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    Appendix A to the Proxy Statement American Electric Power 2019 Annual Report Audited Consolidated Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operations


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    AMERICAN ELECTRIC POWER 1 Riverside Plaza CONTENTS Columbus, Ohio 43215-2373 Glossary of Terms i Forward-Looking Information vi AEP Common Stock Information viii Selected Consolidated Financial Data 1 Management’s Discussion and Analysis of Financial Condition and Results of Operations 2 Report of Independent Registered Public Accounting Firm 57 Management’s Report on Internal Control Over Financial Reporting 61 Consolidated Statements of Income 62 Consolidated Statements of Comprehensive Income (Loss) 63 Consolidated Statements of Changes in Equity 64 Consolidated Balance Sheets 65 Consolidated Statements of Cash Flows 67 Index of Notes to Financial Statements of Registrants 68 Corporate and Shareholder Information 255 Executive Leadership Team 256


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    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 variable interest entity of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies. AEP Energy AEP Energy, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States. 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 Utilities AEP Utilities, Inc., a former subsidiary of AEP and holding company for TCC, TNC and CSW Energy, Inc. Effective December 31, 2016, TCC and TNC were merged into AEP Utilities, Inc. Subsequently following this merger, the assets and liabilities of CSW Energy, Inc. were transferred to a competitive affiliate company and AEP Utilities, Inc. was renamed AEP Texas Inc. AEP Wind Holdings LLC Acquired in April 2019 as Sempra Renewables LLC, develops, owns and operates, or holds interests in, wind generation facilities in the United States. AEPEP AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, hedging activities, asset management and commercial and industrial sales in deregulated markets. AEPRO AEP River Operations, LLC, a commercial barge operation sold in November 2015. AEPSC American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries. AEPTCo AEP Transmission Company, LLC, a wholly-owned subsidiary of AEP Transmission Holdco, is an intermediate holding company that owns the State Transcos. AEPTCo Parent AEP Transmission Company, LLC, the holding company of the State Transcos within the AEPTCo consolidation. AFUDC Allowance for 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 Appalachian Consumer Rate Relief Funding LLC, a wholly-owned subsidiary of APCo Rate Relief Funding and a consolidated variable interest entity 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 ratemaking purposes. ARO Asset Retirement Obligations. ASU Accounting Standards Update. CAA Clean Air Act. CLECO Central Louisiana Electric Company, a nonaffiliated utility company. CO2 Carbon dioxide and other greenhouse gases. Conesville Plant A single unit coal-fired generation plant totaling 651 MW located in Conesville, Ohio. The plant is jointly owned by AGR and a nonaffiliate. i


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    Term Meaning Cook Plant Donald C. Cook Nuclear Plant, a two-unit, 2,288 MW nuclear plant owned by I&M. CRES provider Competitive Retail Electric Service providers under Ohio law that target retail customers by offering alternative generation service. CSAPR Cross-State Air Pollution Rule. CWA Clean Water Act. CWIP Construction Work in Progress. DCC Fuel DCC Fuel IX, DCC Fuel X, DCC Fuel XI, DCC Fuel XII, DCC Fuel XIII, and DCC Fuel XIV consolidated variable interest entities formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DOE U. S. Department of Energy. Desert Sky Desert Sky Wind Farm, a 168 MW wind electricity generation facility located on Indian Mesa in Pecos County, Texas. 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 variable interest entity 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. FAC Fuel Adjustment Clause. 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 FAC Audits. I&M Indiana Michigan Power Company, an AEP electric utility subsidiary. IRS Internal Revenue Service. ITC Investment Tax Credit IURC Indiana Utility Regulatory Commission. KGPCo Kingsport Power Company, an AEP electric utility subsidiary. KPCo Kentucky Power Company, an AEP electric utility subsidiary. kV Kilovolt. KWh Kilowatt-hour. LPSC Louisiana Public Service Commission. MATS Mercury and Air Toxics Standards. ii


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    Term Meaning MISO Midwest Independent Transmission System Operator. MMBtu Million British Thermal Units. MPSC Michigan Public Service Commission. MTM Mark-to-Market. MW Megawatt. MWh Megawatt-hour. NAAQS National Ambient Air Quality Standards. Nonutility Money Pool Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries. North Central Wind Energy A proposed joint PSO and SWEPCo project, which includes three Oklahoma wind Facilities facilities totaling approximately 1,485 MWs of wind generation. NO2 Nitrogen dioxide. NOx Nitrogen oxide. NPDES National Pollutant Discharge Elimination System. NRC Nuclear Regulatory Commission. NSR New Source Review. OATT Open Access Transmission Tariff. OCC Corporation Commission of the State of Oklahoma. Ohio Phase-in-Recovery Ohio Phase-in-Recovery Funding LLC, a wholly-owned subsidiary of OPCo and a Funding consolidated variable interest entity 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. Operating Agreement Agreement, dated January 1, 1997, as amended, by and among PSO and SWEPCo governing generating capacity allocation, energy pricing, and revenues and costs of third-party sales. AEPSC acts as the agent. 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. PCA Power Coordination Agreement among APCo, I&M, KPCo and WPCo. PJM Pennsylvania – New Jersey – Maryland regional transmission organization. PM Particulate Matter. PPA Purchase Power and Sale Agreement. Price River Rights and interests in certain coal reserves located in Carbon County, Utah. PSO Public Service Company of Oklahoma, an AEP electric utility subsidiary. PTC Production Tax Credits. PUCO Public Utilities Commission of Ohio. PUCT Public Utility Commission of Texas. Racine A generation plant consisting of two hydroelectric generating units totaling 48 MWs located in Racine, Ohio and owned by AGR. 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. REP Texas Retail Electric Provider. Restoration Funding AEP Texas Restoration Funding LLC, a wholly-owned subsidiary of AEP Texas and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to storm restoration in Texas primarily caused by Hurricane Harvey. Risk Management Trading and non-trading derivatives, including those derivatives designated as cash Contracts flow and fair value hedges. iii


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    Term Meaning Rockport Plant A generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana. AEGCo and I&M jointly-own Unit 1. In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2. ROE Return on Equity. RPM Reliability Pricing Model. RTO Regional Transmission Organization, responsible for moving electricity over large interstate areas. Sabine Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity for AEP and SWEPCo. Santa Rita East Santa Rita East Wind Holdings, LLC, a consolidated VIE whose sole purpose is to own and operate a 302 MW wind generation facility in west Texas in which AEP owns a 75% interest. 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. SIA System Integration Agreement, effective June 15, 2000, as amended, provides contractual basis for coordinated planning, operation and maintenance of the power supply sources of the combined AEP. 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, each of which is geographically aligned with AEP existing utility operating companies. SWEPCo Southwestern Electric Power Company, an AEP electric utility subsidiary. Tax Reform On December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal Revenue Code of 1986, including a reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018. TCC Formerly AEP Texas Central Company, now a division of AEP Texas. Texas Restructuring Legislation enacted in 1999 to restructure the electric utility industry in Texas. Legislation TNC Formerly AEP Texas North Company, now a division of AEP Texas. Transition Funding AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated variable interest entities formed for the purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation. Transource Energy Transource Energy, LLC, a consolidated variable interest entity formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates. Trent Trent Wind Farm, a 154 MW wind electricity generation facility located between Abilene and Sweetwater in West Texas. Turk Plant John W. Turk, Jr. Plant, a 600 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo. UMWA United Mine Workers of America. UPA Unit Power Agreement. Utility Money Pool Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries. VIE Variable Interest Entity. Virginia SCC Virginia State Corporation Commission. iv


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    Term Meaning Wind Catcher Project Wind Catcher Energy Connection Project, a joint PSO and SWEPCo project that was cancelled in July 2018. The estimated $4.5 billion project included the acquisition of a wind generation facility, totaling approximately 2,000 MWs of wind generation, and the construction of a generation interconnection tie-line totaling approximately 350 miles. WPCo Wheeling Power Company, an AEP electric utility subsidiary. WVPSC Public Service Commission of West Virginia. v


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    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,” 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 coal ash and nuclear fuel. Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance. Resolution of litigation. The ability to constrain operation and maintenance costs. Prices and demand for power generated and sold at wholesale. Changes in technology, particularly with respect to energy storage and new, developing, alternative or distributed sources of generation. The ability to recover through rates any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives. Volatility and changes in markets for coal and other energy-related commodities, particularly changes in the price of natural gas. Changes in utility regulation and the allocation of costs within RTOs including ERCOT, PJM and SPP. Changes in the creditworthiness of the counterparties with contractual arrangements, including participants in the energy trading market. Actions of rating agencies, including changes in the ratings of debt. The impact of volatility in the capital markets on the value of the investments held by the pension, OPEB, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements. Accounting standards periodically issued by accounting standard-setting bodies. vi


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    Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, naturally occurring and human-caused fires, cyber security threats and other catastrophic events. The ability to attract and retain the requisite work force and key personnel. The forward-looking statements of the Registrants speak only as of the date of this report or as of the date they are made. The Registrants expressly disclaim any obligation to update any forward-looking information, except as required by law. For a more detailed discussion of these factors, see “Risk Factors” in Part I 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. vii


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    AEP COMMON STOCK INFORMATION AEP common stock is principally traded using the trading symbol “AEP” on the New York Stock Exchange. As of December 31, 2019, AEP had approximately 57,000 registered shareholders. viii


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    AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SELECTED CONSOLIDATED FINANCIAL DATA 2019 (a) 2018 2017 2016 2015 (dollars in millions, except per share amounts) STATEMENTS OF INCOME DATA Total Revenues $15,561.4 $16,195.7 $15,424.9 $16,380.1 $16,453.2 Operating Income $ 2,592.3 $ 2,682.7 $ 3,525.0 $ 1,163.9 $ 3,292.4 Income from Continuing Operations $ 1,919.8 $ 1,931.3 $ 1,928.9 $ 620.5 $ 1,768.6 Income (Loss) From Discontinued Operations, Net of Tax — — — (2.5) 283.7 Net Income 1,919.8 1,931.3 1,928.9 618.0 2,052.3 Net Income (Loss) Attributable to Noncontrolling Interest (1.3) 7.5 16.3 7.1 5.2 EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $ 1,921.1 $ 1,923.8 $ 1,912.6 $ 610.9 $ 2,047.1 BALANCE SHEETS DATA Total Property, Plant and Equipment $79,145.7 $73,085.2 $67,428.5 $62,036.6 $65,481.4 Accumulated Depreciation and Amortization 19,007.6 17,986.1 17,167.0 16,397.3 19,348.2 Total Property, Plant and Equipment – Net $60,138.1 $55,099.1 $50,261.5 $45,639.3 $46,133.2 Total Assets $75,892.3 $68,802.8 $64,729.1 $63,467.7 $61,683.1 Total AEP Common Shareholders’ Equity $19,632.2 $19,028.4 $18,287.0 $17,397.0 $17,891.7 Noncontrolling Interests $ 281.0 $ 31.0 $ 26.6 $ 23.1 $ 13.2 Long-term Debt (b) $26,725.5 $23,346.7 $21,173.3 $20,256.4 $19,572.7 Obligations Under Finance Leases (b) $ 306.8 $ 289.0 $ 297.8 $ 305.5 $ 343.5 Obligations Under Operating Leases (b) (c) $ 968.7 $ — $ — $ — $ — AEP COMMON STOCK DATA Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders: From Continuing Operations $ 3.89 $ 3.90 $ 3.89 $ 1.25 $ 3.59 From Discontinued Operations — — — (0.01) 0.58 Total Basic Earnings per Share Attributable to AEP Common Shareholders $ 3.89 $ 3.90 $ 3.89 $ 1.24 $ 4.17 Weighted Average Number of Basic Shares Outstanding (in millions) 493.7 492.8 491.8 491.5 490.3 Market Price Range: High $ 96.22 $ 81.05 $ 78.07 $ 71.32 $ 65.38 Low $ 72.26 $ 62.71 $ 61.82 $ 56.75 $ 52.29 Year-end Market Price $ 94.51 $ 74.74 $ 73.57 $ 62.96 $ 58.27 Cash Dividends Declared per AEP Common Share $ 2.71 $ 2.53 $ 2.39 $ 2.27 $ 2.15 Dividend Payout Ratio 69.67% 64.87% 61.44% 183.06% 51.56% Book Value per AEP Common Share $ 39.73 $ 38.58 $ 37.17 $ 35.38 $ 36.44 (a) The 2019 financial results include pretax asset impairments of $156 million. See Note 7 - Acquisitions, Dispositions and Impairments for additional information. (b) Includes portion due within one year. (c) Reflects the adoption of ASU 2016-02 “Accounting for Leases.” See Note 2 - New Accounting Standards and Note 13 - Leases for additional information. 1


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    AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS EXECUTIVE OVERVIEW Company Overview AEP is one of the largest investor-owned electric public utility holding companies in the United States. AEP’s electric utility operating companies provide generation, transmission and distribution services to more than five million retail customers in Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. AEP’s subsidiaries operate an extensive portfolio of assets including: Approximately 221,000 miles of distribution lines that deliver electricity to 5.5 million customers. Approximately 40,000 circuit miles of transmission lines, including approximately 2,200 circuit miles of 765 kV lines, the backbone of the electric interconnection grid in the eastern United States. Approximately 22,000 MWs of regulated owned generating capacity and approximately 4,900 MWs of regulated PPA capacity in 3 RTOs as of December 31, 2019, one of the largest complements of generation in the United States. Customer Demand AEP’s weather-normalized retail sales volumes for the year ended December 31, 2019 decreased by 0.8% from the year ended December 31, 2018. AEP’s 2019 industrial sales volumes decreased 1.9% compared to 2018. The decline in industrial sales was spread across most operating companies and many industries. Weather-normalized residential sales decreased 0.1% despite a 0.3% growth in customer counts. Weather-normalized commercial sales decreased by 0.4% in 2019 compared to 2018. In 2020, AEP anticipates weather-normalized retail sales volumes will increase by 0.5%. The industrial class is expected to increase by 3.2% in 2020, while weather-normalized residential sales volumes are projected to decrease by 1.4%. Weather-normalized commercial sales volumes are projected to decrease by 0.4%. (a) Percentage change for the year ended December 31, 2019 as compared to the year ended December 31, 2018. (b) Forecasted percentage change for the year ended December 31, 2020 compared to the year ended December 31, 2019. 2


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    Regulatory Matters AEP’s public utility subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. Depending on the outcomes, these rate and regulatory proceedings can have a material impact on results of operations, cash flows and possibly financial condition. AEP is currently involved in the following key proceedings. See Note 4 - Rate Matters for additional information. 2019 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. In November 2019, ALJs issued a Proposal for Decision recommending a $60 million annual rate reduction based upon a 9.4% return on common equity. The ALJs recommended disallowances that could potentially result in write-offs of $84 million related to capital incentives and $5 million related to other plant additions. Additionally, the ALJs recommended that AEP Texas should be required to file an application for a separate proceeding to determine if any refunds are required associated with any disallowances on distribution or transmission capital investments. In February 2020, AEP Texas, the PUCT staff and various intervenors filed a stipulation and settlement agreement with the PUCT. The agreement includes a proposed annual base rate reduction of $40 million based upon a 9.4% return on common equity with a capital structure of 57.5% debt and 42.5% common equity. The agreement provides recovery of $26 million in capitalized vegetation management expenses that were incurred through 2018. The agreement includes disallowances of $23 million related to capital investments recorded through 2018 and $4 million related to rate case expenses. In addition, AEP Texas will refund: (a) $77 million of Excess ADIT and excess federal income taxes collected as a result of Tax Reform to distribution customers over a one year period, (b) $31 million of Excess ADIT and excess federal income taxes collected as a result of Tax Reform to transmission customers as a one-time credit and (c) $30 million of previously collected rates that were subject to reconciliation in this proceeding over a one year period with no carrying costs. As a result of the stipulation and settlement agreement, AEP Texas (a) recorded an impairment of $33 million in December 2019 related to capital investments, which included $10 million of current year investments, (b) recorded a $30 million provision for refund for revenues previously collected through rates and (c) wrote-off $4 million of rate case expenses. The PUCT is expected to issue an order in the first quarter of 2020. 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. In August 2019, certain intervenors filed testimony that includes recommended disallowances that could potentially result in write-offs of $41 million related to the remaining book value of existing Indiana jurisdictional meters if I&M is approved to deploy Automated Metering Infrastructure meters and $11 million associated with certain Cook Plant study costs. The IURC is expected to issue an order on this case in the first quarter of 2020. 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 in excess of 70 basis points above APCo’s Virginia SCC authorized ROE would be refunded to customers. Virginia law provides that costs associated with asset impairments of retired coal generation assets, or automated meters, or both, which a utility records as an expense, shall be attributed to the test periods under review in a triennial review proceeding, and be deemed recovered. Based on management’s interpretation of Virginia law and more certainty regarding APCo’s triennial revenues, expenses and resulting earnings upon reaching the end of the three-year review period, APCo recorded a pretax expense of $93 million related to its previously retired coal-fired generation assets in December 2019. This expense is included in Asset Impairments and Other Related Charges on the statements of income. As a result, management deems these costs to be substantially recovered by APCo during the triennial review period. Inclusive of the $93 million expense associated with APCo’s Virginia jurisdictional retired coal-fired plants, APCo estimates its Virginia earnings for the triennial period to be below the authorized ROE range. 3


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    2020 Increase in West Virginia Retail Rates for WPCo 17.5% Merchant Share of Mitchell Plant - In 2015, the WVPSC approved a settlement agreement in which 82.5% of the West Virginia jurisdictional 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 to reflect the recovery of WPCo’s remaining 17.5% interest in the Mitchell Plant. In December 2019, the WVPSC issued an order approving a stipulation and settlement agreement that will allow APCo and WPCo to recover the remaining 17.5% West Virginia share of costs related to the Mitchell Plant and increase pretax earnings on a combined company basis by approximately $21 million annually beginning January 1, 2020. 2012 Texas Base Rate Case - In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant. In July 2018, the Texas Third Court of Appeals reversed the PUCT’s judgment affirming the prudence of the Turk Plant and remanded the issue back to the PUCT. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court. In May 2019, various intervenors filed replies to the petition. In July 2019, SWEPCo filed its response to these replies. In the fourth quarter of 2019 and first quarter of 2020, SWEPCo and various intervenors filed briefs with the Texas Supreme Court. As of December 31, 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 including lost shared savings revenues of $26 million annually and renewable mandates no later than 2020 and after 2026, respectively. The bill provides for the recovery of existing renewable energy contracts on a bypassable basis through 2032. The clean energy legislation also includes a provision for recovery of OVEC costs through 2030 which will be allocated to all electric distribution utilities on a non-bypassable basis. OPCo’s Inter-Company Power Agreement for OVEC terminates in June 2040. To the extent that OPCo is unable to recover the costs of renewable energy contracts on a bypassable basis by the end of 2032, recover costs of OVEC after 2030 or fully recover energy efficiency costs through 2020 it could reduce future net income and cash flows and impact financial condition. 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 SWEPCo Arkansas 52.8 9.45% January 2020 I&M Michigan 36.4 9.86% February 2020 4


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    Pending Base Rate Case Proceedings Commission Staff/ Filing Requested Revenue Requested Intervenor Range of Company Jurisdiction Date Requirement Increase ROE Recommended ROE (in millions) AEP Texas (a) Texas May 2019 $ 56.0 10.5% 9% - 9.35% I&M Indiana May 2019 172.0 10.5% 9% - 9.73% (a) In February 2020, AEP Texas, the PUCT staff and various intervenors filed a stipulation and settlement agreement with the PUCT that includes a proposed annual base rate reduction of $40 million based upon a 9.4% return on common equity. See “2019 Texas Base Rate Case” section of Note 4 for additional information. Dolet Hills Power Station and Related Fuel Operations During the second quarter of 2019, the Dolet Hills Power Station initiated a seasonal operating schedule. In January 2020, in accordance with the terms of SWEPCo’s settlement of its base rate review filed with the APSC, management announced that SWEPCo will seek regulatory approval to retire the Dolet Hills Power Station by the end of 2026. Management also continues to monitor the economic viability of the Dolet Hills Power Station and DHLC mining operations, which may result in a decision to seek permission from appropriate regulatory agencies to discontinue operations earlier than 2026. The Dolet Hills Power Station costs are recoverable by SWEPCo through base rates. SWEPCo’s share of the net investment in the Dolet Hills Power Station is $157 million, including CWIP and materials and supplies, before cost of removal. Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses. Under the Lignite Mining Agreement, DHLC bills SWEPCo its proportionate share of incurred lignite extraction and associated mining-related costs as fuel is delivered. As of December 31, 2019, DHLC has unbilled fixed costs of $106 million that will be billed to SWEPCo prior to the closure of the Dolet Hills Power Station. In 2009, SWEPCo acquired interests in the Oxbow Lignite Company (Oxbow), which owns mineral rights and leases land. Under a Joint Operating Agreement pertaining to the Oxbow mineral rights and land leases, Oxbow bills SWEPCo its proportionate share of incurred costs. As of December 31, 2019, Oxbow has unbilled fixed costs of $22 million that will be billed to SWEPCo prior to the closure of the Dolet Hills Power Station. Additional operational and land-related costs are expected to be incurred by DHLC and Oxbow and billed to SWEPCo prior to the closure of the Dolet Hills Power Station and recovered through fuel clauses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 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 ownership interests in 724 MWs of wind generation and battery assets valued at approximately $1.1 billion. AEP paid $580 million in cash and acquired a 50% ownership interest in five non-consolidated joint ventures with net assets valued at $404 million as of the acquisition date (which includes $364 million of existing debt obligations). Additionally, the transaction included the acquisition of two tax 5


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    equity partnerships and the associated recognition of noncontrolling tax equity interest of $135 million. 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 7 for additional information. In July 2019, AEP acquired a 75% interest, or 227 MWs, in Santa Rita East 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. See “Acquisitions” section of Note 7 for additional information. As of December 31, 2019, subsidiaries within AEP’s Generation & Marketing segment had approximately 1,421 MWs of contracted renewable generation projects in-service. In addition, as of December 31, 2019, these subsidiaries had approximately 156 MWs of renewable generation projects under construction with total estimated capital costs of $229 million related to these projects. 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. In November 2019, PUCO denied OPCo’s application for a resource planning need finding. In December 2019, OPCo filed an Application for Rehearing, which was also denied. In July 2019, PSO and SWEPCo submitted filings before their respective commissions for the approval to acquire the North Central Wind Energy Facilities, comprised of three Oklahoma wind facilities totaling 1,485 MWs, on a fixed cost turn-key basis at completion. Subject to regulatory approval, PSO will own 45.5% and SWEPCo will own 54.5% of the project, which will cost approximately $2 billion. Two wind facilities, totaling 1,286 MWs, would qualify for 80% of the federal PTC with year-end 2021 in-service dates. The third wind facility (199 MWs) would qualify for 100% of the PTC with a year-end 2020 in-service date. The acquisition can be scaled, subject to commercial limitation, to align with individual state resource needs and approvals. In December 2019, PSO reached a joint stipulation and settlement agreement with the OCC, Oklahoma Attorney General’s office and customer groups. In January 2020, SWEPCo reached a joint settlement agreement with the APSC, Arkansas Attorney General’s office and Walmart, Inc. SWEPCo continues to work through the regulatory process in Texas and Louisiana. Hearings are scheduled for the first quarter of 2020. PSO and SWEPCo are seeking regulatory approvals by July 2020. Federal Tax Reform Based on current regulatory orders received, management anticipates amortization of $249 million of Excess ADIT in 2020 ($68 million of Excess ADIT subject to normalization requirements and $181 million of Excess ADIT that is not subject to normalization requirements). Customer usage or new regulatory orders could result in changes to these estimates. Management anticipates amortizing the following ranges of Excess ADIT that is not subject to normalization requirements over the next five years: Annual Amortization of Unamortized Balance as of December 31, 2019 Year Range (in millions) 2020 $ 165.0 - $ 196.0 2021 102.0 - 134.0 2022 75.0 - 105.0 2023 67.0 - 98.0 2024 34.0 - 65.0 6


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    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 - Acquisitions, Dispositions and Impairments for additional information. Reconstruction activities at Racine are currently 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 book value once complete. 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. Merchant Portion of Turk Plant SWEPCo constructed the Turk Plant, a base load 600 MW (650 MW net maximum capacity) pulverized coal ultra- supercritical generating unit in Arkansas, which was placed into service in December 2012 and is included in the Vertically Integrated Utilities segment. SWEPCo owns 73% (440 MWs/477 MWs) of the Turk Plant and operates the facility. The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant (approximately 20%). Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN. In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN. This share of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the wholesale market. Approximately 80% of the Turk Plant investment is recovered under cost-based rate recovery in Texas, Louisiana and through SWEPCo’s wholesale customers under FERC-based rates. As of December 31, 2019, the net book value of Turk Plant was $1.5 billion, before cost of removal, including materials and supplies inventory and CWIP. If SWEPCo cannot ultimately recover its investment and expenses related to the Turk Plant, it could reduce future net income and cash flows and impact financial condition. FERC Transmission ROE Methodology In November 2019, the FERC issued Opinion No. 569, which adopted a revised methodology for determining whether an existing base ROE is just and reasonable under Federal Power Act and determined the base ROE for MISO’s transmission-owning members should be reduced to 9.88% (10.38% inclusive of RTO incentive adder of 0.5%). The revised ROE methodology relies on two financial models, which include the discounted cash flow model and the capital asset pricing model, to establish a composite zone of reasonableness. In December 2019, AEP filed multiple requests for rehearing and participated in filing comments and requests for rehearing on behalf of transmission owners and industry organizations. Management believes FERC Opinion No. 569 reverses the expectation of a four-model framework proposed by FERC in 2018 and vetted widely in FERC 2019 Notice of Inquiry regarding base ROE policy. Management does not believe this ruling will have a material impact on financial results for its MISO transmission- owning subsidiaries. In the second quarter of 2019, FERC approved settlement agreements establishing base ROEs of 9.85% (10.35% inclusive of RTO incentive adder of 0.5%) and 10% (10.5% inclusive of RTO incentive adder of 0.5%) for AEP’s PJM and SPP transmission-owning subsidiaries, respectively. If FERC makes any changes to its ROE and incentive policies, they would be applied to AEP’s PJM and SPP transmission owning subsidiaries on a prospective basis, and could affect future net income and cash flows and impact financial condition. LITIGATION In the ordinary course of business, AEP is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases that have a probable likelihood of loss if the loss can be estimated. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition. See Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies for additional information. 7


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    Rockport Plant Litigation In 2013, the Wilmington Trust Company filed a complaint in the U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it would be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering, refueling or retirement of the unit. The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. AEGCo and I&M sought and were granted dismissal by the U.S. District Court for the Southern District of Ohio of certain of the plaintiffs’ claims, including claims for compensatory damages, breach of contract, breach of the implied covenant of good faith and fair dealing and indemnification of costs. Plaintiffs voluntarily dismissed the surviving claims that AEGCo and I&M failed to exercise prudent utility practices with prejudice, and the court issued a final judgment. The plaintiffs subsequently filed an appeal in the U.S. Court of Appeals for the Sixth Circuit. In 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion and judgment affirming the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims, reversing the district court’s dismissal of the breach of contract claims and remanding the case for further proceedings. Thereafter, AEP filed a motion with the U.S. District Court for the Southern District of Ohio in the original NSR litigation, seeking to modify the consent decree. The district court granted the owners’ unopposed motion to stay the lease litigation to afford time for resolution of AEP’s motion to modify the consent decree. The consent decree was modified based on an agreement among the parties in July 2019. The district court entered a stay that expired in February 2020. Settlement negotiations are continuing, and the parties filed a joint proposed case schedule in February 2020. See “Modification of the NSR Litigation Consent Decree” section below for additional information. Management will continue to defend against the claims. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management cannot determine a range of potential losses that is reasonably possible of occurring. Patent Infringement Complaint In July 2019, Midwest Energy Emissions Corporation and MES Inc. (collectively, the plaintiffs) filed a patent infringement complaint against various parties, including AEP Texas, AGR, Cardinal Operating Company and SWEPCo (collectively, the AEP Defendants). The complaint alleges that the AEP Defendants infringed two patents owned by the plaintiffs by using specific processes for mercury control at certain coal-fired generating stations. The complaint seeks injunctive relief and damages. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring. Claims Challenging Transition of American Electric Power System Retirement Plan to Cash Balance Formula The American Electric Power System Retirement Plan (the Plan) has received a letter written on behalf of four participants (the Claimants) making a claim for additional plan benefits and purporting to advance such claims on behalf of a class. When the Plan’s benefit formula was changed in the year 2000, AEP provided a special provision for employees hired before January 1, 2001, allowing them to continue benefit accruals under the then benefit formula for a full 10 years alongside of the new cash balance benefit formula then being implemented. Employees who were hired on or after January 1, 2001 accrued benefits only under the new cash balance benefit formula. The Claimants have asserted claims that (a) the Plan violates the requirements under the Employee Retirement Income Security Act (ERISA) intended to preclude back-loading the accrual of benefits to the end of a participant’s career; (b) the Plan violates the age discrimination prohibitions of ERISA and the Age Discrimination in Employment Act (ADEA); and (c) the company failed to provide required notice regarding the changes to the Plan. AEP has responded to the Claimants 8


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    providing a reasoned explanation for why each of their claims have been denied, and offering an opportunity to appeal those determinations. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring. ENVIRONMENTAL ISSUES AEP has a substantial capital investment program and incurs additional operational costs to comply with environmental control requirements. Additional investments and operational changes will be made in response to existing and anticipated requirements to reduce emissions from fossil generation, rules governing the beneficial use and disposal of coal combustion by-products, clean water rules and renewal permits for certain water discharges. AEP is engaged in litigation about environmental issues, was notified of potential responsibility for the clean-up of contaminated sites and incurred costs for disposal of SNF and future decommissioning of the nuclear units. AEP, along with other parties, challenged some of the Federal EPA requirements. Management is engaged in the development of possible future requirements including the items discussed below. Management believes that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals. AEP will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances. If AEP cannot recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition. Environmental Controls Impact on the Generating Fleet The rules and proposed environmental controls discussed below will have a material impact on AEP System generating units. Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance. As of December 31, 2019, the AEP System had generating capacity of approximately 25,500 MWs, of which approximately 13,200 MWs were coal-fired. Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on fossil generation. Based upon management estimates, AEP’s future investment to meet these existing and proposed requirements ranges from approximately $500 million to $1 billion through 2026. The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in finalizing proposed rules or revising certain existing requirements. The cost estimates will also change based on: (a) potential state rules that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) actual performance of the pollution control technologies installed, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors. In addition, management continues to evaluate the economic feasibility of environmental investments on regulated and competitive plants. 9


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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 December 31, 2019. Generating Amounts Pending Company Plant Name and Unit Capacity Regulatory Approval (in MWs) (in millions) APCo (a) Kanawha River Plant 400 $ 14.1 APCo (b) Clinch River Plant 705 25.5 APCo (a) Sporn Plant, Units 1 and 3 300 2.0 APCo (a) Glen Lyn Plant 335 3.5 SWEPCo (c) Welsh Plant, Unit 2 528 35.5 Total 2,268 $ 80.6 (a) Remaining amounts pending regulatory approval represent the FERC and the West Virginia jurisdictional share. Management expensed the Virginia jurisdictional share in December 2019. See “Virginia Legislation Affecting Earnings Reviews” section of Note 4 for additional information. (b) APCo obtained permits following the Virginia SCC’s and WVPSC’s approval to convert Clinch River Plant, Units 1 and 2 to natural gas. In 2015, APCo retired the coal-related assets of Clinch River Plant, Units 1 and 2. Clinch River Plant, Units 1 and 2 began operations as natural gas units in 2016. (c) Remaining amount pending regulatory approval represents the FERC and Louisiana jurisdictional share. The APSC issued an order in December 2019 approving the recovery of the $15 million Arkansas jurisdictional share. See “2019 Arkansas Base Rate Case” section of Note 4 for additional information. 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 NOx emissions from the AEP System and various mitigation projects. In 2017, AEP filed a motion with the district court seeking to modify the consent decree to eliminate an obligation to install future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. The other parties to the consent decree opposed AEP’s motion. The district court granted AEP’s request to delay the deadline to install Selective Catalytic Reduction technology at Rockport Plant, Unit 2 until June 2020. In May 2019, the parties filed a proposed order to modify the consent decree. The proposed order requires AEP to enhance the dry sorbent injection system on both units at the Rockport Plant by the end of 2020, and meet 30-day rolling average emission rates for SO2 and NOx at the combined stack for the Rockport Plant beginning in 2021. Total SO2 emissions from the Rockport Plant are limited to 10,000 tons per year beginning in 2021 and reduce to 5,000 tons per year when Rockport Plant, Unit 1 retires in 2028. The proposed modification was approved by the district court and became effective in July 2019. As part of the modification to the consent decree, I&M agreed to provide an additional $7.5 million to citizens’ groups and the states for environmental mitigation projects. As joint owners in the Rockport Plant, the $7.5 million payment was shared between AEGCo and I&M based on the joint ownership agreement. Clean Air Act Requirements The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions. The states implement and administer many of these programs and could impose additional or more stringent requirements. The primary regulatory programs that continue to drive investments in AEP’s existing 10


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    generating units include: (a) periodic revisions to NAAQS and the development of SIPs to achieve any more stringent standards, (b) implementation of the regional haze program by the states and the Federal EPA, (c) regulation of hazardous air pollutant emissions under MATS, (d) implementation and review of CSAPR and (e) the Federal EPA’s regulation of greenhouse gas emissions from fossil generation under Section 111 of the CAA. Notable developments in significant CAA regulatory requirements affecting AEP’s operations are discussed in the following sections. National Ambient Air Quality Standards The Federal EPA issued new, more stringent NAAQS for PM in 2012 and ozone in 2015. The Federal EPA is currently reviewing both of these standards. The existing standards for NO2 and SO2 were retained after review by the Federal EPA in 2018 and 2019, respectively. Implementation of these standards is underway. The Federal EPA finalized non-attainment designations for the 2015 ozone standard in 2018. The Federal EPA confirmed that for states included in the CSAPR program, there are no additional interstate transport obligations, as all areas of the country are expected to attain the 2008 ozone standard before 2023. Challenges to the 2015 ozone standard and the Federal EPA’s determination that CSAPR satisfies certain states’ interstate transport obligations were filed in the U.S. Court of Appeals for the District of Columbia Circuit. In August 2019, the court upheld the 2015 primary ozone standard, but remanded the secondary welfare-based standard for further review. The court vacated the Federal EPA’s determination that CSAPR fulfilled the states’ interstate transport obligations, because the Federal EPA’s modeling analysis did not demonstrate that all significant contributions would be eliminated by the attainment deadlines for downwind states. Any further changes will require additional rulemaking. Management cannot currently predict the nature, stringency or timing of additional requirements for AEP’s facilities based on the outcome of these activities. 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. The Federal EPA initially disapproved portions of the Arkansas regional haze SIP, but has approved a revised SIP and all of SWEPCo's affected units are in compliance with the relevant requirements. The Federal EPA also disapproved portions of the Texas regional haze SIP. In 2017, the Federal EPA finalized a FIP that allows participation in the CSAPR ozone season program to satisfy the NOx regional haze obligations for electric generating units in Texas. Additionally, the Federal EPA finalized an intrastate SO2 emissions trading program based on CSAPR allowance allocations. A challenge to the FIP was filed in the U.S. Court of Appeals for the Fifth Circuit and the case is pending the Federal EPA’s reconsideration of the final rule. In August 2018, the Federal EPA proposed to affirm its 2017 FIP approval. In November 2019, in response to comment, the Federal EPA proposed revisions to the intrastate trading program. Management supports the intrastate trading program as a compliance alternative to source-specific controls. Cross-State Air Pollution Rule In 2011, the Federal EPA issued CSAPR as a replacement for the Clean Air Interstate Rule, a regional trading program designed to address interstate transport of emissions that contributed significantly to downwind non-attainment with the 1997 ozone and PM NAAQS. CSAPR relies on SO2 and NOx 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 NOx 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. 11


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    In 2016, the Federal EPA issued a final rule, the CSAPR Update, to address the remand and to incorporate additional changes necessary to address the 2008 ozone standard. The CSAPR Update significantly reduced ozone season budgets in many states and discounted the value of banked CSAPR ozone season allowances beginning with the 2017 ozone season. In 2019, the appeals court remanded the CSAPR Update to the Federal EPA because it determined the Federal EPA had not properly considered the attainment dates for downwind areas in establishing its partial remedy, and should have considered whether there were available measures to control emissions from sources other than generating units. Any further changes to the CSAPR rule will require additional rulemaking. Mercury and Other Hazardous Air Pollutants (HAPs) Regulation In 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants. The rule established unit-specific emission rates for units burning coal on a 30-day rolling average basis for mercury, PM (as a surrogate for particles of non-mercury metals) and hydrogen chloride (as a surrogate for acid gases). In addition, the rule proposed work practice standards for controlling emissions of organic HAPs and dioxin/furans, with compliance required within three years. Management obtained administrative extensions for up to one year at several units to facilitate the installation of controls or to avoid a serious reliability problem. In 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied all of the petitions for review of the 2012 final rule. Various intervenors filed petitions for further review in the U.S. Supreme Court. In 2015, the U.S. Supreme Court reversed the decision of the U.S. Court of Appeals for the District of Columbia Circuit. The court remanded the MATS rule to the Federal EPA to consider costs in determining whether to regulate emissions of HAPs from power plants. In 2016, the Federal EPA issued a supplemental finding concluding that, after considering the costs of compliance, it was appropriate and necessary to regulate HAP emissions from coal and oil-fired units. Petitions for review of the Federal EPA’s determination were filed in the U.S. Court of Appeals for the District of Columbia Circuit. In 2018, the Federal EPA released a revised finding that the costs of reducing HAP emissions to the level in the current rule exceed the benefits of those HAP emission reductions. The Federal EPA also determined that there are no significant changes in control technologies and the remaining risks associated with HAP emissions do not justify any more stringent standards. Therefore, the Federal EPA proposed to retain the current MATS standards without change. Climate Change, CO2 Regulation and Energy Policy In 2015, the Federal EPA published the final CO2 emissions standards for new, modified and reconstructed fossil generating units, and final guidelines for the development of state plans to regulate CO2 emissions from existing sources, known as the Clean Power Plan (CPP). In 2016, the U.S. Supreme Court issued a stay of the final CPP, including all of the deadlines for submission of initial or final state plans until a final decision is issued by the U.S. Court of Appeals for the District of Columbia Circuit and the U.S. Supreme Court considers any petition for review. In 2017, the President issued an Executive Order directing the Federal EPA to reconsider the CPP and the associated standards for new sources. The Federal EPA filed a motion to hold the challenges to the CPP in abeyance pending reconsideration. In September 2019, following the Federal EPA’s repeal of the CPP and promulgation of a replacement rule, the Court of Appeals for the District of Columbia Circuit dismissed the challenges. In July 2019, the Federal EPA finalized the Affordable Clean Energy (ACE) rule to replace the CPP with new emission guidelines for regulating CO2 from existing sources. ACE establishes a framework for states to adopt standards of performance for utility boilers based on heat rate improvements for such boilers. The final rule applies to generating units that commenced construction prior to January 2014, generate greater than 25 MWs, have a baseload rating above 250 MMBtu per hour and burn coal for more than 10% of the annual average heat input over the preceding three calendar years, with certain exceptions. States must establish standards of performance for each affected facility in terms of pounds of CO2 emitted per MWh, based on certain heat rate improvement measures and the degree of emission reduction achievable through each applicable measure, together with consideration of certain site-specific factors and the unit’s remaining useful life. State plans are required to be submitted in 2022, and the Federal EPA has up to two 12


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    years to review and approve a plan or disapprove it and adopt a federal plan. The final ACE rule has been challenged in the courts. In 2018, the Federal EPA filed a proposed rule revising the standards for new sources and determined that partial carbon capture and storage is not the best system of emission reduction because it is not available throughout the U.S. and is not cost-effective. Management continues to actively monitor these rulemaking activities. AEP has taken action to reduce and offset CO2 emissions from its generating fleet. AEP expects CO2 emissions from its operations to continue to decline due to the retirement of some of its coal-fired generation units, and actions taken to diversify the generation fleet and increase energy efficiency where there is regulatory support for such activities. The majority of the states where AEP has generating facilities passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements that can assist in reducing carbon emissions. Management is taking steps to comply with these requirements, including increasing wind and solar installations, purchasing renewable power and broadening AEP System’s portfolio of energy efficiency programs. In September 2019, AEP announced new intermediate and long-term CO2 emission reduction goals, based on the output of the company’s integrated resource plans, which take into account economics, customer demand, grid reliability and resiliency, regulations and the company’s current business strategy. The intermediate goal is a 70% reduction from 2000 CO2 emission levels from AEP generating facilities by 2030; the long-term goal is to surpass an 80% reduction of CO2 emissions from AEP generating facilities from 2000 levels by 2050. AEP’s total estimated CO2 emissions in 2019 were approximately 58 million metric tons, a 65% reduction from AEP’s 2000 CO2 emissions. AEP has made significant progress in reducing CO2 emissions from its power generation fleet and expects its emissions to continue to decline. AEP’s aspirational emissions goal is zero CO2 emissions by 2050. Technological advances, including energy storage, will determine how quickly AEP can achieve zero emissions while continuing to provide reliable, affordable power for customers. Federal and state legislation or regulations that mandate limits on the emission of CO2 could result in significant increases in capital expenditures and operating costs, which in turn, could lead to increased liquidity needs and higher financing costs. Excessive costs to comply with future legislation or regulations might force AEP to close some coal- fired facilities, which could possibly lead to impairment of assets. Coal Combustion Residual (CCR) Rule In 2015, the Federal EPA published a final rule to regulate the disposal and beneficial re-use of CCR, including fly ash and bottom ash created from coal-fired generating units and FGD gypsum generated at some coal-fired plants. The rule applies to active CCR landfills and surface impoundments at operating electric utility or independent generation facilities. The rule imposes construction and operating obligations, including location restrictions, liner criteria, structural integrity requirements for impoundments, operating criteria and additional groundwater monitoring requirements to be implemented on a schedule spanning an approximate four-year implementation period. In 2018, some of AEP’s facilities were required to begin monitoring programs to determine if unacceptable groundwater impacts will trigger future corrective measures. Based on additional groundwater data, further studies to design and assess appropriate corrective measures have been undertaken at four facilities. In a challenge to the final 2015 rule, the parties initially agreed to settle some of the issues. In 2018, the U.S. Court of Appeals for the District of Columbia Circuit addressed or dismissed the remaining issues in its decision vacating and remanding certain provisions of the 2015 rule. The provisions addressed by the court’s decision, including changes to the provisions for unlined impoundments and legacy sites, will be the subject of further rulemaking consistent with the court’s decision. Prior to the court’s decision, the Federal EPA issued the July 2018 rule that modifies certain compliance deadlines and other requirements in the 2015 rule. In December 2018, challengers filed a motion for partial stay or vacatur of the July 2018 rule. On the same day, the Federal EPA filed a motion for partial remand of the July 2018 rule. The court granted the Federal EPA’s motion. In November 2019, the Federal EPA proposed revisions to implement the court’s decision regarding the timing for closure of unlined surface impoundments along with impoundments not meeting the 13


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    required distance from an aquifer. The comment period closed in January 2020. In December 2019, the Federal EPA proposed a federal permit program, implementing the Water Infrastructure Improvements for the Nation Act, that would apply in states that do not have an approved CCR program. Other utilities and industrial sources have been engaged in litigation with environmental advocacy groups who claim that releases of contaminants from wells, CCR units, pipelines and other facilities to groundwaters that have a hydrologic connection to a surface water body represent an “unpermitted discharge” under the CWA. Two cases were accepted by the U.S. Supreme Court for further review of the scope of CWA jurisdiction. 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. Additional ARO revisions will occur on a site-by-site basis if groundwater monitoring activities conclude that corrective actions are required to mitigate groundwater impacts, which could include costs to remove ash from some unlined units. In January 2020, a bill was introduced in Virginia to require removal of ash from units at the retired Glen Lyn Station, and provide for recovery of the costs incurred to remove the ash and close those units. If removal of ash is required without providing similar assurances of cost recovery in regulated jurisdictions, it would impose significant additional operating costs on AEP, which could lead to increased financing costs and liquidity needs. Other units in Virginia, Ohio, West Virginia, and Kentucky already have been closed in place in accordance with state law programs. Management will continue to 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. In April 2019, the Fifth Circuit vacated the standards for landfill leachate and legacy wastewater, and remanded them to the Federal EPA for reconsideration. In November 2019, the Federal EPA proposed revisions to the guidelines for existing generation facilities. The comment period ended in January 2020. Management is assessing technology additions and retrofits to comply with the rule and the impacts of the Federal EPA’s recent actions on facilities’ wastewater discharge permitting. In 2015, the Federal EPA and the U.S. Army Corps of Engineers jointly issued a final rule to clarify the scope of the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases. Various parties challenged the 2015 rule in different U.S. District Courts, which resulted in a patchwork of applicability of the 2015 rule and its predecessor. In December 2018, the Federal EPA and the U.S. Army Corps of Engineers proposed a replacement rule. In September 2019, the Federal EPA repealed the 2015 rule. A final rule was issued in January 2020, which limits that scope of CWA jurisdiction to four categories of waters, and clarifies exclusions for ground water, ephemeral streams, ditches, artificial ponds and waste treatment systems. 14


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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 Contracted renewable energy investments and management services. Competitive generation in ERCOT and PJM. Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. 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, interest expense, income tax expense and other nonallocated costs. The following discussion of AEP’s 2019 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, Generation Deferrals 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, these expenses 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. 15


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    A detailed discussion of AEP’s 2018 results of operations by operating segment can be found in Management’s Discussion and Analysis of Financial Condition and Results of Operation section included in the 2018 Annual Report on Form 10-K filed with the SEC on February 21, 2019. The following table presents Earnings (Loss) Attributable to AEP Common Shareholders by segment: Years Ended December 31, 2019 2018 2017 (in millions) Vertically Integrated Utilities $ 982.0 $ 990.5 $ 790.5 Transmission and Distribution Utilities 451.0 527.4 636.4 AEP Transmission Holdco 516.3 369.9 352.1 Generation & Marketing 112.8 135.3 166.0 Corporate and Other (141.0) (99.3) (32.4) Earnings Attributable to AEP Common Shareholders $ 1,921.1 $ 1,923.8 $ 1,912.6 Note: 2019 Earnings Attributable to AEP Common Shareholders by Segment excludes Corporate and Other which is not considered a reportable segment. 16


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    AEP CONSOLIDATED 2019 Compared to 2018 Earnings Attributable to AEP Common Shareholders decreased $3 million from $1.924 billion in 2018 to $1.921 billion in 2019 primarily due to: A decrease in weather-related usage. An increase in asset impairments and other related charges. These decreases were partially offset by: Favorable rate proceedings in AEP’s various jurisdictions. An increase in transmission investment, which resulted in higher revenues and income. AEP’s results of operations by reportable segment are discussed below. 17


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    VERTICALLY INTEGRATED UTILITIES (a) Other AEP Segments excludes Corporate and Other which is not considered a reportable segment. Years Ended December 31, Vertically Integrated Utilities 2019 2018 2017 (in millions) Revenues $ 9,367.1 $ 9,645.5 $ 9,192.0 Fuel and Purchased Electricity 3,103.1 3,488.9 3,142.7 Gross Margin 6,264.0 6,156.6 6,049.3 Other Operation and Maintenance 2,934.4 2,959.8 2,760.7 Asset Impairments and Other Related Charges 92.9 3.4 33.6 Depreciation and Amortization 1,447.0 1,316.2 1,142.5 Taxes Other Than Income Taxes 460.9 433.2 413.3 Operating Income 1,328.8 1,444.0 1,699.2 Other Income 6.1 17.0 22.0 Allowance for Equity Funds Used During Construction 50.7 35.4 28.0 Non-Service Cost Components of Net Periodic Benefit Cost 67.6 69.9 23.5 Interest Expense (568.3) (567.8) (540.0) Income Before Income Tax Expense (Benefit) and Equity Earnings (Loss) 884.9 998.5 1,232.7 Income Tax Expense (Benefit) (97.7) 5.7 425.6 Equity Earnings (Loss) of Unconsolidated Subsidiary 3.0 2.7 (3.8) Net Income 985.6 995.5 803.3 Net Income Attributable to Noncontrolling Interests 3.6 5.0 12.8 Earnings Attributable to AEP Common Shareholders $ 982.0 $ 990.5 $ 790.5 18


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    Summary of KWh Energy Sales for Vertically Integrated Utilities Years Ended December 31, 2019 2018 2017 (in millions of KWhs) Retail: Residential 32,359 33,908 30,817 Commercial 23,839 24,452 24,052 Industrial 35,252 35,730 35,043 Miscellaneous 2,302 2,330 2,279 Total Retail (a) 93,752 96,420 92,191 Wholesale (b) 20,090 22,682 25,098 Total KWhs 113,842 119,102 117,289 (a) 2018 and 2017 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. 19


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    Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues. In general, degree day changes in the eastern region have a larger effect on revenues than changes in the western region due to the relative size of the two regions and the number of customers within each region. Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities Years Ended December 31, 2019 2018 2017 (in degree days) Eastern Region Actual – Heating (a) 2,617 2,886 2,298 Normal – Heating (b) 2,732 2,738 2,746 Actual – Cooling (c) 1,369 1,443 1,088 Normal – Cooling (b) 1,092 1,083 1,078 Western Region Actual – Heating (a) 1,512 1,599 1,040 Normal – Heating (b) 1,473 1,475 1,494 Actual – Cooling (c) 2,328 2,502 2,164 Normal – Cooling (b) 2,240 2,230 2,229 (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. 20


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    2019 Compared to 2018 Reconciliation of Year Ended December 31, 2018 to Year Ended December 31, 2019 Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities (in millions) Year Ended December 31, 2018 $ 990.5 Changes in Gross Margin: Retail Margins 134.1 Margins from Off-system Sales (16.0) Transmission Revenues (14.0) Other Revenues 3.3 Total Change in Gross Margin 107.4 Changes in Expenses and Other: Other Operation and Maintenance 25.4 Asset Impairments and Other Related Charges (89.5) Depreciation and Amortization (130.8) Taxes Other Than Income Taxes (27.7) Other Income (10.9) Allowance for Equity Funds Used During Construction 15.3 Non-Service Cost Components of Net Periodic Pension Cost (2.3) Interest Expense (0.5) Total Change in Expenses and Other (221.0) Income Tax Expense (Benefit) 103.4 Equity Earnings (Loss) of Unconsolidated Subsidiary 0.3 Net Income Attributable to Noncontrolling Interests 1.4 Year Ended December 31, 2019 $ 982.0 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 $134 million primarily due to the following: A $91 million increase at APCo and WPCo due to a 2018 reduction in the deferred fuel under recovery balance as a result of the 2018 West Virginia Tax Reform settlement. This increase was offset in Income Tax Expense (Benefit) below. A $30 million increase at APCo in deferred fuel related to recoverable PJM expenses that were offset below. A $10 million increase due to 2018 Virginia legislation which increased non-recoverable fuel expense at APCo in the prior year. The effect of rate proceedings in AEP’s service territories which included: A $112 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 $46 million increase at PSO due to new base rates implemented in April 2019 and March 2018. A $28 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 $23 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. A $21 million increase at APCo and WPCo due to base rate increases in West Virginia implemented in March 2019. A $20 million increase at SWEPCo primarily due to rider and base rate revenue increases in Louisiana and Texas. This increase was offset in other expense items below. A $6 million decrease at I&M in fuel-related expenses due to timing of recovery for fuel and other variable production costs related to wholesale contracts. 21


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    These increases were partially offset by: A $120 million decrease due to customer refunds related to Tax Reform primarily at APCo, PSO and SWEPCo. This decrease was partially offset in Income Tax Expense (Benefit) below. A $102 million decrease in weather-related usage across all regions primarily in the residential and commercial classes. A $61 million decrease in weather-normalized retail margins primarily in the eastern region across all classes. Margins from Off-system Sales decreased $16 million primarily due to mid-year 2018 changes in the Indiana OSS sharing mechanism at I&M and lower volumes across the system. Transmission Revenues decreased $14 million primarily due to the following: A $40 million decrease in the annual SPP formula rate true-up at SWEPCo. A $19 million decrease at SWEPCo and PSO primarily due to a decrease in SPP Base Plan Funding Revenues. A $5 million decrease due to a $14 million decrease at I&M, partially offset by a $9 million increase at KPCo and WPCo due to the 2018 PJM Transmission formula rate true-up. These decreases were partially offset by: An $18 million increase in the net revenue requirement at APCo. A $16 million increase at APCo due to 2018 PJM provisions for refunds. A $16 million increase due to a provision for refund recorded at SWEPCo and PSO in 2018 related to certain transmission assets that management believes should not have been included in the SPP formula rate. Expenses and Other and Income Tax Expense changed between years as follows: Other Operation and Maintenance expenses decreased $25 million primarily due to the following: A $73 million decrease in planned plant outage and maintenance expenses primarily at I&M, APCo, SWEPCo and KPCo. A $58 million decrease due to SPP transmission services including the annual formula rate true-up. A $40 million decrease due to Wind Catcher Project expenses incurred in 2018 at SWEPCo and PSO. A $40 million decrease at APCo and WPCo due to the extinguishment of certain regulatory asset balances as agreed to within the 2018 West Virginia Tax Reform settlement. This decrease is partially offset in Retail Margins above and Income Tax Expense (Benefit) below. A $25 million decrease in recoverable expenses primarily associated with Energy Efficiency/Demand Response and storm-related expenses fully recovered in rate riders/trackers within Gross Margin above. A $10 million decrease in expense at APCo due to lower current year amortization of certain regulatory assets that were extinguished in August 2018 as agreed to within the 2018 West Virginia Tax Reform settlement. A $10 million decrease in estimated expense for claims related to asbestos exposure. These decreases were partially offset by: A $131 million increase due to PJM transmission services including the annual formula rate true-up. A $31 million increase in charitable contributions, primarily to the AEP Foundation. A $25 million increase in employee-related expenses. A $15 million increase at APCo and WPCo due to 2019 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 due to the modification of the NSR consent decree impacting I&M and AEGCo. A $7 million increase due to North Central Wind Energy Facilities expenses at SWEPCo and PSO. A $4 million increase due to the disallowance of previously recorded capital incentives at SWEPCo as a result of the December 2018 APSC final order. A $4 million increase in accounts receivable factoring expense primarily at I&M and SWEPCo. Asset Impairments and Other Related Charges increased $90 million primarily due to a pretax expense recorded in 2019 related to previously retired coal-fired assets. Depreciation and Amortization expenses increased $131 million primarily due to a higher depreciable base and increased depreciation rates approved at APCo, I&M, PSO and SWEPCo. 22


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    Taxes Other Than Income Taxes increased $28 million primarily due to the following: A $15 million increase in property taxes driven by an increase in utility plant. A $13 million increase in West Virginia business and occupational taxes at APCo and WPCo. Other Income decreased $11 million primarily due the following: A $6 million decrease in carrying charges on certain riders at I&M. A $4 million decrease in affiliated interest income at SWEPCo and I&M due to lower Utility Money Pool investment balances. Allowance for Equity Funds Used During Construction increased $15 million primarily due to the following: A $10 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 decreased $103 million primarily due to additional amortization of Excess ADIT not subject to normalization requirements as a result of finalized rate orders in 2019, a decrease in pretax book income and a decrease in state tax expense. The amortization of Excess ADIT is partially offset in Gross Margin and Other Operation and Maintenance expenses above. 23


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    TRANSMISSION AND DISTRIBUTION UTILITIES (a) Other AEP Segments excludes Corporate and Other which is not considered a reportable segment. Years Ended December 31, Transmission and Distribution Utilities 2019 2018 2017 (in millions) Revenues $ 4,482.5 $ 4,653.1 $ 4,419.3 Purchased Electricity 794.3 858.3 835.3 Amortization of Generation Deferrals 65.3 223.9 229.2 Gross Margin 3,622.9 3,570.9 3,354.8 Other Operation and Maintenance 1,628.1 1,541.7 1,199.3 Asset Impairments and Other Related Charges 32.5 — — Depreciation and Amortization 789.5 734.1 667.5 Taxes Other Than Income Taxes 575.0 545.3 513.7 Operating Income 597.8 749.8 974.3 Interest and Investment Income 6.6 4.2 7.7 Carrying Costs Income 1.0 1.7 3.6 Allowance for Equity Funds Used During Construction 33.4 29.9 13.2 Non-Service Cost Components of Net Periodic Benefit Cost 30.3 32.3 8.9 Interest Expense (243.3) (248.1) (244.1) Income Before Income Tax Expense (Benefit) 425.8 569.8 763.6 Income Tax Expense (Benefit) (25.2) 42.4 127.2 Net Income 451.0 527.4 636.4 Net Income Attributable to Noncontrolling Interests — — — Earnings Attributable to AEP Common Shareholders $ 451.0 $ 527.4 $ 636.4 24


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    Summary of KWh Energy Sales for Transmission and Distribution Utilities Years Ended December 31, 2019 2018 2017 (in millions of KWhs) Retail: Residential 26,407 27,042 25,108 Commercial 25,018 24,877 24,724 Industrial 23,289 23,908 23,673 Miscellaneous 779 760 757 Total Retail (a)(b) 75,493 76,587 74,262 Wholesale (c) 2,335 2,441 2,387 Total KWhs 77,828 79,028 76,649 (a) 2018 and 2017 KWhs have been revised to reflect the reclassification of certain customer accounts between Retail classes. This reclassification did not impact previously reported Total Retail KWhs. Management concluded that these prior period disclosure only errors were immaterial individually and in the aggregate. (b) Represents energy delivered to distribution customers. (c) Primarily Ohio’s contractually obligated purchases of OVEC power sold into PJM. 25


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    Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues. In general, degree day changes in the eastern region have a larger effect on revenues than changes in the western region due to the relative size of the two regions and the number of customers within each region. Summary of Heating and Cooling Degree Days for Transmission and Distribution Utilities Years Ended December 31, 2019 2018 2017 (in degree days) Eastern Region Actual – Heating (a) 3,071 3,357 2,709 Normal – Heating (b) 3,208 3,215 3,225 Actual – Cooling (c) 1,224 1,402 1,002 Normal – Cooling (b) 992 980 974 Western Region Actual – Heating (a) 301 354 239 Normal – Heating (b) 322 325 330 Actual – Cooling (d) 2,989 2,861 2,950 Normal – Cooling (b) 2,699 2,688 2,669 (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. 26


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    2019 Compared to 2018 Reconciliation of Year Ended December 31, 2018 to Year Ended December 31, 2019 Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities (in millions) Year Ended December 31, 2018 $ 527.4 Changes in Gross Margin: Retail Margins (65.2) Margins from Off-system Sales 11.8 Transmission Revenues 85.6 Other Revenues 19.8 Total Change in Gross Margin 52.0 Changes in Expenses and Other: Other Operation and Maintenance (86.4) Asset Impairments and Other Related Charges (32.5) Depreciation and Amortization (55.4) Taxes Other Than Income Taxes (29.7) Interest and Investment Income 2.4 Carrying Costs Income (0.7) Allowance for Equity Funds Used During Construction 3.5 Non-Service Cost Component of Net Periodic Benefit Cost (2.0) Interest Expense 4.8 Total Change in Expenses and Other (196.0) Income Tax Expense (Benefit) 67.6 Year Ended December 31, 2019 $ 451.0 The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows: Retail Margins decreased $65 million primarily due to the following: A $103 million net decrease in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses. This decrease was partially offset in Other Operation and Maintenance expenses below. A $30 million decrease due to a provision for refund in the 2019 Texas Base Rate Case. A $25 million decrease in Ohio Deferred Asset Phase-In-Recovery Rider revenues which ended in the second quarter of 2019. This decrease was offset in Depreciation and Amortization expenses below. A $22 million decrease in revenues associated with a vegetation management rider in Ohio. This decrease was offset in Other Operation and Maintenance expenses below. A $21 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 $21 million net decrease in margin in Ohio for the Rate Stability Rider including associated amortizations which ended in the third quarter of 2019. A $10 million decrease in weather-normalized margins primarily in the residential and commercial classes. These decreases were partially offset by: A $58 million increase due to a reversal of a regulatory provision in Ohio. A $41 million increase in revenues associated with Ohio smart grid riders. This increase was partially offset in other expense items below. A $33 million net increase due to 2018 adjustments to the distribution decoupling under-recovery balance as a result of the 2018 Ohio Tax Reform settlement and changes in tax riders. This increase was partially offset in Income Tax Expense (Benefit) below. 27


  • Page 39

    A $30 million increase due to the recovery of higher current year losses from a power contract with OVEC in Ohio. This increase was offset in Margins from Off-system Sales below. An $11 million increase in Ohio Energy Efficiency/Peak Demand Reduction rider revenues. This increase was offset in Other Operation and Maintenance expenses below. Margins from Off-system Sales increased $12 million primarily due to the following: A $42 million increase due to higher affiliated PPA revenues in Texas. This increase was partially offset in Other Operation and Maintenance expenses below. This increase was partially offset by: A $31 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 in Retail Margins above. Transmission Revenues increased $86 million primarily due to recovery of increased transmission investment in ERCOT. Other Revenues increased $20 million primarily due to the following: An $11 million increase primarily due to securitization revenue. This increase was offset below in Depreciation and Amortization expenses and in Interest Expense. A $7 million increase primarily due to distribution connection fees and pole attachment revenues in Ohio. Expenses and Other and Income Tax Expense (Benefit) changed between years as follows: Other Operation and Maintenance expenses increased $86 million primarily due to the following: A $68 million increase in PJM expenses primarily related to the annual formula rate true-up. 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 in Income Tax Expense (Benefit) below. A $49 million increase in affiliated PPA expenses in Texas. This increase was offset in Margins from Off- system Sales above. A $12 million increase due to a charitable contribution to the AEP Foundation. These increases were partially offset by: A $117 million decrease in transmission expenses that were fully recovered in rate riders/trackers in Gross Margin above. Asset Impairments and Other Related Charges increased $33 million due to regulatory disallowances in the 2019 Texas Base Rate Case. Depreciation and Amortization expenses increased $55 million primarily due to the following: A $68 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets. A $17 million increase in securitization amortizations in Texas. This increase was offset in Other Revenues above and in Interest Expense below. An $11 million increase due to lower deferred equity amortizations associated with the Deferred Asset Phase- In-Recovery Rider in Ohio which ended in the second quarter of 2019. A $6 million increase in depreciation expense related to the Oklaunion Power Station. These increases were partially offset by: A $26 million decrease in Ohio recoverable DIR depreciation expense. This decrease was partially offset in Retail Margins above. A $23 million decrease in amortizations associated with the Deferred Asset Phase-In-Recovery Rider in Ohio which ended in the second quarter of 2019. This decrease was offset in Retail Margins above. Taxes Other Than Income Taxes increased $30 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 the following: An $8 million increase in Ohio primarily due to adjustments that resulted from 2019 FERC audit findings. This increase was partially offset by: A $5 million decrease in the Equity component as a result of higher short-term debt balances, partially offset by increased transmission projects. 28


  • Page 40

    Interest Expense decreased $5 million primarily due to the following: A $21 million decrease 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. An $11 million decrease in expense related to Securitization assets. This decrease was offset in Other Revenues and Depreciation and Amortization expenses above. These decreases were partially offset by: A $22 million increase due to higher long-term debt balances. A $2 million increase due to higher short-term debt balances. Income Tax Expense (Benefit) decreased $68 million primarily due to an increase in 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 and a decrease in pretax book income. This decrease was partially offset above in Retail Margins and Other Operation and Maintenance expenses. 29


  • Page 41

    AEP TRANSMISSION HOLDCO (a) Other AEP Segments excludes Corporate and Other which is not considered a reportable segment. Years Ended December 31, AEP Transmission Holdco 2019 2018 2017 (in millions) Transmission Revenues $ 1,073.2 $ 804.1 $ 766.7 Other Operation and Maintenance 119.0 105.6 74.7 Depreciation and Amortization 183.4 137.8 102.2 Taxes Other Than Income Taxes 174.4 142.3 114.0 Operating Income 596.4 418.4 475.8 Other Income 3.4 2.1 1.0 Allowance for Equity Funds Used During Construction 84.3 67.2 52.5 Non-Service Cost Components of Net Periodic Benefit Cost 2.7 2.6 0.3 Interest Expense (103.3) (90.7) (72.8) Income Before Income Tax Expense and Equity Earnings 583.5 399.6 456.8 Income Tax Expense 136.2 95.3 189.8 Equity Earnings of Unconsolidated Subsidiary 72.8 68.7 88.6 Net Income 520.1 373.0 355.6 Net Income Attributable to Noncontrolling Interests 3.8 3.1 3.5 Earnings Attributable to AEP Common Shareholders $ 516.3 $ 369.9 $ 352.1 30


  • Page 42

    Summary of Investment in Transmission Assets for AEP Transmission Holdco December 31, 2019 2018 2017 (in millions) Plant in Service $ 8,812.2 $ 7,008.4 $ 5,784.6 Construction Work in Progress 1,521.8 1,651.1 1,325.6 Accumulated Depreciation and Amortization 418.9 282.8 176.6 Total Transmission Property, Net $ 9,915.1 $ 8,376.7 $ 6,933.6 31


  • Page 43

    2019 Compared to 2018 Reconciliation of Year Ended December 31, 2018 to Year Ended December 31, 2019 Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco (in millions) Year Ended December 31, 2018 $ 369.9 Changes in Transmission Revenues: Transmission Revenues 269.1 Total Change in Transmission Revenues 269.1 Changes in Expenses and Other: Other Operation and Maintenance (13.4) Depreciation and Amortization (45.6) Taxes Other Than Income Taxes (32.1) Other Income 1.3 Allowance for Equity Funds Used During Construction 17.1 Non-Service Cost Components of Net Periodic Pension Cost 0.1 Interest Expense (12.6) Total Change in Expenses and Other (85.2) Income Tax Expense (40.9) Equity Earnings of Unconsolidated Subsidiary 4.1 Net Income Attributable to Noncontrolling Interests (0.7) Year Ended December 31, 2019 $ 516.3 The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and nonaffiliates were as follows: Transmission Revenues increased $269 million primarily due to continued investment in transmission assets. Expenses and Other, Income Tax Expense and Equity Earnings of Unconsolidated Subsidiaries changed between years as follows: Other Operation and Maintenance expenses increased $13 million primarily due to the following: A $7 million increase due to a charitable contribution to the AEP Foundation. A $6 million increase due to continued investment in transmission assets. Depreciation and Amortization expenses increased $46 million primarily due to a higher depreciable base. Taxes Other Than Income Taxes increased $32 million primarily due to higher property taxes as a result of increased transmission investment. Allowance for Equity Funds Used During Construction increased $17 million primarily due to the following: An $18 million increase due to higher monthly CWIP balances. A $12 million increase due to the FERC’s approval of a settlement agreement. These increases were partially offset by: A $13 million decrease due to recent FERC audit findings. Interest Expense increased $13 million primarily due to higher long-term debt balances. Income Tax Expense increased $41 million primarily due to higher pretax book income. Equity Earnings of Unconsolidated Subsidiaries increased $4 million primarily due to higher pretax equity earnings at ETT. 32


  • Page 44

    GENERATION & MARKETING (a) Other AEP Segments excludes Corporate and Other which is not considered a reportable segment. Years Ended December 31, Generation & Marketing 2019 2018 2017 (in millions) Revenues $ 1,857.6 $ 1,940.3 $ 1,875.1 Fuel, Purchased Electricity and Other 1,456.2 1,537.3 1,377.2 Gross Margin 401.4 403.0 497.9 Other Operation and Maintenance 223.8 229.3 279.5 Asset Impairments and Other Related Charges 31.0 47.7 53.5 Gain on Sale of Merchant Generation Assets — — (226.4) Depreciation and Amortization 69.5 41.0 24.2 Taxes Other Than Income Taxes 15.6 13.4 12.1 Operating Income 61.5 71.6 355.0 Interest and Investment Income 7.7 13.1 10.3 Non-Service Cost Components of Net Periodic Benefit Cost 14.9 15.2 8.9 Interest Expense (30.0) (14.9) (18.5) Income Before Income Tax Expense (Benefit) and Equity Earnings (Loss) 54.1 85.0 355.7 Income Tax Expense (Benefit) (53.8) (49.2) 189.7 Equity Earnings (Loss) of Unconsolidated Subsidiaries (3.8) 0.5 — Net Income 104.1 134.7 166.0 Net Loss Attributable to Noncontrolling Interests (8.7) (0.6) — Earnings Attributable to AEP Common Shareholders $ 112.8 $ 135.3 $ 166.0 33


  • Page 45

    Summary of MWhs Generated for Generation & Marketing Years Ended December 31, 2019 2018 2017 (in millions of MWhs) Fuel Type: Coal 6 8 12 Natural Gas — — 2 Renewables 2 1 1 Total MWhs 8 9 15 34


  • Page 46

    2019 Compared to 2018 Reconciliation of Year Ended December 31, 2018 to Year Ended December 31, 2019 Earnings Attributable to AEP Common Shareholders from Generation & Marketing (in millions) Year Ended December 31, 2018 $ 135.3 Changes in Gross Margin: Merchant Generation (73.3) Renewable Generation 31.9 Retail, Trading and Marketing 39.8 Total Change in Gross Margin (1.6) Changes in Expenses and Other: Other Operation and Maintenance 5.5 Asset Impairments and Other Related Charges 16.7 Depreciation and Amortization (28.5) Taxes Other Than Income Taxes (2.2) Interest and Investment Income (5.4) Non-Service Cost Components of Net Periodic Benefit Cost (0.3) Interest Expense (15.1) Total Change in Expenses and Other (29.3) Income Tax Expense (Benefit) 4.6 Equity Earnings (Loss) of Unconsolidated Subsidiaries (4.3) Net Loss Attributable to Noncontrolling Interests 8.1 Year Ended December 31, 2019 $ 112.8 The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, purchased electricity and certain cost of service for retail operations were as follows: Merchant Generation decreased $73 million primarily due to the following: A $42 million decrease due to reduced capacity and energy margins. A $17 million decrease due to the retirement of the Stuart Plant in 2018. A $14 million decrease due to the retirement of Conesville Units 5 and 6 in 2019. Renewable Generation increased $32 million primarily due to the Sempra Renewables LLC acquisition and other renewable projects placed in-service. Retail, Trading and Marketing increased $40 million due to higher retail margins due to lower market costs and higher delivered volumes and higher marketing activity in 2019. Expenses and Other and Income Tax Expense (Benefit) changed between years as follows: Other Operation and Maintenance expenses decreased $6 million primarily due to the retirement of the Stuart Plant and Conesville Units 5 and 6 partially offset by expenses related to the Sempra Renewables LLC acquisition and increased investments in wind farms and renewable energy sources. Asset Impairments and Other Related Charges decreased $17 million primarily due to a $35 million decrease in impairment charges related to Racine partially offset by a $19 million increase in impairment charges related to the Conesville plant in 2019. Depreciation and Amortization expenses increased $29 million primarily due to a higher depreciable base from increased investments in renewable energy sources. 35


  • Page 47

    Interest Expense increased $15 million primarily due to increased borrowing costs related to the Sempra Renewables LLC acquisition. Income Tax Expense (Benefit) increased $5 million primarily due to an increase in income and production tax credits related to the Sempra Renewables LLC and Santa Rita East acquisitions. This increase was partially offset by a decrease in parent savings in 2019. Equity Earnings of Unconsolidated Subsidiaries decreased $4 million primarily due to the Sempra Renewables LLC acquisition. Net Loss Attributed to Noncontrolling Interests increased $8 million primarily due to the Sempra Renewables LLC acquisition. 36


  • Page 48

    CORPORATE AND OTHER 2019 Compared to 2018 Earnings attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $99 million in 2018 to a loss of $141 million in 2019 primarily due to: A $71 million increase in interest expense as a result of increased debt outstanding. A $12 million increase in general corporate expenses. A $6 million increase in tax expense primarily due to the following: A $23 million increase in state income tax expense related to unitary state filing requirements. 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. These increases were partially offset by: A $43 million decrease due to a decrease in the allocation of the parent company loss benefit due to the tax sharing agreement. A $5 million write-off 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. An $18 million increase in interest income from affiliates. A $16 million increase in interest income due to a higher return on investments held by EIS. AEP SYSTEM INCOME TAXES 2019 Compared to 2018 Income Tax Expense decreased $128 million primarily due to an increase in amortization of Excess ADIT not subject to normalization requirements as a result of finalized rate orders in 2019, an increase in income and production tax credits driven by the Sempra Renewables LLC and Santa Rita East acquisitions and a decrease in pretax book income. 37


  • Page 49

    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 December 31, 2019 2018 (dollars in millions) Long-term Debt, including amounts due within one year $ 26,725.5 54.1% $ 23,346.7 52.7% Short-term Debt 2,838.3 5.7 1,910.0 4.3 Total Debt 29,563.8 59.8 25,256.7 57.0 AEP Common Equity 19,632.2 39.6 19,028.4 42.9 Noncontrolling Interests 281.0 0.6 31.0 0.1 Total Debt and Equity Capitalization $ 49,477.0 100.0% $ 44,316.1 100.0% AEP’s ratio of debt-to-total capital increased from 57.0% to 59.8% as of December 31, 2018 and 2019, respectively, 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 December 31, 2019, AEP had a $4 billion revolving credit facility to support its commercial paper program. Additional liquidity is available from cash from operations and a receivables securitization agreement. Management is committed to maintaining adequate liquidity. AEP generally uses short-term borrowings to fund working capital needs, property acquisitions and construction until long- term funding is arranged. Sources of long-term funding include issuance of long-term debt, leasing agreements, hybrid securities or common stock. Net Available Liquidity AEP manages liquidity by maintaining adequate external financing commitments. As of December 31, 2019, available liquidity was $2.1 billion as illustrated in the table below: Amount Maturity (in millions) Commercial Paper Backup: Revolving Credit Facility $ 4,000.0 June 2022 Cash and Cash Equivalents 246.8 Total Liquidity Sources 4,246.8 Less: AEP Commercial Paper Outstanding 2,110.0 Net Available Liquidity $ 2,136.8 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 2019 was $2.2 billion. The weighted-average interest rate for AEP’s commercial paper during 2019 was 2.51%. 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 December 31, 2019, was $207 million with maturities ranging from January 2020 to December 2020. 38


  • Page 50

    Financing Plan As of December 31, 2019, AEP had $1.6 billion of long-term debt due within one year. This included $431 million of Pollution Control Bonds with mandatory tender dates and credit support for variable interest rates that requires the debt be classified as current and $392 million of securitization bonds and DCC Fuel notes. Management plans to refinance the majority of the maturities due within one year on a long-term basis. Securitized Accounts Receivables AEP receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and expires in July 2021. Debt Covenants and Borrowing Limitations AEP’s credit agreements contain certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5%. The method for calculating outstanding debt and capitalization is contractually- defined in AEP’s credit agreements. Debt as defined in the revolving credit agreement excludes securitization bonds and debt of AEP Credit. As of December 31, 2019, this contractually-defined percentage was 57.4%. 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 14 - Financing Activities for additional information. Dividend Policy and Restrictions The Board of Directors declared a quarterly dividend of $0.70 per share in January 2020. Future dividends may vary depending upon AEP’s profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. Management does not believe these restrictions will have any significant impact on its ability to access cash to meet the payment of dividends on its common stock. See “Dividend Restrictions” section of Note 14 for additional information. 39

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