Edgar Filing: AMERICAN ELECTRIC POWER CO INC

Document

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, 2019

[ ] 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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit such files). 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 x Accelerated filer ¨ Non-accelerated filer ¨

Smaller reporting company ¨			Emerging growth company ¨



Indicate by check mark whether AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, non-accelerated filers, smaller reporting companies, or emerging growth companies. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer x

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 25, 2019

American Electric Power Company, Inc.	493,435,530
	($6.50 par value)
AEP Texas Inc.	100
	($0.01 par value)
AEP Transmission Company, LLC (a)	NA

Appalachian Power Company	13,499,500
	(no par value)
Indiana Michigan Power Company	1,400,000
	(no par value)
Ohio Power Company	27,952,473
	(no par value)
Public Service Company of Oklahoma	9,013,000
	($15 par value)
Southwestern Electric Power Company	7,536,640
	($18 par value)


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


NA	Not applicable.



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF QUARTERLY REPORTS ON FORM 10-Q
March 31, 2019

		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	34

AEP Texas Inc. and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	41
	Condensed Consolidated Financial Statements	44

AEP Transmission Company, LLC and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	51
	Condensed Consolidated Financial Statements	52

Appalachian Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	58
	Condensed Consolidated Financial Statements	60

Indiana Michigan Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	67
	Condensed Consolidated Financial Statements	69

Ohio Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	76
	Condensed Consolidated Financial Statements	79

Public Service Company of Oklahoma:
	Management’s Narrative Discussion and Analysis of Results of Operations	86
	Condensed Financial Statements	88

Southwestern Electric Power Company Consolidated:
	Management’s Narrative Discussion and Analysis of Results of Operations	95
	Condensed Consolidated Financial Statements	97

Index of Condensed Notes to Condensed Financial Statements of Registrants		103

Controls and Procedures		183



Part II. OTHER INFORMATION

	Item 1.	Legal Proceedings	184
	Item 1A.	Risk Factors	184
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	184
	Item 3.	Defaults Upon Senior Securities	184
	Item 4.	Mine Safety Disclosures	184
	Item 5.	Other Information	184
	Item 6.	Exhibits	185

SIGNATURE			186


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 VIE 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 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 VIE formed for the purpose of issuing and servicing securitization bonds related to the under-recovered ENEC deferral balance.
APSC		Arkansas Public Service Commission.
ARAM		Average Rate Assumption Method, an IRS approved method used to calculate the reversal of Excess ADIT for rate-making purposes.
ARO		Asset Retirement Obligations.
ASC		Accounting Standard Codification.
ASU		Accounting Standards Update.
CAA		Clean Air Act.
CLECO		Central Louisiana Electric Company, a nonaffiliated utility company.
CO₂		Carbon dioxide and other greenhouse gases.
Conesville Plant		A generation plant consisting of three coal-fired generating units totaling 1,695 MW located in Conesville, Ohio. The plant is jointly-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.
CSAPR		Cross-State Air Pollution Rule.
CWA		Clean Water Act.
CWIP		Construction Work in Progress.
DCC Fuel		DCC Fuel VII, DCC Fuel VIII, DCC Fuel IX, DCC Fuel X, DCC Fuel XI and DCC Fuel XII, consolidated VIEs formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.



Term		Meaning

DHLC		Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.
DIR		Distribution Investment Rider.
EIS		Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated VIE 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 Units		AEP’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.
ETT		Electric Transmission Texas, LLC, an equity interest joint venture between AEP Transmission Holdco and Berkshire Hathaway Energy Company formed to own and operate electric transmission facilities in ERCOT.
Excess ADIT		Excess accumulated deferred income taxes.
FASB		Financial Accounting Standards Board.
Federal EPA		United States Environmental Protection Agency.
FERC		Federal Energy Regulatory Commission.
FGD		Flue Gas Desulfurization or scrubbers.
FIP		Federal 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.
KWh		Kilowatt-hour.
LPSC		Louisiana Public Service Commission.
MATS		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		Megawatt-hour.
NAAQS		National 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.
NO_x		Nitrogen oxide.
NPDES		National Pollutant Discharge Elimination System.
NSR		New Source Review.
OATT		Open Access Transmission Tariff.



Term		Meaning

OCC		Corporation Commission of the State of Oklahoma.
Ohio Phase-in-Recovery Funding		Ohio Phase-in-Recovery Funding LLC, a wholly-owned subsidiary of OPCo and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to phase-in recovery property.
Oklaunion Power Station		A single unit coal-fired generation plant totaling 650 MW located in Vernon, Texas. The plant is jointly-owned by AEP Texas, PSO and certain nonaffiliated entities.
OPCo		Ohio Power Company, an AEP electric utility subsidiary.
OPEB		Other Postretirement Benefits.
OSS		Off-system Sales.
OTC		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.
Racine		A generation plant consisting of two hydroelectric generating units totaling 47.5 MWs located in Racine, Ohio and owned by AGR.
Registrant Subsidiaries		AEP subsidiaries which are SEC registrants: AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
Registrants		SEC registrants: AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
Risk Management Contracts		Trading and non-trading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant		A generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana. AEGCo and I&M jointly-own Unit 1. In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2.
ROE		Return on Equity.
RPM		Reliability Pricing Model.
RSR		Retail Stability Rider.
RTO		Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine		Sabine Mining Company, a lignite mining company that is a consolidated VIE for AEP and SWEPCo.
SCR		Selective Catalytic Reduction, NO_xreduction technology at Rockport Plant.
SEC		U.S. Securities and Exchange Commission.
SEET		Significantly Excessive Earnings Test.
SIP		State 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, which are 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



Term		Meaning

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.
Transition Funding		AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation.
Transource Energy		Transource Energy, LLC, a consolidated VIE formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates.
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 that was cancelled in July 2018. The estimated $4.5 billion project included the acquisition of a wind generation facility, totaling approximately 2,000 MWs 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.

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 2018 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:



•	Changes in economic conditions, electric market demand and demographic patterns in AEP service territories.
•	Inflationary or deflationary interest rate trends.
•	Volatility in the financial markets, particularly developments affecting the availability or cost of capital to finance new capital projects and refinance existing debt.
•	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.
•	Electric load and customer growth.
•	Weather conditions, including storms and drought conditions, and the ability to recover significant storm restoration costs.
•	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 SNF.
•	Availability of necessary generation capacity, the performance of generation plants and the availability of fuel.
•	The ability to recover fuel and other energy costs through regulated or competitive electric rates.
•	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.
•	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 PM and other substances that could impact the continued operation, cost recovery and/or profitability of generation plants and related assets.
•	Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel.
•	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.
•	Resolution of litigation.
•	The ability to constrain operation and maintenance costs.
•	Prices and demand for power generated and sold at wholesale.
•	Changes in technology, particularly with respect to energy storage and new, developing, alternative or distributed sources of generation.
•	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.
•	Volatility and changes in markets for capacity and electricity, coal and other energy-related commodities, particularly changes in the price of natural gas.
•	Changes in utility regulation and the allocation of costs within RTOs including ERCOT, PJM and SPP.
•	Changes in the creditworthiness of the counterparties with contractual arrangements, including participants in the energy trading market.
•	Actions of rating agencies, including changes in the ratings of debt.
•	The impact of volatility in the capital markets on the value of the investments held by the pension, 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.



•	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 2018 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.

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 2019 decreased by 0.3% from the first quarter of 2018. AEP’s first quarter 2019 industrial sales volumes decreased 0.4% compared to the first quarter of 2018. The decline in industrial sales was primarily in the east vertically integrated operating companies. Weather-normalized residential sales increased 0.9% while weather-normalized commercial sales decreased 1.7% in the first quarter of 2019, respectively, from the first quarter of 2018.

Regulatory Matters

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

•

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.

•

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.


•	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.

•

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.

•

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.

•

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 Ohio 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 current energy efficiency and renewable mandates for Ohio electric utilities in order to pay for the zero/reduced emission credits. Management is analyzing the impact of this new legislation but it could be significantly amended before passage and cannot, at this time, estimate the impact results on operations, cash flows or financial condition.

Utility Rates and Rate Proceedings

The Registrants file rate cases with their regulatory commissions seeking increases or decreases to their electric service rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Registrants’ current and future results of operations, cash flows and financial position.

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

Completed Base Rate Case Proceedings



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

Pending Base Rate Case Proceedings

Commission Staff/

Filing

Requested Revenue

Requested

Intervenor Range of

Company

Jurisdiction

Date

Requirement Increase

ROE

Recommended ROE

(in millions)

SWEPCo

Arkansas

February 2019

75.0

10.5%

(a)

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

Renewable Generation

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

Contracted Renewable Generation Facilities

AEP continues to develop its renewable portfolio within the Generation & Marketing segment. Activities include working directly with wholesale and large retail customers to provide tailored solutions based upon market knowledge, technology innovations and deal structuring which may include distributed solar, wind, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other forms of cost reducing energy technologies. The Generation & Marketing segment also develops and/or acquires large scale renewable generation projects that are backed with long-term contracts with creditworthy counterparties. As of March 31, 2019, subsidiaries within AEP’s Generation & Marketing segment had approximately 438 MWs of contracted renewable generation projects in-service. In addition, as of March 31, 2019, these subsidiaries had approximately 56 MWs of renewable generation projects under construction with total estimated capital costs of $78 million related to these projects.

In December 2018, AEP signed a Purchase and Sale Agreement with a nonaffiliate to acquire a 75% 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 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 estimated $110 million as of the acquisition date associated with certain of the 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 6 for additional information.

Regulated Renewable Generation Facilities

In September 2018, OPCo, consistent with its commitment in the previously approved PPA application, submitted a filing with the PUCO demonstrating a need for up to 900 MWs of economically beneficial renewable resources in Ohio. This filing was followed by a separate filing for two solar Renewable Energy Purchase Agreements totaling 400 MWs. In January 2019, PUCO staff recommended that the PUCO reject OPCo’s request. If approved, the solar generation facilities are expected to be operational by the end of 2021.

In January 2019, PSO and SWEPCo issued requests for proposals to acquire up to 1,000 MWs and 1,200 MWs of wind generation, respectively. The wind generation projects would be subject to regulatory approval and placed in-service by the end of 2021.

Racine

A project to reconstruct a defective dam structure at Racine began in the first quarter of 2017. Due to a significant increase in estimated costs to complete the reconstruction project, AEP recorded impairments in 2017 and 2018. See Note 7 - Dispositions and Impairments in the 2018 Annual Report for additional information.

Reconstruction activities at Racine are estimated to be completed in the fourth quarter of 2019. AEP expects to incur additional capital expenditures to complete the reconstruction project, at which point the fair value of Racine, as fully operational, is expected to approximate the amount of those remaining estimated capital expenditures. Future revisions in cost estimates could result in additional losses which could reduce future net income and cash flows and impact financial condition.

Dolet Hills Lignite Company Operations

In November 2018, SWEPCo and CLECO announced that the Dolet Hills Power Station will change to a seasonal operational strategy. DHLC’s mining operation will continue year-round but will reduce its lignite output. SWEPCo’s share of the net investment in the Dolet Hills Power Station is $132 million and the maximum exposure of SWEPCo’s total investment in DHLC is $170 million. Management will continue to monitor the economic viability of the Dolet Hills Power Station and DHLC.

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

AEGCo and I&M sought and were granted dismissal by the U.S. District Court for the Southern District of Ohio of certain of the plaintiffs’ claims, including claims for compensatory damages, breach of contract, breach of the implied covenant of good faith and fair dealing and indemnification of costs. Plaintiffs voluntarily dismissed the surviving claims that AEGCo and I&M failed to exercise prudent utility practices with prejudice, and the court issued a final judgment. The plaintiffs subsequently filed an appeal in the U.S. Court of Appeals for the Sixth Circuit.

In 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion and judgment affirming the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims, reversing the district court’s dismissal of the breach of contract claims and remanding the case for further proceedings.

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. The 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 incurs additional operational costs to comply with environmental control requirements. Additional investments and operational changes will be made in response to existing and anticipated requirements to reduce emissions from fossil 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 other parties challenged some of the Federal EPA requirements in court. Management is 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, 2019, the AEP System had generating capacity of approximately 25,400 MWs, of which approximately 13,200 MWs were coal-fired. Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on the fossil generating facilities. Based upon management estimates, AEP’s investment to meet these existing and proposed requirements ranges from approximately $650 million to $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) potential state rules that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) 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 (h) other factors. In addition, management continues to evaluate the economic feasibility of environmental investments on regulated and competitive plants.

The table below represents the net book value before cost of removal, including related materials and supplies inventory, of plants or units of plants previously retired that have a remaining net book value as of March 31, 2019.



		Generating	Amounts Pending
Company	Plant Name and Unit	Capacity	Regulatory Approval
		(in MWs)	(in millions)
APCo	Kanawha River Plant	400	$	43.8
APCo	Clinch River Plant, Unit 3	235	31.8
APCo (a)	Clinch River Plant, Units 1 and 2	470	26.7
APCo	Sporn Plant, Units 1 and 3	300	15.6
APCo	Glen Lyn Plant	335	13.6
SWEPCo	Welsh Plant, Unit 2	528	50.6
Total		2,268	$	182.1


(a)	APCo obtained permits following the Virginia SCC’s and WVPSC’s approval to convert 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, Units 1 and 2 began operations as natural gas units in 2016.

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

Proposed Modification of the New Source Review Litigation Consent Decree

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

In 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.

In 2018, AEP filed a supplemental motion and a detailed statement of the specific relief requested to address the changed circumstances at Rockport Plant, Unit 2. In September 2018, the district court granted AEP’s unopposed motion to stay further proceedings on the pending motion to modify the 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” section 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 NAAQS and the development of SIPs to achieve any more stringent standards, (b) implementation of the regional haze program by the states and the Federal EPA, (c) regulation of hazardous air pollutant emissions under MATS, (d) implementation and review of CSAPR and (e) the Federal EPA’s regulation of greenhouse gas emissions from fossil generating units under Section 111 of the CAA. Notable developments in significant CAA regulatory requirements affecting AEP’s operations are discussed in the following sections.

National Ambient Air Quality Standards

The Federal EPA issued new, more stringent NAAQS for PM in 2012 and ozone in 2015. The existing standards for NO₂ and SO₂were retained after review by the Federal EPA in 2018 and 2019, respectively. Implementation of these standards is underway.

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

The Federal EPA finalized non-attainment designations for the 2015 ozone standard in 2018. The Federal EPA has confirmed that for states included in the CSAPR program, there are no additional interstate transport obligations, as all areas of the 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. In 2018, the Federal EPA proposed final requirements for implementing the 2015 ozone standard, which have also been challenged in the U.S. Court of Appeals for the District of Columbia Circuit. Management cannot currently predict the nature, stringency or timing of additional requirements for AEP’s facilities based on the outcome of these activities.

Regional Haze

The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA’s requirement that certain facilities install best available retrofit technology (BART) would address regional haze in federal parks and other protected areas. BART requirements apply to power plants. CAVR will be implemented through SIPs or FIPs. In 2017, the Federal EPA revised the rules governing submission of SIPs to implement the visibility programs, including a provision that postpones the due date for the next comprehensive SIP revisions until 2021. Petitions for review of the final rule revisions have been filed in the U.S. Court of Appeals for the District of Columbia Circuit.

In 2012, the Federal EPA proposed disapproval of a portion of the regional haze SIP in Arkansas and finalized a FIP in 2016. In 2017, Arkansas issued a proposed SIP revision to allow sources to participate in the CSAPR ozone season program in lieu of the source-specific NO_x BART requirements in the FIP, and in 2018, the Federal EPA approved the revision. Arkansas finalized a separate action in 2017 to revise the SO₂ BART determinations. In 2018, the 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 also disapproved portions of the Texas regional haze SIP. In 2017, the Federal EPA finalized a FIP that allows participation in the CSAPR ozone season program to satisfy the NO_xregional haze obligations for electric generating units in Texas. Additionally, the Federal EPA finalized an intrastate SO₂ emissions trading program based on CSAPR allowance allocations. A challenge to the FIP was filed in the U.S. Court of Appeals for the Fifth Circuit by various intervenors and the case is pending the Federal EPA’s reconsideration of the final rule. In August 2018, the Federal EPA proposed to affirm its 2017 FIP approval. Management supports the intrastate trading program contained in the FIP as a compliance alternative to source-specific controls.

Cross-State Air Pollution Rule

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

Petitions to review the CSAPR were filed in the U.S. Court of Appeals for the District of Columbia Circuit. In 2015, the court found that the Federal EPA over-controlled the SO₂ and/or NO_x budgets of 14 states. The court remanded the rule to the Federal EPA for revision consistent with the court’s opinion while CSAPR remained in place.

In 2016, the Federal EPA issued a final rule to address the remand and to incorporate additional changes necessary to address the 2008 ozone standard. The final rule significantly reduced ozone season budgets in many states and discounted the value of banked CSAPR ozone season allowances beginning with the 2017 ozone season. The rule has been challenged in the courts and petitions for administrative reconsideration have been filed. Management has complied with the more stringent ozone season budgets while these petitions were pending.

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

In 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants. The rule established unit-specific emission rates for units burning coal on a 30-day rolling average basis for mercury, PM (as a surrogate for particles of non-mercury metals) and hydrogen chloride (as a surrogate for acid gases). In addition, the rule proposed work practice standards for controlling emissions of organic HAPs and dioxin/furans, 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 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied all of the petitions for review of the 2012 final rule. Various intervenors filed petitions for further review in the U.S. Supreme Court.

In 2015, the U.S. Supreme Court reversed the decision of the U.S. Court of Appeals for the District of Columbia Circuit. The court remanded the MATS rule to the Federal EPA to consider costs in determining whether to regulate emissions of HAPs from power plants. In 2016, the Federal EPA issued a supplemental finding concluding that, after considering the costs of compliance, it was appropriate and necessary to regulate HAP emissions from coal and oil-fired units. Petitions for review of the Federal EPA’s determination were filed in the U.S. Court of Appeals for the District of Columbia Circuit. In 2018, the Federal EPA released a revised finding that the costs of reducing HAP emissions to the 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 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 comment period on this proposal ends in April 2019.

Climate Change, CO₂ Regulation and Energy Policy

In 2015, the Federal EPA published the final CO₂emissions standards for new, modified and reconstructed fossil generating units, and final guidelines for the development of state plans to regulate CO₂ emissions from existing sources, known as the Clean Power Plan (CPP).

The final rules were challenged in the courts. In 2016, the U.S. Supreme Court issued a stay on the final CPP, including all of the deadlines for submission of initial or final state plans until a final decision is issued by the U.S. Court of Appeals for the District of Columbia Circuit and the U.S. Supreme Court considers any petition for review. In 2017, the President issued an Executive Order directing the Federal EPA to reconsider the CPP and the associated standards for new sources. The Federal EPA filed a motion to hold the challenges to the CPP in abeyance, and the cases are still pending.

In 2018, the Federal EPA proposed the Affordable Clean Energy (ACE) rule to replace the CPP with new emission guidelines for regulating CO₂from 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 revising the standards for new sources and determined that partial carbon capture and storage is not the best system of emission reduction because it is not available throughout the U.S. and is not cost-effective. Management actively monitors these rulemaking activities.

AEP has taken action to reduce and offset CO₂ emissions from its generating fleet and expects CO₂ emissions from its operations to continue to decline due to the retirement of some of its coal-fired generation units, and actions taken to diversify the generation fleet and increase energy efficiency where there is regulatory support for such activities. The majority of the states where AEP has generating facilities passed legislation establishing renewable energy,

alternative energy and/or energy efficiency requirements that can assist in reducing carbon emissions. Management is taking steps to comply with these requirements, including increasing wind and solar installations, power purchases and broadening AEP System’s portfolio of energy efficiency programs.

In 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, grid reliability and resiliency, regulations and 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 estimated CO₂emissions in 2018 were approximately 69 million metric tons, a 59% reduction from AEP’s 2000 CO₂ 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, which could possibly lead to impairment of assets.

Coal Combustion Residual (CCR) Rule

In 2015, the Federal EPA published a final rule to regulate the disposal and beneficial re-use of CCR, including fly ash and bottom ash created from coal-fired generating units and FGD gypsum generated at some coal-fired plants. The rule applies to active CCR landfills and surface impoundments at operating electric utility or independent generation 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-year implementation period. In 2018, some of AEP’s facilities were required to begin monitoring programs to determine if unacceptable groundwater impacts will trigger future corrective measures. Based on additional groundwater data, further studies to design and assess appropriate corrective measures will be undertaken at four facilities in accordance with the rule.

The final 2015 rule was challenged in the courts. In 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued its decision vacating and remanding certain provisions of the 2015 rule. Remaining issues were dismissed. 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 motion for partial stay or vacatur of the July 2018 rule. On the same day, the Federal EPA filed a motion for partial remand of the July 2018 rule. The court granted the Federal EPA’s motion, and further rulemaking to address the court’s decisions is expected to be completed near the end of 2019.

Other utilities and industrial sources have been engaged in litigation with environmental advocacy groups who claim that releases of contaminants from wells, CCR units, pipelines and other facilities to groundwaters that have a hydrologic connection to a surface water body represent an “unpermitted discharge” under the CWA. Two cases were accepted by the U.S. Supreme Court for further review of the scope of CWA jurisdiction. The Federal EPA has opened a rulemaking docket to solicit information to determine whether it should provide additional clarification of the scope of CWA permitting requirements for discharges to groundwater, and has signed a guidance document that determines that discharges to groundwater are 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 AEP’s facilities.

Because AEP currently uses surface impoundments and landfills to manage CCR materials at generating facilities, significant costs will be incurred to upgrade or close and replace these existing facilities and conduct any required remedial actions. Closure and post-closure costs have been included in ARO in accordance with the requirements in the final rule. This estimate does not include costs of groundwater remediation, if required. Management will continue to evaluate the rule’s impact on operations.

Clean Water Act 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 impinged or entrained in the cooling water. The rule was upheld on review by the U.S. Court of Appeals for the Second Circuit. Compliance timeframes are established by the permit agency through each facility’s NPDES permit as those permits are renewed and 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 their intake structures.

In 2015, the Federal EPA issued a final rule revising effluent limitation guidelines for generating facilities. The rule established limits on FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater to be imposed as soon as possible after November 2018 and no later than December 2023. These requirements would be implemented through each facility’s wastewater discharge permit. The rule was challenged in the U.S. Court of Appeals for the Fifth Circuit. In 2017, the Federal EPA announced its intent to reconsider and potentially revise the standards for FGD wastewater and bottom ash transport water. The Federal EPA postponed the compliance deadlines for those wastewater categories to be no earlier than 2020, to allow for reconsideration. A revised rule could be proposed later in 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 is assessing technology additions and retrofits to comply with the rule and the impacts of the Federal EPA’s recent actions on facilities’ wastewater discharge permitting.

In 2015, the Federal EPA and the U.S. Army Corps of Engineers jointly issued a final rule to clarify the scope of the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases. The final rule was challenged in several courts that have reached different conclusions about whether the 2015 rule should be implemented. In December 2018, the Federal EPA and the U.S. Army Corps of Engineers released a proposed rule revising the definition, which would replace the definition in the 2015 rule and could significantly alter the scope of certain CWA programs. The comment period for this proposal ends in 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, 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,
	2019			2018
	(in millions)
Vertically Integrated Utilities	$	302.4		$	231.2
Transmission and Distribution Utilities	156.5			125.4
AEP Transmission Holdco	124.2			104.0
Generation & Marketing	40.1			18.2
Corporate and Other	(50.4		)	(24.4		)
Earnings Attributable to AEP Common Shareholders	$	572.8		$	454.4

AEP CONSOLIDATED

First Quarter of 2019 Compared to First Quarter of 2018

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


•	An increase in transmission investment primarily at AEP Transmission Holdco, which resulted in higher revenues and income.


•	Favorable rate proceedings in AEP’s various jurisdictions.


•	A 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 on the following pages.

VERTICALLY INTEGRATED UTILITIES



	Three Months Ended March 31,
Vertically Integrated Utilities	2019			2018
	(in millions)
Revenues	$	2,403.3		$	2,408.0
Fuel and Purchased Electricity	856.4			857.8
Gross Margin	1,546.9			1,550.2
Other Operation and Maintenance	690.1			740.0
Depreciation and Amortization	356.3			313.3
Taxes Other Than Income Taxes	116.0			109.9
Operating Income	384.5			387.0
Other Income	1.3			5.4
Allowance for Equity Funds Used During Construction	10.7			7.4
Non-Service Cost Components of Net Periodic Benefit Cost	17.0			18.1
Interest Expense	(139.0		)	(137.9		)
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	0.7			0.5
Net Income	303.6			232.8
Net Income Attributable to Noncontrolling Interests	1.2			1.6
Earnings Attributable to AEP Common Shareholders	$	302.4		$	231.2

Summary of KWh Energy Sales for Vertically Integrated Utilities



	Three Months Ended March 31,
	2019	2018
	(in millions of KWhs)
Retail:
Residential	9,216	9,572
Commercial	5,633	5,787
Industrial	8,545	8,578
Miscellaneous	546	553
Total Retail (a)	23,940	24,490

Wholesale (b)	5,804	5,738

Total KWhs	29,744	30,228


(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,
	2019	2018
	(in degree days)
Eastern Region
Actual – Heating (a)	1,571	1,637
Normal – Heating (b)	1,595	1,602

Actual – Cooling (c)	1	6
Normal – Cooling (b)	5	5

Western Region
Actual – Heating (a)	941	881
Normal – Heating (b)	866	875

Actual – Cooling (c)	11	36
Normal – Cooling (b)	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 2019 Compared to First Quarter of 2018



Reconciliation 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 2018	$	231.2

Changes in Gross Margin:
Retail Margins	(2.5		)
Off-system Sales	(6.6		)
Transmission Revenues	9.4
Other Revenues	(3.6		)
Total Change in Gross Margin	(3.3		)

Changes in Expenses and Other:
Other Operation and Maintenance	49.9
Depreciation and Amortization	(43.0		)
Taxes Other Than Income Taxes	(6.1		)
Other Income	(4.1		)
Allowance for Equity Funds Used During Construction	3.3
Non-Service Cost Components of Net Periodic Pension Cost	(1.1		)
Interest Expense	(1.1		)
Total Change in Expenses and Other	(2.2		)

Income Tax Expense (Benefit)	76.1
Equity Earnings	0.2
Net Income Attributable to Noncontrolling Interests	0.4

First Quarter of 2019	$	302.4

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


•	Retail Margins decreased $3 million primarily due to the following:


•	A $30 million decrease due to customer refunds related to Tax Reform. This decrease was partially offset in Income Tax Expense (Benefit) below.


•	A $24 million decrease in weather-normalized retail margins across all classes.


•	A $14 million decrease in weather-related usage in the eastern region primarily in the residential class.

These decreases were partially offset by:


•	The effect of rate proceedings in AEP’s service territories which included:


•	A $47 million increase from rate proceedings for I&M, inclusive of a $9 million decrease due to the impact of Tax Reform. This increase was partially offset in other expense items below.


•	An $11 million increase at PSO due to new base rates implemented in March 2018.


•	A $4 million increase at SWEPCo primarily due to rider and base rate revenue increases in Louisiana. This increase was partially offset by corresponding increases in other expense items below.


•	A $3 million increase at APCo primarily due to increases from riders and base rate revenue increases in West Virginia. This increase was partially offset by increases in various 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.

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


•	Other Operation and Maintenance expenses decreased $50 million primarily due to the following:


•	A $24 million decrease in planned plant outage and maintenance expenses primarily for APCo, I&M, KPCo and SWEPCo.


•	An $18 million decrease in recoverable expenses primarily associated with Energy Efficiency/Demand Response and storm expenses fully recovered in rate riders/trackers within Gross Margins above.


•	A $14 million decrease due to Wind Catcher Project expenses incurred in 2018 for SWEPCo and PSO.


•	A $9 million decrease in estimated expense for claims related to asbestos exposure.

These decreases were partially offset by:


•	An $18 million increase in employee-related expenses.


•	Depreciation and Amortization expenses increased $43 million primarily 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 Tax Expense (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.

TRANSMISSION AND DISTRIBUTION UTILITIES



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

Summary of KWh Energy Sales for Transmission and Distribution Utilities



	Three Months Ended March 31,
	2019	2018
	(in millions of KWhs)
Retail:
Residential	6,547	6,797
Commercial	5,618	5,686
Industrial	5,771	5,674
Miscellaneous	176	171
Total Retail (a)(b)	18,112	18,328

Wholesale (c)	638	667

Total KWhs	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.

Summary of Heating and Cooling Degree Days for Transmission and Distribution Utilities



	Three Months Ended March 31,
	2019	2018
	(in degree days)
Eastern Region
Actual – Heating (a)	1,892	1,884
Normal – Heating (b)	1,877	1,884

Actual – Cooling (c)	1	4
Normal – Cooling (b)	3	3

Western Region
Actual – Heating (a)	177	230
Normal – Heating (b)	187	191

Actual – Cooling (d)	122	196
Normal – Cooling (b)	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.

(d) Western Region cooling degree days are calculated on a 70 degree temperature base.

First Quarter of 2019 Compared to First Quarter of 2018



Reconciliation 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 2018	$	125.4

Changes in Gross Margin:
Retail Margins	58.0
Off-system Sales	20.9
Transmission Revenues	22.4
Other Revenues	(0.6		)
Total Change in Gross Margin	100.7

Changes in Expenses and Other:
Other Operation and Maintenance	(53.2		)
Depreciation and Amortization	(11.1		)
Taxes Other Than Income Taxes	(8.1		)
Interest and Investment Income	(0.1		)
Carrying Costs Income	(0.5		)
Allowance for Equity Funds Used During Construction	(1.1		)
Non-Service Cost Components of Net Periodic Benefit Cost	(0.6		)
Interest Expense	(1.9		)
Total Change in Expenses and Other	(76.6		)

Income Tax Expense	7.0

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 $58 million primarily due to the following:


•	A $58 million increase due to a reversal of a regulatory provision in Ohio.


•	A $17 million net increase in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset by an increase in Other Operation and Maintenance expenses below.


•	A $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 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 $9 million decrease in weather-related usage in Texas primarily due to a 23% decrease in heating degree days and a 38% decrease in cooling degree days.


•	A $6 million decrease in revenues associated with vegetation management riders in Ohio. This decrease was offset in Other Operation and Maintenance expenses below.


•	A $5 million decrease in affiliated PPA capacity revenues in 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 $4 million decrease in Texas revenues associated with the Transmission Cost Recovery Factor revenue rider. This decrease was partially offset by a decrease in Other 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.


•	Transmission Revenues increased $22 million primarily due to the following:


•	A $12 million increase primarily 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 $53 million primarily due to the following:


•	A $23 million increase in transmission expenses that were fully recovered in rate riders/trackers within Gross Margins above.


•	A $17 million increase in affiliated PPA expenses in Texas. This increase was offset by an increase in Margins from Off-system Sales above.


•	A $10 million increase in PJM expenses primarily related to the annual formula rate true-up.


•	A $6 million increase in employee-related expenses.


•	Depreciation and Amortization expenses increased $11 million primarily due to the following:


•	A $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 $10 million decrease in Ohio recoverable DIR depreciation expense. This decrease 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 Tax Expense 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.

AEP TRANSMISSION HOLDCO



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

Summary of Investment in Transmission Assets for AEP Transmission Holdco



	As of March 31,
	2019		2018
	(in millions)
Plant in Service	$	7,073.6	$	5,912.8
Construction Work in Progress	1,899.6		1,533.7
Accumulated Depreciation and Amortization	318.8		200.0
Total Transmission Property, Net	$	8,654.4	$	7,246.5

First Quarter of 2019 Compared to First Quarter of 2018

Reconciliation of First Quarter of 2018 to First Quarter of 2019

Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco

(in millions)



First Quarter of 2018	$	104.0

Changes in Transmission Revenues:
Transmission Revenues	50.9
Total Change in Transmission Revenues	50.9

Changes in Expenses and Other:
Other Operation and Maintenance	(0.4		)
Depreciation and Amortization	(10.0		)
Taxes Other Than Income Taxes	(9.9		)
Interest and Investment Income	0.4
Allowance for Equity Funds Used During Construction	(4.0		)
Non-Service Cost Components of Net Periodic Pension Cost	(0.1		)
Interest Expense	(1.9		)
Total Change in Expenses and Other	(25.9		)

Income Tax Expense	(4.4		)
Equity Earnings of Unconsolidated Subsidiaries	(0.2		)
Net Income Attributable to Noncontrolling Interests	(0.2		)

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 $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 recent FERC audit findings.

This decrease was partially offset by:


•	A $5 million increase due to increased transmission investment.


•	Income Tax Expense increased $4 million primarily due to higher pretax book income.

GENERATION & MARKETING



	Three Months Ended March 31,
Generation & Marketing	2019			2018
	(in millions)
Revenues	$	481.8		$	505.1
Fuel, Purchased Electricity and Other	383.3			408.8
Gross Margin	98.5			96.3
Other Operation and Maintenance	50.6			67.6
Depreciation and Amortization	12.9			6.9
Taxes Other Than Income Taxes	3.8			3.2
Operating Income	31.2			18.6
Interest and Investment Income	2.3			2.5
Non-Service Cost Components of Net Periodic Benefit Cost	3.7			3.9
Interest Expense	(3.8		)	(3.9		)
Income Before Income Tax Expense (Benefit)	33.4			21.1
Income Tax Expense (Benefit)	(5.8		)	3.0
Net Income	39.2			18.1
Net Loss Attributable to Noncontrolling Interests	(0.9		)	(0.1		)
Earnings Attributable to AEP Common Shareholders	$	40.1		$	18.2

Summary of MWhs Generated for Generation & Marketing



	Three Months Ended March 31,
	2019	2018
	(in millions of MWhs)
Fuel Type:
Coal	1	4
Total MWhs	1	4

First Quarter of 2019 Compared to First Quarter of 2018



Reconciliation of First Quarter of 2018 to First Quarter of 2019
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)

First Quarter of 2018	$	18.2

Changes in Gross Margin:
Generation	(33.7		)
Retail, Trading and Marketing	34.3
Other	1.6
Total Change in Gross Margin	2.2

Changes in Expenses and Other:
Other Operation and Maintenance	17.0
Depreciation and Amortization	(6.0		)
Taxes Other Than Income Taxes	(0.6		)
Interest and Investment Income	(0.2		)
Non-Service Cost Components of Net Periodic Benefit Cost	(0.2		)
Interest Expense	0.1
Total Change in Expenses and Other	10.1

Income Tax Expense (Benefit)	8.8
Net Loss Attributable to Noncontrolling Interests	0.8

First Quarter of 2019	$	40.1

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


•	Generation decreased $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.

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.

CORPORATE AND OTHER

First Quarter of 2019 Compared to First Quarter of 2018

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $24 million in 2018 to a loss of $50 million in 2019 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 in 2018.

AEP SYSTEM INCOME TAXES

First Quarter of 2019 Compared to First Quarter of 2018

Income Tax Expense decreased $58 million 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.

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, 2019				December 31, 2018
	(dollars in millions)
Long-term Debt, including amounts due within one year	$	24,426.7	53.7	%	$	23,346.7	52.7	%
Short-term Debt	1,858.0		4.1		1,910.0		4.3
Total Debt	26,284.7		57.8		25,256.7		57.0
AEP Common Equity	19,196.3		42.2		19,028.4		42.9
Noncontrolling Interests	32.2		—		31.0		0.1
Total Debt and Equity Capitalization	$	45,513.2	100.0	%	$	44,316.1	100.0	%

AEP’s ratio of debt-to-total capital increased from 57% as of December 31, 2018 to 57.8% as of March 31, 2019 primarily due to an increase in debt to support distribution, transmission and 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, 2019, AEP had a $4 billion revolving credit facility to support its 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-and-leaseback or leasing agreements, hybrid securities or common stock.

Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments. As of March 31, 2019, available liquidity was approximately $3.1 billion as illustrated in the table below:



		Amount		Maturity
		(in millions)
Commercial Paper Backup:
	Revolving Credit Facility	$	4,000.0	June 2022
Cash and Cash Equivalents		227.7
Total Liquidity Sources		4,227.7
Less:	AEP Commercial Paper Outstanding	1,108.0

Net Available Liquidity		$	3,119.7

AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries. The program funds a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and the short-term debt requirements of subsidiaries that are not participating in either money pool for regulatory or operational reasons, as direct borrowers. The maximum amount of commercial paper outstanding during the first three months of 2019 was $1.9 billion. The weighted-average interest rate for AEP’s commercial paper during the first three months of 2019 was 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 April 2019, AEP executed two additional $50 million uncommitted letter of credit facilities. The Registrants’

maximum future payments for letters of credit issued under the uncommitted facilities as of March 31, 2019 was $106 million with maturities ranging from June 2019 to March 2020.

Securitized Accounts Receivables

AEP’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and includes a $125 million and a $625 million facility which expire in 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-total capitalization at a level that does not exceed 67.5%. The method for calculating outstanding debt and capitalization is contractually-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, 2019, this contractually-defined percentage was 53.8%. Non-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-traded commodity contracts and would similarly allow lenders and counterparties to declare the outstanding amounts payable. However, a default under AEP’s non-exchange-traded commodity contracts would not cause an event of default under its credit agreements.

The revolving credit facility does not permit the lenders to refuse a draw on any facility if a material adverse change occurs.

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

Equity Units

In March 2019, AEP issued 16.1 million Equity Units initially in the form of corporate units, at a stated amount of $50 per unit, for a total stated amount of $805 million. Net proceeds from the issuance were approximately $785 million. Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 3.40% Junior Subordinated Notes due in 2024 and a forward equity purchase contract which settles after three years in 2022. The proceeds from this issuance 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 $0.67 per share in April 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,
	2019			2018
	(in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	$	444.1		$	412.6
Net Cash Flows from Operating Activities	808.3			802.2
Net Cash Flows Used for Investing Activities	(1,582.8		)	(1,927.8		)
Net Cash Flows from Financing Activities	693.5			1,029.5
Net Decrease in Cash, Cash Equivalents and Restricted Cash	(81.0		)	(96.1		)
Cash, Cash Equivalents and Restricted Cash at End of Period	$	363.1		$	316.5

Operating Activities



	Three Months Ended March 31,
	2019			2018
	(in millions)
Net Income	$	574.1		$	456.7
Non-Cash Adjustments to Net Income (a)	618.8			623.7
Mark-to-Market of Risk Management Contracts	65.5			(0.7		)
Property Taxes	(75.6		)	(63.7		)
Deferred Fuel Over/Under Recovery, Net	32.5			(61.2		)
Recovery of Ohio Capacity Costs, Net	14.7			18.0
Provision for Refund - Global Settlement, Net	(4.1		)	(5.4		)
Change in Other Noncurrent Assets	(47.9		)	(59.8		)
Change in Other Noncurrent Liabilities	67.3			133.3
Change in Certain Components of Working Capital	(437.0		)	(238.7		)
Net Cash Flows from Operating Activities	$	808.3		$	802.2


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

Net Cash Flows from Operating Activities increased by $6 million primarily due to the following:


•	A $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 higher employee-related payments and the reversal of a regulatory provision at OPCo. See Note 4 - Rate Matters for additional information.


•	A $66 million decrease in Change in Other Noncurrent Liabilities primarily due to decreased Accumulated Provisions for Rate Refunds as a result of Tax Reform in 2018, partially offset by lower employee-related payments.

Investing Activities



	Three Months Ended March 31,
	2019			2018
	(in millions)
Construction Expenditures	$	(1,565.4	)	$	(1,905.8	)
Acquisitions of Nuclear Fuel	(32.4		)	(23.8		)
Other	15.0			1.8
Net Cash Flows Used for Investing Activities	$	(1,582.8	)	$	(1,927.8	)

Net Cash Flows Used for Investing Activities decreased by $345 million primarily due to decreased construction expenditures in AEP Transmission Holdco of $201 million and Transmission and Distribution Utilities of $108 million.

Financing Activities



	Three Months Ended March 31,
	2019			2018
	(in millions)
Issuance of Common Stock, Net	$	14.5		$	32.2
Issuance/Retirement of Debt, Net	1,013.0			1,317.2
Dividends Paid on Common Stock	(333.6		)	(306.1		)
Other	(0.4		)	(13.8		)
Net Cash Flows from Financing Activities	$	693.5		$	1,029.5

Net Cash Flows from Financing Activities decreased by $336 million primarily due to the following:


•	A $1.1 billion decrease in cash from short-term debt primarily due to decreased borrowings of commercial paper. See Note 13 - Financing Activities for additional information.

These decreases in cash were partially offset by:


•	A $445 million increase in cash due to increased issuances of long-term debt. See Note 13 - Financing Activities for additional information.


•	A $323 million increase in cash due to decreased retirements of long-term debt. See Note 13 - Financing Activities for additional information.

See “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 flows from operations and financing activities. Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged. For complete information of forecasted capital expenditures, see the “Budgeted Capital Expenditures” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2018 Annual Report.

CONTRACTUAL OBLIGATION INFORMATION

A summary of contractual obligations is included in the 2018 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING 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 2018 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 2019 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 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, 2018:



MTM Risk Management Contract Net Assets (Liabilities)
Three Months Ended March 31, 2019

	Vertically Integrated Utilities			Transmission and Distribution Utilities			Generation & Marketing			Total
	(in millions)
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	(3.2		)	(1.1		)	(9.2		)	(13.5		)
Fair Value of New Contracts at Inception When Entered During the Period (a)	—			—			0.1			0.1
Changes in Fair Value Due to Market Fluctuations During the Period (b)	—			—			7.7			7.7
Changes in Fair Value Allocated to Regulated Jurisdictions (c)	(69.5		)	(4.4		)	—			(73.9		)
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										(55.8		)
Fair Value Hedge Contracts										(6.3		)
Collateral Deposits										0.3
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 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, 2019, credit exposure net of collateral to sub investment grade counterparties was approximately 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, 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%
	(in millions, except number of counterparties)
Investment Grade	$	501.7	$	1.7	$	500.0	2	$	213.0
Noninvestment Grade	0.1		0.1		—		—	—
No External Ratings:
Internal Investment Grade	128.1		—		128.1		3	83.1
Internal Noninvestment Grade	51.7		10.5		41.2		2	28.2
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, 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 Ended								Twelve Months Ended
March 31, 2019								December 31, 2018
End		High		Average		Low		End		High		Average		Low
(in millions)								(in millions)
$	0.1	$	1.2	$	0.3	$	0.1	$	1.1	$	1.8	$	0.3	$	0.1

VaR Model

Non-Trading Portfolio



Three Months Ended								Twelve Months Ended
March 31, 2019								December 31, 2018
End		High		Average		Low		End		High		Average		Low
(in millions)								(in millions)
$	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 and long-term debt which is subject to a variable rate. AEP manages interest rate risk by limiting variable rate exposures to a percentage of total debt, by entering into interest rate derivative instruments and by monitoring the effects of market changes in interest rates. A 100 basis point change in the benchmark rate on AEP’s variable rate debt would impact pretax interest expense annually by $25 million for the three months ended March 31, 2019 and 2018, respectively.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, 2019 and 2018

(in millions, except per-share and share amounts)

(Unaudited)



	Three Months Ended March 31,
	2019			2018
REVENUES
Vertically Integrated Utilities	$	2,372.3		$	2,381.5
Transmission and Distribution Utilities	1,179.8			1,141.2
Generation & Marketing	439.7			477.5
Other Revenues	65.0			48.1
TOTAL REVENUES	4,056.8			4,048.3

EXPENSES
Fuel and Other Consumables Used for Electric Generation	550.4			501.8
Purchased Electricity for Resale	861.8			990.3
Other Operation	666.0			726.4
Maintenance	274.5			298.5
Depreciation and Amortization	605.8			539.7
Taxes Other Than Income Taxes	309.9			285.6
TOTAL EXPENSES	3,268.4			3,342.3

OPERATING INCOME	788.4			706.0

Other Income (Expense):
Other Income	8.6			5.5
Allowance for Equity Funds Used During Construction	28.9			30.7
Non-Service Cost Components of Net Periodic Benefit Cost	30.0			32.0
Interest Expense	(255.8		)	(234.0		)

INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	600.1			540.2

Income Tax Expense	44.5			102.0
Equity Earnings of Unconsolidated Subsidiaries	18.5			18.5

NET INCOME	574.1			456.7

Net Income Attributable to Noncontrolling Interests	1.3			2.3

EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	572.8		$	454.4

WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING	493,309,076			492,267,402

TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	1.16		$	0.92

WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING	494,484,144			493,127,300

TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	1.16		$	0.92



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2019			2018
Net Income	$	574.1		$	456.7

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
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)	(30.3		)	1.3

TOTAL COMPREHENSIVE INCOME	543.8			458.0

Total Comprehensive Income Attributable to Noncontrolling Interests	1.3			2.3

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	542.5		$	455.7



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	AEP Common Shareholders
	Common Stock										Accumulated Other Comprehensive Income (Loss)
	Shares	Amount		Paid-in Capital				Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
TOTAL EQUITY – DECEMBER 31, 2017	512.2	$	3,329.4	$	6,398.7			$	8,626.7		$	(67.8	)	$	26.6		$	18,313.6

Issuance of Common Stock	0.5	3.3		28.9													32.2
Common Stock Dividends ($0.62 per share)								(305.5		)				(0.6		)	(306.1		)
Other Changes in Equity				16.9													16.9
ASU 2018-02 Adoption								14.0			(17.0		)				(3.0		)
ASU 2016-01 Adoption								11.9			(11.9		)				—
Net Income								454.4						2.3			456.7
Other Comprehensive Income											1.3						1.3
TOTAL EQUITY – MARCH 31, 2018	512.7	$	3,332.7	$	6,444.5			$	8,801.5		$	(95.4	)	$	28.3		$	18,511.6

TOTAL EQUITY – DECEMBER 31, 2018	513.5	$	3,337.4	$	6,486.1			$	9,325.3		$	(120.4	)	$	31.0		$	19,059.4

Issuance of Common Stock	0.1	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, 2019	513.6	$	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 103.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, 2019 and December 31, 2018

(in millions)

(Unaudited)



	March 31,			December 31,
	2019			2018
CURRENT ASSETS
Cash and Cash Equivalents	$	227.7		$	234.1
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	696.6			699.0
Accrued Unbilled Revenues	207.8			209.3
Pledged Accounts Receivable – AEP Credit	970.5			999.8
Miscellaneous	48.3			55.2
Allowance for Uncollectible Accounts	(40.9		)	(36.8		)
Total Accounts Receivable	1,882.3			1,926.5
Fuel	360.3			341.5
Materials and Supplies	586.3			579.6
Risk Management Assets	93.9			162.8
Regulatory Asset for Under-Recovered Fuel Costs	123.3			150.1
Margin Deposits	136.3			141.4
Prepayments and Other Current Assets	200.4			208.8
TOTAL CURRENT ASSETS	3,914.8			4,113.9

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	21,780.6			21,699.9
Transmission	21,773.5			21,531.0
Distribution	21,483.5			21,195.4
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	4,202.7			4,265.0
Construction Work in Progress	4,910.9			4,393.9
Total Property, Plant and Equipment	74,151.2			73,085.2
Accumulated Depreciation and Amortization	18,182.6			17,986.1
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	55,968.6			55,099.1

OTHER NONCURRENT ASSETS
Regulatory Assets	3,297.9			3,310.4
Securitized Assets	853.0			920.6
Spent Nuclear Fuel and Decommissioning Trusts	2,684.0			2,474.9
Goodwill	52.5			52.5
Long-term Risk Management Assets	250.4			254.0
Operating Lease Assets	1,045.4			—
Deferred Charges and Other Noncurrent Assets	2,655.4			2,577.4
TOTAL OTHER NONCURRENT ASSETS	10,838.6			9,589.8

TOTAL ASSETS	$	70,722.0		$	68,802.8



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

March 31, 2019 and December 31, 2018

(dollars in millions)

(Unaudited)



			March 31,			December 31,
			2019			2018
CURRENT LIABILITIES
Accounts Payable			$	1,497.2		$	1,874.3
Short-term Debt:
Securitized Debt for Receivables – AEP Credit			750.0			750.0
Other Short-term Debt			1,108.0			1,160.0
Total Short-term Debt			1,858.0			1,910.0
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			63.4			55.0
Customer Deposits			400.4			412.2
Accrued Taxes			1,156.5			1,218.0
Accrued Interest			306.0			231.7
Obligations Under Operating Leases			228.2			—
Regulatory Liability for Over-Recovered Fuel Costs			64.3			58.6
Other Current Liabilities			888.1			1,190.5
TOTAL CURRENT LIABILITIES			7,990.6			8,648.8

NONCURRENT LIABILITIES
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			267.9			263.4
Deferred Income Taxes			7,193.0			7,086.5
Regulatory Liabilities and Deferred Investment Tax Credits			8,669.8			8,540.3
Asset Retirement Obligations			2,317.3			2,287.7
Employee Benefits and Pension Obligations			383.9			377.1
Obligations Under Operating Leases			860.2			—
Deferred Credits and Other Noncurrent Liabilities			797.9			782.6
TOTAL NONCURRENT LIABILITIES			43,388.2			40,985.8

TOTAL LIABILITIES			51,378.8			49,634.6

Rate Matters (Note 4)
Commitments and Contingencies (Note 5)

MEZZANINE EQUITY
Redeemable Noncontrolling Interest			68.5			69.4
Contingently Redeemable Performance Share Awards			46.2			39.4
TOTAL MEZZANINE EQUITY			114.7			108.8

EQUITY
Common Stock – Par Value – $6.50 Per Share:
	2019	2018
Shares Authorized	600,000,000	600,000,000
Shares Issued	513,632,124	513,450,036
(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			6,442.8			6,486.1
Retained Earnings			9,565.6			9,325.3
Accumulated Other Comprehensive Income (Loss)			(150.7		)	(120.4		)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY			19,196.3			19,028.4

Noncontrolling Interests			32.2			31.0

TOTAL EQUITY			19,228.5			19,059.4

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 103.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2019			2018
OPERATING ACTIVITIES
Net Income	$	574.1		$	456.7
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	605.8			539.7
Deferred Income Taxes	16.8			87.3
Allowance for Equity Funds Used During Construction	(28.9		)	(30.7		)
Mark-to-Market of Risk Management Contracts	65.5			(0.7		)
Amortization of Nuclear Fuel	25.1			27.4
Property Taxes	(75.6		)	(63.7		)
Deferred Fuel Over/Under-Recovery, Net	32.5			(61.2		)
Recovery of Ohio Capacity Costs	14.7			18.0
Provision for Refund – Global Settlement, Net	(4.1		)	(5.4		)
Change in Other Noncurrent Assets	(47.9		)	(59.8		)
Change in Other Noncurrent Liabilities	67.3			133.3
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	57.5			39.7
Fuel, Materials and Supplies	(26.4		)	28.5
Accounts Payable	(152.6		)	(129.3		)
Accrued Taxes, Net	(77.0		)	(74.3		)
Other Current Assets	(18.8		)	(40.1		)
Other Current Liabilities	(219.7		)	(63.2		)
Net Cash Flows from Operating Activities	808.3			802.2

INVESTING ACTIVITIES
Construction Expenditures	(1,565.4		)	(1,905.8		)
Purchases of Investment Securities	(130.4		)	(525.9		)
Sales of Investment Securities	111.9			508.6
Acquisitions of Nuclear Fuel	(32.4		)	(23.8		)
Other Investing Activities	33.5			19.1
Net Cash Flows Used for Investing Activities	(1,582.8		)	(1,927.8		)

FINANCING ACTIVITIES
Issuance of Common Stock, Net	14.5			32.2
Issuance of Long-term Debt	1,285.6			841.0
Commercial Paper and Credit Facility Borrowings	—			205.6
Change in Short-term Debt, Net	(52.0		)	814.6
Retirement of Long-term Debt	(220.6		)	(544.0		)
Principal Payments for Finance Lease Obligations	(14.3		)	(16.8		)
Dividends Paid on Common Stock	(333.6		)	(306.1		)
Other Financing Activities	13.9			3.0
Net Cash Flows from Financing Activities	693.5			1,029.5

Net Decrease in Cash, Cash Equivalents and Restricted Cash	(81.0		)	(96.1		)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	444.1			412.6
Cash, Cash Equivalents and Restricted Cash at End of Period	$	363.1		$	316.5

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	168.9		$	188.0
Net Cash Paid (Received) for Income Taxes	(0.6		)	(0.9		)
Noncash Acquisitions Under Finance Leases	23.1			21.4
Construction Expenditures Included in Current Liabilities as of March 31,	846.3			799.9
Noncash Contribution of Assets by Noncontrolling Interest	—			84.0
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage	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 103.

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,
	2019	2018
	(in millions of KWhs)
Retail:
Residential	2,424	2,664
Commercial	2,091	2,153
Industrial	2,148	2,101
Miscellaneous	145	140
Total Retail (a)	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,
	2019	2018
	(in degree days)
Actual – Heating (a)	177	230
Normal – Heating (b)	187	191

Actual – Cooling (c)	122	196
Normal – Cooling (b)	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.

First Quarter of 2019 Compared to First Quarter of 2018



Reconciliation of First Quarter of 2018 to First Quarter of 2019
Net Income
(in millions)

First Quarter of 2018	$	46.8

Changes in Gross Margin:
Retail Margins	(11.8		)
Off-system Sales	21.5
Transmission Revenues	12.0
Other Revenues	(3.1		)
Total Change in Gross Margin	18.6

Changes in Expenses and Other:
Other Operation and Maintenance	3.4
Depreciation and Amortization	(28.9		)
Taxes Other Than Income Taxes	(4.1		)
Interest Income	(0.1		)
Allowance for Equity Funds Used During Construction	(3.7		)
Non-Service Cost Components of Net Periodic Benefit Cost	(0.3		)
Interest Expense	(2.4		)
Total Change in Expenses and Other	(36.1		)

Income Tax Expense	5.1

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:


•	A $9 million decrease in weather-related usage primarily due to a 23% decrease in heating degree days and a 38% decrease in cooling degree days.


•	A $4 million decrease in revenues associated with the Transmission Cost Recovery Factor revenue rider. This decrease was partially offset by a 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.

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:


•	A $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 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.


•	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.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2019			2018
REVENUES
Electric Transmission and Distribution	$	349.8		$	352.4
Sales to AEP Affiliates	40.2			18.2
Other Revenues	0.7			1.0
TOTAL REVENUES	390.7			371.6

EXPENSES
Fuel and Other Consumables Used for Electric Generation	9.4			8.9
Other Operation	109.8			117.0
Maintenance	25.3			21.5
Depreciation and Amortization	138.9			110.0
Taxes Other Than Income Taxes	36.5			32.4
TOTAL EXPENSES	319.9			289.8

OPERATING INCOME	70.8			81.8

Other Income (Expense):
Interest Income	0.4			0.5
Allowance for Equity Funds Used During Construction	1.8			5.5
Non-Service Cost Components of Net Periodic Benefit Cost	2.8			3.1
Interest Expense	(37.4		)	(35.0		)

INCOME BEFORE INCOME TAX EXPENSE	38.4			55.9

Income Tax Expense	4.0			9.1

NET INCOME	$	34.4		$	46.8

The common stock of AEP Texas is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2019		2018
Net Income	$	34.4	$	46.8

OTHER COMPREHENSIVE INCOME, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 in 2019 and 2018, Respectively	0.3		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 INCOME	0.3		0.3

TOTAL COMPREHENSIVE INCOME	$	34.7	$	47.1

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017	$	1,057.9	$	1,124.6	$	(12.6	)	$	2,169.9

Capital Contribution from Parent	100.0							100.0
ASU 2018-02 Adoption			1.8		(2.7		)	(0.9		)
Net Income			46.8					46.8
Other Comprehensive Income					0.3			0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018	$	1,157.9	$	1,173.2	$	(15.0	)	$	2,316.1

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 103.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, 2019 and December 31, 2018

(in millions)

(Unaudited)



	March 31,			December 31,
	2019			2018
CURRENT ASSETS
Cash and Cash Equivalents	$	0.1		$	3.1
Restricted Cash for Securitized Transition Funding	100.6			156.7
Advances to Affiliates	7.7			8.0
Accounts Receivable:
Customers	125.5			110.9
Affiliated Companies	15.9			15.0
Accrued Unbilled Revenues	63.0			70.4
Miscellaneous	1.8			1.9
Allowance for Uncollectible Accounts	(1.5		)	(1.3		)
Total Accounts Receivable	204.7			196.9
Fuel	8.5			8.8
Materials and Supplies	54.1			52.8
Accrued Tax Benefits	24.3			44.9
Prepayments and Other Current Assets	4.8			5.3
TOTAL CURRENT ASSETS	404.8			476.5

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	352.0			352.1
Transmission	3,777.7			3,683.6
Distribution	4,100.6			4,043.2
Other Property, Plant and Equipment	734.5			727.9
Construction Work in Progress	941.8			836.2
Total Property, Plant and Equipment	9,906.6			9,643.0
Accumulated Depreciation and Amortization	1,686.6			1,651.2
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	8,220.0			7,991.8

OTHER NONCURRENT ASSETS
Regulatory Assets	426.7			430.0
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	212.0			56.3
TOTAL OTHER NONCURRENT ASSETS	1,231.6			1,135.4

TOTAL ASSETS	$	9,856.4		$	9,603.7

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

March 31, 2019 and December 31, 2018

(in millions)

(Unaudited)



	March 31,			December 31,
	2019			2018
CURRENT LIABILITIES
Advances from Affiliates	$	271.2		$	216.0
Accounts Payable:
General	242.0			276.5
Affiliated Companies	22.6			30.3
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	112.4			75.5
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	82.4			98.3
TOTAL CURRENT LIABILITIES	1,328.1			1,259.5

NONCURRENT LIABILITIES
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	908.8			913.1
Regulatory Liabilities and Deferred Investment Tax Credits	1,344.1			1,344.3
Oklaunion Purchase Power Agreement	15.1			22.1
Obligations Under Operating Leases	70.2			—
Deferred Credits and Other Noncurrent Liabilities	105.2			104.0
TOTAL NONCURRENT LIABILITIES	5,713.1			5,763.7

TOTAL LIABILITIES	7,041.2			7,023.2

Rate Matters (Note 4)
Commitments and Contingencies (Note 5)

COMMON SHAREHOLDER’S EQUITY
Paid-in Capital	1,457.9			1,257.9
Retained Earnings	1,372.1			1,337.7
Accumulated Other Comprehensive Income (Loss)	(14.8		)	(15.1		)
TOTAL COMMON SHAREHOLDER’S EQUITY	2,815.2			2,580.5

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	9,856.4		$	9,603.7

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2019			2018
OPERATING ACTIVITIES
Net Income	$	34.4		$	46.8
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	138.9			110.0
Deferred Income Taxes	(11.0		)	(4.4		)
Allowance for Equity Funds Used During Construction	(1.8		)	(5.5		)
Mark-to-Market of Risk Management Contracts	—			0.2
Property Taxes	(73.8		)	(56.1		)
Change in Other Noncurrent Assets	(3.2		)	(12.7		)
Change in Other Noncurrent Liabilities	(5.7		)	6.5
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(7.8		)	1.8
Fuel, Materials and Supplies	(1.0		)	(0.2		)
Accounts Payable	4.2			(25.9		)
Accrued Taxes, Net	57.5			25.2
Other Current Assets	0.5			(1.6		)
Other Current Liabilities	(4.4		)	(5.1		)
Net Cash Flows from Operating Activities	126.8			79.0

INVESTING ACTIVITIES
Construction Expenditures	(343.1		)	(481.6		)
Change in Advances to Affiliates, Net	0.3			103.8
Other Investing Activities	6.2			13.4
Net Cash Flows Used for Investing Activities	(336.6		)	(364.4		)

FINANCING ACTIVITIES
Capital Contribution from Parent	200.0			100.0
Change in Advances from Affiliates, Net	55.2			232.7
Retirement of Long-term Debt – Nonaffiliated	(103.5		)	(96.5		)
Principal Payments for Finance Lease Obligations	(1.2		)	(1.1		)
Other Financing Activities	0.2			0.3
Net Cash Flows from Financing Activities	150.7			235.4

Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding	(59.1		)	(50.0		)
Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding at Beginning of Period	159.8			157.2
Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding at End of Period	$	100.7		$	107.2

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	22.4		$	27.8
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,	195.7			169.3

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

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,
	2019		2018
	(in millions)
Plant In Service	$	6,755.0	$	5,595.4
Construction Work in Progress	1,812.2		1,512.6
Accumulated Depreciation and Amortization	306.7		192.7
Total Transmission Property, Net	$	8,260.5	$	6,915.3

First Quarter of 2019 Compared to First Quarter of 2018



Reconciliation of First Quarter of 2018 to First Quarter of 2019
Net Income
(in millions)

First Quarter of 2018	$	84.1

Changes in Transmission Revenues:
Transmission Revenues	51.8
Total Change in Transmission Revenues	51.8

Changes in Expenses and Other:
Other Operation and Maintenance	(1.0		)
Depreciation and Amortization	(10.0		)
Taxes Other Than Income Taxes	(10.3		)
Interest Income	0.3
Allowance for Equity Funds Used During Construction	(3.6		)
Interest Expense	(1.4		)
Total Change in Expenses and Other	(26.0		)

Income Tax Expense	(5.6		)

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.

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 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.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2019			2018
REVENUES
Transmission Revenues	$	50.3		$	30.9
Sales to AEP Affiliates	193.2			160.7
Other Revenues	—			0.1
TOTAL REVENUES	243.5			191.7

EXPENSES
Other Operation	17.0			16.6
Maintenance	3.2			2.6
Depreciation and Amortization	40.3			30.3
Taxes Other Than Income Taxes	41.4			31.1
TOTAL EXPENSES	101.9			80.6

OPERATING INCOME	141.6			111.1

Other Income (Expense):
Interest Income	0.7			0.4
Allowance for Equity Funds Used During Construction	11.3			14.9
Interest Expense	(21.7		)	(20.3		)

INCOME BEFORE INCOME TAX EXPENSE	131.9			106.1

Income Tax Expense	27.6			22.0

NET INCOME	$	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 103.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

MEMBER’S EQUITY

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Paid-in Capital		Retained Earnings		Total Member’s Equity
TOTAL MEMBER’S EQUITY – DECEMBER 31, 2017	$	1,816.6	$	773.3	$	2,589.9

Capital Contributions from Member	65.0				65.0
Net Income			84.1		84.1
TOTAL MEMBER’S EQUITY – MARCH 31, 2018	$	1,881.6	$	857.4	$	2,739.0

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 103.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, 2019 and December 31, 2018

(in millions)

(Unaudited)



	March 31,		December 31,
	2019		2018
CURRENT ASSETS
Advances to Affiliates	$	73.5	$	96.9
Accounts Receivable:
Customers	19.0		11.8
Affiliated Companies	68.8		61.0
Miscellaneous	0.2		—
Total Accounts Receivable	88.0		72.8
Materials and Supplies	19.6		19.0
Accrued Tax Benefits	19.1		33.4
Prepayments and Other Current Assets	2.9		3.4
TOTAL CURRENT ASSETS	203.1		225.5

TRANSMISSION PROPERTY
Transmission Property	6,580.6		6,515.8
Other Property, Plant and Equipment	174.4		174.0
Construction Work in Progress	1,812.2		1,578.3
Total Transmission Property	8,567.2		8,268.1
Accumulated Depreciation and Amortization	306.7		271.9
TOTAL TRANSMISSION PROPERTY – NET	8,260.5		7,996.2

OTHER NONCURRENT ASSETS
Regulatory Assets	10.5		12.9
Deferred Property Taxes	134.7		157.9
Deferred Charges and Other Noncurrent Assets	7.3		1.6
TOTAL OTHER NONCURRENT ASSETS	152.5		172.4

TOTAL ASSETS	$	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 103.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND MEMBER’S EQUITY

March 31, 2019 and December 31, 2018

(in millions)

(Unaudited)



	March 31,		December 31,
	2019		2018

CURRENT LIABILITIES
Advances from Affiliates	$	223.1	$	45.4
Accounts Payable:
General	258.0		347.2
Affiliated Companies	67.0		56.0
Long-term Debt Due Within One Year – Nonaffiliated	85.0		85.0
Accrued Taxes	242.5		288.9
Accrued Interest	35.1		15.9
Obligations Under Operating Leases	2.6		—
Other Current Liabilities	20.3		3.8
TOTAL CURRENT LIABILITIES	933.6		842.2

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	2,738.4		2,738.0
Deferred Income Taxes	721.9		704.4
Regulatory Liabilities	527.9		521.3
Obligations Under Operating Leases	3.2		—
Deferred Credits and Other Noncurrent Liabilities	17.0		18.4
TOTAL NONCURRENT LIABILITIES	4,008.4		3,982.1

TOTAL LIABILITIES	4,942.0		4,824.3

Rate Matters (Note 4)
Commitments and Contingencies (Note 5)

MEMBER’S EQUITY
Paid-in Capital	2,480.6		2,480.6
Retained Earnings	1,193.5		1,089.2
TOTAL MEMBER’S EQUITY	3,674.1		3,569.8

TOTAL LIABILITIES AND MEMBER’S EQUITY	$	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 103.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2019			2018
OPERATING ACTIVITIES
Net Income	$	104.3		$	84.1
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	40.3			30.3
Deferred Income Taxes	14.5			15.5
Allowance for Equity Funds Used During Construction	(11.3		)	(14.9		)
Property Taxes	23.2			17.3
Change in Other Noncurrent Assets	2.7			2.9
Change in Other Noncurrent Liabilities	2.2			23.9
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(8.2		)	(9.6		)
Materials and Supplies	(0.6		)	(1.9		)
Accounts Payable	11.4			(10.7		)
Accrued Taxes, Net	(32.1		)	(34.0		)
Accrued Interest	19.2			23.3
Other Current Assets	0.4			0.3
Other Current Liabilities	0.2			0.6
Net Cash Flows from Operating Activities	166.2			127.1

INVESTING ACTIVITIES
Construction Expenditures	(365.0		)	(571.8		)
Change in Advances to Affiliates, Net	23.4			114.2
Acquisitions of Assets	(2.5		)	(1.8		)
Other Investing Activities	0.3			1.0
Net Cash Flows Used for Investing Activities	(343.8		)	(458.4		)

FINANCING ACTIVITIES
Capital Contributions from Member	—			65.0
Change in Advances from Affiliates, Net	177.7			266.4
Other Financing Activities	(0.1		)	(0.1		)
Net Cash Flows from Financing Activities	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	(1.2		)	—
Construction Expenditures Included in Current Liabilities as of March 31,	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 103.

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,
	2019	2018
	(in millions of KWhs)
Retail:
Residential	3,587	3,845
Commercial	1,596	1,689
Industrial	2,336	2,382
Miscellaneous	219	224
Total Retail (a)	7,738	8,140

Wholesale	816	495

Total KWhs	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,
	2019	2018
	(in degree days)
Actual – Heating (a)	1,252	1,389
Normal – Heating (b)	1,312	1,317

Actual – Cooling (c)	—	8
Normal – Cooling (b)	7	7

(a) Heating degree days are calculated on a 55 degree temperature base.

(b) Normal Heating/Cooling represents the thirty-year average of degree days.

First Quarter of 2019 Compared to First Quarter of 2018



Reconciliation of First Quarter of 2018 to First Quarter of 2019
Net Income
(in millions)

First Quarter of 2018	$	125.5

Changes in Gross Margin:
Retail Margins	(59.3		)
Off-system Sales	1.7
Transmission Revenues	12.3
Other Revenues	(1.3		)
Total Change in Gross Margin	(46.6		)

Changes in Expenses and Other:
Other Operation and Maintenance	11.8
Depreciation and Amortization	(4.0		)
Taxes Other Than Income Taxes	(2.1		)
Interest Income	0.5
Carrying Costs Income	(0.5		)
Allowance for Equity Funds Used During Construction	(0.9		)
Non-Service Cost Components of Net Periodic Benefit Cost	(0.2		)
Interest Expense	(1.9		)
Total Change in Expenses and Other	2.7

Income Tax Expense (Benefit)	52.1

First Quarter of 2019	$	133.7


•	Retail Margins decreased $59 million primarily due to the following:


•	A $28 million decrease due to customer refunds related to Tax Reform. This decrease was partially offset in Income Tax Expense (Benefit) below.


•	A $15 million decrease in weather-normalized margins occurring across all retail classes.


•	A $14 million decrease 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 decreased $12 million primarily due to the following:


•	A $5 million decrease in estimated expenses for claims related to asbestos exposure.


•	A $4 million decrease in storm-related expenses.


•	A $4 million decrease in maintenance expense at various generation plants.


•	A $3 million decrease in expenses due to the extinguishment of regulatory asset balances as agreed to within the West Virginia Tax Reform settlement.


•	A $3 million decrease in vegetation management expenses.

These decreases were primarily offset by:


•	An $8 million increase in PJM expenses primarily related to the 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.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2019			2018
REVENUES
Electric Generation, Transmission and Distribution	$	738.7		$	767.5
Sales to AEP Affiliates	51.7			49.4
Other Revenues	2.4			3.5
TOTAL REVENUES	792.8			820.4

EXPENSES
Fuel and Other Consumables Used for Electric Generation	183.3			69.0
Purchased Electricity for Resale	110.6			205.9
Other Operation	136.9			138.2
Maintenance	61.5			72.0
Depreciation and Amortization	112.5			108.5
Taxes Other Than Income Taxes	35.9			33.8
TOTAL EXPENSES	640.7			627.4

OPERATING INCOME	152.1			193.0

Other Income (Expense):
Interest Income	0.8			0.3
Carrying Costs Income	—			0.5
Allowance for Equity Funds Used During Construction	1.7			2.6
Non-Service Cost Components of Net Periodic Benefit Cost	4.3			4.5
Interest Expense	(49.3		)	(47.4		)

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	109.6			153.5

Income Tax Expense (Benefit)	(24.1		)	28.0

NET INCOME	$	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 103.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2019			2018
Net Income	$	133.7		$	125.5

OTHER COMPREHENSIVE LOSS, NET OF TAXES
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	(0.8		)	(1.0		)

TOTAL COMPREHENSIVE INCOME	$	132.9		$	124.5



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017	$	260.4	$	1,828.7	$	1,714.1		$	1.3		$	3,804.5

Common Stock Dividends					(40.0		)				(40.0		)
ASU 2018-02 Adoption					0.1			0.3			0.4
Net Income					125.5						125.5
Other Comprehensive Loss								(1.0		)	(1.0		)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018	$	260.4	$	1,828.7	$	1,799.7		$	0.6		$	3,889.4

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 103.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, 2019 and December 31, 2018

(in millions)

(Unaudited)



	March 31,			December 31,
	2019			2018
CURRENT ASSETS
Cash and Cash Equivalents	$	2.9		$	4.2
Restricted Cash for Securitized Funding	18.3			25.6
Advances to Affiliates	216.6			23.0
Accounts Receivable:
Customers	144.4			146.5
Affiliated Companies	60.3			73.4
Accrued Unbilled Revenues	61.7			63.5
Miscellaneous	1.1			2.3
Allowance for Uncollectible Accounts	(2.8		)	(2.3		)
Total Accounts Receivable	264.7			283.4
Fuel	69.9			61.3
Materials and Supplies	102.1			100.1
Risk Management Assets	12.9			57.2
Regulatory Asset for Under-Recovered Fuel Costs	78.8			99.6
Prepayments and Other Current Assets	33.9			44.3
TOTAL CURRENT ASSETS	800.1			698.7

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	6,531.5			6,509.6
Transmission	3,330.1			3,317.7
Distribution	4,014.6			3,989.4
Other Property, Plant and Equipment	504.5			485.8
Construction Work in Progress	524.9			490.2
Total Property, Plant and Equipment	14,905.6			14,792.7
Accumulated Depreciation and Amortization	4,174.9			4,124.4
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	10,730.7			10,668.3

OTHER NONCURRENT ASSETS
Regulatory Assets	469.6			475.8
Securitized Assets	252.7			258.7
Long-term Risk Management Assets	0.3			0.9
Operating Lease Assets	79.1			—
Deferred Charges and Other Noncurrent Assets	194.9			188.1
TOTAL OTHER NONCURRENT ASSETS	996.6			923.5

TOTAL ASSETS	$	12,527.4		$	12,290.5



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

March 31, 2019 and December 31, 2018

(Unaudited)



	March 31,			December 31,
	2019			2018
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	—		$	205.6
Accounts Payable:
General	218.7			263.8
Affiliated Companies	80.8			84.0
Long-term Debt Due Within One Year – Nonaffiliated	345.0			430.7
Risk Management Liabilities	6.1			0.4
Customer Deposits	88.3			88.4
Accrued Taxes	92.3			89.3
Accrued Interest	74.2			41.5
Obligations Under Operating Leases	15.0			—
Other Current Liabilities	103.7			150.3
TOTAL CURRENT LIABILITIES	1,024.1			1,354.0

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	4,099.0			3,631.9
Long-term Risk Management Liabilities	0.2			0.2
Deferred Income Taxes	1,615.4			1,625.8
Regulatory Liabilities and Deferred Investment Tax Credits	1,415.7			1,449.7
Asset Retirement Obligations	106.2			107.1
Employee Benefits and Pension Obligations	54.3			57.1
Obligations Under Operating Leases	64.8			—
Deferred Credits and Other Noncurrent Liabilities	58.7			58.6
TOTAL NONCURRENT LIABILITIES	7,414.3			6,930.4

TOTAL LIABILITIES	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
Paid-in Capital	1,828.7			1,828.7
Retained Earnings	2,005.7			1,922.0
Accumulated Other Comprehensive Income (Loss)	(5.8		)	(5.0		)
TOTAL COMMON SHAREHOLDER’S EQUITY	4,089.0			4,006.1

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	12,527.4		$	12,290.5



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2019			2018
OPERATING ACTIVITIES
Net Income	$	133.7		$	125.5
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	112.5			108.5
Deferred Income Taxes	(45.0		)	11.0
Allowance for Equity Funds Used During Construction	(1.7		)	(2.6		)
Mark-to-Market of Risk Management Contracts	50.6			14.9
Deferred Fuel Over/Under-Recovery, Net	20.8			(90.7		)
Change in Other Noncurrent Assets	(12.1		)	3.9
Change in Other Noncurrent Liabilities	(20.5		)	37.9
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	19.5			(14.2		)
Fuel, Materials and Supplies	(9.6		)	19.3
Accounts Payable	(8.3		)	(21.6		)
Accrued Taxes, Net	13.7			17.8
Other Current Assets	(0.8		)	(15.8		)
Other Current Liabilities	(2.3		)	5.6
Net Cash Flows from Operating Activities	250.5			199.5

INVESTING ACTIVITIES
Construction Expenditures	(205.1		)	(218.5		)
Change in Advances to Affiliates, Net	(193.6		)	—
Other Investing Activities	15.2			4.4
Net Cash Flows Used for Investing Activities	(383.5		)	(214.1		)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated	393.3			—
Change in Advances from Affiliates, Net	(205.6		)	59.9
Retirement of Long-term Debt – Nonaffiliated	(12.0		)	(11.7		)
Principal Payments for Finance Lease Obligations	(1.6		)	(1.7		)
Dividends Paid on Common Stock	(50.0		)	(40.0		)
Other Financing Activities	0.3			0.2
Net Cash Flows from Financing Activities	124.4			6.7

Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding	(8.6		)	(7.9		)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period	29.8			19.2
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period	$	21.2		$	11.3

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	14.5		$	23.4
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,	87.8			94.5



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

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,
	2019	2018
	(in millions of KWhs)
Retail:
Residential	1,615	1,623
Commercial	1,156	1,164
Industrial	1,888	1,916
Miscellaneous	19	20
Total Retail (a)	4,678	4,723

Wholesale	2,423	2,926

Total KWhs	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,
	2019	2018
	(in degree days)
Actual – Heating (a)	2,239	2,157
Normal – Heating (b)	2,160	2,168

Actual – Cooling (c)	—	—
Normal – Cooling (b)	2	2

(a) Heating degree days are calculated on a 55 degree temperature base.

(b) Normal Heating/Cooling represents the thirty-year average of degree days.

First Quarter of 2019 Compared to First Quarter of 2018



Reconciliation of First Quarter of 2018 to First Quarter of 2019
Net Income
(in millions)

First Quarter of 2018	$	64.2

Changes in Gross Margin:
Retail Margins	56.4
Off-system Sales	(7.3		)
Transmission Revenues	(1.0		)
Other Revenues	(3.1		)
Total Change in Gross Margin	45.0

Changes in Expenses and Other:
Other Operation and Maintenance	1.8
Depreciation and Amortization	(26.9		)
Taxes Other Than Income Taxes	(2.3		)
Other Income	1.3
Non-Service Cost Components of Net Periodic Benefit Cost	(0.1		)
Interest Expense	0.8
Total Change in Expenses and Other	(25.4		)

Income Tax Expense (Benefit)	15.1

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 $56 million primarily due to the following:


•	A $47 million increase from rate proceedings, inclusive of a $9 million decrease due to the impact of Tax Reform. This increase was partially offset in other expense items below.


•	A $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 4% increase in heating degree days.

These increases were partially offset by:


•	A $4 million decrease due to increased costs for power acquired under the UPA between AEGCo and I&M as a result of increased depreciation rates for Rockport Plant approved by the FERC in January 2019.


•	Margins from Off-system Sales decreased $7 million primarily due to mid-year 2018 changes in the OSS sharing mechanism.

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:


•	A $4 million decrease in generation expenses at Cook Plant primarily due to a decrease in various maintenance activities.


•	A $3 million decrease 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. This decrease was partially offset in Retail Margins above.

These decreases were partially offset by:


•	A $4 million increase in distribution costs primarily due to vegetation management expenses.


•	Depreciation and Amortization expenses increased $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.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2019			2018
REVENUES
Electric Generation, Transmission and Distribution	$	596.7		$	553.9
Sales to AEP Affiliates	2.3			4.7
Other Revenues – Affiliated	13.3			13.2
Other Revenues – Nonaffiliated	2.0			5.0
TOTAL REVENUES	614.3			576.8

EXPENSES
Fuel and Other Consumables Used for Electric Generation	57.6			77.5
Purchased Electricity for Resale	69.6			55.6
Purchased Electricity from AEP Affiliates	59.8			61.4
Other Operation	140.5			146.1
Maintenance	58.3			54.5
Depreciation and Amortization	86.2			59.3
Taxes Other Than Income Taxes	27.3			25.0
TOTAL EXPENSES	499.3			479.4

OPERATING INCOME	115.0			97.4

Other Income (Expense):
Other Income	5.7			4.4
Non-Service Cost Components of Net Periodic Benefit Cost	4.4			4.5
Interest Expense	(28.9		)	(29.7		)

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	96.2			76.6

Income Tax Expense (Benefit)	(2.7		)	12.4

NET INCOME	$	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 103.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2019		2018
Net Income	$	98.9	$	64.2

OTHER COMPREHENSIVE INCOME, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 in 2019 and 2018, Respectively	0.4		0.4

TOTAL COMPREHENSIVE INCOME	$	99.3	$	64.6

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017	$	56.6	$	980.9	$	1,192.2		$	(12.1	)	$	2,217.6

Common Stock Dividends					(33.5		)				(33.5		)
ASU 2018-02 Adoption					0.3			(2.7		)	(2.4		)
Net Income					64.2						64.2
Other Comprehensive Income								0.4			0.4
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018	$	56.6	$	980.9	$	1,223.2		$	(14.4	)	$	2,246.3

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 103.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, 2019 and December 31, 2018

(in millions)

(Unaudited)



	March 31,			December 31,
	2019			2018
CURRENT ASSETS
Cash and Cash Equivalents	$	1.7		$	2.4
Advances to Affiliates	12.8			12.7
Accounts Receivable:
Customers	62.9			63.1
Affiliated Companies	55.4			75.0
Accrued Unbilled Revenues	8.1			3.6
Miscellaneous	1.2			1.4
Allowance for Uncollectible Accounts	(0.2		)	(0.1		)
Total Accounts Receivable	127.4			143.0
Fuel	32.0			37.3
Materials and Supplies	166.1			167.3
Risk Management Assets	4.4			8.6
Accrued Tax Benefits	12.0			26.6
Accrued Reimbursement of Spent Nuclear Fuel Costs	23.5			7.9
Prepayments and Other Current Assets	23.4			24.6
TOTAL CURRENT ASSETS	403.3			430.4

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	4,895.0			4,887.2
Transmission	1,588.9			1,576.8
Distribution	2,291.5			2,249.7
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	580.1			583.8
Construction Work in Progress	533.5			465.3
Total Property, Plant and Equipment	9,889.0			9,762.8
Accumulated Depreciation, Depletion and Amortization	3,208.4			3,151.6
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	6,680.6			6,611.2

OTHER NONCURRENT ASSETS
Regulatory Assets	504.7			512.5
Spent Nuclear Fuel and Decommissioning Trusts	2,684.0			2,474.9
Long-term Risk Management Assets	0.1			0.6
Operating Lease Assets	326.3			—
Deferred Charges and Other Noncurrent Assets	171.0			193.0
TOTAL OTHER NONCURRENT ASSETS	3,686.1			3,181.0

TOTAL ASSETS	$	10,770.0		$	10,222.6

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

March 31, 2019 and December 31, 2018

(dollars in millions)

(Unaudited)



	March 31,			December 31,
	2019			2018
CURRENT LIABILITIES
Advances from Affiliates	$	34.7		$	1.1
Accounts Payable:
General	160.3			174.7
Affiliated Companies	70.4			70.2
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	0.3			0.3
Customer Deposits	38.6			38.0
Accrued Taxes	101.7			90.7
Accrued Interest	20.9			37.3
Obligations Under Operating Leases	81.8			—
Regulatory Liability for Over-Recovered Fuel Costs	22.2			27.4
Other Current Liabilities	68.2			103.0
TOTAL CURRENT LIABILITIES	739.5			698.1

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	2,871.0			2,880.0
Long-term Risk Management Liabilities	0.1			0.1
Deferred Income Taxes	951.1			948.0
Regulatory Liabilities and Deferred Investment Tax Credits	1,743.5			1,574.5
Asset Retirement Obligations	1,697.8			1,681.3
Obligations Under Operating Leases	266.0			—
Deferred Credits and Other Noncurrent Liabilities	68.9			87.8
TOTAL NONCURRENT LIABILITIES	7,598.4			7,171.7

TOTAL LIABILITIES	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
Paid-in Capital	980.9			980.9
Retained Earnings	1,408.0			1,329.1
Accumulated Other Comprehensive Income (Loss)	(13.4		)	(13.8		)
TOTAL COMMON SHAREHOLDER’S EQUITY	2,432.1			2,352.8

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	10,770.0		$	10,222.6

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2019			2018
OPERATING ACTIVITIES
Net Income	$	98.9		$	64.2
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	86.2			59.3
Deferred Income Taxes	(13.9		)	13.7
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	(6.2		)	(1.8		)
Mark-to-Market of Risk Management Contracts	4.7			3.4
Amortization of Nuclear Fuel	25.1			27.4
Deferred Fuel Over/Under-Recovery, Net	(5.2		)	3.4
Change in Other Noncurrent Assets	12.8			(11.0		)
Change in Other Noncurrent Liabilities	5.2			33.7
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	16.0			3.5
Fuel, Materials and Supplies	6.6			(4.5		)
Accounts Payable	(3.1		)	1.3
Accrued Taxes, Net	25.6			8.2
Other Current Assets	1.4			(11.1		)
Other Current Liabilities	(35.2		)	(27.8		)
Net Cash Flows from Operating Activities	204.8			147.2

INVESTING ACTIVITIES
Construction Expenditures	(149.3		)	(148.9		)
Change in Advances to Affiliates, Net	(0.1		)	(0.1		)
Purchases of Investment Securities	(130.3		)	(525.3		)
Sales of Investment Securities	111.9			508.6
Acquisitions of Nuclear Fuel	(32.4		)	(23.8		)
Other Investing Activities	8.6			4.2
Net Cash Flows Used for Investing Activities	(191.6		)	(185.3		)

FINANCING ACTIVITIES
Change in Advances from Affiliates, Net	33.6			102.5
Retirement of Long-term Debt – Nonaffiliated	(26.5		)	(29.4		)
Principal Payments for Finance Lease Obligations	(1.2		)	(2.7		)
Dividends Paid on Common Stock	(20.0		)	(33.5		)
Other Financing Activities	0.2			0.5
Net Cash Flows from (Used for) Financing Activities	(13.9		)	37.4

Net Decrease in Cash and Cash Equivalents	(0.7		)	(0.7		)
Cash and Cash Equivalents at Beginning of Period	2.4			1.3
Cash and Cash Equivalents at End of Period	$	1.7		$	0.6

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	43.3		$	50.6
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,	80.0			77.2
Acquisition of Nuclear Fuel Included in Current Liabilities as of March 31,	1.0			0.1
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage	7.9			0.1

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

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,
	2019	2018
	(in millions of KWhs)
Retail:
Residential	4,123	4,133
Commercial	3,527	3,533
Industrial	3,623	3,573
Miscellaneous	31	31
Total Retail (a)(b)	11,304	11,270

Wholesale (c)	638	667

Total KWhs	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.

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,
	2019	2018
	(in degree days)
Actual – Heating (a)	1,892	1,884
Normal – Heating (b)	1,877	1,884

Actual – Cooling (c)	1	4
Normal – Cooling (b)	3	3

(a) Heating degree days are calculated on a 55 degree temperature base.

(b) Normal Heating/Cooling represents the thirty-year average of degree days.

First Quarter of 2019 Compared to First Quarter of 2018



Reconciliation of First Quarter of 2018 to First Quarter of 2019
Net Income
(in millions)

First Quarter of 2018	$	79.6

Changes in Gross Margin:
Retail Margins	75.3
Off-system Sales	(0.8		)
Transmission Revenues	10.4
Other Revenues	2.6
Total Change in Gross Margin	87.5

Changes in Expenses and Other:
Other Operation and Maintenance	(40.0		)
Depreciation and Amortization	1.5
Taxes Other Than Income Taxes	(3.8		)
Interest Income	(0.1		)
Carrying Costs Income	(0.5		)
Allowance for Equity Funds Used During Construction	2.7
Non-Service Cost Components of Net Periodic Benefit Cost	(0.2		)
Interest Expense	0.6
Total Change in Expenses and Other	(39.8		)

Income Tax Expense	0.7

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 $75 million primarily due to the following:


•	A $58 million increase due to a reversal of a regulatory provision.


•	A $17 million net increase in Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset by an increase in Other Operation and Maintenance expenses below.


•	A $10 million increase in revenues associated with 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.

These increases were partially offset by:


•	A $6 million decrease in revenues associated with vegetation management riders. This decrease was offset in Other Operation and Maintenance expenses below.


•	A $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.

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


•	Other Operation and Maintenance expenses increased $40 million primarily due to the following:


•	A $31 million increase in recoverable PJM expenses. This increase was offset within Gross Margins above.


•	A $10 million increase in PJM expenses primarily related to the 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 $5 million decrease in recoverable distribution expenses related to vegetation management. This decrease was partially offset in Retail Margins above.


•	Depreciation and Amortization expenses decreased $2 million primarily due to the following:


•	A $10 million decrease in recoverable DIR depreciation expense. This decrease was partially offset in Retail Margins above.

This decrease was offset by:


•	A $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.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2019			2018
REVENUES
Electricity, Transmission and Distribution	$	826.5		$	786.3
Sales to AEP Affiliates	7.5			3.1
Other Revenues	2.8			1.5
TOTAL REVENUES	836.8			790.9

EXPENSES
Purchased Electricity for Resale	174.2			205.5
Purchased Electricity from AEP Affiliates	46.1			30.2
Amortization of Generation Deferrals	32.4			58.6
Other Operation	216.9			172.2
Maintenance	32.5			37.2
Depreciation and Amortization	63.3			64.8
Taxes Other Than Income Taxes	108.9			105.1
TOTAL EXPENSES	674.3			673.6

OPERATING INCOME	162.5			117.3

Other Income (Expense):
Interest Income	0.8			0.9
Carrying Costs Income	0.2			0.7
Allowance for Equity Funds Used During Construction	5.2			2.5
Non-Service Cost Components of Net Periodic Benefit Cost	3.7			3.9
Interest Expense	(24.6		)	(25.2		)

INCOME BEFORE INCOME TAX EXPENSE	147.8			100.1

Income Tax Expense	19.8			20.5

NET INCOME	$	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 103.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2019			2018
Net Income	$	128.0		$	79.6

OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) in 2019 and 2018, Respectively	(0.3		)	(0.3		)

TOTAL COMPREHENSIVE INCOME	$	127.7		$	79.3

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017	$	321.2	$	838.8	$	1,148.4		$	1.9		$	2,310.3

Common Stock Dividends					(112.5		)				(112.5		)
ASU 2018-02 Adoption								0.4			0.4
Net Income					79.6						79.6
Other Comprehensive Loss								(0.3		)	(0.3		)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018	$	321.2	$	838.8	$	1,115.5		$	2.0		$	2,277.5

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 103.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, 2019 and December 31, 2018

(in millions)

(Unaudited)



	March 31,			December 31,
	2019			2018
CURRENT ASSETS
Cash and Cash Equivalents	$	3.3		$	4.9
Restricted Cash for Securitized Funding	16.5			27.6
Accounts Receivable:
Customers	89.4			111.1
Affiliated Companies	55.9			70.8
Accrued Unbilled Revenues	27.1			21.4
Miscellaneous	0.4			0.3
Allowance for Uncollectible Accounts	(0.6		)	(1.0		)
Total Accounts Receivable	172.2			202.6
Materials and Supplies	42.9			42.9
Renewable Energy Credits	27.1			25.9
Prepayments and Other Current Assets	15.1			15.7
TOTAL CURRENT ASSETS	277.1			319.6

PROPERTY, PLANT AND EQUIPMENT
Electric:
Transmission	2,551.7			2,544.3
Distribution	5,026.6			4,942.3
Other Property, Plant and Equipment	580.0			574.8
Construction Work in Progress	461.0			432.1
Total Property, Plant and Equipment	8,619.3			8,493.5
Accumulated Depreciation and Amortization	2,224.1			2,218.6
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	6,395.2			6,274.9

OTHER NONCURRENT ASSETS
Regulatory Assets	375.0			387.5
Securitized Assets	7.3			12.9
Deferred Charges and Other Noncurrent Assets	464.2			441.0
TOTAL OTHER NONCURRENT ASSETS	846.5			841.4

TOTAL ASSETS	$	7,518.8		$	7,435.9



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

March 31, 2019 and December 31, 2018

(dollars in millions)

(Unaudited)



	March 31,		December 31,
	2019		2018
CURRENT LIABILITIES
Advances from Affiliates	$	227.6	$	114.1
Accounts Payable:
General	177.7		211.9
Affiliated Companies	91.1		102.9
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	6.9		5.8
Customer Deposits	103.1		113.1
Accrued Taxes	423.4		537.8
Obligations Under Operating Leases	13.0		—
Other Current Liabilities	147.2		214.2
TOTAL CURRENT LIABILITIES	1,214.6		1,347.7

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	1,669.0		1,668.7
Long-term Risk Management Liabilities	99.4		93.8
Deferred Income Taxes	782.3		763.3
Regulatory Liabilities and Deferred Investment Tax Credits	1,234.4		1,221.2
Obligations Under Operating Leases	74.0		—
Deferred Credits and Other Noncurrent Liabilities	45.0		43.8
TOTAL NONCURRENT LIABILITIES	3,904.1		3,790.8

TOTAL LIABILITIES	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
Paid-in Capital	838.8		838.8
Retained Earnings	1,239.4		1,136.4
Accumulated Other Comprehensive Income (Loss)	0.7		1.0
TOTAL COMMON SHAREHOLDER’S EQUITY	2,400.1		2,297.4

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 103.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2019			2018
OPERATING ACTIVITIES
Net Income	$	128.0		$	79.6
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	63.3			64.8
Amortization of Generation Deferrals	32.4			58.6
Deferred Income Taxes	10.1			(4.9		)
Carrying Costs Income	(0.2		)	(0.7		)
Allowance for Equity Funds Used During Construction	(5.2		)	(2.5		)
Mark-to-Market of Risk Management Contracts	6.7			(33.7		)
Property Taxes	66.0			62.9
Provision for Refund – Global Settlement	(4.1		)	(5.4		)
Reversal of a Regulatory Provision	(56.2		)	—
Change in Other Noncurrent Assets	(7.3		)	14.3
Change in Other Noncurrent Liabilities	17.6			40.6
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	31.7			38.8
Materials and Supplies	(3.4		)	(1.9		)
Accounts Payable	(23.9		)	(22.5		)
Accrued Taxes, Net	(114.4		)	(92.8		)
Other Current Assets	(7.7		)	(7.5		)
Other Current Liabilities	(16.2		)	(2.9		)
Net Cash Flows from Operating Activities	117.2			184.8

INVESTING ACTIVITIES
Construction Expenditures	(198.5		)	(168.2		)
Change in Advances to Affiliates, Net	—			(200.4		)
Other Investing Activities	3.7			1.7
Net Cash Flows Used for Investing Activities	(194.8		)	(366.9		)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated	—			393.3
Change in Advances from Affiliates, Net	113.5			(87.8		)
Retirement of Long-term Debt – Nonaffiliated	(23.4		)	(22.9		)
Principal Payments for Finance Lease Obligations	(0.7		)	(0.9		)
Dividends Paid on Common Stock	(25.0		)	(112.5		)
Other Financing Activities	0.5			0.5
Net Cash Flows from Financing Activities	64.9			169.7

Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding	(12.7		)	(12.4		)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period	32.5			29.7
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period	$	19.8		$	17.3

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	17.0		$	17.0
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,	72.8			52.3



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

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,
	2019	2018
	(in millions of KWhs)
Retail:
Residential	1,520	1,493
Commercial	1,089	1,083
Industrial	1,433	1,419
Miscellaneous	274	276
Total Retail (a)	4,316	4,271

Wholesale	245	157

Total KWhs	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,
	2019	2018
	(in degree days)
Actual – Heating (a)	1,171	1,032
Normal – Heating (b)	1,032	1,041

Actual – Cooling (c)	3	12
Normal – Cooling (b)	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.

First Quarter of 2019 Compared to First Quarter of 2018



Reconciliation of First Quarter of 2018 to First Quarter of 2019
Net Income (Loss)
(in millions)

First Quarter of 2018	$	(7.2	)

Changes in Gross Margin:
Retail Margins (a)	5.8
Off-system Sales	0.1
Transmission Revenues	(1.4		)
Other Revenues	1.4
Total Change in Gross Margin	5.9

Changes in Expenses and Other:
Other Operation and Maintenance	17.6
Depreciation and Amortization	(6.7		)
Taxes Other Than Income Taxes	0.2
Other Income	0.1
Non-Service Cost Components of Net Periodic Benefit Cost	(0.1		)
Interest Expense	(2.2		)
Total Change in Expenses and Other	8.9

Income Tax Benefit	(1.4		)

First Quarter of 2019	$	6.2


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

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


•	Retail Margins increased $6 million primarily due to the following:


•	An $11 million increase due to new base rates implemented in March 2018.


•	A $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 was partially offset in other expense items below.

These increases were partially offset by:


•	An $8 million decrease due to lower weather-normalized margins.

Expenses and Other changed between years as follows:


•	Other Operation and Maintenance expenses decreased $18 million primarily due to the following:


•	A $5 million decrease in transmission expenses primarily due to a decrease in SPP transmission services.


•	A $5 million decrease in Energy Efficiency program costs due to a change in the amortizations of costs approved by the OCC.


•	A $5 million decrease in distribution expenses related to vegetation management.


•	A $4 million decrease due to 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.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF OPERATIONS

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2019			2018
REVENUES
Electric Generation, Transmission and Distribution	$	329.2		$	335.1
Sales to AEP Affiliates	1.6			1.1
Other Revenues	2.0			0.6
TOTAL REVENUES	332.8			336.8

EXPENSES
Fuel and Other Consumables Used for Electric Generation	38.0			48.4
Purchased Electricity for Resale	122.9			122.4
Other Operation	73.6			86.8
Maintenance	22.5			26.9
Depreciation and Amortization	43.5			36.8
Taxes Other Than Income Taxes	11.4			11.6
TOTAL EXPENSES	311.9			332.9

OPERATING INCOME	20.9			3.9

Other Income (Expense):
Other Income	0.1			—
Non-Service Cost Components of Net Periodic Benefit Cost	2.1			2.2
Interest Expense	(16.9		)	(14.7		)

INCOME (LOSS) BEFORE INCOME TAX BENEFIT	6.2			(8.6		)

Income Tax Benefit	—			(1.4		)

NET INCOME (LOSS)	$	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 103.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2019			2018
Net Income (Loss)	$	6.2		$	(7.2	)

OTHER COMPREHENSIVE LOSS, NET OF TAXES
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)	$	6.0		$	(7.4	)



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017	$	157.2	$	364.0	$	691.5		$	2.6		$	1,215.3

Common Stock Dividends					(12.5		)				(12.5		)
ASU 2018-02 Adoption								0.5			0.5
Net Loss					(7.2		)				(7.2		)
Other Comprehensive Loss								(0.2		)	(0.2		)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018	$	157.2	$	364.0	$	671.8		$	2.9		$	1,195.9

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 103.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED BALANCE SHEETS

ASSETS

March 31, 2019 and December 31, 2018

(in millions)

(Unaudited)



	March 31,			December 31,
	2019			2018
CURRENT ASSETS
Cash and Cash Equivalents	$	1.5		$	2.0
Accounts Receivable:
Customers	35.7			32.5
Affiliated Companies	24.3			26.2
Miscellaneous	3.6			5.7
Allowance for Uncollectible Accounts	(0.4		)	(0.1		)
Total Accounts Receivable	63.2			64.3
Fuel	10.0			12.3
Materials and Supplies	43.9			44.8
Risk Management Assets	5.0			10.4
Accrued Tax Benefits	9.5			14.7
Prepayments and Other Current Assets	12.7			9.4
TOTAL CURRENT ASSETS	145.8			157.9

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	1,568.6			1,577.0
Transmission	899.8			892.3
Distribution	2,600.1			2,572.8
Other Property, Plant and Equipment	306.0			303.5
Construction Work in Progress	98.6			94.0
Total Property, Plant and Equipment	5,473.1			5,439.6
Accumulated Depreciation and Amortization	1,496.2			1,472.9
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	3,976.9			3,966.7

OTHER NONCURRENT ASSETS
Regulatory Assets	365.1			369.0
Employee Benefits and Pension Assets	32.0			31.7
Operating Lease Assets	34.8			—
Deferred Charges and Other Noncurrent Assets	37.9			7.1
TOTAL OTHER NONCURRENT ASSETS	469.8			407.8

TOTAL ASSETS	$	4,592.5		$	4,532.4



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

March 31, 2019 and December 31, 2018

(Unaudited)



	March 31,		December 31,
	2019		2018
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	55.2	$	105.5
Accounts Payable:
General	90.1		126.9
Affiliated Companies	45.9		47.1
Long-term Debt Due Within One Year – Nonaffiliated	375.5		375.5
Risk Management Liabilities	0.7		1.0
Customer Deposits	59.2		58.6
Accrued Taxes	42.5		22.4
Obligations Under Operating Leases	5.7		—
Regulatory Liability for Over-Recovered Fuel Costs	17.7		20.1
Other Current Liabilities	63.5		64.5
TOTAL CURRENT LIABILITIES	756.0		821.6

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	1,010.7		911.5
Deferred Income Taxes	610.6		607.8
Regulatory Liabilities and Deferred Investment Tax Credits	861.2		864.7
Asset Retirement Obligations	47.9		46.3
Obligations Under Operating Leases	29.1		—
Deferred Credits and Other Noncurrent Liabilities	34.3		32.5
TOTAL NONCURRENT LIABILITIES	2,593.8		2,462.8

TOTAL LIABILITIES	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
Paid-in Capital	364.0		364.0
Retained Earnings	719.6		724.7
Accumulated Other Comprehensive Income (Loss)	1.9		2.1
TOTAL COMMON SHAREHOLDER’S EQUITY	1,242.7		1,248.0

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	4,592.5	$	4,532.4



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2019			2018
OPERATING ACTIVITIES
Net Income (Loss)	$	6.2		$	(7.2	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities:
Depreciation and Amortization	43.5			36.8
Deferred Income Taxes	(5.8		)	(4.5		)
Allowance for Equity Funds Used During Construction	(0.1		)	0.1
Mark-to-Market of Risk Management Contracts	5.1			3.5
Property Taxes	(29.9		)	(30.1		)
Deferred Fuel Over/Under-Recovery, Net	(2.4		)	14.6
Change in Other Noncurrent Assets	8.0			—
Change in Other Noncurrent Liabilities	(0.7		)	5.7
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	2.0			6.9
Fuel, Materials and Supplies	3.2			(1.7		)
Accounts Payable	(23.3		)	(10.9		)
Accrued Taxes, Net	25.3			22.4
Other Current Assets	(3.8		)	0.9
Other Current Liabilities	4.4			(1.3		)
Net Cash Flows from Operating Activities	31.7			35.2

INVESTING ACTIVITIES
Construction Expenditures	(70.7		)	(54.4		)
Other Investing Activities	0.4			2.0
Net Cash Flows Used for Investing Activities	(70.3		)	(52.4		)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated	99.9			—
Change in Advances from Affiliates, Net	(50.3		)	29.5
Retirement of Long-term Debt – Nonaffiliated	(0.1		)	(0.1		)
Principal Payments for Finance Lease Obligations	(0.7		)	(1.0		)
Dividends Paid on Common Stock	(11.3		)	(12.5		)
Other Financing Activities	0.6			0.3
Net Cash Flows from Financing Activities	38.1			16.2

Net Decrease in Cash and Cash Equivalents	(0.5		)	(1.0		)
Cash and Cash Equivalents at Beginning of Period	2.0			1.6
Cash and Cash Equivalents at End of Period	$	1.5		$	0.6

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	10.9		$	10.3
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,	15.6			25.4



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

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,
	2019	2018
	(in millions of KWhs)
Retail:
Residential	1,528	1,558
Commercial	1,273	1,310
Industrial	1,250	1,177
Miscellaneous	20	19
Total Retail (a)	4,071	4,064

Wholesale	1,979	1,908

Total KWhs	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,
	2019	2018
	(in degree days)
Actual – Heating (a)	708	729
Normal – Heating (b)	698	707

Actual – Cooling (c)	20	60
Normal – Cooling (b)	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.

First Quarter of 2019 Compared to First Quarter of 2018



Reconciliation of First Quarter of 2018 to First Quarter of 2019
Earnings Attributable to SWEPCo Common Shareholder
(in millions)

First Quarter of 2018	$	11.8

Changes in Gross Margin:
Retail Margins (a)	6.1
Off-system Sales	0.6
Transmission Revenues	(1.7		)
Other Revenues	0.1
Total Change in Gross Margin	5.1

Changes in Expenses and Other:
Other Operation and Maintenance	12.4
Depreciation and Amortization	(4.7		)
Taxes Other Than Income Taxes	(0.3		)
Interest Income	(1.1		)
Allowance for Equity Funds Used During Construction	(0.5		)
Non-Service Cost Components of Net Periodic Benefit Cost	(0.2		)
Interest Expense	2.5
Total Change in Expenses and Other	8.1

Income Tax Expense	2.2
Equity Earnings of Unconsolidated Subsidiary	0.2
Net Income Attributable to Noncontrolling Interest	0.4

First Quarter of 2019	$	27.8


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


•	Retail Margins increased $6 million primarily due to the following:


•	A $4 million increase primarily due to rider and base rate revenue increases in Louisiana. This increase was partially offset by corresponding increases in other expense items below.


•	A $4 million increase due to higher weather-normalized margins.

These increases were partially offset by:


•	A $3 million decrease in weather-related usage primarily due to a 67% decrease in cooling degree days and a 3% decrease in 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.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2019			2018
REVENUES
Electric Generation, Transmission and Distribution	$	414.3		$	413.0
Sales to AEP Affiliates	6.4			6.1
Other Revenues	0.4			0.3
TOTAL REVENUES	421.1			419.4

EXPENSES
Fuel and Other Consumables Used for Electric Generation	133.5			126.8
Purchased Electricity for Resale	32.6			42.7
Other Operation	84.6			94.9
Maintenance	28.9			31.0
Depreciation and Amortization	62.1			57.4
Taxes Other Than Income Taxes	25.3			25.0
TOTAL EXPENSES	367.0			377.8

OPERATING INCOME	54.1			41.6

Other Income (Expense):
Interest Income	0.7			1.8
Allowance for Equity Funds Used During Construction	1.8			2.3
Non-Service Cost Components of Net Periodic Benefit Cost	2.1			2.3
Interest Expense	(29.7		)	(32.2		)

INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	29.0			15.8

Income Tax Expense	0.7			2.9
Equity Earnings of Unconsolidated Subsidiary	0.7			0.5

NET INCOME	29.0			13.4

Net Income Attributable to Noncontrolling Interest	1.2			1.6

EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER	$	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 103.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2019			2018
Net Income	$	29.0		$	13.4

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 in 2019 and 2018, Respectively	0.4			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 INCOME	0.1			0.1

TOTAL COMPREHENSIVE INCOME	29.1			13.5

Total Comprehensive Income Attributable to Noncontrolling Interest	1.2			1.6

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER	$	27.9		$	11.9



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	SWEPCo Common Shareholder
	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total
TOTAL EQUITY – DECEMBER 31, 2017	$	135.7	$	676.6	$	1,426.6		$	(4.0	)	$	(0.4	)	$	2,234.5

Common Stock Dividends					(20.0		)							(20.0		)
Common Stock Dividends – Nonaffiliated											(0.8		)	(0.8		)
ASU 2018-02 Adoption					(0.4		)	(0.9		)				(1.3		)
Net Income					11.8						1.6			13.4
Other Comprehensive Income								0.1						0.1
TOTAL EQUITY – MARCH 31, 2018	$	135.7	$	676.6	$	1,418.0		$	(4.8	)	$	0.4		$	2,225.9

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 103.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, 2019 and December 31, 2018

(in millions)

(Unaudited)



	March 31,			December 31,
	2019			2018
CURRENT ASSETS
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			83.4
Accounts Receivable:
Customers	32.0			24.5
Affiliated Companies	20.0			28.8
Miscellaneous	18.2			20.2
Allowance for Uncollectible Accounts	(1.2		)	(0.7		)
Total Accounts Receivable	69.0			72.8
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	69.1			67.5
Risk Management Assets	2.0			4.8
Regulatory Asset for Under-Recovered Fuel Costs	15.6			18.8
Prepayments and Other Current Assets	31.3			22.2
TOTAL CURRENT ASSETS	346.2			414.5

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	4,711.6			4,672.6
Transmission	1,907.2			1,866.9
Distribution	2,204.9			2,178.6
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	193.4			199.3
Total Property, Plant and Equipment	9,676.0			9,680.1
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	6,915.4			6,871.8

OTHER NONCURRENT ASSETS
Regulatory Assets	226.6			230.8
Deferred Charges and Other Noncurrent Assets	193.8			111.2
TOTAL OTHER NONCURRENT ASSETS	420.4			342.0

TOTAL ASSETS	$	7,682.0		$	7,628.3



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

100

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

March 31, 2019 and December 31, 2018

(Unaudited)



	March 31,			December 31,
	2019			2018
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	74.0		$	—
Accounts Payable:
General	98.6			129.1
Affiliated Companies	45.8			64.2
Long-term Debt Due Within One Year – Nonaffiliated	6.2			59.7
Risk Management Liabilities	0.2			0.4
Customer Deposits	65.6			64.5
Accrued Taxes	91.1			42.8
Accrued Interest	22.0			34.7
Obligations Under Finance Leases	10.6			10.2
Obligations Under Operating Leases	6.1			—
Other Current Liabilities	87.0			107.3
TOTAL CURRENT LIABILITIES	507.2			512.9

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	2,652.9			2,653.7
Long-term Risk Management Liabilities	1.9			2.2
Deferred Income Taxes	910.1			902.8
Regulatory Liabilities and Deferred Investment Tax Credits	922.7			923.0
Asset Retirement Obligations	197.0			191.3
Employee Benefits and Pension Obligations	23.7			24.8
Obligations Under Finance Leases	49.3			50.6
Obligations Under Operating Leases	32.3			—
Deferred Credits and Other Noncurrent Liabilities	60.0			51.4
TOTAL NONCURRENT LIABILITIES	4,849.9			4,799.8

TOTAL LIABILITIES	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
Paid-in Capital	676.6			676.6
Retained Earnings	1,517.5			1,508.4
Accumulated Other Comprehensive Income (Loss)	(5.3		)	(5.4		)
TOTAL COMMON SHAREHOLDER’S EQUITY	2,324.5			2,315.3

Noncontrolling Interest	0.4			0.3

TOTAL EQUITY	2,324.9			2,315.6

TOTAL LIABILITIES AND EQUITY	$	7,682.0		$	7,628.3



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

101

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2019 and 2018

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2019			2018
OPERATING ACTIVITIES
Net Income	$	29.0		$	13.4
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	62.1			57.4
Deferred Income Taxes	(2.5		)	1.0
Allowance for Equity Funds Used During Construction	(1.8		)	(2.3		)
Mark-to-Market of Risk Management Contracts	2.3			5.1
Property Taxes	(48.9		)	(48.8		)
Deferred Fuel Over/Under-Recovery, Net	10.3			(4.6		)
Change in Other Noncurrent Assets	2.9			1.3
Change in Other Noncurrent Liabilities	7.9			18.8
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	6.3			27.9
Fuel, Materials and Supplies	(16.2		)	2.2
Accounts Payable	(55.0		)	(24.6		)
Accrued Taxes, Net	52.7			55.2
Accrued Interest	(12.7		)	(13.0		)
Other Current Assets	(10.0		)	(0.8		)
Other Current Liabilities	(17.0		)	(12.5		)
Net Cash Flows from Operating Activities	9.4			75.7

INVESTING ACTIVITIES
Construction Expenditures	(86.6		)	(139.7		)
Change in Advances to Affiliates, Net	81.4			—
Other Investing Activities	(3.1		)	(5.4		)
Net Cash Flows Used for Investing Activities	(8.3		)	(145.1		)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated	—			444.6
Change in Short-term Debt, Net – Nonaffiliated	—			0.6
Change in Advances from Affiliates, Net	74.0			29.9
Retirement of Long-term Debt – Nonaffiliated	(55.1		)	(383.4		)
Principal Payments for Finance Lease Obligations	(2.7		)	(2.8		)
Dividends Paid on Common Stock	(18.7		)	(20.0		)
Dividends Paid on Common Stock – Nonaffiliated	(1.1		)	(0.8		)
Other Financing Activities	0.1			0.4
Net Cash Flows from (Used for) Financing Activities	(3.5		)	68.5

Net Decrease in Cash and Cash Equivalents	(2.4		)	(0.9		)
Cash and Cash Equivalents at Beginning of Period	24.5			1.6
Cash and Cash Equivalents at End of Period	$	22.1		$	0.7

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	40.5		$	43.7
Net Cash Paid (Received) for Income Taxes	0.2			(0.1		)
Noncash Acquisitions Under Finance Leases	0.8			1.9
Construction Expenditures Included in Current Liabilities as of March 31,	44.8			50.3



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 103.

102

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	104
New Accounting Pronouncements	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	107
Comprehensive Income	AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo	109
Rate Matters	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	116
Commitments, Guarantees and Contingencies	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	126
Acquisitions and Impairments	AEP, APCo	129
Benefit Plans	AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo	130
Business Segments	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	132
Derivatives and Hedging	AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo	137
Fair Value Measurements	AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo	148
Income Taxes	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	163
Leases	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	166
Financing Activities	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	171
Revenue from Contracts with Customers	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	178

103

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, 2019 is not necessarily indicative of results that may be expected for the year ending December 31, 2019. The condensed financial statements are unaudited and should be read in conjunction with the audited 2018 financial statements and notes thereto, which are included in the Registrants’ Annual Reports on Form 10-K as filed with the SEC on February 21, 2019.

Earnings Per Share (EPS) (Applies to AEP)

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

The following 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 Outstanding	493.3		$	1.16	492.3		$	0.92
Weighted Average Dilutive Effect of Stock-Based Awards	1.2		—		0.8		—
Weighted Average Number of Diluted Shares Outstanding	494.5		$	1.16	493.1		$	0.92

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, 2019 and 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, 2019
	AEP		AEP Texas		APCo		OPCo
	(in millions)
Cash and Cash Equivalents	$	227.7	$	0.1	$	2.9	$	3.3
Restricted Cash	135.4		100.6		18.3		16.5
Total Cash, Cash Equivalents and Restricted Cash	$	363.1	$	100.7	$	21.2	$	19.8

104



	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

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.

105

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.

106

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 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 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.

New leasing standard implementation activities included the identification of the lease population within the AEP System as well as the sampling of representative lease contracts to analyze accounting treatment under the new accounting guidance. Based upon the completed assessments, management also prepared a gap analysis to outline new disclosure compliance requirements.

Management adopted ASU 2016-02 effective January 1, 2019 by means of a cumulative-effect adjustment to the balance sheet. Management elected the following practical expedients upon adoption:



Practical Expedient		Description
Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package)		Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases.
Lease and Non-lease Components (elect by class of underlying asset)		Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component.
Short-term Lease (elect by class of underlying asset)		Elect as an accounting policy to not apply the recognition requirements to short-term leases.
Existing and expired land easements not previously accounted for as leases		Elect optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840.
Cumulative-effect adjustment in the period of adoption		Elect 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.

Management concluded that the result of adoption would not materially change the volume of contracts that qualify as leases going forward. The adoption of the new standard did not materially impact results of operations or cash flows, but did have a material impact on the balance sheet. See Note 12 - Leases for additional disclosures required by the new standard.

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

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

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period

107

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

In August 2018, the FASB issued ASU 2018-15 aligning the requirements for capitalizing implementation costs incurred in a cloud computing arrangement (hosting arrangement) that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The new standard requires an entity (customer) in a hosting arrangement that is a service contract to follow the accounting guidance for “Internal-Use Software” to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. To eliminate diversity in practice, the new standard changes the presentation of implementation costs for cloud service arrangements that are service contracts without the purchase of a license. Implementation costs for cloud service contracts will be presented on the balance sheets in the same manner as a prepayment. The Registrants currently present implementation costs in property, plant and equipment on the 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 term of the cloud service arrangement, rather than Depreciation and Amortization expense on the statements of income. Payments for capitalized implementation costs in the statement of cash flows will be 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, 2019, with early adoption permitted. The amendments may be applied either retrospectively or prospectively to applicable implementation costs incurred after the date of adoption. Management is analyzing the impact of this new standard and at this time, cannot estimate the impact of adoption on results of operations, financial position or cash flows. Management plans to adopt ASU 2018-15 prospectively, effective January 1, 2020.

108

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, 2019 and 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, 2019



	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) Benefit	12.3			0.2			(1.8		)	10.7
Income Tax (Expense) Benefit	2.6			—			(0.4		)	2.2
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	9.7			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	)

AEP

Changes in Accumulated Other Comprehensive Income (Loss) by Component

For the Three Months Ended March 31, 2018



	Cash Flow Hedges
	Commodity			Interest Rate			Securities Available for Sale			Pension and OPEB			Total
	(in millions)
Balance in AOCI as of December 31, 2017	$	(28.4	)	$	(13.0	)	$	11.9		$	(38.3	)	$	(67.8	)
Change in Fair Value Recognized in AOCI	12.8			—			—			—			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	)

109

AEP Texas

Changes in Accumulated Other Comprehensive Income (Loss) by Component

For the Three Months Ended March 31, 2019



		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	)

AEP Texas

Changes in Accumulated Other Comprehensive Income (Loss) by Component

For the Three Months Ended March 31, 2018



		Cash Flow Hedge – Interest Rate			Pension and OPEB			Total
	(in millions)
Balance in AOCI as of December 31, 2017		$	(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	)

110

APCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component

For the Three Months Ended March 31, 2019



	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	)

APCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component

For the Three Months Ended March 31, 2018



	Cash Flow Hedges
	Commodity			Interest Rate			Pension and OPEB			Total
	(in millions)
Balance in AOCI as of December 31, 2017	$	—		$	2.2		$	(0.9	)	$	1.3
Change in Fair Value Recognized in AOCI	(0.7		)	—			—			(0.7		)
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity for Resale (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

111

I&M

Changes in Accumulated Other Comprehensive Income (Loss) by Component

For the Three Months Ended March 31, 2019



	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	)

I&M

Changes in Accumulated Other Comprehensive Income (Loss) by Component

For the Three Months Ended March 31, 2018



	Cash Flow Hedge – Interest Rate			Pension and OPEB			Total
	(in millions)
Balance in AOCI as of December 31, 2017	$	(10.7	)	$	(1.4	)	$	(12.1	)
Change in Fair Value Recognized in AOCI	—			—			—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (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	)

112

OPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component

For the Three Months Ended March 31, 2019



	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

OPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component

For the Three Months Ended March 31, 2018



		Cash Flow Hedge – Interest Rate
	(in millions)
Balance in AOCI as of December 31, 2017		$	1.9
Change in Fair Value Recognized in AOCI		—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (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

113

PSO

Changes in Accumulated Other Comprehensive Income (Loss) by Component

For the Three Months Ended March 31, 2019



	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

PSO

Changes in Accumulated Other Comprehensive Income (Loss) by Component

For the Three Months Ended March 31, 2018



	Cash Flow Hedge – Interest Rate
	(in millions)
Balance in AOCI as of December 31, 2017	$	2.6
Change in Fair Value Recognized in AOCI	—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (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

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SWEPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component

For the Three Months Ended March 31, 2019



	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	)

SWEPCo

Changes in Accumulated Other Comprehensive Income (Loss) by Component

For the Three Months Ended March 31, 2018



	Cash Flow Hedge – Interest Rate			Pension and OPEB			Total
	(in millions)
Balance in AOCI as of December 31, 2017	$	(6.0	)	$	2.0		$	(4.0	)
Change in Fair Value Recognized in AOCI	—			—			—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (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.

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4. RATE MATTERS

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

As discussed in the 2018 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2018 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 rate-making developments in 2019 and updates the 2018 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)



	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


(a)	As of March 31, 2019, AEP Texas has deferred $137 million related to Hurricane 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.

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	AEP Texas
	March 31,		December 31,
	2019		2018
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Not Earning a Return
Storm-Related Costs (a)	$	152.0	$	152.4
Rate Case Expense	0.4		0.2
Total Regulatory Assets Pending Final Regulatory Approval	$	152.4	$	152.6


(a)	As of March 31, 2019, AEP Texas has deferred $137 million related to Hurricane 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

(a)



	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



	OPCo
	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	$	0.1	$	1.0
Total Regulatory Assets Pending Final Regulatory Approval	$	0.1	$	1.0

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	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,
	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.

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

AEP Texas Interim Transmission and Distribution Rates

As of March 31, 2019, AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2018, subject to review, are estimated to be $1.1 billion. A base rate review could result 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 2018, the PUCT adopted a rule requiring investor-owned utilities operating solely within ERCOT to make periodic filings for rate proceedings. The rule requires AEP Texas to file for a comprehensive rate review no later than May 1, 2019.

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

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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. See the table below for details of the request:



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 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 these costs are not recovered, it could have an adverse effect on future net income, cash flows and financial condition.

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

Virginia Legislation Affecting Earnings Reviews

Under a 2015 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. The 2015 amendments also precluded the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017.

New Virginia legislation impacting investor-owned utilities was enacted, effective July 1, 2018, that 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”). 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 for the 2017-2019 triennial period and rate adjustment clauses from November 2018 through November 2020. Management has reviewed APCo’s actual and forecasted earnings for the triennial period and concluded that it is not probable but is reasonably possible that APCo will over-earn in Virginia during the 2017-2019 triennial period. Due to various uncertainties, including weather, storm restoration, weather-normalized demand and potential customer shopping during 2019, management cannot estimate a range of potential APCo Virginia over-earnings during the 2017-2019 triennial period. The Virginia triennial review of 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.

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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 million related 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, 2019, AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $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 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)

Michigan Tax Reform

In October 2018, I&M made a filing with the MPSC recommending to: (a) refund approximately $68 million of Excess ADIT associated with certain depreciable property using ARAM and (b) refund approximately $37 million of Excess ADIT that is not subject to rate normalization requirements over ten years. An order from the MPSC regarding Excess ADIT is expected in the second half of 2019.

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OPCo Rate Matters (Applies to AEP and OPCo)

Ohio Electric Security Plan Filings

ESP Extension through 2024

In 2016, OPCo refiled its amended ESP extension application and supporting testimony, consistent with the terms of the modified and approved stipulation agreement and based upon a 2016 PUCO order. The amended filing proposed to extend the ESP through May 2024.

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

In April 2018, the PUCO issued an order approving the ESP extension stipulation agreement, with no significant changes. In 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 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 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 $58 million provision in the first quarter of 2019.

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PSO Rate Matters (Applies to AEP and PSO)

2018 Oklahoma Base Rate Case

In October 2018, PSO filed a request with the OCC for an $88 million annual increase in Oklahoma retail rates based upon a 10.3% return on common equity. PSO also proposed to implement a performance-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 disallowance in 2013. The resulting annual base rate increase was approximately $52 million. In 2017, the Texas District Court upheld the PUCT’s 2014 order and intervenors filed appeals with the Texas Third Court of Appeals.

In July 2018, the Texas Third Court of Appeals reversed the PUCT’s judgment affirming the prudence of the Turk Plant and remanded the issue back to the PUCT. In August 2018, SWEPCo filed a Motion for Reconsideration at the Court of Appeals, which was denied. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court, 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.

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2016 Texas Base Rate Case

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

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

2018 Louisiana Formula Rate Filing

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

In July 2018, SWEPCo made a supplemental filing to its formula rate plan with the LPSC to reduce the requested annual increase to $18 million. The difference between SWEPCo’s requested $28 million annual increase and the $18 million annual increase in the supplemental filing is primarily the result of the return of Excess ADIT benefits to customers.

In October 2018, the LPSC staff issued a recommendation that SWEPCo refund $11 million of excess federal income taxes collected, as a result of Tax Reform, from January 1, 2018 through July 31, 2018. A decision by the LPSC is expected in 2019.

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

Welsh Plant - Environmental Impact

Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could total approximately $550 million, excluding AFUDC. As of March 31, 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, 2019, the total net book value of Welsh Plant, Units 1 and 3 was $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 2017, the LPSC approved recovery of $131 million in investments related to its Louisiana jurisdictional share of environmental controls installed at Welsh Plant. SWEPCo’s approved Louisiana jurisdictional share of Welsh Plant deferrals: (a) are $10 million, excluding $5 million of unrecognized equity as of March 31, 2019, (b) is subject to review by the LPSC

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and (c) includes a weighted average cost of capital return on environmental investments and the related depreciation expense and taxes. See “2018 Louisiana Formula Rate Filing” 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

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

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

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.

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

In 2017, several parties filed a complaint at the FERC that states the base return on common equity used by AEP’s transmission owning subsidiaries within SPP in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36%, effective upon the date of the complaint through September 5, 2018. 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.

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

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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 Registrants’ 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 2018 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-parties unless specified below.

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

Standby letters of credit are entered into with 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 $4 billion revolving credit facility due in June 2022, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of March 31, 2019, no letters of credit were issued under the revolving credit facility.



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

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

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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 commits SWEPCo to complete the reclamation, in the event, Sabine does not complete the work. This guarantee ends upon depletion of reserves and completion of reclamation. The reserves are estimated to deplete in 2036 with reclamation completed by 2046 at an estimated cost of $107 million. Actual reclamation costs could vary due to inflation and scope changes to the mine reclamation. As of March 31, 2019, SWEPCo has collected $76 million through a rider for reclamation costs, of which $82 million was recorded in Asset Retirement Obligations, offset by $6 million recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets.

Sabine charges all of its costs to its only customer, SWEPCo, which recovers these costs through its fuel 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, 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, 2019, there were no material liabilities recorded for any indemnifications.

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

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 non-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.

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OPERATIONAL CONTINGENCIES

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

128

6. ACQUISITIONS AND IMPAIRMENTS

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

ACQUISITIONS

Sempra Renewables LLC (Generation & Marketing Segment)

In April 2019, AEP acquired 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 estimated $110 million as of the acquisition date associated with certain of the acquired wind farms. The purchase price will be allocated primarily to equity 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 credit 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 portion of their energy production and are accounted for under the accounting guidance for “Regulated Operations.” If the Sempra acquisition would have been completed prior to the Balance Sheet date, the revenue and earnings impact would have been immaterial to AEP for the three months ended March 31, 2019 and 2018, respectively.

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 statements of income related to the equity investment and related assets. The impairment also had an immaterial impact to APCo.

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7. BENEFIT PLANS

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

AEP sponsors a qualified pension plan and two unfunded non-qualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a non-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 Cost	51.1			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 Loss	14.4			21.3			5.5			2.6
Net Periodic Benefit Cost (Credit)	$	15.4		$	20.1		$	(20.2	)	$	(25.5	)

AEP Texas



	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 Cost	4.4			4.0			1.0			0.9
Expected Return on Plan Assets	(6.4		)	(6.4		)	(2.0		)	(2.1		)
Amortization of Prior Service Credit	—			—			(1.5		)	(1.5		)
Amortization of Net Actuarial Loss	1.2			1.8			0.5			0.2
Net Periodic Benefit Cost (Credit)	$	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 Cost	6.3			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 Loss	1.8			2.6			0.9			0.5
Net Periodic Benefit Cost (Credit)	$	1.1		$	1.7		$	(2.8	)	$	(3.7	)

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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 Cost	6.0			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 Loss	1.6			2.5			0.7			0.3
Net Periodic Benefit Cost (Credit)	$	1.8		$	2.5		$	(2.7	)	$	(3.4	)

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 Cost	4.7			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 Loss	1.3			2.0			0.6			0.3
Net Periodic Benefit Cost (Credit)	$	0.7		$	1.2		$	(2.2	)	$	(2.9	)

PSO



	Pension Plans						OPEB
	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2019			2018
	(in millions)
Service Cost	$	1.6		$	1.8		$	0.2		$	0.2
Interest Cost	2.6			2.4			0.7			0.6
Expected Return on Plan Assets	(4.1		)	(4.0		)	(1.3		)	(1.4		)
Amortization of Prior Service Credit	—			—			(1.1		)	(1.0		)
Amortization of Net Actuarial Loss	0.8			1.1			0.3			0.1
Net Periodic Benefit Cost (Credit)	$	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 Cost	3.1			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 Loss	0.9			1.3			0.3			0.1
Net Periodic Benefit Cost (Credit)	$	1.7		$	2.1		$	(1.5	)	$	(1.8	)

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8. BUSINESS SEGMENTS

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

AEP’s Reportable Segments

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, interest expense, income tax expense and other nonallocated costs.

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The tables below present AEP’s reportable segment income statement information for the three months ended March 31, 2019 and 2018 and reportable segment balance sheet information as of March 31, 2019 and December 31, 2018.



	Three Months Ended March 31, 2019
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other (a)			Reconciling Adjustments			Consolidated
	(in millions)
Revenues from:
External Customers	$	2,372.3	$	1,179.8	$	61.2	$	439.7	$	3.8		$	—		$	4,056.8
Other Operating Segments	31.0		42.2		195.2		42.1		21.7			(332.2		)	—
Total Revenues	$	2,403.3	$	1,222.0	$	256.4	$	481.8	$	25.5		$	(332.2	)	$	4,056.8

Net Income (Loss)	$	303.6	$	156.5	$	125.2	$	39.2	$	(50.4	)	$	—		$	574.1

	Three Months Ended March 31, 2018
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other (a)			Reconciling Adjustments			Consolidated
	(in millions)
Revenues from:
External Customers	$	2,381.5	$	1,141.2	$	41.1	$	477.5	$	7.0		$	—		$	4,048.3
Other Operating Segments	26.5		21.2		164.4		27.6		17.0			(256.7		)	—
Total Revenues	$	2,408.0	$	1,162.4	$	205.5	$	505.1	$	24.0		$	(256.7	)	$	4,048.3

Net Income (Loss)	$	232.8	$	125.4	$	104.8	$	18.1	$	(24.4	)	$	—		$	456.7

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	March 31, 2019
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing			Corporate and Other (a)				Reconciling Adjustments				Consolidated
	(in millions)
Total Property, Plant and Equipment	$	45,684.3	$	18,526.1	$	8,973.2	$	915.6		$	406.4			$	(354.4	)	(b)	$	74,151.2
Accumulated Depreciation and Amortization	13,944.5		3,856.1		318.8		58.7			190.9				(186.4		)	(b)	18,182.6
Total Property Plant and Equipment - Net	$	31,739.8	$	14,670.0	$	8,654.4	$	856.9		$	215.5			$	(168.0	)	(b)	$	55,968.6


Total Assets	$	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	$	912.1	533.3		85.0		—			(1.9		)	(e)	—				$	1,528.5

Long-term Debt:
Affiliated	50.0		—		—		32.2			—				(82.2		)		—
Nonaffiliated	11,999.5		4,938.6		2,895.3		(0.3		)	3,065.1				—				22,898.2

Total Long-term Debt	$	12,961.6	$	5,471.9	$	2,980.3	$	31.9		$	3,063.2		(e)	$	(82.2	)		$	24,426.7

	December 31, 2018
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing			Corporate and Other (a)				Reconciling Adjustments				Consolidated
	(in millions)
Total Property, Plant and Equipment	$	45,365.1	$	18,126.7	$	8,659.5	$	893.3		$	395.2			$	(354.6	)	(b)	$	73,085.2
Accumulated Depreciation and Amortization	13,822.5		3,833.7		282.8		47.0			186.6				(186.5		)	(b)	17,986.1
Total Property Plant and Equipment - Net	$	31,542.6	$	14,293.0	$	8,376.7	$	846.3		$	208.6			$	(168.1	)	(b)	$	55,099.1

Total Assets	$	38,874.3	$	17,083.4	$	9,543.7	$	1,979.7		$	4,036.5		(c)	$	(2,714.8	)	(b) (d)	$	68,802.8

Long-term Debt Due Within One Year:
Nonaffiliated	$	1,066.3	$	549.1	$	85.0	$	0.1		$	(2.0	)	(e)	$	—			$	1,698.5

Long-term Debt:
Affiliated	50.0		—		—		32.2			—				(82.2		)		—
Nonaffiliated	11,442.7		5,048.8		2,888.6		(0.3		)	2,268.4				—				21,648.2

Total Long-term Debt	$	12,559.0	$	5,597.9	$	2,973.6	$	32.0		$	2,266.4		(e)	$	(82.2	)		$	23,346.7


(a)	Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. 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 finance 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.

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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 the State Transcos. The 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 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 information for the three months ended March 31, 2019 and 2018 and reportable segment balance sheet information as of March 31, 2019 and December 31, 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 Affiliates	193.2		—			—				193.2
Total Revenues	$	243.5	$	—		$	—			$	243.5

Interest Income	$	0.2	$	28.4		$	(27.9	)	(a)	$	0.7
Interest Expense	21.7		27.9			(27.9		)	(a)	21.7
Income Tax Expense	27.6		—			—				27.6

Net Income	$	104.2	$	0.1	(b)	—				$	104.3



	Three Months Ended March 31, 2018
	State Transcos (f)		AEPTCo Parent		Reconciling Adjustments				AEPTCo Consolidated (f)
	(in millions)
Revenues from:
External Customers	$	30.9	$	—	$	—			$	30.9
Sales to AEP Affiliates	160.7		—		—				160.7
Other Revenues	0.1		—		—				0.1
Total Revenues	$	191.7	$	—	$	—			$	191.7

Interest Income	$	0.2	$	25.0	$	(24.8	)	(a)	$	0.4
Interest Expense	20.3		24.8		(24.8		)	(a)	20.3
Income Tax Expense	21.7		0.3		—				22.0

Net Income	$	84.1	$	—	$	—			$	84.1

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	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 Amortization	306.7		—			—				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



	December 31, 2018
	State Transcos		AEPTCo Parent			Reconciling Adjustments				AEPTCo Consolidated
	(in millions)
Total Transmission Property	$	8,268.1	$	—		$	—			$	8,268.1
Accumulated Depreciation and Amortization	271.9		—			—				271.9
Total Transmission Property – Net	$	7,996.2	$	—		$	—			$	7,996.2

Notes Receivable – Affiliated	$	—	$	2,823.0		$	(2,823.0	)	(c)	$	—

Total Assets	$	8,406.8	$	2,857.1	(d)	$	(2,869.8	)	(e)	$	8,394.1

Total Long-term Debt	$	2,850.0	$	2,823.0		$	(2,850.0	)	(c)	$	2,823.0


(a)	Elimination of intercompany interest income/interest expense on affiliated debt arrangement.


(b)	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.

136

9. DERIVATIVES AND HEDGING

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

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.

137

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

Notional Volume of Derivative Instruments

March 31, 2019



Primary Risk Exposure	Unit of Measure	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
		(in millions)
Commodity:
Power	MWhs	310.4		—		43.9		25.9		7.6		7.8		2.0
Natural Gas	MMBtus	80.6		—		4.0		2.3		—		—		14.3
Heating Oil and Gasoline	Gallons	5.4		1.1		1.0		0.5		1.3		0.5		0.6
Interest Rate	USD	$	33.8	$	—	$	—	$	—	$	—	$	—	$	—

Interest Rate	USD	$	500.0	$	—	$	—	$	—	$	—	$	—	$	—

Notional Volume of Derivative Instruments

December 31, 2018



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	$	—	$	—	$	—	$	—	$	—	$	—

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. 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.

138

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-party contractual agreements and risk profiles. AEP netted cash collateral received from third-parties against short-term and long-term risk management assets in the amounts of $9 million and $18 million as of March 31, 2019 and December 31, 2018, respectively. AEP netted cash collateral paid to third-parties against short-term and long-term risk management liabilities in the amounts of $9 million and $4 million as of March 31, 2019 and December 31, 2018, respectively. The netted cash collateral from third-parties against short-term and long-term risk management assets and netted cash collateral paid to third-parties against short-term and long-term risk management liabilities were immaterial for the other Registrants as of March 31, 2019 and December 31, 2018.

139

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, 2019



	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	$	228.3	$	20.8		$	—		$	249.1	$	(155.2	)	$	93.9
Long-term Risk Management Assets	279.0		7.4			—			286.4		(36.0		)	250.4
Total Assets	507.3		28.2			—			535.5		(191.2		)	344.3

Current Risk Management Liabilities	195.9		15.4			1.9			213.2		(149.8		)	63.4
Long-term Risk Management Liabilities	236.6		68.6			4.4			309.6		(41.7		)	267.9
Total Liabilities	432.5		84.0			6.3			522.8		(191.5		)	331.3

Total MTM Derivative Contract Net Assets (Liabilities)	$	74.8	$	(55.8	)	$	(6.3	)	$	12.7	$	0.3		$	13.0

Fair Value of Derivative Instruments

December 31, 2018



	Risk Management Contracts		Hedging Contracts						Gross Amounts of Risk Management Assets/ Liabilities Recognized		Gross Amounts Offset in the Statement of Financial Position (b)			Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c)
Balance Sheet Location	Commodity (a)		Commodity (a)			Interest Rate (a)
	(in millions)
Current Risk Management Assets	$	397.5	$	28.5		$	—		$	426.0	$	(263.2	)	$	162.8
Long-term Risk Management Assets	276.4		16.0			—			292.4		(38.4		)	254.0
Total Assets	673.9		44.5			—			718.4		(301.6		)	416.8

Current Risk Management Liabilities	293.8		13.2			2.0			309.0		(254.0		)	55.0
Long-term Risk Management Liabilities	225.7		56.1			15.4			297.2		(33.8		)	263.4
Total Liabilities	519.5		69.3			17.4			606.2		(287.8		)	318.4

Total MTM Derivative Contract Net Assets (Liabilities)	$	154.4	$	(24.8	)	$	(17.4	)	$	112.2	$	(13.8	)	$	98.4

140

AEP Texas

Fair Value of Derivative Instruments

March 31, 2019



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	0.2			—		0.2
Long-term Risk Management Liabilities	—			—		—
Total Liabilities	0.2			—		0.2

Total MTM Derivative Contract Net Liabilities	$	(0.2	)	$	—	$	(0.2	)

Fair Value of Derivative Instruments

December 31, 2018



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	0.7			(0.5		)	0.2
Long-term Risk Management Liabilities	—			—			—
Total Liabilities	0.7			(0.5		)	0.2

Total MTM Derivative Contract Net Assets (Liabilities)	$	(0.7	)	$	0.5		$	(0.2	)

APCo

Fair Value of Derivative Instruments

March 31, 2019



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	$	40.5	$	(27.6	)	$	12.9
Long-term Risk Management Assets	3.9		(3.6		)	0.3
Total Assets	44.4		(31.2		)	13.2

Current Risk Management Liabilities	33.5		(27.4		)	6.1
Long-term Risk Management Liabilities	3.7		(3.5		)	0.2
Total Liabilities	37.2		(30.9		)	6.3

Total MTM Derivative Contract Net Assets (Liabilities)	$	7.2	$	(0.3	)	$	6.9

Fair Value of Derivative Instruments

December 31, 2018



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	$	114.4	$	(57.2	)	$	57.2
Long-term Risk Management Assets	3.1		(2.2		)	0.9
Total Assets	117.5		(59.4		)	58.1

Current Risk Management Liabilities	56.7		(56.3		)	0.4
Long-term Risk Management Liabilities	2.4		(2.2		)	0.2
Total Liabilities	59.1		(58.5		)	0.6

Total MTM Derivative Contract Net Assets (Liabilities)	$	58.4	$	(0.9	)	$	57.5

141

I&M

Fair Value of Derivative Instruments

March 31, 2019



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	$	22.0	$	(17.6	)	$	4.4
Long-term Risk Management Assets	2.3		(2.2		)	0.1
Total Assets	24.3		(19.8		)	4.5

Current Risk Management Liabilities	17.6		(17.3		)	0.3
Long-term Risk Management Liabilities	2.2		(2.1		)	0.1
Total Liabilities	19.8		(19.4		)	0.4

Total MTM Derivative Contract Net Assets (Liabilities)	$	4.5	$	(0.4	)	$	4.1

Fair Value of Derivative Instruments

December 31, 2018



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	$	50.4	$	(41.8	)	$	8.6
Long-term Risk Management Assets	2.0		(1.4		)	0.6
Total Assets	52.4		(43.2		)	9.2

Current Risk Management Liabilities	41.1		(40.8		)	0.3
Long-term Risk Management Liabilities	1.6		(1.5		)	0.1
Total Liabilities	42.7		(42.3		)	0.4

Total MTM Derivative Contract Net Assets (Liabilities)	$	9.7	$	(0.9	)	$	8.8

OPCo

Fair Value of Derivative Instruments

March 31, 2019



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	6.9			—		6.9
Long-term Risk Management Liabilities	99.4			—		99.4
Total Liabilities	106.3			—		106.3

Total MTM Derivative Contract Net Liabilities	$	(106.3	)	$	—	$	(106.3	)

Fair Value of Derivative Instruments

December 31, 2018



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	)

142

PSO

Fair Value of Derivative Instruments

March 31, 2019



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	$	5.4	$	(0.4	)	$	5.0
Long-term Risk Management Assets	—		—			—
Total Assets	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	$	4.3	$	—		$	4.3

Fair Value of Derivative Instruments

December 31, 2018



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	$	10.9	$	(0.5	)	$	10.4
Long-term Risk Management Assets	—		—			—
Total Assets	10.9		(0.5		)	10.4

Current Risk Management Liabilities	1.7		(0.7		)	1.0
Long-term Risk Management Liabilities	—		—			—
Total Liabilities	1.7		(0.7		)	1.0

Total MTM Derivative Contract Net Assets	$	9.2	$	0.2		$	9.4

SWEPCo

Fair Value of Derivative Instruments

March 31, 2019



Balance Sheet Location	Risk Management Contracts - Commodity (a)			Gross Amounts Offset in the Statement of Financial Position (b)			Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c)
	(in millions)
Current Risk Management Assets	$	2.3		$	(0.3	)	$	2.0
Long-term Risk Management Assets	—			—			—
Total Assets	2.3			(0.3		)	2.0

Current Risk Management Liabilities	0.5			(0.3		)	0.2
Long-term Risk Management Liabilities	1.9			—			1.9
Total Liabilities	2.4			(0.3		)	2.1

Total MTM Derivative Contract Net Liabilities	$	(0.1	)	$	—		$	(0.1	)

Fair Value of Derivative Instruments

December 31, 2018



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	$	5.6	$	(0.8	)	$	4.8
Long-term Risk Management Assets	—		—			—
Total Assets	5.6		(0.8		)	4.8

Current Risk Management Liabilities	1.5		(1.1		)	0.4
Long-term Risk Management Liabilities	2.2		—			2.2
Total Liabilities	3.7		(1.1		)	2.6

Total MTM Derivative Contract Net Assets	$	1.9	$	0.3		$	2.2


(a)	Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.”


(b)	Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”


(c)	All derivative contracts subject to a master netting arrangement or similar agreement are offset in the statement of financial position.

143

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	)


(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.”

144

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 income during the period of change.

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

The following table shows the impacts recognized on the balance sheets related to the hedged items in fair value hedging relationships:



	Carrying Amount of the Hedged Assets/(Liabilities)						Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Assets/(Liabilities)
	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.

The pretax effects of fair value hedge 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 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.

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, 2019 and 2018, AEP applied cash flow hedging to outstanding power derivatives. During the three months ended March 31, 2019 and 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, 2019 and 2018, the Registrants did not apply cash flow hedging to outstanding interest rate derivatives.

145

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, 2019 and 2018, the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives.

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

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

Impact of Cash Flow Hedges on AEP’s Balance Sheets



	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	)

As of March 31, 2019 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 177 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		)

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

Credit Risk

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

Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. 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.

146

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 no derivative contracts with collateral triggering events in a net liability position as of March 31, 2019 and December 31, 2018, respectively.

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

In addition, a majority of non-exchange-traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third-party obligation that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount that the exposure has been reduced by cash collateral posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering contractual netting arrangements:



	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



	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

147

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-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 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-based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility.

AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts.

Assets in the nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and 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.

148

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


(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, 2019
Other Temporary Investments	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(in millions)
Restricted Cash and Other Cash Deposits (a)	$	159.6	$	—	$	—		$	159.6
Fixed Income Securities – Mutual Funds (b)	107.2		—		(1.3		)	105.9
Equity Securities – Mutual Funds	22.5		16.3		—			38.8
Total Other Temporary Investments	$	289.3	$	16.3	$	(1.3	)	$	304.3



	December 31, 2018
Other Temporary Investments	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(in millions)
Restricted Cash and Other Cash Deposits (a)	$	230.6	$	—	$	—		$	230.6
Fixed Income Securities – Mutual Funds (b)	106.6		—		(2.3		)	104.3
Equity Securities – Mutual Funds	17.8		16.4		—			34.2
Total Other Temporary Investments	$	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.

149

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 Investments	0.1		0.6
Gross Realized Gains on Investment Sales	—		—
Gross Realized Losses on Investment Sales	—		—

For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three months ended March 31, 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 SNF trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and SNF disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include:


•	Acceptable investments (rated investment grade or above when purchased).


•	Maximum percentage invested in a specific type of investment.


•	Prohibition of investment in obligations of AEP, I&M or their affiliates.


•	Withdrawals permitted only for payment of decommissioning costs and trust expenses.

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

I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. With the adoption of ASU 2016-01, effective January 2018, available-for-sale classification only applies to investment in debt securities. Additionally, the adoption of ASU 2016-01 required changes in fair value of equity securities to be recognized in earnings. However, due to the regulatory treatment described below, this is not applicable for I&M’s trust fund securities.

Other-than-temporary impairments for investments in 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.

150

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 Government	1,015.6		44.0		(6.7		)	996.1		26.7		(7.1		)
Corporate Debt	54.2		2.9		(1.8		)	52.4		1.1		(1.9		)
State and Local Government	8.7		0.7		(0.2		)	8.6		0.6		(0.2		)
Subtotal Fixed Income Securities	1,078.5		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	)

(a)

Amount reported as Gross Unrealized Gains includes unrealized gains of $955 million and $784 million and unrealized losses of $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 Investments	130.3		525.3
Gross Realized Gains on Investment Sales	12.3		12.0
Gross Realized Losses on Investment Sales	13.8		10.9

The base cost of fixed income securities was $1 billion and $1 billion as of March 31, 2019 and December 31, 2018, respectively. The base cost of equity securities was $643 million and $629 million as of March 31, 2019 and December 31, 2018, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of March 31, 2019 was as follows:



	Fair Value of Fixed Income Securities
	(in millions)
Within 1 year	$	356.4
After 1 year through 5 years	375.4
After 5 years through 10 years	172.8
After 10 years	173.9
Total	$	1,078.5

151

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, 2019



	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)

Other Temporary Investments
Restricted Cash and Other Cash Deposits (a)	$	147.1	$	—	$	—	$	12.5		$	159.6
Fixed Income Securities – Mutual Funds	105.9		—		—		—			105.9
Equity Securities – Mutual Funds (b)	38.8		—		—		—			38.8
Total Other Temporary Investments	291.8		—		—		12.5			304.3

Risk Management Assets
Risk Management Commodity Contracts (c) (d)	2.5		200.4		276.6		(155.4		)	324.1
Cash Flow Hedges:
Commodity Hedges (c)	—		14.8		5.5		(0.1		)	20.2
Total Risk Management Assets	2.5		215.2		282.1		(155.5		)	344.3

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	$	1,891.7	$	1,293.7	$	282.1	$	(134.9	)	$	3,332.6

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (d)	$	2.7	$	204.8	$	197.2	$	(155.7	)	$	249.0
Cash Flow Hedges:
Commodity Hedges (c)	—		29.3		46.8		(0.1		)	76.0
Fair Value Hedges	—		6.3		—		—			6.3
Total Risk Management Liabilities	$	2.7	$	240.4	$	244.0	$	(155.8	)	$	331.3

152

AEP

Assets and Liabilities Measured at Fair Value on a Recurring Basis

December 31, 2018



	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

153

AEP Texas

Assets and Liabilities Measured at Fair Value on a Recurring Basis

March 31, 2019



	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)

Restricted Cash for Securitized Funding	$	100.6	$	—	$	—	$	—	$	100.6

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	0.2	$	—	$	—	$	0.2

December 31, 2018



	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)

Restricted Cash for Securitized Funding	$	156.7	$	—	$	—	$	—		$	156.7

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	0.7	$	—	$	(0.5	)	$	0.2

APCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

March 31, 2019



	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)

Restricted Cash for Securitized Funding	$	18.3	$	—	$	—	$	—		$	18.3

Risk Management Assets
Risk Management Commodity Contracts (c) (g)	0.2		26.8		13.4		(27.2		)	13.2

Total Assets	$	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

154

I&M

Assets and Liabilities Measured at Fair Value on a Recurring Basis

March 31, 2019



	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)

Risk Management Assets
Risk Management Commodity Contracts (c) (g)	$	—	$	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	$	1,597.4	$	1,095.2	$	5.2	$	(9.3	)	$	2,688.5

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	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

155

OPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

March 31, 2019



	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)

Restricted Cash for Securitized Funding	$	16.5	$	—	$	—	$	—	$	16.5

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	0.2	$	106.1	$	—	$	106.3

December 31, 2018



	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, 2019



	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

156

SWEPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

March 31, 2019



	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

December 31, 2018



	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)

Risk Management Assets
Risk Management Commodity Contracts (c) (g)	$	—	$	—	$	5.6	$	(0.8	)	$	4.8

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	0.4	$	3.3	$	(1.1	)	$	2.6


(a)	Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or third-parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.


(b)	Amounts represent publicly traded equity securities and equity-based mutual funds.


(c)	Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.”

(d)

The March 31, 2019 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(7) million in 2019, $2 million in periods 2023-2024 and $1 million in periods 2025-2032; Level 3 matures $27 million in 2019, $42 million in periods 2020-2022, $23 million in periods 2023-2024 and $(13) million in periods 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, 2018 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(4) million in 2019, $1 million in periods 2020-2022, $1 million in periods 2023-2024 and $1 million in periods 2025-2032; Level 3 matures $108 million in 2019, $37 million in periods 2020-2022, $23 million in periods 2023-2024 and $(12) million in periods 2025-2032. Risk management commodity contracts are substantially comprised of power contracts.


(g)	Substantially comprised of power contracts for the Registrant Subsidiaries.

There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2019 and 2018.

157

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, 2019	AEP			APCo			I&M			OPCo			PSO			SWEPCo
	(in millions)
Balance as of December 31, 2018	$	131.2		$	57.8		$	8.9		$	(99.4	)	$	9.5		$	2.3
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)	(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)	8.5			—			—			—			—			—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income	(15.8		)	—			—			—			—			—
Settlements	(54.5		)	(17.8		)	(5.1		)	1.8			(13.0		)	(7.3		)
Transfers into Level 3 (c) (d)	0.1			—			—			—			—			—
Transfers out of Level 3 (d)	(1.2		)	(0.7		)	(0.4		)	—			—			—
Changes in Fair Value Allocated to Regulated Jurisdictions (e)	(7.2		)	(2.9		)	1.0			(8.1		)	1.1			1.7
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


(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 or accounts payable.

158

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

Significant Unobservable Inputs

March 31, 2019

AEP



						Significant	Input/Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input	Low			High		Average
	(in millions)
Energy Contracts	$	256.7	$	229.0	Discounted Cash Flow	Forward Market Price (a)	$	(0.05	)	$	165.64	$	32.60
Natural Gas Contracts	—		2.0		Discounted Cash Flow	Forward Market Price (b)	2.27			2.87		2.48
FTRs	25.4		13.0		Discounted Cash Flow	Forward Market Price (a)	(8.34		)	10.30		(0.02		)
Total	$	282.1	$	244.0

December 31, 2018



						Significant	Input/Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input	Low			High		Average
	(in millions)
Energy Contracts	$	257.1	$	212.5	Discounted Cash Flow	Forward Market Price (a)	$	(0.05	)	$	176.57	$	33.07
Natural Gas Contracts	—		2.5		Discounted Cash Flow	Forward Market Price (b)	2.18			3.54		2.47
FTRs	96.5		7.4		Discounted Cash Flow	Forward Market Price (a)	(11.68		)	17.79		1.09
Total	$	353.6	$	222.4

159

Significant Unobservable Inputs

March 31, 2019

APCo



						Significant	Input/Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input (a)	Low			High		Average
	(in millions)
Energy Contracts	$	3.6	$	0.4	Discounted Cash Flow	Forward Market Price	$	17.40		$	49.25	$	34.91
FTRs	9.8		5.6		Discounted Cash Flow	Forward Market Price	(0.06		)	2.44		0.61
Total	$	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
FTRs	55.9		—		Discounted Cash Flow	Forward Market Price	0.10		15.16		3.27
Total	$	58.3	$	0.5

Significant Unobservable Inputs

March 31, 2019

I&M



						Significant	Input/Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input (a)	Low			High		Average
	(in millions)
Energy Contracts	$	1.9	$	0.3	Discounted Cash Flow	Forward Market Price	$	17.40		$	49.25	$	34.91
FTRs	3.3		0.5		Discounted Cash Flow	Forward Market Price	(0.10		)	2.02		0.86
Total	$	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
FTRs	8.9		0.5		Discounted Cash Flow	Forward Market Price	(2.11		)	6.21		1.06
Total	$	10.3	$	1.4

160

Significant Unobservable Inputs

March 31, 2019

OPCo

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, 2019

PSO



						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	)

161

Significant Unobservable Inputs

March 31, 2019

SWEPCo



						Significant	Input/Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input	Low			High		Average
	(in millions)
Natural Gas Contracts	$	—	$	2.0	Discounted Cash Flow	Forward Market Price (b)	$	2.27		$	2.87	$	2.48
FTRs	2.3		0.3		Discounted Cash Flow	Forward Market Price (a)	(8.34		)	10.30		(1.09		)
Total	$	2.3	$	2.3

December 31, 2018



						Significant	Input/Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input	Low			High		Average
	(in millions)
Natural Gas Contracts	$	—	$	2.5	Discounted Cash Flow	Forward Market Price (b)	$	2.18		$	3.54	$	2.47
FTRs	5.6		0.8		Discounted Cash Flow	Forward Market Price (a)	(11.68		)	10.30		(1.40		)
Total	$	5.6	$	3.3


(a)	Represents market prices in dollars per MWh.


(b)	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, 2019 and December 31, 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)

162

11. INCOME TAXES

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

Status of Tax Reform Regulatory Proceedings

For AEP’s various regulatory jurisdictions where the regulatory effects of Tax Reform proceedings have not been fully resolved, the table below summarizes the current status. See Note 4 - Rate Matters for additional information.



Registrant (Jurisdiction)	Change in Tax Rate	Excess ADIT Subject to Normalization Requirements	Excess ADIT Not Subject to Normalization Requirements
AEP Texas (Texas-Distribution)	Order Issued	Order Issued	Order Issued – Partial (a)
AEP Texas (Texas-Transmission)	Order Issued	To be addressed in a later filing	To be addressed in a later filing
I&M (Michigan)	Order Issued	Case Pending	Case Pending
SWEPCo (Louisiana)	Case Pending – Rates Implemented (b)	Case Pending – Rates Implemented (b)	Case Pending – Rates Implemented (b)
SWEPCo (Texas)	Order Issued	To be addressed in a later filing	To be addressed in a later filing
PJM FERC Transmission	Settlement Approved (c)	Settlement Approved (c)	Settlement Approved (c)
SPP FERC Transmission	Settlement Pending	Settlement Pending	Settlement 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.

Effective Tax Rates (ETR)

The Registrants’ interim ETR reflect the estimated annual ETR for 2019 and 2018, adjusted for tax expense associated with certain discrete items. The interim ETR differ from the federal statutory tax rate of 21% primarily due to increased amortization of 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	%

163

AEP

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

The decrease in the ETR is primarily due to $66 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (10.8)%.

AEP Texas

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

The decrease in the ETR is primarily due to $1 million of increased amortization of Excess ADIT not subject to normalization requirements and an increase in parent company loss benefit which impacted the 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, 2019 Compared to Three Months Ended March 31, 2018

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 ETR by (37.9)%. Amortization of Excess ADIT not subject to normalization requirements for the three months ended March 31, 2019 reflects October 2018 and March 2019 Virginia SCC Tax Reform orders as well as August 2018 and February 2019 WVPSC orders.

I&M

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

The decrease in the ETR is primarily due to $13 million of increased amortization of Excess ADIT not subject to normalization requirements and an increase in favorable book/tax differences accounted for on a flow-through basis which impacted the 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.

OPCo

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

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 ETR by (6)%. Amortization of Excess ADIT not subject to normalization requirements for the three months ended March 31, 2019 reflects the October 2018 PUCO Tax Reform order.

164

PSO

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

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 ETR 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 March 2019.

SWEPCo

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

The decrease in the ETR is primarily due to $3 million of increased amortization of Excess ADIT not subject to normalization requirements and a decrease in state tax expense which impacted the ETR by (11.3)% and (1.3)%, respectively. Amortization of Excess ADIT not subject to normalization requirements for the 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 for all years through 2016.

AEP and subsidiaries file income tax returns in various state and local 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 2007.

165

12. LEASES

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

166

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

167



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

168

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.

169

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.

170

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, net of issuance costs and premiums or discounts:



Type of Debt	March 31, 2019		December 31, 2018
	(in millions)
Senior Unsecured Notes	$	19,411.6	$	18,903.3
Pollution Control Bonds	1,590.0		1,643.8
Notes Payable	177.0		204.7
Securitization Bonds	973.0		1,111.4
Spent Nuclear Fuel Obligation (a)	275.3		273.6
Junior Subordinated Notes (b)	785.0		—
Other Long-term Debt	1,214.8		1,209.9
Total Long-term Debt Outstanding	24,426.7		23,346.7
Long-term Debt Due Within One Year	1,528.5		1,698.5
Long-term Debt	$	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 SNF disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $318 million and $317 million as of March 31, 2019 and December 31, 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 2019 are shown in the following tables:



Company	Type of Debt	Principal Amount (a)		Interest Rate	Due Date
Issuances:		(in millions)		(%)
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	6.3		Variable	2020
Total Issuances		$	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.

171



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

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

Long-term Debt Subsequent Events

In April 2019, I&M retired $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.

172

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 Liabilities with 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 3.0% of consolidated tangible net assets as of March 31, 2019. The method for calculating the consolidated tangible net assets is contractually-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. 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-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-defined in the credit agreements.

173

Corporate Borrowing Program - AEP System (Applies to Registrant Subsidiaries)

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and direct borrowing from AEP. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of March 31, 2019 and December 31, 2018 are included in Advances to Affiliates and Advances from Affiliates, respectively, on 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, 2019 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


(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, LLC participate in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of March 31, 2019 and December 31, 2018 are included in Advances to Affiliates on the subsidiaries’ balance sheets. The Nonutility Money Pool participants’ money pool activity for the three months ended March 31, 2019 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

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, 2019 and December 31, 2018 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, 2019 is described in the following table:

Authorized

Maximum

Average

Borrowings from

Loans to

Short-term

Borrowings

Loans

Borrowings

Loans

AEP as of

Borrowing

from AEP

to AEP

from AEP

to AEP

March 31, 2019

Limit

(in millions)

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.

174

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool 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	%

The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized for the 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	%

Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized in the following table:

Three Months Ended March 31, 2019

Three Months Ended March 31, 2018

Maximum

Minimum

Average

Maximum

Minimum

Average

Interest Rate

for Funds

Loaned to

the Nonutility

Company

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

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 AEP		to 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	%

175

Short-term Debt (Applies to AEP)

Outstanding short-term debt was as follows:



	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-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 that provides a commitment of $750 million from bank 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. Accounts receivable information for AEP Credit was as follows:



	Three Months Ended March 31,
	2019			2018
	(dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable	2.71		%	1.74		%
Net Uncollectible Accounts Receivable Written-Off	$	6.4		$	4.2



	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

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.

176

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

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

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

177

14. REVENUE FROM CONTRACTS WITH CUSTOMERS

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

Disaggregated Revenues from Contracts with Customers

The tables below represent AEP’s reportable segment revenues from contracts with customers, net of respective provisions for refund, by type of revenue:



	Three Months Ended 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


(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.

178



	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.

179

The tables below represent 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


(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.

180



	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.

Fixed Performance Obligations

The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of March 31, 2019. Fixed performance obligations primarily include wholesale transmission services, electricity sales for fixed amounts of energy and stand ready services into PJM’s RPM market. The Registrants Subsidiaries amounts shown in the table below include affiliated and nonaffiliated 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

181

Contract Assets and Liabilities

Contract assets are recognized when the Registrants have a right to consideration that is conditional upon the occurrence of an event other than the passage of time, such as future performance under a contract. The Registrants did not have any material contract assets as of 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 did 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 were not material as of March 31, 2019 and December 31, 2018. See “Securitized Accounts Receivable - AEP Credit” section of Note 13 for additional information related to AEP Credit’s securitized accounts receivable.

The following table represents the amount of affiliated accounts receivable from contracts with customers included in Accounts Receivable - Affiliated Companies on the Registrant Subsidiaries’ balance sheets:



Company	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

182

CONTROLS AND PROCEDURES

During the first quarter of 2019, management, including the principal executive officer and principal financial officer of each of the Registrants, evaluated the Registrants’ disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. As of March 31, 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 2019 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

183

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For a discussion of material legal proceedings, see Note 5 - Commitments, Guarantees and Contingencies incorporated herein by reference.

Item 1A. Risk Factors

The Annual Report on Form 10-K for the year ended December 31, 2018 includes a detailed discussion of risk factors. As of March 31, 2019, there have been no material changes to the risk factors previously disclosed in the 2018 Annual Report on Form 10-K.

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, 2019.

Item 5. Other Information

None.

184

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.



Exhibit	Description	Previously Filed as Exhibit to:

AEP‡ File No. 1-3525

*4.1	Purchase 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

*4.2	Junior 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)

*4.3	Supplemental 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

*4.4	Company 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 herewith.

Exhibit

Description

AEP

Texas

AEPTCo

APCo

I&M

OPCo

PSO

SWEPCo

31(a)

Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31(b)

Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32(a)

Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

32(b)

Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

Mine Safety Disclosures

101.INS

XBRL Instance Document

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XBRL Taxonomy Extension Calculation Linkbase

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185

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 25, 2019

186