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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, 20172019
ORor
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from ____ to ____
Commission Registrants; States of Incorporation; I.R.S. Employer
File Number Address and Telephone Number  States of IncorporationIdentification Nos.
     
1-3525 AMERICAN ELECTRIC POWER COMPANY,CO INC. (A New York Corporation) 13-4922640
333-221643AEP TEXAS INC.Delaware51-0007707
333-217143 AEP TRANSMISSION COMPANY, LLC (A Delaware Limited Liability Company) 46-1125168
1-3457 APPALACHIAN POWER COMPANY (A Virginia Corporation) 54-0124790
1-3570 INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) 35-0410455
1-6543 OHIO POWER COMPANY (An Ohio Corporation) 31-4271000
0-343 PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation) 73-0410895
1-3146 SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation) 72-0323455
  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 valueAEPNew York Stock Exchange
American Electric Power Company Inc.6.125% Corporate UnitsAEP PR BNew York Stock Exchange
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¨
   
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 filerx   (Do not check if a smaller reporting company)
       
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, 201724, 2019
  
American Electric Power Company, Inc.491,883,887493,951,812

 ($6.50 par value)

AEP Texas Inc.100
($0.01 par value)
AEP Transmission Company, LLC (a)NA

  
Appalachian Power Company13,499,500

 (no par value)

Indiana Michigan Power Company1,400,000

 (no par value)

Ohio Power Company27,952,473

 (no par value)

Public Service Company of Oklahoma9,013,000

 ($15 par value)

Southwestern Electric Power Company7,536,640

 ($18 par value)



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







AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF QUARTERLY REPORTS ON FORM 10-Q
September 30, 20172019
     
    Page
    Number
Glossary of Terms
     
Forward-Looking Information
     
Part I. FINANCIAL INFORMATION 
     
 Items 1, 2, 3 and 4 - Financial Statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosures About Market Risk, and Controls and Procedures: 
     
American Electric Power Company, Inc. and Subsidiary Companies: 
 Management’s Discussion and Analysis of Financial Condition and Results of Operations
 Condensed Consolidated Financial Statements
AEP Texas Inc. and Subsidiaries:
Management’s Narrative Discussion and Analysis of Results of Operations
Condensed Consolidated Financial Statements
     
AEP Transmission Company, LLC and Subsidiaries: 
 Management’s Narrative Discussion and Analysis of Results of Operations
 Condensed Consolidated Financial Statements
     
Appalachian Power Company and Subsidiaries: 
 Management’s Narrative Discussion and Analysis of Results of Operations
 Condensed Consolidated Financial Statements
     
Indiana Michigan Power Company and Subsidiaries: 
 Management’s Narrative Discussion and Analysis of Results of Operations
 Condensed Consolidated Financial Statements
     
Ohio Power Company and Subsidiaries: 
 Management’s Narrative Discussion and Analysis of Results of Operations
 Condensed Consolidated Financial Statements
     
Public Service Company of Oklahoma: 
 Management’s Narrative Discussion and Analysis of Results of Operations
 Condensed Financial Statements
     
Southwestern Electric Power Company Consolidated: 
 Management’s Narrative Discussion and Analysis of Results of Operations
 Condensed Consolidated Financial Statements
     
Index of Condensed Notes to Condensed Financial Statements of Registrants
     
Controls and Procedures





Part II.  OTHER INFORMATION 
     
 Item 1.  Legal Proceedings
 Item 1A.  Risk Factors
 Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds
 Item 3.  Defaults Upon Senior Securities
 Item 4.  Mine Safety Disclosures
 Item 5.  Other Information
 Item 6.  Exhibits:Exhibits
Exhibit 12
Exhibit 31(a)
Exhibit 31(b)
Exhibit 32(a)
Exhibit 32(b)
Exhibit 95
Exhibit 101.INS
Exhibit 101.SCH
Exhibit 101.CAL
Exhibit 101.DEF
Exhibit 101.LAB
Exhibit 101.PRE
     
SIGNATURE  
     
     
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 Texas AEP 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.
AEPRO AEP River Operations, LLC, a commercial barge operation sold in November 2015.
AEPSC American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AEPTCo AEP Transmission Company, LLC, a wholly-owned subsidiary of AEP Transmission Holdco, andis an intermediate holding company that owns seven wholly-owned transmission companies.the State Transcos.
AEPTCo Parent AEP Transmission Company, LLC, the equity ownerholding company of the State Transcos within the AEPTCo consolidation.
AFUDC Allowance for Equity Funds Used During Construction.
AGR AEP Generation Resources Inc., a competitive AEP subsidiary in the Generation & Marketing segment.
ALJAdministrative Law Judge.
AOCI Accumulated Other Comprehensive Income.
APCo Appalachian Power Company, an AEP electric utility subsidiary.
Appalachian Consumer Rate Relief Funding Appalachian Consumer Rate Relief Funding LLC, a wholly-owned subsidiary of APCo and a consolidated variable interest entityVIE formed for the purpose of issuing and servicing securitization bonds related to the under-recovered ENEC deferral balance.
APSC Arkansas 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.
ASU Accounting Standards Update.
CAA Clean Air Act.
CAIRCLECO Clean Air Interstate Rule.Central Louisiana Electric Company, a nonaffiliated utility company.
Cardinal Operating CompanyA jointly-owned organization between AGR and a nonaffiliate. The nonaffiliate operates the three unit Cardinal Plant and wholly-owns Units 2 and 3.
CO2
 Carbon dioxide and other greenhouse gases.
Conesville PlantA generation plant consisting of three coal-fired generating units totaling 1,695 MW located in Conesville, Ohio. The plant is jointly-owned by AGR and a nonaffiliate.
Cook Plant Donald C. Cook Nuclear Plant, a two-unit, 2,278 MW nuclear plant owned by I&M.
CSAPRCross-State Air Pollution Rule.
CWAClean Water Act.
CWIP Construction Work in Progress.
DCC Fuel DCC Fuel VI LLC, DCC Fuel VII, DCC Fuel VIII, DCC Fuel IX, DCC Fuel X, DCC Fuel XI, DCC Fuel XII and DCC Fuel X,XIII, consolidated variable interest entitiesVIEs formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.

i



TermMeaning
DHLC Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.
DIR Distribution Investment Rider.
EIS Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated variable interest entityVIE of AEP.
ENEC Expanded Net Energy Cost.
Energy Supply AEP Energy Supply LLC, a nonregulated holding company for AEP’s competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP.
Equity UnitsAEP’s Equity Units issued in March 2019.
ERCOT Electric Reliability Council of Texas regional transmission organization.

i



TermMeaning
ESP Electric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO.
ETT Electric 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 EPA United 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.
IURC Indiana Utility Regulatory Commission.
KGPCo Kingsport Power Company, an AEP electric utility subsidiary.
KPCo Kentucky Power Company, an AEP electric utility subsidiary.
KPSCKentucky Public Service Commission.
kVKilovolt.
KWh Kilowatthour.Kilowatt-hour.
LPSC Louisiana Public Service Commission.
Market Based MechanismMATS An 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.
MPSC Michigan 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 proposed joint PSO and SWEPCo project, which includes three Oklahoma wind facilities totaling approximately 1,485 MWs of wind generation.
NO2
Nitrogen dioxide.
NOx
Nitrogen oxide.
NPDESNational Pollutant Discharge Elimination System.
NSR New Source Review.

ii



TermMeaning
OATT Open Access Transmission Tariff.
OCC Corporation Commission of the State of Oklahoma.
Ohio Phase-in-Recovery Funding Ohio Phase-in-Recovery Funding LLC, a wholly-owned subsidiary of OPCo and a consolidated variable interest entityVIE formed for the purpose of issuing and servicing securitization bonds related to phase-in recovery property.
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 certain nonaffiliated entities.
OPCo Ohio Power Company, an AEP electric utility subsidiary.
OPEB Other Postretirement Benefit Plans.Benefits.
OSSOff-system Sales.
OTC Over the counter.Over-the-counter.
OVEC Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
Parent American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.
PJM Pennsylvania – New Jersey – Maryland regional transmission organization.
PM Particulate Matter.
PPA Purchase Power and Sale Agreement.
PSO Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PTCProduction Tax Credits.
PUCO Public Utilities Commission of Ohio.
PUCT Public Utility Commission of Texas.

ii



TermRacine Meaning
A generation plant consisting of two hydroelectric generating units totaling 47.5 MWs located in Racine, Ohio and owned by AGR.
Registrant Subsidiaries AEP subsidiaries which are SEC registrants: AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
Registrants SEC 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 Plant A generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana. AEGCo and I&M jointly-own Unit 1. In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2.
ROEReturn on Equity.
RPMReliability Pricing Model.
RSR Retail Stability Rider.
RTO Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine Sabine Mining Company, a lignite mining company that is a consolidated variable interest entityVIE for AEP and SWEPCo.
Santa Rita EastSanta 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.
SCR
Selective Catalytic Reduction, NOx reduction technology at Rockport Plant.
SEC U.S. Securities and Exchange Commission.
SEET Significantly Excessive Earnings Test.
Sempra Renewables LLCSempra Renewables LLC, acquired in April 2019, consists of 724 MWs of wind generation and battery assets in the United States.
SIPState Implementation Plan.
SNF Spent Nuclear Fuel.
SO2
 Sulfur dioxide.
SPP Southwest Power Pool regional transmission organization.

iii



TermMeaning
SSO Standard service offer.
State Transcos AEPTCo’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.
Tax ReformOn December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal Revenue Code of 1986, including a reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018.
TCC Formerly AEP Texas Central Company, now a division of AEP Texas.
Texas Restructuring Legislation Legislation 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 Energy Transource 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 MissouriA 100% wholly-owned subsidiary of Transource Energy.
Turk Plant John W. Turk, Jr. Plant, a 600 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.
UPAUnit Power Agreement.
Utility Money Pool Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
VIEVariable Interest Entity.
Virginia SCC Virginia State Corporation Commission.
Wind Catcher Project Wind Catcher Energy Connection Project, a joint PSO and SWEPCo project which includesthat was cancelled in July 2018. The project included 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.
WVPSC Public Service Commission of West Virginia.


iiiiv





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 – Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the 20162018 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, 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:
ŸEconomic growth or contraction within and changesChanges in economic conditions, electric market demand and demographic patterns in AEP service territories.
ŸInflationary or deflationary interest rate trends.
ŸVolatility in the financial markets, particularly developments affecting the availability or cost of capital to finance new capital projects and refinance existing debt.
ŸThe 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.
ŸElectric load and customer growth.Decreased demand for electricity.
ŸWeather conditions, including storms and drought conditions, and the ability to recover significant storm restoration costs.
ŸThe 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.
ŸAvailabilityThe 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.
ŸThe ability to recover fuel and other energy costs through regulated or competitive electric rates.
ŸThe 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.
ŸNew 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.
ŸEvolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including coal ash and nuclear fuel.
ŸA 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.
ŸResolution of litigation.
ŸThe ability to constrain operation and maintenance costs.
ŸThe 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.
ŸChanges in technology, particularly with respect to energy storage and new, developing, alternative or distributed sources of generation.
ŸThe 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.
ŸVolatility and changes in markets for capacity and electricity, coal and other energy-related commodities, particularly changes in the price of natural gas.
ŸChanges in utility regulation and the allocation of costs within regional transmission organizations,RTOs including ERCOT, PJM and SPP.
ŸThe 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.
ŸActions of rating agencies, including changes in the ratings of debt.
ŸThe 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.
ŸAccounting pronouncementsstandards periodically issued by accounting standard-setting bodies.

v



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 20162018 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.


vvi









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


EXECUTIVE OVERVIEW


Customer Demand


AEP’s weather-normalized retail sales volumes for the third quarter of 2017 decreased by 0.7%2019 were flat compared to the third quarter of 2016.2018. AEP’s third quarter 20172019 industrial sales increaseddecreased by 1.7%1.1% compared to the third quarter of 2016.2018. The growthdecline in industrial sales was spread across many industriesmost operating companies and most operating companies.industries outside of the oil and gas sector. Weather-normalized residential sales decreased 2.4%increased 0.7% while weather-normalized commercial sales increased by 0.4% in the third quarter of 20172019 compared to 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 2016.2018.


AEP’s weather-normalized retail sales volumes for the nine months ended September 30, 20172019 decreased by 0.4%0.6% compared to the nine months ended September 30, 2016.2018. AEP’s industrial sales volumes for the nine months ended September 30, 2017 increased 1.6%2019 decreased 1.4% compared to the nine months ended September 30, 2016.2018. The growthdecline in industrial sales was spread across many industriesmost operating companies and most operating companies.industries outside of the oil and gas sector. Weather-normalized residential and commercial sales decreased 1.5% and 1.4%, respectively,0.7% for the nine months ended September 30, 20172019 compared to the nine months ended September 30, 2016.2018, while weather-normalized residential sales increased by 0.2%.


Merchant Generation AssetsRegulatory Matters


In September 2016, AEP signed an agreement to sell Darby, Gavin, LawrenceburgAEP’s public utility subsidiaries are involved in rate 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 proceeds fromregulatory proceedings at the transaction were approximately $1.2 billion in cash after taxes, repayment of debt associated with these assetsFERC 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 included in the sale transaction have been recorded as Assets Held for Sale and Liabilities Held for Sale, respectively,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.
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% return on common equity. In July and August 2019, PUCT Staff and various intervenors filed testimony that includes recommended disallowances that could potentially result in write-offs exceeding $450 million. The PUCT staff's recommended disallowances primarily consisted of $85 million in capital incentives and $26 million for capitalized vegetation management expenses.  The intervenors recommended disallowances primarily consisted of (a) $173 million for a newly constructed transmission operations center and other service centers, (b) $94 million for Hurricane Harvey costs, (c) $36 million for capitalized cross arms and (d) $21 million for capitalized plant costs related to unreimbursed damages to assets caused by third-parties.  In addition, one intervenor recommended AEP Texas refund $115 million of Excess ADIT, which includes $2 million in interest, related to previously owned deregulated generation assets. AEP Texas recorded $113 million as a favorable adjustment to income tax expense in 2017 as a result of Tax Reform. The PUCT is expected to issue an order on the case by the first quarter of 2020.

In May 2019, I&M filed a request with the IURC for a $172 million annual increase. The requested increase in Indiana rates would be phased in through January 2021 and is based upon a proposed 10.5% return on common equity.  In August 2019, various intervenors filed testimony that includes recommended disallowances that could potentially result in write-offs of $41 million related to the remaining book value of existing Indiana jurisdictional meters and $11 million associated with certain Cook Plant study costs. The IURC is expected to issue an order on the case by the first quarter of 2020.



Management continues to evaluate potential alternatives
Virginia Legislation Affecting Earnings Reviews - In March 2018, Virginia enacted legislation requiring APCo to file its next generation and distribution base rate case by March 31, 2020 using 2017, 2018 and 2019 test years (triennial review). Triennial reviews are subject to an earnings test which provides that 70% of any earnings exceeding 70 basis points over the Virginia SCC authorized return on common equity would be refunded to customers or be used to lower APCo’s Virginia retail base rates on a prospective basis. The Virginia legislation also states that, under certain circumstances, costs associated with asset impairments related to early retirement determinations made by a utility for generation facilities fueled by coal, natural gas or oil or for automated meters be considered fully recovered in the period recorded. Management has reviewed APCo’s actual and forecasted earnings for the triennial period and concluded that it is not probable, but is reasonably possible, that APCo will over-earn in Virginia during the 2017-2019 triennial period. Due to various uncertainties, including weather, storm restoration, weather-normalized demand and potential customer shopping during 2019, management cannot estimate a range of potential APCo Virginia over-earnings during the 2017-2019 triennial period.

Virginia Staff Depreciation Study Request - In November 2018, Virginia staff recommended that APCo implement new Virginia jurisdictional depreciation rates effective January 1, 2018 based on APCo’s depreciation study that was prepared at Virginia staff’s request using December 31, 2017 APCo property balances. Implementation of those depreciation rates would result in a $21 million pretax increase in annual depreciation expense with no corresponding increase in retail base rates. In December 2018, APCo submitted a response to the Virginia Staff stating that it was inappropriate for APCo to change Virginia depreciation rates in advance of APCo’s triennial review, citing the Virginia SCC’s November 2014 order to not change APCo’s Virginia depreciation rates until APCo’s next base rate case/review.

2020 Increase in West Virginia Retail Rates for WPCo 17.5% Merchant Share of Mitchell Plant - In January 2015, the WVPSC approved a settlement agreement in which 82.5% of the costs associated with WPCo’s acquired interest were prospectively reflected in retail rates with the remaining 17.5% of costs associated with the acquired interest to be included in rates starting January 2020. APCo and WPCo file joint retail rates in West Virginia. In June 2019, APCo and WPCo filed with the WVPSC to increase each company’s retail rates (through a surcharge) starting January 1, 2020 to reflect the recovery of WPCo’s remaining 17.5% interest in the Mitchell Plant. The joint filing will increase APCo’s and WPCo’s combined West Virginia retail rates by approximately $21 million annually.

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 August 2018, SWEPCo filed a Motion for Reconsideration at the Court of Appeals, which was denied. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court. In May 2019, various intervenors filed replies to the petition. In July 2019, SWEPCo filed its response to these briefs. The Texas Supreme Court has requested full briefing by the parties. SWEPCo’s initial brief is due in October 2019. Response briefs are due in November 2019 and SWEPCo’s reply brief is due in December 2019. As of September 30, 2019, the net book value of Turk Plant was $1.5 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 which offers incentives for power-generating facilities with zero or reduced carbon emissions was signed into law by the Ohio Governor.  The clean energy legislation phases out current energy efficiency and renewable mandates no later than 2020 and after 2026, respectively.  The bill provides for the remaining merchant generation assets. These potential alternatives may include, but are not limitedrecovery of existing renewable energy contracts on a bypassable basis through 2032. The clean energy legislation also includes a provision for recovery of OVEC costs through 2030 which will be allocated to transferall electric distribution utilities on a non-bypassable basis.  OPCo’s Inter-Company Power Agreement for OVEC terminates in June 2040. To the extent that OPCo is unable to recover the costs of renewable energy contracts on a bypassable basis by the end of 2032, recover costs of OVEC after 2030 or sale of AEP’s ownership interests, or a wind down of merchant coal-fired generation fleet operations. Management has not set a specific time frame for a decision on these assets. These alternatives could result in additional losses whichfully recover energy efficiency costs through 2020 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.

The following tables show the Registrants’ completed and pending base rate case proceedings in 2019. See Note 4 - Rate Matters for additional information.

Completed Base Rate Case Proceedings
    Approved Revenue Approved New Rates
Company Jurisdiction Requirement Increase ROE Effective
    (in millions)    
APCo West Virginia $35.8
 9.75% March 2019
WPCo West Virginia 8.4
 9.75% March 2019
PSO Oklahoma 46.0
 9.4% April 2019

Pending Base Rate Case Proceedings
          Commission Staff/
    Filing Requested Revenue Requested Intervenor Range of
Company Jurisdiction Date Requirement Increase ROE Recommended ROE
      (in millions)    
SWEPCo (a) Arkansas February 2019 $67.0
 10.5% 9% - 9.5%
AEP Texas Texas May 2019 56.0
 10.5% 9% - 9.35%
I&M Indiana May 2019 172.0
 10.5% 9% - 9.73%
I&M Michigan June 2019 58.4
 10.5% 9.1% - 9.75%

(a)In October 2019, SWEPCo, the APSC staff and various intervenors filed a stipulation and settlement agreement with the APSC that included a base rate increase of $24 million based upon a 9.45% return on common equity. See “2019 Arkansas Base Rate Case” section of Note 4 for additional information.

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.

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. AEP paid $583 million in cash and acquired a 50% ownership interest in five non-consolidated joint ventures with net assets valued at $406 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. The wind generation portfolio includes seven wind farms with long-term PPAs for 100% of their energy production. Five of the 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. See “Acquisitions” section of Note 6 for additional information.


In July 2019, AEP acquired a 75% interest, or 227 MWs, in Santa Rita East for approximately $356 million. The project is located in west Texas and was placed in-service in July 2019. Long-term virtual power purchase agreements are in place with nonaffiliates for the project’s generation. See “Acquisitions” section of Note 6 for additional information.

As of September 30, 2017, these2019, subsidiaries havewithin AEP’s Generation & Marketing segment had approximately 1481,396 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, 2017,2019, these subsidiaries havehad approximately 4254 MWs of renewable generation projects under construction andwith total estimated capital costs of $54$67 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 September 2018, OPCo, consistent with its commitment in the previously approved PPA application, submitted a filing with the PUCO demonstrating a need for up to 900 MWs of economically beneficial renewable resources in Ohio. This filing was followed by a separate filing for two solar Renewable Energy Purchase Agreements totaling 400 MWs. In January 2019, PUCO staff recommended that the PUCO reject OPCo’s request. If approved, the solar generation facilities are expected to be operational by the end of 2021.

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 approval to acquire the North Central Wind Energy Facilities, comprised of three Oklahoma wind facilities totaling 1,485 MWs, on a fixed cost turn-key basis at completion.  Subject to regulatory approval, PSO will own 45.5% and SWEPCo will own 55.5% of the project, is estimatedwhich will cost approximately $2 billion.  Two wind facilities, totaling 1,286 MWs, would qualify for 80% of the federal PTC with year-end 2021 in-service dates.  The third wind facility (199 MWs) would qualify for 100% of the PTC with a year-end 2020 in-service date. The acquisition can be scaled, subject to be $4.5 billioncommercial limitation, to align with individual state resource needs and will serve both retail and FERC wholesale load.approvals. Hearings are scheduled for the first quarter of 2020. PSO and SWEPCo will haveare seeking regulatory approvals by July 2020.

Racine

A project to reconstruct a 30% and 70% ownership share, respectively, in these assets. The wind generating facility is located in Oklahoma and, if approved by all state commissions, is anticipated to be in-service by the end of 2020. In July 2017, the LPSC approved SWEPCo’s request for an exemption to the Market Based Mechanism. In August 2017, the Oklahoma Attorney General filed a motion to dismiss with the OCC. In August 2017, the motion to dismiss was denied by the OCC. Hearingsdefective dam structure at the APSC, LPSC, OCC and PUCT are scheduledRacine began in the first quarter of 2018.

Hurricane Harvey

In August2017.  Due to a significant increase in estimated costs to complete the reconstruction project, AEP recorded impairments in 2017 Hurricane Harvey hit the coast of Texas, causing power outagesand 2018.  See Note 7 - Dispositions and Impairments in the AEP Texas service territory. As restoration efforts are ongoing, AEP Texas’ total costs related2018 Annual Report for additional information.

Due 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 currentlyweather-related delays in the early stagesfirst quarter of analyzing the impact of potential insurance claims and recoveries and,2019, reconstruction activities at this time, cannot estimate this amount. Any future insurance recoveries received willRacine are now estimated to 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 operationscompleted in the third quarterfirst half of 2017. If2020. AEP expects to incur additional capital expenditures to complete the ultimate costsreconstruction project, at which point the fair value of the incident are not recovered by insurance or through the regulatory process, it could have an adverse effect on future net income, cash flows and financial condition.

Merchant Portion of Turk Plant

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

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas 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, the net book value of Turk Plant was $1.5 billion, beforeonce complete. Future revisions in 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.

If SWEPCo cannot ultimately recover its investment and expenses related to the Turk Plant, itestimates or delays in completion could result in additional losses which 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 2024Dolet Hills Lignite Company Operations


In March 2016,During the second quarter of 2019, Dolet Hills Power Station switched to 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. Consistent with the terms of a modified and approved stipulation agreement, and based upon a September 2016 PUCO order, in November 2016, OPCo refiledseasonal operational strategy. DHLC’s mining operation will continue year-round but will reduce its amended ESP extension application and supporting testimony. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Renewable Resource Rider.

In August 2017, OPCo and various intervenors filed a stipulation agreement with the PUCO. The stipulation extends the term of the ESP through May 2024 and includes: (a) an extension of the OVEC PPA rider, (b) a proposed 10% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) rate caps related to OPCo’s DIR ranging from $215 million to $290 million for the periods 2018 through 2021, (e) the addition of various new riders, including a Smart City Rider and a Renewable Generation Rider, (f) a decrease in annual depreciation rates based on a depreciation study using data through December 2015 and (g) amortization of approximately $24 million annually beginning January 2018 of OPCo’s excess distribution accumulated depreciation reserve, which was $239 million as of December 31, 2015. Upon PUCO approval of the stipulation, 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.

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. 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.  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 ownershiplignite output. SWEPCo’s 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 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 recoverednet investment in the riderDolet Hills Power Station is $129 million 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.

2017 Indiana Base Rate Case

In July 2017, I&M filed a request with the IURC for a $263 million annual increase in Indiana rates based upon a proposed 10.6% return on common equity with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increase would be subject to a temporary offsetting $23 million annual reduction to customer bills through December 2018 for a credit adjustment rider related to the timing of estimated in-service dates of certain capital expenditures.  The proposed annual increase includes $78 million related to increased annual depreciation rates and an $11 million increase related to the amortization of certain Cook Plant and Rockport Plant regulatory assets. The increase in depreciation rates includes a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant, including the Cook Plant Life Cycle Management Project. A hearing at the IURC is scheduled for January 2018. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2017 Michigan Base Rate Case

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 resultmaximum exposure 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 Planttotal investment 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 $4DHLC is $153 million. Management will continue to vigorously defend against these claims. Ifmonitor 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 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 behalfeconomic viability 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.Dolet Hills Power Station and DHLC.


If any of these costs are not recoverable, 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. 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 entered a stipulated order to stay the lease litigation to afford time for the parties in the lease litigation to engage in settlement discussions. 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 is unable tocannot determine a range of potential losses that are reasonably possible of occurring.


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.  The complaint seeks injunctive relief and damages.  Management will continue to defend against the claims. Management is unable to determine a range of potential loss 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, 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.
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, 2017,2019, the AEP System had a total generating capacity of approximately 25,60025,500 MWs, of which approximately 13,50013,200 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 investment to meet these existing and proposed requirements ranges from approximately $2.2$550 million to $1.1 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 theplants or units listed below was approved for recovery, except for $338 million. Management is seeking or will seek recovery of theplants previously retired that have a remaining net book value associated with these plants in future rate proceedings.as of September 30, 2019.
 Generating Amounts Pending Generating Amounts Pending
Company Plant Name and Unit Capacity Regulatory Approval Plant Name and Unit Capacity Regulatory Approval
   (in MWs)  (in millions)   (in MWs)  (in millions)
APCo Kanawha River Plant 400
 $42.3
 Kanawha River Plant 400
 $43.8
APCo Clinch River Plant, Unit 3 235
 32.7
 Clinch River Plant, Unit 3 235
 31.8
APCo (a) Clinch River Plant, Units 1 and 2 470
 31.8
 Clinch River Plant, Units 1 and 2 470
 29.2
APCo Sporn Plant 600
 17.2
 Sporn Plant, Units 1 and 3 300
 15.6
APCo Glen Lyn Plant 335
 13.4
 Glen Lyn Plant 335
 13.5
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
SWEPCo (b) Welsh Plant, Unit 2 528
 50.6
Total   4,033
 $338.3
   2,268
 $184.5


(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, UnitUnits 1 and Unit 2 began operations as natural gas units in February 2016 and April 2016, respectively.2016.
(b)I&M requestedIn October 2019, SWEPCo filed a stipulation and settlement agreement with the APSC, which includes recovery of the Indiana (approximately 65%) and Michigan (approximately 14%)remaining $15 million Arkansas 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 22. An order from the APSC is expected in the 2016 Texas Base Rate Case. This regulatory asset is pending regulatory approval.fourth quarter of 2019.


In January 2017, Dayton Power and Light Company announced the future retirementManagement is seeking or will seek recovery 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 ofremaining net book value in future rate proceedings. To the Stuart Plant, Units 1-4. As of September 30, 2017, AGR’sextent the net book value of the Stuart Plant, Units 1-4 was zero.

To the extent existingthese generation assets and the cost of new equipment and converted facilities areis 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 SCR technology at Rockport Plant, Unit 2 until March 2020, pending resolution ofJune 2020.

In May 2019, the motion.  AEP also proposes to retire Conesville Plant, Units 5 and 6 by December 31, 2022 and to retire one Rockport Plant unit by December 31, 2028.


AEP is seekingparties 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 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.


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 NAAQS for SO2 in 2010, PM in 2012 and ozone in 2015. The existing standards for NO2 and SO2 were retained after review by the Federal EPA in 2018 and 2019, respectively. Implementation of these standards is underway. States are still in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the 2010 SO2 NAAQS and may develop additional requirements for AEP’s facilities as a result of those evaluations.

In April 2017,2016, the Federal EPA requestedcompleted an integrated review plan for the 2012 PM standard. Work is currently underway on scientific, risk and policy assessments necessary to develop a stayproposed rule, which is anticipated in 2021.

The Federal EPA finalized non-attainment designations for the 2015 ozone standard in 2018. The Federal EPA has confirmed that for states included in the CSAPR program, there are no additional interstate transport obligations, as all areas of proceedingsthe country are expected to attain the 2008 ozone standard before 2023. Challenges to the 2015 ozone standard and the Federal EPA’s determination that CSAPR satisfies certain states’ interstate transport obligations are pending in the U.S. Court of Appeals for the District of Columbia Circuit where challenges toCircuit. In 2018, the Federal EPA proposed final requirements for implementing the 2015 ozone standard, are pending, to allow reconsideration of that standard by the new administration. The Federal EPA initially announced a one-year delaywhich have been challenged in the designationU.S. Court of ozone non-attainment areas, but withdrew that decision. Final designations were due October 1, 2017, but have not yet been announced.Appeals for the District of Columbia Circuit. 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.


TheIn 2012, the Federal EPA proposed disapproval of a portion of the regional haze SIPsSIP in a few states, including Arkansas and Texas.finalized a FIP in 2016. In March 2012, the Federal EPA disapproved certain portions of the Arkansas regional haze SIP. In April 2015, the Federal EPA published a proposed FIP to replace the disapproved portions, including revised BART determinations for the Flint Creek Plant that were 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 in 2018, the Federal EPA has proposed to approve that SIP approved the


revision. Arkansas finalized a separate action in 2017 to revise the SO2 BART determinations and in September 2019, the Federal EPA have askedapproved the Eighth Circuit to continue to hold litigationArkansas SO2 BART determinations. SWEPCo’s Flint Creek Plant is already in abeyance until October 31, 2017 to facilitate settlement discussions. Management cannot predictcompliance with the outcome of these proceedings.applicable requirements.


In January 2016, theThe Federal EPA also 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 by various intervenors 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. Management supports the intrastate trading program contained in the FIP as a compliance with CSAPR programs as satisfaction of the BART requirements.alternative to source-specific controls.


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. The ruleIn 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. Management has been challenged in the courts and petitions for administrative reconsideration have been filed. The rule remains in effect. Management is complyingcomplied with the more stringent ozone season budgets while these petitions are being considered.were pending.




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. The rule remainscomment period on this proposal ended in effect.April 2019.



Climate Change, CO2 Regulation and Energy Policy


In 2015, the Federal EPA published the final CO2 emissions standards for new, modified and reconstructed fossil generating units, and final guidelines for the development of state plans to regulate CO2 emissions from existing sources, known as the Clean Power Plan (CPP).

In 2016, the U.S. Supreme Court issued a stay on the final CPP, including all of the deadlines for submission of initial or final state plans 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 2017, the President issued an Executive Order directing the Federal EPA to reconsider the CPP and the associated standards for new sources. The Federal EPA filed a motion to hold the challenges to the CPP in abeyance pending reconsideration. In September 2019, following the Federal EPA’s finalization of rescission of the CPP and promulgation of the replacement rule, the Court of Appeals for the District of Columbia Circuit dismissed the challenges.

In July 2019, the Federal EPA finalized the Affordable Clean Energy (ACE) rule to replace 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 burn coal for more than 10% of the annual 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 the degree of emission reduction achievable through each applicable measure, together with consideration of certain site-specific factors and the unit’s remaining useful life. State plans are required to be submitted within three years, and the Federal EPA has up to two years to review and approve or disapprove the plan and adopt a federal plan. The final ACE rule has been challenged in the courts.

In 2018, the Federal EPA filed a proposed rule revising the standards for new sources and determined that partial carbon capture and storage is not the best system of emission reduction because it is not available throughout the U.S. and is not cost-effective. Management continues to actively monitor these rulemaking activities.

AEP has taken action to reduce and offset CO2 emissions from its generating fleet and 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.  Management is taking steps to comply with these requirements, including increasing wind and solar installations, andpurchasing renewable power purchases and broadening the AEP System’s portfolio of energy efficiency programs.


In October 2015, the Federal EPA published the final standards forSeptember 2019, AEP announced new modifiedintermediate and reconstructed fossil fired steam generating units and combustion turbines, and final guidelines for the development of state plans to regulatelong-term 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 on the final CPP, including all of the deadlines for submission of initial or final state plans. The stay will remain in effect until a final decision is issued by the U.S. Court of Appeals for the District of Columbia Circuit and the U.S. Supreme Court considers any petition for review. In April 2017, the Federal EPA withdrew its previously issued proposals for model trading rules and a CEIP.


In March 2017, the Federal EPA filed in the U.S. Court of Appeals for the District of Columbia Circuit notice of: (a) an Executive Order from the President of the United States titled “Promoting Energy Independence and Economic Growth” directing the Federal EPA to review the CPP and related rules; (b) the Federal EPA’s initiation of a review of the CPP and (c) a forthcoming rulemaking related to the CPP consistent with the Executive Order, if the Federal EPA determines appropriate. In this same filing, the Federal EPA also presented a motion to hold the litigation in abeyance until 30 days after the conclusion of review 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 issued a proposed rule repealing the CPP and withdrawing the legal memoranda issued in connection with the rule. The Federal EPA has re-examined its legal interpretation of the “best system of emission reduction” and found thatreduction 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 2018 were approximately 69 million metric tons, a 59% reduction from AEP’s 2000 CO2 emissions. AEP has made significant progress in reducing CO2 emissions from power generation fleet and other systems thatexpect its emissions to continue to decline. AEP’s aspirational emissions goal is zero 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.


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 four facilities. Alternative source demonstrations have been prepared in accordance with the rule at four other 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 issued the July 2018 rule that modifies certain compliance deadlines and other requirements in the 2015 rule.  In December 2018, challengers filed a motion for partial stay or 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 the Federal EPA’s motion, and further rulemaking to approve such programs if they are no less stringent thanaddress the minimum federal standards.court’s decisions is expected to be completed near the end of 2019.

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. The Federal EPA may also enforce compliance withopened a rulemaking docket to solicit information to determine whether it should provide additional clarification of the minimum standards until a state programscope 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 approvedunable to predict the impact of this guidance or if states fail to adopt their own programs. In September 2017, the Federal EPA granted industry petitions to reconsider the CCR rule and asked that litigation regarding the rule be held in abeyance. The court has ordered oral argument to proceed in November 2017 and that the motion for abeyance be addressed during oral argument.outcome of these cases on AEP’s facilities.


Because AEP currently uses surface impoundments and landfills to manage CCR materials at generating facilities, significant costs will be incurred to upgrade or close and replace these existing facilities at some pointand conduct any required remedial actions. Closure and post-closure costs have been included in ARO in accordance with the requirements in the future as the new rule is implemented. Management recorded a $95 million increase in asset retirement obligations in the second quarterfinal rule. This estimate does not include costs of 2015 primarily due to the publication of the final rule.groundwater remediation, where required. Management will continue to evaluate the rule’s impact on operations.


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 over the next fiveand have been incorporated into permits at several AEP facilities. Additional AEP facilities are reviewing these requirements as their wastewater discharge permits are renewed and making appropriate adjustments 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.their intake structures.


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 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, was issuedto allow for reconsideration. A revised rule could be proposed later in September 2017.2019. In April 2019, the Fifth Circuit vacated the standards for landfill leachate and legacy wastewater, and remanded them to the Federal EPA for reconsideration.  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.


In June 2015, the Federal EPA and the U.S. Army Corps of Engineers jointly issued a final rule to clarify the scope of the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases. The CWA provides for federal jurisdiction over “navigable waters” defined as “the waters of the United States.” This jurisdictional definition applies to all CWA programs, potentially impacting generation, transmission and distribution permitting and compliance requirements. Among those programs are permits for wastewater and storm water discharges, permits for impacts to wetlands and water bodies and oil spill prevention planning. The final definition continues to recognize traditional navigable waters of the U.S. as jurisdictional as well as certain exclusions. The rule also contains a number of new specific definitions and criteria for determining whether certain other waters are jurisdictional because of a “significant nexus.” Management believes that clarity and efficiency in the permitting process is needed. Management remains concerned that the rule introduces new concepts and could subject more of AEP’s operations to CWA jurisdiction, thereby increasing the time and complexity of permitting. The final rule is being challenged in both courts of appeal and district courts. Challengers include industry associations of which AEP is a member. The U.S. Court of Appeals for the Sixth Circuit granted a nationwide stay of the rule pending jurisdictional determinations. In February 2016, the U.S. Court of Appeals for the Sixth Circuit issued a decision holding that it has exclusive jurisdiction to decide the challenges to the “waters of the United States” rule. Industry, state and related associations 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 appealed to the U.S. Supreme Court, which granted certiorari to review 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 rule and the appeal on the jurisdictional issue continues.

In March 2017,December 2018, the Federal EPA published a notice of intent to reviewand the rule and provide an advanced notice of a proposed rulemaking consistent with the Executive Order of the President of the United States directing the Federal EPA and U.S. Army Corps of Engineers to review and rescind or revise the rule. In June 2017, the agencies signedreleased a notice of proposed rule to rescindreplace the definition in the 2015 rule. The comment period for this proposal ended in April 2019. In September 2019, the Federal EPA announced the final repeal of the 2015 definition of “waters of the United States” and recodification of the regulatory definition that was adopted in June 2015, and to re-codify the definition of that phrase as it existed immediatelyplace prior to that action. This action would effectively retain the status quo until a new rule is adopted by the agencies.2015 rule.




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 SSO 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.
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 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.




The following table presents Earnings (Loss) Attributable to AEP Common Shareholders by segment:
Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
Three Months Ended 
September 30,
 Nine Months Ended 
September 30,
2017 2016 2017 20162019 2018 2019 2018
(in millions)(in millions)
Vertically Integrated Utilities$286.3
 $342.3
 $626.6
 $829.3
$437.6
 $344.2
 $917.7
 $852.2
Transmission and Distribution Utilities144.0
 155.7
 374.3
 387.8
133.7
 145.2
 421.6
 384.6
AEP Transmission Holdco75.5
 69.0
 275.7
 207.5
126.1
 73.3
 404.8
 278.4
Generation & Marketing33.7
 (1,369.2) 246.3
 (1,248.8)90.0
 5.3
 139.5
 62.3
Corporate and Other5.2
 36.4
 (11.0) 61.7
(53.9) 9.6
 (116.0) (17.1)
Earnings (Loss) Attributable to AEP Common Shareholders$544.7
 $(765.8) $1,511.9
 $237.5
Earnings Attributable to AEP Common Shareholders$733.5
 $577.6
 $1,767.6
 $1,560.4


AEP CONSOLIDATED


Third Quarter of 20172019 Compared to Third Quarter of 20162018

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$578 million in 20162018 to income of $1.5 billion$734 million in 20172019 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.

An increase in weather-related usage.
An increase in transmission investment, which resulted in higher revenues and income.

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018

Earnings Attributable to AEP Common Shareholders increased from $1.6 billion in 2018 to $1.8 billion in 2019 primarily due to:

Favorable rate proceedings in AEP’s various jurisdictions.
An increase in transmission investment, 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.
A decrease in weather-normalized sales.
A decrease in FERC wholesale municipal and cooperative revenues.
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.


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





VERTICALLY INTEGRATED UTILITIES
 Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
 Three Months Ended 
September 30,
 Nine Months Ended 
September 30,
Vertically Integrated Utilities 2017 2016 2017 2016 2019 2018 2019 2018
 (in millions) (in millions)
Revenues $2,482.2
 $2,556.3
 $6,893.1
 $6,927.8
 $2,645.5
 $2,636.7
 $7,172.6
 $7,393.7
Fuel and Purchased Electricity 868.6
 858.3
 2,368.9
 2,299.8
 874.2
 1,034.6
 2,430.2
 2,700.4
Gross Margin 1,613.6
 1,698.0
 4,524.2
 4,628.0
 1,771.3
 1,602.1
 4,742.4
 4,693.3
Other Operation and Maintenance 659.1
 673.0
 2,024.5
 1,926.9
 742.9
 753.7
 2,117.1
 2,197.5
Asset Impairments and Other Related Charges 
 10.5
 
 10.5
Depreciation and Amortization 288.8
 277.7
 845.1
 815.5
 364.3
 340.1
 1,079.6
 966.1
Taxes Other Than Income Taxes 105.7
 99.0
 306.2
 295.0
 117.9
 108.8
 347.1
 326.4
Operating Income 560.0
 637.8
 1,348.4
 1,580.1
 546.2
 399.5
 1,198.6
 1,203.3
Interest and Investment Income 1.3
 0.8
 5.4
 2.4
Carrying Costs Income 2.1
 0.8
 11.3
 8.1
Other Income 0.9
 4.1
 4.4
 14.2
Allowance for Equity Funds Used During Construction 7.5
 10.0
 20.0
 35.4
 12.2
 9.3
 38.9
 24.0
Non-Service Cost Components of Net Periodic Benefit Cost 17.0
 18.0
 50.8
 53.7
Interest Expense (134.9) (136.7) (406.5) (399.9) (140.6) (149.2) (422.6) (428.0)
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
Income Before Income Tax Expense (Benefit) and Equity Earnings 435.7
 281.7
 870.1
 867.2
Income Tax Expense (Benefit) (1.9) (63.1) (48.4) 12.9
Equity Earnings of Unconsolidated Subsidiary 0.8
 0.8
 2.3
 2.0
Net Income 297.3
 343.4
 639.2
 832.6
 438.4
 345.6
 920.8
 856.3
Net Income Attributable to Noncontrolling Interests 11.0
 1.1
 12.6
 3.3
 0.8
 1.4
 3.1
 4.1
Earnings Attributable to AEP Common Shareholders $286.3
 $342.3
 $626.6
 $829.3
 $437.6
 $344.2
 $917.7
 $852.2


Summary of KWh Energy Sales for Vertically Integrated Utilities
Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
Three Months Ended 
September 30,
 Nine Months Ended 
September 30,
2017 2016 2017 20162019 2018 2019 2018
(in millions of KWhs)(in millions of KWhs)
Retail: 
  
  
  
 
  
  
  
Residential8,488
 9,575
 23,226
 25,373
9,254
 8,988
 24,785
 26,105
Commercial6,701
 7,137
 18,386
 19,207
6,840
 6,723
 18,183
 18,699
Industrial8,839
 8,655
 25,792
 25,576
9,123
 9,107
 26,533
 26,757
Miscellaneous603
 634
 1,701
 1,740
641
 621
 1,734
 1,762
Total Retail(a)24,631
 26,001
 69,105
 71,896
25,858
 25,439
 71,235
 73,323
              
Wholesale (a)(b)6,837
 6,765
 19,262
 17,253
5,864
 6,432
 16,494
 17,156
              
Total KWhs31,468
 32,766
 88,367
 89,149
31,722
 31,871
 87,729
 90,479

(a)2018 KWhs have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail KWhs. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.
(b)Includes off-system sales,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,
Three Months Ended 
September 30,
 Nine Months Ended 
September 30,
2017 2016 2017 20162019 2018 2019 2018
(in degree days)(in degree days)
Eastern Region 
  
  
  
 
  
  
  
Actual Heating (a)

 
 1,266
 1,684

 
 1,670
 1,844
Normal Heating (b)
4
 5
 1,757
 1,775
5
 5
 1,742
 1,745
              
Actual Cooling (c)
698
 954
 1,034
 1,306
937
 878
 1,316
 1,364
Normal Cooling (b)
731
 726
 1,060
 1,058
732
 730
 1,070
 1,063
              
Western Region 
  
  
  
 
  
  
  
Actual Heating (a)

 
 539
 685

 
 967
 974
Normal Heating (b)
1
 1
 926
 927
1
 1
 902
 908
              
Actual Cooling (c)
1,281
 1,519
 2,000
 2,262
1,572
 1,443
 2,234
 2,380
Normal Cooling (b)
1,404
 1,400
 2,124
 2,116
1,402
 1,402
 2,129
 2,121


(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 20172019 Compared to Third Quarter of 20162018
Reconciliation of Third Quarter of 2016 to Third Quarter of 2017
Reconciliation of Third Quarter of 2018 to Third Quarter of 2019Reconciliation of Third Quarter of 2018 to Third Quarter of 2019
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities(in millions)
    
Third Quarter of 2016 $342.3
Third Quarter of 2018 $344.2
  
  
Changes in Gross Margin:  
  
Retail Margins (74.1) 145.1
Off-system Sales (0.8)
Margins from Off-system Sales (0.9)
Transmission Revenues (7.6) 23.8
Other Revenues (1.9) 1.2
Total Change in Gross Margin (84.4) 169.2
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance 13.9
 10.8
Asset Impairments and Other Related Charges 10.5
Depreciation and Amortization (11.1) (24.2)
Taxes Other Than Income Taxes (6.7) (9.1)
Interest and Investment Income 0.5
Carrying Costs Income 1.3
Other Income (3.2)
Allowance for Equity Funds Used During Construction (2.5) 2.9
Non-Service Cost Components of Net Periodic Pension Cost (1.0)
Interest Expense 1.8
 8.6
Total Change in Expenses and Other 7.7
 (15.2)
  
  
Income Tax Expense 32.9
Equity Earnings (Loss) of Unconsolidated Subsidiary (2.3)
Net Income Attributable to Noncontrolling Interest (9.9)
Income Tax Expense (Benefit) (61.2)
Net Income Attributable to Noncontrolling Interests 0.6
    
Third Quarter of 2017 $286.3
Third Quarter of 2019 $437.6


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 $74
Retail Margins increased $145 million primarily due to the following:
A $91 million increase at APCo and WPCo due to a 2018 reduction in the following:
deferred fuel under recovery balance as a result of the 2018 West Virginia Tax Reform settlement. This increase was partially offset in Income Tax Expense (Benefit) below.
An $80A $23 million decreaseincrease in weather-related usage primarily in the eastern and western regions.residential class.
A $15 million increase at APCo in deferred fuel related to recoverable PJM expenses that were offset below.
A $10 million increase due to 2018 Virginia legislation which increased non-recoverable fuel expense at APCo in the prior year.
A $4 million increase in weather-normalized retail margins across all classes.
The effect of rate proceedings in AEP’s service territories which included:
A $17$19 million decrease forincrease from rate proceedings at I&M. This increase was partially offset in other expense items below.
A $14 million increase at PSO due to new base rates implemented in April 2019.
A $10 million increase at APCo and WPCo due to revenue primarily from rate riders in West Virginia. This increase was offset in other expense items below.
An $8 million increase related to rider revenues at I&M, primarily due to higher rates implementedthe timing of the Indiana PJM/OSS rider recovery. This increase was partially offset in 2016 associated with interim rates.other expense items below.
A $6$7 million decrease primarilyincrease at APCo and WPCo due to a decrease in ratesbase rate increases in West Virginia and Virginia.
For the rate decreases described above, $4 million relate to riders/trackers which have corresponding decreasesimplemented in expense items below.March 2019.
These decreasesincreases were partially offset by:
The effect of rate proceedings in AEP’s service territories which included:
An $11 million increase from rate proceedings in the Indiana service territory.
An $11 million increase primarily due to rider revenue increases in Louisiana, partially offset in expense items below.
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$74 million decrease due to a net favorable accrual for SPP sponsor-funded transmission upgradescustomer refunds related to Tax Reform. This decrease was partially offset in third quarter 2016.Income Tax Expense (Benefit) below.



Transmission Revenues increased $24 million primarily due to the following:
A $16 million increase due to SPP provisions for refund recorded in 2018.
A $16 million increase primarily due to 2018 PJM provisions for refunds mainly at APCo.
These increases were partially offset by:
An $8 million decrease primarily due to a reduction in SPP Base Plan Funding revenues and a decrease in nonaffiliated transmission services.

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


Other Operation and Maintenance expenses decreased $14
Other Operation and Maintenance expenses decreased $11 million primarily due to the following:
A $40 million decrease at APCo and WPCo due to the following:
extinguishment of certain regulatory asset balances as agreed to within the 2018 West Virginia Tax Reform settlement.
A $15$12 million decrease in employee-related expenses.planned plant outage and maintenance expenses primarily at APCo and I&M.
A $10$9 million decrease due to Wind Catcher Project expenses incurred in 2018 for SWEPCo and PSO.
A $3 million decrease in PJMrecoverable expenses primarily associated with Energy Efficiency/Demand Response and SPP transmission services expense not recovered through riders/trackers.
A $6 million decrease in storm expenses primarilyfully recovered in the APCo region.rate riders/trackers within Gross Margin above.
These decreases were partially offset by:
A $5$45 million increase due to PJM transmission services including the annual formula rate true-up.
An $8 million increase due to the modification of the NSR consent decree impacting I&M and AEGCo.
A $2 million increase due to North Central Wind Catcher ProjectEnergy Facilities expenses for PSOSWEPCo and PSO.
Depreciation and Amortization expenses increased $24 millionprimarily due to a higher depreciable base and increased depreciation rates approved at APCo, I&M and SWEPCo.
Taxes Other Than Income Taxes increased $9 million primarily due to the following:
A $5 million increase in property taxes driven by an increase in utility plant.
A $5 million increase in nuclear expensesWest Virginia business and occupational taxes at Cook Plant.
A $3 million increase in vegetation management expenses, primarily at PSOAPCo and SWEPCo.WPCo.
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 is offset by a decrease in Income Tax Expense.
Interest Expense decreased $9 million primarily due to lower interest rates on outstanding long-term debt at I&M and SWEPCo.
Income TaxExpense (Benefit) increased $61 million primarily due to the one time recognition of $86 million of additional amortization of Excess ADIT as a result of the West Virginia Tax Reform order received in the third quarter of 2018. The additional excess amortization from the West Virginia Tax Reform order was partially offset in Retail Margins and Other Operation and Maintenance expenses above.





Nine Months Ended September 30, 20172019 Compared to Nine Months Ended September 30, 20162018
Reconciliation of Nine Months Ended September 30, 2016 to Nine Months Ended September 30, 2017
Reconciliation of Nine Months Ended September 30, 2018 to Nine Months Ended September 30, 2019Reconciliation of Nine Months Ended September 30, 2018 to Nine Months Ended September 30, 2019
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities(in millions)
    
Nine Months Ended September 30, 2016 $829.3
Nine Months Ended September 30, 2018 $852.2
  
  
Changes in Gross Margin:  
  
Retail Margins (123.9) 75.4
Off-system Sales 7.4
Margins from Off-system Sales (10.4)
Transmission Revenues 11.0
 (16.4)
Other Revenues 1.7
 0.5
Total Change in Gross Margin (103.8) 49.1
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance (97.6) 80.4
Asset Impairments and Other Related Charges 10.5
Depreciation and Amortization (29.6) (113.5)
Taxes Other Than Income Taxes (11.2) (20.7)
Interest and Investment Income 3.0
Carrying Costs Income 3.2
Other Income (9.8)
Allowance for Equity Funds Used During Construction (15.4) 14.9
Non-Service Cost Components of Net Periodic Pension Cost (2.9)
Interest Expense (6.6) 5.4
Total Change in Expenses and Other (143.7) (46.2)
  
  
Income Tax Expense 63.5
Equity Earnings (Loss) of Unconsolidated Subsidiary (9.4)
Net Income Attributable to Noncontrolling Interest (9.3)
Income Tax Expense (Benefit) 61.3
Equity Earnings of Unconsolidated Subsidiary 0.3
Net Income Attributable to Noncontrolling Interests 1.0
    
Nine Months Ended September 30, 2017 $626.6
Nine Months Ended September 30, 2019 $917.7


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
Retail Margins increased $75 million primarily due to the following:
A $91 million increase at APCo and WPCo due to a 2018 reduction in the following:
deferred fuel under recovery balance as a result of the 2018 West Virginia Tax Reform settlement. This increase was partially offset in Income Tax Expense (Benefit) below.
A $164$12 million decreaseincrease at APCo in weather-related usagedeferred fuel related to recoverable PJM expenses that were offset below.
A $10 million increase due to 2018 Virginia legislation which increased non-recoverable fuel expense at APCo in the eastern and western regions.prior year.
A $42$6 million decrease in FERC generation wholesale municipal and cooperative revenues primarily due to an annual formula rate true-up and adjustments at I&M in fuel-related expenses due to timing of recovery for fuel and SWEPCo.other variable production costs related to wholesale contracts.
The effect of rate proceedings in AEP’s service territories which included:
A $14 million decrease primarily due to prior year recognition of deferred billing in West Virginia as approved by the WVPSC.
A $9 million net decrease for PSO primarily due to revenue decreases associated with interim base rates implemented in 2016.
For the rate decreases described above, $1 million relate to riders/trackers which have corresponding decreases in expense items below.
A $5 million decrease in weather-normalized margins.
These decreases were partially offset by:
The effect of rate proceedings in AEP’s service territories which included:
A $42$94 million increase from rate proceedings in the Indiana service territory.
A $33at I&M, inclusive of a $30 million increasedecrease due to rider revenue increases in Louisiana, Texas and Arkansas,the impact of Tax Reform. This increase was partially offset in other expense items below.
A $6$35 million increase for KGPCoat PSO due to revenue increases from rate riders/trackers.new base rates implemented in April 2019 and March 2018.
ForA $21 million increase related to rider revenues at I&M, primarily due to the rate increases described above, $37 million relate to riders/trackers which have corresponding increasestiming of the Indiana PJM/OSS rider recovery. This increase was partially offset in other expense items below.
A $17 million increase at APCo and WPCo primarily due to revenue from rate riders in West Virginia. This increase was offset in other expense items below.

A $14 million increase at APCo and WPCo due to base rate increases in West Virginia implemented in March 2019.


A $19$7 million increase at SWEPCo primarily due to reduced fuelrider and base rate revenue increases in Louisiana. The increase in rider rates had increases in other variable production costs not recovered through fuel clauses or other trackers.
Margins from Off-system Sales increased $7 million primarily due to higher market prices.
Transmission Revenues increased $11 million primarily due the following:
expense items below.
A $35$4 million increase primarily due to increases in formula rates driven by continued investment in transmission assets. This increase is partiallyrider revenues at KPCo offset in Other Operation and Maintenance expensesother expense items below.
These increases were partially offset by:
A $23$117 million decrease due to customer refunds related to Tax Reform. This decrease was partially offset in Income Tax Expense (Benefit) below.
A $73 million decrease in weather-related usage across all regions primarily in the residential class.
A $67 million decrease in weather-normalized retail margins across all classes.
Margins from Off-system Sales decreased $10 million primarily due to mid-year 2018 changes in the OSS sharing mechanism at I&M.
Transmission Revenues decreased $16 million primarily due to the following:
A $40 million decrease in SWEPCo’s annual SPP Transmission formula rate true-up.
A $12 million decrease primarily due to I&M’s annual PJM Transmission formula rate true-up and reduced net PJM Network Integration Transmission Service revenues resulting from increased affiliated transmission-related charges.true-up.
A $5An $11 million net decrease primarily due to a net favorable accrualreduction in SPP Base Plan Funding revenues.
These decreases were partially offset by:
A $36 million increase primarily due to 2018 PJM provisions for refund mainly at APCo.
A $16 million increase due to a provision for refund recorded at PSO and SWEPCo in 2018 related to certain transmission assets that management believes should not have been included in the SPP sponsor-funded transmission upgrades in third quarter 2016.formula rate.


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


Other Operation and Maintenance expenses increased $98
Other Operation and Maintenance expenses decreased $80 million primarily due to the following:
A $56 million decrease due to SPP transmission services including the annual formula rate true-up.
A $47 million decrease in planned plant outage and maintenance expenses primarily for I&M, APCo, SWEPCo and KPCo.
A $40 million decrease due to Wind Catcher Project expenses incurred in 2018 for SWEPCo and PSO.
A $40 million decrease at APCo and WPCo due to the following:
extinguishment of certain regulatory asset balances as agreed to within the 2018 West Virginia Tax Reform settlement.
A $103$25 million increasedecrease in recoverable expenses primarily PJM expensesassociated with Energy Efficiency/Demand Response and energy efficiencystorm expenses fully recovered in rate recovery riders/trackers within Gross Margin above.
A $22$10 million increasedecrease in vegetation management expenses, primarilyexpense at PSO and I&M.APCo due to lower current year amortization of certain regulatory assets that were extinguished in August 2018 as agreed to within the 2018 West Virginia Tax Reform settlement.
A $6$9 million increase duedecrease in estimated expense for claims related to a favorable land sale in 2016 in the APCo region.asbestos exposure.
These increasesdecreases were partially offset by:
A $27$92 million decreaseincrease due to PJM transmission services including the annual formula rate true-up.
A $23 million increase in employee-related expenses.
Asset Impairments and Other Related Charges decreased $11A $13 million increase at APCo due to 2019 contributions to benefit low income West Virginia residential customers as a result of the 2018 West Virginia Tax Reform settlement. This increase was offset in Income Tax Expense (Benefit) below.
An $8 million increase in storm-related expenses primarily at SWEPCo.
An $8 million increase due to the impairmentmodification of the NSR consent decree impacting I&M’s Price River Coal reserves in 2016.
&M and AEGCo.
Depreciation and Amortization expenses increased $30A $5 millionprimarily increase due to the following:North Central Wind Energy Facilities expenses for SWEPCo and PSO.
Depreciation and Amortization expenses increased $114 millionprimarily due to a higher depreciable base and increased depreciation rates approved at I&M, APCo, SWEPCo and PSO.
Taxes Other Than Income Taxes increased $21 million primarily due to the following:
A $14 million increase in property taxes driven by an increase in utility plant.
A $46$9 million increase at APCo and WPCo in West Virginia business and occupational taxes.
Other Income decreased $10 million primarily due to a decrease in carrying charges for certain riders at I&M.
Allowance for Equity Funds Used During Construction increased $15 million primarily due to the following:
A $10 million increase primarily due to higher depreciable base.various increases in equity rates at I&M, APCo and PSO and increased projects at I&M.
A $15$3 million increase due to amortizationrecent FERC audit findings.
A $2 million increase due to the FERC’s approval of capitalized software costs.a settlement agreement.
These increases were

Interest Expense decreased $5 million primarily due to the following:
A $16 million decrease due to lower interest rates on outstanding long-term debt at I&M and SWEPCo.
This decrease was 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 increasedAn $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 million primarily due to the following:
A $7 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 mainly at I&M.APCo and PSO.
Income TaxExpense (Benefit) decreased $61 million primarily due to additional amortization of Excess ADIT as a result of finalized rate orders. The excess amortization is partially offset within Gross Margin and Other Operation and Maintenance above.

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 $64 million primarily due to a decrease in pretax book income and income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine, partially offset by the recording of favorable state and federal income tax adjustments in 2016.
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 Ended 
 September 30,
 Nine Months Ended 
 September 30,
 Three Months Ended 
September 30,
 Nine Months Ended 
September 30,
Transmission and Distribution Utilities 2017 2016 2017 2016 2019 2018 2019 2018
 (in millions) (in millions)
Revenues $1,173.3
 $1,275.6
 $3,313.2
 $3,468.5
 $1,186.6
 $1,211.5
 $3,454.3
 $3,510.9
Purchased Electricity 215.7
 253.6
 626.0
 662.2
 210.1
 218.7
 603.5
 660.0
Amortization of Generation Deferrals 58.7
 66.1
 172.9
 173.0
 8.8
 56.9
 65.3
 171.9
Gross Margin 898.9
 955.9
 2,514.3
 2,633.3
 967.7
 935.9
 2,785.5
 2,679.0
Other Operation and Maintenance 303.2
 358.2
 882.5
 1,009.5
 405.8
 420.4
 1,222.1
 1,152.1
Depreciation and Amortization 182.3
 181.4
 502.4
 505.0
 209.3
 201.4
 586.4
 558.4
Taxes Other Than Income Taxes 133.6
 132.0
 387.1
 373.0
 151.8
 143.2
 437.2
 413.2
Operating Income 279.8
 284.3
 742.3
 745.8
 200.8
 170.9
 539.8
 555.3
Interest and Investment Income 1.2
 1.5
 5.6
 5.5
 1.1
 1.3
 4.2
 2.6
Carrying Costs Income 0.5
 0.9
 3.0
 4.0
 0.3
 0.2
 0.7
 1.5
Allowance for Equity Funds Used During Construction 0.9
 2.2
 6.3
 10.6
 9.8
 7.8
 22.3
 23.0
Non-Service Cost Components of Net Periodic Benefit Cost 7.7
 8.3
 22.8
 24.6
Interest Expense (61.0) (63.2) (182.5) (196.0) (63.6) (63.5) (170.8) (185.6)
Income Before Income Tax Expense 221.4
 225.7
 574.7
 569.9
Income Tax Expense 77.4
 70.0
 200.4
 182.1
Income Before Income Tax Expense (Benefit) 156.1
 125.0
 419.0
 421.4
Income Tax Expense (Benefit) 22.4
 (20.2) (2.6) 36.8
Net Income 144.0
 155.7
 374.3
 387.8
 133.7
 145.2
 421.6
 384.6
Net Income Attributable to Noncontrolling Interests 
 
 
 
 
 
 
 
Earnings Attributable to AEP Common Shareholders $144.0
 $155.7
 $374.3
 $387.8
 $133.7
 $145.2
 $421.6
 $384.6


Summary of KWh Energy Sales for Transmission and Distribution Utilities
Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
Three Months Ended 
September 30,
 Nine Months Ended 
September 30,
2017 2016 2017 20162019 2018 2019 2018
(in millions of KWhs)(in millions of KWhs)
Retail: 
  
  
  
 
  
  
  
Residential7,511
 8,325
 19,361
 20,575
8,268
 7,948
 20,614
 21,154
Commercial6,941
 7,287
 19,184
 19,676
7,219
 6,958
 19,069
 19,061
Industrial5,575
 5,518
 16,992
 16,522
5,857
 5,904
 17,492
 17,772
Miscellaneous185
 187
 516
 528
223
 209
 595
 574
Total Retail (a)(b)20,212
 21,317
 56,053
 57,301
21,567
 21,019
 57,770
 58,561
              
Wholesale (b)(c)585
 654
 1,749
 1,389
453
 634
 1,531
 1,835
              
Total KWhs20,797
 21,971
 57,802
 58,690
22,020
 21,653
 59,301
 60,396


(a)2018 KWhs have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail KWhs. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.
(b)Represents energy delivered to distribution customers.
(b)(c)Primarily Ohio’s contractually obligated purchases of OVEC power sold intoto 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,
Three Months Ended 
September 30,
 Nine Months Ended 
September 30,
2017 2016 2017 20162019 2018 2019 2018
(in degree days)(in degree days)
Eastern Region 
  
  
  
 
  
  
  
Actual Heating (a)

 
 1,500
 1,929

 
 2,006
 2,158
Normal Heating (b)
6
 7
 2,091
 2,110
6
 6
 2,072
 2,076
              
Actual Cooling (c)
642
 900
 957
 1,209
872
 864
 1,176
 1,322
Normal Cooling (b)
670
 664
 960
 956
672
 670
 973
 964
              
Western Region 
  
  
  
 
  
  
  
Actual Heating (a)

 
 103
 123

 
 180
 234
Normal Heating (b)

 
 199
 198

 
 190
 194
              
Actual Cooling (d)
1,393
 1,534
 2,640
 2,619
1,587
 1,424
 2,679
 2,612
Normal Cooling (b)
1,364
 1,358
 2,396
 2,384
1,368
 1,367
 2,425
 2,413


(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 20172019 Compared to Third Quarter of 20162018
Reconciliation of Third Quarter of 2016 to Third Quarter of 2017
Reconciliation of Third Quarter of 2018 to Third Quarter of 2019Reconciliation of Third Quarter of 2018 to Third Quarter of 2019
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities(in millions)
    
Third Quarter of 2016 $155.7
Third Quarter of 2018 $145.2
  
  
Changes in Gross Margin:  
  
Retail Margins (58.7) 2.2
Off-system Sales (11.6)
Margins from Off-system Sales 4.6
Transmission Revenues 7.6
 17.3
Other Revenues 5.7
 7.7
Total Change in Gross Margin (57.0) 31.8
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance 55.0
 14.6
Depreciation and Amortization (0.9) (7.9)
Taxes Other Than Income Taxes (1.6) (8.6)
Interest and Investment Income (0.3) (0.2)
Carrying Costs Income (0.4) 0.1
Allowance for Equity Funds Used During Construction (1.3) 2.0
Non-Service Cost Components of Net Periodic Benefit Cost (0.6)
Interest Expense 2.2
 (0.1)
Total Change in Expenses and Other 52.7
 (0.7)
  
  
Income Tax Expense (7.4)
Income Tax Expense (Benefit) (42.6)
  
  
Third Quarter of 2017 $144.0
Third Quarter of 2019 $133.7


The major components of the decreaseincrease 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 $2 million primarily due to the following:
Retail Margins decreased $59A $27 million net increase primarily due to the following:
A $52 million decrease in Ohio revenues associated with the Universal Service Fund (USF) surcharge rate decrease. This decrease was offset by a corresponding decrease in Other Operating and Maintenance expenses below.
An $18 million net decrease in recovery of equity carrying charges related2018 adjustments to the distribution decoupling under-recovery balance as a result of the 2018 Ohio Phase-In Recovery Rider (PIRR), net of associated amortizations.
An $8 million decreaseTax Reform settlement and changes in revenues associated with smart grid riders in Ohio.tax riders. This decreaseincrease was partially offset in expense itemsIncome Tax Expense (Benefit) 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. This decrease was offset by a corresponding decrease in Taxes Other Than Income Taxes below.
These decreases were partially offset by:
A $14 million increase in AEP Texas revenues associated with the Distribution Cost Recovery Factor revenue rider.
A $12 million favorable impact in Ohioincrease 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.
Margins from Off-system Sales decreased $12 million due tohigher current year losses from a power contract with OVEC in Ohio. This increase was offset in Margins from Off-system Sales below.
A $9 million increase in revenues associated with Ohio smart grid riders. This increase was partially offset in other expense items below.
An $8 million increase in weather-related usage in Texas primarily due to an 11% increase in cooling degree days.
A $6 million increase in weather-normalized margins primarily in the residential class.
A $4 million increase in Ohio rider revenues associated with the DIR. This decrease was partially offset in other expense items below.
A $3 million increase in Ohio Energy Efficiency/Peak Demand Reduction rider revenues. This increase was offset by a corresponding increase in Other Operation and Maintenance expenses below.
These increases were partially offset by:
A $28 million net decrease in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses. This decrease was partially offset in Other Operation and Maintenance expenses below.
A $13 million decrease in Ohio Deferred Asset Phase-In-Recovery Rider revenues which is deferredended in Retailthe second quarter of 2019. This decrease was offset in Depreciation and Amortization expenses below.
An $8 million net decrease in margin in Ohio for the Rate Stability Rider including associated amortizations which ended in the third quarter of 2019.


A $6 million decrease in revenues associated with a vegetation management rider in Ohio. This decrease was offset in Other Operation and Maintenance expenses below.
A $6 million net decrease in margin in Ohio for the Phase-In-Recovery Rider including associated amortizations which ended in the first quarter of 2019.
A $6 million decrease in affiliated PPA capacity revenues in Texas. This decrease was offset in Margins abovefrom Off-system Sales below.
Margins from Off-system Sales increased $5 million primarily due to the following:
A $17 million increase due to higher affiliated PPA revenues in Texas. This increase was partially offset by in Other Operation and Maintenance expenses below.
This increase was partially offset by:
A $12 million decrease primarily due to higher current year losses from a power contract with OVEC and lower deferrals as a result of the OVEC PPA rider beginning 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 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 $55 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 $5 million decrease in employee-related expenses.
A $3 million decrease in recoverable smart grid expenses in Ohio. This decrease was offset in Retail Margins above.
Transmission Revenues increased $17 million primarily due to the recovery of increased transmission investment in ERCOT.
Other Revenues increased $8 million primarily due to securitization revenue related to Transition Funding. This decrease was offset below in Depreciation and Amortization expenses and in Interest Expense.

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

Other Operation and Maintenance expenses decreased $15 million primarily due to the following:
A $29 million decrease in transmission expenses that were fully recovered in rate riders/trackers in Gross Margin above.
A $4 million decrease due to higher charitable contributions in 2018 in Ohio.
These decreases were partially offset by:
A $16 million increase in affiliated PPA expenses in Texas. This increase was offset by an increase in Margins from Off-system Sales above.
A $12 million increase in PJM expenses primarily related to the annual formula rate true-up.
Depreciation and Amortization expenses increased $8 million primarily due to the following:
A $15 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
A $7 million increase in securitization amortizations primarily related to Transition Funding. This increase was offset in Other Revenues above and in Interest Expense below.
These increases were partially offset by:
An $8million decrease in amortizations associated with the Deferred Asset Phase-In-Recovery Rider in Ohio which ended in the second quarter of 2019. This decrease was offset in Retail Margins above.
A $6 million decrease in Ohio recoverable DIR depreciation expense. This decrease was partially offset in Retail Margins above.
Taxes Other Than Income Taxes increased $9 million primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
Interest Expense was unchanged primarily due to the following:
A $5 million decrease due to the 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 $3 million decrease in expense related to Transition Funding Securitization assets. This decrease was offset in Other Revenues and Depreciation and Amortization expenses above.
These decreases were partially offset by:
A $6 million increase in storm expenses, primarily in the Texas region.
Depreciation and Amortization expenses increased $1 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 million increase in property taxes due to additional investments in transmission and distribution assets and higher tax rates.long-term debt balances.
This increase was partially offset by:
A $5 million decrease in state excise taxes due to a decrease 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.
Income Tax Expense (Benefit) decreased $43 million primarily due to a one-time recognition of increased amortization of Excess ADIT not subject to normalization requirements as a result of the 2018 Ohio Tax Reform Settlement. This increase was partially offset in Retail Margins above.



Nine Months Ended September 30, 20172019 Compared to Nine Months Ended September 30, 20162018
Reconciliation of Nine Months Ended September 30, 2016 to Nine Months Ended September 30, 2017
Reconciliation of Nine Months Ended September 30, 2018 to Nine Months Ended September 30, 2019Reconciliation of Nine Months Ended September 30, 2018 to Nine Months Ended September 30, 2019
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities(in millions)
    
Nine Months Ended September 30, 2016 $387.8
Nine Months Ended September 30, 2018 $384.6
  
  
Changes in Gross Margin:  
  
Retail Margins (123.0) (9.3)
Off-system Sales (26.8)
Margins from Off-system Sales 38.5
Transmission Revenues 24.2
 68.2
Other Revenues 6.6
 9.1
Total Change in Gross Margin (119.0) 106.5
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance 127.0
 (70.0)
Depreciation and Amortization 2.6
 (28.0)
Taxes Other Than Income Taxes (14.1) (24.0)
Interest and Investment Income 0.1
 1.6
Carrying Costs Income (1.0) (0.8)
Allowance for Equity Funds Used During Construction (4.3) (0.7)
Non-Service Cost Components of Net Periodic Benefit Cost (1.8)
Interest Expense 13.5
 14.8
Total Change in Expenses and Other 123.8
 (108.9)
  
  
Income Tax Expense (18.3)
Income Tax Expense (Benefit) 39.4
  
  
Nine Months Ended September 30, 2017 $374.3
Nine Months Ended September 30, 2019 $421.6


The major components of the decreaseincrease 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 $9 million primarily due to the following:
Retail Margins decreased $123A $71 million primarily due to the following:
A $140 millionnet decrease in Ohio Basic Transmission Cost Rider revenues associated with the USF surcharge rate decrease.and recoverable PJM expenses. This decrease was partially offset by a corresponding decrease in Other OperatingOperation 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 $13An $18 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 $9$17 million decrease in affiliated PPA capacity revenues in Texas. This decrease was offset in Margins from Off-system Sales below.
A $16 million net decrease in recoverymargin in Ohio for the Phase-In-Recovery Rider including associated amortizations which ended in the first quarter of equity carrying charges related to2019.
A $13 million decrease in Ohio Deferred Asset Phase-In-Recovery Rider revenues which ended in the PIRR,second quarter of 2019. This decrease was offset in Depreciation and Amortization expenses below.
A $12 million net decrease in margin in Ohio for the Rate Stability Rider including associated amortizations which ended in the third quarter of associated amortizations.2019.
A $7 million decrease in state excise taxesTexas revenues associated with the Transmission Cost Recovery Factor revenue rider. This decrease was partially offset in Other Operation and Maintenance expenses below.
A $5 million decrease in weather-related usage in Texas primarily due to a 23% decrease in metered KWhheating degree days partially offset by a 3% increase in Ohio.cooling degree days.
A $4 million decrease in Ohio rider revenues associated with the DIR. This decrease was partially offset by a corresponding decrease in Taxes Other Than Income Taxes.other expense items below.
These decreases were partially offset by:
A $46$58 million favorable impact in Ohioincrease due to the recoverya reversal of losses from a power contract with OVEC. The PUCO approved a PPA rider beginningregulatory provision in January 2017Ohio.


A $33 million net increase due to recover any net margin related2018 adjustments to the deferraldistribution decoupling under-recovery balance as a result of OVEC losses startingthe 2018 Ohio Tax Reform settlement and changes in June 2016.tax riders. This increase was partially offset by a corresponding decrease in Margins from Off-System SalesIncome Tax Expense (Benefit) below.
A $40$31 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.Ohio smart grid riders. This increase iswas partially offset in other expense items below.


Margins from Off-system Sales decreased $27A $21 million primarilyincrease due to the following:
A $46 million decrease in Ohio due torecovery of higher current year losses from a power contract with OVEC which is deferred in RetailOhio. This increase was offset in Margins abovefrom Off-system Sales below.
A $9 million increase in Ohio Energy Efficiency/Peak Demand Reduction rider revenues. This increase was offset in Other Operation and Maintenance expenses below.
Margins from Off-system Sales increased $39 million primarily due to the following:
A $59 million increase due to higher affiliated PPA revenues in Texas. This increase was partially offset in Other Operation and Maintenance expenses below.
This increase was partially offset by:
A $21 million decrease primarily due to higher current year losses from a power contract with OVEC 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 expenses in Ohio. This decrease was offset in Retail Margins above.
Transmission Revenues increased $68 million primarily due to the following:
A $62 million increase primarily due to recovery of increased transmission investment in ERCOT.
A $6 million increase in Ohio primarily due to 2018 provisions for refunds.
Other Revenues increased $9 million primarily due to distribution connection fees and pole attachment revenues.

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

Other Operation and Maintenance expenses increased $70 million primarily due to the following:
A $64 million increase in expense due to the partial amortization of the Texas Storm Cost Securitization regulatory asset as a result of the final PUCT order in the Texas Storm Cost Case. This increase was offset in Income Tax Expense (Benefit) below.
A $57 million increase in PJM expenses primarily related to the annual formula rate true-up.
A $49 million increase in affiliated PPA expenses in Texas. This increase was offset in Margins from Off-system Sales above.
These decreasesincreases were partially offset by:
A $16$93 million increase due to securitization amortizations related to transition funding, offsetdecrease in Other Revenuestransmission expenses that were fully recovered in rate riders/trackers in Gross Margin above.
Depreciation and Amortization expenses increased $28 million primarily due to the following:
A $9$51 million increase in depreciation expense primarily due to an increase in the depreciable base of transmission and distribution assets.
A $6 million increase due to amortization of capitalized software costs.
Taxes Other Than Income Taxes increased $14 million primarily due to the following:
A $20$9 million increase in property taxes duesecuritization amortizations primarily related to additional investmentsTransition Funding. This increase was offset in transmissionOther Revenues above and distribution assets and higher tax rates.in Interest Expense below.
ThisA $7 million increase in depreciation expense related to the Oklaunion Power Station.
These increases were partially offset by:
A $7$30 million decrease in state excise taxes due to aOhio recoverable DIR depreciation expense. This decrease was partially offset in Retail Margins above.
An $11 million decrease in metered KWhamortizations associated with the Deferred Asset Phase-In-Recovery Rider which ended in Ohio.
Allowance for Equity Funds Used During Construction decreased $4 millionprimarily due to larger short-term debt balances.
Interest Expense decreased $14 million primarily due to the following:second quarter of 2019. This decrease was offset in Retail Margins above.
Taxes Other Than Income Taxes increased $24 million primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
Interest Expense decreased $15 million primarily due to the following:
A $9$21 million decrease due to the maturitydeferral of previously recorded interest expense approved for recovery as a senior unsecured noteresult of the Texas Storm Cost Securitization financing order issued by the PUCT in June 2016 in Ohio.2019.
A $7An $8 million decrease in the Texas securitization transition assets dueexpense related to the final maturity of the first Texas securitization bond.Transition Funding Securitization assets. This decrease was offset by a corresponding decrease in Other Revenues and Depreciation and Amortization expenses above.
These decreases were partially offset by:
Income TaxExpense increased $18A $14 million increase due to higher long-term debt balances.


Income Tax Expense (Benefit) decreased $39 million primarily due to the following:
A $64 million decrease due to the amortization of Excess ADIT not subject to normalization requirements as approved in the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019. This increase was offset in Other Operation and Maintenance expenses above.
This decrease was partially offset by:
A $30 million increase primarily due to a one-time recognition of increased amortization of Excess ADIT not subject to normalization requirements as a result of the recording of favorable state and federal income tax adjustments2018 Ohio Tax Reform Settlement. This increase was partially offset in 2016 and other book/tax differences which are accounted for on a flow-through basis.Retail Margins above.




AEP TRANSMISSION HOLDCO
 Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
 Three Months Ended 
September 30,
 Nine Months Ended 
September 30,
AEP Transmission Holdco 2017 2016 2017 2016 2019 2018 2019 2018
 (in millions) (in millions)
Transmission Revenues $178.5
 $132.4
 $581.9
 $382.7
 $273.0
 $187.2
 $808.3
 $605.2
Other Operation and Maintenance 23.1
 12.2
 54.5
 32.7
 31.8
 30.9
 77.0
 76.2
Depreciation and Amortization 26.1
 17.1
 74.7
 48.4
 47.3
 34.4
 133.7
 100.0
Taxes Other Than Income Taxes 28.6
 22.7
 85.0
 65.7
 44.3
 36.3
 130.4
 106.5
Operating Income 100.7
 80.4
 367.7
 235.9
 149.6
 85.6
 467.2
 322.5
Interest and Investment Income 0.1
 
 0.5
 
Carrying Costs Expense 
 
 (0.1) (0.2)
Other Income 0.8
 0.4
 2.3
 1.1
Allowance for Equity Funds Used During Construction 11.6
 13.5
 35.9
 39.8
 21.0
 13.8
 61.1
 45.4
Non-Service Cost Components of Net Periodic Benefit Cost 0.7
 0.7
 2.0
 2.1
Interest Expense (17.9) (12.2) (52.3) (35.4) (27.8) (24.2) (73.8) (66.8)
Income Before Income Tax Expense and Equity Earnings 94.5
 81.7
 351.7
 240.1
 144.3
 76.3
 458.8
 304.3
Income Tax Expense 38.6
 35.2
 142.1
 103.2
 35.4
 19.2
 105.7
 75.0
Equity Earnings of Unconsolidated Subsidiaries 20.6
 23.0
 68.7
 72.6
Equity Earnings of Unconsolidated Subsidiary 18.1
 17.1
 54.5
 51.6
Net Income 76.5
 69.5
 278.3
 209.5
 127.0
 74.2
 407.6
 280.9
Net Income Attributable to Noncontrolling Interests 1.0
 0.5
 2.6
 2.0
 0.9
 0.9
 2.8
 2.5
Earnings Attributable to AEP Common Shareholders $75.5
 $69.0
 $275.7
 $207.5
 $126.1
 $73.3
 $404.8
 $278.4


Summary of Investment in Transmission Assets for AEP Transmission Holdco
 September 30, September 30,
 2017 2016 2019 2018
 (in millions) (in millions)
Plant in Service $5,001.4
 $3,330.5
 $7,796.9
 $6,307.3
CWIP 1,392.8
 1,565.8
Accumulated Depreciation 156.6
 88.1
Construction Work in Progress 1,903.4
 1,823.0
Accumulated Depreciation and Amortization 383.7
 244.3
Total Transmission Property, Net $6,237.6
 $4,808.2
 $9,316.6
 $7,886.0



Third Quarter of 20172019 Compared to Third Quarter of 20162018
 
Reconciliation of Third Quarter of 20162018 to Third Quarter of 20172019
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
Third Quarter of 2016 $69.0
Third Quarter of 2018 $73.3
    
Changes in Transmission Revenues:    
Transmission Revenues 46.1
 85.8
Total Change in Transmission Revenues 46.1
 85.8
    
Changes in Expenses and Other:    
Other Operation and Maintenance (10.9) (0.9)
Depreciation and Amortization (9.0) (12.9)
Taxes Other Than Income Taxes (5.9) (8.0)
Interest and Investment Income 0.1
Other Income 0.4
Allowance for Equity Funds Used During Construction (1.9) 7.2
Interest Expense (5.7) (3.6)
Total Change in Expenses and Other (33.3) (17.8)
    
Income Tax Expense (3.4) (16.2)
Equity Earnings (2.4)
Net Income Attributable to Noncontrolling Interests (0.5)
Equity Earnings of Unconsolidated Subsidiary 1.0
    
Third Quarter of 2017 $75.5
Third Quarter of 2019 $126.1


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 $86 million primarily due to continued investment in transmission assets.
Transmission Revenues increased $46 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 and Maintenance expenses increased $11 million primarily due to increased transmission investment.
Depreciation and Amortization expenses increased $9 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 additional transmission investment.
Interest Expense increased $6 million primarily due to higher outstanding long-term debt balances.
Income Tax Expense increased $3 million primarily due to an increase in pretax book income.
Depreciation and Amortization expenses increased $13 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $8 million primarily due to higher property taxes as a result of increased transmission investment.
Allowance for Equity Funds Used During Construction increased $7 million primarily due to higher CWIP balances.
Interest Expense increased $4 million primarily due to higher long-term debt balances.
Income Tax Expense increased $16 million primarily due to higher pretax book income.



Nine Months Ended September 30, 20172019 Compared to Nine Months Ended September 30, 20162018
 
Reconciliation of Nine Months Ended September 30, 20162018 to Nine Months Ended September 30, 20172019
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
Nine Months Ended September 30, 2016 $207.5
Nine Months Ended September 30, 2018 $278.4
    
Changes in Transmission Revenues:    
Transmission Revenues 199.2
 203.1
Total Change in Transmission Revenues 199.2
 203.1
    
Changes in Expenses and Other:    
Other Operation and Maintenance (21.8) (0.8)
Depreciation and Amortization (26.3) (33.7)
Taxes Other Than Income Taxes (19.3) (23.9)
Interest and Investment Income 0.5
Carrying Costs Expense 0.1
Other Income 1.2
Allowance for Equity Funds Used During Construction (3.9) 15.7
Non-Service Cost Components of Net Periodic Pension Cost (0.1)
Interest Expense (16.9) (7.0)
Total Change in Expenses and Other (87.6) (48.6)
    
Income Tax Expense (38.9) (30.7)
Equity Earnings (3.9)
Equity Earnings of Unconsolidated Subsidiary 2.9
Net Income Attributable to Noncontrolling Interests (0.6) (0.3)
    
Nine Months Ended September 30, 2017 $275.7
Nine Months Ended September 30, 2019 $404.8

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 $203 million primarily due to continued investment in transmission assets.
Transmission Revenues increased $199 million primarily due to the current year favorable impact of the modification of the PJM OATT formula rates combined with an increase driven by continued investment in transmission assets.


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


Depreciation and Amortization expenses increased $34 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $24 million primarily due to higher property taxes as a result of increased transmission investment.
Allowance for Equity Funds Used During Construction increased $16 million primarily due to the following:
Other Operation and Maintenance expenses increased $22A $13 million primarily due to increased transmission investment.
Depreciation and Amortization expenses increased $26 millionincrease primarily due to higher depreciable base.
CWIP balances.
Taxes Other Than Income Taxes increased $19A $12 million primarily due to increased property taxes as a result of additional transmission investment.
Allowance for Equity Funds Used During Construction decreased $4 million primarilyincrease due to the FERC transmission complaint and an increase in the amountFERC’s approval of short-term debt,a settlement agreement.
These increases were partially offset by an increase in the CWIP balance.
by:
Interest Expense increased $17A $13 million primarilydecrease due to higher outstanding long-term debt balances.recent FERC audit findings.
Interest Expense increased $7 million primarily due to higher long-term debt balances.
Income Tax Expense increased $31 million primarily due to higher pretax book income with a partial offset due to the FERC’s approval of a settlement agreement.

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, partially offset by increased revenues. The revenue increase is primarily due to interim rate increases in the third quarter of 2016 and higher loads, partially offset by an ETT rate reduction that went into effect in March 2017.




GENERATION & MARKETING
 Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
 Three Months Ended 
September 30,
 Nine Months Ended 
September 30,
Generation & Marketing 2017 2016 2017 2016 2019 2018 2019 2018
 (in millions) (in millions)
Revenues $465.5
 $859.4
 $1,467.5
 $2,291.2
 $533.7
 $521.6
 $1,428.2
 $1,487.4
Fuel, Purchased Electricity and Other 354.6
 567.4
 1,062.7
 1,490.6
 403.8
 405.0
 1,117.8
 1,167.8
Gross Margin 110.9
 292.0
 404.8
 800.6
 129.9
 116.6
 310.4
 319.6
Other Operation and Maintenance 56.5
 95.8
 211.4
 290.2
 44.0
 68.2
 158.0
 192.6
Asset Impairments and Other Related Charges (2.5) 2,254.4
 10.6
 2,254.4
 
 35.0
 
 35.0
Gain on Sale of Merchant Generation Assets 
 
 (226.4) 
Depreciation and Amortization 6.2
 50.5
 17.5
 149.8
 20.6
 12.0
 49.1
 26.4
Taxes Other Than Income Taxes 3.2
 8.7
 8.9
 29.0
 4.4
 3.7
 11.8
 10.3
Operating Income (Loss) 47.5
 (2,117.4) 382.8
 (1,922.8) 60.9
 (2.3) 91.5
 55.3
Interest and Investment Income 2.7
 0.3
 7.9
 1.2
 1.9
 3.6
 6.0
 9.9
Non-Service Cost Components of Net Periodic Benefit Cost 3.8
 3.8
 11.2
 11.5
Interest Expense (4.0) (9.5) (14.7) (27.1) (10.5) (3.8) (21.5) (11.7)
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)
Income Before Income Tax Expense (Benefit) and Equity Earnings (Loss) 56.1
 1.3
 87.2
 65.0
Income Tax Expense (Benefit) (36.4) (3.6) (51.8) 3.7
Equity Earnings (Loss) of Unconsolidated Subsidiaries (3.8) 0.2
 (5.9) 0.5
Net Income 88.7
 5.1
 133.1
 61.8
Net Loss Attributable to Noncontrolling Interests (1.3) (0.2) (6.4) (0.5)
Earnings Attributable to AEP Common Shareholders $90.0
 $5.3
 $139.5
 $62.3


Summary of MWhs Generated for Generation & Marketing
Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
Three Months Ended 
September 30,
 Nine Months Ended 
September 30,
2017 2016 2017 20162019 2018 2019 2018
(in millions of MWhs)(in millions of MWhs)
Fuel Type: 
  
  
  
 
  
  
  
Coal2
 8
 10
 19
2
 4
 4
 10
Natural Gas
 4
 2
 11
Renewables1
 
 2
 1
Total MWhs2
 12
 12
 30
3
 4
 6
 11





Third Quarter of 20172019 Compared to Third Quarter of 20162018
Reconciliation of Third Quarter of 2016 to Third Quarter of 2017
Reconciliation of Third Quarter of 2018 to Third Quarter of 2019Reconciliation of Third Quarter of 2018 to Third Quarter of 2019
Earnings Attributable to AEP Common Shareholders from Generation & Marketing(in millions)
    
Third Quarter of 2016 $(1,369.2)
Third Quarter of 2018 $5.3
  
  
Changes in Gross Margin:  
  
Generation (175.4) (10.6)
Retail, Trading and Marketing (10.1) 12.9
Other 4.4
Other Revenues 11.0
Total Change in Gross Margin (181.1) 13.3
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance 39.3
 24.2
Asset Impairments and Other Related Charges 2,256.9
 35.0
Depreciation and Amortization 44.3
 (8.6)
Taxes Other Than Income Taxes 5.5
 (0.7)
Interest and Investment Income 2.4
 (1.7)
Interest Expense 5.5
 (6.7)
Total Change in Expenses and Other 2,353.9
 41.5
  
  
Income Tax Expense (769.9)
Income Tax Expense (Benefit) 32.8
Equity Earnings (Loss) of Unconsolidated Subsidiaries (4.0)
Net Loss Attributable to Noncontrolling Interests 1.1
  
  
Third Quarter of 2017 $33.7
Third Quarter of 2019 $90.0

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

Generation decreased $11 million primarily due to reduction in capacity revenues in 2019 partially due to the retirement of Conesville Units 5 & 6 in 2019.
Retail, Trading and Marketing increased $13 million due to higher trading and marketing activity in 2019.
Other Revenues increased $11 million primarily due to the Sempra Renewables LLC acquisition and other renewable projects placed in-service.

Expenses and Other, Income Tax Expense (Benefit) and Net Loss Attributable to Noncontrolling Interests changed between years as follows:

Other Operation and Maintenance expenses decreased $24 million due to the following:
A $20 million decrease due to the retirement of Conesville Units 5 & 6 in 2019.
An $11 million decrease due to the retirement of Stuart Plant in June of 2018.
These decreases were partially offset by:
A $7 million increase due to the acquisitions of Sempra Renewables LLC and Santa Rita East.
Asset Impairment and Other Related Charges decreased $35 million due to the impairment of Racine in the third quarter of 2018.
Depreciation and Amortization expenses increased $9 million due to a higher depreciable base from increased investments in wind farms and renewable energy sources.
Interest Expense increased $7 million primarily due to increased borrowing costs related to the Sempra Renewables LLC acquisition.
Income Tax Expense (Benefit) decreased $33 million primarily due to an increase in projected renewable PTC primarily driven by the Sempra Renewables LLC acquisition partially offset by an increase in pretax book income.
Equity Earnings (Loss) of Unconsolidated Subsidiaries decreased $4 million primarily due to the Sempra Renewables LLC acquisition.


Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018
Reconciliation of Nine Months Ended September 30, 2018 to Nine Months Ended September 30, 2019
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
   
Nine Months Ended September 30, 2018 $62.3
   
Changes in Gross Margin:  
Generation (55.1)
Retail, Trading and Marketing 28.0
Other Revenues 17.9
Total Change in Gross Margin (9.2)
   
Changes in Expenses and Other:  
Other Operation and Maintenance 34.6
Asset Impairments and Other Related Charges 35.0
Depreciation and Amortization (22.7)
Taxes Other Than Income Taxes (1.5)
Interest and Investment Income (3.9)
Non-Service Cost Components of Net Periodic Benefit Cost (0.3)
Interest Expense (9.8)
Total Change in Expenses and Other 31.4
   
Income Tax Expense (Benefit) 55.5
Equity Earnings (Loss) of Unconsolidated Subsidiaries (6.4)
Net Loss Attributable to Noncontrolling Interests 5.9
   
Nine Months Ended September 30, 2019 $139.5

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


Generation decreased $55 million primarily due to the reduction of capacity revenues and energy margins in 2019, a reduction in revenues due to the retirement of the Stuart Plant in 2018 and the retirement of Conesville Units 5 & 6 in 2019.
Retail, Trading and Marketing increased $28 million primarily due to higher retail margins due to lower market costs and higher delivered volumes and higher marketing activity in 2019.
Other Revenues increased $18 million primarily due to the Sempra Renewables LLC acquisition and other renewable projects placed in-service.
Generation decreased $175 million primarily due to the reduction of revenues associated with the sale of certain merchant generation assets.
Retail, Trading and Marketing decreased $10 million due to lower retail margins in 2017 partially offset by favorable wholesale trading and marketing performance in 2017.
Other increased $4 million primarily due to renewable projects placed in service.


Expenses and Other, and Income Tax Expense (Benefit), Equity Earnings (Loss) of Unconsolidated Subsidiaries and Net Loss Attributable to Noncontrolling Interests changed between years as follows:


Other Operation and Maintenance expenses decreased $35 million due to the following:
Other Operation and Maintenance expenses decreased $39A $40 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 billiondecrease due to the asset impairmentretirement of certain merchant generation assetsConesville Units 5 & 6 in 2016.
2019.
Depreciation and Amortization expenses decreased $44A $15 million primarilydecrease due to the sale and impairmentretirement of certain merchant generation assets.
Stuart Plant in June of 2018.
These decreases were partially offset by:
Taxes Other Than Income Taxes decreased $6A $20 million primarilyincrease due to the saleacquisitions of certain merchant generation assets.Sempra Renewables LLC and Santa Rita East.
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.
Asset Impairment and Other Related Charges decreased $35 million due to the impairment of Racine in the third quarter of 2018.
Depreciation and Amortization expenses increased $23 million due to a higher depreciable base from increased investments in wind farms and renewable energy sources.
Interest and Investment Income decreased $4 million primarily due to a reduction in Advances to Affiliates which was driven by a dividend payment made to Parent in 2018.



Interest Expense increased $10 million primarily due to increased borrowing costs related to the Sempra Renewables LLC acquisition.
Income Tax Expense (Benefit) decreased $56 million primarily due to an increase in projected renewable PTC primarily driven by the Sempra Renewables LLC acquisition partially offset by an increase in pretax book income.
Equity Earnings (Loss) of Unconsolidated Subsidiaries decreased $6 million primarily due to the Sempra Renewables LLC acquisition.
Net Loss Attributable to Noncontrolling Interests increased $6 million primarily due to the Sempra Renewables LLC acquisition.
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 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:

Generation decreased $376 million primarily due to the reduction of revenues associated with the sale of certain merchant generation assets.
Retail, Trading and Marketing decreased $34 million primarily due to lower margins in 2017 combined with the impact of favorable wholesale trading and marketing performance in 2016.
Other increased $14 million primarily due to renewable projects placed in service.

Expenses and Other and Income Tax Expense 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 million due to the sale of certain merchant generation assets.
Depreciation and Amortization expenses decreased $132 million primarily due to the sale and impairment of certain merchant generation assets.
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 20172019 Compared to Third Quarter of 20162018


Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from $36$10 million in 20162018 to $5a loss of $54 million in 20172019 primarily due to:

A $40 million increase in income tax expense due to an increase in consolidating tax adjustments. This increase is offset primarily within the prior year reversalGeneration & Marketing segment.
A $20 million increase in interest expense as a result 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 investment in the third quarter of 2017.increased debt outstanding.


Nine Months Ended September 30, 20172019 Compared to Nine Months Ended September 30, 20162018


Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from incomea loss of $62$17 million in 20162018 to a loss of $11$116 million in 20172019 primarily due to:

A $63 million increase in income tax expense primarily due to the following:
A $30 million increase due to an increase in consolidating tax adjustments. This increase is offset primarily within the Generation & Marketing segment.
An $18 million increase related to the enactment of the Kentucky state tax legislation in the second quarter of 2018.
A $10 million increase due to an increase in the allocation of the parent company loss benefit due to the tax sharing agreement with AEP Subsidiaries.
A $5 million increase due to the current year revaluation of AEP’s state deferred tax liability as a result of the state income tax filing requirement in Kansas associated with the Sempra Renewables LLC acquisition.
A $55 million increase in interest expense as a result of increased debt outstanding.
A $5 million impairment of an equity investment and related assets in 2019.

These items were partially offset by:

A $20 million impairment of an equity investment and related assets in 2018.
An $8 million increase in interest income due to a higher return on investments held by EIS.

AEP SYSTEM INCOME TAXES

Third Quarter of 2019 Compared to Third Quarter of 2018

Income Tax Expense (Benefit) increased $121 million primarily due to the prior year reversaleffects of capital loss valuation allowances related to effectively settling a 2011 audit issue with the IRS and thediscrete impact of $124 million of amortization of Excess ADIT not subject to normalization requirements as a result 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, partially offset by the gain recognized on the sale of a cost-based investmentOhio and West Virginia Tax Reform Orders received in the third quarter of 2017.2018.

AEP SYSTEM INCOME TAXES

Third Quarter of 2017 Compared to Third Quarter of 2016

Income Tax Expense increased $799 million primarily due to an increase 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 due to the third quarter 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.


Nine Months Ended September 30, 20172019 Compared to Nine Months Ended September 30, 20162018


Income Tax Expense increased $932(Benefit) decreased $63 million primarily due to increased amortization of Excess ADIT not subject to normalization requirements as a result of finalized Tax Reform orders and an increase in pretax bookprojected renewable income driven by the impairment of certain merchant generation assets in the third quarter of 2016. The increase in Income Tax Expense 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 as well as prior year tax return adjustments related to the disposition of AEP’s commercial barging operations.credits.




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, 2017 December 31, 2016September 30, 2019 December 31, 2018
(dollars in millions)(dollars in millions)
Long-term Debt, including amounts due within one year$20,721.7
 51.9% $20,391.2
(a)51.6%$25,881.2
 53.5% $23,346.7
 52.7%
Short-term Debt1,059.3
 2.7
 1,713.0
 4.3
2,510.0
 5.2
 1,910.0
 4.3
Total Debt21,781.0
 54.6
 22,104.2
(a)55.9
28,391.2
 58.7
 25,256.7
 57.0
AEP Common Equity18,069.1
 45.3
 17,397.0
 44.0
19,716.4
 40.7
 19,028.4
 42.9
Noncontrolling Interests36.4
 0.1
 23.1
 0.1
281.3
 0.6
 31.0
 0.1
Total Debt and Equity Capitalization$39,886.5
 100.0% $39,524.3
 100.0%$48,388.9
 100.0% $44,316.1
 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%57% as of December 31, 20162018 to 54.6%58.7% as of September 30, 20172019 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, 2017,2019, 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.


Commercial Paper Credit FacilitiesNet Available Liquidity


AEP manages liquidity by maintaining adequate external financing commitments.  As of September 30, 2017,2019, available liquidity was approximately $3$2.6 billion as illustrated in the table below:
 Amount Maturity
 (in millions)  Amount
Maturity
Commercial Paper Backup:Commercial Paper Backup: 
  Commercial Paper Backup:(in millions)

Revolving Credit Facility$3,000.0
 June 2021Revolving Credit Facility$4,000.0

June 2022
Total3,000.0
  
Cash and Cash EquivalentsCash and Cash Equivalents343.9
  Cash and Cash Equivalents348.8
  
Total Liquidity SourcesTotal Liquidity Sources3,343.9
  Total Liquidity Sources4,348.8
  
Less:AEP Commercial Paper Outstanding295.0
  AEP Commercial Paper Outstanding1,760.0
  
   
  
Net Available LiquidityNet Available Liquidity$3,048.9
  Net Available Liquidity$2,588.8
  

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 20172019 was $1.6$2.2 billion.  The weighted-average interest rate for AEP’s commercial paper during 20172019 was 1.19%2.66%.


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, 2019 was $123$204 millionwith maturities ranging from October 20172019 to September 2018.October 2020.


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.July 2021.


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, 2017,2019,this contractually-defined percentage was 52.4%55.3%.  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 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 recent acquisition of Sempra Renewables LLC. See Note 13 - Financing Activities for additional information.

Dividend Policy and Restrictions


The Board of Directors declared a quarterly dividend of $0.62$0.70 per share in October 2017.2019. 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 13 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,
 2019 2018
 (in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period$444.1
 $412.6
Net Cash Flows from Operating Activities3,349.9
 3,932.6
Net Cash Flows Used for Investing Activities(5,357.6) (4,688.7)
Net Cash Flows from Financing Activities2,053.4
 1,281.0
Net Increase in Cash, Cash Equivalents and Restricted Cash45.7
 524.9
Cash, Cash Equivalents and Restricted Cash at End of Period$489.8
 $937.5

Operating Activities
 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
 Nine Months Ended 
September 30,
 2019 2018
 (in millions)
Net Income$1,767.1
 $1,566.5
Non-Cash Adjustments to Net Income (a)1,838.8
 1,728.7
Mark-to-Market of Risk Management Contracts(41.6) (95.4)
Property Taxes341.7
 304.8
Deferred Fuel Over/Under-Recovery, Net93.7
 210.6
Recovery of Ohio Capacity Costs34.1
 52.7
Refund of Global Settlement(12.4) (5.5)
Change in Other Noncurrent Assets(9.6) 161.6
Change in Other Noncurrent Liabilities(16.3) 141.9
Change in Certain Components of Working Capital(645.6) (133.3)
Net Cash Flows from Operating Activities$3,349.9
 $3,932.6


(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 $583 million primarily due to the following:
A $512 million decrease in cash from Change in Certain Components of Working Capital. The decrease is primarily due to increase in purchases of fuel, material and supplies, decreased accrued taxes, higher employee-related payments and refund related to Tax Reform, partially offset by receivables due to the changes in timing.
A $171 million decrease in cash from Change in Other Noncurrent Assets primarily due to a change in regulatory assets as a result of AEP subsidiaries with rider recovery mechanisms. See Note 4 - Rate Matters for additional information.
A $158 million decrease in cash from Change in Other Noncurrent Liabilities primarily due to decreased Accumulated Provisions for Rate Refunds as a result of Tax Reform
A $117 million decrease in cash from Deferred Fuel Over/Under Recovery, Net primarily due to fluctuations APCo and WPCo as a result of the 2018 West Virginia Tax Reform Order, the full recovery of Ohio Phase in recovery rider and the fluctuations of fuel and purchase power cost at PSO.
These decreases in cash were $3.1 billionpartially offset by:
A $310 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 billion 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 HeldOperations for Sale for a complete discussion of this sale and these impairments. Deferred and Accrued Taxes changed primarily due to 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.further detail.




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,
Nine Months Ended 
September 30,
2017 20162019 2018
(in millions)(in millions)
Construction Expenditures$(3,778.2) $(3,387.0)$(4,336.0) $(4,688.4)
Acquisitions of Nuclear Fuel(73.2) (127.6)(91.9) (26.1)
Proceeds from Sale of Merchant Generation Assets2,159.6
 
Acquisition of Sempra Renewables LLC and Santa Rita East, net of cash and restricted cash acquired(921.3) 
Other15.2
 85.9
(8.4) 25.8
Net Cash Flows Used for Continuing Investing Activities$(1,676.6) $(3,428.7)
Net Cash Flows Used for Investing Activities$(5,357.6) $(4,688.7)

Net Cash Flows Used for Continuing Investing Activities were $1.7 billion in 2017 increased by $669 million primarily due to Construction Expenditures for environmental, distributionthe following:
A $921 million increase due to the acquisition of Sempra Renewables LLC and transmission investments, partially offset by the proceeds received from the saleSanta Rita East. The $921 million represents a cash payment of certain merchant generation assets.$939 million, net of cash and restricted cash acquired of $18 million. See Note 6 - Impairment, DispositionAcquisitions and Assets and Liabilities HeldImpairments for Sale for a complete discussionadditional information.
This increase in the use of this sale.cash was partially offset by:

Net Cash Flows Used for Continuing Investing Activities were $3.4 billion in 2016 primarilyA $352 million decrease due to Construction Expenditures for environmental, distributiondecreased construction expenditures, primarily driven by decreases at AEP Transmission Holdco of $210 million and transmission investments.Transmission and Distribution Utilities of $109 million.

Financing Activities
Nine Months Ended 
 September 30,
Nine Months Ended 
September 30,
2017 20162019 2018
(in millions)(in millions)
Issuance of Common Stock, Net$
 $34.2
Issuance of Common Stock$44.7
 $62.5
Issuance/Retirement of Debt, Net(338.2) 930.3
3,063.9
 2,206.2
Make Whole Premium on Extinguishment of Long-term Debt(46.1) 
Dividends Paid on Common Stock(875.0) (829.8)(1,002.0) (922.5)
Other(54.9) (88.7)(53.2) (65.2)
Net Cash Flows from (Used for) Continuing Financing Activities$(1,314.2) $46.0
Net Cash Flows from Financing Activities$2,053.4
 $1,281.0

Net Cash Flows Used for Continuingfrom Financing Activities increased by $772 million primarily due to the following:
A $936 million increase in 2017 were $1.3 billion. AEP’s net debt retirements were $338 million. The net retirements includecash due to decreased 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.long-term debt. 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 1213 - Financing Activities for a complete discussionadditional information.
This increase in cash was partially offset by:
An $80 million decrease in issuances 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 in short-term borrowing 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.debt. See Note 1213 - Financing Activities for a complete discussionadditional information.
An $80 million decrease in cash due to the increased common stock dividends payments primarily due to increase dividends per share from 2018 to 2019.

See “Long-term Debt Subsequent Events” section of long-termNote 13 for Long-term debt issuances and retirements.other securities issued, retired and principal payments made after September 30, 2019 through October 24, 2019, the date that the third quarter 10-Q was issued.

BUDGETED CAPITAL EXPENDITURES

Management forecasts approximately $32.9 billion of capital expenditures for 2019 to 2023.  Capital expenditures related to North Central Wind Energy Facilities are excluded from these budgeted amounts. The expenditures are generally for transmission, generation, distribution, regulated and contracted renewables, and required environmental investment to comply with the Federal EPA rules.  Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital.  Management expects to fund these capital expenditures through cash flows from operations and financing activities.  Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-

In October 2017, I&M retired $1 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 enters in the normal course of business.  The following identifies significant off-balance sheet arrangements:
 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

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 20162018 Annual Report.


CONTRACTUAL OBLIGATION INFORMATION


A summary of contractual obligations is included in the 20162018 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 20162018 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 2019 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 regarding compliance with policies, limits and procedures.  The Regulated Risk Committee consists of AEPSC’s Chief Financial Officer, Executive Vice President of Generation, 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 following table summarizes the reasons for changes in total MTM value as compared to December 31, 2016:2018:
MTM Risk Management Contract Net Assets (Liabilities)
Nine Months Ended September 30, 2017
Nine Months Ended September 30, 2019Nine Months Ended September 30, 2019
              
Vertically
Integrated
Utilities
 
Transmission
and
Distribution
Utilities
 
Generation
&
Marketing
 Total
Vertically
Integrated
Utilities
 
Transmission
and
Distribution
Utilities
 
Generation
&
Marketing
 Total
(in millions)(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)
Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2018$90.9
 $(101.0) $164.5
 $154.4
Gain from Contracts Realized/Settled During the Period and Entered in a Prior Period(65.5) (5.0) (14.3) (84.8)
Fair Value of New Contracts at Inception When Entered During the Period (a)
 
 26.7
 26.7

 
 8.8
 8.8
Changes in Fair Value Due to Market Fluctuations During the Period (b)
 
 10.5
 10.5

 
 12.8
 12.8
Changes in Fair Value Allocated to Regulated Jurisdictions (c)64.9
 (23.2) 
 41.7
76.9
 (7.2) 
 69.7
Total MTM Risk Management Contract Net Assets (Liabilities) as of September 30, 2017$63.1
 $(138.0) $168.6
 93.7
Total MTM Risk Management Contract Net Assets (Liabilities) as of September 30, 2019$102.3
 $(113.2) $171.8
 160.9
Commodity Cash Flow Hedge Contracts
   
  
 (75.6)   
   (97.3)
Interest Rate and Foreign Currency Cash Flow Hedge Contracts
   
  
 4.2
Interest Rate Cash Flow Hedge Contracts
   
  
 1.9
Fair Value Hedge Contracts   
  
 (1.4)   
  
 25.1
Collateral Deposits   
  
 13.5
   
  
 21.2
Total MTM Derivative Contract Net Assets as of September 30, 2017   
  
 $34.4
Total MTM Derivative Contract Net Assets as of September 30, 2019   
  
 $111.8


(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.


See Note 9 – Derivatives and Hedging and Note 10 – Fair Value Measurements for additional information related to risk management contracts.  The following tables and discussion provide information on credit risk and market volatility risk.


Credit Risk


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




AEP has risk management contracts (includes non-derivative contracts) with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, exposures change daily. As of September 30, 2017,2019, credit exposure net of collateral to sub investment grade counterparties was approximately 7.9%6.4%, 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, 2017,2019, the following table approximates AEP’s counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:
Counterparty Credit Quality 
Exposure
Before
Credit
Collateral
 
Credit
Collateral
 
Net
Exposure
 Number of
Counterparties
>10% of
Net Exposure
 
Net Exposure
of
Counterparties
>10%
 
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) (in millions, except number of counterparties)
Investment Grade $619.6
 $2.2
 $617.4
 3
 $352.2
 $529.6
 $0.3
 $529.3
 2
 $218.3
Split Rating 5.6
 
 5.6
 2
 5.6
 0.8
 
 0.8
 1
 0.8
Noninvestment Grade 
 
 
 
 
No External Ratings:  
  
 

  
  
  
  
 

  
  
Internal Investment Grade 119.2
 
 119.2
 3
 78.7
 138.2
 
 138.2
 3
 84.2
Internal Noninvestment Grade 75.4
 11.5
 63.9
 3
 40.5
 56.2
 10.5
 45.7
 2
 30.1
Total as of September 30, 2017 $819.8
 $13.7
 $806.1
 

 

Total as of September 30, 2019 $724.8
 $10.8
 $714.0
 

 



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, 2017,2019, a near term typical change in commodity prices is not expected to materially impact net income, cash flows or financial condition.


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


VaR Model
Trading Portfolio
Nine Months EndedNine Months Ended Twelve Months EndedNine Months Ended Twelve Months Ended
September 30, 2017 December 31, 2016
September 30, 2019September 30, 2019 December 31, 2018
EndEnd High Average Low End High Average LowEnd High Average Low End High Average Low
(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
0.3
 $1.2
 $0.2
 $0.1
 $1.1
 $1.8
 $0.3
 $0.1


VaR Model
Non-Trading Portfolio
Nine Months EndedNine Months Ended Twelve Months EndedNine Months Ended Twelve Months Ended
September 30, 2017 December 31, 2016
September 30, 2019September 30, 2019 December 31, 2018
EndEnd High Average Low End High Average LowEnd High Average Low End High Average Low
(in millions)(in millions) (in millions)(in millions) (in millions)
$0.7
 $6.5
 $0.9
 $0.3
 $5.6
 $8.4
 $1.5
 $0.4
0.2
 $8.5
 $1.3
 $0.2
 $4.0
 $16.5
 $2.7
 $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, 2019 and 2018, 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$24 million and $29$25 million, respectively.






AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONSINCOME
For the Three and Nine Months Ended September 30, 20172019 and 20162018
(in millions, except per-share and share amounts)
(Unaudited)
 Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended
 September 30, September 30, September 30, September 30,
 2017 2016 2017 2016 2019 2018 2019 2018
REVENUES                
Vertically Integrated Utilities $2,453.8
 $2,538.3
 $6,819.3
 $6,864.6
 $2,598.9
 $2,610.2
 $7,087.6
 $7,332.4
Transmission and Distribution Utilities 1,149.7
 1,245.4
 3,242.7
 3,398.9
 1,147.3
 1,180.9
 3,328.7
 3,450.0
Generation & Marketing 441.5
 823.3
 1,386.8
 2,192.5
 501.2
 486.5
 1,323.8
 1,399.3
Other Revenues 59.7
 45.2
 165.7
 134.0
 67.6
 55.5
 205.3
 212.9
TOTAL REVENUES 4,104.7
 4,652.2
 11,614.5
 12,590.0
 4,315.0
 4,333.1
 11,945.4
 12,394.6
                
EXPENSES  
  
  
  
  
  
  
  
Fuel and Other Consumables Used for Electric Generation 707.4
 880.1
 1,865.3
 2,236.1
 631.2
 840.4
 1,662.5
 1,909.1
Purchased Electricity for Resale 718.1
 774.0
 2,156.9
 2,134.6
 783.9
 784.7
 2,306.4
 2,551.7
Other Operation 636.1
 771.1
 1,842.5
 2,150.7
 708.3
 826.0
 1,981.7
 2,332.7
Maintenance 268.0
 286.3
 859.4
 854.4
 267.7
 316.6
 890.9
 911.0
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
 645.2
 602.6
 1,873.6
 1,695.5
Taxes Other Than Income Taxes 272.6
 264.4
 792.0
 767.9
 320.5
 294.2
 932.7
 863.0
TOTAL EXPENSES 3,118.2
 5,780.1
 8,786.2
 11,958.8
 3,356.8
 3,664.5
 9,647.8
 10,263.0
                
OPERATING INCOME (LOSS) 986.5
 (1,127.9) 2,828.3
 631.2
OPERATING INCOME 958.2
 668.6
 2,297.6
 2,131.6
                
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
Other Income 3.2
 6.3
 18.4
 18.5
Allowance for Equity Funds Used During Construction 20.0
 25.6
 62.2
 86.1
 43.0
 30.9
 122.3
 92.4
Gain on Sale of Equity Investment 12.4
 
 12.4
 
Non-Service Cost Components of Net Periodic Benefit Cost 30.0
 31.9
 90.0
 95.3
Interest Expense (223.3) (225.3) (668.0) (667.2) (275.1) (256.8) (781.6) (733.1)
                
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS 800.6
 (1,323.9) 2,261.8
 68.5
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS 759.3
 480.9
 1,746.7
 1,604.7
                
Income Tax Expense (Credit) 264.0
 (534.5) 797.8
 (134.0)
Income Tax Expense (Benefit) 40.6
 (80.7) 30.7
 93.5
Equity Earnings of Unconsolidated Subsidiaries 20.1
 25.2
 63.1
 42.8
 15.2
 18.1
 51.1
 55.3
                
INCOME (LOSS) FROM CONTINUING OPERATIONS 556.7
 (764.2) 1,527.1
 245.3
NET INCOME 733.9
 579.7
 1,767.1
 1,566.5
                
LOSS FROM DISCONTINUED OPERATIONS, NET OF TAX 
 
 
 (2.5)
Net Income (Loss) Attributable to Noncontrolling Interests 0.4
 2.1
 (0.5) 6.1
                
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
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $733.5
 $577.6
 $1,767.6
 $1,560.4
                
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING 491,840,722
 491,697,809
 491,781,643
 491,422,921
 493,839,034
 492,984,741
 493,579,430
 492,649,456
                
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
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $1.49
 $1.17
 $3.58
 $3.17
                
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING 492,986,307
 491,813,858
 492,428,586
 491,596,861
 495,461,509
 493,940,543
 495,105,986
 493,526,937
                
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
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $1.48
 $1.17
 $3.57
 $3.16
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20172019 and 20162018
(in millions)
(Unaudited)
  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
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2019 2018 2019 2018
Net Income $733.9
 $579.7
 $1,767.1
 $1,566.5
         
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES  
  
  
  
Cash Flow Hedges, Net of Tax of $11.8 and $2.7 for the Three Months Ended September 30, 2019 and 2018, Respectively, and $(16.8) and $3.9 for the Nine Months Ended September 30, 2019 and 2018, Respectively 44.2
 10.2
 (63.3) 14.7
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.4) and $(0.4) for the Three Months Ended September 30, 2019 and 2018, Respectively, and $(1.1) and $(1.1) for the Nine Months Ended September 30, 2019 and 2018, Respectively (1.4) (1.4) (4.2) (4.0)
   
  
  
  
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) 42.8
 8.8
 (67.5) 10.7
         
TOTAL COMPREHENSIVE INCOME 776.7
 588.5
 1,699.6
 1,577.2
         
Total Other Comprehensive Income (Loss) Attributable To Noncontrolling Interests 0.4
 2.1
 (0.5) 6.1
         
TOTAL OTHER COMPREHENSIVE INCOME ATTIBUTABLE TO AEP COMMON SHAREHOLDERS $776.3
 $586.4
 $1,700.1
 $1,571.1
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Nine Months Ended September 30, 20172019 and 20162018
(in millions)
(Unaudited)
AEP Common Shareholders    AEP Common Shareholders    
Common Stock     
Accumulated
Other
Comprehensive
Income (Loss)
    Common Stock     Accumulated
Other
Comprehensive
Income (Loss)
    
Shares Amount 
Paid-in
Capital
 
Retained
Earnings
 
Noncontrolling
Interests
 TotalShares 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
TOTAL EQUITY – DECEMBER 31, 2017512.2
 $3,329.4
 $6,398.7
 $8,626.7
 $(67.8) $26.6
 $18,313.6
             
Issuance of Common Stock0.5
 3.3
 28.9
  
     32.2
Common Stock Dividends      (305.5)(b)  (0.6) (306.1)
Other Changes in Equity    16.9
       16.9
ASU 2018-02 Adoption      14.0
 (17.0)   (3.0)
ASU 2016-01 Adoption      11.9
 (11.9)   
Net Income      454.4
   2.3
 456.7
Other Comprehensive Income 
  
  
  
 1.3
   1.3
TOTAL EQUITY – MARCH 31, 2018512.7
 3,332.7
 6,444.5
 8,801.5
 (95.4) 28.3
 18,511.6
             
Issuance of Common Stock0.4
 2.7
 16.0
  
  
  
 18.7
Common Stock Dividends 
  
  
 (306.8)(b) 
 (1.3) (308.1)
Other Changes in Equity 
  
 (1.9)    
 0.4
 (1.5)
Net Income      528.4
  
 1.7
 530.1
Other Comprehensive Income 
  
  
  
 0.6
  
 0.6
TOTAL EQUITY – JUNE 30, 2018513.1
 3,335.4
 6,458.6
 9,023.1
 (94.8) 29.1
 18,751.4
             
Issuance of Common Stock0.2
 1.1
 10.5
       11.6
Common Stock Dividends      (307.0)(b)  (1.3) (308.3)
Other Changes in Equity    3.5
     0.1
 3.6
Net Income      577.6
   2.1
 579.7
Other Comprehensive Income        8.8
   8.8
TOTAL EQUITY – SEPTEMBER 30, 2018513.3
 $3,336.5
 $6,472.6
 $9,293.7
 $(86.0) $30.0
 $19,046.8
             
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 Stock0.6
 4.3
 29.9
  
  
  
 34.2
0.1
 1.2
 13.3
       14.5
Common Stock Dividends 
  
  
 (826.4)  
 (3.4) (829.8)      (332.5)(c)  (1.1) (333.6)
Other Changes in Equity 
  
 3.6
    
 6.0
 9.6
    (56.6)(a)    1.0
 (55.6)
Net Income      237.5
  
 5.3
 242.8
      572.8
   1.3
 574.1
Other Comprehensive Loss 
  
  
  
 (18.7)  
 (18.7)        (30.3)   (30.3)
TOTAL EQUITY - SEPTEMBER 30, 2016512.0
 $3,328.3
 $6,330.0
 $7,809.4
 $(145.8) $21.1
 $17,343.0
TOTAL EQUITY – MARCH 31, 2019513.6
 3,338.6
 6,442.8
 9,565.6
 (150.7) 32.2
 19,228.5
                          
TOTAL EQUITY - DECEMBER 31, 2016512.0
 $3,328.3
 $6,332.6
 $7,892.4
 $(156.3) $23.1
 $17,420.1
             
Issuance of Common Stock0.4
 2.2
 15.6
       17.8
Common Stock Dividends 
  
  
 (872.3)  
 (2.7) (875.0)      (332.7)(c)  (1.8) (334.5)
Other Changes in Equity 
  
 51.6
    
 0.8
 52.4
    (3.1)     0.6
 (2.5)
Acquisition of Sempra Renewables LLC          134.8
 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)(c) 
 (1.5) (333.9)
Other Changes in Equity 
  
 0.5
    
 


 0.5
Acquisition of Santa Rita East          118.8
 118.8
Net Income      1,511.9
  
 15.2
 1,527.1
      733.5
  
 0.4
 733.9
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
Other Comprehensive Income 
  
  
  
 42.8
  
 42.8
TOTAL EQUITY – SEPTEMBER 30, 2019514.1
 $3,341.9
 $6,467.1
 $10,095.3
 $(187.9) $281.3
 $19,997.7

(a)Includes $(62) million related to a forward equity purchase contract associated with the issuance of Equity Units. See “Equity Units” section of Note 13 for additional information.
(b)Common Stock dividends declared per AEP common share were $0.62.
(c)Common Stock dividends declared per AEP common share were $0.67.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20172019 and December 31, 20162018
(in millions)
(Unaudited)
 September 30, December 31, September 30, December 31,
 2017 2016 2019 2018
CURRENT ASSETS  
  
  
  
Cash and Cash Equivalents $343.9
 $210.5
 $348.8
 $234.1
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
Restricted Cash
(September 30, 2019 and December 31, 2018 Amounts Include $141 and $210, Respectively, Related to Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and Santa Rita East)
 141.0
 210.0
Other Temporary Investments
(September 30, 2019 and December 31, 2018 Amounts Include $193.4 and $152.7, Respectively, Related to EIS and Transource Energy)
 198.4
 159.1
Accounts Receivable:  
  
  
  
Customers 522.7
 705.1
 609.0
 699.0
Accrued Unbilled Revenues 187.3
 158.7
 268.8
 209.3
Pledged Accounts Receivable – AEP Credit 967.6
 972.7
 955.6
 999.8
Miscellaneous 99.9
 118.1
 36.6
 55.2
Allowance for Uncollectible Accounts (36.6) (37.9) (44.9) (36.8)
Total Accounts Receivable 1,740.9
 1,916.7
 1,825.1
 1,926.5
Fuel 354.2
 423.8
 437.8
 341.5
Materials and Supplies 562.3
 543.5
 613.5
 579.6
Risk Management Assets 146.1
 94.5
 186.7
 162.8
Regulatory Asset for Under-Recovered Fuel Costs 153.5
 156.6
 98.5
 150.1
Margin Deposits 105.7
 79.9
 54.2
 141.4
Assets Held for Sale 
 1,951.2
Prepayments and Other Current Assets 350.5
 325.5
 262.4
 208.8
TOTAL CURRENT ASSETS 4,067.8
 6,033.9
 4,166.4
 4,113.9
        
PROPERTY, PLANT AND EQUIPMENT  
  
  
  
Electric:  
  
  
  
Generation 20,739.3
 19,848.9
 22,624.4
 21,699.9
Transmission 17,785.4
 16,658.7
 23,082.8
 21,531.0
Distribution 19,589.4
 18,900.8
 21,991.0
 21,195.4
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) 3,614.1
 3,444.3
 4,510.2
 4,265.0
Construction Work in Progress 3,710.0
 3,183.9
 5,244.5
 4,393.9
Total Property, Plant and Equipment 65,438.2
 62,036.6
 77,452.9
 73,085.2
Accumulated Depreciation and Amortization 17,121.7
 16,397.3
 18,760.2
 17,986.1
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 48,316.5
 45,639.3
 58,692.7
 55,099.1
        
OTHER NONCURRENT ASSETS  
  
  
  
Regulatory Assets 5,640.0
 5,625.5
 3,131.4
 3,310.4
Securitized Assets 1,287.8
 1,486.1
 938.7
 920.6
Spent Nuclear Fuel and Decommissioning Trusts 2,433.0
 2,256.2
 2,835.2
 2,474.9
Goodwill 52.5
 52.5
 52.5
 52.5
Long-term Risk Management Assets 310.4
 289.1
 299.0
 254.0
Operating Lease Assets 990.0
 
Deferred Charges and Other Noncurrent Assets 1,856.9
 2,085.1
 2,794.8
 2,577.4
TOTAL OTHER NONCURRENT ASSETS 11,580.6
 11,794.5
 11,041.6
 9,589.8
        
TOTAL ASSETS $63,964.9
 $63,467.7
 $73,900.7
 $68,802.8
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 20172019 and December 31, 20162018
(dollars in millions)millions, except per-share and share amounts)
(Unaudited)
     September 30, December 31,     September 30, December 31,
 2017 2016 2019 2018
CURRENT LIABILITIESCURRENT LIABILITIES    CURRENT LIABILITIES    
Accounts Payable $1,537.0
 $1,688.5
 $1,766.8
 $1,874.3
Short-term Debt:        
Securitized Debt for Receivables – AEP Credit 750.0
 673.0
 750.0
 750.0
Other Short-term Debt 309.3
 1,040.0
 1,760.0
 1,160.0
Total Short-term Debt 1,059.3
 1,713.0
 2,510.0
 1,910.0
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
Long-term Debt Due Within One Year
(September 30, 2019 and December 31, 2018 Amounts Include $544.7 and $406.5, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, Transource Energy, Sabine and Restoration Funding)
Long-term Debt Due Within One Year
(September 30, 2019 and December 31, 2018 Amounts Include $544.7 and $406.5, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, Transource Energy, Sabine and Restoration Funding)
 1,327.7
 1,698.5
Risk Management Liabilities 69.4
 53.4
 75.3
 55.0
Customer Deposits 346.6
 343.2
 381.4
 412.2
Accrued Taxes 716.5
 1,048.0
 883.4
 1,218.0
Accrued Interest 260.3
 227.2
 304.8
 231.7
Obligations Under Operating Leases 228.8
 
Regulatory Liability for Over-Recovered Fuel CostsRegulatory Liability for Over-Recovered Fuel Costs 19.7
 8.0
Regulatory Liability for Over-Recovered Fuel Costs 100.6
 58.6
Liabilities Held for Sale 
 235.9
Other Current Liabilities 953.9
 1,302.8
 1,032.4
 1,190.5
TOTAL CURRENT LIABILITIES 7,322.0
 9,498.0
 8,611.2
 8,648.8
         
NONCURRENT LIABILITIESNONCURRENT LIABILITIES    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 Debt
(September 30, 2019 and December 31, 2018 Amounts Include $918.4 and $1,109.2, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, Transource Energy, Sabine and Restoration Funding)
Long-term Debt
(September 30, 2019 and December 31, 2018 Amounts Include $918.4 and $1,109.2, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, Transource Energy, Sabine and Restoration Funding)
 24,553.5
 21,648.2
Long-term Risk Management Liabilities 352.7
 316.2
 298.6
 263.4
Deferred Income Taxes 12,628.2
 11,884.4
 7,427.8
 7,086.5
Regulatory Liabilities and Deferred Investment Tax CreditsRegulatory Liabilities and Deferred Investment Tax Credits 3,959.6
 3,751.3
Regulatory Liabilities and Deferred Investment Tax Credits 8,552.8
 8,540.3
Asset Retirement Obligations 1,919.3
 1,830.6
 2,353.5
 2,287.7
Employee Benefits and Pension Obligations 468.9
 614.1
 376.6
 377.1
Obligations Under Operating Leases 801.1
 
Deferred Credits and Other Noncurrent LiabilitiesDeferred Credits and Other Noncurrent Liabilities 837.0
 774.6
Deferred Credits and Other Noncurrent Liabilities 790.0
 782.6
TOTAL NONCURRENT LIABILITIES 38,528.1
 36,549.6
 45,153.9
 40,985.8
        
TOTAL LIABILITIES 45,850.1
 46,047.6
 53,765.1
 49,634.6
        
Rate Matters (Note 4) 
 
 

 

Commitments and Contingencies (Note 5) 
 
 

 

        
MEZZANINE EQUITYMEZZANINE EQUITY    MEZZANINE EQUITY    
Redeemable Noncontrolling Interest 67.3
 69.4
Contingently Redeemable Performance Share Awards 9.3
 
 70.6
 39.4
TOTAL MEZZANINE EQUITY 137.9
 108.8
        
EQUITYEQUITY    EQUITY    
Common Stock – Par Value – $6.50 Per Share:        
 2017 2016     2019 2018    
Shares Authorized 600,000,000 600,000,000     600,000,000 600,000,000    
Shares Issued 512,048,663 512,048,520     514,140,235 513,450,036    
(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
(20,204,160 Shares were Held in Treasury as of September 30, 2019 and December 31, 2018, Respectively)(20,204,160 Shares were Held in Treasury as of September 30, 2019 and December 31, 2018, Respectively) 3,341.9
 3,337.4
Paid-in Capital 6,384.2
 6,332.6
 �� 6,467.1
 6,486.1
Retained Earnings 8,532.0
 7,892.4
 10,095.3
 9,325.3
Accumulated Other Comprehensive Income (Loss)Accumulated Other Comprehensive Income (Loss) (175.4) (156.3)Accumulated Other Comprehensive Income (Loss) (187.9) (120.4)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITYTOTAL AEP COMMON SHAREHOLDERS’ EQUITY 18,069.1
 17,397.0
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY 19,716.4
 19,028.4
        
Noncontrolling Interests 36.4
 23.1
 281.3
 31.0
        
TOTAL EQUITY 18,105.5
 17,420.1
 19,997.7
 19,059.4
        
TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITYTOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY $63,964.9
 $63,467.7
TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY $73,900.7
 $68,802.8
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20172019 and 20162018
(in millions)
(Unaudited)
  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
  Nine Months Ended September 30,
  2019 2018
OPERATING ACTIVITIES  
  
Net Income $1,767.1
 $1,566.5
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
Depreciation and Amortization 1,873.6
 1,695.5
Deferred Income Taxes 15.9
 43.0
Allowance for Equity Funds Used During Construction (122.3) (92.4)
Mark-to-Market of Risk Management Contracts (41.6) (95.4)
Amortization of Nuclear Fuel 71.6
 82.6
Property Taxes 341.7
 304.8
Deferred Fuel Over/Under-Recovery, Net 93.7
 210.6
Recovery of Ohio Capacity Costs 34.1
 52.7
Refund of Global Settlement (12.4) (5.5)
Change in Other Noncurrent Assets (9.6) 161.6
Change in Other Noncurrent Liabilities (16.3) 141.9
Changes in Certain Components of Working Capital:    
Accounts Receivable, Net 125.0
 (52.3)
Fuel, Materials and Supplies (116.6) 98.7
Accounts Payable (32.4) (45.0)
Accrued Taxes, Net (359.9) (247.5)
Other Current Assets 60.2
 11.7
Other Current Liabilities (321.9) 101.1
Net Cash Flows from Operating Activities 3,349.9
 3,932.6
     
INVESTING ACTIVITIES    
Construction Expenditures (4,336.0) (4,688.4)
Purchases of Investment Securities (951.5) (1,591.2)
Sales of Investment Securities 874.2
 1,550.9
Acquisitions of Nuclear Fuel (91.9) (26.1)
Acquisition of Sempra Renewables LLC and Santa Rita East, net of cash and restricted cash acquired (921.3) 
Other Investing Activities 68.9
 66.1
Net Cash Flows Used for Investing Activities (5,357.6) (4,688.7)
     
FINANCING ACTIVITIES    
Issuance of Common Stock 44.7
 62.5
Issuance of Long-term Debt 3,492.4
 3,572.0
Commercial Paper and Credit Facility Borrowings 
 205.6
Change in Short-term Debt, Net 600.0
 604.0
Retirement of Long-term Debt (1,023.5) (1,959.5)
Make Whole Premium on Extinguishment of Long-term Debt (5.0) (10.3)
Commercial Paper and Credit Facility Repayments 
 (205.6)
Principal Payments for Finance Lease Obligations (44.5) (49.4)
Dividends Paid on Common Stock (1,002.0) (922.5)
Other Financing Activities (8.7) (15.8)
Net Cash Flows from Financing Activities 2,053.4
 1,281.0
     
Net Increase in Cash, Cash Equivalents and Restricted Cash 45.7
 524.9
Cash, Cash Equivalents and Restricted Cash at Beginning of Period 444.1
 412.6
Cash, Cash Equivalents and Restricted Cash at End of Period $489.8
 $937.5
     
SUPPLEMENTARY INFORMATION    
Cash Paid for Interest, Net of Capitalized Amounts $689.7
 $631.3
Net Cash Paid (Received) for Income Taxes 22.8
 (27.9)
Noncash Acquisitions Under Finance Leases 66.7
 43.5
Construction Expenditures Included in Current Liabilities as of September 30, 1,018.9
 882.3
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, 
 12.1
Noncash Contribution of Assets by Noncontrolling Interest 
 84.0
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage 
 2.1
Noncontrolling Interest assumed with Sempra Renewable LLC and Santa Rita East Acquisition 253.4
 
Liabilities assumed with Sempra Renewable LLC and Santa Rita East Acquisition 32.4
 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.



AEP TEXAS INC.
AND SUBSIDIARIES



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

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 Three Months Ended Nine Months Ended
 September 30, September 30,
 2019 2018 2019 2018
 (in millions of KWhs)
Retail: 
  
    
Residential4,148
 3,893
 9,580
 9,679
Commercial3,152
 2,987
 7,997
 7,916
Industrial2,168
 2,216
 6,556
 6,705
Miscellaneous197
 182
 512
 490
Total Retail (a)9,665
 9,278
 24,645
 24,790

(a)2018 KWhs have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail KWhs. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.

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,
 2019 2018 2019 2018
 (in degree days)
Actual – Heating (a)
 
 180
 234
Normal – Heating (b)
 
 190
 194
        
Actual – Cooling (c)1,587
 1,424
 2,679
 2,612
Normal – Cooling (b)1,368
 1,367
 2,425
 2,413

(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.



Third Quarter of 2019 Compared to Third Quarter of 2018
Reconciliation of Third Quarter of 2018 to Third Quarter of 2019
Net Income
(in millions)
 
Third Quarter of 2018 $57.8
   
Changes in Gross Margin:  
Retail Margins 12.6
Margins from Off-system Sales 16.7
Transmission Revenues 23.9
Other Revenues 4.7
Total Change in Gross Margin 57.9
   
Changes in Expenses and Other:  
Other Operation and Maintenance 6.7
Depreciation and Amortization (36.9)
Taxes Other Than Income Taxes (3.5)
Interest Income (0.1)
Allowance for Equity Funds Used During Construction (0.7)
Non-Service Cost Components of Net Periodic Benefit Cost (0.3)
Interest Expense 1.5
Total Change in Expenses and Other (33.3)
   
Income Tax Expense (Benefit) (5.4)
   
Third Quarter of 2019 $77.0

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

Retail Margins increased $13 million primarily due to the following:
An $8 million increase in weather-related usage primarily due to an 11% increase in cooling degree days.
A $4 million increase in weather-normalized margins primarily in the residential class.
Margins from Off-system Sales increased $17 million due to higher affiliated PPA revenues. This increase was partially offset below in Other Operation and Maintenance expenses and in Depreciation and Amortization expenses.
Transmission Revenues increased $24 million primarily due to the recovery of increased transmission investment in ERCOT.
Other Revenues increased $5 million primarily due to securitization revenue related to Transition Funding. This decrease was offset below in Depreciation and Amortization expenses and in Interest Expense.

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

Other Operation and Maintenance expenses decreased $7 million primarily due to the following:
A $4 million decrease in expenses associated with Oklaunion Power Station. This decrease was partially offset in Margins from Off-system Sales above and in Depreciation and Amortization expenses below.
A $3 million decrease in ERCOT transmission expenses. This decrease was partially offset in Retail Margins above.


Depreciation and Amortization expenses increased $37 million primarily due to the following:
A $16 million increase in depreciation expense due to a change in the useful life of the Oklaunion Power Station. This increase was partially offset in Margins from Off-system Sales above and in Other Operation and Maintenance expenses above.
An $11 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets primarily related to advanced metering systems.
A $7 million increase in securitization amortizations primarily related to Transition Funding. This increase was offset in Other Revenues above and in Interest Expense below.
Taxes Other Than Income Taxes increased $4 million primarily due to increased property taxes as a result of additional investments in transmission and distribution assets and higher tax rates.
Interest Expense decreased $2 million primarily due to the following:
A $5 million decrease due to the 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 $3 million decrease in expense related to Transition Funding Securitization assets. This decrease was offset above in Other Revenues and Depreciation and Amortization expenses.
These decreases were partially offset by:
A $2 million increase due to higher long-term debt balances.
Income Tax Expense (Benefit) increased $5 million primarily due to an increase in pretax book income.


Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018
Reconciliation of Nine Months Ended September 30, 2018 to Nine Months Ended September 30, 2019
Net Income
(in millions)
 
Nine Months Ended September 30, 2018 $151.1
   
Changes in Gross Margin:  
Retail Margins 
Margins from Off-system Sales 59.3
Transmission Revenues 62.3
Other Revenues 1.9
Total Change in Gross Margin 123.5
   
Changes in Expenses and Other:  
Other Operation and Maintenance (49.9)
Depreciation and Amortization (99.9)
Taxes Other Than Income Taxes (8.0)
Interest Income 1.5
Allowance for Equity Funds Used During Construction (6.9)
Non-Service Cost Components of Net Periodic Benefit Cost (0.8)
Interest Expense 16.2
Total Change in Expenses and Other (147.8)
   
Income Tax Expense (Benefit) 65.2
   
Nine Months Ended September 30, 2019 $192.0
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals were as follows:
Retail Margins were unchanged primarily due to the following:
A $7 million decrease in revenues associated with the Transmission Cost Recovery Factor revenue rider. This decrease was partially offset in Other Operation and Maintenance expenses below.
A $5 million decrease in weather-related usage primarily due to a 23% decrease in heating degree days, partially offset by a 3% increase in cooling degree days.
These decreases were offset by:
A $12 million increase in weather-normalized margins primarily in the residential and commercial classes.
Margins from Off-system Sales increased $59 million due to higher affiliated PPA revenues. This increase was partially offset below in Other Operation and Maintenance expenses and in Depreciation and Amortization expenses.
Transmission Revenues increased $62 million primarily due to recovery of increased transmission investment in ERCOT.
Expenses and Other and Income Tax Expense (Benefit) changed between years as follows:
Other Operation and Maintenance expenses increased $50 million primarily due to the following:
A $64 million increase in expense due to the partial amortization of the Texas Storm Cost Securitization regulatory asset as a result of the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019. This increase was offset in Income Tax Expense (Benefit) below.
These increases were partially offset by:
A $7 million decrease in distribution expenses.
A $7 million decrease in ERCOT transmission expenses. This decrease was partially offset in Retail Margins above.
A $5 million decrease in expenses associated with Oklaunion Power Station. This decrease was partially offset in Margins from Off-system Sales above and in Depreciation and Amortization expenses below.



Depreciation and Amortization expenses increased $100 million primarily due to the following:
A $49 million increase in depreciation expense due to a change in the useful life of the Oklaunion Power Station. This increase was offset above in Margins from Off-system Sales and in Other Operation and Maintenance expenses.
A $34 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets primarily related to advanced metering systems.
A $9 million increase in securitization amortizations primarily related to Transition Funding. This increase was offset in Other Revenues above and in Interest Expense below.
A $6 million increase in ARO associated with Oklaunion Power Station.
Taxes Other Than Income Taxes increased $8 million primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
Allowance for Equity Funds Used During Construction decreased $7 million primarily due to a decrease in the Equity component as a result of higher short-term debt balances, partially offset by increased transmission projects.
Interest Expense decreased $16 million primarily due to:
A $21 million decrease due to the 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.
An $8 million decrease in expense related to Transition Funding Securitization assets. This decrease was offset above in Other Revenues and Depreciation and Amortization expenses.
These decreases were partially offset by:
An $11 million increase due to higher long-term debt balances.
Income Tax Expense (Benefit) decreased $65 million primarily due to the amortization of Excess ADIT not subject to normalization requirements as approved in the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019. This decrease was partially offset above in Other Operation and Maintenance expenses.



AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2019 and 2018
(in millions)
(Unaudited)
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2019 2018 2019 2018
REVENUES        
Electric Transmission and Distribution $445.4
 $404.5
 $1,190.3
 $1,127.0
Sales to AEP Affiliates 42.7
 27.5
 125.1
 63.3
Other Revenues 1.2
 1.4
 2.6
 3.0
TOTAL REVENUES 489.3
 433.4
 1,318.0
 1,193.3
         
EXPENSES  
  
  
  
Fuel and Other Consumables Used for Electric Generation 11.2
 13.2
 29.1
 27.9
Other Operation 128.2
 133.4
 349.2
 368.4
Maintenance 21.7
 23.2
 136.9
 67.8
Depreciation and Amortization 170.2
 133.3
 464.8
 364.9
Taxes Other Than Income Taxes 39.8
 36.3
 110.3
 102.3
TOTAL EXPENSES 371.1
 339.4
 1,090.3
 931.3
         
OPERATING INCOME 118.2
 94.0
 227.7
 262.0
         
Other Income (Expense):  
  
  
  
Interest Income 0.4
 0.5
 1.5
 
Allowance for Equity Funds Used During Construction 5.1
 5.8
 8.3
 15.2
Non-Service Cost Components of Net Periodic Benefit Cost 2.8
 3.1
 8.4
 9.2
Interest Expense (35.8) (37.3) (92.7) (108.9)
         
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 90.7
 66.1
 153.2
 177.5
         
Income Tax Expense (Benefit) 13.7
 8.3
 (38.8) 26.4
         
NET INCOME $77.0
 $57.8
 $192.0
 $151.1
The common stock of AEP Texas is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.



AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2019 and 2018
(in millions)
(Unaudited)
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2019 2018 2019 2018
Net Income $77.0
 $57.8
 $192.0
 $151.1
         
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, 2019 and 2018, Respectively, and $0.2 and $0.2 for the Nine Months Ended September 30, 2019 and 2018, Respectively 0.3
 0.3
 0.8
 0.8
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2019 and 2018, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2019 and 2018, Respectively 
 
 0.1
 0.1
         
TOTAL OTHER COMPREHENSIVE INCOME 0.3
 0.3
 0.9
 0.9
         
TOTAL COMPREHENSIVE INCOME $77.3
 $58.1
 $192.9
 $152.0
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.



AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2019 and 2018
(in millions)
(Unaudited)
  Paid-in
Capital
 Retained
Earnings
 Accumulated
Other
Comprehensive
Income (Loss)
 Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017 $1,057.9
 $1,124.6
 $(12.6) $2,169.9
         
Capital Contribution from Parent 100.0
     100.0
ASU 2018-02 Adoption   1.8
 (2.7) (0.9)
Net Income   46.8
   46.8
Other Comprehensive Income     0.3
 0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018 1,157.9
 1,173.2
 (15.0) 2,316.1
         
Net Income  
 46.5
  
 46.5
Other Comprehensive Income  
  
 0.3
 0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2018 1,157.9
 1,219.7
 (14.7) 2,362.9
         
Net Income   57.8
   57.8
Other Comprehensive Income     0.3
 0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2018 $1,157.9
 $1,277.5
 $(14.4) $2,421.0
         
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018 $1,257.9
 $1,337.7
 $(15.1) $2,580.5
         
Capital Contribution from Parent 200.0
     200.0
Net Income   34.4
   34.4
Other Comprehensive Income     0.3
 0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2019 1,457.9
 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, 2019 1,457.9
 1,452.7
 (14.5) 2,896.1
         
Net Income   77.0
   77.0
Other Comprehensive Income     0.3
 0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2019 $1,457.9
 $1,529.7
 $(14.2) $2,973.4

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.



AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2019 and December 31, 2018
(in millions)
(Unaudited)
  September 30, December 31,
  2019 2018
CURRENT ASSETS    
Cash and Cash Equivalents $0.1
 $3.1
Restricted Cash for Securitized Transition Funding 114.3
 156.7
Advances to Affiliates 7.7
 8.0
Accounts Receivable:    
Customers 148.0
 110.9
Affiliated Companies 17.6
 15.0
Accrued Unbilled Revenues 82.7
 70.4
Miscellaneous 0.2
 1.9
Allowance for Uncollectible Accounts (1.6) (1.3)
Total Accounts Receivable 246.9
 196.9
Fuel 7.1
 8.8
Materials and Supplies 54.6
 52.8
Accrued Tax Benefits 111.3
 44.9
Prepayments and Other Current Assets 6.4
 5.3
TOTAL CURRENT ASSETS 548.4
 476.5
     
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Generation 351.8
 352.1
Transmission 4,102.8
 3,683.6
Distribution 4,122.2
 4,043.2
Other Property, Plant and Equipment 775.3
 727.9
Construction Work in Progress 978.4
 836.2
Total Property, Plant and Equipment 10,330.5
 9,643.0
Accumulated Depreciation and Amortization 1,742.7
 1,651.2
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 8,587.8
 7,991.8
     
OTHER NONCURRENT ASSETS    
Regulatory Assets 259.6
 430.0
Securitized Assets
(September 30, 2019 and December 31, 2018 Amounts Include $693 and $636.8, Respectively, Related to Transition Funding and Restoration Funding)
 698.1
 649.1
Deferred Charges and Other Noncurrent Assets 161.9
 56.3
TOTAL OTHER NONCURRENT ASSETS 1,119.6
 1,135.4
     
TOTAL ASSETS $10,255.8
 $9,603.7
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.



AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2019 and December 31, 2018
(in millions)
(Unaudited)
  September 30, December 31,
  2019 2018
CURRENT LIABILITIES    
Advances from Affiliates $74.8
 $216.0
Accounts Payable:    
General 224.1
 276.5
Affiliated Companies 41.0
 30.3
Long-term Debt Due Within One Year – Nonaffiliated
(September 30, 2019 and December 31, 2018 Amounts Include $280.8 and $251.1, Respectively, Related to Transition Funding and Restoration Funding)
 391.4
 501.1
Risk Management Liabilities 0.3
 0.2
Accrued Taxes 108.5
 75.5
Accrued Interest
(September 30, 2019 and December 31, 2018 Amounts Include $6.1 and $11.3, Respectively, Related to Transition Funding and Restoration Funding)
 50.6
 37.3
Oklaunion Purchase Power Agreement 28.7
 24.3
Obligations Under Operating Leases 11.7
 
Other Current Liabilities 85.1
 98.3
TOTAL CURRENT LIABILITIES 1,016.2
 1,259.5
     
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated
(September 30, 2019 and December 31, 2018 Amounts Include $530.5 and $540.1, Respectively, Related to Transition Funding and Restoration Funding)
 3,755.1
 3,380.2
Long-term Risk Management Liabilities 0.1
 
Deferred Income Taxes 977.7
 913.1
Regulatory Liabilities and Deferred Investment Tax Credits 1,325.1
 1,344.3
Oklaunion Purchase Power Agreement 
 22.1
Obligations Under Operating Leases 71.1
 
Deferred Credits and Other Noncurrent Liabilities 137.1
 104.0
TOTAL NONCURRENT LIABILITIES 6,266.2
 5,763.7
     
TOTAL LIABILITIES 7,282.4
 7,023.2
     
Rate Matters (Note 4) 

 

Commitments and Contingencies (Note 5) 

 

     
COMMON SHAREHOLDER’S EQUITY    
Paid-in Capital 1,457.9
 1,257.9
Retained Earnings 1,529.7
 1,337.7
Accumulated Other Comprehensive Income (Loss) (14.2) (15.1)
TOTAL COMMON SHAREHOLDER’S EQUITY 2,973.4
 2,580.5
     
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $10,255.8
 $9,603.7
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.



AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2019 and 2018
(in millions)
(Unaudited)
  Nine Months Ended September 30,
  2019 2018
OPERATING ACTIVITIES  
  
Net Income $192.0
 $151.1
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
Depreciation and Amortization 464.8
 364.9
Deferred Income Taxes (0.6) (21.2)
Allowance for Equity Funds Used During Construction (8.3) (15.2)
Mark-to-Market of Risk Management Contracts 0.2
 
Change in Other Noncurrent Assets 0.5
 (55.7)
Change in Other Noncurrent Liabilities 6.5
 67.1
Changes in Certain Components of Working Capital:  
  
Accounts Receivable, Net (50.0) (26.5)
Fuel, Materials and Supplies (0.1) (2.4)
Accounts Payable 17.8
 (19.1)
Accrued Taxes, Net (33.4) 40.0
Other Current Assets (0.7) (6.3)
Other Current Liabilities (12.9) 14.1
Net Cash Flows from Operating Activities 575.8
 490.8
     
INVESTING ACTIVITIES  
  
Construction Expenditures (954.5) (1,096.1)
Change in Advances to Affiliates, Net 0.3
 103.9
Other Investing Activities 18.4
 31.1
Net Cash Flows Used for Investing Activities (935.8) (961.1)
     
FINANCING ACTIVITIES  
  
Capital Contribution from Parent 200.0
 100.0
Issuance of Long-term Debt – Nonaffiliated 627.5
 494.0
Change in Advances from Affiliates, Net (141.2) 77.8
Retirement of Long-term Debt – Nonaffiliated (366.8) (231.7)
Principal Payments for Finance Lease Obligations (3.8) (3.6)
Other Financing Activities (1.1) 0.9
Net Cash Flows from Financing Activities 314.6
 437.4
     
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding (45.4) (32.9)
Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding at Beginning of Period 159.8
 157.2
Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding at End of Period $114.4
 $124.3
     
SUPPLEMENTARY INFORMATION  
  
Cash Paid for Interest, Net of Capitalized Amounts $95.1
 $92.2
Net Cash Paid (Received) for Income Taxes 28.7
 (14.2)
Noncash Acquisitions Under Finance Leases 6.9
 8.9
Construction Expenditures Included in Current Liabilities as of September 30, 183.6
 176.4
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.





AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES




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, As of September 30,
 2017 2016 2019 2018
 (in millions) (in millions)
Plant In Service $4,684.4
 $3,260.7
 $7,409.0
 $5,988.7
CWIP 1,383.1
 1,328.6
Accumulated Depreciation 151.5
 86.6
Construction Work in Progress 1,858.4
 1,772.9
Accumulated Depreciation and Amortization 368.8
 234.6
Total Transmission Property, Net $5,916.0
 $4,502.7
 $8,898.6
 $7,527.0


Third Quarter of 20172019 Compared to Third Quarter of 20162018
Reconciliation of Third Quarter of 2016 to Third Quarter of 2017
Reconciliation of Third Quarter of 2018 to Third Quarter of 2019Reconciliation of Third Quarter of 2018 to Third Quarter of 2019
Net Income(in millions)
    
Third Quarter of 2016 $52.4
Third Quarter of 2018 $78.1
    
Changes in Transmission Revenues:    
Transmission Revenues 42.0
 65.3
Total Change in Transmission Revenues 42.0
 65.3
    
Changes in Expenses and Other:    
Other Operation and Maintenance (10.4) (1.9)
Depreciation and Amortization (8.0) (10.4)
Taxes Other Than Income Taxes (4.9) (7.7)
Interest Income 0.1
 0.3
Allowance for Equity Funds Used During Construction (1.6) 3.0
Interest Expense (5.9) (6.6)
Total Change in Expenses and Other (30.7) (23.3)
    
Income Tax Expense (3.8) (12.5)
    
Third Quarter of 2017 $59.9
Third Quarter of 2019 $107.6


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 $65 million primarily due to continued investment in transmission assets.
Transmission Revenues increased $42 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 and Maintenance expenses increased $10 million primarily due to increased transmission investment.
Depreciation and Amortization expenses increased $8 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 additional transmission investment.
Interest Expense increased $6 million primarily due to higher outstanding long-term debt balances.
Income Tax Expense increased $4 million primarily due to an increase in pretax book income.
Depreciation and Amortization expenses increased $10 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $8 million primarily due to higher property taxes as a result of increased transmission investment.
Allowance for Equity Funds Used During Construction increased $3 million primarily due to higher CWIP balances.
Interest Expense increased $7 million primarily due to higher long-term debt balances.
Income Tax Expense increased $13 million primarily due to higher pretax book income.



Nine Months Ended September 30, 20172019 Compared to Nine Months Ended September 30, 20162018
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
Reconciliation of Nine Months Ended September 30, 2018 to Nine Months Ended September 30, 2019
Net Income
(in millions)
Nine Months Ended September 30, 2018$244.2

Changes in Transmission Revenues:
Transmission Revenues183.9
Total Change in Transmission Revenues183.9

Changes in Expenses and Other:
Other Operation and Maintenance(3.4)
Depreciation and Amortization(30.9)
Taxes Other Than Income Taxes(23.3)
Interest Income0.8
Allowance for Equity Funds Used During Construction12.4
Interest Expense(8.8)
Total Change in Expenses and Other(53.2)

Income Tax Expense(27.0)

Nine Months Ended September 30, 2019$347.9

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 $184 million primarily due to continued investment in transmission assets.
Transmission Revenues increased $191 million primarily due to the current year favorable impact of the modification of the PJM OATT formula rates combined with an increase driven by continued investment in transmission assets.

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

Other Operation and Maintenance expenses increased $20 million primarily due to increased transmission investment.
Depreciation and Amortization
Depreciation and Amortization expenses increased $31 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $23 million primarily due to higher property taxes as a result of increased transmission investment.
Allowance for Equity Funds Used During Construction increased $12 millionprimarily due to the following:
A $13 million increase primarily due to higher depreciable base.
CWIP balances.
Taxes Other Than Income Taxes increased $17A $12 million primarily due to increased property taxes as a result of additional transmission investment.
Allowance for Equity Funds Used During Construction decreased $4 millionprimarilyincrease due to the FERC transmission complaint and an increase in the amountFERC’s approval of short term debt,a settlement agreement.
These increases were partially offset by an increase in the CWIP balance.
by:
Interest Expense increased $16A $13 million primarilydecrease due to higher outstanding long-term debt balances.recent FERC audit findings.
Interest Expense increased $9 million primarily due to higher long-term debt balances.
Income Tax Expense increased $27 million primarily due to higher pretax book income.

Income Tax Expense increased $41 million primarily due to an increase in pretax book income.







AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20172019 and 20162018
(in millions)
(Unaudited)
 Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended
 September 30, September 30, September 30, September 30,
 2017 2016 2017 2016 2019 2018 2019 2018
REVENUES                
Transmission Revenues $35.9
 $33.5
 $99.2
 $89.6
 $54.0
 $46.0
 $162.1
 $132.3
Sales to AEP Affiliates 131.4
 91.8
 450.2
 268.4
 205.7
 148.4
 608.0
 453.8
Other Revenues 
 
 
 0.1
TOTAL REVENUES 167.3
 125.3
 549.4
 358.0
 259.7
 194.4
 770.1
 586.2
                
EXPENSES  
    
  
  
  
  
  
Other Operation 18.4
 7.5
 38.8
 21.0
 26.0
 24.5
 61.7
 59.6
Maintenance 1.4
 1.9
 6.8
 4.8
 3.2
 2.8
 8.9
 7.6
Depreciation and Amortization 24.8
 16.8
 70.9
 47.5
 45.3
 34.9
 128.4
 97.5
Taxes Other Than Income Taxes 27.6
 22.7
 82.0
 65.4
 42.9
 35.2
 126.2
 102.9
TOTAL EXPENSES 72.2
 48.9
 198.5
 138.7
 117.4
 97.4
 325.2
 267.6
                
OPERATING INCOME 95.1
 76.4
 350.9
 219.3
 142.3
 97.0
 444.9
 318.6
                
Other Income (Expense):  
    
  
  
  
  
  
Interest Income 0.2
 0.1
 0.5
 0.2
 0.8
 0.5
 2.1
 1.3
Allowance for Equity Funds Used During Construction 11.7
 13.3
 36.0
 39.7
 21.0
 18.0
 61.1
 48.7
Interest Expense (16.9) (11.0) (48.6) (32.3) (26.4) (19.8) (69.5) (60.7)
                
INCOME BEFORE INCOME TAX EXPENSE 90.1
 78.8
 338.8
 226.9
 137.7
 95.7
 438.6
 307.9
                
Income Tax Expense 30.2
 26.4
 114.5
 73.9
 30.1
 17.6
 90.7
 63.7
                
NET INCOME $59.9
 $52.4
 $224.3
 $153.0
 $107.6
 $78.1
 $347.9
 $244.2
See Condensed Notes to Condensed Consolidated Financial Statements of Registrants beginning on page 118126.




AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY
For the Nine Months Ended September 30, 20172019 and 20162018
(in millions)
(Unaudited)
 Paid-in
Capital
 Retained
Earnings
 Total Member’s Equity Paid-in
Capital
 Retained
Earnings
 Total
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2015 $1,243.0
 $309.9
 $1,552.9
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2017 $1,816.6
 $773.3
 $2,589.9
      
Capital Contribution from Member 65.0
   65.0
Net Income  
 84.1
 84.1
TOTAL MEMBER'S EQUITY – MARCH 31, 2018 1,881.6
 857.4
 2,739.0
            
Capital Contributions from Member 116.0
   116.0
 312.0
   312.0
Net Income  
 153.0
 153.0
   82.0
 82.0
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2016 $1,359.0
 $462.9
 $1,821.9
TOTAL MEMBER'S EQUITY – JUNE 30, 2018 2,193.6
 939.4
 3,133.0
            
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2016 $1,455.0
 $502.6
 $1,957.6
Capital Contribution from Member 205.0
   205.0
Net Income   78.1
 78.1
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2018 $2,398.6
 $1,017.5
 $3,416.1
            
Capital Contributions from Member 185.5
   185.5
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2018 $2,480.6
 $1,089.2
 $3,569.8
      
Net Income  
 224.3
 224.3
   104.3
 104.3
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2017 $1,640.5
 $726.9
 $2,367.4
TOTAL MEMBER'S EQUITY – MARCH 31, 2019 2,480.6
 1,193.5
 3,674.1
      
Net Income   136.0
 136.0
TOTAL MEMBER'S EQUITY – JUNE 30, 2019 2,480.6
 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
See Condensed Notes to Condensed Consolidated Financial Statements of Registrants beginning on page 118126.





AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20172019 and December 31, 20162018
(in millions)
(Unaudited)
 September 30, December 31, September 30, December 31,
 2017 2016 2019 2018
CURRENT ASSETS        
Advances to Affiliates $290.9
 $67.1
 $275.2
 $96.9
Accounts Receivable:        
Customers 19.5
 11.3
 23.5
 11.8
Affiliated Companies 102.8
 66.6
 61.3
 61.0
Total Accounts Receivable 122.3
 77.9
 84.8
 72.8
Materials and Supplies 16.0
 5.0
 15.1
 19.0
Accrued Tax Benefits 12.7
 26.0
 9.7
 33.4
Prepayments and Other Current Assets 8.1
 2.8
 4.4
 3.4
TOTAL CURRENT ASSETS 450.0
 178.8
 389.2
 225.5
        
TRANSMISSION PROPERTY        
Transmission Property 4,570.9
 3,973.5
 7,181.8
 6,515.8
Other Property, Plant and Equipment 113.5
 99.4
 227.2
 174.0
Construction Work in Progress 1,383.1
 981.3
 1,858.4
 1,578.3
Total Transmission Property 6,067.5
 5,054.2
 9,267.4
 8,268.1
Accumulated Depreciation and Amortization 151.5
 99.6
 368.8
 271.9
TOTAL TRANSMISSION PROPERTY NET
 5,916.0
 4,954.6
 8,898.6
 7,996.2
        
OTHER NONCURRENT ASSETS        
Accounts Receivable - Affiliated Companies 13.8
 
Accounts Receivable – Affiliated Companies 4.8
 
Regulatory Assets 138.0
 112.3
 7.3
 12.9
Deferred Property Taxes 29.8
 102.2
 47.2
 157.9
Deferred Charges and Other Noncurrent Assets 1.3
 1.9
 5.6
 1.6
TOTAL OTHER NONCURRENT ASSETS 182.9
 216.4
 64.9
 172.4
        
TOTAL ASSETS $6,548.9
 $5,349.8
 $9,352.7
 $8,394.1
See Condensed Notes to Condensed Consolidated Financial Statements of Registrants beginning on page 118126.




AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND MEMBER’S EQUITY
September 30, 20172019 and December 31, 20162018
(in millions)
(Unaudited)
 September 30, December 31, September 30, December 31,
 2017 2016 2019 2018
CURRENT LIABILITIES        
Advances from Affiliates $32.8
 $4.1
 $9.1
 $45.4
Accounts Payable:        
General 233.2
 289.7
 319.1
 347.2
Affiliated Companies 50.0
 43.1
 57.1
 56.0
Long-term Debt Due Within One Year – Nonaffiliated 85.0
 85.0
Accrued Taxes 112.5
 191.8
 172.4
 288.9
Accrued Interest 28.9
 10.5
 39.7
 15.9
Obligations Under Operating Leases 2.3
 
Other Current Liabilities 10.4
 10.9
 25.5
 3.8
TOTAL CURRENT LIABILITIES 467.8
 550.1
 710.2
 842.2
        
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated 2,550.0
 1,932.0
 3,426.9
 2,738.0
Deferred Income Taxes 1,073.1
 862.1
 751.4
 704.4
Regulatory Liabilities 60.5
 44.0
 541.2
 521.3
Obligations Under Operating Leases 2.2
 
Deferred Credits and Other Noncurrent Liabilities 30.1
 4.0
 3.1
 18.4
TOTAL NONCURRENT LIABILITIES 3,713.7
 2,842.1
 4,724.8
 3,982.1
        
TOTAL LIABILITIES 4,181.5
 3,392.2
 5,435.0
 4,824.3
        
Rate Matters (Note 4) 
 
 

 

Commitments and Contingencies (Note 5) 
 
 

 

        
MEMBER’S EQUITY        
Paid-in Capital 1,640.5
 1,455.0
 2,480.6
 2,480.6
Retained Earnings 726.9
 502.6
 1,437.1
 1,089.2
TOTAL MEMBER’S EQUITY 2,367.4
 1,957.6
 3,917.7
 3,569.8
        
TOTAL LIABILITIES AND MEMBER’S EQUITY $6,548.9
 $5,349.8
 $9,352.7
 $8,394.1
See Condensed Notes to Condensed Consolidated Financial Statements of Registrants beginning on page 118126.




AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20172019 and 20162018
(in millions)
(Unaudited)
 Nine Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2019 2018
OPERATING ACTIVITIES        
Net Income $224.3
 $153.0
 $347.9
 $244.2
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:        
Depreciation and Amortization 70.9
 47.5
 128.4
 97.5
Deferred Income Taxes 193.0
 161.2
 36.7
 76.3
Allowance for Equity Funds Used During Construction (36.0) (39.7) (61.1) (48.7)
Property Taxes 72.4
 63.5
 110.7
 86.9
Long-term Accounts Receivable - Affiliated (13.8) 
Long-term Accounts Receivable – Affiliated (4.8) (3.1)
Change in Other Noncurrent Assets 7.6
 (6.4) 5.8
 12.7
Change in Other Noncurrent Liabilities 25.7
 0.6
 (3.8) 18.0
Changes in Certain Components of Working Capital:    
    
Accounts Receivable, Net (44.4) (43.3) (5.1) 23.5
Materials and Supplies (11.0) (1.5) 3.9
 (2.8)
Accounts Payable 8.6
 (1.7) 4.1
 3.3
Accrued Taxes, Net (66.0) 61.2
 (92.8) (73.2)
Accrued Interest 18.4
 11.3
 23.8
 20.9
Other Current Assets (5.3) (0.1) (1.0) (0.5)
Other Current Liabilities 0.5
 0.1
 (8.5) (28.0)
Net Cash Flows from Operating Activities 444.9
 405.7
 484.2
 427.0
        
INVESTING ACTIVITIES  
  
  
  
Construction Expenditures (1,050.7) (799.8) (959.9) (1,171.8)
Change in Advances to Affiliates, Net (223.8) 83.7
 (178.3) (131.7)
Acquisitions of Assets (7.6) (13.2)
Other Investing Activities (2.9) (4.6) 12.0
 1.2
Net Cash Flows Used for Investing Activities (1,277.4) (720.7) (1,133.8) (1,315.5)
        
FINANCING ACTIVITIES    
    
Capital Contributions from Member 185.5
 116.0
 
 582.0
Issuance of Long-term Debt - Nonaffiliated 618.3
 
Issuance of Long-term Debt – Nonaffiliated 685.9
 321.1
Change in Advances from Affiliates, Net 28.7
 199.0
 (36.3) (14.6)
Net Cash Flows from Financing Activities 832.5
 315.0
 649.6
 888.5
        
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
 $43.0
 $38.4
Net Cash Paid (Received) for Income Taxes (93.4) (209.8) 29.8
 (32.1)
Construction Expenditures Included in Current Liabilities as of September 30, 239.0
 204.8
 315.1
 237.0
See Condensed Notes to Condensed Consolidated Financial Statements of Registrants beginning on page 118126.








APPALACHIAN POWER COMPANY
AND SUBSIDIARIES




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


RESULTS OF OPERATIONS


KWh Sales/Degree Days


Summary of KWh Energy Sales
Three Months Ended Nine Months EndedThree Months Ended Nine Months Ended
September 30, September 30,September 30, September 30,
2017 2016 2017 20162019 2018 2019 2018
(in millions of KWhs)(in millions of KWhs)
Retail: 
  
  
  
 
  
  
  
Residential2,488
 2,845
 7,829
 8,743
2,728
 2,662
 8,401
 8,895
Commercial1,673
 1,823
 4,805
 5,125
1,721
 1,715
 4,812
 4,980
Industrial2,431
 2,391
 7,106
 7,022
2,487
 2,433
 7,180
 7,181
Miscellaneous202
 217
 613
 637
216
 215
 640
 644
Total Retail(a)6,794
 7,276
 20,353
 21,527
7,152
 7,025
 21,033
 21,700
              
Wholesale994
 1,029
 2,684
 2,413
938
 1,143
 2,667
 2,252
              
Total KWhs7,788
 8,305
 23,037
 23,940
8,090
 8,168
 23,700
 23,952


(a)2018 KWhs have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail KWhs. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.

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)
 
 1,000
 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
 Three Months Ended Nine Months Ended
 September 30, September 30,
 2019 2018 2019 2018
 (in degree days)
Actual – Heating (a)
 
 1,295
 1,518
Normal – Heating (b)3
 2
 1,407
 1,410
        
Actual – Cooling (c)1,071
 950
 1,530
 1,495
Normal – Cooling (b)815
 814
 1,194
 1,184

(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 2019 Compared to Third Quarter of 2018
Reconciliation of Third Quarter of 2018 to Third Quarter of 2019
Net Income
(in millions)
 
Third Quarter of 2018 $87.1
   
Changes in Gross Margin:  
Retail Margins 68.2
Transmission Revenues 12.8
Other Revenues 0.7
Total Change in Gross Margin 81.7
   
Changes in Expenses and Other:  
Other Operation and Maintenance 27.2
Depreciation and Amortization (13.0)
Taxes Other Than Income Taxes (3.1)
Interest Income (0.1)
Carrying Costs Income (0.2)
Allowance for Equity Funds Used During Construction 0.7
Non-Service Cost Components of Net Periodic Benefit Cost (0.2)
Interest Expense (0.8)
Total Change in Expenses and Other 10.5
   
Income Tax Expense (Benefit) (75.0)
   
Third Quarter of 2019 $104.3

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

Retail Margins increased $68 million primarily due to the following:
A $78 million increase due to a 2018 reduction in the deferred fuel under recovery balance as a result of the 2018 West Virginia Tax Reform settlement. This increase was offset in Income Tax Expense (Benefit) below.
A $15 million increase in deferred fuel related to recoverable PJM expenses that were offset below.
An $11 million increase in weather-related usage primarily driven by a 13% increase in cooling degree days.
A $10 million increase due to 2018 Virginia legislation which increased non-recoverable fuel expense in the prior year.
An $8 million increase due to revenue primarily from rate riders in West Virginia. This increase was offset in other expense items below.
A $6 million increase due to a base rate increase in West Virginia implemented in March 2019.
These increases were partially offset by:
A $56 million decrease due to customer refunds related to Tax Reform. This decrease was partially offset in Income Tax Expense (Benefit) below.
A $3 million decrease in weather-normalized margins occurring across all retail classes.
Transmission Revenues increased $13 million primarily due to 2018 provisions for refunds.



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

Other Operation and Maintenance expenses decreased $27 million primarily due to the following:
A $39 million decrease due to the extinguishment of certain regulatory asset balances as agreed to within the 2018 West Virginia Tax Reform settlement.
A $4 million decrease in maintenance expense at various generation plants.
These decreases were partially offset by:
An $11 million increase in recoverable PJM transmission expenses which were partially offset within Gross Margins above.
A $9 million increase in PJM expenses related to the annual formula rate true-up.
Depreciation and Amortization expenses increased $13 million primarily due to a higher depreciable base and an increase in West Virginia depreciation rates beginning in March 2019.
Taxes Other Than Income Taxes increased $3 million primarily due to an increase in West Virginia business and occupational taxes.
Income Tax Expense (Benefit) increased $75 million primarily due to a one-time recognition of increased amortization of Excess ADIT not subject to normalization requirements as a result of the 2018 West Virginia Tax Reform settlement. This increase was partially offset in Gross Margin and Other Operation and Maintenance expenses above.


Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018
Reconciliation of Nine Months Ended September 30, 2018 to Nine Months Ended September 30, 2019
Net Income
(in millions)
 
Nine Months Ended September 30, 2018 $290.0
   
Changes in Gross Margin:  
Retail Margins (11.0)
Margins from Off-system Sales 2.0
Transmission Revenues 25.9
Other Revenues 1.1
Total Change in Gross Margin 18.0
   
Changes in Expenses and Other:  
Other Operation and Maintenance 14.4
Depreciation and Amortization (28.8)
Taxes Other Than Income Taxes (7.4)
Interest Income 0.8
Carrying Costs Income (1.2)
Allowance for Equity Funds Used During Construction 2.9
Non-Service Cost Components of Net Periodic Benefit Cost (0.6)
Interest Expense (6.5)
Total Change in Expenses and Other (26.4)
   
Income Tax Expense (Benefit) 11.9
   
Nine Months Ended September 30, 2019 $293.5

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

Retail Margins decreased $11 million primarily due to the following:
A $91 million decrease due to customer refunds related to Tax Reform. This decrease was partially offset in Income Tax Expense (Benefit) below.
A $23 million decrease in weather-normalized margins occurring across all retail classes.
A $22 million decrease in weather-related usage primarily driven by a 15% decrease in heating degree days partially offset by a 2% increase in cooling degree days.
These decreases were partially offset by:
A $78 million increase due to a 2018 reduction in the deferred fuel under recovery balance as a result of the 2018 West Virginia Tax Reform settlement. This increase was offset in Income Tax Expense (Benefit) below.
A $14 million increase primarily due to revenue from rate riders in West Virginia. This increase was offset in other expense items below.
A $12 million increase due to base rate increases in West Virginia implemented in March 2019.
A $12 million increase in deferred fuel related to recoverable PJM expenses that were offset below.
A $10 million increase due to 2018 Virginia legislation which increased non-recoverable fuel expense at APCo in the prior year.
Transmission Revenues increased $26 million primarily due to 2018 provisions for refunds.



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 $39 million decrease due to the extinguishment of certain regulatory asset balances as agreed to within the 2018 West Virginia Tax Reform settlement.
A $10 million decrease in expense due to lower current year amortization of certain regulatory assets that were extinguished in August 2018 as agreed to within the 2018 West Virginia Tax Reform settlement.
An $8 million decrease in maintenance expense at various generation plants.
A $5 million decrease in vegetation management expenses.
A $5 million decrease in storm-related expenses.
A $5 million decrease in estimated expenses for claims related to asbestos exposure.
These decreases were partially offset by:
A $42 million increase in PJM expenses primarily related to the annual formula rate true-up.
A $13 million increase due to 2019 contributions to benefit low income West Virginia residential customers as a result of the 2018 West Virginia Tax Reform settlement. This increase was offset in Income Tax Expense (Benefit) below.
A $5 million increase in employee-related expenses.
Depreciation and Amortization expenses increased $29 million primarily due to a higher depreciable base and an increase in West Virginia depreciation rates beginning in March 2019.
Taxes Other Than Income Taxes increased $7 million primarily due to an increase in West Virginia business and occupational taxes.
Interest Expense increased $7 million primarily due to higher long-term debt balances.
Income Tax Expense (Benefit) decreased $12 million primarily due to an increase in amortization of Excess ADIT not subject to normalization requirements and a decrease in pretax book income. This benefit was partially offset by the one-time recognition of increased amortization of Excess ADIT not subject to normalization requirements as a result of the 2018 West Virginia Tax Reform settlement. This decrease was partially offset in Gross Margin and Other Operation and Maintenance expenses above.



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2019 and 2018
(in millions)
(Unaudited)
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2019 2018 2019 2018
REVENUES        
Electric Generation, Transmission and Distribution $696.7
 $716.8
 $2,041.3
 $2,103.1
Sales to AEP Affiliates 56.6
 42.9
 154.6
 138.7
Other Revenues 2.2
 2.3
 8.2
 7.6
TOTAL REVENUES 755.5
 762.0
 2,204.1
 2,249.4
         
EXPENSES  
  
  
  
Fuel and Other Consumables Used for Electric Generation 177.3
 263.4
 521.8
 487.7
Purchased Electricity for Resale 78.3
 80.4
 253.4
 350.8
Other Operation 140.4
 131.9
 416.2
 380.0
Maintenance 61.5
 97.2
 184.3
 234.9
Depreciation and Amortization 118.7
 105.7
 348.3
 319.5
Taxes Other Than Income Taxes 36.7
 33.6
 108.5
 101.1
TOTAL EXPENSES 612.9
 712.2
 1,832.5
 1,874.0
         
OPERATING INCOME 142.6
 49.8
 371.6
 375.4
         
Other Income (Expense):  
  
  
  
Interest Income 0.3
 0.4
 2.1
 1.3
Carrying Costs Income 
 0.2
 
 1.2
Allowance for Equity Funds Used During Construction 4.8
 4.1
 12.5
 9.6
Non-Service Cost Components of Net Periodic Benefit Cost 4.3
 4.5
 12.8
 13.4
Interest Expense (51.6) (50.8) (152.5) (146.0)
         
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 100.4
 8.2
 246.5
 254.9
         
Income Tax Expense (Benefit) (3.9) (78.9) (47.0) (35.1)
         
NET INCOME $104.3
 $87.1
 $293.5
 $290.0
The common stock of APCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2019 and 2018
(in millions)
(Unaudited)
  
  Three Months Ended
 Nine Months Ended
  September 30, September 30,
  2019 2018 2019 2018
Net Income $104.3
 $87.1
 $293.5
 $290.0
         
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, 2019 and 2018, Respectively, and $(0.2) and $(0.2) for the Nine Months Ended September 30, 2019 and 2018, Respectively (0.3) (0.3) (0.7) (0.7)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.2) and $(0.2) for the Three Months Ended September 30, 2019 and 2018, Respectively, and $(0.5) and $(0.6) for the Nine Months Ended September 30, 2019 and 2018, Respectively (0.6) (0.7) (1.9) (2.3)
         
TOTAL OTHER COMPREHENSIVE LOSS (0.9) (1.0) (2.6) (3.0)
         
TOTAL COMPREHENSIVE INCOME $103.4
 $86.1
 $290.9
 $287.0
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2019 and 2018
(in millions)
(Unaudited)
  Common
Stock
 Paid-in
Capital
 Retained
Earnings
 Accumulated
Other
Comprehensive
Income (Loss)
 Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017 $260.4
 $1,828.7
 $1,714.1
 $1.3
 $3,804.5
           
Common Stock Dividends     (40.0)   (40.0)
ASU 2018-02 Adoption     0.1
 0.3
 0.4
Net Income     125.5
   125.5
Other Comprehensive Loss       (1.0) (1.0)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018 260.4
 1,828.7
 1,799.7
 0.6
 3,889.4
           
Common Stock Dividends  
  
 (40.0)  
 (40.0)
Net Income  
  
 77.4
  
 77.4
Other Comprehensive Loss  
  
  
 (1.0) (1.0)
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2018 260.4
 1,828.7
 1,837.1
 (0.4) 3,925.8
           
Common Stock Dividends     (40.0)   (40.0)
Net Income     87.1
   87.1
Other Comprehensive Loss       (1.0) (1.0)
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2018 $260.4
 $1,828.7
 $1,884.2
 $(1.4) $3,971.9
           
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 Income     133.7
   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 Income  
  
 104.3
  
 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
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2019 and December 31, 2018
(in millions)
(Unaudited)
  September 30, December 31,
  2019 2018
CURRENT ASSETS    
Cash and Cash Equivalents $3.5
 $4.2
Restricted Cash for Securitized Funding 17.1
 25.6
Advances to Affiliates 22.7
 23.0
Accounts Receivable:    
Customers 112.1
 146.5
Affiliated Companies 56.4
 73.4
Accrued Unbilled Revenues 56.9
 63.5
Miscellaneous 1.0
 2.3
Allowance for Uncollectible Accounts (2.3) (2.3)
Total Accounts Receivable 224.1
 283.4
Fuel 108.8
 61.3
Materials and Supplies 102.1
 100.1
Risk Management Assets 56.5
 57.2
Regulatory Asset for Under-Recovered Fuel Costs 43.7
 99.6
Prepayments and Other Current Assets 36.3
 44.3
TOTAL CURRENT ASSETS 614.8
 698.7
     
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Generation 6,560.5
 6,509.6
Transmission 3,412.4
 3,317.7
Distribution 4,126.7
 3,989.4
Other Property, Plant and Equipment 525.3
 485.8
Construction Work in Progress 667.4
 490.2
Total Property, Plant and Equipment 15,292.3
 14,792.7
Accumulated Depreciation and Amortization 4,300.2
 4,124.4
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 10,992.1
 10,668.3
     
OTHER NONCURRENT ASSETS    
Regulatory Assets 474.2
 475.8
Securitized Assets 240.6
 258.7
Long-term Risk Management Assets 0.2
 0.9
Operating Lease Assets 79.4
 
Deferred Charges and Other Noncurrent Assets 159.3
 188.1
TOTAL OTHER NONCURRENT ASSETS 953.7
 923.5
     
TOTAL ASSETS $12,560.6
 $12,290.5
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2019 and December 31, 2018
(Unaudited)
  September 30, December 31,
  2019 2018
  (in millions)
CURRENT LIABILITIES    
Advances from Affiliates $40.4
 $205.6
Accounts Payable:  
  
General 298.5
 263.8
Affiliated Companies 90.8
 84.0
Long-term Debt Due Within One Year – Nonaffiliated 215.6
 430.7
Risk Management Liabilities 1.1
 0.4
Customer Deposits 85.1
 88.4
Accrued Taxes 58.2
 89.3
Accrued Interest 67.5
 41.5
Obligations Under Operating Leases 15.3
 
Other Current Liabilities 107.6
 150.3
TOTAL CURRENT LIABILITIES 980.1
 1,354.0
     
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated 4,147.3
 3,631.9
Long-term Risk Management Liabilities 0.3
 0.2
Deferred Income Taxes 1,640.8
 1,625.8
Regulatory Liabilities and Deferred Investment Tax Credits 1,336.9
 1,449.7
Asset Retirement Obligations 108.2
 107.1
Employee Benefits and Pension Obligations 52.7
 57.1
Obligations Under Operating Leases 64.8
 
Deferred Credits and Other Noncurrent Liabilities 57.5
 58.6
TOTAL NONCURRENT LIABILITIES 7,408.5
 6,930.4
     
TOTAL LIABILITIES 8,388.6
 8,284.4
     
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 2,090.5
 1,922.0
Accumulated Other Comprehensive Income (Loss) (7.6) (5.0)
TOTAL COMMON SHAREHOLDER’S EQUITY 4,172.0
 4,006.1
     
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $12,560.6
 $12,290.5
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2019 and 2018
(in millions)
(Unaudited)
  Nine Months Ended September 30,
  2019 2018
OPERATING ACTIVITIES  
  
Net Income $293.5
 $290.0
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
Depreciation and Amortization 348.3
 319.5
Deferred Income Taxes (101.9) (83.8)
Allowance for Equity Funds Used During Construction (12.5) (9.6)
Mark-to-Market of Risk Management Contracts 2.2
 (43.7)
Deferred Fuel Over/Under-Recovery, Net 60.8
 12.8
Change in Other Noncurrent Assets 6.7
 94.8
Change in Other Noncurrent Liabilities (29.6) 3.8
Changes in Certain Components of Working Capital:  
  
Accounts Receivable, Net 61.7
 39.4
Fuel, Materials and Supplies (49.2) 53.0
Accounts Payable 40.1
 (21.5)
Accrued Taxes, Net (30.2) (20.2)
Other Current Assets 6.8
 (7.9)
Other Current Liabilities (25.1) 64.1
Net Cash Flows from Operating Activities 571.6
 690.7
     
INVESTING ACTIVITIES  
  
Construction Expenditures (607.1) (575.8)
Change in Advances to Affiliates, Net 0.3
 0.4
Other Investing Activities 22.8
 10.0
Net Cash Flows Used for Investing Activities (584.0) (565.4)
     
FINANCING ACTIVITIES  
  
Issuance of Long-term Debt – Nonaffiliated 478.2
 103.3
Change in Advances from Affiliates, Net (165.2) (87.5)
Retirement of Long-term Debt – Nonaffiliated (180.4) (24.0)
Principal Payments for Finance Lease Obligations (5.0) (5.2)
Dividends Paid on Common Stock (125.0) (120.0)
Other Financing Activities 0.6
 1.0
Net Cash Flows from (Used for) Financing Activities 3.2
 (132.4)
     
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding (9.2) (7.1)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period 29.8
 19.2
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period $20.6
 $12.1
     
SUPPLEMENTARY INFORMATION  
  
Cash Paid for Interest, Net of Capitalized Amounts $120.6
 $104.5
Net Cash Paid for Income Taxes 58.7
 26.7
Noncash Acquisitions Under Finance Leases 7.1
 3.9
Construction Expenditures Included in Current Liabilities as of September 30, 134.2
 87.6
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.




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,
 2019 2018 2019 2018
 (in millions of KWhs)
Retail: 
  
  
  
Residential1,496
 1,562
 4,159
 4,430
Commercial1,312
 1,348
 3,555
 3,708
Industrial1,937
 2,018
 5,742
 5,920
Miscellaneous16
 15
 49
 50
Total Retail (a)4,761
 4,943
 13,505
 14,108
        
Wholesale2,398
 2,613
 6,842
 7,927
        
Total KWhs7,159
 7,556
 20,347
 22,035

(a)2018 KWhs have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail KWhs. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.

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,
 2019 2018 2019 2018
 (in degree days)
Actual – Heating (a)
 2
 2,456
 2,523
Normal – Heating (b)11
 10
 2,412
 2,413
        
Actual – Cooling (c)684
 722
 917
 1,084
Normal – Cooling (b)573
 574
 836
 837

(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 20172019 Compared to Third Quarter of 20162018
Reconciliation of Third Quarter of 2016 to Third Quarter of 2017
Reconciliation of Third Quarter of 2018 to Third Quarter of 2019Reconciliation of Third Quarter of 2018 to Third Quarter of 2019
Net Income(in millions)
  
Third Quarter of 2016 $104.1
Third Quarter of 2018 $72.7
  
  
Changes in Gross Margin:  
  
Retail Margins (40.6) 17.5
Off-system Sales (1.0)
Transmission Revenues 1.8
 (1.7)
Other Revenues 0.5
 3.4
Total Change in Gross Margin (39.3) 19.2
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance 12.9
 (17.1)
Depreciation and Amortization (4.7) (2.9)
Taxes Other Than Income Taxes (0.3) (2.1)
Carrying Costs Income 0.4
Allowance for Equity Funds Used During Construction (1.8)
Other Income (2.6)
Non-Service Cost Components of Net Periodic Benefit Cost (0.1)
Interest Expense (0.8) 5.7
Total Change in Expenses and Other 5.7
 (19.1)
  
  
Income Tax Expense 15.5
Income Tax Expense (Benefit) 16.0
  
  
Third Quarter of 2017 $86.0
Third Quarter of 2019 $88.8


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 increased $18 million primarily due to the following:
A $19 million increase from rate proceedings. This increase was partially offset in other expense items below.
Retail Margins decreased $41An $8 million increase related to rider revenues, primarily due to the following:timing of the Indiana PJM/OSS rider recovery. This increase was partially offset in other expense items below.
These increases were partially offset by:
A $25$6 million decrease in weather-normalized margins across all retail classes.
A $3 million decrease in weather-related usage primarily driven bydue to a 23%5% decrease in cooling degree days.
Other Revenues increased $3 million primarily due to an increase in barging deliveries by River Transportation Division (RTD). The increase in RTD revenue was offset by a corresponding increase in Other Operation and Maintenance expenses for barging activities discussed below.
An $8 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. This decrease is partially offset by a corresponding decrease in Other Operation and Maintenance expenses below.


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


Other Operation and Maintenance expenses increased $17 million primarily due to the following:
Other Operation and MaintenanceA $15 million increase in transmission expenses decreased $13 million primarily due to a $10 million increase in recoverable PJM expenses and a $6 million increase from the following:
A $7 million decreaseamortization of credits under the 2018 Regional Transmission Enhancement Plan settlement. This increase was partially offset in storm-related expenses.Retail Margins above.
A $4 million decreaseincrease in generation plant maintenance expenses.
Depreciation and Amortization RTD expenses increased $5 million primarily due tofor barging activities. The increase in RTD expenses was offset by a higher depreciable base.
Income Tax Expense decreased $16 million primarily due to a decreasecorresponding increase in pretax book income and the recording of federal income tax adjustments.Other Revenues from barging activities discussed above.
Depreciation and Amortizationexpensesincreased $3 million primarily due to a higher depreciable base. This increase was partially offset in Retail Margins above.
Interest Expensedecreased $6 million primarily due to the reissuance of long-term debt at lower interest rates in 2018.
Income Tax Expense (Benefit) decreased $16 million primarily due to increased amortization of Excess ADIT not subject to normalization requirements and a decrease in flow-through tax expense.



Nine Months Ended September 30, 20172019 Compared to Nine Months Ended September 30, 20162018
Reconciliation of Nine Months Ended September 30, 2016 to Nine Months Ended September 30, 2017
Reconciliation of Nine Months Ended September 30, 2018 to Nine Months Ended September 30, 2019Reconciliation of Nine Months Ended September 30, 2018 to Nine Months Ended September 30, 2019
Net Income(in millions)
  
Nine Months Ended September 30, 2016 $303.8
Nine Months Ended September 30, 2018 $231.6
    
Changes in Gross Margin:  
  
Retail Margins (93.7) 89.7
Off-system Sales (0.1)
Margins from Off-system Sales (9.4)
Transmission Revenues 25.9
 (12.0)
Other Revenues 3.2
 3.7
Total Change in Gross Margin (64.7) 72.0
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance (8.3) (36.6)
Depreciation and Amortization (14.1) (54.5)
Taxes Other Than Income Taxes 0.6
 (5.7)
Interest Income 0.3
Carrying Costs Income 0.8
Allowance for Equity Funds Used During Construction (2.9)
Other Income (0.1)
Non-Service Cost Components of Net Periodic Benefit Cost (0.3)
Interest Expense (2.8) 9.7
Total Change in Expenses and Other (26.4) (87.5)
  
  
Income Tax Expense 36.0
Income Tax Expense (Benefit) 31.9
  
  
Nine Months Ended September 30, 2017 $248.7
Nine Months Ended September 30, 2019 $248.0


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 increased $90 million primarily due to the following:
Retail Margins decreasedA $94 million increase from rate proceedings, inclusive of a $30 million decrease due to the impact of Tax Reform. This increase was partially offset in other expense items below.
A $21 million increase related to rider revenues, primarily due to the following:
timing of the Indiana PJM/OSS rider recovery. This increase was partially offset in other expense items below.
A $72$6 million decrease in fuel-related expenses due to timing of recovery for fuel and other variable production costs related to wholesale contracts.
These increases were partially offset by:
A $19 million decrease in weather-related usage primarily driven bydue to a 30%15% decrease in cooling degree days and a 3% decrease in heating degree days and an 18% decrease in cooling 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$16 million decrease in weather-normalized margin primarily driven by the commercial class.margins across all retail classes.
Margins from Off-system Salesdecreased $9 million primarily due to mid-year 2018 changes in the OSS sharing mechanism.
Transmission Revenues decreased $12 million primarily due to the 2018 PJM Transmission formula rate true-up.
Other Revenues increased $4 million primarily due to an increase in barging deliveries by RTD. The increase in RTD revenue was offset by a corresponding increase in Other Operation and Maintenance expenses for barging activities discussed below.
Transmission Revenues increased $26 million primarily due to increase in formula rates driven by continued investment in transmission assets. This increase is partially offset in Other Operation and Maintenance expenses below.



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


Other Operation and Maintenance expenses increased $8$37 million primarily due to the following:
A $13$32 million increase in transmission expenses primarily due to a $44 million increase in recoverable PJM transmission expenses.expenses, partially offset by an $11 million decrease from the amortization of credits under the 2018 Regional Transmission Enhancement Plan settlement. This increase was partially offset in expense is offset within Gross MarginRetail Margins above.
A $6 million gain on the sale of propertyincrease in 2016.RTD expenses for barging activities. The increase in RTD expenses was offset by a corresponding increase in Other Revenues from barging activities discussed above.
A $5 million increase in distribution costs primarily due to vegetation management expenses.
These increases were partially offset by:
An $8A $9 million decrease in storm-related expenses.
A $5 million decrease in employee-related expenses.
Depreciation and Amortizationgeneration expenses increased $14 millionat Cook Plant primarily due to a higher depreciable base.decreased incremental refueling outage costs.
Depreciation and Amortizationexpensesincreased $55 million primarily due to increased depreciation rates approved in 2018 and a higher depreciable base. This increase was partially offset in Retail Margins above.
Taxes Other Than Income Taxes increased $6 million due to property taxes driven by an increase in utility plant.
Interest Expense decreased $10 million primarily due to the reissuance of long-term debt at lower interest rates in 2018.
Income Tax Expense (Benefit) decreased $32 million primarily due to increased amortization of Excess ADIT not subject to normalization requirements and a decrease in flow-through tax expense.

Income Tax Expense decreased $36 million primarily due to a decrease in pretax book income and the recording of federal income tax adjustments.





APPALACHIANINDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20172019 and 20162018
(in millions)
(Unaudited)
 Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended
 September 30, September 30, September 30, September 30,
 2017 2016 2017 2016 2019 2018 2019 2018
REVENUES        
        
Electric Generation, Transmission and Distribution $674.4
 $739.0
 $2,045.0
 $2,153.3
 $589.1
 $609.9
 $1,703.2
 $1,723.9
Sales to AEP Affiliates 41.9
 36.4
 130.6
 109.0
 2.7
 3.4
 7.3
 18.9
Other Revenues 3.0
 2.8
 11.8
 9.4
Other Revenues – Affiliated 16.2
 13.7
 50.4
 43.3
Other Revenues – Nonaffiliated 3.1
 2.7
 7.6
 10.1
TOTAL REVENUES 719.3
 778.2
 2,187.4
 2,271.7
 611.1
 629.7
 1,768.5
 1,796.2
                
EXPENSES  
    
  
  
  
  
  
Fuel and Other Consumables Used for Electric Generation 178.6
 190.1
 498.3
 494.1
 61.2
 95.9
 161.2
 246.8
Purchased Electricity for Resale 61.1
 69.2
 217.1
 240.9
 44.8
 48.9
 163.3
 167.7
Purchased Electricity from AEP Affiliates 61.0
 60.0
 172.1
 181.8
Other Operation 115.7
 117.6
 366.2
 349.4
 172.7
 149.3
 467.7
 425.8
Maintenance 55.8
 66.8
 187.8
 196.3
 50.9
 57.2
 163.8
 169.1
Depreciation and Amortization 102.8
 98.1
 304.1
 290.0
 88.1
 85.2
 261.6
 207.1
Taxes Other Than Income Taxes 32.3
 32.0
 93.3
 93.9
 25.1
 23.0
 78.6
 72.9
TOTAL EXPENSES 546.3
 573.8
 1,666.8
 1,664.6
 503.8
 519.5
 1,468.3
 1,471.2
                
OPERATING INCOME 173.0
 204.4
 520.6
 607.1
 107.3
 110.2
 300.2
 325.0
                
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
Other Income 3.5
 6.1
 15.3
 15.4
Non-Service Cost Components of Net Periodic Benefit Cost 4.5
 4.6
 13.3
 13.6
Interest Expense (47.2) (46.4) (143.5) (140.7) (28.8) (34.5) (85.9) (95.6)
                
INCOME BEFORE INCOME TAX EXPENSE 129.2
 162.8
 385.4
 476.5
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 86.5
 86.4
 242.9
 258.4
                
Income Tax Expense 43.2
 58.7
 136.7
 172.7
Income Tax Expense (Benefit) (2.3) 13.7
 (5.1) 26.8
                
NET INCOME $86.0
 $104.1
 $248.7
 $303.8
 $88.8
 $72.7
 $248.0
 $231.6
The common stock of APCoI&M is wholly-owned by Parent.
 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.



APPALACHIAN
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20172019 and 20162018
(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
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2019 2018 2019 2018
Net Income $88.8
 $72.7
 $248.0
 $231.6
         
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, 2019 and 2018, Respectively, and $0.3 and $0.3 for the Nine Months Ended September 30, 2019 and 2018, Respectively 0.4
 0.3
 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, 2019 and 2018, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2019 and 2018, Respectively 
 
 (0.1) 
         
TOTAL OTHER COMPREHENSIVE INCOME 0.4
 0.3
 1.1
 1.2
         
TOTAL COMPREHENSIVE INCOME $89.2
 $73.0
 $249.1
 $232.8
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.



APPALACHIAN
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 20172019 and 20162018
(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
  Common
Stock
 Paid-in
Capital
 Retained
Earnings
 Accumulated
Other
Comprehensive
Income (Loss)
 Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017 $56.6
 $980.9
 $1,192.2
 $(12.1) $2,217.6
           
Common Stock Dividends  
  
 (33.5)  
 (33.5)
ASU 2018-02 Adoption     0.3
 (2.7) (2.4)
Net Income  
  
 64.2
  
 64.2
Other Comprehensive Income  
  
  
 0.4
 0.4
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018 56.6
 980.9
 1,223.2
 (14.4) 2,246.3
           
Common Stock Dividends     (33.5)   (33.5)
Net Income     94.7
   94.7
Other Comprehensive Income       0.5
 0.5
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2018 56.6
 980.9
 1,284.4
 (13.9) 2,308.0
           
Common Stock Dividends     (38.5)   (38.5)
Net Income     72.7
   72.7
Other Comprehensive Income       0.3
 0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2018 $56.6
 $980.9
 $1,318.6
 $(13.6) $2,342.5
   
  
  
  
  
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, 2019 56.6
 980.9
 1,408.0
 (13.4) 2,432.1
           
Common Stock Dividends  
  
 (20.0)  
 (20.0)
Net Income  
  
 60.3
  
 60.3
Other Comprehensive Income  
  
  
 0.3
 0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2019 56.6
 980.9
 1,448.3
 (13.1) 2,472.7
           
Common Stock Dividends     (20.0)   (20.0)
Net Income     88.8
   88.8
Other Comprehensive Income       0.4
 0.4
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2019 $56.6
 $980.9
 $1,517.1
 $(12.7) $2,541.9
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.



APPALACHIAN
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20172019 and December 31, 20162018
(in millions)
(Unaudited)
 September 30, December 31, September 30, December 31,
 2017 2016 2019 2018
CURRENT ASSETS        
Cash and Cash Equivalents $2.9
 $2.7
 $2.5
 $2.4
Restricted Cash for Securitized Funding 8.3
 15.8
Advances to Affiliates 23.6
 24.1
 13.2
 12.7
Accounts Receivable:        
Customers 96.8
 131.4
 45.0
 63.1
Affiliated Companies 59.5
 54.4
 45.3
 75.0
Accrued Unbilled Revenues 41.1
 52.7
 2.7
 3.6
Miscellaneous 1.3
 0.9
 1.0
 1.4
Allowance for Uncollectible Accounts (2.7) (3.5) (0.1) (0.1)
Total Accounts Receivable 196.0
 235.9
 93.9
 143.0
Fuel 96.3
 112.0
 39.8
 37.3
Materials and Supplies 100.8
 98.8
 169.9
 167.3
Risk Management Assets 30.3
 2.6
 10.5
 8.6
Accrued Tax Benefits 0.4
 4.2
 43.2
 26.6
Regulatory Asset for Under-Recovered Fuel Costs 63.5
 68.4
Margin Deposits 11.8
 17.5
Accrued Reimbursement of Spent Nuclear Fuel Costs 24.2
 7.9
Prepayments and Other Current Assets 18.2
 9.7
 16.9
 24.6
TOTAL CURRENT ASSETS 552.1
 591.7
 414.1
 430.4
        
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
Generation 6,393.7
 6,332.8
 5,002.0
 4,887.2
Transmission 2,904.4
 2,796.9
 1,614.5
 1,576.8
Distribution 3,703.5
 3,569.1
 2,373.3
 2,249.7
Other Property, Plant and Equipment 409.8
 373.5
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) 607.2
 583.8
Construction Work in Progress 493.5
 390.3
 516.2
 465.3
Total Property, Plant and Equipment 13,904.9
 13,462.6
 10,113.2
 9,762.8
Accumulated Depreciation and Amortization 3,836.7
 3,636.8
Accumulated Depreciation, Depletion and Amortization 3,280.5
 3,151.6
TOTAL PROPERTY, PLANT AND EQUIPMENTNET
 10,068.2
 9,825.8
 6,832.7
 6,611.2
        
OTHER NONCURRENT ASSETS        
Regulatory Assets 1,100.1
 1,121.1
 490.2
 512.5
Securitized Assets 288.0
 305.3
Spent Nuclear Fuel and Decommissioning Trusts 2,835.2
 2,474.9
Long-term Risk Management Assets 0.6
 
 0.1
 0.6
Operating Lease Assets 295.3
 
Deferred Charges and Other Noncurrent Assets 113.6
 133.3
 129.6
 193.0
TOTAL OTHER NONCURRENT ASSETS 1,502.3
 1,559.7
 3,750.4
 3,181.0
        
TOTAL ASSETS $12,122.6
 $11,977.2
 $10,997.2
 $10,222.6
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.



APPALACHIAN
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 20172019 and December 31, 20162018
(dollars in millions)
(Unaudited)
 September 30, December 31,
 2017 2016 September 30, December 31,
 (in millions) 2019 2018
CURRENT LIABILITIES        
Advances from Affiliates $69.5
 $79.6
 $102.4
 $1.1
Accounts Payable:  
  
    
General 235.4
 253.7
 148.4
 174.7
Affiliated Companies 75.5
 82.6
 71.6
 70.2
Long-term Debt Due Within One Year - Nonaffiliated 149.2
 503.1
Long-term Debt Due Within One Year – Nonaffiliated
(September 30, 2019 and December 31, 2018 Amounts Include $68.8 and $76.8, Respectively, Related to DCC Fuel)
 147.4
 155.4
Risk Management Liabilities 0.9
 0.3
 0.2
 0.3
Customer Deposits 84.0
 83.1
 37.9
 38.0
Accrued Taxes 64.0
 107.6
 57.9
 90.7
Accrued Interest 71.4
 40.6
 20.5
 37.3
Obligations Under Operating Leases 82.0
 
Regulatory Liability for Over-Recovered Fuel Costs 7.3
 27.4
Other Current Liabilities 99.2
 129.5
 85.5
 103.0
TOTAL CURRENT LIABILITIES 849.1
 1,280.1
 761.1
 698.1
        
NONCURRENT LIABILITIES        
Long-term Debt - Nonaffiliated 3,830.1
 3,530.8
Long-term Debt – Nonaffiliated 2,884.1
 2,880.0
Long-term Risk Management Liabilities 0.3
 0.9
 
 0.1
Deferred Income Taxes 2,796.7
 2,672.3
 970.0
 948.0
Regulatory Liabilities and Deferred Investment Tax Credits 634.4
 627.8
 1,809.0
 1,574.5
Asset Retirement Obligations 101.2
 108.8
 1,731.5
 1,681.3
Employee Benefits and Pension Obligations 92.2
 108.5
Obligations Under Operating Leases 234.0
 
Deferred Credits and Other Noncurrent Liabilities 77.8
 64.5
 65.6
 87.8
TOTAL NONCURRENT LIABILITIES 7,532.7
 7,113.6
 7,694.2
 7,171.7
        
TOTAL LIABILITIES 8,381.8
 8,393.7
 8,455.3
 7,869.8
        
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
Authorized – 2,500,000 Shares    
Outstanding – 1,400,000 Shares 56.6
 56.6
Paid-in Capital 1,828.7
 1,828.7
 980.9
 980.9
Retained Earnings 1,661.5
 1,502.8
 1,517.1
 1,329.1
Accumulated Other Comprehensive Income (Loss) (9.8) (8.4) (12.7) (13.8)
TOTAL COMMON SHAREHOLDER’S EQUITY 3,740.8
 3,583.5
 2,541.9
 2,352.8
        
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $12,122.6
 $11,977.2
 $10,997.2
 $10,222.6
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.



APPALACHIAN
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20172019 and 20162018
(in millions)
(Unaudited)
 Nine Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2019 2018
OPERATING ACTIVITIES  
  
  
  
Net Income $248.7
 $303.8
 $248.0
 $231.6
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
  
  
Depreciation and Amortization 304.1
 290.0
 261.6
 207.1
Rent - Rockport Plant, Unit 2 58.9
 
Deferred Income Taxes 121.7
 100.9
 (29.9) 28.1
Carrying Costs Income (1.0) (0.2)
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net (11.6) 13.5
Allowance for Equity Funds Used During Construction (6.2) (9.1) (16.4) (8.0)
Mark-to-Market of Risk Management Contracts (28.3) 18.4
 (1.6) (0.3)
Pension Contributions to Qualified Plan Trust (10.2) (8.8)
Property Taxes 29.8
 29.2
Amortization of Nuclear Fuel 71.6
 82.6
Deferred Fuel Over/Under-Recovery, Net 4.9
 19.0
 (20.0) 29.6
Change in Other Noncurrent Assets 8.3
 (5.1) 46.0
 (12.0)
Change in Other Noncurrent Liabilities 7.9
 (23.0) 13.8
 46.3
Changes in Certain Components of Working Capital:  
  
  
  
Accounts Receivable, Net 39.9
 (20.5) 50.5
 6.5
Fuel, Materials and Supplies 14.0
 (1.2) (4.6) (1.1)
Accounts Payable 6.2
 4.9
 (7.3) (34.7)
Accrued Taxes, Net (44.2) (13.9) (49.4) (7.1)
Payments for Rockport Plant, Unit 2 Operating Lease (36.9) 
Other Current Assets (2.5) (0.2) 7.8
 4.9
Other Current Liabilities 9.1
 (4.1) (49.7) (15.7)
Net Cash Flows from Operating Activities 702.2
 680.1
 530.8
 571.3
        
INVESTING ACTIVITIES  
  
  
  
Construction Expenditures (560.0) (472.7) (431.7) (434.5)
Change in Restricted Cash for Securitized Funding 7.5
 7.0
Change in Advances to Affiliates, Net 0.5
 1.2
 (0.5) (60.1)
Purchases of Investment Securities (915.7) (1,589.0)
Sales of Investment Securities 871.4
 1,550.9
Acquisitions of Nuclear Fuel (91.9) (26.1)
Other Investing Activities 11.8
 10.6
 10.5
 9.2
Net Cash Flows Used for Investing Activities (540.2) (453.9) (557.9) (549.6)
        
FINANCING ACTIVITIES  
  
  
  
Issuance of Long-term Debt - Nonaffiliated 320.9
 314.1
Issuance of Long-term Debt – Nonaffiliated 62.9
 1,168.1
Change in Advances from Affiliates, Net (10.1) (96.9) 101.3
 (211.6)
Retirement of Long-term Debt - Nonaffiliated (377.9) (213.6)
Principal Payments for Capital Lease Obligations (5.2) (4.7)
Retirement of Long-term Debt – Nonaffiliated (73.6) (856.1)
Principal Payments for Finance Lease Obligations (4.0) (7.3)
Dividends Paid on Common Stock (90.0) (225.0) (60.0) (105.5)
Other Financing Activities 0.5
 0.4
 0.6
 (9.0)
Net Cash Flows Used for Financing Activities (161.8) (225.7)
Net Cash Flows from (Used for) Financing Activities 27.2
 (21.4)
        
Net Increase in Cash and Cash Equivalents 0.2
 0.5
 0.1
 0.3
Cash and Cash Equivalents at Beginning of Period 2.7
 2.8
 2.4
 1.3
Cash and Cash Equivalents at End of Period $2.9
 $3.3
 $2.5
 $1.6
        
SUPPLEMENTARY INFORMATION  
  
  
  
Cash Paid for Interest, Net of Capitalized Amounts $107.1
 $113.2
 $98.7
 $104.4
Net Cash Paid for Income Taxes 24.4
 55.8
Noncash Acquisitions Under Capital Leases 2.9
 2.1
Net Cash Paid (Received) for Income Taxes 40.2
 (26.5)
Noncash Acquisitions Under Finance Leases 8.1
 4.4
Construction Expenditures Included in Current Liabilities as of September 30, 107.2
 66.8
 76.3
 66.4
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, 
 12.1
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage 
 2.1
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.







INDIANA MICHIGAN
OHIO POWER COMPANY
AND SUBSIDIARIES




INDIANA MICHIGAN
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 EndedThree Months Ended Nine Months Ended
September 30, September 30,September 30, September 30,
2017 2016 2017 20162019 2018 2019 2018
(in millions of KWhs)(in millions of KWhs)
Retail: 
  
  
  
 
  
  
  
Residential1,404
 1,619
 4,015
 4,344
4,120
 4,055
 11,034
 11,475
Commercial1,313
 1,405
 3,640
 3,780
4,067
 3,971
 11,072
 11,146
Industrial1,978
 1,996
 5,793
 5,876
3,689
 3,688
 10,936
 11,066
Miscellaneous16
 15
 50
 50
26
 27
 83
 84
Total Retail(b)4,711
 5,035
 13,498
 14,050
11,902
 11,741
 33,125
 33,771
              
Wholesale(c)2,807
 2,613
 8,567
 7,038
453
 634
 1,531
 1,835
              
Total KWhs7,518
 7,648
 22,065
 21,088
12,355
 12,375
 34,656
 35,606


(a)2018 KWhs have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail KWhs. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.
(b)Represents energy delivered to distribution customers.
(c)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 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
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2019 2018 2019 2018
  (in degree days)
Actual – Heating (a) 
 
 2,006
 2,158
Normal – Heating (b) 6
 6
 2,072
 2,076
         
Actual – Cooling (c) 872
 864
 1,176
 1,322
Normal – Cooling (b) 672
 670
 973
 964


(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 20172019 Compared to Third Quarter of 20162018
Reconciliation of Third Quarter of 2016 to Third Quarter of 2017
Reconciliation of Third Quarter of 2018 to Third Quarter of 2019Reconciliation of Third Quarter of 2018 to Third Quarter of 2019
Net Income(in millions)
    
Third Quarter of 2016 $75.4
Third Quarter of 2018 $88.7
  
  
Changes in Gross Margin:  
  
Retail Margins (a) (4.4) (2.9)
Margins from Off-system Sales (12.2)
Transmission Revenues (6.2) 0.5
Other Revenues (1.5) 1.7
Total Change in Gross Margin (12.1) (12.9)
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance (7.4) 23.7
Asset Impairments and Other Related Charges 10.5
Depreciation and Amortization (5.9) 13.0
Taxes Other Than Income Taxes (1.4) (5.1)
Other Income 0.1
Carrying Costs Income 0.1
Allowance for Equity Funds Used During Construction 2.8
Non-Service Cost Components of Net Periodic Benefit Cost (0.1)
Interest Expense (0.8) (1.8)
Total Change in Expenses and Other (4.9) 32.6
  
  
Income Tax Expense 6.5
Income Tax Expense (Benefit) (39.3)
  
  
Third Quarter of 2017 $64.9
Third Quarter of 2019 $69.1

(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 consumptionpurchased electricity and amortization of chemicals and emissions allowances, and purchased electricitygeneration deferrals were as follows:


Retail Margins decreased $3 million primarily due to the following:
A $28 million net decrease in Basic Transmission Cost Rider revenues and recoverable PJM expenses. This decrease was partially offset in Other Operation and Maintenance expenses below.
Retail Margins decreased $4 million primarily due to the following:
An $18A $13 million decrease in weather-related usage primarily due to a 32%Deferred Asset Phase-In-Recovery Rider revenues which ended in the second quarter of 2019. This decrease was offset in Depreciation and Amortization expenses below.
An $8 million net decrease in cooling degree days.margin for the Rate Stability Rider including associated amortizations which ended in the third quarter of 2019.
A $6 million decrease in weather-normalized margins.revenues associated with a vegetation management rider. This decrease was offset in Other Operation and Maintenance expenses below.
A $6 million net decrease in margin for the Phase-In-Recovery Rider including associated amortizations which ended in the first quarter of 2019.
These decreases were partially offset by:
A $27 million net increase primarily due to 2018 adjustments to the distribution decoupling under-recovery balance as a result of the 2018 Ohio Tax Reform settlement and changes in tax riders. This increase was partially offset in Income Tax Expense (Benefit) below.
A $12 million increase due to the recovery of higher current year losses from a power contract with OVEC. This increase was offset in Margins from Off-system Sales below.
A $9 million increase in revenues associated with smart grid riders. This increase was partially offset in other expense items below.
A $4 million increase in rider revenues associated with the DIR. This decrease was partially offset in other expense items below.
A $3 million increase in Energy Efficiency/Peak Demand Reduction rider revenues. This increase was offset in Other Operation and Maintenance expenses below.


Margins from Off-system Sales decreased $12 million primarily due to higher current year losses from a power contract with OVEC and lower deferrals as a result of the OVEC PPA rider. This decrease was offset in Retail Margins above.

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

Other Operation and Maintenance expenses decreased $24 million primarily due to the following:
A $26 million decrease in recoverable PJM expenses. This decrease was offset in Gross Margin above.
A $5 million decrease in FERC generation wholesale municipal and cooperative revenues primarily duerecoverable distribution expenses related to formula rate adjustments.vegetation management. This decrease was partially offset in Retail Margins above.
A $2$4 million decrease due to increased costs for power acquired under the Unit Power Agreement between AEGCo and I&M.higher charitable contributions in 2018.
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 increasePJM expenses primarily related to over/under recovery of riders.the annual formula rate true-up.
Depreciation and Amortization expensesdecreased $13 million primarily due to the following:
A $2An $8 million decrease in PJM related expenses primarily due to reduced FTRs.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.
Transmission Revenues decreasedA $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.
decrease in recoverable DIR depreciation expense. This decrease was partially offset in Retail Margins above.



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:
These decreases were partially offset by:
A $9$4 million increase in transmission expenses primarilydepreciation expense due to an increase in recoverable PJM expenses. This increase in expense is offset within Retail Margins above.
A $3 million increase in nuclear expenses primarily due to an increase in refueling outage amortizationthe depreciable base of transmission and refueling outage expenses not deferred, partially offset by a decrease in employee-related expenses.
These increases were partially offset by:
A $3 million decrease in distribution expenses primarily due to decreased vegetation management.assets.
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.
Taxes Other Than Income Taxes increased $5 million primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
Income Tax Expense (Benefit) increased $39 million primarily due to a one-time recognition of increased amortization of Excess ADIT not subject to normalization requirements as a result of the 2018 Ohio Tax Reform Settlement. This increase was partially offset in Retail Margins above.



Nine Months Ended September 30, 20172019 Compared to Nine Months Ended September 30, 20162018
Reconciliation of Nine Months Ended September 30, 2016 to Nine Months Ended September 30, 2017
Reconciliation of Nine Months Ended September 30, 2018 to Nine Months Ended September 30, 2019Reconciliation of Nine Months Ended September 30, 2018 to Nine Months Ended September 30, 2019
Net Income(in millions)
    
Nine Months Ended September 30, 2016 $201.4
Nine Months Ended September 30, 2018 $237.1
  
  
Changes in Gross Margin:  
  
Retail Margins (a) (11.2) 9.2
Off-system Sales 0.5
Margins from Off-system Sales (20.8)
Transmission Revenues (23.0) 5.9
Other Revenues (2.1) 6.0
Total Change in Gross Margin (35.8) 0.3
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance (39.3) 28.7
Asset Impairments and Other Related Charges 10.5
Depreciation and Amortization (11.6) 23.5
Taxes Other Than Income Taxes 3.2
 (15.9)
Other Income (0.4)
Interest Income 0.1
Carrying Costs Income (0.8)
Allowance for Equity Funds Used During Construction 6.3
Non-Service Cost Components of Net Periodic Benefit Cost (0.6)
Interest Expense (6.7) (1.5)
Total Change in Expenses and Other (44.3) 39.8
  
  
Income Tax Expense 22.5
Income Tax Expense (Benefit) (29.5)
  
  
Nine Months Ended September 30, 2017 $143.8
Nine Months Ended September 30, 2019 $247.7

(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 consumptionpurchased electricity and amortization of chemicals and emissions allowances, and purchased electricitygeneration deferrals were as follows:


Retail Margins decreased $11
Retail Margins increased $9 million primarily due to the following:
A $58 million increase due to the following:
a reversal of a regulatory provision.
A $33 million net increase due to 2018 adjustments to the distribution decoupling under-recovery balance as a result of the 2018 Ohio Tax Reform settlement and changes in tax riders. This increase was partially offset in Income Tax Expense (Benefit) below.
A $31 million increase in revenues associated with smart grid riders. This increase was partially offset in other expense items below.
A $21 million increase due to the recovery of higher current year losses from a power contract with OVEC. This increase was offset in Margins from Off-system Sales below.
A $9 million increase in Energy Efficiency/Peak Demand Reduction rider revenues. This increase was offset in Other Operation and Maintenance expenses below.
These increases were partially offset by:
A $71 million net decrease in FERC generation wholesale municipalBasic Transmission Cost Rider revenues and cooperative revenues primarily due to an annual formula rate true-uprecoverable PJM expenses. This decrease was partially offset in Other Operation and other rate adjustments.Maintenance expenses below.
A $29An $18 million decrease in weather-related usage primarily due torevenues associated with a 24%vegetation management rider. This decrease was offset in Other Operation and Maintenance expenses below.
A $16 million net decrease in cooling degree days and a 17% decreasemargin for the Phase-In-Recovery Rider including associated amortizations which ended in heating degree days.the first quarter of 2019.
An $11A $13 million decrease in weather-normalized margins.Deferred Asset Phase-In-Recovery Rider revenues which ended in the second quarter of 2019. This decrease was offset in Depreciation and Amortization expenses below.


A $5$12 million net decrease in margin for the Rate Stability Rider including associated amortizations which ended in the third quarter of 2019.
An $8 million decrease in usage primarily in the residential and commercial classes.
A $4 million decrease in rider revenues associated with the DIR. This decrease was partially offset in other expense items below.
Margins from Off-system Sales decreased $21 million primarily due to higher current year losses from a power contract with OVEC as a result of the OVEC PPA rider. This decrease was offset in Retail Margins above.
Transmission Revenues increased $6 million primarily due to 2018 provisions for refunds, partially offset by the annual PJM Transmission formula rate true-up.
Other Revenues increased $6 million primarily due to distribution connection fees and pole attachment revenues.

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

Other Operation and Maintenance expenses decreased $29 million primarily due to the following:
A $78 million decrease in recoverable PJM expenses. This decrease was offset in Gross Margin above.
A $10 million decrease in recoverable distribution expenses related to increased costs for power acquired under the Unit Power Agreement between AEGCo and I&M.vegetation management. This decrease was partially offset in Retail Margins above.
These decreases were partially offset by:
A $47$57 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 increasePJM expenses primarily related to over/under recovery of riders.the annual formula rate true-up.
Depreciation and Amortization expensesdecreased $24 million primarily due to the following:
A $2$30 million decrease in PJM related expenses primarily due to reduced FTRs.recoverable DIR depreciation expense. This decrease was partially offset in Retail Margins above.
Transmission Revenues decreased $23An $11 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.
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.


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

Other Operation and Maintenance expenses increased $39 million primarily due to the following:
This decrease was offset by:
A $38$17 million increase in transmission expenses primarilydepreciation expense 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 expensesthe depreciable base of transmission and material write-off.
A $3 million increase in distribution expenses primarily due to increased vegetation management.assets.
Taxes Other Than Income Taxes increased $16 million primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
Allowance for Equity Funds Used During Construction increased $6 million primarily due to adjustments that resulted from 2019 FERC audit findings.
Income Tax Expense (Benefit) increased $30 million primarily due to a one-time recognition of increased amortization of Excess ADIT not subject to normalization requirements as a result of the 2018 Ohio Tax Reform Settlement. This increase was partially offset in Retail Margins above.
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 Expense decreased $23 million primarily due to a decrease in pretax book income, partially offset by the recording of favorable federal income tax adjustments in 2016.




INDIANA MICHIGANOHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20172019 and 20162018
(in millions)
(Unaudited)
 Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended
 September 30, September 30, September 30, September 30,
 2017 2016 2017 2016 2019 2018 2019 2018
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
Electricity, Transmission and Distribution $698.6
 $772.6
 $2,127.4
 $2,294.8
Sales to AEP Affiliates 9.0
 3.3
 18.2
 17.9
Other Revenues 3.0
 2.4
 8.4
 5.3
TOTAL REVENUES 557.7
 597.6
 1,585.5
 1,652.7
 710.6
 778.3
 2,154.0
 2,318.0
                
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
 158.3
 166.3
 454.0
 534.7
Purchased Electricity from AEP Affiliates 62.4
 64.5
 166.2
 165.9
 40.6
 39.3
 120.4
 97.4
Amortization of Generation Deferrals 8.8
 56.9
 65.3
 171.9
Other Operation 140.5
 138.9
 434.2
 413.9
 194.9
 215.2
 565.7
 586.4
Maintenance 51.5
 45.7
 153.6
 134.6
 40.0
 43.4
 106.7
 114.7
Asset Impairments and Other Related Charges 
 10.5
 
 10.5
Depreciation and Amortization 55.0
 49.1
 154.8
 143.2
 57.4
 70.4
 176.8
 200.3
Taxes Other Than Income Taxes 23.9
 22.5
 68.3
 71.5
 112.0
 106.9
 326.9
 311.0
TOTAL EXPENSES 442.6
 466.2
 1,316.5
 1,310.7
 612.0
 698.4
 1,815.8
 2,016.4
                
OPERATING INCOME 115.1
 131.4
 269.0
 342.0
 98.6
 79.9
 338.2
 301.6
                
Other Income (Expense):  
    
  
  
  
  
  
Interest Income 2.4
 1.7
 11.5
 9.1
 0.8
 0.8
 2.7
 2.6
Carrying Costs Income 0.3
 0.2
 0.7
 1.5
Allowance for Equity Funds Used During Construction 3.5
 4.1
 8.1
 10.9
 4.8
 2.0
 14.1
 7.8
Non-Service Cost Components of Net Periodic Benefit Cost 3.7
 3.8
 11.0
 11.6
Interest Expense (27.5) (26.7) (83.0) (76.3) (27.9) (26.1) (78.1) (76.6)
                
INCOME BEFORE INCOME TAX EXPENSE 93.5
 110.5
 205.6
 285.7
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 80.3
 60.6
 288.6
 248.5
                
Income Tax Expense 28.6
 35.1
 61.8
 84.3
Income Tax Expense (Benefit) 11.2
 (28.1) 40.9
 11.4
                
NET INCOME $64.9
 $75.4
 $143.8
 $201.4
 $69.1
 $88.7
 $247.7
 $237.1
The common stock of I&MOPCo is wholly-owned by Parent.
 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.



INDIANA MICHIGAN
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20172019 and 20162018
(in millions)
(Unaudited)
 Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended
 September 30, September 30, September 30, September 30,
 2017 2016 2017 2016 2019 2018 2019 2018
Net Income $64.9
 $75.4
 $143.8
 $201.4
 $69.1
 $88.7
 $247.7
 $237.1
                
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
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, 2019 and 2018, Respectively, and $(0.3) and $(0.3) for the Nine Months Ended September 30, 2019 and 2018, Respectively (0.3) (0.4) (1.0) (1.0)
                
TOTAL COMPREHENSIVE INCOME $65.2
 $75.7
 $144.8
 $202.4
 $68.8
 $88.3
 $246.7
 $236.1
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.



INDIANA MICHIGAN
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 20172019 and 20162018
(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
  Common
Stock
 Paid-in
Capital
 Retained
Earnings
 Accumulated
Other
Comprehensive
Income (Loss)
 Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017 $321.2
 $838.8
 $1,148.4
 $1.9
 $2,310.3
           
Common Stock Dividends     (112.5)   (112.5)
ASU 2018-02 Adoption       0.4
 0.4
Net Income     79.6
   79.6
Other Comprehensive Loss       (0.3) (0.3)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018 321.2
 838.8
 1,115.5
 2.0
 2,277.5
           
Common Stock Dividends  
  
 (112.5)  
 (112.5)
Net Income  
  
 68.8
  
 68.8
Other Comprehensive Loss  
  
  
 (0.3) (0.3)
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2018 321.2
 838.8
 1,071.8
 1.7
 2,233.5
           
Common Stock Dividends     (112.5)   (112.5)
Net Income     88.7
   88.7
Other Comprehensive Loss       (0.4) (0.4)
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2018 $321.2
 $838.8
 $1,048.0
 $1.3
 $2,209.3
   
  
  
  
  
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 Income     128.0
   128.0
Other Comprehensive Loss       (0.3) (0.3)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2019 321.2
 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, 2019 321.2
 838.8
 1,230.0
 0.3
 2,390.3
           
Net Income     69.1
   69.1
Other Comprehensive Loss       (0.3) (0.3)
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2019 $321.2
 $838.8
 $1,299.1
 $
 $2,459.1
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.



INDIANA MICHIGAN
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20172019 and December 31, 20162018
(in millions)
(Unaudited)
 September 30, December 31, September 30, December 31,
 2017 2016 2019 2018
CURRENT ASSETS        
Cash and Cash Equivalents $1.3
 $1.2
 $4.7
 $4.9
Advances to Affiliates 12.6
 12.5
Restricted Cash for Securitized Funding 
 27.6
Accounts Receivable:        
Customers 42.1
 60.2
 35.4
 111.1
Affiliated Companies 42.8
 51.0
 56.2
 70.8
Accrued Unbilled Revenues 8.4
 1.5
 26.5
 21.4
Miscellaneous 1.1
 0.7
 0.3
 0.3
Allowance for Uncollectible Accounts (0.3) 
 (2.1) (1.0)
Total Accounts Receivable 94.1
 113.4
 116.3
 202.6
Fuel 32.3
 32.3
Materials and Supplies 156.5
 150.8
 48.5
 42.9
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
Renewable Energy Credits 41.5
 25.9
Prepayments and Other Current Assets 26.9
 19.9
 19.8
 15.7
TOTAL CURRENT ASSETS 393.1
 419.5
 230.8
 319.6
        
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
Generation 4,399.9
 4,056.1
Transmission 1,491.4
 1,472.8
 2,613.0
 2,544.3
Distribution 2,000.1
 1,899.3
 5,192.8
 4,942.3
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) 555.9
 550.2
Other Property, Plant and Equipment 662.3
 574.8
Construction Work in Progress 478.9
 654.2
 485.3
 432.1
Total Property, Plant and Equipment 8,926.2
 8,632.6
 8,953.4
 8,493.5
Accumulated Depreciation, Depletion and Amortization 3,022.5
 3,005.1
Accumulated Depreciation and Amortization 2,256.1
 2,218.6
TOTAL PROPERTY, PLANT AND EQUIPMENTNET
 5,903.7
 5,627.5
 6,697.3
 6,274.9
        
OTHER NONCURRENT ASSETS        
Regulatory Assets 941.0
 916.6
 372.2
 387.5
Spent Nuclear Fuel and Decommissioning Trusts 2,433.0
 2,256.2
Long-term Risk Management Assets 0.5
 
Securitized Assets 
 12.9
Deferred Charges and Other Noncurrent Assets 95.9
 121.5
 320.3
 441.0
TOTAL OTHER NONCURRENT ASSETS 3,470.4
 3,294.3
 692.5
 841.4
        
TOTAL ASSETS $9,767.2
 $9,341.3
 $7,620.6
 $7,435.9
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.



INDIANA MICHIGAN
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 20172019 and December 31, 20162018
(dollars in millions)
(Unaudited)
 September 30, December 31, September 30, December 31,
 2017 2016 2019 2018
CURRENT LIABILITIES        
Advances from Affiliates $177.5
 $215.2
 $17.6
 $114.1
Accounts Payable:      
  
General 168.6
 179.0
 203.1
 211.9
Affiliated Companies 72.2
 75.6
 100.2
 102.9
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
Long-term Debt Due Within One Year – Nonaffiliated
(September 30, 2019 and December 31, 2018 Amounts Include $0 and $47.8, Respectively, Related to Ohio Phase-in-Recovery Funding)
 0.1
 47.9
Risk Management Liabilities 2.0
 0.3
 7.2
 5.8
Customer Deposits 37.3
 34.3
 88.2
 113.1
Accrued Taxes 43.8
 77.2
 294.3
 537.8
Accrued Interest 14.3
 31.7
 44.7
 31.4
Obligations Under Capital Leases 7.3
 9.4
Obligations Under Operating Leases 12.8
 
Other Current Liabilities 114.3
 123.4
 99.4
 182.8
TOTAL CURRENT LIABILITIES 1,099.4
 955.4
 867.6
 1,347.7
        
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated 2,196.4
 2,262.1
 2,113.8
 1,668.7
Long-term Risk Management Liabilities 0.2
 0.8
 105.7
 93.8
Deferred Income Taxes 1,681.8
 1,527.4
 805.0
 763.3
Regulatory Liabilities and Deferred Investment Tax Credits 1,169.6
 1,065.5
 1,143.6
 1,221.2
Asset Retirement Obligations 1,307.4
 1,257.9
Obligations Under Operating Leases 75.9
 
Deferred Credits and Other Noncurrent Liabilities 109.5
 120.4
 49.9
 43.8
TOTAL NONCURRENT LIABILITIES 6,464.9
 6,234.1
 4,293.9
 3,790.8
        
TOTAL LIABILITIES 7,564.3
 7,189.5
 5,161.5
 5,138.5
        
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
Authorized – 40,000,000 Shares  
  
Outstanding – 27,952,473 Shares 321.2
 321.2
Paid-in Capital 980.9
 980.9
 838.8
 838.8
Retained Earnings 1,180.6
 1,130.5
 1,299.1
 1,136.4
Accumulated Other Comprehensive Income (Loss) (15.2) (16.2) 
 1.0
TOTAL COMMON SHAREHOLDER’S EQUITY 2,202.9
 2,151.8
 2,459.1
 2,297.4
        
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $9,767.2
 $9,341.3
 $7,620.6
 $7,435.9
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.



INDIANA MICHIGAN
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20172019 and 20162018
(in millions)
(Unaudited)
 Nine Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2019 2018
OPERATING ACTIVITIES  
  
  
  
Net Income $143.8
 $201.4
 $247.7
 $237.1
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
  
  
Depreciation and Amortization 154.8
 143.2
 176.8
 200.3
Amortization of Generation Deferrals 65.3
 171.9
Deferred Income Taxes 132.2
 116.2
 16.8
 (71.9)
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) (14.1) (7.8)
Mark-to-Market of Risk Management Contracts (7.5) 0.5
 13.3
 (37.1)
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
Property Taxes 197.7
 191.1
Refund of Global Settlement (12.4) (5.5)
Reversal of Regulatory Provision (56.2) 
Change in Regulatory Assets (28.1) 180.9
Change in Other Noncurrent Assets (42.1) 
 (19.4) 0.8
Change in Other Noncurrent Liabilities 40.9
 30.0
 (51.1) 62.5
Changes in Certain Components of Working Capital:  
  
  
  
Accounts Receivable, Net 19.3
 17.0
 90.0
 21.3
Fuel, Materials and Supplies (4.1) (1.1)
Materials and Supplies (9.6) (3.7)
Accounts Payable 16.6
 (17.9) (12.3) (31.8)
Accrued Taxes, Net (30.2) (16.5) (245.9) (210.6)
Other Current Assets 8.0
 6.7
 (9.0) 7.6
Other Current Liabilities (28.6) (27.8) (40.0) (4.3)
Net Cash Flows from Operating Activities 524.3
 537.0
 309.5
 700.8
        
INVESTING ACTIVITIES  
  
  
  
Construction Expenditures (469.2) (405.1) (570.6) (538.5)
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
 20.0
 15.5
Net Cash Flows Used for Investing Activities (568.8) (551.5) (550.6) (523.0)
        
FINANCING ACTIVITIES  
  
  
  
Issuance of Long-term Debt – Nonaffiliated 411.1
 482.7
 444.3
 392.8
Change in Advances from Affiliates, Net (37.7) (268.0) (96.5) 155.1
Retirement of Long-term Debt – Nonaffiliated (227.1) (76.8) (48.0) (397.0)
Principal Payments for Capital Lease Obligations (8.7) (29.8)
Principal Payments for Finance Lease Obligations (2.6) (2.9)
Dividends Paid on Common Stock (93.7) (93.8) (85.0) (337.5)
Other Financing Activities 0.7
 0.7
 1.1
 0.7
Net Cash Flows from Financing Activities 44.6
 15.0
Net Cash Flows from (Used for) Financing Activities 213.3
 (188.8)
        
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
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding (27.8) (11.0)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period 32.5
 29.7
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period $4.7
 $18.7
        
SUPPLEMENTARY INFORMATION  
  
  
  
Cash Paid for Interest, Net of Capitalized Amounts $92.0
 $85.6
 $61.3
 $67.3
Net Cash Paid (Received) for Income Taxes (69.6) (36.0)
Noncash Acquisitions Under Capital Leases 5.9
 16.8
Net Cash Paid for Income Taxes 25.7
 54.1
Noncash Acquisitions Under Finance Leases 8.6
 3.0
Construction Expenditures Included in Current Liabilities as of September 30, 74.5
 83.4
 99.9
 66.0
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 118126.







OHIO POWER
PUBLIC SERVICE COMPANY AND SUBSIDIARIESOF OKLAHOMA




OHIO POWER
PUBLIC SERVICE COMPANY AND SUBSIDIARIESOF 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 EndedThree Months Ended Nine Months Ended
September 30, September 30,September 30, September 30,
2017 2016 2017 20162019 2018 2019 2018
(in millions of KWhs)(in millions of KWhs)
Retail: 
  
  
  
 
  
  
  
Residential3,644
 4,380
 10,198
 11,209
2,172
 2,005
 4,981
 5,133
Commercial3,806
 4,114
 10,789
 11,158
1,497
 1,433
 3,818
 3,864
Industrial3,708
 3,610
 10,967
 10,671
1,642
 1,604
 4,665
 4,559
Miscellaneous28
 27
 87
 89
378
 362
 950
 973
Total Retail (a)11,186
 12,131
 32,041
 33,127
5,689
 5,404
 14,414
 14,529
              
Wholesale (b)585
 654
 1,749
 1,389
224
 182
 617
 544
              
Total KWhs11,771
 12,785
 33,790
 34,516
5,913
 5,586
 15,031
 15,073


(a)Represents energy delivered2018 KWhs have been revised to distribution customers.
(b)Primarily Ohio’s contractually obligated purchasesreflect the reclassification of OVEC power sold into PJM.certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail KWhs. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.


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
 Three Months Ended Nine Months Ended
 September 30, September 30,
 2019 2018 2019 2018
 (in degree days)
Actual – Heating (a)
 
 1,199
 1,161
Normal – Heating (b)1
 1
 1,077
 1,082
        
Actual – Cooling (c)1,593
 1,433
 2,206
 2,352
Normal – Cooling (b)1,397
 1,396
 2,072
 2,063


(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 20172019 Compared to Third Quarter of 20162018
Reconciliation of Third Quarter of 2016 to Third Quarter of 2017
Reconciliation of Third Quarter of 2018 to Third Quarter of 2019Reconciliation of Third Quarter of 2018 to Third Quarter of 2019
Net Income(in millions)
    
Third Quarter of 2016 $99.9
Third Quarter of 2018 $60.4
  
  
Changes in Gross Margin:  
  
Retail Margins(a) (74.1) 22.0
Off-system Sales (12.0)
Margins from Off-system Sales 0.8
Transmission Revenues (1.8) (3.7)
Other Revenues (2.1)
Total Change in Gross Margin (90.0) 19.1
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance 59.3
 19.5
Depreciation and Amortization 12.1
 3.2
Taxes Other Than Income Taxes 1.5
 (0.3)
Carrying Costs Income (0.4)
Allowance for Equity Funds Used During Construction 0.6
Other Income (Expense) 1.4
Interest Expense 1.5
 0.3
Total Change in Expenses and Other 74.6
 24.1
  
  
Income Tax Expense (1.9) (3.3)
  
  
Third Quarter of 2017 $82.6
Third Quarter of 2019 $100.3

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

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

Retail Margins increased $22 million primarily due to the following:
A $14 million increase due to new base rates implemented in April 2019.
A $9 million increase in weather-related usage due to an 11% increase in cooling degree days.
A $5 million increase in weather-normalized margins.
These increases were partially offset by:
A $7 million decrease due to customer refunds related to Tax Reform. This decrease was partially offset in Income Tax Expense below.
Transmission Revenues decreased $4 million primarily due to a decrease in SPP Base Plan Funding revenues.

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

Other Operation and Maintenance expenses decreased $20 million primarily due the following:
A $9 million decrease in transmission expenses primarily due to decreased SPP transmission services.
A $5 million decrease in Energy Efficiency program costs due to a change in amortizations of costs approved by the OCC. This decrease was offset in Retail Margins above.
A $3 million decrease due to Wind Catcher Project expenses incurred in 2018.
Depreciation and Amortization expenses decreased $3 million primarily due to the refund of Excess ADIT.
Income Tax Expense increased $3 million primarily due to an increase in pretax book income partially offset by an increase in amortization of Excess ADIT. The amortization of Excess ADIT was partially offset in Gross Margin above.


Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018
Reconciliation of Nine Months Ended September 30, 2018 to Nine Months Ended September 30, 2019
Net Income
(in millions)
   
Nine Months Ended September 30, 2018 $89.8
   
Changes in Gross Margin:  
Retail Margins (a) 2.2
Margin from Off-system Sales 0.9
Transmission Revenues (5.6)
Other Revenues 1.8
Total Change in Gross Margin (0.7)
   
Changes in Expenses and Other:  
Other Operation and Maintenance 63.9
Depreciation and Amortization (4.9)
Taxes Other Than Income Taxes (0.4)
Other Income (Expense) 2.4
Non-Service Cost Components of Net Periodic Benefit Cost (0.2)
Interest Expense (2.9)
Total Change in Expenses and Other 57.9
   
Income Tax Expense 1.4
   
Nine Months Ended September 30, 2019 $148.4

(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 and amortization of generation deferrals were as follows:


Retail Margins decreased $74
Retail Margins increased $2 million primarily due to the following:
A $35 million increase due to the following:
A $52 million decreasenew base rates implemented in revenues associated with the Universal Service Fund (USF) surcharge rate decrease. This decrease was offset by a corresponding decrease in Other OperationApril 2019 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 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.
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.March 2018.
This decreaseincrease 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$13 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 chargescustomer refunds 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.


Tax Reform. This decrease was partially offset by:in Income Tax Expense below.
An $18$11 million increase primarilydecrease in weather-related usage due to the impact of prior year losses from a power contract with OVEC which was not included6% decrease in the OVEC PPA rider.cooling degree days.

A $10 million decrease in weather-normalized margins.
Transmission Revenues decreased $6 million primarily due to a decrease in SPP Base Plan Funding revenues.

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


Other Operation and Maintenance expenses decreased $64 million primarily due to the following:
Other Operation and MaintenanceA $31 million decrease in transmission expenses decreased $144 million primarily due to the following:
decreased SPP transmission services.
A $140$17 million decrease in remitted USF surcharge paymentsEnergy Efficiency program costs due to a change in amortizations of costs approved by 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.OCC. This decrease was offset in Retail Margins above.
A $7$12 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 decreaseWind Catcher Project expenses incurred in amortization expenses for the collection of carrying costs on deferred capacity charges beginning June 2015.2018.
Depreciation and Amortization expenses increased $5 million primarily due to the following:
An $8 million decrease in recoveries of transmission cost rider carrying costs. 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 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:
A $9 million increasea higher depreciable base and new rates implemented in property taxes due to additional investments in transmission and distribution assets and higher tax rates.March 2018.
This increase was partially offset by:
A $7$3 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 maturityrefund of a senior unsecured note in June 2016.Excess ADIT.
Income Tax Expense decreased $1 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 Margin above.

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 POWERPUBLIC SERVICE COMPANY AND SUBSIDIARIESOF OKLAHOMA
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20172019 and 20162018
(in millions)
(Unaudited)
 Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended
 September 30, September 30, September 30, September 30,
 2017 2016 2017 2016 2019 2018 2019 2018
REVENUES        
        
Electricity, Transmission and Distribution $736.0
 $864.4
 $2,127.8
 $2,349.2
Electric Generation, Transmission and Distribution $490.5
 $479.1
 $1,164.3
 $1,209.5
Sales to AEP Affiliates 4.6
 5.5
 19.4
 11.7
 1.3
 1.1
 5.0
 3.7
Other Revenues 1.4
 1.4
 4.8
 4.8
 1.2
 1.2
 4.6
 3.3
TOTAL REVENUES 742.0
 871.3
 2,152.0
 2,365.7
 493.0
 481.4
 1,173.9
 1,216.5
                
EXPENSES  
  
  
  
  
  
  
  
Fuel and Other Consumables Used for Electric Generation 98.4
 104.4
 181.2
 211.5
Purchased Electricity for Resale 180.7
 203.4
 525.4
 516.1
 115.3
 116.8
 340.7
 352.3
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
 87.6
 106.3
 226.0
 286.8
Maintenance 37.9
 38.8
 108.4
 104.4
 21.5
 22.3
 70.1
 73.2
Depreciation and Amortization 57.3
 69.4
 165.7
 189.0
 39.1
 42.3
 125.4
 120.5
Taxes Other Than Income Taxes 100.4
 101.9
 293.8
 291.7
 11.1
 10.8
 33.0
 32.6
TOTAL EXPENSES 587.5
 699.7
 1,727.2
 1,921.5
 373.0
 402.9
 976.4
 1,076.9
                
OPERATING INCOME 154.5
 171.6
 424.8
 444.2
 120.0
 78.5
 197.5
 139.6
                
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
Other Income (Expense) 1.2
 (0.2) 2.1
 (0.3)
Non-Service Cost Components of Net Periodic Benefit Cost 2.1
 2.1
 6.3
 6.5
Interest Expense (25.7) (27.2) (76.8) (87.7) (16.1) (16.4) (50.3) (47.4)
                
INCOME BEFORE INCOME TAX EXPENSE 130.9
 146.3
 359.1
 367.2
 107.2
 64.0
 155.6
 98.4
                
Income Tax Expense 48.3
 46.4
 128.0
 122.5
 6.9
 3.6
 7.2
 8.6
                
NET INCOME $82.6
 $99.9
 $231.1
 $244.7
 $100.3
 $60.4
 $148.4
 $89.8
The common stock of OPCoPSO is wholly-owned by Parent.
     
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.



OHIO POWER
PUBLIC SERVICE COMPANY AND SUBSIDIARIESOF OKLAHOMA
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20172019 and 20162018
(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
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2019 2018 2019 2018
Net Income $100.3
 $60.4
 $148.4
 $89.8
         
OTHER COMPREHENSIVE LOSS, NET OF TAXES  
  
  
  
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2019 and 2018, Respectively, and $(0.2) and $(0.2) for the Nine Months Ended September 30, 2019 and 2018, Respectively (0.2) (0.2) (0.7) (0.7)
   
  
  
  
TOTAL COMPREHENSIVE INCOME $100.1
 $60.2

$147.7
 $89.1
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.



OHIO POWER
PUBLIC SERVICE COMPANY AND SUBSIDIARIESOF OKLAHOMA
CONDENSED CONSOLIDATED BALANCE SHEETSSTATEMENTS OF CHANGES IN
ASSETSCOMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 20172019 and December 31, 20162018
(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
  Common
Stock
 Paid-in
Capital
 Retained
Earnings
 Accumulated
Other
Comprehensive
Income (Loss)
 Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017 $157.2
 $364.0
 $691.5
 $2.6
 $1,215.3
           
Common Stock Dividends     (12.5)   (12.5)
ASU 2018-02 Adoption       0.5
 0.5
Net Loss     (7.2)   (7.2)
Other Comprehensive Loss       (0.2) (0.2)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018 157.2
 364.0
 671.8
 2.9
 1,195.9
           
Common Stock Dividends     (12.5)   (12.5)
Net Income  
  
 36.6
  
 36.6
Other Comprehensive Loss  
  
  
 (0.3) (0.3)
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2018 157.2
 364.0
 695.9
 2.6
 1,219.7
   
  
  
  
  
Common Stock Dividends     (12.5)   (12.5)
Net Income     60.4
   60.4
Other Comprehensive Loss       (0.2) (0.2)
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2018 $157.2
 $364.0
 $743.8
 $2.4
 $1,267.4
           
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 Income     6.2
   6.2
Other Comprehensive Loss       (0.2) (0.2)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2019 157.2
 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, 2019 157.2
 364.0
 761.5
 1.6
 1,284.3
           
Net Income     100.3
   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
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.



OHIO POWER
PUBLIC SERVICE COMPANY AND SUBSIDIARIESOF OKLAHOMA
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITYASSETS
September 30, 20172019 and December 31, 20162018
(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
  September 30, December 31,
  2019 2018
CURRENT ASSETS    
Cash and Cash Equivalents $2.9
 $2.0
Advances to Affiliates 95.1
 
Accounts Receivable:    
Customers 25.2
 32.5
Affiliated Companies 27.3
 26.2
Miscellaneous 4.0
 5.7
Allowance for Uncollectible Accounts (0.4) (0.1)
Total Accounts Receivable 56.1
 64.3
Fuel 12.8
 12.3
Materials and Supplies 46.2
 44.8
Risk Management Assets 21.7
 10.4
Accrued Tax Benefits 17.0
 14.7
Prepayments and Other Current Assets 11.5
 9.4
TOTAL CURRENT ASSETS 263.3
 157.9
     
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Generation 1,569.9
 1,577.0
Transmission 928.4
 892.3
Distribution 2,650.1
 2,572.8
Other Property, Plant and Equipment 319.6
 303.5
Construction Work in Progress 128.8
 94.0
Total Property, Plant and Equipment 5,596.8
 5,439.6
Accumulated Depreciation and Amortization 1,558.5
 1,472.9
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 4,038.3
 3,966.7
     
OTHER NONCURRENT ASSETS    
Regulatory Assets 380.7
 369.0
Employee Benefits and Pension Assets 32.6
 31.7
Operating Lease Assets 37.1
 
Deferred Charges and Other Noncurrent Assets 17.2
 7.1
TOTAL OTHER NONCURRENT ASSETS 467.6
 407.8
     
TOTAL ASSETS $4,769.2
 $4,532.4
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.



OHIO POWER
PUBLIC SERVICE COMPANY AND SUBSIDIARIESOF OKLAHOMA
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWSBALANCE SHEETS
For the Nine Months Ended LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 20172019 and 2016
(in millions)December 31, 2018
(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
  September 30, December 31,
  2019 2018
  (in millions)
CURRENT LIABILITIES    
Advances from Affiliates $
 $105.5
Accounts Payable:  
  
General 128.6
 126.9
Affiliated Companies 38.6
 47.1
Long-term Debt Due Within One Year – Nonaffiliated 138.2
 375.5
Risk Management Liabilities 0.3
 1.0
Customer Deposits 59.0
 58.6
Accrued Taxes 43.7
 22.4
Obligations Under Operating Leases 6.0
 
Regulatory Liability for Over-Recovered Fuel Costs 69.9
 20.1
Other Current Liabilities 67.7
 64.5
TOTAL CURRENT LIABILITIES 552.0
 821.6
     
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated 1,248.2
 911.5
Deferred Income Taxes 617.5
 607.8
Regulatory Liabilities and Deferred Investment Tax Credits 858.9
 864.7
Asset Retirement Obligations 50.9
 46.3
Obligations Under Operating Leases 31.2
 
Deferred Credits and Other Noncurrent Liabilities 26.1
 32.5
TOTAL NONCURRENT LIABILITIES 2,832.8
 2,462.8
     
TOTAL LIABILITIES 3,384.8
 3,284.4
     
Rate Matters (Note 4) 

 

Commitments and Contingencies (Note 5) 

 

     
COMMON SHAREHOLDER’S EQUITY    
Common Stock – Par Value – $15 Per Share:    
Authorized – 11,000,000 Shares  
  
Issued – 10,482,000 Shares  
  
Outstanding – 9,013,000 Shares 157.2
 157.2
Paid-in Capital 364.0
 364.0
Retained Earnings 861.8
 724.7
Accumulated Other Comprehensive Income (Loss) 1.4
 2.1
TOTAL COMMON SHAREHOLDER’S EQUITY 1,384.4
 1,248.0
     
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $4,769.2
 $4,532.4
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.






PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2019 and 2018
(in millions)
(Unaudited)
  Nine Months Ended September 30,
  2019 2018
OPERATING ACTIVITIES  
  
Net Income $148.4
 $89.8
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
Depreciation and Amortization 125.4
 120.5
Deferred Income Taxes (9.7) (13.4)
Allowance for Equity Funds Used During Construction (1.5) 0.3
Mark-to-Market of Risk Management Contracts (12.0) (11.5)
Property Taxes (9.6) (9.6)
Deferred Fuel Over/Under-Recovery, Net 49.8
 73.3
Change in Other Noncurrent Assets 4.6
 6.9
Change in Other Noncurrent Liabilities (0.2) 14.6
Changes in Certain Components of Working Capital:  
  
Accounts Receivable, Net 9.1
 (3.4)
Fuel, Materials and Supplies (1.9) (1.5)
Accounts Payable (5.8) 6.9
Accrued Taxes, Net 19.0
 38.4
Other Current Assets (2.4) 0.3
Other Current Liabilities 1.1
 15.1
Net Cash Flows from Operating Activities 314.3
 326.7
     
INVESTING ACTIVITIES  
  
Construction Expenditures (198.7) (162.8)
Change in Advances to Affiliates, Net (95.1) 
Other Investing Activities 2.1
 3.9
Net Cash Flows Used for Investing Activities (291.7) (158.9)
     
FINANCING ACTIVITIES  
  
Issuance of Long-term Debt – Nonaffiliated 349.8
 
Change in Advances from Affiliates, Net (105.5) (127.6)
Retirement of Long-term Debt – Nonaffiliated (250.4) (0.3)
Make Whole Premium on Extinguishment of Long-term Debt (3.0) 
Principal Payments for Finance Lease Obligations (2.2) (2.5)
Dividends Paid on Common Stock (11.3) (37.5)
Other Financing Activities 0.9
 0.4
Net Cash Flows Used for Financing Activities (21.7) (167.5)
     
Net Increase in Cash and Cash Equivalents 0.9
 0.3
Cash and Cash Equivalents at Beginning of Period 2.0
 1.6
Cash and Cash Equivalents at End of Period $2.9
 $1.9
     
SUPPLEMENTARY INFORMATION  
  
Cash Paid for Interest, Net of Capitalized Amounts $46.5
 $42.0
Net Cash Paid for Income Taxes 16.0
 1.6
Noncash Acquisitions Under Finance Leases 3.4
 2.3
Construction Expenditures Included in Current Liabilities as of September 30, 31.5
 24.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 126.



PUBLIC SERVICE


SOUTHWESTERN ELECTRIC POWER COMPANY OF OKLAHOMACONSOLIDATED



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


RESULTS OF OPERATIONS


KWh Sales/Degree Days


Summary of KWh Energy Sales
Three Months Ended Nine Months EndedThree Months Ended Nine Months Ended
September 30, September 30,September 30, September 30,
2017 2016 2017 20162019 2018 2019 2018
(in millions of KWhs)(in millions of KWhs)
Retail: 
  
  
  
 
  
  
  
Residential1,992
 2,184
 4,662
 4,925
2,071
 1,992
 4,896
 5,156
Commercial1,488
 1,529
 3,926
 4,001
1,746
 1,675
 4,430
 4,548
Industrial1,472
 1,494
 4,249
 4,162
1,414
 1,366
 4,020
 4,033
Miscellaneous353
 369
 942
 955
19
 19
 59
 59
Total Retail(a)5,305
 5,576
 13,779
 14,043
5,250
 5,052
 13,405
 13,796
              
Wholesale82
 113
 309
 226
1,831
 1,881
 5,317
 5,352
              
Total KWhs5,387
 5,689
 14,088
 14,269
7,081
 6,933
 18,722
 19,148


(a)2018 KWhs have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail KWhs. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.

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
 Three Months Ended Nine Months Ended
 September 30, September 30,
 2019 2018 2019 2018
 (in degree days)
Actual – Heating (a)
 
 732
 784
Normal – Heating (b)1
 1
 725
 733
        
Actual – Cooling (c)1,552
 1,453
 2,263
 2,408
Normal – Cooling (b)1,408
 1,408
 2,187
 2,179


(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 20172019 Compared to Third Quarter of 20162018
Reconciliation of Third Quarter of 2016 to Third Quarter of 2017
Net Income
Reconciliation of Third Quarter of 2018 to Third Quarter of 2019Reconciliation of Third Quarter of 2018 to Third Quarter of 2019
Earnings Attributable to SWEPCo Common ShareholderEarnings Attributable to SWEPCo Common Shareholder
(in millions)
    
Third Quarter of 2016 $52.8
Third Quarter of 2018 $88.2
    
Changes in Gross Margin:    
Retail Margins (a) (15.6) 10.7
Off-system Sales (0.7) (0.2)
Transmission Revenues 4.1
 (4.8)
Other Revenues (2.0) (0.4)
Total Change in Gross Margin (14.2) 5.3
    
Changes in Expenses and Other:  
  
Other Operation and Maintenance (2.2) 4.9
Depreciation and Amortization 5.5
 (3.3)
Taxes Other Than Income Taxes (0.7) 0.7
Interest Income (0.2) (0.5)
Allowance for Equity Funds Used During Construction (1.1) 1.0
Non-Service Cost Components of Net Periodic Benefit Cost (0.2)
Interest Expense 1.7
 3.5
Total Change in Expenses and Other 3.0
 6.1
  
  
Income Tax Expense 4.6
Income Tax Expense (Benefit) 10.3
Net Income Attributable to Noncontrolling Interest 0.6
  
  
Third Quarter of 2017 $46.2
Third Quarter of 2019 $110.5


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

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

Retail Margins increased $11 million primarily due to the following:
A $6 million increase in weather-normalized margins.
A $5 million increase in weather-related usage primarily due to a 7% increase in cooling degree days.
Transmission Revenues decreased $5 million primarily due to a decrease in SPP Base Plan Funding revenues and a decrease in nonaffiliated transmission services.

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

Other Operation and Maintenance expenses decreased $5 million primarily due to Wind Catcher Project expenses incurred in 2018.
Depreciation and Amortization expenses increased $3 million primarily due to a higher depreciable base.
Interest Expense decreased $4 million primarily due to lower interest rates on outstanding long-term debt.
Income Tax Expense (Benefit) decreased $10 million primarily due to an increase in amortization of Excess ADIT not subject to normalization requirements. This decrease was partially offset in Gross Margin above.


Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018
Reconciliation of Nine Months Ended September 30, 2018 to Nine Months Ended September 30, 2019
Earnings Attributable to SWEPCo Common Shareholder
(in millions)
   
Nine Months Ended September 30, 2018 $137.6
   
Changes in Gross Margin:  
Retail Margins (a) (18.3)
Off-system Sales (0.1)
Transmission Revenues (35.6)
Other Revenues (0.3)
Total Change in Gross Margin (54.3)
   
Changes in Expenses and Other:  
Other Operation and Maintenance 47.7
Depreciation and Amortization (11.2)
Taxes Other Than Income Taxes 0.4
Interest Income (1.5)
Allowance for Equity Funds Used During Construction 0.7
Non-Service Cost Components of Net Periodic Benefit Cost (0.5)
Interest Expense 6.4
Total Change in Expenses and Other 42.0
   
Income Tax Expense (Benefit) 17.9
Equity Earnings of Unconsolidated Subsidiary 0.3
Net Income Attributable to Noncontrolling Interest 1.0
   
Nine Months Ended September 30, 2019 $144.5

(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:
Retail Margins decreased $18 million primarily due to the following:
A $17 million decrease primarily due to higher rates implemented in 2016 associated with interim rates.
An $11$14 million decrease in weather-related usage primarily due to a 14%6% decrease in cooling degree days and a 7% decrease in heating degree days.
A $10 million decrease in weather-normalized margins.
These decreases were partially offset by:
A $14$7 million increase primarily due to rider and base rate revenue increases in Louisiana. This increase was offset in other expense items below.
Transmission Revenues decreased $36 million primarily due to the following:
A $40 million decrease in the annual SPP formula rate true-up.
A $7 million decrease primarily due to a reduction in SPP Base Plan Funding revenues.
These decreases were partially offset by:
An $11 million increase due to weather-normalized margins.a provision for refund recorded in 2018 related to certain transmission assets that management believes should not have been included in the SPP formula rate.
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 (Benefit) 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
Other Operation and Maintenance expenses decreased $48 million primarily due to municipals and cooperatives.the following:

A $28 million decrease due to Wind Catcher Project expenses incurred in 2018.
The major components of theA $24 million 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 millionaffiliated SPP transmission expenses 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.annual formula rate true-up.
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$7 million increase in vegetation management expenses.  This increase is partially offset by a corresponding increase in Retail Margins as vegetation managementoverhead line 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.storm restoration.
This decrease was partially offset by:
A $12 million increase primarily related to new depreciation rates implemented in 2017
Depreciation and Amortization expenses increased $11 million primarily due to higher depreciation rates implemented in the third quarter of 2018 and a higher depreciable base.
Interest Expense decreased $6 million primarily due to lower interest rates on outstanding long-term debt.
Income Tax Expense (Benefit) decreased $18 million primarily due to an increase in amortization of Excess ADIT not subject to normalization requirements and a decrease in pretax book income. This decrease was partially offset in Gross Margin above.
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 SERVICESOUTHWESTERN ELECTRIC POWER COMPANY OF OKLAHOMACONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20172019 and 20162018
(in millions)
(Unaudited)
  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, 2017 and 2016
(in millions)
(Unaudited)
  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, 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$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, 2017 and December 31, 2016
(in millions)
(Unaudited)
  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, 2017 and December 31, 2016
(Unaudited)
  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, 2017 and 2016
(in millions)
(Unaudited)
  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



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

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 Three Months Ended 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 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 2017 Compared to Third Quarter of 2016
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)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 million primarily due to the following:
An $18 million decrease in weather-related usage due to a 17% decrease in cooling degree days.
This decrease was partially offset by:
An $11 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 upgrades in third quarter 2016. This decrease is offset by a corresponding decrease in Other Operation and Maintenance expenses below.

Expenses and Other, 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 million primarily due to a higher depreciable base.
Income Tax Expense decreased $11 million primarily due to income tax benefits attributable to SWEPCo’s noncontrolling interest 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 is offset by a decrease in Income Tax Expense above.


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 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)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 $8 million primarily due to the following:
A $29 million decrease in weather-related usage primarily due to a 33% decrease in heating degree days and a 12% decrease in cooling degree days.
A $9 million decrease in FERC generation wholesale municipal and cooperative revenues due to an annual formula rate true-up.
A $3 million decrease primarily due to lower fuel cost recovery.
These decreases were partially offset by:
A $33 million increase due to rider revenue increases in Louisiana, Texas and Arkansas, partially offset in various expenses below.
Margins from Off-System Sales increased $4 million primarily due to higher sales prices.
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, 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.
Taxes Other than Income Taxes increased $6 million primarily due to an increase in property taxes.
Allowance for Equity Funds Used During Construction decreased $8 million primarily due to the completion of environmental projects.
Income Tax Expense decreased $9 million primarily due to income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine. This decrease is offset by an increase in Net Income Attributable to Noncontrolling Interest below.
Equity Earnings (Loss) of Unconsolidated Subsidiary decreased $9 million primarily due to a prior period income tax adjustment for DHLC.
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 above.



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
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 Three Months Ended Nine Months Ended
 September 30, September 30, September 30, September 30,
 2017 2016 2017 2016 2019 2018 2019 2018
REVENUES        
        
Electric Generation, Transmission and Distribution $509.5
 $530.5
 $1,321.8
 $1,324.1
 $536.5
 $526.0
 $1,344.8
 $1,390.4
Sales to AEP Affiliates 7.7
 8.6
 20.4
 20.0
 8.8
 8.7
 21.6
 20.2
Provision for Refund – Affiliated (0.1) 
 (25.3) 
Other Revenues 0.4
 0.6
 1.4
 1.6
 0.3
 0.6
 1.0
 1.2
TOTAL REVENUES 517.6
 539.7
 1,343.6
 1,345.7
 545.5
 535.3
 1,342.1
 1,411.8
                
EXPENSES  
  
  
  
  
  
  
  
Fuel and Other Consumables Used for Electric Generation 147.5
 158.8
 389.8
 403.3
 148.8
 152.1
 400.2
 393.4
Purchased Electricity for Resale 40.0
 35.9
 118.7
 97.5
 44.8
 36.6
 110.5
 132.7
Other Operation 80.3
 89.2
 232.2
 243.3
 91.9
 99.1
 242.4
 292.0
Maintenance 32.6
 33.8
 106.5
 102.0
 35.9
 33.6
 104.1
 102.2
Depreciation and Amortization 55.2
 51.2
 158.1
 148.1
 63.2
 59.9
 187.1
 175.9
Taxes Other Than Income Taxes 25.0
 23.4
 72.6
 66.8
 26.2
 26.9
 76.0
 76.4
TOTAL EXPENSES 380.6
 392.3
 1,077.9
 1,061.0
 410.8
 408.2
 1,120.3
 1,172.6
                
OPERATING INCOME 137.0
 147.4
 265.7
 284.7
 134.7
 127.1
 221.8
 239.2
                
Other Income (Expense):  
  
  
  
  
  
    
Interest Income 0.7
 
 2.0
 
 0.6
 1.1
 2.0
 3.5
Allowance for Equity Funds Used During Construction 0.4
 0.1
 1.2
 9.5
 1.6
 0.6
 4.5
 3.8
Non-Service Cost Components of Net Periodic Benefit Cost 2.1
 2.3
 6.4
 6.9
Interest Expense (31.9) (32.6) (92.7) (92.0) (29.2) (32.7) (89.4) (95.8)
                
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 EARNINGS 109.8
 98.4
 145.3
 157.6
                
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) (0.7) 9.6
 
 17.9
Equity Earnings of Unconsolidated Subsidiary 0.8
 0.8
 2.3
 2.0
                
NET INCOME 84.1
 84.4
 126.5
 153.2
 111.3
 89.6
 147.6
 141.7
                
Net Income Attributable to Noncontrolling Interest 11.0
 1.1
 12.6
 3.3
 0.8
 1.4
 3.1
 4.1
                
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER $73.1
 $83.3
 $113.9
 $149.9
 $110.5
 $88.2
 $144.5
 $137.6
The common stock of SWEPCo is wholly-owned by Parent.
     
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20172019 and 20162018
(in millions)
(Unaudited)
Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended
September 30, September 30, September 30, September 30,
2017 2016 2017 2016 2019 2018 2019 2018
Net Income$84.1
 $84.4
 $126.5
 $153.2
 $111.3
 $89.6
 $147.6
 $141.7
               
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)
Cash Flow Hedges, Net of Tax of $0.1 and $0.8 for the Three Months Ended September 30, 2019 and 2018, Respectively, and $0.3 and $1 for the Nine Months Ended September 30, 2019 and 2018, Respectively 0.3
 2.7
 1.1
 3.6
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $(0.1) for the Three Months Ended September 30, 2019 and 2018, Respectively, and $(0.2) and $(0.3) for the Nine Months Ended September 30, 2019 and 2018, Respectively (0.3) (0.3) (0.9) (1.0)
               
TOTAL OTHER COMPREHENSIVE INCOME0.2
 0.3
 0.6
 0.8
 
 2.4
 0.2
 2.6
               
TOTAL COMPREHENSIVE INCOME84.3
 84.7
 127.1
 154.0
 111.3
 92.0
 147.8
 144.3
               
Total Comprehensive Income Attributable to Noncontrolling Interest11.0
 1.1
 12.6
 3.3
 0.8
 1.4
 3.1
 4.1
               
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER$73.3
 $83.6
 $114.5
 $150.7
 $110.5
 $90.6
 $144.7
 $140.2
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Nine Months Ended September 30, 20172019 and 20162018
(in millions)
(Unaudited)
  SWEPCo Common Shareholder    SWEPCo Common Shareholder    
Common
Stock
 Paid-in
Capital
 Retained
Earnings
 Accumulated
Other
Comprehensive
Income (Loss)
 
Noncontrolling
Interest
 TotalCommon
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
TOTAL EQUITY – DECEMBER 31, 2017$135.7
 $676.6
 $1,426.6
 $(4.0) $(0.4) $2,234.5
           
Common Stock Dividends    (20.0)     (20.0)
Common Stock Dividends – Nonaffiliated        (0.8) (0.8)
ASU 2018-02 Adoption    (0.4) (0.9)   (1.3)
Net Income    11.8
   1.6
 13.4
Other Comprehensive Income      0.1
   0.1
TOTAL EQUITY – MARCH 31, 2018135.7
 676.6
 1,418.0
 (4.8) 0.4
 2,225.9
                      
Common Stock Dividends    (90.0)     (90.0)    (20.0)     (20.0)
Common Stock Dividends – Nonaffiliated 
  
  
  
 (3.5) (3.5) 
  
  
  
 (1.0) (1.0)
Net Income 
  
 149.9
  
 3.3
 153.2
 
  
 37.6
  
 1.1
 38.7
Other Comprehensive Income 
  
  
 0.8
  
 0.8
 
  
  
 0.1
  
 0.1
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
TOTAL EQUITY – JUNE 30, 2018135.7
 676.6
 1,435.6
 (4.7) 0.5
 2,243.7
                      
Common Stock Dividends 
  
 (82.5)  
  
 (82.5)    (20.0)     (20.0)
Common Stock Dividends – Nonaffiliated 
  
  
  
 (2.7) (2.7)        (1.4) (1.4)
Net Income 
  
 113.9
  
 12.6
 126.5
    88.2
   1.4
 89.6
Other Comprehensive Income 
  
  
 0.6
  
 0.6
      2.4
   2.4
TOTAL EQUITY - SEPTEMBER 30, 2017$135.7
 $676.6
 $1,443.3
 $(8.8) $10.3
 $2,257.1
TOTAL EQUITY – SEPTEMBER 30, 2018$135.7
 $676.6
 $1,503.8
 $(2.3) $0.5
 $2,314.3
           
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 Income    27.8
   1.2
 29.0
Other Comprehensive Income      0.1
   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 Income    110.5
   0.8
 111.3
TOTAL EQUITY – SEPTEMBER 30, 2019$135.7
 $676.6
 $1,615.4
 $(5.2) $0.1
 $2,422.6
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20172019 and December 31, 20162018
(in millions)
(Unaudited)
 September 30, December 31, September 30, December 31,
 2017 2016 2019 2018
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
Cash and Cash Equivalents
(September 30, 2019 and December 31, 2018 Amounts Include $18.2 and $22, Respectively, Related to Sabine)
 $21.4
 $24.5
Advances to Affiliates 2.0
 169.8
 8.5
 83.4
Accounts Receivable:        
Customers 23.5
 48.5
 20.6
 24.5
Affiliated Companies 37.6
 29.3
 56.8
 28.8
Miscellaneous 20.8
 17.5
 16.6
 20.2
Allowance for Uncollectible Accounts (1.5) (1.2) (1.4) (0.7)
Total Accounts Receivable 80.4
 94.1
 92.6
 72.8
Fuel
(September 30, 2017 and December 31, 2016 Amounts Include $43.2 and $34.3, Respectively, Related to Sabine)
 93.1
 107.1
Fuel
(September 30, 2019 and December 31, 2018 Amounts Include $51.6 and $35.7, Respectively, Related to Sabine)
 135.9
 120.5
Materials and Supplies 68.8
 68.4
 69.8
 67.5
Risk Management Assets 12.5
 0.9
 9.4
 4.8
Accrued Tax Benefits 14.5
 51.5
Regulatory Asset for Under-Recovered Fuel Costs 13.6
 8.4
 11.1
 18.8
Prepayments and Other Current Assets 35.5
 35.5
 24.4
 22.2
TOTAL CURRENT ASSETS 322.6
 546.0
 373.1
 414.5
        
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
Generation 4,632.9
 4,607.6
 4,676.1
 4,672.6
Transmission 1,656.4
 1,584.2
 1,995.9
 1,866.9
Distribution 2,084.2
 2,020.6
 2,241.1
 2,178.6
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
Other Property, Plant and Equipment
(September 30, 2019 and December 31, 2018 Amounts Include $210.3 and $276.9, Respectively, Related to Sabine)
 703.2
 762.7
Construction Work in Progress 145.2
 113.8
 235.0
 199.3
Total Property, Plant and Equipment 9,220.3
 8,996.6
 9,851.3
 9,680.1
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
Accumulated Depreciation and Amortization
(September 30, 2019 and December 31, 2018 Amounts Include $105.7 and $174.6, Respectively, Related to Sabine)
 2,848.2
 2,808.3
TOTAL PROPERTY, PLANT AND EQUIPMENTNET
 6,549.8
 6,429.5
 7,003.1
 6,871.8
        
OTHER NONCURRENT ASSETS        
Regulatory Assets 566.4
 551.2
 223.6
 230.8
Long-term Risk Management Assets 0.7
 
Deferred Charges and Other Noncurrent Assets 116.4
 99.9
 167.2
 111.2
TOTAL OTHER NONCURRENT ASSETS 683.5
 651.1
 390.8
 342.0
        
TOTAL ASSETS $7,555.9
 $7,626.6
 $7,767.0
 $7,628.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 20172019 and December 31, 20162018
(Unaudited)
 September 30, December 31, September 30, December 31,
 2017 2016 2019 2018
 (in millions) (in millions)
CURRENT LIABILITIES        
Advances from Affiliates $48.3
 $
Accounts Payable:        
General 120.9
 117.5
 $127.6
 $129.1
Affiliated Companies 38.5
 68.5
 62.4
 64.2
Short-term Debt – Nonaffiliated 14.3
 
Long-term Debt Due Within One Year – Nonaffiliated 385.4
 353.7
 121.2
 59.7
Risk Management Liabilities 0.1
 0.3
 1.7
 0.4
Customer Deposits 61.6
 62.1
 65.0
 64.5
Accrued Taxes 73.0
 40.9
 94.7
 42.8
Accrued Interest 25.1
 45.1
 22.9
 34.7
Obligations Under Capital Leases 11.4
 11.8
Obligations Under Operating Leases 5.9
 
Regulatory Liability for Over-Recovered Fuel Costs 17.4
 11.1
Other Current Liabilities 77.5
 83.9
 108.0
 106.4
TOTAL CURRENT LIABILITIES 856.1
 783.8
 626.8
 512.9
        
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated 2,056.1
 2,325.4
 2,535.7
 2,653.7
Long-term Risk Management Liabilities 3.0
 2.2
Deferred Income Taxes 1,694.5
 1,606.9
 919.1
 902.8
Regulatory Liabilities and Deferred Investment Tax Credits 441.3
 438.9
 918.1
 923.0
Asset Retirement Obligations 159.0
 147.1
 200.9
 191.3
Employee Benefits and Pension Obligations 19.9
 34.1
Obligations Under Capital Leases 60.2
 65.5
Obligations Under Operating Leases 32.5
 
Deferred Credits and Other Noncurrent Liabilities 11.7
 9.7
 108.3
 126.8
TOTAL NONCURRENT LIABILITIES 4,442.7
 4,627.6
 4,717.6
 4,799.8
        
TOTAL LIABILITIES 5,298.8
 5,411.4
 5,344.4
 5,312.7
        
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
 135.7
 135.7
Paid-in Capital 676.6
 676.6
 676.6
 676.6
Retained Earnings 1,443.3
 1,411.9
 1,615.4
 1,508.4
Accumulated Other Comprehensive Income (Loss) (8.8) (9.4) (5.2) (5.4)
TOTAL COMMON SHAREHOLDER’S EQUITY 2,246.8
 2,214.8
 2,422.5
 2,315.3
        
Noncontrolling Interest 10.3
 0.4
 0.1
 0.3
        
TOTAL EQUITY 2,257.1
 2,215.2
 2,422.6
 2,315.6
        
TOTAL LIABILITIES AND EQUITY $7,555.9
 $7,626.6
 $7,767.0
 $7,628.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20172019 and 20162018
(in millions)
(Unaudited)
 Nine Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2019 2018
OPERATING ACTIVITIES  
  
  
  
Net Income $126.5
 $153.2
 $147.6
 $141.7
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:        
Depreciation and Amortization 158.1
 148.1
 187.1
 175.9
Deferred Income Taxes 79.8
 141.9
 (15.9) 2.0
Allowance for Equity Funds Used During Construction (1.2) (9.5) (4.5) (3.8)
Mark-to-Market of Risk Management Contracts (12.5) (5.8) (2.5) 2.5
Pension Contributions to Qualified Plan Trust (8.9) (8.3)
Property Taxes (15.4) (13.7) (16.1) (15.8)
Deferred Fuel Over/Under-Recovery, Net 2.4
 1.2
 14.1
 4.4
Change in Other Noncurrent Assets (2.9) 18.4
 3.5
 (8.9)
Change in Other Noncurrent Liabilities (5.2) (25.8) 5.8
 52.1
Changes in Certain Components of Working Capital:        
Accounts Receivable, Net 12.1
 12.2
 (17.2) 44.3
Fuel, Materials and Supplies 13.6
 33.4
 (17.7) 5.0
Accounts Payable (25.7) (17.2) (12.8) (29.9)
Accrued Taxes, Net 69.1
 14.1
 54.1
 38.4
Accrued Interest (20.0) (20.0)
Other Current Assets 0.7
 (2.4) (4.5) 3.2
Other Current Liabilities (14.6) (24.8) (13.9) 4.2
Net Cash Flows from Operating Activities 355.9
 395.0
 307.1
 415.3
        
INVESTING ACTIVITIES        
Construction Expenditures (265.3) (315.3) (277.3) (336.6)
Change in Advances to Affiliates, Net 167.8
 (297.4) 74.9
 (516.6)
Other Investing Activities 3.1
 (1.9) (1.2) 1.2
Net Cash Flows Used for Investing Activities (94.4) (614.6) (203.6) (852.0)
        
FINANCING ACTIVITIES        
Issuance of Long-term Debt – Nonaffiliated 114.6
 402.2
 
 1,015.4
Change in Short-term Debt – Nonaffiliated 14.3
 
 
 (2.6)
Change in Advances from Affiliates, Net 48.3
 (58.3) 
 (118.7)
Retirement of Long-term Debt – Nonaffiliated (353.6) (3.3) (58.2) (385.3)
Principal Payments for Capital Lease Obligations (8.4) (18.6)
Principal Payments for Finance Lease Obligations (8.1) (8.5)
Dividends Paid on Common Stock (82.5) (90.0) (37.5) (60.0)
Dividends Paid on Common Stock – Nonaffiliated (2.7) (3.5) (3.3) (3.2)
Other Financing Activities 0.4
 1.1
 0.5
 0.5
Net Cash Flows from (Used for) Financing Activities (269.6) 229.6
 (106.6) 437.6
        
Net Increase (Decrease) in Cash and Cash Equivalents (8.1) 10.0
 (3.1) 0.9
Cash and Cash Equivalents at Beginning of Period 10.3
 5.2
 24.5
 1.6
Cash and Cash Equivalents at End of Period $2.2
 $15.2
 $21.4
 $2.5
        
SUPPLEMENTARY INFORMATION        
Cash Paid for Interest, Net of Capitalized Amounts $109.4
 $107.6
 $95.1
 $102.5
Net Cash Paid (Received) for Income Taxes (70.5) (66.6)
Noncash Acquisitions Under Capital Leases 2.8
 5.5
Net Cash Paid for Income Taxes 7.3
 12.9
Noncash Acquisitions Under Finance Leases 4.7
 3.2
Construction Expenditures Included in Current Liabilities as of September 30, 40.7
 54.3
 52.0
 37.0
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 118126.




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:
Note Registrant 
Page
Number
     
Significant Accounting Matters AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 
New Accounting PronouncementsStandards AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 
Comprehensive Income AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo 
Rate Matters AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 
Commitments, Guarantees and Contingencies AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 
Impairment, Disposition,Acquisitions and Assets and Liabilities Held for SaleImpairments AEP, I&MAPCo 
Benefit Plans AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo 
Business Segments AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 
Derivatives and Hedging AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo 
Fair Value Measurements AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 
Income Taxes AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 
Financing ActivitiesLeases AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 
Financing ActivitiesAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
Variable Interest Entities and Equity Method InvestmentsAEP
Revenue from Contracts with CustomersAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo




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, 20172019 is not necessarily indicative of results that may be expected for the year ending December 31, 2017.2019.  The condensed financial statements are unaudited and should be read in conjunction with the audited 20162018 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 should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 2017.21, 2019.


Earnings Per Share (EPS) (Applies to AEP)


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


The following tables present AEP’s basic and diluted EPS calculations included on the statements of income:
Three Months Ended September 30,Three Months Ended September 30,
2017 20162019 2018
(in millions, except per share data)(in millions, except per share data)
 
 $/share   $/share 
 $/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)  
Earnings Attributable to AEP Common Shareholders$733.5
  
 $577.6
  
              
Weighted Average Number of Basic Shares Outstanding491.8
 $1.11
 491.7
 $(1.56)493.8
 $1.49
 493.0
 $1.17
Weighted Average Dilutive Effect of Stock-Based Awards1.2
 (0.01) 0.1
 
1.7
 (0.01) 0.9
 
Weighted Average Number of Diluted Shares Outstanding493.0
 $1.10
 491.8
 $(1.56)495.5
 $1.48
 493.9
 $1.17
 Nine Months Ended September 30,
 2019 2018
 (in millions, except per share data)
  
 $/share   $/share
Earnings Attributable to AEP Common Shareholders$1,767.6
   $1,560.4
  
        
Weighted Average Number of Basic Shares Outstanding493.6
 $3.58
 492.6
 $3.17
Weighted Average Dilutive Effect of Stock-Based Awards1.5
 (0.01) 0.9
 (0.01)
Weighted Average Number of Diluted Shares Outstanding495.1
 $3.57
 493.5
 $3.16

 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 issued in March 2019 are potentially dilutive securities but were excluded from the calculation of diluted EPS for the three and nine months ended September 30, 2019, as the dilutive stock price threshold was not met. See Note 13 - Financing Activities for more information related to Equity Units.

There were no antidilutive shares outstanding as of September 30, 20172019 and 2016.2018.




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

SWEPCo recorded prior year income tax adjustments inRestricted Cash primarily included funds held by trustee for the second quarterpayment of 2017 relatedsecuritization 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 DHLC that impacted Equity Earnings (Loss)the total of Unconsolidated Subsidiary in the amountsame amounts shown on the statements of $6 million.

Supplementary Cash Flow Information (Applies to AEP)cash flows:
  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
 
  September 30, 2019
  AEP AEP Texas APCo OPCo
  (in millions)
Cash and Cash Equivalents $348.8
 $0.1
 $3.5
 $4.7
Restricted Cash 141.0
 114.3
 17.1
 
Total Cash, Cash Equivalents and Restricted Cash $489.8
 $114.4
 $20.6
 $4.7
  December 31, 2018
  AEP AEP Texas APCo OPCo
  (in millions)
Cash and Cash Equivalents $234.1
 $3.1
 $4.2
 $4.9
Restricted Cash 210.0
 156.7
 25.6
 27.6
Total Cash, Cash Equivalents and Restricted Cash $444.1
 $159.8
 $29.8
 $32.5







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” (ASU 2014-09)

In May 2014, the FASB issued ASU 2014-09 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.

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 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.




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 beleases are known as a finance leaseleases going forward. Leases with lease terms of 12 months or longer will beare also subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remainremains the same, but will beis 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 atNew leasing standard implementation activities included the beginningidentification of the earliest period presented.

Management continues to analyzelease population within the impact of the new lease standard. During 2016 and 2017, lease contract assessments were completed. The AEP System lease population was identified andas well as the sampling of representative lease contracts were sampled.to analyze accounting treatment under the new accounting guidance. Based upon the completed assessments, management also prepared a system gap analysis to outline new disclosure compliance requirements comparedrequirements.

Management adopted ASU 2016-02 effective January 1, 2019 by means of a cumulative-effect adjustment to current system capabilities. Multiple lease system options were also evaluated.the balance sheets. Management plans to elect certain ofelected the following practical expedients upon adoption:
Practical Expedient Description
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 termExisting and expired land easements not previously accounted for as leases Elect optional transition practical expedient to use hindsightnot evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840.
Cumulative-effect adjustment in the period of adoptionElect the optional transition practical expedient to determineadopt the new lease term.requirements through a cumulative-effect adjustment on the balance sheet in the period of adoption.


EvaluationManagement concluded that the result of new leaseadoption would not materially change the volume of contracts continues and the processthat qualify as leases going forward. The adoption of implementing a compliant lease system solution began in the third quarter of 2017. Management expects the new standard todid not materially 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.

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 classificationflows, but did have a material impact on the statements of cash flows. Underbalance sheets. See Note 12 - Leases for additional disclosures required by 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.standard.

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 the recognition of an allowance to be recorded for all expected credit losses for financial assets.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 isshould be based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions torevises the other than temporaryother-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 analyzingcontinues to analyze the impact of this new standard and, at this time, cannot estimatestandard. Implementation activities to date include the impactidentification of adoption on net income. Management plansthe population of financial instruments within the AEP system that are subject 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 cashand evaluations to determine whether the new expected loss recognition model will be included with cashcause any material changes to previously calculated allowance balances and cash equivalents when reconciling the beginning-of-period and end-of-period total amountssupporting valuation models. Based on the statementsassessments performed to date, Management does not expect the new standard to have a material impact on results of operations, financial position or cash flows.


TheManagement’s implementation activities, including an assessment of the new standard’s disclosure requirements will continue throughout the fourth quarter of 2019. Management will continue to analyze the related impacts to allowances for credit losses and monitor for any potential industry implementation issues. Additionally, Management does not anticipate any significant changes to current accounting guidance is effective for annual periods beginning after December 15, 2017. Earlysystems because of the 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 pension2016-13 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 accountingits related implementation 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, 2018.2020.


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

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

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2016
  Cash Flow Hedges Pension  
Three Months Ended September 30, 2019 Commodity Interest Rate and OPEB Total
  (in millions)
Balance in AOCI as of June 30, 2019 $(127.2) $(15.9) $(87.6) $(230.7)
Change in Fair Value Recognized in AOCI 38.4
 (0.8)(b)
 37.6
Amount of (Gain) Loss Reclassified from AOCI        
Generation & Marketing Revenues (a) (0.1) 
 
 (0.1)
Purchased Electricity for Resale (a) 8.5
 
 
 8.5
Amortization of Prior Service Cost (Credit) 
 
 (4.8) (4.8)
Amortization of Actuarial (Gains) Losses 
 
 3.0
 3.0
Reclassifications from AOCI, before Income Tax (Expense) Benefit 8.4
 
 (1.8) 6.6
Income Tax (Expense) Benefit 1.8
 
 (0.4) 1.4
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 6.6
 
 (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)
Cash Flow Hedges       Cash Flow Hedges Pension  
Three Months Ended September 30, 2018 Commodity Interest Rate and OPEB Total
Commodity Interest Rate 
Securities
Available for Sale
 
Pension
and OPEB
 Total (in millions)
(in millions)
Balance in AOCI as of June 30, 2016$1.9
 $(16.5) $8.3
 $(111.6) $(117.9)
Balance in AOCI as of June 30, 2018 $(30.4) $(15.3) $(49.1) $(94.8)
Change in Fair Value Recognized in AOCI(26.7) 
 0.5
 
 (26.2) 12.2
 2.3
 
 14.5
Amount of (Gain) Loss Reclassified from AOCI                 
Generation & Marketing Revenues(a)(5.4) 
 
 
 (5.4) (0.1) 
 
 (0.1)
Purchased Electricity for Resale(a)1.8
 
 
 
 1.8
 (5.8) 
 
 (5.8)
Interest Expense(a)
 0.6
 
 
 0.6
 
 0.4
 
 0.4
Amortization of Prior Service Cost (Credit)
 
 
 (4.8) (4.8) 
 
 (5.0) (5.0)
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)
Amortization of Actuarial (Gains) Losses 
 
 3.2
 3.2
Reclassifications from AOCI, before Income Tax (Expense) Benefit (5.9) 0.4
 (1.8) (7.3)
Income Tax (Expense) Benefit (1.3) 0.1
 (0.4) (1.6)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (4.6) 0.3
 (1.4) (5.7)
Net Current Period Other Comprehensive Income (Loss)(29.0) 0.4
 0.5
 0.2
 (27.9) 7.6
 2.6
 (1.4) 8.8
Balance in AOCI as of September 30, 2016$(27.1) $(16.1) $8.8
 $(111.4) $(145.8)
Balance in AOCI as of September 30, 2018 $(22.8) $(12.7) $(50.5) $(86.0)




AEP

  Cash Flow Hedges Pension  
Nine Months Ended September 30, 2019 Commodity Interest Rate and OPEB Total
  (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)(b)
 (96.8)
Amount of (Gain) Loss Reclassified from AOCI        
Generation & Marketing Revenues (a) (0.1) 
 
 (0.1)
Purchased Electricity for Resale (a) 42.0
 
 
 42.0
Interest Expense (a) 
 0.5
 
 0.5
Amortization of Prior Service Cost (Credit) 
 
 (14.3) (14.3)
Amortization of Actuarial (Gains) Losses 
 
 9.0
 9.0
Reclassifications from AOCI, before Income Tax (Expense) Benefit 41.9
 0.5
 (5.3) 37.1
Income Tax (Expense) Benefit 8.8
 0.1
 (1.1) 7.8
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 33.1
 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)
Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2017
 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)
  Cash Flow Hedges Securities    
    Interest Available Pension  
Nine Months Ended September 30, 2018 Commodity Rate for Sale and OPEB Total
  (in millions)
Balance in AOCI as of December 31, 2017 $(28.4) $(13.0) $11.9
 $(38.3) $(67.8)
Change in Fair Value Recognized in AOCI 30.4
 2.3
 
 
 32.7
Amount of (Gain) Loss Reclassified from AOCI          
Generation & Marketing Revenues (a) (0.1) 
 
 
 (0.1)
Purchased Electricity for Resale (a) (23.6) 
 
 
 (23.6)
Interest Expense (a) 
 0.9
 
 
 0.9
Amortization of Prior Service Cost (Credit) 
 
 
 (14.7) (14.7)
Amortization of Actuarial (Gains) Losses 
 
 
 9.6
 9.6
Reclassifications from AOCI, before Income Tax (Expense) Benefit (23.7) 0.9
 
 (5.1) (27.9)
Income Tax (Expense) Benefit (5.0) 0.2
 
 (1.1) (5.9)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (18.7) 0.7
 
 (4.0) (22.0)
Net Current Period Other Comprehensive Income (Loss) 11.7
 3.0
 
 (4.0) 10.7
ASU 2018-02 Adoption (6.1) (2.7) 
 (8.2) (17.0)
ASU 2016-01 Adoption 
 
 (11.9) 
 (11.9)
Balance in AOCI as of September 30, 2018 $(22.8) $(12.7) $
 $(50.5) $(86.0)

AEP

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2016AEP Texas
 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)
  Cash Flow Hedge – Pension  
Three Months Ended September 30, 2019 Interest Rate and OPEB Total
 (in millions)
Balance in AOCI as of June 30, 2019 $(3.9) $(10.6) $(14.5)
Change in Fair Value Recognized in AOCI 0.3
 
 0.3
Amount of (Gain) Loss Reclassified from AOCI      
Amortization of Prior Service Cost (Credit) 
 (0.1) (0.1)
Amortization of Actuarial (Gains) Losses 
 0.1
 0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit 
 
 
Income Tax (Expense) Benefit 
 
 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 
 
 
Net Current Period Other Comprehensive Income (Loss) 0.3
 
 0.3
Balance in AOCI as of September 30, 2019 $(3.6) $(10.6) $(14.2)

  Cash Flow Hedge – Pension  
Three Months Ended September 30, 2018 Interest Rate and OPEB Total
 (in millions)
Balance in AOCI as of June 30, 2018 $(4.9) $(9.8) $(14.7)
Change in Fair Value Recognized in AOCI 
 
 
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense (a) 0.4
 
 0.4
Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.4
 
 0.4
Income Tax (Expense) Benefit 0.1
 
 0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.3
 
 0.3
Net Current Period Other Comprehensive Income (Loss) 0.3
 
 0.3
Balance in AOCI as of September 30, 2018 $(4.6) $(9.8) $(14.4)

  Cash Flow Hedge – Pension  
Nine Months Ended September 30, 2019 Interest Rate and OPEB Total
 (in millions)
Balance in AOCI as of December 31, 2018 $(4.4) $(10.7) $(15.1)
Change in Fair Value Recognized in AOCI 0.3
 
 0.3
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense (a) 0.6
 
 0.6
Amortization of Prior Service Cost (Credit) 
 (0.1) (0.1)
Amortization of Actuarial (Gains) Losses 
 0.2
 0.2
Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.6
 0.1
 0.7
Income Tax (Expense) Benefit 0.1
 
 0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.5
 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)

APCo

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 $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)
  Cash Flow Hedge – Pension  
Nine Months Ended September 30, 2018 Interest Rate and OPEB Total
 (in millions)
Balance in AOCI as of December 31, 2017 $(4.5) $(8.1) $(12.6)
Change in Fair Value Recognized in AOCI 
 
 
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense (a) 1.0
 
 1.0
Amortization of Prior Service Cost (Credit) 
 (0.1) (0.1)
Amortization of Actuarial (Gains) Losses 
 0.2
 0.2
Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.0
 0.1
 1.1
Income Tax (Expense) Benefit 0.2
 
 0.2
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.8
 0.1
 0.9
Net Current Period Other Comprehensive Income (Loss) 0.8
 0.1
 0.9
ASU 2018-02 Adoption (0.9) (1.8) (2.7)
Balance in AOCI as of September 30, 2018 $(4.6) $(9.8) $(14.4)

APCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2016APCo
  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 Hedge – Pension  
Three Months Ended September 30, 2019 Interest Rate and OPEB Total
 (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) 
 (0.3)
Amount of (Gain) Loss Reclassified from AOCI      
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) Benefit 
 (0.8) (0.8)
Income Tax (Expense) Benefit 
 (0.2) (0.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 
 (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)
  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)
  Cash Flow Hedge – Pension  
Three Months Ended September 30, 2018 Interest Rate and OPEB Total
 (in millions)
Balance in AOCI as of June 30, 2018 $2.3
 $(2.7) $(0.4)
Change in Fair Value Recognized in AOCI 
 
 
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense (a) (0.4) 
 (0.4)
Amortization of Prior Service Cost (Credit) 
 (1.3) (1.3)
Amortization of Actuarial (Gains) Losses 
 0.4
 0.4
Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.4) (0.9) (1.3)
Income Tax (Expense) Benefit (0.1) (0.2) (0.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.3) (0.7) (1.0)
Net Current Period Other Comprehensive Income (Loss) (0.3) (0.7) (1.0)
Balance in AOCI as of September 30, 2018 $2.0
 $(3.4) $(1.4)
  Cash Flow Hedge – Pension  
Nine Months Ended September 30, 2019 Interest Rate and OPEB Total
 (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) 
 (0.3)
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense (a) (0.5) 
 (0.5)
Amortization of Prior Service Cost (Credit) 
 (4.0) (4.0)
Amortization of Actuarial (Gains) Losses 
 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)
  Cash Flow Hedges Pension  
Nine Months Ended September 30, 2018 Commodity Interest Rate and OPEB Total
  (in millions)
Balance in AOCI as of December 31, 2017 $
 $2.2
 $(0.9) $1.3
Change in Fair Value Recognized in AOCI (0.7) 
 
 (0.7)
Amount of (Gain) Loss Reclassified from AOCI        
Purchased Electricity for Resale (a) 0.9
 
 
 0.9
Interest Expense (a) 
 (0.9) 
 (0.9)
Amortization of Prior Service Cost (Credit) 
 
 (3.9) (3.9)
Amortization of Actuarial (Gains) Losses 
 
 1.0
 1.0
Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.9
 (0.9) (2.9) (2.9)
Income Tax (Expense) Benefit 0.2
 (0.2) (0.6) (0.6)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.7
 (0.7) (2.3) (2.3)
Net Current Period Other Comprehensive Income (Loss) 
 (0.7) (2.3) (3.0)
ASU 2018-02 Adoption 
 0.5
 (0.2) 0.3
Balance in AOCI as of September 30, 2018 $
 $2.0
 $(3.4) $(1.4)


APCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2016I&M
  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

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2017
  Cash Flow Hedge – Pension  
Three Months Ended September 30, 2019 Interest Rate and OPEB Total
 (in millions)
Balance in AOCI as of June 30, 2019 $(10.7) $(2.4) $(13.1)
Change in Fair Value Recognized in AOCI 0.4
 
 0.4
Amount of (Gain) Loss Reclassified from AOCI      
Amortization of Prior Service Cost (Credit) 
 (0.2) (0.2)
Amortization of Actuarial (Gains) Losses 
 0.2
 0.2
Reclassifications from AOCI, before Income Tax (Expense) Benefit 
 
 
Income Tax (Expense) Benefit 
 
 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 
 
 
Net Current Period Other Comprehensive Income (Loss) 0.4
 
 0.4
Balance in AOCI as of September 30, 2019 $(10.3) $(2.4) $(12.7)
  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 in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2016
  Cash Flow Hedge – Pension  
Three Months Ended September 30, 2018 Interest Rate and OPEB Total
 (in millions)
Balance in AOCI as of June 30, 2018 $(12.2) $(1.7) $(13.9)
Change in Fair Value Recognized in AOCI 
 
 
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense (a) 0.4
 
 0.4
Amortization of Prior Service Cost (Credit) 
 (0.2) (0.2)
Amortization of Actuarial (Gains) Losses 
 0.2
 0.2
Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.4
 
 0.4
Income Tax (Expense) Benefit 0.1
 
 0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.3
 
 0.3
Net Current Period Other Comprehensive Income (Loss) 0.3
 
 0.3
Balance in AOCI as of September 30, 2018 $(11.9) $(1.7) $(13.6)
  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)
  Cash Flow Hedge – Pension  
Nine Months Ended September 30, 2019 Interest Rate and OPEB Total
 (in millions)
Balance in AOCI as of December 31, 2018 $(11.5) $(2.3) $(13.8)
Change in Fair Value Recognized in AOCI 0.4
 
 0.4
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense (a) 1.0
 
 1.0
Amortization of Prior Service Cost (Credit) 
 (0.6) (0.6)
Amortization of Actuarial (Gains) Losses 
 0.5
 0.5
Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.0
 (0.1) 0.9
Income Tax (Expense) Benefit 0.2
 
 0.2
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.8
 (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)
  Cash Flow Hedge – Pension  
Nine Months Ended September 30, 2018 Interest Rate and OPEB Total
  (in millions)
Balance in AOCI as of December 31, 2017 $(10.7) $(1.4) $(12.1)
Change in Fair Value Recognized in AOCI 
 
 
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense (a) 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) Benefit 1.5
 
 1.5
Income Tax (Expense) Benefit 0.3
 
 0.3
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.2
 
 1.2
Net Current Period Other Comprehensive Income (Loss) 1.2
 
 1.2
ASU 2018-02 Adoption (2.4) (0.3) (2.7)
Balance in AOCI as of September 30, 2018 $(11.9) $(1.7) $(13.6)





I&M

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2017OPCo
  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 Hedge –
Three Months Ended September 30, 2019 Interest 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 (a) (0.1)
Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.1)
Income Tax (Expense) Benefit 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.1)
Net Current Period Other Comprehensive Income (Loss) (0.3)
Balance in AOCI as of September 30, 2019 $
  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 Hedge –
Three Months Ended September 30, 2018 Interest Rate
 (in millions)
Balance in AOCI as of June 30, 2018 $1.7
Change in Fair Value Recognized in AOCI 
Amount of (Gain) Loss Reclassified from AOCI  
Interest Expense (a) (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) (0.4)
Balance in AOCI as of September 30, 2018 $1.3
  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
  Cash Flow Hedge –
Nine Months Ended September 30, 2019 Interest 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 (a) (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 $
  Cash Flow Hedge –
Nine Months Ended September 30, 2018 Interest Rate
 (in millions)
Balance in AOCI as of December 31, 2017 $1.9
Change in Fair Value Recognized in AOCI 
Amount of (Gain) Loss Reclassified from AOCI  
Interest Expense (a) (1.3)
Reclassifications from AOCI, before Income Tax (Expense) Benefit (1.3)
Income Tax (Expense) Benefit (0.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (1.0)
Net Current Period Other Comprehensive Income (Loss) (1.0)
ASU 2018-02 Adoption 0.4
Balance in AOCI as of September 30, 2018 $1.3


OPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2016PSO
  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 Hedge –
Three Months Ended September 30, 2019 Interest 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 (a) 0.2
Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.2
Income Tax (Expense) Benefit 0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.1
Net Current Period Other Comprehensive Income (Loss) (0.2)
Balance in AOCI as of September 30, 2019 $1.4
  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
  Cash Flow Hedge –
Three Months Ended September 30, 2018 Interest Rate
 (in millions)
Balance in AOCI as of June 30, 2018 $2.6
Change in Fair Value Recognized in AOCI 
Amount of (Gain) Loss Reclassified from AOCI  
Interest Expense (a) (0.2)
Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.2)
Income Tax (Expense) Benefit 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.2)
Net Current Period Other Comprehensive Income (Loss) (0.2)
Balance in AOCI as of September 30, 2018 $2.4
  Cash Flow Hedge –
Nine Months Ended September 30, 2019 Interest 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 (a) (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
  Cash Flow Hedge –
Nine Months Ended September 30, 2018 Interest Rate
 (in millions)
Balance in AOCI as of December 31, 2017 $2.6
Change in Fair Value Recognized in AOCI 
Amount of (Gain) Loss Reclassified from AOCI  
Interest Expense (a) (0.9)
Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.9)
Income Tax (Expense) Benefit (0.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.7)
Net Current Period Other Comprehensive Income (Loss) (0.7)
ASU 2018-02 Adoption 0.5
Balance in AOCI as of September 30, 2018 $2.4


OPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2016SWEPCo
  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 Hedge – Pension  
Three Months Ended September 30, 2019 Interest Rate and OPEB Total
 (in millions)
Balance in AOCI as of June 30, 2019 $(2.5) $(2.7) $(5.2)
Change in Fair Value Recognized in AOCI 0.3
 
 0.3
Amount of (Gain) Loss Reclassified from AOCI      
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) Benefit 
 (0.3) (0.3)
Income Tax (Expense) Benefit 
 
 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 
 (0.3) (0.3)
Net Current Period Other Comprehensive Income (Loss) 0.3
 (0.3) 
Balance in AOCI as of September 30, 2019 $(2.2) $(3.0) $(5.2)
  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 Hedge – Pension  
Three Months Ended September 30, 2018 Interest Rate and OPEB Total
 (in millions)
Balance in AOCI as of June 30, 2018 $(6.4) $1.7
 $(4.7)
Change in Fair Value Recognized in AOCI 2.3
 
 2.3
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense (a) 0.5
 
 0.5
Amortization of Prior Service Cost (Credit) 
 (0.5) (0.5)
Amortization of Actuarial (Gains) Losses 
 0.1
 0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.5
 (0.4) 0.1
Income Tax (Expense) Benefit 0.1
 (0.1) 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.4
 (0.3) 0.1
Net Current Period Other Comprehensive Income (Loss) 2.7
 (0.3) 2.4
Balance in AOCI as of September 30, 2018 $(3.7) $1.4
 $(2.3)
  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 Hedge – Pension  
Nine Months Ended September 30, 2019 Interest Rate and OPEB Total
 (in millions)
Balance in AOCI as of December 31, 2018 $(3.3) $(2.1) $(5.4)
Change in Fair Value Recognized in AOCI 0.3
 
 0.3
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense (a) 1.0
 
 1.0
Amortization of Prior Service Cost (Credit) 
 (1.5) (1.5)
Amortization of Actuarial (Gains) Losses 
 0.4
 0.4
Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.0
 (1.1) (0.1)
Income Tax (Expense) Benefit 0.2
 (0.2) 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.8
 (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)
  Cash Flow Hedge – Pension  
Nine Months Ended September 30, 2018 Interest Rate and OPEB Total
 (in millions)
Balance in AOCI as of December 31, 2017 $(6.0) $2.0
 $(4.0)
Change in Fair Value Recognized in AOCI 2.3
 
 2.3
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense (a) 1.6
 
 1.6
Amortization of Prior Service Cost (Credit) 
 (1.5) (1.5)
Amortization of Actuarial (Gains) Losses 
 0.2
 0.2
Reclassifications from AOCI, before Income Tax (Expense) Benefit 1.6
 (1.3) 0.3
Income Tax (Expense) Benefit 0.3
 (0.3) 
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 1.3
 (1.0) 0.3
Net Current Period Other Comprehensive Income (Loss) 3.6
 (1.0) 2.6
ASU 2018-02 Adoption (1.3) 0.4
 (0.9)
Balance in AOCI as of September 30, 2018 $(3.7) $1.4
 $(2.3)


(a)Amounts reclassified to the referenced line item on the statements of income.
(b)The change in fair value includes $2 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, 2019, respectively. See “Sempra Renewables LLC” section of Note 14 for additional information.

  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 2018 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 2018 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 20172019 and updates AEP’sthe 2018 Annual Report.

Regulated Generating Unit to be Retired by 2020 (Applies to AEP and AEPTCo’s 2016 Annual Reports.PSO)


Regulatory Assets Pending Final Regulatory ApprovalIn September 2018, management announced that the Oklaunion Power Station is probable of abandonment and is to be retired by October 2020.  The table below summarizes the plant investment and cost of removal, currently being recovered, as well as the regulatory asset for accelerated depreciation for the generating unit as of September 30, 2019. See “2018 Oklahoma Base Rate Case” below for additional information.
Gross
Investment
 Accumulated
Depreciation
 Net
Investment
 Accelerated
Depreciation
Regulatory
Asset (a)
 Materials and Supplies Cost of
Removal
Regulatory
Liability
 Expected
Retirement
Date
 Remaining
Recovery
Period
(dollars in millions)
$106.6
 $80.6
 $26.0
 $21.9
 $3.2
 $5.1
 2020 27 years

  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


(a)In March 2017, $41October 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. See “2018 Oklahoma Base Rate Case” discussion below for additional information.

Regulatory Assets Pending Final Regulatory Approval (Applies to all Registrants except AEPTCo)
  AEP
  September 30, December 31,
  2019 2018
 Noncurrent Regulatory Assets (in millions)
     
Regulatory Assets Currently Earning a Return    
Plant Retirement Costs  Unrecovered Plant
 $50.3
 $50.3
Kentucky Deferred Purchase Power Expenses 26.2
 14.5
Oklaunion Power Station Accelerated Depreciation 21.9
 5.5
Other Regulatory Assets Pending Final Regulatory Approval 5.4
 9.3
Regulatory Assets Currently Not Earning a Return  
  
Plant Retirement Costs  Asset Retirement Obligation Costs
 37.8
 35.3
Storm-Related Costs (a) 
 152.4
Other Regulatory Assets Pending Final Regulatory Approval 26.8
 20.7
Total Regulatory Assets Pending Final Regulatory Approval (b)$168.4
 $288.0

(a)In September 2019, AEP Texas securitized $235 million of storm-related costs. As a result of the securitization, the regulatory asset balance was reclassified from accumulated depreciationtransferred to regulatory assets related to Northeastern Plant, Unit 3. As of September 30, 2017,Securitized Assets on the unrecovered plant balance related to Northeastern Plant, Unit 3 was $52 million. sheets. See “Texas Storm Cost Securitization” discussion below for additional information.
(b)In 2015, APCo recorded a $91 million reduction, before cost of removal of $17 million, 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. RecoveryAPCo’s 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.SCC’s 2020 triennial review of APCo’s generation and distribution base rates.



  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
  AEP Texas
  September 30, December 31,
  2019 2018
Noncurrent Regulatory Assets (in millions)
     
Regulatory Assets Currently Not Earning a Return    
Rate Case Expense $2.3
 $0.2
Storm-Related Costs (a) 
 152.4
Total Regulatory Assets Pending Final Regulatory Approval $2.3
 $152.6


(a)In September 2019, AEP Texas securitized $235 million of storm-related costs. As a result of the securitization, the regulatory asset balance was transferred to Securitized Assets on the balance sheets. See “Texas Storm Cost Securitization” discussion below for additional information.
  APCo
  September 30, December 31,
  2019 2018
Noncurrent Regulatory Assets (in millions)
     
Regulatory Assets Currently Earning a Return    
Plant Retirement Costs  Materials and Supplies
 $5.1
 $9.0
Regulatory Assets Currently Not Earning a Return    
Plant Retirement Costs  Asset Retirement Obligation Costs
 37.8
 35.3
Other Regulatory Assets Pending Final Regulatory Approval 
 0.6
Total Regulatory Assets Pending Final Regulatory Approval (a) $42.9
 $44.9

(a)In 2015, APCo recorded a $91 million reduction, before cost of removal of $17 million, 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. RecoveryAPCo’s 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.SCC’s 2020 triennial review of APCo’s generation and distribution base rates.
 I&M I&M
 September 30, December 31, September 30, December 31,
 2017 2016 2019 2018
Noncurrent Regulatory Assets (in millions) (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
Cook Plant Study Costs $10.7
 $
Other Regulatory Assets Pending Final Regulatory Approval 1.5
 0.9
 0.1
 3.3
Total Regulatory Assets Pending Final Regulatory Approval $75.3
 $64.7
 $10.8
 $3.3
 OPCo OPCo
 September 30, December 31, September 30, December 31,
 2017 2016 2019 2018
Noncurrent Regulatory Assets (in millions) (in millions)
        
Regulatory Assets Currently Earning a Return    
Capacity Deferral $
 $96.7
Regulatory Assets Currently Not Earning a Return  
  
    
Smart Grid Costs 
 4.1
Other Regulatory Assets Pending Final Regulatory Approval $0.1
 $1.0
Total Regulatory Assets Pending Final Regulatory Approval $
 $100.8
 $0.1
 $1.0




  PSO
  September 30, December 31,
  2019 2018
Noncurrent Regulatory Assets (in millions)
     
Regulatory Assets Currently Earning a Return    
Oklaunion Power Station Accelerated Depreciation $21.9
 $5.5
Regulatory Assets Currently Not Earning a Return  
  
Other Regulatory Assets Pending Final Regulatory Approval 
 0.5
Total Regulatory Assets Pending Final Regulatory Approval $21.9
 $6.0
 PSO SWEPCo
 September 30, December 31, September 30, December 31,
 2017 2016 2019 2018
Noncurrent Regulatory Assets (in millions) (in millions)
        
Regulatory Assets Currently Earning a Return        
Plant Retirement Costs - Unrecovered Plant (a) $133.7
 $84.5
Plant Retirement Costs Unrecovered Plant
 $50.3
 $50.3
Other Regulatory Assets Pending Final Regulatory Approval 0.5
 0.5
 0.3
 0.3
Regulatory Assets Currently Not Earning a Return  
  
  
  
Storm-Related Costs 36.7
 20.0
Environmental Control Projects 24.3
 13.1
Asset Retirement Obligation - Arkansas, Louisiana 6.8
 5.3
Rate Case Expense Texas
 1.4
 4.9
Other Regulatory Assets Pending Final Regulatory Approval 0.4
 
 4.2
 3.6
Total Regulatory Assets Pending Final Regulatory Approval $195.6
 $118.1
 $63.0
 $64.4


(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.


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


AEP Texas Interim Transmission and Distribution Rates


As of September 30, 2017,2019, AEP Texas’ cumulative revenues from interim basetransmission and distribution rate increases from 2008 through 2017,2019, subject to review, are estimated to be $697 million. A$1.3 billion. The 2019 base rate reviewcase described below 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.

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% return on common equity. The filing includes a proposed Income Tax Refund Rider that will refund $21 million annually of Excess ADIT that is primarily not subject to rate normalization requirements. The rate case also seeks a prudence determination on all capital additions included in interim rates from 2008.

In July and August 2019, PUCT staff and various intervenors filed testimony. The PUCT staff recommended a $63 million annual rate reduction based on a 9.35% return on common equity while intervenors recommended annual rate reductions of up to $159 million based on a return on common equity ranging from 9% to 9.2%. The difference between AEP Texas’ requested annual base rate increase and the PUCT staff’s and various intervenor’s recommendations are primarily due to: (a) recommended capital structure of 60% debt and 40% common equity as compared to the 55% debt and 45% common equity requested by AEP Texas, (b) a reduction in the requested return on common equity and (c) various disallowances that could potentially result in write-offs exceeding $450 million. The PUCT staff's recommended disallowances primarily consisted of $85 million in capital incentives and $26 million for capitalized vegetation management expenses. The intervenors recommended disallowances primarily consisted of (a) $173 million


for a newly constructed transmission operations center and other service centers, (b) $94 million for Hurricane Harvey costs, (c) $36 million for capitalized cross arms and (d) $21 million for capitalized plant costs related to unreimbursed damages to assets caused by third-parties. In addition, one intervenor recommended AEP Texas refund $115 million of Excess ADIT, which includes $2 million in interest, related to previously owned deregulated generation assets. AEP Texas recorded $113 million as a favorable adjustment to income tax expense in 2017 as a result of Tax Reform. Hearings were held in August 2019 and briefs were filed in September 2019. AEP Texas is expecting a Proposal for Decision from the ALJ in the fourth quarter of 2019. The PUCT is expected to issue an order on the case by the first quarter of 2020. If any of these costs are not recoverable or refunds of revenues collected under interim transmission and distribution rates are ordered to be returned to customers, it could reduce future net income and cash flows and impact financial condition.


Texas Storm Cost Securitization

In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. In March 2019, AEP Texas hasfiled a request to securitize total estimated distribution-related system restoration costs with the PUCT, which included estimated carrying costs. In June 2019, the PUCT approved catastrophe reserve in base rates and can defer incremental storm expenses.the financing order. As part of the financing order, AEP Texas currently recovers approximately $1agreed to offset $64 million of storm costs annually through base rates. As of September 30, 2017,Excess ADIT that is not subject to rate normalization requirements against the total balance ofdistribution-related system restoration costs. In September 2019, AEP Texas’ deferred storm costs is approximately $97 million including approximately $73


Texas issued $235 million of incremental storm expensessecuritization bonds. The securitization bonds included carrying costs of $33 million, which includes $21 million of debt carrying costs recorded as a regulatory asset relatedreduction to Hurricane Harvey. ManagementInterest Expense in 2019.

The remaining $95 million of estimated net transmission-related system restoration costs, including carrying charges, is currentlyexpected to be recovered 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. AEP2019 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.Base Rate Case described above or through interim transmission base rate increases. If the ultimatethese costs of the incident are not recovered, by insurance or through the regulatory process, it wouldcould have an adverse effect on future net income, cash flows and financial condition.


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


Virginia Legislation Affecting BiennialEarnings Reviews


InUnder a 2015 amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates arewere frozen until after the Virginia SCC rulesruled on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. Thesereview. The 2015 amendments also precludeprecluded 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

New Virginia legislation impacting investor-owned utilities was enacted, effective July 1, 2018, that requires APCo will absorbto file its Virginia jurisdictional share of incrementalnext generation and distribution costs incurred from 2014 throughbase 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 are associated with severe weather events and/70% of any earnings exceeding 70 basis points over the Virginia SCC authorized return on common equity would be refunded to customers or natural disasters andbe used to lower APCo’s Virginia retail base rates on a prospective basis. The Virginia legislation also states that, under certain circumstances, costs associated with potential asset impairments related to new carbon emission guidelines issuedearly retirement determinations made by a utility for generation facilities fueled by coal, natural gas or oil or for automated meters be considered fully recovered in the Federal EPA.period recorded.

In November 2018, the Virginia SCC approved a return on common equity of 9.42% applicable to APCo base rate earnings for the 2017-2019 triennial period and rate adjustment clauses from November 2018 through November 2020. Management has reviewed APCo’s actual and forecasted earnings for the triennial period and concluded that it is not probable, but is reasonably possible, that APCo will over-earn in Virginia during the 2017-2019 triennial period. Due to various uncertainties, including weather, storm restoration, weather-normalized demand and potential customer shopping during 2019, management cannot estimate a range of potential APCo Virginia over-earnings during the 2017-2019 triennial period. If the Virginia triennial review of APCo earnings results in any disallowance, it could reduce future net income and cash flows and impact financial condition.



Virginia Staff Depreciation Study Request

In 2016,November 2018, Virginia staff recommended that APCo implement new Virginia jurisdictional depreciation rates effective January 1, 2018 based on APCo’s depreciation study that was prepared at Virginia staff’s request using December 31, 2017 APCo property balances. Implementation of those depreciation rates would result in a $21 million pretax increase in annual depreciation expense ($6 million related to transmission) with no corresponding increase in retail base rates. In December 2018, APCo submitted a response to the Virginia staff stating that it was inappropriate for APCo to change Virginia depreciation rates in advance of the Virginia SCC’s upcoming Triennial Review of APCo, citing the Virginia SCC’s November 2014 order to not change APCo’s Virginia depreciation rates until APCo’s next base rate case/review. If the Virginia SCC were to issue an order approving the Virginia staff’s recommended retroactive change in APCo’s Virginia depreciation rates, it would reduce future net income and cash flows and impact financial condition.

Virginia Tax Reform

In March 2019, the Virginia SCC issued an order to reduce APCo’s base rates to refund: (a) $40 million annually for ongoing annual tax savings, (b) $9 million annually of Excess ADIT associated with certain depreciable property using ARAM, (c) $94 million of Excess ADIT that deniedis not subject to rate normalization requirements over three years and (d) a one-time credit of $22 million for estimated excess taxes collected from customers during the petition of certain15-month period ending March 31, 2019.

2018 West Virginia Base Rate Case

In May 2018, APCo industrial customers that requestedand WPCo filed a joint request with the issuance ofWVPSC to increase their combined West Virginia base rates by $115 million ($98 million related to APCo) annually based on a declaratory order that would find10.22% return on common equity. The proposed annual increase included $32 million ($28 million related to APCo) due to increased annual depreciation expense and reflected the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, direct APCo to make biennial review filings beginning in 2016. In July 2016, the industrial customers filed an appealimpact of the reduction in the federal income tax rate due to Tax Reform.In October 2018, APCo and WPCo filed updated schedules supporting a $95 million ($80 million related to APCo) annual increase in West Virginia base rates primarily due to the impact of West Virginia Tax Reform.

In February 2019, the WVPSC issued an order withapproving a Stipulation and Settlement agreement between APCo, WPCo, WVPSC staff and certain intervenors. The agreement included an annual base rate increase of $44 million ($36 millionrelated to APCo) based upon a 9.75% return on common equity effective March 2019. The agreement also included: (a) $18 million ($14 million related to APCo) of increased annual depreciation expense, (b) a $24 million refund ($19 million related to APCo) over two years, through a rider beginning March 2019, of Excess ADIT that is not subject to rate normalization requirements, (c) the Supreme Courtutilization of Virginia. In September 2017, the Supreme Court$14 million ($12 million related to APCo) of Virginia affirmed the Virginia SCC’s 2016 order.Excess ADIT that is not subject to rate normalization requirements to offset regulatory asset balances relating to ENEC, (d) an agreement to seek WVPSC approval of economic incentive programs to provide funds to aid in industrial and commercial development and (e) an agreement, barring any unforeseen events, to not initiate another base rate proceeding prior to April 1, 2020.


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, 2017,2019, AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $709$987 million.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 rate proceedings. The rule requires ETT to file for a comprehensive rate review no later than February 1, 2021.

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


2017Michigan Tax Reform

In October 2018, I&M made a filing with the MPSC recommending to: (a) refund approximately $68 million of Excess ADIT associated with certain depreciable property using ARAM and (b) refund approximately $37 million of Excess ADIT that is not subject to rate normalization requirements over ten years. In September 2019, an ALJ issued a Proposal for Decision and various intervenors filed objections which included changing the refund period from ten years to seven years. In October 2019, I&M filed responses to the various intervenor objections. An order from the MPSC regarding Excess ADIT is expected in the fourth quarter of 2019.

2019 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 is based upon a proposed 10.6%10.5% return on common equity with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increase would be subject to a temporary offsetting $23 million annual reduction to customer bills through December 2018 for a credit adjustment rider related to the timing of estimated in-service dates of certain capital expenditures.equity.  The proposed annual increase includes $78 million related to a proposed annual increase in depreciation expense. The requested annual increase in depreciation expense includes $52 million related to proposed investments and $26 million related to increased depreciation rates. The request includes the continuation of all existing riders and a new Automated Metering Infrastructure rider for proposed meter projects.

In August 2019, various intervenors filed testimony that recommended annual rate increases ranging from $2 million to $33 million based upon a return on common equity ranging from 9% to 9.73%. The difference between I&M’s requested annual base rate increase and the intervenor’s recommendations are primarily due to: (a) proposed denial of return on and of certain new plant investments, (b) proposed lower depreciation rates, (c) a reduction in the requested return on common equity and an $11(d) exclusion of I&M’s proposed re-allocation of capacity costs related to I&M’s June 2020 loss of a significant FERC wholesale contract. In addition, certain parties recommended disallowances that could potentially result in write-offs of $41 million increase related to the amortizationremaining book value of existing Indiana jurisdictional meters and $11 million associated with certain Cook Plant and Rockport Plant regulatory assets. The increase in depreciation rates includes a change instudy costs.

In September 2019, I&M filed testimony rebutting 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.various parties’ recommendations. A hearing at the IURC began in October 2019. The IURC is scheduled for January 2018.expected to issue an order on the case by the first quarter of 2020. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.



20172019 Michigan Base Rate Case


In May 2017,June 2019, I&M filed a request with the MPSC for a $52$58 million annual increase. The requested increase in Michigan base rates would be phased in through June 2020 and is based upon a proposed 10.6%10.5% return on common equity with the increase to be implemented no later than April 2018.equity.  The proposed annual increase includes $23$19 million related to a proposed annual increase in depreciation expense. The requested annual increase in depreciation expense includes $13 million related to proposed investments and $6 million related to increased depreciation rates. The proposed annual depreciation rates and a $4increase also includes $10 million increasefor annual lost revenue related to the amortization of certain Cook Plant regulatory assets. The increaseMichigan Electric Customer Choice Program that began 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. 2019.

In October 2017, the2019, MPSC staff and various intervenors filed testimony. The MPSC staff recommended ana $38 million annual net revenuerate increase based upon a 9.75% return on common equity while intervenors recommended annual rate increases of $49up to $28 million including proposed retirement dates of 2028 for both Rockport Plant, Units 1 (from 2044) and 2 (from 2022) andbased on a return on common equity of 9.8%. The intervenors proposed certain adjustmentsranging from 9.1% 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%9.25%. 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.

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.  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 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.

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 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)


Ohio Electric Security PlanESP 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.2024.



In August 2017, OPCo and various intervenors filed aApril 2018, the PUCO issued an order approving the ESP extension stipulation agreement, with no significant changes. In October 2018, an intervenor filed an appeal 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 previouslyOhio Supreme Court challenging various approved riders. In October 2019, oral arguments were held in the June 2015 - May 2018 ESP, (d) rate caps related to OPCo’s DIR ranging from $215 million to $290 million forOhio Supreme Court. If the periods 2018 through 2021 and (e)Ohio Supreme Court reverses 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,PUCO’s decision, it could reduce future net income and cash flows and impact financial condition.


OPCo’s Enhanced Service Reliability Rider (ESRR) authorized under the ESP is subject to annual audits.  In May 2018, the PUCO staff filed comments indicating that 2016 spending under the ESRR was subject to authorized limits and that OPCo overspent those limits.  OPCo filed reply comments objecting to the PUCO staff’s position, including the method of calculating the overspent amount.  In March 2019, the PUCO staff filed additional comments which adjusted the method of the calculation but maintained that OPCo overspent the authorized limit in 2016 and 2017, which could result in a refund of $10 million. Management believes that both 2016 and 2017 ESRR spending is not subject to an authorized limit and that a spending limit was not established until 2018, as part of the ESP extension. A hearing was held in May 2019 to address the 2016 audit. Post-hearing briefs in this case were filed in June 2019 and reply briefs were filed in July 2019. If it is determined OPCo did have an authorized spending limit under the ESRR in 2016 and 2017, and refunds are ordered, it would 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:Settlement that was filed at the PUCO in December 2016 and subsequently approved in February 2017: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings.

In May 2017, OPCo submitted its 2016 SEET filing withFebruary 2019, the PUCO in which management indicatedissued an order 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 treatment2016. As a result of the Global Settlement issues described above or adopt a different 2016 SEET threshold. Iforder, OPCo reversed the PUCO orders a refund$58 million provision in the first quarter of 2016 OPCo earnings, it could reduce future net income and cash flows and impact financial condition.2019.

PSO Rate Matters (Applies to AEP and PSO)


20172018 Oklahoma Base Rate Case


In June 2017,2018, PSO filed an application for a base rate reviewrequest with the OCC that requested a netfor an $88 million annual increase in annual revenues of $156 millionOklahoma retail rates based upon a proposed 10%10.3% return on common equity. PSO also proposed to implement a performance-based rate plan that combines a formula rate with a set of customer-focused performance incentive measures related to reliability, public safety, customer satisfaction and economic development. The proposed base rateannual 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$13 million related to Northeastern Plant, Unit 4increased annual depreciation rates and $38 million associated with capitalized incentives. Also, a party recommended a potential refund of $43$7 million related to increased storm expense amortization. The requested increase in annual depreciation rates included the recovery of Oklaunion Power Station through 2028 (currently being recovered in rates through 2046).  Management has announced plans to retire Oklaunion Power Station by October 2020.



In March 2019, the OCC issued an SPP rider claimingorder approving a Stipulation and Settlement agreement for a $46 million annual increase, based on a 9.4% return on equity effective with the first billing cycle of April 2019. The order also included agreements between the parties that: (a) depreciation rates will remain unchanged, (b) PSO will file a new base rate request no earlier than October 2020 and no later than October 2021 and (c) PSO will refund Excess ADIT that PSOis not subject to rate normalization requirements over five years instead of the ten years ordered in the Oklahoma Tax Reform case. The order did not adequately support


approve the performance-based rate plan but instead provided for an expansion of the SPP Transmission Tariff that tracks previously untracked SPP costs and a new Distribution Reliability and Safety Rider that provides additional revenues capped at $5 million per year for distribution projects related SPP costs. The combined total impact could result in a write-offto safety 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 costsreliability that are not recoverable, it could reduce future net income and cash flows and impact financial condition.normal distribution replacements.


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 August 2018, SWEPCo filed a Motion for Reconsideration at the Court of Appeals, which was denied. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court. In May 2019, various intervenors filed replies to the petition. In July 2019, SWEPCo filed its response to these replies. The Texas Supreme Court has requested full briefing by the parties. SWEPCo’s initial brief is due in October 2019. Response briefs are due in November 2019 and SWEPCo’s reply brief is due in December 2019.

As of September 30, 2019, the net book value of Turk Plant was $1.5 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. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $50 million based upon a return on common equity of 9.6%, effective May 2017. The 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. The ALJs rejected SWEPCo’s proposed transmission cost recovery mechanism. The estimated potential write-off associated with2 and $12 million related to other disallowed plant investments, (b) recognized $32 million of additional revenues, for the ALJs proposal is approximately $22 million which includes $9 millionassociated with the lackperiod of a return on Welsh Plant, Unit 2.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 $32 million of additional 2017 revenues was collected during 2018. In March 2018, the PUCT clarified and corrected portions of the final order, without changing the overall decision or amounts of the rate change. The order has been appealed by various intervenors. If anycertain parts of these coststhe PUCT 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.



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) Even 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.

20152018 Louisiana Formula Rate Filing


In April 2015,2018, SWEPCo filed its formula rate plan for test year 20142017 with the LPSC.  The filing included a $14net $28 million annual increase, which was effective August 2015.  This2018 and included SWEPCo’s Louisiana jurisdictional share 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 subjectprimarily the result of the return of Excess ADIT benefits to customers.

In October 2018, the LPSC staff reviewissued a recommendation that SWEPCo refund $11 million of excess federal income taxes collected, as a result of 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 SWEPCo 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. A decision by the LPSC on the remaining issues is subject to refund.  expected in the fourth quarter of 2019.

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$550 million, excluding AFUDC. As of September 30, 2017,2019, SWEPCo had incurred costs of $398$399 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, 2017,2019, the total net book value of Welsh Plant, Units 1 and 3 was $626$612 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 2016,2017, the LPSC approved deferralrecovery of certain expenses$131 million in investments related to theits 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$10 million, excluding $6$5 million of unrecognized equity as of September 30, 2017,2019, (b) is subject to review by the LPSC and (c) includes a WACCweighted average cost of capital 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“2018 Louisiana Formula Rate Filing” and “2019 Arkansas Base Rate Case” disclosures above.for additional information.


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



2019 Arkansas Base Rate Case

In February 2019, SWEPCo filed a request with the APSC for a $75 million increase in Arkansas base rates based upon a proposed 10.5% return on common equity. The filing requests rate base treatment for the Stall Plant and environmental retrofits that are currently being recovered through riders. Eliminating these riders would result in a net annual requested base rate increase of $58 million. The proposed net annual increase includes $12 million related to vegetation management to improve the reliability of its Arkansas distribution system. The filing also provides notice of SWEPCo’s proposal to have its rates regulated under the formula rate review mechanism authorized by Arkansas law, including a Formula Rate Review Rider. In October 2019, SWEPCo reduced its requested base rate increase from $75 million to $67 million.

In October 2019,SWEPCo, the APSC staff and various intervenors filed a unanimous stipulation and settlement agreement with the APSC.  The agreement includes a proposed annual base rate increase of $53 million ($24 million net of amounts currently recovered through riders) based upon a 9.45% return on common equity and includes $6 million for increased annual depreciation expense.  The agreement provides recovery for: (a) the Stall Plant, (b) environmental retrofit projects and (c) the remaining net book value, with a debt return for investors, of Welsh Unit 2. The agreement also includes a proposal to have its rates regulated under the formula rate mechanism authorized by Arkansas law, including a Formula Rate Review Rider. Also in October 2019, a settlement hearing with the APSC was held. SWEPCo expects the APSC to issue an order in the fourth quarter of 2019. If any of these costs are not recoverable, or disallowances were to occur, it could reduce future net income and cash flows and impact financial condition.

FERC Rate Matters


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


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

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

In October 2016, severalseven parties filed a joint complaint at the FERC that statesalleged the base return on common equity used by AEP’s eastern transmission owning subsidiaries within PJM in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint.  Management believes its financial statements adequately address the impactIn March 2018, AEP’s transmission owning subsidiaries within PJM and six of the complaint. Ifcomplainants filed a settlement agreement with the FERC orders revenue reductions as(the seventh complainant abstained).  The settlement agreement: (a) established a resultbase ROE for AEP’s transmission owning subsidiaries within PJM of 9.85% (10.35% inclusive of the complaint, including refundsRTO incentive adder of 0.5%), effective January 1, 2018, (b) required AEP’s transmission owning subsidiaries within PJM to provide a one-time refund of $50 million, attributable from the date of the complaint filing, it could reduce future netthrough December 31, 2017, which was credited to customer bills in the second quarter of 2018 and (c) increased the cap on the equity portion of the capital structure to 55% from 50%.  As part of the settlement agreement, AEP’s transmission owning subsidiaries within PJM also filed updated transmission formula rates incorporating the reduction in the corporate federal income and cash flows and impact financial condition.

Modificationstax rate due 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 from historical to projected expenses. In March 2017, the FERC accepted the proposed modificationsTax Reform, effective January 1, 2017,2018 and providing for the amortization of the portion of the Excess ADIT that is not subject to refund, and set this matter for hearing and settlement procedures. Effective January 1, 2017,rate normalization requirements over a ten-year period through credits to the modified PJM OATT formula rates were implemented, subject to refund, based on projected 2017 calendar year financial activity and projected plant balances. Iffederal income tax expense component of the revenue requirement. In May 2019, the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.approved the settlement agreement.


FERC Transmission Complaint - AEP’s SPP Participants (Applies(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 owning subsidiaries within SPP in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36%, effective upon the date of the complaint. 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)

through September 5, 2018. In September 2017, ETEC and NTEC2018, the same parties filed aanother complaint at the FERC that states the base return on common equity used by SWEPCoAEP’s transmission owning subsidiaries within SPP in calculating their power supply formula transmission rates under the SPP OATT is excessive and should be reduced from 11.1%10.7% to 8.41%8.71%, effective upon the date of the second complaint. Management believes its financial statements adequately addressIn June 2019, the impactFERC approved an unopposed settlement agreement between AEP’s transmission owning subsidiaries within SPP and the complainants. The settlement agreement established a base ROE of 10% (10.50% inclusive of the complaint. If the FERC orders revenue reductions as a resultRTO incentive adder of the complaint,0.5%) effective January 1, 2019. Additionally, refunds including refundscarrying charges will be made from the date of the first complaint filing, it could reduce future net income and cash flows and impact financial condition.

through December 31, 2018. Refunds for the period prior to 2019 will be


made at the time of the 2019 true-up of 2018 rates. Refunds from January 2019 onward will conclude with the 2020 true-up of 2019 rates.
Modifications to AEP’s SPP Transmission Rates (Applies to AEP, AEPTCo, PSO and SWEPCo)

In 2017, AEP’s transmission owning subsidiaries within SPP filed an application at the FERC to modify the SPP OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to projected expenses.  The modified SPP OATT formula rates are based on projected calendar year financial activity and projected plant balances. The FERC accepted the proposed modifications effective January 1, 2018, subject to refund. In February 2019, AEP’s transmission owning subsidiaries within SPP filed an uncontested settlement agreement with the FERC resolving all outstanding issues. In June 2019, the FERC approved the settlement agreement.


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 2018 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, AEP Texas and OPCo)


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, 2017,2019, 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, 2019 were as follows:
Company Amount Maturity
  (in millions)  
AEP $204.4
 October 2019 to October 2020
AEP Texas 2.2
 July 2020
OPCo 3.6
 April 2020 to September 2020

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.$155 million. Since SWEPCo uses self-bonding, the guarantee provides forcommits SWEPCo to commit to use its resources to complete the reclamation, in the event, Sabine does not complete the work is not completed by Sabine.work.  This guarantee ends upon depletion of reserves and completion of final reclamation.  It isThe reserves are estimated the reserves will be depletedto deplete in 2036 with final reclamation completed by 2046 at an estimated cost of $76$107 million.  Actual reclamation costs could vary due to period inflation and anyscope changes to actualthe mine reclamation.  As of September 30, 2017,2019, SWEPCo has collected $71$77 million through a rider


for final mine closure and reclamation costs, of which $76$83 million iswas recorded in Asset Retirement Obligations, offset by $5$6 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheet.sheets.


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


Guarantees of Equity Method Investees (Applies to AEP)


In December 2016, AEP issued a performance guarantee 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, 2017,2019, the maximum potential amount of future payments associated with this guarantee was $75 million, which expiresexpired in DecemberOctober 2019.


In April 2019, AEP acquired Sempra Renewables LLC. See “Acquisitions” section of Note 6 for additional information.

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, 2017,2019, 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

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.  As of September 30, 2017, the maximum potential loss by Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows:
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


Railcar LeaseENVIRONMENTAL CONTINGENCIES (Applies to AEP, I&M and SWEPCo)all Registrants except AEPTCo)

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars.  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 five 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.  I&M and SWEPCo have assumed the guarantee under the return-and-sale option.  The maximum potential losses related to the guarantee are $8 million and $10 million for I&M and SWEPCo, respectively, as of September 30, 2017, assuming the fair value of the equipment is zero at the end of the current five-year lease term.  However, management believes that the fair value would produce a sufficient sales price to avoid any loss.

AEPRO Boat and Barge Leases (Applies to AEP)

In October 2015, AEP signed a Purchase and Sale Agreement to sell 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, ensuring future payments under such leases with maturities up to 2027. As of September 30, 2017, the maximum potential amount of future payments required under the guaranteed leases was $52 million. In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee to the extent of the sale proceeds. As of September 30, 2017, AEP’s boat and barge lease guarantee liability was $7 million, of which $1 million was recorded in Other Current Liabilities and $6 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheet.

ENVIRONMENTAL CONTINGENCIES


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.

In 2008, I&M received a letter from the Michigan Department 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. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of September 30, 2017, I&M’s accrual for all of these sites is $3 million.  As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation.  Management cannot predict the amount of additional cost, if any.




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. 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, the $7.5 million payment was shared between AEGCo and I&M based on the joint ownership agreement. See “Modification of the New Source Review Litigation Consent Decree” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations 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 is unable tocannot determine a range of potential losses that are reasonably possible of occurring.


Natural Gas Markets Lawsuits (Applies to AEP)Patent Infringement Complaint


In 2002,July 2019, Midwest Energy Emissions Corporation and MES Inc. (collectively, the plaintiffs) filed a lawsuit was commenced in Los Angeles County California Superior Courtpatent infringement complaint against numerous energy companies,various parties, including AEP alleging violations of California law through alleged fraudulent reporting of false natural gas priceTexas, AGR, Cardinal Operating Company and volume information with an intent to affectSWEPCo (collectively, the market price of natural gas and electricity.  AEP was dismissed fromDefendants). The complaint alleges that 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, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill.  As a result of OPCo transferring 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 filed in Ohio. In August 2015, the court denied the motion. Defendants appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issuedinfringed two patents owned by the court denying the appealplaintiffs by using specific processes for mercury control at certain coal-fired generating stations.  The complaint seeks injunctive relief 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 under Ohio law. The WVMLP denied the motion and defendants again appealed to the West Virginia Supreme Court. The West Virginia Supreme Court granted the appeal 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.damages.  Management will continue to defend against the remaining claims and believes the provision recorded is adequate.claims. Management is unable to determine a range of potential additional lossesloss that areis reasonably possible of occurring.




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


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

IMPAIRMENTACQUISITIONS


Merchant Generating AssetsSempra Renewables LLC (Generation & Marketing Segment)


In September 2016, dueApril 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 AEP’s ongoing evaluationgrow its renewable generation portfolio and to diversify generation resources. AEP paid $583 million in cash and acquired a 50% ownership interest in five non-consolidated joint ventures with net assets valued at $406 million as of strategic alternatives for its merchant generationthe 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. The purchase price, subject to working capital adjustments, was allocated as follows:
Purchase Price Allocation of Sempra Renewables LLC at Acquisition Date - April 22nd, 2019
Assets: Liabilities and Equity: Net Purchase Price
(in millions)
Current Assets$9.7
 Current Liabilities$12.9
  
Property, Plant and Equipment238.1
 Asset Retirement Obligations5.7
  
Investment in Joint Ventures405.9
 Total Liabilities18.6
  
Other Noncurrent Assets82.9
 Noncontrolling Interest134.8
  
Total Assets$736.6
 Liabilities and Noncontrolling Interest$153.4
 $583.2


Management allocated the purchase price based upon the relative fair value of the assets declining forecastsacquired and noncontrolling interests assumed. The fair value of future energythe primary assets acquired and capacity prices, andthe noncontrolling interests assumed was determined using a decreasing likelihood of cost recovery through regulatory proceedings or legislationdiscounted cash flow method under the income approach. The key input assumptions utilized in the statedetermination of Ohio providingthe fair value of these assets were the pricing and terms of the existing purchase power agreements, forecasted market power prices, forecasted PTCs from the wind farms, expected wind farm net capacity, forecasted cash benefits from income tax depreciation and discount rates reflecting risk inherent in the future cash flows and future power prices. Additional key input assumptions for the recoveryfair value of AEP’s existing Ohio merchantthe noncontrolling interests include the terms of the limited liability company agreements that dictate the sharing of the tax attributes and cash flows associated with the tax equity partnerships. Under the accounting rules for acquisitions, AEP has one year to finalize the purchase price allocation, including working capital adjustments and other closing adjustments.

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 assets, AEP performed an impairment analysis at the unit level on the remaining merchant generation assets in accordance with accounting guidance for impairments of long-lived assets. Based on the impairment analysis performedfacilities in the third quarterUnited 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 2016, AEP recordedtheir energy production. One of the joint venture wind farms has PPAs with I&M and OPCo for a pretax impairmentportion of $2.3 billion in Asset Impairmentsits energy production which totaled $2 million and Other Related Charges on$3 million, respectively, of purchased electricity for the statementthree months ended September 30, 2019, and $5 million and $10 million, respectively, for the nine months ended September 30, 2019. Another joint venture wind farm has a PPA with SWEPCo for a portion of operations.

Through the third quarterits energy production which totaled $3 million and $6 million of 2017, AEP recorded an additional pretax impairment of $4 million in Asset Impairments and Other Related Charges 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.

DISPOSITION

Zimmer 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 immaterialpurchased electricity for the three and nine months ended September 30, 20172019, respectively. The PPAs with I&M, OPCo and 2016.SWEPCo were executed prior to the acquisition of the wind farms and will be accounted for in accordance with the accounting guidance for “Related Parties.”

Parent has issued guarantees over the performance of the joint ventures. If a joint venture were to default on payments or performance, Parent would be required to make payments on behalf of the joint venture. As of September 30, 2019, the maximum potential amount of future payments associated with these guarantees was $186 million, with the last guarantee expiring in December 2037. The liability recorded associated with these guarantees was $34 million as of September 30, 2019.


Tanners Creek Plant
The acquired business contributed revenues and Net Income to AEP that were not material for the period April 22, 2019 to September 30, 2019. The pro-forma revenue and net income related to the acquisition of Sempra Renewables LLC were not material for the three and nine months ended September 30, 2019 and 2018.

See Note 14 - Variable Interest Entities and Equity Method Investments for additional information related to the purchased wind farms.

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 accounting guidance for “Business Combinations,” management determined that the acquisition of Santa Rita East represents an asset acquisition. Additionally, and in accordance with the accounting guidance for “Consolidation,” management concluded that Santa Rita East is a VIE. As a result, to account for the initial consolidation of Santa Rita East, management applied the acquisition method by allocating the purchase price based on the relative fair value of the assets acquired and noncontrolling interest assumed.  The fair value of the primary assets acquired and the noncontrolling interest assumed was determined using the market approach.  The key input assumptions were the transaction price paid for AEP’s interest in Santa Rita East and recent third-party market transactions for similar wind farms. See “Santa Rita East” section of Note 14 for additional information.

IMPAIRMENTS

Other Assets (Corporate and Other) (Vertically Integrated Utilities Segment) (Applies to AEP and I&M)APCo)

In October 2016, I&M sold its retired Tanners Creek plant site including its associated asset retirement obligations (AROs)the first quarter of 2018, AEP was notified by an equity investee that it had ceased operations. AEP recorded a pretax impairment of $21 million in Other Operation on the statements of income related to the equity investment and related assets. The impairment also had an immaterial impact to APCo.

Merchant Generating Assets (Generation & Marketing Segment)

A project to reconstruct a defective dam structure at Racine began in the first quarter of 2017. As of September 30, 2018, the Racine reconstruction project had accumulated new capital expenditures of $35 million. Due to a nonaffiliated party.  I&M paid $92 million andsignificant increase in estimated costs to complete the nonaffiliated party took ownershipreconstruction project, in the third quarter of 2018, an impairment analysis was performed. AEP performed step one of the Tanners Creek plant site assetsimpairment analysis using undiscounted cash flows for the estimated useful life of Racine based upon energy and assumed responsibility for environmental liabilitiescapacity price curves, which were developed internally with observable Level 2 third-party quotations and AROs, including ash pond closure, asbestos abatementunobservable Level 3 inputs, as well as management’s forecasts of operating expenses and decommissioning and demolition.  I&M did not record a gain or loss related to this sale and will address recovery of Tanner’s Creek deferred costs in future rate proceedings. If anycapital expenditures. AEP performed step two of the costs associated with Tanner’s Creekimpairment analysis on Racine using a ten-year discounted cash flow model based upon similar forecasted information used in the step one test. The step two analysis resulted in a determination that the fair value of Racine in its condition as of September 30, 2018 was $0. As a result, AEP recorded a pretax impairment of $35 million in Other Operation on the statements of income in the third quarter of 2018. In October 2018, AEP received authorization from the FERC to restart generation at Racine and generation resumed in November 2018.

Due to weather-related delays in the first quarter of 2019, reconstruction activities at Racine are not recoverable, itnow estimated to be completed in the first half of 2020. AEP expects to incur additional capital expenditures to complete the reconstruction project, at which point the fair value of Racine, as fully operational, is expected to approximate the book value once complete. Future revisions in cost estimates or delays in completion could result in additional losses which could reduce future net income and cash flows and impact financial condition.


Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)
In September 2016, AEP signed a 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 to 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 payment related to the debt, payment of a coal contract associated with one of the plants and transaction fees. The sale resulted 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 third 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.

  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 Plans OPEB
Three Months Ended September 30, Three Months Ended September 30,Three Months Ended September 30, Three Months Ended September 30,
2017 2016 2017 20162019 2018 2019 2018
(in millions)(in millions)
Service Cost$24.1
 $21.4
 $2.8
 $2.6
$23.8
 $24.4
 $2.4
 $2.9
Interest Cost50.7
 52.9
 14.8
 15.3
51.1
 46.9
 12.6
 11.8
Expected Return on Plan Assets(71.1) (70.1) (25.3) (26.8)(74.0) (72.6) (23.4) (25.6)
Amortization of Prior Service Cost (Credit)0.3
 0.6
 (17.3) (17.3)
Amortization of Prior Service Credit
 
 (17.3) (17.3)
Amortization of Net Actuarial Loss20.7
 21.0
 9.2
 7.8
14.4
 21.3
 5.5
 2.7
Net Periodic Benefit Cost (Credit)$24.7
 $25.8
 $(15.8) $(18.4)$15.3
 $20.0
 $(20.2) $(25.5)
Pension Plans 
Other Postretirement
Benefit Plans
Pension Plans OPEB
Nine Months Ended September 30, Nine Months Ended September 30,Nine Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 20162019 2018 2019 2018
(in millions)(in millions)
Service Cost$72.3
 $64.3
 $8.4
 $7.7
$71.6
 $73.2
 $7.1
 $8.7
Interest Cost152.3
 158.7
 44.5
 45.7
153.3
 140.8
 37.9
 35.5
Expected Return on Plan Assets(213.5) (210.2) (76.0) (80.3)(222.0) (217.7) (70.3) (76.7)
Amortization of Prior Service Cost (Credit)0.8
 1.7
 (51.8) (51.8)
Amortization of Prior Service Credit
 
 (51.8) (51.8)
Amortization of Net Actuarial Loss62.1
 62.9
 27.5
 23.5
43.2
 63.9
 16.6
 7.9
Net Periodic Benefit Cost (Credit)$74.0
 $77.4
 $(47.4) $(55.2)$46.1
 $60.2
 $(60.5) $(76.4)





AEP Texas
 Pension Plans OPEB
 Three Months Ended September 30, Three Months Ended September 30,
 2019 2018 2019 2018
 (in millions)
Service Cost$2.2
 $2.3
 $0.1
 $0.3
Interest Cost4.4
 4.0
 1.0
 0.9
Expected Return on Plan Assets(6.5) (6.4) (1.9) (2.1)
Amortization of Prior Service Credit
 
 (1.5) (1.5)
Amortization of Net Actuarial Loss1.2
 1.8
 0.5
 0.2
Net Periodic Benefit Cost (Credit)$1.3
 $1.7
 $(1.8) $(2.2)
 Pension Plans OPEB
 Nine Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
 (in millions)
Service Cost$6.5
 $6.9
 $0.5
 $0.7
Interest Cost13.1
 12.0
 3.0
 2.8
Expected Return on Plan Assets(19.4) (19.2) (5.8) (6.4)
Amortization of Prior Service Credit
 
 (4.4) (4.4)
Amortization of Net Actuarial Loss3.7
 5.4
 1.4
 0.6
Net Periodic Benefit Cost (Credit)$3.9
 $5.1
 $(5.3) $(6.7)

APCo
 Pension Plans OPEB
 Three Months Ended September 30, Three Months Ended September 30,
 2019
2018 2019 2018
 (in millions)
Service Cost$2.4
 $2.4
 $0.2
 $0.3
Interest Cost6.3
 5.8
 2.2
 2.1
Expected Return on Plan Assets(9.4) (9.1) (3.7) (4.0)
Amortization of Prior Service Credit
 
 (2.5) (2.5)
Amortization of Net Actuarial Loss1.8
 2.6
 1.0
 0.4
Net Periodic Benefit Cost (Credit)$1.1
 $1.7
 $(2.8) $(3.7)
Pension Plans 
Other Postretirement
Benefit Plans
Pension Plans OPEB
Three Months Ended September 30, Three Months Ended September 30,Nine Months Ended September 30, Nine Months Ended September 30,
2017
2016 2017 20162019 2018 2019 2018
(in millions)(in millions)
Service Cost$2.3
 $2.1
 $0.3
 $0.2
$7.1
 $7.0
 $0.7
 $0.8
Interest Cost6.5
 6.8
 2.6
 2.7
18.9
 17.6
 6.5
 6.2
Expected Return on Plan Assets(8.9) (8.8) (4.1) (4.3)(28.1) (27.4) (11.0) (12.0)
Amortization of Prior Service Credit
 
 (2.5) (2.5)
 
 (7.5) (7.5)
Amortization of Net Actuarial Loss2.6
 2.6
 1.6
 1.4
5.3
 7.9
 2.8
 1.4
Net Periodic Benefit Cost (Credit)$2.5
 $2.7
 $(2.1) $(2.5)$3.2
 $5.1
 $(8.5) $(11.1)
 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 Plans 
Other Postretirement
Benefit Plans
Pension Plans OPEB
Three Months Ended September 30, Three Months Ended September 30,Three Months Ended September 30, Three Months Ended September 30,
2017 2016 2017 20162019 2018 2019 2018
(in millions)(in millions)
Service Cost$3.5
 $3.1
 $0.4
 $0.4
$3.3
 $3.4
 $0.3
 $0.4
Interest Cost6.1
 6.3
 1.7
 1.7
6.0
 5.6
 1.5
 1.4
Expected Return on Plan Assets(8.6) (8.4) (3.1) (3.2)(9.1) (9.0) (2.8) (3.1)
Amortization of Prior Service Credit
 
 (2.3) (2.4)
 
 (2.4) (2.4)
Amortization of Net Actuarial Loss2.4
 2.5
 1.1
 0.9
1.6
 2.5
 0.7
 0.3
Net Periodic Benefit Cost (Credit)$3.4
 $3.5
 $(2.2) $(2.6)$1.8
 $2.5
 $(2.7) $(3.4)
 Pension Plans OPEB
 Nine Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
 (in millions)
Service Cost$10.0
 $10.2
 $1.0
 $1.2
Interest Cost17.9
 16.6
 4.4
 4.1
Expected Return on Plan Assets(27.5) (26.8) (8.5) (9.3)
Amortization of Prior Service Credit
 
 (7.1) (7.1)
Amortization of Net Actuarial Loss4.9
 7.4
 2.0
 0.9
Net Periodic Benefit Cost (Credit)$5.3
 $7.4
 $(8.2) $(10.2)

 Pension Plans 
Other Postretirement
Benefit Plans
 Nine Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (in millions)
Service Cost$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 Plans 
Other Postretirement
Benefit Plans
Pension Plans OPEB
Three Months Ended September 30, Three Months Ended September 30,Three Months Ended September 30, Three Months Ended September 30,
2017 2016 2017 20162019 2018 2019 2018
(in millions)(in millions)
Service Cost$1.8
 $1.6
 $0.3
 $0.2
$1.9
 $2.0
 $0.2
 $0.2
Interest Cost4.8
 5.1
 1.6
 1.8
4.8
 4.4
 1.4
 1.3
Expected Return on Plan Assets(6.9) (6.9) (3.0) (3.3)(7.3) (7.2) (2.7) (2.9)
Amortization of Prior Service Credit
 
 (1.7) (1.7)
 
 (1.8) (1.7)
Amortization of Net Actuarial Loss2.0
 2.1
 1.1
 0.9
1.3
 2.0
 0.6
 0.3
Net Periodic Benefit Cost (Credit)$1.7
 $1.9
 $(1.7) $(2.1)$0.7
 $1.2
 $(2.3) $(2.8)
 Pension Plans OPEB
 Nine Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
 (in millions)
Service Cost$5.9
 $5.8
 $0.6
 $0.7
Interest Cost14.3
 13.3
 4.1
 3.9
Expected Return on Plan Assets(22.0) (21.6) (8.1) (8.8)
Amortization of Prior Service Credit
 
 (5.2) (5.2)
Amortization of Net Actuarial Loss4.0
 6.0
 1.9
 0.8
Net Periodic Benefit Cost (Credit)$2.2
 $3.5
 $(6.7) $(8.6)

 Pension Plans 
Other Postretirement
Benefit Plans
 Nine Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (in millions)
Service Cost$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 Plans 
Other Postretirement
Benefit Plans
Pension Plans OPEB
Three Months Ended September 30, Three Months Ended September 30,Three Months Ended September 30, Three Months Ended September 30,
2017 2016 2017 20162019 2018 2019 2018
(in millions)(in millions)
Service Cost$1.7
 $1.5
 $0.2
 $0.2
$1.6
 $1.7
 $0.2
 $0.1
Interest Cost2.6
 2.8
 0.8
 0.8
2.6
 2.5
 0.7
 0.6
Expected Return on Plan Assets(3.9) (3.9) (1.4) (1.5)(4.0) (4.0) (1.3) (1.3)
Amortization of Prior Service Cost (Credit)
 0.1
 (1.1) (1.1)
Amortization of Prior Service Credit
 
 (1.1) (1.1)
Amortization of Net Actuarial Loss1.1
 1.1
 0.5
 0.4
0.7
 1.1
 0.3
 0.1
Net Periodic Benefit Cost (Credit)$1.5
 $1.6
 $(1.0) $(1.2)$0.9
 $1.3
 $(1.2) $(1.6)
 Pension Plans OPEB
 Nine Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
 (in millions)
Service Cost$4.9
 $5.3
 $0.5
 $0.5
Interest Cost7.9
 7.4
 2.0
 1.8
Expected Return on Plan Assets(12.2) (12.1) (3.9) (4.1)
Amortization of Prior Service Credit
 
 (3.2) (3.2)
Amortization of Net Actuarial Loss2.2
 3.3
 0.9
 0.4
Net Periodic Benefit Cost (Credit)$2.8
 $3.9
 $(3.7) $(4.6)

 Pension Plans 
Other Postretirement
Benefit Plans
 Nine Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (in millions)
Service Cost$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 Plans 
Other Postretirement
Benefit Plans
Pension Plans OPEB
Three Months Ended September 30, Three Months Ended September 30,Three Months Ended September 30, Three Months Ended September 30,
2017 2016 2017 20162019 2018 2019 2018
(in millions)(in millions)
Service Cost$2.1
 $2.0
 $0.2
 $0.2
$2.1
 $2.4
 $0.2
 $0.2
Interest Cost3.1
 3.1
 0.9
 0.9
3.1
 2.8
 0.7
 0.7
Expected Return on Plan Assets(4.2) (4.0) (1.5) (1.7)(4.4) (4.4) (1.5) (1.6)
Amortization of Prior Service Credit
 
 (1.3) (1.3)
 
 (1.3) (1.3)
Amortization of Net Actuarial Loss1.3
 1.2
 0.5
 0.5
0.9
 1.3
 0.4
 0.2
Net Periodic Benefit Cost (Credit)$2.3
 $2.3
 $(1.2) $(1.4)$1.7
 $2.1
 $(1.5) $(1.8)
 Pension Plans OPEB
 Nine Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
 (in millions)
Service Cost$6.4
 $7.0
 $0.6
 $0.7
Interest Cost9.3
 8.5
 2.3
 2.1
Expected Return on Plan Assets(13.3) (13.1) (4.5) (4.8)
Amortization of Prior Service Credit
 
 (3.9) (3.9)
Amortization of Net Actuarial Loss2.6
 3.8
 1.1
 0.5
Net Periodic Benefit Cost (Credit)$5.0
 $6.2
 $(4.4) $(5.4)


 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 SSO 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.
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.



The tables below present AEP’s reportable segment income statement information for the three and nine months ended September 30, 20172019 and 20162018 and reportable segment balance sheet information as of September 30, 20172019 and December 31, 2016. These amounts include certain estimates and allocations where necessary.2018.
 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)



 Three Months Ended September 30, 2019
 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$2,598.9
 $1,147.3
 $65.5
 $501.2
 $2.1
 $
 $4,315.0
Other Operating Segments46.6
 39.3
 207.5
 32.5
 22.3
 (348.2) 
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) $
 $733.9
Nine Months Ended September 30, 2017Three Months Ended September 30, 2018
Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing
 Corporate and Other (a) Reconciling Adjustments ConsolidatedVertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing
 Corporate and Other (a) Reconciling Adjustments Consolidated
(in millions)(in millions)
Revenues from: 
  
  
  
  
    
 
  
  
  
  
    
External Customers$6,819.3
 $3,242.7
 $125.8
 $1,386.8
 $39.9
 $
 $11,614.5
$2,610.2
 $1,180.9
 $51.9
 $486.5
 $3.6
 $
 $4,333.1
Other Operating Segments73.8
 70.5
 456.1
 80.7
 46.8
 (727.9) 
26.5
 30.6
 135.3
 35.1
 20.1
 (247.6) 
Total Revenues$6,893.1
 $3,313.2
 $581.9
 $1,467.5
 $86.7
 $(727.9) $11,614.5
$2,636.7
 $1,211.5
 $187.2
 $521.6
 $23.7
 $(247.6) $4,333.1
                          
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
$345.6
 $145.2
 $74.2
 $5.1
 $9.6
 $
 $579.7
             
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
 Nine Months Ended September 30, 2019
 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$7,087.6
 $3,328.7
 $196.5
 $1,323.8
 $8.8
 $
 $11,945.4
Other Operating Segments85.0
 125.6
 611.8
 104.4
 64.9
 (991.7) 
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) $
 $1,767.1
 Nine Months Ended September 30, 2018
 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing
 Corporate and Other (a) Reconciling Adjustments Consolidated
 (in millions)
Revenues from: 
  
  
  
  
    
External Customers$7,332.4
 $3,450.0
 $196.5
 $1,399.3
 $16.4
 $
 $12,394.6
Other Operating Segments61.3
 60.9
 408.7
 88.1
 55.1
 (674.1) 
Total Revenues$7,393.7
 $3,510.9
 $605.2
 $1,487.4
 $71.5
 $(674.1) $12,394.6
              
Net Income (Loss)$856.3
 $384.6
 $280.9
 $61.8
 $(17.1) $
 $1,566.5



  September 30, 2019
  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 $46,739.8
 $19,283.9
 $9,700.4
 $1,661.6
 $421.7
 $(354.5)(b)$77,452.9
Accumulated Depreciation and Amortization 14,359.3
 3,907.3
 383.8
 99.8
 196.4
 (186.4)(b)18,760.2
Total Property Plant and Equipment - Net $32,380.5
 $15,376.6
 $9,316.6
 $1,561.8
 $225.3
 $(168.1)(b)$58,692.7
               
Total Assets $40,746.1
 $17,967.6
 $10,606.7
 $3,315.9
 $5,002.3
(c)$(3,737.9)(b) (d)$73,900.7
               
Long-term Debt Due Within One Year:              
Nonaffiliated $687.4
 $391.5
 $249.0
 $
 $(0.2)(e)$
 $1,327.7
               
Long-term Debt:              
Affiliated 59.0
 
 
 32.2
 
 (91.2) 
Nonaffiliated 12,161.1
 5,868.9
 3,426.9
 (0.3) 3,096.9
 
 24,553.5
               
Total Long-term Debt $12,907.5
 $6,260.4
 $3,675.9
 $31.9
 $3,096.7
(e)$(91.2) $25,881.2
  December 31, 2018
  Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing
 Corporate and Other (a) Reconciling
Adjustments
 Consolidated
  (in millions)
Total Property, Plant and Equipment $45,365.1
 $18,126.7
 $8,659.5
 $893.3
 $395.2
 $(354.6)(b)$73,085.2
Accumulated Depreciation and Amortization 13,822.5
 3,833.7
 282.8
 47.0
 186.6
 (186.5)(b)17,986.1
Total Property Plant and Equipment - Net $31,542.6
 $14,293.0
 $8,376.7
 $846.3
 $208.6
 $(168.1)(b)$55,099.1
               
Total Assets $38,874.3
 $17,083.4
 $9,543.7
 $1,979.7
 $4,036.5
(c)$(2,714.8)(b) (d)$68,802.8
               
Long-term Debt Due Within One Year:              
Nonaffiliated $1,066.3
 $549.1
 $85.0
 $0.1
 $(2.0)(e)$
 $1,698.5
               
Long-term Debt:              
Affiliated 50.0
 
 
 32.2
 
 (82.2) 
Nonaffiliated 11,442.7
 5,048.8
 2,888.6
 (0.3) 2,268.4
 
 21,648.2
               
Total Long-term Debt $12,559.0
 $5,597.9
 $2,973.6
 $32.0
 $2,266.4
(e)$(82.2) $23,346.7

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



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.



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, 20172019 and 20162018 and reportable segment balance sheet information as of September 30, 20172019 and December 31, 2016. These amounts include certain estimates and allocations where necessary.2018.
Three Months Ended September 30, 2017Three Months Ended September 30, 2019
State Transcos AEPTCo Parent Reconciling Adjustments 
AEPTCo
Consolidated
State Transcos AEPTCo Parent Reconciling Adjustments 
AEPTCo
Consolidated
(in millions)(in millions)
Revenues from:              
External Customers$35.9
 $
 $
 $35.9
$54.0
 $
 $
 $54.0
Sales to AEP Affiliates131.3
 
 0.1
 131.4
205.7
 
 
 205.7
Other Revenues
 
 
 
Total Revenues$167.2
 $
 $0.1
 $167.3
$259.7
 $
 $
 $259.7
              
Interest Income$
 $19.5
 $(19.3)(a)$0.2
$0.4
 $32.3
 $(31.9)(a)$0.8
Interest Expense16.9
 19.3
 (19.3)(a)16.9
26.4
 31.9
 (31.9)(a)26.4
Income Tax Expense30.2
 
 
 30.2
30.0
 0.1
 
 30.1
Equity Earnings in State Transcos
 59.8
 (59.8)(b)
              
Net Income$59.8
 $59.9
 $(59.8)(b)$59.9
$107.3
 $0.3
(b)$
 $107.6
Three Months Ended September 30, 2016Three Months Ended September 30, 2018
State Transcos AEPTCo Parent Reconciling Adjustments 
AEPTCo
Consolidated
State Transcos AEPTCo Parent Reconciling Adjustments 
AEPTCo
Consolidated
(in millions)(in millions)
Revenues from:              
External Customers$33.5
 $
 $
 $33.5
$46.0
 $
 $
 $46.0
Sales to AEP Affiliates91.8
 
 
 91.8
148.4
 
 
 148.4
Other Revenues
 
 
 
Total Revenues$125.3
 $
 $
 $125.3
$194.4
 $
 $
 $194.4
              
Interest Income$
 $14.0
 $(13.9)(a)$0.1
$0.2
 $26.0
 $(25.7)(a)$0.5
Interest Expense11.0
 13.9
 (13.9)(a)11.0
19.8
 25.7
 (25.7)(a)19.8
Income Tax Expense26.4
 
 
 26.4
18.4
 (0.8) 
 17.6
Equity Earnings in State Transcos
 52.3
 (52.3)(b)
              
Net Income$52.3
 $52.4
 $(52.3)(b)$52.4
$77.1
 $1.0
(b)$
 $78.1



Nine Months Ended September 30, 2017Nine Months Ended September 30, 2019
State Transcos AEPTCo Parent Reconciling Adjustments 
AEPTCo
Consolidated
State Transcos AEPTCo Parent Reconciling Adjustments 
AEPTCo
Consolidated
(in millions)(in millions)
Revenues from:              
External Customers$99.2
 $
 $
 $99.2
$162.1
 $
 $
 $162.1
Sales to AEP Affiliates450.2
 
 
 450.2
608.0
 
 
 608.0
Other Revenues
 
 
 
Total Revenues$549.4
 $
 $
 $549.4
$770.1
 $
 $
 $770.1
              
Interest Income$0.1
 $58.0
 $(57.6)(a)$0.5
$0.8
 $89.7
 $(88.4)(a)$2.1
Interest Expense48.6
 57.6
 (57.6)(a)48.6
69.5
 88.4
 (88.4)(a)69.5
Income Tax Expense114.3
 0.2
 
 114.5
90.5
 0.2
 
 90.7
Equity Earnings in State Transcos
 224.0
 (224.0)(b)
              
Net Income$224.0
 $224.3
 $(224.0)(b)$224.3
$347.1
 $0.8
(b)$
 $347.9
Nine Months Ended September 30, 2016Nine Months Ended September 30, 2018
State Transcos AEPTCo Parent Reconciling Adjustments 
AEPTCo
Consolidated
State Transcos AEPTCo Parent Reconciling Adjustments 
AEPTCo
Consolidated
(in millions)(in millions)
Revenues from:              
External Customers$89.6
 $
 $
 $89.6
$132.3
 $
 $
 $132.3
Sales to AEP Affiliates268.4
 
 
 268.4
453.8
 
 
 453.8
Other Revenues0.1
 
 
 0.1
Total Revenues$358.0
 $
 $
 $358.0
$586.2
 $
 $
 $586.2
              
Interest Income$
 $41.8
 $(41.6)(a)$0.2
$0.4
 $76.2
 $(75.3)(a)$1.3
Interest Expense32.3
 41.6
 (41.6)(a)32.3
60.7
 75.3
 (75.3)(a)60.7
Income Tax Expense73.9
 
 
 73.9
63.7
 
 
 63.7
Equity Earnings in State Transcos
 153.0
 (153.0)(b)
              
Net Income$153.0
 $153.0
 $(153.0)(b)$153.0
$243.6
 $0.6
(b)$
 $244.2
 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

 September 30, 2019
 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated
 (in millions)
Total Transmission Property$9,267.4
 $
 $
 $9,267.4
Accumulated Depreciation and Amortization368.8
 
 
 368.8
Total Transmission Property – Net$8,898.6
 $
 $
 $8,898.6
        
Notes Receivable - Affiliated$
 $3,511.9
 $(3,511.9)(c)$
        
Total Assets$9,363.5
 $3,589.0
(d)$(3,599.8)(e)$9,352.7
        
Total Long-term Debt$3,550.0
 $3,511.9
 $(3,550.0)(c)$3,511.9
 December 31, 2018
 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated
 (in millions)
Total Transmission Property$8,268.1
 $
 $
 $8,268.1
Accumulated Depreciation and Amortization271.9
 
 
 271.9
Total Transmission Property – Net$7,996.2
 $
 $
 $7,996.2
        
Notes Receivable - Affiliated$
 $2,823.0
 $(2,823.0)(c)$
        
Total Assets$8,406.8
 $2,857.1
(d)$(2,869.8)(e)$8,394.1
        
Total Long-term Debt$2,850.0
 $2,823.0
 $(2,850.0)(c)$2,823.0

(a)Elimination of intercompany interest income/interest expense on affiliated debt arrangement.
(b)EliminationIncludes 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 AEPTCo Parent’s investment in the State Transcos and NoteNotes 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, LLC 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.





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


Notional Volume of Derivative Instruments
September 30, 20172019
Primary Risk
Exposure
 
Unit of
Measure
 AEP APCo I&M OPCo PSO SWEPCo 
Unit of
Measure
 AEP AEP Texas APCo I&M OPCo PSO SWEPCo
 (in millions) (in millions)
Commodity:        
  
  
  
          
  
  
  
Power MWhs 406.0
 73.7
 45.8
 10.6
 13.7
 34.5
 MWhs 424.3
 
 94.7
 37.1
 7.3
 21.6
 6.9
Coal Tons 0.5
 
 0.2
 
 
 0.3
Natural Gas MMBtus 48.1
 2.0
 1.2
 
 
 18.3
 MMBtus 53.2
 
 
 
 
 
 12.5
Heating Oil and Gasoline Gallons 7.9
 1.5
 0.7
 1.8
 0.8
 0.9
 Gallons 8.4
 1.8
 1.6
 0.8
 2.0
 0.8
 0.9
Interest Rate USD $53.2
 $
 $
 $
 $
 $
 USD $140.1
 $
 $
 $
 $
 $
 $
                          
Interest Rate USD $1,000.0
 $
 $
 $
 $
 $
 USD $600.0
 $
 $
 $
 $
 $
 $


Notional Volume of Derivative Instruments
December 31, 20162018
Primary Risk
Exposure
 
Unit of
Measure
 AEP AEP Texas APCo I&M OPCo PSO SWEPCo
    (in millions)
Commodity:          
  
  
  
Power MWhs 371.1
 
 66.4
 40.9
 7.8
 15.2
 4.5
Natural Gas MMBtus 87.9
 
 4.0
 2.3
 
 
 15.2
Heating Oil and Gasoline Gallons 7.4
 1.5
 1.4
 0.7
 1.8
 0.7
 0.8
Interest Rate USD $37.7
 $
 $
 $
 $
 $
 $
                 
Interest Rate USD $500.0
 $
 $
 $
 $
 $
 $

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.

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 million and $18 million as of September 30, 2019 and December 31, 2018, respectively. AEP netted cash collateral paid to third-parties against short-term and long-term risk management liabilities in the amounts of $21 million and $4 million as of September 30, 2019 and December 31, 2018, 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 other Registrants as follows:
  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
 
of September 30, 2019 and December 31, 2018.



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, 20172019
 
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)
 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)  Commodity (a) Commodity (a) Interest Rate (a) 
 (in millions) (in millions)
Current Risk Management Assets $277.4
 $8.1
 $4.2
 $289.7
 $(143.6) $146.1
 $337.0
 $16.5
 $1.9
 $355.4
 $(168.7) $186.7
Long-term Risk Management Assets 348.1
 3.8
 
 351.9
 (41.5) 310.4
 319.0
 10.0
 25.3
 354.3
 (55.3) 299.0
Total Assets 625.5
 11.9
 4.2
 641.6
 (185.1) 456.5
 656.0
 26.5
 27.2
 709.7
 (224.0) 485.7
                        
Current Risk Management Liabilities 202.2
 13.5
 1.4
 217.1
 (147.7) 69.4
 213.4
 36.4
 0.2
 250.0
 (174.7) 75.3
Long-term Risk Management Liabilities 329.6
 74.0
 
 403.6
 (50.9) 352.7
 281.7
 87.4
 
 369.1
 (70.5) 298.6
Total Liabilities 531.8
 87.5
 1.4
 620.7
 (198.6) 422.1
 495.1
 123.8
 0.2
 619.1
 (245.2) 373.9
                        
Total MTM Derivative Contract Net Assets (Liabilities) $93.7
 $(75.6) $2.8
 $20.9
 $13.5
 $34.4
 $160.9
 $(97.3) $27.0
 $90.6
 $21.2
 $111.8
            
            
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

December 31, 2018
  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 $397.5
 $28.5
 $
 $426.0
 $(263.2) $162.8
Long-term Risk Management Assets 276.4
 16.0
 
 292.4
 (38.4) 254.0
Total Assets 673.9
 44.5
 
 718.4
 (301.6) 416.8
             
Current Risk Management Liabilities 293.8
 13.2
 2.0
 309.0
 (254.0) 55.0
Long-term Risk Management Liabilities 225.7
 56.1
 15.4
 297.2
 (33.8) 263.4
Total Liabilities 519.5
 69.3
 17.4
 606.2
 (287.8) 318.4
             
Total MTM Derivative Contract Net Assets (Liabilities) $154.4
 $(24.8) $(17.4) $112.2
 $(13.8) $98.4






AEP Texas
Fair Value of Derivative Instruments
September 30, 2019
  Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
  Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c)
  (in millions)
Current Risk Management Assets $
 $
 $
Long-term Risk Management Assets 
 
 
Total Assets 
 
 
       
Current Risk Management Liabilities 0.4
 (0.1) 0.3
Long-term Risk Management Liabilities 
 0.1
 0.1
Total Liabilities 0.4
 
 0.4
       
Total MTM Derivative Contract Net Liabilities $(0.4) $
 $(0.4)

December 31, 2018
  Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
  Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c)
  (in millions)
Current Risk Management Assets $
 $
 $
Long-term Risk Management Assets 
 
 
Total Assets 
 
 
       
Current Risk Management Liabilities 0.7
 (0.5) 0.2
Long-term Risk Management Liabilities 
 
 
Total Liabilities 0.7
 (0.5) 0.2
       
Total MTM Derivative Contract Net Assets (Liabilities) $(0.7) $0.5
 $(0.2)

APCo
Fair Value of Derivative Instruments
September 30, 20172019
 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
 Contracts - in the Statement of Presented in the Statement Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) Commodity (a) Financial Position (b) Financial Position (c)
 (in millions) (in millions)
Current Risk Management Assets $50.4
 $(20.1) $30.3
 $86.3
 $(29.8) $56.5
Long-term Risk Management Assets 4.9
 (4.3) 0.6
 4.1
 (3.9) 0.2
Total Assets 55.3
 (24.4) 30.9
 90.4
 (33.7) 56.7
            
Current Risk Management Liabilities 20.7
 (19.8) 0.9
 32.3
 (31.2) 1.1
Long-term Risk Management Liabilities 4.8
 (4.5) 0.3
 4.4
 (4.1) 0.3
Total Liabilities 25.5
 (24.3) 1.2
 36.7
 (35.3) 1.4
            
Total MTM Derivative Contract Net Assets (Liabilities) $29.8
 $(0.1) $29.7
Total MTM Derivative Contract Net Assets $53.7
 $1.6
 $55.3

Fair Value of Derivative Instruments
December 31, 20162018
  Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
  Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c)
  (in millions)
Current Risk Management Assets $114.4
 $(57.2) $57.2
Long-term Risk Management Assets 3.1
 (2.2) 0.9
Total Assets 117.5
 (59.4) 58.1
       
Current Risk Management Liabilities 56.7
 (56.3) 0.4
Long-term Risk Management Liabilities 2.4
 (2.2) 0.2
Total Liabilities 59.1
 (58.5) 0.6
       
Total MTM Derivative Contract Net Assets (Liabilities) $58.4
 $(0.9) $57.5
  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, 20172019
 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
 Contracts - in the Statement of Presented in the Statement Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) Commodity (a) Financial Position (b) Financial Position (c)
 (in millions) (in millions)
Current Risk Management Assets $27.4
 $(15.8) $11.6
 $30.5
 $(20.0) $10.5
Long-term Risk Management Assets 3.3
 (2.8) 0.5
 2.7
 (2.6) 0.1
Total Assets 30.7
 (18.6) 12.1
 33.2
 (22.6) 10.6
            
Current Risk Management Liabilities 17.6
 (15.6) 2.0
 21.0
 (20.8) 0.2
Long-term Risk Management Liabilities 3.0
 (2.8) 0.2
 2.7
 (2.7) 
Total Liabilities 20.6
 (18.4) 2.2
 23.7
 (23.5) 0.2
            
Total MTM Derivative Contract Net Assets (Liabilities) $10.1
 $(0.2) $9.9
Total MTM Derivative Contract Net Assets $9.5
 $0.9
 $10.4

Fair Value of Derivative Instruments
December 31, 20162018
 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
 Contracts - in the Statement of Presented in the Statement Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) Commodity (a) Financial Position (b) Financial Position (c)
 (in millions) (in millions)
Current Risk Management Assets $14.9
 $(11.4) $3.5
 $50.4
 $(41.8) $8.6
Long-term Risk Management Assets 1.1
 (1.1) 
 2.0
 (1.4) 0.6
Total Assets 16.0
 (12.5) 3.5
 52.4
 (43.2) 9.2
            
Current Risk Management Liabilities 11.8
 (11.5) 0.3
 41.1
 (40.8) 0.3
Long-term Risk Management Liabilities 1.9
 (1.1) 0.8
 1.6
 (1.5) 0.1
Total Liabilities 13.7
 (12.6) 1.1
 42.7
 (42.3) 0.4
            
Total MTM Derivative Contract Net Assets $2.3
 $0.1
 $2.4
Total MTM Derivative Contract Net Assets (Liabilities) $9.7
 $(0.9) $8.8




OPCo
Fair Value of Derivative Instruments
September 30, 20172019
 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
 Contracts - in the Statement of Presented in the Statement Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) Commodity (a) Financial Position (b) Financial Position (c)
 (in millions) (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
 7.2
 
 7.2
Long-term Risk Management Liabilities 130.9
 
 130.9
 105.7
 
 105.7
Total Liabilities 138.5
 
 138.5
 112.9
 
 112.9
            
Total MTM Derivative Contract Net Liabilities $(138.2) $(0.1) $(138.3) $(112.9) $
 $(112.9)

Fair Value of Derivative Instruments
December 31, 20162018
  Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
  Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c)
  (in millions)
Current Risk Management Assets $
 $
 $
Long-term Risk Management Assets 
 
 
Total Assets 
 
 
       
Current Risk Management Liabilities 6.4
 (0.6) 5.8
Long-term Risk Management Liabilities 93.8
 
 93.8
Total Liabilities 100.2
 (0.6) 99.6
       
Total MTM Derivative Contract Net Assets (Liabilities) $(100.2) $0.6
 $(99.6)
  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, 20172019
 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
 Contracts - in the Statement of Presented in the Statement Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) Commodity (a) Financial Position (b) Financial Position (c)
 (in millions) (in millions)
Current Risk Management Assets $4.7
 $
 $4.7
 $21.9
 $(0.2) $21.7
Long-term Risk Management Assets 
 
 
 
 
 
Total Assets 4.7
 
 4.7
 21.9
 (0.2) 21.7
            
Current Risk Management Liabilities 
 
 
 0.5
 (0.2) 0.3
Long-term Risk Management Liabilities 
 
 
 
 
 
Total Liabilities 
 
 
 0.5
 (0.2) 0.3
            
Total MTM Derivative Contract Net Assets $4.7
 $
 $4.7
 $21.4
 $
 $21.4

Fair Value of Derivative Instruments
December 31, 20162018
 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
 Contracts - in the Statement of Presented in the Statement Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) Commodity (a) Financial Position (b) Financial Position (c)
 (in millions) (in millions)
Current Risk Management Assets $0.9
 $(0.1) $0.8
 $10.9
 $(0.5) $10.4
Long-term Risk Management Assets 
 
 
 
 
 
Total Assets 0.9
 (0.1) 0.8
 10.9
 (0.5) 10.4
            
Current Risk Management Liabilities 
 
 
 1.7
 (0.7) 1.0
Long-term Risk Management Liabilities 
 
 
 
 
 
Total Liabilities 
 
 
 1.7
 (0.7) 1.0
            
Total MTM Derivative Contract Net Assets (Liabilities) $0.9
 $(0.1) $0.8
Total MTM Derivative Contract Net Assets $9.2
 $0.2
 $9.4




SWEPCo
Fair Value of Derivative Instruments
September 30, 20172019
 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
 Contracts - in the Statement of Presented in the Statement Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) Commodity (a) Financial Position (b) Financial Position (c)
 (in millions) (in millions)
Current Risk Management Assets $12.7
 $(0.2) $12.5
 $9.8
 $(0.4) $9.4
Long-term Risk Management Assets 0.7
 
 0.7
 
 
 
Total Assets 13.4
 (0.2) 13.2
 9.8
 (0.4) 9.4
            
Current Risk Management Liabilities 0.3
 (0.2) 0.1
 2.1
 (0.4) 1.7
Long-term Risk Management Liabilities 
 
 
 3.0
 
 3.0
Total Liabilities 0.3
 (0.2) 0.1
 5.1
 (0.4) 4.7
            
Total MTM Derivative Contract Net Assets $13.1
 $
 $13.1
 $4.7
 $
 $4.7

Fair Value of Derivative Instruments
December 31, 20162018
 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
 Contracts - in the Statement of Presented in the Statement Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) Commodity (a) Financial Position (b) Financial Position (c)
 (in millions) (in millions)
Current Risk Management Assets $1.1
 $(0.2) $0.9
 $5.6
 $(0.8) $4.8
Long-term Risk Management Assets 
 
 
 
 
 
Total Assets 1.1
 (0.2) 0.9
 5.6
 (0.8) 4.8
            
Current Risk Management Liabilities 0.4
 (0.1) 0.3
 1.5
 (1.1) 0.4
Long-term Risk Management Liabilities 
 
 
 2.2
 
 2.2
Total Liabilities 0.4
 (0.1) 0.3
 3.7
 (1.1) 2.6
            
Total MTM Derivative Contract Net Assets (Liabilities) $0.7
 $(0.1) $0.6
Total MTM Derivative Contract Net Assets $1.9
 $0.3
 $2.2


(a)Derivative instruments within these categories are reported gross.  These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.”
(b)Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”
(c)There are noAll 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, 20172019
Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo AEP AEP Texas APCo I&M OPCo PSO SWEPCo
 (in millions) (in millions)
Vertically Integrated Utilities Revenues $0.9
 $
 $
 $
 $
 $
 $0.5
 $
 $
 $
 $
 $
 $
Generation & Marketing Revenues 17.7
 
 
 
 
 
 21.0
 
 
 
 
 
 
Electric Generation, Transmission and Distribution Revenues 
 0.3
 0.6
 
 
 (0.1) 
 
 0.2
 0.2
 
 
��
Purchased Electricity for Resale 1.0
 0.3
 0.2
 
 
 
 0.4
 
 0.3
 
 
 
 
Other Operation 0.1
 
 
 0.1
 
 
 (0.1) 
 (0.1) (0.1) (0.1) (0.1) 
Maintenance 0.1
 0.1
 
 0.1
 
 
 (0.2) 
 
 (0.1) 
 
 
Regulatory Assets (a) (8.8) 0.1
 (0.8) (8.7) 
 0.3
 (4.8) (0.2) 0.2
 
 (2.6) (0.1) (1.6)
Regulatory Liabilities (a) 15.6
 3.7
 2.1
 
 2.6
 7.0
 26.3
 
 10.0
 3.2
 
 4.3
 4.5
Total Gain (Loss) on Risk Management Contracts $26.6
 $4.5
 $2.1
 $(8.5) $2.6
 $7.2
 $43.1
 $(0.2) $10.6
 $3.2
 $(2.7) $4.1
 $2.9


Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended September 30, 20162018
Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo AEP AEP Texas APCo I&M OPCo PSO SWEPCo
 (in millions) (in millions)
Vertically Integrated Utilities Revenues $2.4
 $
 $
 $
 $
 $
 $(0.7) $
 $
 $
 $
 $
 $
Transmission and Distribution Utilities Revenues 0.1
 
 
 
 
 
Generation & Marketing Revenues 9.2
 
 
 
 
 
 19.3
 
 
 
 
 
 
Electric Generation, Transmission and Distribution Revenues 
 1.0
 1.2
 0.1
 
 (0.1) 
 
 (0.5) (0.1) 
 
 
Purchased Electricity for Resale 1.5
 0.8
 0.1
 
 
 
 0.3
 
 0.3
 
 
 
 
Other Operation (0.4) 
 
 (0.1) 
 
 0.5
 0.1
 0.1
 0.1
 0.1
 0.1
 0.1
Maintenance (0.4) (0.1) 
 (0.1) (0.1) (0.1) 0.6
 0.1
 0.1
 0.1
 0.1
 0.1
 0.1
Regulatory Assets (a) (22.5) 5.2
 1.6
 (95.4) 0.1
 2.8
 (14.0) 
 
 (3.5) (9.3) (0.6) (0.6)
Regulatory Liabilities (a) 28.6
 16.9
 5.5
 
 0.8
 3.7
 33.8
 
 24.0
 
 
 3.9
 1.5
Total Gain (Loss) on Risk Management Contracts $18.5
 $23.8
 $8.4
 $(95.5) $0.8
 $6.3
 $39.8
 $0.2
 $24.0
 $(3.4) $(9.1) $3.5
 $1.1





Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Nine Months Ended September 30, 20172019
Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo AEP AEP Texas APCo I&M OPCo PSO SWEPCo
 (in millions) (in millions)
Vertically Integrated Utilities Revenues $7.0
 $
 $
 $
 $
 $
 $1.0
 $
 $
 $
 $
 $
 $
Generation & Marketing Revenues 38.5
 
 
 
 
 
 27.2
 
 
 
 
 
 
Electric Generation, Transmission and Distribution Revenues 
 0.6
 6.3
 
 
 
 
 
 0.2
 0.5
 
 
 0.1
Purchased Electricity for Resale 4.9
 1.6
 0.5
 
 
 
 1.6
 
 1.4
 0.1
 
 
 
Other Operation 0.5
 
 
 0.1
 
 
 (0.6) (0.1) (0.1) (0.1) (0.2) (0.1) (0.1)
Maintenance 0.4
 0.1
 
 0.1
 
 
 (0.6) (0.1) (0.1) (0.1) (0.1) 
 (0.1)
Regulatory Assets (a) (26.8) 
 (1.0) (25.9) 
 0.1
 (19.4) 0.3
 0.4
 0.2
 (19.8) 0.9
 (0.4)
Regulatory Liabilities (a) 81.8
 28.2
 15.3
 
 13.7
 22.0
 64.5
 
 (5.3) 17.2
 
 26.6
 22.9
Total Gain (Loss) on Risk Management Contracts $106.3
 $30.5
 $21.1
 $(25.7) $13.7
 $22.1
 $73.7
 $0.1
 $(3.5) $17.8
 $(20.1) $27.4
 $22.4


Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Nine Months Ended September 30, 20162018
Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo
  (in millions)
Vertically Integrated Utilities Revenues $(9.4) $
 $
 $
 $
 $
 $
Generation & Marketing Revenues 31.7
 
 
 
 
 
 
Electric Generation, Transmission and Distribution Revenues 
 
 (1.3) (7.8) 
 
 0.1
Purchased Electricity for Resale 8.3
 
 7.3
 0.8
 
 
 
Other Operation 1.3
 0.3
 0.2
 0.2
 0.3
 0.2
 0.2
Maintenance 1.5
 0.3
 0.3
 0.2
 0.3
 0.2
 0.2
Regulatory Assets (a) 29.2
 
 
 (0.3) 31.8
 (0.6) (1.7)
Regulatory Liabilities (a) 206.2
 
 127.3
 11.7
 0.6
 34.8
 7.6
Total Gain on Risk Management Contracts $268.8
 $0.6
 $133.8
 $4.8
 $33.0
 $34.6
 $6.4

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.


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.

The following table shows the results ofimpacts recognized on the balance sheets related to the hedged items in fair value hedging gains (losses):relationships:
 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)
  Carrying Amount of the Hedged
Assets/(Liabilities)
 Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Assets/(Liabilities)
  September 30, 2019 December 31, 2018 September 30, 2019 December 31, 2018
  (in millions)
Long-term Debt (a) $(521.2) $(478.3) $(25.1) $17.4


(a)Amounts included on the balance sheets within Long-term Debt Due within One Year and Long-term Debt, respectively.

During the three and nine months ended September 30, 2017 and 2016,The pretax effects of fair value hedge ineffectiveness was immaterial.accounting on income were as follows:

 Three Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
 (in millions)
Gain (Loss) on Interest Rate Contracts:       
Gain (Loss) on Fair Value Hedging Instruments (a)$13.2
 $(6.3) $42.5
 $(28.1)
Gain (Loss) on Fair Value Portion of Long-term Debt (a)(13.2) 6.3
 (42.5) 28.1


(a)Gain (Loss) is included 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, 20172019 and 2016,2018, AEP applied cash flow hedging to outstanding power derivatives. During the three and nine months ended September 30, 20172019 and 2016,2018, 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, 2017 and 2016,2019 AEP applied cash flow hedging to outstanding interest rate derivatives.derivatives and the other Registrant Subsidiaries did not. During the three and nine months ended September 30, 20172018 AEP and 2016, the Registrant Subsidiaries did not applySWEPCo applied cash flow hedging to outstanding interest rate derivatives.derivatives and the other Registrant Subsidiaries did not.

The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and nine months ended September 30, 2017 and 2016, the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives.

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, 2019 December 31, 2018
  Commodity Interest Rate Commodity Interest Rate
  (in millions)
AOCI Gain (Loss) Net of Tax $(82.2) $(16.7)(a)$(23.0) $(12.6)
Portion Expected to be Reclassed to Net Income During the Next Twelve Months (24.2) (3.7) 10.4
 (1.1)

  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 includedIncludes $6 million related to AEP's investment in Risk Management Assets and Liabilities onjoint venture wind farms acquired as part of the balance sheets.purchase of Sempra Renewables LLC. See “Sempra Renewables LLC” section of Note 14 for additional information.


As of September 30, 20172019 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 123 months.months and 135 months for commodity and interest rate hedges, respectively.


Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets
  September 30, 2019 December 31, 2018
  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)
AEP Texas $(3.6) $(1.1) $(4.4) $(1.1)
APCo 1.1
 0.9
 1.8
 0.9
I&M (10.3) (1.6) (11.5) (1.6)
OPCo 
 
 1.0
 1.0
PSO 1.4
 1.0
 2.1
 1.0
SWEPCo (2.2) (1.5) (3.3) (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.





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, 20172019 and December 31, 2016.2018, 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, 2017 September 30, 2019
 Liabilities for   Additional Liabilities for   Additional
 Contracts with Cross   Settlement Contracts with Cross   Settlement
 Default Provisions   Liability if Cross Default Provisions   Liability if Cross
 Prior to Contractual Amount of Cash Default Provision Prior to Contractual Amount of Cash Default Provision
Company Netting Arrangements Collateral Posted is Triggered Netting Arrangements Collateral Posted is Triggered
 (in millions) (in millions)
AEP $285.9
 $2.5
 $274.4
 $261.0
 $3.4
 $230.7
APCo 
 
 
 3.9
 
 0.2
I&M 
 
 
 2.3
 
 0.1
SWEPCo 4.7
 
 2.8
  December 31, 2018
  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 $225.5
 $1.8
 $181.0
APCo 0.9
 
 
I&M 0.5
 
 
SWEPCo 2.3
 
 2.3


  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.



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, 2019 December 31, 2018
Company Book Value Fair Value Book Value Fair Value
  (in millions)
AEP (a) $25,881.2
 $29,729.1
 $23,346.7
 $24,093.9
AEP Texas 4,146.5
 4,631.5
 3,881.3
 3,964.6
AEPTCo 3,511.9
 3,984.9
 2,823.0
 2,782.4
APCo 4,362.9
 5,370.2
 4,062.6
 4,473.3
I&M 3,031.5
 3,497.3
 3,035.4
 3,070.2
OPCo 2,113.9
 2,618.5
 1,716.6
 1,919.7
PSO 1,386.4
 1,632.9
 1,287.0
 1,361.9
SWEPCo 2,656.9
 2,983.0
 2,713.4
 2,670.2

  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)Amounts includeThe fair value amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheetAEP’s Equity Units issued in March 2019 and has a fair value of $172 million.$887 million as of September 30, 2019. See the Assets and Liabilities Held for Sale“Equity Units” section of Note 613 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, 2017 September 30, 2019
   Gross Gross     Gross Gross  
   Unrealized Unrealized Fair   Unrealized Unrealized Fair
Other Temporary Investments Cost Gains Losses Value Cost Gains Losses Value
 (in millions) (in millions)
Restricted Cash (a) $172.9
 $
 $
 $172.9
Restricted Cash and Other Cash Deposits (a) $160.1
 $
 $
 $160.1
Fixed Income Securities – Mutual Funds (b) 103.9
 
 (0.7) 103.2
 133.4
 
 (0.2) 133.2
Equity Securities Mutual Funds
 16.8
 17.8
 
 34.6
 28.5
 17.6
 
 46.1
Total Other Temporary Investments $293.6
 $17.8
 $(0.7) $310.7
 $322.0
 $17.6
 $(0.2) $339.4
 December 31, 2016 December 31, 2018
   Gross Gross     Gross Gross  
   Unrealized Unrealized Fair   Unrealized Unrealized Fair
Other Temporary Investments Cost Gains Losses Value Cost Gains Losses Value
 (in millions) (in millions)
Restricted Cash (a) $211.7
 $
 $
 $211.7
Restricted Cash and Other Cash Deposits (a) $230.6
 $
 $
 $230.6
Fixed Income Securities Mutual Funds (b)
 92.7
 
 (1.0) 91.7
 106.6
 
 (2.3) 104.3
Equity Securities Mutual Funds
 14.4
 13.9
 
 28.3
 17.8
 16.4
 
 34.2
Total Other Temporary Investments $318.8
 $13.9
 $(1.0) $331.7
 $355.0
 $16.4
 $(2.3) $369.1


(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,
 2019 2018 2019 2018
 (in millions)
Proceeds from Investment Sales$2.8
 $
 $2.8
 $
Purchases of Investments26.9
 0.8
 35.8
 2.2
Gross Realized Gains on Investment Sales
 
 
 
Gross Realized Losses on Investment Sales
 
 
 

 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 2016,2018, see Note 3.3 - Comprehensive Income.


Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M)


Nuclear decommissioning and spent nuclear fuelSNF trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuelSNF disposal liabilities.  By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines.  In general, limitations include:


Acceptable investments (rated investment grade or above when purchased).
Maximum percentage invested in a specific type of investment.
Prohibition of investment in obligations of AEP, I&M or their affiliates.
Withdrawals permitted only for payment of decommissioning costs and trust expenses.


I&M maintains trust funds for each regulatory jurisdiction.  Regulatory approval is required to withdraw decommissioning funds. These funds are managed by 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. With the adoption of ASU 2016-01, effective January 2018, available-for-sale classification only applies to investment in debt securities. Additionally, the adoption of ASU 2016-01 required 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.



The following is a summary of nuclear trust fund investments:
 September 30, 2019 December 31, 2018
   Gross Other-Than-   Gross Other-Than-
 Fair Unrealized Temporary Fair Unrealized Temporary
 Value Gains Impairments Value Gains Impairments
 (in millions)
Cash and Cash Equivalents$17.4
 $
 $
 $22.5
 $
 $
Fixed Income Securities:           
United States Government1,047.4
 67.8
 (5.8) 996.1
 26.7
 (7.1)
Corporate Debt68.6
 6.1
 (1.7) 52.4
 1.1
 (1.9)
State and Local Government7.5
 0.7
 (0.2) 8.6
 0.6
 (0.2)
Subtotal Fixed Income Securities1,123.5
 74.6
 (7.7) 1,057.1
 28.4
 (9.2)
Equity Securities - Domestic (a)1,694.3
 1,037.7
 
 1,395.3
 766.3
 
Spent Nuclear Fuel and Decommissioning Trusts$2,835.2
 $1,112.3
 $(7.7) $2,474.9
 $794.7
 $(9.2)

 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 billion and $784 million and unrealized losses of $9 million and $18 million as of September 30, 2019 and December 31, 2018, respectively. AEP adopted ASU 2016-01 during the first quarter of 2018 by means of a modified retrospective approach. Due to the adoption of the ASU, Other-Than-Temporary Impairments are no longer applicable to Equity Securities with readily determinable fair values.



The following table provides the securities activity within the decommissioning and SNF trusts:
  Three Months Ended September 30, Nine Months Ended September 30,
  2019 2018 2019 2018
  (in millions)
Proceeds from Investment Sales $671.9
 $513.1
 $871.4
 $1,550.9
Purchases of Investments 689.1
 521.2
 915.7
 1,589.0
Gross Realized Gains on Investment Sales 10.9
 3.9
 26.6
 27.7
Gross Realized Losses on Investment Sales 7.1
 3.5
 15.1
 22.2

  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 billion and $938 million$1 billion as of September 30, 20172019 and December 31, 2016,2018, respectively.  The base cost of equity securities was $586$657 million and $592$629 million as of September 30, 20172019 and December 31, 2016,2018, respectively.


The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 20172019 was as follows:
 Fair Value of Fixed
 Income Securities
 (in millions)
Within 1 year$334.9
After 1 year through 5 years390.9
After 5 years through 10 years199.2
After 10 years198.5
Total$1,123.5
 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, 20172019
 Level 1 Level 2 Level 3 Other Total Level 1 Level 2 Level 3 Other Total
Assets: (in millions) (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
Restricted Cash and Other Cash Deposits (a) $152.9
 $
 $
 $7.2
 $160.1
Fixed Income Securities Mutual Funds
 103.2
 
 
 
 103.2
 133.2
 
 
 
 133.2
Equity Securities Mutual Funds (b)
 34.6
 
 
 
 34.6
 46.1
 
 
 
 46.1
Total Other Temporary Investments
 296.4
 1.4
 
 12.9
 310.7
 332.2
 
 
 7.2
 339.4
                    
Risk Management Assets  
  
  
  
  
          
Risk Management Commodity Contracts (c) (d) 1.2
 307.9
 300.3
 (161.4) 448.0
 5.6
 228.2
 407.7
 (195.3) 446.2
Cash Flow Hedges:  
  
  
  
  
          
Commodity Hedges (c) 
 9.1
 1.3
 (6.1) 4.3
 
 17.6
 2.9
 (8.2) 12.3
Interest Rate/Foreign Currency Hedges 
 4.2
 
 
 4.2
Interest Rate Hedges 
 1.9
 
 
 1.9
Fair Value Hedges 
 25.3
 
 
 25.3
Total Risk Management Assets 1.2
 321.2
 301.6
 (167.5) 456.5
 5.6
 273.0
 410.6
 (203.5) 485.7
                    
Spent Nuclear Fuel and Decommissioning Trusts  
  
  
  
  
          
Cash and Cash Equivalents (e) 14.0
 
 
 6.5
 20.5
 9.4
 
 
 8.0
 17.4
Fixed Income Securities:  
  
  
  
  
          
United States Government 
 974.3
 
 
 974.3
 
 1,047.4
 
 
 1,047.4
Corporate Debt 
 60.0
 
 
 60.0
 
 68.6
 
 
 68.6
State and Local Government 
 9.0
 
 
 9.0
 
 7.5
 
 
 7.5
Subtotal Fixed Income Securities 
 1,043.3
 
 
 1,043.3
 
 1,123.5
 
 
 1,123.5
Equity Securities Domestic (b)
 1,369.2
 
 
 
 1,369.2
 1,694.3
 
 
 
 1,694.3
Total Spent Nuclear Fuel and Decommissioning Trusts
 1,383.2
 1,043.3
 
 6.5
 2,433.0
 1,703.7
 1,123.5
 
 8.0
 2,835.2
                    
Total Assets $1,680.8
 $1,365.9
 $301.6
 $195.8
 $3,544.1
 $2,041.5
 $1,396.5
 $410.6
 $(188.3) $3,660.3
                    
Liabilities:  
  
  
  
  
          
                    
Risk Management Liabilities  
  
  
  
  
          
Risk Management Commodity Contracts (c) (d) $3.2
 $306.6
 $205.9
 $(174.9) $340.8
 $5.1
 $243.9
 $231.6
 $(216.5) $264.1
Cash Flow Hedges:  
  
  
  
  
          
Commodity Hedges (c) 
 35.3
 50.7
 (6.1) 79.9
 
 49.1
 68.7
 (8.2) 109.6
Fair Value Hedges 
 1.4
 
 
 1.4
 
 0.2
 
 
 0.2
Total Risk Management Liabilities $3.2
 $343.3
 $256.6
 $(181.0) $422.1
 $5.1
 $293.2
 $300.3
 $(224.7) $373.9




AEP


Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 20162018
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Other Temporary Investments          
Restricted Cash and Other Cash Deposits (a) $221.5
 $
 $
 $9.1
 $230.6
Fixed Income Securities – Mutual Funds 104.3
 
 
 
 104.3
Equity Securities – Mutual Funds (b) 34.2
 
 
 
 34.2
Total Other Temporary Investments 360.0
 
 
 9.1
 369.1
           
Risk Management Assets          
Risk Management Commodity Contracts (c) (f) 3.8
 326.5
 340.9
 (288.5) 382.7
Cash Flow Hedges:          
Commodity Hedges (c) 
 24.1
 12.7
 (2.7) 34.1
Total Risk Management Assets 3.8
 350.6
 353.6
 (291.2) 416.8
           
Spent Nuclear Fuel and Decommissioning Trusts          
Cash and Cash Equivalents (e) 12.3
 
 
 10.2
 22.5
Fixed Income Securities:          
United States Government 
 996.1
 
 
 996.1
Corporate Debt 
 52.4
 
 
 52.4
State and Local Government 
 8.6
 
 
 8.6
Subtotal Fixed Income Securities 
 1,057.1
 
 
 1,057.1
Equity Securities – Domestic (b) 1,395.3
 
 
 
 1,395.3
Total Spent Nuclear Fuel and Decommissioning Trusts 1,407.6
 1,057.1
 
 10.2
 2,474.9
           
Total Assets $1,771.4
 $1,407.7
 $353.6
 $(271.9) $3,260.8
           
Liabilities:          
           
Risk Management Liabilities          
Risk Management Commodity Contracts (c) (f) $4.2
 $327.0
 $185.6
 $(274.7) $242.1
Cash Flow Hedges:          
Commodity Hedges (c) 
 24.8
 36.8
 (2.7) 58.9
Fair Value Hedges 
 17.4
 
 
 17.4
Total Risk Management Liabilities $4.2
 $369.2
 $222.4
 $(277.4) $318.4

  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, 20172019
 Level 1 Level 2 Level 3 Other Total Level 1 Level 2 Level 3 Other Total
Assets: (in millions) (in millions)
                    
Restricted Cash for Securitized Funding (a) $8.3
 $
 $
 $0.1
 $8.4
 $114.3
 $
 $
 $
 $114.3
                    
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
Risk Management Commodity Contracts (c) $
 $0.4
 $
 $
 $0.4


December 31, 2018
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Restricted Cash for Securitized Funding $156.7
 $
 $
 $
 $156.7
           
Liabilities:          
           
Risk Management Liabilities          
Risk Management Commodity Contracts (c) $
 $0.7
 $
 $(0.5) $0.2

APCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2016September 30, 2019
 Level 1 Level 2 Level 3 Other Total Level 1 Level 2 Level 3 Other Total
Assets: (in millions) (in millions)
                    
Restricted Cash for Securitized Funding (a) $15.8
 $
 $
 $0.1
 $15.9
 $17.1
 $
 $
 $
 $17.1
                    
Risk Management Assets  
  
  
  
  
          
Risk Management Commodity Contracts (c) (g) 
 20.5
 3.9
 (21.8) 2.6
 
 31.4
 57.3
 (32.0) 56.7
                    
Total Assets $15.8
 $20.5
 $3.9
 $(21.7) $18.5
 $17.1
 $31.4
 $57.3
 $(32.0) $73.8
                    
Liabilities:  
  
  
  
  
          
                    
Risk Management Liabilities  
  
  
  
  
          
Risk Management Commodity Contracts (c) (g) $
 $20.7
 $2.5
 $(22.0) $1.2
 $
 $33.2
 $1.8
 $(33.6) $1.4

December 31, 2018
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Restricted Cash for Securitized Funding $25.6
 $
 $
 $
 $25.6
           
Risk Management Assets          
Risk Management Commodity Contracts (c) (g) 0.1
 59.1
 58.3
 (59.4) 58.1
           
Total Assets $25.7
 $59.1
 $58.3
 $(59.4) $83.7
           
Liabilities:          
           
Risk Management Liabilities          
Risk Management Commodity Contracts (c) (g) $0.2
 $58.4
 $0.5
 $(58.5) $0.6




I&M

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 20172019
 Level 1 Level 2 Level 3 Other Total Level 1 Level 2 Level 3 Other Total
Assets: (in millions) (in millions)
                    
Risk Management Assets  
  
  
  
  
          
Risk Management Commodity Contracts (c) (g) $
 $16.3
 $12.4
 $(16.6) $12.1
 $
 $21.9
 $10.2
 $(21.5) $10.6
                    
Spent Nuclear Fuel and Decommissioning Trusts  
  
  
  
  
          
Cash and Cash Equivalents (e) 14.0
 
 
 6.5
 20.5
 9.4
 
 
 8.0
 17.4
Fixed Income Securities:  
  
  
  
  
          
United States Government 
 974.3
 
 
 974.3
 
 1,047.4
 
 
 1,047.4
Corporate Debt 
 60.0
 
 
 60.0
 
 68.6
 
 
 68.6
State and Local Government 
 9.0
 
 
 9.0
 
 7.5
 
 
 7.5
Subtotal Fixed Income Securities 
 1,043.3
 
 
 1,043.3
 
 1,123.5
 
 
 1,123.5
Equity Securities - Domestic (b) 1,369.2
 
 
 
 1,369.2
 1,694.3
 
 
 
 1,694.3
Total Spent Nuclear Fuel and Decommissioning Trusts
 1,383.2
 1,043.3
 
 6.5
 2,433.0
 1,703.7
 1,123.5
 
 8.0
 2,835.2
                    
Total Assets $1,383.2
 $1,059.6
 $12.4
 $(10.1) $2,445.1
 $1,703.7
 $1,145.4
 $10.2
 $(13.5) $2,845.8
                    
Liabilities:  
  
  
  
  
          
                    
Risk Management Liabilities  
  
  
  
  
          
Risk Management Commodity Contracts (c) (g) $
 $16.4
 $2.2
 $(16.4) $2.2
 $
 $21.3
 $1.3
 $(22.4) $0.2

December 31, 2018
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets          
Risk Management Commodity Contracts (c) (g) $
 $42.1
 $10.3
 $(43.2) $9.2
           
Spent Nuclear Fuel and Decommissioning Trusts          
Cash and Cash Equivalents (e) 12.3
 
 
 10.2
 22.5
Fixed Income Securities:         

United States Government 
 996.1
 
 
 996.1
Corporate Debt 
 52.4
 
 
 52.4
State and Local Government 
 8.6
 
 
 8.6
Subtotal Fixed Income Securities 
 1,057.1
 
 
 1,057.1
Equity Securities - Domestic (b) 1,395.3
 
 
 
 1,395.3
Total Spent Nuclear Fuel and Decommissioning Trusts 1,407.6
 1,057.1
 
 10.2
 2,474.9
           
Total Assets $1,407.6
 $1,099.2
 $10.3
 $(33.0) $2,484.1
           
Liabilities:          
           
Risk Management Liabilities          
Risk Management Commodity Contracts (c) (g) $0.1
 $41.2
 $1.4
 $(42.3) $0.4


I&M

OPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2016September 30, 2019
  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
  Level 1 Level 2 Level 3 Other Total
Liabilities: (in millions)
           
Risk Management Liabilities          
Risk Management Commodity Contracts (c) (g) $
 $0.4
 $112.5
 $
 $112.9



December 31, 2018
OPCo
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Restricted Cash for Securitized Funding $27.6
 $
 $
 $
 $27.6
           
Liabilities:          
           
Risk Management Liabilities          
Risk Management Commodity Contracts (c) (g) $
 $0.8
 $99.4
 $(0.6) $99.6



PSO
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 20172019
 Level 1 Level 2 Level 3 Other Total Level 1 Level 2 Level 3 Other Total
Assets: (in millions) (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
 $
 $
 $22.0
 $(0.3) $21.7
          
Total Assets $15.6
 $0.3
 $
 $(0.1) $15.8
                    
Liabilities:                    
                    
Risk Management Liabilities                    
Risk Management Commodity Contracts (c) (g) $
 $
 $138.5
 $
 $138.5
 $
 $0.2
 $0.4
 $(0.3) $0.3

December 31, 2018
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets          
Risk Management Commodity Contracts (c) (g) $
 $
 $10.8
 $(0.4) $10.4
           
Liabilities:          
           
Risk Management Liabilities          
Risk Management Commodity Contracts (c) (g) $
 $0.3
 $1.3
 $(0.6) $1.0



OPCo

SWEPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2016September 30, 2019
 Level 1 Level 2 Level 3 Other Total Level 1 Level 2 Level 3 Other Total
Assets: (in millions) (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
 $
 $
 $9.8
 $(0.4) $9.4
          
Total Assets $
 $0.4
 $
 $27.0
 $27.4
                    
Liabilities:  
  
  
  
  
          
                    
Risk Management Liabilities  
  
  
  
  
          
Risk Management Commodity Contracts (c) (g) $
 $
 $119.0
 $
 $119.0
 $
 $0.2
 $4.9
 $(0.4) $4.7




PSO

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2017December 31, 2018
 Level 1 Level 2 Level 3 Other Total Level 1 Level 2 Level 3 Other Total
Assets: (in millions) (in millions)
                    
Risk Management Assets  
  
  
  
  
          
Risk Management Commodity Contracts (c) (g) $
 $
 $4.8
 $(0.1) $4.7
 $
 $
 $5.6
 $(0.8) $4.8
                    
Liabilities:  
  
  
  
  
          
                    
Risk Management Liabilities  
  
  
  
  
          
Risk Management Commodity Contracts (c) (g) $
 $
 $0.1
 $(0.1) $
 $
 $0.4
 $3.3
 $(1.1) $2.6

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.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, 20172019 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 12 matures $(2)$(6) million in 2019, $(8) million in periods 2018-2020;  Level 2 matures $(1) million in 2017 and $3 million in periods 2018-20202020-2022 and $(1) million in periods 2021-2022;2025-2032; Level 3 matures $23$40 million in 2017, $772019, $114 million in periods 2018-2020, $162020-2022, $26 million in periods 2021-20222023-2024 and $(21)$(4) million in periods 2023-2032.2025-2032.  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, 20162018 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 12 matures $(2)$(4) million in 2019, $1 million in periods 2018-2020; Level 2 matures $20 million in 2017, $42020-2022, $1 million in periods 2018-2020, $3 million in periods 2021-20222023-2024 and $1 million in periods 2023-2032;2025-2032; Level 3 matures $17$108 million in 2017, $282019, $37 million in periods 2018-2020, $112020-2022, $23 million in periods 2021-20222023-2024 and $(31)$(12) million in periods 2023-2032.2025-2032.  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 Level 1 and Level 2 during the three and nine months ended September 30, 20172019 and 2016.2018.



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, 2017 AEP APCo I&M OPCo PSO SWEPCo
Three Months Ended September 30, 2019 AEP APCo I&M OPCo PSO SWEPCo
 (in millions) (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
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
 
 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 (b)(a) 14.8
 
 
 
 
 
 2.9
 
 
 
 
 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (24.3) 
 
 
 
 
 22.1
 
 
 
 
 
Settlements (49.2) (16.2) (8.4) 1.2
 (6.9) (7.6) (67.4) (28.1) (7.2) 1.1
 (11.2) (6.7)
Transfers into Level 3 (d) (e) 5.7
 
 
 
 
 
Transfers into Level 3 (c) (d) 3.5
 
 
 
 
 
Transfers out of Level 3 (e)(d) 0.2
 
 
 
 
 
 6.6
 
 
 
 
 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)(e) (9.3) (1.9) (0.7) (9.1) (1.9) 4.5
 (0.3) 1.3
 0.7
 (2.1) 0.9
 (0.5)
Balance as of September 30, 2017 $45.0
 $29.4
 $10.2
 $(138.5) $4.7
 $13.1
Balance as of September 30, 2019 $110.3
 $55.5
 $8.9
 $(112.5) $21.6
 $4.9
Three Months Ended September 30, 2018 AEP APCo I&M OPCo PSO SWEPCo
  (in millions)
Balance as of June 30, 2018 $172.3
 $60.0
 $13.2
 $(86.9) $24.3
 $4.9
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 19.9
 9.0
 1.9
 
 3.7
 1.7
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 1.5
 
 
 
 
 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 10.4
 
 
 
 
 
Settlements (56.0) (19.8) (5.5) 0.6
 (10.8) (2.7)
Transfers into Level 3 (c) (d) 2.3
 
 
 
 
 
Transfers out of Level 3 (d) (1.2) 
 
 
 
 
Changes in Fair Value Allocated to Regulated Jurisdictions (e) 12.0
 17.3
 (0.2) (8.9) 0.4
 (0.4)
Balance as of September 30, 2018 $161.2
 $66.5
 $9.4
 $(95.2) $17.6
 $3.5

Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo
Nine Months Ended September 30, 2019 AEP APCo I&M OPCo PSO SWEPCo
 (in millions) (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
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 (b)(a) 12.3
 
 
 
 
 
 32.9
 
 
��
 
 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4) 
 
 
 
 
 (42.8) 
 
 
 
 
Settlements (37.1) (17.9) (5.0) 0.9
 (0.7) (4.4) (114.6) (41.9) (12.6) 4.6
 (23.0) (10.1)
Transfers into Level 3 (d) (e) 13.1
 0.1
 
 
 
 
Transfers into Level 3 (c) (d) 0.4
 
 
 
 
 
Transfers out of Level 3 (e)(d) (10.0) 
 
 
 
 
 1.4
 (0.7) (0.4) 
 
 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)(e) (29.0) 0.9
 2.2
 (95.3) 0.3
 0.3
 87.2
 54.4
 8.4
 (16.8) 21.6
 6.7
Balance as of September 30, 2016 $98.4
 $(7.1) $4.5
 $(109.1) $1.1
 $1.3
Balance as of September 30, 2019 $110.3
 $55.5
 $8.9
 $(112.5) $21.6
 $4.9


Nine Months Ended September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo
Nine Months Ended September 30, 2018 AEP APCo I&M OPCo PSO SWEPCo
 (in millions) (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
Balance as of December 31, 2017 $40.3
 $24.7
 $7.6
 $(132.4) $6.2
 $5.9
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 150.9
 104.4
 14.7
 1.3
 18.1
 (4.8)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b)(a) 37.2
 
 
 
 
 
 9.5
 
 
 
 
 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (29.5) 
 
 
 
 
 16.4
 
 
 
 
 
Settlements (49.7) (18.9) (7.1) 5.1
 (3.8) (6.8) (212.3) (128.3) (21.9) 3.0
 (24.3) (1.3)
Transfers into Level 3 (d) (e) 16.1
 
 
 
 
 
Transfers into Level 3 (c) (d) 16.5
 
 
 
 
 
Transfers out of Level 3 (e)(d) (9.1) 
 
 
 
 
 (2.5) 
 (0.3) 
 
 
Changes in Fair Value Allocated to Regulated Jurisdictions (f)(e) 40.1
 29.7
 10.5
 (23.6) 4.7
 13.2
 142.4
 65.7
 9.3
 32.9
 17.6
 3.7
Balance as of September 30, 2017 $45.0
 $29.4
 $10.2
 $(138.5) $4.7
 $13.1
Balance as of September 30, 2018 $161.2
 $66.5
 $9.4
 $(95.2) $17.6
 $3.5


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)(b)Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(d)(c)Represents existing assets or liabilities that were previously categorized as Level 2.
(e)(d)Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
(f)(e)Relates to the net gains (losses) of those contracts that are not reflected on the statements of income.  These net gains (losses) are recorded as regulatory liabilities/assetsassets/liabilities 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, 2017
AEP2019
   Significant Input/Range   Significant Input/Range
Fair ValueValuation Unobservable     WeightedFair ValueValuation Unobservable     Weighted
Assets Liabilities Technique Input Low High AverageAssets Liabilities Technique Input Low High Average
(in millions)      (in millions)      
Energy Contracts$233.8
 $252.6
 Discounted Cash Flow  Forward Market Price (a)  $(0.05) $92.77
 $35.82
$298.8
 $286.8
 Discounted Cash Flow Forward Market Price (a) $(0.05) $180.10
 $31.34
    Counterparty Credit Risk (b)  10
 539
 204
Natural Gas Contracts0.9
 
 Discounted Cash Flow  Forward Market Price (c)  2.47
 3.03
 2.68

 4.5
 Discounted Cash Flow Forward Market Price (b) 1.96
 2.62
 2.25
FTRs66.9
 4.0
 Discounted Cash Flow  Forward Market Price (a)  (9.80) 9.37
 0.32
111.8
 9.0
 Discounted Cash Flow Forward Market Price (a) (10.40) 11.65
 0.54
Total$301.6
 $256.6
      
  
  $410.6
 $300.3
      

December 31, 2018
     Significant Input/Range
 Fair ValueValuation Unobservable     Weighted
 Assets Liabilities Technique Input Low High Average
 (in millions)          
Energy Contracts$257.1
 $212.5
 Discounted Cash Flow Forward Market Price (a) $(0.05) $176.57
 $33.07
Natural Gas Contracts
 2.5
 Discounted Cash Flow Forward Market Price (b) 2.18
 3.54
 2.47
FTRs96.5
 7.4
 Discounted Cash Flow Forward Market Price (a) (11.68) 17.79
 1.09
Total$353.6
 $222.4
          



APCo
Significant Unobservable Inputs
December 31, 2016
AEPSeptember 30, 2019
   Significant Input/Range  Significant Input/Range
Fair ValueValuation Unobservable     WeightedFair Value Valuation Unobservable     Weighted
Assets Liabilities Technique Input Low High AverageAssets Liabilities Technique Input (a) Low High Average
(in millions)      (in millions)      
Energy Contracts$183.8
 $187.1
 Discounted Cash Flow  Forward Market Price (a)  $6.51
 $86.59
 $39.40
$3.6
 $1.1
 Discounted Cash Flow Forward Market Price $12.93
 $59.25
 $31.28
    Counterparty Credit Risk (b)  35
 824
 391
FTRs10.1
 4.3
 Discounted Cash Flow  Forward Market Price (a)  (7.99) 8.91
 0.86
53.7
 0.7
 Discounted Cash Flow Forward Market Price (0.91) 10.14
 1.63
Total$193.9
 $191.4
      
  
  $57.3
 $1.8
      



December 31, 2018

     Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
Energy Contracts$2.4
 $0.5
 Discounted Cash Flow Forward Market Price $16.82
 $62.65
 $37.00
FTRs55.9
 
 Discounted Cash Flow Forward Market Price 0.10
 15.16
 3.27
Total$58.3
 $0.5
          

I&M
Significant Unobservable Inputs
September 30, 2017
APCo2019
  Significant Input/Range    Significant Input/Range
Fair Value Valuation Unobservable     WeightedFair Value Valuation Unobservable     Weighted
Assets Liabilities Technique Input (a) Low High AverageAssets Liabilities Technique Input (a) Low High Average
(in millions)          (in millions)      
Energy Contracts$1.0
 $0.4
 Discounted Cash Flow  Forward Market Price  $14.85
 $45.72
 $33.99
$2.2
 $0.7
 Discounted Cash Flow Forward Market Price $12.93
 $59.25
 $31.28
FTRs29.0
 0.2
 Discounted Cash Flow  Forward Market Price  0.08
 6.36
 1.20
8.0
 0.6
 Discounted Cash Flow Forward Market Price (1.76) 7.26
 0.87
Total$30.0
 $0.6
      
  
  $10.2
 $1.3
      

December 31, 2018
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
Energy Contracts$1.4
 $0.9
 Discounted Cash Flow Forward Market Price $16.82
 $62.65
 $37.00
FTRs8.9
 0.5
 Discounted Cash Flow Forward Market Price (2.11) 6.21
 1.06
Total$10.3
 $1.4
          


OPCo
Significant Unobservable Inputs
December 31, 2016
APCoSeptember 30, 2019
     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
      
  
  
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
Energy Contracts$
 $112.5
 Discounted Cash Flow Forward Market Price $27.47
 $65.81
 $40.30


December 31, 2018
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
Energy Contracts$
 $99.4
 Discounted Cash Flow Forward Market Price $26.29
 $62.74
 $42.50

PSO
Significant Unobservable Inputs
September 30, 2017
I&M2019
       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
      
  
  
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
FTRs$22.0
 $0.4
 Discounted Cash Flow Forward Market Price $(6.87) $0.93
 $(2.19)

December 31, 2018
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
FTRs$10.8
 $1.3
 Discounted Cash Flow Forward Market Price $(11.68) $10.30
 $(1.40)


SWEPCo
Significant Unobservable Inputs
December 31, 2016
I&MSeptember 30, 2019
    Significant Input/Range    Significant Input/Range
Fair Value Valuation Unobservable     WeightedFair Value Valuation Unobservable     Weighted
Assets Liabilities Technique Input (a) Low High AverageAssets Liabilities Technique Input Low High Average
(in millions)          (in millions)      
Energy Contracts$0.3
 $0.2
 Discounted Cash Flow  Forward Market Price  $19.68
 $48.55
 $36.34
Natural Gas Contracts$
 $4.5
 Discounted Cash Flow Forward Market Price (b) $1.96
 $2.62
 $2.25
FTRs2.7
 
 Discounted Cash Flow  Forward Market Price  (7.90) 8.91
 1.32
9.8
 0.4
 Discounted Cash Flow Forward Market Price (a) (6.87) 0.93
 (2.19)
Total$3.0
 $0.2
      
  
  $9.8
 $4.9
      




Significant Unobservable Inputs
September 30, 2017
OPCoDecember 31, 2018
    Significant Input/Range    Significant Input/Range
Fair Value Valuation Unobservable     WeightedFair Value Valuation Unobservable     Weighted
Assets Liabilities Technique Input Low High AverageAssets Liabilities Technique Input Low High Average
(in millions)          (in millions)      
Energy Contracts$
 $138.5
 Discounted Cash Flow  Forward Market Price (a) $22.89
 $61.48
 $41.21
    Counterparty Credit Risk (b) 10
 210
 150
Natural Gas Contracts$
 $2.5
 Discounted Cash Flow Forward Market Price (b) $2.18
 $3.54
 $2.47
FTRs5.6
 0.8
 Discounted Cash Flow Forward Market Price (a) (11.68) 10.30
 (1.40)
Total$
 $138.5
      $5.6
 $3.3
      

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 sensitivity 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, 20172019 and December 31, 2016:2018:


Sensitivity of Fair Value Measurements
Significant Unobservable Input Position Change in Input 
Impact on Fair Value
Measurement
Forward Market Price Buy Increase (Decrease) Higher (Lower)
Forward Market Price Sell Increase (Decrease) Lower (Higher)
Counterparty Credit RiskLossIncrease (Decrease)Higher (Lower)
Counterparty Credit RiskGainIncrease (Decrease)Lower (Higher)





11.  INCOME TAXES


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


Status of Tax Reform Regulatory Proceedings

For AEP’s various regulatory jurisdictions where the regulatory effects of Tax Reform proceedings have not been fully resolved, the table below summarizes the current status. See Note 4 - Rate Matters for additional information related to regulatory filings in these jurisdictions.
Registrant (Jurisdiction)Change in Tax RateExcess ADIT Subject to Normalization RequirementsExcess ADIT Not Subject to Normalization Requirements
AEP Texas (Texas-Distribution)Order IssuedOrder IssuedOrder Issued – Partial (a)
AEP Texas (Texas-Transmission)Order IssuedCase PendingCase Pending
I&M (Michigan)Order IssuedCase PendingCase Pending
SWEPCo (Louisiana)Case Pending – Rates Implemented (b)Case Pending – Rates Implemented (b)Case Pending – Rates Implemented (b)
SWEPCo (Texas)Order IssuedTo be addressed in a later filingTo be addressed in a later filing


(a)A portion of the Excess ADIT that is not subject to rate normalization requirements is addressed in a current pending case.
(b)Rates have been implemented through a filed formula rate plan that is subject to true-up and final commission approval.

Effective Tax Rates (ETR)


The Registrants’ interim ETR for AEP’s operating companies reflect the estimated annual ETR for 20172019 and 2016,2018, adjusted for tax expense associated with certain discrete items. The interim ETR differsdiffer from the federal statutory tax rate of 35%21% primarily due to increased amortization of Excess ADIT, tax adjustments, state income taxescredits and other book/tax differences which are accounted for on a flow-through basis.


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

The ETR from continuing operations for each of the Registrants are included in the following table. Significant variances in the ETR are described below.
  Three Months Ended September 30, Nine Months Ended September 30,
Company 2019 2018 2019 2018
AEP 5.2 % (16.2)% 1.7 % 5.6 %
AEP Texas 15.1 % 12.6 % (25.3)% 14.9 %
AEPTCo 21.9 % 18.4 % 20.7 % 20.7 %
APCo (3.9)% (962.2)% (19.1)% (13.8)%
I&M (2.7)% 15.9 % (2.1)% 10.4 %
OPCo 13.9 % (46.4)% 14.2 % 4.6 %
PSO 6.4 % 5.6 % 4.6 % 8.7 %
SWEPCo (0.6)% 9.8 %  % 11.4 %

  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 %





AEP


Three Months Ended September 30, 20172019 Compared to Three Months Ended September 30, 20162018


The decreaseincrease in the ETR iswas primarily due to $71 million of decreased amortization of Excess ADIT not subject to normalization requirements and $14 million of increased state tax expense which impacted the prior year reversal of a $66 million capital loss valuation allowance related to the pending sale of certain merchant generation assetsETR by 19.1% and prior year tax return adjustments related to the disposition of AEP’s commercial barging operations.1.3%, respectively.


Nine Months Ended September 30, 20172019 Compared to Nine Months Ended September 30, 20162018


The increasedecrease in the ETR iswas primarily due to the increase in pretax book income driven by the impairment$93 million of certain merchant generation assets in the third quarterincreased amortization of 2016. The increase inExcess ADIT not subject to normalization requirements which impacted the ETR is also due to the prior year reversal of a $56 million unrealized capital loss valuation allowance where by (4.5)%.

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.Texas


APCo

Three Months Ended September 30, 20172019 Compared to Three Months Ended September 30, 20162018


The increase in ETR was primarily due to significantly higher pretax book income which reduced the impact that favorable tax deductions had on the ETR.

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018

The decrease in the ETR iswas primarily due to $59 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the recordingETR by (38.9)%. Amortization of favorable federal income tax adjustmentsExcess ADIT not subject to normalization requirements for the nine months ended September 30, 2019 reflects Tax Reform elements of the Stipulation and a decreaseSettlement agreement approved by the PUCT in pretax book income.August 2018 and the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019.



AEPTCo


OPCo

Three Months Ended September 30, 20172019 Compared to Three Months Ended September 30, 20162018


The increase in the ETR iswas primarily due to changes in other book/$3 million of increased state tax differencesexpense and $2 million of decreased amortization of Excess ADIT not subject to normalization requirements which are accounted for on a flow-through basisimpacted the ETR by 1.3% and the recording of federal income tax adjustments.1%, respectively.


Nine Months Ended September 30, 20172019 Compared to Nine Months Ended September 30, 20162018

The ETR remained consistent for the nine months ended September 30, 2019 and 2018.

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.

APCo
SWEPCo

Three Months Ended September 30, 20172019 Compared to Three Months Ended September 30, 20162018

The increase in the ETR was primarily due to $56 million of decreased amortization of Excess ADIT not subject to normalization requirements and $6 million of increased state tax expense which impacted the ETR by 947.3% and 34.8%, respectively. Amortization of Excess ADIT not subject to normalization requirements primarily decreased from the prior year due to the discrete impact of the West Virginia Tax Reform order which enabled APCo to utilize $73 million of Excess ADIT not subject to normalization requirements to offset certain regulatory asset balances in the third quarter of 2018.

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018

The decrease in the ETR iswas primarily due to a$9 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (4.6)%. Amortization of Excess ADIT not subject to normalization requirements for the nine months ended September 30, 2019 reflects the October 2018 and March 2019 Virginia SCC Tax Reform orders as well as the August 2018 and February 2019 WVPSC orders.

I&M

Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018

The decrease in the ETR was primarily due to $10 million of increased amortization of Excess ADIT, $3 million of increased favorable book/tax differences accounted for on a flow-through basis, $2 million of decreased state income tax expense and $1 million of increased parent company loss benefit which impacted the ETR by (11.3)%, (3.2)%, (1.8)% and (1.6)% respectively.

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018

The decrease in Incomethe ETR was primarily due to $16 million of increased amortization of Excess ADIT not subject to normalization requirements and $12 million of increased favorable book/tax differences accounted for on a flow-through basis which impacted the ETR by (6.9)% and (4.8)%, respectively. Amortization of Excess ADIT not subject to normalization requirements for the nine months ended September 30, 2019 reflects the Tax Expense relatedReform elements of the 2017 Indiana Base Rate Case approved by the IURC in May 2018.

OPCo

Three Months Ended September 30, 2019 Compared to income tax benefits attributableThree Months Ended September 30, 2018

The increase in the ETR was primarily due to SWEPCo’s noncontrolling interest$35 million of decreased amortization of Excess ADIT not subject to normalization requirements and $1 million of decreased parent company loss benefit which impacted the ETR by 60% and 2%, respectively. Amortization of Excess ADIT not subject to amortization requirements decreased from the prior year primarily due to the discrete impact of the Ohio Tax Reform order which enabled OPCo to utilize $38 million of Excess ADIT not subject to rate normalization requirements to offset certain regulatory asset balances in Sabine.the third quarter of 2018.

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018

The increase in the ETR was primarily due to $24 million of decreased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by 10.8%. Amortization of Excess ADIT not subject to amortization requirements decreased from the prior year primarily due to the discrete impact of the Ohio Tax Reform order which enabled OPCo to utilize $38 million of Excess ADIT not subject to rate normalization requirements to offset certain regulatory asset balances in the third quarter of 2018.


PSO

Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018

The ETR remained comparable for the three months ended September 30, 2019 and 2018.

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018

The decrease in the ETR was primarily due to $15 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (6.8)%. Amortization of Excess ADIT not subject to normalization requirements for the nine months ended September 30, 2019 reflects the August 2018 OCC Tax Reform order as well as Tax Reform elements of the 2018 Oklahoma Base Rate Case approved by the OCC in March 2019.

SWEPCo

Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018

The decrease in the ETR was primarily due to $11 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (9.7)%. Amortization of Excess ADIT not subject to normalization requirements for the nine months ended September 30, 2019 reflects Tax Reform elements incorporated in the Louisiana 2018 Formula Rate Filing as well as the Arkansas Tax Reform order issued by the APSC in September 2018.

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018

The decrease in the ETR was primarily due to $15 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (10.4)%. Amortization of Excess ADIT not subject to normalization requirements for the nine months ended September 30, 2019 reflects Tax Reform elements incorporated in the Louisiana 2018 Formula Rate Filing as well as the Arkansas Tax Reform order issued by the APSC in September 2018.

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. Thethrough 2013. During the IRS examination of years 2011 2012 and 2013 started in April 2014.through 2014, the statute of limitations for these years was extended to coincide with the examination of 2015. During the third quarter of 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 submitted2014 and 2015 federal returns. Due to the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back to 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 years 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 under examination in several state and local jurisdictions.  However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities.  Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolutionamendment of these auditsfederal returns, the 2014 and 2015 years will not materially impact net income.  remain open for possible IRS examination for only the items that were amended on the 2014 and 2015 federal returns.The Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009.IRS examination of 2016 began in October 2018 and concluded in March 2019.


State Tax Legislation (Applies to AEP, APCo,AEPTCo, I&M and OPCo)


Legislation wasIn April 2018, the Kentucky legislature enacted in theHouse Bill (H.B.) 487. H.B. 487 adopts mandatory unitary combined reporting for state of Illinois in July 2017 increasing the corporate income tax rate from 5.25% to 7% effective July 1, 2017, with the increased rate applied to the portion of the tax year fallingpurposes applicable for taxable years beginning on or after that date. WithJanuary 1, 2019. H.B. 487 also adopts the inclusion of80% federal net operating loss (NOL) limitation under Internal Revenue Code Sec. 172(a) for NOLs generated after January 1, 2018 and the 2.5% Illinois Replacement Tax,federal unlimited carryforward period for unused NOLs generated after January 1, 2018. In addition, H.B. 366 was also enacted in April 2018, which among other things, replaces the total Illinoisgraduated corporate income tax rate increased from 7.75%structure with a flat 5% tax rate for business income and adopts a single-sales factor apportionment formula for apportioning a corporation’s business income to 9.5%, effective July 1, 2017.Kentucky. In the second quarter of 2018, AEP recorded an $18 million benefit to Income Tax Expense (Benefit) as a result of remeasuring Kentucky deferred taxes under a unitary filing group. The enacted legislation isdid not expected to materially impact AEPTCo’s, I&M’s or OPCo’s net income, cash flows or financial condition.income.




12.  FINANCING ACTIVITIESLEASES


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

The Registrants lease property, plant and equipment including, but not limited to, fleet, information technology and real estate leases.These leases require payments of non-lease components, including related property taxes, operating and maintenance costs. As of the adoption date of ASU 2016-02, management elected not to separate non-lease components from associated lease components in accordance with the accounting guidance for “Leases.”  Many of these leases have purchase or renewal options. Leases not renewed are often replaced by other leases. Options to renew or purchase a lease are included in the measurement of lease assets and liabilities if it is reasonably certain the Registrant will exercise the option.

Lease obligations are measured using the discount rate implicit in the lease when that rate is readily determinable. When the implicit rate is not readily determinable, the Registrants measure their lease obligation using their estimated secured incremental borrowing rate. Incremental borrowing rates are comprised of an underlying risk free rate and a secured credit spread relative to the lessee on a matched maturity basis.

Lease rentals for both operating and finance leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations.  Additionally, for regulated operations with finance leases, a finance lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period.  Finance leases for nonregulated property are accounted for as if the assets were owned and financed.  The components of rental costs were as follows:
Three Months Ended September 30, 2019 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
  (in millions)
Operating Lease Cost $64.4
 $4.0
 $0.6
 $4.9
 $23.7
 $4.9
 $1.5
 $1.8
Finance Lease Cost:                
Amortization of Right-of-Use Assets 16.5
 1.5
 0.1
 2.0
 1.6
 1.1
 0.8
 2.8
Interest on Lease Liabilities 4.1
 0.3
 
 0.8
 0.8
 0.2
 0.1
 0.7
Total Lease Rental Costs (a) $85.0
 $5.8
 $0.7
 $7.7
 $26.1
 $6.2
 $2.4
 $5.3
Nine Months Ended September 30, 2019 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
  (in millions)
Operating Lease Cost $200.3
 $12.2
 $1.7
 $14.5
 $70.0
 $13.8
 $5.0
 $5.7
Finance Lease Cost:                
Amortization of Right-of-Use Assets 45.0
 3.8
 0.1
 5.0
 4.2
 2.6
 2.2
 8.2
Interest on Lease Liabilities 12.2
 1.0
 
 2.2
 2.3
 0.5
 0.4
 2.2
Total Lease Rental Costs (a) $257.5
 $17.0
 $1.8
 $21.7
 $76.5
 $16.9
 $7.6
 $16.1

(a)Excludes variable and short-term lease costs, which were immaterial for the three and nine months ended September 30, 2019.



Supplemental information related to leases are shown in the tables below:
September 30, 2019 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
Weighted-Average Remaining Lease Term (years):                
Operating Leases 5.31
 7.05
 2.43
 6.25
 4.05
 8.10
 7.06
 6.63
Finance Leases 5.87
 6.86
 0.58
 6.33
 6.72
 6.58
 6.24
 5.34
Weighted-Average Discount Rate:                
Operating Leases 3.61% 3.79% 3.13% 3.67% 3.45% 3.79% 3.68% 3.80%
Finance Leases 6.02% 4.71% 9.33%��8.19% 8.61% 4.66% 4.73% 5.03%

Nine Months Ended September 30, 2019 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
  (in millions)
Cash paid for amounts included in the measurement of lease liabilities:                
Operating Cash Flows Used for Operating Leases $163.6
 $11.4
 $1.7
 $14.1
 $52.5
 $13.8
 $4.9
 $5.3
Operating Cash Flows Used for Finance Leases 11.0
 1.0
 
 2.2
 2.2
 0.5
 0.4
 1.1
Financing Cash Flows Used for Finance Leases 44.5
 3.8
 
 5.0
 4.0
 2.6
 2.2
 8.1
                 
Non-cash Acquisitions Under Operating Leases $108.9
 $12.7
 $
 $8.6
 $16.6
 $34.6
 $7.3
 $10.6

The following tables show the property, plant and equipment under finance leases and noncurrent assets under operating leases and related obligations recorded on the Registrants’ balance sheets.  Unless shown as a separate line on the balance sheets due to materiality, net operating lease assets are included in Deferred Charges and Other Noncurrent Assets, current finance lease obligations are included in Other Current Liabilities and long-term finance lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the Registrants’ balance sheets. Lease obligations are not recognized on the balance sheets for lease agreements with a lease term of less than twelve months.
September 30, 2019 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
  (in millions)
Property, Plant and Equipment Under Finance Leases:                
Generation $134.9
 $
 $
 $41.3
 $28.5
 $
 $2.6
 $34.2
Other Property, Plant and Equipment 335.9
 41.9
 0.2
 18.4
 37.1
 24.7
 20.7
 50.0
Total Property, Plant and Equipment 470.8
 41.9
 0.2
 59.7
 65.6
 24.7
 23.3
 84.2
Accumulated Amortization 162.7
 10.9
 0.2
 17.8
 22.8
 6.6
 9.1
 26.2
Net Property, Plant and Equipment Under Finance Leases $308.1
 $31.0
 $
 $41.9
 $42.8
 $18.1
 $14.2
 $58.0
                 
Obligations Under Finance Leases:                
Noncurrent Liability $254.0
 $25.8
 $
 $35.2
 $37.1
 $14.5
 $11.0
 $50.5
Liability Due Within One Year 61.4
 5.2
 
 6.7
 6.0
 3.6
 3.2
 11.2
Total Obligations Under Finance Leases $315.4
 $31.0
 $
 $41.9
 $43.1
 $18.1
 $14.2
 $61.7

September 30, 2019 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
  (in millions)
Operating Lease Assets $990.0
 $82.0
 $4.6
 $79.4
 $295.3
 $88.2
 $37.1
 $40.8
                 
Obligations Under Operating Leases:                
Noncurrent Liability $801.1
 $71.1
 $2.2
 $64.8
 $234.0
 $75.9
 $31.2
 $32.5
Liability Due Within One Year 228.8
 11.7
 2.3
 15.3
 82.0
 12.8
 6.0
 5.9
Total Obligations Under Operating Leases $1,029.9
 $82.8
 $4.5
 $80.1
 $316.0
 $88.7
 $37.2
 $38.4




Future minimum lease payments as of September 30, 2019 are presented on a rolling 12-month basis as shown in the tables below:
Finance Leases AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
  (in millions)
Year 1 $76.8
 $6.6
 $
 $9.6
 $9.0
 $4.3
 $3.8
 $13.0
Year 2 67.0
 6.1
 
 8.8
 8.2
 3.9
 3.1
 11.6
Year 3 58.0
 5.3
 
 8.1
 7.6
 3.2
 2.3
 10.6
Year 4 49.0
 4.9
 
 7.5
 7.1
 2.5
 2.1
 9.5
Year 5 50.0
 4.1
 
 7.0
 6.7
 2.1
 1.7
 14.8
Later Years 76.1
 9.8
 
 11.3
 20.9
 5.3
 3.7
 7.5
Total Future Minimum Lease Payments 376.9
 36.8
 
 52.3
 59.5
 21.3
 16.7
 67.0
Less Imputed Interest 61.5
 5.8
 
 10.4
 16.4
 3.2
 2.5
 5.3
Estimated Present Value of Future Minimum Lease Payments $315.4
 $31.0
 $
 $41.9
 $43.1
 $18.1
 $14.2
 $61.7

Operating Leases AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
  (in millions)
Year 1 $267.5
 $15.7
 $2.4
 $18.4
 $92.2
 $16.6
 $7.4
 $8.4
Year 2 252.4
 15.2
 1.5
 16.4
 88.4
 13.9
 6.6
 8.2
Year 3 239.9
 14.1
 0.7
 14.7
 86.3
 13.3
 6.0
 7.5
Year 4 154.2
 13.0
 0.3
 12.5
 48.0
 12.4
 5.5
 7.2
Year 5 63.6
 11.4
 
 9.8
 7.3
 10.8
 5.0
 5.0
Later Years 184.1
 27.8
 
 20.1
 22.0
 38.3
 12.7
 12.4
Total Future Minimum Lease Payments 1,161.7
 97.2
 4.9
 91.9
 344.2
 105.3
 43.2
 48.7
Less Imputed Interest 131.8
 14.4
 0.4
 11.8
 28.2
 16.6
 6.0
 10.3
Estimated Present Value of Future Minimum Lease Payments $1,029.9
 $82.8
 $4.5
 $80.1
 $316.0
 $88.7
 $37.2
 $38.4


Future minimum lease payments consisted of the following as of December 31, 2018:
Finance Leases AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
  (in millions)
2019 $70.8
 $5.8
 $0.1
 $9.0
 $8.2
 $3.3
 $3.4
 $13.1
2020 60.2
 5.3
 
 8.0
 7.2
 2.7
 2.6
 11.5
2021 51.7
 4.7
 
 7.3
 6.6
 2.3
 2.0
 10.5
2022 43.8
 4.2
 
 6.8
 6.1
 1.7
 1.6
 9.4
2023 35.5
 3.7
 
 6.3
 5.7
 1.2
 1.4
 8.6
Later Years 90.2
 10.1
 
 13.3
 21.7
 2.8
 3.3
 18.7
Total Future Minimum Lease Payments 352.2
 33.8
 0.1
 50.7
 55.5
 14.0
 14.3
 71.8
Less Imputed Interest 63.2
 5.3
 
 10.9
 16.8
 1.9
 2.0
 11.0
Estimated Present Value of Future Minimum Lease Payments $289.0
 $28.5
 $0.1
 $39.8
 $38.7
 $12.1
 $12.3
 $60.8
Operating Leases AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
  (in millions)
2019 $259.6
 $15.1
 $2.3
 $17.6
 $92.6
 $14.5
 $6.5
 $7.4
2020 250.1
 14.1
 1.8
 16.5
 89.3
 13.2
 6.0
 7.2
2021 232.7
 13.2
 1.0
 13.9
 84.8
 10.9
 5.0
 6.7
2022 222.5
 12.2
 0.5
 12.8
 83.8
 10.0
 4.6
 6.1
2023 58.3
 10.8
 0.1
 9.9
 6.5
 8.8
 4.1
 5.0
Later Years 165.2
 28.4
 
 20.5
 19.5
 31.7
 10.7
 11.7
Total Future Minimum Lease Payments $1,188.4
 $93.8
 $5.7
 $91.2
 $376.5
 $89.1
 $36.9
 $44.1




Master Lease Agreements (Applies to all Registrants except AEPTCo)

The Registrants lease certain equipment under master lease agreements.  Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee.  Historically, at the end of the lease term the fair value has been in excess of the amount guaranteed.  As of September 30, 2019, the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows:
Company 
Maximum
Potential Loss
  (in millions)
AEP $46.6
AEP Texas 11.2
APCo 6.3
I&M 4.0
OPCo 7.4
PSO 4.3
SWEPCo 4.7


Rockport Lease (Applies to AEP and I&M)

AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant).  The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors. In the first quarter of 2019, in accordance with ASU 2016-02, the $37 million unamortized gain ($15 million related to I&M) associated with the sale-and-leaseback of the Plant was recognized as an adjustment to equity.  The adjustment to equity was then reclassified to regulatory liabilities in accordance with accounting guidance for “Regulated Operations” as AEGCo and I&M will continue to provide the benefit of the unamortized gain to customers in future periods.

The Owner Trustee owns the Plant and leases equal portions to AEGCo and I&M.  The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note.  The lease term is for 33 years and at the end of the lease term, AEGCo and I&M have the option to renew the lease at a rate that approximates fair value.  The option to renew was not included in the measurement of the lease obligation as of September 30, 2019 as the execution of the option was not reasonably certain. AEP, AEGCo and I&M have no ownership interest in the Owner Trustee and do not guarantee its debt.  The future minimum lease payments for this sale-and-leaseback transaction as of September 30, 2019 were as follows:
Future Minimum Lease Payments AEP (a) I&M
  (in millions)
2019 $74.2
 $37.1
2020 147.8
 73.9
2021 147.8
 73.9
2022 147.2
 73.6
Total Future Minimum Lease Payments $517.0
 $258.5

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



AEPRO Boat and Barge Leases (Applies to AEP)

In 2015, AEP sold its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. Certain boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of September 30, 2019, the maximum potential amount of future payments required under the guaranteed leases was $56 million. In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee. As of September 30, 2019, AEP’s boat and barge lease guarantee liability was $4 million, of which $1 million was recorded in Other Current Liabilities and $3 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheet.

In January 2018, S&P Global Inc. downgraded the ratings of the nonaffiliated party and set their outlook to negative. In April 2018, Moody’s Investors Service Inc. (Moody’s) also downgraded their rating and set their outlook to negative. Moody’s further downgraded their rating in April 2019 and maintained a negative outlook. It is reasonably possible that enforcement of AEP’s liability for future payments under these leases could be exercised, which could reduce future net income and cash flows and impact financial condition.

Lessor Activity

The Registrants’ lessor activity was immaterial as of and for the three and nine months ended September 30, 2019.


13.  FINANCING ACTIVITIES

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

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 Debt September 30, 2019 December 31, 2018
  (in millions)
Senior Unsecured Notes $20,829.2
 $18,903.3
Pollution Control Bonds 1,516.5
 1,643.8
Notes Payable 189.1
 204.7
Securitization Bonds 1,059.4
 1,111.4
Spent Nuclear Fuel Obligation (a) 278.5
 273.6
Junior Subordinated Notes (b) 786.8
 
Other Long-term Debt 1,221.7
 1,209.9
Total Long-term Debt Outstanding 25,881.2
 23,346.7
Long-term Debt Due Within One Year 1,327.7
 1,698.5
Long-term Debt $24,553.5
 $21,648.2

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 fuelSNF 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$322 million and $311$317 million as of September 30, 20172019 and December 31, 2016,2018, 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)”“Equity Units” section of Note 6below 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 20172019 are shown in the tables below:following tables:
 Principal Interest 
Company Type of Debt Principal Amount (a) Interest Rate Due Date Type of Debt Amount (a) Rate Due Date
Issuances:   (in millions) (%)    (in millions) (%) 
AEP Junior Subordinated Notes (b) $805.0
 3.40 2024
AEP Texas Securitization Bonds 117.6
 2.06 2025
AEP Texas Securitization Bonds 117.6
 2.29 2029
AEP Texas Pollution Control Bonds 100.6
 2.60 2029
AEP Texas Senior Unsecured Notes 300.0
 4.15 2049
AEPTCo Senior Unsecured Notes $125.0
 3.10 2026 Senior Unsecured Notes 350.0
 3.80 2049
AEPTCo Senior Unsecured Notes 500.0
 3.75 2047 Senior Unsecured Notes 350.0
 3.15 2049
APCo Senior Unsecured Notes 325.0
 3.30 2027 Pollution Control Bonds 86.0
 2.55 2024
APCo Senior Unsecured Notes 400.0
 4.50 2049
I&M Pollution Control Bonds 25.0
 Variable 2019 Notes Payable 62.8
 Variable 2023
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
OPCo Senior Unsecured Notes 450.0
 4.00 2049
PSO Senior Unsecured Notes 100.0
 3.91 2029
PSO Senior Unsecured Notes 150.0
 4.11 2034
PSO Senior Unsecured Notes 100.0
 4.50 2049
 

 
 
   
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
AEGCo Pollution Control Bonds 45.0
 1.35 2022
Transource Energy Other Long-term Debt 132.1
 Variable 2020 Other Long-term Debt 14.4
 Variable 2020
Total Issuances $2,771.1
 
 
 $3,549.0
 
 


(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.



    Principal Interest  
Company Type of Debt Amount Paid Rate Due Date
Retirements and Principal Payments:   (in millions) (%)  
AEP Texas Senior Unsecured Notes $50.0
 2.61 2019
AEP Texas Securitization Bonds 28.2
 1.98 2020
AEP Texas Securitization Bonds 188.0
 5.31 2020
AEP Texas Pollution Control Bonds 100.6
 6.30 2029
APCo Pollution Control Bonds 86.0
 1.90 2019
APCo Pollution Control Bonds 70.0
 3.25 2019
APCo Securitization Bonds 24.4
 2.01 2023
I&M Notes Payable 2.7
 Variable 2019
I&M Notes Payable 4.3
 Variable 2019
I&M Notes Payable 13.7
 Variable 2020
I&M Notes Payable 17.9
 Variable 2021
I&M Notes Payable 11.3
 Variable 2022
I&M Notes Payable 16.0
 Variable 2022
I&M Notes Payable 6.4
 Variable 2023
I&M Other Long-term Debt 1.3
 6.00 2025
OPCo Securitization Bonds 47.9
 2.05 2019
OPCo Other Long-term Debt 0.1
 1.15 2028
PSO Senior Unsecured Notes 250.0
 5.15 2019
PSO Other Long-term Debt 0.4
 3.00 2027
SWEPCo Pollution Control Bonds 53.5
 1.60 2019
SWEPCo Other Long-term Debt 1.5
 4.68 2028
SWEPCo Notes Payable 3.2
 4.58 2032
         
Non-Registrant:        
AEGCo Pollution Control Bonds 45.0
 Variable 2019
AEP Energy Notes Payable 0.1
 5.75 2019
Transource Energy Other Long-term Debt 1.0
 Variable 2020
Total Retirements and Principal Payments   $1,023.5
    

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, I&M retired $1 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.


As of September 30, 2017,2019, trustees held, on behalf of AEP, $728$574 million of their reacquired Pollution Control Bonds. Of this total, $104 million, $50 million and $345 million relates to OPCo.

Long-term Debt Subsequent Events

In October 2019, AEP remarketed $240 million of Pollution Control Bonds that were held in trust.

In October 2019, I&M retired $4 million of Notes Payable related to APCo,DCC Fuel.

In October 2019, I&M retired $25 million of variable rate Pollution Control Bonds.
Equity Units (Applies to AEP)

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 recent 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 OPCo, respectively.a forward equity purchase contract which settles after three years in 2022. The notes are expected to be remarketed in 2022, at which time the interest rate will reset at the then current market rate. Investors may choose to remarket their notes to receive the remarketing proceeds and use those funds to settle the forward equity purchase contract, or accept the remarketed debt and use other funds for the equity purchase. If the remarketing is unsuccessful, investors have the right to put their notes to AEP at a price equal to the



principal. The Equity Units carry an annual distribution rate of 6.125%, which is comprised of a quarterly coupon rate of interest of 3.40% and a quarterly forward equity purchase contract payment of 2.725%.

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

If the AEP common stock market price is equal to or greater than $99.58: 0.5021 shares per contract.
If the AEP common stock market price is less than $99.58 but greater than $82.98: a number of shares per contract equal to $50 divided by the applicable market price. The holder receives a variable number of shares at $50.
If the AEP common stock market price is less than or equal to $82.98: 0.6026 shares per contract.

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

At the time of issuance, the $805 million of notes were recorded within Long-term Debt on the balance sheets. The present value of the purchase contract payments of $62 million were recorded in Deferred Credits and Other Noncurrent Liabilitieswith a current portion in Other Current Liabilities at the time of issuance, representing the obligation to make forward equity contract payments, with an offsetting reduction to Paid-in Capital. The difference between the face value and present value of the purchase contract payments will be accreted to Interest Expense on the statements of income over the three year period ending in 2022. The liability recorded for the contract payments is considered non-cash and excluded from the statements of cash flows. Until settlement of the forward equity purchase contract, earnings per share dilution resulting from the equity unit issuance will be determined under the treasury stock method. The maximum amount of shares AEP will be required to issue to settle the purchase contract is 9,701,860 shares (subject to an anti-dilution adjustment).

Debt Covenants (Applies to AEP and AEPTCo)


Covenants in AEPTCo’s note purchase agreements and indenture 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 0.1% of consolidated tangible net assets as of September 30, 2019. 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,However, the Federal Power Act 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.



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, 20172019 and December 31, 20162018 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, 20172019 are described in the following table:
  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, 2019 Limit 
  (in millions)
AEP Texas $390.7
 $
 $261.8
 $
 $(74.8) $500.0
 
AEPTCo 374.9
 244.4
 179.8
 40.2
 236.6
 795.0
(a)
APCo 225.4
 232.2
 90.4
 61.8
 (17.7) 600.0
 
I&M 120.4
 66.0
 53.1
 17.2
 (89.2) 500.0
 
OPCo 291.2
 178.6
 163.5
 50.1
 (17.6) 500.0
 
PSO 140.5
 215.6
 63.9
 84.1
 95.1
 300.0
 
SWEPCo 105.1
 81.4
 57.8
 11.2
 6.4
 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.


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, 20172019 and December 31, 20162018 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 had2019 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
Company Money Pool Money Pool September 30, 2019
 (in millions)
AEP Texas $8.0
 $7.7
 $7.7
SWEPCo 2.1
 2.0
 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, 20172019 and December 31, 20162018 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 is2019 are described in the following table:
MaximumMaximum Maximum Average Average Borrowings from Loans to Authorized Maximum Maximum Average Average Borrowings from Loans to Authorized 
BorrowingsBorrowings Loans Borrowings Loans AEP as of AEP as of Short-term Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term 
from AEPfrom AEP to AEP from AEP to AEP September 30, 2017 September 30, 2017 Borrowing Limit from AEP to AEP from AEP to AEP September 30, 2019 September 30, 2019 Borrowing Limit 
(in millions)(in millions) (in millions)
$1.1
 $151.9
 $1.1
 $38.9
 $0.9
 $96.1
 $75.0
(a)1.3
 $117.6
 $1.3
 $63.4
 $1.3
 $30.8
 $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,
  2019 2018
Maximum Interest Rate 3.43% 2.52%
Minimum Interest Rate 1.83% 1.81%

  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 Funds Average Interest Rate for Funds
  Borrowed from the Utility Money Pool Loaned to the Utility Money Pool
  for Nine Months Ended September 30, for Nine Months Ended September 30,
Company 2019 2018 2019 2018
AEP Texas 2.71% 2.25% % 2.29%
AEPTCo 2.72% 2.26% 2.57% 2.04%
APCo 2.82% 2.22% 2.73% 2.19%
I&M 2.56% 2.16% 2.73% 2.06%
OPCo 2.80% 2.18% 2.68% 2.47%
PSO 2.85% 2.25% 2.48% 1.86%
SWEPCo 2.74% 2.31% 2.47% 1.87%

  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, 2019 Nine Months Ended September 30, 2018
  Maximum Minimum Average Maximum Minimum Average
  Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate
  for Funds for Funds for Funds for Funds for Funds for Funds
  Loaned to Loaned to Loaned to Loaned to Loaned to Loaned to
  the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility
Company Money Pool Money Pool Money Pool Money Pool Money Pool Money Pool
AEP Texas 3.02% 2.36% 2.70% 2.52% 1.83% 2.26%
SWEPCo 3.02% 2.36% 2.70% 2.52% 1.83% 2.26%

  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:
  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
2019 3.02% 2.36% 3.02% 2.36% 2.70% 2.70%
2018 2.52% 1.76% 2.52% 1.76% 2.26% 2.27%

  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 and SWEPCo)AEP)


Outstanding short-term debt was as follows:
    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
  
  September 30, 2019 December 31, 2018
  Outstanding Interest Outstanding Interest
Type of Debt Amount Rate (a) Amount Rate (a)
  (dollars in millions)
Securitized Debt for Receivables (b) $750.0
 2.56% $750.0
 2.16%
Commercial Paper 1,760.0
 2.36% 1,160.0
 2.96%
Total Short-term Debt $2,510.0
  
 $1,910.0
  


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


Credit Facilities


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


Securitized Accounts Receivables – AEP Credit (Applies to AEP)


AEP Credit has a receivables securitization agreement withthat provides a commitment of $750 million from bank conduits.conduits to purchase receivables and expires in July 2021. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries.  These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections.

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

Accounts receivable information for AEP Credit iswas as follows:
  Three Months Ended 
September 30,
 Nine Months Ended 
September 30,
  2019 2018 2019 2018
  (dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable 2.37% 2.27% 2.56% 2.06%
Net Uncollectible Accounts Receivable Written-Off $8.8
 $9.6
 $19.8
 $19.0
  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, 2019 December 31, 2018
  (in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $923.3
 $972.5
Short-term – Securitized Debt of Receivables 750.0
 750.0
Delinquent Securitized Accounts Receivable 43.9
 50.3
Bad Debt Reserves Related to Securitization 32.3
 27.5
Unbilled Receivables Related to Securitization 216.2
 281.4

  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.





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:
Company September 30, 2019 December 31, 2018
  (in millions)
APCo $95.4
 $133.3
I&M 156.2
 152.9
OPCo 337.5
 395.2
PSO 149.4
 109.7
SWEPCo 168.6
 150.3

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,
Company 2019 2018 2019 2018
  (in millions)
APCo $1.2
 $1.8
 $5.8
 $5.1
I&M 2.4
 2.5
 8.4
 6.8
OPCo 6.4
 7.2
 22.1
 18.8
PSO 2.0
 2.3
 6.2
 6.0
SWEPCo 1.9
 2.6
 7.9
 6.6

  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,
Company 2019 2018 2019 2018
  (in millions)
APCo $303.3
 $334.1
 $978.5
 $1,079.2
I&M 485.3
 498.4
 1,378.9
 1,401.7
OPCo 602.6
 695.2
 1,746.1
 2,046.9
PSO 451.5
 454.9
 1,118.7
 1,171.2
SWEPCo 480.7
 512.6
 1,247.0
 1,364.6


  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

14. VARIABLE INTEREST ENTITIES AND EQUITY METHOD INVESTMENTS

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

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a variable interest in a VIE.  A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently.

AEP holds ownership interests in businesses with varying ownership structures. Partnership interests and other variable interests are evaluated to determine if each entity is a VIE, and if so, whether or not the VIE should be consolidated into AEP’s financial statements. If an entity is determined not to be a VIE, or if the entity is determined to be a VIE and AEP is not deemed to be the primary beneficiary, the entity is accounted for under the equity method of accounting. The Variable Interest Entities note within the 2018 Annual Report should be read in conjunction with this report as this note only includes significant changes to AEP’s VIEs and equity method investments during 2019.

Consolidated Variable Interests Entities

Restoration Funding (Applies to AEP and AEP Texas)

Restoration Funding was formed for the sole purpose of issuing and servicing securitization bonds related to storm restoration of AEP Texas’ distribution system primarily due to damage caused by Hurricane Harvey. See “Texas Storm Cost Securitization” section of Note 4 for additional information. Management has concluded that AEP Texas is the primary beneficiary of Restoration Funding because AEP Texas has the power to direct the most significant activities of the VIE and AEP Texas’ equity interest could potentially be significant. Therefore, AEP Texas is required to consolidate Restoration Funding. The securitized bonds totaled $235 million as of September 30, 2019 and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Restoration Funding has securitized assets of $235 million as of September 30, 2019 which are presented separately on the face of the balance sheets. The securitized restoration assets represent the right to impose and collect Texas storm restoration costs from customers receiving electric transmission or distribution service from AEP Texas under recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to AEP Texas or any other AEP entity. AEP Texas acts as the servicer for Restoration Fundings’ securitized assets and remits all related amounts collected from customers to Restoration Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Restoration Fundings’ assets and liabilities on the balance sheets.




Apple Blossom Wind Holdings LLC and Black Oak Getty Wind Holdings LLC

In April 2019, AEP acquired an equity interest in Apple Blossom Wind Holdings LLC (Apple Blossom) and Black Oak Getty Wind Holdings LLC (Black Oak) (the Project Entities) as part of the purchase of Sempra Renewables LLC. Both of the Project Entities have long-term PPAs for 100% of their energy production. The Project Entities are tax equity partnerships with nonaffiliated noncontrolling interests to which a percentage of earnings, tax attributes and cash flows are allocated in accordance with the respective limited liability company agreements. Management has concluded that the Project Entities are VIEs and that AEP is the primary beneficiary based on its power as managing member to direct the activities that most significantly impact the Project Entities’ economic performance. In addition, AEP has not provided material financial or other support to the Project Entities that was not previously contractually required. As the primary beneficiary of the Project Entities, AEP consolidates the Project Entities into its financial statements. See the table below for the classification of Project Entities’ assets and liabilities on the balance sheets.

The nonaffiliated interests in the Project Entities is presented in Noncontrolling Interests on the balance sheets.  As of September 30, 2019, AEP recorded $129 million of Noncontrolling Interests related to the Project Entities in Equity on the balance sheets.

The Project Entities’ tax equity partnerships represent substantive profit-sharing arrangements. The method for attributing income and loss to the noncontrolling interests is a balance sheet approach referred to as the hypothetical liquidation at book value (HLBV) method. Under the HLBV method, the income and loss attributable to the noncontrolling interests reflect changes in the amounts the members would hypothetically receive at each balance sheet date under the liquidation provisions of the respective limited liability company agreements, assuming the net assets of these entities were liquidated at recorded amounts, after taking into account any capital transactions, such as contributions or distributions, between the entities and the members. For the three and nine months ended September 30, 2019, the HLBV method resulted in $0 and a loss of $4 million, respectively, allocated to Noncontrolling Interests.

Santa Rita East

In July 2019, AEP acquired a 75% interest in Santa Rita East Wind Energy Holdings, LLC and its wholly-owned subsidiary, Santa Rita East Wind Energy, LLC (collectively, Santa Rita East). Santa Rita East is a partnership whose sole purpose is to own and operate a new 302.4 MW wind generation facility in west Texas. Santa Rita East delivers energy and provides renewable energy credits through three long-term PPAs totaling 260 MWs. The remaining 42.4 MWs of energy are sold at wholesale into ERCOT. Management has concluded that Santa Rita East is a VIE and that AEP is the primary beneficiary based on its power as managing member of the partnership to direct the activities that most significantly impact Santa Rita East’s economic performance. As the primary beneficiary of Santa Rita East, AEP consolidates Santa Rita East into its financial statements. See the table below for the classification of Santa Rita’s assets and liabilities on the balance sheets.
AEP recognized $8 million of PTC attributable to Santa Rita East for the three and nine months ended September 30, 2019 which was recorded in Income Tax Expense (Benefit) on the statements of income. The nonaffiliated interest in Santa Rita East is presented in Noncontrolling Interests on the balance sheets. As of September 30, 2019, AEP recorded $118 million of Noncontrolling Interests related to Santa Rita East in Equity on the balance sheets.



American Electric Power Company, Inc. and Subsidiary Companies
Variable Interest Entities
September 30, 2019
      
 Registrant Subsidiary Other Consolidated VIEs
 AEP Texas Restoration Funding Apple Blossom and Black Oak Santa Rita East
 (in millions)
ASSETS     
Current Assets$1.2
 $5.7
 $17.0
Net Property, Plant and Equipment
 233.3
 466.6
Other Noncurrent Assets235.3
 12.5
 0.8
Total Assets$236.5
 $251.5
 $484.4
      
LIABILITIES AND EQUITY     
Current Liabilities$14.4
 $2.2
 $3.5
Noncurrent Liabilities220.9
 4.6
 7.5
Equity

1.2
 244.7
 473.4
Total Liabilities and Equity$236.5
 $251.5
 $484.4


Significant Equity Method Investments in Unconsolidated Entities

The equity method of accounting is used for equity investments where AEP exercises significant influence but does not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings or losses is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. AEP regularly monitors and evaluates equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature.

Sempra Renewables LLC

In April 2019, AEP acquired a 50% interest in five wind farms in multiple states as part of the purchase of Sempra Renewables LLC. The wind farms are joint ventures with BP Wind Energy who holds the other 50% interest. All five wind farms have long-term PPAs for 100% of their energy production. One of the jointly-owned wind farms has PPAs with I&M and OPCo for a portion of its energy production. Another jointly-owned wind farm has a PPA with SWEPCo for a portion of its energy production. The joint venture wind farms are not considered VIEs and AEP is not required to consolidate them as AEP does not have a controlling financial interest. However, AEP is able to exercise significant influence over the wind farms and therefore applies the equity method of accounting. As of September 30, 2019, AEP’s investment in the five joint venture wind farms was $389 million. The investment includes amounts recognized in AOCI related to interest rate cash flow hedges. The investment is comprised of a historical investment of $417 million plus a basis difference of $(19) million. AEP’s equity earnings associated with the five joint venture wind farms were losses of $3 million and $6 million for the three and nine months ended September 30, 2019, respectively. AEP recognized $7 million and $21 million of PTC attributable to the joint venture wind farms for the three and nine months ended September 30, 2019, respectively, which was recorded in Income Tax Expense (Benefit) on the statements of income.



ETT

ETT designs, acquires, constructs, owns and operates certain transmission facilities in ERCOT. Berkshire Hathaway Energy, a nonaffiliated entity, holds a 50% membership interest in ETT, AEP Transmission Holdco holds a 49.5% interest in ETT and AEP Transmission Partner held the remaining 0.5% membership interest in ETT. In July 2019, AEP Transmission Partner was merged into AEP Transmission Holdco, increasing AEP Transmission Holdco’s interest in ETT to 50%. As a result, AEP, through its wholly-owned subsidiary, holds a 50% membership interest in ETT. As of September 30, 2019 and December 31, 2018, AEP’s investment in ETT was $693 million and $666 million, respectively. AEP’s equity earnings associated with ETT were $16 million and $15 million for the three months ended September 30, 2019 and 2018, respectively. AEP’s equity earnings associated with ETT were $49 million and $46 million for the nine months ended September 30, 2019 and 2018, respectively.


15. 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, 2019
  Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other Reconciling Adjustments AEP Consolidated
  (in millions)
Retail Revenues:              
Residential Revenues $1,060.2
 $588.0
 $
 $
 $
 $
 $1,648.2
Commercial Revenues 612.5
 290.9
 
 
 
 
 903.4
Industrial Revenues 566.0
 99.3
 
 
 
 1.5
 666.8
Other Retail Revenues 49.2
 10.6
 
 
 
 
 59.8
Total Retail Revenues 2,287.9
 988.8
 
 
 
 1.5
 3,278.2
               
Wholesale and Competitive Retail Revenues:              
Generation Revenues (a) 231.3
 
 
 77.1
 
 (34.2) 274.2
Transmission Revenues (b) 77.8
 110.9
 269.4
 
 
 (217.2) 240.9
Marketing, Competitive Retail and Renewable Revenues 
 
 
 415.4
 
 0.5
 415.9
Total Wholesale and Competitive Retail Revenues 309.1
 110.9
 269.4
 492.5
 
 (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 Customers 2,644.3
 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) 
 
 (16.8) (11.4)
Other Revenues (c) 
 38.9
 
 26.4
 (11.2) (39.8) 14.3
Total Other Revenues 1.2
 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.




  Three Months Ended September 30, 2018
  Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other Reconciling Adjustments AEP Consolidated
  (in millions)
Retail Revenues:              
Residential Revenues $1,048.7
 $612.2
 $
 $
 $
 $
 $1,660.9
Commercial Revenues 612.8
 330.9
 
 
 
 
 943.7
Industrial Revenues 578.8
 128.8
 
 
 
 
 707.6
Other Retail Revenues 49.1
 10.7
 
 
 
 
 59.8
Total Retail Revenues (a) 2,289.4
 1,082.6
 
 
 
 
 3,372.0
               
Wholesale and Competitive Retail Revenues:              
Generation Revenues (b) 224.2
 
 
 115.1
 
 (98.5) 240.8
Transmission Revenues (c) 72.8
 88.0
 201.4
 
 
 (241.6) 120.6
Marketing, Competitive Retail and Renewable Revenues 
 
 
 399.1
 
 
 399.1
Total Wholesale and Competitive Retail Revenues 297.0
 88.0
 201.4
 514.2
 
 (340.1) 760.5
               
Other Revenues from Contracts with Customers (e) 40.3
 69.9
 0.7

12.7
 21.5
 49.5
 194.6
               
Total Revenues from Contracts with Customers 2,626.7
 1,240.5
 202.1
 526.9
 21.5
 (290.6) 4,327.1
               
Other Revenues:              
Alternative Revenues (d) 0.2
 (37.9) (14.9) 
 
 
 (52.6)
Other Revenues (e) 9.8
 8.9
 
 (5.3) 2.2
 43.0
 58.6
Total Other Revenues 10.0
 (29.0) (14.9) (5.3) 2.2
 43.0
 6.0
               
Total Revenues $2,636.7
 $1,211.5
 $187.2
 $521.6
 $23.7
 $(247.6) $4,333.1

(a)2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $35 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $147 million. The remaining affiliated amounts were immaterial.
(d)The alternative revenue for Transmission and Distribution Utilities was primarily the $48 million reduction in revenue relating to the Ohio Tax Reform settlement.
(e)Amounts include affiliated and nonaffiliated revenues.


  Three Months Ended September 30, 2019
  AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
  (in millions)
Retail Revenues:              
Residential Revenues $192.0
 $
 $315.7
 $198.2
 $395.6
 $231.9
 $222.9
Commercial Revenues 110.6
 
 147.2
 138.3
 180.5
 122.2
 144.3
Industrial Revenues 32.2
 
 152.2
 138.7
 67.1
 84.1
 92.3
Other Retail Revenues 7.5
 
 18.5
 1.9
 3.1
 24.9
 2.3
Total Retail Revenues 342.3
 
 633.6
 477.1
 646.3
 463.1
 461.8
               
Wholesale Revenues:              
Generation Revenues (a) 
 
 70.4
 102.1
 
 21.1
 50.7
Transmission Revenues (b) 97.7
 256.4
 26.2
 6.4
 13.7
 (3.4) 30.0
Total Wholesale Revenues 97.7
 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 Customers 448.2
 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
 
 
 
 (2.8) 
 
Total Other Revenues 41.1
 (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 Kingsport. 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 the barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.


  Three Months Ended September 30, 2018
  AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
  (in millions)
Retail Revenues:              
Residential Revenues $178.8
 $
 $320.9
 $207.4
 $433.5
 $220.8
 $214.1
Commercial Revenues 107.9
 
 155.1
 138.0
 222.9
 119.9
 140.4
Industrial Revenues 32.1
 
 157.6
 150.2
 96.3
 82.4
 89.6
Other Retail Revenues 7.4
 
 19.2
 1.7
 3.3
 24.5
 2.2
Total Retail Revenues (a) 326.2
 
 652.8
 497.3
 756.0
 447.6
 446.3
               
Wholesale Revenues:              
Generation Revenues (b) 
 
 74.5
 93.6
 
 12.5
 53.2
Transmission Revenues (c) 73.6
 206.6
 20.9
 6.2
 14.8
 13.5
 29.5
Total Wholesale Revenues 73.6
 206.6
 95.4
 99.8
 14.8
 26.0
 82.7
               
Other Revenues from Contracts with Customers (d) 7.5
 0.2
 15.9
 22.4
 (29.9) 5.5
 6.6
               
Total Revenues from Contracts with Customers 407.3
 206.8
 764.1
 619.5
 740.9
 479.1
 535.6
               
Other Revenues:              
Alternative Revenues (e) (1.0) (12.4) (1.2) 1.5
 (36.9) 2.3
 (0.3)
Other Revenues (f) 27.1
 
 (0.9) 8.7
 74.3
 
 
Total Other Revenues 26.1
 (12.4) (2.1) 10.2
 37.4
 2.3
 (0.3)
               
Total Revenues $433.4
 $194.4
 $762.0
 $629.7
 $778.3
 $481.4
 $535.3

(a)2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $30 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $146 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $17 million primarily relating to the barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(e)The alternative revenue for OPCo was primarily the $48 million reduction in revenue relating to the Ohio Tax Reform settlement.
(f)Amounts include affiliated and nonaffiliated revenues.



  Nine Months Ended September 30, 2019
  Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other Reconciling Adjustments AEP Consolidated
  (in millions)
Retail Revenues:              
Residential Revenues $2,797.6
 $1,609.1
 $
 $
 $
 $
 $4,406.7
Commercial Revenues 1,641.2
 889.4
 
 
 
 
 2,530.6
Industrial Revenues 1,647.3
 332.6
 
 
 
 
 1,979.9
Other Retail Revenues 136.1
 32.8
 
 
 
 
 168.9
Total Retail Revenues 6,222.2
 2,863.9
 
 
 
 
 9,086.1
               
Wholesale and Competitive Retail Revenues:              
Generation Revenues (a) 661.9
 
 
 282.0
 
 (105.5) 838.4
Transmission Revenues (b) 215.4
 324.0
 814.3
 
 
 (603.6) 750.1
Marketing, Competitive Retail and Renewable Revenues 
 
 
 1,088.5
 
 0.5
 1,089.0
Total Wholesale and Competitive Retail Revenues 877.3
 324.0
 814.3
 1,370.5
 
 (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 Customers 7,228.3
 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) 
 
 (60.3) (113.1)
Other Revenues (c) 
 117.3
 
 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.


  Nine Months Ended September 30, 2018
  Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other Reconciling Adjustments AEP Consolidated
  (in millions)
Retail Revenues:              
Residential Revenues $2,906.9
 $1,711.1
 $
 $
 $
 $
 $4,618.0
Commercial Revenues 1,672.7
 945.2
 
 
 
 
 2,617.9
Industrial Revenues 1,676.1
 381.5
 
 
 
 
 2,057.6
Other Retail Revenues 139.4
 31.8
 
 
 
 
 171.2
Total Retail Revenues (a) 6,395.1
 3,069.6
 
 
 
 
 9,464.7
               
Wholesale and Competitive Retail Revenues:              
Generation Revenues (b) 686.5
 
 
 413.4
 
 (155.2) 944.7
Transmission Revenues (c) 208.4
 272.6
 633.9
 
 
 (520.7) 594.2
Marketing, Competitive Retail and Renewable Revenues 
 
 
 1,040.2
 
 
 1,040.2
Total Wholesale and Competitive Retail Revenues 894.9
 272.6
 633.9
 1,453.6
 
 (675.9) 2,579.1
               
Other Revenues from Contracts with Customers (e) 121.8
 165.1
 11.1
 15.0
 64.8
 1.8
 379.6
               
Total Revenues from Contracts with Customers 7,411.8
 3,507.3
 645.0
 1,468.6
 64.8
 (674.1) 12,423.4
               
Other Revenues:              
Alternative Revenues (d) (19.2) (48.3) (39.8) 
 
 
 (107.3)
Other Revenues (e) 1.1
 51.9
 
 18.8
 6.7
 
 78.5
Total Other Revenues (18.1) 3.6
 (39.8) 18.8
 6.7
 
 (28.8)
               
Total Revenues $7,393.7
 $3,510.9
 $605.2
 $1,487.4
 $71.5
 $(674.1) $12,394.6

(a)2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $87 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $444 million. The remaining affiliated amounts were immaterial.
(d)The alternative revenue for Transmission and Distribution Utilities was primarily the $48 million reduction in revenue relating to the Ohio Tax Reform settlement.
(e)Amounts include affiliated and nonaffiliated revenues.


  Nine Months Ended September 30, 2019
  AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
  (in millions)
Retail Revenues:              
Residential Revenues $454.9
 $
 $944.7
 $558.8
 $1,155.5
 $519.6
 $503.7
Commercial Revenues 314.5
 
 421.5
 371.4
 573.7
 304.3
 371.1
Industrial Revenues 98.8
 
 444.3
 411.9
 233.9
 238.1
 257.2
Other Retail Revenues 22.7
 
 56.5
 5.4
 9.8
 63.1
 6.7
Total Retail Revenues 890.9
 
 1,867.0
 1,347.5
 1,972.9
 1,125.1
 1,138.7
               
Wholesale Revenues:              
Generation Revenues (a) 
 
 200.1
 327.4
 
 35.5
 152.7
Transmission Revenues (b) 282.0
 775.3
 77.6
 18.8
 42.0
 21.9
 78.0
Total Wholesale Revenues 282.0
 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 Customers 1,195.8
 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
 
 
 
 3.8
 
 
Total Other Revenues 122.2
 (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 Kingsport. 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.


  Nine Months Ended September 30, 2018
  AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
  (in millions)
Retail Revenues:              
Residential Revenues $453.6
 $
 $1,017.3
 $559.4
 $1,258.4
 $531.4
 $512.4
Commercial Revenues 310.8
 
 442.3
 369.8
 633.2
 309.3
 372.6
Industrial Revenues 94.8
 
 457.3
 428.0
 287.4
 228.7
 254.0
Other Retail Revenues 21.7
 
 57.6
 5.4
 9.8
 65.2
 6.4
Total Retail Revenues (a) 880.9
 
 1,974.5
 1,362.6
 2,188.8
 1,134.6
 1,145.4
               
Wholesale Revenues:              
Generation Revenues (b) 
 
 194.1
 349.7
 
 26.7
 168.8
Transmission Revenues (c) 229.6
 612.9
 60.2
 16.9
 42.8
 29.4
 77.3
Total Wholesale Revenues 229.6
 612.9
 254.3
 366.6
 42.8
 56.1
 246.1
               
Other Revenues from Contracts with Customers (d) 21.8
 8.7
 42.2
 71.0
 51.3
 14.6
 18.0
               
Total Revenues from Contracts with Customers 1,132.3
 621.6
 2,271.0
 1,800.2
 2,282.9
 1,205.3
 1,409.5
               
Other Revenues:              
Alternative Revenues (e) (1.1) (35.4) (20.7) (4.0) (47.2) 11.2
 2.3
Other Revenues (f) 62.1
 
 (0.9) 
 82.3
 
 
Total Other Revenues 61.0
 (35.4) (21.6) (4.0) 35.1
 11.2
 2.3
               
Total Revenues $1,193.3
 $586.2
 $2,249.4
 $1,796.2
 $2,318.0
 $1,216.5
 $1,411.8

(a)2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $100 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $448 million. The remaining affiliated amounts were immaterial.
(d)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.
(e)The alternative revenue for OPCo was primarily the $48 million reduction in revenue relating to the Ohio Tax Reform settlement.
(f)Amounts include affiliated and nonaffiliated revenues.




Fixed Performance Obligations

The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of September 30, 2019. 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.
Company 2019 2020-2021 2022-2023 After 2023 Total
  (in millions)
AEP $252.7
 $209.7
 $160.9
 $285.5
 $908.8
AEP Texas 96.8
 
 
 
 96.8
AEPTCo 225.8
 
 
 
 225.8
APCo 36.4
 32.5
 25.5
 11.6
 106.0
I&M 7.2
 8.9
 8.8
 4.4
 29.3
OPCo 17.8
 7.5
 
 
 25.3
PSO 4.3
 
 
 
 4.3
SWEPCo 9.8
 
 
 
 9.8


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, 2019 and December 31, 2018.

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, 2019 and December 31, 2018.

Accounts Receivable from Contracts with Customers

Accounts receivable from contracts with customers are presented on the Registrants’ balance sheets within the Accounts Receivable - Customers line item. The Registrants’ 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, 2019 and December 31, 2018. See “Securitized Accounts Receivable - AEP Credit” section of Note 13 for additional information related to AEP Credit’s securitized accounts receivable.

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:
Company September 30, 2019 December 31, 2018
  (in millions)
AEPTCo $69.9
 $58.6
APCo 41.4
 52.5
I&M 28.0
 35.3
OPCo 29.2
 46.1
PSO 10.3
 12.4
SWEPCo 17.8
 16.3





CONTROLS AND PROCEDURES


During the third quarter of 2017,2019, 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, 2017,2019, 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 noThe only 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 20172019 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting, relates to the Registrants’ conversion of work management, asset management, and source to settle (procurement, supply chain, and accounts payable) business processes to a newly implemented third-party software solution. In connection with this conversion, management will continue to evaluate and monitor the Registrants’ internal controls over financial reporting to ensure controls remain effective. There were no other changes in the Registrants’ internal control over financial reporting during the quarter ended September 30, 2019, that have materially affected, or are reasonably likely to materially affect, the Registrants’ internal control over financial reporting.






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 2016 Annual Report on Form 10-K andfor the AEPTCo 2016 Annual Report included within AEPTCo’s Registration Statementyear ended December 31, 2018 includes a detailed discussion of risk factors.  As of September 30, 2017,2019, there have been no material changes to the risk factors previously disclosed in AEPTCo’s Registration Statement. As of September 30, 2017, the risk factor appearing in AEP’s 20162018 Annual Report under the heading set forth below is supplemented and updated as follows:on Form 10-K.

AEP is exposed to nuclear generation risk. (Applies to AEP and I&M)

Through I&M, AEP owns the Cook Plant.  It consists of two nuclear generating units for a rated capacity of 2,278 MWs, or about 7% of the generating capacity in the AEP System.  AEP 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 to an adverse incident/event resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials such as spent nuclear fuel.
Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations.
Uncertainties with respect to contingencies and assessment amounts triggered by a loss event (federal law requires owners 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.  In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment 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 anywhere 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 of that investment and retirement costs.  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 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. In the 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.

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, it could reduce future net income and cash flows and impact financial condition.

If the FERC were to lower the rate of return it has authorized for AEP’s transmission investments and facilities, or if one or more states were to successfully limit FERC jurisdiction on recovery of costs on transmission investment and its return, it could reduce future net income and cash flows and negatively impact financial condition.


Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds


None


Item 3.  Defaults Upon Senior Securities


None


Item 4.  Mine Safety Disclosures


The Federal Mine Safety and Health Act of 1977 (Mine Act) imposes stringent health and safety standards on various mining operations. The Mine Act and its related regulations affect numerous aspects of mining operations, including training of mine personnel, mining procedures, equipment used in mine emergency procedures, mine plans and other matters. SWEPCo, through its ownership of DHLC, a wholly-owned lignite mining subsidiary of SWEPCo, is subject to the provisions of the Mine Act.


The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act. Exhibit 95 “Mine Safety Disclosure Exhibit” contains the notices of violation and proposed assessments received by DHLC under the Mine Act for the quarter ended September 30, 2017.2019.



Item 5.  Other Information

None

Item 5.  Other Information

None



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:
AEPTCo‡ File No. 333-217143
*4.3Company Order and Officer’s Certificate, between AEP Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee, dated September 11, 2019, establishing the terms of the Series L Notes

The exhibits designated with an (X) in the table below are being filed on behalf of the Registrants.
Exhibit Description AEP
AEP
Texas
 AEPTCo APCo I&M OPCo PSO SWEPCo
1210.1 Computation of Consolidated Ratio of Earnings to Fixed ChargesAEP System Incentive Compensation Deferral Plan Amended and Restated effective June 1, 2019  
10.2AEP Aircraft Timesharing Agreement dated October 1, 2019 between American Electric Power Service Corporation and Nicholas K. Akins     
31(a) Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002       
31(b) Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002       
32(a) Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code       
32(b) Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code       
95 Mine Safety Disclosures             
101.INS XBRL Instance Document XXXXXXXThe instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCH XBRL Taxonomy Extension SchemaX X X X X X X X
101.CAL XBRL Taxonomy Extension Calculation Linkbase X X X X X X XX
101.DEF XBRL Taxonomy Extension Definition LinkbaseX X X X X X X X
101.LAB XBRL Taxonomy Extension Label Linkbase X X X X X X XX
101.PRE XBRL Taxonomy Extension Presentation Linkbase X X X X X X XX
104Cover Page Interactive Data FileFormatted as Inline XBRL and contained in Exhibit 101.




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, 201724, 2019


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