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

or

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

For The Transition Period from ____ to ____

Commission	Registrants;						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.

i

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.
NOx	Nitrogen oxide.
NPDES	National Pollutant Discharge Elimination System.
NSR	New Source Review.
OCC	Corporation Commission of the State of Oklahoma.

ii

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.

iv

FORWARD-LOOKING INFORMATION

This report made by the Registrants contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.  Many forward-looking statements appear in “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the 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.

v

• 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.

vi

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.

1

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.

2

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

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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.

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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,

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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.

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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.

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

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claims that AEGCo and I&M failed to exercise prudent utility practices with prejudice, and the court issued a final judgment. The plaintiffs subsequently filed an appeal in the U.S. Court of Appeals for the Sixth Circuit.

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

Thereafter, AEP filed a motion with the U.S. District Court for the Southern District of Ohio in the original NSR litigation, seeking to modify the consent decree. The district court granted the owners’ unopposed motion to stay the lease litigation to afford time for resolution of AEP’s motion to modify the consent decree. The consent decree was modified based on an agreement among the parties in July 2019. 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 NSR Litigation Consent Decree” section below for additional information.

Management will continue to defend against the claims. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management 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

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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.

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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 SO₂ were 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.

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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_x regional haze obligations for electric generating units in Texas. Additionally, the Federal EPA finalized an intrastate SO₂ emissions trading program based on CSAPR allowance allocations. 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.

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

In 2016, the U.S. Supreme Court issued a stay 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.

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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 CO₂ emissions 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

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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

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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.

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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.

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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.

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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.

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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.

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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.

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• 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.

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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.

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

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

	Three Months Ended  March 31,
	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.

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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.

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• 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.

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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

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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.

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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

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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.

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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

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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.

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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

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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.

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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.

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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.

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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).

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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

37

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.

38

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.

39

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.

40

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							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.

41

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.

42

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.

43

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.

44

AEP TEXAS INC.

AND SUBSIDIARIES

45

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.

46

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.

47

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.

48

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.

49

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.

50

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.

51

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.

52

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.

53

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

54

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.

55

• 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.

56

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.

57

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.

58

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.

59

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.

60

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.

61

APPALACHIAN POWER COMPANY

AND SUBSIDIARIES

62

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.

63

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

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 $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.

64

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.

65

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.

66

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.

67

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.

68

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.

69

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.

70

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.

71

INDIANA MICHIGAN POWER COMPANY

AND SUBSIDIARIES

72

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.

73

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

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

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

• 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.

74

• 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.

75

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.

76

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.

77

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.

78

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.

79

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.

80

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.

81

OHIO POWER COMPANY AND SUBSIDIARIES

82

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.

83

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.

84

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.

85

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.

86

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.

87

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.

88

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.

89

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.

90

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.

91

PUBLIC SERVICE COMPANY OF OKLAHOMA

92

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.

93

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.

94

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.

95

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.

96

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.

97

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.

98

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.

99

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.

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

• Retail Margins decreased $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

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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.

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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)

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.

118

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.

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) 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.

	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.

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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.

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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.

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 were as follows:

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)

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 due to the recent passage of the legislation.  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

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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)

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

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

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

Thereafter, AEP filed a motion with the U.S. District Court for the Southern District of Ohio in the original NSR litigation, seeking to modify the consent decree. The district court granted the owners’ unopposed motion to stay the lease litigation to afford time for resolution of AEP’s motion to modify the consent decree. 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.

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.

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

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.

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

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

Vertically Integrated Utilities

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

Transmission and Distribution Utilities

• Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo.

• OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load.

AEP Transmission Holdco

• Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved 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.

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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.

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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

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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

Maximum

Average

Average

Borrowings from

Loans to

Authorized

Borrowings

Loans

Borrowings

Loans

AEP as of

AEP as of

Short-term

from AEP

to AEP

from AEP

to AEP

March 31, 2020

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

Interest Rate

Interest Rate

Interest Rate

Interest Rate

Interest Rate

for Funds

for Funds

for Funds

for Funds

for Funds

for Funds

Loaned to

Loaned to

Loaned to

Loaned to

Loaned to

Loaned to

the Nonutility

the Nonutility

the Nonutility

the Nonutility

the Nonutility

the Nonutility

Company

Money Pool

Money Pool

Money Pool

Money Pool

Money Pool

Money Pool

AEP Texas

2.24

%

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	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	X	X	X	X	X	X	X	X
31(b)	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	X	X	X	X	X	X	X	X
32(a)	Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code	X	X	X	X	X	X	X	X
32(b)	Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code	X	X	X	X	X	X	X	X
95	Mine Safety Disclosures								X
101.INS	XBRL Instance Document	The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCH	XBRL Taxonomy Extension Schema	X	X	X	X	X	X	X	X
101.CAL	XBRL Taxonomy Extension Calculation Linkbase	X	X	X	X	X	X	X	X
101.DEF	XBRL Taxonomy Extension Definition Linkbase	X	X	X	X	X	X	X	X
101.LAB	XBRL Taxonomy Extension Label Linkbase	X	X	X	X	X	X	X	X
101.PRE	XBRL Taxonomy Extension Presentation Linkbase	X	X	X	X	X	X	X	X
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

EX-4.3

Exhibit 4.3

EXECUTION

DEAL CUSIP: 02557NAW2

TERM CUSIP: 02557NAX0

_____________________________________________________________________________________

U.S. $1,000,000,000

CREDIT AGREEMENT

Dated as of March 23, 2020

among

AMERICAN ELECTRIC POWER COMPANY, INC.

as the Borrower

THE LENDERS NAMED HEREIN

as Initial Lenders

and

PNC BANK, NATIONAL ASSOCIATION

as Administrative Agent

______________________________________________________________________________________________________

PNC CAPITAL MARKETS LLC, WELLS FARGO BANK, NATIONAL ASSOCIATION, KEYBANK NATIONAL ASSOCIATION, U.S. BANK NATIONAL ASSOCIATION, SUMITOMO MITSUI BANKING CORPORATION and SUNTRUST ROBINSON HUMPHREY, INC.

as Joint LeadArrangers and Joint Bookrunners

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TABLE OF CONTENTS

			Page
Article I DEFINITIONS AND ACCOUNTING TERMS			5
	Section 1.01. Certain Defined Terms.		5
	Section 1.02. Computation of Time Periods.		22
	Section 1.03. Accounting Terms.		22
	Section 1.04. Other Interpretive Provisions.		22
Article II AMOUNTS AND TERMS OF THE ADVANCES			23
	Section 2.01. The Advances.		23
	Section 2.02. Making the Advances.		23
	Section 2.03. Fees.		24
	Section 2.04. Extension of the Termination Date.		24
	Section 2.05. [Reserved]		25
	Section 2.06. Repayment of Advances.		25
	Section 2.07. Evidence of Indebtedness.		25
	Section 2.08. Interest on Advances.		26
	Section 2.09. Interest Rate Determination.		27
	Section 2.10. Optional Conversion of Advances.		28
	Section 2.11. Optional Prepayments of Advances.		28
	Section 2.12. Increased Costs.		28
	Section 2.13. Illegality.		29
	Section 2.14. Payments and Computations.		30
	Section 2.15. Taxes.		31
	Section 2.16. Sharing of Payments, Etc.		35
	Section 2.17. Mitigation Obligations; Replacement of Lenders.		35
	Section 2.18. Option to Increase Facility.		36
Article III CONDITIONS PRECEDENT			37
	Section 3.01. Conditions Precedent to Effectiveness of this Agreement and Closing Date
		Extension of Credit.	37
	Section 3.02. Conditions Precedent to Each Extension of Credit Following the Closing
		Date.	39
Article IV REPRESENTATIONS AND WARRANTIES			39
	Section 4.01. Representations and Warranties of the Borrower.		39
Article V COVENANTS OF THE BORROWER			42
	Section 5.01. Affirmative Covenants.		42
	Section 5.02. Negative Covenants.		45

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	Section 5.03. Financial Covenant.		47
Article VI EVENTS OF DEFAULT			47
	Section 6.01. Events of Default.		47
Article VII THE ADMINISTRATIVE AGENT			49
	Section 7.01. Authorization and Action.		49
	Section 7.02. Agent’s Reliance, Etc.		49
	Section 7.03. Administrative Agent and its Affiliates.		50
	Section 7.04. Lender Credit Decision.		50
	Section 7.05. Indemnification.		50
	Section 7.06. Successor Agent.		51
Article VIII MISCELLANEOUS			51
	Section 8.01. Amendments, Etc.		51
	Section 8.02. Notices, Etc.		52
	Section 8.03. No Waiver; Remedies.		54
	Section 8.04. Costs and Expenses.		54
	Section 8.05. Right of Set-off.		55
	Section 8.06. Binding Effect.		56
	Section 8.07. Assignments and Participations.		56
	Section 8.08. Confidentiality.		60
	Section 8.09. Governing Law.		61
	Section 8.10. Severability; Survival.		61
	Section 8.11. Execution in Counterparts.		61
	Section 8.12. Jurisdiction, Etc.		61
	Section 8.13. Waiver of Jury Trial.		62
	Section 8.14. USA Patriot Act.		62
	Section 8.15. No Fiduciary Duty.		62
	Section 8.16. Defaulting Lenders.		63
	Section 8.17. Acknowledgement and Consent to Bail-In of EEA Financial
		Institutions.	64
	Section 8.18. Certain ERISA Matters.		65
	Section 8.19. Effect of Benchmark Transition Event		66

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EXHIBITS AND SCHEDULES
EXHIBIT A	---------------	Form of Notice of Borrowing
EXHIBIT B	---------------	Form of Assignment and Assumption
EXHIBIT C	---------------	Form of Opinion of Counsel for the Borrower
EXHIBIT D-1	---------------	Form of U.S. Tax Compliance Certificate (For Foreign Lenders
		That Are Not Partnerships For U.S. Federal Income Tax Purposes)
EXHIBIT D-2	---------------	Form of U.S. Tax Compliance Certificate (For Foreign Participants
		That Are Not Partnerships For U.S. Federal Income Tax Purposes)
EXHIBIT D-3	---------------	Form of U.S. Tax Compliance Certificate (For Foreign Participants
		That Are Partnerships For U.S. Federal Income Tax Purposes)
EXHIBIT D-4	---------------	Form of U.S. Tax Compliance Certificate (For Foreign Lenders
		That Are Partnerships For U.S. Federal Income Tax Purposes)
EXHIBIT E	---------------	Form of Request for Facility Increase
EXHIBIT F	---------------	Form of Confirmation of Facility Increase
EXHIBIT G	---------------	Form of Lender Commitment Increase Agreement
EXHIBIT H	---------------	Form of Lender Joinder Agreement
SCHEDULE I	---------------	Schedule of Initial Lenders
SCHEDULE 4.01(m)	---------------	Schedule of Significant Subsidiaries

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CREDIT AGREEMENT

CREDIT AGREEMENT, dated as of March 23, 2020 (this “Agreement”), among AMERICAN ELECTRIC POWER COMPANY, INC., a New York corporation (the “Borrower”), the banks, financial institutions and other institutional lenders listed on the signatures pages hereof (the “Initial Lenders”), PNC BANK, NATIONAL ASSOCIATION (“PNC”), as administrative agent (in such capacity, and its successors in such capacity as provided in Article VII, the “Administrative Agent”) for the Lenders (as hereinafter defined).

PRELIMINARY STATEMENT:

The Borrower has requested that the Lenders, on the terms and conditions set forth herein, provide the Borrower a $1,000,000,000 term loan credit facility to be used for ongoing working capital and general corporate purposes. The Lenders have indicated their willingness to provide such a facility on the terms and conditions of this Agreement.

NOW, THEREFORE, in consideration of the premises and of the mutual covenants and agreements contained herein, the parties hereto hereby agree as follows:

ARTICLE I

DEFINITIONS AND ACCOUNTING TERMS

SECTION 1.01. Certain Defined Terms.

As used in this Agreement, the following terms shall have the following meanings (such meanings to be equally applicable to both the singular and plural forms of the terms defined):

“Administrative Agent” has the meaning specified in the recital of parties to this Agreement.

“Administrative Questionnaire” means an administrative questionnaire in a form supplied by the Administrative Agent.

“Advance” means an advance by a Lender to a Borrower as part of a Borrowing and refers to a Base Rate Advance or a Eurodollar Rate Advance.

“Affiliate” means, as to any Person, any other Person that, directly or indirectly, controls, is controlled by or is under common control with such Person or is a director or officer of such Person. For purposes of this definition, the term “control” (including the terms “controlling”, “controlled by” and “under common control with”) of a Person means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of Voting Stock, by contract or otherwise.

“Agent Parties” has the meaning specified in Section 8.02(c).

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“Agent’s Account” means an account of the Administrative Agent maintained by the Administrative Agent from time to time designated in a written notice to the Lenders and the Borrower.

“Anti-Corruption Laws” means all laws, rules, and regulations of any jurisdiction applicable to the Borrower or its Subsidiaries from time to time concerning or relating to bribery, money laundering or corruption.

“Applicable Law” means (i) all applicable common law and principles of equity and (ii) all applicable provisions of all (A) constitutions, statutes, rules, regulations and orders of governmental bodies, (B) Governmental Approvals and (C) orders, decisions, judgments and decrees of all courts (whether at law or in equity or admiralty) and arbitrators.

“Applicable Lending Office” means, with respect to each Lender, such Lender’s Domestic Lending Office in the case of a Base Rate Advance and such Lender’s Eurodollar Lending Office in the case of a Eurodollar Rate Advance.

“Applicable Margin” means, with respect to any Base Rate Advance, 0.00% per annum and with respect to any Eurodollar Rate Advance, 0.60% per annum, provided, that the Applicable Margin shall be increased upon the occurrence and during the continuance of any Event of Default by 2.00% per annum.

“Approved Fund” means any Fund that is administered or managed by (i) a Lender, (ii) an Affiliate of a Lender or (iii) an entity or an Affiliate of an entity that administers or manages a Lender.

“Assignment and Assumption” means an assignment and assumption entered into by a Lender and an Eligible Assignee (with the consent of any party whose consent is required by Section 8.07), and accepted by the Administrative Agent, in substantially the form of Exhibit B hereto or any other form approved by the Administrative Agent.

“Bail-In Action” means the exercise of any Write-Down and Conversion Powers by the applicable EEA Resolution Authority in respect of any liability of an EEA Financial Institution.

“Bail-In Legislation” means, with respect to any EEA Member Country implementing Article 55 of Directive 2014/59/EU of the European Parliament and of the Council of the European Union, the implementing law for such EEA Member Country from time to time which is described in the EU Bail-In Legislation Schedule.

“Bankruptcy Event” means, with respect to any Person, such Person becomes the subject of a proceeding under any Debtor Relief Law, or has had a receiver, custodian, conservator, trustee, administrator, assignee for the benefit of creditors or similar Person charged with reorganization or liquidation of its business or assets (including the Federal Deposit Insurance Corporation or any other Governmental Authority acting in a similar capacity) appointed for it, or, in the good faith determination of the Administrative Agent, has taken any action in furtherance of, or indicating its consent to, approval of, or

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acquiescence in, any such proceeding or appointment; provided that, a Bankruptcy Event shall not result solely by virtue of any ownership interest, or acquisition of any equity interest, in such Person by a Governmental Authority so long as such ownership interest does not result in or provide such Person with immunity from the jurisdiction of courts within the United States or from the enforcement of judgments or writs of attachment on its assets or permit such Person (or such Governmental Authority) to reject, repudiate, disavow or disaffirm obligations under any agreement in which it commits to extend credit.

“Base Rate” means a fluctuating interest rate per annum in effect from time to time, which rate per annum shall at all times be equal to the highest of the following rates then in effect:

(i) the rate of interest announced publicly by PNC, from time to time, as PNC’s prime rate (it being acknowledged by the Borrower that such rate is an index or base rate and shall not necessarily be its lowest or best rate charged to its customers or other banks);

(ii) 1/2 of 1% per annum above the Federal Funds Rate; and

(iii) the rate of interest per annum equal to the Eurodollar Rate as determined on such day (or if such day is not a Business Day, on the next preceding Business Day) that would be applicable to a Eurodollar Rate Advance having an Interest Period of one month, plus 1%;

provided that in no event shall the Base Rate hereunder as determined per the above be less than 0.0%.

“Base Rate Advance” means an Advance that bears interest as provided in Section 2.07(a).

“Benefit Plan” means any of (i) an “employee benefit plan” (as defined in Section 3(3) of ERISA) that is subject to Title I of ERISA, (ii) a “plan” as defined in Section 4975 of the Code to which Section 4975 of the Code applies, and (iii) any Person whose assets include (for purposes of the Plan Asset Regulations or otherwise for purposes of Title I of ERISA or Section 4975 of the Code) the assets of any such “employee benefit plan” or “plan”.

“Beneficial Ownership Certification” means a certification regarding beneficial ownership as required by the Beneficial Ownership Regulation.

“Beneficial Ownership Regulation” means 31 C.F.R. § 1010.230.

“Borrower” has the meaning specified in the recital of parties to this Agreement.

“Borrowing” means a borrowing by the Borrower consisting of simultaneous Advances of the same Type, having the same Interest Period and ratably made or Converted on the same day by each of the Lenders pursuant to Section 2.02 or 2.09, as the case may be. All Advances to the Borrower of the same Type, having the same

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Interest Period and made or Converted on the same day shall be deemed a single Borrowing hereunder until repaid or next Converted.

“Borrowing Date” means the date of any Borrowing.

“Business Day” means a day of the year on which banks are not required or authorized by law to close in New York City and such day is a day on which dealings are carried out in the London interbank market.

“Change in Law” means the occurrence, after the date of this Agreement, of any of the following: (a) the adoption or taking effect of any law, rule, regulation or treaty, (b) any change in any law, rule, regulation or treaty or in the administration, interpretation, implementation or application thereof by any Governmental Authority or (c) the making or issuance of any request, rule, guideline or directive (whether or not having the force of law) by any Governmental Authority; provided that notwithstanding anything herein to the contrary, (x) the Dodd-Frank Wall Street Reform and Consumer Protection Act and all requests, rules, guidelines or directives thereunder or issued in connection therewith and (y) all requests, rules, guidelines or directives promulgated by the Bank for International Settlements, the Basel Committee on Banking Supervision (or any successor or similar authority) or the United States or foreign regulatory authorities, in each case pursuant to Basel III, shall in each case be deemed to be a “Change in Law”, regardless of the date enacted, implemented, adopted or issued.

“Closing Date” means, subject to Section 3.1, March 23, 2020.

“Commitment” means, for each Lender, the obligation of such Lender to make an Advance in Dollars to the Borrower on the Closing Date in an amount no greater than the amount set forth on Schedule I hereto or, if such Lender has entered into any Assignment and Assumption, set forth for such Lender in the Register maintained by the Administrative Agent pursuant to Section 8.07(c), or as such amount may be increased from time to time pursuant to Section 2.18.

“Commitment Percentage” means, as to any Lender as of any date of determination, the percentage describing such Lender’s pro rata share of the Commitments set forth in the Register from time to time; provided that in the case of Section 8.16 when a Defaulting Lender shall exist, “Commitment Percentage” means the percentage of the total Commitments (disregarding any Defaulting Lender’s Commitment) represented by such Lender’s Commitment. If the Commitments have terminated or expired, the Commitment Percentages shall be determined based upon the Commitments most recently in effect, giving effect to any assignments and to any Lender’s status as a Defaulting Lender at the time of determination.

“Commitments” means the aggregate of the Lenders’ Commitments hereunder.

“Communications” has the meaning specified in Section 8.02(b).

“Confidential Information” means information that the Borrower furnishes to the Administrative Agent, the Joint Lead Arrangers or any Lender in a writing designated as

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confidential, but does not include any such information that is or becomes generally available to the public or that is or becomes available to the Administrative Agent, the Joint Lead Arrangers or such Lender from a source other than the Borrower.

“Confirmation of Facility Increase” has the meaning specified in Section 2.18.

“Connection Income Taxes” means Other Connection Taxes that are imposed on or measured by overall gross receipts or income, or net income (however denominated) or that are franchise Taxes, privilege Taxes, license Taxes or branch profits Taxes.

“Consolidated Capital” means the sum of (i) Consolidated Debt of the Borrower and (ii) the consolidated equity of all classes of stock (whether common, preferred, mandatorily convertible preferred or preference) of the Borrower, in each case determined in accordance with GAAP, but including Equity-Preferred Securities issued by the Borrower and its Consolidated Subsidiaries and excluding the funded pension and other postretirement benefit plans, net of tax, components of accumulated other comprehensive income (loss).

“Consolidated Debt” of the Borrower means the total principal amount of all Debt described in clauses (i) through (v) of the definition of Debt and Guaranties of such Debt of the Borrower and its Consolidated Subsidiaries, excluding, however, (i) Debt of AEP Credit, Inc. that is non-recourse to the Borrower, (ii) Stranded Cost Recovery Bonds, and (iii) Equity-Preferred Securities not to exceed 10% of Consolidated Capital (calculated for purposes of this clause without reference to any Equity-Preferred Securities); provided that Guaranties of Debt included in the total principal amount of Consolidated Debt shall not be added to such total principal amount.

“Consolidated Subsidiary” means, with respect to any Person at any time, any Subsidiary or other Person the accounts of which would be consolidated with those of such first Person in its consolidated financial statements in accordance with GAAP.

“Consolidated Tangible Net Assets” means, on any date of determination and with respect to any Person at any time, the total of all assets (including revaluations thereof as a result of commercial appraisals, price level restatement or otherwise) appearing on the consolidated balance sheet of such Person and its Consolidated Subsidiaries most recently delivered to the Lenders pursuant to Section 5.01(i) as of such date of determination, net of applicable reserves and deductions, but excluding goodwill, trade names, trademarks, patents, unamortized debt discount and all other like intangible assets (which term shall not be construed to include such revaluations), less the aggregate of the consolidated current liabilities of such Person and its Consolidated Subsidiaries appearing on such balance sheet.

“Convert”, “Conversion” and “Converted” each refers to a conversion of Advances of one Type into Advances of the other Type, or the selection of a new, or the renewal of the same, Interest Period for Eurodollar Rate Advances, pursuant to Section 2.08 or 2.09.

“Credit Party” means the Administrative Agent or any Lender.

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“Debt” of any Person means, without duplication, (i) all indebtedness of such Person for borrowed money, (ii) all obligations of such Person for the deferred purchase price of property or services (other than trade payables not overdue by more than 60 days incurred in the ordinary course of such Person’s business), (iii) all obligations of such Person evidenced by notes, bonds, debentures or other similar instruments, (iv) all obligations of such Person as lessee under leases that have been, in accordance with GAAP, recorded as capital leases, including, without limitation, the leases described in clause (iv) of Section 5.02(c), (v) all obligations of such Person in respect of reimbursement agreements with respect to acceptances, letters of credit (other than trade letters of credit) or similar extensions of credit, (vi) all Guaranties and (vii) all reasonably quantifiable obligations under indemnities or under support or capital contribution agreements, and other reasonably quantifiable obligations (contingent or otherwise) to purchase or otherwise to assure a creditor against loss in respect of, or to assure an obligee against loss in respect of, all Debt of others referred to in clauses (i) through (vi) above guaranteed directly or indirectly in any manner by such Person, or in effect guaranteed directly or indirectly by such Person through an agreement (A) to pay or purchase such Debt or to advance or supply funds for the payment or purchase of such Debt, (B) to purchase, sell or lease (as lessee or lessor) property, or to purchase or sell services, primarily for the purpose of enabling the debtor to make payment of such Debt or to assure the holder of such Debt against loss, (C) to supply funds to or in any other manner invest in the debtor (including any agreement to pay for property or services irrespective of whether such property is received or such services are rendered) or (D) otherwise to assure a creditor against loss.

“Debtor Relief Laws” means the Bankruptcy Code of the United States of America, and all other liquidation, conservatorship, bankruptcy, assignment for the benefit of creditors, moratorium, rearrangement, receivership, insolvency, reorganization, or similar debtor relief laws of the United States or other applicable jurisdictions from time to time in effect.

“Declining Lender” has the meaning specified in Section 2.04(b).

“Default” means any Event of Default or any event that would constitute an Event of Default but for the requirement that notice be given or time elapse or both.

“Defaulting Lender” means, subject to Section 8.16(b), any Lender that (i) has failed to (A) fund all or any portion of its Advances within two Business Days of the date such Advances were required to be funded hereunder unless such Lender notifies the Administrative Agent and the Borrower in writing that such failure is the result of such Lender’s good faith determination that one or more conditions precedent to funding (each of which conditions precedent, together with any applicable Default, shall be specifically identified in such writing) has not been satisfied, or (B) pay to any Credit Party any other amount required to be paid by it hereunder within two Business Days of the date when due, (ii) has notified the Borrower or any Credit Party in writing that it does not intend to comply with its funding obligations hereunder or generally under other agreements in which it commits to extend credit, or has made a public statement to that effect (unless such writing or public statement relates to such Lender’s obligation to fund an Advance hereunder and states that such position is based on such Lender’s good faith

10

determination that a condition precedent to funding (which condition precedent, together with any applicable Default, shall be specifically identified in such writing or public statement) cannot be satisfied), (iii) has failed, within three Business Days after written request by the Administrative Agent or the Borrower, to confirm in writing to the Administrative Agent and the Borrower that it will comply with its prospective funding obligations hereunder (provided that, such Lender shall cease to be a Defaulting Lender pursuant to this clause (iii) upon receipt of such written confirmation by the Administrative Agent and the Borrower), or (iv) has become the subject of (A) a Bankruptcy Event or (B) a Bail-in Action. Any determination by the Administrative Agent that a Lender is a Defaulting Lender under any one or more of clauses (i) through (iv) above shall be conclusive and binding absent manifest error, and such Lender shall be deemed to be a Defaulting Lender (subject to Section 8.16(b)) upon delivery of written notice of such determination to the Borrower and each Lender.

“Designated Lender” has the meaning specified in Section 2.18(a).

“Disclosure Documents” means the Borrower’s Report on Form 10-K, as filed with the SEC, for the fiscal year ended December 31, 2019 and the Borrower’s Current Reports on Form 8-K, as filed with the SEC after the date of filing the Borrower’s Report on Form 10-K for the period ended December 31, 2019 but prior to the Closing Date.

“Dollars” and the symbol “$” mean lawful currency of the United States of America.

“Domestic Lending Office” means, with respect to any Lender, the office of such Lender specified as its “Domestic Lending Office” on such Lender’s Administrative Questionnaire or in the Assignment and Assumption pursuant to which it became a Lender, or such other office of such Lender as such Lender may from time to time specify in writing to the Borrower and the Administrative Agent.

“EEA Financial Institution” means (a) any credit institution or investment firm established in any EEA Member Country which is subject to the supervision of an EEA Resolution Authority, (b) any entity established in an EEA Member Country which is a parent of an institution described in clause (a) of this definition, or (c) any financial institution established in an EEA Member Country which is a subsidiary of an institution described in clauses (a) or (b) of this definition and is subject to consolidated supervision with its parent.

“EEA Member Country” means any of the member states of the European Union, Iceland, Liechtenstein, and Norway.

“EEA Resolution Authority” means any public administrative authority or any person entrusted with public administrative authority of any EEA Member Country (including any delegee) having responsibility for the resolution of any EEA Financial Institution.

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“Eligible Assignee” means any Person that meets the requirements to be an assignee under Section 8.07(b)(iii), (v) and (vi) (subject to such consents, if any, as may be required under Section 8.07(b)(iii)).

“Environmental Action” means any action, suit, demand, demand letter, claim, notice of non-compliance or violation, notice of liability or potential liability, investigation, proceeding, consent order or consent agreement relating in any way to any Environmental Law, Environmental Permit or Hazardous Materials or arising from alleged injury or threat of injury to health, safety or the environment, including, without limitation, (i) by any Governmental Authority for enforcement, cleanup, removal, response, remedial or other actions or damages and (ii) by any Governmental Authority or any third party for damages, contribution, indemnification, cost recovery, compensation or injunctive relief.

“Environmental Law” means any federal, state, local or foreign statute, law, ordinance, rule, regulation, code, order, judgment, decree or judicial or agency interpretation, policy or guidance relating to pollution or protection of the environment, health, safety or natural resources, including, without limitation, those relating to the use, handling, transportation, treatment, storage, disposal, release or discharge of Hazardous Materials.

“Environmental Permit” means any permit, approval, identification number, license or other authorization required under any Environmental Law.

“Equity-Preferred Securities” means (i) debt or preferred securities that are mandatorily convertible or mandatorily exchangeable into common shares of the Borrower and (ii) any other securities, however denominated, including but not limited to hybrid capital and trust originated preferred securities, (A) issued by the Borrower or any Consolidated Subsidiary of the Borrower, (B) that are not subject to mandatory redemption or the underlying securities, if any, of which are not subject to mandatory redemption, (C) that are perpetual or mature no less than 30 years from the date of issuance, (D) the indebtedness issued in connection with which, including any guaranty, is subordinate in right of payment to the unsecured and unsubordinated indebtedness of the issuer of such indebtedness or guaranty, and (E) the terms of which permit the deferral of the payment of interest or distributions thereon to a date occurring after the Termination Date.

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended from time to time, and the regulations promulgated and rulings issued thereunder.

“ERISA Affiliate” means, with respect to any Person, each trade or business (whether or not incorporated) that is considered to be a single employer with such entity within the meaning of Section 414(b), (c), (m) or (o) of the Internal Revenue Code.

“ERISA Event” means (i) the termination of or withdrawal from any Plan by the Borrower or any of its ERISA Affiliates, (ii) the failure by the Borrower or any of its ERISA Affiliates to comply with ERISA or the related provisions of the Internal Revenue

12

Code with respect to any Plan or (iii) the failure by the Borrower or any of its Subsidiaries to comply with Applicable Law with respect to any Foreign Plan.

“EU Bail-In Legislation Schedule” means the EU Bail-In Legislation Schedule published by the Loan Market Association (or any successor person), as in effect from time to time.

“Eurocurrency Liabilities” has the meaning assigned to that term in Regulation D of the Board of Governors of the Federal Reserve System, as in effect from time to time.

“Eurodollar Lending Office” means, with respect to any Lender, the office of such Lender specified as its “Eurodollar Lending Office” on such Lender’s Administrative Questionnaire or in the Assignment and Assumption pursuant to which it became a Lender (or, if no such office is specified, its Domestic Lending Office), or such other office of such Lender as such Lender may from time to time specify in writing to the Borrower and the Administrative Agent.

“Eurodollar Rate” means, for any Interest Period for each Eurodollar Rate Advance comprising part of the same Borrowing, the London interbank offered rate (rounded upward to the nearest 1/100^th of 1%) as administered by ICE Benchmark Administration Limited (or any other Person that takes over the administration of such rate) for deposits in immediately available funds in Dollars for a period equal in length to such Interest Period as displayed on page LIBOR01 of the Reuters screen that displays such rate (or, in the event such rate does not appear on a Reuters page or screen, on any successor or substitute Reuters page or screen that displays such rate, or on the appropriate page or screen of such other comparable information service that publishes such rate from time to time as selected by the Administrative Agent in its discretion) (in each case, the “Screen Rate”) at approximately 11:00 A.M. (London time) two Business Days before the first day of such Interest Period, provided, that if the Screen Rate shall be less than zero, such rate shall be deemed to be zero for the purposes of this Agreement, and provided, further, if the Screen Rate shall not be available at such time for such Interest Period (an “Impacted Interest Period”), the Eurodollar Rate for such Borrowing shall be a rate determined by the Administrative Agent to be the arithmetic average of the rate per annum (rounded upward to the nearest 1/100^th of 1%) at which deposits in Dollars in minimum amounts of at least $5,000,000 would be offered by first class banks in the London interbank market to the Administrative Agent at approximately 11:00 A.M. (London time) two Business Days before the first day of such Interest Period for a period equal to such Interest Period; provided, that if such rate shall be less than zero, such rate shall be deemed to be zero for the purposes of this Agreement.

“Eurodollar Rate Advance” means an Advance that bears interest as provided in Section 2.08(b).

“Eurodollar Rate Reserve Percentage” of any Lender for any Interest Period for each Eurodollar Rate Advance means the reserve percentage applicable to such Lender during such Interest Period (or if more than one such percentage shall be so applicable, the daily average of such percentages for those days in such Interest Period during which any such percentage shall be so applicable) under regulations issued from time to time by

13

the Board of Governors of the Federal Reserve System (or any successor) for determining the maximum reserve requirement (including, without limitation, any emergency, supplemental or other marginal reserve requirement) then applicable to such Lender with respect to liabilities or assets consisting of or including Eurocurrency Liabilities (or with respect to any other category of liabilities that includes deposits by reference to which the interest rate on Eurodollar Rate Advances is determined) having a term equal to such Interest Period.

“Events of Default” has the meaning specified in Section 6.01.

“Exchange Act” has the meaning specified in Section 6.01(f).

“Excluded Taxes” means any of the following Taxes imposed on or with respect to a Recipient or required to be withheld or deducted from a payment to a Recipient, (a) Taxes imposed on or measured by overall gross receipts or income, or net income (however denominated), franchise Taxes, privilege Taxes, license Taxes or branch profits Taxes, in each case, (i) imposed as a result of such Recipient being organized under the laws of, or having its principal office or, in the case of any Lender, its Applicable Lending Office located in, the jurisdiction imposing such Tax (or any political subdivision thereof) or (ii) that are Other Connection Taxes, (b) in the case of a Lender, U.S. federal withholding Taxes imposed on amounts payable to or for the account of such Lender with respect to an applicable interest in an Advance or Commitment pursuant to a law in effect on the date on which (i) such Lender acquires such interest in the Advance or Commitment (other than pursuant to an assignment request by the Borrower under Section 2.17(b)) or (ii) such Lender changes its Applicable Lending Office, except in each case to the extent that, pursuant to Section 2.15, amounts with respect to such Taxes were payable either to such Lender’s assignor immediately before such Lender became a party hereto or to such Lender immediately before it changed its Applicable Lending Office, (c) Taxes attributable to such Recipient’s failure to comply with Section 2.15(g) and (d) any U.S. federal withholding Taxes imposed under FATCA.

“Extension Effective Date” has the meaning specified in Section 2.04(c).

“Extension of Credit” means the making of a Borrowing. For purposes of this Agreement, a Conversion shall not constitute an Extension of Credit.

“Facility” means the aggregate commitment of the Lenders to make Advances to the Borrower hereunder up to a maximum of $1,000,000,000, as such aggregate commitment may be increased pursuant to Section 2.18.

“FATCA” means Sections 1471 through 1474 of the Internal Revenue Code, as of the date of this Agreement (or any amended or successor version that is substantively comparable and not materially more onerous to comply with), any current or future regulations or official interpretations thereof, any agreement entered into pursuant to Section 1471(b)(1) of the Internal Revenue Code, and any intergovernmental agreement entered into in connection with such sections of the Internal Revenue Code and any legislation, law, regulation or practice enacted or promulgated pursuant to such intergovernmental agreement.

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“Federal Funds Rate” means, for any period, a fluctuating interest rate per annum equal for each day during such period to the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers, as published for such day (or, if such day is not a Business Day, for the next preceding Business Day) by the Federal Reserve Bank of New York, or, if such rate is not so published for any day that is a Business Day, the average of the quotations for such day on such transactions received by the Administrative Agent from three Federal funds brokers of recognized standing selected by it; provided that if the Federal Funds Rate as determined in accordance with this definition shall be less than zero, such rate shall be deemed to be zero for purposes of this Agreement.

“Fee Letter” means that certain Fee Letter, dated as of March 20, 2020, among the Borrower and the Administrative Agent.

“Foreign Lender” means a Lender that is not a U.S. Person.

“Foreign Plan” has the meaning specified in Section 4.01(i).

“Fund” means any Person (other than a natural Person) that is (or will be) engaged in making, purchasing, holding or otherwise investing in commercial loans, bonds and similar extensions of credit in the ordinary course of its activities.

“GAAP” has the meaning specified in Section 1.03.

“GenCo” means AEP Generation Resources Inc.

“Governmental Approval” means any authorization, consent, approval, license or exemption of, registration or filing with, or report or notice to, any Governmental Authority.

“Governmental Authority” means the government of the United States of America or any other nation, or of any political subdivision thereof, whether state or local, and any agency, authority, instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative powers or functions of or pertaining to government (including any supra-national bodies such as the European Union or the European Central Bank).

“Guaranty” of any Person means any obligation, contingent or otherwise, of such Person (i) to pay any Debt of any other Person or (ii) incurred in connection with the issuance by a third person of a Guaranty of Debt of any other Person (whether such obligation arises by agreement to reimburse or indemnify such third Person or otherwise).

“Hazardous Materials” means (i) petroleum and petroleum products, byproducts or breakdown products, radioactive materials, asbestos-containing materials, polychlorinated biphenyls and radon gas and (ii) any other chemicals, materials or substances designated, classified or regulated as hazardous or toxic or as a pollutant or contaminant under any Environmental Law.

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“Impacted Interest Period” has the meaning specified for such term in the definition herein of “Eurodollar Rate.”

“Indemnified Party” has the meaning specified in Section 8.04(b).

“Indemnified Taxes” means (a) Taxes, other than Excluded Taxes, imposed on or with respect to any payment made by or on account of any obligation of the Borrower under any Loan Document and (b) to the extent not otherwise described in (a), Other Taxes.

“Initial Lenders” has the meaning specified in the recital of parties to this Agreement.

“Interest Period” means, for each Eurodollar Rate Advance comprising part of the same Borrowing, the period commencing on the date of such Eurodollar Rate Advance or the date of the Conversion of any Base Rate Advance into such Eurodollar Rate Advance and ending on the last day of the period selected by the Borrower pursuant to the provisions below and, thereafter, with respect to Eurodollar Rate Advances, each subsequent period commencing on the last day of the immediately preceding Interest Period and ending on the last day of the period selected by the Borrower pursuant to the provisions below. The duration of each such Interest Period shall be one, two, three or six months (or, for any Borrowing, any period specified by the Borrower that is shorter than one month, if all Lenders agree), as the Borrower may, upon notice received by the Administrative Agent not later than 11:00 A.M. on the third Business Day prior to the first day of such Interest Period, select; provided, however, that:

(i) the Borrower may not select any Interest Period that ends after the Termination Date of any Lender;

(ii) Interest Periods commencing on the same date for Eurodollar Rate Advances comprising part of the same Borrowing shall be of the same duration;

(iii) whenever the last day of any Interest Period would otherwise occur on a day other than a Business Day, the last day of such Interest Period shall be extended to occur on the next succeeding Business Day, provided, however, that, if such extension would cause the last day of such Interest Period to occur in the next following calendar month, the last day of such Interest Period shall occur on the next preceding Business Day; and

(iv) whenever the first day of any Interest Period occurs on a day of an initial calendar month for which there is no numerically corresponding day in the calendar month that succeeds such initial calendar month by the number of months equal to the number of months in such Interest Period, such Interest Period shall end on the last Business Day of such succeeding calendar month.

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“Internal Revenue Code” means the Internal Revenue Code of 1986, as amended from time to time, and the regulations promulgated and rulings issued thereunder.

“IRS” means the United States Internal Revenue Service.

“Joint Lead Arrangers” means PNC Capital Markets LLC, Wells Fargo Bank, National Association, Keybank National Association, U.S. Bank National Association, Sumitomo Mitsui Banking Corporation and SunTrust Robinson Humphrey, Inc., in their capacities as joint lead arrangers and joint bookrunners for the credit facilities provided for herein.

“Lender Commitment Increase Agreement” has the meaning specified in Section 2.18.

“Lender Joinder Agreement” has the meaning specified in Section 2.18.

“Lenders” means, at any time, collectively, (i) the Initial Lenders (other than any such Initial Lenders that have previously assigned all of their respective Advances and Commitments to other Persons in accordance with Section 8.07(b) or Section 2.18 at such time), and (ii) any other Persons that have become Lenders holding Advances and/or Commitments at such time in accordance with Section 8.07(b) or Section 2.18.

“Lien” means any lien, security interest or other charge or encumbrance of any kind, or any other type of preferential arrangement, including, without limitation, the lien or retained security title of a conditional vendor and any easement, right of way or other encumbrance on title to real property.

“Loan Documents” means, collectively, (i) the Fee Letter, (ii) this Agreement and (iii) each promissory note issued pursuant to Section 2.07(d), in each case, as any of the foregoing may be amended, supplemented or modified from time to time.

“Margin Regulations” means Regulations T, U and X of the Board of Governors of the Federal Reserve System, as in effect from time to time.

“Margin Stock” has the meaning specified in the Margin Regulations.

“Material Adverse Change” means any material adverse change (i) in the business, condition (financial or otherwise) or operations of the Borrower and its Subsidiaries, taken as a whole, or (ii) that is reasonably likely to affect the legality, validity or enforceability of this Agreement against the Borrower or the ability of the Borrower to perform its obligations under this Agreement.

“Material Adverse Effect” means a material adverse effect (i) on the business, condition (financial or otherwise) or operations of the Borrower and its Subsidiaries, taken as a whole, or (ii) that is reasonably likely to affect the legality, validity or enforceability of this Agreement against the Borrower or the ability of the Borrower to perform its obligations under this Agreement.

“Moody’s” means Moody’s Investors Service, Inc.

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“Multiemployer Plan” has the meaning specified in Section 4.01(i).

“Non-Consenting Lender” means any Lender that does not approve any consent, waiver or amendment that (i) requires the approval of all Lenders in accordance with the terms of Section 8.01 and (ii) has been approved by the Required Lenders.

“Non-Defaulting Lender” means, at any time, each Lender that is not a Defaulting Lender at such time.

“Notice of Borrowing” has the meaning specified in Section 2.02(a).

“Other Connection Taxes” means, with respect to any Recipient, Taxes imposed as a result of a present or former connection between such Recipient and the jurisdiction imposing such Tax (other than connections arising from such Recipient having executed, delivered, become a party to, performed its obligations under, received payments under, received or perfected a security interest under, engaged in any other transaction pursuant to or enforced any Loan Document, or sold or assigned an interest in any Advance, Commitment or Loan Document).

“Other Taxes” means all present or future stamp, court or documentary, intangible, recording, filing or similar Taxes that arise from any payment made under, from the execution, delivery, performance, enforcement or registration of, from the receipt or perfection of a security interest under, or otherwise with respect to, any Loan Document, except any such Taxes that are Other Connection Taxes imposed with respect to an assignment (other than an assignment made pursuant to Section 2.17(b)).

“Parent” means, with respect to any Lender, any Person as to which such Lender is, directly or indirectly, a subsidiary.

“Participant” has the meaning specified in Section 8.07(d).

“Participant Register” has the meaning specified in Section 8.07(d).

“Patriot Act” has the meaning specified in Section 8.14.

“Permitted Liens” means such of the following as to which no enforcement, collection, execution, levy or foreclosure proceeding shall have been commenced: (i) Liens for taxes, assessments and governmental charges or levies to the extent not required to be paid under Section 5.01(g) hereof; (ii) Liens imposed by law, such as materialmen’s, mechanics’, carriers’, workmen’s and repairmen’s Liens, and other similar Liens arising in the ordinary course of business securing obligations that are not overdue for a period of more than 30 days or that are being contested in good faith by appropriate proceedings; (iii) Liens incurred or deposits made to secure obligations under workers’ compensation laws or similar legislation or to secure public or statutory obligations; (iv) easements, rights of way and other encumbrances on title to real property that do not render title to the property encumbered thereby unmarketable or materially adversely affect the use of such property for its present purposes; (v) any judgment Lien, unless an Event of Default under Section 6.01(g) shall have occurred and be continuing; (vi) any Lien on any asset of any Person existing at the time such Person is merged or

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consolidated with or into the Borrower or any Significant Subsidiary and not created in contemplation of such event; (vii) deposits made in the ordinary course of business to secure the performance of bids, trade contracts (other than for Debt), operating leases and surety bonds; (viii) Liens upon or in any real property or equipment acquired, constructed, improved or held by the Borrower or any Subsidiary in the ordinary course of business to secure the purchase price of such property or equipment or to secure Debt incurred solely for the purpose of financing the acquisition, construction or improvement of such property or equipment, or Liens existing on such property or equipment at the time of its acquisition (other than any such Liens created in contemplation of such acquisition that were not incurred to finance the acquisition of such property); (ix) extensions, renewals or replacements of any Lien described in clause (iii), (vi), (vii) or (viii) for the same or a lesser amount, provided, however, that no such Lien shall extend to or cover any properties not theretofore subject to the Lien being extended, renewed or replaced; and (x) any other Lien not covered by the foregoing exceptions as long as immediately after the creation of such Lien the aggregate principal amount of Debt secured by all Liens created or assumed under this clause (x) does not exceed 10% of Consolidated Tangible Net Assets of the Borrower.

“Person” means an individual, partnership, corporation (including a business trust), joint stock company, trust, unincorporated association, joint venture, limited liability company or other entity, or a government or any political subdivision or agency thereof.

“Plan” has the meaning specified in Section 4.01(i).

“Platform” has the meaning specified in Section 8.02(b).

“PNC” has the meaning specified in the recital of parties to this Agreement.

“PTE” means a prohibited transaction class exemption issued by the U.S. Department of Labor, as any such exemption may be amended from time to time.

“Recipient” means (a) the Administrative Agent and (b) any Lender, as applicable.

“Register” has the meaning specified in Section 8.07(c).

“Related Parties” means, with respect to any Person, such Person’s Affiliates and the partners, directors, officers, employees, agents, trustees, administrators, managers, advisors and representatives of such Person and of such Person’s Affiliates.

“Request for Facility Increase” has the meaning specified in Section 2.18.

“Required Lenders” means at any time Lenders owed in excess of 50% of the Advances at such time, or, if there are no Advances, Lenders having in excess of 50% in interest of the Commitments in effect at such time; provided that at any time there are two or more Lenders hereunder, the term “Required Lenders” must include at least two Lenders. Subject to Section 8.01, the Advances and Commitments of any Defaulting Lender shall be disregarded in determining Required Lenders at any time.

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“Restructuring Law” means Texas Senate Bill 7, as enacted by the Legislature of the State of Texas and signed into law on June 18, 1999, Ohio Senate Bill No. 3, as enacted by the General Assembly of the State of Ohio and signed into law on July 6, 1999, or any similar law applicable to the Borrower or any Subsidiary of the Borrower governing the deregulation or restructuring of the electric power industry.

“RTO Transaction” means the transfer of transmission facilities to a regional transmission organization or equivalent organization as approved or ordered by the Federal Energy Regulatory Commission.

“S&P” means S&P Global Ratings, a business unit of S&P Global, Inc.

“Sanctions” means all economic or financial sanctions or trade embargoes imposed, administered or enforced from time to time by (a) the U.S. government, including those administered by the Office of Foreign Assets Control of the U.S. Department of the Treasury or by the U.S. Department of State, or (b) the United Nations Security Council, the European Union, any EU member state, or Her Majesty’s Treasury of the United Kingdom.

“Sanctioned Country” means, at any time of determination, a country, region or territory that is itself the subject or target of any Sanctions.

“Sanctioned Person” means, at any time of determination, (a) any Person listed in any Sanctions-related list of designated Persons maintained by the Office of Foreign Assets Control of the U.S. Department of the Treasury, the U.S. Department of State, the United Nations Security Council, the European Union or any EU member state, (b) any Person operating, organized or resident in a Sanctioned Country, (c) any Person owned or controlled by or acting on behalf of any such Person described in the preceding clause (a) or (b), or (d) any Person with which, to the Borrower’s actual knowledge, any Lender is prohibited under Sanctions relevant to it from dealing or engaging in transactions. For purposes of the foregoing, control of a Person shall be deemed to include where a Sanctioned Person (i) owns or has power to vote 25% or more of the issued and outstanding equity interests having ordinary voting power for the election of directors of the Person or other individuals performing similar functions for the Person, or (ii) has the power to direct or cause the direction of the management and policies of the Person, whether by ownership of equity interests, contracts or otherwise.

“SEC” means the United States Securities and Exchange Commission.

“Significant Subsidiary” means, at any time, any Subsidiary of the Borrower that constitutes at such time a “significant subsidiary” of the Borrower, as such term is defined in Regulation S-X of the SEC as in effect on the date hereof (17 C.F.R. Part 210) (other than AEP Energy Supply LLC or GenCo); provided, however, that if AEP Energy Supply LLC or GenCo own, on an aggregate basis, assets exceeding 20% of the Borrower’s “total assets” as used in Regulation S-X, AEP Energy Supply LLC or GenCo will be considered Significant Subsidiaries, and provided, further, that “total assets” as used in Regulation S-X shall not include securitization transition assets, phase-in cost

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assets or similar assets on the balance sheet of any Subsidiary resulting from the issuance of Stranded Cost Recovery Bonds or other asset backed securities of a similar nature.

“Stranded Cost Recovery Bonds” means securities, however denominated, that are issued by the Borrower or any Consolidated Subsidiary of the Borrower that are (i) non-recourse to the Borrower and its Significant Subsidiaries (other than for failure to collect and pay over the charges referred to in clause (ii) below) and (ii) payable solely from transition or similar charges authorized by law (including, without limitation, any “financing order”, as such term is defined in the Texas Utilities Code) to be invoiced to customers of any Subsidiary of the Borrower or to retail electric providers.

“Subsidiary” of any Person means any corporation, partnership, joint venture, limited liability company, trust or estate of which (or in which) more than 50% of (i) the issued and outstanding capital stock having ordinary voting power to elect a majority of the board of directors of such corporation (irrespective of whether at the time capital stock of any other class or classes of such corporation shall or might have voting power upon the occurrence of any contingency), (ii) the interest in the capital or profits of such limited liability company, partnership or joint venture or (iii) the beneficial interest in such trust or estate is at the time directly or indirectly owned or controlled by such Person, by such Person and one or more of its other Subsidiaries or by one or more of such Person’s other Subsidiaries.

“Taxes” means all present or future taxes, levies, imposts, duties, deductions, withholdings (including backup withholding), assessments, fees or other charges imposed by any Governmental Authority, including any interest, additions to tax or penalties applicable thereto.

“Termination Date” means, with respect to any Lender, the earlier to occur of (i) March 22, 2021 or such later date that may be established for such Lender from time to time pursuant to Section 2.04 hereof, and (ii) the date on which the obligations hereunder are made due and payable pursuant to Section 6.01.

“Type” refers to the distinction between Advances bearing interest at the Base Rate and Advances bearing interest at the Eurodollar Rate.

“U.S. Person” means any Person that is a “United States Person” as defined in Section 7701(a)(30) of the Internal Revenue Code.

“U.S. Tax Compliance Certificate” has the meaning specified in Section 2.15(g)(ii)(B)(iii).

“Voting Stock” means capital stock issued by a corporation, or equivalent interests in any other Person, the holders of which are ordinarily, in the absence of contingencies, entitled to vote for the election of directors (or Persons performing similar functions) of such Person, even if the right so to vote has been suspended by the happening of such a contingency.

“Withholding Agent” means the Borrower and the Administrative Agent.

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“Write-Down and Conversion Powers” means, with respect to any EEA Resolution Authority, the write-down and conversion powers of such EEA Resolution Authority from time to time under the Bail-In Legislation for the applicable EEA Member Country, which write-down and conversion powers are described in the EU Bail-In Legislation Schedule.

SECTION 1.02. Computation of Time Periods.

In this Agreement in the computation of periods of time from a specified date to a later specified date, the word “from” means “from and including” and the words “to” and “until” each mean “to but excluding”.

SECTION 1.03. Accounting Terms.

All accounting terms not specifically defined herein shall be construed in accordance with generally accepted accounting principles applied in accordance with the consistency requirements thereof as in effect from time to time (“GAAP”); provided that (i) if the Borrower, by notice to the Administrative Agent, shall request an amendment to any provision hereof to eliminate the effect of any change occurring after the Closing Date in GAAP or in the application thereof on the operation of such provision (or if the Administrative Agent or the Required Lenders, by notice to the Borrower, shall request an amendment to any provision hereof for such purpose), regardless of whether any such notice is given before or after such change in GAAP or in the application thereof, then such provision shall be interpreted on the basis of GAAP as in effect and applied immediately before such change shall have become effective until such notice shall have been withdrawn or such provision amended in accordance herewith and (ii) notwithstanding any other provision contained herein, all terms of an accounting or financial nature used herein shall be construed, and all computations of amounts and ratios referred to herein shall be made, without giving effect to any change to GAAP occurring after the Closing Date as a result of the adoption of any proposals set forth in the Proposed Accounting Standards Update, Leases (Topic 840), issued by the Financial Accounting Standards Board on August 17, 2010, or any other proposals issued by the Financial Accounting Standards Board in connection therewith, in each case to the extent that such change would require treating any operating lease entered into on or prior to December 31, 2018 that would not otherwise constitute Debt as a capital lease where such operating lease would not constitute Debt and was not required to be so treated under GAAP as in effect on the Closing Date.

SECTION 1.04. Other Interpretive Provisions.

As used herein, except as otherwise specified herein, (i) references to any Person include its successors and assigns and, in the case of any Governmental Authority, any Person succeeding to its functions and capacities; (ii) references to any Applicable Law include amendments, supplements and successors thereto; (iii) references to specific sections, articles, annexes, schedules and exhibits are to this Agreement; (iv) words importing any gender include the other gender; (v) the singular includes the plural and the plural includes the singular; (vi) the words “including”, “include” and “includes” shall be deemed to be followed by the words “without limitation”; (vii) captions and headings are for ease of reference only and shall not affect the construction hereof; and (viii) references to any time of day shall be to New York City time unless otherwise specified. For all purposes under the Loan Documents, in connection with

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any division or plan of division under Delaware law (or any comparable event under a different jurisdiction’s laws) if any asset, right, obligation or liability of any Person becomes the asset, right, obligation or liability of a different Person, then it shall be deemed to have been transferred from the original Person to the subsequent Person.

ARTICLE II

AMOUNTS AND TERMS OF THE ADVANCES

SECTION 2.01. The Advances.

(a)Each Lender severally agrees, on the terms and conditions hereinafter set forth, to make Advances to the Borrower on the Closing Date in an aggregate outstanding amount not to exceed at any time such Lender’s Commitment at such time. Within the limits of each Lender’s Commitment from time to time and as hereinabove and hereinafter provided, the Borrower may request Borrowings hereunder, and repay or prepay Advances pursuant to Section 2.11. Amounts repaid or prepaid in respect of Advances may not be reborrowed.

(b)In the event any increase in the Facility and the Commitments thereunder is undertaken pursuant to Section 2.18, the Borrower shall be required to make a Borrowing in an amount equal to such increased Commitments on the date which is not more than five (5) Business Days following the effectiveness of such increase pursuant to the terms of Section 2.02.

SECTION 2.02. Making the Advances.

(a)Each Borrowing shall consist of Advances of the same Type made on the same day by the Lenders ratably according to their respective Commitment Percentages. The Borrower shall give notice to the Administrative Agent, (i) not later than 11:00 A.M. three (3) Business Days prior to the applicable Borrowing Date, of a Borrowing consisting of Eurodollar Rate Advances, or (ii) not later than 9:30 A.M. on the applicable Borrowing Date, in the case of a Borrowing consisting of Base Rate Advances, and the Administrative Agent shall give to each Lender prompt written notice of such Borrowing. Each such notice of a Borrowing under this Section 2.02 (a “Notice of Borrowing”) shall be by telephone, confirmed immediately in writing, or fax in substantially the form of Exhibit A hereto, specifying therein the requested (i) Borrowing Date for such Borrowing, (ii) Type of Advances comprising such Borrowing, (iii) aggregate amount of such Borrowing, and (iv) in the case of a Borrowing consisting of Eurodollar Rate Advances, the initial Interest Period for each such Advance. Each Lender shall, before 12:00 Noon on the applicable Borrowing Date, make available for the account of its Applicable Lending Office to the Administrative Agent at the Agent’s Account, in same day funds, such Lender’s ratable portion of the Borrowing to be made on such Borrowing Date. After the Administrative Agent’s receipt of such funds and upon fulfillment of the applicable conditions set forth in Section 3.02, the Administrative Agent will promptly make such funds available to the Borrower in such manner as the Borrower shall have specified in the applicable Notice of Borrowing and as shall be reasonably acceptable to the Administrative Agent.

(b)Anything in subsection (a) above to the contrary notwithstanding, (i) the Borrower may not select Eurodollar Rate Advances if the obligation of the Lenders to make Eurodollar Rate Advances shall then be suspended pursuant to Section 2.09.

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(c)Each Notice of Borrowing shall be irrevocable and binding on the Borrower. In the case of any Borrowing that the related Notice of Borrowing specifies is to comprise Eurodollar Rate Advances, the Borrower shall indemnify each Lender against any loss, cost or expense incurred by such Lender as a result of any failure to fulfill on or before the date specified in such Notice of Borrowing for such Borrowing the applicable conditions set forth in Section 3.02, including, without limitation, any loss (including loss of anticipated profits), cost or expense incurred by reason of the liquidation or reemployment of deposits or other funds acquired by such Lender to fund the Advance to be made by such Lender as part of such Borrowing when such Advance, as a result of such failure, is not made on such date.

(d)Unless the Administrative Agent shall have received notice in writing from a Lender prior to any Borrowing Date or, in the case of a Base Rate Advance, prior to the time of Borrowing, that such Lender will not make available to the Administrative Agent such Lender’s Advance as part of the Borrowing to be made on such Borrowing Date, the Administrative Agent may, but shall not be required to, assume that such Lender has made such portion available to the Administrative Agent on such Borrowing Date in accordance with subsection (a) of this Section 2.02, and the Administrative Agent may (but it shall not be required to), in reliance upon such assumption, make available to the Borrower on such date a corresponding amount. If and to the extent that such Lender shall not have so made such Advance available to the Administrative Agent, such Lender and the Borrower severally agree to repay to the Administrative Agent forthwith on demand such corresponding amount, together with interest thereon, for each day from the date such amount is made available to the Borrower until the date such amount is repaid to the Administrative Agent, at (i) in the case of the Borrower, the interest rate applicable at the time to Advances comprising such Borrowing and (ii) in the case of such Lender, the Federal Funds Rate. If such Lender shall repay to the Administrative Agent such corresponding amount, such amount so repaid shall constitute such Lender’s Advance as part of such Borrowing for purposes of this Agreement.

(e)The failure of any Lender to make the Advance to be made by it as part of any Borrowing shall not relieve any other Lender of its obligation, if any, hereunder to make its Advance on the date of such Borrowing, but no Lender shall be responsible for the failure of any other Lender to make the Advance to be made by such other Lender on the date of any Borrowing.

SECTION 2.03. Fees.

(a)The Borrower shall pay to the Administrative Agent (i) for the account of each Lender a structuring fee as set forth in the Fee Letter and (ii) such other fees as may from time to time be agreed between the Borrower and the Administrative Agent.

SECTION 2.04. Extension of the Termination Date.

(a)Not earlier than 60 days prior to, nor later than 30 days prior to the first anniversary of the date of this Agreement, the Borrower may request by notice made to the Administrative Agent (which shall promptly notify the Lenders thereof) a one-year extension of the Termination Date. Each Lender shall notify the Administrative Agent by the date specified by the Administrative Agent (which date shall be a Business Day and shall not be less than 15 days prior to, nor more than 30 days prior to, the Extension Effective Date) that either (A) such

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Lender declines to consent to extending the Termination Date or (B) such Lender consents to extending the Termination Date. Any Lender not responding within the above time period shall be deemed not to have consented to extending the Termination Date. The Administrative Agent shall, after receiving the notifications from all of the Lenders or the expiration of such period, whichever is earlier, notify the Borrower and the Lenders of the results thereof. The Borrower may request no more than one extension pursuant to this Section.

(b)If any Lender declines, or is deemed to have declined, to consent to such request for extension (each a “Declining Lender”), the Borrower shall have the right to replace such Declining Lender in accordance with Section 2.17(b). Any Lender replacing a Declining Lender shall be deemed to have consented to such request for extension (regardless of when such replacement is effective) and shall not be deemed to be a Declining Lender.

(c)If the Required Lenders have consented to the extension of the Termination Date, the Termination Date shall be extended (solely with respect each Lender that consented to the extension) to the date that is one year after the then-effective Termination Date, effective as of the date to be determined by the Administrative Agent and the Borrower (the “Extension Effective Date”). On or prior to the Extension Effective Date, the Borrower shall deliver to the Administrative Agent, in form and substance satisfactory to the Administrative Agent, (i) the resolutions of the Borrower authorizing such extension, certified as being in effect as of the Extension Effective Date and the related incumbency certificate of the Borrower, (ii) a favorable opinion of counsel for the Borrower (which may be an attorney of American Electric Power Service Corporation), as to such matters as any Lender through the Administrative Agent may reasonably request and (iii) a certificate of the Borrower stating that on and as of such Extension Effective Date, and after giving effect to the extension to be effective on such date, all conditions precedent to an Extension of Credit are satisfied. On each Extension Effective Date, the Declining Lender shall have received payment in full of the principal amount of all Advances outstanding owing to such Declining Lender and all interest thereon and all fees and other amounts (including, without limitation, any amounts payable pursuant to Section 8.04(c)) payable to such Declining Lender accrued through such Extension Effective Date. Promptly following such Extension Effective Date, the Administrative Agent shall distribute an amended Schedule I to this Agreement (which shall thereafter be incorporated into this Agreement) to reflect any changes in the Lenders, the Commitments and each Lender’s Commitment Percentage as of such Extension Effective Date.

SECTION 2.05. [Reserved]

SECTION 2.06. Repayment of Advances.

The Borrower shall repay to the Administrative Agent for the account of each Lender on the Termination Date with respect to such Lender the aggregate principal amount of all Advances made by such Lender to the Borrower then outstanding.

SECTION 2.07. Evidence of Indebtedness.

(a)Each Lender shall maintain in accordance with its usual practice an account or accounts evidencing the indebtedness to such Lender resulting from each Advance made by such

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Lender from time to time, including the amounts of principal and interest payable and paid to such Lender from time to time under this Agreement.

(b)The Administrative Agent shall maintain accounts in which it will record (i) the amount of each Advance made hereunder, the Type of each Advance made and the Interest Period applicable thereto, (ii) the amount of any principal or interest due and payable or to become due and payable from the Borrower to each Lender hereunder and (iii) the amount of any sum received by the Administrative Agent hereunder from the Borrower and each Lender’s share thereof.

(c)The entries made in the accounts maintained pursuant to subsections (a) and (b) of this Section 2.07 shall, to the extent permitted by Applicable Law, be prima facie evidence of the existence and amounts of the obligations therein recorded; provided, however, that the failure of any Lender or the Administrative Agent to maintain such accounts or any error therein shall not in any manner affect the obligations of the Borrower to repay the Advances and interest thereon in accordance with their terms.

(d)Any Lender may request that any Advances made by it be evidenced by one or more promissory notes. In such event, the Borrower shall prepare, execute and deliver to such Lender one or more promissory notes payable to such Lender (or, if requested by such Lender, to such Lender and its assignees) and in a form approved by the Administrative Agent. Thereafter, the Advances evidenced by such promissory notes and interest thereon shall at all times (including after assignment pursuant to Section 8.07) be represented by one or more promissory notes in such form payable to the payee named therein.

SECTION 2.08. Interest on Advances.

The Borrower shall pay interest on the unpaid principal amount of each Advance from the date of such Advance until such principal amount shall be paid in full, at the following rates per annum:

(a)Base Rate Advances. During such periods as such Advance is a Base Rate Advance, a rate per annum equal at all times to the sum of (x) the Base Rate plus (y) the Applicable Margin for Base Rate Advances, payable in arrears quarterly on the last day of each March, June, September and December during such periods and on the date such Base Rate Advance shall be Converted or paid in full.

(b)Eurodollar Rate Advances. During such periods as such Advance is a Eurodollar Rate Advance, a rate per annum equal at all times during each Interest Period for such Advance to the sum of (x) the Eurodollar Rate for such Interest Period for such Advance plus (y) the Applicable Margin for Eurodollar Rate Advances, payable in arrears on the last day of such Interest Period and, if such Interest Period has a duration of more than three months, on each day that occurs during such Interest Period every three months from the first day of such Interest Period and on the date such Eurodollar Rate Advance shall be Converted or paid in full.

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(c)Additional Interest on Eurodollar Rate Advances. The Borrower shall pay to each Lender, so long as such Lender shall be required under regulations of the Board of Governors of the Federal Reserve System to maintain reserves with respect to liabilities or assets consisting of or including Eurocurrency Liabilities, additional interest on the unpaid principal amount of each Eurodollar Rate Advance of such Lender, from the date of such Advance until such principal amount is paid in full, at an interest rate per annum equal at all times to the remainder obtained by subtracting (i) the Eurodollar Rate for the Interest Period for such Advance from (ii) the rate obtained by dividing such Eurodollar Rate by a percentage equal to 100% minus the Eurodollar Rate Reserve Percentage of such Lender for such Interest Period, payable on each date on which interest is payable on such Advance. Such additional interest shall be determined by such Lender and notified to the Borrower through the Administrative Agent.

SECTION 2.09. Interest Rate Determination.

(a)The Administrative Agent shall give prompt notice to the Borrower and the Lenders of the applicable interest rate determined by the Administrative Agent for purposes of Section 2.08(a) or (b), and, if applicable, the rate for the purpose of determining the applicable interest rate under Section 2.08(c).

(b)If, with respect to any Eurodollar Rate Advances, (i) the Required Lenders notify the Administrative Agent that the Eurodollar Rate for any Interest Period for such Advances will not adequately reflect the cost to such Required Lenders of making, funding or maintaining their respective Eurodollar Rate Advances for such Interest Period, or (ii) the Administrative Agent determines that adequate and fair means do not exist for ascertaining the applicable interest rate on the basis provided for in the definition of Eurodollar Rate, the Administrative Agent shall forthwith so notify the Borrower and the Lenders, whereupon (A) each Eurodollar Rate Advance will automatically, on the last day of the then existing Interest Period therefor, Convert into a Base Rate Advance, and (B) the obligation of the Lenders to make, or to Convert Advances into, Eurodollar Rate Advances shall be suspended until the Administrative Agent shall notify the Borrower and the Lenders that the circumstances causing such suspension no longer exist.

(c)If the Borrower shall fail to select the duration of any Interest Period for any Eurodollar Rate Advances in accordance with the provisions contained in the definition of “Interest Period” in Section 1.01, the Administrative Agent will forthwith so notify the Borrower and the Lenders and such Advances will automatically, on the last day of the then existing Interest Period therefor, Convert into Base Rate Advances.

(d)On the date on which the aggregate unpaid principal amount of Eurodollar Rate Advances comprising any Borrowing shall be reduced, by payment or prepayment or otherwise, to less than $10,000,000, such Advances shall automatically Convert into Base Rate Advances.

(e)Upon the occurrence and during the continuance of any Event of Default, (i) each Eurodollar Rate Advance will automatically, on the last day of the then existing Interest Period therefor, Convert into a Base Rate Advance and (ii) the obligation of the Lenders to make, or to Convert Advances into, Eurodollar Rate Advances shall be suspended.

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SECTION 2.10. Optional Conversion of Advances.

The Borrower may on any Business Day, upon notice given to the Administrative Agent not later than 12:00 noon on the third Business Day prior to the date of the proposed Conversion and subject to the provisions of Sections 2.09 and 2.13, Convert all or any part of Advances of one Type comprising the same Borrowing into Advances of the other Type or of the same Type but having a new Interest Period; provided, however, that any Conversion of Eurodollar Rate Advances into Base Rate Advances shall be made only on the last day of an Interest Period for such Eurodollar Rate Advances, any Conversion of Base Rate Advances into Eurodollar Rate Advances shall be in an amount not less than the minimum amount specified in Section 2.02(b) and no Conversion of any Advances shall result in more separate Borrowings than permitted under Section 2.02(b). Each such notice of a Conversion shall, within the restrictions specified above, specify (i) the date of such Conversion, (ii) the Advances to be Converted, and (iii) if such Conversion is into Eurodollar Rate Advances, the duration of the initial Interest Period for each such Advance. Each notice of Conversion shall be irrevocable and binding on the Borrower.

SECTION 2.11. Optional Prepayments of Advances.

The Borrower may, upon at least two Business Days’ notice, in the case of Eurodollar Rate Advances, and upon notice not later than 11:00 A.M. (New York City time) on the date of prepayment, in the case of Base Rate Advances, to the Administrative Agent stating the proposed date and aggregate principal amount of the prepayment, and, if such notice is given, the Borrower shall prepay the outstanding principal amount of the Advances comprising part of the same Borrowing in whole or ratably in part, together with accrued interest to the date of such prepayment on the principal amount prepaid; provided, however, that (x) each partial prepayment shall be in a minimum amount of $5,000,000 or an integral multiple of $1,000,000 in excess thereof, and (y) in the event of any such prepayment of a Eurodollar Rate Advance, the Borrower shall be obligated to reimburse the Lenders in respect thereof pursuant to Section 8.04(c).

SECTION 2.12. Increased Costs.

(a)Increased Costs Generally. If any Change in Law shall:

(i)impose, modify or deem applicable any reserve, special deposit, compulsory loan, insurance charge or similar requirement against assets of, deposits with or for the account of, or credit extended or participated in by, any Lender (except any reserve requirement reflected in the Eurodollar Rate Reserve Percentage, in the case of Eurodollar Rate Advances);

(ii)subject any Recipient to any Taxes (other than (A) Indemnified Taxes, (B) Taxes described in clauses (b) through (d) of the definition of Excluded Taxes and (C) Connection Income Taxes) on its loans, loan principal, letters of credit, commitments, or other obligations, or its deposits, reserves, other liabilities or capital attributable thereto; or

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(iii)impose on any Lender or the London interbank market any other condition, cost or expense (other than Taxes) affecting this Agreement or Advances made by such Lender;

and the result of any of the foregoing shall be to increase the cost to such Lender or such other Recipient of making, converting to, continuing or maintaining any Advance or of maintaining its obligation to make any such Advance, or to reduce the amount of any sum received or receivable by such Lender or other Recipient hereunder (whether of principal, interest or any other amount) then, upon request of such Lender or other Recipient, the Borrower will pay to such Lender or other Recipient, as the case may be, such additional amount or amounts as will compensate such Lender or other Recipient, as the case may be, for such additional costs incurred or reduction suffered.

(b)Capital Requirements. If any Lender determines that any Change in Law affecting such Lender or any Applicable Lending Office of such Lender or such Lender’s holding company, if any, regarding capital or liquidity requirements, has or would have the effect of reducing the rate of return on such Lender’s capital or on the capital of such Lender’s holding company, if any, as a consequence of this Agreement, the Commitments of such Lender or the Advances made by such Lender, such Lender, to a level below that which such Lender or such Lender’s holding company could have achieved but for such Change in Law (taking into consideration such Lender’s policies and the policies of such Lender’s holding company with respect to capital adequacy and liquidity), then from time to time the Borrower will pay to such Lender such additional amount or amounts as will compensate such Lender or such Lender’s holding company for any such reduction suffered.

(c)Certificates for Reimbursement. A certificate of a Lender setting forth the amount or amounts necessary to compensate such Lender or its holding company, as the case may be, as specified in subsection (a) or (b) of this Section and delivered to the Borrower, shall be conclusive absent manifest error. The Borrower shall pay such Lender, as the case may be, the amount shown as due on any such certificate within ten days after receipt thereof.

(d)Delay in Requests. Failure or delay on the part of any Lender to demand compensation pursuant to this Section shall not constitute a waiver of such Lender’s right to demand such compensation; provided that the Borrower shall not be required to compensate a Lender pursuant to this Section for any increased costs incurred or reductions suffered more than six months prior to the date that such Lender notifies the Borrower of the Change in Law giving rise to such increased costs or reductions, and of such Lender’s intention to claim compensation therefor (except that, if the Change in Law giving rise to such increased costs or reductions is retroactive, then the six-month period referred to above shall be extended to include the period of retroactive effect thereof).

SECTION 2.13. Illegality.

If due to any Change in Law it shall become unlawful or impossible for any Credit Party (or its Eurodollar Lending Office) to make, maintain or fund its Eurodollar Rate Advances, and such Credit Party shall so notify the Administrative Agent, the Administrative Agent shall forthwith give notice thereof to the other Credit Parties and the Borrower, whereupon, until such Credit Party notifies the Borrower and the Administrative Agent that the circumstances giving

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rise to such suspension no longer exist, the obligation of such Credit Party to make Eurodollar Rate Advances, or to Convert outstanding Advances into Eurodollar Rate Advances, shall be suspended. Before giving any notice to the Administrative Agent pursuant to this Section 2.13, such Credit Party shall use reasonable efforts (consistent with its internal policy and legal and regulatory restrictions applicable to such Credit Party) to designate a different Eurodollar Lending Office if such designation would avoid the need for giving such notice and would not, in the judgment of such Credit Party, be otherwise disadvantageous to such Credit Party. If such notice is given, each Eurodollar Rate Advance of such Credit Party then outstanding shall be converted to a Base Rate Advance either (i) on the last day of the then current Interest Period applicable to such Eurodollar Rate Advance if such Credit Party may lawfully continue to maintain and fund such Advance to such day or (ii) immediately if such Credit Party shall determine that it may not lawfully continue to maintain and fund such Advance to such day.

SECTION 2.14. Payments and Computations.

(a)The Borrower shall make each payment to be made by it hereunder not later than 1:00 P.M. on the day when due in Dollars to the Administrative Agent at the Agent’s Account in same day funds without condition or deduction for any counterclaim, defense, recoupment or setoff. The Administrative Agent will promptly thereafter cause to be distributed like funds relating to the payment of principal or interest or fees ratably (other than amounts payable pursuant to Section 2.08(c), 2.12, 2.15, 8.04(c) or 8.16) to the Lenders for the account of their respective Applicable Lending Offices, and like funds relating to the payment of any other amount payable to any Lender to such Lender for the account of its Applicable Lending Office, in each case to be applied in accordance with the terms of this Agreement. Upon its acceptance of an Assignment and Assumption and recording of the information contained therein in the Register pursuant to Section 8.07(c), from and after the effective date specified in such Assignment and Assumption, the Administrative Agent shall make all payments hereunder in respect of the interest assigned thereby to the Lender assignee thereunder, and the parties to such Assignment and Assumption shall make all appropriate adjustments in such payments for periods prior to such effective date directly between themselves.

(b)The Borrower hereby authorizes each Lender, if and to the extent payment owed to such Lender is not made when due hereunder, after any applicable grace period, to charge from time to time against any or all of the Borrower’s accounts with such Lender any amount so due.

(c)All computations of interest based on the rate referred to in clause (i) of the definition of the “Base Rate” contained in Section 1.01 shall be made by the Administrative Agent on the basis of a year of 365 or 366 days, as the case may be, and all computations of interest based on the Eurodollar Rate and of fees shall be made by the Administrative Agent on the basis of a year of 360 days, in each case for the actual number of days (including the first day but excluding the last day) occurring in the period for which such interest or fees are payable. Each determination by the Administrative Agent of an interest rate or fee hereunder shall be conclusive and binding for all purposes, absent manifest error.

(d)Whenever any payment hereunder shall be stated to be due on a day other than a Business Day, such payment shall be made on the next succeeding Business Day, and such extension of time shall in such case be included in the computation of payment of interest or

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fees, as the case may be; provided, however, that, if such extension would cause payment of interest on or principal of Eurodollar Rate Advances to be made in the next following calendar month or on a date after the Termination Date, such payment shall be made on the next preceding Business Day.

(e)Unless the Administrative Agent shall have received notice from the Borrower prior to the date on which any payment is due to a Lender hereunder that the Borrower will not make such payment in full, the Administrative Agent may assume that the Borrower has made such payment in full to the Administrative Agent on such date, and the Administrative Agent may, in reliance upon such assumption, cause to be distributed to each Lender on such due date an amount equal to the amount then due such Lender. If and to the extent that the Borrower shall not have so made such payment in full to the Administrative Agent, each Lender shall repay to the Administrative Agent forthwith on demand such amount distributed to such Lender together with interest thereon, for each day from the date such amount is distributed to such Lender until the date such Lender repays such amount to the Administrative Agent, at the Federal Funds Rate.

SECTION 2.15. Taxes.

(a)Defined Terms. For purposes of this Section 2.15, the term “Applicable Law” includes FATCA.

(b)Payments Free of Taxes. Any and all payments by or on account of any obligation of the Borrower under any Loan Document shall be made without deduction or withholding for any Taxes, except as required by Applicable Law. If any Applicable Law (as determined in the good faith discretion of an applicable Withholding Agent) requires the deduction or withholding of any Tax from any such payment by a Withholding Agent, then the applicable Withholding Agent shall be entitled to make such deduction or withholding and shall timely pay the full amount deducted or withheld to the relevant Governmental Authority in accordance with Applicable Law and, if such Tax is an Indemnified Tax, then the sum payable by the Borrower shall be increased as necessary so that after such deduction or withholding has been made (including such deductions and withholdings applicable to additional sums payable under this Section) the applicable Recipient receives an amount equal to the sum it would have received had no such deduction or withholding been made.

(c)Payment of Other Taxes by the Borrower. The Borrower shall timely pay to the relevant Governmental Authority in accordance with Applicable Law, or at the option of the Administrative Agent timely reimburse it for the payment of, any Other Taxes.

(d)Indemnification by the Borrower. The Borrower shall indemnify each Recipient, within 10 days after demand therefor, for the full amount of any Indemnified Taxes (including Indemnified Taxes imposed or asserted on or attributable to amounts payable under this Section) payable or paid by such Recipient or required to be withheld or deducted from a payment to such Recipient and any reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate as to the amount of such payment or liability delivered to the Borrower by a Lender (with a copy to the Administrative Agent), or by the Administrative Agent on its own behalf or on behalf of a Lender, shall be conclusive absent manifest error.

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(e)Indemnification by the Lenders. Each Lender shall severally indemnify the Administrative Agent, within 10 days after demand therefor, for (i) any Indemnified Taxes attributable to such Lender (but only to the extent that the Borrower has not already indemnified the Administrative Agent for such Indemnified Taxes and without limiting the obligation of the Borrower to do so), (ii) any Taxes attributable to such Lender’s failure to comply with the provisions of Section 8.07(d) relating to the maintenance of a Participant Register and (iii) any Excluded Taxes attributable to such Lender, in each case, that are payable or paid by the Administrative Agent in connection with any Loan Document, and any reasonable expenses arising therefrom or with respect thereto, whether or not such Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate as to the amount of such payment or liability delivered to any Lender by the Administrative Agent shall be conclusive absent manifest error. Each Lender hereby authorizes the Administrative Agent to set off and apply any and all amounts at any time owing to such Lender under any Loan Document or otherwise payable by the Administrative Agent to the Lender from any other source against any amount due to the Administrative Agent under this subsection (e).

(f)Evidence of Payments. As soon as practicable after any payment of Taxes by the Borrower to a Governmental Authority pursuant to this Section 2.15, the Borrower shall deliver to the Administrative Agent the original or a certified copy of a receipt issued by such Governmental Authority evidencing such payment, a copy of the return reporting such payment or other evidence of such payment reasonably satisfactory to the Administrative Agent.

(g)Status of Lenders. (i) Any Lender that is entitled to an exemption from or reduction of withholding Tax with respect to payments made under any Loan Document shall deliver to the Borrower and the Administrative Agent, at the time or times reasonably requested by the Borrower or the Administrative Agent, such properly completed and executed documentation reasonably requested by the Borrower or the Administrative Agent as will permit such payments to be made without withholding or at a reduced rate of withholding. In addition, any Lender, if reasonably requested by the Borrower or the Administrative Agent, shall deliver such other documentation prescribed by Applicable Law or reasonably requested by the Borrower or the Administrative Agent as will enable the Borrower or the Administrative Agent to determine whether or not such Lender is subject to backup withholding or information reporting requirements. Notwithstanding anything to the contrary in the preceding two sentences, the completion, execution and submission of such documentation (other than such documentation set forth in Section 2.15(g)(ii)(A), (ii)(B) and (ii)(D) below) shall not be required if in the Lender’s reasonable judgment such completion, execution or submission would subject such Lender to any material unreimbursed cost or expense or would materially prejudice the legal or commercial position of such Lender.

(ii)Without limiting the generality of the foregoing,

(A)any Lender that is a U.S. Person shall deliver to the Borrower and the Administrative Agent on or prior to the date on which such Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), executed copies of IRS Form W-9 certifying that such Lender is exempt from U.S. federal backup withholding tax;

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(B)any Foreign Lender shall, to the extent it is legally entitled to do so, deliver to the Borrower and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), whichever of the following is applicable:

(i)in the case of a Foreign Lender claiming the benefits of an income tax treaty to which the United States is a party (x) with respect to payments of interest under any Loan Document, executed copies of IRS Form W-8BEN or W‑8BEN‑E establishing an exemption from, or reduction of, U.S. federal withholding Tax pursuant to the “interest” article of such tax treaty and (y) with respect to any other applicable payments under any Loan Document, IRS Form W-8BEN or W‑8BEN‑E establishing an exemption from, or reduction of, U.S. federal withholding Tax pursuant to the “business profits” or “other income” article of such tax treaty;

(ii)executed copies of IRS Form W-8ECI;

(iii)in the case of a Foreign Lender claiming the benefits of the exemption for portfolio interest under Section 881(c) of the Internal Revenue Code, (x) a certificate substantially in the form of Exhibit D-1 to the effect that such Foreign Lender is not a “bank” within the meaning of Section 881(c)(3)(A) of the Internal Revenue Code, a “10 percent shareholder” of the Borrower within the meaning of Section 881(c)(3)(B) of the Internal Revenue Code, or a “controlled foreign corporation” described in Section 881(c)(3)(C) of the Internal Revenue Code (a “U.S. Tax Compliance Certificate”) and (y) executed copies of IRS Form W-8BEN or W‑8BEN‑E;

(iv)to the extent a Foreign Lender is not the beneficial owner, executed copies of IRS Form W-8IMY, accompanied by IRS Form W-8ECI, IRS Form W-8BEN, W‑8BEN‑E, a U.S. Tax Compliance Certificate substantially in the form of Exhibit D-2 or Exhibit D-3, IRS Form W-9, and/or other certification documents from each beneficial owner, as applicable; provided that, if the Foreign Lender is a partnership and one or more direct or indirect partners of such Foreign Lender are claiming the portfolio interest exemption, such Foreign Lender may provide a U.S. Tax Compliance Certificate substantially in the form of Exhibit D-4 on behalf of each such direct and indirect partner;

(C)any Foreign Lender shall, to the extent it is legally entitled to do so, deliver to the Borrower and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), executed copies of any other form prescribed by Applicable Law as a basis for claiming exemption from or a reduction in U.S. federal withholding Tax, duly completed, together with such supplementary documentation as may be prescribed by Applicable Law to permit the Borrower or the Administrative Agent to determine the withholding or deduction required to be made; and

(D)if a payment made to a Lender under any Loan Document would be subject to U.S. federal withholding Tax imposed by FATCA if such Lender were to fail to comply with the applicable reporting requirements of FATCA (including those contained in

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Section 1471(b) or 1472(b) of the Internal Revenue Code, as applicable), such Lender shall deliver to the Borrower and the Administrative Agent at the time or times prescribed by law and at such time or times reasonably requested by the Borrower or the Administrative Agent such documentation prescribed by Applicable Law (including as prescribed by Section 1471(b)(3)(C)(i) of the Internal Revenue Code) and such additional documentation reasonably requested by the Borrower or the Administrative Agent as may be necessary for the Borrower and the Administrative Agent to comply with their obligations under FATCA and to determine that such Lender has complied with such Lender’s obligations under FATCA or to determine the amount to deduct and withhold from such payment. Solely for purposes of this clause (D), “FATCA” shall include any amendments made to FATCA after the date of this Agreement.

Each Lender agrees that if any form or certification it previously delivered expires or becomes obsolete or inaccurate in any respect, it shall update such form or certification or promptly notify the Borrower and the Administrative Agent in writing of its legal inability to do so.

(h)Treatment of Certain Refunds. If any party determines, in its sole discretion exercised in good faith, that it has received a refund of any Taxes as to which it has been indemnified pursuant to this Section 2.15 (including by the payment of additional amounts pursuant to this Section 2.15), it shall pay to the indemnifying party an amount equal to such refund (but only to the extent of indemnity payments made under this Section with respect to the Taxes giving rise to such refund), net of all out-of-pocket expenses (including Taxes) of such indemnified party and without interest (other than any interest paid by the relevant Governmental Authority with respect to such refund). Such indemnifying party, upon the request of such indemnified party, shall repay to such indemnified party the amount paid over pursuant to this subsection (h) (plus any penalties, interest or other charges imposed by the relevant Governmental Authority) in the event that such indemnified party is required to repay such refund to such Governmental Authority. Notwithstanding anything to the contrary in this subsection (h), in no event will the indemnified party be required to pay any amount to an indemnifying party pursuant to this subsection (h) the payment of which would place the indemnified party in a less favorable net after-Tax position than the indemnified party would have been in if the Tax subject to indemnification and giving rise to such refund had not been deducted, withheld or otherwise imposed and the indemnification payments or additional amounts with respect to such Tax had never been paid. This subsection shall not be construed to require any indemnified party to make available its Tax returns (or any other information relating to its Taxes that it deems confidential) to the indemnifying party or any other Person.

(i)FATCA Withholding. For purposes of determining withholding Taxes imposed under FATCA, from and after the Closing Date, the Borrower and the Administrative Agent shall treat (and the Lenders hereby authorize the Administrative Agent to treat) the obligations of the Borrower set forth in this Agreement as not qualifying as a “grandfathered obligation” within the meaning of Treasury Regulation Sections 1.1471-2(b)(2)(i) and 1.1471-2T(b)(2)(i).

(j)Survival. Each party’s obligations under this Section 2.15 shall survive the resignation or replacement of the Administrative Agent or any assignment of rights by, or the replacement of, a Lender, the termination of the Commitments and the repayment, satisfaction or discharge of all obligations under any Loan Document.

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SECTION 2.16. Sharing of Payments, Etc.

(a)If any Lender shall obtain any payment (whether voluntary, involuntary, through the exercise of any right of set-off, or otherwise) on account of the Advances owing to it (other than pursuant to Section 2.08(c), 2.12, 2.15, 8.04(c) or 8.16 or in respect of Eurodollar Rate Advances converted into Base Rate Advances pursuant to Section 2.13) by the Borrower in excess of its ratable share of payments on account of the Advances to the Borrower obtained by all the Lenders, such Lender shall forthwith purchase from the other Lenders such participations in such Advances owing to them as shall be necessary to cause such purchasing Lender to share the excess payment ratably with each of them; provided, however, that if all or any portion of such excess payment is thereafter recovered from such purchasing Lender, such purchase from each Lender shall be rescinded and such Lender shall repay to the purchasing Lender the purchase price to the extent of such recovery together with an amount equal to such Lender’s ratable share (according to the proportion of (i) the amount of such Lender’s required repayment to (ii) the total amount so recovered from the purchasing Lender) of any interest or other amount paid or payable by the purchasing Lender in respect of the total amount so recovered. The Borrower agrees that any Lender so purchasing a participation from another Lender pursuant to this Section 2.16 may, to the fullest extent permitted by law, exercise all its rights of payment (including the right of set-off) with respect to such participation as fully as if such Lender were the direct creditor of the Borrower in the amount of such participation.

(b)If any Lender shall fail to make any payment required to be made by it pursuant to Sections 2.02(d) or 7.05, then the Administrative Agent may, in its discretion and notwithstanding any contrary provision hereof, (i) apply any amounts thereafter received by the Administrative Agent for the account of such Lender for the benefit of the Administrative Agent to satisfy such Lender’s obligations to it or them under such Section until all such unsatisfied obligations are fully paid, and/or (ii) hold any such amounts in a segregated account as cash collateral for, and application to, any future funding obligations of such Lender under any such Section, in the case of each of clauses (i) and (ii) above, in any order as determined by the Administrative Agent in its discretion.

SECTION 2.17. Mitigation Obligations; Replacement of Lenders.

(a)Designation of a Different Lending Office. If any Lender delivers a notice pursuant to Section 2.13, requests compensation under Section 2.12, or requires the Borrower to pay any Indemnified Taxes or additional amounts to any Lender or any Governmental Authority for the account of any Lender pursuant to Section 2.15, then such Lender shall (at the request of the Borrower) use reasonable efforts to designate a different Applicable Lending Office or to assign its rights and obligations hereunder to another of its offices, branches or Affiliates, if, in the judgment of such Lender, such designation or assignment (i) would eliminate or reduce amounts payable pursuant to Section 2.12 or 2.15, as the case may be, in the future, and (ii) would not subject such Lender to any unreimbursed cost or expense and would not otherwise be disadvantageous to such Lender. The Borrower hereby agrees to pay all reasonable costs and expenses incurred by any Lender in connection with any such designation or assignment.

(b)Replacement of Lenders. If any Lender delivers a notice pursuant to Section 2.13, requests compensation under Section 2.12, or requires the Borrower to pay any Indemnified Taxes or additional amounts to any Lender or any Governmental Authority for the

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account of any Lender pursuant to Section 2.15 and, in each case, such Lender has declined or is unable to designate a different Applicable Lending Office in accordance with Section 2.17(a), or if any Lender is a Declining Lender, a Defaulting Lender or a Non-Consenting Lender, then the Borrower may, at its sole expense and effort, upon notice to such Lender and the Administrative Agent, require such Lender to assign and delegate, without recourse (in accordance with and subject to the restrictions contained in, and consents required by, Section 8.07), all of its interests, rights (other than its existing rights to payments pursuant to Section 2.12 or 2.15) and obligations under this Agreement and the related Loan Documents to an Eligible Assignee that shall assume such obligations (which assignee may be another Lender, if such Lender accepts such assignment); provided that:

(i)the Borrower shall have paid to the Administrative Agent the assignment fee (if any) specified in Section 8.07(b)(iv);

(ii)such Lender shall have received payment of an amount equal to the outstanding principal of its Advances, together with all applicable accrued interest thereon, accrued fees and all other amounts payable to it hereunder and under the other Loan Documents (including any amounts under Section 8.04(c)) from the assignee (to the extent of such outstanding principal amounts and accrued interest and fees) or the Borrower (in the case of all other amounts);

(iii)in the case of any such assignment resulting from a claim for compensation under Section 2.12 or payments required to be made pursuant to Section 2.15, such assignment will result in a reduction in such compensation or payments thereafter;

(iv)no Default shall have occurred and be continuing;

(v)such assignment does not conflict with Applicable Law; and

(vi)in the case of any assignment resulting from a Lender becoming a Non-Consenting Lender, the applicable assignee shall have consented to the applicable amendment, waiver or consent.

A Lender shall not be required to make any such assignment or delegation if, prior thereto, as a result of a waiver by such Lender or otherwise, the circumstances entitling the Borrower to require such assignment and delegation cease to apply.

SECTION 2.18. Option to Increase Facility.

(c)Upon the written request of the Borrower delivered to the Administrative Agent on or before the date that falls 10 months after the Closing Date (the “Availability Date”), which request from the Borrower can be made no more than twice during the period from and including the Closing Date through the Availability Date (each such request in the form of Exhibit E hereto, a “Request for Facility Increase”), the Administrative Agent shall request that Lenders increase their Commitment under the Facility; provided, that (v) in connection with such request, the Borrower may, at its sole expense and effort, seek to obtain new Commitments from any Person that is not a Lender at such time if such Person is an Eligible Assignee, (w) no Lender

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shall be obligated to increase its Commitment without its prior written consent, (x) any such requested increase must be in a minimum additional aggregate amount of $50,000,000, and integral multiples of $10,000,000 in excess thereof, (y) after giving effect to the increase in Commitments, the sum of (i) the aggregate principal amount of all Advances (disregarding any repayments or prepayments of Advances occurring on or prior to the date of such increase) plus (ii) the Commitments in effect at such time shall not exceed $1,000,000,000 and (z) at the time of and after giving effect to the increase in Commitments and the concurrent funding of Advances, if any, the representations and warranties of the Borrower set forth herein are true and correct and no Default has occurred and is continuing and (z) such increased Commitment shall, for the avoidance of doubt, be on the same terms and conditions as the existing Commitments. In the event that the Administrative Agent does not receive any commitments from the existing Lenders and/or new Lenders to cover such requested increase within 30 days of receipt of any Request for Facility Increase, such Request for Facility Increase shall be deemed to have been withdrawn by the Borrower on such 30^th day. So long as no Default has occurred and is continuing and the Request for Facility Increase has not been withdrawn, any such increase shall be effective upon: (i) written notification from the Administrative Agent to the Borrower and the Lenders (each such notification in the form of Exhibit F hereto, (a “Confirmation of Facility Increase”) confirming the total amount of the increased Facility, describing each Lender or new Lender that has agreed to participate in such increase and each Lender’s Commitment after giving effect to such increase; (ii) the execution and delivery by each such Lender of a Lender Commitment Increase Agreement, in the form of Exhibit G hereto (a “Lender Commitment Increase Agreement”), or a Lender Joinder Agreement, in the form of Exhibit H hereto (a “Lender Joinder Agreement”), as applicable (provided that any new Lender making a commitment pursuant to a Lender Joinder Agreement shall make a commitment of at least $5,000,000), and (iii) delivery by Borrower to the appropriate Lender of replacement or new notes, as applicable, to reflect such increase. Upon the effectiveness of a Commitment of any new Lender, such new Lender (I) shall be deemed to be a “Lender” hereunder, and henceforth shall be entitled to all the rights of, and benefits accruing to, Lenders hereunder and (II) shall be bound by all agreements, acknowledgements and other obligations of Lenders hereunder and under the other Loan Documents.

ARTICLE III

CONDITIONS PRECEDENT

SECTION 3.01. Conditions Precedent to Effectiveness of this Agreement and Closing Date Extension of Credit.

This Agreement and the obligation of each Lender, as applicable, to make the Extension of Credit to be made by it hereunder on the Closing Date shall take effect on the Closing Date, subject to each of the following conditions precedent being satisfied on or before such date:

(a)The Administrative Agent shall have received on or before the Closing Date the following, each dated the Closing Date, in form and substance reasonably satisfactory to the Administrative Agent in sufficient copies for each Lender:

(i)Certified copies of the Borrower’s certificate of incorporation and bylaws, and resolutions of the board of directors of the Borrower approving this Agreement, a certificate of good standing for the Borrower from its jurisdiction of incorporation and all

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documents evidencing other necessary corporate action and Governmental Approvals, if any, with respect to this Agreement.

(ii)A certificate of the Secretary or Assistant Secretary of the Borrower certifying the names and true signatures of the officers of the Borrower authorized to sign this Agreement and the other documents to be delivered by the Borrower hereunder.

(iii)A favorable opinion of counsel for the Borrower (which may be an attorney of American Electric Power Service Corporation), substantially in the form of Exhibit C hereto and as to such other matters as any Lender through the Administrative Agent may reasonably request.

(b)On the Closing Date, the following statements shall be true and the Administrative Agent shall have received for the account of each Lender a certificate signed by a duly authorized officer of the Borrower, dated the Closing Date, stating that:

(i)The representations and warranties of the Borrower contained in Section 4.01 are true and correct in all material respects on and as of the Closing Date, as though made on and as of such date, and

(ii)No event has occurred and is continuing that constitutes a Default.

(c)The Borrower shall have paid all fees and expenses of the Administrative Agent, the Joint Lead Arrangers and the Lenders then due and payable in accordance with the terms of the Loan Documents (including the fees and expenses of counsel to the Administrative Agent to the extent then due and payable).

(d)The Administrative Agent shall have received counterparts of this Agreement, executed and delivered by the Borrower and the Lenders.

(e)The Administrative Agent shall have received all promissory notes (if any) requested by the Lenders pursuant to Section 2.07(d), duly completed and executed by the Borrower and payable to such Lenders.

(f)The Administrative Agent shall have received copies of the Disclosure Documents.

(g)The Administrative Agent shall have received all documentation and information required by regulatory authorities under applicable “know your customer” and anti-money laundering rules and regulations, including, without limitation, the Patriot Act, to the extent such documentation or information is requested by the Administrative Agent on behalf of the Lenders prior to the Closing Date.

(h)The Administrative Agent shall have received copies or other evidence of such other approvals and such other opinions or documents as may be reasonably requested by the Administrative Agent or by any Lender through the Administrative Agent.

(i)The Administrative Agent shall have received a Notice of Borrowing for the Extension of Credit to be made on the Closing Date.

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SECTION 3.02. Conditions Precedent to Each Extension of Credit Following the Closing Date.

The making of any Extension of Credit following the Closing Date pursuant to Section 2.18 shall be subject to the satisfaction of the following conditions precedent:

(a)The following statements shall be true (and each of the giving of the applicable Notice of Borrowing and the acceptance by the Borrower of the proceeds of any Borrowing shall constitute a representation and warranty by the Borrower that on the date of such Borrowing such statements are true):

(i)The representations and warranties of the Borrower contained in Section 4.01 (other than the representation and warranty in Section 4.01(e) and the representation and warranty set forth in the last sentence of Section 4.01(f)) are true and correct in all material respects (or, if already qualified by materiality, in all respects) on and as of the date of such Borrowing, before and after giving effect to such Borrowing and to the application of the proceeds therefrom, as though made on and as of such date; and

(ii)No event has occurred and is continuing or would result from such Borrowing or from the application of the proceeds therefrom, that constitutes a Default.

(b)The Administrative Agent shall have received a Notice of Borrowing for any Extension of Credit to be made on such date.

(c)The Administrative Agent shall have received copies or other evidence of such other approvals and such other opinions or documents as may be reasonably requested by the Administrative Agent or by any Lender through the Administrative Agent.

ARTICLE IV

REPRESENTATIONS AND WARRANTIES

SECTION 4.01. Representations and Warranties of the Borrower.

The Borrower represents and warrants as follows:

(a)The Borrower is a corporation duly organized, validly existing and in good standing under the laws of the jurisdiction in which it is incorporated, and each Significant Subsidiary is duly organized, validly existing and in good standing under the laws of the jurisdiction in which it is incorporated or otherwise organized.

(b)The execution, delivery and performance by the Borrower of each Loan Document, and the consummation of the transactions contemplated hereby, are within the Borrower’s corporate powers, have been duly authorized by all necessary action, and do not contravene (i) the Borrower’s certificate of incorporation or by-laws, (ii) law binding or affecting the Borrower or (iii) any contractual restriction binding on or affecting the Borrower or any of its properties.

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(c)Each Loan Document has been duly executed and delivered by the Borrower. Each Loan Document is the legal, valid and binding obligation of the Borrower enforceable against the Borrower in accordance with its terms, except as the enforceability thereof may be limited by bankruptcy, insolvency, fraudulent conveyance or other similar laws affecting the enforcement of creditors’ rights in general, and except as the availability of the remedy of specific performance is subject to general principles of equity (regardless of whether such remedy is sought in a proceeding in equity or at law) and subject to requirements of reasonableness, good faith and fair dealing.

(d)No authorization or approval or other action by, and no notice to or filing with, any Governmental Authority or any other third party is required for the due execution, delivery and performance by the Borrower of any Loan Document.

(e)There is no pending or threatened action, suit, investigation, litigation or proceeding, including, without limitation, any Environmental Action, affecting the Borrower or any of its Significant Subsidiaries before any Governmental Authority or arbitrator that is reasonably likely to have a Material Adverse Effect, except as disclosed in the Disclosure Documents.

(f)The consolidated balance sheets of the Borrower and its Consolidated Subsidiaries as at December 31, 2019, and the related consolidated statements of income and cash flows of the Borrower and its Consolidated Subsidiaries for the fiscal period then ended (accompanied by an opinion of PricewaterhouseCoopers, an independent registered public accounting firm), copies of which have been furnished to each Lender, fairly present the consolidated financial condition of the Borrower and its Consolidated Subsidiaries as at such dates and the consolidated results of the operations of the Borrower and its Consolidated Subsidiaries for the periods ended on such dates, all in accordance with generally accepted accounting principles consistently applied. Since December 31, 2019, there has been no Material Adverse Change. As of the Closing Date, the information included in the Beneficial Ownership Certification is true and correct in all respects.

(g)No written statement, information, report, financial statement, exhibit or schedule furnished by or on behalf of the Borrower to the Administrative Agent or any Lender in connection with the syndication or negotiation of this Agreement or included herein or delivered pursuant hereto contained, contains, or will contain any material misstatement of fact or intentionally omitted, omits, or will omit to state any material fact necessary to make the statements therein, in the light of the circumstances under which they were, are, or will be made, not misleading.

(h)Except as disclosed in the Disclosure Documents, the Borrower and each Significant Subsidiary is in material compliance with all laws (including ERISA and Environmental Laws) rules, regulations and orders of any Governmental Authority applicable to it.

(i)No failure to satisfy the minimum funding standard applicable to a Plan for a plan year (as described in Section 302 of ERISA and Section 412 of the Internal Revenue Code) that could reasonably be expected to have a Material Adverse Effect, whether or not waived, has occurred with respect to any Plan. The Borrower has not incurred, and does not presently expect

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to incur, any withdrawal liability under Title IV of ERISA with respect to any Multiemployer Plan that could reasonably be expected to have a Material Adverse Effect. The Borrower and each of its ERISA Affiliates have complied in all material respects with ERISA and the Internal Revenue Code. The Borrower and each of its Subsidiaries have complied in all material respects with foreign law applicable to its Foreign Plans, if any. As used herein, the term “Plan” means an “employee pension benefit plan” (as defined in Section 3 of ERISA) which is and has been established or maintained, or to which contributions are or have been made or should be made according to the terms of the plan, by the Borrower or any of its ERISA Affiliates. The term “Multiemployer Plan” means any Plan which is a “multiemployer plan” (as such term is defined in Section 4001(a)(3) of ERISA). The term “Foreign Plan” means any pension, profit-sharing, deferred compensation, or other employee benefit plan, program or arrangement maintained by any Subsidiary which, under applicable local foreign law, is required to be funded through a trust or other funding vehicle.

(j)The Borrower and its Subsidiaries have filed or caused to be filed all material Federal, state and local tax returns that are required to be filed by them, and have paid or caused to be paid all material taxes shown to be due and payable on such returns or on any assessments received by them (to the extent that such taxes and assessments have become due and payable) other than those taxes contested in good faith and for which adequate reserves have been established in accordance with GAAP.

(k)The Borrower is not engaged in the business of extending credit for the purpose of buying or carrying Margin Stock, and no proceeds of any Advance will be used to buy or carry any Margin Stock or to extend credit to others for the purpose of buying or carrying any Margin Stock. Not more than 25% of the assets of the Borrower and the Significant Subsidiaries that are subject to the restrictions of Section 5.02(a), (c) or (d) constitute Margin Stock.

(l)Neither the Borrower nor any Significant Subsidiary is an “investment company,” or an “affiliated person” of, or “promoter” or “principal underwriter” for, an “investment company”, as such terms are defined in the Investment Company Act of 1940, as amended. Neither the making of any Extension of Credit, the application of the proceeds or repayment thereof by the Borrower nor the consummation of the other transactions contemplated hereby will violate any provision of such Act or any rule, regulation or order of the SEC thereunder.

(m)All Significant Subsidiaries as of the date hereof are listed on Schedule 4.01(m) hereto.

(n)The Borrower has implemented and maintains in effect policies and procedures designed to ensure compliance by the Borrower, its Subsidiaries and their respective directors, officers, employees and agents with Anti-Corruption Laws and applicable Sanctions, and the Borrower, its Subsidiaries and their respective directors and officers and, to the knowledge of the Borrower, its employees and agents, are in compliance with Anti-Corruption Laws and applicable Sanctions in all material respects. None of (a) the Borrower, any Subsidiary or any of their respective directors or officers, or (b) to the knowledge of the Borrower, any employee or agent of the Borrower or any Subsidiary that will act in any capacity in connection with or benefit from the credit facility established hereby, is a Sanctioned Person. No Borrowing or use of proceeds thereof or other transaction contemplated by this Agreement will violate Anti-Corruption Laws or applicable Sanctions.

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ARTICLE V

COVENANTS OF THE BORROWER

SECTION 5.01. Affirmative Covenants.

So long as any Advance or any other amount payable hereunder shall remain unpaid or any Lender shall have any Commitment hereunder, the Borrower will:

(a)Preservation of Existence, Etc. Preserve and maintain, and cause each Significant Subsidiary to preserve and maintain, its corporate, partnership or limited liability company (as the case may be) existence and all material rights (charter and statutory) and franchises; provided, however, that the Borrower and any Significant Subsidiary may consummate any merger or consolidation permitted under Section 5.02(a); and providedfurther that neither the Borrower nor any Significant Subsidiary shall be required to preserve any right or franchise if (i) the board of directors of the Borrower or such Significant Subsidiary, as the case may be, shall determine that the preservation thereof is no longer desirable in the conduct of the business of the Borrower or such Significant Subsidiary, as the case may be, and that the loss thereof is not disadvantageous in any material respect to the Borrower or such Significant Subsidiary, as the case may be, or to the Lenders; (ii) required in connection with or pursuant to any Restructuring Law; or (iii) required in connection with the RTO Transaction; and providedfurther, that no Significant Subsidiary shall be required to preserve and maintain its corporate existence if (x) the loss thereof is not disadvantageous in any material respect to the Borrower or to the Lenders or (y) required in connection with or pursuant to any Restructuring Law or (z) required in connection with the RTO Transaction.

(b)Compliance with Laws, Etc. Comply, and cause each Significant Subsidiary to comply, in all material respects, with Applicable Law, with such compliance to include, without limitation, compliance with ERISA and Environmental Laws.

(c)Performance and Compliance with Other Agreements. Perform and comply, and cause each Significant Subsidiary to perform and comply, with the provisions of each indenture, credit agreement, contract or other agreement by which it is bound, the non-performance or non-compliance with which would result in a Material Adverse Change.

(d)Inspection Rights. At any reasonable time and from time to time, permit the Administrative Agent or any Lender or any agents or representatives thereof to examine and make copies of and abstracts from the records and books of account of, and visit the properties of, the Borrower and any Significant Subsidiary and to discuss the affairs, finances and accounts of the Borrower and any Significant Subsidiary with any of their officers or directors and with their independent certified public accountants.

(e)Maintenance of Properties, Etc. Maintain and preserve, and cause each Significant Subsidiary to maintain and preserve, all of its properties that are used or useful in the conduct of its business in good working order and condition, ordinary wear and tear excepted and except as required in connection with or pursuant to any Restructuring Law or in connection with RTO Transaction.

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(f)Maintenance of Insurance. Maintain, and cause each Significant Subsidiary to maintain, insurance with responsible and reputable insurance companies or associations in such amounts and covering such risks as is usually carried by companies engaged in similar businesses and owning similar properties; provided, however, that the Borrower and each Significant Subsidiary may self-insure to the same extent as other companies engaged in similar businesses and owning similar properties and to the extent consistent with prudent business practice.

(g)Payment of Taxes, Etc. Pay and discharge, and cause each of its Subsidiaries to pay and discharge, before the same shall become delinquent, (i) all taxes, assessments and governmental charges or levies imposed upon it or upon its property and (ii) all lawful claims that, if unpaid, might by law become a Lien upon its property; provided, however, that neither the Borrower nor any of its Subsidiaries shall be required to pay or discharge any such tax, assessment, charge or claim that is being contested in good faith and by proper proceedings and as to which adequate reserves are being maintained in accordance with GAAP, unless and until any Lien resulting therefrom attaches to its property and becomes enforceable against its other creditors.

(h)Keeping of Books. Keep, and cause each Significant Subsidiary to keep, proper books of record and account, in which full and correct entries shall be made of all financial transactions and the assets and business of the Borrower and each such Significant Subsidiary in accordance with GAAP.

(i)Reporting Requirements. Furnish to the Lenders:

(i)as soon as available and in any event within 60 days after the end of each of the first three quarters of each fiscal year of the Borrower, a copy of the Borrower’s Quarterly Report on Form 10-Q for such quarter, as filed with the SEC, which shall contain a consolidated balance sheet of the Borrower and its Subsidiaries as of the end of such quarter and consolidated statements of income and cash flows of the Borrower and its Subsidiaries for the period commencing at the end of the previous fiscal year and ending with the end of such quarter, duly certified (subject to year-end audit adjustments) by the chief financial officer, chief accounting officer, treasurer or assistant treasurer of the Borrower as having been prepared in accordance with generally accepted accounting principles and a certificate of the chief financial officer, chief accounting officer, treasurer or assistant treasurer of the Borrower as to compliance with the terms of this Agreement and (A) certifying that there have been no Subsidiaries that have become Significant Subsidiaries at any time during such period, or any Subsidiaries that have ceased to be Significant Subsidiaries at any time during such period, in each case except as expressly identified in such certificate, and (B) setting forth in reasonable detail the calculations necessary to demonstrate compliance with Section 5.03, provided that in the event of any change in GAAP used in the preparation of such financial statements, the Borrower shall also provide, if necessary for the determination of compliance with Section 5.03, a statement of reconciliation conforming such financial statements to GAAP in effect on the date hereof;

(ii)as soon as available and in any event within 120 days after the end of each fiscal year of the Borrower, a copy of the Borrower’s Annual Report on Form 10-K for

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such year, as filed with the SEC, which shall contain a copy of the annual audit report for such year for the Borrower and its Subsidiaries, containing a consolidated balance sheet of the Borrower and its Subsidiaries as of the end of such fiscal year and consolidated statements of income and cash flows of the Borrower and its Subsidiaries for such fiscal year, in each case accompanied by an opinion by Deloitte & Touche LLP or another independent registered public accounting firm acceptable to the Required Lenders, and consolidating statements of income and cash flows of the Borrower and its Subsidiaries for such fiscal year, and a certificate of the chief financial officer, chief accounting officer, treasurer or assistant treasurer of the Borrower as to compliance with the terms of this Agreement and (A) certifying that there have been no Subsidiaries that have become Significant Subsidiaries at any time during such period, or any Subsidiaries that have ceased to be Significant Subsidiaries at any time during such period, in each case except as expressly identified in such certificate, and (B) setting forth in reasonable detail the calculations necessary to demonstrate compliance with Section 5.03, provided that in the event of any change in GAAP used in the preparation of such financial statements, the Borrower shall also provide, if necessary for the determination of compliance with Section 5.03, a statement of reconciliation conforming such financial statements to GAAP in effect on the date hereof;

(iii)as soon as possible and in any event within five days after the chief financial officer or treasurer of the Borrower obtains knowledge of the occurrence of each Default continuing on the date of such statement, a statement of the chief financial officer or treasurer of the Borrower setting forth details of such Default and the action that the Borrower has taken and proposes to take with respect thereto;

(iv)promptly after the sending or filing thereof, copies of all Reports on Form 8-K that the Borrower or any Significant Subsidiary files with the SEC or any national securities exchange;

(v)promptly after the commencement thereof, notice of all actions and proceedings before any Governmental Authority or arbitrator affecting the Borrower or any Significant Subsidiary of the type described in Section 4.01(e); and

(vi)any change in the information provided in the Beneficial Ownership Certification that would result in a change to the list of beneficial owners identified in parts (c) or (d) of such certification;

(vii)such other information respecting the Borrower or any of its Subsidiaries as any Lender through the Administrative Agent may from time to time reasonably request.

Notwithstanding the foregoing, the information required to be delivered pursuant to clauses (i), (ii) and (iv) shall be deemed to have been delivered if such information shall be available on the website of the SEC at http://www.sec.gov or any successor website; provided that the compliance certificates required under clauses (i) and (ii) shall be delivered in the manner specified in Section 8.02(b).

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(j)Compliance with Anti-Corruption Laws and Sanctions. Maintain in effect and enforce policies and procedures designed to ensure compliance by the Borrower, its Subsidiaries and their respective directors, officers, employees and agents with Anti-Corruption Laws and applicable Sanctions.

SECTION 5.02. Negative Covenants.

So long as any Advance or any other amount payable hereunder shall remain unpaid or any Lender shall have any Commitment hereunder, the Borrower agrees that it will not:

(a)Mergers, Etc. Merge or consolidate with or into any Person, or permit any Significant Subsidiary to do so, except that (i) any Subsidiary may merge or consolidate with or into any other Subsidiary of the Borrower, (ii) any Subsidiary may merge into the Borrower, (iii) any Significant Subsidiary may merge with or into any other Person so long as such Significant Subsidiary continues to be a Significant Subsidiary of the Borrower and (iv) the Borrower may merge with any other Person so long as the successor entity (if other than the Borrower) assumes, in form reasonably satisfactory to the Administrative Agent, all of the obligations of the Borrower under this Agreement and the other Loan Documents, is incorporated or otherwise organized under the laws of a state of the United States of America or the District of Columbia and has long-term senior unsecured debt ratings issued (and confirmed after giving effect to such merger) by S&P or Moody’s of at least BBB- and Baa3, respectively (or if no such ratings have been issued, commercial paper ratings issued (and confirmed after giving effect to such merger) by S&P and Moody’s of at least A-3 and P-3, respectively), provided, in each case, that no Default shall have occurred and be continuing at the time of such proposed transaction or would result therefrom.

(b)Stock of Significant Subsidiaries. Sell, lease, transfer or otherwise dispose of, other than (i) in connection with an RTO Transaction, but only if no Default or Event of Default has occurred and is continuing or would result from such RTO Transaction, or (ii) pursuant to the requirements of any Restructuring Law, equity interests in any Significant Subsidiary of the Borrower (other than AEP Energy Services, Inc. or CSW Energy, Inc.) if such Significant Subsidiary would cease to be a Subsidiary as a result of such sale, lease, transfer or disposition.

(c)Sales, Etc. of Assets. Sell, lease, transfer or otherwise dispose of, or permit any Significant Subsidiary (other than AEP Energy Services, Inc. or CSW Energy, Inc.) to sell, lease, transfer or otherwise dispose of, any assets, or grant any option or other right to purchase, lease or otherwise acquire any assets, except (i) sales in the ordinary course of its business, (ii) sales, leases, transfers or dispositions of assets to any Person that is not a wholly-owned Subsidiary of the Borrower that in the aggregate do not exceed 20% of the Consolidated Tangible Net Assets of the Borrower and its Subsidiaries, whether in one transaction or a series of transactions, (iii) other sales, leases, transfers and dispositions made in connection with an RTO Transaction or pursuant to the requirements of any Restructuring Law or to a wholly owned Subsidiary of the Borrower, or (iv) sales of pollution control assets to a state or local government or any political subdivision or agency thereof in connection with any transaction with such Person pursuant to which such Person sells or otherwise transfers such pollution control assets back to the Borrower or a Subsidiary under an installment sale, loan or similar agreement, in each case in connection with the issuance of pollution control or similar bonds.

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(d)Liens, Etc. Create or suffer to exist, or permit any Significant Subsidiary to create or suffer to exist, any Lien on or with respect to any of its properties, including, without limitation, on or with respect to equity interests in any Subsidiary of the Borrower, whether now owned or hereafter acquired, or assign, or permit any Significant Subsidiary to assign, any right to receive income (other than in connection with Stranded Cost Recovery Bonds and the sale of accounts receivable by the Borrower), other than (i) Permitted Liens, (ii) the Liens existing on the date hereof, (iii) Liens securing first mortgage bonds issued by any Subsidiary of the Borrower the rates or charges of which are regulated by the Federal Energy Regulatory Commission or any state governmental authority, provided that the aggregate principal amount of such first mortgage bonds of any such Subsidiary do not exceed 66 2/3% of the net value of plant, property and equipment of such Subsidiary and (iv) the replacement, extension or renewal of any Lien permitted by clauses (ii) and (iii) above upon or in the same property theretofore subject thereto or the replacement, extension or renewal (without increase in the amount or change in any direct or contingent obligor) of the Debt secured thereby.

(e)Restrictive Agreements. Enter into, or permit any Significant Subsidiary to enter into (except in connection with or pursuant to any Restructuring Law), any agreement after the date hereof, or amend, supplement or otherwise modify any agreement existing on the date hereof, that imposes any restriction on the ability of any Significant Subsidiary to make payments, directly or indirectly, to its shareholders by way of dividends, advances, repayment of loans or intercompany charges, expenses and accruals or other returns on investments that is more restrictive than any such restriction applicable to such Significant Subsidiary on the date hereof; provided, however, that any Significant Subsidiary may agree to a financial covenant limiting its ratio of Consolidated Debt to Consolidated Capital to no more than 0.675 to 1.000.

(f)ERISA. (i) Terminate or withdraw from, or permit any of its ERISA Affiliates to terminate or withdraw from, any Plan with respect to which the Borrower or any of its ERISA Affiliates may have any liability by reason of such termination or withdrawal, if such termination or withdrawal could have a Material Adverse Effect, (ii) incur a full or partial withdrawal, or permit any ERISA Affiliate to incur a full or partial withdrawal, from any Multiemployer Plan with respect to which the Borrower or any of its ERISA Affiliates may have any liability by reason of such withdrawal, if such withdrawal could have a Material Adverse Effect, (iii) otherwise fail, or permit any of its ERISA Affiliates to fail, to comply in all material respects with ERISA or the related provisions of the Internal Revenue Code if such noncompliances, singly or in the aggregate, could have a Material Adverse Effect, or (iv) fail, or permit any of its Subsidiaries to fail, to comply with Applicable Law with respect to any Foreign Plan if such noncompliances, singly or in the aggregate, could have a Material Adverse Effect.

(g)Margin Stock. Use the proceeds of any Extension of Credit to buy or carry Margin Stock.

(h)No Violation of Anti-Corruption Laws or Sanctions. Request any Borrowing, or use or permit any of its Subsidiaries or its or their respective directors, officers, employees and agents to use, directly or, to the actual knowledge of the Borrower or any of its Subsidiaries, indirectly, the proceeds of any Borrowing (A) in furtherance of an offer, payment, promise to pay, or authorization of the payment or giving of money, or anything else of value, to any Person in violation of any Anti-Corruption Laws, (B) for the purpose of funding, financing or facilitating any activities, business or transaction of or with any Sanctioned Person, or in any

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Sanctioned Country, or (C) in any manner that would result in the violation of any Sanctions applicable to any party hereto.

SECTION 5.03. Financial Covenant.

So long as any Advance shall remain unpaid or any Lender shall have any Commitment hereunder, the Borrower will maintain a ratio of Consolidated Debt to Consolidated Capital, as of the last day of each March, June, September and December, of not greater than 0.675 to 1.000.

ARTICLE VI

EVENTS OF DEFAULT

SECTION 6.01. Events of Default.

If any of the following events (“Events of Default”) shall occur and be continuing:

(a)The Borrower shall fail to pay any principal of any Advance when the same becomes due and payable, or shall fail to pay any interest on any Advance or make any other payment of fees or other amounts payable under this Agreement within five days after the same becomes due and payable; or

(b)Any representation or warranty made by the Borrower herein or by the Borrower (or any of its officers) in connection with this Agreement shall prove to have been incorrect in any material respect when made; or

(c)(i) The Borrower shall fail to perform or observe any term, covenant or agreement contained in Section 5.01(a), 5.01(i)(iii) or 5.02 (other than Section 5.02(f)) or (ii) the Borrower shall fail to perform or observe any other term, covenant or agreement contained in this Agreement or any other Loan Document if such failure shall remain unremedied for 30 days after written notice thereof shall have been given to the Borrower by the Administrative Agent or any Lender; or

(d)Any event shall occur or condition shall exist under any agreement or instrument relating to Debt of the Borrower (but excluding Debt outstanding hereunder) or any Significant Subsidiary outstanding in a principal or notional amount of at least $50,000,000 in the aggregate if the effect of such event or condition is to accelerate or require early termination of the maturity or tenor of such Debt, or any such Debt shall be declared to be due and payable, or required to be prepaid or redeemed (other than by a regularly scheduled required prepayment or redemption), terminated, purchased or defeased, or an offer to prepay, redeem, purchase or defease such Debt shall be required to be made, in each case prior to the stated maturity or the original tenor thereof; or

(e)The Borrower or any Significant Subsidiary shall generally not pay its debts as such debts become due, or shall admit in writing its inability to pay its debts generally, or shall make a general assignment for the benefit of creditors; or any proceeding shall be instituted by or against the Borrower or any Significant Subsidiary seeking to adjudicate it a bankrupt or insolvent, or seeking liquidation, winding up, reorganization, arrangement, adjustment, protection, relief, or composition of it or its debts under any law relating to bankruptcy, insolvency or reorganization or relief of debtors, or seeking the entry of an order for relief or the

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appointment of a receiver, trustee, custodian or other similar official for it or for any substantial part of its property and, in the case of any such proceeding instituted against it (but not instituted by it), either such proceeding shall remain undismissed or unstayed for a period of 60 days, or any of the actions sought in such proceeding (including, without limitation, the entry of an order for relief against, or the appointment of a receiver, trustee, custodian or other similar official for, it or for any substantial part of its property) shall occur; or the Borrower or any Significant Subsidiary shall take any corporate action to authorize any of the actions set forth above in this subsection (e); or

(f)(i) Any entity, person (within the meaning of Section 14(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act) that as of the date hereof was beneficial owner (as defined in Rule 13d-3 under the Exchange Act) of less than 30% of the Borrower’s Voting Stock shall acquire a beneficial ownership (within the meaning of Rule 13d-3 of the SEC under the Exchange Act), directly or indirectly, of Voting Stock of the Borrower (or other securities convertible into such Voting Stock) representing 30% or more of the combined voting power of all Voting Stock of the Borrower; or (ii) during any period of up to 24 consecutive months, commencing after the date hereof, individuals who at the beginning of such 24-month period were directors of the Borrower shall cease for any reason to constitute a majority of the board of directors of the Borrower, provided that any person becoming a director subsequent to the date hereof, whose election, or nomination for election by the Borrower’s shareholders, was approved by a vote of at least a majority of the directors of the board of directors of the Borrower as comprised as of the date hereof shall be, for purposes of this provision, considered as though such person were a member of the board as of the date hereof; or

(g)Any judgment or order for the payment of money in excess of $50,000,000 in the case of the Borrower or any Significant Subsidiary to the extent not paid or insured shall be rendered against the Borrower or any Significant Subsidiary and either (i) enforcement proceedings shall have been commenced by any creditor upon such judgment or order or (ii) there shall be any period of 30 consecutive days during which a stay of enforcement of such judgment or order, by reason of a pending appeal or otherwise, shall not be in effect; or

(h)(i) The termination of or withdrawal from the United Mine Workers’ of America 1974 Pension Trust by the Borrower or any of its ERISA Affiliates shall have occurred and the liability of the Borrower and its ERISA Affiliates related to such termination or withdrawal exceeds $75,000,000 in the aggregate; or (ii) any other ERISA Event shall have occurred and the liability of the Borrower and its ERISA Affiliates related to such ERISA Event exceeds $50,000,000;

then, and in any such event, the Administrative Agent (i) shall at the request, or may with the consent, of the Required Lenders, by notice to the Borrower, declare the obligation of each Lender to make Extensions of Credit to be terminated, whereupon the same shall forthwith terminate, and (ii) shall at the request, or may with the consent, of the Required Lenders, by notice to the Borrower, declare the outstanding Borrowings, all interest thereon and all other amounts payable under this Agreement to be forthwith due and payable, whereupon the outstanding Borrowings, all such interest and all such amounts shall become and be forthwith due and payable by the Borrower, without presentment, demand, protest or further notice of any kind, all of which are hereby expressly waived by the Borrower; provided, however, that in the

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event of an actual or deemed entry of an order for relief with respect to the Borrower under the Federal Bankruptcy Code, (A) the obligation of each Lender to make Extensions of Credit shall automatically be terminated and (B) the outstanding Borrowings, all such interest and all such amounts shall automatically become and be due and payable, without presentment, demand, protest or any notice of any kind, all of which are hereby expressly waived by the Borrower.

ARTICLE VII

THE ADMINISTRATIVE AGENT

SECTION 7.01. Authorization and Action.

Each Lender hereby appoints and authorizes the Administrative Agent to take such action as agent on its behalf and to exercise such powers and discretion under this Agreement as are delegated to the Administrative Agent by the terms hereof, together with such powers and discretion as are reasonably incidental thereto. As to any matters expressly provided for in this Agreement as being subject to the discretion of the Administrative Agent, such matters shall be subject to the sole discretion of the Administrative Agent, its directors, officers, agents and employees. As to any matters not expressly provided for by this Agreement (including, without limitation, enforcement or collection of the outstanding Borrowings), the Administrative Agent shall not be required to exercise any discretion or take any action, but shall be required to act or to refrain from acting (and shall be fully protected in so acting or refraining from acting) upon the instructions of the Required Lenders, and such instructions shall be binding upon all Lenders; provided, however, that the Administrative Agent shall not be required to take any action that exposes the Administrative Agent to personal liability or that is contrary to this Agreement or Applicable Law. The Administrative Agent agrees to give to each Lender prompt notice of each notice given to it by the Borrower pursuant to the terms of this Agreement.

SECTION 7.02. Agent’s Reliance, Etc.

Neither the Administrative Agent nor any of its directors, officers, agents or employees shall be liable for any action taken or omitted to be taken by it or them under or in connection with this Agreement, except for its or their own gross negligence or willful misconduct as determined in a final, non-appealable judgment by a court of competent jurisdiction. Without limitation of the generality of the foregoing, the Administrative Agent: (i) may treat each Lender recorded in the Register as the owner of the Commitment recorded for such Lender in the Register until the Administrative Agent receives and accepts an Assignment and Assumption entered into by such Lender, as assignor, and an Eligible Assignee, as assignee, as provided in Section 8.07 and except as provided otherwise in Section 8.16; (ii) may consult with legal counsel (including counsel for the Borrower), independent public accountants and other experts selected by it and shall not be liable for any action taken or omitted to be taken in good faith by it in accordance with the advice of such counsel, accountants or experts; (iii) makes no warranty or representation to any Lender and shall not be responsible to any Lender for any statements, warranties or representations (whether written or oral) made in or in connection with this Agreement; (iv) shall not have any duty to ascertain or to inquire as to the performance or observance of any of the terms, covenants or conditions of this Agreement on the part of any Lender or to inspect the property (including the books and records) of any Lender; (v) shall not be responsible to any Lender for the due execution, legality, validity, enforceability, genuineness, sufficiency or value of, this Agreement or any other instrument or document

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furnished pursuant thereto; (vi) shall incur no liability under or in respect of this Agreement by acting upon any notice, consent, certificate or other instrument or writing (which may be by fax) believed by it to be genuine and signed or sent by the proper party or parties; and (vii) shall not have any fiduciary duty to any other Lender.

SECTION 7.03. Administrative Agent and its Affiliates.

With respect to its Commitments and the Advances made by it, the Person serving as Administrative Agent shall have the same rights and powers in its capacity as a Lender under this Agreement as any other Lender and may exercise the same as though it were not the Administrative Agent; and the term “Lender” or “Lenders” shall, unless otherwise expressly indicated, include the Person serving as the Administrative Agent hereunder in its individual capacity. Such Person and its Affiliates may accept deposits from, lend money to, act as trustee under indentures of, own securities of, act as the financial advisor for, accept investment banking engagements from and generally engage in any kind of business with, the Borrower, any Lender and any of their respective Subsidiaries or Affiliates thereof as if such Person were not the Administrative Agent and without any duty to account therefor to the Lenders.

SECTION 7.04. Lender Credit Decision.

Each Lender acknowledges that it has, independently and without reliance upon the Administrative Agent or any other Lender and based on the financial statements referred to in Section 4.01 and such other documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each Lender also acknowledges that it will, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under this Agreement.

SECTION 7.05. Indemnification.

Each Lender severally agrees to indemnify the Administrative Agent and each of its Related Parties (to the extent not promptly reimbursed by the Borrower and without limiting its obligation to do so) from and against such Lender’s ratable share (determined as provided below) of any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever that may be imposed on, incurred by, or asserted against the Administrative Agent or such Related Party in any way relating to or arising out of this Agreement or any action taken or omitted by such Person under this Agreement; provided, however, that no Lender shall be liable, as to the Administrative Agent or any of its Related Parties, for any portion of such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements resulting from the gross negligence or willful misconduct of such Person as determined in a final, non-appealable judgment by a court of competent jurisdiction. Without limitation of the foregoing, each Lender agrees to reimburse the Administrative Agent and each of its Related Parties promptly upon demand for its ratable share of any costs and expenses (including, without limitation, fees and reasonable expenses of counsel) payable by the Borrower under Section 8.04, to the extent that the Administrative Agent or such Related Party is not promptly reimbursed for such costs and expenses by the Borrower after request therefor and without limiting the Borrower’s obligation to do so. For purposes of this Section 7.05, the Lenders’ respective ratable shares of any amount

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shall be determined, at any time, according to the sum of (i) the aggregate principal amount of the Advances outstanding at such time and owing to the respective Lenders and (ii) the aggregate unused portions of their respective Commitments at such time. In the event that any Lender shall have failed to make any Advance as required hereunder, such Lender’s Commitment shall be considered to be unused for purposes of this Section 7.05 to the extent of the amount of such Advance. The failure of any Lender to reimburse the Administrative Agent or any of its Related Parties promptly upon demand for its ratable share of any amount required to be paid by the Lender to the Administrative Agent or such Related Party as provided herein shall not relieve any other Lender of its obligation hereunder to reimburse the Administrative Agent or such Related Party for its ratable share of such amount, but no Lender shall be responsible for the failure of any other Lender to reimburse the Administrative Agent or such Related Party for such other Lender’s ratable share of such amount. Without prejudice to the survival of any other agreement of any Lender hereunder, the agreement and obligations of each Lender contained in this Section 7.05 shall survive the payment in full of principal, interest and all other amounts payable hereunder.

SECTION 7.06. Successor Agent.

The Administrative Agent may resign at any time by giving written notice thereof to the Lenders and the Borrower. Upon any such resignation, the Required Lenders shall have the right to appoint a successor Agent to the Administrative Agent that has resigned. If no successor Administrative Agent shall have been so appointed by the Required Lenders, and shall have accepted such appointment, within 30 days after the retiring Administrative Agent’s giving of notice of resignation, then such retiring Administrative Agent may, on behalf of the Lenders, appoint a successor Administrative Agent, which shall be a Lender or an Affiliate of a Lender that is a commercial bank organized under the laws of the United States or of any State thereof and having a combined capital and surplus of at least $500,000,000. Upon the acceptance of any appointment as Administrative Agent hereunder by a successor Agent, such successor Administrative Agent shall succeed to and become vested with all the rights, powers, discretion, privileges and duties of the retiring Administrative Agent, and the retiring Administrative Agent shall be discharged from its duties and obligations under this Agreement. After any retiring Administrative Agent’s resignation hereunder as Administrative Agent, the provisions of this Article VII shall inure to its benefit as to any actions taken or omitted to be taken by it while it was Administrative Agent under this Agreement.

ARTICLE VIII

MISCELLANEOUS

SECTION 8.01. Amendments, Etc.

Subject to Section 8.16(a)(i), no amendment or waiver of any provision of this Agreement, nor consent to any departure by the Borrower therefrom, shall in any event be effective unless the same shall be in writing and signed by the Required Lenders and the Borrower, and then such waiver or consent shall be effective only in the specific instance and for the specific purpose for which given; provided, however, that no amendment, waiver or consent shall (a) unless in writing and signed by all the Lenders (other than, in the case of the following clauses (i) through (iv), any Defaulting Lender), do any of the following: (i) amend Section 3.01 or 3.02 or waive any of the conditions specified therein, (ii) increase the aggregate amount of the

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Commitments (except pursuant to Section 2.18), (iii) change the definition of Required Lenders or the percentage of the Commitments or of the aggregate unpaid principal amount of the outstanding Borrowings, or the number or percentage of the Lenders, that shall be required for the Lenders or any of them to take any action hereunder, or (iv) amend or waive this Section 8.01 or any provision of this Agreement that requires pro rata treatment of the Lenders; or (b) unless in writing and signed by each Lender that is directly affected thereby, do any of the following: (1) increase the amount or extend the termination date of such Lender’s Commitment, or subject such Lender to any additional obligations, (2) reduce the principal of, or interest on, or rate of interest applicable to, the outstanding Advances of such Lender or any fees or other amounts payable to such Lender hereunder, or (3) postpone any date fixed for any payment of principal of, or interest on, the outstanding Advances or any fees or other amounts payable to such Lender hereunder; and providedfurther that (x) no amendment, waiver or consent shall, unless in writing and signed by the Administrative Agent in addition to the Lenders required above to take such action, affect the rights or duties of the Administrative Agent under this Agreement, and (y) no amendment, waiver or consent shall, unless in writing and signed by the Administrative Agent and the Required Lenders, amend or waive Section 8.16. Notwithstanding the foregoing, any provision of this Agreement may be amended by an agreement in writing entered into by the Borrower, the Required Lenders and the Administrative Agent if (i) by the terms of such agreement the Commitment of each Lender not consenting to the amendment provided for therein shall terminate (but such Lender shall continue to be entitled to the benefits of Sections 2.12, 2.15 and 8.04) upon the effectiveness of such amendment and (ii) at the time such amendment becomes effective, each Lender not consenting thereto receives payment in full of the principal outstanding amount of and interest accrued on each Advance made by it, as the case may be, and all other amounts owing to it or accrued for its account under this Agreement and is released from its obligations hereunder.

SECTION 8.02. Notices, Etc.

(a)The Borrower hereby agrees that any notice that is required to be delivered to it hereunder shall be delivered to the Borrower as set forth in this Section 8.02. All notices and other communications provided for hereunder shall be in writing (including fax) and mailed, faxed or delivered, if to the Borrower at its address at 1 Riverside Plaza, Columbus, Ohio 43215, Attention: Julie Sloat (telephone: (614) 716-2885; email: jsloat@aep.com), with a copy to the General Counsel (fax: (614) 716-3440; telephone: (614) 716-3300) and to Corporatefinance@aep.com); if to any Initial Lender, at its Domestic Lending Office specified in its Administrative Questionnaire; if to any other Lender, at its Domestic Lending Office specified in the Assignment and Assumption pursuant to which it became a Lender; if to the Administrative Agent, at its address at PNC Agency Services, PNC Bank, National Association, PNC Firstside Center, 500 First Avenue, Pittsburgh, Pennsylvania 15219, Attention: Brian Hays, Email: brian.hays@pnc.com, Telephone: 412-762-0915; or, as to the Borrower or the Administrative Agent, at such other address as shall be designated by such party in a written notice to the other parties and, as to each other party, at such other address as shall be designated by such party in a written notice to the Borrower and the Administrative Agent. All such notices and communications shall be effective when delivered or received at the appropriate address or number to the attention of the appropriate individual or department, except that notices and communications to the Administrative Agent pursuant to Article II, III or VII shall not be effective until received by the Administrative Agent. Delivery by fax or electronic transmission of an executed counterpart of any amendment or waiver of any provision of this Agreement or of

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any Exhibit hereto to be executed and delivered hereunder shall be effective as delivery of a manually executed counterpart thereof.

(b)The Borrower and the Lenders hereby agree that the Administrative Agent may make any information required to be delivered under Section 5.01(i)(i), (ii), (iv) and (v) (the “Communications”) available to the Lenders by posting the Communications on Intralinks, SyndTrak or a substantially similar electronic transmission systems (the “Platform”). The Borrower and the Lenders hereby acknowledge that the distribution of material through an electronic medium is not necessarily secure and that there are confidentiality and other risks associated with such distribution.

(c)THE PLATFORM IS PROVIDED “AS IS” AND “AS AVAILABLE”. THE AGENT PARTIES (AS DEFINED BELOW) DO NOT WARRANT THE ACCURACY OR COMPLETENESS OF THE COMMUNICATIONS, OR THE ADEQUACY OF THE PLATFORM AND EXPRESSLY DISCLAIM LIABILITY FOR ERRORS OR OMISSIONS IN THE COMMUNICATIONS. NO WARRANTY OF ANY KIND, EXPRESS, IMPLIED OR STATUTORY, INCLUDING, WITHOUT LIMITATION, ANY WARRANTY OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE, NON-INFRINGEMENT OF THIRD-PARTY RIGHTS OR FREEDOM FROM VIRUSES OR OTHER CODE DEFECTS, IS MADE BY THE AGENT PARTIES IN CONNECTION WITH THE COMMUNICATIONS OR THE PLATFORM. IN NO EVENT SHALL THE ADMINISTRATIVE AGENT OR ANY OF ITS RELATED PARTIES (COLLECTIVELY, “AGENT PARTIES”) HAVE ANY LIABILITY TO THE BORROWER, ANY LENDER OR ANY OTHER PERSON OR ENTITY FOR DAMAGES OF ANY KIND, INCLUDING, WITHOUT LIMITATION, DIRECT OR INDIRECT, SPECIAL, INCIDENTAL OR CONSEQUENTIAL DAMAGES, LOSSES OR EXPENSES (WHETHER IN TORT, CONTRACT OR OTHERWISE) ARISING OUT OF THE BORROWER’S OR THE ADMINISTRATIVE AGENT’S TRANSMISSION OF COMMUNICATIONS THROUGH THE INTERNET, EXCEPT TO THE EXTENT THE LIABILITY OF ANY AGENT PARTY IS FOUND IN A FINAL, NON-APPEALABLE JUDGMENT BY A COURT OF COMPETENT JURISDICTION TO HAVE RESULTED PRIMARILY FROM SUCH AGENT PARTY’S GROSS NEGLIGENCE OR WILLFUL MISCONDUCT.

The Administrative Agent agrees that the receipt of the Communications by the Administrative Agent at its e-mail address set forth above shall constitute effective delivery of the Communications to the Administrative Agent for purposes of the Loan Documents. Each Lender agrees that notice to it (as provided in the next sentence) specifying that the Communications have been posted to the Platform shall constitute effective delivery of the Communications to such Lender for purposes of the Loan Documents. Each Lender agrees (i) to notify the Administrative Agent in writing (including by electronic communication) from time to time of such Lender’s e-mail address to which the foregoing notice may be sent by electronic transmission and (ii) that the foregoing notice may be sent to such e-mail address.

Nothing herein shall prejudice the right of the Administrative Agent or any Lender to give any notice or other communication pursuant to any Loan Document in any other manner specified in such Loan Document.

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SECTION 8.03. No Waiver; Remedies.

No failure on the part of any Lender or the Administrative Agent to exercise, and no delay in exercising, any right hereunder shall operate as a waiver thereof; nor shall any single or partial exercise of any such right preclude any other or further exercise thereof or the exercise of any other right. The remedies herein provided are cumulative and not exclusive of any remedies provided by law.

SECTION 8.04. Costs and Expenses.

(a)The Borrower agrees to pay promptly upon demand all reasonable out-of-pocket costs and expenses of the Administrative Agent in connection with the preparation, execution, delivery, administration, modification and amendment of this Agreement and the other documents to be delivered hereunder, including, without limitation, (i) all due diligence, syndication (including printing, distribution and bank meetings), transportation, computer, duplication, appraisal, consultant, and audit expenses and (ii) the reasonable fees and expenses of counsel for the Administrative Agent with respect thereto and with respect to advising the Administrative Agent as to its rights and responsibilities under this Agreement. The Borrower further agrees to pay promptly upon demand all costs and expenses of the Administrative Agent and the Lenders, if any (including, without limitation, counsel fees and expenses), in connection with the enforcement (whether through negotiations, legal proceedings or otherwise) of this Agreement and the other documents to be delivered hereunder, including, without limitation, reasonable fees and expenses of counsel for the Administrative Agent and the Lenders in connection with the enforcement of rights under this Section 8.04(a).

(b)The Borrower agrees to indemnify and hold harmless each Lender and the Administrative Agent and each of their Related Parties (each, an “Indemnified Party”) from and against any and all claims, damages, losses and liabilities, joint or several, to which any such Indemnified Party may become subject, in each case arising out of or in connection with or relating to (including, without limitation, in connection with any investigation, litigation or proceeding or preparation of a defense in connection therewith) (i) this Agreement, any of the transactions contemplated herein or the actual or proposed use of the proceeds of the Extensions of Credit (ii) any error or omission in connection with posting of the data required to be delivered pursuant to Section 5.01(i)(i), (ii) or (iv) on the website of the SEC or any successor website or (iii) the actual or alleged presence of Hazardous Materials on any property of the Borrower or any of its Subsidiaries or any Environmental Action relating in any way to the Borrower or any of its Subsidiaries, and to reimburse any Indemnified Party for any and all reasonable expenses (including, without limitation, reasonable fees and expenses of counsel) as they are incurred in connection with the investigation of or preparation for or defense of any pending or threatened claim or any action or proceeding arising therefrom, whether or not such Indemnified Party is a party and whether or not such claim, action or proceeding is initiated or brought by or on behalf of the Borrower or any of its Affiliates and whether or not any of the transactions contemplated hereby are consummated or this Agreement is terminated, except to the extent such claim, damage, loss, liability or expense is found in a final, non-appealable judgment by a court of competent jurisdiction to have resulted from such Indemnified Party’s gross negligence or willful misconduct. In the case of an investigation, litigation or other proceeding to which the indemnity in this Section 8.04(b) applies, such indemnity shall be effective whether or not such investigation, litigation or proceeding is brought by the Borrower,

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its directors, shareholders or creditors or an Indemnified Party or any other Person or any Indemnified Party is otherwise a party thereto and whether or not the transactions contemplated hereby are consummated. The Borrower agrees not to assert any claim against any Indemnified Party on any theory of liability, for special, indirect, consequential or punitive damages arising out of or otherwise relating to this Agreement, any of the transactions contemplated herein or the actual or proposed use of the proceeds of the Extensions of Credit.

(c)If any payment of principal of, or Conversion of, any Eurodollar Rate Advance is made by the Borrower to or for the account of a Lender other than on the last day of the Interest Period for such Advance, as a result of a payment or Conversion pursuant to Section 2.06, 2.09(e), 2.12 or 2.14, acceleration of the maturity of the outstanding Borrowings pursuant to Section 6.01, the assignment of any such Advance pursuant to Section 2.16(b) or for any other reason (in the case of any such payment or Conversion), the Borrower shall, promptly upon demand by such Lender (with a copy of such demand to the Administrative Agent), pay to the Administrative Agent for the account of such Lender any amounts required to compensate such Lender for any additional losses, costs or expenses that it may reasonably incur as a result of such payment or Conversion, including, without limitation, any loss (other than loss of Applicable Margin), cost or expense incurred by reason of the liquidation or reemployment of deposits or other funds acquired by any Lender to fund or maintain such Advance.

(d)Without prejudice to the survival of any other agreement of the Borrower hereunder, the agreements and obligations of the Borrower contained in Sections 2.12 and 8.04 shall survive the payment in full of principal, interest and all other amounts payable hereunder.

(e)The Borrower agrees that no Indemnified Party shall have any liability (whether direct or indirect, in contract or tort or otherwise) to the Borrower or its security holders or creditors related to or arising out of or in connection with this Agreement, the Extensions of Credit or the use or proposed use of the proceeds thereof, any of the transactions contemplated by any of the foregoing or in the loan documentation or the performance by an Indemnified Party of any of the foregoing (including the use by unintended recipients of any information or other materials distributed through telecommunications, electronic or other information transmission systems in connection with this Agreement or the other Loan Documents) except to the extent that any loss, claim, damage, liability or expense is found in a final, non-appealable judgment by a court of competent jurisdiction to have resulted from such Indemnified Party’s gross negligence or willful misconduct.

(f)In the event that an Indemnified Party is requested or required to appear as a witness in any action brought by or on behalf of or against the Borrower or any of its Affiliates in which such Indemnified Party is not named as a defendant, the Borrower agrees to reimburse such Indemnified Party for all reasonable expenses incurred by it in connection with such Indemnified Party’s appearing and preparing to appear as such a witness, including, without limitation, the fees and disbursements of its legal counsel.

SECTION 8.05. Right of Set-off.

Upon (i) the occurrence and during the continuance of any Event of Default and (ii) the making of the request or the granting of the consent specified by Section 6.01 to authorize the Administrative Agent to declare the outstanding Borrowings due and payable pursuant to the

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provisions of Section 6.01, each Credit Party and each of its Affiliates is hereby authorized at any time and from time to time, to the fullest extent permitted by law, to set off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other indebtedness at any time owing by such Credit Party or such Affiliate to or for the credit or the account of the Borrower against any and all of the obligations of the Borrower now or hereafter existing under this Agreement held by such Credit Party, whether or not such Credit Party shall have made any demand under this Agreement and although such obligations may be unmatured; provided that, in the event that any Defaulting Lender shall exercise any such right of setoff, (x) all amounts so set off shall be paid over immediately to the Administrative Agent for further application in accordance with the provisions of Section 8.16 and, pending such payment, shall be segregated by such Defaulting Lender from its other funds and deemed held in trust for the benefit of the Administrative Agent and the Lenders, and (y) the Defaulting Lender shall provide promptly to the Administrative Agent a statement describing in reasonable detail the obligations of the Borrower owing to such Defaulting Lender as to which it exercised such right of setoff. Each Credit Party agrees promptly to notify the Borrower after any such set-off and application, provided that the failure to give such notice shall not affect the validity of such set-off and application. The rights of each Credit Party and its Affiliates under this Section are in addition to other rights and remedies (including, without limitation, other rights of set-off) that such Credit Party and its Affiliates may have.

SECTION 8.06. Binding Effect.

This Agreement shall become effective upon satisfaction of the conditions precedent specified in Section 3.01 and thereafter shall be binding upon and inure to the benefit of the Borrower, the Administrative Agent, each Lender and their respective successors and assigns, except that the Borrower shall not have the right to assign its rights hereunder or any interest herein without the prior written consent of all of the Lenders. None of the Joint Lead Arrangers nor any Person designated as a “Documentation Agent” or a “Syndication Agent” with respect to this Agreement shall have any duties under this Agreement.

SECTION 8.07. Assignments and Participations.

(a)Successors and Assigns of Lenders Generally. No Lender may assign or otherwise transfer any of its rights or obligations hereunder except (i) to an assignee in accordance with the provisions of subsection (b) of this Section, (ii) by way of participation in accordance with the provisions of subsection (d) of this Section, or (iii) by way of pledge or assignment of a security interest subject to the restrictions of subsection (e) of this Section (and any other attempted assignment or transfer by any party hereto shall be null and void). Nothing in this Agreement, expressed or implied, shall be construed to confer upon any Person (other than the parties hereto, their respective successors and assigns permitted hereby, Participants to the extent provided in subsection (d) of this Section and, to the extent expressly contemplated hereby, the Related Parties of each of the Administrative Agent and the Lenders) any legal or equitable right, remedy or claim under or by reason of this Agreement.

(b)Assignments by Lenders. Any Lender may at any time assign to one or more assignees all or a portion of its rights and obligations under this Agreement (including all or a portion of its Commitment and the Advances at the time owing to it); provided that any such assignment shall be subject to the following conditions:

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(i)Minimum Amounts.

(A)in the case of an assignment of the entire remaining amount of the assigning Lender’s Commitment and/or the Advances at the time owing to it or contemporaneous assignments to related Approved Funds (determined after giving effect to such assignments) that equal at least the amount specified in subsection (b)(i)(B) of this Section in the aggregate or in the case of an assignment to a Lender, an Affiliate of a Lender or an Approved Fund, no minimum amount need be assigned; and

(B)in any case not described in subsection (b)(i)(A) of this Section, the aggregate amount of the Commitment (which for this purpose includes Advances outstanding thereunder) or, if the applicable Commitment is not then in effect, the principal outstanding balance of the Advances of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Assumption with respect to such assignment is delivered to the Administrative Agent or, if the “Trade Date” is specified in the Assignment and Assumption, as of the Trade Date) shall not be less than $10,000,000, or an integral multiple of $1,000,000 in excess thereof, unless each of the Administrative Agent and, so long as no Default has occurred and is continuing, the Borrower otherwise consents (each such consent not to be unreasonably withheld or delayed).

(ii)Proportionate Amounts. Each partial assignment shall be made as an assignment of a proportionate part of all the assigning Lender’s rights and obligations under this Agreement with respect to the Advances or the Commitment assigned.

(iii)Required Consents. No consent shall be required for any assignment except to the extent required by subsection (b)(i)(B) of this Section and, in addition:

(A)the consent of the Borrower (such consent not to be unreasonably withheld or delayed) shall be required unless (x) a Default has occurred and is continuing at the time of such assignment, or (y) such assignment is to a Lender, an Affiliate of a Lender or an Approved Fund; provided that the Borrower shall be deemed to have consented to any such assignment unless it shall object thereto by written notice to the Administrative Agent within ten Business Days after having received notice thereof; and

(B)the consent of the Administrative Agent (such consent not to be unreasonably withheld or delayed) shall be required for assignments if such assignment is to a Person that is not a Lender, an Affiliate of such Lender or an Approved Fund with respect to such Lender.

(iv)Assignment and Assumption. The parties to each assignment shall execute and deliver to the Administrative Agent an Assignment and Assumption, together with a processing and recordation fee of $3,500 (to be paid by the assigning Lender, or, in the case of an assignment pursuant to Section 2.17(b), the Borrower); provided that the Administrative Agent may, in its sole discretion, elect to waive such processing and

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recordation fee in the case of any assignment. The assignee, if it is not a Lender, shall deliver to the Administrative Agent an Administrative Questionnaire.

(v)No Assignment to Certain Persons. No such assignment shall be made to (A) the Borrower or any of the Borrower’s Affiliates or Subsidiaries or (B) to any Defaulting Lender or any of its Subsidiaries, or any Person who, upon becoming a Lender hereunder, would constitute a Defaulting Lender or a Subsidiary thereof.

(vi)No Assignment to Natural Persons. No such assignment shall be made to a natural Person (or a holding company, investment vehicle or trust for, or owned and operated for the primary benefit of, a natural Person).

(vii)Certain Additional Payments. In connection with any assignment of rights and obligations of any Defaulting Lender hereunder, no such assignment shall be effective unless and until, in addition to the other conditions thereto set forth herein, the parties to the assignment shall make such additional payments to the Administrative Agent in an aggregate amount sufficient, upon distribution thereof as appropriate (which may be outright payment, purchases by the assignee of participations or subparticipations, or other compensating actions, including funding, with the consent of the Borrower and the Administrative Agent, the applicable pro rata share of Advances previously requested but not funded by the Defaulting Lender, to each of which the applicable assignee and assignor hereby irrevocably consent), to (x) pay and satisfy in full all payment liabilities then owed by such Defaulting Lender to the Administrative Agent and each Lender hereunder (and interest accrued thereon), and (y) acquire (and fund as appropriate) its full pro rata share of all Advances and Commitments in accordance with its Commitment Percentage. Notwithstanding the foregoing, in the event that any assignment of rights and obligations of any Defaulting Lender hereunder shall become effective under Applicable Law without compliance with the provisions of this subsection, then the assignee of such interest shall be deemed to be a Defaulting Lender for all purposes of this Agreement until such compliance occurs.

Subject to acceptance and recording thereof by the Administrative Agent pursuant to subsection (c) of this Section, from and after the effective date specified in each Assignment and Assumption, the assignee thereunder shall be a party to this Agreement and, to the extent of the interest assigned by such Assignment and Assumption, have the rights and obligations of a Lender under this Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Assumption, be released from its obligations under this Agreement (and, in the case of an Assignment and Assumption covering all of the assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto) but shall continue to be entitled to the benefits of Sections 2.12, 2.15 and 8.04with respect to facts and circumstances occurring prior to the effective date of such assignment; provided, that except to the extent otherwise expressly agreed in writing by the affected parties, no assignment by a Defaulting Lender will constitute a waiver or release of any claim of any party hereunder arising from that Lender’s having been a Defaulting Lender. Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this subsection shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with subsection (d) of this Section.

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(c)Register. The Administrative Agent, acting solely for this purpose as a non-fiduciary agent of the Borrower, shall maintain at its address referred to in Section 8.02 a copy of each Assignment and Assumption delivered to it and a register in which it shall record the names and addresses of the Lenders, and the Commitments of, and principal amounts (and stated interest) of the Advances owing to, each Lender pursuant to the terms hereof from time to time (the “Register”). The entries in the Register shall be conclusive absent manifest error, and the Borrower, the Administrative Agent and the Lenders shall treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement. The Register shall be available for inspection by the Borrower and any Lender, at any reasonable time and from time to time upon reasonable prior notice.

(d)Participations. Any Lender may at any time, without the consent of, or notice to, the Borrower or the Administrative Agent, sell participations to any Person (other than a natural Person, or a holding company, investment vehicle or trust for, or owned and operated for the primary benefit of, a natural Person, or the Borrower or any of the Borrower’s Affiliates or Subsidiaries) (each, a “Participant”) in all or a portion of such Lender’s rights and/or obligations under this Agreement (including all or a portion of its Commitment and/or the Advances owing to it); provided that (i) such Lender’s obligations under this Agreement shall remain unchanged, (ii) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations, and (iii) the Borrower, the Administrative Agent and Lenders shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Agreement. For the avoidance of doubt, each Lender shall be responsible for the indemnity under Section 7.05 with respect to any payments made by such Lender to its Participant(s).

Any agreement or instrument pursuant to which a Lender sells such a participation shall provide that such Lender shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement; provided that such agreement or instrument may provide that such Lender will not, without the consent of the Participant, agree to any amendment, modification or waiver described in clauses (ii), (iii) or (iv) of the first sentence of Section 8.01that affects such Participant The Borrower agrees that each Participant shall be entitled to the benefits of Sections 2.12, 2.15, 8.04(b) and 8.04(c) (subject to the requirements and limitations therein, including the requirements under Section 2.15(g) (it being understood that the documentation required under Section 2.15(g) shall be delivered to the participating Lender)) to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to subsection (b) of this Section; provided that such Participant (A) agrees to be subject to the provisions of Section 2.17(b) as if it were an assignee under subsection (b) of this Section; and (B) shall not be entitled to receive any greater payment under Sections 2.12or 2.15, with respect to any participation, than its participating Lender would have been entitled to receive, except to the extent such entitlement to receive a greater payment results from a Change in Law that occurs after the Participant acquired the applicable participation. Each Lender that sells a participation agrees, at the Borrower’s request and expense, to use reasonable efforts to cooperate with the Borrower to effectuate the provisions of Section 2.17(b) with respect to any Participant. To the extent permitted by law, each Participant also shall be entitled to the benefits of Section 8.05 as though it were a Lender; provided that such Participant agrees to be subject to Section 2.15as though it were a Lender. Each Lender that sells a participation shall, acting solely for this purpose as a non-fiduciary agent of the Borrower, maintain a register on which it enters the name and address of each Participant and the

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principal amounts (and stated interest) of each Participant’s interest in the Commitments, Advances or other obligations under the Loan Documents (the “Participant Register”); provided that no Lender shall have any obligation to disclose all or any portion of the Participant Register (including the identity of any Participant or any information relating to a Participant’s interest in any Commitments, Advances or its other obligations under any Loan Document) to any Person except to the extent that such disclosure is necessary to establish that such Commitments, Advances or other obligations are in registered form under Section 5f.103-1(c) of the United States Treasury Regulations. The entries in the Participant Register shall be conclusive absent manifest error, and such Lender shall treat each Person whose name is recorded in the Participant Register as the owner of such participation for all purposes of this Agreement notwithstanding any notice to the contrary. For the avoidance of doubt, the Administrative Agent (in its capacity as Administrative Agent) shall have no responsibility for maintaining a Participant Register.

(e)Certain Pledges. Any Lender may at any time pledge or assign a security interest in all or any portion of its rights under this Agreement to secure obligations of such Lender, including any pledge or assignment to secure obligations to a Federal Reserve Bank or other central banking authority; provided that no such pledge or assignment shall release such Lender from any of its obligations hereunder or substitute any such pledgee or assignee for such Lender as a party hereto.

SECTION 8.08. Confidentiality.

Each of the Administrative Agent and the Lenders agree to maintain the confidentiality of the Confidential Information, except that Confidential Information may be disclosed (a) to its Affiliates and to its Related Parties (it being understood that the Persons to whom such disclosure is made will be informed of the confidential nature of such Confidential Information and instructed to keep such Confidential Information confidential); (b) to the extent required or requested by any regulatory authority purporting to have jurisdiction over such Person or its Related Parties (including any state, federal or foreign authority or examiner regulating banks, banking or other financial institutions and any self-regulatory authority, such as the National Association of Insurance Commissioners); (c) to the extent required by Applicable Law or by any subpoena or similar legal process; (d) to any other party hereto; (e) in connection with the exercise of any remedies hereunder or under any other Loan Document or any action or proceeding relating to this Agreement or any other Loan Document or the enforcement of rights hereunder or thereunder; (f) subject to an agreement containing provisions substantially the same as those of this Section, to (i) any assignee of or Participant in, or any prospective assignee of or Participant in, any of its rights and obligations under this Agreement, (ii) any actual or prospective party (or its Related Parties) to any swap, derivative or other transaction under which payments are to be made by reference to the Borrower and its obligations, this Agreement or payments hereunder or (iii) any credit insurance provider relating to the Borrower and its obligations; (g) on a confidential basis to (i) any rating agency in connection with rating the Borrower or its Subsidiaries or this Agreement or (ii) the CUSIP Service Bureau or any similar agency in connection with the issuance and monitoring of CUSIP numbers with respect to this Agreement; (h) with the consent of the Borrower; or (i) to the extent such Confidential Information (x) becomes publicly available other than as a result of a breach of this Section, or (y) becomes available to the Administrative Agent and any Lender or any of their respective Affiliates on a nonconfidential basis from a source other than the Borrower. In addition, the Administrative Agent and each Lender may disclose the existence of this Agreement and

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information about this Agreement to market data collectors, similar service providers to the lending industry and service providers to the Administrative Agent or any Lender in connection with the administration or servicing of this Agreement, the other Loan Documents and the Commitments. Any Person required to maintain the confidentiality of Confidential Information as provided in this Section shall be considered to have complied with its obligation to do so if such Person has exercised the same degree of care to maintain the confidentiality of such Confidential Information as such Person would accord to its own confidential information.

SECTION 8.09. Governing Law.

This Agreement shall be governed by, and construed in accordance with, the laws of the State of New York.

SECTION 8.10. Severability; Survival.

(a)In the event any one or more of the provisions contained in this Agreement should be held invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions contained herein shall not in any way be affected or impaired hereby.

(b)All covenants, agreements, representations and warranties made by the Borrower herein and in the certificates or other instruments delivered in connection with or pursuant to this Agreement shall be considered to have been relied upon by the other parties hereto and shall survive the execution and delivery of this Agreement and the making of any Advances, regardless of any investigation made by any such other party or on its behalf and notwithstanding that the Administrative Agent or any Lender may have had notice or knowledge of any Default or incorrect representation or warranty at the time any credit is extended hereunder, and shall continue in full force and effect as long as the principal of or any accrued interest on any Advance or any fee or any other amount payable under this Agreement is outstanding and unpaid and so long as the Commitments have not expired or terminated.

SECTION 8.11. Execution in Counterparts.

This Agreement may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. Delivery of an executed counterpart of a signature page to this Agreement by fax or electronic transmission shall be effective as delivery of a manually executed counterpart of this Agreement.

SECTION 8.12. Jurisdiction, Etc.

(a)Each of the parties hereto hereby irrevocably and unconditionally submits, for itself and its property, to the exclusive jurisdiction of any New York State court or federal court of the United States of America sitting in New York City, the County of New York, and any appellate court from any thereof, in any action or proceeding arising out of or relating to this Agreement, or for recognition or enforcement of any judgment, and each of the parties hereto hereby irrevocably and unconditionally

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agrees that all claims in respect of any such action or proceeding may be heard and determined in any such New York State court or, to the extent permitted by law, in such federal court. Each of the parties hereto agrees that a final judgment in any such action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law. Nothing in this Agreement shall affect any right that any party may otherwise have to bring any action or proceeding relating to this Agreement in the courts of any jurisdiction.

(b)Each of the parties hereto irrevocably and unconditionally waives, to the fullest extent it may legally and effectively do so, any objection that it may now or hereafter have to the laying of venue of any suit, action or proceeding arising out of or relating to this Agreement in any New York State or federal court. Each of the parties hereto hereby irrevocably waives, to the fullest extent permitted by law, the defense of an inconvenient forum to the maintenance of such action or proceeding in any such court.

8.13. Waiver of Jury Trial.

Each of the Borrower, the Administrative Agent, each Lender hereby irrevocably waives all right to trial by jury in any action, proceeding or counterclaim (whether based on contract, tort or otherwise) arising out of or relating to this Agreement or the actions of the Administrative Agent, the Borrower or any Lender in the negotiation, administration, performance or enforcement thereof.

8.14. USA Patriot Act.

Each of the Lenders hereby notifies the Borrower that (a) pursuant to the requirements of the USA Patriot Act (Title III of Pub. L. 107-56 (signed into law as of October 26, 2001)) (as amended, restated, modified or otherwise supplemented from time to time, the “Patriot Act”), it is required to obtain, verify and record information that identifies the Borrower, which information includes the name and address of the Borrower and other information that will allow such Lender to identify the Borrower in accordance with the Patriot Act and (b) pursuant to the Beneficial Ownership Regulation, it is required to obtain a Beneficial Ownership Certificate.

8.15. No Fiduciary Duty.

Each of the Administrative Agent, each Lender and each of their respective Affiliates and their officers, directors, controlling persons, employees, agents and advisors (collectively, solely for purposes of this Section 8.15, the “Lenders”) may have economic interests that conflict with those of the Borrower.  The Borrower agrees that nothing in the Loan Documents or otherwise will be deemed to create an advisory, fiduciary or agency relationship or fiduciary or other

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implied duty between the Lenders and the Borrower, its stockholders or its Affiliates.  The Borrower acknowledges and agrees that (i) the transactions contemplated by the Loan Documents are arm’s-length commercial transactions between the Lenders, on the one hand, and the Borrower, on the other, (ii) in connection therewith and with the process leading to such transaction each of the Lenders is acting solely as a principal and not the agent or fiduciary of the Borrower, its management, stockholders, creditors or any other person, (iii) no Lender has assumed an advisory or fiduciary responsibility in favor of the Borrower with respect to the transactions contemplated hereby or the process leading thereto (irrespective of whether any Lender or any of its Affiliates has advised or is currently advising the Borrower on other matters) or any other obligation to the Borrower except the obligations expressly set forth in the Loan Documents and (iv) the Borrower has consulted its own legal and financial advisors to the extent it deemed appropriate.  The Borrower further acknowledges and agrees that it is responsible for making its own independent judgment with respect to such transactions and the process leading thereto.  The Borrower agrees that it will not claim that any Lender has rendered advisory services of any nature or respect, or owes a fiduciary or similar duty to the Borrower, in connection with such transaction or the process leading thereto.

SECTION 8.16. Defaulting Lenders.

(a)Defaulting Lender Adjustments. Notwithstanding anything to the contrary contained in this Agreement, if any Lender becomes a Defaulting Lender, then, until such time as such Lender is no longer a Defaulting Lender, to the extent permitted by Applicable Law:

(i)Waivers and Amendments. Such Defaulting Lender’s right to approve or disapprove any amendment, waiver or consent with respect to this Agreement shall be restricted as set forth in the definition of Required Lenders and in Section 8.01.

(ii)Defaulting Lender Waterfall. Any payment of principal, interest, fees or other amounts received by the Administrative Agent for the account of such Defaulting Lender (whether voluntary or mandatory, at maturity, pursuant to Article VI or otherwise) or received by the Administrative Agent from a Defaulting Lender pursuant to Section 8.05 shall be applied at such time or times as may be determined by the Administrative Agent as follows: first, to the payment of any amounts owing by such Defaulting Lender to the Administrative Agent hereunder; second, as the Borrower may request (so long as no Default exists), to the funding of any Advance in respect of which such Defaulting Lender has failed to fund its portion thereof as required by this Agreement, as determined by the Administrative Agent; third, if so determined by the Administrative Agent and the Borrower, to be held in a deposit account and released pro rata in order to satisfy such Defaulting Lender’s potential future funding obligations with respect to Advances under this Agreement; fourth, to the payment of any amounts owing to the Lenders as a result of any judgment of a court of competent jurisdiction obtained by any Lender against such Defaulting Lender as a result of such Defaulting Lender’s breach of its obligations under this Agreement; fifth, so long as no Default exists, to the payment of any amounts owing to the Borrower as a result of any judgment of a court of competent jurisdiction obtained by the Borrower against such Defaulting Lender as a result of such Defaulting Lender's breach of its obligations under this Agreement; and sixth, to such Defaulting Lender or as otherwise directed by a court of competent jurisdiction; provided that, if (x) such payment is a payment of the principal amount of

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any Advances in respect of which such Defaulting Lender has not fully funded its appropriate share, and (y) such Advances were made at a time when the conditions set forth in Section 3.02 were satisfied or waived, such payment shall be applied solely to pay the Advances of all Non-Defaulting Lenders on a pro rata basis prior to being applied to the payment of any Advances of such Defaulting Lender until such time as all Advances are held by the Lenders pro rata in accordance with the Commitments. Any payments, prepayments or other amounts paid or payable to a Defaulting Lender that are applied (or held) to pay amounts owed by a Defaulting Lender pursuant to this Section 8.16(a)(ii) shall be deemed paid to and redirected by such Defaulting Lender, and each Lender irrevocably consents hereto.

(b)Defaulting Lender Cure. If the Borrower and the Administrative Agent agree in writing that a Lender is no longer a Defaulting Lender, the Administrative Agent will so notify the parties hereto, whereupon as of the effective date specified in such notice and subject to any conditions set forth therein, that Lender will, to the extent applicable, purchase at par that portion of outstanding Advances of the other Lenders or take such other actions as the Administrative Agent may determine to be necessary to cause the Advances to be held pro rata by the Lenders in accordance with the Commitments, whereupon such Lender will cease to be a Defaulting Lender; provided that no adjustments will be made retroactively with respect to fees accrued or payments made by or on behalf of the Borrower while that Lender was a Defaulting Lender; and provided, further, that except to the extent otherwise expressly agreed in writing by the affected parties, no change hereunder from Defaulting Lender to Lender will constitute a waiver or release of any claim of any party hereunder arising from that Lender’s having been a Defaulting Lender.

SECTION 8.17. Acknowledgement and Consent to Bail-In of EEA Financial Institutions.

Notwithstanding anything to the contrary in any Loan Document or in any other agreement, arrangement or understanding among any such parties, each party hereto acknowledges that any liability of any Lender that is an EEA Financial Institution arising under any Loan Document, to the extent such liability is unsecured, may be subject to the write-down and conversion powers of an EEA Resolution Authority and agrees and consents to, and acknowledges and agrees to be bound by:

(a)the application of any Write-Down and Conversion Powers by an EEA Resolution Authority to any such liabilities arising hereunder which may be payable to it by any Lender that is an EEA Financial Institution; and

(b)the effects of any Bail-in Action on any such liability, including, if applicable:

(i)a reduction in full or in part or cancellation of any such liability;

(ii)a conversion of all, or a portion of, such liability into shares or other instruments of ownership in such EEA Financial Institution, its parent undertaking, or a bridge institution that may be issued to it or otherwise conferred on it, and that such shares or other instruments of ownership will be accepted by it in lieu of any rights with respect to any such liability under this Agreement or any other Loan Document; or

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(iii)the variation of the terms of such liability in connection with the exercise of the write-down and conversion powers of any EEA Resolution Authority.

SECTION 8.18. Certain ERISA Matters.

(d)Each Lender (x) represents and warrants, as of the date such person became a Lender party hereto, to, and (y) covenants, from the date such person became a Lender party hereto to the date such person ceases being a Lender party hereto, for the benefit of, the Administrative Agent, the Joint Lead Arrangers and their respective Affiliates, and not, for the avoidance of doubt, to or for the benefit of the Borrower, that at least one of the following is and will be true:

(i) such Lender is not using “plan assets” (within the meaning of Section 3(42) of ERISA or otherwise) of one or more Benefit Plans with respect to such Lender’s entrance into, participation in, administration of and performance of the Advances, the Commitments or this Agreement,

(ii) the transaction exemption set forth in one or more PTEs, such as PTE 84-14 (a class exemption for certain transactions determined by independent qualified professional asset managers), PTE 95-60 (a class exemption for certain transactions involving insurance company general accounts), PTE 90-1 (a class exemption for certain transactions involving insurance company pooled separate accounts), PTE 91-38 (a class exemption for certain transactions involving bank collective investment funds) or PTE 96-23 (a class exemption for certain transactions determined by in-house asset managers), is applicable with respect to such Lender’s entrance into, participation in, administration of and performance of the Advances, the Commitments and this Agreement,

(iii) (A) such Lender is an investment fund managed by a “Qualified Professional Asset Manager” (within the meaning of Part VI of PTE 84-14), (B) such Qualified Professional Asset Manager made the investment decision on behalf of such Lender to enter into, participate in, administer and perform the Advances, the Commitments and this Agreement, (C) the entrance into, participation in, administration of and performance of the Advances, the Commitments and this Agreement satisfies the requirements of sub-sections (b) through (g) of Part I of PTE 84-14 and (D) to the best knowledge of such Lender, the requirements of subsection (a) of Part I of PTE 84-14 are satisfied with respect to such Lender’s entrance into, participation in, administration of and performance of the Advances, the Commitments and this Agreement, or

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(iv) such other representation, warranty and covenant as may be agreed in writing between the Administrative Agent, in its sole discretion, and such Lender.

In addition, unless either (1) sub-clause (i) in the immediately preceding clause (a) is true with respect to a Lender or (2) Lender has provided another representation, warranty and covenant in accordance with sub-clause (iv) in the immediately preceding clause (a), such Lender further (x) represents and warrants, as of the date such person became a Lender party hereto, to, and (y) covenants, from the date such person became a Lender party hereto to the date such person ceases being a Lender party hereto, for the benefit of, the Administrative Agent and the Arranger and their respective Affiliates, and not, for the avoidance of doubt, to or for the benefit of the Borrower, that none of the Administrative Agent, Arranger or any of their respective Affiliates is a fiduciary with respect to the assets of such Lender involved in such Lender’s entrance into, participation in, administration of and performance of the Advances, the Commitments and this Agreement (including in connection with the reservation or exercise of any rights by the Administrative Agent under this Agreement, any Loan Document or any documents related hereto or thereto).

SECTION 8.19. Effect of Benchmark Transition Event

(a)Benchmark Replacement. Notwithstanding anything to the contrary herein or in any other Loan Document, upon the occurrence of a Benchmark Transition Event or an Early Opt-in Election, as applicable, the Administrative Agent and the Borrower may amend this Agreement to replace the Eurodollar Rate with a Benchmark Replacement. Any such amendment with respect to a Benchmark Transition Event will become effective at 5:00 p.m. (New York City time) on the fifth (5th) Business Day after the Administrative Agent has posted such proposed amendment to all Lenders and the Borrower so long as the Administrative Agent has not received, by such time, written notice of objection to such amendment from Lenders comprising the Required Lenders. Any such amendment with respect to an Early Opt-in Election will become effective on the date that Lenders comprising the Required Lenders have delivered to the Administrative Agent written notice that such Required Lenders accept such amendment. No replacement of the Eurodollar Rate with a Benchmark Replacement pursuant to this Section titled “Effect of Benchmark Transition Event” will occur prior to the applicable Benchmark Transition Start Date.

(b)Benchmark Replacement Conforming Changes. In connection with the implementation of a Benchmark Replacement, the Administrative Agent will have the right to make Benchmark Replacement Conforming Changes from time to time and, notwithstanding anything to the contrary herein or in any other Loan Document, any amendments implementing such Benchmark Replacement Conforming Changes will become effective without any further action or consent of any other party to this Agreement.

(c)Notices; Standards for Decisions and Determinations. The Administrative Agent will promptly notify the Borrower and the Lenders of (i) any occurrence of a Benchmark Transition Event or an Early Opt-in Election, as applicable, and its related Benchmark Replacement Date and Benchmark Transition Start Date, (ii) the implementation of any Benchmark Replacement, (iii) the effectiveness of any Benchmark Replacement Conforming Changes and (iv) the commencement or conclusion of any Benchmark Unavailability Period.

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Any determination, decision or election that may be made by the Administrative Agent or Lenders pursuant to this Section titled “Effect of Benchmark Transition Event,” including any determination with respect to a tenor, rate or adjustment or of the occurrence or non-occurrence of an event, circumstance or date and any decision to take or refrain from taking any action, will be conclusive and binding absent manifest error and may be made in its or their sole discretion and without consent from any other party hereto, except, in each case, as expressly required pursuant to this Section titled “Effect of Benchmark Transition Event”.

(d)Benchmark Unavailability Period. Upon the Borrower’s receipt of notice of the commencement of a Benchmark Unavailability Period, the Borrower may revoke any request for a Eurodollar Rate Advance of, conversion to or continuation of Eurodollar Rate Advances to be made, converted or continued during any Benchmark Unavailability Period and, failing that, the Borrower will be deemed to have converted any such request into a request for a Borrowing of or conversion to Base Rate Advances. During any Benchmark Unavailability Period, the component of the Base Rate based upon the Eurodollar Rate will not be used in any determination of the Base Rate.

(e)Certain Defined Terms. As used in this Section titled “Effect of Benchmark Transition Event”:

“Benchmark Replacement” means the sum of: (a) the alternate benchmark rate (which may include Term SOFR) that has been selected by the Administrative Agent and the Borrower giving due consideration to (i) any selection or recommendation of a replacement rate or the mechanism for determining such a rate by the Relevant Governmental Body or (ii) any evolving or then-prevailing market convention for determining a rate of interest as a replacement to the Eurodollar Rate for U.S. dollar-denominated syndicated credit facilities and (b) the Benchmark Replacement Adjustment; provided that, if the Benchmark Replacement as so determined would be less than zero, the Benchmark Replacement will be deemed to be zero for the purposes of this Agreement.

“Benchmark Replacement Adjustment” means, with respect to any replacement of the Eurodollar Rate with an Unadjusted Benchmark Replacement for each applicable Interest Period, the spread adjustment, or method for calculating or determining such spread adjustment, (which may be a positive or negative value or zero) that has been selected by the Administrative Agent and the Borrower giving due consideration to (i) any selection or recommendation of a spread adjustment, or method for calculating or determining such spread adjustment, for the replacement of the Eurodollar Rate with the applicable Unadjusted Benchmark Replacement by the Relevant Governmental Body or (ii) any evolving or then-prevailing market convention for determining a spread adjustment, or method for calculating or determining such spread adjustment, for the replacement of the Eurodollar Rate with the applicable Unadjusted Benchmark Replacement for U.S. dollar- denominated syndicated credit facilities at such time.

“Benchmark Replacement Conforming Changes” means, with respect to any Benchmark Replacement, any technical, administrative or operational changes (including changes to the definition of “Base Rate,” the definition of “Interest Period,” timing and frequency of determining rates and making payments of interest and other administrative matters) that the Administrative Agent decides may be appropriate to reflect the adoption and implementation of such Benchmark Replacement and to permit the administration thereof by

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the Administrative Agent in a manner substantially consistent with market practice (or, if the Administrative Agent decides that adoption of any portion of such market practice is not administratively feasible or if the Administrative Agent determines that no market practice for the administration of the Benchmark Replacement exists, in such other manner of administration as the Administrative Agent decides is reasonably necessary in connection with the administration of this Agreement).

“Benchmark Replacement Date” means the earlier to occur of the following events with respect to the Eurodollar Rate:

(1) in the case of clause (1) or (2) of the definition of “Benchmark Transition Event,” the later of (a) the date of the public statement or publication of information referenced therein and (b) the date on which the administrator of the Eurodollar Rate permanently or indefinitely ceases to provide the Eurodollar Rate; or

(2) in the case of clause (3) of the definition of “Benchmark Transition Event,” the date of the public statement or publication of information referenced therein.

“Benchmark Transition Event” means the occurrence of one or more of the following events with respect to the Eurodollar Rate:

(1) a public statement or publication of information by or on behalf of the administrator of the Eurodollar Rate announcing that such administrator has ceased or will cease to provide the Eurodollar Rate, permanently or indefinitely, provided that, at the time of such statement or publication, there is no successor administrator that will continue to provide the Eurodollar Rate;

(2) a public statement or publication of information by the regulatory supervisor for the administrator of the Eurodollar Rate, the U.S. Federal Reserve System, an insolvency official with jurisdiction over the administrator for the Eurodollar Rate, a resolution authority with jurisdiction over the administrator for the Eurodollar Rate or a court or an entity with similar insolvency or resolution authority over the administrator for the Eurodollar Rate, which states that the administrator of the Eurodollar Rate has ceased or will cease to provide the Eurodollar Rate permanently or indefinitely, provided that, at the time of such statement or publication, there is no successor administrator that will continue to provide the Eurodollar Rate; or

(3) a public statement or publication of information by the regulatory supervisor for the administrator of the Eurodollar Rate announcing that the Eurodollar Rate is no longer representative.

“Benchmark Transition Start Date” means (a) in the case of a Benchmark Transition Event, the earlier of (i) the applicable Benchmark Replacement Date and (ii) if such Benchmark Transition Event is a public statement or publication of information of a prospective event, the 90thday prior to the expected

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date of such event as of such public statement or publication of information (or if the expected date of such prospective event is fewer than 90 days after such statement or publication, the date of such statement or publication) and (b) in the case of an Early Opt-in Election, the date specified by the Administrative Agent or the Required Lenders, as applicable, by notice to the Borrower, the Administrative Agent (in the case of such notice by the Required Lenders) and the Lenders.

“Benchmark Unavailability Period” means, if a Benchmark Transition Event and its related Benchmark Replacement Date have occurred with respect to the Eurodollar Rate and solely to the extent that the Eurodollar Rate has not been replaced with a Benchmark Replacement, the period (x) beginning at the time that such Benchmark Replacement Date has occurred if, at such time, no Benchmark Replacement has replaced the Eurodollar Rate for all purposes hereunder in accordance with the Section titled “Effect of Benchmark Transition Event” and (y) ending at the time that a Benchmark Replacement has replaced the Eurodollar Rate for all purposes hereunder pursuant to the Section titled “Effect of Benchmark Transition Event.”

“Early Opt-in Election” means the occurrence of:

(1) (i) a determination by the Administrative Agent or (ii) a notification by the Required Lenders to the Administrative Agent (with a copy to the Borrower) that the Required Lenders have determined that U.S. dollar-denominated syndicated credit facilities being executed at such time, or that include language similar to that contained in this Section titled “Effect of Benchmark Transition Event,” are being executed or amended, as applicable, to incorporate or adopt a new benchmark interest rate to replace the Eurodollar Rate, and

(2) (i) the election by the Administrative Agent or (ii) the election by the Required Lenders to declare that an Early Opt-in Election has occurred and the provision, as applicable, by the Administrative Agent of written notice of such election to the Borrower and the Lenders or by the Required Lenders of written notice of such election to the Administrative Agent.

“Federal Reserve Bank of New York’s Website” means the website of the Federal Reserve Bank of New York at http://www.newyorkfed.org,or any successor source.

“Relevant Governmental Body” means the Federal Reserve Board and/or the Federal Reserve Bank of New York, or a committee officially endorsed or convened by the Federal Reserve Board and/or the Federal Reserve Bank of New York or any successor thereto.

“SOFR” with respect to any day means the secured overnight financing rate published for such day by the Federal Reserve Bank of New York, as the administrator of the benchmark, (or a successor administrator) on the Federal Reserve Bank of New York’s Website.

“Term SOFR” means the forward-looking term rate based on SOFR that has been selected or recommended by the Relevant Governmental Body.

“Unadjusted Benchmark Replacement” means the Benchmark Replacement excluding the Benchmark Replacement Adjustment.

[Remainder of page intentionally left blank.]

IN WITNESS WHEREOF, each of the parties hereto has caused a counterpart of this Agreement to be duly executed and delivered as of the date first above written.

AMERICAN ELECTRIC POWER

COMPANY, INC.

as Borrower

By /s/ Julia A. Sloat

Name: Julia A. Sloat

Title: Treasurer

AEP - CREDIT AGREEMENT

PNC BANK, NATIONAL ASSOCIATION,

as Administrative Agent and a Lender

By /s/ Kelly Sarver

      Name: Kelly Sarver

      Title: Vice President

AEP - CREDIT AGREEMENT

WELLS FARGO BANK, NATIONAL

ASSOCIATION

as a Lender

By /s/ Keith Luettel

Name: Keith Luettel

Title: Managing Director

AEP - CREDIT AGREEMENT

KEYBANK NATIONAL ASSOCIATION,

as a Lender

By /s/ Renee M. Bonnell

Name: Renee M. Bonnell

Title: Senior Vice President

AEP - CREDIT AGREEMENT

U.S. BANK NATIONAL ASSOCIATION,

as a Lender

By/s/ John M. Eyerman

    Name: John M. Eyerman

    Title: Senior Vice President

AEP - CREDIT AGREEMENT

SUMITOMO MITSUI BANKING

CORPORATION,

as a Lender

By /s/ Katie Lee

     Name: Katie Lee

     Title: Director

AEP - CREDIT AGREEMENT

TRUIST BANK,

as a Lender

By /s/ Arize Agumadu

Name: Arize Agumadu

Title: Vice President

AEP - CREDIT AGREEMENT

EXHIBIT A

(to the Credit Agreement)

FORM OF NOTICE OF BORROWING

PNC Bank, National Association, as Administrative Agent

for the Lenders party

to the Credit Agreement

referred to below

Attention: [________________]

[Date]

Ladies and Gentlemen:

The undersigned, American Electric Power Company, Inc., refers to the Credit Agreement, dated as of March 23, 2020 (as amended or modified from time to time, the “Credit Agreement,” the terms defined therein being used herein as therein defined), among the undersigned, the Lenders party thereto and PNC Bank, National Association, as Administrative Agent for said Lenders, and hereby gives you notice, irrevocably, pursuant to Section 2.02(a) of the Credit Agreement that the undersigned hereby requests a Borrowing under the Credit Agreement, and in that connection sets forth below the information relating to such Borrowing (the “Proposed Borrowing”) as required by Section 2.02(a) of the Credit Agreement:

(i)The Business Day of the Proposed Borrowing is __________________, 20__.

(ii)[The Type of Advances comprising the Proposed Borrowing is [Base Rate Advances][Eurodollar Rate Advances].]

(iii)The aggregate amount of the Proposed Borrowing is $___________________.

[(iv)The initial Interest Period for each Eurodollar Rate Advance made as part of the Proposed Borrowing is [[one][two][three][six] month[s]] [OTHER PERIOD OF LESS THAN ONE MONTH AGREED TO BY ALL LENDERS].]

The undersigned hereby certifies that the following statements are true on the date hereof, and will be true on the date of the Proposed Borrowing:

(A)the representations and warranties contained in Section 4.01 of the Credit Agreement (other than Section 4.01(e) and the penultimate sentence of Section 4.01(f)) are true and correct in all material respects (or, if already qualified by materiality, in all respects) on and as of the date hereof, before and after giving effect to the Proposed

A-2

Borrowing and to the application of the proceeds therefrom, as though made on the date hereof; and

(B)no event has occurred and is continuing, or would result from the Proposed Borrowing or from the application of the proceeds therefrom, that constitutes a Default.

Very truly yours,

AMERICAN ELECTRIC POWER COMPANY, INC.

By________________________________________

Name:

Title:

EXHIBIT B

(to the Credit Agreement)

FORM OF ASSIGNMENT AND ASSUMPTION

This Assignment and Assumption (the “Assignment and Assumption”) is dated as of the Effective Date set forth below and is entered into by and between [the][each]¹ Assignor identified in item 1 below ([the][each, an] “Assignor”) and [the][each]² Assignee identified in item 2 below ([the][each, an] “Assignee”). [It is understood and agreed that the rights and obligations of [the Assignors][the Assignees]³ hereunder are several and not joint.]⁴ Capitalized terms used but not defined herein shall have the meanings given to them in the Credit Agreement identified below (as amended, the “Credit Agreement”), receipt of a copy of which is hereby acknowledged by [the][each] Assignee. The Standard Terms and Conditions set forth in Annex 1 attached hereto are hereby agreed to and incorporated herein by reference and made a part of this Assignment and Assumption as if set forth herein in full.

For an agreed consideration, [the][each] Assignor hereby irrevocably sells and assigns to [the Assignee][the respective Assignees], and [the][each] Assignee hereby irrevocably purchases and assumes from [the Assignor][the respective Assignors], subject to and in accordance with the Standard Terms and Conditions and the Credit Agreement, as of the Effective Date inserted by the Administrative Agent as contemplated below (i) all of [the Assignor’s][the respective Assignors’] rights and obligations in [its capacity as a Lender][their respective capacities as Lenders] under the Credit Agreement and any other documents or instruments delivered pursuant thereto to the extent related to the amount and percentage interest identified below of all of such outstanding rights and obligations of [the Assignor][the respective Assignors] under the Credit Agreement, and (ii) to the extent permitted to be assigned under applicable law, all claims, suits, causes of action and any other right of [the Assignor (in its capacity as a Lender)][the respective Assignors (in their respective capacities as Lenders)] against any Person, whether known or unknown, arising under or in connection with the Credit Agreement, any other documents or instruments delivered pursuant thereto or the loan transactions governed thereby or in any way based on or related to any of the foregoing, including, but not limited to, contract claims, tort claims, malpractice claims, statutory claims and all other claims at law or in equity related to the rights and obligations sold and assigned pursuant to clause (i) above (the rights and obligations sold and assigned by [the][any] Assignor to [the][any] Assignee pursuant to clauses (i) and (ii) above being referred to herein collectively as [the][an] “Assigned Interest”). Each such sale and assignment is without recourse to [the][any] Assignor and, except as expressly provided in this Assignment and Assumption, without representation or warranty by [the][any] Assignor.

______________________________

1. For bracketed language here and elsewhere in this form relating to the Assignor(s), if the assignment is from a single Assignor, choose the first bracketed language. If the assignment is from multiple Assignors, choose the second bracketed language.

2. For bracketed language here and elsewhere in this form relating to the Assignee(s), if the assignment is to a single Assignee, choose the first bracketed language. If the assignment is to multiple Assignees, choose the second bracketed language.

3. Select as appropriate.

4. Include bracketed language if there are either multiple Assignors or multiple Assignees.

C-2

1. Assignor[s]:______________________________

______________________________

2. Assignee[s]:______________________________

______________________________

[Assignee is an [Affiliate][Approved Fund] of [identify Lender]

3.	Borrower:	American Electric Power Company, Inc.
4.	Administrative Agent:	PNC Bank, National Association, as the
		Administrative Agent under the Credit Agreement.
5.	Credit Agreement:	The $1,000,000,000 Credit Agreement dated as of March 23, 2020 among American Electric Power Company, Inc., as the Borrower, the Lenders parties thereto and PNC Bank, National Association, as Administrative Agent
6.	Assigned Interest[s]:

Assignor[s] 5	Assignee[s] 6	Aggregate Amount of Commitment/Advances for all Lenders 7	Amount of Commitment/Advances Assigned 8	Percentage  Assigned of Commitment/Advances 8	CUSIP Number
		$	$	%
		$	$	%
		$	$	%

[7.Trade Date:______________]⁹

[Page break]

______________________

5.List each Assignor, as appropriate.

6.List each Assignee, as appropriate.

7. Amount to be adjusted by the counterparties to take into account any payments or prepayments made between the Trade Date and the Effective Date.

8. Set forth, to at least 9 decimals, as a percentage of the Commitment/Advances of all Lenders thereunder.

9. To be completed if the Assignor and the Assignee(s) intend that the minimum assignment amount is to be determined as of the Trade Date.

C-3

Effective Date: _____________ ___, 20___ [TO BE INSERTED BY ADMINISTRATIVE AGENT AND WHICH SHALL BE THE EFFECTIVE DATE OF RECORDATION OF TRANSFER IN THE REGISTER THEREFOR.]

The terms set forth in this Assignment and Assumption are hereby agreed to:

ASSIGNOR[S]¹⁰

[NAME OF ASSIGNOR]

By: ________________________________

Title:

[NAME OF ASSIGNOR]

By:______________________________

Title:

ASSIGNEE[S]¹¹

[NAME OF ASSIGNEE]

By:

Title:

[NAME OF ASSIGNEE]

By:

Title:

_________________________

10.Add additional signature blocks as needed.

11.Add additional signature blocks as needed.

C-4

[Consented to and] ¹²Accepted:

PNC BANK, NATIONAL ASSOCIATION, as

Administrative Agent

By:    _________________________________    

Title:

[Consented to:

American Electric Power Company, Inc.

By:    _________________________________    

Title:]¹³ 

__________________________

12.To be added only if the consent of the Administrative Agent is required by the terms of the Credit Agreement.

13.To be added only if the consent of the Borrower is required by the terms of the Credit Agreement.

ANNEX 1

$1,000,000,000 Credit Agreement dated as of March 23, 2020 among American Electric Power Company, Inc., as the Borrower, the Lenders parties thereto and PNC Bank, National Association, as Administrative Agent

STANDARD TERMS AND CONDITIONS FOR

ASSIGNMENT AND ASSUMPTION

1. Representations and Warranties.

1.1. Assignor[s]. [The][Each] Assignor (a) represents and warrants that (i) it is the legal and beneficial owner of [the][the relevant] Assigned Interest, (ii) [the][such] Assigned Interest is free and clear of any lien, encumbrance or other adverse claim, (iii) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and Assumption and to consummate the transactions contemplated hereby and (iv) it is [not] a Defaulting Lender; and (b) assumes no responsibility with respect to (i) any statements, warranties or representations made in or in connection with the Credit Agreement or any other Loan Document, (ii) the execution, legality, validity, enforceability, genuineness, sufficiency or value of the Loan Documents or any collateral thereunder, (iii) the financial condition of the Borrower, any of its Subsidiaries or Affiliates or any other Person obligated in respect of any Loan Document or (iv) the performance or observance by the Borrower, any of its Subsidiaries or Affiliates or any other Person of any of their respective obligations under any Loan Document.

1.2. Assignee[s]. [The][Each] Assignee (a) represents and warrants that (i) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and Assumption and to consummate the transactions contemplated hereby and to become a Lender under the Credit Agreement, (ii) it meets all the requirements to be an assignee under Section 8.07 of the Credit Agreement (subject to such consents, if any, as may be required thereunder), (iii) from and after the Effective Date, it shall be bound by the provisions of the Credit Agreement as a Lender thereunder and, to the extent of [the][the relevant] Assigned Interest, shall have the obligations of a Lender thereunder, (iv) it is sophisticated with respect to decisions to acquire assets of the type represented by the Assigned Interest and either it, or the Person exercising discretion in making its decision to acquire the Assigned Interest, is experienced in acquiring assets of such type, (v) it has received a copy of the Credit Agreement, and has received or has been accorded the opportunity to receive copies of the most recent financial statements delivered pursuant to clauses (i) and (ii) of Section 5.01(i) thereof, as applicable, and such other documents and information as it deems appropriate to make its own credit analysis and decision to enter into this Assignment and Assumption and to purchase [the][such] Assigned Interest, (vi) it has, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this

C-A1-2

Assignment and Assumption and to purchase [the][such] Assigned Interest, and (vii) attached to the Assignment and Assumption is any documentation required to be delivered by it pursuant to the terms of the Credit Agreement, duly completed and executed by [the][such] Assignee; (b) agrees that (i) it will, independently and without reliance on the Administrative Agent, [the][any] Assignor or any other Lender, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Loan Documents, and (ii) it will perform in accordance with their terms all of the obligations which by the terms of the Loan Documents are required to be performed by it as a Lender and (c) appoints and authorizes the Administrative Agent to take such action as agent on its behalf and to exercise such powers and discretion under the Credit Agreement as are delegated to the Administrative Agent by the terms thereof, together with such powers and discretion as are reasonably incidental thereto.

2. Payments. From and after the Effective Date, the Administrative Agent shall make all payments in respect of [the][each] Assigned Interest (including payments of principal, interest, fees and other amounts) to [the][the relevant] Assignee whether such amounts have accrued prior to, on or after the Effective Date. The Assignor[s] and the Assignee[s] shall make all appropriate adjustments in payments by the Administrative Agent for periods prior to the Effective Date or with respect to the making of this assignment directly between themselves. Notwithstanding the foregoing, the Administrative Agent shall make all payments of interest, fees or other amounts paid or payable in kind from and after the Effective Date to [the][the relevant] Assignee.

3. General Provisions. This Assignment and Assumption shall be binding upon, and inure to the benefit of, the parties hereto and their respective successors and assigns. This Assignment and Assumption may be executed in any number of counterparts, which together shall constitute one instrument. Delivery of an executed counterpart of a signature page of this Assignment and Assumption by fax shall be effective as delivery of a manually executed counterpart of this Assignment and Assumption. This Assignment and Assumption shall be governed by, and construed in accordance with, the law of the State of New York.

Exhibit B

AEP - CREDIT AGREEMENT

D-2

EXHIBIT C

(to the Credit Agreement)

FORM OF OPINION OF COUNSEL FOR THE BORROWER

To each of the Lenders party to the

Credit Agreement referred to below

and to PNC Bank, National Association, as Administrative Agent thereunder

March 23, 2020

Ladies and Gentlemen:

This opinion is furnished to you pursuant to Section 3.01(a)(iii) of the Credit Agreement, dated as of March 23, 2020 (the “Credit Agreement”) among American Electric Power Company, Inc. (the “Borrower”), the Lenders party thereto and PNC Bank, National Association, as Administrative Agent. Terms defined in the Credit Agreement are used herein as therein defined.

I am an Associate General Counsel for American Electric Power Service Corporation, an affiliate of the Borrower, and have acted as counsel to the Borrower in connection with the preparation, execution and delivery of the Credit Agreement. I am generally familiar with the Borrower’s corporate history, properties, operations and charter (including amendments, restatements and supplements thereto).

In connection with this opinion, I, or attorneys over whom I exercise supervision, have examined:

(1) The Credit Agreement and the promissory notes issued by the Borrower on the date hereof pursuant to Section 2.07(d) of the Credit Agreement (collectively, the “Loan Documents”).

(2) The documents furnished by the Borrower pursuant to Article III of the Credit Agreement.

(3) The certificate of incorporation of the Borrower and all amendments thereto.

(4) The by-laws of the Borrower and all amendments thereto.

(5) A certificate of the Secretary of State of New York, dated March [ ], 2020, attesting to the continued existence and good standing of the Borrower in that State.

In addition, I, or attorneys over whom I exercise supervision, have examined the originals, or copies certified to my satisfaction, of such other corporate records of the Borrower, certificates

D-3

of public officials and of officers of the Borrower, and agreements, instruments and other documents, as I have deemed necessary as a basis for the opinions expressed below.

In my examination, I, or attorneys over whom I exercise supervision, have assumed the genuineness of all signatures, the legal capacity of natural persons, the authenticity of all documents submitted to us as originals and the conformity with the originals of all documents submitted to us as copies. In making our examination of documents and instruments executed or to be executed by persons other than the Borrower, I, or attorneys over whom I exercise supervision, have assumed that each such other person had the requisite power and authority to enter into and perform fully its obligations thereunder, the due authorization by each such other person for the execution, delivery and performance thereof and the due execution and delivery thereof by or on behalf of such person of each such document and instrument. In the case of any such person that is not a natural person, I, or attorneys over whom I exercise supervision, have also assumed, insofar as it is relevant to the opinions set forth below, that each such other person is duly organized, validly existing and in good standing under the laws of the jurisdiction in which it was created and is duly qualified and in good standing in each other jurisdiction where the failure to be so qualified could reasonably be expected to have a material effect upon its ability to execute, deliver and/or perform its obligations under any such document or instrument. I, or attorneys over whom I exercise supervision, have further assumed that each document, instrument, agreement, record and certificate reviewed by us for purposes of rendering the opinions expressed below has not been amended by any oral agreement, conduct or course of dealing between the parties thereto.

As to questions of fact material to the opinions expressed herein, I have relied upon certificates and representations of officers of the Borrower (including but not limited to those contained in the Credit Agreement and certificates delivered upon the execution and delivery of the Credit Agreement) and of appropriate public officials, without independent verification of such matters except as otherwise described herein.

Whenever my opinions herein with respect to the existence or absence of facts are stated to be to my knowledge or awareness, it is intended to signify that no information has come to my attention or the attention of other counsel working under my direction in connection with the preparation of this opinion letter that would give me or them actual knowledge of the existence or absence of such facts. However, except to the extent expressly set forth herein, neither I nor they have undertaken any independent investigation to determine the existence or absence of such facts, and no inference as to my or their knowledge of the existence or absence of such facts should be assumed.

I am a member of the Bar of the States of New York and Ohio and do not purport to be expert on the laws of any jurisdiction other than the laws of the States of New York and Ohio and the Federal laws of the United States. My opinions expressed below are limited to the law of the States of New York and Ohio and the Federal law of the United States.

Based upon the foregoing and upon such investigation as I have deemed necessary, and subject to the limitations, qualifications and assumptions set forth herein, I am of the following opinion:

D-4

1. The Borrower (a) is a corporation duly organized, validly existing and in good standing under the laws of the State of New York; (b) has the corporate power and authority, and the legal right, to own and operate its property, to lease the property which it operates as lessee and to conduct the business in which it is currently engaged and in which it proposes to be engaged after the date hereof; (c) is duly qualified as a foreign corporation and is in good standing under the laws of each jurisdiction where its ownership, lease or operation of property or the conduct of its business requires such qualification, except any such jurisdiction where the failure to so qualify could not, in the aggregate, reasonably be expected to result in a Material Adverse Change; (d) owns or possesses all material licenses and permits necessary for the operation by it of its business as currently conducted; and (e) is in compliance with all Requirements of Law, except as disclosed in the Disclosure Documents referenced in Section 4.01(e) of the Credit Agreement or to the extent that the failure to comply therewith could not, in the aggregate, reasonably be expected to have a Material Adverse Effect. The term “Requirements of Law” means the laws of the State of New York and the laws, rules and regulations of the United States of America (including, without limitation, ERISA and Environmental Laws) and orders of any governmental authority applicable to the Borrower.

2. The Borrower has the corporate power and authority, and the legal right, to execute and deliver each Loan Document and to perform its obligations under each Loan Document, and to borrow under the Credit Agreement. The Borrower has taken all necessary corporate action to authorize the execution, delivery and performance of each Loan Document and the incurrence of Advances on the terms and conditions of the Credit Agreement, and each Loan Document has been duly executed and delivered by the Borrower. Each Loan Document constitutes the valid and legally binding obligation of the Borrower enforceable against the Borrower in accordance with its terms.

3. The execution, delivery and performance of each Loan Document and the Advances made under the Credit Agreement will not violate any Requirements of Law, the Borrower’s certificate of incorporation or by-laws, or any material contractual restriction binding on or affecting the Borrower or any of its properties.

4. No approval or authorization or other action by, and no notice to or filing with, any governmental agency or regulatory body or other third person is required in connection with the due execution and delivery of any Loan Document and the performance, validity and enforceability of any Loan Document.

5. Except as described in Section 4.01(e) of the Credit Agreement, no action, suit, investigation, litigation, or proceeding, including, without limitation, any Environmental Action, affecting the Borrower or any of its Significant Subsidiaries before any court, government agency or arbitrator is pending or, to

D-5

my knowledge, threatened, that is reasonably likely to have a Material Adverse Effect.

6. Neither the Borrower nor any of its Significant Subsidiaries is an “investment company”, or an “affiliated person” of, or “promoter” or “principal underwriter” for, an “investment company”, as such terms are defined in the Investment Company Act of 1940, as amended (the “1940 Act”). Neither the making of any Advances, the application of the proceeds or repayment thereof by the Borrower nor the consummation of the other transactions contemplated by the Credit Agreement will violate any provision of the 1940 Act or any rule, regulation or order of the Securities and Exchange Commission thereunder.

The opinion set forth above in the last sentence of paragraph 2 above is subject to the effect of any applicable bankruptcy, insolvency, reorganization, moratorium or similar laws affecting creditor’s rights generally and to general principles of equity, including (without limitation) concepts of materiality, reasonableness, good faith and fair dealing (regardless of whether considered in a proceeding in equity or at law.)

I express no opinion as to (i) Section 8.05 of the Credit Agreement; (ii) the effect of the law of any jurisdiction (other than the State of New York) wherein any Lender may be located which limits the rates of interest which may be charged or collected by such Lender; and (iii) whether a Federal or state court outside of the State of New York would give effect to the choice of New York law provided for in the Credit Agreement.

This opinion letter has been rendered solely for your benefit in connection with the Credit Agreement and the transactions contemplated thereby and may not be used, circulated, quoted, relied upon or otherwise referred to by any other person (other than your respective counsel, auditors and any regulatory agency having jurisdiction over you or as otherwise required pursuant to legal process or other requirements of law) for any other purpose without my prior written consent; provided that, any person that becomes a Lender after the date hereof may rely on the opinions expressed in this opinion letter as though addressed to such person. I undertake no responsibility to update or supplement this opinion in response to changes in law or future events or circumstances.

Very truly yours,

David C. House

Counsel for American Electric Power Company, Inc.

EXHIBIT D-1

FORM OF U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Lenders That Are Not Partnerships

For U.S. Federal Income Tax Purposes)

U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Lenders That Are Not Partnerships For U.S. Federal Income Tax Purposes)

Reference is hereby made to the Credit Agreement, dated as of March 23, 2020 (as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), among American Electric Power Company, Inc. (the “Borrower”), the Lenders named therein and PNC Bank, National Association, as the administrative agent (the “Administrative Agent”) for the Lenders.

Pursuant to the provisions of Section 2.15 of the Credit Agreement, the undersigned hereby certifies that (i) it is the sole record and beneficial owner of the Advance(s) and Commitment (as well as any promissory note(s) evidencing such Advance(s) and Commitment) in respect of which it is providing this certificate, (ii) it is not a bank within the meaning of Section 881(c)(3)(A) of the Internal Revenue Code, (iii) it is not a ten percent shareholder of the Borrower within the meaning of Section 871(h)(3)(B) of the Internal Revenue Code and (iv) it is not a controlled foreign corporation related to the Borrower as described in Section 881(c)(3)(C) of the Internal Revenue Code.

The undersigned has furnished the Administrative Agent and the Borrower with a certificate of its non-U.S. Person status on IRS Form W-8BEN or W‑8BEN‑E. By executing this certificate, the undersigned agrees that (1) if the information provided on this certificate changes, the undersigned shall promptly so inform the Administrative Agent and the Borrower, and (2) the undersigned shall have at all times furnished the Administrative Agent and the Borrower with a properly completed and currently effective certificate in either the calendar year in which each payment is to be made to the undersigned, or in either of the two calendar years preceding such payments.

Unless otherwise defined herein, terms defined in the Credit Agreement and used herein shall have the meanings given to them in the Credit Agreement.

[NAME OF LENDER]

By:_____________________

Name:

Title:

Date: ________ __, 20[ ]

EXHIBIT D-2

FORM OF U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Participants That Are Not Partnerships

For U.S. Federal Income Tax Purposes)

U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Participants That Are Not Partnerships For U.S. Federal Income Tax Purposes)

Reference is hereby made to the Credit Agreement, dated as of March 23, 2020 (as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), among American Electric Power Company, Inc. (the “Borrower”), the Lenders named therein and PNC Bank, National Association, as the administrative agent (the “Administrative Agent”) for the Lenders.

Pursuant to the provisions of Section 2.15 of the Credit Agreement, the undersigned hereby certifies that (i) it is the sole record and beneficial owner of the participation in respect of which it is providing this certificate, (ii) it is not a bank within the meaning of Section 881(c)(3)(A) of the Internal Revenue Code, (iii) it is not a ten percent shareholder of the Borrower within the meaning of Section 871(h)(3)(B) of the Internal Revenue Code, and (iv) it is not a controlled foreign corporation related to the Borrower as described in Section 881(c)(3)(C) of the Internal Revenue Code.

The undersigned has furnished its participating Lender with a certificate of its non-U.S. Person status on IRS Form W-8BEN or W‑8BEN‑E. By executing this certificate, the undersigned agrees that (1) if the information provided on this certificate changes, the undersigned shall promptly so inform such Lender in writing, and (2) the undersigned shall have at all times furnished such Lender with a properly completed and currently effective certificate in either the calendar year in which each payment is to be made to the undersigned, or in either of the two calendar years preceding such payments.

Unless otherwise defined herein, terms defined in the Credit Agreement and used herein shall have the meanings given to them in the Credit Agreement.

[NAME OF PARTICIPANT]

By:____________________

Name:

Title:

Date: ________ __, 20[ ]

EXHIBIT D-3

FORM OF U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Participants That Are Partnerships

For U.S. Federal Income Tax Purposes)

U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Participants That Are Partnerships For U.S. Federal Income Tax Purposes)

Reference is hereby made to the Credit Agreement, dated as of March 23, 2020 (as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), among American Electric Power Company, Inc. (the “Borrower”), the Lenders named therein and PNC Bank, National Association, as the administrative agent (the “Administrative Agent”) for the Lenders.

Pursuant to the provisions of Section 2.15 of the Credit Agreement, the undersigned hereby certifies that (i) it is the sole record owner of the participation in respect of which it is providing this certificate, (ii) its direct or indirect partners/members are the sole beneficial owners of such participation, (iii) with respect such participation, neither the undersigned nor any of its direct or indirect partners/members is a bank extending credit pursuant to a loan agreement entered into in the ordinary course of its trade or business within the meaning of Section 881(c)(3)(A) of the Internal Revenue Code, (iv) none of its direct or indirect partners/members is a ten percent shareholder of the Borrower within the meaning of Section 871(h)(3)(B) of the Internal Revenue Code and (v) none of its direct or indirect partners/members is a controlled foreign corporation related to the Borrower as described in Section 881(c)(3)(C) of the Internal Revenue Code.

The undersigned has furnished its participating Lender with IRS Form W-8IMY accompanied by one of the following forms from each of its partners/members that is claiming the portfolio interest exemption: (i) an IRS Form W-8BEN or W‑8BEN‑E, or (ii) an IRS Form W-8IMY accompanied by an IRS Form W-8BEN or W‑8BEN‑E from each of such partner’s/member’s beneficial owners that is claiming the portfolio interest exemption. By executing this certificate, the undersigned agrees that (1) if the information provided on this certificate changes, the undersigned shall promptly so inform such Lender and (2) the undersigned shall have at all times furnished such Lender with a properly completed and currently effective certificate in either the calendar year in which each payment is to be made to the undersigned, or in either of the two calendar years preceding such payments.

Unless otherwise defined herein, terms defined in the Credit Agreement and used herein shall have the meanings given to them in the Credit Agreement.

[NAME OF PARTICIPANT]

By:_______________________

Name:

Title:

Date: ________ __, 20[ ]

EXHIBIT D-4

FORM OF U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Lenders That Are Partnerships

For U.S. Federal Income Tax Purposes)

U.S. TAX COMPLIANCE CERTIFICATE

(For Foreign Lenders That Are Partnerships For U.S. Federal Income Tax Purposes)

Reference is hereby made to the Credit Agreement, dated as of March 23, 2020 (as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), among American Electric Power Company, Inc. (the “Borrower”), the Lenders named therein and PNC Bank, National Association, as the administrative agent (the “Administrative Agent”) for the Lenders.

Pursuant to the provisions of Section 2.15 of the Credit Agreement, the undersigned hereby certifies that (i) it is the sole record owner of the Advance(s) and Commitment (as well as any promissory note(s) evidencing such Advance(s) and Commitment) in respect of which it is providing this certificate, (ii) its direct or indirect partners/members are the sole beneficial owners of such Advance(s) and Commitment (as well as any promissory note(s) evidencing such Advance(s) and Commitment), (iii) with respect to the extension of credit pursuant to the Credit Agreement or any other Loan Document, neither the undersigned nor any of its direct or indirect partners/members is a bank extending credit pursuant to a loan agreement entered into in the ordinary course of its trade or business within the meaning of Section 881(c)(3)(A) of the Internal Revenue Code, (iv) none of its direct or indirect partners/members is a ten percent shareholder of the Borrower within the meaning of Section 871(h)(3)(B) of the Internal Revenue Code and (v) none of its direct or indirect partners/members is a controlled foreign corporation related to the Borrower as described in Section 881(c)(3)(C) of the Internal Revenue Code.

The undersigned has furnished the Administrative Agent and the Borrower with IRS Form W-8IMY accompanied by one of the following forms from each of its partners/members that is claiming the portfolio interest exemption: (i) an IRS Form W-8BEN or W‑8BEN‑E or (ii) an IRS Form W-8IMY accompanied by an IRS Form W-8BEN or W‑8BEN‑E from each of such partner’s/member’s beneficial owners that is claiming the portfolio interest exemption. By executing this certificate, the undersigned agrees that (1) if the information provided on this certificate changes, the undersigned shall promptly so inform the Administrative Agent and the Borrower, and (2) the undersigned shall have at all times furnished the Administrative Agent and the Borrower with a properly completed and currently effective certificate in either the calendar year in which each payment is to be made to the undersigned, or in either of the two calendar years preceding such payments.

Unless otherwise defined herein, terms defined in the Credit Agreement and used herein shall have the meanings given to them in the Credit Agreement.

[NAME OF LENDER]

By:_________________

Name:

Title:

Date: ________ __, 20[ ]

EXHIBIT E

Form of REQUEST FOR FACILITY INCREASE

_________ __, 20___

PNC Bank, National Association,

as Administrative Agent

[______________]

Attention: [______________]

Re:Credit Agreement dated as of March 23, 2020 (as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), among American Electric Power Company, Inc. (the “Borrower”), PNC Bank, National Association, as Administrative Agent (“Administrative Agent”), and each lender from time to time party thereto (the “Lenders”). Capitalized terms not defined herein shall have the meanings assigned to such terms in the Credit Agreement.

Pursuant to Section 2.18 of the Credit Agreement, the Borrower hereby requests that the aggregate commitment under the Credit Agreement be increased by an amount of $____________, the total Facility amount shall be $_______________ after giving effect to the full amount of such requested increase, such increase to be effective as of ____________ __, 20___. The Borrower hereby acknowledges that in the event the Administrative Agent is unable to secure commitments from existing Lenders or new lenders for the entire amount of the increase requested hereby on or prior to __________, 20___ [insert the 30th day after the date of this request], then this request shall be deemed rescinded with respect to commitments not secured on and as of such date.

As of the date of this Request for Facility Increase: (a) the representations and warranties of the Borrower are true and correct as if made on and as of this date, except to the extent such representations and warranties expressly relate to an earlier date in which case such representations and warranties shall be true and correct as of such earlier date; and (b) no Default or Event of Default has occurred and is continuing.

Sincerely,

AMERICAN ELECTRIC POWER COMPANY, INC.

By

Name:

Title:

EXHIBIT F

FORM OF CONFIRMATION OF FACILITY INCREASE

__________, 20___

American Electric Power Company, Inc.,

as Borrower

[_______]

[_______]

Attention:[__________]

[__________]

[__________]

Re: Credit Agreement dated as of March 23, 2020 (as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), among American Electric Power Company, Inc. (the “Borrower”), PNC Bank, National Association, as Administrative Agent (“Administrative Agent”), and each lender from time to time party thereto (the “Lenders”). Capitalized terms not defined herein shall have the meanings assigned to such terms in the Credit Agreement.

This Confirmation of Facility Increase is delivered pursuant to Section 2.18 of the Credit Agreement.

The undersigned confirms receipt of the Notice of Facility Increase, dated ________ __, 20___.

As of __________ __, 20___, the total Facility amount will be increased to $___________, with the Commitment of each Lender as follows:

Lender	Commitment
	$
	$
	$
	$
Total Facility amount	$

Sincerely,

PNC BANK, NATIONAL ASSOCIATION, as

Administrative Agent

By: _______________________________________

Name:_____________________________________

Title:______________________________________

EXHIBIT G

FORM OF LENDER COMMITMENT INCREASE AGREEMENT

This LENDER COMMITMENT INCREASE AGREEMENT (this “Agreement”) is made as of __________ __, 20__.

WHEREAS, reference is hereby made to the Credit Agreement dated as of March 23, 2020 (as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), among American Electric Power Company, Inc. (the “Borrower”), PNC Bank, National Association, as Administrative Agent (the “Administrative Agent”) and each lender from time to time party thereto (the “Lenders”). Capitalized terms not defined herein shall have the meanings assigned to such terms in the Credit Agreement.

WHEREAS, pursuant to Section 2.18 of the Credit Agreement, the Borrower delivered a Request for Facility Increase to the Administrative Agent, dated ________ __, 20__;

WHEREAS, pursuant to Section 2.18 of the Credit Agreement, the Administrative Agent will deliver a Confirmation of Commitment Increase (the “Confirmation of Commitment Increase”) pursuant to which ____________________________ (“Existing Lender”) will be listed as having a $______________ Commitment under the Credit Agreement, an increase of $_____________ over its existing Commitment (such increase amount, the “Commitment Increase”); and

WHEREAS, Existing Lender, Borrower and Agent desire to enter into this Agreement pursuant to which Existing Lender will increase its Commitment under, the Credit Agreement in an amount equal to the Commitment Increase;

NOW, THEREFORE, in consideration of the mutual promises herein contained and for other valuable consideration, the parties hereto do hereby agree as follows:

1. The Existing Lender hereby:

(a) confirms that it has received a copy of the Credit Agreement and the other Loan Documents, and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into this Agreement;

(b) agrees that it will, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Credit Agreement or any other Loan Document; and

(c) attaches (or has delivered to the Administrative Agent) completed and signed copies of any forms that may be required by the United States Internal Revenue Service in order to certify Existing Lender's exemption from United States withholding taxes with respect to any payments or distributions made or to be made to Existing Lender in respect of the Advances or under the Credit Agreement or such other documents as are necessary to indicate that all such payments or distributions are subject to such taxes at a rate reduced by an applicable tax treaty;

2. The Commitment Increase of Existing Lender shall become effective upon the satisfaction of the following conditions:

(a) the execution of this Agreement by each of the parties hereto;

(b) the receipt by the Administrative Agent of the amount listed in the funding notice delivered to Existing Lender, such amount representing the Existing Lender's pro rata share of the outstanding Advances under the Credit Agreement; and

(c) the Administrative Agent shall have delivered the Confirmation of Facility Increase to the Borrower and the Lenders.

3. EACH OF THE PARTIES HERETO HEREBY IRREVOCABLY AND UNCONDITIONALLY SUBMITS, FOR ITSELF AND ITS PROPERTY, TO THE EXCLUSIVE JURISDICTION OF ANY NEW YORK STATE COURT OR FEDERAL COURT OF THE UNITED STATES OF AMERICA SITTING IN NEW YORK CITY, THE COUNTY OF NEW YORK, AND ANY APPELLATE COURT FROM ANY THEREOF, IN ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT, OR FOR RECOGNITION OR ENFORCEMENT OF ANY JUDGMENT, AND EACH OF THE PARTIES HERETO HEREBY IRREVOCABLY AND UNCONDITIONALLY AGREES THAT ALL CLAIMS IN RESPECT OF ANY SUCH ACTION OR PROCEEDING MAY BE HEARD AND DETERMINED IN ANY SUCH NEW YORK STATE COURT OR, TO THE EXTENT PERMITTED BY LAW, IN SUCH FEDERAL COURT. EACH OF THE PARTIES HERETO AGREES THAT A FINAL JUDGMENT IN ANY SUCH ACTION OR PROCEEDING SHALL BE CONCLUSIVE AND MAY BE ENFORCED IN OTHER JURISDICTIONS BY SUIT ON THE JUDGMENT OR IN ANY OTHER MANNER PROVIDED BY LAW. NOTHING IN THIS AGREEMENT SHALL AFFECT ANY RIGHT THAT ANY PARTY MAY OTHERWISE HAVE TO BRING ANY ACTION OR PROCEEDING RELATING TO THIS AGREEMENT IN THE COURTS OF ANY JURISDICTION.

4. This Agreement may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. Delivery of an executed counterpart of a signature page to this Agreement by fax shall be effective as delivery of a manually executed counterpart of this Agreement.

REMAINDER OF PAGE INTENTIONALLY LEFT BLANK.

SIGNATURE PAGE FOLLOWS.

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by their officers thereunto duly authorized as of the date specified thereon.

[__________], as Existing Lender

By

Name:

Title:

American Electric Power Company, Inc.

By    ____________________________    

Name:

Title:

PNC BANK, NATIONAL ASSOCIATION,

as Administrative Agent

By    ____________________________    

Name:

Title:

EXHIBIT H

FORM OF NEW LENDER JOINDER AGREEMENT

This NEW LENDER JOINDER AGREEMENT (this “Agreement”) is made as of ______________ __, 20___.

WHEREAS, reference is hereby made to the Credit Agreement dated as of March 23, 2020 (as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), among American Electric Power Company, Inc. (the “Borrower”), PNC Bank, National Association, as Administrative Agent (the “Administrative Agent”) and each lender from time to time party thereto (the “Lenders”). Capitalized terms not defined herein shall have the meanings assigned to such terms in the Credit Agreement.

WHEREAS, pursuant to Section 2.18 of the Credit Agreement, the Borrower delivered a Request for Facility Increase to the Administrative Agent, dated ___________ __, 20___;

WHEREAS, pursuant to Section 2.18 of the Credit Agreement, the Administrative Agent will deliver a Confirmation of Commitment Increase (the “Confirmation of Commitment Increase”) pursuant to which _____________________________ (“New Lender”) will be listed as having a $__________________¹ Commitment under the Credit Agreement; and

WHEREAS, New Lender, Borrower and the Administrative Agent desire to enter into this Agreement pursuant to which New Lender will become a party to, and a Lender under, the Credit Agreement;

NOW, THEREFORE, in consideration of the mutual promises herein contained and for other valuable consideration, the parties hereto do hereby agree as follows:

1.New Lender hereby:

(a)confirms that it has received a copy of the Credit Agreement and the other Loan Documents, and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into this Agreement;

(b)agrees that it will, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Credit Agreement or any other Loan Document;

(c)appoints and authorizes the Administrative Agent to take such action as agent on its behalf and to exercise such powers and discretion under the Credit Agreement and the other Loan Documents as are delegated to the Administrative Agent by the terms thereof, together with such powers and discretion as are reasonably incidental thereto;

_______________________

1.Such amount to be not less than $5,000,000

(d)agrees that it will perform in accordance with their terms all of the obligations that by the terms of the Credit Agreement are required to be performed by it as a Lender;

(e)if New Lender is organized under the laws of a jurisdiction outside the United States, attaches (or has delivered to the Administrative Agent) completed and signed copies of any forms that may be required by the United States Internal Revenue Service in order to certify New Lender's exemption from United States withholding taxes with respect to any payments or distributions made or to be made to New Lender in respect of the Advances or under the Credit Agreement or such other documents as are necessary to indicate that all such payments or distributions are subject to such taxes at a rate reduced by an applicable tax treaty; and

(f)provides the following notice information for the purpose of Section 8.02 of the Credit Agreement:

__________________

__________________

__________________

Attn:___________

Tel. No.:________

Fax No.:________

E-Mail:_________

2.New Lender shall become a party to the Credit Agreement and the other Loan Documents, and shall have the rights and obligations of a Lender thereunder, upon the satisfaction of the following conditions:

(a)the execution of this Agreement by each of the parties hereto;

(b)the receipt by the Administrative Agent of the amount listed in the funding notice delivered to New Lender, such amount representing the New Lender's pro rata share of the outstanding Advances under the Credit Agreement; and

(c)the Administrative Agent shall have delivered the Confirmation of Commitment Increase to the Borrower, the Lenders and New Lender.

3.EACH OF THE PARTIES HERETO HEREBY IRREVOCABLY AND UNCONDITIONALLY SUBMITS, FOR ITSELF AND ITS PROPERTY, TO THE EXCLUSIVE JURISDICTION OF ANY NEW YORK STATE COURT OR FEDERAL COURT OF THE UNITED STATES OF AMERICA SITTING IN NEW YORK CITY, THE COUNTY OF NEW YORK, AND ANY APPELLATE COURT FROM ANY THEREOF, IN ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT, OR FOR RECOGNITION OR ENFORCEMENT OF ANY JUDGMENT, AND EACH OF THE PARTIES HERETO HEREBY IRREVOCABLY AND UNCONDITIONALLY AGREES THAT ALL CLAIMS IN RESPECT OF ANY SUCH ACTION OR PROCEEDING MAY BE HEARD AND DETERMINED IN ANY SUCH NEW YORK STATE COURT OR, TO THE EXTENT PERMITTED BY LAW, IN SUCH FEDERAL COURT. EACH OF THE PARTIES HERETO AGREES THAT A FINAL JUDGMENT IN ANY SUCH ACTION OR

PROCEEDING SHALL BE CONCLUSIVE AND MAY BE ENFORCED IN OTHER JURISDICTIONS BY SUIT ON THE JUDGMENT OR IN ANY OTHER MANNER PROVIDED BY LAW. NOTHING IN THIS AGREEMENT SHALL AFFECT ANY RIGHT THAT ANY PARTY MAY OTHERWISE HAVE TO BRING ANY ACTION OR PROCEEDING RELATING TO THIS AGREEMENT IN THE COURTS OF ANY JURISDICTION.

4.This Agreement may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. Delivery of an executed counterpart of a signature page to this Agreement by fax shall be effective as delivery of a manually executed counterpart of this Agreement.

REMAINDER OF PAGE INTENTIONALLY LEFT BLANK.

SIGNATURE PAGE FOLLOWS.

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by their officers thereunto duly authorized as of the date specified thereon.

[__________], as New Lender

By

Name:

Title:

American Electric Power Company, Inc.

By    _____________________________________    

Name:

Title:

PNC BANK, NATIONAL ASSOCIATION,

as Administrative Agent

By    ______________________________________    

Name:

Title:

Schedule I

Schedule of Initial Lenders

Lender Name	Commitment
PNC Bank, National Association	$166,666,666.70
Wells Fargo Bank, National Association	$166,666,666.66
Keybank National Association	$166,666,666.66
U.S. Bank National Association	$166,666,666.66
Sumitomo Mitsui Banking Corporation	$166,666,666.66
Truist Bank	$166,666,666.66
Total	$1,000,000,000.00

Schedule I

AEP - CREDIT AGREEMENT

Schedule 4.01(m)

Significant Subsidiaries

Appalachian Power Company

Ohio Power Company

Indiana Michigan Power Company

Southwestern Electric Power Company

AEP Texas Inc.

AEP Transmission Company, LLC

AEP Transmission Holding Company, LLC

Schedule 4.01(M)

AEP - CREDIT AGREEMENT

EX-31.A

EXHIBIT 31(a)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1. I have reviewed this report on Form 10-Q of American Electric Power Company, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   May 6, 2020	By:	/s/ Nicholas K. Akins
		Nicholas K. Akins
		Chief Executive Officer

EX-31.A

EXHIBIT 31(a)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1. I have reviewed this report on Form 10-Q of AEP Transmission Company, LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 6, 2020	By:	/s/ Nicholas K. Akins
		Nicholas K. Akins
		Chief Executive Officer

EX-31.A

EXHIBIT 31(a)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1. I have reviewed this report on Form 10-Q of AEP Texas Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   May 6, 2020	By:	/s/ Nicholas K. Akins
		Nicholas K. Akins
		Chief Executive Officer

EX-31.A

EXHIBIT 31(a)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1. I have reviewed this report on Form 10-Q of Appalachian Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   May 6, 2020	By:	/s/ Nicholas K. Akins
		Nicholas K. Akins
		Chief Executive Officer

EX-31.A

EXHIBIT 31(a)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1. I have reviewed this report on Form 10-Q of Indiana Michigan Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   May 6, 2020	By:	/s/ Nicholas K. Akins
		Nicholas K. Akins
		Chief Executive Officer

EX-31.A

EXHIBIT 31(a)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1. I have reviewed this report on Form 10-Q of Ohio Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   May 6, 2020	By:	/s/ Nicholas K. Akins
		Nicholas K. Akins
		Chief Executive Officer

EX-31.A

EXHIBIT 31(a)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1. I have reviewed this report on Form 10-Q of Public Service Company of Oklahoma;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   May 6, 2020	By:	/s/ Nicholas K. Akins
		Nicholas K. Akins
		Chief Executive Officer

EX-31.A

EXHIBIT 31(a)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1. I have reviewed this report on Form 10-Q of Southwestern Electric Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   May 6, 2020	By:	/s/ Nicholas K. Akins
		Nicholas K. Akins
		Chief Executive Officer

EX-31.B

EXHIBIT 31(b)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1. I have reviewed this report on Form 10-Q of American Electric Power Company, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   May 6, 2020	By:	/s/ Brian X. Tierney
		Brian X. Tierney
		Chief Financial Officer

EX-31.B

EXHIBIT 31(b)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1. I have reviewed this report on Form 10-Q of AEP Transmission Company, LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 6, 2020	By:	/s/ Brian X. Tierney
		Brian X. Tierney
		Chief Financial Officer

EX-31.B

EXHIBIT 31(b)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1. I have reviewed this report on Form 10-Q of AEP Texas Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   May 6, 2020	By:	/s/ Brian X. Tierney
		Brian X. Tierney
		Chief Financial Officer

EX-31.B

EXHIBIT 31(b)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1. I have reviewed this report on Form 10-Q of Appalachian Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   May 6, 2020	By:	/s/ Brian X. Tierney
		Brian X. Tierney
		Chief Financial Officer

EX-31.B

EXHIBIT 31(b)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1. I have reviewed this report on Form 10-Q of Indiana Michigan Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   May 6, 2020	By:	/s/ Brian X. Tierney
		Brian X. Tierney
		Chief Financial Officer

EX-31.B

EXHIBIT 31(b)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1. I have reviewed this report on Form 10-Q of Ohio Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   May 6, 2020	By:	/s/ Brian X. Tierney
		Brian X. Tierney
		Chief Financial Officer

EX-31.B

EXHIBIT 31(b)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1. I have reviewed this report on Form 10-Q of Public Service Company of Oklahoma;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   May 6, 2020	By:	/s/ Brian X. Tierney
		Brian X. Tierney
		Chief Financial Officer

EX-31.B

EXHIBIT 31(b)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1. I have reviewed this report on Form 10-Q of Southwestern Electric Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   May 6, 2020	By:	/s/ Brian X. Tierney
		Brian X. Tierney
		Chief Financial Officer

EX-32.A

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of American Electric Power Company, Inc. (the “Company”) on Form 10-Q (the “Report”) for the quarter ended March 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

May 6, 2020

A signed original of this written statement required by Section 906 has been provided to American Electric Power Company, Inc. and will be retained by American Electric Power Company, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.A

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of AEP Transmission Company, LLC (the “Company”) on Form 10-Q (the “Report”) for the quarter ended March 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

May 6, 2020

A signed original of this written statement required by Section 906 has been provided to AEP Transmission Company, LLC and will be retained by AEP Transmission Company, LLC and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.A

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of AEP Texas Inc. (the “Company”) on Form 10-Q (the “Report”) for the quarter ended March 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

May 6, 2020

A signed original of this written statement required by Section 906 has been provided to AEP Texas Inc. and will be retained by AEP Texas Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.A

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Appalachian Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended March 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

May 6, 2020

A signed original of this written statement required by Section 906 has been provided to Appalachian Power Company and will be retained by Appalachian Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.A

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Indiana Michigan Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended March 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

May 6, 2020

A signed original of this written statement required by Section 906 has been provided to Indiana Michigan Power Company and will be retained by Indiana Michigan Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.A

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Ohio Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended March 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

May 6, 2020

A signed original of this written statement required by Section 906 has been provided to Ohio Power Company and will be retained by Ohio Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.A

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Public Service Company of Oklahoma (the “Company”) on Form 10-Q (the “Report”) for the quarter ended March 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

May 6, 2020

A signed original of this written statement required by Section 906 has been provided to Public Service Company of Oklahoma and will be retained by Public Service Company of Oklahoma and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.A

Exhibit 32(a)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Southwestern Electric Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended March 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

May 6, 2020

A signed original of this written statement required by Section 906 has been provided to Southwestern Electric Power Company and will be retained by Southwestern Electric Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.B

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of American Electric Power Company, Inc. (the “Company”) on Form 10-Q (the “Report”) for the quarter ended March 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Brian X. Tierney

Brian X. Tierney

Chief Financial Officer

May 6, 2020

A signed original of this written statement required by Section 906 has been provided to American Electric Power Company, Inc. and will be retained by American Electric Power Company, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.B

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of AEP Transmission Company, LLC (the “Company”) on Form 10-Q (the “Report”) for the quarter ended March 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Brian X. Tierney

Brian X. Tierney

Chief Financial Officer

May 6, 2020

A signed original of this written statement required by Section 906 has been provided to AEP Transmission Company, LLC and will be retained by AEP Transmission Company, LLC and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.B

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of AEP Texas Inc. (the “Company”) on Form 10-Q (the “Report”) for the quarter ended March 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Brian X. Tierney

Brian X. Tierney

Chief Financial Officer

May 6, 2020

A signed original of this written statement required by Section 906 has been provided to AEP Texas Inc. and will be retained by AEP Texas Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.B

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Appalachian Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended March 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Brian X. Tierney

Brian X. Tierney

Chief Financial Officer

May 6, 2020

A signed original of this written statement required by Section 906 has been provided to Appalachian Power Company and will be retained by Appalachian Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.B

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Indiana Michigan Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended March 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Brian X. Tierney

Brian X. Tierney

Chief Financial Officer

May 6, 2020

A signed original of this written statement required by Section 906 has been provided to Indiana Michigan Power Company and will be retained by Indiana Michigan Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.B

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Ohio Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended March 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Brian X. Tierney

Brian X. Tierney

Chief Financial Officer

May 6, 2020

A signed original of this written statement required by Section 906 has been provided to Ohio Power Company and will be retained by Ohio Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.B

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Public Service Company of Oklahoma (the “Company”) on Form 10-Q (the “Report”) for the quarter ended March 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Brian X. Tierney

Brian X. Tierney

Chief Financial Officer

May 6, 2020

A signed original of this written statement required by Section 906 has been provided to Public Service Company of Oklahoma and will be retained by Public Service Company of Oklahoma and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.B

Exhibit 32(b)

This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Southwestern Electric Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended March 31, 2020 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Brian X. Tierney

Brian X. Tierney

Chief Financial Officer

May 6, 2020

A signed original of this written statement required by Section 906 has been provided to Southwestern Electric Power Company and will be retained by Southwestern Electric Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-95

Exhibit 95

MINE SAFETY INFORMATION

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 Dolet Hills Lignite Company (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. DHLC received the following notices of violation and proposed assessments under the Mine Act for the quarter ended March 31, 2020:

Number of Citations for S&S Violations of Mandatory Health or Safety Standards under 104 *	0
Number of Orders Issued under 104(b) *	0
Number of Citations and Orders for Unwarrantable Failure to Comply with Mandatory Health or Safety Standards under 104(d) *	0
Number of Flagrant Violations under 110(b)(2) *	0
Number of Imminent Danger Orders Issued under 107(a) *	0
Total Dollar Value of Proposed Assessments **	$	403
Number of Mining-related Fatalities	0

* References to sections under the Mine Act.

** DHLC received two non-S&S citations during the fourth quarter of 2019 and one non-S&S citation in the first quarter of 2020. The proposed assessments for these three citations, totaling $403, were received in this quarter.

There are currently no legal actions pending before the Federal Mine Safety and Health Review Commission.

XML

Commitments, Guarantees and Contingencies

3 Months Ended

Mar. 31, 2020

Commitments, Guarantees and Contingencies

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.

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 were as follows:

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.

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.  

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)

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 due to the recent passage of the legislation.  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.

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)

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

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

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

Thereafter, AEP filed a motion with the U.S. District Court for the Southern District of Ohio in the original NSR litigation, seeking to modify the consent decree. The district court granted the owners’ unopposed motion to stay the lease litigation to afford time for resolution of AEP’s motion to modify the consent decree. 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.

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 (Applies to AEP, AEP Texas and SWEPCo)

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.

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Derivatives and Hedging

3 Months Ended

Mar. 31, 2020

Derivatives and Hedging

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.

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.

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.

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

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

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	)

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.

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.”

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.

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.

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

XML

Comprehensive Income (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2020		Mar. 31, 2019
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		$ (147.7)		$ (120.4)
Change in Fair Value Recognized in AOCI		(108.0)		(38.8)
Commodity
Generation & Marketing Revenues		3,747.5		4,056.8
Interest Rate
Interest Expense		292.1		255.8
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		49.6		10.7
Income Tax (Expense) Benefit		46.5		44.5
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		39.2		8.5
Net Current Period Other Comprehensive Income (Loss)		(68.8)		(30.3)
Ending Balance in AOCI		(216.5)		(150.7)
Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(32.7)		(84.8)
Change in Fair Value Recognized in AOCI		0.0		0.0
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		(2.3)		(1.8)
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		(1.8)		(1.4)
Net Current Period Other Comprehensive Income (Loss)		(1.8)		(1.4)
Ending Balance in AOCI		(34.5)		(86.2)
Accumulated Other Comprehensive Income [Member]
Amortization Of Pension And Other Postretirement Benefit Plans
Net Current Period Other Comprehensive Income (Loss)		(68.8)		(30.3)
Commodity [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(103.5)		(23.0)
Change in Fair Value Recognized in AOCI		(65.3)		(38.8)
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		51.0		12.3
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		40.3		9.7
Net Current Period Other Comprehensive Income (Loss)		(25.0)		(29.1)
Ending Balance in AOCI		(128.5)		(52.1)
Interest Rate [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(11.5)		(12.6)
Change in Fair Value Recognized in AOCI		(42.7)	[1]	0.0
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		0.9		0.2
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		0.7		0.2
Net Current Period Other Comprehensive Income (Loss)		(42.0)		0.2
Ending Balance in AOCI		(53.5)		(12.4)
Generation and Marketing Revenues [Member]
Commodity
Generation & Marketing Revenues		408.4		439.7
Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale		795.7		861.8
Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	[2]	0.9		0.2
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		(4.9)		(4.8)
Amortization of Actuarial (Gains) Losses		2.6		3.0
Income Tax (Expense) Benefit		10.4		2.2
Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Interest Rate
Interest Expense	[2]	0.0		0.0
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		(4.9)		(4.8)
Amortization of Actuarial (Gains) Losses		2.6		3.0
Income Tax (Expense) Benefit		(0.5)		(0.4)
Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	[2]	0.0		0.0
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		0.0		0.0
Amortization of Actuarial (Gains) Losses		0.0		0.0
Income Tax (Expense) Benefit		10.7		2.6
Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	[2]	0.9		0.2
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		0.0		0.0
Amortization of Actuarial (Gains) Losses		0.0		0.0
Income Tax (Expense) Benefit		0.2		0.0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Generation and Marketing Revenues [Member]
Commodity
Generation & Marketing Revenues	[1]	(0.1)
Reclassifications from Accumulated Other Comprehensive Income [Member] | Generation and Marketing Revenues [Member] | Pension and OPEB [Member]
Commodity
Generation & Marketing Revenues	[1]	0.0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Generation and Marketing Revenues [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Commodity
Generation & Marketing Revenues	[1]	(0.1)
Reclassifications from Accumulated Other Comprehensive Income [Member] | Generation and Marketing Revenues [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Commodity
Generation & Marketing Revenues	[1]	0.0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale	[2]	51.1		12.3
Reclassifications from Accumulated Other Comprehensive Income [Member] | Purchased Electricity for Resale [Member] | Pension and OPEB [Member]
Commodity
Purchased Electricity for Resale	[2]	0.0		0.0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Purchased Electricity for Resale [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Commodity
Purchased Electricity for Resale	[2]	51.1		12.3
Reclassifications from Accumulated Other Comprehensive Income [Member] | Purchased Electricity for Resale [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Commodity
Purchased Electricity for Resale	[2]	0.0		0.0
Apple Blossom and Black Oak [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense		5.0
AEP Texas Inc. [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(12.8)		(15.1)
Change in Fair Value Recognized in AOCI		0.0		0.0
Interest Rate
Interest Expense		42.5		37.4
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		0.4		0.4
Income Tax (Expense) Benefit		7.4		4.0
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		0.3		0.3
Net Current Period Other Comprehensive Income (Loss)		0.3		0.3
Ending Balance in AOCI		(12.5)		(14.8)
AEP Texas Inc. [Member] | Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(9.4)		(10.7)
Change in Fair Value Recognized in AOCI		0.0		0.0
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		0.0		0.0
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		0.0		0.0
Net Current Period Other Comprehensive Income (Loss)		0.0		0.0
Ending Balance in AOCI		(9.4)		(10.7)
AEP Texas Inc. [Member] | Accumulated Other Comprehensive Income [Member]
Amortization Of Pension And Other Postretirement Benefit Plans
Net Current Period Other Comprehensive Income (Loss)		0.3		0.3
AEP Texas Inc. [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(3.4)		(4.4)
Change in Fair Value Recognized in AOCI		0.0		0.0
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		0.4		0.4
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		0.3		0.3
Net Current Period Other Comprehensive Income (Loss)		0.3		0.3
Ending Balance in AOCI		(3.1)		(4.1)
AEP Texas Inc. [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	[2]	0.4		0.4
Amortization Of Pension And Other Postretirement Benefit Plans
Income Tax (Expense) Benefit		0.1		0.1
AEP Texas Inc. [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Interest Rate
Interest Expense	[2]	0.0		0.0
Amortization Of Pension And Other Postretirement Benefit Plans
Income Tax (Expense) Benefit		0.0		0.0
AEP Texas Inc. [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	[2]	0.4		0.4
Amortization Of Pension And Other Postretirement Benefit Plans
Income Tax (Expense) Benefit		0.1		0.1
Appalachian Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		5.0		(5.0)
Change in Fair Value Recognized in AOCI		(3.9)		0.0
Interest Rate
Interest Expense		53.1		49.3
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		(1.6)		(1.1)
Income Tax (Expense) Benefit		10.4		(24.1)
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		(1.2)		(0.8)
Net Current Period Other Comprehensive Income (Loss)		(5.1)		(0.8)
Ending Balance in AOCI		(0.1)		(5.8)
Appalachian Power Co [Member] | Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		4.1		(6.8)
Change in Fair Value Recognized in AOCI		0.0		0.0
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		(1.2)		(0.8)
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		(0.9)		(0.6)
Net Current Period Other Comprehensive Income (Loss)		(0.9)		(0.6)
Ending Balance in AOCI		3.2		(7.4)
Appalachian Power Co [Member] | Accumulated Other Comprehensive Income [Member]
Amortization Of Pension And Other Postretirement Benefit Plans
Net Current Period Other Comprehensive Income (Loss)		(5.1)		(0.8)
Appalachian Power Co [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		0.9		1.8
Change in Fair Value Recognized in AOCI		(3.9)		0.0
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		(0.4)		(0.3)
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		(0.3)		(0.2)
Net Current Period Other Comprehensive Income (Loss)		(4.2)		(0.2)
Ending Balance in AOCI		(3.3)		1.6
Appalachian Power Co [Member] | Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale		122.6		110.6
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	[2]	(0.4)		(0.3)
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		(1.3)		(1.3)
Amortization of Actuarial (Gains) Losses		0.1		0.5
Income Tax (Expense) Benefit		(0.4)		(0.3)
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Interest Rate
Interest Expense	[2]	0.0		0.0
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		(1.3)		(1.3)
Amortization of Actuarial (Gains) Losses		0.1		0.5
Income Tax (Expense) Benefit		(0.3)		(0.2)
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	[2]	(0.4)		(0.3)
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		0.0		0.0
Amortization of Actuarial (Gains) Losses		0.0		0.0
Income Tax (Expense) Benefit		(0.1)		(0.1)
Indiana Michigan Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(11.6)		(13.8)
Change in Fair Value Recognized in AOCI		0.0		0.0
Interest Rate
Interest Expense		30.7		28.9
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		0.5		0.5
Income Tax (Expense) Benefit		0.4		(2.7)
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		0.4		0.4
Net Current Period Other Comprehensive Income (Loss)		0.4		0.4
Ending Balance in AOCI		(11.2)		(13.4)
Indiana Michigan Power Co [Member] | Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(1.7)		(2.3)
Change in Fair Value Recognized in AOCI		0.0		0.0
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		0.0		0.0
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		0.0		0.0
Net Current Period Other Comprehensive Income (Loss)		0.0		0.0
Ending Balance in AOCI		(1.7)		(2.3)
Indiana Michigan Power Co [Member] | Accumulated Other Comprehensive Income [Member]
Amortization Of Pension And Other Postretirement Benefit Plans
Net Current Period Other Comprehensive Income (Loss)		0.4		0.4
Indiana Michigan Power Co [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(9.9)		(11.5)
Change in Fair Value Recognized in AOCI		0.0		0.0
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		0.5		0.5
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		0.4		0.4
Net Current Period Other Comprehensive Income (Loss)		0.4		0.4
Ending Balance in AOCI		(9.5)		(11.1)
Indiana Michigan Power Co [Member] | Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale		50.1		69.6
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	[2]	0.5		0.5
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		(0.2)		(0.2)
Amortization of Actuarial (Gains) Losses		0.2		0.2
Income Tax (Expense) Benefit		0.1		0.1
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Interest Rate
Interest Expense	[2]	0.0		0.0
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		(0.2)		(0.2)
Amortization of Actuarial (Gains) Losses		0.2		0.2
Income Tax (Expense) Benefit		0.0		0.0
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	[2]	0.5		0.5
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		0.0		0.0
Amortization of Actuarial (Gains) Losses		0.0		0.0
Income Tax (Expense) Benefit		0.1		0.1
Ohio Power Co [Member]
Interest Rate
Interest Expense		28.9		24.6
Amortization Of Pension And Other Postretirement Benefit Plans
Income Tax (Expense) Benefit		9.7		19.8
Net Current Period Other Comprehensive Income (Loss)				(0.3)
Ohio Power Co [Member] | Accumulated Other Comprehensive Income [Member]
Amortization Of Pension And Other Postretirement Benefit Plans
Net Current Period Other Comprehensive Income (Loss)				(0.3)
Ohio Power Co [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		0.0		1.0
Change in Fair Value Recognized in AOCI		0.0		0.0
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		0.0		(0.4)
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		0.0		(0.3)
Net Current Period Other Comprehensive Income (Loss)		0.0		(0.3)
Ending Balance in AOCI		0.0		0.7
Ohio Power Co [Member] | Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale		149.1		174.2
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	[2]	0.0		(0.4)
Amortization Of Pension And Other Postretirement Benefit Plans
Income Tax (Expense) Benefit		0.0		(0.1)
Public Service Co Of Oklahoma [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		1.1
Interest Rate
Interest Expense		15.8		16.9
Amortization Of Pension And Other Postretirement Benefit Plans
Income Tax (Expense) Benefit		0.1		0.0
Net Current Period Other Comprehensive Income (Loss)		(0.2)		(0.2)
Ending Balance in AOCI		0.9
Public Service Co Of Oklahoma [Member] | Accumulated Other Comprehensive Income [Member]
Amortization Of Pension And Other Postretirement Benefit Plans
Net Current Period Other Comprehensive Income (Loss)		(0.2)		(0.2)
Public Service Co Of Oklahoma [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		1.1		2.1
Change in Fair Value Recognized in AOCI		0.0		0.0
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		(0.3)		(0.3)
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		(0.2)		(0.2)
Net Current Period Other Comprehensive Income (Loss)		(0.2)		(0.2)
Ending Balance in AOCI		0.9		1.9
Public Service Co Of Oklahoma [Member] | Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale		110.4		122.9
Public Service Co Of Oklahoma [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	[2]	(0.3)		(0.3)
Amortization Of Pension And Other Postretirement Benefit Plans
Income Tax (Expense) Benefit		(0.1)		(0.1)
Southwestern Electric Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(1.3)		(5.4)
Change in Fair Value Recognized in AOCI		0.0		0.0
Interest Rate
Interest Expense		30.1		29.7
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		0.0		0.1
Income Tax (Expense) Benefit		(6.2)		0.7
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		0.0		0.1
Net Current Period Other Comprehensive Income (Loss)		0.0		0.1
Ending Balance in AOCI		(1.3)		(5.3)
Southwestern Electric Power Co [Member] | Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		0.5		(2.1)
Change in Fair Value Recognized in AOCI		0.0		0.0
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		(0.5)		(0.4)
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		(0.4)		(0.3)
Net Current Period Other Comprehensive Income (Loss)		(0.4)		(0.3)
Ending Balance in AOCI		0.1		(2.4)
Southwestern Electric Power Co [Member] | Accumulated Other Comprehensive Income [Member]
Amortization Of Pension And Other Postretirement Benefit Plans
Net Current Period Other Comprehensive Income (Loss)				0.1
Southwestern Electric Power Co [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI		(1.8)		(3.3)
Change in Fair Value Recognized in AOCI		0.0		0.0
Amortization Of Pension And Other Postretirement Benefit Plans
Reclassification from AOCI, before Income Tax (Expense) Benefit		0.5		0.5
Reclassification from AOCI, Net of Income Tax (Expense) Benefit		0.4		0.4
Net Current Period Other Comprehensive Income (Loss)		0.4		0.4
Ending Balance in AOCI		(1.4)		(2.9)
Southwestern Electric Power Co [Member] | Purchased Electricity for Resale [Member]
Commodity
Purchased Electricity for Resale		43.1		32.6
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Interest Rate
Interest Expense	[2]	0.5		0.5
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		(0.5)		(0.5)
Amortization of Actuarial (Gains) Losses				0.1
Income Tax (Expense) Benefit		0.0		0.0
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Interest Rate
Interest Expense	[2]	0.0		0.0
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		(0.5)		(0.5)
Amortization of Actuarial (Gains) Losses				0.1
Income Tax (Expense) Benefit		(0.1)		(0.1)
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Interest Rate
Interest Expense	[2]	0.5		0.5
Amortization Of Pension And Other Postretirement Benefit Plans
Amortization of Prior Service Cost (Credit)		0.0		0.0
Amortization of Actuarial (Gains) Losses				0.0
Income Tax (Expense) Benefit		$ 0.1		$ 0.1

[1] (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

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

XML

Income Taxes (Tables)

3 Months Ended

Mar. 31, 2020

Schedule of Effective Income Tax Rate Reconciliation

	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	)%

	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	%

XML

Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2020

Components of Net Periodic Benefit Cost

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	)

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	)

XML

Revenue from Contracts with Customers (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2020		Mar. 31, 2019		Dec. 31, 2019
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		$ 3,747.5		$ 4,056.8
Revenue Not from Contract with Customer, Other		40.6		10.9
Total Revenues		3,747.5		4,056.8
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		1,287.5
Revenue Textuals [Abstract]
Revenue from Related Parties		0.0		0.0
2020 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		732.4
2021-2022 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		171.1
2023-2024 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		160.6
2024 and Forward [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		223.4
Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		2,870.2		3,102.8
Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		1,436.4		1,568.5
Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		766.3		822.1
Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		615.8		657.8
Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		51.7		54.4
Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		765.2		865.0
Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		184.5		294.7
Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		240.8	[1]	208.8	[2]
Renewable Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		16.6	[3]	7.8	[4]
Retail, Trading and Marketing Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		323.3	[5]	353.7	[6]
Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		71.5	[3]	78.1	[4]
Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		3,706.9		4,045.9
Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		20.7	[3]	(0.2)	[4]
Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		70.9		65.0
Revenue Not from Contract with Customer, Other		19.9	[3]	11.1	[4]
AEP Texas Inc. [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		29.5		38.9
Total Revenues		423.6		390.7
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		290.3
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		10.4				$ 10.1
Revenue Textuals [Abstract]
Revenue from Related Parties		31.1		40.2
AEP Texas Inc. [Member] | 2020 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		290.3
AEP Texas Inc. [Member] | 2021-2022 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0.0
AEP Texas Inc. [Member] | 2023-2024 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0.0
AEP Texas Inc. [Member] | 2024 and Forward [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0.0
AEP Texas Inc. [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		289.3		259.1
AEP Texas Inc. [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		132.9		120.9
AEP Texas Inc. [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		112.8		97.9
AEP Texas Inc. [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		35.2		33.0
AEP Texas Inc. [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		8.4		7.3
AEP Texas Inc. [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		96.9		85.8
AEP Texas Inc. [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0	[7]	0.0	[8]
AEP Texas Inc. [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		96.9	[9]	85.8	[10]
AEP Texas Inc. [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		7.9	[11]	6.9	[12]
AEP Texas Inc. [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		394.1		351.8
AEP Texas Inc. [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		(0.7)	[13]	(0.9)	[14]
AEP Texas Inc. [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.9		0.7
Revenue Not from Contract with Customer, Other		30.2	[13]	39.8	[14]
AEP Transmission Co [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		(6.0)		(1.7)
Total Revenues		295.6		243.5
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		821.5
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		87.8				66.1
Revenue Textuals [Abstract]
Revenue from Related Parties		233.7		193.2
AEP Transmission Co [Member] | Short-term Contract with Customer [Member]
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		80.6				65.9
AEP Transmission Co [Member] | 2020 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		821.5
AEP Transmission Co [Member] | 2021-2022 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0.0
AEP Transmission Co [Member] | 2023-2024 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0.0
AEP Transmission Co [Member] | 2024 and Forward [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0.0
AEP Transmission Co [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
AEP Transmission Co [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
AEP Transmission Co [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
AEP Transmission Co [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
AEP Transmission Co [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
AEP Transmission Co [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		298.2		242.1
AEP Transmission Co [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0	[7]	0.0	[8]
AEP Transmission Co [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		298.2	[9]	242.1	[10]
Revenue Textuals [Abstract]
Revenue from Related Parties		235.0		195.0
AEP Transmission Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		3.4	[11]	3.1	[12]
AEP Transmission Co [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		301.6		245.2
AEP Transmission Co [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		(6.0)	[13]	(1.7)	[14]
AEP Transmission Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.6		0.0
Revenue Not from Contract with Customer, Other		0.0	[13]	0.0	[14]
Appalachian Power Co [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		(1.1)		4.4
Total Revenues		749.4		792.8
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		186.9
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		78.0				64.3
Revenue Textuals [Abstract]
Revenue from Related Parties		49.7		51.7
Appalachian Power Co [Member] | Short-term Contract with Customer [Member]
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		56.3				47.3
Appalachian Power Co [Member] | 2020 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		118.6
Appalachian Power Co [Member] | 2021-2022 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		32.3
Appalachian Power Co [Member] | 2023-2024 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		24.4
Appalachian Power Co [Member] | 2024 and Forward [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		11.6
Appalachian Power Co [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		648.8		681.8
Appalachian Power Co [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		357.5		372.5
Appalachian Power Co [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		132.3		142.2
Appalachian Power Co [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		141.1		147.5
Appalachian Power Co [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		17.9		19.6
Appalachian Power Co [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		84.5		93.2
Appalachian Power Co [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		54.1	[7]	67.5	[8]
Revenue Textuals [Abstract]
Revenue from Related Parties		33.0		35.0
Appalachian Power Co [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		30.4	[9]	25.7	[10]
Appalachian Power Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		17.2	[11]	13.4	[12]
Appalachian Power Co [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		750.5		788.4
Appalachian Power Co [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		(1.1)	[13]	4.4	[14]
Appalachian Power Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		2.7		2.4
Revenue Not from Contract with Customer, Other		0.0	[13]	0.0	[14]
Indiana Michigan Power Co [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		0.4		(4.8)
Total Revenues		570.3		614.3
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		44.2
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		51.1				53.7
Revenue Textuals [Abstract]
Revenue from Related Parties		2.9		2.3
Indiana Michigan Power Co [Member] | Short-term Contract with Customer [Member]
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		37.4				37.1
Indiana Michigan Power Co [Member] | 2020 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		22.2
Indiana Michigan Power Co [Member] | 2021-2022 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		8.8
Indiana Michigan Power Co [Member] | 2023-2024 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		8.8
Indiana Michigan Power Co [Member] | 2024 and Forward [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		4.4
Indiana Michigan Power Co [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		463.1		479.9
Indiana Michigan Power Co [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		201.3		218.4
Indiana Michigan Power Co [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		122.2		121.3
Indiana Michigan Power Co [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		137.8		138.4
Indiana Michigan Power Co [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		1.8		1.8
Indiana Michigan Power Co [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		85.8		118.2
Indiana Michigan Power Co [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		78.4	[7]	111.9	[8]
Indiana Michigan Power Co [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		7.4	[9]	6.3	[10]
Indiana Michigan Power Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		21.0	[11]	21.0	[12]
Indiana Michigan Power Co [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		569.9		619.1
Indiana Michigan Power Co [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		0.4	[13]	(4.8)	[14]
Indiana Michigan Power Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		1.5		2.0
Revenue Not from Contract with Customer, Other		0.0	[13]	0.0	[14]
Revenue Textuals [Abstract]
Revenue from Related Parties		16.0		15.0
Ohio Power Co [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		26.1		8.7
Total Revenues		690.3		836.8
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		43.2
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		73.1				59.3
Revenue Textuals [Abstract]
Revenue from Related Parties		8.4		7.5
Ohio Power Co [Member] | Short-term Contract with Customer [Member]
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		39.3				33.9
Ohio Power Co [Member] | 2020 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		43.2
Ohio Power Co [Member] | 2021-2022 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0.0
Ohio Power Co [Member] | 2023-2024 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0.0
Ohio Power Co [Member] | 2024 and Forward [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0.0
Ohio Power Co [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		618.5		775.2
Ohio Power Co [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		388.4		471.6
Ohio Power Co [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		164.0		210.5
Ohio Power Co [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		62.7		89.7
Ohio Power Co [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		3.4		3.4
Ohio Power Co [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		17.1		13.9
Ohio Power Co [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0	[7]	0.0	[8]
Ohio Power Co [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		17.1	[9]	13.9	[10]
Ohio Power Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		28.6	[11]	39.0	[12]
Ohio Power Co [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		664.2		828.1
Ohio Power Co [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		20.0	[13]	3.6	[14]
Ohio Power Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		2.7		2.8
Revenue Not from Contract with Customer, Other		6.1	[13]	5.1	[14]
Public Service Co Of Oklahoma [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		0.4		(1.2)
Total Revenues		297.3		332.8
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		10.8
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		19.9				20.6
Revenue Textuals [Abstract]
Revenue from Related Parties		1.1		1.6
Public Service Co Of Oklahoma [Member] | Short-term Contract with Customer [Member]
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		6.2				9.7
Public Service Co Of Oklahoma [Member] | 2020 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		10.8
Public Service Co Of Oklahoma [Member] | 2021-2022 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0.0
Public Service Co Of Oklahoma [Member] | 2023-2024 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0.0
Public Service Co Of Oklahoma [Member] | 2024 and Forward [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0.0
Public Service Co Of Oklahoma [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		282.5		309.8
Public Service Co Of Oklahoma [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		128.5		140.0
Public Service Co Of Oklahoma [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		76.1		80.8
Public Service Co Of Oklahoma [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		61.3		71.0
Public Service Co Of Oklahoma [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		16.6		18.0
Public Service Co Of Oklahoma [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		9.7		18.4
Public Service Co Of Oklahoma [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		1.9	[7]	8.6	[8]
Public Service Co Of Oklahoma [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		7.8	[9]	9.8	[10]
Public Service Co Of Oklahoma [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		4.7	[11]	5.8	[12]
Public Service Co Of Oklahoma [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		296.9		334.0
Public Service Co Of Oklahoma [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		0.4	[13]	(1.2)	[14]
Public Service Co Of Oklahoma [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.8		2.0
Revenue Not from Contract with Customer, Other		0.0	[13]	0.0	[14]
Southwestern Electric Power Co [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		1.6		(5.3)
Total Revenues		385.9		421.1
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		29.6
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		24.4				34.5
Revenue Textuals [Abstract]
Revenue from Related Parties		7.5		6.4
Southwestern Electric Power Co [Member] | Short-term Contract with Customer [Member]
Assets, Current [Abstract]
Affiliated Companies - Contracts with Customers		11.0				$ 17.6
Southwestern Electric Power Co [Member] | 2020 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		29.6
Southwestern Electric Power Co [Member] | 2021-2022 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0.0
Southwestern Electric Power Co [Member] | 2023-2024 [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0.0
Southwestern Electric Power Co [Member] | 2024 and Forward [Member]
Revenue, Performance Obligation [Abstract]
Fixed Performance Obligations		0.0
Southwestern Electric Power Co [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		319.0		337.2
Southwestern Electric Power Co [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		131.6		140.1
Southwestern Electric Power Co [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		105.6		113.7
Southwestern Electric Power Co [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		79.8		81.2
Southwestern Electric Power Co [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		2.0		2.2
Southwestern Electric Power Co [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		59.5		81.4
Southwestern Electric Power Co [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		34.1	[7]	57.2	[8]
Southwestern Electric Power Co [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		25.4	[9]	24.2	[10]
Southwestern Electric Power Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		5.8	[11]	7.8	[12]
Southwestern Electric Power Co [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		384.3		426.4
Southwestern Electric Power Co [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		1.6	[13]	(5.3)	[14]
Southwestern Electric Power Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.8		0.4
Revenue Not from Contract with Customer, Other		0.0	[13]	0.0	[14]
Consolidation Eliminations [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
Revenue Not from Contract with Customer, Other		(21.0)		(39.7)
Total Revenues		(354.8)		(332.2)
Revenue Textuals [Abstract]
Revenue from Related Parties		(354.8)		(332.2)
Consolidation Eliminations [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		(0.2)		1.8
Consolidation Eliminations [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
Consolidation Eliminations [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
Consolidation Eliminations [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		(0.2)		1.8
Consolidation Eliminations [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
Consolidation Eliminations [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		(293.0)		(258.2)
Consolidation Eliminations [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		(38.8)
Consolidation Eliminations [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		(263.0)	[1]	(219.4)	[2]
Consolidation Eliminations [Member] | Renewable Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		(0.6)	[3]	0.0	[4]
Consolidation Eliminations [Member] | Retail, Trading and Marketing Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		(29.4)	[5]	0.0	[6]
Consolidation Eliminations [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		(40.6)	[3]	(36.1)	[4]
Consolidation Eliminations [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		(333.8)		(292.5)
Consolidation Eliminations [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		4.5	[3]	0.0	[4]
Consolidation Eliminations [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		(25.5)	[3]	(39.7)	[4]
Consolidation Eliminations [Member] | AEP Transmission Co [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
Total Revenues		0.0		0.0
Revenue Textuals [Abstract]
Revenue from Related Parties		0.0		0.0
Consolidation Eliminations [Member] | AEP Transmission Co [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0
Vertically Integrated Utilities [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		0.2		(3.4)
Total Revenues		2,226.7		2,403.3
Revenue Textuals [Abstract]
Revenue from Related Parties		33.7		31.0
Vertically Integrated Utilities [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		1,962.6		2,069.0
Vertically Integrated Utilities [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		915.1		982.4
Vertically Integrated Utilities [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		489.4		511.2
Vertically Integrated Utilities [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		518.2		532.1
Vertically Integrated Utilities [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		39.9		43.3
Vertically Integrated Utilities [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		220.3		298.2
Vertically Integrated Utilities [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		140.4		224.7
Vertically Integrated Utilities [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		79.9	[1]	73.5	[2]
Vertically Integrated Utilities [Member] | Renewable Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0	[3]	0.0	[4]
Vertically Integrated Utilities [Member] | Retail, Trading and Marketing Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0	[5]	0.0	[6]
Vertically Integrated Utilities [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		43.6	[3]	39.5	[4]
Vertically Integrated Utilities [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		2,226.5		2,406.7
Vertically Integrated Utilities [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		0.2	[3]	(3.4)	[4]
Vertically Integrated Utilities [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		0.0	[3]	0.0	[4]
Transmission And Distribution Utilities [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		48.6		44.4
Total Revenues		1,106.9		1,222.0
Revenue Textuals [Abstract]
Revenue from Related Parties		31.7		42.2
Transmission And Distribution Utilities [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		907.8		1,032.0
Transmission And Distribution Utilities [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		521.3		586.1
Transmission And Distribution Utilities [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		276.9		310.9
Transmission And Distribution Utilities [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		97.8		123.9
Transmission And Distribution Utilities [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		11.8		11.1
Transmission And Distribution Utilities [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		114.1		99.6
Transmission And Distribution Utilities [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
Transmission And Distribution Utilities [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		114.1	[1]	99.6	[2]
Transmission And Distribution Utilities [Member] | Renewable Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0	[3]	0.0	[4]
Transmission And Distribution Utilities [Member] | Retail, Trading and Marketing Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0	[5]	0.0	[6]
Transmission And Distribution Utilities [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		36.4	[3]	46.0	[4]
Transmission And Distribution Utilities [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		1,058.3		1,177.6
Transmission And Distribution Utilities [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		19.3	[3]	5.0	[4]
Transmission And Distribution Utilities [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		29.3	[3]	39.4	[4]
AEP Transmission Holdco [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		(3.3)		(1.8)
Total Revenues		310.2		256.4
AEP Transmission Holdco [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
AEP Transmission Holdco [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
AEP Transmission Holdco [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
AEP Transmission Holdco [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
AEP Transmission Holdco [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
AEP Transmission Holdco [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		309.8		255.1
AEP Transmission Holdco [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
AEP Transmission Holdco [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		309.8	[1]	255.1	[2]
Revenue Textuals [Abstract]
Revenue from Related Parties		239.0		198.0
AEP Transmission Holdco [Member] | Renewable Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0	[3]	0.0	[4]
AEP Transmission Holdco [Member] | Retail, Trading and Marketing Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0	[5]	0.0	[6]
AEP Transmission Holdco [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		3.7	[3]	3.1	[4]
AEP Transmission Holdco [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		313.5		258.2
AEP Transmission Holdco [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		(3.3)	[3]	(1.8)	[4]
AEP Transmission Holdco [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		0.0	[3]	0.0	[4]
Generation And Marketing [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		18.3		9.2
Total Revenues		438.6		481.8
Revenue Textuals [Abstract]
Revenue from Related Parties		30.2		42.1
Generation And Marketing [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
Generation And Marketing [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
Generation And Marketing [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
Generation And Marketing [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
Generation And Marketing [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
Generation And Marketing [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		420.0		470.3
Generation And Marketing [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		44.1		108.8
Generation And Marketing [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0	[1]	0.0	[2]
Generation And Marketing [Member] | Wholesale Generation [Member]
Revenue Textuals [Abstract]
Revenue from Related Parties		35.0		37.0
Generation And Marketing [Member] | Renewable Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		17.2	[3]	7.8	[4]
Generation And Marketing [Member] | Retail, Trading and Marketing Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		358.7	[5]	353.7	[6]
Generation And Marketing [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.3	[3]	2.3	[4]
Generation And Marketing [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		420.3		472.6
Generation And Marketing [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		0.0	[3]	0.0	[4]
Generation And Marketing [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		18.3	[3]	9.2	[4]
Other Segments [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		(2.2)		2.2
Total Revenues	[15]	19.9		25.5
Revenue Textuals [Abstract]
Revenue from Related Parties	[15]	22.1		21.7
Other Segments [Member] | Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
Other Segments [Member] | Residential [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
Other Segments [Member] | Commercial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
Other Segments [Member] | Industrial [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
Other Segments [Member] | Other Retail [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
Other Segments [Member] | Wholesale and Competitive [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		(6.0)		0.0
Other Segments [Member] | Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0		0.0
Other Segments [Member] | Transmission [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0	[1]	0.0	[2]
Other Segments [Member] | Renewable Generation [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		0.0	[3]	0.0	[4]
Other Segments [Member] | Retail, Trading and Marketing Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		(6.0)	[5]	0.0	[6]
Other Segments [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		28.1	[3]	23.3	[4]
Other Segments [Member] | Affiliated and Nonaffiliated [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers		22.1		23.3
Other Segments [Member] | Alternative [Member]
Disaggregation of Revenue [Abstract]
Revenue Not from Contract with Customer, Other		0.0	[3]	0.0	[4]
Other Segments [Member] | Other Revenues [Member]
Disaggregation of Revenue [Abstract]
Revenue from Contracts with Customers	[15]	(2.2)		3.8
Revenue Not from Contract with Customer, Other		$ (2.2)	[3]	$ 2.2	[4]

[1] Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $239 million. The remaining affiliated amounts were immaterial.

[2] Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $198 million. The remaining affiliated amounts were immaterial.

[3] Amounts include affiliated and nonaffiliated revenues.

[4] Amounts include affiliated and nonaffiliated revenues.

[5] Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $35 million. The remaining affiliated amounts were immaterial.

[6] Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $37 million. The remaining affiliated amounts were immaterial.

[7] 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.

[8] 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.

[9] Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $235 million. The remaining affiliated amounts were immaterial.

[10] Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $195 million. The remaining affiliated amounts were immaterial.

[11] 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.

[12] 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.

[13] Amounts include affiliated and nonaffiliated revenues.

[14] Amounts include affiliated and nonaffiliated revenues.

[15] 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.

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Condensed Consolidated Balance Sheets - USD ($) $ in Millions		Mar. 31, 2020	Dec. 31, 2019
Current Assets
Cash and Cash Equivalents		$ 1,554.6	$ 246.8
Restricted Cash		116.2	185.8
Other Temporary Investments		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
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		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
Current Liabilities
Accounts Payable		1,593.4	2,085.8
Short-term Debt:
Securitized Debt for Receivables - AEP Credit	[1]	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		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		25,783.0	25,126.8
Affiliated Long Term Debt Noncurrent		0.0	0.0
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
Commitments and Contingencies
Redeemable Noncontrolling Interest		64.8	65.7
Contingently Reedemable Performance Share Awards		53.2	42.9
Total Mezzanine Equity		118.0	108.6
Equity
Common Stock		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 COMMON SHAREHOLDER'S EQUITY		19,728.4	19,632.2
Noncontrolling Interests		279.3	281.0
TOTAL EQUITY		20,007.7	19,913.2
TOTAL LIABILITIES AND EQUITY		77,724.0	75,892.3
AEP Texas Inc. [Member]
Current Assets
Cash and Cash Equivalents		0.1	3.1
Restricted Cash		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
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		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
Current Liabilities
Advances from Affiliates		63.9	0.0
Accounts Payable		233.1	256.8
Affiliated Companies		20.3	35.6
Short-term Debt:
Long-term Debt Due Within One Year		289.0	392.1
Accrued Taxes		109.2	84.9
Accrued Interest		54.8	35.7
Oklaunion Purchase Power Agreement - Current		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		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
Commitments and Contingencies
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 EQUITY		3,009.0	2,961.1
TOTAL LIABILITIES AND EQUITY		10,570.5	10,589.1
AEP Transmission Co [Member]
Current Assets
Cash and Cash Equivalents		0.0	0.0
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
Property, Plant and Equipment
Transmission		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 Property, Plant and Equipment		10,221.2	9,893.2
Accumulated Depreciation and Amortization		445.8	402.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - 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
Current Liabilities
Advances from Affiliates		297.4	137.0
Accounts Payable		334.2	493.4
Affiliated Companies		73.7	71.2
Short-term Debt:
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		3,427.8	3,427.3
Deferred Income Taxes		834.7	817.8
Regulatory Liabilities and Deferred Investment Tax Credits		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
Commitments and Contingencies
Equity
Paid-in Captial		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 EQUITY		10,199.9	9,890.8
Appalachian Power Co [Member]
Current Assets
Cash and Cash Equivalents		2.8	3.3
Restricted Cash		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
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
Current Liabilities
Advances from Affiliates		355.3	236.7
Accounts Payable		198.7	307.8
Affiliated Companies		75.2	92.5
Short-term Debt:
Long-term Debt Due Within One Year		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		3,769.1	4,148.2
Long-term Risk Management Liabilities		0.1	0.0
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
Commitments and Contingencies
Equity
Common Stock		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 EQUITY		4,232.6	4,172.4
TOTAL LIABILITIES AND EQUITY		12,793.6	12,768.3
Indiana Michigan Power Co [Member]
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
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		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 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
Current Liabilities
Advances from Affiliates		103.7	114.4
Accounts Payable		131.5	169.4
Affiliated Companies		71.0	68.4
Short-term Debt:
Long-term Debt Due Within One Year		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		2,894.4	2,910.5
Long-term Risk Management Liabilities		0.1	0.0
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
Commitments and Contingencies
Equity
Common Stock		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 EQUITY		2,616.2	2,544.4
TOTAL LIABILITIES AND EQUITY		10,905.4	11,237.4
Ohio Power Co [Member]
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
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
Current Liabilities
Advances from Affiliates		29.4	131.0
Accounts Payable		220.3	233.7
Affiliated Companies		109.0	103.6
Short-term Debt:
Long-term Debt Due Within One Year		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		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
Commitments and Contingencies
Equity
Common Stock		321.2	321.2
Paid-in Capital		838.8	838.8
Retained Earnings		1,402.0	1,348.5
TOTAL EQUITY		2,562.0	2,508.5
TOTAL LIABILITIES AND EQUITY		8,182.0	8,043.6
Public Service Co Of Oklahoma [Member]
Current Assets
Cash and Cash Equivalents		1.1	1.5
Advances to Affiliates		0.0	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
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
Current Liabilities
Advances from Affiliates		70.9	0.0
Accounts Payable		102.5	134.3
Affiliated Companies		39.8	59.3
Short-term Debt:
Long-term Debt Due Within One Year		263.2	13.2
Risk Management Liabilities		0.1	0.0
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		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
Commitments and Contingencies
Equity
Common Stock		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 EQUITY		1,363.1	1,373.3
TOTAL LIABILITIES AND EQUITY		4,778.0	4,751.5
Southwestern Electric Power Co [Member]
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		147.9	140.1
Materials and Supplies		93.8	94.0
Risk Management Assets		2.6	6.4
Regulatory Asset for Under-Recovered Fuel Costs		0.0	4.9
Prepayments and Other Current Assets		34.3	29.7
TOTAL CURRENT ASSETS		346.1	354.1
Property, Plant and Equipment
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		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		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
Current Liabilities
Advances from Affiliates		148.1	59.9
Accounts Payable		102.5	138.0
Affiliated Companies		37.3	53.6
Short-term Debt:
Other Short-term Debt		30.5	18.3
Long-term Debt Due Within One Year		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		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
Commitments and Contingencies
Equity
Common Stock		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 Interests		0.9	0.6
TOTAL EQUITY		2,458.1	2,441.1
TOTAL LIABILITIES AND EQUITY		$ 7,944.1	$ 7,832.2

[1] Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.

XML

Consolidated Statements of Income - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020		Mar. 31, 2019
Revenues
Revenue from Contracts with Customers	$ 3,747.5		$ 4,056.8
Sales to AEP Affiliates	0.0		0.0
TOTAL REVENUES	3,747.5		4,056.8
Expenses
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 (LOSS)	751.6		788.4
Other Income (Expense):
Other Income	(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 (Benefit)	46.5		44.5
Equity Earnings (Loss) of Unconsolidated Subsidiaries	29.6		18.5
Net Income (Loss)	499.3		574.1
Net Income (Loss) Attributable to Noncontrolling Interests	4.1		1.3
Earnings Attributable to Common Shareholders	$ 495.2		$ 572.8
Earnings Per Share
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
Common Stock, Dividends Per Share, Declared	$ 0.70		$ 0.67
Vertically Integrated Utilities [Member]
Revenues
Revenue from Contracts with Customers	$ 2,193.0		$ 2,372.3
Transmission and Distribution Utilities [Member]
Revenues
Revenue from Contracts with Customers	1,075.2		1,179.8
Generation and Marketing [Member]
Revenues
Revenue from Contracts with Customers	408.4		439.7
Other Revenues [Member]
Revenues
Revenue from Contracts with Customers	70.9		65.0
Fuel and Other Consumables Used for Electric Generation [Member]
Revenues
Revenue from Contracts with Customers	184.5		294.7
Expenses
Cost of Goods and Services Sold	355.3		550.4
Purchased Electricity for Resale [Member]
Expenses
Cost of Goods and Services Sold	795.7		861.8
AEP Texas Inc. [Member]
Revenues
Sales to AEP Affiliates	31.1		40.2
TOTAL REVENUES	423.6		390.7
Expenses
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 (LOSS)	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 AND EQUITY EARNINGS	55.0		38.4
Income Tax Expense (Benefit)	7.4		4.0
Net Income (Loss)	47.6		34.4
AEP Texas Inc. [Member] | Transmission and Distribution Utilities [Member]
Revenues
Revenue from Contracts with Customers	391.6		349.8
AEP Texas Inc. [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers	0.9		0.7
AEP Texas Inc. [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Revenues
Revenue from Contracts with Customers	0.0	[1]	0.0	[2]
Expenses
Cost of Goods and Services Sold	0.0		9.4
AEP Transmission Co [Member]
Revenues
Sales to AEP Affiliates	233.7		193.2
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 (LOSS)	162.2		141.6
Other Income (Expense):
Interest Income	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 AND EQUITY EARNINGS	149.6		131.9
Income Tax Expense (Benefit)	31.8		27.6
Net Income (Loss)	117.8		104.3
AEP Transmission Co [Member] | Transmission [Member]
Revenues
Revenue from Contracts with Customers	61.3		50.3
AEP Transmission Co [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers	0.6		0.0
AEP Transmission Co [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Revenues
Revenue from Contracts with Customers	0.0	[1]	0.0	[2]
Appalachian Power Co [Member]
Revenues
Sales to AEP Affiliates	49.7		51.7
TOTAL REVENUES	749.4		792.8
Expenses
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 (LOSS)	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 AND EQUITY EARNINGS	125.7		109.6
Income Tax Expense (Benefit)	10.4		(24.1)
Net Income (Loss)	115.3		133.7
Appalachian Power Co [Member] | Vertically Integrated Utilities [Member]
Revenues
Revenue from Contracts with Customers	697.0		738.7
Appalachian Power Co [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers	2.7		2.4
Appalachian Power Co [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Revenues
Revenue from Contracts with Customers	54.1	[1]	67.5	[2]
Sales to AEP Affiliates	33.0		35.0
Expenses
Cost of Goods and Services Sold	111.0		183.3
Appalachian Power Co [Member] | Purchased Electricity for Resale [Member]
Expenses
Cost of Goods and Services Sold	122.6		110.6
Indiana Michigan Power Co [Member]
Revenues
Sales to AEP Affiliates	2.9		2.3
Other Revenues - Affiliated	12.5		13.3
TOTAL REVENUES	570.3		614.3
Expenses
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 (LOSS)	116.7		115.0
Other Income (Expense):
Other Income	2.5		5.7
Allowance for Equity Funds Used During Construction	2.0		6.2
Non-Service Cost Components of Net Periodic Benefit Cost	4.2		4.4
Interest Expense	(30.7)		(28.9)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	92.7		96.2
Income Tax Expense (Benefit)	0.4		(2.7)
Net Income (Loss)	92.3		98.9
Indiana Michigan Power Co [Member] | Vertically Integrated Utilities [Member]
Revenues
Revenue from Contracts with Customers	553.4		596.7
Indiana Michigan Power Co [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers	1.5		2.0
Sales to AEP Affiliates	16.0		15.0
Indiana Michigan Power Co [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Revenues
Revenue from Contracts with Customers	78.4	[1]	111.9	[2]
Expenses
Cost of Goods and Services Sold	53.2		57.6
Indiana Michigan Power Co [Member] | Purchased Electricity for Resale [Member]
Expenses
Cost of Goods and Services Sold	50.1		69.6
Ohio Power Co [Member]
Revenues
Sales to AEP Affiliates	8.4		7.5
TOTAL REVENUES	690.3		836.8
Expenses
Purchased Electricity from AEP Affiliates	42.4		46.1
Amortization of Generation Deferrals	0.0		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 (LOSS)	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 AND EQUITY EARNINGS	84.8		147.8
Income Tax Expense (Benefit)	9.7		19.8
Net Income (Loss)	75.1		128.0
Ohio Power Co [Member] | Transmission and Distribution Utilities [Member]
Revenues
Revenue from Contracts with Customers	679.2		826.5
Ohio Power Co [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers	2.7		2.8
Ohio Power Co [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Revenues
Revenue from Contracts with Customers	0.0	[1]	0.0	[2]
Ohio Power Co [Member] | Purchased Electricity for Resale [Member]
Expenses
Cost of Goods and Services Sold	149.1		174.2
Public Service Co Of Oklahoma [Member]
Revenues
Sales to AEP Affiliates	1.1		1.6
TOTAL REVENUES	297.3		332.8
Expenses
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 (LOSS)	2.4		20.9
Other Income (Expense):
Interest Income	0.1		0.0
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 BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	(10.2)		6.2
Income Tax Expense (Benefit)	0.1		0.0
Net Income (Loss)	(10.3)		6.2
Public Service Co Of Oklahoma [Member] | Vertically Integrated Utilities [Member]
Revenues
Revenue from Contracts with Customers	295.4		329.2
Public Service Co Of Oklahoma [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers	0.8		2.0
Public Service Co Of Oklahoma [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Revenues
Revenue from Contracts with Customers	1.9	[1]	8.6	[2]
Expenses
Cost of Goods and Services Sold	16.9		38.0
Public Service Co Of Oklahoma [Member] | Purchased Electricity for Resale [Member]
Expenses
Cost of Goods and Services Sold	110.4		122.9
Southwestern Electric Power Co [Member]
Revenues
Sales to AEP Affiliates	7.5		6.4
TOTAL REVENUES	385.9		421.1
Expenses
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 (LOSS)	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 AND EQUITY EARNINGS	9.1		29.0
Income Tax Expense (Benefit)	(6.2)		0.7
Equity Earnings (Loss) of Unconsolidated Subsidiaries	0.8		0.7
Net Income (Loss)	16.1		29.0
Net Income (Loss) Attributable to Noncontrolling Interests	1.0		1.2
Earnings Attributable to Common Shareholders	15.1		27.8
Southwestern Electric Power Co [Member] | Vertically Integrated Utilities [Member]
Revenues
Revenue from Contracts with Customers	377.6		414.3
Southwestern Electric Power Co [Member] | Other Revenues [Member]
Revenues
Revenue from Contracts with Customers	0.8		0.4
Southwestern Electric Power Co [Member] | Fuel and Other Consumables Used for Electric Generation [Member]
Revenues
Revenue from Contracts with Customers	34.1	[1]	57.2	[2]
Expenses
Cost of Goods and Services Sold	89.1		133.5
Southwestern Electric Power Co [Member] | Purchased Electricity for Resale [Member]
Expenses
Cost of Goods and Services Sold	$ 43.1		$ 32.6

[1] 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.

[2] 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.

XML

Fair Value Assets and Liabilities (Details) - USD ($)		3 Months Ended
		Mar. 31, 2020		Mar. 31, 2019	Dec. 31, 2019
Assets, Fair Value Disclosure
Other Short-term Investments		$ 301,400,000			$ 388,500,000
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		2,679,200,000			2,975,700,000
Total Assets		3,434,700,000			3,803,600,000
Risk Management Assets
Risk Management Assets		454,100,000			439,400,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		448,700,000			376,100,000
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		109,900,000		$ 131,200,000
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	900,000		(23,000,000.0)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[1]	10,900,000		8,500,000
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Other Comprehensive Income (Loss)	[3]	(4,100,000)		(15,800,000)
Settlements		(59,200,000)		(54,500,000)
Transfers into Level 3	[4],[5]	(500,000)		100,000
Transfers out of Level 3	[5]	5,300,000		(1,200,000)
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	(20,700,000)		(7,200,000)
Ending Balance		42,500,000		38,100,000
Other [Member]
Assets, Fair Value Disclosure
Other Short-term Investments		23,800,000			17,100,000
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		9,900,000			8,600,000
Total Assets		(312,000,000.0)			(385,500,000)
Risk Management Assets
Risk Management Assets		(345,700,000)			(411,200,000)
Liabilities, Fair Value Disclosure
Risk Management Liabilities		(421,500,000)			(445,500,000)
Level 1 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments		277,600,000			371,400,000
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,430,800,000			1,774,600,000
Total Assets		1,712,100,000			2,150,000,000.0
Risk Management Assets
Risk Management Assets		3,700,000			4,000,000.0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		4,900,000			3,800,000
Level 2 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments		0			0
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,238,500,000			1,192,500,000
Total Assets		1,684,300,000			1,666,700,000
Risk Management Assets
Risk Management Assets		445,800,000			474,200,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		557,500,000			555,300,000
Level 3 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments		0			0
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
Total Assets		350,300,000			372,400,000
Risk Management Assets
Risk Management Assets		350,300,000			372,400,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		307,800,000			262,500,000
2020 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		(30,000,000)			(7,000,000)
2020 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		37,000,000			96,000,000
2021 - 2023 [Member] | Level 1 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		(1,000,000)
2021 - 2023 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		(9,000,000)			(3,000,000)
2021 - 2023 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		36,000,000			36,000,000
2024 - 2025 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		(1,000,000)
2024 - 2025 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		25,000,000			25,000,000
2026 - 2032 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		(20,000,000)			(12,000,000)
Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[7]	379,100,000	[8]		408,800,000	[9]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	266,600,000	[8]		239,000,000.0	[9]
Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7]	(340,500,000)	[8]		(404,500,000)	[9]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	(416,300,000)	[8]		(438,800,000)	[9]
Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7]	3,700,000	[8]		4,000,000.0	[9]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	4,900,000	[8]		3,800,000	[9]
Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7]	369,800,000	[8]		440,100,000	[9]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	410,100,000	[8]		450,000,000.0	[9]
Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7]	346,100,000	[8]		369,200,000	[9]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	267,900,000	[8]		224,000,000.0	[9]
Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		321,200,000			296,700,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		284,600,000			249,300,000
Energy Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	(0.05)			(0.05)
Energy Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	135.24			177.30
Energy Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10],[11]	29.17			31.31
Natural Gas Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		5,100,000			4,900,000
Natural Gas Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[12]	1.37			1.89
Natural Gas Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[12]	2.51			2.51
Natural Gas Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[11],[12]	2.13			2.19
FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		29,100,000			75,700,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		18,100,000			8,300,000
FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	(10.12)			(8.52)
FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	4.17			9.34
FTRs [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10],[11]	(0.31)			0.42
Commodity Hedges [Member]
Risk Management Assets
Risk Management Assets	[7]	17,700,000			11,500,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	176,800,000			137,100,000
Commodity Hedges [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7]	(5,200,000)			(6,700,000)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	(5,200,000)			(6,700,000)
Commodity Hedges [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7]	0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	0			0
Commodity Hedges [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7]	18,700,000			15,000,000.0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	142,100,000			105,300,000
Commodity Hedges [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7]	4,200,000			3,200,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	39,900,000			38,500,000
Interest Rate [Member]
Risk Management Assets
Risk Management Assets		300,000			4,600,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		5,300,000
Interest Rate [Member] | Other [Member]
Risk Management Assets
Risk Management Assets		0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0
Interest Rate [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets		0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0
Interest Rate [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets		300,000			4,600,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		5,300,000
Interest Rate [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0
Fair Value Hedges [Member]
Risk Management Assets
Risk Management Assets		57,000,000.0			14,500,000
Fair Value Hedges [Member] | Other [Member]
Risk Management Assets
Risk Management Assets		0			0
Fair Value Hedges [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets		0			0
Fair Value Hedges [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets		57,000,000.0			14,500,000
Fair Value Hedges [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0			0
AEP Texas Inc. [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		100,100,000			154,700,000
AEP Texas Inc. [Member] | Other [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0			0
AEP Texas Inc. [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		100,100,000			154,700,000
AEP Texas Inc. [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0			0
AEP Texas Inc. [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0			0
AEP Texas Inc. [Member] | Risk Management Commodity Contracts [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	0
AEP Texas Inc. [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	(1,200,000)
AEP Texas Inc. [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	0
AEP Texas Inc. [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	1,200,000
AEP Texas Inc. [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	0
Appalachian Power Co [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		15,700,000			23,500,000
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		33,900,000			63,000,000.0
Risk Management Assets
Risk Management Assets		18,200,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		15,100,000
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		37,700,000		57,800,000
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	(9,200,000)		(29,000,000.0)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[1]	0		0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Other Comprehensive Income (Loss)	[3]	0		0
Settlements		(21,900,000)		(17,800,000)
Transfers into Level 3	[4],[5]	0		0
Transfers out of Level 3	[5]	700,000		(700,000)
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	(700,000)		(2,900,000)
Ending Balance		6,600,000		7,400,000
Appalachian Power Co [Member] | Other [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0			0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		(54,200,000)			(85,600,000)
Risk Management Assets
Risk Management Assets		(54,200,000)
Liabilities, Fair Value Disclosure
Risk Management Liabilities		(59,500,000)
Appalachian Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		15,700,000			23,500,000
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		15,700,000			23,500,000
Risk Management Assets
Risk Management Assets		0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0
Appalachian Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0			0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		55,300,000			84,600,000
Risk Management Assets
Risk Management Assets		55,300,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		64,100,000
Appalachian Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents		0			0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		17,100,000			40,500,000
Risk Management Assets
Risk Management Assets		17,100,000			40,500,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		10,500,000			2,800,000
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[7],[13]	17,900,000			39,500,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[13]	9,800,000			1,900,000
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7],[13]	(54,200,000)			(85,600,000)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[13]	(59,500,000)			(84,900,000)
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7],[13]	0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[13]	0			0
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7],[13]	55,000,000.0			84,600,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[13]	58,800,000			84,000,000.0
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7],[13]	17,100,000			40,500,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[13]	10,500,000			2,800,000
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		5,300,000			5,700,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		2,200,000			2,600,000
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	9.95			12.70
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	42.15			41.20
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10],[11]	21.81			25.92
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		11,800,000			34,800,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		8,300,000			200,000
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	0			(0.14)
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	3.44			7.08
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10],[11]	0.42			1.70
Appalachian Power Co [Member] | Interest Rate [Member]
Risk Management Assets
Risk Management Assets		300,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		5,300,000
Appalachian Power Co [Member] | Interest Rate [Member] | Other [Member]
Risk Management Assets
Risk Management Assets		0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0
Appalachian Power Co [Member] | Interest Rate [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets		0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0
Appalachian Power Co [Member] | Interest Rate [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets		300,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		5,300,000
Appalachian Power Co [Member] | Interest Rate [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0
Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		2,679,200,000			2,975,700,000
Total Assets		2,686,000,000.0			2,985,600,000
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		5,800,000		8,900,000
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	200,000		0
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[1]	0		0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Other Comprehensive Income (Loss)	[3]	0		0
Settlements		(4,000,000.0)		(5,100,000)
Transfers into Level 3	[4],[5]	0		0
Transfers out of Level 3	[5]	400,000		(400,000)
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	(300,000)		1,000,000.0
Ending Balance		2,100,000		4,400,000
Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		9,900,000			8,600,000
Total Assets		(26,300,000)			(49,000,000.0)
Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,430,800,000			1,774,600,000
Total Assets		1,430,800,000			1,774,600,000
Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,238,500,000			1,192,500,000
Total Assets		1,276,600,000			1,252,000,000.0
Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
Total Assets		4,900,000			8,000,000.0
Risk Management Assets
Risk Management Assets		4,900,000			8,000,000.0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		2,800,000			2,200,000
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[7],[13]	6,800,000			9,900,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[13]	1,800,000			500,000
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7],[13]	(36,200,000)			(57,600,000)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[13]	(37,200,000)			(55,100,000)
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7],[13]	0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[13]	0			0
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7],[13]	38,100,000			59,500,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[13]	36,200,000			53,400,000
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7],[13]	4,900,000			8,000,000.0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[13]	2,800,000			2,200,000
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		3,200,000			3,400,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		1,300,000			1,500,000
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	9.95			12.70
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	42.15			41.20
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10],[11]	21.81			25.92
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		1,700,000			4,600,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		1,500,000			700,000
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	(0.51)			(0.75)
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	2.77			4.07
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10],[11]	0.12			0.74
Ohio Power Co [Member]
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		(103,600,000)		(99,400,000)
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	(300,000)		(400,000)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[1]	0		0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Other Comprehensive Income (Loss)	[3]	0		0
Settlements		2,500,000		1,800,000
Transfers into Level 3	[4],[5]	0		0
Transfers out of Level 3	[5]	0		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	(19,500,000)		(8,100,000)
Ending Balance		(120,900,000)		(106,100,000)
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[13]	120,900,000			103,600,000
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[13]	(900,000)			0
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[13]	0			0
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[13]	900,000			0
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[13]	120,900,000			103,600,000
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		120,900,000			103,600,000
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	12.57			29.23
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	42.71			61.43
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10],[11]	26.31			42.46
Public Service Co Of Oklahoma [Member]
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		15,800,000		9,500,000
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	8,000,000.0		6,800,000
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[1]	0		0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Other Comprehensive Income (Loss)	[3]	0		0
Settlements		(17,700,000)		(13,000,000.0)
Transfers into Level 3	[4],[5]	0		0
Transfers out of Level 3	[5]	0		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	200,000		1,100,000
Ending Balance		6,300,000		4,400,000
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[7],[13]	6,400,000			15,800,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[13]	100,000			0
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7],[13]	(300,000)			(500,000)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[13]	(800,000)			(500,000)
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7],[13]	0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[13]	0			0
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7],[13]	0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[13]	500,000			0
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7],[13]	6,700,000			16,300,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[13]	400,000			500,000
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		6,700,000			16,300,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		400,000			500,000
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	(7.07)			(8.52)
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	0.95			0.85
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10],[11]	(2.38)			(2.31)
Southwestern Electric Power Co [Member]
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		1,400,000		2,300,000
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[1],[2]	1,900,000		3,300,000
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[1]	0		0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Other Comprehensive Income (Loss)	[3]	0		0
Settlements		(5,300,000)		(7,300,000)
Transfers into Level 3	[4],[5]	0		0
Transfers out of Level 3	[5]	0		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	(500,000)		1,700,000
Ending Balance		(2,500,000)		$ 0
Southwestern Electric Power Co [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		2,700,000			6,500,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		5,200,000			5,100,000
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[7],[13]	2,600,000			6,400,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[13]	5,100,000			5,000,000.0
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7],[13]	(100,000)			(100,000)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[13]	(700,000)			(100,000)
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7],[13]	0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[13]	0			0
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7],[13]	0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[13]	600,000			0
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7],[13]	2,700,000			6,500,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[13]	5,200,000			5,100,000
Southwestern Electric Power Co [Member] | Natural Gas Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0			0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		5,100,000			4,900,000
Southwestern Electric Power Co [Member] | Natural Gas Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[12]	1.37			1.89
Southwestern Electric Power Co [Member] | Natural Gas Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[12]	2.51			2.51
Southwestern Electric Power Co [Member] | Natural Gas Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[11],[12]	2.13			2.18
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		2,700,000			6,500,000
Liabilities, Fair Value Disclosure
Risk Management Liabilities		100,000			200,000
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	(7.07)			(8.52)
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10]	0.95			0.85
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit	[10],[11]	(2.38)			(2.31)
Cash [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[14],[15]	151,900,000			214,700,000
Cash [Member] | Other [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[15]	23,800,000			17,100,000
Cash [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[15]	128,100,000			197,600,000
Cash [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[15]	0			0
Cash [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[15]	0			0
Fixed Income Funds [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,238,500,000			1,192,500,000
Fixed Income Funds [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
Fixed Income Funds [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
Fixed Income Funds [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,238,500,000			1,192,500,000
Fixed Income Funds [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,238,500,000			1,192,500,000
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,238,500,000			1,192,500,000
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
Mutual Funds Fixed Income [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[16]	119,000,000.0			123,300,000
Mutual Funds Fixed Income [Member] | Other [Member]
Assets, Fair Value Disclosure
Other Short-term Investments		0			0
Mutual Funds Fixed Income [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments		119,000,000.0			123,300,000
Mutual Funds Fixed Income [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments		0			0
Mutual Funds Fixed Income [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments		0			0
Mutual Funds Equity [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[17]	30,500,000			50,500,000
Mutual Funds Equity [Member] | Other [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[17]	0			0
Mutual Funds Equity [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[17]	30,500,000			50,500,000
Mutual Funds Equity [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[17]	0			0
Mutual Funds Equity [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Other Short-term Investments	[17]	0			0
Cash and Cash Equivalents [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	46,900,000			15,300,000
Cash and Cash Equivalents [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	9,900,000			8,600,000
Cash and Cash Equivalents [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	37,000,000.0			6,700,000
Cash and Cash Equivalents [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	0			0
Cash and Cash Equivalents [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	0			0
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	46,900,000			15,300,000
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	9,900,000			8,600,000
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	37,000,000.0			6,700,000
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	0			0
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	0			0
US Government Agencies Debt Securities [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,026,100,000			1,112,500,000
US Government Agencies Debt Securities [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
US Government Agencies Debt Securities [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
US Government Agencies Debt Securities [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,026,100,000			1,112,500,000
US Government Agencies Debt Securities [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,026,100,000			1,112,500,000
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,026,100,000			1,112,500,000
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
Corporate Debt [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		62,700,000			72,400,000
Corporate Debt [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
Corporate Debt [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
Corporate Debt [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		62,700,000			72,400,000
Corporate Debt [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
Corporate Debt [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		62,700,000			72,400,000
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		62,700,000			72,400,000
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
State and Local Jurisdiction [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		149,700,000			7,600,000
State and Local Jurisdiction [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
State and Local Jurisdiction [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
State and Local Jurisdiction [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		149,700,000			7,600,000
State and Local Jurisdiction [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		149,700,000			7,600,000
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		149,700,000			7,600,000
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0
Domestic [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	1,393,800,000			1,767,900,000
Domestic [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	0			0
Domestic [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	1,393,800,000			1,767,900,000
Domestic [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	0			0
Domestic [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	0			0
Domestic [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	1,393,800,000			1,767,900,000
Domestic [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	0			0
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	1,393,800,000			1,767,900,000
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	0			0
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	$ 0			$ 0

[1] Included in revenues on the statements of income.

[2] Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.

[3] Included in cash flow hedges on the statements of comprehensive income.

[4] Represents existing assets or liabilities that were previously categorized as Level 2.

[5] Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.

[6] 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.

[7] 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.’’

[8] 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.

[9] 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.

[10] Represents market prices in dollars per MWh.

[11] The weighted average is the product of the forward market price of the underlying commodity and volume weighted by term.

[12] Represents market prices in dollars per MMBtu.

[13] Substantially comprised of power contracts for the Registrant Subsidiaries.

[14] Primarily represents amounts held for the repayment of debt.

[15] 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.

[16] Primarily short and intermediate maturities which may be sold and do not contain maturity dates.

[17] Amounts represent publicly traded equity securities and equity-based mutual funds.

[18] Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions.  Level 1 amounts primarily represent investments in money market funds.

XML

Benefit Plans (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Pension Plans [Member]
Components of Net Periodic Benefit Cost
Service Cost	$ 28.0	$ 23.9
Interest Cost	42.0	51.1
Expected Return on Plan Assets	(66.2)	(74.0)
Amortization of Prior Service Cost (Credit)	0.0	0.0
Amortization of Net Actuarial Loss	23.4	14.4
Net Periodic Benefit Cost (Credit)	27.2	15.4
Pension Plans [Member] | AEP Texas Inc. [Member]
Components of Net Periodic Benefit Cost
Service Cost	2.6	2.1
Interest Cost	3.5	4.4
Expected Return on Plan Assets	(5.7)	(6.4)
Amortization of Prior Service Cost (Credit)	0.0	0.0
Amortization of Net Actuarial Loss	1.9	1.2
Net Periodic Benefit Cost (Credit)	2.3	1.3
Pension Plans [Member] | Appalachian Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	2.6	2.4
Interest Cost	5.1	6.3
Expected Return on Plan Assets	(8.4)	(9.4)
Amortization of Prior Service Cost (Credit)	0.0	0.0
Amortization of Net Actuarial Loss	2.8	1.8
Net Periodic Benefit Cost (Credit)	2.1	1.1
Pension Plans [Member] | Indiana Michigan Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	3.9	3.4
Interest Cost	4.9	6.0
Expected Return on Plan Assets	(8.3)	(9.2)
Amortization of Prior Service Cost (Credit)	0.0	0.0
Amortization of Net Actuarial Loss	2.7	1.6
Net Periodic Benefit Cost (Credit)	3.2	1.8
Pension Plans [Member] | Ohio Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	2.4	2.0
Interest Cost	3.9	4.7
Expected Return on Plan Assets	(6.6)	(7.3)
Amortization of Prior Service Cost (Credit)	0.0	0.0
Amortization of Net Actuarial Loss	2.1	1.3
Net Periodic Benefit Cost (Credit)	1.8	0.7
Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Components of Net Periodic Benefit Cost
Service Cost	1.8	1.6
Interest Cost	2.1	2.6
Expected Return on Plan Assets	(3.6)	(4.1)
Amortization of Prior Service Cost (Credit)	0.0	0.0
Amortization of Net Actuarial Loss	1.2	0.8
Net Periodic Benefit Cost (Credit)	1.5	0.9
Pension Plans [Member] | Southwestern Electric Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	2.5	2.1
Interest Cost	2.5	3.1
Expected Return on Plan Assets	(3.9)	(4.4)
Amortization of Prior Service Cost (Credit)	0.0	0.0
Amortization of Net Actuarial Loss	1.4	0.9
Net Periodic Benefit Cost (Credit)	2.5	1.7
Other Postretirement Benefit Plans [Member]
Components of Net Periodic Benefit Cost
Service Cost	2.5	2.4
Interest Cost	9.9	12.6
Expected Return on Plan Assets	(23.9)	(23.4)
Amortization of Prior Service Cost (Credit)	(17.4)	(17.3)
Amortization of Net Actuarial Loss	1.5	5.5
Net Periodic Benefit Cost (Credit)	(27.4)	(20.2)
Other Postretirement Benefit Plans [Member] | AEP Texas Inc. [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.2	0.2
Interest Cost	0.8	1.0
Expected Return on Plan Assets	(2.0)	(2.0)
Amortization of Prior Service Cost (Credit)	(1.4)	(1.5)
Amortization of Net Actuarial Loss	0.1	0.5
Net Periodic Benefit Cost (Credit)	(2.3)	(1.8)
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.3	0.3
Interest Cost	1.6	2.2
Expected Return on Plan Assets	(3.6)	(3.7)
Amortization of Prior Service Cost (Credit)	(2.5)	(2.5)
Amortization of Net Actuarial Loss	0.2	0.9
Net Periodic Benefit Cost (Credit)	(4.0)	(2.8)
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.3	0.3
Interest Cost	1.2	1.5
Expected Return on Plan Assets	(2.9)	(2.8)
Amortization of Prior Service Cost (Credit)	(2.4)	(2.4)
Amortization of Net Actuarial Loss	0.2	0.7
Net Periodic Benefit Cost (Credit)	(3.6)	(2.7)
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.2	0.2
Interest Cost	1.0	1.4
Expected Return on Plan Assets	(2.6)	(2.7)
Amortization of Prior Service Cost (Credit)	(1.8)	(1.7)
Amortization of Net Actuarial Loss	0.2	0.6
Net Periodic Benefit Cost (Credit)	(3.0)	(2.2)
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.2	0.2
Interest Cost	0.5	0.7
Expected Return on Plan Assets	(1.3)	(1.3)
Amortization of Prior Service Cost (Credit)	(1.1)	(1.1)
Amortization of Net Actuarial Loss	0.1	0.3
Net Periodic Benefit Cost (Credit)	(1.6)	(1.2)
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.2	0.2
Interest Cost	0.6	0.8
Expected Return on Plan Assets	(1.5)	(1.5)
Amortization of Prior Service Cost (Credit)	(1.3)	(1.3)
Amortization of Net Actuarial Loss	0.1	0.3
Net Periodic Benefit Cost (Credit)	$ (1.9)	$ (1.5)

XML

Rate Matters East Companies (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Dec. 31, 2019
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net	$ 61,048.9	$ 60,138.1
AEP Transmission Co [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net	9,775.4	9,490.9
Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net	11,156.9	11,081.9
Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net	6,917.5	6,899.7
Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net	$ 7,034.4	6,907.0
2017-2019 Virginia Triennial Review [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Percent of Excess Earnings Subject to Refund	70.00%
Basis Points Over Authorized Return on Equity Considered Excess Earnings	70.00%
Approved Return on Common Equity	9.42%
2019 Indiana Base Rate Case [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Amount of Increase Related to Annual Depreciation Rates	$ 78.0
Requested Annual Increase	$ 172.0
Requested Return on Equity	10.50%
Amount of Increase Related to Annual Depreciation Rates due to Proposed Investments	$ 52.0
Amount of Increase Related to Annual Depreciation Rates due to Increased Depreciation Expense	26.0
Approved Annual Revenue Increase	$ 77.0
Approved Return on Common Equity	9.70%
Initial Phased in Annual Increase	$ 44.0
Impact on Pretax Earnings due to Loss of Significant Contract	20.0
Plant Retirement Costs - Unrecovered Plant [Member] | 2017-2019 Virginia Triennial Review [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Net Book Value of Retired Plants	93.0
Other Asset Impairment Charges	93.0
Requested Annual Increase	$ 65.0
Requested Return on Equity	9.90%
Amount Of Increased Depreciation Expense Requested	$ 19.0
Amount of Increase Related to Calculated Shortfall	8.0
Virginia Jurisdictional AMR Meters [Member] | 2017-2019 Virginia Triennial Review [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net	$ 52.0	$ 51.0

XML

Revenue from Contracts with Customers

3 Months Ended

Mar. 31, 2020

Revenue from Contracts with Customers

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.

	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.

	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.

	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.

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

XML

Income Taxes Amortization of Excess ADIT not Subject to Normalization Requirements Policy (Policies)

3 Months Ended

Mar. 31, 2020

Amortization of Excess ADIT Not Subject to Normalization Requirements [Line Items]

Amortization of Excess ADIT Not Subject to Normalization Requirements Policy [Table Text Block]

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.

XML

Commitments, Guarantees and Contingencies (Tables)

3 Months Ended

Mar. 31, 2020

Maximum Future Payments for Letters of Credit Uncommitted Facilities

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.

Max Potential Loss on Master Lease Agreements [Table Text Block]

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

Future Minimum Lease Payments for Sale and Leaseback [Table Text Block]

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.

XML

Business Segments (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2020	Mar. 31, 2019	Dec. 31, 2019
Reportable Segment Information
Revenue from Contracts with Customers		$ 3,747.5	$ 4,056.8
Sales to AEP Affiliates		0.0	0.0
Total Revenues		3,747.5	4,056.8
Interest Expense		292.1	255.8
Income Tax Expense (Benefit)		46.5	44.5
Net Income (Loss)		499.3	574.1
Balance Sheet Information
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
Total Assets		77,724.0		75,892.3
Affiliated Long Term Debt Current		0.0		0.0
Long-term Debt Due Within One Year		2,109.7		1,598.7
Long-term Debt - Affiliated		0.0		0.0
Long-term Debt		25,783.0		25,126.8
Total Long-term Debt Outstanding		27,892.7		26,725.5
Vertically Integrated Utilities [Member]
Reportable Segment Information
Revenue from Contracts with Customers		2,193.0	2,372.3
Transmission and Distribution Utilities Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		1,075.2	1,179.8
Generation and Marketing Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		408.4	439.7
Other Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		70.9	65.0
AEP Transmission Co [Member]
Reportable Segment Information
Sales to AEP Affiliates		233.7	193.2
Total Revenues		295.6	243.5
Interest Income		0.8	0.7
Interest Expense		29.6	21.7
Income Tax Expense (Benefit)		31.8	27.6
Net Income (Loss)		117.8	104.3
Balance Sheet Information
Total Property, Plant and Equipment		10,221.2		9,893.2
Accumulated Depreciation and Amortization		445.8		402.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		9,775.4		9,490.9
Notes Receivable, Related Parties		0.0		0.0
Total Assets		10,199.9		9,890.8
Long-term Debt		3,427.8		3,427.3
Total Long-term Debt Outstanding		3,427.8		3,427.3
AEP Transmission Co [Member] | Transmission [Member]
Reportable Segment Information
Revenue from Contracts with Customers		61.3	50.3
AEP Transmission Co [Member] | Other Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		0.6	0.0
Reconciling Adjustments [Member]
Reportable Segment Information
Revenue from Contracts with Customers		0.0	0.0
Sales to AEP Affiliates		(354.8)	(332.2)
Total Revenues		(354.8)	(332.2)
Net Income (Loss)		0.0	0.0
Balance Sheet Information
Total Property, Plant and Equipment	[1]	(354.5)		(354.5)
Accumulated Depreciation and Amortization	[1]	(186.5)		(186.4)
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[1]	(168.0)		(168.1)
Total Assets	[1],[2]	(3,923.8)		(3,801.3)
Affiliated Long Term Debt Current		(20.0)		(20.0)
Long-term Debt Due Within One Year		0.0		0.0
Long-term Debt - Affiliated		(39.0)		(39.0)
Long-term Debt		0.0		0.0
Total Long-term Debt Outstanding		(59.0)		(59.0)
Reconciling Adjustments [Member] | AEP Transmission Co [Member]
Reportable Segment Information
Revenue from Contracts with Customers		0.0	0.0
Sales to AEP Affiliates		0.0	0.0
Total Revenues		0.0	0.0
Interest Income	[3]	(33.4)	(27.9)
Interest Expense	[3]	(33.4)	(27.9)
Income Tax Expense (Benefit)		0.0	0.0
Net Income (Loss)		0.0	0.0
Balance Sheet Information
Total Property, Plant and Equipment		0.0		0.0
Accumulated Depreciation and Amortization		0.0		0.0
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		0.0		0.0
Notes Receivable, Related Parties	[4]	(3,427.8)		(3,427.3)
Total Assets	[5]	(3,513.7)		(3,493.3)
Total Long-term Debt Outstanding	[4]	(3,465.0)		(3,465.0)
Reconciling Adjustments [Member] | AEP Transmission Co [Member] | Other Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		0.0
Vertically Integrated Utilities [Member]
Reportable Segment Information
Sales to AEP Affiliates		33.7	31.0
Total Revenues		2,226.7	2,403.3
Net Income (Loss)		246.3	303.6
Balance Sheet Information
Total Property, Plant and Equipment		47,764.3		47,323.7
Accumulated Depreciation and Amortization		14,821.8		14,580.4
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		32,942.5		32,743.3
Total Assets		41,020.5		41,228.8
Affiliated Long Term Debt Current		20.0		20.0
Long-term Debt Due Within One Year		1,316.3		704.7
Long-term Debt - Affiliated		39.0		39.0
Long-term Debt		11,641.0		12,162.0
Total Long-term Debt Outstanding		13,016.3		12,925.7
Vertically Integrated Utilities [Member] | Vertically Integrated Utilities [Member]
Reportable Segment Information
Revenue from Contracts with Customers		2,193.0	2,372.3
Transmission And Distribution Utilities [Member]
Reportable Segment Information
Sales to AEP Affiliates		31.7	42.2
Total Revenues		1,106.9	1,222.0
Net Income (Loss)		116.2	156.5
Balance Sheet Information
Total Property, Plant and Equipment		20,182.8		19,773.3
Accumulated Depreciation and Amortization		3,964.6		3,911.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		16,218.2		15,862.1
Total Assets		18,892.5		18,757.5
Affiliated Long Term Debt Current		0.0		0.0
Long-term Debt Due Within One Year		289.0		392.2
Long-term Debt - Affiliated		0.0		0.0
Long-term Debt		6,585.5		6,248.1
Total Long-term Debt Outstanding		6,874.5		6,640.3
Transmission And Distribution Utilities [Member] | Transmission and Distribution Utilities Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		1,075.2	1,179.8
AEP Transmission Holdco [Member]
Reportable Segment Information
Sales to AEP Affiliates		237.1	195.2
Total Revenues		310.2	256.4
Net Income (Loss)		141.6	125.2
Balance Sheet Information
Total Property, Plant and Equipment		10,662.9		10,334.0
Accumulated Depreciation and Amortization		464.0		418.9
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		10,198.9		9,915.1
Total Assets		11,484.8		11,143.5
Affiliated Long Term Debt Current		0.0		0.0
Long-term Debt Due Within One Year		0.0		0.0
Long-term Debt - Affiliated		0.0		0.0
Long-term Debt		3,600.3		3,593.8
Total Long-term Debt Outstanding		3,600.3		3,593.8
AEP Transmission Holdco [Member] | Transmission [Member]
Reportable Segment Information
Revenue from Contracts with Customers		73.1	61.2
Generation And Marketing [Member]
Reportable Segment Information
Sales to AEP Affiliates		30.2	42.1
Total Revenues		438.6	481.8
Net Income (Loss)		30.5	39.2
Balance Sheet Information
Total Property, Plant and Equipment		1,753.2		1,650.8
Accumulated Depreciation and Amortization		116.9		99.0
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		1,636.3		1,551.8
Total Assets		3,216.4		3,123.8
Affiliated Long Term Debt Current		0.0		0.0
Long-term Debt Due Within One Year		0.0		0.0
Long-term Debt - Affiliated		0.0		0.0
Long-term Debt		0.0		0.0
Total Long-term Debt Outstanding		0.0		0.0
Generation And Marketing [Member] | Generation and Marketing Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		408.4	439.7
All Other [Member]
Reportable Segment Information
Sales to AEP Affiliates	[6]	22.1	21.7
Total Revenues	[6]	19.9	25.5
Net Income (Loss)	[6]	(35.3)	(50.4)
Balance Sheet Information
Total Property, Plant and Equipment	[6]	408.3		418.4
Accumulated Depreciation and Amortization	[6]	187.3		184.5
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[6]	221.0		233.9
Total Assets	[6],[7]	7,033.6		5,440.0
Affiliated Long Term Debt Current	[6]	0.0		0.0
Long-term Debt Due Within One Year	[6],[8]	504.4		501.8
Long-term Debt - Affiliated	[6]	0.0		0.0
Long-term Debt	[6],[8]	3,956.2		3,122.9
Total Long-term Debt Outstanding	[6]	4,460.6		3,624.7
All Other [Member] | Other Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers	[6]	(2.2)	3.8
State Transcos [Member] | AEP Transmission Co [Member]
Reportable Segment Information
Sales to AEP Affiliates		233.7	193.2
Total Revenues		295.6	243.5
Interest Income		0.2	0.2
Interest Expense		29.6	21.7
Income Tax Expense (Benefit)		31.8	27.6
Net Income (Loss)		117.3	104.2
Balance Sheet Information
Total Property, Plant and Equipment		10,221.2		9,893.2
Accumulated Depreciation and Amortization		445.8		402.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		9,775.4		9,490.9
Notes Receivable, Related Parties		0.0		0.0
Total Assets		10,150.9		9,865.0
Total Long-term Debt Outstanding		3,465.0		3,465.0
State Transcos [Member] | AEP Transmission Co [Member] | Transmission [Member]
Reportable Segment Information
Revenue from Contracts with Customers		61.3	50.3
State Transcos [Member] | AEP Transmission Co [Member] | Other Revenues [Member]
Reportable Segment Information
Revenue from Contracts with Customers		0.6
AEPTCo Parent [Member] | AEP Transmission Co [Member]
Reportable Segment Information
Revenue from Contracts with Customers		0.0	0.0
Sales to AEP Affiliates		0.0	0.0
Total Revenues		0.0	0.0
Interest Income		34.0	28.4
Interest Expense		33.4	27.9
Income Tax Expense (Benefit)		0.0	0.0
Net Income (Loss)	[9]	0.5	$ 0.1
Balance Sheet Information
Total Property, Plant and Equipment		0.0		0.0
Accumulated Depreciation and Amortization		0.0		0.0
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		0.0		0.0
Notes Receivable, Related Parties		3,427.8		3,427.3
Total Assets	[10]	3,562.7		3,519.1
Total Long-term Debt Outstanding		3,427.8		$ 3,427.3
AEPTCo Parent [Member] | AEP Transmission Co [Member] | Transmission [Member]
Reportable Segment Information
Revenue from Contracts with Customers		$ 0.0

[1] Includes eliminations due to an intercompany finance lease.

[2] Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable.

[3] Elimination of intercompany interest income/interest expense on affiliated debt arrangement.

[4] Elimination of intercompany debt.

[5] Primarily relates to the elimination of Notes Receivable from the State Transcos.

[6] 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.

[7] Includes elimination of AEP Parent’s investments in wholly-owned subsidiary companies.

[8] Amounts reflect the impact of fair value hedge accounting. See “Accounting for Fair Value Hedging Strategies” section of Note 10 for additional information.

[9] Includes the elimination of AEPTCo Parent’s equity earnings in the State Transcos.

[10] Includes the elimination of AEPTCo Parent’s investments in State Transcos.

XML

Rate Matters West Companies (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended
	May 06, 2020	Mar. 31, 2020	Dec. 31, 2019
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		$ 4,511.5	$ 4,319.8
AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		747.0	763.9
Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		144.9	133.4
Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		232.7	$ 216.9
2019 Texas Base Rate Case [Member] | AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 56.0
Requested Return on Equity		10.50%
Refund for Excess ADIT		$ 21.0
Other Asset Impairment Charges		33.0
2019 Texas Base Rate Case [Member] | AEP Texas Inc. [Member] | Rate Case Expense [Member]
Public Utilities, General Disclosures [Line Items]
Write-off of Regulatory Expense		4.0
2019 Texas Base Rate Case [Member] | AEP Texas Inc. [Member] | Amount of 2019 Investments [Member]
Public Utilities, General Disclosures [Line Items]
Other Asset Impairment Charges		$ 10.0
ETT Interim Transmission Rates [Member]
Public Utilities, General Disclosures [Line Items]
Parent Ownership Interest In ETT		50.00%
AEP Share Of ETT Cumulative Revenues Subject To Review		$ 1,100.0
2012 Texas Base Rate Case [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
2013 Reversal Of Previously Recorded Regulatory Disallowances		114.0
Resulting Approved Base Rate Increase		52.0
2012 Texas Base Rate Case [Member] | Turk Generating Plant [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net		$ 1,500.0
Texas Jurisdictional Share of Turk Plant		33.00%
2016 Texas Base Rate Case [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Return on Equity		10.00%
Requested Net Increase in Texas Annual Revenues		$ 69.0
Approved Net Increase in Texas Annual Revenues		$ 50.0
Approved Return on Common Equity		9.60%
Approved Additional Vegetation Management Expenses		$ 2.0
Impairment Charge Total		19.0
Impairment Charge Welsh Plant, Unit 2		7.0
Impairment Charge Disallowed Plant Investments		12.0
Additional Revenues Recognized to be Surcharged to Customers		32.0
Additional Recognized Expenses Consisting Primarily of Depreciation and Vegetation Management		7.0
Louisiana 2018 Formula Rate Filing [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		28.0
Adjusted Requested Annual Increase		18.0
Refund for Current Year Tax Reform Rate Change		11.0
Additional Refund for Current Year Tax Reform Rate Change		4.0
Staff Recommended Annual Rate Increase		14.0
Subsequent Event [Member] | 2019 Texas Base Rate Case [Member] | AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Approved Annual Revenue Decrease	$ 40.0
Refund for Excess ADIT Associated with Certain Depreciable Property	$ 275.0
Approved Return on Common Equity	9.40%
Public Utilities, Approved Debt Capital Structure, Percentage	57.50%
Public Utilities, Approved Equity Capital Structure, Percentage	42.50%
Subsequent Event [Member] | 2019 Texas Base Rate Case [Member] | AEP Texas Inc. [Member] | Capital Investments [Member]
Public Utilities, General Disclosures [Line Items]
Disallowed Item in Commission Order	$ 23.0
Subsequent Event [Member] | 2019 Texas Base Rate Case [Member] | AEP Texas Inc. [Member] | Rate Case Expense [Member]
Public Utilities, General Disclosures [Line Items]
Disallowed Item in Commission Order	4.0
Capitalized Vegetation Management Expenses [Member] | Subsequent Event [Member] | 2019 Texas Base Rate Case [Member] | AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Approved Item in Commission Order	26.0
Excess ADIT and Excess Federal Income Taxes to Distribution Customers [Member] | Subsequent Event [Member] | 2019 Texas Base Rate Case [Member] | AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Item to be Refunded in Commission Order	77.0
Excess ADIT and Excess Federal Income Taxes to Transmission Customers [Member] | Subsequent Event [Member] | 2019 Texas Base Rate Case [Member] | AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Item to be Refunded in Commission Order	31.0
Previously Collected Rates Subject to Reconciliation [Member] | 2019 Texas Base Rate Case [Member] | AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Provision for Refund		$ 30.0
Previously Collected Rates Subject to Reconciliation [Member] | Subsequent Event [Member] | 2019 Texas Base Rate Case [Member] | AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Item to be Refunded in Commission Order	$ 30.0

XML

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal Statutory Rate	21.00%	21.00%
State Income Tax, net of Federal benefit	2.50%	2.10%
Tax Reform Excess ADIT Reversal	(9.40%)	(13.60%)
Production and Investment Tax Credits	(4.30%)	(2.20%)
Flow Through	0.50%	(0.20%)
AFUDC Equity	(1.40%)	(1.40%)
Parent Company Loss	0.00%	0.00%
Discrete Tax Adjustments	0.00%	1.70%
Other	(0.40%)	(0.20%)
Effective Income Tax Rate	8.50%	7.20%
Income Taxes (Textuals) [Abstract]
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	$ 20
AEP Texas Inc. [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal Statutory Rate	21.00%	21.00%
State Income Tax, net of Federal benefit	1.50%	1.50%
Tax Reform Excess ADIT Reversal	(6.20%)	(7.60%)
Production and Investment Tax Credits	(0.40%)	(1.00%)
Flow Through	0.10%	0.30%
AFUDC Equity	(2.60%)	(1.60%)
Parent Company Loss	(0.20%)	(2.30%)
Discrete Tax Adjustments	0.00%	0.00%
Other	0.30%	0.10%
Effective Income Tax Rate	13.50%	10.40%
AEP Transmission Co [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal Statutory Rate	21.00%	21.00%
State Income Tax, net of Federal benefit	2.90%	2.90%
Tax Reform Excess ADIT Reversal	0.40%	0.40%
Production and Investment Tax Credits	0.00%	0.00%
Flow Through	0.50%	0.20%
AFUDC Equity	(2.60%)	(2.50%)
Parent Company Loss	(0.90%)	(1.00%)
Discrete Tax Adjustments	0.00%	0.00%
Other	0.00%	(0.10%)
Effective Income Tax Rate	21.30%	20.90%
Appalachian Power Co [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal Statutory Rate	21.00%	21.00%
State Income Tax, net of Federal benefit	3.00%	3.40%
Tax Reform Excess ADIT Reversal	(13.00%)	(42.20%)
Production and Investment Tax Credits	0.00%	0.00%
Flow Through	1.50%	(0.90%)
AFUDC Equity	(1.00%)	(1.00%)
Parent Company Loss	(3.30%)	(2.40%)
Discrete Tax Adjustments	0.00%	0.40%
Other	0.10%	(0.30%)
Effective Income Tax Rate	8.30%	(22.00%)
Income Taxes (Textuals) [Abstract]
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	$ 7
Indiana Michigan Power Co [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal Statutory Rate	21.00%	21.00%
State Income Tax, net of Federal benefit	3.20%	2.00%
Tax Reform Excess ADIT Reversal	(19.60%)	(17.40%)
Production and Investment Tax Credits	(1.90%)	(2.00%)
Flow Through	0.20%	(2.40%)
AFUDC Equity	(1.10%)	(1.90%)
Parent Company Loss	(3.90%)	(1.80%)
Discrete Tax Adjustments	2.70%	0.00%
Other	(0.20%)	(0.30%)
Effective Income Tax Rate	0.40%	(2.80%)
Ohio Power Co [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal Statutory Rate	21.00%	21.00%
State Income Tax, net of Federal benefit	0.70%	0.90%
Tax Reform Excess ADIT Reversal	(10.20%)	(7.60%)
Production and Investment Tax Credits	0.00%	0.00%
Flow Through	1.00%	0.70%
AFUDC Equity	(1.00%)	(0.70%)
Parent Company Loss	(0.10%)	(1.10%)
Discrete Tax Adjustments	0.00%	0.00%
Other	0.00%	0.20%
Effective Income Tax Rate	11.40%	13.40%
Income Taxes (Textuals) [Abstract]
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	$ 9
Public Service Co Of Oklahoma [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal Statutory Rate	21.00%	21.00%
State Income Tax, net of Federal benefit	4.60%	4.60%
Tax Reform Excess ADIT Reversal	(23.10%)	(21.90%)
Production and Investment Tax Credits	(1.30%)	(1.70%)
Flow Through	0.60%	0.60%
AFUDC Equity	(0.70%)	(0.40%)
Parent Company Loss	(2.20%)	(1.80%)
Discrete Tax Adjustments	0.00%	0.00%
Other	0.10%	0.20%
Effective Income Tax Rate	(1.00%)	0.60%
Southwestern Electric Power Co [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal Statutory Rate	21.00%	21.00%
State Income Tax, net of Federal benefit	2.70%	0.20%
Tax Reform Excess ADIT Reversal	(94.70%)	(17.00%)
Production and Investment Tax Credits	(0.50%)	(0.80%)
Flow Through	(1.00%)	(0.90%)
AFUDC Equity	(0.40%)	(1.10%)
Parent Company Loss	(2.40%)	(0.50%)
Discrete Tax Adjustments	0.00%	0.00%
Other	7.20%	1.50%
Effective Income Tax Rate	(68.10%)	2.40%

XML

Rate Matters (Tables)

3 Months Ended

Mar. 31, 2020

Regulated Generating Unit Expected to be Retired by 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.

Regulatory Assets Pending Final Regulatory Approval

	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.

	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) 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.

	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

	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

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Financing Activities

3 Months Ended

Mar. 31, 2020

Financing Activities

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.

		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.

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.

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

Maximum

Average

Average

Borrowings from

Loans to

Authorized

Borrowings

Loans

Borrowings

Loans

AEP as of

AEP as of

Short-term

from AEP

to AEP

from AEP

to AEP

March 31, 2020

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.

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

Interest Rate

Interest Rate

Interest Rate

Interest Rate

Interest Rate

for Funds

for Funds

for Funds

for Funds

for Funds

for Funds

Loaned to

Loaned to

Loaned to

Loaned to

Loaned to

Loaned to

the Nonutility

the Nonutility

the Nonutility

the Nonutility

the Nonutility

the Nonutility

Company

Money Pool

Money Pool

Money Pool

Money Pool

Money Pool

Money Pool

AEP Texas

2.24

%

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	%

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.

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

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Fair Value Measurements (Policies)

3 Months Ended

Mar. 31, 2020

Valuation Techniques

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.

Fair Values of Long-term Debt

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.

Trust Assets for Decommissioning and Spent Nuclear Fuel Disposal

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.

Fair Value Assets and Liabilities Measured on Recurring Basis

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.

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Rate Matters

3 Months Ended

Mar. 31, 2020

Rate Matters

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)

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.

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.

	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) 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.

	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

	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.

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.

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.

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.

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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Business Segments

3 Months Ended

Mar. 31, 2020

Business Segments

BUSINESS SEGMENTS

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

AEP’s Reportable Segments

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

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

Vertically Integrated Utilities

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

Transmission and Distribution Utilities

• Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo.

• OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load.

AEP Transmission Holdco

• Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved 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.

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

	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.

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

	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.

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Financing Activities (Tables)

3 Months Ended

Mar. 31, 2020

Long-term Debt

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 Issuances

		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.

Retirements and Principal Payments

		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

Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits

	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.

Nonutility Money Pool Activity

		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

Direct Borrowing Activity

Maximum

Maximum

Average

Average

Borrowings from

Loans to

Authorized

Borrowings

Loans

Borrowings

Loans

AEP as of

AEP as of

Short-term

from AEP

to AEP

from AEP

to AEP

March 31, 2020

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.

Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool

	Three Months Ended March 31,
	2020		2019
Maximum Interest Rate	2.24	%	3.02	%
Minimum Interest Rate	1.76	%	2.73	%

Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool

	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 Average Interest Rates for Funds Borrowed from Loaned to Nonutility Money Pool

Three Months Ended March 31, 2020

Three Months Ended March 31, 2019

Maximum

Minimum

Average

Maximum

Minimum

Average

Interest Rate

Interest Rate

Interest Rate

Interest Rate

Interest Rate

Interest Rate

for Funds

for Funds

for Funds

for Funds

for Funds

for Funds

Loaned to

Loaned to

Loaned to

Loaned to

Loaned to

Loaned to

the Nonutility

the Nonutility

the Nonutility

the Nonutility

the Nonutility

the Nonutility

Company

Money Pool

Money Pool

Money Pool

Money Pool

Money Pool

Money Pool

AEP Texas

2.24

%

1.76

%

1.94

%

3.02

%

2.73

%

2.87

%

SWEPCo

2.24

%

1.76

%

1.94

%

3.02

%

2.73

%

2.87

%

Maximum Minimum and Average Interest Rates for Funds Borrowed from and Loaned to AEP

	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	%

Short Term Debt

		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.

Comparative Accounts Receivable Information

	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

Customer Accounts Receivable Managed Portfolio

	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

Accounts Receivable and Accrued Unbilled Revenues

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

Fees Paid to AEP Credit for Customer Accounts Receivable Sold

	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

Proceeds on Sale of Receivables to AEP Credit

	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

XML

Business Segments (Tables)

3 Months Ended

Mar. 31, 2020

Segment Reporting Information [Line Items]

Reportable Segment Information

	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

	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.

	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

	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.

XML

Rate Matters Regulated Operations (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2020	Dec. 31, 2019
Public Utilities, General Disclosures [Line Items]
Gross Investment		$ 22,853.7	$ 22,762.4
Accumulated Depreciation		19,368.1	19,007.6
Net Investment		61,048.9	60,138.1
Materials and Supplies		645.0	640.7
Regulatory Assets, Noncurrent		3,197.4	3,158.8
AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Gross Investment		351.6	351.7
Accumulated Depreciation		1,800.1	1,758.1
Net Investment		9,055.4	8,845.1
Materials and Supplies		63.8	56.7
Regulatory Assets, Noncurrent		272.2	280.6
AEP Transmission Co [Member]
Public Utilities, General Disclosures [Line Items]
Accumulated Depreciation		445.8	402.3
Net Investment		9,775.4	9,490.9
Materials and Supplies		13.4	13.8
Regulatory Assets, Noncurrent		2.5	4.2
Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Gross Investment		6,602.1	6,563.7
Accumulated Depreciation		4,497.0	4,432.3
Net Investment		11,156.9	11,081.9
Materials and Supplies		100.4	105.2
Regulatory Assets, Noncurrent		464.0	457.2
Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Gross Investment		5,114.0	5,099.7
Accumulated Depreciation		3,356.3	3,294.3
Net Investment		6,917.5	6,899.7
Materials and Supplies		171.1	171.3
Regulatory Assets, Noncurrent		459.0	482.1
Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Accumulated Depreciation		2,292.8	2,263.0
Net Investment		7,034.4	6,907.0
Materials and Supplies		58.3	52.3
Regulatory Assets, Noncurrent		396.4	351.8
Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Gross Investment		1,577.2	1,574.6
Accumulated Depreciation		1,615.8	1,580.1
Net Investment		4,140.4	4,103.3
Materials and Supplies		47.9	46.8
Regulatory Assets, Noncurrent		378.4	375.2
Public Service Co Of Oklahoma [Member] | Oklaunion Generating Station [Member] | Generating Units Probable of Abandonment [Member]
Public Utilities, General Disclosures [Line Items]
Gross Investment		106.8
Accumulated Depreciation		92.6
Net Investment		14.2
Accelerated Depreciation Regulatory Asset	[1]	33.0
Materials and Supplies		3.3
Cost of Removal Regulatory Liability		$ 5.2
Expected Retirement Date		2020
Remaining Recovery Period		27 years
Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Gross Investment		$ 4,703.0	4,691.4
Accumulated Depreciation		2,918.7	2,873.7
Net Investment		7,146.6	7,095.2
Materials and Supplies		93.8	94.0
Regulatory Assets, Noncurrent		236.6	222.4
Southwestern Electric Power Co [Member] | Dolet Hills Power Station [Member] | Generating Units Probable of Abandonment [Member]
Public Utilities, General Disclosures [Line Items]
Gross Investment		341.4
Accumulated Depreciation		205.0
Net Investment		136.4
Accelerated Depreciation Regulatory Asset	[2]	9.1
Materials and Supplies		5.8
Cost of Removal Regulatory Liability		$ 23.7
Expected Retirement Date		2021
Remaining Recovery Period		27 years
Percent of Fuel Supply Provided by DHLC		100.00%
Asset Retirement Obligation, Revision of Estimate		$ 21.0
Share of Net Investment in Dolet Hills Power Station		151.0
Dolet Hills Lignite Company Unbilled Fixed Costs		124.0
Oxbow Unbilled Fixed Costs		26.0
Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	[3]	162.0	181.7
Regulatory Assets Pending Final Regulatory Approval [Member] | Virginia Jurisdictional AMR Meters [Member]
Public Utilities, General Disclosures [Line Items]
Net Investment		52.0	51.0
Regulatory Assets Pending Final Regulatory Approval [Member] | AEP Texas Inc. [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		5.3	30.8
Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	[3]	25.9	30.6
Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member] | Virginia Jurisdictional AMR Meters [Member]
Public Utilities, General Disclosures [Line Items]
Net Investment		52.0	51.0
Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0.0	7.7
Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0.1	0.1
Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		40.3	34.6
Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		56.1	46.3
Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Plant Retirement Costs - Unrecovered Plant [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		35.2	35.2
Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Oklaunion Power Station Accelerated Depreciation [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		33.0	27.4
Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Kentucky Deferred Purchase Power Expenses [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		32.9	30.2
Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Dolet Hills Power Station Accelerated Depreciation [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		9.1	0.0
Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Other Regulatory Assets Not Yet Being Recovered [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		2.1	0.7
Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member] | Plant Retirement Costs - Materials and Supplies [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0.0	0.5
Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member] | Oklaunion Power Station Accelerated Depreciation [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		33.0	27.4
Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member] | Plant Retirement Costs - Unrecovered Plant, Louisiana [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		35.2	35.2
Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member] | Dolet Hills Power Station Accelerated Depreciation [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		9.1	0.0
Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member] | Other Regulatory Assets Not Yet Being Recovered [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		2.2	0.2
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Plant Retirement Costs - Asset Retirement Obligation Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		25.9	30.1
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Asset Retirement Obligation [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		7.7	7.2
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Storm-Related Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		7.3	7.2
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Vegetation Management Program [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	[4]	3.8	29.4
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Vegetation Management Program [Member] | 2019 Texas Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		26.0
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Cook Plant Study Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	[5]	0.0	7.6
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Other Regulatory Assets Not Yet Being Recovered [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		5.0	6.7
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | AEP Texas Inc. [Member] | Vegetation Management Program [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	[4]	3.8	29.4
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | AEP Texas Inc. [Member] | Vegetation Management Program [Member] | 2019 Texas Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		26.0
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | AEP Texas Inc. [Member] | Other Regulatory Assets Not Yet Being Recovered [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		1.5	1.4
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member] | Plant Retirement Costs - Asset Retirement Obligation Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		25.9	30.1
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member] | Cook Plant Study Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	[5]	0.0	7.6
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member] | Other Regulatory Assets Not Yet Being Recovered [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0.0	0.1
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member] | Other Regulatory Assets Not Yet Being Recovered [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0.1	0.1
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member] | Storm-Related Costs [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		7.3	7.2
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member] | Asset Retirement Obligation - Louisiana [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		7.7	7.2
Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member] | Other Regulatory Assets Not Yet Being Recovered [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		$ 1.9	$ 3.7

[1] 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.

[2] 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.

[3] 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.

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

[5] Approved for recovery in the first quarter of 2020 in the Indiana Base Rate Case.

XML

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Current Assets
Cash and Cash Equivalents	$ 1,554.6	$ 246.8
Restricted Cash	116.2	185.8
Other Temporary Investments	185.2	202.7
Fuel	550.9	528.5
Other Inventory, Supplies, Gross	645.0	640.7
Property, Plant and Equipment
Other Property, Plant and Equipment	4,913.2	4,811.5
Accumulated Depreciation and Amortization	19,368.1	19,007.6
Other Noncurrent Assets
Securitized Transition Assets	789.1	858.1
Current Liabilities
Long-term Debt Due Within One Year	2,109.7	1,598.7
Accrued Interest	307.9	243.6
Noncurrent Liabilities
Long-term Debt	$ 25,783.0	$ 25,126.8
Equity
Common Stock, Par Value Per Share	$ 6.50	$ 6.50
Common Stock, Shares Authorized	600,000,000	600,000,000
Common Stock, Shares, Issued	515,411,847	514,373,631
Treasury Stock, Shares	20,204,160	20,204,160
AEP Subsidiaries [Member]
Current Assets
Restricted Cash	$ 116.2	$ 185.8
Other Temporary Investments	163.6	187.8
Current Liabilities
Long-term Debt Due Within One Year	289.6	565.1
Noncurrent Liabilities
Long-term Debt	1,037.6	907.0
AEP Texas Inc. [Member]
Current Assets
Cash and Cash Equivalents	0.1	3.1
Restricted Cash	100.1	154.7
Fuel	6.4	5.9
Other Inventory, Supplies, Gross	63.8	56.7
Property, Plant and Equipment
Other Property, Plant and Equipment	829.1	805.9
Accumulated Depreciation and Amortization	1,800.1	1,758.1
Other Noncurrent Assets
Securitized Transition Assets	560.5	623.4
Current Liabilities
Long-term Debt Due Within One Year	289.0	392.1
Accrued Interest	54.8	35.7
Noncurrent Liabilities
Long-term Debt	4,156.4	4,166.3
AEP Texas Inc. [Member] | AEP Texas Transition Funding and Restoration Funding [Member]
Current Assets
Restricted Cash	100.1	154.7
Other Noncurrent Assets
Securitized Transition Assets	560.7	621.2
Current Liabilities
Long-term Debt Due Within One Year	178.3	281.4
Accrued Interest	4.9	7.5
Noncurrent Liabilities
Long-term Debt	484.7	495.4
Appalachian Power Co [Member]
Current Assets
Cash and Cash Equivalents	2.8	3.3
Restricted Cash	15.7	23.5
Fuel	160.0	149.7
Other Inventory, Supplies, Gross	100.4	105.2
Property, Plant and Equipment
Other Property, Plant and Equipment	585.5	571.3
Accumulated Depreciation and Amortization	4,497.0	4,432.3
Other Noncurrent Assets
Securitized Transition Assets	228.5	234.7
Current Liabilities
Long-term Debt Due Within One Year	583.3	215.6
Accrued Interest	67.0	47.9
Noncurrent Liabilities
Long-term Debt	$ 3,769.1	$ 4,148.2
Equity
Common Stock, Shares Authorized	30,000,000	30,000,000
Common Stock, Shares Outstanding	13,499,500	13,499,500
Indiana Michigan Power Co [Member]
Current Assets
Cash and Cash Equivalents	$ 1.8	$ 2.0
Fuel	71.7	56.2
Other Inventory, Supplies, Gross	171.1	171.3
Property, Plant and Equipment
Other Property, Plant and Equipment	617.4	632.6
Accumulated Depreciation and Amortization	3,356.3	3,294.3
Current Liabilities
Long-term Debt Due Within One Year	133.6	139.7
Accrued Interest	20.3	36.2
Noncurrent Liabilities
Long-term Debt	$ 2,894.4	$ 2,910.5
Equity
Common Stock, No Par Value	$ 0	$ 0
Common Stock, Shares Authorized	2,500,000	2,500,000
Common Stock, Shares Outstanding	1,400,000	1,400,000
Indiana Michigan Power Co [Member] | DCC Fuel [Member]
Current Liabilities
Long-term Debt Due Within One Year	$ 80.0	$ 86.1
Ohio Power Co [Member]
Current Assets
Cash and Cash Equivalents	3.1	3.7
Other Inventory, Supplies, Gross	58.3	52.3
Property, Plant and Equipment
Other Property, Plant and Equipment	797.2	765.8
Accumulated Depreciation and Amortization	2,292.8	2,263.0
Current Liabilities
Long-term Debt Due Within One Year	0.1	0.1
Noncurrent Liabilities
Long-term Debt	$ 2,429.0	$ 2,081.9
Equity
Common Stock, No Par Value	$ 0	$ 0
Common Stock, Shares Authorized	40,000,000	40,000,000
Common Stock, Shares Outstanding	27,952,473	27,952,473
Public Service Co Of Oklahoma [Member]
Current Assets
Cash and Cash Equivalents	$ 1.1	$ 1.5
Fuel	19.6	12.2
Other Inventory, Supplies, Gross	47.9	46.8
Property, Plant and Equipment
Other Property, Plant and Equipment	350.3	342.1
Accumulated Depreciation and Amortization	1,615.8	1,580.1
Current Liabilities
Long-term Debt Due Within One Year	263.2	13.2
Noncurrent Liabilities
Long-term Debt	$ 1,123.1	$ 1,373.0
Equity
Common Stock, Par Value Per Share	$ 15	$ 15
Common Stock, Shares Authorized	11,000,000	11,000,000
Common Stock, Shares, Issued	10,482,000	10,482,000
Common Stock, Shares Outstanding	9,013,000	9,013,000
Southwestern Electric Power Co [Member]
Current Assets
Cash and Cash Equivalents	$ 1.4	$ 1.6
Fuel	147.9	140.1
Other Inventory, Supplies, Gross	93.8	94.0
Property, Plant and Equipment
Other Property, Plant and Equipment	767.2	733.4
Accumulated Depreciation and Amortization	2,918.7	2,873.7
Current Liabilities
Long-term Debt Due Within One Year	121.2	121.2
Accrued Interest	21.9	34.6
Noncurrent Liabilities
Long-term Debt	$ 2,533.2	$ 2,534.4
Equity
Common Stock, Par Value Per Share	$ 18	$ 18
Common Stock, Shares Authorized	7,600,000	7,600,000
Common Stock, Shares Outstanding	7,536,640	7,536,640
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member]
Current Assets
Fuel	$ 42.0	$ 47.0
Other Inventory, Supplies, Gross	23.3	23.1
Property, Plant and Equipment
Other Property, Plant and Equipment	213.5	212.3
Accumulated Depreciation and Amortization	$ 112.0	$ 107.5

XML

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2020	Mar. 31, 2019
Revenue from Contracts with Customers		$ 3,747.5	$ 4,056.8
Net Income (Loss)		499.3	574.1
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax		(67.0)	(28.9)
Amortization of Pension and OPEB Deferred Costs, Net of Tax		(1.8)	(1.4)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		(68.8)	(30.3)
TOTAL COMPREHENSIVE INCOME (LOSS)		430.5	543.8
Total Comprehensive Income (Loss) Attributable to Noncontrolling Interest		4.1	1.3
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS		426.4	542.5
Appalachian Power Co [Member]
Net Income (Loss)		115.3	133.7
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax		(4.2)	(0.2)
Amortization of Pension and OPEB Deferred Costs, Net of Tax		(0.9)	(0.6)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		(5.1)	(0.8)
TOTAL COMPREHENSIVE INCOME (LOSS)		110.2	132.9
AEP Texas Inc. [Member]
Net Income (Loss)		47.6	34.4
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax		0.3	0.3
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		0.3	0.3
TOTAL COMPREHENSIVE INCOME (LOSS)		47.9	34.7
Indiana Michigan Power Co [Member]
Net Income (Loss)		92.3	98.9
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax		0.4	0.4
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		0.4	0.4
TOTAL COMPREHENSIVE INCOME (LOSS)		92.7	99.3
Ohio Power Co [Member]
Net Income (Loss)		75.1	128.0
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax		0.0	(0.3)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)			(0.3)
TOTAL COMPREHENSIVE INCOME (LOSS)		75.1	127.7
Public Service Co Of Oklahoma [Member]
Net Income (Loss)		(10.3)	6.2
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax		(0.2)	(0.2)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		(0.2)	(0.2)
TOTAL COMPREHENSIVE INCOME (LOSS)		(10.5)	6.0
Southwestern Electric Power Co [Member]
Net Income (Loss)		16.1	29.0
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax		0.4	0.4
Amortization of Pension and OPEB Deferred Costs, Net of Tax		(0.4)	(0.3)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		0.0	0.1
TOTAL COMPREHENSIVE INCOME (LOSS)		16.1	29.1
Total Comprehensive Income (Loss) Attributable to Noncontrolling Interest		1.0	1.2
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS		15.1	27.9
Generation and Marketing Revenues [Member]
Revenue from Contracts with Customers		408.4	439.7
Reclassification out of Accumulated Other Comprehensive Income [Member] | Generation and Marketing Revenues [Member]
Revenue from Contracts with Customers	[1]	(0.1)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member]
OTHER COMPREHENSIVE INCOME
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		(1.8)	(1.4)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | Appalachian Power Co [Member]
OTHER COMPREHENSIVE INCOME
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		(0.9)	(0.6)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | AEP Texas Inc. [Member]
OTHER COMPREHENSIVE INCOME
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		0.0	0.0
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | Indiana Michigan Power Co [Member]
OTHER COMPREHENSIVE INCOME
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		0.0	0.0
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | Southwestern Electric Power Co [Member]
OTHER COMPREHENSIVE INCOME
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		(0.4)	$ (0.3)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Generation and Marketing Revenues [Member]
Revenue from Contracts with Customers	[1]	$ 0.0

[1] (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

XML

Financing Activities (Details) - USD ($)			1 Months Ended	3 Months Ended
		May 06, 2020	Apr. 30, 2020	Mar. 31, 2020	Mar. 31, 2019	Dec. 31, 2019
Long-term Debt
Senior Unsecured Notes				$ 22,515,800,000		$ 21,180,700,000
Pollution Control Bonds				1,999,200,000		1,998,800,000
Notes Payable				209,400,000		234,300,000
Securitization Bonds				899,100,000		1,025,100,000
Spent Nuclear Fuel Obligation	[1]			280,900,000		279,800,000
Junior Subordinated Notes	[2]			788,600,000		787,800,000
Other Long-term Debt				1,199,700,000		1,219,000,000.0
Total Long-term Debt Outstanding				27,892,700,000		26,725,500,000
Long-term Debt Due Within One Year				2,109,700,000		1,598,700,000
Long-term Debt				25,783,000,000.0		25,126,800,000
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt	[3]			1,430,000,000.0
Repayments of Long-term Debt				$ 300,500,000	$ 220,600,000
Document Period End Date				Mar. 31, 2020
Short-term Debt:
Securitized Debt for Receivables	[4]			$ 724,000,000.0		710,000,000.0
Commercial Paper				2,709,600,000		2,110,000,000.0
Other Short-term Investments				1,000,000,000.0		0
Notes Payable				30,500,000		18,300,000
Total Short-term Debt				$ 4,464,100,000		$ 2,838,300,000
Securitized Debt for Receivables	[4],[5]			1.75%		2.42%
Comparative Accounts Receivable Information
Effective Interest Rates on Securitization of Accounts Receivable				1.75%	2.71%
Net Uncollectible Accounts Receivable Written Off				$ 4,200,000	$ 6,400,000
Customer Accounts Receivable Managed Portfolio
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts				850,700,000		$ 841,800,000
Total Principal Outstanding				724,000,000.0		710,000,000.0
Delinquent Securitized Accounts Receivable				43,400,000		39,600,000
Bad Debt Reserves Related to Securitization, Sale of Accounts Receivable				34,500,000		32,100,000
Unbilled Receivables Related to Securitization, Sale of Accounts Receivable				219,800,000		266,800,000
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold				3,747,500,000	4,056,800,000
Financing Activities (Textuals)
Trust Fund Assets One Time Fee Obligation for Nuclear Fuel Disposition				$ 324,000,000		$ 323,000,000
Maximum Percentage Debt to Capitalization				67.50%
Total Commitment from Bank Conduits to Finance Receivables				$ 750,000,000
Equity Units Issued				16,100,000
Per Unit Conversion for Equity Units				$ 50
Net Equity Units Issuance Proceeds				785,000,000
Principal Amounts of Junior Subordinated Debt				$ 1,000
Forward Equity Purchase Contract Date				2022
Equity Units Annual Distribution Rate				6.125%
Forward Equity Contract Payment Rate				2.725%
Stockholders' Equity, Other				$ 30,200,000	55,600,000
Maximum Shares Issued Under Equity Units Conversion				9,701,860
Senior Unsecured Notes [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt	[3]			$ 400,000,000.0
Due Date				2030
Interest Rate (Percentage)				2.30%
Senior Unsecured Notes Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt	[3]			$ 400,000,000.0
Due Date				2050
Interest Rate (Percentage)				3.25%
Commercial Paper [Member]
Short-term Debt:
Weighted Average Interest Rate	[5]			2.24%		2.10%
Short-term Debt [Member]
Short-term Debt:
Weighted Average Interest Rate	[5]			1.53%		0.00%
Loans Payable [Member]
Short-term Debt:
Weighted Average Interest Rate	[5]			2.98%		3.29%
AEP Texas Inc. [Member]
Long-term Debt
Total Long-term Debt Outstanding				$ 4,445,400,000		$ 4,558,400,000
Long-term Debt Due Within One Year				289,000,000.0		392,100,000
Long-term Debt				4,156,400,000		4,166,300,000
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt				$ 114,300,000	$ 103,500,000
Financing Activities (Textuals)
Maximum Percentage Debt to Capitalization				67.50%
AEP Texas Inc. [Member] | Utility [Member]
Maximum Interest Rate				2.24%	3.02%
Minimum Interest Rate				1.76%	2.73%
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Borrowings from Money Pool				$ 63,900,000
Maximum Loans to Money Pool				199,700,000
Average Borrowings from Money Pool				39,000,000.0
Average Loans to Money Pool				90,300,000
Net Loans (Borrowings) to/from Money Pool				(63,900,000)
Authorized Short Term Borrowing Limit				$ 500,000,000.0
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				2.05%	2.86%
Average Interest Rate For Funds Loaned				1.97%	0.00%
AEP Texas Inc. [Member] | Nonutility [Member]
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Loans to Money Pool				$ 7,500,000
Average Loans to Money Pool				7,200,000
Net Loans (Borrowings) to/from Money Pool				$ 7,100,000
Maximum and Minimum Interest Rates
Maximum Interest Rate For Funds Loaned				2.24%	3.02%
Minimum Interest Rate for Funds Loaned				1.76%	2.73%
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Loaned				1.94%	2.87%
AEP Texas Inc. [Member] | Securitization Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt				$ 111,000,000.0
Due Date				2020
Interest Rate (Percentage)				5.31%
AEP Texas Inc. [Member] | Securitization Bonds Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt				$ 3,300,000
Due Date				2025
Interest Rate (Percentage)				2.06%
AEP Transmission Co [Member]
Long-term Debt
Total Long-term Debt Outstanding				$ 3,427,800,000		3,427,300,000
Long-term Debt				3,427,800,000		3,427,300,000
Financing Activities (Textuals)
Sub-Limit of Secured Debt				$ 50,000,000
Maximum Percentage of Consolidated Tangible Net Assets				10.00%
Tangible Capital to Tangible Assets				3.30%
Maximum Percentage Debt to Capitalization				67.50%
AEP Transmission Co [Member] | Utility [Member]
Maximum Interest Rate				2.24%	3.02%
Minimum Interest Rate				1.76%	2.73%
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Borrowings from Money Pool				$ 358,400,000
Maximum Loans to Money Pool				69,800,000
Average Borrowings from Money Pool				257,600,000
Average Loans to Money Pool				32,600,000
Net Loans (Borrowings) to/from Money Pool				(261,000,000.0)
Authorized Short Term Borrowing Limit	[6]			$ 820,000,000.0
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				1.95%	2.83%
Average Interest Rate For Funds Loaned				1.91%	2.90%
AEP Transmission Co [Member] | Direct Borrowing [Member]
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Borrowings from Money Pool				$ 1,400,000
Maximum Loans to Money Pool				190,300,000
Average Borrowings from Money Pool				1,400,000
Average Loans to Money Pool				125,100,000
Borrowings from Parent				1,300,000
Loans to Parent				93,300,000
Authorized Short Term Borrowing Limit	[7]			$ 50,000,000.0
Maximum and Minimum Interest Rates
Maximum Interest Rate for Funds Borrowed				2.24%	3.02%
Minimum Interest Rate For Funds Borrowed				1.76%	2.73%
Maximum Interest Rate For Funds Loaned				2.24%	3.02%
Minimum Interest Rate for Funds Loaned				1.76%	2.73%
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				1.94%	2.87%
Average Interest Rate For Funds Loaned				1.94%	2.86%
AEP Transmission Co [Member] | Senior Unsecured Notes [Member] | Subsequent Event [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt			$ 525,000,000
Due Date			2050
Interest Rate (Percentage)			3.65%
Appalachian Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding				$ 4,352,400,000		4,363,800,000
Long-term Debt Due Within One Year				583,300,000		215,600,000
Long-term Debt				3,769,100,000		4,148,200,000
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt				12,200,000	$ 12,000,000.0
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues				121,800,000		120,900,000
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit				$ 352,600,000	374,400,000
Financing Activities (Textuals)
Maximum Percentage Debt to Capitalization				67.50%
Appalachian Power Co [Member] | Servicing Contracts [Member]
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold				$ 1,700,000	$ 2,200,000
Appalachian Power Co [Member] | Utility [Member]
Maximum Interest Rate				2.24%	3.02%
Minimum Interest Rate				1.76%	2.73%
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Borrowings from Money Pool				$ 373,500,000
Maximum Loans to Money Pool				22,200,000
Average Borrowings from Money Pool				303,100,000
Average Loans to Money Pool				22,000,000.0
Net Loans (Borrowings) to/from Money Pool				(333,500,000)
Authorized Short Term Borrowing Limit				$ 500,000,000.0
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				1.95%	2.92%
Average Interest Rate For Funds Loaned				1.94%	2.79%
Appalachian Power Co [Member] | Securitization Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt				$ 12,200,000
Due Date				2023
Interest Rate (Percentage)				2.01%
Indiana Michigan Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding				$ 3,028,000,000.0		3,050,200,000
Long-term Debt Due Within One Year				133,600,000		139,700,000
Long-term Debt				2,894,400,000		2,910,500,000
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt				23,700,000	$ 26,500,000
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues				155,200,000		141,800,000
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit				471,400,000	478,600,000
Financing Activities (Textuals)
Trust Fund Assets One Time Fee Obligation for Nuclear Fuel Disposition				$ 324,000,000		323,000,000
Maximum Percentage Debt to Capitalization				67.50%
Indiana Michigan Power Co [Member] | Servicing Contracts [Member]
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold				$ 2,800,000	$ 2,800,000
Indiana Michigan Power Co [Member] | Utility [Member]
Maximum Interest Rate				2.24%	3.02%
Minimum Interest Rate				1.76%	2.73%
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Borrowings from Money Pool				$ 147,500,000
Maximum Loans to Money Pool				13,300,000
Average Borrowings from Money Pool				108,400,000
Average Loans to Money Pool				13,300,000
Net Loans (Borrowings) to/from Money Pool				(90,400,000)
Authorized Short Term Borrowing Limit				$ 500,000,000.0
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				1.95%	2.80%
Average Interest Rate For Funds Loaned				1.94%	2.87%
Indiana Michigan Power Co [Member] | Notes Payable, Other Payables [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt				$ 700,000
Due Date				2020
Interest Rate (Variable)				Variable
Indiana Michigan Power Co [Member] | Notes Payable, Other Payable Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt				$ 1,500,000
Due Date				2021
Interest Rate (Variable)				Variable
Indiana Michigan Power Co [Member] | Notes Payable, Other Payable Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt				$ 5,100,000
Due Date				2022
Interest Rate (Variable)				Variable
Indiana Michigan Power Co [Member] | Notes Payable, Other Payable Four [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt				$ 3,800,000
Due Date				2022
Interest Rate (Variable)				Variable
Indiana Michigan Power Co [Member] | Notes Payable, Other Payable Five [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt				$ 6,200,000
Due Date				2023
Interest Rate (Variable)				Variable
Indiana Michigan Power Co [Member] | Notes Payable, Other Payables Six [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt				$ 6,000,000.0
Due Date				2024
Interest Rate (Variable)				Variable
Indiana Michigan Power Co [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt				$ 400,000
Due Date				2025
Interest Rate (Percentage)				6.00%
Ohio Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding				$ 2,429,100,000		2,082,000,000.0
Long-term Debt Due Within One Year				100,000		100,000
Long-term Debt				2,429,000,000.0		2,081,900,000
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt				0	$ 23,400,000
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues				338,300,000		330,300,000
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit				570,300,000	636,800,000
Ohio Power Co [Member] | Servicing Contracts [Member]
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold				$ 4,800,000	$ 7,800,000
Ohio Power Co [Member] | Utility [Member]
Maximum Interest Rate				2.24%	3.02%
Minimum Interest Rate				1.76%	2.73%
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Borrowings from Money Pool				$ 353,900,000
Maximum Loans to Money Pool				32,800,000
Average Borrowings from Money Pool				191,500,000
Average Loans to Money Pool				25,200,000
Net Loans (Borrowings) to/from Money Pool				(29,400,000)
Authorized Short Term Borrowing Limit				$ 500,000,000.0
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				1.90%	2.85%
Average Interest Rate For Funds Loaned				2.06%	0.00%
Ohio Power Co [Member] | Senior Unsecured Notes [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt	[3]			$ 350,000,000.0
Due Date				2030
Interest Rate (Percentage)				2.60%
Public Service Co Of Oklahoma [Member]
Long-term Debt
Total Long-term Debt Outstanding				$ 1,386,300,000		1,386,200,000
Long-term Debt Due Within One Year				263,200,000		13,200,000
Long-term Debt				1,123,100,000		1,373,000,000.0
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt				100,000	$ 100,000
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues				93,300,000		101,100,000
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit				$ 294,900,000	324,500,000
Financing Activities (Textuals)
Maximum Percentage Debt to Capitalization				67.50%
Public Service Co Of Oklahoma [Member] | Servicing Contracts [Member]
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold				$ 1,300,000	$ 2,100,000
Public Service Co Of Oklahoma [Member] | Utility [Member]
Maximum Interest Rate				2.24%	3.02%
Minimum Interest Rate				1.76%	2.73%
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Borrowings from Money Pool				$ 70,900,000
Maximum Loans to Money Pool				57,100,000
Average Borrowings from Money Pool				25,300,000
Average Loans to Money Pool				28,400,000
Net Loans (Borrowings) to/from Money Pool				(70,900,000)
Authorized Short Term Borrowing Limit				$ 300,000,000.0
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				2.00%	2.89%
Average Interest Rate For Funds Loaned				1.95%	0.00%
Public Service Co Of Oklahoma [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt				$ 100,000
Due Date				2027
Interest Rate (Percentage)				3.00%
Southwestern Electric Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding				$ 2,654,400,000		2,655,600,000
Long-term Debt Due Within One Year				121,200,000		121,200,000
Long-term Debt				2,533,200,000		2,534,400,000
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt				1,600,000	$ 55,100,000
Short-term Debt:
Notes Payable				30,500,000		18,300,000
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues				121,200,000		$ 125,200,000
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit				$ 365,600,000	371,900,000
Financing Activities (Textuals)
Maximum Percentage Debt to Capitalization				67.50%
Southwestern Electric Power Co [Member] | Servicing Contracts [Member]
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold				$ 2,100,000	$ 2,600,000
Southwestern Electric Power Co [Member] | Utility [Member]
Maximum Interest Rate				2.24%	3.02%
Minimum Interest Rate				1.76%	2.73%
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Borrowings from Money Pool				$ 152,800,000
Maximum Loans to Money Pool				0
Average Borrowings from Money Pool				105,500,000
Average Loans to Money Pool				0
Net Loans (Borrowings) to/from Money Pool				(148,100,000)
Authorized Short Term Borrowing Limit				$ 350,000,000.0
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				1.95%	2.81%
Average Interest Rate For Funds Loaned				0.00%	2.97%
Southwestern Electric Power Co [Member] | Nonutility [Member]
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits
Maximum Loans to Money Pool				$ 2,100,000
Average Loans to Money Pool				2,100,000
Net Loans (Borrowings) to/from Money Pool				$ 2,100,000
Maximum and Minimum Interest Rates
Maximum Interest Rate For Funds Loaned				2.24%	3.02%
Minimum Interest Rate for Funds Loaned				1.76%	2.73%
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool
Average Interest Rate For Funds Loaned				1.94%	2.87%
Southwestern Electric Power Co [Member] | Notes Payable, Other Payables [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt				$ 1,600,000
Due Date				2032
Interest Rate (Percentage)				4.58%
Southwestern Electric Power Co [Member] | Loans Payable [Member]
Short-term Debt:
Weighted Average Interest Rate	[5]			2.98%		3.29%
Kentucky Power Co [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt	[3]			$ 125,000,000.0
Due Date				2022
Interest Rate (Variable)				Variable
Transource Energy [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt	[3]			$ 5,000,000.0
Due Date				2023
Interest Rate (Variable)				Variable
Transource Energy [Member] | Other Long Term Debt [Member] | Subsequent Event [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt			$ 1,000,000
Due Date			2023
Transource Energy [Member] | OtherLongTermDebtTwo [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt				$ 148,600,000
Due Date				2023
Interest Rate (Variable)				Varaible
Transource Energy [Member] | Senior Unsecured Notes [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Proceeds from Issuance of Debt	[3]			$ 150,000,000.0
Due Date				2050
Interest Rate (Percentage)				2.75%
Maximum [Member]
Financing Activities (Textuals)
AEP Share Price for Equity Unit Conversion				$ 99.58
Shares Per Equity Unit				0.6026
Minimum [Member]
Financing Activities (Textuals)
AEP Share Price for Equity Unit Conversion				$ 82.98
Shares Per Equity Unit				0.5021
Retained Earnings [Member]
Financing Activities (Textuals)
Stockholders' Equity, Other				$ 0	$ 62,100,000
Notes Payable, Other Payables [Member] | Indiana Michigan Power Co [Member] | Subsequent Event [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Repayments of Long-term Debt		$ 1,000,000	$ 8,000,000

[1] 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.

[2] See “Equity Units” section below for additional information.

[3] 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.

[4] Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.

[5] Weighted-average rate.

[6] Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.

[7] Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.

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Fair Value Long-term Debt, Other Temporary Investments, Nuclear Trusts (Details) - USD ($) $ in Millions		3 Months Ended		12 Months Ended
		Mar. 31, 2020	Mar. 31, 2019	Dec. 31, 2019
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		$ 27,892.7		$ 26,725.5
Long Term Debt, Fair Value	[1]	29,776.6		30,172.0
Other Temporary Investments
Cost		289.8		367.1
Gross Unrealized Gains		11.6		21.4
Gross Unrealized Losses		0.0		0.0
Other Short-term Investments		301.4		388.5
Debt and Equity Securities Within Other Temporary Investments
Proceeds from Investment Sales		23.2	$ 0.0
Purchases of Investments		6.7	0.1
Gross Realized Gains on Investment Sales		2.0	0.0
Gross Realized Losses on Investment Sales		0.1	0.0
Nuclear Trust Fund Investments
Fair Value		2,679.2		2,975.7
Contractual Maturities, Fair Value of Debt Securities
Fair Value		2,679.2		2,975.7
Spent Nuclear Fuel and Decommissioning Trusts [Member]
Unrealized Gain on Securities		801.0		1,100.0
Nuclear Trust Fund Investments
Gross Unrealized Gains		906.5		1,205.9
Other-Than-Temporary Impairments		(7.4)		(7.9)
Securities Activity Within Decommissioning and SNF Trusts
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
Contractual Maturities, Fair Value of Debt Securities
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
Fair Value Measurements (Textuals)
Adjusted Cost of Debt Securities		1,100.0		1,100.0
Adjusted Cost of Domestic Equity Securities		616.0		623.0
Unrealized Loss on Securities		23.0		5.0
Cash [Member]
Other Temporary Investments
Cost	[2]	151.9		214.7
Gross Unrealized Gains	[2]	0.0		0.0
Gross Unrealized Losses	[2]	0.0		0.0
Other Short-term Investments	[2],[3]	151.9		214.7
Fixed Income Funds [Member]
Nuclear Trust Fund Investments
Fair Value		1,238.5		1,192.5
Contractual Maturities, Fair Value of Debt Securities
Fair Value		1,238.5		1,192.5
Fixed Income Funds [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		128.9		61.5
Other-Than-Temporary Impairments		(7.4)		(7.9)
Mutual Funds Fixed Income [Member]
Other Temporary Investments
Cost	[4]	118.6		123.2
Gross Unrealized Gains	[4]	0.4		0.1
Gross Unrealized Losses	[4]	0.0		0.0
Other Short-term Investments	[4]	119.0		123.3
Domestic [Member]
Nuclear Trust Fund Investments
Fair Value	[5]	1,393.8		1,767.9
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[5]	1,393.8		1,767.9
Domestic [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains	[6]	777.6		1,144.4
Other-Than-Temporary Impairments		0.0		0.0
Mutual Funds Equity [Member]
Other Temporary Investments
Cost		19.3		29.2
Gross Unrealized Gains		11.2		21.3
Gross Unrealized Losses		0.0		0.0
Other Short-term Investments	[5]	30.5		50.5
Cash and Cash Equivalents [Member]
Nuclear Trust Fund Investments
Fair Value	[7]	46.9		15.3
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[7]	46.9		15.3
Cash and Cash Equivalents [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		0.0		0.0
Other-Than-Temporary Impairments		0.0		0.0
US Government Agencies Debt Securities [Member]
Nuclear Trust Fund Investments
Fair Value		1,026.1		1,112.5
Contractual Maturities, Fair Value of Debt Securities
Fair Value		1,026.1		1,112.5
US Government Agencies Debt Securities [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		121.4		55.5
Other-Than-Temporary Impairments		(5.6)		(6.1)
Corporate Debt [Member]
Nuclear Trust Fund Investments
Fair Value		62.7		72.4
Contractual Maturities, Fair Value of Debt Securities
Fair Value		62.7		72.4
Corporate Debt [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		6.0		5.3
Other-Than-Temporary Impairments		(1.6)		(1.6)
State and Local Jurisdiction [Member]
Nuclear Trust Fund Investments
Fair Value		149.7		7.6
Contractual Maturities, Fair Value of Debt Securities
Fair Value		149.7		7.6
State and Local Jurisdiction [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		1.5		0.7
Other-Than-Temporary Impairments		(0.2)		(0.2)
AEP Texas Inc. [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		4,445.4		4,558.4
Long Term Debt, Fair Value		4,637.3		4,981.5
AEP Transmission Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		3,427.8		3,427.3
Long Term Debt, Fair Value		3,680.7		3,868.0
Appalachian Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		4,352.4		4,363.8
Long Term Debt, Fair Value		4,959.0		5,253.1
Indiana Michigan Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		3,028.0		3,050.2
Long Term Debt, Fair Value		3,318.2		3,453.8
Nuclear Trust Fund Investments
Fair Value		2,679.2		2,975.7
Contractual Maturities, Fair Value of Debt Securities
Fair Value		2,679.2		2,975.7
Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Unrealized Gain on Securities		801.0		1,149.0
Nuclear Trust Fund Investments
Gross Unrealized Gains		906.5		1,205.9
Other-Than-Temporary Impairments		(7.4)		(7.9)
Securities Activity Within Decommissioning and SNF Trusts
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
Contractual Maturities, Fair Value of Debt Securities
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
Fair Value Measurements (Textuals)
Adjusted Cost of Debt Securities		1,000.0		1,000.0
Adjusted Cost of Domestic Equity Securities		616.0		623.0
Unrealized Loss on Securities		23.0		5.0
Indiana Michigan Power Co [Member] | Fixed Income Funds [Member]
Nuclear Trust Fund Investments
Fair Value		1,238.5		1,192.5
Contractual Maturities, Fair Value of Debt Securities
Fair Value		1,238.5		1,192.5
Indiana Michigan Power Co [Member] | Fixed Income Funds [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		128.9		61.5
Other-Than-Temporary Impairments		(7.4)		(7.9)
Indiana Michigan Power Co [Member] | Domestic [Member]
Nuclear Trust Fund Investments
Fair Value	[5]	1,393.8		1,767.9
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[5]	1,393.8		1,767.9
Indiana Michigan Power Co [Member] | Domestic [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains	[6]	777.6		1,144.4
Other-Than-Temporary Impairments	[6]	0.0		0.0
Indiana Michigan Power Co [Member] | Cash and Cash Equivalents [Member]
Nuclear Trust Fund Investments
Fair Value	[7]	46.9		15.3
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[7]	46.9		15.3
Indiana Michigan Power Co [Member] | Cash and Cash Equivalents [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		0.0		0.0
Other-Than-Temporary Impairments		0.0		0.0
Indiana Michigan Power Co [Member] | US Government Agencies Debt Securities [Member]
Nuclear Trust Fund Investments
Fair Value		1,026.1		1,112.5
Contractual Maturities, Fair Value of Debt Securities
Fair Value		1,026.1		1,112.5
Indiana Michigan Power Co [Member] | US Government Agencies Debt Securities [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		121.4		55.5
Other-Than-Temporary Impairments		(5.6)		(6.1)
Indiana Michigan Power Co [Member] | Corporate Debt [Member]
Nuclear Trust Fund Investments
Fair Value		62.7		72.4
Contractual Maturities, Fair Value of Debt Securities
Fair Value		62.7		72.4
Indiana Michigan Power Co [Member] | Corporate Debt [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		6.0		5.3
Other-Than-Temporary Impairments		(1.6)		(1.6)
Indiana Michigan Power Co [Member] | State and Local Jurisdiction [Member]
Nuclear Trust Fund Investments
Fair Value		149.7		7.6
Contractual Maturities, Fair Value of Debt Securities
Fair Value		149.7		7.6
Indiana Michigan Power Co [Member] | State and Local Jurisdiction [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains		1.5		0.7
Other-Than-Temporary Impairments		(0.2)		(0.2)
Ohio Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		2,429.1		2,082.0
Long Term Debt, Fair Value		2,795.3		2,554.3
Public Service Co Of Oklahoma [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		1,386.3		1,386.2
Long Term Debt, Fair Value		1,553.9		1,603.3
Southwestern Electric Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		2,654.4		2,655.6
Long Term Debt, Fair Value		2,776.5		2,927.9
Equity Units [Member]
Book Values and Fair Values of Long - term Debt
Long Term Debt, Fair Value		$ 777.0		$ 871.0

[1] 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.

[2] Primarily represents amounts held for the repayment of debt.

[3] 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.

[4] Primarily short and intermediate maturities which may be sold and do not contain maturity dates.

[5] Amounts represent publicly traded equity securities and equity-based mutual funds.

[6] 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.

[7] Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions.  Level 1 amounts primarily represent investments in money market funds.

XML

Acquisitions and Impairments (Details) $ in Millions	3 Months Ended
	Mar. 31, 2020 USD ($) Rate MW	Mar. 31, 2019 USD ($)
Utilities Operating Expense, Operations	$ 602.1	$ 666.0
Generation And Marketing [Member] | AEP Wind Holdings LLC [Member]
Maximum Potential Amount of Future Payments Associated with Guarantee	175.0
Guarantor Obligations, Current Carrying Value	$ 33.0
Percentage of an Asset Acquired | Rate	50.00%
Wind Generation MWs | MW	724
Noncash or Part Noncash Acquisition, Value of Assets Acquired	$ 1,100.0
Payments to Acquire Businesses, Gross	580.0
Noncash or Part Noncash Acquisition, Debt Assumed	364.0
Guarantor Obligations, Current Carrying Value, Contingent Portion	1.0
Equity Method Investments [Member] | Generation And Marketing [Member] | AEP Wind Holdings LLC [Member]
Acquisition	404.0
Noncontrolling Interest [Member] | Generation And Marketing [Member] | AEP Wind Holdings LLC [Member]
Noncash or Part Noncash Acquisition, Other Assets Acquired	135.0
Indiana Michigan Power Co [Member]
Cost of Purchased Power from Affiliate	36.2	59.8
Utilities Operating Expense, Operations	144.7	140.5
Ohio Power Co [Member]
Cost of Purchased Power from Affiliate	42.4	46.1
Utilities Operating Expense, Operations	177.3	216.9
Southwestern Electric Power Co [Member]
Utilities Operating Expense, Operations	$ 92.2	$ 84.6

XML

Significant Accounting Matters (Policies)

3 Months Ended

Mar. 31, 2020

Basis of Accounting

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.

Earnings Per Share

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.

XML

Significant Accounting Matters (Tables)

3 Months Ended

Mar. 31, 2020

Basic and Diluted EPS Calculations

	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

Supplementary Information

	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

XML

Significant Accounting Matters (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019	Dec. 31, 2019	Dec. 31, 2018
Amounts Attributable to AEP Common Shareholders
Earnings Attributable to 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 Dilutive Effect of:
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
Organization and Summary of Significant Accounting Policies (Textuals)
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	697,000	0
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents	$ 1,554.6		$ 246.8
Restricted Cash	116.2		185.8
Total Cash, Cash Equivalents and Restricted Cash	1,670.8	$ 363.1	432.6	$ 444.1
AEP Texas Inc. [Member]
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents	0.1		3.1
Restricted Cash	100.1		154.7
Total Cash, Cash Equivalents and Restricted Cash	100.2	100.7	157.8	159.8
AEP Transmission Co [Member]
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents	0.0	0.0	0.0	0.0
Appalachian Power Co [Member]
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents	2.8		3.3
Restricted Cash	15.7		23.5
Total Cash, Cash Equivalents and Restricted Cash	18.5	21.2	26.8	29.8
Indiana Michigan Power Co [Member]
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents	1.8	1.7	2.0	2.4
Ohio Power Co [Member]
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents	3.1		3.7
Total Cash, Cash Equivalents and Restricted Cash	3.1	19.8	3.7	32.5
Public Service Co Of Oklahoma [Member]
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents	1.1	1.5	1.5	2.0
Southwestern Electric Power Co [Member]
Amounts Attributable to AEP Common Shareholders
Earnings Attributable to Common Shareholders	15.1	27.8
Cash, Cash Equivalents and Restricted Cash
Cash and Cash Equivalents	$ 1.4	$ 22.1	$ 1.6	$ 24.5
Restricted Stock Units and Performance Share Units [Member]
Weighted Average Dilutive Effect of:
Weighted Average Dilutive Effect of Shares	2,000,000.0	1,200,000
Dilutive Securities, Effect on Basic Earnings Per Share	$ 0	$ 0

XML

Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2020

Book Values and Fair Values of Long-term Debt

	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.

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.

Debt 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		—

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.

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

Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts

	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

Fair Value, Assets and Liabilities Measured on Recurring Basis

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

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

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

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

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	)	$	—

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.

Changes in Fair Value of Net Trading Derivatives and Other Investments

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.

Significant Unobservable Inputs for Level 3

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

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

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	)

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.

Sensitivity of Fair Value Measurements

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)

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New Accounting Standards

3 Months Ended

Mar. 31, 2020

New Accounting Standards

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.

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Acquisitions and Impairments

3 Months Ended

Mar. 31, 2020

Acquisitions and Impairments

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.

XML

Fair Value Measurements

3 Months Ended

Mar. 31, 2020

Fair Value Measurements

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.

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.

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.

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

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

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

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

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

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	)	$	—

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.

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.

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

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

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	)

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)

XML

Condensed Consolidated Statements of Changes in Equity - USD ($) $ in Millions	Total	Appalachian Power Co [Member]	AEP Texas Inc. [Member]	AEP Transmission Co [Member]	Indiana Michigan Power Co [Member]	Ohio Power Co [Member]	Public Service Co Of Oklahoma [Member]	Southwestern Electric Power Co [Member]	Common Stock [Member]	Common Stock [Member] Appalachian Power Co [Member]	Common Stock [Member] Indiana Michigan Power Co [Member]	Common Stock [Member] Ohio Power Co [Member]	Common Stock [Member] Public Service Co Of Oklahoma [Member]	Common Stock [Member] Southwestern Electric Power Co [Member]	Additional Paid-in Capital [Member]		Additional Paid-in Capital [Member] Appalachian Power Co [Member]	Additional Paid-in Capital [Member] AEP Texas Inc. [Member]	Additional Paid-in Capital [Member] AEP Transmission Co [Member]	Additional Paid-in Capital [Member] Indiana Michigan Power Co [Member]	Additional Paid-in Capital [Member] Ohio Power Co [Member]	Additional Paid-in Capital [Member] Public Service Co Of Oklahoma [Member]	Additional Paid-in Capital [Member] Southwestern Electric Power Co [Member]	Retained Earnings [Member]		Retained Earnings [Member] Appalachian Power Co [Member]	Retained Earnings [Member] AEP Texas Inc. [Member]	Retained Earnings [Member] AEP Transmission Co [Member]	Retained Earnings [Member] Indiana Michigan Power Co [Member]	Retained Earnings [Member] Ohio Power Co [Member]	Retained Earnings [Member] Public Service Co Of Oklahoma [Member]	Retained Earnings [Member] Southwestern Electric Power Co [Member]	Accumulated Other Comprehensive Income [Member]	Accumulated Other Comprehensive Income [Member] Appalachian Power Co [Member]	Accumulated Other Comprehensive Income [Member] AEP Texas Inc. [Member]	Accumulated Other Comprehensive Income [Member] Indiana Michigan Power Co [Member]	Accumulated Other Comprehensive Income [Member] Ohio Power Co [Member]	Accumulated Other Comprehensive Income [Member] Public Service Co Of Oklahoma [Member]	Accumulated Other Comprehensive Income [Member] Southwestern Electric Power Co [Member]	Noncontrolling Interests [Member]	Noncontrolling Interests [Member] Southwestern Electric Power Co [Member]
Beginning Balance at Dec. 31, 2018				$ 3,569.8															$ 2,480.6									$ 1,089.2
Beginning Balance at Dec. 31, 2018	$ 19,059.4	$ 4,006.1	$ 2,580.5		$ 2,352.8	$ 2,297.4	$ 1,248.0	$ 2,315.6	$ 3,337.4	$ 260.4	$ 56.6	$ 321.2	$ 157.2	$ 135.7	$ 6,486.1		$ 1,828.7	$ 1,257.9		$ 980.9	$ 838.8	$ 364.0	$ 676.6	$ 9,325.3		$ 1,922.0	$ 1,337.7		$ 1,329.1	$ 1,136.4	$ 724.7	$ 1,508.4	$ (120.4)	$ (5.0)	$ (15.1)	$ (13.8)	$ 1.0	$ 2.1	$ (5.4)	$ 31.0	$ 0.3
Beginning Balance, Shares at Dec. 31, 2018									513,500,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of Common Stock, Value	14.5								$ 1.2						13.3
Issuance of Common Stock, Shares									100,000
Common Stock Dividends	(333.6)																							(332.5)	[1]
Common Stock Dividends		(50.0)			(20.0)	(25.0)	(11.3)	(18.7)																		(50.0)			(20.0)	(25.0)	(11.3)	(18.7)
Common Stock Dividends								(1.1)																																(1.1)	(1.1)
Other Changes in Equity	(55.6)														(56.6)	[2]								(62.1)																1.0
Capital Contribution from Member			200.0															200.0
Net Income (Loss)	572.8							27.8																572.8								27.8
Net Income (Loss) Attributable to Noncontrolling Interests	1.3							1.2																																1.3	1.2
Net Income (Loss)	574.1	133.7	34.4	104.3	98.9	128.0	6.2	29.0																		133.7	34.4	104.3	98.9	128.0	6.2
Other Comprehensive Income (Loss)	(30.3)	(0.8)	0.3		0.4	(0.3)	(0.2)	0.1																									(30.3)	(0.8)	0.3	0.4	(0.3)	(0.2)	0.1
Ending Balance at Mar. 31, 2019				3,674.1															2,480.6									1,193.5
Ending Balance at Mar. 31, 2019	$ 19,228.5	4,089.0	2,815.2		2,432.1	2,400.1	1,242.7	2,324.9	$ 3,338.6	260.4	56.6	321.2	157.2	135.7	6,442.8		1,828.7	1,457.9		980.9	838.8	364.0	676.6	9,565.6		2,005.7	1,372.1		1,408.0	1,239.4	719.6	1,517.5	(150.7)	(5.8)	(14.8)	(13.4)	0.7	1.9	(5.3)	32.2	0.4
Ending Balance, Shares at Mar. 31, 2019									513,600,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends Per Share, Declared	$ 0.67
Beginning Balance at Dec. 31, 2019				4,009.5															2,480.6									1,528.9
Beginning Balance at Dec. 31, 2019	$ 19,913.2	4,172.4	2,961.1		2,544.4	2,508.5	$ 1,373.3	2,441.1	$ 3,343.4	260.4	56.6	321.2	157.2	135.7	6,535.6		1,828.7	1,457.9		980.9	838.8	364.0	676.6	9,900.9		2,078.3	1,516.0		1,518.5	1,348.5	851.0	1,629.5	(147.7)	5.0	(12.8)	(11.6)	0.0	1.1	(1.3)	281.0	0.6
Beginning Balance, Shares at Dec. 31, 2019	514,373,631						10,482,000		514,400,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of Common Stock, Value	$ 56.1								$ 6.8						49.3
Issuance of Common Stock, Shares									1,000,000.0
Common Stock Dividends	(363.7)																							(359.1)	[1]
Common Stock Dividends		(50.0)			(21.3)	(21.9)																				(50.0)			(21.3)	(21.9)
Common Stock Dividends								(0.7)																																(4.6)	(0.7)
Other Changes in Equity	(30.2)														(29.0)									0.0																(1.2)
ASU 2016-13 Adoption	(1.8)				0.4	(0.3)	$ (0.3)	(1.6)																(1.8)					0.4	(0.3)	(0.3)	(1.6)
Capital Contribution from Member				185.0															185.0
Net Income (Loss)	495.2							15.1																495.2								15.1
Net Income (Loss) Attributable to Noncontrolling Interests	4.1							1.0																																4.1	1.0
Net Income (Loss)	499.3	115.3	47.6	117.8	92.3	75.1	(10.3)	16.1																		115.3	47.6	117.8	92.3	75.1	(10.3)
Other Comprehensive Income (Loss)	(68.8)	(5.1)	0.3		0.4		(0.2)	0.0																									(68.8)	(5.1)	0.3	0.4		(0.2)
Ending Balance at Mar. 31, 2020				$ 4,312.3															$ 2,665.6									$ 1,646.7
Ending Balance at Mar. 31, 2020	$ 20,007.7	$ 4,232.6	$ 3,009.0		$ 2,616.2	$ 2,562.0	$ 1,363.1	$ 2,458.1	$ 3,350.2	$ 260.4	$ 56.6	$ 321.2	$ 157.2	$ 135.7	$ 6,555.9		$ 1,828.7	$ 1,457.9		$ 980.9	$ 838.8	$ 364.0	$ 676.6	$ 10,038.8		$ 2,143.6	$ 1,563.6		$ 1,589.9	$ 1,402.0	$ 841.0	$ 1,646.2	$ (216.5)	$ (0.1)	$ (12.5)	$ (11.2)	$ 0.0	$ 0.9	$ (1.3)	$ 279.3	$ 0.9
Ending Balance, Shares at Mar. 31, 2020	515,411,847						10,482,000		515,400,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends Per Share, Declared	$ 0.70

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

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

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2020	May 06, 2020
Entity Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2020
Document Transition Report	false
Entity File Number	1-3525
Entity Registrant Name	AMERICAN ELECTRIC POWER CO INC.
Entity Incorporation, State or Country Code	NY
Entity Tax Identification Number	13-4922640
Entity Address, Address Line One	1 Riverside Plaza,
Entity Address, City or Town	Columbus,
Entity Address, State or Province	OH
Entity Address, Postal Zip Code	43215-2373
City Area Code	(614)
Local Phone Number	716-1000
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		495,583,133
Entity Central Index Key	0000004904
Amendment Flag	false
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
AEP Texas Inc. [Member]
Entity Information [Line Items]
Entity File Number	333-221643
Entity Registrant Name	AEP TEXAS INC.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	51-0007707
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		100
Entity Central Index Key	0001721781
AEP Transmission Co [Member]
Entity Information [Line Items]
Entity File Number	333-217143
Entity Registrant Name	AEP TRANSMISSION COMPANY, LLC
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	46-1125168
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Central Index Key	0001702494
Appalachian Power Co [Member]
Entity Information [Line Items]
Entity File Number	1-3457
Entity Registrant Name	APPALACHIAN POWER COMPANY
Entity Incorporation, State or Country Code	VA
Entity Tax Identification Number	54-0124790
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		13,499,500
Entity Central Index Key	0000006879
Indiana Michigan Power Co [Member]
Entity Information [Line Items]
Entity File Number	1-3570
Entity Registrant Name	INDIANA MICHIGAN POWER COMPANY
Entity Incorporation, State or Country Code	IN
Entity Tax Identification Number	35-0410455
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		1,400,000
Entity Central Index Key	0000050172
Ohio Power Co [Member]
Entity Information [Line Items]
Entity File Number	1-6543
Entity Registrant Name	OHIO POWER COMPANY
Entity Incorporation, State or Country Code	OH
Entity Tax Identification Number	31-4271000
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		27,952,473
Entity Central Index Key	0000073986
Public Service Co Of Oklahoma [Member]
Entity Information [Line Items]
Entity File Number	0-343
Entity Registrant Name	PUBLIC SERVICE COMPANY OF OKLAHOMA
Entity Incorporation, State or Country Code	OK
Entity Tax Identification Number	73-0410895
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		9,013,000
Entity Central Index Key	0000081027
Southwestern Electric Power Co [Member]
Entity Information [Line Items]
Entity File Number	1-3146
Entity Registrant Name	SOUTHWESTERN ELECTRIC POWER COMPANY
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	72-0323455
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		7,536,640
Entity Central Index Key	0000092487
New York Stock Exchange | Common Stock [Member]
Entity Information [Line Items]
Title of 12(b) Security	Common Stock, $6.50 par value
Trading Symbol	AEP
Security Exchange Name	NYSE
New York Stock Exchange | Preferred Stock [Member]
Entity Information [Line Items]
Title of 12(b) Security	6.125% Corporate Units
Trading Symbol	AEP PR B
Security Exchange Name	NYSE

XML

Significant Accounting Matters

3 Months Ended

Mar. 31, 2020

Significant Accounting Matters

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

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.

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Revenue from Contracts with Customers (Tables)

3 Months Ended

Mar. 31, 2020

Disaggregated Revenues from Contracts with Customers

	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.

	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.

	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.

	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.

Fixed Performance Obligations

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

Affiliated Accounts Receivable Contracts with Customers

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

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Derivatives and Hedging (Tables)

3 Months Ended

Mar. 31, 2020

Notional Volume of Derivative Instruments

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 of Derivative Instruments

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

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

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	)

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.

Amount of Gain (Loss) Recognized on 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.

Impact of Fair Value Hedges on the Condensed Balance Sheet

	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.

Gain (Loss) on Hedging Instruments

	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.

Impact of Cash Flow Hedges on the Condensed Balance Sheet

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		)

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		)

Liabilities Subject to Cross Default Provisions

	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

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Income Taxes

3 Months Ended

Mar. 31, 2020

Income Taxes

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	)%

	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.

XML

Comprehensive Income

3 Months Ended

Mar. 31, 2020

Comprehensive Income

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	)

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	)

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

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.

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Benefit Plans

3 Months Ended

Mar. 31, 2020

Benefit Plans

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	)

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	)

XML

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Operating Activities
Net Income (Loss)	$ 499.3	$ 574.1
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) 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, Net	0.0	14.7
Refund of Global Settlement	0.0	(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 (Used for) 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 from (Used for) Investing Activities	(1,766.0)	(1,582.8)
Financing Activities
Issuance of Common Stock, Net	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	0.0
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 Leases	(15.4)	(14.3)
Dividends Paid on Common Stock	(363.7)	(333.6)
Other Financing Activities	(32.7)	13.9
Net Cash Flows from (Used for) 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 and Cash Equivalents at Beginning of Period	246.8
Cash, Cash Equivalents and Restricted Cash at End of Period	1,670.8	363.1
Cash and Cash Equivalents at End of Period	1,554.6
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	0.0
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage	1.3	1.0
Stockholders' Equity, Other	30.2	55.6
AEP Texas Inc. [Member]
Operating Activities
Net Income (Loss)	47.6	34.4
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) 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 (Used for) 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 from (Used for) Investing Activities	(120.0)	(336.6)
Financing Activities
Capital Contributions from Parent	0.0	200.0
Change in Advances from Affiliates, Net	63.9	55.2
Retirement of Long-term Debt	(114.3)	(103.5)
Principal Payments for Finance Leases	(1.5)	(1.2)
Other Financing Activities	0.4	0.2
Net Cash Flows from (Used for) Financing Activities	(51.5)	150.7
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(57.6)	(59.1)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	157.8	159.8
Cash and Cash Equivalents at Beginning of Period	3.1
Cash, Cash Equivalents and Restricted Cash at End of Period	100.2	100.7
Cash and Cash Equivalents at End of Period	0.1
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	21.1	22.4
Net Cash Paid (Received) for Income Taxes	0.0	(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
AEP Transmission Co [Member]
Operating Activities
Net Income (Loss)	117.8	104.3
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) 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)
Fuel, 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 (Used for) 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 from (Used for) Investing Activities	(532.4)	(343.8)
Financing Activities
Capital Contributions from Parent	185.0	0.0
Change in Advances from Affiliates, Net	160.4	177.7
Other Financing Activities	0.0	(0.1)
Net Cash Flows from (Used for) Financing Activities	345.4	177.6
Net Increase (Decrease) in Cash and Cash Equivalents	0.0	0.0
Cash and Cash Equivalents at Beginning of Period	0.0	0.0
Cash and Cash Equivalents at End of Period	0.0	0.0
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
Appalachian Power Co [Member]
Operating Activities
Net Income (Loss)	115.3	133.7
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) 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 (Used for) 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 from (Used for) Investing Activities	(217.7)	(383.5)
Financing Activities
Issuance of Long-term Debt	0.0	393.3
Change in Advances from Affiliates, Net	118.6	(205.6)
Retirement of Long-term Debt	(12.2)	(12.0)
Principal Payments for Finance Leases	(1.8)	(1.6)
Dividends Paid on Common Stock	(50.0)	(50.0)
Other Financing Activities	0.2	0.3
Net Cash Flows from (Used for) Financing Activities	54.8	124.4
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(8.3)	(8.6)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	26.8	29.8
Cash and Cash Equivalents at Beginning of Period	3.3
Cash, Cash Equivalents and Restricted Cash at End of Period	18.5	21.2
Cash and Cash Equivalents at End of Period	2.8
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	31.9	14.5
Net Cash Paid (Received) for Income Taxes	0.0	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
Indiana Michigan Power Co [Member]
Operating Activities
Net Income (Loss)	92.3	98.9
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	93.9	86.2
Deferred Income Taxes	(16.3)	(13.9)
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 (Used for) 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 from (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	(23.7)	(26.5)
Principal Payments for Finance Leases	(1.5)	(1.2)
Dividends Paid on Common Stock	(21.3)	(20.0)
Other Financing Activities	0.1	0.2
Net Cash Flows from (Used for) Financing Activities	(57.1)	(13.9)
Net Increase (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	0.0	(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,	0.0	1.0
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage	1.3	7.9
Ohio Power Co [Member]
Operating Activities
Net Income (Loss)	75.1	128.0
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	70.5	63.3
Amortization Of Generation Deferrals	0.0	32.4
Deferred Income Taxes	12.9	10.1
Carrying Costs Income	(0.4)	(0.2)
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	0.0	(4.1)
Reversal of a Regulatory Provision	0.0	(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
Fuel, 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 (Used for) Operating Activities	3.5	117.2
Investing Activities
Construction Expenditures	(232.8)	(198.5)
Other Investing Activities	5.9	3.7
Net Cash Flows from (Used for) Investing Activities	(226.9)	(194.8)
Financing Activities
Issuance of Long-term Debt	347.1	0.0
Change in Advances from Affiliates, Net	(101.6)	113.5
Retirement of Long-term Debt	0.0	(23.4)
Principal Payments for Finance Leases	(1.2)	(0.7)
Dividends Paid on Common Stock	(21.9)	(25.0)
Other Financing Activities	0.4	0.5
Net Cash Flows from (Used for) Financing Activities	222.8	64.9
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(0.6)	(12.7)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	3.7	32.5
Cash and Cash Equivalents at Beginning of Period	3.7
Cash, Cash Equivalents and Restricted Cash at End of Period	3.1	19.8
Cash and Cash Equivalents at End of Period	3.1
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	16.7	17.0
Net Cash Paid (Received) for Income Taxes	0.0	(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
Public Service Co Of Oklahoma [Member]
Operating Activities
Net Income (Loss)	(10.3)	6.2
Adjustments to Reconcile Net Income 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	0.0
Other Investing Activities	1.6	0.4
Net Cash Flows from (Used for) Investing Activities	(56.1)	(70.3)
Financing Activities
Issuance of Long-term Debt	0.0	99.9
Change in Advances from Affiliates, Net	70.9	(50.3)
Retirement of Long-term Debt	(0.1)	(0.1)
Principal Payments for Finance Leases	(0.8)	(0.7)
Dividends Paid on Common Stock	0.0	(11.3)
Other Financing Activities	0.2	0.6
Net Cash Flows from (Used for) Financing Activities	70.2	38.1
Net Increase (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 (Received) for Income Taxes	0.0	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
Southwestern Electric Power Co [Member]
Operating Activities
Net Income (Loss)	16.1	29.0
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) 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 (Used for) Operating Activities	25.8	9.4
Investing Activities
Construction Expenditures	(122.4)	(86.6)
Change in Advances to Affiliates, Net	0.0	81.4
Other Investing Activities	0.8	(3.1)
Net Cash Flows from (Used for) Investing Activities	(121.6)	(8.3)
Financing Activities
Change in Short-term Debt with Original Maturities less than 90 Days, Net	12.2	0.0
Change in Advances from Affiliates, Net	88.2	74.0
Retirement of Long-term Debt	(1.6)	(55.1)
Principal Payments for Finance Leases	(2.7)	(2.7)
Dividends Paid on Common Stock	0.0	(18.7)
Dividends Paid on Common Stock	(0.7)	(1.1)
Other Financing Activities	0.2	0.1
Net Cash Flows from (Used for) Financing Activities	95.6	(3.5)
Net Increase (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 (Received) for Income Taxes	0.0	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
Retained Earnings [Member]
Supplementary Information
Stockholders' Equity, Other	0.0	62.1
Retained Earnings [Member] | AEP Texas Inc. [Member]
Operating Activities
Net Income (Loss)	47.6	34.4
Retained Earnings [Member] | AEP Transmission Co [Member]
Operating Activities
Net Income (Loss)	117.8	104.3
Retained Earnings [Member] | Appalachian Power Co [Member]
Operating Activities
Net Income (Loss)	115.3	133.7
Retained Earnings [Member] | Indiana Michigan Power Co [Member]
Operating Activities
Net Income (Loss)	92.3	98.9
Retained Earnings [Member] | Ohio Power Co [Member]
Operating Activities
Net Income (Loss)	75.1	128.0
Retained Earnings [Member] | Public Service Co Of Oklahoma [Member]
Operating Activities
Net Income (Loss)	$ (10.3)	$ 6.2

XML

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Cash Flow Hedges, Tax	$ (17.8)	$ (7.7)
Amortization of Pension and OPEB Deferred Costs, Tax	(0.5)	(0.4)
Appalachian Power Co [Member]
Cash Flow Hedges, Tax	(1.1)	(0.1)
Amortization of Pension and OPEB Deferred Costs, Tax	(0.3)	(0.2)
AEP Texas Inc. [Member]
Cash Flow Hedges, Tax	0.1	0.1
Indiana Michigan Power Co [Member]
Cash Flow Hedges, Tax	0.1	0.1
Amortization of Pension and OPEB Deferred Costs, Tax	0.0	0.0
Ohio Power Co [Member]
Cash Flow Hedges, Tax	0.0	(0.1)
Public Service Co Of Oklahoma [Member]
Cash Flow Hedges, Tax	(0.1)	(0.1)
Southwestern Electric Power Co [Member]
Cash Flow Hedges, Tax	0.1	0.1
Amortization of Pension and OPEB Deferred Costs, Tax	$ (0.1)	$ (0.1)

XML

Derivatives and Hedging (Details) gal in Millions, MWh in Millions, MMBTU in Millions		3 Months Ended			12 Months Ended
		Mar. 31, 2020 USD ($) MWh MMBTU gal		Mar. 31, 2019 USD ($)	Dec. 31, 2019 USD ($) MWh MMBTU gal
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		$ 0			$ 5,000,000
Cash Collateral Paid Netted Against Risk Management Liabilities		76,000,000			39,000,000
Fair Value of Derivative Instruments
Current Risk Management Assets		130,400,000			172,800,000
Long-term Risk Management Assets		323,700,000			266,600,000
Total Assets		454,100,000			439,400,000
Current Risk Management Liabilities		156,800,000			114,300,000
Long-term Risk Management Liabilities		291,900,000			261,800,000
Total Liabilities		448,700,000			376,100,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(32,900,000)		$ (24,900,000)
Carrying Amount of Hedged Asset (Liability)	[1]	(553,400,000)			(510,800,000)
Cumulative Fair Value Hedging Adjustment in the Carrying Amount of the Hedged Asset (Liability)	[1]	(57,000,000.0)			(14,500,000)
Gain (Loss) on Hedging Instruments
Gain (Loss) on Fair Value Hedging Instruments	[2]	42,500,000		11,100,000
Gain (Loss) on Fair Value Portion of Long Term Debt	[2]	(42,500,000)		(11,100,000)
Collateral Triggering Events [Abstract]
Fair Value Of Derivative Liabilities Subject To Cross Default Provisions		310,400,000			267,300,000
Amount of Cash Collateral Posted		1,600,000			3,700,000
Additional Settlement Liability if Cross Default Provision is Triggered		282,900,000			246,700,000
AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(1,400,000)		400,000
Appalachian Power Co [Member]
Cash Collateral Netting
Cash Collateral Paid Netted Against Risk Management Liabilities		5,000,000			1,000,000
Fair Value of Derivative Instruments
Current Risk Management Assets		18,100,000			39,400,000
Long-term Risk Management Assets		100,000			100,000
Total Assets		18,200,000
Current Risk Management Liabilities		15,000,000.0			1,900,000
Long-term Risk Management Liabilities		100,000			0
Total Liabilities		15,100,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(16,000,000.0)		(34,000,000.0)
Collateral Triggering Events [Abstract]
Fair Value Of Derivative Liabilities Subject To Cross Default Provisions		2,200,000			2,300,000
Amount of Cash Collateral Posted		0			0
Additional Settlement Liability if Cross Default Provision is Triggered		200,000			400,000
Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		6,700,000			9,800,000
Long-term Risk Management Assets		100,000			100,000
Current Risk Management Liabilities		1,700,000			500,000
Long-term Risk Management Liabilities		100,000			0
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		2,600,000		7,200,000
Collateral Triggering Events [Abstract]
Fair Value Of Derivative Liabilities Subject To Cross Default Provisions		1,300,000			1,300,000
Amount of Cash Collateral Posted		0			0
Additional Settlement Liability if Cross Default Provision is Triggered		100,000			200,000
Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Liabilities		8,700,000			7,300,000
Long-term Risk Management Liabilities		112,200,000			96,300,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(15,000,000.0)		(9,100,000)
Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		6,400,000			15,800,000
Current Risk Management Liabilities		100,000			0
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		7,600,000		6,700,000
Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		2,600,000			6,400,000
Current Risk Management Liabilities		2,200,000			1,900,000
Long-term Risk Management Liabilities		2,900,000			3,100,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		1,300,000		4,600,000
Collateral Triggering Events [Abstract]
Fair Value Of Derivative Liabilities Subject To Cross Default Provisions		5,500,000			5,100,000
Amount of Cash Collateral Posted		0			0
Additional Settlement Liability if Cross Default Provision is Triggered		5,500,000			5,100,000
Risk Management Contracts [Member]
Fair Value of Derivative Instruments
Total Assets	[3]	379,100,000	[4]		408,800,000	[5]
Total Liabilities	[3]	266,600,000	[4]		239,000,000.0	[5]
Risk Management Contracts [Member] | AEP Texas Inc. [Member]
Fair Value of Derivative Instruments
Total Liabilities	[3]	0
Risk Management Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[3],[6]	17,900,000			39,500,000
Total Liabilities	[3],[6]	9,800,000			1,900,000
Risk Management Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[3],[6]	6,800,000			9,900,000
Total Liabilities	[3],[6]	1,800,000			500,000
Risk Management Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Total Liabilities	[3],[6]	120,900,000			103,600,000
Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Total Assets	[3],[6]	6,400,000			15,800,000
Total Liabilities	[3],[6]	100,000			0
Risk Management Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[3],[6]	2,600,000			6,400,000
Total Liabilities	[3],[6]	5,100,000			5,000,000.0
Commodity [Member]
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		(128,500,000)			(103,500,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		$ (73,200,000)			(51,700,000)
Derivatives and Hedging (Textuals) [Abstract]
Maximum Term for Exposure to Variability of Future Cash Flows		132 months
Cross Default Provisions Maximum Third Party Obligation Amount		$ 50,000,000			50,000,000
Commodity [Member] | Risk Management Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	412,700,000			513,900,000
Long-term Risk Management Assets	[7]	331,600,000			290,800,000
Total Assets	[7]	744,300,000			804,700,000
Current Risk Management Liabilities	[7]	401,700,000			424,500,000
Long-term Risk Management Liabilities	[7]	305,900,000			244,500,000
Total Liabilities	[7]	707,600,000			669,000,000.0
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	36,700,000			135,700,000
Commodity [Member] | Risk Management Contracts [Member] | AEP Texas Inc. [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	0			0
Long-term Risk Management Assets	[7]	0			0
Total Assets	[7]	0			0
Current Risk Management Liabilities	[7]	1,200,000			0
Long-term Risk Management Liabilities	[7]	0			0
Total Liabilities	[7]	1,200,000			0
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(1,200,000)			0
Commodity [Member] | Risk Management Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	71,100,000			124,400,000
Long-term Risk Management Assets	[7]	3,500,000			900,000
Total Assets	[7]	74,600,000			125,300,000
Current Risk Management Liabilities	[7]	68,300,000			86,200,000
Long-term Risk Management Liabilities	[7]	3,500,000			700,000
Total Liabilities	[7]	71,800,000			86,900,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	2,800,000			38,400,000
Commodity [Member] | Risk Management Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	42,300,000			66,900,000
Long-term Risk Management Assets	[7]	2,100,000			500,000
Total Assets	[7]	44,400,000			67,400,000
Current Risk Management Liabilities	[7]	38,300,000			55,200,000
Long-term Risk Management Liabilities	[7]	2,100,000			400,000
Total Liabilities	[7]	40,400,000			55,600,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	4,000,000.0			11,800,000
Commodity [Member] | Risk Management Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	0			0
Long-term Risk Management Assets	[7]	0			0
Total Assets	[7]	0			0
Current Risk Management Liabilities	[7]	9,600,000			7,300,000
Long-term Risk Management Liabilities	[7]	112,200,000			96,300,000
Total Liabilities	[7]	121,800,000			103,600,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(121,800,000)			(103,600,000)
Commodity [Member] | Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	6,700,000			16,300,000
Long-term Risk Management Assets	[7]	0			0
Total Assets	[7]	6,700,000			16,300,000
Current Risk Management Liabilities	[7]	900,000			500,000
Long-term Risk Management Liabilities	[7]	0			0
Total Liabilities	[7]	900,000			500,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	5,800,000			15,800,000
Commodity [Member] | Risk Management Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	2,700,000			6,500,000
Long-term Risk Management Assets	[7]	0			0
Total Assets	[7]	2,700,000			6,500,000
Current Risk Management Liabilities	[7]	2,900,000			2,000,000.0
Long-term Risk Management Liabilities	[7]	2,900,000			3,100,000
Total Liabilities	[7]	5,800,000			5,100,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(3,100,000)			1,400,000
Commodity [Member] | Hedging Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	13,500,000			11,500,000
Long-term Risk Management Assets	[7]	13,500,000			11,000,000.0
Total Assets	[7]	27,000,000.0			22,500,000
Current Risk Management Liabilities	[7]	103,200,000			72,300,000
Long-term Risk Management Liabilities	[7]	82,900,000			75,700,000
Total Liabilities	[7]	186,100,000			148,000,000.0
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(159,100,000)			(125,500,000)
Interest Rate [Member]
Commodity:
Derivative, Notional Amount		650,000,000.0			625,000,000.0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		(53,500,000)			(11,500,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		$ (4,300,000)			(2,100,000)
Derivatives and Hedging (Textuals) [Abstract]
Maximum Term for Exposure to Variability of Future Cash Flows		129 months
Interest Rate [Member] | AEP Texas Inc. [Member]
Commodity:
Derivative, Notional Amount		$ 0			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		(3,100,000)			(3,400,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		(1,100,000)			(1,100,000)
Interest Rate [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Notional Amount		150,000,000.0			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		(3,300,000)			900,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		1,100,000			900,000
Interest Rate [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		(9,500,000)			(9,900,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		(1,600,000)			(1,600,000)
Interest Rate [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0
Interest Rate [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Notional Amount		0			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		900,000			1,100,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		900,000			1,000,000.0
Interest Rate [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		(1,400,000)			(1,800,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		(1,500,000)			(1,500,000)
Interest Rate [Member] | Hedging Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	4,600,000			6,500,000
Long-term Risk Management Assets	[7]	52,700,000			12,600,000
Total Assets	[7]	57,300,000			19,100,000
Current Risk Management Liabilities	[7]	5,300,000			0
Long-term Risk Management Liabilities	[7]	0			0
Total Liabilities	[7]	5,300,000			0
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	52,000,000.0			19,100,000
Interest Rate [Member] | Hedging Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	300,000
Long-term Risk Management Assets	[7]	0
Total Assets	[7]	300,000
Current Risk Management Liabilities	[7]	5,300,000
Long-term Risk Management Liabilities	[7]	0
Total Liabilities	[7]	5,300,000
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(5,000,000.0)
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		430,800,000			531,900,000
Long-term Risk Management Assets		397,800,000			314,400,000
Total Assets		828,600,000			846,300,000
Current Risk Management Liabilities		510,200,000			496,800,000
Long-term Risk Management Liabilities		388,800,000			320,200,000
Total Liabilities		899,000,000.0			817,000,000.0
Total MTM Derivative Contract Net Assets (Liabilities)		(70,400,000)			29,300,000
Gross Amounts Offset in the Statement of Financial Position [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	(300,400,000)			(359,100,000)
Long-term Risk Management Assets	[8]	(74,100,000)			(47,800,000)
Total Assets	[8]	(374,500,000)			(406,900,000)
Current Risk Management Liabilities	[8]	(353,400,000)			(382,500,000)
Long-term Risk Management Liabilities	[8]	(96,900,000)			(58,400,000)
Total Liabilities	[8]	(450,300,000)			(440,900,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	75,800,000			34,000,000.0
Gross Amounts Offset in the Statement of Financial Position [Member] | AEP Texas Inc. [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	0			0
Long-term Risk Management Assets	[8]	0			0
Total Assets	[8]	0			0
Current Risk Management Liabilities	[8]	(1,200,000)			0
Long-term Risk Management Liabilities	[8]	0			0
Total Liabilities	[8]	(1,200,000)			0
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	1,200,000			0
Gross Amounts Offset in the Statement of Financial Position [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	(53,300,000)			(85,000,000.0)
Long-term Risk Management Assets	[8]	(3,400,000)			(800,000)
Total Assets	[8]	(56,700,000)			(85,800,000)
Current Risk Management Liabilities	[8]	(58,600,000)			(84,300,000)
Long-term Risk Management Liabilities	[8]	(3,400,000)			(700,000)
Total Liabilities	[8]	(62,000,000.0)			(85,000,000.0)
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	5,300,000			(800,000)
Gross Amounts Offset in the Statement of Financial Position [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	(35,600,000)			(57,100,000)
Long-term Risk Management Assets	[8]	(2,000,000.0)			(400,000)
Total Assets	[8]	(37,600,000)			(57,500,000)
Current Risk Management Liabilities	[8]	(36,600,000)			(54,700,000)
Long-term Risk Management Liabilities	[8]	(2,000,000.0)			(400,000)
Total Liabilities	[8]	(38,600,000)			(55,100,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	1,000,000.0			(2,400,000)
Gross Amounts Offset in the Statement of Financial Position [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	0			0
Long-term Risk Management Assets	[8]	0			0
Total Assets	[8]	0			0
Current Risk Management Liabilities	[8]	(900,000)			0
Long-term Risk Management Liabilities	[8]	0			0
Total Liabilities	[8]	(900,000)			0
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	900,000			0
Gross Amounts Offset in the Statement of Financial Position [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	(300,000)			(500,000)
Long-term Risk Management Assets	[8]	0			0
Total Assets	[8]	(300,000)			(500,000)
Current Risk Management Liabilities	[8]	(800,000)			(500,000)
Long-term Risk Management Liabilities	[8]	0			0
Total Liabilities	[8]	(800,000)			(500,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	500,000			0
Gross Amounts Offset in the Statement of Financial Position [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	(100,000)			(100,000)
Long-term Risk Management Assets	[8]	0			0
Total Assets	[8]	(100,000)			(100,000)
Current Risk Management Liabilities	[8]	(700,000)			(100,000)
Long-term Risk Management Liabilities	[8]	0			0
Total Liabilities	[8]	(700,000)			(100,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	600,000			0
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	130,400,000			172,800,000
Long-term Risk Management Assets	[9]	323,700,000			266,600,000
Total Assets	[9]	454,100,000			439,400,000
Current Risk Management Liabilities	[9]	156,800,000			114,300,000
Long-term Risk Management Liabilities	[9]	291,900,000			261,800,000
Total Liabilities	[9]	448,700,000			376,100,000
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	5,400,000			63,300,000
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | AEP Texas Inc. [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	0			0
Long-term Risk Management Assets	[9]	0			0
Total Assets	[9]	0			0
Current Risk Management Liabilities	[9]	0			0
Long-term Risk Management Liabilities	[9]	0			0
Total Liabilities	[9]	0			0
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	0			0
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	18,100,000			39,400,000
Long-term Risk Management Assets	[9]	100,000			100,000
Total Assets	[9]	18,200,000			39,500,000
Current Risk Management Liabilities	[9]	15,000,000.0			1,900,000
Long-term Risk Management Liabilities	[9]	100,000			0
Total Liabilities	[9]	15,100,000			1,900,000
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	3,100,000			37,600,000
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	6,700,000			9,800,000
Long-term Risk Management Assets	[9]	100,000			100,000
Total Assets	[9]	6,800,000			9,900,000
Current Risk Management Liabilities	[9]	1,700,000			500,000
Long-term Risk Management Liabilities	[9]	100,000			0
Total Liabilities	[9]	1,800,000			500,000
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	5,000,000.0			9,400,000
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	0			0
Long-term Risk Management Assets	[9]	0			0
Total Assets	[9]	0			0
Current Risk Management Liabilities	[9]	8,700,000			7,300,000
Long-term Risk Management Liabilities	[9]	112,200,000			96,300,000
Total Liabilities	[9]	120,900,000			103,600,000
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	(120,900,000)			(103,600,000)
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	6,400,000			15,800,000
Long-term Risk Management Assets	[9]	0			0
Total Assets	[9]	6,400,000			15,800,000
Current Risk Management Liabilities	[9]	100,000			0
Long-term Risk Management Liabilities	[9]	0			0
Total Liabilities	[9]	100,000			0
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	6,300,000			15,800,000
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	2,600,000			6,400,000
Long-term Risk Management Assets	[9]	0			0
Total Assets	[9]	2,600,000			6,400,000
Current Risk Management Liabilities	[9]	2,200,000			1,900,000
Long-term Risk Management Liabilities	[9]	2,900,000			3,100,000
Total Liabilities	[9]	5,100,000			5,000,000.0
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	$ (2,500,000)			$ 1,400,000
Power [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		305.4			365.9
Power [Member] | AEP Texas Inc. [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		0.0			0.0
Power [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		38.7			61.0
Power [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		18.5			26.8
Power [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		3.2			7.1
Power [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		5.9			14.9
Power [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		1.7			4.4
Natural Gas [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		42.3			40.7
Natural Gas [Member] | AEP Texas Inc. [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		0.0			0.0
Natural Gas [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		0.0			0.0
Natural Gas [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		0.0			0.0
Natural Gas [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		0.0			0.0
Natural Gas [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		0.0			0.0
Natural Gas [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		10.7			11.6
Heating Oil and Gasoline [Member]
Commodity:
Derivative, Volume Notional Amount | gal		5.0			6.9
Heating Oil and Gasoline [Member] | AEP Texas Inc. [Member]
Commodity:
Derivative, Volume Notional Amount | gal		1.3			1.8
Heating Oil and Gasoline [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Volume Notional Amount | gal		0.8			1.1
Heating Oil and Gasoline [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Volume Notional Amount | gal		0.5			0.6
Heating Oil and Gasoline [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Volume Notional Amount | gal		1.0			1.4
Heating Oil and Gasoline [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Volume Notional Amount | gal		0.5			0.7
Heating Oil and Gasoline [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Volume Notional Amount | gal		0.7			0.9
Interest Rate Contract [Member]
Commodity:
Derivative, Notional Amount		$ 137,100,000			$ 140,100,000
Interest Rate Contract [Member] | AEP Texas Inc. [Member]
Commodity:
Derivative, Notional Amount		0			0
Interest Rate Contract [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0
Interest Rate Contract [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0
Interest Rate Contract [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0
Interest Rate Contract [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Notional Amount		0			0
Interest Rate Contract [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Notional Amount		0			$ 0
Vertically Integrated Utilities Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		400,000		300,000
Vertically Integrated Utilities Revenues [Member] | AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Vertically Integrated Utilities Revenues [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Vertically Integrated Utilities Revenues [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Vertically Integrated Utilities Revenues [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Vertically Integrated Utilities Revenues [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Vertically Integrated Utilities Revenues [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Generation and Marketing Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(10,300,000)		2,700,000
Generation and Marketing Revenues [Member] | AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Generation and Marketing Revenues [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Generation and Marketing Revenues [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Generation and Marketing Revenues [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Generation and Marketing Revenues [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Generation and Marketing Revenues [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Electric Generation, Transmission and Distribution Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Electric Generation, Transmission and Distribution Revenues [Member] | AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Electric Generation, Transmission and Distribution Revenues [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		200,000		(100,000)
Electric Generation, Transmission and Distribution Revenues [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		100,000		300,000
Electric Generation, Transmission and Distribution Revenues [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Electric Generation, Transmission and Distribution Revenues [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Electric Generation, Transmission and Distribution Revenues [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		100,000
Purchased Electricity for Resale [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		100,000		1,400,000
Purchased Electricity for Resale [Member] | AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Purchased Electricity for Resale [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		100,000		0
Purchased Electricity for Resale [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Purchased Electricity for Resale [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Purchased Electricity for Resale [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Purchased Electricity for Resale [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Other Operation Expense [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(200,000)		(400,000)
Other Operation Expense [Member] | AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(100,000)		(100,000)
Other Operation Expense [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		(100,000)
Other Operation Expense [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Other Operation Expense [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(100,000)		(100,000)
Other Operation Expense [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Other Operation Expense [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Maintenance Expense [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(200,000)		(500,000)
Maintenance Expense [Member] | AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(100,000)		(100,000)
Maintenance Expense [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(100,000)		0
Maintenance Expense [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Maintenance Expense [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		(100,000)
Maintenance Expense [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Maintenance Expense [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		(100,000)
Regulatory Assets [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	(33,900,000)		(6,400,000)
Regulatory Assets [Member] | AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	(1,200,000)		600,000
Regulatory Assets [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	(8,900,000)		(2,100,000)
Regulatory Assets [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	(700,000)		300,000
Regulatory Assets [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	(18,400,000)		(8,900,000)
Regulatory Assets [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	(500,000)		500,000
Regulatory Assets [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	(2,000,000.0)		(100,000)
Regulatory Liabilities [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	11,200,000		(22,000,000.0)
Regulatory Liabilities [Member] | AEP Texas Inc. [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	0		0
Regulatory Liabilities [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	(7,300,000)		(31,700,000)
Regulatory Liabilities [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	3,200,000		6,600,000
Regulatory Liabilities [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	3,500,000		0
Regulatory Liabilities [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	8,100,000		6,200,000
Regulatory Liabilities [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[10]	$ 3,300,000		$ 4,700,000

[1] Amounts included on the balance sheets within Long-term Debt Due within One Year and Long-term Debt, respectively.

[2] Gain (Loss) is included in Interest Expense on the statements of income.

[3] 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.’’

[4] 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.

[5] 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.

[6] Substantially comprised of power contracts for the Registrant Subsidiaries.

[7] 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.”

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

[9] All derivative contracts subject to a master netting arrangement or similar agreement are offset in the statement of financial position.

[10] Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

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Commitments, Guarantees and Contingencies (Details) - USD ($) $ in Millions		1 Months Ended
		Jul. 25, 2019	Mar. 31, 2020
Maximum Potential Loss [Abstract]
Max Potential Loss on Master Lease Agreements			$ 48.5
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Payments for Environmental Liabilities		$ 7.5
AEP Texas Inc. [Member]
Maximum Potential Loss [Abstract]
Max Potential Loss on Master Lease Agreements			11.6
Appalachian Power Co [Member]
Maximum Potential Loss [Abstract]
Max Potential Loss on Master Lease Agreements			6.6
Indiana Michigan Power Co [Member]
Maximum Potential Loss [Abstract]
Max Potential Loss on Master Lease Agreements			4.3
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Payments for Environmental Liabilities		$ 7.5
Ohio Power Co [Member]
Maximum Potential Loss [Abstract]
Max Potential Loss on Master Lease Agreements			7.6
Public Service Co Of Oklahoma [Member]
Maximum Potential Loss [Abstract]
Max Potential Loss on Master Lease Agreements			4.4
Southwestern Electric Power Co [Member]
Maximum Potential Loss [Abstract]
Max Potential Loss on Master Lease Agreements			4.9
Rockport Lease [Member]
Present Value of Future Minimum Lease Payments, Sale Leaseback Transactions, Fiscal Year Maturity [Abstract]
Minimum Lease Payments, Sale Leaseback Transactions, Next Twelve Months	[1]		147.8
Minimum Lease Payments, Sale Leaseback Transactions, within Two Years	[1]		147.8
Minimum Lease Payments, Sale Leaseback Transactions, within Three Years	[1]		147.5
Minimum Lease Payments, Sale Leaseback Transactions	[1]		443.1
Rockport Lease [Member] | Indiana Michigan Power Co [Member]
Present Value of Future Minimum Lease Payments, Sale Leaseback Transactions, Fiscal Year Maturity [Abstract]
Minimum Lease Payments, Sale Leaseback Transactions, Next Twelve Months			73.9
Minimum Lease Payments, Sale Leaseback Transactions, within Two Years			73.9
Minimum Lease Payments, Sale Leaseback Transactions, within Three Years			73.7
Minimum Lease Payments, Sale Leaseback Transactions			221.5
Boat and Barge Leases [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Maximum Potential Lease Payments, AEPRO Barge and Boat Leases			53.0
Guarantor Obligations, Current Carrying Value			4.0
Guarantee Obligations Current Carrying Value Other Liabilities Current			1.0
Guarantee Obligations Current Carrying Value Other Liabilities Noncurrent			3.0
Letters of Credit [Member]
Maximum Future Payments for Letters of Credit [Abstract]
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility			241.2
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Letters of Credit Limit			1,200.0
Uncommitted Facility			405.0
Letters of Credit [Member] | AEP Texas Inc. [Member]
Maximum Future Payments for Letters of Credit [Abstract]
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility			2.2
Letters of Credit [Member] | Ohio Power Co [Member]
Maximum Future Payments for Letters of Credit [Abstract]
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility	[2]		1.0
June 2022 [Member] | Letters of Credit [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Revolving Credit Facilities			$ 4,000.0

[1] AEP’s future minimum lease payments include equal shares from AEGCo and I&M.

[2] In April 2020, the maturity date was extended from April 2020 to April 2021.

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Derivatives and Hedging (Policies)

3 Months Ended

Mar. 31, 2020

Derivatives and Hedging

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.

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.

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.

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.

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.

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.

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.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.

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

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

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

Accounting for Fair Value Hedging Strategies (Applies to AEP)

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

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Comprehensive Income (Tables)

3 Months Ended

Mar. 31, 2020

Changes in Accumulated Other Comprehensive Income (Loss) by Component

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	)

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	)

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

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.