AMERICAN ELECTRIC POWER CO INC - Quarter Report: 2020 March (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For The Quarterly Period Ended March 31, 2020

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For The Transition Period from ____ to ____



Commission	Registrants;						I.R.S. Employer
File Number	Address and Telephone Number					States of Incorporation	Identification Nos.

1-3525	AMERICAN ELECTRIC POWER CO INC.					New York	13-4922640
333-221643	AEP TEXAS INC.					Delaware	51-0007707
333-217143	AEP TRANSMISSION COMPANY, LLC					Delaware	46-1125168
1-3457	APPALACHIAN POWER COMPANY					Virginia	54-0124790
1-3570	INDIANA MICHIGAN POWER COMPANY					Indiana	35-0410455
1-6543	OHIO POWER COMPANY					Ohio	31-4271000
0-343	PUBLIC SERVICE COMPANY OF OKLAHOMA					Oklahoma	73-0410895
1-3146	SOUTHWESTERN ELECTRIC POWER COMPANY					Delaware	72-0323455
	1 Riverside Plaza,		Columbus,	Ohio	43215-2373
	Telephone	(614)	716-1000

Securities registered pursuant to Section 12(b) of the Act:



Registrant	Title of each class	Trading Symbol	Name of Each Exchange on Which Registered
American Electric Power Company Inc.	Common Stock, $6.50 par value	AEP	New York Stock Exchange
American Electric Power Company Inc.	6.125% Corporate Units	AEP PR B	New York Stock Exchange



Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
	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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated filer	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
	May 6, 2020

American Electric Power Company, Inc.	495,583,133
	($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, 2020

		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	39

AEP Texas Inc. and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	46
	Condensed Consolidated Financial Statements	48

AEP Transmission Company, LLC and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	55
	Condensed Consolidated Financial Statements	57

Appalachian Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	63
	Condensed Consolidated Financial Statements	66

Indiana Michigan Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	73
	Condensed Consolidated Financial Statements	76

Ohio Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	83
	Condensed Consolidated Financial Statements	86

Public Service Company of Oklahoma:
	Management’s Narrative Discussion and Analysis of Results of Operations	93
	Condensed Financial Statements	95

Southwestern Electric Power Company Consolidated:
	Management’s Narrative Discussion and Analysis of Results of Operations	102
	Condensed Consolidated Financial Statements	104

Index of Condensed Notes to Condensed Financial Statements of Registrants		110

Controls and Procedures		179



Part II. OTHER INFORMATION

	Item 1.	Legal Proceedings	180
	Item 1A.	Risk Factors	180
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	180
	Item 3.	Defaults Upon Senior Securities	180
	Item 4.	Mine Safety Disclosures	180
	Item 5.	Other Information	181
	Item 6.	Exhibits	181

SIGNATURE			182


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.
AEP Wind Holdings LLC		Acquired in April 2019 as Sempra Renewables LLC, develops, owns and operates, or holds interests in, wind generation facilities in the United States.
AEPRO		AEP River Operations, LLC, a commercial barge operation sold in November 2015.
AEPSC		American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AEPTCo		AEP Transmission Company, LLC, a wholly-owned subsidiary of AEP Transmission Holdco, 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.
AMI		Advanced Metering Infrastructure.
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.
ASU		Accounting Standards Update.
CAA		Clean Air Act.
Cardinal Operating Company		A jointly-owned organization between AGR and a nonaffiliate. The nonaffiliate operates the three unit Cardinal Plant and wholly-owns Units 2 and 3.
CO₂		Carbon dioxide and other greenhouse gases.
Cook Plant		Donald C. Cook Nuclear Plant, a two-unit, 2,288 MW nuclear plant owned by I&M.
COVID-19		Coronavirus 2019, a highly infectious respiratory disease. In March 2020, the World Health Organization declared COVID-19 a worldwide pandemic.
CSAPR		Cross-State Air Pollution Rule.
CWA		Clean Water Act.
CWIP		Construction Work in Progress.
DCC Fuel		DCC Fuel IX, DCC Fuel X, DCC Fuel XI, DCC Fuel XII, DCC Fuel XIII, and DCC Fuel XIV, consolidated VIEs formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
DHLC		Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.



Term		Meaning

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.
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.
North Central Wind Energy Facilities		A proposed joint PSO and SWEPCo project, which includes three Oklahoma wind facilities totaling approximately 1,485 MWs of wind generation.
NO₂		Nitrogen dioxide.
NO_x		Nitrogen oxide.
NPDES		National Pollutant Discharge Elimination System.
NSR		New Source Review.
OCC		Corporation Commission of the State of Oklahoma.



Term		Meaning

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.
PATH-WV		PATH West Virginia Transmission Company, LLC, a joint venture owned 50% by FirstEnergy and 50% by AEP.
PJM		Pennsylvania – New Jersey – Maryland regional transmission organization.
PM		Particulate Matter.
PPA		Purchase Power and Sale Agreement.
PSO		Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PTC		Production Tax Credits.
PUCO		Public Utilities Commission of Ohio.
PUCT		Public Utility Commission of Texas.
Racine		A generation plant consisting of two hydroelectric generating units totaling 48 MWs located in Racine, Ohio and owned by AGR.
Reference Rate Reform		The global transition away from referencing the London Interbank Offered Rate and other interbank offered rates, and toward new reference rates that are more reliable and robust.
Registrant Subsidiaries		AEP subsidiaries which are SEC registrants: AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
Registrants		SEC registrants: AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
Restoration Funding		AEP Texas Restoration Funding LLC, a wholly-owned subsidiary of AEP Texas and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to storm restoration in Texas primarily caused by Hurricane Harvey.
Risk Management Contracts		Trading and 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.
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.
Santa Rita East		Santa Rita East Wind Holdings, LLC, a consolidated VIE whose sole purpose is to own and operate a 302.4 MW wind generation facility in west Texas in which AEP owns a 75% interest.
Sempra Renewables LLC		Sempra Renewables LLC, acquired in April 2019, consists of 724 MWs of wind generation and battery assets in the United States.
SIP		State Implementation Plan.
SNF		Spent Nuclear Fuel.
SO₂		Sulfur dioxide.
SPP		Southwest Power Pool regional transmission organization.
SSO		Standard service offer.

iii



Term		Meaning

State Transcos		AEPTCo’s seven wholly-owned, FERC regulated, transmission only electric utilities, which are geographically aligned with AEP’s existing utility operating companies.
SWEPCo		Southwestern Electric Power Company, an AEP electric utility subsidiary.
Tax Reform		On December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal Revenue Code of 1986, including a reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018.
TCC		Formerly AEP Texas Central Company, now a division of AEP Texas.
Texas Restructuring Legislation		Legislation enacted in 1999 to restructure the electric utility industry in Texas.
Transition Funding		AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated VIEs 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.
UPA		Unit Power Agreement.
Utility Money Pool		Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
VIE		Variable Interest Entity.
Virginia SCC		Virginia State Corporation Commission.
Wind Catcher Project		Wind Catcher Energy Connection Project, a joint PSO and SWEPCo project that was cancelled in July 2018. The project included the acquisition of a wind generation facility, totaling approximately 2,000 MW of wind generation, and the construction of a generation interconnection tie-line totaling approximately 350 miles.
WPCo		Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC		Public Service Commission of West Virginia.

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 2019 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.
•	The impact of pandemics, including COVID-19, and any associated disruption of AEP’s business operations due to impacts on economic or market conditions, electricity usage, employees, customers, service providers, vendors and suppliers.
•	Inflationary or deflationary interest rate trends.
•	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.
•	Decreased demand for electricity.
•	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.
•	The availability of fuel and necessary generation capacity and the performance of generation plants.
•	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 coal ash and 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 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 standards 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 ability to attract and retain the requisite work force and key personnel.

The forward-looking statements of the Registrants speak only as of the date of this report or as of the date they are made. The Registrants expressly disclaim any obligation to update any forward-looking information. For a more detailed discussion of these factors, see “Risk Factors” in Part I of the 2019 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

COVID-19

In March 2020, COVID-19 was declared a pandemic by the World Health Organization and the Centers for Disease Control and Prevention. Its rapid spread around the world and throughout the United States prompted many countries, including the United States, to institute restrictions on travel, public gatherings and certain business operations. These restrictions significantly disrupted economic activity in AEP’s service territory and could reduce future demand for energy, particularly from commercial and industrial customers. As of March 31, 2020, the reduction in the demand for energy did not materially impact the Registrants’ financial statements. However, if the severity of the economic disruptions increase as the duration of the COVID-19 pandemic continues, the negative financial impact due to reduced demand could be significantly greater in future periods than in the first quarter.

AEP’s electric utility operating companies informed both retail customers and state regulators that disconnections for non-payment have been temporarily suspended. These uncertain economic conditions may result in the inability of customers to pay for electric service, which could affect the collectability of the Registrants’ revenues and adversely affect financial results. The Registrants are evaluating and working with their state regulatory commissions on potential rate recovery mechanisms for increased costs incurred due to COVID-19. Certain Registrants received orders approving the deferral of certain incremental expenses associated with COVID-19. See Note 4 - Rate Matters for additional information. The Registrants have not observed a material change in their typical collections experience and thus did not materially adjust their allowances for uncollectible accounts as of March 31, 2020.

The effects of the continued outbreak of COVID-19 and related government responses could also include extended disruptions to supply chains and capital markets, reduced labor availability and a prolonged reduction in economic activity. These effects could have a variety of adverse impacts to the Registrants, including their ability to operate their facilities. As of March 31, 2020, there were no material adverse impacts to the Registrants’ operations due to COVID-19.

In addition, the economic disruptions caused by COVID-19 could also adversely impact the impairment risks for certain long-lived assets, equity method investments and goodwill. AEP evaluated these impairment considerations and determined that no such impairments occurred as of March 31, 2020.

During the first quarter of 2020, AEP increased its liquidity position to mitigate the risk of market volatility due to COVID-19. The Registrants’ access to funding was limited for a period of time during the first quarter and therefore AEP entered into a 364–day term loan to reduce reliance on commercial paper and help mitigate potential future liquidity risks. Specifically, for the first three months of 2020, AEP issued approximately $1.4 billion in long-term debt and $1.6 billion in short-term debt primarily via a 364-day term loan to enhance the Registrants’ available liquidity. As of March 31, 2020, AEP’s available liquidity is $2.8 billion. Management believes the Registrants have adequate liquidity under existing credit facilities. To the extent that future access to the capital markets or the cost of funding is adversely affected by COVID-19, the Registrants may need to consider alternative sources of funding for operations and working capital, which may adversely impact future results of operations, financial condition, and cash flows.

The effects of an extended disruption to the supply chains could disrupt or delay construction, testing, supervisory and support activities at renewable generation facilities, in particular, the North Central Wind Energy Facilities and the AEP Generation & Marketing segment’s Flat Ridge 3 wind project. The in-service dates for the North Central Wind Energy Facilities are scheduled for end of year 2020 for one project, and end of year 2021 for the remaining two projects. Under the terms of the Purchase and Sales Agreement, PSO and SWEPCo do not have an obligation to acquire the North Central Wind Energy Facility projects if the projects are not completed by the required in-service dates. The in-service date for the Flat Ridge 3 wind project is scheduled for end of the year 2020. As of March 31, 2020, there has been no material adverse impacts to either the North Central Wind Energy Facility or the Flat Ridge 3 project. AEP currently expects the construction projects to be delivered on-time in accordance with the agreements with the developers. However, depending on the longevity and ultimate impact of COVID-19, future delays in the construction of AEP’s renewable assets could occur which could impact the current construction schedule, budget, and the qualification for federal PTC. AEP is working with industry groups on potential legislative and administrative relief for a PTC continuity safe harbor extension due to the ongoing impacts of COVID-19.

In March 2020, President Trump signed into law legislation referred to as the "Coronavirus Aid, Relief, and Economic Security Act" (the CARES Act). The CARES Act includes tax relief provisions such as: (a) an Alternative Minimum Tax (AMT) Credit Refund, (b) a 5-year net operating losses (NOL) carryback from years 2018-2020 and (c) delayed payment of employer payroll taxes. As of March 31, 2020, AEP has a $20 million AMT credit refund recognized in anticipation of a refund from the U.S. Treasury. Management is evaluating the ability to recover taxes paid in 2014 under the 5-year NOL carryback provision. The Registrants currently expect to defer payments of the employer share of payroll taxes for the period March 27, 2020 through December 31, 2020 and pay 50% of the obligation by December 31, 2021 and the remaining 50% by December 31, 2022.

The Registrants are taking steps to mitigate the potential risks to customers, suppliers and employees posed by the spread of COVID-19. The Registrants have updated and implemented a company-wide pandemic plan to address specific aspects of the COVID-19. This plan guides emergency response, business continuity, and the precautionary measures AEP is taking on behalf of its employees and the public. The Registrants have taken extra precautions for employees who work in the field and for employees who work in their facilities, and have implemented work from home policies where appropriate. The Registrants will continue to monitor developments affecting both their workforce and customers, and will take additional precautions that management determines are necessary in order to mitigate the impacts. AEP continues to focus on providing safe, uninterrupted service to its customers, which includes the implementation of strong physical and cyber-security measures to ensure that its systems remain functional with a partially remote workforce. As of March 31, 2020, there has been no material adverse impact to the Registrants’ business operations and customer service due to remote work. Management will continue to review and modify plans as conditions change. Despite efforts to manage these impacts to the Registrants, the ultimate impact of COVID-19 also depends on factors beyond management’s knowledge or control, including the duration and severity of this outbreak as well as third-party actions taken to contain its spread and mitigate its public health effects. Therefore, management cannot estimate the potential future impact to financial position, results of operations and cash flows, but the impacts could be material.

Customer Demand

AEP’s weather-normalized retail sales volumes for the first quarter of 2020 decreased by 0.7% from the first quarter of 2019. AEP’s first quarter 2020 industrial sales volumes decreased by 0.7% compared to the first quarter of 2019. The decline in industrial sales was spread across many industries. Weather-normalized residential sales decreased 1.2% while weather-normalized commercial sales were flat in the first quarter of 2020, from the first quarter of 2019.

Many businesses were forced to limit or reduce their operations in response to the COVID-19 outbreak over the last two weeks of the first quarter of 2020. While there is uncertainty regarding the duration and total impact that COVID-19 will have on AEP’s retail sales in 2020, AEP expects COVID-19 to have a larger impact in the second quarter of 2020 than it had in the first quarter.

As a result of the impact of COVID-19, AEP revised its forecast for 2020 weather-normalized retail sales volumes from the forecast presented in the 2019 10-K. In 2020, AEP currently anticipates weather-normalized retail sales volumes will decrease by 3.4%. AEP expects industrial class sales volumes to decrease by 8% in 2020, while weather-normalized residential sales volumes are projected to increase by 3%. Finally, AEP currently projects weather-normalized commercial sales volumes to decrease by 5.6%.


(a)	Percentage change for the year ended December 31, 2019 as compared to the year ended December 31, 2018.


(b)	As presented in the 2019 AEP 10-K: Forecasted percentage change for the year ended December 31, 2020 compared to the year ended December 31, 2019.


(c)	Revised for the impact of COVID-19: Forecasted percentage change for the year ended December 31, 2020 compared to the year ended December 31, 2019.

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.

•

2019 Indiana Base Rate Case - In May 2019, I&M filed a request with the IURC for a $172 million annual increase based upon a proposed 10.5% return on common equity. In March 2020, the IURC issued an order authorizing a $77 million annual base rate increase based upon a return on common equity of 9.7% effective March 2020. This increase will be phased in through January 2021 with an approximate $44 million annual increase in base rates effective March 2020 and the full $77 million annual increase effective January 2021. The order rejected I&M’s proposed re-allocation of capacity costs related to the loss of a significant FERC wholesale contract, which will negatively impact I&M’s annual pretax earnings by approximately $20 million starting June 2020. The IURC also rejected I&M’s proposed AMI meter rider. In March 2020, I&M filed for rehearing as a result of the IURC’s ruling to reject I&M’s proposed re-allocation of capacity costs. Intervenors subsequently filed objections to I&M's appeal. In April 2020, I&M filed a reply to these objections on rehearing and appealed the IURC’s order.

•

2017-2019 Virginia Triennial Review - In March 2020, APCo submitted its 2017-2019 Virginia triennial earnings review filing and base rate case with the Virginia SCC as required by state law. APCo requested a $65 million annual increase based upon a proposed 9.9% return on common equity. Triennial reviews are subject to an earnings test, which provides that 70% of any earnings in excess of 70 basis points above APCo’s Virginia SCC authorized ROE would be refunded to customers. In such case, the Virginia SCC could also lower APCo’s Virginia retail base rates on a prospective basis. Virginia law provides that costs associated

with asset impairments of retired coal generation assets, or automated meters, or both, which a utility records as an expense, shall be attributed to the test periods under review in a triennial review proceeding, and be deemed recovered. Based on management’s interpretation of Virginia law and more certainty regarding APCo’s triennial revenues, expenses and resulting earnings upon reaching the end of the three-year review period, APCo recorded a pretax expense of $93 million related to its previously retired coal-fired generation assets in December 2019. As a result, management deems these costs to be substantially recovered by APCo during the triennial review period. Inclusive of the $93 million expense associated with APCo’s Virginia jurisdictional retired coal-fired plants, APCo estimates its Virginia earnings for the triennial period to be below the authorized ROE range.

•

2012 Texas Base Rate Case - In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant. In July 2018, the Texas Third Court of Appeals reversed the PUCT’s judgment affirming the prudence of the Turk Plant and remanded the issue back to the PUCT. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court. In the fourth quarter of 2019 and first quarter of 2020, SWEPCo and various intervenors filed briefs with the Texas Supreme Court. As of March 31, 2020, the net book value of Turk Plant was $1.5 billion, before cost of removal, including materials and supplies inventory and CWIP. SWEPCo’s Texas jurisdictional share of the Turk Plant investment is approximately 33%.

•

In July 2019, clean energy legislation which offers incentives for power-generating facilities with zero or reduced carbon emissions was signed into law by the Ohio Governor. The clean energy legislation phases out current energy efficiency including lost shared savings revenues of $26 million annually and renewable mandates no later than 2020 and after 2026, respectively. The bill provides for the recovery of existing renewable energy contracts on a bypassable basis through 2032. The clean energy legislation also includes a provision for recovery of OVEC costs through 2030 which will be allocated to all electric distribution utilities on a non-bypassable basis. OPCo’s Inter-Company Power Agreement for OVEC terminates in June 2040. To the extent that OPCo is unable to recover the costs of renewable energy contracts on a bypassable basis by the end of 2032, recover costs of OVEC after 2030 or fully recover energy efficiency costs through 2020 it could reduce future net income and cash flows and impact financial condition.

•

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

Utility Rates and Rate Proceedings

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

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

Completed Base Rate Case Proceedings



		Approved Revenue				Approved	New Rates
Company	Jurisdiction	Requirement Increase (Decrease)				ROE	Effective
		(in millions)
I&M	Indiana	$	77.4		(a)	9.7%	March 2020
AEP Texas	Texas	(40.0		)	(b)	9.4%	June 2020


(a)	This increase will be phased in through January 2021 with an approximate $44 million annual increase in base rates effective March 2020 and the full $77 million annual increase effective January 2021. In March 2020, I&M filed for rehearing as a result of the IURC’s ruling to reject I&M’s proposed re-allocation of capacity costs.


(b)	In April 2020, the PUCT issued an order approving the stipulation and settlement agreement with a capital structure of 57.5% debt and 42.5% common equity effective with the first billing cycle in June 2020.

Pending Base Rate Case Proceedings

Commission Staff/

Filing

Requested Revenue

Requested

Intervenor Range of

Company

Jurisdiction

Date

Requirement Increase

ROE

Recommended ROE

(in millions)

APCo

Virginia

March 2020

64.9

9.9%

(a)


(a)	Commission Staff/Intervenor direct testimony to be filed by August 2020.

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, 2020, subsidiaries within AEP’s Generation & Marketing segment had approximately 1,423 MWs of contracted renewable generation projects in-service. In addition, as of March 31, 2020, these subsidiaries had approximately 160 MWs of renewable generation projects under construction with total estimated capital costs of $235 million related to these projects.

Regulated Renewable Generation Facilities

In July 2019, PSO and SWEPCo submitted filings before their respective commissions for the approval to acquire the North Central Wind Energy Facilities, comprised of three Oklahoma wind facilities totaling 1,485 MWs, on a fixed cost turn-key basis at completion. Subject to regulatory approval, PSO will own 45.5% and SWEPCo will own 54.5% of the project, which will cost approximately $2 billion. Two wind facilities, totaling 1,286 MWs, would qualify for 80% of the federal PTC with year-end 2021 in-service dates. The third wind facility (199 MWs) would qualify for 100% of the PTC with a year-end 2020 in-service date. The acquisition can be scaled, subject to commercial limitation,

to align with individual state resource needs and approvals. In December 2019, PSO reached a joint stipulation and settlement agreement with the OCC, Oklahoma Attorney General’s office and customer groups; the PSO agreement was approved by the Oklahoma Commission in February 2020. In January 2020, SWEPCo reached a joint settlement agreement with the APSC, Arkansas Attorney General’s office and Walmart, Inc. Hearings in the Texas proceeding took place in February 2020. In April 2020, SWEPCo reached a joint settlement agreement with Louisiana Staff, Walmart, Inc. and the Alliance for Affordable Energy. In May 2020, the Arkansas Commission approved the settlement agreement as filed, with the exception that SWEPCo use its formula rate rider to recover its costs rather than the requested rider. SWEPCo is seeking regulatory approvals by July 2020.

Hydroelectric Generation

Evaluating Sale of Hydroelectric Generation

In March 2020, management placed 10 hydroelectric generation plants under study for a potential sale. The table below shows the net book value of each plant, including CWIP and materials and supplies, before cost of removal of the plants included in the study.



Owner	Plant Name	Units	State	Net Book Value as of March 31, 2020		Net Maximum Capacity (MWs)	Year Plant or First Unit Commissioned
				(in millions)
AGR	Racine	2	OH	$	43.2	48	1982
APCo	London	3	WV	9.6		14	1935
APCo	Marmet	3	WV	11.0		14	1935
APCo	Winfield	3	WV	13.9		15	1938
I&M	Berrien Springs	12	MI	7.7		6	1908
I&M	Buchanan	10	MI	5.1		3	1919
I&M	Constantine	4	MI	2.6		1	1921
I&M	Elkhart	3	IN	5.5		3	1913
I&M	Mottville	4	MI	2.9		2	1923
I&M	Twin Branch Hydro	8	IN	7.1		5	1904
	Total			$	108.6	111

If management decides to proceed with the sale of these plants, FERC approval would be required. In addition, for all plants, except for Racine, state commission approval would be required. Management currently estimates that any potential sale of these plants would not be completed until late 2020 at the earliest. There is no assurance that management will be able to sell any of these plants.

Dolet Hills Power Station and Related Fuel Operations

During the second quarter of 2019, the Dolet Hills Power Station initiated a seasonal operating schedule. In January 2020, in accordance with the terms of SWEPCo’s settlement of its base rate review filed with the APSC, management announced that SWEPCo will seek regulatory approval to retire the Dolet Hills Power Station by the end of 2026. DHLC provides 100% of the fuel supply to Dolet Hills Power Station. In March 2020, it was determined that DHLC would not proceed developing additional mining areas for future lignite extraction and management notified a substantial portion of its workforce that employment will permanently end in June 2020. Based on these actions, management has revised the estimated useful life of many of DHLC’s assets to June 2020 to coincide with the date at which extraction is expected to be discontinued. Management also revised the useful life of the Dolet Hills Power Station to September 2021 based on the remaining estimated fuel supply available for continued seasonal operation. In March 2020, primarily due to the revision in the useful life of DHLC, SWEPCo recorded a revision to increase estimated ARO liabilities by $21 million. In April 2020, SWEPCo and CLECO jointly filed a notification letter to the LPSC providing notice of the pending cessation of lignite mining in June 2020.

The Dolet Hills Power Station costs are recoverable by SWEPCo through base rates. SWEPCo’s share of the net investment in the Dolet Hills Power Station is $151 million, including CWIP and materials and supplies, before cost of removal.

Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses. Under the Lignite Mining Agreement, DHLC bills SWEPCo its proportionate share of incurred lignite extraction and associated mining-related costs as fuel is delivered. As of March 31, 2020, DHLC has unbilled lignite inventory and fixed costs of $124 million that will be billed to SWEPCo prior to the closure of the Dolet Hills Power Station. In 2009, SWEPCo acquired interests in the Oxbow Lignite Company (Oxbow), which owns mineral rights and leases land. Under a Joint Operating Agreement pertaining to the Oxbow mineral rights and land leases, Oxbow bills SWEPCo its proportionate share of incurred costs. As of March 31, 2020, Oxbow has unbilled fixed costs of $26 million that will be billed to SWEPCo prior to the closure of the Dolet Hills Power Station. Additional operational and land-related costs are expected to be incurred by DHLC and Oxbow and billed to SWEPCo prior to the closure of the Dolet Hills Power Station and recovered through fuel clauses.

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

FERC Transmission ROE Methodology

In November 2019, the FERC issued Opinion No. 569, which adopted a revised methodology for determining whether an existing base ROE is just and reasonable under Federal Power Act and determined the base ROE for MISO’s transmission-owning members should be reduced to 9.88% (10.38% inclusive of RTO incentive adder of 0.5%). The revised ROE methodology relies on two financial models, which include the discounted cash flow model and the capital asset pricing model, to establish a composite zone of reasonableness. In December 2019, AEP filed multiple requests for rehearing and participated in filing comments and requests for rehearing on behalf of transmission owners and industry organizations. Management believes FERC Opinion No. 569 reverses the expectation of a four-model framework proposed by FERC in 2018 and vetted widely in FERC 2019 Notice of Inquiry regarding base ROE policy. Management does not believe this ruling will have a material impact on financial results for its MISO transmission owning subsidiaries. In the second quarter of 2019, FERC approved settlement agreements establishing base ROEs of 9.85% (10.35% inclusive of RTO incentive adder of 0.5%) and 10% (10.5% inclusive of RTO incentive adder of 0.5%) for AEP’s PJM and SPP transmission-owning subsidiaries, respectively. In March 2020, as a follow-up to its 2019 Notice of Inquiry regarding transmission incentives policy, FERC issued a Notice of Proposed Rulemaking and requested comments by July 2020. AEP will file comments and monitor this proceeding. If FERC makes any changes to its ROE and incentive policies, they would be applied to AEP’s PJM and SPP transmission owning subsidiaries on a prospective basis, and could affect future net income and cash flows and impact financial condition.

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.

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.

Management will continue to defend against the claims. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management cannot determine a range of potential losses that is reasonably possible of occurring.

Patent Infringement Complaint

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

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

The American Electric Power System Retirement Plan (the Plan) has received a letter written on behalf of four participants (the Claimants) making a claim for additional plan benefits and purporting to advance such claims on behalf of a class. When the Plan’s benefit formula was changed in the year 2000, AEP provided a special provision for employees hired before January 1, 2001, allowing them to continue benefit accruals under the then benefit formula for a full 10 years alongside of the new cash balance benefit formula then being implemented. Employees who were hired on or after January 1, 2001 accrued benefits only under the new cash balance benefit formula. The Claimants have asserted claims that (a) the Plan violates the requirements under the Employee Retirement Income Security Act (ERISA) intended to preclude back-loading the accrual of benefits to the end of a participant’s career; (b) the Plan violates the age discrimination prohibitions of ERISA and the Age Discrimination in Employment Act (ADEA); and (c) the company failed to provide required notice regarding the changes to the Plan. AEP has responded to the Claimants providing a reasoned explanation for why each of their claims have been denied, and the denial to those claims have been appealed to the AEP System Retirement Plan Appeal Committee. Management will continue to defend against the claims. 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, 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 other parties, challenged some of the Federal EPA requirements. 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 cannot 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 AEP System generating units. Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance. As of March 31, 2020, the AEP System had generating capacity of approximately 25,500 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 fossil generation. Based upon management estimates, AEP’s future investment to meet these existing and proposed requirements ranges from approximately $500 million to $1 billion through 2026.

The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in finalizing proposed rules or 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, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors. In addition, management 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, 2020.



		Generating	Amounts Pending
Company	Plant Name and Unit	Capacity	Regulatory Approval
		(in MWs)	(in millions)
APCo (a)	Kanawha River Plant	400	$	14.0
APCo (b)	Clinch River Plant	705	25.3
APCo (a)	Sporn Plant, Units 1 and 3	300	2.0
APCo (a)	Glen Lyn Plant	335	3.4
SWEPCo (c)	Welsh Plant, Unit 2	528	35.5
Total		2,268	$	80.2


(a)	Remaining amounts pending regulatory approval represent the FERC and the West Virginia jurisdictional share.


(b)	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.


(c)	Remaining amount pending regulatory approval represents the FERC and Louisiana jurisdictional share.

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.

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 district court seeking to modify the consent decree to eliminate an obligation to install future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. The other parties to the consent decree opposed AEP’s motion. The district court granted AEP’s request to delay the deadline to install Selective Catalytic Reduction (SCR) technology at Rockport Plant, Unit 2 until June 2020.

In May 2019, the parties filed a proposed order to modify the consent decree. The proposed order requires AEP to enhance the dry sorbent injection (DSI) system on both units at the Rockport Plant by the end of 2020, and meet 30-day rolling average emission rates for SO₂ and NO_x at the combined stack for the Rockport Plant beginning in 2021. Total SO₂ emissions from the Rockport Plant are limited to 10,000 tons per year beginning in 2021 and reduce to 5,000 tons per year when Rockport Plant, Unit 1 retires in 2028. The proposed modification was approved by the district court and became effective in July 2019. As part of the modification to the consent decree, I&M agreed to provide an additional $7.5 million to citizens’ groups and the states for environmental mitigation projects. As joint owners in the Rockport Plant, the $7.5 million payment was shared between AEGCo and I&M based on the joint ownership agreement.

In April 2020, an employee at the Rockport Plant was diagnosed with COVID-19. Several contract workers stopped working on the SCR project at Rockport Unit 2, and the project workforce reported an increased rate of absenteeism. I&M has notified the parties to the consent decree of this force majeure event and estimates that the date for completion of the SCR and DSI projects will be extended by approximately two weeks past the June 1, 2020 deadline. Management will continue to oversee the project through completion in light of these challenges.

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 generation 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 Federal EPA is currently reviewing both of these standards. A proposed rule to retain the existing PM standards was released in April 2020. 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.

The Federal EPA finalized non-attainment designations for the 2015 ozone standard in 2018. The Federal EPA 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 and the Federal EPA’s determination that CSAPR satisfies certain states’ interstate transport obligations were filed in the U.S. Court of Appeals for the District of Columbia Circuit. In August 2019, the court upheld the 2015 primary ozone standard, but remanded the secondary welfare-based standard for further review. The court vacated the Federal EPA’s determination that CSAPR fulfilled the states’ interstate transport obligations, because the Federal EPA’s modeling analysis did not demonstrate that all significant contributions would be eliminated by the attainment deadlines for downwind states. Any further changes will require additional rulemaking. Management cannot currently predict the nature, stringency or timing of additional requirements for AEP’s facilities based on the outcome of these activities.

Regional Haze

The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA’s requirement that certain facilities install best available retrofit technology (BART) would address regional haze in federal parks and other protected areas. BART requirements apply to certain 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.

The Federal EPA initially disapproved portions of the Arkansas regional haze SIP, but has approved a revised SIP and all of SWEPCo's affected units are in compliance with the relevant 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 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. In November 2019, in response to comment, the Federal EPA proposed revisions to the intrastate trading program. Management supports the intrastate trading program 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, the CSAPR Update, to address the remand and to incorporate additional changes necessary to address the 2008 ozone standard. The CSAPR Update significantly reduced ozone season budgets in many states and discounted the value of banked CSAPR ozone season allowances beginning with the 2017 ozone season. In 2019, the appeals court remanded the CSAPR Update to the Federal EPA because it determined the Federal EPA had not properly considered the attainment dates for downwind areas in establishing its partial remedy, and should have considered whether there were available measures to control emissions from sources other than generating units. Any further changes to the CSAPR rule will require additional rulemaking.

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

In 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants. The rule 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. In April 2020, the Federal EPA released a final rule adopting the conclusions set forth in the proposal and retaining the existing MATS standards.

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).

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

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

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

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

In September 2019, AEP announced new intermediate and long-term CO₂ emission reduction goals, based on the 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 70% reduction from 2000 CO₂ emission levels from AEP generating facilities by 2030; the long-term goal is to surpass an 80% reduction of CO₂ emissions from AEP generating facilities from 2000 levels by 2050. AEP’s total estimated CO₂emissions in 2019 were approximately 58 million metric tons, a 65% reduction from AEP’s 2000 CO₂ emissions. AEP has made significant progress in reducing CO₂ emissions from its power generation fleet and expects its emissions to continue to decline. AEP’s aspirational emissions goal is zero CO₂ emissions by 2050. Technological advances, including energy storage, will determine how quickly AEP can achieve zero emissions while continuing to provide reliable, affordable power for customers.

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

Coal Combustion Residual (CCR) Rule

In 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 have been undertaken at four facilities.

In a challenge to the final 2015 rule, the parties initially agreed to settle some of the issues. In 2018, the U.S. Court of Appeals for the District of Columbia Circuit addressed or dismissed the remaining issues in its decision vacating and remanding certain provisions of the 2015 rule. The provisions addressed by the court’s decision, including changes to 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. In November 2019, the Federal EPA proposed revisions to implement the court’s decision regarding the timing for closure of unlined surface impoundments along with impoundments not meeting the required distance from an aquifer. The comment period closed in January 2020. In December 2019, the Federal EPA proposed a federal permit program, implementing the Water Infrastructure Improvements for the Nation Act, that would apply in states that do not have an approved CCR program.

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

permitting requirements under the CWA. Management is unable to predict the impact of these developments on AEP’s facilities.

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. Additional ARO revisions will occur on a site-by-site basis if groundwater monitoring activities conclude that corrective actions are required to mitigate groundwater impacts, which could include costs to remove ash from some unlined units.

In March 2020, Virginia’s Governor signed House Bill 443 (HB 443) requiring APCo to close ash disposal units at the retired Glen Lyn Station by removal of all coal combustion material. APCo’s current ARO for these units is based on closure in place and will require future revision to reflect the costs of closure by removal. As of March 31, 2020, APCo is unable to reasonably estimate this cost. Management expects to record a material revision to the ARO after engineering plans for the removal are developed later in 2020. The closure is required to be completed within 15 years from the start of the excavation process. HB 443 provides for the recovery of all costs associated with closure by removal through the Virginia environmental rate adjustment clause (E-RAC). APCo may begin deferring incurred costs on July 1, 2020 and recovering these costs through the E-RAC beginning July 1, 2022. APCo is permitted to record carrying costs on the unrecovered balance of closure costs at a weighted average cost of capital approved by the Virginia SCC. HB 443 also allows any closure costs allocated to non-Virginia jurisdictional customers, but not collected from such non-Virginia jurisdictional customers, to be recovered from Virginia jurisdictional customers through the E-RAC. Management does not expect HB 443 to materially impact results of operations or cash flows, but does anticipate a material impact to APCo’s balance sheet.

If removal of ash is required without providing similar assurances of cost recovery in regulated jurisdictions, it would impose significant additional operating costs on AEP, which could lead to increased financing costs and liquidity needs. Other units in Virginia, Ohio, West Virginia, and Kentucky already have been closed in place in accordance with state law programs. Management will continue to participate in rulemaking activities and make adjustments based on new federal and state requirements affecting its ash disposal units.

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. In April 2019, the Fifth Circuit vacated the standards for landfill leachate and legacy wastewater, and remanded them to the Federal EPA for reconsideration. In November 2019, the Federal EPA proposed revisions to the guidelines for existing generation facilities. The comment period ended in January 2020. 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. Various parties challenged the 2015 rule in different U.S. District Courts, which resulted in a patchwork of applicability of the 2015

rule and its predecessor. In December 2018, the Federal EPA and the U.S. Army Corps of Engineers proposed a replacement rule. In September 2019, the Federal EPA repealed the 2015 rule. The final replacement rule was published in the Federal Register in April 2020 and will become effective in June 2020. The final rule limits the scope of CWA jurisdiction to four categories of waters, and clarifies exclusions for ground water, ephemeral streams, artificial ponds and waste treatment systems.

In April 2020, the U.S. District Court for the District of Montana issued a decision vacating the U.S. Army Corps of Engineers’ (Corps) General Nationwide Permit 12 (NWP 12), which provides standard conditions governing linear utility projects in streams, wetlands and other waters of the United States having minimal adverse environmental impacts. The Court found that in reissuing NWP 12 in 2017, the Corps failed to comply with Section 7 of the Endangered Species Act (ESA), which requires the Corps to consult with the U.S. Fish and Wildlife Service regarding potential impacts on endangered species. The Court remanded the permit back to the Corps to complete its ESA consultation, and also enjoined the Corps from authorizing any dredge or fill activities under NWP 12 pending completion of the consultation process. The Department of Justice filed a motion to stay the injunction and tailor the remedy imposed by the Court, and the court ordered the parties to file briefs on the issue in May 2020. Management is monitoring the litigation and evaluating other permitting alternatives, but is currently unable to predict the impact of this decision on current and planned projects.

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.


•	Contracted renewable energy investments and management services.


•	Marketing, risk management and retail activities in ERCOT, MISO, PJM and SPP.

The remainder of AEP’s activities are presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.

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

The following table presents Earnings (Loss) Attributable to AEP Common Shareholders by segment:



	Three Months Ended March 31,
	2020			2019
	(in millions)
Vertically Integrated Utilities	$	245.3		$	302.4
Transmission and Distribution Utilities	116.2			156.5
AEP Transmission Holdco	140.6			124.2
Generation & Marketing	28.4			40.1
Corporate and Other	(35.3		)	(50.4		)
Earnings Attributable to AEP Common Shareholders	$	495.2		$	572.8

AEP CONSOLIDATED

First Quarter of 2020 Compared to First Quarter of 2019

Earnings Attributable to AEP Common Shareholders decreased from $573 million in 2019 to $495 million in 2020 to primarily due to:


•	A decrease in weather-related usage.


•	A one-time reversal of a regulatory provision in 2019.

These decreases were partially offset by:


•	Favorable rate proceedings in AEP’s various jurisdictions.

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

VERTICALLY INTEGRATED UTILITIES



		Three Months Ended March 31,
Vertically Integrated Utilities		2020			2019
	(in millions)
Revenues		$	2,226.7		$	2,403.3
Fuel and Purchased Electricity		671.2			856.4
Gross Margin		1,555.5			1,546.9
Other Operation and Maintenance		691.3			690.1
Depreciation and Amortization		381.7			356.3
Taxes Other Than Income Taxes		117.1			116.0
Operating Income		365.4			384.5
Other Income		1.6			1.3
Allowance for Equity Funds Used During Construction		8.2			10.7
Non-Service Cost Components of Net Periodic Benefit Cost		16.9			17.0
Interest Expense		(144.5		)	(139.0		)
Income Before Income Tax Expense (Benefit) and Equity Earnings		247.6			274.5
Income Tax Expense (Benefit)		2.1			(28.4		)
Equity Earnings of Unconsolidated Subsidiary		0.8			0.7
Net Income		246.3			303.6
Net Income Attributable to Noncontrolling Interests		1.0			1.2
Earnings Attributable to AEP Common Shareholders		$	245.3		$	302.4

Summary of KWh Energy Sales for Vertically Integrated Utilities



	Three Months Ended March 31,
	2020	2019
	(in millions of KWhs)
Retail:
Residential	8,262	9,216
Commercial	5,366	5,633
Industrial	8,475	8,545
Miscellaneous	530	546
Total Retail	22,633	23,940

Wholesale (a)	3,618	5,804

Total KWhs	26,251	29,744


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

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

Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities



	Three Months Ended March 31,
	2020	2019
	(in degree days)
Eastern Region
Actual – Heating (a)	1,241	1,571
Normal – Heating (b)	1,611	1,595

Actual – Cooling (c)	13	1
Normal – Cooling (b)	5	5

Western Region
Actual – Heating (a)	649	941
Normal – Heating (b)	867	866

Actual – Cooling (c)	51	11
Normal – Cooling (b)	28	28


(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 2020 Compared to First Quarter of 2019



Reconciliation of First Quarter of 2019 to First Quarter of 2020
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)

First Quarter of 2019	$	302.4

Changes in Gross Margin:
Retail Margins	5.9
Margins from Off-system Sales	(5.2		)
Transmission Revenues	6.1
Other Revenues	1.8
Total Change in Gross Margin	8.6

Changes in Expenses and Other:
Other Operation and Maintenance	(1.2		)
Depreciation and Amortization	(25.4		)
Taxes Other Than Income Taxes	(1.1		)
Other Income	0.3
Allowance for Equity Funds Used During Construction	(2.5		)
Non-Service Cost Components of Net Periodic Pension Cost	(0.1		)
Interest Expense	(5.5		)
Total Change in Expenses and Other	(35.5		)

Income Tax Expense	(30.5		)
Equity Earnings of Unconsolidated Subsidiary	0.1
Net Income Attributable to Noncontrolling Interests	0.2

First Quarter of 2020	$	245.3

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


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


•	A $25 million increase related to fuel at APCo and I&M, primarily due to the timing of recoverable PJM expenses. This increase was partially offset in other expense items below.


•	A $14 million increase due to the impact of the 2019 WVPSC order which required APCo and WPCo to offset Excess ADIT not subject to normalization requirements against the deferred fuel under-recovery balance in 2019.


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


▪	A $14 million increase from rate proceedings at I&M. This increase was partially offset in other expense items below.


▪	An $11 million increase at PSO due to new base rates implemented in April 2019.


▪	An $11 million increase at SWEPCo primarily due to capital investment rider and base rate revenue increases in Texas, Arkansas and Louisiana.


▪	An $11 million increase at APCo and WPCo due to a base rate increase in West Virginia that was partially offset in Depreciation and Amortization expenses below.


▪	A $5 million increase at APCo and WPCo due to revenue primarily from rate riders in West Virginia.


•	A $9 million increase due to customer refunds related to the 2018 Tax Reform. This increase was partially offset in Income Tax Expense (Benefit) below.

These increases were partially offset by:


•	A $61 million decrease in weather-related usage primarily in the eastern region and primarily in the residential class.


•	A $28 million decrease in weather-normalized retail margins primarily in the eastern region and primarily in the commercial and industrial classes.


•	A $7 million decrease in revenue from rate riders at PSO. This decrease was partially offset in other expense items below.


•	Margins from Off-system Sales decreased $5 million primarily due to WPCo’s historical merchant portion of Mitchell Plant moving to base rates beginning January 2020 and weaker market prices for energy in the RTOs which caused a significant decrease in sales volume.


•	Transmission Revenues increased $6 million primarily due to an increase in SPP transmission services revenue at SWEPCo.

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


•	Other Operation and Maintenance expenses increased $1 million primarily due to the following:


•	An $11 million increase due to PJM transmission services including the annual formula rate true-up.


•	A $5 million increase due to SPP transmission services including the annual formula rate true-up.


•	A $3 million increase due to North Central Wind Energy Facilities expenses for SWEPCo and PSO.

These increases were partially offset by:


•	An $11 million decrease in employee-related expenses.


•	A $7 million decrease due to an increased Nuclear Electric Insurance Limited distribution in 2020.


•	Depreciation and Amortization expenses increased $25 million primarily due to a higher depreciable base and increased depreciation rates approved at APCo, I&M and SWEPCo. This increase was partially offset in Retail Margins above.


•	Interest Expense increased $6 million primarily due to higher long-term debt balances at APCo.


•	Income Tax Expense increased $31 million primarily due to a decrease in amortization of Excess ADIT. The decrease in amortization of excess ADIT is partially offset above in Gross Margin and Other Operation and Maintenance expenses.

TRANSMISSION AND DISTRIBUTION UTILITIES



		Three Months Ended March 31,
Transmission and Distribution Utilities		2020			2019
	(in millions)
Revenues		$	1,106.9		$	1,222.0
Purchased Electricity		191.4			229.7
Amortization of Generation Deferrals		—			32.4
Gross Margin		915.5			959.9
Other Operation and Maintenance		367.2			405.9
Depreciation and Amortization		214.5			183.7
Taxes Other Than Income Taxes		146.2			145.5
Operating Income		187.6			224.8
Interest and Investment Income		0.7			1.3
Carrying Costs Income		0.4			0.2
Allowance for Equity Funds Used During Construction		7.0			6.9
Non-Service Cost Components of Net Periodic Benefit Cost		7.3			7.6
Interest Expense		(71.4		)	(62.0		)
Income Before Income Tax Expense		131.6			178.8
Income Tax Expense		15.4			22.3
Net Income		116.2			156.5
Net Income Attributable to Noncontrolling Interests		—			—
Earnings Attributable to AEP Common Shareholders		$	116.2		$	156.5

Summary of KWh Energy Sales for Transmission and Distribution Utilities



	Three Months Ended March 31,
	2020	2019
	(in millions of KWhs)
Retail:
Residential	6,300	6,547
Commercial	5,873	5,618
Industrial	5,908	5,771
Miscellaneous	182	176
Total Retail (a)	18,263	18,112

Wholesale (b)	390	638

Total KWhs	18,653	18,750

(a)Represents energy delivered to distribution customers.

(b)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,
	2020	2019
	(in degree days)
Eastern Region
Actual – Heating (a)	1,473	1,892
Normal – Heating (b)	1,898	1,877

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

Western Region
Actual – Heating (a)	91	177
Normal – Heating (b)	185	187

Actual – Cooling (d)	231	122
Normal – Cooling (b)	125	123


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


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


(c)	Eastern Region cooling degree days are calculated on a 65 degree temperature base.


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

First Quarter of 2020 Compared to First Quarter of 2019



Reconciliation of First Quarter of 2019 to First Quarter of 2020
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)

First Quarter of 2019	$	156.5

Changes in Gross Margin:
Retail Margins	(74.2		)
Margins from Off-system Sales	0.7
Transmission Revenues	11.9
Other Revenues	17.2
Total Change in Gross Margin	(44.4		)

Changes in Expenses and Other:
Other Operation and Maintenance	38.7
Depreciation and Amortization	(30.8		)
Taxes Other Than Income Taxes	(0.7		)
Interest and Investment Income	(0.6		)
Carrying Costs Income	0.2
Allowance for Equity Funds Used During Construction	0.1
Non-Service Cost Components of Net Periodic Benefit Cost	(0.3		)
Interest Expense	(9.4		)
Total Change in Expenses and Other	(2.8		)

Income Tax Expense	6.9

First Quarter of 2020	$	116.2

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


•	Retail Margins decreased $74 million primarily due to the following:


•	A $58 million decrease due to a reversal of a regulatory provision in Ohio in the first quarter of 2019.


•	A $39 million net decrease in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses. This decrease was partially offset in Other Operation and Maintenance expenses below.


•	A $13 million decrease in Ohio Deferred Asset Phase-In-Recovery Rider revenues which ended in the second quarter of 2019. This decrease was offset in Depreciation and Amortization expenses below.


•	A $7 million net decrease in margin in Ohio for the Rate Stability Rider including associated amortizations which ended in the third quarter of 2019.


•	A $5 million decrease due to the OVEC PPA Rider which was replaced by the Legacy Generation Resource Rider (LGRR). This decrease was offset in Margins from Off-system Sales and Other Revenues below.


•	A $4 million decrease in weather-related usage in Texas primarily due to a 49% decrease in heating degree days, partially offset by an 89% increase in cooling degree days.


•	A $3 million decrease in revenues associated with a vegetation management rider in Ohio. This decrease was offset in Other Operation and Maintenance expenses below.

These decreases were partially offset by:


•	A $17 million increase in rider revenues in Ohio associated with the DIR. This increase was partially offset in other expense items below.


•	A $13 million increase in weather-normalized margins primarily in the residential and commercial classes in Texas.


•	A $7 million increase in revenues associated with Ohio smart grid riders. This increase was partially offset in other expense items below.


•	A $7 million increase in revenues in Ohio associated with the Universal Service Fund (USF). This increase was offset in Other Operation and Maintenance expenses below.


•	A $7 million increase in revenues primarily due to the Transmission Cost Recovery Factor revenue rider in Texas.


•	A $3 million increase in Ohio Energy Efficiency/Peak Demand Reduction rider revenues. This increase was offset in Other Operation and Maintenance expenses below.


•	Transmission Revenues increased $12 million primarily due to recovery of increased transmission investment in ERCOT.


•	Other Revenues increased $17 million primarily due to the following:


•	A $12 million increase primarily due to securitization revenue in Texas. This increase was offset below in Depreciation and Amortization expenses and in Interest Expense.


•	A $4 million increase due to third-party LGRR revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins above.

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


•	Other Operation and Maintenance expenses decreased $39 million primarily due to the following:


•	A $40 million decrease in PJM expenses that were fully recovered in rate riders/trackers in Gross Margin above.


•	A $6 million decrease in PJM expenses primarily related to the annual formula rate true-up.

These decreases were partially offset by:


•	An $8 million increase in distribution-related expenses.


•	A $7 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset in Retail Margins above.


•	Depreciation and Amortization expenses increased $31 million primarily due to the following:


•	A $15 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.


•	A $12 million increase in securitization amortizations in Texas. This increase was offset in Other Revenues above and in Interest Expense below.


•	A $5 million increase due to lower deferred equity amortizations associated with the Deferred Asset Phase-In-Recovery Rider in Ohio which ended in the second quarter of 2019.


•	A $5 million increase in Ohio recoverable DIR depreciation expense. This increase was partially offset in Retail Margins above.

These increases were partially offset by:


•	A $10 million decrease in amortizations associated with the Deferred Asset Phase-In-Recovery Rider in Ohio which ended in the second quarter of 2019. This decrease was offset in Retail Margins above.


•	Interest Expense increased $9 million primarily due to higher long-term debt balances.


•	Income Tax Expense decreased $7 million due to a decrease in pretax book income, partially offset by a decrease in amortization of Excess ADIT. The decrease in amortization of Excess ADIT is partially offset in Retail Margins above.

AEP TRANSMISSION HOLDCO



		Three Months Ended March 31,
AEP Transmission Holdco		2020			2019
	(in millions)
Transmission Revenues		$	310.2		$	256.4
Other Operation and Maintenance		29.9			22.3
Depreciation and Amortization		58.1			41.8
Taxes Other Than Income Taxes		51.9			42.6
Operating Income		170.3			149.7
Interest and Investment Income		0.9			0.7
Allowance for Equity Funds Used During Construction		16.2			11.3
Non-Service Cost Components of Net Periodic Benefit Cost		0.5			0.6
Interest Expense		(30.8		)	(23.0		)
Income Before Income Tax Expense and Equity Earnings		157.1			139.3
Income Tax Expense		38.4			31.9
Equity Earnings of Unconsolidated Subsidiary		22.9			17.8
Net Income		141.6			125.2
Net Income Attributable to Noncontrolling Interests		1.0			1.0
Earnings Attributable to AEP Common Shareholders		$	140.6		$	124.2

Summary of Investment in Transmission Assets for AEP Transmission Holdco



	As of March 31,
	2020		2019
	(in millions)
Plant in Service	$	9,086.6	$	7,073.6
Construction Work in Progress	1,576.3		1,899.6
Accumulated Depreciation and Amortization	464.0		318.8
Total Transmission Property, Net	$	10,198.9	$	8,654.4

First Quarter of 2020 Compared to First Quarter of 2019

Reconciliation of First Quarter of 2019 to First Quarter of 2020

Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco

(in millions)



First Quarter of 2019	$	124.2

Changes in Transmission Revenues:
Transmission Revenues	53.8
Total Change in Transmission Revenues	53.8

Changes in Expenses and Other:
Other Operation and Maintenance	(7.6		)
Depreciation and Amortization	(16.3		)
Taxes Other Than Income Taxes	(9.3		)
Other Income	0.2
Allowance for Equity Funds Used During Construction	4.9
Non-Service Cost Components of Net Periodic Pension Cost	(0.1		)
Interest Expense	(7.8		)
Total Change in Expenses and Other	(36.0		)

Income Tax Expense	(6.5		)
Equity Earnings of Unconsolidated Subsidiary	5.1

First Quarter of 2020	$	140.6

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


•	Transmission Revenues increased $54 million primarily due to continued investment in transmission assets.

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


•	Other Operation and Maintenance expenses increased $8 million primarily due to the following:


•	A $3 million increase due to employee-related expenses.


•	A $2 million increase due to higher rent expense.


•	A $2 million increase due to continued investment in transmission assets.


•	Depreciation and Amortization expenses increased $16 million primarily due to a higher depreciable base.


•	Taxes Other Than Income Taxes increased $9 million primarily due to higher property taxes as a result of increased transmission investment.


•	Allowance for Equity Funds Used During Construction increased $5 million primarily due to the following:


•	A $9 million increase due to prior year FERC audit findings.

This increase was partially offset by:


•	A $5 million decrease due to a decrease in CWIP.


•	Interest Expense increased $8 million primarily due to higher long-term debt balances.


•	Income Tax Expense increased $7 million primarily due to higher pretax book income.


•	Equity Earnings of Unconsolidated Subsidiary increased $5 million primarily due to higher pretax equity earnings at PATH-WV.

GENERATION & MARKETING



		Three Months Ended March 31,
Generation & Marketing		2020			2019
	(in millions)
Revenues		$	438.6		$	481.8
Fuel, Purchased Electricity and Other		360.3			383.3
Gross Margin		78.3			98.5
Other Operation and Maintenance		41.4			50.6
Depreciation and Amortization		17.7			12.9
Taxes Other Than Income Taxes		3.4			3.8
Operating Income		15.8			31.2
Interest and Investment Income		1.0			2.3
Non-Service Cost Components of Net Periodic Benefit Cost		3.9			3.7
Interest Expense		(8.5		)	(3.8		)
Income Before Income Tax Benefit and Equity Earnings		12.2			33.4
Income Tax Benefit		(12.4		)	(5.8		)
Equity Earnings of Unconsolidated Subsidiaries		5.9			—
Net Income		30.5			39.2
Net Earnings (Loss) Attributable to Noncontrolling Interests		2.1			(0.9		)
Earnings Attributable to AEP Common Shareholders		$	28.4		$	40.1

Summary of MWhs Generated for Generation & Marketing



	Three Months Ended March 31,
	2020	2019
	(in millions of MWhs)
Fuel Type:
Coal	1	1
Renewables	1	—
Total MWhs	2	1

First Quarter of 2020 Compared to First Quarter of 2019



Reconciliation of First Quarter of 2019 to First Quarter of 2020
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)

First Quarter of 2019	$	40.1

Changes in Gross Margin:
Merchant Generation	(37.4		)
Renewable Generation	13.3
Retail, Trading and Marketing	3.9
Total Change in Gross Margin	(20.2		)

Changes in Expenses and Other:
Other Operation and Maintenance	9.2
Depreciation and Amortization	(4.8		)
Taxes Other Than Income Taxes	0.4
Interest and Investment Income	(1.3		)
Non-Service Cost Components of Net Periodic Benefit Cost	0.2
Interest Expense	(4.7		)
Total Change in Expenses and Other	(1.0		)

Income Tax Benefit	6.6
Equity Earnings of Unconsolidated Subsidiaries	5.9
Net Earnings (Loss) Attributable to Noncontrolling Interests	(3.0		)

First Quarter of 2020	$	28.4

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


•	Merchant Generation decreased $37 million primarily due to lower energy margins in 2020 and a reduction in revenues related to the retirement of Conesville Units 5 and 6 in 2019.


•	Renewable Generation increased $13 million primarily due to the acquisition of Sempra Renewables LLC and new projects placed in-service.


•	Retail, Trading and Marketing increased $4 million due to higher retail margins partially offset by lower trading and marketing activity.

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


•	Other Operation and Maintenance expenses decreased $9 million primarily due to the retirement of Conesville Units 5 and 6 in 2019 partially offset by expenses related to increased investments in wind farms and other renewable energy sources.


•	Depreciation and Amortization expenses increased $5 million due to a higher depreciable base from increased investments in renewable energy sources.


•	Interest Expense increased $5 million primarily due to increased borrowing costs related to the Sempra Renewables LLC acquisition.


•	Income Tax Benefit increased $7 million primarily due to a decrease in pretax book income and an increase in PTC.


•	Equity Earnings of Unconsolidated Subsidiaries increased $6 million primarily due to the Sempra Renewables LLC acquisition.

CORPORATE AND OTHER

First Quarter of 2020 Compared to First Quarter of 2019

Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $50 million in 2019 to a loss of $35 million in 2020 primarily due to:


•	A $22 million decrease in income tax expense due to a decrease in consolidating tax adjustments and discrete items recorded in 2019.


•	A $13 million decrease in general corporate expenses.


•	A $5 million write-off of an equity investment and related assets in 2019.

These items were partially offset by:

•A $14 million decrease in interest income due to a lower return on investments held by EIS.

•An $11 million increase in interest expense as a result of increased debt outstanding.

AEP SYSTEM INCOME TAXES

First Quarter of 2020 Compared to First Quarter of 2019

Income Tax Expense increased $2 million primarily due to a decrease in amortization of Excess ADIT. This increase is partially offset by a decrease in pretax book income and an increase in PTC.

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, 2020				December 31, 2019
	(dollars in millions)
Long-term Debt, including amounts due within one year	$	27,892.7	53.3	%	$	26,725.5	54.1	%
Short-term Debt	4,464.1		8.5		2,838.3		5.7
Total Debt	32,356.8		61.8		29,563.8		59.8
AEP Common Equity	19,728.4		37.7		19,632.2		39.6
Noncontrolling Interests	279.3		0.5		281.0		0.6
Total Debt and Equity Capitalization	$	52,364.5	100.0	%	$	49,477.0	100.0	%

AEP’s ratio of debt-to-total capital increased from 59.8% as of December 31, 2019 to 61.8% as of March 31, 2020 primarily due to an increase in short-term debt to enhance liquidity as a result of volatility in the capital markets.

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, 2020, 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, leasing agreements, hybrid securities or common stock. There was increased volatility in the capital markets during the first quarter of 2020

resulting in higher commercial paper cost and limited access. To address these issues and the uncertainty around COVID-19, in March 2020, AEP entered into a $1 billion 364-day Term Loan and borrowed the full amount.

Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments. As of March 31, 2020, available liquidity was approximately $2.8 billion as illustrated in the table below:



		Amount		Maturity
Commercial Paper Backup:		(in millions)
	Revolving Credit Facility	$	4,000.0	June 2022
	364-Day Term Loan	1,000.0		March 2021
Cash and Cash Equivalents		1,554.6
Total Liquidity Sources		6,554.6
Less:	AEP Commercial Paper Outstanding	2,709.6
	364-Day Term Loan	1,000.0

Net Available Liquidity		$	2,845.0

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 2020 was $3 billion. The weighted-average interest rate for AEP’s commercial paper during 2020 was 2.06%.

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 six uncommitted facilities totaling $405 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of March 31, 2020 was $241 million with maturities ranging from April 2020 to March 2021.

Securitized Accounts Receivables

AEP’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and expires in July 2021.

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 agreement excludes securitization bonds and debt of AEP Credit. As of March 31, 2020, this contractually-defined percentage was 59.8%. 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 were used to support AEP’s overall capital expenditure plans including the acquisition of Sempra Renewables LLC. See Note 12 - Financing Activities for additional information.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.70 per share in April 2020. Future dividends may vary depending upon AEP’s profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. Management does not believe these restrictions will have any significant impact on its ability to access cash to meet the payment of dividends on its common stock. See “Dividend Restrictions” section of Note 12 for additional information.

Credit Ratings

AEP 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,
	2020			2019
	(in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	$	432.6		$	444.1
Net Cash Flows from Operating Activities	615.7			808.3
Net Cash Flows Used for Investing Activities	(1,766.0		)	(1,582.8		)
Net Cash Flows from Financing Activities	2,388.5			693.5
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	1,238.2			(81.0		)
Cash, Cash Equivalents and Restricted Cash at End of Period	$	1,670.8		$	363.1

Operating Activities



	Three Months Ended March 31,
	2020			2019
	(in millions)
Net Income	$	499.3		$	574.1
Non-Cash Adjustments to Net Income (a)	692.1			618.8
Mark-to-Market of Risk Management Contracts	57.4			65.5
Property Taxes	(59.8		)	(75.6		)
Deferred Fuel Over/Under-Recovery, Net	63.1			32.5
Recovery of Ohio Capacity Costs	—			14.7
Refund of Global Settlement	—			(4.1		)
Change in Other Noncurrent Assets	(50.8		)	(47.9		)
Change in Other Noncurrent Liabilities	(74.8		)	67.3
Change in Certain Components of Working Capital	(510.8		)	(437.0		)
Net Cash Flows from Operating Activities	$	615.7		$	808.3


(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 decreased by $193 million primarily due to the following:


•	A $142 million decrease in cash from Change in Other Noncurrent Liabilities primarily due to increases in revenue refunds related to Tax Reform and Ohio regulatory liabilities.

•

A $74 million decrease in cash from Change in Certain Components of Working Capital. The decrease is primarily due to timing of accounts receivable and accounts payable, an increase in employee-related payments, a decrease in current year employee-related expenses and a decrease in accrued taxes primarily due to the Alternative Minimum Tax Credit Refund recorded as a result of the Coronavirus Aid, Relief, and Economic Security Act. These decreases were partially offset by a refund from the Department of Energy for SNF and by the reversal of a regulatory provision at OPCo in the prior year.

Investing Activities



	Three Months Ended March 31,
	2020			2019
	(in millions)
Construction Expenditures	$	(1,792.7	)	$	(1,565.4	)
Acquisitions of Nuclear Fuel	(1.3		)	(32.4		)
Other	28.0			15.0
Net Cash Flows Used for Investing Activities	$	(1,766.0	)	$	(1,582.8	)

Net Cash Flows Used for Investing Activities increased by $183 million primarily due to the following:


•	A $227 million increase due to increased construction expenditures, primarily driven by increases at AEP Transmission Holdco of $120 million, Vertically Integrated Utilities of $84 million and Transmission and Distribution Utilities of $19 million.

Financing Activities



	Three Months Ended March 31,
	2020			2019
	(in millions)
Issuance of Common Stock	$	56.1		$	14.5
Issuance/Retirement of Debt, Net	2,744.2			1,013.0
Dividends Paid on Common Stock	(363.7		)	(333.6		)
Other	(48.1		)	(0.4		)
Net Cash Flows from Financing Activities	$	2,388.5		$	693.5

Net Cash Flows from Financing Activities increased by $1.7 billion primarily due to the following:


•	A $1.7 billion increase in cash primarily due to an increase in short-term debt including the 364-day Term Loan borrowing. See Note 12 - Financing Activities for additional information.


•	A $133 million increase in issuances of long-term debt. See Note 12 - Financing Activities for additional information.

This increase in cash was partially offset by:


•	An $80 million decrease in cash due to increased retirements of long-term debt. See Note 12 - Financing Activities for additional information.

See “Long-term Debt Subsequent Events” section of Note 12 for Long-term debt and other securities issued, retired and principal payments made after March 31, 2020 through May 6, 2020, the date that the first quarter 10-Q was issued.

BUDGETED CAPITAL EXPENDITURES

Management currently estimates $5.8 billion of capital expenditures for 2020 and forecasts approximately $32.9 billion of capital expenditures for 2020 to 2024. Capital expenditures related to North Central Wind Energy Facilities are excluded from these budgeted amounts. The expenditures are generally for transmission, generation, distribution, regulated and contracted renewables, and required environmental investment to comply with the Federal EPA rules. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital. Management expects to fund these capital expenditures through cash flows from operations and financing activities. Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-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 2019 Annual Report.

CONTRACTUAL OBLIGATION INFORMATION

A summary of contractual obligations is included in the 2019 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 STANDARDS

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 2019 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 standards.

ACCOUNTING STANDARDS

See Note 2 - New Accounting Standards for information related to accounting standards adopted in 2020 and standards 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. 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, Executive Vice President of Utilities, Senior Vice President of Commercial Operations, Senior Vice President of Treasury and Risk and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Financial Officer, Senior Vice President of Treasury and Risk and Chief Risk Officer in addition to Energy Supply’s President and Vice President. When commercial activities exceed predetermined limits, positions are modified to reduce the risk to be within the limits unless specifically approved by the respective committee.

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

The following table summarizes the reasons for changes in total MTM value as compared to December 31, 2019:



MTM Risk Management Contract Net Assets (Liabilities)
Three Months Ended March 31, 2020

	Vertically Integrated Utilities			Transmission and Distribution Utilities			Generation & Marketing			Total
	(in millions)
Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2019	$	75.9		$	(103.6	)	$	163.4		$	135.7
Gain from Contracts Realized/Settled During the Period and Entered in a Prior Period	(36.7		)	(2.1		)	(6.9		)	(45.7		)
Fair Value of New Contracts at Inception When Entered During the Period (a)	—			—			0.5			0.5
Changes in Fair Value Due to Market Fluctuations During the Period (b)	—			—			(7.4		)	(7.4		)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)	(29.1		)	(17.3		)	—			(46.4		)
Total MTM Risk Management Contract Net Assets (Liabilities) as of March 31, 2020	$	10.1		$	(123.0	)	$	149.6		36.7
Commodity Cash Flow Hedge Contracts										(159.1		)
Interest Rate Cash Flow Hedge Contracts										(5.0		)
Fair Value Hedge Contracts										57.0
Collateral Deposits										75.8
Total MTM Derivative Contract Net Assets as of March 31, 2020										$	5.4


(a)	Reflects fair value on primarily long-term structured contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location and delivery term. A significant portion of the total volumetric position has been economically hedged.


(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, etc.


(c)	Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable.

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

Credit Risk

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

AEP has risk management contracts (includes non-derivative contracts) with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, exposures change daily. As of March 31, 2020, credit exposure net of collateral to sub investment grade counterparties was approximately 6.9%, 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, 2020, the following table approximates AEP’s counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:



Counterparty Credit 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	$	493.5	$	—	$	493.5	2	$	255.5
Split Rating	3.0		—		3.0		2	3.0
No External Ratings:
Internal Investment Grade	148.8		—		148.8		3	90.7
Internal Noninvestment Grade	58.5		10.5		48.0		2	30.1
Total as of March 31, 2020	$	703.8	$	10.5	$	693.3

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

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

Value at Risk (VaR) Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates VaR, to measure AEP’s commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, as of March 31, 2020, a near term typical change in commodity prices is not expected to materially impact net income, cash flows or financial condition.

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

VaR Model

Trading Portfolio



Three Months Ended								Twelve Months Ended
March 31, 2020								December 31, 2019
End		High		Average		Low		End		High		Average		Low
(in millions)								(in millions)
$	0.1	$	0.3	$	0.1	$	—	$	0.1	$	1.2	$	0.2	$	0.1

VaR Model

Non-Trading Portfolio



Three Months Ended								Twelve Months Ended
March 31, 2020								December 31, 2019
End		High		Average		Low		End		High		Average		Low
(in millions)								(in millions)
$	0.7	$	1.2	$	0.6	$	0.1	$	0.2	$	8.5	$	1.1	$	0.2

Management back-tests VaR results against performance due to actual price movements. Based on the assumed 95% confidence interval, the performance due to actual price movements would be expected to exceed the VaR at least once every 20 trading days.

As the VaR calculation captures recent price movements, management also performs regular stress testing of the trading portfolio to understand AEP’s exposure to extreme price movements. A historical-based method is employed whereby the current trading portfolio is subjected to actual, observed price movements from the last several years in order to ascertain which historical price movements translated into the largest potential MTM loss. Management then researches the underlying positions, price movements and market events that created the most significant exposure and reports the findings to the Risk Executive Committee, Regulated Risk Committee or Competitive Risk Committee as appropriate.

Interest Rate Risk

AEP is exposed to interest rate market fluctuations in the normal course of business operations. AEP has outstanding short and long-term debt which is subject to a variable rate. AEP manages interest rate risk by limiting variable-rate exposures to a percentage of total debt, by entering into interest rate derivative instruments and by monitoring the effects of market changes in interest rates. For the three months ended March 31, 2020 and 2019, a 100 basis point change in the benchmark rate on AEP’s variable rate debt would impact pretax interest expense annually by $24 million and $25 million, respectively.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, 2020 and 2019

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

(Unaudited)



	Three Months Ended March 31,
	2020			2019
REVENUES
Vertically Integrated Utilities	$	2,193.0		$	2,372.3
Transmission and Distribution Utilities	1,075.2			1,179.8
Generation & Marketing	408.4			439.7
Other Revenues	70.9			65.0
TOTAL REVENUES	3,747.5			4,056.8

EXPENSES
Fuel and Other Consumables Used for Electric Generation	355.3			550.4
Purchased Electricity for Resale	795.7			861.8
Other Operation	602.1			666.0
Maintenance	249.5			274.5
Depreciation and Amortization	672.2			605.8
Taxes Other Than Income Taxes	321.1			309.9
TOTAL EXPENSES	2,995.9			3,268.4

OPERATING INCOME	751.6			788.4

Other Income (Expense):
Other Income (Expense)	(4.4		)	8.6
Allowance for Equity Funds Used During Construction	31.4			28.9
Non-Service Cost Components of Net Periodic Benefit Cost	29.7			30.0
Interest Expense	(292.1		)	(255.8		)

INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	516.2			600.1

Income Tax Expense	46.5			44.5
Equity Earnings of Unconsolidated Subsidiaries	29.6			18.5

NET INCOME	499.3			574.1

Net Income Attributable to Noncontrolling Interests	4.1			1.3

EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	495.2		$	572.8

WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING	494,596,869			493,309,076

TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	1.00		$	1.16

WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING	496,608,918			494,484,144

TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	1.00		$	1.16



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2020			2019
Net Income	$	499.3		$	574.1

OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $(17.8) and $(7.7) in 2020 and 2019, Respectively	(67.0		)	(28.9		)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.5) and $(0.4) in 2020 and 2019, Respectively	(1.8		)	(1.4		)

TOTAL OTHER COMPREHENSIVE LOSS	(68.8		)	(30.3		)

TOTAL COMPREHENSIVE INCOME	430.5			543.8

Total Other Comprehensive Income Attributable To Noncontrolling Interests	4.1			1.3

TOTAL OTHER COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	426.4		$	542.5



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Three Months Ended March 31, 2020 and 2019

(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, 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								(332.5		)	(b)				(1.1		)	(333.6		)
Other Changes in Equity				(56.6		)	(a)								1.0			(55.6		)
Net Income								572.8							1.3			574.1
Other Comprehensive Loss												(30.3		)				(30.3		)
TOTAL EQUITY – MARCH 31, 2019	513.6	$	3,338.6	$	6,442.8			$	9,565.6			$	(150.7	)	$	32.2		$	19,228.5

TOTAL EQUITY – DECEMBER 31, 2019	514.4	$	3,343.4	$	6,535.6			$	9,900.9			$	(147.7	)	$	281.0		$	19,913.2

Issuance of Common Stock	1.0	6.8		49.3														56.1
Common Stock Dividends								(359.1		)	(b)				(4.6		)	(363.7		)
Other Changes in Equity				(29.0		)									(1.2		)	(30.2		)
ASU 2016-13 Adoption								1.8										1.8
Net Income								495.2							4.1			499.3
Other Comprehensive Loss												(68.8		)				(68.8		)
TOTAL EQUITY – MARCH 31, 2020	515.4	$	3,350.2	$	6,555.9			$	10,038.8			$	(216.5	)	$	279.3		$	20,007.7


(a)	Includes $(62) million related to a forward equity purchase contract associated with the issuance of Equity Units.


(b)	Cash dividends declared per AEP common share were $0.70 and $0.67 for the three months ended March 31, 2020 and 2019, respectively.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, 2020 and December 31, 2019

(in millions)

(Unaudited)



	March 31,			December 31,
	2020			2019
CURRENT ASSETS
Cash and Cash Equivalents	$	1,554.6		$	246.8
Restricted Cash (March 31, 2020 and December 31, 2019 Amounts Include $116.2 and $185.8, Respectively, Related to Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Santa Rita East)	116.2			185.8
Other Temporary Investments (March 31, 2020 and December 31, 2019 Amounts Include $163.6 and $187.8, Respectively, Related to EIS and Transource Energy)	185.2			202.7
Accounts Receivable:
Customers	617.9			625.3
Accrued Unbilled Revenues	242.2			222.4
Pledged Accounts Receivable – AEP Credit	885.2			873.9
Miscellaneous	41.1			27.2
Allowance for Uncollectible Accounts	(44.9		)	(43.7		)
Total Accounts Receivable	1,741.5			1,705.1
Fuel	550.9			528.5
Materials and Supplies	645.0			640.7
Risk Management Assets	130.4			172.8
Regulatory Asset for Under-Recovered Fuel Costs	80.8			92.9
Margin Deposits	68.3			60.4
Prepayments and Other Current Assets	219.1			242.1
TOTAL CURRENT ASSETS	5,292.0			4,077.8

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	22,853.7			22,762.4
Transmission	25,314.2			24,808.6
Distribution	22,824.4			22,443.4
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	4,913.2			4,811.5
Construction Work in Progress	4,511.5			4,319.8
Total Property, Plant and Equipment	80,417.0			79,145.7
Accumulated Depreciation and Amortization	19,368.1			19,007.6
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	61,048.9			60,138.1

OTHER NONCURRENT ASSETS
Regulatory Assets	3,197.4			3,158.8
Securitized Assets	789.1			858.1
Spent Nuclear Fuel and Decommissioning Trusts	2,679.2			2,975.7
Goodwill	52.5			52.5
Long-term Risk Management Assets	323.7			266.6
Operating Lease Assets	926.7			957.4
Deferred Charges and Other Noncurrent Assets	3,414.5			3,407.3
TOTAL OTHER NONCURRENT ASSETS	11,383.1			11,676.4

TOTAL ASSETS	$	77,724.0		$	75,892.3



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

March 31, 2020 and December 31, 2019

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

(Unaudited)



			March 31,			December 31,
			2020			2019
CURRENT LIABILITIES
Accounts Payable			$	1,593.4		$	2,085.8
Short-term Debt:
Securitized Debt for Receivables – AEP Credit			724.0			710.0
Other Short-term Debt			3,740.1			2,128.3
Total Short-term Debt			4,464.1			2,838.3
Long-term Debt Due Within One Year (March 31, 2020 and December 31, 2019 Amounts Include $289.6 and $565.1, Respectively, Related to Transition Funding, DCC Fuel, Appalachian Consumer Rate Relief Funding, Transource Energy, Sabine and Restoration Funding)			2,109.7			1,598.7
Risk Management Liabilities			156.8			114.3
Customer Deposits			361.0			366.1
Accrued Taxes			1,255.4			1,357.8
Accrued Interest			307.9			243.6
Obligations Under Operating Leases			234.3			234.1
Regulatory Liability for Over-Recovered Fuel Costs			137.6			86.6
Other Current Liabilities			1,034.5			1,373.8
TOTAL CURRENT LIABILITIES			11,654.7			10,299.1

NONCURRENT LIABILITIES
Long-term Debt (March 31, 2020 and December 31, 2019 Amounts Include $1,037.6 and $907, Respectively, Related to Transition Funding, DCC Fuel, Appalachian Consumer Rate Relief Funding, Transource Energy, Sabine and Restoration Funding)			25,783.0			25,126.8
Long-term Risk Management Liabilities			291.9			261.8
Deferred Income Taxes			7,668.5			7,588.2
Regulatory Liabilities and Deferred Investment Tax Credits			8,049.2			8,457.6
Asset Retirement Obligations			2,254.2			2,216.6
Employee Benefits and Pension Obligations			451.0			466.0
Obligations Under Operating Leases			736.3			734.6
Deferred Credits and Other Noncurrent Liabilities			709.5			719.8
TOTAL NONCURRENT LIABILITIES			45,943.6			45,571.4

TOTAL LIABILITIES			57,598.3			55,870.5

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

MEZZANINE EQUITY
Redeemable Noncontrolling Interest			64.8			65.7
Contingently Redeemable Performance Share Awards			53.2			42.9
TOTAL MEZZANINE EQUITY			118.0			108.6

EQUITY
Common Stock – Par Value – $6.50 Per Share:
	2020	2019
Shares Authorized	600,000,000	600,000,000
Shares Issued	515,411,847	514,373,631
(20,204,160 Shares were Held in Treasury as of March 31, 2020 and December 31, 2019, Respectively)			3,350.2			3,343.4
Paid-in Capital			6,555.9			6,535.6
Retained Earnings			10,038.8			9,900.9
Accumulated Other Comprehensive Income (Loss)			(216.5		)	(147.7		)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY			19,728.4			19,632.2

Noncontrolling Interests			279.3			281.0

TOTAL EQUITY			20,007.7			19,913.2

TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY			$	77,724.0		$	75,892.3



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2020			2019
OPERATING ACTIVITIES
Net Income	$	499.3		$	574.1
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	672.2			605.8
Deferred Income Taxes	27.9			16.8
Allowance for Equity Funds Used During Construction	(31.4		)	(28.9		)
Mark-to-Market of Risk Management Contracts	57.4			65.5
Amortization of Nuclear Fuel	23.4			25.1
Property Taxes	(59.8		)	(75.6		)
Deferred Fuel Over/Under-Recovery, Net	63.1			32.5
Recovery of Ohio Capacity Costs	—			14.7
Refund of Global Settlement	—			(4.1		)
Change in Other Noncurrent Assets	(50.8		)	(47.9		)
Change in Other Noncurrent Liabilities	(74.8		)	67.3
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(32.6		)	57.5
Fuel, Materials and Supplies	(35.8		)	(26.4		)
Accounts Payable	(111.1		)	(152.6		)
Accrued Taxes, Net	(93.9		)	(77.0		)
Other Current Assets	5.3			(18.8		)
Other Current Liabilities	(242.7		)	(219.7		)
Net Cash Flows from Operating Activities	615.7			808.3

INVESTING ACTIVITIES
Construction Expenditures	(1,792.7		)	(1,565.4		)
Purchases of Investment Securities	(632.7		)	(130.4		)
Sales of Investment Securities	635.6			111.9
Acquisitions of Nuclear Fuel	(1.3		)	(32.4		)
Other Investing Activities	25.1			33.5
Net Cash Flows Used for Investing Activities	(1,766.0		)	(1,582.8		)

FINANCING ACTIVITIES
Issuance of Common Stock	56.1			14.5
Issuance of Long-term Debt	1,418.9			1,285.6
Issuance of Short-term Debt with Original Maturities greater than 90 Days	1,297.5			—
Change in Short-term Debt with Original Maturities less than 90 Days, Net	328.3			(52.0		)
Retirement of Long-term Debt	(300.5		)	(220.6		)
Principal Payments for Finance Lease Obligations	(15.4		)	(14.3		)
Dividends Paid on Common Stock	(363.7		)	(333.6		)
Other Financing Activities	(32.7		)	13.9
Net Cash Flows from Financing Activities	2,388.5			693.5

Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	1,238.2			(81.0		)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	432.6			444.1
Cash, Cash Equivalents and Restricted Cash at End of Period	$	1,670.8		$	363.1

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	212.6		$	168.9
Net Cash Paid (Received) for Income Taxes	(0.6		)	(0.6		)
Noncash Acquisitions Under Finance Leases	19.4			23.1
Construction Expenditures Included in Current Liabilities as of March 31,	874.1			846.3
Construction Expenditures Included in Noncurrent Liabilities as of March 31,	8.3			—
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage	1.3			1.0
Forward Equity Purchase Contract Included in Current and Noncurrent Liabilities as of March 31,	—			62.1



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

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,
	2020	2019
	(in millions of KWhs)
Retail:
Residential	2,466	2,424
Commercial	2,357	2,091
Industrial	2,365	2,148
Miscellaneous	152	145
Total Retail	7,340	6,808

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,
	2020	2019
	(in degree days)
Actual – Heating (a)	91	177
Normal – Heating (b)	185	187

Actual – Cooling (c)	231	122
Normal – Cooling (b)	125	123


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


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


(c)	Cooling degree days are calculated on a 70 degree temperature base.

First Quarter of 2020 Compared to First Quarter of 2019



Reconciliation of First Quarter of 2019 to First Quarter of 2020
Net Income
(in millions)

First Quarter of 2019	$	34.4

Changes in Gross Margin:
Retail Margins	19.5
Margins from Off-system Sales	(0.2		)
Transmission Revenues	11.3
Other Revenues	11.7
Total Change in Gross Margin	42.3

Changes in Expenses and Other:
Other Operation and Maintenance	(3.0		)
Depreciation and Amortization	(23.6		)
Taxes Other Than Income Taxes	2.5
Interest Income	0.2
Allowance for Equity Funds Used During Construction	3.3
Interest Expense	(5.1		)
Total Change in Expenses and Other	(25.7		)

Income Tax Expense	(3.4		)

First Quarter of 2020	$	47.6

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


•	Retail Margins increased $20 million primarily due to the following:


•	A $15 million increase in weather-normalized margins primarily in the commercial and residential classes.


•	A $7 million increase in revenues primarily due to the Transmission Cost Recovery Factor revenue rider.

These increases were partially offset by:


•	A $4 million decrease in weather-related usage primarily due to a 49% decrease in heating degree days, partially offset by an 89% increase in cooling degree days.


•	Transmission Revenues increased $11 million primarily due to the recovery of increased transmission investment in ERCOT.


•	Other Revenues increased $12 million primarily due to securitization revenue. This increase was offset below in Depreciation and Amortization expenses and in Interest Expense.

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


•	Other Operation and Maintenance expenses increased $3 million primarily due to an increase in distribution-related expenses.


•	Depreciation and Amortization expenses increased $24 million primarily due to the following:


•	A $12 million increase in securitization amortizations. This increase was offset in Other Revenues above and in Interest Expense below.


•	An $11 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.


•	Allowance for Equity Funds Used During Construction increased $3 million due to an increase in the Equity component of AFUDC as a result of lower short-term balances and increased transmission projects.


•	Interest Expense increased $5 million primarily due to higher long-term debt balances.


•	Income Tax Expense increased $3 million primarily due to an increase in pretax book income.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2020			2019
REVENUES
Electric Transmission and Distribution	$	391.6		$	349.8
Sales to AEP Affiliates	31.1			40.2
Other Revenues	0.9			0.7
TOTAL REVENUES	423.6			390.7

EXPENSES
Fuel and Other Consumables Used for Electric Generation	—			9.4
Other Operation	117.5			109.8
Maintenance	20.6			25.3
Depreciation and Amortization	162.5			138.9
Taxes Other Than Income Taxes	34.0			36.5
TOTAL EXPENSES	334.6			319.9

OPERATING INCOME	89.0			70.8

Other Income (Expense):
Interest Income	0.6			0.4
Allowance for Equity Funds Used During Construction	5.1			1.8
Non-Service Cost Components of Net Periodic Benefit Cost	2.8			2.8
Interest Expense	(42.5		)	(37.4		)

INCOME BEFORE INCOME TAX EXPENSE	55.0			38.4

Income Tax Expense	7.4			4.0

NET INCOME	$	47.6		$	34.4

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

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2020		2019
Net Income	$	47.6	$	34.4

OTHER COMPREHENSIVE INCOME, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 in 2020 and 2019, Respectively	0.3		0.3
TOTAL OTHER COMPREHENSIVE INCOME	0.3		0.3

TOTAL COMPREHENSIVE INCOME	$	47.9	$	34.7

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018	$	1,257.9	$	1,337.7	$	(15.1	)	$	2,580.5

Capital Contribution from 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

TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019	$	1,457.9	$	1,516.0	$	(12.8	)	$	2,961.1

Net Income			47.6					47.6
Other Comprehensive Income					0.3			0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2020	$	1,457.9	$	1,563.6	$	(12.5	)	$	3,009.0

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, 2020 and December 31, 2019

(in millions)

(Unaudited)



	March 31,			December 31,
	2020			2019
CURRENT ASSETS
Cash and Cash Equivalents	$	0.1		$	3.1
Restricted Cash (March 31, 2020 and December 31, 2019 Amounts Include $100.1 and $154.7, Respectively, Related to Transition Funding and Restoration Funding)	100.1			154.7
Advances to Affiliates	7.1			207.2
Accounts Receivable:
Customers	130.1			116.0
Affiliated Companies	10.4			10.1
Accrued Unbilled Revenues	88.6			68.8
Miscellaneous	0.4			0.3
Allowance for Uncollectible Accounts	(1.8		)	(1.8		)
Total Accounts Receivable	227.7			193.4
Fuel	6.4			5.9
Materials and Supplies	63.8			56.7
Accrued Tax Benefits	51.5			66.1
Prepayments and Other Current Assets	6.6			5.8
TOTAL CURRENT ASSETS	463.3			692.9

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	351.6			351.7
Transmission	4,624.7			4,466.5
Distribution	4,303.1			4,215.2
Other Property, Plant and Equipment	829.1			805.9
Construction Work in Progress	747.0			763.9
Total Property, Plant and Equipment	10,855.5			10,603.2
Accumulated Depreciation and Amortization	1,800.1			1,758.1
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	9,055.4			8,845.1

OTHER NONCURRENT ASSETS
Regulatory Assets	272.2			280.6
Securitized Assets (March 31, 2020 and December 31, 2019 Amounts Include $560.7 and $621.2, Respectively, Related to Transition Funding and Restoration Funding)	560.5			623.4
Deferred Charges and Other Noncurrent Assets	219.1			147.1
TOTAL OTHER NONCURRENT ASSETS	1,051.8			1,051.1

TOTAL ASSETS	$	10,570.5		$	10,589.1

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

March 31, 2020 and December 31, 2019

(in millions)

(Unaudited)



	March 31,			December 31,
	2020			2019
CURRENT LIABILITIES
Advances from Affiliates	$	63.9		$	—
Accounts Payable:
General	233.1			256.8
Affiliated Companies	20.3			35.6
Long-term Debt Due Within One Year – Nonaffiliated (March 31, 2020 and December 31, 2019 Amounts Include $178.3 and $281.4, Respectively, Related to Transition Funding and Restoration Funding)	289.0			392.1
Accrued Taxes	109.2			84.9
Accrued Interest (March 31, 2020 and December 31, 2019 Amounts Include $4.9 and $7.5, Respectively, Related to Transition Funding and Restoration Funding)	54.8			35.7
Oklaunion Purchase Power Agreement	15.1			22.1
Obligations Under Operating Leases	13.0			12.0
Provision for Refund	62.9			64.7
Other Current Liabilities	104.3			123.3
TOTAL CURRENT LIABILITIES	965.6			1,027.2

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated (March 31, 2020 and December 31, 2019 Amounts Include $484.7 and $495.4, Respectively, Related to Transition Funding and Restoration Funding)	4,156.4			4,166.3
Deferred Income Taxes	961.8			965.4
Regulatory Liabilities and Deferred Investment Tax Credits	1,321.8			1,316.9
Obligations Under Operating Leases	70.7			71.1
Deferred Credits and Other Noncurrent Liabilities	85.2			81.1
TOTAL NONCURRENT LIABILITIES	6,595.9			6,600.8

TOTAL LIABILITIES	7,561.5			7,628.0

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

COMMON SHAREHOLDER’S EQUITY
Paid-in Capital	1,457.9			1,457.9
Retained Earnings	1,563.6			1,516.0
Accumulated Other Comprehensive Income (Loss)	(12.5		)	(12.8		)
TOTAL COMMON SHAREHOLDER’S EQUITY	3,009.0			2,961.1

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	10,570.5		$	10,589.1

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2020			2019
OPERATING ACTIVITIES
Net Income	$	47.6		$	34.4
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	162.5			138.9
Deferred Income Taxes	(7.6		)	(11.0		)
Allowance for Equity Funds Used During Construction	(5.1		)	(1.8		)
Property Taxes	(69.3		)	(73.8		)
Change in Other Noncurrent Assets	(10.8		)	(3.2		)
Change in Other Noncurrent Liabilities	3.2			(5.7		)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(34.3		)	(7.8		)
Fuel, Materials and Supplies	(7.6		)	(1.0		)
Accounts Payable	2.4			4.2
Accrued Taxes, Net	38.9			57.5
Other Current Assets	(1.4		)	0.5
Other Current Liabilities	(4.6		)	(4.4		)
Net Cash Flows from Operating Activities	113.9			126.8

INVESTING ACTIVITIES
Construction Expenditures	(327.5		)	(343.1		)
Change in Advances to Affiliates, Net	200.1			0.3
Other Investing Activities	7.4			6.2
Net Cash Flows Used for Investing Activities	(120.0		)	(336.6		)

FINANCING ACTIVITIES
Capital Contribution from Parent	—			200.0
Change in Advances from Affiliates, Net	63.9			55.2
Retirement of Long-term Debt – Nonaffiliated	(114.3		)	(103.5		)
Principal Payments for Finance Lease Obligations	(1.5		)	(1.2		)
Other Financing Activities	0.4			0.2
Net Cash Flows from (Used for) Financing Activities	(51.5		)	150.7

Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding	(57.6		)	(59.1		)
Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding at Beginning of Period	157.8			159.8
Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding at End of Period	$	100.2		$	100.7

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	21.1		$	22.4
Net Cash Paid (Received) for Income Taxes	—			(5.6		)
Noncash Acquisitions Under Finance Leases	3.7			2.4
Construction Expenditures Included in Current Liabilities as of March 31,	175.1			195.7

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

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,
	2020		2019
	(in millions)
Plant In Service	$	8,684.9	$	6,755.0
Construction Work in Progress	1,536.3		1,812.2
Accumulated Depreciation and Amortization	445.8		306.7
Total Transmission Property, Net	$	9,775.4	$	8,260.5

First Quarter of 2020 Compared to First Quarter of 2019



Reconciliation of First Quarter of 2019 to First Quarter of 2020
Net Income
(in millions)

First Quarter of 2019	$	104.3

Changes in Transmission Revenues:
Transmission Revenues	52.1
Total Change in Transmission Revenues	52.1

Changes in Expenses and Other:
Other Operation and Maintenance	(6.8		)
Depreciation and Amortization	(15.7		)
Taxes Other Than Income Taxes	(9.0		)
Interest Income	0.1
Allowance for Equity Funds Used During Construction	4.9
Interest Expense	(7.9		)
Total Change in Expenses and Other	(34.4		)

Income Tax Expense	(4.2		)

First Quarter of 2020	$	117.8

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


•	Transmission Revenues increased $52 million primarily due to continued investment in transmission assets.

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


•	Other Operation and Maintenance expenses increased $7 million primarily due to the following:


•	A $3 million increase due to employee-related expenses.


•	A $2 million increase due to higher rent expense.


•	A $1 million increase due to continued investment in transmission assets.


•	Depreciation and Amortization expenses increased $16 million primarily due to a higher depreciable base.


•	Taxes Other Than Income Taxes increased $9 million primarily due to higher property taxes as a result of increased transmission investment.


•	Allowance for Equity Funds Used During Construction increased $5 million primarily due to the following:


•	A $9 million increase due to prior year FERC audit findings.

This increase was partially offset by:


•	A $5 million decrease due to a decrease in CWIP.


•	Interest Expense increased $8 million primarily due to higher long-term debt balances.


•	Income Tax Expense increased $4 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, 2020 and 2019

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2020			2019
REVENUES
Transmission Revenues	$	61.3		$	50.3
Sales to AEP Affiliates	233.7			193.2
Other Revenues	0.6			—
TOTAL REVENUES	295.6			243.5

EXPENSES
Other Operation	23.8			17.0
Maintenance	3.2			3.2
Depreciation and Amortization	56.0			40.3
Taxes Other Than Income Taxes	50.4			41.4
TOTAL EXPENSES	133.4			101.9

OPERATING INCOME	162.2			141.6

Other Income (Expense):
Interest Income - Affiliated	0.8			0.7
Allowance for Equity Funds Used During Construction	16.2			11.3
Interest Expense	(29.6		)	(21.7		)

INCOME BEFORE INCOME TAX EXPENSE	149.6			131.9

Income Tax Expense	31.8			27.6

NET INCOME	$	117.8		$	104.3

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Paid-in Capital		Retained Earnings		Total
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2018	$	2,480.6	$	1,089.2	$	3,569.8

Net Income			104.3		104.3
TOTAL MEMBER'S EQUITY – MARCH 31, 2019	$	2,480.6	$	1,193.5	$	3,674.1

TOTAL MEMBER'S EQUITY – DECEMBER 31, 2019	$	2,480.6	$	1,528.9	$	4,009.5

Capital Contribution from Member	185.0				185.0
Net Income			117.8		117.8
TOTAL MEMBER'S EQUITY – MARCH 31, 2020	$	2,665.6	$	1,646.7	$	4,312.3

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, 2020 and December 31, 2019

(in millions)

(Unaudited)



	March 31,		December 31,
	2020		2019
CURRENT ASSETS
Advances to Affiliates	$	128.4	$	85.4
Accounts Receivable:
Customers	19.3		19.0
Affiliated Companies	87.8		66.1
Total Accounts Receivable	107.1		85.1
Materials and Supplies	13.4		13.8
Accrued Tax Benefits	0.1		9.3
Prepayments and Other Current Assets	3.4		3.8
TOTAL CURRENT ASSETS	252.4		197.4

TRANSMISSION PROPERTY
Transmission Property	8,406.4		8,137.9
Other Property, Plant and Equipment	278.5		269.6
Construction Work in Progress	1,536.3		1,485.7
Total Transmission Property	10,221.2		9,893.2
Accumulated Depreciation and Amortization	445.8		402.3
TOTAL TRANSMISSION PROPERTY – NET	9,775.4		9,490.9

OTHER NONCURRENT ASSETS
Regulatory Assets	2.5		4.2
Deferred Property Taxes	165.1		193.5
Deferred Charges and Other Noncurrent Assets	4.5		4.8
TOTAL OTHER NONCURRENT ASSETS	172.1		202.5

TOTAL ASSETS	$	10,199.9	$	9,890.8

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND MEMBER’S EQUITY

March 31, 2020 and December 31, 2019

(in millions)

(Unaudited)



	March 31,		December 31,
	2020		2019
CURRENT LIABILITIES
Advances from Affiliates	$	297.4	$	137.0
Accounts Payable:
General	334.2		493.4
Affiliated Companies	73.7		71.2
Accrued Taxes	308.6		355.6
Accrued Interest	38.6		19.2
Obligations Under Operating Leases	2.1		2.1
Other Current Liabilities	17.0		14.6
TOTAL CURRENT LIABILITIES	1,071.6		1,093.1

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	3,427.8		3,427.3
Deferred Income Taxes	834.7		817.8
Regulatory Liabilities	551.6		540.9
Obligations Under Operating Leases	1.6		1.9
Deferred Credits and Other Noncurrent Liabilities	0.3		0.3
TOTAL NONCURRENT LIABILITIES	4,816.0		4,788.2

TOTAL LIABILITIES	5,887.6		5,881.3

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

MEMBER’S EQUITY
Paid-in Capital	2,665.6		2,480.6
Retained Earnings	1,646.7		1,528.9
TOTAL MEMBER’S EQUITY	4,312.3		4,009.5

TOTAL LIABILITIES AND MEMBER’S EQUITY	$	10,199.9	$	9,890.8

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2020			2019
OPERATING ACTIVITIES
Net Income	$	117.8		$	104.3
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	56.0			40.3
Deferred Income Taxes	13.7			14.5
Allowance for Equity Funds Used During Construction	(16.2		)	(11.3		)
Property Taxes	28.4			23.2
Change in Other Noncurrent Assets	2.4			2.7
Change in Other Noncurrent Liabilities	0.6			2.2
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(22.0		)	(8.2		)
Materials and Supplies	0.4			(0.6		)
Accounts Payable	22.7			11.4
Accrued Taxes, Net	(37.8		)	(32.1		)
Accrued Interest	19.4			19.2
Other Current Assets	0.4			0.4
Other Current Liabilities	1.2			0.2
Net Cash Flows from Operating Activities	187.0			166.2

INVESTING ACTIVITIES
Construction Expenditures	(491.5		)	(365.0		)
Change in Advances to Affiliates, Net	(43.0		)	23.4
Acquisitions of Assets	(1.7		)	(2.5		)
Other Investing Activities	3.8			0.3
Net Cash Flows Used for Investing Activities	(532.4		)	(343.8		)

FINANCING ACTIVITIES
Capital Contributions from Member	185.0			—
Change in Advances from Affiliates, Net	160.4			177.7
Other Financing Activities	—			(0.1		)
Net Cash Flows from Financing Activities	345.4			177.6

Net Change in Cash and Cash Equivalents	—			—
Cash and Cash Equivalents at Beginning of Period	—			—
Cash and Cash Equivalents at End of Period	$	—		$	—

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	9.3		$	1.6
Net Cash Paid (Received) for Income Taxes	0.1			(1.2		)
Construction Expenditures Included in Current Liabilities as of March 31,	290.6			261.1

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

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,
	2020	2019
	(in millions of KWhs)
Retail:
Residential	3,169	3,587
Commercial	1,477	1,596
Industrial	2,237	2,336
Miscellaneous	207	219
Total Retail	7,090	7,738

Wholesale	472	816

Total KWhs	7,562	8,554

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,
	2020	2019
	(in degree days)
Actual – Heating (a)	953	1,252
Normal – Heating (b)	1,324	1,312

Actual – Cooling (c)	20	—
Normal – Cooling (b)	6	7


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


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


(c)	Cooling degree days are calculated on a 65 degree temperature base.

First Quarter of 2020 Compared to First Quarter of 2019



Reconciliation of First Quarter of 2019 to First Quarter of 2020
Net Income
(in millions)

First Quarter of 2019	$	133.7

Changes in Gross Margin:
Retail Margins	14.3
Margins from Off-system Sales	(0.6		)
Transmission Revenues	1.4
Other Revenues	1.8
Total Change in Gross Margin	16.9

Changes in Expenses and Other:
Other Operation and Maintenance	14.1
Depreciation and Amortization	(9.7		)
Taxes Other Than Income Taxes	(2.0		)
Interest Income	(0.5		)
Allowance for Equity Funds Used During Construction	0.7
Non-Service Cost Components of Net Periodic Benefit Cost	0.4
Interest Expense	(3.8		)
Total Change in Expenses and Other	(0.8		)

Income Tax Expense	(34.5		)

First Quarter of 2020	$	115.3


•	Retail Margins increased $14 million primarily due to the following:


•	A $17 million increase due to customer refunds related to the 2018 Tax Reform. This increase was partially offset in Income Tax Expense (Benefit) below.


•	A $14 million increase in deferred fuel primarily due to the timing of recoverable PJM expenses. This increase was offset in other expense items below.


•	A $12 million increase due to the impact of the 2019 WVPSC order which required the Company to offset Excess ADIT not subject to normalization requirements against the deferred fuel under-recovery balance in 2019.


•	A $10 million increase due to a base rate increase in West Virginia that was partially offset in Depreciation and Amortization expenses below.


•	A $4 million increase due to revenue primarily from rate riders in West Virginia.

These increases were partially offset by:


•	A $33 million decrease in weather-related usage primarily driven by a 24% decrease in heating degree days.


•	A $9 million decrease in weather-normalized margins occurring across all retail classes.

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


•	Other Operation and Maintenance expenses decreased $14 million primarily due to the following:


•	A $5 million decrease in maintenance expense at various generation plants.


•	A $5 million decrease in employee-related expenses.


•	A $4 million decrease in PJM expenses primarily related to the annual formula rate true-up.


•	A $4 million decrease in storm and vegetation management services.

These decreases were partially offset by:


•	A $5 million increase in recoverable PJM transmission expenses which were partially offset within Retail Margins above.


•	Depreciation and Amortization expenses increased $10 million primarily due to a higher depreciable base and an increase in West Virginia depreciation rates beginning in March 2019. This increase was partially offset within Retail Margins above.


•	Interest Expense increased $4 million primarily due to higher long-term debt balances.


•	Income Tax Expense increased $35 million primarily due to a decrease in amortization of excess ADIT and an increase in pretax book income. The decrease in amortization of excess ADIT is partially offset above in Gross Margin and Other Operation and Maintenance expenses.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2020			2019
REVENUES
Electric Generation, Transmission and Distribution	$	697.0		$	738.7
Sales to AEP Affiliates	49.7			51.7
Other Revenues	2.7			2.4
TOTAL REVENUES	749.4			792.8

EXPENSES
Fuel and Other Consumables Used for Electric Generation	111.0			183.3
Purchased Electricity for Resale	122.6			110.6
Other Operation	134.0			136.9
Maintenance	50.3			61.5
Depreciation and Amortization	122.2			112.5
Taxes Other Than Income Taxes	37.9			35.9
TOTAL EXPENSES	578.0			640.7

OPERATING INCOME	171.4			152.1

Other Income (Expense):
Interest Income	0.3			0.8
Allowance for Equity Funds Used During Construction	2.4			1.7
Non-Service Cost Components of Net Periodic Benefit Cost	4.7			4.3
Interest Expense	(53.1		)	(49.3		)

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	125.7			109.6

Income Tax Expense (Benefit)	10.4			(24.1		)

NET INCOME	$	115.3		$	133.7



The common stock of APCo is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2020			2019
Net Income	$	115.3		$	133.7

OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $(1.1) and $(0.1) in 2020 and 2019, Respectively	(4.2		)	(0.2		)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.3) and $(0.2) in 2020 and 2019, Respectively	(0.9		)	(0.6		)

TOTAL OTHER COMPREHENSIVE LOSS	(5.1		)	(0.8		)

TOTAL COMPREHENSIVE INCOME	$	110.2		$	132.9



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018	$	260.4	$	1,828.7	$	1,922.0		$	(5.0	)	$	4,006.1

Common Stock Dividends					(50.0		)				(50.0		)
Net 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

TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019	$	260.4	$	1,828.7	$	2,078.3		$	5.0		$	4,172.4

Common Stock Dividends					(50.0		)				(50.0		)
Net Income					115.3						115.3
Other Comprehensive Loss								(5.1		)	(5.1		)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2020	$	260.4	$	1,828.7	$	2,143.6		$	(0.1	)	$	4,232.6



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, 2020 and December 31, 2019

(in millions)

(Unaudited)



	March 31,			December 31,
	2020			2019
CURRENT ASSETS
Cash and Cash Equivalents	$	2.8		$	3.3
Restricted Cash for Securitized Funding	15.7			23.5
Advances to Affiliates	21.8			22.1
Accounts Receivable:
Customers	132.6			129.0
Affiliated Companies	78.0			64.3
Accrued Unbilled Revenues	46.1			59.7
Miscellaneous	0.6			0.5
Allowance for Uncollectible Accounts	(2.9		)	(2.6		)
Total Accounts Receivable	254.4			250.9
Fuel	160.0			149.7
Materials and Supplies	100.4			105.2
Risk Management Assets	18.1			39.4
Regulatory Asset for Under-Recovered Fuel Costs	34.9			42.5
Prepayments and Other Current Assets	33.1			64.0
TOTAL CURRENT ASSETS	641.2			700.6

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	6,602.1			6,563.7
Transmission	3,613.2			3,584.1
Distribution	4,279.1			4,201.7
Other Property, Plant and Equipment	585.5			571.3
Construction Work in Progress	574.0			593.4
Total Property, Plant and Equipment	15,653.9			15,514.2
Accumulated Depreciation and Amortization	4,497.0			4,432.3
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	11,156.9			11,081.9

OTHER NONCURRENT ASSETS
Regulatory Assets	464.0			457.2
Securitized Assets	228.5			234.7
Long-term Risk Management Assets	0.1			0.1
Operating Lease Assets	77.5			78.5
Deferred Charges and Other Noncurrent Assets	225.4			215.3
TOTAL OTHER NONCURRENT ASSETS	995.5			985.8

TOTAL ASSETS	$	12,793.6		$	12,768.3



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

March 31, 2020 and December 31, 2019

(Unaudited)



	March 31,			December 31,
	2020			2019
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	355.3		$	236.7
Accounts Payable:
General	198.7			307.8
Affiliated Companies	75.2			92.5
Long-term Debt Due Within One Year – Nonaffiliated	583.3			215.6
Risk Management Liabilities	15.0			1.9
Customer Deposits	84.5			85.8
Accrued Taxes	102.7			99.6
Accrued Interest	67.0			47.9
Obligations Under Operating Leases	15.4			15.2
Other Current Liabilities	90.1			123.0
TOTAL CURRENT LIABILITIES	1,587.2			1,226.0

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	3,769.1			4,148.2
Long-term Risk Management Liabilities	0.1			—
Deferred Income Taxes	1,680.9			1,680.8
Regulatory Liabilities and Deferred Investment Tax Credits	1,254.5			1,268.7
Asset Retirement Obligations	103.6			102.1
Employee Benefits and Pension Obligations	47.3			50.9
Obligations Under Operating Leases	63.1			64.0
Deferred Credits and Other Noncurrent Liabilities	55.2			55.2
TOTAL NONCURRENT LIABILITIES	6,973.8			7,369.9

TOTAL LIABILITIES	8,561.0			8,595.9

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	2,143.6			2,078.3
Accumulated Other Comprehensive Income (Loss)	(0.1		)	5.0
TOTAL COMMON SHAREHOLDER’S EQUITY	4,232.6			4,172.4

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	12,793.6		$	12,768.3



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2020			2019
OPERATING ACTIVITIES
Net Income	$	115.3		$	133.7
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	122.2			112.5
Deferred Income Taxes	(5.1		)	(45.0		)
Allowance for Equity Funds Used During Construction	(2.4		)	(1.7		)
Mark-to-Market of Risk Management Contracts	29.6			50.6
Deferred Fuel Over/Under-Recovery, Net	7.6			20.8
Change in Other Noncurrent Assets	(24.4		)	(12.1		)
Change in Other Noncurrent Liabilities	(16.1		)	(20.5		)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(2.6		)	19.5
Fuel, Materials and Supplies	(5.5		)	(9.6		)
Accounts Payable	(86.6		)	(8.3		)
Accrued Taxes, Net	14.5			13.7
Other Current Assets	19.2			(0.8		)
Other Current Liabilities	(11.1		)	(2.3		)
Net Cash Flows from Operating Activities	154.6			250.5

INVESTING ACTIVITIES
Construction Expenditures	(219.1		)	(205.1		)
Change in Advances to Affiliates, Net	0.3			(193.6		)
Other Investing Activities	1.1			15.2
Net Cash Flows Used for Investing Activities	(217.7		)	(383.5		)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated	—			393.3
Change in Advances from Affiliates, Net	118.6			(205.6		)
Retirement of Long-term Debt – Nonaffiliated	(12.2		)	(12.0		)
Principal Payments for Finance Lease Obligations	(1.8		)	(1.6		)
Dividends Paid on Common Stock	(50.0		)	(50.0		)
Other Financing Activities	0.2			0.3
Net Cash Flows from Financing Activities	54.8			124.4

Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding	(8.3		)	(8.6		)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period	26.8			29.8
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period	$	18.5		$	21.2

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	31.9		$	14.5
Net Cash Paid for Income Taxes	—			8.0
Noncash Acquisitions Under Finance Leases	1.9			2.1
Construction Expenditures Included in Current Liabilities as of March 31,	103.7			87.8



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

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,
	2020	2019
	(in millions of KWhs)
Retail:
Residential	1,455	1,615
Commercial	1,122	1,156
Industrial	1,845	1,888
Miscellaneous	18	19
Total Retail	4,440	4,678

Wholesale	1,693	2,423

Total KWhs	6,133	7,101

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,
	2020	2019
	(in degree days)
Actual – Heating (a)	1,836	2,239
Normal – Heating (b)	2,182	2,160

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.


(c)	Cooling degree days are calculated on a 65 degree temperature base.

First Quarter of 2020 Compared to First Quarter of 2019



Reconciliation of First Quarter of 2019 to First Quarter of 2020
Net Income
(in millions)

First Quarter of 2019	$	98.9

Changes in Gross Margin:
Retail Margins	2.7
Margins from Off-system Sales	0.1
Transmission Revenues	1.4
Other Revenues	(0.7		)
Total Change in Gross Margin	3.5

Changes in Expenses and Other:
Other Operation and Maintenance	5.0
Depreciation and Amortization	(7.7		)
Taxes Other Than Income Taxes	0.9
Other Income	(3.2		)
Non-Service Cost Components of Net Periodic Benefit Cost	(0.2		)
Interest Expense	(1.8		)
Total Change in Expenses and Other	(7.0		)

Income Tax Expense	(3.1		)

First Quarter of 2020	$	92.3


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


•	A $14 million increase from rate proceedings. This increase was partially offset in other expense items below.


•	An $11 million increase related to fuel, primarily due to the timing of recoverable PJM expenses. This increase was partially offset in other expense items below.


•	A $4 million increase due to decreased costs for power acquired under the UPA between AEGCo and I&M.


•	A $3 million decrease in fuel-related expenses due to timing of recovery for fuel and other variable production costs related to wholesale contracts.

These increases were partially offset by:


•	A $16 million decrease in weather-normalized margins.


•	A $14 million decrease in weather-related usage primarily due to an 18% decrease in heating degree days.

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


•	Other Operation and Maintenance expenses decreased $5 million primarily due to the following:


•	A $7 million decrease due to an increased Nuclear Electric Insurance Limited distribution in 2020.


•	A $5 million decrease in employee-related expenses.


•	A $2 million decrease in vegetation management expenses.


•	A $2 million decrease in Cook Plant refueling outage amortization expense, primarily due to decreased costs of outages.

These decreases were partially offset by:


•	An $11 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses. This increase was partially offset in Retail Margins above.


•	Depreciation and Amortization expenses increased $8 million primarily due to a higher depreciable base and an increase in depreciation rates. This increase was partially offset in Retail Margins above.


•	Other Income decreased $3 million primarily due to AFUDC adjustments that resulted from 2019 FERC audit findings.


•	Income Tax Expense increased $3 million primarily due to the recognition of a discrete tax adjustment and a decrease in favorable flow through tax benefits.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2020			2019
REVENUES
Electric Generation, Transmission and Distribution	$	553.4		$	596.7
Sales to AEP Affiliates	2.9			2.3
Other Revenues – Affiliated	12.5			13.3
Other Revenues – Nonaffiliated	1.5			2.0
TOTAL REVENUES	570.3			614.3

EXPENSES
Fuel and Other Consumables Used for Electric Generation	53.2			57.6
Purchased Electricity for Resale	50.1			69.6
Purchased Electricity from AEP Affiliates	36.2			59.8
Other Operation	144.7			140.5
Maintenance	49.1			58.3
Depreciation and Amortization	93.9			86.2
Taxes Other Than Income Taxes	26.4			27.3
TOTAL EXPENSES	453.6			499.3

OPERATING INCOME	116.7			115.0

Other Income (Expense):
Other Income	2.5			5.7
Non-Service Cost Components of Net Periodic Benefit Cost	4.2			4.4
Interest Expense	(30.7		)	(28.9		)

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	92.7			96.2

Income Tax Expense (Benefit)	0.4			(2.7		)

NET INCOME	$	92.3		$	98.9

The common stock of I&M is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2020		2019
Net Income	$	92.3	$	98.9

OTHER COMPREHENSIVE INCOME, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 in 2020 and 2019, Respectively	0.4		0.4

TOTAL COMPREHENSIVE INCOME	$	92.7	$	99.3

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018	$	56.6	$	980.9	$	1,329.1		$	(13.8	)	$	2,352.8

Common Stock Dividends					(20.0		)				(20.0		)
Net Income					98.9						98.9
Other Comprehensive Income								0.4			0.4
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2019	$	56.6	$	980.9	$	1,408.0		$	(13.4	)	$	2,432.1

TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019	$	56.6	$	980.9	$	1,518.5		$	(11.6	)	$	2,544.4

Common Stock Dividends					(21.3		)				(21.3		)
ASU 2016-13 Adoption					0.4						0.4
Net Income					92.3						92.3
Other Comprehensive Income								0.4			0.4
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2020	$	56.6	$	980.9	$	1,589.9		$	(11.2	)	$	2,616.2

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, 2020 and December 31, 2019

(in millions)

(Unaudited)



	March 31,			December 31,
	2020			2019
CURRENT ASSETS
Cash and Cash Equivalents	$	1.8		$	2.0
Advances to Affiliates	13.3			13.2
Accounts Receivable:
Customers	47.5			53.6
Affiliated Companies	51.1			53.7
Accrued Unbilled Revenues	1.8			2.5
Miscellaneous	1.3			0.3
Allowance for Uncollectible Accounts	(0.3		)	(0.6		)
Total Accounts Receivable	101.4			109.5
Fuel	71.7			56.2
Materials and Supplies	171.1			171.3
Risk Management Assets	6.7			9.8
Regulatory Asset for Under-Recovered Fuel Costs	1.2			3.0
Accrued Reimbursement of Spent Nuclear Fuel Costs	8.4			24.0
Prepayments and Other Current Assets	16.4			14.0
TOTAL CURRENT ASSETS	392.0			403.0

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	5,114.0			5,099.7
Transmission	1,647.5			1,641.8
Distribution	2,474.8			2,437.6
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	617.4			632.6
Construction Work in Progress	420.1			382.3
Total Property, Plant and Equipment	10,273.8			10,194.0
Accumulated Depreciation, Depletion and Amortization	3,356.3			3,294.3
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	6,917.5			6,899.7

OTHER NONCURRENT ASSETS
Regulatory Assets	459.0			482.1
Spent Nuclear Fuel and Decommissioning Trusts	2,679.2			2,975.7
Long-term Risk Management Assets	0.1			0.1
Operating Lease Assets	273.6			294.9
Deferred Charges and Other Noncurrent Assets	184.0			181.9
TOTAL OTHER NONCURRENT ASSETS	3,595.9			3,934.7

TOTAL ASSETS	$	10,905.4		$	11,237.4

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

March 31, 2020 and December 31, 2019

(dollars in millions)

(Unaudited)



	March 31,			December 31,
	2020			2019
CURRENT LIABILITIES
Advances from Affiliates	$	103.7		$	114.4
Accounts Payable:
General	131.5			169.4
Affiliated Companies	71.0			68.4
Long-term Debt Due Within One Year – Nonaffiliated (March 31, 2020 and December 31, 2019 Amounts Include $80.0 and $86.1, Respectively, Related to DCC Fuel)	133.6			139.7
Risk Management Liabilities	1.7			0.5
Customer Deposits	38.8			39.4
Accrued Taxes	137.4			112.4
Accrued Interest	20.3			36.2
Obligations Under Operating Leases	85.3			87.3
Regulatory Liability for Over-Recovered Fuel Costs	26.7			6.1
Other Current Liabilities	70.8			109.6
TOTAL CURRENT LIABILITIES	820.8			883.4

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	2,894.4			2,910.5
Long-term Risk Management Liabilities	0.1			—
Deferred Income Taxes	984.3			979.7
Regulatory Liabilities and Deferred Investment Tax Credits	1,550.4			1,891.4
Asset Retirement Obligations	1,766.0			1,748.6
Obligations Under Operating Leases	209.0			211.6
Deferred Credits and Other Noncurrent Liabilities	64.2			67.8
TOTAL NONCURRENT LIABILITIES	7,468.4			7,809.6

TOTAL LIABILITIES	8,289.2			8,693.0

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	1,589.9			1,518.5
Accumulated Other Comprehensive Income (Loss)	(11.2		)	(11.6		)
TOTAL COMMON SHAREHOLDER’S EQUITY	2,616.2			2,544.4

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	10,905.4		$	11,237.4

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2020			2019
OPERATING ACTIVITIES
Net Income	$	92.3		$	98.9
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	93.9			86.2
Deferred Income Taxes	(16.3		)	(13.9		)
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net	15.2			(14.8		)
Allowance for Equity Funds Used During Construction	(2.0		)	(6.2		)
Mark-to-Market of Risk Management Contracts	4.4			4.7
Amortization of Nuclear Fuel	23.4			25.1
Deferred Fuel Over/Under-Recovery, Net	22.5			(5.2		)
Change in Other Noncurrent Assets	14.4			13.5
Change in Other Noncurrent Liabilities	10.0			5.2
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	8.6			16.0
Fuel, Materials and Supplies	(16.2		)	6.6
Accounts Payable	(21.6		)	(3.1		)
Accrued Taxes, Net	25.0			25.6
Other Current Assets	18.2			1.4
Other Current Liabilities	(62.7		)	(35.2		)
Net Cash Flows from Operating Activities	209.1			204.8

INVESTING ACTIVITIES
Construction Expenditures	(141.4		)	(149.3		)
Change in Advances to Affiliates, Net	(0.1		)	(0.1		)
Purchases of Investment Securities	(626.0		)	(130.3		)
Sales of Investment Securities	612.4			111.9
Acquisitions of Nuclear Fuel	(1.3		)	(32.4		)
Other Investing Activities	4.2			8.6
Net Cash Flows Used for Investing Activities	(152.2		)	(191.6		)

FINANCING ACTIVITIES
Change in Advances from Affiliates, Net	(10.7		)	33.6
Retirement of Long-term Debt – Nonaffiliated	(23.7		)	(26.5		)
Principal Payments for Finance Lease Obligations	(1.5		)	(1.2		)
Dividends Paid on Common Stock	(21.3		)	(20.0		)
Other Financing Activities	0.1			0.2
Net Cash Flows Used for Financing Activities	(57.1		)	(13.9		)

Net Decrease in Cash and Cash Equivalents	(0.2		)	(0.7		)
Cash and Cash Equivalents at Beginning of Period	2.0			2.4
Cash and Cash Equivalents at End of Period	$	1.8		$	1.7

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	44.3		$	43.3
Net Cash Paid (Received) for Income Taxes	—			(3.3		)
Noncash Acquisitions Under Finance Leases	1.4			1.7
Construction Expenditures Included in Current Liabilities as of March 31,	67.8			80.0
Acquisition of Nuclear Fuel Included in Current Liabilities as of March 31,	—			1.0
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage	1.3			7.9

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

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,
	2020	2019
	(in millions of KWhs)
Retail:
Residential	3,834	4,123
Commercial	3,516	3,527
Industrial	3,543	3,623
Miscellaneous	30	31
Total Retail (a)	10,923	11,304

Wholesale (b)	390	638

Total KWhs	11,313	11,942


(a)	Represents energy delivered to distribution customers.


(b)	Primarily Ohio’s contractually obligated purchases of OVEC power sold to PJM.

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

Summary of Heating and Cooling Degree Days



	Three Months Ended March 31,
	2020	2019
	(in degree days)
Actual – Heating (a)	1,473	1,892
Normal – Heating (b)	1,898	1,877

Actual – Cooling (c)	3	1
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.


(c)	Cooling degree days are calculated on a 65 degree temperature base.

First Quarter of 2020 Compared to First Quarter of 2019



Reconciliation of First Quarter of 2019 to First Quarter of 2020
Net Income
(in millions)

First Quarter of 2019	$	128.0

Changes in Gross Margin:
Retail Margins	(93.7		)
Margins from Off-system Sales	2.3
Transmission Revenues	0.6
Other Revenues	5.5
Total Change in Gross Margin	(85.3		)

Changes in Expenses and Other:
Other Operation and Maintenance	40.5
Depreciation and Amortization	(7.2		)
Taxes Other Than Income Taxes	(3.1		)
Interest Income	(0.6		)
Carrying Costs Income	0.2
Allowance for Equity Funds Used During Construction	(3.3		)
Non-Service Cost Components of Net Periodic Benefit Cost	0.1
Interest Expense	(4.3		)
Total Change in Expenses and Other	22.3

Income Tax Expense	10.1

First Quarter of 2020	$	75.1

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


•	Retail Margins decreased $94 million primarily due to the following:


•	A $58 million decrease due to a reversal of a regulatory provision in the first quarter of 2019.


•	A $39 million net decrease in Basic Transmission Cost Rider revenues and recoverable PJM expenses. This decrease was partially offset in Other Operation and Maintenance expenses below.


•	A $13 million decrease in Deferred Asset Phase-In-Recovery Rider revenues which ended in the second quarter of 2019. This decrease was offset in Depreciation and Amortization expenses below.


•	A $7 million net decrease in margin for the Rate Stability Rider including associated amortizations which ended in the third quarter of 2019.


•	A $5 million decrease due to the OVEC PPA rider which was replaced by the Legacy Generation Resource Rider (LGRR). This decrease was offset in Margins from Off-system Sales and Other Revenues below.


•	A $3 million decrease in revenues associated with a vegetation management rider. This decrease was offset in Other Operation and Maintenance expenses below.

These decreases were partially offset by:


•	A $17 million increase in rider revenues associated with the DIR. This increase was partially offset in other expense items below.


•	A $7 million increase in revenues associated with smart grid riders. This increase was partially offset in other expense items below.


•	A $7 million increase in revenues associated with the Universal Service Fund (USF). This increase was offset in Other Operation and Maintenance expenses below.


•	A $3 million increase in Energy Efficiency/Peak Demand Reduction rider revenues. This increase was offset in Other Operation and Maintenance expenses below.


•	Other Revenues increased $6 million primarily due to third-party LGRR revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins above.

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


•	Other Operation and Maintenance expenses decreased $41 million primarily due to the following:


•	A $40 million decrease in recoverable PJM expenses. This decrease was offset in Gross Margin above.


•	A $6 million decrease in PJM expenses primarily related to the annual formula rate true-up.


•	A $4 million decrease in recoverable distribution expenses related to vegetation management. This decrease was partially offset in Retail Margins above.

These decreases were partially offset by:


•	A $7 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset in Retail Margins above.


•	Depreciation and Amortization expenses increased $7 million primarily due to the following:


•	A $5 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.


•	A $5 million increase due to lower deferred equity amortizations associated with the Deferred Asset Phase-In-Recovery Rider which ended in the second quarter of 2019.


•	A $5 million increase in recoverable DIR depreciation expense. This increase was partially offset in Retail Margins above.

These increases were partially offset by:


•	A $10 million decrease in amortizations associated with the Deferred Asset Phase-In-Recovery Rider which ended in the second quarter of 2019. This decrease was offset in Retail Margins above.


•	Taxes Other Than Income Taxes increased $3 million primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.


•	Allowance for Equity Funds Used During Construction decreased $3 million primarily due to adjustments that resulted from 2019 FERC audit findings and decreased projects.


•	Interest Expense increased $4 million primarily due to higher long-term debt balances.


•	Income Tax Expense decreased $10 million due to a decrease in pretax book income partially offset by a decrease in amortization of Excess ADIT. The decrease in amortization of Excess ADIT is partially offset in Retail Margins above.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2020			2019
REVENUES
Electricity, Transmission and Distribution	$	679.2		$	826.5
Sales to AEP Affiliates	8.4			7.5
Other Revenues	2.7			2.8
TOTAL REVENUES	690.3			836.8

EXPENSES
Purchased Electricity for Resale	149.1			174.2
Purchased Electricity from AEP Affiliates	42.4			46.1
Amortization of Generation Deferrals	—			32.4
Other Operation	177.3			216.9
Maintenance	31.6			32.5
Depreciation and Amortization	70.5			63.3
Taxes Other Than Income Taxes	112.0			108.9
TOTAL EXPENSES	582.9			674.3

OPERATING INCOME	107.4			162.5

Other Income (Expense):
Interest Income	0.2			0.8
Carrying Costs Income	0.4			0.2
Allowance for Equity Funds Used During Construction	1.9			5.2
Non-Service Cost Components of Net Periodic Benefit Cost	3.8			3.7
Interest Expense	(28.9		)	(24.6		)

INCOME BEFORE INCOME TAX EXPENSE	84.8			147.8

Income Tax Expense	9.7			19.8

NET INCOME	$	75.1		$	128.0



The common stock of OPCo is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2020		2019
Net Income	$	75.1	$	128.0

OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $(0.1) in 2020 and 2019, Respectively	—		(0.3		)

TOTAL COMPREHENSIVE INCOME	$	75.1	$	127.7

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018	$	321.2	$	838.8	$	1,136.4		$	1.0		$	2,297.4

Common Stock Dividends					(25.0		)				(25.0		)
Net 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

TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019	$	321.2	$	838.8	$	1,348.5		$	—		$	2,508.5

Common Stock Dividends					(21.9		)				(21.9		)
ASU 2016-13 Adoption					0.3						0.3
Net Income					75.1						75.1
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2020	$	321.2	$	838.8	$	1,402.0		$	—		$	2,562.0



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, 2020 and December 31, 2019

(in millions)

(Unaudited)



	March 31,			December 31,
	2020			2019
CURRENT ASSETS
Cash and Cash Equivalents	$	3.1		$	3.7
Accounts Receivable:
Customers	42.9			53.0
Affiliated Companies	73.1			59.3
Accrued Unbilled Revenues	34.2			20.3
Miscellaneous	3.8			0.5
Allowance for Uncollectible Accounts	(0.4		)	(0.7		)
Total Accounts Receivable	153.6			132.4
Materials and Supplies	58.3			52.3
Renewable Energy Credits	26.9			30.9
Prepayments and Other Current Assets	23.7			19.2
TOTAL CURRENT ASSETS	265.6			238.5

PROPERTY, PLANT AND EQUIPMENT
Electric:
Transmission	2,713.0			2,686.3
Distribution	5,404.5			5,323.5
Other Property, Plant and Equipment	797.2			765.8
Construction Work in Progress	412.5			394.4
Total Property, Plant and Equipment	9,327.2			9,170.0
Accumulated Depreciation and Amortization	2,292.8			2,263.0
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	7,034.4			6,907.0

OTHER NONCURRENT ASSETS
Regulatory Assets	396.4			351.8
Deferred Charges and Other Noncurrent Assets	485.6			546.3
TOTAL OTHER NONCURRENT ASSETS	882.0			898.1

TOTAL ASSETS	$	8,182.0		$	8,043.6



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

March 31, 2020 and December 31, 2019

(dollars in millions)

(Unaudited)



	March 31,		December 31,
	2020		2019
CURRENT LIABILITIES
Advances from Affiliates	$	29.4	$	131.0
Accounts Payable:
General	220.3		233.7
Affiliated Companies	109.0		103.6
Long-term Debt Due Within One Year – Nonaffiliated	0.1		0.1
Risk Management Liabilities	8.7		7.3
Customer Deposits	74.1		70.6
Accrued Taxes	449.2		587.9
Obligations Under Operating Leases	13.0		12.5
Other Current Liabilities	139.5		151.2
TOTAL CURRENT LIABILITIES	1,043.3		1,297.9

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	2,429.0		2,081.9
Long-term Risk Management Liabilities	112.2		96.3
Deferred Income Taxes	871.0		849.4
Regulatory Liabilities and Deferred Investment Tax Credits	1,040.6		1,090.9
Obligations Under Operating Leases	79.8		76.0
Deferred Credits and Other Noncurrent Liabilities	44.1		42.7
TOTAL NONCURRENT LIABILITIES	4,576.7		4,237.2

TOTAL LIABILITIES	5,620.0		5,535.1

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	1,402.0		1,348.5
TOTAL COMMON SHAREHOLDER’S EQUITY	2,562.0		2,508.5

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	8,182.0	$	8,043.6



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2020			2019
OPERATING ACTIVITIES
Net Income	$	75.1		$	128.0
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	70.5			63.3
Amortization of Generation Deferrals	—			32.4
Deferred Income Taxes	12.9			10.1
Allowance for Equity Funds Used During Construction	(1.9		)	(5.2		)
Mark-to-Market of Risk Management Contracts	17.3			6.7
Property Taxes	74.4			66.0
Refund of Global Settlement	—			(4.1		)
Reversal of Regulatory Provision	—			(56.2		)
Change in Other Noncurrent Assets	(61.5		)	(7.5		)
Change in Other Noncurrent Liabilities	(36.4		)	17.6
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(19.9		)	31.7
Materials and Supplies	(10.2		)	(3.4		)
Accounts Payable	35.5			(23.9		)
Accrued Taxes, Net	(141.9		)	(114.4		)
Other Current Assets	(2.0		)	(7.7		)
Other Current Liabilities	(8.4		)	(16.2		)
Net Cash Flows from Operating Activities	3.5			117.2

INVESTING ACTIVITIES
Construction Expenditures	(232.8		)	(198.5		)
Other Investing Activities	5.9			3.7
Net Cash Flows Used for Investing Activities	(226.9		)	(194.8		)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated	347.1			—
Change in Advances from Affiliates, Net	(101.6		)	113.5
Retirement of Long-term Debt – Nonaffiliated	—			(23.4		)
Principal Payments for Finance Lease Obligations	(1.2		)	(0.7		)
Dividends Paid on Common Stock	(21.9		)	(25.0		)
Other Financing Activities	0.4			0.5
Net Cash Flows from Financing Activities	222.8			64.9

Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding	(0.6		)	(12.7		)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period	3.7			32.5
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period	$	3.1		$	19.8

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	16.7		$	17.0
Net Cash Paid (Received) for Income Taxes	—			(0.2		)
Noncash Acquisitions Under Finance Leases	4.3			3.2
Construction Expenditures Included in Current Liabilities as of March 31,	72.9			72.8



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

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,
	2020	2019
	(in millions of KWhs)
Retail:
Residential	1,362	1,520
Commercial	1,055	1,089
Industrial	1,437	1,433
Miscellaneous	272	274
Total Retail	4,126	4,316

Wholesale	53	245

Total KWhs	4,179	4,561

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,
	2020	2019
	(in degree days)
Actual – Heating (a)	799	1,171
Normal – Heating (b)	1,034	1,032

Actual – Cooling (c)	33	3
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.


(c)	Cooling degree days are calculated on a 65 degree temperature base.

First Quarter of 2020 Compared to First Quarter of 2019



Reconciliation of First Quarter of 2019 to First Quarter of 2020
Net Income (Loss)
(in millions)

First Quarter of 2019	$	6.2

Changes in Gross Margin:
Retail Margins (a)	—
Margins from Off-system Sales	(0.2		)
Transmission Revenues	(0.5		)
Other Revenues	(1.2		)
Total Change in Gross Margin	(1.9		)

Changes in Expenses and Other:
Other Operation and Maintenance	(15.5		)
Depreciation and Amortization	(1.2		)
Taxes Other Than Income Taxes	0.1
Interest Income	0.1
Allowance for Equity Funds Used During Construction	0.9
Interest Expense	1.1
Total Change in Expenses and Other	(14.5		)

Income Tax Expense	(0.1		)

First Quarter of 2020	$	(10.3	)


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

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


•	Retail Margins were consistent with the prior year due to the following:


•	An $11 million increase due to new base rates implemented in April 2019.

This increase was partially offset by:


•	A $7 million decrease in revenue from rate riders. This decrease was partially offset in other expense items below.


•	A $3 million decrease in weather-related usage due to a 32% decrease in heating degree days.

Expenses and Other changed between years as follows:


•	Other Operation and Maintenance expenses increased $16 million primarily due the following:


•	A $6 million increase in transmission expenses primarily due to increased SPP transmission services.


•	A $5 million increase in distribution expenses primarily due to an increase in vegetation management expenses.


•	A $1 million increase in Energy Efficiency program costs. This increase was offset in Retail Margins above.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF OPERATIONS

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2020			2019
REVENUES
Electric Generation, Transmission and Distribution	$	295.4		$	329.2
Sales to AEP Affiliates	1.1			1.6
Other Revenues	0.8			2.0
TOTAL REVENUES	297.3			332.8

EXPENSES
Fuel and Other Consumables Used for Electric Generation	16.9			38.0
Purchased Electricity for Resale	110.4			122.9
Other Operation	87.2			73.6
Maintenance	24.4			22.5
Depreciation and Amortization	44.7			43.5
Taxes Other Than Income Taxes	11.3			11.4
TOTAL EXPENSES	294.9			311.9

OPERATING INCOME	2.4			20.9

Other Income (Expense):
Interest Income	0.1			—
Allowance for Equity Funds Used During Construction	1.0			0.1
Non-Service Cost Components of Net Periodic Benefit Cost	2.1			2.1
Interest Expense	(15.8		)	(16.9		)

INCOME (LOSS) BEFORE INCOME TAX EXPENSE	(10.2		)	6.2

Income Tax Expense	0.1			—

NET INCOME (LOSS)	$	(10.3	)	$	6.2



The common stock of PSO is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2020			2019
Net Income (Loss)	$	(10.3	)	$	6.2

OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) in 2020 and 2019, Respectively	(0.2		)	(0.2		)

TOTAL COMPREHENSIVE INCOME (LOSS)	$	(10.5	)	$	6.0



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018	$	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

TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2019	$	157.2	$	364.0	$	851.0		$	1.1		$	1,373.3

ASU 2016-13 Adoption					0.3						0.3
Net Loss					(10.3		)				(10.3		)
Other Comprehensive Loss								(0.2		)	(0.2		)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2020	$	157.2	$	364.0	$	841.0		$	0.9		$	1,363.1



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED BALANCE SHEETS

ASSETS

March 31, 2020 and December 31, 2019

(in millions)

(Unaudited)



	March 31,			December 31,
	2020			2019
CURRENT ASSETS
Cash and Cash Equivalents	$	1.1		$	1.5
Advances to Affiliates	—			38.8
Accounts Receivable:
Customers	28.4			28.9
Affiliated Companies	19.9			20.6
Miscellaneous	0.8			0.6
Allowance for Uncollectible Accounts	(0.2		)	(0.3		)
Total Accounts Receivable	48.9			49.8
Fuel	19.6			12.2
Materials and Supplies	47.9			46.8
Risk Management Assets	6.4			15.8
Accrued Tax Benefits	5.7			11.3
Prepayments and Other Current Assets	13.4			12.0
TOTAL CURRENT ASSETS	143.0			188.2

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	1,577.2			1,574.6
Transmission	959.5			948.5
Distribution	2,724.3			2,684.8
Other Property, Plant and Equipment	350.3			342.1
Construction Work in Progress	144.9			133.4
Total Property, Plant and Equipment	5,756.2			5,683.4
Accumulated Depreciation and Amortization	1,615.8			1,580.1
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	4,140.4			4,103.3

OTHER NONCURRENT ASSETS
Regulatory Assets	378.4			375.2
Employee Benefits and Pension Assets	44.2			43.9
Operating Lease Assets	38.0			36.8
Deferred Charges and Other Noncurrent Assets	34.0			4.1
TOTAL OTHER NONCURRENT ASSETS	494.6			460.0

TOTAL ASSETS	$	4,778.0		$	4,751.5



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

March 31, 2020 and December 31, 2019

(Unaudited)



	March 31,		December 31,
	2020		2019
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	70.9	$	—
Accounts Payable:
General	102.5		134.3
Affiliated Companies	39.8		59.3
Long-term Debt Due Within One Year – Nonaffiliated	263.2		13.2
Risk Management Liabilities	0.1		—
Customer Deposits	59.3		58.9
Accrued Taxes	42.4		22.9
Obligations Under Operating Leases	6.0		5.8
Regulatory Liability for Over-Recovered Fuel Costs	68.0		63.9
Other Current Liabilities	78.6		87.5
TOTAL CURRENT LIABILITIES	730.8		445.8

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	1,123.1		1,373.0
Deferred Income Taxes	629.6		628.3
Regulatory Liabilities and Deferred Investment Tax Credits	835.0		837.2
Asset Retirement Obligations	45.3		44.5
Obligations Under Operating Leases	32.1		31.0
Deferred Credits and Other Noncurrent Liabilities	19.0		18.4
TOTAL NONCURRENT LIABILITIES	2,684.1		2,932.4

TOTAL LIABILITIES	3,414.9		3,378.2

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

COMMON SHAREHOLDER’S EQUITY
Common Stock – Par Value – $15 Per Share:
Authorized – 11,000,000 Shares
Issued – 10,482,000 Shares
Outstanding – 9,013,000 Shares	157.2		157.2
Paid-in Capital	364.0		364.0
Retained Earnings	841.0		851.0
Accumulated Other Comprehensive Income (Loss)	0.9		1.1
TOTAL COMMON SHAREHOLDER’S EQUITY	1,363.1		1,373.3

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	4,778.0	$	4,751.5



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2020			2019
OPERATING ACTIVITIES
Net Income (Loss)	$	(10.3	)	$	6.2
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	44.7			43.5
Deferred Income Taxes	(5.3		)	(5.8		)
Allowance for Equity Funds Used During Construction	(1.0		)	(0.1		)
Mark-to-Market of Risk Management Contracts	9.5			5.1
Property Taxes	(29.8		)	(29.9		)
Deferred Fuel Over/Under-Recovery, Net	4.1			(2.4		)
Change in Other Noncurrent Assets	(0.1		)	8.0
Change in Other Noncurrent Liabilities	4.2			(0.7		)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	0.9			2.0
Fuel, Materials and Supplies	(8.5		)	3.2
Accounts Payable	(39.1		)	(23.3		)
Accrued Taxes, Net	25.1			25.3
Other Current Assets	(1.7		)	(3.8		)
Other Current Liabilities	(7.2		)	4.4
Net Cash Flows from (Used for) Operating Activities	(14.5		)	31.7

INVESTING ACTIVITIES
Construction Expenditures	(96.5		)	(70.7		)
Change in Advances to Affiliates, Net	38.8			—
Other Investing Activities	1.6			0.4
Net Cash Flows Used for Investing Activities	(56.1		)	(70.3		)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated	—			99.9
Change in Advances from Affiliates, Net	70.9			(50.3		)
Retirement of Long-term Debt – Nonaffiliated	(0.1		)	(0.1		)
Principal Payments for Finance Lease Obligations	(0.8		)	(0.7		)
Dividends Paid on Common Stock	—			(11.3		)
Other Financing Activities	0.2			0.6
Net Cash Flows from Financing Activities	70.2			38.1

Net Decrease in Cash and Cash Equivalents	(0.4		)	(0.5		)
Cash and Cash Equivalents at Beginning of Period	1.5			2.0
Cash and Cash Equivalents at End of Period	$	1.1		$	1.5

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	16.7		$	10.9
Net Cash Paid for Income Taxes	—			0.6
Noncash Acquisitions Under Finance Leases	0.9			1.1
Construction Expenditures Included in Current Liabilities as of March 31,	30.8			15.6



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

100

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

101

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,
	2020	2019
	(in millions of KWhs)
Retail:
Residential	1,406	1,528
Commercial	1,228	1,273
Industrial	1,242	1,250
Miscellaneous	20	20
Total Retail	3,896	4,071

Wholesale	1,326	1,979

Total KWhs	5,222	6,050

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,
	2020	2019
	(in degree days)
Actual – Heating (a)	497	708
Normal – Heating (b)	698	698

Actual – Cooling (c)	69	20
Normal – Cooling (b)	39	39


(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.

102

First Quarter of 2020 Compared to First Quarter of 2019



Reconciliation of First Quarter of 2019 to First Quarter of 2020
Earnings Attributable to SWEPCo Common Shareholder
(in millions)

First Quarter of 2019	$	27.8

Changes in Gross Margin:
Retail Margins (a)	(4.2		)
Margins from Off-system Sales	(1.6		)
Transmission Revenues	4.8
Other Revenues	(0.3		)
Total Change in Gross Margin	(1.3		)

Changes in Expenses and Other:
Other Operation and Maintenance	(12.5		)
Depreciation and Amortization	(5.2		)
Interest Income	(0.1		)
Allowance for Equity Funds Used During Construction	(0.4		)
Interest Expense	(0.4		)
Total Change in Expenses and Other	(18.6		)

Income Tax Expense	6.9
Equity Earnings of Unconsolidated Subsidiary	0.1
Net Income Attributable to Noncontrolling Interest	0.2

First Quarter of 2020	$	15.1


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


•	Retail Margins decreased $4 million primarily due to the following:


•	An $8 million decrease in weather-normalized margins.


•	A $5 million decrease in weather-related usage primarily due to a 30% decrease in heating degree days.


•	A $3 million decrease due to an increase in the return of Excess ADIT benefits to customers. This decrease was offset in Income Tax Expense (Benefit) below.

These decreases were partially offset by:


•	An $11 million increase primarily due to capital investment rider and base rate revenue increases in Texas, Arkansas and Louisiana.


•	Transmission Revenues increased $5 million primarily due to an increase in SPP transmission services revenue.

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


•	Other Operation and Maintenance expenses increased $13 million primarily due to the following:


•	A $5 million increase in storm-related expenses.


•	A $3 million increase in SPP transmission expenses.


•	A $2 million increase in employee-related expenses.


•	Depreciation and Amortization expenses increased $5 million primarily due to a higher depreciable base and an increase in Arkansas depreciation rates beginning in January 2020. This increase was partially offset within Retail Margins above.


•	Income Tax Expense decreased $7 million primarily due to a decrease in pretax book income and an increase in amortization of excess ADIT. The increase in amortization of excess ADIT was partially offset in Retail Margins above.

103

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2020			2019
REVENUES
Electric Generation, Transmission and Distribution	$	377.6		$	414.3
Sales to AEP Affiliates	7.5			6.4
Other Revenues	0.8			0.4
TOTAL REVENUES	385.9			421.1

EXPENSES
Fuel and Other Consumables Used for Electric Generation	89.1			133.5
Purchased Electricity for Resale	43.1			32.6
Other Operation	92.2			84.6
Maintenance	33.8			28.9
Depreciation and Amortization	67.3			62.1
Taxes Other Than Income Taxes	25.3			25.3
TOTAL EXPENSES	350.8			367.0

OPERATING INCOME	35.1			54.1

Other Income (Expense):
Interest Income	0.6			0.7
Allowance for Equity Funds Used During Construction	1.4			1.8
Non-Service Cost Components of Net Periodic Benefit Cost	2.1			2.1
Interest Expense	(30.1		)	(29.7		)

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS	9.1			29.0

Income Tax Expense (Benefit)	(6.2		)	0.7
Equity Earnings of Unconsolidated Subsidiary	0.8			0.7

NET INCOME	16.1			29.0

Net Income Attributable to Noncontrolling Interest	1.0			1.2

EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER	$	15.1		$	27.8



The common stock of SWEPCo is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

104

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2020			2019
Net Income	$	16.1		$	29.0

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 in 2020 and 2019, Respectively	0.4			0.4
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) in 2020 and 2019, Respectively	(0.4		)	(0.3		)

TOTAL OTHER COMPREHENSIVE INCOME	—			0.1

TOTAL COMPREHENSIVE INCOME	16.1			29.1

Total Comprehensive Income Attributable to Noncontrolling Interest	1.0			1.2

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER	$	15.1		$	27.9



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

105

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Three Months Ended March 31, 2020 and 2019

(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, 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

TOTAL EQUITY – DECEMBER 31, 2019	$	135.7	$	676.6	$	1,629.5		$	(1.3	)	$	0.6		$	2,441.1

Common Stock Dividends – Nonaffiliated											(0.7		)	(0.7		)
ASU 2016-13 Adoption					1.6									1.6
Net Income					15.1						1.0			16.1
TOTAL EQUITY – MARCH 31, 2020	$	135.7	$	676.6	$	1,646.2		$	(1.3	)	$	0.9		$	2,458.1



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

106

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, 2020 and December 31, 2019

(in millions)

(Unaudited)



	March 31,			December 31,
	2020			2019
CURRENT ASSETS
Cash and Cash Equivalents	$	1.4		$	1.6
Advances to Affiliates	2.1			2.1
Accounts Receivable:
Customers	25.6			29.0
Affiliated Companies	24.4			34.5
Miscellaneous	14.3			13.5
Allowance for Uncollectible Accounts	(0.3		)	(1.7		)
Total Accounts Receivable	64.0			75.3
Fuel (March 31, 2020 and December 31, 2019 Amounts Include $42 and $47, Respectively, Related to Sabine)	147.9			140.1
Materials and Supplies (March 31, 2020 and December 31, 2019 Amounts Include $23.3 and $23.1, Respectively, Related to Sabine)	93.8			94.0
Risk Management Assets	2.6			6.4
Regulatory Asset for Under-Recovered Fuel Costs	—			4.9
Prepayments and Other Current Assets	34.3			29.7
TOTAL CURRENT ASSETS	346.1			354.1

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	4,703.0			4,691.4
Transmission	2,061.6			2,056.5
Distribution	2,300.8			2,270.7
Other Property, Plant and Equipment (March 31, 2020 and December 31, 2019 Amounts Include $213.5 and $212.3, Respectively, Related to Sabine)	767.2			733.4
Construction Work in Progress	232.7			216.9
Total Property, Plant and Equipment	10,065.3			9,968.9
Accumulated Depreciation and Amortization (March 31, 2020 and December 31, 2019 Amounts Include $112 and $107.5, Respectively, Related to Sabine)	2,918.7			2,873.7
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	7,146.6			7,095.2

OTHER NONCURRENT ASSETS
Regulatory Assets	236.6			222.4
Deferred Charges and Other Noncurrent Assets	214.8			160.5
TOTAL OTHER NONCURRENT ASSETS	451.4			382.9

TOTAL ASSETS	$	7,944.1		$	7,832.2



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

107

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

March 31, 2020 and December 31, 2019

(Unaudited)



	March 31,			December 31,
	2020			2019
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	148.1		$	59.9
Accounts Payable:
General	102.5			138.0
Affiliated Companies	37.3			53.6
Short-term Debt – Nonaffiliated	30.5			18.3
Long-term Debt Due Within One Year – Nonaffiliated	121.2			121.2
Risk Management Liabilities	2.2			1.9
Customer Deposits	65.1			65.0
Accrued Taxes	93.0			41.8
Accrued Interest	21.9			34.6
Obligations Under Operating Leases	7.1			6.5
Regulatory Liability for Over-Recovered Fuel Costs	29.7			13.6
Other Current Liabilities	87.8			120.3
TOTAL CURRENT LIABILITIES	746.4			674.7

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	2,533.2			2,534.4
Long-term Risk Management Liabilities	2.9			3.1
Deferred Income Taxes	944.4			940.9
Regulatory Liabilities and Deferred Investment Tax Credits	885.8			892.3
Asset Retirement Obligations	219.7			196.7
Obligations Under Operating Leases	38.2			34.7
Deferred Credits and Other Noncurrent Liabilities	115.4			114.3
TOTAL NONCURRENT LIABILITIES	4,739.6			4,716.4

TOTAL LIABILITIES	5,486.0			5,391.1

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	1,646.2			1,629.5
Accumulated Other Comprehensive Income (Loss)	(1.3		)	(1.3		)
TOTAL COMMON SHAREHOLDER’S EQUITY	2,457.2			2,440.5

Noncontrolling Interest	0.9			0.6

TOTAL EQUITY	2,458.1			2,441.1

TOTAL LIABILITIES AND EQUITY	$	7,944.1		$	7,832.2



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

108

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2020 and 2019

(in millions)

(Unaudited)



	Three Months Ended March 31,
	2020			2019
OPERATING ACTIVITIES
Net Income	$	16.1		$	29.0
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	67.3			62.1
Deferred Income Taxes	(9.2		)	(2.5		)
Allowance for Equity Funds Used During Construction	(1.4		)	(1.8		)
Mark-to-Market of Risk Management Contracts	3.9			2.3
Property Taxes	(49.0		)	(48.9		)
Deferred Fuel Over/Under-Recovery, Net	21.0			10.3
Change in Other Noncurrent Assets	(4.0		)	2.9
Change in Other Noncurrent Liabilities	9.8			7.9
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	11.3			6.3
Fuel, Materials and Supplies	(7.6		)	(16.2		)
Accounts Payable	(31.2		)	(55.0		)
Accrued Taxes, Net	51.2			52.7
Accrued Interest	(12.7		)	(12.7		)
Other Current Assets	(4.0		)	(10.0		)
Other Current Liabilities	(35.7		)	(17.0		)
Net Cash Flows from Operating Activities	25.8			9.4

INVESTING ACTIVITIES
Construction Expenditures	(122.4		)	(86.6		)
Change in Advances to Affiliates, Net	—			81.4
Other Investing Activities	0.8			(3.1		)
Net Cash Flows Used for Investing Activities	(121.6		)	(8.3		)

FINANCING ACTIVITIES
Change in Short-term Debt – Nonaffiliated	12.2			—
Change in Advances from Affiliates, Net	88.2			74.0
Retirement of Long-term Debt – Nonaffiliated	(1.6		)	(55.1		)
Principal Payments for Finance Lease Obligations	(2.7		)	(2.7		)
Dividends Paid on Common Stock	—			(18.7		)
Dividends Paid on Common Stock – Nonaffiliated	(0.7		)	(1.1		)
Other Financing Activities	0.2			0.1
Net Cash Flows from (Used for) Financing Activities	95.6			(3.5		)

Net Decrease in Cash and Cash Equivalents	(0.2		)	(2.4		)
Cash and Cash Equivalents at Beginning of Period	1.6			24.5
Cash and Cash Equivalents at End of Period	$	1.4		$	22.1

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	40.7		$	40.5
Net Cash Paid for Income Taxes	—			0.2
Noncash Acquisitions Under Finance Leases	3.0			0.8
Construction Expenditures Included in Current Liabilities as of March 31,	45.2			44.8



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 110.

109

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	111
New Accounting Standards	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	113
Comprehensive Income	AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo	114
Rate Matters	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	118
Commitments, Guarantees and Contingencies	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	126
Acquisitions and Impairments	AEP, APCo	131
Benefit Plans	AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo	132
Business Segments	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	134
Derivatives and Hedging	AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo	139
Fair Value Measurements	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	150
Income Taxes	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	165
Financing Activities	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	167
Revenue from Contracts with Customers	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	174

110

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 statement 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, 2020 is not necessarily indicative of results that may be expected for the year ending December 31, 2020. The condensed financial statements are unaudited and should be read in conjunction with the audited 2019 financial statements and notes thereto, which are included in the Registrants’ Annual Reports on Form 10-K as filed with the SEC on February 20, 2020.

COVID-19

In March 2020, COVID-19 was declared a pandemic by the World Health Organization and the Centers for Disease Control and Prevention. Its rapid spread around the world and throughout the United States prompted many countries, including the United States, to institute restrictions on travel, public gatherings and certain business operations. These restrictions significantly disrupted economic activity in AEP’s service territory and could reduce future demand for energy, particularly from commercial and industrial customers. The Registrants are taking steps to mitigate the potential risks to customers, suppliers and employees posed by the spread of COVID-19.

As of March 31, 2020 and through the date of this report, the Registrants assessed certain accounting matters that require consideration of forecasted financial information, including, but not limited to, the allowance for credit losses and the carrying value of long-lived assets. While there were not any impairments or significant increases in credit allowances resulting from these assessments as of and for the quarter ended March 31, 2020, the ultimate impact of COVID-19 also depends on factors beyond management’s knowledge or control, including the duration and severity of this outbreak as well as third-party actions taken to contain its spread and mitigate its public health effects. Therefore, management cannot estimate the potential future impact to financial position, results of operations and cash flows, but the impacts could be material.

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 awards.

The following table presents AEP’s basic and diluted EPS calculations included on the statements of income:



	Three Months Ended March 31,
	2020				2019
	(in millions, except per share data)
			$/share				$/share
Earnings Attributable to AEP Common Shareholders	$	495.2			$	572.8

Weighted Average Number of Basic Shares Outstanding	494.6		$	1.00	493.3		$	1.16
Weighted Average Dilutive Effect of Stock-Based Awards	2.0		—		1.2		—
Weighted Average Number of Diluted Shares Outstanding	496.6		$	1.00	494.5		$	1.16

111

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, 2020 and 2019, as the dilutive stock price threshold was not met. See Note 12 - Financing Activities for more information related to Equity Units.

There were 697 thousand and 0 antidilutive shares outstanding as of March 31, 2020 and 2019, respectively. The antidilutive shares were excluded from the calculation of diluted EPS.

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

Restricted Cash primarily included funds held by trustee for the payment of securitization bonds and contractually restricted deposits held for the future payment of the remaining construction activities at Santa Rita East.

Reconciliation of Cash, Cash Equivalents and Restricted Cash

The following tables provide a reconciliation of Cash, Cash Equivalents and Restricted Cash reported within the balance sheets that sum to the total of the same amounts shown on the statements of cash flows:



	March 31, 2020
	AEP		AEP Texas		APCo
	(in millions)
Cash and Cash Equivalents	$	1,554.6	$	0.1	$	2.8
Restricted Cash	116.2		100.1		15.7
Total Cash, Cash Equivalents and Restricted Cash	$	1,670.8	$	100.2	$	18.5



	December 31, 2019
	AEP		AEP Texas		APCo
	(in millions)
Cash and Cash Equivalents	$	246.8	$	3.1	$	3.3
Restricted Cash	185.8		154.7		23.5
Total Cash, Cash Equivalents and Restricted Cash	$	432.6	$	157.8	$	26.8

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Allowance for Uncollectible Accounts

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

112

2. NEW ACCOUNTING STANDARDS

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

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

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

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

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

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

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

In March 2020, the FASB issued ASU 2020-04 providing guidance to ease the potential burden in accounting for Reference Rate Reform on financial reporting. The new standard is elective and applies to all entities, subject to meeting certain criteria, that have contracts, hedging relationships, and other transactions that reference the London Interbank Offered Rate (LIBOR) or another reference rate expected to be discontinued because of Reference Rate Reform. The new standard establishes a general contract modification principle that entities can apply in other areas that may be affected by Reference Rate Reform and certain elective hedge accounting expedients. Under the new standard, an entity may make a one-time election to sell or to transfer to the available-for-sale or trading classifications (or both sell and transfer), debt securities that both reference an affected rate, and were classified as held-to-maturity before January 1, 2020.

The new accounting guidance is effective for all entities as of March 12, 2020 through December 31, 2022. The amendments may be applied to contract modifications as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. The amendments may be applied to eligible hedging relationships existing as of the beginning of the interim period that includes March 12, 2020 and to new eligible hedging relationships entered into after the beginning of the interim period that includes March 12, 2020. The one-time election to sell, transfer, or both sell and transfer debt securities classified as held-to-maturity may be made at any time after March 12, 2020 but no later than December 31, 2022. Management has yet to apply the amendments in the new standard to any contract modifications, hedging relationships, or debt securities. Management is analyzing the impact of this new standard and at this time, cannot estimate the impact of adoption on results of operations, financial position or cash flows.

113

3. COMPREHENSIVE INCOME

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

Presentation of Comprehensive Income

The following tables provide the components of changes in AOCI and details of reclassifications from AOCI. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 - Benefit Plans for additional details.

AEP



	Cash Flow Hedges							Pension
Three Months Ended March 31, 2020	Commodity			Interest Rate				and OPEB			Total
	(in millions)
Balance in AOCI as of December 31, 2019	$	(103.5	)	$	(11.5	)		$	(32.7	)	$	(147.7	)
Change in Fair Value Recognized in AOCI	(65.3		)	(42.7		)	(a)	—			(108.0		)
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (a)	(0.1		)	—				—			(0.1		)
Purchased Electricity for Resale (b)	51.1			—				—			51.1
Interest Expense (b)	—			0.9				—			0.9
Amortization of Prior Service Cost (Credit)	—			—				(4.9		)	(4.9		)
Amortization of Actuarial (Gains) Losses	—			—				2.6			2.6
Reclassifications from AOCI, before Income Tax (Expense) Benefit	51.0			0.9				(2.3		)	49.6
Income Tax (Expense) Benefit	10.7			0.2				(0.5		)	10.4
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	40.3			0.7				(1.8		)	39.2
Net Current Period Other Comprehensive Income (Loss)	(25.0		)	(42.0		)		(1.8		)	(68.8		)
Balance in AOCI as of March 31, 2020	$	(128.5	)	$	(53.5	)		$	(34.5	)	$	(216.5	)



	Cash Flow Hedges						Pension
Three Months Ended March 31, 2019	Commodity			Interest Rate			and OPEB			Total
	(in millions)
Balance in AOCI as of December 31, 2018	$	(23.0	)	$	(12.6	)	$	(84.8	)	$	(120.4	)
Change in Fair Value Recognized in AOCI	(38.8		)	—			—			(38.8		)
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity for Resale (b)	12.3			—			—			12.3
Interest Expense (b)	—			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	)

114

AEP Texas



		Cash Flow Hedge –			Pension
Three Months Ended March 31, 2020		Interest Rate			and OPEB			Total
	(in millions)
Balance in AOCI as of December 31, 2019		$	(3.4	)	$	(9.4	)	$	(12.8	)
Change in Fair Value Recognized in AOCI		—			—			—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)		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, 2020		$	(3.1	)	$	(9.4	)	$	(12.5	)



		Cash Flow Hedge –			Pension
Three Months Ended March 31, 2019		Interest Rate			and OPEB			Total
	(in millions)
Balance in AOCI as of December 31, 2018		$	(4.4	)	$	(10.7	)	$	(15.1	)
Change in Fair Value Recognized in AOCI		—			—			—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)		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	)

APCo



		Cash Flow Hedge –			Pension
Three Months Ended March 31, 2020		Interest Rate			and OPEB			Total
	(in millions)
Balance in AOCI as of December 31, 2019		$	0.9		$	4.1		$	5.0
Change in Fair Value Recognized in AOCI		(3.9		)	—			(3.9		)
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)		(0.4		)	—			(0.4		)
Amortization of Prior Service Cost (Credit)		—			(1.3		)	(1.3		)
Amortization of Actuarial (Gains) Losses		—			0.1			0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(0.4		)	(1.2		)	(1.6		)
Income Tax (Expense) Benefit		(0.1		)	(0.3		)	(0.4		)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.3		)	(0.9		)	(1.2		)
Net Current Period Other Comprehensive Income (Loss)		(4.2		)	(0.9		)	(5.1		)
Balance in AOCI as of March 31, 2020		$	(3.3	)	$	3.2		$	(0.1	)



		Cash Flow Hedge –			Pension
Three Months Ended March 31, 2019		Interest Rate			and OPEB			Total
	(in millions)
Balance in AOCI as of December 31, 2018		$	1.8		$	(6.8	)	$	(5.0	)
Change in Fair Value Recognized in AOCI		—			—			—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)		(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	)

115

I&M



		Cash Flow Hedge –			Pension
Three Months Ended March 31, 2020		Interest Rate			and OPEB			Total
	(in millions)
Balance in AOCI as of December 31, 2019		$	(9.9	)	$	(1.7	)	$	(11.6	)
Change in Fair Value Recognized in AOCI		—			—			—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)		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, 2020		$	(9.5	)	$	(1.7	)	$	(11.2	)



		Cash Flow Hedge –			Pension
Three Months Ended March 31, 2019		Interest Rate			and OPEB			Total
	(in millions)
Balance in AOCI as of December 31, 2018		$	(11.5	)	$	(2.3	)	$	(13.8	)
Change in Fair Value Recognized in AOCI		—			—			—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)		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	)

OPCo



		Cash Flow Hedge –
Three Months Ended March 31, 2020		Interest Rate
	(in millions)
Balance in AOCI as of December 31, 2019		$	—
Change in Fair Value Recognized in AOCI		—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)		—
Reclassifications from AOCI, before Income Tax (Expense) Benefit		—
Income Tax (Expense) Benefit		—
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		—
Net Current Period Other Comprehensive Income (Loss)		—
Balance in AOCI as of March 31, 2020		$	—



		Cash Flow Hedge –
Three Months Ended March 31, 2019		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 (b)		(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

116

PSO



		Cash Flow Hedge –
Three Months Ended March 31, 2020		Interest Rate
	(in millions)
Balance in AOCI as of December 31, 2019		$	1.1
Change in Fair Value Recognized in AOCI		—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)		(0.3		)
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(0.3		)
Income Tax (Expense) 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, 2020		$	0.9



		Cash Flow Hedge –
Three Months Ended March 31, 2019		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 (b)		(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

SWEPCo



		Cash Flow Hedge –			Pension
Three Months Ended March 31, 2020		Interest Rate			and OPEB			Total
	(in millions)
Balance in AOCI as of December 31, 2019		$	(1.8	)	$	0.5		$	(1.3	)
Change in Fair Value Recognized in AOCI		—			—			—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)		0.5			—			0.5
Amortization of Prior Service Cost (Credit)		—			(0.5		)	(0.5		)
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, 2020		$	(1.4	)	$	0.1		$	(1.3	)



		Cash Flow Hedge –			Pension
Three Months Ended March 31, 2019		Interest Rate			and OPEB			Total
	(in millions)
Balance in AOCI as of December 31, 2018		$	(3.3	)	$	(2.1	)	$	(5.4	)
Change in Fair Value Recognized in AOCI		—			—			—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b)		0.5			—			0.5
Amortization of Prior Service Cost (Credit)		—			(0.5		)	(0.5		)
Amortization of Actuarial (Gains) Losses		—			0.1			0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.5			(0.4		)	0.1
Income Tax (Expense) Benefit		0.1			(0.1		)	—
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.4			(0.3		)	0.1
Net Current Period Other Comprehensive Income (Loss)		0.4			(0.3		)	0.1
Balance in AOCI as of March 31, 2019		$	(2.9	)	$	(2.4	)	$	(5.3	)


(a)	The change in fair value includes $5 million related to AEP's investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC for the three months ended March 31, 2020.


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

117

4. RATE MATTERS

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

As discussed in the 2019 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2019 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2020 and updates the 2019 Annual Report.

Regulated Generating Units to be Retired (Applies to AEP, PSO and SWEPCo)

In September 2018, management announced that the Oklaunion Power Station is probable of abandonment and is expected to be retired by October 2020.

In January 2020, as part of the 2019 Arkansas Base Rate Case, management announced that the Dolet Hills Power Station was probable of abandonment and was to be retired by December 2026. In March 2020, management announced plans to accelerate the expected retirement date to the end of September 2021.

The table below summarizes the plant investment and their cost of removal, currently being recovered, as well as the regulatory assets for accelerated depreciation for the generating units as of March 31, 2020.



Plant	Gross Investment		Accumulated Depreciation		Net Investment		Accelerated Depreciation Regulatory Asset			Materials and Supplies		Cost of Removal Regulatory Liability		Expected Retirement Date	Remaining Recovery Period
	(dollars in millions)
Oklaunion Power Station	$	106.8	$	92.6	$	14.2	$	33.0	(a)	$	3.3	$	5.2	2020	27 years
Dolet Hills Power Station	341.4		205.0		136.4		9.1		(b)	5.8		23.7		2021	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.


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

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

118

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

Regulatory Assets Pending Final Regulatory Approval (Applies to all Registrants except AEPTCo)



	AEP
	March 31,		December 31,
	2020		2019
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Plant Retirement Costs – Unrecovered Plant	$	35.2	$	35.2
Oklaunion Power Station Accelerated Depreciation	33.0		27.4
Kentucky Deferred Purchase Power Expenses	32.9		30.2
Dolet Hills Power Station Accelerated Depreciation	9.1		—
Other Regulatory Assets Pending Final Regulatory Approval	2.1		0.7
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs – Asset Retirement Obligation Costs	25.9		30.1
Asset Retirement Obligation	7.7		7.2
Storm-Related Costs	7.3		7.2
Vegetation Management Program (a)	3.8		29.4
Cook Plant Study Costs (b)	—		7.6
Other Regulatory Assets Pending Final Regulatory Approval	5.0		6.7
Total Regulatory Assets Pending Final Regulatory Approval (c)	$	162.0	$	181.7


(a)	In April 2020, $26 million of deferred expenses were approved for recovery. See “2019 Texas Base Rate Case” section below for additional information.


(b)	Approved for recovery in the first quarter of 2020 in the Indiana Base Rate Case.

(c)

APCo is currently in the process of retiring and replacing its Virginia jurisdictional Automated Meter Reading (AMR) meters with AMI meters. As of March 31, 2020 and December 31, 2019, APCo has approximately $52 million and $51 million, respectively, of Virginia jurisdictional AMR meters recorded in Total Property, Plant and Equipment - Net on its balance sheets. APCo is pursuing full recovery of these assets through its Virginia depreciation rates. See “2017-2019 Virginia Triennial Review” section below for additional information.



	AEP Texas
	March 31,		December 31,
	2020		2019
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Not Earning a Return
Vegetation Management Program (a)	$	3.8	$	29.4
Other Regulatory Assets Pending Final Regulatory Approval	1.5		1.4
Total Regulatory Assets Pending Final Regulatory Approval	$	5.3	$	30.8


(a)	In April 2020, $26 million of deferred expenses were approved for recovery. See “2019 Texas Base Rate Case” section below for additional information.

119



	APCo
	March 31,		December 31,
	2020		2019
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Plant Retirement Costs – Materials and Supplies	$	—	$	0.5
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs – Asset Retirement Obligation Costs	25.9		30.1
Total Regulatory Assets Pending Final Regulatory Approval (a)	$	25.9	$	30.6

(a)



	I&M
	March 31,		December 31,
	2020		2019
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Not Earning a Return
Cook Plant Study Costs (a)	$	—	$	7.6
Other Regulatory Assets Pending Final Regulatory Approval	—		0.1
Total Regulatory Assets Pending Final Regulatory Approval	$	—	$	7.7


(a)	Approved for recovery in the first quarter of 2020 in the Indiana Base Rate Case.



	OPCo
	March 31,		December 31,
	2020		2019
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Not Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval	$	0.1	$	0.1
Total Regulatory Assets Pending Final Regulatory Approval	$	0.1	$	0.1



	PSO
	March 31,		December 31,
	2020		2019
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Oklaunion Power Station Accelerated Depreciation	$	33.0	$	27.4
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	7.3		7.2
Total Regulatory Assets Pending Final Regulatory Approval	$	40.3	$	34.6

120



	SWEPCo
	March 31,		December 31,
	2020		2019
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Plant Retirement Costs – Unrecovered Plant, Louisiana	$	35.2	$	35.2
Dolet Hills Power Station Accelerated Depreciation	9.1		—
Other Regulatory Assets Pending Final Regulatory Approval	2.2		0.2
Regulatory Assets Currently Not Earning a Return
Asset Retirement Obligation - Louisiana	7.7		7.2
Other Regulatory Assets Pending Final Regulatory Approval	1.9		3.7
Total Regulatory Assets Pending Final Regulatory Approval	$	56.1	$	46.3

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

COVID-19 Pandemic

AEP’s electric utility operating companies have informed retail customers and state regulators that disconnections for non-payment have been temporarily suspended. These uncertain economic conditions may result in the inability of customers to pay for electric service, which could affect the collectability of the Registrants revenues and adversely affect financial results. The Registrants are currently evaluating and working with regulatory commissions on potential rate recovery for increased costs as a result of the impacts of COVID-19. If any costs related to COVID-19 are not recoverable, it could reduce future net income and cash flows and impact financial condition. The table below describes the key elements of orders received, by jurisdiction, in response to COVID-19:



Company	Jurisdiction		Order
AEP Texas, ETT, SWEPCo	Texas	•	Established a COVID-19 Electricity Relief Program to be funded through a rider for eligible residential customers in the areas of the state open to customer choice (AEP Texas only).
		•	Granted permission for utilities to record a regulatory asset for expenses including, but not limited to, non-payment of qualified customer bills who have been affected by the COVID-19 pandemic.
APCo	Virginia	•	Granted permission for utilities to defer expenses related to the COVID-19 pandemic. Deferral will be subject to APCo’s Virginia earnings test during the 2020-2022 Triennial period.
I&M	Michigan	•	Granted permission for utilities to defer certain expenses related to the COVID-19 pandemic.
SWEPCo	Arkansas	•	Granted permission for utilities to establish a regulatory asset to record costs resulting from the suspension of disconnections offset by any cost savings directly attributable to the suspension of disconnections or other activities during the COVID-19 pandemic.
SWEPCo	Louisiana	•	Granted permission for utilities to record a regulatory asset for expenses resulting from the suspension of disconnections and collection of late fees related to the COVID-19 pandemic.

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

2019 Texas Base Rate Case

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

121

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

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

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

2017-2019 Virginia Triennial Review

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

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

In March 2020, APCo submitted its 2017-2019 Virginia triennial earnings review filing and base rate case with the Virginia SCC as required by state law. APCo requested a $65 million annual increase based upon a proposed 9.9% return on common equity. The requested annual increase includes $19 million related to depreciation for updated test year end depreciable balances and a proposed increase in APCo’s Virginia depreciation rates and $8 million related to APCo’s calculated shortfall in 2017-2019 APCo’s Virginia earnings. Inclusive of the $93 million expense associated with APCo’s Virginia jurisdictional retired coal-fired plants, APCo calculated its 2017-2019 Virginia earnings for the triennial period to be below the authorized ROE range.

122

APCo is currently in the process of retiring and replacing its Virginia jurisdictional Automated Meter Reading (AMR) meters with AMI meters. As of March 31, 2020 and December 31, 2019, APCo has approximately $52 million and $51 million of Virginia jurisdictional AMR meters recorded in Total Property, Plant and Equipment - Net on its balance sheets. APCo is pursuing full recovery of these assets through its Virginia depreciation rates as discussed above.

If any APCo Virginia jurisdictional costs are not recoverable or if refunds of revenues collected from customers during the triennial review period are ordered by the Virginia SCC, it could reduce future net income and cash flows and impact financial condition.

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 base rate proceeding. Through March 31, 2020, AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $1.1 billion. A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring.

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

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

2019 Indiana Base Rate Case

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

In March 2020, the IURC issued an order authorizing a $77 million annual base rate increase based upon a return on common equity of 9.7% effective March 2020. This increase will be phased in through January 2021 with an approximate $44 million annual increase in base rates effective March 2020 and the full $77 million annual increase effective January 2021. The order approved the majority of I&M’s proposed changes in depreciation. The order also approved the test year level of AMI deployment but did not approve a cost recovery rider for AMI investments made in subsequent years. The order rejected I&M’s proposed re-allocation of capacity costs related to the loss of a significant FERC wholesale contract, which will negatively impact I&M’s annual pretax earnings by approximately $20 million starting June 2020. In March 2020, I&M filed for rehearing as a result of the IURC’s ruling to reject I&M’s proposed re-allocation of capacity costs. Intervenors subsequently filed objections to I&M's appeal. In April 2020, I&M filed a reply to these objections on rehearing and appealed the IURC’s order.

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OPCo Rate Matters (Applies to AEP and OPCo)

2020 Ohio Base Rate Case

In April 2020, OPCo filed a pre-filing notice stating its intent to file an application with the PUCO to adjust distribution rates. OPCo plans to file the application in May 2020 and also plans to request a temporary delay of the normal rate case proceeding due to the COVID-19 pandemic.

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 January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court. In the fourth quarter of 2019 and first quarter of 2020, SWEPCo and various intervenors filed briefs with the Texas Supreme Court.

As of March 31, 2020, the net book value of Turk Plant was $1.5 billion, before cost of removal, including materials and supplies inventory and CWIP. If certain parts of the PUCT order are overturned and if SWEPCo cannot ultimately fully recover its approximate 33% Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition.

2016 Texas Base Rate Case

In 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.

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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. In June 2019, the LPSC staff issued its report which reaffirmed its $11 million refund recommendation. The report also contends that SWEPCo’s requested annual rate increase of $18 million, which was implemented in August 2018, is overstated by $4 million and proposes an annual rate increase of $14 million. Additionally, the report recommends SWEPCo refund the excess over-collections associated with the $4 million difference for the period of August 2018 through the implementation of new rates. In July 2019, the LPSC approved the $11 million refund. A decision by the LPSC on the remaining formula rate plan issues is expected in the second quarter of 2020. If 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 2019 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, 2020, no letters of credit were issued under the revolving credit facility.



Company	Amount		Maturity
	(in millions)
AEP	$	241.2	April 2020 to March 2021
AEP Texas	2.2		July 2020
OPCo (a)	1.0		April 2021


(a)	In April 2020, the maturity date was extended from April 2020 to April 2021.

Guarantees of Equity Method Investees (Applies to AEP)

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

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Indemnifications and Other Guarantees

Contracts

The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of March 31, 2020, there were no material liabilities recorded for any indemnifications.

AEPSC conducts power purchase-and-sale activity on behalf of APCo, I&M, KPCo and 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.

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, 2020, the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows:



Company	Maximum Potential Loss
	(in millions)
AEP	$	48.5
AEP Texas	11.6
APCo	6.6
I&M	4.3
OPCo	7.6
PSO	4.4
SWEPCo	4.9

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.

The Owner Trustee owns the Plant and leases equal portions to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note. The lease term is for 33 years and at the end of the lease term, AEGCo and I&M have the option to renew the lease at a rate that approximates fair value. The option to renew was not included in the measurement of the lease obligation as of March 31, 2020 as the execution of the option was not reasonably certain. AEP, AEGCo and I&M have no ownership interest in the Owner Trustee and do not guarantee its debt.

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The future minimum lease payments for this sale-and-leaseback transaction as of March 31, 2020 were as follows:



Future Minimum Lease Payments	AEP (a)		I&M
	(in millions)
2020	$	147.8	$	73.9
2021	147.8		73.9
2022	147.5		73.7
Total Future Minimum Lease Payments	$	443.1	$	221.5


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

AEPRO Boat and Barge Leases (Applies to AEP)

In 2015, AEP sold its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. Certain boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the respective lessors, ensuring future payments under such leases with maturities up to 2027. As of March 31, 2020, the maximum potential amount of future payments required under the guaranteed leases was $53 million. Under the terms of certain of the arrangements, upon the lessors exercising their rights after an event of default by the nonaffiliated party, AEP is entitled to enter into new lease arrangements as a lessee that would have substantially the same terms as the existing leases. Alternatively, for the arrangements with one of the lessors, upon an event of default by the nonaffiliated party and the lessor exercising its rights, payment to the lessor would allow AEP to step into the lessor’s rights as well as obtaining title to the assets. Under either situation, AEP would have the ability to utilize the assets in the normal course of barging operations. AEP would also have the right to sell the acquired assets for which it obtained title. As of March 31, 2020, AEP’s boat and barge lease guarantee liability was $4 million, of which $1 million was recorded in Other Current Liabilities and $3 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheet.

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

ENVIRONMENTAL CONTINGENCIES (Applies to all Registrants except AEPTCo)

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

By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and 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.

Virginia House Bill 443 (Applies to AEP and APCo)

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July 1, 2022. APCo is permitted to record carrying costs on the unrecovered balance of closure costs at a weighted average cost of capital approved by the Virginia SCC. HB 443 also allows any closure costs allocated to non-Virginia jurisdictional customers, but not collected from such non-Virginia jurisdictional customers, to be recovered from Virginia jurisdictional customers through the E-RAC. Management does not expect HB 443 to materially impact results of operations or cash flows, but does anticipate a material impact to APCo’s balance sheet.

NUCLEAR CONTINGENCIES (Applies to AEP and I&M)

I&M owns and operates the 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.

OPERATIONAL CONTINGENCIES

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

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.

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. The consent decree was modified based on an agreement among the parties in July 2019. As part of the modification to the consent decree, I&M agreed to provide an additional $7.5 million to citizens’ groups and the states for environmental mitigation projects. As joint owners in the Rockport Plant, the $7.5 million payment was shared between AEGCo and I&M based on the joint ownership agreement. The district court entered a stay that expired in February 2020. Settlement negotiations are continuing, and the parties filed a joint proposed case schedule in February 2020. See “Modification of the New Source Review Litigation Consent Decree” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information.

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

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

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6. ACQUISITIONS

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

Sempra Renewables LLC (Generation & Marketing Segment)

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

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

Parent has issued guarantees over the performance of the joint ventures. If a joint venture were to default on payments or performance, Parent would be required to make payments on behalf of the joint venture. As of March 31, 2020, the maximum potential amount of future payments associated with these guarantees was $175 million, with the last guarantee expiring in December 2037. The non-contingent liability recorded associated with these guarantees was $33 million, with an additional $1 million expected credit loss liability for the contingent portion of the guarantees. Management considered historical losses, economic conditions, and reasonable and supportable forecasts in the calculation of the expected credit loss. As the joint ventures generate cash flows through PPAs, the measurement of the contingent portion of the guarantee liability is based upon assessments of the credit quality and default probabilities of the respective PPA counterparties.

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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 nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees.

Components of Net Periodic Benefit Cost

The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans:

AEP



	Pension Plans						OPEB
	Three Months Ended March 31,						Three Months Ended March 31,
	2020			2019			2020			2019
	(in millions)
Service Cost	$	28.0		$	23.9		$	2.5		$	2.4
Interest Cost	42.0			51.1			9.9			12.6
Expected Return on Plan Assets	(66.2		)	(74.0		)	(23.9		)	(23.4		)
Amortization of Prior Service Credit	—			—			(17.4		)	(17.3		)
Amortization of Net Actuarial Loss	23.4			14.4			1.5			5.5
Net Periodic Benefit Cost (Credit)	$	27.2		$	15.4		$	(27.4	)	$	(20.2	)

AEP Texas



	Pension Plans						OPEB
	Three Months Ended March 31,						Three Months Ended March 31,
	2020			2019			2020			2019
	(in millions)
Service Cost	$	2.6		$	2.1		$	0.2		$	0.2
Interest Cost	3.5			4.4			0.8			1.0
Expected Return on Plan Assets	(5.7		)	(6.4		)	(2.0		)	(2.0		)
Amortization of Prior Service Credit	—			—			(1.4		)	(1.5		)
Amortization of Net Actuarial Loss	1.9			1.2			0.1			0.5
Net Periodic Benefit Cost (Credit)	$	2.3		$	1.3		$	(2.3	)	$	(1.8	)

APCo



	Pension Plans						OPEB
	Three Months Ended March 31,						Three Months Ended March 31,
	2020			2019			2020			2019
	(in millions)
Service Cost	$	2.6		$	2.4		$	0.3		$	0.3
Interest Cost	5.1			6.3			1.6			2.2
Expected Return on Plan Assets	(8.4		)	(9.4		)	(3.6		)	(3.7		)
Amortization of Prior Service Credit	—			—			(2.5		)	(2.5		)
Amortization of Net Actuarial Loss	2.8			1.8			0.2			0.9
Net Periodic Benefit Cost (Credit)	$	2.1		$	1.1		$	(4.0	)	$	(2.8	)

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I&M



	Pension Plans						OPEB
	Three Months Ended March 31,						Three Months Ended March 31,
	2020			2019			2020			2019
	(in millions)
Service Cost	$	3.9		$	3.4		$	0.3		$	0.3
Interest Cost	4.9			6.0			1.2			1.5
Expected Return on Plan Assets	(8.3		)	(9.2		)	(2.9		)	(2.8		)
Amortization of Prior Service Credit	—			—			(2.4		)	(2.4		)
Amortization of Net Actuarial Loss	2.7			1.6			0.2			0.7
Net Periodic Benefit Cost (Credit)	$	3.2		$	1.8		$	(3.6	)	$	(2.7	)

OPCo



	Pension Plans						OPEB
	Three Months Ended March 31,						Three Months Ended March 31,
	2020			2019			2020			2019
	(in millions)
Service Cost	$	2.4		$	2.0		$	0.2		$	0.2
Interest Cost	3.9			4.7			1.0			1.4
Expected Return on Plan Assets	(6.6		)	(7.3		)	(2.6		)	(2.7		)
Amortization of Prior Service Credit	—			—			(1.8		)	(1.7		)
Amortization of Net Actuarial Loss	2.1			1.3			0.2			0.6
Net Periodic Benefit Cost (Credit)	$	1.8		$	0.7		$	(3.0	)	$	(2.2	)

PSO



	Pension Plans						OPEB
	Three Months Ended March 31,						Three Months Ended March 31,
	2020			2019			2020			2019
	(in millions)
Service Cost	$	1.8		$	1.6		$	0.2		$	0.2
Interest Cost	2.1			2.6			0.5			0.7
Expected Return on Plan Assets	(3.6		)	(4.1		)	(1.3		)	(1.3		)
Amortization of Prior Service Credit	—			—			(1.1		)	(1.1		)
Amortization of Net Actuarial Loss	1.2			0.8			0.1			0.3
Net Periodic Benefit Cost (Credit)	$	1.5		$	0.9		$	(1.6	)	$	(1.2	)

SWEPCo



	Pension Plans						OPEB
	Three Months Ended March 31,						Three Months Ended March 31,
	2020			2019			2020			2019
	(in millions)
Service Cost	$	2.5		$	2.1		$	0.2		$	0.2
Interest Cost	2.5			3.1			0.6			0.8
Expected Return on Plan Assets	(3.9		)	(4.4		)	(1.5		)	(1.5		)
Amortization of Prior Service Credit	—			—			(1.3		)	(1.3		)
Amortization of Net Actuarial Loss	1.4			0.9			0.1			0.3
Net Periodic Benefit Cost (Credit)	$	2.5		$	1.7		$	(1.9	)	$	(1.5	)

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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 ROEs.


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

Generation & Marketing


•	Competitive generation in ERCOT and PJM.


•	Contracted renewable energy investments and management services.


•	Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO.

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, 2020 and 2019 and reportable segment balance sheet information as of March 31, 2020 and December 31, 2019.



	Three Months Ended March 31, 2020
	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	$	2,193.0	$	1,075.2	$	73.1	$	408.4	$	(2.2	)	$	—		$	3,747.5
Other Operating Segments	33.7		31.7		237.1		30.2		22.1			(354.8		)	—
Total Revenues	$	2,226.7	$	1,106.9	$	310.2	$	438.6	$	19.9		$	(354.8	)	$	3,747.5

Net Income (Loss)	$	246.3	$	116.2	$	141.6	$	30.5	$	(35.3	)	$	—		$	499.3

	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

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	March 31, 2020
	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	$	47,764.3	$	20,182.8	$	10,662.9	$	1,753.2	$	408.3		$	(354.5	)	(b)	$	80,417.0
Accumulated Depreciation and Amortization	14,821.8		3,964.6		464.0		116.9		187.3			(186.5		)	(b)	19,368.1
Total Property Plant and Equipment - Net	$	32,942.5	$	16,218.2	$	10,198.9	$	1,636.3	$	221.0		$	(168.0	)	(b)	$	61,048.9

Total Assets	$	41,020.5	$	18,892.5	$	11,484.8	$	3,216.4	$	7,033.6	(c)	$	(3,923.8	)	(b) (d)	$	77,724.0

Long-term Debt Due Within One Year:
Affiliated	$	20.0	$	—	$	—	$	—	$	—		$	(20.0	)		$	—
Nonaffiliated	1,316.3		289.0		—		—		504.4		(e)	—				2,109.7

Long-term Debt:
Affiliated	39.0		—		—		—		—			(39.0		)		—
Nonaffiliated	11,641.0		6,585.5		3,600.3		—		3,956.2		(e)	—				25,783.0

Total Long-term Debt	$	13,016.3	$	6,874.5	$	3,600.3	$	—	$	4,460.6		$	(59.0	)		$	27,892.7



	December 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	$	47,323.7	$	19,773.3	$	10,334.0	$	1,650.8	$	418.4		$	(354.5	)	(b)	$	79,145.7
Accumulated Depreciation and Amortization	14,580.4		3,911.2		418.9		99.0		184.5			(186.4		)	(b)	19,007.6
Total Property Plant and Equipment - Net	$	32,743.3	$	15,862.1	$	9,915.1	$	1,551.8	$	233.9		$	(168.1	)	(b)	$	60,138.1

Total Assets	$	41,228.8	$	18,757.5	$	11,143.5	$	3,123.8	$	5,440.0	(c)	$	(3,801.3	)	(b) (d)	$	75,892.3

Long-term Debt Due Within One Year:
Affiliated	$	20.0	$	—	$	—	$	—	$	—		$	(20.0	)		$	—
Nonaffiliated	704.7		392.2		—		—		501.8		(e)	—				1,598.7

Long-term Debt:
Affiliated	39.0		—		—		—		—			(39.0		)		—
Nonaffiliated	12,162.0		6,248.1		3,593.8		—		3,122.9		(e)	—				25,126.8

Total Long-term Debt	$	12,925.7	$	6,640.3	$	3,593.8	$	—	$	3,624.7		$	(59.0	)		$	26,725.5


(a)	Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and other nonallocated costs.


(b)	Includes 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.

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.

136

AEPTCo’s Reportable Segments

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

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

The tables below present AEPTCo’s reportable segment income statement information for the three months ended March 31, 2020 and 2019 and reportable segment balance sheet information as of March 31, 2020 and December 31, 2019.



	Three Months Ended March 31, 2020
	State Transcos		AEPTCo Parent			Reconciling Adjustments				AEPTCo Consolidated
	(in millions)
Revenues from:
External Customers	$	61.3	$	—		$	—			$	61.3
Sales to AEP Affiliates	233.7		—			—				233.7
Other Revenues	0.6		—			—				0.6
Total Revenues	$	295.6	$	—		$	—			$	295.6

Interest Income	$	0.2	$	34.0		$	(33.4	)	(a)	$	0.8
Interest Expense	29.6		33.4			(33.4		)	(a)	29.6
Income Tax Expense	31.8		—			—				31.8

Net Income	$	117.3	$	0.5	(b)	$	—			$	117.8

	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

137



	March 31, 2020
	State Transcos		AEPTCo Parent			Reconciling Adjustments				AEPTCo Consolidated
	(in millions)
Total Transmission Property	$	10,221.2	$	—		$	—			$	10,221.2
Accumulated Depreciation and Amortization	445.8		—			—				445.8
Total Transmission Property – Net	$	9,775.4	$	—		$	—			$	9,775.4

Notes Receivable - Affiliated	$	—	$	3,427.8		$	(3,427.8	)	(c)	$	—

Total Assets	$	10,150.9	$	3,562.7	(d)	$	(3,513.7	)	(e)	$	10,199.9

Total Long-term Debt	$	3,465.0	$	3,427.8		$	(3,465.0	)	(c)	$	3,427.8

	December 31, 2019
	State Transcos		AEPTCo Parent			Reconciling Adjustments				AEPTCo Consolidated
	(in millions)
Total Transmission Property	$	9,893.2	$	—		$	—			$	9,893.2
Accumulated Depreciation and Amortization	402.3		—			—				402.3
Total Transmission Property – Net	$	9,490.9	$	—		$	—			$	9,490.9

Notes Receivable - Affiliated	$	—	$	3,427.3		$	(3,427.3	)	(c)	$	—

Total Assets	$	9,865.0	$	3,519.1	(d)	$	(3,493.3	)	(e)	$	9,890.8

Total Long-term Debt	$	3,465.0	$	3,427.3		$	(3,465.0	)	(c)	$	3,427.3


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


(b)	Includes the elimination of AEPTCo Parent’s equity earnings in the State Transcos.


(c)	Elimination of intercompany debt.


(d)	Includes the elimination of AEPTCo Parent’s investments in State Transcos.


(e)	Primarily relates to the elimination of Notes Receivable from the State Transcos.

138

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 and credit 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.

139

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

Notional Volume of Derivative Instruments

March 31, 2020



Primary Risk Exposure	Unit of Measure	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
		(in millions)
Commodity:
Power	MWhs	305.4		—		38.7		18.5		3.2		5.9		1.7
Natural Gas	MMBtus	42.3		—		—		—		—		—		10.7
Heating Oil and Gasoline	Gallons	5.0		1.3		0.8		0.5		1.0		0.5		0.7
Interest Rate	USD	$	137.1	$	—	$	—	$	—	$	—	$	—	$	—

Interest Rate on Long-term Debt	USD	$	650.0	$	—	$	150.0	$	—	$	—	$	—	$	—

December 31, 2019



Primary Risk Exposure	Unit of Measure	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
		(in millions)
Commodity:
Power	MWhs	365.9		—		61.0		26.8		7.1		14.9		4.4
Natural Gas	MMBtus	40.7		—		—		—		—		—		11.6
Heating Oil and Gasoline	Gallons	6.9		1.8		1.1		0.6		1.4		0.7		0.9
Interest Rate	USD	$	140.1	$	—	$	—	$	—	$	—	$	—	$	—

Interest Rate on Long-term Debt	USD	$	625.0	$	—	$	—	$	—	$	—	$	—	$	—

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.

140

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 $0 and $5 million as of March 31, 2020 and December 31, 2019, respectively. AEP netted cash collateral paid to third-parties against short-term and long-term risk management liabilities in the amounts of $76 million and $39 million as of March 31, 2020 and December 31, 2019, respectively. APCo netted cash collateral paid to third-parties against short-term and long-term risk management liabilities in the amounts of $5 million and $1 million as of March 31, 2020 and December 31, 2019, respectively. The netted cash collateral from third-parties against short-term and long-term risk management assets and netted cash collateral paid to third-parties against short-term and long-term risk management liabilities were immaterial for the other Registrant Subsidiaries as of March 31, 2020 and December 31, 2019.

141

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, 2020



	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	$	412.7	$	13.5		$	4.6	$	430.8		$	(300.4	)	$	130.4
Long-term Risk Management Assets	331.6		13.5			52.7		397.8			(74.1		)	323.7
Total Assets	744.3		27.0			57.3		828.6			(374.5		)	454.1

Current Risk Management Liabilities	401.7		103.2			5.3		510.2			(353.4		)	156.8
Long-term Risk Management Liabilities	305.9		82.9			—		388.8			(96.9		)	291.9
Total Liabilities	707.6		186.1			5.3		899.0			(450.3		)	448.7

Total MTM Derivative Contract Net Assets (Liabilities)	$	36.7	$	(159.1	)	$	52.0	$	(70.4	)	$	75.8		$	5.4

December 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	$	513.9	$	11.5		$	6.5	$	531.9	$	(359.1	)	$	172.8
Long-term Risk Management Assets	290.8		11.0			12.6		314.4		(47.8		)	266.6
Total Assets	804.7		22.5			19.1		846.3		(406.9		)	439.4

Current Risk Management Liabilities	424.5		72.3			—		496.8		(382.5		)	114.3
Long-term Risk Management Liabilities	244.5		75.7			—		320.2		(58.4		)	261.8
Total Liabilities	669.0		148.0			—		817.0		(440.9		)	376.1

Total MTM Derivative Contract Net Assets (Liabilities)	$	135.7	$	(125.5	)	$	19.1	$	29.3	$	34.0		$	63.3

142

AEP Texas

Fair Value of Derivative Instruments

March 31, 2020



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

Current Risk Management Liabilities	1.2			(1.2		)	—
Long-term Risk Management Liabilities	—			—			—
Total Liabilities	1.2			(1.2		)	—

Total MTM Derivative Contract Net Assets (Liabilities)	$	(1.2	)	$	1.2		$	—

December 31, 2019

Risk Management

Gross Amounts Offset

Net Amounts of Assets/Liabilities

Contracts –

in the Statement of

Presented in the Statement of

Balance Sheet Location

Commodity (a)

Financial Position (b)

Financial Position (c)

(in millions)

Current Risk Management Assets

—

Long-term Risk Management Assets

—

Total Assets

—

Current Risk Management Liabilities

—

Long-term Risk Management Liabilities

—

Total Liabilities

—

Total MTM Derivative Contract Net Assets

—

APCo

Fair Value of Derivative Instruments

March 31, 2020



	Risk Management		Hedging			Gross Amounts Offset			Net Amounts of Assets/Liabilities
	Contracts –		Contracts –			in the Statement of			Presented in the Statement of
Balance Sheet Location	Commodity (a)		Interest Rate (a)			Financial Position (b)			Financial Position (c)
	(in millions)
Current Risk Management Assets	$	71.1	$	0.3		$	(53.3	)	$	18.1
Long-term Risk Management Assets	3.5		—			(3.4		)	0.1
Total Assets	74.6		0.3			(56.7		)	18.2

Current Risk Management Liabilities	68.3		5.3			(58.6		)	15.0
Long-term Risk Management Liabilities	3.5		—			(3.4		)	0.1
Total Liabilities	71.8		5.3			(62.0		)	15.1

Total MTM Derivative Contract Net Assets (Liabilities)	$	2.8	$	(5.0	)	$	5.3		$	3.1

December 31, 2019



	Risk Management		Gross Amounts Offset			Net Amounts of Assets/Liabilities
	Contracts –		in the Statement of			Presented in the Statement of
Balance Sheet Location	Commodity (a)		Financial Position (b)			Financial Position (c)
	(in millions)
Current Risk Management Assets	$	124.4	$	(85.0	)	$	39.4
Long-term Risk Management Assets	0.9		(0.8		)	0.1
Total Assets	125.3		(85.8		)	39.5

Current Risk Management Liabilities	86.2		(84.3		)	1.9
Long-term Risk Management Liabilities	0.7		(0.7		)	—
Total Liabilities	86.9		(85.0		)	1.9

Total MTM Derivative Contract Net Assets (Liabilities)	$	38.4	$	(0.8	)	$	37.6

143

I&M

Fair Value of Derivative Instruments

March 31, 2020



	Risk Management		Gross Amounts Offset			Net Amounts of Assets/Liabilities
	Contracts –		in the Statement of			Presented in the Statement of
Balance Sheet Location	Commodity (a)		Financial Position (b)			Financial Position (c)
	(in millions)
Current Risk Management Assets	$	42.3	$	(35.6	)	$	6.7
Long-term Risk Management Assets	2.1		(2.0		)	0.1
Total Assets	44.4		(37.6		)	6.8

Current Risk Management Liabilities	38.3		(36.6		)	1.7
Long-term Risk Management Liabilities	2.1		(2.0		)	0.1
Total Liabilities	40.4		(38.6		)	1.8

Total MTM Derivative Contract Net Assets	$	4.0	$	1.0		$	5.0

December 31, 2019



	Risk Management		Gross Amounts Offset			Net Amounts of Assets/Liabilities
	Contracts –		in the Statement of			Presented in the Statement of
Balance Sheet Location	Commodity (a)		Financial Position (b)			Financial Position (c)
	(in millions)
Current Risk Management Assets	$	66.9	$	(57.1	)	$	9.8
Long-term Risk Management Assets	0.5		(0.4		)	0.1
Total Assets	67.4		(57.5		)	9.9

Current Risk Management Liabilities	55.2		(54.7		)	0.5
Long-term Risk Management Liabilities	0.4		(0.4		)	—
Total Liabilities	55.6		(55.1		)	0.5

Total MTM Derivative Contract Net Assets (Liabilities)	$	11.8	$	(2.4	)	$	9.4

OPCo

Fair Value of Derivative Instruments

March 31, 2020



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

Current Risk Management Liabilities	9.6			(0.9		)	8.7
Long-term Risk Management Liabilities	112.2			—			112.2
Total Liabilities	121.8			(0.9		)	120.9

Total MTM Derivative Contract Net Assets (Liabilities)	$	(121.8	)	$	0.9		$	(120.9	)

December 31, 2019



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

Current Risk Management Liabilities	7.3			—		7.3
Long-term Risk Management Liabilities	96.3			—		96.3
Total Liabilities	103.6			—		103.6

Total MTM Derivative Contract Net Liabilities	$	(103.6	)	$	—	$	(103.6	)

144

PSO

Fair Value of Derivative Instruments

March 31, 2020



	Risk Management		Gross Amounts Offset			Net Amounts of Assets/Liabilities
	Contracts –		in the Statement of			Presented in the Statement of
Balance Sheet Location	Commodity (a)		Financial Position (b)			Financial Position (c)
	(in millions)
Current Risk Management Assets	$	6.7	$	(0.3	)	$	6.4
Long-term Risk Management Assets	—		—			—
Total Assets	6.7		(0.3		)	6.4

Current Risk Management Liabilities	0.9		(0.8		)	0.1
Long-term Risk Management Liabilities	—		—			—
Total Liabilities	0.9		(0.8		)	0.1

Total MTM Derivative Contract Net Assets	$	5.8	$	0.5		$	6.3

December 31, 2019



	Risk Management		Gross Amounts Offset			Net Amounts of Assets/Liabilities
	Contracts –		in the Statement of			Presented in the Statement of
Balance Sheet Location	Commodity (a)		Financial Position (b)			Financial Position (c)
	(in millions)
Current Risk Management Assets	$	16.3	$	(0.5	)	$	15.8
Long-term Risk Management Assets	—		—			—
Total Assets	16.3		(0.5		)	15.8

Current Risk Management Liabilities	0.5		(0.5		)	—
Long-term Risk Management Liabilities	—		—			—
Total Liabilities	0.5		(0.5		)	—

Total MTM Derivative Contract Net Assets	$	15.8	$	—		$	15.8

SWEPCo

Fair Value of Derivative Instruments

March 31, 2020



	Risk Management			Gross Amounts Offset			Net Amounts of Assets/Liabilities
	Contracts –			in the Statement of			Presented in the Statement of
Balance Sheet Location	Commodity (a)			Financial Position (b)			Financial Position (c)
	(in millions)
Current Risk Management Assets	$	2.7		$	(0.1	)	$	2.6
Long-term Risk Management Assets	—			—			—
Total Assets	2.7			(0.1		)	2.6

Current Risk Management Liabilities	2.9			(0.7		)	2.2
Long-term Risk Management Liabilities	2.9			—			2.9
Total Liabilities	5.8			(0.7		)	5.1

Total MTM Derivative Contract Net Assets (Liabilities)	$	(3.1	)	$	0.6		$	(2.5	)

December 31, 2019



	Risk Management		Gross Amounts Offset			Net Amounts of Assets/Liabilities
	Contracts –		in the Statement of			Presented in the Statement of
Balance Sheet Location	Commodity (a)		Financial Position (b)			Financial Position (c)
	(in millions)
Current Risk Management Assets	$	6.5	$	(0.1	)	$	6.4
Long-term Risk Management Assets	—		—			—
Total Assets	6.5		(0.1		)	6.4

Current Risk Management Liabilities	2.0		(0.1		)	1.9
Long-term Risk Management Liabilities	3.1		—			3.1
Total Liabilities	5.1		(0.1		)	5.0

Total MTM Derivative Contract Net Assets	$	1.4	$	—		$	1.4


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


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


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

145

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, 2020



Location of Gain (Loss)	AEP			AEP Texas			APCo			I&M			OPCo			PSO			SWEPCo
	(in millions)
Vertically Integrated Utilities Revenues	$	0.4		$	—		$	—		$	—		$	—		$	—		$	—
Generation & Marketing Revenues	(10.3		)	—			—			—			—			—			—
Electric Generation, Transmission and Distribution Revenues	—			—			0.2			0.1			—			—			—
Purchased Electricity for Resale	0.1			—			0.1			—			—			—			—
Other Operation	(0.2		)	(0.1		)	—			—			(0.1		)	—			—
Maintenance	(0.2		)	(0.1		)	(0.1		)	—			—			—			—
Regulatory Assets (a)	(33.9		)	(1.2		)	(8.9		)	(0.7		)	(18.4		)	(0.5		)	(2.0		)
Regulatory Liabilities (a)	11.2			—			(7.3		)	3.2			3.5			8.1			3.3
Total Gain (Loss) on Risk Management Contracts	$	(32.9	)	$	(1.4	)	$	(16.0	)	$	2.6		$	(15.0	)	$	7.6		$	1.3

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


(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.”

146

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 Liabilities						Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Liabilities
	March 31, 2020			December 31, 2019			March 31, 2020			December 31, 2019
	(in millions)
Long-term Debt (a)	$	(553.4	)	$	(510.8	)	$	(57.0	)	$	(14.5	)


(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,
	2020			2019
	(in millions)
Gain (Loss) on Interest Rate Contracts:
Gain on Fair Value Hedging Instruments (a)	$	42.5		$	11.1
Loss on Fair Value Portion of Long-term Debt (a)	(42.5		)	(11.1		)


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

Accounting for Cash Flow Hedging Strategies

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects net income.

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, 2020 and 2019, AEP applied cash flow hedging to outstanding power derivatives. During the three months ended March 31, 2020 and 2019, the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives.

The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three months ended March 31, 2020, AEP and APCo applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not. During the three months ended March 31, 2019, the Registrants did not apply cash flow hedging to outstanding interest rate 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.

147

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, 2020						December 31, 2019
	Commodity			Interest Rate			Commodity			Interest Rate
	(in millions)
AOCI Gain (Loss) Net of Tax	$	(128.5	)	$	(53.5	)	$	(103.5	)	$	(11.5	)
Portion Expected to be Reclassed to Net Income During the Next Twelve Months	(73.2		)	(4.3		)	(51.7		)	(2.1		)

As of March 31, 2020 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 132 months and 129 months for commodity and interest rate hedges, respectively.

Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets



	March 31, 2020						December 31, 2019
	Interest Rate
				Expected to be						Expected to be
				Reclassified to						Reclassified to
				Net Income During						Net Income During
	AOCI Gain (Loss)			the Next			AOCI Gain (Loss)			the Next
Company	Net of Tax			Twelve Months			Net of Tax			Twelve Months
	(in millions)
AEP Texas	$	(3.1	)	$	(1.1	)	$	(3.4	)	$	(1.1	)
APCo	(3.3		)	1.1			0.9			0.9
I&M	(9.5		)	(1.6		)	(9.9		)	(1.6		)
PSO	0.9			0.9			1.1			1.0
SWEPCo	(1.4		)	(1.5		)	(1.8		)	(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.

148

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, 2020 and December 31, 2019, 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, 2020
	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	$	310.4	$	1.6	$	282.9
APCo	2.2		—		0.2
I&M	1.3		—		0.1
SWEPCo	5.5		—		5.5



	December 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	$	267.3	$	3.7	$	246.7
APCo	2.3		—		0.4
I&M	1.3		—		0.2
SWEPCo	5.1		—		5.1

149

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.

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.

150

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, 2020				December 31, 2019
Company	Book Value		Fair Value		Book Value		Fair Value
	(in millions)
AEP (a)	$	27,892.7	$	29,776.6	$	26,725.5	$	30,172.0
AEP Texas	4,445.4		4,637.3		4,558.4		4,981.5
AEPTCo	3,427.8		3,680.7		3,427.3		3,868.0
APCo	4,352.4		4,959.0		4,363.8		5,253.1
I&M	3,028.0		3,318.2		3,050.2		3,453.8
OPCo	2,429.1		2,795.3		2,082.0		2,554.3
PSO	1,386.3		1,553.9		1,386.2		1,603.3
SWEPCo	2,654.4		2,776.5		2,655.6		2,927.9


(a)	The fair value amount includes debt related to AEP’s Equity Units issued in March 2019 and has a fair value of $777 million and $871 million as of March 31, 2020 and December 31, 2019, respectively. See “Equity Units” section of Note 12 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, 2020
			Gross		Gross
			Unrealized		Unrealized		Fair
Other Temporary Investments	Cost		Gains		Losses		Value
	(in millions)
Restricted Cash and Other Cash Deposits (a)	$	151.9	$	—	$	—	$	151.9
Fixed Income Securities – Mutual Funds (b)	118.6		0.4		—		119.0
Equity Securities – Mutual Funds	19.3		11.2		—		30.5
Total Other Temporary Investments	$	289.8	$	11.6	$	—	$	301.4



	December 31, 2019
			Gross		Gross
			Unrealized		Unrealized		Fair
Other Temporary Investments	Cost		Gains		Losses		Value
	(in millions)
Restricted Cash and Other Cash Deposits (a)	$	214.7	$	—	$	—	$	214.7
Fixed Income Securities – Mutual Funds (b)	123.2		0.1		—		123.3
Equity Securities – Mutual Funds	29.2		21.3		—		50.5
Total Other Temporary Investments	$	367.1	$	21.4	$	—	$	388.5


(a)	Primarily represents amounts held for the repayment of debt.


(b)	Primarily short and intermediate maturities which may be sold and do not contain maturity dates.

151

The following table provides the activity for fixed income and equity securities within Other Temporary Investments:



	Three Months Ended March 31,
	2020		2019
	(in millions)
Proceeds from Investment Sales	$	23.2	$	—
Purchases of Investments	6.7		0.1
Gross Realized Gains on Investment Sales	2.0		—
Gross Realized Losses on Investment Sales	0.1		—

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

Other-than-temporary impairments for investments in 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.

152

The following is a summary of nuclear trust fund investments:



	March 31, 2020							December 31, 2019
			Gross		Other-Than-					Gross		Other-Than-
	Fair		Unrealized		Temporary			Fair		Unrealized		Temporary
	Value		Gains		Impairments			Value		Gains		Impairments
	(in millions)
Cash and Cash Equivalents	$	46.9	$	—	$	—		$	15.3	$	—	$	—
Fixed Income Securities:
United States Government	1,026.1		121.4		(5.6		)	1,112.5		55.5		(6.1		)
Corporate Debt	62.7		6.0		(1.6		)	72.4		5.3		(1.6		)
State and Local Government	149.7		1.5		(0.2		)	7.6		0.7		(0.2		)
Subtotal Fixed Income Securities	1,238.5		128.9		(7.4		)	1,192.5		61.5		(7.9		)
Equity Securities - Domestic (a)	1,393.8		777.6		—			1,767.9		1,144.4		—
Spent Nuclear Fuel and Decommissioning Trusts	$	2,679.2	$	906.5	$	(7.4	)	$	2,975.7	$	1,205.9	$	(7.9	)


(a)	Amount reported as Gross Unrealized Gains includes unrealized gains of $801 million and $1.1 billion and unrealized losses of $23 million and $5 million as of March 31, 2020 and December 31, 2019, respectively.

The following table provides the securities activity within the decommissioning and SNF trusts:



	Three Months Ended March 31,
	2020		2019
	(in millions)
Proceeds from Investment Sales	$	612.4	$	111.9
Purchases of Investments	626.0		130.3
Gross Realized Gains on Investment Sales	10.9		12.3
Gross Realized Losses on Investment Sales	17.0		13.8

The base cost of fixed income securities was $1.1 billion and $1.1 billion as of March 31, 2020 and December 31, 2019, respectively. The base cost of equity securities was $616 million and $623 million as of March 31, 2020 and December 31, 2019, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of March 31, 2020 was as follows:



	Fair Value of Fixed
	Income Securities
	(in millions)
Within 1 year	$	238.9
After 1 year through 5 years	404.5
After 5 years through 10 years	282.5
After 10 years	312.6
Total	$	1,238.5

153

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, 2020



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

Other Temporary Investments
Restricted Cash and Other Cash Deposits (a)	$	128.1	$	—	$	—	$	23.8		$	151.9
Fixed Income Securities – Mutual Funds	119.0		—		—		—			119.0
Equity Securities – Mutual Funds (b)	30.5		—		—		—			30.5
Total Other Temporary Investments	277.6		—		—		23.8			301.4

Risk Management Assets
Risk Management Commodity Contracts (c) (d)	3.7		369.8		346.1		(340.5		)	379.1
Cash Flow Hedges:
Commodity Hedges (c)	—		18.7		4.2		(5.2		)	17.7
Interest Rate Hedges	—		0.3		—		—			0.3
Fair Value Hedges	—		57.0		—		—			57.0
Total Risk Management Assets	3.7		445.8		350.3		(345.7		)	454.1

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)	37.0		—		—		9.9			46.9
Fixed Income Securities:
United States Government	—		1,026.1		—		—			1,026.1
Corporate Debt	—		62.7		—		—			62.7
State and Local Government	—		149.7		—		—			149.7
Subtotal Fixed Income Securities	—		1,238.5		—		—			1,238.5
Equity Securities – Domestic (b)	1,393.8		—		—		—			1,393.8
Total Spent Nuclear Fuel and Decommissioning Trusts	1,430.8		1,238.5		—		9.9			2,679.2

Total Assets	$	1,712.1	$	1,684.3	$	350.3	$	(312.0	)	$	3,434.7

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (d)	$	4.9	$	410.1	$	267.9	$	(416.3	)	$	266.6
Cash Flow Hedges:
Commodity Hedges (c)	—		142.1		39.9		(5.2		)	176.8
Interest Rate Hedges	—		5.3		—		—			5.3
Total Risk Management Liabilities	$	4.9	$	557.5	$	307.8	$	(421.5	)	$	448.7

154

AEP

Assets and Liabilities Measured at Fair Value on a Recurring Basis

December 31, 2019



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

Other Temporary Investments
Restricted Cash and Other Cash Deposits (a)	$	197.6	$	—	$	—	$	17.1		$	214.7
Fixed Income Securities – Mutual Funds	123.3		—		—		—			123.3
Equity Securities – Mutual Funds (b)	50.5		—		—		—			50.5
Total Other Temporary Investments	371.4		—		—		17.1			388.5

Risk Management Assets
Risk Management Commodity Contracts (c) (f)	4.0		440.1		369.2		(404.5		)	408.8
Cash Flow Hedges:
Commodity Hedges (c)	—		15.0		3.2		(6.7		)	11.5
Interest Rate Hedges	—		4.6		—		—			4.6
Fair Value Hedges	—		14.5		—		—			14.5
Total Risk Management Assets	4.0		474.2		372.4		(411.2		)	439.4

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)	6.7		—		—		8.6			15.3
Fixed Income Securities:
United States Government	—		1,112.5		—		—			1,112.5
Corporate Debt	—		72.4		—		—			72.4
State and Local Government	—		7.6		—		—			7.6
Subtotal Fixed Income Securities	—		1,192.5		—		—			1,192.5
Equity Securities – Domestic (b)	1,767.9		—		—		—			1,767.9
Total Spent Nuclear Fuel and Decommissioning Trusts	1,774.6		1,192.5		—		8.6			2,975.7

Total Assets	$	2,150.0	$	1,666.7	$	372.4	$	(385.5	)	$	3,803.6

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (f)	$	3.8	$	450.0	$	224.0	$	(438.8	)	$	239.0
Cash Flow Hedges:
Commodity Hedges (c)	—		105.3		38.5		(6.7		)	137.1
Total Risk Management Liabilities	$	3.8	$	555.3	$	262.5	$	(445.5	)	$	376.1

155

AEP Texas

Assets and Liabilities Measured at Fair Value on a Recurring Basis

March 31, 2020



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

Restricted Cash for Securitized Funding	$	100.1	$	—	$	—	$	—		$	100.1

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	1.2	$	—	$	(1.2	)	$	—

December 31, 2019



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

Restricted Cash for Securitized Funding	$	154.7	$	—	$	—	$	—	$	154.7

APCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

March 31, 2020



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

Restricted Cash for Securitized Funding	$	15.7	$	—	$	—	$	—		$	15.7

Risk Management Assets
Risk Management Commodity Contracts (c) (g)	—		55.0		17.1		(54.2		)	17.9
Cash Flow Hedges:
Interest Rate Hedges	—		0.3		—		—			0.3
Total Risk Management Assets	—		55.3		17.1		(54.2		)	18.2

Total Assets	$	15.7	$	55.3	$	17.1	$	(54.2	)	$	33.9

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	58.8	$	10.5	$	(59.5	)	$	9.8
Cash Flow Hedges:
Interest Rate Hedges	—		5.3		—		—			5.3
Total Risk Management Liabilities	$	—	$	64.1	$	10.5	$	(59.5	)	$	15.1

December 31, 2019



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

Restricted Cash for Securitized Funding	$	23.5	$	—	$	—	$	—		$	23.5

Risk Management Assets
Risk Management Commodity Contracts (c) (g)	—		84.6		40.5		(85.6		)	39.5

Total Assets	$	23.5	$	84.6	$	40.5	$	(85.6	)	$	63.0

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	84.0	$	2.8	$	(84.9	)	$	1.9

156

I&M

Assets and Liabilities Measured at Fair Value on a Recurring Basis

March 31, 2020



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

Risk Management Assets
Risk Management Commodity Contracts (c) (g)	$	—	$	38.1	$	4.9	$	(36.2	)	$	6.8

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)	37.0		—		—		9.9			46.9
Fixed Income Securities:
United States Government	—		1,026.1		—		—			1,026.1
Corporate Debt	—		62.7		—		—			62.7
State and Local Government	—		149.7		—		—			149.7
Subtotal Fixed Income Securities	—		1,238.5		—		—			1,238.5
Equity Securities - Domestic (b)	1,393.8		—		—		—			1,393.8
Total Spent Nuclear Fuel and Decommissioning Trusts	1,430.8		1,238.5		—		9.9			2,679.2

Total Assets	$	1,430.8	$	1,276.6	$	4.9	$	(26.3	)	$	2,686.0

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	36.2	$	2.8	$	(37.2	)	$	1.8

December 31, 2019



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

Risk Management Assets
Risk Management Commodity Contracts (c) (g)	$	—	$	59.5	$	8.0	$	(57.6	)	$	9.9

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)	6.7		—		—		8.6			15.3
Fixed Income Securities:
United States Government	—		1,112.5		—		—			1,112.5
Corporate Debt	—		72.4		—		—			72.4
State and Local Government	—		7.6		—		—			7.6
Subtotal Fixed Income Securities	—		1,192.5		—		—			1,192.5
Equity Securities - Domestic (b)	1,767.9		—		—		—			1,767.9
Total Spent Nuclear Fuel and Decommissioning Trusts	1,774.6		1,192.5		—		8.6			2,975.7

Total Assets	$	1,774.6	$	1,252.0	$	8.0	$	(49.0	)	$	2,985.6

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	53.4	$	2.2	$	(55.1	)	$	0.5

157

OPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

March 31, 2020



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

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	0.9	$	120.9	$	(0.9	)	$	120.9

December 31, 2019



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

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	—	$	103.6	$	—	$	103.6

PSO

Assets and Liabilities Measured at Fair Value on a Recurring Basis

March 31, 2020



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

Risk Management Assets
Risk Management Commodity Contracts (c) (g)	$	—	$	—	$	6.7	$	(0.3	)	$	6.4

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	0.5	$	0.4	$	(0.8	)	$	0.1

December 31, 2019



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

Risk Management Assets
Risk Management Commodity Contracts (c) (g)	$	—	$	—	$	16.3	$	(0.5	)	$	15.8

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	—	$	0.5	$	(0.5	)	$	—

158

SWEPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

March 31, 2020



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

Risk Management Assets
Risk Management Commodity Contracts (c) (g)	$	—	$	—	$	2.7	$	(0.1	)	$	2.6

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	0.6	$	5.2	$	(0.7	)	$	5.1

December 31, 2019



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

Risk Management Assets
Risk Management Commodity Contracts (c) (g)	$	—	$	—	$	6.5	$	(0.1	)	$	6.4

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	—	$	5.1	$	(0.1	)	$	5.0


(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, 2020 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(1) million in periods 2021-2023; Level 2 matures $(30) million in 2020, $(9) million in periods 2021-2023 and $(1) million in periods 2024-2025; Level 3 matures $37 million in 2020, $36 million in periods 2021-2023, $25 million in periods 2024-2025 and $(20) million in periods 2026-2032. 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, 2019 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(7) million in 2020 and $(3) million in periods 2021-2023; Level 3 matures $96 million in 2020, $36 million in periods 2021-2023, $25 million in periods 2024-2025 and $(12) million in periods 2026-2032. Risk management commodity contracts are substantially comprised of power contracts.


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

159

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, 2020	AEP			APCo			I&M			OPCo			PSO			SWEPCo
	(in millions)
Balance as of December 31, 2019	$	109.9		$	37.7		$	5.8		$	(103.6	)	$	15.8		$	1.4
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)	0.9			(9.2		)	0.2			(0.3		)	8.0			1.9
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)	10.9			—			—			—			—			—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)	(4.1		)	—			—			—			—			—
Settlements	(59.2		)	(21.9		)	(4.0		)	2.5			(17.7		)	(5.3		)
Transfers into Level 3 (d) (e)	(0.5		)	—			—			—			—			—
Transfers out of Level 3 (e)	5.3			0.7			0.4			—			—			—
Changes in Fair Value Allocated to Regulated Jurisdictions (f)	(20.7		)	(0.7		)	(0.3		)	(19.5		)	0.2			(0.5		)
Balance as of March 31, 2020	$	42.5		$	6.6		$	2.1		$	(120.9	)	$	6.3		$	(2.5	)

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 (c)	(15.8		)	—			—			—			—			—
Settlements	(54.5		)	(17.8		)	(5.1		)	1.8			(13.0		)	(7.3		)
Transfers into Level 3 (d) (e)	0.1			—			—			—			—			—
Transfers out of Level 3 (e)	(1.2		)	(0.7		)	(0.4		)	—			—			—
Changes in Fair Value Allocated to Regulated Jurisdictions (f)	(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		$	—


(a)	Included in revenues on the statements of income.


(b)	Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.


(c)	Included in cash flow hedges on the statements of comprehensive income.


(d)	Represents existing assets or liabilities that were previously categorized as Level 2.


(e)	Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.


(f)	Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities or accounts payable.

160

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

AEP

Significant Unobservable Inputs

March 31, 2020



						Significant	Input/Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input	Low			High		Average (c)
	(in millions)
Energy Contracts	$	321.2	$	284.6	Discounted Cash Flow	Forward Market Price (a)	$	(0.05	)	$	135.24	$	29.17
Natural Gas Contracts	—		5.1		Discounted Cash Flow	Forward Market Price (b)	1.37			2.51		2.13
FTRs	29.1		18.1		Discounted Cash Flow	Forward Market Price (a)	(10.12		)	4.17		(0.31		)
Total	$	350.3	$	307.8

December 31, 2019



						Significant	Input/Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input	Low			High		Average (c)
	(in millions)
Energy Contracts	$	296.7	$	249.3	Discounted Cash Flow	Forward Market Price (a)	$	(0.05	)	$	177.30	$	31.31
Natural Gas Contracts	—		4.9		Discounted Cash Flow	Forward Market Price (b)	1.89			2.51		2.19
FTRs	75.7		8.3		Discounted Cash Flow	Forward Market Price (a)	(8.52		)	9.34		0.42
Total	$	372.4	$	262.5

161

APCo

Significant Unobservable Inputs

March 31, 2020



						Significant	Input/Range
	Fair Value				Valuation	Unobservable					Weighted
	Assets		Liabilities		Technique	Input (a)	Low		High		Average (c)
	(in millions)
Energy Contracts	$	5.3	$	2.2	Discounted Cash Flow	Forward Market Price	$	9.95	$	42.15	$	21.81
FTRs	11.8		8.3		Discounted Cash Flow	Forward Market Price	—		3.44		0.42
Total	$	17.1	$	10.5

December 31, 2019



						Significant	Input/Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input (a)	Low			High		Average (c)
	(in millions)
Energy Contracts	$	5.7	$	2.6	Discounted Cash Flow	Forward Market Price	$	12.70		$	41.20	$	25.92
FTRs	34.8		0.2		Discounted Cash Flow	Forward Market Price	(0.14		)	7.08		1.70
Total	$	40.5	$	2.8

I&M

Significant Unobservable Inputs

March 31, 2020



						Significant	Input/Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input (a)	Low			High		Average (c)
	(in millions)
Energy Contracts	$	3.2	$	1.3	Discounted Cash Flow	Forward Market Price	$	9.95		$	42.15	$	21.81
FTRs	1.7		1.5		Discounted Cash Flow	Forward Market Price	(0.51		)	2.77		0.12
Total	$	4.9	$	2.8

December 31, 2019



						Significant	Input/Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input (a)	Low			High		Average (c)
	(in millions)
Energy Contracts	$	3.4	$	1.5	Discounted Cash Flow	Forward Market Price	$	12.70		$	41.20	$	25.92
FTRs	4.6		0.7		Discounted Cash Flow	Forward Market Price	(0.75		)	4.07		0.74
Total	$	8.0	$	2.2

162

OPCo

Significant Unobservable Inputs

March 31, 2020

Significant

Input/Range

Fair Value

Valuation

Unobservable

Weighted

Assets

Liabilities

Technique

Input (a)

Low

High

Average (c)

(in millions)

Energy Contracts

—

120.9

Discounted Cash Flow

Forward Market Price

12.57

42.71

26.31

December 31, 2019

Significant

Input/Range

Fair Value

Valuation

Unobservable

Weighted

Assets

Liabilities

Technique

Input (a)

Low

High

Average (c)

(in millions)

Energy Contracts

—

103.6

Discounted Cash Flow

Forward Market Price

29.23

61.43

42.46

PSO

Significant Unobservable Inputs

March 31, 2020



						Significant	Input/Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input (a)	Low			High		Average (c)
	(in millions)
FTRs	$	6.7	$	0.4	Discounted Cash Flow	Forward Market Price	$	(7.07	)	$	0.95	$	(2.38	)

December 31, 2019



						Significant	Input/Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input (a)	Low			High		Average (c)
	(in millions)
FTRs	$	16.3	$	0.5	Discounted Cash Flow	Forward Market Price	$	(8.52	)	$	0.85	$	(2.31	)

163

SWEPCo

Significant Unobservable Inputs

March 31, 2020



						Significant	Input/Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input	Low			High		Average (c)
	(in millions)
Natural Gas Contracts	$	—	$	5.1	Discounted Cash Flow	Forward Market Price (b)	$	1.37		$	2.51	$	2.13
FTRs	2.7		0.1		Discounted Cash Flow	Forward Market Price (a)	(7.07		)	0.95		(2.38		)
Total	$	2.7	$	5.2

December 31, 2019



						Significant	Input/Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input	Low			High		Average (c)
	(in millions)
Natural Gas Contracts	$	—	$	4.9	Discounted Cash Flow	Forward Market Price (b)	$	1.89		$	2.51	$	2.18
FTRs	6.5		0.2		Discounted Cash Flow	Forward Market Price (a)	(8.52		)	0.85		(2.31		)
Total	$	6.5	$	5.1


(a)	Represents market prices in dollars per MWh.


(b)	Represents market prices in dollars per MMBtu.


(c)	The weighted average is the product of the forward market price of the underlying commodity and volume weighted by term.

The following table provides the measurement uncertainty of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts, Natural Gas Contracts and FTRs for the Registrants as of March 31, 2020 and December 31, 2019:

Uncertainty 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)

164

11. INCOME TAXES

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

Federal Legislation

In March 2020, the "Coronavirus Aid, Relief, and Economic Security Act" (CARES Act) was signed into law. The CARES Act includes several significant changes to the Internal Revenue Code that will have an impact on the Registrants. The CARES Act includes certain tax relief provisions applicable to the Registrants including a) the immediate refund of the corporate Alternative Minimum Tax credit, b) the ability to carryback net operating losses five years for tax years 2018 through 2020 and c) delayed payment of employer payroll taxes. As of March 31, 2020, AEP, OPCo and APCo have a $20 million, $9 million and $7 million AMT credit refund recorded, respectively, in anticipation of a refund from the U.S. Treasury. AEP was most recently a taxpayer in 2014 and management is currently evaluating the ability to recover cash taxes paid in 2014 under the 5-year net operating loss carryback provision.

Effective Tax Rates (ETR)

The Registrants’ interim ETR reflect the estimated annual ETR for 2020 and 2019, adjusted for tax expense associated with certain discrete items. The interim ETR differ from the federal statutory tax rate of 21% primarily due to 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 tables:



	Three Months Ended March 31, 2020
	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
U.S. Federal Statutory Rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
Increase (decrease) due to:
State Income Tax, net of Federal benefit	2.5	%	1.5	%	2.9	%	3.0	%	3.2	%	0.7	%	4.6	%	2.7	%
Tax Reform Excess ADIT Reversal	(9.4	)%	(6.2	)%	0.4	%	(13.0	)%	(19.6	)%	(10.2	)%	(23.1	)%	(94.7	)%
Production and Investment Tax Credits	(4.3	)%	(0.4	)%	—	%	—	%	(1.9	)%	—	%	(1.3	)%	(0.5	)%
Flow Through	0.5	%	0.1	%	0.5	%	1.5	%	0.2	%	1.0	%	0.6	%	(1.0	)%
AFUDC Equity	(1.4	)%	(2.6	)%	(2.6	)%	(1.0	)%	(1.1	)%	(1.0	)%	(0.7	)%	(0.4	)%
Parent Company Loss Benefit	—	%	(0.2	)%	(0.9	)%	(3.3	)%	(3.9	)%	(0.1	)%	(2.2	)%	(2.4	)%
Discrete Tax Adjustments	—	%	—	%	—	%	—	%	2.7	%	—	%	—	%	—	%
Other	(0.4	)%	0.3	%	—	%	0.1	%	(0.2	)%	—	%	0.1	%	7.2	%
Effective Income Tax Rate	8.5	%	13.5	%	21.3	%	8.3	%	0.4	%	11.4	%	(1.0	)%	(68.1	)%

165



	Three Months Ended March 31, 2019
	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
U.S. Federal Statutory Rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
Increase (decrease) due to:
State Income Tax, net of Federal benefit	2.1	%	1.5	%	2.9	%	3.4	%	2.0	%	0.9	%	4.6	%	0.2	%
Tax Reform Excess ADIT Reversal	(13.6	)%	(7.6	)%	0.4	%	(42.2	)%	(17.4	)%	(7.6	)%	(21.9	)%	(17.0	)%
Production and Investment Tax Credits	(2.2	)%	(1.0	)%	—	%	—	%	(2.0	)%	—	%	(1.7	)%	(0.8	)%
Flow Through	(0.2	)%	0.3	%	0.2	%	(0.9	)%	(2.4	)%	0.7	%	0.6	%	(0.9	)%
AFUDC Equity	(1.4	)%	(1.6	)%	(2.5	)%	(1.0	)%	(1.9	)%	(0.7	)%	(0.4	)%	(1.1	)%
Parent Company Loss	—	%	(2.3	)%	(1.0	)%	(2.4	)%	(1.8	)%	(1.1	)%	(1.8	)%	(0.5	)%
Discrete Tax Adjustments	1.7	%	—	%	—	%	0.4	%	—	%	—	%	—	%	—	%
Other	(0.2	)%	0.1	%	(0.1	)%	(0.3	)%	(0.3	)%	0.2	%	0.2	%	1.5	%
Effective Income Tax Rate	7.2	%	10.4	%	20.9	%	(22.0	)%	(2.8	)%	13.4	%	0.6	%	2.4	%

Federal and State Income Tax Audit Status

AEP and subsidiaries are no longer subject to U.S. federal examination by the IRS for all years through 2015. During the third quarter of 2019, AEP and subsidiaries elected to amend the 2014 and 2015 federal returns and as such the IRS may examine only the amended items on the 2014 and 2015 federal returns.

166

12. 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, 2020		December 31, 2019
	(in millions)
Senior Unsecured Notes	$	22,515.8	$	21,180.7
Pollution Control Bonds	1,999.2		1,998.8
Notes Payable	209.4		234.3
Securitization Bonds	899.1		1,025.1
Spent Nuclear Fuel Obligation (a)	280.9		279.8
Junior Subordinated Notes (b)	788.6		787.8
Other Long-term Debt	1,199.7		1,219.0
Total Long-term Debt Outstanding	27,892.7		26,725.5
Long-term Debt Due Within One Year	2,109.7		1,598.7
Long-term Debt	$	25,783.0	$	25,126.8

(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 $324 million and $323 million as of March 31, 2020 and December 31, 2019, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.


(b)	See “Equity Units” section below for additional information.

Long-term Debt Activity

Long-term debt and other securities issued, retired and principal payments made during the first three months of 2020 are shown in the following tables:



		Principal		Interest
Company	Type of Debt	Amount (a)		Rate	Due Date
Issuances:		(in millions)		(%)
AEP	Senior Unsecured Notes	$	400.0	2.30	2030
AEP	Senior Unsecured Notes	400.0		3.25	2050
OPCo	Senior Unsecured Notes	350.0		2.60	2030

Non-Registrant:
KPCo	Other Long-term Debt	125.0		Variable	2022
Transource Energy	Other Long-term Debt	5.0		Variable	2023
Transource Energy	Senior Unsecured Notes	150.0		2.75	2050
Total Issuances		$	1,430.0


(a)	Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.

167



		Principal		Interest
Company	Type of Debt	Amount Paid		Rate	Due Date
Retirements and Principal Payments:		(in millions)		(%)
AEP Texas	Securitization Bonds	$	111.0	5.31	2020
AEP Texas	Securitization Bonds	3.3		2.06	2025
APCo	Securitization Bonds	12.2		2.01	2023
I&M	Notes Payable	0.7		Variable	2020
I&M	Notes Payable	1.5		Variable	2021
I&M	Notes Payable	5.1		Variable	2022
I&M	Notes Payable	3.8		Variable	2022
I&M	Notes Payable	6.2		Variable	2023
I&M	Notes Payable	6.0		Variable	2024
I&M	Other Long-term Debt	0.4		6.00	2025
PSO	Other Long-term Debt	0.1		3.00	2027
SWEPCo	Notes Payable	1.6		4.58	2032

Non-Registrant:
Transource Energy	Other Long-term Debt	148.6		Variable	2023
Total Retirements and Principal Payments		$	300.5

Long-term Debt Subsequent Events

In April 2020, AEPTCo issued $525 million of 3.65% Senior Unsecured Notes due in 2050.

In April and May 2020, I&M retired $8 million and $1 million, respectively, of Notes Payable related to DCC Fuel.

In April 2020, Transource Energy issued $1 million of variable rate Other Long-term Debt due in 2023.

Equity Units (Applies to AEP)

In March 2019, AEP issued 16.1 million Equity Units initially in the form of corporate units, at a stated amount of $50 per unit, for a total stated amount of $805 million. Net proceeds from the issuance were approximately $785 million. The proceeds were used to support AEP’s overall capital expenditure plans including the acquisition of Sempra Renewables LLC.

Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 3.40% Junior Subordinated Notes (notes) due in 2024 and a forward equity purchase contract which settles after three years in 2022. The notes are expected to be remarketed in 2022, at which time the interest rate will reset at the then current market rate. Investors may choose to remarket their notes to receive the remarketing proceeds and use those funds to settle the forward equity purchase contract, or accept the remarketed debt and use other funds for the equity purchase. If the remarketing is unsuccessful, investors have the right to put their notes to AEP at a price equal to the principal. The Equity Units carry an annual distribution rate of 6.125%, which is comprised of a quarterly coupon rate of interest of 3.40% and a quarterly forward equity purchase contract payment of 2.725%.

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


•	If the AEP common stock market price is equal to or greater than $99.58: 0.5021 shares per contract.


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


•	If the AEP common stock market price is less than or equal to $82.98: 0.6026 shares per contract.

168

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

At the time of issuance, the $805 million of notes were recorded within Long-term Debt on the balance sheets. The present value of the purchase contract payments of $62 million were recorded in Deferred Credits and Other Noncurrent 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 3.3% of consolidated tangible net assets as of March 31, 2020. 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. The Federal Power Act also creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M.

Certain AEP subsidiaries have credit agreements that contain 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.

169

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 its agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of March 31, 2020 and December 31, 2019 are included in Advances to Affiliates and Advances from Affiliates, respectively, on the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ activity and corresponding authorized borrowing limits for the three months ended March 31, 2020 are described in the following table:



	Maximum				Average				Net
	Borrowings		Maximum		Borrowings		Average		Borrowings from			Authorized
	from the		Loans to the		from the		Loans to the		the Utility Money			Short-term
	Utility		Utility		Utility		Utility		Pool as of			Borrowing
Company	Money Pool		Money Pool		Money Pool		Money Pool		March 31, 2020			Limit
	(in millions)
AEP Texas	$	63.9	$	199.7	$	39.0	$	90.3	$	(63.9	)	$	500.0
AEPTCo	358.4		69.8		257.6		32.6		(261.0		)	820.0		(a)
APCo	373.5		22.2		303.1		22.0		(333.5		)	500.0
I&M	147.5		13.3		108.4		13.3		(90.4		)	500.0
OPCo	353.9		32.8		191.5		25.2		(29.4		)	500.0
PSO	70.9		57.1		25.3		28.4		(70.9		)	300.0
SWEPCo	152.8		—		105.5		—		(148.1		)	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, 2020 and December 31, 2019 are included in Advances to Affiliates on the subsidiaries’ balance sheets. The Nonutility Money Pool participants’ activity for the three months ended March 31, 2020 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, 2020
	(in millions)
AEP Texas		$	7.5	$	7.2	$	7.1
SWEPCo		2.1		2.1		2.1

AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of outstanding loans to and borrowings from AEP as of March 31, 2020 and December 31, 2019 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct borrowing and lending activity with AEP and corresponding authorized borrowing limit for the three months ended March 31, 2020 are described in the following table:

Maximum

Average

Borrowings from

Loans to

Authorized

Borrowings

Loans

Borrowings

Loans

AEP as of

Short-term

from AEP

to AEP

from AEP

to AEP

March 31, 2020

Borrowing Limit

(in millions)

1.4

190.3

1.4

125.1

1.3

93.3

50.0

(a)


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

170

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,
	2020		2019
Maximum Interest Rate	2.24	%	3.02	%
Minimum Interest Rate	1.76	%	2.73	%

The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized for all Registrant Subsidiaries in the following table:



	Average Interest Rate for Funds				Average Interest Rate for Funds
	Borrowed from the Utility Money Pool				Loaned to the Utility Money Pool
	for Three Months Ended March 31,				for Three Months Ended March 31,
Company	2020		2019		2020		2019
AEP Texas	2.05	%	2.86	%	1.97	%	—	%
AEPTCo	1.95	%	2.83	%	1.91	%	2.90	%
APCo	1.95	%	2.92	%	1.94	%	2.79	%
I&M	1.95	%	2.80	%	1.94	%	2.87	%
OPCo	1.90	%	2.85	%	2.06	%	—	%
PSO	2.00	%	2.89	%	1.95	%	—	%
SWEPCo	1.95	%	2.81	%	—	%	2.97	%

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, 2020

Three Months Ended March 31, 2019

Maximum

Minimum

Average

Maximum

Minimum

Average

Interest Rate

for Funds

Loaned to

the Nonutility

Company

Money Pool

AEP Texas

2.24

1.76

1.94

3.02

2.73

2.87

SWEPCo

2.24

1.76

1.94

3.02

2.73

2.87

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
2020	2.24	%	1.76	%	2.24	%	1.76	%	1.94	%	1.94	%
2019	3.02	%	2.73	%	3.02	%	2.73	%	2.87	%	2.86	%

171

Short-term Debt (Applies to AEP and SWEPCo)

Outstanding short-term debt was as follows:



		March 31, 2020				December 31, 2019
		Outstanding		Interest		Outstanding		Interest
Company	Type of Debt	Amount		Rate (a)		Amount		Rate (a)
		(dollars in millions)
AEP	Securitized Debt for Receivables (b)	$	724.0	1.75	%	$	710.0	2.42	%
AEP	Commercial Paper	2,709.6		2.24	%	2,110.0		2.10	%
AEP	364-Day Term Loan	1,000.0		1.53	%	—		—	%
SWEPCo	Notes Payable	30.5		2.98	%	18.3		3.29	%
	Total Short-term Debt	$	4,464.1			$	2,838.3


(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 Receivables – 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 expires in July 2021. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections. Accounts receivable information for AEP Credit was as follows:



	Three Months Ended March 31,
	2020			2019
	(dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable	1.75		%	2.71		%
Net Uncollectible Accounts Receivable Written-Off	$	4.2		$	6.4



	March 31, 2020		December 31, 2019
	(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts	$	850.7	$	841.8
Short-term – Securitized Debt of Receivables	724.0		710.0
Delinquent Securitized Accounts Receivable	43.4		39.6
Bad Debt Reserves Related to Securitization	34.5		32.1
Unbilled Receivables Related to Securitization	219.8		266.8

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

172

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

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

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreements were:



Company	March 31, 2020		December 31, 2019
	(in millions)
APCo	$	121.8	$	120.9
I&M	155.2		141.8
OPCo	338.3		330.3
PSO	93.3		101.1
SWEPCo	121.2		125.2

The fees paid to AEP Credit for customer accounts receivable sold were:



	Three Months Ended March 31,
Company	2020		2019
	(in millions)
APCo	$	1.7	$	2.2
I&M	2.8		2.8
OPCo	4.8		7.8
PSO	1.3		2.1
SWEPCo	2.1		2.6

The proceeds on the sale of receivables to AEP Credit were:



	Three Months Ended March 31,
Company	2020		2019
	(in millions)
APCo	$	352.6	$	374.4
I&M	471.4		478.6
OPCo	570.3		636.8
PSO	294.9		324.5
SWEPCo	365.6		371.9

173

13. 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, 2020
	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	$	915.1	$	521.3	$	—		$	—	$	—		$	—		$	1,436.4
Commercial Revenues	489.4		276.9		—			—		—			—			766.3
Industrial Revenues	518.2		97.8		—			—		—			(0.2		)	615.8
Other Retail Revenues	39.9		11.8		—			—		—			—			51.7
Total Retail Revenues	1,962.6		907.8		—			—		—			(0.2		)	2,870.2

Wholesale and Competitive Retail Revenues:
Generation Revenues	140.4		—		—			44.1		—			—			184.5
Transmission Revenues (a)	79.9		114.1		309.8			—		—			(263.0		)	240.8
Renewable Generation Revenues (c)	—		—		—			17.2		—			(0.6		)	16.6
Retail, Trading and Marketing Revenues (b)	—		—		—			358.7		(6.0		)	(29.4		)	323.3
Total Wholesale and Competitive Retail Revenues	220.3		114.1		309.8			420.0		(6.0		)	(293.0		)	765.2

Other Revenues from Contracts with Customers (c)	43.6		36.4		3.7			0.3		28.1			(40.6		)	71.5

Total Revenues from Contracts with Customers	2,226.5		1,058.3		313.5			420.3		22.1			(333.8		)	3,706.9

Other Revenues:
Alternative Revenues (c)	0.2		19.3		(3.3		)	—		—			4.5			20.7
Other Revenues (c)	—		29.3		—			18.3		(2.2		)	(25.5		)	19.9
Total Other Revenues	0.2		48.6		(3.3		)	18.3		(2.2		)	(21.0		)	40.6

Total Revenues	$	2,226.7	$	1,106.9	$	310.2		$	438.6	$	19.9		$	(354.8	)	$	3,747.5


(a)	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $239 million. The remaining affiliated amounts were immaterial.


(b)	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $35 million. The remaining affiliated amounts were immaterial.


(c)	Amounts include affiliated and nonaffiliated revenues.

174



	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	224.7			—		—			108.8		—		(38.8		)	294.7
Transmission Revenues (a)	73.5			99.6		255.1			—		—		(219.4		)	208.8
Renewable Generation Revenues (c)	—			—		—			7.8		—		—			7.8
Retail, Trading and Marketing Revenues (b)	—			—		—			353.7		—		—			353.7
Total Wholesale and Competitive Retail Revenues	298.2			99.6		255.1			470.3		—		(258.2		)	865.0

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		(292.5		)	4,045.9

Other Revenues:
Alternative Revenues (c)	(3.4		)	5.0		(1.8		)	—		—		—			(0.2		)
Other Revenues (c)	—			39.4		—			9.2		2.2		(39.7		)	11.1
Total Other Revenues	(3.4		)	44.4		(1.8		)	9.2		2.2		(39.7		)	10.9

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 AEP Transmission Holdco was $198 million. The remaining affiliated amounts were immaterial.


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


(c)	Amounts include affiliated and nonaffiliated revenues.

175



	Three Months Ended March 31, 2020
	AEP Texas			AEPTCo			APCo			I&M		OPCo		PSO		SWEPCo
	(in millions)
Retail Revenues:
Residential Revenues	$	132.9		$	—		$	357.5		$	201.3	$	388.4	$	128.5	$	131.6
Commercial Revenues	112.8			—			132.3			122.2		164.0		76.1		105.6
Industrial Revenues	35.2			—			141.1			137.8		62.7		61.3		79.8
Other Retail Revenues	8.4			—			17.9			1.8		3.4		16.6		2.0
Total Retail Revenues	289.3			—			648.8			463.1		618.5		282.5		319.0

Wholesale Revenues:
Generation Revenues (a)	—			—			54.1			78.4		—		1.9		34.1
Transmission Revenues (b)	96.9			298.2			30.4			7.4		17.1		7.8		25.4
Total Wholesale Revenues	96.9			298.2			84.5			85.8		17.1		9.7		59.5

Other Revenues from Contracts with Customers (c)	7.9			3.4			17.2			21.0		28.6		4.7		5.8

Total Revenues from Contracts with Customers	394.1			301.6			750.5			569.9		664.2		296.9		384.3

Other Revenues:
Alternative Revenues (d)	(0.7		)	(6.0		)	(1.1		)	0.4		20.0		0.4		1.6
Other Revenues (d)	30.2			—			—			—		6.1		—		—
Total Other Revenues	29.5			(6.0		)	(1.1		)	0.4		26.1		0.4		1.6

Total Revenues	$	423.6		$	295.6		$	749.4		$	570.3	$	690.3	$	297.3	$	385.9


(a)	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $33 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 $235 million. The remaining affiliated amounts were immaterial.


(c)	Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $16 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.

176



	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.

177

Fixed Performance Obligations

The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of March 31, 2020. Fixed performance obligations primarily include wholesale transmission services, electricity sales for fixed amounts of energy and stand ready services into PJM’s RPM market. The Registrant Subsidiaries amounts shown in the table below include affiliated and nonaffiliated revenues.



Company	2020		2021-2022		2023-2024		After 2024		Total
	(in millions)
AEP	$	732.4	$	171.1	$	160.6	$	223.4	$	1,287.5
AEP Texas	290.3		—		—		—		290.3
AEPTCo	821.5		—		—		—		821.5
APCo	118.6		32.3		24.4		11.6		186.9
I&M	22.2		8.8		8.8		4.4		44.2
OPCo	43.2		—		—		—		43.2
PSO	10.8		—		—		—		10.8
SWEPCo	29.6		—		—		—		29.6

Contract Assets and Liabilities

Contract assets are recognized when the Registrants have a right to consideration that is conditional upon the occurrence of an event other than the passage of time, such as future performance under a contract. The Registrants did not have material contract assets as of March 31, 2020 and December 31, 2019.

When the Registrants receive consideration, or such consideration is unconditionally due from a customer prior to transferring goods or services to the customer under the terms of a sales contract, they recognize a contract liability on the balance sheet in the amount of that consideration. Revenue for such consideration is subsequently recognized in the period or periods in which the remaining performance obligations in the contract are satisfied. The Registrants’ contract liabilities typically arise from services provided under joint use agreements for utility poles. The Registrants did not have material contract liabilities as of March 31, 2020 and December 31, 2019.

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, 2020 and December 31, 2019. See “Securitized Accounts Receivable - AEP Credit” section of Note 12 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, 2020		December 31, 2019
	(in millions)
AEPTCo	$	80.6	$	65.9
APCo	56.3		47.3
I&M	37.4		37.1
OPCo	39.3		33.9
PSO	6.2		9.7
SWEPCo	11.0		17.6

178

CONTROLS AND PROCEDURES

During the first quarter of 2020, management, including the principal executive officer and principal financial officer of each of the Registrants, evaluated the Registrants’ disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. As of March 31, 2020, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives.

There was no change in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the first quarter of 2020 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

179

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

The AEP 2019 Annual Report on Form 10-K includes a detailed discussion of risk factors. As of March 31, 2020, the risk factors appearing in AEP’s 2019 Annual Report is supplemented and updated as follows:

AEP’s Financial Condition and Results of Operations could be Adversely Affected by the Recent Coronavirus Outbreak

AEP is responding to the global outbreak (pandemic) of the 2019 novel coronavirus (COVID-19) by taking steps to mitigate the potential risks posed by its spread. AEP provides a critical service to its customers which means that it must keep its employees who operate its businesses safe and minimize unnecessary risk of exposure to the virus. AEP has updated and implemented a company-wide pandemic plan to address specific aspects of the coronavirus pandemic. This plan guides AEP’s emergency response, business continuity, and the precautionary measures that AEP is taking on behalf its employees and the public. AEP has taken extra precautions for its employees who work in the field and for employees who continue to work in its facilities, and AEP has implemented work from home policies where appropriate. AEP has informed both retail customers and state regulators that disconnections for non-payment will be temporarily suspended. These uncertain economic conditions may result in the inability of customers to pay for electric service, which could affect the collectability of the Registrants revenues and adversely affect financial results. These conditions might also impact the Registrants’ access to and cost of capital. This is a rapidly evolving situation that could lead to extended disruption of economic activity in AEP’s markets. AEP has instituted measures to ensure its supply chain remains open; however, there could be global shortages that will impact AEP’s maintenance and capital programs that AEP currently cannot anticipate. AEP will continue to monitor developments affecting both its workforce and its customers, and will take additional precautions that are determined to be necessary in order to mitigate the impacts. AEP continues to implement strong physical and cyber security measures to ensure that its systems remain functional in order to both serve its operational needs with a remote workforce and keep them running to ensure uninterrupted service to customers. AEP will continue to review and modify its plans as conditions change. Despite AEP’s efforts to manage these impacts, their ultimate impact also depends on factors beyond AEP’s knowledge or control, including the duration and severity of this outbreak, its impact on economic and market conditions, as well as third-party actions taken to contain its spread and mitigate its public health effects. Therefore, AEP currently cannot estimate the potential impact to its financial position, results of operations and cash flows.

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.

180

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, 2020.

Item 5. Other Information

None

Item 6. Exhibits

The documents designated with an (*) below have previously been filed on behalf of the Registrants shown and are incorporated herein by reference to the documents indicated and made a part hereof.



Exhibit	Description	Previously Filed as Exhibit to:

AEP‡ File No. 1-3525

*4.1	Company Order and Officer’s Certificate, between AEP and The Bank of New York Mellon Trust Company, N.A., as trustee, dated March 5, 2020.	Form 8-K dated March 5, 2020 Exhibit 4(a)

4.3	Credit Agreement among AEP, initial lenders and PNC Bank, National Association.

AEPTCo‡ File No. 333-217143

*4.4	Company Order and Officer’s Certificate, between AEPTCo and The Bank of New York Mellon Trust Company, N.A., as trustee, dated April 1, 2020.	Form 8-K dated April 1, 2020 Exhibit 4(a)

OPCo‡ File No.1-6543

*4.2	Company Order and Officer’s Certificate, between OPCo and The Bank of New York Mellon Trust Company, N.A., as trustee, dated March 17, 2020.	Form 8-K dated March 17, 2020 Exhibit 4(a)

The exhibits designated with an (X) in the table below are being filed on behalf of the Registrants.

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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101.SCH

XBRL Taxonomy Extension Schema

101.CAL

XBRL Taxonomy Extension Calculation Linkbase

101.DEF

XBRL Taxonomy Extension Definition Linkbase

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XBRL Taxonomy Extension Label Linkbase

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104

Cover Page Interactive Data File

Formatted as Inline XBRL and contained in Exhibit 101.

181

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: May 6, 2020

182