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

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For The Quarterly Period Ended June 30, 2020

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

For The Transition Period from ____ to ____


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

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

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

Registrant

Title of each class

Trading Symbol

Name of Each Exchange on Which Registered

American Electric Power Company Inc.

Common Stock, $6.50 par value

AEP

New York Stock Exchange

American Electric Power Company Inc.

6.125% Corporate Units

AEP PR B

New York Stock Exchange

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

Yes

☐

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

☐

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

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

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

☐

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
			August 6, 2020

American Electric Power Company, Inc.			496,155,436
			($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

June 30, 2020

Page

Number

Glossary of Terms

Forward-Looking Information

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

Condensed Consolidated Financial Statements

AEP Texas Inc. and Subsidiaries:

Management’s Narrative Discussion and Analysis of Results of Operations

Condensed Consolidated Financial Statements

AEP Transmission Company, LLC and Subsidiaries:

Management’s Narrative Discussion and Analysis of Results of Operations

Condensed Consolidated Financial Statements

Appalachian Power Company and Subsidiaries:

Management’s Narrative Discussion and Analysis of Results of Operations

Condensed Consolidated Financial Statements

Indiana Michigan Power Company and Subsidiaries:

Management’s Narrative Discussion and Analysis of Results of Operations

Condensed Consolidated Financial Statements

Ohio Power Company and Subsidiaries:

Management’s Narrative Discussion and Analysis of Results of Operations

100

Condensed Consolidated Financial Statements

105

Public Service Company of Oklahoma:

Management’s Narrative Discussion and Analysis of Results of Operations

112

Condensed Financial Statements

115

Southwestern Electric Power Company Consolidated:

Management’s Narrative Discussion and Analysis of Results of Operations

122

Condensed Consolidated Financial Statements

127

Index of Condensed Notes to Condensed Financial Statements of Registrants

133

Controls and Procedures

220

Part II. OTHER INFORMATION

Item 1.

Legal Proceedings

221

Item 1A.

Risk Factors

221

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

222

Item 3.

Defaults Upon Senior Securities

222

Item 4.

Mine Safety Disclosures

223

Item 5.

Other Information

223

Item 6.

Exhibits

223

SIGNATURE

225

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.
AEPEP						AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, hedging activities, asset management and commercial and industrial sales in deregulated markets.
AEPRO						AEP River Operations, LLC, a commercial barge operation sold in November 2015.
AEPSC						American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AEPTCo						AEP Transmission Company, LLC, a wholly-owned subsidiary of AEP Transmission Holdco, is an intermediate holding company that owns the State Transcos.
AEPTCo Parent						AEP Transmission Company, LLC, the holding company of the State Transcos within the AEPTCo consolidation.
AFUDC						Allowance for Equity Funds Used During Construction.
AGR						AEP Generation Resources Inc., a competitive AEP subsidiary in the Generation & Marketing segment.
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.
CLECO						Central Louisiana Electric Company, a nonaffiliated utility company.
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.


Term						Meaning

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. DHLC is a non-consolidated VIE of SWEPCo.
DIR						Distribution Investment Rider.
EIS						Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated VIE of AEP.
ENEC						Expanded Net Energy Cost.
Energy Supply						AEP Energy Supply LLC, a nonregulated holding company for AEP’s competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP.
Equity Units						AEP’s Equity Units issued in March 2019.
ERCOT						Electric Reliability Council of Texas regional transmission organization.

ETT						Electric Transmission Texas, LLC, an equity interest joint venture between AEP Transmission Holdco and Berkshire Hathaway Energy Company formed to own and operate electric transmission facilities in ERCOT.
Excess ADIT						Excess accumulated deferred income taxes.
FASB						Financial Accounting Standards Board.
Federal EPA						United States Environmental Protection Agency.
FERC						Federal Energy Regulatory Commission.
FGD						Flue Gas Desulfurization or scrubbers.
FIP						Federal Implementation Plan.
FTR						Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP						Accounting Principles Generally Accepted in the United States of America.
Global Settlement						In February 2017, the PUCO approved a settlement agreement filed by OPCo in December 2016 which resolved all remaining open issues on remand from the Supreme Court of Ohio in OPCo’s 2009 - 2011 and June 2012 - May 2015 ESP filings. It also resolved all open issues in OPCo’s 2009, 2014 and 2015 SEET filings and 2009, 2012 and 2013 Fuel Adjustment Clause Audits.
I&M						Indiana Michigan Power Company, an AEP electric utility subsidiary.
IRS						Internal Revenue Service.
IURC						Indiana Utility Regulatory Commission.
KGPCo						Kingsport Power Company, an AEP electric utility subsidiary.
KPCo						Kentucky Power Company, an AEP electric utility subsidiary.

KPSC						Kentucky Public Service Commission.
KWh						Kilowatt-hour.
LPSC						Louisiana Public Service Commission.
MATS						Mercury and Air Toxic Standards.
MISO						Midcontinent Independent System Operator.
MMBtu						Million British Thermal Units.
MPSC						Michigan Public Service Commission.
MTM						Mark-to-Market.
MW						Megawatt.
MWh						Megawatt-hour.
NAAQS						National Ambient Air Quality Standards.
Nonutility Money Pool						Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
North Central Wind Energy Facilities						A joint PSO and SWEPCo project, which includes three Oklahoma wind facilities totaling approximately 1,485 MWs of wind generation.
NO₂						Nitrogen dioxide.
NO_x						Nitrogen oxide.


Term						Meaning

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

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.

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.

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.


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.
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.
WPCo						Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC						Public Service Commission of West Virginia.

FORWARD-LOOKING INFORMATION

This report made by the Registrants contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Many forward-looking statements appear in “Part 1 – Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this quarterly report, but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook. These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected. Forward-looking statements in this document are presented as of the date of this document. Except to the extent required by applicable law, management undertakes no obligation to update or revise any forward-looking statement. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:


•			Changes in economic conditions, electric market demand and demographic patterns in AEP service territories.
•			The impact of pandemics, including COVID-19, and any associated disruption of AEP’s business operations due to impacts on economic or market conditions, electricity usage, employees, customers, service providers, vendors and suppliers.
•			Inflationary or deflationary interest rate trends.
•			Volatility in the financial markets, particularly developments affecting the availability or cost of capital to finance new capital projects and refinance existing debt.
•			The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.
•			Decreased demand for electricity.
•			Weather conditions, including storms and drought conditions, and the ability to recover significant storm restoration costs.
•			The cost of fuel and its transportation, the creditworthiness and performance of fuel suppliers and transporters and the cost of storing and disposing of used fuel, including coal ash and SNF.
•			The availability of fuel and necessary generation capacity and the performance of generation plants.
•			The ability to recover fuel and other energy costs through regulated or competitive electric rates.
•			The ability to build or acquire renewable generation, transmission lines and facilities (including the ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs.
•			New legislation, litigation and government regulation, including oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or PM and other substances that could impact the continued operation, cost recovery and/or profitability of generation plants and related assets.
•			Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including coal ash and nuclear fuel.
•			Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance.
•			Resolution of litigation.
•			The ability to constrain operation and maintenance costs.
•			Prices and demand for power generated and sold at wholesale.
•			Changes in technology, particularly with respect to energy storage and new, developing, alternative or distributed sources of generation.
•			The ability to recover through rates any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives.
•			Volatility and changes in markets for coal and other energy-related commodities, particularly changes in the price of natural gas.
•			Changes in utility regulation and the allocation of costs within RTOs including ERCOT, PJM and SPP.
•			Changes in the creditworthiness of the counterparties with contractual arrangements, including participants in the energy trading market.
•			Actions of rating agencies, including changes in the ratings of debt.
•			The impact of volatility in the capital markets on the value of the investments held by the pension, OPEB, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements.


•			Accounting standards periodically issued by accounting standard-setting bodies.
•			Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, naturally occurring and human-caused fires, cyber security threats and other catastrophic events.
•			The ability to attract and retain the requisite work force and key personnel.

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

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

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

COVID-19

In March 2020, COVID-19 was declared a pandemic by the World Health Organization and the Centers for Disease Control and Prevention. Its rapid spread around the world and throughout the United States prompted many countries, including the United States, to institute restrictions on travel, public gatherings and certain business operations. These restrictions significantly disrupted economic activity in AEP’s service territory and could reduce future demand for energy, particularly from commercial and industrial customers. Although AEP cannot predict the severity or duration of the impact of the COVID-19 pandemic, AEP currently anticipates a 3.4% reduction in weather-normalized retail sales volume in 2020 as compared to the prior year. During the first half of 2020, AEP experienced a reduction in weather-normalized retail sales volume of 3.1% as compared to the first half of 2019 primarily driven by a 6.6% decrease in the industrial customer class and a 5.0% decrease in the commercial customer class offset by an increase in demand of 1.9% from the residential customer class. The reduction in weather-normalized retail sales volume of 3.1% did not result in a significant decrease in the corresponding retail margins for the six months ended 2020 as the increase in higher margin residential sales volumes partially offset the decreases in the industrial and commercial sales volumes. Furthermore, the rate design for certain industrial customers includes demand provisions designed to cover the fixed portion of utility costs minimizing the impact of the fluctuations in usage on revenues. AEP’s load forecast is highly dependent on many factors including, but not limited to, the extent and duration of the stay at home restrictions, the speed and strength of economic recovery and the extent and duration of the second wave of COVID-19 infection. If the severity of the economic disruption increases, AEP’s future results of operations, financial condition, and cash flows could be further adversely impacted. See Customer Demand for additional information.

During the first quarter of 2020, AEP’s electric operating companies informed both retail customers and state regulators that disconnections for non-payment were temporarily suspended. Disconnections were reinstated in July 2020 in Michigan and Oklahoma. Disconnections are anticipated to be reinstated starting in August or September of 2020 in Tennessee, Texas (applies to SWEPCo jurisdiction only), Louisiana, Virginia, West Virginia, Ohio, and Indiana. Current continuing adverse economic conditions may result in the inability of customers to pay for electric service, which could affect revenue recognition and the collectability of accounts receivable. During the second quarter of 2020, the Registrants reviewed current collections experience with historical trends, specifically reviewing metrics such as customer receivables and cash collections, days sales outstanding, daily customer deposits, and aging summaries. In addition, the Registrants reviewed historical loss information generally comprised of a rolling 12-month average, in conjunction with a qualitative assessment of elements that impact the collectability of receivables, such as changes in economic factors, regulatory matters, industry trends, customer credit factors, payment options and programs available to customers. Based on this review, AEP’s accounts receivable aging was negatively impacted primarily due to the suspension of the customer disconnects. AEP currently does not expect the deterioration in aging to have a material adverse impact on the Registrants’ allowance for uncollectible accounts based on considerations of the recent impacts of COVID-19 and past trends during times of economic instability. Management will continue to monitor developments affecting suspensions of disconnections and its impact on customer collections. Further deterioration in AEP’s ability to collect from its customers could significantly impact AEP’s future results of operations, financial conditions, and cash flows.

In May 2020, AEP Credit amended its receivables securitization agreement to increase the eligibility criteria related to aged receivable requirements for the participating affiliated utility subsidiaries in response to the COVID-19 pandemic. As of June 30, 2020, the affiliated utility subsidiaries are in compliance with all requirements under the agreement. To the extent that an affiliated utility subsidiary is deemed ineligible under the agreement, receivables would no longer be purchased by the bank conduits and the Registrants would need to rely on additional sources of funding for operation and working capital, which may adversely impact liquidity.

The Registrants have worked with their state commissions to achieve deferral authority for increased costs incurred due to COVID-19. The majority of these jurisdictions have provided deferral authority for incremental COVID-19 costs including uncollectible expense. Initial COVID-19 orders for deferrals have yet to be issued by Kentucky and Tennessee. If any costs related to COVID-19 are not recoverable, it could reduce future net income and cash flows and impact financial condition.

The effects of the continued COVID-19 pandemic and related government responses could also include extended disruptions to supply chains, reduced labor availability, reduced dispatch for certain generation assets 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 June 30, 2020, there were no material adverse impacts to the Registrants’ operations and supplier contracts due to COVID-19. AEP will continue to monitor developments affecting facility operations and will take additional actions necessary in order to mitigate adverse impacts to the Registrants’ future results of operations, financial condition, and cash flows.

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 June 30, 2020.

Market volatility and reduction in collections coupled with longer collection periods due to the expansion of customer payment arrangements could reduce cash from operations and cause an adverse impact to liquidity. During the first six months of 2020, AEP increased its liquidity position to mitigate the market and the collections risk 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 $1 billion 364–day term loan to reduce reliance on commercial paper and help mitigate potential future liquidity risks. In addition, for the first six months of 2020, AEP issued approximately $2.4 billion in long-term debt. As of June 30, 2020, AEP’s available liquidity is $2.9 billion. Management believes the Registrants have adequate liquidity under existing credit facilities. In the first quarter of 2020, AEP shifted capital expenditures of $500 million out of 2020 into future periods to further mitigate adverse liquidity impacts. In the second quarter of 2020, AEP reinstated $100 million of capital expenditures back into 2020. To the extent that future access to the capital markets or the cost of funding is adversely affected by COVID-19, future results of operations, financial condition, and cash flows may be adversely impacted.

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. In May 2020, the House passed the “Health and Economic Recovery Omnibus Emergency Solutions Act” (the HEROES Act) pending decision by the Senate. If enacted, the HEROES Act would disallow NOL carrybacks to any tax year beginning before January 1, 2018. As of June 30, 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 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 June 30, 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 second quarter of 2020 decreased by 5.9% from the second quarter of 2019. Weather-normalized residential sales increased by 6.2% in the second quarter of 2020 from the second quarter of 2019. AEP’s second quarter 2020 industrial sales volumes decreased by 12.4% compared to the second quarter of 2019. The decline in industrial sales was spread across many industries. Weather-normalized commercial sales decreased 10.1% in the second quarter of 2020 from the second quarter of 2019.

AEP’s weather-normalized retail sales volumes for the six months ended June 30, 2020 decreased by 3.1% compared to the six months ended June 30, 2019. Weather-normalized residential sales increased by 1.9% for the six months ended June 30, 2020 compared to the six months ended June 30, 2019. AEP’s industrial sales volumes for the six months ended June 30, 2020 decreased 6.6% compared to the six months ended June 30, 2019. The decline in industrial sales was spread across many industries. Weather-normalized commercial sales decreased 5% for the six months ended June 30, 2020 compared to the six months ended June 30, 2019.

As a result of the impact of COVID-19, AEP revised its forecast for 2020 weather-normalized retail sales volumes in April 2020 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.

•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 in base rates based upon a proposed 9.9% ROE. Triennial reviews are subject to an earnings test, which provides that 70% of any earnings in excess of 70 basis points above APCo’s Virginia SCC authorized ROE would be refunded to customers. In such case, the Virginia SCC could also lower APCo’s Virginia retail base rates on a prospective basis. Virginia law provides that costs associated with asset impairments of retired coal generation assets, or automated meters, or both, which a utility records as an expense, shall be attributed to the test periods under review in a triennial review proceeding, and be deemed recovered. 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. Inclusive of the $93 million expense associated with APCo’s Virginia jurisdictional retired coal-fired generation assets, APCo calculated its Virginia earnings for the triennial period to be below the authorized ROE range. In July 2020, a certain intervenor filed testimony asserting that APCo had a revenue surplus of $23 million for its filed rate year based upon the intervenor’s recommended ROE of 8.75%. In addition, this intervenor contends APCo’s earned return for the Triennial period was 11.12%, which equates to $59 million in earnings (subject to 70% refund provision described above) above the top of the ROE range on a revenue basis. This intervenor also filed a separate legal memorandum opposing the inclusion of the 2019 expensing of the retired coal-fired generation assets from APCo’s 2017-2019 earnings test results. See “2017-2019 Virginia Triennial Review” section of Note 4 for a full listing of proposed adjustments and disallowances by intervenors.

•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 June 30, 2020, the net book value of Turk Plant was $1.4 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 (HB 6) which offers incentives for power-generating facilities with zero or reduced carbon emissions was signed into law by the Ohio Governor. HB 6 phased out current energy efficiency including lost shared savings revenues of $26 million annually and renewable mandates no later than 2020 and after 2026, respectively. HB 6 also provided for the recovery of existing renewable energy contracts on a bypassable basis through 2032 and included 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. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of the Speaker of the Ohio House of Representatives, Larry Householder, four other individuals, and Generation Now, an entity registered as a

501(c)(4) social welfare organization, in connection with a racketeering conspiracy involving the adoption of HB 6. In light of the allegations in the indictment, proposed legislation has been introduced that would repeal HB 6. The outcome of the U.S. Attorney’s Office investigation and its impact on HB 6 is not known. If the provisions of HB 6 were to be eliminated, it is unclear whether and in what form the Ohio General Assembly would pass new legislation addressing similar issues. Management is currently unable to predict the outcome of the proposed legislation and will continue to monitor the legislative process. 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 and became effective in July 2020. The law includes the following requirements: (a) Virginia electric utilities to retire no later than 2045 all electric generating units located in Virginia that emit carbon as a by-product, (b) APCo to 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) Virginia electric utilities to achieve increasing annual energy efficiency savings from 2022-2025 using 2019 as the base year. This law also provides that if the Virginia SCC finds in any triennial review that revenue reductions related to energy efficiency programs approved and deployed since the utility's previous triennial review have caused the utility to earn more than 70 basis points below its authorized rate of return, the Virginia SCC shall order increases to the utility's rates necessary to recover such revenue reductions. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Utility Rates and Rate Proceedings

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

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

Completed Base Rate Case Proceedings

Approved Revenue

Approved

New Rates

Company

Jurisdiction

Requirement Increase (Decrease)

ROE

Effective

(in millions)

I&M

Michigan

36.4

(a)

9.86%

February 2020

I&M

Indiana

77.4

(b)

9.7%

March 2020

AEP Texas

Texas

(40.0)

9.4%

June 2020

(a)In January 2020, the MPSC issued an order approving a stipulation and settlement agreement. See “2019 Michigan Base Rate Case” section of Note 4 Rate Matters in the 2019 Annual Report for additional information.

(b)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.

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%

8.75%

(a)

OPCo

Ohio

June 2020

42.3

10.15%

(b)

KPCo

Kentucky

June 2020

65.0

10%

(c)

(a)In July 2020, Intervenor testimony was filed. Testimony from Virginia Staff must be filed by mid-August 2020.

(b)In June 2020, OPCo filed a request with the PUCO for a 60-day temporary delay of the normal rate case proceeding due to the COVID-19 pandemic.

(c)Commission Staff/Intervenor direct testimony to be filed by October 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 June 30, 2020, subsidiaries within AEP’s Generation & Marketing segment had approximately 1,423 MWs of contracted renewable generation projects in-service. In addition, as of June 30, 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. PSO will own 45.5% and SWEPCo will own 54.5% of the project, which will cost approximately $2 billion. Under prior IRS guidance establishing the “Continuity Safe Harbor” for purposes of the federal PTC, two wind facilities, totaling 1,286 MWs, would have qualified for 80% of the federal PTC with year-end 2021 in-service dates and the third wind facility (199 MWs) would have qualified for 100% of the PTC with a year-end 2020 in-service date. In May 2020, the IRS issued a notice extending the “Continuity Safe Harbor” deadlines for qualifying renewable energy projects that began construction in 2016 and 2017 by one year as many projects are facing supply chain and other project development delays borne by COVID-19. Under the May 2020 IRS notice, qualifying renewable energy projects that began construction in 2016 and 2017 and which are placed in-service by the end of 2021 and 2022, respectively, will satisfy the Continuous Efforts Safe Harbor. As a result of this change by the IRS, the three North Central Wind Energy Facilities projects each have an additional year to achieve commercial operations under the “Continuity Safe Harbor,” should there be a delay in the development of the projects.

In February 2020, the OCC approved PSO’s settlement agreement. In May 2020, the APSC 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. Also in May 2020, the LPSC approved the settlement agreement as filed. Both the APSC and LPSC approved the flex-up option, agreeing to acquire the Texas portion, which the PUCT denied in July 2020. With having regulatory approval and the IRS extension of the “Continuity Safe Harbor,” PSO and SWEPCo are proceeding with the full 1,485MW development of these three projects.

Hydroelectric Generation

Evaluating Sale of Hydroelectric Generation

In March 2020, management placed 10 hydroelectric generation plants under study for a potential sale. In April 2020, the Virginia Clean Economy Act was signed into law by the Virginia Governor. The new law will provide renewable credits to APCo for its existing hydroelectric generation plants. As a result of the new law, management removed the three APCo hydroelectric generation plants (London, Marmet and Winfield) from the list of plants identified for 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 remaining plants included in the study.


Owner	Plant Name	Units	State	Net Book Value as of June 30, 2020		Net Maximum Capacity (MWs)	Year Plant or First Unit Commissioned
				(in millions)
AGR	Racine	2	OH	$	57.9	48	1982
I&M	Berrien Springs	12	MI	7.7		6	1908
I&M	Buchanan	10	MI	5.0		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	2.8		2	1923
I&M	Twin Branch Hydro	8	IN	7.0		5	1904
	Total			$	88.5	68

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. After careful consideration of current economic conditions, and particularly for the benefit of their customers, management of SWEPCo and CLECO determined DHLC would not proceed developing additional Oxbow Lignite Company (Oxbow) mining areas for future lignite extraction and ceased extraction of lignite at the mine in May 2020. Based on these actions, management revised the estimated useful life of DHLC’s and Oxbow’s assets to coincide with the date at which extraction was discontinued and the date at which delivery of lignite is expected to cease in September 2021. 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 cessation of lignite mining.

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 $154 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 June 30, 2020, DHLC has unbilled lignite inventory and fixed costs of $94 million that will be billed to SWEPCo prior to the closure of the Dolet Hills Power Station. In 2009, SWEPCo acquired interests in 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 June 30, 2020, Oxbow has unbilled fixed costs of $11 million that will be billed to SWEPCo prior to the closure of the Dolet Hills Power Station. DHLC and Oxbow have billed SWEPCo $49 million for lignite deliveries from April 2020 through June 2020, which primarily includes accelerated depreciation and amortization of fixed costs. 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 from 12.38% to 9.88%. In May 2020, FERC issued Opinion 569-A, granting rehearing on several issues. Opinion 569, as modified by Opinion 569-A, results in a revised ROE methodology that relies on three financial models. The financial models used to establish a composite zone of reasonableness are the: (a) discounted cash flow model, (b) capital asset pricing model and (c) risk premium model. Order 569-A determined the base ROE for MISO’s transmission-owning members should be 10.02% (10.52% inclusive of the RTO incentive adder of 0.5%). Management believes FERC Opinion Nos. 569 and 569-A change 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 has filed comments and will monitor this proceeding.

If FERC makes any changes to its ROE and incentive policies, they would be applied, as applicable, 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.

AFUDC Waiver

In June 2020, FERC granted a temporary waiver providing utilities the option to elect to modify the existing AFUDC rate calculations in response to the COVID-19 pandemic. As a result of the waiver, the AFUDC formula for the 12-month period starting with March 2020 may be calculated using the simple average of the actual historical short-term debt balances for 2019, instead of current period short-term balances. All other aspects of the AFUDC formula remained unchanged. AEP subsidiaries including certain Registrant Subsidiaries elected to apply the waiver in July 2020. The impact of the waiver is immaterial on the Registrants’ financial statements for the three and six months ended June 30, 2020.

LITIGATION

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

Rockport Plant Litigation

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

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

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

Thereafter, AEP filed a motion with the U.S. District Court for the Southern District of Ohio in the original NSR litigation, seeking to modify the consent decree. The district court granted the owners’ unopposed motion to stay the lease litigation to afford time for resolution of AEP’s motion to modify the consent decree. The consent decree was modified based on an agreement among the parties in July 2019. The district court’s stay expired in February 2020, but the court later extended the stay through August 13, 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. The denial of those claims was appealed to the AEP System Retirement Plan Appeal Committee and the Committee upheld the denial of claims. 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 and in response to rules governing the beneficial use and disposal of coal combustion by-products, clean water and renewal permits for certain water discharges.

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

AEP will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances. If AEP cannot recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.

Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed below will have a material impact on AEP System generating units. Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance. As of June 30, 2020, the AEP System had generating capacity of approximately 24,700 MWs, of which approximately 12,600 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.

Modification of the New Source Review Litigation Consent Decree

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

In 2017, AEP filed a motion with the district court seeking to modify the consent decree to eliminate an obligation to install future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. The other parties to the consent decree opposed AEP’s motion. The district court granted AEP’s request to delay the deadline to install Selective Catalytic Reduction (SCR) technology at Rockport Plant, Unit 2 until June 2020. Construction of the SCR technology was completed by June 1, 2020, testing was conducted, and the unit was released for dispatch on June 5, 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.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions. The states implement and administer many of these programs and could impose additional or more stringent requirements. The primary regulatory programs that continue to drive investments in AEP’s existing generating units include: (a) periodic revisions to NAAQS and the development of SIPs to achieve any more stringent standards, (b) implementation of the regional haze program by the states and the Federal EPA, (c) regulation of hazardous air pollutant emissions under MATS, (d) implementation and review of CSAPR and (e) the Federal EPA’s regulation of greenhouse gas emissions from fossil generation under Section 111 of the CAA. Notable developments in significant CAA regulatory requirements affecting AEP’s operations are discussed in the following sections.

National Ambient Air Quality Standards

The Federal EPA issued new, more stringent NAAQS for PM in 2012 and ozone in 2015. The Federal EPA is currently reviewing both of these standards. A proposed rule to retain the existing PM standards was released in April 2020. The existing standards for NO₂ and SO₂were retained after review by the Federal EPA in 2018 and 2019, respectively. Implementation of these standards is underway.

The Federal EPA finalized non-attainment designations for the 2015 ozone standard in 2018. The Federal EPA confirmed that for states included in the CSAPR program, there are no additional interstate transport obligations, as all areas of the country are expected to attain the 2008 ozone standard before 2023. Challenges to the 2015 ozone standard and the Federal EPA’s determination that CSAPR satisfies certain states’ interstate transport obligations were filed in the U.S. Court of Appeals for the District of Columbia Circuit. In August 2019, the court upheld the 2015 primary ozone standard, but remanded the secondary welfare-based standard for further review. The court

vacated the Federal EPA’s determination that CSAPR fulfilled the states’ interstate transport obligations, because the Federal EPA’s modeling analysis did not demonstrate that all significant contributions would be eliminated by the attainment deadlines for downwind states. Any further changes will require additional rulemaking. Management cannot currently predict the nature, stringency or timing of additional requirements for AEP’s facilities based on the outcome of these activities.

Regional Haze

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

The Federal EPA initially disapproved portions of the Arkansas regional haze SIP, but has approved a revised SIP and all of SWEPCo's affected units are in compliance with the relevant requirements.

The Federal EPA also disapproved portions of the Texas regional haze SIP. In 2017, the Federal EPA finalized a FIP that allows participation in the CSAPR ozone season program to satisfy the NO_xregional haze obligations for electric generating units in Texas. Additionally, the Federal EPA finalized an intrastate SO₂ emissions trading program based on CSAPR allowance allocations. A challenge to the FIP was filed in the U.S. Court of Appeals for the Fifth Circuit and the case is pending the Federal EPA’s reconsideration of the final rule. In August 2018, the Federal EPA proposed to affirm its 2017 FIP approval. In November 2019, in response to comment, the Federal EPA proposed revisions to the intrastate trading program. The Federal EPA finalized the intrastate trading program in July 2020. Management supports the intrastate trading program as a compliance alternative to source-specific controls.

Cross-State Air Pollution Rule

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

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

In 2016, the Federal EPA issued a final rule, the CSAPR Update, to address the remand and to incorporate additional changes necessary to address the 2008 ozone standard. The CSAPR Update significantly reduced ozone season budgets in many states and discounted the value of banked CSAPR ozone season allowances beginning with the 2017 ozone season. In 2019, the appeals court remanded the CSAPR Update to the Federal EPA because it determined the Federal EPA had not properly considered the attainment dates for downwind areas in establishing its partial remedy, and should have considered whether there were available measures to control emissions from sources other than generating units. Any further changes to the CSAPR rule will require additional rulemaking.

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

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

In 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied all of the petitions for review of the 2012 final rule. Various intervenors filed petitions for further review in the U.S. Supreme Court.

In 2015, the U.S. Supreme Court reversed the decision of the U.S. Court of Appeals for the District of Columbia Circuit. The court remanded the MATS rule to the Federal EPA to consider costs in determining whether to regulate emissions of HAPs from power plants. In 2016, the Federal EPA issued a supplemental finding concluding that, after considering the costs of compliance, it was appropriate and necessary to regulate HAP emissions from coal and oil-fired units. Petitions for review of the Federal EPA’s determination were filed in the U.S. Court of Appeals for the District of Columbia Circuit. In 2018, the Federal EPA released a revised finding that the costs of reducing HAP emissions to the level in the current rule exceed the benefits of those HAP emission reductions. The Federal EPA also determined that there are no significant changes in control technologies and the remaining risks associated with HAP emissions do not justify any more stringent standards. Therefore, the Federal EPA proposed to retain the current MATS standards without change. In April 2020, the Federal EPA released a final rule adopting the conclusions set forth in the proposal and retaining the existing MATS standards.

Climate Change, CO₂ Regulation and Energy Policy

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

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

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

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

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

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

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

Coal Combustion Residual (CCR) Rule

In 2015, the Federal EPA published a final rule to regulate the disposal and beneficial re-use of CCR, including fly ash and bottom ash created from coal-fired generating units and FGD gypsum generated at some coal-fired plants. The rule applies to active CCR landfills and surface impoundments at operating electric utility or independent generation facilities. The rule imposes construction and operating obligations, including location restrictions, liner criteria, structural integrity requirements for impoundments, operating criteria and additional groundwater monitoring requirements to be implemented on a schedule spanning an approximate four-year implementation period. In 2018, some of AEP’s facilities were required to begin monitoring programs to determine if unacceptable groundwater impacts will trigger future corrective measures. Based on additional groundwater data, further studies to design and assess appropriate corrective measures have been undertaken at two facilities.

In a challenge to the final 2015 rule, the parties initially agreed to settle some of the issues. In 2018, the U.S. Court of Appeals for the District of Columbia Circuit addressed or dismissed the remaining issues in its decision vacating and remanding certain provisions of the 2015 rule. The provisions addressed by the court’s decision, including changes to the provisions for unlined impoundments and legacy sites, will be the subject of further rulemaking consistent with the court’s decision.

Prior to the court’s decision, the Federal EPA issued the July 2018 rule that modifies certain compliance deadlines and other requirements in the 2015 rule. In December 2018, challengers filed a motion for partial stay or vacatur of the July 2018 rule. On the same day, the Federal EPA filed a motion for partial remand of the July 2018 rule. The court granted the Federal EPA’s motion. In November 2019, the Federal EPA proposed revisions to implement the

court’s decision regarding the timing for closure of unlined surface impoundments along with impoundments not meeting the required distance from an aquifer. The comment period closed in January 2020. In December 2019, the Federal EPA proposed a federal permit program, implementing the Water Infrastructure Improvements for the Nation Act, that would apply in states that do not have an approved CCR program.

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

Because AEP currently uses surface impoundments and landfills to manage CCR materials at generating facilities, significant costs will be incurred to upgrade or close and replace these existing facilities and conduct any required remedial actions. Closure and post-closure costs have been included in ARO in accordance with the requirements in the final rule. Additional ARO revisions will occur on a site-by-site basis if groundwater monitoring activities conclude that corrective actions are required to mitigate groundwater impacts, which could include costs to remove ash from some unlined units.

In March 2020, Virginia’s Governor signed House Bill 443 (HB 443), effective July 2020, requiring APCo to close certain ash disposal units at the retired Glen Lyn Station by removal of all coal combustion material. As a result, in June 2020, APCo recorded a $199 million revision to increase estimated Glen Lyn Station ash disposal ARO liabilities. 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 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.

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

Clean Water Act Regulations

In 2014, the Federal EPA issued a final rule setting forth standards for existing power plants that is intended to reduce mortality of aquatic organisms impinged or entrained in the cooling water. The rule was upheld on review by the U.S. Court of Appeals for the Second Circuit. Compliance timeframes are established by the permit agency through each facility’s NPDES permit as those permits are renewed and have been incorporated into permits at several AEP facilities. Additional AEP facilities are reviewing these requirements as their wastewater discharge permits are renewed and making appropriate adjustments to their intake structures.

In 2015, the Federal EPA issued a final rule revising effluent limitation guidelines for generating facilities. The rule established limits on FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater to be imposed as soon as possible after November 2018 and no later than December 2023. These requirements would be implemented through each facility’s wastewater discharge permit. The rule was challenged in the U.S. Court of Appeals for the Fifth Circuit. In 2017, the Federal EPA announced its intent to reconsider and potentially revise the standards for FGD wastewater and bottom ash transport water. The Federal EPA postponed the compliance deadlines for those wastewater categories to be no earlier than 2020, to allow for reconsideration. In April 2019, the Fifth Circuit vacated the standards for landfill leachate and legacy wastewater, and remanded them to the Federal EPA for reconsideration. In November 2019, the Federal EPA proposed revisions to the guidelines for existing generation facilities. The comment period ended in January 2020. Management is assessing technology additions and retrofits to comply with the rule and the impacts of the Federal EPA’s recent actions on facilities’ wastewater discharge permitting.

In 2015, the Federal EPA and the U.S. Army Corps of Engineers jointly issued a final rule to clarify the scope of the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases. Various parties challenged the 2015 rule in different U.S. District Courts, which resulted in a patchwork of applicability of the 2015 rule and its predecessor. In December 2018, the Federal EPA and the U.S. Army Corps of Engineers proposed a replacement rule. In September 2019, the Federal EPA repealed the 2015 rule. The final replacement rule was published in the Federal Register in April 2020 and became 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. Challenges to the final rule and requests for a preliminary injunction have been brought by states and other groups in multiple U.S. District Courts. At this time, none of the jurisdictions in which AEP operates are impacted by a stay. Management is monitoring these various proceedings but is unable to predict the actions of the various courts.

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. In May 2020, the Court revised its order lifting the injunction for non-oil and gas pipeline construction activities and routine maintenance, inspection and repair activities on existing NWP 12 projects. The Department of Justice appealed the Court’s decision to the Court of Appeals for the Ninth Circuit and moved for stay pending appeal, which was denied. In June 2020, the Department of Justice submitted an application to the U.S. Supreme Court requesting a stay of the District Court’s Order, and the Court granted the request with respect to all oil and gas pipelines except the Keystone Pipeline. Management is monitoring the litigation and evaluating other permitting alternatives, but is currently unable to predict the impact of future proceedings on current and planned projects.

RESULTS OF OPERATIONS

SEGMENTS

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

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

Vertically Integrated Utilities

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

Transmission and Distribution Utilities

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

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

AEP Transmission Holdco

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

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

Generation & Marketing

•Competitive generation in ERCOT and PJM.

•Contracted renewable energy investments and management services.

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

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

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

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020		2019		2020		2019
	(in millions)						(in millions)
Vertically Integrated Utilities	$	255.9	$	177.7	$	501.2	$	480.1
Transmission and Distribution Utilities	139.5		131.4		255.7		287.9
AEP Transmission Holdco	91.5		154.5		232.1		278.7
Generation & Marketing	65.9		9.4		94.3		49.5
Corporate and Other	(32.0)		(11.7)		(67.3)		(62.1)
Earnings Attributable to AEP Common Shareholders	$	520.8	$	461.3	$	1,016.0	$	1,034.1

AEP CONSOLIDATED

Second Quarter of 2020 Compared to Second Quarter of 2019

Earnings Attributable to AEP Common Shareholders increased from $461 million in 2019 to $521 million in 2020 to primarily due to:

•A planned decrease in Other Operation and Maintenance expenses.

•Favorable rate proceedings in AEP’s various jurisdictions.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019

Earnings Attributable to AEP Common Shareholders decreased from $1,034 million in 2019 to $1,016 million in 2020 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.

•A planned decrease in Other Operation and Maintenance expenses.

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

VERTICALLY INTEGRATED UTILITIES


	Three Months Ended						Six Months Ended
	June 30,						June 30,
Vertically Integrated Utilities	2020		2019		2020		2019
	(in millions)
Revenues	$	2,092.0	$	2,123.8	$	4,318.7	$	4,527.1
Fuel and Purchased Electricity	582.1		699.6		1,253.3		1,556.0

Gross Margin	1,509.9		1,424.2		3,065.4		2,971.1
Other Operation and Maintenance	624.6		684.1		1,315.9		1,374.2


Depreciation and Amortization	393.3		359.0		775.0		715.3
Taxes Other Than Income Taxes	117.5		113.2		234.6		229.2
Operating Income	374.5		267.9		739.9		652.4


Other Income	1.4		2.2		3.0		3.5
Allowance for Equity Funds Used During Construction	9.0		16.0		17.2		26.7
Non-Service Cost Components of Net Periodic Benefit Cost	17.1		16.8		34.0		33.8
Interest Expense	(141.8)		(143.0)		(286.3)		(282.0)
Income Before Income Tax Expense (Benefit) and Equity Earnings	260.2		159.9		507.8		434.4
Income Tax Expense (Benefit)	4.6		(18.1)		6.7		(46.5)
Equity Earnings of Unconsolidated Subsidiary	0.7		0.8		1.5		1.5
Net Income	256.3		178.8		502.6		482.4
Net Income Attributable to Noncontrolling Interests	0.4		1.1		1.4		2.3
Earnings Attributable to AEP Common Shareholders	$	255.9	$	177.7	$	501.2	$	480.1

Summary of KWh Energy Sales for Vertically Integrated Utilities


	Three Months Ended June 30,			Six Months Ended June 30,
	2020	2019	2020	2019
	(in millions of KWhs)
Retail:
Residential	6,976	6,315	15,238	15,531
Commercial	5,150	5,710	10,516	11,343
Industrial	7,699	8,865	16,174	17,410
Miscellaneous	511	547	1,041	1,093
Total Retail	20,336	21,437	42,969	45,377

Wholesale (a)	4,924	4,826	8,542	10,630

Total KWhs	25,260	26,263	51,511	56,007

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

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

Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities


	Three Months Ended June 30,			Six Months Ended June 30,
	2020	2019	2020	2019
	(in degree days)
Eastern Region
Actual – Heating (a)	212	99	1,453	1,670
Normal – Heating (b)	137	142	1,748	1,737

Actual – Cooling (c)	324	378	337	379
Normal – Cooling (b)	337	333	342	338

Western Region
Actual – Heating (a)	49	26	698	967
Normal – Heating (b)	34	35	901	901

Actual – Cooling (c)	673	651	724	662
Normal – Cooling (b)	700	699	728	727

(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.

Second Quarter of 2020 Compared to Second Quarter of 2019


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

Second Quarter of 2019	$	177.7

Changes in Gross Margin:
Retail Margins	46.9
Margins from Off-system Sales	(3.5)
Transmission Revenues	45.7
Other Revenues	(3.4)
Total Change in Gross Margin	85.7

Changes in Expenses and Other:
Other Operation and Maintenance	59.5

Depreciation and Amortization	(34.3)
Taxes Other Than Income Taxes	(4.3)


Other Income	(0.8)
Allowance for Equity Funds Used During Construction	(7.0)
Non-Service Cost Components of Net Periodic Pension Cost	0.3
Interest Expense	1.2
Total Change in Expenses and Other	14.6

Income Tax Expense	(22.7)
Equity Earnings of Unconsolidated Subsidiary	(0.1)
Net Income Attributable to Noncontrolling Interests	0.7

Second Quarter of 2020	$	255.9

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

•Retail Margins increased $47 million primarily due to the following:

•A $19 million increase in weather-normalized retail margins driven by a $48 million increase in the residential customer class partially offset by a $28 million decrease in the commercial and industrial customer classes.

•A $17 million increase in weather-related usage primarily in the eastern region and primarily in the residential class.

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

•A $13 million increase at SWEPCo primarily due to rider increases in all jurisdictions and a base rate revenue increase in Arkansas.

•An $8 million increase at I&M primarily due to the Indiana and Michigan base rate cases, partially offset by a decrease in revenue riders. This increase was partially offset in other expense items below.

•A $6 million increase due to a decrease in customer refunds related to Tax Reform. This increase was partially offset in Income Tax Expense below.

•A $6 million increase in deferred fuel at APCo primarily due to the timing of recoverable PJM expenses. This increase was offset in other expense items below.

•A $5 million increase at APCo and WPCo due to the WVPSC’s approval of the Mitchell Plant surcharge effective January 2020.

These increases were partially offset by:

•A $19 million decrease in weather-normalized margins for wholesale customers primarily at I&M.

•A $5 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 $4 million 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 and margins.

•Transmission Revenues increased $46 million primarily due to the following:

•A $36 million increase at SWEPCo as a result of the annual transmission formula rate true-up. This increase was partially offset by an increase in transmission expenses in SPP.

•A $10 million increase at SWEPCo due to continued investment in transmission projects.

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

•Other Operation and Maintenance expenses decreased $60 million primarily due to the following:

•A $30 million decrease in employee-related expenses.

•A $27 million decrease in plant outage and maintenance expenses primarily at APCo, KPCo and PSO.

•An $18 million decrease due to PJM transmission services including the annual formula rate true-up.

•A $13 million decrease due to the capitalization of previously expensed North Central Wind Energy Facilities costs at SWEPCo and PSO.

These decreases were partially offset by:

•A $28 million increase due to SPP transmission services including the annual formula rate true-up.

•A $12 million increase due to storms at KPCo and APCo.

•Depreciation and Amortization expenses increased $34 million primarily due to a higher depreciable base and increased depreciation rates approved at I&M and SWEPCo. This increase was partially offset in Retail Margins above.

•Allowance for Equity Funds Used During Construction decreased $7 million primarily due to a decrease in the AFUDC base primarily at I&M and APCo.

•Income Tax Expense increased $23 million primarily due to an increase in pretax book income.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019


Reconciliation of Six Months Ended June 30, 2019 to Six Months Ended June 30, 2020
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)

Six Months Ended June 30, 2019	$	480.1

Changes in Gross Margin:
Retail Margins	52.8
Margins from Off-system Sales	(8.7)
Transmission Revenues	51.8
Other Revenues	(1.6)
Total Change in Gross Margin	94.3

Changes in Expenses and Other:
Other Operation and Maintenance	58.3

Depreciation and Amortization	(59.7)
Taxes Other Than Income Taxes	(5.4)


Other Income	(0.5)
Allowance for Equity Funds Used During Construction	(9.5)
Non-Service Cost Components of Net Periodic Pension Cost	0.2
Interest Expense	(4.3)
Total Change in Expenses and Other	(20.9)

Income Tax Expense	(53.2)

Net Income Attributable to Noncontrolling Interests	0.9

Six Months Ended June 30, 2020	$	501.2

•Retail Margins increased $53 million primarily due to the following:

•A $20 million increase in deferred fuel at APCo primarily due to the timing of recoverable PJM expenses. This increase was offset in other expense items below.

•A $16 million increase due to a decrease in customer refunds related to Tax Reform. This increase was partially offset in Income Tax Expense 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 $32 million increase at I&M primarily due to the Indiana and Michigan base rate cases. This increase was partially offset in other expense items below.

•A $21 million increase at SWEPCo primarily due to rider increases in all jurisdictions and a base rate revenue increase in Arkansas.

•A $10 million increase at PSO due to new base rates implemented in April 2019.

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

•A $10 million increase at APCo and WPCo due to the WVPSC’s approval of the Mitchell Plant surcharge effective January 1, 2020.

These increases were partially offset by:

•A $44 million decrease in weather-related usage primarily in the eastern region and primarily in the residential class.

•A $23 million decrease in weather-normalized margins for wholesale contracts primarily at I&M.

•A $9 million decrease in weather-normalized retail margins driven by a $51 million decrease in the commercial and industrial classes partially offset by a $44 million increase in the residential customer class.

•A $6 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 $9 million 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 and margins.

•Transmission Revenues increased $52 million primarily due to the following:

•A $36 million increase at SWEPCo as a result of the annual transmission formula rate true-up. This increase was partially offset by an increase in transmission expenses in SPP.

•A $16 million increase at SWEPCo due to continued investment in transmission projects.

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

•Other Operation and Maintenance expenses decreased $58 million primarily due to the following:

•A $40 million decrease in plant outage and maintenance expenses primarily at APCo, WPCo, AEGCo and PSO.

•A $39 million decrease in employee-related expenses.

•A $10 million decrease due to the capitalization of previously expensed North Central Wind Energy Facilities costs at SWEPCo and PSO.

•A $7 million decrease due to PJM transmission services including the annual formula rate true-up.

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

These decreases were partially offset by:

•A $33 million increase due to SPP transmission services including the annual formula rate true-up.

•An $11 million increase due to storms at KPCo and APCo

•Depreciation and Amortization expenses increased $60 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.

•Taxes Other Than Income Taxes increased $5 million primarily due to the following:

•A $5 million increase at APCo and WPCo in West Virginia business and occupational taxes.

•A $4 million increase in property taxes driven by an increase in utility plant.

These increases were partially offset by:

•A $3 million decrease in payroll taxes.

•Allowance for Equity Funds Used During Construction decreased $10 million primarily driven by FERC audit findings recorded in 2019 and a decrease in the AFUDC base primarily at I&M and APCo.

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

•Income Tax Expense increased $53 million primarily due to a decrease in amortization of Excess ADIT, an increase in pretax book income and a decrease in favorable flow-through tax benefits. The decrease in amortization of Excess ADIT is partially offset above in Gross Margin and Other Operation and Maintenance expenses.

TRANSMISSION AND DISTRIBUTION UTILITIES


	Three Months Ended						Six Months Ended
	June 30,						June 30,
Transmission and Distribution Utilities	2020		2019		2020		2019
	(in millions)
Revenues	$	1,034.5	$	1,045.7	$	2,141.4	$	2,267.7
Purchased Electricity	147.5		163.7		338.9		393.4
Amortization of Generation Deferrals	—		24.1		—		56.5
Gross Margin	887.0		857.9		1,802.5		1,817.8
Other Operation and Maintenance	351.9		410.4		719.1		816.3


Depreciation and Amortization	207.0		193.4		421.5		377.1
Taxes Other Than Income Taxes	141.8		139.9		288.0		285.4
Operating Income	186.3		114.2		373.9		339.0
Interest and Investment Income	0.4		1.8		1.1		3.1
Carrying Costs Income	0.6		0.2		1.0		0.4

Allowance for Equity Funds Used During Construction	7.7		5.6		14.7		12.5
Non-Service Cost Components of Net Periodic Benefit Cost	7.4		7.5		14.7		15.1
Interest Expense	(72.2)		(45.2)		(143.6)		(107.2)
Income Before Income Tax Expense (Benefit)	130.2		84.1		261.8		262.9
Income Tax Expense (Benefit)	(9.3)		(47.3)		6.1		(25.0)
Net Income	139.5		131.4		255.7		287.9
Net Income Attributable to Noncontrolling Interests	—		—		—		—
Earnings Attributable to AEP Common Shareholders	$	139.5	$	131.4	$	255.7	$	287.9

Summary of KWh Energy Sales for Transmission and Distribution Utilities


	Three Months Ended June 30,			Six Months Ended June 30,
	2020	2019	2020	2019
	(in millions of KWhs)
Retail:
Residential	6,299	5,799	12,599	12,346
Commercial	5,559	6,232	11,432	11,850
Industrial	5,148	5,864	11,056	11,635
Miscellaneous	180	196	362	372
Total Retail (a)	17,186	18,091	35,449	36,203

Wholesale (b)	455	440	845	1,078

Total KWhs	17,641	18,531	36,294	37,281

(a)Represents energy delivered to distribution customers.

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

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


	Three Months Ended June 30,			Six Months Ended June 30,
	2020	2019	2020	2019
	(in degree days)
Eastern Region
Actual – Heating (a)	292	114	1,765	2,006
Normal – Heating (b)	182	189	2,080	2,066

Actual – Cooling (c)	314	303	317	304
Normal – Cooling (b)	301	298	304	301

Western Region
Actual – Heating (a)	6	3	97	180
Normal – Heating (b)	3	3	188	190

Actual – Cooling (d)	936	970	1,167	1,092
Normal – Cooling (b)	933	934	1,058	1,057

(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.

Second Quarter of 2020 Compared to Second Quarter of 2019


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

Second Quarter of 2019	$	131.4

Changes in Gross Margin:
Retail Margins	28.0
Margins from Off-system Sales	(16.5)
Transmission Revenues	4.0
Other Revenues	13.6
Total Change in Gross Margin	29.1

Changes in Expenses and Other:
Other Operation and Maintenance	58.5
Depreciation and Amortization	(13.6)
Taxes Other Than Income Taxes	(1.9)
Interest and Investment Income	(1.4)
Carrying Costs Income	0.4
Allowance for Equity Funds Used During Construction	2.1
Non-Service Cost Components of Net Periodic Benefit Cost	(0.1)
Interest Expense	(27.0)
Total Change in Expenses and Other	17.0

Income Tax Expense	(38.0)

Second Quarter of 2020	$	139.5

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

•Retail Margins increased $28 million primarily due to the following:

•A $61 million net increase in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset in Other Operation and Maintenance expenses below.

•A $13 million increase in rider revenues in Ohio associated with the DIR. This increase was partially offset in other expense items below.

•A $5 million increase in revenues associated with Ohio smart grid riders. This increase was partially offset in other expense items below.

These increases were partially offset by:

•A $10 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 $10 million decrease in weather-normalized margins primarily in the commercial class partially offset by the residential class.

•A $9 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 $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 $7 million decrease due to refunds of Excess ADIT not subject to normalization requirements in Texas. This decrease was offset in Income Tax Expense below.

•A $5 million decrease due to a PUCO order to refund unused 2018 major storm reserve collections to customers. This decrease was offset in Other Operation and Maintenance expenses below.

•Margins from Off-system Sales decreased $17 million primarily due to the following:

•A $20 million decrease in Texas primarily due to lower Oklaunion Power Station PPA revenues. This decrease was offset in Other Operation and Maintenance expenses below.

This decrease was partially offset by:

•A $7 million increase in Ohio primarily due to higher OVEC PPA deferrals. This increase was offset in Retail Margins above.

•Transmission Revenues increased $4 million primarily due to the following:

•A $10 million increase in Ohio due to the annual transmission formula rate true-up.

•A $10 million increase due to recovery of increased transmission investment in ERCOT.

This increase was partially offset by:

•A $17 million decrease in Texas due to a one-time credit to transmission customers as a result of Tax Reform and the most recent base rate case. This decrease was offset in Income Tax Expense below.

•Other Revenues increased $14 million primarily due to securitization revenue in Texas. 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 decreased $59 million primarily due to the following:

•A $67 million decrease due to prior year partial amortization of the AEP Texas Storm Restoration Securitization regulatory asset as a result of the AEP Texas Storm Cost Securitization financing order issued by the PUCT in June 2019. This decrease was offset in Income Tax Expense below.

•A $34 million decrease in PJM expenses primarily related to the annual transmission formula rate true-up.

•A $17 million decrease due to the revision of the Oklaunion Power Station ARO. This decrease was offset in Margins for Off-System Sales above.

•A $5 million decrease due to a PUCO order to refund unused 2018 major storm reserve collections to customers. This decrease was offset in Retail Margins above.

These decreases were partially offset by:

•A $66 million increase in PJM expenses that were fully recovered in rate riders/trackers in Gross Margin above.

•A $3 million increase in remitted Universal Service Fund (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 $14 million primarily due to the following:

•A $7 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.

•A $7 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 $3 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 $27 million primarily due to the prior year deferral of previously recorded interest expense approved for the recovery as a result of the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019.

•Income Tax Expense increased $38 million primarily due to the prior year amortization of Excess ADIT not subject to normalization requirements as approved in the Texas Storm Cost Securitization financing order issued by the PUCT in 2019 and an increase in pretax book income. This increase was partially offset in Gross Margins and Other Operation and Maintenance Expenses above.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019


Reconciliation of Six Months Ended June 30, 2019 to Six Months Ended June 30, 2020
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)

Six Months Ended June 30, 2019	$	287.9

Changes in Gross Margin:
Retail Margins	(46.1)
Margins from Off-system Sales	(15.9)
Transmission Revenues	15.9
Other Revenues	30.8
Total Change in Gross Margin	(15.3)

Changes in Expenses and Other:
Other Operation and Maintenance	97.2
Depreciation and Amortization	(44.4)
Taxes Other Than Income Taxes	(2.6)
Interest and Investment Income	(2.0)
Carrying Costs Income	0.6
Allowance for Equity Funds Used During Construction	2.2
Non-Service Cost Components of Net Periodic Benefit Cost	(0.4)
Interest Expense	(36.4)
Total Change in Expenses and Other	14.2

Income Tax Expense	(31.1)

Six Months Ended June 30, 2020	$	255.7

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 $46 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 $23 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 $15 million net decrease in margin in Ohio for the Rate Stability Rider including associated amortizations which ended in the third quarter of 2019.

•A $14 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 $7 million decrease due to refunds of Excess ADIT not subject to normalization requirements in Texas. This decrease was offset in Income Tax Expense below.

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

•A $5 million decrease due to a PUCO order to refund unused 2018 major storm reserve collections to customers. This decrease was offset in Other Operation and Maintenance expenses below.

These decreases were partially offset by:

•A $30 million increase in rider revenues in Ohio associated with the DIR. This increase was partially offset in other expense items below.

•A $22 million net increase in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset in Other Operation and Maintenance expenses below.

•A $12 million increase in revenues associated with Ohio smart grid riders. This increase was partially offset in other expense items below.

•A $10 million increase in revenues in Ohio associated with the USF. This increase was offset in Other Operation and Maintenance expenses below.

•A $6 million increase in Texas revenues associated with the Transmission Cost Recovery Factor revenue rider. This decrease was partially offset by a decrease in Other Operation and Maintenance expenses below.

•Margins from Off-system Sales decreased $16 million primarily due to the following:

•A $20 million decrease in Texas primarily due to lower Oklaunion Power Station PPA revenues. This decrease was offset in Other Operation and Maintenance expenses below.

•A $9 million decrease in sales in Ohio due to lower market prices and decreased sales volumes in 2020. This decrease was offset in Retail Margins above.

This decrease was partially offset by:

•A $14 million increase in Ohio due to higher OVEC PPA deferrals. This increase was offset in Retail Margins above.

•Transmission Revenues increased $16 million primarily due to the following:

•A $22 million increase primarily due to recovery of increased transmission investment in ERCOT.

•A $10 million increase in Ohio due to the annual transmission formula rate true-up.

This increase was partially offset by:

•Other Revenues increased $31 million primarily due to the following:

•A $19 million increase in securitization revenue in Texas. This increase was offset in Depreciation and Amortization expenses and in Interest Expense below.

•A $9 million increase in Ohio primarily due to third-party LGRR revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins above.

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

•Other Operation and Maintenance expenses decreased $97 million primarily due to the following:

•A $40 million decrease in PJM expenses primarily related to the annual transmission formula rate true-up.

•A $17 million decrease due to the revision of the Oklaunion Power Station ARO. This decrease was offset in Margins for Off-System Sales above.

•A $5 million decrease due to a PUCO order to refund unused 2018 major storm reserve collections to customers. This decrease was offset in Retail Margins above.

These decreases were partially offset by:

•A $25 million increase in PJM expenses that were fully recovered in rate riders/trackers in Gross Margin above.

•A $10 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 $44 million primarily due to the following:

•A $22 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.

•A $19 million increase in securitization amortizations in Texas. This increase was offset in Other Revenues above and in Interest Expense below.

•A $10 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.

•An $8 million increase in Ohio recoverable DIR depreciation expense. This increase was partially offset in Retail Margins above.

•A $5 million increase in recoverable smart grid expense in Ohio. This increase was offset in Retail Margins above.

These increases were partially offset by:

•A $21 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.

•Taxes Other Than Income Taxes increased $3 million primarily due to the following:

•An $8 million increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.

This increase was partially offset by:

•A $3 million decrease in excise taxes due to lower demand in 2020 in Ohio. This decrease was offset in Retail Margins above.

•Interest Expense increased $36 million primarily due to the following:

•A $19 million increase due to the deferral of previously recorded interest expense approved for recovery as a result of the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019.

•A $14 million increase due to higher long-term debt balances.

•Income Tax Expense increased $31 million primarily due to the prior year amortization of Excess ADIT not subject to normalization requirements as approved in the Texas Storm Cost Securitization financing order issued by the PUCT in 2019. This increase was partially offset in Gross Margins and Other Operation and Maintenance Expenses above.

AEP TRANSMISSION HOLDCO


	Three Months Ended						Six Months Ended
	June 30,						June 30,
AEP Transmission Holdco	2020		2019		2020		2019
	(in millions)
Transmission Revenues	$	249.7	$	278.9	$	559.9	$	535.3
Other Operation and Maintenance	25.9		22.9		55.8		45.2
Depreciation and Amortization	61.1		44.6		119.2		86.4
Taxes Other Than Income Taxes	51.8		43.5		103.7		86.1
Operating Income	110.9		167.9		281.2		317.6
Interest and Investment Income	1.5		0.8		2.4		1.5


Allowance for Equity Funds Used During Construction	18.4		28.8		34.6		40.1
Non-Service Cost Components of Net Periodic Benefit Cost	0.5		0.7		1.0		1.3
Interest Expense	(34.2)		(23.0)		(65.0)		(46.0)
Income Before Income Tax Expense and Equity Earnings	97.1		175.2		254.2		314.5
Income Tax Expense	24.7		38.4		63.1		70.3
Equity Earnings of Unconsolidated Subsidiary	19.8		18.6		42.7		36.4
Net Income	92.2		155.4		233.8		280.6
Net Income Attributable to Noncontrolling Interests	0.7		0.9		1.7		1.9
Earnings Attributable to AEP Common Shareholders	$	91.5	$	154.5	$	232.1	$	278.7

Summary of Investment in Transmission Assets for AEP Transmission Holdco


	As of June 30,
	2020		2019
	(in millions)
Plant in Service	$	9,333.7	$	7,447.3
Construction Work in Progress	1,660.5		1,883.1
Accumulated Depreciation and Amortization	508.2		350.2
Total Transmission Property, Net	$	10,486.0	$	8,980.2

Second Quarter of 2020 Compared to Second Quarter of 2019

Reconciliation of Second Quarter of 2019 to Second Quarter of 2020

Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco

(in millions)


Second Quarter of 2019	$	154.5

Changes in Transmission Revenues:
Transmission Revenues	(29.2)
Total Change in Transmission Revenues	(29.2)

Changes in Expenses and Other:
Other Operation and Maintenance	(3.0)
Depreciation and Amortization	(16.5)
Taxes Other Than Income Taxes	(8.3)
Interest and Investment Income	0.7

Allowance for Equity Funds Used During Construction	(10.4)
Non-Service Cost Components of Net Periodic Pension Cost	(0.2)
Interest Expense	(11.2)
Total Change in Expenses and Other	(48.9)

Income Tax Expense	13.7
Equity Earnings of Unconsolidated Subsidiary	1.2
Net Income Attributable to Noncontrolling Interests	0.2

Second Quarter of 2020	$	91.5

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

•Transmission Revenues decreased $29 million primarily due to the following:

•A $62 million decrease as a result of the affiliated annual transmission formula rate true-up which is offset in Other Operation and Maintenance expense across the other Registrant subsidiaries.

•A $17 million decrease as a result of the non-affiliated annual transmission formula rate true-up.

These decreases were partially offset by:

•A $50 million increase due to continued investment in transmission assets.

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

•Depreciation and Amortization expenses increased $17 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $8 million primarily due to higher property taxes as a result of increased transmission investment.

•Allowance for Equity Funds Used During Construction decreased $10 million primarily due to the following:

•A $12 million decrease driven by the favorable impact of a FERC settlement agreement recorded in 2019.

•A $2 million decrease due to lower CWIP.

These decreases were partially offset by:

•A $4 million increase driven by FERC audit findings recorded in 2019.

•Interest Expense increased $11 million primarily due to higher long-term debt balances.

•Income Tax Expense decreased $14 million primarily due to lower pretax book income.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019

Reconciliation of Six Months Ended June 30, 2019 to Six Months Ended June 30, 2020

Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco

(in millions)


Six Months Ended June 30, 2019	$	278.7

Changes in Transmission Revenues:
Transmission Revenues	24.6
Total Change in Transmission Revenues	24.6

Changes in Expenses and Other:
Other Operation and Maintenance	(10.6)
Depreciation and Amortization	(32.8)
Taxes Other Than Income Taxes	(17.6)
Interest and Investment Income	0.9

Allowance for Equity Funds Used During Construction	(5.5)
Non-Service Cost Components of Net Periodic Pension Cost	(0.3)
Interest Expense	(19.0)
Total Change in Expenses and Other	(84.9)

Income Tax Expense	7.2
Equity Earnings of Unconsolidated Subsidiary	6.3
Net Income Attributable to Noncontrolling Interests	0.2

Six Months Ended June 30, 2020	$	232.1

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

•Transmission Revenues increased $25 million primarily due to the following:

•A $104 million increase due to continued investment in transmission assets.

This increase was partially offset by the following:

•A $62 million decrease as a result of the affiliated annual transmission formula rate true-up which is offset in Other Operation and Maintenance expense across the other Registrant subsidiaries.

•A $17 million decrease as a result of the non-affiliated annual transmission formula rate true-up.

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

•Other Operation and Maintenance expenses increased $11 million primarily due to the following:

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

•A $4 million increase in rent expense.

•Depreciation and Amortization expenses increased $33 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $18 million primarily due to higher property taxes as a result of increased transmission investment.

•Allowance for Equity Funds Used During Construction decreased $6 million primarily due to the following:

•A $12 million decrease driven by the favorable impact of a FERC settlement agreement recorded in 2019.

•A $6 million decrease due to lower CWIP.

These decreases were partially offset by:

•A $13 million increase driven by FERC audit findings recorded in 2019.

•Interest Expense increased $19 million primarily due to higher long-term debt balances.

•Income Tax Expense decreased $7 million primarily due to lower pretax book income.

•Equity Earnings of Unconsolidated Subsidiary increased $6 million primarily due to higher pretax equity earnings at PATH-WV.

GENERATION & MARKETING


	Three Months Ended						Six Months Ended
	June 30,						June 30,
Generation & Marketing	2020		2019		2020		2019
	(in millions)
Revenues	$	376.9	$	412.7	$	815.5	$	894.5
Fuel, Purchased Electricity and Other	298.5		330.7		658.8		714.0

Gross Margin	78.4		82.0		156.7		180.5
Other Operation and Maintenance	16.5		63.4		57.9		114.0


Depreciation and Amortization	17.9		15.6		35.6		28.5
Taxes Other Than Income Taxes	3.7		3.6		7.1		7.4
Operating Income (Loss)	40.3		(0.6)		56.1		30.6
Interest and Investment Income	1.2		1.8		2.2		4.1

Non-Service Cost Components of Net Periodic Benefit Cost	3.8		3.7		7.7		7.4
Interest Expense	(8.2)		(7.2)		(16.7)		(11.0)
Income (Loss) Before Income Tax Benefit and Equity Earnings (Loss)	37.1		(2.3)		49.3		31.1
Income Tax Benefit	(21.0)		(9.6)		(33.4)		(15.4)
Equity Earnings (Loss) of Unconsolidated Subsidiaries	0.4		(2.1)		6.3		(2.1)
Net Income	58.5		5.2		89.0		44.4
Net Loss Attributable to Noncontrolling Interests	(7.4)		(4.2)		(5.3)		(5.1)
Earnings Attributable to AEP Common Shareholders	$	65.9	$	9.4	$	94.3	$	49.5

Summary of MWhs Generated for Generation & Marketing


	Three Months Ended June 30,			Six Months Ended June 30,
	2020	2019	2020	2019
	(in millions of MWhs)
Fuel Type:
Coal	1	1	2	2
Renewables	1	1	2	1

Total MWhs	2	2	4	3

Second Quarter of 2020 Compared to Second Quarter of 2019


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

Second Quarter of 2019	$	9.4

Changes in Gross Margin:
Merchant Generation	(16.5)
Renewable Generation	8.1
Retail, Trading and Marketing	4.8
Total Change in Gross Margin	(3.6)

Changes in Expenses and Other:
Other Operation and Maintenance	46.9


Depreciation and Amortization	(2.3)
Taxes Other Than Income Taxes	(0.1)
Interest and Investment Income	(0.6)


Non-Service Cost Components of Net Periodic Benefit Cost	0.1
Interest Expense	(1.0)
Total Change in Expenses and Other	43.0

Income Tax Benefit	11.4
Equity Earnings (Loss) of Unconsolidated Subsidiaries	2.5
Net Loss Attributable to Noncontrolling Interests	3.2

Second Quarter of 2020	$	65.9

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 $17 million primarily due to lower capacity revenues and energy margins in 2020 and the retirement of the Conesville Plant Units 5 and 6 in 2019 and Unit 4 in 2020.

•Renewable Generation increased $8 million primarily due to the acquisition of Sempra Renewables LLC and new projects placed in-service.

•Retail, Trading and Marketing increased $5 million due to higher trading and marketing activity, partially offset by lower retail margins.

Expenses and Other, Income Tax Benefit, Equity Earnings of (Loss) Unconsolidated Subsidiaries and Net Loss Attributable to Noncontrolling Interests changed between years as follows:

•Other Operation and Maintenance expenses decreased $47 million primarily due to the following:

•A $19 million decrease related to the Oklaunion PPA with AEP Texas primarily due to an ARO revision.

•A $14 million decrease due to the retirement of Conesville Plant Units 5 and 6 in 2019 and Unit 4 in 2020.

•A $12 million decrease due to a gain recorded on the sale of land.

•Depreciation and Amortization expenses increased $2 million due to a higher depreciable base from increased investments in renewable energy sources.

•Income Tax Benefit increased $11 million primarily due to an increase in PTC.

•Equity Earnings (Loss) of Unconsolidated Subsidiaries increased $3 million primarily due to the Sempra Renewables LLC acquisition.

•Net Loss Attributable to Noncontrolling Interests increased $3 million primarily due to the Sempra Renewables LLC acquisition.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019


Reconciliation of Six Months Ended June 30, 2019 to Six Months Ended June 30, 2020
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)

Six Months Ended June 30, 2019	$	49.5

Changes in Gross Margin:
Merchant Generation	(53.9)
Renewable Generation	21.4
Retail, Trading and Marketing	8.7
Total Change in Gross Margin	(23.8)

Changes in Expenses and Other:
Other Operation and Maintenance	56.1


Depreciation and Amortization	(7.1)
Taxes Other Than Income Taxes	0.3
Interest and Investment Income	(1.9)

Non-Service Cost Components of Net Periodic Benefit Cost	0.3
Interest Expense	(5.7)
Total Change in Expenses and Other	42.0

Income Tax Benefit	18.0
Equity Earnings (Loss) of Unconsolidated Subsidiaries	8.4
Net Loss Attributable to Noncontrolling Interests	0.2

Six Months Ended June 30, 2020	$	94.3

•Merchant Generation decreased $54 million primarily due to the reduction of capacity revenues and energy margins in 2020 and the retirement of the Conesville Plant Units 5 and 6 in 2019 and Unit 4 in 2020.

•Renewable Generation increased $21 million primarily due to the Sempra Renewables LLC acquisition and other renewable projects placed in-service.

•Retail, Trading and Marketing increased $9 million due to higher trading and marketing activity, partially offset by lower retail margins.

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

•Other Operation and Maintenance expenses decreased $56 million due to the following:

•A $23 million decrease due to the retirement of Conesville Plant Units 5 and 6 in 2019 and Unit 4 in 2020.

•A $19 million decrease related to the Oklaunion PPA with AEP Texas primarily due to an ARO revision.

•A $15 million decrease due to a gain recorded on the sale of land.

•Depreciation and Amortization expenses increased $7 million due to a higher depreciable base from increased investments in renewable energy sources.

•Interest Expense increased $6 million primarily due to increased borrowing costs related to the Sempra Renewables LLC acquisition.

•Income Tax Benefit increased $18 million primarily due to an increase in PTC.

•Equity Earnings (Loss) of Unconsolidated Subsidiaries increased $8 million primarily due to the Sempra Renewables LLC acquisition.

CORPORATE AND OTHER

Second Quarter of 2020 Compared to Second Quarter of 2019

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $12 million in 2019 to a loss of $32 million in 2020 primarily due to:

•A $31 million increase in income tax expense due to an increase in consolidating tax adjustments and discrete items recorded in 2019.

This item was partially offset by:

•An $8 million decrease in general corporate expenses.

•A $7 million increase in interest income due to a higher return on investments held by EIS.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $62 million in 2019 to a loss of $67 million in 2020 primarily due to:

•A $14 million increase in interest expense as a result of increased debt outstanding.

•A $10 million increase in income tax expense due to an increase in consolidating tax adjustments and discrete items recorded in 2019.

•A $6 million decrease in interest income due to a lower return on investments held by EIS.

These items were partially offset by:

•A $17 million decrease in general corporate expenses.

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

AEP SYSTEM INCOME TAXES

Second Quarter of 2020 Compared to Second Quarter of 2019

Income Tax Expense increased $67 million primarily due to a decrease in amortization of Excess ADIT and an increase in pretax book income.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019

Income Tax Expense increased $69 million primarily due to a decrease in amortization of Excess ADIT.

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


	June 30, 2020						December 31, 2019
	(dollars in millions)
Long-term Debt, including amounts due within one year	$	28,775.4	55.2	%	$	26,725.5	54.1	%
Short-term Debt	3,076.6		5.9		2,838.3		5.7
Total Debt	31,852.0		61.1		29,563.8		59.8
AEP Common Equity	20,007.4		38.4		19,632.2		39.6
Noncontrolling Interests	270.8		0.5		281.0		0.6
Total Debt and Equity Capitalization	$	52,130.2	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 61.1% as of June 30, 2020 primarily due to an increase in debt to support distribution, transmission and renewable investment growth.

Liquidity

Liquidity, or access to cash, is an important factor in determining AEP’s financial stability. Management believes AEP has adequate liquidity under its existing credit facilities. As of June 30, 2020, AEP had a $4 billion revolving credit facility to support its commercial paper program. Additional liquidity is available from cash from operations and a receivables securitization agreement. Management is committed to maintaining adequate liquidity. AEP generally uses short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged. Sources of long-term funding include issuance of long-term debt, leasing agreements, hybrid securities or common stock. There was increased volatility in the capital markets during the first quarter of 2020 resulting in higher commercial paper cost and limited access. To address these issues and the uncertainty around COVID-19, in March 2020, AEP entered into a $1 billion 364-day Term Loan and borrowed the full amount.

Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments. As of June 30, 2020, available liquidity was approximately $2.9 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

348.8

Total Liquidity Sources

5,348.8

Less:

AEP Commercial Paper Outstanding

1,403.5

364-Day Term Loan

1,000.0

Net Available Liquidity

2,945.3

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 six months of 2020 was $3 billion. The weighted-average interest rate for AEP’s commercial paper during 2020 was 1.80%.

Other Credit Facilities

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under six uncommitted facilities totaling $405 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of June 30, 2020 was $192 million with maturities ranging from July 2020 to July 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 June 30, 2020, this contractually-defined percentage was 59.2%. Non-performance under these covenants could result in an event of default under these credit agreements. In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of AEP’s major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements. This condition also applies in a majority of AEP’s non-exchange-traded commodity contracts and would similarly allow lenders and counterparties to declare the outstanding amounts payable. However, a default under AEP’s non-exchange-traded commodity contracts would not cause an event of default under its credit agreements.

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

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

Equity Units

In March 2019, AEP issued 16.1 million Equity Units initially in the form of corporate units, at a stated amount of $50 per unit, for a total stated amount of $805 million. Net proceeds from the issuance were approximately $785 million. Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 3.40% Junior Subordinated Notes due in 2024 and a forward equity purchase contract which settles after three years in 2022. The proceeds from this issuance were used to support AEP’s overall capital expenditure plans including the acquisition of Sempra Renewables LLC. See Note 12 - Financing Activities for additional information.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.70 per share in July 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.


	Six Months Ended June 30,
	2020		2019
	(in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	$	432.6	$	444.1
Net Cash Flows from Operating Activities	1,746.2		1,800.8
Net Cash Flows Used for Investing Activities	(3,247.6)		(3,595.0)
Net Cash Flows from Financing Activities	1,573.5		1,739.8

Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	72.1		(54.4)
Cash, Cash Equivalents and Restricted Cash at End of Period	$	504.7	$	389.7

Operating Activities


	Six Months Ended June 30,
	2020		2019
	(in millions)
Net Income	$	1,013.8	$	1,033.2
Non-Cash Adjustments to Net Income (a)	1,390.8		1,159.7
Mark-to-Market of Risk Management Contracts	13.7		(72.9)

Property Taxes	173.6		137.6
Deferred Fuel Over/Under-Recovery, Net	76.0		36.7
Recovery of Ohio Capacity Costs	—		29.0
Refund of Global Settlement	—		(8.2)
Change in Other Noncurrent Assets	(75.6)		(73.5)
Change in Other Noncurrent Liabilities	(50.0)		(53.6)
Change in Certain Components of Working Capital	(796.1)		(387.2)
Net Cash Flows from Operating Activities	$	1,746.2	$	1,800.8

(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 $55 million primarily due to the following:

•A $409 million decrease in cash from the Change in Certain Components of Working Capital. The decrease is primarily due to timing of accounts receivable, an increase in employee-related payments and a decrease in current year employee-related expenses. These decreases were partially offset by an increased refund from the Department of Energy in the current year for SNF.

This decrease in cash was partially offset by:

•A $212 million increase in cash from Net Income, after non-cash adjustments. See Results of Operations for further detail.

•An $87 million increase in the fair value of risk management contracts due to pricing movement in the commodities markets.

•A $39 million increase in Deferred Fuel Over/Under-Recovery, Net primarily due to over-recoveries at I&M and SWEPCo due to decreased fuel costs partially offset by an under-recovery at PSO as a result of lower rates.

•A $36 million increase in Property Taxes primarily due to increased amortizations of prepaid property taxes at OPCo and AEP Ohio Transmission Company, Inc. as a result of increased investments and higher tax rates.

Investing Activities


	Six Months Ended June 30,
	2020		2019
	(in millions)
Construction Expenditures	$	(3,244.9)	$	(2,986.7)
Acquisitions of Nuclear Fuel	(37.7)		(33.8)


Acquisition of Sempra Renewables LLC, net of cash acquired	—		(581.2)
Other	35.0		6.7
Net Cash Flows Used for Investing Activities	$	(3,247.6)	$	(3,595.0)

Net Cash Flows Used for Investing Activities decreased by $347 million primarily due to the following:

•A $581 million decrease due to the 2019 acquisition of Sempra Renewables LLC. The $581 million represented a cash payment of $583 million, net of cash acquired of $2 million. See Note 6 - Acquisition and Dispositions for additional information.

This decrease in the use of cash was partially offset by:

•A $258 million increase due to increased construction expenditures, primarily due to increases at AEP Transmission Holdco of $149 million and Vertically Integrated Utilities of $69 million.

Financing Activities


	Six Months Ended June 30,
	2020		2019
	(in millions)
Issuance of Common Stock	$	111.0	$	32.3
Issuance/Retirement of Debt, Net	2,236.4		2,409.5

Dividends Paid on Common Stock	(704.6)		(668.1)
Other	(69.3)		(33.9)
Net Cash Flows from Financing Activities	$	1,573.5	$	1,739.8

Net Cash Flows from Financing Activities decreased by $166 million primarily due to the following:

•A $342 million decrease in issuances of long-term debt. See Note 12 - Financing Activities for additional information.

•A $129 million decrease in short-term debt primarily due to increased repayments of commercial paper. See Note 12 - Financing Activities for additional information.

These decreases in cash were partially offset by:

•A $295 million decrease in the retirement 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 June 30, 2020 through August 6, 2020, the date that the second quarter 10-Q was issued.

BUDGETED CAPITAL EXPENDITURES

Management currently estimates $5.9 billion of capital expenditures for 2020 and forecasts approximately $34.9 billion of capital expenditures for 2020 to 2024. Management has revised the capital expenditure forecast for 2020 to 2024 to include approximately $2 billion of capital expenditures for North Central Wind Energy Facilities. The expenditures are generally for transmission, generation, distribution, regulated and contracted renewables, and required environmental investment to comply with the Federal EPA rules. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital. Management expects to fund these capital expenditures through cash flows from operations and financing activities. Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged. For complete information of forecasted capital expenditures, see the “Budgeted Capital Expenditures” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2019 Annual Report.

CONTRACTUAL OBLIGATION INFORMATION

A summary of contractual obligations is included in the 2019 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING STANDARDS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

See the “Critical Accounting Policies and Estimates” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2019 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting standards.

ACCOUNTING STANDARDS

See Note 2 - New Accounting Standards for information related to accounting standards adopted in 2020 and standards effective in the future.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

The Vertically Integrated Utilities segment is exposed to certain market risks as a major power producer and through transactions in power, coal, natural gas and marketing contracts. These risks include commodity price risks which may be subject to capacity risk, credit risk as well as interest rate risk. These risks represent the risk of loss that may impact this segment due to changes in the underlying market prices or rates.

The Transmission and Distribution Utilities segment is exposed to energy procurement risk and interest rate risk.

The Generation & Marketing segment conducts marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. This segment is exposed to certain market risks as a marketer of wholesale and retail electricity. These risks include commodity price risks which may be subject to capacity risk, credit risk as well as interest rate risk. These risks represent the risk of loss that may impact this segment due to changes in the underlying market prices or rates. In addition, the Generation & Marketing segment is also exposed to certain market risks as a power producer and through transactions in wholesale electricity, natural gas and marketing contracts.

Management employs risk management contracts including physical forward and financial forward purchase-and-sale contracts. Management engages in risk management of power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. As a result, AEP is subject to price risk. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Financial Officer, Executive Vice President of Generation, Executive Vice President of Utilities, Senior Vice President of Commercial Operations, Senior Vice President of Treasury and Risk and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Financial Officer, Senior Vice President of Treasury and Risk and Chief Risk Officer in addition to Energy Supply’s President and Vice President. When commercial activities exceed predetermined limits, positions are modified to reduce the risk to be within the limits unless specifically approved by the respective committee.

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

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


MTM Risk Management Contract Net Assets (Liabilities)
Six Months Ended June 30, 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	(44.3)		(4.0)		(10.5)		(58.8)
Fair Value of New Contracts at Inception When Entered During the Period (a)	—		—		9.1		9.1

Changes in Fair Value Due to Market Fluctuations During the Period (b)	—		—		(0.3)		(0.3)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)	45.6		(10.7)		—		34.9
Total MTM Risk Management Contract Net Assets (Liabilities) as of June 30, 2020	$	77.2	$	(118.3)	$	161.7	120.6
Commodity Cash Flow Hedge Contracts							(100.9)
Interest Rate Cash Flow Hedge Contracts							(5.8)

Collateral Deposits							35.6

Total MTM Derivative Contract Net Assets as of June 30, 2020							$	49.5

(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 June 30, 2020, credit exposure net of collateral to sub investment grade counterparties was approximately 7.2%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss).

As of June 30, 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	$	428.7	$	—	$	428.7	3	$	238.9
Split Rating	1.7		—		1.7		1	1.7

No External Ratings:
Internal Investment Grade	135.2		—		135.2		3	89.0
Internal Noninvestment Grade	54.2		10.5		43.7		2	28.2
Total as of June 30, 2020	$	619.8	$	10.5	$	609.3

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 June 30, 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


Six Months Ended														Twelve Months Ended
June 30, 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


Six Months Ended														Twelve Months Ended
June 30, 2020														December 31, 2019
End		High		Average		Low		End		High		Average		Low
(in millions)														(in millions)
$	0.9	$	1.4	$	0.8	$	0.1	$	0.2	$	8.5	$	1.1	$	0.2

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

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

Interest Rate Risk

AEP is exposed to interest rate market fluctuations in the normal course of business operations. AEP has outstanding short and long-term debt which is subject to a variable rate. AEP manages interest rate risk by limiting variable-rate exposures to a percentage of total debt, by entering into interest rate derivative instruments and by monitoring the effects of market changes in interest rates. For the six months ended June 30, 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 $17 million and $24 million, respectively.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2020 and 2019

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

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020		2019		2020		2019
REVENUES
Vertically Integrated Utilities	$	2,062.3	$	2,116.4	$	4,255.3	$	4,488.7
Transmission and Distribution Utilities	1,009.4		1,001.6		2,084.6		2,181.4
Generation & Marketing	350.2		382.9		758.6		822.6
Other Revenues	72.1		72.7		143.0		137.7
TOTAL REVENUES	3,494.0		3,573.6		7,241.5		7,630.4

EXPENSES
Fuel and Other Consumables Used for Electric Generation	360.3		480.9		715.6		1,031.3
Purchased Electricity for Resale	604.6		660.7		1,400.3		1,522.5
Other Operation	566.0		607.4		1,168.1		1,273.4
Maintenance	243.4		348.7		492.9		623.2


Depreciation and Amortization	679.5		622.6		1,351.7		1,228.4
Taxes Other Than Income Taxes	317.5		302.3		638.6		612.2
TOTAL EXPENSES	2,771.3		3,022.6		5,767.2		6,291.0

OPERATING INCOME	722.7		551.0		1,474.3		1,339.4

Other Income (Expense):


Other Income	14.3		6.6		9.9		15.2
Allowance for Equity Funds Used During Construction	35.1		50.4		66.5		79.3
Non-Service Cost Components of Net Periodic Benefit Cost	29.8		30.0		59.5		60.0

Interest Expense	(294.0)		(250.7)		(586.1)		(506.5)

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS	507.9		387.3		1,024.1		987.4

Income Tax Expense (Benefit)	12.6		(54.4)		59.1		(9.9)
Equity Earnings of Unconsolidated Subsidiaries	19.2		17.4		48.8		35.9





NET INCOME	514.5		459.1		1,013.8		1,033.2

Net Loss Attributable to Noncontrolling Interests	(6.3)		(2.2)		(2.2)		(0.9)

EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	520.8	$	461.3	$	1,016.0	$	1,034.1

WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING	495,655,053		493,584,347		495,125,961		493,447,477



TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	1.05	$	0.93	$	2.05	$	2.10

WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING	497,337,980		495,382,966		496,973,449		494,934,320



TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	1.05	$	0.93	$	2.04	$	2.09

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Six Months Ended June 30, 2020 and 2019

(in millions)

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020		2019		2020		2019
Net Income	$	514.5	$	459.1	$	1,013.8	$	1,033.2

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $12.0 and $(20.9) for the Three Months Ended June 30, 2020 and 2019, Respectively, and $(5.8) and $(28.6) for the Six Months Ended June 30, 2020 and 2019, Respectively	45.3		(78.6)		(21.7)		(107.5)

Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.4) and $(0.3) for the Three Months Ended June 30, 2020 and 2019, Respectively, and $(0.9) and $(0.7) for the Six Months Ended June 30, 2020 and 2019, Respectively	(1.7)		(1.4)		(3.5)		(2.8)

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	43.6		(80.0)		(25.2)		(110.3)

TOTAL COMPREHENSIVE INCOME	558.1		379.1		988.6		922.9

Total Other Comprehensive Loss Attributable To Noncontrolling Interests	(6.3)		(2.2)		(2.2)		(0.9)

TOTAL OTHER COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	564.4	$	381.3	$	990.8	$	923.8

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Six Months Ended June 30, 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

Issuance of Common Stock	0.4	2.2		15.6											17.8
Common Stock Dividends							(332.7)		(b)			(1.8)			(334.5)
Other Changes in Equity				(3.1)								0.6			(2.5)
Acquisition of Sempra Renewables LLC												134.8			134.8
Net Income (Loss)							461.3					(2.2)			459.1
Other Comprehensive Loss										(80.0)					(80.0)
TOTAL EQUITY – JUNE 30, 2019	514.0	$	3,340.8	$	6,455.3		$	9,694.2		$	(230.7)	$	163.6		$	19,423.2








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)		(c)			(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

Issuance of Common Stock	0.8	5.2		49.7											54.9
Common Stock Dividends							(337.7)		(c)			(3.2)			(340.9)
Other Changes in Equity				(2.6)								1.0			(1.6)

Net Income (Loss)							520.8					(6.3)			514.5
Other Comprehensive Income										43.6					43.6
TOTAL EQUITY – JUNE 30, 2020	516.2	$	3,355.4	$	6,603.0		$	10,221.9		$	(172.9)	$	270.8		$	20,278.2

(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 $0.67.

(c)Cash dividends declared per AEP common share were $0.70.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2020 and December 31, 2019

(in millions)

(Unaudited)


	June 30,		December 31,
	2020		2019
CURRENT ASSETS
Cash and Cash Equivalents	$	348.8	$	246.8
Restricted Cash (June 30, 2020 and December 31, 2019 Amounts Include $155.9 and $185.8, Respectively, Related to Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Santa Rita East)	155.9		185.8
Other Temporary Investments (June 30, 2020 and December 31, 2019 Amounts Include $176.1 and $187.8, Respectively, Related to EIS and Transource Energy)	192.3		202.7
Accounts Receivable:
Customers	630.3		625.3
Accrued Unbilled Revenues	201.1		222.4
Pledged Accounts Receivable – AEP Credit	976.3		873.9
Miscellaneous	34.8		27.2
Allowance for Uncollectible Accounts	(51.0)		(43.7)
Total Accounts Receivable	1,791.5		1,705.1
Fuel	616.5		528.5
Materials and Supplies	663.3		640.7
Risk Management Assets	150.1		172.8

Regulatory Asset for Under-Recovered Fuel Costs	58.0		92.9
Margin Deposits	55.3		60.4

Prepayments and Other Current Assets	241.5		242.1
TOTAL CURRENT ASSETS	4,273.2		4,077.8

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	23,127.4		22,762.4
Transmission	25,921.8		24,808.6
Distribution	23,153.1		22,443.4
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	5,115.3		4,811.5
Construction Work in Progress	4,386.6		4,319.8
Total Property, Plant and Equipment	81,704.2		79,145.7
Accumulated Depreciation and Amortization	19,777.4		19,007.6
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	61,926.8		60,138.1

OTHER NONCURRENT ASSETS
Regulatory Assets	3,431.9		3,158.8
Securitized Assets	710.9		858.1
Spent Nuclear Fuel and Decommissioning Trusts	2,957.0		2,975.7
Goodwill	52.5		52.5
Long-term Risk Management Assets	247.1		266.6
Operating Lease Assets	912.9		957.4
Deferred Charges and Other Noncurrent Assets	3,292.5		3,407.3
TOTAL OTHER NONCURRENT ASSETS	11,604.8		11,676.4

TOTAL ASSETS	$	77,804.8	$	75,892.3

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

June 30, 2020 and December 31, 2019

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

(Unaudited)


			June 30,		December 31,
			2020		2019
CURRENT LIABILITIES
Accounts Payable			$	1,628.0	$	2,085.8
Short-term Debt:
Securitized Debt for Receivables – AEP Credit			634.0		710.0
Other Short-term Debt			2,442.6		2,128.3
Total Short-term Debt			3,076.6		2,838.3
Long-term Debt Due Within One Year (June 30, 2020 and December 31, 2019 Amounts Include $277.4 and $565.1, Respectively, Related to Transition Funding, DCC Fuel, Appalachian Consumer Rate Relief Funding, Transource Energy, Sabine and Restoration Funding)							2,137.7			1,598.7
Risk Management Liabilities			102.5		114.3
Customer Deposits			356.5		366.1
Accrued Taxes			1,212.5		1,357.8
Accrued Interest			261.3		243.6
Obligations Under Operating Leases			236.4		234.1
Regulatory Liability for Over-Recovered Fuel Costs					127.6		86.6

Other Current Liabilities			982.9		1,373.8
TOTAL CURRENT LIABILITIES			10,122.0		10,299.1

NONCURRENT LIABILITIES
Long-term Debt (June 30, 2020 and December 31, 2019 Amounts Include $994.5 and $907, Respectively, Related to Transition Funding, DCC Fuel, Appalachian Consumer Rate Relief Funding, Transource Energy, Sabine and Restoration Funding)							26,637.7			25,126.8
Long-term Risk Management Liabilities			245.2		261.8
Deferred Income Taxes			7,811.2		7,588.2
Regulatory Liabilities and Deferred Investment Tax Credits							8,242.9			8,457.6
Asset Retirement Obligations			2,471.0		2,216.6
Employee Benefits and Pension Obligations			459.9		466.0
Obligations Under Operating Leases			688.5		734.6
Deferred Credits and Other Noncurrent Liabilities							715.4			719.8
TOTAL NONCURRENT LIABILITIES			47,271.8		45,571.4

TOTAL LIABILITIES			57,393.8		55,870.5

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

MEZZANINE EQUITY
Redeemable Noncontrolling Interest			63.7		65.7
Contingently Redeemable Performance Share Awards			69.1		42.9
TOTAL MEZZANINE EQUITY			132.8		108.6

EQUITY
Common Stock – Par Value – $6.50 Per Share:
	2020	2019
Shares Authorized	600,000,000	600,000,000
Shares Issued	516,214,732	514,373,631
(20,204,160 Shares were Held in Treasury as of June 30, 2020 and December 31, 2019, Respectively)							3,355.4			3,343.4
Paid-in Capital			6,603.0		6,535.6
Retained Earnings			10,221.9		9,900.9
Accumulated Other Comprehensive Income (Loss)							(172.9)			(147.7)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY							20,007.4			19,632.2

Noncontrolling Interests			270.8		281.0

TOTAL EQUITY			20,278.2		19,913.2

TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY								$	77,804.8		$	75,892.3

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2020 and 2019

(in millions)

(Unaudited)


	Six Months Ended June 30,
	2020		2019
OPERATING ACTIVITIES
Net Income	$	1,013.8	$	1,033.2


Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	1,351.7		1,228.4

Deferred Income Taxes	60.0		(35.5)


Allowance for Equity Funds Used During Construction	(66.5)		(79.3)
Mark-to-Market of Risk Management Contracts	13.7		(72.9)
Amortization of Nuclear Fuel	45.6		46.1

Property Taxes	173.6		137.6
Deferred Fuel Over/Under-Recovery, Net	76.0		36.7


Recovery of Ohio Capacity Costs	—		29.0
Refund of Global Settlement	—		(8.2)
Change in Other Noncurrent Assets	(75.6)		(73.5)
Change in Other Noncurrent Liabilities	(50.0)		(53.6)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(80.7)		165.5
Fuel, Materials and Supplies	(120.3)		(114.6)
Accounts Payable	(64.7)		(72.4)
Accrued Taxes, Net	(164.4)		(170.1)
Other Current Assets	18.8		27.4
Other Current Liabilities	(384.8)		(223.0)
Net Cash Flows from Operating Activities	1,746.2		1,800.8

INVESTING ACTIVITIES
Construction Expenditures	(3,244.9)		(2,986.7)

Purchases of Investment Securities	(988.4)		(235.5)
Sales of Investment Securities	971.3		199.5
Acquisitions of Nuclear Fuel	(37.7)		(33.8)
Acquisition of Sempra Renewables LLC, net of cash acquired	—		(581.2)



Other Investing Activities	52.1		42.7
Net Cash Flows Used for Investing Activities	(3,247.6)		(3,595.0)

FINANCING ACTIVITIES
Issuance of Common Stock	111.0		32.3
Issuance of Long-term Debt	2,431.3		2,773.7
Issuance of Short-term Debt with Original Maturities greater than 90 Days	1,304.5		—
Change in Short-term Debt with Original Maturities less than 90 Days, Net	(766.2)		367.0
Retirement of Long-term Debt	(433.2)		(728.2)
Make Whole Premium on Extinguishment of Long-term Debt	—		(3.0)
Redemption of Short-term Debt with Original Maturities Greater than 90 Days	(300.0)		—
Principal Payments for Finance Lease Obligations	(31.3)		(29.6)
Dividends Paid on Common Stock	(704.6)		(668.1)
Other Financing Activities	(38.0)		(4.3)
Net Cash Flows from Financing Activities	1,573.5		1,739.8





Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	72.1		(54.4)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	432.6		444.1
Cash, Cash Equivalents and Restricted Cash at End of Period	$	504.7	$	389.7

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	481.2	$	490.2
Net Cash Paid for Income Taxes	3.1		19.7
Noncash Acquisitions Under Finance Leases	26.8		44.4
Construction Expenditures Included in Current Liabilities as of June 30,	833.3		904.8
Construction Expenditures Included in Noncurrent Liabilities as of June 30,	8.3		—
Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30,	22.3		50.5

Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage	2.2		—
Noncontrolling Interest assumed with Sempra Renewable LLC Business Acquisition	—		134.8
Liabilities assumed with Sempra Renewable LLC Business Acquisition	—		18.6

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

AEP TEXAS INC.

AND SUBSIDIARIES

AEP TEXAS INC. AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales


	Three Months Ended			Six Months Ended
	June 30,			June 30,
	2020	2019	2020	2019
	(in millions of KWhs)
Retail:
Residential	3,158	3,008	5,624	5,432
Commercial	2,402	2,754	4,759	4,845
Industrial	2,216	2,240	4,581	4,388
Miscellaneous	150	170	302	315
Total Retail	7,926	8,172	15,266	14,980

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			Six Months Ended
	June 30,			June 30,
	2020	2019	2020	2019
	(in degree days)
Actual – Heating (a)	6	3	97	180
Normal – Heating (b)	3	3	188	190

Actual – Cooling (c)	936	970	1,167	1,092
Normal – Cooling (b)	933	934	1,058	1,057

(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.

Second Quarter of 2020 Compared to Second Quarter of 2019


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

Second Quarter of 2019	$	80.6

Changes in Gross Margin:
Retail Margins	(15.4)
Margins from Off-system Sales	(19.6)
Transmission Revenues	(6.7)
Other Revenues	10.5
Total Change in Gross Margin	(31.2)

Changes in Expenses and Other:
Other Operation and Maintenance	85.1
Depreciation and Amortization	(9.9)


Interest Income	(0.6)

Allowance for Equity Funds Used During Construction	3.5

Interest Expense	(22.7)
Total Change in Expenses and Other	55.4

Income Tax Benefit	(37.9)

Second Quarter of 2020	$	66.9

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

•Retail Margins decreased $15 million primarily due to the following:

•A $10 million decrease in weather-normalized margins primarily in the commercial class.

•A $7 million decrease due to refunds of Excess ADIT not subject to normalization requirements. This decrease was offset in Income Tax Benefit below.

These decreases were partially offset by:

•A $4 million increase due to the change in the recording of merger savings as authorized by the PUCT in the most recent base rate case.

•Margins for Off-system Sales decreased $20 million primarily due to lower Oklaunion Power Station PPA revenues. This decrease was offset in Other Operation and Maintenance expenses below.

•Transmission Revenues decreased $7 million primarily due to:

•A $17 million decrease due to a one-time credit to transmission customers as a result of Tax Reform and the most recent base rate case. This decrease was offset in Income Tax Benefit below.

This decrease was partially offset by:

•A $10 million increase due to recovery of increased transmission investment in ERCOT.

•Other Revenues increased $11 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 Benefit changed between years as follows:

•Other Operation and Maintenance expenses decreased $85 million primarily due to the following:

•A $17 million decrease due to the revision of the Oklaunion Power Station ARO. This decrease was offset in Margins for Off-System Sales above.

•Depreciation and Amortization expenses increased $10 million primarily due to the following:

•A $7 million increase in securitization amortizations. This increase was offset in Other Revenues above and in Interest Expense below.

•A $3 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 $4 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 $23 million primarily due to the prior year deferral of previously recorded interest expense approved for recovery as a result of the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019.

•Income Tax Benefit decreased $38 million primarily due to the prior year amortization of Excess ADIT not subject to normalization requirements as approved in the Texas Storm Cost Securitization financing order issued by the PUCT in 2019 and an increase in pretax book income. This decrease was partially offset above in Gross Margins and in Other Operation and Maintenance expenses.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019


Reconciliation of Six Months Ended June 30, 2019 to Six Months Ended June 30, 2020
Net Income
(in millions)

Six Months Ended June 30, 2019	$	115.0

Changes in Gross Margin:
Retail Margins	4.1
Margins from Off-system Sales	(19.8)
Transmission Revenues	4.6
Other Revenues	22.2
Total Change in Gross Margin	11.1

Changes in Expenses and Other:
Other Operation and Maintenance	82.1
Depreciation and Amortization	(33.5)
Taxes Other Than Income Taxes	2.5

Interest Income	(0.4)

Allowance for Equity Funds Used During Construction	6.8

Interest Expense	(27.8)
Total Change in Expenses and Other	29.7

Income Tax Benefit	(41.3)

Six Months Ended June 30, 2020	$	114.5

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 $4 million primarily due to the following:

•A $6 million increase in revenues associated with the Transmission Cost Recovery Factor revenue rider.

•A $5 million increase in weather-normalized margins primarily driven by the residential class partially offset by a decrease in the industrial class.

•A $4 million increase due to the change in the recording of merger savings as authorized by the PUCT in the most recent base rate case.

These increases were partially offset by:

•A $7 million decrease due to refunds of Excess ADIT not subject to normalization requirements. This decrease was offset in Income Tax Benefit below.

•A $4 million decrease in weather-related usage primarily due to a 46% decrease in heating degree days.

•Margins from Off-system Sales decreased $20 million primarily due to lower Oklaunion Power Station PPA revenues. This decrease was offset in Other Operation and Maintenance expenses below.

•Transmission Revenues increased $5 million primarily due to the following:

•A $22 million increase primarily due to recovery of increased transmission investment in ERCOT.

This increase was partially offset by:

•A $17 million decrease due to a one-time credit to transmission customers as a result of Tax Reform and the most recent base rate case. This decrease was offset in Income Tax Benefit below.

•Other Revenues increased $22 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 Benefit changed between years as follows:

•Other Operation and Maintenance expenses decreased $82 million primarily due to the following:

•A $17 million decrease due to the revision of the Oklaunion Power Station ARO. This decrease was offset in Margins for Off-System Sales above.

•Depreciation and Amortization expenses increased $34 million primarily due to the following:

•A $19 million increase in securitization amortizations. This increase was offset in Other Revenues above and in Interest Expense below.

•A $14 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 $7 million primarily 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 $28 million primarily due to:

•A $19 million increase due to the prior year deferral of previously recorded interest expense approved for recovery as a result of the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019.

•A $5 million increase due to higher long-term debt balances.

•Income Tax Benefit decreased $41 million primarily due to the prior year amortization of Excess ADIT not subject to normalization requirements as approved in the Texas Storm Cost Securitization financing order issued by the PUCT in 2019 and an increase in pretax book income. This decrease was partially offset above in Gross Margins and in Other Operation and Maintenance expenses.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2020 and 2019

(in millions)

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020		2019		2020		2019
REVENUES
Electric Transmission and Distribution	$	383.5	$	395.1	$	775.1	$	744.9
Sales to AEP Affiliates	16.9		42.2		48.0		82.4
Other Revenues	1.1		0.7		2.0		1.4
TOTAL REVENUES	401.5		438.0		825.1		828.7

EXPENSES
Fuel and Other Consumables Used for Electric Generation	3.2		8.5		3.2		17.9
Other Operation	92.9		111.2		210.4		221.0
Maintenance	23.1		89.9		43.7		115.2
Depreciation and Amortization	165.6		155.7		328.1		294.6
Taxes Other Than Income Taxes	34.0		34.0		68.0		70.5
TOTAL EXPENSES	318.8		399.3		653.4		719.2

OPERATING INCOME	82.7		38.7		171.7		109.5

Other Income (Expense):
Interest Income	0.1		0.7		0.7		1.1

Allowance for Equity Funds Used During Construction	4.9		1.4		10.0		3.2

Non-Service Cost Components of Net Periodic Benefit Cost	2.8		2.8		5.6		5.6
Interest Expense	(42.2)		(19.5)		(84.7)		(56.9)

INCOME BEFORE INCOME TAX BENEFIT	48.3		24.1		103.3		62.5

Income Tax Benefit	(18.6)		(56.5)		(11.2)		(52.5)

NET INCOME	$	66.9	$	80.6	$	114.5	$	115.0


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

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Six Months Ended June 30, 2020 and 2019

(in millions)

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020		2019		2020		2019
Net Income	$	66.9	$	80.6	$	114.5	$	115.0

OTHER COMPREHENSIVE INCOME, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2020 and 2019, Respectively, and $0.1 and $0.1 for the Six Months Ended June 30, 2020 and 2019, Respectively	0.2		0.2		0.5		0.5
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2020 and 2019, Respectively, and $0 and $0 for the Six Months Ended June 30, 2020 and 2019, Respectively	0.1		0.1		0.1		0.1

TOTAL OTHER COMPREHENSIVE INCOME	0.3		0.3		0.6		0.6

TOTAL COMPREHENSIVE INCOME	$	67.2	$	80.9	$	115.1	$	115.6



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Six Months Ended June 30, 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


Net Income			80.6				80.6
Other Comprehensive Income					0.3		0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2019	$	1,457.9	$	1,452.7	$	(14.5)	$	2,896.1






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


Net Income			66.9				66.9
Other Comprehensive Income					0.3		0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2020	$	1,457.9	$	1,630.5	$	(12.2)	$	3,076.2



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2020 and December 31, 2019

(in millions)

(Unaudited)


	June 30,		December 31,
	2020		2019
CURRENT ASSETS
Cash and Cash Equivalents	$	0.1	$	3.1
Restricted Cash  (June 30, 2020 and December 31, 2019 Amounts Include $136.6 and $154.7, Respectively, Related to Transition Funding and Restoration Funding)	136.6		154.7
Advances to Affiliates	7.2		207.2
Accounts Receivable:
Customers	142.7		116.0
Affiliated Companies	50.3		10.1
Accrued Unbilled Revenues	56.3		68.8
Miscellaneous	0.1		0.3
Allowance for Uncollectible Accounts	(1.9)		(1.8)
Total Accounts Receivable	247.5		193.4
Fuel	6.8		5.9
Materials and Supplies	67.2		56.7

Accrued Tax Benefits	6.5		66.1
Prepayments and Other Current Assets	3.4		5.8
TOTAL CURRENT ASSETS	475.3		692.9

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	351.6		351.7
Transmission	4,794.4		4,466.5
Distribution	4,392.8		4,215.2
Other Property, Plant and Equipment	853.8		805.9
Construction Work in Progress	776.1		763.9
Total Property, Plant and Equipment	11,168.7		10,603.2
Accumulated Depreciation and Amortization	1,832.7		1,758.1
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	9,336.0		8,845.1

OTHER NONCURRENT ASSETS
Regulatory Assets	278.7		280.6
Securitized Assets (June 30, 2020 and December 31, 2019 Amounts Include $488.6 and $621.2, Respectively, Related to Transition Funding and Restoration Funding)	488.6		623.4

Deferred Charges and Other Noncurrent Assets	198.4		147.1
TOTAL OTHER NONCURRENT ASSETS	965.7		1,051.1

TOTAL ASSETS	$	10,777.0	$	10,589.1



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

June 30, 2020 and December 31, 2019

(in millions)

(Unaudited)


	June 30,		December 31,
	2020		2019
CURRENT LIABILITIES
Advances from Affiliates	$	320.4	$	—
Accounts Payable:
General	261.2		256.8
Affiliated Companies	30.0		35.6
Short-term Debt – Nonaffiliated	2.0		—
Long-term Debt Due Within One Year – Nonaffiliated (June 30, 2020 and December 31, 2019 Amounts Include $179.1 and $281.4, Respectively, Related to Transition Funding and Restoration Funding)	239.1		392.1
Risk Management Liabilities	0.1		—

Accrued Taxes	104.6		84.9
Accrued Interest (June 30, 2020 and December 31, 2019 Amounts Include $5 and $7.5, Respectively, Related to Transition Funding and Restoration Funding)	40.9		35.7
Oklaunion Purchase Power Agreement	7.7		22.1
Obligations Under Operating Leases	13.6		12.0
Provision for Refund	47.3		64.7
Other Current Liabilities	94.9		123.3
TOTAL CURRENT LIABILITIES	1,161.8		1,027.2

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated (June 30, 2020 and December 31, 2019 Amounts Include $451.4 and $495.4, Respectively, Related to Transition Funding and Restoration Funding)	4,123.5		4,166.3

Deferred Income Taxes	969.9		965.4
Regulatory Liabilities and Deferred Investment Tax Credits	1,301.5		1,316.9

Obligations Under Operating Leases	74.0		71.1
Deferred Credits and Other Noncurrent Liabilities	70.1		81.1
TOTAL NONCURRENT LIABILITIES	6,539.0		6,600.8

TOTAL LIABILITIES	7,700.8		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	1,630.5		1,516.0
Accumulated Other Comprehensive Income (Loss)	(12.2)		(12.8)
TOTAL COMMON SHAREHOLDER’S EQUITY	3,076.2		2,961.1

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	10,777.0	$	10,589.1



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2020 and 2019

(in millions)

(Unaudited)


	Six Months Ended June 30,
	2020		2019
OPERATING ACTIVITIES
Net Income	$	114.5	$	115.0
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	328.1		294.6
Deferred Income Taxes	(33.9)		(59.9)
Allowance for Equity Funds Used During Construction	(10.0)		(3.2)
Mark-to-Market of Risk Management Contracts	0.1		—

Property Taxes	(43.2)		(45.0)

Change in Other Noncurrent Assets	(54.1)		24.4
Change in Other Noncurrent Liabilities	(2.5)		5.6
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(54.1)		(46.2)
Fuel, Materials and Supplies	(11.4)		0.8
Accounts Payable	22.1		1.8

Accrued Taxes, Net	79.3		26.4

Other Current Assets	1.6		2.0
Other Current Liabilities	(38.7)		(21.8)
Net Cash Flows from Operating Activities	297.8		294.5

INVESTING ACTIVITIES
Construction Expenditures	(662.0)		(671.6)
Change in Advances to Affiliates, Net	200.0		0.3

Other Investing Activities	17.1		7.6
Net Cash Flows Used for Investing Activities	(444.9)		(663.7)

FINANCING ACTIVITIES
Capital Contribution from Parent	—		200.0
Issuance of Long-term Debt – Nonaffiliated	—		295.6
Change in Short-term Debt, Net – Nonaffiliated	2.0		—
Change in Advances from Affiliates, Net	320.4		23.0
Retirement of Long-term Debt – Nonaffiliated	(193.8)		(181.8)
Principal Payments for Finance Lease Obligations	(3.1)		(2.5)

Other Financing Activities	0.5		0.6
Net Cash Flows from Financing Activities	126.0		334.9

Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding	(21.1)		(34.3)
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	$	136.7	$	125.5

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	74.3	$	73.4
Net Cash Paid (Received) for Income Taxes	(24.9)		14.4
Noncash Acquisitions Under Finance Leases	4.3		4.4
Construction Expenditures Included in Current Liabilities as of June 30,	192.3		192.9



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

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 June 30,
	2020		2019
	(in millions)
Plant In Service	$	8,931.5	$	7,122.5
Construction Work in Progress	1,613.9		1,785.0
Accumulated Depreciation and Amortization	488.3		336.6
Total Transmission Property, Net	$	10,057.1	$	8,570.9

Second Quarter of 2020 Compared to Second Quarter of 2019


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

Second Quarter of 2019	$	136.0

Changes in Transmission Revenues:
Transmission Revenues	(28.8)
Total Change in Transmission Revenues	(28.8)

Changes in Expenses and Other:
Other Operation and Maintenance	(1.8)
Depreciation and Amortization	(16.1)
Taxes Other Than Income Taxes	(8.3)
Interest Income	0.7
Allowance for Equity Funds Used During Construction	(10.3)
Interest Expense	(11.4)
Total Change in Expenses and Other	(47.2)

Income Tax Expense	13.7


Second Quarter of 2020	$	73.7

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

•Transmission Revenues decreased $29 million primarily due to the following:

•A $62 million decrease as a result of the affiliated annual transmission formula rate true-up which is offset in Other Operation and Maintenance expense across the other Registrant subsidiaries.

•A $17 million decrease as a result of the non-affiliated annual transmission formula rate true-up.

These decreases were partially offset by:

•A $50 million increase due to continued investment in transmission assets.

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

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

•Taxes Other Than Income Taxes increased $8 million primarily due to higher property taxes as a result of increased transmission investment.

•Allowance for Equity Funds Used During Construction decreased $10 million primarily due to the following:

•A $12 million decrease driven by the favorable impact of a FERC settlement agreement recorded in 2019.

•A $2 million decrease due to lower CWIP.

These decreases were partially offset by:

•A $4 million increase driven by FERC audit findings recorded in 2019.

•Interest Expense increased $11 million primarily due to higher long-term debt balances.

•Income Tax Expense decreased $14 million primarily due to lower pretax book income.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019


Reconciliation of Six Months Ended June 30, 2019 to Six Months Ended June 30, 2020
Net Income
(in millions)

Six Months Ended June 30, 2019	$	240.3

Changes in Transmission Revenues:
Transmission Revenues	23.3
Total Change in Transmission Revenues	23.3

Changes in Expenses and Other:
Other Operation and Maintenance	(8.6)
Depreciation and Amortization	(31.8)
Taxes Other Than Income Taxes	(17.3)
Interest Income	0.8
Allowance for Equity Funds Used During Construction	(5.4)
Interest Expense	(19.3)
Total Change in Expenses and Other	(81.6)

Income Tax Expense	9.5

Six Months Ended June 30, 2020	$	191.5

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

•Transmission Revenues increased $23 million primarily due to the following:

•A $102 million increase due to continued investment in transmission assets.

This increase was partially offset by:

•A $62 million decrease as a result of the affiliated annual transmission formula rate true-up which is offset in Other Operation and Maintenance expense across the other Registrant subsidiaries.

•A $17 million decrease as a result of the non-affiliated annual transmission formula rate true-up.

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

•Other Operation and Maintenance expenses increased $9 million primarily due to the following:

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

•A $4 million increase in rent expense.

•Depreciation and Amortization expenses increased $32 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $17 million primarily due to higher property taxes as a result of increased transmission investment.

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

•A $12 million decrease driven by the favorable impact of a FERC settlement agreement recorded in 2019.

•A $6 million decrease due to lower CWIP.

These decreases were partially offset by:

•A $13 million increase driven by FERC audit findings recorded in 2019.

•Interest Expense increased $19 million primarily due to higher long-term debt balances.

•Income Tax Expense decreased $10 million primarily due to lower pretax book income.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2020 and 2019

(in millions)

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020		2019		2020		2019
REVENUES
Transmission Revenues	$	60.4	$	57.8	$	121.7	$	108.1
Sales to AEP Affiliates	177.7		209.1		411.4		402.3
Other Revenues	—		—		0.6		—
TOTAL REVENUES	238.1		266.9		533.7		510.4

EXPENSES
Other Operation	22.9		18.7		46.7		35.7
Maintenance	0.1		2.5		3.3		5.7
Depreciation and Amortization	58.9		42.8		114.9		83.1
Taxes Other Than Income Taxes	50.2		41.9		100.6		83.3
TOTAL EXPENSES	132.1		105.9		265.5		207.8

OPERATING INCOME	106.0		161.0		268.2		302.6

Other Income (Expense):
Interest Income - Affiliated	1.3		0.6		2.1		1.3
Allowance for Equity Funds Used During Construction	18.5		28.8		34.7		40.1

Interest Expense	(32.8)		(21.4)		(62.4)		(43.1)

INCOME BEFORE INCOME TAX EXPENSE	93.0		169.0		242.6		300.9

Income Tax Expense	19.3		33.0		51.1		60.6

NET INCOME	$	73.7	$	136.0	$	191.5	$	240.3


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY

For the Six Months Ended June 30, 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


Net Income			136.0		136.0
TOTAL MEMBER'S EQUITY – JUNE 30, 2019	$	2,480.6	$	1,329.5	$	3,810.1





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


Dividends Paid to AEP Transmission Holdco			(5.0)		(5.0)
Net Income			73.7		73.7
TOTAL MEMBER'S EQUITY – JUNE 30, 2020	$	2,665.6	$	1,715.4	$	4,381.0


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2020 and December 31, 2019

(in millions)

(Unaudited)


	June 30,		December 31,
	2020		2019
CURRENT ASSETS
Advances to Affiliates	$	121.3	$	85.4
Accounts Receivable:
Customers	35.1		19.0
Affiliated Companies	124.7		66.1

Total Accounts Receivable	159.8		85.1
Materials and Supplies	13.4		13.8
Accrued Tax Benefits	0.1		9.3
Prepayments and Other Current Assets	3.3		3.8
TOTAL CURRENT ASSETS	297.9		197.4

TRANSMISSION PROPERTY
Transmission Property	8,642.0		8,137.9
Other Property, Plant and Equipment	289.5		269.6
Construction Work in Progress	1,613.9		1,485.7
Total Transmission Property	10,545.4		9,893.2
Accumulated Depreciation and Amortization	488.3		402.3
TOTAL TRANSMISSION PROPERTY – NET	10,057.1		9,490.9

OTHER NONCURRENT ASSETS

Regulatory Assets	7.6		4.2
Deferred Property Taxes	109.2		193.5
Deferred Charges and Other Noncurrent Assets	3.9		4.8
TOTAL OTHER NONCURRENT ASSETS	120.7		202.5

TOTAL ASSETS	$	10,475.7	$	9,890.8


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND MEMBER’S EQUITY

June 30, 2020 and December 31, 2019

(in millions)

(Unaudited)


	June 30,		December 31,
	2020		2019
CURRENT LIABILITIES
Advances from Affiliates	$	4.0	$	137.0
Accounts Payable:
General	308.0		493.4
Affiliated Companies	61.5		71.2

Accrued Taxes	291.7		355.6
Accrued Interest	23.9		19.2
Obligations Under Operating Leases	1.9		2.1
Other Current Liabilities	14.8		14.6
TOTAL CURRENT LIABILITIES	705.8		1,093.1

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	3,947.4		3,427.3
Deferred Income Taxes	847.3		817.8
Regulatory Liabilities	562.6		540.9
Obligations Under Operating Leases	1.2		1.9
Deferred Credits and Other Noncurrent Liabilities	30.4		0.3
TOTAL NONCURRENT LIABILITIES	5,388.9		4,788.2

TOTAL LIABILITIES	6,094.7		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	1,715.4		1,528.9
TOTAL MEMBER’S EQUITY	4,381.0		4,009.5

TOTAL LIABILITIES AND MEMBER’S EQUITY	$	10,475.7	$	9,890.8


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2020 and 2019

(in millions)

(Unaudited)


	Six Months Ended June 30,
	2020		2019
OPERATING ACTIVITIES
Net Income	$	191.5	$	240.3
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	114.9		83.1
Deferred Income Taxes	22.6		19.7
Allowance for Equity Funds Used During Construction	(34.7)		(40.1)
Property Taxes	84.3		68.3
Long-term Accounts Receivable – Affiliated	—		(7.8)
Change in Other Noncurrent Assets	(2.6)		3.6
Change in Other Noncurrent Liabilities	30.6		(6.4)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(74.7)		(31.7)
Materials and Supplies	0.4		1.8
Accounts Payable	10.5		6.3
Accrued Taxes, Net	(54.7)		(43.1)
Accrued Interest	4.7		0.4
Other Current Assets	0.5		—
Other Current Liabilities	(0.2)		(0.2)
Net Cash Flows from Operating Activities	293.1		294.2

INVESTING ACTIVITIES
Construction Expenditures	(825.4)		(661.5)
Change in Advances to Affiliates, Net	(35.9)		45.7
Acquisitions of Assets	(2.4)		(2.6)

Other Investing Activities	4.2		4.8
Net Cash Flows Used for Investing Activities	(859.5)		(613.6)

FINANCING ACTIVITIES
Capital Contributions from Member	185.0		—
Issuance of Long-term Debt – Nonaffiliated	519.4		344.3
Change in Advances from Affiliates, Net	(133.0)		(24.9)
Dividends Paid to AEP Transmission Holdco	(5.0)		—

Net Cash Flows from Financing Activities	566.4		319.4

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	$	55.8	$	41.0
Net Cash Paid for Income Taxes	13.5		17.4
Construction Expenditures Included in Current Liabilities as of June 30,	263.8		278.5


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

APPALACHIAN POWER COMPANY

AND SUBSIDIARIES

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales


	Three Months Ended			Six Months Ended
	June 30,			June 30,
	2020	2019	2020	2019
	(in millions of KWhs)
Retail:
Residential	2,288	2,086	5,457	5,673
Commercial	1,321	1,495	2,798	3,091
Industrial	2,077	2,357	4,314	4,693
Miscellaneous	175	205	382	424
Total Retail	5,861	6,143	12,951	13,881

Wholesale	1,235	913	1,707	1,729

Total KWhs	7,096	7,056	14,658	15,610

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			Six Months Ended
	June 30,			June 30,
	2020	2019	2020	2019
	(in degree days)
Actual – Heating (a)	144	43	1,097	1,295
Normal – Heating (b)	87	92	1,411	1,404

Actual – Cooling (c)	346	459	366	459
Normal – Cooling (b)	377	372	383	379

(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.

Second Quarter of 2020 Compared to Second Quarter of 2019


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

Second Quarter of 2019	$	55.5

Changes in Gross Margin:
Retail Margins	13.5
Margins from Off-system Sales	(1.4)
Transmission Revenues	(7.2)
Other Revenues	(1.8)
Total Change in Gross Margin	3.1

Changes in Expenses and Other:
Other Operation and Maintenance	45.0
Depreciation and Amortization	(3.5)
Taxes Other Than Income Taxes	(1.6)
Interest Income	(0.5)

Allowance for Equity Funds Used During Construction	(3.6)
Non-Service Cost Components of Net Periodic Benefit Cost	0.5
Interest Expense	(2.5)
Total Change in Expenses and Other	33.8

Income Tax Expense	(11.1)

Second Quarter of 2020	$	81.3

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

•A $6 million increase due to a decrease in customer refunds related to Tax Reform. This increase was partially offset in Income Tax Expense below.

•A $6 million increase in deferred fuel primarily due to the timing of recoverable PJM expenses. This increase was offset in other expense items below.

•A $4 million increase due to the WVPSC’s approval of the Mitchell Plant surcharge effective January 2020.

These increases were partially offset by:

•A $5 million decrease in weather-normalized margins primarily in the commercial and industrial classes, partially offset in residential.

•Transmission Revenue decreased $7 million primarily due to the annual transmission formula rate true-up.

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

•Other Operation and Maintenance expenses decreased $45 million primarily due to the following:

•A $24 million decrease in PJM expenses primarily related to the annual transmission formula rate true-up.

•A $12 million decrease as a result of prior year contributions to benefit low income West Virginia residential customers as a result of the West Virginia Tax Reform settlement. This decrease was offset in Income Tax Expense below.

•An $11 million decrease in maintenance expense at various generation plants.

•A $7 million decrease in employee-related expenses.

These decreases were partially offset by:

•A $13 million increase in recoverable PJM transmission expenses which were partially offset within Retail Margins above.

•Income Tax Expense increased $11 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.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019


Reconciliation of Six Months Ended June 30, 2019 to Six Months Ended June 30, 2020
Net Income
(in millions)

Six Months Ended June 30, 2019	$	189.2

Changes in Gross Margin:
Retail Margins	28.0
Margins from Off-system Sales	(2.0)
Transmission Revenues	(5.9)
Other Revenues	(0.1)
Total Change in Gross Margin	20.0

Changes in Expenses and Other:
Other Operation and Maintenance	59.1
Depreciation and Amortization	(13.2)
Taxes Other Than Income Taxes	(3.6)
Interest Income	(1.0)

Allowance for Equity Funds Used During Construction	(2.9)
Non-Service Cost Components of Net Periodic Benefit Cost	0.9
Interest Expense	(6.3)
Total Change in Expenses and Other	33.0

Income Tax Expense (Benefit)	(45.6)

Six Months Ended June 30, 2020	$	196.6

•Retail Margins increased $28 million primarily due to the following:

•A $23 million increase due to a decrease in customer refunds related to Tax Reform. This increase was partially offset in Income Tax Expense below.

•A $20 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 APCo 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. This increase was partially offset in Depreciation and Amortization expenses below.

•An $8 million increase due to the WVPSC’s approval of the Mitchell Plant surcharge effective January 2020.

These increases were partially offset by:

•A $34 million decrease in weather-related usage primarily driven by a 20% decrease in cooling degree days and a 15% decrease in heating degree days.

•A $13 million decrease in weather-normalized margins primarily in the commercial and industrial classes, partially offset in residential.

•Transmission Revenues decreased $6 million primarily due to the annual transmission formula rate true-up.

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

•Other Operation and Maintenance expenses decreased $59 million primarily due to the following:

•A $29 million decrease in PJM expenses primarily related to the annual transmission formula rate true-up.

•A $16 million decrease in employee-related expenses.

•A $16 million decrease in maintenance expense at various generation plants.

•A $14 million decrease as a result of prior year contributions to benefit low income West Virginia residential customers as a result of the West Virginia Tax Reform settlement. This decrease was offset in Income Tax Expense below.

These decreases were partially offset by:

•An $18 million increase in recoverable PJM transmission expenses. This increase is partially offset within Retail Margins above.

•Depreciation and Amortization expenses increased $13 million primarily due to a higher depreciable base and an increase in West Virginia depreciation rates beginning in March 2019. This increase was partially offset within Retail Margins above.

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

•Income Tax Expense increased $46 million primarily due to a decrease in amortization of Excess ADIT and an increase in pretax book income. The decrease in amortization of Excess ADIT is partially offset above in Gross Margin and Other Operation and Maintenance expenses.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2020 and 2019

(in millions)

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020		2019		2020		2019
REVENUES
Electric Generation, Transmission and Distribution	$	604.0	$	605.9	$	1,301.0	$	1,344.6
Sales to AEP Affiliates	30.8		46.3		80.5		98.0
Other Revenues	2.7		3.6		5.4		6.0
TOTAL REVENUES	637.5		655.8		1,386.9		1,448.6

EXPENSES
Fuel and Other Consumables Used for Electric Generation	153.9		161.2		264.9		344.5
Purchased Electricity for Resale	50.4		64.5		173.0		175.1


Other Operation	108.8		138.9		242.8		275.8
Maintenance	46.4		61.3		96.7		122.8
Depreciation and Amortization	120.6		117.1		242.8		229.6
Taxes Other Than Income Taxes	37.5		35.9		75.4		71.8
TOTAL EXPENSES	517.6		578.9		1,095.6		1,219.6

OPERATING INCOME	119.9		76.9		291.3		229.0

Other Income (Expense):
Interest Income	0.5		1.0		0.8		1.8

Allowance for Equity Funds Used During Construction	2.4		6.0		4.8		7.7
Non-Service Cost Components of Net Periodic Benefit Cost	4.7		4.2		9.4		8.5
Interest Expense	(54.1)		(51.6)		(107.2)		(100.9)

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	73.4		36.5		199.1		146.1

Income Tax Expense (Benefit)	(7.9)		(19.0)		2.5		(43.1)

NET INCOME	$	81.3	$	55.5	$	196.6	$	189.2

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

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Six Months Ended June 30, 2020 and 2019

(in millions)

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020		2019		2020		2019
Net Income	$	81.3	$	55.5	$	196.6	$	189.2

OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $(0.2) and $0 for the Three Months Ended June 30, 2020 and 2019, Respectively, and $(1.3) and $(0.1) for the Six Months Ended June 30, 2020 and 2019, Respectively	(0.8)		(0.2)		(5.0)		(0.4)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.2) and $(0.1) for the Three Months Ended June 30, 2020 and 2019, Respectively, and $(0.5) and $(0.3) for the Six Months Ended June 30, 2020 and 2019, Respectively	(1.0)		(0.7)		(1.9)		(1.3)

TOTAL OTHER COMPREHENSIVE LOSS	(1.8)		(0.9)		(6.9)		(1.7)

TOTAL COMPREHENSIVE INCOME	$	79.5	$	54.6	$	189.7	$	187.5

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Six Months Ended June 30, 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

Common Stock Dividends					(50.0)				(50.0)
Net Income					55.5				55.5
Other Comprehensive Loss							(0.9)		(0.9)
TOTAL COMMON SHAREHOLDER’S EQUITY - JUNE 30, 2019	$	260.4	$	1,828.7	$	2,011.2	$	(6.7)	$	4,093.6






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

Common Stock Dividends					(50.0)				(50.0)

Net Income					81.3				81.3
Other Comprehensive Loss							(1.8)		(1.8)
TOTAL COMMON SHAREHOLDER’S EQUITY - JUNE 30, 2020	$	260.4	$	1,828.7	$	2,174.9	$	(1.9)	$	4,262.1

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2020 and December 31, 2019

(in millions)

(Unaudited)


	June 30,		December 31,
	2020		2019
CURRENT ASSETS
Cash and Cash Equivalents	$	2.5	$	3.3
Restricted Cash for Securitized Funding	19.3		23.5
Advances to Affiliates	82.3		22.1
Accounts Receivable:
Customers	128.6		129.0
Affiliated Companies	117.6		64.3
Accrued Unbilled Revenues	47.5		59.7
Miscellaneous	0.2		0.5
Allowance for Uncollectible Accounts	(4.1)		(2.6)
Total Accounts Receivable	289.8		250.9
Fuel	157.8		149.7
Materials and Supplies	99.3		105.2
Risk Management Assets	37.7		39.4

Regulatory Asset for Under-Recovered Fuel Costs	11.6		42.5

Prepayments and Other Current Assets	38.0		64.0
TOTAL CURRENT ASSETS	738.3		700.6

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	6,607.4		6,563.7
Transmission	3,720.8		3,584.1
Distribution	4,311.5		4,201.7
Other Property, Plant and Equipment	602.6		571.3
Construction Work in Progress	561.0		593.4
Total Property, Plant and Equipment	15,803.3		15,514.2
Accumulated Depreciation and Amortization	4,572.8		4,432.3
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	11,230.5		11,081.9

OTHER NONCURRENT ASSETS
Regulatory Assets	656.6		457.2
Securitized Assets	222.3		234.7
Long-term Risk Management Assets	0.4		0.1
Operating Lease Assets	80.5		78.5
Deferred Charges and Other Noncurrent Assets	213.6		215.3
TOTAL OTHER NONCURRENT ASSETS	1,173.4		985.8

TOTAL ASSETS	$	13,142.2	$	12,768.3

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

June 30, 2020 and December 31, 2019

(Unaudited)


	June 30,		December 31,
	2020		2019
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	—	$	236.7
Accounts Payable:
General	213.5		307.8
Affiliated Companies	71.6		92.5
Long-term Debt Due Within One Year – Nonaffiliated	583.3		215.6

Risk Management Liabilities	7.6		1.9
Customer Deposits	82.4		85.8

Accrued Taxes	101.3		99.6

Obligations Under Operating Leases	14.5		15.2

Other Current Liabilities	144.2		170.9
TOTAL CURRENT LIABILITIES	1,218.4		1,226.0

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	4,262.0		4,148.2

Long-term Risk Management Liabilities	0.2		—
Deferred Income Taxes	1,693.0		1,680.8
Regulatory Liabilities and Deferred Investment Tax Credits	1,232.3		1,268.7
Asset Retirement Obligations	302.1		102.1
Employee Benefits and Pension Obligations	46.5		50.9
Obligations Under Operating Leases	66.5		64.0
Deferred Credits and Other Noncurrent Liabilities	59.1		55.2
TOTAL NONCURRENT LIABILITIES	7,661.7		7,369.9

TOTAL LIABILITIES	8,880.1		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	2,174.9		2,078.3
Accumulated Other Comprehensive Income (Loss)	(1.9)		5.0
TOTAL COMMON SHAREHOLDER’S EQUITY	4,262.1		4,172.4

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	13,142.2	$	12,768.3

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2020 and 2019

(in millions)

(Unaudited)


	Six Months Ended June 30,
	2020		2019
OPERATING ACTIVITIES
Net Income	$	196.6	$	189.2
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	242.8		229.6
Deferred Income Taxes	(11.8)		(73.5)


Allowance for Equity Funds Used During Construction	(4.8)		(7.7)
Mark-to-Market of Risk Management Contracts	1.5		(12.9)


Deferred Fuel Over/Under-Recovery, Net	30.9		41.4
Change in Other Noncurrent Assets	(11.1)		(1.8)
Change in Other Noncurrent Liabilities	(21.3)		(31.2)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(37.3)		60.2
Fuel, Materials and Supplies	(2.2)		(50.2)
Accounts Payable	(69.6)		23.0
Accrued Taxes, Net	8.9		(7.8)
Other Current Assets	18.8		17.4
Other Current Liabilities	(29.7)		(29.8)
Net Cash Flows from Operating Activities	311.7		345.9

INVESTING ACTIVITIES
Construction Expenditures	(400.2)		(397.1)

Change in Advances to Affiliates, Net	(60.2)		0.3

Other Investing Activities	3.9		20.7
Net Cash Flows Used for Investing Activities	(456.5)		(376.1)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated	492.2		478.3
Change in Advances from Affiliates, Net	(236.7)		(179.5)
Retirement of Long-term Debt – Nonaffiliated	(12.2)		(168.0)


Principal Payments for Finance Lease Obligations	(3.6)		(3.1)
Dividends Paid on Common Stock	(100.0)		(100.0)
Other Financing Activities	0.1		0.4
Net Cash Flows from Financing Activities	139.8		28.1

Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding	(5.0)		(2.1)
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	$	21.8	$	27.7

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	101.8	$	91.6
Net Cash Paid for Income Taxes	7.4		35.0
Noncash Acquisitions Under Finance Leases	2.2		5.7
Construction Expenditures Included in Current Liabilities as of June 30,	97.3		116.5

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

INDIANA MICHIGAN POWER COMPANY

AND SUBSIDIARIES

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales


	Three Months Ended			Six Months Ended
	June 30,			June 30,
	2020	2019	2020	2019
	(in millions of KWhs)
Retail:
Residential	1,244	1,048	2,699	2,663
Commercial	1,021	1,087	2,143	2,243
Industrial	1,630	1,917	3,475	3,805
Miscellaneous	15	14	33	33
Total Retail	3,910	4,066	8,350	8,744

Wholesale	2,323	2,021	4,016	4,444

Total KWhs	6,233	6,087	12,366	13,188

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			Six Months Ended
	June 30,			June 30,
	2020	2019	2020	2019
	(in degree days)
Actual – Heating (a)	343	217	2,179	2,456
Normal – Heating (b)	237	241	2,419	2,401

Actual – Cooling (c)	286	233	286	233
Normal – Cooling (b)	263	261	265	263

(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.

Second Quarter of 2020 Compared to Second Quarter of 2019


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

Second Quarter of 2019	$	60.3

Changes in Gross Margin:
Retail Margins	14.0

Margins from Off-system Sales	(0.1)
Transmission Revenues	6.0
Other Revenues	(6.4)
Total Change in Gross Margin	13.5

Changes in Expenses and Other:
Other Operation and Maintenance	15.3

Depreciation and Amortization	(17.9)
Taxes Other Than Income Taxes	0.5
Other Income	(3.0)


Non-Service Cost Components of Net Periodic Benefit Cost	(0.2)
Interest Expense	0.1
Total Change in Expenses and Other	(5.2)

Income Tax Expense	(4.8)

Second Quarter of 2020	$	63.8

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

•An $11 million increase in weather-related usage primarily due to a 23% increase in cooling degree days and 58% increase in heating degree days.

•An $11 million increase in weather-normalized retail margins.

•An $8 million increase primarily due to the Indiana and Michigan base rate cases, partially offset by a decrease in revenue riders. This increase was partially offset in other expense items below.

These increases were partially offset by:

•A $14 million decrease in weather-normalized wholesale margins.

•Transmission Revenues increased $6 million primarily due to the annual transmission formula rate true-up and increased investment in transmission assets.

•Other Revenues decreased $6 million primarily due to a decrease in barging revenues by River Transportation Division (RTD). This decrease was partially offset in Other Operation and Maintenance expenses below.

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

•Other Operation and Maintenance expenses decreased $15 million primarily due to the following:

•An $8 million decrease in nonutility operation expenses primarily due to a decrease in RTD expenses. This decrease was partially offset in Other Revenues above.

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

•A $2 million decrease in vegetation management expenses.

•A $2 million decrease in transmission expenses primarily due to the annual transmission formula rate true-up partially offset by an increase in recoverable PJM expenses. This decrease was partially offset in Transmission Revenues above.

•Depreciation and Amortization expenses increased $18 million primarily due to a higher depreciable base and an increase in depreciation rates. This increase was partially offset in Retail Margins above.

•Other Income decreased $3 million primarily due to a decrease in the AFUDC base.

•Income Tax Expense increased $5 million primarily due to an increase in pretax book income, a decrease in favorable flow-through tax benefits and an increase in state income tax expense.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019


Reconciliation of Six Months Ended June 30, 2019 to Six Months Ended June 30, 2020
Net Income
(in millions)

Six Months Ended June 30, 2019	$	159.2

Changes in Gross Margin:
Retail Margins	16.8


Transmission Revenues	7.4
Other Revenues	(7.2)
Total Change in Gross Margin	17.0

Changes in Expenses and Other:
Other Operation and Maintenance	20.3

Depreciation and Amortization	(25.6)
Taxes Other Than Income Taxes	1.4
Other Income	(6.2)


Non-Service Cost Components of Net Periodic Benefit Cost	(0.4)
Interest Expense	(1.7)
Total Change in Expenses and Other	(12.2)

Income Tax Expense	(7.9)

Six Months Ended June 30, 2020	$	156.1

•Retail Margins increased $17 million primarily due to the following:

•A $32 million increase primarily due to the Indiana and Michigan base rate cases. This increase was partially offset in other expense items below.

This increase was partially offset by:

•A $17 million decrease in weather-normalized wholesale margins.

•Transmission Revenues increased $7 million primarily due to the annual transmission formula rate true-up and increased investment in transmission assets.

•Other Revenues decreased $7 million primarily due to a decrease in barging revenues by RTD. This decrease was partially offset in Other Operation and Maintenance expenses below.

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

•Other Operation and Maintenance expenses decreased $20 million primarily due to the following:

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

•A $9 million decrease in nonutility operation expenses primarily due to a decrease in RTD expenses. This decrease was partially offset in Other Revenues above.

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

•A $4 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:

•A $10 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses, partially offset by the annual transmission formula rate true-up. This increase was partially offset in Transmission Revenues above.

•Depreciation and Amortization expenses increased $26 million primarily due to a higher depreciable base and an increase in depreciation rates. This increase was partially offset in Retail Margins above.

•Other Income decreased $6 million primarily driven by a favorable impact of a FERC settlement agreement recorded in 2019 and a decrease in the AFUDC base.

•Income Tax Expense increased $8 million primarily due to a decrease in favorable flow-through tax benefits and an increase in state income tax expense.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2020 and 2019

(in millions)

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020		2019		2020		2019
REVENUES
Electric Generation, Transmission and Distribution	$	524.9	$	517.4	$	1,078.3	$	1,114.1
Sales to AEP Affiliates	4.9		2.3		7.8		4.6
Other Revenues – Affiliated	15.8		20.9		28.3		34.2
Other Revenues – Nonaffiliated	1.0		2.5		2.5		4.5
TOTAL REVENUES	546.6		543.1		1,116.9		1,157.4

EXPENSES
Fuel and Other Consumables Used for Electric Generation	48.4		42.4		101.6		100.0
Purchased Electricity for Resale	40.5		48.9		90.6		118.5
Purchased Electricity from AEP Affiliates	43.7		51.3		79.9		111.1
Other Operation	149.5		154.5		294.2		295.0
Maintenance	44.3		54.6		93.4		112.9

Depreciation and Amortization	105.2		87.3		199.1		173.5
Taxes Other Than Income Taxes	25.7		26.2		52.1		53.5
TOTAL EXPENSES	457.3		465.2		910.9		964.5

OPERATING INCOME	89.3		77.9		206.0		192.9

Other Income (Expense):
Other Income	3.1		6.1		5.6		11.8


Non-Service Cost Components of Net Periodic Benefit Cost	4.2		4.4		8.4		8.8
Interest Expense	(28.1)		(28.2)		(58.8)		(57.1)

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	68.5		60.2		161.2		156.4

Income Tax Expense (Benefit)	4.7		(0.1)		5.1		(2.8)

NET INCOME	$	63.8	$	60.3	$	156.1	$	159.2


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

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Six Months Ended June 30, 2020 and 2019

(in millions)

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020		2019		2020		2019
Net Income	$	63.8	$	60.3	$	156.1	$	159.2

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended June 30, 2020 and 2019, Respectively, and $0.2 and $0.2 for the Six Months Ended June 30, 2020 and 2019, Respectively	0.4		0.4		0.8		0.8
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2020 and 2019, Respectively, and $0 and $0 for the Six Months Ended June 30, 2020 and 2019, Respectively	—		(0.1)		—		(0.1)

TOTAL OTHER COMPREHENSIVE INCOME	0.4		0.3		0.8		0.7

TOTAL COMPREHENSIVE INCOME	$	64.2	$	60.6	$	156.9	$	159.9


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Six Months Ended June 30, 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

Common Stock Dividends					(20.0)				(20.0)
Net Income					60.3				60.3
Other Comprehensive Income							0.3		0.3
TOTAL COMMON SHAREHOLDER’S EQUITY - JUNE 30, 2019	$	56.6	$	980.9	$	1,448.3	$	(13.1)	$	2,472.7






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

Common Stock Dividends					(21.2)				(21.2)
Net Income					63.8				63.8
Other Comprehensive Income							0.4		0.4
TOTAL COMMON SHAREHOLDER’S EQUITY - JUNE 30, 2020	$	56.6	$	980.9	$	1,632.5	$	(10.8)	$	2,659.2


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2020 and December 31, 2019

(in millions)

(Unaudited)


	June 30,		December 31,
	2020		2019
CURRENT ASSETS
Cash and Cash Equivalents	$	2.0	$	2.0
Advances to Affiliates	13.3		13.2
Accounts Receivable:
Customers	44.3		53.6
Affiliated Companies	79.5		53.7
Accrued Unbilled Revenues	4.9		2.5
Miscellaneous	0.4		0.3
Allowance for Uncollectible Accounts	(0.5)		(0.6)
Total Accounts Receivable	128.6		109.5
Fuel	78.0		56.2
Materials and Supplies	176.1		171.3
Risk Management Assets	6.4		9.8

Regulatory Asset for Under-Recovered Fuel Costs	2.6		3.0
Accrued Reimbursement of Spent Nuclear Fuel Costs	13.9		24.0

Prepayments and Other Current Assets	14.1		14.0
TOTAL CURRENT ASSETS	435.0		403.0

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	5,242.0		5,099.7
Transmission	1,657.6		1,641.8
Distribution	2,511.5		2,437.6
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	672.0		632.6
Construction Work in Progress	325.4		382.3
Total Property, Plant and Equipment	10,408.5		10,194.0
Accumulated Depreciation, Depletion and Amortization	3,416.2		3,294.3
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	6,992.3		6,899.7

OTHER NONCURRENT ASSETS
Regulatory Assets	437.4		482.1
Spent Nuclear Fuel and Decommissioning Trusts	2,957.0		2,975.7
Long-term Risk Management Assets	0.3		0.1
Operating Lease Assets	253.1		294.9
Deferred Charges and Other Noncurrent Assets	173.5		181.9
TOTAL OTHER NONCURRENT ASSETS	3,821.3		3,934.7

TOTAL ASSETS	$	11,248.6	$	11,237.4


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

June 30, 2020 and December 31, 2019

(dollars in millions)

(Unaudited)


	June 30,		December 31,
	2020		2019
CURRENT LIABILITIES
Advances from Affiliates	$	194.1	$	114.4
Accounts Payable:
General	151.9		169.4
Affiliated Companies	63.6		68.4
Long-term Debt Due Within One Year – Nonaffiliated (June 30, 2020 and December 31, 2019 Amounts Include $67.0 and $86.1, Respectively, Related to DCC Fuel)	360.8		139.7
Risk Management Liabilities	0.3		0.5
Customer Deposits	39.3		39.4
Accrued Taxes	115.1		112.4
Accrued Interest	35.9		36.2
Obligations Under Operating Leases	85.6		87.3
Regulatory Liability for Over-Recovered Fuel Costs	32.4		6.1
Other Current Liabilities	76.5		109.6
TOTAL CURRENT LIABILITIES	1,155.5		883.4

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	2,644.0		2,910.5
Long-term Risk Management Liabilities	0.2		—
Deferred Income Taxes	958.3		979.7
Regulatory Liabilities and Deferred Investment Tax Credits	1,811.8		1,891.4
Asset Retirement Obligations	1,783.6		1,748.6
Obligations Under Operating Leases	171.3		211.6
Deferred Credits and Other Noncurrent Liabilities	64.7		67.8
TOTAL NONCURRENT LIABILITIES	7,433.9		7,809.6

TOTAL LIABILITIES	8,589.4		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	1,632.5		1,518.5
Accumulated Other Comprehensive Income (Loss)	(10.8)		(11.6)
TOTAL COMMON SHAREHOLDER’S EQUITY	2,659.2		2,544.4

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	11,248.6	$	11,237.4


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2020 and 2019

(in millions)

(Unaudited)


	Six Months Ended June 30,
	2020		2019
OPERATING ACTIVITIES
Net Income	$	156.1	$	159.2
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	199.1		173.5

Deferred Income Taxes	(47.1)		(17.2)
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net	28.4		(14.3)


Allowance for Equity Funds Used During Construction	(4.8)		(12.5)
Mark-to-Market of Risk Management Contracts	3.2		(6.0)
Amortization of Nuclear Fuel	45.6		46.1

Deferred Fuel Over/Under-Recovery, Net	26.9		(16.5)
Change in Other Noncurrent Assets	50.7		34.0
Change in Other Noncurrent Liabilities	33.2		(3.6)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(18.1)		35.8
Fuel, Materials and Supplies	(26.9)		(3.8)

Accounts Payable	(33.7)		(50.4)

Accrued Taxes, Net	2.7		(15.9)


Other Current Assets	9.7		9.6
Other Current Liabilities	(81.4)		(38.6)
Net Cash Flows from Operating Activities	343.6		279.4

INVESTING ACTIVITIES
Construction Expenditures	(267.6)		(293.8)
Change in Advances to Affiliates, Net	(0.1)		(0.3)
Purchases of Investment Securities	(971.4)		(226.6)
Sales of Investment Securities	940.5		199.5
Acquisitions of Nuclear Fuel	(37.7)		(33.8)

Other Investing Activities	6.2		9.0
Net Cash Flows Used for Investing Activities	(330.1)		(346.0)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated	—		62.8
Change in Advances from Affiliates, Net	79.7		93.6
Retirement of Long-term Debt – Nonaffiliated	(47.6)		(48.3)
Principal Payments for Finance Lease Obligations	(3.3)		(2.7)
Dividends Paid on Common Stock	(42.5)		(40.0)
Other Financing Activities	0.2		0.2
Net Cash Flows from (Used for) Financing Activities	(13.5)		65.6

Net Decrease in Cash and Cash Equivalents	—		(1.0)
Cash and Cash Equivalents at Beginning of Period	2.0		2.4
Cash and Cash Equivalents at End of Period	$	2.0	$	1.4

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	55.6	$	55.2
Net Cash Paid for Income Taxes	48.0		27.9
Noncash Acquisitions Under Finance Leases	1.6		4.5
Construction Expenditures Included in Current Liabilities as of June 30,	69.9		77.7
Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30,	22.3		50.5
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage	2.2		—


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

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			Six Months Ended
	June 30,			June 30,
	2020	2019	2020	2019
	(in millions of KWhs)
Retail:
Residential	3,141	2,791	6,975	6,914
Commercial	3,157	3,478	6,673	7,005
Industrial	2,932	3,624	6,475	7,247
Miscellaneous	30	26	60	57
Total Retail (a)	9,260	9,919	20,183	21,223

Wholesale (b)	455	440	845	1,078

Total KWhs	9,715	10,359	21,028	22,301

(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			Six Months Ended
	June 30,			June 30,
	2020	2019	2020	2019
	(in degree days)
Actual – Heating (a)	292	114	1,765	2,006
Normal – Heating (b)	182	189	2,080	2,066

Actual – Cooling (c)	314	303	317	304
Normal – Cooling (b)	301	298	304	301

(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.

100

Second Quarter of 2020 Compared to Second Quarter of 2019


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

Second Quarter of 2019	$	50.6

Changes in Gross Margin:
Retail Margins	43.4
Margins from Off-system Sales	4.6
Transmission Revenues	17.8
Other Revenues	3.1
Total Change in Gross Margin	68.9

Changes in Expenses and Other:
Other Operation and Maintenance	(25.4)
Depreciation and Amortization	(3.7)
Taxes Other Than Income Taxes	(2.0)
Interest Income	(0.9)
Carrying Costs Income	0.4
Allowance for Equity Funds Used During Construction	(1.3)
Non-Service Cost Components of Net Periodic Benefit Cost	0.1
Interest Expense	(4.5)
Total Change in Expenses and Other	(37.3)

Income Tax Expense	(1.3)

Second Quarter of 2020	$	80.9

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

•Retail Margins increased $43 million primarily due to the following:

•A $61 million net increase in Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset in Other Operation and Maintenance expenses below.

•A $13 million increase in rider revenues associated with the DIR. This increase was partially offset in other expense items below.

•A $5 million increase in revenues associated with smart grid riders. This increase was partially offset in other expense items below.

•A $3 million increase in revenues associated with the Universal Service Fund (USF). This increase was offset in Other Operation and Maintenance expenses below.

These increases were partially offset by:

•A $10 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 $9 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 $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 a PUCO order to refund unused 2018 major storm reserve collections to customers. This decrease was offset in Other Operation and Maintenance expenses below.

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

•Margins from Off-system Sales increased $5 million primarily due to higher OVEC PPA deferrals. This increase was offset in Retail Margins above.

•Transmission Revenues increased $18 million primarily due to the annual transmission formula rate true-up.

101

•Other Revenues increased $3 million primarily due to third-party LGRR revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins above.

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

•Other Operation and Maintenance expenses increased $25 million primarily due to the following:

•A $66 million increase in recoverable PJM expenses. This increase was offset in Gross Margin above.

•A $3 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.

These increases were partially offset by:

•A $34 million decrease in PJM expenses primarily related to the annual transmission formula rate true-up.

•A $5 million decrease due to a PUCO order to refund unused 2018 major storm reserve collections to customers. This decrease was offset in Retail Margins above.

•Depreciation and Amortization expenses increased $4 million primarily due to the following:

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

•A $3 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.

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

•Income Tax Expense increased $1 million due to an increase in pretax book income partially offset by an increase in amortization of Excess ADIT and the recognition of a discrete tax adjustment. The increase in amortization of Excess ADIT is partially offset in Retail Margins above.

102

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019


Reconciliation of Six Months Ended June 30, 2019 to Six Months Ended June 30, 2020
Net Income
(in millions)

Six Months Ended June 30, 2019	$	178.6

Changes in Gross Margin:
Retail Margins	(50.3)
Margins from Off-system Sales	6.9
Transmission Revenues	18.4
Other Revenues	8.6
Total Change in Gross Margin	(16.4)

Changes in Expenses and Other:
Other Operation and Maintenance	15.1
Depreciation and Amortization	(10.9)
Taxes Other Than Income Taxes	(5.1)
Interest Income	(1.5)
Carrying Costs Income	0.6
Allowance for Equity Funds Used During Construction	(4.6)
Non-Service Cost Components of Net Periodic Benefit Cost	0.2
Interest Expense	(8.8)
Total Change in Expenses and Other	(15.0)

Income Tax Expense	8.8

Six Months Ended June 30, 2020	$	156.0

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 $50 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 $23 million decrease in Deferred Asset Phase-In-Recovery Rider revenues which ended in the second quarter of 2019. This decrease was partially offset in Depreciation and Amortization expenses below.

•A $15 million net decrease in margin for the Rate Stability Rider including associated amortizations which ended in the third quarter of 2019.

•A $14 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 $6 million decrease in revenues associated with a vegetation management rider. This decrease was partially offset in Other Operation and Maintenance expenses below.

•A $5 million decrease due to a PUCO order to refund unused 2018 major storm reserve collections to customers. This decrease was offset in Other Operation and Maintenance expenses below.

These decreases were partially offset by:

•A $30 million increase in rider revenues associated with the DIR. This increase was partially offset in other expense items below.

•A $22 million net increase in Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset in Other Operation and Maintenance expenses below.

•A $12 million increase in revenues associated with smart grid riders. This increase was partially offset in other expense items below.

•A $10 million increase in revenues associated with the Universal Service Fund (USF). This increase was offset in Other Operation and Maintenance expenses below.

•A $4 million increase in Energy Efficiency/Peak Demand Reduction rider revenues. This increase was offset in Other Operation and Maintenance expenses below.

103

•Margins from Off-system Sales increased $7 million primarily due to:

•A $14 million increase due to higher OVEC PPA deferrals. This increase was offset in Retail Margins above.

This increase was partially offset by:

•A $9 million decrease in sales due to lower market prices and decreased sales volumes in 2020. This decrease was offset in Retail Margins above.

•Transmission Revenues increased $18 million primarily due to the annual transmission formula rate true-up.

•Other Revenues increased $9 million primarily due to third-party LGRR revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins above.

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

•Other Operation and Maintenance expenses decreased $15 million primarily due to the following:

•A $40 million decrease in PJM expenses primarily related to the annual formula rate true-up.

•A $6 million decrease in customer-related expenses.

•A $5 million decrease due to a PUCO order to refund unused 2018 major storm reserve collections to customers. This decrease was offset in Retail Margins above.

•A $5 million decrease in recoverable distribution expenses related to vegetation management. This decrease was offset in Retail Margins above.

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

These decreases were partially offset by:

•A $25 million increase in recoverable PJM expenses. This increase was offset in Gross Margin above.

•A $4 million increase in Energy Efficiency/Peak Demand Reduction expenses. This increase was offset in Retail Margins above.

•A $4 million increase in recoverable storm expense. This increase was offset in Retail Margins above.

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

•A $10 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 $10 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.

•An $8 million increase in recoverable DIR depreciation expense. This increase was partially offset in Retail Margins above.

•A $5 million increase in recoverable smart grid expense. This increase was offset in Retail Margins above.

These increases were partially offset by:

•A $21 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 $5 million primarily due to the following:

•A $10 million increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.

This increase was partially offset by:

•A $3 million decrease in excise taxes due to lower demand in 2020. This decrease was offset in Retail Margins above.

•Allowance for Equity Funds Used During Construction decreased $5 million primarily due to adjustments that resulted from 2019 FERC audit findings and a decrease in AFUDC base.

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

•Income Tax Expense decreased $9 million due to a decrease in pretax book income and the recognition of a discrete tax adjustment.

104

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2020 and 2019

(in millions)

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020		2019		2020		2019
REVENUES
Electricity, Transmission and Distribution	$	621.8	$	602.3	$	1,301.0	$	1,428.8
Sales to AEP Affiliates	16.3		1.7		24.7		9.2
Other Revenues	2.3		2.6		5.0		5.4
TOTAL REVENUES	640.4		606.6		1,330.7		1,443.4

EXPENSES
Purchased Electricity for Resale	113.9		121.5		263.0		295.7
Purchased Electricity from AEP Affiliates	30.3		33.7		72.7		79.8
Amortization of Generation Deferrals	—		24.1		—		56.5
Other Operation	186.6		153.9		363.9		370.8
Maintenance	26.9		34.2		58.5		66.7
Depreciation and Amortization	59.8		56.1		130.3		119.4
Taxes Other Than Income Taxes	108.0		106.0		220.0		214.9
TOTAL EXPENSES	525.5		529.5		1,108.4		1,203.8

OPERATING INCOME	114.9		77.1		222.3		239.6

Other Income (Expense):
Interest Income	0.2		1.1		0.4		1.9
Carrying Costs Income	0.6		0.2		1.0		0.4
Allowance for Equity Funds Used During Construction	2.8		4.1		4.7		9.3
Non-Service Cost Components of Net Periodic Benefit Cost	3.7		3.6		7.5		7.3
Interest Expense	(30.1)		(25.6)		(59.0)		(50.2)

INCOME BEFORE INCOME TAX EXPENSE	92.1		60.5		176.9		208.3

Income Tax Expense	11.2		9.9		20.9		29.7

NET INCOME	$	80.9	$	50.6	$	156.0	$	178.6

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

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

105

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Six Months Ended June 30, 2020 and 2019

(in millions)

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020		2019		2020		2019
Net Income	$	80.9	$	50.6	$	156.0	$	178.6

OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $(0.1) for the Three Months Ended June 30, 2020 and 2019, Respectively, and $0 and $(0.2) for the Six Months Ended June 30, 2020 and 2019, Respectively	—		(0.4)		—		(0.7)

TOTAL COMPREHENSIVE INCOME	$	80.9	$	50.2	$	156.0	$	177.9



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

106

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Six Months Ended June 30, 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

Common Stock Dividends					(60.0)				(60.0)
Net Income					50.6				50.6
Other Comprehensive Loss							(0.4)		(0.4)
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2019	$	321.2	$	838.8	$	1,230.0	$	0.3	$	2,390.3






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

Common Stock Dividends					(21.9)				(21.9)
Net Income					80.9				80.9

TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2020	$	321.2	$	838.8	$	1,461.0	$	—	$	2,621.0

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

107

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2020 and December 31, 2019

(in millions)

(Unaudited)


	June 30,		December 31,
	2020		2019
CURRENT ASSETS
Cash and Cash Equivalents	$	3.3	$	3.7

Accounts Receivable:
Customers	41.5		53.0
Affiliated Companies	82.0		59.3
Accrued Unbilled Revenues	23.0		20.3
Miscellaneous	3.7		0.5
Allowance for Uncollectible Accounts	(1.2)		(0.7)
Total Accounts Receivable	149.0		132.4
Materials and Supplies	62.2		52.3
Renewable Energy Credits	28.0		30.9

Accrued Tax Benefits	13.3		11.5

Prepayments and Other Current Assets	6.0		7.7
TOTAL CURRENT ASSETS	261.8		238.5

PROPERTY, PLANT AND EQUIPMENT
Electric:
Transmission	2,725.7		2,686.3
Distribution	5,475.4		5,323.5
Other Property, Plant and Equipment	834.3		765.8
Construction Work in Progress	446.0		394.4
Total Property, Plant and Equipment	9,481.4		9,170.0
Accumulated Depreciation and Amortization	2,315.7		2,263.0
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	7,165.7		6,907.0

OTHER NONCURRENT ASSETS
Regulatory Assets	418.9		351.8

Deferred Charges and Other Noncurrent Assets	424.2		546.3
TOTAL OTHER NONCURRENT ASSETS	843.1		898.1

TOTAL ASSETS	$	8,270.6	$	8,043.6

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

108

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

June 30, 2020 and December 31, 2019

(dollars in millions)

(Unaudited)


	June 30,		December 31,
	2020		2019
CURRENT LIABILITIES
Advances from Affiliates	$	143.1	$	131.0
Accounts Payable:
General	180.5		233.7
Affiliated Companies	90.1		103.6
Long-term Debt Due Within One Year – Nonaffiliated	0.1		0.1
Risk Management Liabilities	8.6		7.3
Customer Deposits	65.4		70.6
Accrued Taxes	438.9		587.9

Obligations Under Operating Leases	12.3		12.5
Other Current Liabilities	131.4		151.2
TOTAL CURRENT LIABILITIES	1,070.4		1,297.9

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	2,429.4		2,081.9
Long-term Risk Management Liabilities	108.9		96.3
Deferred Income Taxes	887.8		849.4
Regulatory Liabilities and Deferred Investment Tax Credits	1,026.7		1,090.9

Obligations Under Operating Leases	76.8		76.0
Deferred Credits and Other Noncurrent Liabilities	49.6		42.7
TOTAL NONCURRENT LIABILITIES	4,579.2		4,237.2

TOTAL LIABILITIES	5,649.6		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	1,461.0		1,348.5

TOTAL COMMON SHAREHOLDER’S EQUITY	2,621.0		2,508.5

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	8,270.6	$	8,043.6

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

109

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2020 and 2019

(in millions)

(Unaudited)


	Six Months Ended June 30,
	2020		2019
OPERATING ACTIVITIES
Net Income	$	156.0	$	178.6
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	130.3		119.4
Amortization of Generation Deferrals	—		56.5
Deferred Income Taxes	21.6		9.4

Allowance for Equity Funds Used During Construction	(4.7)		(9.3)
Mark-to-Market of Risk Management Contracts	13.9		12.1

Property Taxes	151.4		130.1
Refund of Global Settlement	—		(8.2)
Reversal of Regulatory Provision	—		(56.2)

Change in Other Noncurrent Assets	(103.2)		(30.5)
Change in Other Noncurrent Liabilities	(45.4)		(38.0)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(14.1)		70.0
Materials and Supplies	(16.8)		(8.5)
Accounts Payable	(23.1)		(34.9)
Accrued Taxes, Net	(150.8)		(169.4)
Other Current Assets	3.1		(4.2)
Other Current Liabilities	(25.7)		2.6
Net Cash Flows from Operating Activities	92.5		219.5

INVESTING ACTIVITIES
Construction Expenditures	(416.7)		(385.5)
Change in Advances to Affiliates, Net	—		(63.9)
Other Investing Activities	10.3		7.5
Net Cash Flows Used for Investing Activities	(406.4)		(441.9)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated	347.0		444.3
Change in Advances from Affiliates, Net	12.1		(114.1)
Retirement of Long-term Debt – Nonaffiliated	—		(23.4)
Principal Payments for Finance Lease Obligations	(2.4)		(1.8)
Dividends Paid on Common Stock	(43.8)		(85.0)
Other Financing Activities	0.6		0.8
Net Cash Flows from Financing Activities	313.5		220.8

Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding	(0.4)		(1.6)
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	$	3.3	$	30.9

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	54.1	$	46.1
Net Cash Paid for Income Taxes	2.4		14.3
Noncash Acquisitions Under Finance Leases	4.9		6.1
Construction Expenditures Included in Current Liabilities as of June 30,	74.1		77.9

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

110

PUBLIC SERVICE COMPANY OF OKLAHOMA

111

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			Six Months Ended
	June 30,			June 30,
	2020	2019	2020	2019
	(in millions of KWhs)
Retail:
Residential	1,457	1,289	2,819	2,809
Commercial	1,136	1,232	2,191	2,321
Industrial	1,401	1,590	2,838	3,023
Miscellaneous	293	298	565	572
Total Retail	4,287	4,409	8,413	8,725

Wholesale	78	148	131	393

Total KWhs	4,365	4,557	8,544	9,118

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			Six Months Ended
	June 30,			June 30,
	2020	2019	2020	2019
	(in degree days)
Actual – Heating (a)	74	28	873	1,199
Normal – Heating (b)	43	44	1,077	1,076

Actual – Cooling (c)	672	610	705	613
Normal – Cooling (b)	659	658	676	675

(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.

112

Second Quarter of 2020 Compared to Second Quarter of 2019


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

Second Quarter of 2019	$	41.9

Changes in Gross Margin:
Retail Margins (a)	5.6
Margins from Off-system Sales	(0.2)
Transmission Revenues	0.2
Other Revenues	4.8
Total Change in Gross Margin	10.4

Changes in Expenses and Other:
Other Operation and Maintenance	(3.3)
Depreciation and Amortization	(2.2)
Taxes Other Than Income Taxes	(1.9)
Interest Income	(0.2)

Allowance for Equity Funds Used During Construction	0.3


Interest Expense	1.8
Total Change in Expenses and Other	(5.5)

Income Tax Expense	(0.4)

Second Quarter of 2020	$	46.4

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

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

•A $7 million increase in weather-normalized margins.

•A $6 million increase in weather-related usage due to a 10% increase in cooling degree days.

These increases were partially offset by:

•A $5 million decrease in revenue from rate riders. This decrease was partially offset in other expense items below.

•Other Revenues increased $5 million primarily due to business development revenue. This increase was partially offset in other expense items below.

Expenses and Other changed between years as follows:

•Other Operation and Maintenance expenses increased $3 million primarily due the following:

•A $9 million increase in transmission expenses primarily due to increased SPP transmission services.

•A $4 million increase in business development expenses. This increase was offset in Other Revenues above.

These increases were partially offset by:

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

•A $5 million decrease due to the capitalization of previously expensed North Central Wind Energy Facilities costs.

113

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019


Reconciliation of Six Months Ended June 30, 2019 to Six Months Ended June 30, 2020
Net Income
(in millions)

Six Months Ended June 30, 2019	$	48.1

Changes in Gross Margin:
Retail Margins (a)	5.6
Margin from Off-system Sales	(0.4)
Transmission Revenues	(0.3)
Other Revenues	3.6
Total Change in Gross Margin	8.5

Changes in Expenses and Other:
Other Operation and Maintenance	(18.8)
Depreciation and Amortization	(3.4)
Taxes Other Than Income Taxes	(1.8)
Interest Income	(0.1)

Allowance for Equity Funds Used During Construction	1.2


Interest Expense	2.9
Total Change in Expenses and Other	(20.0)

Income Tax Expense	(0.5)

Six Months Ended June 30, 2020	$	36.1

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

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

•A $10 million increase due to new base rates implemented in April 2019.

•A $5 million increase in weather-normalized margins.

•A $3 million increase in weather-related usage due to a 15% increase in cooling degree-days.

These increases were partially offset by:

•A $6 million decrease in revenue from rate riders. This decrease was partially offset in other expense items below.

•A $6 million decrease due to customer refunds related to Tax Reform. This decrease was partially offset in Income Tax Expense below.

•Other Revenues increased $4 million primarily due to business development revenue. This increase was partially offset in other expense items below.

Expenses and Other changed between years as follows:

•Other Operation and Maintenance expenses increased $19 million primarily due to the following:

•A $15 million increase in transmission expenses primarily due to increased SPP transmission services.

•A $4 million increase in business development expenses. This increase was offset in Other Revenues above.

•A $3 million increase in vegetation management expenses.

These increases were partially offset by:

•A $4 million decrease due to the capitalization of previously expensed North Central Wind Energy Facilities costs.

•Depreciation and Amortization expenses increased $3 million primarily due to a higher depreciable base.

114

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2020 and 2019

(in millions)

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020		2019		2020		2019
REVENUES
Electric Generation, Transmission and Distribution	$	301.1	$	344.6	$	596.5	$	673.8
Sales to AEP Affiliates	1.3		2.1		2.4		3.7
Other Revenues	6.2		1.4		7.0		3.4
TOTAL REVENUES	308.6		348.1		605.9		680.9

EXPENSES
Fuel and Other Consumables Used for Electric Generation	(1.6)		44.8		15.3		82.8
Purchased Electricity for Resale	99.0		102.5		209.4		225.4

Other Operation	69.6		64.8		156.8		138.4
Maintenance	24.6		26.1		49.0		48.6
Depreciation and Amortization	45.0		42.8		89.7		86.3
Taxes Other Than Income Taxes	12.4		10.5		23.7		21.9
TOTAL EXPENSES	249.0		291.5		543.9		603.4

OPERATING INCOME	59.6		56.6		62.0		77.5

Other Income (Expense):
Interest Income	—		0.2		0.1		0.2

Allowance for Equity Funds Used During Construction	0.9		0.6		1.9		0.7

Non-Service Cost Components of Net Periodic Benefit Cost	2.1		2.1		4.2		4.2
Interest Expense	(15.5)		(17.3)		(31.3)		(34.2)

INCOME BEFORE INCOME TAX EXPENSE	47.1		42.2		36.9		48.4

Income Tax Expense	0.7		0.3		0.8		0.3

NET INCOME	$	46.4	$	41.9	$	36.1	$	48.1

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

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

115

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Six Months Ended June 30, 2020 and 2019

(in millions)

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020		2019		2020		2019
Net Income	$	46.4	$	41.9	$	36.1	$	48.1

OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended June 30, 2020 and 2019, Respectively, and $(0.2) and $(0.2) for the Six Months Ended June 30, 2020 and 2019, Respectively.	(0.3)		(0.3)		(0.5)		(0.5)

TOTAL COMPREHENSIVE INCOME	$	46.1	$	41.6	$	35.6	$	47.6

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

116

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Six Months Ended June 30, 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


Net Income					41.9				41.9
Other Comprehensive Loss							(0.3)		(0.3)
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2019	$	157.2	$	364.0	$	761.5	$	1.6	$	1,284.3






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


Net Income					46.4				46.4
Other Comprehensive Loss							(0.3)		(0.3)
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2020	$	157.2	$	364.0	$	887.4	$	0.6	$	1,409.2

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

117

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED BALANCE SHEETS

ASSETS

June 30, 2020 and December 31, 2019

(in millions)

(Unaudited)


	June 30,		December 31,
	2020		2019
CURRENT ASSETS
Cash and Cash Equivalents	$	1.4	$	1.5
Advances to Affiliates	—		38.8
Accounts Receivable:
Customers	30.6		28.9
Affiliated Companies	41.0		20.6
Miscellaneous	2.5		0.6
Allowance for Uncollectible Accounts	—		(0.3)
Total Accounts Receivable	74.1		49.8
Fuel	26.2		12.2
Materials and Supplies	50.9		46.8
Risk Management Assets	23.8		15.8

Accrued Tax Benefits	1.0		11.3

Prepayments and Other Current Assets	10.0		12.0
TOTAL CURRENT ASSETS	187.4		188.2

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	1,573.0		1,574.6
Transmission	976.9		948.5
Distribution	2,769.9		2,684.8
Other Property, Plant and Equipment	370.2		342.1
Construction Work in Progress	135.3		133.4
Total Property, Plant and Equipment	5,825.3		5,683.4
Accumulated Depreciation and Amortization	1,650.2		1,580.1
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	4,175.1		4,103.3

OTHER NONCURRENT ASSETS
Regulatory Assets	385.1		375.2

Employee Benefits and Pension Assets	44.5		43.9
Operating Lease Assets	40.4		36.8
Deferred Charges and Other Noncurrent Assets	26.3		4.1
TOTAL OTHER NONCURRENT ASSETS	496.3		460.0

TOTAL ASSETS	$	4,858.8	$	4,751.5

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

118

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

June 30, 2020 and December 31, 2019

(Unaudited)


	June 30,		December 31,
	2020		2019
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	106.9	$	—
Accounts Payable:
General	119.6		134.3
Affiliated Companies	55.4		59.3
Long-term Debt Due Within One Year – Nonaffiliated	250.5		13.2
Risk Management Liabilities	0.1		—
Customer Deposits	58.4		58.9
Accrued Taxes	51.1		22.9

Obligations Under Operating Leases	6.2		5.8
Regulatory Liability for Over-Recovered Fuel Costs	46.8		63.9

Other Current Liabilities	72.9		87.5
TOTAL CURRENT LIABILITIES	767.9		445.8

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	1,123.2		1,373.0

Deferred Income Taxes	634.8		628.3
Regulatory Liabilities and Deferred Investment Tax Credits	822.5		837.2
Asset Retirement Obligations	46.1		44.5

Obligations Under Operating Leases	34.3		31.0
Deferred Credits and Other Noncurrent Liabilities	20.8		18.4
TOTAL NONCURRENT LIABILITIES	2,681.7		2,932.4

TOTAL LIABILITIES	3,449.6		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	887.4		851.0
Accumulated Other Comprehensive Income (Loss)	0.6		1.1
TOTAL COMMON SHAREHOLDER’S EQUITY	1,409.2		1,373.3

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	4,858.8	$	4,751.5

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

119

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2020 and 2019

(in millions)

(Unaudited)


	Six Months Ended June 30,
	2020		2019
OPERATING ACTIVITIES
Net Income	$	36.1	$	48.1
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	89.7		86.3
Deferred Income Taxes	(9.2)		(9.0)

Allowance for Equity Funds Used During Construction	(1.9)		(0.7)
Mark-to-Market of Risk Management Contracts	(7.9)		(18.3)

Property Taxes	(21.2)		(19.2)
Deferred Fuel Over/Under-Recovery, Net	(17.1)		9.0

Change in Other Noncurrent Assets	(4.8)		4.6
Change in Other Noncurrent Liabilities	1.3		(2.4)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(24.3)		(12.6)
Fuel, Materials and Supplies	(18.1)		0.4
Accounts Payable	(1.5)		28.5
Accrued Taxes, Net	38.5		12.8
Other Current Assets	1.8		(1.6)
Other Current Liabilities	(10.0)		3.3
Net Cash Flows from Operating Activities	51.4		129.2

INVESTING ACTIVITIES
Construction Expenditures	(184.8)		(132.7)
Change in Advances to Affiliates, Net	38.8		—
Other Investing Activities	2.0		1.1
Net Cash Flows Used for Investing Activities	(144.0)		(131.6)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated	—		349.9
Change in Advances from Affiliates, Net	106.9		(82.9)
Retirement of Long-term Debt – Nonaffiliated	(12.9)		(250.2)

Principal Payments for Finance Lease Obligations	(1.8)		(1.5)
Dividends Paid on Common Stock	—		(11.3)
Other Financing Activities	0.3		(2.2)
Net Cash Flows from Financing Activities	92.5		1.8

Net Decrease in Cash and Cash Equivalents	(0.1)		(0.6)
Cash and Cash Equivalents at Beginning of Period	1.5		2.0
Cash and Cash Equivalents at End of Period	$	1.4	$	1.4

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	30.6	$	30.9
Net Cash Paid (Received) for Income Taxes	(2.7)		11.1
Noncash Acquisitions Under Finance Leases	2.6		2.3
Construction Expenditures Included in Current Liabilities as of June 30,	25.3		19.7

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

120

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

121

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			Six Months Ended
	June 30,			June 30,
	2020	2019	2020	2019
	(in millions of KWhs)
Retail:
Residential	1,346	1,297	2,752	2,825
Commercial	1,236	1,411	2,464	2,684
Industrial	1,187	1,356	2,429	2,606
Miscellaneous	20	20	40	40
Total Retail	3,789	4,084	7,685	8,155

Wholesale	1,184	1,507	2,510	3,486

Total KWhs	4,973	5,591	10,195	11,641

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			Six Months Ended
	June 30,			June 30,
	2020	2019	2020	2019
	(in degree days)
Actual – Heating (a)	25	24	522	732
Normal – Heating (b)	25	26	723	724

Actual – Cooling (c)	674	691	743	711
Normal – Cooling (b)	741	740	780	779

(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.

122

Second Quarter of 2020 Compared to Second Quarter of 2019


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

Second Quarter of 2019	$	6.2

Changes in Gross Margin:
Retail Margins (a)	17.4
Margins from Off-system Sales	(0.6)
Transmission Revenues	48.5
Other Revenues	(1.4)
Total Change in Gross Margin	63.9

Changes in Expenses and Other:
Other Operation and Maintenance	2.5

Depreciation and Amortization	(6.3)
Taxes Other Than Income Taxes	(0.5)
Interest Income	(0.2)
Allowance for Equity Funds Used During Construction	(0.2)
Non-Service Cost Components of Net Periodic Benefit Cost	(0.1)

Interest Expense	0.8
Total Change in Expenses and Other	(4.0)

Income Tax Expense	(7.9)
Equity Earnings of Unconsolidated Subsidiary	(0.1)
Net Income Attributable to Noncontrolling Interest	0.7

Second Quarter of 2020	$	58.8

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

•Retail Margins increased $17 million primarily due to the following:

•A $13 million increase primarily due to rider increases in all jurisdictions and a base rate revenue increase in Arkansas.

•A $6 million increase in municipal and cooperative revenues primarily due to formula rate adjustments.

•Transmission Revenues increased $49 million primarily due to the following:

•A $36 million increase as a result of the annual transmission formula rate true-up. This increase was partially offset by an increase in transmission expenses in SPP.

•A $10 million increase due to continued investment in transmission projects.

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

•Other Operation and Maintenance expenses decreased $3 million primarily due to the following:

•An $8 million decrease due to the capitalization of previously expensed North Central Wind Energy Facilities costs.

•A $6 million decrease in generation expenses.

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

•A $2 million decrease in overhead line maintenance primarily related to storm restoration.

These decreases were partially offset by:

•An $18 million increase in SPP transmission expenses. This increase was offset in Transmission Revenues above.

123

•Depreciation and Amortization expenses increased $6 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 increased $8 million primarily due to an increase in pretax book income partially offset with an increase in amortization of Excess ADIT. The increase in amortization of Excess ADIT was partially offset in Retail Margins above.

124

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019


Reconciliation of Six Months Ended June 30, 2019 to Six Months Ended June 30, 2020
Earnings Attributable to SWEPCo Common Shareholder
(in millions)

Six Months Ended June 30, 2019	$	34.0

Changes in Gross Margin:
Retail Margins (a)	13.3
Margins from Off-system Sales	(2.2)
Transmission Revenues	53.3
Other Revenues	(1.8)
Total Change in Gross Margin	62.6

Changes in Expenses and Other:
Other Operation and Maintenance	(10.0)

Depreciation and Amortization	(11.5)
Taxes Other Than Income Taxes	(0.5)
Interest Income	(0.3)
Allowance for Equity Funds Used During Construction	(0.6)
Non-Service Cost Components of Net Periodic Benefit Cost	(0.1)

Interest Expense	0.4
Total Change in Expenses and Other	(22.6)

Income Tax Expense	(1.0)

Net Income Attributable to Noncontrolling Interest	0.9

Six Months Ended June 30, 2020	$	73.9

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

•Retail Margins increased $13 million primarily due to the following:

•A $21 million increase primarily due to rider increases in all jurisdictions and a base rate revenue increase in Arkansas.

•A $6 million increase in municipal and cooperative revenues primarily due to formula rate adjustments.

These increases were partially offset by:

•A $9 million decrease in weather-normalized margins.

•A $7 million decrease in weather-related usage primarily due to a 29% decrease in heating degree days.

•Transmission Revenues increased $53 million primarily due to the following:

•A $36 million increase as a result of the annual transmission formula rate true-up. This increase was partially offset by an increase in transmission expenses in SPP.

•A $16 million increase due to continued investment in transmission projects.

Expenses and Other changed between years as follows:

•Other Operation and Maintenance expenses increased $10 million primarily due to the following:

•A $19 million increase in SPP transmission expenses. This increase was offset in Transmission Revenues above.

This increase was partially offset by:

•A $6 million decrease due to the capitalization of previously expensed North Central Wind Energy Facilities costs.

125

•Depreciation and Amortization expenses increased $12 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.

126

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2020 and 2019

(in millions)

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020		2019		2020		2019
REVENUES
Electric Generation, Transmission and Distribution	$	401.0	$	394.0	$	778.6	$	808.3
Sales to AEP Affiliates	17.5		6.4		25.0		12.8
Provision for Refund – Affiliated	(4.4)		(25.2)		(4.4)		(25.2)
Other Revenues	0.9		0.3		1.7		0.7
TOTAL REVENUES	415.0		375.5		800.9		796.6

EXPENSES
Fuel and Other Consumables Used for Electric Generation	85.6		117.9		174.7		251.4
Purchased Electricity for Resale	41.0		33.1		84.1		65.7

Other Operation	70.0		65.9		162.2		150.5
Maintenance	32.7		39.3		66.5		68.2

Depreciation and Amortization	68.1		61.8		135.4		123.9
Taxes Other Than Income Taxes	25.0		24.5		50.3		49.8
TOTAL EXPENSES	322.4		342.5		673.2		709.5

OPERATING INCOME	92.6		33.0		127.7		87.1

Other Income (Expense):
Interest Income	0.5		0.7		1.1		1.4
Allowance for Equity Funds Used During Construction	0.9		1.1		2.3		2.9
Non-Service Cost Components of Net Periodic Benefit Cost	2.1		2.2		4.2		4.3

Interest Expense	(29.7)		(30.5)		(59.8)		(60.2)

INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	66.4		6.5		75.5		35.5

Income Tax Expense	7.9		—		1.7		0.7
Equity Earnings of Unconsolidated Subsidiary	0.7		0.8		1.5		1.5

NET INCOME	59.2		7.3		75.3		36.3

Net Income Attributable to Noncontrolling Interest	0.4		1.1		1.4		2.3

EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER	$	58.8	$	6.2	$	73.9	$	34.0

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

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

127

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Six Months Ended June 30, 2020 and 2019

(in millions)

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020		2019		2020		2019
Net Income	$	59.2	$	7.3	$	75.3	$	36.3

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended June 30, 2020 and 2019, Respectively, and $0.2 and $0.2 for the Six Months Ended June 30, 2020 and 2019, Respectively	0.3		0.4		0.7		0.8
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended June 30, 2020 and 2019, Respectively, and $(0.2) and $(0.2) for the Six Months Ended June 30, 2020 and 2019, Respectively	(0.3)		(0.3)		(0.7)		(0.6)

TOTAL OTHER COMPREHENSIVE INCOME	—		0.1		—		0.2

TOTAL COMPREHENSIVE INCOME	59.2		7.4		75.3		36.5

Total Comprehensive Income Attributable to Noncontrolling Interest	0.4		1.1		1.4		2.3

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER	$	58.8	$	6.3	$	73.9	$	34.2

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

128

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Six Months Ended June 30, 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

Common Stock Dividends					(18.8)						(18.8)
Common Stock Dividends – Nonaffiliated									(1.1)		(1.1)
Net Income					6.2				1.1		7.3
Other Comprehensive Income							0.1				0.1
TOTAL EQUITY – JUNE 30, 2019	$	135.7	$	676.6	$	1,504.9	$	(5.2)	$	0.4	$	2,312.4







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


Common Stock Dividends – Nonaffiliated									(1.2)		(1.2)
Net Income					58.8				0.4		59.2

TOTAL EQUITY – JUNE 30, 2020	$	135.7	$	676.6	$	1,705.0	$	(1.3)	$	0.1	$	2,516.1

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

129

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2020 and December 31, 2019

(in millions)

(Unaudited)


	June 30,		December 31,
	2020		2019
CURRENT ASSETS
Cash and Cash Equivalents	$	1.8	$	1.6
Advances to Affiliates	2.1		2.1
Accounts Receivable:
Customers	24.0		29.0
Affiliated Companies	41.7		34.5
Miscellaneous	15.5		13.5
Allowance for Uncollectible Accounts	(0.1)		(1.7)
Total Accounts Receivable	81.1		75.3
Fuel (June 30, 2020 and December 31, 2019 Amounts Include $54.2 and $47, Respectively, Related to Sabine)	197.6		140.1
Materials and Supplies (June 30, 2020 and December 31, 2019 Amounts Include $24 and $23.1, Respectively, Related to Sabine)	97.9		94.0
Risk Management Assets	6.9		6.4


Regulatory Asset for Under-Recovered Fuel Costs	—		4.9
Prepayments and Other Current Assets	25.5		29.7
TOTAL CURRENT ASSETS	412.9		354.1

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	4,691.5		4,691.4
Transmission	2,102.5		2,056.5
Distribution	2,334.8		2,270.7
Other Property, Plant and Equipment (June 30, 2020 and December 31, 2019 Amounts Include $218.6 and $212.3, Respectively, Related to Sabine)	787.4		733.4
Construction Work in Progress	209.2		216.9
Total Property, Plant and Equipment	10,125.4		9,968.9
Accumulated Depreciation and Amortization (June 30, 2020 and December 31, 2019 Amounts Include $115.2 and $107.5, Respectively, Related to Sabine)	3,022.2		2,873.7
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	7,103.2		7,095.2

OTHER NONCURRENT ASSETS
Regulatory Assets	254.8		222.4


Deferred Charges and Other Noncurrent Assets	268.7		160.5
TOTAL OTHER NONCURRENT ASSETS	523.5		382.9

TOTAL ASSETS	$	8,039.6	$	7,832.2

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

130

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

June 30, 2020 and December 31, 2019

(Unaudited)


	June 30,		December 31,
	2020		2019
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	130.4	$	59.9
Accounts Payable:
General	106.3		138.0
Affiliated Companies	56.3		53.6
Short-term Debt – Nonaffiliated	37.0		18.3
Long-term Debt Due Within One Year – Nonaffiliated	6.2		121.2
Risk Management Liabilities	1.6		1.9
Customer Deposits	64.8		65.0
Accrued Taxes	90.0		41.8
Accrued Interest	33.6		34.6

Obligations Under Operating Leases	7.9		6.5
Regulatory Liability for Over-Recovered Fuel Costs	39.8		13.6
Other Current Liabilities	95.2		120.3
TOTAL CURRENT LIABILITIES	669.1		674.7

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	2,632.2		2,534.4
Long-term Risk Management Liabilities	2.1		3.1
Deferred Income Taxes	945.7		940.9
Regulatory Liabilities and Deferred Investment Tax Credits	884.7		892.3
Asset Retirement Obligations	220.9		196.7


Obligations Under Operating Leases	44.5		34.7
Deferred Credits and Other Noncurrent Liabilities	124.3		114.3
TOTAL NONCURRENT LIABILITIES	4,854.4		4,716.4

TOTAL LIABILITIES	5,523.5		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	1,705.0		1,629.5
Accumulated Other Comprehensive Income (Loss)	(1.3)		(1.3)
TOTAL COMMON SHAREHOLDER’S EQUITY	2,516.0		2,440.5

Noncontrolling Interest	0.1		0.6

TOTAL EQUITY	2,516.1		2,441.1

TOTAL LIABILITIES AND EQUITY	$	8,039.6	$	7,832.2

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

131

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2020 and 2019

(in millions)

(Unaudited)


	Six Months Ended June 30,
	2020		2019
OPERATING ACTIVITIES
Net Income	$	75.3	$	36.3
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	135.4		123.9
Deferred Income Taxes	(12.4)		(10.1)

Allowance for Equity Funds Used During Construction	(2.3)		(2.9)
Mark-to-Market of Risk Management Contracts	(1.8)		(6.2)

Property Taxes	(33.0)		(32.2)
Deferred Fuel Over/Under-Recovery, Net	31.1		8.2
Change in Other Noncurrent Assets	(1.6)		2.9
Change in Other Noncurrent Liabilities	13.5		2.0
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(5.8)		(26.1)
Fuel, Materials and Supplies	(60.4)		(19.3)
Accounts Payable	2.9		5.5
Accrued Taxes, Net	52.0		47.7

Other Current Assets	0.2		(1.4)
Other Current Liabilities	(32.6)		23.4
Net Cash Flows from Operating Activities	160.5		151.7

INVESTING ACTIVITIES
Construction Expenditures	(228.5)		(185.2)
Change in Advances to Affiliates, Net	—		81.4
Other Investing Activities	4.3		(2.2)
Net Cash Flows Used for Investing Activities	(224.2)		(106.0)

FINANCING ACTIVITIES


Change in Short-term Debt – Nonaffiliated	18.7		—
Change in Advances from Affiliates, Net	70.5		55.3
Retirement of Long-term Debt – Nonaffiliated	(18.1)		(56.6)
Principal Payments for Finance Lease Obligations	(5.5)		(5.5)
Dividends Paid on Common Stock	—		(37.5)
Dividends Paid on Common Stock – Nonaffiliated	(1.9)		(2.2)
Other Financing Activities	0.2		0.3
Net Cash Flows from (Used for) Financing Activities	63.9		(46.2)

Net Increase (Decrease) in Cash and Cash Equivalents	0.2		(0.5)
Cash and Cash Equivalents at Beginning of Period	1.6		24.5
Cash and Cash Equivalents at End of Period	$	1.8	$	24.0

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	57.0	$	57.1
Net Cash Paid for Income Taxes	8.1		6.2
Noncash Acquisitions Under Finance Leases	4.3		2.6
Construction Expenditures Included in Current Liabilities as of June 30,	33.7		40.9

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 133.

132

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

134

New Accounting Standards

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

137

Comprehensive Income

AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo

138

Rate Matters

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

147

Commitments, Guarantees and Contingencies

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

156

Acquisitions and Impairments

AEP, APCo

161

Benefit Plans

AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo

163

Business Segments

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

167

Derivatives and Hedging

AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo

172

Fair Value Measurements

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

184

Income Taxes

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

200

Financing Activities

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

202

Property, Plant and Equipment

AEP, APCo

210

Revenue from Contracts with Customers

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo

211

133

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 and six months ended June 30, 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

As of June 30, 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 for the three and six months ended June 30, 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.

Voluntary Retirement Incentive Program

In June 2020, AEP announced a voluntary retirement incentive program. Eligible employees may volunteer for retirement from the date of the announcement through July 6, 2020, with most having an effective retirement date of August 1, 2020. Participating employees will receive up to six months base pay and a medical premium subsidy. Certain participating employees will also receive a long-term incentive plan grant, with immediate vesting, of AEP common shares. A total of 200 employees participated in the voluntary retirement program. In August 2020, AEP will record a charge to expense of $13 million primarily related to lump sum salary payments and cash subsidies. AEP also will record a charge to expense of $5 million related to the incremental Long-Term Incentive Plan grants issued related to this initiative. Approximately 92% of the expense was within the AEPSC and will be allocated among affiliated entities including Registrant Subsidiaries.

134

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 June 30,
	2020						2019
	(in millions, except per share data)
			$/share				$/share


Earnings Attributable to AEP Common Shareholders	$	520.8			$	461.3

Weighted Average Number of Basic Shares Outstanding	495.7		$	1.05	493.6		$	0.93
Weighted Average Dilutive Effect of Stock-Based Awards	1.6		—		1.8		—
Weighted Average Number of Diluted Shares Outstanding	497.3		$	1.05	495.4		$	0.93


	Six Months Ended June 30,
	2020						2019
	(in millions, except per share data)
			$/share				$/share


Earnings Attributable to AEP Common Shareholders	$	1,016.0			$	1,034.1

Weighted Average Number of Basic Shares Outstanding	495.1		$	2.05	493.4		$	2.10
Weighted Average Dilutive Effect of Stock-Based Awards	1.9		(0.01)		1.5		(0.01)
Weighted Average Number of Diluted Shares Outstanding	497.0		$	2.04	494.9		$	2.09

Equity Units issued in March 2019 are potentially dilutive securities but were excluded from the calculation of diluted EPS for the three and six months ended June 30, 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 156 thousand and 0 antidilutive shares outstanding as of June 30, 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:


	June 30, 2020
	AEP		AEP Texas		APCo
	(in millions)
Cash and Cash Equivalents	$	348.8	$	0.1	$	2.5
Restricted Cash	155.9		136.6		19.3
Total Cash, Cash Equivalents and Restricted Cash	$	504.7	$	136.7	$	21.8

135


	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.

136

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.

137

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 June 30, 2020	Commodity		Interest Rate			and OPEB		Total
	(in millions)
Balance in AOCI as of March 31, 2020	$	(128.5)	$	(53.5)		$	(34.5)	$	(216.5)
Change in Fair Value Recognized in AOCI	6.5		(2.8)		(a)	—		3.7
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (b)	(0.1)		—			—		(0.1)
Purchased Electricity for Resale (b)	51.3		—			—		51.3
Interest Expense (b)	—		1.4			—		1.4
Amortization of Prior Service Cost (Credit)	—		—			(4.6)		(4.6)
Amortization of Actuarial (Gains) Losses	—		—			2.5		2.5
Reclassifications from AOCI, before Income Tax (Expense) Benefit	51.2		1.4			(2.1)		50.5
Income Tax (Expense) Benefit	10.6		0.4			(0.4)		10.6
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	40.6		1.0			(1.7)		39.9
Net Current Period Other Comprehensive Income (Loss)	47.1		(1.8)			(1.7)		43.6
Balance in AOCI as of June 30, 2020	$	(81.4)	$	(55.3)		$	(36.2)	$	(172.9)


	Cash Flow Hedges							Pension
Three Months Ended June 30, 2019	Commodity		Interest Rate			and OPEB		Total
	(in millions)
Balance in AOCI as of March 31, 2019	$	(52.1)	$	(12.4)		$	(86.2)	$	(150.7)
Change in Fair Value Recognized in AOCI	(91.9)		(3.7)		(c)	—		(95.6)
Amount of (Gain) Loss Reclassified from AOCI

Purchased Electricity for Resale (b)	21.2		—			—		21.2
Interest Expense (b)	—		0.3			—		0.3
Amortization of Prior Service Cost (Credit)	—		—			(4.7)		(4.7)
Amortization of Actuarial (Gains) Losses	—		—			3.0		3.0
Reclassifications from AOCI, before Income Tax (Expense) Benefit	21.2		0.3			(1.7)		19.8
Income Tax (Expense) Benefit	4.4		0.1			(0.3)		4.2
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	16.8		0.2			(1.4)		15.6
Net Current Period Other Comprehensive Income (Loss)	(75.1)		(3.5)			(1.4)		(80.0)
Balance in AOCI as of June 30, 2019	$	(127.2)	$	(15.9)		$	(87.6)	$	(230.7)

138

AEP


	Cash Flow Hedges							Pension
Six Months Ended June 30, 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	(58.8)		(45.5)		(a)	—		(104.3)
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (b)	(0.2)		—			—		(0.2)
Purchased Electricity for Resale (b)	102.4		—			—		102.4
Interest Expense (b)	—		2.3			—		2.3
Amortization of Prior Service Cost (Credit)	—		—			(9.5)		(9.5)
Amortization of Actuarial (Gains) Losses	—		—			5.1		5.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit	102.2		2.3			(4.4)		100.1
Income Tax (Expense) Benefit	21.3		0.6			(0.9)		21.0
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	80.9		1.7			(3.5)		79.1
Net Current Period Other Comprehensive Income (Loss)	22.1		(43.8)			(3.5)		(25.2)
Balance in AOCI as of June 30, 2020	$	(81.4)	$	(55.3)		$	(36.2)	$	(172.9)


	Cash Flow Hedges							Pension
Six Months Ended June 30, 2019	Commodity		Interest Rate			and OPEB		Total
	(in millions)
Balance in AOCI as of December 31, 2018	$	(23.0)	$	(12.6)		$	(84.8)	$	(120.4)
Change in Fair Value Recognized in AOCI	(130.7)		(3.7)		(c)	—		(134.4)
Amount of (Gain) Loss Reclassified from AOCI

Purchased Electricity for Resale (b)	33.5		—			—		33.5
Interest Expense (b)	—		0.5			—		0.5
Amortization of Prior Service Cost (Credit)	—		—			(9.5)		(9.5)
Amortization of Actuarial (Gains) Losses	—		—			6.0		6.0
Reclassifications from AOCI, before Income Tax (Expense) Benefit	33.5		0.5			(3.5)		30.5
Income Tax (Expense) Benefit	7.0		0.1			(0.7)		6.4
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	26.5		0.4			(2.8)		24.1
Net Current Period Other Comprehensive Income (Loss)	(104.2)		(3.3)			(2.8)		(110.3)
Balance in AOCI as of June 30, 2019	$	(127.2)	$	(15.9)		$	(87.6)	$	(230.7)

139

AEP Texas


		Cash Flow Hedge –		Pension
Three Months Ended June 30, 2020		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of March 31, 2020		$	(3.1)	$	(9.4)	$	(12.5)
Change in Fair Value Recognized in AOCI		—		—		—
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)		0.2		—		0.2

Amortization of Actuarial (Gains) Losses		—		0.1		0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.2		0.1		0.3
Income Tax (Expense) Benefit		—		—		—
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.2		0.1		0.3
Net Current Period Other Comprehensive Income (Loss)		0.2		0.1		0.3
Balance in AOCI as of June 30, 2020		$	(2.9)	$	(9.3)	$	(12.2)


		Cash Flow Hedge –		Pension
Three Months Ended June 30, 2019		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of March 31, 2019		$	(4.1)	$	(10.7)	$	(14.8)
Change in Fair Value Recognized in AOCI		—		—		—
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)		0.2		—		0.2

Amortization of Actuarial (Gains) Losses		—		0.1		0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.2		0.1		0.3
Income Tax (Expense) Benefit		—		—		—
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.2		0.1		0.3
Net Current Period Other Comprehensive Income (Loss)		0.2		0.1		0.3
Balance in AOCI as of June 30, 2019		$	(3.9)	$	(10.6)	$	(14.5)


		Cash Flow Hedge –		Pension
Six Months Ended June 30, 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)		0.6		—		0.6

Amortization of Actuarial (Gains) Losses		—		0.1		0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.6		0.1		0.7
Income Tax (Expense) Benefit		0.1		—		0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.5		0.1		0.6
Net Current Period Other Comprehensive Income (Loss)		0.5		0.1		0.6
Balance in AOCI as of June 30, 2020		$	(2.9)	$	(9.3)	$	(12.2)


		Cash Flow Hedge –		Pension
Six Months Ended June 30, 2019		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of December 31, 2018		$	(4.4)	$	(10.7)	$	(15.1)
Change in Fair Value Recognized in AOCI		—		—		—
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)		0.6		—		0.6

Amortization of Actuarial (Gains) Losses		—		0.1		0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.6		0.1		0.7
Income Tax (Expense) Benefit		0.1		—		0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.5		0.1		0.6
Net Current Period Other Comprehensive Income (Loss)		0.5		0.1		0.6
Balance in AOCI as of June 30, 2019		$	(3.9)	$	(10.6)	$	(14.5)

140

APCo


		Cash Flow Hedge –		Pension
Three Months Ended June 30, 2020		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of March 31, 2020		$	(3.3)	$	3.2	$	(0.1)
Change in Fair Value Recognized in AOCI		(0.6)		—		(0.6)
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)		(0.2)		—		(0.2)
Amortization of Prior Service Cost (Credit)		—		(1.4)		(1.4)
Amortization of Actuarial (Gains) Losses		—		0.2		0.2
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(0.2)		(1.2)		(1.4)
Income Tax (Expense) Benefit		—		(0.2)		(0.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.2)		(1.0)		(1.2)
Net Current Period Other Comprehensive Income (Loss)		(0.8)		(1.0)		(1.8)
Balance in AOCI as of June 30, 2020		$	(4.1)	$	2.2	$	(1.9)


		Cash Flow Hedge –		Pension
Three Months Ended June 30, 2019		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of March 31, 2019		$	1.6	$	(7.4)	$	(5.8)
Change in Fair Value Recognized in AOCI		—		—		—
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)		(0.2)		—		(0.2)
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		(0.2)		(0.8)		(1.0)
Income Tax (Expense) Benefit		—		(0.1)		(0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.2)		(0.7)		(0.9)
Net Current Period Other Comprehensive Income (Loss)		(0.2)		(0.7)		(0.9)
Balance in AOCI as of June 30, 2019		$	1.4	$	(8.1)	$	(6.7)


		Cash Flow Hedge –		Pension
Six Months Ended June 30, 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		(4.5)		—		(4.5)
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)		(0.6)		—		(0.6)
Amortization of Prior Service Cost (Credit)		—		(2.7)		(2.7)
Amortization of Actuarial (Gains) Losses		—		0.3		0.3
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(0.6)		(2.4)		(3.0)
Income Tax (Expense) Benefit		(0.1)		(0.5)		(0.6)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.5)		(1.9)		(2.4)
Net Current Period Other Comprehensive Income (Loss)		(5.0)		(1.9)		(6.9)
Balance in AOCI as of June 30, 2020		$	(4.1)	$	2.2	$	(1.9)


		Cash Flow Hedge –		Pension
Six Months Ended June 30, 2019		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of December 31, 2018		$	1.8	$	(6.8)	$	(5.0)
Change in Fair Value Recognized in AOCI		—		—		—
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)		(0.5)		—		(0.5)
Amortization of Prior Service Cost (Credit)		—		(2.6)		(2.6)
Amortization of Actuarial (Gains) Losses		—		1.0		1.0
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(0.5)		(1.6)		(2.1)
Income Tax (Expense) Benefit		(0.1)		(0.3)		(0.4)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.4)		(1.3)		(1.7)
Net Current Period Other Comprehensive Income (Loss)		(0.4)		(1.3)		(1.7)
Balance in AOCI as of June 30, 2019		$	1.4	$	(8.1)	$	(6.7)

141

I&M


		Cash Flow Hedge –		Pension
Three Months Ended June 30, 2020		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of March 31, 2020		$	(9.5)	$	(1.7)	$	(11.2)
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)		—		(0.1)		(0.1)
Amortization of Actuarial (Gains) Losses		—		0.1		0.1
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 June 30, 2020		$	(9.1)	$	(1.7)	$	(10.8)


		Cash Flow Hedge –		Pension
Three Months Ended June 30, 2019		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of March 31, 2019		$	(11.1)	$	(2.3)	$	(13.4)
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)		—		(0.2)		(0.2)
Amortization of Actuarial (Gains) Losses		—		0.1		0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.5		(0.1)		0.4
Income Tax (Expense) Benefit		0.1		—		0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.4		(0.1)		0.3
Net Current Period Other Comprehensive Income (Loss)		0.4		(0.1)		0.3
Balance in AOCI as of June 30, 2019		$	(10.7)	$	(2.4)	$	(13.1)


		Cash Flow Hedge –		Pension
Six Months Ended June 30, 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)		1.0		—		1.0
Amortization of Prior Service Cost (Credit)		—		(0.3)		(0.3)
Amortization of Actuarial (Gains) Losses		—		0.3		0.3
Reclassifications from AOCI, before Income Tax (Expense) Benefit		1.0		—		1.0
Income Tax (Expense) Benefit		0.2		—		0.2
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.8		—		0.8
Net Current Period Other Comprehensive Income (Loss)		0.8		—		0.8
Balance in AOCI as of June 30, 2020		$	(9.1)	$	(1.7)	$	(10.8)


		Cash Flow Hedge –		Pension
Six Months Ended June 30, 2019		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of December 31, 2018		$	(11.5)	$	(2.3)	$	(13.8)
Change in Fair Value Recognized in AOCI		—		—		—
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)		1.0		—		1.0
Amortization of Prior Service Cost (Credit)		—		(0.4)		(0.4)
Amortization of Actuarial (Gains) Losses		—		0.3		0.3
Reclassifications from AOCI, before Income Tax (Expense) Benefit		1.0		(0.1)		0.9
Income Tax (Expense) Benefit		0.2		—		0.2
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.8		(0.1)		0.7
Net Current Period Other Comprehensive Income (Loss)		0.8		(0.1)		0.7
Balance in AOCI as of June 30, 2019		$	(10.7)	$	(2.4)	$	(13.1)

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OPCo

Cash Flow Hedge –

Three Months Ended June 30, 2020

Interest Rate

(in millions)

Balance in AOCI as of March 31, 2020

—

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 June 30, 2020

—


		Cash Flow Hedge –
Three Months Ended June 30, 2019		Interest Rate
	(in millions)
Balance in AOCI as of March 31, 2019		$	0.7
Change in Fair Value Recognized in AOCI		—
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)		(0.5)


Reclassifications from AOCI, before Income Tax (Expense) Benefit		(0.5)
Income Tax (Expense) Benefit		(0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.4)
Net Current Period Other Comprehensive Income (Loss)		(0.4)
Balance in AOCI as of June 30, 2019		$	0.3

Cash Flow Hedge –

Six Months Ended June 30, 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 June 30, 2020

—


		Cash Flow Hedge –
Six Months Ended June 30, 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)		(0.9)


Reclassifications from AOCI, before Income Tax (Expense) Benefit		(0.9)
Income Tax (Expense) Benefit		(0.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.7)
Net Current Period Other Comprehensive Income (Loss)		(0.7)
Balance in AOCI as of June 30, 2019		$	0.3

143

PSO


		Cash Flow Hedge –
Three Months Ended June 30, 2020		Interest Rate
	(in millions)
Balance in AOCI as of March 31, 2020		$	0.9
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 June 30, 2020		$	0.6


		Cash Flow Hedge –
Three Months Ended June 30, 2019		Interest Rate
	(in millions)
Balance in AOCI as of March 31, 2019		$	1.9
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 June 30, 2019		$	1.6


		Cash Flow Hedge –
Six Months Ended June 30, 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)		(0.7)


Reclassifications from AOCI, before Income Tax (Expense) Benefit		(0.7)
Income Tax (Expense) Benefit		(0.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.5)
Net Current Period Other Comprehensive Income (Loss)		(0.5)
Balance in AOCI as of June 30, 2020		$	0.6


		Cash Flow Hedge –
Six Months Ended June 30, 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)		(0.7)


Reclassifications from AOCI, before Income Tax (Expense) Benefit		(0.7)
Income Tax (Expense) Benefit		(0.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.5)
Net Current Period Other Comprehensive Income (Loss)		(0.5)
Balance in AOCI as of June 30, 2019		$	1.6

144

SWEPCo


		Cash Flow Hedge –		Pension
Three Months Ended June 30, 2020		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of March 31, 2020		$	(1.4)	$	0.1	$	(1.3)
Change in Fair Value Recognized in AOCI		—		—		—
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)		0.4		—		0.4
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		0.4		(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 June 30, 2020		$	(1.1)	$	(0.2)	$	(1.3)


		Cash Flow Hedge –		Pension
Three Months Ended June 30, 2019		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of March 31, 2019		$	(2.9)	$	(2.4)	$	(5.3)
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)
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 June 30, 2019		$	(2.5)	$	(2.7)	$	(5.2)

145

SWEPCo


		Cash Flow Hedge –		Pension
Six Months Ended June 30, 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)		0.9		—		0.9
Amortization of Prior Service Cost (Credit)		—		(1.0)		(1.0)
Amortization of Actuarial (Gains) Losses		—		0.1		0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.9		(0.9)		—
Income Tax (Expense) Benefit		0.2		(0.2)		—
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.7		(0.7)		—
Net Current Period Other Comprehensive Income (Loss)		0.7		(0.7)		—
Balance in AOCI as of June 30, 2020		$	(1.1)	$	(0.2)	$	(1.3)


		Cash Flow Hedge –		Pension
Six Months Ended June 30, 2019		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of December 31, 2018		$	(3.3)	$	(2.1)	$	(5.4)
Change in Fair Value Recognized in AOCI		—		—		—
Amount of (Gain) Loss Reclassified from AOCI


Interest Expense (b)		1.0		—		1.0
Amortization of Prior Service Cost (Credit)		—		(1.0)		(1.0)
Amortization of Actuarial (Gains) Losses		—		0.2		0.2
Reclassifications from AOCI, before Income Tax (Expense) Benefit		1.0		(0.8)		0.2
Income Tax (Expense) Benefit		0.2		(0.2)		—
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.8		(0.6)		0.2
Net Current Period Other Comprehensive Income (Loss)		0.8		(0.6)		0.2
Balance in AOCI as of June 30, 2019		$	(2.5)	$	(2.7)	$	(5.2)

(a)The change in fair value includes $2 million and $7 million related to AEP's investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC for the three and six months ended June 30, 2020, respectively.

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

(c)The change in fair value includes $4 million related to AEP’s investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC in 2019.

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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 June 30, 2020.


Plant	Gross Investment Including CWIP		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	$	101.9	$	98.6	$	3.3	$	38.6	(a)	$	3.4	$	5.2	2020	27 years
Dolet Hills Power Station	345.7		227.5		118.2		29.8		(b)	5.8		23.9		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)

147

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
	June 30,				December 31,
	2020				2019
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Oklaunion Power Station Accelerated Depreciation	$	38.6			$	27.4
Kentucky Deferred Purchase Power Expenses	35.7				30.2
Plant Retirement Costs – Unrecovered Plant	35.2				35.2

Dolet Hills Power Station Accelerated Depreciation	29.8				—
COVID-19	0.6				—
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
Storm-Related Costs	9.9				7.2
Asset Retirement Obligation	8.2				7.2
COVID-19	4.7				—
Vegetation Management Program (a)	3.3				29.4
Cook Plant Study Costs (b)	—				7.6
Other Regulatory Assets Pending Final Regulatory Approval	5.9				6.7
Total Regulatory Assets Pending Final Regulatory Approval (c)			$	199.9			$	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 June 30, 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.

148


	AEP Texas
	June 30,		December 31,
	2020		2019
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Not Earning a Return
Vegetation Management Program (a)	$	3.3	$	29.4
COVID-19	2.2		—
Other Regulatory Assets Pending Final Regulatory Approval	1.5		1.4
Total Regulatory Assets Pending Final Regulatory Approval	$	7.0	$	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
	June 30,		December 31,
	2020		2019
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
COVID-19 – Virginia	$	0.6	$	—
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
COVID-19 – West Virginia	0.5		—

Total Regulatory Assets Pending Final Regulatory Approval (a)	$	27.0	$	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 June 30, 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
	June 30,		December 31,
	2020		2019
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Not Earning a Return
COVID-19	$	0.9	$	—
Cook Plant Study Costs (a)	—		7.6
Other Regulatory Assets Pending Final Regulatory Approval	—		0.1
Total Regulatory Assets Pending Final Regulatory Approval	$	0.9	$	7.7

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


	OPCo
	June 30,		December 31,
	2020		2019
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Not Earning a Return



Storm-Related Costs	$	2.2	$	—
Other Regulatory Assets Pending Final Regulatory Approval	0.1		0.1
Total Regulatory Assets Pending Final Regulatory Approval	$	2.3	$	0.1

149


	PSO
	June 30,		December 31,
	2020		2019
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Oklaunion Power Station Accelerated Depreciation	$	38.6	$	27.4

Regulatory Assets Currently Not Earning a Return


Storm-Related Costs	7.7		7.2
Total Regulatory Assets Pending Final Regulatory Approval	$	46.3	$	34.6


	SWEPCo
	June 30,		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	29.8		—
Other Regulatory Assets Pending Final Regulatory Approval	2.2		0.2
Regulatory Assets Currently Not Earning a Return
Asset Retirement Obligation - Louisiana	8.2		7.2


COVID-19	0.5		—
Other Regulatory Assets Pending Final Regulatory Approval	2.8		3.7
Total Regulatory Assets Pending Final Regulatory Approval	$	78.7	$	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 continuing adverse 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 have worked with their state commissions to achieve deferral authority for increased costs incurred due to COVID-19. The majority of these jurisdictions have provided deferral authority for incremental COVID-19 costs including uncollectible expense. Initial COVID-19 orders for deferrals have yet to be issued by Kentucky and Tennessee. If any costs related to COVID-19 are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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% ROE. 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% ROE 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

150

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.

Hurricane Hanna

In July 2020, Hurricane Hanna, a category 1 storm hit Corpus Christi, Laredo and the Rio Grande Valley districts, causing power outages in the AEP Texas service territory. AEP Texas has completed the restoration of power to all customers that are able to accept service. At one point, as many as 200,000 customers were without power. AEP Texas has a PUCT approved catastrophe reserve which allows for the deferral of incremental storm expenses as a regulatory asset and currently recovers approximately $4 million annually through base rates. As restoration efforts continue, AEP Texas’ total costs related to this storm are not final. If any costs related to Hurricane Hanna are not recoverable, it could reduce future net income and cash flows and impact financial condition.

AEP Texas Interim Transmission and Distribution Rates

As of June 30, 2020, AEP Texas’ cumulative revenues from interim base rate increases from 2020, subject to review, are estimated to be $12 million. A base rate review could result in a refund to customers if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. AEP Texas is required to file for a comprehensive rate review no later than April 3, 2024.

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

151

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 in base rates based upon a proposed 9.9% ROE. 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 generation assets, 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 June 30, 2020 and December 31, 2019, APCo has approximately $52 million and $51 million of Virginia jurisdictional AMR meters as well as $83 million and $75 million of Virginia jurisdictional AMI 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.

In July 2020, a certain intervenor filed testimony asserting that APCo had a revenue surplus of $23 million for its filed rate year based upon the intervenor’s recommended ROE of 8.75%. The intervenor also filed proposed adjustments to APCo’s requested revenue requirement including: (a) a reduction to depreciation expense to reflect a 2040 retirement date for Amos Plant instead of 2032 for Amos Units 1 and 2 and 2033 for Amos Unit 3 as proposed by APCo, (b) removal of AMI meters from rate base along with related depreciation and (c) a reduction of purchased power expense related to OVEC demand charges. This intervenor, along with one other intervenor, also proposed the removal of major storm expenses.

In addition, this certain intervenor filed testimony contending APCo’s earned return for the Triennial period was 11.12%, which equates to $59 million in earnings (subject to 70% refund provision described above) above the top of the ROE range on a revenue basis. The intervenor also filed a separate legal memorandum opposing the inclusion of the 2019 expensing of the retired coal-fired generation assets from APCo’s 2017-2019 earnings test results. The testimony also removed the related rate base associated with the retired coal units. Another intervenor recommended a disallowance that could potentially result in a write-off of $121 million related to the recovery of capital expenditures incurred for the Amos and Mountaineer coal-fired generation plants during 2017-2019. An intervenor also recommended that APCo not earn a return on $114 million of prepaid pension and OPEB assets. Testimony from Virginia Staff must be filed by mid-August 2020. APCo expects to receive an order in the fourth quarter of 2020.

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.

West Virginia ENEC and Vegetation Management Riders

In June 2020, the WVPSC issued an order to increase rider rates relating to ENEC and vegetation management by a combined $101 million ($81 million related to APCo) over twelve months beginning September 2020. This increase will be partially offset by a refund of $38 million ($31 million related to APCo) of Excess ADIT that is not subject to normalization requirements over ten months beginning September 2020. These transactions will result in no overall impact to net income.

152

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 June 30, 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% ROE. 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 ROE 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. In May 2020, the IURC issued an order denying I&M’s request for rehearing. In June 2020, I&M filed a motion for voluntary dismissal of its appeal with the IURC.

KPCo Rate Matters (Applies to AEP)

Kentucky Tax Reform

In May 2020, KPCo filed a request with the KPSC to issue a one-time refund of Excess ADIT that is not subject to normalization requirements to customers of approximately $11 million to eliminate certain customer delinquencies attributable to the COVID-19 pandemic. If any costs related to COVID-19 are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2020 Kentucky Base Rate Case

In June 2020, KPCo filed a request with the KPSC for a $65 million net annual increase in base rates based upon a proposed 10% ROE with the increase to be implemented no earlier than January 2021. The filing proposes that KPCo would offset the first year of rate increases by refunding Excess ADIT that is not subject to normalization requirements to customers. Additionally, KPCo requested recovery of the previously authorized deferral of $50 million of Rockport Plant Unit Power Agreement expenses and related carrying charges over a 5-year period beginning in December 2022, through an existing purchased power rider. 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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OPCo Rate Matters (Applies to AEP and OPCo)

2020 Ohio Base Rate Case

In June 2020, OPCo filed a request with the PUCO for a $42 million annual increase in base rates based upon a proposed 10.15% ROE net of existing riders. Additionally, OPCo filed a request with the PUCO for a 60-day temporary delay of the normal rate case proceeding due to the COVID-19 pandemic with rates expected to be effective approximately mid-2021. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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 June 30, 2020, the net book value of Turk Plant was $1.4 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% ROE. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $50 million based upon a ROE 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

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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 through a tax rider that will end when the Excess ADIT not subject to normalization requirements is fully refunded to customers which is currently estimated to be July 2020.

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. In July 2020, the LPSC issued an order approving an unopposed stipulation and settlement agreement for a one-time refund of $6 million over three months beginning in August 2020.

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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 June 30, 2020, no letters of credit were issued under the revolving credit facility.

Company

Amount

Maturity

(in millions)

AEP

191.6

July 2020 to July 2021

AEP Texas (a)

2.2

July 2021

OPCo

1.0

April 2021

(a)In July 2020, the maturity date was extended from July 2020 to July 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 June 30, 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 June 30, 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	$	50.2
AEP Texas	11.9
APCo	7.2
I&M	4.2
OPCo	7.5
PSO	4.7
SWEPCo	5.3

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. 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 June 30, 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 June 30, 2020 were as follows:


Future Minimum Lease Payments	AEP (a)		I&M
	(in millions)
2020	$	73.9	$	37.0
2021	147.8		73.9
2022	147.5		73.7
Total Future Minimum Lease Payments	$	369.2	$	184.6

(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 June 30, 2020, the maximum potential amount of future payments required under the guaranteed leases was $52 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 June 30, 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.

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Virginia House Bill 443 (Applies to AEP and APCo)

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)

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’s stay expired in February 2020, but the court later extended the stay through August 13, 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.

159

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

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. The denial of those claims were appealed to the AEP System Retirement Plan Appeal Committee and the Committee upheld the denial of claims. 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 AND DISPOSITIONS

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

ACQUISITIONS

Sempra Renewables LLC (Generation & Marketing Segment)

In April 2019, AEP acquired Sempra Renewables LLC and its 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 June 30, 2020, the maximum potential amount of future payments associated with these guarantees was $166 million, with the last guarantee expiring in December 2037. The non-contingent liability recorded associated with these guarantees was $32 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.

Santa Rita East (Generation & Marketing Segment)

In July 2019, AEP acquired a 75% interest, or 227 MWs, in Santa Rita East for approximately $356 million. In accordance with the accounting guidance for “Business Combinations,” management determined that the acquisition of Santa Rita East represents an asset acquisition. Additionally, and in accordance with the accounting guidance for “Consolidation,” management concluded that Santa Rita East is a VIE. As a result, to account for the initial consolidation of Santa Rita East, management applied the acquisition method by allocating the purchase price based on the relative fair value of the assets acquired and noncontrolling interest assumed. The fair value of the primary assets acquired and the noncontrolling interest assumed was determined using the market approach. The key input assumptions were the transaction price paid for AEP’s interest in Santa Rita East and recent third-party market transactions for similar wind farms.

DISPOSITIONS

Conesville Plant (Generation & Marketing Segment)

In June 2020, AEP and a non-affiliated joint-owner executed an Environmental Liability and Property Transfer and Asset Purchase Agreement (“sale agreement”) with a non-affiliated third-party related to the merchant Conesville Plant site. The purchaser took ownership of the assets and assumed responsibility for environmental liabilities, including ash pond closure, asbestos abatement and decommissioning and demolition of the Conesville Plant site.

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In consideration of the transfer of the acquired assets to the purchaser and the purchaser’s assumption of liabilities, AEP will pay approximately $98 million, derecognized a $106 million asset retirement obligation and recorded an immaterial gain on the transaction which is recorded in Other Operation on the statements of income. AEP paid approximately $26 million in June 2020 and will make additional payments totaling $28 million in quarterly installments from October 2020 to April 2021 and payments totaling $44 million in quarterly installments from July 2021 to July 2022.

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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 June 30,						Three Months Ended June 30,
	2020		2019		2020		2019
	(in millions)
Service Cost	$	28.0	$	23.9	$	2.5	$	2.3
Interest Cost	41.9		51.1		10.0		12.7
Expected Return on Plan Assets	(66.2)		(74.0)		(24.0)		(23.5)
Amortization of Prior Service Credit	—		—		(17.5)		(17.2)
Amortization of Net Actuarial Loss	23.4		14.4		1.5		5.6
Net Periodic Benefit Cost (Credit)	$	27.1	$	15.4	$	(27.5)	$	(20.1)

	Pension Plans						OPEB
	Six Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
	(in millions)
Service Cost	$	56.0	$	47.8	$	5.0	$	4.7
Interest Cost	83.9		102.2		19.9		25.3
Expected Return on Plan Assets	(132.4)		(148.0)		(47.9)		(46.9)
Amortization of Prior Service Credit	—		—		(34.9)		(34.5)
Amortization of Net Actuarial Loss	46.8		28.8		3.0		11.1
Net Periodic Benefit Cost (Credit)	$	54.3	$	30.8	$	(54.9)	$	(40.3)

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AEP Texas


	Pension Plans						OPEB
	Three Months Ended June 30,						Three Months Ended June 30,
	2020		2019		2020		2019
	(in millions)
Service Cost	$	2.4	$	2.2	$	0.2	$	0.2
Interest Cost	3.5		4.3		0.8		1.0
Expected Return on Plan Assets	(5.7)		(6.5)		(2.0)		(1.9)
Amortization of Prior Service Credit	—		—		(1.6)		(1.4)
Amortization of Net Actuarial Loss	2.0		1.3		0.2		0.4
Net Periodic Benefit Cost (Credit)	$	2.2	$	1.3	$	(2.4)	$	(1.7)

	Pension Plans						OPEB
	Six Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
	(in millions)
Service Cost	$	5.0	$	4.3	$	0.4	$	0.4
Interest Cost	7.0		8.7		1.6		2.0
Expected Return on Plan Assets	(11.4)		(12.9)		(4.0)		(3.9)
Amortization of Prior Service Credit	—		—		(3.0)		(2.9)
Amortization of Net Actuarial Loss	3.9		2.5		0.3		0.9
Net Periodic Benefit Cost (Credit)	$	4.5	$	2.6	$	(4.7)	$	(3.5)

APCo


	Pension Plans						OPEB
	Three Months Ended June 30,						Three Months Ended June 30,
	2020		2019		2020		2019
	(in millions)
Service Cost	$	2.6	$	2.3	$	0.2	$	0.2
Interest Cost	5.1		6.3		1.7		2.1
Expected Return on Plan Assets	(8.4)		(9.3)		(3.7)		(3.6)
Amortization of Prior Service Credit	—		—		(2.6)		(2.5)
Amortization of Net Actuarial Loss	2.8		1.7		0.3		0.9
Net Periodic Benefit Cost (Credit)	$	2.1	$	1.0	$	(4.1)	$	(2.9)

	Pension Plans						OPEB
	Six Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
	(in millions)
Service Cost	$	5.2	$	4.7	$	0.5	$	0.5
Interest Cost	10.2		12.6		3.3		4.3
Expected Return on Plan Assets	(16.8)		(18.7)		(7.3)		(7.3)
Amortization of Prior Service Credit	—		—		(5.1)		(5.0)
Amortization of Net Actuarial Loss	5.6		3.5		0.5		1.8
Net Periodic Benefit Cost (Credit)	$	4.2	$	2.1	$	(8.1)	$	(5.7)

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I&M


	Pension Plans						OPEB
	Three Months Ended June 30,						Three Months Ended June 30,
	2020		2019		2020		2019
	(in millions)
Service Cost	$	3.8	$	3.3	$	0.4	$	0.4
Interest Cost	4.9		5.9		1.1		1.4
Expected Return on Plan Assets	(8.3)		(9.2)		(2.9)		(2.9)
Amortization of Prior Service Credit	—		—		(2.4)		(2.3)
Amortization of Net Actuarial Loss	2.7		1.7		0.2		0.6
Net Periodic Benefit Cost (Credit)	$	3.1	$	1.7	$	(3.6)	$	(2.8)

	Pension Plans						OPEB
	Six Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
	(in millions)
Service Cost	$	7.7	$	6.7	$	0.7	$	0.7
Interest Cost	9.8		11.9		2.3		2.9
Expected Return on Plan Assets	(16.6)		(18.4)		(5.8)		(5.7)
Amortization of Prior Service Credit	—		—		(4.8)		(4.7)
Amortization of Net Actuarial Loss	5.4		3.3		0.4		1.3
Net Periodic Benefit Cost (Credit)	$	6.3	$	3.5	$	(7.2)	$	(5.5)

OPCo


	Pension Plans						OPEB
	Three Months Ended June 30,						Three Months Ended June 30,
	2020		2019		2020		2019
	(in millions)
Service Cost	$	2.4	$	2.0	$	0.3	$	0.2
Interest Cost	3.8		4.8		1.1		1.3
Expected Return on Plan Assets	(6.5)		(7.4)		(2.7)		(2.7)
Amortization of Prior Service Credit	—		—		(1.7)		(1.7)
Amortization of Net Actuarial Loss	2.2		1.4		0.1		0.7
Net Periodic Benefit Cost (Credit)	$	1.9	$	0.8	$	(2.9)	$	(2.2)

	Pension Plans						OPEB
	Six Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
	(in millions)
Service Cost	$	4.8	$	4.0	$	0.5	$	0.4
Interest Cost	7.7		9.5		2.1		2.7
Expected Return on Plan Assets	(13.1)		(14.7)		(5.3)		(5.4)
Amortization of Prior Service Credit	—		—		(3.5)		(3.4)
Amortization of Net Actuarial Loss	4.3		2.7		0.3		1.3
Net Periodic Benefit Cost (Credit)	$	3.7	$	1.5	$	(5.9)	$	(4.4)

165

PSO


	Pension Plans						OPEB
	Three Months Ended June 30,						Three Months Ended June 30,
	2020		2019		2020		2019
	(in millions)
Service Cost	$	1.8	$	1.7	$	0.1	$	0.1
Interest Cost	2.2		2.7		0.5		0.6
Expected Return on Plan Assets	(3.7)		(4.1)		(1.3)		(1.3)
Amortization of Prior Service Credit	—		—		(1.1)		(1.0)
Amortization of Net Actuarial Loss	1.2		0.7		0.1		0.3
Net Periodic Benefit Cost (Credit)	$	1.5	$	1.0	$	(1.7)	$	(1.3)

	Pension Plans						OPEB
	Six Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
	(in millions)
Service Cost	$	3.6	$	3.3	$	0.3	$	0.3
Interest Cost	4.3		5.3		1.0		1.3
Expected Return on Plan Assets	(7.3)		(8.2)		(2.6)		(2.6)
Amortization of Prior Service Credit	—		—		(2.2)		(2.1)
Amortization of Net Actuarial Loss	2.4		1.5		0.2		0.6
Net Periodic Benefit Cost (Credit)	$	3.0	$	1.9	$	(3.3)	$	(2.5)

SWEPCo


	Pension Plans						OPEB
	Three Months Ended June 30,						Three Months Ended June 30,
	2020		2019		2020		2019
	(in millions)
Service Cost	$	2.4	$	2.2	$	0.2	$	0.2
Interest Cost	2.6		3.1		0.7		0.8
Expected Return on Plan Assets	(3.9)		(4.5)		(1.7)		(1.5)
Amortization of Prior Service Credit	—		—		(1.3)		(1.3)
Amortization of Net Actuarial Loss	1.4		0.8		0.1		0.4
Net Periodic Benefit Cost (Credit)	$	2.5	$	1.6	$	(2.0)	$	(1.4)

	Pension Plans						OPEB
	Six Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
	(in millions)
Service Cost	$	4.9	$	4.3	$	0.4	$	0.4
Interest Cost	5.1		6.2		1.3		1.6
Expected Return on Plan Assets	(7.8)		(8.9)		(3.2)		(3.0)
Amortization of Prior Service Credit	—		—		(2.6)		(2.6)
Amortization of Net Actuarial Loss	2.8		1.7		0.2		0.7
Net Periodic Benefit Cost (Credit)	$	5.0	$	3.3	$	(3.9)	$	(2.9)

166

8. BUSINESS SEGMENTS

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

AEP’s Reportable Segments

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

Vertically Integrated Utilities

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

Transmission and Distribution Utilities

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

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

AEP Transmission Holdco

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

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

Generation & Marketing

•Competitive generation in ERCOT and PJM.

•Contracted renewable energy investments and management services.

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

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

167

The tables below present AEP’s reportable segment income statement information for the three and six months ended June 30, 2020 and 2019 and reportable segment balance sheet information as of June 30, 2020 and December 31, 2019.


	Three Months Ended June 30, 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	$	2,062.3	$	1,009.4	$	69.2	$	350.2	$	2.9	$	—	$	3,494.0
Other Operating Segments	29.7		25.1		180.5		26.7		16.6		(278.6)		—
Total Revenues	$	2,092.0	$	1,034.5	$	249.7	$	376.9	$	19.5	$	(278.6)	$	3,494.0



Net Income (Loss)	$	256.3	$	139.5	$	92.2	$	58.5	$	(32.0)	$	—	$	514.5

	Three Months Ended June 30, 2019
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other (a)		Reconciling Adjustments		Consolidated
	(in millions)
Revenues from:
External Customers	$	2,116.4	$	1,001.6	$	69.8	$	382.9	$	2.9	$	—	$	3,573.6
Other Operating Segments	7.4		44.1		209.1		29.8		20.9		(311.3)		—
Total Revenues	$	2,123.8	$	1,045.7	$	278.9	$	412.7	$	23.8	$	(311.3)	$	3,573.6



Net Income (Loss)	$	178.8	$	131.4	$	155.4	$	5.2	$	(11.7)	$	—	$	459.1



	Six Months Ended June 30, 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	$	4,255.3	$	2,084.6	$	142.3	$	758.6	$	0.7	$	—	$	7,241.5
Other Operating Segments	63.4		56.8		417.6		56.9		38.7		(633.4)		—
Total Revenues	$	4,318.7	$	2,141.4	$	559.9	$	815.5	$	39.4	$	(633.4)	$	7,241.5


Net Income (Loss)	$	502.6	$	255.7	$	233.8	$	89.0	$	(67.3)	$	—	$	1,013.8

	Six Months Ended June 30, 2019
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other (a)		Reconciling Adjustments		Consolidated
	(in millions)
Revenues from:
External Customers	$	4,488.7	$	2,181.4	$	131.0	$	822.6	$	6.7	$	—	$	7,630.4
Other Operating Segments	38.4		86.3		404.3		71.9		42.6		(643.5)		—
Total Revenues	$	4,527.1	$	2,267.7	$	535.3	$	894.5	$	49.3	$	(643.5)	$	7,630.4



Net Income (Loss)	$	482.4	$	287.9	$	280.6	$	44.4	$	(62.1)	$	—	$	1,033.2

168


	June 30, 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	$	48,233.4	$	20,650.2	$	10,994.4	$	1,772.1	$	408.6		$	(354.5)	(b)	$	81,704.2
Accumulated Depreciation and Amortization	15,130.5		4,001.7		508.2		134.7		188.9			(186.6)		(b)	19,777.4
Total Property Plant and Equipment - Net	$	33,102.9	$	16,648.5	$	10,486.2	$	1,637.4	$	219.7		$	(167.9)	(b)	$	61,926.8

Total Assets	$	41,991.2	$	19,209.5	$	11,804.0	$	3,249.0	$	5,897.9	(c)	$	(4,346.8)	(b) (d)	$	77,804.8

Long-term Debt Due Within One Year:
Affiliated	$	20.0	$	—	$	—	$	—	$	—		$	(20.0)		$	—
Nonaffiliated	1,390.8		239.2		—		—		507.7		(e)	—			2,137.7

Long-term Debt:
Affiliated	39.0		—		—		—		—			(39.0)			—
Nonaffiliated	12,007.4		6,552.9		4,121.9		—		3,955.5		(e)	—			26,637.7

Total Long-term Debt	$	13,457.2	$	6,792.1	$	4,121.9	$	—	$	4,463.2		$	(59.0)		$	28,775.4


	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 are inclusive of 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.

169

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 and six months ended June 30, 2020 and 2019 and reportable segment balance sheet information as of June 30, 2020 and December 31, 2019.


	Three Months Ended June 30, 2020
	State Transcos		AEPTCo Parent			Reconciling Adjustments			AEPTCo Consolidated
	(in millions)
Revenues from:
External Customers	$	60.4	$	—		$	—		$	60.4
Sales to AEP Affiliates	177.7		—			—			177.7

Total Revenues	$	238.1	$	—		$	—		$	238.1

Interest Income	$	0.7	$	38.9		$	(38.3)	(a)	$	1.3
Interest Expense	32.8		38.3			(38.3)		(a)	32.8
Income Tax Expense	19.2		0.1			—			19.3


Net Income	$	73.2	$	0.5	(b)	$	—		$	73.7

	Three Months Ended June 30, 2019
	State Transcos		AEPTCo Parent			Reconciling Adjustments			AEPTCo Consolidated
	(in millions)
Revenues from:
External Customers	$	57.8	$	—		$	—		$	57.8
Sales to AEP Affiliates	209.1		—			—			209.1

Total Revenues	$	266.9	$	—		$	—		$	266.9

Interest Income	$	0.2	$	29.0		$	(28.6)	(a)	$	0.6
Interest Expense	21.4		28.6			(28.6)		(a)	21.4
Income Tax Expense	32.9		0.1			—			33.0


Net Income	$	135.6	$	0.4	(b)	$	—		$	136.0

170


	Six Months Ended June 30, 2020
	State Transcos		AEPTCo Parent			Reconciling Adjustments			AEPTCo Consolidated
	(in millions)
Revenues from:
External Customers	$	121.7	$	—		$	—		$	121.7
Sales to AEP Affiliates	411.4		—			—			411.4
Other Revenues	0.6		—			—			0.6
Total Revenues	$	533.7	$	—		$	—		$	533.7

Interest Income	$	0.9	$	72.9		$	(71.7)	(a)	$	2.1
Interest Expense	62.4		71.7			(71.7)		(a)	62.4
Income Tax Expense	51.0		0.1			—			51.1


Net Income	$	190.5	$	1.0	(b)	$	—		$	191.5

	Six Months Ended June 30, 2019
	State Transcos		AEPTCo Parent			Reconciling Adjustments			AEPTCo Consolidated
	(in millions)
Revenues from:
External Customers	$	108.1	$	—		$	—		$	108.1
Sales to AEP Affiliates	402.3		—			—			402.3

Total Revenues	$	510.4	$	—		$	—		$	510.4

Interest Income	$	0.4	$	57.4		$	(56.5)	(a)	$	1.3
Interest Expense	43.1		56.5			(56.5)		(a)	43.1
Income Tax Expense	60.5		0.1			—			60.6


Net Income	$	239.8	$	0.5	(b)	$	—		$	240.3


































	June 30, 2020
	State Transcos		AEPTCo Parent			Reconciling Adjustments			AEPTCo Consolidated
	(in millions)
Total Transmission Property	$	10,545.4	$	—		$	—		$	10,545.4
Accumulated Depreciation and Amortization	488.3		—			—			488.3
Total Transmission Property – Net	$	10,057.1	$	—		$	—		$	10,057.1

Notes Receivable - Affiliated	$	—	$	3,947.4		$	(3,947.4)	(c)	$	—

Total Assets	$	10,434.6	$	4,064.3	(d)	$	(4,023.2)	(e)	$	10,475.7

Total Long-term Debt	$	3,990.0	$	3,947.4		$	(3,990.0)	(c)	$	3,947.4

	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.

171

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.

172

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

Notional Volume of Derivative Instruments

June 30, 2020


Primary Risk Exposure	Unit of Measure	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
		(in millions)
Commodity:
Power	MWhs	463.9		—		98.1		39.7		3.1		32.0		9.6

Natural Gas	MMBtus	36.8		—		—		—		—		—		9.7
Heating Oil and Gasoline	Gallons	10.2		2.6		1.6		0.9		2.0		1.1		1.4
Interest Rate	USD	$	137.1	$	—	$	—	$	—	$	—	$	—	$	—

Interest Rate on Long-term Debt	USD	$	200.0	$	—	$	200.0	$	—	$	—	$	—	$	—

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.

173

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 June 30, 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 $36 million and $39 million as of June 30, 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 Registrant Subsidiaries as of June 30, 2020 and December 31, 2019.

174

The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets:

AEP

Fair Value of Derivative Instruments

June 30, 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	$	349.5	$	15.4	$	0.1	$	365.0	$	(214.9)	$	150.1
Long-term Risk Management Assets	307.7		19.1		—		326.8		(79.7)		247.1
Total Assets	657.2		34.5		0.1		691.8		(294.6)		397.2

Current Risk Management Liabilities	264.5		72.1		5.9		342.5		(240.0)		102.5
Long-term Risk Management Liabilities	272.1		63.3		—		335.4		(90.2)		245.2
Total Liabilities	536.6		135.4		5.9		677.9		(330.2)		347.7

Total MTM Derivative Contract Net Assets (Liabilities)	$	120.6	$	(100.9)	$	(5.8)	$	13.9	$	35.6	$	49.5

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

175

AEP Texas

Fair Value of Derivative Instruments

June 30, 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	0.6		(0.5)		0.1
Long-term Risk Management Liabilities	—		—		—
Total Liabilities	0.6		(0.5)		0.1

Total MTM Derivative Contract Net Assets (Liabilities)	$	(0.6)	$	0.5	$	(0.1)

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

—

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

June 30, 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	$	71.2	$	0.1	$	(33.6)	$	37.7
Long-term Risk Management Assets	3.7		—		(3.3)		0.4
Total Assets	74.9		0.1		(36.9)		38.1

Current Risk Management Liabilities	35.8		5.9		(34.1)		7.6
Long-term Risk Management Liabilities	3.4		—		(3.2)		0.2
Total Liabilities	39.2		5.9		(37.3)		7.8

Total MTM Derivative Contract Net Assets (Liabilities)	$	35.7	$	(5.8)	$	0.4	$	30.3

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	$	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

176

I&M

Fair Value of Derivative Instruments

June 30, 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	$	28.6	$	(22.2)	$	6.4
Long-term Risk Management Assets	2.2		(1.9)		0.3
Total Assets	30.8		(24.1)		6.7

Current Risk Management Liabilities	22.6		(22.3)		0.3
Long-term Risk Management Liabilities	2.2		(2.0)		0.2
Total Liabilities	24.8		(24.3)		0.5

Total MTM Derivative Contract Net Assets	$	6.0	$	0.2	$	6.2

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	$	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

June 30, 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	8.9		(0.3)		8.6
Long-term Risk Management Liabilities	108.9		—		108.9
Total Liabilities	117.8		(0.3)		117.5

Total MTM Derivative Contract Net Assets (Liabilities)	$	(117.8)	$	0.3	$	(117.5)

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	$	—	$	—	$	—
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)

177

PSO

Fair Value of Derivative Instruments

June 30, 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	$	23.9	$	(0.1)	$	23.8
Long-term Risk Management Assets	—		—		—
Total Assets	23.9		(0.1)		23.8

Current Risk Management Liabilities	0.3		(0.2)		0.1
Long-term Risk Management Liabilities	—		—		—
Total Liabilities	0.3		(0.2)		0.1

Total MTM Derivative Contract Net Assets	$	23.6	$	0.1	$	23.7

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

June 30, 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	$	7.0	$	(0.1)	$	6.9
Long-term Risk Management Assets	—		—		—
Total Assets	7.0		(0.1)		6.9

Current Risk Management Liabilities	1.9		(0.3)		1.6
Long-term Risk Management Liabilities	2.1		—		2.1
Total Liabilities	4.0		(0.3)		3.7

Total MTM Derivative Contract Net Assets	$	3.0	$	0.2	$	3.2

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	$	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.

178

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

Amount of Gain (Loss) Recognized on

Risk Management Contracts

Three Months Ended June 30, 2020


Location of Gain (Loss)	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Vertically Integrated Utilities Revenues	$	(0.1)	$	—	$	—	$	—	$	—	$	—	$	—

Generation & Marketing Revenues	9.9		—		—		—		—		—		—
Electric Generation, Transmission and Distribution Revenues	—		—		(0.1)		—		—		—		0.1


Purchased Electricity for Resale	0.8		—		0.7		—		—		—		—
Other Operation	(0.8)		(0.2)		(0.1)		(0.1)		(0.1)		(0.1)		(0.1)
Maintenance	(1.2)		(0.3)		(0.1)		(0.1)		(0.2)		(0.2)		(0.2)
Regulatory Assets (a)	17.5		0.7		8.4		0.3		4.1		0.3		1.3
Regulatory Liabilities (a)	52.7		—		19.7		3.0		3.2		12.7		9.5
Total Gain on Risk Management Contracts	$	78.8	$	0.2	$	28.5	$	3.1	$	7.0	$	12.7	$	10.6

Three Months Ended June 30, 2019


Location of Gain (Loss)	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Vertically Integrated Utilities Revenues	$	0.2	$	—	$	—	$	—	$	—	$	—	$	—

Generation & Marketing Revenues	3.5		—		—		—		—		—		—
Electric Generation, Transmission and Distribution Revenues	—		—		0.1		—		—		—		—


Purchased Electricity for Resale	(0.2)		—		1.1		0.1		—		—		—
Other Operation	(0.1)		—		0.1		—		—		—		(0.1)
Maintenance	0.1		—		(0.1)		—		—		—		—
Regulatory Assets (a)	(8.2)		(0.1)		2.3		(0.1)		(8.3)		0.5		1.3
Regulatory Liabilities (a)	60.2		—		16.4		7.4		—		16.1		13.7
Total Gain (Loss) on Risk Management Contracts	$	55.5	$	(0.1)	$	19.9	$	7.4	$	(8.3)	$	16.6	$	14.9

Six Months Ended June 30, 2020


Location of Gain (Loss)	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Vertically Integrated Utilities Revenues	$	0.3	$	—	$	—	$	—	$	—	$	—	$	—

Generation & Marketing Revenues	(0.4)		—		—		—		—		—		—
Electric Generation, Transmission and Distribution Revenues	—		—		0.1		0.1		—		—		0.1


Purchased Electricity for Resale	0.9		—		0.8		—		—		—		—
Other Operation	(1.0)		(0.3)		(0.1)		(0.1)		(0.2)		(0.1)		(0.1)
Maintenance	(1.4)		(0.4)		(0.2)		(0.1)		(0.2)		(0.2)		(0.2)
Regulatory Assets (a)	(16.4)		(0.5)		(0.5)		(0.4)		(14.3)		(0.2)		(0.7)
Regulatory Liabilities (a)	63.9		—		12.4		6.2		6.7		20.8		12.8
Total Gain (Loss) on Risk Management Contracts	$	45.9	$	(1.2)	$	12.5	$	5.7	$	(8.0)	$	20.3	$	11.9

179

Six Months Ended June 30, 2019


Location of Gain (Loss)	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Vertically Integrated Utilities Revenues	$	0.5	$	—	$	—	$	—	$	—	$	—	$	—

Generation & Marketing Revenues	6.2		—		—		—		—		—		—
Electric Generation, Transmission and Distribution Revenues	—		—		—		0.3		—		—		0.1


Purchased Electricity for Resale	1.2		—		1.1		0.1		—		—		—
Other Operation	(0.5)		(0.1)		—		—		(0.1)		—		(0.1)
Maintenance	(0.4)		(0.1)		(0.1)		—		(0.1)		—		(0.1)
Regulatory Assets (a)	(14.6)		0.5		0.2		0.2		(17.2)		1.0		1.2
Regulatory Liabilities (a)	38.2		—		(15.3)		14.0		—		22.3		18.4
Total Gain (Loss) on Risk Management Contracts	$	30.6	$	0.3	$	(14.1)	$	14.6	$	(17.4)	$	23.3	$	19.5

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

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

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

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

Accounting for Fair Value Hedging Strategies (Applies to AEP)

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

180

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
	June 30, 2020		December 31, 2019		June 30, 2020		December 31, 2019
	(in millions)
Long-term Debt (a) (b)	$	(553.7)	$	(510.8)	$	(57.1)	$	(14.5)

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

(b)Amounts include $(57) million and $0 as of June 30, 2020 and December 31, 2019, respectively, for the fair value hedge adjustment of hedged debt obligations for which hedge accounting has been discontinued.

The pretax effects of fair value hedge accounting on income were as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
	(in millions)
Gain (Loss) on Interest Rate Contracts:
Gain on Fair Value Hedging Instruments (a)	$	0.1	$	18.2	$	42.6	$	29.3
Loss on Fair Value Portion of Long-term Debt (a)	(0.1)		(18.2)		(42.6)		(29.3)

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

In June 2020, AEP terminated a $500 million notional amount interest rate swap resulting in the discontinuance of the hedging relationship. A gain of $57 million on the fair value of the hedging instrument was settled in cash and recorded within operating activities on the statement of cash flows. Subsequent to the discontinuation of hedge accounting, the remaining adjustment to the carrying amount of the hedged item of $57 million will be amortized on a straight line basis through November 2027 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 and six months ended June 30, 2020 and 2019, AEP applied cash flow hedging to outstanding power derivatives. During the three and six months ended June 30, 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 and six months ended June 30, 2020, AEP and APCo applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not. During the three and six months ended June 30, 2019, the Registrants did not apply cash flow hedging to outstanding interest rate derivatives.

181

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


	June 30, 2020						December 31, 2019
	Commodity		Interest Rate		Commodity		Interest Rate
	(in millions)
AOCI Gain (Loss) Net of Tax	$	(81.4)	$	(55.3)	$	(103.5)	$	(11.5)
Portion Expected to be Reclassed to Net Income During the Next Twelve Months	(46.4)		(4.8)		(51.7)		(2.1)

As of June 30, 2020 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 129 months and 126 months for commodity and interest rate hedges, respectively.

Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets


	June 30, 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	$	(2.9)	$	(1.1)	$	(3.4)	$	(1.1)
APCo	(4.1)		0.9		0.9		0.9
I&M	(9.1)		(1.6)		(9.9)		(1.6)

PSO	0.6		0.6		1.1		1.0
SWEPCo	(1.1)		(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.

182

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 June 30, 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:


	June 30, 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	$	239.5	$	2.8	$	208.0
APCo	6.4		—		5.9
I&M	0.3		—		—


SWEPCo	4.0		—		4.0


	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

183

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.

184

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:


	June 30, 2020						December 31, 2019
Company	Book Value		Fair Value		Book Value		Fair Value
	(in millions)
AEP (a)	$	28,775.4	$	34,049.4	$	26,725.5	$	30,172.0
AEP Texas	4,362.6		5,036.0		4,558.4		4,981.5
AEPTCo	3,947.4		4,828.4		3,427.3		3,868.0
APCo	4,845.3		6,129.7		4,363.8		5,253.1
I&M	3,004.8		3,638.6		3,050.2		3,453.8
OPCo	2,429.5		3,103.2		2,082.0		2,554.3
PSO	1,373.7		1,688.5		1,386.2		1,603.3
SWEPCo	2,638.4		3,085.4		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 $779 million and $871 million as of June 30, 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:


	June 30, 2020
			Gross		Gross
			Unrealized		Unrealized		Fair
Other Temporary Investments	Cost		Gains		Losses		Value
	(in millions)
Restricted Cash and Other Cash Deposits (a)	$	186.5	$	—	$	—	$	186.5
Fixed Income Securities – Mutual Funds (b)	113.1		2.5		—		115.6
Equity Securities – Mutual Funds	27.4		18.7		—		46.1
Total Other Temporary Investments	$	327.0	$	21.2	$	—	$	348.2


	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.

185

The following table provides the activity for fixed income and equity securities within Other Temporary Investments:


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
	(in millions)
Proceeds from Investment Sales	$	7.6	$	—	$	30.8	$	—
Purchases of Investments	10.3		8.8		17.0		8.9
Gross Realized Gains on Investment Sales	0.2		—		2.2		—
Gross Realized Losses on Investment Sales	0.1		—		0.2		—

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.

186

The following is a summary of nuclear trust fund investments:


	June 30, 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	$	70.5	$	—	$	—	$	15.3	$	—	$	—
Fixed Income Securities:
United States Government	988.1		118.0		(5.6)		1,112.5		55.5		(6.1)
Corporate Debt	74.9		8.8		(1.5)		72.4		5.3		(1.6)
State and Local Government	161.5		1.9		(0.2)		7.6		0.7		(0.2)
Subtotal Fixed Income Securities	1,224.5		128.7		(7.3)		1,192.5		61.5		(7.9)
Equity Securities - Domestic (a)	1,662.0		1,040.3		—		1,767.9		1,144.4		—
Spent Nuclear Fuel and Decommissioning Trusts	$	2,957.0	$	1,169.0	$	(7.3)	$	2,975.7	$	1,205.9	$	(7.9)

(a)Amount reported as Gross Unrealized Gains includes unrealized gains of $1.1 billion and $1.1 billion and unrealized losses of $14 million and $5 million as of June 30, 2020 and December 31, 2019, respectively.

The following table provides the securities activity within the decommissioning and SNF trusts:


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
	(in millions)
Proceeds from Investment Sales	$	328.1	$	87.6	$	940.5	$	199.5
Purchases of Investments	345.4		96.3		971.4		226.6
Gross Realized Gains on Investment Sales	11.1		3.4		22.0		15.7
Gross Realized Losses on Investment Sales	7.7		6.1		24.7		19.9

The base cost of fixed income securities was $1.1 billion and $1.1 billion as of June 30, 2020 and December 31, 2019, respectively. The base cost of equity securities was $622 million and $623 million as of June 30, 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 June 30, 2020 was as follows:


	Fair Value of Fixed
	Income Securities
	(in millions)
Within 1 year	$	186.8
After 1 year through 5 years	405.1
After 5 years through 10 years	293.9
After 10 years	338.7
Total	$	1,224.5

187

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

June 30, 2020


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



Other Temporary Investments
Restricted Cash and Other Cash Deposits (a)	$	168.0	$	—	$	—	$	18.5	$	186.5
Fixed Income Securities – Mutual Funds	115.6		—		—		—		115.6
Equity Securities – Mutual Funds (b)	46.1		—		—		—		46.1
Total Other Temporary Investments	329.7		—		—		18.5		348.2

Risk Management Assets
Risk Management Commodity Contracts (c) (d)	2.7		331.2		313.5		(262.9)		384.5
Cash Flow Hedges:
Commodity Hedges (c)	—		28.6		3.2		(19.2)		12.6
Interest Rate Hedges	—		0.1		—		—		0.1

Total Risk Management Assets	2.7		359.9		316.7		(282.1)		397.2

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)	60.6		—		—		9.9		70.5
Fixed Income Securities:
United States Government	—		988.1		—		—		988.1
Corporate Debt	—		74.9		—		—		74.9
State and Local Government	—		161.5		—		—		161.5
Subtotal Fixed Income Securities	—		1,224.5		—		—		1,224.5
Equity Securities – Domestic (b)	1,662.0		—		—		—		1,662.0
Total Spent Nuclear Fuel and Decommissioning Trusts	1,722.6		1,224.5		—		9.9		2,957.0

Total Assets	$	2,055.0	$	1,584.4	$	316.7	$	(253.7)	$	3,702.4

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (d)	$	3.7	$	328.8	$	194.3	$	(298.5)	$	228.3
Cash Flow Hedges:
Commodity Hedges (c)	—		121.9		10.8		(19.2)		113.5
Interest Rate Hedges	—		5.9		—		—		5.9

Total Risk Management Liabilities	$	3.7	$	456.6	$	205.1	$	(317.7)	$	347.7

188

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

189

AEP Texas

Assets and Liabilities Measured at Fair Value on a Recurring Basis

June 30, 2020


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

Restricted Cash for Securitized Funding	$	136.6	$	—	$	—	$	—	$	136.6






Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	0.5	$	—	$	(0.4)	$	0.1

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

June 30, 2020


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

Restricted Cash for Securitized Funding	$	19.3	$	—	$	—	$	—	$	19.3

Risk Management Assets
Risk Management Commodity Contracts (c) (g)	—		36.1		37.3		(35.4)		38.0
Cash Flow Hedges:
Interest Rate Hedges	—		0.1		—		—		0.1
Total Risk Management Assets	—		36.2		37.3		(35.4)		38.1

Total Assets	$	19.3	$	36.2	$	37.3	$	(35.4)	$	57.4

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	37.0	$	0.8	$	(35.9)	$	1.9
Cash Flow Hedges:
Interest Rate Hedges	—		5.9		—		—		5.9
Total Risk Management Liabilities	$	—	$	42.9	$	0.8	$	(35.9)	$	7.8

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

190

I&M

Assets and Liabilities Measured at Fair Value on a Recurring Basis

June 30, 2020


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

Risk Management Assets
Risk Management Commodity Contracts (c) (g)	$	—	$	25.0	$	5.0	$	(23.3)	$	6.7

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)	60.6		—		—		9.9		70.5
Fixed Income Securities:
United States Government	—		988.1		—		—		988.1
Corporate Debt	—		74.9		—		—		74.9
State and Local Government	—		161.5		—		—		161.5
Subtotal Fixed Income Securities	—		1,224.5		—		—		1,224.5
Equity Securities - Domestic (b)	1,662.0		—		—		—		1,662.0
Total Spent Nuclear Fuel and Decommissioning Trusts	1,722.6		1,224.5		—		9.9		2,957.0

Total Assets	$	1,722.6	$	1,249.5	$	5.0	$	(13.4)	$	2,963.7

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	23.4	$	0.5	$	(23.4)	$	0.5

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

191

OPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

June 30, 2020


	Level 1		Level 2		Level 3		Other		Total









Liabilities:	(in millions)

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	0.4	$	117.4	$	(0.3)	$	117.5

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

June 30, 2020


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

Risk Management Assets
Risk Management Commodity Contracts (c) (g)	$	—	$	—	$	23.9	$	(0.1)	$	23.8

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	0.3	$	0.1	$	(0.3)	$	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)	$	—

192

SWEPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

June 30, 2020


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



Risk Management Assets
Risk Management Commodity Contracts (c) (g)	$	—	$	—	$	7.0	$	(0.1)	$	6.9



Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	0.3	$	3.7	$	(0.3)	$	3.7

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 June 30, 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 $(10) million in 2020, $(1) million in periods 2021-2023, $4 million in periods 2024-2025 and $10 million in periods 2026-2032; Level 3 matures $60 million in 2020, $61 million in periods 2021-2023, $20 million in periods 2024-2025 and $(22) 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.

193

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 June 30, 2020	AEP		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Balance as of March 31, 2020	$	42.5	$	6.6	$	2.1	$	(120.9)	$	6.3	$	(2.5)
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)	39.1		23.5		2.8		—		3.9		0.8
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)	(17.2)		—		—		—		—		—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)	22.0		—		—		—		—		—
Settlements	(54.7)		(28.9)		(4.1)		2.6		(10.2)		(2.4)

Transfers out of Level 3 (e)	(0.2)		—		—		—		—		—
Changes in Fair Value Allocated to Regulated Jurisdictions (f)	80.1		35.3		3.7		0.9		23.8		7.4
Balance as of June 30, 2020	$	111.6	$	36.5	$	4.5	$	(117.4)	$	23.8	$	3.3

Three Months Ended June 30, 2019	AEP		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Balance as of March 31, 2019	$	38.1	$	7.4	$	4.4	$	(106.1)	$	4.4	$	—
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)	36.5		17.3		3.3		(0.1)		7.2		2.2
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)	21.6		—		—		—		—		—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)	(53.5)		—		—		—		—		—
Settlements	(50.6)		(22.1)		(6.3)		1.9		(10.0)		(3.3)
Transfers into Level 3 (d) (e)	(1.5)		—		—		—		—		—
Transfers out of Level 3 (e)	(1.6)		—		—		—		—		—
Changes in Fair Value Allocated to Regulated Jurisdictions (f)	123.7		65.9		10.9		(7.2)		26.2		9.6
Balance as of June 30, 2019	$	112.7	$	68.5	$	12.3	$	(111.5)	$	27.8	$	8.5

Six Months Ended June 30, 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)	38.2		12.9		2.3		(0.9)		11.9		2.8
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)	(6.4)		—		—		—		—		—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)	18.3		—		—		—		—		—
Settlements	(113.7)		(50.8)		(8.1)		5.1		(27.6)		(7.6)
Transfers into Level 3 (d) (e)	(0.6)		—		—		—		—		—
Transfers out of Level 3 (e)	4.3		0.7		0.4		—		—		—
Changes in Fair Value Allocated to Regulated Jurisdictions (f)	61.6		36.0		4.1		(18.0)		23.7		6.7
Balance as of June 30, 2020	$	111.6	$	36.5	$	4.5	$	(117.4)	$	23.8	$	3.3

194


Six Months Ended June 30, 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)	32.7		(13.6)		4.3		(0.7)		22.8		16.2
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)	29.2		—		—		—		—		—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)	(69.2)		—		—		—		—		—
Settlements	(126.6)		(41.1)		(11.8)		3.6		(32.3)		(20.8)
Transfers into Level 3 (d) (e)	(1.4)		—		—		—		—		—
Transfers out of Level 3 (e)	(2.7)		(0.7)		(0.4)		—		—		—
Changes in Fair Value Allocated to Regulated Jurisdictions (f)	119.5		66.1		11.3		(15.0)		27.8		10.8
Balance as of June 30, 2019	$	112.7	$	68.5	$	12.3	$	(111.5)	$	27.8	$	8.5

(a)Included in revenues on the statements of income.

(b)Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.

(c)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.

195

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

AEP

Significant Unobservable Inputs

June 30, 2020


								Significant			Input/Range
	Fair Value						Valuation			Unobservable					Weighted
	Assets		Liabilities		Technique	Input		Low			High		Average (c)
	(in millions)
Energy Contracts	$	232.1	$	196.5	Discounted Cash Flow	Forward Market Price (a)		$	4.76		$	112.91	$	31.49
Natural Gas Contracts	—		3.6		Discounted Cash Flow	Forward Market Price (b)		1.44			2.66		2.23
FTRs	84.6		5.0		Discounted Cash Flow	Forward Market Price (a)		(5.98)			7.47		0.12
Total	$	316.7	$	205.1

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

196

APCo

Significant Unobservable Inputs

June 30, 2020


							Significant		Input/Range
	Fair Value					Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input (a)	Low		High		Average (c)
	(in millions)
Energy Contracts	$	1.9	$	0.7	Discounted Cash Flow	Forward Market Price	$	8.53	$	40.35	$	25.34
FTRs	35.4		0.1		Discounted Cash Flow	Forward Market Price	(0.79)		6.55		0.95
Total	$	37.3	$	0.8

December 31, 2019


							Significant		Input/Range
	Fair Value					Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input (a)	Low		High		Average (c)
	(in millions)
Energy Contracts	$	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

June 30, 2020


						Significant	Input/Range
	Fair Value					Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input (a)	Low		High		Average (c)
	(in millions)
Energy Contracts	$	1.2	$	0.4	Discounted Cash Flow	Forward Market Price	$	8.53	$	40.35	$	25.34
FTRs	3.8		0.1		Discounted Cash Flow	Forward Market Price	(2.69)		4.69		0.31
Total	$	5.0	$	0.5

December 31, 2019


						Significant	Input/Range
	Fair Value					Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input (a)	Low		High		Average (c)
	(in millions)
Energy Contracts	$	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

197

OPCo

Significant Unobservable Inputs

June 30, 2020

Significant

Input/Range

Fair Value

Valuation

Unobservable

Weighted

Assets

Liabilities

Technique

Input (a)

Low

High

Average (c)

(in millions)

Energy Contracts

—

117.4

Discounted Cash Flow

Forward Market Price

12.38

44.46

27.32

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

June 30, 2020

Significant

Input/Range

Fair Value

Valuation

Unobservable

Weighted

Assets

Liabilities

Technique

Input (a)

Low

High

Average (c)

(in millions)

FTRs

23.9

0.1

Discounted Cash Flow

Forward Market Price

(5.98)

0.57

(1.63)

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)

198

SWEPCo

Significant Unobservable Inputs

June 30, 2020


						Significant	Input/Range
	Fair Value					Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input	Low		High		Average (c)
	(in millions)
Natural Gas Contracts	$	—	$	3.6	Discounted Cash Flow	Forward Market Price (b)	$	1.44	$	2.66	$	2.23
FTRs	7.0		0.1		Discounted Cash Flow	Forward Market Price (a)	(5.98)		0.57		(1.63)
Total	$	7.0	$	3.7

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 June 30, 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)

199

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 June 30, 2020, AEP, APCo and OPCo have a $20 million, $7 million and $9 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 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 June 30, 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	2.7	%	1.8	%	2.9	%	3.2	%	3.6	%	0.7	%	4.6	%	2.1	%
Tax Reform Excess ADIT Reversal	(16.4)	%	(57.9)	%	0.4	%	(32.5)	%	(12.6)	%	(9.3)	%	(20.9)	%	(6.3)	%
Production and Investment Tax Credits	(4.6)	%	(0.5)	%	—	%	—	%	(1.2)	%	—	%	(1.2)	%	(0.4)	%
Flow Through	0.5	%	0.2	%	0.5	%	1.9	%	0.1	%	0.9	%	0.3	%	(1.2)	%
AFUDC Equity	(1.5)	%	(3.3)	%	(2.6)	%	(1.3)	%	(0.7)	%	(0.8)	%	(0.6)	%	(0.3)	%
Parent Company Loss Benefit	—	%	0.2	%	(0.8)	%	(2.9)	%	(3.3)	%	(0.4)	%	(1.8)	%	(1.7)	%

Other	0.7	%	—	%	(0.6)	%	(0.2)	%	—	%	0.1	%	0.1	%	(1.3)	%
Effective Income Tax Rate	2.4	%	(38.5)	%	20.8	%	(10.8)	%	6.9	%	12.2	%	1.5	%	11.9	%

200


	Three Months Ended June 30, 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	2.0	%	1.5	%	2.9	%	3.5	%	2.0	%	0.9	%	4.6	%	0.1	%
Tax Reform Excess ADIT Reversal	(30.7)	%	(243.4)	%	0.4	%	(71.6)	%	(17.4)	%	(7.6)	%	(21.9)	%	(12.7)	%
Production and Investment Tax Credits	(5.5)	%	(1.0)	%	—	%	—	%	(1.9)	%	—	%	(1.7)	%	(0.6)	%
Flow Through	(0.2)	%	0.3	%	0.2	%	(1.0)	%	(2.4)	%	0.7	%	0.6	%	(0.7)	%
AFUDC Equity	(1.4)	%	(1.6)	%	(2.5)	%	(1.1)	%	(1.9)	%	(0.7)	%	(0.4)	%	(0.8)	%
Parent Company Loss Benefit	—	%	(2.3)	%	(0.9)	%	(2.8)	%	(1.8)	%	(1.1)	%	(1.8)	%	(0.4)	%
Discrete Tax Adjustments	0.2	%	(8.4)	%	(1.5)	%	—	%	2.7	%	3.2	%	—	%	(5.9)	%
Other	1.1	%	(0.5)	%	(0.1)	%	(0.1)	%	(0.5)	%	—	%	0.3	%	—	%
Effective Income Tax Rate	(13.5)	%	(234.4)	%	19.5	%	(52.1)	%	(0.2)	%	16.4	%	0.7	%	—	%

	Six Months Ended June 30, 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	2.6	%	1.7	%	2.9	%	3.1	%	3.4	%	0.7	%	4.6	%	2.2	%
Tax Reform Excess ADIT Reversal	(12.8)	%	(30.4)	%	0.4	%	(20.2)	%	(16.7)	%	(9.7)	%	(20.3)	%	(17.0)	%
Production and Investment Tax Credits	(4.4)	%	(0.4)	%	—	%	—	%	(1.6)	%	—	%	(1.1)	%	(0.4)	%
Flow Through	0.5	%	0.1	%	0.5	%	1.6	%	0.2	%	0.9	%	0.2	%	(1.1)	%
AFUDC Equity	(1.5)	%	(2.9)	%	(2.6)	%	(1.1)	%	(0.9)	%	(0.9)	%	(0.6)	%	(0.3)	%
Parent Company Loss Benefit	—	%	—	%	(0.9)	%	(3.1)	%	(3.7)	%	(0.3)	%	(1.7)	%	(1.8)	%
Discrete Tax Adjustments	—	%	—	%	—	%	—	%	1.6	%	—	%	—	%	—	%
Other	0.1	%	0.1	%	(0.2)	%	—	%	(0.1)	%	0.1	%	0.1	%	(0.3)	%
Effective Income Tax Rate	5.5	%	(10.8)	%	21.1	%	1.3	%	3.2	%	11.8	%	2.2	%	2.3	%



	Six Months Ended June 30, 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	%	3.5	%	2.0	%	0.9	%	4.6	%	0.2	%
Tax Reform Excess ADIT Reversal	(20.4)	%	(98.8)	%	0.4	%	(49.5)	%	(17.4)	%	(7.6)	%	(21.9)	%	(16.2)	%
Production and Investment Tax Credits	(3.5)	%	(1.0)	%	—	%	—	%	(1.9)	%	—	%	(1.7)	%	(0.8)	%
Flow Through	(0.1)	%	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)	%	(1.0)	%
Parent Company Loss Benefit	—	%	(2.3)	%	(0.9)	%	(2.5)	%	(1.8)	%	(1.1)	%	(1.8)	%	(0.5)	%
Discrete Tax Adjustments	1.1	%	(3.2)	%	(0.8)	%	0.3	%	1.0	%	0.9	%	—	%	(1.1)	%
Other	0.2	%	0.1	%	(0.2)	%	(0.4)	%	(0.4)	%	0.2	%	0.2	%	1.3	%
Effective Income Tax Rate	(1.0)	%	(84.0)	%	20.1	%	(29.5)	%	(1.8)	%	14.3	%	0.6	%	2.0	%

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. In the first quarter of 2020, the IRS notified AEP that it was beginning an examination of these amended returns, including the net operating loss carryback to 2015 that originated in the 2017 return. The IRS may examine only the amended items on the 2014 and 2015 federal returns.

201

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	June 30, 2020		December 31, 2019
	(in millions)
Senior Unsecured Notes	$	23,530.3	$	21,180.7
Pollution Control Bonds	1,936.2		1,998.8
Notes Payable	186.0		234.3
Securitization Bonds	866.7		1,025.1
Spent Nuclear Fuel Obligation (a)	281.0		279.8
Junior Subordinated Notes (b)	789.7		787.8
Other Long-term Debt	1,185.5		1,219.0
Total Long-term Debt Outstanding	28,775.4		26,725.5
Long-term Debt Due Within One Year	2,137.7		1,598.7
Long-term Debt	$	26,637.7	$	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 $326 million and $323 million as of June 30, 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 six 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
AEPTCo	Senior Unsecured Notes	525.0		3.65	2050
APCo	Senior Unsecured Notes	500.0		3.70	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	7.1		Variable	2023
Transource Energy	Senior Unsecured Notes	150.0		2.75	2050
Total Issuances		$	2,457.1

(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.

202


		Principal		Interest
Company	Type of Debt	Amount Paid		Rate	Due Date
Retirements and Principal Payments:		(in millions)		(%)
AEP Texas	Pollution Control Bonds	$	50.6	4.45	2020

AEP Texas	Securitization Bonds	28.7		1.98	2020
AEP Texas	Securitization Bonds	111.0		5.31	2020
AEP Texas	Securitization Bonds	0.2		2.85	2024
AEP Texas	Securitization Bonds	3.3		2.06	2025



APCo	Securitization Bonds	12.2		2.01	2023






I&M	Notes Payable	1.3		Variable	2020
I&M	Notes Payable	3.1		Variable	2021
I&M	Notes Payable	10.2		Variable	2022
I&M	Notes Payable	7.5		Variable	2022
I&M	Notes Payable	12.5		Variable	2023
I&M	Notes Payable	12.1		Variable	2024
I&M	Other Long-term Debt	0.9		6.00	2025


PSO	Pollution Control Bonds	12.7		4.45	2020
PSO	Other Long-term Debt	0.2		3.00	2027


SWEPCo	Other Long-term Debt	15.0		Variable	2020
SWEPCo	Other Long-term Debt	1.5		4.68	2028
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		$	433.2

Long-term Debt Subsequent Events

In July 2020, AEP Texas issued $600 million of Senior Unsecured Notes due in 2030.

In July and August 2020, AEP Texas retired $92 million and $11 million, respectively, of Securitization Bonds, the Transition Funding II bonds are now fully matured.

In July and August 2020, I&M retired $8 million and $1 million, respectively, of Notes Payable related to DCC Fuel.

In July 2020, Transource Energy issued $3 million of variable rate Other Long-term Debt due in 2023.

In August 2020, APCo retired $13 million of Securitization Bonds.

Equity Units (Applies to AEP)

In March 2019, AEP issued 16.1 million Equity Units initially in the form of corporate units, at a stated amount of $50 per unit, for a total stated amount of $805 million. Net proceeds from the issuance were approximately $785 million. The proceeds were used to support AEP’s overall capital expenditure plans including the 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%.

203

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 immaterial as of June 30, 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.

204

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 June 30, 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 six months ended June 30, 2020 are described in the following table:


	Maximum				Average				Net Loans to
	Borrowings		Maximum		Borrowings		Average		(Borrowings) from		Authorized
	from the		Loans to the		from the		Loans to the		the Utility Money		Short-term
	Utility		Utility		Utility		Utility		Pool as of		Borrowing
Company	Money Pool		Money Pool		Money Pool		Money Pool		June 30, 2020		Limit
	(in millions)
AEP Texas	$	320.4	$	199.7	$	154.7	$	90.3	$	(320.4)	$	500.0
AEPTCo	358.4		259.7		130.9		85.6		28.0		820.0		(a)
APCo	434.3		174.8		331.3		45.3		82.3		500.0
I&M	194.1		13.4		102.5		13.3		(180.8)		500.0
OPCo	353.9		32.8		145.6		25.2		(143.1)		500.0
PSO	125.4		57.1		66.8		28.4		(106.9)		300.0
SWEPCo	178.9		—		129.3		—		(130.4)		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 June 30, 2020 and December 31, 2019 are included in Advances to Affiliates on the subsidiaries’ balance sheets. The Nonutility Money Pool participants’ activity for the six months ended June 30, 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		June 30, 2020
	(in millions)
AEP Texas		$	7.5	$	7.2	$	7.2
SWEPCo		2.1		2.1		2.1

205

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 June 30, 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 six months ended June 30, 2020 are described in the following table:

Maximum

Average

Borrowings from

Loans to

Authorized

Borrowings

Loans

Borrowings

Loans

AEP as of

Short-term

from AEP

to AEP

from AEP

to AEP

June 30, 2020

Borrowing Limit

(in millions)

1.4

190.3

1.3

124.7

1.2

90.5

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:


	Six Months Ended June 30,
	2020		2019
Maximum Interest Rate	2.70	%	3.02	%
Minimum Interest Rate	0.33	%	2.68	%

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 Six Months Ended June 30,						for Six Months Ended June 30,
Company	2020		2019		2020		2019
AEP Texas	1.55	%	2.81	%	1.97	%	—	%
AEPTCo	1.94	%	2.78	%	2.06	%	2.83	%
APCo	2.14	%	2.91	%	1.62	%	2.77	%
I&M	1.80	%	2.74	%	1.87	%	2.82	%
OPCo	1.80	%	2.81	%	2.06	%	2.73	%
PSO	1.71	%	2.85	%	1.95	%	2.74	%
SWEPCo	1.87	%	2.77	%	—	%	2.97	%

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

Six Months Ended June 30, 2020

Six Months Ended June 30, 2019

Maximum

Minimum

Average

Maximum

Minimum

Average

Interest Rate

for Funds

Loaned to

the Nonutility

Company

Money Pool

AEP Texas

2.70

0.33

1.87

3.02

2.68

2.81

SWEPCo

2.70

0.33

1.87

3.02

2.68

2.81

206

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
Six Months	for Funds		for Funds		for Funds			for Funds			for Funds			for Funds
Ended	Borrowed		Borrowed		Loaned			Loaned			Borrowed			Loaned
June 30,	from AEP		from AEP				to AEP			to AEP			from AEP			to AEP
2020	2.70	%	0.50	%	2.70	%		0.50	%		1.88	%		1.86	%
2019	3.02	%	2.68	%	3.02	%		2.68	%		2.81	%		2.80	%

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

Outstanding short-term debt was as follows:


		June 30, 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)	$	634.0	1.40	%	$	710.0	2.42	%
AEP	Commercial Paper	1,403.5		0.34	%	2,110.0		2.10	%
AEP	364-Day Term Loan	1,000.0		0.78	%	—		—	%
AEP Texas	COVID-19 Electricity Relief Program Loan (c)	2.0		—	%	—		—	%
SWEPCo	Notes Payable	37.1		2.35	%	18.3		3.29	%
	Total Short-term Debt	$	3,076.6			$	2,838.3

(a)Weighted-average rate.

(b)Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.

(c)Principal amount of loan shall not bear interest if paid in full by the maturity date. Unpaid principal after the maturity date will accrue interest of 2% per annum beginning the first day after the maturity date until all outstanding principal is paid.

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.

207

Accounts receivable information for AEP Credit was as follows:


	Three Months Ended June 30,									Six Months Ended June 30,
	2020			2019			2020			2019
	(dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable	1.06		%	2.60		%	1.40		%	2.66		%
Net Uncollectible Accounts Receivable Written-Off	$	3.4		$	4.6		$	7.6		$	11.0


	June 30, 2020		December 31, 2019
	(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts	$	937.6	$	841.8
Short-term – Securitized Debt of Receivables	634.0		710.0
Delinquent Securitized Accounts Receivable	93.6		39.6
Bad Debt Reserves Related to Securitization	38.7		32.1
Unbilled Receivables Related to Securitization	293.2		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	June 30, 2020		December 31, 2019
	(in millions)
APCo	$	116.3	$	120.9
I&M	172.2		141.8
OPCo	366.7		330.3
PSO	115.6		101.1
SWEPCo	152.8		125.2

The fees paid to AEP Credit for customer accounts receivable sold were:


	Three Months Ended June 30,						Six Months Ended June 30,
Company	2020		2019		2020		2019
	(in millions)
APCo	$	1.3	$	2.4	$	3.0	$	4.6
I&M	2.6		3.2		5.4		6.0
OPCo	5.0		7.9		9.8		15.7
PSO	1.0		2.1		2.3		4.2
SWEPCo	1.9		3.4		4.0		6.0

208

The proceeds on the sale of receivables to AEP Credit were:


	Three Months Ended June 30,						Six Months Ended June 30,
Company	2020		2019		2020		2019
	(in millions)
APCo	$	285.7	$	300.8	$	638.3	$	675.2
I&M	439.9		415.0		911.3		893.6
OPCo	556.7		506.7		1,127.0		1,143.5
PSO	297.3		342.6		592.2		667.1
SWEPCo	381.4		394.5		747.0		766.4

209

13. PROPERTY, PLANT AND EQUIPMENT

The disclosure in this note applies to AEP, AEP Texas, APCo, PSO and SWEPCo.

Asset Retirement Obligations

The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, wind farms, solar farms and certain coal mining facilities. The Registrants recorded the following revisions to ARO estimates during the first six months of 2020:

•In March 2020, SWEPCo recorded a revision to increase estimated ARO liabilities by $21 million primarily due to the revision in the useful life of DHLC. See Note 4 - Rate Matters for additional details.

•In June 2020, AEP Texas and PSO recorded a revision to decrease estimated ARO liabilities by $17 million and $5 million, respectively, due to the expected retirement of the Oklaunion Power Station in October 2020. See Note 4 - Rate Matters for additional details.

•In June 2020, AGR derecognized $106 million of Conesville Plant related ARO liabilities as a result of the Environmental Liability and Property Transfer and Asset Purchase Agreement executed with a non-affiliated third-party. See Note 6 - Acquisitions and Dispositions for additional details.

•In June 2020, APCo recorded a revision to increase estimated Glen Lyn Station ash disposal ARO liabilities by $199 million due to the enactment of House Bill 443. This bill requires APCo to close the ash disposal units at the retired Glen Lyn Station by removal of all coal combustion material. The legislation provides for regulatory recovery of these costs. See Note 5 - Commitments, Guarantees and Contingencies for additional details.

The following is a reconciliation of the aggregate carrying amounts of ARO for AEP, AEP Texas, APCo, PSO and SWEPCo:


Company	ARO as of December 31, 2019		Accretion Expense		Liabilities Incurred		Liabilities Settled		Revisions in Cash Flow Estimates		ARO as of June 30, 2020
	(in millions)
AEP (a)(b)(c)(d)	$	2,418.9	$	50.8	$	0.2	$	(129.9)	$	204.3	$	2,544.3
AEP Texas (a)(d)	29.1		0.6		—		—		(16.8)		12.9
APCo (a)(d)	111.1		2.8		—		(2.7)		199.8		311.0
PSO (a)(d)	52.2		1.5		—		—		(4.8)		48.9
SWEPCo (a)(c)(d)	212.2		5.4		—		(2.1)		24.0		239.5

(a)Includes ARO related to ash disposal facilities.

(b)Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.76 billion and $1.73 billion as of June 30, 2020 and December 31, 2019, respectively.

(c)Includes ARO related to Sabine and DHLC.

(d)Includes ARO related to asbestos removal.

210

14. REVENUE FROM CONTRACTS WITH CUSTOMERS

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

Disaggregated Revenues from Contracts with Customers

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


	Three Months Ended June 30, 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	$	820.7	$	494.5	$	—	$	—	$	—	$	—	$	1,315.2
Commercial Revenues	474.5		256.3		—		—		—		—		730.8
Industrial Revenues	486.0		98.7		—		—		—		(0.2)		584.5
Other Retail Revenues	36.9		10.3		—		—		—		—		47.2
Total Retail Revenues	1,818.1		859.8		—		—		—		(0.2)		2,677.7

Wholesale and Competitive Retail Revenues:
Generation Revenues	148.6		—		—		31.5		—		—		180.1

Transmission Revenues (a)	84.1		108.4		310.2		—		—		(201.8)		300.9
Renewable Generation Revenues (c)	—		—		—		17.7		—		(0.3)		17.4
Retail, Trading and Marketing Revenues (b)	—		—		—		327.6		(0.6)		(26.5)		300.5
Total Wholesale and Competitive Retail Revenues	232.7		108.4		310.2		376.8		(0.6)		(228.6)		798.9

Other Revenues from Contracts with Customers (c)	46.4		33.1		11.4		0.7		22.4		(31.4)		82.6


Total Revenues from Contracts with Customers	2,097.2		1,001.3		321.6		377.5		21.8		(260.2)		3,559.2

Other Revenues:
Alternative Revenues (c)	(5.2)		20.6		(71.9)		—		—		(7.6)		(64.1)
Other Revenues (c)	—		12.6		—		(0.6)		(2.3)		(10.8)		(1.1)

Total Other Revenues	(5.2)		33.2		(71.9)		(0.6)		(2.3)		(18.4)		(65.2)

Total Revenues	$	2,092.0	$	1,034.5	$	249.7	$	376.9	$	19.5	$	(278.6)	$	3,494.0

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $240 million. The remaining affiliated amounts were immaterial.

(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $27 million. The remaining affiliated amounts were immaterial.

(c)Amounts include affiliated and nonaffiliated revenues.

211


	Three Months Ended June 30, 2019
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other		Reconciling Adjustments		AEP Consolidated
	(in millions)
Retail Revenues:
Residential Revenues	$	755.0	$	435.0	$	—	$	—	$	—	$	—	$	1,190.0
Commercial Revenues	517.5		287.6		—		—		—		—		805.1
Industrial Revenues	549.2		109.4		—		—		—		(3.3)		655.3
Other Retail Revenues	43.6		11.1		—		—		—		—		54.7
Total Retail Revenues	1,865.3		843.1		—		—		—		(3.3)		2,705.1

Wholesale and Competitive Retail Revenues:
Generation Revenues (a)	205.9		—		—		299.7		—		7.2		512.8

Transmission Revenues (b)	64.1		113.5		289.8		—		—		(173.6)		293.8

Renewable Generation Revenues (c)	—		—		—		11.1		—		—		11.1
Retail, Trading and Marketing Revenues (c)	—		—		—		95.8		—		—		95.8
Total Wholesale and Competitive Retail Revenues	270.0		113.5		289.8		406.6		—		(166.4)		913.5

Other Revenues from Contracts with Customers (c)	42.0		38.7		5.0		(12.6)		21.5		(35.3)		59.3


Total Revenues from Contracts with Customers	2,177.3		995.3		294.8		394.0		21.5		(205.0)		3,677.9

Other Revenues:
Alternative Revenues (c)	(53.5)		11.4		(15.9)		—		—		(36.9)		(94.9)
Other Revenues (c)	—		39.0		—		18.7		2.3		(69.4)		(9.4)

Total Other Revenues	(53.5)		50.4		(15.9)		18.7		2.3		(106.3)		(104.3)

Total Revenues	$	2,123.8	$	1,045.7	$	278.9	$	412.7	$	23.8	$	(311.3)	$	3,573.6

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $34 million. The remaining affiliated amounts were immaterial.

(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $201 million. The remaining affiliated amounts were immaterial.

(c)Amounts include affiliated and nonaffiliated revenues.

212


	Three Months Ended June 30, 2020
	AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Retail Revenues:
Residential Revenues	$	149.6	$	—	$	272.7	$	186.9	$	344.8	$	139.2	$	147.7
Commercial Revenues	94.4		—		119.9		118.0		162.1		77.3		110.6
Industrial Revenues	31.3		—		134.5		130.7		67.3		54.5		82.3
Other Retail Revenues	7.0		—		15.4		1.6		3.3		16.2		2.3
Total Retail Revenues	282.3		—		542.5		437.2		577.5		287.2		342.9

Wholesale Revenues:
Generation Revenues (a)	—		—		60.9		75.6		—		2.2		30.3

Transmission Revenues (b)	91.7		298.7		30.3		7.3		16.8		3.9		33.4

Total Wholesale Revenues	91.7		298.7		91.2		82.9		16.8		6.1		63.7

Other Revenues from Contracts with Customers (c)	10.3		11.1		13.5		21.9		22.7		13.7		9.7


Total Revenues from Contracts with Customers	384.3		309.8		647.2		542.0		617.0		307.0		416.3

Other Revenues:
Alternative Revenues (d)	1.1		(71.7)		(9.7)		4.6		19.6		1.6		(1.3)
Other Revenues (d)	16.1		—		—		—		3.8		—		—

Total Other Revenues	17.2		(71.7)		(9.7)		4.6		23.4		1.6		(1.3)

Total Revenues	$	401.5	$	238.1	$	637.5	$	546.6	$	640.4	$	308.6	$	415.0

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $24 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 $237 million. The remaining affiliated amounts were immaterial.

(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $18 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.

(d)Amounts include affiliated and nonaffiliated revenues.

213


	Three Months Ended June 30, 2019
	AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Retail Revenues:
Residential Revenues	$	142.0	$	—	$	256.5	$	142.2	$	288.3	$	147.7	$	140.7
Commercial Revenues	106.0		—		132.1		111.8		182.7		101.3		113.1
Industrial Revenues	33.6		—		144.6		134.8		77.1		83.0		83.7
Other Retail Revenues	7.9		—		18.4		1.7		3.3		20.2		2.2
Total Retail Revenues	289.5		—		551.6		390.5		551.4		352.2		339.7

Wholesale Revenues:
Generation Revenues (a)	—		—		62.2		113.4		—		5.8		44.8

Transmission Revenues (b)	98.5		276.8		25.7		6.1		14.4		15.5		23.8

Total Wholesale Revenues	98.5		276.8		87.9		119.5		14.4		21.3		68.6

Other Revenues from Contracts with Customers (c)	7.8		5.0		16.1		28.6		33.3		5.8		5.3


Total Revenues from Contracts with Customers	395.8		281.8		655.6		538.6		599.1		379.3		413.6

Other Revenues:
Alternative Revenues (d)	1.2		(14.9)		0.2		4.5		6.0		(31.2)		(38.1)
Other Revenues (d)	41.0		—		—		—		1.5		—		—

Total Other Revenues	42.2		(14.9)		0.2		4.5		7.5		(31.2)		(38.1)

Total Revenues	$	438.0	$	266.9	$	655.8	$	543.1	$	606.6	$	348.1	$	375.5

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $30 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 $198 million. The remaining affiliated amounts were immaterial.

(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $23 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.

(d)Amounts include affiliated and nonaffiliated revenues.

214


	Six Months Ended June 30, 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	$	1,735.8	$	1,015.8	$	—	$	—	$	—	$	—	$	2,751.6
Commercial Revenues	963.9		533.2		—		—		—		—		1,497.1
Industrial Revenues	1,004.2		196.5		—		—		—		(0.4)		1,200.3
Other Retail Revenues	76.8		22.1		—		—		—		—		98.9
Total Retail Revenues	3,780.7		1,767.6		—		—		—		(0.4)		5,547.9

Wholesale and Competitive Retail Revenues:
Generation Revenues	289.0		—		—		75.6		—		—		$	364.6

Transmission Revenues (a)	164.0		222.5		620.0		—		—		(464.8)		541.7

Renewable Generation Revenues (c)	—		—		—		34.9		—		(0.9)		34.0
Retail, Trading and Marketing Revenues (b)	—		—		—		686.3		(6.6)		(55.9)		623.8
Total Wholesale and Competitive Retail Revenues	453.0		222.5		620.0		796.8		(6.6)		(521.6)		1,564.1

Other Revenues from Contracts with Customers (c)	90.0		69.5		15.1		1.0		50.5		(72.0)		154.1


Total Revenues from Contracts with Customers	4,323.7		2,059.6		635.1		797.8		43.9		(594.0)		7,266.1

Other Revenues:
Alternative Revenues (c)	(5.0)		39.9		(75.2)		—		—		(3.1)		(43.4)
Other Revenues (c)	—		41.9		—		17.7		(4.5)		(36.3)		18.8

Total Other Revenues	(5.0)		81.8		(75.2)		17.7		(4.5)		(39.4)		(24.6)

Total Revenues	$	4,318.7	$	2,141.4	$	559.9	$	815.5	$	39.4	$	(633.4)	$	7,241.5

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $479 million. The remaining affiliated amounts were immaterial.

(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $62 million. The remaining affiliated amounts were immaterial.

(c)Amounts include affiliated and nonaffiliated revenues.

215


	Six Months Ended June 30, 2019
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other		Reconciling Adjustments		AEP Consolidated
	(in millions)
Retail Revenues:
Residential Revenues	$	1,737.4	$	1,021.1	$	—	$	—	$	—	$	—	$	2,758.5
Commercial Revenues	1,028.7		598.5		—		—		—		—		1,627.2
Industrial Revenues	1,081.3		233.3		—		—		—		(1.5)		1,313.1
Other Retail Revenues	86.9		22.2		—		—		—		—		109.1
Total Retail Revenues	3,934.3		1,875.1		—		—		—		(1.5)		5,807.9

Wholesale and Competitive Retail Revenues:
Generation Revenues (a)	430.6		—		—		408.5		—		(71.3)		767.8

Transmission Revenues (b)	137.6		213.1		544.9		—		—		(386.4)		509.2
Renewable Generation Revenues (c)	—		—		—		18.8		—		—		18.8
Retail, Trading and Marketing Revenues (c)	—		—		—		450.7		—		—		450.7
Total Wholesale and Competitive Retail Revenues	568.2		213.1		544.9		878.0		—		(457.7)		1,746.5

Other Revenues from Contracts with Customers (c)	81.5		84.7		8.1		(10.3)		44.8		(71.4)		137.4


Total Revenues from Contracts with Customers	4,584.0		2,172.9		553.0		867.7		44.8		(530.6)		7,691.8

Other Revenues:
Alternative Revenues (c)	(56.9)		16.4		(17.7)		—		—		(43.5)		(101.7)
Other Revenues (c)	—		78.4		—		26.8		4.5		(69.4)		40.3

Total Other Revenues	(56.9)		94.8		(17.7)		26.8		4.5		(112.9)		(61.4)

Total Revenues	$	4,527.1	$	2,267.7	$	535.3	$	894.5	$	49.3	$	(643.5)	$	7,630.4

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $71 million. The remaining affiliated amounts were immaterial.

(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $399 million. The remaining affiliated amounts were immaterial.

(c)Amounts include affiliated and nonaffiliated revenues.

216


	Six Months Ended June 30, 2020
	AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Retail Revenues:
Residential Revenues	$	282.5	$	—	$	630.2	$	388.2	$	733.2	$	267.7	$	279.3
Commercial Revenues	207.2		—		252.2		240.2		326.1		153.4		216.2
Industrial Revenues	66.5		—		275.6		268.5		130.0		115.8		162.1
Other Retail Revenues	15.4		—		33.3		3.4		6.7		32.8		4.3
Total Retail Revenues	571.6		—		1,191.3		900.3		1,196.0		569.7		661.9

Wholesale Revenues:
Generation Revenues (a)	—		—		115.0		154.0		—		4.1		64.4

Transmission Revenues (b)	188.6		596.9		60.7		14.7		33.9		11.7		58.8

Total Wholesale Revenues	188.6		596.9		175.7		168.7		33.9		15.8		123.2

Other Revenues from Contracts with Customers (c)	18.2		14.5		30.7		42.9		51.3		18.4		15.5


Total Revenues from Contracts with Customers	778.4		611.4		1,397.7		1,111.9		1,281.2		603.9		800.6

Other Revenues:
Alternative Revenues (d)	0.4		(77.7)		(10.8)		5.0		39.6		2.0		0.3
Other Revenues (d)	46.3		—		—		—		9.9		—		—

Total Other Revenues	46.7		(77.7)		(10.8)		5.0		49.5		2.0		0.3

Total Revenues	$	825.1	$	533.7	$	1,386.9	$	1,116.9	$	1,330.7	$	605.9	$	800.9

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $57 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 $472 million. The remaining affiliated amounts were immaterial.

(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $34 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.

(d)Amounts include affiliated and nonaffiliated revenues.

217


	Six Months Ended June 30, 2019
	AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Retail Revenues:
Residential Revenues	$	262.9	$	—	$	629.0	$	360.6	$	759.9	$	287.7	$	280.8
Commercial Revenues	203.9		—		274.3		233.1		393.2		182.1		226.8
Industrial Revenues	66.6		—		292.1		273.2		166.8		154.0		164.9
Other Retail Revenues	15.2		—		38.0		3.5		6.7		38.2		4.4
Total Retail Revenues	548.6		—		1,233.4		870.4		1,326.6		662.0		676.9

Wholesale Revenues:
Generation Revenues (a)	—		—		129.7		225.3		—		14.4		102.0

Transmission Revenues (b)	184.3		518.9		51.4		12.4		28.3		25.3		48.0

Total Wholesale Revenues	184.3		518.9		181.1		237.7		28.3		39.7		150.0

Other Revenues from Contracts with Customers (c)	14.7		8.1		29.5		49.6		72.3		11.6		13.1


Total Revenues from Contracts with Customers	747.6		527.0		1,444.0		1,157.7		1,427.2		713.3		840.0

Other Revenues:
Alternative Revenues (d)	0.3		(16.6)		4.6		(0.3)		9.6		(32.4)		(43.4)
Other Revenues (d)	80.8		—		—		—		6.6		—		—

Total Other Revenues	81.1		(16.6)		4.6		(0.3)		16.2		(32.4)		(43.4)

Total Revenues	$	828.7	$	510.4	$	1,448.6	$	1,157.4	$	1,443.4	$	680.9	$	796.6

(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $64 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 $393 million. The remaining affiliated amounts were immaterial.

(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $38 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.

(d)Amounts include affiliated and nonaffiliated revenues.

218

Fixed Performance Obligations

The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of June 30, 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	$	527.5	$	185.4	$	160.3	$	223.4	$	1,096.6
AEP Texas	216.3		—		—		—		216.3
AEPTCo	549.6		—		—		—		549.6
APCo	80.2		33.1		25.5		11.6		150.4
I&M	17.3		10.9		8.8		4.4		41.4
OPCo	33.1		5.3		—		—		38.4
PSO	7.5		—		—		—		7.5
SWEPCo	21.0		—		—		—		21.0

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 June 30, 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 June 30, 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 June 30, 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	June 30, 2020		December 31, 2019
	(in millions)
AEPTCo	$	80.1	$	65.9
APCo	48.5		47.3
I&M	29.9		37.1
OPCo	37.8		33.9
PSO	6.8		9.7
SWEPCo	22.6		17.6

219

CONTROLS AND PROCEDURES

During the second 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 June 30, 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 second quarter of 2020 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

220

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 June 30, 2020, the risk factors appearing in AEP’s 2019 Annual Report are supplemented and updated as follows:

AEP’s Financial Condition and Results of Operations could continue to be Adversely Affected by the Ongoing Coronavirus Pandemic

AEP is responding to the global 2019 novel coronavirus (COVID-19) pandemic by taking steps to mitigate the potential risks posed by its spread. 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 has reduced demand for energy, particularly from commercial and industrial customers. 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.

During the first quarter of 2020, AEP informed both retail customers and state regulators that disconnections for non-payment have been temporarily suspended. Disconnections are anticipated to be reinstated starting in the third quarter of 2020 in Ohio, Virginia, West Virginia, Indiana, Michigan, Oklahoma, Louisiana and Texas. These uncertain economic conditions may result in the inability of customers to pay for electric service, which could affect revenue recognition and the collectability of accounts receivables. 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.

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. Market volatility and reduction in collections coupled with longer collection periods due to the expansion of customer payment arrangements could reduce cash from operations and cause an adverse impact to liquidity.

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.

221

Ohio House Bill 6 (HB 6), which provides for beneficial cost recovery for OPCo and for plants owned by OVEC, has come under public scrutiny (Applies to AEP and OPCo)

In 2019, Ohio adopted and implemented HB 6. Among other provisions, HB 6 phased out current energy efficiency including lost shared savings revenues of $26 million annually and renewable mandates no later than 2020 and after 2026, respectively. HB 6 also provided for the recovery of existing renewable energy contracts on a bypassable basis through 2032, and included a provision for recovery of OVEC coal-fired unit costs through 2030. AEP and OPCo engaged in lobbying efforts and provided testimony during the legislative process in support of HB 6. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of the Speaker of the Ohio House of Representatives, Larry Householder, four other individuals, and Generation Now, an entity registered as a 501(c)(4) social welfare organization, in connection with an alleged racketeering conspiracy involving the adoption of HB 6. In light of the allegations in the indictment, proposed legislation has been introduced that would repeal HB 6. The outcome of the U.S. Attorney’s Office investigation and its impact on HB 6 is not known. If the provisions of HB 6 were to be eliminated, it is unclear whether and in what form the Ohio General Assembly would pass new legislation addressing similar issues. 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 through 2030 or fully recover energy efficiency costs through 2020 it could reduce future net income and cash flows and impact financial condition. In addition, the impact of continued public scrutiny of HB 6 is not known, and may have an adverse impact on AEP’s and OPCo’s relationship with regulatory and legislative authorities, customers and other stakeholders.

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

AEP and several nonaffiliated utility companies own OVEC. The Inter-Company Power Agreement (ICPA) defines the rights and obligations and sets the power participation ratio of the parties to it. Under the ICPA, parties are entitled to receive and are obligated to pay for all OVEC capacity (approximately 2,400 MWs) in proportion to their respective power participation ratios. The aggregate power participation ratio of APCo, I&M and OPCo is 43.47%. If a party fails to make payments owed by it under the ICPA, OVEC may not have sufficient funds to honor its payment obligations, including its ongoing operating expenses as well as its indebtedness. As of June 30, 2020, OVEC has outstanding indebtedness of approximately $1.3 billion, of which APCo, I&M, and OPCo are collectively responsible for $568 million through the ICPA. Although they are not an obligor or guarantor, APCo, I&M, and OPCo are responsible for their respective ratio of OVEC’s outstanding debt through the ICPA.

Energy Harbor (formerly FirstEnergy Solutions), a nonaffiliated party, whose aggregate power participation ratio is 4.85% under the ICPA, filed a petition seeking protection under the bankruptcy law. In May 2020, Energy Harbor entered into a bankruptcy settlement and resumed performance under the ICPA as of June 1, 2020. In July 2020, federal prosecutors arrested the Speaker of the Ohio House of Representatives and four other individuals alleging that they engaged in a bribery and money laundering scheme connected to the passage of HB 6. Subsequently, proposed legislation was introduced that would repeal HB 6. If HB 6 is repealed and not replaced, Energy Harbor’s financial ability to participate in the ICPA could be adversely impacted. Management is currently unable to predict the outcome of the proposed legislation and will continue to monitor the legislative process and any potential impact to OVEC’s cash flows or financial condition. If OVEC does not have sufficient funds to honor its payment obligations, there is risk that APCo, I&M and/or OPCo may need to make payments in addition to their power participation ratio payments. Further, if OVEC’s indebtedness is accelerated for any reason, there is risk that APCo, I&M and/or OPCo may be required to pay some or all of such accelerated indebtedness in amounts equal to their aggregate power participation ratio of 43.47%.

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

None

Item 3. Defaults Upon Senior Securities

None

222

Item 4. Mine Safety Disclosures

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

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act. Exhibit 95 “Mine Safety Disclosure Exhibit” contains the notices of violation and proposed assessments received by DHLC under the Mine Act for the quarter ended June 30, 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 TEXAS‡ File No. 333-221643

4.2

Company Order and Officer’s Certificate, between AEP Texas and The Bank of New York Mellon Trust Company, N.A., as trustee, dated July 1, 2020

Form 8-K dated July 1, 2020 Exhibit 4(a)

APCo‡ File No. 1-3457

4.1

Company Order and Officer’s Certificate, between APCo and The Bank of New York Mellon Trust Company, N.A., as trustee, dated May 14, 2020

Form 8-K dated May 14, 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

Amendment to the AEP Executive Severance Plan dated as of June 17, 2020

31(a)

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

31(b)

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

32(a)

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

32(b)

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

Mine Safety Disclosures

101.INS

XBRL Instance Document

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

223

Exhibit

Description

AEP

AEP
Texas

AEPTCo

APCo

I&M

OPCo

PSO

SWEPCo

101.CAL

XBRL Taxonomy Extension Calculation Linkbase

101.DEF

XBRL Taxonomy Extension Definition Linkbase

101.LAB

XBRL Taxonomy Extension Label Linkbase

101.PRE

XBRL Taxonomy Extension Presentation Linkbase

104

Cover Page Interactive Data File

Formatted as Inline XBRL and contained in Exhibit 101.

224

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: August 6, 2020

225