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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, 20182019
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
333-221643 AEP TEXAS INC. (A Delaware Corporation) 51-0007707
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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit such files).
YesxNo¨☐
Indicate by check mark whether American Electric Power Company, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
  
Large Accelerated filer
xAccelerated filer¨☐Non-accelerated filer¨☐
       
Smaller reporting company¨
☐
Emerging growth company¨
☐   
Indicate by check mark whether AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, non-accelerated filers, smaller reporting companies, or emerging growth companies.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
  
Large Accelerated filer¨
☐Accelerated filer¨☐Non-accelerated filerx
       
Smaller reporting company¨
☐
Emerging growth company¨
☐   
If an emerging growth company, indicate by check mark if the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.¨
 ☐
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).
Yes¨☐Nox
AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.









 
Number of shares
of common stock
outstanding of the
Registrants as of
 October 25, 201824, 2019
  
American Electric Power Company, Inc.493,108,827493,951,812

 ($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, 20182019
     
    Page
    Number
Glossary of Terms
i
     
Forward-Looking Information
v
     
Part I. FINANCIAL INFORMATION 
     
 Items 1, 2, 3 and 4 - Financial Statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosures About Market Risk, and Controls and Procedures: 
     
American Electric Power Company, Inc. and Subsidiary Companies: 
 Management’s Discussion and Analysis of Financial Condition and Results of Operations
1
 Condensed Consolidated Financial Statements
5444
     
AEP Texas Inc. and Subsidiaries: 
 Management’s Narrative Discussion and Analysis of Results of Operations
6151
 Condensed Consolidated Financial Statements
6656
     
AEP Transmission Company, LLC and Subsidiaries: 
 Management’s Narrative Discussion and Analysis of Results of Operations
7363
 Condensed Consolidated Financial Statements
7665
     
Appalachian Power Company and Subsidiaries: 
 Management’s Narrative Discussion and Analysis of Results of Operations
8271
Condensed Consolidated Financial Statements
76
Indiana Michigan Power Company and Subsidiaries:
Management’s Narrative Discussion and Analysis of Results of Operations
83
 Condensed Consolidated Financial Statements
87
     
Indiana MichiganOhio Power Company and Subsidiaries: 
 Management’s Narrative Discussion and Analysis of Results of Operations
94
 Condensed Consolidated Financial Statements
99
     
Ohio PowerPublic Service Company and Subsidiaries:of Oklahoma: 
 Management’s Narrative Discussion and Analysis of Results of Operations
106
 Condensed Consolidated Financial Statements
111
Public Service Company of Oklahoma:
Management’s Narrative Discussion and Analysis of Results of Operations
118
Condensed Financial Statements
123109
     
Southwestern Electric Power Company Consolidated: 
 Management’s Narrative Discussion and Analysis of Results of Operations
130116
 Condensed Consolidated Financial Statements
135120
     
Index of Condensed Notes to Condensed Financial Statements of Registrants
141126
     
Controls and Procedures
247220




Part II.  OTHER INFORMATION 
     
 Item 1.  Legal Proceedings
248221
 Item 1A.  Risk Factors
248221
 Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds
249221
 Item 3.  Defaults Upon Senior Securities
249221
 Item 4.  Mine Safety Disclosures
249221
 Item 5.  Other Information
250221
 Item 6.  Exhibits:Exhibits
250222
Exhibit 4
Exhibit 10
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  
251223
     
     
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 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.
AEPEPAEP Wind Holdings LLC AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketingAcquired in April 2019 as Sempra Renewables LLC, develops, owns and trading, hedging activities, asset management and commercial and industrial salesoperates, or holds interests in, wind generation facilities in the deregulated Ohio and Texas markets.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, is an intermediate holding company that owns seven wholly-owned transmission companies.the State Transcos.
AEPTCo Parent AEP Transmission Company, LLC, the holding 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.
ALJ Administrative 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.
ARAM Average Rate Assumption Method, an IRS approved method used to calculate the reversal of Excess ADIT for ratemakingrate-making purposes.
ASCARO Accounting Standard Codification.Asset Retirement Obligations.
ASU Accounting Standards Update.
CAA Clean Air Act.
CLECOCentral 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 Plant A generation plant consisting of three coal-fired generating units totaling 1,695 MW located in Conesville, Ohio. The plant is jointly ownedjointly-owned by AGR and a non-affiliate entity.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 VII, DCC Fuel VIII, DCC Fuel IX, DCC Fuel X, DCC Fuel XI, DCC Fuel XII and DCC Fuel XIIXIII, consolidated variable interest entitiesVIEs formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
Desert SkyDesert Sky Wind Farm, a 168 MW wind electricity generation facility located on Indian Mesa in Pecos County, Texas.


i




Term Meaning
   
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.
ESP Electric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO.
ETREffective tax rates.
ETT Electric Transmission Texas, LLC, an equity interest joint venture between AEP Transmission Holdco and Berkshire Hathaway Energy Company formed to own and operate electric transmission facilities in ERCOT.
Excess ADIT Excess 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 Settlement In 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.
MATSMercury and Air Toxic Standards.
MISO Midcontinent Independent System Operator.
MMBtu Million British Thermal Units.
MPSC Michigan Public Service Commission.
MTM Mark-to-Market.
MW Megawatt.
MWh Megawatthour.Megawatt-hour.
NAAQSNational Ambient Air Quality Standards.
Nonutility Money Pool Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
North Central Wind Energy FacilitiesA 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.
OATTOpen Access Transmission Tariff.
OCCCorporation Commission of the State of Oklahoma.


ii




Term Meaning
   
OATTOpen Access Transmission Tariff.
OCCCorporation 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 Station A single unit coal-fired generation plant totaling 650 MW located in Vernon, Texas. The plant is jointly ownedjointly-owned by AEP Texas, PSO and certain non-affiliatednonaffiliated entities.
OPCo Ohio Power Company, an AEP electric utility subsidiary.
OPEB Other Postretirement Benefit Plans.Benefits.
OSS Off-SystemOff-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.
Racine A generation plant consisting of two hydroelectric generating units totaling 47.5 MWMWs 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.
ROE Return on Equity.
RPM Reliability 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 only electric utilities, each of which isare geographically aligned with AEP’s existing utility operating companies.
SWEPCo Southwestern Electric Power Company, an AEP electric utility subsidiary.
Tax Reform On 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.

iii


TermMeaning
Transition Funding AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated 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.
TrentTrent Wind Farm, a 154 MW wind electricity generation facility located between Abilene and Sweetwater in West Texas.
Turk Plant John W. Turk, Jr. Plant, a 600 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.
UMWAUnited Mine Workers of America.
UPA Unit Power Agreement.
Utility Money Pool Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
VIE Variable Interest Entity.
Virginia SCC Virginia State Corporation Commission.
Wind Catcher Project Wind Catcher Energy Connection Project, a joint PSO and SWEPCo project that 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.


iv




FORWARD-LOOKING INFORMATION


This report made by the Registrants contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.  Many forward-looking statements appear in “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the 20172018 Annual Report, but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook.  These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected.  Forward-looking statements in this document are presented as of the date of this document.  Except to the extent required by applicable law, management undertakes no obligation to update or revise any forward-looking statement.  Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:
Ÿ•Economic growth or contraction within and changesChanges in economic conditions, electric market demand and demographic patterns in AEP service territories.
Ÿ•Inflationary or deflationary interest rate trends.
Ÿ•Volatility in the financial markets, particularly developments affecting the availability or cost of capital to finance new capital projects and refinance existing debt.
Ÿ•The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.
Ÿ•Electric load and customer growth.Decreased demand for electricity.
Ÿ•Weather conditions, including storms and drought conditions, and the ability to recover significant storm restoration costs.
Ÿ•The cost of fuel and its transportation, the creditworthiness and performance of fuel suppliers and transporters and the cost of storing and disposing of used fuel, including coal ash and spent nuclear fuel.SNF.
Ÿ•AvailabilityThe availability of fuel and necessary generation capacity and the performance of generation plants and the availability of fuel, including processed nuclear fuel, parts and service from reliable vendors.plants.
Ÿ•The ability to recover fuel and other energy costs through regulated or competitive electric rates.
Ÿ•The ability to build or acquire renewable generation, transmission lines and facilities (including the ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs.
Ÿ•New legislation, litigation and government regulation, including oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matterPM and other substances that could impact the continued operation, cost recovery and/or profitability of generation plants and related assets.
Ÿ•Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including coal ash and nuclear fuel.
Ÿ•Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance and Excess ADIT.compliance.
Ÿ•Resolution of litigation.
Ÿ•The ability to constrain operation and maintenance costs.
Ÿ•Prices and demand for power generated and sold at wholesale.
Ÿ•Changes in technology, particularly with respect to energy storage and new, developing, alternative or distributed sources of generation.
Ÿ•The ability to recover through rates any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives.
Ÿ•Volatility and changes in markets for capacity and electricity, coal and other energy-related commodities, particularly changes in the price of natural gas.
Ÿ•Changes in utility regulation and the allocation of costs within regional transmission organizations,RTOs including ERCOT, PJM and SPP.
Ÿ•Changes in the creditworthiness of the counterparties with contractual arrangements, including participants in the energy trading market.
Ÿ•Actions of rating agencies, including changes in the ratings of debt.
Ÿ•The impact of volatility in the capital markets on the value of the investments held by the pension, other postretirement benefit plans,OPEB, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements.
•Accounting standards periodically issued by accounting standard-setting bodies.


v




ŸAccounting pronouncements periodically issued by accounting standard-setting bodies.
ŸImpact of federal tax reform on customer rates, income tax expense and cash flows.
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 20172018 Annual Report and in Part II of this report.


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


vi








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


EXECUTIVE OVERVIEW


Customer Demand


AEP’s weather-normalized retail sales volumes for the third quarter of 2018 increased by 0.3%2019 were flat compared to the third quarter of 2017.2018. AEP’s third quarter 20182019 industrial sales increaseddecreased by 2.4%1.1% compared to the third quarter of 2017.2018. The growthdecline in industrial sales was spread across most operating companies and driven by growth inmost industries outside of the oil and gas sector. Weather-normalized residential sales decreased 0.8%increased 0.7% while weather-normalized commercial sales increased by 0.4% in the third quarter of 20182019 compared to the third quarter of 2017. Weather-normalized commercial sales decreased by 0.5% in the third quarter of 2018 compared to the third quarter of 2017.2018.


AEP’s weather-normalized retail sales volumes for the nine months ended September 30, 2018 increased2019 decreased by 1.2%0.6% compared to the nine months ended September 30, 2017.2018. AEP’s industrial sales volumes for the nine months ended September 30, 2018 increased 2.6%2019 decreased 1.4% compared to the nine months ended September 30, 2017.2018. 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 increaseddecreased 0.7% and 0.2%, respectively, for the nine months ended September 30, 20182019 compared to the nine months ended September 30, 2017.2018, while weather-normalized residential sales increased by 0.2%.

Regulatory Matters

AEP’s public utility subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.  Depending on the outcomes, these rate and regulatory proceedings can have a material impact on results of operations, cash flows and possibly financial condition. AEP is currently involved in the following key proceedings. See Note 4 - Rate Matters for additional information.
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.



Wind Catcher Project
•
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.

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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.

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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 2017, PSO2019, 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 SWEPCo submitted filings with the OCC, LPSC, APSCrenewable mandates no later than 2020 and PUCT requesting various regulatory approvals neededafter 2026, respectively.  The bill provides for the companiesrecovery 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 proceed withall electric distribution utilities on a non-bypassable basis.  OPCo’s Inter-Company Power Agreement for OVEC terminates in June 2040. To the Wind Catcher Project. The Wind Catcher Project includedextent that OPCo is unable to recover the acquisitioncosts of renewable energy contracts on a wind generation facility, totaling approximately 2,000 MWsbypassable basis by the end of wind generation,2032, recover costs of OVEC after 2030 or fully recover energy efficiency costs through 2020 it could reduce future net income and the construction of a generation interconnection tie-line totaling approximately 350 miles. Total investment for the project was estimated to be $4.5 billioncash flows and would serve both retail and FERC wholesale load. PSO and SWEPCo would have had 30% and 70% ownership shares, respectively, in these assets.impact financial condition.

In July 2018,
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 PUCT denied SWEPCo’s requestRegistrants’ 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 a Certificate of Public Convenience and Necessity to proceed with the Wind Catcher Project. PSO and SWEPCo subsequently cancelled the Wind Catcher Project.additional information.


Other 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


The growth of AEP’s renewable generation portfolio reflects the company’s strategy to diversify generation resources to provide clean energy options to customers that meet both their energy and capacity needs.


Contracted Renewable Generation Facilities


AEP continues to develop its renewable portfolio within the Generation & Marketing segment.  Activities include working directly with wholesale and large retail customers to provide tailored solutions based upon market knowledge, technology innovations and deal structuring which may include distributed solar, wind, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other forms of cost reducing energy technologies.  The Generation & Marketing segment also develops and/or acquires large scale renewable generation projects that are backed with long-term contracts.  contracts with creditworthy counterparties.

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, 2018,2019, subsidiaries within AEP’s Generation & Marketing segment havehad approximately 4001,396 MWs of contracted renewable generation projects in operation.in-service.  In addition, as of September 30, 2018,2019, these subsidiaries havehad approximately 1054 MWs of new renewable generation projects under construction with total estimated capital costs of $27$67 million related to these projects.



In January 2018, AEP admitted a nonaffiliate as a member of Desert Sky Wind Farm LLC and Trent Wind Farm LLC (collectively “the LLCs”) to own and repower Desert Sky and Trent.  The nonaffiliated member contributed full turbine sets to each project in exchange for a 20.1% interest in the LLCs. AEP has contributed substantially all of its cash equity capital commitment of $235 million related to its 79.9% share of the LLCs, or 257 MW. The wind farms are fully repowered and in-service as of September 30, 2018. AEP is subject to a put and a call option after certain conditions are met, either of which would liquidate the nonaffiliated member’s interest. See Note 13 - Variable Interest Entities for additional information.


Regulated Renewable Generation Facilities

In July 2017, APCo submitted filings with the Virginia SCC and the WVPSC requesting regulatory approval to acquire two wind generation facilities totaling approximately 225 MWs of wind generation. In April 2018, the Virginia SCC denied APCo’s application to acquire the two wind generation facilities. APCo filed a petition for reconsideration with the Virginia SCC, which was denied. In May 2018, the WVPSC also denied APCo’s application to acquire the two wind 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. TheIn January 2019, PUCO staff recommended that the PUCO reject OPCo’s request. If approved, the solar generation facilities if approved, are expected to be in-serviceoperational by the end of 2021.

Federal Tax Reform


In December 2017, Tax Reform legislation was signed into law. Tax Reform includes significant changes to the Internal Revenue Code of 1986, as amended,July 2019, PSO and had a material impact on the Registrants’ financial statements in the reporting period of its enactment. Tax Reform lowered the corporate federal income tax rate from 35% to 21%. Tax Reform provisions related to regulated public utilities generally allowSWEPCo submitted filings before their respective commissions for the continued deductibilityapproval to acquire the North Central Wind Energy Facilities, comprised of interest expense, impact bonus depreciationthree 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, which will cost approximately $2 billion.  Two wind facilities, totaling 1,286 MWs, would qualify for certain property acquired and placed in service after September 27, 2017 and continue certain rate normalization requirements for accelerated depreciation benefits.

The mechanism and time period to provide the benefits80% of Tax Reform to customers varies by jurisdiction. Tax Reform did not have a material impact on net income in the third quarter of 2018 and is not expected to have a material impact on future net income. However, the Registrants will experience a decrease in future cash flows primarily due to the elimination of bonus depreciation, the reduction in the federal tax rate from 35% to 21% and the flow back of Excess ADIT. Further, the Registrants expect that access to capital markets will be sufficient to satisfy any liquidity needs that result from any such decrease in future cash flows.

Provisional Amounts

PTC with year-end 2021 in-service dates.  The Registrants applied Staff Accounting Bulletin 118 (SAB 118), issued by the SEC staff in December 2017, and made reasonable estimatesthird wind facility (199 MWs) would qualify for the measurement and accounting100% of the effects of Tax Reform which are reflected in the financial statements as provisional amounts based on the best information available. While the Registrants were able to make reasonable estimates of the impact of Tax Reform in 2017, the final impact may differ from the recorded provisional amounts to the extent refinements are made to the estimated cumulative differences or asPTC with a result of additional guidance or technical corrections that mayyear-end 2020 in-service date. The acquisition can be issued by the IRS that may impact management’s interpretation and assumptions utilized. The Registrants expect to complete the analysis of the provisional items during the fourth quarter of 2018.

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

State utility commissions have issued orders or instructions requiring public utilities, including the Registrants, to record liabilities to reflect the impact of the reduction in the corporate federal income tax rate in excess of the enacted corporate federal income tax rate of 21% beginning in 2018. As described in Note 4 - Rate Matters, certain Registrants


have received state utility commission orders and have reflected the lower corporate federal income tax rate in current customer rates. As of September 30, 2018, AEP has recorded estimated provisions for revenue refunds totaling $150 million as a result of the reduction in the corporate federal tax rate.

Excess ADIT - Pending Rate Reductions

As of September 30, 2018, the Registrants have approximately $4.3 billion of Excess ADIT, as well as an incremental liability of $1.1 billion to reflect the $4.3 billion Excess ADIT on a pretax basis, presented in Regulatory Liabilities and Deferred Investment Tax Credits on the balance sheets.  The Excess ADIT is reflected on a pretax basis to appropriately contemplate future tax consequences in the periods when the regulatory liability is settled.  As of September 30, 2018, approximately $3.4 billion of the Excess ADIT relates to temporary differences associated with certain depreciable propertyscaled, subject to rate normalization requirements.

As reflected in the Registrants’ respective estimated annual ETRcommercial limitation, to align with individual state resource needs and approvals. Hearings are scheduled for 2018, AEP’s regulated public utilities began amortizing the Excess ADIT associated with certain depreciable property subject to rate normalization requirements using the ARAM during the first quarter of 2018. As a result of state utility commission orders or instructions, the Registrants have recorded estimated provisions for revenue refund offsetting the amortization of the Excess ADIT to the extent not yet reflected in current customer rates. As of September 30, 2018, AEP has recorded estimated provisions for revenue refunds totaling $36 million.2020. PSO and SWEPCo are seeking regulatory approvals by July 2020.

In addition, with respect to the remaining $0.9 billion of Excess ADIT recorded in Regulatory Liabilities and Deferred Investment Tax Credits that are not subject to rate normalization requirements, the Registrants have received state utility commission orders or instructions and a filed FERC settlement agreement to begin amortization.

Merchant Coal Generation Assets

In September 2018, management announced plans to close Oklaunion Power Station by October 2020. In October 2018, management announced plans to close Conesville Plant in May 2020.  The closures are not expected to have a material impact on net income, cash flows or financial condition.


Racine


A project to reconstruct a defective dam structure at Racine began in the first quarter of 2017.  In December 2017, an impairment analysis was triggered by the expected costs of the dam reconstruction activities, resulting in a pretax impairment charge equal to Racine’s net book value of $43 million as of December 31, 2017.

Construction activities at Racine continued through 2018, accumulating new capital expenditures of $35 million as of September 30, 2018. Due to a significant increase in estimated costs to complete the reconstruction project, AEP recorded impairments in 2017 and 2018.  See Note 7 - Dispositions and Impairments in the third2018 Annual Report for additional information.

Due to weather-related delays in the first quarter of 2018, an impairment analysis was performed resulting2019, reconstruction activities at Racine are now estimated to be completed in an impairmentthe first half of $35 million.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 amount of those remaining estimated capital expenditures.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.

Hurricane Harvey

In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. Rebuilding efforts are expected to continue through the end of 2018 and AEP Texas’ total costs related to this storm are not yet final. AEP Texas has a PUCT approved catastrophe reserve which allows for the deferral of incremental storm expenses as a regulatory asset, and currently recovers approximately $1 million of storm costs annually through base rates. As of September 30, 2018, the total balance of AEP Texas’ regulatory asset for deferred storm costs is approximately $150 million, inclusive of approximately $127 million of incremental storm expenses related to Hurricane Harvey. As of September 30, 2018, AEP Texas has recorded approximately $205 million of capital expenditures related to Hurricane Harvey. Also, as of September 30, 2018, AEP Texas has received $10 million in


insurance proceeds, and has recorded a receivable for an additional $4 million that will be received in the fourth quarter of 2018, which were applied to the Hurricane Harvey related regulatory asset and property, plant and equipment balances. Management, in conjunction with the insurance adjusters, is reviewing all damages to determine the extent of coverage for additional insurance reimbursement. Any future insurance recoveries received will be applied to, and will offset, the regulatory asset and property, plant and equipment, as applicable.

Management believes the amount recorded as a regulatory asset is probable of recovery and is in the process of requesting securitization of the distribution portion of the regulatory asset. The standard process for securitization of storm cost recovery in Texas requires two filings with the PUCT. In August 2018, AEP Texas filed a Determination of System Restoration Costs with the PUCT for total estimated storm costs in the amount of $425 million, which includes estimated carrying costs. The estimated value of the total storm costs net of insurance proceeds, tax credits and Excess ADIT is $370 million. AEP Texas intends to request securitization for distribution related assets of $253 million while the remaining $117 million of transmission related assets will be recovered through interim transmission filings or an upcoming base rate case. The request for securitization is expected to occur by the first quarter of 2019.

In October 2018, intervenors filed testimony requesting a $24 million reduction in AEP Texas’ Determination of System Restoration Costs. Also in October 2018, the PUCT staff filed testimony requesting a $4 million reduction AEP Texas’ Determination of System Restoration Costs. Settlement negotiations are ongoing. If the ultimate costs 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.

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

In April 2018, the PUCO issued an order approving the ESP extension through May 2024 which includes: (a) an extension of the OVEC PPA rider, (b) a 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) revenue 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, effective June 1, 2018, based on a depreciation study using data through December 2015 and (g) amortization of approximately $24 million annually beginning June 2018 of OPCo’s excess distribution accumulated depreciation reserve, which was $239 million as of December 31, 2015. Upon the issuance of the PUCO order, OPCo stopped recording $39 million in annual amortization of excess distribution accumulated depreciation reserve in June 2018, which was previously approved to end in December 2018 in accordance with PUCO’s December 2011 OPCo distribution base rate case order. OPCo and intervenors agreed 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 May 2018, OPCo and various intervenors filed requests for rehearing with the PUCO. In June 2018, these requests for rehearing were approved to allow further consideration of the requests. In August 2018, the PUCO denied all requests for rehearing. In October 2018, an intervenor filed an appeal with the Ohio Supreme Court challenging various approved riders. See “Ohio Electric Security Plan Filings” section of Note 4 for additional information.

2016 SEET Filing

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

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



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

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

Rockport Plant, Unit 2 SCR

In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2. 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 and is expected to be placed in service in May 2020. The estimated cost of the SCR project is $274 million, excluding AFUDC, to be shared equally between I&M and AEGCo.  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.

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

In April 2018, a group of intervenors filed a Petition for Reconsideration and Rehearing of the March 2018 IURC order.  In June 2018, the IURC denied the Petition for Reconsideration and Rehearing.

Management intends to request recovery of the Michigan jurisdictional share of the SCR project in a future base rate case. The AEGCo ownership share of the SCR project will be billable under the Rockport UPA to I&M and KPCo and will be subject to future regulatory approval for recovery.

2017 Indiana Base Rate Case

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

In February 2018, I&M filed a Stipulation and Settlement Agreement for a $97 million annual increase in Indiana rates effective July 1, 2018 subject to a temporary offsetting reduction to customer bills through December 2018 for a credit rider related to the timing of estimated in-service dates of certain capital expenditures.  The difference between I&M’s requested $263 million annual increase and the $97 million annual increase in the Stipulation and Settlement Agreement


is primarily a result of: (a) the reduction in the federal income tax rate due to Tax Reform, (b) the feedback of credits for Excess ADIT, (c) a 9.95% return on equity, (d) longer recovery periods of regulatory assets, (e) lower depreciation expense primarily for meters, (f) an increase in the sharing of off-system sales margins with customers from 50% to 95% and (g) a refund of $4 million from July through December 2018 for the impact of Tax Reform for the period January 2018 through June 2018. 
In May 2018, the IURC issued an order approving the Stipulation and Settlement Agreement in its entirety.
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 included $23 million related to increased annual depreciation rates and a $4 million increase related to the amortization of certain Cook Plant regulatory assets. The increase in depreciation rates is primarily due to the proposed change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant related to the Life Cycle Management Project.

In February 2018, an MPSC ALJ issued a Proposal for Decision and recommended an annual revenue increase of $49 million, including an intervenor’s proposal for up to 10% of I&M’s Michigan retail customers to choose an alternate supplier for generation and a proposed capacity rate based on PJM’s net cost of new entry value of $289/MW-day, as well as the MPSC staff’s recommended calculation of depreciation expense for both units of Rockport Plant through 2028 and a return on common equity of 9.8%.  If the maximum 10% of customers choose an alternate supplier starting in February 2019, the estimated annual pretax loss due to the reduced capacity rate would be approximately $9 million.  In October 2018, I&M filed a request with the MPSC seeking authority to defer costs related to customers choosing an alternate supplier starting in February 2019.

In April 2018, the MPSC issued an order that generally approved the ALJ proposal resulting in an annual revenue increase of $50 million, effective April 2018 based on a 9.9% return on common equity.  The MPSC also approved the ALJ’s recommendation related to the capacity rate.

In May 2018, I&M filed a Petition for Rehearing on the capacity rate issue. In June 2018, the MPSC denied I&M’s request.

Merchant Portion of Turk Plant

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

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas 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 and through SWEPCo’s wholesale customers under FERC-based rates. As of September 30, 2018, the net book value of Turk Plant was $1.5 billion, before cost of removal, including materials and supplies inventory and CWIP. If SWEPCo cannot ultimately recover its investment and expenses related to the Turk Plant, it could reduce future net income and cash flows and impact financial condition.



Dolet Hills Lignite Company Operations


2012 Texas Base Rate Case

In July 2018,During 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. In October 2018, the Court of Appeals denied SWEPCo’s request. SWEPCo intends to file an appeal with the Texas Supreme Court in the fourthsecond quarter of 2018. If SWEPCo cannot ultimately recover2019, Dolet Hills Power Station switched to a seasonal operational strategy. DHLC’s mining operation will continue year-round but will reduce its investment and expenses related to the Turk Plant, it could reduce future net income and cash flows and impact financial condition. See “2012 Texas Base Rate Case” section of Note 4.

2016 Texas Base Rate Case

In December 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $50 million based upon a return on common equity of 9.6%, effective May 2017. The final order also included: (a) approval to recover the Texas jurisdictional share of environmental investments placed in service, as of June 30, 2016, at various plants, including Welsh Plant, Units 1 and 3, (b) approval of recovery of, but no return on, the Texas jurisdictionallignite output. SWEPCo’s share of the net book value of Welsh Plant, Unit 2, (c) approval of $2investment in the Dolet Hills Power Station is $129 million in additional vegetation management expenses and (d) the rejectionmaximum exposure of SWEPCo’s proposed transmission cost recovery mechanism.

As a resulttotal investment in DHLC is $153 million. Management will continue to monitor the economic viability of the final order, in 2017 SWEPCo: (a) recorded an impairment charge of $19 million, which included $7 million associated with the lack of return on Welsh Plant, Unit 2 and $12 million related to other disallowed plant investments, (b) recognized $32 million of additional revenues, for the period of May 2017 through December 2017, that will be surcharged to customersand (c) recognized an additional $7 million of expenses consisting primarily of depreciation expense and vegetation management expense, offset by the deferral of rate case expense. SWEPCo implemented new rates in February 2018 billings. The $32 million of additional 2017 revenues will be collected by the end of 2018. In March 2018, the PUCT clarified and corrected portions of the final order, without changing the overall decision or amounts of the rate change. The order has been appealed by various intervenors.

In April 2018, SWEPCo made an income tax rate refund tariff filing which includes an annual revenue reduction of approximately $18 million to reflect the difference between rates collected under the final order and the rates that would be collected under Tax Reform. The filing did not address the return of Excess ADIT benefits to customers. In June 2018, the ALJ issued an order approving interim rates that provided for a reduction of residential rates of $8 million. In September 2018, the ALJ issued an order approving interim rates for the remaining customers. The matter has been sent to the PUCT for final approval.

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. In October 2017, SWEPCo filed testimony in Louisiana supporting the prudence of its environmental control investment for Welsh Plant, Units 1 and 3 and Flint Creek power plants. These environmental costs are subject to prudence review by the LPSC. In May 2018, LPSC staff filed testimony that the environmental control investment for Welsh Plant, Units 1 and 3 and Flint Creek power plants is prudent. In August 2018, the LPSC issued an order affirming prudence and approved the settlement agreement for the environmental control investment. In October 2018, the LPSC staff filed a report approving the $31 million increase as filed. The net annual increase is subject to refund pending commission approval. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.



2018 Louisiana Formula Rate Filing

In April 2018, SWEPCo filed its formula rate plan for test year 2017 with the LPSC.  The filing included a net $28 million annual increase, which was effective August 2018 and includes 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 primarily the result of the return of Excess ADIT benefits to customers.
In October 2018, the LPSC staff issued 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. A decision by the LPSC is expected in the fourth quarter of 2018.

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

2018 Oklahoma Base Rate Case

In October 2018, PSO filed a request with the OCC for an $88 million annual increase in Oklahoma retail rates based upon a 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 annual increase includes $13 million related to increased annual depreciation rates and $7 million related to increased storm expense amortization. The requested increase in annual depreciation rates includes the recovery of OklaunionDolet Hills Power Station through 2028 (currently being recovered in rates through 2046).  Management has announced plans to retire Oklaunion Power Station by October 2020. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.DHLC.


2017 Kentucky Base Rate Case

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

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

In April 2018, KPCo and the intervenor filed a settlement agreement with the KPSC in which KPCo withdrew its requested increase related to the recovery of purchased power costs associated with forced outages and the intervenor withdrew its claim regarding the impact of the reduced corporate federal income tax rates on purchased power costs related to the Rockport UPA.



In June 2018, the KPSC issued an order approving the settlement agreement including KPCo’s requested additional revenue increase of $765 thousand related to the calculation of federal income tax expense. This rate increase was effective June 28, 2018.

Virginia Legislation Affecting Earnings Reviews

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

In March 2018, new Virginia legislation impacting investor-owned utilities was enacted, effective July 1, 2018, that: (a) on a one-time basis, required APCo to exclude $10 million of incurred fuel expenses from the July 2018 over/under recovery calculation, (b) reduced APCo’s base rates by $50 million annually effective July 30, 2018, on an interim basis and subject to true-up, to reflect the reduction in the federal income tax rate due to Tax Reform, (c) will require APCo to file its next generation and distribution base rate case by March 31, 2020 using 2017, 2018 and 2019 test years (“triennial review”), (d) will require an adjustment in APCo’s base rates on April 1, 2019 to reflect actual annual reductions in corporate income taxes due to Tax Reform, (e) will require APCo to seek approval from the Virginia SCC for energy efficiency programs with projected costs in the aggregate of at least $140 million over the 10-year period ending July 1, 2028 and (f) will require APCo to construct and/or acquire solar generation facilities in Virginia, as approved by the Virginia SCC, of at least 200 MW of aggregate capacity by July 1, 2028. Triennial reviews are subject to an earnings test which provides that 70% of any over earnings would be refunded or may be reinvested in approved energy distribution grid transformation projects and/or new utility-owned solar and wind generation facilities. The Virginia SCC’s triennial review of 2017-2019 APCo earnings could reduce future net income and cash flows and impact financial condition.

2018 West Virginia Base Rate Case

In May 2018, APCo and WPCo filed a joint request with the WVPSC to increase their combined West Virginia base rates by $115 million ($98 million related to APCo) annually based on a 10.22% return on common equity. The proposed annual increase includes $32 million ($28 million related to APCo) due to increased annual depreciation rates and also reflects the impact 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 the approved settlement agreement with the WVPSC. See “West Virginia Tax Reform” section of Note 4 for additional information.

In October 2018, WVPSC staff and intervenors filed testimony. WVPSC staff recommended a $2 million annual net revenue increase based on a 9.25% return on common equity while intervenors recommended a $14 million annual net revenue decrease based on an 8.75% return on common equity. The difference between APCo and WPCo’s requested annual base rate increase and the WVPSC staff and intervenors recommendations are primarily due to: (a) a reduction in the requested return on common equity, (b) the rejection of updates to the rate base calculation methodology, (c) the rejection of updates to rate base for certain known plant in service increases in 2018 and (d) a reduction in annual depreciation rates primarily related to continuing with a 2040 retirement date for Clinch River Plant rather than APCo’s proposed retirement date of 2025. A hearing at the WVPSC is scheduled for November 2018. If 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 PJM Participants

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


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

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

If the FERC orders revenue reductions in excess of the terms of the settlement agreement, it could reduce future net income and cash flows and impact financial condition.  A decision from the FERC is pending.

Modifications to AEP’s PJM Transmission Rates

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

FERC Transmission Complaint - AEP’s SPP Participants

In June 2017, several parties filed a complaint at the FERC that states the base return on common equity used by AEP’s transmission owning subsidiaries within SPP in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36%, effective upon the date of the complaint through September 5, 2018. In November 2017, a FERC order set the matter for hearing and settlement procedures. The parties were unable to settle and the proceeding is currently in the hearing phase.

In September 2018, the same parties filed another complaint at the FERC that states the base return on common equity used by AEP’s transmission owning subsidiaries within SPP in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.71%, effective upon the date of the second complaint.

Management believes its financial statements adequately address the impact of these complaints. If the FERC orders revenue reductions as a result of these complaints, including refunds from the date of the complaint filings, it could reduce future net income and cash flows and impact financial condition.



Modifications to AEP’s SPP Transmission Rates

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

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 $550 million, excluding AFUDC. As of September 30, 2018, SWEPCo had incurred costs of $399 million, including AFUDC, related to these projects.  Management continues to evaluate the impact of environmental rules and related project cost estimates. As of September 30, 2018, the total net book value of Welsh Plant, Units 1 and 3 was $621 million, before cost of removal, including materials and supplies inventory and CWIP.

In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas filed base rate proceeding. In April 2017, the LPSC approved recovery of $131 million in investments related to its Louisiana jurisdictional share of environmental controls installed at Welsh Plant, effective May 2017. SWEPCo’s approved Louisiana jurisdictional share of Welsh Plant deferrals: (a) are $10 million, excluding $6 million of unrecognized equity as of September 30, 2018, (b) is subject to review by the LPSC and (c) includes a WACC return on environmental investments and the related depreciation expense and taxes. See “2017 Louisiana Formula Rate Filing” and “2018 Louisiana Formula Rate Filing” disclosures above.

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

Westinghouse Electric Company Bankruptcy Filing

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


LITIGATION


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



Rockport Plant Litigation


In July 2013, the Wilmington Trust Company filed a complaint in the U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it would be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022.  The terms of the consent decree allow the installation of environmental emission control equipment, repowering, refueling or retirement of the unit.  The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs.  The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio.


AEGCo and I&M sought and were granted dismissal by the U.S. District Court for the Southern District of Ohio of certain of the plaintiffs’ claims, including claims for compensatory damages, breach of contract, breach of the implied covenant of good faith and fair dealing and indemnification of costs. The court permitted plaintiffs to move forward with their claimPlaintiffs voluntarily dismissed the surviving claims that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. Plaintiffs voluntarily dismissed the surviving claims with prejudice, and the court issued a final judgment. The plaintiffs subsequently filed an appeal in the U.S. Court of Appeals for the Sixth Circuit on whether the trial court erred in dismissing plaintiffs’ claims for breach of contract and breach of the implied 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 in part. In June 2017, on rehearing, the court of appeals issued an amended opinion reversing the district court’s dismissal of certain of plaintiffs’ claims for breach of contract, vacating the denial of the plaintiffs’ motion for partial summary judgment and remanding the case to the district court for further proceedings.  The amended opinion and judgment affirmedaffirming 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 removed the instruction toreversing the district court in the original opinion to enter summary judgment in favorcourt’s dismissal of the owners.breach of contract claims and remanding the case for further proceedings.


In July 2017,Thereafter, AEP filed a motion with the U.S. District Court for the Southern District of Ohio in the original NSR litigation, seeking to modify the consent decree to eliminate the obligation to install certain future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that Unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. Responsive and supplemental filings have been made by all parties. In November 2017, theThe district court granted the owners’ unopposed motion to stay the lease litigation to afford time for resolution of AEP’s motion to modify the consent decree. The consent decree was modified based on an agreement among the parties in July 2019. The district court 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 “Proposed Modification“Modification of the NSR Litigation Consent Decree” section below for additional information. In September 2018, the district court granted AEP’s unopposed motion to stay further proceedings regarding the consent decree to facilitate settlement discussions among the parties to the consent decree.


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 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.



AEP will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances.  If AEP is unable tocannot recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.


Environmental Controls Impact on the Generating Fleet


The rules and proposed environmental controls discussed below will have a material impact on theAEP System generating units in the AEP System.units.  Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of September 30, 2018,2019, the AEP System had a total generating capacity of approximately 25,60025,500 MWs, of which approximately 13,50013,200 MWs were 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 $650$550 million to $1.5$1.1 billion through 2025.2026.


The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in finalizing proposed rules or revising certain existing requirements.  The cost estimates will also change based on: (a) the states’ implementation of these regulatory programs, including the potential for state implementation plans (SIPs) or federal implementation plans (FIPs)rules that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed, on the units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity (g) the outcome of the pending motion to modify the NSR consent decree and (h)(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 previously retired that have a remaining net book value. As of September 30, 2018, the net book value before cost of removal, including related materials and supplies inventory, of the plants/plants or units listed below was $190 million. Management is seeking or will seek recovery of theplants previously retired that have a remaining net book value as of $190 million in future rate proceedings.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
 $44.8
 Kanawha River Plant 400
 $43.8
APCo Clinch River Plant, Unit 3 235
 32.6
 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, Units 1 and 3 300
 17.2
 Sporn Plant, Units 1 and 3 300
 15.6
APCo Glen Lyn Plant 335
 13.4
 Glen Lyn Plant 335
 13.5
SWEPCo(b) Welsh Plant, Unit 2 528
 50.6
 Welsh Plant, Unit 2 528
 50.6
Total   2,268
 $190.4
   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 20162016.
(b)In October 2019, SWEPCo filed a stipulation and April 2016, respectively.settlement agreement with the APSC, which includes recovery of the remaining $15 million Arkansas jurisdictional share of the net book value of Welsh Plant, Unit 2. An order from the APSC is expected in the fourth quarter of 2019.


Management is seeking or will seek recovery of the remaining net book value in future rate proceedings. To the extent existingthe net book value of these generation assets areis not recoverable, it could materially reduce future net income and cash flows and impact financial condition.


Proposed Modification of the NSRNew Source Review Litigation Consent Decree


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



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 June 2020.


In January 2018, AEPMay 2019, the parties filed a supplemental motion proposingproposed order to install the SCR at Rockport Plant, Unit 2 and achieve the final SO2 emission cap applicable to the plant undermodify the consent decreedecree. The proposed order requires AEP to enhance the dry sorbent injection system on both units at the Rockport Plant by the end of 2020, beforeand meet 30-day rolling average emission rates for SO2 and NOx at the expirationcombined stack for the Rockport Plant beginning in 2021. Total SO2 emissions from the Rockport Plant are limited to 10,000 tons per year beginning in 2021 and reduce to 5,000 tons per year when Rockport Plant, Unit 1 retires in 2028. The proposed modification was approved by the district court and became effective in July 2019. As part of the initial lease term. Since all required emission reductions would be achieved, no unit retirements or other compensating measures were offered to maintain the benefits of the current consent decree. Responsive filings were filed in February 2018 by parties opposing AEP’s proposed modificationsmodification to the consent decree. AEP filed a detailed statement ofdecree, I&M agreed to provide an additional $7.5 million to citizens’ groups and the specific relief requested to addressstates for environmental mitigation projects. As joint owners in the changed circumstances at Rockport Plant, Unit 2,the $7.5 million payment was shared between AEGCo and the opposing parties responded thereto. In September 2018, the district court granted AEP’s unopposed motion to stay further proceedingsI&M based on the pending motion to modify the consent decree to facilitate settlement discussions among the parties.joint ownership agreement.


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



Clean Air Act Requirements


The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions. The states implement and administer many of these programs and could impose additional or more stringent requirements. The primary regulatory programs that continue to drive investments in AEP’s existing generating units include: (a) periodic revisions to the National Ambient Air Quality Standards (NAAQS)NAAQS and the development of SIPs to achieve any more stringent standards, (b) implementation of the regional haze program by the states and the Federal EPA, (c) regulation of hazardous air pollutant emissions under the Mercury and Air Toxics Standards (MATS) Rule,MATS, (d) implementation and review of the Cross-State Air Pollution Rule (CSAPR), a FIP designed to eliminate significant contributions from sources in upwind states to nonattainment or maintenance areas in downwind statesCSAPR and (e) the Federal EPA’s regulation of greenhouse gas emissions from fossil-fueled electric generating unitsfossil generation under Section 111 of the CAA.

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

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


NAAQSNational Ambient Air Quality Standards


The Federal EPA issued new, more stringent NAAQS for SO2 in 2010, PM in 2012 and ozone in 2015; the2015. The existing standards for NO2 and SO2 were retained after review by the Federal EPA in 2018.2018 and 2019, respectively. Implementation of these standards is underway. In December 2017, the Federal EPA published final designations for certain areas’ compliance with the 2010 SO2 NAAQS. Additional designations will be made in 2020. States may develop additional requirements for AEP’s facilities as a result of these designations. In June 2018, the Federal EPA proposed to retain the current primary standard for SO2 of 75 parts per billion, without change.


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


Most areas of the country were designated attainment or unclassifiableThe Federal EPA finalized non-attainment designations for the 2015 ozone standard in November 2017. The Federal EPA finalized nonattainment designations for the remaining areas in April and July 2018. The Federal EPA has also issued information to assist the states in developing plans that address their obligations under the interstate transport provisions of the CAA for the 2008 and 2015 ozone standards. The Federal EPA has confirmed that for states included in the CSAPR program, there are no additional interstate transport obligations, as all areas of the country are expected to attain the 2008 ozone standard before 2023. State implementation plans forChallenges to the 2015 ozone standard and the Federal EPA’s determination that CSAPR satisfies certain states’ interstate transport obligations are due in October 2018. The Federal EPA had requested a stay of proceedingspending 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 reconsiderationwhich have been challenged in the U.S. Court of that standard byAppeals for the new administration. In June 2018, the court lifted the stay, allowing those challenges to proceed.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) would 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.


In March 2012, the Federal EPA proposed disapproval of a portion of the regional haze SIP in Arkansas. 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 planned environmental controls to address other CAA requirements. In September 2016, the Federal EPA published a final FIP, retaining its BART determinations, but accelerating the schedule for implementation of certain required controls. The final rule is being challenged in the U.S. Court of Appeals for the Eighth Circuit, but has been held in abeyance to allow the parties to engage in settlement negotiations. Arkansas and other affected parties filed motions to stay the compliance deadlines pending further action from the Federal EPA and the motion was granted.finalized a FIP in 2016. In 2017, 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 approved the


revision. Arkansas finalized a separate action in 2017 to revise the SO2 BART determinations which has been challenged beforeand in September 2019, the Federal EPA approved the Arkansas Pollution Control and Ecology Commission. Management cannot predictSO2 BART determinations. SWEPCo’s Flint Creek Plant is already in compliance with the outcome of these proceedings.applicable requirements.


The Federal EPA also disapproved portions of the Texas regional haze SIP and promulgated a final FIP that did not include any BART determinations in January 2016. That rule was challenged in the U.S. Court of Appeals for the Fifth Circuit and in March 2017, the court granted partial remand of the final rule.SIP. In January 2017, the Federal EPA proposed source-specific BART requirements for SO2 from sources in Texas, including Welsh Plant, Unit 1. The proposed source-specific approach for Welsh Plant, Unit 1 called for installation of a wet FGD system. In October 2017, the Federal EPA finalized a FIP that allows participation in the CSAPR ozone season program to satisfy the NOx regional haze obligations for electric generating units in Texas. Additionally, the Federal EPA finalized an intrastate SO2 emissions trading program based on CSAPR allowance allocations as an alternative to source-specific SO2 requirements. 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.allocations. A challenge to the FIP has beenwas filed in the U.S. Court of Appeals for the Fifth Circuit by various intervenors. The Federal EPAintervenors and petitioners filed a joint motion to hold the case in abeyanceis pending the Federal EPA’s reviewreconsideration of challengers’ petition for reconsideration. In March 2018, that motion was granted.the final rule. In August 2018, the Federal EPA proposed to affirm its October 2017 FIP approval and requested comment on certain aspects of the FIP promulgation and specifically on the intrastate SO2 trading program.approval. Management supports the intrastate trading program contained in the FIP as a compliance alternative to source-specific controls.


In June 2012, the Federal EPA published revisions to the regional haze rules to allow states participating in the CSAPR trading programs to use those programs in place of source-specific BART for SO2 and NOx emissions based on its determination that CSAPR results in greater visibility improvements than source-specific BART in the CSAPR states.  The rule was challenged in the U.S. Court of Appeals for the District of Columbia Circuit. The Federal EPA confirmed in 2017 that changes to the CSAPR program, including the removal of Texas sources, did not alter that conclusion. In March 2018, the U.S. Court of Appeals for the District of Columbia Circuit affirmed the Federal EPA rule that found that CSAPR provides greater visibility improvements than BART. Challenges to the changes made to the scope of the program in 2016 are being held in abeyance while the Federal EPA reconsiders the Texas SO2 BART FIP.Cross-State Air Pollution Rule


CSAPR

In 2011, the Federal EPA issued CSAPR as a replacement for the 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 NOx allowances and individual state budgets to compel further emission reductions from electric utility generating units.  Interstate trading of allowances is allowed on a restricted sub-regional basis.




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 rule was vacated, but that decision was reversed on appeal to the U.S. Supreme Court. On remand, the U.S. Court of Appeals for the District of Columbia Circuit allowed 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 court found that the Federal EPA over-controlled the SO2 and/or NOx budgets of 14 states. The court remanded the rule to the Federal EPA for revision consistent with the court’s opinion while CSAPR remained in place.


In October 2016, the Federal EPA issued a final rule, the CSAPR Update, to address the remand and to incorporate additional changes necessary to address the 2008 ozone standard. The final ruleCSAPR Update significantly reduced ozone season budgets in many states and discounted the value of banked CSAPR ozone season allowances beginning with the 2017 ozone season. The rule has been challenged inIn 2019, the courts and petitions for administrative reconsideration have been filed. In March 2018,appeals court remanded the U.S. Court of Appeals for the District of Columbia Circuit denied the petitions and other challengesCSAPR Update to the rule.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 complyingcomplied with the more stringent ozone season budgets while these petitions 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 established 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 proposed 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.


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 court remanded the MATS rule to the Federal EPA to consider costs in determining whether to regulate emissions of HAPs from power plants. TheIn 2016, the Federal EPA issued a supplemental finding concluding that, after considering the costs of compliance, it was appropriate and necessary to regulate HAP emissions from coal-firedcoal and oil-fired units. Petitions for review of the Federal EPA’s 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 2017,In 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, which remainsremaining 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 comment period on this proposal ended in effect.April 2019.



Climate Change, CO2 Regulation and Energy Policy


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


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 effectplans until a final decision is issued by the U.S. Court of Appeals for the District of Columbia Circuit and the U.S. Supreme Court considers any petition for review.

In March 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 U.S.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 notice of: (a) an Executive Order fromdismissed the President of the United States titled “Promoting Energy Independence and Economic Growth” directingchallenges.

In July 2019, the Federal EPA to review the CPP and related rules, (b) the Federal EPA’s initiation of a review of the CPP and (c) a forthcoming rulemaking related to the CPP consistent with the Executive Order, if the Federal EPA determines appropriate. In this same filing, the Federal EPA also presented a motion to hold the litigation in abeyance until 30 days after the conclusion of review of any resulting rulemaking. The U.S. Court of Appeals for 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. In December 2017, the Federal EPA issued an advanced notice of proposed rulemaking seeking information that should be considered by the Federal EPA in developing revised guidelines for state programs. In August 2018, the Federal EPA proposedfinalized the Affordable Clean Energy (ACE) rule to replace the CPP with new emission guidelines for regulating CO2from existing sources. ACE would establishestablishes a framework for states to adopt standards of performance for utility boilers based on heat rate improvements for such boilers. CommentsThe 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 proposeddegree 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 will be accepted until the end of October 2018. Management is actively monitoring these rulemakings and participatinghas been challenged in the developmentcourts.

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 any new guidelines.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, purchasing renewable power purchases and broadening AEP System’s portfolio of energy efficiency programs.


In February 2018,September 2019, AEP announced new intermediate and long-term CO2 emission reduction goals, based on the output of the company’s integrated resource plans, which take into account economics, customer demand, grid reliability and resiliency, regulations and the company’s current business strategy. The intermediate goal is a 60%70% reduction from 2000 CO2 emission levels from AEP generating facilities by 2030; the long-term goal is to surpass an 80% reduction of CO2 emissions from AEP generating facilities from 2000 levels by 2050. AEP’s total projectedestimated CO2emissions in 2018 arewere approximately 9069 million metric tons, a 46%59% reduction from AEP’s 2000 CO2 emissions. AEP has made significant progress in reducing CO2 emissions of approximately 167 million metric tons.from power generation fleet and expect 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 achieve zero emissions while continuing to provide reliable, affordable power for customers.


Federal and state legislation or regulations that mandate limits on the emission of CO2 could result in significant increases in capital expenditures and operating costs, which in turn, could lead to increased liquidity needs and higher financing costs.  Excessive costs to comply with future legislation or regulations might force AEP to close some coal-fired facilities, which could possibly lead to 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 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 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. Certain records must be posted to a publicly available internet site. Initial groundwater monitoring reports were posted in the first quarter ofIn 2018, and some of AEP’s existing facilities were required to begin assessment monitoring programs to determine if unacceptable groundwater impacts will trigger future remedial actions.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 U.S. Congress passed legislation authorizing statesfinal 2015 rule, the parties initially agreed to submit programs to regulate CCR facilities, and the Federal EPA to approve such programs if they are no less stringent than the minimum federal standards. The Federal EPA may also enforce compliance with the minimum standards until a state program is approved or if states fail to adopt their own programs. Oklahoma has received approval to operate its state program in lieusettle some of the federal rules.issues.  In October 2018, the Federal EPA’s approval of the Oklahoma program was challenged in the Federal District Court for the District of Columbia and in the U.S. Court of Appeals for the District of Columbia Circuit. The Company is complying withCircuit addressed or dismissed the Oklahoma program, which remainsremaining issues in place.

The final 2015 rule has been challenged in the courts.  In August 2018, the U.S. Circuit Court of Appeals for the District of Columbia Circuit issued its decision vacating and remanding certain provisions of the 2015 rule.  Remaining issues


were dismissed. None of the parties filed a motion for rehearing.  The provisions addressed by the Court’scourt’s decision, including changes to the provisions for unlined impoundments and legacy sites, will be the subject of further rulemaking consistent with the Court’scourt’s decision.


In September 2017,Prior to the Federal EPA granted industry petitions to reconsider the CCR rule.  In March 2018,court’s decision, the Federal EPA issued a proposed rule to modify certain provisions of the solid waste management standards and provide additional flexibility to facilities regulated under approved state programs.  A final rule was signed in July 2018 rule that modifies certain compliance deadlines and other requirements in the 2015 rule.  Additional changes to the minimum performance standards that were contained in the March proposed rule, and changes to respond to the decisionIn December 2018, challengers filed a motion for partial stay or vacatur of the U.S. Court of Appeals forJuly 2018 rule. On the District of Columbia Circuit will be addressed in future rulemakings.  Management supports the adoption of more flexible compliance alternatives subject tosame day, the Federal EPA or state oversight.filed a motion for partial remand of the July 2018 rule. The court granted the Federal EPA’s motion, and further rulemaking to address the 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 ground watersgroundwaters that have a hydrologic connection to a surface water body representsrepresent an “unpermitted discharge” under the Clean Water Act.CWA. Two cases were accepted by the U.S. Supreme Court for further review of the scope of CWA jurisdiction. The Federal EPA has opened a rulemaking docket to solicit information to determine whether it should provide additional clarification of the scope of Clean Water ActCWA permitting requirements for discharges to ground water.groundwater, and issued an interpretive statement finding that discharges to groundwater are not subject to NPDES permitting requirements under the CWA. Management is unable to predict the impact of this guidance or the outcome of these cases or the Federal EPA’s rulemaking, which could impose significant additional costs 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 and conduct any required remedial actions. Management recorded a $95 million increase in asset retirement obligations in 2015 based on the closureClosure and post-closure carecosts have been included in ARO in accordance with the requirements in the final rule. This estimate does not include costs of groundwater remediation, ifwhere 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.  The rule was upheld on review by the U.S. Court of Appeals for the Second Circuit. Compliance timeframes are established by the permit agency through each facility’s National Pollutant Discharge Elimination SystemNPDES permit as those permits are renewed and have been incorporated into permits at several AEP facilities. Petitions for review were filed by industry and environmental groups in the U.S. Court of Appeals for the Second Circuit.  The court denied the petitions and upheld the final rule. AEP’sAdditional AEP facilities are reviewing these requirements as their waste waterwastewater discharge permits are renewed and making appropriate adjustments to their intake structures.


In November 2015, the Federal EPA issued a final rule revising effluent limitation guidelines for electricity generating facilities. The 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 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. A final rule revisingEPA announced its intent to reconsider and potentially revise 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, but has been challenged in2019. In April 2019, the courts.Fifth Circuit vacated the standards for landfill leachate and legacy wastewater, and remanded them to the Federal EPA for reconsideration.  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. Management is actively participating in the reconsideration proceedings.


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 final rule was challenged in both courts of appeal and district courts. In JanuaryDecember 2018, the Federal EPA and the U.S. Supreme Court ruled that challengesArmy Corps of Engineers released a proposed rule to replace 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” must be filedand recodification of the regulatory definition that was in federal district courts. Challengesplace prior to the rule will proceed.


In March 2017, the Federal EPA published a notice of intent to review the rule and provide an advanced notice of a proposed rulemaking consistent with the Executive Order of the President of the United States directing the Federal EPA and U.S. Army Corps of Engineers to review and rescind or revise the rule. In June 2017, the agencies signed a notice of proposed rule to rescind the definition of “waters of the United States” that was adopted in June 2015, and to re-codify the definition of that phrase as it existed immediately prior to that action. This action would effectively retain the status quo until a new rule is adopted by the agencies. A supplemental proposal was signed by the Administrator in June 2018 to provide further clarification of the impact of and support for repeal of the 2015 rule. The Federal EPA and U.S. Army Corps of Engineers also finalized a new rule to extend the applicability date of the 2015 rule to 2020. Challenges to the applicability date rule were filed by third parties in several federal district courts. In August 2018, the Federal District Court for the District of South Carolina vacated the postponement of the applicability date, allowing the 2015 rule to go into effect in 26 states. Management will participate in further rulemaking activities.




RESULTS OF OPERATIONS


SEGMENTS


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


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


Vertically Integrated Utilities


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


Transmission and Distribution Utilities


Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo.
OPCo purchases energy and capacity at auction to serve SSO customers and provides transmission and distribution services for all connected load.


AEP Transmission Holdco


Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved returns on equity.
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 are presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.


The following discussion of AEP’s results of operations by operating segment includes an analysis of Gross Margin, which is a non-GAAP financial measure. Gross Margin includes Total Revenues less the costs of Fuel and Other Consumables Used for Electric Generation as well as Purchased Electricity for Resale and Amortization of Generation Deferrals as presented in the Registrants statements of income as applicable. Under the various state utility rate making processes, these expenses are generally reimbursable directly from and billed to customers. As a result, they do not typically impact Operating Income or Earnings Attributable to AEP Common Shareholders. Management believes that Gross Margin provides a useful measure for investors and other financial statement users to analyze AEP’s financial performance in that it excludes the effect on Total Revenues caused by volatility in these expenses. Operating Income, which is presented in accordance with GAAP in AEP’s statements of income, is the most directly comparable GAAP financial measure to the presentation of Gross Margin. AEP’s definition of Gross Margin may not be directly comparable to similarly titled financial measures used by other companies.





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,
2018 2017 2018 20172019 2018 2019 2018
(in millions)(in millions)
Vertically Integrated Utilities$344.2
 $286.3
 $852.2
 $626.6
$437.6
 $344.2
 $917.7
 $852.2
Transmission and Distribution Utilities145.2
 144.0
 384.6
 374.3
133.7
 145.2
 421.6
 384.6
AEP Transmission Holdco73.3
 75.5
 278.4
 275.7
126.1
 73.3
 404.8
 278.4
Generation & Marketing5.3
 33.7
 62.3
 246.3
90.0
 5.3
 139.5
 62.3
Corporate and Other9.6
 5.2
 (17.1) (11.0)(53.9) 9.6
 (116.0) (17.1)
Earnings Attributable to AEP Common Shareholders$577.6
 $544.7
 $1,560.4
 $1,511.9
$733.5
 $577.6
 $1,767.6
 $1,560.4


AEP CONSOLIDATED


Third Quarter of 20182019 Compared to Third Quarter of 20172018


Earnings Attributable to AEP Common Shareholders increased from $545 million in 2017 to $578 million in 2018 to $734 million in 2019 primarily due to:

An increase in weather-related usage.
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, 20182019 Compared to Nine Months Ended September 30, 20172018


Earnings Attributable to AEP Common Shareholders increased from $1,512 million$1.6 billion in 20172018 to $1,560 million$1.8 billion in 20182019 primarily due to:

An increase in weather-related usage.
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 earnings in the Generation & Marketing segment primarily due to the 2017 gain resulting from the sale of certain merchant generation assets.weather-related usage.


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 2018 2017 2018 2017 2019 2018 2019 2018
 (in millions) (in millions)
Revenues $2,636.7
 $2,482.2
 $7,393.7
 $6,893.1
 $2,645.5
 $2,636.7
 $7,172.6
 $7,393.7
Fuel and Purchased Electricity 1,034.6
 868.6
 2,700.4
 2,368.9
 874.2
 1,034.6
 2,430.2
 2,700.4
Gross Margin 1,602.1
 1,613.6
 4,693.3
 4,524.2
 1,771.3
 1,602.1
 4,742.4
 4,693.3
Other Operation and Maintenance 753.7
 665.0
 2,197.5
 2,042.2
 742.9
 753.7
 2,117.1
 2,197.5
Depreciation and Amortization 340.1
 288.8
 966.1
 845.1
 364.3
 340.1
 1,079.6
 966.1
Taxes Other Than Income Taxes 108.8
 105.7
 326.4
 306.2
 117.9
 108.8
 347.1
 326.4
Operating Income 399.5
 554.1
 1,203.3
 1,330.7
 546.2
 399.5
 1,198.6
 1,203.3
Interest and Investment Income 3.3
 1.3
 8.3
 5.4
Carrying Costs Income 0.8
 2.1
 5.9
 11.3
Other Income 0.9
 4.1
 4.4
 14.2
Allowance for Equity Funds Used During Construction 9.3
 7.5
 24.0
 20.0
 12.2
 9.3
 38.9
 24.0
Non-Service Cost Components of Net Periodic Benefit Cost 18.0
 5.9
 53.7
 17.7
 17.0
 18.0
 50.8
 53.7
Interest Expense (149.2) (134.9) (428.0) (406.5) (140.6) (149.2) (422.6) (428.0)
Income Before Income Tax Expense (Credit) and Equity Earnings (Loss) 281.7
 436.0
 867.2
 978.6
Income Tax Expense (Credit) (63.1) 139.1
 12.9
 334.9
Equity Earnings (Loss) of Unconsolidated Subsidiaries 0.8
 0.4
 2.0
 (4.5)
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 345.6
 297.3
 856.3
 639.2
 438.4
 345.6
 920.8
 856.3
Net Income Attributable to Noncontrolling Interests 1.4
 11.0
 4.1
 12.6
 0.8
 1.4
 3.1
 4.1
Earnings Attributable to AEP Common Shareholders $344.2
 $286.3
 $852.2
 $626.6
 $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,
2018 2017 2018 20172019 2018 2019 2018
(in millions of KWhs)(in millions of KWhs)
Retail: 
  
  
  
 
  
  
  
Residential8,988
 8,488
 26,105
 23,226
9,254
 8,988
 24,785
 26,105
Commercial6,799
 6,701
 18,988
 18,386
6,840
 6,723
 18,183
 18,699
Industrial9,032
 8,839
 26,471
 25,792
9,123
 9,107
 26,533
 26,757
Miscellaneous620
 603
 1,759
 1,701
641
 621
 1,734
 1,762
Total Retail(a)25,439
 24,631
 73,323
 69,105
25,858
 25,439
 71,235
 73,323
              
Wholesale (a)(b)6,432
 6,837
 17,156
 19,262
5,864
 6,432
 16,494
 17,156
              
Total KWhs31,871
 31,468
 90,479
 88,367
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,
2018 2017 2018 20172019 2018 2019 2018
(in degree days)(in degree days)
Eastern Region 
  
  
  
 
  
  
  
Actual – Heating (a)
—
 —
 1,844
 1,266
—
 —
 1,670
 1,844
Normal – Heating (b)
5
 4
 1,745
 1,757
5
 5
 1,742
 1,745
              
Actual – Cooling (c)
878
 698
 1,364
 1,034
937
 878
 1,316
 1,364
Normal – Cooling (b)
730
 731
 1,063
 1,060
732
 730
 1,070
 1,063
              
Western Region 
  
  
  
 
  
  
  
Actual – Heating (a)
—
 —
 974
 539
—
 —
 967
 974
Normal – Heating (b)
1
 1
 908
 926
1
 1
 902
 908
              
Actual – Cooling (c)
1,443
 1,281
 2,380
 2,000
1,572
 1,443
 2,234
 2,380
Normal – Cooling (b)
1,402
 1,404
 2,121
 2,124
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 20182019 Compared to Third Quarter of 20172018
Reconciliation of Third Quarter of 2017 to Third Quarter of 2018
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 2017 $286.3
Third Quarter of 2018 $344.2
  
  
Changes in Gross Margin:  
  
Retail Margins 4.8
 145.1
Off-system Sales (3.8)
Margins from Off-system Sales (0.9)
Transmission Revenues (6.5) 23.8
Other Revenues (6.0) 1.2
Total Change in Gross Margin (11.5) 169.2
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance (88.7) 10.8
Depreciation and Amortization (51.3) (24.2)
Taxes Other Than Income Taxes (3.1) (9.1)
Interest and Investment Income 2.0
Carrying Costs Income (1.3)
Other Income (3.2)
Allowance for Equity Funds Used During Construction 1.8
 2.9
Non-Service Cost Components of Net Periodic Pension Cost 12.1
 (1.0)
Interest Expense (14.3) 8.6
Total Change in Expenses and Other (142.8) (15.2)
  
  
Income Tax Expense (Credit) 202.2
Equity Earnings (Loss) of Unconsolidated Subsidiaries 0.4
Net Income Attributable to Noncontrolling Interest 9.6
Income Tax Expense (Benefit) (61.2)
Net Income Attributable to Noncontrolling Interests 0.6
    
Third Quarter of 2018 $344.2
Third Quarter of 2019 $437.6

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

Retail Margins increased $5 million primarily due to the following:
The effect of rate proceedings in AEP’s service territories which included:
A $47 million increase from rate proceedings for I&M, inclusive of a $22 million decrease due to the impact of Tax Reform in the Indiana jurisdiction.
A $20 million increase for PSO due to new rates implemented in March 2018, inclusive of a $9 million decrease due to the change in the corporate federal tax rate.
An $18 million increase for SWEPCo primarily due to rider and base rate revenue increases in Texas and Louisiana.
For the rate increases described above, $17 million related to riders/trackers, which had corresponding increases in expense items below.
A $61 million increase in weather-related usage across all regions.
These increases were partially offset by:
A $91 million reduction at APCo and WPCo in deferred fuel under-recovery related to the West Virginia Tax Reform settlement. This decrease was offset in Income Tax Expense (Credit) below.
A $13 million decrease due to lower weather-normalized wholesale margins, primarily due to SWEPCo and I&M wholesale customer load loss from contracts that expired at the end of 2017.
A $12 million decrease in weather-normalized retail margins primarily in the industrial and commercial classes.
An $11 million increase at APCo in deferred fuel related to recoverable PJM expenses that were offset below.


A $10 million increase at APCo in non-recoverable fuel expense related to Virginia legislation.
A $4 million decrease at PSO related to the System Reliability Rider (SRR) that ended in August 2017. This decrease was partially offset by a corresponding decrease recognized in other expense items below.
Margins from Off-system Sales decreased $4 million primarily due to mid-year changes in the OSS sharing mechanism at I&M.
Transmission Revenues decreased $7 million primarily due to the following:
A $16 million decrease due to current year provisions for rate refunds.
These decreases were partially offset by:
A $6 million increase primarily due to an increase in transmission investments in SPP.
A $4 million increase primarily due to an increase in transmission investments in PJM.
Other Revenues decreased $6 million primarily due to reduced rates for KPCo Demand Side Management programs beginning in 2018. This decrease was partially offset in Other Operation and Maintenance expenses below.

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

Other Operation and Maintenance expenses increased $89 million primarily due to the following:
A $40 million increase in expenses at APCo and WPCo due to the extinguishment of regulatory asset balances as agreed to within the West Virginia Tax Reform settlement. This increase was partially offset in Retail Margins above and Income Tax Expense (Credit) below.
A $25 million increase in employee-related expenses.
A $10 million increase in vegetation management expenses primarily in the east region.
A $7 million increase in plant outage and maintenance expenses primarily for APCo and KPCo.
A $4 million increase in customer-related expenses.
A $3 million increase in SPP transmission services.
A $3 million increase due to the Wind Catcher Project for SWEPCo and PSO.
This increase was partially offset by:
A $23 million decrease in PJM transmission services.
Depreciation and Amortization expenses increased $51 millionprimarily due to a higher depreciable base and increased depreciation rates approved at I&M, PSO and SWEPCo.
Non-Service Cost Components of Net Periodic Benefit Cost decreased $12 millionprimarily due to favorable asset returns for the funded Pension and OPEB plans, favorable OPEB cost savings arrangements and the implementation of ASU 2017-07.
Interest Expense increased $14 million primarily due to the following:
A $7 million increase at I&M primarily due to increased long-term debt balances.
A $3 million increase at PSO due to the 2017 deferral of the debt component of carrying charges on environmental control costs for projects at Northeastern Plant, Unit 3 and Comanche Plant.
A $3 million increase in other interest expense at APCo due to the West Virginia Tax Reform settlement.
Income TaxExpense (Credit) decreased $202 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, amortization of Excess ADIT, other book/tax differences which are accounted for on a flow-through basis and a decrease in pretax book income.
Net Income Attributable to Noncontrolling Interest decreased $10 million primarily due to income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine. This decrease was offset by an increase in Income Tax Expense (Credit) above.



Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017
Reconciliation of Nine Months Ended September 30, 2017 to Nine Months Ended September 30, 2018
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
   
Nine Months Ended September 30, 2017 $626.6
   
Changes in Gross Margin:  
Retail Margins 167.3
Off-system Sales (6.9)
Transmission Revenues 24.8
Other Revenues (16.1)
Total Change in Gross Margin 169.1
   
Changes in Expenses and Other:  
Other Operation and Maintenance (155.3)
Depreciation and Amortization (121.0)
Taxes Other Than Income Taxes (20.2)
Interest and Investment Income 2.9
Carrying Costs Income (5.4)
Allowance for Equity Funds Used During Construction 4.0
Non-Service Cost Components of Net Periodic Pension Cost 36.0
Interest Expense (21.5)
Total Change in Expenses and Other (280.5)
   
Income Tax Expense (Credit) 322.0
Equity Earnings (Loss) of Unconsolidated Subsidiaries 6.5
Net Income Attributable to Noncontrolling Interest 8.5
   
Nine Months Ended September 30, 2018 $852.2


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


Retail Margins increased $167
•
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.
A $240$23 million increase in weather-related usage across all regions primarily in the residential and commercial classes.
The effect of rate proceedings in AEP’s service territories which included:
An $89 million increase from rate proceedings for I&M, inclusive of a $26 million decrease due to the impact of Tax Reform in the Indiana jurisdiction.
A $57 million increase for SWEPCo due to rider and base rate revenue increases in Texas, Louisiana and Arkansas.
A $37 million increase for PSO due to new rates implemented in March 2018, inclusive of a $19 million decrease due to the change in the corporate federal tax rate.
For the rate increases described above, $4 million related to riders/trackers, which had corresponding increases in expense items below.
A $32 million increase for I&M in FERC generation wholesale municipal and cooperative revenues primarily due to changes to the annual formula rate.
A $16 million increase in weather-normalized retail margins primarily in the residential class.
These increases were partially offset by:
A $111 million decrease due to customer refunds related to Tax Reform. This decrease was offset in Income Tax Expense (Credit) below.
A $91 million reduction at APCo and WPCo in deferred fuel under-recovery related to the West Virginia Tax Reform settlements. This decrease was offset in Income Tax Expense (Credit) below.


A $39 million decrease due to lower weather-normalized wholesale margins, primarily due to SWEPCo and I&M wholesale customer load loss from contracts that expired at the end of 2017.
A $28$15 million increase at APCo in deferred fuel related to recoverable PJM expenses that were offset below.
A $16$10 million decrease primarilyincrease due to 2018 Virginia legislation which increased non-recoverable fuel and other variable production costs not recovered through fuel clauses or other trackers.expense at APCo in the prior year.
A $16$4 million decreaseincrease in weather-normalized retail margins across all classes.
The effect of rate proceedings in AEP’s service territories which included:
A $19 million increase from rate proceedings at PSO related to the SRR that ended in August 2017.I&M. This decreaseincrease was partially offset by a corresponding decrease recognized 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 non-recoverable fuelWest Virginia. This increase was offset in other expense items below.
An $8 million increase related to Virginia legislation.
Margins from Off-system Sales decreased $7 million primarily due to mid-year changes in the OSS sharing mechanismrider revenues at I&M.
Transmission Revenues increased $25 million&M, primarily due to the following:
timing of the Indiana PJM/OSS rider recovery. This increase was partially offset in other expense items below.
A $23$7 million increase at APCo and WPCo due to the annual formulabase rate true-up and decreased RTO provisions at I&M.
A $19 million increase primarily due to an increaseincreases in transmission investmentsWest Virginia implemented in SPP.March 2019.
These increases were partially offset by:
A $16$74 million decrease due to current year provisions for rate refunds.
Other Revenues decreased $16 million primarily duecustomer refunds related to reduced rates for KPCo Demand Side Management programs beginning in 2018.Tax Reform. This decrease was partially offset in Other Operation and Maintenance expensesIncome 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 (Credit), Equity Earnings (Loss) of Unconsolidated Subsidiaries and Net Income Attributable to Noncontrolling Interest (Benefit)changed between years as follows:


Other Operation and Maintenance expenses increased $155 million primarily due to the following:
•
Other Operation and Maintenance expenses decreased $11 million primarily due to the following:
A $40 million increase in expensesdecrease at APCo and WPCo due to the extinguishment of certain regulatory asset balances as agreed to within the 2018 West Virginia Tax Reform settlement. This increase was partially offset in Retail Margins above and Income Tax Expense (Credit) below.
A $39$12 million increasedecrease in SPP transmission services.
A $35 million increase due to the Wind Catcher Project for SWEPCo and PSO.
A $25 million increase in employee-related expenses.
A $19 million increase inplanned plant outage and maintenance expenses primarily for KPCoat APCo and I&M.
A $13$9 million increasedecrease due to Wind Catcher Project expenses incurred in vegetation management.2018 for SWEPCo and PSO.
A $9$3 million increase due to an increasedecrease in estimated expense for claims related to asbestos exposure.
A $7 million increaserecoverable expenses primarily associated with Energy Efficiency/Demand Response and storm expenses fully recovered in storms primarily for APCo.
A $6 million increase in customer-related expenses.
A $5 million increase in factoring expense.rate riders/trackers within Gross Margin above.
These increasesdecreases were partially offset by:
A $55$45 million decrease inincrease due to PJM transmission expenses primarily due toservices including the annual formula rate true-up.
Depreciation and Amortization expenses increased $121An $8 millionprimarily increase due to a higher depreciable basethe modification of the NSR consent decree impacting I&M and increased depreciation rates approved at I&M, PSOAEGCo.
A $2 million increase due to North Central Wind Energy Facilities expenses for SWEPCo and SWEPCo.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:
Taxes Other Than Income Taxes increased $20 million primarily due to:
An $8A $5 million increase in property taxes driven by an increase in utility plant.
An $8A $5 million increase in stateWest Virginia business and localoccupational taxes at APCo and WPCo.
•
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, 2019 Compared to higher reported taxable KWhNine 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 Vertically Integrated Utilities
(in millions)
   
Nine Months Ended September 30, 2018 $852.2
   
Changes in Gross Margin:  
Retail Margins 75.4
Margins from Off-system Sales (10.4)
Transmission Revenues (16.4)
Other Revenues 0.5
Total Change in Gross Margin 49.1
   
Changes in Expenses and Other:  
Other Operation and Maintenance 80.4
Depreciation and Amortization (113.5)
Taxes Other Than Income Taxes (20.7)
Other Income (9.8)
Allowance for Equity Funds Used During Construction 14.9
Non-Service Cost Components of Net Periodic Pension Cost (2.9)
Interest Expense 5.4
Total Change in Expenses and Other (46.2)
   
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, 2019 $917.7

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and taxable revenuesemissions allowances, and a prior period refund.purchased electricity were as follows:
Carrying Costs Income decreased $5
•
Retail Margins increased $75 million primarily due to the following:
A $91 million increase at APCo and WPCo due to a decrease2018 reduction in carrying charges for certain ridersthe 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 $12 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 $6 million decrease at I&M.
Allowance for Equity Funds Used During Construction increased $4 million primarily&M in fuel-related expenses due to antiming of recovery for fuel and other variable production costs related to wholesale contracts.
The effect of rate proceedings in AEP’s service territories which included:
A $94 million increase in construction activityfrom rate proceedings at APCo and SWEPCo.
Non-Service Cost ComponentsI&M, inclusive of Net Periodic Benefit Cost decreased $36a $30 million primarilydecrease due to favorable asset returns for the funded Pensionimpact of Tax Reform. This increase was partially offset in other expense items below.
A $35 million increase at PSO due to new base rates implemented in April 2019 and OPEB plans, favorable OPEB cost savings arrangements and the implementation of ASU 2017-07.
March 2018.


Interest Expense increased $22A $21 million increase related to rider revenues at I&M, primarily due to the following:timing 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 $13 million increase due to increased long-term debt balances at I&M.
A $7$14 million increase at PSO primarilyAPCo and WPCo due to the 2017 deferral of the debt component of carrying charges on environmental control costs for projects at Northeastern Plant, Unit 3 and Comanche Plant.base rate increases in West Virginia implemented in March 2019.


A $3$7 million increase at SWEPCo primarily due to rider and base rate revenue increases in Louisiana. The increase in rider rates had increases in other interest expense accruals foritems below.
A $4 million increase in rider revenues at KPCo offset in other expense items below.
These increases were partially offset by:
A $117 million decrease due to customer refunds and true-upsrelated to Tax Reform. This decrease was partially offset in 2018 and interest expense credits in 2017 on Welsh Plant and Flint Creek Plant environmental project deferrals.
Income TaxExpense (Credit) decreased $322(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 the changeI&M’s annual PJM Transmission formula rate true-up.
An $11 million decrease primarily due to a reduction 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 corporate federalSPP formula rate.

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

•
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 extinguishment of certain regulatory asset balances as agreed to within the 2018 West Virginia Tax Reform settlement.
A $25 million decrease in recoverable expenses primarily associated with Energy Efficiency/Demand Response and storm expenses fully recovered in rate riders/trackers within Gross Margin above.
A $10 million decrease in expense at 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 $9 million decrease in estimated expense for claims related to asbestos exposure.
These decreases were partially offset by:
A $92 million increase due to PJM transmission services including the annual formula rate true-up.
A $23 million increase in employee-related expenses.
A $13 million increase at APCo due to 2019 contributions to benefit low income tax rate from 35% in 2017 to 21% in 2018West Virginia residential customers as a result of the 2018 West Virginia Tax Reform amortization of Excess ADIT, other book/tax differences which are accounted for on a flow-through basis and a decreasesettlement. This increase was offset in pretax book income.
Income Tax Expense (Benefit) below.
Equity Earnings (Loss) of Unconsolidated Subsidiaries increased $7An $8 million increase in storm-related expenses primarily at SWEPCo.
An $8 million increase due to a prior period income tax adjustment recognized in 2017.
the modification of the NSR consent decree impacting I&M and AEGCo.
Net Income Attributable to Noncontrolling Interest decreased $9A $5 million primarilyincrease due to income tax benefits attributable to SWEPCo’s noncontrolling interestNorth 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 Sabine. This decrease was offsetproperty taxes driven by an increase in Income Tax Expense (Credit) above.utility plant.
A $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 various increases in equity rates at I&M, APCo and PSO and increased projects at I&M.
A $3 million increase due to recent FERC audit findings.
A $2 million increase due to the FERC’s approval of a settlement agreement.



•
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:
An $11 million increase primarily due to higher long-term debt balances mainly at 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.



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 2018 2017 2018 2017 2019 2018 2019 2018
 (in millions) (in millions)
Revenues $1,211.5
 $1,173.3
 $3,510.9
 $3,313.2
 $1,186.6
 $1,211.5
 $3,454.3
 $3,510.9
Purchased Electricity 218.7
 215.7
 660.0
 626.0
 210.1
 218.7
 603.5
 660.0
Amortization of Generation Deferrals 56.9
 58.7
 171.9
 172.9
 8.8
 56.9
 65.3
 171.9
Gross Margin 935.9
 898.9
 2,679.0
 2,514.3
 967.7
 935.9
 2,785.5
 2,679.0
Other Operation and Maintenance 420.4
 305.4
 1,152.1
 889.2
 405.8
 420.4
 1,222.1
 1,152.1
Depreciation and Amortization 201.4
 182.3
 558.4
 502.4
 209.3
 201.4
 586.4
 558.4
Taxes Other Than Income Taxes 143.2
 133.6
 413.2
 387.1
 151.8
 143.2
 437.2
 413.2
Operating Income 170.9
 277.6
 555.3
 735.6
 200.8
 170.9
 539.8
 555.3
Interest and Investment Income 1.3
 1.2
 2.6
 5.6
 1.1
 1.3
 4.2
 2.6
Carrying Costs Income 0.2
 0.5
 1.5
 3.0
 0.3
 0.2
 0.7
 1.5
Allowance for Equity Funds Used During Construction 7.8
 0.9
 23.0
 6.3
 9.8
 7.8
 22.3
 23.0
Non-Service Cost Components of Net Periodic Benefit Cost 8.3
 2.2
 24.6
 6.7
 7.7
 8.3
 22.8
 24.6
Interest Expense (63.5) (61.0) (185.6) (182.5) (63.6) (63.5) (170.8) (185.6)
Income Before Income Tax Expense (Credit) 125.0
 221.4
 421.4
 574.7
Income Tax Expense (Credit) (20.2) 77.4
 36.8
 200.4
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 145.2
 144.0
 384.6
 374.3
 133.7
 145.2
 421.6
 384.6
Net Income Attributable to Noncontrolling Interests —
 —
 —
 —
 —
 —
 —
 —
Earnings Attributable to AEP Common Shareholders $145.2
 $144.0
 $384.6
 $374.3
 $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,
2018 2017 2018 20172019 2018 2019 2018
(in millions of KWhs)(in millions of KWhs)
Retail: 
  
  
  
 
  
  
  
Residential7,948
 7,511
 21,154
 19,361
8,268
 7,948
 20,614
 21,154
Commercial7,165
 6,941
 19,634
 19,184
7,219
 6,958
 19,069
 19,061
Industrial5,720
 5,575
 17,259
 16,992
5,857
 5,904
 17,492
 17,772
Miscellaneous186
 185
 514
 516
223
 209
 595
 574
Total Retail (a)(b)21,019
 20,212
 58,561
 56,053
21,567
 21,019
 57,770
 58,561
              
Wholesale (b)(c)634
 585
 1,835
 1,749
453
 634
 1,531
 1,835
              
Total KWhs21,653
 20,797
 60,396
 57,802
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 OPCo’sOhio’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,
2018 2017 2018 20172019 2018 2019 2018
(in degree days)(in degree days)
Eastern Region 
  
  
  
 
  
  
  
Actual – Heating (a)
—
 —
 2,158
 1,500
—
 —
 2,006
 2,158
Normal – Heating (b)
6
 6
 2,076
 2,091
6
 6
 2,072
 2,076
              
Actual – Cooling (c)
864
 642
 1,322
 957
872
 864
 1,176
 1,322
Normal – Cooling (b)
670
 670
 964
 960
672
 670
 973
 964
              
Western Region 
  
  
  
 
  
  
  
Actual – Heating (a)
—
 —
 234
 103
—
 —
 180
 234
Normal – Heating (b)
—
 —
 194
 199
—
 —
 190
 194
              
Actual – Cooling (d)
1,424
 1,393
 2,612
 2,640
1,587
 1,424
 2,679
 2,612
Normal – Cooling (b)
1,367
 1,364
 2,413
 2,396
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 20182019 Compared to Third Quarter of 20172018
Reconciliation of Third Quarter of 2017 to Third Quarter of 2018
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 2017 $144.0
Third Quarter of 2018 $145.2
  
  
Changes in Gross Margin:  
  
Retail Margins 21.2
 2.2
Off-system Sales 16.0
Margins from Off-system Sales 4.6
Transmission Revenues (0.8) 17.3
Other Revenues 0.6
 7.7
Total Change in Gross Margin 37.0
 31.8
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance (115.0) 14.6
Depreciation and Amortization (19.1) (7.9)
Taxes Other Than Income Taxes (9.6) (8.6)
Interest and Investment Income 0.1
 (0.2)
Carrying Costs Income (0.3) 0.1
Allowance for Equity Funds Used During Construction 6.9
 2.0
Non-Service Cost Components of Net Periodic Benefit Cost 6.1
 (0.6)
Interest Expense (2.5) (0.1)
Total Change in Expenses and Other (133.4) (0.7)
  
  
Income Tax Expense (Credit) 97.6
Income Tax Expense (Benefit) (42.6)
  
  
Third Quarter of 2018 $145.2
Third Quarter of 2019 $133.7


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


•
Retail Margins increased $2 million primarily due to the following:
Retail Margins increased $21A $27 million net increase primarily due to 2018 adjustments to the following:
A $46 million net increasedistribution decoupling under-recovery balance as a result of the 2018 Ohio Tax Reform settlement and changes in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses.tax riders. This increase was partially offset by anin Income Tax Expense (Benefit) below.
A $12 million increase due to the recovery of higher 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 Other Operation and Maintenancerevenues 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 $21$6 million increase in weather-normalized margins primarily in the residential class.
A $4 million increase in Ohio rider revenues associated with the Universal Service Fund (USF).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 $7$28 million increasenet decrease in Ohio Basic Transmission Cost Rider revenues associated with smart grid riders in Ohio.and recoverable PJM expenses. This increasedecrease was partially offset by an increase in various expenses below.
A $4 million increase in Ohio rider revenues associated with the DIR. This increase was partially offset in various expenses below.
A $3 million increase in rider revenues recovering state excise taxes due to an increase in metered KWh in Ohio. This increase was offset by a corresponding increase in Taxes Other Than Income Taxes below.
A $3 million increase in Texas revenues associated with the Distribution Cost Recovery Factor revenue rider.
A $2 million increase in Texas revenues associated with the Transmission Cost Recovery Factor revenue rider. This increase was partially offset by an increase in Other Operation and Maintenance expenses below.
These increases were partially offset by:
A $46$13 million decrease due to adjustments toin Ohio Deferred Asset Phase-In-Recovery Rider revenues which ended in the distribution decoupling under-recovery balance as a resultsecond quarter of the 2018 Ohio Tax Reform settlement.2019. This decrease was offset in Income Tax Expense (Credit)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 $12$6 million decrease in Ohio due to the recovery of lower current year losses fromrevenues associated with a power contract with OVEC.vegetation management rider in Ohio. This decrease was offset by a corresponding increasein 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 from Off-system Sales below.
•
Margins from Off-system Sales increased $5 million primarily due to the following:
An $11A $17 million decreaseincrease due to higher affiliated PPA revenues in weather-normalized margins.Texas. This increase was partially offset by in Other Operation and Maintenance expenses below.
This increase was partially offset by:
Margins from Off-system Sales increased $16A $12 million decrease primarily due to lowerhigher current year losses from a power contract with OVEC in Ohio which was offset in Retail Margins aboveand lower deferrals as a result of the OVEC PPA rider beginning in January 2017.


Transmission Revenues decreased $1 million primarily due to the following:
A $6 million decrease due to lower rates in order to pass the benefits of Tax Reform on to customers in Texas.Ohio. This decrease was offset in Income Tax Expense (Credit) below.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.

This decrease was offset by:
A $6 million increase due to recovery of increased transmission investment in ERCOT.

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


Other Operation and Maintenance expenses increased $115 million primarily due to the following:
•
Other Operation and Maintenance expenses decreased $15 million primarily due to the following:
A $51$29 million increasedecrease in recoverable transmission expenses that were fully recovered in rate recovery riders/trackers withinin Gross MarginsMargin above.
A $21$4 million decrease due to higher charitable contributions in 2018 in Ohio.
These decreases were partially offset by:
A $16 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers.affiliated PPA expenses in Texas. This increase was offset by a correspondingan increase in Retail Margins from Off-system Sales above.
A $10$12 million increase in employee-related expenses.
A $4 million increase in customer-related expenses.
Depreciation and AmortizationPJM expenses increased $19 million primarily duerelated to the following:annual formula rate true-up.
•
Depreciation and Amortization expenses increased $8 million primarily due to the following:
A $10$15 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
A $4$7 million increase in recoverable smart grid depreciation expenses in Ohio.securitization amortizations primarily related to Transition Funding. This increase was offset in Retail Margins above.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 $2$6 million increasedecrease in amortization due to capitalized software.
Taxes Other Than Income Taxes increased $10 million primarily due to the following:
A $5 million increase in property taxes due to additional investments in transmission and distribution assets and higher tax rates.
A $4 million increase in rider revenues recovering state excise taxes due to an increase in metered KWhs.Ohio recoverable DIR depreciation expense. This increasedecrease 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:
Allowance for Equity Funds Used During Construction increased $7A $5 million primarily due to increased transmission projects in Texas.
Non-Service Cost Components of Net Periodic Benefit Cost decreased $6 million primarily due to favorable asset returns for the funded Pension and OPEB plans, favorable OPEB cost savings arrangements and the implementation of ASU 2017-07. 
Income Tax Expense (Credit) decreased $98 million primarilydecrease due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018deferral of previously recorded interest expense approved for recovery as a result of Tax Reform, amortization of Excess ADIT and athe Texas Storm Cost Securitization financing order issued by the PUCT in June 2019.
A $3 million decrease in pretax book income.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 due to higher long-term debt balances.
•
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, 20182019 Compared to Nine Months Ended September 30, 20172018
Reconciliation of Nine Months Ended September 30, 2017 to Nine Months Ended September 30, 2018
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, 2017 $374.3
Nine Months Ended September 30, 2018 $384.6
  
  
Changes in Gross Margin:  
  
Retail Margins 140.4
 (9.3)
Off-system Sales 32.6
Margins from Off-system Sales 38.5
Transmission Revenues (7.6) 68.2
Other Revenues (0.7) 9.1
Total Change in Gross Margin 164.7
 106.5
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance (262.9) (70.0)
Depreciation and Amortization (56.0) (28.0)
Taxes Other Than Income Taxes (26.1) (24.0)
Interest and Investment Income (3.0) 1.6
Carrying Costs Income (1.5) (0.8)
Allowance for Equity Funds Used During Construction 16.7
 (0.7)
Non-Service Cost Components of Net Periodic Benefit Cost 17.9
 (1.8)
Interest Expense (3.1) 14.8
Total Change in Expenses and Other (318.0) (108.9)
  
  
Income Tax Expense (Credit) 163.6
Income Tax Expense (Benefit) 39.4
  
  
Nine Months Ended September 30, 2018 $384.6
Nine Months Ended September 30, 2019 $421.6


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


Retail Margins increased $140 million primarily due to the following:
•
Retail Margins decreased $9 million primarily due to the following:
A $155$71 million net increasedecrease in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increasedecrease was partially offset by an increase in Other Operation and Maintenance expenses below.
A $61 million increase in Ohio revenues associated with the USF. This increase was offset by a corresponding increase in Other Operation and Maintenance expenses below.
An $18 million increasedecrease in Ohio rider revenues associated with the DIR.a vegetation management rider in Ohio. This increasedecrease was partially offset in variousOther Operation and Maintenance expenses below.
A $17 million decrease in affiliated PPA capacity revenues in Texas. This decrease was offset in Margins from Off-system Sales below.
A $16 million increasenet decrease in Texas revenuesmargin in Ohio for the Phase-In-Recovery Rider including associated withamortizations which ended in the Distribution Cost Recovery Factor revenue rider.first quarter of 2019.
A $13 million increasedecrease in Ohio 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 $12 million net decrease in margin in Ohio for the Rate Stability Rider including associated amortizations which ended in the third quarter of 2019.
A $7 million decrease in Texas revenues associated with the Transmission Cost Recovery Factor revenue rider. This increasedecrease was partially offset by an increase in Other Operation and Maintenance expenses below.
A $13$5 million increasedecrease in weather-related usage in Texas weather-related usage primarily driven bydue to a 127% increase23% decrease in heating degree days partially offset by a 1% decrease3% increase in cooling degree days.
A $4 million decrease in Ohio rider revenues associated with the DIR. This decrease was partially offset in other expense items below.
These increasesdecreases were partially offset by:
A $46$58 million decreaseincrease due to a reversal of a regulatory provision in Ohio.


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.settlement and changes in tax riders. This decreaseincrease was partially offset in Income Tax Expense (Credit)(Benefit) below.
A $42$31 million decrease due to the 2018 provisions for customer refunds related to Tax Reform.increase in revenues associated with Ohio smart grid riders. This decreaseincrease was partially offset in Income Tax Expense (Credit)other expense items below.
A $30$21 million decrease in Ohioincrease due to the recovery of lower current year losses from a power contract with OVEC. This decrease was offset by a corresponding increase in Margins from Off-system Sales below.



Margins from Off-system Sales increased $33 million primarily due to lowerhigher current year losses from a power contract with OVEC in Ohio whichOhio. This increase was offset in Retail 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.
Transmission Revenues decreased $8 million primarily due to the following:
A $20 million decrease due to the 2018 provisions for customer refunds due to Tax Reform.Ohio. This decrease was offset in Income Tax Expense (Credit) below.Retail Margins above.
•
Transmission Revenues increased $68 million primarily due to the following:
A $6$62 million decrease due to lower rates in order to pass the benefits of Tax Reform on to customers in Texas. This decrease was offset in Income Tax Expense (Credit) below.
These decreases were partially offset by:
A $19 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 (Credit)(Benefit) changed between years as follows:


Other Operation and Maintenance expenses increased $263
•
Other Operation and Maintenance expenses increased $70 million primarily due to the following:
A $64 million increase in expense due to the following:
A $195 million increasepartial amortization of the Texas Storm Cost Securitization regulatory asset as a result of the final PUCT order in recoverable transmission expenses that were fully recovered in rate recovery riders/trackers within Gross Margins above.
A $61 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers.Texas Storm Cost Case. This increase was offset by a corresponding increase in Retail Margins above.Income Tax Expense (Benefit) below.
A $7$57 million increase in distribution expenses.
A $7 million increase in employee-related expenses.
These increases were partially offset by:
A $55 million decrease in Ohio PJM expenses primarily related to the annual formula rate true-up that will be refunded in future periods.
Depreciation and Amortization expenses increased $56 million primarily due to the following:
true-up.
A $49 million increase in affiliated PPA expenses in Texas. This increase was offset in Margins from Off-system Sales above.
These increases were partially offset by:
A $93 million decrease in transmission 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 $51 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
A $13$9 million increase in recoverable DIR depreciation expense in Ohio. This increase was offset in Retail Margins above.
A $6 million increase in amortization due to capitalized software.
A $5 million increase due to securitization amortizations primarily related to Texas securitized transition funding.Transition Funding. This increase was offset in Other Revenues above and in Interest Expense.
Taxes Other Than Income Taxes increased $26 million primarily due to the following:
Expense below.
A $14$7 million increase in property taxes duedepreciation expense related to additional investmentsthe Oklaunion Power Station.
These increases were partially offset by:
A $30 million decrease in transmission and distribution assets and higher tax rates.Ohio recoverable DIR depreciation expense. This decrease was partially offset in Retail Margins above.
An $11 million increasedecrease in rider revenues recovering state excise taxes due to an increaseamortizations associated with the Deferred Asset Phase-In-Recovery Rider which ended in metered KWhs.the second quarter of 2019. This increasedecrease 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:
Allowance for Equity Funds Used During Construction increased $17A $21 million primarily due to increased transmission projects in Texas.
Non-Service Cost Components of Net Periodic Benefit Cost decreased $18 million primarily due to favorable asset returns for the funded Pension and OPEB plans, favorable OPEB cost savings arrangements and the implementation of ASU 2017-07. 
Income TaxExpense(Credit) decreased $164 million primarilydecrease due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018deferral of previously recorded interest expense approved for recovery as a result of Tax Reform,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 in Other Revenues and Depreciation and Amortization expenses above.
These decreases were partially offset by:
A $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 decreaseone-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 pretax book income.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 2018 2017 2018 2017 2019 2018 2019 2018
 (in millions) (in millions)
Transmission Revenues $187.2
 $178.5
 $605.2
 $581.9
 $273.0
 $187.2
 $808.3
 $605.2
Other Operation and Maintenance 30.9
 23.2
 76.2
 54.7
 31.8
 30.9
 77.0
 76.2
Depreciation and Amortization 34.4
 26.1
 100.0
 74.7
 47.3
 34.4
 133.7
 100.0
Taxes Other Than Income Taxes 36.3
 28.6
 106.5
 85.0
 44.3
 36.3
 130.4
 106.5
Operating Income 85.6
 100.6
 322.5
 367.5
 149.6
 85.6
 467.2
 322.5
Interest and Investment Income 0.4
 0.1
 1.1
 0.4
Other Income 0.8
 0.4
 2.3
 1.1
Allowance for Equity Funds Used During Construction 13.8
 11.6
 45.4
 35.9
 21.0
 13.8
 61.1
 45.4
Non-Service Cost Components of Net Periodic Benefit Cost 0.7
 0.1
 2.1
 0.2
 0.7
 0.7
 2.0
 2.1
Interest Expense (24.2) (17.9) (66.8) (52.3) (27.8) (24.2) (73.8) (66.8)
Income Before Income Tax Expense and Equity Earnings 76.3
 94.5
 304.3
 351.7
 144.3
 76.3
 458.8
 304.3
Income Tax Expense 19.2
 38.6
 75.0
 142.1
 35.4
 19.2
 105.7
 75.0
Equity Earnings of Unconsolidated Subsidiaries 17.1
 20.6
 51.6
 68.7
Equity Earnings of Unconsolidated Subsidiary 18.1
 17.1
 54.5
 51.6
Net Income 74.2
 76.5
 280.9
 278.3
 127.0
 74.2
 407.6
 280.9
Net Income Attributable to Noncontrolling Interests 0.9
 1.0
 2.5
 2.6
 0.9
 0.9
 2.8
 2.5
Earnings Attributable to AEP Common Shareholders $73.3
 $75.5
 $278.4
 $275.7
 $126.1
 $73.3
 $404.8
 $278.4


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



Third Quarter of 20182019 Compared to Third Quarter of 20172018
 
Reconciliation of Third Quarter of 20172018 to Third Quarter of 20182019
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
Third Quarter of 2017 $75.5
Third Quarter of 2018 $73.3
    
Changes in Transmission Revenues:    
Transmission Revenues 8.7
 85.8
Total Change in Transmission Revenues 8.7
 85.8
    
Changes in Expenses and Other:    
Other Operation and Maintenance (7.7) (0.9)
Depreciation and Amortization (8.3) (12.9)
Taxes Other Than Income Taxes (7.7) (8.0)
Interest and Investment Income 0.3
Other Income 0.4
Allowance for Equity Funds Used During Construction 2.2
 7.2
Non-Service Cost Components of Net Periodic Pension Cost 0.6
Interest Expense (6.3) (3.6)
Total Change in Expenses and Other (26.9) (17.8)
    
Income Tax Expense 19.4
 (16.2)
Equity Earnings of Unconsolidated Subsidiaries (3.5)
Net Income Attributable to Noncontrolling Interests 0.1
Equity Earnings of Unconsolidated Subsidiary 1.0
    
Third Quarter of 2018 $73.3
Third Quarter of 2019 $126.1


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


•
Transmission Revenues increased $86 million primarily due to continued investment in transmission assets.
Transmission Revenues increased $9 million primarily due to an increase in the formula rate revenue requirement primarily driven by continued investment in transmission assets. This increase includes the impact of the reduction in revenue related to Tax Reform, which was offset by a decrease in Income Tax Expense below.


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


Other Operation and Maintenance expenses increased $8 million primarily due to increased transmission investment.
Depreciation and Amortization expenses increased $8 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.
Interest Expense increased $6 million primarily due to higher long-term debt balances.
Income Tax Expense decreased $19 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, amortization of Excess ADIT and a decrease in pretax book income.
Equity Earnings of Unconsolidated Subsidiaries decreased $4 million due to lower pretax equity earnings at ETT primarily due to decreased revenues driven by Tax Reform.
•
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, 20182019 Compared to Nine Months Ended September 30, 20172018
 
Reconciliation of Nine Months Ended September 30, 20172018 to Nine Months Ended September 30, 20182019
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
Nine Months Ended September 30, 2017 $275.7
Nine Months Ended September 30, 2018 $278.4
    
Changes in Transmission Revenues:    
Transmission Revenues 23.3
 203.1
Total Change in Transmission Revenues 23.3
 203.1
    
Changes in Expenses and Other:    
Other Operation and Maintenance (21.5) (0.8)
Depreciation and Amortization (25.3) (33.7)
Taxes Other Than Income Taxes (21.5) (23.9)
Interest and Investment Income 0.7
Other Income 1.2
Allowance for Equity Funds Used During Construction 9.5
 15.7
Non-Service Cost Components of Net Periodic Pension Cost 1.9
 (0.1)
Interest Expense (14.5) (7.0)
Total Change in Expenses and Other (70.7) (48.6)
    
Income Tax Expense 67.1
 (30.7)
Equity Earnings of Unconsolidated Subsidiaries (17.1)
Equity Earnings of Unconsolidated Subsidiary 2.9
Net Income Attributable to Noncontrolling Interests 0.1
 (0.3)
    
Nine Months Ended September 30, 2018 $278.4
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 nonaffiliates, were as follows:
 
•
Transmission Revenues increased $203 million primarily due to continued investment in transmission assets.
Transmission Revenues increased $23 million primarily due to the following:
An $87 million increase in revenues due to an increase in the formula rate revenue requirement primarily driven by continued investment in transmission assets. This increase includes the impact of the reduction in revenue related to Tax Reform, which was offset by a decrease in Income Tax Expense below.
This increase was partially offset by:
A $64 million decrease in revenues due to a lower annual formula rate true-up in 2018 driven by implementing forward looking formula rates in 2017.

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

Other Operation and Maintenance expenses increased $22 million primarily due to increased transmission investment.
Depreciation and Amortization expenses increased $25 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $22 million primarily due to higher property taxes as a result of increased transmission investment.
Allowance for Equity Funds Used During Construction increased $10 million primarily due to increased transmission investment resulting in a higher CWIP balance.
Interest Expense increased $15 million primarily due to the following:
•
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:
A $19$13 million increase primarily due to higher long-term debtCWIP balances.
ThisA $12 million increase wasdue to the FERC’s approval of a settlement agreement.
These increases were partially offset by:
A $4$13 million decrease due to higher AFUDC borrowed funds resulting from a higher CWIP balance.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 decreased $67 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, amortization of Excess ADIT and a decrease in pretax book income.
Equity Earnings of Unconsolidated Subsidiaries decreased $17 million primarily due to lower pretax equity earnings at ETT due to decreased revenues driven by Tax Reform and an ETT rate reduction implemented 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 2018 2017 2018 2017 2019 2018 2019 2018
 (in millions) (in millions)
Revenues $521.6
 $465.5
 $1,487.4
 $1,467.5
 $533.7
 $521.6
 $1,428.2
 $1,487.4
Fuel, Purchased Electricity and Other 405.0
 354.6
 1,167.8
 1,062.7
 403.8
 405.0
 1,117.8
 1,167.8
Gross Margin 116.6
 110.9
 319.6
 404.8
 129.9
 116.6
 310.4
 319.6
Other Operation and Maintenance 68.2
 58.7
 192.6
 218.1
 44.0
 68.2
 158.0
 192.6
Asset Impairments and Other Related Charges 35.0
 (2.5) 35.0
 10.6
 —
 35.0
 —
 35.0
Gain on Sale of Merchant Generation Assets —
 —
 —
 (226.4)
Depreciation and Amortization 12.0
 6.2
 26.4
 17.5
 20.6
 12.0
 49.1
 26.4
Taxes Other Than Income Taxes 3.7
 3.2
 10.3
 8.9
 4.4
 3.7
 11.8
 10.3
Operating Income (Loss) (2.3) 45.3
 55.3
 376.1
 60.9
 (2.3) 91.5
 55.3
Interest and Investment Income 3.6
 2.7
 9.9
 7.9
 1.9
 3.6
 6.0
 9.9
Non-Service Cost Components of Net Periodic Benefit Cost 3.8
 2.2
 11.5
 6.7
 3.8
 3.8
 11.2
 11.5
Interest Expense (3.8) (4.0) (11.7) (14.7) (10.5) (3.8) (21.5) (11.7)
Income Before Income Tax Expense (Credit) and Equity Earnings 1.3
 46.2
 65.0
 376.0
Income Tax Expense (Credit) (3.6) 12.5
 3.7
 129.7
Equity Earnings of Unconsolidated Subsidiaries 0.2
 —
 0.5
 —
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 5.1
 33.7
 61.8
 246.3
 88.7
 5.1
 133.1
 61.8
Net Loss Attributable to Noncontrolling Interests (0.2) —
 (0.5) —
 (1.3) (0.2) (6.4) (0.5)
Earnings Attributable to AEP Common Shareholders $5.3
 $33.7
 $62.3
 $246.3
 $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,
2018 2017 2018 20172019 2018 2019 2018
(in millions of MWhs)(in millions of MWhs)
Fuel Type: 
  
  
  
 
  
  
  
Coal4
 2
 10
 10
2
 4
 4
 10
Natural Gas—
 —
 —
 2
Wind—
 —
 1
 —
Renewables1
 —
 2
 1
Total MWhs4
 2
 11
 12
3
 4
 6
 11





Third Quarter of 20182019 Compared to Third Quarter of 20172018
Reconciliation of Third Quarter of 2017 to Third Quarter of 2018
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 2017 $33.7
Third Quarter of 2018 $5.3
  
  
Changes in Gross Margin:  
  
Generation (7.5) (10.6)
Retail, Trading and Marketing 6.7
 12.9
Other Revenues 6.5
 11.0
Total Change in Gross Margin 5.7
 13.3
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance (9.5) 24.2
Asset Impairments and Other Related Charges (37.5) 35.0
Depreciation and Amortization (5.8) (8.6)
Taxes Other Than Income Taxes (0.5) (0.7)
Interest and Investment Income 0.9
 (1.7)
Non-Service Cost Components of Net Periodic Benefit Cost 1.6
Interest Expense 0.2
 (6.7)
Total Change in Expenses and Other (50.6) 41.5
  
  
Income Tax Expense (Credit) 16.1
Equity Earnings of Unconsolidated Subsidiaries 0.2
Income Tax Expense (Benefit) 32.8
Equity Earnings (Loss) of Unconsolidated Subsidiaries (4.0)
Net Loss Attributable to Noncontrolling Interests 0.2
 1.1
  
  
Third Quarter of 2018 $5.3
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.
Generation decreased $8 million primarily due to the reduction of energy margins.
Retail, Trading and Marketing increased $7 million due to increased energy volumes.
Other Revenues increased $7 million primarily due to renewable projects placed in service and the repowering of Trent and Desert Sky.


Expenses and Other, and Income Tax Expense (Credit)(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:
Other Operation and Maintenance expenses increased $10A $20 million primarilydecrease due to the following:
retirement of Conesville Units 5 & 6 in 2019.
A $17An $11 million increasedecrease due to severance accruals related to the announced merchant generation plant retirements.retirement of Stuart Plant in June of 2018.
This increase wasThese decreases were partially offset by:
A $7 million decrease primarilyincrease due to the saleacquisitions of certain merchant generation assets in 2017.
Asset ImpairmentsSempra Renewables LLC and Other Related Chargesincreased $38 million primarily due to the $35 million impairment of Racine in the third quarter of 2018.Santa Rita East.
Depreciation and Amortization increased $6 million due to a higher depreciable base from increased investments in wind farms and renewable energy sources.
Income Tax Expense (Credit) decreased $16 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and a decrease in pretax book income.
•
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, 20182019 Compared to Nine Months Ended September 30, 20172018
Reconciliation of Nine Months Ended September 30, 2017 to Nine Months Ended September 30, 2018
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 Generation & Marketing(in millions)
    
Nine Months Ended September 30, 2017 $246.3
Nine Months Ended September 30, 2018 $62.3
  
  
Changes in Gross Margin:  
  
Generation (74.6) (55.1)
Retail, Trading and Marketing (20.1) 28.0
Other Revenues 9.5
 17.9
Total Change in Gross Margin (85.2) (9.2)
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance 25.5
 34.6
Asset Impairments and Other Related Charges (24.4) 35.0
Gain on Sale of Merchant Generation Assets (226.4)
Depreciation and Amortization (8.9) (22.7)
Taxes Other Than Income Taxes (1.4) (1.5)
Interest and Investment Income 2.0
 (3.9)
Non-Service Cost Components of Net Periodic Benefit Cost 4.8
 (0.3)
Interest Expense 3.0
 (9.8)
Total Change in Expenses and Other (225.8) 31.4
  
  
Income Tax Expense (Credit) 126.0
Equity Earnings of Unconsolidated Subsidiaries 0.5
Income Tax Expense (Benefit) 55.5
Equity Earnings (Loss) of Unconsolidated Subsidiaries (6.4)
Net Loss Attributable to Noncontrolling Interests 0.5
 5.9
  
  
Nine Months Ended September 30, 2018 $62.3
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 $75 million primarily due to the reduction of revenues associated with the sale of certain merchant generation assets in 2017 combined with reduced energy margins in 2018.
Retail, Trading and Marketing decreased $20 million primarily due to lower margins in 2018 combined with the impact of favorable wholesale trading and marketing performance in 2017.
Other Revenues increased $10 million primarily due to renewable projects placed in service and the repowering of Trent and Desert Sky.


Expenses and Other, and Income Tax Expense (Credit)(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 $26A $40 million primarily due the following:
A $43 million decrease primarily due to the saleretirement of certain merchant generation assetsConesville Units 5 & 6 in 2017.2019.
ThisA $15 million decrease wasdue to the retirement of Stuart Plant in June of 2018.
These decreases were partially offset by:
A $17$20 million increase due to severance accruals related to the announced merchant generation plant retirements.
Asset Impairmentsacquisitions of Sempra Renewables LLC and Other Related Charges increased $24 million due to the $35 million impairment of Racine in the third quarter of 2018 compared to the $11 million impairment of other merchant generation assets in 2017.Santa Rita East.
Gain on Sale of Merchant Generation Assets decreased $226 million due to the sale of certain merchant generation assets in 2017.
Depreciation and Amortization increased $9 million due to a higher depreciable base from increased investments in wind farms and renewable energy sources.
•
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.
Non-Service Cost Components of Net Periodic Benefit Cost decreased $5 million primarily due to favorable asset returns for the funded Pension and OPEB plans, favorable OPEB cost savings arrangements and the implementation of ASU 2017-07.
Income Tax Expense (Credit) decreased $126 million primarily due to a decrease in pretax book income driven by the gain on the sale of certain merchant generation assets in 2017 and the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform.


CORPORATE AND OTHER


Third Quarter of 20182019 Compared to Third Quarter of 20172018


Earnings Attributable to AEP Common Shareholders from Corporate and Other increaseddecreased from $5 million in 2017 to $10 million in 2018 to a loss of $54 million in 2019 primarily due to a $25to:

A $40 million decreaseincrease in general corporate expenses and a $10 million decrease in federal income tax expense partiallydue to an increase in consolidating tax adjustments. This increase is offset by a $14primarily within the Generation & Marketing segment.
A $20 million increase in interest expense as a result of increased debt outstanding and a $12 million gain recognized on the sale of an equity investment in the third quarter of 2017.outstanding.


Nine Months Ended September 30, 20182019 Compared to Nine Months Ended September 30, 20172018


Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $11$17 million in 20172018 to a loss of $17$116 million in 20182019 primarily due to:

A $63 million increase in income tax expense primarily due to a $42the following:
A $30 million increase due to an increase in interest expense as a result of increased debt outstanding, a $20 million impairment of an equity investment and related assets in 2018 and a $12 million gain recognized onconsolidating tax adjustments. This increase is offset primarily within the sale of an equity investment in the third quarter of 2017. These items were partially offset by a $45 million decrease in general corporate expenses and anGeneration & Marketing segment.
An $18 million decrease in income tax expenseincrease 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 20182019 Compared to Third Quarter of 20172018


Income Tax Expense decreased $345(Benefit) increased $121 million primarily due to the change inprior year effects of the corporate federal income tax rate from 35% in 2017discrete impact of $124 million of amortization of Excess ADIT not subject to 21% in 2018normalization requirements as a result of the Ohio and West Virginia Tax Reform amortizationOrders received in the third quarter of Excess ADIT and a decrease in pretax book income.2018.


Nine Months Ended September 30, 20182019 Compared to Nine Months Ended September 30, 20172018


Income Tax Expense (Benefit) decreased $704$63 million primarily due to the change in the corporate federal income tax rate from 35% in 2017increased amortization of Excess ADIT not subject to 21% in 2018normalization requirements as a result of finalized Tax Reform amortization of Excess ADITorders and a decreasean increase in pretax book income.projected renewable income tax 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, 2018 December 31, 2017September 30, 2019 December 31, 2018
(dollars in millions)(dollars in millions)
Long-term Debt, including amounts due within one year$22,774.0
 51.7% $21,173.3
 51.5%$25,881.2
 53.5% $23,346.7
 52.7%
Short-term Debt2,242.6
 5.1
 1,638.6
 4.0
2,510.0
 5.2
 1,910.0
 4.3
Total Debt25,016.6
 56.8
 22,811.9
 55.5
28,391.2
 58.7
 25,256.7
 57.0
AEP Common Equity19,016.8
 43.1
 18,287.0
 44.4
19,716.4
 40.7
 19,028.4
 42.9
Noncontrolling Interests30.0
 0.1
 26.6
 0.1
281.3
 0.6
 31.0
 0.1
Total Debt and Equity Capitalization$44,063.4
 100.0% $41,125.5
 100.0%$48,388.9
 100.0% $44,316.1
 100.0%


AEP’s ratio of debt-to-total capital increased from 55.5%57% as of December 31, 20172018 to 56.8%58.7% as of September 30, 20182019 primarily due to an increase in debt due to increasing construction expenditures forsupport distribution, transmission and transmission investments.renewable investment growth.


Liquidity


Liquidity, or access to cash, is an important factor in determining AEP’s financial stability.  Management believes AEP has adequate liquidity under its existing credit facilities.  As of September 30, 2018,2019, AEP had a $3$4 billion revolving credit facility commitment to support its operations.  In October 2018, the revolving credit facility was increased to $4 billion and extended until June 2022.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, 2018,2019, available liquidity was approximately $2.3$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
Cash and Cash EquivalentsCash and Cash Equivalents788.3
  Cash and Cash Equivalents348.8
  
Total Liquidity SourcesTotal Liquidity Sources3,788.3
  Total Liquidity Sources4,348.8
  
Less:AEP Commercial Paper Outstanding1,473.2
  AEP Commercial Paper Outstanding1,760.0
  
   
  
Net Available LiquidityNet Available Liquidity$2,315.1
  Net Available Liquidity$2,588.8
  


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 20182019 was $2.3$2.2 billion.  The weighted-average interest rate for AEP’s commercial paper during 20182019 was 2.25%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 foursix uncommitted facilities totaling $305$405 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of September 30, 20182019 was $72$204 millionwith maturities ranging from October 20182019 to September 2019.October 2020.


Securitized Accounts Receivables


AEP’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and was amendedexpires in July 2018 to include a $125 million and a $625 million facility which expire in July 2020 and 2021, respectively.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, 2018,2019,this contractually-defined percentage was 55.1%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 any facility if a material adverse change occurs.


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


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 $0.67$0.70 per share in October 2018.2019. 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 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 1213 for additional information.


Credit Ratings


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



CASH FLOW


AEP relies primarily on cash flows from operations, debt issuances and its existing cash and cash equivalents to fund its liquidity and investing activities. AEP’s investing and capital requirements are primarily capital expenditures, repaying of long-term debt and paying dividends to shareholders. AEP uses short-term debt, including commercial paper, as a bridge to long-term debt financing. The levels of borrowing may vary significantly due to the timing of long-term debt financings and the impact of fluctuations in cash flows.
Nine Months Ended 
 September 30,		Nine Months Ended 
September 30,
2018 20172019 2018
(in millions)(in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period$412.6
 $403.5
$444.1
 $412.6
Net Cash Flows from Operating Activities3,932.6
 3,124.2
3,349.9
 3,932.6
Net Cash Flows Used for Investing Activities(4,688.7) (1,722.7)(5,357.6) (4,688.7)
Net Cash Flows from (Used for) Financing Activities1,281.0
 (1,314.2)
Net Cash Flows from Financing Activities2,053.4
 1,281.0
Net Increase in Cash, Cash Equivalents and Restricted Cash524.9
 87.3
45.7
 524.9
Cash, Cash Equivalents and Restricted Cash at End of Period$937.5
 $490.8
$489.8
 $937.5


Operating Activities
Nine Months Ended 
 September 30,		Nine Months Ended 
September 30,
2018 20172019 2018
(in millions)(in millions)
Net Income$1,566.5
 $1,527.1
$1,767.1
 $1,566.5
Non-Cash Adjustments to Net Income (a)1,728.7
 2,030.6
1,838.8
 1,728.7
Mark-to-Market of Risk Management Contracts(95.4) (56.2)(41.6) (95.4)
Pension Contributions to Qualified Plant Trust—
 (93.3)
Property Taxes304.8
 291.4
341.7
 304.8
Deferred Fuel Over/Under Recovery, Net210.6
 81.0
Recovery of Ohio Capacity Costs, Net52.7
 65.6
Provision for Refund - Global Settlement, Net(5.5) (93.3)
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 Assets161.6
 (334.6)(9.6) 161.6
Change in Other Noncurrent Liabilities141.9
 205.7
(16.3) 141.9
Change in Certain Components of Working Capital(133.3) (499.8)(645.6) (133.3)
Net Cash Flows from Operating Activities$3,932.6
 $3,124.2
$3,349.9
 $3,932.6


(a)Non-Cash Adjustments to Net Income includes Depreciation and Amortization, Deferred Income Taxes, Allowance for Equity Funds Used During Construction,AFUDC and Amortization of Nuclear Fuel, Gain on Sale of Merchant Generation Assets and Gain on Sale of Equity Investments.Fuel.
 
Net Cash Flows from Operating Activities increased decreased by $808$583 million primarily due to the following:
A $496$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 changesa change in regulatory assets as a result of the impact of the FERC settlement on regulated AEP subsidiaries with rider recovery mechanisms in addition to the settlement of certain regulatory assets as a result of Ohio and West Virginia jurisdictional orders related to Tax Reform.mechanisms. See Note 4 - Rate Matters for additional information.
A $367$158 million increasedecrease in cash from Change in Certain Components of Working Capital. This increase isOther Noncurrent Liabilities primarily due to lower employee-related payments, increased provisionsdecreased Accumulated Provisions for refund related toRate Refunds as a result of Tax Reform and decreased Fuel, Material and Supplies balances, partially offset by timing of receivables and payables.
A $130$117 million increasedecrease in cash from Deferred Fuel Over/Under Recovery, Net primarily due to fluctuations of fuel and purchase power costs at PSO and the reduction of ENEC balances at APCo and WPCo as a result of the 2018 West Virginia Tax Reform Order.
A $93 million increaseOrder, the full recovery of Ohio Phase in cash due to a pension contribution made inrecovery rider and the second quarterfluctuations of 2017.


An $88 million increase in cash due to Provision for Refund - Global Settlement, Net. Refunds were primarily issued in 2017.fuel and purchase power cost at PSO.
These increasesdecreases in cash were partially offset by:
A $263$310 million decreaseincrease in cash from Net Income from Continuing Operations, after non-cash adjustments. See Results of Operations for additional information.further detail.


Investing Activities
Nine Months Ended 
 September 30,		Nine Months Ended 
September 30,
2018 20172019 2018
(in millions)(in millions)
Construction Expenditures$(4,688.4) $(3,778.2)$(4,336.0) $(4,688.4)
Acquisitions of Nuclear Fuel(26.1) (73.2)(91.9) (26.1)
Proceeds from Sale of Merchant Generation Assets—
 2,159.6
Acquisition of Sempra Renewables LLC and Santa Rita East, net of cash and restricted cash acquired(921.3) —
Other25.8
 (30.9)(8.4) 25.8
Net Cash Flows Used for Investing Activities$(4,688.7) $(1,722.7)$(5,357.6) $(4,688.7)
 
Net Cash Flows Used for Investing Activities increased by $3 billion$669 million primarily due to the following:
A $2.2 billion decrease in cash$921 million increase due to the saleacquisition of certain merchant generation assets in 2017.Sempra Renewables LLC and Santa Rita East. The $921 million represents a cash payment of $939 million, net of cash and restricted cash acquired of $18 million. See Note 6 - DispositionsAcquisitions and Impairments for additional information.
This increase in the use of cash was partially offset by:
A $910$352 million decrease in cash due to increaseddecreased construction expenditures, primarily due to increases indriven by decreases at AEP Transmission Holdco of $210 million and Transmission and Distribution Utilities of $653 million and AEP Transmission Holdco of $140$109 million.
 
Financing Activities
Nine Months Ended 
 September 30,		Nine Months Ended 
September 30,
2018 20172019 2018
(in millions)(in millions)
Issuance of Common Stock, Net$62.5
 $—
Issuance of Common Stock$44.7
 $62.5
Issuance/Retirement of Debt, Net2,216.5
 (338.2)3,063.9
 2,206.2
Dividends Paid on Common Stock(922.5) (875.0)(1,002.0) (922.5)
Other(75.5) (101.0)(53.2) (65.2)
Net Cash Flows from (Used for) Financing Activities$1,281.0
 $(1,314.2)
Net Cash Flows from Financing Activities$2,053.4
 $1,281.0
 
Net Cash Flows from (Used for) Financing Activities increased by $2.6 billion$772 million primarily due to the following:
A $1.3 billion increase in cash from short-term debt primarily due to increased borrowings of commercial paper. See Note 12 - Financing Activities for additional information.
An $829 million increase in cash due to increased issuances of long-term debt. See Note 12 - Financing Activities for additional information.
A $468$936 million increase in cash due to decreased retirements of long-term debt. See Note 1213 - Financing Activities for additional information.
This increase in cash was partially offset by:
A $62An $80 million increasedecrease in issuances of long-term debt. See Note 13 - Financing Activities for additional information.
An $80 million decrease in cash due to increased proceeds from issuances of common stock.
These increases in cash were partially offset by:
A $48 million decrease due tothe increased common stock dividenddividends payments primarily due to increasedincrease dividends per share from 20172018 to 2018.2019.


InSee “Long-term Debt Subsequent Events” section of Note 13 for Long-term debt and other securities issued, retired and principal payments made after September 30, 2019 through October 2018, I&M retired $4 million of Notes Payable related to DCC Fuel.24, 2019, the date that the third quarter 10-Q was issued.







BUDGETED CONSTRUCTIONCAPITAL EXPENDITURES


Management forecasts approximately $24$32.9 billion of constructioncapital expenditures for 20182019 to 2021.2023.  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 constructioncapital 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 constructioncapital 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-termlong-


term funding is arranged. For complete information of forecasted constructioncapital expenditures, see the “Budgeted ConstructionCapital Expenditures” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 20172018 Annual Report.

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,
2018		 December 31,
2017
 (in millions)
Rockport Plant, Unit 2 Future Minimum Lease Payments$664.7
 $738.4
Railcars Maximum Potential Loss from Lease Agreement13.9
 17.9

For complete information on each of these off-balance sheet arrangements, see the “Off-Balance Sheet Arrangements” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2017 Annual Report.


CONTRACTUAL OBLIGATION INFORMATION


A summary of contractual obligations is included in the 20172018 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.

CYBER SECURITY

The electric utility industry is an identified critical infrastructure function with mandatory cyber security requirements under the authority of FERC. The North American Electric Reliability Corporation (NERC), which FERC certified as the nation’s Electric Reliability Organization, developed mandatory critical infrastructure protection cyber security reliability standards. AEP began participating in the NERC grid security and emergency response exercises, GridEx, in 2013 and continues to participate in the bi-yearly exercises. These efforts, led by NERC, test and further develop the coordination, threat sharing and interaction between utilities and various government agencies relative to potential cyber and physical threats against the nation’s electric grid. In 2014, the U.S. Department of Energy published an Energy Sector Cyber Security Framework Implementation Guide for utilities to use in adopting and implementing the National Institute of Standards and Technology framework. AEP continues to be actively engaged in the framework process. In addition to these enterprise-wide initiatives, the operations of AEP’s electric utility subsidiaries are subject to extensive and rigorous mandatory cyber security requirements that are developed and enforced by NERC to protect grid security and reliability.

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



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

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

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

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

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


CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING PRONOUNCEMENTSSTANDARDS


CRITICAL ACCOUNTING POLICIES AND ESTIMATES


See the “Critical Accounting Policies and Estimates” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 20172018 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.standards.


ACCOUNTING PRONOUNCEMENTSSTANDARDS


See Note 2 - New Accounting PronouncementsStandards for information related to accounting pronouncementsstandards adopted in 20182019 and pronouncementsstandards effective in the future.


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, 2017:2018:
MTM Risk Management Contract Net Assets (Liabilities)
Nine Months Ended September 30, 2018
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, 2017$42.1
 $(131.3) $163.9
 $74.7
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(29.3) (3.4) (16.7) (49.4)(65.5) (5.0) (14.3) (84.8)
Fair Value of New Contracts at Inception When Entered During the Period (a)—
 —
 15.1
 15.1
—
 —
 8.8
 8.8
Changes in Fair Value Due to Market Fluctuations During the Period (b)—
 —
 7.0
 7.0
—
 —
 12.8
 12.8
Changes in Fair Value Allocated to Regulated Jurisdictions (c)94.8
 40.6
 —
 135.4
76.9
 (7.2) —
 69.7
Total MTM Risk Management Contract Net Assets (Liabilities) as of September 30, 2018$107.6
 $(94.1) $169.3
 182.8
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
   
  
 (23.2)   
   (97.3)
Interest Rate Cash Flow Hedge Contracts
   
  
 1.9
Fair Value Hedge Contracts   
  
 (34.2)   
  
 25.1
Collateral Deposits   
  
 (13.1)   
  
 21.2
Total MTM Derivative Contract Net Assets as of September 30, 2018   
  
 $112.3
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 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, 2018,2019, credit exposure net of collateral to sub investment grade counterparties was approximately 6.5%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, 2018,2019, 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 $491.4
 $2.2
 $489.2
 3
 $268.7
 $529.6
 $0.3
 $529.3
 2
 $218.3
Noninvestment Grade 0.6
 0.6
 —
 —
 —
Split Rating 0.8
 —
 0.8
 1
 0.8
No External Ratings:  
  
 

  
  
  
  
 

  
  
Internal Investment Grade 122.5
 —
 122.5
 3
 77.8
 138.2
 —
 138.2
 3
 84.2
Internal Noninvestment Grade 52.6
 10.5
 42.1
 2
 29.1
 56.2
 10.5
 45.7
 2
 30.1
Total as of September 30, 2018 $667.1
 $13.3
 $653.8
 

 

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, 2018,2019, 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, 2018 December 31, 2017
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
 $1.8
 $0.3
 $0.1
 $0.2
 $0.5
 $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, 2018 December 31, 2017
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)
$0.6
 $16.5
 $2.9
 $0.4
 $4.1
 $6.5
 $1.0
 $0.3
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


AEP is exposed to interest rate market fluctuations in the normal course of business operations. AEP has outstanding short and long-term debt which is subject to a variable rate. AEP manages interest rate risk by limiting variable-rate exposures to a percentage of total debt, by entering into interest rate derivative instruments and by monitoring the effects of market changes in interest rates. For the nine months ended September 30, 20182019 and 2017,2018, a 100 basis point change in the benchmark rate on AEP’s variable rate debt would impact pretax interest expense annually by $24 million and $25 million, and $28 million, respectively.






AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20182019 and 20172018
(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,
 2018 2017 2018 2017 2019 2018 2019 2018
REVENUES                
Vertically Integrated Utilities $2,610.2
 $2,453.8
 $7,332.4
 $6,819.3
 $2,598.9
 $2,610.2
 $7,087.6
 $7,332.4
Transmission and Distribution Utilities 1,180.9
 1,149.7
 3,450.0
 3,242.7
 1,147.3
 1,180.9
 3,328.7
 3,450.0
Generation & Marketing 486.5
 441.5
 1,399.3
 1,386.8
 501.2
 486.5
 1,323.8
 1,399.3
Other Revenues 55.5
 59.7
 212.9
 165.7
 67.6
 55.5
 205.3
 212.9
TOTAL REVENUES 4,333.1
 4,104.7
 12,394.6
 11,614.5
 4,315.0
 4,333.1
 11,945.4
 12,394.6
                
EXPENSES  
  
  
  
  
  
  
  
Fuel and Other Consumables Used for Electric Generation 840.4
 707.4
 1,909.1
 1,865.3
 631.2
 840.4
 1,662.5
 1,909.1
Purchased Electricity for Resale 784.7
 718.1
 2,551.7
 2,156.9
 783.9
 784.7
 2,306.4
 2,551.7
Other Operation 826.0
 644.0
 2,332.7
 1,884.1
 708.3
 826.0
 1,981.7
 2,332.7
Maintenance 316.6
 269.0
 911.0
 862.6
 267.7
 316.6
 890.9
 911.0
Gain on Sale of Merchant Generation Assets —
 —
 —
 (226.4)
Depreciation and Amortization 602.6
 518.5
 1,695.5
 1,485.9
 645.2
 602.6
 1,873.6
 1,695.5
Taxes Other Than Income Taxes 294.2
 272.6
 863.0
 792.0
 320.5
 294.2
 932.7
 863.0
TOTAL EXPENSES 3,664.5
 3,129.6
 10,263.0
 8,820.4
 3,356.8
 3,664.5
 9,647.8
 10,263.0
                
OPERATING INCOME 668.6
 975.1
 2,131.6
 2,794.1
 958.2
 668.6
 2,297.6
 2,131.6
                
Other Income (Expense):  
  
  
  
  
  
  
  
Interest and Investment Income 5.4
 2.4
 11.3
 12.7
Carrying Costs Income 0.9
 2.6
 7.2
 14.2
Other Income 3.2
 6.3
 18.4
 18.5
Allowance for Equity Funds Used During Construction 30.9
 20.0
 92.4
 62.2
 43.0
 30.9
 122.3
 92.4
Non-Service Cost Components of Net Periodic Benefit Cost 31.9
 11.4
 95.3
 34.2
 30.0
 31.9
 90.0
 95.3
Gain on Sale of Equity Investment —
 12.4
 —
 12.4
Interest Expense (256.8) (223.3) (733.1) (668.0) (275.1) (256.8) (781.6) (733.1)
                
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS 480.9
 800.6
 1,604.7
 2,261.8
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS 759.3
 480.9
 1,746.7
 1,604.7
                
Income Tax Expense (Credit) (80.7) 264.0
 93.5
 797.8
Income Tax Expense (Benefit) 40.6
 (80.7) 30.7
 93.5
Equity Earnings of Unconsolidated Subsidiaries 18.1
 20.1
 55.3
 63.1
 15.2
 18.1
 51.1
 55.3
                
NET INCOME 579.7
 556.7
 1,566.5
 1,527.1
 733.9
 579.7
 1,767.1
 1,566.5
                
Net Income Attributable to Noncontrolling Interests 2.1
 12.0
 6.1
 15.2
Net Income (Loss) Attributable to Noncontrolling Interests 0.4
 2.1
 (0.5) 6.1
                
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $577.6
 $544.7
 $1,560.4
 $1,511.9
 $733.5
 $577.6
 $1,767.6
 $1,560.4
                
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING 492,984,741
 491,840,722
 492,649,456
 491,781,643
 493,839,034
 492,984,741
 493,579,430
 492,649,456
                
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $1.17
 $1.11
 $3.17
 $3.07
 $1.49
 $1.17
 $3.58
 $3.17
                
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING 493,940,543
 492,986,307
 493,526,937
 492,428,586
 495,461,509
 493,940,543
 495,105,986
 493,526,937
                
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $1.17
 $1.10
 $3.16
 $3.07
 $1.48
 $1.17
 $3.57
 $3.16
        
CASH DIVIDENDS DECLARED PER SHARE $0.62
 $0.59
 $1.86
 $1.77
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141126.




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20182019 and 20172018
(in millions)
(Unaudited)
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2018 2017 2018 2017
Net Income $579.7
 $556.7
 $1,566.5
 $1,527.1
         
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES  
  
  
  
Cash Flow Hedges, Net of Tax of $2.7 and $(8.1) for the Three Months Ended September 30, 2018 and 2017, Respectively, and $3.9 and $(12.2) for the Nine Months Ended September 30, 2018 and 2017, Respectively 10.2
 (15.0) 14.7
 (22.6)
Securities Available for Sale, Net of Tax of $0 and $0.5 for the Three Months Ended September 30, 2018 and 2017, Respectively, and $0 and $1.5 for the Nine Months Ended September 30, 2018 and 2017, Respectively —
 0.9
 —
 2.7
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.4) and $0.1 for the Three Months Ended September 30, 2018 and 2017, Respectively, and $(1.1) and $0.4 for the Nine Months Ended September 30, 2018 and 2017, Respectively (1.4) 0.3
 (4.0) 0.8
         
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) 8.8
 (13.8) 10.7
 (19.1)
         
TOTAL COMPREHENSIVE INCOME 588.5
 542.9
 1,577.2
 1,508.0
         
Total Comprehensive Income Attributable to Noncontrolling Interests 2.1
 12.0
 6.1
 15.2
         
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $586.4
 $530.9
 $1,571.1
 $1,492.8
  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 141126.




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Nine Months Ended September 30, 20182019 and 20172018
(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
 Total
TOTAL EQUITY – DECEMBER 31, 2016512.0
 $3,328.3
 $6,332.6
 $7,892.4
 $(156.3) $23.1
 $17,420.1
             
Common Stock Dividends 
  
  
 (872.3)  
 (2.7) (875.0)
Other Changes in Equity 
  
 51.6
    
 0.8
 52.4
Net Income      1,511.9
  
 15.2
 1,527.1
Other Comprehensive Loss 
  
  
  
 (19.1)  
 (19.1)
TOTAL EQUITY – SEPTEMBER 30, 2017512.0
 $3,328.3
 $6,384.2
 $8,532.0
 $(175.4) $36.4
 $18,105.5
             Shares Amount Paid-in
Capital		 Retained
Earnings		 Accumulated
Other
Comprehensive
Income (Loss)		 Noncontrolling
Interests		 Total
TOTAL EQUITY – DECEMBER 31, 2017512.2
 $3,329.4
 $6,398.7
 $8,626.7
 $(67.8) $26.6
 $18,313.6
512.2
 $3,329.4
 $6,398.7
 $8,626.7
 $26.6
 $18,313.6
                          
Issuance of Common Stock1.1
 7.1
 55.4
  
  
  
 62.5
0.5
 3.3
 28.9
  
     32.2
Common Stock Dividends 
  
  
 (919.3)  
 (3.2) (922.5)      (305.5)(b)  (0.6) (306.1)
Other Changes in Equity 
  
 18.5
    
 0.5
 19.0
    16.9
       16.9
ASU 2018-02 Adoption      14.0
 (17.0)   (3.0)      14.0
 (17.0)   (3.0)
ASU 2016-01 Adoption    

 11.9
 (11.9)   —
      11.9
 (11.9)   —
Net Income      1,560.4
  
 6.1
 1,566.5
      454.4
   2.3
 456.7
Other Comprehensive Income 
  
  
  
 10.7
  
 10.7
 
  
  
  
 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
513.3
 $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 Stock0.1
 1.2
 13.3
       14.5
Common Stock Dividends      (332.5)(c)  (1.1) (333.6)
Other Changes in Equity    (56.6)(a)    1.0
 (55.6)
Net Income      572.8
   1.3
 574.1
Other Comprehensive Loss        (30.3)   (30.3)
TOTAL EQUITY – MARCH 31, 2019513.6
 3,338.6
 6,442.8
 9,565.6
 (150.7) 32.2
 19,228.5
             
Issuance of Common Stock0.4
 2.2
 15.6
       17.8
Common Stock Dividends      (332.7)(c)  (1.8) (334.5)
Other Changes in Equity    (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      733.5
  
 0.4
 733.9
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 141126.




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20182019 and December 31, 20172018
(in millions)
(Unaudited)
 September 30, December 31, September 30, December 31,
 2018 2017 2019 2018
CURRENT ASSETS  
  
  
  
Cash and Cash Equivalents $788.3
 $214.6
 $348.8
 $234.1
Restricted Cash
(September 30, 2018 and December 31, 2017 Amounts Include $149.2 and $198, Respectively, Related to Transition Funding, Ohio Phase-in-Recovery Funding and Appalachian Consumer Rate Relief Funding)
 149.2
 198.0
Other Temporary Investments
(September 30, 2018 and December 31, 2017 Amounts Include $157 and $155.4, Respectively, Related to EIS and Transource Energy)
 164.1
 161.7
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 757.9
 643.9
 609.0
 699.0
Accrued Unbilled Revenues 241.2
 230.2
 268.8
 209.3
Pledged Accounts Receivable – AEP Credit 1,112.2
 954.2
 955.6
 999.8
Miscellaneous 47.2
 101.2
 36.6
 55.2
Allowance for Uncollectible Accounts (40.4) (38.5) (44.9) (36.8)
Total Accounts Receivable 2,118.1
 1,891.0
 1,825.1
 1,926.5
Fuel 282.3
 387.7
 437.8
 341.5
Materials and Supplies 565.6
 565.5
 613.5
 579.6
Risk Management Assets 191.9
 126.2
 186.7
 162.8
Regulatory Asset for Under-Recovered Fuel Costs 137.5
 292.5
 98.5
 150.1
Margin Deposits 108.8
 105.5
 54.2
 141.4
Prepayments and Other Current Assets 186.6
 310.4
 262.4
 208.8
TOTAL CURRENT ASSETS 4,692.4
 4,253.1
 4,166.4
 4,113.9
        
PROPERTY, PLANT AND EQUIPMENT  
  
  
  
Electric:  
  
  
  
Generation 21,327.3
 20,760.5
 22,624.4
 21,699.9
Transmission 20,113.7
 18,972.5
 23,082.8
 21,531.0
Distribution 20,763.9
 19,868.5
 21,991.0
 21,195.4
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) 3,996.9
 3,706.3
 4,510.2
 4,265.0
Construction Work in Progress 4,995.5
 4,120.7
 5,244.5
 4,393.9
Total Property, Plant and Equipment 71,197.3
 67,428.5
 77,452.9
 73,085.2
Accumulated Depreciation and Amortization 17,841.6
 17,167.0
 18,760.2
 17,986.1
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 53,355.7
 50,261.5
 58,692.7
 55,099.1
        
OTHER NONCURRENT ASSETS  
  
  
  
Regulatory Assets 3,189.9
 3,587.6
 3,131.4
 3,310.4
Securitized Assets 1,001.4
 1,211.2
 938.7
 920.6
Spent Nuclear Fuel and Decommissioning Trusts 2,666.0
 2,527.6
 2,835.2
 2,474.9
Goodwill 52.5
 52.5
 52.5
 52.5
Long-term Risk Management Assets 264.9
 282.1
 299.0
 254.0
Operating Lease Assets 990.0
 —
Deferred Charges and Other Noncurrent Assets 2,394.6
 2,553.5
 2,794.8
 2,577.4
TOTAL OTHER NONCURRENT ASSETS 9,569.3
 10,214.5
 11,041.6
 9,589.8
        
TOTAL ASSETS $67,617.4
 $64,729.1
 $73,900.7
 $68,802.8
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141126.




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 20182019 and December 31, 20172018
(dollars in millions)millions, except per-share and share amounts)
(Unaudited)
     September 30, December 31,     September 30, December 31,
 2018 2017 2019 2018
CURRENT LIABILITIESCURRENT LIABILITIES    CURRENT LIABILITIES    
Accounts Payable $1,579.9
 $2,065.3
 $1,766.8
 $1,874.3
Short-term Debt:        
Securitized Debt for Receivables – AEP Credit 750.0
 718.0
 750.0
 750.0
Other Short-term Debt 1,492.6
 920.6
 1,760.0
 1,160.0
Total Short-term Debt 2,242.6
 1,638.6
 2,510.0
 1,910.0
Long-term Debt Due Within One Year
(September 30, 2018 and December 31, 2017 Amounts Include $420.7 and $406.9, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and Sabine)
 1,904.2
 1,753.7
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 57.3
 61.6
 75.3
 55.0
Customer Deposits 372.5
 357.0
 381.4
 412.2
Accrued Taxes 774.1
 1,115.5
 883.4
 1,218.0
Accrued Interest 299.8
 234.5
 304.8
 231.7
Obligations Under Operating Leases 228.8
 —
Regulatory Liability for Over-Recovered Fuel CostsRegulatory Liability for Over-Recovered Fuel Costs 66.9
 11.9
Regulatory Liability for Over-Recovered Fuel Costs 100.6
 58.6
Other Current Liabilities 1,128.9
 1,033.2
 1,032.4
 1,190.5
TOTAL CURRENT LIABILITIES 8,426.2
 8,271.3
 8,611.2
 8,648.8
         
NONCURRENT LIABILITIESNONCURRENT LIABILITIES    NONCURRENT LIABILITIES    
Long-term Debt
(September 30, 2018 and December 31, 2017 Amounts Include $1,110 and $1,410.5, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, Transource Energy, and Sabine)
 20,869.8
 19,419.6
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 287.2
 322.0
 298.6
 263.4
Deferred Income Taxes 7,110.4
 6,813.9
 7,427.8
 7,086.5
Regulatory Liabilities and Deferred Investment Tax CreditsRegulatory Liabilities and Deferred Investment Tax Credits 8,643.5
 8,422.3
Regulatory Liabilities and Deferred Investment Tax Credits 8,552.8
 8,540.3
Asset Retirement Obligations 1,975.1
 1,925.5
 2,353.5
 2,287.7
Employee Benefits and Pension Obligations 350.7
 398.1
 376.6
 377.1
Obligations Under Operating Leases 801.1
 —
Deferred Credits and Other Noncurrent LiabilitiesDeferred Credits and Other Noncurrent Liabilities 807.2
 830.9
Deferred Credits and Other Noncurrent Liabilities 790.0
 782.6
TOTAL NONCURRENT LIABILITIES 40,043.9
 38,132.3
 45,153.9
 40,985.8
        
TOTAL LIABILITIES 48,470.1
 46,403.6
 53,765.1
 49,634.6
        
Rate Matters (Note 4) 
 
 

 

Commitments and Contingencies (Note 5) 
 
 

 

        
MEZZANINE EQUITYMEZZANINE EQUITY    MEZZANINE EQUITY    
Redeemable Noncontrolling Interest 70.0
 —
 67.3
 69.4
Contingently Redeemable Performance Share Awards 30.5
 11.9
 70.6
 39.4
TOTAL MEZZANINE EQUITY 100.5
 11.9
 137.9
 108.8
        
EQUITYEQUITY    EQUITY    
Common Stock – Par Value – $6.50 Per Share:        
 2018 2017     2019 2018    
Shares Authorized 600,000,000 600,000,000     600,000,000 600,000,000    
Shares Issued 513,301,636 512,210,644     514,140,235 513,450,036    
(20,204,160 and 20,205,046 Shares were Held in Treasury as of September 30, 2018 and December 31, 2017, Respectively) 3,336.5
 3,329.4
(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 6,472.6
 6,398.7
 �� 6,467.1
 6,486.1
Retained Earnings 9,293.7
 8,626.7
 10,095.3
 9,325.3
Accumulated Other Comprehensive Income (Loss)Accumulated Other Comprehensive Income (Loss) (86.0) (67.8)Accumulated Other Comprehensive Income (Loss) (187.9) (120.4)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITYTOTAL AEP COMMON SHAREHOLDERS’ EQUITY 19,016.8
 18,287.0
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY 19,716.4
 19,028.4
        
Noncontrolling Interests 30.0
 26.6
 281.3
 31.0
        
TOTAL EQUITY 19,046.8
 18,313.6
 19,997.7
 19,059.4
        
TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITYTOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY $67,617.4
 $64,729.1
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 141126.




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20182019 and 20172018
(in millions)
(Unaudited)
  Nine Months Ended September 30,
  2018 2017
OPERATING ACTIVITIES  
  
Net Income $1,566.5
 $1,527.1
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
Depreciation and Amortization 1,695.5
 1,485.9
Deferred Income Taxes 43.0
 740.9
Allowance for Equity Funds Used During Construction (92.4) (62.2)
Mark-to-Market of Risk Management Contracts (95.4) (56.2)
Amortization of Nuclear Fuel 82.6
 104.8
Pension Contributions to Qualified Plan Trust —
 (93.3)
Property Taxes 304.8
 291.4
Deferred Fuel Over/Under-Recovery, Net 210.6
 81.0
Gain on Sale of Merchant Generation Assets —
 (226.4)
Gain on Sale of Equity Investment —
 (12.4)
Recovery of Ohio Capacity Costs 52.7
 65.6
Provision for Refund – Global Settlement, Net

 (5.5) (93.3)
Change in Other Noncurrent Assets 161.6
 (334.6)
Change in Other Noncurrent Liabilities 141.9
 205.7
Changes in Certain Components of Working Capital:    
Accounts Receivable, Net (52.3) 201.3
Fuel, Materials and Supplies 98.7
 58.5
Accounts Payable (45.0) (91.0)
Accrued Taxes, Net (247.5) (310.1)
Other Current Assets 11.7
 (98.2)
Other Current Liabilities 101.1
 (260.3)
Net Cash Flows from Operating Activities 3,932.6
 3,124.2
     
INVESTING ACTIVITIES    
Construction Expenditures (4,688.4) (3,778.2)
Purchases of Investment Securities (1,591.2) (1,855.8)
Sales of Investment Securities 1,550.9
 1,808.6
Acquisitions of Nuclear Fuel (26.1) (73.2)
Proceeds from Sale of Merchant Generation Assets —
 2,159.6
Other Investing Activities 66.1
 16.3
Net Cash Flows Used for Investing Activities (4,688.7) (1,722.7)
     
FINANCING ACTIVITIES    
Issuance of Common Stock 62.5
 —
Issuance of Long-term Debt 3,572.0
 2,742.7
Commercial Paper and Credit Facility Borrowings 205.6
 —
Change in Short-term Debt, Net 604.0
 (653.7)
Retirement of Long-term Debt (1,959.5) (2,427.2)
Commercial Paper and Credit Facility Repayments (205.6) —
Make Whole Premium on Extinguishment of Long-term Debt (10.3) (46.1)
Principal Payments for Capital Lease Obligations (49.4) (50.5)
Dividends Paid on Common Stock (922.5) (875.0)
Other Financing Activities (15.8) (4.4)
Net Cash Flows from (Used for) Financing Activities 1,281.0
 (1,314.2)
     
Net Increase in Cash, Cash Equivalents and Restricted Cash 524.9
 87.3
Cash, Cash Equivalents and Restricted Cash at Beginning of Period 412.6
 403.5
Cash, Cash Equivalents and Restricted Cash at End of Period $937.5
 $490.8
     
SUPPLEMENTARY INFORMATION    
Cash Paid for Interest, Net of Capitalized Amounts $631.3
 $613.8
Net Cash Paid (Received) for Income Taxes (27.9) (6.8)
Noncash Acquisitions Under Capital Leases 43.5
 44.5
Construction Expenditures Included in Current Liabilities as of September 30, 882.3
 791.6
Construction Expenditures Included in Noncurrent Liabilities as of September 30, —
 71.8
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, 12.1
 0.6
Noncash Contribution of Assets by Noncontrolling Interest 84.0
 —
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage 2.1
 2.8
  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 141126.




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 EndedThree Months Ended Nine Months Ended
September 30, September 30,September 30, September 30,
2018 2017 2018 20172019 2018 2019 2018
(in millions of KWhs)(in millions of KWhs)
Retail: 
  
     
  
    
Residential3,893
 3,867
 9,679
 9,163
4,148
 3,893
 9,580
 9,679
Commercial3,172
 3,135
 8,438
 8,395
3,152
 2,987
 7,997
 7,916
Industrial2,054
 1,867
 6,243
 6,025
2,168
 2,216
 6,556
 6,705
Miscellaneous159
 157
 430
 429
197
 182
 512
 490
Total Retail(a)9,278
 9,026
 24,790
 24,012
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 EndedThree Months Ended Nine Months Ended
September 30, September 30,September 30, September 30,
2018 2017 2018 20172019 2018 2019 2018
(in degree days)(in degree days)
Actual – Heating (a)—
 —
 234
 103
—
 —
 180
 234
Normal – Heating (b)—
 —
 194
 199
—
 —
 190
 194
              
Actual – Cooling (c)1,424
 1,393
 2,612
 2,640
1,587
 1,424
 2,679
 2,612
Normal – Cooling (b)1,367
 1,364
 2,413
 2,396
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 6570 degree temperature base.




Third Quarter of 20182019 Compared to Third Quarter of 20172018
Reconciliation of Third Quarter of 2017 to Third Quarter of 2018
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 2017 $64.3
Third Quarter of 2018 $57.8
  
  
Changes in Gross Margin:    
Retail Margins (4.4) 12.6
Off-system Sales 3.7
Margins from Off-system Sales 16.7
Transmission Revenues (0.6) 23.9
Other Revenues (1.4) 4.7
Total Change in Gross Margin (2.7) 57.9
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance (19.8) 6.7
Depreciation and Amortization (9.3) (36.9)
Taxes Other Than Income Taxes (3.0) (3.5)
Interest Income (0.1)
Allowance for Equity Funds Used During Construction 5.8
 (0.7)
Non-Service Cost Components of Net Periodic Benefit Cost 2.2
 (0.3)
Interest Expense (2.0) 1.5
Total Change in Expenses and Other (26.1) (33.3)
  
  
Income Tax Expense 22.3
Income Tax Expense (Benefit) (5.4)
  
  
Third Quarter of 2018 $57.8
Third Quarter of 2019 $77.0

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

Retail Margins decreased $4 million primarily due to the following:
A $6 million decrease due to lower weather-normalized margins.
A $6 million decrease due to the 2018 provisions for customer refunds related to Tax Reform.  This decrease was offset in Income Tax Expense below.
These decreases were partially offset by:
A $3 million increase in revenues associated with the Distribution Cost Recovery Factor revenue rider.
A $2 million increase in revenues associated with the Transmission Cost Recovery Factor revenue rider. This increase was partially offset by an increase in Other Operation and Maintenance expenses below.
A $2 million increase in weather-related usage primarily driven by a 2% increase in cooling degree days.
Margins from Off-system Sales increased $4 million primarily due to higher affiliated PPA revenues, which were offset by a corresponding increase in Other Operation and Maintenance expenses below.
Transmission Revenues decreased $1 million primarily due to the following:
A $6 million decrease due to lower rates in order to pass the benefits of Tax Reform on to customers. This decrease was offset in Income Tax Expense below.
This decrease was offset by:
A $6 million increase due to recovery of increased transmission investment in ERCOT.



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

Other Operation and Maintenance expenses increased $20 million primarily due to the following:
A $7 million increase in ERCOT transmission expenses. This increase was offset by an increase in Retail Margins above.
A $6 million increase in employee-related expenses.
A $5 million increase in affiliated PPA expenses. This increase was offset by an increase in Margins from Off-system sales above.
Depreciation and Amortization expenses increased $9 million primarily due to the following:
A $4 million increase due to a prior year asset retirement obligation revision for the Oklaunion Power Station.
A $3 million increase in depreciation expense primarily due to an increase in the depreciable base of transmission and distribution assets.
Taxes Other Than Income Taxes increased $3 million primarily due to increased property taxes as a result of additional capital investment and increased tax rates.
Allowance for Equity Funds Used During Construction increased $6 million primarily due to increased transmission projects.
Interest Expense increased $2 million primarily due to the following:
An $8 million increase due to the issuances of long-term debt.
This increase was offset by:
A $4 million decrease due to a higher debt component of AFUDC and increased investment primarily in transmission projects.
A $2 million decrease in securitization assets related to Transition Funding. This decrease was offset above in Other Revenues and Depreciation and Amortization.
Income Tax Expense decreased $22 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, amortization of Excess ADIT and a decrease in pretax book income.


Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017
Reconciliation of Nine Months Ended September 30, 2017 to Nine Months Ended September 30, 2018
Net Income
(in millions)
 
Nine Months Ended September 30, 2017 $146.6
   
Changes in Gross Margin:  
Retail Margins 16.1
Off-system Sales 2.0
Transmission Revenues 1.4
Other Revenues (1.2)
Total Change in Gross Margin 18.3
   
Changes in Expenses and Other:  
Other Operation and Maintenance (45.3)
Depreciation and Amortization (21.9)
Taxes Other Than Income Taxes (9.0)
Interest Income (1.6)
Allowance for Equity Funds Used During Construction 13.0
Non-Service Cost Components of Net Periodic Benefit Cost 6.5
Interest Expense (3.3)
Total Change in Expenses and Other (61.6)
   
Income Tax Expense 47.8
   
Nine Months Ended September 30, 2018 $151.1


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:
Retail Margins increased $16 million primarily due to the following:
A $16 million increase in revenues associated with the Distribution Cost Recovery Factor revenue rider.
A $13 million increase in revenues associated with the Transmission Cost Recovery Factor revenue rider. This increase was partially offset by an increase in Other Operation and Maintenance expenses below.
A $13An $8 million increase in weather-related usage primarily driven by a 127%due to an 11% increase in heating degree days partially offset by a 1% decrease in cooling degree days.
These increases were partially offset by:
An $18A $4 million decrease due to the 2018 provisions for customer refunds related to Tax Reform.  This decrease was offsetincrease in Income Tax Expense below.
A $7 million decrease due to lower 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.
Transmission Revenues increased $1 million primarily due to the following:
A $19 million increase due to recovery of increased transmission investment in ERCOT.
This increase was partially offset by:
An $11 million decrease due to the 2018 provisions for customer refunds due to Tax Reform.  This decrease was offset in Income Tax Expense below.
A $6 million decrease due to lower rates in order to pass the benefits of Tax Reform on to customers. This decrease was offset in Income Tax Expense below.




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 Maintenancein Depreciation and Amortization expenses increased $45 million primarily due to the following:
below.
A $20$3 million increasedecrease in ERCOT transmission expenses. This increasedecrease was partially offset by an increase in Retail Margins above.


•
Depreciation and Amortization expenses increased $37 million primarily due to the following:
A $9$16 million increase in distribution expenses.
A $9 million increasedepreciation expense due to a change in employee-related expenses.
A $5 million increase in affiliated PPA expenses.the useful life of the Oklaunion Power Station. This increase was partially offset by an increase in Margins from Off-system salesSales above and in Other Operation and Maintenance expenses above.
Depreciation and Amortization expenses increased $22 million primarily due to the following:
An $11 million increase in depreciation expense primarily due to an increase in the depreciable base of transmission and distribution assets.assets primarily related to advanced metering systems.
A $5$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 $4$5 million increasedecrease due to the deferral of previously recorded interest expense approved for recovery as a prior year asset retirement obligation revision forresult of the Oklaunion Power Station.Texas Storm Cost Securitization financing order issued by the PUCT in June 2019.
A $3 million increase in amortization primarily due to advanced metering infrastructure projects and capitalized software.
Taxes Other Than Income Taxes increased $9 million primarily due to increased property taxes as a result of additional capital investment and increased tax rates.
Allowance for Equity Funds Used During Construction increased $13 million primarily due to increased transmission projects.
Non-Service Cost Components of Net Periodic Cost decreased $7 million primarily due to favorable asset returns for the funded Pension and OPEB plans, favorable OPEB cost savings arrangements and the implementation of ASU 2017-07.
Interest Expense increased $3 million primarily due to the following:
A $20 million increase due to the issuances of long-term debt.
This increase was partially offset by:
A $10 million decrease due to a higher debt component of AFUDC and increased investment primarily in transmission projects.
An $8 million decrease in securitization assetsexpense related to Transition Funding.Funding Securitization assets. This decrease was offset above in Other Revenues and Depreciation and Amortization.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
Income Tax Expense decreased $48
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 the changea 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 corporate federal income tax rate from 35%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 2017expense due to 21% in 2018the 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 Reform, amortization of Excess ADIT and aExpense (Benefit) below.
These increases were partially offset by:
A $7 million decrease in pretax book income.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, 20182019 and 20172018
(in millions)
(Unaudited)
 Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended
 September 30, September 30, September 30, September 30,
 2018 2017 2018 2017 2019 2018 2019 2018
REVENUES                
Electric Transmission and Distribution $404.5
 $411.5
 $1,127.0
 $1,111.4
 $445.4
 $404.5
 $1,190.3
 $1,127.0
Sales to AEP Affiliates 27.5
 18.9
 63.3
 50.8
 42.7
 27.5
 125.1
 63.3
Other Revenues 1.4
 0.8
 3.0
 2.1
 1.2
 1.4
 2.6
 3.0
TOTAL REVENUES 433.4
 431.2
 1,193.3
 1,164.3
 489.3
 433.4
 1,318.0
 1,193.3
                
EXPENSES  
  
  
  
  
  
  
  
Fuel and Other Consumables Used for Electric Generation 13.2
 8.3
 27.9
 17.2
 11.2
 13.2
 29.1
 27.9
Other Operation 133.4
 117.5
 368.4
 332.8
 128.2
 133.4
 349.2
 368.4
Maintenance 23.2
 19.3
 67.8
 58.1
 21.7
 23.2
 136.9
 67.8
Depreciation and Amortization 133.3
 124.0
 364.9
 343.0
 170.2
 133.3
 464.8
 364.9
Taxes Other Than Income Taxes 36.3
 33.3
 102.3
 93.3
 39.8
 36.3
 110.3
 102.3
TOTAL EXPENSES 339.4
 302.4
 931.3
 844.4
 371.1
 339.4
 1,090.3
 931.3
                
OPERATING INCOME 94.0
 128.8
 262.0
 319.9
 118.2
 94.0
 227.7
 262.0
                
Other Income (Expense):  
  
  
  
  
  
  
  
Interest Income 0.5
 0.5
 —
 1.6
 0.4
 0.5
 1.5
 —
Allowance for Equity Funds Used During Construction 5.8
 —
 15.2
 2.2
 5.1
 5.8
 8.3
 15.2
Non-Service Cost Components of Net Periodic Benefit Cost 3.1
 0.9
 9.2
 2.7
 2.8
 3.1
 8.4
 9.2
Interest Expense (37.3) (35.3) (108.9) (105.6) (35.8) (37.3) (92.7) (108.9)
                
INCOME BEFORE INCOME TAX EXPENSE 66.1
 94.9
 177.5
 220.8
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 90.7
 66.1
 153.2
 177.5
                
Income Tax Expense 8.3
 30.6
 26.4
 74.2
Income Tax Expense (Benefit) 13.7
 8.3
 (38.8) 26.4
                
NET INCOME $57.8
 $64.3
 $151.1
 $146.6
 $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 141126.






AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20182019 and 20172018
(in millions)
(Unaudited)
 Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended
 September 30, September 30, September 30, September 30,
 2018 2017 2018 2017 2019 2018 2019 2018
Net Income $57.8
 $64.3
 $151.1
 $146.6
 $77.0
 $57.8
 $192.0
 $151.1
                
OTHER COMPREHENSIVE INCOME, NET OF TAXES                
Cash Flow Hedges, Net of Tax of $0.1 and $0.2 for the Three Months Ended September 30, 2018 and 2017, Respectively, and $0.2 and $0.4 for the Nine Months Ended September 30, 2018 and 2017, Respectively 0.3
 0.2
 0.8
 0.7
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2018 and 2017, Respectively, and $0 and $0.1 for the Nine Months Ended September 30, 2018 and 2017, Respectively —
 0.1
 0.1
 0.2
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
 0.3
 0.3
 0.9
 0.9
                
TOTAL COMPREHENSIVE INCOME $58.1
 $64.6
 $152.0
 $147.5
 $77.3
 $58.1
 $192.9
 $152.0
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141126.






AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 20182019 and 20172018
(in millions)
(Unaudited)
 
Paid-in
Capital
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2016 $857.9
 $814.1
 $(14.9) $1,657.1
        
Capital Contribution from Parent 200.0
    
 200.0
Net Income  
 146.6
  
 146.6
Other Comprehensive Income  
  
 0.9
 0.9
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2017 $1,057.9
 $960.7
 $(14.0) $2,004.6
         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
 $1,057.9
 $1,124.6
 $(12.6) $2,169.9
                
Capital Contribution from Parent 100.0
     100.0
 100.0
     100.0
ASU 2018-02 Adoption   1.8
 (2.7) (0.9)   1.8
 (2.7) (0.9)
Net Income  
 151.1
   151.1
   46.8
   46.8
Other Comprehensive Income  
   0.9
 0.9
     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
 $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 141126.






AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20182019 and December 31, 20172018
(in millions)
(Unaudited)
 September 30, December 31, September 30, December 31,
 2018 2017 2019 2018
CURRENT ASSETS        
Cash and Cash Equivalents $0.1
 $2.0
 $0.1
 $3.1
Restricted Cash for Securitized Transition Funding 124.2
 155.2
 114.3
 156.7
Advances to Affiliates 8.0
 111.9
 7.7
 8.0
Accounts Receivable:        
Customers 132.9
 105.3
 148.0
 110.9
Affiliated Companies 14.3
 12.3
 17.6
 15.0
Accrued Unbilled Revenues 73.7
 75.8
 82.7
 70.4
Miscellaneous 0.5
 1.3
 0.2
 1.9
Allowance for Uncollectible Accounts (0.9) (0.7) (1.6) (1.3)
Total Accounts Receivable 220.5
 194.0
 246.9
 196.9
Fuel 6.9
 3.6
 7.1
 8.8
Materials and Supplies 51.1
 52.0
 54.6
 52.8
Risk Management Assets 0.5
 0.5
Accrued Tax Benefits 14.6
 41.0
 111.3
 44.9
Prepayments and Other Current Assets 12.0
 3.6
 6.4
 5.3
TOTAL CURRENT ASSETS 437.9
 563.8
 548.4
 476.5
        
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
Generation 352.1
 350.7
 351.8
 352.1
Transmission 3,302.3
 3,053.6
 4,102.8
 3,683.6
Distribution 3,968.4
 3,718.6
 4,122.2
 4,043.2
Other Property, Plant and Equipment 554.0
 461.0
 775.3
 727.9
Construction Work in Progress 1,108.8
 835.7
 978.4
 836.2
Total Property, Plant and Equipment 9,285.6
 8,419.6
 10,330.5
 9,643.0
Accumulated Depreciation and Amortization 1,643.9
 1,594.5
 1,742.7
 1,651.2
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 7,641.7
 6,825.1
 8,587.8
 7,991.8
        
OTHER NONCURRENT ASSETS        
Regulatory Assets 396.4
 378.7
 259.6
 430.0
Securitized Transition Assets
(September 30, 2018 and December 31, 2017 Amounts Include $702.9 and $869.5, Respectively, Related to Transition Funding)
 717.9
 891.2
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 97.8
 114.8
 161.9
 56.3
TOTAL OTHER NONCURRENT ASSETS 1,212.1
 1,384.7
 1,119.6
 1,135.4
        
TOTAL ASSETS $9,291.7
 $8,773.6
 $10,255.8
 $9,603.7
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141126.






AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 20182019 and December 31, 20172018
(in millions)
(Unaudited)
 September 30, December 31, September 30, December 31,
 2018 2017 2019 2018
CURRENT LIABILITIES        
Advances from Affiliates $77.8
 $—
 $74.8
 $216.0
Accounts Payable:        
General 208.8
 379.4
 224.1
 276.5
Affiliated Companies 31.7
 30.2
 41.0
 30.3
Long-term Debt Due Within One Year – Nonaffiliated
(September 30, 2018 and December 31, 2017 Amounts Include $250.5 and $236.1, Respectively, Related to Transition Funding)
 500.5
 266.1
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 90.8
 77.2
 108.5
 75.5
Accrued Interest
(September 30, 2018 and December 31, 2017 Amounts Include $9 and $15.9, Respectively, Related to Transition Funding)
 54.3
 42.2
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 22.8
 —
 28.7
 24.3
Obligations Under Operating Leases 11.7
 —
Other Current Liabilities 99.5
 76.4
 85.1
 98.3
TOTAL CURRENT LIABILITIES 1,086.2
 871.5
 1,016.2
 1,259.5
        
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated
(September 30, 2018 and December 31, 2017 Amounts Include $574.7 and $790.1, Respectively, Related to Transition Funding)
 3,413.9
 3,383.2
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 902.3
 913.1
 977.7
 913.1
Regulatory Liabilities and Deferred Investment Tax Credits 1,346.4
 1,320.5
 1,325.1
 1,344.3
Oklaunion Purchase Power Agreement 28.7
 52.0
 —
 22.1
Obligations Under Operating Leases 71.1
 —
Deferred Credits and Other Noncurrent Liabilities 93.2
 63.4
 137.1
 104.0
TOTAL NONCURRENT LIABILITIES 5,784.5
 5,732.2
 6,266.2
 5,763.7
        
TOTAL LIABILITIES 6,870.7
 6,603.7
 7,282.4
 7,023.2
        
Rate Matters (Note 4) 
 
 

 

Commitments and Contingencies (Note 5) 
 
 

 

        
COMMON SHAREHOLDER’S EQUITY        
Paid-in Capital 1,157.9
 1,057.9
 1,457.9
 1,257.9
Retained Earnings 1,277.5
 1,124.6
 1,529.7
 1,337.7
Accumulated Other Comprehensive Income (Loss) (14.4) (12.6) (14.2) (15.1)
TOTAL COMMON SHAREHOLDER’S EQUITY 2,421.0
 2,169.9
 2,973.4
 2,580.5
        
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $9,291.7
 $8,773.6
 $10,255.8
 $9,603.7
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141126.






AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20182019 and 20172018
(in millions)
(Unaudited)
 Nine Months Ended September 30, Nine Months Ended September 30,
 2018 2017 2019 2018
OPERATING ACTIVITIES  
  
  
  
Net Income $151.1
 $146.6
 $192.0
 $151.1
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
  
  
Depreciation and Amortization 364.9
 343.0
 464.8
 364.9
Deferred Income Taxes (21.2) 124.1
 (0.6) (21.2)
Allowance for Equity Funds Used During Construction (15.2) (2.2) (8.3) (15.2)
Mark-to-Market of Risk Management Contracts —
 0.1
 0.2
 —
Pension Contributions to Qualified Plan Trust —
 (8.8)
Property Taxes (19.2) (15.9)
Change in Regulatory Asset – Catastrophe Reserve (22.3) (72.3)
Change in Other Noncurrent Assets (14.2) (29.1) 0.5
 (55.7)
Change in Other Noncurrent Liabilities 67.1
 7.4
 6.5
 67.1
Changes in Certain Components of Working Capital:  
    
  
Accounts Receivable, Net (26.5) (47.6) (50.0) (26.5)
Fuel, Materials and Supplies (2.4) (0.1) (0.1) (2.4)
Accounts Payable (19.1) 77.3
 17.8
 (19.1)
Accrued Taxes, Net 40.0
 1.7
 (33.4) 40.0
Other Current Assets (6.3) (2.5) (0.7) (6.3)
Other Current Liabilities 14.1
 (31.2) (12.9) 14.1
Net Cash Flows from Operating Activities 490.8
 490.5
 575.8
 490.8
        
INVESTING ACTIVITIES  
  
  
  
Construction Expenditures (1,096.1) (617.5) (954.5) (1,096.1)
Change in Advances to Affiliates, Net 103.9
 (437.0) 0.3
 103.9
Other Investing Activities 31.1
 11.5
 18.4
 31.1
Net Cash Flows Used for Investing Activities (961.1) (1,043.0) (935.8) (961.1)
        
FINANCING ACTIVITIES  
  
  
  
Capital Contribution from Parent 100.0
 200.0
 200.0
 100.0
Issuance of Long-term Debt – Nonaffiliated 494.0
 749.9
 627.5
 494.0
Change in Advances from Affiliates, Net 77.8
 (169.5) (141.2) 77.8
Retirement of Long-term Debt – Nonaffiliated (231.7) (248.4) (366.8) (231.7)
Principal Payments for Capital Lease Obligations (3.6) (3.0)
Principal Payments for Finance Lease Obligations (3.8) (3.6)
Other Financing Activities 0.9
 (0.3) (1.1) 0.9
Net Cash Flows from Financing Activities 437.4
 528.7
 314.6
 437.4
        
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding (32.9) (23.8) (45.4) (32.9)
Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding at Beginning of Period 157.2
 146.9
 159.8
 157.2
Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding at End of Period $124.3
 $123.1
 $114.4
 $124.3
        
SUPPLEMENTARY INFORMATION  
  
  
  
Cash Paid for Interest, Net of Capitalized Amounts $92.2
 $101.1
 $95.1
 $92.2
Net Cash Paid (Received) for Income Taxes (14.2) (23.3) 28.7
 (14.2)
Noncash Acquisitions Under Capital Leases 8.9
 5.3
Noncash Acquisitions Under Finance Leases 6.9
 8.9
Construction Expenditures Included in Current Liabilities as of September 30, 176.4
 166.1
 183.6
 176.4
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141126.










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,
 2018 2017 2019 2018
 (in millions) (in millions)
Plant In Service $5,988.7
 $4,664.1
 $7,409.0
 $5,988.7
Construction Work in Progress 1,772.9
 1,393.0
 1,858.4
 1,772.9
Accumulated Depreciation and Amortization 234.6
 134.0
 368.8
 234.6
Total Transmission Property, Net $7,527.0
 $5,923.1
 $8,898.6
 $7,527.0


Third Quarter of 20182019 Compared to Third Quarter of 20172018
Reconciliation of Third Quarter of 2017 to Third Quarter of 2018
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 2017 $58.6
Third Quarter of 2018 $78.1
    
Changes in Transmission Revenues:    
Transmission Revenues 28.8
 65.3
Total Change in Transmission Revenues 28.8
 65.3
    
Changes in Expenses and Other:    
Other Operation and Maintenance (7.5) (1.9)
Depreciation and Amortization (10.3) (10.4)
Taxes Other Than Income Taxes (7.6) (7.7)
Interest Income 0.3
 0.3
Allowance for Equity Funds Used During Construction 6.6
 3.0
Interest Expense (2.7) (6.6)
Total Change in Expenses and Other (21.2) (23.3)
    
Income Tax Expense 11.9
 (12.5)
    
Third Quarter of 2018 $78.1
Third Quarter of 2019 $107.6

The tables above reflect the revisions made to AEPTCo’s previously issued financial statements. For additional details on the revisions to AEPTCo’s financial statements, see Note 1 - Significant Accounting Matters.


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


•
Transmission Revenues increased $65 million primarily due to continued investment in transmission assets.
Transmission Revenues increased $29 million due to an increase in the formula rate revenue requirement primarily driven by continued investment in transmission assets. This increase includes the impact of the reduction in revenue related to Tax Reform, which was offset by a decrease in Income Tax Expense below.




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


Other Operation and Maintenance expenses increased $8 million primarily due to increased transmission investment.
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 $7 million primarily due to increased transmission investment resulting in a higher CWIP balance.
Interest Expense increased $3 million primarily due to the following:
A $5 million increase primarily due to higher long-term debt balances.
This increase was partially offset by:
A $2 million decrease due to higher AFUDC borrowed funds resulting from a higher CWIP balance.
Income Tax Expense decreased $12 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and amortization of Excess ADIT, partially offset by 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, 20182019 Compared to Nine Months Ended September 30, 20172018
Reconciliation of Nine Months Ended September 30, 2017 to Nine Months Ended September 30, 2018
Net Income
(in millions)
 
Nine Months Ended September 30, 2017 $212.4
   
Changes in Transmission Revenues:  
Transmission Revenues 51.4
Total Change in Transmission Revenues 51.4
   
Changes in Expenses and Other:  
Other Operation and Maintenance (21.6)
Depreciation and Amortization (27.8)
Taxes Other Than Income Taxes (20.9)
Interest Income 0.8
Allowance for Equity Funds Used During Construction 15.7
Interest Expense (10.3)
Total Change in Expenses and Other (64.1)
   
Income Tax Expense 44.5
   
Nine Months Ended September 30, 2018 $244.2
The table above reflects the revisions made to AEPTCo’s previously issued financial statements. For additional details on the revisions to AEPTCo’s financial statements, see Note 1 - Significant Accounting Matters.
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 nonaffiliates were as follows:
 
Transmission Revenues increased $51 million primarily due to the following:
A $115 million increase in revenues due to an increase in the formula rate revenue requirement primarily driven by continued investment in transmission assets. This increase includes the impact of the reduction in revenue related to Tax Reform, which was offset by a decrease in Income Tax Expense below.
This increase was partially offset by:
A $64 million decrease in revenues due to a lower annual formula rate true-up in 2018 driven by implementing forward looking formula rates in 2017.
•
Transmission Revenues increased $184 million primarily due to continued investment in transmission assets.
 
Expenses and Other and Income Tax Expense changed between years as follows:
 
Other Operation and Maintenance expenses increased $22 million primarily due to increased transmission investment.
Depreciation and Amortization expenses increased $28 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $21 million primarily due to higher property taxes as a result of increased transmission investment.
Allowance for Equity Funds Used During Construction increased $16 millionprimarily due to increased transmission investment resulting in a higher CWIP balance.
Interest Expense increased $10 million primarily due to the following:
•
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 $16$13 million increase primarily due to higher long-term debtCWIP balances.
ThisA $12 million increase wasdue to the FERC’s approval of a settlement agreement.
These increases were partially offset by:
A $6$13 million decrease due to higher AFUDC borrowed funds resulting from a higher CWIP balance.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 decreased $45 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, amortization of Excess ADIT and a decrease in pretax book income.





AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20182019 and 20172018
(in millions)
(Unaudited)
 Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended
 September 30, September 30, September 30, September 30,
 2018 2017 2018 2017 2019 2018 2019 2018
REVENUES                
Transmission Revenues $46.0
 $35.6
 $132.3
 $95.7
 $54.0
 $46.0
 $162.1
 $132.3
Sales to AEP Affiliates 148.4
 130.1
 453.8
 439.1
 205.7
 148.4
 608.0
 453.8
Other Revenues —
 (0.1) 0.1
 —
 —
 —
 —
 0.1
TOTAL REVENUES 194.4
 165.6
 586.2
 534.8
 259.7
 194.4
 770.1
 586.2
                
EXPENSES  
    
  
  
  
  
  
Other Operation 24.5
 18.4
 59.6
 38.8
 26.0
 24.5
 61.7
 59.6
Maintenance 2.8
 1.4
 7.6
 6.8
 3.2
 2.8
 8.9
 7.6
Depreciation and Amortization 34.9
 24.6
 97.5
 69.7
 45.3
 34.9
 128.4
 97.5
Taxes Other Than Income Taxes 35.2
 27.6
 102.9
 82.0
 42.9
 35.2
 126.2
 102.9
TOTAL EXPENSES 97.4
 72.0
 267.6
 197.3
 117.4
 97.4
 325.2
 267.6
                
OPERATING INCOME 97.0
 93.6
 318.6
 337.5
 142.3
 97.0
 444.9
 318.6
                
Other Income (Expense):  
    
  
  
  
  
  
Interest Income 0.5
 0.2
 1.3
 0.5
 0.8
 0.5
 2.1
 1.3
Allowance for Equity Funds Used During Construction 18.0
 11.4
 48.7
 33.0
 21.0
 18.0
 61.1
 48.7
Interest Expense (19.8) (17.1) (60.7) (50.4) (26.4) (19.8) (69.5) (60.7)
                
INCOME BEFORE INCOME TAX EXPENSE 95.7
 88.1
 307.9
 320.6
 137.7
 95.7
 438.6
 307.9
                
Income Tax Expense 17.6
 29.5
 63.7
 108.2
 30.1
 17.6
 90.7
 63.7
                
NET INCOME $78.1
 $58.6
 $244.2
 $212.4
 $107.6
 $78.1
 $347.9
 $244.2
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141126.




AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY
For the Nine Months Ended September 30, 20182019 and 20172018
(in millions)
(Unaudited)
 Paid-in
Capital		 Retained
Earnings		 Total Paid-in
Capital		 Retained
Earnings		 Total
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2016 $1,455.0
 $502.6
 $1,957.6
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 185.5
   185.5
 312.0
   312.0
Net Income  
 212.4
 212.4
   82.0
 82.0
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2017 $1,640.5
 $715.0
 $2,355.5
TOTAL MEMBER'S EQUITY – JUNE 30, 2018 2,193.6
 939.4
 3,133.0
            
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2017 $1,816.6
 $773.3
 $2,589.9
      
Capital Contributions from Member 582.0
   582.0
Capital Contribution from Member 205.0
   205.0
Net Income  
 244.2
 244.2
   78.1
 78.1
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2018 $2,398.6
 $1,017.5
 $3,416.1
 $2,398.6
 $1,017.5
 $3,416.1
      
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2018 $2,480.6
 $1,089.2
 $3,569.8
      
Net Income   104.3
 104.3
TOTAL MEMBER'S EQUITY – MARCH 31, 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 Financial Statements of Registrants beginning on page 141126.





AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20182019 and December 31, 20172018
(in millions)
(Unaudited)
 September 30, December 31, September 30, December 31,
 2018 2017 2019 2018
CURRENT ASSETS        
Advances to Affiliates $278.0
 $146.3
 $275.2
 $96.9
Accounts Receivable:        
Customers 11.9
 15.0
 23.5
 11.8
Affiliated Companies 73.0
 93.2
 61.3
 61.0
Miscellaneous 1.1
 1.3
Total Accounts Receivable 86.0
 109.5
 84.8
 72.8
Materials and Supplies 16.4
 13.6
 15.1
 19.0
Accrued Tax Benefits 29.8
 49.4
 9.7
 33.4
Prepayments and Other Current Assets 3.5
 7.6
 4.4
 3.4
TOTAL CURRENT ASSETS 413.7
 326.4
 389.2
 225.5
        
TRANSMISSION PROPERTY        
Transmission Property 5,833.5
 5,319.7
 7,181.8
 6,515.8
Other Property, Plant and Equipment 155.2
 126.8
 227.2
 174.0
Construction Work in Progress 1,772.9
 1,324.0
 1,858.4
 1,578.3
Total Transmission Property 7,761.6
 6,770.5
 9,267.4
 8,268.1
Accumulated Depreciation and Amortization 234.6
 152.6
 368.8
 271.9
TOTAL TRANSMISSION PROPERTY – NET
 7,527.0
 6,617.9
 8,898.6
 7,996.2
        
OTHER NONCURRENT ASSETS        
Accounts Receivable – Affiliated Companies 4.8
 —
Regulatory Assets 15.3
 11.7
 7.3
 12.9
Deferred Property Taxes 38.1
 125.0
 47.2
 157.9
Deferred Charges and Other Noncurrent Assets 4.3
 1.1
 5.6
 1.6
TOTAL OTHER NONCURRENT ASSETS 57.7
 137.8
 64.9
 172.4
        
TOTAL ASSETS $7,998.4
 $7,082.1
 $9,352.7
 $8,394.1
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141126.




AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND MEMBER’S EQUITY
September 30, 20182019 and December 31, 20172018
(in millions)
(Unaudited)
 September 30, December 31, September 30, December 31,
 2018 2017 2019 2018
CURRENT LIABILITIES        
Advances from Affiliates $1.1
 $15.7
 $9.1
 $45.4
Accounts Payable:        
General 237.4
 484.5
 319.1
 347.2
Affiliated Companies 79.0
 66.1
 57.1
 56.0
Long-term Debt Due Within One Year – Nonaffiliated 50.0
 50.0
 85.0
 85.0
Accrued Taxes 138.7
 231.5
 172.4
 288.9
Accrued Interest 35.9
 15.0
 39.7
 15.9
Obligations Under Operating Leases 2.3
 —
Other Current Liabilities 4.3
 4.1
 25.5
 3.8
TOTAL CURRENT LIABILITIES 546.4
 866.9
 710.2
 842.2
        
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated 2,822.6
 2,500.4
 3,426.9
 2,738.0
Deferred Income Taxes 684.4
 600.4
 751.4
 704.4
Regulatory Liabilities 509.6
 493.8
 541.2
 521.3
Obligations Under Operating Leases 2.2
 —
Deferred Credits and Other Noncurrent Liabilities 19.3
 30.7
 3.1
 18.4
TOTAL NONCURRENT LIABILITIES 4,035.9
 3,625.3
 4,724.8
 3,982.1
        
TOTAL LIABILITIES 4,582.3
 4,492.2
 5,435.0
 4,824.3
        
Rate Matters (Note 4) 
 
 

 

Commitments and Contingencies (Note 5) 
 
 

 

        
MEMBER’S EQUITY        
Paid-in Capital 2,398.6
 1,816.6
 2,480.6
 2,480.6
Retained Earnings 1,017.5
 773.3
 1,437.1
 1,089.2
TOTAL MEMBER’S EQUITY 3,416.1
 2,589.9
 3,917.7
 3,569.8
        
TOTAL LIABILITIES AND MEMBER’S EQUITY $7,998.4
 $7,082.1
 $9,352.7
 $8,394.1
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141126.




AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20182019 and 20172018
(in millions)
(Unaudited)
 Nine Months Ended September 30, Nine Months Ended September 30,
 2018 2017 2019 2018
OPERATING ACTIVITIES        
Net Income $244.2
 $212.4
 $347.9
 $244.2
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:        
Depreciation and Amortization 97.5
 69.7
 128.4
 97.5
Deferred Income Taxes 76.3
 191.9
 36.7
 76.3
Allowance for Equity Funds Used During Construction (48.7) (33.0) (61.1) (48.7)
Property Taxes 86.9
 72.4
 110.7
 86.9
Long-term Accounts Receivable – Affiliated (3.1) (13.8) (4.8) (3.1)
Change in Other Noncurrent Assets 12.7
 8.6
 5.8
 12.7
Change in Other Noncurrent Liabilities 18.0
 25.7
 (3.8) 18.0
Changes in Certain Components of Working Capital:    
    
Accounts Receivable 23.5
 (40.8)
Accounts Receivable, Net (5.1) 23.5
Materials and Supplies (2.8) (11.0) 3.9
 (2.8)
Accounts Payable 3.3
 20.4
 4.1
 3.3
Accrued Taxes, Net (73.2) (71.2) (92.8) (73.2)
Accrued Interest 20.9
 18.4
 23.8
 20.9
Other Current Assets (0.5) (5.3) (1.0) (0.5)
Other Current Liabilities (28.0) 0.5
 (8.5) (28.0)
Net Cash Flows from Operating Activities 427.0
 444.9
 484.2
 427.0
        
INVESTING ACTIVITIES  
  
  
  
Construction Expenditures (1,171.8) (1,050.7) (959.9) (1,171.8)
Change in Advances to Affiliates, Net (131.7) (223.8) (178.3) (131.7)
Acquisitions of Assets (13.2) (3.8) (7.6) (13.2)
Other Investing Activities 1.2
 0.9
 12.0
 1.2
Net Cash Flows Used for Investing Activities (1,315.5) (1,277.4) (1,133.8) (1,315.5)
        
FINANCING ACTIVITIES    
    
Capital Contributions from Member 582.0
 185.5
 —
 582.0
Issuance of Long-term Debt – Nonaffiliated 321.1
 618.3
 685.9
 321.1
Change in Advances from Affiliates, Net (14.6) 28.7
 (36.3) (14.6)
Net Cash Flows from Financing Activities 888.5
 832.5
 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 $38.4
 $30.4
 $43.0
 $38.4
Net Cash Paid (Received) for Income Taxes (32.1) (93.4) 29.8
 (32.1)
Construction Expenditures Included in Current Liabilities as of September 30, 237.0
 248.9
 315.1
 237.0
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141126.








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,
2018 2017 2018 20172019 2018 2019 2018
(in millions of KWhs)(in millions of KWhs)
Retail: 
  
  
  
 
  
  
  
Residential2,662
 2,488
 8,895
 7,829
2,728
 2,662
 8,401
 8,895
Commercial1,721
 1,673
 4,996
 4,805
1,721
 1,715
 4,812
 4,980
Industrial2,427
 2,431
 7,165
 7,106
2,487
 2,433
 7,180
 7,181
Miscellaneous215
 202
 644
 613
216
 215
 640
 644
Total Retail(a)7,025
 6,794
 21,700
 20,353
7,152
 7,025
 21,033
 21,700
              
Wholesale1,143
 994
 2,252
 2,684
938
 1,143
 2,667
 2,252
              
Total KWhs8,168
 7,788
 23,952
 23,037
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 EndedThree Months Ended Nine Months Ended
September 30, September 30,September 30, September 30,
2018 2017 2018 20172019 2018 2019 2018
(in degree days)(in degree days)
Actual – Heating (a)—
 —
 1,518
 1,000
—
 —
 1,295
 1,518
Normal – Heating (b)2
 2
 1,410
 1,420
3
 2
 1,407
 1,410
              
Actual – Cooling (c)950
 805
 1,495
 1,180
1,071
 950
 1,530
 1,495
Normal – Cooling (b)814
 812
 1,184
 1,179
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 20182019 Compared to Third Quarter of 20172018
Reconciliation of Third Quarter of 2017 to Third Quarter of 2018
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 2017 $86.0
Third Quarter of 2018 $72.7
  
  
Changes in Gross Margin:  
  
Retail Margins (64.0) 17.5
Off-system Sales 1.4
Transmission Revenues 2.4
 (1.7)
Other Revenues (1.2) 3.4
Total Change in Gross Margin (61.4) 19.2
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance (56.3) (17.1)
Depreciation and Amortization (2.9) (2.9)
Taxes Other Than Income Taxes (1.3) (2.1)
Interest Income 0.1
Carrying Costs Income (0.2)
Allowance for Equity Funds Used During Construction 1.4
Other Income (2.6)
Non-Service Cost Components of Net Periodic Benefit Cost 3.2
 (0.1)
Interest Expense (3.6) 5.7
Total Change in Expenses and Other (59.6) (19.1)
  
  
Income Tax Expense (Credit) 122.1
Income Tax Expense (Benefit) 16.0
  
  
Third Quarter of 2018 $87.1
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 $64An $8 million increase related to rider revenues, primarily due to the following:
A $78 million reduction in deferred fuel under-recovery related totiming of the West Virginia Tax Reform settlement.Indiana PJM/OSS rider recovery. This decreaseincrease was partially offset in Income Tax Expense (Credit)other expense items below.
An $11 million increase in deferred fuel related to recoverable PJM expenses that were offset below.
A $10 million increase in non-recoverable fuel expense related to Virginia legislation.
These decreasesincreases were partially offset by:
A $17$6 million increase due to an adjustment to the 2018 provisions for customer refunds related to Tax Reform. This increase was partially offsetdecrease in Other Operation and Maintenance expenses and Income Tax Expense (Credit) below.weather-normalized margins across all retail classes.
A $15$3 million increasedecrease in weather-related usage primarily due to an 18% increasea 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.


Expenses and Other and Income Tax Expense (Credit)(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 increased $56 million primarily due to the following:
A $39a $10 million increase in recoverable PJM expenses due toand a $6 million increase from the extinguishmentamortization of regulatory asset balances as agreed to withincredits under the West Virginia Tax Reform2018 Regional Transmission Enhancement Plan settlement. This increase was partially offset in Retail Margins above and Income Tax Expense (Credit) below.above.
An $8A $4 million increase in employee-related expenses.
Non-Service Cost Components of Net Periodic Benefit Cost decreased $3 million primarily due to favorable asset returnsRTD expenses for the funded Pension and OPEB plans, favorable OPEB cost savings arrangements and the implementation of ASU 2017-07.barging activities. The increase in RTD expenses was offset by a corresponding increase in 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.


Income Tax Expense (Credit) decreased $122 million primarily due to the impact of the West Virginia Tax Reform settlement, the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, amortization of Excess ADIT and a decrease in pretax book income.



Nine Months Ended September 30, 20182019 Compared to Nine Months Ended September 30, 20172018
Reconciliation of Nine Months Ended September 30, 2017 to Nine Months Ended September 30, 2018
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, 2017 $248.7
Nine Months Ended September 30, 2018 $231.6
    
Changes in Gross Margin:  
  
Retail Margins (61.0) 89.7
Off-system Sales 1.7
Margins from Off-system Sales (9.4)
Transmission Revenues 2.8
 (12.0)
Other Revenues (4.6) 3.7
Total Change in Gross Margin (61.1) 72.0
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance (57.0) (36.6)
Depreciation and Amortization (15.4) (54.5)
Taxes Other Than Income Taxes (7.8) (5.7)
Interest Income 0.2
Carrying Costs Income 0.2
Allowance for Equity Funds Used During Construction 3.4
Other Income (0.1)
Non-Service Cost Components of Net Periodic Benefit Cost 9.5
 (0.3)
Interest Expense (2.5) 9.7
Total Change in Expenses and Other (69.4) (87.5)
  
  
Income Tax Expense (Credit) 171.8
Income Tax Expense (Benefit) 31.9
  
  
Nine Months Ended September 30, 2018 $290.0
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 decreased $61A $94 million primarily due to the following:
A $78 million reductionincrease from rate proceedings, inclusive of deferred fuel under-recovery related to the West Virginia Tax Reform settlement. This decrease was offset in Income Tax Expense (Credit) below.
A $41a $30 million decrease due to the 2018 provisions for customer refunds related toimpact of Tax Reform. This decreaseincrease was partially offset in Other Operation and Maintenance expenses and Income Tax Expense (Credit)other expense items below.
A $28$21 million increase in deferred fuel related to recoverable PJM expenses that wererider revenues, primarily due to the timing of the Indiana PJM/OSS rider recovery. This increase was partially offset in other expense items below.
A $10$6 million increasedecrease in non-recoverablefuel-related expenses due to timing of recovery for fuel expenseand other variable production costs related to Virginia legislation.wholesale contracts.
These increases were partially offset by:
A $5$19 million decrease in weather-related usage primarily due to a 15% decrease in cooling degree days and a 3% decrease in heating degree days.
A $16 million decrease in weather-normalized margins occurring 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.
These decreases were partially offset by:
A $90 million increase in weather-related usage primarily driven by a 52% increase in heating degree days along with a 27% increase in cooling degree days.
A $6 million increase primarily due to increases from rate riders in Virginia. This increase was partially offset by an increase in Other Operation and Maintenance expenses.



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


Other Operation and Maintenance expenses increased $57$37 million primarily due to the following:
A $39$32 million increase in transmission expenses primarily due to a $44 million increase in recoverable PJM expenses, partially offset by an $11 million decrease from the extinguishmentamortization of regulatory asset balances as agreed to withincredits under the West Virginia Tax Reform2018 Regional Transmission Enhancement Plan settlement. This increase was partially offset in Retail Margins above and Income Tax Expense (Credit) below.above.
A $21$6 million increase in recoverable PJM expenses. ThisRTD expenses for barging activities. The increase in expenseRTD expenses was primarily offset within Retail Margins above.
A $13 millionby a corresponding increase in employee-related expenses.
A $9 million increase in storm-related expenses.Other Revenues from barging activities discussed above.
A $5 million increase in estimated expenses for claims relateddistribution costs primarily due to asbestos exposure.vegetation management expenses.
These increases were partially offset by:
A $41$9 million decrease in PJMgeneration expenses primarily related to the annual formula rate true-up that will be refunded in future periods.
Depreciation and Amortization expenses increased $15 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.

Taxes Other Than Income Taxes increased $8 million primarily due to an increase in property taxes due to additional investments in utility plant.

Allowance for Equity Funds Used During Construction increased $3 million due to an increase in construction activity.
Non-Service Cost Components of Net Periodic Benefit Cost decreased $10 million primarily due to favorable asset returns for the funded Pension and OPEB plans, favorable OPEB cost savings arrangements and the implementation of ASU 2017-07.
Income Tax Expense (Credit) decreased $172 million primarily due to the impact of the West Virginia Tax Reform settlement, the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, amortization of Excess ADIT and a decrease in pretax book income.




APPALACHIANINDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20182019 and 20172018
(in millions)
(Unaudited)
 Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended
 September 30, September 30, September 30, September 30,
 2018 2017 2018 2017 2019 2018 2019 2018
REVENUES        
        
Electric Generation, Transmission and Distribution $716.8
 $674.4
 $2,103.1
 $2,045.0
 $589.1
 $609.9
 $1,703.2
 $1,723.9
Sales to AEP Affiliates 42.9
 41.9
 138.7
 130.6
 2.7
 3.4
 7.3
 18.9
Other Revenues 2.3
 3.0
 7.6
 11.8
Other Revenues – Affiliated 16.2
 13.7
 50.4
 43.3
Other Revenues – Nonaffiliated 3.1
 2.7
 7.6
 10.1
TOTAL REVENUES 762.0
 719.3
 2,249.4
 2,187.4
 611.1
 629.7
 1,768.5
 1,796.2
                
EXPENSES  
    
  
  
  
  
  
Fuel and Other Consumables Used for Electric Generation 263.4
 178.6
 487.7
 498.3
 61.2
 95.9
 161.2
 246.8
Purchased Electricity for Resale 80.4
 61.1
 350.8
 217.1
 44.8
 48.9
 163.3
 167.7
Purchased Electricity from AEP Affiliates 61.0
 60.0
 172.1
 181.8
Other Operation 131.9
 117.0
 380.0
 370.1
 172.7
 149.3
 467.7
 425.8
Maintenance 97.2
 55.8
 234.9
 187.8
 50.9
 57.2
 163.8
 169.1
Depreciation and Amortization 105.7
 102.8
 319.5
 304.1
 88.1
 85.2
 261.6
 207.1
Taxes Other Than Income Taxes 33.6
 32.3
 101.1
 93.3
 25.1
 23.0
 78.6
 72.9
TOTAL EXPENSES 712.2
 547.6
 1,874.0
 1,670.7
 503.8
 519.5
 1,468.3
 1,471.2
                
OPERATING INCOME 49.8
 171.7
 375.4
 516.7
 107.3
 110.2
 300.2
 325.0
                
Other Income (Expense):  
    
  
  
  
  
  
Interest Income 0.4
 0.3
 1.3
 1.1
Carrying Costs Income 0.2
 0.4
 1.2
 1.0
Allowance for Equity Funds Used During Construction 4.1
 2.7
 9.6
 6.2
Other Income 3.5
 6.1
 15.3
 15.4
Non-Service Cost Components of Net Periodic Benefit Cost 4.5
 1.3
 13.4
 3.9
 4.5
 4.6
 13.3
 13.6
Interest Expense (50.8) (47.2) (146.0) (143.5) (28.8) (34.5) (85.9) (95.6)
                
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) 8.2
 129.2
 254.9
 385.4
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 86.5
 86.4
 242.9
 258.4
                
Income Tax Expense (Credit) (78.9) 43.2
 (35.1) 136.7
Income Tax Expense (Benefit) (2.3) 13.7
 (5.1) 26.8
                
NET INCOME $87.1
 $86.0
 $290.0
 $248.7
 $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 141126.



APPALACHIAN
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20182019 and 20172018
(in millions)
(Unaudited)
  
  Three Months Ended
 Nine Months Ended
  September 30, September 30,
  2018 2017 2018 2017
Net Income $87.1
 $86.0
 $290.0
 $248.7
         
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, 2018 and 2017, Respectively, and $(0.2) and $(0.3) for the Nine Months Ended September 30, 2018 and 2017, Respectively (0.3) (0.1) (0.7) (0.5)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.2) and $(0.1) for the Three Months Ended September 30, 2018 and 2017, Respectively, and $(0.6) and $(0.4) for the Nine Months Ended September 30, 2018 and 2017, Respectively (0.7) (0.3) (2.3) (0.9)
         
TOTAL OTHER COMPREHENSIVE LOSS (1.0) (0.4) (3.0) (1.4)
         
TOTAL COMPREHENSIVE INCOME $86.1
 $85.6
 $287.0
 $247.3
  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 141126.



APPALACHIAN
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 20182019 and 20172018
(in millions)
(Unaudited)
 
Common
Stock
 
Paid-in
Capital
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2016 $260.4
 $1,828.7
 $1,502.8
 $(8.4) $3,583.5
          
Common Stock Dividends  
  
 (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 $260.4
 $1,828.7
 $1,714.1
 $1.3
 $3,804.5
 $56.6
 $980.9
 $1,192.2
 $(12.1) $2,217.6
                    
Common Stock Dividends  
  
 (120.0)  
 (120.0)  
  
 (33.5)  
 (33.5)
ASU 2018-02 Adoption     0.1
 0.3
 0.4
     0.3
 (2.7) (2.4)
Net Income  
  
 290.0
  
 290.0
  
  
 64.2
  
 64.2
Other Comprehensive Loss  
  
  
 (3.0) (3.0)
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 $260.4
 $1,828.7
 $1,884.2
 $(1.4) $3,971.9
 $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 141126.



APPALACHIAN
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20182019 and December 31, 20172018
(in millions)
(Unaudited)
  September 30, December 31,
  2018 2017
CURRENT ASSETS    
Cash and Cash Equivalents $2.2
 $2.9
Restricted Cash for Securitized Funding 9.9
 16.3
Advances to Affiliates 23.1
 23.5
Accounts Receivable:    
Customers 155.7
 123.1
Affiliated Companies 70.6
 69.3
Accrued Unbilled Revenues 52.6
 74.1
Miscellaneous 0.9
 1.1
Allowance for Uncollectible Accounts (4.0) (3.7)
Total Accounts Receivable 275.8
 263.9
Fuel 37.7
 89.3
Materials and Supplies 98.4
 99.5
Risk Management Assets 68.4
 24.9
Regulatory Asset for Under-Recovered Fuel Costs 79.9
 88.8
Margin Deposits 12.5
 14.4
Prepayments and Other Current Assets 23.0
 12.7
TOTAL CURRENT ASSETS 630.9
 636.2
     
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Generation 6,490.0
 6,446.9
Transmission 3,141.2
 3,019.9
Distribution 3,897.2
 3,763.8
Other Property, Plant and Equipment 461.4
 427.9
Construction Work in Progress 602.1
 483.0
Total Property, Plant and Equipment 14,591.9
 14,141.5
Accumulated Depreciation and Amortization 4,086.2
 3,896.4
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 10,505.7
 10,245.1
     
OTHER NONCURRENT ASSETS    
Regulatory Assets 475.3
 573.9
Securitized Assets 264.5
 282.3
Long-term Risk Management Assets 1.4
 1.1
Deferred Charges and Other Noncurrent Assets 180.1
 190.0
TOTAL OTHER NONCURRENT ASSETS 921.3
 1,047.3
     
TOTAL ASSETS $12,057.9
 $11,928.6
  September 30, December 31,
  2019 2018
CURRENT ASSETS    
Cash and Cash Equivalents $2.5
 $2.4
Advances to Affiliates 13.2
 12.7
Accounts Receivable:    
Customers 45.0
 63.1
Affiliated Companies 45.3
 75.0
Accrued Unbilled Revenues 2.7
 3.6
Miscellaneous 1.0
 1.4
Allowance for Uncollectible Accounts (0.1) (0.1)
Total Accounts Receivable 93.9
 143.0
Fuel 39.8
 37.3
Materials and Supplies 169.9
 167.3
Risk Management Assets 10.5
 8.6
Accrued Tax Benefits 43.2
 26.6
Accrued Reimbursement of Spent Nuclear Fuel Costs 24.2
 7.9
Prepayments and Other Current Assets 16.9
 24.6
TOTAL CURRENT ASSETS 414.1
 430.4
     
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Generation 5,002.0
 4,887.2
Transmission 1,614.5
 1,576.8
Distribution 2,373.3
 2,249.7
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) 607.2
 583.8
Construction Work in Progress 516.2
 465.3
Total Property, Plant and Equipment 10,113.2
 9,762.8
Accumulated Depreciation, Depletion and Amortization 3,280.5
 3,151.6
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 6,832.7
 6,611.2
     
OTHER NONCURRENT ASSETS    
Regulatory Assets 490.2
 512.5
Spent Nuclear Fuel and Decommissioning Trusts 2,835.2
 2,474.9
Long-term Risk Management Assets 0.1
 0.6
Operating Lease Assets 295.3
 —
Deferred Charges and Other Noncurrent Assets 129.6
 193.0
TOTAL OTHER NONCURRENT ASSETS 3,750.4
 3,181.0
     
TOTAL ASSETS $10,997.2
 $10,222.6
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141126.



APPALACHIAN
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 20182019 and December 31, 20172018
(dollars in millions)
(Unaudited)
 September 30, December 31,
 2018 2017 September 30, December 31,
 (in millions) 2019 2018
CURRENT LIABILITIES        
Advances from Affiliates $98.5
 $186.0
 $102.4
 $1.1
Accounts Payable:  
  
    
General 219.1
 264.9
 148.4
 174.7
Affiliated Companies 73.6
 92.7
 71.6
 70.2
Long-term Debt Due Within One Year – Nonaffiliated 430.7
 249.2
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
 1.3
 0.2
 0.3
Customer Deposits 88.0
 86.1
 37.9
 38.0
Accrued Taxes 81.5
 94.5
 57.9
 90.7
Accrued Interest 72.6
 40.5
 20.5
 37.3
Obligations Under Operating Leases 82.0
 —
Regulatory Liability for Over-Recovered Fuel Costs 7.3
 27.4
Other Current Liabilities 151.6
 109.0
 85.5
 103.0
TOTAL CURRENT LIABILITIES 1,216.5
 1,124.2
 761.1
 698.1
        
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated 3,631.0
 3,730.9
 2,884.1
 2,880.0
Long-term Risk Management Liabilities 0.7
 0.2
 —
 0.1
Deferred Income Taxes 1,581.5
 1,565.7
 970.0
 948.0
Regulatory Liabilities and Deferred Investment Tax Credits 1,423.8
 1,454.9
 1,809.0
 1,574.5
Asset Retirement Obligations 103.2
 100.2
 1,731.5
 1,681.3
Employee Benefits and Pension Obligations 65.7
 73.3
Obligations Under Operating Leases 234.0
 —
Deferred Credits and Other Noncurrent Liabilities 63.6
 74.7
 65.6
 87.8
TOTAL NONCURRENT LIABILITIES 6,869.5
 6,999.9
 7,694.2
 7,171.7
        
TOTAL LIABILITIES 8,086.0
 8,124.1
 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 1,884.2
 1,714.1
 1,517.1
 1,329.1
Accumulated Other Comprehensive Income (Loss) (1.4) 1.3
 (12.7) (13.8)
TOTAL COMMON SHAREHOLDER’S EQUITY 3,971.9
 3,804.5
 2,541.9
 2,352.8
        
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $12,057.9
 $11,928.6
 $10,997.2
 $10,222.6
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141126.



APPALACHIAN
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20182019 and 20172018
(in millions)
(Unaudited)
 Nine Months Ended September 30, Nine Months Ended September 30,
 2018 2017 2019 2018
OPERATING ACTIVITIES  
  
  
  
Net Income $290.0
 $248.7
 $248.0
 $231.6
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
  
  
Depreciation and Amortization 319.5
 304.1
 261.6
 207.1
Rent - Rockport Plant, Unit 2 58.9
 —
Deferred Income Taxes (83.8) 121.7
 (29.9) 28.1
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net (11.6) 13.5
Allowance for Equity Funds Used During Construction (9.6) (6.2) (16.4) (8.0)
Mark-to-Market of Risk Management Contracts (43.7) (28.3) (1.6) (0.3)
Pension Contributions to Qualified Plan Trust —
 (10.2)
Amortization of Nuclear Fuel 71.6
 82.6
Deferred Fuel Over/Under-Recovery, Net 12.8
 4.9
 (20.0) 29.6
Change in Other Noncurrent Assets 94.8
 37.1
 46.0
 (12.0)
Change in Other Noncurrent Liabilities 3.8
 7.9
 13.8
 46.3
Changes in Certain Components of Working Capital:  
  
  
  
Accounts Receivable, Net 39.4
 39.9
 50.5
 6.5
Fuel, Materials and Supplies 53.0
 14.0
 (4.6) (1.1)
Accounts Payable (21.5) 6.2
 (7.3) (34.7)
Accrued Taxes, Net (20.2) (44.2) (49.4) (7.1)
Payments for Rockport Plant, Unit 2 Operating Lease (36.9) —
Other Current Assets (7.9) (2.5) 7.8
 4.9
Other Current Liabilities 64.1
 9.1
 (49.7) (15.7)
Net Cash Flows from Operating Activities 690.7
 702.2
 530.8
 571.3
        
INVESTING ACTIVITIES  
  
  
  
Construction Expenditures (575.8) (560.0) (431.7) (434.5)
Change in Advances to Affiliates, Net 0.4
 0.5
 (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 10.0
 11.8
 10.5
 9.2
Net Cash Flows Used for Investing Activities (565.4) (547.7) (557.9) (549.6)
        
FINANCING ACTIVITIES  
  
  
  
Issuance of Long-term Debt - Nonaffiliated 103.3
 320.9
Issuance of Long-term Debt – Nonaffiliated 62.9
 1,168.1
Change in Advances from Affiliates, Net (87.5) (10.1) 101.3
 (211.6)
Retirement of Long-term Debt - Nonaffiliated (24.0) (377.9)
Principal Payments for Capital Lease Obligations (5.2) (5.2)
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 (120.0) (90.0) (60.0) (105.5)
Other Financing Activities 1.0
 0.5
 0.6
 (9.0)
Net Cash Flows Used for Financing Activities (132.4) (161.8)
Net Cash Flows from (Used for) Financing Activities 27.2
 (21.4)
        
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding (7.1) (7.3)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period 19.2
 18.5
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period $12.1
 $11.2
Net Increase in Cash and Cash Equivalents 0.1
 0.3
Cash and Cash Equivalents at Beginning of Period 2.4
 1.3
Cash and Cash Equivalents at End of Period $2.5
 $1.6
        
SUPPLEMENTARY INFORMATION  
  
  
  
Cash Paid for Interest, Net of Capitalized Amounts $104.5
 $107.1
 $98.7
 $104.4
Net Cash Paid for Income Taxes 26.7
 24.4
Noncash Acquisitions Under Capital Leases 3.9
 2.9
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, 87.6
 107.2
 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 141126.







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,
2018 2017 2018 20172019 2018 2019 2018
(in millions of KWhs)(in millions of KWhs)
Retail: 
  
  
  
 
  
  
  
Residential1,562
 1,404
 4,430
 4,015
4,120
 4,055
 11,034
 11,475
Commercial1,363
 1,313
 3,748
 3,640
4,067
 3,971
 11,072
 11,146
Industrial2,003
 1,978
 5,880
 5,793
3,689
 3,688
 10,936
 11,066
Miscellaneous15
 16
 50
 50
26
 27
 83
 84
Total Retail(b)4,943
 4,711
 14,108
 13,498
11,902
 11,741
 33,125
 33,771
              
Wholesale(c)2,613
 2,807
 7,927
 8,567
453
 634
 1,531
 1,835
              
Total KWhs7,556
 7,518
 22,035
 22,065
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 Three Months Ended Nine Months Ended
September 30, September 30, September 30, September 30,
2018 2017 2018 2017 2019 2018 2019 2018
(in degree days) (in degree days)
Actual – Heating (a)2
 —
 2,523
 1,816
 —
 —
 2,006
 2,158
Normal – Heating (b)10
 11
 2,413
 2,430
 6
 6
 2,072
 2,076
               
Actual – Cooling (c)722
 504
 1,084
 764
 872
 864
 1,176
 1,322
Normal – Cooling (b)574
 574
 837
 835
 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 20182019 Compared to Third Quarter of 20172018
Reconciliation of Third Quarter of 2017 to Third Quarter of 2018
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 2017 $64.9
Third Quarter of 2018 $88.7
  
  
Changes in Gross Margin:  
  
Retail Margins 42.4
 (2.9)
Off-system Sales (3.8)
Margins from Off-system Sales (12.2)
Transmission Revenues 1.8
 0.5
Other Revenues (1.5) 1.7
Total Change in Gross Margin 38.9
 (12.9)
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance (13.0) 23.7
Depreciation and Amortization (30.2) 13.0
Taxes Other Than Income Taxes 0.9
 (5.1)
Interest Income 1.4
Carrying Cost Income (1.6)
Carrying Costs Income 0.1
Allowance for Equity Funds Used During Construction 0.4
 2.8
Non-Service Cost Components of Net Periodic Benefit Cost 3.1
 (0.1)
Interest Expense (7.0) (1.8)
Total Change in Expenses and Other (46.0) 32.6
  
  
Income Tax Expense 14.9
Income Tax Expense (Benefit) (39.3)
  
  
Third Quarter of 2018 $72.7
Third Quarter of 2019 $69.1

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 $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.
A $13 million decrease in 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 margin 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. 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 recoverable distribution expenses related to vegetation management. This decrease was partially offset in Retail Margins above.
A $4 million decrease due to higher charitable contributions in 2018.
These decreases were partially offset by:
A $13 million increase in PJM expenses primarily related to the annual formula rate true-up.
•
Depreciation and Amortization expensesdecreased $13 million primarily due to the following:
An $8 million decrease in amortizations associated with the Deferred Asset Phase-In-Recovery Rider which ended in the second quarter of 2019. This decrease was offset in Retail Margins above.
A $6 million decrease in recoverable DIR depreciation expense. This decrease was partially offset in Retail Margins above.
These decreases were partially offset by:
A $4 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
•
Taxes Other Than Income Taxes increased $5 million primarily due to 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, 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 $237.1
   
Changes in Gross Margin:  
Retail Margins 9.2
Margins from Off-system Sales (20.8)
Transmission Revenues 5.9
Other Revenues 6.0
Total Change in Gross Margin 0.3
   
Changes in Expenses and Other:  
Other Operation and Maintenance 28.7
Depreciation and Amortization 23.5
Taxes Other Than Income Taxes (15.9)
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 (1.5)
Total Change in Expenses and Other 39.8
   
Income Tax Expense (Benefit) (29.5)
   
Nine Months Ended September 30, 2019 $247.7

The major components of the increase 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 increased $42
•
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 $47$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 from rate proceedings in the I&M service territory, inclusive of a $22 million decrease due to the impact of Tax Reform in the Indiana jurisdiction. Therevenues associated with smart grid riders. This increase in Retail Margins relating to riders had corresponding increaseswas partially offset in other expense items below.
A $21 million increase in weather-related usage primarily due to the recovery of higher current year losses from a 43%power contract with OVEC. This increase was offset in Margins from Off-system Sales below.
A $9 million increase in cooling degree days.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 $15$71 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.
An $18 million decrease related to over/under recoveryin revenues associated with a vegetation management rider. This decrease was offset in Other Operation and Maintenance expenses below.
A $16 million net decrease in margin for the Phase-In-Recovery Rider including associated amortizations which ended in the first quarter of riders.2019.
A $13 million decrease in 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 $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 due to timing differences in rider revenues associated with the recovery of increased fuel and other variable production costs not related to fuel clauses or other trackers.
A $3 million decrease due to customer refunds related to Tax Reform.DIR. This decrease was partially offset in Income Tax Expenseother 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.
A $3 million decrease due to lower weather-normalized margins primarily due to wholesale customer load loss from contracts that expired at the end of 2017.
Margins from Off-system Sales decreased $4 million primarily due to mid-year changes in the OSS sharing mechanism.




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


Other Operation and Maintenance expenses increased $13 million primarily due to the following:
•
Other Operation and Maintenance expenses decreased $29 million primarily due to the following:
A $5$78 million increase in demand-side management expenses. This increase was offset within Retail Margins above.
A $5 million increase in distribution forestry expenses.
A $4 million increase in Cook Plant refueling outage amortization expense, primarily due to increased costs of outages.
A $4 million increase in employee-related expenses.
These increases were partially offset by:
A $5 million decrease in transmission expenses primarily due to a decrease in recoverable PJM expenses. This decrease was offset in Gross Margin above.
A $10 million decrease in recoverable distribution expenses related to vegetation management. This decrease was partially offset withinin Retail Margins above.
Depreciation and Amortization expensesincreased $30 million primarily due to a higher depreciable base and increased depreciation rates approved in the 2017 Indiana and Michigan base rate cases.
Non-Service Cost Components of Net Periodic Benefit Cost decreased $3 million primarily due to favorable asset returns for the funded Pension and OPEB plans, favorable OPEB cost savings arrangements and the implementation of ASU 2017-07.
Interest Expense increased $7 million primarily due to increased long-term debt balances.
Income Tax Expense decreased $15 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, amortization of Excess ADIT and a decrease in pretax book income.


Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017
Reconciliation of Nine Months Ended September 30, 2017 to Nine Months Ended September 30, 2018
Net Income
(in millions)
   
Nine Months Ended September 30, 2017 $143.8
   
Changes in Gross Margin:  
Retail Margins 105.3
Off-system Sales (5.4)
Transmission Revenues 23.3
Other Revenues (3.2)
Total Change in Gross Margin 120.0
   
Changes in Expenses and Other:  
Other Operation and Maintenance (2.5)
Depreciation and Amortization (52.3)
Taxes Other Than Income Taxes (4.6)
Interest Income 1.2
Carrying Cost Income (5.3)
Allowance for Equity Funds Used During Construction (0.1)
Non-Service Cost Components of Net Periodic Benefit Cost 9.0
Interest Expense (12.6)
Total Change in Expenses and Other (67.2)
   
Income Tax Expense 35.0
   
Nine Months Ended September 30, 2018 $231.6

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

Retail Margins increased $105 million primarily due to the following:
An $89 million increase from rate proceedings in the I&M service territory, inclusive of a $26 million decrease due to the impact of Tax Reform in the Indiana jurisdiction. The increase in Retail Margins relating to riders had corresponding increases in other expense items below.
A $51 million increase in weather-related usage primarily due to a 39% increase in heating degree days and a 42% increase in cooling degree days.
A $32 million increase in FERC generation wholesale municipal and cooperative revenues primarily due to the annual formula rate true-up and changes to the formula rate.
These increasesdecreases were partially offset by:
A $30 million decrease related to over/under recovery of riders.
A $14 million decrease due to customer refunds related to Tax Reform. This decrease was offset in Income Tax Expense below.
A $10 million decrease due to timing differences in the recovery of increased fuel and other variable production costs not related to fuel clauses or other trackers.
Margins from Off-system Sales decreased $5 million primarily due to mid-year changes in the OSS sharing mechanism.
Transmission Revenues increased $23 million primarily due to the annual formula rate true-up and decreased RTO provisions.


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

Other Operation and Maintenance expenses increased $3 million primarily due to the following:
A $10$57 million increase in Cook Plant refueling outage amortization expense, primarily due to increased costs of outages.
A $7 million increase in employee-related expenses.
A $6 million increase in distribution forestry expenses.
A $5 million increase in demand-side management expenses. This increase was offset within Retail Margins above.
These increases were partially offset by:
A $19 million decrease in transmissionPJM expenses primarily duerelated to the annual formula rate true-up.
•
Depreciation and Amortization expensesdecreased $24 million primarily due to the following:
A $7$30 million decrease in recoverable DIR depreciation expense. This decrease was partially offset in Retail Margins above.
An $11 million decrease in amortizations associated with the Deferred Asset Phase-In-Recovery Rider which ended in the second quarter of 2019. This decrease was offset in Retail Margins above.
This decrease was offset by:
A $17 million increase in depreciation expense due to an increased Nuclear Electric Insurance Limited distributionincrease in 2018.
Depreciation and Amortization expensesincreased $52 million primarily due to a higherthe depreciable base of transmission and increased depreciation rates approved in the 2017 Indiana and Michigan base rate cases.distribution 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.

Taxes Other Than Income Taxes increased $5 million primarily due to increased state taxes due to higher reported taxable KWh and taxable revenues and a prior period refund.

Carrying Cost Income decreased $5 million primarily due to a decrease in carrying charges for certain riders in Indiana.
Non-Service Cost Components of Net Periodic Benefit Cost decreased $9 million primarily due to favorable asset returns for the funded Pension and OPEB plans, favorable OPEB cost savings arrangements and the implementation of ASU 2017-07.
Interest Expense increased $13 million primarily due to increased long-term debt balances.
Income Tax Expense decreased $35 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and amortization of Excess ADIT, partially offset by an increase in pretax book income.




INDIANA MICHIGANOHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20182019 and 20172018
(in millions)
(Unaudited)
 Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended
 September 30, September 30, September 30, September 30,
 2018 2017 2018 2017 2019 2018 2019 2018
REVENUES        
        
Electric Generation, Transmission and Distribution $609.9
 $537.0
 $1,723.9
 $1,527.4
Other Revenues – Affiliated 17.1
 17.1
 62.2
 48.2
Other Revenues – Nonaffiliated 2.7
 3.6
 10.1
 9.9
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 629.7
 557.7
 1,796.2
 1,585.5
 710.6
 778.3
 2,154.0
 2,318.0
                
EXPENSES  
    
  
  
  
  
  
Fuel and Other Consumables Used for Electric Generation 95.9
 76.4
 246.8
 238.2
Purchased Electricity for Resale 48.9
 32.9
 167.7
 101.2
 158.3
 166.3
 454.0
 534.7
Purchased Electricity from AEP Affiliates 60.0
 62.4
 181.8
 166.2
 40.6
 39.3
 120.4
 97.4
Amortization of Generation Deferrals 8.8
 56.9
 65.3
 171.9
Other Operation 149.3
 142.0
 425.8
 438.8
 194.9
 215.2
 565.7
 586.4
Maintenance 57.2
 51.5
 169.1
 153.6
 40.0
 43.4
 106.7
 114.7
Depreciation and Amortization 85.2
 55.0
 207.1
 154.8
 57.4
 70.4
 176.8
 200.3
Taxes Other Than Income Taxes 23.0
 23.9
 72.9
 68.3
 112.0
 106.9
 326.9
 311.0
TOTAL EXPENSES 519.5
 444.1
 1,471.2
 1,321.1
 612.0
 698.4
 1,815.8
 2,016.4
                
OPERATING INCOME 110.2
 113.6
 325.0
 264.4
 98.6
 79.9
 338.2
 301.6
                
Other Income (Expense):  
    
  
  
  
  
  
Interest Income 1.6
 0.2
 2.8
 1.6
 0.8
 0.8
 2.7
 2.6
Carrying Costs Income 0.6
 2.2
 4.6
 9.9
 0.3
 0.2
 0.7
 1.5
Allowance for Equity Funds Used During Construction 3.9
 3.5
 8.0
 8.1
 4.8
 2.0
 14.1
 7.8
Non-Service Cost Components of Net Periodic Benefit Cost 4.6
 1.5
 13.6
 4.6
 3.7
 3.8
 11.0
 11.6
Interest Expense (34.5) (27.5) (95.6) (83.0) (27.9) (26.1) (78.1) (76.6)
                
INCOME BEFORE INCOME TAX EXPENSE 86.4
 93.5
 258.4
 205.6
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 80.3
 60.6
 288.6
 248.5
                
Income Tax Expense 13.7
 28.6
 26.8
 61.8
Income Tax Expense (Benefit) 11.2
 (28.1) 40.9
 11.4
                
NET INCOME $72.7
 $64.9
 $231.6
 $143.8
 $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 141126.



INDIANA MICHIGAN
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20182019 and 20172018
(in millions)
(Unaudited)
 Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended
 September 30, September 30, September 30, September 30,
 2018 2017 2018 2017 2019 2018 2019 2018
Net Income $72.7
 $64.9
 $231.6
 $143.8
 $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, 2018 and 2017, Respectively, and $0.3 and $0.5 for the Nine Months Ended September 30, 2018 and 2017, Respectively 0.3
 0.3
 1.2
 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 $73.0
 $65.2
 $232.8
 $144.8
 $68.8
 $88.3
 $246.7
 $236.1
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141126.



INDIANA MICHIGAN
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 20182019 and 20172018
(in millions)
(Unaudited)
 Common
Stock		 Paid-in
Capital		 Retained
Earnings		 Accumulated
Other
Comprehensive
Income (Loss)		 Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2016 $56.6
 $980.9
 $1,130.5
 $(16.2) $2,151.8
          
Common Stock Dividends  
  
 (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 $56.6
 $980.9
 $1,192.2
 $(12.1) $2,217.6
 $321.2
 $838.8
 $1,148.4
 $1.9
 $2,310.3
                    
Common Stock Dividends  
  
 (105.5)  
 (105.5)     (112.5)   (112.5)
ASU 2018-02 Adoption     0.3
 (2.7) (2.4)       0.4
 0.4
Net Income  
  
 231.6
  
 231.6
     79.6
   79.6
Other Comprehensive Income  
  
  
 1.2
 1.2
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 $56.6
 $980.9
 $1,318.6
 $(13.6) $2,342.5
 $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 141126.



INDIANA MICHIGAN
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20182019 and December 31, 20172018
(in millions)
(Unaudited)
 September 30, December 31, September 30, December 31,
 2018 2017 2019 2018
CURRENT ASSETS        
Cash and Cash Equivalents $1.6
 $1.3
 $4.7
 $4.9
Advances to Affiliates 72.5
 12.4
Restricted Cash for Securitized Funding —
 27.6
Accounts Receivable:        
Customers 70.5
 56.4
 35.4
 111.1
Affiliated Companies 51.7
 50.0
 56.2
 70.8
Accrued Unbilled Revenues 16.1
 7.3
 26.5
 21.4
Miscellaneous 1.9
 2.0
 0.3
 0.3
Allowance for Uncollectible Accounts (0.2) (0.1) (2.1) (1.0)
Total Accounts Receivable 140.0
 115.6
 116.3
 202.6
Fuel 28.7
 31.4
Materials and Supplies 165.7
 160.6
 48.5
 42.9
Risk Management Assets 10.9
 7.6
Accrued Tax Benefits 35.4
 58.4
Regulatory Asset for Under-Recovered Fuel Costs 0.1
 15.0
Accrued Reimbursement of Spent Nuclear Fuel Costs 7.9
 10.8
Renewable Energy Credits 41.5
 25.9
Prepayments and Other Current Assets 20.9
 20.9
 19.8
 15.7
TOTAL CURRENT ASSETS 483.7
 434.0
 230.8
 319.6
        
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
Generation 4,579.9
 4,445.9
Transmission 1,543.3
 1,504.0
 2,613.0
 2,544.3
Distribution 2,183.9
 2,069.3
 5,192.8
 4,942.3
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) 584.7
 595.2
Other Property, Plant and Equipment 662.3
 574.8
Construction Work in Progress 458.6
 460.2
 485.3
 432.1
Total Property, Plant and Equipment 9,350.4
 9,074.6
 8,953.4
 8,493.5
Accumulated Depreciation, Depletion and Amortization 3,113.9
 3,024.2
Accumulated Depreciation and Amortization 2,256.1
 2,218.6
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 6,236.5
 6,050.4
 6,697.3
 6,274.9
        
OTHER NONCURRENT ASSETS        
Regulatory Assets 545.3
 579.4
 372.2
 387.5
Spent Nuclear Fuel and Decommissioning Trusts 2,666.0
 2,527.6
Long-term Risk Management Assets 0.9
 0.7
Securitized Assets —
 12.9
Deferred Charges and Other Noncurrent Assets 175.7
 179.9
 320.3
 441.0
TOTAL OTHER NONCURRENT ASSETS 3,387.9
 3,287.6
 692.5
 841.4
        
TOTAL ASSETS $10,108.1
 $9,772.0
 $7,620.6
 $7,435.9
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141126.



INDIANA MICHIGAN
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 20182019 and December 31, 20172018
(dollars in millions)
(Unaudited)
 September 30, December 31, September 30, December 31,
 2018 2017 2019 2018
CURRENT LIABILITIES        
Advances from Affiliates $—
 $211.6
 $17.6
 $114.1
Accounts Payable:      
  
General 142.6
 154.5
 203.1
 211.9
Affiliated Companies 65.6
 98.3
 100.2
 102.9
Long-term Debt Due Within One Year – Nonaffiliated
(September 30, 2018 and December 31, 2017 Amounts Include $94.2 and $96.3, Respectively, Related to DCC Fuel)
 172.7
 474.7
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 6.4
 3.5
 7.2
 5.8
Customer Deposits 37.0
 37.7
 88.2
 113.1
Accrued Taxes 44.7
 81.3
 294.3
 537.8
Accrued Interest 22.2
 37.5
 44.7
 31.4
Obligations Under Operating Leases 12.8
 —
Other Current Liabilities 129.8
 112.2
 99.4
 182.8
TOTAL CURRENT LIABILITIES 621.0
 1,211.3
 867.6
 1,347.7
        
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated 2,889.7
 2,270.4
 2,113.8
 1,668.7
Long-term Risk Management Liabilities 0.4
 0.1
 105.7
 93.8
Deferred Income Taxes 1,010.0
 953.8
 805.0
 763.3
Regulatory Liabilities and Deferred Investment Tax Credits 1,791.9
 1,708.7
 1,143.6
 1,221.2
Asset Retirement Obligations 1,365.1
 1,321.6
Obligations Under Operating Leases 75.9
 —
Deferred Credits and Other Noncurrent Liabilities 87.5
 88.5
 49.9
 43.8
TOTAL NONCURRENT LIABILITIES 7,144.6
 6,343.1
 4,293.9
 3,790.8
        
TOTAL LIABILITIES 7,765.6
 7,554.4
 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 1,318.6
 1,192.2
 1,299.1
 1,136.4
Accumulated Other Comprehensive Income (Loss) (13.6) (12.1) —
 1.0
TOTAL COMMON SHAREHOLDER’S EQUITY 2,342.5
 2,217.6
 2,459.1
 2,297.4
        
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $10,108.1
 $9,772.0
 $7,620.6
 $7,435.9
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141126.



INDIANA MICHIGAN
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20182019 and 20172018
(in millions)
(Unaudited)
 Nine Months Ended September 30, Nine Months Ended September 30,
 2018 2017 2019 2018
OPERATING ACTIVITIES  
  
  
  
Net Income $231.6
 $143.8
 $247.7
 $237.1
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
  
  
Depreciation and Amortization 207.1
 154.8
 176.8
 200.3
Amortization of Generation Deferrals 65.3
 171.9
Deferred Income Taxes 28.1
 132.2
 16.8
 (71.9)
Amortization of Incremental Nuclear Refueling Outage Expenses, Net 13.5
 15.5
Carrying Costs Income (4.6) (9.9)
Allowance for Equity Funds Used During Construction (8.0) (8.1) (14.1) (7.8)
Mark-to-Market of Risk Management Contracts (0.3) (7.5) 13.3
 (37.1)
Amortization of Nuclear Fuel 82.6
 104.8
Pension Contribution to Qualified Plan Trust —
 (13.0)
Deferred Fuel Over/Under-Recovery, Net 29.6
 22.0
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 (7.4) (32.2) (19.4) 0.8
Change in Other Noncurrent Liabilities 46.3
 40.9
 (51.1) 62.5
Changes in Certain Components of Working Capital:  
  
  
  
Accounts Receivable, Net 6.5
 19.3
 90.0
 21.3
Fuel, Materials and Supplies (1.1) (4.1)
Materials and Supplies (9.6) (3.7)
Accounts Payable (34.7) 16.6
 (12.3) (31.8)
Customer Deposits (0.7) 3.0
Accrued Taxes, Net (7.1) (30.2) (245.9) (210.6)
Accrued Interest (15.3) (17.4)
Other Current Assets 4.9
 8.0
 (9.0) 7.6
Other Current Liabilities 0.3
 (14.2) (40.0) (4.3)
Net Cash Flows from Operating Activities 571.3
 524.3
 309.5
 700.8
        
INVESTING ACTIVITIES  
  
  
  
Construction Expenditures (434.5) (469.2) (570.6) (538.5)
Change in Advances to Affiliates, Net (60.1) (0.1)
Purchases of Investment Securities (1,589.0) (1,842.2)
Sales of Investment Securities 1,550.9
 1,808.6
Acquisitions of Nuclear Fuel (26.1) (73.2)
Other Investing Activities 9.2
 7.3
 20.0
 15.5
Net Cash Flows Used for Investing Activities (549.6) (568.8) (550.6) (523.0)
        
FINANCING ACTIVITIES  
  
  
  
Issuance of Long-term Debt – Nonaffiliated 1,168.1
 411.1
 444.3
 392.8
Change in Advances from Affiliates, Net (211.6) (37.7) (96.5) 155.1
Retirement of Long-term Debt – Nonaffiliated (856.1) (227.1) (48.0) (397.0)
Principal Payments for Capital Lease Obligations (7.3) (8.7)
Principal Payments for Finance Lease Obligations (2.6) (2.9)
Dividends Paid on Common Stock (105.5) (93.7) (85.0) (337.5)
Other Financing Activities (9.0) 0.7
 1.1
 0.7
Net Cash Flows from (Used for) Financing Activities (21.4) 44.6
 213.3
 (188.8)
        
Net Increase in Cash and Cash Equivalents 0.3
 0.1
Cash and Cash Equivalents at Beginning of Period 1.3
 1.2
Cash and Cash Equivalents at End of Period $1.6
 $1.3
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 $104.4
 $92.0
 $61.3
 $67.3
Net Cash Paid (Received) for Income Taxes (26.5) (69.6)
Noncash Acquisitions Under Capital Leases 4.4
 5.9
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, 66.4
 74.5
 99.9
 66.0
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, 12.1
 0.6
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage 2.1
 2.8
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141126.







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,
2018 2017 2018 20172019 2018 2019 2018
(in millions of KWhs)(in millions of KWhs)
Retail: 
  
  
  
 
  
  
  
Residential4,055
 3,644
 11,475
 10,198
2,172
 2,005
 4,981
 5,133
Commercial3,993
 3,806
 11,196
 10,789
1,497
 1,433
 3,818
 3,864
Industrial3,666
 3,708
 11,016
 10,967
1,642
 1,604
 4,665
 4,559
Miscellaneous27
 28
 84
 87
378
 362
 950
 973
Total Retail (a)11,741
 11,186
 33,771
 32,041
5,689
 5,404
 14,414
 14,529
              
Wholesale (b)634
 585
 1,835
 1,749
224
 182
 617
 544
              
Total KWhs12,375
 11,771
 35,606
 33,790
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 EndedThree Months Ended Nine Months Ended
 September 30, September 30,September 30, September 30,
 2018 2017 2018 20172019 2018 2019 2018
 (in degree days)(in degree days)
Actual – Heating (a) —
 —
 2,158
 1,500
—
 —
 1,199
 1,161
Normal – Heating (b) 6
 6
 2,076
 2,091
1
 1
 1,077
 1,082
               
Actual – Cooling (c) 864
 642
 1,322
 957
1,593
 1,433
 2,206
 2,352
Normal – Cooling (b) 670
 670
 964
 960
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 20182019 Compared to Third Quarter of 20172018
Reconciliation of Third Quarter of 2017 to Third Quarter of 2018
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 2017 $82.6
Third Quarter of 2018 $60.4
  
  
Changes in Gross Margin:  
  
Retail Margins(a) 25.7
 22.0
Off-system Sales 12.3
Margins from Off-system Sales 0.8
Transmission Revenues (0.2) (3.7)
Other Revenues 2.1
Total Change in Gross Margin 39.9
 19.1
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance (93.8) 19.5
Depreciation and Amortization (13.1) 3.2
Taxes Other Than Income Taxes (6.5) (0.3)
Interest Income 0.1
Carrying Costs Income (0.3)
Allowance for Equity Funds Used During Construction 1.1
Non-Service Cost Components of Net Periodic Benefit Cost 2.7
Other Income (Expense) 1.4
Interest Expense (0.4) 0.3
Total Change in Expenses and Other (110.2) 24.1
  
  
Income Tax Expense (Credit) 76.4
Income Tax Expense (3.3)
  
  
Third Quarter of 2018 $88.7
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 and amortization of generation deferrals were as follows:


Retail Margins increased $26 million primarily due to the following:
•
Retail Margins increased $22 million primarily due to the following:
A $46 million net increase in Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset by an increase in Other Operation and Maintenance expenses below.
A $21 million increase in revenues associated with the Universal Service Fund (USF). This increase was offset by a corresponding increase in Other Operation and Maintenance expenses below.
A $7 million increase in revenues associated with smart grid riders. This increase was partially offset by an increase in various expenses below.
A $6$14 million increase due to the reversal of a portion of the 2018 provisions for customer refunds primarily related to the October 2018 Ohio Tax Reform settlement.  This increase was partially offsetnew base rates implemented in Income Tax Expense (Credit) below.April 2019.
A $4$9 million increase in rider revenues associated with the DIR. Thisweather-related usage due to an 11% increase was partially offset in various expenses below.cooling degree days.
A $5 million increase in weather-normalized margins.
These increases were partially offset by:
A $46$7 million decrease due to adjustmentscustomer refunds related to the distribution decoupling under-recovery balance as a result of the 2018 Ohio Tax Reform settlement.Reform. This decrease was partially offset in Income Tax Expense (Credit) below.
•
Transmission Revenues decreased $4 million primarily due to a decrease in SPP Base Plan Funding revenues.
A $12 million decrease due to the recovery of lower current year losses from a power contract with OVEC. This decrease was offset by a corresponding increase in Margins from Off-system Sales below.
Margins from Off-system Sales increased $12 million primarily due to lower current year losses from a power contract with OVEC which was offset in Retail Margins above as a result of the OVEC PPA rider beginning in January 2017.




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


•
Other Operation and Maintenance expenses decreased $20 million primarily due the following:
Other Operation and MaintenanceA $9 million decrease in transmission expenses increased $94 million primarily due to the following:
decreased SPP transmission services.
A $50$5 million increasedecrease in recoverable PJM expenses. This increase was offset within Gross Margins above.
A $21 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistanceEnergy Efficiency program for qualified Ohio customers. This increase was offset by a corresponding increase in Retail Margins above.
Depreciation and Amortization expensesincreased $13 million primarilycosts due to a change in amortizations of costs approved by the following:
A $6 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
A $4 million increase in recoverable smart grid depreciation expenses.OCC. This increasedecrease was offset in Retail Margins above.
Taxes Other Than Income Taxes increased $7 million primarily due to the following:
A $3 million increase in rider revenues recovering state excise taxes due to an increase in metered KWh. This increase was offset by a corresponding increase in Retail Margins above.
A $3 million increase in property taxesdecrease due to additional investmentsWind Catcher Project expenses incurred in transmission and distribution assets and higher tax rates.2018.
Income Tax Expense (Credit) decreased $76 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, amortization of Excess ADIT and a decrease in pretax book income.
•
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, 20182019 Compared to Nine Months Ended September 30, 20172018
Reconciliation of Nine Months Ended September 30, 2017 to Nine Months Ended September 30, 2018
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, 2017 $231.1
Nine Months Ended September 30, 2018 $89.8
  
  
Changes in Gross Margin:  
  
Retail Margins(a) 121.6
 2.2
Off-system Sales 30.5
Margin from Off-system Sales 0.9
Transmission Revenues (9.0) (5.6)
Other Revenues 0.6
 1.8
Total Change in Gross Margin 143.7
 (0.7)
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance (211.8) 63.9
Depreciation and Amortization (34.6) (4.9)
Taxes Other Than Income Taxes (17.2) (0.4)
Interest Income (1.4)
Carrying Costs Income (1.5)
Allowance for Equity Funds Used During Construction 3.7
Other Income (Expense) 2.4
Non-Service Cost Components of Net Periodic Benefit Cost 8.3
 (0.2)
Interest Expense 0.2
 (2.9)
Total Change in Expenses and Other (254.3) 57.9
  
  
Income Tax Expense (Credit) 116.6
Income Tax Expense 1.4
  
  
Nine Months Ended September 30, 2018 $237.1
Nine Months Ended September 30, 2019 $148.4


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

The major components of the increasedecrease 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 increased $122
•
Retail Margins increased $2 million primarily due to the following:
A $35 million increase due to the following:
new base rates implemented in April 2019 and March 2018.
A $155 million net increase in Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset by an increase in Other Operation and Maintenance expenses below.
A $61 million increase in revenues associated with the Universal Service Fund (USF). This increase was offset by a corresponding increase in Other Operation and Maintenance expenses below.
An $18 million increase in rider revenues associated with the DIR. This increase was partially offset in various expenses below.
A $9 million increase in usage primarily in the residential class.
An $8 million increase in rider revenues recovering state excise taxes due to an increase in metered KWh. This increase was offset by a corresponding increase in Taxes Other Than Income Taxes below.
These increases were partially offset by:
A $46$13 million decrease due to adjustments to the distribution decoupling under-recovery balance as a result of the 2018 Ohio Tax Reform settlement. This decrease was offset in Income Tax Expense (Credit) below.
A $30 million decrease due to the recovery of lower current year losses from a power contract with OVEC. This decrease was offset by a corresponding increase in Margins from Off-system Sales below.
A $24 million decrease due to the 2018 provisions for customer refunds related to Tax Reform. This decrease was offset in Income Tax Expense (Credit) below.
A $9 million net decrease in margin for the Phase-In-Recovery Rider including associated amortizations.
An $8 million decrease in Energy Efficiency/Peak Demand Reduction rider revenues. This decrease was offset by a decrease in Other Operation and Maintenance expenses below.



Margins from Off-system Sales increased $31 million primarily due to lower current year losses from a power contract with OVEC which was offset in Retail Margins above as a result of the OVEC PPA rider beginning in January 2017.
Transmission Revenues decreased $9 million due to the 2018 provisions for customer refunds due to Tax Reform. This decrease waspartially offset in Income Tax Expense below.

An $11 million decrease in weather-related usage due to a 6% decrease in 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 (Credit) 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 increased $212 million primarily due to the following:
decreased SPP transmission services.
A $181 million increase in recoverable PJM expenses. This increase was offset within Gross Margins above.
A $61 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset by a corresponding increase in Retail Margins above.
These increases were partially offset by:
A $55$17 million decrease in PJM expenses primarily related to the annual formula rate true-up that will be refunded in future periods.
Depreciation and Amortization expensesincreased $35 million primarilyEnergy Efficiency program costs due to a change in amortizations of costs approved by the following:
A $13 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
A $13 million increase in recoverable DIR depreciation expense.OCC. This increasedecrease was offset in Retail Margins above.
A $4$12 million increase in amortizationdecrease due to capitalized software.Wind Catcher Project expenses incurred in 2018.
•
Depreciation and Amortization expenses increased $5 million primarily due to the following:
Taxes Other Than Income Taxes increased $17 million primarily due to the following:
•An $8 million increase in rider revenues recovering state excise taxes due to an increasea higher depreciable base and new rates implemented in metered KWh. March 2018.
This increase was partially offset by a corresponding increase in Retail Margins above.by:
An $8•A $3 million increase in property taxes due to additional investments in transmission and distribution assets and higher tax rates.
Non-Service Cost Components of Net Periodic Cost decreased $8 million primarily due to favorable asset returns for the funded Pension and OPEB plans, favorable OPEB cost savings arrangements and the implementation of ASU 2017-07.
Income Tax Expense(Credit) decreased $117 million primarilydecrease due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, amortizationrefund of Excess ADIT and a decrease in pretax book income.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.






OHIO POWERPUBLIC SERVICE COMPANY AND SUBSIDIARIESOF OKLAHOMA
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20182019 and 20172018
(in millions)
(Unaudited)
 Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended
 September 30, September 30, September 30, September 30,
 2018 2017 2018 2017 2019 2018 2019 2018
REVENUES        
        
Electricity, Transmission and Distribution $772.6
 $736.0
 $2,294.8
 $2,127.8
Electric Generation, Transmission and Distribution $490.5
 $479.1
 $1,164.3
 $1,209.5
Sales to AEP Affiliates 3.3
 4.6
 17.9
 19.4
 1.3
 1.1
 5.0
 3.7
Other Revenues 2.4
 1.4
 5.3
 4.8
 1.2
 1.2
 4.6
 3.3
TOTAL REVENUES 778.3
 742.0
 2,318.0
 2,152.0
 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 166.3
 180.7
 534.7
 525.4
 115.3
 116.8
 340.7
 352.3
Purchased Electricity from AEP Affiliates 39.3
 26.7
 97.4
 83.4
Amortization of Generation Deferrals 56.9
 58.7
 171.9
 172.9
Other Operation 215.2
 126.9
 586.4
 380.9
 87.6
 106.3
 226.0
 286.8
Maintenance 43.4
 37.9
 114.7
 108.4
 21.5
 22.3
 70.1
 73.2
Depreciation and Amortization 70.4
 57.3
 200.3
 165.7
 39.1
 42.3
 125.4
 120.5
Taxes Other Than Income Taxes 106.9
 100.4
 311.0
 293.8
 11.1
 10.8
 33.0
 32.6
TOTAL EXPENSES 698.4
 588.6
 2,016.4
 1,730.5
 373.0
 402.9
 976.4
 1,076.9
                
OPERATING INCOME 79.9
 153.4
 301.6
 421.5
 120.0
 78.5
 197.5
 139.6
                
Other Income (Expense):  
  
  
  
  
  
  
  
Interest Income 0.8
 0.7
 2.6
 4.0
Carrying Costs Income 0.2
 0.5
 1.5
 3.0
Allowance for Equity Funds Used During Construction 2.0
 0.9
 7.8
 4.1
Other Income (Expense) 1.2
 (0.2) 2.1
 (0.3)
Non-Service Cost Components of Net Periodic Benefit Cost 3.8
 1.1
 11.6
 3.3
 2.1
 2.1
 6.3
 6.5
Interest Expense (26.1) (25.7) (76.6) (76.8) (16.1) (16.4) (50.3) (47.4)
                
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) 60.6
 130.9
 248.5
 359.1
INCOME BEFORE INCOME TAX EXPENSE 107.2
 64.0
 155.6
 98.4
                
Income Tax Expense (Credit) (28.1) 48.3
 11.4
 128.0
Income Tax Expense 6.9
 3.6
 7.2
 8.6
                
NET INCOME $88.7
 $82.6
 $237.1
 $231.1
 $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 141126.



OHIO POWER
PUBLIC SERVICE COMPANY AND SUBSIDIARIESOF OKLAHOMA
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20182019 and 20172018
(in millions)
(Unaudited)
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2018 2017 2018 2017
Net Income $88.7
 $82.6
 $237.1
 $231.1
         
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, 2018 and 2017, Respectively, and $(0.3) and $(0.4) for the Nine Months Ended September 30, 2018 and 2017, Respectively (0.4) (0.3) (1.0) (0.8)
         
TOTAL COMPREHENSIVE INCOME $88.3
 $82.3
 $236.1
 $230.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141.


OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2018 and 2017
(in millions)
(Unaudited)
  Common
Stock		 Paid-in
Capital		 Retained
Earnings		 Accumulated
Other
Comprehensive
Income (Loss)		 Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2016 $321.2
 $838.8
 $954.5
 $3.0
 $2,117.5
           
Common Stock Dividends  
  
 (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
   
  
  
  
  
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017 $321.2
 $838.8
 $1,148.4
 $1.9
 $2,310.3
           
Common Stock Dividends  
  
 (337.5)  
 (337.5)
ASU 2018-02 Adoption       0.4
 0.4
Net Income  
  
 237.1
  
 237.1
Other Comprehensive Loss  
  
  
 (1.0) (1.0)
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2018 $321.2
 $838.8
 $1,048.0
 $1.3
 $2,209.3
  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 141126.



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, 20182019 and December 31, 20172018
(in millions)
(Unaudited)
  September 30, December 31,
  2018 2017
CURRENT ASSETS    
Cash and Cash Equivalents $3.5
 $3.1
Restricted Cash for Securitized Funding 15.2
 26.6
Accounts Receivable:    
Customers 116.9
 67.8
Affiliated Companies 72.4
 70.2
Accrued Unbilled Revenues 32.7
 29.7
Miscellaneous 0.9
 1.9
Allowance for Uncollectible Accounts (1.4) (0.6)
Total Accounts Receivable 221.5
 169.0
Materials and Supplies 38.5
 41.9
Renewable Energy Credits 23.0
 25.0
Risk Management Assets 0.6
 0.6
Regulatory Asset for Under-Recovered Fuel Costs 34.1
 115.9
Prepayments and Other Current Assets 16.7
 15.8
TOTAL CURRENT ASSETS 353.1
 397.9
     
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Transmission 2,484.5
 2,419.2
Distribution 4,825.6
 4,626.4
Other Property, Plant and Equipment 547.5
 495.9
Construction Work in Progress 475.7
 410.1
Total Property, Plant and Equipment 8,333.3
 7,951.6
Accumulated Depreciation and Amortization 2,230.6
 2,184.8
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 6,102.7
 5,766.8
     
OTHER NONCURRENT ASSETS    
Regulatory Assets 389.1
 652.8
Securitized Assets 19.0
 37.7
Long-term Risk Management Assets 0.1
 —
Deferred Charges and Other Noncurrent Assets 254.6
 406.5
TOTAL OTHER NONCURRENT ASSETS 662.8
 1,097.0
     
TOTAL ASSETS $7,118.6
 $7,261.7
  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 141126.



OHIO POWER
PUBLIC SERVICE COMPANY AND SUBSIDIARIESOF OKLAHOMA
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITYASSETS
September 30, 20182019 and December 31, 20172018
(dollars in millions)
(Unaudited)
  September 30, December 31,
  2018 2017
CURRENT LIABILITIES    
Advances from Affiliates $242.9
 $87.8
Accounts Payable:  
  
General 169.2
 205.8
Affiliated Companies 95.3
 118.2
Long-term Debt Due Within One Year – Nonaffiliated
(September 30, 2018 and December 31, 2017 Amounts Include $47.7 and $47, Respectively, Related to Ohio Phase-in-Recovery Funding)
 47.8
 397.0
Risk Management Liabilities 5.4
 6.4
Customer Deposits 77.5
 69.2
Accrued Taxes 293.8
 512.5
Other Current Liabilities 205.9
 196.9
TOTAL CURRENT LIABILITIES 1,137.8
 1,593.8
     
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated
(September 30, 2018 and December 31, 2017 Amounts Include $0 and $47.5, Respectively, Related to Ohio Phase-in-Recovery Funding)
 1,668.5
 1,322.3
Long-term Risk Management Liabilities 89.8
 126.0
Deferred Income Taxes 742.8
 762.9
Regulatory Liabilities and Deferred Investment Tax Credits 1,197.7
 1,100.2
Deferred Credits and Other Noncurrent Liabilities 72.7
 46.2
TOTAL NONCURRENT LIABILITIES 3,771.5
 3,357.6
     
TOTAL LIABILITIES 4,909.3
 4,951.4
     
Rate Matters (Note 4) 
 
Commitments and Contingencies (Note 5) 
 
     
COMMON SHAREHOLDER’S EQUITY    
Common Stock – No Par Value:    
Authorized – 40,000,000 Shares  
  
Outstanding – 27,952,473 Shares 321.2
 321.2
Paid-in Capital 838.8
 838.8
Retained Earnings 1,048.0
 1,148.4
Accumulated Other Comprehensive Income (Loss) 1.3
 1.9
TOTAL COMMON SHAREHOLDER’S EQUITY 2,209.3
 2,310.3
     
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $7,118.6
 $7,261.7
  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 141126.



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, 20182019 and 2017
(in millions)December 31, 2018
(Unaudited)
  Nine Months Ended September 30,
  2018 2017
OPERATING ACTIVITIES  
  
Net Income $237.1
 $231.1
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
Depreciation and Amortization 200.3
 165.7
Amortization of Generation Deferrals 171.9
 172.9
Deferred Income Taxes (71.9) 117.5
Carrying Costs Income (1.5) (3.0)
Allowance for Equity Funds Used During Construction (7.8) (4.1)
Mark-to-Market of Risk Management Contracts (37.1) 19.5
Pension Contributions to Qualified Plan Trust —
 (8.2)
Property Taxes 191.1
 175.9
Provision for Refund – Global Settlement, Net (5.5) (93.3)
Change in Regulatory Assets 180.9
 (82.2)
Change in Other Noncurrent Assets 0.8
 (44.5)
Change in Other Noncurrent Liabilities 62.5
 43.4
Changes in Certain Components of Working Capital:  
  
Accounts Receivable, Net 21.3
 14.9
Materials and Supplies (3.7) (7.1)
Accounts Payable (31.8) (31.2)
Accrued Taxes, Net (210.6) (284.3)
Other Current Assets 9.1
 (17.3)
Other Current Liabilities (4.3) (34.8)
Net Cash Flows from Operating Activities 700.8
 330.9
     
INVESTING ACTIVITIES  
  
Construction Expenditures (538.5) (362.5)
Change in Advances to Affiliates, Net —
 24.2
Other Investing Activities 15.5
 6.9
Net Cash Flows Used for Investing Activities (523.0) (331.4)
     
FINANCING ACTIVITIES  
  
Issuance of Long-term Debt – Nonaffiliated 392.8
 —
Change in Advances from Affiliates, Net 155.1
 167.6
Retirement of Long-term Debt – Nonaffiliated (397.0) (46.4)
Principal Payments for Capital Lease Obligations (2.9) (3.1)
Dividends Paid on Common Stock (337.5) (130.0)
Other Financing Activities 0.7
 0.8
Net Cash Flows Used for Financing Activities (188.8) (11.1)
  ��  
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding (11.0) (11.6)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period 29.7
 30.3
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period $18.7
 $18.7
     
SUPPLEMENTARY INFORMATION  
  
Cash Paid for Interest, Net of Capitalized Amounts $67.3
 $68.1
Net Cash Paid for Income Taxes 54.1
 69.6
Noncash Acquisitions Under Capital Leases 3.0
 3.6
Construction Expenditures Included in Current Liabilities as of September 30, 66.0
 56.8
  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 141126.






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,
2018 2017 2018 20172019 2018 2019 2018
(in millions of KWhs)(in millions of KWhs)
Retail: 
  
  
  
 
  
  
  
Residential2,005
 1,992
 5,133
 4,662
2,071
 1,992
 4,896
 5,156
Commercial1,456
 1,488
 4,008
 3,926
1,746
 1,675
 4,430
 4,548
Industrial1,582
 1,472
 4,418
 4,249
1,414
 1,366
 4,020
 4,033
Miscellaneous361
 353
 970
 942
19
 19
 59
 59
Total Retail(a)5,404
 5,305
 14,529
 13,779
5,250
 5,052
 13,405
 13,796
              
Wholesale182
 82
 544
 309
1,831
 1,881
 5,317
 5,352
              
Total KWhs5,586
 5,387
 15,073
 14,088
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 EndedThree Months Ended Nine Months Ended
September 30, September 30,September 30, September 30,
2018 2017 2018 20172019 2018 2019 2018
(in degree days)(in degree days)
Actual – Heating (a)—
 —
 1,161
 682
—
 —
 732
 784
Normal – Heating (b)1
 1
 1,082
 1,104
1
 1
 725
 733
              
Actual – Cooling (c)1,433
 1,313
 2,352
 2,001
1,552
 1,453
 2,263
 2,408
Normal – Cooling (b)1,396
 1,395
 2,063
 2,064
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 20182019 Compared to Third Quarter of 20172018
Reconciliation of Third Quarter of 2017 to Third Quarter of 2018
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 2017 $46.2
Third Quarter of 2018 $88.2
    
Changes in Gross Margin:    
Retail Margins (a) 21.3
 10.7
Off-system Sales 0.6
 (0.2)
Transmission Revenues 1.0
 (4.8)
Other Revenues 0.2
 (0.4)
Total Change in Gross Margin 23.1
 5.3
    
Changes in Expenses and Other:  
  
Other Operation and Maintenance (18.9) 4.9
Depreciation and Amortization (10.6) (3.3)
Taxes Other Than Income Taxes (1.0) 0.7
Other Income (Expense) (0.2)
Interest Income (0.5)
Allowance for Equity Funds Used During Construction 1.0
Non-Service Cost Components of Net Periodic Benefit Cost 1.2
 (0.2)
Interest Expense (3.2) 3.5
Total Change in Expenses and Other (32.7) 6.1
  
  
Income Tax Expense 23.8
Income Tax Expense (Benefit) 10.3
Net Income Attributable to Noncontrolling Interest 0.6
  
  
Third Quarter of 2018 $60.4
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 $21 million primarily due to the following:
A $20 million increase due to new rates implemented in March 2018, inclusive of a $9 million decrease due to the change in the corporate federal tax rate.
An $11 million increase in revenue from rate riders. This increase was partially offset by corresponding increases to riders/trackers recognized in other expense items below.
•
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 9%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.
These increases were partially offset by:
A $6 million decrease due to lower weather-normalized margins.
A $5 million decrease due to 2018 customer refunds related to Tax Reform. This decrease was offset in Income Tax Expense below.
A $4 million decrease related to the System Reliability Rider (SRR) that ended in August 2017. This decrease was partially offset by a corresponding decrease recognized in other expense items below.




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


Other Operation and Maintenance expenses increased $19 million primarily due the following:
A $13 million increase in transmission expenses primarily due to increased SPP transmission services.
A $4 million increase in Energy Efficiency program costs. This increase was offset by an increase from rate riders in Retail Margins above.
A $3 million increase in generation expenses including employee-related expenses.
These increases were partially offset by:
A $3 million decrease in distribution expenses primarily due to the amortization of previously deferred vegetation management costs collected through the SRR. This decrease was partially offset by a corresponding decrease in Retail Margins above.
Depreciation and Amortization expenses increased $11 million primarily due to a higher depreciable base and new rates implemented in March 2018.
Income Tax Expense decreased $24 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, amortization of Excess ADIT and a decrease in pretax book income.
•
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, 20182019 Compared to Nine Months Ended September 30, 20172018
Reconciliation of Nine Months Ended September 30, 2017 to Nine Months Ended September 30, 2018
Net Income
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 SWEPCo Common ShareholderEarnings Attributable to SWEPCo Common Shareholder
(in millions)
    
Nine Months Ended September 30, 2017 $71.4
Nine Months Ended September 30, 2018 $137.6
  
  
Changes in Gross Margin:  
  
Retail Margins (a) 55.3
 (18.3)
Off-system Sales 0.8
 (0.1)
Transmission Revenues 0.4
 (35.6)
Other Revenues 0.2
 (0.3)
Total Change in Gross Margin 56.7
 (54.3)
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance (42.9) 47.7
Depreciation and Amortization (22.7) (11.2)
Taxes Other Than Income Taxes (2.6) 0.4
Other Income (Expense) (0.8)
Interest Income (1.5)
Allowance for Equity Funds Used During Construction 0.7
Non-Service Cost Components of Net Periodic Benefit Cost 3.9
 (0.5)
Interest Expense (7.2) 6.4
Total Change in Expenses and Other (72.3) 42.0
  
  
Income Tax Expense 34.0
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, 2018 $89.8
Nine Months Ended September 30, 2019 $144.5


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


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


•
Retail Margins decreased $18 million primarily due to the following:
Retail Margins increased $55A $14 million decrease in weather-related usage primarily due to the following:
A $37 million increase due to new rates implementeda 6% decrease in March 2018, inclusive ofcooling degree days and a $19 million7% decrease due to the change in the corporate federal tax rate.
A $30 million increase in weather-related usage due to a 70% increase in heating degree days and an 18% increase in cooling degree days.
A $24$10 million increasedecrease in revenue from rate riders. This increase was partially offset by corresponding increases to riders/trackers recognized in other expense items below.weather-normalized margins.
These increasesdecreases were partially offset by:
A $16 million decrease related to the SRR that ended in August 2017. This decrease was partially offset by a corresponding decrease recognized in other expense items below.
A $15 million decrease due to 2018 customer refunds related to Tax Reform. This decrease was offset in Income Tax Expense below.
A $4 million decrease due to lower weather-normalized margins.


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

Other Operation and Maintenance expenses increased $43 million primarily due to the following:
A $37 million increase in transmission expenses primarily due to increased SPP transmission services.
A $12 million increase in Energy Efficiency program costs. This increase was offset by an increase from rate riders in Retail Margins above.
A $10 million increase due to the Wind Catcher Project.
A $4 million increase in generation expenses including employee-related expenses.
These increases were partially offset by:
An $11 million decrease in distribution expenses primarily due to the amortization of previously deferred vegetation management costs collected through the SRR. This decrease was partially offset by a corresponding decrease in Retail Margins above.
An $11 million decrease due to a refund associated with SPP transmission expenses incurred in prior periods.
Depreciation and Amortization expenses increased $23 million primarily due to a higher depreciable base and new rates implemented in March 2018.
Non-Service Cost Components of Net Periodic Benefit Cost decreased $4 million primarily due to favorable asset returns for the funded Pension and OPEB plans, favorable OPEB cost savings arrangements and the implementation of ASU 2017-07.
Interest Expense increased $7 million primarily due to the 2017 deferral of the debt component of carrying charges on environmental control costs for projects at Northeastern Plant, Unit 3 and Comanche Plant.
Income Tax Expense decreased $34 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, amortization of Excess ADIT and a decrease in pretax book income.



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2018 and 2017
(in millions)
(Unaudited)
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2018 2017 2018 2017
REVENUES        
Electric Generation, Transmission and Distribution $479.1
 $440.6
 $1,209.5
 $1,085.1
Sales to AEP Affiliates 1.1
 1.1
 3.7
 3.2
Other Revenues 1.2
 1.1
 3.3
 3.3
TOTAL REVENUES 481.4
 442.8
 1,216.5
 1,091.6
         
EXPENSES  
  
  
  
Fuel and Other Consumables Used for Electric Generation 104.4
 77.9
 211.5
 115.8
Purchased Electricity for Resale 116.8
 127.8
 352.3
 379.8
Other Operation 106.3
 84.5
 286.8
 228.9
Maintenance 22.3
 25.2
 73.2
 88.2
Depreciation and Amortization 42.3
 31.7
 120.5
 97.8
Taxes Other Than Income Taxes 10.8
 9.8
 32.6
 30.0
TOTAL EXPENSES 402.9
 356.9
 1,076.9
 940.5
         
OPERATING INCOME 78.5
 85.9
 139.6
 151.1
         
Other Income (Expense):  
  
  
  
Other Income (Expense) (0.2) —
 (0.3) 0.5
Non-Service Cost Components of Net Periodic Benefit Cost 2.1
 0.9
 6.5
 2.6
Interest Expense (16.4) (13.2) (47.4) (40.2)
         
INCOME BEFORE INCOME TAX EXPENSE 64.0
 73.6
 98.4
 114.0
         
Income Tax Expense 3.6
 27.4
 8.6
 42.6
         
NET INCOME $60.4
 $46.2
 $89.8
 $71.4
The common stock of PSO is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141.


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 2018 and 2017
(in millions)
(Unaudited)
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2018 2017 2018 2017
Net Income $60.4
 $46.2
 $89.8
 $71.4
         
OTHER COMPREHENSIVE LOSS, NET OF TAXES  
    
  
Cash Flow Hedges, Net of Tax of $0 and $(0.1) for the Three Months Ended September 30, 2018 and 2017, Respectively, and $(0.2) and $(0.3) for the Nine Months Ended September 30, 2018 and 2017, Respectively (0.2) (0.2) (0.7) (0.6)
   
    
  
TOTAL COMPREHENSIVE INCOME $60.2
 $46.0

$89.1
 $70.8
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141.


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 2018 and 2017
(in millions)
(Unaudited)
  Common
Stock		 Paid-in
Capital		 Retained
Earnings		 Accumulated
Other
Comprehensive
Income (Loss)		 Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2016 $157.2
 $364.0
 $689.5
 $3.4
 $1,214.1
           
Common Stock Dividends     (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
   
  
  
  
  
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017 $157.2
 $364.0
 $691.5
 $2.6
 $1,215.3
           
Common Stock Dividends  
  
 (37.5)  
 (37.5)
ASU 2018-02 Adoption       0.5
 0.5
Net Income  
  
 89.8
  
 89.8
Other Comprehensive Loss  
  
  
 (0.7) (0.7)
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2018 $157.2
 $364.0
 $743.8
 $2.4
 $1,267.4
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141.


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
September 30, 2018 and December 31, 2017
(in millions)
(Unaudited)
  September 30, December 31,
  2018 2017
CURRENT ASSETS    
Cash and Cash Equivalents $1.9
 $1.6
Accounts Receivable:    
Customers 28.8
 32.5
Affiliated Companies 39.8
 32.9
Miscellaneous 4.4
 4.1
Allowance for Uncollectible Accounts (0.2) (0.1)
Total Accounts Receivable 72.8
 69.4
Fuel 12.6
 12.5
Materials and Supplies 43.4
 42.0
Risk Management Assets 18.5
 6.4
Accrued Tax Benefits 12.5
 28.1
Regulatory Asset for Under-Recovered Fuel Costs —
 36.7
Prepayments and Other Current Assets 8.1
 8.6
TOTAL CURRENT ASSETS 169.8
 205.3
     
PROPERTY, PLANT AND EQUIPMENT    
Electric:    
Generation 1,576.3
 1,577.2
Transmission 881.5
 858.8
Distribution 2,543.1
 2,445.1
Other Property, Plant and Equipment 308.3
 287.4
Construction Work in Progress 85.7
 111.3
Total Property, Plant and Equipment 5,394.9
 5,279.8
Accumulated Depreciation and Amortization 1,461.2
 1,393.6
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 3,933.7
 3,886.2
     
OTHER NONCURRENT ASSETS    
Regulatory Assets 352.1
 368.1
Employee Benefits and Pension Assets 41.3
 40.0
Deferred Charges and Other Noncurrent Assets 16.6
 8.7
TOTAL OTHER NONCURRENT ASSETS 410.0
 416.8
     
TOTAL ASSETS $4,513.5
 $4,508.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141.


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 2018 and December 31, 2017
(Unaudited)
  September 30, December 31,
  2018 2017
  (in millions)
CURRENT LIABILITIES    
Advances from Affiliates $22.0
 $149.6
Accounts Payable:  
  
General 113.0
 102.4
Affiliated Companies 42.2
 48.0
Long-term Debt Due Within One Year – Nonaffiliated 0.5
 0.5
Risk Management Liabilities 0.6
 —
Customer Deposits 56.1
 54.1
Accrued Taxes 40.5
 22.6
Accrued Interest 18.9
 14.1
Regulatory Liability for Over-Recovered Fuel Costs 36.0
 —
Other Current Liabilities 56.5
 44.7
TOTAL CURRENT LIABILITIES 386.3
 436.0
     
NONCURRENT LIABILITIES    
Long-term Debt – Nonaffiliated 1,286.4
 1,286.0
Deferred Income Taxes 636.6
 642.0
Regulatory Liabilities and Deferred Investment Tax Credits 850.3
 853.5
Asset Retirement Obligations 54.8
 53.0
Deferred Credits and Other Noncurrent Liabilities 31.7
 22.5
TOTAL NONCURRENT LIABILITIES 2,859.8
 2,857.0
     
TOTAL LIABILITIES 3,246.1
 3,293.0
     
Rate Matters (Note 4) 
 
Commitments and Contingencies (Note 5) 
 
     
COMMON SHAREHOLDER’S EQUITY    
Common Stock – Par Value – $15 Per Share:    
Authorized – 11,000,000 Shares  
  
Issued – 10,482,000 Shares  
  
Outstanding – 9,013,000 Shares 157.2
 157.2
Paid-in Capital 364.0
 364.0
Retained Earnings 743.8
 691.5
Accumulated Other Comprehensive Income (Loss) 2.4
 2.6
TOTAL COMMON SHAREHOLDER’S EQUITY 1,267.4
 1,215.3
     
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $4,513.5
 $4,508.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141.


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2018 and 2017
(in millions)
(Unaudited)
  Nine Months Ended September 30,
  2018 2017
OPERATING ACTIVITIES  
  
Net Income $89.8
 $71.4
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
Depreciation and Amortization 120.5
 97.8
Deferred Income Taxes (13.4) 93.7
Allowance for Equity Funds Used During Construction 0.3
 (0.4)
Mark-to-Market of Risk Management Contracts (11.5) (3.9)
Pension Contributions to Qualified Plan Trust —
 (5.3)
Property Taxes (9.6) (9.4)
Deferred Fuel Over/Under-Recovery, Net 73.3
 (5.6)
Provision for Refund, Net 3.7
 (39.4)
Change in Other Noncurrent Assets 6.9
 (19.8)
Change in Other Noncurrent Liabilities 10.9
 (1.4)
Changes in Certain Components of Working Capital:  
  
Accounts Receivable, Net (3.4) 5.8
Fuel, Materials and Supplies (1.5) 13.5
Accounts Payable 6.9
 (18.5)
Accrued Taxes, Net 38.4
 20.1
Other Current Assets 0.3
 (8.2)
Other Current Liabilities 15.1
 1.5
Net Cash Flows from Operating Activities 326.7
 191.9
     
INVESTING ACTIVITIES  
  
Construction Expenditures (162.8) (203.1)
Other Investing Activities 3.9
 1.5
Net Cash Flows Used for Investing Activities (158.9) (201.6)
     
FINANCING ACTIVITIES  
  
Change in Advances from Affiliates, Net (127.6) 66.0
Retirement of Long-term Debt – Nonaffiliated (0.3) (0.3)
Principal Payments for Capital Lease Obligations (2.5) (3.2)
Dividends Paid on Common Stock (37.5) (52.5)
Other Financing Activities 0.4
 0.3
Net Cash Flows from (Used for) Financing Activities (167.5) 10.3
     
Net Increase in Cash and Cash Equivalents 0.3
 0.6
Cash and Cash Equivalents at Beginning of Period 1.6
 1.5
Cash and Cash Equivalents at End of Period $1.9
 $2.1
     
SUPPLEMENTARY INFORMATION  
  
Cash Paid for Interest, Net of Capitalized Amounts $42.0
 $40.9
Net Cash Paid (Received) for Income Taxes 1.6
 (46.6)
Noncash Acquisitions Under Capital Leases 2.3
 1.0
Construction Expenditures Included in Current Liabilities as of September 30, 24.3
 15.1
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141.




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,
 2018 2017 2018 2017
 (in millions of KWhs)
Retail: 
  
  
  
Residential1,992
 1,887
 5,156
 4,547
Commercial1,701
 1,677
 4,619
 4,466
Industrial1,340
 1,339
 3,962
 3,895
Miscellaneous19
 19
 59
 60
Total Retail5,052
 4,922
 13,796
 12,968
        
Wholesale1,881
 2,105
 5,352
 6,286
        
Total KWhs6,933
 7,027
 19,148
 19,254

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,
 2018 2017 2018 2017
 (in degree days)
Actual – Heating (a)—
 —
 784
 394
Normal – Heating (b)1
 1
 733
 747
        
Actual – Cooling (c)1,453
 1,248
 2,408
 1,999
Normal – Cooling (b)1,408
 1,414
 2,179
 2,185

(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 2018 Compared to Third Quarter of 2017
Reconciliation of Third Quarter of 2017 to Third Quarter of 2018
Earnings Attributable to SWEPCo Common Shareholder
(in millions)
   
Third Quarter of 2017 $73.1
   
Changes in Gross Margin:  
Retail Margins (a) 11.0
Transmission Revenues 5.3
Other Revenues 0.2
Total Change in Gross Margin 16.5
   
Changes in Expenses and Other:  
Other Operation and Maintenance (18.9)
Depreciation and Amortization (4.7)
Taxes Other Than Income Taxes (1.8)
Interest Income 0.4
Allowance for Equity Funds Used During Construction 0.2
Non-Service Cost Components of Net Periodic Benefit Cost 1.3
Interest Expense (0.8)
Total Change in Expenses and Other (24.3)
   
Income Tax Expense 12.9
Equity Earnings (Loss) of Unconsolidated Subsidiary 0.4
Net Income Attributable to Noncontrolling Interest 9.6
   
Third Quarter of 2018 $88.2

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

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

Retail Margins increased $11 million primarily due to the following:
An $18 million increase primarily due to rider and base rate revenue increases in Texas and Louisiana.
A $14 million increase in weather-related usage primarily due to a 16% increase in cooling degree days.
These increases were partially offset by:
A $15 million decrease due to lower weather-normalized margins.
A $9 million decrease due to the 2018 provisions for customer refunds related to Tax Reform. This decrease was offset in Income Tax Expense below.
Transmission Revenues increased $5 million primarily due to an increase in SPP transmission investments.

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

Other Operation and Maintenance expenses increased $19 million primarily due to the following:
A $4 million increase due to employee-related expenses.
A $4 million increase in SPP transmission services.
A $3 million increase due to the Wind Catcher Project.
A $3 million increase in Energy Efficiency program costs. This increase was offset by an increase from rate riders in Retail Margins above.
A $2 million increase in distribution expenses.
Depreciation and Amortization expenses increased $5 million primarily due to a higher depreciable base.


Income Tax Expense decreased $13 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, amortization of Excess ADIT and a decrease in pretax book income.
Net Income Attributable to Noncontrolling Interest decreased $10 million primarily due to income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine. This decrease was offset by an increase in Income Tax Expense above.


Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017
Reconciliation of Nine Months Ended September 30, 2017 to Nine Months Ended September 30, 2018
Earnings Attributable to SWEPCo Common Shareholder
(in millions)
   
Nine Months Ended September 30, 2017 $113.9
   
Changes in Gross Margin:  
Retail Margins (a) 49.4
Off-system Sales (1.6)
Transmission Revenues 2.8
Total Change in Gross Margin 50.6
   
Changes in Expenses and Other:  
Other Operation and Maintenance (52.8)
Depreciation and Amortization (17.8)
Taxes Other Than Income Taxes (3.7)
Interest Income 1.5
Allowance for Equity Funds Used During Construction 2.6
Non-Service Cost Components of Net Periodic Benefit Cost 4.1
Interest Expense (3.1)
Total Change in Expenses and Other (69.2)
   
Income Tax Expense 27.3
Equity Earnings (Loss) of Unconsolidated Subsidiary 6.5
Net Income Attributable to Noncontrolling Interest 8.5
   
Nine Months Ended September 30, 2018 $137.6

other expense items below.
(a)•Includes firm wholesale sales
Transmission Revenues decreased $36 million primarily due to municipals and cooperatives.the following:

The major components ofA $40 million decrease in 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 $49 million primarily due to the following:
annual SPP formula rate true-up.
A $57$7 million increase primarily due to rider and base rate revenue increases in Texas, Louisiana and Arkansas.
A $48 million increase in weather-related usagedecrease primarily due to a 99% increasereduction in heating degree days and a 20% increase in cooling degree days.SPP Base Plan Funding revenues.
These increasesdecreases were partially offset by:
A $36An $11 million decrease due to the 2018 provisions for customer refunds related to Tax Reform. This decrease was offset in Income Tax Expense below.
A $26 million decrease due to lower weather-normalized margins, primarily due to wholesale customer load loss from contracts that expired at the end of 2017.
Transmission Revenues increased $3 million primarilyincrease due to a $14 million increase from continued SPP transmission investments, partially offset by an $11 million decrease from a 2018 provision for refund related to revenues recorded in prior periods on2018 related to certain transmission assets that management believes should not have been included in the SPP 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 $53
•
Other Operation and Maintenance expenses decreased $48 million primarily due to the following:
A $28 million decrease due to the following:
Wind Catcher Project expenses incurred in 2018.
A $25$24 million increase due to the Wind Catcher Project.
A $21 million increasedecrease in affiliated SPP transmission services.
An $8 million increase in customer expenses primarily due to the following:
A $3 million increase in Energy Efficiency program costs. This increase was offset by an increase fromannual formula rate riders in Retail Margins above.
A $3 million increase in customer assistance.
A $5 million increase due to employee-related expenses.true-up.
These increasesdecreases were partially offset by:
An $8 million decrease due to a refund associated with transmission expenses incurred in prior periods.
Depreciation and Amortization expenses increased $18 million primarily due to a higher depreciable base and higher depreciation rates from the 2017 Texas base rate case order.
Taxes Other Than Income Taxes increased $4 million primarily due to increased franchise and property taxes.
Non-Service Cost Components of Net Periodic Benefit Cost decreased $4 million primarily due to favorable asset returns for the funded Pension and OPEB plans, favorable OPEB cost savings arrangements and the implementation of ASU 2017-07.
Interest Expense increased $3 million primarily due to other interest expense accruals for refunds and true-ups in 2018 and interest expense credits in 2017 on Welsh Plant and Flint Creek Plant environmental project deferrals.
Income Tax Expense decreased $27 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, amortization of Excess ADIT and a decrease in pretax book income.
Equity Earnings (Loss) of Unconsolidated Subsidiary increasedA $7 million primarily due to a prior period income tax adjustment recognized in 2017.
Net Income Attributable to Noncontrolling Interest decreased $9 million primarily due to income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine. This decrease was offset by an increase in Income Tax Expense above.overhead line expenses primarily related to storm restoration.
•
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.






SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20182019 and 20172018
(in millions)
(Unaudited)
 Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended
 September 30, September 30, September 30, September 30,
 2018 2017 2018 2017 2019 2018 2019 2018
REVENUES        
        
Electric Generation, Transmission and Distribution $526.0
 $509.5
 $1,390.4
 $1,321.8
 $536.5
 $526.0
 $1,344.8
 $1,390.4
Sales to AEP Affiliates 8.7
 7.7
 20.2
 20.4
 8.8
 8.7
 21.6
 20.2
Provision for Refund – Affiliated (0.1) —
 (25.3) —
Other Revenues 0.6
 0.4
 1.2
 1.4
 0.3
 0.6
 1.0
 1.2
TOTAL REVENUES 535.3
 517.6
 1,411.8
 1,343.6
 545.5
 535.3
 1,342.1
 1,411.8
                
EXPENSES  
  
  
  
  
  
  
  
Fuel and Other Consumables Used for Electric Generation 152.1
 147.5
 393.4
 389.8
 148.8
 152.1
 400.2
 393.4
Purchased Electricity for Resale 36.6
 40.0
 132.7
 118.7
 44.8
 36.6
 110.5
 132.7
Other Operation 99.1
 81.2
 292.0
 234.9
 91.9
 99.1
 242.4
 292.0
Maintenance 33.6
 32.6
 102.2
 106.5
 35.9
 33.6
 104.1
 102.2
Depreciation and Amortization 59.9
 55.2
 175.9
 158.1
 63.2
 59.9
 187.1
 175.9
Taxes Other Than Income Taxes 26.9
 25.1
 76.4
 72.7
 26.2
 26.9
 76.0
 76.4
TOTAL EXPENSES 408.2
 381.6
 1,172.6
 1,080.7
 410.8
 408.2
 1,120.3
 1,172.6
                
OPERATING INCOME 127.1
 136.0
 239.2
 262.9
 134.7
 127.1
 221.8
 239.2
                
Other Income (Expense):  
  
  
  
  
  
    
Interest Income 1.1
 0.7
 3.5
 2.0
 0.6
 1.1
 2.0
 3.5
Allowance for Equity Funds Used During Construction 0.6
 0.4
 3.8
 1.2
 1.6
 0.6
 4.5
 3.8
Non-Service Cost Components of Net Periodic Benefit Cost 2.3
 1.0
 6.9
 2.8
 2.1
 2.3
 6.4
 6.9
Interest Expense (32.7) (31.9) (95.8) (92.7) (29.2) (32.7) (89.4) (95.8)
                
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS (LOSS) 98.4
 106.2
 157.6
 176.2
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS 109.8
 98.4
 145.3
 157.6
                
Income Tax Expense 9.6
 22.5
 17.9
 45.2
Equity Earnings (Loss) of Unconsolidated Subsidiary 0.8
 0.4
 2.0
 (4.5)
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 89.6
 84.1
 141.7
 126.5
 111.3
 89.6
 147.6
 141.7
                
Net Income Attributable to Noncontrolling Interest 1.4
 11.0
 4.1
 12.6
 0.8
 1.4
 3.1
 4.1
                
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER $88.2
 $73.1
 $137.6
 $113.9
 $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 141126.




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20182019 and 20172018
(in millions)
(Unaudited)
 Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended
 September 30, September 30, September 30, September 30,
 2018 2017 2018 2017 2019 2018 2019 2018
Net Income $89.6
 $84.1
 $141.7
 $126.5
 $111.3
 $89.6
 $147.6
 $141.7
                
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES  
    
  
  
  
  
  
Cash Flow Hedges, Net of Tax of $0.8 and $0.2 for the Three Months Ended September 30, 2018 and 2017, Respectively, and $1 and $0.6 for the Nine Months Ended September 30, 2018 and 2017, Respectively 2.7
 0.4
 3.6
 1.1
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2018 and 2017, Respectively, and $(0.3) and $(0.3) for the Nine Months Ended September 30, 2018 and 2017, Respectively (0.3) (0.2) (1.0) (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 INCOME 2.4
 0.2
 2.6
 0.6
 —
 2.4
 0.2
 2.6
                
TOTAL COMPREHENSIVE INCOME 92.0
 84.3
 144.3
 127.1
 111.3
 92.0
 147.8
 144.3
                
Total Comprehensive Income Attributable to Noncontrolling Interest 1.4
 11.0
 4.1
 12.6
 0.8
 1.4
 3.1
 4.1
                
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER $90.6
 $73.3
 $140.2
 $114.5
 $110.5
 $90.6
 $144.7
 $140.2
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141126.




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Nine Months Ended September 30, 20182019 and 20172018
(in millions)
(Unaudited)
  SWEPCo Common Shareholder    SWEPCo Common Shareholder    
Common
Stock		 Paid-in
Capital		 Retained
Earnings		 Accumulated
Other
Comprehensive
Income (Loss)		 
Noncontrolling
Interest
 Total
TOTAL EQUITY – DECEMBER 31, 2016$135.7
 $676.6
 $1,411.9
 $(9.4) $0.4
 $2,215.2
           
Common Stock Dividends    (82.5)     (82.5)
Common Stock Dividends – Nonaffiliated 
  
  
  
 (2.7) (2.7)
Net Income 
  
 113.9
  
 12.6
 126.5
Other Comprehensive Income 
 ��
  
 0.6
  
 0.6
TOTAL EQUITY – SEPTEMBER 30, 2017$135.7
 $676.6
 $1,443.3
 $(8.8) $10.3
 $2,257.1
           Common
Stock		 Paid-in
Capital		 Retained
Earnings		 Accumulated
Other
Comprehensive
Income (Loss)		 Noncontrolling
Interest		 Total
TOTAL EQUITY – DECEMBER 31, 2017$135.7
 $676.6
 $1,426.6
 $(4.0) $(0.4) $2,234.5
$135.7
 $676.6
 $1,426.6
 $(4.0) $(0.4) $2,234.5
                      
Common Stock Dividends 
  
 (60.0)  
  
 (60.0)    (20.0)     (20.0)
Common Stock Dividends – Nonaffiliated 
  
  
  
 (3.2) (3.2)        (0.8) (0.8)
ASU 2018-02 Adoption    (0.4) (0.9)   (1.3)    (0.4) (0.9)   (1.3)
Net Income 
  
 137.6
  
 4.1
 141.7
    11.8
   1.6
 13.4
Other Comprehensive Income 
  
  
 2.6
  
 2.6
      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    (20.0)     (20.0)
Common Stock Dividends – Nonaffiliated 
  
  
  
 (1.0) (1.0)
Net Income 
  
 37.6
  
 1.1
 38.7
Other Comprehensive Income 
  
  
 0.1
  
 0.1
TOTAL EQUITY – JUNE 30, 2018135.7
 676.6
 1,435.6
 (4.7) 0.5
 2,243.7
           
Common Stock Dividends    (20.0)     (20.0)
Common Stock Dividends – Nonaffiliated        (1.4) (1.4)
Net Income    88.2
   1.4
 89.6
Other Comprehensive Income      2.4
   2.4
TOTAL EQUITY – SEPTEMBER 30, 2018$135.7
 $676.6
 $1,503.8
 $(2.3) $0.5
 $2,314.3
$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 141126.




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20182019 and December 31, 20172018
(in millions)
(Unaudited)
 September 30, December 31, September 30, December 31,
 2018 2017 2019 2018
CURRENT ASSETS        
Cash and Cash Equivalents

 $2.5
 $1.6
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 518.6
 2.0
 8.5
 83.4
Accounts Receivable:        
Customers 29.1
 70.9
 20.6
 24.5
Affiliated Companies 32.8
 30.2
 56.8
 28.8
Miscellaneous 20.9
 25.8
 16.6
 20.2
Allowance for Uncollectible Accounts (0.9) (1.3) (1.4) (0.7)
Total Accounts Receivable 81.9
 125.6
 92.6
 72.8
Fuel
(September 30, 2018 and December 31, 2017 Amounts Include $33.4 and $41.5, Respectively, Related to Sabine)
 117.5
 123.6
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 69.0
 67.9
 69.8
 67.5
Risk Management Assets 6.5
 6.4
 9.4
 4.8
Regulatory Asset for Under-Recovered Fuel Costs 14.5
 14.1
 11.1
 18.8
Prepayments and Other Current Assets 32.0
 39.2
 24.4
 22.2
TOTAL CURRENT ASSETS 842.5
 380.4
 373.1
 414.5
        
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
Generation 4,655.6
 4,624.9
 4,676.1
 4,672.6
Transmission 1,812.0
 1,679.8
 1,995.9
 1,866.9
Distribution 2,146.4
 2,095.8
 2,241.1
 2,178.6
Other Property, Plant and Equipment
(September 30, 2018 and December 31, 2017 Amounts Include $269.6 and $266.7, Respectively, Related to Sabine)
 744.4
 684.1
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 234.5
 233.2
 235.0
 199.3
Total Property, Plant and Equipment 9,592.9
 9,317.8
 9,851.3
 9,680.1
Accumulated Depreciation and Amortization
(September 30, 2018 and December 31, 2017 Amounts Include $174.7 and $165.9, Respectively, Related to Sabine)
 2,798.9
 2,685.8
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 EQUIPMENT – NET
 6,794.0
 6,632.0
 7,003.1
 6,871.8
        
OTHER NONCURRENT ASSETS        
Regulatory Assets 217.8
 220.6
 223.6
 230.8
Deferred Charges and Other Noncurrent Assets 133.1
 109.9
 167.2
 111.2
TOTAL OTHER NONCURRENT ASSETS 350.9
 330.5
 390.8
 342.0
        
TOTAL ASSETS $7,987.4
 $7,342.9
 $7,767.0
 $7,628.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141126.




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 20182019 and December 31, 20172018
(Unaudited)
 September 30, December 31, September 30, December 31,
 2018 2017 2019 2018
 (in millions) (in millions)
CURRENT LIABILITIES        
Advances from Affiliates $—
 $118.7
Accounts Payable:        
General 117.6
 160.4
 $127.6
 $129.1
Affiliated Companies 41.3
 63.7
 62.4
 64.2
Short-term Debt – Nonaffiliated 19.4
 22.0
Long-term Debt Due Within One Year – Nonaffiliated 457.2
 3.7
 121.2
 59.7
Risk Management Liabilities 0.2
 0.2
 1.7
 0.4
Customer Deposits 62.7
 62.1
 65.0
 64.5
Accrued Taxes 75.2
 39.0
 94.7
 42.8
Accrued Interest 27.5
 38.9
 22.9
 34.7
Obligations Under Capital Leases 10.8
 11.2
Obligations Under Operating Leases 5.9
 —
Regulatory Liability for Over-Recovered Fuel Costs 17.4
 11.1
Other Current Liabilities 101.6
 78.7
 108.0
 106.4
TOTAL CURRENT LIABILITIES 913.5
 598.6
 626.8
 512.9
        
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated 2,615.5
 2,438.2
 2,535.7
 2,653.7
Long-term Risk Management Liabilities 2.6
 —
 3.0
 2.2
Deferred Income Taxes 932.9
 917.7
 919.1
 902.8
Regulatory Liabilities and Deferred Investment Tax Credits 896.7
 896.4
 918.1
 923.0
Asset Retirement Obligations 179.3
 160.3
 200.9
 191.3
Employee Benefits and Pension Obligations 19.3
 19.5
Obligations Under Capital Leases 52.8
 57.8
Obligations Under Operating Leases 32.5
 —
Deferred Credits and Other Noncurrent Liabilities 60.5
 19.9
 108.3
 126.8
TOTAL NONCURRENT LIABILITIES 4,759.6
 4,509.8
 4,717.6
 4,799.8
        
TOTAL LIABILITIES 5,673.1
 5,108.4
 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 1,503.8
 1,426.6
 1,615.4
 1,508.4
Accumulated Other Comprehensive Income (Loss) (2.3) (4.0) (5.2) (5.4)
TOTAL COMMON SHAREHOLDER’S EQUITY 2,313.8
 2,234.9
 2,422.5
 2,315.3
        
Noncontrolling Interest 0.5
 (0.4) 0.1
 0.3
        
TOTAL EQUITY 2,314.3
 2,234.5
 2,422.6
 2,315.6
        
TOTAL LIABILITIES AND EQUITY $7,987.4
 $7,342.9
 $7,767.0
 $7,628.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141126.




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20182019 and 20172018
(in millions)
(Unaudited)
 Nine Months Ended September 30, Nine Months Ended September 30,
 2018 2017 2019 2018
OPERATING ACTIVITIES  
  
  
  
Net Income $141.7
 $126.5
 $147.6
 $141.7
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:        
Depreciation and Amortization 175.9
 158.1
 187.1
 175.9
Deferred Income Taxes 2.0
 79.8
 (15.9) 2.0
Allowance for Equity Funds Used During Construction (3.8) (1.2) (4.5) (3.8)
Mark-to-Market of Risk Management Contracts 2.5
 (12.5) (2.5) 2.5
Pension Contributions to Qualified Plan Trust —
 (8.9)
Property Taxes (15.8) (15.4) (16.1) (15.8)
Deferred Fuel Over/Under-Recovery, Net 4.4
 2.4
 14.1
 4.4
Change in Other Noncurrent Assets (8.9) (2.9) 3.5
 (8.9)
Change in Other Noncurrent Liabilities 52.1
 (5.2) 5.8
 52.1
Changes in Certain Components of Working Capital:        
Accounts Receivable, Net 44.3
 12.1
 (17.2) 44.3
Fuel, Materials and Supplies 5.0
 13.6
 (17.7) 5.0
Accounts Payable (29.9) (25.7) (12.8) (29.9)
Accrued Taxes, Net 38.4
 69.1
 54.1
 38.4
Accrued Interest (11.4) (20.0)
Other Current Assets 3.2
 0.7
 (4.5) 3.2
Other Current Liabilities 15.6
 (14.6) (13.9) 4.2
Net Cash Flows from Operating Activities 415.3
 355.9
 307.1
 415.3
        
INVESTING ACTIVITIES        
Construction Expenditures (336.6) (265.3) (277.3) (336.6)
Change in Advances to Affiliates, Net (516.6) 167.8
 74.9
 (516.6)
Other Investing Activities 1.2
 3.1
 (1.2) 1.2
Net Cash Flows Used for Investing Activities (852.0) (94.4) (203.6) (852.0)
        
FINANCING ACTIVITIES        
Issuance of Long-term Debt – Nonaffiliated 1,015.4
 114.6
 —
 1,015.4
Change in Short-term Debt – Nonaffiliated (2.6) 14.3
 —
 (2.6)
Change in Advances from Affiliates, Net (118.7) 48.3
 —
 (118.7)
Retirement of Long-term Debt – Nonaffiliated (385.3) (353.6) (58.2) (385.3)
Principal Payments for Capital Lease Obligations (8.5) (8.4)
Principal Payments for Finance Lease Obligations (8.1) (8.5)
Dividends Paid on Common Stock (60.0) (82.5) (37.5) (60.0)
Dividends Paid on Common Stock – Nonaffiliated (3.2) (2.7) (3.3) (3.2)
Other Financing Activities 0.5
 0.4
 0.5
 0.5
Net Cash Flows from (Used for) Financing Activities 437.6
 (269.6) (106.6) 437.6
        
Net Increase (Decrease) in Cash and Cash Equivalents 0.9
 (8.1) (3.1) 0.9
Cash and Cash Equivalents at Beginning of Period 1.6
 10.3
 24.5
 1.6
Cash and Cash Equivalents at End of Period $2.5
 $2.2
 $21.4
 $2.5
        
SUPPLEMENTARY INFORMATION        
Cash Paid for Interest, Net of Capitalized Amounts $102.5
 $109.4
 $95.1
 $102.5
Net Cash Paid (Received) for Income Taxes 12.9
 (70.5)
Noncash Acquisitions Under Capital Leases 3.2
 2.8
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, 37.0
 40.7
 52.0
 37.0
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 141126.




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 
142127
New Accounting PronouncementsStandards AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 
147129
Comprehensive Income AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo 
151131
Rate Matters AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 
165139
Commitments, Guarantees and Contingencies AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 
179150
DispositionsAcquisitions and Impairments AEP, APCo 
184153
Benefit Plans AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo 
185155
Business Segments AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 
189159
Derivatives and Hedging AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo 
194164
Fair Value Measurements AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 
206176
Income Taxes AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 
224191
LeasesAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
195
Financing Activities AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 
231200
Variable Interest Entities and Equity Method Investments AEP 
238207
Revenue from Contracts with Customers AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 
240211




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, 20182019 is not necessarily indicative of results that may be expected for the year ending December 31, 2018.2019.  The condensed financial statements are unaudited and should be read in conjunction with the audited 20172018 financial statements and notes thereto, which are included in the Registrants’ Annual Reports on Form 10-K as filed with the SEC on February 22, 2018.21, 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,
2018 20172019 2018
(in millions, except per share data)(in millions, except per share data)
 
 $/share   $/share 
 $/share   $/share
Earnings Attributable to AEP Common Shareholders$577.6
  
 $544.7
  
$733.5
  
 $577.6
  
              
Weighted Average Number of Basic Shares Outstanding493.0
 $1.17
 491.8
 $1.11
493.8
 $1.49
 493.0
 $1.17
Weighted Average Dilutive Effect of Stock-Based Awards0.9
 —
 1.2
 (0.01)1.7
 (0.01) 0.9
 —
Weighted Average Number of Diluted Shares Outstanding493.9
 $1.17
 493.0
 $1.10
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,
 2018 2017
 (in millions, except per share data)
  
 $/share   $/share
Earnings Attributable to AEP Common Shareholders$1,560.4
   $1,511.9
  
        
Weighted Average Number of Basic Shares Outstanding492.6
 $3.17
 491.8
 $3.07
Weighted Average Dilutive Effect of Stock-Based Awards0.9
 (0.01) 0.6
 —
Weighted Average Number of Diluted Shares Outstanding493.5
 $3.16
 492.4
 $3.07


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, 20182019 and 2017.2018.


Nonconsolidated Variable Interest Entity (Applies to AEP and SWEPCo)

SWEPCo recorded prior year income tax adjustments in the second quarter of 2017 related to DHLC that impacted Equity Earnings (Loss) of Unconsolidated Subsidiary in the amount of $6 million.


Revisions to Previously Issued Financial Statements (Applies to only AEPTCo)
In the second quarter of 2018, management identified certain transmission assets that it believes should not have been included in AEPTCo’s SPP transmission formula rates. As a result, AEPTCo recorded a pretax out of period correction of an error of approximately $17 million related to revenue recorded from 2013 through March 31, 2018 in the second quarter of 2018. Subsequent to filing the second quarter 2018 Form 10-Q, AEPTCo identified an additional error in its previously issued financial statements. This error resulted from the improper capitalization of AFUDC and subsequent revenue recorded on the AFUDC. The impact of this misstatement reduced AEPTCo’s pretax income by approximately $7 million on a cumulative basis for the period 2011 through June 30, 2018.
Management assessed the materiality of the misstatements on all previously issued AEPTCo financial statements in accordance with SEC Staff Accounting Bulletin (SAB) No. 99, Materiality, codified in ASC 250, Presentation of Financial Statements and concluded these misstatements were not material, individually or in the aggregate, to any prior annual or interim period. In accordance with ASC 250 (SAB No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements), management revised the prior period AEPTCo financial statements included in this report to reflect the impact of correcting the immaterial misstatements described above. In addition, management will revise the historical 2017, March 31, 2018 and June 30, 2018 periods presented in AEPTCo’s previously issued financial statements in future SEC Form 10-Q and Form 10-K filings to reflect the impact of the misstatements. The $(18) million adjustment to pretax income for the nine months ended September 30, 2017 includes adjustments of $(12) million relating to 2016 and earlier periods. The effect of recording this adjustment of $(12) million in 2017 is not material to AEPTCo’s financial statements for 2017 or any earlier period.
AEPTCo has also corrected other previously recorded immaterial out of period adjustments. The impact of these additional adjustments did not impact net income in any period.
Management also assessed the materiality of the AEPTCo’s misstatements discussed above on all previously issued and the current year AEP financial statements in accordance with ASC 250, and concluded these misstatements were not material, individually or in the aggregate, to any prior and current interim and annual period financial statements. As a result, AEP recorded the correction in the third quarter of 2018.
Statements of Income
The table below reflects the effects of correcting the immaterial errors described above on AEPTCo’s statements of income for the three and nine months ended September 30, 2017:
  
Three Months Ended
September 30, 2017
 
Nine Months Ended
September 30, 2017
  As Reported Adjustments As Adjusted As Reported Adjustments As Adjusted
  (in millions) (in millions)
TOTAL REVENUES $167.3
 $(1.7) $165.6
 $549.4
 $(14.6) $534.8
             
EXPENSES  
    
  
    
Depreciation and Amortization 24.8
 (0.2) 24.6
 70.9
 (1.2) 69.7
TOTAL EXPENSES 72.2
 (0.2) 72.0
 198.5
 (1.2) 197.3
             
OPERATING INCOME 95.1
 (1.5) 93.6
 350.9
 (13.4) 337.5
             
Other Income (Expense):  
    
  
    
Allowance for Equity Funds Used During Construction 11.7
 (0.3) 11.4
 36.0
 (3.0) 33.0
Interest Expense (16.9) (0.2) (17.1) (48.6) (1.8) (50.4)
             
INCOME BEFORE INCOME TAX EXPENSE 90.1
 (2.0) 88.1
 338.8
 (18.2) 320.6
             
Income Tax Expense 30.2
 (0.7) 29.5
 114.5
 (6.3) 108.2
             
NET INCOME $59.9
 $(1.3) $58.6
 $224.3
 $(11.9) $212.4


Balance Sheet

The table below reflects the effects of correcting the immaterial errors described above on AEPTCo’s Balance Sheet as of December 31, 2017:
  December 31, 2017
  As Reported Adjustment As Adjusted
CURRENT ASSETS (in millions)
Accounts Receivable:      
Customers $19.1
 $(4.1) $15.0
Total Accounts Receivable 113.6
 (4.1) 109.5
Accrued Tax Benefits 46.6
 2.8
 49.4
TOTAL CURRENT ASSETS 327.7
 (1.3) 326.4
       
TRANSMISSION PROPERTY      
Transmission Property 5,336.1
 (16.4) 5,319.7
Other Property, Plant and Equipment 131.4
 (4.6) 126.8
Construction Work in Progress 1,312.7
 11.3
 1,324.0
Total Transmission Property 6,780.2
 (9.7) 6,770.5
Accumulated Depreciation and Amortization 170.4
 (17.8) 152.6
TOTAL TRANSMISSION PROPERTY – NET
 6,609.8
 8.1
 6,617.9
       
OTHER NONCURRENT ASSETS      
Deferred Property Taxes 117.8
 7.2
 125.0
TOTAL OTHER NONCURRENT ASSETS 130.6
 7.2
 137.8
       
TOTAL ASSETS $7,068.1
 $14.0
 $7,082.1
CURRENT LIABILITIES      
Accounts Payable:      
General $473.2
 $11.3
 $484.5
Affiliated Companies 52.9
 13.2
 66.1
Accrued Taxes 225.4
 6.1
 231.5
TOTAL CURRENT LIABILITIES 836.3
 30.6
 866.9
       
NONCURRENT LIABILITIES      
Deferred Income Taxes 601.7
 (1.3) 600.4
Regulatory Liabilities 493.7
 0.1
 493.8
TOTAL NONCURRENT LIABILITIES 3,626.5
 (1.2) 3,625.3
       
TOTAL LIABILITIES 4,462.8
 29.4
 4,492.2
       
MEMBER’S EQUITY      
Retained Earnings 788.7
 (15.4) 773.3
TOTAL MEMBER’S EQUITY 2,605.3
 (15.4) 2,589.9
       
TOTAL LIABILITIES AND MEMBER’S EQUITY $7,068.1
 $14.0
 $7,082.1



Statement of Cash Flows
The table below reflects the effects of correcting the immaterial errors described above on AEPTCo’s statement of cash flows for the nine months ended September 30, 2017:
  Nine Months Ended September 30, 2017
  As Reported Adjustments As Adjusted
  (in millions)
OPERATING ACTIVITIES      
Net Income $224.3
 $(11.9) $212.4
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:      
Depreciation and Amortization 70.9
 (1.2) 69.7
Deferred Income Taxes 193.0
 (1.1) 191.9
Allowance for Equity Funds Used During Construction (36.0) 3.0
 (33.0)
Change in Other Noncurrent Assets 7.6
 1.0
 8.6
Changes in Certain Components of Working Capital:   

  
Accounts Receivable, Net (44.4) 3.6
 (40.8)
Accounts Payable 8.6
 11.8
 20.4
Accrued Taxes, Net (66.0) (5.2) (71.2)
Net Cash Flows from Operating Activities 444.9
 —
 444.9
       
INVESTING ACTIVITIES   

 

Net Cash Flows Used for Investing Activities (1,277.4) —
 (1,277.4)
       
FINANCING ACTIVITIES  
    
Net Cash Flows from Financing Activities 832.5
 —
 832.5
       
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
 $1.8
 $30.4
Construction Expenditures Included in Current Liabilities as of September 30, 239.0
 9.9
 248.9
Statement of Changes in Member’s Equity
The statement of changes in AEPTCo’s member’s equity reflects the adjustments to Net Income of $(1) million and $(12) million for the three and nine months ended September 30, 2017 as shown in the table under Net Income above. The statement of changes in member’s equity also reflects the adjustments to Retained Earnings of $(15) million as of December 31, 2017 as shown in the table under Balance Sheet above.



Restricted Cash (Applies to AEP, AEP Texas, APCo and OPCo)
 
Restricted Cash primarily includesincluded funds held by trusteestrustee for the payment of securitization bonds.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 onwithin the balance sheets that sum to the total of the same amounts shown on the statements of cash flows:
 September 30, 2018 September 30, 2019
 AEP AEP Texas APCo OPCo AEP AEP Texas APCo OPCo
 (in millions) (in millions)
Cash and Cash Equivalents $788.3
 $0.1
 $2.2
 $3.5
 $348.8
 $0.1
 $3.5
 $4.7
Restricted Cash 149.2
 124.2
 9.9
 15.2
 141.0
 114.3
 17.1
 —
Total Cash, Cash Equivalents and Restricted Cash $937.5
 $124.3
 $12.1
 $18.7
 $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




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



2. NEW ACCOUNTING PRONOUNCEMENTSSTANDARDS


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


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

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

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

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

Management adopted ASU 2016-01 effective January 1, 2018, by means of a cumulative-effect adjustment to the balance sheet. The adoption of ASU 2016-01 resulted in an immaterial impact on results of operations and financial position of AEP, and no impact to results of operations or financial position of the Registrant Subsidiaries. There was no impact on cash flows of the Registrants.


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


In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheets and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will beleases are known as a finance leaseleases going forward. Leases with 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. In July 2018, the FASB issued ASU 2018-11 “Leases (Topic 842): Targeted Improvements”, which provides an optional expedient to adopt the new lease requirements through a cumulative-effect adjustment in the period of adoption. Management plans to apply the new optional transition guidance.


New leasing standard implementation activities to date includeincluded the identification of the lease population within the AEP System as well as the sampling of representative lease contracts to analyze accounting treatment under the new accounting guidance. Based upon the completed assessments, management also prepared a gap analysis to outline new disclosure compliance requirements. A lease system was selected after reviewing multiple system options. System implementation activities of core functionality continue in the fourth quarter of 2018. Implementation of reporting functionality designed to meet new disclosure requirements is ongoing.


Management plansadopted ASU 2016-02 effective January 1, 2019 by means of a cumulative-effect adjustment to elect certain of the optionalbalance sheets. Management elected 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.
Existing and expired land easements not previously accounted for as leases Elect optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840.
Cumulative-effect adjustment in the period of adoptionElect the optional transition practical expedient to adopt the new lease 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 will continue through the fourth quarter. Management expectsthat qualify as leases going forward. The adoption of the new standard todid not materially impact financial position and, at this time, cannot estimate the impact. Management does not expect any impact to results of operations or cash flows. Management plans to adopt ASU 2016-02 and its related guidance effective January 1, 2019.flows, but did have a material impact on the balance sheets. See Note 12 - Leases for additional disclosures required by the new standard.


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 impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020.



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

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

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

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

In August 2017, the FASB issued ASU 2017-12 amending the recognition and presentation requirements for hedge accounting activities. The objectivesAEP system that are subject 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. Among other things, ASU 2017-12: (a) expands the types of transactions eligible for hedge accounting, (b) eliminates the separate measurement and presentation of hedge ineffectiveness, (c) simplifies the requirements around the assessment of hedge effectiveness, (d) provides companies more time to finalize hedge documentation and (e) enhances presentation and disclosure requirements.

Management early adopted ASU 2017-12 in the second quarter of 2018, effective January 1, 2018, by means of a modified retrospective approach. The adoption of ASU 2017-12 resulted in an immaterial impact on results of operations and financial position of AEP, and no impact to results of operations or financial position of the Registrant Subsidiaries. There was no impact on cash flows of the Registrants. Further, given the lack of material impact to the financial statements, the adoption of the new standard did not give riseand evaluations to determine whether the new expected loss recognition model will cause any material changes into previously calculated allowance balances and supporting valuation models. Based on the Registrants’ previously established accounting policies for derivatives and hedging.

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

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

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



ASU 2018-15 “Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract” (ASU 2018-15)

In August 2018, the FASB issued ASU 2018-15 aligning the requirements for capitalizing implementation costs incurred in a cloud computing arrangement (hosting arrangement) that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The new standard requires an entity (customer) in a hosting arrangement that is a service contract to follow the accounting guidance for “Internal-Use Software” to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. Capitalized implementation costs of a hosting arrangement that is a service contract should be amortized over the term of the hosting arrangement. The expense related to the capitalized implementation costs should be presented in the same line item in the statement of income as the fees associated with the hosting element (service) of the arrangement.  Payments for capitalized implementation costs in the statement of cash flows should be classified in the same manner as payments made for fees associated with the hosting element. Capitalized implementation costs in the statement of financial position should be presented in the same line item that a prepayment for the fees of the associated hosting arrangement would be presented.

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. The amendments may be applied either retrospectively or prospectively to applicable implementation costs incurred after the date of adoption. Management is analyzing the impact of this new standard and at this time, cannot estimate the impact of adoption on results of operations, financial position or cash flows.

Management’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 systems because of the adoption of the new standard. Management plans to adopt ASU 2018-15 prospectively,2016-13 and its related implementation guidance effective January 1, 2020.







3.  COMPREHENSIVE INCOME


The disclosures in this note apply to all Registrants except for AEPTCo. AEPTCo does not have any components of other comprehensive income for any period presented in the financial statements.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, 2018 and 2017.AOCI.  The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 - Benefit Plans for additional details.


AEP

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2018
 Cash Flow Hedges    
 Commodity Interest Rate Pension
and OPEB		 Total
 (in millions)
Balance in AOCI as of June 30, 2018$(30.4) $(15.3) $(49.1) $(94.8)
Change in Fair Value Recognized in AOCI12.2
 2.3
 —
 14.5
Amount of (Gain) Loss Reclassified from AOCI       
Generation & Marketing Revenues (a)(0.1) —
 —
 (0.1)
Purchased Electricity for Resale (a)(5.8) —
 —
 (5.8)
Interest Expense (a)—
 0.4
 —
 0.4
Amortization of Prior Service Cost (Credit)—
 —
 (5.0) (5.0)
Amortization of Actuarial (Gains)/Losses—
 —
 3.2
 3.2
Reclassifications from AOCI, before Income Tax (Expense) Credit(5.9) 0.4
 (1.8) (7.3)
Income Tax (Expense) Credit(1.3) 0.1
 (0.4) (1.6)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit(4.6) 0.3
 (1.4) (5.7)
Net Current Period Other Comprehensive Income (Loss)7.6
 2.6
 (1.4) 8.8
Balance in AOCI as of September 30, 2018$(22.8) $(12.7) $(50.5) $(86.0)

AEP

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2017
  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, 2017$(36.0) $(10.4) $10.2
 $(125.4) $(161.6)
Balance in AOCI as of June 30, 2018 $(30.4) $(15.3) $(49.1) $(94.8)
Change in Fair Value Recognized in AOCI(15.8) (2.0) 0.9
 —
 (16.9) 12.2
 2.3
 —
 14.5
Amount of (Gain) Loss Reclassified from AOCI                 
Generation & Marketing Revenues (a)(0.9) —
 —
 —
 (0.9) (0.1) —
 —
 (0.1)
Purchased Electricity for Resale (a)4.9
 —
 —
 —
 4.9
 (5.8) —
 —
 (5.8)
Interest Expense (a)—
 0.4
 —
 —
 0.4
 —
 0.4
 —
 0.4
Amortization of Prior Service Cost (Credit)—
 —
 —
 (5.0) (5.0) —
 —
 (5.0) (5.0)
Amortization of Actuarial (Gains)/Losses—
 —
 —
 5.4
 5.4
Reclassifications from AOCI, before Income Tax (Expense) Credit4.0
 0.4
 —
 0.4
 4.8
Income Tax (Expense) Credit1.4
 0.2
 —
 0.1
 1.7
Reclassifications from AOCI, Net of Income Tax (Expense) Credit2.6
 0.2
 —
 0.3
 3.1
Amortization of Actuarial (Gains) Losses —
 —
 3.2
 3.2
Reclassifications from AOCI, before Income Tax (Expense) Benefit (5.9) 0.4
 (1.8) (7.3)
Income Tax (Expense) Benefit (1.3) 0.1
 (0.4) (1.6)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (4.6) 0.3
 (1.4) (5.7)
Net Current Period Other Comprehensive Income (Loss)(13.2) (1.8) 0.9
 0.3
 (13.8) 7.6
 2.6
 (1.4) 8.8
Balance in AOCI as of September 30, 2017$(49.2) $(12.2) $11.1
 $(125.1) $(175.4)
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, 2018
Cash Flow Hedges       Cash Flow Hedges Securities    
Commodity Interest Rate 
Securities
Available for Sale
 
Pension
and OPEB
 Total   Interest Available Pension  
Nine Months Ended September 30, 2018 Commodity Rate for Sale and OPEB Total
(in millions) (in millions)
Balance in AOCI as of December 31, 2017$(28.4) $(13.0) $11.9
 $(38.3) $(67.8) $(28.4) $(13.0) $11.9
 $(38.3) $(67.8)
Change in Fair Value Recognized in AOCI30.4
 2.3
 —
 —
 32.7
 30.4
 2.3
 —
 —
 32.7
Amount of (Gain) Loss Reclassified from AOCI                   
Generation & Marketing Revenues (a)(0.1) —
 —
 —
 (0.1) (0.1) —
 —
 —
 (0.1)
Purchased Electricity for Resale (a)(23.6) —
 —
 —
 (23.6) (23.6) —
 —
 —
 (23.6)
Interest Expense (a)—
 0.9
 —
 —
 0.9
 —
 0.9
 —
 —
 0.9
Amortization of Prior Service Cost (Credit)—
 —
 —
 (14.7) (14.7) —
 —
 —
 (14.7) (14.7)
Amortization of Actuarial (Gains)/Losses—
 —
 —
 9.6
 9.6
Reclassifications from AOCI, before Income Tax (Expense) Credit(23.7) 0.9
 —
 (5.1) (27.9)
Income Tax (Expense) Credit(5.0) 0.2
 —
 (1.1) (5.9)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit(18.7) 0.7
 —
 (4.0) (22.0)
Amortization of Actuarial (Gains) Losses —
 —
 —
 9.6
 9.6
Reclassifications from AOCI, before Income Tax (Expense) Benefit (23.7) 0.9
 —
 (5.1) (27.9)
Income Tax (Expense) Benefit (5.0) 0.2
 —
 (1.1) (5.9)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (18.7) 0.7
 —
 (4.0) (22.0)
Net Current Period Other Comprehensive Income (Loss)11.7
 3.0
 —
 (4.0) 10.7
 11.7
 3.0
 —
 (4.0) 10.7
ASU 2018-02 Adoption (b)(6.1) (2.7) —
 (8.2) (17.0)
ASU 2016-01 Adoption (b)—
 —
 (11.9) —
 (11.9)
ASU 2018-02 Adoption (6.1) (2.7) —
 (8.2) (17.0)
ASU 2016-01 Adoption —
 —
 (11.9) —
 (11.9)
Balance in AOCI as of September 30, 2018$(22.8) $(12.7) $—
 $(50.5) $(86.0) $(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, 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) $(156.3)
Change in Fair Value Recognized in AOCI(39.4) 2.7
 2.7
 —
 (34.0)
Amount of (Gain) Loss Reclassified from AOCI         
Generation & Marketing Revenues (a)(5.6) —
 —
 —
 (5.6)
Purchased Electricity for Resale (a)26.0
 —
 —
 —
 26.0
Interest Expense (a)—
 1.2
 —
 —
 1.2
Amortization of Prior Service Cost (Credit)—
 —
 —
 (14.8) (14.8)
Amortization of Actuarial (Gains)/Losses—
 —
 —
 16.0
 16.0
Reclassifications from AOCI, before Income Tax (Expense) Credit20.4
 1.2
 —
 1.2
 22.8
Income Tax (Expense) Credit7.1
 0.4
 —
 0.4
 7.9
Reclassifications from AOCI, Net of Income Tax (Expense) Credit13.3
 0.8
 —
 0.8
 14.9
Net Current Period Other Comprehensive Income (Loss)(26.1) 3.5
 2.7
 0.8
 (19.1)
Balance in AOCI as of September 30, 2017$(49.2) $(12.2) $11.1
 $(125.1) $(175.4)




AEP Texas

Changes in Accumulated Other Comprehensive Income (Loss) by Component
  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)
For the Three Months Ended September 30, 2018
  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)

 Cash Flow Hedge – Interest Rate 
Pension
and OPEB
 Total Cash Flow Hedge – Pension  
Nine Months Ended September 30, 2018 Interest Rate and OPEB Total
(in millions)(in millions)
Balance in AOCI as of June 30, 2018 $(4.9) $(9.8) $(14.7)
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) 0.4
 —
 0.4
 1.0
 —
 1.0
Amortization of Prior Service Cost (Credit) —
 —
 —
 —
 (0.1) (0.1)
Amortization of Actuarial (Gains)/Losses —
 —
 —
Reclassifications from AOCI, before Income Tax (Expense) Credit 0.4
 —
 0.4
Income Tax (Expense) Credit 0.1
 —
 0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3
 —
 0.3
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) 0.3
 —
 0.3
 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) $(4.6) $(9.8) $(14.4)

AEP Texas

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2017APCo
  Cash Flow Hedge – Interest Rate 
Pension
and OPEB
 Total
 (in millions)
Balance in AOCI as of June 30, 2017 $(4.9) $(9.4) $(14.3)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense (a) 0.3
 —
 0.3
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) Credit 0.3
 0.1
 0.4
Income Tax (Expense) Credit 0.1
 —
 0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.2
 0.1
 0.3
Net Current Period Other Comprehensive Income (Loss) 0.2
 0.1
 0.3
Balance in AOCI as of September 30, 2017 $(4.7) $(9.3) $(14.0)



AEP Texas

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2018
  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 Hedge – Interest Rate 
Pension
and OPEB
 Total Cash Flow Hedge – Pension  
Three Months Ended September 30, 2018 Interest Rate and OPEB Total
(in millions)(in millions)
Balance in AOCI as of December 31, 2017 $(4.5) $(8.1) $(12.6)
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) 1.0
 —
 1.0
 (0.4) —
 (0.4)
Amortization of Prior Service Cost (Credit) —
 (0.1) (0.1) —
 (1.3) (1.3)
Amortization of Actuarial (Gains)/Losses —
 0.2
 0.2
Reclassifications from AOCI, before Income Tax (Expense) Credit 1.0
 0.1
 1.1
Income Tax (Expense) Credit 0.2
 —
 0.2
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.8
 0.1
 0.9
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) 0.8
 0.1
 0.9
 (0.3) (0.7) (1.0)
ASU 2018-02 Adoption (b) (0.9) (1.8) (2.7)
Balance in AOCI as of September 30, 2018 $(4.6) $(9.8) $(14.4) $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)


AEP Texas

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2017I&M
  Cash Flow Hedge – Interest Rate 
Pension
and OPEB
 Total
 (in millions)
Balance in AOCI as of December 31, 2016 $(5.4) $(9.5) $(14.9)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense (a) 1.0
 —
 1.0
Amortization of Prior Service Cost (Credit) —
 (0.1) (0.1)
Amortization of Actuarial (Gains)/Losses —
 0.4
 0.4
Reclassifications from AOCI, before Income Tax (Expense) Credit 1.0
 0.3
 1.3
Income Tax (Expense) Credit 0.3
 0.1
 0.4
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7
 0.2
 0.9
Net Current Period Other Comprehensive Income (Loss) 0.7
 0.2
 0.9
Balance in AOCI as of September 30, 2017 $(4.7) $(9.3) $(14.0)



APCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2018
  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 Hedge – Interest Rate 
Pension
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) Credit (0.4) (0.9) (1.3)
Income Tax (Expense) Credit (0.1) (0.2) (0.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (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)

APCo

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, 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 Hedge – 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 (a) (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 Income (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, 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)






APCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2018OPCo
  Cash Flow Hedges    
  Commodity Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of December 31, 2017 $—
 $2.2
 $(0.9) $1.3
Change in Fair Value Recognized in AOCI (0.7) —
 —
 (0.7)
Amount of (Gain) Loss Reclassified from AOCI        
Purchased Electricity for Resale (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) Credit 0.9
 (0.9) (2.9) (2.9)
Income Tax (Expense) Credit 0.2
 (0.2) (0.6) (0.6)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 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 (b) —
 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, 2017
  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 Hedge – Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of December 31, 2016 $2.9
 $(11.3) $(8.4)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense (a) (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 Income (Loss) (0.5) (0.9) (1.4)
Balance in AOCI as of September 30, 2017 $2.4
 $(12.2) $(9.8)



I&M

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2018
  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 Hedge – Interest Rate 
Pension
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) Credit 0.4
 —
 0.4
Income Tax (Expense) Credit 0.1
 —
 0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3
 —
 0.3
Net Current Period Other Comprehensive Income (Loss) 0.3
 —
 0.3
Balance in AOCI as of September 30, 2018 $(11.9) $(1.7) $(13.6)
  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


I&M

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2017PSO
  Cash Flow Hedge – 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 (a) 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 (Loss) 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 Nine Months Ended September 30, 2018
  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 Hedge – Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of December 31, 2017 $(10.7) $(1.4) $(12.1)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense (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) Credit 1.5
 —
 1.5
Income Tax (Expense) Credit 0.3
 —
 0.3
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.2
 —
 1.2
Net Current Period Other Comprehensive Income (Loss) 1.2
 —
 1.2
ASU 2018-02 Adoption (b) (2.4) (0.3) (2.7)
Balance in AOCI as of September 30, 2018 $(11.9) $(1.7) $(13.6)
  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


I&M

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2017SWEPCo
  Cash Flow Hedge – Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of December 31, 2016 $(12.0) $(4.2) $(16.2)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense (a) 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 (Loss) 1.0
 —
 1.0
Balance in AOCI as of September 30, 2017 $(11.0) $(4.2) $(15.2)



OPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2018
  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 Hedge – 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) Credit (0.5)
Income Tax (Expense) Credit (0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4)
Net Current Period Other Comprehensive Income (Loss) (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, 2017
  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 Hedge – 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 (a) (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 Income (Loss) (0.3)
Balance in AOCI as of September 30, 2017 $2.2



OPCo

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


OPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2017
  Cash Flow Hedge – Interest Rate
  (in millions)
Balance in AOCI as of December 31, 2016 $3.0
Change in Fair Value Recognized in AOCI —
Amount of (Gain) Loss Reclassified from AOCI  
Interest Expense (a) (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 Income (Loss) (0.8)
Balance in AOCI as of September 30, 2017 $2.2



PSO

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2018
  Cash Flow Hedge – 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) Credit (0.2)
Income Tax (Expense) Credit —
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2)
Net Current Period Other Comprehensive Income (Loss) (0.2)
Balance in AOCI as of September 30, 2018 $2.4

PSO

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2017
  Cash Flow Hedge – 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 (a) (0.4)
Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4)
Income Tax (Expense) Credit (0.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2)
Net Current Period Other Comprehensive Income (Loss) (0.2)
Balance in AOCI as of September 30, 2017 $2.8



PSO

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

PSO

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2017
  Cash Flow Hedge – Interest Rate
  (in millions)
Balance in AOCI as of December 31, 2016 $3.4
Change in Fair Value Recognized in AOCI —
Amount of (Gain) Loss Reclassified from AOCI  
Interest Expense (a) (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 Income (Loss) (0.6)
Balance in AOCI as of September 30, 2017 $2.8



SWEPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2018
  Cash Flow Hedge – Interest Rate 
Pension
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) Credit 0.5
 (0.4) 0.1
Income Tax (Expense) Credit 0.1
 (0.1) —
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4
 (0.3) 0.1
Net Current Period Other Comprehensive Income (Loss) 2.7
 (0.3) 2.4
Balance in AOCI as of September 30, 2018 $(3.7) $1.4
 $(2.3)

SWEPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended September 30, 2017
  Cash Flow Hedge – 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 (a) 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 Nine Months Ended September 30, 2018
  Cash Flow Hedge – Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of December 31, 2017 $(6.0) $2.0
 $(4.0)
Change in Fair Value Recognized in AOCI 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) Credit 1.6
 (1.3) 0.3
Income Tax (Expense) Credit 0.3
 (0.3) —
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.3
 (1.0) 0.3
Net Current Period Other Comprehensive Income (Loss) 3.6
 (1.0) 2.6
ASU 2018-02 Adoption (b) (1.3) 0.4
 (0.9)
Balance in AOCI as of September 30, 2018 $(3.7) $1.4
 $(2.3)

SWEPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Nine Months Ended September 30, 2017
  Cash Flow Hedge – Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of December 31, 2016 $(7.4) $(2.0) $(9.4)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense (a) 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)

(a) Amounts reclassified to the referenced line item on the statements of income.
(b) See Note 2 - New Accounting Pronouncements for additional information.


4.  RATE MATTERS


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


As discussed in the 20172018 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 20172018 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 20182019 and updates the 20172018 Annual Report.


Regulated Generating Unit to be Retired by 2020 (Applies to AEP and PSO)


In 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, 2018.2019. 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

Gross
Investment
 
Accumulated
Depreciation
 
Net
Investment
 Materials and Supplies 
Cost of
Removal
Regulatory
Liability
 
Expected
Retirement
Date
 
Remaining
Recovery
Period
(dollars in millions)
$106.5
 $56.8
 $49.7
 $3.1
 $5.0
 2020 28 years

(a)In October 2018, PSO changed depreciation rates to utilize the 2020 end-of-life and defer depreciation expense to a regulatory asset for the amount in excess of the previously OCC-approved depreciation rates for Oklaunion Power Station. See “2018 Oklahoma Base Rate Case” discussion below for additional information.


Regulatory Assets Pending Final Regulatory Approval (Applies to all Registrants except AEPTCo and OPCo)AEPTCo)
 AEP AEP
 September 30, December 31, September 30, December 31,
 2018 2017 2019 2018
Noncurrent Regulatory Assets (in millions) (in millions)
        
Regulatory Assets Currently Earning a Return        
Plant Retirement Costs - Unrecovered Plant $50.3
 $50.3
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 20.1
 9.6
 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) 151.7
 128.0
 —
 152.4
Plant Retirement Costs - Asset Retirement Obligation Costs 39.7
 39.7
Cook Plant Uprate Project —
 36.3
Cook Plant Turbine —
 15.9
Other Regulatory Assets Pending Final Regulatory Approval 18.8
 42.2
 26.8
 20.7
Total Regulatory Assets Pending Final Regulatory Approval (b)Total Regulatory Assets Pending Final Regulatory Approval (b)$280.6
 $322.0
Total Regulatory Assets Pending Final Regulatory Approval (b)$168.4
 $288.0


(a)As ofIn September 30, 2018,2019, AEP Texas has deferred $127securitized $235 million related to Hurricane Harvey and is in the process of requesting securitizationstorm-related costs. As a result of the distribution portion ofsecuritization, the regulatory asset.asset balance was transferred to Securitized Assets on the balance 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. APCo’s recovery of the remaining Virginia net book value for the retired plants will be considered in the Virginia SCC’s 2020 triennial review of APCo’s generation and distribution base rates. In 2017, the Virginia SCC staff requested that APCo prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. In June 2018, APCo submitted the new depreciation study, based on December 31, 2017 property balances, to the Virginia SCC staff.




 AEP Texas AEP Texas
 September 30, December 31, September 30, December 31,
 2018 2017 2019 2018
Noncurrent Regulatory Assets (in millions) (in millions)
        
Regulatory Assets Currently Not Earning a Return        
Rate Case Expense $2.3
 $0.2
Storm-Related Costs (a) $150.2
 $123.3
 —
 152.4
Rate Case Expense 0.2
 0.1
Total Regulatory Assets Pending Final Regulatory Approval $150.4
 $123.4
 $2.3
 $152.6


(a)
As ofIn September 30, 2018,2019, AEP Texas has deferred $127securitized $235 millionrelated to Hurricane Harvey and is in the process of requesting securitizationstorm-related costs. As a result of the distribution portion ofsecuritization, the regulatory asset.
asset balance was transferred to Securitized Assets on the balance sheets. See “Texas Storm Cost Securitization” discussion below for additional information.
 APCo APCo
 September 30, December 31, September 30, December 31,
 2018 2017 2019 2018
Noncurrent Regulatory Assets (in millions) (in millions)
        
Regulatory Assets Currently Earning a Return        
Plant Retirement Costs - Materials and Supplies $9.0
 $9.1
Plant Retirement Costs – Materials and Supplies
 $5.1
 $9.0
Regulatory Assets Currently Not Earning a Return        
Plant Retirement Costs - Asset Retirement Obligation Costs 39.7
 39.7
Plant Retirement Costs – Asset Retirement Obligation Costs
 37.8
 35.3
Other Regulatory Assets Pending Final Regulatory Approval 0.6
 0.6
 —
 0.6
Total Regulatory Assets Pending Final Regulatory Approval (a) $49.3
 $49.4
 $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. APCo’s recovery of the remaining Virginia net book value for the retired plants will be considered in the Virginia SCC’s 2020 triennial review of APCo’s generation and distribution base rates. In 2017, the Virginia SCC staff requested that APCo prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. In June 2018, APCo submitted the new depreciation study, based on December 31, 2017 property balances, to the Virginia SCC staff.
 I&M I&M
 September 30, December 31, September 30, December 31,
 2018 2017 2019 2018
Noncurrent Regulatory Assets (in millions) (in millions)
        
Regulatory Assets Currently Not Earning a Return        
Cook Plant Uprate Project $—
 $36.3
Deferred Cook Plant Life Cycle Management Project Costs - Michigan —
 14.7
Cook Plant Turbine —
 15.9
Rockport Dry Sorbent Injection System - Indiana —
 10.4
Cook Plant Study Costs $10.7
 $—
Other Regulatory Assets Pending Final Regulatory Approval 3.4
 2.0
 0.1
 3.3
Total Regulatory Assets Pending Final Regulatory Approval $3.4
 $79.3
 $10.8
 $3.3
 PSO OPCo
 September 30, December 31, September 30, December 31,
�� 2018 2017
 2019 2018
Noncurrent Regulatory Assets (in millions) (in millions)
        
Regulatory Assets Currently Not Earning a Return  
  
    
Storm-Related Costs $—
 $3.2
Other Regulatory Assets Pending Final Regulatory Approval 0.5
 0.1
 $0.1
 $1.0
Total Regulatory Assets Pending Final Regulatory Approval $0.5
 $3.3
 $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
 SWEPCo SWEPCo
 September 30, December 31, September 30, December 31,
 2018 2017 2019 2018
Noncurrent Regulatory Assets (in millions) (in millions)
        
Regulatory Assets Currently Earning a Return        
Plant Retirement Costs - Unrecovered Plant $50.3
 $50.3
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  
  
  
  
Asset Retirement Obligation - Arkansas, Louisiana 5.0
 4.0
 6.8
 5.3
Rate Case Expense - Texas 4.6
 4.3
Shipe Road Transmission Project - FERC —
 3.3
Rate Case Expense – Texas
 1.4
 4.9
Other Regulatory Assets Pending Final Regulatory Approval 3.3
 2.5
 4.2
 3.6
Total Regulatory Assets Pending Final Regulatory Approval $63.7
 $64.9
 $63.0
 $64.4



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


Impact of Tax Reform

Rate and regulatory matters are impacted by federal income tax implications. In December 2017, Tax Reform was enacted, which impacts outstanding rate and regulatory matters. For additional details on the impact of Tax Reform, see Note 11 - Income Taxes.

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


AEP Texas Interim Transmission and Distribution Rates


As of September 30, 2018,2019, AEP Texas’ cumulative revenues from interim basetransmission and distribution rate increases from 2008 through 2018,2019, subject to review, are estimated to be $959 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 April 2018,May 2019, AEP Texas filed a request with the PUCT adopted a rule requiring investor-owned utilities operating solely within ERCOT to make periodic filings for rate proceedings. The rule requires AEP Texas to file for a comprehensive rate review no later than May 1, 2019.

In 2018, the PUCT issued approvals to increase AEP Texas’ transmission rates by $22$56 million annually. The approvals included anannual increase in annual revenues to recover transmission capital additions of $46rates based upon a proposed 10.5% return on common equity. The filing includes a proposed Income Tax Refund Rider that will refund $21 million offset by a reduction in annual revenues of $24 million due to the reduction in the federal income tax rate due to Tax Reform. The approvals did not address the returnannually of Excess ADIT benefits to customers.

In August 2018, the PUCT approved a Stipulation and Settlement agreement to amend AEP Texas’ Distribution Cost Recovery Factor to reduce annual distribution rates by approximately $24 million annually, beginning September 1, 2018. The settlement included an increase in annual revenues to recover 2017 distribution capital additions of $19 million offset by reductions in annual revenues of: (a) $21 million due to the reduction in the federal income tax rate due to Tax Reform, (b) $10 million due to Excess ADIT associated with certain depreciable property to be amortized using ARAM and (c) $12 million due to Excess ADIT that is primarily not subject to rate normalization requirementsrequirements. 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 refunded over 5 years.returned to customers, it could reduce future net income and cash flows and impact financial condition.



Texas Storm Cost Securitization


Hurricane Harvey

In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. 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, 2018, the total balance of AEP Texas’ regulatory asset for deferred storm costs is approximately $150 million, inclusive of approximately $127 millionof incremental storm expenses related to Hurricane Harvey. As of September 30, 2018, AEP Texas has recorded approximately $205 millionof capital expenditures related to Hurricane Harvey. Also, as of September 30, 2018, AEP Texas has received $10 millionin insurance proceeds, and has recorded a receivable for an additional $4 million that will be received in the fourth quarter of 2018, which were applied to the Hurricane Harvey related regulatory asset and property, plant and equipment balances. Management, in conjunction with the insurance adjusters, is reviewing all damages to determine the extent of coverage for additional insurance reimbursement. Any future insurance recoveries received will be applied to and will offset the regulatory asset and property, plant and equipment, as applicable.

Management believes the amount recorded as a regulatory asset is probable of recovery and is in the process of requesting securitization of the distribution portion of the regulatory asset. The standard process for securitization of storm cost recovery in Texas requires two filings with the PUCT. In August 2018,March 2019, AEP Texas filed a Determination of System Restoration Costsrequest to securitize total estimated distribution-related system restoration costs with the PUCT, forwhich included estimated carrying costs. In June 2019, the PUCT approved the financing order. As part of the financing order, AEP Texas agreed to offset $64 million of Excess ADIT that is not subject to rate normalization requirements against the total estimated stormdistribution-related system restoration costs. In September 2019, AEP Texas issued $235 million of securitization bonds. The securitization bonds included carrying costs in the amount of $425$33 million, which includes estimated carrying costs. The estimated value of the total storm costs net of insurance proceeds, tax credits and Excess ADIT is $370 million. AEP Texas intends to request securitization for distribution related assets of $253 million while the remaining $117$21 million of transmission related assets willdebt carrying costs recorded as a reduction to Interest Expense in 2019.

The remaining $95 million of estimated net transmission-related system restoration costs, including carrying charges, is expected to be recovered in the 2019 Texas Base Rate Case described above or through interim transmission filings or an upcoming base rate case. The request for securitization is expected to occur by the first quarter of 2019.

In October 2018, intervenors filed testimony requesting a $24 million reduction in AEP Texas’ Determination of System Restoration Costs.Also in October 2018, the PUCT staff filed testimony requesting a $4 million reduction AEP Texas’ Determination of System Restoration Costs. Settlement negotiations are ongoing.increases. If the ultimatethese costs 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.


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


Virginia Legislation Affecting Earnings 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 were frozen until after the Virginia SCC ruled on APCo’s next biennial review. TheseThe 2015 amendments also precluded the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017.


In March 2018, newNew Virginia legislation impacting investor-owned utilities was enacted, effective July 1, 2018, that: (a) on a one-time basis, required APCo to exclude $10 million of incurred fuel expenses from the July 2018 over/under recovery calculation, (b) reduced APCo’s base rates by $50 million annually effective July 30, 2018, on an interim basis and subject to true-up, to reflect the reduction in the federal income tax rate due to Tax Reform, (c) will requirethat requires APCo to file its next generation and distribution base rate case by March 31, 2020 using 2017, 2018 and 2019 earnings test years (“triennial review”), (d) will require an adjustment in APCo’s base rates on April 1, 2019 to reflect actual annual reductions in corporate income taxes due to Tax Reform, (e) will require APCo to seek approval from the Virginia SCC for energy efficiency programs with projected costs in the aggregate of at least $140 million over the 10-year period ending July 1, 2028 and (f) will require APCo to construct and/or acquire solar generation facilities in Virginia, as approved by the Virginia SCC, of at least 200 MW of aggregate capacity by July 1, 2028.(triennial review). Triennial reviews are subject to an earnings test which provides that 70% of any earnings exceeding 70 basis points over earningsthe Virginia SCC authorized return on common equity would be refunded to customers or may be reinvested in approved energy distribution grid transformation projects and/or new utility-owned solar and wind generation facilities.used to lower APCo’s Virginia retail base rates on a prospective basis. The Virginia SCC’slegislation 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.

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 2017-2019 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 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 October 2018,March 2019, the Virginia SCC issued an order approvingto reduce APCo’s requestbase rates to refund $55refund: (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 is not subject to rate normalization requirements to customers throughover three years and (d) a rider. The rider will be paid over twelve months effective November 1, 2018 and will offset APCo’s recent increase in interim fuel rates, subject to refund, that was filed with the Virginia SCC.

In October 2018, APCo submitted a filing with the Virginia SCC to resolve outstanding issues related to Tax Reform. The filing incorporated amounts already refunded to customers as disclosed in “Virginia Legislation Affecting Earnings Reviews” above and, if approved, will reduce APCo’s base rates by an additional $7one-time credit of $22 million annually. The combined reduction in APCo’s base rates due to Tax Reform will refund: (a) $39 million annually offor estimated excess federal income taxes collected since January 1, 2018 until new base rates are implemented, (b) $7 million annually of Excess ADIT associated with certain depreciable property using ARAM and (c) $11 million annually of Excess ADIT that is not subject to rate normalization requirements over 10 years. APCo anticipates a final order from customers during the Virginia SCC in the first quarter of 2019 and expects to implement additional customer rate credits in a tax-related rider starting in April15-month period ending March 31, 2019. The Virginia SCC’s review of APCo’s October 2018 Tax Reform filing could reduce future net income and cash flows and impact financial condition.


2018 West Virginia Base Rate Case


In May 2018, APCo and WPCo filed a joint request with the WVPSC to increase their combined West Virginia base rates by $115 million ($98 million related to APCo) annually based on a 10.22% return on common equity. The proposed annual increase includesincluded $32 million ($28 million related to APCo) due to increased annual depreciation ratesexpense and also reflectsreflected the impact 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$95 million ($ ($80 million related to APCo) annual increase in West Virginia base rates primarily due to the impact of West Virginia Tax Reform discussed below.Reform.


In October 2018,February 2019, the WVPSC issued an order approving a Stipulation and Settlement agreement between APCo, WPCo, WVPSC staff and intervenors filed testimony. WVPSC staff recommendedcertain intervenors. The agreement included an annual base rate increase of $44 million ($36 millionrelated to APCo) based upon a $2 million annual net revenue increase based on a 9.25%9.75% return on common equity while intervenors recommended a $14 million annual net revenue decrease based on an 8.75% return on common equity. The difference between APCo and WPCo’s requested annual base rate increase and the WVPSC staff and intervenors recommendations are primarily due to: (a) a reduction in the requested return on common equity, (b) the rejection of updates to the rate base calculation methodology, (c) the rejection of updates to rate base for certain known plant in service increases in 2018 and (d) a reduction in annual depreciation rates primarily related to continuing with a 2040 retirement date for Clinch River Plant rather than APCo’s proposed retirement date of 2025. A hearing at the WVPSC is scheduled for November 2018. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

West Virginia Tax Reform

In August 2018, the WVPSC approved a settlement agreement between APCo, WPCo and various intervenors that addresses the reduction in the federal income tax rate due to Tax Reform.effective March 2019. The agreement will provide refunds to customers, through a rider, of approximately $63also included: (a) $18 million ($51 million related to APCo) through June 2020. In addition, APCo and WPCo utilized $139 million ($12514 million related to APCo) of current tax savings andincreased 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 offset regulatory asset balances related to carbon capture, storm damage, ENEC and vegetation management. The remaining balancerate normalization requirements, (c) the utilization of $87$14 million ($7712 million related to APCo) of Excess ADIT that is not subject to rate normalization requirements will be addressed by theto offset regulatory asset balances relating to ENEC, (d) an agreement to seek WVPSC at a later date.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


AEP has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. Through September 30, 2018,2019, AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $849$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. 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 April 2018, the PUCT adopted a rule requiring investor-owned utilities operating solely inside ERCOT to make periodic filings for rate proceedings. The rule requires ETT to file for a comprehensive rate review no later than February 1, 2021.


In June 2018, the PUCT approved ETT’s application to reduce its transmission rates by $28 million annually, beginning June 21, 2018, to reflect the reduction in the federal income tax rate due to Tax Reform. The filing did not address the return of Excess ADIT benefits to customers.

In September 2018, ETT filed a request with the PUCT to refund $11 million of excess federal income taxes collected in 2018 prior to the reduction in transmission rates that were implemented on June 21, 2018.

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


2017 Indiana Base Rate Case

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

In February 2018, I&M filed a Stipulation and Settlement Agreement for a $97 million annual increase in Indiana rates effective July 1, 2018 subject to a temporary offsetting reduction to customer bills through December 2018 for a credit rider related to the timing of estimated in-service dates of certain capital expenditures.  The difference between I&M’s requested $263 million annual increase and the $97 million annual increase in the Stipulation and Settlement Agreement is primarily a result of: (a) the reduction in the federal income tax rate due toMichigan Tax Reform (b) the feedback of credits for Excess ADIT, (c) a 9.95% return on equity, (d) longer recovery periods of regulatory assets, (e) lower depreciation expense primarily for meters, (f) an increase in the sharing of off-system sales margins with customers from 50% to 95% and (g) a refund of $4 million from July 2018 through December 2018 for the impact of Tax Reform for the period January 2018 through June 2018.
In May 2018, the IURC issued an order approving the Stipulation and Settlement Agreement in its entirety.


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 included $23 million related to increased annual depreciation rates and a $4 million increase related to the amortization of certain Cook Plant regulatory assets. The increase in depreciation rates is primarily due to the proposed change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant related to the Life Cycle Management Project.

In February 2018, an MPSC ALJ issued a Proposal for Decision and recommended an annual revenue increase of $49 million, including an intervenor’s proposal for up to 10% of I&M’s Michigan retail customers to choose an alternate supplier for generation and a proposed capacity rate based on PJM’s net cost of new entry value of $289/MW-day, as well as the MPSC staff’s recommended calculation of depreciation expense for both units of Rockport Plant through 2028 and a return on common equity of 9.8%.  If the maximum 10% of customers choose an alternate supplier starting in February 2019, the estimated annual pretax loss due to the reduced capacity rate would be approximately $9 million. In October 2018, I&M filedmade a request with the MPSC seeking authority to defer costs related to customers choosing an alternate supplier starting in February 2019.

In April 2018, the MPSC issued an order that generally approved the ALJ proposal resulting in an annual revenue increase of $50 million, effective April 2018 based on a 9.9% return on common equity.  The MPSC also approved the ALJ’s recommendation related to the capacity rate.
In May 2018, I&M filed a Petition for Rehearing on the capacity rate issue. In June 2018, the MPSC denied I&M’s request.

Michigan Tax Reform

In August 2018, the MPSC approved I&M’s application to refund, through a rider, approximately $9 million annually for the impact of Tax Reform on I&M’s Michigan jurisdictional earnings effective September 1, 2018.  In October 2018, I&M also made two filingsfiling with the MPSC recommending to: (a) refund $3 million over eight months for the impact of Tax Reform on Michigan jurisdictional earnings for the period April 26, 2018 through August 31, 2018, (b) refund approximately $68 million of Excess ADIT associated with certain depreciable property using ARAM and (c)(b) refund approximately $37 million of Excess ADIT that is not subject to rate normalization requirements over 10ten 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 byin the endfourth quarter of 2019.

2019 Indiana Base Rate Case

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.  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 (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 related to the remaining book value of existing Indiana jurisdictional meters and $11 million associated with certain Cook Plant study costs.

In September 2019, I&M filed testimony rebutting the various parties’ recommendations. A hearing at the IURC began in October 2019. The IURC is expected to issue an order on the case by the first quarter of 2019.

Rockport Plant, Unit 2 SCR

In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2. 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 and is expected to be placed in service in May 2020. The estimated cost of the SCR project is $274 million, excluding AFUDC, to be shared equally between I&M and AEGCo.  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 recoveryIf any of these costs using the existing Clean Coal Technology Rider in aare not recoverable, it could reduce future filing subsequent to approval of the SCR project.net income and cash flows and impact financial condition.


2019 Michigan Base Rate Case

In March 2018,June 2019, I&M filed a request with the IURC issued an order approving: (a)MPSC for a $58 million annual increase. The requested increase in Michigan rates would be phased in through June 2020 and is based upon a proposed 10.5% return on common equity.  The proposed annual increase includes $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 increase also includes $10 million for annual lost revenue related to the CPCN, (b) the $274Michigan Electric Customer Choice Program that began in 2019.

In October 2019, MPSC staff and various intervenors filed testimony. The MPSC staff recommended a $38 million estimated costannual rate increase based upon a 9.75% return on common equity while intervenors recommended annual rate increases of the SCR, excluding AFUDC, (c) deferral of the Indiana jurisdictional ownership share of costs, including investment carrying costs, (d) depreciation of the SCR asset over 10 years and (e) recoveryup to $28 million based on a return on common equity ranging from 9.1% to 9.25%. If any of these costs using an I&M Indiana rider.are not recoverable, it could reduce future net income and cash flows and impact financial condition.


In April 2018, a group of intervenors filed a Petition for Reconsideration and Rehearing of the March 2018 IURC order.  In June 2018, the IURC denied the Petition for Reconsideration and Rehearing.



Management intends to request recovery of the Michigan jurisdictional share of the SCR project in a future base rate case. The AEGCo ownership share of the SCR project will be billable under the Rockport UPA to I&M and KPCo and will be subject to future regulatory approval for recovery.

KPCo Rate Matters (Applies to AEP)

2017 Kentucky Base Rate Case

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

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

In April 2018, KPCo and the intervenor filed a settlement agreement with the KPSC in which KPCo withdrew its requested increase related to the recovery of purchased power costs associated with forced outages and the intervenor withdrew its claim regarding the impact of the reduced corporate federal income tax rates on purchased power costs related to the Rockport UPA.

In June 2018, the KPSC issued an order approving the settlement agreement including KPCo’s requested additional revenue increase of $765 thousand related to the calculation of federal income tax expense. This rate increase was effective June 28, 2018.

Kentucky Tax Reform

In June 2018, the KPSC issued an order approving a settlement agreement between KPCo and an intervenor that stipulates that KPCo will refund an estimated $82 million of Excess ADIT associated with certain depreciable property using ARAM and an estimated $93 million of Excess ADIT that is not subject to rate normalization requirements over 18 years. The refund was effective July 1, 2018.

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 and 2016, the PUCO issued orders in this proceeding. As part of the issued orders, the PUCO approved: (a) the DIR with modified revenue caps, (b) recovery of OVEC-related net margin incurred beginning June 2016, (c)


potential additional contingent customer credits of up to $15 million to be included in the PPA rider over the final four years of the PPA rider and (d) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects.

In April 2017, the PUCO rejected all pending rehearing requests related to the OVEC PPA. 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 June 2018, oral arguments were held before the Supreme Court of Ohio.

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.


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

In April 2018, the PUCO issued an order approving the ESP extension stipulation agreement, with no significant changes. In May 2018, OPCo and various intervenors filed requests for rehearing with the PUCO. In June 2018, these requests for rehearing were approved to allow further consideration of the requests.In August 2018, the PUCO denied all requests for rehearing. In October 2018, an intervenor filed an appeal with the Ohio Supreme Court challenging various approved riders. In October 2019, oral arguments were held in the Ohio Supreme Court. If the Ohio Supreme Court reverses the 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 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 for2016. As a result of the comparable utilities risk group.

In January 2018, PUCO staff filed testimony thatorder, OPCo did not have significantly excessive earnings. Also in January 2018, an intervenor filed testimony recommending a $53reversed the $58 million refund to customers. In February 2018, OPCo and PUCO staff filed a stipulation agreement in which both parties agreed that OPCo did not have significantly excessive earnings in 2016.



A 2016 SEET hearing was held in April 2018 and management expects to receive an orderprovision in the first halfquarter of 2019. While management believes that OPCo’s adjusted 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s proposed SEET adjustments, including treatment of the Global Settlement issues described above, adjust the comparable risk group or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could negatively affect future SEET filings, reduce future net income and cash flows and impact financial condition.

Ohio Tax Reform

In October 2018, the PUCO issued an order approving a September 2018 settlement agreement between OPCo and various intervenors that addresses the reduction in the federal income tax rate due to Tax Reform. The settlement will: (a) refund excess federal income tax of $20 million annually, through a rider, effective January 1, 2018 until new base rates are implemented, (b) refund an estimated $278 million of Excess ADIT associated with depreciable property through OPCo’s DIR, (c) utilize $48 million of Excess ADIT that is not subject to rate normalization to offset regulatory asset balances related to OPCo’s distribution decoupling program and (d) refund the remaining estimated $129 million of Excess ADIT that is not subject to rate normalization by December 31, 2024 through a rider.

PSO Rate Matters (Applies to AEP and PSO)


2018 Oklahoma Base Rate Case


In October 2018, PSO filed a request with the OCC for an $88 million annual increase in Oklahoma retail rates based upon a 10.3% return on common equity. PSO also proposed to implement a performance basedperformance-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 annual increase includesincluded $13 million related to increased annual depreciation rates and $7 million related to increased storm expense amortization. The requested increase in annual depreciation rates includesincluded 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. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Oklahoma Tax Reform


In August 2018,March 2019, the OCC issued an order that approved PSO’s compliance filing that addressesapproving a Stipulation and Settlement agreement for a $46 million annual increase, based on a 9.4% return on equity effective with the reduction infirst billing cycle of April 2019. The order also included agreements between the federal income tax rate due to Tax Reform. As a result of the orderparties that: (a) depreciation rates will remain unchanged, (b) PSO will establishfile a rider to: (a) refund $3 million of excess federal income taxes collected from January 9, 2018 through February 28, 2018 by the end of 2018, (b) refund an estimated $353 million of Excess ADIT associated with certain depreciable property using ARAMnew base rate request no earlier than October 2020 and no later than October 2021 and (c) PSO will refund an estimated $72 million of Excess ADIT that is not subject to rate normalization requirements over 10 years.five years instead of the ten years ordered in the Oklahoma Tax Reform case. The order did not 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 to safety and reliability that are not 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.


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




In 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.Appeals, which was denied. In October 2018,January 2019, SWEPCo and the Court of Appeals denied SWEPCo’s request. SWEPCo intends to file an appealPUCT 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 fourth quarternet book value of 2018.

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 final order also included: (a) approval to recover the Texas jurisdictional share of environmental investments placed inin- service, as of June 30, 2016, at various plants, including Welsh Plant, Units 1 and 3, (b) approval of recovery of, but no return on, the Texas jurisdictional share of the net book value of Welsh Plant, Unit 2, (c) approval of $2 million in additional vegetation management expenses and (d) the rejection of SWEPCo’s proposed transmission cost recovery mechanism.


As a result of the final order, in 2017 SWEPCo: (a) recorded an impairment charge of $19 million, which included $7 million associated with the lack of return on Welsh Plant, Unit 2 and $12 million related to other disallowed plant investments, (b) recognized $32 million of additional revenues, for the period of May 2017 through December 2017,


that will bewas surcharged to customers in 2018and (c) recognized an additional $7 million of expenses consisting primarily of depreciation expense and vegetation management expense, offset by the deferral of rate case expense. SWEPCo implemented new rates in February 2018 billings. The $32 million of additional 2017 revenues will bewas collected by the end ofduring 2018. In March 2018, the PUCT clarified and corrected portions of the final order, without changing the overall decision or amounts of the rate change. The order has been appealed by various intervenors.

In April 2018, SWEPCo made an income tax rate refund tariff filing which includes an annual revenue reduction If certain parts of approximately $18 million to reflect the difference between rates collected under the final order and the rates that would be collected under Tax Reform. The filing did not address the return of Excess ADIT benefits to customers. In June 2018, the ALJ issued an order approving interim rates that provided for a reduction of residential rates of $8 million. In September 2018, the ALJ issued an order approving interim rates for the remaining customers. The matter has been sent to the PUCT for final approval.

Texas Tax Reform

In October 2018, SWEPCo filed a Stipulation and Settlement Agreement with the PUCT to refund $10 million of excess federal income taxes collected, as a result of Tax Reform, from January 1, 2018 through June 14, 2018 for residential customers and January 1, 2018 through September 19, 2018 for all other customer classes. An interim order was issued by an ALJ and the refunds will be made to customers through a rider in the fourth quarter of 2018.

2015 Louisiana Formula Rate Filing

In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC.  The filing included a $14 million annual increase, which was effective August 2015.  In February 2018, LPSC staff filed a report approving the increase as filed. This increase is subject to refund pending commission approval.  If any of these costs are not recoverable,overturned, 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. In October 2017, SWEPCo filed testimony in Louisiana supporting the prudence of its environmental control investment for Welsh Plant, Units 1 and 3 and Flint Creek power plants. These environmental costs are subject to prudence review by the LPSC. In May 2018, LPSC staff filed testimony that the environmental control investment for Welsh Plant, Units 1 and 3 and Flint Creek power plants is prudent. In August 2018, the LPSC issued an order affirming prudence and approved the settlement agreement for the environmental control investment. In October 2018, the LPSC staff filed a report approving the $31 million increase as filed. The net annual increase is subject to refund pending commission approval. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.


2018 Louisiana Formula Rate Filing


In April 2018, SWEPCo filed its formula rate plan for test year 2017 with the LPSC.  The filing included a net $28 million annual increase, which was effective August 2018 and includesincluded 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 primarily the result of the return of Excess ADIT benefits to customers.

In October 2018, the LPSC staff issued 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 expected in the fourth quarter of 2018.2019.


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 $550 million, excluding AFUDC. As of September 30, 2018,2019, SWEPCo had incurred costs of $399 million, including AFUDC, related to these projects.  Management continues to evaluate the impact of environmental rules and related project cost estimates. As of September 30, 2018,2019, the total net book value of Welsh Plant, Units 1 and 3 was $621$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 April 2017, the LPSC approved recovery of $131 million in investments related to its Louisiana jurisdictional share of environmental controls installed at Welsh Plant, effective May 2017.Plant. SWEPCo’s approved Louisiana jurisdictional share of Welsh Plant deferrals: (a) are $10 million, excluding $6$5 million of unrecognized equity as of September 30, 2018,2019, (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. See “2017“2018 Louisiana Formula Rate Filing” and “2018 Louisiana Formula“2019 Arkansas Base Rate Filing”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 Tax ReformBase Rate Case


In September 2018,February 2019, SWEPCo filed a request with the APSC issued an order that approved SWEPCo’s application to implementfor a rider for SWEPCo’s$75 million increase in Arkansas jurisdiction to address the reduction in the federal income tax rate due to Tax Reform. The rider was implemented in the first billing cycle of October 2018 and will: (a) refund $7 million over 15 months of excess federal income taxes collected from January 1, 2018 through September 30, 2018, (b) refund an ongoing estimated $655 thousand monthly from October 1, 2018 until new base rates go into effect asbased 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 a subsequent APSC order, (c) refund an estimated $66$58 million. The proposed net annual increase includes $12 million of Excess ADIT associated with certain depreciable property using ARAM and (d) refund an estimated $11 million of Excess ADIT that is not subject to rate normalization requirements over 15 months.

FERC Rate Matters

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

In June 2016, PJM transmission owners, including AEP’s transmission owning subsidiaries within PJM, and various state commissions filed a settlement agreement at the FERC to resolve outstanding issues related to cost responsibility for chargesvegetation management to transmission customers for certain transmission facilities that operate at or above 500 kV.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 July 2016, certain parties filed comments at the FERC contesting the settlement agreement. In May 2018, the FERC approved the contested settlement agreement. PJM implemented a transmission enhancement charge adjustment through the PJM OATT, which will be billable through 2025. Management expects that any refunds received would generally be returned to retail customers through existing state rider mechanisms and has recorded $134 million to Customer Accounts Receivable andOctober 2019, SWEPCo reduced its requested base rate increase from $75 million to Deferred Charges$67 million.

In October 2019,SWEPCo, the APSC staff and Other Noncurrent Assets,various intervenors filed a unanimous stipulation and settlement agreement with offsetsthe 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 Regulatory Liabilitieshave 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 Deferred Investment Tax Credits as of September 30, 2018.cash flows and impact financial condition.


FERC Rate Matters

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


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

In April 2018, certain intervenors filed comments atMay 2019, the FERC recommending a base ROE of 8.48% and a one-time refund of $184 million. The FERC trial staff filed comments recommending a base ROE of 8.41% and one-time refund of $175 million. Another intervenor recommended the refund be calculated in accordance with the base ROE that will ultimately be approved by the FERC. In May 2018, management filed reply comments providing further support for the 9.85% base ROE agreed to in the settlement agreement.

If the FERC orders revenue reductions in excess of the terms of the settlement agreement, it could reduce future net income and cash flows and impact financial condition.  A decision from the FERC is pending.



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

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


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


In June 2017, several parties filed a complaint at the FERC that states the base return on common equity used by AEP’s transmission owning subsidiaries within SPP in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36%, effective upon the date of the complaint through September 5, 2018. In November 2017, a FERC order set the matter for hearing and settlement procedures. The parties were unable to settle and the proceeding is currently in the hearing phase.

In September 2018, the same parties filed another complaint at the FERC that states the base return on common equity used by AEP’s transmission owning subsidiaries within SPP in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.71%, effective upon the date of the second complaint.

Management believes its financial statements adequately address the impact of these complaints. If In June 2019, the FERC orders revenue reductions asapproved an unopposed settlement agreement between AEP’s transmission owning subsidiaries within SPP and the complainants. The settlement agreement established a resultbase ROE of these complaints,10% (10.50% inclusive of the RTO incentive adder of 0.5%) effective January 1, 2019. Additionally, refunds including refundscarrying charges will be made from the date of the first complaint filings, 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 October 2017, AEP’s transmission owning subsidiaries within SPP filed an application at the FERC to modify the SPP OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to projected expenses.  The modified SPP OATT formula rates are based on projected calendar year financial activity and projected plant balances. In December 2017, theThe FERC accepted the proposed modifications effective January 1, 2018, subject to refund, and set this matter for hearing and settlement procedures. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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

refund. In September 2017, ETEC and NTECFebruary 2019, AEP’s transmission owning subsidiaries within SPP filed a complaint at the FERC that states the base return on common equity used by SWEPCo in calculating its power supply formula rates is excessive and should be reduced from 11.1% to 8.41%, effective upon the date of the complaint. In November 2017, a FERC order set the matter for hearing and settlement procedures.

In May 2018, SWEPCo filed aan uncontested settlement agreement with ETEC and NTEC at the FERC that resolves the issues of the complaint. If approved byresolving all outstanding issues. In June 2019, the FERC approved the settlement agreement: (a) reduces the base return on common equity from 11.1% to 10.1% effective September 1, 2017, (b) requires SWEPCo to provide a one-time billing credit of $287 thousand to reflect the decrease in return on common equity from September 1, 2017 through December 31, 2017 and (c) implements the lower return on common equity on contracts starting January 1, 2018. In July 2018, the FERC issued an order approving 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 the 20172018 Annual Report should be read in conjunction with this report.


GUARANTEES


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


Letters of Credit (Applies to AEP, 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, 2018,2019, no letters of credit were issued under the $3 billion revolving credit facility. In October 2018, the revolving credit facility was increased to $4 billion and extended until June 2022.


An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility.  AEP issues letters of credit on behalf of subsidiaries under foursix uncommitted facilities totaling $305$405 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of September 30, 20182019 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 $71.8
 October 2018 to September 2019
AEP Texas 2.8
 January 2019
OPCo 0.6
 September 2019

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



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


As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $140$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 $79$107 million.  Actual reclamation costs could vary due to period inflation and anyscope changes to actualthe mine reclamation.  As of September 30, 2018,2019, SWEPCo has collected $74$77 million through a rider


for final mine closure and reclamation costs, of which $79$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, 2018,2019, 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, 2018,2019, there were no material liabilities recorded for any indemnifications.


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

Master Lease Agreements (Applies to all Registrants except AEPTCo)

The Registrants lease certain equipment under master lease agreements.  Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term.  If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee.  Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.  As of September 30, 2018, 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 $47.7
AEP Texas 11.4
APCo 8.8
I&M 3.5
OPCo 7.6
PSO 4.1
SWEPCo 4.2


Railcar Lease (Applies to AEP, I&M and SWEPCo)

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 have exercised all renewal options for the maximum lease term.  The future minimum lease obligations were $7 million and $7 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2018.

Under the remaining five-year 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 is equal to 77% of the projected fair value of the equipment.  I&M and SWEPCo have assumed the guarantee under the return-and-sale option.  The maximum potential losses related to the guarantee were $5 million and $5 million for I&M and SWEPCo, respectively, as of September 30, 2018, 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, 2018, the maximum potential amount of future payments required under the guaranteed leases was $46 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, 2018, AEP’s boat and barge lease guarantee liability was $6 million, of which $1 million was recorded in Other Current Liabilities and $5 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. also downgraded their ratings and set their outlook to negative. 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.


ENVIRONMENTAL CONTINGENCIES (Applies to all Registrants except AEPTCo)


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


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




NUCLEAR CONTINGENCIES (Applies to AEP and I&M)


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

Westinghouse Electric Company Bankruptcy Filing

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

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 would be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering, refueling or retirement of the unit. The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio.


AEGCo and I&M sought and were granted dismissal by the U.S. District Court for the Southern District of Ohio of certain of the plaintiffs’ claims, including claims for compensatory damages, breach of contract, breach of the implied covenant of good faith and fair dealing and indemnification of costs. The court permitted plaintiffs to move forward with their claimPlaintiffs voluntarily dismissed the surviving claims that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. Plaintiffs voluntarily dismissed the surviving claims with prejudice, and the court issued a final judgment. The plaintiffs subsequently filed an appeal in the U.S. Court of Appeals for the Sixth Circuit on whether the trial court erred in dismissing plaintiffs’ claims for breach of contract and breach of the implied 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 in part. In June 2017, on rehearing, the court of appeals issued an amended opinion reversing the district court’s dismissal of certain of plaintiffs’ claims for breach of contract, vacating the denial of the plaintiffs’ motion for partial summary judgment and remanding the case to the district court for further proceedings.  The amended opinion and judgment affirmedaffirming 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 removed the instruction toreversing the district court in the original opinion to enter summary judgment in favorcourt’s dismissal of the owners.breach of contract claims and remanding the case for further proceedings.


In July 2017,Thereafter, AEP filed a motion with the U.S. District Court for the Southern District of Ohio in the original NSR litigation, seeking to modify the consent decree to eliminate the obligation to install certain future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that Unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. Responsive and supplemental filings have been made by all parties. In November 2017, theThe district court granted the owners’ unopposed motion to stay the lease litigation to afford time for resolution of AEP’s motion to modify the consent decree. In September 2018,The consent decree was modified based on an agreement among the district court granted AEP’s unopposed motionparties in July 2019. As part of the modification to stay further proceedings regarding the consent decree, I&M agreed to facilitate settlement discussions amongprovide an additional $7.5 million to citizens’ groups and the parties tostates for environmental mitigation projects. As joint owners in the consent decree.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.


Gavin Landfill Litigation (Applies to AEP and OPCo)Patent Infringement Complaint


In August 2014, a complaint was filed inJuly 2019, Midwest Energy Emissions Corporation and MES Inc. (collectively, 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 became the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors.  Twelve of the family members pursued personal injury/illness claims (non-working direct claims) and the remainder pursued loss of consortium claims.  The plaintiffs sought compensatory and punitive damages, as well as medical monitoring.  In September 2014, defendantsplaintiffs) filed a motion to dismisspatent infringement complaint against various parties, including AEP Texas, AGR, Cardinal Operating Company and SWEPCo (collectively, the AEP Defendants). The complaint contendingalleges that the case should be filed in Ohio. In August 2015, the court denied the motion.AEP Defendants appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issuedinfringed two patents owned by the court denyingplaintiffs 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 appeal and remanding the caseclaims. Management is unable to the West Virginia Mass Litigation Panel (WVMLP), rather than back to the Mason County, West Virginia Circuit Court. Defendants subsequently fileddetermine 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. In June 2017, the West Virginia Supreme Court reversed the WVMLP decision and dismissed the claimsrange of the twelve non-working direct claim plaintiffs. A settlement was reached with allpotential loss that is reasonably possible of the plaintiffs and was approved by the WVMLP in June 2018. The settlement did not have a material impact on net income, cash flows or financial condition.occurring.




6. DISPOSITIONSACQUISITIONS AND IMPAIRMENTS

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

Zimmer PlantSempra Renewables LLC (Generation & Marketing Segment)

In February 2017,April 2019, AEP signed an agreementacquired 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 sellgrow its 25.4%renewable generation portfolio and to diversify generation resources. AEP paid $583 million in cash and acquired a 50% ownership shareinterest in five non-consolidated joint ventures with net assets valued at $406 million as of Zimmer Plantthe 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 acquired and noncontrolling interests assumed. The fair value of the primary assets acquired and the noncontrolling interests assumed was determined using a nonaffiliated party.discounted cash flow method under the income approach. The transaction closedkey input assumptions utilized in the second quarterdetermination of 2017the fair value of these assets were the pricing and did not have a material impact onterms 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 fair value of the 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 financial condition.holds interests in, wind generation facilities in the United States. The Income before Income Tax Expenseoperating wind generation portfolio includes seven wind farms. Five wind farms are jointly-owned with BP Wind Energy, and Equity Earningstwo 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 Zimmer Plant was immaterialtheir energy production. One of the joint venture wind farms has PPAs with I&M and OPCo for a portion of its energy production which totaled $2 million and $3 million, respectively, of purchased electricity for the three 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 its energy production which totaled $3 million and $6 million of purchased electricity for the three and nine months ended September 30, 2017.2019, respectively. The PPAs with I&M, OPCo and 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.”

Gavin, Waterford, DarbyParent 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.



The acquired business contributed revenues and Lawrenceburg PlantsNet 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 September 2016,July 2019, AEP signedacquired a Purchase75% 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 Sale Agreementin accordance with the accounting guidance for “Consolidation,” management concluded that Santa Rita East is a VIE. As a result, to sell AGR’s Gavin, Waterford and Darby Plants as well as AEGCo’s Lawrenceburg Plant totaling 5,329 MWsaccount for the initial consolidation of competitive generation assets to a nonaffiliated party. The sale closed in January 2017 for $2.2 billion, which was recorded in Investing ActivitiesSanta Rita East, management applied the acquisition method by allocating the purchase price based on the statementrelative fair value of cash flows.the assets acquired and noncontrolling interest assumed.  The net proceeds fromfair value of the primary assets acquired and the noncontrolling interest assumed was determined using the market approach.  The key input assumptions were the transaction were $1.2 billionprice paid for AEP’s interest in cash after taxes, repaymentSanta Rita East and recent third-party market transactions for similar wind farms. See “Santa Rita East” section 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.Note 14 for additional information.

IMPAIRMENTS


Other Assets (Corporate and Other) (Vertically Integrated Utilities Segment) (Applies to AEP and APCo)
 
In 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 statementstatements 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. In December 2017, and in accordance withAs of September 30, 2018, the accounting guidance for impairments of long-lived assets, an impairment analysis was triggered by the expected costs of the damRacine reconstruction activities, resulting in the conclusion that the fair value of Racine, in its present condition, was $0 as of December 31, 2017. A pretax impairment charge equal to Racine’s net book value of $43 million was recognized in AEP’s 2017 statement of income.
Construction activities at Racine continued throughout 2018, accumulatingproject had accumulated new capital expenditures of $35 million as of September 30, 2018. However, duemillion. Due to a significant increase in estimated costs to complete the reconstruction project, in the third quarter of 2018, an impairment analysis was performed. AEP performed step one of the impairment analysis using undiscounted cash flows for the estimated useful life of Racine based upon energy and capacity price curves, which were developed internally with observable Level 2 third partythird-party quotations and unobservable Level 3 inputs, as well as management’s forecasts of operating expenses and capital expenditures. AEP performed step two of the impairment 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 present condition was $0 as of September 30, 2018.2018 was $0. As a result, AEP recorded a pretax impairment of $35 million in Other Operation on the statementstatements of income in the third quarter of 2018. In October 2018, AEP received authorization from the FERC to restart generation at Racine.  Management plansRacine and generation resumed in November 2018.

Due to resume generation at Racine during the fourth quarter of 2018.
Inweather-related delays in the first quarter of 2017,2019, reconstruction activities at Racine are now estimated to be completed in the first half of 2020. AEP recorded a pretax impairmentexpects to incur additional capital expenditures to complete the reconstruction project, at which point the fair value of $4 millionRacine, as fully operational, is expected to approximate the book value once complete. Future revisions in Other Operation on the statement ofcost estimates or delays in completion could result in additional losses which could reduce future net income related to the Merchant Coal-fired Generation Assets. In addition, AEP recorded a $7 million pretax impairment in Other Operation on the statement of income related to the sale of Zimmer Plant.and cash flows and impact financial condition.





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 OPEBPension Plans OPEB
Three Months Ended September 30, Three Months Ended September 30,Three Months Ended September 30, Three Months Ended September 30,
2018 2017 2018 20172019 2018 2019 2018
(in millions)(in millions)
Service Cost$24.4
 $24.1
 $2.9
 $2.8
$23.8
 $24.4
 $2.4
 $2.9
Interest Cost46.9
 50.7
 11.8
 14.8
51.1
 46.9
 12.6
 11.8
Expected Return on Plan Assets(72.6) (71.1) (25.6) (25.3)(74.0) (72.6) (23.4) (25.6)
Amortization of Prior Service Cost (Credit)—
 0.3
 (17.3) (17.3)
Amortization of Prior Service Credit—
 —
 (17.3) (17.3)
Amortization of Net Actuarial Loss21.3
 20.7
 2.7
 9.2
14.4
 21.3
 5.5
 2.7
Net Periodic Benefit Cost (Credit)$20.0
 $24.7
 $(25.5) $(15.8)$15.3
 $20.0
 $(20.2) $(25.5)
Pension Plans OPEBPension Plans OPEB
Nine Months Ended September 30, Nine Months Ended September 30,Nine Months Ended September 30, Nine Months Ended September 30,
2018 2017 2018 20172019 2018 2019 2018
(in millions)(in millions)
Service Cost$73.2
 $72.3
 $8.7
 $8.4
$71.6
 $73.2
 $7.1
 $8.7
Interest Cost140.8
 152.3
 35.5
 44.5
153.3
 140.8
 37.9
 35.5
Expected Return on Plan Assets(217.7) (213.5) (76.7) (76.0)(222.0) (217.7) (70.3) (76.7)
Amortization of Prior Service Cost (Credit)—
 0.8
 (51.8) (51.8)
Amortization of Prior Service Credit—
 —
 (51.8) (51.8)
Amortization of Net Actuarial Loss63.9
 62.1
 7.9
 27.5
43.2
 63.9
 16.6
 7.9
Net Periodic Benefit Cost (Credit)$60.2
 $74.0
 $(76.4) $(47.4)$46.1
 $60.2
 $(60.5) $(76.4)






AEP Texas
Pension Plans OPEBPension Plans OPEB
Three Months Ended September 30, Three Months Ended September 30,Three Months Ended September 30, Three Months Ended September 30,
2018 2017 2018 20172019 2018 2019 2018
(in millions)(in millions)
Service Cost$2.3
 $2.1
 $0.3
 $0.3
$2.2
 $2.3
 $0.1
 $0.3
Interest Cost4.0
 4.3
 0.9
 1.2
4.4
 4.0
 1.0
 0.9
Expected Return on Plan Assets(6.4) (6.2) (2.1) (2.2)(6.5) (6.4) (1.9) (2.1)
Amortization of Prior Service Credit—
 —
 (1.5) (1.5)—
 —
 (1.5) (1.5)
Amortization of Net Actuarial Loss1.8
 1.7
 0.2
 0.8
1.2
 1.8
 0.5
 0.2
Net Periodic Benefit Cost (Credit)$1.7
 $1.9
 $(2.2) $(1.4)$1.3
 $1.7
 $(1.8) $(2.2)
Pension Plans OPEBPension Plans OPEB
Nine Months Ended September 30, Nine Months Ended September 30,Nine Months Ended September 30, Nine Months Ended September 30,
2018 2017 2018 20172019 2018 2019 2018
(in millions)(in millions)
Service Cost$6.9
 $6.4
 $0.7
 $0.7
$6.5
 $6.9
 $0.5
 $0.7
Interest Cost12.0
 12.9
 2.8
 3.7
13.1
 12.0
 3.0
 2.8
Expected Return on Plan Assets(19.2) (18.8) (6.4) (6.6)(19.4) (19.2) (5.8) (6.4)
Amortization of Prior Service Credit—
 —
 (4.4) (4.4)—
 —
 (4.4) (4.4)
Amortization of Net Actuarial Loss5.4
 5.2
 0.6
 2.4
3.7
 5.4
 1.4
 0.6
Net Periodic Benefit Cost (Credit)$5.1
 $5.7
 $(6.7) $(4.2)$3.9
 $5.1
 $(5.3) $(6.7)


APCo
Pension Plans OPEBPension Plans OPEB
Three Months Ended September 30, Three Months Ended September 30,Three Months Ended September 30, Three Months Ended September 30,
2018
2017 2018 20172019
2018 2019 2018
(in millions)(in millions)
Service Cost$2.4
 $2.3
 $0.3
 $0.3
$2.4
 $2.4
 $0.2
 $0.3
Interest Cost5.8
 6.5
 2.1
 2.6
6.3
 5.8
 2.2
 2.1
Expected Return on Plan Assets(9.1) (8.9) (4.0) (4.1)(9.4) (9.1) (3.7) (4.0)
Amortization of Prior Service Credit—
 —
 (2.5) (2.5)—
 —
 (2.5) (2.5)
Amortization of Net Actuarial Loss2.6
 2.6
 0.4
 1.6
1.8
 2.6
 1.0
 0.4
Net Periodic Benefit Cost (Credit)$1.7
 $2.5
 $(3.7) $(2.1)$1.1
 $1.7
 $(2.8) $(3.7)
Pension Plans OPEBPension Plans OPEB
Nine Months Ended September 30, Nine Months Ended September 30,Nine Months Ended September 30, Nine Months Ended September 30,
2018 2017 2018 20172019 2018 2019 2018
(in millions)(in millions)
Service Cost$7.0
 $7.0
 $0.8
 $0.8
$7.1
 $7.0
 $0.7
 $0.8
Interest Cost17.6
 19.3
 6.2
 7.9
18.9
 17.6
 6.5
 6.2
Expected Return on Plan Assets(27.4) (26.8) (12.0) (12.3)(28.1) (27.4) (11.0) (12.0)
Amortization of Prior Service Cost (Credit)—
 0.1
 (7.5) (7.5)
Amortization of Prior Service Credit—
 —
 (7.5) (7.5)
Amortization of Net Actuarial Loss7.9
 7.8
 1.4
 4.7
5.3
 7.9
 2.8
 1.4
Net Periodic Benefit Cost (Credit)$5.1
 $7.4
 $(11.1) $(6.4)$3.2
 $5.1
 $(8.5) $(11.1)




I&M
Pension Plans OPEBPension Plans OPEB
Three Months Ended September 30, Three Months Ended September 30,Three Months Ended September 30, Three Months Ended September 30,
2018 2017 2018 20172019 2018 2019 2018
(in millions)(in millions)
Service Cost$3.4
 $3.5
 $0.4
 $0.4
$3.3
 $3.4
 $0.3
 $0.4
Interest Cost5.6
 6.1
 1.4
 1.7
6.0
 5.6
 1.5
 1.4
Expected Return on Plan Assets(9.0) (8.6) (3.1) (3.1)(9.1) (9.0) (2.8) (3.1)
Amortization of Prior Service Credit—
 —
 (2.4) (2.3)—
 —
 (2.4) (2.4)
Amortization of Net Actuarial Loss2.5
 2.4
 0.3
 1.1
1.6
 2.5
 0.7
 0.3
Net Periodic Benefit Cost (Credit)$2.5
 $3.4
 $(3.4) $(2.2)$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 OPEB
 Nine Months Ended September 30, Nine Months Ended September 30,
 2018 2017 2018 2017
 (in millions)
Service Cost$10.2
 $10.5
 $1.2
 $1.2
Interest Cost16.6
 18.2
 4.1
 5.2
Expected Return on Plan Assets(26.8) (25.9) (9.3) (9.2)
Amortization of Prior Service Cost (Credit)—
 0.1
 (7.1) (7.0)
Amortization of Net Actuarial Loss7.4
 7.3
 0.9
 3.3
Net Periodic Benefit Cost (Credit)$7.4
 $10.2
 $(10.2) $(6.5)


OPCo
Pension Plans OPEBPension Plans OPEB
Three Months Ended September 30, Three Months Ended September 30,Three Months Ended September 30, Three Months Ended September 30,
2018 2017 2018 20172019 2018 2019 2018
(in millions)(in millions)
Service Cost$2.0
 $1.8
 $0.2
 $0.3
$1.9
 $2.0
 $0.2
 $0.2
Interest Cost4.4
 4.8
 1.3
 1.6
4.8
 4.4
 1.4
 1.3
Expected Return on Plan Assets(7.2) (6.9) (2.9) (3.0)(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
 2.0
 0.3
 1.1
1.3
 2.0
 0.6
 0.3
Net Periodic Benefit Cost (Credit)$1.2
 $1.7
 $(2.8) $(1.7)$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 OPEB
 Nine Months Ended September 30, Nine Months Ended September 30,
 2018 2017 2018 2017
 (in millions)
Service Cost$5.8
 $5.6
 $0.7
 $0.7
Interest Cost13.3
 14.5
 3.9
 5.0
Expected Return on Plan Assets(21.6) (20.9) (8.8) (9.0)
Amortization of Prior Service Cost (Credit)—
 0.1
 (5.2) (5.2)
Amortization of Net Actuarial Loss6.0
 5.9
 0.8
 3.3
Net Periodic Benefit Cost (Credit)$3.5
 $5.2
 $(8.6) $(5.2)





PSO
Pension Plans OPEBPension Plans OPEB
Three Months Ended September 30, Three Months Ended September 30,Three Months Ended September 30, Three Months Ended September 30,
2018 2017 2018 20172019 2018 2019 2018
(in millions)(in millions)
Service Cost$1.7
 $1.7
 $0.1
 $0.2
$1.6
 $1.7
 $0.2
 $0.1
Interest Cost2.5
 2.6
 0.6
 0.8
2.6
 2.5
 0.7
 0.6
Expected Return on Plan Assets(4.0) (3.9) (1.3) (1.4)(4.0) (4.0) (1.3) (1.3)
Amortization of Prior Service Credit—
 —
 (1.1) (1.1)—
 —
 (1.1) (1.1)
Amortization of Net Actuarial Loss1.1
 1.1
 0.1
 0.5
0.7
 1.1
 0.3
 0.1
Net Periodic Benefit Cost (Credit)$1.3
 $1.5
 $(1.6) $(1.0)$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 OPEB
 Nine Months Ended September 30, Nine Months Ended September 30,
 2018 2017 2018 2017
 (in millions)
Service Cost$5.3
 $4.9
 $0.5
 $0.5
Interest Cost7.4
 8.0
 1.8
 2.4
Expected Return on Plan Assets(12.1) (11.8) (4.1) (4.2)
Amortization of Prior Service Credit—
 —
 (3.2) (3.2)
Amortization of Net Actuarial Loss3.3
 3.3
 0.4
 1.5
Net Periodic Benefit Cost (Credit)$3.9
 $4.4
 $(4.6) $(3.0)


SWEPCo
Pension Plans OPEBPension Plans OPEB
Three Months Ended September 30, Three Months Ended September 30,Three Months Ended September 30, Three Months Ended September 30,
2018 2017 2018 20172019 2018 2019 2018
(in millions)(in millions)
Service Cost$2.4
 $2.1
 $0.2
 $0.2
$2.1
 $2.4
 $0.2
 $0.2
Interest Cost2.8
 3.1
 0.7
 0.9
3.1
 2.8
 0.7
 0.7
Expected Return on Plan Assets(4.4) (4.2) (1.6) (1.5)(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
 1.3
 0.2
 0.5
0.9
 1.3
 0.4
 0.2
Net Periodic Benefit Cost (Credit)$2.1
 $2.3
 $(1.8) $(1.2)$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 OPEB
 Nine Months Ended September 30, Nine Months Ended September 30,
 2018 2017 2018 2017
 (in millions)
Service Cost$7.0
 $6.5
 $0.7
 $0.6
Interest Cost8.5
 9.2
 2.1
 2.7
Expected Return on Plan Assets(13.1) (12.6) (4.8) (4.7)
Amortization of Prior Service Credit—
 —
 (3.9) (3.9)
Amortization of Net Actuarial Loss3.8
 3.7
 0.5
 1.7
Net Periodic Benefit Cost (Credit)$6.2
 $6.8
 $(5.4) $(3.6)



8.  BUSINESS SEGMENTS


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


AEP’s Reportable Segments


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


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


Vertically Integrated Utilities


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


Transmission and Distribution Utilities


Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo.
OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load.


AEP Transmission Holdco


Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved returns on equity.ROEs.
Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity.ROEs.


Generation & Marketing


Competitive generation in ERCOT 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, 20182019 and 20172018 and reportable segment balance sheet information as of September 30, 20182019 and December 31, 2017.2018.
 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
 Three 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$2,610.2
 $1,180.9
 $51.9
 $486.5
 $3.6
 $—
 $4,333.1
Other Operating Segments26.5
 30.6
 135.3
 35.1
 20.1
 (247.6) —
Total Revenues$2,636.7
 $1,211.5
 $187.2
 $521.6
 $23.7
 $(247.6) $4,333.1
              
Net Income (Loss)$345.6
 $145.2
 $74.2
 $5.1
 $9.6
 $—
 $579.7
Three Months Ended September 30, 2017Nine Months Ended September 30, 2019
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$2,453.8
 $1,149.7
 $45.1
 $441.5
 $14.6
 $—
 $4,104.7
$7,087.6
 $3,328.7
 $196.5
 $1,323.8
 $8.8
 $—
 $11,945.4
Other Operating Segments28.4
 23.6
 133.4
 24.0
 16.7
 (226.1) —
85.0
 125.6
 611.8
 104.4
 64.9
 (991.7) —
Total Revenues$2,482.2
 $1,173.3
 $178.5
 $465.5
 $31.3
 $(226.1) $4,104.7
$7,172.6
 $3,454.3
 $808.3
 $1,428.2
 $73.7
 $(991.7) $11,945.4
                          
Net Income (Loss)$297.3
 $144.0
 $76.5
 $33.7
 $5.2
 $—
 $556.7
$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
 Nine Months Ended September 30, 2017
 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing		 Corporate and Other (a) Reconciling Adjustments Consolidated
 (in millions)
Revenues from: 
  
  
�� 
  
    
External Customers$6,819.3
 $3,242.7
 $125.8
 $1,386.8
 $39.9
 $—
 $11,614.5
Other Operating Segments73.8
 70.5
 456.1
 80.7
 46.8
 (727.9) —
Total Revenues$6,893.1
 $3,313.2
 $581.9
 $1,467.5
 $86.7
 $(727.9) $11,614.5
              
Net Income (Loss)$639.2
 $374.3
 $278.3
 $246.3
 $(11.0) $—
 $1,527.1





 September 30, 2018 September 30, 2019
 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing		 Corporate and Other (a) Reconciling
Adjustments		 Consolidated Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing		 Corporate and Other (a) Reconciling
Adjustments		 Consolidated
 (in millions) (in millions)
Total Property, Plant and Equipment $44,553.4
 $17,619.1
 $8,130.3
 $864.1
 $384.8
 $(354.4)(b)$71,197.3
 $46,739.8
 $19,283.9
 $9,700.4
 $1,661.6
 $421.7
 $(354.5)(b)$77,452.9
Accumulated Depreciation and Amortization 13,703.3
 3,856.7
 244.3
 40.1
 183.6
 (186.4)(b)17,841.6
 14,359.3
 3,907.3
 383.8
 99.8
 196.4
 (186.4)(b)18,760.2
Total Property Plant and Equipment - Net $30,850.1
 $13,762.4
 $7,886.0
 $824.0
 $201.2
 $(168.0)(b)$53,355.7
 $32,380.5
 $15,376.6
 $9,316.6
 $1,561.8
 $225.3
 $(168.1)(b)$58,692.7
                            
Total Assets $38,813.2
 $16,399.1
 $9,127.7
 $2,369.3
 $4,306.1
(c)$(3,398.0)(b) (d)$67,617.4
 $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 $1,306.1
 $548.5
 $50.0
 $0.1
 $(0.5) $—
 $1,904.2
 $687.4
 $391.5
 $249.0
 $—
 $(0.2)(e)$—
 $1,327.7
                            
Long-term Debt:                            
Affiliated 50.0
 —
 —
 32.2
 —
 (82.2) —
 59.0
 —
 —
 32.2
 —
 (91.2) —
Nonaffiliated 11,563.5
 5,082.2
 2,966.2
 (0.3) 1,258.2
 —
 20,869.8
 12,161.1
 5,868.9
 3,426.9
 (0.3) 3,096.9
 —
 24,553.5
                            
Total Long-term Debt $12,919.6
 $5,630.7
 $3,016.2
 $32.0
 $1,257.7
 $(82.2) $22,774.0
 $12,907.5
 $6,260.4
 $3,675.9
 $31.9
 $3,096.7
(e)$(91.2) $25,881.2
 December 31, 2017 December 31, 2018
 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing		 Corporate and Other (a) Reconciling
Adjustments		 Consolidated Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing		 Corporate and Other (a) Reconciling
Adjustments		 Consolidated
 (in millions) (in millions)
Total Property, Plant and Equipment $43,294.4
 $16,371.2
 $7,110.2
 $644.6
 $374.5
 $(366.4)(b)$67,428.5
 $45,365.1
 $18,126.7
 $8,659.5
 $893.3
 $395.2
 $(354.6)(b)$73,085.2
Accumulated Depreciation and Amortization 13,153.4
 3,768.3
 176.6
 75.0
 180.6
 (186.9)(b)17,167.0
 13,822.5
 3,833.7
 282.8
 47.0
 186.6
 (186.5)(b)17,986.1
Total Property Plant and Equipment - Net $30,141.0
 $12,602.9
 $6,933.6
 $569.6
 $193.9
 $(179.5)(b)$50,261.5
 $31,542.6
 $14,293.0
 $8,376.7
 $846.3
 $208.6
 $(168.1)(b)$55,099.1
                            
Total Assets $37,579.7
 $16,060.7
 $8,141.8
 $2,009.8
 $3,959.1
(c)$(3,022.0)(b) (d)$64,729.1
 $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 $1,038.1
 $663.1
 $50.0
 $—
 $2.5
 $—
 $1,753.7
 $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) —
 50.0
 —
 —
 32.2
 —
 (82.2) —
Nonaffiliated 10,801.4
 4,705.4
 2,631.3
 (0.3) 1,281.8
 —
 19,419.6
 11,442.7
 5,048.8
 2,888.6
 (0.3) 2,268.4
 —
 21,648.2
                            
Total Long-term Debt $11,889.5
 $5,368.5
 $2,681.3
 $31.9
 $1,284.3
 $(82.2) $21,173.3
 $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. 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 elimination of intercompany advances to affiliates and intercompany accounts receivable.
(e)Amounts reflect the impact of fair value hedge accounting. See “Accounting for Fair Value Hedging Strategies” section of Note 10 for additional information.


Registrant Subsidiaries’ Reportable Segments (Applies to all Registrant Subsidiaries except AEPTCo)


The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an integrated electricity transmission and distribution business for AEP Texas and OPCo.  Other activities are insignificant.  The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.





AEPTCo’s Reportable Segments


AEPTCo Parent is the holding company of seven FERC-regulated transmission-only electric utilities (State Transcos).utilities. The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting.” The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the RTOs in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and provide service to AEP’s wholesale and retail customers. The State Transcos are regulated for rate-making purposes exclusively by the FERC and earn revenues through tariff rates charged for the use of their electric transmission systems.


AEPTCo’s Chief Operating Decision Maker makes operating decisions, allocates resources to and assesses performance based on these operating segments. The seven State Transcos operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one operating segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities.


The tables below present AEPTCo’s reportable segment income statement information for the three and nine months ended September 30, 20182019 and 20172018 and reportable segment balance sheet information as of September 30, 20182019 and December 31, 2017.2018.
Three Months Ended September 30, 2018Three 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$46.0
 $—
 $—
 $46.0
$54.0
 $—
 $—
 $54.0
Sales to AEP Affiliates148.4
 —
 —
 148.4
205.7
 —
 —
 205.7
Other Revenues—
 —
 —
 —
—
 —
 —
 —
Total Revenues$194.4
 $—
 $—
 $194.4
$259.7
 $—
 $—
 $259.7
              
Interest Income$0.2
 $26.0
 $(25.7)(b)$0.5
$0.4
 $32.3
 $(31.9)(a)$0.8
Interest Expense19.8
 25.7
 (25.7)(b)19.8
26.4
 31.9
 (31.9)(a)26.4
Income Tax Expense18.4
 (0.8) —
 17.6
30.0
 0.1
 —
 30.1
              
Net Income$77.1
 $1.0
(c)$—
 $78.1
$107.3
 $0.3
(b)$—
 $107.6
Three Months Ended September 30, 2017Three Months Ended September 30, 2018
State Transcos (a) AEPTCo Parent Reconciling Adjustments 
AEPTCo
Consolidated (a)
State Transcos AEPTCo Parent Reconciling Adjustments 
AEPTCo
Consolidated
(in millions)(in millions)
Revenues from:              
External Customers$35.6
 $—
 $—
 $35.6
$46.0
 $—
 $—
 $46.0
Sales to AEP Affiliates130.1
 —
 —
 130.1
148.4
 —
 —
 148.4
Other Revenues(0.1) —
 —
 (0.1)—
 —
 —
 —
Total Revenues$165.6
 $—
 $—
 $165.6
$194.4
 $—
 $—
 $194.4
              
Interest Income$—
 $19.5
 $(19.3)(b)$0.2
$0.2
 $26.0
 $(25.7)(a)$0.5
Interest Expense17.1
 19.3
 (19.3)(b)17.1
19.8
 25.7
 (25.7)(a)19.8
Income Tax Expense29.5
 —
 —
 29.5
18.4
 (0.8) —
 17.6
              
Net Income$58.5
 $0.1
(c)$—
 $58.6
$77.1
 $1.0
(b)$—
 $78.1



Nine Months Ended September 30, 2018Nine Months Ended September 30, 2019
State Transcos (a) AEPTCo Parent Reconciling Adjustments 
AEPTCo
Consolidated (a)
State Transcos AEPTCo Parent Reconciling Adjustments 
AEPTCo
Consolidated
(in millions)(in millions)
Revenues from:              
External Customers$132.3
 $—
 $—
 $132.3
$162.1
 $—
 $—
 $162.1
Sales to AEP Affiliates453.8
 —
 —
 453.8
608.0
 —
 —
 608.0
Other Revenues0.1
 $—
 $—
 0.1
—
 —
 —
 —
Total Revenues$586.2
 $—
 $—
 $586.2
$770.1
 $—
 $—
 $770.1
              
Interest Income$0.4
 $76.2
 $(75.3)(b)$1.3
$0.8
 $89.7
 $(88.4)(a)$2.1
Interest Expense60.7
 75.3
 (75.3)(b)60.7
69.5
 88.4
 (88.4)(a)69.5
Income Tax Expense63.7
 —
 —
 63.7
90.5
 0.2
 —
 90.7
              
Net Income$243.6
 $0.6
(c)$—
 $244.2
$347.1
 $0.8
(b)$—
 $347.9
Nine Months Ended September 30, 2017Nine Months Ended September 30, 2018
State Transcos (a) AEPTCo Parent Reconciling Adjustments 
AEPTCo
Consolidated (a)
State Transcos AEPTCo Parent Reconciling Adjustments 
AEPTCo
Consolidated
(in millions)(in millions)
Revenues from:              
External Customers$95.7
 $—
 $—
 $95.7
$132.3
 $—
 $—
 $132.3
Sales to AEP Affiliates439.1
 —
 —
 439.1
453.8
 —
 —
 453.8
Other Revenues—
 —
 —
 —
0.1
 —
 —
 0.1
Total Revenues$534.8
 $—
 $—
 $534.8
$586.2
 $—
 $—
 $586.2
              
Interest Income$0.1
 $58.0
 $(57.6)(b)$0.5
$0.4
 $76.2
 $(75.3)(a)$1.3
Interest Expense50.4
 57.6
 (57.6)(b)50.4
60.7
 75.3
 (75.3)(a)60.7
Income Tax Expense108.0
 0.2
 —
 108.2
63.7
 —
 —
 63.7
              
Net Income$212.1
 $0.3
(c)$—
 $212.4
$243.6
 $0.6
(b)$—
 $244.2
 September 30, 2018
 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated		 
 (in millions) 
Total Transmission Property$7,761.6
(a)$—
 $—
 $7,761.6
(a)
Accumulated Depreciation and Amortization234.6
(a)—
 —
 234.6
(a)
Total Transmission Property – Net$7,527.0
(a)$—
 $—
 $7,527.0
(a)
         
Notes Receivable - Affiliated$—
 $2,900.0
 $(2,900.0)(d)$—
 
         
Total Assets$7,983.6
(a)$2,988.4
(e)$(2,973.6)(f)$7,998.4
(a)
         
Total Long-term Debt$2,900.0
 $2,872.6
 $(2,900.0)(d)$2,872.6
 
 December 31, 2017 
 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated		 
 (in millions) 
Total Transmission Property$6,770.5
(a)$—
 $—
 $6,770.5
(a)
Accumulated Depreciation and Amortization152.6
(a)—
 —
 152.6
(a)
Total Transmission Property – Net$6,617.9
(a)$—
 $—
 $6,617.9
(a)
         
Notes Receivable - Affiliated$—
 $2,550.4
 $(2,550.4)(d)$—
 
         
Total Assets$7,086.9
(a)$2,590.1
(e)$(2,594.9)(f)$7,082.1
(a)
         
Total Long-term Debt$2,575.0
 $2,550.4
 $(2,575.0)(d)$2,550.4
 

 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)The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. For additional details on revisions made to AEPTCo’s financial statements, see Note 1- Significant Accounting Matters.
(b)Elimination of intercompany interest income/interest expense on affiliated debt arrangement.
(c)(b)Includes the elimination of AEPTCo Parent’s equity earnings in the State Transcos.
(d)(c)Elimination of intercompany debt.
(e)(d)Includes the elimination of AEPTCo Parent’s investments in State Transcos.
(f)(e)Primarily relates to the elimination of Notes Receivable from the State Transcos.







9.  DERIVATIVES AND HEDGING


The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any derivative and hedging activity.


The Registrants adopted ASU 2017-12 in the second quarter of 2018, effective January 1, 2018. See Note 2 - New Accounting Pronouncements for additional information.

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries.


The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets.  These risks include commodity price risks which may be subject to capacity risk, interest rate risk credit risk and foreign currency exchangecredit risk.  These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates.  Management utilizes derivative instruments to manage these risks.


STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES


Risk Management Strategies


The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.


The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors.





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


Notional Volume of Derivative Instruments
September 30, 20182019
Primary Risk
Exposure
 
Unit of
Measure
 AEP AEP Texas 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 415.7
 —
 88.7
 52.8
 8.0
 19.0
 13.0
 MWhs 424.3
 —
 94.7
 37.1
 7.3
 21.6
 6.9
Coal Tons 0.2
 —
 —
 0.2
 —
 —
 —
Natural Gas MMBtus 84.4
 —
 8.4
 4.9
 —
 —
 16.1
 MMBtus 53.2
 —
 —
 —
 —
 —
 12.5
Heating Oil and Gasoline Gallons 8.3
 1.7
 1.6
 0.8
 2.0
 0.8
 0.9
 Gallons 8.4
 1.8
 1.6
 0.8
 2.0
 0.8
 0.9
Interest Rate USD $37.7
 $—
 $—
 $—
 $—
 $—
 $—
 USD $140.1
 $—
 $—
 $—
 $—
 $—
 $—
                            
Interest Rate USD $500.0
 $—
 $—
 $—
 $—
 $—
 $—
 USD $600.0
 $—
 $—
 $—
 $—
 $—
 $—


Notional Volume of Derivative Instruments
December 31, 20172018
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 AEP Texas APCo I&M OPCo PSO SWEPCo
    (in millions)
Commodity:          
  
  
  
Power MWhs 358.7
 —
 57.4
 38.5
 10.4
 10.3
 22.7
Coal Tons 2.0
 —
 —
 2.0
 —
 —
 —
Natural Gas MMBtus 53.7
 —
 1.1
 0.7
 —
 —
 18.3
Heating Oil and Gasoline Gallons 6.9
 1.4
 1.3
 0.7
 1.6
 0.7
 0.8
Interest Rate USD $50.7
 $—
 $—
 $—
 $—
 $—
 $—
                 
Interest Rate 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. AEP netted cash collateral received from third partiesthird-parties against short-term and long-term
risk management assets in the amounts of $15$0 million and $9.4$18 million as of September 30, 20182019 and December 31, 2017,2018, respectively. AEP netted cash collateral paid to third partiesthird-parties against short-term and long-term risk management liabilities in the amounts of $1$21 million and $9$4 million as of September 30, 20182019 and December 31, 2017,2018, respectively. The netted cash collateral from third partiesthird-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 of September 30, 20182019 and December 31, 2017.2018.



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, 20182019
 
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 $359.9
 $29.1
 $—
 $389.0
 $(197.1) $191.9
 $337.0
 $16.5
 $1.9
 $355.4
 $(168.7) $186.7
Long-term Risk Management Assets 295.3
 10.6
 —
 305.9
 (41.0) 264.9
 319.0
 10.0
 25.3
 354.3
 (55.3) 299.0
Total Assets 655.2
 39.7
 —
 694.9
 (238.1) 456.8
 656.0
 26.5
 27.2
 709.7
 (224.0) 485.7
                        
Current Risk Management Liabilities 232.4
 7.5
 0.5
 240.4
 (183.1) 57.3
 213.4
 36.4
 0.2
 250.0
 (174.7) 75.3
Long-term Risk Management Liabilities 240.0
 55.4
 33.7
 329.1
 (41.9) 287.2
 281.7
 87.4
 —
 369.1
 (70.5) 298.6
Total Liabilities 472.4
 62.9
 34.2
 569.5
 (225.0) 344.5
 495.1
 123.8
 0.2
 619.1
 (245.2) 373.9
                        
Total MTM Derivative Contract Net Assets (Liabilities) $182.8
 $(23.2) $(34.2) $125.4
 $(13.1) $112.3
 $160.9
 $(97.3) $27.0
 $90.6
 $21.2
 $111.8


Fair Value of Derivative Instruments
December 31, 20172018
 
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 $389.0
 $17.5
 $2.5
 $409.0
 $(282.8) $126.2
 $397.5
 $28.5
 $—
 $426.0
 $(263.2) $162.8
Long-term Risk Management Assets 300.9
 6.3
 —
 307.2
 (25.1) 282.1
 276.4
 16.0
 —
 292.4
 (38.4) 254.0
Total Assets 689.9
 23.8
 2.5
 716.2
 (307.9) 408.3
 673.9
 44.5
 —
 718.4
 (301.6) 416.8
                        
Current Risk Management Liabilities 334.6
 9.0
 —
 343.6
 (282.0) 61.6
 293.8
 13.2
 2.0
 309.0
 (254.0) 55.0
Long-term Risk Management Liabilities 280.6
 58.3
 8.6
 347.5
 (25.5) 322.0
 225.7
 56.1
 15.4
 297.2
 (33.8) 263.4
Total Liabilities 615.2
 67.3
 8.6
 691.1
 (307.5) 383.6
 519.5
 69.3
 17.4
 606.2
 (287.8) 318.4
                        
Total MTM Derivative Contract Net Assets (Liabilities) $74.7
 $(43.5) $(6.1) $25.1
 $(0.4) $24.7
 $154.4
 $(24.8) $(17.4) $112.2
 $(13.8) $98.4







AEP Texas
Fair Value of Derivative Instruments
September 30, 20182019
 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
 Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Commodity (a) Financial Position (b) Financial Position (c)
 (in millions) (in millions)
Current Risk Management Assets $0.5
 $—
 $0.5
 $—
 $—
 $—
Long-term Risk Management Assets —
 —
 —
 —
 —
 —
Total Assets 0.5
 —
 0.5
 —
 —
 —
            
Current Risk Management Liabilities —
 —
 —
 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 Assets $0.5
 $—
 $0.5
Total MTM Derivative Contract Net Liabilities $(0.4) $—
 $(0.4)

Fair Value of Derivative Instruments
December 31, 20172018
 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
 Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Commodity (a) Financial Position (b) Financial Position (c)
 (in millions) (in millions)
Current Risk Management Assets $0.5
 $—
 $0.5
 $—
 $—
 $—
Long-term Risk Management Assets —
 —
 —
 —
 —
 —
Total Assets 0.5
 —
 0.5
 —
 —
 —
            
Current Risk Management Liabilities —
 —
 —
 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 $0.5
 $—
 $0.5
Total MTM Derivative Contract Net Assets (Liabilities) $(0.7) $0.5
 $(0.2)


APCo
Fair Value of Derivative Instruments
September 30, 20182019
 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
 Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Commodity (a) Financial Position (b) Financial Position (c)
 (in millions) (in millions)
Current Risk Management Assets $106.6
 $(38.2) $68.4
 $86.3
 $(29.8) $56.5
Long-term Risk Management Assets 6.0
 (4.6) 1.4
 4.1
 (3.9) 0.2
Total Assets 112.6
 (42.8) 69.8
 90.4
 (33.7) 56.7
            
Current Risk Management Liabilities 39.1
 (38.2) 0.9
 32.3
 (31.2) 1.1
Long-term Risk Management Liabilities 5.5
 (4.8) 0.7
 4.4
 (4.1) 0.3
Total Liabilities 44.6
 (43.0) 1.6
 36.7
 (35.3) 1.4
            
Total MTM Derivative Contract Net Assets $68.0
 $0.2
 $68.2
 $53.7
 $1.6
 $55.3

Fair Value of Derivative Instruments
December 31, 20172018
  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
Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c)
  (in millions)
Current Risk Management Assets $75.6
 $(50.7) $24.9
Long-term Risk Management Assets 2.4
 (1.3) 1.1
Total Assets 78.0
 (52.0) 26.0
       
Current Risk Management Liabilities 50.6
 (49.3) 1.3
Long-term Risk Management Liabilities 1.4
 (1.2) 0.2
Total Liabilities 52.0
 (50.5) 1.5
       
Total MTM Derivative Contract Net Assets (Liabilities) $26.0
 $(1.5) $24.5




I&M
Fair Value of Derivative Instruments
September 30, 20182019
 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
 Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Commodity (a) Financial Position (b) Financial Position (c)
 (in millions) (in millions)
Current Risk Management Assets $39.4
 $(28.5) $10.9
 $30.5
 $(20.0) $10.5
Long-term Risk Management Assets 3.7
 (2.8) 0.9
 2.7
 (2.6) 0.1
Total Assets 43.1
 (31.3) 11.8
 33.2
 (22.6) 10.6
            
Current Risk Management Liabilities 35.2
 (28.8) 6.4
 21.0
 (20.8) 0.2
Long-term Risk Management Liabilities 3.2
 (2.8) 0.4
 2.7
 (2.7) —
Total Liabilities 38.4
 (31.6) 6.8
 23.7
 (23.5) 0.2
            
Total MTM Derivative Contract Net Assets $4.7
 $0.3
 $5.0
 $9.5
 $0.9
 $10.4

Fair Value of Derivative Instruments
December 31, 20172018
 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
 Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Commodity (a) Financial Position (b) Financial Position (c)
 (in millions) (in millions)
Current Risk Management Assets $47.2
 $(39.6) $7.6
 $50.4
 $(41.8) $8.6
Long-term Risk Management Assets 1.6
 (0.9) 0.7
 2.0
 (1.4) 0.6
Total Assets 48.8
 (40.5) 8.3
 52.4
 (43.2) 9.2
            
Current Risk Management Liabilities 48.5
 (45.0) 3.5
 41.1
 (40.8) 0.3
Long-term Risk Management Liabilities 0.9
 (0.8) 0.1
 1.6
 (1.5) 0.1
Total Liabilities 49.4
 (45.8) 3.6
 42.7
 (42.3) 0.4
            
Total MTM Derivative Contract Net Assets (Liabilities) $(0.6) $5.3
 $4.7
 $9.7
 $(0.9) $8.8


OPCo
Fair Value of Derivative Instruments
September 30, 20182019
 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
 Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Commodity (a) Financial Position (b) Financial Position (c)
 (in millions) (in millions)
Current Risk Management Assets $0.6
 $—
 $0.6
 $—
 $—
 $—
Long-term Risk Management Assets 0.1
 —
 0.1
 —
 —
 —
Total Assets 0.7
 —
 0.7
 —
 —
 —
            
Current Risk Management Liabilities 5.4
 —
 5.4
 7.2
 —
 7.2
Long-term Risk Management Liabilities 89.8
 —
 89.8
 105.7
 —
 105.7
Total Liabilities 95.2
 —
 95.2
 112.9
 —
 112.9
            
Total MTM Derivative Contract Net Liabilities $(94.5) $—
 $(94.5) $(112.9) $—
 $(112.9)

Fair Value of Derivative Instruments
December 31, 20172018
  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)
Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c)
  (in millions)
Current Risk Management Assets $0.6
 $—
 $0.6
Long-term Risk Management Assets —
 —
 —
Total Assets 0.6
 —
 0.6
       
Current Risk Management Liabilities 6.4
 —
 6.4
Long-term Risk Management Liabilities 126.0
 —
 126.0
Total Liabilities 132.4
 —
 132.4
       
Total MTM Derivative Contract Net Liabilities $(131.8) $—
 $(131.8)




PSO
Fair Value of Derivative Instruments
September 30, 20182019
 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
 Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Commodity (a) Financial Position (b) Financial Position (c)
 (in millions) (in millions)
Current Risk Management Assets $18.8
 $(0.3) $18.5
 $21.9
 $(0.2) $21.7
Long-term Risk Management Assets —
 —
 —
 —
 —
 —
Total Assets 18.8
 (0.3) 18.5
 21.9
 (0.2) 21.7
            
Current Risk Management Liabilities 0.9
 (0.3) 0.6
 0.5
 (0.2) 0.3
Long-term Risk Management Liabilities —
 —
 —
 —
 —
 —
Total Liabilities 0.9
 (0.3) 0.6
 0.5
 (0.2) 0.3
            
Total MTM Derivative Contract Net Assets $17.9
 $—
 $17.9
 $21.4
 $—
 $21.4

Fair Value of Derivative Instruments
December 31, 20172018
 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
 Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Commodity (a) Financial Position (b) Financial Position (c)
 (in millions) (in millions)
Current Risk Management Assets $6.6
 $(0.2) $6.4
 $10.9
 $(0.5) $10.4
Long-term Risk Management Assets —
 —
 —
 —
 —
 —
Total Assets 6.6
 (0.2) 6.4
 10.9
 (0.5) 10.4
            
Current Risk Management Liabilities 0.2
 (0.2) —
 1.7
 (0.7) 1.0
Long-term Risk Management Liabilities —
 —
 —
 —
 —
 —
Total Liabilities 0.2
 (0.2) —
 1.7
 (0.7) 1.0
            
Total MTM Derivative Contract Net Assets $6.4
 $—
 $6.4
 $9.2
 $0.2
 $9.4


SWEPCo
Fair Value of Derivative Instruments
September 30, 20182019
 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
 Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Commodity (a) Financial Position (b) Financial Position (c)
 (in millions) (in millions)
Current Risk Management Assets $8.1
 $(1.6) $6.5
 $9.8
 $(0.4) $9.4
Long-term Risk Management Assets —
 —
 —
 —
 —
 —
Total Assets 8.1
 (1.6) 6.5
 9.8
 (0.4) 9.4
            
Current Risk Management Liabilities 1.8
 (1.6) 0.2
 2.1
 (0.4) 1.7
Long-term Risk Management Liabilities 2.6
 —
 2.6
 3.0
 —
 3.0
Total Liabilities 4.4
 (1.6) 2.8
 5.1
 (0.4) 4.7
            
Total MTM Derivative Contract Net Assets $3.7
 $—
 $3.7
 $4.7
 $—
 $4.7

Fair Value of Derivative Instruments
December 31, 20172018
 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
 Contracts – in the Statement of Presented in the Statement of
Balance Sheet Location Risk Management Contracts – Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Commodity (a) Financial Position (b) Financial Position (c)
 (in millions) (in millions)
Current Risk Management Assets $7.0
 $(0.6) $6.4
 $5.6
 $(0.8) $4.8
Long-term Risk Management Assets —
 —
 —
 —
 —
 —
Total Assets 7.0
 (0.6) 6.4
 5.6
 (0.8) 4.8
            
Current Risk Management Liabilities 0.8
 (0.6) 0.2
 1.5
 (1.1) 0.4
Long-term Risk Management Liabilities —
 —
 —
 2.2
 —
 2.2
Total Liabilities 0.8
 (0.6) 0.2
 3.7
 (1.1) 2.6
            
Total MTM Derivative Contract Net Assets $6.2
 $—
 $6.2
 $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)All derivative contracts subject to a master netting arrangement or similar agreement are 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, 20182019
Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo AEP AEP Texas APCo I&M OPCo PSO SWEPCo
 (in millions) (in millions)
Vertically Integrated Utilities Revenues $(0.7) $—
 $—
 $—
 $—
 $—
 $—
 $0.5
 $—
 $—
 $—
 $—
 $—
 $—
Generation & Marketing Revenues 19.3
 —
 —
 —
 —
 —
 —
 21.0
 —
 —
 —
 —
 —
 —
Electric Generation, Transmission and Distribution Revenues —
 —
 (0.5) (0.1) —
 —
 —
 —
 —
 0.2
 0.2
 —
 —
��—
Purchased Electricity for Resale 0.3
 —
 0.3
 —
 —
 —
 —
 0.4
 —
 0.3
 —
 —
 —
 —
Other Operation 0.5
 0.1
 0.1
 0.1
 0.1
 0.1
 0.1
 (0.1) —
 (0.1) (0.1) (0.1) (0.1) —
Maintenance 0.6
 0.1
 0.1
 0.1
 0.1
 0.1
 0.1
 (0.2) —
 —
 (0.1) —
 —
 —
Regulatory Assets (a) (14.0) —
 —
 (3.5) (9.3) (0.6) (0.6) (4.8) (0.2) 0.2
 —
 (2.6) (0.1) (1.6)
Regulatory Liabilities (a) 33.8
 —
 24.0
 —
 —
 3.9
 1.5
 26.3
 —
 10.0
 3.2
 —
 4.3
 4.5
Total Gain (Loss) on Risk Management Contracts $39.8
 $0.2
 $24.0
 $(3.4) $(9.1) $3.5
 $1.1
 $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, 20172018
Location of Gain (Loss) AEP AEP Texas 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
 $—
 $—
 $—
 $—
 $—
 $—
 $(0.7) $—
 $—
 $—
 $—
 $—
 $—
Generation & Marketing Revenues 17.7
 —
 —
 —
 —
 —
 —
 19.3
 —
 —
 —
 —
 —
 —
Electric Generation, Transmission and Distribution Revenues —
 —
 0.3
 0.6
 —
 —
 (0.1) —
 —
 (0.5) (0.1) —
 —
 —
Purchased Electricity for Resale 1.0
 —
 0.3
 0.2
 —
 —
 —
 0.3
 —
 0.3
 —
 —
 —
 —
Other Operation 0.1
 0.1
 —
 —
 0.1
 —
 —
 0.5
 0.1
 0.1
 0.1
 0.1
 0.1
 0.1
Maintenance 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) (8.8) 0.1
 0.1
 (0.8) (8.7) —
 0.3
 (14.0) —
 —
 (3.5) (9.3) (0.6) (0.6)
Regulatory Liabilities (a) 15.6
 0.1
 3.7
 2.1
 —
 2.6
 7.0
 33.8
 —
 24.0
 —
 —
 3.9
 1.5
Total Gain (Loss) on Risk Management Contracts $26.6
 $0.4
 $4.5
 $2.1
 $(8.5) $2.6
 $7.2
 $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, 20182019
Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo AEP AEP Texas APCo I&M OPCo PSO SWEPCo
 (in millions) (in millions)
Vertically Integrated Utilities Revenues $(9.4) $—
 $—
 $—
 $—
 $—
 $—
 $1.0
 $—
 $—
 $—
 $—
 $—
 $—
Generation & Marketing Revenues 31.7
 —
 —
 —
 —
 —
 —
 27.2
 —
 —
 —
 —
 —
 —
Electric Generation, Transmission and Distribution Revenues —
 —
 (1.3) (7.8) —
 —
 0.1
 —
 —
 0.2
 0.5
 —
 —
 0.1
Purchased Electricity for Resale 8.3
 —
 7.3
 0.8
 —
 —
 —
 1.6
 —
 1.4
 0.1
 —
 —
 —
Other Operation 1.3
 0.3
 0.2
 0.2
 0.3
 0.2
 0.2
 (0.6) (0.1) (0.1) (0.1) (0.2) (0.1) (0.1)
Maintenance 1.5
 0.3
 0.3
 0.2
 0.3
 0.2
 0.2
 (0.6) (0.1) (0.1) (0.1) (0.1) —
 (0.1)
Regulatory Assets (a) 29.2
 —
 —
 (0.3) 31.8
 (0.6) (1.7) (19.4) 0.3
 0.4
 0.2
 (19.8) 0.9
 (0.4)
Regulatory Liabilities (a) 206.2
 —
 127.3
 11.7
 0.6
 34.8
 7.6
 64.5
 —
 (5.3) 17.2
 —
 26.6
 22.9
Total Gain on Risk Management Contracts $268.8
 $0.6
 $133.8
 $4.8
 $33.0
 $34.6
 $6.4
Total Gain (Loss) on Risk Management Contracts $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, 20172018
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 AEP Texas APCo I&M OPCo PSO SWEPCo
  (in millions)
Vertically Integrated Utilities Revenues $7.0
 $—
 $—
 $—
 $—
 $—
 $—
Generation & Marketing Revenues 38.5
 —
 —
 —
 —
 —
 —
Electric Generation, Transmission and Distribution Revenues —
 —
 0.6
 6.3
 —
 —
 —
Purchased Electricity for Resale 4.9
 —
 1.6
 0.5
 —
 —
 —
Other Operation 0.5
 0.1
 —
 —
 0.1
 —
 —
Maintenance 0.4
 0.1
 0.1
 —
 0.1
 —
 —
Regulatory Assets (a) (26.8) —
 —
 (1.0) (25.9) —
 0.1
Regulatory Liabilities (a) 81.8
 (0.2) 28.2
 15.3
 —
 13.7
 22.0
Total Gain (Loss) on Risk Management Contracts $106.3
 $—
 $30.5
 $21.1
 $(25.7) $13.7
 $22.1


(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 impacts recognized on the balance sheets related to the hedged items in fair value hedging relationships:
  
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, 2018 December 31, 2017 September 30, 2018 December 31, 2017
  (in millions)
Long-Term Debt (a) $(461.4) $(489.3) $34.2
 $6.1
  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.


The pretax effects of fair value hedge 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

 Three Months Ended September 30, Nine Months Ended September 30,
 2018 2017 2018 2017
 (in millions)
Gain (Loss) on Interest Rate Contracts:       
Gain (Loss) on Fair Value Hedging Instruments (a)$(6.3) $0.1
 $(28.1) $(0.1)
Gain (Loss) on Fair Value Portion of Long-term Debt (a)6.3
 (0.1) 28.1
 0.1


(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 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.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, 20182019 and 2017,2018, AEP applied cash flow hedging to outstanding power derivatives. During the three and nine months ended September 30, 20182019 and 2017,2018, 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, 2018 and 2017,2019 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, 2017, the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. During the three2018 AEP and nine months ended September 30, 2018 SWEPCo applied cash flow hedging to outstanding interest rate 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, 2018 and 2017, the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives.


For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 - Comprehensive Income.


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, 2018 December 31, 2017
  Commodity Interest Rate Commodity Interest Rate
  (in millions)
AOCI Loss Net of Tax $(22.8) $(12.7) $(28.4) $(13.0)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months 14.4
 (0.8) 5.5
 (0.8)

(a)Includes $6 million related to AEP's investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC. See “Sempra Renewables LLC” section of Note 14 for additional information.


As of September 30, 20182019 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 183 months.123 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, 2018 December 31, 2017
  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 $(4.6) $(1.1) $(4.5) $(0.9)
APCo 2.0
 0.9
 2.2
 0.7
I&M (11.9) (1.6) (10.7) (1.3)
OPCo 1.3
 1.3
 1.9
 1.1
PSO 2.4
 1.0
 2.6
 0.8
SWEPCo (3.7) (1.5) (6.0) (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 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.  The 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, 20182019 and December 31, 2017,2018, respectively.


Cross-Default Triggers (Applies to AEP, APCo, I&M and SWEPCo)


In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third partythird-party obligation that is $50 million or greater.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following 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, 2018 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 $253.1
 $0.8
 $211.2
 $261.0
 $3.4
 $230.7
APCo 0.1
 —
 0.1
 3.9
 —
 0.2
I&M —
 —
 —
 2.3
 —
 0.1
SWEPCo 2.8
 —
 2.8
 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, 2017
  Liabilities for   Additional
  Contracts with Cross   Settlement
  Default Provisions   Liability if Cross
  Prior to Contractual Amount of Cash Default Provision
Company Netting Arrangements Collateral Posted is Triggered
  (in millions)
AEP $243.6
 $1.3
 $223.1
APCo 0.6
 —
 0.5
I&M 0.4
 —
 0.4
SWEPCo 0.2
 —
 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 benefit plan and nuclear trusts.  AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value.  AEP’s management performs its own valuation testing to verify the fair values of the securities.  AEP receives audit reports of the trustee’s operating controls and valuation processes.  The trustee uses multiple pricing vendors for the assets held in the trusts.


Assets in the nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.



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, 2018 December 31, 2017
Company Book Value Fair Value Book Value Fair Value
  (in millions)
AEP $22,774.0
 $23,869.1
 $21,173.3
 $23,649.6
AEP Texas 3,914.4
 4,019.2
 3,649.3
 3,964.8
AEPTCo 2,872.6
 2,861.1
 2,550.4
 2,782.9
APCo 4,061.7
 4,629.8
 3,980.1
 4,782.6
I&M 3,062.4
 3,161.9
 2,745.1
 3,014.7
OPCo 1,716.3
 1,941.9
 1,719.3
 2,064.3
PSO 1,286.9
 1,373.4
 1,286.5
 1,457.1
SWEPCo 3,072.7
 3,068.4
 2,441.9
 2,645.9

(a)The fair value amount includes debt related to AEP’s Equity Units issued in March 2019 and has a fair value of $887 million as of September 30, 2019. See “Equity Units” section of Note 13 for additional information.


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


Other Temporary Investments include marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS.


The following is a summary of Other Temporary Investments:
 September 30, 2018 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 and Other Cash Deposits (a) $170.4
 $—
 $—
 $170.4
 $160.1
 $—
 $—
 $160.1
Fixed Income Securities – Mutual Funds (b) 105.9
 —
 (2.8) 103.1
 133.4
 —
 (0.2) 133.2
Equity Securities – Mutual Funds
 17.6
 22.2
 —
 39.8
 28.5
 17.6
 —
 46.1
Total Other Temporary Investments $293.9
 $22.2
 $(2.8) $313.3
 $322.0
 $17.6
 $(0.2) $339.4
 December 31, 2017 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 and Other Cash Deposits (a) $220.1
 $—
 $—
 $220.1
 $230.6
 $—
 $—
 $230.6
Fixed Income Securities – Mutual Funds (b)
 104.3
 —
 (1.4) 102.9
 106.6
 —
 (2.3) 104.3
Equity Securities – Mutual Funds
 17.0
 19.7
 —
 36.7
 17.8
 16.4
 —
 34.2
Total Other Temporary Investments $341.4
 $19.7
 $(1.4) $359.7
 $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,
 2018 2017 2018 2017
 (in millions)
Proceeds from Investment Sales$—
 $—
 $—
 $—
Purchases of Investments0.8
 12.6
 2.2
 13.6
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, 2017,2018, see Note 3 - Comprehensive Income.


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


Nuclear decommissioning and spent nuclear fuelSNF trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and SNF 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. UponWith the adoption of ASU 2016-01, in first quarter 2018, equity securities are now recorded with changes in fair value recognized in earnings. Effectiveeffective January 2018, available for saleavailable-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 debt securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains, unrealized losses and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI.





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, 2018 December 31, 2017
   Gross Other-Than-   Gross Other-Than-
 Fair Unrealized Temporary Fair Unrealized Temporary
 Value Gains Impairments Value Gains Impairments
 (in millions)
Cash and Cash Equivalents$41.6
 $—
 $—
 $17.2
 $—
 $—
Fixed Income Securities: 
  
  
  
  
  
United States Government951.9
 12.2
 (6.2) 981.2
 29.7
 (3.6)
Corporate Debt54.4
 1.1
 (1.6) 58.7
 3.8
 (1.2)
State and Local Government8.5
 0.5
 (0.2) 8.8
 0.8
 (0.2)
Subtotal Fixed Income Securities1,014.8
 13.8
 (8.0) 1,048.7
 34.3
 (5.0)
Equity Securities - Domestic (a)1,609.6
 990.5
 —
 1,461.7
 868.2
 (75.5)
Spent Nuclear Fuel and Decommissioning Trusts$2,666.0
 $1,004.3
 $(8.0) $2,527.6
 $902.5
 $(80.5)


(a)Amount reported as Gross Unrealized Gains includes unrealized gains of $995.8$1 billion and $784 million and unrealized losses of $5.3 million.$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,
  2018 2017 2018 2017
  (in millions)
Proceeds from Investment Sales $513.1
 $519.5
 $1,550.9
 $1,808.6
Purchases of Investments 521.2
 525.0
 1,589.0
 1,842.2
Gross Realized Gains on Investment Sales 3.9
 9.8
 27.7
 198.1
Gross Realized Losses on Investment Sales 3.5
 5.2
 22.2
 145.4


The base cost of fixed income securities was $1 billion and $1 billion as of September 30, 20182019 and December 31, 2017,2018, respectively.  The base cost of equity securities was $619$657 million and $594$629 million as of September 30, 20182019 and December 31, 2017,2018, respectively.


The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 20182019 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$348.7
After 1 year through 5 years331.4
After 5 years through 10 years177.0
After 10 years157.7
Total$1,014.8




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, 20182019
 Level 1 Level 2 Level 3 Other Total Level 1 Level 2 Level 3 Other Total
Assets: (in millions) (in millions)
                    
Other Temporary Investments                    
Restricted Cash and Other Cash Deposits (a) $160.8
 $—
 $—
 $9.6
 $170.4
 $152.9
 $—
 $—
 $7.2
 $160.1
Fixed Income Securities – Mutual Funds
 103.1
 —
 —
 —
 103.1
 133.2
 —
 —
 —
 133.2
Equity Securities – Mutual Funds (b)
 39.8
 —
 —
 —
 39.8
 46.1
 —
 —
 —
 46.1
Total Other Temporary Investments
 303.7
 —
 —
 9.6
 313.3
 332.2
 —
 —
 7.2
 339.4
                    
Risk Management Assets  
  
  
  
  
          
Risk Management Commodity Contracts (c) (d) 1.7
 270.9
 361.7
 (213.2) 421.1
 5.6
 228.2
 407.7
 (195.3) 446.2
Cash Flow Hedges:  
  
  
  
  
          
Commodity Hedges (c) —
 20.9
 11.7
 3.1
 35.7
 —
 17.6
 2.9
 (8.2) 12.3
Interest Rate Hedges —
 1.9
 —
 —
 1.9
Fair Value Hedges —
 25.3
 —
 —
 25.3
Total Risk Management Assets 1.7
 291.8
 373.4
 (210.1) 456.8
 5.6
 273.0
 410.6
 (203.5) 485.7
                    
Spent Nuclear Fuel and Decommissioning Trusts  
  
  
  
  
          
Cash and Cash Equivalents (e) 27.2
 —
 —
 14.4
 41.6
 9.4
 —
 —
 8.0
 17.4
Fixed Income Securities:  
  
  
  
  
          
United States Government —
 951.9
 —
 —
 951.9
 —
 1,047.4
 —
 —
 1,047.4
Corporate Debt —
 54.4
 —
 —
 54.4
 —
 68.6
 —
 —
 68.6
State and Local Government —
 8.5
 —
 —
 8.5
 —
 7.5
 —
 —
 7.5
Subtotal Fixed Income Securities —
 1,014.8
 —
 —
 1,014.8
 —
 1,123.5
 —
 —
 1,123.5
Equity Securities – Domestic (b)
 1,609.6
 —
 —
 —
 1,609.6
 1,694.3
 —
 —
 —
 1,694.3
Total Spent Nuclear Fuel and Decommissioning Trusts
 1,636.8
 1,014.8
 —
 14.4
 2,666.0
 1,703.7
 1,123.5
 —
 8.0
 2,835.2
                    
Total Assets $1,942.2
 $1,306.6
 $373.4
 $(186.1) $3,436.1
 $2,041.5
 $1,396.5
 $410.6
 $(188.3) $3,660.3
                    
Liabilities:  
  
  
  
  
          
                    
Risk Management Liabilities  
  
  
  
  
          
Risk Management Commodity Contracts (c) (d) $1.9
 $271.4
 $178.2
 $(200.1) $251.4
 $5.1
 $243.9
 $231.6
 $(216.5) $264.1
Cash Flow Hedges:  
    
  
  
          
Commodity Hedges (c) —
 21.8
 34.0
 3.1
 58.9
 —
 49.1
 68.7
 (8.2) 109.6
Fair Value Hedges —
 34.2
 —
 —
 34.2
 —
 0.2
 —
 —
 0.2
Total Risk Management Liabilities $1.9
 $327.4
 $212.2
 $(197.0) $344.5
 $5.1
 $293.2
 $300.3
 $(224.7) $373.9



AEP


Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 20172018
  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)
           
Other Temporary Investments          
Restricted Cash and Other Cash Deposits (a) $183.2
 $—
 $—
 $36.9
 $220.1
Fixed Income Securities – Mutual Funds
 102.9
 —
 —
 —
 102.9
Equity Securities – Mutual Funds (b)
 36.7
 —
 —
 —
 36.7
Total Other Temporary Investments
 322.8
 —
 —
 36.9
 359.7
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (f) 3.9
 391.2
 274.1
 (285.4) 383.8
Cash Flow Hedges:  
  
  
  
  
Commodity Hedges (c) —
 17.3
 4.7
 —
 22.0
Fair Value Hedges —
 2.5
 —
 —
 2.5
Total Risk Management Assets 3.9
 411.0
 278.8
 (285.4) 408.3
           
Spent Nuclear Fuel and Decommissioning Trusts  
  
  
  
  
Cash and Cash Equivalents (e) 7.5
 —
 —
 9.7
 17.2
Fixed Income Securities:  
  
  
  
  
United States Government —
 981.2
 —
 —
 981.2
Corporate Debt —
 58.7
 —
 —
 58.7
State and Local Government —
 8.8
 —
 —
 8.8
Subtotal Fixed Income Securities —
 1,048.7
 —
 —
 1,048.7
Equity Securities – Domestic (b)
 1,461.7
 —
 —
 —
 1,461.7
Total Spent Nuclear Fuel and Decommissioning Trusts
 1,469.2
 1,048.7
 —
 9.7
 2,527.6
           
Total Assets $1,795.9
 $1,459.7
 $278.8
 $(238.8) $3,295.6
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (f) $5.1
 $392.5
 $196.9
 $(285.0) $309.5
Cash Flow Hedges:  
  
  
  
  
Commodity Hedges (c) —
 23.9
 41.6
 —
 65.5
Fair Value Hedges —
 8.6
 —
 —
 8.6
Total Risk Management Liabilities $5.1
 $425.0
 $238.5
 $(285.0) $383.6







AEP Texas

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 20182019
 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 $124.2
 $—
 $—
 $—
 $124.2
 $114.3
 $—
 $—
 $—
 $114.3
                    
Risk Management Assets  
  
  
  
  
Liabilities:          
          
Risk Management Liabilities          
Risk Management Commodity Contracts (c) —
 0.5
 —
 —
 0.5
 $—
 $0.4
 $—
 $—
 $0.4
          
Total Assets $124.2
 $0.5
 $—
 $—
 $124.7


AEP TexasDecember 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, 2017September 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 $155.2
 $—
 $—
 $—
 $155.2
 $17.1
 $—
 $—
 $—
 $17.1
                    
Risk Management Assets  
  
  
  
  
          
Risk Management Commodity Contracts (c) —
 0.5
 —
 —
 0.5
Risk Management Commodity Contracts (c) (g) —
 31.4
 57.3
 (32.0) 56.7
                    
Total Assets $155.2
 $0.5
 $—
 $—
 $155.7
 $17.1
 $31.4
 $57.3
 $(32.0) $73.8
          
Liabilities:          
          
Risk Management Liabilities          
Risk Management Commodity Contracts (c) (g) $—
 $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








APCo

I&M
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 20182019
 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 $9.9
 $—
 $—
 $—
 $9.9
          
Risk Management Assets  
  
  
  
  
          
Risk Management Commodity Contracts (c) (g) 0.2
 41.8
 66.7
 (38.9) 69.8
 $—
 $21.9
 $10.2
 $(21.5) $10.6
          
Spent Nuclear Fuel and Decommissioning Trusts          
Cash and Cash Equivalents (e) 9.4
 —
 —
 8.0
 17.4
Fixed Income Securities:          
United States Government —
 1,047.4
 —
 —
 1,047.4
Corporate Debt —
 68.6
 —
 —
 68.6
State and Local Government —
 7.5
 —
 —
 7.5
Subtotal Fixed Income Securities —
 1,123.5
 —
 —
 1,123.5
Equity Securities - Domestic (b) 1,694.3
 —
 —
 —
 1,694.3
Total Spent Nuclear Fuel and Decommissioning Trusts 1,703.7
 1,123.5
 —
 8.0
 2,835.2
                    
Total Assets $10.1
 $41.8
 $66.7
 $(38.9) $79.7
 $1,703.7
 $1,145.4
 $10.2
 $(13.5) $2,845.8
                    
Liabilities:  
  
  
  
  
          
                    
Risk Management Liabilities  
  
  
  
  
          
Risk Management Commodity Contracts (c) (g) $0.3
 $40.2
 $0.2
 $(39.1) $1.6
 $—
 $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


APCo

OPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2017September 30, 2019
 Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
          
Restricted Cash for Securitized Funding $16.3
 $—
 $—
 $—
 $16.3
          
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) —
 52.5
 25.1
 (51.6) 26.0
          
Total Assets $16.3
 $52.5
 $25.1
 $(51.6) $42.3
           Level 1 Level 2 Level 3 Other Total
Liabilities:  
  
  
  
  
 (in millions)
                    
Risk Management Liabilities  
  
  
  
  
          
Risk Management Commodity Contracts (c) (g) $—
 $51.2
 $0.4
 $(50.1) $1.5
 $—
 $0.4
 $112.5
 $—
 $112.9



December 31, 2018
I&M
  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, 20182019
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $0.1
 $28.5
 $12.3
 $(29.1) $11.8
           
Spent Nuclear Fuel and Decommissioning Trusts  
  
  
  
  
Cash and Cash Equivalents (e) 27.2
 —
 —
 14.4
 41.6
Fixed Income Securities:  
  
  
  
  
United States Government —
 951.9
 —
 —
 951.9
Corporate Debt —
 54.4
 —
 —
 54.4
State and Local Government —
 8.5
 —
 —
 8.5
Subtotal Fixed Income Securities —
 1,014.8
 —
 —
 1,014.8
Equity Securities - Domestic (b) 1,609.6
 —
 —
 —
 1,609.6
Total Spent Nuclear Fuel and Decommissioning Trusts
 1,636.8
 1,014.8
 —
 14.4
 2,666.0
           
Total Assets $1,636.9
 $1,043.3
 $12.3
 $(14.7) $2,677.8
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $0.1
 $33.2
 $2.9
 $(29.4) $6.8
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets          
Risk Management Commodity Contracts (c) (g) $—
 $—
 $22.0
 $(0.3) $21.7
           
Liabilities:          
           
Risk Management Liabilities          
Risk Management Commodity Contracts (c) (g) $—
 $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



I&M

SWEPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2017September 30, 2019
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $39.4
 $9.1
 $(40.2) $8.3
           
Spent Nuclear Fuel and Decommissioning Trusts  
  
  
  
  
Cash and Cash Equivalents (e) 7.5
 —
 —
 9.7
 17.2
Fixed Income Securities:  
  
  
  
 

United States Government —
 981.2
 —
 —
 981.2
Corporate Debt —
 58.7
 —
 —
 58.7
State and Local Government —
 8.8
 —
 —
 8.8
Subtotal Fixed Income Securities —
 1,048.7
 —
 —
 1,048.7
Equity Securities - Domestic (b) 1,461.7
 —
 —
 —
 1,461.7
Total Spent Nuclear Fuel and Decommissioning Trusts
 1,469.2
 1,048.7
 —
 9.7
 2,527.6
           
Total Assets $1,469.2
 $1,088.1
 $9.1
 $(30.5) $2,535.9
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $47.6
 $1.5
 $(45.5) $3.6
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets          
Risk Management Commodity Contracts (c) (g) $—
 $—
 $9.8
 $(0.4) $9.4
           
Liabilities:          
           
Risk Management Liabilities          
Risk Management Commodity Contracts (c) (g) $—
 $0.2
 $4.9
 $(0.4) $4.7



OPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30,December 31, 2018
 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 $15.2
 $—
 $—
 $—
 $15.2
          
Risk Management Assets  
  
  
  
  
          
Risk Management Commodity Contracts (c) (g) —
 0.7
 —
 —
 0.7
 $—
 $—
 $5.6
 $(0.8) $4.8
          
Total Assets $15.2
 $0.7
 $—
 $—
 $15.9
                    
Liabilities:                    
                    
Risk Management Liabilities                    
Risk Management Commodity Contracts (c) (g) $—
 $—
 $95.2
 $—
 $95.2
 $—
 $0.4
 $3.3
 $(1.1) $2.6

OPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2017
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $0.6
 $—
 $—
 $0.6
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $—
 $132.4
 $—
 $132.4



PSO

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2018
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $0.3
 $18.5
 $(0.3) $18.5
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $—
 $0.9
 $(0.3) $0.6

PSO

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2017
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $0.2
 $6.4
 $(0.2) $6.4
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $—
 $0.2
 $(0.2) $—



SWEPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2018
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $0.2
 $7.9
 $(1.6) $6.5
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $—
 $4.4
 $(1.6) $2.8

SWEPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2017
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $0.3
 $6.7
 $(0.6) $6.4
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $—
 $0.8
 $(0.6) $0.2


(a)Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or 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, 20182019 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(2)$(6) million in 2018 and $(2)2019, $(8) million in periods 2019-20212020-2022 and $3$(1) million in periods 2022-2023;2025-2032; Level 3 matures $40 million in 2018, $1222019, $114 million in periods 2019-2021, $212020-2022, $26 million in periods 2022-20232023-2024 and $1$(4) million in periods 2024-2032.2025-2032.  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, 20172018 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 12 matures $(1)$(4) million in 2018; Level 2 matures $(3) million in 2018 and $22019, $1 million in periods 2022-2023;2020-2022, $1 million in periods 2023-2024 and $1 million in periods 2025-2032; Level 3 matures $59$108 million in 2018, $332019, $37 million in periods 2019-2021, $142020-2022, $23 million in periods 2022-20232023-2024 and $(29)$(12) million in periods 2024-2032.2025-2032.  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, 20182019 and 2017.2018.



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, 2019 AEP APCo I&M OPCo PSO SWEPCo
  (in millions)
Balance as of June 30, 2019 $112.7
 $68.5
 $12.3
 $(111.5) $27.8
 $8.5
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 30.2
 13.8
 3.1
 —
 4.1
 3.6
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 2.9
 —
 —
 —
 —
 —
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 22.1
 —
 —
 —
 —
 —
Settlements (67.4) (28.1) (7.2) 1.1
 (11.2) (6.7)
Transfers into Level 3 (c) (d) 3.5
 —
 —
 —
 —
 —
Transfers out of Level 3 (d) 6.6
 —
 —
 —
 —
 —
Changes in Fair Value Allocated to Regulated Jurisdictions (e) (0.3) 1.3
 0.7
 (2.1) 0.9
 (0.5)
Balance as of September 30, 2019 $110.3
 $55.5
 $8.9
 $(112.5) $21.6
 $4.9
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, 2017 AEP APCo I&M 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, 2017 $87.3
 $41.3
 $15.5
 $(130.5) $9.5
 $12.4
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) 19.8
 6.2
 3.8
 (0.1) 4.0
 3.8
 14.6
 (14.1) 4.6
 (0.9) 13.5
 6.0
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 14.8
 —
 —
 —
 —
 —
 32.9
 —
 —
��—
 —
 —
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (24.3) —
 —
 —
 —
 —
 (42.8) —
 —
 —
 —
 —
Settlements (49.2) (16.2) (8.4) 1.2
 (6.9) (7.6) (114.6) (41.9) (12.6) 4.6
 (23.0) (10.1)
Transfers into Level 3 (c) (d) 5.7
 —
 —
 —
 —
 —
 0.4
 —
 —
 —
 —
 —
Transfers out of Level 3 (d) 0.2
 —
 —
 —
 —
 —
 1.4
 (0.7) (0.4) —
 —
 —
Changes in Fair Value Allocated to Regulated Jurisdictions (e) (9.3) (1.9) (0.7) (9.1) (1.9) 4.5
 87.2
 54.4
 8.4
 (16.8) 21.6
 6.7
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


Nine Months Ended September 30, 2018 AEP APCo I&M OPCo PSO SWEPCo
  (in millions)
Balance as of December 31, 2017 $40.3
 $24.7
 $7.6
 $(132.4) $6.2
 $5.9
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 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 (a) 9.5
 —
 —
 —
 —
 —
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 16.4
 —
 —
 —
 —
 —
Settlements (212.3) (128.3) (21.9) 3.0
 (24.3) (1.3)
Transfers into Level 3 (c) (d) 16.5
 —
 —
 —
 —
 —
Transfers out of Level 3 (d) (2.5) —
 (0.3) —
 —
 —
Changes in Fair Value Allocated to Regulated Jurisdictions (e) 142.4
 65.7
 9.3
 32.9
 17.6
 3.7
Balance as of September 30, 2018 $161.2
 $66.5
 $9.4
 $(95.2) $17.6
 $3.5


Nine Months Ended September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo
  (in millions)
Balance as of December 31, 2016 $2.5
 $1.4
 $2.8
 $(119.0) $0.7
 $0.7
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 37.4
 17.2
 4.0
 (1.0) 3.1
 6.0
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 37.2
 —
 —
 —
 —
 —
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (29.5) —
 —
 —
 —
 —
Settlements (49.7) (18.9) (7.1) 5.1
 (3.8) (6.8)
Transfers into Level 3 (c) (d) 16.1
 —
 —
 —
 —
 —
Transfers out of Level 3 (d) (9.1) —
 —
 —
 —
 —
Changes in Fair Value Allocated to Regulated Jurisdictions (e) 40.1
 29.7
 10.5
 (23.6) 4.7
 13.2
Balance as of September 30, 2017 $45.0
 $29.4
 $10.2
 $(138.5) $4.7
 $13.1


(a)Included in revenues on the statements of income.
(b)Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(c)Represents existing assets or liabilities that were previously categorized as Level 2.
(d)Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
(e)Relates to the net gains (losses) of those contracts that are not reflected on the statements of income.  These net gains (losses) are recorded as regulatory 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, 2018
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$251.5
 $202.4
 Discounted Cash Flow  Forward Market Price (a)  $(0.05) $161.90
 $33.54
$298.8
 $286.8
 Discounted Cash Flow Forward Market Price (a) $(0.05) $180.10
 $31.34
    Counterparty Credit Risk (b)  10
 418
 158
Natural Gas Contracts—
 2.8
 Discounted Cash Flow  Forward Market Price (c)  2.19
 2.97
 2.45
—
 4.5
 Discounted Cash Flow Forward Market Price (b) 1.96
 2.62
 2.25
FTRs121.9
 7.0
 Discounted Cash Flow  Forward Market Price (a)  (9.40) 16.17
 0.83
111.8
 9.0
 Discounted Cash Flow Forward Market Price (a) (10.40) 11.65
 0.54
Total$373.4
 $212.2
      
  
  $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, 2017
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$225.1
 $233.7
 Discounted Cash Flow  Forward Market Price (a)  $(0.05) $263.00
 $36.32
$3.6
 $1.1
 Discounted Cash Flow Forward Market Price $12.93
 $59.25
 $31.28
    Counterparty Credit Risk (b)  8
 456
 180
Natural Gas Contracts—
 0.2
 Discounted Cash Flow  Forward Market Price (c)  2.37
 2.96
 2.62
FTRs53.7
 4.6
 Discounted Cash Flow  Forward Market Price (a)  (55.62) 54.88
 0.41
53.7
 0.7
 Discounted Cash Flow Forward Market Price (0.91) 10.14
 1.63
Total$278.8
 $238.5
      
  
  $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, 2018
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$1.8
 $0.1
 Discounted Cash Flow  Forward Market Price  $14.98
 $59.45
 $36.30
$2.2
 $0.7
 Discounted Cash Flow Forward Market Price $12.93
 $59.25
 $31.28
FTRs64.9
 0.1
 Discounted Cash Flow  Forward Market Price  0.06
 12.73
 2.37
8.0
 0.6
 Discounted Cash Flow Forward Market Price (1.76) 7.26
 0.87
Total$66.7
 $0.2
      
  
  $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, 2017
APCoSeptember 30, 2019
     Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
Energy Contracts$0.8
 $0.4
 Discounted Cash Flow  Forward Market Price  $20.52
 $195.00
 $33.80
FTRs24.3
 —
 Discounted Cash Flow  Forward Market Price  (0.36) 7.15
 1.62
Total$25.1
 $0.4
      
  
  
       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, 2018
I&M2019
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
Energy Contracts$1.1
 $0.9
 Discounted Cash Flow  Forward Market Price  $14.98
 $59.45
 $36.30
FTRs11.2
 2.0
 Discounted Cash Flow  Forward Market Price  (2.58) 6.21
 0.73
Total$12.3
 $2.9
      
  
  
       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, 2017
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$0.5
 $0.3
 Discounted Cash Flow  Forward Market Price  $20.52
 $195.00
 $33.80
Natural Gas Contracts$—
 $4.5
 Discounted Cash Flow Forward Market Price (b) $1.96
 $2.62
 $2.25
FTRs8.6
 1.2
 Discounted Cash Flow  Forward Market Price  (0.36) 5.75
 0.86
9.8
 0.4
 Discounted Cash Flow Forward Market Price (a) (6.87) 0.93
 (2.19)
Total$9.1
 $1.5
      
  
  $9.8
 $4.9
      



Significant Unobservable Inputs
September 30,December 31, 2018
OPCo
    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$—
 $95.2
 Discounted Cash Flow  Forward Market Price (a) $27.23
 $64.61
 $43.26
    Counterparty Credit Risk (b) 10
 188
 141
Natural Gas Contracts$—
 $2.5
 Discounted Cash Flow Forward Market Price (b) $2.18
 $3.54
 $2.47
FTRs5.6
 0.8
 Discounted Cash Flow Forward Market Price (a) (11.68) 10.30
 (1.40)
Total$—
 $95.2
      $5.6
 $3.3
      

Significant Unobservable Inputs
December 31, 2017
OPCo
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input Low High Average
 (in millions)          
Energy Contracts$—
 $132.4
 Discounted Cash Flow  Forward Market Price (a) $30.52
 $170.43
 $44.62
 

 

   Counterparty Credit Risk (b) 8
 190
 136
Total$—
 $132.4
          

Significant Unobservable Inputs
September 30, 2018
PSO
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
FTRs$18.5
 $0.9
 Discounted Cash Flow  Forward Market Price  $(9.40) $10.30
 $(1.49)

Significant Unobservable Inputs
December 31, 2017
PSO
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
FTRs$6.4
 $0.2
 Discounted Cash Flow  Forward Market Price  $(6.62) $1.41
 $(0.76)


Significant Unobservable Inputs
September 30, 2018
SWEPCo
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input Low High Average
 (in millions)          
Natural Gas Contracts$—
 $2.8
 Discounted Cash Flow  Forward Market Price (c) $2.19
 $2.97
 $2.45
FTRs7.9
 1.6
 Discounted Cash Flow  Forward Market Price (a) (9.40) 10.30
 (1.49)
Total$7.9
 $4.4
          

Significant Unobservable Inputs
December 31, 2017
SWEPCo
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input Low High Average
 (in millions)          
Natural Gas Contracts$—
 $0.2
 Discounted Cash Flow  Forward Market Price (c) $2.37
 $2.96
 $2.62
FTRs6.7
 0.6
 Discounted Cash Flow  Forward Market Price (a) (6.62) 1.41
 (0.76)
Total$6.7
 $0.8
          


(a)Represents market prices in dollars per MWh.
(b)Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points.
(c)Represents market prices in dollars per MMBtu.


The following table provides 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, 20182019 and December 31, 2017:2018:


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.


Federal Tax Reform

In December 2017, Tax Reform legislation was signed into law. Tax Reform includes significant changes to the Internal Revenue Code of 1986, as amended, and had a material impact on the Registrants’ financial statements in the reporting period of its enactment. Tax Reform lowered the corporate federal income tax rate from 35% to 21%. Tax Reform provisions related to regulated public utilities generally allow for the continued deductibility of interest expense, impact bonus depreciation for certain property acquired and placed in service after September 27, 2017 and continue certain rate normalization requirements for accelerated depreciation benefits.

Provisional Amounts

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

During the third quarter of 2018, the IRS proposed new regulations that reflect changes made by Tax Reform and affect taxpayers with qualified depreciable property acquired and placed in service after September 27, 2017. The Registrants expect to complete the analysis of the provisional items, including analysis of the new regulations proposed by the IRS, during the fourth quarter of 2018.



Status of Tax Reform Regulatory Proceedings


TheFor 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 of Tax Reform in AEP’s various regulatory jurisdictions.status. See Note 4 - Rate Matters for additional information related to regulatory filings in these jurisdictions.
Registrant (Jurisdiction) Change in Tax Rate Excess ADIT Subject to Normalization Requirements Excess ADIT Not Subject to Normalization Requirements
AEP Texas (Texas-Distribution) Order Issued Order Issued Order Issued – Partial (a)
AEP Texas (Texas-Transmission) Order Issued To be addressed in a later filingCase Pending To be addressed in a later filing
APCo (Virginia)Legislation Enacted – Case Pending (b)Legislation Enacted – Case Pending (b)Order Issued – Partial; Separate Case Pending (c)
APCo (West Virginia)Order IssuedOrder IssuedOrder Issued
I&M (Indiana)Order IssuedOrder IssuedOrder Issued
I&M (Michigan) Order Issued; Separate Case Pending (d)Issued Case Pending Case Pending
AEP (Tennessee)Case PendingCase PendingCase Pending
AEP (Kentucky)Order IssuedOrder IssuedOrder Issued
OPCo (Ohio)Order IssuedOrder IssuedOrder Issued
PSO (Oklahoma)Order IssuedOrder IssuedOrder Issued
SWEPCo (Arkansas)Order IssuedOrder IssuedOrder Issued
SWEPCo (Louisiana) Case Pending – Rates Implemented (e)(b) Case Pending – Rates Implemented (e)(b) Case Pending – Rates Implemented (e)(b)
SWEPCo (Texas) Order Issued (f)To be addressed in a later filingTo be addressed in a later filing
PJM FERC TransmissionSettlement Approved (g)Settlement Approved (g)Settlement Approved (g)
SPP FERC TransmissionTo be addressed in a later filing To be addressed in a later filing To be addressed in a later filing



(a)A portion of the Excess ADIT that is not subject to rate normalization requirements is to be addressed in a later filing.
(b)Legislation has been issued for a blanket amount that is subject to true-up and final commission approval.
(c)In October 2018, the Virginia SCC issued an order approving APCo’s request to refund a portion of the Excess ADIT that is not subject to rate normalization requirements to customers. The remainder is to be addressed in a separatecurrent pending case.
(d)A rider was implemented to refund the impact of Tax Reform prospectively and effective September 1, 2018. A separate filing was submitted in October 2018 for the Tax Reform impact from January 1, 2018 through August 31, 2018.
(e)(b)Rates have been implemented through a filed formula rate plan that is subject to true-up and final commission approval.
(f)An interim order has been issued to lower rates. Parties continue to finalize settlement.
(g)An administrative law judge has approved a settlement. The settlement is subject to final FERC ruling.

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

State utility commissions have issued orders or instructions requiring public utilities, including the Registrants, to record liabilities to reflect the impact of the reduction in the corporate federal income tax rate in excess of the enacted corporate federal income tax rate of 21% beginning in 2018. As described in Note 4 - Rate Matters, certain Registrants have received state utility commission orders and have reflected the lower corporate federal income tax rate in current customer rates. The table below provides a summary of the estimated provisions for revenue refund recorded by the Registrants related to the reduction in the corporate federal tax rate as of September 30, 2018:
  AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
  (in millions)
Included in Current Liabilities $51.1
 $—
 $—
 $40.5
 $2.0
 $—
 $2.4
 $5.3
Included in Deferred Credits and Other Noncurrent Liabilities 98.4
 21.9
 8.6
 3.7
 12.8
 20.8
 2.3
 27.6

Excess ADIT - Pending Rate Reductions

As of September 30, 2018, the Registrants have approximately $4.3 billion of Excess ADIT, as well as an incremental liability of $1.1 billion to reflect the $4.3 billion Excess ADIT on a pretax basis, presented in Regulatory Liabilities and Deferred Investment Tax Credits on the balance sheets.  The Excess ADIT is reflected on a pretax basis to appropriately contemplate future tax consequences in the periods when the regulatory liability is settled.  As of September 30, 2018, approximately $3.4 billion of the Excess ADIT relates to temporary differences associated with certain depreciable property subject to rate normalization requirements.



As reflected in the Registrants’ respective estimated annual ETR for 2018, AEP’s regulated public utilities began amortizing the Excess ADIT associated with certain depreciable property subject to rate normalization requirements using the ARAM during the first quarter of 2018. The amortization resulted in a reduction in the Excess ADIT balance recorded in Regulatory Liabilities and Deferred Investment Tax Credits and a reduction in Income Tax Expense. As a result of state utility commission orders or instructions, the Registrants have recorded estimated provisions for revenue refund offsetting the amortization of the Excess ADIT to the extent not yet reflected in current customer rates. The table below provides a summary of the estimated provisions for revenue refund recorded by the Registrants as of September 30, 2018:
  AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
  (in millions)
Included in Current Liabilities $15.3
 $—
 $—
 $9.5
 $—
 $—
 $4.7
 $1.2
Included in Deferred Credits and Other Noncurrent Liabilities 20.6
 6.9
 0.1
 0.7
 1.4
 3.3
 —
 7.8

In addition, with respect to the remaining $0.9 billion of Excess ADIT recorded in Regulatory Liabilities and Deferred Investment Tax Credits that are not subject to rate normalization requirements, the Registrants have received state utility commission orders or instructions and a filed FERC settlement agreement to begin amortization.


Effective Tax Rates (ETR)


The Registrants’ interim ETR reflect the estimated annual ETR for 20182019 and 2017,2018, adjusted for tax expense associated with certain discrete items. As previously mentioned, effective January 1, 2018, Tax Reform lowered the corporate tax rate from 35% to 21%. The interim ETR differ from the federal statutory tax rate of 21% and 35% in 2018 and 2017, respectively, primarily due to state income taxes, theincreased amortization of the Excess ADIT, tax credits 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 for each of the Registrants isare 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 2018 2017 2018 2017
AEP (16.2)% 33.0% 5.6 % 35.3%
AEP Texas 12.6 % 32.2% 14.9 % 33.6%
AEPTCo (a) 18.4 % 33.5% 20.7 % 33.8%
APCo (962.2)% 33.4% (13.8)% 35.5%
I&M 15.9 % 30.6% 10.4 % 30.1%
OPCo (46.4)% 36.9% 4.6 % 35.6%
PSO 5.6 % 37.2% 8.7 % 37.4%
SWEPCo 9.8 % 21.2% 11.4 % 25.7%



(a)The 2017 ETRs presented above reflect the revisions made to AEPTCo's previously issued financial statements.  See Note 1 - Significant Accounting Matters for additional information.





AEP


Three Months Ended September 30, 20182019 Compared to Three Months Ended September 30, 20172018


The increase in the ETR was 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 ETR by 19.1% and 1.3%, respectively.

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

The decrease in the ETR was primarily due to $93 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (4.5)%.

AEP Texas

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

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 was primarily due to $59 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (38.9)%. Amortization of Excess ADIT not subject to normalization requirements for the nine months ended September 30, 2019 reflects Tax Reform elements of the Stipulation and Settlement agreement approved by the PUCT in August 2018 and the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019.

AEPTCo

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

The increase in the ETR was primarily due to $3 million of increased state tax expense and $2 million of decreased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by 1.3% and 1%, respectively.

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

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


APCo
Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018
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 was primarily due to $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 the 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 Reform elements of the 2017 Indiana Base Rate Case approved by the IURC in May 2018.

OPCo

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

The increase in the ETR was primarily due to $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 ordersorder which enabled APCo, OPCo and WPCo to utilize $38 million of Excess ADIT not subject to rate normalization requirements to offset certain regulatory asset balances.  The West Virginia and Ohio Tax Reform orders impacted the ETR by (17.9)% and (7.8)%, respectively.  See “West Virginia Tax Reform” and “Ohio Tax Reform” sections of Note 4 for additional information.  Additionally, the ETR decreased as a result of the changebalances in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a resultthird quarter of Tax Reform and decreased (7.4)% due to increased 2018 amortization of Excess ADIT.2018.


Nine Months Ended September 30, 20182019 Compared to Nine Months Ended September 30, 20172018


The decreaseincrease 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 West Virginia and Ohio Tax Reform ordersorder which enabled APCo, OPCo and WPCo to utilize $38 million of Excess ADIT not subject to rate normalization requirements to offset certain regulatory asset balances.  The West Virginia and Ohio Tax Reform orders impacted the ETR by (5.4)% and (2.3)%, respectively. See “West Virginia Tax Reform” and “Ohio Tax Reform” sections of Note 4 for additional information. Additionally, the ETR decreased as a result of the changebalances in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a resultthird quarter of Tax Reform, state tax legislation enacted in Kentucky in April 2018 impacted the ETR by (1.1)% and increased 2018 amortization of Excess ADIT impacted the ETR by (4.7)%.2018.

AEP Texas

PSO

Three Months Ended September 30, 20182019 Compared to Three Months Ended September 30, 20172018


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 the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result$15 million of Tax Reform and increased 2018 amortization of Excess ADIT.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.


NineSWEPCo

Three Months Ended September 30, 20182019 Compared to NineThree Months Ended September 30, 20172018


The decrease in the ETR was primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result$11 million of Tax Reform and increased 2018 amortization of Excess ADIT.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.


AEPTCo

ThreeNine Months Ended September 30, 20182019 Compared to ThreeNine Months Ended September 30, 20172018


The decrease in the ETR was primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result$15 million of Tax Reform.

Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017

The decrease in the ETR was primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a resultincreased amortization of Tax Reform.



APCo
Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017
The decrease in the ETR was primarily due to the discrete impact of the West Virginia Tax Reform orders which enabled APCo to utilize Excess ADIT not subject to rate normalization requirements to offset certain regulatory asset balances.  The West Virginia Tax Reform orderwhich impacted the ETR by (887.8)(10.4)%. See “West Virginia Tax Reform” sectionAmortization of Note 4 for additional information.  Additionally, the ETR decreased as a result of the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and decreased (31.7)% due to increased 2018 amortization of Excess ADIT.

Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017

The decrease in the ETR was primarily due to the discrete impact of the West Virginia Tax Reform orders which enabled APCo to utilize Excess ADIT not subject to rate normalization requirements to offset certain regulatory asset balances.  The West Virginiafor 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 impactedissued by the ETR by (28.6)%.  See “West Virginia Tax Reform” section of Note 4 for additional information.  Additionally, the ETR decreased as a result of the changeAPSC in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and decreased (4.9)% due to increased 2018 amortization of Excess ADIT.September 2018.


I&M

Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017

The decrease in the ETR was primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, increased 2018 amortization of Excess ADIT and decreased state income taxes.  These decreases were partially offset by an increase in book/tax differences which are accounted for on a flow-through basis resulting from a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028.

Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017

The decrease in the ETR was primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, increased 2018 amortization of Excess ADIT and decreased state income taxes.  These decreases were partially offset by an increase in book/tax differences which are accounted for on a flow-through basis resulting from a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028.

OPCo

Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017

The decrease in the ETR was primarily due to the discrete impact of the Ohio Tax Reform orders which enabled OPCo to utilize Excess ADIT not subject to rate normalization requirements to offset certain regulatory asset balances.  The Ohio Tax Reform order impacted the ETR by (62.0)%.  See “Ohio Tax Reform” section of Note 4 for additional information. Additionally, the ETR decreased as a result of the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and decreased (4.1)% due to increased 2018 amortization of Excess ADIT.

Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017

The decrease in the ETR was primarily due to the discrete impact of the Ohio Tax Reform orders which enabled OPCo to utilize Excess ADIT not subject to rate normalization requirements to offset certain regulatory asset balances.  The Ohio Tax Reform order impacted the ETR by (15.1)%.  See “Ohio Tax Reform” section of Note 4 for additional information.  Additionally, the ETR decreased as a result of the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and decreased (2.5)% due to increased 2018 amortization of Excess ADIT.



PSO

Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017

The decrease in the ETR was primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and increased 2018 amortization of Excess ADIT. The amortization of Excess ADIT impacted the ETR by (17.3)%.

Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017

The decrease in the ETR was primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and increased 2018 amortization of Excess ADIT. The amortization of Excess ADIT impacted the ETR by (13.9)%.

SWEPCo

Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017

The decrease in the ETR was primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and increased 2018 amortization of Excess ADIT. The amortization of Excess ADIT impacted the ETR by (9.0)%. These decreases are partially offset by a prior year income tax benefit attributable to SWEPCo’s noncontrolling interest in Sabine.

Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017

The decrease in the ETR was primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and increased 2018 amortization of Excess ADIT. The amortization of Excess ADIT impacted the ETR by (7.9)%.

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 through 2013 started in April 2014. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing2014, the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 auditstatute of limitations for these years was submittedextended to coincide with the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back to the IRS exam team for further consideration. To resolve the issue under consideration, AEP and subsidiaries and the IRS exam team agreed to utilize the Fast Track Settlement Program in December 2017. The program was completed in March 2018 and tax years 2014 and 2015 were added to the IRS examination to reflect the impact of the Fast Track changes that were carried forward to 2014 and 2015. In June 2018, AEP settled all outstanding issues under audit for tax years 2011-2013, and the audit was again submitted to the Joint Committee for approval inDuring the third quarter of 2018. As a result, the related $72 million unrecognized tax benefit was reversed in the second quarter of 2018. The settlement did not materially impact the Registrants net income, cash flows or financial condition. In the third quarter of 2018, AEP was notified that the IRS would commence an audit of the 2016 tax year in October 2018.

2019, AEP and subsidiaries file income tax returns in various state, local or foreign jurisdictions.  These taxing authorities routinely examineelected to amend the tax2014 and 2015 federal 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 thatDue to 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, AEPTCo, I&M and OPCo)


In April 2018, the Kentucky legislature enacted House Bill (H.B.) 487. H.B. 487 adopts mandatory unitary combined reporting for state corporate income tax purposes applicable for taxable years beginning on or after January 1, 2019. H.B. 487 also adopts the 80% federal net operating loss (NOL) limitation under Internal Revenue Code Sec. 172(a) for NOLs generated after January 1, 2018 and the 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 graduated corporate tax rate 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 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 did not materially impact AEPTCo’s, I&M’s or OPCo’s net 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, 2018 December 31, 2017
  (in millions)
Senior Unsecured Notes $18,342.1
 $16,478.3
Pollution Control Bonds 1,643.2
 1,621.7
Notes Payable 233.2
 260.8
Securitization Bonds 1,145.2
 1,416.5
Spent Nuclear Fuel Obligation (a) 272.1
 268.6
Other Long-term Debt 1,138.2
 1,127.4
Total Long-term Debt Outstanding 22,774.0
 21,173.3
Long-term Debt Due Within One Year 1,904.2
 1,753.7
Long-term Debt $20,869.8
 $19,419.6


(a)Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for 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 $316$322 million and $312$317 million as of September 30, 20182019 and December 31, 2017,2018, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.
(b)See “Equity Units” section below for additional information.


Long-term Debt Activity


Long-term debt and other securities issued, retired and principal payments made during the first nine months of 20182019 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 $500.0
 3.95 2028 Senior Unsecured Notes 300.0
 4.15 2049
AEPTCo Senior Unsecured Notes 325.0
 4.25 2048 Senior Unsecured Notes 350.0
 3.80 2049
AEPTCo Senior Unsecured Notes 350.0
 3.15 2049
APCo Pollution Control Bonds 86.0
 2.55 2024
APCo Pollution Control Bonds 104.4
 2.625 2022 Senior Unsecured Notes 400.0
 4.50 2049
I&M Other Long-term Debt 200.0
 Variable 2021 Notes Payable 62.8
 Variable 2023
I&M Notes Payable 55.5
 Variable 2022
I&M Pollution Control Bonds 100.0
 3.05 2025
I&M Senior Unsecured Notes 350.0
 3.85 2028
I&M Senior Unsecured Notes 475.0
 4.25 2048
OPCo Senior Unsecured Notes 400.0
 4.15 2048 Senior Unsecured Notes 450.0
 4.00 2049
SWEPCo Senior Unsecured Notes 575.0
 4.10 2028
SWEPCo Senior Unsecured Notes 450.0
 3.85 2048
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: 

 
 
   
AEGCo Pollution Control Bonds 45.0
 1.35 2022
Transource Energy Other Long-term Debt 12.7
 Variable 2020 Other Long-term Debt 14.4
 Variable 2020
WPCo Pollution Control Bonds 65.0
 3.00 2022
Total Issuances $3,612.6
 
 
 $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) (%)  
AEP Texas Securitization Bonds $70.0
 5.17 2018
AEP Texas Senior Unsecured Notes 30.0
 5.89 2018
AEP Texas Securitization Bonds 27.6
 1.976 2020
AEP Texas Securitization Bonds 104.1
 5.306 2020
APCo Securitization Bonds 24.0
 2.008 2023
I&M Other Long-term Debt 200.0
 Variable 2018
I&M Pollution Control Bonds 100.0
 1.75 2018
I&M Senior Unsecured Notes 475.0
 7.00 2019
I&M Notes Payable 3.5
 Variable 2019
I&M Notes Payable 10.1
 Variable 2019
I&M Notes Payable 18.8
 Variable 2020
I&M Notes Payable 19.5
 Variable 2021
I&M Notes Payable 21.3
 Variable 2022
I&M Notes Payable 6.7
 Variable 2022
I&M Other Long-term Debt 1.2
 6.00 2025
OPCo Senior Unsecured Notes 350.0
 6.05 2018
OPCo Securitization Bonds 46.9
 2.049 2019
OPCo Other Long-term Debt 0.1
 1.149 2028
PSO Other Long-term Debt 0.3
 3.00 2027
SWEPCo Pollution Control Bonds 81.7
 4.95 2018
SWEPCo Senior Unsecured Notes 300.0
 5.875 2018
SWEPCo Other Long-term Debt 0.2
 3.50 2023
SWEPCo Other Long-term Debt 0.2
 4.28 2023
SWEPCo Notes Payable 3.2
 4.58 2032
         
Non-Registrant:        
AEP Energy Notes Payable 0.1
 5.75 2019
WPCo Pollution Control Bonds 65.0
 Variable 2018
Total Retirements and Principal Payments   $1,959.5
    


As of September 30, 2018,2019, trustees held, on behalf of AEP, $574 million of their reacquired Pollution Control Bonds. Of this total, $345 million relates to OPCo.


Long-term Debt Subsequent Events


In October 2018,2019, 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 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 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 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 immaterial0.1% of consolidated tangible net assets as of September 30, 2018.2019. 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 covenants that limit their debt to capitalization ratio to 67.5%. The method for calculating outstanding debt and capitalization is contractually definedcontractually-defined in the credit agreements.


The Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings.



Parent Restrictions (Applies to AEP)


The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends.  Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries.


Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%.  The method for calculating outstanding debt and capitalization is contractually definedcontractually-defined in the credit agreements.



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; a Nonutility Money Pool, which funds certain AEP nonutility 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, 20182019 and December 31, 20172018 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ balance sheets.  The Utility Money Pool participants’ money pool activity and corresponding authorized borrowing limits for the nine months ended September 30, 20182019 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, 2018 Limit 
  (in millions)
AEP Texas $390.6
 $106.9
 $189.9
 $47.1
 $(77.8) $500.0
 
AEPTCo 371.3
 232.7
 237.9
 28.1
 232.7
 795.0
(a)
APCo 295.5
 23.7
 185.3
 23.4
 (75.4) 600.0
 
I&M 322.1
 657.8
 257.6
 116.4
 72.5
 500.0
 
OPCo 270.8
 225.0
 169.0
 189.4
 (242.9) 500.0
 
PSO 193.7
 30.9
 119.8
 10.1
 (22.0) 300.0
 
SWEPCo 200.1
 525.5
 143.2
 343.3
 516.6
 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 are participantsLLC participate in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 20182019 and December 31, 20172018 are included in Advances to Affiliates on eachthe subsidiaries’ balance sheets. The Nonutility Money Pool participants’ money pool activity for the nine months ended September 30, 20182019 is described in the following 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 to the
  Loans to the Loans to the Nonutility
  Nonutility Nonutility Money Pool as of
Company Money Pool Money Pool September 30, 2018
 (in millions)
AEP Texas $8.4
 $8.1
 $8.0
SWEPCo 2.0
 2.0
 2.0



AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of outstanding loans to (borrowings from)and borrowings from AEP as of September 30, 20182019 and December 31, 20172018 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, 2018 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, 2018 September 30, 2018 Borrowing Limit from AEP to AEP from AEP to AEP September 30, 2019 September 30, 2019 Borrowing Limit 
(in millions)
$1.1
 $104.7
 $1.1
 $50.0
 $1.1
 $45.3
 $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,
  2018 2017
Maximum Interest Rate 2.52% 1.49%
Minimum Interest Rate 1.81% 0.92%


The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized for all Registrant Subsidiaries in the following table:
  Average Interest Rate for 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 from for Funds Loaned to
  the Utility Money Pool for the the Utility Money Pool for the
  Nine Months Ended September 30, Nine Months Ended September 30,
Company 2018 2017 2018 2017
AEP Texas 2.25% 1.29% 2.29% 1.35%
AEPTCo 2.26% 1.36% 2.04% 1.04%
APCo 2.22% 1.24% 2.19% 1.28%
I&M 2.16% 1.24% 2.06% 1.27%
OPCo 2.18% 1.40% 2.47% 0.98%
PSO 2.25% 1.30% 1.86% —%
SWEPCo 2.31% 1.26% 1.87% 0.98%


Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized 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%

  Nine Months Ended September 30, 2018 Nine Months Ended September 30, 2017
  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 2.52% 1.83% 2.26% 1.49% —% 1.27%
SWEPCo 2.52% 1.83% 2.26% 1.49% —% 1.27%



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
2018 2.52% 1.76% 2.52% 1.76% 2.26% 2.27%
2017 1.49% 0.92% 1.49% 0.92% 1.27% 1.31%



Short-term Debt (Applies to AEP and SWEPCo)AEP)


Outstanding short-term debt was as follows:
    September 30, 2018 December 31, 2017
Company Type of Debt 
Outstanding
Amount
 
Interest
Rate (a)
 Outstanding
Amount		 Interest
Rate (a)
    (dollars in millions)
AEP Securitized Debt for Receivables (b) $750.0
 2.06% $718.0
 1.22%
AEP Commercial Paper 1,473.2
 2.40% 898.6
 1.85%
SWEPCo Notes Payable 19.4
 3.45% 22.0
 2.92%
  Total Short-term Debt $2,242.6
  
 $1,638.6
  
  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 was amended in July 2018 to include a $125 million and a $625 million facility which expire in July 2020 and 2021, respectively.

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,
  2018 2017 2018 2017
  (dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable 2.27% 1.33% 2.06% 1.17%
Net Uncollectible Accounts Receivable Written Off $9.6
 $7.0
 $19.0
 $18.2

  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, 2018 December 31, 2017
  (in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $1,082.9
 $925.5
Short-term – Securitized Debt of Receivables 750.0
 718.0
Delinquent Securitized Accounts Receivable 58.2
 41.1
Bad Debt Reserves Related to Securitization 29.3
 28.7
Unbilled Receivables Related to Securitization 242.1
 303.2


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 Subsidiaries’Subsidiary’s receivables.  APCo does not have regulatory authority to sell its West Virginia accounts receivable.  The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income.  The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder.


The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreements were:
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, 2018 December 31, 2017
  (in millions)
APCo $122.9
 $136.2
I&M 169.5
 136.5
OPCo 413.7
 367.4
PSO 163.0
 115.1
SWEPCo 190.5
 138.2


The fees paid 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 2018 2017 2018 2017
  (in millions)
APCo $1.8
 $1.5
 $5.1
 $4.2
I&M 2.5
 1.8
 6.8
 4.9
OPCo 7.2
 6.1
 18.8
 16.5
PSO 2.3
 2.0
 6.0
 5.2
SWEPCo 2.6
 2.0
 6.6
 5.4


The 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 2018 2017 2018 2017
  (in millions)
APCo $334.1
 $335.5
 $1,079.2
 $1,029.4
I&M 498.4
 409.9
 1,401.7
 1,218.9
OPCo 695.2
 616.3
 2,046.9
 1,741.7
PSO 454.9
 407.0
 1,171.2
 1,022.6
SWEPCo 512.6
 455.0
 1,364.6
 1,200.8



13. 14. VARIABLE INTEREST ENTITIES AND EQUITY METHOD INVESTMENTS


The disclosures in this note apply to AEP only.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.


Desert Sky Wind Farm LLC (Desert Sky)AEP holds ownership interests in businesses with varying ownership structures. Partnership interests and Trent Wind Farm LLC (Trent) (collectively “the LLCs”) were establishedother 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 repowering, owningissuing and operating wind-powered electric energy generation facilities in Texas. In January 2018,servicing securitization bonds related to storm restoration of AEP admitted a nonaffiliate as a memberTexas’ 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 LLCsVIE and AEP Texas’ equity interest could potentially be significant. Therefore, AEP Texas is required to ownconsolidate Restoration Funding. The securitized bonds totaled $235 million as of September 30, 2019 and repower Desert Skyare included in Long-term Debt Due Within One Year - Nonaffiliated and Trent. The nonaffiliate contributed full turbine sets to each project in exchange for a 20.1% interest in the LLCs. The nonaffiliates’ contribution of $84 million was recorded as Net Property, Plant and EquipmentLong-term Debt - Nonaffiliated on the balance sheets, which was the fair valuesheets. Restoration Funding has securitized assets of $235 million as of September 30, 2019 which are presented separately on the contribution date determined based on key input assumptionsface of the original costbalance 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 full turbine setspurchase 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 the discounted cash flow benefit associatedflows are allocated in accordance with the production tax credits available from repowering Desert Sky and Trent based on their expected net capacity, capacity factor and the operational availability. AEP owns 79.9% of the LLCs. As a result, managementrespective limited liability company agreements. Management has concluded that Desert Sky and Trent, collectively,the Project Entities are VIE’sVIEs and that AEP is the primary beneficiary based on its power as managing member to direct the activities that most significantly impact Desert Sky and Trent’sthe Project Entities’ economic performance. Also in January 2018, Desert Sky and Trent entered into a forward PPA for the sale of power to AEPEP related to deliveries of electricity beginning January 1, 2021 for a 12 year period. PriorIn addition, AEP has not provided material financial or other support to the effective dateProject Entities that was not previously contractually required. As the primary beneficiary of the PPA, Desert Sky and Trent will sell power at market ratesProject Entities, AEP consolidates the Project Entities into ERCOT. AEP and the nonaffiliate will share tax attributes including production tax credits and cash distributions from the operation of the LLCs generally consistent with the ownership percentages.its financial statements. See the table below for the classification of Desert Sky and Trent’sProject Entities’ assets and liabilities on the balance sheet:sheets.

American Electric Power Company, Inc.
Variable Interest Entities
September 30, 2018
  
 Desert Sky and Trent
 (in millions)
ASSETS 
Current Assets$89.2
Net Property, Plant and Equipment350.8
Other Noncurrent Assets0.4
Total Assets$440.4
  
LIABILITIES AND EQUITY 
Current Liabilities$93.4
Noncurrent Liabilities6.1
Equity340.9
Total Liabilities and Equity$440.4
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 hasexercises significant influence but does not hold a call right, which if exercised, would require the nonaffiliate to sell its noncontrolling interestcontrolling financial interest. Such investments are initially recorded at cost in the LLCs to AEP. The call exercise period is for ninety days, beginning July 2020 for TrentDeferred Charges and August 2020 for Desert Sky. The nonaffiliates’ interest in the LLCs is presented as Redeemable Noncontrolling InterestOther Noncurrent Assets on the balance sheets. The nonaffiliate holds redemption rights, which if exercised, would requireproportionate 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 purchasedetermine whether they are impaired. An impairment is recorded when the nonaffiliates’ noncontrollinginvestment 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 the LLCs.  The redemption right exercise period is for ninety days, beginning July 2021 for Trent and August 2021 for Desert Sky. The exercise price for both the call and redemption right are determined using a discounted cash flow model with agreed input assumptionsfive wind farms in multiple states as well as potential updates to certain assumptions reasonably expected based on the actual resultspart of the LLCs.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, 2018,2019, 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 recorded $70recognized $7 million and $21 million of Redeemable Noncontrolling InterestPTC attributable to the joint venture wind farms for the three and nine months ended September 30, 2019, respectively, which was recorded in Mezzanine EquityIncome Tax Expense (Benefit) on the balance sheets.statements of income.



14.
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, 2018 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 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other Reconciling Adjustments AEP Consolidated
 (in millions) (in millions)
Retail Revenues:                            
Residential Revenues $1,048.7
 $612.2
 $—
 $—
 $—
 $—
 $1,660.9
 $1,060.2
 $588.0
 $—
 $—
 $—
 $—
 $1,648.2
Commercial Revenues 618.5
 336.7
 —
 —
 —
 —
 955.2
 612.5
 290.9
 —
 —
 —
 —
 903.4
Industrial Revenues 573.2
 123.9
 —
 —
 —
 —
 697.1
 566.0
 99.3
 —
 —
 —
 1.5
 666.8
Other Retail Revenues 49.0
 9.8
 —
 —
 —
 —
 58.8
 49.2
 10.6
 —
 —
 —
 —
 59.8
Total Retail Revenues 2,289.4
 1,082.6
 —
 —
 —
 —
 3,372.0
 2,287.9
 988.8
 —
 —
 —
 1.5
 3,278.2
                            
Wholesale and Competitive Retail Revenues:                            
Generation Revenues (a) 224.2
 —
 —
 115.1
 —
 (98.5) 240.8
 231.3
 —
 —
 77.1
 —
 (34.2) 274.2
Transmission Revenues (b) 72.8
 88.0
 201.4
 —
 —
 (241.6) 120.6
 77.8
 110.9
 269.4
 —
 —
 (217.2) 240.9
Marketing, Competitive Retail and Renewable Revenues —
 —
 —
 399.1
 —
 —
 399.1
 —
 —
 —
 415.4
 —
 0.5
 415.9
Total Wholesale and Competitive Retail Revenues 297.0
 88.0
 201.4
 514.2
 —
 (340.1) 760.5
 309.1
 110.9
 269.4
 492.5
 —
 (250.9) 931.0
                            
Other Revenues from Contracts with Customers (c) 40.3
 69.9
 0.7
 12.7
 21.5
 49.5
 194.6
 47.3
 42.9
 4.5
 14.8
 35.6
 (42.2) 102.9
                            
Total Revenues from Contracts with Customers 2,626.7
 1,240.5
 202.1
 526.9
 21.5
 (290.6) 4,327.1
 2,644.3
 1,142.6
 273.9
 507.3
 35.6
 (291.6) 4,312.1
                            
Other Revenues:                            
Alternative Revenues (d)(c) 0.2
 (37.9) (14.9) —
 —
 —
 (52.6) 1.2
 5.1
 (0.9) —
 —
 (16.8) (11.4)
Other Revenues (c) 9.8
 8.9
 —
 (5.3) 2.2
 43.0
 58.6
 —
 38.9
 —
 26.4
 (11.2) (39.8) 14.3
Total Other Revenues 10.0
 (29.0) (14.9) (5.3) 2.2
 43.0
 6.0
 1.2
 44.0
 (0.9) 26.4
 (11.2) (56.6) 2.9
                            
Total Revenues $2,636.7
 $1,211.5
 $187.2
 $521.6
 $23.7
 $(247.6) $4,333.1
 $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 is $35was $34 million. The remaining affiliated amounts arewere immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco is $147was $197 million. The remaining affiliated amounts arewere 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 iswas primarily the $48 million reduction in revenue relating to the Ohio taxTax Reform settlement. See the “Ohio Tax Reform” section of Note 4 for additional information.
(e)Amounts include affiliated and nonaffiliated revenues.






 Nine Months Ended September 30, 2018 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 AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
 (in millions) (in millions)
Retail Revenues:                            
Residential Revenues $2,906.9
 $1,711.0
 $—
 $—
 $—
 $—
 $4,617.9
 $192.0
 $—
 $315.7
 $198.2
 $395.6
 $231.9
 $222.9
Commercial Revenues 1,693.9
 962.6
 —
 —
 —
 —
 2,656.5
 110.6
 —
 147.2
 138.3
 180.5
 122.2
 144.3
Industrial Revenues 1,655.2
 366.8
 —
 —
 —
 —
 2,022.0
 32.2
 —
 152.2
 138.7
 67.1
 84.1
 92.3
Other Retail Revenues 139.1
 29.2
 —
 —
 —
 —
 168.3
 7.5
 —
 18.5
 1.9
 3.1
 24.9
 2.3
Total Retail Revenues 6,395.1
 3,069.6
 —
 —
 —
 —
 9,464.7
 342.3
 —
 633.6
 477.1
 646.3
 463.1
 461.8
                            
Wholesale and Competitive Retail Revenues:              
Wholesale Revenues:              
Generation Revenues (a) 686.5
 —
 —
 413.4
 —
 (155.2) 944.7
 —
 —
 70.4
 102.1
 —
 21.1
 50.7
Transmission Revenues (b) 208.4
 272.6
 633.9
 —
 —
 (520.7) 594.2
 97.7
 256.4
 26.2
 6.4
 13.7
 (3.4) 30.0
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
Total Wholesale Revenues 97.7
 256.4
 96.6
 108.5
 13.7
 17.7
 80.7
                            
Other Revenues from Contracts with Customers (c) 121.8
 165.1
 11.1
 15.0
 64.8
 1.8
 379.6
 8.2
 4.5
 18.7
 26.6
 41.0
 5.1
 7.0
                            
Total Revenues from Contracts with Customers 7,411.8
 3,507.3
 645.0
 1,468.6
 64.8
 (674.1) 12,423.4
 448.2
 260.9
 748.9
 612.2
 701.0
 485.9
 549.5
                            
Other Revenues:                            
Alternative Revenues (d) (19.2) (48.3) (39.8) —
 —
 —
 (107.3) (0.7) (1.2) 6.6
 (1.1) 12.4
 7.1
 (4.0)
Other Revenues (c) 1.1
 51.9
 —
 18.8
 6.7
 —
 78.5
Other Revenues (d) 41.8
 —
 —
 —
 (2.8) —
 —
Total Other Revenues (18.1) 3.6
 (39.8) 18.8
 6.7
 —
 (28.8) 41.1
 (1.2) 6.6
 (1.1) 9.6
 7.1
 (4.0)
                            
Total Revenues $7,393.7
 $3,510.9
 $605.2
 $1,487.4
 $71.5
 $(674.1) $12,394.6
 $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 is $87was $105 million. The remaining affiliated amounts arewere immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco is $444was $596 million. The remaining affiliated amounts arewere 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 iswas primarily the $48 million reduction in revenue relating to the Ohio taxTax Reform settlement. See the “Ohio Tax Reform” section of Note 4 for additional information.
(e)Amounts include affiliated and nonaffiliated revenues.





The tables below represent revenues from contracts with customers, net of respective provisions for refund, by type of revenue for the Registrant Subsidiaries:
  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

  Three Months Ended September 30, 2018
  AEP Texas AEPTCo (a) APCo I&M OPCo PSO SWEPCo
  (in millions)
Retail Revenues:              
Residential Revenues $178.8
 $—
 $320.9
 $207.4
 $433.5
 $220.8
 $214.0
Commercial Revenues 113.7
 —
 155.6
 139.5
 222.9
 122.2
 142.6
Industrial Revenues 27.2
 —
 157.1
 148.7
 96.3
 80.2
 87.5
Other Retail Revenues 6.5
 —
 19.2
 1.7
 3.3
 24.4
 2.2
Total Retail Revenues 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)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 presentedwere 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 revisions made to AEPTCo’sreclassification of certain customer accounts between Retail classes. This reclassification did not impact previously issued financial statements. For additional details on revisions made to AEPTCo’s financial statements, see Note 1- Significant Accounting Matters.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 is $30was $100 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts arewere immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo is $146was $448 million. The remaining affiliated amounts arewere immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M is $17 million primarily relating to the barging, urea transloading and other transportation services. The remaining affiliated amounts are immaterial.
(e)The alternative revenue for OPCo is primarily the $48 million reduction in revenue relating to the Ohio tax settlement. See the “Ohio Tax Reform” section of Note 4 for additional information.
(f)Amounts include affiliated and nonaffiliated revenues.





  Nine Months Ended September 30, 2018
  AEP Texas AEPTCo (a) APCo I&M OPCo PSO SWEPCo
  (in millions)
Retail Revenues:              
Residential Revenues $453.6
 $—
 $1,017.2
 $559.4
 $1,258.4
 $531.4
 $512.3
Commercial Revenues 328.5
 —
 443.8
 373.7
 632.8
 317.9
 378.6
Industrial Revenues 79.7
 —
 455.9
 424.1
 287.8
 220.4
 248.1
Other Retail Revenues 19.1
 —
 57.6
 5.4
 9.8
 64.9
 6.4
Total Retail Revenues 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)The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. For additional details on revisions made to AEPTCo’s financial statements, see Note 1- Significant Accounting Matters.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo is $100 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts are immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo is $448 million. The remaining affiliated amounts are immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M iswas $57 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts arewere immaterial.
(e)The alternative revenue for OPCo iswas primarily the $48 million reduction in revenue relating to the Ohio taxTax Reform settlement. See the “Ohio Tax Reform” section of Note 4 for additional information.
(f)Amounts include affiliated and nonaffiliated revenues.


Performance Obligations

AEP has performance obligations as part of its normal course of business. A performance obligation is a promise to transfer a distinct good or service, or a series of distinct goods or services that are substantially the same and have the same pattern of transfer to a customer. The invoice practical expedient within the accounting guidance for “Revenue from Contracts with Customers” allows for the recognition of revenue from performance obligations in the amount of consideration to which there is a right to invoice the customer and when the amount for which there is a right to invoice corresponds directly to the value transferred to the customer.

The purpose of the invoice practical expedient is to depict an entity’s measure of progress toward completion of the performance obligation within a contract and can only be applied to performance obligations that are satisfied over time and when the invoice is representative of services provided to date. AEP subsidiaries elected to apply the invoice practical expedient to recognize revenue for performance obligations satisfied over time as the invoices from the respective revenue streams are representative of services or goods provided to date to the customer. Performance obligations for AEP’s subsidiaries are summarized as follows:



Retail Revenues

AEP’s subsidiaries within the Vertically Integrated Utilities and Transmission and Distribution Utilities segments have performance obligations to generate, transmit and distribute electricity for sale to rate-regulated retail customers. The performance obligation to deliver electricity is satisfied over time as the customer simultaneously receives and consumes the benefits provided. Revenues are variable as they are subject to the customer’s usage requirements.

Rate-regulated retail customers typically have the right to discontinue receiving service at will, therefore these contracts between AEP’s subsidiaries and their customers for rate-regulated services are generally limited to the services requested and received to date for such arrangements. Retail customers are generally billed on a monthly basis, and payment is typically due within 15 to 20 days after the issuance of the invoice. Payments from Retail Electric Providers are due to AEP Texas within 35 days.

Wholesale Revenues - Generation

AEP’s subsidiaries within the Vertically Integrated Utilities and Generation & Marketing segments have performance obligations to sell electricity to wholesale customers from generation assets in PJM, SPP and ERCOT. The performance obligation to deliver electricity from generation assets is satisfied over time as the customer simultaneously receives and consumes the benefits provided. Wholesale generation revenues are variable as they are subject to the customer’s usage requirements.

AEP’s subsidiaries within the Vertically Integrated Utilities and Generation & Marketing segments also have performance obligations to stand ready in order to promote grid reliability. Stand ready services are sold into PJM’s RPM capacity market. RPM entails a base auction and at least three incremental auctions for a specific PJM delivery year, with the incremental auctions spanning three years. The performance obligation to stand ready is satisfied over time and the consideration for which is variable until the occurrence of the final incremental auction, at which point the performance obligation becomes fixed.

Payments from the RTO for stand ready services are typically received within one week from the issuance of the invoice, which is typically issued weekly. Gross margin resulting from generation sales within the Vertically Integrated Utilities segment are primarily subject to margin sharing agreements with customers and vary by state, where the revenues are reflected gross in the disaggregated revenue tables above.

APCo has a performance obligation to supply wholesale electricity to KGPCo through a purchased power agreement. The FERC regulates the cost-based wholesale power transactions between APCo and KGPCo. The purchased power agreement includes a component for the recovery of transmission costs under the FERC OATT. The transmission cost component of purchased power is cost-based and regulated by the Tennessee Regulatory Authority. APCo’s performance obligation under the purchased power agreement is satisfied over time as KGPCo simultaneously receives and consumes the wholesale electricity. APCo’s revenues from the purchased power agreement are presented within the Generation Revenues line in the disaggregated revenue tables above.

Wholesale Revenues - Transmission

AEP’s subsidiaries within the Vertically Integrated Utilities, Transmission and Distribution Utilities and AEP Transmission Holdco segments have performance obligations to transmit electricity to wholesale customers through assets owned and operated by AEP subsidiaries. The performance obligation to provide transmission services in PJM, SPP and ERCOT encompass a time frame greater than a year, where the performance obligation within each RTO is partially fixed for a period of one year or less. Payments from the RTO for transmission services are typically received within one week from the issuance of the invoice, which is issued monthly for SPP and ERCOT and weekly for PJM.

AEP subsidiaries within the PJM and SPP regions collect revenues through transmission formula rates. The FERC-approved rates establish the annual transmission revenue requirement (ATRR) and transmission service rates for transmission owners. The formula rates establish rates for a one year period and also include a true-up calculation for


the prior year’s billings, allowing for over/under-recovery of the transmission owner’s ATRR. The annual true-ups meet the definition of alternative revenues in accordance with the accounting guidance for “Regulated Operations,” and are therefore presented as such in the disaggregated revenue tables above. AEP subsidiaries within the ERCOT region collect revenues through a combination of base rates and interim Transmission Costs of Services filings that are approved by the PUCT.

APCo, I&M, KGPCo, KPCo, OPCo and WPCo (AEP East Companies) are parties to the Transmission Agreement (TA), which defines how transmission costs are allocated among the AEP East Companies on a 12-month average coincident peak basis. PSO, SWEPCo and AEPSC are parties to the Transmission Coordination Agreement (TCA) by and among PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two AEP utility subsidiaries. AEPTCo is a load serving entity within the PJM and SPP regions providing transmission services to affiliates in accordance with the OATT, TA and TCA. Affiliate revenues as a result of the respective TA and the TCA are reflected as Transmission Revenues in the disaggregated revenue tables above.

Marketing, Competitive Retail and Renewable Revenues

AEP’s subsidiaries within the Generation & Marketing segment have performance obligations to deliver electricity to competitive retail and wholesale customers. Performance obligations for marketing, competitive retail and renewable offtake sales are satisfied over time as the customer simultaneously receives and consumes the benefits provided. Revenues are primarily variable as they are subject to customer’s usage requirements; however, certain contracts mandate a delivery of a set quantity of electricity at a predetermined price, resulting in a fixed performance obligation.

Payment terms under marketing arrangements typically follow standard Edison Electric Institute and International Swaps and Derivatives Association terms, which call for payment in 20 days. Payments for competitive retail and offtake arrangements for renewable assets range from 15 to 60 days and are dependent on the product sold, location and the creditworthiness of customer. Invoices for marketing arrangements, competitive retail and offtake arrangements for renewable assets are issued monthly.

Fixed Performance Obligations


The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of September 30, 2018.2019. 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

Company 2018 2019-2020 2021-2022 After 2022 Total
  (in millions)
AEP $246.1
 $258.7
 $164.8
 $349.0
 $1,018.6
AEP Texas 74.2
 —
 —
 —
 74.2
AEPTCo 166.8
 —
 —
 —
 166.8
APCo 30.7
 32.9
 25.5
 11.6
 100.7
I&M 6.3
 3.0
 2.9
 1.4
 13.6
OPCo 21.5
 12.4
 —
 —
 33.9
PSO 4.5
 —
 —
 —
 4.5
SWEPCo 9.1
 —
 —
 —
 9.1


Contract Assets and Liabilities


Contract assets are recognized when the Registrants have a right to consideration that is conditional upon the occurrence of an event other than the passage of time, such as future performance under a contract. The Registrants did not have any 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 any 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 1213 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




Company September 30, 2018 January 1, 2018
  (in millions)
AEPTCo $71.9
 $47.1
APCo 54.1
 35.6
I&M 24.7
 15.1
OPCo 42.5
 26.1
PSO 17.1
 6.1
SWEPCo 20.3
 11.0


Contract Costs

Contract costs to obtain or fulfill a contract for AEP subsidiaries within the Generation & Marketing segment are accounted for under the guidance for “Other Assets and Deferred Costs” and presented as a single asset and are neither bifurcated nor reclassified between current and noncurrent assets on the Registrants’ balance sheets. Contract costs to acquire a contract are amortized in a manner consistent with the transfer of goods or services to the customer in Other Operation on the Registrants’ income statements. The Registrants did not have material contract costs as of September 30, 2018.


CONTROLS AND PROCEDURES


During the third quarter of 2018,2019, 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, 2018,2019, 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 20182019 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 Annual Report on Form 10-K for the year ended December 31, 20172018 includes a detailed discussion of risk factors.  As of September 30, 2018,2019, there have been no material changes to the risk factor appearingfactors previously disclosed in the 20172018 Annual Report on Form 10-K under the heading set forth below is supplemented and updated as follows:10-K.

Certain elements of AEP’s transmission formula rates have been challenged, which could result in lowered rates and/or refunds of amounts previously collected and thus have an adverse effect on AEP’s business, financial condition, results of operations and cash flows. (Applies to all Registrants other than AEP Texas)

AEP provides transmission service under rates regulated by the FERC. The FERC has approved the cost-based formula rate templates used by AEP to calculate its respective annual revenue requirements, but it has not expressly approved the amount of actual capital and operating expenditures to be used in the formula rates. All aspects of AEP’s rates accepted or approved by the FERC, including the formula rate templates, the rates of return on the actual equity portion of its respective capital structures and the approved targeted capital structures, are subject to challenge by interested parties at the FERC, or by the FERC on its own initiative. In addition, interested parties may challenge the annual implementation and calculation by AEP of its projected rates and formula rate true up pursuant to its approved formula rate templates under AEP’s formula rate implementation protocols. If a challenger can establish that any of these aspects are unjust, unreasonable, unduly discriminatory or preferential, then the FERC will make appropriate prospective adjustments to them and/or disallow any of AEP’s inclusion of those aspects in the rate setting formula.

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

In April 2018, certain intervenors filed comments at the FERC recommending a base ROE of 8.48% and a one-time refund of $184 million. The FERC trial staff filed comments recommending a base ROE of 8.41% and one-time refund of $175 million. Another intervenor recommended the refund be calculated in accordance with the base ROE that will ultimately be approved by the FERC. In May 2018, management filed reply comments providing further support for the 9.85% base ROE agreed to in the settlement agreement. Management believes its financial statements adequately address the impact of the settlement agreement.  If the FERC orders revenue reductions in excess of the terms of the settlement agreement, it could reduce future net income and cash flows and impact financial condition.  A decision from the FERC is pending.

In June 2017, a similar complaint was filed with the FERC claiming that the base ROE used by AEP’s transmission owning subsidiaries within SPP in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36%, effective upon the date of the complaint through September 5, 2018. In September 2018, the same parties filed another complaint at the FERC that states the base return on common equity used by AEP’s transmission owning subsidiaries within SPP in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.71%, effective upon the date of the second complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.



End-use consumers and entities supplying electricity to end-use consumers may also attempt to influence government and/or regulators to change the rate setting methodologies that apply to AEP, particularly if rates for delivered electricity increase substantially.

OVEC may require additional liquidity and other capital support.  (Applies to AEP, APCo, I&M and OPCo)

AEP and several nonaffiliated utility companies own OVEC. The Inter-Company Power Agreement (ICPA) defines the rights and obligations and sets the power participation ratio of the parties to it.  Under the ICPA, parties are entitled to receive and are obligated to pay for all OVEC capacity (approximately 2,400 MWs) in proportion to their respective power participation ratios. The aggregate power participation ratio of APCo, I&M and OPCo is 43.47%. If a party fails to make payments owed by it under the ICPA, OVEC may not have sufficient funds to honor its payment obligations, including its ongoing operating expenses as well as its indebtedness. As of September 30, 2018, OVEC has outstanding indebtedness of approximately $1.4 billion, of which APCo, I&M, and OPCo are collectively responsible for $611 million through the ICPA. Although they are not an obligor or guarantor, APCo, I&M, and OPCo are responsible for their respective ratio of OVEC’s outstanding debt through the ICPA.

FirstEnergy Solutions, a nonaffiliated party, whose aggregate power participation ratio is 4.85% under the ICPA, has filed a petition seeking protection under bankruptcy law.  Bankruptcy filings typically trigger review of the petitioner’s contractual obligations, including, in this instance, the ICPA.  Because the ICPA is subject to FERC approval and jurisdiction, prior to the bankruptcy petition OVEC made a filing at FERC seeking, among other objectives, to confirm FERC’s jurisdiction.  Litigation related to these filings continues.  In addition, as a result of these and prior related developments, OVEC’s credit ratings have been impacted.

If OVEC does not have sufficient funds to honor its payment obligations, there is risk that APCo, I&M and/or OPCo may need to make payments in addition to their power participation ratio payments.  Further, if OVEC’s indebtedness is accelerated for any reason, there is risk that APCo, I&M and/or OPCo may be required to pay some or all of such accelerated indebtedness in amounts equal to their aggregate power participation ratio of 43.47%.  Also, as a result of the credit rating agencies’ actions, OVEC’s ability to access capital markets on terms as favorable as previously may diminish and its financing costs will increase.


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


None


Item 3.  Defaults Upon Senior Securities


None


Item 4.  Mine Safety Disclosures


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


The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act. Exhibit 95 “Mine Safety Disclosure Exhibit” contains the notices of violation and proposed assessments received by DHLC under the Mine Act for the quarter ended September 30, 2018.2019.



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
Form 8-K Exhibit 4(a) dated September 9, 2019

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
410.1 First Amendment to FourthAEP System Incentive Compensation Deferral Plan Amended and Restated Credit Agreement datedeffective June 30, 20161, 2019 
X
              
1010.2 AEP Aircraft Time SharingTimesharing Agreement dated September 17, 2018October 1, 2019 between American Electric Power Service Corporation and Mr.Nicholas K. Akins 
X
              
12Computation of Consolidated Ratio of Earnings to Fixed Charges
X
X
X
X
X
X
X
X
31(a) Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 
X
 
X
 
X
 
X
 
X
 
X
 
X
 
X
31(b) Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 
X
 
X
 
X
 
X
 
X
 
X
 
X
 
X
32(a) Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code 
X
 
X
 
X
 
X
 
X
 
X
 
X
 
X
32(b) Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code 
X
 
X
 
X
 
X
 
X
 
X
 
X
 
X
95 Mine Safety Disclosures               
X
101.INS XBRL Instance Document XXXXXXXXThe 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 Schema X X X X X X X X
101.CAL XBRL Taxonomy Extension Calculation Linkbase X X X X X X X X
101.DEF XBRL Taxonomy Extension Definition Linkbase X X X X X X X X
101.LAB XBRL Taxonomy Extension Label Linkbase X X X X X X X X
101.PRE XBRL Taxonomy Extension Presentation Linkbase X X X X X X X X
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 25, 201824, 2019


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