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, 2019

or

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

For The Transition Period from ____ to ____

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

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

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

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
	Yes	x	No	☐

Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit such files).
	Yes	x	No	☐

Indicate by check mark whether American Electric Power Company, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large Accelerated filer	x	Accelerated filer	☐	Non-accelerated filer	☐
Smaller reporting company	☐	Emerging growth company	☐

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

If an emerging growth company, indicate by check mark if the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
	☐

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No x

AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.

	Number of shares of common stock outstanding of the Registrants as of
	July 25, 2019
American Electric Power Company, Inc.	493,795,111
	($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, 2019
		Page
		Number
Glossary of Terms		i
Forward-Looking Information		v
Part I. FINANCIAL INFORMATION
	Items 1, 2, 3 and 4 - Financial Statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosures About Market Risk, and Controls and Procedures:
American Electric Power Company, Inc. and Subsidiary Companies:
	Management’s Discussion and Analysis of Financial Condition and Results of Operations	1
	Condensed Consolidated Financial Statements	40
AEP Texas Inc. and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	47
	Condensed Consolidated Financial Statements	52
AEP Transmission Company, LLC and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	59
	Condensed Consolidated Financial Statements	61
Appalachian Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	67
	Condensed Consolidated Financial Statements	72
Indiana Michigan Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	79
	Condensed Consolidated Financial Statements	84
Ohio Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	91
	Condensed Consolidated Financial Statements	96
Public Service Company of Oklahoma:
	Management’s Narrative Discussion and Analysis of Results of Operations	103
	Condensed Financial Statements	106
Southwestern Electric Power Company Consolidated:
	Management’s Narrative Discussion and Analysis of Results of Operations	113
	Condensed Consolidated Financial Statements	117
Index of Condensed Notes to Condensed Financial Statements of Registrants		123
Controls and Procedures		215

Part II.  OTHER INFORMATION
	Item 1.	Legal Proceedings	216
	Item 1A.	Risk Factors	216
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	216
	Item 3.	Defaults Upon Senior Securities	216
	Item 4.	Mine Safety Disclosures	216
	Item 5.	Other Information	216
	Item 6.	Exhibits	217
SIGNATURE			218
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 the deregulated Ohio and Texas markets.
AEPRO	AEP River Operations, LLC, a commercial barge operation sold in November 2015.
AEPSC	American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AEPTCo	AEP Transmission Company, LLC, a wholly-owned subsidiary of AEP Transmission Holdco, is an intermediate holding company that owns the State Transcos.
AEPTCo Parent	AEP Transmission Company, LLC, the holding company of the State Transcos within the AEPTCo consolidation.
AFUDC	Allowance for Equity Funds Used During Construction.
AGR	AEP Generation Resources Inc., a competitive AEP subsidiary in the Generation & Marketing segment.
ALJ	Administrative Law Judge.
AOCI	Accumulated Other Comprehensive Income.
APCo	Appalachian Power Company, an AEP electric utility subsidiary.
Appalachian Consumer Rate Relief Funding	Appalachian Consumer Rate Relief Funding LLC, a wholly-owned subsidiary of APCo and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to the under-recovered ENEC deferral balance.
APSC	Arkansas Public Service Commission.
ARAM	Average Rate Assumption Method, an IRS approved method used to calculate the reversal of Excess ADIT for rate-making purposes.
ARO	Asset Retirement Obligations.
ASC	Accounting Standard Codification.
ASU	Accounting Standards Update.
CAA	Clean Air Act.
CLECO	Central Louisiana Electric Company, a nonaffiliated utility company.
Cardinal Operating Company	A jointly-owned organization between AGR and a nonaffiliate. The nonaffiliate operates the three unit Cardinal Plant and wholly-owns Units 2 and 3.
CO2	Carbon dioxide and other greenhouse gases.
Conesville Plant	A generation plant consisting of three coal-fired generating units totaling 1,695 MW located in Conesville, Ohio. The plant is jointly-owned by AGR and a nonaffiliate.
Cook Plant	Donald C. Cook Nuclear Plant, a two-unit, 2,278 MW nuclear plant owned by I&M.
CSAPR	Cross-State Air Pollution Rule.
CWA	Clean Water Act.
CWIP	Construction Work in Progress.

i

Term	Meaning
DCC Fuel	DCC Fuel VIII, DCC Fuel IX, DCC Fuel X, DCC Fuel XI, DCC Fuel XII and DCC Fuel XIII, 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.
DIR	Distribution Investment Rider.
EIS	Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated VIE of AEP.
ENEC	Expanded Net Energy Cost.
Energy Supply	AEP Energy Supply LLC, a nonregulated holding company for AEP’s competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP.
Equity Units	AEP’s Equity Units issued in March 2019.
ERCOT	Electric Reliability Council of Texas regional transmission organization.
ESP	Electric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO.
ETT	Electric Transmission Texas, LLC, an equity interest joint venture between AEP Transmission Holdco and Berkshire Hathaway Energy Company formed to own and operate electric transmission facilities in ERCOT.
Excess ADIT	Excess accumulated deferred income taxes.
FASB	Financial Accounting Standards Board.
Federal EPA	United States Environmental Protection Agency.
FERC	Federal Energy Regulatory Commission.
FGD	Flue Gas Desulfurization or scrubbers.
FIP	Federal Implementation Plan.
FTR	Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP	Accounting Principles Generally Accepted in the United States of America.
Global Settlement	In February 2017, the PUCO approved a settlement agreement filed by OPCo in December 2016 which resolved all remaining open issues on remand from the Supreme Court of Ohio in OPCo’s 2009 - 2011 and June 2012 - May 2015 ESP filings. It also resolved all open issues in OPCo’s 2009, 2014 and 2015 SEET filings and 2009, 2012 and 2013 Fuel Adjustment Clause Audits.
I&M	Indiana Michigan Power Company, an AEP electric utility subsidiary.
IRS	Internal Revenue Service.
IURC	Indiana Utility Regulatory Commission.
KGPCo	Kingsport Power Company, an AEP electric utility subsidiary.
KPCo	Kentucky Power Company, an AEP electric utility subsidiary.
KPSC	Kentucky Public Service Commission.
KWh	Kilowatt-hour.
LPSC	Louisiana Public Service Commission.
MATS	Mercury and Air Toxic Standards.
MISO	Midcontinent Independent System Operator.
MMBtu	Million British Thermal Units.
MPSC	Michigan Public Service Commission.
MTM	Mark-to-Market.
MW	Megawatt.
MWh	Megawatt-hour.
NAAQS	National Ambient Air Quality Standards.
Nonutility Money Pool	Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
NO2	Nitrogen dioxide.
NOx	Nitrogen oxide.

ii

Term	Meaning
NPDES	National Pollutant Discharge Elimination System.
NSR	New Source Review.
OATT	Open Access Transmission Tariff.
OCC	Corporation Commission of the State of Oklahoma.
Ohio Phase-in-Recovery Funding	Ohio Phase-in-Recovery Funding LLC, a wholly-owned subsidiary of OPCo and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to phase-in recovery property.
Oklaunion Power Station	A single unit coal-fired generation plant totaling 650 MW located in Vernon, Texas. The plant is jointly-owned by AEP Texas, PSO and certain nonaffiliated entities.
OPCo	Ohio Power Company, an AEP electric utility subsidiary.
OPEB	Other Postretirement Benefits.
OSS	Off-system Sales.
OTC	Over-the-counter.
OVEC	Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
Parent	American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.
PJM	Pennsylvania – New Jersey – Maryland regional transmission organization.
PM	Particulate Matter.
PPA	Purchase Power and Sale Agreement.
PSO	Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO	Public Utilities Commission of Ohio.
PUCT	Public Utility Commission of Texas.
Racine	A generation plant consisting of two hydroelectric generating units totaling 47.5 MWs located in Racine, Ohio and owned by AGR.
Registrant Subsidiaries	AEP subsidiaries which are SEC registrants: AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
Registrants	SEC registrants: AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
Risk Management Contracts	Trading and non-trading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant	A generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana. AEGCo and I&M jointly-own Unit 1. In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2.
ROE	Return on Equity.
RPM	Reliability Pricing Model.
RSR	Retail Stability Rider.
RTO	Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine	Sabine Mining Company, a lignite mining company that is a consolidated VIE for AEP and SWEPCo.
SCR	Selective Catalytic Reduction, NOx reduction technology at Rockport Plant.
SEC	U.S. Securities and Exchange Commission.
SEET	Significantly Excessive Earnings Test.
Sempra Renewables LLC	Sempra Renewables LLC, acquired in April 2019, consists of 724 MWs of wind generation and battery assets in the United States.
SIP	State Implementation Plan.
SNF	Spent Nuclear Fuel.
SO2	Sulfur dioxide.
SPP	Southwest Power Pool regional transmission organization.
SSO	Standard service offer.
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.

iii

Term	Meaning
Tax Reform	On December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal Revenue Code of 1986, including a reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018.
TCC	Formerly AEP Texas Central Company, now a division of AEP Texas.
Texas Restructuring Legislation	Legislation enacted in 1999 to restructure the electric utility industry in Texas.
Transition Funding	AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated VIEs formed for the purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation.
Transource Energy	Transource Energy, LLC, a consolidated VIE formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates.
Turk Plant	John W. Turk, Jr. Plant, a 600 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.
UPA	Unit Power Agreement.
Utility Money Pool	Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
VIE	Variable Interest Entity.
Virginia SCC	Virginia State Corporation Commission.
Wind Catcher Project	Wind Catcher Energy Connection Project, a joint PSO and SWEPCo project that was cancelled in July 2018. The project included the acquisition of a wind generation facility, totaling approximately 2,000 MW of wind generation, and the construction of a generation interconnection tie-line totaling approximately 350 miles.
WPCo	Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC	Public Service Commission of West Virginia.

iv

FORWARD-LOOKING INFORMATION

This report made by the Registrants contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.  Many forward-looking statements appear in “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the 2018 Annual Report, but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook.  These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected.  Forward-looking statements in this document are presented as of the date of this document.  Except to the extent required by applicable law, management undertakes no obligation to update or revise any forward-looking statement.  Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:

• Changes in economic conditions, electric market demand and demographic patterns in AEP service territories.

• Inflationary or deflationary interest rate trends.

• Volatility in the financial markets, particularly developments affecting the availability or cost of capital to finance new capital projects and refinance existing debt.

• The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.

• 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 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 pronouncements periodically issued by accounting standard-setting bodies.

v

• Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, naturally occurring and human-caused fires, cyber security threats and other catastrophic events.

The forward-looking statements of the Registrants speak only as of the date of this report or as of the date they are made.  The Registrants expressly disclaim any obligation to update any forward-looking information.  For a more detailed discussion of these factors, see “Risk Factors” in Part I of the 2018 Annual Report and in Part II of this report.

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

vi

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Customer Demand

AEP’s weather-normalized retail sales volumes for the second quarter of 2019 decreased by 1.8% compared to the second quarter of 2018. AEP’s second quarter 2019 industrial sales decreased by 2.7% compared to the second quarter of 2018. The decline in industrial sales was spread across most operating companies and most industries outside of the oil and gas sector. Weather-normalized residential sales decreased 1.4% while weather-normalized commercial sales decreased by 0.9% in the second quarter of 2019 compared to the second quarter of 2018.

AEP’s weather-normalized retail sales volumes for the six months ended June 30, 2019 decreased by 1.0% compared to the six months ended June 30, 2018. AEP’s industrial sales volumes for the six months ended June 30, 2019 decreased 1.5% compared to the six months ended June 30, 2018. The decline in industrial sales was spread across most operating companies and most industries outside of the oil and gas sector. Weather-normalized residential and commercial sales decreased 0.1% and 1.3%, respectively, for the six months ended June 30, 2019 compared to the six months ended June 30, 2018.

Regulatory Matters

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

• Texas Storm Cost Securitization - In March 2019, AEP Texas filed a request to securitize total estimated distribution-related system restoration costs with the PUCT in the amount of $230 million, which included estimated carrying costs. In June 2019, the PUCT issued a financing order approving the filing with minimal changes. Subject to market conditions, securitization bonds are expected to be issued in the third quarter of 2019. The remaining $95 million of estimated net transmission-related system restoration costs, including carrying charges, is expected to be recovered in the 2019 Texas Base Rate Case or through interim transmission base rate increases.

• Virginia Legislation Affecting Earnings Reviews - In March 2018, Virginia enacted legislation requiring APCo to file its next generation and distribution base rate case by March 31, 2020 using 2017, 2018 and 2019 test years (“triennial review”). Triennial reviews are subject to an earnings test which provides that 70% of any earnings exceeding 70 basis points over the Virginia SCC authorized return on common equity would be refunded to customers or be used to lower APCo’s Virginia retail base rates on a prospective basis. The Virginia legislation also states that, under certain circumstances, costs associated with asset impairments related to early retirement determinations made by a utility for generation facilities fueled by coal, natural gas or oil or for automated meters be considered fully recovered in the period recorded. Management has reviewed APCo’s actual and forecasted earnings for the triennial period and concluded that it is not probable, but is reasonably possible, that APCo will over-earn in Virginia during the 2017-2019 triennial period. Due to various uncertainties, including weather, storm restoration, weather-normalized demand and potential customer shopping during 2019, management cannot estimate a range of potential APCo Virginia over-earnings during the 2017-2019 triennial period.

• Virginia Staff Depreciation Study Request - In November 2018, Virginia staff recommended that APCo implement new Virginia jurisdictional depreciation rates effective January 1, 2018 based on APCo’s depreciation study that was prepared at Virginia staff’s request using December 31, 2017 APCo property balances. Implementation of those depreciation rates would result in a $21 million pretax increase in annual

1

depreciation expense with no corresponding increase in retail base rates. In December 2018, APCo submitted a response to the Virginia Staff stating that it was inappropriate for APCo to change Virginia depreciation rates in advance of APCo’s triennial review, citing the Virginia SCC’s November 2014 order to not change APCo’s Virginia depreciation rates until APCo’s next base rate case/review.

• 2020 Increase in West Virginia Retail Rates for WPCo 17.5% Merchant Share of Mitchell Plant - In January 2015, the WVPSC approved a settlement agreement whereby 82.5% of the costs associated with WPCo’s acquired interest were prospectively reflected in retail rates with the remaining 17.5% of costs associated with the acquired interest to be included in rates starting January 2020. APCo and WPCo file joint retail rates in West Virginia. In June 2019, APCo and WPCo filed with the WVPSC to increase each company’s retail rates (through a surcharge) starting January 1, 2020 to reflect the recovery of WPCo’s remaining 17.5% interest in the Mitchell Plant. The joint filing will increase APCo’s and WPCo’s combined West Virginia retail rates by approximately $21 million annually.

• 2012 Texas Base Rate Case - In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant. In July 2018, the Texas Third Court of Appeals reversed the PUCT’s judgment affirming the prudence of the Turk Plant and remanded the issue back to the PUCT. In August 2018, SWEPCo filed a Motion for Reconsideration at the Court of Appeals, which was denied. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court. In May 2019, various intervenors filed replies to the petition. SWEPCo’s response to these replies is due in July 2019. As of June 30, 2019, the net book value of Turk Plant was $1.5 billion, before cost of removal, including materials and supplies inventory and CWIP. SWEPCo’s Texas jurisdictional share of the Turk Plant investment is approximately 33%.

• In July 2019, clean energy legislation which offers incentives for power-generating facilities with zero- or reduced carbon emissions was signed into law by the Ohio Governor.  The clean energy legislation phases out current energy efficiency and renewable mandates after 2020 and 2026, respectively.  The bill also provides for the recovery of existing renewable energy contracts on a bypassable basis through 2032 and includes a provision for recovery of certain legacy generation resources which will be allocated to all electric distribution utilities on a non-bypassable basis.  Management is analyzing the impact of this legislation and at this time cannot estimate the impact on results of operations, cash flows or 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 2019. See Note 4 - Rate Matters for additional information.

Completed Base Rate Case Proceedings

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

2

Pending Base Rate Case Proceedings

						Commission Staff/
		Filing	Requested Revenue		Requested	Intervenor Range of
Company	Jurisdiction	Date	Requirement Increase		ROE	Recommended ROE
			(in millions)
SWEPCo	Arkansas	February 2019	$	75.0	10.5%	9% - 9.5%
AEP Texas	Texas	May 2019	56.0		10.5%	(a)
I&M	Indiana	May 2019	172.0		10.5%	(b)
I&M	Michigan	June 2019	58.4		10.5%	(c)

(a) Intervenor direct testimony to be filed by July 25, 2019. Commission Staff direct testimony to be filed by August 1, 2019.

(b) Commission Staff/Intervenor direct testimony to be filed in the third quarter of 2019.

(c) Commission Staff/Intervenor direct testimony to be filed in October 2019.

Renewable Generation

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

Contracted Renewable Generation Facilities

AEP continues to develop its renewable portfolio within the Generation & Marketing segment.  Activities include working directly with wholesale and large retail customers to provide tailored solutions based upon market knowledge, technology innovations and deal structuring which may include distributed solar, wind, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other forms of cost reducing energy technologies.  The Generation & Marketing segment also develops and/or acquires large scale renewable generation projects that are backed with long-term contracts with creditworthy counterparties.

In April 2019, AEP acquired Sempra Renewables LLC and its 724 MWs of wind generation and battery assets for approximately $1.1 billion, subject to working capital adjustments. AEP paid $583 million in cash and assumed approximately $364 million of existing project debt obligations of the non-consolidated joint ventures. Additionally, the acquisition includes the recognition of noncontrolling tax equity interest of an estimated $135 million as of the acquisition date associated with certain of the acquired wind farms. The wind generation portfolio includes seven wind farms with long-term PPAs for 100% of their energy production. Five of the 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. See “Acquisitions” section of Note 6 for additional information.

As of June 30, 2019, subsidiaries within AEP’s Generation & Marketing segment had approximately 1,163 MWs of contracted renewable generation projects in-service.  In addition, as of June 30, 2019, these subsidiaries had approximately 55 MWs of renewable generation projects under construction with total estimated capital costs of $75 million related to these projects.

In July 2019, AEP acquired a 75% interest, or 227 MWs, in the Santa Rita East Wind Project for approximately $356 million. The project is located in West Texas and was placed in-service in July 2019. Long-term virtual power purchase agreements are in place with nonaffiliates for the project’s generation.

Regulated Renewable Generation Facilities

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

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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 55.5% of the project, which will cost approximately $2 billion.  Two wind facilities, totaling 1,286 MWs, would qualify for 80% of the federal Production Tax Credit (PTC) with year-end 2021 in-service dates.  The third wind facility (199 MWs) would qualify for 100% of the PTC with a year-end 2020 in-service date. The acquisition can be scaled, subject to commercial limitation, to align with individual state resource needs and approvals. PSO and SWEPCo are seeking regulatory approval by July 2020.

Racine

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

Due to weather-related delays in the first quarter of 2019, reconstruction activities at Racine are now estimated to be completed in the first half of 2020. AEP expects to incur additional capital expenditures to complete the reconstruction project, at which point the fair value of Racine, as fully operational, is expected to approximate the amount of those remaining estimated capital expenditures. Future revisions in cost estimates or delays in completion could result in additional losses which could reduce future net income and cash flows and impact financial condition.

Dolet Hills Lignite Company Operations

During the second quarter of 2019, Dolet Hills Power Station switched to a seasonal operational strategy. DHLC’s mining operation will continue year-round but will reduce its lignite output. SWEPCo’s share of the net investment in the Dolet Hills Power Station is $130 million and the maximum exposure of SWEPCo’s total investment in DHLC is $163 million. Management will continue to monitor the economic viability of the Dolet Hills Power Station and DHLC.

LITIGATION

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

Rockport Plant Litigation

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

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

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

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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. 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 is unable to determine a range of potential losses that are reasonably possible of occurring.

ENVIRONMENTAL ISSUES

AEP has a substantial capital investment program and incurs additional operational costs to comply with environmental control requirements.  Additional investments and operational changes will be made in response to existing and anticipated requirements to reduce emissions from fossil generation facilities, rules governing the beneficial use and disposal of coal combustion by-products, clean water rules and renewal permits for certain water discharges.

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

AEP will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances.  If AEP is unable to recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.

Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed below will have a material impact on the generating units in the AEP System.  Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of June 30, 2019, the AEP System had generating capacity of approximately 25,400 MWs, of which approximately 13,200 MWs were coal-fired.  Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on the fossil generating facilities. Based upon management estimates, AEP’s investment to meet these existing and proposed requirements ranges from approximately $550 million to $1.1 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 on the units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors.  In addition, management continues to evaluate the economic feasibility of environmental investments on regulated and competitive plants.

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The table below represents the net book value before cost of removal, including related materials and supplies inventory, of plants or units of plants previously retired that have a remaining net book value as of June 30, 2019.

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

(a) APCo obtained permits following the Virginia SCC’s and WVPSC’s approval to convert Clinch River Plant, Units 1 and 2 to natural gas. In 2015, APCo retired the coal-related assets of Clinch River Plant, Units 1 and 2. Clinch River Plant, Units 1 and 2 began operations as natural gas units in 2016.

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

Modification of the New Source Review Litigation Consent Decree

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

In 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio seeking to modify the consent decree to eliminate an obligation to install future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree.  The other parties to the consent decree opposed AEP’s motion. The district court granted AEP’s request to delay the deadline to install SCR technology at Rockport Plant, Unit 2 until June 2020.

In May 2019, the parties filed a proposed order to modify the consent decree and notified the district court that the proposed modification would be published in the Federal Register and made available for public comment for a period of 30 days. The proposed order requires AEP to enhance the dry sorbent injection 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.

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 is evaluating the allegations of patent infringement and cannot predict the outcome of this proceeding or determine a range of potential losses that are reasonably possible of occurring.

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Clean Air Act Requirements

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

National Ambient Air Quality Standards

The Federal EPA issued new, more stringent NAAQS for PM in 2012 and ozone in 2015. The existing standards for NO₂ and SO₂ were retained after review by the Federal EPA in 2018 and 2019, respectively. Implementation of these standards is underway.

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

The Federal EPA finalized non-attainment designations for the 2015 ozone standard in 2018. The Federal EPA has confirmed that for states included in the CSAPR program, there are no additional interstate transport obligations, as all areas of the country are expected to attain the 2008 ozone standard before 2023. Challenges to the 2015 ozone standard and the Federal EPA’s determination that CSAPR satisfies certain states’ interstate transport obligations are pending in the U.S. Court of Appeals for the District of Columbia Circuit. In 2018, the Federal EPA proposed final requirements for implementing the 2015 ozone standard, which have also been challenged in the U.S. Court of Appeals for the District of Columbia Circuit. Management cannot currently predict the nature, stringency or timing of additional requirements for AEP’s facilities based on the outcome of these activities.

Regional Haze

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

In 2012, the Federal EPA proposed disapproval of a portion of the regional haze SIP in Arkansas and finalized a FIP in 2016. In 2017, Arkansas issued a proposed SIP revision to allow sources to participate in the CSAPR ozone season program in lieu of the source-specific NO_x BART requirements in the FIP, and in 2018, the Federal EPA approved the revision. Arkansas finalized a separate action in 2017 to revise the SO₂ BART determinations. In 2018, the Federal EPA proposed to approve the Arkansas SO₂ BART determinations. SWEPCo’s Flint Creek Plant is already in compliance with the applicable requirements.

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

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Cross-State Air Pollution Rule

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

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

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

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

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

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

In 2015, the U.S. Supreme Court reversed the decision of the U.S. Court of Appeals for the District of Columbia Circuit. The court remanded the MATS rule to the Federal EPA to consider costs in determining whether to regulate emissions of HAPs from power plants. In 2016, the Federal EPA issued a supplemental finding concluding that, after considering the costs of compliance, it was appropriate and necessary to regulate HAP emissions from coal and oil-fired units. Petitions for review of the Federal EPA’s determination were filed in the U.S. Court of Appeals for the District of Columbia Circuit. In 2018, the Federal EPA released a revised finding that the costs of reducing HAP emissions to the level in the current rule exceed the benefits of those HAP emission reductions. The Federal EPA also determined that there are no significant changes in control technologies and the remaining risks associated with HAP emissions do not justify any more stringent standards. Therefore, the Federal EPA proposed to retain the current MATS standards without change. The comment period on this proposal ended in April 2019.

Climate Change, CO₂ Regulation and Energy Policy

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

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

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In 2018, the Federal EPA proposed the Affordable Clean Energy (ACE) rule to replace the CPP with new emission guidelines for regulating CO₂ from existing sources. ACE would establish a framework for states to adopt standards of performance for utility boilers based on heat rate improvements for such boilers. A final rule repealing the CPP and adopting the ACE rule was published in July 2019. The final rule applies to generating units that commenced construction prior to January 2014, greater than 25 MWs, have a baseload rating above 250 MMBtu per hour and burn coal for more than 10% of the annual average heat input over the preceding three calendar years, with certain exceptions. States must establish standards of performance for each affected facility in terms of pounds of CO₂ emitted per MWh, based on certain heat rate improvement measures and the degree of emission reduction achievable through each applicable measure, together with consideration of certain site-specific factors and the unit’s remaining useful life. State plans are required to be submitted within three years, and the Federal EPA has up to two years to review and approve or disapprove the plan and adopt a federal plan.

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 and expects CO₂ emissions from its operations to continue to decline due to the retirement of some of its coal-fired generation units, and actions taken to diversify the generation fleet and increase energy efficiency where there is regulatory support for such activities. The majority of the states where AEP has generating facilities passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements that can assist in reducing carbon emissions.  Management is taking steps to comply with these requirements, including increasing wind and solar installations, renewable power purchases and broadening AEP System’s portfolio of energy efficiency programs.

In 2018, AEP announced new intermediate and long-term CO₂ emission reduction goals, based on the output of the company’s integrated resource plans, which take into account economics, customer demand, grid reliability and resiliency, regulations and the company’s current business strategy. The intermediate goal is a 60% reduction from 2000 CO₂ emission levels from AEP generating facilities by 2030; the long-term goal is an 80% reduction of CO₂ emissions from AEP generating facilities from 2000 levels by 2050. AEP’s total estimated CO₂ emissions in 2018 were approximately 69 million metric tons, a 59% reduction from AEP’s 2000 CO₂ emissions.

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

Coal Combustion Residual (CCR) Rule

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

The final 2015 rule was challenged in the courts.  In 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued its decision vacating and remanding certain provisions of the 2015 rule.  Remaining issues were dismissed.  The provisions addressed by the court’s decision, including changes to the provisions for unlined impoundments and legacy sites, will be the subject of further rulemaking consistent with the court’s decision.

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Prior to the court’s decision, the Federal EPA issued the July 2018 rule that modifies certain compliance deadlines and other requirements in the 2015 rule.  In December 2018, challengers filed a motion for partial stay or vacatur of the July 2018 rule. On the same day, the Federal EPA filed a motion for partial remand of the July 2018 rule. The court granted the Federal EPA’s motion, and further rulemaking to address the court’s decisions is expected to be completed near the end of 2019.

Other utilities and industrial sources have been engaged in litigation with environmental advocacy groups who claim that releases of contaminants from wells, CCR units, pipelines and other facilities to groundwaters that have a hydrologic connection to a surface water body represent an “unpermitted discharge” under the CWA. Two cases were accepted by the U.S. Supreme Court for further review of the scope of CWA jurisdiction. The Federal EPA 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 this guidance or the outcome of these cases on AEP’s facilities.

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

Clean Water Act Regulations

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

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

In 2015, the Federal EPA and the U.S. Army Corps of Engineers jointly issued a final rule to clarify the scope of the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases. The final rule was challenged in several courts that have reached different conclusions about whether the 2015 rule should be implemented. In December 2018, the Federal EPA and the U.S. Army Corps of Engineers released a proposed rule revising the definition, which would replace the definition in the 2015 rule and could significantly alter the scope of certain CWA programs. The comment period for this proposal ended in April 2019.

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RESULTS OF OPERATIONS

SEGMENTS

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

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

Vertically Integrated Utilities

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

Transmission and Distribution Utilities

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

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

AEP Transmission Holdco

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

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

Generation & Marketing

• Competitive generation in ERCOT and PJM.

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

• Contracted renewable energy investments and management services.

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

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

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

	Three Months Ended  June 30,						Six Months Ended  June 30,
	2019			2018			2019			2018
	(in millions)
Vertically Integrated Utilities	$	177.7		$	276.8		$	480.1		$	508.0
Transmission and Distribution Utilities	131.4			114.0			287.9			239.4
AEP Transmission Holdco	154.5			101.1			278.7			205.1
Generation & Marketing	9.4			38.8			49.5			57.0
Corporate and Other	(11.7		)	(2.3		)	(62.1		)	(26.7		)
Earnings Attributable to AEP Common Shareholders	$	461.3		$	528.4		$	1,034.1		$	982.8

AEP CONSOLIDATED

Second Quarter of 2019 Compared to Second Quarter of 2018

Earnings Attributable to AEP Common Shareholders decreased from $528 million in 2018 to $461 million in 2019 primarily due to:

• A decrease in weather-related usage.

This decrease was partially offset by:

• An increase in transmission investment, which resulted in higher revenues and income.

• Favorable rate proceedings in AEP’s various jurisdictions.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

Earnings Attributable to AEP Common Shareholders increased from $983 million in 2018 to $1,034 million in 2019 primarily due to:

• An increase in transmission investment, which resulted in higher revenues and income.

• Favorable rate proceedings in AEP’s various jurisdictions.

These increases were partially offset by:

• A decrease in weather-related usage.

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

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VERTICALLY INTEGRATED UTILITIES

	Three Months Ended  June 30,						Six Months Ended  June 30,
Vertically Integrated Utilities	2019			2018			2019			2018
	(in millions)
Revenues	$	2,123.8		$	2,349.0		$	4,527.1		$	4,757.0
Fuel and Purchased Electricity	699.6			808.0			1,556.0			1,665.8
Gross Margin	1,424.2			1,541.0			2,971.1			3,091.2
Other Operation and Maintenance	684.1			703.8			1,374.2			1,443.8
Depreciation and Amortization	359.0			312.7			715.3			626.0
Taxes Other Than Income Taxes	113.2			107.7			229.2			217.6
Operating Income	267.9			416.8			652.4			803.8
Other Income	2.2			4.7			3.5			10.1
Allowance for Equity Funds Used During Construction	16.0			7.3			26.7			14.7
Non-Service Cost Components of Net Periodic Benefit Cost	16.8			17.6			33.8			35.7
Interest Expense	(143.0		)	(140.9		)	(282.0		)	(278.8		)
Income Before Income Tax Expense (Benefit) and Equity Earnings	159.9			305.5			434.4			585.5
Income Tax Expense (Benefit)	(18.1		)	28.3			(46.5		)	76.0
Equity Earnings of Unconsolidated Subsidiaries	0.8			0.7			1.5			1.2
Net Income	178.8			277.9			482.4			510.7
Net Income Attributable to Noncontrolling Interests	1.1			1.1			2.3			2.7
Earnings Attributable to AEP Common Shareholders	$	177.7		$	276.8		$	480.1		$	508.0

Summary of KWh Energy Sales for Vertically Integrated Utilities

	Three Months Ended  June 30,		Six Months Ended  June 30,
	2019	2018	2019	2018
	(in millions of KWhs)
Retail:
Residential	6,315	7,545	15,531	17,117
Commercial	5,710	6,189	11,343	11,976
Industrial	8,865	9,072	17,410	17,650
Miscellaneous	547	588	1,093	1,141
Total Retail (a)	21,437	23,394	45,377	47,884
Wholesale (b)	4,826	4,986	10,630	10,724
Total KWhs	26,263	28,380	56,007	58,608

(a) 2018 KWhs have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail KWhs. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.

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

13

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,
	2019	2018	2019	2018
	(in degree days)
Eastern Region
Actual – Heating (a)	99	207	1,670	1,844
Normal – Heating (b)	142	138	1,737	1,740
Actual – Cooling (c)	378	480	379	486
Normal – Cooling (b)	333	328	338	333
Western Region
Actual – Heating (a)	26	93	967	974
Normal – Heating (b)	35	32	901	907
Actual – Cooling (c)	651	901	662	937
Normal – Cooling (b)	699	692	727	719

(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.

14

Second Quarter of 2019 Compared to Second Quarter of 2018

Reconciliation of Second Quarter of 2018 to Second Quarter of 2019
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
Second Quarter of 2018	$	276.8
Changes in Gross Margin:
Retail Margins	(67.2		)
Off-system Sales	(2.8		)
Transmission Revenues	(49.6		)
Other Revenues	2.8
Total Change in Gross Margin	(116.8		)
Changes in Expenses and Other:
Other Operation and Maintenance	19.7
Depreciation and Amortization	(46.3		)
Taxes Other Than Income Taxes	(5.5		)
Other Income	(2.5		)
Allowance for Equity Funds Used During Construction	8.7
Non-Service Cost Components of Net Periodic Pension Cost	(0.8		)
Interest Expense	(2.1		)
Total Change in Expenses and Other	(28.8		)
Income Tax Expense (Benefit)	46.4
Equity Earnings of Unconsolidated Subsidiaries	0.1
Second Quarter of 2019	$	177.7

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

• Retail Margins decreased $67 million primarily due to the following:

• An $81 million decrease in weather-related usage primarily in the residential class.

• A $48 million decrease in weather-normalized retail margins across all classes.

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

These decreases were partially offset by:

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

• A $28 million increase from rate proceedings at I&M, inclusive of a $24 million decrease due to the impact of Tax Reform. This increase was partially offset in other expense items below.

• A $13 million increase related to rider revenues at I&M, primarily due to the timing of the Indiana PJM/OSS rider recovery. This increase was partially offset in other expense items below.

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

• A $6 million increase at APCo and WPCo due to base rate increases in West Virginia implemented in March 2019.

• A $5 million increase at APCo and WPCo due to revenue from rate riders in West Virginia. This increase was partially offset in other expense items below.

• Transmission Revenues decreased $50 million primarily due to the following:

• A $40 million decrease in SWEPCo’s annual SPP Transmission formula rate true-up. This decrease was partially offset by a decrease in transmission expenses in SPP.

• A $9 million decrease in I&M’s annual PJM Transmission formula rate true-up.

15

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

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

• A $58 million decrease due to SPP transmission services including the annual formula rate true-up.

• A $17 million decrease due to Wind Catcher Project expenses incurred in 2018 for SWEPCo and PSO.

• A $15 million decrease in recoverable expenses primarily associated with Energy Efficiency/Demand Response and storm expenses fully recovered in rate riders/trackers within Gross Margin above.

• A $10 million decrease in planned plant outage and maintenance expenses primarily for I&M and SWEPCo.

• A $3 million decrease in expense at APCo due to the extinguishment of certain regulatory asset balances in August 2018 as agreed to within the 2018 West Virginia Tax Reform settlement. This decrease was offset in Retail Margins above.

These decreases were partially offset by:

• A $43 million increase due to PJM transmission services including the annual formula rate true-up.

• A $12 million increase at APCo due to contributions to benefit low income West Virginia residential customers as a result of the 2018 West Virginia Tax Reform settlement. This increase was offset in Income Tax Expense (Benefit) below.

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

• A $6 million increase in storm-related expenses primarily at SWEPCo.

• A $5 million increase in customer related expenses.

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

• Depreciation and Amortization expenses increased $46 million primarily due to a higher depreciable base and increased depreciation rates approved at APCo, I&M and SWEPCo.

• Taxes Other Than Income Taxes increased $6 million primarily due to an increase in property taxes driven by an increase in utility plant.

• Allowance for Equity Funds Used During Construction increased $9 million primarily due to the following:

• A $5 million increase primarily due to various increases in equity rates at I&M, APCo and PSO and increased projects at I&M.

• A $2 million increase due to the FERC’s approval of a settlement agreement.

• A $2 million increase due to recent FERC audit findings.

• Income Tax Expense (Benefit) decreased $46 million primarily due to $30 million of increased amortization of Excess ADIT not subject to normalization requirements. This decrease was partially offset in Gross Margin above.

16

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

Reconciliation of Six Months Ended June 30, 2018 to Six Months Ended June 30, 2019
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
Six Months Ended June 30, 2018	$	508.0
Changes in Gross Margin:
Retail Margins	(69.7		)
Off-system Sales	(9.4		)
Transmission Revenues	(40.2		)
Other Revenues	(0.8		)
Total Change in Gross Margin	(120.1		)
Changes in Expenses and Other:
Other Operation and Maintenance	69.6
Depreciation and Amortization	(89.3		)
Taxes Other Than Income Taxes	(11.6		)
Other Income	(6.6		)
Allowance for Equity Funds Used During Construction	12.0
Non-Service Cost Components of Net Periodic Pension Cost	(1.9		)
Interest Expense	(3.2		)
Total Change in Expenses and Other	(31.0		)
Income Tax Expense (Benefit)	122.5
Equity Earnings of Unconsolidated Subsidiaries	0.3
Net Income Attributable to Noncontrolling Interests	0.4
Six Months Ended June 30, 2019	$	480.1

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

• Retail Margins decreased $70 million primarily due to the following:

• A $95 million decrease in weather-related usage across all regions primarily in the residential class.

• A $72 million decrease in weather-normalized retail margins across all classes.

• A $34 million decrease due to customer refunds related to Tax Reform. This decrease was partially offset in Income Tax Expense (Benefit) below.

These decreases were partially offset by:

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

• A $75 million increase from rate proceedings at I&M, inclusive of a $33 million decrease due to the impact of Tax Reform. This increase was partially offset in other expense items below.

• A $22 million increase at PSO due to new base rates implemented in April 2019 and March 2018.

• A $10 million increase due to the timing of recovery of the Indiana PJM/OSS rider at I&M. This increase was partially offset in other expense items below.

• An $8 million increase at APCo and WPCo primarily due to revenue from rate riders in West Virginia. This increase was offset in other expense items below.

• A $7 million increase at APCo and WPCo due to base rate increases in West Virginia implemented in March 2019.

• Margins from Off-system Sales decreased $9 million primarily due to mid-year 2018 changes in the OSS sharing mechanism at I&M.

17

• Transmission Revenues decreased $40 million primarily due to the following:

• A $40 million decrease in SWEPCo’s annual SPP Transmission formula rate true-up. This decrease was partially offset by a decrease in transmission expenses in SPP.

• A $10 million decrease in I&M’s annual PJM Transmission formula rate true-up.

These decreases were partially offset by:

• A $13 million increase primarily due to 2018 provisions for refunds at APCo.

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

• Other Operation and Maintenance expenses decreased $70 million primarily due to the following:

• A $64 million decrease due to SPP transmission services including the annual formula rate true-up.

• A $34 million decrease in planned plant outage and maintenance expenses primarily for I&M, SWEPCo, KPCo and APCo.

• A $31 million decrease due to Wind Catcher Project expenses incurred in 2018 for SWEPCo and PSO.

• A $26 million decrease in recoverable expenses primarily associated with Energy Efficiency/Demand Response and storm expenses fully recovered in rate riders/trackers within Gross Margin above.

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

• A $6 million decrease in expense at APCo due to the extinguishment of certain regulatory asset balances in August 2018 as agreed to within the 2018 West Virginia Tax Reform settlement. This decrease was offset in Retail Margins above.

These decreases were partially offset by:

• A $47 million increase due to PJM transmission services including the annual formula rate true-up.

• A $26 million increase in employee-related expenses.

• A $13 million increase at APCo due to contributions to benefit low income West Virginia residential customers as a result of the 2018 West Virginia Tax Reform settlement. This increase was offset in Income Tax Expense (Benefit) below.

• A $7 million increase in storm-related expenses primarily at SWEPCo.

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

• Depreciation and Amortization expenses increased $89 million primarily due to a higher depreciable base and increased depreciation rates approved at APCo, I&M, PSO and SWEPCo.

• Taxes Other Than Income Taxes increased $12 million primarily due to the following:

• A $9 million increase in property taxes driven by an increase in utility plant.

• A $4 million increase at APCo in West Virginia business and occupational taxes.

• Other Income decreased $7 million primarily due to a decrease in carrying charges for certain riders at I&M.

• Allowance for Equity Funds Used During Construction increased $12 million primarily due to the following:

• A $7 million increase primarily due to various increases in equity rates at I&M, APCo and PSO and increased projects at I&M.

• A $3 million increase due to recent FERC audit findings.

• A $2 million increase due to the FERC’s approval of a settlement agreement.

• Income Tax Expense (Benefit) decreased $123 million primarily due to $89 million of increased amortization of Excess ADIT not subject to normalization requirements. This decrease was partially offset in Gross Margin above.

18

TRANSMISSION AND DISTRIBUTION UTILITIES

	Three Months Ended  June 30,						Six Months Ended  June 30,
Transmission and Distribution Utilities	2019			2018			2019			2018
	(in millions)
Revenues	$	1,045.7		$	1,137.0		$	2,267.7		$	2,299.4
Purchased Electricity	163.7			196.7			393.4			441.3
Amortization of Generation Deferrals	24.1			56.4			56.5			115.0
Gross Margin	857.9			883.9			1,817.8			1,743.1
Other Operation and Maintenance	410.4			379.0			816.3			731.7
Depreciation and Amortization	193.4			184.4			377.1			357.0
Taxes Other Than Income Taxes	139.9			132.6			285.4			270.0
Operating Income	114.2			187.9			339.0			384.4
Interest and Investment Income (Loss)	1.8			(0.1		)	3.1			1.3
Carrying Costs Income	0.2			0.6			0.4			1.3
Allowance for Equity Funds Used During Construction	5.6			7.2			12.5			15.2
Non-Service Cost Components of Net Periodic Benefit Cost	7.5			8.1			15.1			16.3
Interest Expense	(45.2		)	(62.0		)	(107.2		)	(122.1		)
Income Before Income Tax Expense (Benefit)	84.1			141.7			262.9			296.4
Income Tax Expense (Benefit)	(47.3		)	27.7			(25.0		)	57.0
Net Income	131.4			114.0			287.9			239.4
Net Income Attributable to Noncontrolling Interests	—			—			—			—
Earnings Attributable to AEP Common Shareholders	$	131.4		$	114.0		$	287.9		$	239.4

Summary of KWh Energy Sales for Transmission and Distribution Utilities

	Three Months Ended  June 30,		Six Months Ended  June 30,
	2019	2018	2019	2018
	(in millions of KWhs)
Retail:
Residential	5,799	6,409	12,346	13,206
Commercial	6,232	6,417	11,850	12,103
Industrial	5,864	6,194	11,635	11,868
Miscellaneous	196	194	372	365
Total Retail (a)(b)	18,091	19,214	36,203	37,542
Wholesale (c)	440	534	1,078	1,201
Total KWhs	18,531	19,748	37,281	38,743

(a) 2018 KWhs have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail KWhs. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.

(b) Represents energy delivered to distribution customers.

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

19

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

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

	Three Months Ended  June 30,		Six Months Ended  June 30,
	2019	2018	2019	2018
	(in degree days)
Eastern Region
Actual – Heating (a)	114	274	2,006	2,158
Normal – Heating (b)	189	186	2,066	2,070
Actual – Cooling (c)	303	454	304	458
Normal – Cooling (b)	298	291	301	294
Western Region
Actual – Heating (a)	3	4	180	234
Normal – Heating (b)	3	3	190	194
Actual – Cooling (d)	970	992	1,092	1,188
Normal – Cooling (b)	934	927	1,057	1,046

(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.

20

Second Quarter of 2019 Compared to Second Quarter of 2018

Reconciliation of Second Quarter of 2018 to Second Quarter of 2019
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
Second Quarter of 2018	$	114.0
Changes in Gross Margin:
Retail Margins	(69.5		)
Off-system Sales	13.0
Transmission Revenues	28.5
Other Revenues	2.0
Total Change in Gross Margin	(26.0		)
Changes in Expenses and Other:
Other Operation and Maintenance	(31.4		)
Depreciation and Amortization	(9.0		)
Taxes Other Than Income Taxes	(7.3		)
Interest and Investment Income	1.9
Carrying Costs Income	(0.4		)
Allowance for Equity Funds Used During Construction	(1.6		)
Non-Service Cost Components of Net Periodic Benefit Cost	(0.6		)
Interest Expense	16.8
Total Change in Expenses and Other	(31.6		)
Income Tax Expense (Benefit)	75.0
Second Quarter of 2019	$	131.4

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 $70 million primarily due to the following:

• A $60 million net decrease in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses. This decrease was partially offset by a decrease in Other Operation and Maintenance expenses below.

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

• A $6 million net decrease in margin in Ohio for the Phase-In-Recovery Rider including associated amortizations which ended in the first quarter of 2019.

• A $6 million decrease in rider revenues associated with the DIR in Ohio. This decrease was partially offset in various expenses below.

• A $6 million decrease in affiliated PPA capacity revenues in Texas. This decrease was offset by a corresponding increase in Margins from Off-system Sales below.

These decreases were partially offset by:

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

• An $8 million increase due to the recovery of higher current year losses from a power contract with OVEC in Ohio. This increase was offset by a corresponding decrease in Margins from Off-system Sales below.

21

• Margins from Off-system Sales increased $13 million primarily due to the following:

• A $21 million increase due to higher affiliated PPA revenues in Texas. This increase was partially offset by a corresponding increase in Other Operation and Maintenance expenses below.

This increase was partially offset by:

• An $8 million decrease primarily due to higher current year losses from a power contract with OVEC as a result of the OVEC PPA rider in Ohio. This decrease was offset by a corresponding increase in Retail Margins above.

• Transmission Revenues increased $29 million primarily due to the recovery of increased transmission investment in ERCOT.

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

• Other Operation and Maintenance expenses increased $31 million primarily due to the following:

• A $64 million increase in expense due to the partial amortization of the Texas Storm Cost Securitization regulatory asset as a result of the final PUCT order in the Texas Storm Cost Case. This increase was offset by a corresponding decrease in Income Tax Expense (Benefit) below.

• A $35 million increase in PJM expenses primarily related to the annual formula rate true-up.

• A $16 million increase in affiliated PPA expenses in Texas. This increase was offset by an increase in Margins from Off-system Sales above.

These increases were partially offset by:

• An $88 million decrease in transmission expenses that were fully recovered in rate riders/trackers within Gross Margin above.

• Depreciation and Amortization expenses increased $9 million primarily due to the following:

• A $19 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.

• A $2 million increase in depreciation expense related to the Oklaunion Power Station.

These increases were partially offset by:

• A $14 million decrease in Ohio recoverable DIR depreciation expense. This decrease was partially offset in Retail Margins above.

• Taxes Other Than Income Taxes increased $7 million primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.

• Interest Expense decreased $17 million primarily 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.

• Income Tax Expense (Benefit) decreased $75 million primarily due to the amortization of Excess ADIT not subject to normalization requirements as approved in the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019. This decrease was partially offset in Other Operation and Maintenance expenses above.

22

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

Reconciliation of Six Months Ended June 30, 2018 to Six Months Ended June 30, 2019
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
Six Months Ended June 30, 2018	$	239.4
Changes in Gross Margin:
Retail Margins	(11.5		)
Off-system Sales	33.9
Transmission Revenues	50.9
Other Revenues	1.4
Total Change in Gross Margin	74.7
Changes in Expenses and Other:
Other Operation and Maintenance	(84.6		)
Depreciation and Amortization	(20.1		)
Taxes Other Than Income Taxes	(15.4		)
Interest and Investment Income	1.8
Carrying Costs Income	(0.9		)
Allowance for Equity Funds Used During Construction	(2.7		)
Non-Service Cost Components of Net Periodic Benefit Cost	(1.2		)
Interest Expense	14.9
Total Change in Expenses and Other	(108.2		)
Income Tax Expense (Benefit)	82.0
Six Months Ended June 30, 2019	$	287.9

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 decreased $12 million primarily due to the following:

• A $43 million net decrease in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses. This decrease was partially offset by a decrease in Other Operation and Maintenance expenses below.

• A $13 million decrease in weather-related usage in Texas primarily due to a 23% decrease in heating degree days and an 8% decrease in cooling degree days.

• A $12 million decrease in revenues associated with vegetation management riders in Ohio. This decrease was offset in Other Operation and Maintenance expenses below.

• An $11 million decrease in affiliated PPA capacity revenues in Texas. This decrease was offset by a corresponding increase in Margins from Off-system Sales below.

• A $10 million net decrease in margin in Ohio for the Phase-In-Recovery Rider including associated amortizations which ended in the first quarter of 2019.

• An $8 million decrease in rider revenues associated with the DIR in Ohio. This decrease was partially offset in various expenses below.

• An $8 million decrease in Texas revenues associated with the Transmission Cost Recovery Factor revenue rider. This decrease was partially offset by a decrease in Other Operation and Maintenance expenses below.

These decreases were partially offset by:

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

• A $22 million increase in revenues associated with Ohio smart grid riders. This increase was partially offset by increases in other expense items below.

• A $9 million increase due to the recovery of higher current year losses from a power contract with OVEC in Ohio. This increase was offset by a corresponding decrease in Margins from Off-system Sales below.

23

• Margins from Off-system Sales increased $34 million primarily due to due to the following:

• A $43 million increase due to higher affiliated PPA revenues in Texas. This increase was partially offset by a corresponding increase in Other Operation and Maintenance expenses below.

This increase was partially offset by:

• A $9 million decrease primarily due to higher current year losses from a power contract with OVEC as a result of the OVEC PPA rider in Ohio. This decrease was offset by a corresponding increase in Retail Margins above.

• Transmission Revenues increased $51 million primarily due to the following:

• A $38 million increase primarily due to recovery of increased transmission investment in ERCOT.

• A $13 million increase in Ohio primarily due to 2018 provisions for refunds.

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

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

• A $64 million increase in expense due to the partial amortization of the Texas Storm Cost Securitization regulatory asset as a result of the final PUCT order in the Texas Storm Cost Case. This increase was offset by a corresponding decrease in Income Tax Expense (Benefit) below.

• A $45 million increase in PJM expenses primarily related to the annual formula rate true-up.

• A $33 million increase in affiliated PPA expenses in Texas. This increase was offset by an increase in Margins from Off-system Sales above.

These increases were partially offset by:

• A $65 million decrease in transmission expenses that were fully recovered in rate riders/trackers within Gross Margin above.

• Depreciation and Amortization expenses increased $20 million primarily due to the following:

• A $36 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.

• A $4 million increase in depreciation expense related to the Oklaunion Power Station.

These increases were partially offset by:

• A $24 million decrease in Ohio recoverable DIR depreciation expense. This decrease was partially offset in Retail Margins above.

• Taxes Other Than Income Taxes increased $15 million primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.

• Interest Expense decreased $15 million primarily 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.

• Income Tax Expense (Benefit) decreased $82 million primarily due to the amortization of Excess ADIT not subject to normalization requirements as approved in the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019. This decrease was partially offset in Other Operation and Maintenance expenses above.

24

AEP TRANSMISSION HOLDCO

	Three Months Ended  June 30,						Six Months Ended  June 30,
AEP Transmission Holdco	2019			2018			2019			2018
	(in millions)
Transmission Revenues	$	278.9		$	212.5		$	535.3		$	418.0
Other Operation and Maintenance	22.9			23.4			45.2			45.3
Depreciation and Amortization	44.6			33.8			86.4			65.6
Taxes Other Than Income Taxes	43.5			37.5			86.1			70.2
Operating Income	167.9			117.8			317.6			236.9
Other Income	0.8			0.4			1.5			0.7
Allowance for Equity Funds Used During Construction	28.8			16.3			40.1			31.6
Non-Service Cost Components of Net Periodic Benefit Cost	0.7			0.7			1.3			1.4
Interest Expense	(23.0		)	(21.5		)	(46.0		)	(42.6		)
Income Before Income Tax Expense and Equity Earnings	175.2			113.7			314.5			228.0
Income Tax Expense	38.4			28.3			70.3			55.8
Equity Earnings of Unconsolidated Subsidiaries	18.6			16.5			36.4			34.5
Net Income	155.4			101.9			280.6			206.7
Net Income Attributable to Noncontrolling Interests	0.9			0.8			1.9			1.6
Earnings Attributable to AEP Common Shareholders	$	154.5		$	101.1		$	278.7		$	205.1

Summary of Investment in Transmission Assets for AEP Transmission Holdco

	June 30,
	2019		2018
	(in millions)
Plant in Service	$	7,447.3	$	6,158.5
Construction Work in Progress	1,883.1		1,626.0
Accumulated Depreciation and Amortization	350.2		219.0
Total Transmission Property, Net	$	8,980.2	$	7,565.5

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Second Quarter of 2019 Compared to Second Quarter of 2018

Reconciliation of Second Quarter of 2018 to Second Quarter of 2019

Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco

(in millions)

Second Quarter of 2018	$	101.1
Changes in Transmission Revenues:
Transmission Revenues	66.4
Total Change in Transmission Revenues	66.4
Changes in Expenses and Other:
Other Operation and Maintenance	0.5
Depreciation and Amortization	(10.8		)
Taxes Other Than Income Taxes	(6.0		)
Other Income	0.4
Allowance for Equity Funds Used During Construction	12.5
Non-Service Cost Components of Net Periodic Pension Cost	—
Interest Expense	(1.5		)
Total Change in Expenses and Other	(4.9		)
Income Tax Expense	(10.1		)
Equity Earnings of Unconsolidated Subsidiaries	2.1
Net Income Attributable to Noncontrolling Interests	(0.1		)
Second Quarter of 2019	$	154.5

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

• Transmission Revenues increased $66 million primarily due to continued investment in transmission assets.

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

• Depreciation and Amortization expenses increased $11 million primarily due to a higher depreciable base.

• Taxes Other Than Income Taxes increased $6 million primarily due to higher property taxes as a result of increased transmission investment.

• Allowance for Equity Funds Used During Construction increased $13 million primarily due to the following:

• A $12 million increase due to the FERC’s approval of a settlement agreement.

• A $5 million increase due to increased transmission investment resulting in a higher CWIP balance.

These increases were partially offset by:

• A $4 million decrease due to recent FERC audit findings.

• Income Tax Expense increased $10 million primarily due to higher pretax book income with a partial offset due to the FERC’s approval of a settlement agreement.

26

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

Reconciliation of Six Months Ended June 30, 2018 to Six Months Ended June 30, 2019

Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco

(in millions)

Six Months Ended June 30, 2018	$	205.1
Changes in Transmission Revenues:
Transmission Revenues	117.3
Total Change in Transmission Revenues	117.3
Changes in Expenses and Other:
Other Operation and Maintenance	0.1
Depreciation and Amortization	(20.8		)
Taxes Other Than Income Taxes	(15.9		)
Other Income	0.8
Allowance for Equity Funds Used During Construction	8.5
Non-Service Cost Components of Net Periodic Pension Cost	(0.1		)
Interest Expense	(3.4		)
Total Change in Expenses and Other	(30.8		)
Income Tax Expense	(14.5		)
Equity Earnings of Unconsolidated Subsidiaries	1.9
Net Income Attributable to Noncontrolling Interests	(0.3		)
Six Months Ended June 30, 2019	$	278.7

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

• Transmission Revenues increased $117 million primarily due to continued investment in transmission assets.

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

• Depreciation and Amortization expenses increased $21 million primarily due to a higher depreciable base.

• Taxes Other Than Income Taxes increased $16 million primarily due to higher property taxes as a result of increased transmission investment.

• Allowance for Equity Funds Used During Construction increased $9 million primarily due to the following:

• A $12 million increase due to the FERC’s approval of a settlement agreement.

• A $10 million increase due to increased transmission investment resulting in a higher CWIP balance.

These increases were partially offset by:

• A $13 million decrease due to recent FERC audit findings.

• Income Tax Expense increased $15 million primarily due to higher pretax book income with a partial offset due to the FERC’s approval of a settlement agreement.

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GENERATION & MARKETING

	Three Months Ended  June 30,						Six Months Ended  June 30,
Generation & Marketing	2019			2018			2019			2018
	(in millions)
Revenues	$	412.7		$	460.7		$	894.5		$	965.8
Fuel, Purchased Electricity and Other	330.7			354.0			714.0			762.8
Gross Margin	82.0			106.7			180.5			203.0
Other Operation and Maintenance	63.4			56.8			114.0			124.4
Depreciation and Amortization	15.6			7.5			28.5			14.4
Taxes Other Than Income Taxes	3.6			3.4			7.4			6.6
Operating Income (Loss)	(0.6		)	39.0			30.6			57.6
Interest and Investment Income	1.8			3.8			4.1			6.3
Non-Service Cost Components of Net Periodic Benefit Cost	3.7			3.8			7.4			7.7
Interest Expense	(7.2		)	(4.0		)	(11.0		)	(7.9		)
Income (Loss) Before Income Tax Expense (Benefit) and Equity Earnings (Loss)	(2.3		)	42.6			31.1			63.7
Income Tax Expense (Benefit)	(9.6		)	4.3			(15.4		)	7.3
Equity Earnings (Loss) of Unconsolidated Subsidiaries	(2.1		)	0.3			(2.1		)	0.3
Net Income	5.2			38.6			44.4			56.7
Net Loss Attributable to Noncontrolling Interests	(4.2		)	(0.2		)	(5.1		)	(0.3		)
Earnings Attributable to AEP Common Shareholders	$	9.4		$	38.8		$	49.5		$	57.0

Summary of MWhs Generated for Generation & Marketing

	Three Months Ended  June 30,		Six Months Ended  June 30,
	2019	2018	2019	2018
	(in millions of MWhs)
Fuel Type:
Coal	1	4	2	6
Renewables	1	—	1	—
Total MWhs	2	4	3	6

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Second Quarter of 2019 Compared to Second Quarter of 2018

Reconciliation of Second Quarter of 2018 to Second Quarter of 2019
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
Second Quarter of 2018	$	38.8
Changes in Gross Margin:
Generation	(10.8		)
Retail, Trading and Marketing	(19.1		)
Other Revenues	5.2
Total Change in Gross Margin	(24.7		)
Changes in Expenses and Other:
Other Operation and Maintenance	(6.6		)
Depreciation and Amortization	(8.1		)
Taxes Other Than Income Taxes	(0.2		)
Interest and Investment Income	(2.0		)
Non-Service Cost Components of Net Periodic Benefit Cost	(0.1		)
Interest Expense	(3.2		)
Total Change in Expenses and Other	(20.2		)
Income Tax Expense (Benefit)	13.9
Equity Earnings (Loss) of Unconsolidated Subsidiaries	(2.4		)
Net Loss Attributable to Noncontrolling Interests	4.0
Second Quarter of 2019	$	9.4

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

• Generation decreased $11 million primarily due to the reduction of energy margins in 2019, a reduction in revenues due to the retirement of the Stuart Plant in 2018 and outages at the Conesville Plant.

• Retail, Trading and Marketing decreased $19 million due to higher MTM hedge losses offset by higher retail margins due to lower market costs and higher delivered volumes.

• Other Revenues increased $5 million primarily due to the Sempra Renewables LLC acquisition and other renewable projects placed in service.

Expenses and Other, Income Tax Expense (Benefit) and Net Loss Attributable to Noncontrolling Interests changed between years as follows:

• Other Operation and Maintenance expenses increased $7 million primarily due to the Sempra Renewables LLC acquisition costs and increased investments in wind farms and renewable energy sources.

• Depreciation and Amortization expenses increased $8 million due to a higher depreciable base from increased investments in wind farms and renewable energy sources.

• Interest Expense increased $3 million primarily due to increased borrowing costs related to the Sempra Renewables LLC acquisition.

• Income Tax Expense (Benefit) decreased $14 million primarily due to an increase in projected renewable income tax credits primarily driven by the Sempra Renewables LLC acquisition and a decrease in pretax book income.

• Net Loss Attributable to Noncontrolling Interests increased $4 million primarily due to the Sempra Renewables LLC acquisition.

29

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

Reconciliation of Six Months Ended June 30, 2018 to Six Months Ended June 30, 2019
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
Six Months Ended June 30, 2018	$	57.0
Changes in Gross Margin:
Generation	(44.5		)
Retail, Trading and Marketing	15.1
Other Revenues	6.9
Total Change in Gross Margin	(22.5		)
Changes in Expenses and Other:
Other Operation and Maintenance	10.4
Depreciation and Amortization	(14.1		)
Taxes Other Than Income Taxes	(0.8		)
Interest and Investment Income	(2.2		)
Non-Service Cost Components of Net Periodic Benefit Cost	(0.3		)
Interest Expense	(3.1		)
Total Change in Expenses and Other	(10.1		)
Income Tax Expense (Benefit)	22.7
Equity Earnings (Loss) of Unconsolidated Subsidiaries	(2.4		)
Net Loss Attributable to Noncontrolling Interests	4.8
Six Months Ended June 30, 2019	$	49.5

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:

• Generation decreased $45 million primarily due to the reduction of energy margins in 2019, a reduction in revenues due to the retirement of the Stuart Plant in 2018 and outages at the Conesville Plant.

• Retail, Trading and Marketing increased $15 million primarily due to higher retail margins due to lower market costs and higher delivered volumes and reduced MTM hedge losses.

• Other Revenues increased $7 million primarily due to the Sempra Renewables LLC acquisition and other renewable projects placed in service.

Expenses and Other, Income Tax Expense (Benefit) and Net Loss Attributable to Noncontrolling Interests changed between years as follows:

• Other Operation and Maintenance expenses decreased $10 million primarily due to the closure of the Stuart Plant in 2018 and lower operating costs at the Conesville Plant partially offset by expenses related to the Sempra Renewables LLC acquisition costs and increased investments in wind farms and renewable energy sources.

• Depreciation and Amortization expenses increased $14 million due to a higher depreciable base from increased investments in wind farms and renewable energy sources.

• Interest Expense increased $3 million primarily due to increased borrowing costs related to the Sempra Renewables LLC acquisition.

• Income Tax Expense (Benefit) decreased $23 million primarily due to an increase in projected renewable income tax credits primarily driven by the Sempra Renewables LLC acquisition and a decrease in pretax book income.

• Net Loss Attributable to Noncontrolling Interests increased $5 million primarily due to the Sempra Renewables LLC acquisition.

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CORPORATE AND OTHER

Second Quarter of 2019 Compared to Second Quarter of 2018

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $2 million in 2018 to a loss of $12 million in 2019 primarily due to:

• An $18 million increase in interest expense as a result of increased debt outstanding.

This item was partially offset by:

• A $5 million decrease in general corporate expenses.

• A $2 million increase in interest income due to higher return on investments held by EIS.

• A $2 million decrease in income tax expense primarily due to the following:

• A $27 million decrease in income tax expense due to an increase in consolidating tax adjustments and discrete items recorded in the period.

These items were partially offset by:

• An $18 million increase related to the enactment of the Kentucky state tax legislation, which reduced income tax expense by $18 million in the second quarter of 2018.

• A $5 million increase due to the current year revaluation of AEP’s state deferred tax liability as a result of the state income tax filing requirement in Kansas associated with the Sempra Renewables LLC acquisition.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $26 million in 2018 to a loss of $62 million in 2019 primarily due to:

• A $36 million increase in interest expense as a result of increased debt outstanding.

• A $28 million increase in income tax expense primarily due to the following:

• An $18 million increase related to the enactment of the Kentucky state tax legislation in the second quarter of 2018.

• A $5 million increase due to the current year revaluation of AEP’s state deferred tax liability as a result of the state income tax filing requirement in Kansas associated with the Sempra Renewables LLC acquisition.

• A $5 million impairment of an equity investment and related assets in 2019.

These items were partially offset by:

• A $20 million impairment of an equity investment and related assets in 2018.

• A $9 million increase in interest income due to a higher return on investments held by EIS.

AEP SYSTEM INCOME TAXES

Second Quarter of 2019 Compared to Second Quarter of 2018

Income Tax Expense decreased $127 million primarily due to additional amortization of excess ADIT as a result of finalized rate orders and an increase in projected renewable income tax credits.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

Income Tax Expense decreased $184 million primarily due to additional amortization of excess ADIT as a result of finalized rate orders and an increase in projected renewable income tax credits.

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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, 2019				December 31, 2018
	(dollars in millions)
Long-term Debt, including amounts due within one year	$	25,431.8	54.0	%	$	23,346.7	52.7	%
Short-term Debt	2,277.0		4.8		1,910.0		4.3
Total Debt	27,708.8		58.8		25,256.7		57.0
AEP Common Equity	19,259.6		40.9		19,028.4		42.9
Noncontrolling Interests	163.6		0.3		31.0		0.1
Total Debt and Equity Capitalization	$	47,132.0	100.0	%	$	44,316.1	100.0	%

AEP’s ratio of debt-to-total capital increased from 57% as of December 31, 2018 to 58.8% as of June 30, 2019 primarily due to an increase in debt to support distribution, transmission and renewable investment growth.

Liquidity

Liquidity, or access to cash, is an important factor in determining AEP’s financial stability.  Management believes AEP has adequate liquidity under its existing credit facilities.  As of June 30, 2019, AEP had a $4 billion revolving credit facility to support its commercial paper program.  Additional liquidity is available from cash from operations and a receivables securitization agreement.  Management is committed to maintaining adequate liquidity.  AEP generally uses short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged.  Sources of long-term funding include issuance of long-term debt, leasing agreements, hybrid securities or common stock.

Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments.  As of June 30, 2019, available liquidity was approximately $2.6 billion as illustrated in the table below:

		Amount		Maturity
Commercial Paper Backup:		(in millions)
	Revolving Credit Facility	$	4,000.0	June 2022
Cash and Cash Equivalents		210.5
Total Liquidity Sources		4,210.5
Less:	AEP Commercial Paper Outstanding	1,585.0
Net Available Liquidity		$	2,625.5

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 2019 was $1.9 billion.  The weighted-average interest rate for AEP’s commercial paper during 2019 was 2.76%.

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, 2019 was $181 million with maturities ranging from July 2019 to June 2020.

32

Securitized Accounts Receivables

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

Debt Covenants and Borrowing Limitations

AEP’s credit agreements contain certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5%.  The method for calculating outstanding debt and capitalization is contractually-defined in AEP’s credit agreements.  Debt as defined in the revolving credit agreement excludes securitization bonds and debt of AEP Credit. As of June 30, 2019, this contractually-defined percentage was 55.4%.  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 recent acquisition of Sempra Renewables LLC. See Note 13 - Financing Activities for additional information.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.67 per share in July 2019. Future dividends may vary depending upon AEP’s profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. Management does not believe these restrictions will have any significant impact on its ability to access cash to meet the payment of dividends on its common stock. See “Dividend Restrictions” section of Note 13 for additional information.

Credit Ratings

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

33

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,
	2019			2018
	(in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	$	444.1		$	412.6
Net Cash Flows from Operating Activities	1,800.8			2,006.8
Net Cash Flows Used for Investing Activities	(3,595.0		)	(3,238.9		)
Net Cash Flows from Financing Activities	1,739.7			1,206.8
Net Decrease in Cash, Cash Equivalents and Restricted Cash	(54.5		)	(25.3		)
Cash, Cash Equivalents and Restricted Cash at End of Period	$	389.6		$	387.3

Operating Activities

	Six Months Ended  June 30,
	2019			2018
	(in millions)
Net Income	$	1,033.2		$	986.8
Non-Cash Adjustments to Net Income (a)	1,159.7			1,232.5
Mark-to-Market of Risk Management Contracts	(72.9		)	(112.9		)
Property Taxes	137.6			119.9
Deferred Fuel Over/Under-Recovery, Net	36.7			12.3
Recovery of Ohio Capacity Costs	29.0			35.8
Refund of Global Settlement	(8.2		)	(5.5		)
Change in Other Noncurrent Assets	(73.5		)	10.4
Change in Other Noncurrent Liabilities	(53.6		)	185.1
Change in Certain Components of Working Capital	(387.2		)	(457.6		)
Net Cash Flows from Operating Activities	$	1,800.8		$	2,006.8

(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 $206 million primarily due to the following:

• A $239 million decrease in cash from Change in Other Noncurrent Liabilities primarily due to decreased Accumulated Provisions for Rate Refunds as a result of Tax Reform in 2018.

• An $84 million decrease in cash from Change in Other Noncurrent Assets primarily due to a change in regulatory assets as a result of AEP subsidiaries with rider recovery mechanisms.

These decreases in cash were partially offset by:

• A $70 million increase in cash from Change in Certain Components of Working Capital. The increase is primarily due to changes in timing of receivables, partially offset by higher employee-related payments, increased usage of fuel and material and supplies.

34

Investing Activities

	Six Months Ended  June 30,
	2019			2018
	(in millions)
Construction Expenditures	$	(2,986.7	)	$	(3,223.4	)
Acquisitions of Nuclear Fuel	(33.8		)	(24.2		)
Acquisition of Sempra Renewables LLC, net of cash acquired	(581.2		)	—
Other	6.7			8.7
Net Cash Flows Used for Investing Activities	$	(3,595.0	)	$	(3,238.9	)

Net Cash Flows Used for Investing Activities increased by $356 million primarily due to the following:

• A $581 million increase due to the acquisition of Sempra Renewables LLC. The $581 million represents a cash payment of $583 million, net of cash acquired of $2 million. See Note 6 - Acquisitions and Impairments for additional information.

This increase was partially offset by:

• A $237 million decrease due to decreased construction expenditures, primarily driven by decreases at Transmission and Distribution Utilities of $129 million and AEP Transmission Holdco of $114 million.

Financing Activities

	Six Months Ended  June 30,
	2019			2018
	(in millions)
Issuance of Common Stock	$	32.3		$	50.9
Issuance/Retirement of Debt, Net	2,412.4			1,820.0
Dividends Paid on Common Stock	(668.1		)	(614.2		)
Other	(36.9		)	(49.9		)
Net Cash Flows from Financing Activities	$	1,739.7		$	1,206.8

Net Cash Flows from Financing Activities increased by $533 million primarily due to the following:

• A $612 million increase in cash due to decreased retirements of long-term debt. See Note 13 - Financing Activities for additional information.

• A $565 million increase in cash due to increased issuances of long-term debt. See Note 13 - Financing Activities for additional information.

These increases in cash were partially offset by:

• A $584 million decrease in cash from short-term debt primarily due to decreased borrowings of commercial paper. See Note 13 - Financing Activities for additional information.     

See “Long-term Debt Subsequent Events” section of Note 13 for Long-term debt and other securities issued, retired and principal payments made after June 30, 2019 through July 25, 2019, the date that the second quarter 10-Q was issued.

BUDGETED CAPITAL EXPENDITURES

Management forecasts approximately $32.9 billion of capital expenditures for 2019 to 2023.  Capital expenditures related to North Central Wind Energy Facilities are excluded from these budgeted amounts. The expenditures are generally for transmission, generation, distribution, regulated and contracted renewables, and required environmental investment to comply with the Federal EPA rules.  Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital.  Management expects to fund these capital expenditures through cash flows from operations and financing activities.  Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged. For complete information of forecasted capital expenditures, see the “Budgeted Capital Expenditures” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2018 Annual Report.

35

CONTRACTUAL OBLIGATION INFORMATION

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING PRONOUNCEMENTS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

See the “Critical Accounting Policies and Estimates” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2018 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.

ACCOUNTING PRONOUNCEMENTS

See Note 2 - New Accounting Pronouncements for information related to accounting pronouncements adopted in 2019 and pronouncements effective in the future.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

The Vertically Integrated Utilities segment is exposed to certain market risks as a major power producer and through transactions in power, coal, natural gas and marketing contracts. These risks include commodity price risks which may be subject to capacity risk, credit risk as well as interest rate risk. In addition, this segment may be exposed to foreign currency exchange risk from occasionally procuring various services and materials used in its energy business from foreign suppliers. These risks represent the risk of loss that may impact this segment due to changes in the underlying market prices or rates.

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

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

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

36

The following table summarizes the reasons for changes in total MTM value as compared to December 31, 2018:

MTM Risk Management Contract Net Assets (Liabilities)
Six Months Ended June 30, 2019
	Vertically Integrated Utilities			Transmission and Distribution Utilities			Generation & Marketing			Total
	(in millions)
Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2018	$	90.9		$	(101.0	)	$	164.5		$	154.4
Gain from Contracts Realized/Settled During the Period and Entered in a Prior Period	(100.5		)	(3.8		)	(14.0		)	(118.3		)
Fair Value of New Contracts at Inception When Entered During the Period (a)	—			—			11.3			11.3
Changes in Fair Value Allocated to Regulated Jurisdictions (b)	145.2			(7.1		)	—			138.1
Total MTM Risk Management Contract Net Assets (Liabilities) as of June 30, 2019	$	135.6		$	(111.9	)	$	161.8		185.5
Commodity Cash Flow Hedge Contracts										(152.2		)
Fair Value Hedge Contracts										11.9
Collateral Deposits										28.0
Total MTM Derivative Contract Net Assets as of June 30, 2019										$	73.2

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

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

Credit Risk

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

AEP has risk management contracts with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, exposures change daily. As of June 30, 2019, credit exposure net of collateral to sub investment grade counterparties was approximately 5.8%, 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).

37

As of June 30, 2019, the following table approximates AEP’s counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:

Counterparty Credit Quality	Exposure Before Credit Collateral		Credit Collateral		Net Exposure		Number of Counterparties >10% of Net Exposure	Net Exposure of Counterparties >10%
	(in millions, except number of counterparties)
Investment Grade	$	624.8	$	1.3	$	623.5	2	$	228.4
Noninvestment Grade	0.4		—		0.4		1	0.4
No External Ratings:
Internal Investment Grade	143.1		—		143.1		3	90.2
Internal Noninvestment Grade	57.2		10.0		47.2		2	30.1
Total as of June 30, 2019	$	825.5	$	11.3	$	814.2

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, 2019, a near term typical change in commodity prices is not expected to materially impact net income, cash flows or financial condition.

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

VaR Model

Trading Portfolio

Six Months Ended								Twelve Months Ended
June 30, 2019								December 31, 2018
End		High		Average		Low		End		High		Average		Low
(in millions)								(in millions)
$	0.2	$	1.2	$	0.2	$	0.1	$	1.1	$	1.8	$	0.3	$	0.1

VaR Model

Non-Trading Portfolio

Six Months Ended								Twelve Months Ended
June 30, 2019								December 31, 2018
End		High		Average		Low		End		High		Average		Low
(in millions)								(in millions)
$	0.8	$	6.6	$	1.1	$	0.2	$	4.0	$	16.5	$	2.7	$	0.4

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

38

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, 2019 and 2018, a 100 basis point change in the benchmark rate on AEP’s variable rate debt would impact pretax interest expense annually by $24 million and $25 million, respectively.

39

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2019 and 2018

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

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
REVENUES
Vertically Integrated Utilities	$	2,116.4		$	2,340.7		$	4,488.7		$	4,722.2
Transmission and Distribution Utilities	1,001.6			1,127.9			2,181.4			2,269.1
Generation & Marketing	382.9			435.3			822.6			912.8
Other Revenues	72.7			109.3			137.7			157.4
TOTAL REVENUES	3,573.6			4,013.2			7,630.4			8,061.5
EXPENSES
Fuel and Other Consumables Used for Electric Generation	480.9			566.9			1,031.3			1,068.7
Purchased Electricity for Resale	660.7			776.7			1,522.5			1,767.0
Other Operation	607.4			780.3			1,273.4			1,506.7
Maintenance	348.7			295.9			623.2			594.4
Depreciation and Amortization	622.6			553.2			1,228.4			1,092.9
Taxes Other Than Income Taxes	302.3			283.2			612.2			568.8
TOTAL EXPENSES	3,022.6			3,256.2			6,291.0			6,598.5
OPERATING INCOME	551.0			757.0			1,339.4			1,463.0
Other Income (Expense):
Other Income	6.6			6.7			15.2			12.2
Allowance for Equity Funds Used During Construction	50.4			30.8			79.3			61.5
Non-Service Cost Components of Net Periodic Benefit Cost	30.0			31.4			60.0			63.4
Interest Expense	(250.7		)	(242.3		)	(506.5		)	(476.3		)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS	387.3			583.6			987.4			1,123.8
Income Tax Expense (Benefit)	(54.4		)	72.2			(9.9		)	174.2
Equity Earnings of Unconsolidated Subsidiaries	17.4			18.7			35.9			37.2
NET INCOME	459.1			530.1			1,033.2			986.8
Net Income (Loss) Attributable to Noncontrolling Interests	(2.2		)	1.7			(0.9		)	4.0
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	461.3		$	528.4		$	1,034.1		$	982.8
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING	493,584,347			492,688,342			493,447,477			492,479,035
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	0.93		$	1.07		$	2.10		$	2.00
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING	495,382,966			493,505,085			494,934,320			493,317,355
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	0.93		$	1.07		$	2.09		$	1.99

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
Net Income	$	459.1		$	530.1		$	1,033.2		$	986.8
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $(20.9) and $0.5 for the Three Months Ended June 30, 2019 and 2018, Respectively, and $(28.6) and $1.2 for the Six Months Ended June 30, 2019 and 2018, Respectively	(78.6		)	1.8			(107.5		)	4.5
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.3) and $(0.3) for the Three Months Ended June 30, 2019 and 2018, Respectively, and $(0.7) and $(0.7) for the Six Months Ended June 30, 2019 and 2018, Respectively	(1.4		)	(1.2		)	(2.8		)	(2.6		)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(80.0		)	0.6			(110.3		)	1.9
TOTAL COMPREHENSIVE INCOME	379.1			530.7			922.9			988.7
Total Comprehensive Income (Loss) Attributable to Noncontrolling Interests	(2.2		)	1.7			(0.9		)	4.0
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	381.3		$	529.0		$	923.8		$	984.7

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Six Months Ended June 30, 2019 and 2018

(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, 2017	512.2	$	3,329.4	$	6,398.7			$	8,626.7			$	(67.8	)	$	26.6		$	18,313.6
Issuance of Common Stock	0.5	3.3		28.9														32.2
Common Stock Dividends								(305.5		)	(b)				(0.6		)	(306.1		)
Other Changes in Equity				16.9														16.9
ASU 2018-02 Adoption								14.0				(17.0		)				(3.0		)
ASU 2016-01 Adoption								11.9				(11.9		)				—
Net Income								454.4							2.3			456.7
Other Comprehensive Income												1.3						1.3
TOTAL EQUITY – MARCH 31, 2018	512.7	3,332.7		6,444.5				8,801.5				(95.4		)	28.3			18,511.6
Issuance of Common Stock	0.4	2.7		16.0														18.7
Common Stock Dividends								(306.8		)	(b)				(1.3		)	(308.1		)
Other Changes in Equity				(1.9		)									0.4			(1.5		)
Net Income								528.4							1.7			530.1
Other Comprehensive Income												0.6						0.6
TOTAL EQUITY – JUNE 30, 2018	513.1	$	3,335.4	$	6,458.6			$	9,023.1			$	(94.8	)	$	29.1		$	18,751.4
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		)	(c)				(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		)	(c)				(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								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

(a) Includes $(62) million related to a forward equity purchase contract associated with the issuance of Equity Units. See “Equity Units” section of Note 13 for additional information.

(b) Common Stock dividends declared per AEP common share were $0.62.

(c) Common Stock dividends declared per AEP common share were $0.67.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2019 and December 31, 2018

(in millions)

(Unaudited)

	June 30,			December 31,
	2019			2018
CURRENT ASSETS
Cash and Cash Equivalents	$	210.5		$	234.1
Restricted Cash (June 30, 2019 and December 31, 2018 Amounts Include $179.1 and $210, Respectively, Related to Transition Funding, Ohio Phase-in-Recovery Funding and Appalachian Consumer Rate Relief Funding)	179.1			210.0
Other Temporary Investments (June 30, 2019 and December 31, 2018 Amounts Include $168.9 and $152.7, Respectively, Related to EIS and Transource Energy)	175.7			159.1
Accounts Receivable:
Customers	688.9			699.0
Accrued Unbilled Revenues	164.1			209.3
Pledged Accounts Receivable – AEP Credit	940.3			999.8
Miscellaneous	32.3			55.2
Allowance for Uncollectible Accounts	(44.4		)	(36.8		)
Total Accounts Receivable	1,781.2			1,926.5
Fuel	441.7			341.5
Materials and Supplies	592.7			579.6
Risk Management Assets	249.6			162.8
Regulatory Asset for Under-Recovered Fuel Costs	109.9			150.1
Margin Deposits	87.0			141.4
Prepayments and Other Current Assets	233.9			208.8
TOTAL CURRENT ASSETS	4,061.3			4,113.9
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	22,098.3			21,699.9
Transmission	22,455.3			21,531.0
Distribution	21,691.7			21,195.4
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	4,452.2			4,265.0
Construction Work in Progress	4,944.5			4,393.9
Total Property, Plant and Equipment	75,642.0			73,085.2
Accumulated Depreciation and Amortization	18,439.1			17,986.1
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	57,202.9			55,099.1
OTHER NONCURRENT ASSETS
Regulatory Assets	3,350.1			3,310.4
Securitized Assets	785.3			920.6
Spent Nuclear Fuel and Decommissioning Trusts	2,776.4			2,474.9
Goodwill	52.5			52.5
Long-term Risk Management Assets	313.5			254.0
Operating Lease Assets	1,016.5			—
Deferred Charges and Other Noncurrent Assets	2,991.5			2,577.4
TOTAL OTHER NONCURRENT ASSETS	11,285.8			9,589.8
TOTAL ASSETS	$	72,550.0		$	68,802.8

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

June 30, 2019 and December 31, 2018

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

(Unaudited)

			June 30,			December 31,
			2019			2018
CURRENT LIABILITIES
Accounts Payable			$	1,689.0		$	1,874.3
Short-term Debt:
Securitized Debt for Receivables – AEP Credit			692.0			750.0
Other Short-term Debt			1,585.0			1,160.0
Total Short-term Debt			2,277.0			1,910.0
Long-term Debt Due Within One Year (June 30, 2019 and December 31, 2018 Amounts Include $554.4 and $406.5, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, Transource Energy and Sabine)			1,257.4			1,698.5
Risk Management Liabilities			141.4			55.0
Customer Deposits			382.1			412.2
Accrued Taxes			1,046.2			1,218.0
Accrued Interest			241.2			231.7
Obligations Under Operating Leases			229.2			—
Regulatory Liability for Over-Recovered Fuel Costs			55.1			58.6
Other Current Liabilities			1,038.5			1,190.5
TOTAL CURRENT LIABILITIES			8,357.1			8,648.8
NONCURRENT LIABILITIES
Long-term Debt (June 30, 2019 and December 31, 2018 Amounts Include $819.9 and $1,109.2, Respectively, Related to Transition Funding, DCC Fuel, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, Transource Energy, and Sabine)			24,174.4			21,648.2
Long-term Risk Management Liabilities			348.5			263.4
Deferred Income Taxes			7,294.0			7,086.5
Regulatory Liabilities and Deferred Investment Tax Credits			8,556.6			8,540.3
Asset Retirement Obligations			2,331.3			2,287.7
Employee Benefits and Pension Obligations			378.8			377.1
Obligations Under Operating Leases			797.2			—
Deferred Credits and Other Noncurrent Liabilities			763.1			782.6
TOTAL NONCURRENT LIABILITIES			44,643.9			40,985.8
TOTAL LIABILITIES			53,001.0			49,634.6
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
MEZZANINE EQUITY
Redeemable Noncontrolling Interest			67.6			69.4
Contingently Redeemable Performance Share Awards			58.2			39.4
TOTAL MEZZANINE EQUITY			125.8			108.8
EQUITY
Common Stock – Par Value – $6.50 Per Share:
	2019	2018
Shares Authorized	600,000,000	600,000,000
Shares Issued	513,962,056	513,450,036
(20,204,160 Shares were Held in Treasury as of June 30, 2019 and December 31, 2018, Respectively)			3,340.8			3,337.4
Paid-in Capital			6,455.3			6,486.1
Retained Earnings			9,694.2			9,325.3
Accumulated Other Comprehensive Income (Loss)			(230.7		)	(120.4		)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY			19,259.6			19,028.4
Noncontrolling Interests			163.6			31.0
TOTAL EQUITY			19,423.2			19,059.4
TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY			$	72,550.0		$	68,802.8

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Six Months Ended June 30,
	2019			2018
OPERATING ACTIVITIES
Net Income	$	1,033.2		$	986.8
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	1,228.4			1,092.9
Deferred Income Taxes	(35.5		)	149.7
Allowance for Equity Funds Used During Construction	(79.3		)	(61.5		)
Mark-to-Market of Risk Management Contracts	(72.9		)	(112.9		)
Amortization of Nuclear Fuel	46.1			51.4
Property Taxes	137.6			119.9
Deferred Fuel Over/Under-Recovery, Net	36.7			12.3
Recovery of Ohio Capacity Costs	29.0			35.8
Refund of Global Settlement	(8.2		)	(5.5		)
Change in Other Noncurrent Assets	(73.5		)	10.4
Change in Other Noncurrent Liabilities	(53.6		)	185.1
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	165.5			(209.9		)
Fuel, Materials and Supplies	(114.6		)	31.2
Accounts Payable	(72.4		)	(53.6		)
Accrued Taxes, Net	(170.1		)	(127.8		)
Other Current Assets	27.4			14.8
Other Current Liabilities	(223.0		)	(112.3		)
Net Cash Flows from Operating Activities	1,800.8			2,006.8
INVESTING ACTIVITIES
Construction Expenditures	(2,986.7		)	(3,223.4		)
Purchases of Investment Securities	(235.5		)	(1,069.2		)
Sales of Investment Securities	199.5			1,037.8
Acquisitions of Nuclear Fuel	(33.8		)	(24.2		)
Acquisition of Sempra Renewables LLC, net of cash acquired	(581.2		)	—
Other Investing Activities	42.7			40.1
Net Cash Flows Used for Investing Activities	(3,595.0		)	(3,238.9		)
FINANCING ACTIVITIES
Issuance of Common Stock	32.3			50.9
Issuance of Long-term Debt	2,773.7			2,209.2
Commercial Paper and Credit Facility Borrowings	—			205.6
Change in Short-term Debt, Net	367.0			952.0
Retirement of Long-term Debt	(728.3		)	(1,339.8		)
Make Whole Premium on Extinguishment of Long-term Debt	(3.0		)	—
Commercial Paper and Credit Facility Repayments	—			(207.0		)
Principal Payments for Finance Lease Obligations	(29.6		)	(33.5		)
Dividends Paid on Common Stock	(668.1		)	(614.2		)
Other Financing Activities	(4.3		)	(16.4		)
Net Cash Flows from Financing Activities	1,739.7			1,206.8
Net Decrease in Cash, Cash Equivalents and Restricted Cash	(54.5		)	(25.3		)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	444.1			412.6
Cash, Cash Equivalents and Restricted Cash at End of Period	$	389.6		$	387.3
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	490.2		$	455.4
Net Cash Paid for Income Taxes	19.7			33.8
Noncash Acquisitions Under Finance Leases	44.4			32.8
Construction Expenditures Included in Current Liabilities as of June 30,	904.8			940.0
Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30,	50.5			0.6
Noncash Contribution of Assets by Noncontrolling Interest	—			84.0
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage	—			0.7
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 123.

45

AEP TEXAS INC.

AND SUBSIDIARIES

46

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,
	2019	2018	2019	2018
	(in millions of KWhs)
Retail:
Residential	3,008	3,122	5,432	5,786
Commercial	2,754	2,776	4,845	4,929
Industrial	2,240	2,388	4,388	4,489
Miscellaneous	170	168	315	308
Total Retail (a)	8,172	8,454	14,980	15,512

(a) 2018 KWhs have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail KWhs. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.

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

Summary of Heating and Cooling Degree Days

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2019	2018	2019	2018
	(in degree days)
Actual – Heating (a)	3	4	180	234
Normal – Heating (b)	3	3	190	194
Actual – Cooling (c)	970	992	1,092	1,188
Normal – Cooling (b)	934	927	1,057	1,046

(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.

47

Second Quarter of 2019 Compared to Second Quarter of 2018

Reconciliation of Second Quarter of 2018 to Second Quarter of 2019
Net Income
(in millions)
Second Quarter of 2018	$	46.5
Changes in Gross Margin:
Retail Margins	(0.8		)
Off-system Sales	21.1
Transmission Revenues	26.4
Other Revenues	0.3
Total Change in Gross Margin	47.0
Changes in Expenses and Other:
Other Operation and Maintenance	(60.0		)
Depreciation and Amortization	(34.1		)
Taxes Other Than Income Taxes	(0.4		)
Other Income	(0.8		)
Non-Service Cost Components of Net Periodic Benefit Cost	(0.2		)
Interest Expense	17.1
Total Change in Expenses and Other	(78.4		)
Income Tax Expense (Benefit)	65.5
Second Quarter of 2019	$	80.6

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

• Retail Margins decreased $1 million primarily due to the following:

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

• A $4 million decrease in weather-related usage primarily due to a 2% decrease in cooling degree days.

These decreases were partially offset by:

• A $7 million increase in weather-normalized margins primarily in the residential and commercial classes. 

• Margins from Off-system Sales increased $21 million due to higher affiliated PPA revenues, which were offset by corresponding increases in Other Operation and Maintenance expenses and Depreciation and Amortization expenses below.

• Transmission Revenues increased $26 million primarily due to the recovery of increased transmission investment in ERCOT.

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

• Other Operation and Maintenance expenses increased $60 million primarily due to the partial amortization of the Texas Storm Cost Securitization regulatory asset as a result of the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019. This increase was offset by a corresponding decrease in Income Tax Expense (Benefit) below.

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

• A $16 million increase in depreciation expense due to a revision in the useful life of the Oklaunion Power Station. This increase was offset by an increase in Margins from Off-system Sales above.

• A $14 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.

48

• Interest Expense decreased $17 million primarily 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.

• Income Tax Expense (Benefit) decreased $66 million primarily due to the amortization of Excess ADIT not subject to normalization requirements as approved in the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019. This decrease was partially offset in Other Operation and Maintenance expenses above.

49

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

Reconciliation of Six Months Ended June 30, 2018 to Six Months Ended June 30, 2019
Net Income
(in millions)
Six Months Ended June 30, 2018	$	93.3
Changes in Gross Margin:
Retail Margins	(12.6		)
Off-system Sales	42.6
Transmission Revenues	38.4
Other Revenues	(2.8		)
Total Change in Gross Margin	65.6
Changes in Expenses and Other:
Other Operation and Maintenance	(56.6		)
Depreciation and Amortization	(63.0		)
Taxes Other Than Income Taxes	(4.5		)
Other Income	(4.6		)
Non-Service Cost Components of Net Periodic Benefit Cost	(0.5		)
Interest Expense	14.7
Total Change in Expenses and Other	(114.5		)
Income Tax Expense (Benefit)	70.6
Six Months Ended June 30, 2019	$	115.0

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

• Retail Margins decreased $13 million primarily due to the following:

• A $13 million decrease in weather-related usage primarily due to a 23% decrease in heating degree days and an 8% decrease in cooling degree days.

• An $8 million decrease in revenues associated with the Transmission Cost Recovery Factor revenue rider. This decrease was partially offset by a decrease in Other Operation and Maintenance expenses below.

These decreases were partially offset by:

• An $8 million increase in weather-normalized margins primarily in the residential and commercial classes.

• Margins from Off-system Sales increased $43 million due to higher affiliated PPA revenues, which were offset by corresponding increases in Other Operation and Maintenance expenses and Depreciation and Amortization expenses below.

• Transmission Revenues increased $38 million primarily due to recovery of increased transmission investment in ERCOT.

• Other Revenues decreased $3 million primarily due to securitization revenue related to Transition Funding. This decrease was offset below in Depreciation and Amortization expenses and in Interest Expense.

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

• Other Operation and Maintenance expenses increased $57 million primarily due to the following:

• A $64 million increase in expense due to the partial amortization of the Texas Storm Cost Securitization regulatory asset as a result of the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019. This increase was offset by a corresponding decrease in Income Tax Expense (Benefit) below.

• A $5 million increase due to employee-related expenses.

These increases were partially offset by:

• A $7 million decrease in distribution expenses.

• A $6 million decrease in ERCOT transmission expenses. This decrease was partially offset by a decrease in Retail Margins above.

50

• Depreciation and Amortization expenses increased $63 million primarily due to the following:

• A $32 million increase in depreciation expense due to a revision in the useful life of the Oklaunion Power Station. This increase was offset by an increase in Margins from Off-system Sales above.

• A $24 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.

• Taxes Other Than Income Taxes increased $5 million primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.

• Other Income decreased $5 million primarily due to a decrease in the equity component of AFUDC as a result of higher short-term debt balances, partially offset by increased transmission projects.

• Interest Expense decreased $15 million primarily 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.

• Income Tax Expense (Benefit) decreased $71 million primarily due to the amortization of Excess ADIT not subject to normalization requirements as approved in the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019. This decrease was partially offset in Other Operation and Maintenance expenses above.

51

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
REVENUES
Electric Transmission and Distribution	$	395.1		$	370.1		$	744.9		$	722.5
Sales to AEP Affiliates	42.2			17.6			82.4			35.8
Other Revenues	0.7			0.6			1.4			1.6
TOTAL REVENUES	438.0			388.3			828.7			759.9
EXPENSES
Fuel and Other Consumables Used for Electric Generation	8.5			5.8			17.9			14.7
Other Operation	111.2			118.0			221.0			235.0
Maintenance	89.9			23.1			115.2			44.6
Depreciation and Amortization	155.7			121.6			294.6			231.6
Taxes Other Than Income Taxes	34.0			33.6			70.5			66.0
TOTAL EXPENSES	399.3			302.1			719.2			591.9
OPERATING INCOME	38.7			86.2			109.5			168.0
Other Income (Expense):
Other Income	2.1			2.9			4.3			8.9
Non-Service Cost Components of Net Periodic Benefit Cost	2.8			3.0			5.6			6.1
Interest Expense	(19.5		)	(36.6		)	(56.9		)	(71.6		)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	24.1			55.5			62.5			111.4
Income Tax Expense (Benefit)	(56.5		)	9.0			(52.5		)	18.1
NET INCOME	$	80.6		$	46.5		$	115.0		$	93.3

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

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

52

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2019		2018		2019		2018
Net Income	$	80.6	$	46.5	$	115.0	$	93.3
OTHER COMPREHENSIVE INCOME, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2019 and 2018, Respectively, and $0.1 and $0.1 for the Six Months Ended June 30, 2019 and 2018, Respectively	0.2		0.3		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, 2019 and 2018, Respectively, and $0 and $0 for the Six Months Ended June 30, 2019 and 2018, Respectively	0.1		—		0.1		0.1
TOTAL OTHER COMPREHENSIVE INCOME	0.3		0.3		0.6		0.6
TOTAL COMPREHENSIVE INCOME	$	80.9	$	46.8	$	115.6	$	93.9

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

53

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017	$	1,057.9	$	1,124.6	$	(12.6	)	$	2,169.9
Capital Contribution from Parent	100.0							100.0
ASU 2018-02 Adoption			1.8		(2.7		)	(0.9		)
Net Income			46.8					46.8
Other Comprehensive Income					0.3			0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018	1,157.9		1,173.2		(15.0		)	2,316.1
Net Income			46.5					46.5
Other Comprehensive Income					0.3			0.3
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2018	$	1,157.9	$	1,219.7	$	(14.7	)	$	2,362.9
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

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

54

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2019 and December 31, 2018

(in millions)

(Unaudited)

	June 30,			December 31,
	2019			2018
CURRENT ASSETS
Cash and Cash Equivalents	$	0.1		$	3.1
Restricted Cash for Securitized Transition Funding	125.4			156.7
Advances to Affiliates	7.7			8.0
Accounts Receivable:
Customers	142.7			110.9
Affiliated Companies	20.4			15.0
Accrued Unbilled Revenues	81.4			70.4
Miscellaneous	0.2			1.9
Allowance for Uncollectible Accounts	(1.6		)	(1.3		)
Total Accounts Receivable	243.1			196.9
Fuel	6.4			8.8
Materials and Supplies	54.4			52.8
Accrued Tax Benefits	45.6			44.9
Prepayments and Other Current Assets	3.4			5.3
TOTAL CURRENT ASSETS	486.1			476.5
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	351.8			352.1
Transmission	3,946.9			3,683.6
Distribution	4,064.9			4,043.2
Other Property, Plant and Equipment	766.7			727.9
Construction Work in Progress	963.0			836.2
Total Property, Plant and Equipment	10,093.3			9,643.0
Accumulated Depreciation and Amortization	1,712.6			1,651.2
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	8,380.7			7,991.8
OTHER NONCURRENT ASSETS
Regulatory Assets	483.5			430.0
Securitized Transition Assets (June 30, 2019 and December 31, 2018 Amounts Include $528.9 and $636.8 Respectively, Related to Transition Funding)	536.9			649.1
Deferred Charges and Other Noncurrent Assets	181.5			56.3
TOTAL OTHER NONCURRENT ASSETS	1,201.9			1,135.4
TOTAL ASSETS	$	10,068.7		$	9,603.7

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

55

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

June 30, 2019 and December 31, 2018

(in millions)

(Unaudited)

	June 30,			December 31,
	2019			2018
CURRENT LIABILITIES
Advances from Affiliates	$	239.0		$	216.0
Accounts Payable:
General	238.4			276.5
Affiliated Companies	22.4			30.3
Long-term Debt Due Within One Year – Nonaffiliated (June 30, 2019 and December 31, 2018 Amounts Include $259.2 and $251.1, Respectively, Related to Transition Funding)	309.9			501.1
Risk Management Liabilities	0.2			0.2
Accrued Taxes	102.6			75.5
Accrued Interest (June 30, 2019 and December 31, 2018 Amounts Include $8.5 and $11.3 Respectively, Related to Transition Funding)	36.3			37.3
Oklaunion Purchase Power Agreement	27.2			24.3
Obligations Under Operating Leases	11.6			—
Other Current Liabilities	85.1			98.3
TOTAL CURRENT LIABILITIES	1,072.7			1,259.5
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated (June 30, 2019 and December 31, 2018 Amounts Include $400.8 and $540.1 Respectively, Related to Transition Funding)	3,684.7			3,380.2
Deferred Income Taxes	927.9			913.1
Regulatory Liabilities and Deferred Investment Tax Credits	1,299.6			1,344.3
Oklaunion Purchase Power Agreement	7.7			22.1
Obligations Under Operating Leases	69.9			—
Deferred Credits and Other Noncurrent Liabilities	110.1			104.0
TOTAL NONCURRENT LIABILITIES	6,099.9			5,763.7
TOTAL LIABILITIES	7,172.6			7,023.2
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY
Paid-in Capital	1,457.9			1,257.9
Retained Earnings	1,452.7			1,337.7
Accumulated Other Comprehensive Income (Loss)	(14.5		)	(15.1		)
TOTAL COMMON SHAREHOLDER’S EQUITY	2,896.1			2,580.5
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	10,068.7		$	9,603.7

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

56

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Six Months Ended June 30,
	2019			2018
OPERATING ACTIVITIES
Net Income	$	115.0		$	93.3
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	294.6			231.6
Deferred Income Taxes	(59.9		)	24.9
Allowance for Equity Funds Used During Construction	(3.2		)	(9.4		)
Property Taxes	(45.0		)	(38.4		)
Change in Other Noncurrent Assets	24.4			(36.1		)
Change in Other Noncurrent Liabilities	5.6			21.6
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(46.2		)	(67.1		)
Fuel, Materials and Supplies	0.8			0.5
Accounts Payable	1.8			(29.6		)
Accrued Taxes, Net	26.4			37.5
Other Current Assets	2.0			1.6
Other Current Liabilities	(21.8		)	(5.5		)
Net Cash Flows from Operating Activities	294.5			224.9
INVESTING ACTIVITIES
Construction Expenditures	(671.6		)	(792.8		)
Change in Advances to Affiliates, Net	0.3			84.8
Other Investing Activities	7.6			19.2
Net Cash Flows Used for Investing Activities	(663.7		)	(688.8		)
FINANCING ACTIVITIES
Capital Contribution from Parent	200.0			100.0
Issuance of Long-term Debt – Nonaffiliated	295.6			494.5
Change in Advances from Affiliates, Net	23.0			—
Retirement of Long-term Debt – Nonaffiliated	(181.8		)	(154.1		)
Principal Payments for Finance Lease Obligations	(2.5		)	(2.3		)
Other Financing Activities	0.6			0.6
Net Cash Flows from Financing Activities	334.9			438.7
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding	(34.3		)	(25.2		)
Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding at Beginning of Period	159.8			157.2
Cash, Cash Equivalents and Restricted Cash for Securitized Transition Funding at End of Period	$	125.5		$	132.0
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	73.4		$	69.3
Net Cash Paid (Received) for Income Taxes	14.4			(22.4		)
Noncash Acquisitions Under Finance Leases	4.4			6.3
Construction Expenditures Included in Current Liabilities as of June 30,	192.9			186.8

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

57

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

58

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,
	2019		2018
	(in millions)
Plant In Service	$	7,122.5	$	5,840.5
Construction Work in Progress	1,785.0		1,585.9
Accumulated Depreciation and Amortization	336.6		210.5
Total Transmission Property, Net	$	8,570.9	$	7,215.9

Second Quarter of 2019 Compared to Second Quarter of 2018

Reconciliation of Second Quarter of 2018 to Second Quarter of 2019
Net Income
(in millions)
Second Quarter of 2018	$	82.0
Changes in Transmission Revenues:
Transmission Revenues	66.8
Total Change in Transmission Revenues	66.8
Changes in Expenses and Other:
Other Operation and Maintenance	(0.5		)
Depreciation and Amortization	(10.5		)
Taxes Other Than Income Taxes	(5.3		)
Interest Income	0.2
Allowance for Equity Funds Used During Construction	13.0
Interest Expense	(0.8		)
Total Change in Expenses and Other	(3.9		)
Income Tax Expense	(8.9		)
Second Quarter of 2019	$	136.0

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

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

• Transmission Revenues increased $67 million primarily due to continued investment in transmission assets.

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

• Depreciation and Amortization expenses increased $11 million primarily due to a higher depreciable base.

• Taxes Other Than Income Taxes increased $5 million primarily due to higher property taxes as a result of increased transmission investment.

• Allowance for Equity Funds Used During Construction increased $13 million primarily due to the following:

• A $12 million increase due to the FERC’s approval of a settlement agreement.

• A $5 million increase due to increased transmission investment resulting in a higher CWIP balance.

These increases were partially offset by:

• A $4 million decrease due to recent FERC audit findings.

• Income Tax Expense increased $9 million primarily due to higher pretax book income with a partial offset due to the FERC’s approval of a settlement agreement.

59

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

Reconciliation of Six Months Ended June 30, 2018 to Six Months Ended June 30, 2019
Net Income
(in millions)
Six Months Ended June 30, 2018	$	166.1
Changes in Transmission Revenues:
Transmission Revenues	118.6
Total Change in Transmission Revenues	118.6
Changes in Expenses and Other:
Other Operation and Maintenance	(1.5		)
Depreciation and Amortization	(20.5		)
Taxes Other Than Income Taxes	(15.6		)
Interest Income	0.5
Allowance for Equity Funds Used During Construction	9.4
Interest Expense	(2.2		)
Total Change in Expenses and Other	(29.9		)
Income Tax Expense	(14.5		)
Six Months Ended June 30, 2019	$	240.3

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

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

• Transmission Revenues increased $119 million primarily due to continued investment in transmission assets.

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

• Depreciation and Amortization expenses increased $21 million primarily due to a higher depreciable base.

• Taxes Other Than Income Taxes increased $16 million primarily due to higher property taxes as a result of increased transmission investment.

• Allowance for Equity Funds Used During Construction increased $9 million primarily due to the following:

• A $12 million increase due to the FERC’s approval of a settlement agreement.

• A $10 million increase due to increased transmission investment resulting in a higher CWIP balance.

These increases were partially offset by:

• A $13 million decrease due to recent FERC audit findings.

• Income Tax Expense increased $15 million primarily due to higher pretax book income with a partial offset due to the FERC’s approval of a settlement agreement.

60

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
REVENUES
Transmission Revenues	$	57.8		$	55.4		$	108.1		$	86.3
Sales to AEP Affiliates	209.1			144.7			402.3			305.4
Other Revenues	—			—			—			0.1
TOTAL REVENUES	266.9			200.1			510.4			391.8
EXPENSES
Other Operation	18.7			18.5			35.7			35.1
Maintenance	2.5			2.2			5.7			4.8
Depreciation and Amortization	42.8			32.3			83.1			62.6
Taxes Other Than Income Taxes	41.9			36.6			83.3			67.7
TOTAL EXPENSES	105.9			89.6			207.8			170.2
OPERATING INCOME	161.0			110.5			302.6			221.6
Other Income (Expense):
Interest Income	0.6			0.4			1.3			0.8
Allowance for Equity Funds Used During Construction	28.8			15.8			40.1			30.7
Interest Expense	(21.4		)	(20.6		)	(43.1		)	(40.9		)
INCOME BEFORE INCOME TAX EXPENSE	169.0			106.1			300.9			212.2
Income Tax Expense	33.0			24.1			60.6			46.1
NET INCOME	$	136.0		$	82.0		$	240.3		$	166.1

The 2018 amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

61

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY

For the Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Paid-in Capital		Retained Earnings		Total
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2017	$	1,816.6	$	773.3	$	2,589.9
Capital Contributions from Member	65.0				65.0
Net Income			84.1		84.1
TOTAL MEMBER'S EQUITY – MARCH 31, 2018	1,881.6		857.4		2,739.0
Capital Contributions from Member	312.0				312.0
Net Income			82.0		82.0
TOTAL MEMBER'S EQUITY – JUNE 30, 2018	$	2,193.6	$	939.4	$	3,133.0
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2018	$	2,480.6	$	1,089.2	$	3,569.8
Net Income			104.3		104.3
TOTAL MEMBER'S EQUITY – MARCH 31, 2019	2,480.6		1,193.5		3,674.1
Net Income			136.0		136.0
TOTAL MEMBER'S EQUITY – JUNE 30, 2019	$	2,480.6	$	1,329.5	$	3,810.1

Net Income for the three months ended June 30, 2018 reflects the revisions made to AEPTCo’s previously issued financial statements.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

62

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2019 and December 31, 2018

(in millions)

(Unaudited)

	June 30,		December 31,
	2019		2018
CURRENT ASSETS
Advances to Affiliates	$	51.2	$	96.9
Accounts Receivable:
Customers	27.3		11.8
Affiliated Companies	84.2		61.0
Total Accounts Receivable	111.5		72.8
Materials and Supplies	17.2		19.0
Accrued Tax Benefits	11.3		33.4
Prepayments and Other Current Assets	3.3		3.4
TOTAL CURRENT ASSETS	194.5		225.5
TRANSMISSION PROPERTY
Transmission Property	6,900.3		6,515.8
Other Property, Plant and Equipment	222.2		174.0
Construction Work in Progress	1,785.0		1,578.3
Total Transmission Property	8,907.5		8,268.1
Accumulated Depreciation and Amortization	336.6		271.9
TOTAL TRANSMISSION PROPERTY – NET	8,570.9		7,996.2
OTHER NONCURRENT ASSETS
Accounts Receivable – Affiliated Companies	7.8		—
Regulatory Assets	9.8		12.9
Deferred Property Taxes	89.6		157.9
Deferred Charges and Other Noncurrent Assets	6.6		1.6
TOTAL OTHER NONCURRENT ASSETS	113.8		172.4
TOTAL ASSETS	$	8,879.2	$	8,394.1

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

63

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND MEMBER’S EQUITY

June 30, 2019 and December 31, 2018

(in millions)

(Unaudited)

	June 30,		December 31,
	2019		2018
CURRENT LIABILITIES
Advances from Affiliates	$	20.5	$	45.4
Accounts Payable:
General	270.4		347.2
Affiliated Companies	63.0		56.0
Long-term Debt Due Within One Year – Nonaffiliated	85.0		85.0
Accrued Taxes	223.7		288.9
Accrued Interest	16.3		15.9
Obligations Under Operating Leases	2.6		—
Other Current Liabilities	30.5		3.8
TOTAL CURRENT LIABILITIES	712.0		842.2
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	3,082.9		2,738.0
Deferred Income Taxes	730.5		704.4
Regulatory Liabilities	534.4		521.3
Obligations Under Operating Leases	2.8		—
Deferred Credits and Other Noncurrent Liabilities	6.5		18.4
TOTAL NONCURRENT LIABILITIES	4,357.1		3,982.1
TOTAL LIABILITIES	5,069.1		4,824.3
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
MEMBER’S EQUITY
Paid-in Capital	2,480.6		2,480.6
Retained Earnings	1,329.5		1,089.2
TOTAL MEMBER’S EQUITY	3,810.1		3,569.8
TOTAL LIABILITIES AND MEMBER’S EQUITY	$	8,879.2	$	8,394.1

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

64

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Six Months Ended June 30,
	2019			2018
OPERATING ACTIVITIES
Net Income	$	240.3		$	166.1
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	83.1			62.6
Deferred Income Taxes	19.7			49.9
Allowance for Equity Funds Used During Construction	(40.1		)	(30.7		)
Property Taxes	68.3			44.7
Long-term Accounts Receivable – Affiliated	(7.8		)	(6.2		)
Change in Other Noncurrent Assets	3.6			(6.7		)
Change in Other Noncurrent Liabilities	(6.4		)	17.8
Changes in Certain Components of Working Capital:
Accounts Receivable	(31.7		)	8.5
Materials and Supplies	1.8			(2.4		)
Accounts Payable	6.3			3.4
Accrued Taxes, Net	(43.1		)	(29.8		)
Accrued Interest	0.4			(3.3		)
Other Current Assets	—			0.4
Other Current Liabilities	(0.2		)	(28.2		)
Net Cash Flows from Operating Activities	294.2			246.1
INVESTING ACTIVITIES
Construction Expenditures	(661.5		)	(855.4		)
Change in Advances to Affiliates, Net	45.7			92.7
Acquisitions of Assets	(2.6		)	(13.1		)
Other Investing Activities	4.8			1.1
Net Cash Flows Used for Investing Activities	(613.6		)	(774.7		)
FINANCING ACTIVITIES
Capital Contributions from Member	—			377.0
Issuance of Long-term Debt – Nonaffiliated	344.3			—
Change in Advances from Affiliates, Net	(24.9		)	151.8
Other Financing Activities	—			(0.2		)
Net Cash Flows from Financing Activities	319.4			528.6
Net Change in Cash and Cash Equivalents	—			—
Cash and Cash Equivalents at Beginning of Period	—			—
Cash and Cash Equivalents at End of Period	$	—		$	—
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	41.0		$	43.1
Net Cash Paid (Received) for Income Taxes	17.4			(20.4		)
Construction Expenditures Included in Current Liabilities as of June 30,	278.5			241.1

The 2018 amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

65

APPALACHIAN POWER COMPANY

AND SUBSIDIARIES

66

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,
	2019	2018	2019	2018
	(in millions of KWhs)
Retail:
Residential	2,086	2,388	5,673	6,233
Commercial	1,495	1,576	3,091	3,265
Industrial	2,357	2,366	4,693	4,748
Miscellaneous	205	205	424	429
Total Retail (a)	6,143	6,535	13,881	14,675
Wholesale	913	614	1,729	1,109
Total KWhs	7,056	7,149	15,610	15,784

(a) 2018 KWhs have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail KWhs. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.

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

Summary of Heating and Cooling Degree Days

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2019	2018	2019	2018
	(in degree days)
Actual – Heating (a)	43	129	1,295	1,518
Normal – Heating (b)	92	91	1,404	1,408
Actual – Cooling (c)	459	537	459	545
Normal – Cooling (b)	372	363	379	370

(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.

67

Second Quarter of 2019 Compared to Second Quarter of 2018

Reconciliation of Second Quarter of 2018 to Second Quarter of 2019
Net Income
(in millions)
Second Quarter of 2018	$	77.4
Changes in Gross Margin:
Retail Margins	(19.9		)
Off-system Sales	0.3
Transmission Revenues	0.8
Other Revenues	1.7
Total Change in Gross Margin	(17.1		)
Changes in Expenses and Other:
Other Operation and Maintenance	(24.6		)
Depreciation and Amortization	(11.8		)
Taxes Other Than Income Taxes	(2.2		)
Interest Income	0.4
Carrying Costs Income	(0.5		)
Allowance for Equity Funds Used During Construction	3.1
Non-Service Cost Components of Net Periodic Benefit Cost	(0.2		)
Interest Expense	(3.8		)
Total Change in Expenses and Other	(39.6		)
Income Tax Expense (Benefit)	34.8
Second Quarter of 2019	$	55.5

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

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

• A $19 million decrease in weather-related usage primarily driven by a 15% decrease in cooling degree days and a 67% decrease in heating degree days.

• A $7 million decrease due to customer refunds related to Tax Reform. This decrease was partially offset in Income Tax Expense (Benefit) below.

• A $5 million decrease in weather-normalized margins occurring across all retail classes.

These decreases were partially offset by:

• A $5 million increase due to a base rate increase in West Virginia implemented in March 2019.

• A $4 million increase due to revenue from rate riders in West Virginia. This increase was offset in other expense items below.

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

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

• A $25 million increase in PJM expenses primarily related to the annual formula rate true-up.

• A $12 million increase due to contributions to benefit low income West Virginia residential customers as a result of the 2018 West Virginia Tax Reform settlement. This increase was offset in Income Tax Expense (Benefit) below.

These increases were partially offset by:

• A $10 million decrease in recoverable PJM transmission expenses which were partially offset within Gross Margins above.

• A $3 million decrease in expense due to the extinguishment of certain regulatory asset balances in August 2018 as agreed to within the 2018 West Virginia Tax Reform settlement.

• A $3 million decrease in storm-related expenses.

68

• Depreciation and Amortization expenses increased $12 million primarily due to a higher depreciable base and an increase in West Virginia depreciation rates beginning in March 2019.

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

• Income Tax Expense (Benefit) decreased $35 million primarily due to an increase in amortization of Excess ADIT not subject to normalization requirements and a decrease in pretax book income. This decrease was partially offset in Gross Margin above.

69

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

Reconciliation of Six Months Ended June 30, 2018 to Six Months Ended June 30, 2019
Net Income
(in millions)
Six Months Ended June 30, 2018	$	202.9
Changes in Gross Margin:
Retail Margins	(79.2		)
Off-system Sales	2.0
Transmission Revenues	13.1
Other Revenues	0.4
Total Change in Gross Margin	(63.7		)
Changes in Expenses and Other:
Other Operation and Maintenance	(12.8		)
Depreciation and Amortization	(15.8		)
Taxes Other Than Income Taxes	(4.3		)
Interest Income	0.9
Carrying Costs Income	(1.0		)
Allowance for Equity Funds Used During Construction	2.2
Non-Service Cost Components of Net Periodic Benefit Cost	(0.4		)
Interest Expense	(5.7		)
Total Change in Expenses and Other	(36.9		)
Income Tax Expense (Benefit)	86.9
Six Months Ended June 30, 2019	$	189.2

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

• Retail Margins decreased $79 million primarily due to the following:

• A $35 million decrease due to customer refunds related to Tax Reform. This decrease was partially offset in Income Tax Expense (Benefit) below.

• A $33 million decrease in weather-related usage primarily driven by a 16% decrease in cooling degree days and a 15% decrease in heating degree days.

• A $20 million decrease in weather-normalized margins occurring across all retail classes.

These decreases were partially offset by:

• A $6 million increase due to a base rate increase in West Virginia implemented in March 2019.

• A $6 million increase due to revenue from rate riders in West Virginia. This increase was offset in other expense items below.

• Transmission Revenue increased $13 million primarily due to 2018 provisions for refunds.

70

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

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

• A $33 million increase in PJM expenses primarily related to the annual formula rate true-up.

• A $13 million increase due to contributions to benefit low income West Virginia residential customers as a result of the 2018 West Virginia Tax Reform settlement. This increase was offset in Income Tax Expense (Benefit) below.

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

These increases were partially offset by:

• A $12 million decrease in recoverable PJM transmission expenses which were partially offset within Gross Margins above.

• A $6 million decrease in expense due to the extinguishment of certain regulatory asset balances in August 2018 as agreed to within the 2018 West Virginia Tax Reform settlement.

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

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

• A $4 million decrease in vegetation management expenses.

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

• Depreciation and Amortization expenses increased $16 million primarily due to a higher depreciable base and an increase in West Virginia depreciation rates beginning in March 2019.

• Taxes Other Than Income Taxes increased $4 million primarily due to an increase in West Virginia business and occupational taxes.

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

• Income Tax Expense (Benefit) decreased $87 million primarily due to an increase in amortization of Excess ADIT not subject to normalization requirements and a decrease in pretax book income. This decrease was partially offset in Gross Margin above.

71

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
REVENUES
Electric Generation, Transmission and Distribution	$	605.9		$	618.8		$	1,344.6		$	1,386.3
Sales to AEP Affiliates	46.3			46.4			98.0			95.8
Other Revenues	3.6			1.8			6.0			5.3
TOTAL REVENUES	655.8			667.0			1,448.6			1,487.4
EXPENSES
Fuel and Other Consumables Used for Electric Generation	161.2			155.3			344.5			224.3
Purchased Electricity for Resale	64.5			64.5			175.1			270.4
Other Operation	138.9			109.9			275.8			248.1
Maintenance	61.3			65.7			122.8			137.7
Depreciation and Amortization	117.1			105.3			229.6			213.8
Taxes Other Than Income Taxes	35.9			33.7			71.8			67.5
TOTAL EXPENSES	578.9			534.4			1,219.6			1,161.8
OPERATING INCOME	76.9			132.6			229.0			325.6
Other Income (Expense):
Interest Income	1.0			0.6			1.8			0.9
Carrying Costs Income	—			0.5			—			1.0
Allowance for Equity Funds Used During Construction	6.0			2.9			7.7			5.5
Non-Service Cost Components of Net Periodic Benefit Cost	4.2			4.4			8.5			8.9
Interest Expense	(51.6		)	(47.8		)	(100.9		)	(95.2		)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	36.5			93.2			146.1			246.7
Income Tax Expense (Benefit)	(19.0		)	15.8			(43.1		)	43.8
NET INCOME	$	55.5		$	77.4		$	189.2		$	202.9

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

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

72

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
Net Income	$	55.5		$	77.4		$	189.2		$	202.9
OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2019 and 2018, Respectively, and $(0.1) and $(0.1) for the Six Months Ended June 30, 2019 and 2018, Respectively	(0.2		)	(0.2		)	(0.4		)	(0.4		)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.2) for the Three Months Ended June 30, 2019 and 2018, Respectively, and $(0.3) and $(0.4) for the Six Months Ended June 30, 2019 and 2018, Respectively	(0.7		)	(0.8		)	(1.3		)	(1.6		)
TOTAL OTHER COMPREHENSIVE LOSS	(0.9		)	(1.0		)	(1.7		)	(2.0		)
TOTAL COMPREHENSIVE INCOME	$	54.6		$	76.4		$	187.5		$	200.9

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

73

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017	$	260.4	$	1,828.7	$	1,714.1		$	1.3		$	3,804.5
Common Stock Dividends					(40.0		)				(40.0		)
ASU 2018-02 Adoption					0.1			0.3			0.4
Net Income					125.5						125.5
Other Comprehensive Loss								(1.0		)	(1.0		)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018	260.4		1,828.7		1,799.7			0.6			3,889.4
Common Stock Dividends					(40.0		)				(40.0		)
Net Income					77.4						77.4
Other Comprehensive Loss								(1.0		)	(1.0		)
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2018	$	260.4	$	1,828.7	$	1,837.1		$	(0.4	)	$	3,925.8
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

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

74

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2019 and December 31, 2018

(in millions)

(Unaudited)

	June 30,			December 31,
	2019			2018
CURRENT ASSETS
Cash and Cash Equivalents	$	2.3		$	4.2
Restricted Cash for Securitized Funding	25.4			25.6
Advances to Affiliates	22.7			23.0
Accounts Receivable:
Customers	127.2			146.5
Affiliated Companies	54.9			73.4
Accrued Unbilled Revenues	43.8			63.5
Miscellaneous	1.2			2.3
Allowance for Uncollectible Accounts	(2.2		)	(2.3		)
Total Accounts Receivable	224.9			283.4
Fuel	110.9			61.3
Materials and Supplies	101.8			100.1
Risk Management Assets	74.7			57.2
Regulatory Asset for Under-Recovered Fuel Costs	58.1			99.6
Prepayments and Other Current Assets	29.6			44.3
TOTAL CURRENT ASSETS	650.4			698.7
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	6,547.5			6,509.6
Transmission	3,388.8			3,317.7
Distribution	4,078.8			3,989.4
Other Property, Plant and Equipment	517.0			485.8
Construction Work in Progress	556.1			490.2
Total Property, Plant and Equipment	15,088.2			14,792.7
Accumulated Depreciation and Amortization	4,230.8			4,124.4
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	10,857.4			10,668.3
OTHER NONCURRENT ASSETS
Regulatory Assets	470.1			475.8
Securitized Assets	246.6			258.7
Long-term Risk Management Assets	0.4			0.9
Operating Lease Assets	78.3			—
Deferred Charges and Other Noncurrent Assets	176.1			188.1
TOTAL OTHER NONCURRENT ASSETS	971.5			923.5
TOTAL ASSETS	$	12,479.3		$	12,290.5

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

75

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

June 30, 2019 and December 31, 2018

(Unaudited)

	June 30,			December 31,
	2019			2018
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	26.1		$	205.6
Accounts Payable:
General	290.7			263.8
Affiliated Companies	67.5			84.0
Long-term Debt Due Within One Year – Nonaffiliated	150.0			430.7
Risk Management Liabilities	4.6			0.4
Customer Deposits	87.2			88.4
Accrued Taxes	84.8			89.3
Accrued Interest	47.0			41.5
Obligations Under Operating Leases	14.9			—
Other Current Liabilities	108.7			150.3
TOTAL CURRENT LIABILITIES	881.5			1,354.0
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	4,224.8			3,631.9
Long-term Risk Management Liabilities	0.1			0.2
Deferred Income Taxes	1,633.4			1,625.8
Regulatory Liabilities and Deferred Investment Tax Credits	1,363.6			1,449.7
Asset Retirement Obligations	105.5			107.1
Employee Benefits and Pension Obligations	53.8			57.1
Obligations Under Operating Leases	63.8			—
Deferred Credits and Other Noncurrent Liabilities	59.2			58.6
TOTAL NONCURRENT LIABILITIES	7,504.2			6,930.4
TOTAL LIABILITIES	8,385.7			8,284.4
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 30,000,000 Shares
Outstanding – 13,499,500 Shares	260.4			260.4
Paid-in Capital	1,828.7			1,828.7
Retained Earnings	2,011.2			1,922.0
Accumulated Other Comprehensive Income (Loss)	(6.7		)	(5.0		)
TOTAL COMMON SHAREHOLDER’S EQUITY	4,093.6			4,006.1
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	12,479.3		$	12,290.5

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

76

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Six Months Ended June 30,
	2019			2018
OPERATING ACTIVITIES
Net Income	$	189.2		$	202.9
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	229.6			213.8
Deferred Income Taxes	(73.5		)	10.8
Allowance for Equity Funds Used During Construction	(7.7		)	(5.5		)
Mark-to-Market of Risk Management Contracts	(12.9		)	(36.1		)
Deferred Fuel Over/Under-Recovery, Net	41.4			(73.8		)
Change in Other Noncurrent Assets	(1.8		)	32.0
Change in Other Noncurrent Liabilities	(31.2		)	68.7
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	60.2			4.7
Fuel, Materials and Supplies	(50.2		)	20.2
Accounts Payable	23.0			(11.1		)
Accrued Taxes, Net	(7.8		)	(7.6		)
Other Current Assets	17.4			7.1
Other Current Liabilities	(29.8		)	(21.9		)
Net Cash Flows from Operating Activities	345.9			404.2
INVESTING ACTIVITIES
Construction Expenditures	(397.1		)	(406.8		)
Change in Advances to Affiliates, Net	0.3			0.1
Other Investing Activities	20.7			7.8
Net Cash Flows Used for Investing Activities	(376.1		)	(398.9		)
FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated	478.3			103.7
Change in Advances from Affiliates, Net	(179.5		)	(13.3		)
Retirement of Long-term Debt – Nonaffiliated	(168.0		)	(11.7		)
Principal Payments for Finance Lease Obligations	(3.1		)	(3.4		)
Dividends Paid on Common Stock	(100.0		)	(80.0		)
Other Financing Activities	0.4			0.7
Net Cash Flows from (Used for) Financing Activities	28.1			(4.0		)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash for Securitized Funding	(2.1		)	1.3
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period	29.8			19.2
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period	$	27.7		$	20.5
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	91.6		$	90.9
Net Cash Paid for Income Taxes	35.0			19.7
Noncash Acquisitions Under Finance Leases	5.7			2.7
Construction Expenditures Included in Current Liabilities as of June 30,	116.5			89.5

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

77

INDIANA MICHIGAN POWER COMPANY

AND SUBSIDIARIES

78

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,
	2019	2018	2019	2018
	(in millions of KWhs)
Retail:
Residential	1,048	1,245	2,663	2,868
Commercial	1,087	1,196	2,243	2,360
Industrial	1,917	1,986	3,805	3,902
Miscellaneous	14	15	33	35
Total Retail (a)	4,066	4,442	8,744	9,165
Wholesale	2,021	2,388	4,444	5,314
Total KWhs	6,087	6,830	13,188	14,479

(a) 2018 KWhs have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail KWhs. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.

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

Summary of Heating and Cooling Degree Days

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2019	2018	2019	2018
	(in degree days)
Actual – Heating (a)	217	364	2,456	2,521
Normal – Heating (b)	241	235	2,401	2,403
Actual – Cooling (c)	233	362	233	362
Normal – Cooling (b)	261	261	263	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.

79

Second Quarter of 2019 Compared to Second Quarter of 2018

Reconciliation of Second Quarter of 2018 to Second Quarter of 2019
Net Income
(in millions)
Second Quarter of 2018	$	94.7
Changes in Gross Margin:
Retail Margins	15.8
Off-system Sales	(2.1		)
Transmission Revenues	(9.3		)
Other Revenues	3.4
Total Change in Gross Margin	7.8
Changes in Expenses and Other:
Other Operation and Maintenance	(21.3		)
Depreciation and Amortization	(24.7		)
Taxes Other Than Income Taxes	(1.3		)
Other Income	1.2
Non-Service Cost Components of Net Periodic Benefit Cost	(0.1		)
Interest Expense	3.2
Total Change in Expenses and Other	(43.0		)
Income Tax Expense (Benefit)	0.8
Second Quarter of 2019	$	60.3

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

• Retail Margins increased $16 million primarily due to the following:

• A $28 million increase from rate proceedings, inclusive of a $24 million decrease due to the impact of Tax Reform. This increase was partially offset in other expense items below.

• A $13 million increase related to rider revenues, primarily due to the timing of the Indiana PJM/OSS rider recovery. This increase was partially offset in other expense items below.

These increases were partially offset by:

• An $18 million decrease in weather-related usage primarily due to a 36% decrease in cooling degree days and a 40% decrease in heating degree days.

• An $11 million decrease in weather-normalized margins across all retail classes.

• Transmission Revenues decreased $9 million primarily due to the 2018 PJM Transmission formula rate true-up.

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

• Other Operation and Maintenance expenses increased $21 million primarily due to the following:

• A $19 million increase in transmission expenses primarily due to a $25 million increase in recoverable PJM Expenses, partially offset by a $7 million decrease from the 2018 Regional Transmission Enhancement Plan settlement. This increase was partially offset in Retail Margins above.

• A $4 million increase in nonutility operation expenses primarily due to an increase in River Transportation Division expenses. This increase was offset by a corresponding increase in Gross Margin above.

These increases were partially offset by:

• A $3 million decrease in generation expenses at Cook Plant primarily due to decreased incremental refueling outage costs.

80

• Depreciation and Amortization expenses increased $25 million primarily due to increased depreciation rates approved in 2018 and higher depreciable base. This increase was partially offset in Retail Margins above.

• Interest Expense decreased $3 million primarily due to the reissuance of long-term debt at lower interest rates in 2018.

• Income Tax Expense (Benefit) decreased $1 million primarily due to decreased pretax book income offset by decreased amortization of Excess ADIT not subject to normalization requirements and increased state income taxes.

81

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

Reconciliation of Six Months Ended June 30, 2018 to Six Months Ended June 30, 2019
Net Income
(in millions)
Six Months Ended June 30, 2018	$	158.9
Changes in Gross Margin:
Retail Margins	72.2
Off-system Sales	(9.4		)
Transmission Revenues	(10.3		)
Other Revenues	0.3
Total Change in Gross Margin	52.8
Changes in Expenses and Other:
Other Operation and Maintenance	(19.5		)
Depreciation and Amortization	(51.6		)
Taxes Other Than Income Taxes	(3.6		)
Other Income	2.5
Non-Service Cost Components of Net Periodic Benefit Cost	(0.2		)
Interest Expense	4.0
Total Change in Expenses and Other	(68.4		)
Income Tax Expense (Benefit)	15.9
Six Months Ended June 30, 2019	$	159.2

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 $72 million primarily due to the following:

• A $75 million increase from rate proceedings, inclusive of a $33 million decrease due to the impact of Tax Reform. This increase was partially offset in other expense items below.

• A $10 million increase due to the timing of recovery of the Indiana PJM/OSS rider. This increase was partially offset in other expense items below.

• A $4 million decrease in fuel-related expenses due to timing of recovery for fuel and other variable production costs related to wholesale contracts.

These increases were partially offset by:

• A $15 million decrease in weather-related usage primarily due to a 36% decrease in cooling degree days.

• A $10 million decrease in weather-normalized margins across all retail classes.

• Margins from Off-system Sales decreased $9 million primarily due to mid-year 2018 changes in the OSS sharing mechanism.

• Transmission Revenues decreased $10 million primarily due to the 2018 PJM Transmission formula rate true-up.

82

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

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

• A $16 million increase in transmission expenses primarily due to a $31 million increase in recoverable PJM Expenses, partially offset by a $15 million decrease from the 2018 Regional Transmission Enhancement Plan settlement. This increase was partially offset in Retail Margins above.

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

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

• A $3 million increase in demand-side management expenses. This increase was offset within Retail Margins above.

• A $2 million increase in nonutility operation expenses primarily due to an increase in River Transportation Division expenses. The increase was offset by a corresponding increase in Gross Margin above.

These increases were partially offset by:

• A $7 million decrease in generation expenses at Cook Plant primarily due to decreased incremental refueling outage costs.

• A $3 million decrease in the amortization of discontinued riders in the Indiana jurisdiction.

• Depreciation and Amortization expenses increased $52 million primarily due to increased depreciation rates approved in 2018 and higher depreciable base. This increase was partially offset in Retail Margins above.

• Interest Expense decreased $4 million primarily due to the reissuance of long-term debt at lower interest rates in 2018.

• Income Tax Expense (Benefit) decreased $16 million primarily due to an increase in amortization of Excess ADIT not subject to normalization requirements. This decrease was partially offset in Gross Margin above.

83

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
REVENUES
Electric Generation, Transmission and Distribution	$	517.4		$	560.1		$	1,114.1		$	1,114.0
Sales to AEP Affiliates	2.3			10.8			4.6			15.5
Other Revenues – Affiliated	20.9			16.4			34.2			29.6
Other Revenues – Nonaffiliated	2.5			2.4			4.5			7.4
TOTAL REVENUES	543.1			589.7			1,157.4			1,166.5
EXPENSES
Fuel and Other Consumables Used for Electric Generation	42.4			73.4			100.0			150.9
Purchased Electricity for Resale	48.9			63.2			118.5			118.8
Purchased Electricity from AEP Affiliates	51.3			60.4			111.1			121.8
Other Operation	154.5			130.4			295.0			276.5
Maintenance	54.6			57.4			112.9			111.9
Depreciation and Amortization	87.3			62.6			173.5			121.9
Taxes Other Than Income Taxes	26.2			24.9			53.5			49.9
TOTAL EXPENSES	465.2			472.3			964.5			951.7
OPERATING INCOME	77.9			117.4			192.9			214.8
Other Income (Expense):
Other Income	6.1			4.9			11.8			9.3
Non-Service Cost Components of Net Periodic Benefit Cost	4.4			4.5			8.8			9.0
Interest Expense	(28.2		)	(31.4		)	(57.1		)	(61.1		)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	60.2			95.4			156.4			172.0
Income Tax Expense (Benefit)	(0.1		)	0.7			(2.8		)	13.1
NET INCOME	$	60.3		$	94.7		$	159.2		$	158.9

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

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

84

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2019			2018		2019			2018
Net Income	$	60.3		$	94.7	$	159.2		$	158.9
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, 2019 and 2018, Respectively, and $0.2 and $0.2 for the Six Months Ended June 30, 2019 and 2018, Respectively	0.4			0.5		0.8			0.9
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2019 and 2018, Respectively, and $0 and $0 for the Six Months Ended June 30, 2019 and 2018, Respectively	(0.1		)	—		(0.1		)	—
TOTAL OTHER COMPREHENSIVE INCOME	0.3			0.5		0.7			0.9
TOTAL COMPREHENSIVE INCOME	$	60.6		$	95.2	$	159.9		$	159.8

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

85

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017	$	56.6	$	980.9	$	1,192.2		$	(12.1	)	$	2,217.6
Common Stock Dividends					(33.5		)				(33.5		)
ASU 2018-02 Adoption					0.3			(2.7		)	(2.4		)
Net Income					64.2						64.2
Other Comprehensive Income								0.4			0.4
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018	56.6		980.9		1,223.2			(14.4		)	2,246.3
Common Stock Dividends					(33.5		)				(33.5		)
Net Income					94.7						94.7
Other Comprehensive Income								0.5			0.5
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2018	$	56.6	$	980.9	$	1,284.4		$	(13.9	)	$	2,308.0
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

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

86

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2019 and December 31, 2018

(in millions)

(Unaudited)

	June 30,			December 31,
	2019			2018
CURRENT ASSETS
Cash and Cash Equivalents	$	1.4		$	2.4
Advances to Affiliates	13.0			12.7
Accounts Receivable:
Customers	55.9			63.1
Affiliated Companies	47.3			75.0
Accrued Unbilled Revenues	3.0			3.6
Miscellaneous	1.1			1.4
Allowance for Uncollectible Accounts	(0.1		)	(0.1		)
Total Accounts Receivable	107.2			143.0
Fuel	39.3			37.3
Materials and Supplies	169.1			167.3
Risk Management Assets	15.7			8.6
Accrued Tax Benefits	41.6			26.6
Accrued Reimbursement of Spent Nuclear Fuel Costs	23.8			7.9
Prepayments and Other Current Assets	16.4			24.6
TOTAL CURRENT ASSETS	427.5			430.4
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	4,987.2			4,887.2
Transmission	1,601.9			1,576.8
Distribution	2,331.5			2,249.7
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	617.0			583.8
Construction Work in Progress	474.1			465.3
Total Property, Plant and Equipment	10,011.7			9,762.8
Accumulated Depreciation, Depletion and Amortization	3,227.6			3,151.6
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	6,784.1			6,611.2
OTHER NONCURRENT ASSETS
Regulatory Assets	492.3			512.5
Spent Nuclear Fuel and Decommissioning Trusts	2,776.4			2,474.9
Long-term Risk Management Assets	0.3			0.6
Operating Lease Assets	312.6			—
Deferred Charges and Other Noncurrent Assets	156.4			193.0
TOTAL OTHER NONCURRENT ASSETS	3,738.0			3,181.0
TOTAL ASSETS	$	10,949.6		$	10,222.6

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

87

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

June 30, 2019 and December 31, 2018

(dollars in millions)

(Unaudited)

	June 30,			December 31,
	2019			2018
CURRENT LIABILITIES
Advances from Affiliates	$	94.7		$	1.1
Accounts Payable:
General	176.6			174.7
Affiliated Companies	54.1			70.2
Long-term Debt Due Within One Year – Nonaffiliated (June 30, 2019 and December 31, 2018 Amounts Include $76.6 and $76.8, Respectively, Related to DCC Fuel)	155.1			155.4
Risk Management Liabilities	1.2			0.3
Customer Deposits	38.2			38.0
Accrued Taxes	89.8			90.7
Accrued Interest	36.7			37.3
Obligations Under Operating Leases	82.2			—
Regulatory Liability for Over-Receovered Fuel Costs	10.9			27.4
Other Current Liabilities	71.4			103.0
TOTAL CURRENT LIABILITIES	810.9			698.1
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	2,899.4			2,880.0
Long-term Risk Management Liabilities	—			0.1
Deferred Income Taxes	965.9			948.0
Regulatory Liabilities and Deferred Investment Tax Credits	1,788.0			1,574.5
Asset Retirement Obligations	1,714.6			1,681.3
Obligations Under Operating Leases	234.7			—
Deferred Credits and Other Noncurrent Liabilities	63.4			87.8
TOTAL NONCURRENT LIABILITIES	7,666.0			7,171.7
TOTAL LIABILITIES	8,476.9			7,869.8
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 2,500,000 Shares
Outstanding – 1,400,000 Shares	56.6			56.6
Paid-in Capital	980.9			980.9
Retained Earnings	1,448.3			1,329.1
Accumulated Other Comprehensive Income (Loss)	(13.1		)	(13.8		)
TOTAL COMMON SHAREHOLDER’S EQUITY	2,472.7			2,352.8
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	10,949.6		$	10,222.6

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

88

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Six Months Ended June 30,
	2019			2018
OPERATING ACTIVITIES
Net Income	$	159.2		$	158.9
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	173.5			121.9
Deferred Income Taxes	(17.2		)	33.1
Deferral of Incremental Nuclear Refueling Outage Expenses, Net	(14.3		)	(3.5		)
Carrying Costs Income	1.4			(4.0		)
Allowance for Equity Funds Used During Construction	(12.5		)	(4.1		)
Mark-to-Market of Risk Management Contracts	(6.0		)	(5.2		)
Amortization of Nuclear Fuel	46.1			51.4
Deferred Fuel Over/Under-Recovery, Net	(16.5		)	8.1
Change in Other Noncurrent Assets	32.6			(5.6		)
Change in Other Noncurrent Liabilities	(3.6		)	44.4
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	35.8			(18.3		)
Fuel, Materials and Supplies	(3.8		)	(5.0		)
Accounts Payable	(50.4		)	(12.2		)
Accrued Taxes, Net	(15.9		)	0.8
Other Current Assets	9.6			1.2
Other Current Liabilities	(38.6		)	(16.9		)
Net Cash Flows from Operating Activities	279.4			345.0
INVESTING ACTIVITIES
Construction Expenditures	(293.8		)	(284.7		)
Change in Advances to Affiliates, Net	(0.3		)	(79.9		)
Purchases of Investment Securities	(226.6		)	(1,067.8		)
Sales of Investment Securities	199.5			1,037.8
Acquisitions of Nuclear Fuel	(33.8		)	(24.2		)
Other Investing Activities	9.0			8.2
Net Cash Flows Used for Investing Activities	(346.0		)	(410.6		)
FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated	62.8			700.6
Change in Advances from Affiliates, Net	93.6			(211.6		)
Retirement of Long-term Debt – Nonaffiliated	(48.3		)	(352.4		)
Principal Payments for Finance Lease Obligations	(2.7		)	(5.2		)
Dividends Paid on Common Stock	(40.0		)	(67.0		)
Other Financing Activities	0.2			1.3
Net Cash Flows from Financing Activities	65.6			65.7
Net Increase (Decrease) in Cash and Cash Equivalents	(1.0		)	0.1
Cash and Cash Equivalents at Beginning of Period	2.4			1.3
Cash and Cash Equivalents at End of Period	$	1.4		$	1.4
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	55.2		$	55.2
Net Cash Paid (Received) for Income Taxes	27.9			(23.6		)
Noncash Acquisitions Under Finance Leases	4.5			3.2
Construction Expenditures Included in Current Liabilities as of June 30,	77.7			86.5
Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30,	50.5			0.6
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage	—			0.7

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

89

OHIO POWER COMPANY AND SUBSIDIARIES

90

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,
	2019	2018	2019	2018
	(in millions of KWhs)
Retail:
Residential	2,791	3,287	6,914	7,420
Commercial	3,478	3,642	7,005	7,175
Industrial	3,624	3,805	7,247	7,378
Miscellaneous	26	26	57	57
Total Retail (a)(b)	9,919	10,760	21,223	22,030
Wholesale (c)	440	534	1,078	1,201
Total KWhs	10,359	11,294	22,301	23,231

(a) 2018 KWhs have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail KWhs. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.

(b) Represents energy delivered to distribution customers.

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

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,
	2019	2018	2019	2018
	(in degree days)
Actual – Heating (a)	114	274	2,006	2,158
Normal – Heating (b)	189	186	2,066	2,070
Actual – Cooling (c)	303	454	304	458
Normal – Cooling (b)	298	291	301	294

(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.

91

Second Quarter of 2019 Compared to Second Quarter of 2018

Reconciliation of Second Quarter of 2018 to Second Quarter of 2019
Net Income
(in millions)
Second Quarter of 2018	$	68.8
Changes in Gross Margin:
Retail Margins	(63.2		)
Off-system Sales	(7.9		)
Transmission Revenues	(5.0		)
Other Revenues	1.8
Total Change in Gross Margin	(74.3		)
Changes in Expenses and Other:
Other Operation and Maintenance	45.0
Depreciation and Amortization	9.0
Taxes Other Than Income Taxes	(7.0		)
Interest Income	0.2
Carrying Costs Income	(0.4		)
Allowance for Equity Funds Used During Construction	0.8
Non-Service Cost Components of Net Periodic Benefit Cost	(0.3		)
Interest Expense	(0.3		)
Total Change in Expenses and Other	47.0
Income Tax Expense	9.1
Second Quarter of 2019	$	50.6

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 $63 million primarily due to the following:

• A $60 million net decrease in Basic Transmission Cost Rider revenues and recoverable PJM expenses. This decrease was partially offset by a decrease in Other Operation and Maintenance expenses below.

• An $8 million decrease in usage primarily in the residential and commercial classes.

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

• A $6 million net decrease in margin for the Phase-In-Recovery Rider including associated amortizations which ended in the first quarter of 2019.

• A $6 million decrease in rider revenues associated with the DIR. This decrease was partially offset in various expenses below.

These decreases were partially offset by:

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

• An $8 million increase due to the recovery of higher current year losses from a power contract with OVEC. This increase was offset by a corresponding decrease in Margins from Off-system Sales below.

• Margins from Off-system Sales decreased $8 million primarily due to higher current year losses from a power contract with OVEC as a result of the OVEC PPA rider. This decrease was offset by a corresponding increase in Retail Margins above.

• Transmission Revenues decreased $5 million primarily due to the annual PJM Transmission formula rate true-up.

92

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:

• An $83 million decrease in recoverable PJM expenses. This decrease was offset within Gross Margins above.

This decrease was partially offset by:

• A $35 million increase in PJM expenses primarily related to the annual formula rate true-up.

• Depreciation and Amortization expenses decreased $9 million primarily due to the following:

• A $14 million decrease in recoverable DIR depreciation expense. This decrease was partially offset in Retail Margins above.

This decrease was partially offset by:

• A $6 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.

• Taxes Other Than Income Taxes increased $7 million primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.

• Income Tax Expense decreased $9 million primarily due to increased amortization of Excess ADIT not subject to normalization requirements. This decrease was partially offset in Gross Margin above.

93

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

Reconciliation of Six Months Ended June 30, 2018 to Six Months Ended June 30, 2019
Net Income
(in millions)
Six Months Ended June 30, 2018	$	148.4
Changes in Gross Margin:
Retail Margins	12.1
Off-system Sales	(8.7		)
Transmission Revenues	5.4
Other Revenues	4.4
Total Change in Gross Margin	13.2
Changes in Expenses and Other:
Other Operation and Maintenance	5.0
Depreciation and Amortization	10.5
Taxes Other Than Income Taxes	(10.8		)
Interest Income	0.1
Carrying Costs Income	(0.9		)
Allowance for Equity Funds Used During Construction	3.5
Non-Service Cost Components of Net Periodic Benefit Cost	(0.5		)
Interest Expense	0.3
Total Change in Expenses and Other	7.2
Income Tax Expense	9.8
Six Months Ended June 30, 2019	$	178.6

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 $12 million primarily due to the following:

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

• A $22 million increase in revenues associated with smart grid riders. This increase was partially offset by increases in other expense items below.

• A $9 million increase due to the recovery of higher current year losses from a power contract with OVEC. This increase was offset by a corresponding decrease in Margins from Off-system Sales below.

• A $6 million increase in Energy Efficiency/Peak Demand Reduction rider revenues. This increase was offset by a corresponding increase in Other Operation and Maintenance expenses below.

These increases were partially offset by:

• A $43 million net decrease in Basic Transmission Cost Rider revenues and recoverable PJM expenses. This decrease was partially offset by a decrease in Other Operation and Maintenance expenses below.

• A $12 million decrease in revenues associated with vegetation management riders. This decrease was offset in Other Operation and Maintenance expenses below.

• An $11 million decrease in usage primarily in the residential and commercial classes.

• A $10 million net decrease in margin for the Phase-In-Recovery Rider including associated amortizations which ended in the first quarter of 2019.

• An $8 million decrease in rider revenues associated with the DIR. This decrease was partially offset in various expenses below.

• Margins from Off-system Sales decreased $9 million primarily due to higher current year losses from a power contract with OVEC as a result of the OVEC PPA rider. This decrease was offset by a corresponding increase in Retail Margins above.

• Transmission Revenues increased $5 million primarily due to 2018 provisions for refunds, partially offset by the annual PJM Transmission formula rate true-up.

• Other Revenues increased $4 million primarily due to distribution connection fees and pole attachment revenues.

94

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

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

• A $52 million decrease in recoverable PJM expenses. This decrease was offset within Gross Margins above.

This decrease was partially offset by:

• A $45 million increase in PJM expenses primarily related to the annual formula rate true-up.

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

• A $24 million decrease in recoverable DIR depreciation expense. This decrease was partially offset in Retail Margins above.

This decrease was offset by:

• A $13 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.

• Taxes Other Than Income Taxes increased $11 million primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.

• Allowance for Equity Funds Used During Construction increased $4 million primarily due to adjustments that resulted from 2019 FERC audit findings.

• Income Tax Expense decreased $10 million due to increased amortization of Excess ADIT not subject to normalization requirements partially offset by an increase in pretax book income. This decrease was partially offset in Gross Margin above.

95

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
REVENUES
Electricity, Transmission and Distribution	$	602.3		$	735.9		$	1,428.8		$	1,522.2
Sales to AEP Affiliates	1.7			11.5			9.2			14.6
Other Revenues	2.6			1.4			5.4			2.9
TOTAL REVENUES	606.6			748.8			1,443.4			1,539.7
EXPENSES
Purchased Electricity for Resale	121.5			162.9			295.7			368.4
Purchased Electricity from AEP Affiliates	33.7			27.9			79.8			58.1
Amortization of Generation Deferrals	24.1			56.4			56.5			115.0
Other Operation	153.9			199.0			370.8			371.2
Maintenance	34.2			34.1			66.7			71.3
Depreciation and Amortization	56.1			65.1			119.4			129.9
Taxes Other Than Income Taxes	106.0			99.0			214.9			204.1
TOTAL EXPENSES	529.5			644.4			1,203.8			1,318.0
OPERATING INCOME	77.1			104.4			239.6			221.7
Other Income (Expense):
Interest Income	1.1			0.9			1.9			1.8
Carrying Costs Income	0.2			0.6			0.4			1.3
Allowance for Equity Funds Used During Construction	4.1			3.3			9.3			5.8
Non-Service Cost Components of Net Periodic Benefit Cost	3.6			3.9			7.3			7.8
Interest Expense	(25.6		)	(25.3		)	(50.2		)	(50.5		)
INCOME BEFORE INCOME TAX EXPENSE	60.5			87.8			208.3			187.9
Income Tax Expense	9.9			19.0			29.7			39.5
NET INCOME	$	50.6		$	68.8		$	178.6		$	148.4

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

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

96

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
Net Income	$	50.6		$	68.8		$	178.6		$	148.4
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, 2019 and 2018, Respectively, and $(0.2) and $(0.2) for the Six Months Ended June 30, 2019 and 2018, Respectively	(0.4		)	(0.3		)	(0.7		)	(0.6		)
TOTAL COMPREHENSIVE INCOME	$	50.2		$	68.5		$	177.9		$	147.8

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

97

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017	$	321.2	$	838.8	$	1,148.4		$	1.9		$	2,310.3
Common Stock Dividends					(112.5		)				(112.5		)
ASU 2018-02 Adoption								0.4			0.4
Net Income					79.6						79.6
Other Comprehensive Loss								(0.3		)	(0.3		)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018	321.2		838.8		1,115.5			2.0			2,277.5
Common Stock Dividends					(112.5		)				(112.5		)
Net Income					68.8						68.8
Other Comprehensive Loss								(0.3		)	(0.3		)
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2018	$	321.2	$	838.8	$	1,071.8		$	1.7		$	2,233.5
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2018	$	321.2	$	838.8	$	1,136.4		$	1.0		$	2,297.4
Common Stock Dividends					(25.0		)				(25.0		)
Net Income					128.0						128.0
Other Comprehensive Loss								(0.3		)	(0.3		)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2019	321.2		838.8		1,239.4			0.7			2,400.1
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

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

98

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2019 and December 31, 2018

(in millions)

(Unaudited)

	June 30,			December 31,
	2019			2018
CURRENT ASSETS
Cash and Cash Equivalents	$	2.7		$	4.9
Restricted Cash for Securitized Funding	28.2			27.6
Advances to Affiliates	63.9			—
Accounts Receivable:
Customers	76.5			111.1
Affiliated Companies	51.9			70.8
Accrued Unbilled Revenues	7.5			21.4
Miscellaneous	0.4			0.3
Allowance for Uncollectible Accounts	(1.3		)	(1.0		)
Total Accounts Receivable	135.0			202.6
Materials and Supplies	45.7			42.9
Renewable Energy Credits	28.5			25.9
Prepayments and Other Current Assets	14.3			15.7
TOTAL CURRENT ASSETS	318.3			319.6
PROPERTY, PLANT AND EQUIPMENT
Electric:
Transmission	2,573.8			2,544.3
Distribution	5,104.6			4,942.3
Other Property, Plant and Equipment	643.3			574.8
Construction Work in Progress	459.4			432.1
Total Property, Plant and Equipment	8,781.1			8,493.5
Accumulated Depreciation and Amortization	2,238.8			2,218.6
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	6,542.3			6,274.9
OTHER NONCURRENT ASSETS
Regulatory Assets	370.4			387.5
Securitized Assets	1.8			12.9
Deferred Charges and Other Noncurrent Assets	402.8			441.0
TOTAL OTHER NONCURRENT ASSETS	775.0			841.4
TOTAL ASSETS	$	7,635.6		$	7,435.9

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

99

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

June 30, 2019 and December 31, 2018

(dollars in millions)

(Unaudited)

	June 30,		December 31,
	2019		2018
CURRENT LIABILITIES
Advances from Affiliates	$	—	$	114.1
Accounts Payable:
General	177.0		211.9
Affiliated Companies	85.6		102.9
Long-term Debt Due Within One Year – Nonaffiliated (June 30, 2019 and December 31, 2018 Amounts Include $24.6 and $47.8, Respectively, Related to Ohio Phase-in-Recovery Funding)	24.7		47.9
Risk Management Liabilities	7.6		5.8
Customer Deposits	88.6		113.1
Accrued Taxes	370.5		537.8
Obligations Under Operating Leases	13.2		—
Other Current Liabilities	181.5		214.2
TOTAL CURRENT LIABILITIES	948.7		1,347.7
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	2,113.5		1,668.7
Long-term Risk Management Liabilities	104.1		93.8
Deferred Income Taxes	788.4		763.3
Regulatory Liabilities and Deferred Investment Tax Credits	1,167.7		1,221.2
Obligations Under Operating Leases	75.4		—
Deferred Credits and Other Noncurrent Liabilities	47.5		43.8
TOTAL NONCURRENT LIABILITIES	4,296.6		3,790.8
TOTAL LIABILITIES	5,245.3		5,138.5
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 40,000,000 Shares
Outstanding – 27,952,473 Shares	321.2		321.2
Paid-in Capital	838.8		838.8
Retained Earnings	1,230.0		1,136.4
Accumulated Other Comprehensive Income (Loss)	0.3		1.0
TOTAL COMMON SHAREHOLDER’S EQUITY	2,390.3		2,297.4
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	7,635.6	$	7,435.9

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

100

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Six Months Ended June 30,
	2019			2018
OPERATING ACTIVITIES
Net Income	$	178.6		$	148.4
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	119.4			129.9
Amortization of Generation Deferrals	56.5			115.0
Deferred Income Taxes	9.4			(12.5		)
Carrying Costs Income	(0.4		)	(1.3		)
Allowance for Equity Funds Used During Construction	(9.3		)	(5.8		)
Mark-to-Market of Risk Management Contracts	12.1			(45.5		)
Property Taxes	130.1			129.6
Refund of Global Settlement	(8.2		)	(5.5		)
Reversal of Regulatory Provision	(56.2		)	—
Change in Other Noncurrent Assets	(30.1		)	83.3
Change in Other Noncurrent Liabilities	(38.0		)	56.0
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	70.0			14.0
Materials and Supplies	(8.5		)	(3.6		)
Accounts Payable	(34.9		)	(39.9		)
Accrued Taxes, Net	(169.4		)	(169.5		)
Other Current Assets	(4.2		)	(0.6		)
Other Current Liabilities	2.6			(11.4		)
Net Cash Flows from Operating Activities	219.5			380.6
INVESTING ACTIVITIES
Construction Expenditures	(385.5		)	(312.8		)
Change in Advances to Affiliates, Net	(63.9		)	—
Other Investing Activities	7.5			12.7
Net Cash Flows Used for Investing Activities	(441.9		)	(300.1		)
FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated	444.3			392.9
Change in Advances from Affiliates, Net	(114.1		)	126.1
Retirement of Long-term Debt – Nonaffiliated	(23.4		)	(372.9		)
Principal Payments for Finance Lease Obligations	(1.8		)	(1.9		)
Dividends Paid on Common Stock	(85.0		)	(225.0		)
Other Financing Activities	0.8			0.4
Net Cash Flows From (Used for) Financing Activities	220.8			(80.4		)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash for Securitized Funding	(1.6		)	0.1
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period	32.5			29.7
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period	$	30.9		$	29.8
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	46.1		$	48.3
Net Cash Paid for Income Taxes	14.3			45.1
Noncash Acquisitions Under Finance Leases	6.1			1.9
Construction Expenditures Included in Current Liabilities as of June 30,	77.9			64.5

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

101

PUBLIC SERVICE COMPANY OF OKLAHOMA

102

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,
	2019	2018	2019	2018
	(in millions of KWhs)
Retail:
Residential	1,289	1,635	2,809	3,128
Commercial	1,232	1,348	2,321	2,431
Industrial	1,590	1,536	3,023	2,955
Miscellaneous	298	335	572	611
Total Retail (a)	4,409	4,854	8,725	9,125
Wholesale	148	205	393	362
Total KWhs	4,557	5,059	9,118	9,487

(a) 2018 KWhs have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail KWhs. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.

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

Summary of Heating and Cooling Degree Days

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2019	2018	2019	2018
	(in degree days)
Actual – Heating (a)	28	129	1,199	1,161
Normal – Heating (b)	44	40	1,076	1,081
Actual – Cooling (c)	610	907	613	919
Normal – Cooling (b)	658	650	675	667

(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.

103

Second Quarter of 2019 Compared to Second Quarter of 2018

Reconciliation of Second Quarter of 2018 to Second Quarter of 2019
Net Income
(in millions)
Second Quarter of 2018	$	36.6
Changes in Gross Margin:
Retail Margins (a)	(25.6		)
Transmission Revenues	(0.5		)
Other Revenues	0.4
Total Change in Gross Margin	(25.7		)
Changes in Expenses and Other:
Other Operation and Maintenance	26.8
Depreciation and Amortization	(1.4		)
Taxes Other Than Income Taxes	(0.3		)
Other Income (Expense)	0.9
Non-Service Cost Components of Net Periodic Benefit Cost	(0.1		)
Interest Expense	(1.0		)
Total Change in Expenses and Other	24.9
Income Tax Expense	6.1
Second Quarter of 2019	$	41.9

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

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

• Retail Margins decreased $26 million primarily due to the following:

• A $22 million decrease in weather-related usage due to a 33% decrease in cooling degree days and a 78% decrease in heating degree days.

• A $7 million decrease in weather-normalized margins.

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

These decreases were partially offset by:

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

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

• Other Operation and Maintenance expenses decreased $27 million primarily due the following:

• A $17 million decrease in transmission expenses primarily due to decreased SPP transmission services.

• A $6 million decrease in Energy Efficiency program costs due to a change in amortizations of costs approved by the OCC. This decrease was offset in Retail Margins above.

• A $5 million decrease due to Wind Catcher Project expenses incurred in 2018.

• Income Tax Expense decreased $6 million primarily due to an increase in amortization of Excess ADIT. This decrease was partially offset in Gross Margin above.

104

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

Reconciliation of Six Months Ended June 30, 2018 to Six Months Ended June 30, 2019
Net Income
(in millions)
Six Months Ended June 30, 2018	$	29.4
Changes in Gross Margin:
Retail Margins (a)	(19.8		)
Off-system Sales	0.1
Transmission Revenues	(1.9		)
Other Revenues	1.8
Total Change in Gross Margin	(19.8		)
Changes in Expenses and Other:
Other Operation and Maintenance	44.4
Depreciation and Amortization	(8.1		)
Taxes Other Than Income Taxes	(0.1		)
Other Income (Expense)	1.0
Non-Service Cost Components of Net Periodic Benefit Cost	(0.2		)
Interest Expense	(3.2		)
Total Change in Expenses and Other	33.8
Income Tax Expense	4.7
Six Months Ended June 30, 2019	$	48.1

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

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

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

• A $20 million decrease in weather-related usage due to a 33% decrease in cooling degree days.

• A $15 million decrease in weather-normalized margins.

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

These decreases were partially offset by:

• A $22 million increase due to new base rates implemented in April 2019 and March 2018.

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

• Other Operation and Maintenance expenses decreased $44 million primarily due to the following:

• A $22 million decrease in transmission expenses primarily due to decreased SPP transmission services.

• An $11 million decrease in Energy Efficiency program costs due to a change in amortizations of costs approved by the OCC. This decrease was offset in Retail Margins above.

• A $9 million decrease due to Wind Catcher Project expenses incurred in 2018.

• A $4 million decrease in distribution expenses related to vegetation management.

• Depreciation and Amortization expenses increased $8 million primarily due to a higher depreciable base and new rates implemented in March 2018.

• Income Tax Expense decreased $5 million primarily due to an increase in amortization of Excess ADIT partially offset by an increase in pretax book income. This decrease was partially offset in Gross Margin above.

105

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
REVENUES
Electric Generation, Transmission and Distribution	$	344.6		$	395.3		$	673.8		$	730.4
Sales to AEP Affiliates	2.1			1.5			3.7			2.6
Other Revenues	1.4			1.5			3.4			2.1
TOTAL REVENUES	348.1			398.3			680.9			735.1
EXPENSES
Fuel and Other Consumables Used for Electric Generation	44.8			58.7			82.8			107.1
Purchased Electricity for Resale	102.5			113.1			225.4			235.5
Other Operation	64.8			93.7			138.4			180.5
Maintenance	26.1			24.0			48.6			50.9
Depreciation and Amortization	42.8			41.4			86.3			78.2
Taxes Other Than Income Taxes	10.5			10.2			21.9			21.8
TOTAL EXPENSES	291.5			341.1			603.4			674.0
OPERATING INCOME	56.6			57.2			77.5			61.1
Other Income (Expense):
Other Income (Expense)	0.8			(0.1		)	0.9			(0.1		)
Non-Service Cost Components of Net Periodic Benefit Cost	2.1			2.2			4.2			4.4
Interest Expense	(17.3		)	(16.3		)	(34.2		)	(31.0		)
INCOME BEFORE INCOME TAX EXPENSE	42.2			43.0			48.4			34.4
Income Tax Expense	0.3			6.4			0.3			5.0
NET INCOME	$	41.9		$	36.6		$	48.1		$	29.4

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

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

106

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
Net Income	$	41.9		$	36.6		$	48.1		$	29.4
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, 2019 and 2018, Respectively, and $(0.2) and $(0.2) for the Six Months Ended June 30, 2019 and 2018, Respectively	(0.3		)	(0.3		)	(0.5		)	(0.5		)
TOTAL COMPREHENSIVE INCOME	$	41.6		$	36.3		$	47.6		$	28.9

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

107

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2017	$	157.2	$	364.0	$	691.5		$	2.6		$	1,215.3
Common Stock Dividends					(12.5		)				(12.5		)
ASU 2018-02 Adoption								0.5			0.5
Net Loss					(7.2		)				(7.2		)
Other Comprehensive Loss								(0.2		)	(0.2		)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2018	157.2		364.0		671.8			2.9			1,195.9
Common Stock Dividends					(12.5		)				(12.5		)
Net Income					36.6						36.6
Other Comprehensive Loss								(0.3		)	(0.3		)
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2018	$	157.2	$	364.0	$	695.9		$	2.6		$	1,219.7
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

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

108

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED BALANCE SHEETS

ASSETS

June 30, 2019 and December 31, 2018

(in millions)

(Unaudited)

	June 30,			December 31,
	2019			2018
CURRENT ASSETS
Cash and Cash Equivalents	$	1.4		$	2.0
Accounts Receivable:
Customers	39.3			32.5
Affiliated Companies	36.5			26.2
Miscellaneous	2.2			5.7
Allowance for Uncollectible Accounts	(0.2		)	(0.1		)
Total Accounts Receivable	77.8			64.3
Fuel	10.5			12.3
Materials and Supplies	46.2			44.8
Risk Management Assets	28.0			10.4
Accrued Tax Benefits	19.9			14.7
Prepayments and Other Current Assets	10.4			9.4
TOTAL CURRENT ASSETS	194.2			157.9
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	1,566.5			1,577.0
Transmission	920.0			892.3
Distribution	2,625.9			2,572.8
Other Property, Plant and Equipment	313.5			303.5
Construction Work in Progress	101.7			94.0
Total Property, Plant and Equipment	5,527.6			5,439.6
Accumulated Depreciation and Amortization	1,527.2			1,472.9
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	4,000.4			3,966.7
OTHER NONCURRENT ASSETS
Regulatory Assets	375.9			369.0
Employee Benefits and Pension Assets	32.3			31.7
Operating Lease Assets	35.1			—
Deferred Charges and Other Noncurrent Assets	28.0			7.1
TOTAL OTHER NONCURRENT ASSETS	471.3			407.8
TOTAL ASSETS	$	4,665.9		$	4,532.4

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

109

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

June 30, 2019 and December 31, 2018

(Unaudited)

	June 30,		December 31,
	2019		2018
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	22.6	$	105.5
Accounts Payable:
General	114.8		126.9
Affiliated Companies	76.5		47.1
Long-term Debt Due Within One Year – Nonaffiliated	138.1		375.5
Risk Management Liabilities	0.3		1.0
Customer Deposits	59.3		58.6
Accrued Taxes	40.4		22.4
Obligations Under Operating Leases	5.9		—
Regulatory Liability for Over-Recovered Fuel Costs	29.1		20.1
Other Current Liabilities	64.2		64.5
TOTAL CURRENT LIABILITIES	551.2		821.6
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	1,248.2		911.5
Deferred Income Taxes	615.3		607.8
Regulatory Liabilities and Deferred Investment Tax Credits	860.2		864.7
Asset Retirement Obligations	48.5		46.3
Obligations Under Operating Leases	29.3		—
Deferred Credits and Other Noncurrent Liabilities	28.9		32.5
TOTAL NONCURRENT LIABILITIES	2,830.4		2,462.8
TOTAL LIABILITIES	3,381.6		3,284.4
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY
Common Stock – Par Value – $15 Per Share:
Authorized – 11,000,000 Shares
Issued – 10,482,000 Shares
Outstanding – 9,013,000 Shares	157.2		157.2
Paid-in Capital	364.0		364.0
Retained Earnings	761.5		724.7
Accumulated Other Comprehensive Income (Loss)	1.6		2.1
TOTAL COMMON SHAREHOLDER’S EQUITY	1,284.3		1,248.0
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	4,665.9	$	4,532.4

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

110

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Six Months Ended June 30,
	2019			2018
OPERATING ACTIVITIES
Net Income	$	48.1		$	29.4
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	86.3			78.2
Deferred Income Taxes	(9.0		)	(6.5		)
Allowance for Equity Funds Used During Construction	(0.7		)	0.1
Mark-to-Market of Risk Management Contracts	(18.3		)	(18.1		)
Property Taxes	(19.2		)	(19.2		)
Deferred Fuel Over/Under-Recovery, Net	9.0			29.9
Change in Other Noncurrent Assets	4.6			1.4
Change in Other Noncurrent Liabilities	(2.4		)	14.8
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(12.6		)	(6.4		)
Fuel, Materials and Supplies	0.4			(0.8		)
Accounts Payable	28.5			23.0
Accrued Taxes, Net	12.8			30.0
Other Current Assets	(1.6		)	0.5
Other Current Liabilities	3.3			3.0
Net Cash Flows from Operating Activities	129.2			159.3
INVESTING ACTIVITIES
Construction Expenditures	(132.7		)	(104.2		)
Other Investing Activities	1.1			2.7
Net Cash Flows Used for Investing Activities	(131.6		)	(101.5		)
FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated	349.9			—
Change in Advances from Affiliates, Net	(82.9		)	(31.2		)
Retirement of Long-term Debt – Nonaffiliated	(250.2		)	(0.2		)
Principal Payments for Finance Lease Obligations	(1.5		)	(1.8		)
Dividends Paid on Common Stock	(11.3		)	(25.0		)
Other Financing Activities	(2.2		)	0.4
Net Cash Flows from (Used for) Financing Activities	1.8			(57.8		)
Net Decrease in Cash and Cash Equivalents	(0.6		)	—
Cash and Cash Equivalents at Beginning of Period	2.0			1.6
Cash and Cash Equivalents at End of Period	$	1.4		$	1.6
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	30.9		$	31.7
Net Cash Paid (Received) for Income Taxes	11.1			(1.8		)
Noncash Acquisitions Under Finance Leases	2.3			1.8
Construction Expenditures Included in Current Liabilities as of June 30,	19.7			25.9

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

111

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

112

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,
	2019	2018	2019	2018
	(in millions of KWhs)
Retail:
Residential	1,297	1,606	2,825	3,164
Commercial	1,411	1,563	2,684	2,873
Industrial	1,356	1,490	2,606	2,667
Miscellaneous	20	21	40	40
Total Retail (a)	4,084	4,680	8,155	8,744
Wholesale	1,507	1,563	3,486	3,471
Total KWhs	5,591	6,243	11,641	12,215

(a) 2018 KWhs have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail KWhs. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.

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

Summary of Heating and Cooling Degree Days

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2019	2018	2019	2018
	(in degree days)
Actual – Heating (a)	24	55	732	784
Normal – Heating (b)	26	25	724	732
Actual – Cooling (c)	691	895	711	955
Normal – Cooling (b)	740	733	779	771

(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.

113

Second Quarter of 2019 Compared to Second Quarter of 2018

Reconciliation of Second Quarter of 2018 to Second Quarter of 2019
Earnings Attributable to SWEPCo Common Shareholder
(in millions)
Second Quarter of 2018	$	37.6
Changes in Gross Margin:
Retail Margins (a)	(35.1		)
Off-system Sales	(0.5		)
Transmission Revenues	(29.1		)
Total Change in Gross Margin	(64.7		)
Changes in Expenses and Other:
Other Operation and Maintenance	30.4
Depreciation and Amortization	(3.2		)
Interest Income	0.1
Allowance for Equity Funds Used During Construction	0.2
Non-Service Cost Components of Net Periodic Benefit Cost	(0.1		)
Interest Expense	0.4
Total Change in Expenses and Other	27.8
Income Tax Expense	5.4
Equity Earnings of Unconsolidated Subsidiary	0.1
Second Quarter of 2019	$	6.2

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

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

• Retail Margins decreased $35 million primarily due to the following:

• A $21 million decrease in weather-normalized margins.

• A $16 million decrease in weather-related usage primarily due to a 23% decrease in cooling degree days and a 56% decrease in heating degree days.

These decreases were partially offset by:

• A $4 million increase due to customer refunds related to Tax Reform. This increase was partially offset in Income Tax Expense below.

• Transmission Revenues decreased $29 million primarily due to a $40 million decrease in the annual SPP formula rate true-ups, partially offset by an $11 million 2018 provision for refund on certain transmission assets that management believes should not have been included in the SPP formula rate. This decrease was partially offset by a decrease in transmission expenses in SPP.

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

• Other Operation and Maintenance expenses decreased $30 million primarily due to the following:

• A $23 million decrease in SPP expenses primarily due to decreases in Transmission Revenues above.

• A $12 million decrease due to Wind Catcher Project expenses incurred in 2018.

These decreases were partially offset by:

• An $8 million increase in overhead line expenses primarily related to storm restoration.

• Depreciation and Amortization expenses increased $3 million primarily due to higher depreciation rates implemented in the third quarter of 2018 and a higher depreciable base.

• Income Tax Expense decreased $5 million primarily due to an increase in amortization of Excess ADIT not subject to normalization requirements and a decrease in pretax book income. This decrease was partially offset in Gross Margin above.

114

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

Reconciliation of Six Months Ended June 30, 2018 to Six Months Ended June 30, 2019
Earnings Attributable to SWEPCo Common Shareholder
(in millions)
Six Months Ended June 30, 2018	$	49.4
Changes in Gross Margin:
Retail Margins (a)	(29.0		)
Off-system Sales	0.1
Transmission Revenues	(30.8		)
Other Revenues	0.1
Total Change in Gross Margin	(59.6		)
Changes in Expenses and Other:
Other Operation and Maintenance	42.8
Depreciation and Amortization	(7.9		)
Taxes Other Than Income Taxes	(0.3		)
Interest Income	(1.0		)
Allowance for Equity Funds Used During Construction	(0.3		)
Non-Service Cost Components of Net Periodic Benefit Cost	(0.3		)
Interest Expense	2.9
Total Change in Expenses and Other	35.9
Income Tax Expense	7.6
Equity Earnings of Unconsolidated Subsidiary	0.3
Net Income Attributable to Noncontrolling Interest	0.4
Six Months Ended June 30, 2019	$	34.0

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

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

• Retail Margins decreased $29 million primarily due to the following:

• A $19 million decrease in weather-related usage primarily due to a 26% decrease in cooling degree days and a 7% decrease in heating degree days.

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

These decreases were partially offset by:

• A $7 million increase due to customer refunds related to Tax Reform. This increase was partially offset in Income Tax Expense below.

• Transmission Revenues decreased $31 million primarily due to a $40 million decrease in the annual SPP formula rate true-ups, partially offset by an $11 million 2018 provision for refund on certain transmission assets that management believes should not have been included in the SPP formula rate. This decrease was partially offset by a decrease in transmission expenses in SPP.

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

• Other Operation and Maintenance expenses decreased $43 million primarily due to the following:

• A $25 million decrease in SPP expenses primarily due to decreases in Transmission Revenues above.

• A $22 million decrease due to Wind Catcher Project expenses incurred in 2018.

These decreases were partially offset by:

• A $7 million increase in overhead line expenses primarily related to storm restoration.

115

• Depreciation and Amortization expenses increased $8 million primarily due to higher depreciation rates implemented in the third quarter of 2018 and a higher depreciable base.

• Interest Expense decreased $3 million primarily due to lower interest rates on outstanding long-term debt.

• Income Tax Expense decreased $8 million primarily due to an increase in amortization of Excess ADIT not subject to normalization requirements, partially offset by an increase in pretax book income. This decrease was partially offset in Gross Margin above.

116

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
REVENUES
Electric Generation, Transmission and Distribution	$	394.0		$	451.4		$	808.3		$	864.4
Sales to AEP Affiliates	6.4			5.4			12.8			11.5
Provision for Refund – Affiliated	(25.2		)	—			(25.2		)	—
Other Revenues	0.3			0.3			0.7			0.6
TOTAL REVENUES	375.5			457.1			796.6			876.5
EXPENSES
Fuel and Other Consumables Used for Electric Generation	117.9			114.5			251.4			241.3
Purchased Electricity for Resale	33.1			53.4			65.7			96.1
Other Operation	65.9			98.0			150.5			192.9
Maintenance	39.3			37.6			68.2			68.6
Depreciation and Amortization	61.8			58.6			123.9			116.0
Taxes Other Than Income Taxes	24.5			24.5			49.8			49.5
TOTAL EXPENSES	342.5			386.6			709.5			764.4
OPERATING INCOME	33.0			70.5			87.1			112.1
Other Income (Expense):
Interest Income	0.7			0.6			1.4			2.4
Allowance for Equity Funds Used During Construction	1.1			0.9			2.9			3.2
Non-Service Cost Components of Net Periodic Benefit Cost	2.2			2.3			4.3			4.6
Interest Expense	(30.5		)	(30.9		)	(60.2		)	(63.1		)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	6.5			43.4			35.5			59.2
Income Tax Expense	—			5.4			0.7			8.3
Equity Earnings of Unconsolidated Subsidiary	0.8			0.7			1.5			1.2
NET INCOME	7.3			38.7			36.3			52.1
Net Income Attributable to Noncontrolling Interest	1.1			1.1			2.3			2.7
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER	$	6.2		$	37.6		$	34.0		$	49.4

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

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

117

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
Net Income	$	7.3		$	38.7		$	36.3		$	52.1
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, 2019 and 2018, Respectively, and $0.2 and $0.2 for the Six Months Ended June 30, 2019 and 2018, Respectively	0.4			0.5			0.8			0.9
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended June 30, 2019 and 2018, Respectively, and $(0.2) and $(0.2) for the Six Months Ended June 30, 2019 and 2018, Respectively	(0.3		)	(0.4		)	(0.6		)	(0.7		)
TOTAL OTHER COMPREHENSIVE INCOME	0.1			0.1			0.2			0.2
TOTAL COMPREHENSIVE INCOME	7.4			38.8			36.5			52.3
Total Comprehensive Income Attributable to Noncontrolling Interest	1.1			1.1			2.3			2.7
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER	$	6.3		$	37.7		$	34.2		$	49.6

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

118

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	SWEPCo Common Shareholder
	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total
TOTAL EQUITY – DECEMBER 31, 2017	$	135.7	$	676.6	$	1,426.6		$	(4.0	)	$	(0.4	)	$	2,234.5
Common Stock Dividends					(20.0		)							(20.0		)
Common Stock Dividends – Nonaffiliated											(0.8		)	(0.8		)
ASU 2018-02 Adoption					(0.4		)	(0.9		)				(1.3		)
Net Income					11.8						1.6			13.4
Other Comprehensive Income								0.1						0.1
TOTAL EQUITY – MARCH 31, 2018	135.7		676.6		1,418.0			(4.8		)	0.4			2,225.9
Common Stock Dividends					(20.0		)							(20.0		)
Common Stock Dividends – Nonaffiliated											(1.0		)	(1.0		)
Net Income					37.6						1.1			38.7
Other Comprehensive Income								0.1						0.1
TOTAL EQUITY – JUNE 30, 2018	$	135.7	$	676.6	$	1,435.6		$	(4.7	)	$	0.5		$	2,243.7
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

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

119

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2019 and December 31, 2018

(in millions)

(Unaudited)

	June 30,			December 31,
	2019			2018
CURRENT ASSETS
Cash and Cash Equivalents (June 30, 2019 and December 31, 2018 Amounts Include $22.2 and $22, Respectively, Related to Sabine)	$	24.0		$	24.5
Advances to Affiliates	2.0			83.4
Accounts Receivable:
Customers	31.2			24.5
Affiliated Companies	56.5			28.8
Miscellaneous	15.6			20.2
Allowance for Uncollectible Accounts	(1.8		)	(0.7		)
Total Accounts Receivable	101.5			72.8
Fuel (June 30, 2019 and December 31, 2018 Amounts Include $34.9 and $35.7, Respectively, Related to Sabine)	136.6			120.5
Materials and Supplies	70.7			67.5
Risk Management Assets	12.3			4.8
Regulatory Asset for Under-Recovered Fuel Costs	14.4			18.8
Prepayments and Other Current Assets	23.0			22.2
TOTAL CURRENT ASSETS	384.5			414.5
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	4,670.4			4,672.6
Transmission	1,960.0			1,866.9
Distribution	2,222.0			2,178.6
Other Property, Plant and Equipment (June 30, 2019 and December 31, 2018 Amounts Include $210.3 and $276.9, Respectively, Related to Sabine)	698.8			762.7
Construction Work in Progress	209.4			199.3
Total Property, Plant and Equipment	9,760.6			9,680.1
Accumulated Depreciation and Amortization (June 30, 2019 and December 31, 2018 Amounts Include $101.6 and $174.6, Respectively, Related to Sabine)	2,805.2			2,808.3
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	6,955.4			6,871.8
OTHER NONCURRENT ASSETS
Regulatory Assets	224.0			230.8
Deferred Charges and Other Noncurrent Assets	179.5			111.2
TOTAL OTHER NONCURRENT ASSETS	403.5			342.0
TOTAL ASSETS	$	7,743.4		$	7,628.3

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

120

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

June 30, 2019 and December 31, 2018

(Unaudited)

	June 30,			December 31,
	2019			2018
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	55.3		$	—
Accounts Payable:
General	108.8			129.1
Affiliated Companies	89.1			64.2
Long-term Debt Due Within One Year – Nonaffiliated	121.2			59.7
Risk Management Liabilities	1.5			0.4
Customer Deposits	65.5			64.5
Accrued Taxes	89.2			42.8
Accrued Interest	33.8			34.7
Obligations Under Operating Leases	6.0			—
Regulatory Liability for Over-Recovered Fuel Costs	14.8			11.1
Other Current Liabilities	123.7			106.4
TOTAL CURRENT LIABILITIES	708.9			512.9
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	2,536.9			2,653.7
Long-term Risk Management Liabilities	2.4			2.2
Deferred Income Taxes	913.3			902.8
Regulatory Liabilities and Deferred Investment Tax Credits	921.6			923.0
Asset Retirement Obligations	198.4			191.3
Employee Benefits and Pension Obligations	24.3			24.8
Obligations Under Finance Leases	49.7			50.6
Obligations Under Operating Leases	31.5			—
Deferred Credits and Other Noncurrent Liabilities	44.0			51.4
TOTAL NONCURRENT LIABILITIES	4,722.1			4,799.8
TOTAL LIABILITIES	5,431.0			5,312.7
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
EQUITY
Common Stock – Par Value – $18 Per Share:
Authorized – 7,600,000 Shares
Outstanding – 7,536,640 Shares	135.7			135.7
Paid-in Capital	676.6			676.6
Retained Earnings	1,504.9			1,508.4
Accumulated Other Comprehensive Income (Loss)	(5.2		)	(5.4		)
TOTAL COMMON SHAREHOLDER’S EQUITY	2,312.0			2,315.3
Noncontrolling Interest	0.4			0.3
TOTAL EQUITY	2,312.4			2,315.6
TOTAL LIABILITIES AND EQUITY	$	7,743.4		$	7,628.3

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

121

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2019 and 2018

(in millions)

(Unaudited)

	Six Months Ended June 30,
	2019			2018
OPERATING ACTIVITIES
Net Income	$	36.3		$	52.1
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	123.9			116.0
Deferred Income Taxes	(10.1		)	0.4
Allowance for Equity Funds Used During Construction	(2.9		)	(3.2		)
Mark-to-Market of Risk Management Contracts	(6.2		)	1.1
Property Taxes	(32.2		)	(31.6		)
Deferred Fuel Over/Under-Recovery, Net	8.2			0.8
Change in Other Noncurrent Assets	2.9			(7.6		)
Change in Other Noncurrent Liabilities	2.0			45.4
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(26.1		)	22.1
Fuel, Materials and Supplies	(19.3		)	1.2
Accounts Payable	5.5			(17.3		)
Accrued Taxes, Net	47.7			31.8
Other Current Assets	(1.4		)	4.5
Other Current Liabilities	23.4			10.5
Net Cash Flows from Operating Activities	151.7			226.2
INVESTING ACTIVITIES
Construction Expenditures	(185.2		)	(244.6		)
Change in Advances to Affiliates, Net	81.4			—
Other Investing Activities	(2.2		)	0.6
Net Cash Flows Used for Investing Activities	(106.0		)	(244.0		)
FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated	—			444.6
Change in Short-term Debt – Nonaffiliated	—			3.2
Change in Advances from Affiliates, Net	55.3			1.2
Retirement of Long-term Debt – Nonaffiliated	(56.6		)	(383.5		)
Principal Payments for Finance Lease Obligations	(5.5		)	(5.7		)
Dividends Paid on Common Stock	(37.5		)	(40.0		)
Dividends Paid on Common Stock – Nonaffiliated	(2.2		)	(1.8		)
Other Financing Activities	0.3			0.3
Net Cash Flows from (Used for) Financing Activities	(46.2		)	18.3
Net Increase (Decrease) in Cash and Cash Equivalents	(0.5		)	0.5
Cash and Cash Equivalents at Beginning of Period	24.5			1.6
Cash and Cash Equivalents at End of Period	$	24.0		$	2.1
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	57.1		$	59.7
Net Cash Paid for Income Taxes	6.2			16.3
Noncash Acquisitions Under Finance Leases	2.6			2.7
Construction Expenditures Included in Current Liabilities as of June 30,	40.9			39.5

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 123.

122

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	124
New Accounting Pronouncements	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	127
Comprehensive Income	AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo	129
Rate Matters	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	137
Commitments, Guarantees and Contingencies	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	147
Acquisitions and Impairments	AEP, APCo	150
Benefit Plans	AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo	152
Business Segments	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	156
Derivatives and Hedging	AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo	161
Fair Value Measurements	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	173
Income Taxes	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	188
Leases	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	192
Financing Activities	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	197
Variable Interest Entities and Equity Method Investments	AEP	204
Revenue from Contracts with Customers	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	206

123

1.  SIGNIFICANT ACCOUNTING MATTERS

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

General

The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC.  Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant.  Net income for the three and six months ended June 30, 2019 is not necessarily indicative of results that may be expected for the year ending December 31, 2019.  The condensed financial statements are unaudited and should be read in conjunction with the audited 2018 financial statements and notes thereto, which are included in the Registrants’ Annual Reports on Form 10-K as filed with the SEC on February 21, 2019.

Earnings Per Share (EPS) (Applies to AEP)

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

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

	Three Months Ended June 30,
	2019				2018
	(in millions, except per share data)
			$/share				$/share
Earnings Attributable to AEP Common Shareholders	$	461.3			$	528.4
Weighted Average Number of Basic Shares Outstanding	493.6		$	0.93	492.7		$	1.07
Weighted Average Dilutive Effect of Stock-Based Awards	1.8		—		0.8		—
Weighted Average Number of Diluted Shares Outstanding	495.4		$	0.93	493.5		$	1.07

	Six Months Ended June 30,
	2019					2018
	(in millions, except per share data)
			$/share					$/share
Earnings Attributable to AEP Common Shareholders	$	1,034.1				$	982.8
Weighted Average Number of Basic Shares Outstanding	493.4		$	2.10		492.5		$	2.00
Weighted Average Dilutive Effect of Stock-Based Awards	1.5		(0.01		)	0.8		(0.01		)
Weighted Average Number of Diluted Shares Outstanding	494.9		$	2.09		493.3		$	1.99

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, 2019, as the dilutive stock price threshold was not met. See Note 13 - Financing Activities for more information related to Equity Units.

There were no antidilutive shares outstanding as of June 30, 2019 and 2018.

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

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

Reconciliation of Cash, Cash Equivalents and Restricted Cash

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

	June 30, 2019
	AEP		AEP Texas		APCo		OPCo
	(in millions)
Cash and Cash Equivalents	$	210.5	$	0.1	$	2.3	$	2.7
Restricted Cash	179.1		125.4		25.4		28.2
Total Cash, Cash Equivalents and Restricted Cash	$	389.6	$	125.5	$	27.7	$	30.9

	December 31, 2018
	AEP		AEP Texas		APCo		OPCo
	(in millions)
Cash and Cash Equivalents	$	234.1	$	3.1	$	4.2	$	4.9
Restricted Cash	210.0		156.7		25.6		27.6
Total Cash, Cash Equivalents and Restricted Cash	$	444.1	$	159.8	$	29.8	$	32.5

Revisions to Previously Issued Financial Statements (Applies to only AEPTCo)

In the second quarter of 2018, management identified certain transmission assets that it believes should not have been included in AEPTCo’s SPP transmission formula rates. As a result, AEPTCo recorded a pretax out of period correction of an error of approximately $17 million related to revenue recorded from 2013 through March 31, 2018 in the second quarter of 2018. Subsequent to filing the second quarter 2018 Form 10-Q, AEPTCo identified an additional error in its previously issued financial statements. This error resulted from the improper capitalization of AFUDC and subsequent revenue recorded on the AFUDC. The impact of this misstatement reduced AEPTCo’s pretax income by approximately $7 million on a cumulative basis for the period 2011 through June 30, 2018.

Management assessed the materiality of the misstatements on all previously issued AEPTCo financial statements in accordance with SEC Staff Accounting Bulletin (SAB) No. 99, Materiality, codified in ASC 250, Presentation of Financial Statements and concluded these misstatements were not material, individually or in the aggregate, to any prior annual or interim period. In accordance with ASC 250 (SAB No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements), management revised the prior period AEPTCo financial statements included in this report to reflect the impact of correcting the immaterial misstatements described above.

AEPTCo has also corrected other immaterial out of period adjustments. The impact of these additional adjustments did not impact net income in any period.

Management also assessed the materiality of the AEPTCo’s misstatements discussed above on all previously issued AEP financial statements in accordance with ASC 250, and concluded these misstatements were not material, individually or in the aggregate, to any prior interim and annual period financial statements. As a result, AEP recorded the correction in the third quarter of 2018.

125

Statements of Income

The table below reflects the effects of correcting the immaterial errors described above on AEPTCo’s statements of income for the three and six months ended June 30, 2018:

	Three Months Ended  June 30, 2018									Six Months Ended  June 30, 2018
	As Reported			Adjustments			As Adjusted			As Reported			Adjustments			As Adjusted
	(in millions)									(in millions)
TOTAL REVENUES	$	183.8		$	16.3		$	200.1		$	377.3		$	14.5		$	391.8
EXPENSES
Depreciation and Amortization	32.4			(0.1		)	32.3			63.0			(0.4		)	62.6
TOTAL EXPENSES	89.7			(0.1		)	89.6			170.6			(0.4		)	170.2
OPERATING INCOME	94.1			16.4			110.5			206.7			14.9			221.6
Other Income (Expense):
Allowance for Equity Funds Used During Construction	16.3			(0.5		)	15.8			31.6			(0.9		)	30.7
Interest Expense	(20.3		)	(0.3		)	(20.6		)	(40.2		)	(0.7		)	(40.9		)
INCOME BEFORE INCOME TAX EXPENSE	90.5			15.6			106.1			198.9			13.3			212.2
Income Tax Expense	20.0			4.1			24.1			42.5			3.6			46.1
NET INCOME	$	70.5		$	11.5		$	82.0		$	156.4		$	9.7		$	166.1

Statement of Cash Flows

The table below reflects the effects of correcting the immaterial errors described above on AEPTCo’s statement of cash flows for the six months ended June 30, 2018:

	Six Months Ended June 30, 2018
	As Reported			Adjustments			As Adjusted
	(in millions)
OPERATING ACTIVITIES
Net Income	$	156.4		$	9.7		$	166.1
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	63.0			(0.4		)	62.6
Deferred Income Taxes	50.2			(0.3		)	49.9
Allowance for Equity Funds Used During Construction	(31.6		)	0.9			(30.7		)
Change in Other Noncurrent Assets	(7.0		)	0.3			(6.7		)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	8.4			0.1			8.5
Accounts Payable	13.7			(10.3		)	3.4
Net Cash Flows from Operating Activities	246.1			—			246.1
INVESTING ACTIVITIES
Net Cash Flows Used for Investing Activities	(774.7		)	—			(774.7		)
FINANCING ACTIVITIES
Net Cash Flows from Financing Activities	528.6			—			528.6
Net Change in Cash and Cash Equivalents	—			—			—
Cash and Cash Equivalents at Beginning of Period	—			—			—
Cash and Cash Equivalents at End of Period	$	—		$	—		$	—
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	42.7		$	0.4		$	43.1
Construction Expenditures Included in Current Liabilities as of June 30,	234.7			6.4			241.1

Statement of Changes in Member’s Equity

The statement of changes in AEPTCo’s member’s equity reflects the adjustments to Net Income of $12 million and $10 million for the three and six months ended June 30, 2018 as shown in the table under Net Income above.

126

2. NEW ACCOUNTING PRONOUNCEMENTS

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

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

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

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

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

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

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

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

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

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

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

127

in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on results of operations, financial position or cash flows. Management plans to adopt ASU 2016-13 and related implementation guidance effective January 1, 2020.

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

In August 2018, the FASB issued ASU 2018-15 aligning the requirements for capitalizing implementation costs incurred in a cloud computing arrangement (hosting arrangement) that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The new standard requires an entity (customer) in a hosting arrangement that is a service contract to follow the accounting guidance for “Internal-Use Software” to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. To eliminate diversity in practice, the new standard changes the presentation of implementation costs for cloud service arrangements that are service contracts without the purchase of a license. Implementation costs for cloud service contracts will be presented on the balance sheets in the same manner as a prepayment.  The Registrants currently present implementation costs in property, plant and equipment on the balance sheets.  Under the new standard, amortization of capitalized implementation costs of a hosting arrangement will be recorded in Operation and Maintenance expense over the term of the cloud service arrangement, rather than Depreciation and Amortization expense on the statements of income.  Payments for capitalized implementation costs in the statement of cash flows will be classified in the same manner as payments made for fees associated with the hosting element.

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. The amendments may be applied either retrospectively or prospectively to applicable implementation costs incurred after the date of adoption. Management is analyzing the impact of this new standard and at this time, cannot estimate the impact of adoption on results of operations, financial position or cash flows. Management plans to adopt ASU 2018-15 prospectively, effective January 1, 2020.

128

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, 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		)	(b)	—			(95.6		)
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity for Resale (a)	21.2			—				—			21.2
Interest Expense (a)	—			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	)

	Cash Flow Hedges						Pension
Three Months Ended June 30, 2018	Commodity			Interest Rate			and OPEB			Total
	(in millions)
Balance in AOCI as of March 31, 2018	$	(32.0	)	$	(15.5	)	$	(47.9	)	$	(95.4	)
Change in Fair Value Recognized in AOCI	5.4			—			—			5.4
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity for Resale (a)	(4.7		)	—			—			(4.7		)
Interest Expense (a)	—			0.2			—			0.2
Amortization of Prior Service Cost (Credit)	—			—			(4.7		)	(4.7		)
Amortization of Actuarial (Gains) Losses	—			—			3.2			3.2
Reclassifications from AOCI, before Income Tax (Expense) Benefit	(4.7		)	0.2			(1.5		)	(6.0		)
Income Tax (Expense) Benefit	(0.9		)	—			(0.3		)	(1.2		)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	(3.8		)	0.2			(1.2		)	(4.8		)
Net Current Period Other Comprehensive Income (Loss)	1.6			0.2			(1.2		)	0.6
Balance in AOCI as of June 30, 2018	$	(30.4	)	$	(15.3	)	$	(49.1	)	$	(94.8	)

129

AEP

	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		)	(b)	—			(134.4		)
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity for Resale (a)	33.5			—				—			33.5
Interest Expense (a)	—			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	)

	Cash Flow Hedges						Securities
				Interest			Available			Pension
Six Months Ended June 30, 2018	Commodity			Rate			for Sale			and OPEB			Total
	(in millions)
Balance in AOCI as of December 31, 2017	$	(28.4	)	$	(13.0	)	$	11.9		$	(38.3	)	$	(67.8	)
Change in Fair Value Recognized in AOCI	18.2			—			—			—			18.2
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity for Resale (a)	(17.8		)	—			—			—			(17.8		)
Interest Expense (a)	—			0.5			—			—			0.5
Amortization of Prior Service Cost (Credit)	—			—			—			(9.7		)	(9.7		)
Amortization of Actuarial (Gains) Losses	—			—			—			6.4			6.4
Reclassifications from AOCI, before Income Tax (Expense) Benefit	(17.8		)	0.5			—			(3.3		)	(20.6		)
Income Tax (Expense) Benefit	(3.7		)	0.1			—			(0.7		)	(4.3		)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	(14.1		)	0.4			—			(2.6		)	(16.3		)
Net Current Period Other Comprehensive Income (Loss)	4.1			0.4			—			(2.6		)	1.9
ASU 2018-02 Adoption	(6.1		)	(2.7		)	—			(8.2		)	(17.0		)
ASU 2016-01 Adoption	—			—			(11.9		)	—			(11.9		)
Balance in AOCI as of June 30, 2018	$	(30.4	)	$	(15.3	)	$	—		$	(49.1	)	$	(94.8	)

130

AEP Texas

		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 (a)		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
Three Months Ended June 30, 2018		Interest Rate			and OPEB			Total
	(in millions)
Balance in AOCI as of March 31, 2018		$	(5.2	)	$	(9.8	)	$	(15.0	)
Change in Fair Value Recognized in AOCI		—			—			—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (a)		0.3			—			0.3
Amortization of Prior Service Cost (Credit)		—			(0.1		)	(0.1		)
Amortization of Actuarial (Gains) Losses		—			0.1			0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.3			—			0.3
Income Tax (Expense) Benefit		—			—			—
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, 2018		$	(4.9	)	$	(9.8	)	$	(14.7	)

		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 (a)		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	)

		Cash Flow Hedge –			Pension
Six Months Ended June 30, 2018		Interest Rate			and OPEB			Total
	(in millions)
Balance in AOCI as of December 31, 2017		$	(4.5	)	$	(8.1	)	$	(12.6	)
Change in Fair Value Recognized in AOCI		—			—			—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (a)		0.6			—			0.6
Amortization of Prior Service Cost (Credit)		—			(0.1		)	(0.1		)
Amortization of Actuarial (Gains) Losses		—			0.2			0.2
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
ASU 2018-02 Adoption		(0.9		)	(1.8		)	(2.7		)
Balance in AOCI as of June 30, 2018		$	(4.9	)	$	(9.8	)	$	(14.7	)

131

APCo

		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 (a)		(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
Three Months Ended June 30, 2018		Interest Rate			and OPEB			Total
	(in millions)
Balance in AOCI as of March 31, 2018		$	2.5		$	(1.9	)	$	0.6
Change in Fair Value Recognized in AOCI		—			—			—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (a)		(0.2		)	—			(0.2		)
Amortization of Prior Service Cost (Credit)		—			(1.3		)	(1.3		)
Amortization of Actuarial (Gains) Losses		—			0.3			0.3
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(0.2		)	(1.0		)	(1.2		)
Income Tax (Expense) Benefit		—			(0.2		)	(0.2		)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.2		)	(0.8		)	(1.0		)
Net Current Period Other Comprehensive Income (Loss)		(0.2		)	(0.8		)	(1.0		)
Balance in AOCI as of June 30, 2018		$	2.3		$	(2.7	)	$	(0.4	)

		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 (a)		(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	)

	Cash Flow Hedges						Pension
Six Months Ended June 30, 2018	Commodity			Interest Rate			and OPEB			Total
	(in millions)
Balance in AOCI as of December 31, 2017	$	—		$	2.2		$	(0.9	)	$	1.3
Change in Fair Value Recognized in AOCI	(0.7		)	—			—			(0.7		)
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity for Resale (a)	0.9			—			—			0.9
Interest Expense (a)	—			(0.5		)	—			(0.5		)
Amortization of Prior Service Cost (Credit)	—			—			(2.6		)	(2.6		)
Amortization of Actuarial (Gains) Losses	—			—			0.6			0.6
Reclassifications from AOCI, before Income Tax (Expense) Benefit	0.9			(0.5		)	(2.0		)	(1.6		)
Income Tax (Expense) Benefit	0.2			(0.1		)	(0.4		)	(0.3		)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	0.7			(0.4		)	(1.6		)	(1.3		)
Net Current Period Other Comprehensive Income (Loss)	—			(0.4		)	(1.6		)	(2.0		)
ASU 2018-02 Adoption	—			0.5			(0.2		)	0.3
Balance in AOCI as of June 30, 2018	$	—		$	2.3		$	(2.7	)	$	(0.4	)

132

I&M

		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 (a)		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
Three Months Ended June 30, 2018		Interest Rate			and OPEB			Total
	(in millions)
Balance in AOCI as of March 31, 2018		$	(12.7	)	$	(1.7	)	$	(14.4	)
Change in Fair Value Recognized in AOCI		—			—			—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (a)		0.6			—			0.6
Amortization of Prior Service Cost (Credit)		—			(0.2		)	(0.2		)
Amortization of Actuarial (Gains) Losses		—			0.2			0.2
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.6			—			0.6
Income Tax (Expense) Benefit		0.1			—			0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.5			—			0.5
Net Current Period Other Comprehensive Income (Loss)		0.5			—			0.5
Balance in AOCI as of June 30, 2018		$	(12.2	)	$	(1.7	)	$	(13.9	)

		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		$	(11.5	)	$	(2.3	)	$	(13.8	)
Change in Fair Value Recognized in AOCI		—			—			—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (a)		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	)

	Cash Flow Hedge –			Pension
Six Months Ended June 30, 2018	Interest Rate			and OPEB			Total
	(in millions)
Balance in AOCI as of December 31, 2017	$	(10.7	)	$	(1.4	)	$	(12.1	)
Change in Fair Value Recognized in AOCI	—			—			—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (a)	1.1			—			1.1
Amortization of Prior Service Cost (Credit)	—			(0.4		)	(0.4		)
Amortization of Actuarial (Gains) Losses	—			0.4			0.4
Reclassifications from AOCI, before Income Tax (Expense) Benefit	1.1			—			1.1
Income Tax (Expense) Benefit	0.2			—			0.2
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	0.9			—			0.9
Net Current Period Other Comprehensive Income (Loss)	0.9			—			0.9
ASU 2018-02 Adoption	(2.4		)	(0.3		)	(2.7		)
Balance in AOCI as of June 30, 2018	$	(12.2	)	$	(1.7	)	$	(13.9	)

133

OPCo

		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 (a)		(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 –
Three Months Ended June 30, 2018		Interest Rate
	(in millions)
Balance in AOCI as of March 31, 2018		$	2.0
Change in Fair Value Recognized in AOCI		—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (a)		(0.4		)
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(0.4		)
Income Tax (Expense) Benefit		(0.1		)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.3		)
Net Current Period Other Comprehensive Income (Loss)		(0.3		)
Balance in AOCI as of June 30, 2018		$	1.7

		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 (a)		(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

		Cash Flow Hedge –
Six Months Ended June 30, 2018		Interest Rate
	(in millions)
Balance in AOCI as of December 31, 2017		$	1.9
Change in Fair Value Recognized in AOCI		—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (a)		(0.8		)
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(0.8		)
Income Tax (Expense) Benefit		(0.2		)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.6		)
Net Current Period Other Comprehensive Income (Loss)		(0.6		)
ASU 2018-02 Adoption		0.4
Balance in AOCI as of June 30, 2018		$	1.7

134

PSO

		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 (a)		(0.4		)
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(0.4		)
Income Tax (Expense) Benefit		(0.1		)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.3		)
Net Current Period Other Comprehensive Income (Loss)		(0.3		)
Balance in AOCI as of June 30, 2019		$	1.6

		Cash Flow Hedge –
Three Months Ended June 30, 2018		Interest Rate
	(in millions)
Balance in AOCI as of March 31, 2018		$	2.9
Change in Fair Value Recognized in AOCI		—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (a)		(0.4		)
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(0.4		)
Income Tax (Expense) Benefit		(0.1		)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.3		)
Net Current Period Other Comprehensive Income (Loss)		(0.3		)
Balance in AOCI as of June 30, 2018		$	2.6

		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 (a)		(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

		Cash Flow Hedge –
Six Months Ended June 30, 2018		Interest Rate
	(in millions)
Balance in AOCI as of December 31, 2017		$	2.6
Change in Fair Value Recognized in AOCI		—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (a)		(0.7		)
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		)
ASU 2018-02 Adoption		0.5
Balance in AOCI as of June 30, 2018		$	2.6

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SWEPCo

		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 (a)		0.5			—			0.5
Amortization of Prior Service Cost (Credit)		—			(0.5		)	(0.5		)
Amortization of Actuarial (Gains) Losses		—			0.1			0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.5			(0.4		)	0.1
Income Tax (Expense) Benefit		0.1			(0.1		)	—
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.4			(0.3		)	0.1
Net Current Period Other Comprehensive Income (Loss)		0.4			(0.3		)	0.1
Balance in AOCI as of June 30, 2019		$	(2.5	)	$	(2.7	)	$	(5.2	)

		Cash Flow Hedge –			Pension
Three Months Ended June 30, 2018		Interest Rate			and OPEB			Total
	(in millions)
Balance in AOCI as of March 31, 2018		$	(6.9	)	$	2.1		$	(4.8	)
Change in Fair Value Recognized in AOCI		—			—			—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (a)		0.6			—			0.6
Amortization of Prior Service Cost (Credit)		—			(0.5		)	(0.5		)
Reclassifications from AOCI, before Income Tax (Expense) Benefit		0.6			(0.5		)	0.1
Income Tax (Expense) Benefit		0.1			(0.1		)	—
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.5			(0.4		)	0.1
Net Current Period Other Comprehensive Income (Loss)		0.5			(0.4		)	0.1
Balance in AOCI as of June 30, 2018		$	(6.4	)	$	1.7		$	(4.7	)

		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 (a)		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	)

		Cash Flow Hedge –			Pension
Six Months Ended June 30, 2018		Interest Rate			and OPEB			Total
	(in millions)
Balance in AOCI as of December 31, 2017		$	(6.0	)	$	2.0		$	(4.0	)
Change in Fair Value Recognized in AOCI		—			—			—
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (a)		1.1			—			1.1
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		1.1			(0.9		)	0.2
Income Tax (Expense) Benefit		0.2			(0.2		)	—
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		0.9			(0.7		)	0.2
Net Current Period Other Comprehensive Income (Loss)		0.9			(0.7		)	0.2
ASU 2018-02 Adoption		(1.3		)	0.4			(0.9		)
Balance in AOCI as of June 30, 2018		$	(6.4	)	$	1.7		$	(4.7	)

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

(b) 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. See “Sempra Renewables LLC” section of Note 14 for additional information.

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4.  RATE MATTERS

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

As discussed in the 2018 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2018 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2019 and updates the 2018 Annual Report.

Regulated Generating Unit to be Retired by 2020 (Applies to AEP and PSO)

In September 2018, management announced that the Oklaunion Power Station is probable of abandonment and is to be retired by October 2020.  The table below summarizes the plant investment and cost of removal, currently being recovered, as well as the regulatory asset for accelerated depreciation for the generating unit as of June 30, 2019. See “2018 Oklahoma Base Rate Case” below for additional information.

Gross Investment		Accumulated Depreciation		Net Investment		Accelerated Depreciation Regulatory Asset (a)		Materials and Supplies		Cost of Removal Regulatory Liability		Expected Retirement Date	Remaining Recovery Period
(dollars in millions)
$	106.6	$	74.6	$	32.0	$	16.4	$	3.1	$	5.1	2020	27 years

(a) In October 2018, PSO changed depreciation rates to utilize the 2020 end-of-life and defer depreciation expense to a regulatory asset for the amount in excess of the previously OCC-approved depreciation rates for Oklaunion Power Station. See “2018 Oklahoma Base Rate Case” discussion below for additional information.

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

	AEP
	June 30,		December 31,
	2019		2018
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs – Unrecovered Plant	$	50.3	$	50.3
Kentucky Deferred Purchase Power Expenses	22.3		14.5
Oklaunion Power Station Accelerated Depreciation	16.4		5.5
Other Regulatory Assets Pending Final Regulatory Approval	5.4		9.3
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs – Asset Retirement Obligation Costs	35.3		35.3
Storm-Related Costs (a)	—		152.4
Other Regulatory Assets Pending Final Regulatory Approval	13.5		20.7
Total Regulatory Assets Pending Final Regulatory Approval (b)	$	143.2	$	288.0

(a) In June 2019, the PUCT approved AEP Texas’ request to securitize its total estimated distribution-related system restoration costs. See “Texas Storm Cost Securitization” discussion below for additional information.

(b) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. APCo’s recovery of the remaining Virginia net book value for the retired plants will be considered in the Virginia SCC’s 2020 triennial review of APCo’s generation and distribution base rates.

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	AEP Texas
	June 30,		December 31,
	2019		2018
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Not Earning a Return
Rate Case Expense	$	0.7	$	0.2
Storm-Related Costs (a)	—		152.4
Total Regulatory Assets Pending Final Regulatory Approval	$	0.7	$	152.6

(a) In June 2019, the PUCT approved AEP Texas’ request to securitize its total estimated distribution-related system restoration costs. See “Texas Storm Cost Securitization” discussion below for additional information.

	APCo
	June 30,		December 31,
	2019		2018
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs – Materials and Supplies	$	5.1	$	9.0
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs – Asset Retirement Obligation Costs	35.3		35.3
Other Regulatory Assets Pending Final Regulatory Approval	—		0.6
Total Regulatory Assets Pending Final Regulatory Approval (a)	$	40.4	$	44.9

(a) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. APCo’s recovery of the remaining Virginia net book value for the retired plants will be considered in the Virginia SCC’s 2020 triennial review of APCo’s generation and distribution base rates.

	I&M
	June 30,		December 31,
	2019		2018
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Not Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval	$	—	$	3.3
Total Regulatory Assets Pending Final Regulatory Approval	$	—	$	3.3

	OPCo
	June 30,		December 31,
	2019		2018
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Not Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval	$	0.1	$	1.0
Total Regulatory Assets Pending Final Regulatory Approval	$	0.1	$	1.0

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	PSO
	June 30,		December 31,
	2019		2018
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Oklaunion Power Station Accelerated Depreciation	$	16.4	$	5.5
Regulatory Assets Currently Not Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval	—		0.5
Total Regulatory Assets Pending Final Regulatory Approval	$	16.4	$	6.0

	SWEPCo
	June 30,		December 31,
	2019		2018
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Plant Retirement Costs – Unrecovered Plant	$	50.3	$	50.3
Other Regulatory Assets Pending Final Regulatory Approval	0.3		0.3
Regulatory Assets Currently Not Earning a Return
Asset Retirement Obligation - Arkansas, Louisiana	6.3		5.3
Rate Case Expense – Texas	1.2		4.9
Other Regulatory Assets Pending Final Regulatory Approval	4.0		3.6
Total Regulatory Assets Pending Final Regulatory Approval	$	62.1	$	64.4

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

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

AEP Texas Interim Transmission and Distribution Rates

As of June 30, 2019, AEP Texas’ cumulative revenues from interim transmission and distribution rate increases from 2008 through 2019, subject to review, are estimated to be $1.2 billion. The 2019 base rate case described below 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.

2019 Texas Base Rate Case

In May 2019, AEP Texas filed a request with the PUCT for a $56 million annual increase in rates based upon a proposed 10.5% return on common equity. The filing includes a proposed Income Tax Refund Rider that will refund $21 million annually of Excess ADIT that is primarily not subject to rate normalization requirements. The rate case also seeks a prudence determination on all capital additions included in interim rates from 2008. If any of these costs are not recoverable or refunds of revenues collected under interim transmission and distribution rates are ordered to be returned, it could reduce future net income and cash flows and impact financial condition.

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Texas Storm Cost Securitization

In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. AEP Texas has a PUCT approved catastrophe reserve in base rates and can defer incremental storm expenses. AEP Texas currently recovers approximately $1 million of storm costs annually through base rates. As of June 30, 2019, the total balance of AEP Texas’ regulatory asset for deferred storm costs is approximately $210 million.

In March 2019, AEP Texas filed a request to securitize total estimated distribution-related system restoration costs with the PUCT in the amount of $230 million, which included estimated carrying costs. In June 2019, the PUCT issued a financing order approving the filing with minimal changes. Subject to market conditions, securitization bonds are expected to be issued in the third quarter of 2019. See the table below for details:

Total Estimated Distribution-Related System Restoration Costs
	(in millions)
Distribution-Related System Restoration Costs	$	264.6
Estimated Carrying Costs (through June 2019) (a)	26.9
Up-front Qualified Costs	4.4
Total Distribution-Related System Restoration Costs	295.9
less:
Insurance Proceeds and Government Grants	(3.1		)
Excess ADIT (b)	(63.5		)
Total Approved Distribution-Related System Restoration Costs	$	229.3

(a) Amount includes $16 million of debt carrying costs recorded as a reduction to Interest Expense in the second quarter of 2019.

(b) As part of the financing order, AEP Texas agreed to offset a portion of their Excess ADIT that is not subject to rate normalization requirements against the total distribution-related system restoration costs.

The remaining $95 million of estimated net transmission-related system restoration costs, including carrying charges, is expected to be recovered in the 2019 Texas Base Rate Case described above or through interim transmission base rate increases. If these costs are not recovered, it could have an adverse effect on future net income, cash flows and financial condition.

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

Virginia Legislation Affecting Earnings Reviews

Under a 2015 amended Virginia law, APCo’s existing generation and distribution base rates were frozen until after the Virginia SCC ruled on APCo’s next biennial review. The 2015 amendments also precluded the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017.

New Virginia legislation impacting investor-owned utilities was enacted, effective July 1, 2018, that requires APCo to file its next generation and distribution base rate case by March 31, 2020 using 2017, 2018 and 2019 earnings test years (“triennial review”). Triennial reviews are subject to an earnings test which provides that 70% of any earnings exceeding 70 basis points over the Virginia SCC authorized return on common equity would be refunded to customers or be used to lower APCo’s Virginia retail base rates on a prospective basis. The Virginia legislation also states that, under certain circumstances, costs associated with asset impairments related to early retirement determinations made by a utility for generation facilities fueled by coal, natural gas or oil or for automated meters be considered fully recovered in the period recorded.

In November 2018, the Virginia SCC approved a return on common equity of 9.42% applicable to APCo base rate earnings for the 2017-2019 triennial period and rate adjustment clauses from November 2018 through November 2020. Management has reviewed APCo’s actual and forecasted earnings for the triennial period and concluded that it is not probable, but is reasonably possible, that APCo will over-earn in Virginia during the 2017-2019 triennial period. Due

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to various uncertainties, including weather, storm restoration, weather-normalized demand and potential customer shopping during 2019, management cannot estimate a range of potential APCo Virginia over-earnings during the 2017-2019 triennial period. If the Virginia triennial review of APCo earnings results in any disallowance, it could materially reduce future net income and cash flows and impact financial condition.

Virginia Staff Depreciation Study Request

In November 2018, Virginia staff recommended that APCo implement new Virginia jurisdictional depreciation rates effective January 1, 2018 based on APCo’s depreciation study that was prepared at Virginia staff’s request using December 31, 2017 APCo property balances. Implementation of those depreciation rates would result in a $21 million pretax increase in annual depreciation expense ($6 million related to transmission) with no corresponding increase in retail base rates. In December 2018, APCo submitted a response to the Virginia staff stating that it was inappropriate for APCo to change Virginia depreciation rates in advance of the Virginia SCC’s upcoming Triennial Review of APCo, citing the Virginia SCC’s November 2014 order to not change APCo’s Virginia depreciation rates until APCo’s next base rate case/review. If the Virginia SCC were to issue an order approving the Virginia staff’s recommended retroactive change in APCo’s Virginia depreciation rates, it would reduce future net income and cash flows and impact financial condition.

Virginia Tax Reform

In March 2019, the Virginia SCC issued an order to reduce APCo’s base rates to refund: (a) $40 million annually for ongoing annual tax savings, (b) $9 million annually of Excess ADIT associated with certain depreciable property using ARAM, (c) $94 million of Excess ADIT that is not subject to rate normalization requirements over three years and (d) a one-time credit of $22 million for estimated excess taxes collected from customers during the 15-month period ending March 31, 2019.

2018 West Virginia Base Rate Case

In May 2018, APCo and WPCo filed a joint request with the WVPSC to increase their combined West Virginia base rates by $115 million ($98 million related to APCo) annually based on a 10.22% return on common equity. The proposed annual increase included $32 million ($28 million related to APCo) due to increased annual depreciation expense and reflected the impact of the reduction in the federal income tax rate due to Tax Reform. In October 2018, APCo and WPCo filed updated schedules supporting a $95 million ($80 million related to APCo) annual increase in West Virginia base rates primarily due to the impact of West Virginia Tax Reform.

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

ETT Rate Matters (Applies to AEP)

ETT Interim Transmission Rates

AEP has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. Through June 30, 2019, AEP’s share of ETT’s cumulative revenues that are subject to review is estimated

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to be $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 rate proceedings. The rule requires ETT to file for a comprehensive rate review no later than February 1, 2021.

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

Michigan Tax Reform

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

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 is based upon a proposed 10.5% return on common equity.  The proposed annual increase includes $78 million related to a proposed annual increase in depreciation expense. The requested annual increase in depreciation expense includes $52 million related to proposed investments and $26 million related to increased depreciation rates. The request includes the continuation of all existing riders and a new Automated Metering Infrastructure rider for proposed meter projects. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2019 Michigan Base Rate Case

In June 2019, I&M filed a request with the MPSC for a $58 million annual increase. The requested increase in Michigan rates would be phased in through June 2020 and is based upon a proposed 10.5% return on common equity.  The proposed annual increase includes $19 million related to a proposed annual increase in depreciation expense. The requested annual increase in depreciation expense includes $13 million related to proposed investments and $6 million related to increased depreciation rates. The proposed annual increase also includes $10 million for annual lost revenue related to the Michigan Electric Customer Choice Program that began in 2019. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

OPCo Rate Matters (Applies to AEP and OPCo)

Ohio ESP Filings

ESP Extension through 2024

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

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

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In April 2018, the PUCO issued an order approving the ESP extension stipulation agreement, with no significant changes. In October 2018, an intervenor filed an appeal with the Ohio Supreme Court challenging various approved riders. If the Ohio Supreme Court reverses the PUCO’s decision, it could reduce future net income and cash flows and impact financial condition.

OPCo’s Enhanced Service Reliability Rider authorized under the ESP is subject to annual audits.  In May 2018, the PUCO staff filed comments indicating that 2016 spending under the Enhanced Service Reliability Rider was subject to authorized limits and that OPCo overspent those limits.  OPCo filed reply comments objecting to the PUCO staff’s position, including the method of calculating the overspent amount.  In March 2019, the PUCO staff filed additional comments which adjusted the method of the calculation but maintained that OPCo overspent the authorized limit in 2016 and 2017, which could result in a refund of $10 million. Management believes that the 2016 or 2017 spending is not subject to an authorized limit and that a spending limit was not established until 2018, as part of the ESP extension. A hearing was held in May 2019 to address the 2016 audit. Post-hearing briefs in this case were filed in June 2019 and reply-hearing briefs were filed in July 2019. If it is determined OPCo did have an authorized spending limit under the Enhanced Service Reliability Rider in 2016 and 2017, and refunds are ordered, it would reduce future net income and cash flows and impact financial condition.

2016 SEET Filing

Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk.

In 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement that was filed at the PUCO in December 2016 and subsequently approved in February 2017: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings.

In February 2019, the PUCO issued an order that OPCo did not have significantly excessive earnings in 2016. As a result of the order, OPCo reversed the $58 million provision in the first quarter of 2019.

PSO Rate Matters (Applies to AEP and PSO)

2018 Oklahoma Base Rate Case

In 2018, PSO filed a request with the OCC for an $88 million annual increase in Oklahoma retail rates based upon a 10.3% return on common equity. PSO also proposed to implement a performance-based rate plan that combines a formula rate with a set of customer-focused performance incentive measures related to reliability, public safety, customer satisfaction and economic development. The proposed annual increase included $13 million related to increased annual depreciation rates and $7 million related to increased storm expense amortization. The requested increase in annual depreciation rates includes the recovery of Oklaunion Power Station through 2028 (currently being recovered in rates through 2046).  Management has announced plans to retire Oklaunion Power Station by October 2020.

In March 2019, the OCC issued an order approving a Stipulation and Settlement agreement for a $46 million annual increase, based on a 9.4% return on equity effective with the first billing cycle of April 2019. The order also included agreements between the parties that: (a) depreciation rates will remain unchanged, (b) PSO will file a new base rate request no earlier than October 2020 and no later than October 2021 and (c) PSO will refund Excess ADIT that is not subject to rate normalization requirements over five years instead of the ten years ordered in the Oklahoma Tax Reform case. The order did not approve the performance-based rate plan but instead provided for an expansion of the SPP Transmission Tariff that tracks previously untracked SPP costs and a new Distribution Reliability and Safety Rider that provides additional revenues capped at $5 million per year for distribution projects related to safety and reliability that are not normal distribution replacements.

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SWEPCo Rate Matters (Applies to AEP and SWEPCo)

2012 Texas Base Rate Case

In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs.

Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, SWEPCo reversed $114 million of a previously recorded regulatory disallowance in 2013. The resulting annual base rate increase was approximately $52 million. In 2017, the Texas District Court upheld the PUCT’s 2014 order and intervenors filed appeals with the Texas Third Court of Appeals.

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

As of June 30, 2019, the net book value of Turk Plant was $1.5 billion, before cost of removal, including materials and supplies inventory and CWIP. If certain parts of the PUCT order are overturned and if SWEPCo cannot ultimately fully recover its approximate 33% Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition.

2016 Texas Base Rate Case

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

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

2018 Louisiana Formula Rate Filing

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

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

In October 2018, the LPSC staff issued a recommendation that SWEPCo refund $11 million of excess federal income taxes collected, as a result of Tax Reform, from January 1, 2018 through July 31, 2018. In June 2019, the LPSC staff issued its report which was in agreement with its $11 million refund recommendation. The report also contends that SWEPCo’s requested annual rate increase of $18 million, that was implemented in August 2018, is overstated by $4 million and proposes an annual rate increase of $14 million. Additionally, the report recommends SWEPCo refund the excess over-collections associated with the $4 million difference for the period of August 2018 through the implementation of new rates. In July 2019, the LPSC approved the $11 million refund. A decision by the LPSC on the remaining issues is expected in 2019.

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

Welsh Plant - Environmental Impact

Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could total approximately $550 million, excluding AFUDC. As of June 30, 2019, SWEPCo had incurred costs of $399 million, including AFUDC, related to these projects.  Management continues to evaluate the impact of environmental rules and related project cost estimates. As of June 30, 2019, the total net book value of Welsh Plant, Units 1 and 3 was $617 million, before cost of removal, including materials and supplies inventory and CWIP. 

In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas filed base rate proceeding. In 2017, the LPSC approved recovery of $131 million in investments related to its Louisiana jurisdictional share of environmental controls installed at Welsh Plant. SWEPCo’s approved Louisiana jurisdictional share of Welsh Plant deferrals: (a) are $10 million, excluding $5 million of unrecognized equity as of June 30, 2019, (b) is subject to review by the LPSC and (c) includes a weighted average cost of capital return on environmental investments and the related depreciation expense and taxes. See “2018 Louisiana Formula Rate Filing” disclosure above for additional information.

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

2019 Arkansas Base Rate Case

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

In July 2019, APSC staff and various intervenors filed testimony.  APSC staff recommended a $20 million annual rate increase (excluding amounts currently recovered through riders) based on a 9.5% return on common equity while intervenors recommended annual rate increases ranging from $21 million to $25 million based on a return on common equity ranging from 9.0% to 9.2%, respectively.  The difference between SWEPCo’s requested annual base rate increase and the APSC staff and intervenors recommendations are primarily due to:  (a) a reduction in the requested return on common equity, (b) proposed lower depreciation rates, (c) proposed decreases of  certain operating expenses, (d) exclusion of a projected investment placed in service by December 31, 2019 and (e) treatment of Turk Plant accumulated deferred taxes and other items on  the capital structure.  Also, certain parties recommended disallowances for meters,

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Welsh Unit 2 and its replacement energy costs in the Energy Cost Recovery Rider, capitalized incentives and Dolet Hills environmental retrofits. Management is currently evaluating the impact of these recommendations. SWEPCo’s rebuttal testimony is due in August 2019. If any of these costs are not recoverable, or disallowances were to occur, it could reduce future net income and cash flows and impact financial condition.

FERC Rate Matters

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

In 2016, seven parties filed a complaint at the FERC that alleged the base return on common equity used by AEP’s transmission owning subsidiaries within PJM in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint.  In March 2018, AEP’s transmission owning subsidiaries within PJM and six of the complainants filed a settlement agreement with the FERC (the seventh complainant abstained).  The settlement agreement: (a) establishes a base ROE for AEP’s transmission owning subsidiaries within PJM of 9.85% (10.35% inclusive of the RTO incentive adder of 0.5%), effective January 1, 2018, (b) requires AEP’s transmission owning subsidiaries within PJM to provide a one-time refund of $50 million, attributable from the date of the complaint through December 31, 2017, which was credited to customer bills in the second quarter of 2018 and (c) increases the cap on the equity portion of the capital structure to 55% from 50%.  As part of the settlement agreement, AEP’s transmission owning subsidiaries within PJM also filed updated transmission formula rates incorporating the reduction in the corporate federal income tax rate due to Tax Reform, effective January 1, 2018 and providing for the amortization of the portion of the Excess ADIT that is not subject to the normalization method of accounting, ratably over a ten-year period through credits to the federal income tax expense component of the revenue requirement. In May 2019, the FERC approved the settlement agreement.

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

In 2017, several parties filed a complaint at the FERC that states the base return on common equity used by AEP’s transmission owning subsidiaries within SPP in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36%, effective upon the date of the complaint through September 5, 2018. In September 2018, the same parties filed another complaint at the FERC that states the base return on common equity used by AEP’s transmission owning subsidiaries within SPP in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.71%, effective upon the date of the second complaint. In June 2019, the FERC approved an unopposed settlement agreement between AEP’s transmission owning subsidiaries within SPP and the complainants. The settlement agreement establishes a base ROE of 10% (10.50% inclusive of the RTO incentive adder of 0.5%) effective January 1, 2019. Additionally, refunds including carrying charges will be made from the date of the first complaint through December 31, 2018. Refunds for the period prior to 2019 will be made at the time of the 2019 true-up of 2018 rates. Refunds from January 2019 onward will conclude with the 2020 true-up of 2019 rates.

Modifications to AEP’s SPP Transmission Rates (Applies to AEP, AEPTCo, PSO and SWEPCo)

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

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5.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

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

The Registrants are subject to certain claims and legal actions arising in the ordinary course of business.  In addition, the Registrants’ business activities are subject to extensive governmental regulation related to public health and the environment.  The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted.  Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates.

For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2018 Annual Report should be read in conjunction with this report.

GUARANTEES

Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.”  There is no collateral held in relation to any guarantees.  In the event any guarantee is drawn, there is no recourse to third-parties unless specified below.

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

Standby letters of credit are entered into with third-parties.  These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.

AEP has a $4 billion revolving credit facility due in June 2022, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of June 30, 2019, no letters of credit were issued under the revolving credit facility.

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility.  AEP issues letters of credit on behalf of subsidiaries under six uncommitted facilities totaling $405 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of June 30, 2019 were as follows:

Company	Amount		Maturity
	(in millions)
AEP	$	181.0	July 2019 to June 2020
AEP Texas	2.2		January 2020
OPCo	3.6		September 2019 to April 2020

As of June 30, 2019, AEP had $45 million of variable rate Pollution Control Bonds supported by $46 million of bilateral letters of credit. Beginning in July 2019, the $45 million of variable rate Pollution Control Bonds were held in trust.

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

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $140 million. Since SWEPCo uses self-bonding, the guarantee commits SWEPCo to complete the reclamation, in the event, Sabine does not complete the work.  This guarantee ends upon depletion of reserves and completion of reclamation.  The reserves are estimated to deplete in 2036 with reclamation completed by 2046 at an estimated cost of $107 million.  Actual reclamation costs could vary due to inflation and scope changes to the mine reclamation.  As of June 30, 2019, SWEPCo has collected $76 million through a rider for reclamation costs, of which $82 million was recorded in Asset Retirement Obligations, offset by $6 million recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets.

Sabine charges all of its costs to its only customer, SWEPCo, which recovers these costs through its fuel clauses.

Guarantees of Equity Method Investees (Applies to AEP)

In December 2016, AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of June 30, 2019, the maximum potential amount of future payments associated with this guarantee was $75 million, which expires in December 2019.

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

Indemnifications and Other Guarantees

Contracts

The Registrants enter into certain types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, exposure generally does not exceed the sale price.  As of June 30, 2019, there were no material liabilities recorded for any indemnifications.

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

ENVIRONMENTAL CONTINGENCIES (Applies to all Registrants except AEPTCo)

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

By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF.  Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized.  In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and non-hazardous materials.  The Registrants currently incur costs to dispose of these substances safely. For remediation processes not specifically discussed, management does not anticipate that the liabilities, if any, arising from such remediation processes would have a material effect on the financial statements.

NUCLEAR CONTINGENCIES (Applies to AEP and I&M)

I&M owns and operates the Cook Plant under licenses granted by the Nuclear Regulatory Commission.  I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant.  The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037.  The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements.  By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.

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OPERATIONAL CONTINGENCIES

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

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

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

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

Thereafter, AEP filed a motion with the U.S. District Court for the Southern District of Ohio in the original NSR litigation, seeking to modify the consent decree. The district court granted the owners’ unopposed motion to stay the lease litigation to afford time for resolution of AEP’s motion to modify the consent decree. The consent decree was modified based on an agreement among the parties in July 2019. As part of the modification to the consent decree, I&M agreed to provide an additional $7.5 million to citizens’ groups and the states for environmental mitigation projects. See “Modification of the New Source Review Litigation Consent Decree” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information.

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

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6. ACQUISITIONS AND IMPAIRMENTS

The disclosures in this note apply to AEP only 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 $583 million in cash and acquired a 50% ownership interest in five non-consolidated joint ventures with net assets valued at $406 million as of the acquisition date (which includes $364 million of existing debt obligations). Additionally, the transaction includes the acquisition of two tax equity partnerships and the associated recognition of noncontrolling tax equity interest of $135 million. The purchase price, subject to working capital adjustments, was allocated as follows:

Purchase Price Allocation of Sempra Renewables LLC at Acquisition Date - April 22nd, 2019
Assets:			Liabilities and Equity:			Net Purchase Price
(in millions)
Current Assets	$	9.7	Current Liabilities	$	12.9
Property, Plant and Equipment	238.1		Asset Retirement Obligations	5.7
Investment in Joint Ventures	405.9		Total Liabilities	18.6
Other Noncurrent Assets	82.9		Noncontrolling Interest	134.8
Total Assets	$	736.6	Liabilities and Noncontrolling Interest	$	153.4	$	583.2

Management allocated the purchase price based upon the relative fair value of the assets acquired and noncontrolling interests assumed. The fair value of the primary assets acquired and the noncontrolling interests assumed was determined using a discounted cash flow method under the income approach. The key input assumptions utilized in the determination of the fair value of these assets were the pricing and terms of the existing purchase power agreements, forecasted market power prices, forecasted production tax credits from the wind farms, expected wind farm net capacity, forecasted cash benefits from income tax depreciation and discount rates reflecting risk inherent in the future cash flows and future power prices. Additional key input assumptions for the fair value of the noncontrolling interests include the terms of the limited liability company agreements that dictate the sharing of the tax attributes and cash flows associated with the tax equity partnerships. Under the accounting rules for acquisitions, AEP has one year to finalize the purchase price allocation, including working capital adjustments and other closing adjustments.

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. One of the joint venture wind farms has PPAs with I&M and OPCo for a portion of its energy production which totaled $3 million and $7 million of purchased electricity, respectively, since the date of acquisition. Another joint venture wind farm has a PPA with SWEPCo for a portion of its energy production which totaled $3 million of purchased electricity since the date of acquisition. The PPAs with I&M, OPCo and SWEPCo were executed prior to the acquisition of the wind farms and will be accounted for in accordance with the accounting guidance for “Related Parties.”

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, 2019, the maximum potential amount of future payments associated with these guarantees was $186 million, with the last guarantee expiring in December 2037. The liability recorded associated with these guarantees was $35 million as of June 30, 2019.

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The acquired business contributed revenues and Net Income to AEP that were not material for the period April 22, 2019 to June 30, 2019. The pro-forma revenue and net income related to the acquisition of Sempra Renewables LLC were not material for the three and six months ended June 30, 2019 and 2018.

See Note 14 - Variable Interest Entities and Equity Method Investments for additional information related to the purchased wind farms.

Santa Rita East Wind Project (Generation & Marketing Segment)

In July 2019, AEP acquired a 75% interest, or 227 MWs, in the Santa Rita East Wind Project for approximately $356 million. The project is located in West Texas and was placed in-service in July 2019. Long-term virtual power purchase agreements are in place with nonaffiliates for the project’s generation.

IMPAIRMENTS

Other Assets (Corporate and Other) (Vertically Integrated Utilities Segment) (Applies to AEP and APCo)

In the first quarter of 2018, AEP was notified by an equity investee that it had ceased operations. AEP recorded a pretax impairment of $21 million in Other Operation on the statements of income related to the equity investment and related assets. The impairment also had an immaterial impact to APCo.

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7.  BENEFIT PLANS

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

AEP sponsors a qualified pension plan and two unfunded 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,
	2019			2018			2019			2018
	(in millions)
Service Cost	$	23.9		$	24.4		$	2.3		$	2.9
Interest Cost	51.1			47.0			12.7			11.9
Expected Return on Plan Assets	(74.0		)	(72.6		)	(23.5		)	(25.6		)
Amortization of Prior Service Credit	—			—			(17.2		)	(17.2		)
Amortization of Net Actuarial Loss	14.4			21.3			5.6			2.6
Net Periodic Benefit Cost (Credit)	$	15.4		$	20.1		$	(20.1	)	$	(25.4	)

	Pension Plans						OPEB
	Six Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)
Service Cost	$	47.8		$	48.8		$	4.7		$	5.8
Interest Cost	102.2			93.9			25.3			23.7
Expected Return on Plan Assets	(148.0		)	(145.1		)	(46.9		)	(51.1		)
Amortization of Prior Service Credit	—			—			(34.5		)	(34.5		)
Amortization of Net Actuarial Loss	28.8			42.6			11.1			5.2
Net Periodic Benefit Cost (Credit)	$	30.8		$	40.2		$	(40.3	)	$	(50.9	)

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AEP Texas

	Pension Plans						OPEB
	Three Months Ended June 30,						Three Months Ended June 30,
	2019			2018			2019			2018
	(in millions)
Service Cost	$	2.2		$	2.3		$	0.2		$	0.1
Interest Cost	4.3			4.0			1.0			1.0
Expected Return on Plan Assets	(6.5		)	(6.4		)	(1.9		)	(2.2		)
Amortization of Prior Service Credit	—			—			(1.4		)	(1.4		)
Amortization of Net Actuarial Loss	1.3			1.8			0.4			0.2
Net Periodic Benefit Cost (Credit)	$	1.3		$	1.7		$	(1.7	)	$	(2.3	)

	Pension Plans						OPEB
	Six Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)
Service Cost	$	4.3		$	4.6		$	0.4		$	0.4
Interest Cost	8.7			8.0			2.0			1.9
Expected Return on Plan Assets	(12.9		)	(12.8		)	(3.9		)	(4.3		)
Amortization of Prior Service Credit	—			—			(2.9		)	(2.9		)
Amortization of Net Actuarial Loss	2.5			3.6			0.9			0.4
Net Periodic Benefit Cost (Credit)	$	2.6		$	3.4		$	(3.5	)	$	(4.5	)

APCo

	Pension Plans						OPEB
	Three Months Ended June 30,						Three Months Ended June 30,
	2019			2018			2019			2018
	(in millions)
Service Cost	$	2.3		$	2.3		$	0.2		$	0.2
Interest Cost	6.3			5.9			2.1			2.1
Expected Return on Plan Assets	(9.3		)	(9.2		)	(3.6		)	(4.0		)
Amortization of Prior Service Credit	—			—			(2.5		)	(2.5		)
Amortization of Net Actuarial Loss	1.7			2.7			0.9			0.5
Net Periodic Benefit Cost (Credit)	$	1.0		$	1.7		$	(2.9	)	$	(3.7	)

	Pension Plans						OPEB
	Six Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)
Service Cost	$	4.7		$	4.6		$	0.5		$	0.5
Interest Cost	12.6			11.8			4.3			4.1
Expected Return on Plan Assets	(18.7		)	(18.3		)	(7.3		)	(8.0		)
Amortization of Prior Service Credit	—			—			(5.0		)	(5.0		)
Amortization of Net Actuarial Loss	3.5			5.3			1.8			1.0
Net Periodic Benefit Cost (Credit)	$	2.1		$	3.4		$	(5.7	)	$	(7.4	)

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I&M

	Pension Plans						OPEB
	Three Months Ended June 30,						Three Months Ended June 30,
	2019			2018			2019			2018
	(in millions)
Service Cost	$	3.3		$	3.4		$	0.4		$	0.4
Interest Cost	5.9			5.5			1.4			1.3
Expected Return on Plan Assets	(9.2		)	(8.9		)	(2.9		)	(3.1		)
Amortization of Prior Service Credit	—			—			(2.3		)	(2.3		)
Amortization of Net Actuarial Loss	1.7			2.4			0.6			0.3
Net Periodic Benefit Cost (Credit)	$	1.7		$	2.4		$	(2.8	)	$	(3.4	)

	Pension Plans						OPEB
	Six Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)
Service Cost	$	6.7		$	6.8		$	0.7		$	0.8
Interest Cost	11.9			11.0			2.9			2.7
Expected Return on Plan Assets	(18.4		)	(17.8		)	(5.7		)	(6.2		)
Amortization of Prior Service Credit	—			—			(4.7		)	(4.7		)
Amortization of Net Actuarial Loss	3.3			4.9			1.3			0.6
Net Periodic Benefit Cost (Credit)	$	3.5		$	4.9		$	(5.5	)	$	(6.8	)

OPCo

	Pension Plans						OPEB
	Three Months Ended June 30,						Three Months Ended June 30,
	2019			2018			2019			2018
	(in millions)
Service Cost	$	2.0		$	1.8		$	0.2		$	0.3
Interest Cost	4.8			4.5			1.3			1.3
Expected Return on Plan Assets	(7.4		)	(7.2		)	(2.7		)	(2.9		)
Amortization of Prior Service Credit	—			—			(1.7		)	(1.8		)
Amortization of Net Actuarial Loss	1.4			2.0			0.7			0.2
Net Periodic Benefit Cost (Credit)	$	0.8		$	1.1		$	(2.2	)	$	(2.9	)

	Pension Plans						OPEB
	Six Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)
Service Cost	$	4.0		$	3.8		$	0.4		$	0.5
Interest Cost	9.5			8.9			2.7			2.6
Expected Return on Plan Assets	(14.7		)	(14.4		)	(5.4		)	(5.9		)
Amortization of Prior Service Credit	—			—			(3.4		)	(3.5		)
Amortization of Net Actuarial Loss	2.7			4.0			1.3			0.5
Net Periodic Benefit Cost (Credit)	$	1.5		$	2.3		$	(4.4	)	$	(5.8	)

154

PSO

	Pension Plans						OPEB
	Three Months Ended June 30,						Three Months Ended June 30,
	2019			2018			2019			2018
	(in millions)
Service Cost	$	1.7		$	1.8		$	0.1		$	0.2
Interest Cost	2.7			2.5			0.6			0.6
Expected Return on Plan Assets	(4.1		)	(4.1		)	(1.3		)	(1.4		)
Amortization of Prior Service Credit	—			—			(1.0		)	(1.1		)
Amortization of Net Actuarial Loss	0.7			1.1			0.3			0.2
Net Periodic Benefit Cost (Credit)	$	1.0		$	1.3		$	(1.3	)	$	(1.5	)

	Pension Plans						OPEB
	Six Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)
Service Cost	$	3.3		$	3.6		$	0.3		$	0.4
Interest Cost	5.3			4.9			1.3			1.2
Expected Return on Plan Assets	(8.2		)	(8.1		)	(2.6		)	(2.8		)
Amortization of Prior Service Credit	—			—			(2.1		)	(2.1		)
Amortization of Net Actuarial Loss	1.5			2.2			0.6			0.3
Net Periodic Benefit Cost (Credit)	$	1.9		$	2.6		$	(2.5	)	$	(3.0	)

SWEPCo

	Pension Plans						OPEB
	Three Months Ended June 30,						Three Months Ended June 30,
	2019			2018			2019			2018
	(in millions)
Service Cost	$	2.2		$	2.3		$	0.2		$	0.2
Interest Cost	3.1			2.8			0.8			0.7
Expected Return on Plan Assets	(4.5		)	(4.3		)	(1.5		)	(1.6		)
Amortization of Prior Service Credit	—			—			(1.3		)	(1.3		)
Amortization of Net Actuarial Loss	0.8			1.2			0.4			0.2
Net Periodic Benefit Cost (Credit)	$	1.6		$	2.0		$	(1.4	)	$	(1.8	)

	Pension Plans						OPEB
	Six Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)
Service Cost	$	4.3		$	4.6		$	0.4		$	0.5
Interest Cost	6.2			5.7			1.6			1.4
Expected Return on Plan Assets	(8.9		)	(8.7		)	(3.0		)	(3.2		)
Amortization of Prior Service Credit	—			—			(2.6		)	(2.6		)
Amortization of Net Actuarial Loss	1.7			2.5			0.7			0.3
Net Periodic Benefit Cost (Credit)	$	3.3		$	4.1		$	(2.9	)	$	(3.6	)

155

8.  BUSINESS SEGMENTS

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

AEP’s Reportable Segments

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

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

Vertically Integrated Utilities

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

Transmission and Distribution Utilities

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

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

AEP Transmission Holdco

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

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

Generation & Marketing

• Competitive generation in ERCOT and PJM.

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

• Contracted renewable energy investments and management services.

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

156

The tables below present AEP’s reportable segment income statement information for the three and six months ended June 30, 2019 and 2018 and reportable segment balance sheet information as of June 30, 2019 and December 31, 2018.

	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

	Three Months Ended June 30, 2018
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other (a)			Reconciling Adjustments			Consolidated
	(in millions)
Revenues from:
External Customers	$	2,340.7	$	1,127.9	$	103.5	$	435.3	$	5.8		$	—		$	4,013.2
Other Operating Segments	8.3		9.1		109.0		25.4		18.0			(169.8		)	—
Total Revenues	$	2,349.0	$	1,137.0	$	212.5	$	460.7	$	23.8		$	(169.8	)	$	4,013.2
Net Income (Loss)	$	277.9	$	114.0	$	101.9	$	38.6	$	(2.3	)	$	—		$	530.1

	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

	Six Months Ended June 30, 2018
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing		Corporate and Other (a)			Reconciling Adjustments			Consolidated
	(in millions)
Revenues from:
External Customers	$	4,722.2	$	2,269.1	$	144.6	$	912.8	$	12.8		$	—		$	8,061.5
Other Operating Segments	34.8		30.3		273.4		53.0		35.0			(426.5		)	—
Total Revenues	$	4,757.0	$	2,299.4	$	418.0	$	965.8	$	47.8		$	(426.5	)	$	8,061.5
Net Income (Loss)	$	510.7	$	239.4	$	206.7	$	56.7	$	(26.7	)	$	—		$	986.8

157

	June 30, 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	$	46,201.8	$	18,874.5	$	9,330.3	$	1,176.7		$	413.2		$	(354.5	)	(b)	$	75,642.0
Accumulated Depreciation and Amortization	14,124.6		3,878.3		350.1		79.2			193.3			(186.4		)	(b)	18,439.1
Total Property Plant and Equipment - Net	$	32,077.2	$	14,996.2	$	8,980.2	$	1,097.5		$	219.9		$	(168.1	)	(b)	$	57,202.9
Total Assets	$	40,430.0	$	17,769.1	$	10,088.4	$	2,795.2		$	4,719.1	(c)	$	(3,251.8	)	(b) (d)	$	72,550.0
Long-term Debt Due Within One Year:
Nonaffiliated	$	674.5	$	334.5	$	248.2	$	—		$	0.2	(e)	$	—			$	1,257.4
Long-term Debt:
Affiliated	59.0		—		—		32.2			—			(91.2		)		—
Nonaffiliated	12,210.3		5,798.2		3,082.9		(0.3		)	3,083.3			—				24,174.4
Total Long-term Debt	$	12,943.8	$	6,132.7	$	3,331.1	$	31.9		$	3,083.5	(e)	$	(91.2	)		$	25,431.8

	December 31, 2018
	Vertically Integrated Utilities		Transmission and Distribution Utilities		AEP Transmission Holdco		Generation & Marketing			Corporate and Other (a)				Reconciling Adjustments				Consolidated
	(in millions)
Total Property, Plant and Equipment	$	45,365.1	$	18,126.7	$	8,659.5	$	893.3		$	395.2			$	(354.6	)	(b)	$	73,085.2
Accumulated Depreciation and Amortization	13,822.5		3,833.7		282.8		47.0			186.6				(186.5		)	(b)	17,986.1
Total Property Plant and Equipment - Net	$	31,542.6	$	14,293.0	$	8,376.7	$	846.3		$	208.6			$	(168.1	)	(b)	$	55,099.1
Total Assets	$	38,874.3	$	17,083.4	$	9,543.7	$	1,979.7		$	4,036.5		(c)	$	(2,714.8	)	(b) (d)	$	68,802.8
Long-term Debt Due Within One Year:
Nonaffiliated	$	1,066.3	$	549.1	$	85.0	$	0.1		$	(2.0	)	(e)	$	—			$	1,698.5
Long-term Debt:
Affiliated	50.0		—		—		32.2			—				(82.2		)		—
Nonaffiliated	11,442.7		5,048.8		2,888.6		(0.3		)	2,268.4				—				21,648.2
Total Long-term Debt	$	12,559.0	$	5,597.9	$	2,973.6	$	32.0		$	2,266.4		(e)	$	(82.2	)		$	23,346.7

(a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.

(b) Includes eliminations due to an intercompany finance lease.

(c) Includes elimination of AEP Parent’s investments in wholly-owned subsidiary companies.

(d) Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable.

(e) Amounts reflect the impact of fair value hedge accounting. See “Accounting for Fair Value Hedging Strategies” section of Note 10 for additional information.

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.

158

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, 2019 and 2018 and reportable segment balance sheet information as of June 30, 2019 and December 31, 2018.

	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
Other Revenues	—		—			—				—
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

	Three Months Ended June 30, 2018
	State Transcos (f)		AEPTCo Parent				Reconciling Adjustments				AEPTCo Consolidated (f)
	(in millions)
Revenues from:
External Customers	$	55.4	$	—			$	—			$	55.4
Sales to AEP Affiliates	144.7		—				—				144.7
Other Revenues	—		—				—				—
Total Revenues	$	200.1	$	—			$	—			$	200.1
Interest Income	$	—	$	25.2			$	(24.8	)	(a)	$	0.4
Interest Expense	20.6		24.8				(24.8		)	(a)	20.6
Income Tax Expense	23.6		0.5				—				24.1
Net Income	$	82.4	$	(0.4	)	(b)	$	—			$	82.0

159

	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
Other Revenues	—		—			—				—
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

	Six Months Ended June 30, 2018
	State Transcos (f)		AEPTCo Parent				Reconciling Adjustments				AEPTCo Consolidated (f)
	(in millions)
Revenues from:
External Customers	$	86.3	$	—			$	—			$	86.3
Sales to AEP Affiliates	305.4		—				—				305.4
Other Revenues	0.1		—				—				0.1
Total Revenues	$	391.8	$	—			$	—			$	391.8
Interest Income	$	0.2	$	50.2			$	(49.6	)	(a)	$	0.8
Interest Expense	40.9		49.6				(49.6		)	(a)	40.9
Income Tax Expense	45.3		0.8				—				46.1
Net Income	$	166.5	$	(0.4	)	(b)	$	—			$	166.1

	June 30, 2019
	State Transcos		AEPTCo Parent			Reconciling Adjustments				AEPTCo Consolidated
	(in millions)
Total Transmission Property	$	8,907.5	$	—		$	—			$	8,907.5
Accumulated Depreciation and Amortization	336.6		—			—				336.6
Total Transmission Property – Net	$	8,570.9	$	—		$	—			$	8,570.9
Notes Receivable - Affiliated	$	—	$	3,167.9		$	(3,167.9	)	(c)	$	—
Total Assets	$	8,897.7	$	3,218.9	(d)	$	(3,237.4	)	(e)	$	8,879.2
Total Long-term Debt	$	3,200.0	$	3,167.9		$	(3,200.0	)	(c)	$	3,167.9

	December 31, 2018
	State Transcos		AEPTCo Parent			Reconciling Adjustments				AEPTCo Consolidated
	(in millions)
Total Transmission Property	$	8,268.1	$	—		$	—			$	8,268.1
Accumulated Depreciation and Amortization	271.9		—			—				271.9
Total Transmission Property – Net	$	7,996.2	$	—		$	—			$	7,996.2
Notes Receivable - Affiliated	$	—	$	2,823.0		$	(2,823.0	)	(c)	$	—
Total Assets	$	8,406.8	$	2,857.1	(d)	$	(2,869.8	)	(e)	$	8,394.1
Total Long-term Debt	$	2,850.0	$	2,823.0		$	(2,850.0	)	(c)	$	2,823.0

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

(b) Includes the elimination of AEPTCo Parent’s equity earnings in the State Transcos.

(c) Elimination of intercompany debt.

(d) Includes the elimination of AEPTCo Parent’s investments in State Transcos.

(e) Primarily relates to the elimination of Notes Receivable from the State Transcos.

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

160

9.  DERIVATIVES AND HEDGING

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

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

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

The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets.  These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk.  These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates.  Management utilizes derivative instruments to manage these risks.

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Risk Management Strategies

The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.

The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors.

161

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

Notional Volume of Derivative Instruments

June 30, 2019

Primary Risk Exposure	Unit of Measure	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
		(in millions)
Commodity:
Power	MWhs	478.4		—		125.6		45.1		7.4		31.0		9.8
Natural Gas	MMBtus	64.5		—		—		—		—		—		13.4
Heating Oil and Gasoline	Gallons	7.9		1.6		1.5		0.7		1.9		0.8		0.9
Interest Rate	USD	$	143.9	$	—	$	—	$	—	$	—	$	—	$	—
Interest Rate	USD	$	500.0	$	—	$	—	$	—	$	—	$	—	$	—

Notional Volume of Derivative Instruments

December 31, 2018

Primary Risk Exposure	Unit of Measure	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
		(in millions)
Commodity:
Power	MWhs	371.1		—		66.4		40.9		7.8		15.2		4.5
Natural Gas	MMBtus	87.9		—		4.0		2.3		—		—		15.2
Heating Oil and Gasoline	Gallons	7.4		1.5		1.4		0.7		1.8		0.7		0.8
Interest Rate	USD	$	37.7	$	—	$	—	$	—	$	—	$	—	$	—
Interest Rate	USD	$	500.0	$	—	$	—	$	—	$	—	$	—	$	—

Fair Value Hedging Strategies (Applies to AEP)

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

Cash Flow Hedging Strategies

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

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

At times, the Registrants may be exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure.

162

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. The Registrants netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows:

	June 30, 2019				December 31, 2018
	Cash Collateral		Cash Collateral		Cash Collateral		Cash Collateral
	Received		Paid		Received		Paid
	Netted Against		Netted Against		Netted Against		Netted Against
	Risk Management		Risk Management		Risk Management		Risk Management
Company	Assets		Liabilities		Assets		Liabilities
	(in millions)
AEP	$	3.5	$	31.5	$	18.0	$	4.2
APCo	0.9		3.4		1.5		0.6
I&M	0.8		2.1		1.6		0.7

Amounts for AEP Texas, OPCo, PSO and SWEPCo are immaterial as of June 30, 2019 and December 31, 2018, respectively.

163

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, 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	$	534.3	$	4.8		$	0.2	$	539.3	$	(289.7	)	$	249.6
Long-term Risk Management Assets	358.7		4.2			11.7		374.6		(61.1		)	313.5
Total Assets	893.0		9.0			11.9		913.9		(350.8		)	563.1
Current Risk Management Liabilities	384.7		55.5			—		440.2		(298.8		)	141.4
Long-term Risk Management Liabilities	322.8		105.7			—		428.5		(80.0		)	348.5
Total Liabilities	707.5		161.2			—		868.7		(378.8		)	489.9
Total MTM Derivative Contract Net Assets (Liabilities)	$	185.5	$	(152.2	)	$	11.9	$	45.2	$	28.0		$	73.2

December 31, 2018

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

164

AEP Texas

Fair Value of Derivative Instruments

June 30, 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	0.2			—		0.2
Long-term Risk Management Liabilities	—			—		—
Total Liabilities	0.2			—		0.2
Total MTM Derivative Contract Net Liabilities	$	(0.2	)	$	—	$	(0.2	)

December 31, 2018

	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	0.7			(0.5		)	0.2
Long-term Risk Management Liabilities	—			—			—
Total Liabilities	0.7			(0.5		)	0.2
Total MTM Derivative Contract Net Assets (Liabilities)	$	(0.7	)	$	0.5		$	(0.2	)

APCo

Fair Value of Derivative Instruments

June 30, 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	$	138.1	$	(63.4	)	$	74.7
Long-term Risk Management Assets	7.3		(6.9		)	0.4
Total Assets	145.4		(70.3		)	75.1
Current Risk Management Liabilities	70.4		(65.8		)	4.6
Long-term Risk Management Liabilities	7.1		(7.0		)	0.1
Total Liabilities	77.5		(72.8		)	4.7
Total MTM Derivative Contract Net Assets	$	67.9	$	2.5		$	70.4

December 31, 2018

	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	$	114.4	$	(57.2	)	$	57.2
Long-term Risk Management Assets	3.1		(2.2		)	0.9
Total Assets	117.5		(59.4		)	58.1
Current Risk Management Liabilities	56.7		(56.3		)	0.4
Long-term Risk Management Liabilities	2.4		(2.2		)	0.2
Total Liabilities	59.1		(58.5		)	0.6
Total MTM Derivative Contract Net Assets (Liabilities)	$	58.4	$	(0.9	)	$	57.5

165

I&M

Fair Value of Derivative Instruments

June 30, 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	$	55.1	$	(39.4	)	$	15.7
Long-term Risk Management Assets	4.5		(4.2		)	0.3
Total Assets	59.6		(43.6		)	16.0
Current Risk Management Liabilities	41.8		(40.6		)	1.2
Long-term Risk Management Liabilities	4.3		(4.3		)	—
Total Liabilities	46.1		(44.9		)	1.2
Total MTM Derivative Contract Net Assets	$	13.5	$	1.3		$	14.8

December 31, 2018

	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	$	50.4	$	(41.8	)	$	8.6
Long-term Risk Management Assets	2.0		(1.4		)	0.6
Total Assets	52.4		(43.2		)	9.2
Current Risk Management Liabilities	41.1		(40.8		)	0.3
Long-term Risk Management Liabilities	1.6		(1.5		)	0.1
Total Liabilities	42.7		(42.3		)	0.4
Total MTM Derivative Contract Net Assets (Liabilities)	$	9.7	$	(0.9	)	$	8.8

OPCo

Fair Value of Derivative Instruments

June 30, 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	7.6			—		7.6
Long-term Risk Management Liabilities	104.1			—		104.1
Total Liabilities	111.7			—		111.7
Total MTM Derivative Contract Net Liabilities	$	(111.7	)	$	—	$	(111.7	)

December 31, 2018

	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	6.4			(0.6		)	5.8
Long-term Risk Management Liabilities	93.8			—			93.8
Total Liabilities	100.2			(0.6		)	99.6
Total MTM Derivative Contract Net Assets (Liabilities)	$	(100.2	)	$	0.6		$	(99.6	)

166

PSO

Fair Value of Derivative Instruments

June 30, 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	$	28.4	$	(0.4	)	$	28.0
Long-term Risk Management Assets	—		—			—
Total Assets	28.4		(0.4		)	28.0
Current Risk Management Liabilities	0.7		(0.4		)	0.3
Long-term Risk Management Liabilities	—		—			—
Total Liabilities	0.7		(0.4		)	0.3
Total MTM Derivative Contract Net Assets	$	27.7	$	—		$	27.7

December 31, 2018

	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	$	10.9	$	(0.5	)	$	10.4
Long-term Risk Management Assets	—		—			—
Total Assets	10.9		(0.5		)	10.4
Current Risk Management Liabilities	1.7		(0.7		)	1.0
Long-term Risk Management Liabilities	—		—			—
Total Liabilities	1.7		(0.7		)	1.0
Total MTM Derivative Contract Net Assets	$	9.2	$	0.2		$	9.4

SWEPCo

Fair Value of Derivative Instruments

June 30, 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	$	12.5	$	(0.2	)	$	12.3
Long-term Risk Management Assets	—		—			—
Total Assets	12.5		(0.2		)	12.3
Current Risk Management Liabilities	1.7		(0.2		)	1.5
Long-term Risk Management Liabilities	2.4		—			2.4
Total Liabilities	4.1		(0.2		)	3.9
Total MTM Derivative Contract Net Assets	$	8.4	$	—		$	8.4

December 31, 2018

	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	$	5.6	$	(0.8	)	$	4.8
Long-term Risk Management Assets	—		—			—
Total Assets	5.6		(0.8		)	4.8
Current Risk Management Liabilities	1.5		(1.1		)	0.4
Long-term Risk Management Liabilities	2.2		—			2.2
Total Liabilities	3.7		(1.1		)	2.6
Total MTM Derivative Contract Net Assets	$	1.9	$	0.3		$	2.2

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

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

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

167

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, 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

Amount of Gain (Loss) Recognized on

Risk Management Contracts

Three Months Ended June 30, 2018

Location of Gain (Loss)	AEP			AEP Texas		APCo			I&M			OPCo		PSO		SWEPCo
	(in millions)
Vertically Integrated Utilities Revenues	$	(3.2	)	$	—	$	—		$	—		$	—	$	—	$	—
Generation & Marketing Revenues	27.5			—		—			—			—		—		—
Electric Generation, Transmission and Distribution Revenues	—			—		(0.5		)	(2.6		)	—		—		0.1
Purchased Electricity for Resale	3.1			—		2.4			0.6			—		—		—
Other Operation	0.5			0.1		0.1			0.1			0.1		0.1		0.1
Maintenance	0.5			0.1		0.1			0.1			0.1		0.1		0.1
Regulatory Assets (a)	5.9			—		—			(3.0		)	9.7		—		(0.8		)
Regulatory Liabilities (a)	85.4			0.1		39.2			11.5			0.6		18.8		6.9
Total Gain on Risk Management Contracts	$	119.7		$	0.3	$	41.3		$	6.7		$	10.5	$	19.0	$	6.4

168

Amount of Gain (Loss) Recognized on

Risk Management Contracts

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

Amount of Gain (Loss) Recognized on

Risk Management Contracts

Six Months Ended June 30, 2018

Location of Gain (Loss)	AEP			AEP Texas		APCo			I&M			OPCo		PSO		SWEPCo
	(in millions)
Vertically Integrated Utilities Revenues	$	(8.7	)	$	—	$	—		$	—		$	—	$	—	$	—
Generation & Marketing Revenues	12.4			—		—			—			—		—		—
Electric Generation, Transmission and Distribution Revenues	—			—		(0.8		)	(7.7		)	—		—		0.1
Purchased Electricity for Resale	8.0			—		7.0			0.8			—		—		—
Other Operation	0.8			0.2		0.1			0.1			0.2		0.1		0.1
Maintenance	0.9			0.2		0.2			0.1			0.2		0.1		0.1
Regulatory Assets (a)	43.2			—		—			3.2			41.1		—		(1.1		)
Regulatory Liabilities (a)	172.4			—		103.3			11.7			0.6		30.9		6.1
Total Gain on Risk Management Contracts	$	229.0		$	0.4	$	109.8		$	8.2		$	42.1	$	31.1	$	5.3

(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.”

169

Accounting for Fair Value Hedging Strategies (Applies to AEP)

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

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

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

	Carrying Amount of the Hedged Assets/(Liabilities)						Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Assets/(Liabilities)
	June 30, 2019			December 31, 2018			June 30, 2019			December 31, 2018
	(in millions)
Long-term Debt (a)	$	(507.9	)	$	(478.3	)	$	(11.9	)	$	17.4

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

The pretax effects of fair value hedge accounting on income were as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)
Gain (Loss) on Interest Rate Contracts:
Gain (Loss) on Fair Value Hedging Instruments (a)	$	18.2		$	(7.3	)	$	29.3		$	(21.8	)
Gain (Loss) on Fair Value Portion of Long-term Debt (a)	(18.2		)	7.3			(29.3		)	21.8

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

Accounting for Cash Flow Hedging Strategies

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects net income.

Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three and six months ended June 30, 2019 and 2018, AEP applied cash flow hedging to outstanding power derivatives. During the three and six months ended June 30, 2019 and 2018, the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives.

The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three and six months ended June 30, 2019 and 2018, the Registrants did not apply cash flow hedging to outstanding interest rate derivatives.

The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and six months ended June 30, 2019 and 2018, the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives.

170

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, 2019							December 31, 2018
	Commodity			Interest Rate				Commodity			Interest Rate
	(in millions)
AOCI Gain (Loss) Net of Tax	$	(127.2	)	$	(15.9	)	(a)	$	(23.0	)	$	(12.6	)
Portion Expected to be Reclassed to Net Income During the Next Twelve Months	(45.4		)	(2.2		)		10.4			(1.1		)

(a) Includes $4 million related to AEP's investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC. See “Sempra Renewables LLC” section of Note 14 for additional information.

As of June 30, 2019 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 126 months and 138 months for commodity and interest rate hedges, respectively.

Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets

	June 30, 2019						December 31, 2018
	Interest Rate
				Expected to be						Expected to be
				Reclassified to						Reclassified to
				Net Income During						Net Income During
	AOCI Gain (Loss)			the Next			AOCI Gain (Loss)			the Next
Company	Net of Tax			Twelve Months			Net of Tax			Twelve Months
	(in millions)
AEP Texas	$	(3.9	)	$	(1.1	)	$	(4.4	)	$	(1.1	)
APCo	1.4			0.9			1.8			0.9
I&M	(10.7		)	(1.6		)	(11.5		)	(1.6		)
OPCo	0.3			0.3			1.0			1.0
PSO	1.6			1.0			2.1			1.0
SWEPCo	(2.5		)	(1.5		)	(3.3		)	(1.5		)

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

Credit Risk

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

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

171

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, 2019 and December 31, 2018, respectively.

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

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

	June 30, 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	$	347.0	$	6.7	$	317.8
APCo	6.1		—		0.5
I&M	3.6		—		0.3
SWEPCo	4.0		—		2.9

	December 31, 2018
	Liabilities for				Additional
	Contracts with Cross				Settlement
	Default Provisions				Liability if Cross
	Prior to Contractual		Amount of Cash		Default Provision
Company	Netting Arrangements		Collateral Posted		is Triggered
	(in millions)
AEP	$	225.5	$	1.8	$	181.0
APCo	0.9		—		—
I&M	0.5		—		—
SWEPCo	2.3		—		2.3

172

10.  FAIR VALUE MEASUREMENTS

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

Fair Value Hierarchy and Valuation Techniques

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.  When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value.  Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.

For commercial activities, exchange-traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange-traded derivatives where there is insufficient market liquidity to warrant inclusion in Level 1.  Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated.  Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace.  When multiple broker quotes are obtained, the quoted bid and ask prices are averaged.  In certain circumstances, a broker quote may be discarded if it is a clear outlier.  Management uses a historical correlation analysis between the broker quoted location and the illiquid locations.  If the points are highly correlated, these locations are included within Level 2 as well.  Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information.  Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket-based inputs.  Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.  The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market.  A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility.

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

Assets in the nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.

173

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, 2019				December 31, 2018
Company	Book Value		Fair Value		Book Value		Fair Value
	(in millions)
AEP (a)	$	25,431.8	$	28,377.7	$	23,346.7	$	24,093.9
AEP Texas	3,994.6		4,403.8		3,881.3		3,964.6
AEPTCo	3,167.9		3,481.7		2,823.0		2,782.4
APCo	4,374.8		5,177.0		4,062.6		4,473.3
I&M	3,054.5		3,389.9		3,035.4		3,070.2
OPCo	2,138.2		2,553.1		1,716.6		1,919.7
PSO	1,386.3		1,579.7		1,287.0		1,361.9
SWEPCo	2,658.1		2,868.5		2,713.4		2,670.2

(a) The fair value amount includes debt related to AEP’s Equity Units issued in March 2019 and has a fair value of $862 million as of June 30, 2019. See “Equity Units” section of Note 13 for additional information.

Fair Value Measurements of Other Temporary Investments (Applies to AEP)

Other Temporary Investments include marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS.

The following is a summary of Other Temporary Investments:

	June 30, 2019
			Gross		Gross
			Unrealized		Unrealized			Fair
Other Temporary Investments	Cost		Gains		Losses			Value
	(in millions)
Restricted Cash and Other Cash Deposits (a)	$	199.9	$	—	$	—		$	199.9
Fixed Income Securities – Mutual Funds (b)	115.0		—		(0.4		)	114.6
Equity Securities – Mutual Funds	22.7		17.6		—			40.3
Total Other Temporary Investments	$	337.6	$	17.6	$	(0.4	)	$	354.8

	December 31, 2018
			Gross		Gross
			Unrealized		Unrealized			Fair
Other Temporary Investments	Cost		Gains		Losses			Value
	(in millions)
Restricted Cash and Other Cash Deposits (a)	$	230.6	$	—	$	—		$	230.6
Fixed Income Securities – Mutual Funds (b)	106.6		—		(2.3		)	104.3
Equity Securities – Mutual Funds	17.8		16.4		—			34.2
Total Other Temporary Investments	$	355.0	$	16.4	$	(2.3	)	$	369.1

(a) Primarily represents amounts held for the repayment of debt.

(b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates.

174

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,
	2019		2018		2019		2018
	(in millions)
Proceeds from Investment Sales	$	—	$	—	$	—	$	—
Purchases of Investments	8.8		0.8		8.9		1.4
Gross Realized Gains on Investment Sales	—		—		—		—
Gross Realized Losses on Investment Sales	—		—		—		—

For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and six months ended June 30, 2018, see Note 3 - Comprehensive Income.

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M)

Nuclear decommissioning and SNF trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and SNF disposal liabilities.  By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines.  In general, limitations include:

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

• Maximum percentage invested in a specific type of investment.

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

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

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

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

Other-than-temporary impairments for investments in debt securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains, unrealized losses and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI.

175

The following is a summary of nuclear trust fund investments:

	June 30, 2019							December 31, 2018
			Gross		Other-Than-					Gross		Other-Than-
	Fair		Unrealized		Temporary			Fair		Unrealized		Temporary
	Value		Gains		Impairments			Value		Gains		Impairments
	(in millions)
Cash and Cash Equivalents	$	21.1	$	—	$	—		$	22.5	$	—	$	—
Fixed Income Securities:
United States Government	1,026.8		54.6		(6.3		)	996.1		26.7		(7.1		)
Corporate Debt	62.3		4.6		(1.7		)	52.4		1.1		(1.9		)
State and Local Government	7.6		0.7		(0.2		)	8.6		0.6		(0.2		)
Subtotal Fixed Income Securities	1,096.7		59.9		(8.2		)	1,057.1		28.4		(9.2		)
Equity Securities - Domestic (a)	1,658.6		1,010.2		—			1,395.3		766.3		—
Spent Nuclear Fuel and Decommissioning Trusts	$	2,776.4	$	1,070.1	$	(8.2	)	$	2,474.9	$	794.7	$	(9.2	)

(a) Amount reported as Gross Unrealized Gains includes unrealized gains of $1 billion and $784 million and unrealized losses of $8 million and $18 million as of June 30, 2019 and December 31, 2018, respectively. AEP adopted ASU 2016-01 during the first quarter of 2018 by means of a modified retrospective approach. Due to the adoption of the ASU, Other-Than-Temporary Impairments are no longer applicable to Equity Securities with readily determinable fair values.

The following table provides the securities activity within the decommissioning and SNF trusts:

	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
	(in millions)
Proceeds from Investment Sales	$	87.6	$	529.2	$	199.5	$	1,037.8
Purchases of Investments	96.3		542.5		226.6		1,067.8
Gross Realized Gains on Investment Sales	3.4		11.8		15.7		23.8
Gross Realized Losses on Investment Sales	6.1		7.8		19.9		18.7

The base cost of fixed income securities was $1 billion and $1 billion as of June 30, 2019 and December 31, 2018, respectively.  The base cost of equity securities was $648 million and $629 million as of June 30, 2019 and December 31, 2018, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of June 30, 2019 was as follows:

	Fair Value of Fixed
	Income Securities
	(in millions)
Within 1 year	$	335.0
After 1 year through 5 years	394.3
After 5 years through 10 years	181.8
After 10 years	185.6
Total	$	1,096.7

176

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, 2019

	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Other Temporary Investments
Restricted Cash and Other Cash Deposits (a)	$	162.7	$	—	$	—	$	37.2		$	199.9
Fixed Income Securities – Mutual Funds	114.6		—		—		—			114.6
Equity Securities – Mutual Funds (b)	40.3		—		—		—			40.3
Total Other Temporary Investments	317.6		—		—		37.2			354.8
Risk Management Assets
Risk Management Commodity Contracts (c) (d)	7.2		412.8		468.7		(353.2		)	535.5
Cash Flow Hedges:
Commodity Hedges (c)	—		6.6		2.0		7.1			15.7
Fair Value Hedges	—		11.9		—		—			11.9
Total Risk Management Assets	7.2		431.3		470.7		(346.1		)	563.1
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)	11.5		—		—		9.6			21.1
Fixed Income Securities:
United States Government	—		1,026.8		—		—			1,026.8
Corporate Debt	—		62.3		—		—			62.3
State and Local Government	—		7.6		—		—			7.6
Subtotal Fixed Income Securities	—		1,096.7		—		—			1,096.7
Equity Securities – Domestic (b)	1,658.6		—		—		—			1,658.6
Total Spent Nuclear Fuel and Decommissioning Trusts	1,670.1		1,096.7		—		9.6			2,776.4
Total Assets	$	1,994.9	$	1,528.0	$	470.7	$	(299.3	)	$	3,694.3
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (d)	$	7.3	$	430.6	$	265.3	$	(381.2	)	$	322.0
Cash Flow Hedges:
Commodity Hedges (c)	—		68.1		92.7		7.1			167.9
Total Risk Management Liabilities	$	7.3	$	498.7	$	358.0	$	(374.1	)	$	489.9

177

AEP

Assets and Liabilities Measured at Fair Value on a Recurring Basis

December 31, 2018

	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Other Temporary Investments
Restricted Cash and Other Cash Deposits (a)	$	221.5	$	—	$	—	$	9.1		$	230.6
Fixed Income Securities – Mutual Funds	104.3		—		—		—			104.3
Equity Securities – Mutual Funds (b)	34.2		—		—		—			34.2
Total Other Temporary Investments	360.0		—		—		9.1			369.1
Risk Management Assets
Risk Management Commodity Contracts (c) (f)	3.8		326.5		340.9		(288.5		)	382.7
Cash Flow Hedges:
Commodity Hedges (c)	—		24.1		12.7		(2.7		)	34.1
Total Risk Management Assets	3.8		350.6		353.6		(291.2		)	416.8
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)	12.3		—		—		10.2			22.5
Fixed Income Securities:
United States Government	—		996.1		—		—			996.1
Corporate Debt	—		52.4		—		—			52.4
State and Local Government	—		8.6		—		—			8.6
Subtotal Fixed Income Securities	—		1,057.1		—		—			1,057.1
Equity Securities – Domestic (b)	1,395.3		—		—		—			1,395.3
Total Spent Nuclear Fuel and Decommissioning Trusts	1,407.6		1,057.1		—		10.2			2,474.9
Total Assets	$	1,771.4	$	1,407.7	$	353.6	$	(271.9	)	$	3,260.8
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (f)	$	4.2	$	327.0	$	185.6	$	(274.7	)	$	242.1
Cash Flow Hedges:
Commodity Hedges (c)	—		24.8		36.8		(2.7		)	58.9
Fair Value Hedges	—		17.4		—		—			17.4
Total Risk Management Liabilities	$	4.2	$	369.2	$	222.4	$	(277.4	)	$	318.4

178

AEP Texas

Assets and Liabilities Measured at Fair Value on a Recurring Basis

June 30, 2019

	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)
Restricted Cash for Securitized Funding	$	125.4	$	—	$	—	$	—	$	125.4
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	0.2	$	—	$	—	$	0.2

December 31, 2018

	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Restricted Cash for Securitized Funding	$	156.7	$	—	$	—	$	—		$	156.7
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	0.7	$	—	$	(0.5	)	$	0.2

APCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

June 30, 2019

	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Restricted Cash for Securitized Funding	$	25.4	$	—	$	—	$	—		$	25.4
Risk Management Assets
Risk Management Commodity Contracts (c) (g)	—		69.4		75.7		(70.0		)	75.1
Total Assets	$	25.4	$	69.4	$	75.7	$	(70.0	)	$	100.5
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	70.0	$	7.2	$	(72.5	)	$	4.7

December 31, 2018

	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Restricted Cash for Securitized Funding	$	25.6	$	—	$	—	$	—		$	25.6
Risk Management Assets
Risk Management Commodity Contracts (c) (g)	0.1		59.1		58.3		(59.4		)	58.1
Total Assets	$	25.7	$	59.1	$	58.3	$	(59.4	)	$	83.7
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	0.2	$	58.4	$	0.5	$	(58.5	)	$	0.6

179

I&M

Assets and Liabilities Measured at Fair Value on a Recurring Basis

June 30, 2019

	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)	$	—	$	43.7	$	15.6	$	(43.3	)	$	16.0
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)	11.5		—		—		9.6			21.1
Fixed Income Securities:
United States Government	—		1,026.8		—		—			1,026.8
Corporate Debt	—		62.3		—		—			62.3
State and Local Government	—		7.6		—		—			7.6
Subtotal Fixed Income Securities	—		1,096.7		—		—			1,096.7
Equity Securities - Domestic (b)	1,658.6		—		—		—			1,658.6
Total Spent Nuclear Fuel and Decommissioning Trusts	1,670.1		1,096.7		—		9.6			2,776.4
Total Assets	$	1,670.1	$	1,140.4	$	15.6	$	(33.7	)	$	2,792.4
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	42.5	$	3.3	$	(44.6	)	$	1.2

December 31, 2018

	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)	$	—	$	42.1	$	10.3	$	(43.2	)	$	9.2
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)	12.3		—		—		10.2			22.5
Fixed Income Securities:
United States Government	—		996.1		—		—			996.1
Corporate Debt	—		52.4		—		—			52.4
State and Local Government	—		8.6		—		—			8.6
Subtotal Fixed Income Securities	—		1,057.1		—		—			1,057.1
Equity Securities - Domestic (b)	1,395.3		—		—		—			1,395.3
Total Spent Nuclear Fuel and Decommissioning Trusts	1,407.6		1,057.1		—		10.2			2,474.9
Total Assets	$	1,407.6	$	1,099.2	$	10.3	$	(33.0	)	$	2,484.1
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	0.1	$	41.2	$	1.4	$	(42.3	)	$	0.4

180

OPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

June 30, 2019

	Level 1		Level 2		Level 3		Other		Total
Liabilities:	(in millions)
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	0.2	$	111.5	$	—	$	111.7

December 31, 2018

	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Restricted Cash for Securitized Funding	$	27.6	$	—	$	—	$	—		$	27.6
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	0.8	$	99.4	$	(0.6	)	$	99.6

PSO

Assets and Liabilities Measured at Fair Value on a Recurring Basis

June 30, 2019

	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)	$	—	$	—	$	28.4	$	(0.4	)	$	28.0
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	0.1	$	0.6	$	(0.4	)	$	0.3

December 31, 2018

	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)	$	—	$	—	$	10.8	$	(0.4	)	$	10.4
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	0.3	$	1.3	$	(0.6	)	$	1.0

181

SWEPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

June 30, 2019

	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)	$	—	$	—	$	12.5	$	(0.2	)	$	12.3
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	0.1	$	4.0	$	(0.2	)	$	3.9

December 31, 2018

	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g)	$	—	$	—	$	5.6	$	(0.8	)	$	4.8
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	—	$	0.4	$	3.3	$	(1.1	)	$	2.6

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

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

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

(d) The June 30, 2019 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 2 matures $(10) million in 2019 and $(10) million in periods 2020-2022, $2 million in periods 2023-2024 and $1 million in periods 2025-2032; Level 3 matures $86 million in 2019, $106 million in periods 2020-2022, $23 million in periods 2023-2024 and $(12) million in periods 2025-2032.  Risk management commodity contracts are substantially comprised of power contracts.

(e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions.  Level 1 amounts primarily represent investments in money market funds.

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

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

There were no transfers between Level 1 and Level 2 during the three and six months ended June 30, 2019 and 2018.

182

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, 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	(53.5		)	—			—			—			—			—
Settlements	(50.6		)	(22.1		)	(6.3		)	1.9			(10.0		)	(3.3		)
Transfers into Level 3 (c) (d)	(1.5		)	—			—			—			—			—
Transfers out of Level 3 (d)	(1.6		)	—			—			—			—			—
Changes in Fair Value Allocated to Regulated Jurisdictions (e)	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

Three Months Ended June 30, 2018	AEP			APCo			I&M			OPCo			PSO			SWEPCo
	(in millions)
Balance as of March 31, 2018	$	62.0		$	9.1		$	2.9		$	(98.5	)	$	2.8		$	0.9
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)	55.0			36.0			11.8			0.2			6.1			(4.0		)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)	5.9			—			—			—			—			—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income	(10.3		)	—			—			—			—			—
Settlements	(75.8		)	(43.2		)	(14.6		)	1.3			(8.9		)	2.6
Transfers into Level 3 (c) (d)	12.6			—			—			—			—			—
Transfers out of Level 3 (d)	0.4			—			—			—			—			—
Changes in Fair Value Allocated to Regulated Jurisdictions (e)	122.5			58.1			13.1			10.1			24.3			5.4
Balance as of June 30, 2018	$	172.3		$	60.0		$	13.2		$	(86.9	)	$	24.3		$	4.9

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	(69.2		)	—			—			—			—			—
Settlements	(126.6		)	(41.1		)	(11.8		)	3.6			(32.3		)	(20.8		)
Transfers into Level 3 (c) (d)	(1.4		)	—			—			—			—			—
Transfers out of Level 3 (d)	(2.7		)	(0.7		)	(0.4		)	—			—			—
Changes in Fair Value Allocated to Regulated Jurisdictions (e)	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

183

Six Months Ended June 30, 2018	AEP			APCo			I&M			OPCo			PSO			SWEPCo
	(in millions)
Balance as of December 31, 2017	$	40.3		$	24.7		$	7.6		$	(132.4	)	$	6.2		$	5.9
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)	152.6			104.7			15.1			0.9			18.1			(4.8		)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)	8.0			—			—			—			—			—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income	7.6			—			—			—			—			—
Settlements	(204.6		)	(128.4		)	(22.1		)	2.5			(24.3		)	(1.3		)
Transfers into Level 3 (c) (d)	14.7			—			—			—			—			—
Transfers out of Level 3 (d)	(1.5		)	—			(0.3		)	—			—			—
Changes in Fair Value Allocated to Regulated Jurisdictions (e)	155.2			59.0			12.9			42.1			24.3			5.1
Balance as of June 30, 2018	$	172.3		$	60.0		$	13.2		$	(86.9	)	$	24.3		$	4.9

(a) Included in revenues on the statements of income.

(b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.

(c) Represents existing assets or liabilities that were previously categorized as Level 2.

(d) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.

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

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

AEP

Significant Unobservable Inputs

June 30, 2019

						Significant	Input/Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input	Low			High		Average
	(in millions)
Energy Contracts	$	331.6	$	340.0	Discounted Cash Flow	Forward Market Price (a)	$	(0.05	)	$	113.20	$	29.42
Natural Gas Contracts	—		3.8		Discounted Cash Flow	Forward Market Price (b)	1.96			2.69		2.33
FTRs	139.1		14.2		Discounted Cash Flow	Forward Market Price (a)	(7.42		)	7.87		0.43
Total	$	470.7	$	358.0

December 31, 2018

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

184

APCo

Significant Unobservable Inputs

June 30, 2019

						Significant	Input/Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input (a)	Low			High		Average
	(in millions)
Energy Contracts	$	10.1	$	2.5	Discounted Cash Flow	Forward Market Price	$	12.55		$	45.35	$	27.56
FTRs	65.6		4.7		Discounted Cash Flow	Forward Market Price	(0.88		)	6.81		1.37
Total	$	75.7	$	7.2

December 31, 2018

						Significant	Input/Range
	Fair Value				Valuation	Unobservable					Weighted
	Assets		Liabilities		Technique	Input (a)	Low		High		Average
	(in millions)
Energy Contracts	$	2.4	$	0.5	Discounted Cash Flow	Forward Market Price	$	16.82	$	62.65	$	37.00
FTRs	55.9		—		Discounted Cash Flow	Forward Market Price	0.10		15.16		3.27
Total	$	58.3	$	0.5

I&M

Significant Unobservable Inputs

June 30, 2019

						Significant	Input/Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input (a)	Low			High		Average
	(in millions)
Energy Contracts	$	5.9	$	1.5	Discounted Cash Flow	Forward Market Price	$	12.55		$	45.35	$	27.56
FTRs	9.7		1.8		Discounted Cash Flow	Forward Market Price	(1.07		)	3.76		0.67
Total	$	15.6	$	3.3

December 31, 2018

						Significant	Input/Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input (a)	Low			High		Average
	(in millions)
Energy Contracts	$	1.4	$	0.9	Discounted Cash Flow	Forward Market Price	$	16.82		$	62.65	$	37.00
FTRs	8.9		0.5		Discounted Cash Flow	Forward Market Price	(2.11		)	6.21		1.06
Total	$	10.3	$	1.4

185

OPCo

Significant Unobservable Inputs

June 30, 2019

Significant

Input/Range

Fair Value

Valuation

Unobservable

Weighted

Assets

Liabilities

Technique

Input (a)

Low

High

Average

(in millions)

Energy Contracts

$

—

$

111.5

Discounted Cash Flow

Forward Market Price

$

25.96

$

57.96

$

39.66

December 31, 2018

Significant

Input/Range

Fair Value

Valuation

Unobservable

Weighted

Assets

Liabilities

Technique

Input (a)

Low

High

Average

(in millions)

Energy Contracts

$

—

$

99.4

Discounted Cash Flow

Forward Market Price

$

26.29

$

62.74

$

42.50

PSO

Significant Unobservable Inputs

June 30, 2019

						Significant	Input/Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input (a)	Low			High		Average
	(in millions)
FTRs	$	28.4	$	0.6	Discounted Cash Flow	Forward Market Price	$	(6.94	)	$	0.63	$	(1.97	)

December 31, 2018

						Significant	Input/Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input (a)	Low			High		Average
	(in millions)
FTRs	$	10.8	$	1.3	Discounted Cash Flow	Forward Market Price	$	(11.68	)	$	10.30	$	(1.40	)

186

SWEPCo

Significant Unobservable Inputs

June 30, 2019

						Significant	Input/Range
	Fair Value				Valuation	Unobservable						Weighted
	Assets		Liabilities		Technique	Input	Low			High		Average
	(in millions)
Natural Gas Contracts	$	—	$	3.8	Discounted Cash Flow	Forward Market Price (b)	$	1.96		$	2.69	$	2.33
FTRs	12.5		0.2		Discounted Cash Flow	Forward Market Price (a)	(6.94		)	0.63		(1.97		)
Total	$	12.5	$	4.0

December 31, 2018

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

(a) Represents market prices in dollars per MWh.

(b) Represents market prices in dollars per MMBtu.

The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts, Natural Gas Contracts and FTRs for the Registrants as of June 30, 2019 and December 31, 2018:

Sensitivity of Fair Value Measurements

Significant Unobservable Input	Position	Change in Input	Impact on Fair Value Measurement
Forward Market Price	Buy	Increase (Decrease)	Higher (Lower)
Forward Market Price	Sell	Increase (Decrease)	Lower (Higher)

187

11.  INCOME TAXES

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

Status of Tax Reform Regulatory Proceedings

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

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

(a) A portion of the Excess ADIT that is not subject to rate normalization requirements is addressed in a current pending case.

(b) Rates have been implemented through a filed formula rate plan that is subject to true-up and final commission approval.

Effective Tax Rates (ETR)

The Registrants’ interim ETR reflect the estimated annual ETR for 2019 and 2018, adjusted for tax expense associated with certain discrete items. The interim ETR differ from the federal statutory tax rate of 21% primarily due to increased amortization of Excess ADIT, tax credits and other book/tax differences which are accounted for on a flow-through basis.

The Registrants include the amortization of Excess ADIT not subject to normalization requirements in the annual estimated ETR when regulatory proceedings instruct the Registrants to provide the benefits of Tax Reform to customers over multiple interim periods.  Certain regulatory proceedings instruct the Registrants to provide the benefits of Tax Reform to customers in a single period (e.g. by applying the Excess ADIT not subject to normalization requirements against an existing regulatory asset balance) and in these circumstances, the Registrants recognize the tax benefit discretely in the period recorded. The annual amount of Excess ADIT approved by the Registrant’s regulatory commissions may not impact the ETR ratably during each interim period due to the variability of pretax book income between interim periods and the application of an annual estimated ETR.

The ETR for each of the Registrants are included in the following table. Significant variances in the ETR are described below.

	Three Months Ended June 30,				Six Months Ended June 30,
Company	2019		2018		2019		2018
AEP	(13.5	)%	12.0	%	(1.0	)%	15.0	%
AEP Texas	(234.4	)%	16.2	%	(84.0	)%	16.2	%
AEPTCo	19.5	%	22.7	%	20.1	%	21.7	%
APCo	(52.1	)%	17.0	%	(29.5	)%	17.8	%
I&M	(0.2	)%	0.7	%	(1.8	)%	7.6	%
OPCo	16.4	%	21.6	%	14.3	%	21.0	%
PSO	0.7	%	14.9	%	0.6	%	14.5	%
SWEPCo	—	%	12.4	%	2.0	%	14.0	%

188

AEP

Three Months Ended June 30, 2019 Compared to Three Months Ended June 30, 2018

The decrease in the ETR was primarily due to $97 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (25.4)%.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

The decrease in the ETR was primarily due to $164 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (16.2)%.

AEP Texas

Three Months Ended June 30, 2019 Compared to Three Months Ended June 30, 2018

The decrease in the ETR was primarily due to $58 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (239.7)%. Amortization of Excess ADIT not subject to normalization requirements for the three months ended June 30, 2019 reflects Tax Reform elements of the Stipulation and Settlement agreement approved by the PUCT in August 2018 and the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019. The impact of the Texas Storm Cost Securitization financing order was treated as a discrete item.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

The decrease in the ETR was primarily due to $59 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (95.0)%. Amortization of Excess ADIT not subject to normalization requirements for the six months ended June 30, 2019 reflects Tax Reform elements of the Stipulation and Settlement agreement approved by the PUCT in August 2018 and the Texas Storm Cost Securitization financing order issued by the PUCT in June 2019. The impact of the Texas Storm Cost Securitization financing order was treated as a discrete item.

AEPTCo

Three Months Ended June 30, 2019 Compared to Three Months Ended June 30, 2018

The decrease in the ETR was primarily due to the FERC order issued in May 2019 regarding the 2018 ROE settlement and its $3 million impact on AFUDC equity which impacted the ETR by (1.7)%. See “FERC Transmission Complaint - AEP’s PJM Participants” section of Note 4 for additional information.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

The decrease in the ETR was primarily due to the FERC order issued in May 2019 regarding the 2018 ROE settlement and its $3 million impact on AFUDC equity which impacted the ETR by (0.9)%. See “FERC Transmission Complaint - AEP’s PJM Participants” section of Note 4 for additional information.

APCo

Three Months Ended June 30, 2019 Compared to Three Months Ended June 30, 2018

The decrease in the ETR was primarily due to $24 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (65.9)%. Amortization of Excess ADIT not subject to normalization requirements for the three months ended June 30, 2019 reflects the October 2018 and March 2019 Virginia SCC Tax Reform orders as well as the August 2018 and February 2019 WVPSC orders.

189

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

The decrease in the ETR was primarily due to $65 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (44.8)%. Amortization of Excess ADIT not subject to normalization requirements for the six months ended June 30, 2019 reflects the October 2018 and March 2019 Virginia SCC Tax Reform orders as well as the August 2018 and February 2019 WVPSC orders.

I&M

Three Months Ended June 30, 2019 Compared to Three Months Ended June 30, 2018

The decrease in the ETR was primarily due to $4 million of increased favorable book/tax differences accounted for on a flow-through basis partially offset by $2 million of increased state income tax expenses which impacted the ETR by (5.4)% and 3.2%, respectively.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

The decrease in the ETR was primarily due to $9 million of increased favorable book/tax differences accounted for on a flow-through basis and $8 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (5.7)% and (5.8)%, respectively. The decrease in ETR was partially offset by $5 million of increased state income tax expenses which impacted the ETR by 3.1%. Amortization of Excess ADIT not subject to normalization requirements for the six months ended June 30, 2019 reflects the Tax Reform elements of the 2017 Indiana Base Rate Case approved by the IURC in May 2018.

OPCo

Three Months Ended June 30, 2019 Compared to Three Months Ended June 30, 2018

The decrease in the ETR was primarily due to $2 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (4)%. Amortization of Excess ADIT not subject to normalization requirements for the three months ended June 30, 2019 reflects the October 2018 PUCO Tax Reform order.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

The decrease in the ETR was primarily due to $11 million of increased amortization of Excess ADIT not subject to normalization requirements which impacted the ETR by (5.1)%. Amortization of Excess ADIT not subject to normalization requirements for the six months ended June, 2019 reflects the October 2018 PUCO Tax Reform order.

PSO

Three Months Ended June 30, 2019 Compared to Three Months Ended June 30, 2018

The decrease in the ETR was primarily due to $7 million of increased amortization of Excess ADIT not subject to normalization requirements partially offset by $1 million of decreased amortization of Excess ADIT subject to normalization requirements which impacted the ETR by (16.9)%, and 2.4%, respectively. Amortization of Excess ADIT not subject to normalization requirements for the three months ended June 30, 2019 reflects the August 2018 OCC Tax Reform order as well as Tax Reform elements of the 2018 Oklahoma Base Rate Case approved by the OCC in March 2019.

190

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

The decrease in the ETR was primarily due to $8 million of increased amortization of Excess ADIT not subject to normalization requirements partially offset by decreased amortization of Excess ADIT subject to normalization requirements which impacted the ETR by (16.9)% and 2.7%, respectively. Amortization of Excess ADIT not subject to normalization requirements for the six months ended June 30, 2019 reflects the August 2018 OCC Tax Reform order as well as Tax Reform elements of the 2018 Oklahoma Base Rate Case approved by the OCC in March 2019.

SWEPCo

Three Months Ended June 30, 2019 Compared to Three Months Ended June 30, 2018

The decrease in the ETR was primarily due to $1 million of increased amortization of Excess ADIT not subject to normalization requirements and $1 million of decreased state tax expenses which impacted the ETR by (8.4)% and (1.3)%, respectively. Amortization of Excess ADIT not subject to normalization requirements for the three months ended June 30, 2019 reflects Tax Reform elements incorporated into the Louisiana 2018 Formula Rate Filing as well as the Arkansas Tax Reform order issued by the APSC in September 2018.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

The decrease in the ETR was primarily due to $4 million of increased amortization of Excess ADIT not subject to normalization requirements and $1 million of decreased state tax expenses which impacted the ETR by (10.8)% and (1.2)%, respectively. Amortization of Excess ADIT not subject to normalization requirements for the six months ended June 30, 2019 reflects Tax Reform elements incorporated into the Louisiana 2018 Formula Rate Filing as well as the Arkansas Tax Reform order issued by the APSC in September 2018.

Federal and State Income Tax Audit Status

The IRS has completed its examination of AEP and subsidiaries for all years through 2016.

AEP and subsidiaries file income tax returns in various state and local jurisdictions.  These taxing authorities routinely examine the tax returns. AEP and subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2007.

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

In April 2018, the Kentucky legislature enacted House Bill (H.B.) 487. H.B. 487 adopts mandatory unitary combined reporting for state corporate income tax purposes applicable for taxable years beginning on or after January 1, 2019. H.B. 487 also adopts the 80% federal net operating loss (NOL) limitation under Internal Revenue Code Sec. 172(a) for NOLs generated after January 1, 2018 and the federal unlimited carryforward period for unused NOLs generated after January 1, 2018. In addition, H.B. 366 was also enacted in April 2018, which among other things, replaces the graduated corporate tax rate structure with a flat 5% tax rate for business income and adopts a single-sales factor apportionment formula for apportioning a corporation’s business income to Kentucky. In the second quarter of 2018, AEP recorded an $18 million benefit to Income Tax Expense (Benefit) as a result of remeasuring Kentucky deferred taxes under a unitary filing group. The enacted legislation did not materially impact AEPTCo’s, I&M’s or OPCo’s net income.

191

12.  LEASES

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

The Registrants lease property, plant and equipment including, but not limited to, fleet, information technology and real estate leases. These leases require payments of non-lease components, including related property taxes, operating and maintenance costs. As of the adoption date of ASU 2016-02, management elected not to separate non-lease components from associated lease components in accordance with the accounting guidance for “Leases.”  Many of these leases have purchase or renewal options. Leases not renewed are often replaced by other leases. Options to renew or purchase a lease are included in the measurement of lease assets and liabilities if it is reasonably certain the Registrant will exercise the option.

Lease obligations are measured using the discount rate implicit in the lease when that rate is readily determinable. When the implicit rate is not readily determinable, the Registrants measure their lease obligation using their estimated secured incremental borrowing rate. Incremental borrowing rates are comprised of an underlying risk free rate and a secured credit spread relative to the lessee on a matched maturity basis.

Lease rentals for both operating and finance leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations.  Additionally, for regulated operations with finance leases, a finance lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period.  Finance leases for nonregulated property are accounted for as if the assets were owned and financed.  The components of rental costs were as follows:

Three Months Ended June 30, 2019	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Operating Lease Cost	$	71.3	$	4.4	$	0.5	$	5.0	$	23.3	$	5.3	$	2.0	$	2.1
Finance Lease Cost:
Amortization of Right-of-Use Assets	14.3		1.2		—		1.5		1.3		0.8		0.7		2.7
Interest on Lease Liabilities	4.0		0.4		—		0.7		0.7		0.1		0.2		0.7
Total Lease Rental Costs (a)	$	89.6	$	6.0	$	0.5	$	7.2	$	25.3	$	6.2	$	2.9	$	5.5

Six Months Ended June 30, 2019	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Operating Lease Cost	$	135.9	$	8.2	$	1.1	$	9.6	$	46.3	$	8.9	$	3.5	$	3.9
Finance Lease Cost:
Amortization of Right-of-Use Assets	28.5		2.3		—		3.0		2.6		1.5		1.4		5.4
Interest on Lease Liabilities	8.1		0.7		—		1.4		1.5		0.3		0.3		1.5
Total Lease Rental Costs (a)	$	172.5	$	11.2	$	1.1	$	14.0	$	50.4	$	10.7	$	5.2	$	10.8

(a) Excludes variable and short-term lease costs, which were immaterial for the three and six months ended June 30, 2019.

192

Supplemental information related to leases are shown in the tables below:

June 30, 2019	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
Weighted-Average Remaining Lease Term (years):
Operating Leases	5.45		7.19		2.53		6.34		4.25		8.19		7.12		6.67
Finance Leases	5.88		7.00		0.83		6.26		6.79		6.42		6.02		5.44
Weighted-Average Discount Rate:
Operating Leases	3.63	%	3.82	%	3.15	%	3.68	%	3.46	%	3.83	%	3.71	%	3.87	%
Finance Leases	6.16	%	4.79	%	9.33	%	8.55	%	8.97	%	4.80	%	4.77	%	5.01	%

Six Months Ended June 30, 2019	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Cash paid for amounts included in the measurement of lease liabilities:
Operating Cash Flows from Operating Leases	$	132.3	$	7.5	$	1.1	$	9.5	$	47.0	$	8.5	$	3.2	$	3.7
Operating Cash Flows from Finance Leases	8.1		0.7		—		1.4		1.5		0.3		0.3		1.5
Financing Cash Flows from Finance Leases	29.6		2.5		—		3.1		2.7		1.8		1.5		5.5
Non-cash Acquisitions Under Operating Leases	$	84.2	$	10.7	$	—	$	7.0	$	11.3	$	30.0	$	6.2	$	7.5

The following tables show the property, plant and equipment under finance leases and noncurrent assets under operating leases and related obligations recorded on the Registrants’ balance sheets.  Unless shown as a separate line on the balance sheets due to materiality, net operating lease assets are included in Deferred Charges and Other Noncurrent Assets, current finance lease obligations are included in Other Current Liabilities and long-term finance lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the Registrants’ balance sheets. Lease obligations are not recognized on the balance sheets for lease agreements with a lease term of less than twelve months.

June 30, 2019	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Property, Plant and Equipment Under Finance Leases:
Generation	$	131.2	$	—	$	—	$	38.6	$	27.0	$	—	$	2.6	$	34.3
Other Property, Plant and Equipment	325.5		40.9		0.2		20.4		35.4		23.0		19.1		48.3
Total Property, Plant and Equipment	456.7		40.9		0.2		59.0		62.4		23.0		21.7		82.6
Accumulated Amortization	154.3		10.6		0.1		16.7		22.0		6.5		8.6		22.8
Net Property, Plant and Equipment Under Finance Leases	$	302.4	$	30.3	$	0.1	$	42.3	$	40.4	$	16.5	$	13.1	$	59.8
Obligations Under Finance Leases:
Noncurrent Liability	$	247.1	$	25.3	$	—	$	35.7	$	34.9	$	13.2	$	10.0	$	49.7
Liability Due Within One Year	59.6		5.0		0.1		6.6		5.5		3.3		3.1		10.9
Total Obligations Under Finance Leases	$	306.7	$	30.3	$	0.1	$	42.3	$	40.4	$	16.5	$	13.1	$	60.6

June 30, 2019	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Operating Lease Assets	$	1,016.5	$	80.9	$	5.4	$	78.3	$	312.6	$	88.2	$	35.1	$	37.3
Obligations Under Operating Leases:
Noncurrent Liability	$	797.2	$	69.9	$	2.8	$	63.8	$	234.7	$	75.4	$	29.3	$	31.5
Liability Due Within One Year	229.2		11.6		2.6		14.9		82.2		13.2		5.9		6.0
Total Obligations Under Operating Leases	$	1,026.4	$	81.5	$	5.4	$	78.7	$	316.9	$	88.6	$	35.2	$	37.5

193

Future minimum lease payments as of June 30, 2019 are presented on a rolling 12-month basis as shown in the tables below:

Finance Leases	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Year 1	$	75.1	$	6.3	$	0.1	$	9.5	$	8.5	$	4.0	$	3.6	$	13.1
Year 2	65.0		5.9		—		8.7		7.8		3.6		2.9		11.4
Year 3	56.2		5.2		—		7.9		7.1		3.0		2.2		10.6
Year 4	47.4		4.7		—		7.4		6.6		2.3		1.8		9.4
Year 5	44.2		4.0		—		6.9		6.3		1.9		1.5		12.8
Later Years	84.0		10.2		—		13.0		21.6		4.8		3.4		10.6
Total Future Minimum Lease Payments	371.9		36.3		0.1		53.4		57.9		19.6		15.4		67.9
Less Imputed Interest	65.2		6.0		—		11.1		17.5		3.1		2.3		7.3
Estimated Present Value of Future Minimum Lease Payments	$	306.7	$	30.3	$	0.1	$	42.3	$	40.4	$	16.5	$	13.1	$	60.6

Operating Leases	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Year 1	$	265.4	$	15.3	$	2.8	$	18.0	$	92.5	$	16.4	$	7.0	$	8.0
Year 2	253.1		14.7		1.7		16.1		89.4		14.3		6.4		7.9
Year 3	237.7		13.6		0.7		14.3		86.0		12.9		5.6		7.1
Year 4	154.4		12.6		0.5		12.6		48.3		12.1		5.2		6.7
Year 5	63.0		11.1		—		9.6		7.7		10.5		4.6		5.4
Later Years	182.6		28.4		—		19.8		21.9		38.9		12.0		11.4
Total Future Minimum Lease Payments	1,156.2		95.7		5.7		90.4		345.8		105.1		40.8		46.5
Less Imputed Interest	129.8		14.2		0.3		11.7		28.9		16.5		5.6		9.0
Estimated Present Value of Future Minimum Lease Payments	$	1,026.4	$	81.5	$	5.4	$	78.7	$	316.9	$	88.6	$	35.2	$	37.5

Future minimum lease payments consisted of the following as of December 31, 2018:

Finance Leases	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
2019	$	70.8	$	5.8	$	0.1	$	9.0	$	8.2	$	3.3	$	3.4	$	13.1
2020	60.2		5.3		—		8.0		7.2		2.7		2.6		11.5
2021	51.7		4.7		—		7.3		6.6		2.3		2.0		10.5
2022	43.8		4.2		—		6.8		6.1		1.7		1.6		9.4
2023	35.5		3.7		—		6.3		5.7		1.2		1.4		8.6
Later Years	90.2		10.1		—		13.3		21.7		2.8		3.3		18.7
Total Future Minimum Lease Payments	352.2		33.8		0.1		50.7		55.5		14.0		14.3		71.8
Less Imputed Interest	63.2		5.3		—		10.9		16.8		1.9		2.0		11.0
Estimated Present Value of Future Minimum Lease Payments	$	289.0	$	28.5	$	0.1	$	39.8	$	38.7	$	12.1	$	12.3	$	60.8

Operating Leases	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
2019	$	259.6	$	15.1	$	2.3	$	17.6	$	92.6	$	14.5	$	6.5	$	7.4
2020	250.1		14.1		1.8		16.5		89.3		13.2		6.0		7.2
2021	232.7		13.2		1.0		13.9		84.8		10.9		5.0		6.7
2022	222.5		12.2		0.5		12.8		83.8		10.0		4.6		6.1
2023	58.3		10.8		0.1		9.9		6.5		8.8		4.1		5.0
Later Years	165.2		28.4		—		20.5		19.5		31.7		10.7		11.7
Total Future Minimum Lease Payments	$	1,188.4	$	93.8	$	5.7	$	91.2	$	376.5	$	89.1	$	36.9	$	44.1

194

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, 2019, the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows:

Company	Maximum Potential Loss
	(in millions)
AEP	$	46.1
AEP Texas	10.9
APCo	6.1
I&M	4.0
OPCo	7.7
PSO	4.1
SWEPCo	4.4

Rockport Lease (Applies to AEP and I&M)

AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant).  The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors. In the first quarter of 2019, in accordance with ASU 2016-02, the $37 million unamortized gain ($15 million related to I&M) associated with the sale-and-leaseback of the Plant was recognized as an adjustment to equity.  The adjustment to equity was then reclassified to regulatory liabilities in accordance with accounting guidance for “Regulated Operations” as AEGCo and I&M will continue to provide the benefit of the unamortized gain to customers in future periods.

The Owner Trustee owns the Plant and leases equal portions to AEGCo and I&M.  The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note.  The lease term is for 33 years and at the end of the lease term, AEGCo and I&M have the option to renew the lease at a rate that approximates fair value.  The option to renew was not included in the measurement of the lease obligation as of June 30, 2019 as the execution of the option was not reasonably certain. AEP, AEGCo and I&M have no ownership interest in the Owner Trustee and do not guarantee its debt.  The future minimum lease payments for this sale-and-leaseback transaction as of June 30, 2019 were as follows:

Future Minimum Lease Payments	AEP (a)		I&M
	(in millions)
2019	$	74.2	$	37.1
2020	147.8		73.9
2021	147.8		73.9
2022	147.2		73.6
Total Future Minimum Lease Payments	$	517.0	$	258.5

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

195

AEPRO Boat and Barge Leases (Applies to AEP)

In 2015, AEP sold its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. Certain boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of June 30, 2019, the maximum potential amount of future payments required under the guaranteed leases was $58 million. In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee. As of June 30, 2019, AEP’s boat and barge lease guarantee liability was $5 million, of which $1 million was recorded in Other Current Liabilities and $4 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheet.

In January 2018, S&P Global Inc. downgraded the ratings of the nonaffiliated party and set their outlook to negative. In April 2018, Moody’s Investors Service Inc. (Moody’s) also downgraded their rating and set their outlook to negative. Moody’s further downgraded their rating in April 2019 and maintained a negative outlook. It is reasonably possible that enforcement of AEP’s liability for future payments under these leases could be exercised, which could reduce future net income and cash flows and impact financial condition.

Lessor Activity

The Registrants’ lessor activity was immaterial as of and for the three and six months ended June 30, 2019.

196

13.  FINANCING ACTIVITIES

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

Long-term Debt Outstanding (Applies to AEP)

The following table details long-term debt outstanding, net of issuance costs and premiums or discounts:

Type of Debt	June 30, 2019		December 31, 2018
	(in millions)
Senior Unsecured Notes	$	20,468.9	$	18,903.3
Pollution Control Bonds	1,518.1		1,643.8
Notes Payable	216.9		204.7
Securitization Bonds	945.2		1,111.4
Spent Nuclear Fuel Obligation (a)	277.0		273.6
Junior Subordinated Notes (b)	786.1		—
Other Long-term Debt	1,219.6		1,209.9
Total Long-term Debt Outstanding	25,431.8		23,346.7
Long-term Debt Due Within One Year	1,257.4		1,698.5
Long-term Debt	$	24,174.4	$	21,648.2

(a) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for SNF disposal.  The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983.  Trust fund assets related to this obligation were $320 million and $317 million as of June 30, 2019 and December 31, 2018, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.

(b) See “Equity Units” section below for additional information.

Long-term Debt Activity

Long-term debt and other securities issued, retired and principal payments made during the first six months of 2019 are shown in the following tables:

		Principal		Interest
Company	Type of Debt	Amount (a)		Rate	Due Date
Issuances:		(in millions)		(%)
AEP	Junior Subordinated Notes (b)	$	805.0	3.40	2024
AEP Texas	Senior Unsecured Notes	300.0		4.15	2049
AEPTCo	Senior Unsecured Notes	350.0		3.80	2049
APCo	Pollution Control Bonds	86.0		2.55	2024
APCo	Senior Unsecured Notes	400.0		4.50	2049
I&M	Notes Payable	62.8		Variable	2023
OPCo	Senior Unsecured Notes	450.0		4.00	2049
PSO	Senior Unsecured Notes	100.0		3.91	2029
PSO	Senior Unsecured Notes	150.0		4.11	2034
PSO	Senior Unsecured Notes	100.0		4.50	2049
Non-Registrant:
Transource Energy	Other Long-term Debt	12.6		Variable	2020
Total Issuances		$	2,816.4

(a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.

(b) See “Equity Units” section below for additional information.

197

		Principal		Interest
Company	Type of Debt	Amount Paid		Rate	Due Date
Retirements and Principal Payments:		(in millions)		(%)
AEP Texas	Senior Unsecured Notes	$	50.0	2.61	2019
AEP Texas	Securitization Bonds	103.5		5.31	2020
AEP Texas	Securitization Bonds	28.3		1.98	2020
APCo	Pollution Control Bonds	86.0		1.90	2019
APCo	Pollution Control Bonds	70.0		3.25	2019
APCo	Securitization Bonds	12.0		2.01	2023
I&M	Notes Payable	2.7		Variable	2019
I&M	Notes Payable	2.9		Variable	2019
I&M	Notes Payable	13.1		Variable	2020
I&M	Notes Payable	11.9		Variable	2021
I&M	Notes Payable	6.2		Variable	2022
I&M	Notes Payable	10.6		Variable	2022
I&M	Notes Payable	0.1		Variable	2023
I&M	Other Long-term Debt	0.8		6.00	2025
OPCo	Securitization Bonds	23.3		2.05	2019
OPCo	Other Long-term Debt	0.1		1.15	2028
PSO	Senior Unsecured Notes	250.0		5.15	2019
PSO	Other Long-term Debt	0.2		3.00	2027
SWEPCo	Pollution Control Bonds	53.5		1.60	2019
SWEPCo	Other Long-term Debt	1.5		4.68	2028
SWEPCo	Notes Payable	1.6		4.58	2032
Total Retirements and Principal Payments		$	728.3

As of June 30, 2019, trustees held, on behalf of AEP, $574 million of their reacquired Pollution Control Bonds. Of this total, $345 million relates to OPCo.

Long-term Debt Subsequent Events

In July 2019, AEP Texas retired $84 million of Securitization Bonds.

In July 2019, I&M retired $6 million of Notes Payable related to DCC Fuel.

In July 2019, OPCo retired $25 million of Securitization Bonds.

In July 2019, AEGCo reacquired $45 million of variable rate Pollution Control Bonds, which are being held in trust.

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

Equity Units (Applies to AEP)

In March 2019, AEP issued 16.1 million Equity Units initially in the form of corporate units, at a stated amount of $50 per unit, for a total stated amount of $805 million. Net proceeds from the issuance were approximately $785 million. The proceeds were used to support AEP’s overall capital expenditure plans including the recent 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%.

198

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 0.3% of consolidated tangible net assets as of June 30, 2019. The method for calculating the consolidated tangible net assets is contractually-defined in the note purchase agreements.

Dividend Restrictions

Utility Subsidiaries’ Restrictions

Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends.

All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. However, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M.

Certain AEP subsidiaries have credit agreements that contain covenants that limit their debt to capitalization ratio to 67.5%. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements.

The Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings.

199

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, 2019 and December 31, 2018 are included in Advances to Affiliates and Advances from Affiliates, respectively, on the Registrant Subsidiaries’ balance sheets.  The Utility Money Pool participants’ activity and corresponding authorized borrowing limits for the six months ended June 30, 2019 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, 2019			Limit
	(in millions)
AEP Texas	$	390.7	$	—	$	262.7	$	—	$	(239.0	)	$	500.0
AEPTCo	374.9		80.0		215.7		29.2		14.7			795.0		(a)
APCo	225.4		232.2		146.3		82.2		(3.4		)	600.0
I&M	98.2		66.0		32.0		19.3		(81.7		)	500.0
OPCo	291.2		178.6		194.4		98.8		63.9			500.0
PSO	140.5		215.6		67.3		206.2		(22.6		)	300.0
SWEPCo	105.1		81.4		67.0		24.0		(55.3		)	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, 2019 and December 31, 2018 are included in Advances to Affiliates on the subsidiaries’ balance sheets. The Nonutility Money Pool participants’ activity for the six months ended June 30, 2019 is described in the following table:

		Maximum Loans		Average Loans		Loans to the Nonutility
		to the Nonutility		to the Nonutility		Money Pool as of
Company		Money Pool		Money Pool		June 30, 2019
	(in millions)
AEP Texas		$	8.0	$	7.7	$	7.7
SWEPCo		2.0		2.0		2.0

200

AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of outstanding loans to (borrowings from) AEP as of June 30, 2019 and December 31, 2018 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct borrowing and lending activity with AEP and corresponding authorized borrowing limit for the six months ended June 30, 2019 are described in the following table:

Maximum

Maximum

Average

Average

Borrowings from

Loans to

Authorized

Borrowings

Loans

Borrowings

Loans

AEP as of

AEP as of

Short-term

from AEP

to AEP

from AEP

to AEP

June 30, 2019

June 30, 2019

Borrowing Limit

(in millions)

$

1.3

$

117.6

$

1.3

$

63.3

$

1.3

$

17.3

$

75.0

(a)

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

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool are summarized in the following table:

	Six Months Ended June 30,
	2019		2018
Maximum Interest Rate	3.02	%	2.52	%
Minimum Interest Rate	2.68	%	1.83	%

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	2019		2018		2019		2018
AEP Texas	2.81	%	2.28	%	—	%	2.28	%
AEPTCo	2.78	%	2.30	%	2.83	%	2.06	%
APCo	2.91	%	2.23	%	2.77	%	2.23	%
I&M	2.74	%	2.16	%	2.82	%	2.37	%
OPCo	2.81	%	2.24	%	2.73	%	2.47	%
PSO	2.85	%	2.24	%	2.74	%	—	%
SWEPCo	2.77	%	2.34	%	2.97	%	1.88	%

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, 2019

Six Months Ended June 30, 2018

Maximum

Minimum

Average

Maximum

Minimum

Average

Interest Rate

Interest Rate

Interest Rate

Interest Rate

Interest Rate

Interest Rate

for Funds

for Funds

for Funds

for Funds

for Funds

for Funds

Loaned to

Loaned to

Loaned to

Loaned to

Loaned to

Loaned to

the Nonutility

the Nonutility

the Nonutility

the Nonutility

the Nonutility

the Nonutility

Company

Money Pool

Money Pool

Money Pool

Money Pool

Money Pool

Money Pool

AEP Texas

3.02

%

2.68

%

2.81

%

2.52

%

1.83

%

2.23

%

SWEPCo

3.02

%

2.68

%

2.81

%

2.52

%

1.83

%

2.23

%

201

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
2019	3.02	%	2.68	%	3.02	%	2.68	%	2.81	%	2.80	%
2018	2.52	%	1.83	%	2.52	%	1.83	%	2.23	%	2.23	%

Short-term Debt (Applies to AEP)

Outstanding short-term debt was as follows:

	June 30, 2019				December 31, 2018
	Outstanding		Interest		Outstanding		Interest
Type of Debt	Amount		Rate (a)		Amount		Rate (a)
	(dollars in millions)
Securitized Debt for Receivables (b)	$	692.0	2.66	%	$	750.0	2.16	%
Commercial Paper	1,585.0		2.67	%	1,160.0		2.96	%
Total Short-term Debt	$	2,277.0			$	1,910.0

(a) Weighted-average rate.

(b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 5.

Securitized Accounts 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 includes a $125 million and a $625 million facility which expire in July 2020 and 2021, respectively. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries.  These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections. Accounts receivable information for AEP Credit was as follows:

	Three Months Ended  June 30,						Six Months Ended  June 30,
	2019			2018			2019			2018
	(dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable	2.60		%	2.16		%	2.66		%	1.95		%
Net Uncollectible Accounts Receivable Written-Off	$	4.6		$	5.3		$	11.0		$	9.4

	June 30, 2019		December 31, 2018
	(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts	$	907.8	$	972.5
Short-term – Securitized Debt of Receivables	692.0		750.0
Delinquent Securitized Accounts Receivable	49.9		50.3
Bad Debt Reserves Related to Securitization	32.5		27.5
Unbilled Receivables Related to Securitization	298.5		281.4

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

202

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, 2019		December 31, 2018
	(in millions)
APCo	$	114.2	$	133.3
I&M	153.6		152.9
OPCo	342.9		395.2
PSO	127.7		109.7
SWEPCo	153.7		150.3

The fees paid to AEP Credit for customer accounts receivable sold were:

	Three Months Ended June 30,				Six Months Ended June 30,
Company	2019		2018		2019		2018
	(in millions)
APCo	$	2.4	$	1.6	$	4.6	$	3.3
I&M	3.2		2.2		6.0		4.3
OPCo	7.9		6.0		15.7		11.6
PSO	2.1		1.9		4.2		3.7
SWEPCo	3.4		2.1		6.0		4.0

The proceeds on the sale of receivables to AEP Credit were:

	Three Months Ended June 30,				Six Months Ended June 30,
Company	2019		2018		2019		2018
	(in millions)
APCo	$	300.8	$	344.9	$	675.2	$	745.1
I&M	415.0		444.2		893.6		903.3
OPCo	506.7		671.7		1,143.5		1,351.7
PSO	342.6		383.7		667.1		716.4
SWEPCo	394.5		454.5		766.4		852.0

203

14. VARIABLE INTEREST ENTITIES AND EQUITY METHOD INVESTMENTS

The disclosures in this note apply to AEP only.

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a variable interest in a VIE.  A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently.

AEP holds ownership interests in businesses with varying ownership structures. Partnership interests and other variable interests are evaluated to determine if each entity is a VIE, and if so, whether or not the VIE should be consolidated into AEP’s financial statements. If an entity is determined not to be a VIE, or if the entity is determined to be a VIE and AEP is not deemed to be the primary beneficiary, the entity is accounted for under the equity method of accounting. The Variable Interest Entities note within the 2018 Annual Report should be read in conjunction with this report as this note only includes significant changes to AEP’s VIEs and equity method investments during 2019.

Consolidated Variable Interests Entities

In April 2019, AEP acquired an equity interest in Apple Blossom Wind Holdings LLC (Apple Blossom) and Black Oak Getty Wind Holdings LLC (Black Oak) (“the Project Entities”) as part of the purchase of Sempra Renewables LLC. Both of the Project Entities have long-term PPAs for 100% of their energy production. The Project Entities are tax equity partnerships with nonaffiliated noncontrolling interests to which a percentage of earnings, tax attributes and cash flows are allocated in accordance with the respective limited liability company agreements. Management has concluded that the Project Entities are VIEs and that AEP is the primary beneficiary based on its power as managing member to direct the activities that most significantly impact the Project Entity’s economic performance. In addition, AEP has not provided material financial or other support to the Project Entities that was not previously contractually required. As the primary beneficiary of the Project Entities, AEP consolidates the Project Entities into its financial statements. See the table below for the classification of Project Entities’ assets and liabilities on the balance sheet:

American Electric Power Company, Inc.
Variable Interest Entities
June 30, 2019
	Apple Blossom and Black Oak
	(in millions)
ASSETS
Current Assets	$	8.6
Net Property, Plant and Equipment	235.4
Other Noncurrent Assets	14.0
Total Assets	$	258.0
LIABILITIES AND EQUITY
Current Liabilities	$	6.8
Noncurrent Liabilities	4.6
Equity	246.6
Total Liabilities and Equity	$	258.0

204

The nonaffiliated interests in the Project Entities is presented in Noncontrolling Interests on the balance sheets.  As of June 30, 2019, AEP recorded $131 million of Noncontrolling Interests related to the Project Entities in Equity on the balance sheets.

The Project Entities’ tax equity partnerships represent substantive profit-sharing arrangements. The method for attributing income and loss to the noncontrolling interests is a balance sheet approach referred to as the hypothetical liquidation at book value (HLBV) method. Under the HLBV method, the income and loss attributable to the noncontrolling interests reflect changes in the amounts the members would hypothetically receive at each balance sheet date under the liquidation provisions of the respective limited liability company agreements, assuming the net assets of these entities were liquidated at recorded amounts, after taking into account any capital transactions, such as contributions or distributions, between the entities and the members. For the three and six months ended June 30, 2019, the HLBV method resulted in a $4 million loss allocated to Noncontrolling Interests.

Significant Equity Method Investments in Unconsolidated Entities

The equity method of accounting is used for equity investments where AEP exercises significant influence but does not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings or losses is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. AEP regularly monitors and evaluates equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature.

Sempra Renewables LLC

In April 2019, AEP acquired a 50% interest in five wind farms in multiple states as part of the purchase of Sempra Renewables LLC. The wind farms are joint ventures with BP Wind Energy who holds the other 50% interest. All five wind farms have long-term PPAs for 100% of their energy production. One of the jointly-owned wind farms has PPAs with I&M and OPCo for a portion of its energy production. Another jointly-owned wind farm has a PPA with SWEPCo for a portion of its energy production. The joint venture wind farms are not considered VIEs and AEP is not required to consolidate them as AEP does not have a controlling financial interest. However, AEP is able to exercise significant influence over the wind farms and therefore applies the equity method of accounting. As of June 30, 2019, AEP’s investment in the five joint venture wind farms was $403 million. The investment includes amounts recognized in AOCI related to interest rate cash flow hedges. The investment is comprised of a historical investment of $425 million plus a basis difference of $(19) million. AEP’s equity earnings associated with the five joint venture wind farms was a $3 million loss for the three and six months ended June 30, 2019. AEP recognized $14 million of production tax credits attributable to the joint venture wind farms for the three and six months ended June 30, 2019 which is recorded in Income Tax Expense (Benefit) on the statements of income.

ETT

ETT designs, acquires, constructs, owns and operates certain transmission facilities in ERCOT. Berkshire Hathaway Energy, a nonaffiliated entity, holds a 50%membership interest in ETT, AEP Transmission Holdco a 49.5% interest in ETT and AEP Transmission Partner held the remaining 0.5% membership interest in ETT. On July 1, 2019 AEP Transmission Partner was merged into AEP Transmission Holdco, increasing AEP Transmission Holdco’s interest in ETT to 50%. As a result, AEP, through its wholly-owned subsidiary, holds a 50% membership interest in ETT. As of June 30, 2019 and December 31, 2018, AEP’s investment in ETT was $677 million and $666 million, respectively. AEP’s equity earnings associated with ETT were $16 million and $15 million for the three months ended June 30, 2019 and 2018, respectively. AEP’s equity earnings associated with ETT were $33 million and $31 million for the six months ended June 30, 2019 and 2018, respectively.

205

15. 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, 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
Marketing, Competitive Retail and Renewable Revenues	—			—		—			106.9			—		—			106.9
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 is $34 million. The remaining affiliated amounts are immaterial.

(b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco is $201 million. The remaining affiliated amounts are immaterial.

(c) Amounts include affiliated and nonaffiliated revenues.

206

	Three Months Ended June 30, 2018
	Vertically Integrated Utilities			Transmission and Distribution Utilities			AEP Transmission Holdco			Generation & Marketing		Corporate and Other		Reconciling Adjustments			AEP Consolidated
	(in millions)
Retail Revenues:
Residential Revenues	$	857.0		$	530.9		$	—		$	—	$	—	$	—		$	1,387.9
Commercial Revenues	551.9			320.1			—			—		—		—			872.0
Industrial Revenues	570.7			134.2			—			—		—		—			704.9
Other Retail Revenues	46.4			10.9			—			—		—		—			57.3
Total Retail Revenues (a)	2,026.0			996.1			—			—		—		—			3,022.1
Wholesale and Competitive Retail Revenues:
Generation Revenues (b)	245.3			—			—			126.1		—		(26.6		)	344.8
Transmission Revenues (c)	60.6			90.5			213.0			—		—		(99.3		)	264.8
Marketing, Competitive Retail and Renewable Revenues	—			—			—			331.4		—		—			331.4
Total Wholesale and Competitive Retail Revenues	305.9			90.5			213.0			457.5		—		(125.9		)	941.0
Other Revenues from Contracts with Customers (d)	41.6			45.5			8.4			0.1		21.3		(22.6		)	94.3
Total Revenues from Contracts with Customers	2,373.5			1,132.1			221.4			457.6		21.3		(148.5		)	4,057.4
Other Revenues:
Alternative Revenues (d)	(10.3		)	(16.4		)	(8.9		)	—		—		—			(35.6		)
Other Revenues (d)	(14.2		)	21.3			—			3.1		2.5		(21.3		)	(8.6		)
Total Other Revenues	(24.5		)	4.9			(8.9		)	3.1		2.5		(21.3		)	(44.2		)
Total Revenues	$	2,349.0		$	1,137.0		$	212.5		$	460.7	$	23.8	$	(169.8	)	$	4,013.2

(a) 2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.

(b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing is $25 million. The remaining affiliated amounts are immaterial.

(c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco is $134 million. The remaining affiliated amounts are immaterial.

(d) Amounts include affiliated and nonaffiliated revenues.

207

	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 is $30 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts are immaterial.

(b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo is $198 million. The remaining affiliated amounts are immaterial.

(c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M is $23 million primarily relating to the barging, urea transloading and other transportation services. The remaining affiliated amounts are immaterial.

(d) Amounts include affiliated and nonaffiliated revenues.

208

	Three Months Ended June 30, 2018
	AEP Texas		AEPTCo (f)			APCo			I&M			OPCo			PSO		SWEPCo
	(in millions)
Retail Revenues:
Residential Revenues	$	143.2	$	—		$	282.3		$	163.0		$	388.1		$	169.4	$	158.2
Commercial Revenues	103.4		—			140.6			122.1			215.7			105.2		123.9
Industrial Revenues	31.8		—			152.5			145.9			103.3			77.3		87.2
Other Retail Revenues	7.3		—			18.8			1.5			3.3			22.3		2.1
Total Retail Revenues (a)	285.7		—			594.2			432.5			710.4			374.2		371.4
Wholesale Revenues:
Generation Revenues (b)	—		—			56.8			142.1			—			8.3		55.7
Transmission Revenues (c)	78.0		221.4			14.5			3.9			12.0			5.3		21.8
Total Wholesale Revenues	78.0		221.4			71.3			146.0			12.0			13.6		77.5
Other Revenues from Contracts with Customers (d)	7.2		6.4			15.1			25.9			38.9			4.9		5.3
Total Revenues from Contracts with Customers	370.9		227.8			680.6			604.4			761.3			392.7		454.2
Other Revenues:
Alternative Revenues (e)	0.2		(27.7		)	(13.6		)	(0.5		)	(16.6		)	5.6		2.9
Other Revenues (e)	17.2		—			—			(14.2		)	4.1			—		—
Total Other Revenues	17.4		(27.7		)	(13.6		)	(14.7		)	(12.5		)	5.6		2.9
Total Revenues	$	388.3	$	200.1		$	667.0		$	589.7		$	748.8		$	398.3	$	457.1

(a) 2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.

(b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo is $29 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts are immaterial.

(c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo is $104 million. The remaining affiliated amounts are immaterial.

(d) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M is $26 million primarily relating to the barging, urea transloading and other transportation services. The remaining affiliated amounts are immaterial.

(e) Amounts include affiliated and nonaffiliated revenues.

(f) These amounts presented reflect the revisions made to AEPTCo’s previously issued financial statement. See the “revisions to Previously Issued Financial Statements” section of Note 1 for additional information.

209

	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
Marketing, Competitive Retail and Renewable Revenues	—			—		—			469.5			—		—			469.5
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 is $71 million. The remaining affiliated amounts are immaterial.

(b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco is $399 million. The remaining affiliated amounts are immaterial.

(c) Amounts include affiliated and nonaffiliated revenues.

210

	Six Months Ended June 30, 2018
	Vertically Integrated Utilities			Transmission and Distribution Utilities			AEP Transmission Holdco			Generation & Marketing		Corporate and Other		Reconciling Adjustments			AEP Consolidated
	(in millions)
Retail Revenues:
Residential Revenues	$	1,858.2		$	1,098.8		$	—		$	—	$	—	$	—		$	2,957.0
Commercial Revenues	1,059.9			614.4			—			—		—		—			1,674.3
Industrial Revenues	1,097.3			252.7			—			—		—		—			1,350.0
Other Retail Revenues	90.3			21.1			—			—		—		—			111.4
Total Retail Revenues (a)	4,105.7			1,987.0			—			—		—		—			6,092.7
Wholesale and Competitive Retail Revenues:
Generation Revenues (b)	462.3			—			—			298.3		—		(56.7		)	703.9
Transmission Revenues (c)	135.6			184.6			432.5			—		—		(279.1		)	473.6
Marketing, Competitive Retail and Renewable Revenues	—			—			—			641.1		—		—			641.1
Total Wholesale and Competitive Retail Revenues	597.9			184.6			432.5			939.4		—		(335.8		)	1,818.6
Other Revenues from Contracts with Customers (d)	81.5			95.2			10.4			2.3		43.3		(47.7		)	185.0
Total Revenues from Contracts with Customers	4,785.1			2,266.8			442.9			941.7		43.3		(383.5		)	8,096.3
Other Revenues:
Alternative Revenues (d)	(19.4		)	(10.4		)	(24.9		)	—		—		—			(54.7		)
Other Revenues (d)	(8.7		)	43.0			—			24.1		4.5		(43.0		)	19.9
Total Other Revenues	(28.1		)	32.6			(24.9		)	24.1		4.5		(43.0		)	(34.8		)
Total Revenues	$	4,757.0		$	2,299.4		$	418.0		$	965.8	$	47.8	$	(426.5	)	$	8,061.5

(a) 2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.

(b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing is $52 million. The remaining affiliated amounts are immaterial.

(c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco is $297 million. The remaining affiliated amounts are immaterial.

(d) Amounts include affiliated and nonaffiliated revenues.

211

	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 is $64 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts are immaterial.

(b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo is $393 million. The remaining affiliated amounts are immaterial.

(c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M is $38 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts are immaterial.

(d) Amounts include affiliated and nonaffiliated revenues.

212

	Six Months Ended June 30, 2018
	AEP Texas			AEPTCo (f)			APCo			I&M			OPCo			PSO		SWEPCo
	(in millions)
Retail Revenues:
Residential Revenues	$	274.8		$	—		$	696.3		$	352.0		$	824.9		$	310.6	$	298.3
Commercial Revenues	202.9			—			287.2			231.8			410.3			189.3		232.2
Industrial Revenues	62.7			—			299.8			277.8			191.1			146.4		164.4
Other Retail Revenues	14.3			—			38.4			3.7			6.5			40.7		4.2
Total Retail Revenues (a)	554.7			—			1,321.7			865.3			1,432.8			687.0		699.1
Wholesale Revenues:
Generation Revenues (b)	—			—			119.6			256.1			—			14.2		115.6
Transmission Revenues (c)	156.0			406.3			39.3			10.7			28.0			15.9		47.8
Total Wholesale Revenues	156.0			406.3			158.9			266.8			28.0			30.1		163.4
Other Revenues from Contracts with Customers (d)	14.3			8.5			26.3			48.6			81.2			9.1		11.4
Total Revenues from Contracts with Customers	725.0			414.8			1,506.9			1,180.7			1,542.0			726.2		873.9
Other Revenues:
Alternative Revenues (e)	(0.1		)	(23.0		)	(19.5		)	(5.5		)	(10.3		)	8.9		2.6
Other Revenues (e)	35.0			—			—			(8.7		)	8.0			—		—
Total Other Revenues	34.9			(23.0		)	(19.5		)	(14.2		)	(2.3		)	8.9		2.6
Total Revenues	$	759.9		$	391.8		$	1,487.4		$	1,166.5		$	1,539.7		$	735.1	$	876.5

(a) 2018 amounts have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail Revenues. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate.

(b) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo is $69 million primarily relating to the PPA with Kingsport. The remaining affiliated amounts are immaterial.

(c) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo is $241 million. The remaining affiliated amounts are immaterial.

(d) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M is $41 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts are immaterial.

(e) Amounts include affiliated and nonaffiliated revenues.

(f) The amounts presented reflect the revisions made to AEPTCo’s previously issued financial statements. For additional details on revisions made to AEPTCo’s financial statements, see Note 1- Significant Accounting Matters.

213

Fixed Performance Obligations

The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of June 30, 2019. Fixed performance obligations primarily include wholesale transmission services, electricity sales for fixed amounts of energy and stand ready services into PJM’s RPM market. The Registrant Subsidiaries amounts shown in the table below include affiliated and nonaffiliated revenues.

Company	2019		2020-2021		2022-2023		After 2023		Total
	(in millions)
AEP	$	505.5	$	210.3	$	163.1	$	284.7	$	1,163.6
AEP Texas	193.5		—		—		—		193.5
AEPTCo	451.6		—		—		—		451.6
APCo	72.9		32.7		25.5		11.6		142.7
I&M	14.4		8.9		8.8		4.4		36.5
OPCo	35.6		7.5		—		—		43.1
PSO	8.6		—		—		—		8.6
SWEPCo	20.0		—		—		—		20.0

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 any material contract assets as of June 30, 2019 and December 31, 2018.

When the Registrants receive consideration, or such consideration is unconditionally due from a customer prior to transferring goods or services to the customer under the terms of a sales contract, they recognize a contract liability on the balance sheet in the amount of that consideration. Revenue for such consideration is subsequently recognized in the period or periods in which the remaining performance obligations in the contract are satisfied. The Registrants’ contract liabilities typically arise from services provided under joint use agreements for utility poles. The Registrants did not have any material contract liabilities as of June 30, 2019 and December 31, 2018.

Accounts Receivable from Contracts with Customers

Accounts receivable from contracts with customers are presented on the Registrants’ balance sheets within the Accounts Receivable - Customers line item. The Registrants’ balances for receivables from contracts that are not recognized in accordance with the accounting guidance for “Revenue from Contracts with Customers” included in Accounts Receivable - Customers were not material as of June 30, 2019 and December 31, 2018. See “Securitized Accounts Receivable - AEP Credit” section of Note 13 for additional information related to AEP Credit’s securitized accounts receivable.

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

Company	June 30, 2019		December 31, 2018
	(in millions)
AEPTCo	$	82.8	$	58.6
APCo	40.4		52.5
I&M	14.5		35.3
OPCo	30.8		46.1
PSO	24.5		12.4
SWEPCo	45.9		16.3

214

CONTROLS AND PROCEDURES

During the second quarter of 2019, management, including the principal executive officer and principal financial officer of each of the Registrants, evaluated the Registrants’ disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. As of June 30, 2019, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives.

The only 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 2019 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting, relates to the Registrants’ outsourcing of certain accounting and tax transaction processing activities to a third party contractor. These transactional activities executed by the third party contractor are subject to management review controls. In connection with this new strategic relationship, management will continue to evaluate and monitor the Registrants’ internal controls over financial reporting to ensure controls remain effective. There were no other changes in the Registrants’ internal control over financial reporting during the quarter ended June 30, 2019, that have materially affected, or are reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

215

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 Annual Report on Form 10-K for the year ended December 31, 2018 includes a detailed discussion of risk factors.  As of June 30, 2019, there have been no material changes to the risk factors previously disclosed in the 2018 Annual Report on Form 10-K.

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

None

Item 3.  Defaults Upon Senior Securities

None

Item 4.  Mine Safety Disclosures

The Federal Mine Safety and Health Act of 1977 (Mine Act) imposes stringent health and safety standards on various mining operations. The Mine Act and its related regulations affect numerous aspects of mining operations, including training of mine personnel, mining procedures, equipment used in mine emergency procedures, mine plans and other matters. SWEPCo, through its ownership of DHLC, a wholly-owned lignite mining subsidiary of SWEPCo, is subject to the provisions of the Mine Act.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act. Exhibit 95 “Mine Safety Disclosure Exhibit” contains the notices of violation and proposed assessments received by DHLC under the Mine Act for the quarter ended June 30, 2019.

Item 5.  Other Information

None

216

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
*4.1	Company Order and Officer’s Certificate, between AEP Texas Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee, dated May 1, 2019, establishing the terms of the Series G Notes (including Form of Note).	Form 8-K, Exhibit 4(a) dated May 1, 2019
AEPTCo‡ File No. 333-217143
*4.2	Company Order and Officer’s Certificate, between AEP Transmission Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee, dated June 10, 2019, establishing the terms of the Series K Notes (including Form of Note).	Form 8-K Exhibit 4(a) dated June 12, 2019
OPCo‡ File No.1-6543
*4.3	Company Order and Officer’s Certificate, between Ohio Power Company and The Bank of New York Mellon Trust Company, N.A., as trustee, dated May 22, 2019, establishing the terms of the Series O Notes (including Form of Note).	Form 8-K, Exhibit 4(a) dated May 22, 2019

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
3	Composite of Amended Restated Certificate of Incorporation of American Electric Power Company, Inc.	X
10	Modification to Consent Decree with U.S. District Court dated July 17, 2019.	X				X
31(a)	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	X	X	X	X	X	X	X	X
31(b)	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	X	X	X	X	X	X	X	X
32(a)	Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code	X	X	X	X	X	X	X	X
32(b)	Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code	X	X	X	X	X	X	X	X
95	Mine Safety Disclosures								X
101.INS	XBRL Instance Document	The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCH	XBRL Taxonomy Extension Schema	X	X	X	X	X	X	X	X
101.CAL	XBRL Taxonomy Extension Calculation Linkbase	X	X	X	X	X	X	X	X
101.DEF	XBRL Taxonomy Extension Definition Linkbase	X	X	X	X	X	X	X	X
101.LAB	XBRL Taxonomy Extension Label Linkbase	X	X	X	X	X	X	X	X
101.PRE	XBRL Taxonomy Extension Presentation Linkbase	X	X	X	X	X	X	X	X

217

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:  July 25, 2019

218