT to file for a comprehensive base rate review no later than February 1, 2021.

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


20172019 Indiana Base Rate Case


In July 2017,May 2019, I&M filed a request with the IURC for a $263$172 million annual increase. The requested increase in Indiana rates would be phased in through January 2021 and was based upon a proposed 10.5% ROE.  The proposed annual increase included $78 million related to a proposed annual increase in depreciation expense. The requested annual increase in depreciation expense included $52 million related to proposed investments and $26 million related to increased depreciation rates. The request included the continuation of all existing riders and a new AMI rider for proposed meter projects.


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In March 2020, the IURC issued an order approving a phased-in increase in base rates of up to $77 million based upon an ROE of 9.7%. This approved phase-in increase includes: (a) an annual increase in base rates of $44 million effective March 2020 and (b) an annual increase in base rates of up to $77 million, effective January 2021, based on the IURC-approved forecast of December 31, 2020 Indiana jurisdictional electric plant in service. A compliance filing will be made in January 2021 to adjust the final rate increase to reflect the lower of I&M’s actual or IURC-approved Indiana jurisdictional electric plant in service balance as of December 31, 2020. The order also approved the majority of I&M’s proposed changes in depreciation as well as the test year level of AMI deployment, but did not approve a cost recovery rider for AMI investments made in subsequent years. The order rejected I&M’s proposed re-allocation of capacity costs related to the loss of a significant FERC wholesale contract, which will negatively impact I&M’s annual pretax earnings by approximately $20 million starting June 2020.

KPCo Rate Matters (Applies to AEP)

Kentucky Tax Reform

In May 2020, KPCo filed a request with the KPSC to issue a one-time refund of Excess ADIT that is not subject to normalization requirements to customers of approximately $11 million to eliminate certain customer delinquencies attributable to the COVID-19 pandemic. In October 2020, the KPSC denied KPCo’s request.

2020 Kentucky Base Rate Case

In June 2020, KPCo filed a request with the KPSC for a $65 million net annual increase in base rates based upon a proposed 10.6% return on common equity10% ROE with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increaseno earlier than January 2021. The filing proposes that KPCo would beoffset the first year of rate increases by refunding Excess ADIT that is not subject to a temporary offsetting $23normalization requirements to customers. Additionally, KPCo requested recovery of the previously authorized deferral of $50 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. TheUnit Power Agreement expenses and related carrying charges over a 5-year period beginning in December 2022, through an existing purchased power rider.

In October 2020, various intervenors filed testimony recommending annual rate increases ranging from $0 to $17 million based upon a ROE ranging from 8.93% to 9.25%. Other differences between KPCo’s requested annual base rate increase in depreciation rates includesand the intervenors’ recommendations are primarily due to: (a) a proposed change in the expected retirement date forrecovery period of Rockport Plant, Unit 12 SCR depreciation expense from 2044three to 2028 combinedten years, (b) a proposal to remove certain employee-related expenses from the revenue requirement and (c) a recommendation that KPCo not earn a return on $64 million of prepaid pension and OPEB assets. In addition, intervenors expressed opposition to: (a) KPCo’s proposed recovery/return of certain annual PJM Open Access Transmission Tariff expenses below/above the corresponding level recovered in base rates through an existing rider, (b) deployment of AMI with increased investment at the Cook Plant, including the Cook Plant Life Cycle Management Project. A hearing at the IURC is scheduled for January 2018.cost recovery through a new rider and (c) KPCo’s proposed changes to its net metering tariff. KPCo will file rebuttal testimony in November 2020. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.



OPCo Rate Matters (Applies to AEP and OPCo)
2017 Michigan
2020 Ohio Base Rate Case


In May 2017, I&MJune 2020, OPCo filed a request with the MPSCPUCO for a $52$42 million annual increase in Michigan base rates based upon a proposed 10.6% return on common equity10.15% ROE net of existing riders. Additionally, OPCo filed a request with the increase to be implemented no later than April 2018. The proposed annual increase includes $23 million related to increased annual depreciation rates andPUCO for a $4 million increase related to60-day temporary delay of the amortization of certain Cook Plant regulatory assets. The increase in depreciation rates is primarilynormal rate case proceeding due to the proposed change in theCOVID-19 pandemic with rates 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. Additionally, the total proposed increase includes incremental costs related to the Cook Plant Life Cycle Management Program and increased vegetation management expenses. In October 2017, the MPSC staff and intervenors filed testimony.  The MPSC staff recommended an annual net revenue increase of $49 million including proposed retirement dates of 2028 for both Rockport Plant, Units 1 (from 2044) and 2 (from 2022) and a return on common equity of 9.8%. The intervenors proposed certain adjustments to I&M’s request including no change to the current 2044 retirement date of Rockport Plant, Unit 1, but did not propose an annual net revenue increase. Their recommended return on common equity ranged from 9.3% to 9.5%. A hearing at the MPSC is scheduled for November 2017. be effective approximately mid-2021. If any of thesethe requested costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.


Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR)

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2019 Ohio DIR Audit

OPCo conducts business under an Electric Security Plan as approved by the PUCO which subjects the DIR to annual audits. In October 2016, I&MAugust 2020, a third-party consulting company filed an applicationaudit report with the IURC for approval of a Certificate of Public ConveniencePUCO indicating that OPCo exceeded its 2019 authorized revenue limit by $17 million. Management disagrees with the audit results and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by Decemberbelieves that OPCo was below its authorized revenue limit in 2019. The equipment will allow I&MPUCO has not yet issued a procedural schedule 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 costaddress the audit results. If the results of the SCR project is $274 million, excluding AFUDC,audit are upheld by the PUCO and any refunds to be shared equally between I&M and AEGCo.  As of September 30, 2017, total costs incurred related to this project, including AFUDC, were approximately $17 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 Unit Power Agreement to I&M and KPCo and will be subject to future regulatory approval for recovery. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a trackercustomers or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and limitations on other costs related to legal issues involving the Rockport Plant, Unit 2 lease. A hearing at the IURC was held in March 2017. An order from the IURC is pending. In July 2017, I&M filed a motion with the U.S. District Court for the Southern District of Ohio to remove the requirement to install SCR technology at Rockport Plant, Unit 2. In August 2017, the district court delayed the deadline for installation of the SCR technology until March 2020.

KPCo Rate Matters (Applies to AEP)

2017 Kentucky Base Rate Case

In June 2017, KPCo filed a request with the KPSC for a $66 million annual increase in Kentucky base rates based upon a proposed 10.31% return on common equity with the increase to be implemented no later than January 2018. The proposed increase includes: (a) lost load since KPCo last changed base rates in July 2015, (b) incremental costs related to OATT charges from PJM not currently recovered from retail ratepayers, (c) increased depreciation expense including updated Big Sandy Plant, Unit 1 depreciation rates using a proposed retirement date of 2031, (d) recovery of other Big Sandy Plant, Unit 1 generation costs currently recovered through a retail rider and (e) incremental purchased power costs. Additionally, KPCo requested a $4 million annual increase in environmental surcharge revenues.



In August 2017, KPCo submitted a supplemental filing with the KPSC that decreased the proposed annual base rate revenue request to $60 million. The modification was due to a lower interest expense related to June 2017 debt refinancings. In October 2017, various intervenors filed testimony that included annual net revenue increase recommendations ranging from $13 million to $40 million. Intervenors recommended returns on common equity ranging from 8.6% to 8.85%. Intervenors also recommended significant delays in KPCo’s proposed recoveries of: (a) depreciation expense related to Big Sandy Plant, Unit 1 (gas unit), proposing a 30-year depreciable life instead of KPCo’s proposed 15-year life and (b) lease expense on Rockport Plant, Unit 2 billed from AEGCo, proposing that the approximate $100 million of lease expense for the period 2018 through 2022 be deferred with a WACC carrying charge for recovery over 10 years beginning 2023. Testimony on behalf of the Attorney General also discussed that the KPSC could consider disallowing all or a portion of the costs currently being recovered over 25 years through the Big Sandy Plant, Unit 2 retirement rider.  As of September 30, 2017, KPCo’s regulatory asset related to the retired Big Sandy Plant, Unit 2 was $289 million. A hearing at the KPSC is scheduled for December 2017.

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


OPCoSWEPCo 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, the PUCO issued orders that approved OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The orders included: (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo’s proposed OVEC PPA and (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal. Also in 2015, OPCo subsequently filed an amended OVEC PPA application that, among other things, addressed certain PPA requirements set forth in a 2015 PUCO order. In 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments.

In 2016, the PUCO issued orders that approved a contested stipulation agreement related to the PPA rider application. Additionally, as part of these orders, the PUCO approved (a) recovery of OVEC-related net margin incurred beginning June 2016, (b) 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 (c) 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 and the orders are all now final. 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 is subject to review by the PUCO. A hearing at the PUCO is scheduled for November 2017.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition.

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: (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. Although 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 SEET treatment of the Global Settlement issues described above or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could reduce future net income and cash flows and impact financial condition.

PSO Rate Matters (Applies to AEP and PSO)

2017 Oklahoma Base Rate Case

In June 2017, PSO filed an application for a base rate review with the OCC that requested a net increase in annual revenues of $156 million based upon a proposed 10% return on common equity. The proposed base rate increase includes (a) environmental compliance investments, including recovery of previously deferred environmental compliance related costs currently recorded as regulatory assets, (b) Advanced Metering Infrastructure investments, (c) additional capital investments and costs to serve PSO’s customers, and (d) an annual $42 million depreciation rate increase due primarily to shorter service lives and lower net salvage estimates. As part of this filing, consistent with the OCC’s final order in its previous base rate case, PSO requested recovery through 2040 of Northeastern Plant, Unit 3, including the environmental control investment, and the net book value of Northeastern Plant, Unit 4 that was retired in 2016. As of September 30, 2017, the net book value of Northeastern Plant, Unit 4 was $82 million.

In September 2017, various intervenors and the OCC staff filed testimony that included annual net revenue increase recommendations ranging from $28 million to $108 million. The recommended returns on common equity ranged from 8% to 9%. In addition, certain parties recommended investment disallowances that ranged from $27 million to $82 million related to Northeastern Plant, Unit 4 and $38 million associated with capitalized incentives. Also, a party recommended a potential refund of $43 million related to an SPP rider claiming that PSO did not adequately support


the related SPP costs. The combined total impact could result in a write-off and refund of up to approximately $163 million. In addition, if similar plant recovery issues would apply to Northeastern Plant, Unit 3, the net book value of plant, including regulatory assets, materials and supplies inventory and CWIP of $346 million as of September 30, 2017, could be adversely impacted. A hearing at the OCC is scheduled to begin in October 2017.

If any of these costs are not recoverable, it could 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. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2.


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, in the fourth quarter of 2013, SWEPCo reversed $114 million of a previously recorded regulatory disallowances.disallowance 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 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 the fourth quarter of 2019 and first quarter of 2020, SWEPCo and various intervenors filed briefs with the Texas Supreme Court. In August 2020, the Texas Supreme Court granted SWEPCo’s petition for review and oral arguments were scheduled for December 2020.

As of September 30, 2020, 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 ROE of 9.6%, effective May 2017. The annual increase includes approximately:final order also included: (a) $34 million relatedapproval to additional environmental controls, including those installed at the Welsh Plant, to comply with Federal EPA mandates, (b) $25 million for additional generation, transmission and distribution investments and increased operating costs, (c) $8 million related to transmission cost recovery within SWEPCo’s regional transmission organization and (d) $2 million in additional vegetation management. As part of this filing, SWEPCo requested recovery ofrecover the Texas jurisdictional share (approximately 33%)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, through 2042,(c) approval of $2 million in additional vegetation management expenses and (d) the remaining life of Welsh Plant, Unit 3.

In April and May 2017, various intervenors and the PUCT staff filed testimony that included annual net revenue increase recommendations ranging from $36 million to $47 million. The recommended returns on common equity ranged from 9.2% to 9.35%. In addition, no parties recommended approvalrejection of SWEPCo’s proposed transmission cost recovery and certain parties recommended investment disallowances that couldmechanism.

As a result of the final order, in write-offs2017 SWEPCo: (a) recorded an impairment charge of up to approximately $89$19 million, including approximately $40which included $7 million related to environmental investments and $25 million related to Welsh Plant, Unit 2. A hearing atassociated with the PUCT was held in June 2017.

In September 2017, the Administrative Law Judges (ALJs) issued their proposal for decision including an annual net revenue increaselack of $50 million including recovery of Welsh Plant, Unit 2 environmental investments as of June 30, 2016. The ALJs proposed a return on common equity of 9.6% and recovery of but no return on Welsh Plant, Unit 2.2 and $12 million related to other disallowed plant investments, (b) recognized $32 million of additional revenues, for the period of May 2017 through December 2017, that was surcharged to customers in 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 expense. SWEPCo implemented new rates in February 2018 billings. The ALJs rejected SWEPCo’s proposed transmission cost recovery mechanism.$32 million of additional 2017 revenues was
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collected during 2018. In March 2018, the PUCT clarified and corrected portions of the final order, without changing the overall decision or amounts of the rate change. The estimated potential write-off associated withorder has been appealed by various intervenors. If certain parts of the ALJs proposal is approximately $22 million which includes $9 millionassociated with the lack of a return on Welsh Plant, Unit 2.

If any of these costsPUCT order are not recoverable, including environmental investments and retirement-related costs for Welsh Plant, Unit 2,overturned, it could reduce future net income and cash flows and impact financial condition.



2018 Louisiana Formula Rate Filing
Louisiana Turk Plant Prudence Review

Beginning January 2013,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 was effective August 2018 and included SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 33%)of Welsh Plant and Flint Creek Plant environmental controls. The filing also included a reduction in the federal income tax rate due to Tax Reform but did not address the return of Excess ADIT benefits to customers.

In July 2018, SWEPCo made a supplemental filing to its formula rate plan with the LPSC to reduce the requested annual increase to $18 million. The difference between SWEPCo’s requested $28 million annual increase and the $18 million annual increase in the supplemental filing is primarily the result of the Turk Plant, have been collectedreturn of Excess ADIT benefits to customers through a tax rider that will end when the Excess ADIT not subject to refund pending the outcome of a prudence review of the Turk Plant investment,normalization requirements is fully refunded to customers which was placed into service in December 2012. is currently estimated to be July 2020.

In October 2017,2018, the LPSC staff filed testimony contendingissued a recommendation that SWEPCo failed to continue to evaluate the suspension or cancellationrefund $11 million of the Turk Plant during its construction period. The testimony also identified five individual items totaling approximately $51 million for potential disallowance relating to Louisiana’s jurisdictional share of Turk Plant. Asexcess federal income taxes collected, as a result of SWEPCo’s alleged failure to meet its continuing prudence obligations,Tax Reform, from January 1, 2018 through July 31, 2018. In June 2019, the LPSC staff issued its report which reaffirmed its $11 million refund recommendation. The report also contends that SWEPCo’s requested annual rate increase of $18 million, which was implemented in August 2018, is overstated by $4 million and proposes an annual rate increase of $14 million. Additionally, the report recommends oneSWEPCo refund the excess over-collections associated with the $4 million difference for the period of August 2018 through the implementation of new rates. In July 2019, the LPSC approved the $11 million refund. In July 2020, the LPSC issued an order approving an unopposed stipulation and settlement agreement for a one-time refund of $6 million over three months beginning in August 2020.

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 following potential unfavorable scenarios: (a) Even sharing2020 Texas Base Rate Case, SWEPCo requested deferral authority of construction cost overruns betweenincremental other operation and maintenance expenses. SWEPCo and ratepayers, (b) an imposition of a cost cap similar to Texas or (c) approximately a 1% reduction of the rate on common equityis currently evaluating recovery options for the Turk Plant. As SWEPCo has included the full value of the Turk Plantstorm damage in rate base since its in-service date, SWEPCo may be required to refund potential over-collections from January 2013 through the date new rates are implemented.Arkansas jurisdiction. As of September 30, 2017, if2020, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $69 million ($67 million of which has been deferred as a regulatory asset related to the LPSC adopts oneLouisiana jurisdiction) and incremental capital expenditures of these potential scenarios, and disallows$31 million ($30 million related to the five individual items, pretax write-offs could range from $50 millionLouisiana jurisdiction). If any costs related to $80 million and refund provisions, including interest, could range from $15 million to $27 million. Future annual revenue reductions could range from $3 million to $4 million. Management will continue to vigorously defend against these claims. If the LPSC orders in favor of one of these scenarios,Hurricane Laura are not recoverable, it could reduce future net income and cash flows and impact financial condition. A hearing at the LPSC is scheduled for December 2017.


2015 Louisiana Formula Rate FilingHurricane Delta


In April 2015,October 2020, Hurricane Delta hit the coast of Louisiana, causing power outages to more than 23,000 customers in SWEPCo’s Louisiana jurisdiction. Management currently estimates that SWEPCo has incurred incremental other operation and maintenance expenses ranging from $10 million to $18 million and incremental capital expenditures of up to $6 million. SWEPCo will seek deferral authority of incremental other operation and maintenance expenses from the LPSC. If any costs related to Hurricane Delta are not recoverable, it could reduce future net income and cash flows and impact financial condition.


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2020 Texas Base Rate Case

In October 2020, SWEPCo filed its formula rate plan for test year 2014a request with the LPSC.  The filing includedPUCT for a $14$105 million annual increase in Texas base rates based upon a proposed 10.35% ROE. The request would move transmission and distribution interim revenues recovered through riders into base rates. Eliminating these riders would result in a net annual requested base rate increase of $90 million primarily due to increased investments. The proposed net annual increase: (a) includes $5 million related to vegetation management to maintain and improve the reliability of its 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 also requested recovery of the Texas jurisdictional share of the Dolet Hills Power Station of $45 million which was effective August 2015.  This increase is subjectexpected to LPSC staff review and is subject to refund.be retired by the end of 2021. If any of these costs are not recoverable, 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 included a net annual increase not to exceed $31 million, 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. These environmental costs are subject to prudence review. 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. 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.

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 September 30, 2017, SWEPCo had incurred costs of $398 million, including AFUDC, related to these projects.  Management continues to evaluate the impact of environmental rules and related project cost estimates. As of September 30, 2017, the total net book value of Welsh Plant, Units 1 and 3 was $626 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 December 2016, the LPSC approved deferral of certain expenses related to the Louisiana jurisdictional share of environmental controls installed at Welsh Plant. In April 2017, the LPSC approved SWEPCo’s recovery of these deferred costs 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 September 30, 2017, (b) is subject to review by the LPSC, and (c) includes a WACC return on environmental investments and the related depreciation expense and taxes. Effective May


2017, SWEPCo began recovering $131 million in investments related to its Louisiana jurisdictional share of environmental costs. SWEPCo has sought recovery of its project costs from retail customers in its current Texas base rate case at the PUCT 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 AFUDC Waiver (Applies to all Registrants except AEP AEPTCo, APCo, I&M and OPCo)Texas)


In June 2016, PJM transmission owners, including AEP’s eastern transmission subsidiaries and various state commissions filed2020, FERC granted a settlement agreement attemporary waiver providing utilities the FERCoption to resolve outstanding issues relatedelect to cost responsibility for chargesmodify the existing AFUDC rate calculations in response 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 Transmission Complaint - AEP’s PJM Participants (Applies to AEP, AEPTCo, APCo, I&M and OPCo)

In October 2016, several parties filed a joint complaint at the FERC that states the base return on common equity used by AEP’s eastern transmission subsidiaries 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. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions asCOVID-19 pandemic. As a result of the complaint, including refunds fromwaiver, the dateAFUDC formula for the 12-month period starting with March 2020 may be calculated using the simple average of the complaint filing, it could reduce future net income and cash flows and impact financial condition.

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

In November 2016, AEP’s eastern transmission subsidiaries filed an application with 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 fromactual historical to projected expenses. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this mattershort-term debt balances for hearing and settlement procedures. Effective January 1, 2017, the modified PJM OATT formula rates were implemented, subject to refund, based on projected 2017 calendar year financial activity and projected plant2019, instead of current period short-term balances. 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 Transmission Complaint - AEP’s SPP Participants (Applies to AEP, AEPTCo, PSO and SWEPCo)

In June 2017, several parties filed a joint complaint at the FERC that states the base return on common equity used by AEP’s western transmission subsidiaries in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36%, effective upon the dateAll other aspects of the complaint. Management believes itsAFUDC formula remained unchanged. AEP subsidiaries including certain Registrant Subsidiaries elected to apply the waiver in July 2020. The impact upon election was immaterial on the Registrants’ 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.statements.

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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. 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 AEP’s and AEPTCo’s 2016the 2019 Annual ReportsReport 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 revolving credit facility due in June 2021,2022, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of September 30, 2017,2020, no letters of credit were issued under the $3 billion revolving credit facility. In May 2017, the $500 million revolving credit facility due in June 2018 was terminated.


An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility.  AEP also issues letters of credit on behalf of subsidiaries under fivesix uncommitted facilities totaling $445$405 million. In August 2017, AEP executed a $75 million uncommitted letter of credit facility due in August 2018. As of September 30, 2017, theThe Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of September 30, 2020 were as follows:
CompanyAmountMaturity
(in millions)
AEP$197.3 October 2020 to August 2021
AEP Texas2.2 July 2021
Company Amount Maturity
  (in millions)  
AEP $123.2
 October 2017 to September 2018
OPCo 0.6
 September 2018


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 $115 million, which increased to $140 million in October 2017.  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 $76 million.  Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation.  As of September 30, 2017, SWEPCo has collected $71 million through a rider for final mine closure and reclamation costs, of which $76 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 April 2019, AEP issued a performance guaranteeacquired Sempra Renewables LLC. See “Acquisitions” section of Note 6 for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of September 30, 2017, the maximum potential amount of future payments associated with this guarantee was $75 million, which expires in December 2019.additional information.


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Indemnifications and Other Guarantees


Contracts


The Registrants enter into certain types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, exposure generally does not exceed the sale price.  As of September 30, 2017,2020, there were no material liabilities recorded for any indemnifications.


AEPSC conducts power purchase-and-sale activity on behalf of APCo, I&M, KPCo and OPCoWPCo, who are jointly and severally liable for activity conducted byon their behalf.  AEPSC also conducts power purchase-and-sale activity on behalf of AEP companies related to power purchase and sale activity.  PSO and SWEPCo, who are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity.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 September 30, 2017,2020, 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$49.8 
AEP Texas11.4 
APCo6.8 
I&M4.5 
OPCo7.9 
PSO4.6 
SWEPCo5.2 
Company 
Maximum
Potential Loss
  (in millions)
AEP $42.1
APCo 8.8
I&M 3.4
OPCo 6.0
PSO 3.3
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 $8 million and $9 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2017.

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.lease at a rate that approximates fair value.  The maximum potential losses relatedoption to renew was not included in the guarantee are $8 million and $10 million for I&M and SWEPCo, respectively,measurement of the lease obligation as of September 30, 2017, assuming2020 as the fair valueexecution of the equipment is zero atoption was not reasonably certain. AEP, AEGCo and I&M have no ownership interest in the endOwner Trustee and do not guarantee its debt. 

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The future minimum lease payments for this sale-and-leaseback transaction as of the current five-yearSeptember 30, 2020 were as follows:
Future Minimum Lease PaymentsAEP (a)I&M
(in millions)
2020$73.9 $37.0 
2021147.8 73.9 
2022147.5 73.7 
Total Future Minimum Lease Payments$369.2 $184.6 

(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 September 30, 2017,2020, the maximum potential amount of future payments required under the guaranteed leases was $52$50 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 to the extent of the sale proceeds.for which it obtained title. As of September 30, 2017,2020, AEP’s boat and barge lease guarantee liability was $7$3 million, of which $1 million was recorded in Other Current Liabilities and $6$2 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheet.


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

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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Virginia House Bill 443 (Applies to AEP and APCo)

In 2008, I&M received a letter fromMarch 2020, Virginia’s Governor signed House Bill 443 (HB 443), effective July 2020, requiring APCo to close certain ash disposal units at the Michigan Departmentretired Glen Lyn Station by removal of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm.  I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan.all coal combustion material.  As a result, of receiving approval ofin June 2020, APCo recorded a $199 million revision to increase estimated Glen Lyn Station ash disposal ARO liabilities.  The closure is required to be completed remediation workwithin 15 years from the MDEQ in March 2015, I&M’s accrual was reduced. Asstart of September 30, 2017, I&M’s accrualthe excavation process.  HB 443 provides for the recovery of all costs associated with closure by removal through the Virginia environmental rate adjustment clause (E-RAC).  APCo may begin recovering these costs through the E-RAC beginning July 1, 2022. APCo is permitted to record carrying costs on the unrecovered balance of these sites is $3 million.  Asclosure costs at a weighted average cost of capital approved by the remediation work is completed, I&M’s cost may change as new information becomes available concerning eitherVirginia SCC. HB 443 also allows any closure costs allocated to non-Virginia jurisdictional customers, but not collected from such non-Virginia jurisdictional customers, to be recovered from Virginia jurisdictional customers through the level of contamination at the sites or changes in the scope of remediation.  Management cannot predict the amount of additional cost, if any.E-RAC.




NUCLEAR CONTINGENCIES (APPLIES TO(Applies to AEP ANDand I&M)


I&M owns and operates the two-unit 2,278 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC).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 (Applies to AEP and I&M)

In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the U.S. Bankruptcy Code.  It intends to reorganize, not cease business operations. However, it is in the early stages of the bankruptcy process and it is unclear whether the company can successfully reorganize.  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.  I&M is evaluating how this reorganization affects these contracts.  Westinghouse has stated that it intends to continue performance on I&M’s contracts, but given the importance of upcoming dates in the fuel fabrication process for Cook Plant, and their vital part in Cook Plant’s ongoing operations, I&M continues to work with Westinghouse in the bankruptcy proceedings to avoid any interruptions to that service. In the unlikely event Westinghouse rejects I&M’s contracts, or is unable to reorganize or sell its profitable businesses in the bankruptcy, Cook Plant’s operations would be significantly impacted and potentially shut down temporarily as I&M seeks other vendors for these services.

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 eliminatedecree. The district court granted the 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. In October 2017, the owners filed aowners’ unopposed motion to stay their claims until January 2018,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

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district court enter a judgment for the plaintiffs on their breach of contract claim. AEP’s memorandum in opposition was filed in October 2020. All deadlines, including discovery, are stayed, pending resolution of the motion.

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, management cannot determine a range of potential losses that is reasonably possible of occurring.

Patent Infringement Complaint (Applies to AEP, AEP Texas and SWEPCo)

In July 2019, Midwest Energy Emissions Corporation and MES Inc. (collectively, the plaintiffs) filed a patent infringement complaint against various parties, including AEP Texas, AGR, Cardinal Operating Company and SWEPCo (collectively, the AEP Defendants). The complaint alleges that the AEP Defendants infringed two patents owned by the plaintiffs by using specific processes for mercury control at certain coal-fired generating stations.  In July 2020, plaintiffs amended the complaint to add three new patents. The amended complaint seeks injunctive relief and damages.  The case is scheduled for trial in January 2023. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

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

The American Electric Power System Retirement Plan (the Plan) has received a letter written on behalf of four participants (the Claimants) making a claim for additional plan benefits and purporting to advance such claims on behalf of a class. When the Plan’s benefit formula was changed in the year 2000, AEP provided a special provision for employees hired before January 1, 2001, allowing them to continue benefit accruals under the then benefit formula for a full 10 years alongside of the new cash balance benefit formula then being implemented.  Employees who were hired on or after January 1, 2001 accrued benefits only under the new cash balance benefit formula.  The Claimants have asserted claims that (a) the Plan violates the requirements under the Employee Retirement Income Security Act (ERISA) intended to preclude back-loading the accrual of benefits to the end of a participant’s career; (b) the Plan violates the age discrimination prohibitions of ERISA and the Age Discrimination in Employment Act; and (c) the company failed to provide required notice regarding the changes to the Plan.  AEP has responded to the Claimants providing a reasoned explanation for why each of their claims have been denied. The denial of those claims was appealed to the AEP System Retirement Plan Appeal Committee and the Committee upheld the denial of claims. Management will continue to defend against the claims.  Management is unable to determine a range of potential losses that are reasonably possible of occurring.


Natural Gas Markets Lawsuits (AppliesLitigation Related to AEP)Ohio House Bill 6

In 2002, a lawsuit was commenced in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity.  AEP was dismissed from the case.  A number of similar cases were also filed in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies.  AEP is among the companies named as defendants in some of these cases.  AEP settled, received summary judgment or was dismissed from all of these cases.  The plaintiffs appealed the Nevada federal district court’s dismissal of several cases involving AEP companies to the U.S. Court of Appeals for the Ninth Circuit.  In April 2013, the appellate court reversed in part, and affirmed in part, the district court’s orders in these cases.  The United States Supreme Court affirmed the U.S. Court of Appeals for the Ninth Circuit’s opinion.  The cases were remanded to the district court for further proceedings. AEP had four pending cases, of which three were class actions and one was a single plaintiff case. In February 2017, a settlement was reached in the single plaintiff case. A settlement was also reached in the three class actions and the district court issued final approval of the settlement in June 2017.



Gavin Landfill Litigation (Applies to AEP and OPCo)


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 death and personal injury/illness claims arising outcertain of purported exposure to coal combustion by-product waste at the Gavin Plant landfill.  As a resultits officers for alleged violations of OPCo transferringsecurities laws. The complaint alleges misrepresentations or omissions by AEP regarding: (a) its generation assets to AGR, the outcome of this complaint will be 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 are pursuing personal injury/illness claims (non-working direct claims) and the remainder are pursuing loss of consortium claims.  The plaintiffs seek compensatory and punitive damages, as well as medical monitoring.  In September 2014, defendants filed a motion to dismiss the complaint, contending the case should be filedalleged participation in Ohio. In August 2015, the court denied the motion. Defendants appealed that decisionpublic corruption with respect to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appealpassage of Ohio House Bill 6, (b) its regulatory, legislative and remanding 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 direct claims underlobbying activities in Ohio law.and (c) its clean energy strategy. The WVMLP denied the motion and defendants again appealed to the West Virginia Supreme Court. The West Virginia Supreme Court granted the appealcomplaint seeks monetary damages among other forms of the twelve non-working direct claims and heard oral argument in March 2017. In June 2017, the West Virginia Supreme Court reversed the WVMLP decision and dismissed the claims of the twelve non-working direct claim plaintiffs. Management will continue to defend against the remaining claims and believes the provision recorded is adequate.relief. Management is unable to determine a range of potential additional losses that areis reasonably possible of occurring.



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6. IMPAIRMENT, DISPOSITION,ACQUISITIONS AND ASSETS AND LIABILITIES HELD FOR SALEDISPOSITIONS


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


IMPAIRMENTACQUISITIONS


Merchant Generating AssetsSempra Renewables LLC (Generation & Marketing Segment)


In April 2019, AEP acquired Sempra Renewables LLC and its ownership interests in 724 MWs of wind generation and battery assets valued at approximately $1.1 billion. This acquisition is part of AEP’s strategy to grow its renewable generation portfolio and to diversify generation resources. AEP paid $580 million in cash and acquired a 50% ownership interest in five non-consolidated joint ventures with net assets valued at $404 million as of the acquisition date (which includes $364 million of existing debt obligations). Additionally, the transaction included the acquisition of two tax equity partnerships and the associated recognition of noncontrolling tax equity interest of $135 million.

Upon closing of the purchase, Sempra Renewables LLC was legally renamed AEP Wind Holdings LLC. AEP Wind Holdings LLC develops, owns and operates, or holds interests in, wind generation facilities in the United States. The operating wind generation portfolio includes seven wind farms. Five wind farms are jointly-owned with BP Wind Energy, and two wind farms are consolidated by AEP and are tax equity partnerships with nonaffiliated noncontrolling interests. All seven wind farms have long-term PPAs for 100% of their energy production.

Parent has issued guarantees over the performance of the joint ventures. If a joint venture were to default on payments or performance, Parent would be required to make payments on behalf of the joint venture. As of September 2016, due to AEP’s ongoing evaluation of strategic alternatives for its merchant generation assets, declining forecasts30, 2020, the maximum potential amount of future energypayments associated with these guarantees was $166 million, with the last guarantee expiring in December 2037. The non-contingent liability recorded associated with these guarantees was $31 million, with an additional $1 million expected credit loss liability for the contingent portion of the guarantees. Management considered historical losses, economic conditions, and capacity prices,reasonable and a decreasing likelihood of cost recovery through regulatory proceedings or legislationsupportable forecasts in the statecalculation of Ohio providingthe 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.

Santa Rita East (Generation & Marketing Segment)

In July 2019, AEP acquired a 75% interest, or 227 MWs, in Santa Rita East for approximately $356 million. In accordance with the recoveryaccounting guidance for “Business Combinations,” management determined that the acquisition of AEP’s existing Ohio merchant generation assets, AEP performedSanta Rita East represents an impairment analysis at the unit level on the remaining merchant generation assetsasset acquisition. Additionally, and in accordance with the accounting guidance for impairments“Consolidation,” management concluded that Santa Rita East is a VIE. As a result, to account for the initial consolidation of long-lived assets. BasedSanta Rita East, management applied the acquisition method by allocating the purchase price based on the impairment analysis performedrelative fair value of the assets acquired and noncontrolling interest assumed.  The fair value of the primary assets acquired and the noncontrolling interest assumed was determined using the market approach.  The key input assumptions were the transaction price paid for AEP’s interest in Santa Rita East and recent third-party market transactions for similar wind farms.

Desert Sky Wind Farm and Trent Wind Farm (Generation & Marketing Segment)

In August 2020, AEP exercised its call right which required the third quarternonaffiliated member of 2016, AEP recordedDesert Sky Wind Farm LLC and Trent Wind Farm LLC (collectively the LLCs) to sell its noncontrolling interest to AEP. The exercise price for the call right was determined using a pretax impairment of $2.3 billion in Asset Impairments and Other Related Chargesdiscounted cash flow model with agreed input assumptions as well as updates to certain assumptions reasonably expected based on the statementactual results of operations.

Through the third quarterLLCs. As a result, the LLCs are wholly-owned by AEP and management has concluded that the LLCs are no longer VIEs. AEP paid $57 million in cash, derecognized $63 million of 2017, AEPRedeemable Noncontrolling Interest within Mezzanine Equity and recorded an additional pretax impairmentincrease of $4$6 million in Asset Impairments and Other Related Chargesof Paid-In Capital on AEP’s statements of income related to the Merchant Coal-fired Generation Assets. In addition, AEP recorded a $7 million pretax impairment as Asset Impairments and Other Related Charges on AEP’s statements of income related to the sale of Zimmer Plant. The sale is further discussed in the “Disposition” section of this note.balance sheets.

164

DISPOSITION


Zimmer


DISPOSITIONS

Conesville Plant (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 and nine months ended September 30, 2017 and 2016.

Tanners Creek Plant (Vertically Integrated Utilities Segment) (Applies toJune 2020, AEP and I&M)

In October 2016, I&M sold its retired Tanners Creek plant site including its associated asset retirement obligations (AROs)a non-affiliated joint-owner executed an Environmental Liability and Property Transfer and Asset Purchase Agreement with a non-affiliated third-party related to a nonaffiliated party.  I&M paid $92 million and the nonaffiliated partymerchant Conesville Plant site. The purchaser took ownership of the Tanners Creek plant site assets and assumed responsibility for environmental liabilities, and AROs, including ash pond closure, asbestos abatement and decommissioning and demolition.  I&M did not record ademolition 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 approximately $98 million, derecognized $106 million in ARO and recorded an immaterial gain or loss related to this saleon the transaction which is recorded in Other Operation on the statements of income. AEP paid approximately $26 million in June 2020 and will address recovery of Tanner’s Creek deferred costsmake additional payments totaling $28 million in future rate proceedings. If any of the costs associated with Tanner’s Creek are not recoverable, it could reduce future net incomequarterly installments from October 2020 to April 2021 and impact financial condition.payments totaling $44 million in quarterly installments from July 2021 to July 2022.


Gavin, Waterford, DarbyOklaunion Power Station (Applies to AEP, AEP Texas and Lawrenceburg Plants (Generation & Marketing Segment)PSO)

In September 2016,October 2020, AEP signedTexas, PSO and a non-affiliated joint-owner executed an Environmental Liability and Property Transfer and Asset Purchase and Sale Agreement to sell AGR’s Gavin, Waterford and Darby Plants as well as AEGCo’s Lawrenceburg Plant totaling 5,329 MWs of competitive generation assets towith a nonaffiliated party. The sale closed in January 2017 for $2.2 billion, which was recorded in Investing Activities on the statement of cash flows. The net proceeds from the transaction were $1.2 billion in cash after taxes, repayment of debt associated with these assets including a make whole paymentnon-affiliated third-party related to the debt, payment of a coal contract associated with oneOklaunion Power Station site. The purchaser took ownership of the plantsassets and transaction fees.assumed responsibility for environmental liabilities, including ash pond closure, asbestos abatement and decommissioning and demolition of the Oklaunion Power Station site. The sale resultedis expected to have an immaterial impact on the financial statements in a pretax gain of $226 million that was recorded in Gain on Sale of Merchant Generation Assets on AEP’s statement of income.



ASSETS AND LIABILITIES HELD FOR SALE

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

In the thirdfourth quarter of 2016, management determined Gavin, Waterford, Darby and Lawrenceburg Plants met the classification of held for sale. Accordingly, the four plants’ assets and liabilities have been recorded as Assets Held for Sale and Liabilities Held for Sale on AEP’s balance sheet as of December 31, 2016 and as shown in the table below. The Income before Income Tax Expense and Equity Earnings of the four plants was approximately $116 million for the three months ended September 30, 2016 and $42 million (excluding the $226 million pretax gain) and $312 million for the nine months ended September 30, 2017 and 2016, respectively.2020.




165
  December 31,
  2016
Assets:  
Fuel $145.5
Materials and Supplies 49.4
Property, Plant and Equipment - Net 1,756.2
Other Class of Assets That Are Not Major 0.1
Total Assets Classified as Held for Sale on the Balance Sheets $1,951.2
   
Liabilities:  
Long-term Debt $134.8
Waterford Plant Upgrade Liability 52.2
Asset Retirement Obligations 36.7
Other Classes of Liabilities That Are Not Major 12.2
Total Liabilities Classified as Held for Sale on the Balance Sheets $235.9







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 Plans 
Other Postretirement
Benefit Plans
Pension PlansOPEB
Three Months Ended September 30, Three Months Ended September 30,Three Months Ended September 30,Three Months Ended September 30,
2017 2016 2017 2016 2020201920202019
(in millions) (in millions)
Service Cost$24.1
 $21.4
 $2.8
 $2.6
Service Cost$28.0 $23.8 $2.5 $2.4 
Interest Cost50.7
 52.9
 14.8
 15.3
Interest Cost42.0 51.1 10.0 12.6 
Expected Return on Plan Assets(71.1) (70.1) (25.3) (26.8)Expected Return on Plan Assets(66.3)(74.0)(23.9)(23.4)
Amortization of Prior Service Cost (Credit)0.3
 0.6
 (17.3) (17.3)
Amortization of Prior Service CreditAmortization of Prior Service Credit0 0 (17.4)(17.3)
Amortization of Net Actuarial Loss20.7
 21.0
 9.2
 7.8
Amortization of Net Actuarial Loss23.5 14.4 1.4 5.5 
Net Periodic Benefit Cost (Credit)$24.7
 $25.8
 $(15.8) $(18.4)Net Periodic Benefit Cost (Credit)$27.2 $15.3 $(27.4)$(20.2)
Pension PlansOPEB
Nine Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(in millions)
Service CostService Cost$84.0 $71.6 $7.5 $7.1 
Interest CostInterest Cost125.9 153.3 29.9 37.9 
Expected Return on Plan AssetsExpected Return on Plan Assets(198.7)(222.0)(71.8)(70.3)
Amortization of Prior Service CreditAmortization of Prior Service Credit0 0 (52.3)(51.8)
Amortization of Net Actuarial LossAmortization of Net Actuarial Loss70.3 43.2 4.4 16.6 
Net Periodic Benefit Cost (Credit)Net Periodic Benefit Cost (Credit)$81.5 $46.1 $(82.3)$(60.5)
 Pension Plans 
Other Postretirement
Benefit Plans
 Nine Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (in millions)
Service Cost$72.3
 $64.3
 $8.4
 $7.7
Interest Cost152.3
 158.7
 44.5
 45.7
Expected Return on Plan Assets(213.5) (210.2) (76.0) (80.3)
Amortization of Prior Service Cost (Credit)0.8
 1.7
 (51.8) (51.8)
Amortization of Net Actuarial Loss62.1
 62.9
 27.5
 23.5
Net Periodic Benefit Cost (Credit)$74.0
 $77.4
 $(47.4) $(55.2)


166






AEP Texas

Pension PlansOPEB
Three Months Ended September 30,Three Months Ended September 30,
 2020201920202019
 (in millions)
Service Cost$2.6 $2.2 $0.2 $0.1 
Interest Cost3.5 4.4 0.8 1.0 
Expected Return on Plan Assets(5.7)(6.5)(2.0)(1.9)
Amortization of Prior Service Credit0 0 (1.4)(1.5)
Amortization of Net Actuarial Loss1.9 1.2 0.1 0.5 
Net Periodic Benefit Cost (Credit)$2.3 $1.3 $(2.3)$(1.8)
Pension PlansOPEB
Nine Months Ended September 30,Nine Months Ended September 30,
 2020201920202019
 (in millions)
Service Cost$7.6 $6.5 $0.6 $0.5 
Interest Cost10.5 13.1 2.4 3.0 
Expected Return on Plan Assets(17.1)(19.4)(6.0)(5.8)
Amortization of Prior Service Credit0 0 (4.4)(4.4)
Amortization of Net Actuarial Loss5.8 3.7 0.4 1.4 
Net Periodic Benefit Cost (Credit)$6.8 $3.9 $(7.0)$(5.3)

APCo
Pension Plans 
Other Postretirement
Benefit Plans
Pension PlansOPEB
Three Months Ended September 30, Three Months Ended September 30,Three Months Ended September 30,Three Months Ended September 30,
2017
2016 2017 2016 2020201920202019
(in millions) (in millions)
Service Cost$2.3
 $2.1
 $0.3
 $0.2
Service Cost$2.7 $2.4 $0.3 $0.2 
Interest Cost6.5
 6.8
 2.6
 2.7
Interest Cost5.0 6.3 1.6 2.2 
Expected Return on Plan Assets(8.9) (8.8) (4.1) (4.3)Expected Return on Plan Assets(8.4)(9.4)(3.6)(3.7)
Amortization of Prior Service Credit—
 —
 (2.5) (2.5)Amortization of Prior Service Credit0 0 (2.5)(2.5)
Amortization of Net Actuarial Loss2.6
 2.6
 1.6
 1.4
Amortization of Net Actuarial Loss2.8 1.8 0.2 1.0 
Net Periodic Benefit Cost (Credit)$2.5
 $2.7
 $(2.1) $(2.5)Net Periodic Benefit Cost (Credit)$2.1 $1.1 $(4.0)$(2.8)
Pension PlansOPEB
Nine Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(in millions)
Service CostService Cost$7.9 $7.1 $0.8 $0.7 
Interest CostInterest Cost15.2 18.9 4.9 6.5 
Expected Return on Plan AssetsExpected Return on Plan Assets(25.2)(28.1)(10.9)(11.0)
Amortization of Prior Service CreditAmortization of Prior Service Credit0 0 (7.6)(7.5)
Amortization of Net Actuarial LossAmortization of Net Actuarial Loss8.4 5.3 0.7 2.8 
Net Periodic Benefit Cost (Credit)Net Periodic Benefit Cost (Credit)$6.3 $3.2 $(12.1)$(8.5)
167
 Pension Plans 
Other Postretirement
Benefit Plans
 Nine Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (in millions)
Service Cost$7.0
 $6.1
 $0.8
 $0.7
Interest Cost19.3
 20.4
 7.9
 8.1
Expected Return on Plan Assets(26.8) (26.5) (12.3) (13.0)
Amortization of Prior Service Cost (Credit)0.1
 0.1
 (7.5) (7.5)
Amortization of Net Actuarial Loss7.8
 8.0
 4.7
 4.1
Net Periodic Benefit Cost (Credit)$7.4
 $8.1
 $(6.4) $(7.6)






I&M
Pension PlansOPEB
Three Months Ended September 30,Three Months Ended September 30,
 2020201920202019
 (in millions)
Service Cost$3.9 $3.3 $0.4 $0.3 
Interest Cost4.9 6.0 1.2 1.5 
Expected Return on Plan Assets(8.3)(9.1)(3.0)(2.8)
Amortization of Prior Service Credit0 0 (2.3)(2.4)
Amortization of Net Actuarial Loss2.7 1.6 0.1 0.7 
Net Periodic Benefit Cost (Credit)$3.2 $1.8 $(3.6)$(2.7)
Pension PlansOPEB
Nine Months Ended September 30,Nine Months Ended September 30,
 2020201920202019
 (in millions)
Service Cost$11.6 $10.0 $1.1 $1.0 
Interest Cost14.7 17.9 3.5 4.4 
Expected Return on Plan Assets(24.9)(27.5)(8.8)(8.5)
Amortization of Prior Service Credit0 0 (7.1)(7.1)
Amortization of Net Actuarial Loss8.1 4.9 0.5 2.0 
Net Periodic Benefit Cost (Credit)$9.5 $5.3 $(10.8)$(8.2)
 Pension Plans 
Other Postretirement
Benefit Plans
 Three Months Ended September 30, Three Months Ended September 30,
 2017 2016 2017 2016
 (in millions)
Service Cost$3.5
 $3.1
 $0.4
 $0.4
Interest Cost6.1
 6.3
 1.7
 1.7
Expected Return on Plan Assets(8.6) (8.4) (3.1) (3.2)
Amortization of Prior Service Credit—
 —
 (2.3) (2.4)
Amortization of Net Actuarial Loss2.4
 2.5
 1.1
 0.9
Net Periodic Benefit Cost (Credit)$3.4
 $3.5
 $(2.2) $(2.6)
 Pension Plans 
Other Postretirement
Benefit Plans
 Nine Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (in millions)
Service Cost$10.5
 $9.2
 $1.2
 $1.1
Interest Cost18.2
 19.0
 5.2
 5.2
Expected Return on Plan Assets(25.9) (25.2) (9.2) (9.6)
Amortization of Prior Service Cost (Credit)0.1
 0.1
 (7.0) (7.1)
Amortization of Net Actuarial Loss7.3
 7.4
 3.3
 2.8
Net Periodic Benefit Cost (Credit)$10.2
 $10.5
 $(6.5) $(7.6)



OPCo
Pension PlansOPEB
Three Months Ended September 30,Three Months Ended September 30,
 2020201920202019
 (in millions)
Service Cost$2.4 $1.9 $0.2 $0.2 
Interest Cost3.9 4.8 1.0 1.4 
Expected Return on Plan Assets(6.6)(7.3)(2.6)(2.7)
Amortization of Prior Service Credit0 0 (1.8)(1.8)
Amortization of Net Actuarial Loss2.1 1.3 0.2 0.6 
Net Periodic Benefit Cost (Credit)$1.8 $0.7 $(3.0)$(2.3)
Pension PlansOPEB
Nine Months Ended September 30,Nine Months Ended September 30,
 2020201920202019
 (in millions)
Service Cost$7.2 $5.9 $0.7 $0.6 
Interest Cost11.6 14.3 3.1 4.1 
Expected Return on Plan Assets(19.7)(22.0)(7.9)(8.1)
Amortization of Prior Service Credit0 0 (5.3)(5.2)
Amortization of Net Actuarial Loss6.4 4.0 0.5 1.9 
Net Periodic Benefit Cost (Credit)$5.5 $2.2 $(8.9)$(6.7)
 Pension Plans 
Other Postretirement
Benefit Plans
 Three Months Ended September 30, Three Months Ended September 30,
 2017 2016 2017 2016
 (in millions)
Service Cost$1.8
 $1.6
 $0.3
 $0.2
Interest Cost4.8
 5.1
 1.6
 1.8
Expected Return on Plan Assets(6.9) (6.9) (3.0) (3.3)
Amortization of Prior Service Credit—
 —
 (1.7) (1.7)
Amortization of Net Actuarial Loss2.0
 2.1
 1.1
 0.9
Net Periodic Benefit Cost (Credit)$1.7
 $1.9
 $(1.7) $(2.1)


168
 Pension Plans 
Other Postretirement
Benefit Plans
 Nine Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (in millions)
Service Cost$5.6
 $4.9
 $0.7
 $0.6
Interest Cost14.5
 15.4
 5.0
 5.3
Expected Return on Plan Assets(20.9) (20.8) (9.0) (9.7)
Amortization of Prior Service Cost (Credit)0.1
 0.1
 (5.2) (5.2)
Amortization of Net Actuarial Loss5.9
 6.1
 3.3
 2.8
Net Periodic Benefit Cost (Credit)$5.2
 $5.7
 $(5.2) $(6.2)






PSO
Pension PlansOPEB
Three Months Ended September 30,Three Months Ended September 30,
 2020201920202019
 (in millions)
Service Cost$1.9 $1.6 $0.1 $0.2 
Interest Cost2.1 2.6 0.6 0.7 
Expected Return on Plan Assets(3.6)(4.0)(1.3)(1.3)
Amortization of Prior Service Credit0 0 (1.0)(1.1)
Amortization of Net Actuarial Loss1.1 0.7 0 0.3 
Net Periodic Benefit Cost (Credit)$1.5 $0.9 $(1.6)$(1.2)
Pension PlansOPEB
Nine Months Ended September 30,Nine Months Ended September 30,
 2020201920202019
 (in millions)
Service Cost$5.5 $4.9 $0.4 $0.5 
Interest Cost6.4 7.9 1.6 2.0 
Expected Return on Plan Assets(10.9)(12.2)(3.9)(3.9)
Amortization of Prior Service Credit0 0 (3.2)(3.2)
Amortization of Net Actuarial Loss3.5 2.2 0.2 0.9 
Net Periodic Benefit Cost (Credit)$4.5 $2.8 $(4.9)$(3.7)
 Pension Plans 
Other Postretirement
Benefit Plans
 Three Months Ended September 30, Three Months Ended September 30,
 2017 2016 2017 2016
 (in millions)
Service Cost$1.7
 $1.5
 $0.2
 $0.2
Interest Cost2.6
 2.8
 0.8
 0.8
Expected Return on Plan Assets(3.9) (3.9) (1.4) (1.5)
Amortization of Prior Service Cost (Credit)—
 0.1
 (1.1) (1.1)
Amortization of Net Actuarial Loss1.1
 1.1
 0.5
 0.4
Net Periodic Benefit Cost (Credit)$1.5
 $1.6
 $(1.0) $(1.2)
 Pension Plans 
Other Postretirement
Benefit Plans
 Nine Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (in millions)
Service Cost$4.9
 $4.6
 $0.5
 $0.5
Interest Cost8.0
 8.4
 2.4
 2.4
Expected Return on Plan Assets(11.8) (11.6) (4.2) (4.5)
Amortization of Prior Service Cost (Credit)—
 0.2
 (3.2) (3.2)
Amortization of Net Actuarial Loss3.3
 3.3
 1.5
 1.3
Net Periodic Benefit Cost (Credit)$4.4
 $4.9
 $(3.0) $(3.5)




SWEPCo
Pension PlansOPEB
Three Months Ended September 30,Three Months Ended September 30,
 2020201920202019
 (in millions)
Service Cost$2.6 $2.1 $0.2 $0.2 
Interest Cost2.5 3.1 0.6 0.7 
Expected Return on Plan Assets(3.9)(4.4)(1.5)(1.5)
Amortization of Prior Service Credit0 0 (1.3)(1.3)
Amortization of Net Actuarial Loss1.4 0.9 0.1 0.4 
Net Periodic Benefit Cost (Credit)$2.6 $1.7 $(1.9)$(1.5)
Pension PlansOPEB
Nine Months Ended September 30,Nine Months Ended September 30,
 2020201920202019
 (in millions)
Service Cost$7.5 $6.4 $0.6 $0.6 
Interest Cost7.6 9.3 1.9 2.3 
Expected Return on Plan Assets(11.7)(13.3)(4.7)(4.5)
Amortization of Prior Service Credit0 0 (3.9)(3.9)
Amortization of Net Actuarial Loss4.2 2.6 0.3 1.1 
Net Periodic Benefit Cost (Credit)$7.6 $5.0 $(5.8)$(4.4)


169





 Pension Plans 
Other Postretirement
Benefit Plans
 Three Months Ended September 30, Three Months Ended September 30,
 2017 2016 2017 2016
 (in millions)
Service Cost$2.1
 $2.0
 $0.2
 $0.2
Interest Cost3.1
 3.1
 0.9
 0.9
Expected Return on Plan Assets(4.2) (4.0) (1.5) (1.7)
Amortization of Prior Service Credit—
 —
 (1.3) (1.3)
Amortization of Net Actuarial Loss1.3
 1.2
 0.5
 0.5
Net Periodic Benefit Cost (Credit)$2.3
 $2.3
 $(1.2) $(1.4)
Qualified Pension Contribution (Applies to all Registrants except AEPTCo and PSO)

For the qualified pension plan, discretionary contributions may be made to maintain the funded status of the plan. In the third quarter of 2020, AEP made a discretionary contribution to the qualified pension plan. The following table provides details of the contribution by Registrant:
CompanyQualified Pension Plan
(in millions)
AEP$110.3 
AEP Texas11.3 
APCo7.0 
I&M6.4 
OPCo0.1 
SWEPCo8.9 
170
 Pension Plans 
Other Postretirement
Benefit Plans
 Nine Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (in millions)
Service Cost$6.5
 $6.1
 $0.6
 $0.6
Interest Cost9.2
 9.3
 2.7
 2.7
Expected Return on Plan Assets(12.6) (12.3) (4.7) (5.0)
Amortization of Prior Service Cost (Credit)—
 0.2
 (3.9) (3.9)
Amortization of Net Actuarial Loss3.7
 3.6
 1.7
 1.5
Net Periodic Benefit Cost (Credit)$6.8
 $6.9
 $(3.6) $(4.1)







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 OPCoAEP Texas and AEP Texas.OPCo.
•OPCo purchases energy and capacity to serve SSOstandard service offer customers and provides transmission and distribution services for all connected load.
With the merger of TCC and TNC into AEP Utilities, Inc. to form AEP Texas, the Transmission and Distribution segment now includes certain activities related to the former AEP Utilities, Inc. that had been included in Corporate and Other.


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


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.

171






The tables below present AEP’s reportable segment income statement information for the three and nine months ended September 30, 20172020 and 20162019 and reportable segment balance sheet information as of September 30, 20172020 and December 31, 2016. These amounts2019.
Three Months Ended September 30, 2020
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing		Corporate and Other (a)Reconciling AdjustmentsConsolidated
 (in millions)
Revenues from:      
External Customers$2,400.1 $1,124.1 $73.4 $464.8 $4.0 $0 $4,066.4 
Other Operating Segments34.7 41.2 244.5 25.2 28.6 (374.2)0 
Total Revenues$2,434.8 $1,165.3 $317.9 $490.0 $32.6 $(374.2)$4,066.4 
Net Income (Loss)$394.2 $147.4 $139.3 $114.6 $(47.3)$0 $748.2 
Three Months Ended September 30, 2019
 Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing		Corporate and Other (a)Reconciling AdjustmentsConsolidated
 (in millions)
Revenues from:      
External Customers$2,598.9 $1,147.3 $65.5 $501.2 $2.1 $0 $4,315.0 
Other Operating Segments46.6 39.3 207.5 32.5 22.3 (348.2)0 
Total Revenues$2,645.5 $1,186.6 $273.0 $533.7 $24.4 $(348.2)$4,315.0 
Net Income (Loss)$438.4 $133.7 $127.0 $88.7 $(53.9)$0 $733.9 
Nine Months Ended September 30, 2020
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing		Corporate and Other (a)Reconciling AdjustmentsConsolidated
(in millions)
Revenues from:
External Customers$6,655.4 $3,208.7 $215.7 $1,223.4 $4.7 $0 $11,307.9 
Other Operating Segments98.1 98.0 662.1 82.1 67.3 (1,007.6)0 
Total Revenues$6,753.5 $3,306.7 $877.8 $1,305.5 $72.0 $(1,007.6)$11,307.9 
Net Income (Loss)$896.8 $403.1 $373.1 $203.6 $(114.6)$0 $1,762.0 
Nine Months Ended September 30, 2019
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing		Corporate and Other (a)Reconciling AdjustmentsConsolidated
(in millions)
Revenues from:
External Customers$7,087.6 $3,328.7 $196.5 $1,323.8 $8.8 $0 $11,945.4 
Other Operating Segments85.0 125.6 611.8 104.4 64.9 (991.7)0 
Total Revenues$7,172.6 $3,454.3 $808.3 $1,428.2 $73.7 $(991.7)$11,945.4 
Net Income (Loss)$920.8 $421.6 $407.6 $133.1 $(116.0)$0 $1,767.1 

172





September 30, 2020
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing		Corporate and Other (a)Reconciling
Adjustments		Consolidated
 (in millions)
Total Property, Plant and Equipment$48,533.5 $20,738.7 $11,377.1 $1,854.4 $399.3 $0 $82,903.0 
Accumulated Depreciation and Amortization15,340.1 3,891.6 553.1 150.1 181.7 0 20,116.6 
Total Property Plant and Equipment - Net$33,193.4 $16,847.1 $10,824.0 $1,704.3 $217.6 $0 $62,786.4 
Total Assets$42,110.4 $19,250.3 $12,035.8 $3,368.6 $5,718.9 (b)$(3,794.7)(c)$78,689.3 
Long-term Debt Due Within One Year:
Nonaffiliated1,313.7 87.8 2.3 0 507.8 (d)0 1,911.6 
Long-term Debt:
Affiliated59.0 0 0 0 0 (59.0)0 
Nonaffiliated12,048.7 7,196.7 4,123.2 0 4,786.9 (d)0 28,155.5 
Total Long-term Debt$13,421.4 $7,284.5 $4,125.5 $0 $5,294.7 $(59.0)$30,067.1 
December 31, 2019
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration
&
Marketing		Corporate and Other (a)Reconciling
Adjustments		Consolidated
 (in millions)
Total Property, Plant and Equipment$47,323.7 $19,773.3 $10,334.0 $1,650.8 $418.4 $(354.5)(e)$79,145.7 
Accumulated Depreciation and Amortization14,580.4 3,911.2 418.9 99.0 184.5 (186.4)(e)19,007.6 
Total Property Plant and Equipment - Net$32,743.3 $15,862.1 $9,915.1 $1,551.8 $233.9 $(168.1)(e)$60,138.1 
Total Assets$41,228.8 $18,757.5 $11,143.5 $3,123.8 $5,440.0 (b)$(3,801.3)(c) (e)$75,892.3 
Long-term Debt Due Within One Year:
Affiliated$20.0 $0 $0 $0 $0 $(20.0)$0 
Nonaffiliated704.7 392.2 0 0 501.8 (d)0 1,598.7 
Long-term Debt:
Affiliated39.0 0 0 0 0 (39.0)0 
Nonaffiliated12,162.0 6,248.1 3,593.8 0 3,122.9 (d)0 25,126.8 
Total Long-term Debt$12,925.7 $6,640.3 $3,593.8 $0 $3,624.7 $(59.0)$26,725.5 

(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 certain estimateselimination of intercompany advances to affiliates and allocations where necessary.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.
 Three Months Ended September 30, 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$2,453.8
 $1,149.7
 $45.1
 $441.5
 $14.6
 $—
 $4,104.7
Other Operating Segments28.4
 23.6
 133.4
 24.0
 16.7
 (226.1) —
Total Revenues$2,482.2
 $1,173.3
 $178.5
 $465.5
 $31.3
 $(226.1) $4,104.7
              
Income (Loss) from Continuing Operations$297.3
 $144.0
 $76.5
 $33.7
 $5.2
 $—
 $556.7
Loss from Discontinued Operations, Net of Tax—
 —
 —
 —
 —
 —
 —
Net Income (Loss)$297.3
 $144.0
 $76.5
 $33.7
 $5.2
 $—
 $556.7
              
 Three Months Ended September 30, 2016
 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$2,538.3
 $1,245.4
 $39.5
 $823.3
 $5.7
 $—
 $4,652.2
Other Operating Segments18.0
 30.2
 92.9
 36.1
 19.1
 (196.3) —
Total Revenues$2,556.3
 $1,275.6
 $132.4
 $859.4
 $24.8
 $(196.3) $4,652.2
              
Income (Loss) from Continuing Operations$343.4
 $155.7
 $69.5
 $(1,369.2) $36.4
 $—
 $(764.2)
Loss from Discontinued Operations, Net of Tax—
 —
 —
 —
 —
 —
 —
Net Income (Loss)$343.4
 $155.7
 $69.5
 $(1,369.2) $36.4
 $—
 $(764.2)
(e)Includes eliminations due to an intercompany finance lease.



 Nine Months Ended September 30, 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$6,819.3
 $3,242.7
 $125.8
 $1,386.8
 $39.9
 $—
 $11,614.5
Other Operating Segments73.8
 70.5
 456.1
 80.7
 46.8
 (727.9) —
Total Revenues$6,893.1
 $3,313.2
 $581.9
 $1,467.5
 $86.7
 $(727.9) $11,614.5
              
Income (Loss) from Continuing Operations$639.2
 $374.3
 $278.3
 $246.3
 $(11.0) $—
 $1,527.1
Loss from Discontinued Operations, Net of Tax—
 —
 —
 —
 —
 —
 —
Net Income (Loss)$639.2
 $374.3
 $278.3
 $246.3
 $(11.0) $—
 $1,527.1
              
 Nine Months Ended September 30, 2016
 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$6,864.6
 $3,398.9
 $110.1
 $2,192.5
 $23.9
 $—
 $12,590.0
Other Operating Segments63.2
 69.6
 272.6
 98.7
 55.2
 (559.3) —
Total Revenues$6,927.8
 $3,468.5
 $382.7
 $2,291.2
 $79.1
 $(559.3) $12,590.0
              
Income (Loss) from Continuing Operations$832.6
 $387.8
 $209.5
 $(1,248.8) $64.2
 $—
 $245.3
Loss from Discontinued Operations, Net of Tax—
 —
 —
 —
 (2.5) —
 (2.5)
Net Income (Loss)$832.6
 $387.8
 $209.5
 $(1,248.8) $61.7
 $—
 $242.8


  September 30, 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 $42,722.9
 $15,695.2
 $6,394.2
 $632.9
 $359.5
 $(366.5)(b)$65,438.2
Accumulated Depreciation and Amortization 13,042.9
 3,766.2
 156.6
 161.7
 180.8
 (186.5)(b)17,121.7
Total Property Plant and Equipment - Net $29,680.0
 $11,929.0
 $6,237.6
 $471.2
 $178.7
 $(180.0)(b)$48,316.5
               
Total Assets $38,136.4
 $15,765.0
 $7,631.2
 $1,904.4
 $22,339.9
 $(21,812.0)(b) (c)$63,964.9
               
Long-term Debt Due Within One Year:              
Non-Affiliated $1,107.2
 $703.4
 $—
 $0.1
 $548.6
 $—
 $2,359.3
               
Long-term Debt:              
Affiliated 50.0
 —
 —
 32.2
 —
 (82.2) —
Non-Affiliated 10,644.2
 4,738.0
 2,682.1
 (0.3) 298.4
 —
 18,362.4
               
Total Long-term Debt $11,801.4
 $5,441.4
 $2,682.1
 $32.0
 $847.0
 $(82.2) $20,721.7
               
  December 31, 2016
  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 $41,552.6
 $14,762.2
 $5,354.0
 $364.7
 $356.6
 $(353.5)(b)$62,036.6
Accumulated Depreciation and Amortization 12,596.7
 3,655.0
 101.4
 42.2
 186.0
 (184.0)(b)16,397.3
Total Property Plant and Equipment - Net $28,955.9
 $11,107.2
 $5,252.6
 $322.5
 $170.6
 $(169.5)(b)$45,639.3
               
Assets Held for Sale $—
 $—
 $—
 $1,951.2
 $—
 $—
 $1,951.2
               
Total Assets $37,428.3
 $14,802.4
 $6,384.8
 $3,386.1
 $20,354.8
 $(18,888.7)(b) (c)$63,467.7
               
Long-term Debt Due Within One Year:              
Non-Affiliated $1,519.9
 $309.4
 $—
 $500.1
 $548.6
 $—
 $2,878.0
               
Long-term Debt:              
Affiliated 20.0
 —
 —
 32.2
 —
 (52.2) —
Non-Affiliated 10,353.3
 4,672.2
 2,055.7
 —
 297.2
 —
 17,378.4
               
Total Long-term Debt $11,893.2
 $4,981.6
 $2,055.7
 $532.3
 $845.8
 $(52.2) $20,256.4
               
Liabilities Held for Sale $—
 $—
 $—
 $235.9
 $—
 $—
 $235.9

(a)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.
(b)Includes eliminations due to an intercompany capital lease.
(c)Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies.



Registrant Subsidiaries’ Reportable Segments (Applies to APCo, I&M, OPCo, PSO and SWEPCo)all Registrant Subsidiaries except AEPTCo)


The Registrant Subsidiaries besides AEPTCo, 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.  OperationsThe 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.


173





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 RTO’sRTOs 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 TranscoTranscos operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one operating segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities.


The tables below present AEPTCo’s reportable segment income statement information for the three and nine months ended September 30, 20172020 and 20162019 and reportable segment balance sheet information as of September 30, 20172020 and December 31, 2016. These amounts include certain estimates and allocations where necessary.2019.
Three Months Ended September 30, 2020
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Revenues from:
External Customers$62.9 $0 $0 $62.9 
Sales to AEP Affiliates241.2 0 0 241.2 
Total Revenues$304.1 $0 $0 $304.1 
Interest Income$0 $38.4 $(38.2)(a)$0.2 
Interest Expense32.7 38.2 (38.2)(a)32.7 
Income Tax Expense31.7 0 0 31.7 
Net Income$117.5 $0.1 (b)$0 $117.6 
Three Months Ended September 30, 2019
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Revenues from:
External Customers$54.0 $0 $0 $54.0 
Sales to AEP Affiliates205.7 0 0 205.7 
Total Revenues$259.7 $0 $0 $259.7 
Interest Income$0.4 $32.3 $(31.9)(a)$0.8 
Interest Expense26.4 31.9 (31.9)(a)26.4 
Income Tax Expense30.0 0.1 0 30.1 
Net Income$107.3 $0.3 (b)$0 $107.6 
174





Three Months Ended September 30, 2017Nine Months Ended September 30, 2020
State Transcos AEPTCo Parent Reconciling Adjustments 
AEPTCo
Consolidated
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo Consolidated
(in millions)(in millions)
Revenues from:       Revenues from:
External Customers$35.9
 $—
 $—
 $35.9
External Customers$184.6 $0 $0 $184.6 
Sales to AEP Affiliates131.3
 —
 0.1
 131.4
Sales to AEP Affiliates652.60 0 652.6 
Other RevenuesOther Revenues0.6 0 0 0.6 
Total Revenues$167.2
 $—
 $0.1
 $167.3
Total Revenues$837.8 $0 $0 $837.8 
       
Interest Income$—
 $19.5
 $(19.3)(a)$0.2
Interest Income$0.9 $111.3 $(109.9)(a)$2.3 
Interest Expense16.9
 19.3
 (19.3)(a)16.9
Interest Expense95.1 109.9 (109.9)(a)95.1 
Income Tax Expense30.2
 —
 —
 30.2
Income Tax Expense82.7 0.1 0 82.8 
Equity Earnings in State Transcos—
 59.8
 (59.8)(b)—
       
Net Income$59.8
 $59.9
 $(59.8)(b)$59.9
Net Income$308.0 $1.1 (b)$0 $309.1 
Nine Months Ended September 30, 2019
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo Consolidated
(in millions)
Revenues from:Revenues from:
External CustomersExternal Customers$162.1 $0 $0 $162.1 
Sales to AEP AffiliatesSales to AEP Affiliates608.00 0 608.0 
Total RevenuesTotal Revenues$770.1 $0 $0 $770.1 
Interest IncomeInterest Income$0.8 $89.7 $(88.4)(a)$2.1 
Interest ExpenseInterest Expense69.588.4(88.4)(a)69.5
Income Tax ExpenseIncome Tax Expense90.5 0.2 0 90.7 
Net IncomeNet Income$347.1 $0.8 (b)$0 $347.9 
September 30, 2020
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Total Transmission Property$10,921.3 $0 $0 $10,921.3 
Accumulated Depreciation and Amortization531.8 0 0 531.8 
Total Transmission Property – Net$10,389.5 $0 $0 $10,389.5 
Notes Receivable - Affiliated$0 $3,947.9 $(3,947.9)(c)$0 
Total Assets$10,641.8 $4,104.1 (d)$(4,047.2)(e)$10,698.7 
Total Long-term Debt$3,990.0 $3,947.9 $(3,990.0)(c)$3,947.9 
December 31, 2019
State TranscosAEPTCo ParentReconciling AdjustmentsAEPTCo
Consolidated
(in millions)
Total Transmission Property$9,893.2 $0 $0 $9,893.2 
Accumulated Depreciation and Amortization402.3 0 0 402.3 
Total Transmission Property – Net$9,490.9 $0 $0 $9,490.9 
Notes Receivable - Affiliated$— $3,427.3 $(3,427.3)(c)$0 
Total Assets$9,865.0 $3,519.1 (d)$(3,493.3)(e)$9,890.8 
Total Long-term Debt$3,465.0 $3,427.3 $(3,465.0)(c)$3,427.3 

(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.


175
 Three Months Ended September 30, 2016
 State Transcos AEPTCo Parent Reconciling Adjustments 
AEPTCo
Consolidated
 (in millions)
Revenues from:       
External Customers$33.5
 $—
 $—
 $33.5
Sales to AEP Affiliates91.8
 —
 —
 91.8
Total Revenues$125.3
 $—
 $—
 $125.3
        
Interest Income$—
 $14.0
 $(13.9)(a)$0.1
Interest Expense11.0
 13.9
 (13.9)(a)11.0
Income Tax Expense26.4
 —
 —
 26.4
Equity Earnings in State Transcos—
 52.3
 (52.3)(b)—
        
Net Income$52.3
 $52.4
 $(52.3)(b)$52.4







 Nine Months Ended September 30, 2017
 State Transcos AEPTCo Parent Reconciling Adjustments 
AEPTCo
Consolidated
 (in millions)
Revenues from:       
External Customers$99.2
 $—
 $—
 $99.2
Sales to AEP Affiliates450.2
 —
 —
 450.2
Total Revenues$549.4
 $—
 $—
 $549.4
        
Interest Income$0.1
 $58.0
 $(57.6)(a)$0.5
Interest Expense48.6
 57.6
 (57.6)(a)48.6
Income Tax Expense114.3
 0.2
 —
 114.5
Equity Earnings in State Transcos—
 224.0
 (224.0)(b)—
        
Net Income$224.0
 $224.3
 $(224.0)(b)$224.3
 Nine Months Ended September 30, 2016
 State Transcos AEPTCo Parent Reconciling Adjustments 
AEPTCo
Consolidated
 (in millions)
Revenues from:       
External Customers$89.6
 $—
 $—
 $89.6
Sales to AEP Affiliates268.4
 —
 —
 268.4
Total Revenues$358.0
 $—
 $—
 $358.0
        
Interest Income$—
 $41.8
 $(41.6)(a)$0.2
Interest Expense32.3
 41.6
 (41.6)(a)32.3
Income Tax Expense73.9
 —
 —
 73.9
Equity Earnings in State Transcos—
 153.0
 (153.0)(b)—
        
Net Income$153.0
 $153.0
 $(153.0)(b)$153.0
 September 30, 2017
 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated
 (in millions)
Total Transmission Property$6,067.5
 $—
 $—
 $6,067.5
Accumulated Depreciation and Amortization151.5
 —
 —
 151.5
Total Transmission Property – Net$5,916.0
 $—
 $—
 $5,916.0
        
Notes Receivable - Affiliated$—
 $2,500.0
 $(2,500.0)(c)$—
        
Total Assets$6,455.2
 $5,010.8
 $(4,917.1)(d)$6,548.9
        
Total Long-term Debt$2,475.6
 $2,574.4
 $(2,500.0)(c)$2,550.0
 December 31, 2016
 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated
 (in millions)
Total Transmission Property$5,054.2
 $—
 $—
 $5,054.2
Accumulated Depreciation and Amortization99.6
 —
 —
 99.6
Total Transmission Property – Net$4,954.6
 $—
 $—
 $4,954.6
        
Notes Receivable - Affiliated$—
 $1,950.0
 $(1,950.0)(c)$—
        
Total Assets$5,337.5
 $3,947.8
 $(3,935.5)(d)$5,349.8
        
Total Long-term Debt$1,932.0
 $1,950.0
 $(1,950.0)(c)$1,932.0

(a)Elimination of intercompany interest income/interest expense on affiliated debt arrangement.
(b)Elimination of AEPTCo Parent’s equity earnings in the State Transcos.
(c)Elimination of intercompany debt.
(d)Primarily relates to the elimination of AEPTCo Parent’s investment in the State Transcos and Note 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. AEP Energy Partners, LLCAEPEP 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.



176






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


Notional Volume of Derivative Instruments
September 30, 20172020
Primary Risk
Exposure
 
Unit of
Measure
 AEP APCo I&M OPCo PSO SWEPCo
    (in millions)
Commodity:        
  
  
  
Power MWhs 406.0
 73.7
 45.8
 10.6
 13.7
 34.5
Coal Tons 0.5
 —
 0.2
 —
 —
 0.3
Natural Gas MMBtus 48.1
 2.0
 1.2
 —
 —
 18.3
Heating Oil and Gasoline Gallons 7.9
 1.5
 0.7
 1.8
 0.8
 0.9
Interest Rate USD $53.2
 $—
 $—
 $—
 $—
 $—
               
Interest Rate USD $1,000.0
 $—
 $—
 $—
 $—
 $—

Notional Volume of Derivative Instruments
Primary Risk
Exposure		Unit of
Measure		AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Commodity:      
PowerMWhs390.6 0 71.7 28.9 3.1 19.8 5.6 
Natural GasMMBtus33.3 0 0 0 0 0 8.8 
Heating Oil and GasolineGallons8.3 2.2 1.3 0.8 1.7 0.9 1.1 
Interest RateUSD$129.8 $0 $0 $0 $0 $0 $0 
Interest Rate on Long-term DebtUSD$200.0 $0 $200.0 $0 $0 $0 $0 
December 31, 20162019
Primary Risk
Exposure		Unit of
Measure		AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Commodity:      
PowerMWhs365.9 0 61.0 26.8 7.1 14.9 4.4 
Natural GasMMBtus40.7 0 0 0 0 0 11.6 
Heating Oil and GasolineGallons6.9 1.8 1.1 0.6 1.4 0.7 0.9 
Interest RateUSD$140.1 $0 $0 $0 $0 $0 $0 
Interest Rate on Long-term DebtUSD$625.0 $0 $0 $0 $0 $0 $0 
Primary Risk
Exposure
 
Unit of
Measure
 AEP APCo I&M OPCo PSO SWEPCo
    (in millions)
Commodity:        
  
  
  
Power MWhs 348.0
 51.9
 19.9
 11.2
 11.9
 14.2
Coal Tons 1.5
 —
 0.5
 —
 —
 1.0
Natural Gas MMBtus 32.8
 —
 —
 —
 —
 —
Heating Oil and Gasoline Gallons 7.4
 1.4
 0.7
 1.6
 0.8
 0.9
Interest Rate USD $75.2
 $0.1
 $0.1
 $—
 $—
 $—
               
Interest Rate 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.

177

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 and 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. The RegistrantsAEP netted cash collateral received from third partiesthird-parties against short-term and long-term risk management assets in the amounts of $0 and $5 million as of September 30, 2020 and December 31, 2019, respectively. AEP netted cash collateral paid to third-parties against short-term and long-term risk management liabilities in the amounts of $9 million and $39 million as of September 30, 2020 and December 31, 2019, respectively. The netted cash collateral from third-parties against short-term and long-term risk management assets and netted cash collateral paid to third partiesthird-parties against short-term and long-term risk management liabilities were immaterial for the Registrant Subsidiaries as follows:of September 30, 2020 and December 31, 2019.
178
  September 30, 2017 December 31, 2016
  Cash Collateral Cash Collateral Cash Collateral Cash Collateral
  Received Paid Received Paid
  Netted Against Netted Against Netted Against Netted Against
  Risk Management Risk Management Risk Management Risk Management
Company Assets Liabilities Assets Liabilities
  (in millions)
AEP $3.5
 $17.0
 $7.9
 $7.6
APCo 0.4
 0.3
 0.5
 0.7
I&M 0.3
 0.1
 0.3
 0.4
OPCo 0.1
 —
 0.2
 —
PSO —
 —
 0.1
 —
SWEPCo —
 —
 0.1
 —







The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets:


AEP


Fair Value of Derivative Instruments
September 30, 20172020
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$253.7 $24.5 $0.6 $278.8 $(163.6)$115.2 
Long-term Risk Management Assets283.3 17.5 0 300.8 (57.9)242.9 
Total Assets537.0 42.0 0.6 579.6 (221.5)358.1 
Current Risk Management Liabilities183.1 40.6 5.3 229.0 (166.6)62.4 
Long-term Risk Management Liabilities239.0 57.0 0 296.0 (63.6)232.4 
Total Liabilities422.1 97.6 5.3 525.0 (230.2)294.8 
Total MTM Derivative Contract Net Assets (Liabilities)$114.9 $(55.6)$(4.7)$54.6 $8.7 $63.3 

December 31, 2019
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$513.9 $11.5 $6.5 $531.9 $(359.1)$172.8 
Long-term Risk Management Assets290.8 11.0 12.6 314.4 (47.8)266.6 
Total Assets804.7 22.5 19.1 846.3 (406.9)439.4 
Current Risk Management Liabilities424.5 72.3 0 496.8 (382.5)114.3 
Long-term Risk Management Liabilities244.5 75.7 0 320.2 (58.4)261.8 
Total Liabilities669.0 148.0 0 817.0 (440.9)376.1 
Total MTM Derivative Contract Net Assets (Liabilities)$135.7 $(125.5)$19.1 $29.3 $34.0 $63.3 

179





  
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 $277.4
 $8.1
 $4.2
 $289.7
 $(143.6) $146.1
Long-term Risk Management Assets 348.1
 3.8
 —
 351.9
 (41.5) 310.4
Total Assets 625.5
 11.9
 4.2
 641.6
 (185.1) 456.5
             
Current Risk Management Liabilities 202.2
 13.5
 1.4
 217.1
 (147.7) 69.4
Long-term Risk Management Liabilities 329.6
 74.0
 —
 403.6
 (50.9) 352.7
Total Liabilities 531.8
 87.5
 1.4
 620.7
 (198.6) 422.1
             
Total MTM Derivative Contract Net Assets (Liabilities) $93.7
 $(75.6) $2.8
 $20.9
 $13.5
 $34.4
             
             
Fair Value of Derivative Instruments
December 31, 2016
             
  
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 $264.4
 $13.2
 $—
 $277.6
 $(183.1) $94.5
Long-term Risk Management Assets 315.0
 7.7
 —
 322.7
 (33.6) 289.1
Total Assets 579.4
 20.9
 —
 600.3
 (216.7) 383.6
             
Current Risk Management Liabilities 227.2
 6.3
 —
 233.5
 (180.1) 53.4
Long-term Risk Management Liabilities 301.0
 50.1
 1.4
 352.5
 (36.3) 316.2
Total Liabilities 528.2
 56.4
 1.4
 586.0
 (216.4) 369.6
             
Total MTM Derivative Contract Net Assets (Liabilities) $51.2
 $(35.5) $(1.4) $14.3
 $(0.3) $14.0
AEP Texas

Fair Value of Derivative Instruments

September 30, 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 $0 $0 
Long-term Risk Management Assets0 0 0 
Total Assets0 0 0 
Current Risk Management Liabilities0.2 (0.1)0.1 
Long-term Risk Management Liabilities0 0 0 
Total Liabilities0.2 (0.1)0.1 
Total MTM Derivative Contract Net Assets (Liabilities)$(0.2)$0.1 $(0.1)

December 31, 2019
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 $0 $0 
Long-term Risk Management Assets0 0 0 
Total Assets0 0 0 
Current Risk Management Liabilities0 0 0 
Long-term Risk Management Liabilities0 0 0 
Total Liabilities0 0 0 
Total MTM Derivative Contract Net Assets$0 $0 $0 

APCo
Fair Value of Derivative Instruments
September 30, 20172020
Risk ManagementHedgingGross Amounts OffsetNet Amounts of Assets/Liabilities
Contracts –Contracts –in the Statement ofPresented in the Statement of
Balance Sheet LocationCommodity (a)Interest Rate (a)Financial Position (b)Financial Position (c)
(in millions)
Current Risk Management Assets$49.6 $0.6 $(19.5)$30.7 
Long-term Risk Management Assets1.6 0 (1.5)0.1 
Total Assets51.2 0.6 (21.0)30.8 
Current Risk Management Liabilities20.7 5.3 (20.4)5.6 
Long-term Risk Management Liabilities1.8 0 (1.6)0.2 
Total Liabilities22.5 5.3 (22.0)5.8 
Total MTM Derivative Contract Net Assets (Liabilities)$28.7 $(4.7)$1.0 $25.0 
  Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
  Contracts - in the Statement of Presented in the Statement
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c)
  (in millions)
Current Risk Management Assets $50.4
 $(20.1) $30.3
Long-term Risk Management Assets 4.9
 (4.3) 0.6
Total Assets 55.3
 (24.4) 30.9
       
Current Risk Management Liabilities 20.7
 (19.8) 0.9
Long-term Risk Management Liabilities 4.8
 (4.5) 0.3
Total Liabilities 25.5
 (24.3) 1.2
       
Total MTM Derivative Contract Net Assets (Liabilities) $29.8
 $(0.1) $29.7

Fair Value of Derivative Instruments
December 31, 20162019
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$124.4 $(85.0)$39.4 
Long-term Risk Management Assets0.9 (0.8)0.1 
Total Assets125.3 (85.8)39.5 
Current Risk Management Liabilities86.2 (84.3)1.9 
Long-term Risk Management Liabilities0.7 (0.7)0 
Total Liabilities86.9 (85.0)1.9 
Total MTM Derivative Contract Net Assets (Liabilities)$38.4 $(0.8)$37.6 
180
  Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
  Contracts - in the Statement of Presented in the Statement
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c)
  (in millions)
Current Risk Management Assets $22.7
 $(20.1) $2.6
Long-term Risk Management Assets 1.9
 (1.9) —
Total Assets 24.6
 (22.0) 2.6
       
Current Risk Management Liabilities 20.6
 (20.3) 0.3
Long-term Risk Management Liabilities 2.8
 (1.9) 0.9
Total Liabilities 23.4
 (22.2) 1.2
       
Total MTM Derivative Contract Net Assets $1.2
 $0.2
 $1.4






I&M
Fair Value of Derivative Instruments
September 30, 20172020
Risk ManagementGross Amounts OffsetNet Amounts of Assets/Liabilities
Contracts –in the Statement ofPresented in the Statement of
Balance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)
(in millions)
Current Risk Management Assets$16.5 $(12.4)$4.1 
Long-term Risk Management Assets1.0 (1.0)0 
Total Assets17.5 (13.4)4.1 
Current Risk Management Liabilities13.1 (12.9)0.2 
Long-term Risk Management Liabilities1.1 (1.0)0.1 
Total Liabilities14.2 (13.9)0.3 
Total MTM Derivative Contract Net Assets$3.3 $0.5 $3.8 
  Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
  Contracts - in the Statement of Presented in the Statement
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c)
  (in millions)
Current Risk Management Assets $27.4
 $(15.8) $11.6
Long-term Risk Management Assets 3.3
 (2.8) 0.5
Total Assets 30.7
 (18.6) 12.1
       
Current Risk Management Liabilities 17.6
 (15.6) 2.0
Long-term Risk Management Liabilities 3.0
 (2.8) 0.2
Total Liabilities 20.6
 (18.4) 2.2
       
Total MTM Derivative Contract Net Assets (Liabilities) $10.1
 $(0.2) $9.9

Fair Value of Derivative Instruments
December 31, 20162019
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$66.9 $(57.1)$9.8 
Long-term Risk Management Assets0.5 (0.4)0.1 
Total Assets67.4 (57.5)9.9 
Current Risk Management Liabilities55.2 (54.7)0.5 
Long-term Risk Management Liabilities0.4 (0.4)0 
Total Liabilities55.6 (55.1)0.5 
Total MTM Derivative Contract Net Assets (Liabilities)$11.8 $(2.4)$9.4 
  Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
  Contracts - in the Statement of Presented in the Statement
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c)
  (in millions)
Current Risk Management Assets $14.9
 $(11.4) $3.5
Long-term Risk Management Assets 1.1
 (1.1) —
Total Assets 16.0
 (12.5) 3.5
       
Current Risk Management Liabilities 11.8
 (11.5) 0.3
Long-term Risk Management Liabilities 1.9
 (1.1) 0.8
Total Liabilities 13.7
 (12.6) 1.1
       
Total MTM Derivative Contract Net Assets $2.3
 $0.1
 $2.4




OPCo
Fair Value of Derivative Instruments
September 30, 20172020
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 $0 $0 
Long-term Risk Management Assets0 0 0 
Total Assets0 0 0 
Current Risk Management Liabilities8.3 (0.1)8.2 
Long-term Risk Management Liabilities105.1 0 105.1 
Total Liabilities113.4 (0.1)113.3 
Total MTM Derivative Contract Net Assets (Liabilities)$(113.4)$0.1 $(113.3)
  Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
  Contracts - in the Statement of Presented in the Statement
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c)
  (in millions)
Current Risk Management Assets $0.3
 $(0.1) $0.2
Long-term Risk Management Assets —
 —
 —
Total Assets 0.3
 (0.1) 0.2
       
Current Risk Management Liabilities 7.6
 —
 7.6
Long-term Risk Management Liabilities 130.9
 —
 130.9
Total Liabilities 138.5
 —
 138.5
       
Total MTM Derivative Contract Net Liabilities $(138.2) $(0.1) $(138.3)

Fair Value of Derivative Instruments
December 31, 20162019
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 $0 $0 
Long-term Risk Management Assets0 0 0 
Total Assets0 0 0 
Current Risk Management Liabilities7.3 0 7.3 
Long-term Risk Management Liabilities96.3 0 96.3 
Total Liabilities103.6 0 103.6 
Total MTM Derivative Contract Net Liabilities$(103.6)$0 $(103.6)
181
  Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
  Contracts - in the Statement of Presented in the Statement
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c)
  (in millions)
Current Risk Management Assets $0.4
 $(0.2) $0.2
Long-term Risk Management Assets —
 —
 —
Total Assets 0.4
 (0.2) 0.2
       
Current Risk Management Liabilities 5.9
 —
 5.9
Long-term Risk Management Liabilities 113.1
 —
 113.1
Total Liabilities 119.0
 —
 119.0
       
Total MTM Derivative Contract Net Liabilities $(118.6) $(0.2) $(118.8)






PSO
Fair Value of Derivative Instruments
September 30, 20172020
Risk ManagementGross Amounts OffsetNet Amounts of Assets/Liabilities
Contracts –in the Statement ofPresented in the Statement of
Balance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)
(in millions)
Current Risk Management Assets$16.6 $0 $16.6 
Long-term Risk Management Assets0 0 0 
Total Assets16.6 0 16.6 
Current Risk Management Liabilities0.6 (0.1)0.5 
Long-term Risk Management Liabilities0 0 0 
Total Liabilities0.6 (0.1)0.5 
Total MTM Derivative Contract Net Assets$16.0 $0.1 $16.1 
  Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
  Contracts - in the Statement of Presented in the Statement
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c)
  (in millions)
Current Risk Management Assets $4.7
 $—
 $4.7
Long-term Risk Management Assets —
 —
 —
Total Assets 4.7
 —
 4.7
       
Current Risk Management Liabilities —
 —
 —
Long-term Risk Management Liabilities —
 —
 —
Total Liabilities —
 —
 —
       
Total MTM Derivative Contract Net Assets $4.7
 $—
 $4.7

Fair Value of Derivative Instruments
December 31, 20162019
Risk ManagementGross Amounts OffsetNet Amounts of Assets/Liabilities
Contracts –in the Statement ofPresented in the Statement of
Balance Sheet LocationCommodity (a)Financial Position (b)Financial Position (c)
(in millions)
Current Risk Management Assets$16.3 $(0.5)$15.8 
Long-term Risk Management Assets0 0 0 
Total Assets16.3 (0.5)15.8 
Current Risk Management Liabilities0.5 (0.5)0 
Long-term Risk Management Liabilities0 0 0 
Total Liabilities0.5 (0.5)0 
Total MTM Derivative Contract Net Assets$15.8 $0 $15.8 
  Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
  Contracts - in the Statement of Presented in the Statement
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c)
  (in millions)
Current Risk Management Assets $0.9
 $(0.1) $0.8
Long-term Risk Management Assets —
 —
 —
Total Assets 0.9
 (0.1) 0.8
       
Current Risk Management Liabilities —
 —
 —
Long-term Risk Management Liabilities —
 —
 —
Total Liabilities —
 —
 —
       
Total MTM Derivative Contract Net Assets (Liabilities) $0.9
 $(0.1) $0.8




SWEPCo
Fair Value of Derivative Instruments
September 30, 20172020
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$4.5 $0 $4.5 
Long-term Risk Management Assets0 0 0 
Total Assets4.5 0 4.5 
Current Risk Management Liabilities0.2 (0.1)0.1 
Long-term Risk Management Liabilities0.7 0 0.7 
Total Liabilities0.9 (0.1)0.8 
Total MTM Derivative Contract Net Assets$3.6 $0.1 $3.7 
  Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
  Contracts - in the Statement of Presented in the Statement
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c)
  (in millions)
Current Risk Management Assets $12.7
 $(0.2) $12.5
Long-term Risk Management Assets 0.7
 —
 0.7
Total Assets 13.4
 (0.2) 13.2
       
Current Risk Management Liabilities 0.3
 (0.2) 0.1
Long-term Risk Management Liabilities —
 —
 —
Total Liabilities 0.3
 (0.2) 0.1
       
Total MTM Derivative Contract Net Assets $13.1
 $—
 $13.1

Fair Value of Derivative Instruments
December 31, 20162019
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$6.5 $(0.1)$6.4 
Long-term Risk Management Assets0 0 0 
Total Assets6.5 (0.1)6.4 
Current Risk Management Liabilities2.0 (0.1)1.9 
Long-term Risk Management Liabilities3.1 0 3.1 
Total Liabilities5.1 (0.1)5.0 
Total MTM Derivative Contract Net Assets$1.4 $0 $1.4 

(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)All derivative contracts subject to a master netting arrangement or similar agreement are offset in the statement of financial position.
182
  Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
  Contracts - in the Statement of Presented in the Statement
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c)
  (in millions)
Current Risk Management Assets $1.1
 $(0.2) $0.9
Long-term Risk Management Assets —
 —
 —
Total Assets 1.1
 (0.2) 0.9
       
Current Risk Management Liabilities 0.4
 (0.1) 0.3
Long-term Risk Management Liabilities —
 —
 —
Total Liabilities 0.4
 (0.1) 0.3
       
Total MTM Derivative Contract Net Assets (Liabilities) $0.7
 $(0.1) $0.6


(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’ activity of derivative risk management contracts:


Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended September 30, 20172020
Location of Gain (Loss)AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Vertically Integrated Utilities Revenues$0.5 $0 $0 $0 $0 $0 $0 
Generation & Marketing Revenues11.5 0 0 0 0 0 0 
Electric Generation, Transmission and Distribution Revenues0 0 0.3 0 0 0 0 
Purchased Electricity for Resale0.3 0 0.2 0.1 0 0 0 
Other Operation(0.4)(0.1)(0.1)(0.1)(0.1)(0.1)(0.1)
Maintenance(0.8)(0.2)(0.1)(0.1)(0.2)0 (0.1)
Regulatory Assets (a)7.9 0.2 0.4 0.2 4.4 (0.4)2.9 
Regulatory Liabilities (a)17.0 0 3.8 2.6 1.7 3.1 2.0 
Total Gain (Loss) on Risk Management Contracts$36.0 $(0.1)$4.5 $2.7 $5.8 $2.6 $4.7 
Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo
  (in millions)
Vertically Integrated Utilities Revenues $0.9
 $—
 $—
 $—
 $—
 $—
Generation & Marketing Revenues 17.7
 —
 —
 —
 —
 —
Electric Generation, Transmission and Distribution Revenues —
 0.3
 0.6
 —
 —
 (0.1)
Purchased Electricity for Resale 1.0
 0.3
 0.2
 —
 —
 —
Other Operation 0.1
 —
 —
 0.1
 —
 —
Maintenance 0.1
 0.1
 —
 0.1
 —
 —
Regulatory Assets (a) (8.8) 0.1
 (0.8) (8.7) —
 0.3
Regulatory Liabilities (a) 15.6
 3.7
 2.1
 —
 2.6
 7.0
Total Gain (Loss) on Risk Management Contracts $26.6
 $4.5
 $2.1
 $(8.5) $2.6
 $7.2


Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended September 30, 20162019
Location of Gain (Loss)AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Vertically Integrated Utilities Revenues$0.5 $0 $0 $0 $0 $0 $0 
Generation & Marketing Revenues21.0 0 0 0 0 0 0 
Electric Generation, Transmission and Distribution Revenues0 0 0.2 0.2 0 0 0 
Purchased Electricity for Resale0.4 0 0.3 0 0 0 0 
Other Operation(0.1)0 (0.1)(0.1)(0.1)(0.1)0 
Maintenance(0.2)0 0 (0.1)0 0 0 
Regulatory Assets (a)(4.8)(0.2)0.2 0 (2.6)(0.1)(1.6)
Regulatory Liabilities (a)26.3 0 10.0 3.2 0 4.3 4.5 
Total Gain (Loss) on Risk Management Contracts$43.1 $(0.2)$10.6 $3.2 $(2.7)$4.1 $2.9 
Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo
  (in millions)
Vertically Integrated Utilities Revenues $2.4
 $—
 $—
 $—
 $—
 $—
Transmission and Distribution Utilities Revenues 0.1
 —
 —
 —
 —
 —
Generation & Marketing Revenues 9.2
 —
 —
 —
 —
 —
Electric Generation, Transmission and Distribution Revenues —
 1.0
 1.2
 0.1
 —
 (0.1)
Purchased Electricity for Resale 1.5
 0.8
 0.1
 —
 —
 —
Other Operation (0.4) —
 —
 (0.1) —
 —
Maintenance (0.4) (0.1) —
 (0.1) (0.1) (0.1)
Regulatory Assets (a) (22.5) 5.2
 1.6
 (95.4) 0.1
 2.8
Regulatory Liabilities (a) 28.6
 16.9
 5.5
 —
 0.8
 3.7
Total Gain (Loss) on Risk Management Contracts $18.5
 $23.8
 $8.4
 $(95.5) $0.8
 $6.3




Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Nine Months Ended September 30, 20172020
Location of Gain (Loss)AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Vertically Integrated Utilities Revenues$0.8 $0 $0 $0 $0 $0 $0 
Generation & Marketing Revenues11.1 0 0 0 0 0 0 
Electric Generation, Transmission and Distribution Revenues0 0 0.4 0.1 0 0 0.1 
Purchased Electricity for Resale1.2 0 1.0 0.1 0 0 0 
Other Operation(1.4)(0.4)(0.2)(0.2)(0.3)(0.2)(0.2)
Maintenance(2.2)(0.6)(0.3)(0.2)(0.4)(0.2)(0.3)
Regulatory Assets (a)(8.5)(0.3)(0.1)(0.2)(9.9)(0.6)2.2 
Regulatory Liabilities (a)80.9 0 16.2 8.8 8.4 23.9 14.8 
Total Gain (Loss) on Risk Management Contracts$81.9 $(1.3)$17.0 $8.4 $(2.2)$22.9 $16.6 
183





Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo
  (in millions)
Vertically Integrated Utilities Revenues $7.0
 $—
 $—
 $—
 $—
 $—
Generation & Marketing Revenues 38.5
 —
 —
 —
 —
 —
Electric Generation, Transmission and Distribution Revenues —
 0.6
 6.3
 —
 —
 —
Purchased Electricity for Resale 4.9
 1.6
 0.5
 —
 —
 —
Other Operation 0.5
 —
 —
 0.1
 —
 —
Maintenance 0.4
 0.1
 —
 0.1
 —
 —
Regulatory Assets (a) (26.8) —
 (1.0) (25.9) —
 0.1
Regulatory Liabilities (a) 81.8
 28.2
 15.3
 —
 13.7
 22.0
Total Gain (Loss) on Risk Management Contracts $106.3
 $30.5
 $21.1
 $(25.7) $13.7
 $22.1


Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Nine Months Ended September 30, 20162019
Location of Gain (Loss)AEPAEP TexasAPCoI&MOPCoPSOSWEPCo
(in millions)
Vertically Integrated Utilities Revenues$1.0 $0 $0 $0 $0 $0 $0 
Generation & Marketing Revenues27.2 0 0 0 0 0 0 
Electric Generation, Transmission and Distribution Revenues0 0 0.2 0.5 0 0 0.1 
Purchased Electricity for Resale1.6 0 1.4 0.1 0 0 0 
Other Operation(0.6)(0.1)(0.1)(0.1)(0.2)(0.1)(0.1)
Maintenance(0.6)(0.1)(0.1)(0.1)(0.1)0 (0.1)
Regulatory Assets (a)(19.4)0.3 0.4 0.2 (19.8)0.9 (0.4)
Regulatory Liabilities (a)64.5 0 (5.3)17.2 0 26.6 22.9 
Total Gain (Loss) on Risk Management Contracts$73.7 $0.1 $(3.5)$17.8 $(20.1)$27.4 $22.4 
Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo
  (in millions)
Vertically Integrated Utilities Revenues $3.1
 $—
 $—
 $—
 $—
 $—
Transmission and Distribution Utilities Revenues 0.1
 —
 —
 —
 —
 —
Generation & Marketing Revenues 50.1
 —
 —
 —
 —
 —
Electric Generation, Transmission and Distribution Revenues —
 (0.8) 3.7
 0.1
 —
 (0.1)
Sales to AEP Affiliates —
 2.1
 5.8
 —
 —
 —
Purchased Electricity for Resale 4.9
 2.7
 0.2
 —
 —
 —
Other Operation (1.3) (0.1) (0.1) (0.3) (0.1) (0.2)
Maintenance (1.6) (0.3) (0.1) (0.3) (0.2) (0.2)
Regulatory Assets (a) (51.0) (7.2) 3.0
 (115.9) 0.4
 5.5
Regulatory Liabilities (a) 58.0
 39.2
 11.2
 (15.2) 3.2
 14.7
Total Gain (Loss) on Risk Management Contracts $62.3
 $35.6
 $23.7
 $(131.6) $3.3
 $19.7


(a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
(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.

184






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
September 30, 2020December 31, 2019September 30, 2020December 31, 2019
(in millions)
Long-term Debt (a) (b)$(551.9)$(510.8)$(55.2)$(14.5)

(a)Amounts included on the balance sheets within Long-term Debt Due within One Year and Long-term Debt, respectively.
(b)Amounts include $(55) million and $0 as of hedging gains (losses):
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (in millions)
Gain (Loss) on Fair Value Hedging Instruments$0.1
 $(1.1) $(0.1) $3.0
Gain (Loss) on Fair Value Portion of Long-term Debt(0.1) 1.1
 0.1
 (3.0)

During the three and nine months ended September 30, 20172020 and 2016,December 31, 2019, respectively, for the fair value hedge ineffectivenessadjustment of hedged debt obligations for which hedge accounting has been discontinued.

The pretax effects of fair value hedge accounting on income were as follows:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(in millions)
Gain (Loss) on Interest Rate Contracts:
Gain on Fair Value Hedging Instruments (a)$0 $13.2 $42.6 $42.5 
Loss on Fair Value Portion of Long-term Debt (a)0 (13.2)(42.6)(42.5)

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

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


Accounting for Cash Flow Hedging Strategies


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 nine months ended September 30, 20172020 and 2016,2019, AEP applied cash flow hedging to outstanding power derivatives. During the three and nine months ended September 30, 20172020 and 2016,2019, 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 nine months ended September 30, 20172020, AEP and 2016,APCo applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not. During the three and nine months ended September 30, 2019, AEP applied cash flow hedging to outstanding interest rate derivatives. During the threederivatives and nine months ended September 30, 2017 and 2016, the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives.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 and nine months ended September 30, 2017 and 2016, the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives.
185



During the three and nine months ended September 30, 2017 and 2016, 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 3.3 - Comprehensive Income.




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


Impact of Cash Flow Hedges on AEP’s Balance Sheets
September 30, 2020December 31, 2019
CommodityInterest RateCommodityInterest Rate
(in millions)
AOCI Gain (Loss) Net of Tax$(45.1)$(52.3)$(103.5)$(11.5)
Portion Expected to be Reclassed to Net Income During the Next Twelve Months(13.9)(5.3)(51.7)(2.1)
  September 30, 2017 December 31, 2016
  Commodity Interest Rate Commodity Interest Rate
  (in millions)
Hedging Assets (a) $4.3
 $4.2
 $11.2
 $—
Hedging Liabilities (a) 79.9
 —
 46.7
 —
AOCI Gain (Loss) Net of Tax (49.2) (12.2) (23.1) (15.7)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months (3.6) (0.7) 4.3
 (1.0)

(a)Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets.


As of September 30, 20172020 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 126 months and 123 months.months for commodity and interest rate hedges, respectively.


Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets
September 30, 2020December 31, 2019
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$(2.6)$(1.1)$(3.4)$(1.1)
APCo(3.5)0.6 0.9 0.9 
I&M(8.7)(1.6)(9.9)(1.6)
PSO0.3 0.3 1.1 1.0 
SWEPCo(0.7)(1.5)(1.8)(1.5)
  September 30, 2017 December 31, 2016
  Interest Rate
    Expected to be   Expected to be
    Reclassified to   Reclassified to
    Net Income During   Net Income During
  AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next
Company Net of Tax Twelve Months Net of Tax Twelve Months
  (in millions)
APCo $2.4
 $0.7
 $2.9
 $0.7
I&M (11.0) (1.3) (12.0) (1.3)
OPCo 2.2
 1.1
 3.0
 1.1
PSO 2.8
 0.8
 3.4
 0.8
SWEPCo (6.3) (1.4) (7.4) (1.4)


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, Standard and Poor’s,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.



186







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.  AEP, APCo, I&M, PSO and SWEPCoThe Registrants have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral.  The Registrants had immaterialno derivative contracts with collateral triggering events in a net liability position as of September 30, 20172020 and December 31, 2016.2019, respectively.


Cross-Default Triggers (Applies to AEP, APCo, I&M and I&M)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 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:
September 30, 2020
Liabilities forAdditional
Contracts with CrossSettlement
Default ProvisionsLiability if Cross
Prior to ContractualAmount of CashDefault Provision
CompanyNetting ArrangementsCollateral Postedis Triggered
(in millions)
AEP$189.7 $0 $162.3 
APCo5.7 0 5.3 
I&M0.3 0 0 
SWEPCo0.9 0 0.9 
December 31, 2019
Liabilities forAdditional
Contracts with CrossSettlement
Default ProvisionsLiability if Cross
Prior to ContractualAmount of CashDefault Provision
CompanyNetting ArrangementsCollateral Postedis Triggered
(in millions)
AEP$267.3 $3.7 $246.7 
APCo2.3 0 0.4 
I&M1.3 0 0.2 
SWEPCo5.1 0 5.1 
187
  September 30, 2017
  Liabilities for   Additional
  Contracts with Cross   Settlement
  Default Provisions   Liability if Cross
  Prior to Contractual Amount of Cash Default Provision
Company Netting Arrangements Collateral Posted is Triggered
  (in millions)
AEP $285.9
 $2.5
 $274.4
APCo —
 —
 —
I&M —
 —
 —





  December 31, 2016
  Liabilities for   Additional
  Contracts with Cross   Settlement
  Default Provisions   Liability if Cross
  Prior to Contractual Amount of Cash Default Provision
Company Netting Arrangements Collateral Posted is Triggered
  (in millions)
AEP $259.6
 $0.4
 $235.8
APCo 0.1
 —
 —
I&M 0.1
 —
 —


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 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 and cash equivalent funds.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.

188






Fair Value Measurements of Long-term Debt (Applies to all Registrants)


The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs.  These instruments are not marked-to-market.  The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The fair value of AEP’s Equity Units (Level 1) are valued based on publicly traded securities issued by AEP.


The book values and fair values of Long-term Debt are summarized in the following table:
September 30, 2020December 31, 2019
CompanyBook ValueFair ValueBook ValueFair Value
(in millions)
AEP (a)$30,067.1 $35,603.2 $26,725.5 $30,172.0 
AEP Texas4,854.7 5,590.0 4,558.4 4,981.5 
AEPTCo3,947.9 4,859.5 3,427.3 3,868.0 
APCo4,833.3 6,167.6 4,363.8 5,253.1 
I&M2,981.9 3,637.4 3,050.2 3,453.8 
OPCo2,429.9 3,137.5 2,082.0 2,554.3 
PSO1,373.7 1,694.9 1,386.2 1,603.3 
SWEPCo2,637.3 3,119.2 2,655.6 2,927.9 
  September 30, 2017 December 31, 2016 
Company Book Value Fair Value Book Value  Fair Value 
  (in millions) 
AEP $20,721.7
 $22,988.8
 $20,391.2
(a) $22,211.9
(a)
AEPTCo 2,550.0
 2,720.8
 1,932.0
  1,984.3
 
APCo 3,979.3
 4,721.3
 4,033.9
  4,613.2
 
I&M 2,658.5
 2,898.7
 2,471.4
  2,661.6
 
OPCo 1,718.9
 2,068.9
 1,763.9
  2,092.5
 
PSO 1,286.4
 1,448.0
 1,286.0
  1,419.0
 
SWEPCo 2,441.5
 2,620.7
 2,679.1
  2,814.3
 


(a)The fair value amounts include debt related to AEP’s Equity Units and had a fair value of $1.6 billion and $871 million as of September 30, 2020 and December 31, 2019, respectively. See “Equity Units” section of Note 12 for additional information.
(a)Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million. See the Assets and Liabilities Held for Sale section of Note 6 for additional information.


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


Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including 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:
September 30, 2020
GrossGross
UnrealizedUnrealizedFair
Other Temporary InvestmentsCostGainsLossesValue
(in millions)
Restricted Cash and Other Cash Deposits (a)$79.6 $0 $0 $79.6 
Fixed Income Securities – Mutual Funds (b)127.9 2.9 0 130.8 
Equity Securities – Mutual Funds30.2 22.5 0 52.7 
Total Other Temporary Investments$237.7 $25.4 $0 $263.1 
 September 30, 2017December 31, 2019
   Gross Gross  GrossGross
   Unrealized Unrealized FairUnrealizedUnrealizedFair
Other Temporary Investments Cost Gains Losses ValueOther Temporary InvestmentsCostGainsLossesValue
 (in millions)(in millions)
Restricted Cash (a) $172.9
 $—
 $—
 $172.9
Restricted Cash and Other Cash Deposits (a)Restricted Cash and Other Cash Deposits (a)$214.7 $0 $0 $214.7 
Fixed Income Securities – Mutual Funds (b) 103.9
 —
 (0.7) 103.2
Fixed Income Securities – Mutual Funds (b)123.2 0.1 0 123.3 
Equity Securities – Mutual Funds
 16.8
 17.8
 —
 34.6
Equity Securities – Mutual Funds29.2 21.3 0 50.5 
Total Other Temporary Investments $293.6
 $17.8
 $(0.7) $310.7
Total Other Temporary Investments$367.1 $21.4 $0 $388.5 

(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.

189
  December 31, 2016
    Gross Gross  
    Unrealized Unrealized Fair
Other Temporary Investments Cost Gains Losses Value
  (in millions)
Restricted Cash (a) $211.7
 $—
 $—
 $211.7
Fixed Income Securities – Mutual Funds (b)
 92.7
 —
 (1.0) 91.7
Equity Securities – Mutual Funds
 14.4
 13.9
 —
 28.3
Total Other Temporary Investments $318.8
 $13.9
 $(1.0) $331.7


(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 September 30,Nine Months Ended September 30,
 2020201920202019
(in millions)
Proceeds from Investment Sales$5.1 $2.8 $35.9 $2.8 
Purchases of Investments22.5 26.9 39.5 35.8 
Gross Realized Gains on Investment Sales0.2 0 2.4 0 
Gross Realized Losses on Investment Sales0 0 0.2 0 
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (in millions)
Proceeds from Investment Sales$—
 $—
 $—
 $—
Purchases of Investments12.6
 0.6
 13.6
 1.6
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 and nine months ended September 30, 2017 and 2016, see Note 3.


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 external investment managers who 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 securities in the trust funds as available-for-sale due to their long-term purpose. Available-for-sale classification only applies to investment in debt securities in accordance with ASU 2016-01. Additionally, ASU 2016-01 requires changes in fair value of equity securities to be recognized in earnings. However, due to the regulatory treatment described below, this is not applicable for I&M’s trust fund securities.

Other-than-temporary impairments for investments in both debt and equity 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.


190





The following is a summary of nuclear trust fund investments:
 September 30, 2020December 31, 2019
GrossOther-Than-GrossOther-Than-
FairUnrealizedTemporaryFairUnrealizedTemporary
ValueGainsImpairmentsValueGainsImpairments
(in millions)
Cash and Cash Equivalents$33.7 $0 $0 $15.3 $0 $0 
Fixed Income Securities:
United States Government1,039.2 112.3 (5.8)1,112.5 55.5 (6.1)
Corporate Debt85.6 8.9 (1.5)72.4 5.3 (1.6)
State and Local Government123.9 1.5 (0.3)7.6 0.7 (0.2)
Subtotal Fixed Income Securities1,248.7 122.7 (7.6)1,192.5 61.5 (7.9)
Equity Securities - Domestic (a)1,793.5 1,165.8 0 1,767.9 1,144.4 0 
Spent Nuclear Fuel and Decommissioning Trusts$3,075.9 $1,288.5 $(7.6)$2,975.7 $1,205.9 $(7.9)
 September 30, 2017 December 31, 2016
   Gross Other-Than-   Gross Other-Than-
 Fair Unrealized Temporary Fair Unrealized Temporary
 Value Gains Impairments Value Gains Impairments
 (in millions)
Cash and Cash Equivalents$20.5
 $—
 $—
 $18.7
 $—
 $—
Fixed Income Securities: 
  
  
  
  
  
United States Government974.3
 32.6
 (1.9) 785.4
 27.1
 (5.5)
Corporate Debt60.0
 3.5
 (1.2) 60.9
 2.3
 (1.4)
State and Local Government9.0
 1.0
 (0.2) 121.1
 0.4
 (0.7)
Subtotal Fixed Income Securities1,043.3
 37.1
 (3.3) 967.4
 29.8
 (7.6)
Equity Securities - Domestic1,369.2
 783.1
 (75.4) 1,270.1
 677.9
 (79.6)
Spent Nuclear Fuel and Decommissioning Trusts$2,433.0
 $820.2
 $(78.7) $2,256.2
 $707.7
 $(87.2)


(a)Amount reported as Gross Unrealized Gains includes unrealized gains of $1.2 billion and $1.1 billion and unrealized losses of $17 million and $5 million as of September 30, 2020 and December 31, 2019, respectively.


The following table provides the securities activity within the decommissioning and SNF trusts:
Three Months Ended September 30,Nine Months Ended September 30,
 2020201920202019
 (in millions)
Proceeds from Investment Sales$316.6 $671.9 $1,257.1 $871.4 
Purchases of Investments318.6 689.1 1,290.0 915.7 
Gross Realized Gains on Investment Sales3.4 10.9 25.4 26.6 
Gross Realized Losses on Investment Sales0.5 7.1 25.2 15.1 
  Three Months Ended September 30, Nine Months Ended September 30,
  2017 2016 2017 2016
  (in millions)
Proceeds from Investment Sales $519.5
 $650.0
 $1,808.6
 $2,427.0
Purchases of Investments 525.0
 656.5
 1,842.2
 2,452.9
Gross Realized Gains on Investment Sales 9.8
 13.9
 198.1
 41.9
Gross Realized Losses on Investment Sales 5.2
 6.5
 145.4
 22.2


The base cost of fixed income securities was $1$1.1 billion and $938 million$1.1 billion as of September 30, 20172020 and December 31, 2016,2019, respectively.  The base cost of equity securities was $586$628 million and $592$623 million as of September 30, 20172020 and December 31, 2016,2019, respectively.


The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 20172020 was as follows:
Fair Value of Fixed
Income Securities
(in millions)
Within 1 year$291.6 
After 1 year through 5 years355.9 
After 5 years through 10 years255.1 
After 10 years346.1 
Total$1,248.7 
191
 Fair Value of Fixed Income Securities
 (in millions)
Within 1 year$403.6
After 1 year through 5 years287.9
After 5 years through 10 years184.2
After 10 years167.6
Total$1,043.3







Fair Value Measurements of Financial Assets and Liabilities


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


AEP


Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 20172020
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Other Temporary Investments
Restricted Cash and Other Cash Deposits (a)$66.3 $0 $0 $13.3 $79.6 
Fixed Income Securities – Mutual Funds130.8 0 0 0 130.8 
Equity Securities – Mutual Funds (b)52.7 0 0 0 52.7 
Total Other Temporary Investments249.8 0 0 13.3 263.1 
Risk Management Assets
Risk Management Commodity Contracts (c) (d)3.2 247.1 280.3 (185.3)345.3 
Cash Flow Hedges:
Commodity Hedges (c)0 36.1 4.3 (28.2)12.2 
Interest Rate Hedges0 0.6 0 0 0.6 
Total Risk Management Assets3.2 283.8 284.6 (213.5)358.1 
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)24.7 0 0 9.0 33.7 
Fixed Income Securities:
United States Government0 1,039.2 0 0 1,039.2 
Corporate Debt0 85.6 0 0 85.6 
State and Local Government0 123.9 0 0 123.9 
Subtotal Fixed Income Securities0 1,248.7 0 0 1,248.7 
Equity Securities – Domestic (b)1,793.5 0 0 0 1,793.5 
Total Spent Nuclear Fuel and Decommissioning Trusts1,818.2 1,248.7 0 9.0 3,075.9 
Total Assets$2,071.2 $1,532.5 $284.6 $(191.2)$3,697.1 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (d)$3.4 $239.1 $173.2 $(194.0)$221.7 
Cash Flow Hedges:
Commodity Hedges (c)0 90.7 5.3 (28.2)67.8 
Interest Rate Hedges0 5.3 0 0 5.3 
Total Risk Management Liabilities$3.4 $335.1 $178.5 $(222.2)$294.8 
192
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Cash and Cash Equivalents (a) $—
 $—
 $—
 $343.9
 $343.9
           
Other Temporary Investments          
Restricted Cash (a) 158.6
 1.4
 —
 12.9
 172.9
Fixed Income Securities – Mutual Funds
 103.2
 —
 —
 —
 103.2
Equity Securities – Mutual Funds (b)
 34.6
 —
 —
 —
 34.6
Total Other Temporary Investments
 296.4
 1.4
 —
 12.9
 310.7
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (d) 1.2
 307.9
 300.3
 (161.4) 448.0
Cash Flow Hedges:  
  
  
  
  
Commodity Hedges (c) —
 9.1
 1.3
 (6.1) 4.3
Interest Rate/Foreign Currency Hedges —
 4.2
 —
 —
 4.2
Total Risk Management Assets 1.2
 321.2
 301.6
 (167.5) 456.5
           
Spent Nuclear Fuel and Decommissioning Trusts  
  
  
  
  
Cash and Cash Equivalents (e) 14.0
 —
 —
 6.5
 20.5
Fixed Income Securities:  
  
  
  
  
United States Government —
 974.3
 —
 —
 974.3
Corporate Debt —
 60.0
 —
 —
 60.0
State and Local Government —
 9.0
 —
 —
 9.0
Subtotal Fixed Income Securities —
 1,043.3
 —
 —
 1,043.3
Equity Securities – Domestic (b)
 1,369.2
 —
 —
 —
 1,369.2
Total Spent Nuclear Fuel and Decommissioning Trusts
 1,383.2
 1,043.3
 —
 6.5
 2,433.0
           
Total Assets $1,680.8
 $1,365.9
 $301.6
 $195.8
 $3,544.1
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (d) $3.2
 $306.6
 $205.9
 $(174.9) $340.8
Cash Flow Hedges:  
  
  
  
  
Commodity Hedges (c) —
 35.3
 50.7
 (6.1) 79.9
Fair Value Hedges —
 1.4
 —
 —
 1.4
Total Risk Management Liabilities $3.2
 $343.3
 $256.6
 $(181.0) $422.1








AEP


Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 20162019
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Other Temporary Investments
Restricted Cash and Other Cash Deposits (a)$197.6 $0 $0 $17.1 $214.7 
Fixed Income Securities – Mutual Funds123.3 0 0 0 123.3 
Equity Securities – Mutual Funds (b)50.5 0 0 0 50.5 
Total Other Temporary Investments371.4 0 0 17.1 388.5 
Risk Management Assets
Risk Management Commodity Contracts (c) (f)4.0 440.1 369.2 (404.5)408.8 
Cash Flow Hedges:
Commodity Hedges (c)0 15.0 3.2 (6.7)11.5 
Interest Rate Hedges0 4.6 0 0 4.6 
Fair Value Hedges0 14.5 0 0 14.5 
Total Risk Management Assets4.0 474.2 372.4 (411.2)439.4 
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)6.7 0 0 8.6 15.3 
Fixed Income Securities:
United States Government0 1,112.5 0 0 1,112.5 
Corporate Debt0 72.4 0 0 72.4 
State and Local Government0 7.6 0 0 7.6��
Subtotal Fixed Income Securities0 1,192.5 0 0 1,192.5 
Equity Securities – Domestic (b)1,767.9 0 0 0 1,767.9 
Total Spent Nuclear Fuel and Decommissioning Trusts1,774.6 1,192.5 0 8.6 2,975.7 
Total Assets$2,150.0 $1,666.7 $372.4 $(385.5)$3,803.6 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (f)$3.8 $450.0 $224.0 $(438.8)$239.0 
Cash Flow Hedges:
Commodity Hedges (c)0 105.3 38.5 (6.7)137.1 
Total Risk Management Liabilities$3.8 $555.3 $262.5 $(445.5)$376.1 

193





  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Cash and Cash Equivalents (a) $8.7
 $—
 $—
 $201.8
 $210.5
           
Other Temporary Investments          
Restricted Cash (a) 173.8
 5.1
 —
 32.8
 211.7
Fixed Income Securities – Mutual Funds
 91.7
 —
 —
 —
 91.7
Equity Securities – Mutual Funds (b)
 28.3
 —
 —
 —
 28.3
Total Other Temporary Investments
 293.8
 5.1
 —
 32.8
 331.7
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (f) 6.0
 379.9
 192.2
 (205.7) 372.4
Cash Flow Hedges:  
  
  
  
  
Commodity Hedges (c) —
 16.8
 1.7
 (7.3) 11.2
Total Risk Management Assets 6.0
 396.7
 193.9
 (213.0) 383.6
           
Spent Nuclear Fuel and Decommissioning Trusts  
  
  
  
  
Cash and Cash Equivalents (e) 7.3
 —
 —
 11.4
 18.7
Fixed Income Securities:  
  
  
  
  
United States Government —
 785.4
 —
 —
 785.4
Corporate Debt —
 60.9
 —
 —
 60.9
State and Local Government —
 121.1
 —
 —
 121.1
Subtotal Fixed Income Securities —
 967.4
 —
 —
 967.4
Equity Securities – Domestic (b)
 1,270.1
 —
 —
 —
 1,270.1
Total Spent Nuclear Fuel and Decommissioning Trusts
 1,277.4
 967.4
 —
 11.4
 2,256.2
           
Total Assets $1,585.9
 $1,369.2
 $193.9
 $33.0
 $3,182.0
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (f) $8.2
 $352.0
 $166.7
 $(205.4) $321.5
Cash Flow Hedges:  
  
  
  
  
Commodity Hedges (c) —
 29.3
 24.7
 (7.3) 46.7
Fair Value Hedges —
 1.4
 —
 —
 1.4
Total Risk Management Liabilities $8.2
 $382.7
 $191.4
 $(212.7) $369.6



APCo

AEP Texas
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 20172020
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$44.8 $0 $0 $0 $44.8 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)$0 $0.2 $0 $(0.1)$0.1 
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Restricted Cash for Securitized Funding (a) $8.3
 $—
 $—
 $0.1
 $8.4
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) —
 22.2
 30.0
 (21.3) 30.9
           
Total Assets $8.3
 $22.2
 $30.0
 $(21.2) $39.3
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $21.8
 $0.6
 $(21.2) $1.2


December 31, 2019
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$154.7 $0 $0 $0 $154.7 

APCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2020
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$9.3 $0 $0 $0 $9.3 
Risk Management Assets
Risk Management Commodity Contracts (c) (g)0 20.4 30.1 (20.3)30.2 
Cash Flow Hedges:
Interest Rate Hedges0 0.6 0 0 0.6 
Total Risk Management Assets0 21.0 30.1 (20.3)30.8 
Total Assets$9.3 $21.0 $30.1 $(20.3)$40.1 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$0 $21.2 $0.5 $(21.2)$0.5 
Cash Flow Hedges:
Interest Rate Hedges0 5.3 0 0 5.3 
Total Risk Management Liabilities$0 $26.5 $0.5 $(21.2)$5.8 

December 31, 20162019
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Restricted Cash for Securitized Funding$23.5 $0 $0 $0 $23.5 
Risk Management Assets
Risk Management Commodity Contracts (c) (g)0 84.6 40.5 (85.6)39.5 
Total Assets$23.5 $84.6 $40.5 $(85.6)$63.0 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$0 $84.0 $2.8 $(84.9)$1.9 
194
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Restricted Cash for Securitized Funding (a) $15.8
 $—
 $—
 $0.1
 $15.9
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) —
 20.5
 3.9
 (21.8) 2.6
           
Total Assets $15.8
 $20.5
 $3.9
 $(21.7) $18.5
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $20.7
 $2.5
 $(22.0) $1.2







I&M

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 20172020
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)$0 $12.9 $4.1 $(12.9)$4.1 
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)24.7 0 0 9.0 33.7 
Fixed Income Securities:
United States Government0 1,039.2 0 0 1,039.2 
Corporate Debt0 85.6 0 0 85.6 
State and Local Government0 123.9 0 0 123.9 
Subtotal Fixed Income Securities0 1,248.7 0 0 1,248.7 
Equity Securities - Domestic (b)1,793.5 0 0 0 1,793.5 
Total Spent Nuclear Fuel and Decommissioning Trusts1,818.2 1,248.7 0 9.0 3,075.9 
Total Assets$1,818.2 $1,261.6 $4.1 $(3.9)$3,080.0 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$0 $13.4 $0.3 $(13.4)$0.3 

December 31, 2019
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)$0 $59.5 $8.0 $(57.6)$9.9 
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)6.7 0 0 8.6 15.3 
Fixed Income Securities:
United States Government0 1,112.5 0 0 1,112.5 
Corporate Debt0 72.4 0 0 72.4 
State and Local Government0 7.6 0 0 7.6 
Subtotal Fixed Income Securities0 1,192.5 0 0 1,192.5 
Equity Securities - Domestic (b)1,767.9 0 0 0 1,767.9 
Total Spent Nuclear Fuel and Decommissioning Trusts1,774.6 1,192.5 0 8.6 2,975.7 
Total Assets$1,774.6 $1,252.0 $8.0 $(49.0)$2,985.6 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$0 $53.4 $2.2 $(55.1)$0.5 
195





  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $16.3
 $12.4
 $(16.6) $12.1
           
Spent Nuclear Fuel and Decommissioning Trusts  
  
  
  
  
Cash and Cash Equivalents (e) 14.0
 —
 —
 6.5
 20.5
Fixed Income Securities:  
  
  
  
  
United States Government —
 974.3
 —
 —
 974.3
Corporate Debt —
 60.0
 —
 —
 60.0
State and Local Government —
 9.0
 —
 —
 9.0
Subtotal Fixed Income Securities —
 1,043.3
 —
 —
 1,043.3
Equity Securities - Domestic (b) 1,369.2
 —
 —
 —
 1,369.2
Total Spent Nuclear Fuel and Decommissioning Trusts
 1,383.2
 1,043.3
 —
 6.5
 2,433.0
           
Total Assets $1,383.2
 $1,059.6
 $12.4
 $(10.1) $2,445.1
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $16.4
 $2.2
 $(16.4) $2.2

I&M

OPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2020
Level 1Level 2Level 3OtherTotal
Liabilities:(in millions)
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$0 $0.2 $113.2 $(0.1)$113.3 

December 31, 20162019
Level 1Level 2Level 3OtherTotal
Liabilities:(in millions)
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$0 $0 $103.6 $0 $103.6 
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $12.8
 $3.0
 $(12.3) $3.5
           
Spent Nuclear Fuel and Decommissioning Trusts  
  
  
  
  
Cash and Cash Equivalents (e) 7.3
 —
 —
 11.4
 18.7
Fixed Income Securities:  
  
  
  
 

United States Government —
 785.4
 —
 —
 785.4
Corporate Debt —
 60.9
 —
 —
 60.9
State and Local Government —
 121.1
 —
 —
 121.1
Subtotal Fixed Income Securities —
 967.4
 —
 —
 967.4
Equity Securities - Domestic (b) 1,270.1
 —
 —
 —
 1,270.1
Total Spent Nuclear Fuel and Decommissioning Trusts
 1,277.4
 967.4
 —
 11.4
 2,256.2
           
Total Assets $1,277.4
 $980.2
 $3.0
 $(0.9) $2,259.7
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $13.3
 $0.2
 $(12.4) $1.1



OPCo

PSO
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 20172020
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)$0 $0 $16.6 $0 $16.6 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$0 $0.1 $0.5 $(0.1)$0.5 

December 31, 2019
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)$0 $0 $16.3 $(0.5)$15.8 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$0 $0 $0.5 $(0.5)$0 
196





  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Restricted Cash for Securitized Funding (a) $15.6
 $—
 $—
 $—
 $15.6
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) —
 0.3
 —
 (0.1) 0.2
           
Total Assets $15.6
 $0.3
 $—
 $(0.1) $15.8
           
Liabilities:          
           
Risk Management Liabilities          
Risk Management Commodity Contracts (c) (g) $—
 $—
 $138.5
 $—
 $138.5

OPCo

SWEPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2020
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)$0 $0 $4.4 $0.1 $4.5 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$0 $0.1 $0.7 $0 $0.8 

December 31, 20162019
Level 1Level 2Level 3OtherTotal
Assets:(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)$0 $0 $6.5 $(0.1)$6.4 
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)$0 $0 $5.1 $(0.1)$5.0 
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Restricted Cash for Securitized Funding (a) $—
 $—
 $—
 $27.2
 $27.2
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) —
 0.4
 —
 (0.2) 0.2
           
Total Assets $—
 $0.4
 $—
 $27.0
 $27.4
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $—
 $119.0
 $—
 $119.0




PSO

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2017
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $—
 $4.8
 $(0.1) $4.7
           
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, 2016
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $0.2
 $0.7
 $(0.1) $0.8



SWEPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2017
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Cash and Cash Equivalents (a) $—
 $—
 $—
 $2.2
 $2.2
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) —
 0.1
 13.3
 (0.2) 13.2
           
Total Assets $—
 $0.1
 $13.3
 $2.0
 $15.4
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $0.1
 $0.2
 $(0.2) $0.1

SWEPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2016
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Cash and Cash Equivalents (a) $8.7
 $—
 $—
 $1.6
 $10.3
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) —
 0.3
 0.8
 (0.2) 0.9
           
Total Assets $8.7
 $0.3
 $0.8
 $1.4
 $11.2
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $0.3
 $0.1
 $(0.1) $0.3

(a)Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties.  Level 1 and Level 2 amounts primarily represent investments in money market funds.
(b)Amounts represent publicly traded equity securities and equity-based mutual funds.
(c)Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’
(d)The September 30, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures $(2) million in periods 2018-2020;  Level 2 matures $(1) million in 2017 and $3 million in periods 2018-2020 and $(1) million in periods 2021-2022;  Level 3 matures $23 million in 2017, $77 million in periods 2018-2020, $16 million in periods 2021-2022 and $(21) million in periods 2023-2032.  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, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures $(2) million in periods 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032.  Risk management commodity contracts are substantially comprised of power contracts.
(g)Substantially comprised of power contracts for the Registrant Subsidiaries.

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 threeaccounting guidance for “Derivatives and nine months endedHedging.’’
(d)The September 30, 20172020 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(6) million in 2020, $3 million in periods 2021-2023, $4 million in periods 2024-2025 and 2016.$7 million in periods 2026-2033; Level 3 matures $35 million in 2020, $63 million in periods 2021-2023, $21 million in periods 2024-2025 and $(12) million in periods 2026-2033.  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, 2019 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(7) million in 2020 and $(3) million in periods 2021-2023; Level 3 matures $96 million in 2020, $36 million in periods 2021-2023, $25 million in periods 2024-2025 and $(12) million in periods 2026-2032.  Risk management commodity contracts are substantially comprised of power contracts.
(g)Substantially comprised of power contracts for the Registrant Subsidiaries.

197





The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:
Three Months Ended September 30, 2020AEPAPCoI&MOPCoPSOSWEPCo
 (in millions)
Balance as of June 30, 2020$111.6 $36.5 $4.5 $(117.4)$23.8 $3.3 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)18.7 6.4 3.3 0 3.0 1.5 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)6.5 0 0 0 0 0 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)2.6 0 0 0 0 0 
Settlements(37.0)(11.1)(5.0)1.3 (10.3)(3.5)
Transfers into Level 3 (d) (e)(1.0)0 0 0 0 0 
Transfers out of Level 3 (e)1.1 0 0 0 0 0 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)3.6 (2.2)1.0 2.9 (0.4)2.4 
Balance as of September 30, 2020$106.1 $29.6 $3.8 $(113.2)$16.1 $3.7 
Three Months Ended September 30, 2019AEPAPCoI&MOPCoPSOSWEPCo
 (in millions)
Balance as of June 30, 2019$112.7 $68.5 $12.3 $(111.5)$27.8 $8.5 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)30.2 13.8 3.1 0 4.1 3.6 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)2.9 0 0 0 0 0 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)22.1 0 0 0 0 0 
Settlements(67.4)(28.1)(7.2)1.1 (11.2)(6.7)
Transfers into Level 3 (d) (e)3.5 0 0 0 0 0 
Transfers out of Level 3 (e)6.6 0 0 0 0 0 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)(0.3)1.3 0.7 (2.1)0.9 (0.5)
Balance as of September 30, 2019$110.3 $55.5 $8.9 $(112.5)$21.6 $4.9 
Nine Months Ended September 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)39.6 13.1 2.4 (1.2)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)(2.4)0 0 0 0 0 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)21.7 0 0 0 0 0 
Settlements(115.3)(51.4)(8.5)6.4 (27.6)(6.9)
Transfers into Level 3 (d) (e)(1.1)0 0 0 0 0 
Transfers out of Level 3 (e)5.6 0.7 0.4 0 0 0 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)48.1 29.5 3.7 (14.8)16.0 6.4 
Balance as of September 30, 2020$106.1 $29.6 $3.8 $(113.2)$16.1 $3.7 
198





Three Months Ended September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo
  (in millions)
Balance as of June 30, 2017 $87.3
 $41.3
 $15.5
 $(130.5) $9.5
 $12.4
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 19.8
 6.2
 3.8
 (0.1) 4.0
 3.8
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 14.8
 —
 —
 —
 —
 —
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (24.3) —
 —
 —
 —
 —
Settlements (49.2) (16.2) (8.4) 1.2
 (6.9) (7.6)
Transfers into Level 3 (d) (e) 5.7
 —
 —
 —
 —
 —
Transfers out of Level 3 (e) 0.2
 —
 —
 —
 —
 —
Changes in Fair Value Allocated to Regulated Jurisdictions (f) (9.3) (1.9) (0.7) (9.1) (1.9) 4.5
Balance as of September 30, 2017 $45.0
 $29.4
 $10.2
 $(138.5) $4.7
 $13.1
Nine Months Ended September 30, 2019AEPAPCoI&MOPCoPSOSWEPCo
 (in millions)
Balance as of December 31, 2018$131.2 $57.8 $8.9 $(99.4)$9.5 $2.3 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)14.6 (14.1)4.6 (0.9)13.5 6.0 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)32.9 0 0 0 0 0 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)(42.8)0 0 0 0 0 
Settlements(114.6)(41.9)(12.6)4.6 (23.0)(10.1)
Transfers into Level 3 (d) (e)0.4 0 0 0 0 0 
Transfers out of Level 3 (e)1.4 (0.7)(0.4)0 0 0 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)87.2 54.4 8.4 (16.8)21.6 6.7 
Balance as of September 30, 2019$110.3 $55.5 $8.9 $(112.5)$21.6 $4.9 

(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.

199
Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo
  (in millions)
Balance as of June 30, 2016 $149.3
 $(12.9) $3.5
 $(14.6) $1.1
 $1.4
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2
 22.7
 3.8
 (0.1) 0.4
 4.0
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3
 —
 —
 —
 —
 —
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4) —
 —
 —
 —
 —
Settlements (37.1) (17.9) (5.0) 0.9
 (0.7) (4.4)
Transfers into Level 3 (d) (e) 13.1
 0.1
 —
 —
 —
 —
Transfers out of Level 3 (e) (10.0) —
 —
 —
 —
 —
Changes in Fair Value Allocated to Regulated Jurisdictions (f) (29.0) 0.9
 2.2
 (95.3) 0.3
 0.3
Balance as of September 30, 2016 $98.4
 $(7.1) $4.5
 $(109.1) $1.1
 $1.3


Nine Months Ended September 30, 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) (b) (c) 37.4
 17.2
 4.0
 (1.0) 3.1
 6.0
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.2
 —
 —
 —
 —
 —
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (29.5) —
 —
 —
 —
 —
Settlements (49.7) (18.9) (7.1) 5.1
 (3.8) (6.8)
Transfers into Level 3 (d) (e) 16.1
 —
 —
 —
 —
 —
Transfers out of Level 3 (e) (9.1) —
 —
 —
 —
 —
Changes in Fair Value Allocated to Regulated Jurisdictions (f) 40.1
 29.7
 10.5
 (23.6) 4.7
 13.2
Balance as of September 30, 2017 $45.0
 $29.4
 $10.2
 $(138.5) $4.7
 $13.1





Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo
  (in millions)
Balance as of December 31, 2015 $146.9
 $11.7
 $4.3
 $15.9
 $0.6
 $0.8
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1
 25.5
 7.0
 (1.8) (1.0) 7.7
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5
 —
 —
 —
 —
 —
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7) —
 —
 —
 —
 —
Settlements (67.1) (36.2) (10.3) 4.0
 0.4
 (8.4)
Transfers into Level 3 (d) (e) 11.2
 —
 —
 —
 —
 —
Transfers out of Level 3 (e) 1.1
 0.1
 0.1
 —
 —
 —
Changes in Fair Value Allocated to Regulated Jurisdictions (f) (64.6) (8.2) 3.4
 (127.2) 1.1
 1.2
Balance as of September 30, 2016 $98.4
 $(7.1) $4.5
 $(109.1) $1.1
 $1.3

(a)Includes both affiliated and nonaffiliated transactions.
(b)Included in revenues on the statements of income.
(c)Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(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 liabilities/assets or accounts payable.



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


AEP
Significant Unobservable Inputs
September 30, 20172020
AEP
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInputLowHighAverage (c)
(in millions)
Energy Contracts$219.2 $173.0 Discounted Cash FlowForward Market Price (a)$3.36 $111.42 $32.62 
Natural Gas Contracts0 0.6 Discounted Cash FlowForward Market Price (b)1.79 3.06 2.61 
FTRs65.4 4.9 Discounted Cash FlowForward Market Price (a)(6.15)10.66 0.23 
Total$284.6 $178.5 

December 31, 2019
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInputLowHighAverage (c)
(in millions)
Energy Contracts$296.7 $249.3 Discounted Cash FlowForward Market Price (a)$(0.05)$177.30 $31.31 
Natural Gas Contracts0 4.9 Discounted Cash FlowForward Market Price (b)1.89 2.51 2.19 
FTRs75.7 8.3 Discounted Cash FlowForward Market Price (a)(8.52)9.34 0.42 
Total$372.4 $262.5 
200





     Significant Input/Range
 Fair ValueValuation Unobservable     Weighted
 Assets Liabilities Technique Input Low High Average
 (in millions)          
Energy Contracts$233.8
 $252.6
 Discounted Cash Flow  Forward Market Price (a)  $(0.05) $92.77
 $35.82
       Counterparty Credit Risk (b)  10
 539
 204
Natural Gas Contracts0.9
 —
 Discounted Cash Flow  Forward Market Price (c)  2.47
 3.03
 2.68
FTRs66.9
 4.0
 Discounted Cash Flow  Forward Market Price (a)  (9.80) 9.37
 0.32
Total$301.6
 $256.6
      
  
  

APCo
Significant Unobservable Inputs
September 30, 2020
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (c)
(in millions)
Energy Contracts$0.8 $0.5 Discounted Cash FlowForward Market Price$9.56 $41.80 $27.25 
FTRs29.3 0 Discounted Cash FlowForward Market Price(0.81)6.57 1.09 
Total$30.1 $0.5 

December 31, 20162019
AEP
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (c)
(in millions)
Energy Contracts$5.7 $2.6 Discounted Cash FlowForward Market Price$12.70 $41.20 $25.92 
FTRs34.8 0.2 Discounted Cash FlowForward Market Price(0.14)7.08 1.70 
Total$40.5 $2.8 

     Significant Input/Range
 Fair ValueValuation Unobservable     Weighted
 Assets Liabilities Technique Input Low High Average
 (in millions)          
Energy Contracts$183.8
 $187.1
 Discounted Cash Flow  Forward Market Price (a)  $6.51
 $86.59
 $39.40
       Counterparty Credit Risk (b)  35
 824
 391
FTRs10.1
 4.3
 Discounted Cash Flow  Forward Market Price (a)  (7.99) 8.91
 0.86
Total$193.9
 $191.4
      
  
  



I&M
Significant Unobservable Inputs
September 30, 20172020
APCo
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (c)
(in millions)
Energy Contracts$0.5 $0.3 Discounted Cash FlowForward Market Price$9.56 $41.80 $27.25 
FTRs3.6 0 Discounted Cash FlowForward Market Price(2.68)4.24 0.41 
Total$4.1 $0.3 

December 31, 2019
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (c)
(in millions)
Energy Contracts$3.4 $1.5 Discounted Cash FlowForward Market Price$12.70 $41.20 $25.92 
FTRs4.6 0.7 Discounted Cash FlowForward Market Price(0.75)4.07 0.74 
Total$8.0 $2.2 
201





     Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
Energy Contracts$1.0
 $0.4
 Discounted Cash Flow  Forward Market Price  $14.85
 $45.72
 $33.99
FTRs29.0
 0.2
 Discounted Cash Flow  Forward Market Price  0.08
 6.36
 1.20
Total$30.0
 $0.6
      
  
  

OPCo
Significant Unobservable Inputs
September 30, 2020
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (c)
(in millions)
Energy Contracts$0 $113.2 Discounted Cash FlowForward Market Price$11.68 $47.28 $28.31 

December 31, 20162019
APCo
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (c)
(in millions)
Energy Contracts$0 $103.6 Discounted Cash FlowForward Market Price$29.23 $61.43 $42.46 

     Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
Energy Contracts$0.4
 $0.4
 Discounted Cash Flow  Forward Market Price  $19.68
 $48.55
 $36.34
FTRs3.5
 2.1
 Discounted Cash Flow  Forward Market Price  (0.23) 8.91
 2.37
Total$3.9
 $2.5
      
  
  

PSO
Significant Unobservable Inputs
September 30, 20172020
I&M
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (c)
(in millions)
FTRs$16.6 $0.5 Discounted Cash FlowForward Market Price$(5.98)$0.70 $(1.85)

December 31, 2019
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInput (a)LowHighAverage (c)
(in millions)
FTRs$16.3 $0.5 Discounted Cash FlowForward Market Price$(8.52)$0.85 $(2.31)
202





       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
Energy Contracts$0.6
 $0.3
 Discounted Cash Flow  Forward Market Price  $14.85
 $45.72
 $33.99
FTRs11.8
 1.9
 Discounted Cash Flow  Forward Market Price  (0.02) 6.36
 0.71
Total$12.4
 $2.2
      
  
  

SWEPCo
Significant Unobservable Inputs
September 30, 2020
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInputLowHighAverage (c)
(in millions)
Natural Gas Contracts$0 $0.6 Discounted Cash FlowForward Market Price (b)$1.79 $3.02 $2.54 
FTRs4.4 0.1 Discounted Cash FlowForward Market Price (a)(5.98)0.70 (1.85)
Total$4.4 $0.7 

December 31, 20162019
I&M
SignificantInput/Range
Fair ValueValuationUnobservableWeighted
AssetsLiabilitiesTechniqueInputLowHighAverage (c)
(in millions)
Natural Gas Contracts$0 $4.9 Discounted Cash FlowForward Market Price (b)$1.89 $2.51 $2.18 
FTRs6.5 0.2 Discounted Cash FlowForward Market Price (a)(8.52)0.85 (2.31)
Total$6.5 $5.1 

       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
Energy Contracts$0.3
 $0.2
 Discounted Cash Flow  Forward Market Price  $19.68
 $48.55
 $36.34
FTRs2.7
 —
 Discounted Cash Flow  Forward Market Price  (7.90) 8.91
 1.32
Total$3.0
 $0.2
      
  
  
(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.

Significant Unobservable Inputs
September 30, 2017
OPCo
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input Low High Average
 (in millions)          
Energy Contracts$—
 $138.5
 Discounted Cash Flow  Forward Market Price (a) $22.89
 $61.48
 $41.21
       Counterparty Credit Risk (b) 10
 210
 150
Total$—
 $138.5
          

Significant Unobservable Inputs
December 31, 2016
OPCo
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input Low High Average
 (in millions)          
Energy Contracts$—
 $119.0
 Discounted Cash Flow  Forward Market Price (a) $30.14
 $71.85
 $47.45
 

 

   Counterparty Credit Risk (b) 47
 340
 272
Total$—
 $119.0
          

Significant Unobservable Inputs
September 30, 2017
PSO
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
FTRs$4.8
 $0.1
 Discounted Cash Flow  Forward Market Price  $(9.80) $1.03
 $(0.69)

Significant Unobservable Inputs
December 31, 2016
PSO
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
FTRs$0.7
 $—
 Discounted Cash Flow  Forward Market Price  $(7.99) $1.03
 $(0.36)


Significant Unobservable Inputs
September 30, 2017
SWEPCo
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input Low High Average
 (in millions)          
Natural Gas Contracts$0.9
 $—
 Discounted Cash Flow  Forward Market Price (c) $2.47
 $3.03
 $2.68
FTRs12.4
 0.2
 Discounted Cash Flow  Forward Market Price (a) (9.80) 1.03
 (0.69)
 $13.3
 $0.2
          

Significant Unobservable Inputs
December 31, 2016
SWEPCo
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
FTRs$0.8
 $0.1
 Discounted Cash Flow  Forward Market Price  $(7.99) $1.03
 $(0.36)

(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 and FTRs for the Registrants as of September 30, 20172020 and December 31, 2016:2019:


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 RiskLossIncrease (Decrease)Higher (Lower)
Counterparty Credit RiskGainIncrease (Decrease)Lower (Higher)

203






11.  INCOME TAXES


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


Federal Legislation

In March 2020, the CARES Act was signed into law.  The CARES Act includes tax relief provisions such as: (a) an Alternative Minimum Tax (AMT) Credit Refund, (b) a 5-year net operating losses (NOL) carryback from years 2018-2020 and (c) delayed payment of employer payroll taxes. In May 2020, the House passed the "Health and Economic Recovery Omnibus Emergency Solutions Act" (HEROES Act) pending decision by the Senate. If enacted, the HEROES Act would disallow NOL carrybacks to any tax year beginning before January 1, 2018.  Pursuant to the CARES Act, AEP, APCo and OPCo requested and in July received a $20 million, $7 million and $9 million, respectively, refund of AMT credit. In the third quarter of 2020, AEP also requested a $95 million refund of taxes paid in 2014 under the 5-year NOL carryback provision of the CARES Act. AEP carried back an 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 $52 million, recorded discretely, primarily at the Generation & Marketing segment. On October 1, 2020, after AEP filed its request with the IRS, the House passed a revised version of the HEROES Act; which similar to the original legislation would disallow NOL carryback to years prior to 2018. Management will continue to monitor the potential impact of this legislation. The Registrants are currently deferring payments of the employer share of payroll taxes for the period March 27, 2020 through December 31, 2020 and will pay 50% of the obligation by December 31, 2021 and the remaining 50% by December 31, 2022.

Effective Tax Rates (ETR)


The Registrants’ interim ETR for AEP’s operating companies reflect the estimated annual ETR for 20172020 and 2016,2019, adjusted for tax expense associated with certain discrete items.

The Registrants include the amortization of Excess ADIT not subject to normalization requirements in the annual estimated ETR when regulatory proceedings instruct the Registrants to provide the benefits of Tax Reform to customers over multiple interim periods.  Certain regulatory proceedings instruct the Registrants to provide the benefits of Tax Reform to customers in a single period (e.g. by applying the Excess ADIT not subject to normalization requirements against an existing regulatory asset balance) and in these circumstances, the Registrants recognize the tax benefit discretely in the period recorded. The annual amount of Excess ADIT approved by the Registrant’s regulatory commissions may not impact the ETR differs from the federal statutory tax rate of 35% primarilyratably during each interim period due to tax adjustments, statethe variability of pretax book income taxesbetween interim periods and other book/tax differences which are accounted for on a flow-through basis.the application of an annual estimated ETR.


The ETR from continuing operations for each of the Registrants are included in the following table. Significant variances in the ETR are described below.tables:
Three Months Ended September 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 %2.0 %2.9 %3.1 %3.4 %0.8 %4.6 %2.4 %
Tax Reform Excess ADIT Reversal(11.0)%(14.6)%0.4 %(22.0)%(16.7)%(6.7)%(20.3)%(7.3)%
Production and Investment Tax Credits(4.6)%(0.5)%0 %0 %(1.6)%0 %(1.1)%(0.5)%
Flow Through0.5 %0.2 %0.5 %1.6 %0.2 %0.9 %0.2 %(1.2)%
AFUDC Equity(1.5)%(3.5)%(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)%(2.0)%
Discrete Tax Adjustments(7.4)%(3.6)%(0.2)%(6.6)%2.3 %8.4 %(0.6)%(0.6)%
Other0.1 %0.3 %0.1 %0 %0 %0.3 %0.1 %(0.6)%
Effective Income Tax Rate(0.2)%1.3 %21.2 %(7.1)%4.0 %23.5 %1.6 %10.9 %
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  Three Months Ended September 30, Nine Months Ended September 30,
Company 2017 2016 2017 2016
AEP 33.0% 40.4% 35.3% (195.6)%
AEPTCo 33.5% 33.5% 33.8% 32.6 %
APCo 33.4% 36.1% 35.5% 36.2 %
I&M 30.6% 31.8% 30.1% 29.5 %
OPCo 36.9% 31.7% 35.6% 33.4 %
PSO 37.2% 37.7% 37.4% 36.8 %
SWEPCo 21.2% 28.9% 25.7% 26.7 %
Three Months Ended September 30, 2019
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 %1.4 %3.1 %3.0 %(0.1)%0.4 %4.8 %2.4 %
Tax Reform Excess ADIT Reversal(11.9)%(6.1)%1.4 %(26.6)%(17.3)%(6.9)%(16.5)%(19.5)%
Production and Investment Tax Credits(3.7)%(0.2)%0 %0 %(2.0)%0 %(1.4)%(0.9)%
Flow Through0.4 %0 %0.1 %3.8 %(0.7)%1.0 %0.7 %(0.5)%
AFUDC Equity(1.5)%(1.1)%(2.6)%(1.3)%(1.7)%(1.7)%(0.3)%(0.9)%
Parent Company Loss Benefit0 %(0.1)%(1.3)%(1.1)%(1.0)%0.4 %(1.8)%(1.8)%
Discrete Tax Adjustments(1.7)%0 %(0.1)%(2.4)%(1.3)%1.7 %0 %0 %
Other0 %0.2 %0.3 %(0.3)%0.4 %(2.0)%(0.1)%(0.4)%
Effective Income Tax Rate5.2 %15.1 %21.9 %(3.9)%(2.7)%13.9 %6.4 %(0.6)%
Nine Months Ended September 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 %1.8 %2.9 %3.1 %3.4 %0.7 %4.6 %2.3 %
Tax Reform Excess ADIT Reversal(12.1)%(23.4)%0.4 %(20.8)%(16.7)%(8.8)%(20.3)%(11.5)%
Production and Investment Tax Credits(4.5)%(0.5)%0 %0 %(1.6)%0 %(1.1)%(0.5)%
Flow Through0.5 %0.1 %0.5 %1.6 %0.2 %0.9 %0.2 %(1.2)%
AFUDC Equity(1.5)%(3.2)%(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)%(1.9)%
Discrete Tax Adjustments(3.0)%(1.6)%(0.1)%(2.3)%1.8 %2.6 %(0.4)%(0.3)%
Other0.2 %0.4 %(0.1)%(0.1)%(0.1)%0.2 %0.1 %(0.4)%
Effective Income Tax Rate3.2 %(5.4)%21.1 %(1.7)%3.4 %15.4 %1.8 %7.2 %

Nine Months Ended September 30, 2019
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 Benefit2.1 %1.5 %3.0 %3.3 %1.2 %0.7 %4.7 %1.8 %
Tax Reform Excess ADIT Reversal(16.7)%(43.9)%0.7 %(40.2)%(17.3)%(7.4)%(18.2)%(18.7)%
Production and Investment Tax Credits(3.6)%(0.5)%0 %0 %(2.0)%0 %(1.5)%(0.8)%
Flow Through0.1 %0.1 %0.2 %0.7 %(1.8)%0.7 %0.6 %(0.6)%
AFUDC Equity(1.5)%(1.3)%(2.5)%(1.1)%(1.9)%(1.0)%(0.3)%(0.9)%
Parent Company Loss Benefit0 %(1.0)%(1.1)%(1.9)%(1.5)%(0.7)%(1.8)%(1.5)%
Discrete Tax Adjustments0 %(1.3)%(0.6)%(0.8)%0.2 %0.5 %0 %(0.2)%
Other0.3 %0.1 %0 %(0.1)%0 %0.4 %0.1 %(0.1)%
Effective Income Tax Rate1.7 %(25.3)%20.7 %(19.1)%(2.1)%14.2 %4.6 %0 %
AEP

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016

The decrease in the ETR is due to the prior year reversal of a $66 million capital loss valuation allowance related to the pending sale of certain merchant generation assets and prior year tax return adjustments related to the disposition of AEP’s commercial barging operations.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016

The increase in the ETR is primarily due to the increase in pretax book income driven by the impairment of certain merchant generation assets in the third quarter of 2016. The increase in the ETR is also due to the prior year reversal of a $56 million unrealized capital loss valuation allowance where AEP effectively settled a 2011 audit issue with the IRS, the prior year reversal of a $66 million capital loss valuation allowance related to the pending sale of certain merchant generation assets and prior year tax return adjustments related to the disposition of AEP’s commercial barging operations.

APCo

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016

The decrease in the ETR is primarily due to the recording of favorable federal income tax adjustments and a decrease in pretax book income.



OPCo

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016

The increase in the ETR is primarily due to changes in other book/tax differences which are accounted for on a flow-through basis and the recording of federal income tax adjustments.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016

The increase in the ETR is primarily due to changes in other book/tax differences which are accounted for on a flow-through basis, the recording of federal income tax adjustments and an increase in pretax book income.

SWEPCo

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016

The decrease in the ETR is primarily due to a $10 million decrease in Income Tax Expense related to income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine.

Federal and State Income Tax Audit Status


AEP and subsidiaries are no longer subject to U.S. federal examination by the IRS for all years before 2011. The IRS examinationthrough 2015. During the third quarter of years 2011, 2012 and 2013 started in April 2014.2019, AEP and subsidiaries received a Revenue Agents Report in April 2016, completingelected to amend the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to2014 and 2015 federal returns. In the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back tofirst quarter of 2020, the IRS exam team for further consideration. 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 yearsnotified AEP that upon final resolution are expected to materially impact net income.

AEP and subsidiaries file income tax returns in various state, local or foreign jurisdictions.  These taxing authorities routinely examine the tax returns. AEP and subsidiaries are currently underit was beginning an 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 impactamended returns, including the net income.  The Registrants are no longer subjectoperating loss carryback to state, local or non-U.S. income tax examinations by tax authorities for years before 2009.

State Tax Legislation (Applies to AEP, APCo, I&M and OPCo)

Legislation was enacted2015 that originated in the state of Illinois in July 2017 increasingreturn. The IRS may examine only the corporate income tax rate from 5.25% to 7% effective July 1, 2017, withamended items on the increased rate applied to the portion of the tax year falling on or after that date. With the inclusion of the 2.5% Illinois Replacement Tax, the total Illinois corporate income tax rate increased from 7.75% to 9.5%, effective July 1, 2017. The legislation is not expected to materially impact net income, cash flows or financial condition.

2014 and 2015 federal returns.

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12.  FINANCING ACTIVITIES


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


Reverse Stock Split (Applies to SWEPCo)

In August 2020, SWEPCo executed a reverse stock split with each 2,048 shares of common stock issued and outstanding being combined into 1 share of common stock. The common stock of SWEPCo is wholly-owned by Parent.

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 DebtSeptember 30, 2020December 31, 2019
 (in millions)
Senior Unsecured Notes$24,125.4 $21,180.7 
Pollution Control Bonds1,936.1 1,998.8 
Notes Payable161.3 234.3 
Securitization Bonds751.6 1,025.1 
Spent Nuclear Fuel Obligation (a)281.1 279.8 
Junior Subordinated Notes (b)1,622.1 787.8 
Other Long-term Debt1,189.5 1,219.0 
Total Long-term Debt Outstanding30,067.1 26,725.5 
Long-term Debt Due Within One Year1,911.6 1,598.7 
Long-term Debt$28,155.5 $25,126.8 
Type of Debt September 30, 2017 December 31, 2016 
  (in millions) 
Senior Unsecured Notes $16,038.6
 $14,761.0
(b)
Pollution Control Bonds 1,612.4
 1,725.1
 
Notes Payable 224.5
 326.9
 
Securitization Bonds 1,449.4
 1,705.0
 
Spent Nuclear Fuel Obligation (a) 267.9
 266.3
 
Other Long-term Debt 1,128.9
 1,606.9
 
Total Long-term Debt Outstanding 20,721.7
 20,391.2
(b)
Long-term Debt Due Within One Year 2,359.3
 3,013.4
(b)
Long-term Debt $18,362.4
 $17,377.8
(b)


(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 $311 million and $311 million as of September 30, 2017 and December 31, 2016, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.
(b)Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information.

(a)Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for SNF disposal.  The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983.  Trust fund assets related to this obligation were $326 million and $323 million as of September 30, 2020 and December 31, 2019, 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 nine months of 20172020 are shown in the tables below:following tables:
PrincipalInterest
CompanyType of DebtAmount (a)RateDue Date
Issuances: (in millions)(%)
AEPJunior Subordinated Notes (b)$850.0 1.302025
AEPSenior Unsecured Notes400.0 2.302030
AEPSenior Unsecured Notes400.0 3.252050
AEP TexasPollution Control Bonds60.0 0.902023
AEP TexasSenior Unsecured Notes600.0 2.102030
AEPTCoSenior Unsecured Notes525.0 3.652050
APCoPollution Control Bonds65.4 1.002025
APCoSenior Unsecured Notes500.0 3.702050
OPCoSenior Unsecured Notes350.0 2.602030
Non-Registrant:
KPCoOther Long-term Debt125.0 Variable2022
Transource EnergyOther Long-term Debt4.4 Variable2020
Transource EnergyOther Long-term Debt7.1 Variable2023
Transource EnergySenior Unsecured Notes150.0 2.752050
Total Issuances$4,036.9 

(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.
(b)See “Equity Units” section below for additional information.
206





Company Type of Debt Principal Amount (a) Interest Rate Due Date
Issuances:   (in millions) (%)  
AEPTCo Senior Unsecured Notes $125.0
 3.10 2026
AEPTCo Senior Unsecured Notes 500.0
 3.75 2047
APCo Senior Unsecured Notes 325.0
 3.30 2027
I&M Pollution Control Bonds 25.0
 Variable 2019
I&M Pollution Control Bonds 40.0
 2.05 2021
I&M Pollution Control Bonds 52.0
 Variable 2021
I&M Senior Unsecured Notes 300.0
 3.75 2047
SWEPCo Other Long-term Debt 115.0
 Variable 2020
    

 
 
Non-Registrant:   

 
 
AEP Texas Pollution Control Bonds 60.0
 1.75 2020
AEP Texas Senior Unsecured Notes 400.0
 2.40 2022
AEP Texas Senior Unsecured Notes 300.0
 3.80 2047
KPCo Pollution Control Bonds 65.0
 2.00 2020
KPCo Senior Unsecured Notes 65.0
 3.13 2024
KPCo Senior Unsecured Notes 40.0
 3.35 2027
KPCo Senior Unsecured Notes 165.0
 3.45 2029
KPCo Senior Unsecured Notes 55.0
 4.12 2047
Transource Missouri Other Long-term Debt 7.0
 Variable 2018
Transource Energy Other Long-term Debt 132.1
 Variable 2020
Total Issuances   $2,771.1
 
 


(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 TexasPollution Control Bonds$50.6 4.452020
AEP TexasSecuritization Bonds28.7 1.982020
AEP TexasSecuritization Bonds202.6 5.312020
AEP TexasPollution Control Bonds60.0 1.752020
AEP TexasSecuritization Bonds0.2 2.852024
AEP TexasSecuritization Bonds14.4 2.062025
APCoPollution Control Bonds65.4 1.702020
APCoSecuritization Bonds24.9 2.012023
I&MNotes Payable2.0 Variable2020
I&MNotes Payable4.6 Variable2021
I&MNotes Payable14.9 Variable2022
I&MNotes Payable11.4 Variable2022
I&MNotes Payable18.7 Variable2023
I&MNotes Payable18.2 Variable2024
I&MOther Long-term Debt1.3 6.002025
OPCoOther Long-term Debt0.1 1.152028
PSOPollution Control Bonds12.7 4.452020
PSOOther Long-term Debt0.3 3.002027
SWEPCoOther Long-term Debt15.0 Variable2020
SWEPCoOther Long-term Debt1.5 4.682028
SWEPCoNotes Payable3.2 4.582032
Non-Registrant:
Transource EnergyOther Long-term Debt148.6 Variable2023
Transource EnergySenior Unsecured Notes1.2 2.752050
Total Retirements and Principal Payments$700.5 


Long-term Debt Subsequent Events
Company Type of Debt  Principal Amount Paid Interest Rate Due Date
Retirements and Principal Payments:   (in millions) (%)  
APCo Senior Unsecured Notes $250.0
 5.00 2017
APCo Securitization Bonds 23.5
 2.008 2024
APCo Pollution Control Bonds 104.4
 Variable 2017
I&M��Notes Payable 4.9
 Variable 2017
I&M Pollution Control Bonds 25.0
 Variable 2017
I&M Notes Payable 22.3
 Variable 2019
I&M Notes Payable 23.6
 Variable 2019
I&M Notes Payable 23.9
 Variable 2020
I&M Pollution Control Bonds 52.0
 Variable 2017
I&M Notes Payable 24.3
 Variable 2021
I&M Other Long-term Debt 1.1
 6.00 2025
I&M Pollution Control Bonds 50.0
 Variable 2025
OPCo Securitization Bonds 16.2
 0.958 2017
OPCo Securitization Bonds 22.5
 0.958 2018
OPCo Securitization Bonds 7.6
 2.049 2019
OPCo Other Long-term Debt 0.1
 1.149 2028
PSO Other Long-term Debt 0.3
 3.00 2027
SWEPCo Senior Unsecured Notes 250.0
 5.55 2017
SWEPCo Other Long-term Debt 100.0
 Variable 2017
SWEPCo Other Long-term Debt 0.2
 3.50 2023
SWEPCo Other Long-term Debt 0.1
 4.28 2023
SWEPCo Notes Payable 3.3
 4.58 2032
         
Non-Registrant:        
AEGCo Senior Unsecured Notes 152.7
 6.33 2037
AGR Other Long-term Debt 500.0
 Variable 2017
KPCo Pollution Control Bonds 65.0
 Variable 2017
KPCo Senior Unsecured Notes 325.0
 6.00 2017
TCC Securitization Bonds 27.2
 0.88 2017
TCC Securitization Bonds 161.2
 5.17 2018
TCC Pollution Control Bonds 60.0
 5.20 2030
Transource Missouri Other Long-term Debt 130.8
 Variable 2018
Total Retirements and Principal Payments   $2,427.2
    


In October 2017,2020, I&M retired $1issued $70 million of Notes Payable related to DCC Fuel.


In October 2017, AEP Texas2020, I&M retired $41$5 million of 5.625% Pollution Control BondsNotes 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 2017.2025 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%.


As
207





Each forward equity purchase contract obligates the holder to purchase, and AEP to sell, for $50 a number of September 30, 2017, trustees held, on behalfshares in common stock in accordance with the conversion ratios set forth below (subject to an anti-dilution adjustment):

•If the AEP common stock market price is equal to or greater than $99.95: 0.5003 shares per contract.
•If the AEP common stock market price is less than $99.95 but greater than $83.29: a number of shares per contract equal to $50 divided by the applicable market price. The holder receives a variable number of shares at $50.
•If the AEP $728common 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 reacquired Pollution Control Bonds. Of this total, $104notes 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.


208





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 $50of 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 $345 million relatedOther Noncurrent Liabilitieswith a current portion in Other Current Liabilities at the time of issuance, representing the obligation to APCo, I&Mmake forward equity contract payments, with an offsetting reduction to Paid-in Capital. The difference between the face value and OPCo, respectively.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 also limit the amount of contractually-defined priority debt (which includes a further sub-limit of $50 million of secured debt) to 10% of consolidated tangible net assets. AEPTCo’s contractually-defined priority debt was 0.9% of consolidated tangible net assets as of September 30, 2020. 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 a covenantcovenants that limitslimit their debt to capitalization ratio to 67.5%. As of September 30, 2017, no subsidiaries have exceeded their debt to capitalization limit. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the AEP subsidiary distributing the dividend. The method for calculating outstanding debt and capitalization is contractually definedcontractually-defined in the credit agreements.


As of September 30, 2017, theThe 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%.  As of September 30, 2017, AEP has not exceeded its debt to capitalization limit.  The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend.  The method for calculating outstanding debt and capitalization is contractually definedcontractually-defined in the credit agreements.

209






Corporate Borrowing Program - AEP System (Applies to 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, andsubsidiaries; 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 September 30, 20172020 and December 31, 20162019 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 their corresponding authorized borrowing limits for the nine months ended September 30, 20172020 are described in the following table:
MaximumAverageNet Loans to
BorrowingsMaximumBorrowingsAverage(Borrowings) fromAuthorized
from theLoans to thefrom theLoans to thethe Utility MoneyShort-term
UtilityUtilityUtilityUtilityPool as ofBorrowing
CompanyMoney PoolMoney PoolMoney PoolMoney PoolSeptember 30, 2020Limit
 (in millions)
AEP Texas$320.4 $313.4 $154.7 $167.4 $141.3 $500.0 
AEPTCo358.4 259.7 112.7 59.1 (84.3)820.0 (a)
APCo434.3��189.0 274.8 74.6 155.2 500.0 
I&M218.6 13.4 115.3 13.3 (145.8)500.0 
OPCo353.9 32.8 158.3 25.2 (215.9)500.0 
PSO125.4 57.1 64.6 28.4 (77.8)300.0 
SWEPCo178.9 0 113.6 0 (71.8)350.0 
  Maximum   Average   Net Loans to   
  Borrowings Maximum Borrowings Average (Borrowings from) Authorized 
  from the Loans to the from the Loans to the the Utility Money Short-term 
  Utility Utility Utility Utility Pool as of Borrowing 
Company Money Pool Money Pool Money Pool Money Pool September 30, 2017 Limit 
  (in millions) 
AEPTCo $467.2
 $194.8
 $235.7
 $19.3
 $162.9
 $795.0
(a)
APCo 231.5
 160.7
 152.2
 32.2
 (45.9) 600.0
 
I&M 367.4
 12.6
 205.7
 12.6
 (164.9) 500.0
 
OPCo 280.6
 56.2
 141.0
 27.9
 (167.6) 400.0
 
PSO 185.2
 —
 121.3
 —
 (118.0) 300.0
 
SWEPCo 187.5
 178.6
 109.6
 169.5
 (48.3) 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, which is a participantLLC participate in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 20172020 and December 31, 20162019 are included in Advances to Affiliates on SWEPCo’sthe subsidiaries’ balance sheets. ForThe Nonutility Money Pool participants’ activity for the nine months ended September 30, 2017, Mutual Energy SWEPCo, LP had2020 is described in the following activity in the Nonutility Money Pool:table:
Maximum Loans Average Loans Loans to the Nonutility
to the Nonutility to the Nonutility Money Pool as of
CompanyMoney PoolMoney PoolSeptember 30, 2020
(in millions)
AEP Texas$7.5 $7.1 $7.1 
SWEPCo2.1 2.1 2.1 
Maximum Average Loans
Loans Loans to the Nonutility
to the Nonutility to the Nonutility Money Pool as of
Money Pool Money Pool September 30, 2017
(in millions)
$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 September 30, 20172020 and December 31, 20162019 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct borrowing and lending activity with AEP and corresponding authorized borrowing limit for the nine months ended September 30, 2017 is2020 are described in the following table:
Maximum Maximum Average Average Borrowings from Loans toAuthorized
Borrowings Loans Borrowings Loans AEP as of AEP as ofShort-term
from AEP to AEP from AEP to AEP September 30, 2020September 30, 2020Borrowing Limit
(in millions)
$1.4 $195.8 $1.3 $128.7 $1.2 $105.4 $50.0 (a)

(a)    Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
210





Maximum Maximum Average Average Borrowings from Loans to Authorized 
Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term 
from AEP to AEP from AEP to AEP September 30, 2017 September 30, 2017 Borrowing Limit 
(in millions) 
$1.1
 $151.9
 $1.1
 $38.9
 $0.9
 $96.1
 $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:
 Nine Months Ended September 30,
20202019
Maximum Interest Rate2.70 %3.43 %
Minimum Interest Rate0.33 %1.83 %
  Nine Months Ended September 30,
  2017 2016
Maximum Interest Rate 1.49% 0.91%
Minimum Interest Rate 0.92% 0.69%


The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized for all Registrant Subsidiaries in the following table:
Average Interest Rate for FundsAverage Interest Rate for Funds
Borrowed from the Utility Money PoolLoaned to the Utility Money Pool
for Nine Months Ended September 30,for Nine Months Ended September 30,
Company2020201920202019
AEP Texas1.55 %2.71 %0.87 %0 %
AEPTCo1.63 %2.72 %2.00 %2.57 %
APCo2.14 %2.82 %0.99 %2.73 %
I&M1.30 %2.56 %1.44 %2.73 %
OPCo1.32 %2.80 %2.06 %2.68 %
PSO1.24 %2.85 %1.95 %2.48 %
SWEPCo1.55 %2.74 %0 %2.47 %
  Average Interest Rate Average Interest Rate
  for Funds Borrowed for Funds Loaned
  from the Utility Money Pool for to the Utility Money Pool for
  Nine Months Ended September 30, Nine Months Ended September 30,
Company 2017 2016 2017 2016
AEPTCo 1.36% 0.82% 1.04% 0.74%
APCo 1.24% 0.78% 1.28% 0.79%
I&M 1.24% 0.73% 1.27% 0.78%
OPCo 1.40% 0.85% 0.98% 0.74%
PSO 1.30% 0.76% —% 0.81%
SWEPCo 1.26% 0.79% 0.98% 0.91%


Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LP in the following table:
Nine Months Ended September 30, 2020Nine Months Ended September 30, 2019
  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 2.70 %0.33 %1.44 %3.02 %2.36 %2.70 %
SWEPCo 2.70 %0.33 %1.44 %3.02 %2.36 %2.70 %
  Maximum Minimum Average
  Interest Rate Interest Rate Interest Rate
Nine Months for Funds Loaned for Funds Loaned for Funds Loaned
Ended to the Nonutility  to the Nonutility to the Nonutility
September 30,Money Pool Money Pool Money Pool
2017 1.49% —% 1.27%
2016 0.91% 0.69% 0.79%


AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table:
 MaximumMinimumMaximumMinimumAverageAverage
 Interest RateInterest RateInterest RateInterest RateInterest RateInterest Rate
Nine Months for Fundsfor Fundsfor Fundsfor Fundsfor Fundsfor Funds
Ended BorrowedBorrowedLoanedLoanedBorrowedLoaned
September 30, from AEP from AEPto AEP to AEP from AEP to AEP
2020 2.70 %0.50 %2.70 %0.50 %1.45 %1.40 %
2019 3.02 %2.36 %3.02 %2.36 %2.70 %2.70 %


211
  Maximum Minimum Maximum Minimum Average Average
  Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate
Nine Months for Funds for Funds for Funds for Funds for Funds for Funds
Ended Borrowed Borrowed Loaned Loaned Borrowed Loaned
September 30, from AEP from AEPto AEP to AEP from AEP to AEP
2017 1.49% 0.92% 1.49% 0.92% 1.27% 1.31%
2016 0.91% 0.69% 0.91% 0.69% 0.80% 0.81%








Short-term Debt (Applies to AEP, AEP Texas and SWEPCo)


Outstanding short-term debt was as follows:
 September 30, 2020December 31, 2019
OutstandingInterestOutstandingInterest
CompanyType of DebtAmountRate (a)AmountRate (a)
 (dollars in millions)
AEPSecuritized Debt for Receivables (b)$703.0 1.05 %$710.0 2.42 %
AEPCommercial Paper650.0 0.21 %2,110.0 2.10 %
AEP364-Day Term Loan1,000.0 0.75 %0 0 %
AEP TexasCOVID-19 Electricity Relief Program Loan (c)2.0 0 %0 0 %
SWEPCoNotes Payable42.0 2.46 %18.3 3.29 %
Total Short-term Debt$2,397.0  $2,838.3  
    September 30, 2017 December 31, 2016
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
 1.17% $673.0
 0.70%
AEP Commercial Paper 295.0
 1.39% 1,040.0
 1.02%
SWEPCo Notes Payable 14.3
 2.88% —
 —%
  Total Short-term Debt $1,059.3
  
 $1,713.0
  


(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.
(c)Principal amount of loan shall not bear interest if paid in full by the maturity date. Unpaid principal after the maturity date will accrue interest of 2% per annum beginning the first day after the maturity date until all outstanding principal is paid.

Credit Facilities


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


Securitized Accounts Receivables – AEP Credit (Applies to AEP)


AEP Credit has a receivables securitization agreement 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 May 2020, AEP Credit’sCredit amended its receivables securitization agreement provides a commitmentto increase the eligibility criteria related to aged receivable requirements for the participating affiliated utility subsidiaries in response to the COVID-19 pandemic. As of $750 million fromSeptember 30, 2020, 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, receivables would no longer be purchased by the bank conduits and the Registrants would need to purchase receivablesrely on additional sources of funding for operation and expires in June 2019.working capital, which may adversely impact liquidity.


Accounts receivable information for AEP Credit iswas as follows:
Three Months Ended 
September 30,		Nine Months Ended 
September 30,
2020201920202019
(dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable0.36 %2.37 %1.05 %2.56 %
Net Uncollectible Accounts Receivable Written-Off$2.9 $8.8 $10.5 $19.8 
  Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
  2017 2016 2017 2016
  (dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable 1.33% 0.73% 1.17% 0.65%
Net Uncollectible Accounts Receivable Written Off $7.0
 $7.7
 $18.2
 $17.5
September 30, 2020December 31, 2019
(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts$1,002.4 $841.8 
Short-term – Securitized Debt of Receivables703.0 710.0 
Delinquent Securitized Accounts Receivable103.8 39.6 
Bad Debt Reserves Related to Securitization52.7 32.1 
Unbilled Receivables Related to Securitization227.4 266.8 
  September 30, 2017 December 31, 2016
  (in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $939.8
 $945.0
Short-term – Securitized Debt of Receivables 750.0
 673.0
Delinquent Securitized Accounts Receivable 44.3
 42.7
Bad Debt Reserves Related to Securitization 27.8
 27.7
Unbilled Receivables Related to Securitization 264.2
 322.1


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

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Securitized Accounts Receivables – AEP Credit (Applies to 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 agreement for each Registrant Subsidiary was as follows:agreements were:
CompanySeptember 30, 2020December 31, 2019
 (in millions)
APCo$117.3 $120.9 
I&M184.3 141.8 
OPCo394.3 330.3 
PSO122.0 101.1 
SWEPCo177.6 125.2 
Company September 30, 2017 December 31, 2016
  (in millions)
APCo $116.9
 $142.0
I&M 132.7
 136.7
OPCo 356.3
 388.3
PSO 143.4
 110.4
SWEPCo 167.1
 130.9


The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were:
 Three Months Ended September 30,Nine Months Ended September 30,
Company2020201920202019
 (in millions)
APCo$2.0 $1.2 $5.0 $5.8 
I&M3.9 2.4 9.3 8.4 
OPCo9.8 6.4 19.6 22.1 
PSO1.5 2.0 3.8 6.2 
SWEPCo2.8 1.9 6.8 7.9 
  Three Months Ended September 30, Nine Months Ended September 30,
Company 2017 2016 2017 2016
  (in millions)
APCo $1.5
 $1.6
 $4.2
 $5.4
I&M 1.8
 2.0
 4.9
 5.6
OPCo 6.1
 8.1
 16.5
 23.4
PSO 2.0
 1.8
 5.2
 4.7
SWEPCo 2.0
 2.1
 5.4
 5.3


The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were:
 Three Months Ended September 30,Nine Months Ended September 30,
Company2020201920202019
(in millions)
APCo$323.5 $303.3 $961.8 $978.5 
I&M532.3 485.3 1,443.6 1,378.9 
OPCo666.0 602.6 1,793.0 1,746.1 
PSO369.2 451.5 961.4 1,118.7 
SWEPCo478.3 480.7 1,225.3 1,247.0 

213
  Three Months Ended September 30, Nine Months Ended September 30,
Company 2017 2016 2017 2016
  (in millions)
APCo $335.5
 $361.7
 $1,029.4
 $1,071.6
I&M 409.9
 448.0
 1,218.9
 1,220.2
OPCo 616.3
 750.9
 1,741.7
 2,011.2
PSO 407.0
 390.6
 1,022.6
 971.9
SWEPCo 455.0
 460.4
 1,200.8
 1,183.9







13. PROPERTY, PLANT AND EQUIPMENT

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

Asset Retirement Obligations

The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, wind farms, solar farms and certain coal mining facilities. The Registrants recorded the following revisions to ARO estimates during the first nine months of 2020:

•In March 2020, SWEPCo recorded a revision to increase estimated ARO liabilities by $21 million primarily due to the revision in the useful life of DHLC. See Note 4 - Rate Matters for additional details. In September 2020, SWEPCo recorded an $18 million revision due to a reduction in estimated ash pond closure costs.
•In June 2020, AEP Texas and PSO recorded a revision to decrease estimated ARO liabilities by $17 million and $5 million, respectively, due to the retirement of the Oklaunion Power Station in September 2020. See Note 4 - Rate Matters for additional details.
•In June 2020, AGR derecognized $106 million of Conesville Plant related ARO liabilities as a result of the Environmental Liability and Property Transfer and Asset Purchase Agreement executed with a non-affiliated third-party. See Note 6 - Acquisitions and Dispositions for additional details.
•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 House Bill 443. This bill requires APCo to close the ash disposal units at the retired Glen Lyn Station by removal of all coal combustion material. The legislation provides for regulatory recovery of these costs. See Note 5 - Commitments, Guarantees and Contingencies for additional details.

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

CompanyARO as of December 31, 2019Accretion
Expense		Liabilities
Incurred		Liabilities
Settled		Revisions in
Cash Flow
Estimates		ARO as of September 30, 2020
(in millions)
AEP (a)(b)(c)(d)$2,418.9 $76.8 $0.2 $(155.4)$170.5 $2,511.0 
AEP Texas (a)(d)29.1 0.7 0 0 (16.8)13.0 
APCo (a)(d)111.1 5.9 0 (5.3)195.4 307.1 
PSO (a)(d)52.2 2.3 0 (0.5)(4.8)49.2 
SWEPCo (a)(c)(d)212.2 8.2 0 (5.6)6.2 221.0 

(a)Includes ARO related to ash disposal facilities.
(b)Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.78 billion and $1.73 billion as of September 30, 2020 and December 31, 2019, respectively.
(c)Includes ARO related to Sabine and DHLC.
(d)Includes ARO related to asbestos removal.





214





14. REVENUE FROM CONTRACTS WITH CUSTOMERS

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

Disaggregated Revenues from Contracts with Customers

The tables below represent AEP’s reportable segment revenues from contracts with customers, net of respective provisions for refund, by type of revenue:
Three Months Ended September 30, 2020
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration & MarketingCorporate and OtherReconciling AdjustmentsAEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues$1,053.3 $594.8 $0 $0 $0 $0 $1,648.1 
Commercial Revenues559.7 259.2 0 0 0 0 818.9 
Industrial Revenues504.5 93.9 0 0 0 (0.1)598.3 
Other Retail Revenues41.4 10.0 0 0 0 0 51.4 
Total Retail Revenues2,158.9 957.9 0 0 0 (0.1)3,116.7 
Wholesale and Competitive Retail Revenues:
Generation Revenues158.4 0 0 30.5 0 0 188.9 
Transmission Revenues (a)84.4 119.1 317.7 0 0 (276.9)244.3 
Renewable Generation Revenues (b)0 0 0 15.8 0 (0.3)15.5 
Retail, Trading and Marketing Revenues (c)0 0 0 447.5 0.9 (24.8)423.6 
Total Wholesale and Competitive Retail Revenues242.8 119.1 317.7 493.8 0.9 (302.0)872.3 
Other Revenues from Contracts with Customers (b)34.1 42.8 2.4 0.7 33.9 (43.7)70.2 
Total Revenues from Contracts with Customers2,435.8 1,119.8 320.1 494.5 34.8 (345.8)4,059.2 
Other Revenues:
Alternative Revenues (b)(1.0)9.3 (2.2)0 0 6.6 12.7 
Other Revenues (b)0 36.2 0 (4.5)(2.2)(35.0)(5.5)
Total Other Revenues(1.0)45.5 (2.2)(4.5)(2.2)(28.4)7.2 
Total Revenues$2,434.8 $1,165.3 $317.9 $490.0 $32.6 $(374.2)$4,066.4 

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $246 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 $19 million. The remaining affiliated amounts were immaterial.



215





Three Months Ended September 30, 2019
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration & MarketingCorporate and OtherReconciling AdjustmentsAEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues$1,060.2 $588.0 $0 $0 $0 $0 $1,648.2 
Commercial Revenues612.5 290.9 0 0 0 0 903.4 
Industrial Revenues566.0 99.3 0 0 0 1.5 666.8 
Other Retail Revenues49.2 10.6 0 0 0 0 59.8 
Total Retail Revenues2,287.9 988.8 0 0 0 1.5 3,278.2 
Wholesale and Competitive Retail Revenues:
Generation Revenues (a)231.3 0 0 77.1 0 (34.2)274.2 
Transmission Revenues (b)77.8 110.9 269.4 0 0 (217.2)240.9 
Renewable Generation Revenues (c)0 0 0 20.1 0 0 20.1 
Retail, Trading and Marketing Revenues (c)0 0 0 395.3 0 0.5 395.8 
Total Wholesale and Competitive Retail Revenues309.1 110.9 269.4 492.5 0 (250.9)931.0 
Other Revenues from Contracts with Customers (c)47.3 42.9 4.5 14.8 35.6 (42.2)102.9 
Total Revenues from Contracts with Customers2,644.3 1,142.6 273.9 507.3 35.6 (291.6)4,312.1 
Other Revenues:
Alternative Revenues (c)1.2 5.1 (0.9)0 0 (16.8)(11.4)
Other Revenues (c)0 38.9 0 26.4 (11.2)(39.8)14.3 
Total Other Revenues1.2 44.0 (0.9)26.4 (11.2)(56.6)2.9 
Total Revenues$2,645.5 $1,186.6 $273.0 $533.7 $24.4 $(348.2)$4,315.0 

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $34 million. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $197 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues.




216





Three Months Ended September 30, 2020
AEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Retail Revenues:
Residential Revenues$165.3 $0 $324.2 $222.6 $429.4 $195.8 $219.4 
Commercial Revenues78.0 0 138.4 135.8 181.2 94.4 135.0 
Industrial Revenues24.9 0 139.4 139.7 69.1 55.0 83.8 
Other Retail Revenues6.9 0 17.6 1.6 3.1 18.4 2.3 
Total Retail Revenues275.1 0 619.6 499.7 682.8 363.6 440.5 
Wholesale Revenues:
Generation Revenues (a)0 0 70.3 61.5 0 5.8 42.3 
Transmission Revenues (b)101.8 305.7 30.8 7.4 17.2 8.5 28.7 
Total Wholesale Revenues101.8 305.7 101.1 68.9 17.2 14.3 71.0 
Other Revenues from Contracts with Customers (c)15.2 3.0 16.1 17.7 27.6 4.8 5.6 
Total Revenues from Contracts with Customers392.1 308.7 736.8 586.3 727.6 382.7 517.1 
Other Revenues:
Alternative Revenues (d)(0.7)(4.6)(1.1)0.4 10.0 (0.5)0.2 
Other Revenues (d)40.6 0 0 0 3.4 0 0 
Total Other Revenues39.9 (4.6)(1.1)0.4 13.4 (0.5)0.2 
Total Revenues$432.0 $304.1 $735.7 $586.7 $741.0 $382.2 $517.3 

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $28 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $243 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $15 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.



217





Three Months Ended September 30, 2019
AEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Retail Revenues:
Residential Revenues$192.0 $0 $315.7 $198.2 $395.6 $231.9 $222.9 
Commercial Revenues110.6 0 147.2 138.3 180.5 122.2 144.3 
Industrial Revenues32.2 0 152.2 138.7 67.1 84.1 92.3 
Other Retail Revenues7.5 0 18.5 1.9 3.1 24.9 2.3 
Total Retail Revenues342.3 0 633.6 477.1 646.3 463.1 461.8 
Wholesale Revenues:
Generation Revenues (a)0 0 70.4 102.1 0 21.1 50.7 
Transmission Revenues (b)97.7 256.4 26.2 6.4 13.7 (3.4)30.0 
Total Wholesale Revenues97.7 256.4 96.6 108.5 13.7 17.7 80.7 
Other Revenues from Contracts with Customers (c)8.2 4.5 18.7 26.6 41.0 5.1 7.0 
Total Revenues from Contracts with Customers448.2 260.9 748.9 612.2 701.0 485.9 549.5 
Other Revenues:
Alternative Revenues (d)(0.7)(1.2)6.6 (1.1)12.4 7.1 (4.0)
Other Revenues (d)41.8 0 0 0 (2.8)0 0 
Total Other Revenues41.1 (1.2)6.6 (1.1)9.6 7.1 (4.0)
Total Revenues$489.3 $259.7 $755.5 $611.1 $710.6 $493.0 $545.5 

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $32 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $194 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $20 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.


218





Nine Months Ended September 30, 2020
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration & MarketingCorporate and OtherReconciling AdjustmentsAEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues$2,789.1 $1,610.6 $0 $0 $0 $0 $4,399.7 
Commercial Revenues1,523.6 792.4 0 0 0 0 2,316.0 
Industrial Revenues1,508.7 290.4 0 0 0 (0.5)1,798.6 
Other Retail Revenues118.2 32.1 0 0 0 0 150.3 
Total Retail Revenues5,939.6 2,725.5 0 0 0 (0.5)8,664.6 
Wholesale and Competitive Retail Revenues:
Generation Revenues447.4 0 0 106.1 0 0 553.5 
Transmission Revenues (a)248.4 341.6 937.7 0 0 (741.7)786.0 
Renewable Generation Revenues (b)0 0 0 50.7 0 (1.2)49.5 
Retail, Trading and Marketing Revenues (c)0 0 0 1,133.8 (5.7)(80.7)1,047.4 
Total Wholesale and Competitive Retail Revenues695.8 341.6 937.7 1,290.6 (5.7)(823.6)2,436.4 
Other Revenues from Contracts with Customers (b)124.1 112.3 17.5 1.7 84.4 (115.7)224.3 
Total Revenues from Contracts with Customers6,759.5 3,179.4 955.2 1,292.3 78.7 (939.8)11,325.3 
Other Revenues:
Alternative Revenues (b)(6.0)49.2 (77.4)0 0 3.5 (30.7)
Other Revenues (b)0 78.1 0 13.2 (6.7)(71.3)13.3 
Total Other Revenues(6.0)127.3 (77.4)13.2 (6.7)(67.8)(17.4)
Total Revenues$6,753.5 $3,306.7 $877.8 $1,305.5 $72.0 $(1,007.6)$11,307.9 

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $725 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 $81 million. The remaining affiliated amounts were immaterial.

219





Nine Months Ended September 30, 2019
Vertically Integrated UtilitiesTransmission and Distribution UtilitiesAEP Transmission HoldcoGeneration & MarketingCorporate and OtherReconciling AdjustmentsAEP Consolidated
(in millions)
Retail Revenues:
Residential Revenues$2,797.6 $1,609.1 $0 $0 $0 $0 $4,406.7 
Commercial Revenues1,641.2 889.4 0 0 0 0 2,530.6 
Industrial Revenues1,647.3 332.6 0 0 0 0 1,979.9 
Other Retail Revenues136.1 32.8 0 0 0 0 168.9 
Total Retail Revenues6,222.2 2,863.9 0 0 0 0 9,086.1 
Wholesale and Competitive Retail Revenues:
Generation Revenues (a)661.9 0 0 282.0 0 (105.5)838.4 
Transmission Revenues (b)215.4 324.0 814.3 0 0 (603.6)750.1 
Renewable Generation Revenues (c)0 0 0 39.0 0 0.5 39.5 
Retail, Trading and Marketing Revenues (c)0 0 0 1,049.5 0 0 1,049.5 
Total Wholesale and Competitive Retail Revenues877.3 324.0 814.3 1,370.5 0 (708.6)2,677.5 
Other Revenues from Contracts with Customers (c)128.8 127.6 12.6 4.5 80.4 (113.6)240.3 
Total Revenues from Contracts with Customers7,228.3 3,315.5 826.9 1,375.0 80.4 (822.2)12,003.9 
Other Revenues:
Alternative Revenues (c)(55.7)21.5 (18.6)0 0 (60.3)(113.1)
Other Revenues (c)0 117.3 0 53.2 (6.7)(109.2)54.6 
Total Other Revenues(55.7)138.8 (18.6)53.2 (6.7)(169.5)(58.5)
Total Revenues$7,172.6 $3,454.3 $808.3 $1,428.2 $73.7 $(991.7)$11,945.4 

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $105 million. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $596 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues.
220





Nine Months Ended September 30, 2020
AEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Retail Revenues:
Residential Revenues$447.8 $0 $954.4 $610.8 $1,162.6 $463.5 $498.7 
Commercial Revenues285.2 0 390.6 376.0 507.3 247.8 351.2 
Industrial Revenues91.4 0 415.0 408.2 199.1 170.8 245.9 
Other Retail Revenues22.3 0 50.9 5.0 9.8 51.2 6.6 
Total Retail Revenues846.7 0 1,810.9 1,400.0 1,878.8 933.3 1,102.4 
Wholesale Revenues:
Generation Revenues (a)0 0 185.3 215.5 0 9.9 106.7 
Transmission Revenues (b)290.4 902.6 91.5 22.1 51.1 20.2 87.5 
Total Wholesale Revenues290.4 902.6 276.8 237.6 51.1 30.1 194.2 
Other Revenues from Contracts with Customers (c)33.4 17.5 46.8 60.6 78.9 23.2 21.1 
Total Revenues from Contracts with Customers1,170.5 920.1 2,134.5 1,698.2 2,008.8 986.6 1,317.7 
Other Revenues:
Alternative Revenues (d)(0.3)(82.3)(11.9)5.4 49.6 1.5 0.5 
Other Revenues (d)86.9 0 0 0 13.3 0 0 
Total Other Revenues86.6 (82.3)(11.9)5.4 62.9 1.5 0.5 
Total Revenues$1,257.1 $837.8 $2,122.6 $1,703.6 $2,071.7 $988.1 $1,318.2 

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $85 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $715 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $49 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.

221





Nine Months Ended September 30, 2019
AEP TexasAEPTCoAPCoI&MOPCoPSOSWEPCo
(in millions)
Retail Revenues:
Residential Revenues$454.9 $0 $944.7 $558.8 $1,155.5 $519.6 $503.7 
Commercial Revenues314.5 0 421.5 371.4 573.7 304.3 371.1 
Industrial Revenues98.8 0 444.3 411.9 233.9 238.1 257.2 
Other Retail Revenues22.7 0 56.5 5.4 9.8 63.1 6.7 
Total Retail Revenues890.9 0 1,867.0 1,347.5 1,972.9 1,125.1 1,138.7 
Wholesale Revenues:
Generation Revenues (a)0 0 200.1 327.4 0 35.5 152.7 
Transmission Revenues (b)282.0 775.3 77.6 18.8 42.0 21.9 78.0 
Total Wholesale Revenues282.0 775.3 277.7 346.2 42.0 57.4 230.7 
Other Revenues from Contracts with Customers (c)22.9 12.6 48.2 76.2 113.3 16.7 20.1 
Total Revenues from Contracts with Customers1,195.8 787.9 2,192.9 1,769.9 2,128.2 1,199.2 1,389.5 
Other Revenues:
Alternative Revenues (d)(0.4)(17.8)11.2 (1.4)22.0 (25.3)(47.4)
Other Revenues (d)122.6 0 0 0 3.8 0 0 
Total Other Revenues122.2 (17.8)11.2 (1.4)25.8 (25.3)(47.4)
Total Revenues$1,318.0 $770.1 $2,204.1 $1,768.5 $2,154.0 $1,173.9 $1,342.1 

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $96 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $587 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $57 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.



222





Fixed Performance Obligations

The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of September 30, 2020. Fixed performance obligations primarily include wholesale transmission services, electricity sales for fixed amounts of energy and stand ready services into PJM’s RPM market. The Registrant Subsidiaries amounts shown in the table below include affiliated and nonaffiliated revenues.
Company20202021-20222023-2024After 2024Total
(in millions)
AEP$263.8 $188.3 $164.2 $223.4 $839.7 
AEP Texas108.2 0 0 0 108.2 
AEPTCo274.8 0 0 0 274.8 
APCo40.1 33.1 26.6 11.6 111.4 
I&M8.6 10.9 8.8 4.5 32.8 
OPCo16.5 5.3 0 0 21.8 
PSO3.8 0 0 0 3.8 
SWEPCo10.3 0 0 0 10.3 

Contract Assets and Liabilities

Contract assets are recognized when the Registrants have a right to consideration that is conditional upon the occurrence of an event other than the passage of time, such as future performance under a contract. The Registrants did not have material contract assets as of September 30, 2020 and December 31, 2019.

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 sheet in the amount of that consideration. Revenue for such consideration is subsequently recognized in the period or periods in which the remaining performance obligations in the contract are satisfied. The Registrants’ contract liabilities typically arise from services provided under joint use agreements for utility poles. The Registrants did not have material contract liabilities as of September 30, 2020 and December 31, 2019.

Accounts Receivable from Contracts with Customers

Accounts receivable from contracts with customers are presented on the Registrant Subsidiaries’ balance sheets within the Accounts Receivable - Customers line item. The Registrant Subsidiaries’ balances for receivables from contracts that are not recognized in accordance with the accounting guidance for “Revenue from Contracts with Customers” included in Accounts Receivable - Customers were not material as of September 30, 2020 and December 31, 2019. See “Securitized Accounts Receivable - AEP Credit” section of Note 12 for additional information.

The following table represents the amount of affiliated accounts receivable from contracts with customers included in Accounts Receivable - Affiliated Companies on the Registrant Subsidiaries’ balance sheets:
CompanySeptember 30, 2020December 31, 2019
(in millions)
AEPTCo$79.9 $65.9 
APCo49.3 47.3 
I&M30.5 37.1 
OPCo36.5 33.9 
PSO11.0 9.7 
SWEPCo18.4 17.6 

223





CONTROLS AND PROCEDURES


During the third quarter of 2017,2020, management, including the principal executive officer and principal financial officer of each of the Registrants, evaluated the Registrants’ disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. As of September 30, 2017,2020, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives.


There was no change in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the third quarter of 20172020 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

224








PART II.  OTHER INFORMATION


Item 1.  Legal Proceedings


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


Item 1A.  Risk Factors


The AEP 20162019 Annual Report on Form 10-K and the AEPTCo 2016 Annual Report included within AEPTCo’s Registration Statement includes a detailed discussion of risk factors. As of September 30, 2017, there have been no material changes to2020, the risk factors previously disclosed in AEPTCo’s Registration Statement. As of September 30, 2017, the risk factor appearing in AEP’s 20162019 Annual Report under the heading set forth below isare supplemented and updated as follows:


AEP’s Financial Condition and Results of Operations could continue to be Adversely Affected by the Ongoing Coronavirus Pandemic

AEP is exposedresponding to nuclear generation risk.the global 2019 novel coronavirus (COVID-19) pandemic by taking steps to mitigate the potential risks posed by its spread. 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 continue to disrupt economic activity in AEP’s service territory and could reduce future demand for energy, particularly from commercial and industrial customers. AEP provides a critical service to its customers which means that it must keep its employees who operate its businesses safe and minimize unnecessary risk of exposure to the virus. AEP has updated and implemented a company-wide pandemic plan to address specific aspects of the coronavirus pandemic. This plan guides AEP’s emergency response, business continuity, and the precautionary measures that AEP is taking on behalf its employees and the public. AEP has taken extra precautions for its employees who work in the field and for employees who continue to work in its facilities, and AEP has implemented work from home policies where appropriate.

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. These conditions might also impact the Registrants’ access to and cost of capital. This is a rapidly evolving situation that could lead to extended disruption of economic activity in AEP’s markets.

AEP has instituted measures to ensure its supply chain remains open; however, there could be global shortages that will impact AEP’s maintenance and capital programs that AEP currently cannot anticipate. AEP will continue to monitor developments affecting both its workforce and its customers, and will take additional precautions that are determined to be necessary in order to mitigate the impacts.

AEP continues to implement strong physical and cyber security measures to ensure that its systems remain functional in order to both serve its operational needs with a remote workforce and keep them running to ensure uninterrupted service to customers.

In addition, the economic disruptions caused by COVID-19 could also adversely impact the impairment risks for certain long-lived assets, equity method investments and goodwill. Market volatility and reduction in collections coupled with longer collection periods due to the expansion of customer payment arrangements could reduce cash from operations and cause an adverse impact to liquidity.

AEP will continue to review and modify its plans as conditions change. Despite AEP’s efforts to manage these impacts, their ultimate impact also depends on factors beyond AEP’s knowledge or control, including the duration and severity of this outbreak, its impact on economic and market conditions, as well as third-party actions taken to contain its spread and mitigate its public health effects. Therefore, AEP currently cannot estimate the potential impact to its financial position, results of operations and cash flows.

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Ohio House Bill 6 (HB 6), which provides for beneficial cost recovery for OPCo and for plants owned by OVEC, has come under public scrutiny (Applies to AEP and I&M)OPCo)


Through I&M,In 2019, Ohio adopted and implemented HB 6. Among other provisions, HB 6 phased out current energy efficiency including lost shared savings revenues of $26 million annually and renewable mandates no later than 2020 and after 2026, respectively. 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 coal-fired unit costs through 2030. AEP ownsand OPCo engaged in lobbying efforts and provided testimony during the Cook Plant.  It consistslegislative process in support of two nuclear generating units forHB 6. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a rated capacity of 2,278 MWs, or about 7%federal grand jury indictment of the generating capacity inSpeaker of the AEP System.  AEPOhio House of Representatives, Larry Householder, four other individuals, and I&M are, therefore, subject to the risks of nuclear generation, which include the following:

The potential harmful effects on the environment and human health due toGeneration Now, an adverse incident/event resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials suchentity registered as spent nuclear fuel.
Limitations on the amounts and types of insurance commercially available to cover losses that might arisea 501(c)(4) social welfare organization, in connection with nuclear operations.
Uncertainties with respect to contingencies and assessment amounts triggered by a loss event (federal law requires ownersan alleged racketeering conspiracy involving the adoption of nuclear units to purchase the maximum available amount of nuclear liability insurance and potentially contribute to the coverage for losses of others).
Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.
Uncertainties related to reliance on a vendor for manufacturing nuclear fuel and for providing specialized engineering services and parts.

There can be no assurance that I&M’s preparations or risk mitigation measures will be adequate if these risks are triggered.

The Nuclear Regulatory Commission has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities.HB 6. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessmentlight of the severity of the situation, until compliance is achieved.  Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants.  In addition, although management has no reason to anticipate a serious nuclear incident at the Cook Plant, if an incident did occur, it could harm results of operations or financial condition.  A major incident at a nuclear facility anywhereallegations in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit.  Moreover, a major incident at any nuclear facility in the U.S. could require AEP or I&M to make material contributory payments.

Costs associated with the operation (including fuel), maintenance and retirement of nuclear plants continue to be more significant and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements and safety standards, availability of nuclear waste disposal facilities and experience gained in the operation of nuclear facilities.  Costs also may include replacement power, any unamortized investment at the end of the useful life of the Cook Plant (whether scheduled or premature), the carrying costs ofindictment, proposed legislation has been introduced that investment and retirement costs.would repeal HB 6. The ability to obtain adequate and timely recovery of costs associated with the Cook Plant is not assured.


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. In March 2017, Westinghouse filed a petition to reorganize under Chapter 11outcome of the U.S. Bankruptcy Code. It intendsAttorney’s Office investigation and its impact on HB 6 is not known. If the provisions of HB 6 were to reorganize, not cease business operations. However, it is in the early stages of the bankruptcy process andbe eliminated, it is unclear whether and in what form the company can successfully reorganize. InOhio General Assembly would pass new legislation addressing similar issues. To the event Westinghouse rejects I&M’s contracts, orextent that OPCo is unable to reorganizerecover the costs of renewable energy contracts on a bypassable basis by the end of 2032, recover costs of OVEC after 2030 or sell its profitable businesses in the bankruptcy, Cook Plant’s operations would be significantly impacted and potentially shut down temporarily as I&M seeks other vendors for these services.

AEP’s transmission investment strategy and execution bears certain risks associated with these activities. (Applies to all Registrants)

Management expects that a growing portion of AEP’s earnings in the future will be derived from transmission investments and activities.  FERC policy currently favors the expansion and updating of the transmission infrastructure within its jurisdiction.  If the FERC were to adopt a different policy, if states were to limit or restrict such policies, or if transmission needs do not continue or develop as projected, AEP’s strategy of investing in transmission could be impacted.  Management believes AEP’s experience with transmission facilities construction and operation gives AEP an advantage over other competitors in securing authorization to install, construct and operate new transmission lines and facilities.  However, there can be no assurance that PJM, SPP or other RTOs will authorize new transmission projects or will award such projects to AEP.

In October 2016, several parties filed a joint complaint with the FERC claiming that the base return on common equity used by eastern AEP affiliates 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 June 2017, several parties filed a joint complaint with the FERC that states the base return on common equity used by western AEP affiliates, including the State Transcos that operate in 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. If the FERC orders revenue reductions as a result of these complaints, including refunds from the date each complaint was filed,fully recover energy efficiency costs through 2020, it could reduce future net income and cash flows and impact financial condition. In addition, the impact of continued public scrutiny of HB 6 is not known, and may have an adverse impact on AEP and OPCo, including their relationship with regulatory and legislative authorities, customers and other stakeholders and their potential involvement with various current or future litigation arising out HB 6.


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 FERC wereICPA, OVEC may not have sufficient funds to lowerhonor its payment obligations, including its ongoing operating expenses as well as its indebtedness. As of September 30, 2020, OVEC has outstanding indebtedness of approximately $1.3 billion, of which APCo, I&M, and OPCo are collectively responsible for $563 million through the rateICPA. Although they are not an obligor or guarantor, APCo, I&M, and OPCo are responsible for their respective ratio of return it has authorized for AEP’s transmission investmentsOVEC’s outstanding debt through the ICPA.

Energy Harbor (formerly FirstEnergy Solutions), a nonaffiliated party, whose aggregate power participation ratio is 4.85% under the ICPA, filed a petition seeking protection under the bankruptcy law. In May 2020, Energy Harbor entered into a bankruptcy settlement and facilities, or if one or more states wereresumed performance under the ICPA as of June 1, 2020. In July 2020, federal prosecutors arrested the Speaker of the Ohio House of Representatives and four other individuals alleging that they engaged in a bribery and money laundering scheme connected to successfully limit FERC jurisdiction on recoverythe passage of costs on transmission investmentHB 6. Subsequently, proposed legislation was introduced that would repeal HB 6. If HB 6 is repealed and its return, itnot replaced, Energy Harbor’s financial ability to participate in the ICPA could reduce future net incomebe adversely impacted. Management is currently unable to predict the outcome of the proposed legislation and will continue to monitor the legislative process and any potential impact to OVEC’s cash flows and negatively impactor financial condition. 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%.


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


None


Item 3.  Defaults Upon Senior Securities


None


Item 4.  Mine Safety Disclosures


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


The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act. Exhibit 95 “Mine Safety Disclosure Exhibit” contains the notices of violation and proposed assessments received by DHLC under the Mine Act for the quarter ended September 30, 2017.2020.




Item 5.  Other Information


NoneOn October 21, 2020, the Company entered into a separation, release of all claims and noncompetition agreement with Ms. Hillebrand pursuant to which the Company will provide $1,106,875 in severance benefits due to the elimination of her position and separation from service, effective December 31, 2020. This amount is equivalent to 1× her annual base salary and target annual incentive award, which is the current severance benefit for all participants under AEP’s Executive Severance plan. Half of this amount will be paid 6 months after her termination date and the remainder will be paid over the following 13 biweekly pay periods. In addition, the Company agreed to provide $500,000 in unrestricted AEP shares under AEP’s Long-Term Incentive Plan upon her separation from AEP service. The number of unrestricted AEP shares provided to Ms. Hillebrand will be determined by dividing the $500,000 value by the closing price of AEP Common Stock as reported by NASDAQ on December 31, 2020 and will be granted under AEP’s Long-Term Incentive Plan. This agreement also contains among other provisions, a one-year non-competition agreement and affirms certain non-solicitation, confidentiality and cooperation stipulations.


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Item 6.  Exhibits


The documents designated with an (*) below have previously been filed on behalf of the Registrants shown and are incorporated herein by reference to the documents indicated and made a part hereof.
ExhibitDescriptionPreviously Filed as Exhibit to:
AEP‡ File No. 1-3525
4.1Purchase Contract dated as of August 14, 2020, between the Company and The Bank of New York Mellon Trust Company, N.A., as purchase contract agent, collateral agent, custodial agent and securities intermediary
4.2Junior Subordinated Indenture, dated March 1, 2008, between the Company and The Bank of New York Mellon Trust Company, N.A., as Trustee for the Junior Subordinated Debentures
Registration Statement No. 333-156387, Exhibits 4(c) and 4(d); Form 8-K, Exhibit 4.3, dated March 19, 2019
4.3Supplemental Indenture No. 2, dated August 14, 2020, from the Company to The Bank of New York Mellon Trust Company, N.A., as trustee
Form 8-K dated August 14, 2020 Exhibit 4.3
SWEPCo‡   File No. 1-3146
4.4Amendment to Certificate of Incorporation filed with Delaware Secretary of State effective August 31, 2020 to authorize a reverse stock split of the common stock, eliminate the authorized preferred stock and reduce the authorized number of shares of common stock

The exhibits designated with an (X) in the table below are being filed on behalf of the Registrants.
ExhibitDescriptionAEPAEPTCoAEP
Texas		APCoAEPTCoAPCoI&MOPCoPSOSWEPCo
1210.1Computation of Consolidated Ratio of Earnings to Fixed ChargesAEP System Stock Ownership Requirement Plan As Amended and Restated Effective October 1, 2020
X
X
X
X
X
X
X
31(a)10.2AEP Retainer Deferral Plan For Non-Employee Directors As Amended and Restated Effective October 1, 2020
X
10.3AEP Stock Unit Accumulation Plan For Non-Employee Directors As Amended Effective October 1, 2020
X
10.4Severance, Stock Award, Release of All Claims and Noncompetition Agreement dated October 21, 2020 between AEPSC and Lana Hillebrand
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
228





101.INSExhibitDescriptionAEPAEP
Texas		AEPTCoAPCoI&MOPCoPSOSWEPCo
101.INSXBRL Instance DocumentXThe instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.XXXXXX
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.

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SIGNATURE




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




AMERICAN ELECTRIC POWER COMPANY, INC.






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






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






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






Date:  October 26, 2017

22, 2020
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