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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 March 31, 20182019
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from ____ to ____
Commission Registrants; States of Incorporation; I.R.S. Employer
File Number Address and Telephone Number Identification Nos.
     
1-3525 AMERICAN ELECTRIC POWER COMPANY, 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, Ohio 43215-2373  
  Telephone (614) 716-1000  
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. Yes x     No ¨
Indicate by check mark whether the registrants have submitted electronically and posted on their corporate websites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). Yes x     No ¨
Indicate by check mark whether American Electric Power Company, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
  
Large Accelerated filer xAccelerated filer ¨Non-accelerated filer ¨   (Do not check if a smaller reporting company)
       
Smaller reporting company ¨
 
Emerging growth company ¨
   
Indicate by check mark whether AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, non-accelerated filers, smaller reporting companies, or emerging growth companies.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
  
Large Accelerated filer ¨             Accelerated filer ¨             Non-accelerated filer x   (Do not check if a smaller reporting company)
       
Smaller reporting company ¨
 
Emerging growth company ¨
   
 
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 ¨No x
AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.








 
Number of Shares
of Common Stock
Outstanding of the
Registrants as of
 April 26, 201825, 2019
  
American Electric Power Company, Inc.492,523,470493,435,530

 ($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
March 31, 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
4634
     
AEP Texas Inc. and Subsidiaries: 
 Management’s Narrative Discussion and Analysis of Results of Operations
5341
 Condensed Consolidated Financial Statements
5644
     
AEP Transmission Company, LLC and Subsidiaries: 
 Management’s Narrative Discussion and Analysis of Results of Operations
6351
 Condensed Consolidated Financial Statements
6552
     
Appalachian Power Company and Subsidiaries: 
 Management’s Narrative Discussion and Analysis of Results of Operations
7158
 Condensed Consolidated Financial Statements
7460
     
Indiana Michigan Power Company and Subsidiaries: 
 Management’s Narrative Discussion and Analysis of Results of Operations
8167
 Condensed Consolidated Financial Statements
8469
     
Ohio Power Company and Subsidiaries: 
 Management’s Narrative Discussion and Analysis of Results of Operations
9176
 Condensed Consolidated Financial Statements
9479
     
Public Service Company of Oklahoma: 
 Management’s Narrative Discussion and Analysis of Results of Operations
10186
 Condensed Financial Statements
10488
     
Southwestern Electric Power Company Consolidated: 
 Management’s Narrative Discussion and Analysis of Results of Operations
11195
 Condensed Consolidated Financial Statements
11497
     
Index of Condensed Notes to Condensed Financial Statements of Registrants
120103
     
Controls and Procedures
202183




Part II.  OTHER INFORMATION 
     
 Item 1.Legal Proceedings
203184
 Item 1A.Risk Factors
203184
 Item 2.Unregistered Sales of Equity Securities and Use of Proceeds
204184
Item 3.Defaults Upon Senior Securities
184
 Item 4.Mine Safety Disclosures
204184
 Item 5.Other Information
204184
 Item 6.  Exhibits:Exhibits
205185
Exhibit 10(a)
Exhibit 10(b)
Exhibit 12
Exhibit 31(a)
Exhibit 31(b)
Exhibit 32(a)
Exhibit 32(b)
Exhibit 95
Exhibit 101.INS
Exhibit 101.SCH
Exhibit 101.CAL
Exhibit 101.DEF
Exhibit 101.LAB
Exhibit 101.PRE
     
SIGNATURE  
206186
     
     
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.
AEPEP AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, hedging activities, asset management and commercial and industrial sales in the deregulated Ohio and Texas markets.
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 Accumulated Deferred Income TaxesADIT for ratemakingrate-making purposes.
AROAsset Retirement Obligations.
ASC Accounting Standard Codification.
ASU Accounting Standards Update.
CAA Clean Air Act.
CAIRCLECO Clean Air Interstate Rule.Central Louisiana Electric Company, a nonaffiliated utility company.
CO2
 Carbon dioxide and other greenhouse gases.
Conesville PlantA generation plant consisting of three coal-fired generating units totaling 1,695 MW located in Conesville, Ohio. The plant is jointly-owned by AGR and a nonaffiliate.
Cook Plant Donald C. Cook Nuclear Plant, a two-unit, 2,278 MW nuclear plant owned by I&M.
CSAPRCross-State Air Pollution Rule.
CWAClean Water Act.
CWIP Construction Work in Progress.
DCC Fuel DCC Fuel VI LLC, DCC Fuel VII, DCC Fuel VIII, DCC Fuel IX, DCC Fuel X, DCC Fuel XI and DCC Fuel XIXII, consolidated variable interest entitiesVIEs formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
Desert SkyDesert Sky Wind Farm, a 160.5 MW wind electricity generation facility located on Indian Mesa in Pecos County, Texas.
DHLCDolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.


i




Term Meaning
   
DHLCDolet 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 ADITExcess accumulated deferred income taxes.
FASB Financial Accounting Standards Board.
Federal EPA United States Environmental Protection Agency.
FERC Federal Energy Regulatory Commission.
FGD Flue Gas Desulfurization or scrubbers.
FIPFederal Implementation Plan.
FTR Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP Accounting Principles Generally Accepted in the United States of America.
Global 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.
KPSC Kentucky Public Service Commission.
kVKilovolt.
KWh Kilowatthour.Kilowatt-hour.
LPSC Louisiana Public Service Commission.
Market Based MechanismMATS An order from the LPSC established to evaluate proposals to construct or acquire generating capacity. The LPSC directs that the market based mechanism shall be a request for proposal competitive solicitation process.Mercury and Air Toxic Standards.
MISO 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.
NO2
 Nitrogen dioxide.
NOx
 Nitrogen oxide.
NPDESNational Pollutant Discharge Elimination System.
NSR New Source Review.
OATT Open Access Transmission Tariff.
OCCCorporation Commission of the State of Oklahoma.


ii




Term Meaning
   
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 StationA single unit coal-fired generation plant totaling 650 MW located in Vernon, Texas. The plant is jointly-owned by AEP Texas, PSO and certain nonaffiliated entities.
OPCo Ohio Power Company, an AEP electric utility subsidiary.
OPEB Other Postretirement Benefit Plans.Benefits.
OSSOff-system Sales.
OTC Over the counter.Over-the-counter.
OVEC Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
Parent American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.
PJM Pennsylvania – New Jersey – Maryland regional transmission organization.
PM Particulate Matter.
PPA Purchase Power and Sale Agreement.
PSO Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO Public Utilities Commission of Ohio.
PUCT Public Utility Commission of Texas.
RacineA generation plant consisting of two hydroelectric generating units totaling 47.5 MWs located in Racine, Ohio and owned by AGR.
Registrant Subsidiaries AEP subsidiaries which are SEC registrants: AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
Registrants SEC registrants: AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
Risk Management Contracts Trading and nontradingnon-trading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant A generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana. AEGCo and I&M jointly-own Unit 1. In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2.
ROEReturn on Equity.
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.
SCR 
Selective Catalytic Reduction, NOx reduction technology at Rockport Plant.
SEC U.S. Securities and Exchange Commission.
SEET Significantly Excessive Earnings Test.
SIPState Implementation Plan.
SNF Spent Nuclear Fuel.
SO2
 Sulfur dioxide.
SPP Southwest Power Pool regional transmission organization.
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 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.

iii


TermMeaning
Texas Restructuring Legislation Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC Formerly AEP Texas North Company, now a division of AEP Texas.
TRATennessee Regulatory Authority.
Transition Funding AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated variable interest entitiesVIE formed for the purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation.

iii


TermMeaning
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 150 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.
UMWA United 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 which includesthat was cancelled in July 2018. The estimated $4.5 billion project included the acquisition of a wind generation facility, totaling approximately 2,000 MWMWs 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.
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•Availability of necessary generation capacity, the performance of generation plants and the availability of fuel, including processed nuclear fuel, parts and service from reliable vendors.fuel.
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 nuclear fuel.
Ÿ•Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance and excess accumulated deferred income taxes.compliance.
Ÿ•Resolution of litigation.
Ÿ•The ability to constrain operation and maintenance costs.
Ÿ•Prices and demand for power generated and sold at wholesale.
Ÿ•Changes in technology, particularly with respect to energy storage and new, developing, alternative or distributed sources of generation.
Ÿ•The ability to recover through rates any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives.
Ÿ•Volatility and changes in markets for capacity and electricity, coal and other energy-related commodities, particularly changes in the price of natural gas.
Ÿ•Changes in utility regulation and the allocation of costs within regional transmission organizations,RTOs including ERCOT, PJM and SPP.
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 pronouncements 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 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 first quarter of 2018 increased2019 decreased by 1.5%0.3% from the first quarter of 2017.2018. AEP’s first quarter 20182019 industrial sales volumes increased 2.5%decreased 0.4% compared to the first quarter of 2017.2018. The growthdecline in industrial sales was spread across most industries and mostprimarily in the east vertically integrated operating companies. Weather-normalized residential andsales increased 0.9% while weather-normalized commercial sales increased 1.4% and 0.5%decreased 1.7% in the first quarter of 2018,2019, respectively, from the first quarter of 2017.2018.

Federal Tax ReformRegulatory Matters

In December 2017, legislation referred to as Tax Reform was signed into law. Tax Reform includes significant changes toAEP’s public utility subsidiaries are involved in rate and regulatory proceedings at the Internal Revenue Code of 1986, as amended, (the Code)FERC and had a material impacttheir state commissions.  Depending on the Registrants financial statements in the reporting period of its enactment. Tax Reform lowered the corporate federal income taxoutcomes, these rate from 35% to 21%. Tax Reform provisions related to regulated public utilities generally allow for the continued deductibility of interest expense, eliminate bonus depreciation for certain property acquired after September 27, 2017 and continue certain rate normalization requirements for accelerated depreciation benefits.

The Registrants expect the mechanism and time period to provide the benefits of Tax Reform to customers will continue to vary by jurisdiction. Tax Reform did notregulatory proceedings can have a material impact on net incomeresults of operations, cash flows and possibly financial condition. AEP is currently involved in the first quarter of 2018 and is not expected to have a material impact on future net income. However, the Registrants anticipate a decrease in future cash flows primarily due to the elimination of bonus depreciation, the reduction in the federal tax rate from 35% to 21% and the flow back of excess accumulated deferred income taxes (Excess ADIT). Further, the Registrants expect that access to capital markets will be sufficient to satisfy any liquidity needs that result from any such decrease in future cash flows.following key proceedings. See Note 4 - Rate Matters for additional information.
•
Texas Storm Cost Securitization - In March 2019, AEP Texas filed a request to securitize total estimated distribution-related system restoration costs with the PUCT in the amount of $230 million, which includes estimated carrying costs. A decision by the PUCT is expected in the second quarter of 2019. The remaining $95 million of estimated net transmission-related system restoration costs, including carrying charges, is expected to be recovered through interim transmission filings or an upcoming base rate case.
•
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 ROE would be refunded to customers. 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.
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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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2016 SEET Filing - Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. In 2016, OPCo recorded a 2016 SEET provision of $58 million. In February 2019, the PUCO issued an order that OPCo did not have significantly excessive earnings in 2016. As a result of the order, OPCo reversed the provision in the first quarter of 2019.


Provisional Amounts
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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, which has ordered Appellants to file responses by April 29, 2019. As of March 31, 2019, the net book value of Turk Plant was $1.5 billion, before cost of removal, including materials and supplies inventory and CWIP.


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FERC Transmission Complaint - AEP’s PJM Participants- In 2016, seven parties filed a complaint at the FERC that alleged the base ROE 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 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 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 and increases the cap on the equity portion of the capital structure to 55% from 50%.  In April 2018, an ALJ accepted the interim settlement rates, which were implemented effective January 1, 2018. These interim rates are subject to refund or surcharge, with interest. Also in April 2018, certain intervenors filed comments at the FERC recommending a lower ROE. In March 2019, the intervenors subsequently withdrew their opposition to the settlement and the settling parties filed a joint motion at the FERC seeking approval of this now uncontested settlement. A decision from the FERC is pending.

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FERC Transmission Complaint - AEP’s SPP Participants - In 2017, several parties filed a complaint at the FERC that states 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 ROE used should be reduced from 10.7% to 8.71%, effective upon the date of the second complaint. In March 2019, AEP’s transmission owning subsidiaries within SPP and the complainants filed an unopposed settlement agreement with the FERC that establishes a base ROE of 10% (10.50% inclusive of the RTO incentive adder of 0.5%) effective January 1, 2019. Additionally, refunds, including carrying charges, would be made from the date of the first complaint through December 31, 2018. Refunds for the period prior to 2019 would be made at the time of the 2019 true-up of 2018 rates. Refunds from January 2019 onward would begin following a FERC approval of the settlement and conclude with the 2020 true-up of 2019 rates. A decision from the FERC is pending.

The Registrants applied Staff Accounting Bulletin 118 (SAB 118), issued byOhio House of Representatives introduced a clean energy bill in April 2019, which would offer incentives for power-generating facilities with zero- or reduced carbon emissions.  The Ohio bill also proposes to eliminate the SEC staffcurrent energy efficiency and renewable mandates for Ohio electric utilities in December 2017, and made reasonable estimatesorder to pay for the measurement and accounting of the effects of Tax Reform which are reflected in the financial statements as provisional amounts based on the best information available. While the Registrants were able to make reasonable estimates ofzero/reduced emission credits.  Management is analyzing 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 maythis new legislation but it could be issued by the IRS that may impact management’s interpretationsignificantly amended before passage and assumptions utilized. The Registrants expect to complete the analysis of the provisional items during the second half of 2018.

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

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



Excess Accumulated Deferred Income Taxes - Pending Rate Reductions

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

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

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

Merchant Generation Assets

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

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


In December 2017, AEP signed an amendment to the Cardinal Station Agreement with Buckeye Power Incorporated, which terminates certain commercial arrangements between the parties and transitions management oversight and administrative support of the Cardinal facility from AEP to Buckeye Power Incorporated.  The amendment required approval from Rural Utilities Service and the FERC, which were obtained in February 2018. The new amendment became effective March 2018 and did not have a material impact on net income, cash flows or financial condition.

Management continues
Utility Rates and Rate Proceedings

The Registrants file rate cases with their regulatory commissions seeking increases or decreases to evaluate potential alternatives for its remaining merchant generation assets. These potential alternatives may include, but are not limitedtheir electric service rates to transfer or salerecover their costs and earn a fair return on their investments. The outcomes of AEP’s ownership interests or a wind downthese regulatory proceedings impact the Registrants’ current and future results of merchant coal-fired generation fleet operations. Management has not set a specific time frame for a decision on these assets. These alternatives could result in additional losses which could reduce future net income andoperations, cash flows and impact financial condition.position.


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

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

Pending Base Rate Case Proceedings
          Commission Staff/
    Filing Requested Revenue Requested Intervenor Range of
Company Jurisdiction Date Requirement Increase ROE Recommended ROE
      (in millions)    
SWEPCo Arkansas February 2019 $75.0
 10.5% (a)

(a) Commission Staff/Intervenor direct testimony to be filed by July 16, 2019.

Renewable Generation Portfolio


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




Contracted Renewable Generation Facilities


AEP continues to develop its renewable portfolio within the Generation & Marketing segment.  Activities include working directly with wholesale and large retail customers to provide tailored solutions based upon market knowledge, technology innovations and deal structuring which may include distributed solar, wind, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other forms of cost reducing energy technologies.  The Generation & Marketing segment also develops and/or acquires large scale renewable generation projects that are backed with long-term contracts.contracts with creditworthy counterparties.  As of March 31, 2018,2019, subsidiaries within AEP’s Generation & Marketing segment havehad approximately 400438 MWs of contracted renewable generation projects in operation.in-service.  In addition, as of March 31, 2018,2019, these subsidiaries havehad approximately 1056 MWs of new renewable generation projects under construction with total estimated capital costs of $26$78 million related to these projects.


In JanuaryDecember 2018, AEP admittedsigned a Purchase and Sale Agreement with a nonaffiliate asto acquire a member of Desert Sky Wind Farm75% interest in a 302 MW wind generation project located in West Texas upon completion. Management expects the transaction to close and the wind generation facility to be in-service in mid-2019.

In April 2019, AEP acquired Sempra Renewables LLC and Trent Wind Farm LLC (collectively the “LLCs”)its 724 MWs of wind generation and battery assets for approximately $1.1 billion, subject to ownworking capital adjustments. AEP paid $584 million in cash and repower Desert Sky and Trent, which is expected to be completed in 2018.  The nonaffiliated member contributed full turbine sets to eachassumed approximately $358 million of existing project in exchange for a 20.1% interest in the LLCs. AEP’s 79.9% sharedebt obligations of the LLCs, or 248 MWs, represents $232non-consolidated joint ventures. Additionally, the acquisition includes the recognition of noncontrolling tax equity interest of an estimated $110 million of additional estimated capital, of which $131 million has been incurred and recorded in CWIP as of March 31, 2018. AEP is subject to a put and a call option afterthe acquisition date associated with certain conditions are met, either of which would liquidate the nonaffiliated member’s interest.acquired wind farms. The wind generation portfolio includes seven wholly or jointly-owned wind farms with long-term PPAs for 100% of their energy production. See “Acquisitions” section of Note 13 - Variable Interest Entities6 for additional information.



Regulated Renewable Generation Facilities


In July 2017, APCoSeptember 2018, OPCo, consistent with its commitment in the previously approved PPA application, submitted filingsa filing with the Virginia SCC and the WVPSC requesting regulatory approvalPUCO demonstrating a need for up to acquire two wind generation facilities totaling approximately 225900 MWs of wind generation. The wind generating facilities are locatedeconomically beneficial renewable resources in West Virginia and Ohio and, if approved, are anticipated to be in-service in the second half of 2019. APCo will assume ownership of the facilities at or near the anticipated in-service date. APCo currently plans to sell theOhio. This filing was followed by a separate filing for two solar Renewable Energy Certificates associated with the generation from these facilities. In December 2017, the WVPSC staff and an industrial intervenor filed testimony in West Virginia and the Virginia SCC staff filed testimony in Virginia arguing that APCo’s forecast of natural gas and energy prices was too high and, with the exception of the WVPSC staff’s recommended approval of the facility located in West Virginia, did not support approval of APCo’s acquisition of the facilities.Purchase Agreements totaling 400 MWs. In January 2018, APCo filed supplemental testimony with the WVPSC to address changes in the economics of the wind projects as a result of Tax Reform. A hearing at the WVPSC was held in March 2018 and briefs were filed in April 2018. The WVPSC2019, PUCO staff the industrial intervenor and the Consumer Advocate Division of the Public Service Commission all recommended that the WVPSC deny APCO’s request for approvalPUCO reject OPCo’s request. If approved, the solar generation facilities are expected to be operational by the end of the wind farms. Also 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.2021.


In July 2017,January 2019, PSO and SWEPCo submitted filings with the OCC, LPSC, APSCissued requests for proposals to acquire up to 1,000 MWs and PUCT requesting various regulatory approvals needed for the companies to proceed with the Wind Catcher Project. The Wind Catcher Project includes the acquisition of a wind generation facility, totaling approximately 2,0001,200 MWs of wind generation, and the construction of a generation interconnection tie-line totaling approximately 380 miles. Total investment for the project is estimated to be $4.5 billion and will serve both retail and FERC wholesale load. PSO and SWEPCo will have a 30% and 70% ownership share, respectively, in these assets.respectively. The wind generating facility is located in Oklahomageneration projects would be subject to regulatory approval and if approved by all state commissions, is anticipated to beplaced in-service by the end of 2020. In July 2017,2021.

Racine

A project to reconstruct a defective dam structure at Racine began in the LPSC approved SWEPCo’s request for an exemptionfirst quarter of 2017.  Due to a significant increase in estimated costs to complete the Market Based Mechanism. In Augustreconstruction project, AEP recorded impairments in 2017 and December 2017, the OCC denied the Oklahoma Attorney General’s respective August2018.  See Note 7 - Dispositions and December 2017 motions to dismiss. Also in December 2017, the companies filed a request at the FERC to transfer the wind generation facility to PSO and SWEPCo upon its construction by a third party, which was approved in April 2018. The transfer remains subject to the approval of the project at the respective state commissions. Parties’ testimony filedImpairments in the Oklahoma, Texas and Louisiana dockets generally opposes the companies’ request. In February 2018 the ALJ in Oklahoma recommended that PSO’s request for preapproval of future recovery of Wind Catcher Project costs be denied. In March 2018, oral arguments were held before three Oklahoma Commissioners regarding the ALJ report and parties agreed to waive the 240 day statutory deadline for an order to continue the discussions. A non-unanimous settlement agreement was filed in Arkansas in


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

Hurricane Harvey

In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. As rebuilding efforts continue, AEP Texas’ total costs related to this storm are not yet final. AEP Texas’ current estimated cost is approximately $325 million to $375 million, including capital expenditures. AEP Texas has a PUCT approved catastrophe reserve which allows for the deferral of incremental storm expenses as a regulatory asset, and currently recovers approximately $1 million annually through base rates. As of March 31, 2018, the total balance of AEP Texas’ catastrophe reserve deferral is $129 million, inclusive of approximately $105 million of net incremental storm expenses related to Hurricane Harvey. As of March 31, 2018, AEP Texas has recorded approximately $186 million of capital expenditures related to Hurricane Harvey. Also, as of March 31, 2018, AEP Texas has received $10 million in insurance proceeds, which were applied to the regulatory asset and property, plant and equipment. Management, in 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 also be applied to, and will offset, the regulatory asset and property, plant and equipment, as applicable. Management believes the amount recorded as a regulatory asset is probable of recovery and AEP Texas is currently evaluating recovery options for the regulatory asset, including securitization. The standard process for storm cost recovery in Texas requires two filings with the PUCT. Management expects the first filing by the end of third quarter of 2018. If the ultimate costs of the incident are not recovered by insurance or through the regulatory process, it would have an adverse effect on future net income, cash flows and financial condition.

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

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

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



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

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

2016 SEET Filing

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

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

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

A 2016 SEET hearing was held in April 2018 and management expects to receive an order in the second half of 2018. While management believes that OPCo’s adjusted 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s proposed SEET adjustments, including treatment of the Global Settlement issues described above, adjust the comparable risk group or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could negatively affect future SEET filings, reduce future net income and cash flows and impact financial condition. See “2016 SEET Filing” section of Note 4Annual Report 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 technologyReconstruction activities at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NOx from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. TheRacine are estimated cost of the SCR project is $274 million, excluding AFUDC, to be shared equally between I&M and AEGCo.  Ascompleted in the fourth quarter of March 31, 2018, total costs incurred related2019. AEP expects to thisincur additional capital expenditures to complete the reconstruction project, including AFUDC, were approximately $28 million.  The filing included a request for authorization for I&Mat which point the fair value of Racine, as fully operational, is expected to defer its Indiana jurisdictional ownership shareapproximate the amount of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport UPA to I&M and KPCo and will be subject to future regulatory approval for recovery.

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

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


2017 Indiana Base Rate Case

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

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

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

Dolet Hills Lignite Company Operations

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

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

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



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 March 31, 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.

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

2018 Louisiana Formula Rate Filing

In AprilNovember 2018, SWEPCo filed its formula rate plan for test year 2017 withand CLECO announced that the LPSC.  The filing includedDolet Hills Power Station will change to a net $28 million annual increase, whichseasonal operational strategy. DHLC’s mining operation will be effective August 2018.  The filing included a reduction in the federal income tax rate due to Tax Reform. The return of excess deferred income tax benefits to customers will be addressed in a supplemental filing andcontinue year-round but will reduce the $28 million annual increase. The increase includesits lignite output. SWEPCo’s jurisdictional share of Welsh Plant and Flint Creek Plant environmental controls, whose prudence review hearing is scheduled for May 2018. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2017 Kentucky Base Rate Case

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

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


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

2016 Texas Base Rate Case

In December 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $50 million based upon a return on common equity of 9.6%, effective May 2017. The final order also included (a) approval to recover the Texas jurisdictional share of environmental investments placed in service, as of June 30, 2016, at various plants, including Welsh Plant, Units 1 and 3, (b) approval of recovery of, but no return on, the Texas jurisdictional share of the net book value of Welsh Plant, Unit 2, (c) approval of $2investment in the Dolet Hills Power Station is $132 million additional vegetation management expenses and (d) the rejectionmaximum exposure of SWEPCo’s proposed transmission cost recovery mechanism.

As a resulttotal investment in DHLC is $170 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 includes $7 million associated with the lack of return on Welsh Plant, Unit 2Dolet Hills Power Station and $12 million related to other disallowed plant investments, (b) recognized $32 million of additional revenues, for the period of May 2017 through December 2017, that will be surcharged to customersand (c) recognized an additional $7 million of expenses consisting primarily of depreciation expense and vegetation management expense, offset by the deferral of rate case expenses. SWEPCo implemented new rates in February 2018 billings. The $32 million of additional 2017 revenues will be collected by the end of 2018. In March 2018, the PUCT clarified and corrected portions of the final order, without changing the overall decision or amounts of the rate change. This order is subject to appeal as early as the second quarter of 2018. In April 2018, SWEPCo made an income tax rate refund tariff filing which includes an annual revenue reduction of approximately $18 million to reflect the difference between rates collected under the final order and the rates that would be collected under Tax Reform. The filing did not address the return of excess deferred income tax benefits to customers.DHLC.

Virginia Legislation Affecting Earnings Reviews

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

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

FERC Transmission Complaint - AEP’s PJM Participants

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


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

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

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

Modifications to AEP’s PJM Transmission Rates

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

FERC Transmission Complaint - AEP’s SPP Participants

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

Modifications to AEP’s SPP Transmission Rates

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



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

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

Welsh Plant - Environmental Impact

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

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

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

Westinghouse Electric Company Bankruptcy Filing

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


LITIGATION


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




Rockport Plant Litigation


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

AEGCo and I&M.

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

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



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


In July 2017,Thereafter, AEP filed a motion with the U.S. District Court for the Southern District of Ohio in the original NSR litigation, seeking to modify the consent decree to eliminate the obligation to install certain future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that Unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. In November 2017, theThe district court granted the owners’ unopposed motion to stay the lease litigation to afford time for resolution of AEP’s motion to modify the consent decree. 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. See “Proposed Modification of the NSR Litigation Consent Decree” section below for additional information.




Management will continue to defend against the claims. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management is unable to determine a range of potential losses that are 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 facilities, rules governing the beneficial use and disposal of coal combustion by-products, clean water rules and renewal permits for certain water discharges.


AEP is engaged in litigation about environmental issues, was notified of potential responsibility for the clean-up of contaminated sites and incurred costs for disposal of SNF and future decommissioning of the nuclear units.  AEP, along with various industry groups, affected states and other parties challenged some of the Federal EPA requirements in court.  Management is also engaged in the development of possible future requirements including the items discussed below.  Management believes that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.


AEP will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances.  If AEP is unable to 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 the generating units in the AEP System.  Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of March 31, 2018,2019, the AEP System had a total generating capacity of approximately 25,60025,400 MWs, of which approximately 13,50013,200 MWs arewere coal-fired.  Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on the fossil generating facilities. Based upon management estimates, AEP’s investment to meet these existing and proposed requirements ranges from approximately $2.1 billion$650 million to $2.7$1.5 billion through 2025.


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) resolution of the pending motion to modify the NSR consent decree and (g)(h) other factors.  In addition, management is continuingcontinues to evaluate the economic feasibility of environmental investments on both regulated and competitive plants.





The table below represents the plants or units of plants retired in 2016 and 2015 with a remaining net book value. As of March 31, 2018, the net book value before cost of removal, including related materials and supplies inventory, and CWIP balances, of theplants or units listed below was approved for recovery, except for $218 million. Management is seeking or will seek recovery of theplants previously retired that have a remaining net book value as of $218 million in future rate proceedings.March 31, 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
 26.7
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
 13.6
I&M (b) Tanners Creek Plant 995
 27.7
SWEPCo Welsh Plant, Unit 2 528
 50.6
 Welsh Plant, Unit 2 528
 50.6
Total   3,263
 $218.1
   2,268
 $182.1


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


In January 2017, Dayton Power and Light Company announced the future retirementManagement is seeking or will seek recovery of the 2,308 MW Stuart Plant, Units 1-4. The retirement is scheduled for June 2018. Stuart Plant, Units 1-4 are operated by Dayton Power and Light Company and are jointly owned by AGR and nonaffiliated entities. AGR owns 600 MWs ofremaining net book value in future rate proceedings. To the Stuart Plant, Units 1-4. As of March 31, 2018, AGR’sextent the net book value of the Stuart Plant, Units 1-4 was zero.

To the extent existingthese 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 the AEP subsidiaries in the eastern area of the AEP System and the Department of Justice, the Federal EPA, eight northeastern states and other interested parties to settle claims that the AEP subsidiaries violated the NSR provisions of the CAA when they undertook various equipment repair and replacement projects over a period of nearly 20 years.  The consent decree’s terms include installation of environmental control equipment on certain generating units, a declining cap on SO2 and 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 Ohio 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.  AEP also proposed to retire Conesville Plant, Units 5 and 6 by December 31, 2022 and to retire one unit at Rockport Plant by December 31, 2028. Plaintiffs opposed AEP’s motion.


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


modifications to the consent decree. AEP was directed to file a detailed statement of the specific relief requested to address the changed circumstances at Rockport andPlant, Unit 2. In September 2018, the opposing parties were provided with an opportunitydistrict court granted AEP’s unopposed motion to respond thereto. Thestay further proceedings on the pending motion remains pending and a decision fromto modify the court is expected in 2018.consent decree to facilitate settlement discussions among the parties.


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 Contingenciessection above for additional information.


Clean Air Act Requirements


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

NAAQS

National 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. States are still in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the 2010 SO2 NAAQS.

In December 2017,2016, the Federal EPA published finalcompleted 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.

The Federal EPA finalized non-attainment designations for certain areas’ compliance with the 2010 SO2 NAAQS. States may develop additional requirements for AEP’s facilities as a result of these designations. In April 2017, the2015 ozone standard in 2018. The Federal EPA requested a stayhas confirmed that for states included in the CSAPR program, there are no additional interstate transport obligations, as all areas of proceedingsthe country are expected to attain the 2008 ozone standard before 2023. Challenges to the 2015 ozone standard are pending in the U.S. Court of Appeals for the District of Columbia Circuit where challenges toCircuit. In 2018, the Federal EPA proposed final requirements for implementing the 2015 ozone standard, are pending, to allow reconsideration of that standard by the new administration. The Federal EPA initially announced a one-year delaywhich have also been challenged in the designationU.S. Court of ozone non-attainment areas, but withdrew that decision. In December 2017, the Federal EPA issued a notice of data availability and requested public comment on recommended designations for compliance with the 2015 ozone standard. In March 2018, the Federal EPA responded to additional data regarding certain areas submitted by Texas. The Federal EPA anticipates completing the designations process within 120 days of providing notice to the states. The Federal EPA has also issued information to assist the states in developing plans that address their obligations under the interstate transport provisions of the CAA. State implementation plansAppeals for the 2015 ozone standard are due in October 2018.District of Columbia Circuit. Management cannot currently predict the nature, stringency or timing of additional requirements for AEP’s facilities based on the outcome of these activities.




Regional Haze


The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA’s requirement that certain facilities install best available retrofit technology (BART) willwould address regional haze in federal parks and other protected areas.  BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants.  CAVR will be implemented through SIPs or if SIPs are not adequate or are not developed on schedule, through FIPs.  In January 2017, the Federal EPA revised the rules governing submission of SIPs to implement the visibility programs, including a provision that postpones the due date for the next comprehensive SIP revisions until 2021. Petitions for review of the final rule revisions have been filed in the U.S. Court of Appeals for the District of Columbia Circuit.


TheIn 2012, the Federal EPA proposed disapproval of a portion of the regional haze SIPsSIP in a few states, including Arkansas and Texas.finalized a FIP in 2016. In March 2012, the Federal EPA disapproved certain portions of the Arkansas regional haze SIP. In April 2015, the Federal EPA published a proposed FIP to replace the disapproved portions, including revised BART determinations for the Flint Creek Plant that were consistent with the environmental controls under construction. In September 2016, the Federal EPA published a final FIP that retains its BART determinations, but accelerates the schedule for implementation of certain required controls. The final rule is being challenged in the courts. In March 2017, the Federal EPA filed a motion that was granted by the U.S. Court of Appeals for the Eighth Circuit to hold the case in abeyance for 90 days to allow the parties to engage in settlement negotiations. Arkansas issued a proposed SIP revision to allow sources to participate in the CSAPR ozone season program in lieu of the source-specific NOx BART requirements in the FIP, and in 2018, the Federal EPA has approved that SIPthe revision. Arkansas issuedfinalized a second proposalseparate action in 2017 to revise the SO2 BART determinations, anddeterminations. In 2018, the public comment period on that action has closed. Federal EPA proposed to approve the Arkansas SO2 BART determinations. SWEPCo’s Flint Creek Plant is already in compliance with the applicable requirements.

The Federal EPA has asked the Eighth Circuit to continue to hold litigation in abeyance to facilitate settlement discussions. Arkansas and other affected parties filed motions to stay the compliance deadlines pending further action from the Federal EPA and the motion was granted. Management cannot predict the outcome of these proceedings.

In January 2016, the Federal EPAalso disapproved portions of the Texas regional haze SIP and promulgated a final FIP that did not include any BART determinations. That rule was challenged and stayed by the U.S. Court of Appeals for the Fifth Circuit. The parties engaged in a settlement discussion but were unable to reach an agreement.SIP. In March 2017, the U.S. Court of Appeals for the Fifth Circuit granted partial remand of the final rule. In January 2017, the Federal EPA proposed source-specific BART requirements for SO2 from sources in Texas, including Welsh Plant, Unit 1. Management submitted comments on the proposal and engaged in discussions with the Texas Commission on Environmental Quality (TCEQ) regarding the development of an alternative to source-specific BART. In September 2017, the Federal EPA issued a final rule withdrawing Texas from the annual CSAPR budget programs and reaffirming CSAPR as a BART alternative. The Federal EPA then issued a separate rule finalizing the regional haze requirements for electric generating units in Texas and confirmed TCEQ’s determination that no new PM limitations are required for regional haze. The Federal EPA also finalized a FIP that allows participation in the CSAPR ozone season program to satisfy the NOx regional haze obligations for electric generating units.units in Texas. Additionally, the Federal EPA finalized an intrastate SO2 emissions trading program based on CSAPR allowance allocations as an alternative to source-specific SO2 requirements. The proposed source-specific approach called for a wet FGD system to be installed on Welsh Plant, Unit 1. The opportunity to use emissions trading to satisfy the regional haze requirements for NOx and SO2 at AEP’s affected generating units provides greater flexibility and lower cost compliance options than the original proposal.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.the final rule. In MarchAugust 2018, that motion was granted.the Federal EPA proposed to affirm its 2017 FIP 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. In March 2018, the U.S. Court of Appeals for the District of Columbia Circuit affirmed the Federal EPA rule.Cross-State Air Pollution Rule




CSAPR

In 2011, the Federal EPA issued CSAPR as a replacement for the CAIR,Clean Air Interstate Rule, a regional trading program designed to address interstate transport of emissions that contributed significantly to downwind nonattainmentnon-attainment with the 1997 ozone and PM NAAQS.  Certain revisions to the rule were finalized in 2012.  CSAPR relies on newly-created SO2 and NOxallowances and individual state budgets to compel further emission reductions from electric utility generating units.  Interstate trading of allowances is allowed on a restricted sub-regional basis.


Numerous affected entities, states and other parties filed petitionsPetitions to review the CSAPR were filed in the U.S. Court of Appeals for the District of Columbia Circuit. The court stayed implementation of the rule.  Following extended proceedings in the U.S. Court of Appeals for the District of Columbia Circuit and the U.S. Supreme Court, but while the litigation was still pending, the U.S. Court of Appeals for the District of Columbia Circuit granted the Federal EPA’s motion to lift the stay and allow Phase I of CSAPR to take effect on January 1, 2015 and Phase II to take effect on January 1, 2017. In July 2015, the U.S. Court of Appeals for the District of Columbia Circuitcourt found that the Federal EPA over-controlled the SO2and/or NOxbudgets of 14 states. The U.S. Court of Appeals for the District of Columbia Circuitcourt remanded the rule to the Federal EPA to timely revise the rulefor revision consistent with the court’s opinion while CSAPR remainsremained in place.



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


Mercury and Other Hazardous Air Pollutants (HAPs) Regulation


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


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


In June 2015, the U.S. Supreme Court reversed the decision of the U.S. Court of Appeals for the District of Columbia Circuit. The U.S. Court of Appeals for the District of Columbia Circuitcourt remanded the MATS rule for further proceedings consistent with the U.S. Supreme Court’s decision thatto the Federal EPA was unreasonable in refusing to consider costs in its determinationdetermining whether to regulate emissions of HAPs from power plants. TheIn 2016, the Federal EPA issued notice of a supplemental finding concluding that, after considering the costs of compliance, it iswas appropriate and necessary to regulate HAP emissions from coal-firedcoal and oil-fired units. Management submitted comments on the proposal. In April 2016, the Federal EPA affirmed its determination that regulation of HAPs from electric generating units is necessary and appropriate. Petitions for review of the Federal EPA’s April 2016 determination have beenwere filed in the U.S. Court of Appeals for the District of Columbia Circuit. Oral argument was scheduled for May 2017, but in April 2017In 2018, the Federal EPA requestedreleased a revised finding that oral argument be postponedthe costs of reducing HAP emissions to facilitate its reviewthe level in the current rule exceed the benefits of those HAP emission reductions. The Federal EPA also determined that there are no significant changes in control technologies and the rule.remaining risks associated with HAP emissions do not justify any more stringent standards. Therefore, the Federal EPA proposed to retain the current MATS standards without change. The rule remainscomment period on this proposal ends in effect.April 2019.




Climate Change, CO2 Regulation and Energy Policy


The majority of the states where AEP has generating facilities passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements that can assist in reducing carbon emissions.  Management is taking steps to comply with these requirements, including increasing wind and solar installations and power purchases and broadening the AEP System’s portfolio of energy efficiency programs.

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

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

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


The final rules are beingwere 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 April 2017, the Federal EPA withdrew its previouslyPresident issued proposals for model trading rules and a CEIP.

In March 2017, the Federal EPA filed in the U.S. Court of Appeals for the District of Columbia Circuit notice of: (a) an Executive Order from the President of the United States titled “Promoting Energy Independence and Economic Growth” directing the Federal EPA to reviewreconsider 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 theassociated standards for new sources. The Federal EPA determines appropriate. In this same filing, the Federal EPA also presentedfiled a motion to hold the litigationchallenges to the CPP in abeyance, until 30 days afterand the conclusion of review of any resulting rulemaking. The District of Columbia Circuit granted the Federal EPA’s motion in part and has requested periodic status reports. cases are still pending.

In October 2017,2018, the Federal EPA issuedproposed the Affordable Clean Energy (ACE) rule to replace the CPP with new emission guidelines for regulating CO2 from existing sources. ACE would establish a framework for states to adopt standards of performance for utility boilers based on heat rate improvements for such boilers. In 2018, the Federal EPA filed a proposed rule repealingrevising the CPPstandards for new sources and withdrawingdetermined that partial carbon capture and storage is not the legal memoranda issued in connection with the rule. The Federal EPA has re-examined its legal interpretation of the “bestbest system of emission reduction”reduction because it is not available throughout the U.S. and found that based on the statutory text, legislative history, use of similar terms elsewhere in the CAA and its own historic implementation of Section 111 that a narrower interpretation of the term limits it to those designs, processes, control technologies and other systems that can be applied directly to or at the source. Since the primary systems relied on in the CPP areis not consistent with that interpretation, the Federal EPA proposes that the rule be withdrawn. The comment period on the proposed repeal has been extended to April 2018. In December 2017, the Federal EPA issued an advanced notice of proposedcost-effective. Management actively monitors these rulemaking seeking information that should be considered by the Federal EPA in developing guidelines for state programs. Management is actively monitoring these rulemakings and participating in the development of any new guidelines.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, power purchases and broadening AEP System’s portfolio of energy efficiency programs.

In February 2018, AEP announced new intermediate and long-term CO2 emission reduction goals, based on the output


of the company’s integrated resource plans, which take into account economics, customer demand, regulations, and grid reliability and resiliency, regulations and reflect the company’s current business strategy. The intermediate goal is a 60% reduction from 2000 CO2 emission levels from AEP generating facilities by 2030; the long-term goal is 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 of approximately 167 million metric tons. emissions.


Federal and state legislation or regulations that mandate limits on the emission of CO2 could result in significant increases in capital expenditures and operating costs, which in turn, could lead to increased liquidity needs and higher financing costs.  Excessive costs to comply with future legislation or regulations might force AEP to close some coal-fired facilities, andwhich could possibly lead to possible impairment of assets.


Coal Combustion Residual (CCR) Rule


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

The final rule became effective in October 2015. CCR are regulated as non-hazardous solid wastes and facilities managing CCR must meet new minimum federal solid waste management standards. The rule applies to 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 postedIn 2018, some of AEP’s facilities were required to a publicly available internet site.

In December 2016, the U.S. Congress passed legislation authorizing states to submitbegin monitoring programs to regulate CCRdetermine if unacceptable groundwater impacts will trigger future corrective measures. Based on additional groundwater data, further studies to design and assess appropriate corrective measures will be undertaken at four 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 compliancein accordance with the minimum standards until a state program is approved or if states fail to adopt their own programs.rule.

The final 2015 rule was challenged in the courts.  In September 2017,2018, the Federal EPA granted industry petitions to reconsider the CCR rule and asked that litigation regarding the rule be held in abeyance. The U.S. Court of Appeals for the District of Columbia Circuit heard oral argument in November 2017. In March 2018,issued its decision vacating and remanding certain provisions of the 2015 rule.  Remaining issues were dismissed.  The provisions addressed by the court’s decision, including changes to the provisions for unlined impoundments and legacy sites, will be the subject of further rulemaking consistent with the court’s decision.

Prior to the court’s decision, the Federal EPA issued the July 2018 rule that modifies certain compliance deadlines and other requirements in the 2015 rule.  In December 2018, challengers filed a proposed rule to modify certain provisionsmotion for partial stay or vacatur of the solid waste management standardsJuly 2018 rule. On the same day, the Federal EPA filed a motion for partial remand of the July 2018 rule. The court granted the Federal EPA’s motion, and provide additional flexibilityfurther rulemaking to facilities regulated under approved state programs. The comment periodaddress the court’s decisions is open untilexpected to be completed near the end of April 2018. Management supports the adoption of more flexible compliance alternatives subject to the Federal EPA or state oversight.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. Commentsgroundwater, and has signed a guidance document that determines that discharges to groundwater are due in May 2018.not subject to NPDES permitting requirements under the CWA. Management is unable to predict the impact of this guidance document or the outcome of these cases on the Federal EPA’s rulemaking, but they could impose significant additional costs on AEP’s facilities.


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




Clean Water Act (CWA) Regulations


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


In addition,2015, the Federal EPA developed revisedissued a final rule revising effluent limitation guidelines for electricity generating facilities. A finalThe rule was issued in November 2015. The final rule establishesestablished limits on FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater to be imposed as soon as possible after November 2018 and no later than December 2023. These new requirements willwould be implemented through each facility’s wastewater discharge permit. The rule has beenwas challenged in the U.S. Court of Appeals for the Fifth Circuit. In March 2017, industry associations filed a petition for reconsideration of the rule with the Federal EPA. In April 2017, the Federal EPA granted reconsideration ofannounced its intent to reconsider and potentially revise the rule and issued a stay of the rule’s future compliance deadlines, which has now expired. In April 2017, the U.S. Court of Appeals for the Fifth Circuit granted a stay of the litigation for 120 days. In June 2017, the Federal EPA also issued a proposal to temporarily postpone certain compliance deadlines in the rule. A final rule revising the compliance deadlinesstandards for FGD wastewater and bottom ash transport waterwater. The Federal EPA postponed the compliance deadlines for those wastewater categories to be no earlier than 2020, was issuedto allow for reconsideration. A revised rule could be proposed later in September 2017.2019. In April 2019, the Fifth Circuit vacated the standards for landfill leachate and legacy wastewaters, and remanded them to the Federal EPA for reconsideration.  Management submitted comments supporting the proposed postponement. Management continues to assessis assessing technology additions and retrofits to comply with the rule and the impacts of the Federal EPA’s recent actions on facilities’ wastewater discharge permitting. 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 CWA provides for federal jurisdiction over “navigable waters” defined as “the waters of the United States.” This jurisdictional definition applies to all CWA programs, potentially impacting generation, transmission and distribution permitting and compliance requirements. Among those programs are permits for wastewater and storm water discharges, permits for impacts to wetlands and water bodies and oil spill prevention planning. The final definition continues to recognize traditional navigable waters of the U.S. as jurisdictional as well as certain exclusions. The rule also contains a number of new specific definitions and criteria for determining whether certain other waters are jurisdictional because of a “significant nexus.” Management believes that clarity and efficiency in the permitting process is needed. Management remains concerned that the rule introduces new concepts and could subject more of AEP’s operations to CWA jurisdiction, thereby increasing the time and complexity of permitting. The final rule is beingwas challenged in bothseveral courts of appeal and district courts. The U.S. Court of Appeals forthat have reached different conclusions about whether the Sixth Circuit granted a nationwide stay of the2015 rule pending jurisdictional determinations.should be implemented. In February 2016, the U.S. Court of Appeals for the Sixth Circuit issued a decision holding that it has exclusive jurisdiction to decide the challenges to the “waters of the United States” rule. Industry, state and related associations filed petitions for a rehearing of the jurisdictional decision. In April 2016, the U.S. Court of Appeals for the Sixth Circuit denied the petitions. In January 2017, the decision was appealed to the U.S. Supreme Court, which granted certiorari to review the jurisdictional issue. Oral argument was heard in October 2017. In JanuaryDecember 2018, the U.S. Supreme Court ruled that challenges to the definition of “waters of the United States” must be filed in the federal district court, and remanded the case to the U.S. Court of Appeals for the Sixth Circuit with directions to dismiss the petitions for review for lack of jurisdiction. The stay has been lifted and the Sixth Circuit case has been dismissed. Challenges to the rule will proceed in federal district courts.



In March 2017, the Federal EPA published a notice of intent to reviewand the rule and provide an advanced notice of a proposed rulemaking consistent with the Executive Order of the President of the United States directing the Federal EPA and U.S. Army Corps of Engineers to review and rescind or revise the rule. In June 2017, the agencies signedreleased a notice of proposed rule to rescindrevising the definition, of “waters of the United States” that was adopted in June 2015, and to re-codifywhich would replace the definition of that phrase as it existed immediately prior to that action. This action would effectively retain the status quo until a new rule is adopted by the agencies. The Federal EPA and U.S. Army Corps of Engineers also finalized a new rule to extend the applicability date ofin the 2015 rule by two years beforeand could significantly alter the nationwide stay issued by the U.S. Courtscope of Appealscertain CWA programs. The comment period for the Sixth Circuit was lifted. Challenges to the applicability date rule have been filed by third partiesthis proposal ends in several federal district courts. Management will participate in further rulemaking activities.April 2019.




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 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 of revenue received from affiliates, investment income, interest income, and interest expense, income tax 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 March 31,Three Months Ended March 31,
2018 20172019 2018
(in millions)(in millions)
Vertically Integrated Utilities$231.2
 $219.5
$302.4
 $231.2
Transmission and Distribution Utilities125.4
 119.1
156.5
 125.4
AEP Transmission Holdco104.0
 71.8
124.2
 104.0
Generation & Marketing18.2
 186.2
40.1
 18.2
Corporate and Other(24.4) (4.4)(50.4) (24.4)
Earnings Attributable to AEP Common Shareholders$454.4
 $592.2
$572.8
 $454.4


AEP CONSOLIDATED


First Quarter of 20182019 Compared to First Quarter of 20172018


Earnings Attributable to AEP Common Shareholders decreasedincreased from $592 million in 2017 to $454 million in 2018 to $573 million in 2019 primarily due to:

A decrease in earnings in the Generation & Marketing segment primarily due to the 2017 gain resulting from the sale of certain merchant generation assets.

This decrease was partially offset by:


An increase in transmission investment primarily at AEP Transmission Holdco, which resulted in higher revenues and income.
An increase in weather-related usage.
Favorable rate proceedings in AEP’s various jurisdictions.

A decrease in other operation and maintenance expenses primarily within the Vertically Integrated Utilities and Generation & Marketing segments.
A decrease in Income Tax Expense primarily due to increased amortization of Excess ADIT not subject to normalization requirements as a result of finalized rate orders and an increase in projected renewable income tax credits.

These increases were partially offset by:

An increase in depreciation and amortization expenses primarily due to a higher depreciable base.
A decrease in weather-related usage.

AEP’s results of operations by operating segment are discussed below.on the following pages.






VERTICALLY INTEGRATED UTILITIES
 Three Months Ended March 31, Three Months Ended March 31,
Vertically Integrated Utilities 2018 2017 2019 2018
 (in millions) (in millions)
Revenues $2,408.0
 $2,290.4
 $2,403.3
 $2,408.0
Fuel and Purchased Electricity 857.8
 788.4
 856.4
 857.8
Gross Margin 1,550.2
 1,502.0
 1,546.9
 1,550.2
Other Operation and Maintenance 740.0
 660.1
 690.1
 740.0
Depreciation and Amortization 313.3
 278.3
 356.3
 313.3
Taxes Other Than Income Taxes 109.9
 101.1
 116.0
 109.9
Operating Income 387.0
 462.5
 384.5
 387.0
Interest and Investment Income 2.6
 3.1
Carrying Costs Income 2.8
 4.1
Other Income 1.3
 5.4
Allowance for Equity Funds Used During Construction 7.4
 6.2
 10.7
 7.4
Non-Service Cost Components of Net Periodic Benefit Cost 18.1
 5.9
 17.0
 18.1
Interest Expense (137.9) (134.9) (139.0) (137.9)
Income Before Income Tax Expense and Equity Earnings 280.0
 346.9
Income Tax Expense 47.7
 127.7
Income Before Income Tax Expense (Benefit) and Equity Earnings 274.5
 280.0
Income Tax Expense (Benefit) (28.4) 47.7
Equity Earnings of Unconsolidated Subsidiaries 0.5
 1.3
 0.7
 0.5
Net Income 232.8
 220.5
 303.6
 232.8
Net Income Attributable to Noncontrolling Interests 1.6
 1.0
 1.2
 1.6
Earnings Attributable to AEP Common Shareholders $231.2
 $219.5
 $302.4
 $231.2


Summary of KWh Energy Sales for Vertically Integrated Utilities
Three Months Ended March 31,Three Months Ended March 31,
2018 20172019 2018
(in millions of KWhs)(in millions of KWhs)
Retail: 
  
 
  
Residential9,572
 8,239
9,216
 9,572
Commercial5,868
 5,689
5,633
 5,787
Industrial8,497
 8,264
8,545
 8,578
Miscellaneous553
 536
546
 553
Total Retail(a)24,490
 22,728
23,940
 24,490
      
Wholesale (a)(b)5,738
 6,507
5,804
 5,738
      
Total KWhs30,228
 29,235
29,744
 30,228
(a) Includes off-system sales,
(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, 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 March 31,Three Months Ended March 31,
2018 20172019 2018
(in degree days)(in degree days)
Eastern Region 
  
 
  
Actual – Heating (a)
1,637
 1,181
1,571
 1,637
Normal – Heating (b)
1,602
 1,615
1,595
 1,602
      
Actual – Cooling (c)
6
 1
1
 6
Normal – Cooling (b)
5
 5
5
 5
      
Western Region 
  
 
  
Actual – Heating (a)
881
 530
941
 881
Normal – Heating (b)
875
 892
866
 875
      
Actual – Cooling (c)
36
 82
11
 36
Normal – Cooling (b)
27
 24
28
 27


(a)Heating degree days are calculated on a 55 degree temperature base.
(b)Normal Heating/Cooling represents the thirty-year average of degree days.
(c)Cooling degree days are calculated on a 65 degree temperature base.





First Quarter of 20182019 Compared to First Quarter of 20172018
Reconciliation of First Quarter of 2017 to First Quarter of 2018
Reconciliation of First Quarter of 2018 to First Quarter of 2019Reconciliation of First Quarter of 2018 to First Quarter of 2019
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities(in millions)
    
First Quarter of 2017 $219.5
First Quarter of 2018 $231.2
  
  
Changes in Gross Margin:  
  
Retail Margins 49.5
 (2.5)
Off-system Sales 1.0
 (6.6)
Transmission Revenues 2.7
 9.4
Other Revenues (5.0) (3.6)
Total Change in Gross Margin 48.2
 (3.3)
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance (79.9) 49.9
Depreciation and Amortization (35.0) (43.0)
Taxes Other Than Income Taxes (8.8) (6.1)
Interest and Investment Income (0.5)
Carrying Costs Income (1.3)
Other Income (4.1)
Allowance for Equity Funds Used During Construction 1.2
 3.3
Non-Service Cost Components of Net Periodic Pension Cost 12.2
 (1.1)
Interest Expense (3.0) (1.1)
Total Change in Expenses and Other (115.1) (2.2)
  
  
Income Tax Expense 80.0
Income Tax Expense (Benefit) 76.1
Equity Earnings (0.8) 0.2
Net Income Attributable to Noncontrolling Interests (0.6) 0.4
    
First Quarter of 2018 $231.2
First Quarter of 2019 $302.4


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 increased $50
•
Retail Margins decreased $3 million primarily due to the following:
A $30 million decrease due to the following:
customer refunds related to Tax Reform. This decrease was partially offset in Income Tax Expense (Benefit) below.
An $89A $24 million increasedecrease in weather-normalized retail margins across all classes.
A $14 million decrease in weather-related usage in the eastern region primarily in the eastern region.residential class.
These decreases were partially offset by:
The effect of rate proceedings in AEP’s service territories which included:
A $25$47 million increase for I&M from rate proceedings primarilyfor I&M, inclusive of a $9 million decrease due to the impact of Tax Reform. This increase was partially offset in Indiana.other expense items below.
An $11 million increase at PSO due to new base rates implemented in March 2018.
A $22$4 million increase forat SWEPCo primarily due to rider and base rate revenue increases in Texas and Louisiana. This increase was partially offset by corresponding increases in other expense items below.
An $11A $3 million increase forat APCo primarily due to increases from riders and base rate riders in Virginia.
A $4 million increase for PSO due to new rates implemented in March 2018, inclusive of a $2 million decrease due to the change in the corporate federal tax rate.
For the rate increases described above, $26 million relate to riders/trackers, which have correspondingrevenue increases in expense items below.
These increases wereWest Virginia. This increase was partially offset by:
A $71 million decrease due to the 2018 provisions for customer refunds primarily related to Tax Reform. This decrease is offsetby increases in Income Tax Expensevarious expenses below.
•
Margins from Off-system Sales decreased $7 million primarily due to mid-year 2018 changes in the OSS sharing mechanism at I&M.
•
Transmission Revenues increased $9 million primarily due to 2018 provisions for refunds at APCo.
A $16 million decrease due to lower weather-normalized margins, primarily due to SWEPCo and I&M wholesale customer load loss from contracts that expired at the end of 2017.
A $4 million decrease primarily due to increased fuel and other variable production costs not recovered through fuel clauses or other trackers.
A $4 million decrease for I&M in FERC generation wholesale municipal and cooperative revenues primarily due to changes to the annual formula rate.


Transmission Revenues increased $3 million primarily due to an increase in transmission investments in SPP.
Other Revenues decreased $5 million primarily due to reduced rates for KPCo Demand Side Management programs beginning in 2018. This decrease is partially offset in Other Operation and Maintenance expense below.


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


Other Operation and Maintenance expenses increased $80 million primarily due to the following:
•
Other Operation and Maintenance expenses decreased $50 million primarily due to the following:
A $45$24 million increasedecrease in planned plant outage and maintenance expenses primarily for APCo, I&M, KPCo and SWEPCo.
An $18 million decrease in recoverable expenses primarily fuel supportassociated with Energy Efficiency/Demand Response and PJMstorm expenses fully recovered in rate recovery riders/trackers inwithin Gross Margins above.
A $15 million increase in plant maintenance primarily for I&M, KPCo and SWEPCo.
A $14 million increasedecrease due to the Wind Catcher Project expenses incurred in 2018 for SWEPCo and PSO.
A $10 million increase in transmission services primarily in SPP.
A $9 million increase due to an increasedecrease in estimated expense for claims related to asbestos exposure.
These increasesdecreases were partially offset by:
A $7 million decrease due to an increased Nuclear Electric Insurance Limited distribution in 2018.
A $6 million decrease in distribution expenses primarily due to distribution system improvements in 2017.
Depreciation and Amortization expenses increased $35 millionprimarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $9 million primarily due to:
A $4An $18 million increase in state gross receipts tax due to a prior period refund.employee-related expenses.
A $3 million increase in property tax
•
Depreciation and Amortization expenses increased $43 millionprimarily due to a higher depreciable base and increased depreciation rates approved at I&M, PSO and SWEPCo.
•
Taxes Other Than Income Taxes increased $6 million primarily due to an increase in property taxes driven by an increase in utility plant.
•
Other Income decreased $4 million primarily due to a decrease in carrying charges for certain riders at I&M.
•
Income TaxExpense (Benefit) decreased $76 million primarily due to increased amortization of Excess ADIT not subject to normalization requirements as a result of finalized rate orders. This decrease was partially offset in Gross Margin above.
Non-Service Cost Components of Net Periodic Benefit Cost decreased $12 millionprimarily due to favorable asset returns for the funded Pension and OPEB plans and by moving to a Medicare Advantage arrangement for post-65 retirees in the Non-UMWA OPEB plan.  Additionally, the decrease was partially due to the implementation of ASU 2017-07 in 2018, which eliminated AEP’s ability to capitalize a portion of its non-service cost components.
Income TaxExpense decreased $80 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, amortization of excess accumulated deferred income taxes associated with certain depreciable property and a decrease in pretax book income.



TRANSMISSION AND DISTRIBUTION UTILITIES
 Three Months Ended March 31, Three Months Ended March 31,
Transmission and Distribution Utilities 2018 2017 2019 2018
 (in millions) (in millions)
Revenues $1,162.4
 $1,086.4
 $1,222.0
 $1,162.4
Purchased Electricity 244.6
 223.4
 229.7
 244.6
Amortization of Generation Deferrals 58.6
 60.9
 32.4
 58.6
Gross Margin 859.2
 802.1
 959.9
 859.2
Other Operation and Maintenance 352.7
 287.9
 405.9
 352.7
Depreciation and Amortization 172.6
 156.2
 183.7
 172.6
Taxes Other Than Income Taxes 137.4
 126.9
 145.5
 137.4
Operating Income 196.5
 231.1
 224.8
 196.5
Interest and Investment Income 1.4
 3.5
 1.3
 1.4
Carrying Costs Income 0.7
 1.9
 0.2
 0.7
Allowance for Equity Funds Used During Construction 8.0
 4.2
 6.9
 8.0
Non-Service Cost Components of Net Periodic Benefit Cost 8.2
 2.2
 7.6
 8.2
Interest Expense (60.1) (60.0) (62.0) (60.1)
Income Before Income Tax Expense 154.7
 182.9
 178.8
 154.7
Income Tax Expense 29.3
 63.8
 22.3
 29.3
Net Income 125.4
 119.1
 156.5
 125.4
Net Income Attributable to Noncontrolling Interests —
 —
 —
 —
Earnings Attributable to AEP Common Shareholders $125.4
 $119.1
 $156.5
 $125.4


Summary of KWh Energy Sales for Transmission and Distribution Utilities
Three Months Ended March 31,Three Months Ended March 31,
2018 20172019 2018
(in millions of KWhs)(in millions of KWhs)
Retail: 
  
 
  
Residential6,797
 5,894
6,547
 6,797
Commercial5,864
 5,753
5,618
 5,686
Industrial5,514
 5,476
5,771
 5,674
Miscellaneous153
 160
176
 171
Total Retail (a)(b)18,328
 17,283
18,112
 18,328
      
Wholesale (b)(c)667
 798
638
 667
      
Total KWhs18,995
 18,081
18,750
 18,995

(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.



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




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


Summary of Heating and Cooling Degree Days for Transmission and Distribution Utilities
Three Months Ended March 31,Three Months Ended March 31,
2018 20172019 2018
(in degree days)(in degree days)
Eastern Region 
  
 
  
Actual – Heating (a)
1,884
 1,403
1,892
 1,884
Normal – Heating (b)
1,884
 1,899
1,877
 1,884
      
Actual – Cooling (c)
4
 3
1
 4
Normal – Cooling (b)
3
 3
3
 3
      
Western Region 
  
 
  
Actual – Heating (a)
230
 102
177
 230
Normal – Heating (b)
191
 195
187
 191
      
Actual – Cooling (d)
196
 258
122
 196
Normal – Cooling (b)
119
 113
123
 119


(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.





First Quarter of 20182019 Compared to First Quarter of 20172018
Reconciliation of First Quarter of 2017 to First Quarter of 2018
Reconciliation of First Quarter of 2018 to First Quarter of 2019Reconciliation of First Quarter of 2018 to First Quarter of 2019
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities(in millions)
    
First Quarter of 2017 $119.1
First Quarter of 2018 $125.4
  
  
Changes in Gross Margin:  
  
Retail Margins 53.8
 58.0
Off-System Sales 5.5
Off-system Sales 20.9
Transmission Revenues (4.0) 22.4
Other Revenues 1.8
 (0.6)
Total Change in Gross Margin 57.1
 100.7
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance (64.8) (53.2)
Depreciation and Amortization (16.4) (11.1)
Taxes Other Than Income Taxes (10.5) (8.1)
Interest and Investment Income (2.1) (0.1)
Carrying Costs Income (1.2) (0.5)
Allowance for Equity Funds Used During Construction 3.8
 (1.1)
Non-Service Cost Components of Net Periodic Benefit Cost 6.0
 (0.6)
Interest Expense (0.1) (1.9)
Total Change in Expenses and Other (85.3) (76.6)
  
  
Income Tax Expense 34.5
 7.0
  
  
First Quarter of 2018 $125.4
First Quarter of 2019 $156.5


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


Retail Margins increased $54
•
Retail Margins increased $58 million primarily due to the following:
A $58 million increase due to the following:
a reversal of a regulatory provision in Ohio.
A $39$17 million net increase in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset by a correspondingan increase in Other Operation and Maintenance expenses below.
A $21$10 million increase in revenues associated with Ohio smart grid riders. This increase was partially offset by increases in other expense items below.
A $5 million increase in Ohio revenues associated with the Universal Service Fund (USF).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 $10$9 million increasedecrease in weather-related usage in Texas weather-related usage primarily driven bydue to a 125% increase23% decrease in heating degree days partially offset byand a 24%38% decrease in cooling degree days.
A $10$6 million increasedecrease in weather-normalized margins, primarily in the residential and commercial classes.
A $9 million increase in Texas revenues associated with the Transmission Cost Recovery Factor revenue rider.vegetation management riders in Ohio. This increasedecrease was partially offset by an increase in Other Operation and Maintenance expenses below.
A $7 million increase in Texas revenues associated with the Distribution Cost Recovery Factor revenue rider.
A $6 million increase in Ohio rider revenues associated with the DIR. This increase was partially offset in various expenses below.
A $4 million net increase in Ohio RSR revenues less associated amortizations.
These increases were partially offset by:
A $21 million decrease due to the 2018 provisions for customer refunds primarily related to Tax Reform. This decrease is offset in Income Tax Expense below.
An $11$5 million decrease in Energy Efficiency/Peak Demand Reduction rideraffiliated PPA capacity revenues in Ohio. This decrease was partially offset by a corresponding decrease in Other Operation and Maintenance expenses below.
A $10 million decrease in margin for the Ohio Phase-In-Recovery Rider including associated amortizations.
A $7 million decrease in Ohio due to the recovery of lower current year losses from a power contract with OVEC.Texas. This decrease was offset by a corresponding increase in Margins from Off-system Sales below.


A $4 million net decrease in margin in Ohio for the Phase-In-Recovery Rider including associated amortizations.
A $7$4 million decrease in OhioTexas revenues associated with smart grid riders.the Transmission Cost Recovery Factor revenue rider. This decrease was partially offset by a corresponding decrease in variousOther Operation and Maintenance expenses below.
•
Margins from Off-system Sales increased $21 million primarily due to due to higher affiliated PPA revenues in Texas, which were partially offset by a corresponding increase in Other Operation and Maintenance expenses below.

Margins from Off-system Sales increased $6
•
Transmission Revenues increased $22 million primarily due to the following:
A $12 million increase primarily due to lower current year losses from a power contract with OVEC in Ohio which was offset in Retail Margins above as a result of the OVEC PPA rider beginning in January 2017.
Transmission Revenues decreased $4 million primarily due to the following:
An $11 million decrease mainly due to the 2018 provisions for customer refunds primarily due to Tax Reform. This decrease is offset in Income Tax Expense below.
This decrease was partially offset by:
A $7 million increase due to recovery of increased transmission investment in ERCOT.

A $10 million increase in Ohio primarily due to 2018 provisions for refunds.

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


Other Operation and Maintenance expenses increased $65 million primarily due to the following:
•
Other Operation and Maintenance expenses increased $53 million primarily due to the following:
A $44$23 million increase in transmission expenses that were fully recovered in rate recovery riders/trackers within Gross Margins above.
A $21$17 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.
These increases were partially offset by:A $10 million increase in PJM expenses primarily related to the annual formula rate true-up.
A $9$6 million decreaseincrease in Ohio Energy Efficiency/Peak Demand Reduction expenses that were fully recovered in rate recovery riders/trackers within Retail Margins above.employee-related expenses.
Depreciation and Amortization expenses increased $16 million primarily due to the following:
•
Depreciation and Amortization expenses increased $11 million primarily due to the following:
A $7$17 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
This increase was partially offset by:
A $6$10 million increasedecrease in Ohio recoverable DIR depreciation expense in Ohio.expense. This increasedecrease was partially offset in Retail Margins above.
•
Taxes Other Than Income Taxes increased $8 million primarily due to an increase in property taxes due to additional investments in transmission and distribution assets and higher tax rates.
•
Income TaxExpense decreased $7 million primarily due to increased amortization of Excess ADIT not subject to normalization requirements as a result of finalized rate orders partially offset by an increase in pretax book income. This decrease was partially offset in Gross Margin above.
A $5 million increase due to securitization amortizations related to Texas securitized transition funding. This increase was offset in Other Revenues above and in Interest Expense below.
Taxes Other Than Income Taxes increased $11 million primarily due to the following:
A $6 million increase in property taxes due to additional investments in transmission and distribution assets and higher tax rates.
A $4 million increase in state excise taxes due to an increase in metered KWhs. This increase was offset in Retail Margins above.
Allowance for Equity Funds Used During Construction increased $4 million 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 and by moving to a Medicare Advantage arrangement for post-65 retirees in the Non-UMWA OPEB plan.  Additionally, the decrease was partially due to the implementation of ASU 2017-07 in 2018, which eliminated AEP’s ability to capitalize a portion of its non-service cost components.
Income TaxExpense 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 a decrease in pretax book income.



AEP TRANSMISSION HOLDCO
 Three Months Ended March 31, Three Months Ended March 31,
AEP Transmission Holdco 2018 2017 2019 2018
 (in millions) (in millions)
Transmission Revenues $205.5
 $156.1
 $256.4
 $205.5
Other Operation and Maintenance 21.9
 14.1
 22.3
 21.9
Depreciation and Amortization 31.8
 24.6
 41.8
 31.8
Taxes Other Than Income Taxes 32.7
 28.0
 42.6
 32.7
Operating Income 119.1
 89.4
 149.7
 119.1
Interest and Investment Income 0.3
 0.2
 0.7
 0.3
Allowance for Equity Funds Used During Construction 15.3
 10.8
 11.3
 15.3
Non-Service Cost Components of Net Periodic Benefit Cost 0.7
 0.1
 0.6
 0.7
Interest Expense (21.1) (17.3) (23.0) (21.1)
Income Before Income Tax Expense and Equity Earnings 114.3
 83.2
 139.3
 114.3
Income Tax Expense 27.5
 36.4
 31.9
 27.5
Equity Earnings of Unconsolidated Subsidiaries 18.0
 26.0
 17.8
 18.0
Net Income 104.8
 72.8
 125.2
 104.8
Net Income Attributable to Noncontrolling Interests 0.8
 1.0
 1.0
 0.8
Earnings Attributable to AEP Common Shareholders $104.0
 $71.8
 $124.2
 $104.0


Summary of Investment in Transmission Assets for AEP Transmission Holdco
 As of March 31, As of March 31,
 2018 2017 2019 2018
 (in millions) (in millions)
Plant in Service $5,912.8
 $4,476.5
 $7,073.6
 $5,912.8
Construction Work in Progress 1,533.7
 1,188.8
 1,899.6
 1,533.7
Accumulated Depreciation and Amortization 200.0
 120.6
 318.8
 200.0
Total Transmission Property, Net $7,246.5
 $5,544.7
 $8,654.4
 $7,246.5



First Quarter of 20182019 Compared to First Quarter of 20172018
 
Reconciliation of First Quarter of 20172018 to First Quarter of 20182019
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
First Quarter of 2017 $71.8
First Quarter of 2018 $104.0
    
Changes in Transmission Revenues:    
Transmission Revenues 49.4
 50.9
Total Change in Transmission Revenues 49.4
 50.9
    
Changes in Expenses and Other:    
Other Operation and Maintenance (7.8) (0.4)
Depreciation and Amortization (7.2) (10.0)
Taxes Other Than Income Taxes (4.7) (9.9)
Interest and Investment Income 0.1
 0.4
Allowance for Equity Funds Used During Construction 4.5
 (4.0)
Non-Service Cost Components of Net Periodic Pension Cost 0.6
 (0.1)
Interest Expense (3.8) (1.9)
Total Change in Expenses and Other (18.3) (25.9)
    
Income Tax Expense 8.9
 (4.4)
Equity Earnings of Unconsolidated Subsidiaries (8.0) (0.2)
Net Income Attributable to Noncontrolling Interests 0.2
 (0.2)
    
First Quarter of 2018 $104.0
First Quarter of 2019 $124.2


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


Transmission Revenues increased $49
•
Transmission Revenues increased $51 million primarily due to continued investment in transmission assets.

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

•
Depreciation and Amortization expenses increased $10 million primarily due to a higher depreciable base.
•
Taxes Other Than Income Taxes increased $10 million primarily due to higher property taxes as a result of increased transmission investment.
•
Allowance for Equity Funds Used During Construction decreased $4 million primarily due to the following:
A $9 million decrease due to the following:
Formula rate increases of $68 million driven by continued investment in transmission assets.recent FERC audit findings.
This increasedecrease was partially offset by:
A $19$5 million decrease due to the 2018 provisions for customer refunds primarily related to Tax Reform. This decrease is offset in Income Tax Expense below.

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

Other Operation and Maintenance expenses increased $8 million primarilyincrease due to increased transmission investment.
•
Income Tax Expense increased $4 million primarily due to higher pretax book income.

Depreciation and Amortization expenses increased $7 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increased $5 million primarily due to higher property taxes as a result of increased transmission investment.
Allowance for Equity Funds Used During Construction increased $5 million primarily due to increased transmission investment resulting in a higher CWIP balance.
Interest Expense increased $4 million primarily due to higher outstanding long-term debt balances.
Income Tax Expense decreased $9 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, partially offset by an increase in pretax book income.
Equity Earnings of Unconsolidated Subsidiaries decreased $8 million primarily due to lower earnings at ETT resulting from decreased revenues driven by Tax Reform and by an ETT rate reduction that went into effect in March 2017, increased operating expenses, decreased AFUDC and increased interest expense.



GENERATION & MARKETING
 Three Months Ended March 31, Three Months Ended March 31,
Generation & Marketing 2018 2017 2019 2018
 (in millions) (in millions)
Revenues $505.1
 $591.4
 $481.8
 $505.1
Fuel, Purchased Electricity and Other 408.8
 405.2
 383.3
 408.8
Gross Margin 96.3
 186.2
 98.5
 96.3
Other Operation and Maintenance 67.6
 99.8
 50.6
 67.6
Gain on Sale of Merchant Generation Assets —
 (226.5)
Depreciation and Amortization 6.9
 5.7
 12.9
 6.9
Taxes Other Than Income Taxes 3.2
 2.0
 3.8
 3.2
Operating Income 18.6
 305.2
 31.2
 18.6
Interest and Investment Income 2.5
 2.2
 2.3
 2.5
Non-Service Cost Components of Net Periodic Benefit Cost 3.9
 2.3
 3.7
 3.9
Interest Expense (3.9) (6.5) (3.8) (3.9)
Income Before Income Tax Expense 21.1
 303.2
Income Tax Expense 3.0
 117.0
Income Before Income Tax Expense (Benefit) 33.4
 21.1
Income Tax Expense (Benefit) (5.8) 3.0
Net Income 18.1
 186.2
 39.2
 18.1
Net Loss Attributable to Noncontrolling Interests (0.1) —
 (0.9) (0.1)
Earnings Attributable to AEP Common Shareholders $18.2
 $186.2
 $40.1
 $18.2


Summary of MWhs Generated for Generation & Marketing
Three Months Ended March 31,Three Months Ended March 31,
2018 20172019 2018
(in millions of MWhs)(in millions of MWhs)
Fuel Type: 
  
 
  
Coal4
 6
1
 4
Natural Gas—
 2
Total MWhs4
 8
1
 4





First Quarter of 20182019 Compared to First Quarter of 20172018
Reconciliation of First Quarter of 2017 to First Quarter of 2018
Reconciliation of First Quarter of 2018 to First Quarter of 2019Reconciliation of First Quarter of 2018 to First Quarter of 2019
Earnings Attributable to AEP Common Shareholders from Generation & Marketing(in millions)
    
First Quarter of 2017 $186.2
First Quarter of 2018 $18.2
  
  
Changes in Gross Margin:  
  
Generation (53.6) (33.7)
Retail, Trading and Marketing (37.7) 34.3
Other 1.4
 1.6
Total Change in Gross Margin (89.9) 2.2
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance 32.2
 17.0
Gain on Sale of Merchant Generation Assets (226.5)
Depreciation and Amortization (1.2) (6.0)
Taxes Other Than Income Taxes (1.2) (0.6)
Interest and Investment Income 0.3
 (0.2)
Non-Service Cost Components of Net Periodic Benefit Cost 1.6
 (0.2)
Interest Expense 2.6
 0.1
Total Change in Expenses and Other (192.2) 10.1
  
  
Income Tax Expense 114.0
Income Tax Expense (Benefit) 8.8
Net Loss Attributable to Noncontrolling Interests 0.1
 0.8
  
  
First Quarter of 2018 $18.2
First Quarter of 2019 $40.1


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


•
Generation decreased $34 million primarily due to a reduction of energy margins in 2019, a reduction in revenues due to the retirement of the Stuart Plant in 2018 and outages at the Conesville Plant.
•
Retail, Trading and Marketing increased $34 million primarily due to reduced MTM hedge losses and higher retail margins due to lower market costs and higher delivered volumes.
•
Other Revenue increased $2 million primarily due to renewable projects placed in-service.
Generation decreased $54 million primarily due to the reduction of revenues associated with the sale of certain merchant generation assets in 2017.
Retail, Trading and Marketing decreased $38 million primarily due to reduced wholesale trading and marketing revenues, mark-to-market hedge losses and lower retail margins.


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


•
Other Operation and Maintenance expenses decreased $17 million primarily due to the closure of the Stuart Plant in 2018 and lower operating costs at the Conesville Plant.
•
Depreciation and Amortization increased $6 million primarily due to a higher depreciable base from increased investments in wind farms and renewable energy sources.
•
Income Tax Expense (Benefit) decreased $9 million primarily due to an increase in projected renewable income tax credits.
Other Operation and Maintenance expenses decreased $32 million primarily due to the following:
•A $21 million decrease in expenses due to the sale of certain merchant generation assets in 2017.
•An $11 million decrease in expenses due to an impairment of certain merchant generation assets in 2017.
Gain on Sale of Merchant Generation Assets decreased $227 million due to the sale of certain merchant generation assets in 2017.
Income Tax Expense decreased $114 million primarily due to a reduction in pretax book income due to the gain on sale of certain merchant generation assets in 2017 and the change in corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform.


CORPORATE AND OTHER


First Quarter of 20182019 Compared to First Quarter of 20172018


Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $4$24 million in 20172018 to a loss of $24$50 million in 2018. The loss in 2018 is2019 primarily due to:

A $30 million increase in income tax expense due to an increase in consolidating tax adjustments and discrete items recorded in the period.
A $17 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 and a $12 million increase in interest expense partially offset by a $9 million decrease in general corporate expenses.2018.


AEP SYSTEM INCOME TAXES


First Quarter of 20182019 Compared to First Quarter of 20172018


Income Tax Expense decreased $241$58 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 Tax Reform, the amortization of excess accumulated deferredfinalized rate orders and an increase in projected renewable income taxes associated with certain depreciable property in 2018 and a decrease in pretax book 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
March 31, 2018 December 31, 2017March 31, 2019 December 31, 2018
(dollars in millions)(dollars in millions)
Long-term Debt, including amounts due within one year$21,461.0
 50.3% $21,173.3
 51.5%$24,426.7
 53.7 % $23,346.7
 52.7%
Short-term Debt2,658.8
 6.2
 1,638.6
 4.0
1,858.0
 4.1
 1,910.0
 4.3
Total Debt24,119.8
 56.5
 22,811.9
 55.5
26,284.7
 57.8
 25,256.7
 57.0
AEP Common Equity18,483.3
 43.4
 18,287.0
 44.4
19,196.3
 42.2
 19,028.4
 42.9
Noncontrolling Interests28.3
 0.1
 26.6
 0.1
32.2
 —
 31.0
 0.1
Total Debt and Equity Capitalization$42,631.4
 100.0% $41,125.5
 100.0%$45,513.2
 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 56.5%57.8% as of March 31, 20182019 primarily due to an increase in short-term 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 March 31, 2018,2019, AEP had a $3$4 billion revolving credit facility commitment to support its operations.commercial paper program.  Additional liquidity is available from cash from operations and a receivables securitization agreement.  Management is committed to maintaining adequate liquidity.  AEP generally uses short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged.  Sources of long-term funding include issuance of long-term debt, sale-leasebacksale-and-leaseback or leasing agreements, hybrid securities or common stock.



Net Available Liquidity

Commercial Paper Credit Facilities


AEP manages liquidity by maintaining adequate external financing commitments.  As of March 31, 2018,2019, available liquidity was approximately $1.3$3.1 billion as illustrated in the table below:
 Amount Maturity Amount Maturity
 (in millions)   (in millions)  
Commercial Paper Backup:Commercial Paper Backup: 
  Commercial Paper Backup: 
  
Revolving Credit Facility$3,000.0
 June 2021Revolving Credit Facility$4,000.0
 June 2022
Cash and Cash EquivalentsCash and Cash Equivalents183.4
  Cash and Cash Equivalents227.7
  
Total Liquidity SourcesTotal Liquidity Sources3,183.4
  Total Liquidity Sources4,227.7
  
Less:AEP Commercial Paper Outstanding1,886.2
  AEP Commercial Paper Outstanding1,108.0
  
      
Net Available LiquidityNet Available Liquidity$1,297.2
  Net Available Liquidity$3,119.7
  


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 three months of 20182019 was $2.2$1.9 billion.  The weighted-average interest rate for AEP’s commercial paper during 2018the first three months of 2019 was 2.07%2.80%.


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 four uncommitted facilities totaling $305 million. In March 2018, oneApril 2019, AEP executed two additional $50 million uncommitted letter of the uncommitted credit facilities was reduced by $40 million.facilities. The Registrants’


maximum future payments for letters of credit issued under the uncommitted facilities as of March 31, 20182019 was $81$106 millionwith maturities ranging from May 2018June 2019 to March 2019.2020.


Securitized Accounts Receivables


AEP’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and expiresincludes a $125 million and a $625 million facility which expire in June 2019.July 2020 and 2021, respectively.


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 agreements excludes securitization bonds and debt of AEP Credit. As of March 31, 2018,2019,this contractually-defined percentage was 54.8%53.8%.  NonperformanceNon-performance under these covenants could result in an event of default under these credit agreements.  In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of AEP’s major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements.  This condition also applies in a majority of AEP’s non-exchange tradednon-exchange-traded commodity contracts and would similarly allow lenders and counterparties to declare the outstanding amounts payable.  However, a default under AEP’s non-exchange tradednon-exchange-traded commodity contracts would not cause an event of default under its credit agreements.


The revolving credit facilities dofacility 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 are expected to support AEP’s overall capital expenditure plans including the recent acquisition of a contracted renewable portfolio. See Note 13 - Financing Activities for additional information.

Dividend Policy and Restrictions


The Board of Directors declared a quarterly dividend of $0.62$0.67per share in April 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 13 for additional information.


Credit Ratings


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


CASH FLOW


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

Three Months Ended 
 March 31,		Three Months Ended March 31,
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 Activities802.2
 806.8
808.3
 802.2
Net Cash Flows from (Used for) Investing Activities(1,927.8) 776.2
Net Cash Flows from (Used for) Financing Activities1,029.5
 (1,687.1)
Net Cash Flows Used for Investing Activities(1,582.8) (1,927.8)
Net Cash Flows from Financing Activities693.5
 1,029.5
Net Decrease in Cash, Cash Equivalents and Restricted Cash(96.1) (104.1)(81.0) (96.1)
Cash, Cash Equivalents and Restricted Cash at End of Period$316.5
 $299.4
$363.1
 $316.5




Operating Activities
Three Months Ended 
 March 31,		Three Months Ended March 31,
2018 20172019 2018
(in millions)(in millions)
Net Income$456.7
 $594.2
$574.1
 $456.7
Non-Cash Adjustments to Net Income (a)623.7
 405.5
618.8
 623.7
Mark-to-Market of Risk Management Contracts(0.7) 6.0
65.5
 (0.7)
Property Taxes(63.7) (44.4)(75.6) (63.7)
Deferred Fuel Over/Under Recovery, Net(61.2) 19.3
32.5
 (61.2)
Recovery of Ohio Capacity Costs, Net18.0
 30.2
14.7
 18.0
Provision for Refund - Global Settlement, Net(5.4) —
(4.1) (5.4)
Change in Other Noncurrent Assets(59.8) (99.1)(47.9) (59.8)
Change in Other Noncurrent Liabilities133.3
 45.0
67.3
 133.3
Change in Certain Components of Working Capital(238.7) (149.9)(437.0) (238.7)
Net Cash Flows from Operating Activities$802.2
 $806.8
$808.3
 $802.2


(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 and Gain on Sale of Merchant Generation Assets.Fuel.
 
Net Cash Flows from Operating Activities decreased increased by $5$6 million primarily due to the following:
An $89A $113 million increase in cash from Net Income, after non-cash adjustments. See Results of Operations for additional information.
A $94 million increase in cash from Deferred Fuel Over/Under-Recovery, Net, primarily due to fluctuations of fuel and purchase power costs at APCo.
These increases in cash were partially offset by:
A $198 million decrease in cash from Changes in Certain Components of Working Capital. This decrease is primarily due to changes in accrued federal taxeshigher employee-related payments and timingthe reversal of receivables and payables, partially offset by lower employee-related payments.a regulatory provision at OPCo. See Note 4 - Rate Matters for additional information.
An $81A $66 million decrease in cash from Deferred Fuel Over/Under Recovery, Net, primarily due to fluctuations of fuel and purchase power costs at APCo.
These decreases in cash were partially offset by:
An $88 million increase in Change in Other Noncurrent Liabilities primarily due to increaseddecreased Accumulated Provisions for Rate Refunds as a result of Tax Reform.Reform in 2018, partially offset by lower employee-related payments.
An $81 million increase in cash from Net Income, after non-cash adjustments. See Results of Operations for additional information.


Investing Activities
Three Months Ended 
 March 31,		Three Months Ended March 31,
2018 20172019 2018
(in millions)(in millions)
Construction Expenditures$(1,905.8) $(1,365.8)$(1,565.4) $(1,905.8)
Acquisitions of Nuclear Fuel(23.8) (3.7)(32.4) (23.8)
Proceeds from Sale of Merchant Generation Assets—
 2,159.6
Other1.8
 (13.9)15.0
 1.8
Net Cash Flows from (Used for) Investing Activities$(1,927.8) $776.2
Net Cash Flows Used for Investing Activities$(1,582.8) $(1,927.8)

Net Cash Flows from (Used for)Used for Investing Activities decreased by $2.7 billion$345 million primarily due to the following:
A $2.2 billion decrease in cash due to the sale of certain merchant generation assets in 2017. See Note 6 - Dispositions and Impairments for additional information.
A $540 million decrease in cash due to increaseddecreased construction expenditures primarily due to increases in AEP Transmission Holdco of $201 million and Transmission and Distribution Utilities of $343 million and AEP Transmission Holdco of $168$108 million.



Financing Activities
Three Months Ended 
 March 31,		Three Months Ended March 31,
2018 20172019 2018
(in millions)(in millions)
Issuance of Common Stock, Net$32.2
 $—
$14.5
 $32.2
Issuance/Retirement of Debt, Net1,317.2
 (1,336.4)1,013.0
 1,317.2
Dividends Paid on Common Stock(306.1) (291.4)(333.6) (306.1)
Other(13.8) (59.3)(0.4) (13.8)
Net Cash Flows from (Used for) Financing Activities$1,029.5
 $(1,687.1)
Net Cash Flows from Financing Activities$693.5
 $1,029.5

Net Cash Flows from (Used for) Financing Activities increased decreased by $2.7 billion$336 million primarily due to the following:
A $1.2$1.1 billion increasedecrease in cash from short-term debt primarily due to increaseddecreased borrowings of commercial paper. See Note 1213 - Financing Activities for additional information.
These decreases in cash were partially offset by:
A $758$445 million increase in cash due to increased issuances of long-term debt. See Note 1213 - Financing Activities for additional information.
A $698$323 million increase in cash due to decreased retirements of long-term debt. See Note 1213 - Financing Activities for additional information.

A $32 million increase inSee “Long-term Debt Subsequent Events” section of Note 13 for Long-term debt and other securities issued, retired and principal payments made after March 31, 2019 through April 25, 2019, the date that the first quarter 10-Q was issued.

BUDGETED CAPITAL EXPENDITURES

Management forecasts approximately $32.9 billion of capital expenditures for 2019 to 2023.  The expenditures are generally for transmission, generation, distribution, regulated and contracted renewables, and required environmental investment to comply with the Federal EPA rules.  Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital.  Management expects to fund these capital expenditures through cash dueflows from operations and financing activities.  Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to increased proceeds from issuances of common stock.
These increases in cash were partially offset by:
A $15 million decrease due to increased common stock dividend payments primarily due to increased dividends per share from 2017 to 2018.

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

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

OFF-BALANCE SHEET ARRANGEMENTS

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

fund these expenditures until long-term funding is arranged. For complete information on each of these off-balance sheet arrangements,forecasted capital expenditures, see the “Off-balance Sheet Arrangements”“Budgeted Capital Expenditures” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 20172018 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 PRONOUNCEMENTS


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.


ACCOUNTING PRONOUNCEMENTS


See Note 2 - New Accounting Pronouncements for information related to accounting pronouncements adopted in 20182019 and pronouncements 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 major power producer and through transactions in wholesale electricity, natural gas and marketing contracts.


Management employs risk management contracts including physical forward and financial forward purchase-and-sale contracts.  Management engages in risk management of power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business.  As a result, AEP is subject to price risk.  The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors.  AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures.  The Regulated Risk Committee consists of AEPSC’s Chief Financial Officer, 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)
Three Months Ended March 31, 2018
Three Months Ended March 31, 2019Three Months Ended March 31, 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(30.5) (1.1) (9.2) (40.8)(3.2) (1.1) (9.2) (13.5)
Fair Value of New Contracts at Inception When Entered During the Period (a)—
 —
 6.1
 6.1
—
 —
 0.1
 0.1
Changes in Fair Value Due to Market Fluctuations During the Period (b)—
 —
 (22.4) (22.4)—
 —
 7.7
 7.7
Changes in Fair Value Allocated to Regulated Jurisdictions (c)5.8
 34.8
 —
 40.6
(69.5) (4.4) —
 (73.9)
Total MTM Risk Management Contract Net Assets (Liabilities) as of March 31, 2018$17.4
 $(97.6) $138.4
 58.2
Total MTM Risk Management Contract Net Assets (Liabilities) as of March 31, 2019$18.2
 $(106.5) $163.1
 74.8
Commodity Cash Flow Hedge Contracts
   
  
 (33.4)   
  
 (55.8)
Fair Value Hedge Contracts   
  
 (20.6)   
  
 (6.3)
Collateral Deposits   
  
 16.8
   
  
 0.3
Total MTM Derivative Contract Net Assets as of March 31, 2018   
  
 $21.0
Total MTM Derivative Contract Net Assets as of March 31, 2019   
  
 $13.0


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


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


Credit Risk


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


AEP has risk management contracts with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, exposures change daily. As of March 31, 2018,2019, credit exposure net of collateral to sub investment grade counterparties was approximately 7%6.2%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss).


As of March 31, 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 $502.5
 $—
 $502.5
 3
 $273.6
 $501.7
 $1.7
 $500.0
 2
 $213.0
Split Rating 3.5
 —
 3.5
 1
 3.5
Noninvestment Grade 0.8
 0.8
 —
 —
 —
 0.1
 0.1
 —
 —
 —
No External Ratings:  
  
 

  
  
  
  
 

  
  
Internal Investment Grade 114.7
 —
 114.7
 3
 72.3
 128.1
 —
 128.1
 3
 83.1
Internal Noninvestment Grade 57.3
 10.5
 46.8
 2
 30.6
 51.7
 10.5
 41.2
 2
 28.2
Total as of March 31, 2018 $678.8
 $11.3
 $667.5
 

 

Total as of March 31, 2019 $681.6
 $12.3
 $669.3
 

 



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


Value at Risk (VaR) Associated with Risk Management Contracts


Management uses a risk measurement model, which calculates VaR, to measure AEP’s commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, as of March 31, 2018,2019, 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
Three Months EndedThree Months Ended Twelve Months EndedThree Months Ended Twelve Months Ended
March 31, 2018 December 31, 2017
March 31, 2019March 31, 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
 $0.4
 $0.1
 $0.2
 $0.5
 $0.2
 $0.1
0.1
 $1.2
 $0.3
 $0.1
 $1.1
 $1.8
 $0.3
 $0.1


VaR Model
Non-Trading Portfolio
Three Months EndedThree Months Ended Twelve Months EndedThree Months Ended Twelve Months Ended
March 31, 2018 December 31, 2017
March 31, 2019March 31, 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)
$1.4
 $6.9
 $2.8
 $1.0
 $4.1
 $6.5
 $1.0
 $0.3
0.4
 $6.6
 $1.6
 $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-short and long-term debt which is subject to a variable rate. AEP manages interest rate risk by limiting variable-ratevariable rate exposures to a percentage of total debt, by entering into interest rate derivative instruments and by monitoring the effects of market changes in interest rates. For the three months ended March 31, 2018 and 2017, aA 100 basis point change in the benchmark rate on AEP’s variable rate debt would impact pre-taxpretax interest expense annually by $25 million for the three months ended March 31, 2019 and $35 million,2018, respectively.






AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 20182019 and 20172018
(in millions, except per-share and share amounts)
(Unaudited)
 Three Months Ended March 31, Three Months Ended March 31,
 2018 2017 2019 2018
REVENUES        
Vertically Integrated Utilities $2,381.5
 $2,269.8
 $2,372.3
 $2,381.5
Transmission and Distribution Utilities 1,141.2
 1,066.4
 1,179.8
 1,141.2
Generation & Marketing 477.5
 558.8
 439.7
 477.5
Other Revenues 48.1
 38.3
 65.0
 48.1
TOTAL REVENUES 4,048.3
 3,933.3
 4,056.8
 4,048.3
        
EXPENSES  
  
  
  
Fuel and Other Consumables Used for Electric Generation 501.8
 635.6
 550.4
 501.8
Purchased Electricity for Resale 990.3
 769.6
 861.8
 990.3
Other Operation 726.4
 623.7
 666.0
 726.4
Maintenance 298.5
 303.5
 274.5
 298.5
Gain on Sale of Merchant Generation Assets —
 (226.5)
Depreciation and Amortization 539.7
 481.9
 605.8
 539.7
Taxes Other Than Income Taxes 285.6
 259.8
 309.9
 285.6
TOTAL EXPENSES 3,342.3
 2,847.6
 3,268.4
 3,342.3
        
OPERATING INCOME 706.0
 1,085.7
 788.4
 706.0
        
Other Income (Expense):  
  
  
  
Interest and Investment Income 2.1
 8.0
Carrying Costs Income 3.4
 5.9
Other Income 8.6
 5.5
Allowance for Equity Funds Used During Construction 30.7
 21.2
 28.9
 30.7
Non-Service Cost Components of Net Periodic Benefit Cost 32.0
 11.4
 30.0
 32.0
Interest Expense (234.0) (221.8) (255.8) (234.0)
        
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS 540.2
 910.4
 600.1
 540.2
        
Income Tax Expense 102.0
 343.2
 44.5
 102.0
Equity Earnings of Unconsolidated Subsidiaries 18.5
 27.0
 18.5
 18.5
        
NET INCOME 456.7
 594.2
 574.1
 456.7
        
Net Income Attributable to Noncontrolling Interests 2.3
 2.0
 1.3
 2.3
        
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $454.4
 $592.2
 $572.8
 $454.4
        
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING 492,267,402
 491,712,042
 493,309,076
 492,267,402
        
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $0.92
 $1.20
 $1.16
 $0.92
        
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING 493,127,300
 492,031,975
 494,484,144
 493,127,300
        
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $0.92
 $1.20
 $1.16
 $0.92
    
CASH DIVIDENDS DECLARED PER SHARE $0.62
 $0.59
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 20182019 and 20172018
(in millions)
(Unaudited)
 Three Months Ended March 31, Three Months Ended March 31,
 2018 2017 2019 2018
Net Income $456.7
 $594.2
 $574.1
 $456.7
        
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES  
  
  
  
Cash Flow Hedges, Net of Tax of $0.7 and $(8.7) in 2018 and 2017, Respectively 2.7
 (16.1)
Securities Available for Sale, Net of Tax of $0 and $0.6 in 2018 and 2017, Respectively —
 1.2
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.4) and $0.1 in 2018 and 2017, Respectively (1.4) 0.2
Cash Flow Hedges, Net of Tax of $(7.7) and $0.7 in 2019 and 2018, Respectively (28.9) 2.7
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.4) and $(0.4) in 2019 and 2018, Respectively (1.4) (1.4)
        
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) 1.3
 (14.7) (30.3) 1.3
        
TOTAL COMPREHENSIVE INCOME 458.0
 579.5
 543.8
 458.0
        
Total Comprehensive Income Attributable to Noncontrolling Interests 2.3
 2.0
 1.3
 2.3
        
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $455.7
 $577.5
 $542.5
 $455.7
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.






AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Three Months Ended March 31, 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
 TotalShares Amount 
Paid-in
Capital
 
Retained
Earnings
 
Noncontrolling
Interests
 Total
TOTAL EQUITY – DECEMBER 31, 2016512.0
 $3,328.3
 $6,332.6
 $7,892.4
 $(156.3) $23.1
 $17,420.1
             
Common Stock Dividends 
  
  
 (290.3)  
 (1.1) (291.4)
Other Changes in Equity 
  
 2.9
 

  
 0.6
 3.5
Net Income      592.2
  
 2.0
 594.2
Other Comprehensive Loss 
  
  
  
 (14.7)  
 (14.7)
TOTAL EQUITY – MARCH 31, 2017512.0
 $3,328.3
 $6,335.5
 $8,194.3
 $(171.0) $24.6
 $17,711.7
             
TOTAL EQUITY – DECEMBER 31, 2017512.2
 $3,329.4
 $6,398.7
 $8,626.7
 $(67.8) $26.6
 $18,313.6
512.2
 $3,329.4
 $6,398.7
 $8,626.7
 $(67.8) $26.6
 $18,313.6
                          
Issuance of Common Stock0.5
 3.3
 28.9
  
  
  
 32.2
0.5
 3.3
 28.9
  
  
  
 32.2
Common Stock Dividends 
  
  
 (305.5)  
 (0.6) (306.1)
Common Stock Dividends ($0.62 per share) 
  
  
 (305.5)  
 (0.6) (306.1)
Other Changes in Equity    16.9
     

 16.9
 
  
 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      454.4
  
 2.3
 456.7
      454.4
  
 2.3
 456.7
Other Comprehensive Income 
  
  
  
 1.3
  
 1.3
 
  
  
  
 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
512.7
 $3,332.7
 $6,444.5
 $8,801.5
 $(95.4) $28.3
 $18,511.6
             
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 ($0.67 per share) 
  
  
 (332.5)  
 (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

(a)Includes $(62) million related to a forward equity purchase contract associated with the issuance of Equity Units. See “Equity Units” section of Footnote 13 - Financing Activities.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.






AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 20182019 and December 31, 20172018
(in millions)
(Unaudited)
 March 31, December 31, March 31, December 31,
 2018 2017 2019 2018
CURRENT ASSETS  
  
  
  
Cash and Cash Equivalents $183.4
 $214.6
 $227.7
 $234.1
Restricted Cash
(March 31, 2018 and December 31, 2017 Amounts Relate to Transition Funding, Ohio Phase-in-Recovery Funding and Appalachian Consumer Rate Relief Funding)
 133.1
 198.0
Other Temporary Investments
(March 31, 2018 and December 31, 2017 Amounts Include $155.8 and $155.4, Respectively, Related to EIS, Transource Energy and Sabine)
 167.9
 161.7
Restricted Cash
(March 31, 2019 and December 31, 2018 Amounts Include $135.4 and $210, Respectively, Related to Transition Funding, Ohio Phase-in-Recovery Funding and Appalachian Consumer Rate Relief Funding)
 135.4
 210.0
Other Temporary Investments
(March 31, 2019 and December 31, 2018 Amounts Include $159.1 and $152.7, Respectively, Related to EIS and Transource Energy)
 168.9
 159.1
Accounts Receivable:  
  
  
  
Customers 635.6
 643.9
 696.6
 699.0
Accrued Unbilled Revenues 213.4
 230.2
 207.8
 209.3
Pledged Accounts Receivable – AEP Credit 975.3
 954.2
 970.5
 999.8
Miscellaneous 66.5
 101.2
 48.3
 55.2
Allowance for Uncollectible Accounts (39.3) (38.5) (40.9) (36.8)
Total Accounts Receivable 1,851.5
 1,891.0
 1,882.3
 1,926.5
Fuel 359.6
 387.7
 360.3
 341.5
Materials and Supplies 563.2
 565.5
 586.3
 579.6
Risk Management Assets 89.6
 126.2
 93.9
 162.8
Regulatory Asset for Under-Recovered Fuel Costs 352.3
 292.5
 123.3
 150.1
Margin Deposits 154.2
 105.5
 136.3
 141.4
Prepayments and Other Current Assets 280.2
 310.4
 200.4
 208.8
TOTAL CURRENT ASSETS 4,135.0
 4,253.1
 3,914.8
 4,113.9
        
PROPERTY, PLANT AND EQUIPMENT  
  
  
  
Electric:  
  
  
  
Generation 20,824.0
 20,760.5
 21,780.6
 21,699.9
Transmission 19,239.9
 18,972.5
 21,773.5
 21,531.0
Distribution 20,160.5
 19,868.5
 21,483.5
 21,195.4
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) 3,812.5
 3,706.3
 4,202.7
 4,265.0
Construction Work in Progress 4,759.4
 4,120.7
 4,910.9
 4,393.9
Total Property, Plant and Equipment 68,796.3
 67,428.5
 74,151.2
 73,085.2
Accumulated Depreciation and Amortization 17,431.2
 17,167.0
 18,182.6
 17,986.1
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET 51,365.1
 50,261.5
 55,968.6
 55,099.1
        
OTHER NONCURRENT ASSETS  
  
  
  
Regulatory Assets 3,516.9
 3,587.6
 3,297.9
 3,310.4
Securitized Assets 1,146.6
 1,211.2
 853.0
 920.6
Spent Nuclear Fuel and Decommissioning Trusts 2,510.6
 2,527.6
 2,684.0
 2,474.9
Goodwill 52.5
 52.5
 52.5
 52.5
Long-term Risk Management Assets 271.2
 282.1
 250.4
 254.0
Operating Lease Assets 1,045.4
 —
Deferred Charges and Other Noncurrent Assets 2,611.6
 2,553.5
 2,655.4
 2,577.4
TOTAL OTHER NONCURRENT ASSETS 10,109.4
 10,214.5
 10,838.6
 9,589.8
        
TOTAL ASSETS $65,609.5
 $64,729.1
 $70,722.0
 $68,802.8
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.






AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
March 31, 20182019 and December 31, 20172018
(dollars in millions)
(Unaudited)
     March 31, December 31,     March 31, December 31,
 2018 2017 2019 2018
CURRENT LIABILITIESCURRENT LIABILITIES    CURRENT LIABILITIES    
Accounts Payable $1,449.6
 $2,065.3
 $1,497.2
 $1,874.3
Short-term Debt:        
Securitized Debt for Receivables – AEP CreditSecuritized Debt for Receivables – AEP Credit 750.0
 718.0
Securitized Debt for Receivables – AEP Credit 750.0
 750.0
Other Short-term Debt 1,908.8
 920.6
 1,108.0
 1,160.0
Total Short-term Debt 2,658.8
 1,638.6
 1,858.0
 1,910.0
Long-term Debt Due Within One Year
(March 31, 2018 and December 31, 2017 Amounts Include $406.5 and $406.9, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and Sabine)
 2,616.1
 1,753.7
Long-term Debt Due Within One Year
(March 31, 2019 and December 31, 2018 Amounts Include $375.9 and $406.5, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and Sabine)
Long-term Debt Due Within One Year
(March 31, 2019 and December 31, 2018 Amounts Include $375.9 and $406.5, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and Sabine)
 1,528.5
 1,698.5
Risk Management Liabilities 57.1
 61.6
 63.4
 55.0
Customer Deposits 365.5
 357.0
 400.4
 412.2
Accrued Taxes 1,081.4
 1,115.5
 1,156.5
 1,218.0
Accrued Interest 273.1
 234.5
 306.0
 231.7
Obligations Under Operating Leases 228.2
 —
Regulatory Liability for Over-Recovered Fuel CostsRegulatory Liability for Over-Recovered Fuel Costs 9.8
 11.9
Regulatory Liability for Over-Recovered Fuel Costs 64.3
 58.6
Other Current Liabilities 960.0
 1,033.2
 888.1
 1,190.5
TOTAL CURRENT LIABILITIES 9,471.4
 8,271.3
 7,990.6
 8,648.8
        
NONCURRENT LIABILITIESNONCURRENT LIABILITIES    NONCURRENT LIABILITIES    
Long-term Debt
(March 31, 2018 and December 31, 2017 Amounts Include $1,253 and $1,410.5, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, Transource Energy and Sabine)
 18,844.9
 19,419.6
Long-term Debt
(March 31, 2019 and December 31, 2018 Amounts Include $980 and $1,109.2, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, Transource Energy and Sabine)
Long-term Debt
(March 31, 2019 and December 31, 2018 Amounts Include $980 and $1,109.2, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, Transource Energy and Sabine)
 22,898.2
 21,648.2
Long-term Risk Management Liabilities 282.7
 322.0
 267.9
 263.4
Deferred Income Taxes 6,943.9
 6,813.9
 7,193.0
 7,086.5
Regulatory Liabilities and Deferred Investment Tax CreditsRegulatory Liabilities and Deferred Investment Tax Credits 8,394.5
 8,422.3
Regulatory Liabilities and Deferred Investment Tax Credits 8,669.8
 8,540.3
Asset Retirement Obligations 1,933.7
 1,925.5
 2,317.3
 2,287.7
Employee Benefits and Pension Obligations 330.9
 398.1
 383.9
 377.1
Obligations Under Operating Leases 860.2
 —
Deferred Credits and Other Noncurrent LiabilitiesDeferred Credits and Other Noncurrent Liabilities 808.2
 830.9
Deferred Credits and Other Noncurrent Liabilities 797.9
 782.6
TOTAL NONCURRENT LIABILITIES 37,538.8
 38,132.3
 43,388.2
 40,985.8
        
TOTAL LIABILITIES 47,010.2
 46,403.6
 51,378.8
 49,634.6
        
Rate Matters (Note 4) 
 
 

 

Commitments and Contingencies (Note 5) 
 
 

 

        
MEZZANINE EQUITYMEZZANINE EQUITY    MEZZANINE EQUITY    
Redeemable Noncontrolling Interest 70.7
 —
 68.5
 69.4
Contingently Redeemable Performance Share Awards 17.0
 11.9
 46.2
 39.4
TOTAL MEZZANINE EQUITY 87.7
 11.9
 114.7
 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 512,716,170 512,210,644     513,632,124 513,450,036    
(20,204,160 and 20,205,046 Shares were Held in Treasury as of March 31, 2018 and December 31, 2017, Respectively) 3,332.7
 3,329.4
(20,204,160 Shares were Held in Treasury as of March 31, 2019 and December 31, 2018)(20,204,160 Shares were Held in Treasury as of March 31, 2019 and December 31, 2018) 3,338.6
 3,337.4
Paid-in Capital 6,444.5
 6,398.7
 6,442.8
 6,486.1
Retained Earnings 8,801.5
 8,626.7
 9,565.6
 9,325.3
Accumulated Other Comprehensive Income (Loss)Accumulated Other Comprehensive Income (Loss) (95.4) (67.8)Accumulated Other Comprehensive Income (Loss) (150.7) (120.4)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITYTOTAL AEP COMMON SHAREHOLDERS’ EQUITY 18,483.3
 18,287.0
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY 19,196.3
 19,028.4
        
Noncontrolling Interests 28.3
 26.6
 32.2
 31.0
        
TOTAL EQUITY 18,511.6
 18,313.6
 19,228.5
 19,059.4
        
TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITYTOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY $65,609.5
 $64,729.1
TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY $70,722.0
 $68,802.8
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 20182019 and 20172018
(in millions)
(Unaudited)
 Three Months Ended March 31, Three Months Ended March 31,
 2018 2017 2019 2018
OPERATING ACTIVITIES  
  
  
  
Net Income $456.7
 $594.2
 $574.1
 $456.7
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:        
Depreciation and Amortization 539.7
 481.9
 605.8
 539.7
Deferred Income Taxes 87.3
 136.2
 16.8
 87.3
Allowance for Equity Funds Used During Construction (30.7) (21.2) (28.9) (30.7)
Mark-to-Market of Risk Management Contracts (0.7) 6.0
 65.5
 (0.7)
Amortization of Nuclear Fuel 27.4
 35.1
 25.1
 27.4
Property Taxes (63.7) (44.4) (75.6) (63.7)
Deferred Fuel Over/Under-Recovery, Net (61.2) 19.3
 32.5
 (61.2)
Gain on Sale of Merchant Generation Assets —
 (226.5)
Recovery of Ohio Capacity Costs 18.0
 30.2
 14.7
 18.0
Provision for Refund - Global Settlement, Net (5.4) —
Provision for Refund – Global Settlement, Net (4.1) (5.4)
Change in Other Noncurrent Assets (59.8) (99.1) (47.9) (59.8)
Change in Other Noncurrent Liabilities 133.3
 45.0
 67.3
 133.3
Changes in Certain Components of Working Capital:        
Accounts Receivable, Net 39.7
 235.8
 57.5
 39.7
Fuel, Materials and Supplies 28.5
 13.4
 (26.4) 28.5
Accounts Payable (129.3) (250.7) (152.6) (129.3)
Accrued Taxes, Net (74.3) 186.8
 (77.0) (74.3)
Other Current Assets (40.1) (45.9) (18.8) (40.1)
Other Current Liabilities (63.2) (289.3) (219.7) (63.2)
Net Cash Flows from Operating Activities 802.2
 806.8
 808.3
 802.2
        
INVESTING ACTIVITIES        
Construction Expenditures (1,905.8) (1,365.8) (1,565.4) (1,905.8)
Purchases of Investment Securities (525.9) (506.0) (130.4) (525.9)
Sales of Investment Securities 508.6
 487.9
 111.9
 508.6
Acquisitions of Nuclear Fuel (23.8) (3.7) (32.4) (23.8)
Proceeds from Sale of Merchant Generation Assets —
 2,159.6
Other Investing Activities 19.1
 4.2
 33.5
 19.1
Net Cash Flows from (Used for) Investing Activities (1,927.8) 776.2
Net Cash Flows Used for Investing Activities (1,582.8) (1,927.8)
        
FINANCING ACTIVITIES        
Issuance of Common Stock, Net 32.2
 —
 14.5
 32.2
Issuance of Long-term Debt 841.0
 82.9
 1,285.6
 841.0
Commercial Paper and Credit Facility Borrowings 205.6
 —
 —
 205.6
Change in Short-term Debt, Net 814.6
 (177.0) (52.0) 814.6
Retirement of Long-term Debt (544.0) (1,242.3) (220.6) (544.0)
Make Whole Payment on Extinguishment of Long-term Debt —
 (44.9)
Principal Payments for Capital Lease Obligations (16.8) (16.6)
Principal Payments for Finance Lease Obligations (14.3) (16.8)
Dividends Paid on Common Stock (306.1) (291.4) (333.6) (306.1)
Other Financing Activities 3.0
 2.2
 13.9
 3.0
Net Cash Flows from (Used for) Financing Activities 1,029.5
 (1,687.1)
Net Cash Flows from Financing Activities 693.5
 1,029.5
        
Net Decrease in Cash, Cash Equivalents and Restricted Cash (96.1) (104.1) (81.0) (96.1)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period 412.6
 403.5
 444.1
 412.6
Cash, Cash Equivalents and Restricted Cash at End of Period $316.5
 $299.4
 $363.1
 $316.5
        
SUPPLEMENTARY INFORMATION        
Cash Paid for Interest, Net of Capitalized Amounts $188.0
 $205.9
 $168.9
 $188.0
Net Cash Paid (Received) for Income Taxes (0.9) (88.8) (0.6) (0.9)
Noncash Acquisitions Under Capital Leases 21.4
 11.4
Noncash Acquisitions Under Finance Leases 23.1
 21.4
Construction Expenditures Included in Current Liabilities as of March 31, 799.9
 515.6
 846.3
 799.9
Noncash Contribution of Assets by Noncontrolling Interest 84.0
 —
 —
 84.0
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage 0.1
 1.0
 1.0
 0.1
Forward Equity Purchase Contract Included Current and Noncurrent Liabilities as of March 31, 62.1
 —
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.






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 March 31,Three Months Ended March 31,
2018 20172019 2018
(in millions of KWhs)(in millions of KWhs)
Retail: 
  
 
  
Residential2,664
 2,201
2,424
 2,664
Commercial2,312
 2,325
2,091
 2,153
Industrial1,960
 1,907
2,148
 2,101
Miscellaneous122
 128
145
 140
Total Retail(a)7,058
 6,561
6,808
 7,058


(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 March 31,Three Months Ended March 31,
2018 20172019 2018
(in degree days)(in degree days)
Actual – Heating (a)230
 102
177
 230
Normal – Heating (b)191
 195
187
 191
      
Actual – Cooling (c)196
 258
122
 196
Normal – Cooling (b)119
 113
123
 119


(a) Heating degree days are calculated on a 55 degree temperature base.
(b) Normal Heating/Cooling represents the thirty-year average of degree days.
(c) Cooling degree days are calculated on a 6570 degree temperature base.



First Quarter of 20182019 Compared to First Quarter of 20172018
Reconciliation of First Quarter of 2017 to First Quarter of 2018
Reconciliation of First Quarter of 2018 to First Quarter of 2019Reconciliation of First Quarter of 2018 to First Quarter of 2019
Net Income(in millions)
First Quarter of 2017 $33.3
First Quarter of 2018 $46.8
  
  
Changes in Gross Margin:    
Retail Margins 18.6
 (11.8)
Off-system Sales (1.6) 21.5
Transmission Revenues 2.4
 12.0
Other Revenues 2.7
 (3.1)
Total Change in Gross Margin 22.1
 18.6
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance (11.3) 3.4
Depreciation and Amortization (7.2) (28.9)
Taxes Other Than Income Taxes (4.1) (4.1)
Interest Income (0.5) (0.1)
Allowance for Equity Funds Used During Construction 3.7
 (3.7)
Non-Service Cost Components of Net Periodic Benefit Cost 2.2
 (0.3)
Interest Expense —
 (2.4)
Total Change in Expenses and Other (17.2) (36.1)
  
  
Income Tax Expense 8.6
 5.1
  
  
First Quarter of 2018 $46.8
First Quarter of 2019 $34.4


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 decreased $12 million primarily due to the following:
Retail Margins increased $19A $9 million primarily due to the following:
A $10 million increasedecrease in weather-related usage primarily driven bydue to a 125% increase23% decrease in heating degree days partially offset byand a 24%38% decrease in cooling degree days.
A $9$4 million increasedecrease in revenues associated with the Transmission Cost Recovery Factor revenue rider. This increasedecrease was partially offset by an increasea decrease in Other Operation and Maintenance expenses below.
•
Margins from Off-system Sales increased $22 million due to higher affiliated PPA revenues, which were offset by corresponding increases in Other Operation and Maintenance expenses and Depreciation and Amortization expenses below.
•
Transmission Revenues increased $12 million primarily due to recovery of increased transmission investment in ERCOT.
•
Other Revenues decreased $3 million primarily due to securitization revenue related to Transition Funding. This decrease was offset in Depreciation and Amortization and in Interest Expense.
A $7 million increase in revenues associated with the Distribution Cost Recovery Factor revenue rider.
These increases were partially offset by:
A $5 million decrease due to the 2018 provisions for customer refunds primarily related to Tax Reform.  This decrease is offset in Income Tax Expense below.
Transmission Revenues increased by $2 million primarily due to the following:
A $7 million increase due to recovery of increased transmission investment in ERCOT.
This increase was partially offset by:
A $5 million decrease due to the 2018 provisions for customer refunds primarily due to Tax Reform.  This decrease is offset in Income Tax Expense below.
Other Revenues increased $3 million primarily due to securitization revenue related to Transition Funding. This increase was offset in Depreciation and Amortization and Interest Expense below.


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

•
Other Operation and Maintenance expenses decreased $3 million primarily due to the following:
A $5 million decrease in distribution expenses.
A $2 million decrease in ERCOT transmission expenses. This decrease was partially offset by a decrease in Retail Margins above.
These decreases were partially offset by:
A $4 million increase primarily due to employee-related expenses.


•
Depreciation and Amortization expenses increased $29 million primarily due to the following:
Other Operation and Maintenance expenses increased $11A $16 million increase in depreciation expense due to a revision in the useful life of the Oklaunion Power Station. This increase was offset by an increase in Margins from Off-system Sales above.
A $12 million increase in depreciation expense primarily due to an increase in ERCOTthe depreciable base of transmission expenses. This increase was partially offset by an increase in Retail Margins above.and distribution assets.
•
Taxes Other Than Income Taxes increased $4 million primarily due to an increase in property taxes due to additional investments in transmission and distribution assets and higher tax rates.
•
Allowance for Equity Funds Used During Construction decreased $4 million primarily due to a decrease in the Equity component of AFUDC as a result of higher short-term debt balances, partially offset by increased transmission projects.
•
Income Tax Expense decreased $5 million primarily due to a decrease in pretax book income and an increase in amortization of Excess ADIT not subject to normalization requirements. This decrease was partially offset in Gross Margin above.



Depreciation and Amortization expenses increased $7 million primarily due to securitization amortizations 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 capital investment and increased tax rates.
Interest Expense was unchanged primarily due to:
A $3 million decrease in securitization assets related to Transition Funding. This decrease was offset above in Other Revenues and in Depreciation and Amortization.
A $2 million decrease due to higher debt component of AFUDC from increased transmission projects.
These decreases were offset by:
A $5 million increase in interest due to the issuance of long-term debt in September 2017.
Allowance for Equity Funds Used During Construction increased $4 million due to increased transmission projects.
Income Tax Expense decreased $9 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and amortization of excess accumulated deferred income taxes associated with certain depreciable property, partially offset by an increase in pretax book income.




 
AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 20182019 and 20172018
(in millions)
(Unaudited)
 Three Months Ended March 31, Three Months Ended March 31,
 2018 2017 2019 2018
REVENUES        
Electric Transmission and Distribution $352.4
 $328.9
 $349.8
 $352.4
Sales to AEP Affiliates 18.2
 14.1
 40.2
 18.2
Other Revenues 1.0
 0.6
 0.7
 1.0
TOTAL REVENUES 371.6
 343.6
 390.7
 371.6
        
EXPENSES  
  
  
  
Fuel and Other Consumables Used for Electric Generation 8.9
 3.0
 9.4
 8.9
Other Operation 117.0
 108.8
 109.8
 117.0
Maintenance 21.5
 18.4
 25.3
 21.5
Depreciation and Amortization 110.0
 102.8
 138.9
 110.0
Taxes Other Than Income Taxes 32.4
 28.3
 36.5
 32.4
TOTAL EXPENSES 289.8
 261.3
 319.9
 289.8
        
OPERATING INCOME 81.8
 82.3
 70.8
 81.8
        
Other Income (Expense):  
  
  
  
Interest Income 0.5
 1.0
 0.4
 0.5
Allowance for Equity Funds Used During Construction 5.5
 1.8
 1.8
 5.5
Non-Service Cost Components of Net Periodic Benefit Cost 3.1
 0.9
 2.8
 3.1
Interest Expense (35.0) (35.0) (37.4) (35.0)
        
INCOME BEFORE INCOME TAX EXPENSE 55.9
 51.0
 38.4
 55.9
        
Income Tax Expense 9.1
 17.7
 4.0
 9.1
        
NET INCOME $46.8
 $33.3
 $34.4
 $46.8
The common stock of AEP Texas Inc. is wholly-owned by Parent.
 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.






AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 20182019 and 20172018
(in millions)
(Unaudited)
Three Months Ended March 31,Three Months Ended March 31,
2018 20172019 2018
Net Income$46.8
 $33.3
$34.4
 $46.8
      
OTHER COMPREHENSIVE INCOME, NET OF TAXES      
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 in 2018 and 2017, Respectively0.2
 0.2
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 in 2018 and 2017, Respectively0.1
 0.1
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 in 2019 and 2018, Respectively0.3
 0.2
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 in 2019 and 2018, Respectively—
 0.1
      
TOTAL OTHER COMPREHENSIVE INCOME0.3
 0.3
0.3
 0.3
      
TOTAL COMPREHENSIVE INCOME$47.1
 $33.6
$34.7
 $47.1
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.






AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Three Months Ended March 31, 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  
 33.3
  
 33.3
Other Comprehensive Income  
  
 0.3
 0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2017 $1,057.9
 $847.4
 $(14.6) $1,890.7
         
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  
 46.8
   46.8
  
 46.8
  
 46.8
Other Comprehensive Income  
   0.3
 0.3
  
  
 0.3
 0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018 $1,157.9
 $1,173.2
 $(15.0) $2,316.1
 $1,157.9
 $1,173.2
 $(15.0) $2,316.1
        
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
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.






AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 20182019 and December 31, 20172018
(in millions)
(Unaudited)
 March 31, December 31, March 31, 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 107.1
 155.2
 100.6
 156.7
Advances to Affiliates 8.1
 111.9
 7.7
 8.0
Accounts Receivable:        
Customers 117.7
 105.3
 125.5
 110.9
Affiliated Companies 9.0
 12.3
 15.9
 15.0
Accrued Unbilled Revenues 65.7
 75.8
 63.0
 70.4
Miscellaneous 0.3
 1.3
 1.8
 1.9
Allowance for Uncollectible Accounts (0.5) (0.7) (1.5) (1.3)
Total Accounts Receivable 192.2
 194.0
 204.7
 196.9
Fuel 6.4
 3.6
 8.5
 8.8
Materials and Supplies 49.4
 52.0
 54.1
 52.8
Risk Management Assets 0.3
 0.5
Accrued Tax Benefits 66.4
 41.0
 24.3
 44.9
Prepayments and Other Current Assets 5.8
 3.6
 4.8
 5.3
TOTAL CURRENT ASSETS 435.8
 563.8
 404.8
 476.5
        
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
Generation 350.9
 350.7
 352.0
 352.1
Transmission 3,097.6
 3,053.6
 3,777.7
 3,683.6
Distribution 3,854.2
 3,718.6
 4,100.6
 4,043.2
Other Property, Plant and Equipment 475.4
 461.0
 734.5
 727.9
Construction Work in Progress 951.6
 835.7
 941.8
 836.2
Total Property, Plant and Equipment 8,729.7
 8,419.6
 9,906.6
 9,643.0
Accumulated Depreciation and Amortization 1,617.4
 1,594.5
 1,686.6
 1,651.2
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 7,112.3
 6,825.1
 8,220.0
 7,991.8
        
OTHER NONCURRENT ASSETS        
Regulatory Assets 379.4
 378.7
 426.7
 430.0
Securitized Transition Assets
(March 31, 2018 and December 31, 2017 Amounts Include $819.2 and $869.5, Respectively, Related to Transition Funding)
 838.9
 891.2
Securitized Transition Assets
(March 31, 2019 and December 31, 2018 Amounts Include $582.8 and $636.8, Respectively, Related to Transition Funding)
 592.9
 649.1
Deferred Charges and Other Noncurrent Assets 134.0
 114.8
 212.0
 56.3
TOTAL OTHER NONCURRENT ASSETS 1,352.3
 1,384.7
 1,231.6
 1,135.4
        
TOTAL ASSETS $8,900.4
 $8,773.6
 $9,856.4
 $9,603.7
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.






AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
March 31, 20182019 and December 31, 20172018
(in millions)
(Unaudited)
 March 31, December 31, March 31, December 31,
 2018 2017 2019 2018
CURRENT LIABILITIES        
Advances from Affiliates $232.7
 $—
 $271.2
 $216.0
Accounts Payable:        
General 209.0
 379.4
 242.0
 276.5
Affiliated Companies 22.7
 30.2
 22.6
 30.3
Long-term Debt Due Within One Year – Nonaffiliated
(March 31, 2018 and December 31, 2017 Amounts Include $243.1 and $236.1, Respectively, Related to Transition Funding)
 273.1
 266.1
Long-term Debt Due Within One Year – Nonaffiliated
(March 31, 2019 and December 31, 2018 Amounts Include $258.6 and $251.1, Respectively, Related to Transition Funding)
 508.6
 501.1
Risk Management Liabilities 0.2
 0.2
Accrued Taxes 89.7
 77.2
 112.4
 75.5
Accrued Interest
(March 31, 2018 and December 31, 2017 Amounts Include $10.2 and $15.9, Respectively, Related to Transition Funding)
 48.0
 42.2
Accrued Interest
(March 31, 2019 and December 31, 2018 Amounts Include $7.4 and $11.3, Respectively, Related to Transition Funding)
 50.7
 37.3
Oklaunion Purchase Power Agreement 25.8
 24.3
Obligations Under Operating Leases 12.2
 —
Other Current Liabilities 70.7
 76.4
 82.4
 98.3
TOTAL CURRENT LIABILITIES 945.9
 871.5
 1,328.1
 1,259.5
        
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated
(March 31, 2018 and December 31, 2017 Amounts Include $686.8 and $790.1, Respectively, Related to Transition Funding)
 3,280.2
 3,383.2
Long-term Debt – Nonaffiliated
(March 31, 2019 and December 31, 2018 Amounts Include $429.4 and $540.1, Respectively, Related to Transition Funding)
 3,269.7
 3,380.2
Deferred Income Taxes 913.1
 913.1
 908.8
 913.1
Regulatory Liabilities and Deferred Investment Tax Credits 1,320.2
 1,320.5
 1,344.1
 1,344.3
Oklaunion Purchase Power Agreement 51.8
 52.0
 15.1
 22.1
Obligations Under Operating Leases 70.2
 —
Deferred Credits and Other Noncurrent Liabilities 73.1
 63.4
 105.2
 104.0
TOTAL NONCURRENT LIABILITIES 5,638.4
 5,732.2
 5,713.1
 5,763.7
        
TOTAL LIABILITIES 6,584.3
 6,603.7
 7,041.2
 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 1,173.2
 1,124.6
 1,372.1
 1,337.7
Accumulated Other Comprehensive Income (Loss) (15.0) (12.6) (14.8) (15.1)
TOTAL COMMON SHAREHOLDER’S EQUITY 2,316.1
 2,169.9
 2,815.2
 2,580.5
        
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $8,900.4
 $8,773.6
 $9,856.4
 $9,603.7
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.






AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 20182019 and 20172018
(in millions)
(Unaudited)
 Three Months Ended March 31, Three Months Ended March 31,
 2018 2017 2019 2018
OPERATING ACTIVITIES  
  
  
  
Net Income $46.8
 $33.3
 $34.4
 $46.8
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
  
  
Depreciation and Amortization 110.0
 102.8
 138.9
 110.0
Deferred Income Taxes (4.4) 40.8
 (11.0) (4.4)
Allowance for Equity Funds Used During Construction (5.5) (1.8) (1.8) (5.5)
Mark-to-Market of Risk Management Contracts 0.2
 0.1
 —
 0.2
Property Taxes (56.1) (46.2) (73.8) (56.1)
Change in Other Noncurrent Assets (12.7) (12.7) (3.2) (12.7)
Change in Other Noncurrent Liabilities 6.5
 4.8
 (5.7) 6.5
Changes in Certain Components of Working Capital:  
  
  
  
Accounts Receivable, Net 1.8
 3.7
 (7.8) 1.8
Fuel, Materials and Supplies (0.2) 0.4
 (1.0) (0.2)
Accounts Payable (25.9) (13.4) 4.2
 (25.9)
Accrued Taxes, Net 25.2
 (3.5) 57.5
 25.2
Other Current Assets (1.6) (0.3) 0.5
 (1.6)
Other Current Liabilities (5.1) (25.9) (4.4) (5.1)
Net Cash Flows from Operating Activities 79.0
 82.1
 126.8
 79.0
        
INVESTING ACTIVITIES  
  
  
  
Construction Expenditures (481.6) (200.2) (343.1) (481.6)
Change in Advances to Affiliates, Net 103.8
 0.3
 0.3
 103.8
Other Investing Activities 13.4
 4.6
 6.2
 13.4
Net Cash Flows Used for Investing Activities (364.4) (195.3) (336.6) (364.4)
        
FINANCING ACTIVITIES  
  
  
  
Capital Contribution from Parent 100.0
 200.0
 200.0
 100.0
Change in Advances from Affiliates, Net 232.7
 (43.0) 55.2
 232.7
Retirement of Long-term Debt – Nonaffiliated (96.5) (89.9) (103.5) (96.5)
Principal Payments for Capital Lease Obligations (1.1) (0.9)
Principal Payments for Finance Lease Obligations (1.2) (1.1)
Other Financing Activities 0.3
 0.6
 0.2
 0.3
Net Cash Flows from Financing Activities 235.4
 66.8
 150.7
 235.4
        
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding (50.0) (46.4) (59.1) (50.0)
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 $107.2
 $100.5
 $100.7
 $107.2
        
SUPPLEMENTARY INFORMATION        
Cash Paid for Interest, Net of Capitalized Amounts $27.8
 $33.7
 $22.4
 $27.8
Noncash Acquisitions Under Capital Leases 4.0
 2.0
Net Cash Paid (Received) for Income Taxes (5.6) —
Noncash Acquisitions Under Finance Leases 2.4
 4.0
Construction Expenditures Included in Current Liabilities as of March 31, 169.3
 65.5
 195.7
 169.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.






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 March 31, As of March 31,
 2018 2017 2019 2018
 (in millions) (in millions)
Plant In Service $5,595.4
 $4,162.3
 $6,755.0
 $5,595.4
Construction Work in Progress 1,512.6
 1,184.4
 1,812.2
 1,512.6
Accumulated Depreciation and Amortization 192.7
 117.8
 306.7
 192.7
Total Transmission Property, Net $6,915.3
 $5,228.9
 $8,260.5
 $6,915.3


First Quarter of 20182019 Compared to First Quarter of 20172018
Reconciliation of First Quarter of 2017 to First Quarter of 2018
Reconciliation of First Quarter of 2018 to First Quarter of 2019Reconciliation of First Quarter of 2018 to First Quarter of 2019
Net Income(in millions)
First Quarter of 2017 $57.0
First Quarter of 2018 $84.1
  
  
Changes in Transmission Revenues:    
Transmission Revenues 40.8
 51.8
Total Change in Transmission Revenues 40.8
 51.8
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance (7.0) (1.0)
Depreciation and Amortization (7.3) (10.0)
Taxes Other Than Income Taxes (4.3) (10.3)
Interest Income 0.2
 0.3
Allowance for Equity Funds Used During Construction 4.4
 (3.6)
Interest Expense (3.9) (1.4)
Total Change in Expenses and Other (17.9) (26.0)
  
  
Income Tax Expense 6.0
 (5.6)
  
  
First Quarter of 2018 $85.9
First Quarter of 2019 $104.3


The amounts presented in the tables above reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.

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


•
Transmission Revenues increased $52 million primarily due to continued investment in transmission assets.
Transmission Revenues increased $41 million primarily due to the following:
Formula rate increases of $60 million driven by continued investment in transmission assets.
This increase was partially offset by:
A $19 million decrease due to the 2018 provisions for customer refunds primarily related to Tax Reform.
This decrease is offset in Income Tax Expense below.


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


Other Operation and Maintenance expenses increased $7
•
Depreciation and Amortization expenses increased $10 million primarily due to a higher depreciable base.
•
Taxes Other Than Income Taxes increased $10 million primarily due to higher property taxes as a result of increased transmission investment.
•
Allowance for Equity Funds Used During Construction decreased $4 million primarily due to the following:
A $9 million decrease due to recent FERC audit findings.
This decrease was partially offset by:
A $5 million increase due to increased transmission investment.
•
Income Tax Expense increased $6 million primarily due to higher pretax book income.

Depreciation and Amortization expenses increased $7 million primarily due to a higher depreciable base.


Taxes Other Than Income Taxes increased $4 million primarily due to higher property taxes as a result of increased transmission investment.
Allowance for Equity Funds Used During Construction increased $4 million primarily due to increased transmission investment resulting in a higher CWIP balance.
Interest Expense increased $4 million primarily due to higher outstanding long-term debt balances.
Income Tax Expense decreased $6 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, partially offset by an increase in pretax book income.




 
AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 20182019 and 20172018
(in millions)
(Unaudited)
 Three Months Ended March 31, Three Months Ended March 31,
 2018 2017 2019 2018
REVENUES        
Transmission Revenues $31.3
 $19.2
 $50.3
 $30.9
Sales to AEP Affiliates 162.1
 133.4
 193.2
 160.7
Other Revenues 0.1
 0.1
 —
 0.1
TOTAL REVENUES 193.5
 152.7
 243.5
 191.7
        
EXPENSES        
Other Operation 16.6
 9.1
 17.0
 16.6
Maintenance 2.6
 3.1
 3.2
 2.6
Depreciation and Amortization 30.6
 23.3
 40.3
 30.3
Taxes Other Than Income Taxes 31.1
 26.8
 41.4
 31.1
TOTAL EXPENSES 80.9
 62.3
 101.9
 80.6
        
OPERATING INCOME 112.6
 90.4
 141.6
 111.1
        
Other Income (Expense):        
Interest Income 0.4
 0.2
 0.7
 0.4
Allowance for Equity Funds Used During Construction 15.3
 10.9
 11.3
 14.9
Interest Expense (19.9) (16.0) (21.7) (20.3)
        
INCOME BEFORE INCOME TAX EXPENSE 108.4
 85.5
 131.9
 106.1
        
Income Tax Expense 22.5
 28.5
 27.6
 22.0
        
NET INCOME $85.9
 $57.0
 $104.3
 $84.1
The 2018 amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
MEMBER’S EQUITY
For the Three Months Ended March 31, 20182019 and 20172018
(in millions)
(Unaudited)
 
Paid-in
Capital
 
Retained
Earnings
 Total Member’s Equity
TOTAL MEMBER’S EQUITY – DECEMBER 31, 2016 $1,455.0
 $502.6
 $1,957.6
      
Capital Contributions from Member 125.5
   125.5
Net Income   57.0
 57.0
TOTAL MEMBER’S EQUITY – MARCH 31, 2017 $1,580.5
 $559.6
 $2,140.1
       
Paid-in
Capital
 
Retained
Earnings
 Total Member’s Equity
TOTAL MEMBER’S EQUITY – DECEMBER 31, 2017 $1,816.6
 $788.7
 $2,605.3
 $1,816.6
 $773.3
 $2,589.9
            
Capital Contributions from Member 65.0
   65.0
 65.0
   65.0
Net Income   85.9
 85.9
   84.1
 84.1
TOTAL MEMBER’S EQUITY – MARCH 31, 2018 $1,881.6
 $874.6
 $2,756.2
 $1,881.6
 $857.4
 $2,739.0
      
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
The 2017 and 2018 amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 20182019 and December 31, 20172018
(in millions)
(Unaudited)
 March 31, December 31, March 31, December 31,
 2018 2017 2019 2018
CURRENT ASSETS        
Advances to Affiliates $32.1
 $146.3
 $73.5
 $96.9
Accounts Receivable:        
Customers 20.5
 19.1
 19.0
 11.8
Affiliated Companies 102.0
 93.2
 68.8
 61.0
Miscellaneous 1.2
 1.3
 0.2
 —
Total Accounts Receivable 123.7
 113.6
 88.0
 72.8
Materials and Supplies 15.5
 13.6
 19.6
 19.0
Accrued Tax Benefits 40.1
 46.6
 19.1
 33.4
Prepayments and Other Current Assets 2.8
 7.6
 2.9
 3.4
TOTAL CURRENT ASSETS 214.2
 327.7
 203.1
 225.5
        
TRANSMISSION PROPERTY        
Transmission Property 5,458.3
 5,336.1
 6,580.6
 6,515.8
Other Property, Plant and Equipment 137.1
 131.4
 174.4
 174.0
Construction Work in Progress 1,512.6
 1,312.7
 1,812.2
 1,578.3
Total Transmission Property 7,108.0
 6,780.2
 8,567.2
 8,268.1
Accumulated Depreciation and Amortization 192.7
 170.4
 306.7
 271.9
TOTAL TRANSMISSION PROPERTY – NET
 6,915.3
 6,609.8
 8,260.5
 7,996.2
        
OTHER NONCURRENT ASSETS        
Regulatory Assets 8.9
 11.7
 10.5
 12.9
Deferred Property Taxes 100.5
 117.8
 134.7
 157.9
Deferred Charges and Other Noncurrent Assets 1.0
 1.1
 7.3
 1.6
TOTAL OTHER NONCURRENT ASSETS 110.4
 130.6
 152.5
 172.4
        
TOTAL ASSETS $7,239.9
 $7,068.1
 $8,616.1
 $8,394.1
The 2018 amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND MEMBER’S EQUITY
March 31, 20182019 and December 31, 20172018
(in millions)
(Unaudited)
 March 31, December 31, March 31, December 31,
 2018 2017 2019 2018
    
CURRENT LIABILITIES        
Advances from Affiliates $282.1
 $15.7
 $223.1
 $45.4
Accounts Payable:        
General 210.5
 473.2
 258.0
 347.2
Affiliated Companies 41.3
 52.9
 67.0
 56.0
Long-term Debt Due Within One Year – Nonaffiliated 50.0
 50.0
 85.0
 85.0
Accrued Taxes 185.3
 225.4
 242.5
 288.9
Accrued Interest 38.3
 15.0
 35.1
 15.9
Provision for Refund 47.6
 —
Obligations Under Operating Leases 2.6
 —
Other Current Liabilities 2.6
 4.1
 20.3
 3.8
TOTAL CURRENT LIABILITIES 857.7
 836.3
 933.6
 842.2
        
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated 2,500.7
 2,500.4
 2,738.4
 2,738.0
Deferred Income Taxes 621.3
 601.7
 721.9
 704.4
Regulatory Liabilities 497.2
 493.7
 527.9
 521.3
Obligations Under Operating Leases 3.2
 —
Deferred Credits and Other Noncurrent Liabilities 6.8
 30.7
 17.0
 18.4
TOTAL NONCURRENT LIABILITIES 3,626.0
 3,626.5
 4,008.4
 3,982.1
        
TOTAL LIABILITIES 4,483.7
 4,462.8
 4,942.0
 4,824.3
        
Rate Matters (Note 4) 

 

 


 


Commitments and Contingencies (Note 5) 

 

 


 


        
MEMBER’S EQUITY        
Paid-in Capital 1,881.6
 1,816.6
 2,480.6
 2,480.6
Retained Earnings 874.6
 788.7
 1,193.5
 1,089.2
TOTAL MEMBER’S EQUITY 2,756.2
 2,605.3
 3,674.1
 3,569.8
        
TOTAL LIABILITIES AND MEMBER’S EQUITY $7,239.9
 $7,068.1
 $8,616.1
 $8,394.1
The 2018 amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 20182019 and 20172018
(in millions)
(Unaudited)
 Three Months Ended March 31, Three Months Ended March 31,
 2018 2017 2019 2018
OPERATING ACTIVITIES        
Net Income $85.9
 $57.0
 $104.3
 $84.1
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:        
Depreciation and Amortization 30.6
 23.3
 40.3
 30.3
Deferred Income Taxes 15.7
 74.1
 14.5
 15.5
Allowance for Equity Funds Used During Construction (15.3) (10.9) (11.3) (14.9)
Property Taxes 17.3
 16.8
 23.2
 17.3
Change in Other Noncurrent Assets 2.7
 2.2
 2.7
 2.9
Change in Other Noncurrent Liabilities 23.9
 8.3
 2.2
 23.9
Changes in Certain Components of Working Capital:        
Accounts Receivable, Net (10.1) (39.0) (8.2) (9.6)
Materials and Supplies (1.9) (3.8) (0.6) (1.9)
Accounts Payable (12.3) (8.2) 11.4
 (10.7)
Accrued Taxes, Net (33.6) (79.1) (32.1) (34.0)
Accrued Interest 23.3
 17.6
 19.2
 23.3
Other Current Assets 0.3
 0.2
 0.4
 0.3
Other Current Liabilities 0.6
 —
 0.2
 0.6
Net Cash Flows from Operating Activities 127.1
 58.5
 166.2
 127.1
        
INVESTING ACTIVITIES        
Construction Expenditures (571.8) (390.4) (365.0) (571.8)
Change in Advances to Affiliates, Net 114.2
 56.9
 23.4
 114.2
Acquisitions of Assets (1.8) (0.6) (2.5) (1.8)
Other Investing Activities 1.0
 —
 0.3
 1.0
Net Cash Flows Used for Investing Activities (458.4) (334.1) (343.8) (458.4)
        
FINANCING ACTIVITIES        
Capital Contributions from Member 65.0
 125.5
 —
 65.0
Change in Advances from Affiliates, Net 266.4
 150.9
 177.7
 266.4
Other Financing Activities (0.1) (0.8) (0.1) (0.1)
Net Cash Flows from Financing Activities 331.3
 275.6
 177.6
 331.3
        
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 (Received) for Interest, Net of Capitalized Amounts $1.6
 $(3.0)
Net Cash Paid (Received) for Income Taxes $—
 $(0.6) (1.2) —
Construction Expenditures Included in Current Liabilities as of March 31, 210.6
 189.2
 261.1
 213.8
The 2018 amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




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 March 31,Three Months Ended March 31,
2018 20172019 2018
(in millions of KWhs)(in millions of KWhs)
Retail: 
  
 
  
Residential3,845
 3,250
3,587
 3,845
Commercial1,694
 1,591
1,596
 1,689
Industrial2,377
 2,299
2,336
 2,382
Miscellaneous224
 210
219
 224
Total Retail(a)8,140
 7,350
7,738
 8,140
      
Wholesale495
 806
816
 495
      
Total KWhs8,635
 8,156
8,554
 8,635


(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 March 31,Three Months Ended March 31,
2018 20172019 2018
(in degree days)(in degree days)
Actual – Heating (a)1,389
 955
1,252
 1,389
Normal – Heating (b)1,317
 1,328
1,312
 1,317
      
Actual – Cooling (c)8
 2
—
 8
Normal – Cooling (b)7
 7
7
 7


(a) Heating degree days are calculated on a 55 degree temperature base.
(b) Normal Heating/Cooling represents the thirty-year average of degree days.
(c) Cooling degree days are calculated on a 65 degree temperature base.



First Quarter of 20182019 Compared to First Quarter of 20172018
Reconciliation of First Quarter of 2017 to First Quarter of 2018
Reconciliation of First Quarter of 2018 to First Quarter of 2019Reconciliation of First Quarter of 2018 to First Quarter of 2019
Net Income(in millions)
First Quarter of 2017 $110.6
First Quarter of 2018 $125.5
  
  
Changes in Gross Margin:    
Retail Margins 15.0
 (59.3)
Off-system Sales (0.2) 1.7
Transmission Revenues (1.9) 12.3
Other Revenues (2.2) (1.3)
Total Change in Gross Margin 10.7
 (46.6)
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance (25.1) 11.8
Depreciation and Amortization (7.9) (4.0)
Taxes Other Than Income Taxes (3.6) (2.1)
Interest Income 0.5
Carrying Costs Income 0.2
 (0.5)
Allowance for Equity Funds Used During Construction 1.1
 (0.9)
Non-Service Cost Components of Net Periodic Benefit Cost 3.2
 (0.2)
Interest Expense 0.7
 (1.9)
Total Change in Expenses and Other (31.4) 2.7
  
  
Income Tax Expense 35.6
Income Tax Expense (Benefit) 52.1
  
  
First Quarter of 2018 $125.5
First Quarter of 2019 $133.7


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 increased $15 million primarily due to the following:
•
Retail Margins decreased $59 million primarily due to the following:
A $50 million increase in weather-related usage primarily due to a 45% increase in heating degree days.
An $11 million increase primarily due to increases from rate riders in Virginia. This increase is partially offset by a corresponding increase in Other Operation and Maintenance expenses.
These increases were partially offset by:
A $32$28 million decrease due to the 2018 provisions for customer refunds primarily related to Tax Reform. This decrease iswas partially offset in Income Tax Expense (Benefit) below.
A $5$15 million decrease in weather-normalized margins occurring primarily in the residential and industrialacross all retail classes.
A $4$14 million decrease due to increased fuel and other variable production costs not recovered through fuel or other trackers.in weather-related usage primarily driven by a 10% decrease in heating degree days.
•
Transmission Revenue increased $12 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 increased $25 million primarily due to the following:
A $12 million increase in recoverable PJM transmission expenses. This increase is offset within Retail Margins above.
•
Other Operation and Maintenance expenses decreased $12 million primarily due to the following:
A $5 million increasedecrease in estimated expenseexpenses for claims related to asbestos exposure.
A $4 million increasedecrease in employee-relatedstorm-related expenses.
Depreciation and Amortization expenses increased $8 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxes increasedA $4 million primarilydecrease in maintenance expense at various generation plants.
A $3 million decrease in expenses due to the following:
extinguishment of regulatory asset balances as agreed to within the West Virginia Tax Reform settlement.
A $2$3 million decrease in vegetation management expenses.
These decreases were primarily offset by:
An $8 million increase in property taxes driven by an increase in utility plant.
A $2 million increase in state gross receipts tax due to a prior period refund.
Non-Service Cost Components of Net Periodic Cost decreased $3 millionPJM expenses primarily due to favorable asset returns for the funded Pension and OPEB plans and by moving to a Medicare Advantage arrangement for post-65 retirees in the Non-UMWA OPEB plan. Additionally, the decrease was partially duerelated to the implementation of ASU 2017-07 in 2018, which eliminated APCo’s ability to capitalize a portion of its non-service cost components.annual formula rate true-up.
•
Depreciation and Amortization expenses increased $4 million primarily due to a higher depreciable base.
•
Income Tax Expense(Benefit) decreased $52 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.

Income Tax Expense decreased $36 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and a decrease in pretax book income.





APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 20182019 and 20172018
(in millions)
(Unaudited)
 Three Months Ended March 31, Three Months Ended March 31,
 2018 2017 2019 2018
REVENUES        
Electric Generation, Transmission and Distribution $767.5
 $745.0
 $738.7
 $767.5
Sales to AEP Affiliates 49.4
 42.4
 51.7
 49.4
Other Revenues 3.5
 5.4
 2.4
 3.5
TOTAL REVENUES 820.4
 792.8
 792.8
 820.4
        
EXPENSES  
  
  
  
Fuel and Other Consumables Used for Electric Generation 69.0
 167.2
 183.3
 69.0
Purchased Electricity for Resale 205.9
 90.8
 110.6
 205.9
Other Operation 138.2
 113.9
 136.9
 138.2
Maintenance 72.0
 71.2
 61.5
 72.0
Depreciation and Amortization 108.5
 100.6
 112.5
 108.5
Taxes Other Than Income Taxes 33.8
 30.2
 35.9
 33.8
TOTAL EXPENSES 627.4
 573.9
 640.7
 627.4
        
OPERATING INCOME 193.0
 218.9
 152.1
 193.0
        
Other Income (Expense):  
  
  
  
Interest Income 0.3
 0.3
 0.8
 0.3
Carrying Costs Income 0.5
 0.3
 —
 0.5
Allowance for Equity Funds Used During Construction 2.6
 1.5
 1.7
 2.6
Non-Service Cost Components of Net Periodic Benefit Cost 4.5
 1.3
 4.3
 4.5
Interest Expense (47.4) (48.1) (49.3) (47.4)
        
INCOME BEFORE INCOME TAX EXPENSE 153.5
 174.2
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 109.6
 153.5
        
Income Tax Expense 28.0
 63.6
Income Tax Expense (Benefit) (24.1) 28.0
        
NET INCOME $125.5
 $110.6
 $133.7
 $125.5
The common stock of APCo is wholly-owned by Parent. 
     
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.








APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 20182019 and 20172018
(in millions)
(Unaudited)
Three Months Ended March 31,Three Months Ended March 31,
2018 20172019 2018
Net Income$125.5
 $110.6
$133.7
 $125.5
      
OTHER COMPREHENSIVE LOSS, NET OF TAXES 
  
 
  
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) in 2018 and 2017, Respectively(0.2) (0.2)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.2) and $(0.2) in 2018 and 2017, Respectively(0.8) (0.3)
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) in 2019 and 2018, Respectively(0.2) (0.2)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.2) and $(0.2) in 2019 and 2018, Respectively(0.6) (0.8)
      
TOTAL OTHER COMPREHENSIVE LOSS(1.0) (0.5)(0.8) (1.0)
      
TOTAL COMPREHENSIVE INCOME$124.5
 $110.1
$132.9
 $124.5
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.








APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Three Months Ended March 31, 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  
  
 (30.0)  
 (30.0)
Net Income  
  
 110.6
  
 110.6
Other Comprehensive Loss  
  
  
 (0.5) (0.5)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2017 $260.4
 $1,828.7
 $1,583.4
 $(8.9) $3,663.6
           
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
 $260.4
 $1,828.7
 $1,714.1
 $1.3
 $3,804.5
                    
Common Stock Dividends  
  
 (40.0)  
 (40.0)  
  
 (40.0)  
 (40.0)
ASU 2018-02 Adoption     0.1
 0.3
 0.4
     0.1
 0.3
 0.4
Net Income  
  
 125.5
  
 125.5
  
  
 125.5
  
 125.5
Other Comprehensive Loss  
  
  
 (1.0) (1.0)  
  
  
 (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
 $260.4
 $1,828.7
 $1,799.7
 $0.6
 $3,889.4
          
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
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.










APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 20182019 and December 31, 20172018
(in millions)
(Unaudited)
 March 31, December 31, March 31, December 31,
 2018 2017 2019 2018
CURRENT ASSETS        
Cash and Cash Equivalents $1.2
 $2.9
 $2.9
 $4.2
Restricted Cash for Securitized Funding 10.1
 16.3
 18.3
 25.6
Advances to Affiliates 23.5
 23.5
 216.6
 23.0
Accounts Receivable:        
Customers 137.9
 123.1
 144.4
 146.5
Affiliated Companies 67.6
 69.3
 60.3
 73.4
Accrued Unbilled Revenues 75.1
 74.1
 61.7
 63.5
Miscellaneous 1.0
 1.1
 1.1
 2.3
Allowance for Uncollectible Accounts (3.5) (3.7) (2.8) (2.3)
Total Accounts Receivable 278.1
 263.9
 264.7
 283.4
Fuel 72.1
 89.3
 69.9
 61.3
Materials and Supplies 97.4
 99.5
 102.1
 100.1
Risk Management Assets 8.0
 24.9
 12.9
 57.2
Regulatory Asset for Under-Recovered Fuel Costs 179.5
 88.8
 78.8
 99.6
Margin Deposits 32.1
 14.4
Prepayments and Other Current Assets 11.2
 12.7
 33.9
 44.3
TOTAL CURRENT ASSETS 713.2
 636.2
 800.1
 698.7
        
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
Generation 6,466.9
 6,446.9
 6,531.5
 6,509.6
Transmission 3,032.5
 3,019.9
 3,330.1
 3,317.7
Distribution 3,795.8
 3,763.8
 4,014.6
 3,989.4
Other Property, Plant and Equipment 440.2
 427.9
 504.5
 485.8
Construction Work in Progress 558.8
 483.0
 524.9
 490.2
Total Property, Plant and Equipment 14,294.2
 14,141.5
 14,905.6
 14,792.7
Accumulated Depreciation and Amortization 3,956.8
 3,896.4
 4,174.9
 4,124.4
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 10,337.4
 10,245.1
 10,730.7
 10,668.3
        
OTHER NONCURRENT ASSETS        
Regulatory Assets 552.3
 573.9
 469.6
 475.8
Securitized Assets 276.4
 282.3
 252.7
 258.7
Long-term Risk Management Assets 2.6
 1.1
 0.3
 0.9
Operating Lease Assets 79.1
 —
Deferred Charges and Other Noncurrent Assets 195.1
 190.0
 194.9
 188.1
TOTAL OTHER NONCURRENT ASSETS 1,026.4
 1,047.3
 996.6
 923.5
        
TOTAL ASSETS $12,077.0
 $11,928.6
 $12,527.4
 $12,290.5
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.








APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
March 31, 20182019 and December 31, 20172018
(Unaudited)
 March 31, December 31, March 31, December 31,
 2018 2017 2019 2018
 (in millions) (in millions)
CURRENT LIABILITIES        
Advances from Affiliates $245.9
 $186.0
 $—
 $205.6
Accounts Payable:  
  
  
  
General 218.1
 264.9
 218.7
 263.8
Affiliated Companies 88.1
 92.7
 80.8
 84.0
Long-term Debt Due Within One Year – Nonaffiliated 249.5
 249.2
 345.0
 430.7
Risk Management Liabilities 0.6
 1.3
 6.1
 0.4
Customer Deposits 86.5
 86.1
 88.3
 88.4
Accrued Taxes 119.0
 94.5
 92.3
 89.3
Accrued Interest 62.9
 40.5
 74.2
 41.5
Obligations Under Operating Leases 15.0
 —
Other Current Liabilities 111.3
 109.0
 103.7
 150.3
TOTAL CURRENT LIABILITIES 1,181.9
 1,124.2
 1,024.1
 1,354.0
        
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated 3,719.8
 3,730.9
 4,099.0
 3,631.9
Long-term Risk Management Liabilities 0.4
 0.2
 0.2
 0.2
Deferred Income Taxes 1,586.0
 1,565.7
 1,615.4
 1,625.8
Regulatory Liabilities and Deferred Investment Tax Credits 1,444.3
 1,454.9
 1,415.7
 1,449.7
Asset Retirement Obligations 98.4
 100.2
 106.2
 107.1
Employee Benefits and Pension Obligations 68.6
 73.3
 54.3
 57.1
Obligations Under Operating Leases 64.8
 —
Deferred Credits and Other Noncurrent Liabilities 88.2
 74.7
 58.7
 58.6
TOTAL NONCURRENT LIABILITIES 7,005.7
 6,999.9
 7,414.3
 6,930.4
        
TOTAL LIABILITIES 8,187.6
 8,124.1
 8,438.4
 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
 260.4
 260.4
Paid-in Capital 1,828.7
 1,828.7
 1,828.7
 1,828.7
Retained Earnings 1,799.7
 1,714.1
 2,005.7
 1,922.0
Accumulated Other Comprehensive Income (Loss) 0.6
 1.3
 (5.8) (5.0)
TOTAL COMMON SHAREHOLDER’S EQUITY 3,889.4
 3,804.5
 4,089.0
 4,006.1
        
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $12,077.0
 $11,928.6
 $12,527.4
 $12,290.5
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.






APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 20182019 and 20172018
(in millions)
(Unaudited)
 Three Months Ended March 31, Three Months Ended March 31,
 2018 2017 2019 2018
OPERATING ACTIVITIES  
  
  
  
Net Income $125.5
 $110.6
 $133.7
 $125.5
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
  
  
Depreciation and Amortization 108.5
 100.6
 112.5
 108.5
Deferred Income Taxes 11.0
 52.2
 (45.0) 11.0
Allowance for Equity Funds Used During Construction (2.6) (1.5) (1.7) (2.6)
Mark-to-Market of Risk Management Contracts 14.9
 6.8
 50.6
 14.9
Deferred Fuel Over/Under-Recovery, Net (90.7) 1.1
 20.8
 (90.7)
Change in Other Noncurrent Assets 3.9
 1.0
 (12.1) 3.9
Change in Other Noncurrent Liabilities 37.9
 (3.7) (20.5) 37.9
Changes in Certain Components of Working Capital:  
  
  
  
Accounts Receivable, Net (14.2) (2.2) 19.5
 (14.2)
Fuel, Materials and Supplies 19.3
 (6.9) (9.6) 19.3
Accounts Payable (21.6) (12.7) (8.3) (21.6)
Accrued Taxes, Net 17.8
 9.4
 13.7
 17.8
Other Current Assets (15.8) 7.8
 (0.8) (15.8)
Other Current Liabilities 5.6
 (3.5) (2.3) 5.6
Net Cash Flows from Operating Activities 199.5
 259.0
 250.5
 199.5
        
INVESTING ACTIVITIES  
  
  
  
Construction Expenditures (218.5) (223.7) (205.1) (218.5)
Change in Advances to Affiliates, Net —
 0.4
 (193.6) —
Other Investing Activities 4.4
 1.4
 15.2
 4.4
Net Cash Flows Used for Investing Activities (214.1) (221.9) (383.5) (214.1)
        
FINANCING ACTIVITIES  
  
  
  
Issuance of Long-term Debt – Nonaffiliated 393.3
 —
Change in Advances from Affiliates, Net 59.9
 102.8
 (205.6) 59.9
Retirement of Long-term Debt – Nonaffiliated (11.7) (115.9) (12.0) (11.7)
Principal Payments for Capital Lease Obligations (1.7) (1.8)
Principal Payments for Finance Lease Obligations (1.6) (1.7)
Dividends Paid on Common Stock (40.0) (30.0) (50.0) (40.0)
Other Financing Activities 0.2
 0.3
 0.3
 0.2
Net Cash Flows from (Used for) Financing Activities 6.7
 (44.6)
Net Cash Flows from Financing Activities 124.4
 6.7
        
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding (7.9) (7.5) (8.6) (7.9)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period 19.2
 18.5
 29.8
 19.2
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period $11.3
 $11.0
 $21.2
 $11.3
        
SUPPLEMENTARY INFORMATION  
  
  
  
Cash Paid for Interest, Net of Capitalized Amounts $23.4
 $23.8
 $14.5
 $23.4
Noncash Acquisitions Under Capital Leases 1.8
 0.5
Net Cash Paid for Income Taxes 8.0
 —
Noncash Acquisitions Under Finance Leases 2.1
 1.8
Construction Expenditures Included in Current Liabilities as of March 31, 94.5
 63.7
 87.8
 94.5
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.








INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES




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


RESULTS OF OPERATIONS


KWh Sales/Degree Days
Summary of KWh Energy Sales
Three Months Ended March 31,Three Months Ended March 31,
2018 20172019 2018
(in millions of KWhs)(in millions of KWhs)
Retail: 
  
 
  
Residential1,623
 1,492
1,615
 1,623
Commercial1,176
 1,157
1,156
 1,164
Industrial1,904
 1,896
1,888
 1,916
Miscellaneous20
 20
19
 20
Total Retail(a)4,723
 4,565
4,678
 4,723
      
Wholesale2,926
 2,954
2,423
 2,926
      
Total KWhs7,649
 7,519
7,101
 7,649


(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 March 31,Three Months Ended March 31,
2018 20172019 2018
(in degree days)(in degree days)
Actual – Heating (a)2,157
 1,648
2,239
 2,157
Normal – Heating (b)2,168
 2,185
2,160
 2,168
      
Actual – Cooling (c)—
 —
—
 —
Normal – Cooling (b)2
 2
2
 2


(a) Heating degree days are calculated on a 55 degree temperature base.
(b) Normal Heating/Cooling represents the thirty-year average of degree days.
(c) Cooling degree days are calculated on a 65 degree temperature base.





First Quarter of 20182019 Compared to First Quarter of 20172018
Reconciliation of First Quarter of 2017 to First Quarter of 2018
Reconciliation of First Quarter of 2018 to First Quarter of 2019Reconciliation of First Quarter of 2018 to First Quarter of 2019
Net Income(in millions)
    
First Quarter of 2017 $68.4
First Quarter of 2018 $64.2
  
  
Changes in Gross Margin:  
  
Retail Margins 3.2
 56.4
Off-system Sales 0.4
 (7.3)
Transmission Revenues 2.8
 (1.0)
Other Revenues (2.7) (3.1)
Total Change in Gross Margin 3.7
 45.0
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance (12.1) 1.8
Depreciation and Amortization (9.3) (26.9)
Taxes Other Than Income Taxes (2.1) (2.3)
Interest Income (0.9)
Carrying Cost Income (1.0)
Allowance for Equity Funds Used During Construction (0.3)
Other Income 1.3
Non-Service Cost Components of Net Periodic Benefit Cost 3.0
 (0.1)
Interest Expense (2.0) 0.8
Total Change in Expenses and Other (24.7) (25.4)
  
  
Income Tax Expense 16.8
Income Tax Expense (Benefit) 15.1
  
  
First Quarter of 2018 $64.2
First Quarter of 2019 $98.9


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


Retail Margins increased $3 million primarily due to the following:
•
Retail Margins increased $56 million primarily due to the following:
A $25$47 million increase from rate proceedings, ininclusive of a $9 million decrease due to the I&M service territory. Theimpact of Tax Reform. This increase in Retail Margins relating to riders has corresponding increaseswas partially offset in other expense items below.
A $14$4 million decrease in fuel-related expenses due to timing of recovery for fuel and other variable production costs related to wholesale contracts.
A $3 million increase in weather-related usage primarily due to a 31%4% increase in heating degree days.
These increases were partially offset by:
A $16 million decrease related to the 2018 provisions for customer refunds primarily related to Tax Reform. This decrease is offset in Income Tax Expense below.
An $8 million decrease related to over/under recovery of riders.
A $4 million decrease due to lower weather-normalized margins primarily due to wholesale customer load loss from contracts that expired atincreased costs for power acquired under the endUPA between AEGCo and I&M as a result of 2017.
A $4 million decreaseincreased depreciation rates for Rockport Plant approved by the FERC in FERC generation wholesale municipal and cooperative revenues primarily due to changes to the annual formula rate.January 2019.
•
Margins from Off-system Sales decreased $7 million primarily due to mid-year 2018 changes in the OSS sharing mechanism.
A $3 million decrease due to increased fuel and other variable production costs not recovered through fuel clauses or other trackers.


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


•
Other Operation and Maintenance expenses decreased $2 million primarily due to the following:
Other Operation and MaintenanceA $4 million decrease in generation expenses increased $12 millionat Cook Plant primarily due to the following:
a decrease in various maintenance activities.
A $12$3 million increasedecrease in transmission expenses primarily due to an $8 million decrease from the 2018 Regional Transmission Enhancement Plan settlement, partially offset by a $6 million increase in recoverable PJM expenses.Expenses. This increasedecrease was partially offset withinin Retail Margins above.
These decreases were partially offset by:
A $4 million increase in Cook Plant refueling outage amortization expense,distribution costs primarily due to increased costs of outages.vegetation management expenses.
•
Depreciation and Amortization expensesincreased $27 million primarily due to a higher depreciable base and increased depreciation rates approved in 2018. This increase was partially offset in Retail Margins above.
•
Income Tax Expense (Benefit) decreased $15 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.
These increases were partially offset by:
A $7 million decrease due to an increased Nuclear Electric Insurance Limited distribution in 2018.


Depreciation and Amortization expensesincreased $9 million primarily due to a higher depreciable base.
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 and by moving to a Medicare Advantage arrangement for post-65 retirees in the Non-UMWA OPEB plan. Additionally, the decrease was partially due to the implementation of ASU 2017-07 in 2018, which eliminated I&M’s ability to capitalize a portion of its non-service cost components.

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




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 20182019 and 20172018
(in millions)
(Unaudited)
 Three Months Ended March 31, Three Months Ended March 31,
 2018 2017 2019 2018
REVENUES    
    
Electric Generation, Transmission and Distribution $553.9
 $538.5
 $596.7
 $553.9
Sales to AEP Affiliates 4.7
 0.6
 2.3
 4.7
Other Revenues – Affiliated 13.2
 18.1
 13.3
 13.2
Other Revenues – Nonaffiliated 5.0
 3.3
 2.0
 5.0
TOTAL REVENUES 576.8
 560.5
 614.3
 576.8
        
EXPENSES  
  
  
  
Fuel and Other Consumables Used for Electric Generation 77.5
 90.7
 57.6
 77.5
Purchased Electricity for Resale 55.6
 37.3
 69.6
 55.6
Purchased Electricity from AEP Affiliates 61.4
 53.9
 59.8
 61.4
Other Operation 146.1
 137.1
 140.5
 146.1
Maintenance 54.5
 51.4
 58.3
 54.5
Depreciation and Amortization 59.3
 50.0
 86.2
 59.3
Taxes Other Than Income Taxes 25.0
 22.9
 27.3
 25.0
TOTAL EXPENSES 479.4
 443.3
 499.3
 479.4
        
OPERATING INCOME 97.4
 117.2
 115.0
 97.4
        
Other Income (Expense):  
  
  
  
Interest Income 0.2
 1.1
Carrying Costs Income 2.4
 3.4
Allowance for Equity Funds Used During Construction 1.8
 2.1
Other Income 5.7
 4.4
Non-Service Cost Components of Net Periodic Benefit Cost 4.5
 1.5
 4.4
 4.5
Interest Expense (29.7) (27.7) (28.9) (29.7)
        
INCOME BEFORE INCOME TAX EXPENSE 76.6
 97.6
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 96.2
 76.6
        
Income Tax Expense 12.4
 29.2
Income Tax Expense (Benefit) (2.7) 12.4
        
NET INCOME $64.2
 $68.4
 $98.9
 $64.2
The common stock of I&M is wholly-owned by Parent.
 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.






INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 20182019 and 20172018
(in millions)
(Unaudited)
Three Months Ended March 31,Three Months Ended March 31,
2018 20172019 2018
Net Income$64.2
 $68.4
$98.9
 $64.2
      
OTHER COMPREHENSIVE INCOME, NET OF TAXES 
  
 
  
Cash Flow Hedges, Net of Tax of $0.1 and $0.2 in 2018 and 2017, Respectively0.4
 0.3
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 in 2019 and 2018, Respectively0.4
 0.4
      
TOTAL COMPREHENSIVE INCOME$64.6
 $68.7
$99.3
 $64.6
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Three Months Ended March 31, 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  
  
 (31.3)  
 (31.3)
Net Income  
  
 68.4
  
 68.4
Other Comprehensive Income  
  
  
 0.3
 0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2017 $56.6
 $980.9
 $1,167.6
 $(15.9) $2,189.2
  
  
  
  
  
 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
 $56.6
 $980.9
 $1,192.2
 $(12.1) $2,217.6
                    
Common Stock Dividends  
  
 (33.5)  
 (33.5)  
  
 (33.5)  
 (33.5)
ASU 2018-02 Adoption     0.3
 (2.7) (2.4)     0.3
 (2.7) (2.4)
Net Income  
  
 64.2
  
 64.2
  
  
 64.2
  
 64.2
Other Comprehensive Income  
  
  
 0.4
 0.4
  
  
  
 0.4
 0.4
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018 $56.6
 $980.9
 $1,223.2
 $(14.4) $2,246.3
 $56.6
 $980.9
 $1,223.2
 $(14.4) $2,246.3
  
  
  
  
  
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
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 20182019 and December 31, 20172018
(in millions)
(Unaudited)
 March 31, December 31, March 31, December 31,
 2018 2017 2019 2018
CURRENT ASSETS        
Cash and Cash Equivalents $0.6
 $1.3
 $1.7
 $2.4
Advances to Affiliates 12.5
 12.4
 12.8
 12.7
Accounts Receivable:        
Customers 48.7
 56.4
 62.9
 63.1
Affiliated Companies 49.9
 50.0
 55.4
 75.0
Accrued Unbilled Revenues 8.1
 7.3
 8.1
 3.6
Miscellaneous 5.4
 2.0
 1.2
 1.4
Allowance for Uncollectible Accounts —
 (0.1) (0.2) (0.1)
Total Accounts Receivable 112.1
 115.6
 127.4
 143.0
Fuel 35.2
 31.4
 32.0
 37.3
Materials and Supplies 161.6
 160.6
 166.1
 167.3
Risk Management Assets 3.3
 7.6
 4.4
 8.6
Accrued Tax Benefits 65.0
 58.4
 12.0
 26.6
Regulatory Asset for Under-Recovered Fuel Costs 12.4
 15.0
Accrued Reimbursement of Spent Nuclear Fuel Costs 6.2
 10.8
 23.5
 7.9
Margin Deposits 25.6
 11.5
Prepayments and Other Current Assets 13.6
 9.4
 23.4
 24.6
TOTAL CURRENT ASSETS 448.1
 434.0
 403.3
 430.4
        
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
Generation 4,464.5
 4,445.9
 4,895.0
 4,887.2
Transmission 1,523.5
 1,504.0
 1,588.9
 1,576.8
Distribution 2,097.3
 2,069.3
 2,291.5
 2,249.7
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) 610.9
 595.2
 580.1
 583.8
Construction Work in Progress 503.5
 460.2
 533.5
 465.3
Total Property, Plant and Equipment 9,199.7
 9,074.6
 9,889.0
 9,762.8
Accumulated Depreciation, Depletion and Amortization 3,073.1
 3,024.2
 3,208.4
 3,151.6
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 6,126.6
 6,050.4
 6,680.6
 6,611.2
        
OTHER NONCURRENT ASSETS        
Regulatory Assets 589.2
 579.4
 504.7
 512.5
Spent Nuclear Fuel and Decommissioning Trusts 2,510.6
 2,527.6
 2,684.0
 2,474.9
Long-term Risk Management Assets 2.0
 0.7
 0.1
 0.6
Operating Lease Assets 326.3
 —
Deferred Charges and Other Noncurrent Assets 168.4
 179.9
 171.0
 193.0
TOTAL OTHER NONCURRENT ASSETS 3,270.2
 3,287.6
 3,686.1
 3,181.0
        
TOTAL ASSETS $9,844.9
 $9,772.0
 $10,770.0
 $10,222.6
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
March 31, 20182019 and December 31, 20172018
(dollars in millions)
(Unaudited)
 March 31, December 31, March 31, December 31,
 2018 2017 2019 2018
CURRENT LIABILITIES        
Advances from Affiliates $314.1
 $211.6
 $34.7
 $1.1
Accounts Payable:        
General 164.8
 154.5
 160.3
 174.7
Affiliated Companies 81.4
 98.3
 70.4
 70.2
Long-term Debt Due Within One Year – Nonaffiliated
(March 31, 2018 and December 31, 2017 Amounts Include $88.1 and $96.3, Respectively, Related to DCC Fuel)
 941.5
 474.7
Long-term Debt Due Within One Year – Nonaffiliated
(March 31, 2019 and December 31, 2018 Amounts Include $61.8 and $76.8, Respectively, Related to DCC Fuel)
 140.4
 155.4
Risk Management Liabilities 3.8
 3.5
 0.3
 0.3
Customer Deposits 38.0
 37.7
 38.6
 38.0
Accrued Taxes 89.6
 81.3
 101.7
 90.7
Accrued Interest 14.8
 37.5
 20.9
 37.3
Obligations Under Capital Leases 5.8
 5.8
Obligations Under Operating Leases 81.8
 —
Regulatory Liability for Over-Recovered Fuel Costs 22.2
 27.4
Other Current Liabilities 102.7
 106.4
 68.2
 103.0
TOTAL CURRENT LIABILITIES 1,756.5
 1,211.3
 739.5
 698.1
        
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated 1,775.7
 2,270.4
 2,871.0
 2,880.0
Long-term Risk Management Liabilities 0.2
 0.1
 0.1
 0.1
Deferred Income Taxes 978.3
 953.8
 951.1
 948.0
Regulatory Liabilities and Deferred Investment Tax Credits 1,660.2
 1,708.7
 1,743.5
 1,574.5
Asset Retirement Obligations 1,336.0
 1,321.6
 1,697.8
 1,681.3
Obligations Under Operating Leases 266.0
 —
Deferred Credits and Other Noncurrent Liabilities 91.7
 88.5
 68.9
 87.8
TOTAL NONCURRENT LIABILITIES 5,842.1
 6,343.1
 7,598.4
 7,171.7
        
TOTAL LIABILITIES 7,598.6
 7,554.4
 8,337.9
 7,869.8
        
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
 56.6
 56.6
Paid-in Capital 980.9
 980.9
 980.9
 980.9
Retained Earnings 1,223.2
 1,192.2
 1,408.0
 1,329.1
Accumulated Other Comprehensive Income (Loss) (14.4) (12.1) (13.4) (13.8)
TOTAL COMMON SHAREHOLDER’S EQUITY 2,246.3
 2,217.6
 2,432.1
 2,352.8
        
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $9,844.9
 $9,772.0
 $10,770.0
 $10,222.6
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 20182019 and 20172018
(in millions)
(Unaudited)
 Three Months Ended March 31, Three Months Ended March 31,
 2018 2017 2019 2018
OPERATING ACTIVITIES  
  
  
  
Net Income $64.2
 $68.4
 $98.9
 $64.2
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
  
  
Depreciation and Amortization 59.3
 50.0
 86.2
 59.3
Deferred Income Taxes 13.7
 48.8
 (13.9) 13.7
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net (12.3) 16.6
Deferral of Incremental Nuclear Refueling Outage Expenses, Net (14.8) (12.3)
Carrying Costs Income 0.7
 (2.4)
Allowance for Equity Funds Used During Construction (1.8) (2.1) (6.2) (1.8)
Mark-to-Market of Risk Management Contracts 3.4
 2.3
 4.7
 3.4
Amortization of Nuclear Fuel 27.4
 35.1
 25.1
 27.4
Deferred Fuel Over/Under-Recovery, Net 3.4
 19.6
 (5.2) 3.4
Change in Other Noncurrent Assets (13.4) (17.6) 12.8
 (11.0)
Change in Other Noncurrent Liabilities 33.7
 13.5
 5.2
 33.7
Changes in Certain Components of Working Capital:  
  
  
  
Accounts Receivable, Net 3.5
 3.0
 16.0
 3.5
Fuel, Materials and Supplies (4.5) (8.5) 6.6
 (4.5)
Accounts Payable 1.3
 (22.5) (3.1) 1.3
Accrued Taxes, Net 8.2
 (6.9) 25.6
 8.2
Other Current Assets (11.1) 15.8
 1.4
 (11.1)
Other Current Liabilities (27.8) (41.2) (35.2) (27.8)
Net Cash Flows from Operating Activities 147.2
 174.3
 204.8
 147.2
        
INVESTING ACTIVITIES  
  
  
  
Construction Expenditures (148.9) (159.7) (149.3) (148.9)
Change in Advances to Affiliates, Net (0.1) —
 (0.1) (0.1)
Purchases of Investment Securities (525.3) (505.5) (130.3) (525.3)
Sales of Investment Securities 508.6
 487.9
 111.9
 508.6
Acquisitions of Nuclear Fuel (23.8) (3.7) (32.4) (23.8)
Other Investing Activities 4.2
 2.0
 8.6
 4.2
Net Cash Flows Used for Investing Activities (185.3) (179.0) (191.6) (185.3)
        
FINANCING ACTIVITIES  
  
  
  
Issuance of Long-term Debt – Nonaffiliated —
 76.7
Change in Advances from Affiliates, Net 102.5
 71.6
 33.6
 102.5
Retirement of Long-term Debt – Nonaffiliated (29.4) (109.5) (26.5) (29.4)
Principal Payments for Capital Lease Obligations (2.7) (2.9)
Principal Payments for Finance Lease Obligations (1.2) (2.7)
Dividends Paid on Common Stock (33.5) (31.3) (20.0) (33.5)
Other Financing Activities 0.5
 0.1
 0.2
 0.5
Net Cash Flows from Financing Activities 37.4
 4.7
Net Cash Flows from (Used for) Financing Activities (13.9) 37.4
        
Net Decrease in Cash and Cash Equivalents (0.7) —
 (0.7) (0.7)
Cash and Cash Equivalents at Beginning of Period 1.3
 1.2
 2.4
 1.3
Cash and Cash Equivalents at End of Period $0.6
 $1.2
 $1.7
 $0.6
        
SUPPLEMENTARY INFORMATION  
  
  
  
Cash Paid for Interest, Net of Capitalized Amounts $50.6
 $44.3
 $43.3
 $50.6
Net Cash Paid for Income Taxes —
 0.6
Noncash Acquisitions Under Capital Leases 1.7
 1.5
Net Cash Paid (Received) for Income Taxes (3.3) —
Noncash Acquisitions Under Finance Leases 1.7
 1.7
Construction Expenditures Included in Current Liabilities as of March 31, 77.2
 75.9
 80.0
 77.2
Acquisition of Nuclear Fuel Included in Current Liabilities as of March 31, 0.1
 —
 1.0
 0.1
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage 0.1
 1.0
 7.9
 0.1
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




OHIO POWER COMPANY AND SUBSIDIARIES






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


RESULTS OF OPERATIONS


KWh Sales/Degree Days


Summary of KWh Energy Sales
Three Months Ended March 31,Three Months Ended March 31,
2018 20172019 2018
(in millions of KWhs)(in millions of KWhs)
Retail: 
  
 
  
Residential4,133
 3,693
4,123
 4,133
Commercial3,552
 3,428
3,527
 3,533
Industrial3,554
 3,569
3,623
 3,573
Miscellaneous31
 32
31
 31
Total Retail (a)(b)11,270
 10,722
11,304
 11,270
      
Wholesale (b)(c)667

674
638

667
      
Total KWhs11,937
 11,396
11,942
 11,937


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


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


Summary of Heating and Cooling Degree Days
Three Months Ended March 31,Three Months Ended March 31,
2018 20172019 2018
(in degree days)(in degree days)
Actual – Heating (a)1,884
 1,403
1,892
 1,884
Normal – Heating (b)1,884
 1,899
1,877
 1,884
      
Actual – Cooling (c)4
 3
1
 4
Normal – Cooling (b)3
 3
3
 3


(a) Heating degree days are calculated on a 55 degree temperature base.
(b) Normal Heating/Cooling represents the thirty-year average of degree days.
(c) Cooling degree days are calculated on a 65 degree temperature base.





First Quarter of 20182019 Compared to First Quarter of 20172018
Reconciliation of First Quarter of 2017 to First Quarter of 2018
Reconciliation of First Quarter of 2018 to First Quarter of 2019Reconciliation of First Quarter of 2018 to First Quarter of 2019
Net Income(in millions)
    
First Quarter of 2017 $86.2
First Quarter of 2018 $79.6
  
  
Changes in Gross Margin:  
  
Retail Margins 31.8
 75.3
Off-system Sales 7.2
 (0.8)
Transmission Revenues (6.4) 10.4
Other Revenues (0.9) 2.6
Total Change in Gross Margin 31.7
 87.5
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance (49.9) (40.0)
Depreciation and Amortization (7.5) 1.5
Taxes Other Than Income Taxes (6.6) (3.8)
Interest Income (1.6) (0.1)
Carrying Costs Income (1.2) (0.5)
Allowance for Equity Funds Used During Construction 0.1
 2.7
Non-Service Cost Components of Net Periodic Benefit Cost 2.8
 (0.2)
Interest Expense (0.2) 0.6
Total Change in Expenses and Other (64.1) (39.8)
  
  
Income Tax Expense 25.8
 0.7
  
  
First Quarter of 2018 $79.6
First Quarter of 2019 $128.0


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


Retail Margins increased $32
•
Retail Margins increased $75 million primarily due to the following:
A $58 million increase due to the following:
a reversal of a regulatory provision.
A $39$17 million net increase in Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset by a correspondingan increase in Other Operation and Maintenance expenses below.
A $21$10 million increase in revenues associated with the Universal Service Fund (USF).smart grid riders. This increase was partially offset by increases in other expense items below.
A $5 million increase in Energy Efficiency/Peak Demand Reduction rider revenues. This increase was offset by a corresponding increase in Other Operation and Maintenance expenses below.
A $9 million increase in usage primarily in the residential class.
A $6 million increase in rider revenues associated with the DIR. This increase was partially offset in various expenses below.
A $4 million net increase in RSR revenues less associated amortizations.
These increases were partially offset by:
A $16 million decrease due to the 2018 provisions for customer refunds primarily related to Tax Reform. This decrease is offset in Income Tax Expense below.
An $11$6 million decrease in Energy Efficiency/Peak Demand Reduction rider revenues.revenues associated with vegetation management riders. This decrease was partially offset by a corresponding decrease in Other Operation and Maintenance expenses below.
A $10$4 million net decrease in margin for the Phase-In-Recovery Rider including associated amortizations.
•
Transmission Revenues increased $10 million primarily due to 2018 provisions for refunds.
A $7 million decrease due to the recovery of lower current year losses from a power contract with OVEC. This decrease was offset by a corresponding increase in Margins from Off-system Sales below.
A $7 million decrease in revenues associated with smart grid riders. This decrease was partially offset by a corresponding decrease in various expenses below.


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


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


Other Operation and Maintenance expenses increased $50 million primarily due to the following:
•
Other Operation and Maintenance expenses increased $40 million primarily due to the following:
A $35$31 million increase in recoverable PJM expenses. This increase was offset by a corresponding increase in Retailwithin Gross Margins above.
A $21$10 million increase in remitted USF surcharge paymentsPJM expenses primarily related to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers.annual formula rate true-up.
A $5 million increase in Energy Efficiency/Peak Demand Reduction rider costs and associated deferrals. This increase was offset by a corresponding increase in Retail Margins above.
These increases were partially offset by:
A $10$5 million decrease in Energy Efficiency/Peak Demand Reduction rider costs and associated deferrals.recoverable distribution expenses related to vegetation management. This decrease was partially offset by a decrease in Retail Margins above.
•
Depreciation and Amortization expenses decreased $2 million primarily due to the following:
Depreciation and Amortization expensesincreased $8A $10 million primarily due to the following:
A $6 million increasedecrease in recoverable DIR depreciation expense. This increasedecrease was partially offset in Retail Margins above.
This decrease was offset by:
A $3$7 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
•
Taxes Other Than Income Taxes increased $4 million primarily due to an increase in property taxes due to additional investments in transmission and distribution assets and higher tax rates.
•
Income Tax Expense decreased $1 million due to increased amortization of Excess ADIT not subject to normalization requirements partially offset by an increase in pretax book income. This decrease was partially offset in Gross Margin above.
A $2 million increase primarily due to amortization of capitalized software costs.
These increases were partially offset by:
A $3 million decrease in recoverable smart grid depreciation expenses. This decrease was offset in Retail Margins above.
Taxes Other Than Income Taxes increased by $7 million primarily due to the following:
A $4 million increase in property taxes due to additional investments in transmission and distribution assets and higher tax rates.
A $3 million increase in state excise taxes due to an increase in metered KWh. This increase was offset by a corresponding increase in Retail Margins above.
Income Tax Expense decreased $26 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform and a decrease in pretax book income.




OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 20182019 and 20172018
(in millions)
(Unaudited)
 Three Months Ended March 31, Three Months Ended March 31,
 2018 2017 2019 2018
REVENUES        
Electricity, Transmission and Distribution $786.3
 $738.4
 $826.5
 $786.3
Sales to AEP Affiliates 3.1
 5.7
 7.5
 3.1
Other Revenues 1.5
 2.0
 2.8
 1.5
TOTAL REVENUES 790.9
 746.1
 836.8
 790.9
        
EXPENSES  
  
  
  
Purchased Electricity for Resale 205.5
 188.3
 174.2
 205.5
Purchased Electricity from AEP Affiliates 30.2
 32.0
 46.1
 30.2
Amortization of Generation Deferrals 58.6
 60.9
 32.4
 58.6
Other Operation 172.2
 122.3
 216.9
 172.2
Maintenance 37.2
 37.2
 32.5
 37.2
Depreciation and Amortization 64.8
 57.3
 63.3
 64.8
Taxes Other Than Income Taxes 105.1
 98.5
 108.9
 105.1
TOTAL EXPENSES 673.6
 596.5
 674.3
 673.6
        
OPERATING INCOME 117.3
 149.6
 162.5
 117.3
        
Other Income (Expense):  
  
  
  
Interest Income 0.9
 2.5
 0.8
 0.9
Carrying Costs Income 0.7
 1.9
 0.2
 0.7
Allowance for Equity Funds Used During Construction 2.5
 2.4
 5.2
 2.5
Non-Service Cost Components of Net Periodic Benefit Cost 3.9
 1.1
 3.7
 3.9
Interest Expense (25.2) (25.0) (24.6) (25.2)
        
INCOME BEFORE INCOME TAX EXPENSE 100.1
 132.5
 147.8
 100.1
        
Income Tax Expense 20.5
 46.3
 19.8
 20.5
        
NET INCOME $79.6
 $86.2
 $128.0
 $79.6
The common stock of OPCo is wholly-owned by Parent.
 
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 20182019 and 20172018
(in millions)
(Unaudited)
Three Months Ended March 31,Three Months Ended March 31,
2018 20172019 2018
Net Income$79.6
 $86.2
$128.0
 $79.6
      
OTHER COMPREHENSIVE LOSS, NET OF TAXES      
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) in 2018 and 2017, Respectively(0.3) (0.2)
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) in 2019 and 2018, Respectively(0.3) (0.3)
 
  
 
  
TOTAL COMPREHENSIVE INCOME$79.3
 $86.0
$127.7
 $79.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Three Months Ended March 31, 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 $321.2
 $838.8
 $954.5
 $3.0
 $2,117.5
          
Common Stock Dividends  
  
 (65.0)  
 (65.0)
Net Income  
  
 86.2
  
 86.2
Other Comprehensive Loss  
  
  
 (0.2) (0.2)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2017 $321.2
 $838.8
 $975.7
 $2.8
 $2,138.5
  
  
  
  
  
 Common
Stock		 Paid-in
Capital		 Retained
Earnings		 Accumulated
Other
Comprehensive
Income (Loss)		 Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017 $321.2
 $838.8
 $1,148.4
 $1.9
 $2,310.3
 $321.2
 $838.8
 $1,148.4
 $1.9
 $2,310.3
                    
Common Stock Dividends  
  
 (112.5)  
 (112.5)  
  
 (112.5)  
 (112.5)
ASU 2018-02 Adoption       0.4
 0.4
       0.4
 0.4
Net Income  
  
 79.6
  
 79.6
  
  
 79.6
  
 79.6
Other Comprehensive Loss  
  
  
 (0.3) (0.3)  
  
  
 (0.3) (0.3)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018 $321.2
 $838.8
 $1,115.5
 $2.0
 $2,277.5
 $321.2
 $838.8
 $1,115.5
 $2.0
 $2,277.5
  
  
  
  
  
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
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 20182019 and December 31, 20172018
(in millions)
(Unaudited)
 March 31, December 31, March 31, December 31,
 2018 2017 2019 2018
CURRENT ASSETS        
Cash and Cash Equivalents $1.4
 $3.1
 $3.3
 $4.9
Restricted Cash for Securitized Funding 15.9
 26.6
 16.5
 27.6
Advances to Affiliates 200.4
 —
Accounts Receivable:        
Customers 42.0
 67.8
 89.4
 111.1
Affiliated Companies 60.4
 70.2
 55.9
 70.8
Accrued Unbilled Revenues 27.2
 29.7
 27.1
 21.4
Miscellaneous 1.2
 1.9
 0.4
 0.3
Allowance for Uncollectible Accounts (0.6) (0.6) (0.6) (1.0)
Total Accounts Receivable 130.2
 169.0
 172.2
 202.6
Materials and Supplies 41.2
 41.9
 42.9
 42.9
Renewable Energy Credits 24.8
 25.0
 27.1
 25.9
Risk Management Assets 0.4
 0.6
Regulatory Asset for Under-Recovered Fuel Costs 89.3
 115.9
Prepayments and Other Current Assets 27.1
 15.8
 15.1
 15.7
TOTAL CURRENT ASSETS 530.7
 397.9
 277.1
 319.6
        
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
Transmission 2,440.5
 2,419.2
 2,551.7
 2,544.3
Distribution 4,669.3
 4,626.4
 5,026.6
 4,942.3
Other Property, Plant and Equipment 518.9
 495.9
 580.0
 574.8
Construction Work in Progress 432.0
 410.1
 461.0
 432.1
Total Property, Plant and Equipment 8,060.7
 7,951.6
 8,619.3
 8,493.5
Accumulated Depreciation and Amortization 2,205.7
 2,184.8
 2,224.1
 2,218.6
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 5,855.0
 5,766.8
 6,395.2
 6,274.9
        
OTHER NONCURRENT ASSETS        
Regulatory Assets 597.6
 652.8
 375.0
 387.5
Securitized Assets 31.4
 37.7
 7.3
 12.9
Deferred Charges and Other Noncurrent Assets 342.0
 406.5
 464.2
 441.0
TOTAL OTHER NONCURRENT ASSETS 971.0
 1,097.0
 846.5
 841.4
        
TOTAL ASSETS $7,356.7
 $7,261.7
 $7,518.8
 $7,435.9
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
March 31, 20182019 and December 31, 20172018
(dollars in millions)
(Unaudited)
 March 31, December 31, March 31, December 31,
 2018 2017 2019 2018
CURRENT LIABILITIES        
Advances from Affiliates $—
 $87.8
 $227.6
 $114.1
Accounts Payable:  
  
  
  
General 159.9
 205.8
 177.7
 211.9
Affiliated Companies 105.5
 118.2
 91.1
 102.9
Long-term Debt Due Within One Year – Nonaffiliated
(March 31, 2018 and December 31, 2017 Amounts Include $47.5 and $47, Respectively, Related to Ohio Phase-in-Recovery Funding)
 397.5
 397.0
Long-term Debt Due Within One Year – Nonaffiliated
(March 31, 2019 and December 31, 2018 Amounts Include $24.5 and $47.8, Respectively, Related to Ohio Phase-in-Recovery Funding)		 24.6
 47.9
Risk Management Liabilities 5.3
 6.4
 6.9
 5.8
Customer Deposits 76.5
 69.2
 103.1
 113.1
Accrued Taxes 418.5
 512.5
 423.4
 537.8
Accrued Interest 38.7
 31.0
Obligations Under Operating Leases 13.0
 —
Other Current Liabilities 161.2
 165.9
 147.2
 214.2
TOTAL CURRENT LIABILITIES 1,363.1
 1,593.8
 1,214.6
 1,347.7
        
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated
(March 31, 2018 and December 31, 2017 Amounts Include $24.3 and $47.5, Respectively, Related to Ohio Phase-in-Recovery Funding)
 1,692.2
 1,322.3
Long-term Debt – Nonaffiliated 1,669.0
 1,668.7
Long-term Risk Management Liabilities 93.2
 126.0
 99.4
 93.8
Deferred Income Taxes 759.0
 762.9
 782.3
 763.3
Regulatory Liabilities and Deferred Investment Tax Credits 1,120.8
 1,100.2
 1,234.4
 1,221.2
Obligations Under Operating Leases 74.0
 —
Deferred Credits and Other Noncurrent Liabilities 50.9
 46.2
 45.0
 43.8
TOTAL NONCURRENT LIABILITIES 3,716.1
 3,357.6
 3,904.1
 3,790.8
        
TOTAL LIABILITIES 5,079.2
 4,951.4
 5,118.7
 5,138.5
        
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
 321.2
 321.2
Paid-in Capital 838.8
 838.8
 838.8
 838.8
Retained Earnings 1,115.5
 1,148.4
 1,239.4
 1,136.4
Accumulated Other Comprehensive Income (Loss) 2.0
 1.9
 0.7
 1.0
TOTAL COMMON SHAREHOLDER’S EQUITY 2,277.5
 2,310.3
 2,400.1
 2,297.4
        
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $7,356.7
 $7,261.7
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY $7,518.8
 $7,435.9
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 20182019 and 20172018
(in millions)
(Unaudited)
 Three Months Ended March 31, Three Months Ended March 31,
 2018 2017 2019 2018
OPERATING ACTIVITIES  
  
  
  
Net Income $79.6
 $86.2
 $128.0
 $79.6
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:  
  
  
  
Depreciation and Amortization 64.8
 57.3
 63.3
 64.8
Amortization of Generation Deferrals 58.6
 60.9
 32.4
 58.6
Deferred Income Taxes (4.9) 36.7
 10.1
 (4.9)
Carrying Costs Income (0.7) (1.9) (0.2) (0.7)
Allowance for Equity Funds Used During Construction (2.5) (2.4) (5.2) (2.5)
Mark-to-Market of Risk Management Contracts (33.7) 5.7
 6.7
 (33.7)
Property Taxes 62.9
 58.4
 66.0
 62.9
Provision for Refund – Global Settlement (5.4) —
 (4.1) (5.4)
Reversal of a Regulatory Provision (56.2) —
Change in Other Noncurrent Assets 14.3
 (45.8) (7.3) 14.3
Change in Other Noncurrent Liabilities 40.6
 30.6
 17.6
 40.6
Changes in Certain Components of Working Capital:  
  
  
  
Accounts Receivable, Net 38.8
 30.2
 31.7
 38.8
Materials and Supplies (1.9) (1.8) (3.4) (1.9)
Accounts Payable (22.5) (34.9) (23.9) (22.5)
Accrued Taxes, Net (92.8) (107.2) (114.4) (92.8)
Other Current Assets (7.5) (0.3) (7.7) (7.5)
Other Current Liabilities (2.9) (31.2) (16.2) (2.9)
Net Cash Flows from Operating Activities 184.8
 140.5
 117.2
 184.8
        
INVESTING ACTIVITIES  
  
  
  
Construction Expenditures (168.2) (108.4) (198.5) (168.2)
Change in Advances to Affiliates, Net (200.4) 24.2
 —
 (200.4)
Other Investing Activities 1.7
 2.0
 3.7
 1.7
Net Cash Flows Used for Investing Activities (366.9) (82.2) (194.8) (366.9)
        
FINANCING ACTIVITIES  
  
  
  
Issuance of Long-term Debt – Nonaffiliated 393.3
 —
 —
 393.3
Change in Advances from Affiliates, Net (87.8) 18.3
 113.5
 (87.8)
Retirement of Long-term Debt – Nonaffiliated (22.9) (22.5) (23.4) (22.9)
Principal Payments for Capital Lease Obligations (0.9) (1.0)
Principal Payments for Finance Lease Obligations (0.7) (0.9)
Dividends Paid on Common Stock (112.5) (65.0) (25.0) (112.5)
Other Financing Activities 0.5
 0.6
 0.5
 0.5
Net Cash Flows from (Used for) Financing Activities 169.7
 (69.6)
Net Cash Flows from Financing Activities 64.9
 169.7
        
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding (12.4) (11.3) (12.7) (12.4)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period 29.7
 30.3
 32.5
 29.7
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period $17.3
 $19.0
 $19.8
 $17.3
        
SUPPLEMENTARY INFORMATION  
  
  
  
Cash Paid for Interest, Net of Capitalized Amounts $17.0
 $17.2
 $17.0
 $17.0
Net Cash Paid for Income Taxes —
 1.7
Noncash Acquisitions Under Capital Leases 1.4
 1.3
Net Cash Paid (Received) for Income Taxes (0.2) —
Noncash Acquisitions Under Finance Leases 3.2
 1.4
Construction Expenditures Included in Current Liabilities as of March 31, 52.3
 28.3
 72.8
 52.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




PUBLIC SERVICE COMPANY OF OKLAHOMA




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


RESULTS OF OPERATIONS


KWh Sales/Degree Days


Summary of KWh Energy Sales
Three Months Ended March 31,Three Months Ended March 31,
2018 20172019 2018
(in millions of KWhs)(in millions of KWhs)
Retail: 
  
 
  
Residential1,493
 1,312
1,520
 1,493
Commercial1,162
 1,130
1,089
 1,083
Industrial1,340
 1,306
1,433
 1,419
Miscellaneous276
 273
274
 276
Total Retail(a)4,271
 4,021
4,316
 4,271
      
Wholesale157
 81
245
 157
      
Total KWhs4,428
 4,102
4,561
 4,428


(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 March 31,Three Months Ended March 31,
2018 20172019 2018
(in degree days)(in degree days)
Actual – Heating (a)1,032
 670
1,171
 1,032
Normal – Heating (b)1,041
 1,062
1,032
 1,041
      
Actual – Cooling (c)12
 59
3
 12
Normal – Cooling (b)17
 14
17
 17


(a) Heating degree days are calculated on a 55 degree temperature base.
(b) Normal Heating/Cooling represents the thirty-year average of degree days.
(c) Cooling degree days are calculated on a 65 degree temperature base.





First Quarter of 20182019 Compared to First Quarter of 20172018
Reconciliation of First Quarter of 2017 to First Quarter of 2018
Reconciliation of First Quarter of 2018 to First Quarter of 2019Reconciliation of First Quarter of 2018 to First Quarter of 2019
Net Income (Loss)(in millions)
    
First Quarter of 2017 $4.8
First Quarter of 2018 $(7.2)
    
Changes in Gross Margin:    
Retail Margins (a) (0.2) 5.8
Off-system Sales 0.1
 0.1
Transmission Revenues (1.4)
Other Revenues (0.4) 1.4
Total Change in Gross Margin (0.5) 5.9
    
Changes in Expenses and Other:  
  
Other Operation and Maintenance (11.2) 17.6
Depreciation and Amortization (3.3) (6.7)
Taxes Other Than Income Taxes (1.0) 0.2
Other Income 0.1
Non-Service Cost Components of Net Periodic Benefit Cost 1.3
 (0.1)
Other Income (0.5)
Interest Expense (1.1) (2.2)
Total Change in Expenses and Other (15.8) 8.9
  
  
Income Tax Expense 4.3
Income Tax Benefit (1.4)
  
  
First Quarter of 2018 $(7.2)
First Quarter of 2019 $6.2


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


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


•
Retail Margins increased $6 million primarily due to the following:
Retail Margins were consistent with the prior yearAn $11 million increase due to the following:
new base rates implemented in March 2018.
A $5$2 million increase in weather-related usage due to a 13% increase in heating degree days.
A $2 million increase in revenue from rate riders. This increase in Retail Margins iswas partially offset by a corresponding increase to riders/trackers recognized in other expense items below.
A $4 million increase due to new rates implemented in March 2018, inclusive of a $2 million decrease due to the change in the corporate federal tax rate.
A $3 million increase in weather-related usage due to a 54% increase in heating degree days.
These increases were partially offset by:
A $6 million decrease due to 2018 provisions for customer refunds primarily related to Tax Reform. This decrease is offset in Income Tax Expense below.
A $5 million decrease related to the System Reliability Rider (SRR) that ended in August 2017. This decrease is partially offset by a corresponding decrease recognized in other expense items below.
A $1An $8 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 decreased $18 million primarily due to the following:
Other Operation and Maintenance expenses increased $11A $5 million primarily due to the following:
A $9 million increasedecrease in transmission expenses primarily due to increaseda decrease in SPP transmission services.
A $4$5 million increase due to the Wind Catcher Project.
A $3 million increasedecrease in Energy Efficiency program costs. This increase was offsetcosts due to a change in the amortizations of costs approved by an increase from rate riders in Retail Margins above.




These increases were partially offset by:the OCC.
A $6$5 million decrease in the amortization of previously deferreddistribution expenses related to vegetation management costs collected through the SRR. Thismanagement.
A $4 million decrease was partially offset by a corresponding decrease in Retail Margins above.
Depreciation and Amortization expenses increased $3 million primarily due to the following:Wind Catcher Project expenses incurred in 2018.
•
Depreciation and Amortization expenses increased $7 million primarily due to a higher depreciable base and increased depreciation rates implemented in March 2018.

A $2 million increase due to a higher depreciable base.
A $1 million increase due to amortization of capitalized software costs.
Income Tax Expense decreased $4 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, amortization of excess accumulated deferred income taxes associated with certain depreciable property and a decrease in pretax book income.




PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF OPERATIONS
For the Three Months Ended March 31, 20182019 and 20172018
(in millions)
(Unaudited)
 Three Months Ended March 31, Three Months Ended March 31,
 2018 2017 2019 2018
REVENUES        
Electric Generation, Transmission and Distribution $335.1
 $301.9
 $329.2
 $335.1
Sales to AEP Affiliates 1.1
 1.1
 1.6
 1.1
Other Revenues 0.6
 1.1
 2.0
 0.6
TOTAL REVENUES 336.8
 304.1
 332.8
 336.8
        
EXPENSES  
  
  
  
Fuel and Other Consumables Used for Electric Generation 48.4
 12.3
 38.0
 48.4
Purchased Electricity for Resale 122.4
 125.3
 122.9
 122.4
Other Operation 86.8
 68.3
 73.6
 86.8
Maintenance 26.9
 34.2
 22.5
 26.9
Depreciation and Amortization 36.8
 33.5
 43.5
 36.8
Taxes Other Than Income Taxes 11.6
 10.6
 11.4
 11.6
TOTAL EXPENSES 332.9
 284.2
 311.9
 332.9
        
OPERATING INCOME 3.9
 19.9
 20.9
 3.9
        
Other Income (Expense):  
  
  
  
Other Income —
 0.5
 0.1
 —
Non-Service Cost Components of Net Periodic Benefit Cost

 2.2
 0.9
 2.1
 2.2
Interest Expense (14.7) (13.6) (16.9) (14.7)
        
INCOME (LOSS) BEFORE INCOME TAX EXPENSE (CREDIT) (8.6) 7.7
INCOME (LOSS) BEFORE INCOME TAX BENEFIT 6.2
 (8.6)
        
Income Tax Expense (Credit) (1.4) 2.9
Income Tax Benefit —
 (1.4)
        
NET INCOME (LOSS) $(7.2) $4.8
 $6.2
 $(7.2)
The common stock of PSO is wholly-owned by Parent.
     
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 20182019 and 20172018
(in millions)
(Unaudited)
Three Months Ended March 31,Three Months Ended March 31,
2018 20172019 2018
Net Income (Loss)$(7.2) $4.8
$6.2
 $(7.2)
      
OTHER COMPREHENSIVE LOSS, NET OF TAXES 
  
 
  
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) in 2018 and 2017, Respectively(0.2) (0.2)
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) in 2019 and 2018, Respectively(0.2) (0.2)
 
  
 
  
TOTAL COMPREHENSIVE INCOME (LOSS)$(7.4) $4.6
$6.0
 $(7.4)
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Three Months Ended March 31, 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 $157.2
 $364.0
 $689.5
 $3.4
 $1,214.1
          
Common Stock Dividends  
  
 (17.5)  
 (17.5)
Net Income  
  
 4.8
  
 4.8
Other Comprehensive Loss  
  
  
 (0.2) (0.2)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2017 $157.2
 $364.0
 $676.8
 $3.2
 $1,201.2
  
  
  
  
  
 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
 $157.2
 $364.0
 $691.5
 $2.6
 $1,215.3
                    
Common Stock Dividends  
  
 (12.5)  
 (12.5)  
  
 (12.5)  
 (12.5)
ASU 2018-02 Adoption       0.5
 0.5
       0.5
 0.5
Net Loss  
  
 (7.2)  
 (7.2)  
  
 (7.2)  
 (7.2)
Other Comprehensive Loss  
  
  
 (0.2) (0.2)  
  
  
 (0.2) (0.2)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018 $157.2
 $364.0
 $671.8
 $2.9
 $1,195.9
 $157.2
 $364.0
 $671.8
 $2.9
 $1,195.9
  
  
  
  
  
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
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.






PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
March 31, 20182019 and December 31, 20172018
(in millions)
(Unaudited)
 March 31, December 31, March 31, December 31,
 2018 2017 2019 2018
CURRENT ASSETS        
Cash and Cash Equivalents $0.6
 $1.6
 $1.5
 $2.0
Accounts Receivable:        
Customers 30.9
 32.5
 35.7
 32.5
Affiliated Companies 27.7
 32.9
 24.3
 26.2
Miscellaneous 3.9
 4.1
 3.6
 5.7
Allowance for Uncollectible Accounts —
 (0.1) (0.4) (0.1)
Total Accounts Receivable 62.5
 69.4
 63.2
 64.3
Fuel 13.0
 12.5
 10.0
 12.3
Materials and Supplies 43.2
 42.0
 43.9
 44.8
Risk Management Assets 2.9
 6.4
 5.0
 10.4
Accrued Tax Benefits 30.2
 28.1
 9.5
 14.7
Regulatory Asset for Under-Recovered Fuel Costs 22.7
 36.7
Prepayments and Other Current Assets 7.5
 8.6
 12.7
 9.4
TOTAL CURRENT ASSETS 182.6
 205.3
 145.8
 157.9
        
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
Generation 1,572.4
 1,577.2
 1,568.6
 1,577.0
Transmission 862.0
 858.8
 899.8
 892.3
Distribution 2,475.5
 2,445.1
 2,600.1
 2,572.8
Other Property, Plant and Equipment 297.0
 287.4
 306.0
 303.5
Construction Work in Progress 110.3
 111.3
 98.6
 94.0
Total Property, Plant and Equipment 5,317.2
 5,279.8
 5,473.1
 5,439.6
Accumulated Depreciation and Amortization 1,415.5
 1,393.6
 1,496.2
 1,472.9
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 3,901.7
 3,886.2
 3,976.9
 3,966.7
        
OTHER NONCURRENT ASSETS        
Regulatory Assets 366.8
 368.1
 365.1
 369.0
Employee Benefits and Pension Assets 40.4
 40.0
 32.0
 31.7
Operating Lease Assets 34.8
 —
Deferred Charges and Other Noncurrent Assets 34.2
 8.7
 37.9
 7.1
TOTAL OTHER NONCURRENT ASSETS 441.4
 416.8
 469.8
 407.8
        
TOTAL ASSETS $4,525.7
 $4,508.3
 $4,592.5
 $4,532.4
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
March 31, 20182019 and December 31, 20172018
(Unaudited)
 March 31, December 31, March 31, December 31,
 2018 2017 2019 2018
 (in millions) (in millions)
CURRENT LIABILITIES        
Advances from Affiliates $179.1
 $149.6
 $55.2
 $105.5
Accounts Payable:  
  
  
  
General 88.7
 102.4
 90.1
 126.9
Affiliated Companies 51.5
 48.0
 45.9
 47.1
Long-term Debt Due Within One Year – Nonaffiliated 0.5
 0.5
 375.5
 375.5
Risk Management Liabilities 0.7
 1.0
Customer Deposits 54.5
 54.1
 59.2
 58.6
Accrued Taxes 42.1
 22.6
 42.5
 22.4
Accrued Interest 19.3
 14.1
Obligations Under Operating Leases 5.7
 —
Regulatory Liability for Over-Recovered Fuel Costs 17.7
 20.1
Other Current Liabilities 34.8
 44.7
 63.5
 64.5
TOTAL CURRENT LIABILITIES 470.5
 436.0
 756.0
 821.6
        
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated 1,286.2
 1,286.0
 1,010.7
 911.5
Deferred Income Taxes 639.6
 642.0
 610.6
 607.8
Regulatory Liabilities and Deferred Investment Tax Credits 851.5
 853.5
 861.2
 864.7
Asset Retirement Obligations 53.7
 53.0
 47.9
 46.3
Obligations Under Operating Leases 29.1
 —
Deferred Credits and Other Noncurrent Liabilities 28.3
 22.5
 34.3
 32.5
TOTAL NONCURRENT LIABILITIES 2,859.3
 2,857.0
 2,593.8
 2,462.8
        
TOTAL LIABILITIES 3,329.8
 3,293.0
 3,349.8
 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
 157.2
 157.2
Paid-in Capital 364.0
 364.0
 364.0
 364.0
Retained Earnings 671.8
 691.5
 719.6
 724.7
Accumulated Other Comprehensive Income (Loss) 2.9
 2.6
 1.9
 2.1
TOTAL COMMON SHAREHOLDER’S EQUITY 1,195.9
 1,215.3
 1,242.7
 1,248.0
        
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY $4,525.7
 $4,508.3
 $4,592.5
 $4,532.4
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 20182019 and 20172018
(in millions)
(Unaudited)
 Three Months Ended March 31, Three Months Ended March 31,
 2018 2017 2019 2018
OPERATING ACTIVITIES  
  
  
  
Net Income (Loss) $(7.2) $4.8
 $6.2
 $(7.2)
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from (Used for) Operating Activities:  
  
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities:  
  
Depreciation and Amortization 36.8
 33.5
 43.5
 36.8
Deferred Income Taxes (4.5) 27.4
 (5.8) (4.5)
Allowance for Equity Funds Used During Construction 0.1
 (0.4) (0.1) 0.1
Mark-to-Market of Risk Management Contracts 3.5
 0.3
 5.1
 3.5
Property Taxes (30.1) (29.8) (29.9) (30.1)
Deferred Fuel Over/Under-Recovery, Net 14.6
 (13.1) (2.4) 14.6
Change in Other Noncurrent Assets —
 (9.3) 8.0
 —
Change in Other Noncurrent Liabilities 5.7
 (1.9) (0.7) 5.7
Changes in Certain Components of Working Capital:  
  
  
  
Accounts Receivable, Net 6.9
 16.6
 2.0
 6.9
Fuel, Materials and Supplies (1.7) 3.4
 3.2
 (1.7)
Accounts Payable (10.9) (27.7) (23.3) (10.9)
Accrued Taxes, Net 22.4
 (0.3) 25.3
 22.4
Other Current Assets 0.9
 0.3
 (3.8) 0.9
Other Current Liabilities (1.3) (22.3) 4.4
 (1.3)
Net Cash Flows from (Used for) Operating Activities 35.2
 (18.5)
Net Cash Flows from Operating Activities 31.7
 35.2
        
INVESTING ACTIVITIES  
  
  
  
Construction Expenditures (54.4) (75.7) (70.7) (54.4)
Other Investing Activities 2.0
 0.9
 0.4
 2.0
Net Cash Flows Used for Investing Activities (52.4) (74.8) (70.3) (52.4)
        
FINANCING ACTIVITIES  
  
  
  
Issuance of Long-term Debt – Nonaffiliated 99.9
 —
Change in Advances from Affiliates, Net 29.5
 111.7
 (50.3) 29.5
Retirement of Long-term Debt – Nonaffiliated (0.1) (0.1) (0.1) (0.1)
Principal Payments for Capital Lease Obligations (1.0) (1.1)
Principal Payments for Finance Lease Obligations (0.7) (1.0)
Dividends Paid on Common Stock (12.5) (17.5) (11.3) (12.5)
Other Financing Activities 0.3
 0.1
 0.6
 0.3
Net Cash Flows from Financing Activities 16.2
 93.1
 38.1
 16.2
        
Net Decrease in Cash and Cash Equivalents (1.0) (0.2) (0.5) (1.0)
Cash and Cash Equivalents at Beginning of Period 1.6
 1.5
 2.0
 1.6
Cash and Cash Equivalents at End of Period $0.6
 $1.3
 $1.5
 $0.6
        
SUPPLEMENTARY INFORMATION  
  
  
  
Cash Paid for Interest, Net of Capitalized Amounts $10.3
 $15.9
 $10.9
 $10.3
Net Cash Paid (Received) for Income Taxes —
 (2.6)
Noncash Acquisitions Under Capital Leases 0.9
 0.7
Net Cash Paid for Income Taxes 0.6
 —
Noncash Acquisitions Under Finance Leases 1.1
 0.9
Construction Expenditures Included in Current Liabilities as of March 31, 25.4
 22.3
 15.6
 25.4
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED






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


RESULTS OF OPERATIONS


KWh Sales/Degree Days


Summary of KWh Energy Sales
Three Months Ended March 31,Three Months Ended March 31,
2018 20172019 2018
(in millions of KWhs)(in millions of KWhs)
Retail: 
  
 
  
Residential1,558
 1,310
1,528
 1,558
Commercial1,288
 1,305
1,273
 1,310
Industrial1,199
 1,222
1,250
 1,177
Miscellaneous19
 20
20
 19
Total Retail(a)4,064
 3,857
4,071
 4,064
      
Wholesale1,908
 2,439
1,979
 1,908
      
Total KWhs5,972
 6,296
6,050
 5,972


(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 March 31,Three Months Ended March 31,
2018 20172019 2018
(in degree days)(in degree days)
Actual – Heating (a)729
 388
708
 729
Normal – Heating (b)707
 720
698
 707
      
Actual – Cooling (c)60
 106
20
 60
Normal – Cooling (b)38
 34
39
 38


(a) Heating degree days are calculated on a 55 degree temperature base.
(b) Normal Heating/Cooling represents the thirty-year average of degree days.
(c) Cooling degree days are calculated on a 65 degree temperature base.







First Quarter of 20182019 Compared to First Quarter of 20172018
Reconciliation of First Quarter of 2017 to First Quarter of 2018
Reconciliation of First Quarter of 2018 to First Quarter of 2019Reconciliation of First Quarter of 2018 to First Quarter of 2019
Earnings Attributable to SWEPCo Common Shareholder(in millions)
    
First Quarter of 2017 $16.3
First Quarter of 2018 $11.8
  
  
Changes in Gross Margin:  
  
Retail Margins (a) 10.2
 6.1
Off-system Sales (1.1) 0.6
Transmission Revenues 2.7
 (1.7)
Other Revenues 0.1
 0.1
Total Change in Gross Margin 11.9
 5.1
  
  
Changes in Expenses and Other:  
  
Other Operation and Maintenance (14.8) 12.4
Depreciation and Amortization (6.6) (4.7)
Taxes Other Than Income Taxes (1.7) (0.3)
Interest Income 0.9
 (1.1)
Allowance for Equity Funds Used During Construction 1.5
 (0.5)
Non-Service Cost Components of Net Periodic Benefit Cost 1.4
 (0.2)
Interest Expense (2.3) 2.5
Total Change in Expenses and Other (21.6) 8.1
  
  
Income Tax Expense 6.6
 2.2
Equity Earnings of Unconsolidated Subsidiary (0.8) 0.2
Net Income Attributable to Noncontrolling Interest (0.6) 0.4
  
  
First Quarter of 2018 $11.8
First Quarter of 2019 $27.8


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


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


Retail Margins increased $10 million primarily due to the following:
•
Retail Margins increased $6 million primarily due to the following:
A $22$4 million increase primarily due to rider and base rate revenue increases in Texas and Louisiana. This increase was partially offset by corresponding increases in other expense items below.
A $14$4 million increase in weather-related usage primarily due to an 88% increase in heating degree days.higher weather-normalized margins.
These increases were partially offset by:
A $15$3 million decrease due to lower weather-normalized margins,in weather-related usage primarily due to wholesale customer load loss from contracts that expired at the end of 2017.
A $12 milliona 67% decrease due to the 2018 provisions for customer refunds primarily related to Tax Reform. Thisin cooling degree days and a 3% decrease is offset in Income Tax Expense below.
Transmission Revenues increased $3 million primarily due to an increase in transmission investments in SPP.
heating degree days.
      
Expenses and Other and Income Tax Expense changed between years as follows:


•
Other Operation and Maintenance expenses decreased $12 million primarily due to Wind Catcher Project expenses incurred in 2018.
•
Depreciation and Amortization expenses increased $5 million primarily due to higher depreciation rates implemented in the third quarter of 2018 and a higher depreciable base.
•
Interest Expense decreased $3 million primarily due to lower interest rates on outstanding long-term debt.
•
Income Tax Expense decreased $2 million primarily due to an increase in amortization of Excess ADIT not subject to normalization requirements, partially offset by an increase in pretax book income. This decrease was partially offset in Gross Margin above.
Other Operation and Maintenance expenses increased $15 million primarily due to the following:
A $10 million increase due to the Wind Catcher Project.
A $5 million increase in SPP transmission services.
A $3 million increase in employee-related expenses.
These increases were partially offset by:
A $4 million decrease in distribution expenses primarily due to distribution system improvements in 2017.
Depreciation and Amortization expenses increased $7 million primarily due to a higher depreciable base.


Income Tax Expense decreased $7 million primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform, amortization of excess accumulated deferred income taxes associated with certain depreciable property and a decrease in pretax book income.




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 20182019 and 20172018
(in millions)
(Unaudited)
 Three Months Ended March 31, Three Months Ended March 31,
 2018 2017 2019 2018
REVENUES        
Electric Generation, Transmission and Distribution $413.0
 $396.3
 $414.3
 $413.0
Sales to AEP Affiliates 6.1
 4.6
 6.4
 6.1
Other Revenues 0.3
 0.4
 0.4
 0.3
TOTAL REVENUES 419.4
 401.3
 421.1
 419.4
        
EXPENSES  
  
  
  
Fuel and Other Consumables Used for Electric Generation 126.8
 130.9
 133.5
 126.8
Purchased Electricity for Resale 42.7
 32.4
 32.6
 42.7
Other Operation 94.9
 78.9
 84.6
 94.9
Maintenance 31.0
 32.2
 28.9
 31.0
Depreciation and Amortization 57.4
 50.8
 62.1
 57.4
Taxes Other Than Income Taxes 25.0
 23.3
 25.3
 25.0
TOTAL EXPENSES 377.8
 348.5
 367.0
 377.8
        
OPERATING INCOME 41.6
 52.8
 54.1
 41.6
        
Other Income (Expense):  
  
  
  
Interest Income 1.8
 0.9
 0.7
 1.8
Allowance for Equity Funds Used During Construction 2.3
 0.8
 1.8
 2.3
Non-Service Cost Components of Net Periodic Benefit Cost 2.3
 0.9
 2.1
 2.3
Interest Expense (32.2) (29.9) (29.7) (32.2)
        
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS 15.8
 25.5
 29.0
 15.8
        
Income Tax Expense 2.9
 9.5
 0.7
 2.9
Equity Earnings of Unconsolidated Subsidiary 0.5
 1.3
 0.7
 0.5
        
NET INCOME 13.4
 17.3
 29.0
 13.4
        
Net Income Attributable to Noncontrolling Interest 1.6
 1.0
 1.2
 1.6
        
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER $11.8
 $16.3
 $27.8
 $11.8
The common stock of SWEPCo is wholly-owned by Parent.
     
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 20182019 and 20172018
(in millions)
(Unaudited)
Three Months Ended March 31,Three Months Ended March 31,
2018 20172019 2018
Net Income$13.4
 $17.3
$29.0
 $13.4
      
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES 
  
 
  
Cash Flow Hedges, Net of Tax of $0.1 and $0.2 in 2018 and 2017, Respectively0.4
 0.5
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) in 2018 and 2017, Respectively(0.3) (0.2)
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 in 2019 and 2018, Respectively0.4
 0.4
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) in 2019 and 2018, Respectively(0.3) (0.3)
      
TOTAL OTHER COMPREHENSIVE INCOME0.1
 0.3
0.1
 0.1
      
TOTAL COMPREHENSIVE INCOME13.5
 17.6
29.1
 13.5
      
Total Comprehensive Income Attributable to Noncontrolling Interest1.6
 1.0
1.2
 1.6
 
  
 
  
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER$11.9
 $16.6
$27.9
 $11.9
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Three Months Ended March 31, 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    (27.5)     (27.5)
Common Stock Dividends – Nonaffiliated 
  
  
  
 (1.1) (1.1)
Net Income 
  
 16.3
  
 1.0
 17.3
Other Comprehensive Income 
  
  
 0.3
  
 0.3
TOTAL EQUITY – MARCH 31, 2017$135.7
 $676.6
 $1,400.7
 $(9.1) $0.3
 $2,204.2
           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 
  
 (20.0)  
  
 (20.0)    (20.0)     (20.0)
Common Stock Dividends – Nonaffiliated 
  
  
  
 (0.8) (0.8) 
  
  
  
 (0.8) (0.8)
ASU 2018-02 Adoption    (0.4) (0.9)   (1.3)    (0.4) (0.9)   (1.3)
Net Income 
  
 11.8
  
 1.6
 13.4
 
  
 11.8
  
 1.6
 13.4
Other Comprehensive Income 
  
  
 0.1
  
 0.1
 
  
  
 0.1
  
 0.1
TOTAL EQUITY – MARCH 31, 2018$135.7
 $676.6
 $1,418.0
 $(4.8) $0.4
 $2,225.9
$135.7
 $676.6
 $1,418.0
 $(4.8) $0.4
 $2,225.9
           
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, 2019$135.7
 $676.6
 $1,517.5
 $(5.3) $0.4
 $2,324.9
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




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

 $0.7
 $1.6
Cash and Cash Equivalents
(March 31, 2019 and December 31, 2018 Amounts Include $20.2 and $22, Respectively, Related to Sabine)
 $22.1
 $24.5
Advances to Affiliates 2.0
 2.0
 2.0
 83.4
Accounts Receivable:        
Customers 67.0
 70.9
 32.0
 24.5
Affiliated Companies 18.0
 30.2
 20.0
 28.8
Miscellaneous 13.2
 25.8
 18.2
 20.2
Allowance for Uncollectible Accounts (0.5) (1.3) (1.2) (0.7)
Total Accounts Receivable 97.7
 125.6
 69.0
 72.8
Fuel
(March 31, 2018 and December 31, 2017 Amounts Include $37.7 and $41.5, Respectively, Related to Sabine)
 120.5
 123.6
Fuel
(March 31, 2019 and December 31, 2018 Amounts Include $31.4 and $35.7, Respectively, Related to Sabine)
 135.1
 120.5
Materials and Supplies 68.8
 67.9
 69.1
 67.5
Risk Management Assets 1.7
 6.4
 2.0
 4.8
Regulatory Asset for Under-Recovered Fuel Costs 16.5
 14.1
 15.6
 18.8
Prepayments and Other Current Assets 40.2
 39.2
 31.3
 22.2
TOTAL CURRENT ASSETS 348.1
 380.4
 346.2
 414.5
        
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
Generation 4,622.6
 4,624.9
 4,711.6
 4,672.6
Transmission 1,715.0
 1,679.8
 1,907.2
 1,866.9
Distribution 2,108.1
 2,095.8
 2,204.9
 2,178.6
Other Property, Plant and Equipment
(March 31, 2018 and December 31, 2017 Amounts Include $264.9 and $266.7, Respectively, Related to Sabine)
 704.4
 684.1
Other Property, Plant and Equipment
(March 31, 2019 and December 31, 2018 Amounts Include $210 and $276.9, Respectively, Related to Sabine)
 658.9
 762.7
Construction Work in Progress 266.9
 233.2
 193.4
 199.3
Total Property, Plant and Equipment 9,417.0
 9,317.8
 9,676.0
 9,680.1
Accumulated Depreciation and Amortization
(March 31, 2018 and December 31, 2017 Amounts Include $167.4 and $165.9, Respectively, Related to Sabine)
 2,724.7
 2,685.8
Accumulated Depreciation and Amortization
(March 31, 2019 and December 31, 2018 Amounts Include $99.3 and $174.6, Respectively, Related to Sabine)
 2,760.6
 2,808.3
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
 6,692.3
 6,632.0
 6,915.4
 6,871.8
        
OTHER NONCURRENT ASSETS        
Regulatory Assets 217.9
 220.6
 226.6
 230.8
Deferred Charges and Other Noncurrent Assets 165.5
 109.9
 193.8
 111.2
TOTAL OTHER NONCURRENT ASSETS 383.4
 330.5
 420.4
 342.0
        
TOTAL ASSETS $7,423.8
 $7,342.9
 $7,682.0
 $7,628.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
March 31, 20182019 and December 31, 20172018
(Unaudited)
 March 31, December 31, March 31, December 31,
 2018 2017 2019 2018
 (in millions) (in millions)
CURRENT LIABILITIES        
Advances from Affiliates $148.6
 $118.7
 $74.0
 $—
Accounts Payable:        
General 118.5
 160.4
 98.6
 129.1
Affiliated Companies 60.7
 63.7
 45.8
 64.2
Short-term Debt – Nonaffiliated 22.6
 22.0
Long-term Debt Due Within One Year – Nonaffiliated 457.2
 3.7
 6.2
 59.7
Risk Management Liabilities 0.1
 0.2
 0.2
 0.4
Customer Deposits 62.9
 62.1
 65.6
 64.5
Accrued Taxes 91.1
 39.0
 91.1
 42.8
Accrued Interest 25.9
 38.9
 22.0
 34.7
Obligations Under Capital Leases 11.3
 11.2
Obligations Under Finance Leases 10.6
 10.2
Obligations Under Operating Leases 6.1
 —
Other Current Liabilities 60.4
 78.7
 87.0
 107.3
TOTAL CURRENT LIABILITIES 1,059.3
 598.6
 507.2
 512.9
        
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated 2,046.5
 2,438.2
 2,652.9
 2,653.7
Long-term Risk Management Liabilities 0.5
 —
 1.9
 2.2
Deferred Income Taxes 924.2
 917.7
 910.1
 902.8
Regulatory Liabilities and Deferred Investment Tax Credits 895.2
 896.4
 922.7
 923.0
Asset Retirement Obligations 160.8
 160.3
 197.0
 191.3
Employee Benefits and Pension Obligations 18.1
 19.5
 23.7
 24.8
Obligations Under Capital Leases 56.9
 57.8
Obligations Under Finance Leases 49.3
 50.6
Obligations Under Operating Leases 32.3
 —
Deferred Credits and Other Noncurrent Liabilities 36.4
 19.9
 60.0
 51.4
TOTAL NONCURRENT LIABILITIES 4,138.6
 4,509.8
 4,849.9
 4,799.8
        
TOTAL LIABILITIES 5,197.9
 5,108.4
 5,357.1
 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 1,418.0
 1,426.6
 1,517.5
 1,508.4
Accumulated Other Comprehensive Income (Loss) (4.8) (4.0) (5.3) (5.4)
TOTAL COMMON SHAREHOLDER’S EQUITY 2,225.5
 2,234.9
 2,324.5
 2,315.3
        
Noncontrolling Interest 0.4
 (0.4) 0.4
 0.3
        
TOTAL EQUITY 2,225.9
 2,234.5
 2,324.9
 2,315.6
        
TOTAL LIABILITIES AND EQUITY $7,423.8
 $7,342.9
 $7,682.0
 $7,628.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 20182019 and 20172018
(in millions)
(Unaudited)
 Three Months Ended March 31, Three Months Ended March 31,
 2018 2017 2019 2018
OPERATING ACTIVITIES  
  
  
  
Net Income $13.4
 $17.3
 $29.0
 $13.4
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:        
Depreciation and Amortization 57.4
 50.8
 62.1
 57.4
Deferred Income Taxes 1.0
 43.1
 (2.5) 1.0
Allowance for Equity Funds Used During Construction (2.3) (0.8) (1.8) (2.3)
Mark-to-Market of Risk Management Contracts 5.1
 0.4
 2.3
 5.1
Property Taxes (48.8) (45.3) (48.9) (48.8)
Deferred Fuel Over/Under-Recovery, Net (4.6) (3.4) 10.3
 (4.6)
Change in Other Noncurrent Assets 1.3
 (0.6) 2.9
 1.3
Change in Other Noncurrent Liabilities 18.8
 (12.1) 7.9
 18.8
Changes in Certain Components of Working Capital:        
Accounts Receivable, Net 27.9
 23.1
 6.3
 27.9
Fuel, Materials and Supplies 2.2
 12.5
 (16.2) 2.2
Accounts Payable (24.6) (33.5) (55.0) (24.6)
Accrued Taxes, Net 55.2
 11.8
 52.7
 55.2
Accrued Interest (13.0) (20.3) (12.7) (13.0)
Other Current Assets (0.8) 3.2
 (10.0) (0.8)
Other Current Liabilities (12.5) (19.1) (17.0) (12.5)
Net Cash Flows from Operating Activities 75.7
 27.1
 9.4
 75.7
        
INVESTING ACTIVITIES        
Construction Expenditures (139.7) (75.6) (86.6) (139.7)
Change in Advances to Affiliates, Net —
 167.8
 81.4
 —
Other Investing Activities (5.4) (4.4) (3.1) (5.4)
Net Cash Flows from (Used for) Investing Activities (145.1) 87.8
Net Cash Flows Used for Investing Activities (8.3) (145.1)
        
FINANCING ACTIVITIES        
Issuance of Long-term Debt – Nonaffiliated 444.6
 —
 —
 444.6
Change in Short-term Debt, Net – Nonaffiliated 0.6
 —
 —
 0.6
Change in Advances from Affiliates, Net 29.9
 167.9
 74.0
 29.9
Retirement of Long-term Debt – Nonaffiliated (383.4) (251.7) (55.1) (383.4)
Principal Payments for Capital Lease Obligations (2.8) (2.8)
Principal Payments for Finance Lease Obligations (2.7) (2.8)
Dividends Paid on Common Stock (20.0) (27.5) (18.7) (20.0)
Dividends Paid on Common Stock – Nonaffiliated (0.8) (1.1) (1.1) (0.8)
Other Financing Activities 0.4
 0.3
 0.1
 0.4
Net Cash Flows from (Used for) Financing Activities 68.5
 (114.9) (3.5) 68.5
        
Net Decrease in Cash and Cash Equivalents (0.9) —
 (2.4) (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 $0.7
 $10.3
 $22.1
 $0.7
        
SUPPLEMENTARY INFORMATION        
Cash Paid for Interest, Net of Capitalized Amounts $43.7
 $50.6
 $40.5
 $43.7
Net Cash Paid (Received) for Income Taxes (0.1) —
 0.2
 (0.1)
Noncash Acquisitions Under Capital Leases 1.9
 1.3
Noncash Acquisitions Under Finance Leases 0.8
 1.9
Construction Expenditures Included in Current Liabilities as of March 31, 50.3
 31.8
 44.8
 50.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 120103.




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 
121104
New Accounting Pronouncements AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 
123107
Comprehensive Income AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo 
126109
Rate Matters AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 
133116
Commitments, Guarantees and Contingencies AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 
144126
DispositionsAcquisitions and Impairments AEP, APCo 
149129
Benefit Plans AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo 
150130
Business Segments AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 
152132
Derivatives and Hedging AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo 
157137
Fair Value Measurements AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo 
167148
Income Taxes AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 
184163
LeasesAEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
166
Financing Activities AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 
188
Variable Interest EntitiesAEP
195171
Revenue Fromfrom Contracts Withwith Customers AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo 
197178





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 presentation of the net income, financial position and cash flows for the interim periods for each Registrant.  Net income for the three months ended March 31, 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 averageweighted-average number of common shares outstanding during the period.  Diluted EPS is calculated by adjusting the weighted averageweighted-average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards.


The following table presents AEP’s basic and diluted EPS calculations included on the statements of income:
 Three Months Ended March 31,
 2019 2018
 (in millions, except per share data)
  
 $/share   $/share
Earnings Attributable to AEP Common Shareholders$572.8
  
 $454.4

 
        
Weighted Average Number of Basic Shares Outstanding493.3
 $1.16
 492.3
 $0.92
Weighted Average Dilutive Effect of Stock-Based Awards1.2
 —
 0.8
 —
Weighted Average Number of Diluted Shares Outstanding494.5
 $1.16
 493.1
 $0.92

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

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


Equity Units issued in March 2019 are potentially dilutive securities but were excluded from the calculation of diluted EPS for the three months ended March 31, 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 March 31, 20182019 and 2017.2018.


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


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


Reconciliation of Cash, Cash Equivalents and Restricted Cash

The following tables provide a reconciliation of Cash, Cash Equivalents and Restricted Cash reported within the balance sheet that sum to the total of the same amounts shown on the statement of cash flows:
 March 31, 2018 March 31, 2019
 AEP AEP Texas APCo OPCo AEP AEP Texas APCo OPCo
 (in millions) (in millions)
Cash and Cash Equivalents $183.4
 $0.1
 $1.2
 $1.4
 $227.7
 $0.1
 $2.9
 $3.3
Restricted Cash 133.1
 107.1
 10.1
 15.9
 135.4
 100.6
 18.3
 16.5
Total Cash, Cash Equivalents and Restricted Cash $316.5
 $107.2
 $11.3
 $17.3
 $363.1
 $100.7
 $21.2
 $19.8



  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


Revisions to Previously Issued Financial Statements (Applies to 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 June 30, 2018 period presented in AEPTCo’s previously issued financial statements in the quarterly period ended June 30, 2019 SEC Form 10-Q filing to reflect the impact of the misstatements.
AEPTCo has also corrected other 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 AEPTCo’s misstatements discussed above on all previously issued AEP financial statements in accordance with ASC 250, and concluded these misstatements were not material, individually or in the aggregate, to any prior interim and annual period financial statements. As a result, AEP recorded the correction in the third quarter of 2018.



Statement of Income
The table below reflects the effects of correcting the immaterial errors described above on AEPTCo’s statement of income for the three months ended March 31, 2018:
  Three Months Ended March 31, 2018
  As Reported Adjustments As Adjusted
  (in millions)
TOTAL REVENUES $193.5
 $(1.8) $191.7
       
EXPENSES  
    
Depreciation and Amortization 30.6
 (0.3) 30.3
TOTAL EXPENSES 80.9
 (0.3) 80.6
       
OPERATING INCOME 112.6
 (1.5) 111.1
       
Other Income (Expense):  
    
Allowance for Equity Funds Used During Construction 15.3
 (0.4) 14.9
Interest Expense (19.9) (0.4) (20.3)
       
INCOME BEFORE INCOME TAX EXPENSE 108.4
 (2.3) 106.1
       
Income Tax Expense 22.5
 (0.5) 22.0
       
NET INCOME $85.9
 $(1.8) $84.1


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 three months ended March 31, 2018:
  Three Months Ended March 31, 2018
  As Reported Adjustments As Adjusted
  (in millions)
OPERATING ACTIVITIES      
Net Income $85.9
 $(1.8) $84.1
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:      
Depreciation and Amortization 30.6
 (0.3) 30.3
Deferred Income Taxes 15.7
 (0.2) 15.5
Allowance for Equity Funds Used During Construction (15.3) 0.4
 (14.9)
Change in Other Noncurrent Assets 2.7
 0.2
 2.9
Changes in Certain Components of Working Capital:      
Accounts Receivable, Net (10.1) 0.5
 (9.6)
Accounts Payable (12.3) 1.6
 (10.7)
Accrued Taxes, Net (33.6) (0.4) (34.0)
Net Cash Flows from Operating Activities 127.1
 —
 127.1
       
INVESTING ACTIVITIES      
Net Cash Flows Used for Investing Activities (458.4) —
 (458.4)
       
FINANCING ACTIVITIES  
    
Net Cash Flows from Financing Activities 331.3
 —
 331.3
       
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      
Construction Expenditures Included in Current Liabilities as of March 31, $210.6
 $3.2
 $213.8

Statement of Changes in Member’s Equity
The statement of changes in AEPTCo’s member’s equity reflects the adjustments to Net Income of $(2) million for the three months ended March 31, 2018 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.


2. NEW ACCOUNTING PRONOUNCEMENTS


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


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

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

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

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


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


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




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

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

Management adopted ASU 2016-02 effective January 1, 2019 by means of a cumulative-effect adjustment to current system capabilities. Multiple lease system options were also evaluated.the balance sheet. Management plans to elect certain ofelected the following practical expedients upon adoption:
Practical Expedient Description
Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package) Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases.
Lease and Non-lease Components (elect by class of underlying asset) Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component.
Short-term Lease (elect by class of underlying asset) Elect as an accounting policy to not apply the recognition requirements to short-term leases.
Lease termElect to use hindsight to determine the lease term.
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 continues and the processthat qualify as leases going forward. The adoption of implementing a compliant lease system solution began in the third quarter of 2017. Management expects the new standard todid not materially impact financial position and, at this time, cannot estimate the impact. Management expects no impact to results of operations or cash flows.

Management continues to monitor industry implementation issues as well as FASB’s ongoing standard-setting activities that may result inflows, but did have a material impact on the issuance ofbalance sheet. See Note 12 - Leases for additional targeted improvements todisclosures required by the new lease guidance. Management plans to adopt ASU 2016-02 effective January 1, 2019.standard.


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


In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than 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 analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 and related implementation guidance effective January 1, 2020.




ASU 2017-07 “Compensation - Retirement Benefits”2018-15 “Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract” (ASU 2017-07)2018-15)


In March 2017,August 2018, the FASB issued ASU 2017-07 requiring2018-15 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 employer reportentity (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 cost componentcontract and which costs to expense. To eliminate diversity in practice, the new standard changes the presentation of pension and postretirement benefits inimplementation costs for cloud service arrangements that are service contracts without the same line item or items as other compensation costs. The other componentspurchase of net benefit cost are required toa license. Implementation costs for cloud service contracts will be presented on the statements of income separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor.

Management adopted ASU 2017-07 effective January 1, 2018. Presentation of the non-service components on a separate line outside of operating income was applied on a retrospective basis, using the amounts disclosedbalance sheets in the benefit plan note for the estimation basissame manner as a practical expedient. Capitalization of onlyprepayment.  The Registrants currently present implementation costs in property, plant and equipment on the service cost component was applied on a prospective basis.

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

In August 2017, the FASB issued ASU 2017-12 amending the recognition and presentation requirements for hedge accounting activities. The objectives are to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and reduce the complexity of applying hedge accounting.balance sheets.  Under the new standard, amortization of capitalized implementation costs of a hosting arrangement will be recorded in Operation and Maintenance expense over the conceptterm of recognizing hedge ineffectiveness withinthe cloud service arrangement, rather than Depreciation and Amortization expense on the statements of incomeincome.  Payments for capitalized implementation costs in the statement of cash flow hedges, which has historically been immaterial to AEP,flows will be eliminated. In addition, certain required tabular disclosures relating to fair value and cash flow hedges will be modified.classified in the same manner as payments made for fees associated with the hosting element.


The new accounting guidance is effective for interim and annual periods beginning after December 15, 2018,2019, with early adoption permitted for any interimpermitted. The amendments may be applied either retrospectively or annual periodprospectively to applicable implementation costs incurred after August 2017.the date of adoption. Management is analyzing the impact of this new standard including the possibility of early adoption, and at this time, cannot estimate the impact of adoption on results of operations, financial position or cash flows.

Management plans to adopt ASU 2018-02 “Reclassification of Certain Tax Effects from AOCI” (ASU 2018-02)

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

Management adopted ASU 2018-022018-15 prospectively, effective January 1, 2018, electing to reclassify the effects of the change in the federal corporate tax rate due to Tax Reform from AOCI to Retained Earnings. A portion of the reclassification was recorded to Regulatory Liabilities to adjust the tax effects of certain interest rate hedges in AEP's regulated jurisdictions that were previously deferred as a part of the accounting for Tax Reform. There were no other effects from Tax Reform that impacted AOCI. Management applied the new guidance at the beginning of the period of adoption. The adoption of the new standard did not have a material impact on the statement of financial position and did not impact results of operations or cash flows.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.


Presentation of Comprehensive Income


The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three months ended March 31, 20182019 and 2017.2018.  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 March 31, 20182019
 Cash Flow Hedges    
 Commodity Interest Rate 
Pension
and OPEB
 Total
 (in millions)
Balance in AOCI as of December 31, 2018$(23.0) $(12.6) $(84.8) $(120.4)
Change in Fair Value Recognized in AOCI(38.8) —
 —
 (38.8)
Amount of (Gain) Loss Reclassified from AOCI       
Purchased Electricity for Resale (a)12.3
 —
 —
 12.3
Interest Expense (a)—
 0.2
 —
 0.2
Amortization of Prior Service Cost (Credit)—
 —
 (4.8) (4.8)
Amortization of Actuarial (Gains) Losses—
 —
 3.0
 3.0
Reclassifications from AOCI, before Income Tax (Expense) Benefit12.3
 0.2
 (1.8) 10.7
Income Tax (Expense) Benefit2.6
 —
 (0.4) 2.2
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit9.7
 0.2
 (1.4) 8.5
Net Current Period Other Comprehensive Income (Loss)(29.1) 0.2
 (1.4) (30.3)
Balance in AOCI as of March 31, 2019$(52.1) $(12.4) $(86.2) $(150.7)

 Cash Flow Hedges      
 Commodity Interest Rate 
Securities
Available for Sale
 
Pension
and OPEB
 Total
 (in millions)
Balance in AOCI as of December 31, 2017$(28.4) $(13.0) $11.9
 $(38.3) $(67.8)
Change in Fair Value Recognized in AOCI12.8
 —
 —
 —
 12.8
Amount of (Gain) Loss Reclassified from AOCI         
Purchased Electricity for Resale(13.1) —
 —
 —
 (13.1)
Interest Expense—
 0.3
 —
 —
 0.3
Amortization of Prior Service Cost (Credit)—
 —
 —
 (5.0) (5.0)
Amortization of Actuarial (Gains)/Losses—
 —
 —
 3.2
 3.2
Reclassifications from AOCI, before Income Tax (Expense) Credit(13.1) 0.3
 —
 (1.8) (14.6)
Income Tax (Expense) Credit(2.8) 0.1
 —
 (0.4) (3.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit(10.3) 0.2
 —
 (1.4) (11.5)
Net Current Period Other Comprehensive Income (Loss)2.5
 0.2
 —
 (1.4) 1.3
ASU 2018-02 Adoption (a)(6.1) (2.7) —
 (8.2) (17.0)
ASU 2016-01 Adoption (a)—
 —
 (11.9) —
 (11.9)
Balance in AOCI as of March 31, 2018$(32.0) $(15.5) $—
 $(47.9) $(95.4)

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


AEP


Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 20172018
 Cash Flow Hedges      
 Commodity Interest Rate 
Securities
Available for Sale
 
Pension
and OPEB
 Total
 (in millions)
Balance in AOCI as of December 31, 2016$(23.1) $(15.7) $8.4
 $(125.9) $(156.3)
Change in Fair Value Recognized in AOCI(21.8) —
 1.2
 —
 (20.6)
Amount of (Gain) Loss Reclassified from AOCI        

Generation & Marketing Revenues(4.7) —
 —
 —
 (4.7)
Purchased Electricity for Resale12.8
 —
 —
 —
 12.8
Interest Expense—
 0.5
 —
 —
 0.5
Amortization of Prior Service Cost (Credit)—
 —
 —
 (4.9) (4.9)
Amortization of Actuarial (Gains)/Losses—
 —
 —
 5.3
 5.3
Reclassifications from AOCI, before Income Tax (Expense) Credit8.1
 0.5
 —
 0.4
 9.0
Income Tax (Expense) Credit2.8
 0.1
 —
 0.2
 3.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit5.3
 0.4
 —
 0.2
 5.9
Net Current Period Other Comprehensive Income (Loss)(16.5) 0.4
 1.2
 0.2
 (14.7)
Balance in AOCI as of March 31, 2017$(39.6) $(15.3) $9.6
 $(125.7) $(171.0)
 Cash Flow Hedges      
 Commodity Interest Rate 
Securities
Available for Sale
 
Pension
and OPEB
 Total
 (in millions)
Balance in AOCI as of December 31, 2017$(28.4) $(13.0) $11.9
 $(38.3) $(67.8)
Change in Fair Value Recognized in AOCI12.8
 —
 —
 —
 12.8
Amount of (Gain) Loss Reclassified from AOCI        

Purchased Electricity for Resale (a)(13.1) —
 —
 —
 (13.1)
Interest Expense (a)—
 0.3
 —
 —
 0.3
Amortization of Prior Service Cost (Credit)—
 —
 —
 (5.0) (5.0)
Amortization of Actuarial (Gains) Losses—
 —
 —
 3.2
 3.2
Reclassifications from AOCI, before Income Tax (Expense) Benefit(13.1) 0.3
 —
 (1.8) (14.6)
Income Tax (Expense) Benefit(2.8) 0.1
 —
 (0.4) (3.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit(10.3) 0.2
 —
 (1.4) (11.5)
Net Current Period Other Comprehensive Income (Loss)2.5
 0.2
 —
 (1.4) 1.3
ASU 2018-02 Adoption(6.1) (2.7) —
 (8.2) (17.0)
ASU 2016-01 Adoption—
 —
 (11.9) —
 (11.9)
Balance in AOCI as of March 31, 2018$(32.0) $(15.5) $—
 $(47.9) $(95.4)



AEP Texas


Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 20182019
       
  Cash Flow Hedge - Interest Rate 
Pension
and OPEB
 Total
 (in millions)
Balance in AOCI as of December 31, 2017 $(4.5) $(8.1) $(12.6)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense 0.3
 —
 0.3
Amortization of Prior Service Cost (Credit) —
 —
 —
Amortization of Actuarial (Gains)/Losses —
 0.1
 0.1
Reclassifications from AOCI, before Income Tax (Expense) Credit 0.3
 0.1
 0.4
Income Tax (Expense) Credit 0.1
 —
 0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.2
 0.1
 0.3
Net Current Period Other Comprehensive Income (Loss) 0.2
 0.1
 0.3
ASU 2018-02 Adoption (a) (0.9) (1.8) (2.7)
Balance in AOCI as of March 31, 2018 $(5.2) $(9.8) $(15.0)
  Cash Flow Hedge – Interest Rate 
Pension
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 —
 —
 —
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 March 31, 2019 $(4.1) $(10.7) $(14.8)

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


AEP Texas


Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 20172018
       
  Cash Flow Hedge - Interest Rate 
Pension
and OPEB
 Total
 (in millions)
Balance in AOCI as of December 31, 2016 $(5.4) $(9.5) $(14.9)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense 0.3
 —
 0.3
Amortization of Actuarial (Gains)/Losses —
 0.1
 0.1
Reclassifications from AOCI, before Income Tax (Expense) Credit 0.3
 0.1
 0.4
Income Tax (Expense) Credit 0.1
 —
 0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.2
 0.1
 0.3
Net Current Period Other Comprehensive Income (Loss) 0.2
 0.1
 0.3
Balance in AOCI as of March 31, 2017 $(5.2) $(9.4) $(14.6)
  Cash Flow Hedge – Interest Rate 
Pension
and OPEB
 Total
 (in millions)
Balance in AOCI as of December 31, 2017 $(4.5) $(8.1) $(12.6)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense (a) 0.3
 —
 0.3
Amortization of Actuarial (Gains) Losses —
 0.1
 0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.3
 0.1
 0.4
Income Tax (Expense) Benefit 0.1
 —
 0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.2
 0.1
 0.3
Net Current Period Other Comprehensive Income (Loss) 0.2
 0.1
 0.3
ASU 2018-02 Adoption (0.9) (1.8) (2.7)
Balance in AOCI as of March 31, 2018 $(5.2) $(9.8) $(15.0)





APCo


Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 20182019
  Cash Flow Hedges   
  Commodity Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of December 31, 2017 $—
 $2.2
 $(0.9) $1.3
Change in Fair Value Recognized in AOCI (0.7) —
 —
 (0.7)
Amount of (Gain) Loss Reclassified from AOCI   

 

 

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

 

 

Interest Expense (a) (0.3) —
 (0.3)
Amortization of Prior Service Cost (Credit) —
 (1.3) (1.3)
Amortization of Actuarial (Gains) Losses —
 0.5
 0.5
Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.3) (0.8) (1.1)
Income Tax (Expense) Benefit (0.1) (0.2) (0.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.2) (0.6) (0.8)
Net Current Period Other Comprehensive Income (Loss) (0.2) (0.6) (0.8)
Balance in AOCI as of March 31, 2019 $1.6
 $(7.4) $(5.8)

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


APCo


Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 20172018
       
  Cash Flow Hedge - Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of December 31, 2016 $2.9
 $(11.3) $(8.4)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI 

 

 

Interest Expense (0.3) —
 (0.3)
Amortization of Prior Service Cost (Credit) —
 (1.3) (1.3)
Amortization of Actuarial (Gains)/Losses —
 0.8
 0.8
Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3) (0.5) (0.8)
Income Tax (Expense) Credit (0.1) (0.2) (0.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2) (0.3) (0.5)
Net Current Period Other Comprehensive Income (Loss) (0.2) (0.3) (0.5)
Balance in AOCI as of March 31, 2017 $2.7
 $(11.6) $(8.9)
  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) —
 (0.3) —
 (0.3)
Amortization of Prior Service Cost (Credit) —
 —
 (1.3) (1.3)
Amortization of Actuarial (Gains) Losses —
 —
 0.3
 0.3
Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.9
 (0.3) (1.0) (0.4)
Income Tax (Expense) Benefit 0.2
 (0.1) (0.2) (0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.7
 (0.2) (0.8) (0.3)
Net Current Period Other Comprehensive Income (Loss) —
 (0.2) (0.8) (1.0)
ASU 2018-02 Adoption —
 0.5
 (0.2) 0.3
Balance in AOCI as of March 31, 2018 $—
 $2.5
 $(1.9) $0.6









I&M


Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 20182019
       
  Cash Flow Hedge - Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of December 31, 2017 $(10.7) $(1.4) $(12.1)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense 0.5
 —
 0.5
Amortization of Prior Service Cost (Credit) —
 (0.2) (0.2)
Amortization of Actuarial (Gains)/Losses —
 0.2
 0.2
Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5
 —
 0.5
Income Tax (Expense) Credit 0.1
 —
 0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4
 —
 0.4
Net Current Period Other Comprehensive Income (Loss) 0.4
 —
 0.4
ASU 2018-02 Adoption (a) (2.4) (0.3) (2.7)
Balance in AOCI as of March 31, 2018 $(12.7) $(1.7) $(14.4)
  Cash Flow Hedge – Interest Rate 
Pension
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 —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense (a) 0.5
 —
 0.5
Amortization of Prior Service Cost (Credit) —
 (0.2) (0.2)
Amortization of Actuarial (Gains) Losses —
 0.2
 0.2
Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.5
 —
 0.5
Income Tax (Expense) Benefit 0.1
 —
 0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.4
 —
 0.4
Net Current Period Other Comprehensive Income (Loss) 0.4
 —
 0.4
Balance in AOCI as of March 31, 2019 $(11.1) $(2.3) $(13.4)

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


I&M


Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 20172018
  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) 0.5
 —
 0.5
Amortization of Prior Service Cost (Credit) —
 (0.2) (0.2)
Amortization of Actuarial (Gains) Losses —
 0.2
 0.2
Reclassifications from AOCI, before Income Tax (Expense) Benefit 0.5
 —
 0.5
Income Tax (Expense) Benefit 0.1
 —
 0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit 0.4
 —
 0.4
Net Current Period Other Comprehensive Income (Loss) 0.4
 —
 0.4
ASU 2018-02 Adoption (2.4) (0.3) (2.7)
Balance in AOCI as of March 31, 2018 $(12.7) $(1.7) $(14.4)

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





OPCo


Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 20182019
   
  Cash Flow Hedge - Interest Rate
  (in millions)
Balance in AOCI as of December 31, 2017 $1.9
Change in Fair Value Recognized in AOCI —
Amount of (Gain) Loss Reclassified from AOCI 

Interest Expense (0.4)
Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4)
Income Tax (Expense) Credit (0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3)
Net Current Period Other Comprehensive Income (Loss) (0.3)
ASU 2018-02 Adoption (a) 0.4
Balance in AOCI as of March 31, 2018 $2.0
  Cash Flow Hedge – Interest Rate
  (in millions)
Balance in AOCI as of December 31, 2018 $1.0
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) Benefit (0.4)
Income Tax (Expense) Benefit (0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.3)
Net Current Period Other Comprehensive Income (Loss) (0.3)
Balance in AOCI as of March 31, 2019 $0.7
 
(a)See Note 2 - New Accounting Pronouncements for additional information.

OPCo


Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 20172018
  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) (0.4)
Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.4)
Income Tax (Expense) Benefit (0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.3)
Net Current Period Other Comprehensive Income (Loss) (0.3)
ASU 2018-02 Adoption 0.4
Balance in AOCI as of March 31, 2018 $2.0

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





PSO


Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 20182019
   
  Cash Flow Hedge - Interest Rate
  (in millions)
Balance in AOCI as of December 31, 2017 $2.6
Change in Fair Value Recognized in AOCI —
Amount of (Gain) Loss Reclassified from AOCI 

Interest Expense (0.3)
Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3)
Income Tax (Expense) Credit (0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2)
Net Current Period Other Comprehensive Income (Loss) (0.2)
ASU 2018-02 Adoption (a) 0.5
Balance in AOCI as of March 31, 2018 $2.9
  Cash Flow Hedge – Interest Rate
  (in millions)
Balance in AOCI as of December 31, 2018 $2.1
Change in Fair Value Recognized in AOCI —
Amount of (Gain) Loss Reclassified from AOCI 

Interest Expense (a) (0.3)
Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.3)
Income Tax (Expense) Benefit (0.1)
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 March 31, 2019 $1.9
 
(a)See Note 2 - New Accounting Pronouncements for additional information.

PSO


Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 20172018
   
  Cash Flow Hedge - Interest Rate
  (in millions)
Balance in AOCI as of December 31, 2016 $3.4
Change in Fair Value Recognized in AOCI —
Amount of (Gain) Loss Reclassified from AOCI 

Interest Expense (0.3)
Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3)
Income Tax (Expense) Credit (0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2)
Net Current Period Other Comprehensive Income (Loss) (0.2)
Balance in AOCI as of March 31, 2017 $3.2
  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) (0.3)
Reclassifications from AOCI, before Income Tax (Expense) Benefit (0.3)
Income Tax (Expense) Benefit (0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.2)
Net Current Period Other Comprehensive Income (Loss) (0.2)
ASU 2018-02 Adoption 0.5
Balance in AOCI as of March 31, 2018 $2.9







SWEPCo


Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 20182019
       
  Cash Flow Hedge - Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of December 31, 2017 $(6.0) $2.0
 $(4.0)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI 

 

 

Interest Expense 0.5
 —
 0.5
Amortization of Prior Service Cost (Credit) —
 (0.5) (0.5)
Amortization of Actuarial (Gains)/Losses —
 0.1
 0.1
Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5
 (0.4) 0.1
Income Tax (Expense) Credit 0.1
 (0.1) —
Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4
 (0.3) 0.1
Net Current Period Other Comprehensive Income (Loss) 0.4
 (0.3) 0.1
ASU 2018-02 Adoption (a) (1.3) 0.4
 (0.9)
Balance in AOCI as of March 31, 2018 $(6.9) $2.1
 $(4.8)
  Cash Flow Hedge – Interest Rate 
Pension
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 —
 —
 —
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) 0.4
 (0.3) 0.1
Balance in AOCI as of March 31, 2019 $(2.9) $(2.4) $(5.3)

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


SWEPCo


Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Three Months Ended March 31, 20172018
  Cash Flow Hedge – Interest Rate 
Pension
and OPEB
 Total
  (in millions)
Balance in AOCI as of December 31, 2017 $(6.0) $2.0
 $(4.0)
Change in Fair Value Recognized in AOCI —
 —
 —
Amount of (Gain) Loss Reclassified from AOCI      
Interest Expense (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) 0.4
 (0.3) 0.1
ASU 2018-02 Adoption (1.3) 0.4
 (0.9)
Balance in AOCI as of March 31, 2018 $(6.9) $2.1
 $(4.8)


(a)Amounts reclassified to the referenced line item on the statements of income.

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



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 ratemakingrate-making 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 March 31, 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)
$106.5
 $68.7
 $37.8
 $10.9
 $3.1
 $5.0
 2020 27 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
  March 31, December 31,
  2019 2018
 Noncurrent Regulatory Assets (in millions)
     
Regulatory Assets Currently Earning a Return    
Plant Retirement Costs - Unrecovered Plant $50.3
 $50.3
Kentucky Deferred Purchase Power Expenses 18.4
 14.5
Other Regulatory Assets Pending Final Regulatory Approval 16.4
 14.8
Regulatory Assets Currently Not Earning a Return  
  
Storm Related Costs (a) 152.0
 152.4
Plant Retirement Costs - Asset Retirement Obligation Costs 35.3
 35.3
Other Regulatory Assets Pending Final Regulatory Approval 15.4
 20.7
Total Regulatory Assets Pending Final Regulatory Approval (b)$287.8
 $288.0

  AEP
  March 31, December 31,
  2018 2017
 Noncurrent Regulatory Assets (in millions)
     
Regulatory Assets Currently Earning a Return    
Plant Retirement Costs - Unrecovered Plant $50.3
 $50.3
Other Regulatory Assets Pending Final Regulatory Approval 12.5
 9.6
Regulatory Assets Currently Not Earning a Return  
  
Storm Related Costs (a) 130.3
 128.0
Plant Retirement Costs - Asset Retirement Obligation Costs 39.7
 39.7
Cook Plant Uprate Project 31.1
 36.3
Cook Plant Turbine 11.2
 15.9
Other Regulatory Assets Pending Final Regulatory Approval 32.6
 42.2
Total Regulatory Assets Pending Final Regulatory Approval (b)$307.7
 $322.0


(a)As of March 31, 2018,2019, AEP Texas has deferred $105$137 million related to Hurricane Harvey and is currently exploring recovery options, including securitization.Harvey. In March 2019, AEP Texas filed a request to securitize total estimated distribution-related system restoration costs with the PUCT. See “Texas Storm Cost Securitization” discussion below for additional information.
(b)In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. APCo’s recovery of the remaining Virginia net book value for the retired plants will be considered in the Virginia SCC’s 2020 triennial review of APCo’s generation and distribution base rates. The Virginia SCC staff has requested that APCo prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018.







 AEP Texas AEP Texas
 March 31, December 31, March 31, December 31,
 2018 2017 2019 2018
Noncurrent Regulatory Assets (in millions) (in millions)
        
Regulatory Assets Currently Not Earning a Return        
Storm-Related Costs (a) $128.7
 $123.3
 $152.0
 $152.4
Rate Case Expense 0.2
 0.1
 0.4
 0.2
Total Regulatory Assets Pending Final Regulatory Approval $128.9
 $123.4
 $152.4
 $152.6


(a)As of March 31, 2018,2019, AEP Texas has deferred $105$137 million related to Hurricane Harvey and is currently exploring recovery options, including securitization.Harvey. In March 2019, AEP Texas filed a request to securitize total estimated distribution-related system restoration costs with the PUCT. See “Texas Storm Cost Securitization” discussion below for additional information.
  APCo
  March 31, December 31,
  2019 2018
Noncurrent Regulatory Assets (in millions)
     
Regulatory Assets Currently Earning a Return    
Plant Retirement Costs - Materials and Supplies $5.1
 $9.0
Regulatory Assets Currently Not Earning a Return    
Plant Retirement Costs - Asset Retirement Obligation Costs 35.3
 35.3
Other Regulatory Assets Pending Final Regulatory Approval —
 0.6
Total Regulatory Assets Pending Final Regulatory Approval (a) $40.4
 $44.9

  APCo
  March 31, December 31,
  2018 2017
Noncurrent Regulatory Assets (in millions)
     
Regulatory Assets Currently Earning a Return    
Plant Retirement Costs - Materials and Supplies $9.0
 $9.1
Regulatory Assets Currently Not Earning a Return    
Plant Retirement Costs - Asset Retirement Obligation Costs 39.7
 39.7
Other Regulatory Assets Pending Final Regulatory Approval 0.6
 0.6
Total Regulatory Assets Pending Final Regulatory Approval (a) $49.3
 $49.4


(a)In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. APCo’s recovery of the remaining Virginia net book value for the retired plants will be considered in the Virginia SCC’s 2020 triennial review of APCo’s generation and distribution base rates. The Virginia SCC staff has requested that APCo prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018.
  I&M
  March 31, December 31,
  2019 2018
Noncurrent Regulatory Assets (in millions)
     
Regulatory Assets Currently Not Earning a Return    
Other Regulatory Assets Pending Final Regulatory Approval $3.4
 $3.3
Total Regulatory Assets Pending Final Regulatory Approval $3.4
 $3.3
  I&M
  March 31, December 31,
  2018 2017
Noncurrent Regulatory Assets (in millions)
     
Regulatory Assets Currently Not Earning a Return    
Cook Plant Uprate Project $31.1
 $36.3
Deferred Cook Plant Life Cycle Management Project Costs - Michigan —
 14.7
Cook Plant Turbine 11.2
 15.9
Rockport Dry Sorbent Injection System - Indiana 11.3
 10.4
Other Regulatory Assets Pending Final Regulatory Approval 4.5
 2.0
Total Regulatory Assets Pending Final Regulatory Approval $58.1
 $79.3

 PSO OPCo
 March 31, December 31, March 31, 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 0.1
 0.1
 $0.1
 $1.0
Total Regulatory Assets Pending Final Regulatory Approval $0.1
 $3.3
 $0.1
 $1.0





  PSO
  March 31, December 31,
  2019 2018
Noncurrent Regulatory Assets (in millions)
     
Regulatory Assets Currently Earning a Return    
Oklaunion Power Station Accelerated Depreciation $10.9
 $5.5
Total Regulatory Assets Pending Final Regulatory Approval $10.9
 $5.5

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


  SWEPCo
  March 31, December 31,
  2019 2018
Noncurrent Regulatory Assets (in millions)
     
Regulatory Assets Currently Earning a Return    
Plant Retirement Costs - Unrecovered Plant $50.3
 $50.3
Other Regulatory Assets Pending Final Regulatory Approval 0.3
 0.3
Regulatory Assets Currently Not Earning a Return  
  
Asset Retirement Obligation - Arkansas, Louisiana 5.8
 5.3
Rate Case Expense - Texas 0.9
 4.9
Other Regulatory Assets Pending Final Regulatory Approval 3.7
 3.6
Total Regulatory Assets Pending Final Regulatory Approval $61.0
 $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 will impact 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 March 31, 2018,2019, AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2017,2018, subject to review, are estimated to be $830 million.$1.1 billion. A base rate review could produceresult in a refund to customers if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition.


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

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

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


Hurricane HarveyTexas Storm Cost Securitization


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 March 31, 2018,


2019, the total balance of AEP Texas’ regulatory asset for deferred storm costs is approximately $129$152 million, inclusive of approximately $105$137 millionof incremental storm expenses recorded as a regulatory asset related to Hurricane Harvey. As of



In March 31, 2018,2019, AEP Texas has recorded approximately $186 millionof capital expenditures relatedfiled a request to Hurricane Harvey. Also, as of March 31, 2018, AEP Texas has received $10 million in insurance proceeds, which were applied to the regulatory asset and property, plant and equipment. Management, in conjunctionsecuritize total estimated distribution-related system restoration costs 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 believesPUCT in the amount recorded as a regulatory asset is probable of recovery and AEP Texas is currently evaluating recovery options for the regulatory asset, including securitization. The standard process for storm cost recovery in Texas requires two filings with the PUCT. Management expects the first filing$230 million, which includes estimated carrying costs. A decision by the endPUCT is expected in the second quarter of 2019. See the table below for details of the third quarterrequest:
Total Estimated Distribution-Related System Restoration Costs
   (in millions)
Distribution-Related System Restoration Costs $264.6
Estimated Carrying Costs 26.9
Up-front Qualified Costs 4.6
Total Distribution-Related System Restoration Costs 296.1
less:  
Insurance Proceeds and Government Grants (3.1)
Excess ADIT (a) (63.5)
Total Requested Distribution-Related System Restoration Costs $229.5

(a)Amount represents Non-Hurricane Harvey Excess ADIT that is not subject to rate normalization requirements.

The remaining $95 million of 2018.estimated net transmission-related system restoration costs, including carrying charges, is expected to be recovered through interim transmission filings or an upcoming base rate case. If the ultimatethese costs of the incident are not recovered, by insurance or through the regulatory process, it wouldcould have an adverse effect on future net income, cash flows and financial condition.


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


Virginia Legislation Affecting 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 will: (a) on a one-time basis, require APCo to exclude $10 million of fuel expenses from the July 2018 over/under calculation, (b) reduce APCo’s base rates by $50 million annually no later than July 30, 2018, on an interim basis and subject to true-up, to reflect the lower federal income tax rate due to Tax Reform, (c) require APCo to file its next generation and distribution base rate case by March 31, 2020 using 2017, 2018 and 2019 earnings test years (“triennial review”), (d) require an adjustment in APCo’s base rates on April 1, 2019 to reflect actual annual reductions in corporate income taxes due to Tax Reform, (e) require APCo to obtain approval from the Virginia SCC for energy efficiency programs with projected costs in the aggregate of at least $140 million over the 10-year period from July 1, 2018 through July 1, 2028 and (f) require APCo to construct and/or acquire solar generation facilities in Virginia of at least 200 MW of aggregate capacity.. Triennial reviews are subject to an earnings test which provides that 70% of any earnings exceeding 70 basis points over the Virginia SCC authorized return on common equity would be refunded to customers. In November 2018, the Virginia SCC approved a return on common equity of 9.42% applicable to APCo base rate earnings may be reinvestedfor 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 approved energy distribution grid transformation projects.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. The Virginia SCC’s triennial review of 2017-2019 APCo earnings could materially 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 March 2019, the Virginia SCC issued an order to reduce APCo’s base rates to refund: (a) $40 million annually for ongoing annual tax savings, (b) $9 million annually of Excess ADIT associated with certain depreciable property using ARAM, (c) $94 million of Excess ADIT that is not subject to rate normalization requirements over three years and (d) a one-time credit of $22 million for estimated excess taxes collected from customers during the 15-month period ending March 31, 2019.

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 included $32 million ($28 million related to APCo) due to increased annual depreciation expense and reflected 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 West Virginia Tax Reform.

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

ETT Rate Matters (Applies to AEP)


ETT Interim Transmission Rates


AEP has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. Through March 31, 2018,2019, AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $781$918 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 February 2018, ETT filed an application to reduce its transmission rates by $27 million to reflect the lower federal income tax rate due to Tax Reform. The filing did not address the return of excess deferred income tax benefits to customers.

In April 2018, the PUCT adopted a rule requiring investor-owned utilities operating solely inside ERCOT to make periodic filings for rate proceedings. The rule requires ETT to file for a comprehensive rate review no later than February 1, 2021.




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


2017 Indiana Base Rate CaseMichigan Tax Reform


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

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

In FebruaryOctober 2018, I&M made a filing with the MPSC recommending to: (a) refund approximately $68 million of Excess ADIT associated with certain depreciable property using ARAM and all parties to the case, except one industrial customer, filed a Stipulation and Settlement Agreement for a $97(b) refund approximately $37 million annual increase in Indiana rates effective July 1, 2018of Excess ADIT that is not subject to a temporary offsetting reduction to customer bills through December 2018 for a credit rider related torate normalization requirements over ten years. An order from the timing of estimated in-service dates of certain capital expenditures.  The one industrial customer agreed to not oppose the Stipulation and Settlement Agreement. The difference between I&M’s requested $263 million annual increase and the $97 million annual increase in the Stipulation and Settlement Agreement is primarily a result of: (a) the reduction in the federal income tax rate due to Tax Reform, (b) the feedback of credits for excess deferred income taxes, (c) a 9.95% return on equity, (d) longer recovery periods of regulatory assets, (e) lower depreciation expense primarily for meters and (f) an increase in the sharing of off-system sales margins with customers from 50% to 95%.  If the Stipulation and Settlement is approved, I&M will also refund $4 million from July through December 2018 for the impact of Tax Reform for the period January through June 2018.  A hearing at the IURC was held in March 2018 and an IURC orderMPSC regarding Excess ADIT is expected in the second quarterhalf of 2018. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.2019.
2017 Michigan Base Rate Case

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

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

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



Rockport Plant, Unit 2 SCR

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

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

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

KPCo Rate Matters (Applies to AEP)

2017 Kentucky Base Rate Case

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

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



OPCo Rate Matters (Applies to AEP and OPCo)


Ohio Electric Security Plan Filings


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


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

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

In November 2016, OPCo refiled its amended ESP extension application and supporting testimony, consistent with the terms of the modified and approved stipulation agreement and based upon a 2016 PUCO order. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Renewable Resource Rider.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 October 2017, intervenor testimony opposing the stipulation agreement was filed recommending: (a) a return on common equity to not exceed 9.3% for riders earning a return on capital investments, (b) that OPCo should file a base distribution case concurrent with the conclusion of the current ESP in May 2018 and (c) denial of certain new riders proposed in OPCo’s ESP extension. The stipulation was reviewed by the PUCO at a hearing in November 2017.


In April 2018, the PUCO issued an order approving the ESP extension stipulation agreement, with no significant changes. In October 2018, an intervenor filed an appeal with the Ohio Supreme Court challenging various approved riders. 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 authorized under the ESP is subject to annual audits.  In May 2018, the PUCO staff filed comments indicating that 2016 spending 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 the 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 the 2016 or 2017 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 has been set for May 2019 to address the 2016 audit. If it is determined OPCo did have an authorized spending limit 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.order, OPCo reversed the $58 million provision in the first quarter of 2019.




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

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

SWEPCoPSO Rate Matters (Applies to AEP and SWEPCo)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-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 included $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 Oklaunion Power Station through 2028 (currently being recovered in rates through 2046).  Management has announced plans to retire Oklaunion Power Station by October 2020.

In March 2019, the OCC issued an order approving a Stipulation and Settlement agreement for a $46 million annual increase, based on a 9.4% return on equity effective with the first billing cycle of April 2019. The order also included agreements between the parties that: (a) depreciation rates will remain unchanged, (b) PSO will file a new base rate request no earlier than October 2020 and no later than October 2021 and (c) PSO will refund Excess ADIT that is not subject to rate normalization requirements over five years instead of the ten years ordered in the Oklahoma Tax Reform case. The order did not 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 AprilJuly 2018, oral arguments were heard by the Texas Third Court of Appeals.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, which has ordered appellants to file responses by May 29, 2019.


As of March 31, 2019, the net book value of Turk Plant was $1.5 billion, before cost of removal, including materials and supplies inventory and CWIP. If certain parts of the PUCT order are overturned and if SWEPCo cannot ultimately fully recover its approximate 33% Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition.



2016 Texas Base Rate Case


In December 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $50 million based upon a return on common equity of 9.6%, effective May 2017. The final order also includedincluded: (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 SWEPCoSWEPCo: (a) recorded an impairment charge of $19 million, which includesincluded $7 million associated with the lack of return on Welsh Plant, Unit 2 and $12 million related to other disallowed plant investments, (b) recognized $32 million of additional revenues, for the period of May 2017 through December 2017, that will bewas surcharged to customers in 2018and (c) recognized an additional $7 million of expenses consisting primarily of depreciation expense and vegetation management expense, offset by the deferral of rate case expenses.expense. SWEPCo implemented new rates in February 2018 billings. The $32 million of additional 2017 revenues will bewas collected by the end ofduring 2018. In March 2018, the PUCT clarified and corrected portions of the final order, without changing the overall decision or amounts of the rate change. ThisThe order is subject to appeal as early ashas been appealed by various intervenors. If certain parts of the second quarter 2018. In April 2018, SWEPCo made an income tax rate refund tariff filing which includes an annual revenue reduction of approximately $18 million to reflect the difference between rates collected under the finalPUCT order and the rates that would be collected under Tax Reform. The filing did not address the return of excess deferred income tax benefits to customers.

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


2018 Louisiana Formula Rate Filing


In April 2018, SWEPCo filed its formula rate plan for test year 2017 with the LPSC.  The filing included a net $28 million annual increase, which will bewas effective August 2018.2018 and included SWEPCo’s Louisiana jurisdictional share of Welsh Plant and Flint Creek Plant environmental controls. The filing also included a reduction in the federal income tax rate due to Tax Reform. TheReform but did not address the return of excess deferred income taxExcess ADIT benefits to customers will be addressed incustomers.

In July 2018, SWEPCo made a supplemental filing and willto 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. The increase includes SWEPCo’s jurisdictional shareand the $18 million annual increase in the supplemental filing is primarily the result of Welsh Plant and Flint Creek Plant environmental controls, whose prudence review hearingthe 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 scheduled for May 2018. expected in 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 $850$550 million, excluding AFUDC. As of March 31, 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 March 31, 2018,2019, the total net book value of Welsh Plant, Units 1 and 3 was $625$623 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 $11$10 million, excluding $6$5 million of unrecognized equity as of March 31, 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. In January 2018, SWEPCo received written approval from the PUCT to recover its project costs from retail customers in its 2016 Texas base rate case and is recovering these costs from wholesale customers through SWEPCo’s FERC-approved agreements. See “2016 Texas Base Rate Case” and “2017“2018 Louisiana Formula Rate Filing” disclosures above.disclosure above for additional information.


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


2019 Arkansas Base Rate Case

In February 2019, SWEPCo filed a request with the APSC for a $75 million increase in Arkansas base rates based upon a proposed 10.5% return on common equity. The filing requests rate base treatment for the Stall Plant and the environmental retrofits that are currently being recovered through riders. Eliminating these riders would result in a net annual requested base rate increase of $58 million. The proposed net annual increase includes $12 million related to vegetation management to improve the reliability of its Arkansas distribution system. The filing also provides notice of SWEPCo’s proposal to have its rates regulated under the formula rate review mechanism authorized by Arkansas Act 725 of 2015, including a Formula Rate Review Rider.

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

FERC Rate Matters

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

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


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


In October 2016, seven parties filed a complaint at the FERC that alleged the base return on common equity used by AEP’s transmission owning subsidiaries within PJM in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint.  In November 2017, a FERC order set the matter for hearing and settlement procedures.  In March 2018, AEP’s transmission owning subsidiaries within PJM and six of the complainants filed a settlement agreement with the FERC (the seventh complainant abstained).  If approved by the FERC, the settlement agreementagreement: (a) establishes a base ROE for AEP’s transmission owning subsidiaries within PJM of 9.85% (10.35% inclusive of the RTO incentive adder of 0.5%), effective January 1, 2018, (b) requires AEP’s transmission owning subsidiaries within PJM to provide a one-time refund of $50 million, attributable from the date of the complaint through December 31, 2017, to bewhich 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 accumulated deferred income taxesExcess ADIT that areis not subject to the normalization method of accounting, ratably over a ten yearten-year period through credits to the federal income tax expense component of the revenue requirement. In April 2018, an ALJ accepted the interim settlement rates, pending the FERC’s consideration of the settlement, and therates. These interim rates are subject to refund or surcharge, with interest.

In Also in April 2018, certain intervenors filed comments at the FERC recommending a base ROE of 8.48%lower ROE. In March 2019, the intervenors subsequently withdrew their opposition to the settlement and the settling parties filed a one-time refund of $184 million. In addition,joint motion at the FERC trial staff filed comments recommending a base ROEseeking approval of 8.41% and one-time refund of $175 million. Also in April 2018, another intervenor recommendedthis now uncontested settlement. A decision from the refund be calculated in accordance with the base ROE that will ultimately be approved by the FERC. Management intends to file reply comments providing further support for the 9.85% base ROE agreed to in the settlement agreement.FERC is pending.


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



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

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


FERC Transmission Complaint - AEP’s SPP 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. In November 2017, acomplaint through September 5, 2018. A FERC order set the matter for hearing and settlement procedures.

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.



In March 2019, AEP’s transmission owning subsidiaries within SPP and the complainants filed an unopposed settlement agreement with the FERC that establishes a base ROE of 10% (10.50% inclusive of the RTO incentive adder of 0.5%) effective January 1, 2019. Additionally, if approved, refunds including carrying charges would be made from the date of the first complaint through December 31, 2018. Refunds for the period prior to 2019 would be made at the time of the 2019 true-up of 2018 rates. Refunds from January 2019 onward would begin following a FERC approval of the settlement and conclude with the 2020 true-up of 2019 rates. A decision from the FERC is pending.

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


Modifications to AEP’s SPP Transmission Rates (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 2018 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 andrefund. In February 2019, AEP’s transmission owning subsidiaries within SPP filed an uncontested settlement procedures.agreement with the FERC, subject to FERC approval, resolving all outstanding issues. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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



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





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 March 31, 2018,2019, no letters of credit were issued under the $3 billion revolving credit facility.


An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under four uncommitted facilities totaling $305 million. In March 2018, oneApril 2019, AEP executed two additional $50 million uncommitted letter of the uncommitted credit facilities was reduced by $40 million.facilities. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of March 31, 20182019 were as follows:
Company Amount Maturity
  (in millions)  
AEP $105.8
 June 2019 to March 2020
AEP Texas 2.2
 January 2020
OPCo 1.2
 September 2019 to March 2020

Company Amount Maturity
  (in millions)  
AEP $81.3
 May 2018 to March 2019
OPCo 0.6
 September 2018


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




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


As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $140 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 $77$107 million.  Actual reclamation costs could vary due to period inflation and anyscope changes to actualthe mine reclamation.  As of March 31, 2018,2019, SWEPCo has collected $72$76 million through a rider for final mine closure and reclamation costs, of which $77$82 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 March 31, 2018,2019, the maximum potential amount of future payments associated with this guarantee was $75 million, which expires in December 2019.


Indemnifications and Other Guarantees


Contracts


The Registrants enter into certain types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, exposure generally does not exceed the sale price.  As of March 31, 2018,2019, 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 March 31, 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 $43.4
AEP Texas 10.5
APCo 8.8
I&M 3.1
OPCo 6.3
PSO 3.7
SWEPCo 3.7


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 intend to renew these leases for the full lease term of twenty years via the renewal options.  The future minimum lease obligations are $7 million and $8 million for I&M and SWEPCo, respectively, for the remaining railcars as of March 31, 2018.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% of the projected fair value of the equipment under the current five year lease term to 77% at the end of the 20-year term.  I&M and SWEPCo have assumed the guarantee under the return-and-sale option.  The maximum potential losses related to the guarantee are $8 million and $9 million for I&M and SWEPCo, respectively, as of March 31, 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 March 31, 2018, the maximum potential amount of future payments required under the guaranteed leases was $49 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 March 31, 2018, AEP’s boat and barge lease guarantee liability was $7 million, of which $2 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, a nonaffiliated third party. Pursuant to the sale, Brookfield will assume all of I&M’s contracts with Westinghouse. The sale is subject to regulatory approvals and is expected to close in the third quarter of 2018.

OPERATIONAL CONTINGENCIES


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


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

AEGCo and I&M.

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

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



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


In July 2017,Thereafter, AEP filed a motion with the U.S. District Court for the Southern District of Ohio in the original NSR litigation, seeking to modify the consent decree to eliminate the obligation to install certain future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that Unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. In November 2017, theThe district court granted the owners’ unopposed motion to stay the lease litigation to afford time for resolution of AEP’s motion to modify the consent decree. 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. See “Proposed Modification of the NSR 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 to determine a range of potential losses that are reasonably possible of occurring.

Gavin Landfill Litigation (Applies to AEP and OPCo)



In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill.  As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint became the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors.  Twelve of the family members pursued personal injury/illness claims (non-working direct claims) and the remainder pursued loss of consortium claims.  The plaintiffs sought compensatory and punitive damages, as well as medical monitoring.  In September 2014, defendants filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Defendants appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appeal and remanding the case to the West Virginia Mass Litigation Panel (WVMLP), rather than back to the Mason County, West Virginia Circuit Court. Defendants subsequently filed a motion to dismiss the twelve non-working direct claims under Ohio law. The WVMLP denied the motion and defendants again appealed to the West Virginia Supreme Court. In June 2017, the West Virginia Supreme Court reversed the WVMLP decision and dismissed the claims of the twelve non-working direct claim plaintiffs. In April 2018, a settlement in principle was reached. This settlement, once finalized, will be subject to court approval. Management believes the provision recorded for this case is adequate.


6. DISPOSITIONSACQUISITIONS AND IMPAIRMENTS


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


DISPOSITIONSACQUISITIONS


Zimmer PlantSempra Renewables LLC (Generation & Marketing Segment)


In February 2017,April 2019, AEP signedacquired Sempra Renewables LLC and its 724 MWs of wind generation and battery assets for approximately $1.1 billion, subject to working capital adjustments. AEP paid $584 million in cash and assumed approximately $358 million of existing project debt obligations of the non-consolidated joint ventures. Additionally, the acquisition includes the recognition of noncontrolling tax equity interest of an agreementestimated $110 million as of the acquisition date associated with certain of the acquired wind farms. The purchase price will be allocated primarily to sell its 25.4% ownership shareequity method investment (included in Deferred Charges and Other Noncurrent Assets) and Property, Plant and Equipment on AEP’s balance sheets. AEP has issued guarantees and letters of Zimmer Plantcredit in relation to the acquisition to support project debt and other requirements.

The wind generation portfolio includes seven wholly or jointly-owned wind farms with long-term PPAs for 100% of their energy production. Two of the jointly-owned wind farms have PPAs with I&M, OPCo and SWEPCo for a nonaffiliated party.  The transaction closed inportion of their energy production and are accounted for under the second quarter of 2017accounting guidance for “Regulated Operations.” If the Sempra acquisition would have been completed prior to the Balance Sheet date, the revenue and did notearnings impact would have a material impact on net income, cash flows or financial condition.  The Income before Income Tax Expense and Equity Earnings of Zimmer Plant wasbeen immaterial to AEP for the three months ended March 31, 2017.2019 and 2018, respectively.

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

In September 2016, AEP signed a Purchase and Sale Agreement to sell AGR’s Gavin, Waterford and Darby Plants as well as AEGCo’s Lawrenceburg Plant totaling 5,329 MWs of competitive generation assets to a nonaffiliated party. The sale closed in January 2017 for $2.2 billion, which was recorded in Investing Activities on the statement of cash flows. The net proceeds from the transaction were $1.2 billion in cash after taxes, repayment of debt associated with these assets including a make whole payment related to the debt, payment of a coal contract associated with one of the plants and transaction fees. The sale resulted in a pretax gain of $227 million that was recorded in Gain on Sale of Merchant Generation Assets on AEP’s statement of income for the three months ended March 31, 2017.


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)



In the first quarter of 2017, AEP recorded a pretax impairment of $4 million in Other Operation on the statement of 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.


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 nonqualifiednon-qualified pension plans.  Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualifiednon-qualified 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 OPEB
 Three Months Ended March 31, Three Months Ended March 31,
 2019 2018 2019 2018
 (in millions)
Service Cost$23.9
 $24.4
 $2.4
 $2.9
Interest Cost51.1
 46.9
 12.6
 11.8
Expected Return on Plan Assets(74.0) (72.5) (23.4) (25.5)
Amortization of Prior Service Credit—
 —
 (17.3) (17.3)
Amortization of Net Actuarial Loss14.4
 21.3
 5.5
 2.6
Net Periodic Benefit Cost (Credit)$15.4
 $20.1
 $(20.2) $(25.5)

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


AEP Texas
Pension Plans OPEBPension Plans OPEB
Three Months Ended March 31, Three Months Ended March 31,Three Months Ended March 31, Three Months Ended March 31,
2018 2017 2018 20172019 2018 2019 2018
(in millions)(in millions)
Service Cost$2.3
 $2.1
 $0.3
 $0.2
$2.1
 $2.3
 $0.2
 $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) (6.3) (2.1) (2.2)(6.4) (6.4) (2.0) (2.1)
Amortization of Prior Service Credit—
 —
 (1.5) (1.4)—
 —
 (1.5) (1.5)
Amortization of Net Actuarial Loss1.8
 1.8
 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)


APCo
 Pension Plans OPEB
 Three Months Ended March 31, Three Months Ended March 31,
 2019
2018 2019 2018
 (in millions)
Service Cost$2.4
 $2.3
 $0.3
 $0.3
Interest Cost6.3
 5.9
 2.2
 2.0
Expected Return on Plan Assets(9.4) (9.1) (3.7) (4.0)
Amortization of Prior Service Credit—
 —
 (2.5) (2.5)
Amortization of Net Actuarial Loss1.8
 2.6
 0.9
 0.5
Net Periodic Benefit Cost (Credit)$1.1
 $1.7
 $(2.8) $(3.7)
 Pension Plans OPEB
 Three Months Ended March 31, Three Months Ended March 31,
 2018
2017 2018 2017
 (in millions)
Service Cost$2.3
 $2.3
 $0.3
 $0.3
Interest Cost5.9
 6.4
 2.0
 2.6
Expected Return on Plan Assets(9.1) (8.9) (4.0) (4.1)
Amortization of Prior Service Cost (Credit)—
 0.1
 (2.5) (2.5)
Amortization of Net Actuarial Loss2.6
 2.6
 0.5
 1.6
Net Periodic Benefit Cost (Credit)$1.7
 $2.5
 $(3.7) $(2.1)





I&M
 Pension Plans OPEB
 Three Months Ended March 31, Three Months Ended March 31,
 2019 2018 2019 2018
 (in millions)
Service Cost$3.4
 $3.4
 $0.3
 $0.4
Interest Cost6.0
 5.5
 1.5
 1.4
Expected Return on Plan Assets(9.2) (8.9) (2.8) (3.1)
Amortization of Prior Service Credit—
 —
 (2.4) (2.4)
Amortization of Net Actuarial Loss1.6
 2.5
 0.7
 0.3
Net Periodic Benefit Cost (Credit)$1.8
 $2.5
 $(2.7) $(3.4)

 Pension Plans OPEB
 Three Months Ended March 31, Three Months Ended March 31,
 2018 2017 2018 2017
 (in millions)
Service Cost$3.4
 $3.5
 $0.4
 $0.4
Interest Cost5.5
 6.1
 1.4
 1.7
Expected Return on Plan Assets(8.9) (8.6) (3.1) (3.1)
Amortization of Prior Service Credit—
 —
 (2.4) (2.3)
Amortization of Net Actuarial Loss2.5
 2.4
 0.3
 1.1
Net Periodic Benefit Cost (Credit)$2.5
 $3.4
 $(3.4) $(2.2)


OPCo
 Pension Plans OPEB
 Three Months Ended March 31, Three Months Ended March 31,
 2019 2018 2019 2018
 (in millions)
Service Cost$2.0
 $2.0
 $0.2
 $0.2
Interest Cost4.7
 4.4
 1.4
 1.3
Expected Return on Plan Assets(7.3) (7.2) (2.7) (3.0)
Amortization of Prior Service Credit—
 —
 (1.7) (1.7)
Amortization of Net Actuarial Loss1.3
 2.0
 0.6
 0.3
Net Periodic Benefit Cost (Credit)$0.7
 $1.2
 $(2.2) $(2.9)

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


PSO
Pension Plans OPEBPension Plans OPEB
Three Months Ended March 31, Three Months Ended March 31,Three Months Ended March 31, Three Months Ended March 31,
2018 2017 2018 20172019 2018 2019 2018
(in millions)(in millions)
Service Cost$1.8
 $1.6
 $0.2
 $0.2
$1.6
 $1.8
 $0.2
 $0.2
Interest Cost2.4
 2.7
 0.6
 0.8
2.6
 2.4
 0.7
 0.6
Expected Return on Plan Assets(4.0) (3.9) (1.4) (1.4)(4.1) (4.0) (1.3) (1.4)
Amortization of Prior Service Credit—
 —
 (1.0) (1.1)—
 —
 (1.1) (1.0)
Amortization of Net Actuarial Loss1.1
 1.1
 0.1
 0.5
0.8
 1.1
 0.3
 0.1
Net Periodic Benefit Cost (Credit)$1.3
 $1.5
 $(1.5) $(1.0)$0.9
 $1.3
 $(1.2) $(1.5)


SWEPCo
 Pension Plans OPEB
 Three Months Ended March 31, Three Months Ended March 31,
 2019 2018 2019 2018
 (in millions)
Service Cost$2.1
 $2.3
 $0.2
 $0.3
Interest Cost3.1
 2.9
 0.8
 0.7
Expected Return on Plan Assets(4.4) (4.4) (1.5) (1.6)
Amortization of Prior Service Credit—
 —
 (1.3) (1.3)
Amortization of Net Actuarial Loss0.9
 1.3
 0.3
 0.1
Net Periodic Benefit Cost (Credit)$1.7
 $2.1
 $(1.5) $(1.8)



 Pension Plans OPEB
 Three Months Ended March 31, Three Months Ended March 31,
 2018 2017 2018 2017
 (in millions)
Service Cost$2.3
 $2.2
 $0.3
 $0.2
Interest Cost2.9
 3.1
 0.7
 0.9
Expected Return on Plan Assets(4.4) (4.2) (1.6) (1.6)
Amortization of Prior Service Credit—
 —
 (1.3) (1.3)
Amortization of Net Actuarial Loss1.3
 1.2
 0.1
 0.6
Net Periodic Benefit Cost (Credit)$2.1
 $2.3
 $(1.8) $(1.2)




8.  BUSINESS SEGMENTS


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


AEP’s Reportable Segments


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


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


Vertically Integrated Utilities


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


Transmission and Distribution Utilities


Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo.
OPCo purchases energy and capacity to serve 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 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 months ended March 31, 20182019 and 20172018 and reportable segment balance sheet information as of March 31, 20182019 and December 31, 2017.2018.
Three Months Ended March 31, 2018Three Months Ended March 31, 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$2,381.5
 $1,141.2
 $41.1
 $477.5
 $7.0
 $—
 $4,048.3
$2,372.3
 $1,179.8
 $61.2
 $439.7
 $3.8
 $—
 $4,056.8
Other Operating Segments26.5
 21.2
 164.4
 27.6
 17.0
 (256.7) —
31.0
 42.2
 195.2
 42.1
 21.7
 (332.2) —
Total Revenues$2,408.0
 $1,162.4
 $205.5
 $505.1
 $24.0
 $(256.7) $4,048.3
$2,403.3
 $1,222.0
 $256.4
 $481.8
 $25.5
 $(332.2) $4,056.8
                          
Net Income (Loss)$232.8
 $125.4
 $104.8
 $18.1
 $(24.4) $—
 $456.7
$303.6
 $156.5
 $125.2
 $39.2
 $(50.4) $—
 $574.1
                          
Three Months Ended March 31, 2017Three Months Ended March 31, 2018
Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing		 Corporate and Other (a) Reconciling Adjustments ConsolidatedVertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing		 Corporate and Other (a) Reconciling Adjustments Consolidated
(in millions)(in millions)
Revenues from: 
 ��
  
  
  
    
 
  
  
  
  
    
External Customers$2,269.8
 $1,066.4
 $27.7
 $558.8
 $10.6
 $—
 $3,933.3
$2,381.5
 $1,141.2
 $41.1
 $477.5
 $7.0
 $—
 $4,048.3
Other Operating Segments20.6
 20.0
 128.4
 32.6
 15.9
 (217.5) —
26.5
 21.2
 164.4
 27.6
 17.0
 (256.7) —
Total Revenues$2,290.4
 $1,086.4
 $156.1
 $591.4
 $26.5
 $(217.5) $3,933.3
$2,408.0
 $1,162.4
 $205.5
 $505.1
 $24.0
 $(256.7) $4,048.3
                          
Net Income (Loss)$220.5
 $119.1
 $72.8
 $186.2
 $(4.4) $—
 $594.2
$232.8
 $125.4
 $104.8
 $18.1
 $(24.4) $—
 $456.7






 March 31, 2018 March 31, 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 $43,749.8
 $16,790.4
 $7,446.6
 $786.9
 $377.7
 $(355.1)(b)$68,796.3
 $45,684.3
 $18,526.1
 $8,973.2
 $915.6
 $406.4
 $(354.4)(b)$74,151.2
Accumulated Depreciation and Amortization 13,355.3
 3,809.8
 200.1
 70.1
 182.9
 (187.0)(b)17,431.2
 13,944.5
 3,856.1
 318.8
 58.7
 190.9
 (186.4)(b)18,182.6
Total Property Plant and Equipment - Net $30,394.5
 $12,980.6
 $7,246.5
 $716.8
 $194.8
 $(168.1)(b)$51,365.1
 $31,739.8
 $14,670.0
 $8,654.4
 $856.9
 $215.5
 $(168.0)(b)$55,968.6
                            
                            
Total Assets $37,913.3
 $16,272.6
 $8,340.5
 $2,123.7
 $4,552.9
(c)$(3,593.5)(b) (d)$65,609.5
 $40,085.7
 $17,419.0
 $9,790.2
 $1,960.1
 $4,341.2
(c)$(2,874.2)(b) (d)$70,722.0
                            
Long-term Debt Due Within One Year:                            
Nonaffiliated $1,893.7
 $670.6
 $50.0
 $0.1
 $1.7
 $—
 $2,616.1
 $912.1
 533.3
 85.0
 —
 (1.9)(e)—
 $1,528.5
                            
Long-term Debt:                            
Affiliated 50.0
 —
 —
 32.2
 —
 (82.2) —
 50.0
 —
 —
 32.2
 —
 (82.2) —
Nonaffiliated 9,969.2
 4,972.4
 2,635.0
 (0.3) 1,268.6
 —
 18,844.9
 11,999.5
 4,938.6
 2,895.3
 (0.3) 3,065.1
 —
 22,898.2
                            
Total Long-term Debt $11,912.9
 $5,643.0
 $2,685.0
 $32.0
 $1,270.3
 $(82.2) $21,461.0
 $12,961.6
 $5,471.9
 $2,980.3
 $31.9
 $3,063.2
(e)$(82.2) $24,426.7
                            
 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).the State Transcos. 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 statements of income statement information for the three months ended March 31, 20182019 and 20172018 and reportable segment balance sheet information as of March 31, 20182019 and December 31, 2017.2018.
 Three Months Ended March 31, 2019
 State Transcos AEPTCo Parent Reconciling Adjustments 
AEPTCo
Consolidated
 (in millions)
Revenues from:       
External Customers$50.3
 $—
 $—
 $50.3
Sales to AEP Affiliates193.2
 —
 —
 193.2
Total Revenues$243.5
 $—
 $—
 $243.5
        
Interest Income$0.2
 $28.4
 $(27.9)(a)$0.7
Interest Expense21.7
 27.9
 (27.9)(a)21.7
Income Tax Expense27.6
 —
 —
 27.6
        
Net Income$104.2
 $0.1
(b)—
 $104.3
Three Months Ended March 31, 2018Three Months Ended March 31, 2018
State Transcos AEPTCo Parent Reconciling Adjustments 
AEPTCo
Consolidated
State Transcos (f) AEPTCo Parent Reconciling Adjustments 
AEPTCo
Consolidated (f)
(in millions)(in millions)
Revenues from:              
External Customers$31.3
 $—
 $—
 $31.3
$30.9
 $—
 $—
 $30.9
Sales to AEP Affiliates162.1
 —
 —
 162.1
160.7
 —
 —
 160.7
Other Revenues0.1
 —
 —
 0.1
0.1
 —
 —
 0.1
Total Revenues$193.5
 $—
 $—
 $193.5
$191.7
 $—
 $—
 $191.7
              
Interest Income$0.2
 $25.0
 $(24.8)(a)$0.4
$0.2
 $25.0
 $(24.8)(a)$0.4
Interest Expense19.9
 24.8
 (24.8)(a)19.9
20.3
 24.8
 (24.8)(a)20.3
Income Tax Expense22.3
 0.2
 —
 22.5
21.7
 0.3
 —
 22.0
              
Net Income (Loss)$86.0
 $(0.1)(b)$—
 $85.9
Net Income$84.1
 $—
 $—
 $84.1



 Three Months Ended March 31, 2017
 State Transcos AEPTCo Parent Reconciling Adjustments 
AEPTCo
Consolidated
 (in millions)
Revenues from:       
External Customers$19.2
 $—
 $—
 $19.2
Sales to AEP Affiliates133.4
 —
 —
 133.4
    Other Revenues0.1
 —
 —
 0.1
Total Revenues$152.7
 $—
 $—
 $152.7
        
Interest Income$0.1
 $19.1
 $(19.0)(a)$0.2
Interest Expense15.8
 19.2
 (19.0)(a)16.0
Income Tax Expense28.4
 0.1
 —
 28.5
        
Net Income$56.8
 $0.2
(b)$—
 $57.0



 March 31, 2019
 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated
 (in millions)
Total Transmission Property$8,567.2
 $—
 $—
 $8,567.2
Accumulated Depreciation and Amortization306.7
 —
 —
 306.7
Total Transmission Property – Net$8,260.5
 $—
 $—
 $8,260.5
        
Notes Receivable – Affiliated$—
 $2,823.4
 $(2,823.4)(c)$—
        
Total Assets$8,584.0
 $2,928.1
(d)$(2,896.0)(e)$8,616.1
        
Total Long-term Debt$2,850.0
 $2,823.4
 $(2,850.0)(c)$2,823.4
March 31, 2018December 31, 2018
State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated		State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated
(in millions)(in millions)
Total Transmission Property$7,108.0
 $—
 $—
 $7,108.0
$8,268.1
 $—
 $—
 $8,268.1
Accumulated Depreciation and Amortization192.7
 —
 —
 192.7
271.9
 —
 —
 271.9
Total Transmission Property – Net$6,915.3
 $—
 $—
 $6,915.3
$7,996.2
 $—
 $—
 $7,996.2
              
Notes Receivable - Affiliated$—
 $2,550.7
 $(2,550.7)(c)$—
Notes Receivable – Affiliated$—
 $2,823.0
 $(2,823.0)(c)$—
              
Total Assets$7,220.0
 $2,637.3
(d)$(2,617.4)(e)$7,239.9
$8,406.8
 $2,857.1
(d)$(2,869.8)(e)$8,394.1
              
Total Long-term Debt$2,575.0
 $2,550.7
 $(2,575.0)(c)$2,550.7
$2,850.0
 $2,823.0
 $(2,850.0)(c)$2,823.0
 December 31, 2017
 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated
 (in millions)
Total Transmission Property$6,780.2
 $—
 $—
 $6,780.2
Accumulated Depreciation and Amortization170.4
 —
 —
 170.4
Total Transmission Property – Net$6,609.8
 $—
 $—
 $6,609.8
        
Notes Receivable - Affiliated$—
 $2,550.4
 $(2,550.4)(c)$—
        
Total Assets$7,072.9
 $2,590.1
(d)$(2,594.9)(e)$7,068.1
        
Total Long-term Debt$2,575.0
 $2,550.4
 $(2,575.0)(c)$2,550.4


(a)Elimination of intercompany interest income/interest expense on affiliated debt arrangement.
(b)Includes the elimination of AEPTCo Parent’s equity earnings in the State Transcos.
(c)Elimination of intercompany debt.
(d)Includes the elimination of AEPTCo Parent’s investments in State Transcos.
(e)Primarily relates to the elimination of Notes Receivable from the State Transcos.
(f)The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.




9.  DERIVATIVES AND HEDGING


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


OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS


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


The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets.  These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange 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
March 31, 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 298.4
 —
 43.2
 33.0
 8.3
 4.0
 8.1
 MWhs 310.4
 —
 43.9
 25.9
 7.6
 7.8
 2.0
Coal Tons 1.2
 —
 —
 1.2
 —
 —
 —
Natural Gas MMBtus 78.2
 —
 6.2
 3.7
 —
 —
 18.0
 MMBtus 80.6
 —
 4.0
 2.3
 —
 —
 14.3
Heating Oil and Gasoline Gallons 5.0
 1.1
 1.0
 0.5
 1.2
 0.5
 0.6
 Gallons 5.4
 1.1
 1.0
 0.5
 1.3
 0.5
 0.6
Interest Rate USD $49.8
 $—
 $—
 $—
 $—
 $—
 $—
 USD $33.8
 $—
 $—
 $—
 $—
 $—
 $—
                            
Interest Rate and Foreign Currency USD $500.0
 $—
 $—
 $—
 $—
 $—
 $—
Interest Rate USD $500.0
 $—
 $—
 $—
 $—
 $—
 $—


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 and Foreign Currency USD $500.0
 $—
 $—
 $—
 $—
 $—
 $—


Fair Value Hedging Strategies (Applies to AEP)


Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate.floating-rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges.


Cash Flow Hedging Strategies


The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk.


The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure.


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 $1$9 million and $9.4$18 million as of March 31, 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 $18$9 million and $9$4 million as of March 31, 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 March 31, 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
March 31, 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 $257.0
 $20.1
 $1.7
 $278.8
 $(189.2) $89.6
 $228.3
 $20.8
 $—
 $249.1
 $(155.2) $93.9
Long-term Risk Management Assets 319.6
 5.1
 —
 324.7
 (53.5) 271.2
 279.0
 7.4
 —
 286.4
 (36.0) 250.4
Total Assets 576.6
 25.2
 1.7
 603.5
 (242.7) 360.8
 507.3
 28.2
 —
 535.5
 (191.2) 344.3
                        
Current Risk Management Liabilities 246.8
 10.1
 —
 256.9
 (199.8) 57.1
 195.9
 15.4
 1.9
 213.2
 (149.8) 63.4
Long-term Risk Management Liabilities 271.6
 48.5
 22.3
 342.4
 (59.7) 282.7
 236.6
 68.6
 4.4
 309.6
 (41.7) 267.9
Total Liabilities 518.4
 58.6
 22.3
 599.3
 (259.5) 339.8
 432.5
 84.0
 6.3
 522.8
 (191.5) 331.3
                        
Total MTM Derivative Contract Net Assets (Liabilities) $58.2
 $(33.4) $(20.6) $4.2
 $16.8
 $21.0
 $74.8
 $(55.8) $(6.3) $12.7
 $0.3
 $13.0


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)
Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a)   
  (in millions)
Current Risk Management Assets $397.5
 $28.5
 $—
 $426.0
 $(263.2) $162.8
Long-term Risk Management Assets 276.4
 16.0
 —
 292.4
 (38.4) 254.0
Total Assets 673.9
 44.5
 —
 718.4
 (301.6) 416.8
             
Current Risk Management Liabilities 293.8
 13.2
 2.0
 309.0
 (254.0) 55.0
Long-term Risk Management Liabilities 225.7
 56.1
 15.4
 297.2
 (33.8) 263.4
Total Liabilities 519.5
 69.3
 17.4
 606.2
 (287.8) 318.4
             
Total MTM Derivative Contract Net Assets (Liabilities) $154.4
 $(24.8) $(17.4) $112.2
 $(13.8) $98.4

  
Risk
Management
Contracts
 Hedging Contracts 
Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
 
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
 
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a)   
  (in millions)
Current Risk Management Assets $389.0
 $17.5
 $2.5
 $409.0
 $(282.8) $126.2
Long-term Risk Management Assets 300.9
 6.3
 —
 307.2
 (25.1) 282.1
Total Assets 689.9
 23.8
 2.5
 716.2
 (307.9) 408.3
             
Current Risk Management Liabilities 334.6
 9.0
 —
 343.6
 (282.0) 61.6
Long-term Risk Management Liabilities 280.6
 58.3
 8.6
 347.5
 (25.5) 322.0
Total Liabilities 615.2
 67.3
 8.6
 691.1
 (307.5) 383.6
             
Total MTM Derivative Contract Net Assets (Liabilities) $74.7
 $(43.5) $(6.1) $25.1
 $(0.4) $24.7







AEP Texas
Fair Value of Derivative Instruments
March 31, 20182019
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)
 
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) (in millions)
Current Risk Management Assets $0.4
 $(0.1) $0.3
 $—
 $—
 $—
Long-term Risk Management Assets —
 —
 —
 —
 —
 —
Total Assets 0.4
 (0.1) 0.3
 —
 —
 —
            
Current Risk Management Liabilities —
 —
 —
 0.2
 —
 0.2
Long-term Risk Management Liabilities —
 —
 —
 —
 —
 —
Total Liabilities —
 —
 —
 0.2
 —
 0.2
            
Total MTM Derivative Contract Net Assets (Liabilities) $0.4
 $(0.1) $0.3
Total MTM Derivative Contract Net Liabilities $(0.2) $—
 $(0.2)
 
Fair Value of Derivative Instruments
December 31, 20172018
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)
 
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) (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
March 31, 20182019
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)
 
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) (in millions)
Current Risk Management Assets $35.8
 $(27.8) $8.0
 $40.5
 $(27.6) $12.9
Long-term Risk Management Assets 11.2
 (8.6) 2.6
 3.9
 (3.6) 0.3
Total Assets 47.0
 (36.4) 10.6
 44.4
 (31.2) 13.2
            
Current Risk Management Liabilities 28.4
 (27.8) 0.6
 33.5
 (27.4) 6.1
Long-term Risk Management Liabilities 9.1
 (8.7) 0.4
 3.7
 (3.5) 0.2
Total Liabilities 37.5
 (36.5) 1.0
 37.2
 (30.9) 6.3
            
Total MTM Derivative Contract Net Assets $9.5
 $0.1
 $9.6
Total MTM Derivative Contract Net Assets (Liabilities) $7.2
 $(0.3) $6.9
 
Fair Value of Derivative Instruments
December 31, 20172018
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)
 
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) (in millions)
Current Risk Management Assets $75.6
 $(50.7) $24.9
 $114.4
 $(57.2) $57.2
Long-term Risk Management Assets 2.4
 (1.3) 1.1
 3.1
 (2.2) 0.9
Total Assets 78.0
 (52.0) 26.0
 117.5
 (59.4) 58.1
            
Current Risk Management Liabilities 50.6
 (49.3) 1.3
 56.7
 (56.3) 0.4
Long-term Risk Management Liabilities 1.4
 (1.2) 0.2
 2.4
 (2.2) 0.2
Total Liabilities 52.0
 (50.5) 1.5
 59.1
 (58.5) 0.6
            
Total MTM Derivative Contract Net Assets (Liabilities) $26.0
 $(1.5) $24.5
 $58.4
 $(0.9) $57.5







I&M
Fair Value of Derivative Instruments
March 31, 20182019
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)
 
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) (in millions)
Current Risk Management Assets $24.0
 $(20.7) $3.3
 $22.0
 $(17.6) $4.4
Long-term Risk Management Assets 8.0
 (6.0) 2.0
 2.3
 (2.2) 0.1
Total Assets 32.0
 (26.7) 5.3
 24.3
 (19.8) 4.5
            
Current Risk Management Liabilities 24.6
 (20.8) 3.8
 17.6
 (17.3) 0.3
Long-term Risk Management Liabilities 6.1
 (5.9) 0.2
 2.2
 (2.1) 0.1
Total Liabilities 30.7
 (26.7) 4.0
 19.8
 (19.4) 0.4
            
Total MTM Derivative Contract Net Assets $1.3
 $—
 $1.3
Total MTM Derivative Contract Net Assets (Liabilities) $4.5
 $(0.4) $4.1
 


Fair Value of Derivative Instruments
December 31, 20172018
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)
 
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) (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
March 31, 20182019
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)
 
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) (in millions)
Current Risk Management Assets $0.5
 $(0.1) $0.4
 $—
 $—
 $—
Long-term Risk Management Assets —
 —
 —
 —
 —
 —
Total Assets 0.5
 (0.1) 0.4
 —
 —
 —
            
Current Risk Management Liabilities 5.3
 —
 5.3
 6.9
 —
 6.9
Long-term Risk Management Liabilities 93.2
 —
 93.2
 99.4
 —
 99.4
Total Liabilities 98.5
 —
 98.5
 106.3
 —
 106.3
            
Total MTM Derivative Contract Net Liabilities $(98.0) $(0.1) $(98.1) $(106.3) $—
 $(106.3)
 
Fair Value of Derivative Instruments
December 31, 20172018
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 $—
 $—
 $—
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
March 31, 20182019
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)
 
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) (in millions)
Current Risk Management Assets $2.9
 $—
 $2.9
 $5.4
 $(0.4) $5.0
Long-term Risk Management Assets —
 —
 —
 —
 —
 —
Total Assets 2.9
 —
 2.9
 5.4
 (0.4) 5.0
            
Current Risk Management Liabilities —
 —
 —
 1.1
 (0.4) 0.7
Long-term Risk Management Liabilities —
 —
 —
 —
 —
 —
Total Liabilities —
 —
 —
 1.1
 (0.4) 0.7
            
Total MTM Derivative Contract Net Assets $2.9
 $—
 $2.9
 $4.3
 $—
 $4.3
 
Fair Value of Derivative Instruments
December 31, 20172018
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)
 
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) (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
March 31, 20182019
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)
 
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) (in millions)
Current Risk Management Assets $2.8
 $(1.1) $1.7
 $2.3
 $(0.3) $2.0
Long-term Risk Management Assets —
 —
 —
 —
 —
 —
Total Assets 2.8
 (1.1) 1.7
 2.3
 (0.3) 2.0
            
Current Risk Management Liabilities 1.2
 (1.1) 0.1
 0.5
 (0.3) 0.2
Long-term Risk Management Liabilities 0.5
 —
 0.5
 1.9
 —
 1.9
Total Liabilities 1.7
 (1.1) 0.6
 2.4
 (0.3) 2.1
            
Total MTM Derivative Contract Net Assets $1.1
 $—
 $1.1
Total MTM Derivative Contract Net Liabilities $(0.1) $—
 $(0.1)
 
Fair Value of Derivative Instruments
December 31, 20172018
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)
 
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) (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)There are noAll derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.



The tables below present the Registrants’ activity of derivative risk management contracts:


Amount of Gain (Loss) Recognized on
Risk Management Contracts
Three Months Ended March 31, 2019
Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo
  (in millions)
Vertically Integrated Utilities Revenues $0.3
 $—
 $—
 $—
 $—
 $—
 $—
Generation & Marketing Revenues 2.7
 —
 —
 —
 —
 —
 —
Electric Generation, Transmission and Distribution Revenues —
 —
 (0.1) 0.3
 —
 —
 0.1
Purchased Electricity for Resale 1.4
 —
 —
 —
 —
 —
 —
Other Operation (0.4) (0.1) (0.1) —
 (0.1) —
 —
Maintenance (0.5) (0.1) —
 —
 (0.1) —
 (0.1)
Regulatory Assets (a) (6.4) 0.6
 (2.1) 0.3
 (8.9) 0.5
 (0.1)
Regulatory Liabilities (a) (22.0) —
 (31.7) 6.6
 —
 6.2
 4.7
Total Gain (Loss) on Risk Management Contracts $(24.9) $0.4
 $(34.0) $7.2
 $(9.1) $6.7
 $4.6

Amount of Gain (Loss) Recognized on
Risk Management Contracts
Three Months Ended March 31, 2018
Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo
  (in millions)
Vertically Integrated Utilities Revenues $(5.5) $—
 $—
 $—
 $—
 $—
 $—
Generation & Marketing Revenues (15.1) —
 —
 —
 —
 —
 —
Electric Generation, Transmission and Distribution Revenues —
 —
 (0.3) (5.1) —
 —
 —
Purchased Electricity for Resale 4.9
 —
 4.6
 0.2
 —
 —
 —
Other Operation 0.3
 0.1
 —
 —
 0.1
 —
 —
Maintenance 0.4
 0.1
 0.1
 —
 0.1
 —
 —
Regulatory Assets (a) 37.3
 —
 —
 6.2
 31.4
 —
 (0.3)
Regulatory Liabilities (a) 87.0
 (0.1) 64.1
 0.2
 —
 12.1
 (0.8)
Total Gain (Loss) on Risk Management Contracts $109.3
 $0.1
 $68.5
 $1.5
 $31.6
 $12.1
 $(1.1)

Amount of Gain (Loss) Recognized on
Risk Management Contracts
Three Months Ended March 31, 2017
Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo
  (in millions)
Vertically Integrated Utilities Revenues $5.5
 $—
 $—
 $—
 $—
 $—
 $—
Generation & Marketing Revenues 10.5
 —
 —
 —
 —
 —
 —
Electric Generation, Transmission and Distribution Revenues —
 —
 0.4
 5.2
 —
 —
 0.1
Purchased Electricity for Resale 2.4
 —
 0.8
 0.1
 —
 —
 —
Other Operation 0.2
 —
 —
 —
 —
 —
 —
Maintenance 0.2
 —
 —
 —
 —
 —
 —
Regulatory Assets (a) (14.9) —
 (5.8) (0.2) (8.6) —
 (0.2)
Regulatory Liabilities (a) 25.2
 (0.2) 10.9
 6.8
 —
 2.4
 4.6
Total Gain (Loss) on Risk Management Contracts $29.1
 $(0.2) $6.3
 $11.9
 $(8.6) $2.4
 $4.5


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


Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis.


The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge.


For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”



Accounting for Fair Value Hedging Strategies (Applies to AEP)


For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Incomenet income during the period of change.


AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income.

The following table shows the results ofimpacts recognized on the balance sheets related to the hedged items in fair value hedging gains (losses):

relationships:
 Three Months Ended March 31,
 2018 2017
 (in millions)
Loss on Fair Value Hedging Instruments$(14.5) $(0.5)
Gain on Fair Value Portion of Long-term Debt14.2
 0.5
  
Carrying Amount of the Hedged
 Assets/(Liabilities)
 Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Assets/(Liabilities)
  March 31, 2019 December 31, 2018 March 31, 2019 December 31, 2018
  (in millions)
Long-term Debt (a) $(489.6) $(478.3) $6.3
 $17.4


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

During the three months ended March 31, 2018 and 2017,The pretax effects of fair value hedge ineffectiveness was immaterial.accounting on income were as follows:

 Three Months Ended March 31,
 2019 2018
 (in millions)
Gain (Loss) on Interest Rate Contracts:   
Gain (Loss) on Fair Value Hedging Instruments (a)$11.1
 $(14.5)
Gain (Loss) on Fair Value Portion of Long-term Debt (a)(11.1) 14.5

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

Accounting for Cash Flow Hedging Strategies


For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable.net income.


Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three months ended March 31, 20182019 and 2017,2018, AEP applied cash flow hedging to outstanding power derivatives. During the three months ended March 31, 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 months ended March 31, 20182019 and 2017,2018, the Registrants did not apply cash flow hedging to outstanding interest rate derivatives.



The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three months ended March 31, 20182019 and 2017,2018, the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives.



During the three months ended March 31, 2018 and 2017, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.


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


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
  March 31, 2019 December 31, 2018
  Commodity Interest Rate Commodity Interest Rate
  (in millions)
AOCI Gain (Loss) Net of Tax (52.1) (12.4) (23.0) (12.6)
Portion Expected to be Reclassed to Net Income During the Next Twelve Months 1.6
 (1.5) 10.4
 (1.1)

  March 31, 2018 December 31, 2017
  Commodity Interest Rate Commodity Interest Rate
  (in millions)
Hedging Assets (a) $25.5
 $—
 $22.0
 $—
Hedging Liabilities (a) 58.9
 —
 65.5
 —
AOCI Loss Net of Tax (32.0) (15.5) (28.4) (13.0)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months 3.1
 (1.0) 5.5
 (0.8)

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


As of March 31, 20182019 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 117177 months.


Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets
  March 31, 2019 December 31, 2018
  Interest Rate
Company 
AOCI Gain (Loss)
Net of Tax
 
Expected to be Reclassed to
Net Income During the Next
Twelve Months
 
AOCI Gain (Loss)
Net of Tax
 
Expected to be Reclassed to
Net Income During the Next
Twelve Months
  (in millions)
AEP Texas $(4.1) $(1.1) $(4.4) $(1.1)
APCo 1.6
 0.9
 1.8
 0.9
I&M (11.1) (1.6) (11.5) (1.6)
OPCo 0.7
 0.6
 1.0
 1.0
PSO 1.9
 1.0
 2.1
 1.0
SWEPCo (2.9) (1.5) (3.3) (1.5)

  March 31, 2018 December 31, 2017
  Interest Rate
Company 
AOCI Gain (Loss)
Net of Tax
 
Expected to be Reclassified to
Net Income During the Next
Twelve Months
 
AOCI Gain (Loss)
Net of Tax
 
Expected to be Reclassified to
Net Income During the Next
Twelve Months
  (in millions)
AEP Texas $(5.2)—
$(1.1) $(4.5) $(0.9)
APCo 2.5
 0.9
 2.2
 0.7
I&M (12.7) (1.6) (10.7) (1.3)
OPCo 2.0
 1.3
 1.9
 1.1
PSO 2.9
 1.0
 2.6
 0.8
SWEPCo (6.9) (1.7) (6.0) (1.4)


The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.


Credit Risk


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


Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination
and liquidation of all positions in the event of a default including a failure or inability to post collateral when required.



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 March 31, 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 tradednon-exchange-traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third partythird-party obligation that is $50 million or greater.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following table represents:tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount that the exposure has been reduced by cash collateral posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering contractual netting arrangements:
  March 31, 2019
  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 $219.2
 $3.8
 $189.0
APCo 1.4
 —
 0.1
I&M 0.8
 —
 0.1
SWEPCo 2.0
 —
 1.9

  AEP
  
Liabilities for
Contracts with Cross
Default Provisions
Prior to Contractual
Netting Arrangements
 
Amount of Cash
Collateral Posted
 
Additional
Settlement
Liability if Cross
Default Provision
is Triggered
  (in millions)
March 31, 2018 $272.7
 $1.0
 $202.4
December 31, 2017 243.6
 1.3
 223.1
  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


Amounts for APCo, I&M and SWEPCo are immaterial as of March 31, 2018 and December 31, 2017, respectively.


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:
  March 31, 2019 December 31, 2018
Company Book Value Fair Value Book Value Fair Value
  (in millions)
AEP (a) $24,426.7
 $26,225.6
 $23,346.7
 $24,093.9
AEP Texas 3,778.3
 3,973.4
 3,881.3
 3,964.6
AEPTCo 2,823.4
 2,949.6
 2,823.0
 2,782.4
APCo 4,444.0
 5,040.6
 4,062.6
 4,473.3
I&M 3,011.4
 3,201.8
 3,035.4
 3,070.2
OPCo 1,693.6
 1,989.2
 1,716.6
 1,919.7
PSO 1,386.2
 1,503.6
 1,287.0
 1,361.9
SWEPCo 2,659.1
 2,763.0
 2,713.4
 2,670.2

  March 31, 2018 December 31, 2017
Company Book Value Fair Value Book Value Fair Value
  (in millions)
AEP $21,461.0
 $23,039.8
 $21,173.3
 $23,649.6
AEP Texas 3,553.3
 3,818.3
 3,649.3
 3,964.8
AEPTCo 2,550.7
 2,620.6
 2,550.4
 2,782.9
APCo 3,969.3
 4,532.0
 3,980.1
 4,782.6
I&M 2,717.2
 2,869.5
 2,745.1
 3,014.7
OPCo 2,089.7
 2,367.9
 1,719.3
 2,064.3
PSO 1,286.7
 1,400.3
 1,286.5
 1,457.1
SWEPCo 2,503.7
 2,587.3
 2,441.9
 2,645.9

(a)The fair value amount includes debt related to AEP’s Equity Units issued in March 2019 and has a fair value of $828 million as of March 31, 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:
 March 31, 2018 March 31, 2019
Other Temporary Investments Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 (in millions) (in millions)
Restricted Cash and Other Cash Deposits (a) $162.0
 $—
 $—
 $162.0
 $159.6
 $—
 $—
 $159.6
Fixed Income Securities – Mutual Funds (b) 104.8
 —
 (2.2) 102.6
 107.2
 —
 (1.3) 105.9
Equity Securities – Mutual Funds
 17.2
 19.2
 —
 36.4
 22.5
 16.3
 —
 38.8
Total Other Temporary Investments $284.0
 $19.2
 $(2.2) $301.0
 $289.3
 $16.3
 $(1.3) $304.3
 December 31, 2017 December 31, 2018
Other Temporary Investments Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
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 March 31,
 2019 2018
 (in millions)
Proceeds from Investment Sales$—
 $—
Purchases of Investments0.1
 0.6
Gross Realized Gains on Investment Sales—
 —
Gross Realized Losses on Investment Sales—
 —

 Three Months Ended March 31,
 2018 2017
 (in millions)
Proceeds from Investment Sales$—
 $—
Purchases of Investments0.6
 0.5
Gross Realized Gains on Investment Sales—
 —
Gross Realized Losses on Investment Sales—
 —


For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three months ended March 31, 2017,2018, 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 spent nuclear fuelSNF disposal liabilities.  By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines.  In general, limitations include:


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


I&M maintains trust funds for each regulatory jurisdiction.  Regulatory approval is required to withdraw decommissioning funds. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities.  The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.


I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities at fair value.  I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. 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:
 March 31, 2019 December 31, 2018
 
Fair
Value
 
Gross Unrealized
Gains
 
Other-Than-Temporary
Impairments
 
Fair
Value
 
Gross Unrealized
Gains
 Other-Than-Temporary Impairments
 (in millions)
Cash and Cash Equivalents$17.4
 $—
 $—
 $22.5
 $—
 $—
Fixed Income Securities:   
  
  
  
  
United States Government1,015.6
 44.0
 (6.7) 996.1
 26.7
 (7.1)
Corporate Debt54.2
 2.9
 (1.8) 52.4
 1.1
 (1.9)
State and Local Government8.7
 0.7
 (0.2) 8.6
 0.6
 (0.2)
Subtotal Fixed Income Securities1,078.5
 47.6
 (8.7) 1,057.1
 28.4
 (9.2)
Equity Securities – Domestic (a)1,588.1
 945.6
 —
 1,395.3
 766.3
 —
Spent Nuclear Fuel and Decommissioning Trusts$2,684.0
 $993.2
 $(8.7) $2,474.9
 $794.7
 $(9.2)

 March 31, 2018 December 31, 2017
 
Fair
Value
 
Gross Unrealized
Gains
 
Other-Than-Temporary
Impairments
 
Fair
Value
 
Gross Unrealized
Gains
 Other-Than-Temporary Impairments
 (in millions)
Cash and Cash Equivalents$16.4
 $—
 $—
 $17.2
 $—
 $—
Fixed Income Securities:   
  
  
  
  
United States Government974.6
 19.0
 (8.4) 981.2
 29.7
 (3.6)
Corporate Debt57.8
 2.0
 (1.7) 58.7
 3.8
 (1.2)
State and Local Government8.6
 0.6
 (0.2) 8.8
 0.8
 (0.2)
Subtotal Fixed Income Securities1,041.0
 21.6
 (10.3) 1,048.7
 34.3
 (5.0)
Equity Securities – Domestic (a)1,453.2
 850.3
 —
 1,461.7
 868.2
 (75.5)
Spent Nuclear Fuel and Decommissioning Trusts$2,510.6
 $871.9
 $(10.3) $2,527.6
 $902.5
 $(80.5)


(a)Amount reported as Gross Unrealized Gains includes unrealized gains of $855$955 million and $784 million and unrealized losses of $4.7 million.$9 million and $18 million as of March 31, 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 March 31,
 2019 2018
 (in millions)
Proceeds from Investment Sales$111.9
 $508.6
Purchases of Investments130.3
 525.3
Gross Realized Gains on Investment Sales12.3
 12.0
Gross Realized Losses on Investment Sales13.8
 10.9

 Three Months Ended March 31,
 2018 2017
 (in millions)
Proceeds from Investment Sales$508.6
 $487.9
Purchases of Investments525.3
 505.5
Gross Realized Gains on Investment Sales12.0
 11.3
Gross Realized Losses on Investment Sales10.9
 8.1


The base cost of fixed income securities was $1 billion and $1 billion as of March 31, 20182019 and December 31, 2017,2018, respectively.  The base cost of equity securities was $603$643 million and $594$629 million as of March 31, 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 March 31, 20182019 was as follows:
 Fair Value of Fixed Income Securities
 (in millions)
Within 1 year$356.4
After 1 year through 5 years375.4
After 5 years through 10 years172.8
After 10 years173.9
Total$1,078.5

 Fair Value of Fixed Income Securities
 (in millions)
Within 1 year$355.7
After 1 year through 5 years315.3
After 5 years through 10 years205.8
After 10 years164.2
Total$1,041.0





Fair Value Measurements of Financial Assets and Liabilities


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


AEP


Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31, 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) $144.8
 $—
 $—
 $17.2
 $162.0
 $147.1
 $—
 $—
 $12.5
 $159.6
Fixed Income Securities – Mutual Funds
 102.6
 —
 —
 —
 102.6
 105.9
 —
 —
 —
 105.9
Equity Securities – Mutual Funds (b)
 36.4
 —
 —
 —
 36.4
 38.8
 —
 —
 —
 38.8
Total Other Temporary Investments
 283.8
 —
 —
 17.2
 301.0
 291.8
 —
 —
 12.5
 304.3
                    
Risk Management Assets  
  
  
  
  
  
  
  
  
  
Risk Management Commodity Contracts (c) (d) 3.0
 265.0
 243.3
 (177.7) 333.6
 2.5
 200.4
 276.6
 (155.4) 324.1
Cash Flow Hedges:  
  
  
  
  
  
  
  
  
  
Commodity Hedges (c) —
 11.6
 3.1
 10.8
 25.5
 —
 14.8
 5.5
 (0.1) 20.2
Fair Value Hedges —
 1.7
 —
 —
 1.7
Total Risk Management Assets 3.0
 278.3
 246.4
 (166.9) 360.8
 2.5
 215.2
 282.1
 (155.5) 344.3
                    
Spent Nuclear Fuel and Decommissioning Trusts  
  
  
  
  
  
  
  
  
  
Cash and Cash Equivalents (e) 9.1
 —
 —
 7.3
 16.4
 9.3
 —
 —
 8.1
 17.4
Fixed Income Securities:  
  
  
  
  
  
  
  
  
  
United States Government —
 974.6
 —
 —
 974.6
 —
 1,015.6
 —
 —
 1,015.6
Corporate Debt —
 57.8
 —
 —
 57.8
 —
 54.2
 —
 —
 54.2
State and Local Government —
 8.6
 —
 —
 8.6
 —
 8.7
 —
 —
 8.7
Subtotal Fixed Income Securities —
 1,041.0
 —
 —
 1,041.0
 —
 1,078.5
 —
 —
 1,078.5
Equity Securities – Domestic (b)
 1,453.2
 —
 —
 —
 1,453.2
 1,588.1
 —
 —
 —
 1,588.1
Total Spent Nuclear Fuel and Decommissioning Trusts
 1,462.3
 1,041.0
 —
 7.3
 2,510.6
 1,597.4
 1,078.5
 —
 8.1
 2,684.0
                    
Total Assets $1,749.1
 $1,319.3
 $246.4
 $(142.4) $3,172.4
 $1,891.7
 $1,293.7
 $282.1
 $(134.9) $3,332.6
                    
Liabilities:  
  
  
  
  
  
  
  
  
  
                    
Risk Management Liabilities  
  
  
  
  
  
  
  
  
  
Risk Management Commodity Contracts (c) (d) $3.6
 $284.7
 $164.8
 $(194.5) $258.6
 $2.7
 $204.8
 $197.2
 $(155.7) $249.0
Cash Flow Hedges:  
  
  
  
  
  
  
  
  
  
Commodity Hedges (c) —
 28.5
 19.6
 10.8
 58.9
 —
 29.3
 46.8
 (0.1) 76.0
Fair Value Hedges —
 22.3
 —
 —
 22.3
 —
 6.3
 —
 —
 6.3
Total Risk Management Liabilities $3.6
 $335.5
 $184.4
 $(183.7) $339.8
 $2.7
 $240.4
 $244.0
 $(155.8) $331.3



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
March 31, 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 $107.1
 $—
 $—
 $—
 $107.1
 $100.6
 $—
 $—
 $—
 $100.6
                    
Risk Management Assets  
  
  
  
  
Liabilities:  
  
  
  
  
          
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) —
 0.4
 —
 (0.1) 0.3
 $—
 $0.2
 $—
 $—
 $0.2
          
Total Assets $107.1
 $0.4
 $—
 $(0.1) $107.4


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
DecemberMarch 31, 20172019
 Level 1 Level 2 Level 3 Other Total Level 1 Level 2 Level 3 Other Total
Assets: (in millions) (in millions)
                    
Restricted Cash for Securitized Funding $155.2
 $—
 $—
 $—
 $155.2
 $18.3
 $—
 $—
 $—
 $18.3
                    
Risk Management Assets  
  
  
  
  
  
  
  
  
  
Risk Management Commodity Contracts (c) —
 0.5
 —
 —
 0.5
Risk Management Commodity Contracts (c) (g) 0.2
 26.8
 13.4
 (27.2) 13.2
                    
Total Assets $155.2
 $0.5
 $—
 $—
 $155.7
 $18.5
 $26.8
 $13.4
 $(27.2) $31.5
          
Liabilities:  
  
  
  
  
          
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $0.2
 $27.0
 $6.0
 $(26.9) $6.3

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




APCoI&M


Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31, 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 $10.1
 $—
 $—
 $—
 $10.1
          
Risk Management Assets  
  
  
  
  
  
  
  
  
  
Risk Management Commodity Contracts (c) (g) 0.6
 27.0
 10.4
 (27.4) 10.6
 $—
 $16.7
 $5.2
 $(17.4) $4.5
          
Spent Nuclear Fuel and Decommissioning Trusts  
  
  
  
  
Cash and Cash Equivalents (e) 9.3
 —
 —
 8.1
 17.4
Fixed Income Securities:  
  
  
  
  
United States Government —
 1,015.6
 —
 —
 1,015.6
Corporate Debt —
 54.2
 —
 —
 54.2
State and Local Government —
 8.7
 —
 —
 8.7
Subtotal Fixed Income Securities —
 1,078.5
 —
 —
 1,078.5
Equity Securities - Domestic (b) 1,588.1
 —
 —
 —
 1,588.1
Total Spent Nuclear Fuel and Decommissioning Trusts
 1,597.4
 1,078.5
 —
 8.1
 2,684.0
                    
Total Assets $10.7
 $27.0
 $10.4
 $(27.4) $20.7
 $1,597.4
 $1,095.2
 $5.2
 $(9.3) $2,688.5
                    
Liabilities:  
  
  
  
  
  
  
  
  
  
                    
Risk Management Liabilities  
  
  
  
  
  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $0.6
 $26.6
 $1.3
 $(27.5) $1.0
 $0.1
 $16.5
 $0.8
 $(17.0) $0.4

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
DecemberMarch 31, 20172019
 Level 1 Level 2 Level 3 Other Total Level 1 Level 2 Level 3 Other Total
Assets: (in millions) (in millions)
                    
Restricted Cash for Securitized Funding $16.3
 $—
 $—
 $—
 $16.3
 $16.5
 $—
 $—
 $—
 $16.5
                    
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) —
 52.5
 25.1
 (51.6) 26.0
          
Total Assets $16.3
 $52.5
 $25.1
 $(51.6) $42.3
          
Liabilities:  
  
  
  
  
          
                    
Risk Management Liabilities  
  
  
  
  
          
Risk Management Commodity Contracts (c) (g) $—
 $51.2
 $0.4
 $(50.1) $1.5
 $—
 $0.2
 $106.1
 $—
 $106.3



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
March 31, 20182019
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $0.3
 $19.4
 $5.1
 $(19.5) $5.3
           
Spent Nuclear Fuel and Decommissioning Trusts  
  
  
  
  
Cash and Cash Equivalents (e) 9.1
 —
 —
 7.3
 16.4
Fixed Income Securities:  
  
  
  
  
United States Government —
 974.6
 —
 —
 974.6
Corporate Debt —
 57.8
 —
 —
 57.8
State and Local Government —
 8.6
 —
 —
 8.6
Subtotal Fixed Income Securities —
 1,041.0
 —
 —
 1,041.0
Equity Securities - Domestic (b) 1,453.2
 —
 —
 —
 1,453.2
Total Spent Nuclear Fuel and Decommissioning Trusts
 1,462.3
 1,041.0
 —
 7.3
 2,510.6
           
Total Assets $1,462.6
 $1,060.4
 $5.1
 $(12.2) $2,515.9
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $0.3
 $21.0
 $2.2
 $(19.5) $4.0
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $—
 $5.4
 $(0.4) $5.0
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $0.1
 $1.0
 $(0.4) $0.7

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
DecemberMarch 31, 20172019
  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) $—
 $—
 $2.3
 $(0.3) $2.0
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $0.1
 $2.3
 $(0.3) $2.1



OPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
MarchDecember 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 $15.9
 $—
 $—
 $—
 $15.9
          
Risk Management Assets  
  
  
  
  
  
  
  
  
  
Risk Management Commodity Contracts (c) (g) —
 0.5
 —
 (0.1) 0.4
 $—
 $—
 $5.6
 $(0.8) $4.8
          
Total Assets $15.9
 $0.5
 $—
 $(0.1) $16.3
                    
Liabilities:            
  
  
  
  
                    
Risk Management Liabilities            
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $—
 $98.5
 $—
 $98.5
 $—
 $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
March 31, 2018
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $0.1
 $2.9
 $(0.1) $2.9
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $—
 $0.1
 $(0.1) $—

PSO

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


SWEPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis
March 31, 2018
  Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
           
Risk Management Assets  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $0.2
 $2.6
 $(1.1) $1.7
           
Liabilities:  
  
  
  
  
           
Risk Management Liabilities  
  
  
  
  
Risk Management Commodity Contracts (c) (g) $—
 $—
 $1.7
 $(1.1) $0.6

SWEPCo

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


(a)Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or third parties.third-parties.  Level 1 and Level 2 amounts primarily represent investments in money market funds.
(b)Amounts represent publicly traded equity securities and equity-based mutual funds.
(c)Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.”
(d)The March 31, 20182019 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(19)$(7) million in 2018, $(3) million in periods 2019-2021 and2019, $2 million in periods 2022-2023;2023-2024 and $1 million in periods 2025-2032; Level 3 matures $24$27 million in 2018, $382019, $42 million in periods 2019-2021, $212020-2022, $23 million in periods 2022-20232023-2024 and $(5)$(13) 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.contracts for the Registrant Subsidiaries.


There were no transfers between Level 1 and Level 2 during the three months ended March 31, 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 March 31, 2018 AEP APCo I&M OPCo PSO SWEPCo
Three Months Ended March 31, 2019 AEP APCo I&M OPCo PSO SWEPCo
 (in millions) (in millions)
Balance as of December 31, 2017 $40.3
 $24.7
 $7.6
 $(132.4) $6.2
 $5.9
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) 97.3
 68.1
 3.0
 0.3
 11.4
 0.6
 (23.0) (29.0) —
 (0.4) 6.8
 3.3
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 2.0
 —
 —
 —
 —
 —
 8.5
 —
 —
 —
 —
 —
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 17.9
 —
 —
 —
 —
 —
 (15.8) —
 —
 —
 —
 —
Settlements (129.8) (85.4) (7.4) 1.1
 (16.1) (3.9) (54.5) (17.8) (5.1) 1.8
 (13.0) (7.3)
Transfers into Level 3 (c) (d) 2.1
 —
 —
 —
 —
 —
 0.1
 —
 —
 —
 —
 —
Transfers out of Level 3 (d) (2.0) —
 (0.3) —
 —
 —
 (1.2) (0.7) (0.4) —
 —
 —
Changes in Fair Value Allocated to Regulated Jurisdictions (e) 34.2
 1.7
 —
 32.5
 1.3
 (1.7) (7.2) (2.9) 1.0
 (8.1) 1.1
 1.7
Balance as of March 31, 2018 $62.0
 $9.1
 $2.9
 $(98.5) $2.8
 $0.9
Balance as of March 31, 2019 $38.1
 $7.4
 $4.4
 $(106.1) $4.4
 $—
Three Months Ended March 31, 2018 AEP APCo I&M OPCo PSO SWEPCo
  (in millions)
Balance as of December 31, 2017 $40.3
 $24.7
 $7.6
 $(132.4) $6.2
 $5.9
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 97.3
 68.1
 3.0
 0.3
 11.4
 0.6
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 2.0
 —
 —
 —
 —
 —
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 17.9
 —
 —
 —
 —
 —
Settlements (129.8) (85.4) (7.4) 1.1
 (16.1) (3.9)
Transfers into Level 3 (c) (d) 2.1
 —
 —
 —
 —
 —
Transfers out of Level 3 (d) (2.0) —
 (0.3) —
 —
 —
Changes in Fair Value Allocated to Regulated Jurisdictions (e) 34.2
 1.7
 —
 32.5
 1.3
 (1.7)
Balance as of March 31, 2018 $62.0
 $9.1
 $2.9
 $(98.5) $2.8
 $0.9

Three Months Ended March 31, 2017 AEP APCo I&M OPCo PSO SWEPCo
  (in millions)
Balance as of December 31, 2016 $2.5
 $1.4
 $2.8
 $(119.0) $0.7
 $0.7
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 17.8
 5.7
 2.0
 (0.5) 2.2
 4.5
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 16.1
 —
 —
 —
 —
 —
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (17.2) —
 —
 —
 —
 —
Settlements (28.8) (12.2) (4.3) 2.1
 (2.6) (4.9)
Transfers into Level 3 (c) (d) 5.2
 —
 —
 —
 —
 —
Transfers out of Level 3 (d) (8.3) —
 —
 —
 —
 —
Changes in Fair Value Allocated to Regulated Jurisdictions (e) (5.8) (0.7) 1.5
 (7.2) 0.1
 0.2
Balance as of March 31, 2017 $(18.5) $(5.8) $2.0
 $(124.6) $0.4
 $0.5


(a)Included in revenues on the statements of income.
(b)Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(c)Represents existing assets or liabilities that were previously categorized as Level 2.
(d)Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
(e)Relates to the net gains (losses) of those contracts that are not reflected on the statements of income.  These net gains (losses) are recorded as regulatory assets/liabilities.liabilities or accounts payable.




The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions:


Significant Unobservable Inputs
March 31, 20182019
AEP
   Significant Input/Range   Significant Input/Range
Fair ValueValuation Unobservable     WeightedFair ValueValuation Unobservable     Weighted
Assets LiabilitiesTechnique Input Low High AverageAssets LiabilitiesTechnique Input Low High Average
(in millions)          (in millions)          
Energy Contracts$226.0
 $178.3
 Discounted Cash Flow  Forward Market Price (a)  $8.54
 $202.55
 $34.74
$256.7
 $229.0
 Discounted Cash Flow  Forward Market Price (a)  $(0.05) $165.64
 $32.60
    Counterparty Credit Risk (b)  9
 501
 179
Natural Gas Contracts—
 0.6
 Discounted Cash Flow Forward Market Price (c) 2.33
 2.96
 2.59
—
 2.0
 Discounted Cash Flow Forward Market Price (b) 2.27
 2.87
 2.48
FTRs20.4
 5.5
 Discounted Cash Flow  Forward Market Price (a)  (9.68) 8.81
 0.28
25.4
 13.0
 Discounted Cash Flow  Forward Market Price (a)  (8.34) 10.30
 (0.02)
Total$246.4
 $184.4
      
  
  $282.1
 $244.0
      
  
  

December 31, 2018
     Significant Input/Range
 Fair ValueValuation Unobservable     Weighted
 Assets LiabilitiesTechnique 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
      
  
  




Significant Unobservable Inputs
DecemberMarch 31, 20172019
AEPAPCo
   Significant Input/Range  Significant Input/Range
Fair ValueValuation Unobservable     WeightedFair Value Valuation Unobservable     Weighted
Assets LiabilitiesTechnique 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
 $0.4
 Discounted Cash Flow  Forward Market Price  $17.40
 $49.25
 $34.91
    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
9.8
 5.6
 Discounted Cash Flow  Forward Market Price  (0.06) 2.44
 0.61
Total$278.8
 $238.5
      
  
  $13.4
 $6.0
      
  
  



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
      
  
  


Significant Unobservable Inputs
March 31, 2018
APCo
     Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
Energy Contracts$2.5
 $0.3
 Discounted Cash Flow  Forward Market Price  $20.56
 $46.25
 $33.30
FTRs7.9
 1.0
 Discounted Cash Flow  Forward Market Price  (0.30) 6.36
 1.14
Total$10.4
 $1.3
      
  
  

Significant Unobservable Inputs
December 31, 2017
APCo
     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 Unobservable Inputs
March 31, 20182019
I&M
    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$1.5
 $1.3
 Discounted Cash Flow  Forward Market Price  $20.56
 $46.25
 $33.30
$1.9
 $0.3
 Discounted Cash Flow  Forward Market Price  $17.40
 $49.25
 $34.91
FTRs3.6
 0.9
 Discounted Cash Flow  Forward Market Price  (0.35) 5.74
 0.77
3.3
 0.5
 Discounted Cash Flow  Forward Market Price  (0.10) 2.02
 0.86
Total$5.1
 $2.2
      
  
  $5.2
 $0.8
      
  
  

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
      
  
  




Significant Unobservable Inputs
DecemberMarch 31, 20172019
I&MOPCo
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
Energy Contracts$0.5
 $0.3
 Discounted Cash Flow  Forward Market Price  $20.52
 $195.00
 $33.80
FTRs8.6
 1.2
 Discounted Cash Flow  Forward Market Price  (0.36) 5.75
 0.86
Total$9.1
 $1.5
      
  
  
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
Energy Contracts$—
 $106.1
 Discounted Cash Flow  Forward Market Price $25.35
 $66.99
 $43.29



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


Significant Unobservable Inputs
March 31, 20182019
OPCoPSO
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input Low High Average
 (in millions)          
Energy Contracts$—
 $98.5
 Discounted Cash Flow  Forward Market Price (a) $27.42
 $62.16
 $43.76
       Counterparty Credit Risk (b)  9
 202
 144
Total$—
 $98.5
          
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
FTRs$5.4
 $1.0
 Discounted Cash Flow  Forward Market Price  $(8.34) $10.30
 $(1.09)

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)




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

 

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

Significant Unobservable Inputs
March 31, 2018
PSO
       Significant Input/Range
 Fair Value Valuation Unobservable     Weighted
 Assets Liabilities Technique Input (a) Low High Average
 (in millions)          
FTRs$2.9
 $0.1
 Discounted Cash Flow  Forward Market Price  $(9.68) $1.39
 $(0.76)

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



Significant Unobservable Inputs
March 31, 20182019
SWEPCo
    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)          
Natural Gas Contracts$—
 $0.6
 Discounted Cash Flow Forward Market Price (c) $2.33
 $2.96
 $2.59
$—
 $2.0
 Discounted Cash Flow Forward Market Price (b) $2.27
 $2.87
 $2.48
FTRs2.6
 1.1
 Discounted Cash Flow  Forward Market Price (a) (9.68) 1.39
 (0.76)2.3
 0.3
 Discounted Cash Flow  Forward Market Price (a) (8.34) 10.30
 (1.09)
Total$2.6
 $1.7
      $2.3
 $2.3
      


Significant Unobservable Inputs
December 31, 2017
SWEPCo2018
    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)          
Natural Gas Contracts$—
 $0.2
 Discounted Cash Flow Forward Market Price (c) $2.37
 $2.96
 $2.62
$—
 $2.5
 Discounted Cash Flow Forward Market Price (b) $2.18
 $3.54
 $2.47
FTRs6.7
 0.6
 Discounted Cash Flow  Forward Market Price (a) (6.62) 1.41
 (0.76)5.6
 0.8
 Discounted Cash Flow  Forward Market Price (a) (11.68) 10.30
 (1.40)
Total$6.7
 $0.8
      $5.6
 $3.3
      


(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 March 31, 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.


FederalStatus of Tax Reform Regulatory Proceedings


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

Provisional Amounts

The Registrants applied Staff Accounting Bulletin 118 (SAB 118), issued by the SEC staff in December 2017, and made reasonable estimates for the measurement and accounting of theregulatory effects of Tax Reform which are reflected inproceedings have not been fully resolved, the financial statements as provisional amounts based ontable below summarizes the best information available. SAB 118 providescurrent status. See Note 4 - Rate Matters for up to a one year period to complete the required analysis and accounting for Tax Reform referred to as the measurement period. While the Registrants were able to make reasonable estimates of the impact of Tax Reform in 2017, the final impact may differ from the recorded provisional amounts to the extent refinements are made to the estimated cumulative differences or as a result of additional guidance or technical corrections that may be issued by the IRS that may impact management’s interpretation and assumptions utilized. The measurement period adjustments recorded during the first quarter of 2018 to the provisional amounts were immaterial. The Registrants expect to complete the analysis of the provisional items during the second half of 2018.

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

State utility commissions have issued orders or instructions requiring public utilities, including the Registrants, to record liabilities to reflect the impact of the reduction in the corporate federal income tax rate in excess of the enacted corporate federal income tax rate of 21% beginning in 2018. The following table provides a summary of the estimated provisions for revenue refund recorded by the Registrants related to the reduction in the corporate federal tax rate as of and for the three months ended March 31, 2018:information.
  AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
  (in millions)
Decrease in Total Revenues $(119.5) $(7.6) $(19.0) $(35.4) $(17.8) $(21.3) $(3.8) $(11.0)
Increase in Current Liabilities 33.9
 —
 16.2
 7.8
 3.0
 6.2
 —
 —
Increase in Deferred Credits and Other Noncurrent Liabilities 85.6
 7.6
 2.8
 27.6
 14.8
 15.1
 3.8
 11.0
Registrant (Jurisdiction)Change in Tax RateExcess ADIT Subject to Normalization RequirementsExcess ADIT Not Subject to Normalization Requirements
AEP Texas (Texas-Distribution)Order IssuedOrder IssuedOrder Issued – Partial (a)
AEP Texas (Texas-Transmission)Order IssuedTo be addressed in a later filingTo be addressed in a later filing
I&M (Michigan)Order IssuedCase PendingCase Pending
SWEPCo (Louisiana)Case Pending – Rates Implemented (b)Case Pending – Rates Implemented (b)Case Pending – Rates Implemented (b)
SWEPCo (Texas)Order IssuedTo be addressed in a later filingTo be addressed in a later filing
PJM FERC TransmissionSettlement Approved (c)Settlement Approved (c)Settlement Approved (c)
SPP FERC TransmissionSettlement PendingSettlement PendingSettlement Pending


(a)A portion of the Excess ADIT that is not subject to rate normalization requirements is to be addressed in a later filing.
(b)Rates have been implemented through a filed formula rate plan that is subject to true-up and final commission approval.
(c)An ALJ has approved a settlement. The settlement is subject to final FERC ruling.
Excess Accumulated Deferred Income Taxes - Pending Rate Reductions

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

As reflected in the Registrants’ respective estimated annual ETR for 2018, AEP’s regulated public utilities began amortizing the excess accumulated deferred income taxes (Excess ADIT) associated with certain depreciable property subject to rate normalization requirements using the ARAM during the first quarter of 2018. The amortization resulted in a reduction in the Excess ADIT balance recorded in Regulatory Liabilities and Deferred Investment Tax Credits and a reduction in Income Tax Expense. As a result of state utility commission orders or instructions, in the first quarter


of 2018 the Registrants recorded estimated provisions for revenue refund offsetting the amortization of the Excess ADIT as shown in the table below:
  AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
  (in millions)
Decrease in Total Revenues $(17.2) $(2.1) $(0.1) $(4.6) $(1.7) $(1.4) $(2.2) $(3.5)
Increase in Deferred Credits and Other Noncurrent Liabilities 17.2
 2.1
 0.1
 4.6
 1.7
 1.4
 2.2
 3.5

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


Effective Tax Rates (ETR)


The Registrants’ interim ETR reflect the estimated annual ETR for 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 accumulated deferred income taxes associated with certain depreciable property using the ARAM,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 are included in the following table. Significant variances in the ETR are described below.
  Three Months Ended 
March 31,
Company 2019 2018
AEP 7.2 % 18.3%
AEP Texas 10.4 % 16.3%
AEPTCo 20.9 % 20.7%
APCo (22.0)% 18.2%
I&M (2.8)% 16.2%
OPCo 13.4 % 20.5%
PSO 0.6 % 16.3%
SWEPCo 2.4 % 18.4%

  Three Months Ended 
 March 31,
Company 2018 2017
AEP 18.3% 36.7%
AEP Texas 16.3% 34.7%
AEPTCo 20.8% 33.3%
APCo 18.2% 36.5%
I&M 16.2% 29.9%
OPCo 20.5% 34.9%
PSO 16.3% 37.7%
SWEPCo 18.4% 37.3%



AEP


Three Months Ended March 31, 20182019 Compared to Three Months Ended March 31, 20172018


The decrease in the ETR is primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result$66 million of Tax Reform and increased 2018 amortization of Excess ADIT associated with certain depreciable property usingnot subject to normalization requirements which impacted the ARAM.ETR by (10.8)%.


AEP Texas


Three Months Ended March 31, 20182019 Compared to Three Months Ended March 31, 20172018


The decrease in the ETR is primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result$1 million of Tax Reform and increased 2018 amortization of Excess ADIT associated with certain depreciable property usingnot subject to normalization requirements and an increase in parent company loss benefit which impacted the ARAM.ETR by (3.9)% and (2.2)%, respectively. Amortization of Excess ADIT not subject to normalization requirements for the three months ended March 31, 2019 reflects Tax Reform elements of a Stipulation and Settlement agreement approved by the PUCT in August 2018.




AEPTCo


Three Months Ended March 31, 20182019 Compared to Three Months Ended March 31, 20172018


The increase in the ETR is primarily due to the decrease in favorable book/tax differences accounted for on a flow-through basis.

APCo

Three Months Ended March 31, 2019 Compared to Three Months Ended March 31, 2018

The decrease in the ETR is primarily due to $41 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the change inETR by (37.9)%. Amortization of Excess ADIT not subject to normalization requirements for the corporate federal income tax rate from 35% in 2017 to 21% inthree months ended March 31, 2019 reflects October 2018 and March 2019 Virginia SCC Tax Reform orders as a result of Tax Reform.well as August 2018 and February 2019 WVPSC orders.


APCoI&M


Three Months Ended March 31, 20182019 Compared to Three Months Ended March 31, 20172018


The decrease in the ETR is primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result$13 million of Tax Reform and increased 2018 amortization of Excess ADIT associated with certain depreciable property usingnot subject to normalization requirements and an increase in favorable book/tax differences accounted for on a flow-through basis which impacted the ARAM.ETR by (13.7)% and (6.1)%, respectively. Amortization of Excess ADIT not subject to normalization requirements for the three months ended March 31, 2019 reflects the Tax Reform elements of the 2017 Indiana Base Rate Case approved by the IURC in May 2018.


I&MOPCo


Three Months Ended March 31, 20182019 Compared to Three Months Ended March 31, 20172018


The decrease in the ETR is primarily due to $9 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the change inETR by (6)%. Amortization of Excess ADIT not subject to normalization requirements for the corporate federal income tax rate from 35% in 2017 to 21% inthree months ended March 31, 2019 reflects the October 2018 as a result ofPUCO Tax Reform increased 2018 amortization of excess accumulated deferred income taxes associated with certain depreciable property using the ARAM, and decreased state income taxes resulting from elimination of bonus depreciation for certain property acquired after September 27, 2017.  These decreases were partially offset by an increase in book/tax differences which are accounted for on a flow-through basis resulting from a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028.order.


OPCo

PSO

Three Months Ended March 31, 20182019 Compared to Three Months Ended March 31, 20172018


The decrease in the ETR is primarily due to $1 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the changeETR by (16.9)%. Amortization of Excess ADIT not subject to normalization requirements for the three months ended March 31, 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 the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reform.March 2019.


PSOSWEPCo


Three Months Ended March 31, 20182019 Compared to Three Months Ended March 31, 20172018


The decrease in the ETR is primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result$3 million of Tax Reform and increased 2018 amortization of Excess ADIT associated with certain depreciable property using the ARAM.

SWEPCo

Three Months Ended March 31, 2018 Comparednot subject to Three Months Ended March 31, 2017

Thenormalization requirements and a decrease in state tax expense which impacted the ETR is primarily due to the change in the corporate federal income tax rate from 35% in 2017 to 21% in 2018 as a result of Tax Reformby (11.3)% and increased 2018 amortization(1.3)%, respectively. Amortization of Excess ADIT associated with certain depreciable property usingnot subject to normalization requirements for the ARAM.three months ended March 31, 2019 reflects Tax Reform elements incorporated into Louisiana’s 2018 Formula Rate Filing as well as an Arkansas Tax Reform order issued by the APSC in September 2018.




Federal and State Income Tax Audit Status


The IRS has completed its examination of AEP and subsidiaries are no longer subject to U.S. federal examination for all years before 2011.  The IRS examination of years 2011 through 2013 started in April 2014.  AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit.  The 2011 through 2013 audit was submitted to 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 2015.2016.

Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters.  In addition, the Registrants accrue interest on these uncertain tax positions.  Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income.


AEP and subsidiaries file income tax returns in various state and local or foreign jurisdictions.  These taxing authorities routinely examine the tax returns. AEP and subsidiaries are currently under examination in several state and local jurisdictions.  However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities.  Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income.  The Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009.2007.

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



In April 2018, the Kentucky legislature enacted House Bill 366 (HB 366) adopting significant changes to Kentucky's corporate income tax code.  HB 366 amended and reduced the corporate tax rate from a graduated rate with a maximum 6% rate to a single 5% corporate tax rate.  HB 366 also modified the apportionment formula from a traditional three-factor formula of property, payroll, and double weighted sales to a single sales factor apportionment.  The corporate income tax changes under HB 366 are effective for tax years beginning on or after January 1, 2018.  The legislation is not expected to materially impact net income, cash flows or financial condition.12.  LEASES



12.  FINANCING ACTIVITIES


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 rate implicit in the lease when that rate is readily determinable. When the implicit rate is not readily determinable, the Registrants calculate their lease obligation using their incremental borrowing rate. Spreads to estimate the discount associated with borrowing on a secured basis are incorporated into the calculation.

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 March 31, 2019 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
  (in millions)
Operating Lease Cost $64.6
 $3.8
 $0.6
 $4.6
 $23.0
 $3.6
 $1.5
 $1.8
Finance Lease Cost: 

 

 

 

 

 

 

 

Amortization of Right-of-Use Assets 14.2
 1.1
 —
 1.5
 1.3
 0.7
 0.7
 2.7
Interest on Lease Liabilities 4.1
 0.3
 —
 0.7
 0.8
 0.2
 0.1
 0.8
Total Lease Rental Costs (a) $82.9
 $5.2
 $0.6
 $6.8
 $25.1
 $4.5
 $2.3
 $5.3

(a)Excludes variable and short-term lease costs, which were immaterial for the three months ended March 31, 2019.

Supplemental information related to leases as of and for the three months ended March 31, 2019 are shown in the tables below.
Lease Term and Discount Rate AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
                 
Weighted-Average Remaining Lease Term (years):                
Operating Leases 5.43
 7.30
 2.71
 6.34
 4.32
 8.21
 7.11
 6.67
Finance Leases 5.94
 7.07
 1.08
 6.44
 6.91
 6.16
 6.06
 5.60
Weighted-Average Discount Rate:                
Operating Leases 3.61% 3.82% 3.14% 3.66% 3.45% 3.86% 3.67% 3.89%
Finance Leases 6.19% 4.79% 9.33% 8.61% 9.03% 4.81% 4.78% 5.04%

  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 from Operating Leases $28.9
 $3.8
 $0.7
 $4.2
 $5.0
 $3.6
 $1.5
 $1.4
Operating Cash Flows from Finance Leases 3.8
 0.3
 —
 0.7
 0.7
 0.2
 0.1
 0.7
Financing Cash Flows from Finance Leases 14.3
 1.2
 —
 1.6
 1.2
 0.7
 0.7
 2.7
                 
Non-cash Acquisitions Under Operating Leases $38.5
 $4.6
 $—
 $3.5
 $2.6
 $15.8
 $2.3
 $2.6




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.
March 31, 2019 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
  (in millions)
Property, Plant and Equipment Under Finance Leases:                
Generation $166.3
 $—
 $—
 $38.6
 $27.0
 $—
 $2.6
 $69.4
Other Property, Plant and Equipment 277.3
 39.9
 0.2
 17.4
 33.4
 21.3
 18.3
 11.7
Total Property, Plant and Equipment 443.6
 39.9
 0.2
 56.0
 60.4
 21.3
 20.9
 81.1
Accumulated Amortization 149.4
 10.1
 0.1
 15.7
 21.2
 6.7
 8.1
 22.1
Net Property, Plant and Equipment Under Finance Leases $294.2
 $29.8
 $0.1
 $40.3
 $39.2
 $14.6
 $12.8
 $59.0
                 
Obligations Under Finance Leases:                
Noncurrent Liability $237.4
 $24.9
 $—
 $34.0
 $33.7
 $11.4
 $9.8
 $49.3
Liability Due Within One Year 61.5
 4.9
 0.1
 6.3
 5.5
 3.2
 3.0
 10.6
Total Obligations Under Finance Leases $298.9
 $29.8
 $0.1
 $40.3
 $39.2
 $14.6
 $12.8
 $59.9

March 31, 2019 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
  (in millions)
Operating Lease Assets $1,045.4
 $82.4
 $5.8
 $79.1
 $326.3
 $86.6
 $34.8
 $38.0
                 
Obligations Under Operating Leases:                
Noncurrent Liability $860.2
 $70.2
 $3.2
 $64.8
 $266.0
 $74.0
 $29.1
 $32.3
Liability Due Within One Year 228.2
 12.2
 2.6
 15.0
 81.8
 13.0
 5.7
 6.1
Total Obligations Under Operating Leases $1,088.4
 $82.4
 $5.8
 $79.8
 $347.8
 $87.0
 $34.8
 $38.4


Future minimum lease payments as of March 31, 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 $74.1
 $6.2
 $0.1
 $9.2
 $8.4
 $3.8
 $3.6
 $13.2
Year 2 63.6
 5.8
 —
 8.4
 7.5
 3.3
 2.9
 11.3
Year 3 54.9
 5.1
 —
 7.6
 6.9
 2.7
 2.1
 10.5
Year 4 46.2
 4.5
 —
 7.1
 6.3
 2.0
 1.7
 9.3
Year 5 38.8
 3.9
 —
 6.6
 5.9
 1.5
 1.4
 9.3
Later Years 87.4
 10.2
 —
 12.3
 20.9
 4.0
 3.3
 15.7
Total Future Minimum Lease Payments 365.0
 35.7
 0.1
 51.2
 55.9
 17.3
 15.0
 69.3
Less Imputed Interest 66.1
 5.9
 —
 10.9
 16.7
 2.7
 2.2
 9.4
Estimated Present Value of Future Minimum Lease Payments $298.9
 $29.8
 $0.1
 $40.3
 $39.2
 $14.6
 $12.8
 $59.9



Noncancelable Operating Leases AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
  (in millions)
Year 1 $263.3
 $15.2
 $2.7
 $18.0
 $92.5
 $16.0
 $6.8
 $7.6
Year 2 253.3
 14.4
 2.0
 16.5
 89.5
 14.4
 6.4
 7.4
Year 3 235.9
 13.5
 0.9
 14.0
 84.9
 12.4
 5.4
 6.9
Year 4 226.8
 12.5
 0.6
 12.8
 85.2
 11.6
 5.1
 6.4
Year 5 61.5
 11.1
 —
 9.7
 7.0
 10.2
 4.6
 5.2
Later Years 180.7
 29.4
 —
 20.5
 20.4
 38.6
 12.1
 11.1
Total Future Minimum Lease Payments 1,221.5
 96.1
 6.2
 91.5
 379.5
 103.2
 40.4
 44.6
Less Imputed Interest 133.1
 13.7
 0.4
 11.7
 31.7
 16.2
 5.6
 6.2
Estimated Present Value of Future Minimum Lease Payments $1,088.4
 $82.4
 $5.8
 $79.8
 $347.8
 $87.0
 $34.8
 $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
Noncancelable 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 March 31, 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 $48.8
AEP Texas 10.9
APCo 8.9
I&M 3.9
OPCo 8.4
PSO 4.0
SWEPCo 4.4


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 it equally 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 with potential renewal options.  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 March 31, 2019 as the option to renew 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 March 31, 2019 were as follows:
Future Minimum Lease Payments AEP (a) I&M
  (in millions)
2019 $147.8
 $73.9
2020 147.8
 73.9
2021 147.8
 73.9
2022 147.2
 73.6
Total Future Minimum Lease Payments $590.6
 $295.3

(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 March 31, 2019, the maximum potential amount of future payments required under the guaranteed leases was $43 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 March 31, 2019, AEP’s boat and barge lease guarantee liability was $5 million, of which $1 million was recorded in Other Current Liabilities and $4 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 rating 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.

Lessor Activity

The Registrants’ lessor activity was immaterial as of and for the three months ended March 31, 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 March 31, 2018 December 31, 2017 March 31, 2019 December 31, 2018
 (in millions) (in millions)
Senior Unsecured Notes $17,004.6
 $16,478.3
 $19,411.6
 $18,903.3
Pollution Control Bonds 1,540.4
 1,621.7
 1,590.0
 1,643.8
Notes Payable 230.2
 260.8
 177.0
 204.7
Securitization Bonds 1,285.9
 1,416.5
 973.0
 1,111.4
Spent Nuclear Fuel Obligation (a) 269.5
 268.6
 275.3
 273.6
Junior Subordinated Notes (b) 785.0
 —
Other Long-term Debt 1,130.4
 1,127.4
 1,214.8
 1,209.9
Total Long-term Debt Outstanding 21,461.0
 21,173.3
 24,426.7
 23,346.7
Long-term Debt Due Within One Year 2,616.1
 1,753.7
 1,528.5
 1,698.5
Long-term Debt $18,844.9
 $19,419.6
 $22,898.2
 $21,648.2


(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 $313$318 million and $312$317 million as of March 31, 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 three months of 20182019 are shown in the tables below:following tables:
Company Type of Debt Principal Amount (a) Interest Rate Due Date Type of Debt Principal Amount (a) Interest Rate Due Date
Issuances:   (in millions) (%)     (in millions) (%) 
OPCo Senior Unsecured Notes $400.0
 4.15 2048
SWEPCo Senior Unsecured Notes 450.0
 3.85 2048
AEP Junior Subordinated Notes (b) $805.0
 3.40 2024
APCo Senior Unsecured Notes 400.0
 4.50 2049
PSO Senior Unsecured Notes 100.0
 3.91 2029
      
Non-Registrant:      
Transource Energy Other Long-term Debt 3.4
 Variable 2020 Other Long-term Debt 6.3
 Variable 2020
Total Issuances $853.4
  $1,311.3
 


(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.



Company Type of Debt  Principal Amount Paid Interest Rate Due Date
Retirements and Principal Payments:   (in millions) (%)  
AEP Texas Securitization Bonds $103.5
 5.31 2020
APCo Securitization Bonds 12.0
 2.01 2023
I&M Notes Payable 1.4
 Variable 2019
I&M Notes Payable 1.4
 Variable 2019
I&M Notes Payable 7.1
 Variable 2020
I&M Notes Payable 5.9
 Variable 2021
I&M Notes Payable 5.0
 Variable 2022
I&M Notes Payable 5.3
 Variable 2022
I&M Other Long-term Debt 0.4
 6.00 2025
OPCo Securitization Bonds 23.4
 2.05 2019
PSO Other Long-term Debt 0.1
 3.00 2027
SWEPCo Pollution Control Bonds 53.5
 1.60 2019
SWEPCo Notes Payable 1.6
 4.58 2032
Total Retirements and Principal Payments   $220.6
    

Company Type of Debt  Principal Amount Paid Interest Rate Due Date
Retirements and Principal Payments:   (in millions) (%)  
AEP Texas Securitization Bonds $70.0
 5.17 2018
AEP Texas Securitization Bonds 26.5
 5.306 2020
APCo Securitization Bonds 11.7
 2.008 2023
I&M Notes Payable 0.8
 Variable 2019
I&M Notes Payable 7.9
 Variable 2019
I&M Notes Payable 4.8
 Variable 2020
I&M Notes Payable 8.5
 Variable 2021
I&M Notes Payable 7.0
 Variable 2022
I&M Other Long-term Debt 0.4
 6.00 2025
OPCo Securitization Bonds 22.9
 2.049 2019
PSO Other Long-term Debt 0.1
 3.00 2027
SWEPCo Pollution Control Bonds 81.7
 4.95 2018
SWEPCo Senior Unsecured Notes 300.0
 5.875 2018
SWEPCo Other Long-term Debt 0.1
 3.50 2023
SWEPCo Notes Payable 1.6
 4.58 2032
Total Retirements and Principal Payments   $544.0
    


As of March 31, 2018,2019, trustees held, on behalf of AEP, $678$574 million of their reacquired Pollution Control Bonds. Of this total, $104 million and $345 million related to APCo and OPCo, respectively.OPCo.


Long-term Debt Subsequent Events

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

In April 2018,2019, I&M retired $2$2 million of Notes Payable related to DCC Fuel.

In April 2019, Transource Energy issued $2 million of variable rate Other Long-term Debt due in 2020.

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 are expected to support AEP’s overall capital expenditure plans including the recent acquisition of a contracted renewable portfolio.

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 4.5%3.0% of consolidated tangible net assets as of March 31, 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,subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries,subsidiaries; and direct borrowing from AEP.  The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC.  The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of March 31, 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 three months ended March 31, 20182019 are described in the following table:
Company 
Maximum
Borrowings
from the
Utility
Money Pool
 
Maximum
Loans to the
Utility
Money Pool
 
Average
Borrowings
from the
Utility
Money Pool
 
Average
Loans to the
Utility
Money Pool
 Net Loans to
(Borrowings from)
the Utility Money
Pool as of
March 31, 2019		 
Authorized
Short-term
Borrowing
Limit
 
  (in millions)
AEP Texas $379.9
 $—
 $301.9
 $—
 $(271.2) $500.0
 
AEPTCo 279.0
 80.0
 165.3
 32.2
 (191.1) 795.0
(a)
APCo 225.4
 232.2
 189.3
 75.9
 216.6
 600.0
 
I&M 46.3
 66.0
 19.0
 23.2
 (21.9) 500.0
 
OPCo 238.1
 —
 156.9
 —
 (227.6) 500.0
 
PSO 140.5
 —
 89.1
 —
 (55.2) 300.0
 
SWEPCo 100.6
 81.4
 41.9
 24.0
 (74.0) 350.0
 

Company 
Maximum
Borrowings
from the
Utility
Money Pool
 
Maximum
Loans to the
Utility
Money Pool
 
Average
Borrowings
from the
Utility
Money Pool
 
Average
Loans to the
Utility
Money Pool
 
Net Loans to
(Borrowings from)
the Utility Money
Pool as of
March 31, 2018
 
Authorized
Short-term
Borrowing
Limit
 
  (in millions)
AEP Texas $307.2
 $103.6
 $219.2
 $50.4
 $(232.7) $500.0
 
AEPTCo 337.3
 123.9
 188.2
 26.3
 (272.8) 795.0
(a)
APCo 285.6
 23.7
 223.6
 23.5
 (222.4) 600.0
 
I&M 314.1
 12.5
 240.6
 12.5
 (301.6) 500.0
 
OPCo 229.1
 216.4
 104.9
 179.5
 200.4
 400.0
 
PSO 179.1
 —
 143.3
 —
 (179.1) 300.0
 
SWEPCo 169.1
 296.5
 143.7
 273.2
 (148.6) 350.0
 


(a)Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.


The activity in the above table does not include short-term lending activity of certain AEP nonutility subsidiaries. AEP Texas’ wholly-owned subsidiary, AEP Texas North Generation Company, LLC and SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LP are participantsLLC participate in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of March 31, 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 three months ended March 31, 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 March 31, 2019
  (in millions)
AEP Texas $8.0
 $7.7
 $7.7
SWEPCo 2.0
 2.0
 2.0

  Maximum Maximum Average Average Loans to the
  Borrowings from Loans to the Borrowings from Loans to the Nonutility
  the Nonutility Nonutility the Nonutility Nonutility Money Pool as of
Company Money Pool Money Pool Money Pool Money Pool March 31, 2018
  (in millions)
AEP Texas $—
 $8.4
 $—
 $8.2
 $8.1
SWEPCo —
 2.0
 —
 2.0
 2.0


AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of outstanding loans to (borrowings from) AEP as of March 31, 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 for the three months ended March 31, 20182019 is described in the following table:
           Authorized             Authorized 
MaximumMaximum Maximum Average Average Borrowings from Loans to Short-term Maximum Maximum Average Average Borrowings from Loans to Short-term 
BorrowingsBorrowings Loans Borrowings Loans AEP as of AEP as of Borrowing Borrowings Loans Borrowings Loans AEP as of AEP as of Borrowing 
from AEPfrom AEP to AEP from AEP to AEP March 31, 2018 March 31, 2018 Limit from AEP to AEP from AEP to AEP March 31, 2019 March 31, 2019 Limit 
(in millions)
$1.1
 $104.7
 $1.1
 $51.1
 $1.1
 $23.9
 $75.0
(a)1.3
 $117.6
 $1.2
 $61.8
 $1.2
 $42.7
 $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:
  Three Months Ended March 31,
  2019 2018
Maximum Interest Rate 3.02% 2.42%
Minimum Interest Rate 2.73% 1.83%

  Three Months Ended March 31,
  2018 2017
Maximum Interest Rate 2.42% 1.27%
Minimum Interest Rate 1.83% 0.92%


The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized for allthe 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 Three Months Ended March 31, for Three Months Ended March 31,
Company 2019 2018 2019 2018
AEP Texas 2.86% 2.07% —% 1.90%
AEPTCo 2.83% 2.06% 2.90% 1.92%
APCo 2.92% 2.00% 2.79% 2.00%
I&M 2.80% 2.02% 2.87% 2.00%
OPCo 2.85% 2.00% —% 2.40%
PSO 2.89% 2.01% —% —%
SWEPCo 2.81% 2.10% 2.97% 1.88%

  Average Interest Rate Average Interest Rate
  for Funds Borrowed for Funds Loaned
  from the Utility Money Pool for to the Utility Money Pool for
  Three Months Ended March 31, Three Months Ended March 31,
Company 2018 2017 2018 2017
AEP Texas 2.07% 1.02% 1.90% —%
AEPTCo 2.06% 1.08% 1.92% 0.99%
APCo 2.00% 1.04% 2.00% 1.03%
I&M 2.02% 1.04% 2.00% 1.03%
OPCo 2.00% 1.10% 2.40% 0.98%
PSO 2.01% 1.06% —% —%
SWEPCo 2.10% 1.06% 1.88% 0.98%


Maximum, minimum and average interest rates for funds either borrowed from or loaned to the Nonutility Money Pool are summarized in the following tables:

Three Months Ended March 31, 2018:table:
  Three Months Ended March 31, 2019 Three Months Ended March 31, 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 PoolMoney Pool Money Pool Money Pool
AEP Texas 3.02% 2.73% 2.87% 2.42% 1.83% 2.00%
SWEPCo 3.02% 2.73% 2.87% 2.42% 1.83% 2.00%

  Maximum Minimum Maximum Minimum Average Average
  Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate
  for Funds for Funds for Funds for Funds for Funds for Funds
  Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to
  the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility
Company Money Pool Money PoolMoney Pool Money Pool Money Pool Money Pool
AEP Texas —% —% 2.42% 1.83% —% 2.00%
SWEPCo —% —% 2.42% 1.83% —% 2.00%

Three Months Ended March 31, 2017:
  Maximum Minimum Maximum Minimum Average Average
  Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate
  for Funds for Funds for Funds for Funds for Funds for Funds
  Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to
  the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility
Company Money Pool Money PoolMoney Pool Money Pool Money Pool Money Pool
AEP Texas —% —% 1.27% 0.92% —% 1.03%
SWEPCo —% —% 1.27%.0.92% —% 1.03%


AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table:
  Maximum Minimum Maximum Minimum Average Average
  Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate
Three Months for Funds for Funds for Funds for Funds for Funds for Funds
Ended Borrowed Borrowed Loaned Loaned Borrowed Loaned
March 31, from AEP from AEPto AEP to AEP from AEP to AEP
2019 3.02% 2.73% 3.02% 2.73% 2.87% 2.86%
2018 2.42% 1.83% 2.42% 1.83% 2.00% 2.02%
  Maximum Minimum Maximum Minimum Average Average
  Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate
Three Months for Funds for Funds for Funds for Funds for Funds for Funds
Ended Borrowed Borrowed Loaned Loaned Borrowed Loaned
March 31, from AEP from AEPto AEP to AEP from AEP to AEP
2018 2.42% 1.83% 2.42% 1.83% 2.00% 2.02%
2017 1.27% 0.92% 1.27% 0.92% 1.03% 1.04%




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


Outstanding short-term debt was as follows:
    March 31, 2018 December 31, 2017
Company Type of Debt 
Outstanding
Amount
 
Interest
Rate (a)
 Outstanding
Amount		 Interest
Rate (a)
    (in millions)  
 (in millions)  
AEP Securitized Debt for Receivables (b) $750.0
 1.74% $718.0
 1.22%
AEP Commercial Paper 1,886.2
 2.41% 898.6
 1.85%
SWEPCo Notes Payable 22.6
 3.20% 22.0
 2.92%
  Total Short-term Debt $2,658.8
  
 $1,638.6
  
  March 31, 2019 December 31, 2018
Type of Debt 
Outstanding
Amount
 
Interest
Rate (a)
 Outstanding
Amount		 Interest
Rate (a)
  (dollars in millions)
Securitized Debt for Receivables (b) $750.0
 2.71% $750.0
 2.16%
Commercial Paper 1,108.0
 2.75% 1,160.0
 2.96%
Total Short-term Debt $1,858.0
  
 $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 Receivable – 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 includes a $125 million and a $625 million facility which expire in July 2020 and 2021, respectively. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries.  These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections.

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

Accounts receivable information for AEP Credit iswas as follows:
 Three Months Ended March 31,
 2019 2018
 (dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable2.71% 1.74%
Net Uncollectible Accounts Receivable Written-Off$6.4
 $4.2
 Three Months Ended March 31,
 2018 2017
 (dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable1.74% 1.00%
Net Uncollectible Accounts Receivable Written Off$4.2
 $5.9

  March 31, 2019 December 31, 2018
  (in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $941.4
 $972.5
Short-term – Securitized Debt of Receivables 750.0
 750.0
Delinquent Securitized Accounts Receivable 52.7
 50.3
Bad Debt Reserves Related to Securitization 29.1
 27.5
Unbilled Receivables Related to Securitization 230.3
 281.4

  March 31, 2018 December 31, 2017
  (in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $944.5
 $925.5
Short-term – Securitized Debt of Receivables 750.0
 718.0
Delinquent Securitized Accounts Receivable 55.1
 41.1
Bad Debt Reserves Related to Securitization 30.8
 28.7
Unbilled Receivables Related to Securitization 249.9
 303.2


AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due.



Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries, except AEP Texas and AEPTCo)


Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables.  APCo does not have regulatory authority to sell its West Virginia accounts receivable.  The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income.  The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder.



The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreements were:
Company March 31, 2019 December 31, 2018
  (in millions)
APCo $132.4
 $133.3
I&M 165.4
 152.9
OPCo 383.8
 395.2
PSO 103.2
 109.7
SWEPCo 129.1
 150.3

Company March 31, 2018 December 31, 2017
  (in millions)
APCo $139.2
 $136.2
I&M 147.8
 136.5
OPCo 386.2
 367.4
PSO 109.2
 115.1
SWEPCo 130.6
 138.2


The fees paid to AEP Credit for customer accounts receivable sold were:
  Three Months Ended March 31,
Company 2019 2018
  (in millions)
APCo $2.2
 $1.7
I&M 2.8
 2.1
OPCo 7.8
 5.6
PSO 2.1
 1.8
SWEPCo 2.6
 1.9

  Three Months Ended March 31,
Company 2018 2017
  (in millions)
APCo $1.7
 $1.4
I&M 2.1
 1.5
OPCo 5.6
 5.7
PSO 1.8
 1.5
SWEPCo 1.9
 1.6


The proceeds on the sale of receivables to AEP Credit were:
  Three Months Ended March 31,
Company 2019 2018
  (in millions)
APCo $374.4
 $400.2
I&M 478.6
 459.1
OPCo 636.8
 680.0
PSO 324.5
 332.6
SWEPCo 371.9
 397.6


  Three Months Ended March 31,
Company 2018 2017
  (in millions)
APCo $400.2
 $369.7
I&M 459.1
 418.2
OPCo 680.0
 632.3
PSO 332.6
 286.8
SWEPCo 397.6
 341.2



13. VARIABLE INTEREST ENTITIES

The disclosures in this note apply to AEP only.

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) and Trent Wind Farm LLC (Trent) (collectively “the LLCs”) were established for the purpose of repowering, owning and operating approximately 310.5 MW of wind-powered electric energy generation facilities in Texas. In January 2018, AEP admitted a non-affiliate as a member of the LLCs to own and repower Desert Sky and Trent, which is expected to be completed in 2018. The non-affiliate contributed full turbine sets to each project in exchange for a 20.1% interest in the LLCs. The non-affiliates’ contribution of $84 million was recorded as Net Property, Plant and Equipment on the balance sheets, which was the fair value as of the contribution date determined based on key input assumptions of the original cost of the full turbine sets and the discounted cash flow benefit associated with the production tax credits available from repowering Desert Sky and Trent based on their expected net capacity, capacity factor and the operational availability. AEP owns 79.9% of the LLCs. As a result, management has concluded that Desert Sky and Trent, collectively, are VIE’s and that AEP is the primary beneficiary based on its power to direct the activities that most significantly impact Desert Sky and Trent’s economic performance. Also in January 2018, Desert Sky and Trent entered into a forward PPA for the sale of power to AEPEP related to deliveries of electricity beginning January 1, 2021 for a 12 year period. Prior to the effective date of the PPA, Desert Sky and Trent will sell power at market rates into ERCOT. AEP and the non-affiliate will share tax attributes including production tax credits and cash distributions from the operation of the LLCs generally consistent with the ownership percentages. See the table below for the classification of Desert Sky and Trent’s assets and liabilities on the balance sheets:
American Electric Power Company, Inc.
Variable Interest Entities
March 31, 2018
  
 Desert Sky and Trent
 (in millions)
ASSETS 
Current Assets$41.1
Net Property, Plant and Equipment255.4
Other Noncurrent Assets0.7
Total Assets$297.2
  
LIABILITIES AND EQUITY 
Current Liabilities$41.4
Noncurrent Liabilities8.3
Equity247.5
Total Liabilities and Equity$297.2



AEP has a call right, which if exercised, would require the non-affiliate to sell its noncontrolling interest in the LLCs to AEP. The exercise period is for ninety days, beginning two years after the repowering completion. The non-affiliates’ interest in the LLCs is presented as redeemable noncontrolling interest on the balance sheets.  The non-affiliate holds redemption rights, which if exercised, would require AEP to purchase the non-affiliates’ noncontrolling interest in the LLCs.  The exercise price for both the call and redemption right are determined using a discounted cash flow model with agreed input assumptions as well as potential updates to certain assumptions reasonably expected based on the actual results of the LLCs.  As of March 31, 2018, AEP recorded $71 million of Redeemable Noncontrolling Interest in Mezzanine Equity on the balance sheets.


14. REVENUE FROM CONTRACTS WITH CUSTOMERS


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


Disaggregated Revenues from Contracts with Customers

The tabletables below representsrepresent AEP’s reportable segment revenues from contracts with customers, net of respective provisions for refund, by type of revenue:
  Three Months Ended March 31, 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 $982.4
 $586.1
 $—
 $—
 $—
 $—
 $1,568.5
Commercial Revenues 511.2
 310.9
 —
 —
 —
 —
 822.1
Industrial Revenues 532.1
 123.9
 —
 —
 —
 1.8
 657.8
Other Retail Revenues 43.3
 11.1
 —
 —
 —
 —
 54.4
Total Retail Revenues 2,069.0
 1,032.0
 —
 —
 —
 1.8
 3,102.8
               
Wholesale and Competitive Retail Revenues:              
Generation Revenues (a) 224.7
 —
 —
 108.8
 —
 (78.5) 255.0
Transmission Revenues (b) 73.5
 99.6
 255.1
 —
 —
 (219.4) 208.8
Marketing, Competitive Retail and Renewable Revenues —
 —
 —
 361.5
 —
 —
 361.5
Total Wholesale and Competitive Retail Revenues 298.2
 99.6
 255.1
 470.3
 —
 (297.9) 825.3
               
Other Revenues from Contracts with Customers (c) 39.5
 46.0
 3.1
 2.3
 23.3
 (36.1) 78.1
               
Total Revenues from Contracts with Customers 2,406.7
 1,177.6
 258.2
 472.6
 23.3
 (332.2) 4,006.2
               
Other Revenues:              
Alternative Revenues (c) (3.4) 5.0
 (1.8) —
 —
 —
 (0.2)
Other Revenues (c) —
 39.4
 —
 9.2
 2.2
 —
 50.8
Total Other Revenues (3.4) 44.4
 (1.8) 9.2
 2.2
 —
 50.6
               
Total Revenues $2,403.3
 $1,222.0
 $256.4
 $481.8
 $25.5
 $(332.2) $4,056.8

  Three Months Ended March 31, 2018
  Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other Reconciling Adjustments AEP Consolidated
  (in millions)
Retail Revenues:              
Residential Revenues $1,001.2
 $567.9
 $—
 $—
 $—
 $—
 $1,569.1
Commercial Revenues 515.8
 300.3
 —
 —
 —
 —
 816.1
Industrial Revenues 518.9
 113.2
 —
 —
 —
 —
 632.1
Other Retail Revenues 43.8
 9.5
 —
 —
 —
 —
 53.3
Total Retail Revenues 2,079.7
 990.9
 —
 —
 —
 —
 3,070.6
               
Wholesale and Competitive Retail Revenues:              
Generation Revenues 214.0
 —
 —
 145.1
 —
 —
 359.1
Generation Revenues – Affiliated 3.0
 —
 —
 27.1
 —
 (30.1) —
Transmission Revenues 57.9
 94.1
 56.8
 —
 —
 —
 208.8
Transmission Revenues – Affiliated 17.1
 —
 162.7
 —
 —
 (179.8) —
Marketing, Competitive Retail and Renewable Revenues —
 —
 —
 309.7
 —
 —
 309.7
Total Wholesale and Competitive Retail Revenues 292.0
 94.1
 219.5
 481.9
 —
 (209.9) 877.6
               
Other Revenues from Contracts with Customers 34.7
 49.0
 0.3
 1.7
 5.0
 —
 90.7
Other Revenues from Contracts with Customers - Affiliated 5.2
 0.7
 1.7
 0.5
 17.0
 (25.1) —
               
Total Revenues from Contracts with Customers 2,411.6
 1,134.7
 221.5
 484.1
 22.0
 (235.0) 4,038.9
               
Other Revenues:              
Alternative Revenues (9.1) 6.0
 (16.0) —
 —
 —
 (19.1)
Other Revenues 5.5
 —
 —
 21.0
 2.0
 —
 28.5
Other Revenues - Affiliated —
 21.7
 —
 —
 —
 (21.7) —
Total Other Revenues (3.6) 27.7
 (16.0) 21.0
 2.0
 (21.7) 9.4
               
Total Revenues $2,408.0
 $1,162.4
 $205.5
 $505.1
 $24.0
 $(256.7) $4,048.3

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $37 million. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $198 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues.



  Three Months Ended March 31, 2018
  Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other Reconciling Adjustments AEP Consolidated
  (in millions)
Retail Revenues:              
Residential Revenues $1,001.2
 $567.9
 $—
 $—
 $—
 $—
 $1,569.1
Commercial Revenues 508.0
 294.1
 —
 —
 —
 —
 802.1
Industrial Revenues 526.6
 118.5
 —
 —
 —
 —
 645.1
Other Retail Revenues 43.9
 10.4
 —
 —
 —
 —
 54.3
Total Retail Revenues (a) 2,079.7
 990.9
 —
 —
 —
 —
 3,070.6
               
Wholesale and Competitive Retail Revenues:              
Generation Revenues (b) 217.0
 —
 —
 172.2
 —
 (30.1) 359.1
Transmission Revenues (c) 75.0
 94.1
 219.5
 —
 —
 (179.8) 208.8
Marketing, Competitive Retail and Renewable Revenues —
 —
 —
 309.7
 —
 —
 309.7
Total Wholesale and Competitive Retail Revenues 292.0
 94.1
 219.5
 481.9
 —
 (209.9) 877.6
               
Other Revenues from Contracts with Customers (d) 39.9
 49.7
 2.0
 2.2
 22.0
 (25.1) 90.7
               
Total Revenues from Contracts with Customers 2,411.6
 1,134.7
 221.5
 484.1
 22.0
 (235.0) 4,038.9
               
Other Revenues:              
Alternative Revenues (d) (9.1) 6.0
 (16.0) —
 —
 —
 (19.1)
Other Revenues (d) 5.5
 21.7
 —
 21.0
 2.0
 (21.7) 28.5
Total Other Revenues (3.6) 27.7
 (16.0) 21.0
 2.0
 (21.7) 9.4
               
Total Revenues $2,408.0
 $1,162.4
 $205.5
 $505.1
 $24.0
 $(256.7) $4,048.3

(a)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 $27 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $162 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.



The tabletables below representsrepresent revenues from contracts with customers, net of respective provisions for refund, by type of revenue for the Registrant Subsidiaries:
  Three Months Ended March 31, 2019
  AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo
  (in millions)
Retail Revenues:              
Residential Revenues $120.9
 $—
 $372.5
 $218.4
 $471.6
 $140.0
 $140.1
Commercial Revenues 97.9
 —
 142.2
 121.3
 210.5
 80.8
 113.7
Industrial Revenues 33.0
 —
 147.5
 138.4
 89.7
 71.0
 81.2
Other Retail Revenues 7.3
 —
 19.6
 1.8
 3.4
 18.0
 2.2
Total Retail Revenues 259.1
 —
 681.8
 479.9
 775.2
 309.8
 337.2
               
Wholesale Revenues:              
Generation Revenues (a) —
 —
 67.5
 111.9
 —
 8.6
 57.2
Transmission Revenues (b) 85.8
 242.1
 25.7
 6.3
 13.9
 9.8
 24.2
Total Wholesale Revenues 85.8
 242.1
 93.2
 118.2
 13.9
 18.4
 81.4
               
Other Revenues from Contracts with Customers (c) 6.9
 3.1
 13.4
 21.0
 39.0
 5.8
 7.8
               
Total Revenues from Contracts with Customers 351.8
 245.2
 788.4
 619.1
 828.1
 334.0
 426.4
               
Other Revenues:              
Alternative Revenues (d) (0.9) (1.7) 4.4
 (4.8) 3.6
 (1.2) (5.3)
Other Revenues (d) 39.8
 —
 —
 —
 5.1
 —
 —
Total Other Revenues 38.9
 (1.7) 4.4
 (4.8) 8.7
 (1.2) (5.3)
               
Total Revenues $390.7
 $243.5
 $792.8
 $614.3
 $836.8
 $332.8
 $421.1

  Three Months Ended March 31, 2018
  AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCO
  (in millions)
Retail Revenues:              
Residential Revenues $131.6
 $—
 $414.0
 $189.0
 $436.8
 $141.1
 $140.1
Commercial Revenues 105.4
 —
 147.1
 110.8
 194.7
 88.0
 110.1
Industrial Revenues 25.8
 —
 146.8
 130.8
 87.7
 65.4
 75.4
Other Retail Revenues 6.2
 —
 19.6
 2.2
 3.2
 18.3
 2.1
Total Retail Revenues 269.0
 —
 727.5
 432.8
 722.4
 312.8
 327.7
               
Wholesale Revenues:              
Generation Revenues —
 —
 22.3
 111.1
 —
 5.9
 59.9
Generation Revenues – Affiliated —
 —
 40.5
 2.9
 —
 —
 —
Transmission Revenues 78.0
 48.3
 16.9
 6.8
 16.0
 10.6
 20.2
Transmission Revenues – Affiliated —
 160.1
 7.9
 —
 —
 —
 5.8
Total Wholesale Revenues 78.0
 208.4
 87.6
 120.8
 16.0
 16.5
 85.9
               
Other Revenues from Contracts with Customers 6.7
 0.1
 10.2
 7.7
 42.3
 3.1
 5.8
Other Revenues from Contracts with Customers - Affiliated 0.4
 2.0
 1.0
 15.0
 —
 1.1
 0.3
               
Total Revenues from Contracts with Customers 354.1
 210.5
 826.3
 576.3
 780.7
 333.5
 419.7
               
Other Revenues:              
Alternative Revenues (0.3) (17.0) (5.9) (5.0) 6.3
 3.3
 (0.3)
Other Revenues —
 —
 —
 5.5
 0.8
 —
 —
Other Revenues - Affiliated 17.8
 —
 —
 —
 3.1
 —
 —
Total Other Revenues 17.5
 (17.0) (5.9) 0.5
 10.2
 3.3
 (0.3)
               
Total Revenues $371.6
 $193.5
 $820.4
 $576.8
 $790.9
 $336.8
 $419.4

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $35 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $195 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $15 million primarily relating to the barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)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.
  Three Months Ended March 31, 2018
  AEP Texas AEPTCo (f) APCo I&M OPCo PSO SWEPCo
  (in millions)
Retail Revenues:              
Residential Revenues $131.6
 $—
 $414.0
 $189.0
 $436.8
 $141.1
 $140.1
Commercial Revenues 99.4
 —
 146.6
 109.6
 194.5
 84.3
 108.3
Industrial Revenues 30.9
 —
 147.3
 132.0
 87.9
 69.1
 77.2
Other Retail Revenues 7.1
 —
 19.6
 2.2
 3.2
 18.3
 2.1
Total Retail Revenues (a) 269.0
 —
 727.5
 432.8
 722.4
 312.8
 327.7
               
Wholesale Revenues:              
Generation Revenues (b) —
 —
 62.8
 114.0
 —
 5.9
 59.9
Transmission Revenues (c) 78.0
 185.0
 24.8
 6.8
 16.0
 10.6
 26.0
Total Wholesale Revenues 78.0
 185.0
 87.6
 120.8
 16.0
 16.5
 85.9
               
Other Revenues from Contracts with Customers (d) 7.1
 2.0
 11.2
 22.7
 42.3
 4.2
 6.1
               
Total Revenues from Contracts with Customers 354.1
 187.0
 826.3
 576.3
 780.7
 333.5
 419.7
               
Other Revenues:              
Alternative Revenues (e) (0.3) 4.7
 (5.9) (5.0) 6.3
 3.3
 (0.3)
Other Revenues (e) 17.8
 —
 —
 5.5
 3.9
 —
 —
Total Other Revenues 17.5
 4.7
 (5.9) 0.5
 10.2
 3.3
 (0.3)
               
Total Revenues $371.6
 $191.7
 $820.4
 $576.8
 $790.9
 $336.8
 $419.4


(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 $40 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $160 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $15 million primarily relating to the barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(e)Amounts include affiliated and nonaffiliated revenues.
(f)The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. See the “Revisions to Previously Issued Financial Statements” section of Note 1 for additional information.
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 Reliability Pricing Model (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 third incremental auction, at which point the performance obligation becomes fixed.

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

Wholesale Revenues - Generation Affiliated

APCo has a performance obligation to supply wholesale electricity to KGPCo through a purchased power agreement. The FERC regulates the cost-based wholesale power transactions between APCo and KGPCo. The purchased power agreement includes a 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 TRA. 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 - Affiliated 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.


Wholesale Revenues - Transmission Affiliated

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

Marketing, Competitive Retail and Renewable Revenues

AEP’s subsidiaries within the Generation & Marketing segment have performance 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 March 31, 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.
Company (a) Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total
  (in millions)
AEP $748.7
 $256.1
 $164.1
 $348.7
 $1,517.6
AEP Texas 233.4
 —
 —
 —
 233.4
AEPTCo 536.2
 —
 —
 —
 536.2
APCo 92.0
 31.8
 22.7
 11.4
 157.9
I&M 20.6
 8.7
 8.7
 4.3
 42.3
OPCo 42.1
 —
 —
 —
 42.1
PSO 11.9
 —
 —
 —
 11.9
SWEPCo 24.9
 —
 —
 —
 24.9

(a)Amounts The Registrants Subsidiaries amounts shown in the table below include affiliated and nonaffiliated revenues except for AEP.revenues.
Company 2019 2020-2021 2022-2023 After 2023 Total
  (in millions)
AEP $732.3
 $199.1
 $162.7
 $285.7
 $1,379.8
AEP Texas 278.2
 —
 —
 —
 278.2
AEPTCo 672.5
 —
 —
 —
 672.5
APCo 108.9
 31.1
 23.2
 11.6
 174.8
I&M 21.5
 8.8
 8.8
 4.4
 43.5
OPCo 47.4
 —
 —
 —
 47.4
PSO 13.6
 —
 —
 —
 13.6
SWEPCo 28.7
 —
 —
 —
 28.7




Contract Assets and Liabilities


Contract assets are recognized when the Registrants have a right to consideration that is conditional upon the occurrence of an event other than the passage of time, such as future performance under a contract. The Registrants dodid not have any material contract assets as of March 31, 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 dodid not have any material contract liabilities as of March 31, 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 arewere not material as of March 31, 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 March 31, 2019 December 31, 2018
  (in millions)
AEPTCo $65.9
 $58.6
APCo 46.3
 52.5
I&M 24.0
 35.3
OPCo 31.2
 46.1
PSO 13.3
 12.4
SWEPCo 10.6
 16.3




Company March 31, 2018 January 1, 2018
  (in millions)
AEP Texas $—
 $—
AEPTCo 60.6
 47.1
APCo 36.3
 35.6
I&M 14.8
 15.1
OPCo 27.1
 26.1
PSO 6.2
 6.1
SWEPCo 11.4
 11.0


Contract Costs

Contract costs to obtain or fulfill a contract for AEP subsidiaries within the Generation & Marketing segment are accounted for under the guidance for “Other Assets and Deferred Costs” and presented as a single asset and neither bifurcated nor reclassified between current and noncurrent assets on the Registrants’ balance sheets. Contract costs to acquire a contract are amortized in a manner consistent with the transfer of goods or services to the customer in Other Operation on the Registrants’ income statements. The Registrants do not have material contract costs as of March 31, 2018.


CONTROLS AND PROCEDURES


During the first quarter of 20182019, management, including the principal executive officer and principal financial officer of each of the Registrants, evaluated the Registrants’ disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. As of March 31, 2018,2019, 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 no change in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the first quarter of 20182019 that materially affected, or is 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 Note 5 - Commitments, Guarantees and Contingenciesincorporated 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 March 31, 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. In addition, the FERC trial staff filed comments recommending a base ROE of 8.41% and one-time refund of $175 million. Also in April 2018, another intervenor recommended the refund be calculated in accordance with the approved base ROE. Management believes its financial statements adequately address the impact of the settlement agreement.  If the FERC orders revenue reductions in excess of the terms of the settlement agreement, it could reduce future net income and cash flows and impact financial condition.  A decision from the FERC is pending.

In June 2017, a similar complaint was filed with the FERC claiming that the base ROE used by certain AEP subsidiaries that operate in SPP, including the West Transcos, in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36%, effective upon the date of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.

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



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

AEP and several nonaffiliated utility companies own OVEC. The Inter-Company Power Agreement (ICPA) defines the rights and obligations and sets the power participation ratio of the parties to it.  Under the ICPA, parties are entitled to receive and are obligated to pay for all OVEC capacity (approximately 2,400 MWs) in proportion to their respective power participation ratios. The aggregate power participation ratio of APCo, I&M and OPCo is 43.47%. If a party fails to make payments owed by it under the ICPA, OVEC may not have sufficient funds to honor its payment obligations, including its ongoing operating expenses as well as its indebtedness. OVEC has outstanding indebtedness of approximately $1.4 billion, of which APCo, I&M, and OPCo are collectively responsible for $622 million through the ICPA. Although they are not an obligor or guarantor, APCo, I&M, and OPCo are responsible for their respective ratio of OVEC’s outstanding debt through the ICPA.

A nonaffiliated party, whose aggregate power participation ratio is 4.85% under the ICPA, has filed a petition seeking protection under bankruptcy law.  Bankruptcy filings typically trigger review of the petitioner’s contractual obligations, including, in this instance, the ICPA.  Because the ICPA is subject to FERC 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 March 31, 2018.2019.


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:
AEP‡   File No. 1-3525
*4.1Purchase Contract and Pledge Agreement, dated as of March 19, 2019, between the Company and The Bank of New York Mellon Trust Company, N.A., as purchase contract agent, collateral agent, custodial agent and securities intermediary.
Form 8-K, Ex 4.1 dated March 14, 2019
*4.2Junior Subordinated Indenture, dated March  1, 2008, between the Company and The Bank of New York Mellon Trust Company, N.A., as Trustee for the Junior Subordinated Debentures.
Registration Statement No. 333-156387, Ex 4(c)(d)
*4.3Supplemental Indenture No. 1, dated March 19, 2019, from the Company to The Bank of New York Mellon Trust Company, N.A., as trustee.
Form 8-K, Ex 4.3 dated March 14, 2019
APCo‡   File No. 1-3457
*4.4Company Order and Officer’s Certificate, between the Company and The Bank of New York Mellon Trust Company, N.A., as trustee, dated March 6, 2019, establishing the terms of the 4.50% Senior Notes, Series Y, due 2049.
Form 8-K, Ex 4(a) dated March 6, 2019

The exhibits designated with an (X) in the table below are being filed on behalf of the Registrants.Registrants herewith.
Exhibit Description AEP 
AEP
Texas
 AEPTCo APCo I&M OPCo PSO SWEPCo
10(a)Performance Share Award Agreement furnished to participants of the AEP System AEP Long-Term Incentive Plan, as amended
X
10(b)Restricted Stock Unit Agreement furnished to participants of the AEP System AEP-Long Term Incentive Plan, as Amended and Restated
X
12Computation of Consolidated Ratio of Earnings to Fixed Charges
X
X
X
X
X
X
X
X
31(a) Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 
X
 
X
 
X
 
X
 
X
 
X
 
X
 
X
31(b) Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 
X
 
X
 
X
 
X
 
X
 
X
 
X
 
X
32(a) Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code 
X
 
X
 
X
 
X
 
X
 
X
 
X
 
X
32(b) Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code 
X
 
X
 
X
 
X
 
X
 
X
 
X
 
X
95 Mine Safety Disclosures               
X
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SIGNATURE




Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.  The signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.




AMERICAN ELECTRIC POWER COMPANY, INC.






By: /s/ Joseph M. Buonaiuto
Joseph M. Buonaiuto
Controller and Chief Accounting Officer






AEP TEXAS INC.
AEP TRANSMISSION COMPANY, LLC
APPALACHIAN POWER COMPANY
INDIANA MICHIGAN POWER COMPANY
OHIO POWER COMPANY
PUBLIC SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN ELECTRIC POWER COMPANY






By: /s/ Joseph M. Buonaiuto
Joseph M. Buonaiuto
Controller and Chief Accounting Officer






Date:  April 26, 201825, 2019




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