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    Appendix A to the Proxy Statement American Electric Power 2017 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 v AEP Common Stock and Dividend Information vii Selected Consolidated Financial Data 1 Management’s Discussion and Analysis of Financial Condition and Results of Operations 2 Reports of Independent Registered Public Accounting Firm 67 Management’s Report on Internal Control Over Financial Reporting 70 Consolidated Statements of Income 71 Consolidated Statements of Comprehensive Income (Loss) 72 Consolidated Statements of Changes in Equity 73 Consolidated Balance Sheets 74 Consolidated Statements of Cash Flows 76 Index of Notes to Financial Statements of Registrants 77 Corporate and Shareholder Information 265 Executive Leadership Team 266


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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 Renewables AEP Renewables, LLC, a wholly-owned subsidiary of Energy Supply formed for the purpose of providing utility scale wind and solar projects whose power output is sold via long-term power purchase agreements to other utilities, cities and corporations. 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. AEPEP AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, hedging activities, asset management and commercial and industrial sales in the deregulated Ohio and Texas market. 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, and its consolidated State Transcos, a subsidiary of AEP Transmission Holdco. 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 Rate Appalachian Consumer Rate Relief Funding LLC, a wholly-owned subsidiary of Relief Funding APCo 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. ASU Accounting Standards Update. CAA Clean Air Act. CAIR Clean Air Interstate Rule. CLECO Central Louisiana Electric Company, a nonaffiliated utility company. CO2 Carbon dioxide and other greenhouse gases. Cook Plant Donald C. Cook Nuclear Plant, a two-unit, 2,278 MW nuclear plant owned by I&M. i


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    Term Meaning CRES provider Competitive Retail Electric Service providers under Ohio law that target retail customers by offering alternative generation service. CWIP Construction Work in Progress. DCC Fuel DCC Fuel VI LLC, DCC Fuel VII, DCC Fuel VIII, DCC Fuel IX, DCC Fuel X and DCC Fuel XI consolidated variable interest entities formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. Desert Sky Desert Sky Wind Farm, a 160.5 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. 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. 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. FTR Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices. GAAP Accounting Principles Generally Accepted in the United States of America. Global Settlement In February 2017, the PUCO approved a settlement agreement filed by OPCo in December 2016 which resolved all remaining open issues on remand from the Supreme Court of Ohio in OPCo’s 2009 - 2011 and June 2012 - May 2015 ESP filings. It also resolved all open issues in OPCo’s 2009, 2014 and 2015 SEET filings and 2009, 2012 and 2013 Fuel Adjustment Clause Audits. I&M Indiana Michigan Power Company, an AEP electric utility subsidiary. Interconnection Agreement An agreement by and among APCo, I&M, KPCo and OPCo, which defined the sharing of costs and benefits associated with their respective generation plants. This agreement was terminated January 1, 2014. IRS Internal Revenue Service. IURC Indiana Utility Regulatory Commission. KGPCo Kingsport Power Company, an AEP electric utility subsidiary. KPCo Kentucky Power Company, an AEP electric utility subsidiary. KPSC Kentucky Public Service Commission. kV Kilovolt. KWh Kilowatthour. LPSC Louisiana Public Service Commission. Market Based Mechanism An order from the LPSC established to evaluate proposals to construct or acquire generating capacity. The LPSC directs that the market based mechanism shall be a request for proposal competitive solicitation process. MISO Midwest Independent Transmission System Operator. ii


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    Term Meaning MLR Member load ratio, the method used to allocate transactions among members of the Interconnection Agreement. MMBtu Million British Thermal Units. MPSC Michigan Public Service Commission. MTM Mark-to-Market. MW Megawatt. MWh Megawatthour. Nonutility Money Pool Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries. NOx Nitrogen oxide. 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 Funding a consolidated variable interest entity formed for the purpose of issuing and servicing securitization bonds related to phase-in recovery property. OPCo Ohio Power Company, an AEP electric utility subsidiary. OPEB Other Postretirement Benefit Plans. 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. 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. PIRR Phase-In Recovery Rider. 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. PUCO Public Utilities Commission of Ohio. PUCT Public Utility Commission of Texas. Putnam Rights and interests in certain coal reserves located in Putnam, Mason and Jackson Counties, West Virginia. 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. Risk Management Contracts Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges. Rockport Plant A generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana. AEGCo and I&M jointly-own Unit 1. In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2. RSR Retail Stability Rider. RTO Regional Transmission Organization, responsible for moving electricity over large interstate areas. Sabine Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity for AEP and SWEPCo. SCR Selective Catalytic Reduction, NOx reduction technology at Rockport Plant. SEC U.S. Securities and Exchange Commission. iii


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    Term Meaning SEET Significantly Excessive Earnings Test. 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. SNF Spent Nuclear Fuel. SO2 Sulfur dioxide. SPP Southwest Power Pool regional transmission organization. SSO Standard service offer. Stall Unit J. Lamar Stall Unit at Arsenal Hill Plant, a 534 MW natural gas unit owned by SWEPCo. 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. TRA Tennessee Regulatory Authority. 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. Transource Missouri A 100% wholly-owned subsidiary of Transource Energy. Trent Trent Wind Farm, a 150 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. Utility Money Pool Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries. VIE Variable Interest Entity. Virginia SCC Virginia State Corporation Commission. Wind Catcher Project Wind Catcher Energy Connection Project, a joint PSO and SWEPCo project which includes the acquisition of a wind generation facility, totaling approximately 2,000 MW of wind generation, and the construction of a generation interconnection tie-line totaling approximately 350 miles. WPCo Wheeling Power Company, an AEP electric utility subsidiary. WVPSC Public Service Commission of West Virginia. iv


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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: Economic growth or contraction within and changes in 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. Electric load and customer growth. 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 spent nuclear fuel. Availability of necessary generation capacity, the performance of generation plants and the availability of fuel, including processed nuclear fuel, parts and service from reliable vendors. The ability to recover fuel and other energy costs through regulated or competitive electric rates. The ability to build 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 particulate matter and other substances that could impact the continued operation, cost recovery and/or profitability of generation plants and related assets. Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel. Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service, environmental compliance and excess accumulated deferred income taxes. 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 capacity and electricity, coal and other energy-related commodities, particularly changes in the price of natural gas. Changes in utility regulation and the allocation of costs within regional transmission organizations, 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, other postretirement benefit plans, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements. v


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    Accounting pronouncements periodically issued by accounting standard-setting bodies. Impact of federal tax reform on customer rates. Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events. The forward-looking statements of the Registrants speak only as of the date of this report or as of the date they are made. The Registrants expressly disclaim any obligation to update any forward-looking information. For a more detailed discussion of these factors, see “Risk Factors” in Part I of this report. Investors should note that the Registrants announce material financial information in SEC filings, press releases and public conference calls. Based on guidance from the SEC, the Registrants may use the Investors section of AEP’s website (www.aep.com) to communicate with investors about the Registrants. It is possible that the financial and other information posted there could be deemed to be material information. The information on AEP’s website is not part of this report. vi


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    AEP COMMON STOCK AND DIVIDEND INFORMATION The AEP common stock quarterly high and low sales prices, quarter-end closing price and the cash dividends paid per share are shown in the following table: Quarter-End Quarter Ended High Low Closing Price Dividend December 31, 2017 $ 78.07 $ 69.55 $ 73.57 $ 0.62 September 30, 2017 74.59 68.11 70.24 0.59 June 30, 2017 72.97 66.50 69.47 0.59 March 31, 2017 68.25 61.82 67.13 0.59 December 31, 2016 $ 65.25 $ 57.89 $ 62.96 $ 0.59 September 30, 2016 71.32 63.56 64.21 0.56 June 30, 2016 70.10 61.42 70.09 0.56 March 31, 2016 66.49 56.75 66.40 0.56 AEP common stock is traded principally on the New York Stock Exchange. As of December 31, 2017, AEP had approximately 63,000 registered shareholders. vii


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    AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SELECTED CONSOLIDATED FINANCIAL DATA 2017 (a) 2016 2015 2014 2013 (dollars in millions, except per share amounts) STATEMENTS OF INCOME DATA Total Revenues $15,424.9 $16,380.1 $16,453.2 $16,378.6 $14,813.5 Operating Income $ 3,570.5 $ 1,207.1 $ 3,333.5 $ 3,127.4 $ 2,822.5 Income from Continuing Operations $ 1,928.9 $ 620.5 $ 1,768.6 $ 1,590.5 $ 1,473.9 Income (Loss) From Discontinued Operations, Net of Tax — (2.5) 283.7 47.5 10.3 Net Income 1,928.9 618.0 2,052.3 1,638.0 1,484.2 Net Income Attributable to Noncontrolling Interests 16.3 7.1 5.2 4.2 3.7 EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $ 1,912.6 $ 610.9 $ 2,047.1 $ 1,633.8 $ 1,480.5 BALANCE SHEETS DATA Total Property, Plant and Equipment $67,428.5 $62,036.6 $65,481.4 $63,605.9 $59,646.7 Accumulated Depreciation and Amortization 17,167.0 16,397.3 19,348.2 19,970.8 19,098.6 Total Property, Plant and Equipment – Net $50,261.5 $45,639.3 $46,133.2 $43,635.1 $40,548.1 Total Assets $64,729.1 $63,467.7 $61,683.1 $59,544.6 $56,321.0 Total AEP Common Shareholders’ Equity $18,287.0 $17,397.0 $17,891.7 $16,820.2 $16,085.0 Noncontrolling Interests $ 26.6 $ 23.1 $ 13.2 $ 4.3 $ 0.8 Long-term Debt (b) $21,173.3 $20,256.4 $19,572.7 $18,512.4 $18,198.2 Obligations Under Capital Leases (b) $ 297.8 $ 305.5 $ 343.5 $ 362.8 $ 403.3 AEP COMMON STOCK DATA Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders: From Continuing Operations $ 3.89 $ 1.25 $ 3.59 $ 3.24 $ 3.02 From Discontinued Operations — (0.01) 0.58 0.10 0.02 Total Basic Earnings per Share Attributable to AEP Common Shareholders $ 3.89 $ 1.24 $ 4.17 $ 3.34 $ 3.04 Weighted Average Number of Basic Shares Outstanding (in millions) 491.8 491.5 490.3 488.6 486.6 Market Price Range: High $ 78.07 $ 71.32 $ 65.38 $ 63.22 $ 51.60 Low $ 61.82 $ 56.75 $ 52.29 $ 45.80 $ 41.83 Year-end Market Price $ 73.57 $ 62.96 $ 58.27 $ 60.72 $ 46.74 Cash Dividends Declared per AEP Common Share $ 2.39 $ 2.27 $ 2.15 $ 2.03 $ 1.95 Dividend Payout Ratio 61.44% 183.06% 51.56% 60.78% 64.14% Book Value per AEP Common Share $ 37.17 $ 35.38 $ 36.44 $ 34.37 $ 32.98 (a) The 2017 financial results include a pretax gain on the sale of merchant generation assets of $226 million and asset impairments of $87 million (see Note 7 to the financial statements). (b) Includes portion due within one year. 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 219,000 miles of distribution lines that deliver electricity to 5.4 million customers. Approximately 40,000 circuit miles of transmission lines, including approximately 2,100 circuit miles of 765 kV lines, the backbone of the electric interconnection grid in the Eastern United States. AEP Transmission Holdco has approximately $5.8 billion of transmission assets in-service. Approximately 23,000 megawatts of regulated owned generating capacity and approximately 4,800 megawatts of regulated PPA capacity in 3 RTOs as of December 31, 2017, 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, 2017 increased by 0.3% from the year ended December 31, 2016. AEP’s 2017 industrial sales volumes increased 2.8% compared to 2016. The growth in industrial sales was spread across many industries and most operating companies. Weather-normalized residential sales decreased 1.2% and commercial sales decreased by 0.8% in 2017, respectively, from 2016. In 2018, AEP anticipates weather-normalized retail sales volumes will increase by 0.2%. The industrial class is expected to remain flat in 2018, while weather-normalized residential sales volumes are projected to increase by 0.3%, primarily related to projected customer growth. Weather-normalized commercial sales volumes are projected to increase by 0.4%. Federal Tax Reform In December 2017, legislation referred to as Tax Reform was signed into law. The majority of the provisions in the new legislation are effective for taxable years beginning after December 31, 2017. Tax Reform includes significant changes to the Internal Revenue Code of 1986 (as amended, the Code), including amendments which significantly change the taxation of business entities and also includes provisions specific to regulated public utilities. The more significant changes that affect the Registrants include the reduction in the corporate federal income tax rate from 35% to 21%, and several technical provisions including, among others, limiting the utilization of net operating losses arising after December 31, 2017 to 80% of taxable income with an indefinite carryforward period. The Tax Reform provisions related to regulated public utilities generally allow for the continued deductibility of interest expense, eliminate bonus depreciation for certain property acquired after September 27, 2017 and continue certain rate normalization requirements for accelerated depreciation benefits. Changes in the Code due to Tax Reform had a material impact on the Registrants’ 2017 financial statements. As a result of Tax Reform, the Registrants’ deferred tax assets and liabilities were re-measured using the newly enacted tax rate of 21% in December 2017. This re-measurement resulted in a significant reduction in the Registrants’ net accumulated deferred income tax liability. With respect to the Registrants’ regulated operations, the reduction of the net accumulated deferred income tax liability was primarily offset by a corresponding decrease in income tax related regulatory assets and an increase in income tax related regulatory liabilities because the benefit of the lower federal 2


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    tax rate is expected to be provided to customers. However, when the underlying asset or liability giving rise to the temporary difference was not previously contemplated in regulated rates, the re-measurement of the deferred taxes on those assets or liabilities was recorded as an adjustment to income tax expense. For the Registrants’ unregulated operations, the re-measurement of deferred taxes arising from those operations was recorded as an adjustment to income tax expense. The following tables provide a summary of the impact of Tax Reform on the Registrants’ 2017 financial statements. Year Ended AEP December 31, 2017 AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Decrease in Deferred Income Tax Liabilities $ 6,101.1 $ 807.1 $ 558.6 $ 1,296.4 $ 808.7 $ 743.1 $ 538.6 $ 782.9 This decrease in deferred income tax liabilities resulted in an increase in income tax related regulatory liabilities, a decrease in income tax related regulatory assets and an adjustment to income tax expense as shown in the table below. Year Ended AEP December 31, 2017 AEP (c) Texas AEPTCo APCo I&M OPCo PSO SWEPCo (in millions) Increase (Decrease) in Income Tax Expense (a) $ (16.5) $ (117.4) (b) $ 0.6 $ 5.7 $ 2.3 $ (14.3) (b) $ 2.8 $ 0.7 Decrease in Regulatory Assets 470.2 12.1 66.9 129.1 85.3 62.7 8.3 69.8 Increase in Regulatory Liabilities 5,614.4 677.6 492.3 1,173.0 725.7 666.1 533.1 713.8 (a) In 2017, in contemplation of corporate federal tax reform, the Registrants adopted a method under Internal Revenue Section 162 for deducting repair and maintenance costs associated with transmission and distribution property. This change resulted in a decrease in state income tax expense of approximately $10 million that has been excluded from the tables above. (b) AEP Texas and OPCo recorded favorable adjustments to income tax expense of approximately $113 million and $16 million related to previously owned deregulated generation assets and certain deferred fuel amounts, respectively. (c) The effect of Tax Reform on AEP’s other business operations (other than the Registrant Subsidiaries), which primarily include unregulated activities in the Generation & Marketing segment, transmission operations reflected in the AEP Transmission Holdco segment and activities recorded in Corporate and Other, increased income tax expense for the year-ended December 31, 2017 by approximately $103 million. Regulatory Treatment As a result of Tax Reform, the Registrants recognized a regulatory liability for approximately $4.4 billion of excess accumulated deferred income taxes (Excess ADIT), as well as an incremental liability of $1.2 billion to reflect the $4.4 billion Excess ADIT on a pre-tax basis. The Excess ADIT is reflected on a pre-tax basis to appropriately contemplate future tax consequences in the periods when the regulatory liability is settled. Approximately $3.2 billion of the Excess ADIT relates to temporary differences associated with depreciable property. The Tax Reform legislation includes certain rate normalization requirements that stipulate how the portion of the total Excess ADIT that is related to certain depreciable property must be passed back to customers. Specifically, for AEP’s regulated public utilities that are subject to those rate normalization requirements, Excess ADIT resulting from the reduction of the corporate tax rate with respect to prior depreciation or recovery deductions on property will be normalized using the average rate assumption method. As a result, once the amortization of this Excess ADIT is reflected in rates, customers will receive the benefits over the remaining weighted average useful life of the applicable property. For the remaining $1.2 billion of Excess ADIT, the Registrants expect to continue working with each state regulatory commission to determine the appropriate mechanism and time period over which to provide the benefits of Tax Reform to customers. 3


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    The Registrants expect the mechanism and time period to provide the benefits of Tax Reform to customers will vary by jurisdiction and is not expected to have a material impact on future net income. However, the Registrants anticipate a decrease in future cash flows primarily due to the elimination of bonus depreciation, the reduction in the federal tax rate from 35% to 21% and the flow back of Excess ADIT. Further, the Registrants expect that access to capital markets will be sufficient to satisfy any liquidity needs that result from any such decrease in future cash flows. State Regulatory Matters Various state utility commissions have recently issued orders requiring public utilities, including the Registrants, to record regulatory liabilities to reflect the corporate federal income taxes currently collected in utility rates in excess of the enacted corporate federal income tax rate of 21% beginning January 1, 2018. See Note 4 - Rate Matters for additional information regarding state utility commission orders received impacting the Registrant Subsidiaries. Merchant Generation Assets In September 2016, AEP signed an agreement to sell Darby, Gavin, Lawrenceburg and Waterford Plants (“Disposition Plants”) totaling 5,329 MWs of competitive generation to a nonaffiliated party. The sale closed in January 2017 for approximately $2.2 billion. The net proceeds from the transaction were approximately $1.2 billion in cash after taxes, repayment of debt associated with these assets and transaction fees, which resulted in an after tax gain of approximately $129 million. AEP primarily used these proceeds to reduce outstanding debt and invest in its regulated businesses, including transmission and contracted renewable projects. The assets and liabilities included in the sale transaction have been recorded as Assets Held for Sale and Liabilities Held for Sale, respectively, on the balance sheet as of December 31, 2016. See “Dispositions” and “Assets and Liabilities Held for Sale” sections of Note 7 for additional information. In February 2017, AEP signed an agreement to sell its 25.4% ownership share of Zimmer Plant to Dynegy Corporation. Simultaneously, AEP signed an agreement to purchase Dynegy Corporation’s 40% ownership share of Conesville Plant, Unit 4. The transactions closed in the second quarter of 2017 and did not have a material impact on net income, cash flows or financial condition. In December 2017, AEP signed an amendment to the Cardinal Station Agreement with Buckeye Power Incorporated, which terminates certain commercial arrangements between the parties and transitions management oversite and administrative support of the Cardinal facility from AEP to Buckeye Power Incorporated. The amendment required approval from Rural Utilities Service and the FERC, which were obtained in February 2018. The new amendment will be effective March 2018 and is not expected to have a material impact on net income, cash flows or financial condition. Management continues to evaluate potential alternatives for the remaining merchant generation assets. These potential alternatives may include, but are not limited to, transfer or sale of AEP’s ownership interests, or a wind down of merchant coal-fired generation fleet operations. Management has not set a specific time frame for a decision on these assets. These alternatives could result in additional losses which could reduce future net income and cash flows and impact financial condition. Renewable Generation Portfolio 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 is further developing 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, 4


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    energy storage, waste heat recovery, energy efficiency, peaking generation and other forms of cost reducing energy technologies. Projects are pursued where a suitable termed agreement is entered into with a creditworthy counterparty. Generation & Marketing also develops and/or acquires large scale renewable generation projects that are backed with long-term contracts with creditworthy counterparties. As of December 31, 2017, subsidiaries within AEP’s Generation & Marketing segment have approximately 489 MWs of contracted renewable generation projects in operation. In addition, as of December 31, 2017, these subsidiaries have approximately 34 MWs of new renewable generation projects under construction and estimated capital costs of $61 million related to these projects. In January 2018, AEP entered into a partnership with a non-affiliate to own and repower Desert Sky and Trent, which is expected to be completed in 2018. The non-affiliate partner contributed full turbine sets to each project in exchange for a 20% interest in the partnership. AEP’s 80% share of the partnership, or 248 MWs, represents $232 million of additional estimated capital, of which $90 million has been spent and is recorded in construction work in progress as of December 31, 2017. The partnership is subject to a put and a call after certain conditions are met, either of which would liquidate the non-affiliated partner’s interest. Regulated Renewable Generation Facilities In July 2017, APCo submitted filings with the Virginia SCC and the WVPSC requesting regulatory approval to acquire two wind generation facilities totaling approximately 225 MWs of wind generation. The wind generating facilities are located in West Virginia and Ohio and, if approved, are anticipated to be in-service in the second half of 2019. APCo will assume ownership of the facilities at or near the anticipated in-service date. APCo currently plans to sell the Renewable Energy Certificates associated with the generation from these facilities. In December 2017, the WVPSC staff and an industrial intervenor filed testimony in West Virginia and the Virginia SCC staff filed testimony in Virginia arguing that APCo’s forecast of natural gas and energy prices was too high and, with the exception of the WVPSC staff’s recommended approval of the facility located in West Virginia, do not support approval of APCo’s acquisition of the facilities. In January 2018, APCo filed supplemental testimony with the WVPSC to address changes in the economics of the wind projects as a result of Tax Reform. A hearing at the Virginia SCC was held in February 2018 and a hearing is scheduled at the WVPSC in March 2018. In July 2017, PSO and SWEPCo submitted filings with the OCC, LPSC, APSC and PUCT requesting various regulatory approvals needed to proceed with the Wind Catcher Project. The Wind Catcher Project includes 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. Total investment for the project is estimated to be $4.5 billion and will serve both retail and FERC wholesale load. PSO and SWEPCo will have a 30% and 70% ownership share, respectively, in these assets. The wind generating facility is located in Oklahoma and, if approved by all state commissions, is anticipated to be in-service by the end of 2020. In July 2017, the LPSC approved SWEPCo’s request for an exemption to the Market Based Mechanism. In August 2017, the Oklahoma Attorney General filed a motion to dismiss with the OCC. In August 2017, the motion to dismiss was denied by the OCC. In December 2017, the Oklahoma Attorney General’s motion to dismiss was renewed and again denied by the OCC. Also in December 2017, the companies filed a request at FERC to transfer the wind generation facility to PSO and SWEPCo upon its construction by a third party, subject to the approval of the project at the respective state commissions. Parties’ testimony filed in the Oklahoma, Texas and Louisiana dockets generally opposes the companies’ request. In the companies’ rebuttal testimony filed in Oklahoma, Texas, Arkansas and Louisiana, certain commitments have been made related to the cost of the investment and operational performance. In addition, PSO and SWEPCo committed in each jurisdiction to the timely filing of a base rate case to shorten the duration of cost recovery through a temporary mechanism. In February 2018, the ALJ in Oklahoma recommended that PSO’s request for preapproval of future recovery of Wind Catcher Project costs be denied. Also in February 2018, SWEPCo announced a settlement agreement with the APSC staff, the Arkansas Attorney General and other parties in SWEPCo’s request for approval of the Wind Catcher Project. SWEPCo agreed to certain commitments related to the cost of the investment, qualification for 100% of the Production Tax Credits and operational performance. The parties filed a joint motion asking the APSC to approve the Wind Catcher Project under the terms of the settlement agreement. 5


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    Hurricane Harvey In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. As rebuilding efforts continue, AEP Texas’ total costs related to this storm are not yet final. AEP Texas’ current estimated cost is approximately $325 million to $375 million, including capital expenditures. AEP Texas has a PUCT approved catastrophe reserve which allows for the deferral of incremental storm expenses as a regulatory asset, and currently recovers approximately $1 million annually through base rates. As of December 31, 2017, the total balance of AEP Texas’ catastrophe reserve deferral is $123 million, inclusive of approximately $100 million of net incremental storm expenses related to Hurricane Harvey. AEP Texas currently estimates that it will incur approximately $12 million of additional incremental expense related to Hurricane Harvey service restoration efforts. As of December 31, 2017, AEP Texas has recorded approximately $133 million of capital expenditures related to Hurricane Harvey. Also, as of December 31, 2017, AEP Texas has received $10 million in insurance proceeds, which were applied to the regulatory asset and property, plant and equipment. Management, in conjunction with the insurance adjusters, is reviewing all damages to determine the extent of coverage for additional insurance reimbursement. Any future insurance recoveries received will also be applied to, and will offset, the regulatory asset and property, plant and equipment, as applicable. Management believes the amount recorded as a regulatory asset is probable of recovery and AEP Texas is currently evaluating recovery options for the regulatory asset. The other named 2017 hurricanes did not have a material impact on AEP’s operations. If the ultimate costs of the incident are not recovered by insurance or through the regulatory process, it would have an adverse effect on future net income, cash flows and financial condition. June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024 In March 2016, a contested stipulation agreement related to the PPA rider application was modified and approved by the PUCO. The approved PPA rider is subject to audit and review by the PUCO. Consistent with the terms of the modified and approved stipulation agreement, and based upon a September 2016 PUCO order, in November 2016, OPCo refiled its amended ESP extension application and supporting testimony. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Renewable Resource Rider. In August 2017, OPCo and various intervenors filed a stipulation agreement with the PUCO. The stipulation extends the term of the ESP through May 2024 and includes: (a) an extension of the OVEC PPA rider, (b) a proposed 10% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) rate caps related to OPCo’s DIR ranging from $215 million to $290 million for the periods 2018 through 2021, (e) the addition of various new riders, including a Smart City Rider and a Renewable Generation Rider, (f) a decrease in annual depreciation rates based on a depreciation study using data through December 2015 and (g) amortization of approximately $24 million annually beginning January 2018 of OPCo’s excess distribution accumulated depreciation reserve, which was $239 million as of December 31, 2015. Upon PUCO approval of the stipulation, effective January 2018, OPCo will cease recording $39 million in annual amortization previously approved to end in December 2018 in accordance with PUCO’s December 2011 OPCo distribution base rate case order. In the stipulation, OPCo and intervenors agree that OPCo can request in future proceedings a change in meter depreciation rates due to retired meters pursuant to the smart grid Phase 2 project. DIR rate caps will be reset in OPCo’s next distribution base rate case which must be filed by June 2020. In October 2017, intervenor testimony opposing the stipulation agreement was filed recommending: (a) a return on common equity to not exceed 9.3% for riders earning a return on capital investments, (b) that OPCo should file a base distribution case concurrent with the conclusion of the current ESP in May 2018 and (c) denial of certain new riders proposed in OPCo’s ESP extension. The stipulation is subject to review by the PUCO. A hearing at the PUCO was held in November 2017. An order from the PUCO is expected in the first quarter of 2018. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. See “Ohio Electric Security Plan Filings” section of Note 4 for additional information. 6


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    2016 SEET Filing In December 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings. In May 2017, OPCo submitted its 2016 SEET filing with the PUCO in which management indicated that OPCo did not have significantly excessive earnings in 2016 based upon actual earnings data for the comparable utilities risk group. In January 2018, the PUCO staff filed testimony that OPCo did not have significantly excessive earnings. Also in January 2018, an intervenor filed testimony recommending a $53 million refund to customers. In February 2018, OPCo and PUCO staff filed a stipulation agreement in which both parties agreed that OPCo did not have significantly excessive earnings in 2016. In February 2018, a procedural schedule was issued by the PUCO. A hearing is scheduled for April 2018 and management expects to receive an order in the second quarter of 2018. While management believes that OPCo’s adjusted 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s proposed SEET adjustments, including treatment of the Global Settlement issues described above, adjust the comparable risk group, or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could reduce future net income and cash flows and impact financial condition. See “2016 SEET Filing” section of Note 4 for additional information. Rockport Plant, Unit 2 SCR In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NOx from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million, excluding AFUDC, to be shared equally between I&M and AEGCo. As of December 31, 2017, total costs incurred related to this project, including AFUDC, were approximately $23 million. The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to I&M and KPCo and will be subject to future regulatory approval for recovery. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and limitations on other costs related to legal issues involving the Rockport Plant, Unit 2 lease. A hearing at the IURC was held in March 2017. An order from the IURC is pending. In July 2017, I&M filed a motion with the U.S. District Court for the Southern District of Ohio to remove the requirement to install SCR technology at Rockport Plant, Unit 2, which plaintiffs opposed. The district court has delayed the deadline for installation of the SCR technology until June 2020. In January 2018, I&M filed a supplemental motion with the U.S. District Court for the Southern District of Ohio proposing to install the SCR at Rockport Plant, Unit 2 and achieve the final SO2 emission cap applicable to the plant under the consent decree by the end of 2020, before the expiration of the initial lease term. Responsive filings were filed in February 2018 and a decision is anticipated in the first quarter of 2018. 7


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    2017 Indiana Base Rate Case In July 2017, I&M filed a request with the IURC for a $263 million annual increase in Indiana rates based upon a proposed 10.6% return on common equity with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increase would be subject to a temporary offsetting $23 million annual reduction to customer bills through December 2018 for a credit adjustment rider related to the timing of estimated in-service dates of certain capital expenditures. The proposed annual increase includes $78 million related to increased annual depreciation rates and an $11 million increase related to the amortization of certain Cook Plant and Rockport Plant regulatory assets. The increase in depreciation rates includes a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant, including the Cook Plant Life Cycle Management Project. In November 2017, various intervenors filed testimony that included annual revenue increase recommendations ranging from $125 million to $152 million. The recommended returns on common equity ranged from 8.65% to 9.1%. In addition, certain parties recommended longer recovery periods than I&M proposed for recovery of regulatory assets and depreciation expenses related to Rockport Plant, Units 1 and 2. In January 2018, in response to a January 2018 IURC request related to the impact of Tax Reform on I&M’s pending base rate case, I&M filed updated schedules supporting a $191 million annual increase in Indiana base rates if the effect of Tax Reform was included in the cost of service. In February 2018, I&M and all parties to the case, except one industrial customer, filed a Stipulation and Settlement Agreement for a $97 million annual increase in Indiana rates effective July 1, 2018 subject to a temporary offsetting reduction to customer bills through December 2018 for a credit rider related to the timing of estimated in-service dates of certain capital expenditures. The one industrial customer agreed to not oppose the Stipulation and Settlement Agreement. The difference between I&M’s requested $263 million annual increase and the $97 million annual increase in the Stipulation and Settlement Agreement is primarily due to lower federal income taxes as a result of the reduction in the federal income tax rate due to Tax Reform, the feedback of credits for excess deferred income taxes, a 9.95% return on equity, longer recovery periods of regulatory assets, lower depreciation expense primarily for meters, and an increase in the sharing of off-system sales margins with customers from 50% to 95%. I&M will also refund $4 million from July through December 2018 for the impact of Tax Reform for the period January through June 2018. A hearing at the IURC is scheduled for March 2018. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Michigan Base Rate Case In May 2017, I&M filed a request with the MPSC for a $52 million annual increase in Michigan base rates based upon a proposed 10.6% return on common equity with the increase to be implemented no later than April 2018. The proposed annual increase includes $23 million related to increased annual depreciation rates and a $4 million increase related to the amortization of certain Cook Plant regulatory assets. The increase in depreciation rates is primarily due to the proposed change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant related to the Life Cycle Management Project. Additionally, the total proposed increase includes incremental costs related to the Cook Plant Life Cycle Management Program and increased vegetation management expenses. In October 2017, the MPSC staff and intervenors filed testimony. The MPSC staff recommended an annual net revenue increase of $49 million including proposed retirement dates of 2028 for both Rockport Plant, Units 1 (from 2044) and 2 (from 2022), a reduced capacity charge and a return on common equity of 9.8%. The intervenors proposed certain adjustments to I&M’s request including no change to the current 2044 retirement date of Rockport Plant, Unit 1, a market based capacity charge effective February 2019 for up to 10% of I&M’s Michigan customers, but did not address an annual net revenue increase. The intervenors’ recommended returns on common equity ranged from 9.3% to 9.5%. A hearing at the MPSC was held in November 2017. In February 2018, an MPSC ALJ issued a Proposal for Decision and recommended an annual revenue increase of $49 million, including the intervenors’ proposed capacity charge and staff’s depreciation rates for Rockport Plant and a 8


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    return on common equity of 9.8%. If the maximum 10% of customers choose an alternate supplier starting in February 2019, the estimated annual pretax loss due to the reduced capacity charge is approximately $9 million. An order is expected in the first half of 2018. If any of these costs are not recoverable, it 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 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) 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, 2017, the net book value of Turk Plant was $1.5 billion, before cost of removal, including materials and supplies inventory and CWIP. In January 2018, SWEPCo and the LPSC staff agreed on settlement terms relating to the prudence review of the Turk Plant. See “Louisiana Turk Plant Prudence Review” section of Note 4. 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. Louisiana Turk Plant Prudence Review Beginning January 2013, SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 33%) of the Turk Plant, have been collected subject to refund pending the outcome of a prudence review of the Turk Plant investment, which was placed into service in December 2012. In October 2017, the LPSC staff filed testimony contending that SWEPCo failed to continue to evaluate the suspension or cancellation of the Turk Plant during its construction period. In January 2018, SWEPCo and the LPSC staff filed a settlement, subject to LPSC approval, providing for a $19 million pretax write-off of the Louisiana jurisdictional share of previously capitalized Turk Plant costs and a $10 million rate refund provision for previously collected revenues associated with the disallowed portion of the Turk Plant. Based on the agreement, management concluded that the disallowance was probable resulting in a $23 million pretax write off in the fourth quarter, consisting of a $15 million pretax impairment and an $8 million pretax provision for revenue refund. The agreement requires $2 million of the provision to be refunded to customers in the first billing cycle following LPSC approval of the settlement and the remaining $8 million to be amortized as a cost of service reduction for customers over 5 years, effective August 1, 2018. In February 2018, the LPSC approved the settlement agreement. 2017 Louisiana Formula Rate Filing In April 2017, the LPSC approved an uncontested stipulation agreement that SWEPCo filed for its formula rate plan for test year 2015. The filing included a net annual increase not to exceed $31 million, which was effective May 2017 and includes SWEPCo’s Louisiana jurisdictional share of Welsh Plant and Flint Creek Plant environmental controls which were placed in service in 2016. The net annual increase is subject to refund. In October 2017, SWEPCo filed testimony in Louisiana supporting the prudence of its environmental control investment for Welsh Plant, Units 1 and 3 and Flint Creek power plants. These environmental costs are subject to prudence review. A hearing at the LPSC is scheduled for May 2018. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 9


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    2017 Oklahoma Base Rate Case In June 2017, PSO filed an application for a base rate review with the OCC that requested an increase in annual revenues of $156 million, less an $11 million refund obligation, for a net increase of $145 million based upon a proposed 10% return on common equity. The proposed base rate increase includes (a) environmental compliance investments, including recovery of previously deferred environmental compliance related costs currently recorded as regulatory assets, (b) Advanced Metering Infrastructure investments, (c) additional capital investments and costs to serve PSO’s customers, and (d) an annual $42 million depreciation rate increase due primarily to shorter service lives and lower net salvage estimates. As part of this filing, consistent with the OCC’s final order in its previous base rate case, PSO requested recovery through 2040 of Northeastern Plant, Unit 3, including the environmental control investment, and the net book value of Northeastern Plant, Unit 4 that was retired in 2016. As of December 31, 2017, the net book value of Northeastern Plant, Unit 4 was $81 million. In January 2018, the OCC issued a final order approving a net increase in Oklahoma annual revenues of $84 million, which was then reduced by $32 million to $52 million to account for changes as a result of Tax Reform, based upon a return on common equity of 9.3%. The final order also included approval for recovery, with a debt return for investors, of the net book value of Northeastern Plant Unit 4 and an annual depreciation expense increase of $19 million, including requested recovery through 2040 of Northeastern Plant Unit 3. PSO anticipates implementing new rates in March 2018 billings. 2017 Kentucky Base Rate Case In June 2017, KPCo filed a request with the KPSC for a $66 million annual increase in Kentucky base rates based upon a proposed 10.31% return on common equity with the increase to be implemented no later than January 2018. The proposed increase included: (a) lost load since KPCo last changed base rates in July 2015, (b) incremental costs related to OATT charges from PJM not currently recovered from retail ratepayers, (c) increased depreciation expense including updated Big Sandy Plant, Unit 1 depreciation rates using a proposed retirement date of 2031, (d) recovery of other Big Sandy Plant, Unit 1 generation costs currently recovered through a retail rider and (e) incremental purchased power costs. Additionally, KPCo requested a $4 million annual increase in environmental surcharge revenues. In August 2017, KPCo submitted a supplemental filing with the KPSC that decreased the proposed annual base rate revenue request to $60 million. The modification was due to lower interest expense related to June 2017 debt refinancings. In November 2017, KPCo filed a non-unanimous settlement agreement with the KPSC. The settlement agreement included a proposed annual base rate increase of $32 million based upon a 9.75% return on common equity. In January 2018, the KPSC issued an order approving the non-unanimous settlement agreement with certain modifications resulting in an annual revenue increase of $12 million, effective January 2018, based on a 9.7% ROE. The KPSC’s primary revenue requirement modification to the settlement agreement was a $14 million annual revenue reduction for the decrease in the corporate federal income tax rate due to Tax Reform. The KPSC approved: (a) the deferral of $50 million of Rockport Plant Unit Power Agreement expenses for the years 2018 through 2022, with recovery of the deferral to be addressed in KPCo’s next base rate case, (b) the recovery/return of 80% of certain annual PJM OATT expenses above/below the corresponding level recovered in base rates, (c) KPCo’s commitment to not file a base rate case for three years and (d) increased depreciation expense based upon updated Big Sandy Plant, Unit 1 depreciation rates using a 20-year depreciable life. In February 2018, KPCo filed with the KPSC for rehearing of the January 2018 base case order and requested an additional $2.3 million of annual revenue increases related to: (a) the calculation of federal income tax expense, (b) recovery of purchased power costs associated with forced outages and (c) capital structure adjustments. Also in February 2018, an intervenor filed for rehearing recommending that the reduced corporate federal income tax rate, as a result of Tax Reform, be reflected in lower purchased power expense related to the Rockport UPA. It is anticipated that the KPSC will rule upon this rehearing request in the first quarter of 2018. 10


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    2016 Texas Base Rate Case In December 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $50 million based upon a return on common equity of 9.6%, effective May 2017. The final order also included (a) approval to recover the Texas jurisdictional share of environmental investments placed in service, as of June 30, 2016, at various plants, including Welsh Plant, Units 1 and 3, (b) approval of recovery of, but no return on, the Texas jurisdictional share of the net book value of Welsh Plant, Unit 2, (c) approval of $2 million additional vegetation management expenses and (d) the rejection of SWEPCo’s proposed transmission cost recovery mechanism. As a result of the final order, in the fourth quarter, SWEPCo (a) recorded an impairment charge of $19 million, which includes $7 million associated with the lack of return on Welsh Plant, Unit 2 and $12 million related to other disallowed plant investments (b) recognized $32 million of additional revenues, for the period of May 2017 through December 2017, that will be surcharged to customers and (c) recognized an additional $7 million of expenses consisting primarily of depreciation expense and vegetation management expense, offset by the deferral of rate case expenses. SWEPCo implemented new rates in February 2018 billings. The $32 million of additional 2017 revenues will be collected by the end of 2018. In addition, SWEPCo is required to file a refund tariff within 120 days to reflect the difference between rates collected under the final order and the rates that would be collected under Tax Reform. Virginia Legislation Affecting Biennial Reviews In 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also precluded the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. In February 2018, legislation separately passed the Virginia House of Delegates and the Senate of Virginia and, if enacted and signed into law by the Governor in its present form, will: (a) require APCo to not recover $10 million of fuel expenses incurred after July 1, 2018, (b) reduce APCo’s base rates by $50 million annually, on an interim basis and subject to true-up, effective July 30, 2018 related to Tax Reform and (c) require an adjustment in APCo’s base rates on April 1, 2019 to reflect actual annual reductions in corporate income taxes due to Tax Reform. APCo’s next base rate review in 2020 will now include a review of earnings for test years 2017-2019, with triennial reviews of APCo’s base rates and earnings thereafter instead of biennial reviews. The current VA legislative session is scheduled to adjourn in March 2018. Either a biennial review of 2018-2019 or a triennial review of 2017-2019 could reduce future net income and cash flows and impact financial condition. FERC Transmission Complaint - AEP’s PJM Participants In October 2016, several parties filed a complaint at the FERC that states the base return on common equity used by AEP’s eastern transmission subsidiaries in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32%, effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. In November 2017, a FERC Order set the matter for hearing and settlement procedures. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition. Modifications to AEP’s PJM Transmission Rates In November 2016, AEP’s eastern transmission subsidiaries filed an application at the FERC to modify the PJM OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to projected expenses. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. The modified PJM OATT formula rates are based on projected calendar year financial activity and projected plant balances. In December 2017, AEP’s 11


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    eastern transmission subsidiaries filed an uncontested settlement agreement with the FERC resolving all outstanding issues. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. FERC Transmission Complaint - AEP’s SPP Participants In June 2017, several parties filed a complaint at the FERC that states the base return on common equity used by AEP’s western transmission subsidiaries in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36%, effective upon the date of the complaint. In November 2017, a FERC order set the matter for hearing and settlement procedures. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition. Modifications to AEP’s SPP Transmission Rates In October 2017, AEP’s western transmission subsidiaries filed an application at the FERC to modify the SPP OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to projected expenses. The modified SPP OATT formula rates are based on projected 2018 calendar year financial activity and projected plant balances. In December 2017, the FERC accepted the proposed modifications effective January 1, 2018, subject to refund, and set this matter for hearing and settlement procedures. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. FERC SWEPCo Power Supply Agreements Complaint - East Texas Electric Cooperative, Inc. (ETEC) and Northeast Texas Electric Cooperative, Inc. (NTEC) In September 2017, ETEC and NTEC filed a complaint at the FERC that states the base return on common equity used by SWEPCo in calculating their power supply formula rates is excessive and should be reduced from 11.1% to 8.41%, effective upon the date of the complaint. In November 2017, a FERC order set the matter for hearing and settlement procedures. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition. Welsh Plant - Environmental Impact Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could total approximately $850 million, excluding AFUDC. As of December 31, 2017, SWEPCo had incurred costs of $398 million, including AFUDC, related to these projects. Management continues to evaluate the impact of environmental rules and related project cost estimates. As of December 31, 2017, the total net book value of Welsh Plant, Units 1 and 3 was $627 million, before cost of removal, including materials and supplies inventory and CWIP. In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas filed base rate proceeding. In April 2017, the LPSC approved recovery of $131 million in investments related to its Louisiana jurisdictional share of environmental controls installed at Welsh Plant, effective May 2017. SWEPCo’s approved Louisiana jurisdictional share of Welsh Plant deferrals: (a) are $11 million, excluding $6 million of unrecognized equity as of December 31, 2017, (b) is subject to review by the LPSC, and (c) includes a WACC return on environmental investments and the related depreciation expense and taxes. In January 2018, SWEPCo received written approval from the PUCT to recover its project costs from retail customers in its 2016 Texas base rate case and is recovering these costs from wholesale customers through SWEPCo’s FERC-approved agreements. See “2016 Texas Base Rate Case” and “2017 Louisiana Formula Rate Filing” disclosures above. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See “Welsh Plant - Environmental Impact” section of Note 4 for additional information. 12


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    Westinghouse Electric Company Bankruptcy Filing In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the U.S. Bankruptcy Code. It intends to reorganize, not cease business operations. However, it is in the early stages of the bankruptcy process and it is unclear whether the company can successfully reorganize. Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuel fabrication and ongoing engineering projects. The most significant of these relate to Cook Plant fuel fabrication. Westinghouse has stated that it intends to continue performance on I&M’s contracts, but given the importance of upcoming dates in the fuel fabrication process for Cook Plant, and their vital part in Cook Plant’s ongoing operations, I&M continues to work with Westinghouse in the bankruptcy proceedings to avoid any interruptions to that service. In January 2018, Westinghouse issued a news release stating that it intends to sell all of its global business, including the portion of the nuclear business that contracts with Cook Plant. Any sale would require approval by the bankruptcy court. In the unlikely event Westinghouse rejects I&M’s contracts, or there is an interference with the sale process, Cook Plant’s operations would be significantly impacted and potentially shut down temporarily as I&M seeks other vendors for these services. 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. For details on the regulatory proceedings and pending litigation see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition. Rockport Plant Litigation In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will 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 or retirement of the unit. The plaintiffs further allege that the defendants’ actions constitute breach of the lease and participation agreement. 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. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims, including the dismissal without prejudice of plaintiffs’ claims seeking compensatory damages. Several claims remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. In November 2015, AEGCo and I&M filed a motion to strike the plaintiffs’ motion for partial judgment and filed a motion to dismiss the case for failure to state a claim. In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining 13


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    claims with prejudice and the court subsequently entered a final judgment. In May 2016, plaintiffs filed an appeal in the U.S. Court of Appeals for the Sixth Circuit on whether AEGCo and I&M are in breach of certain contract provisions that plaintiffs allege operate to protect the plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing. In April 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion reversing the district court’s decisions which had dismissed certain of plaintiffs’ claims for breach of contract and remanding the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. In April 2017, AEGCo and I&M filed a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit, which was granted. In June 2017, the U.S. Court of Appeals for the Sixth Circuit issued an amended opinion and judgment which reverses the district court’s dismissal of certain of the owners’ claims under the lease agreements, vacates the denial of the owners’ motion for partial summary judgment and remands the case to the district court for further proceedings. The amended opinion and judgment also affirms the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims and removes the instruction to the district court in the original opinion to enter summary judgment in favor of the owners. In July 2017, 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 to eliminate the obligation to install certain 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. In November 2017, 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. See “Proposed Modification of the NSR Litigation Consent Decree” section below for additional information. Management will continue to defend against the claims. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management is unable to determine a range of potential losses that are reasonably possible of occurring. ENVIRONMENTAL ISSUES AEP has a substantial capital investment program and is incurring additional operational costs to comply with environmental control requirements. Additional investments and operational changes will need to be made in response to existing and anticipated requirements such as new CAA requirements to reduce emissions from fossil fuel-fired power plants, rules governing the beneficial use and disposal of coal combustion by-products, clean water rules and renewal permits for certain water discharges. AEP is engaged in litigation about environmental issues, was notified of potential responsibility for the clean-up of contaminated sites and incurred costs for disposal of SNF and future decommissioning of the nuclear units. AEP, along with various industry groups, affected states and other parties challenged some of the Federal EPA requirements in court. Management is also engaged in the development of possible future requirements including the items discussed below. Management believes that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals. AEP will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances. If AEP is unable to recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition. 14


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    Environmental Controls Impact on the Generating Fleet The rules and proposed environmental controls discussed below will have a material impact on the generating units in the AEP System. Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance. As of December 31, 2017, the AEP System had a total generating capacity of approximately 25,600 MWs, of which approximately 13,500 MWs are coal-fired. Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on the fossil generating facilities. Based upon management estimates, AEP’s investment to meet these existing and proposed requirements ranges from approximately $2.1 billion to $2.7 billion through 2025. 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) the states’ implementation of these regulatory programs, including the potential for state implementation plans (SIPs) or federal implementation plans (FIPs) that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed on the units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors. In addition, management is continuing to evaluate the economic feasibility of environmental investments on both regulated and competitive plants. The table below represents the plants or units of plants retired in 2016 and 2015 with a remaining net book value. As of December 31, 2017, the net book value before cost of removal, including related materials and supplies inventory and CWIP balances, of the units listed below was approved for recovery, except for $233 million. Management is seeking or will seek recovery of the remaining net book value of $233 million in future rate proceedings. Generating Amounts Pending Company Plant Name and Unit Capacity Regulatory Approval (in MWs) (in millions) APCo Kanawha River Plant 400 $ 44.8 APCo Clinch River Plant, Unit 3 235 32.7 APCo (a) Clinch River Plant, Units 1 and 2 470 31.8 APCo Sporn Plant 600 17.2 APCo Glen Lyn Plant 335 13.4 I&M (b) Tanners Creek Plant 995 42.6 SWEPCo Welsh Plant, Unit 2 528 50.8 Total 3,563 $ 233.3 (a) APCo obtained permits following the Virginia SCC’s and WVPSC’s approval to convert its 470 MW 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, Unit 1 and Unit 2 began operations as natural gas units in February 2016 and April 2016, respectively. (b) I&M requested recovery of the Indiana (approximately 65%) and Michigan (approximately 14%) jurisdictional shares of the remaining retirement costs of Tanners Creek Plant in the 2017 Indiana and Michigan base rate cases. See “2017 Indiana Base Rate Case” and “2017 Michigan Base Rate Case” sections of Note 4 for additional information. In January 2017, Dayton Power and Light Company announced the future retirement of the 2,308 MW Stuart Plant, Units 1-4. The retirement is scheduled for June 2018. Stuart Plant, Units 1-4 are operated by Dayton Power and Light Company and are jointly owned by AGR and nonaffiliated entities. AGR owns 600 MWs of the Stuart Plant, Units 1-4. As of December 31, 2017, AGR’s net book value of the Stuart Plant, Units 1-4 was zero. To the extent existing generation assets are not recoverable, it could materially reduce future net income and cash flows and impact financial condition. 15


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    Proposed Modification of the NSR Litigation Consent Decree In 2007, the U.S. District Court for the Southern District of Ohio approved a consent decree between the 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 July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio seeking to modify the consent decree to eliminate an obligation to install future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. The district court granted AEP’s request to delay the deadline to install SCR technology at Rockport Plant, Unit 2 until June 2020, pending resolution of the motion. AEP also proposed to retire Conesville Plant, Units 5 and 6 by December 31, 2022 and to retire one Rockport Plant unit by December 31, 2028. Plaintiffs opposed AEP’s motion. In January 2018, AEP filed a supplemental motion proposing to install the SCR at Rockport Plant, Unit 2 and achieve the final SO2 emission cap applicable to the plant under the consent decree by the end of 2020, before the expiration of the initial lease term. Responsive filings were filed in February 2018 and a decision is anticipated in the first quarter of 2018. AEP is seeking to modify the consent decree as a means to resolve or substantially narrow the issues in pending litigation with the owners of Rockport Plant, Unit 2. See “Rockport Plant Litigation” in Management’s Discussion and Analysis of Financial Condition and Results of Operations and in Note 6 - Commitments, Guarantees and Contingencies for additional information. Clean Air Act Requirements The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions. The states implement and administer many of these programs and could impose additional or more stringent requirements. The primary regulatory programs that continue to drive investments in AEP’s existing generating units include: (a) periodic revisions to the National Ambient Air Quality Standards (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 the Mercury and Air Toxics Standards (MATS) Rule; (d) implementation and review of the Cross-State Air Pollution Rule (CSAPR), a FIP designed to eliminate significant contributions from sources in upwind states to nonattainment or maintenance areas in downwind states and (e) the Federal EPA’s regulation of greenhouse gas emissions from fossil-fueled electric generating units under Section 111 of the CAA. In March 2017, President Trump issued a series of executive orders designed to allow the Federal EPA to review and take appropriate action to revise or rescind regulatory requirements that place undue burdens on affected entities, including specific orders directing the Federal EPA to review rules that unnecessarily burden the production and use of energy. The Federal EPA published notice and an opportunity to comment on how to identify such requirements and what steps can be taken to reduce or eliminate such burdens. Future changes that result from this effort may affect AEP’s compliance plans. Notable developments in significant CAA regulatory requirements affecting AEP’s operations are discussed in the following sections. 16


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    NAAQS The Federal EPA issued new, more stringent NAAQS for SO2 in 2010, PM in 2012 and ozone in 2015. Implementation of these standards is underway. States are still in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the 2010 SO2 NAAQS. In December 2017, the Federal EPA published final designations for certain areas’ compliance with the 2010 SO2 NAAQS. States may develop additional requirements for AEP’s facilities as a result of these designations. In April 2017, the Federal EPA requested a stay of proceedings in the U.S. Court of Appeals for the District of Columbia Circuit where challenges to the 2015 ozone standard are pending, to allow reconsideration of that standard by the new administration. The Federal EPA initially announced a one-year delay in the designation of ozone non-attainment areas, but withdrew that decision. In December 2017, the Federal EPA issued a notice of data availability and requested public comment on recommended designations for compliance with the 2015 ozone standard. 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) will address regional haze in federal parks and other protected areas. BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants. CAVR will be implemented through SIPs or, if SIPs are not adequate or are not developed on schedule, through FIPs. In January 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 proposed disapproval of regional haze SIPs in a few states, including Arkansas and Texas. In March 2012, the Federal EPA disapproved certain portions of the Arkansas regional haze SIP. In April 2015, the Federal EPA published a proposed FIP to replace the disapproved portions, including revised BART determinations for the Flint Creek Plant that were consistent with the environmental controls currently under construction. In September 2016, the Federal EPA published a final FIP that retains its BART determinations, but accelerates the schedule for implementation of certain required controls. The final rule is being challenged in the courts. In March 2017, the Federal EPA filed a motion that was granted by the U.S. Court of Appeals for the Eighth Circuit to hold the case in abeyance for 90 days to allow the parties to engage in settlement negotiations. Arkansas issued a proposed SIP revision to allow sources to participate in the CSAPR ozone season program in lieu of the source-specific NOx BART requirements in the FIP, and the Federal EPA has proposed to approve that SIP revision. Arkansas issued a second proposal to revise the SO2 BART determinations, and that proposal is open for public comment. The Federal EPA has asked the Eighth Circuit to continue to hold litigation in abeyance to facilitate settlement discussions. Arkansas and other affected parties have filed motions to stay the compliance deadlines pending further action from the Federal EPA. Management cannot predict the outcome of these proceedings. In January 2016, the Federal EPA disapproved portions of the Texas regional haze SIP and promulgated a final FIP that did not include any BART determinations. That rule was challenged and stayed by the U.S. Court of Appeals for the Fifth Circuit. The parties engaged in a settlement discussion but were unable to reach an agreement. In March 2017, the U.S. Court of Appeals for the Fifth Circuit granted partial remand of the final rule. In January 2017, the Federal EPA proposed source-specific BART requirements for SO2 from sources in Texas, including Welsh Plant, Unit 1. Management submitted comments on the proposal and is engaged in discussions with the Texas Commission on Environmental Quality (TCEQ) regarding the development of an alternative to source-specific BART. In September 2017, the Federal EPA issued a final rule withdrawing Texas from the annual CSAPR budget programs. The Federal EPA then issued a separate rule finalizing the regional haze requirements for electric generating units in Texas and confirmed TCEQ’s determination that no new PM limitations are required for regional haze. The Federal EPA also finalized a FIP that allows participation in the CSAPR ozone season program to satisfy the NOx regional haze obligations for electric generating units. Additionally, the Federal EPA finalized an intrastate SO2 emissions trading program based on CSAPR allowance allocations as an alternative to source-specific SO2 requirements. The proposed source-specific approach called for a wet FGD system to be installed on Welsh Plant, Unit 1. The opportunity to use emissions trading 17


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    to satisfy the regional haze requirements for NOx and SO2 at AEP’s affected generating units provides greater flexibility and lower cost compliance options than the original proposal. A challenge to the FIP has been filed in the U.S. Court of Appeals for the Fifth Circuit by various intervenors. Management supports the intrastate trading program contained in the FIP as a compliance alternative to source-specific controls. In June 2012, the Federal EPA published revisions to the regional haze rules to allow states participating in the CSAPR trading programs to use those programs in place of source-specific BART for SO2 and NOx emissions based on its determination that CSAPR results in greater visibility improvements than source-specific BART in the CSAPR states. This rule is being challenged in the U.S. Court of Appeals for the District of Columbia Circuit. Management supports compliance with CSAPR programs as satisfaction of the BART requirements. CSAPR In 2011, the Federal EPA issued CSAPR as a replacement for the CAIR, a regional trading program designed to address interstate transport of emissions that contributed significantly to downwind nonattainment with the 1997 ozone and PM NAAQS. Certain revisions to the rule were finalized in 2012. CSAPR relies on newly-created 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. Numerous affected entities, states and other parties filed petitions to review the CSAPR in the U.S. Court of Appeals for the District of Columbia Circuit. The court stayed implementation of the rule. Following extended proceedings in the U.S. Court of Appeals for the District of Columbia Circuit and the U.S. Supreme Court, but while the litigation was still pending, the U.S. Court of Appeals for the District of Columbia Circuit granted the Federal EPA’s motion to lift the stay and allow Phase I of CSAPR to take effect on January 1, 2015 and Phase II to take effect on January 1, 2017. In July 2015, the U.S. Court of Appeals for the District of Columbia Circuit found that the Federal EPA over- controlled the SO2 and/or NOx budgets of 14 states. The U.S. Court of Appeals for the District of Columbia Circuit remanded the rule to the Federal EPA to timely revise the rule consistent with the court’s opinion while CSAPR remains in place. In October 2016, a final rule was issued to address the remand and to incorporate additional changes necessary to address the 2008 ozone standard. The final rule significantly reduces ozone season budgets in many states and discounts the value of banked CSAPR ozone season allowances beginning with the 2017 ozone season. The rule has been challenged in the courts and petitions for administrative reconsideration have been filed. The rule remains in effect. Management is complying with the more stringent ozone season budgets while these petitions are being considered. 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 establishes unit-specific emission rates for units burning coal on a 30-day rolling average basis for mercury, PM (as a surrogate for particles of nonmercury metals) and hydrogen chloride (as a surrogate for acid gases). In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans. Compliance was 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 April 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied all of the petitions for review of the April 2012 final rule. Industry trade groups and several states filed petitions for further review in the U.S. Supreme Court and the court granted those petitions in November 2014. In June 2015, the U.S. Supreme Court reversed the decision of the U.S. Court of Appeals for the District of Columbia Circuit. The U.S. Court of Appeals for the District of Columbia Circuit remanded the MATS rule for further proceedings consistent with the U.S. Supreme Court’s decision that the Federal EPA was unreasonable in refusing to consider costs in its determination whether to regulate emissions of HAPs from power plants. The Federal EPA issued notice of a supplemental finding concluding that it is appropriate and necessary to regulate HAP emissions from coal-fired and oil-fired units. Management submitted comments on the proposal. In April 2016, the Federal EPA affirmed its determination that regulation of HAPs from electric generating units is necessary and appropriate. Petitions for review 18


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    of the Federal EPA’s April 2016 determination have been filed in the U.S. Court of Appeals for the District of Columbia Circuit. Oral argument was scheduled for May 2017, but in April 2017 the Federal EPA requested that oral argument be postponed to facilitate its review of the rule. The rule remains in effect. Climate Change, CO2 Regulation and Energy Policy 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 and power purchases and broadening the AEP System’s portfolio of energy efficiency programs. In October 2015, the Federal EPA published the final standards for new, modified and reconstructed fossil fuel fired steam generating units and combustion turbines, and final guidelines for the development of state plans to regulate CO2 emissions from existing sources. The final standard for new combustion turbines is 1,000 pounds of CO2 per MWh and the final standard for new fossil steam units is 1,400 pounds of CO2 per MWh. Reconstructed turbines are subject to the same standard as new units and no standard for modified combustion turbines was issued. Reconstructed fossil steam units are subject to a standard of 1,800 pounds of CO2 per MWh for larger units and 2,000 pounds of CO2 per MWh for smaller units. Modified fossil steam units will be subject to a site specific standard no lower than the standards that would be applied if the units were reconstructed. The final emissions guidelines for existing sources, known as the Clean Power Plan (CPP), are based on a series of declining emission rates that are implemented beginning in 2022 through 2029. The final emission rate is 771 pounds of CO2 per MWh for existing natural gas combined cycle units and 1,305 pounds of CO2 per MWh for existing fossil steam units in 2030 and thereafter. The Federal EPA also developed a set of rate-based and mass-based state goals. The Federal EPA also published proposed “model” rules that could be adopted by the states that would allow sources within “trading ready” state programs to trade, bank or sell allowances or credits issued by the states. These rules would also be the basis for any federal plan issued by the Federal EPA in a state that fails to submit or receive approval for a state plan. In June 2016, the Federal EPA issued a separate proposal for the Clean Energy Incentive Program (CEIP) that was included in the model rules. The final rules are being challenged in the courts. In February 2016, the U.S. Supreme Court issued a stay on the final CPP, including all of the deadlines for submission of initial or final state plans. The stay will remain in effect 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 April 2017, the Federal EPA withdrew its previously issued proposals for model trading rules and a CEIP. In March 2017, the Federal EPA filed in the U.S. Court of Appeals for the District of Columbia Circuit notice of: (a) an Executive Order from the President of the United States titled “Promoting Energy Independence and Economic Growth” directing the Federal EPA to review the CPP and related rules; (b) the Federal EPA’s initiation of a review of the CPP and (c) a forthcoming rulemaking related to the CPP consistent with the Executive Order, if the Federal EPA determines appropriate. In this same filing, the Federal EPA also presented a motion to hold the litigation in abeyance until 30 days after the conclusion of review of any resulting rulemaking. The District of Columbia Circuit granted the Federal EPA’s motion in part and has requested periodic status reports. In October 2017, the Federal EPA issued a proposed rule repealing the CPP and withdrawing the legal memoranda issued in connection with the rule. The Federal EPA has re-examined its legal interpretation of the “best system of emission reduction” and found that based on the statutory text, legislative history, use of similar terms elsewhere in the CAA and its own historic implementation of Section 111 that a narrower interpretation of the term limits it to those designs, processes, control technologies and other systems that can be applied directly to or at the source. Since the primary systems relied on in the CPP are not consistent with that interpretation, the Federal EPA proposes that the rule be withdrawn. The comment period on the proposed repeal has been extended to April 2018. In December 2017, the Federal EPA issued an advanced notice of proposed rulemaking seeking information that should be considered by the Federal EPA in developing guidelines for state programs. Management anticipates providing information in response to this notice, and actively participating in the development of any new guidelines. 19


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    AEP has taken action to reduce and offset CO2 emissions from its generating fleet and expects CO2 emissions from its operations to continue to decline due to the retirement of some of its coal-fired generation units, and actions taken to diversify the generation fleet and increase energy efficiency where there is regulatory support for such activities. In February 2018, AEP announced new intermediate and long-term CO2 emission reduction goals, based on the output of the company’s integrated resource plans, which take into account economics, customer demand, regulations, and grid reliability and resiliency, and reflect the company’s current business strategy. The intermediate goal is a 60 percent reduction from 2000 CO2 emission levels from AEP generating facilities by 2030; the long-term goal is an 80 percent reduction of CO2 emissions from AEP generating facilities from 2000 levels by 2050. AEP’s total projected CO2 emissions in 2018 are approximately 90 million metric tons, a 46% reduction from AEP’s 2000 CO2 emissions of approximately 167 million metric tons. 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 and could lead to possible impairment of assets. Coal Combustion Residual Rule In April 2015, the Federal EPA published a final rule to regulate the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The final rule has been challenged in the courts. The final rule became effective in October 2015. The Federal EPA regulates CCR as a non-hazardous solid waste by its issuance of new minimum federal solid waste management standards. The rule applies to new and existing active CCR landfills and CCR surface impoundments at operating electric utility or independent power production facilities. The rule imposes new and additional 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 December 2016, the U.S. Congress passed legislation authorizing states to submit programs to regulate CCR facilities, and the Federal EPA to approve such programs if they are no less stringent than the minimum federal standards. The Federal EPA may also enforce compliance with the minimum standards until a state program is approved or if states fail to adopt their own programs. In September 2017, the Federal EPA granted industry petitions to reconsider the CCR rule and asked that litigation regarding the rule be held in abeyance. The U.S. Court of Appeals for the District of Columbia Circuit heard oral argument in November 2017. 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 at some point in the future as the new rule is implemented. Management recorded a $95 million increase in asset retirement obligations in 2015 primarily due to the publication of the final rule. Management will continue to evaluate the rule’s impact on operations. Clean Water Act (CWA) 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 pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water. Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress. The final rule affects all plants withdrawing more than two million gallons of cooling water per day. The rule offers seven technology options to comply with the impingement standard and requires site-specific studies to determine appropriate entrainment compliance measures at facilities withdrawing more than 125 million gallons per day. Additional requirements may be imposed as a result of consultation with other federal agencies to protect threatened and endangered species and their habitats. Facilities with existing closed cycle recirculating cooling systems, as defined in the rule, are not expected to require any technology changes. Facilities subject to both the impingement standard and site-specific entrainment studies will typically be given at least three 20


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    years to conduct and submit the results of those studies to the permit agency. Compliance timeframes will then be established by the permit agency through each facility’s National Pollutant Discharge Elimination System (NPDES) permit for installation of any required technology changes, as those permits are renewed over the next five to eight years. Petitions for review of the final rule were filed by industry and environmental groups and are currently pending in the U.S. Court of Appeals for the Second Circuit. In addition, the Federal EPA developed revised effluent limitation guidelines for electricity generating facilities. A final rule was issued in November 2015. The final rule establishes 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 new requirements will be implemented through each facility’s wastewater discharge permit. The rule has been challenged in the U.S. Court of Appeals for the Fifth Circuit. In March 2017, industry associations filed a petition for reconsideration of the rule with the Federal EPA. In April 2017, the Federal EPA granted reconsideration of the rule and issued a stay of the rule’s future compliance deadlines, which has now expired. In April 2017, the U.S. Court of Appeals for the Fifth Circuit granted a stay of the litigation for 120 days. In June 2017, the Federal EPA also issued a proposal to temporarily postpone certain compliance deadlines in the rule. A final rule revising the compliance deadlines for FGD wastewater and bottom ash transport water to be no earlier than 2020 was issued in September 2017. Management submitted comments supporting the proposed postponement. Management continues to assess 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 June 2015, the Federal EPA and the U.S. Army Corps of Engineers jointly issued a final rule to clarify the scope of the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases. The CWA provides for federal jurisdiction over “navigable waters” defined as “the waters of the United States.” This jurisdictional definition applies to all CWA programs, potentially impacting generation, transmission and distribution permitting and compliance requirements. Among those programs are permits for wastewater and storm water discharges, permits for impacts to wetlands and water bodies and oil spill prevention planning. The final definition continues to recognize traditional navigable waters of the U.S. as jurisdictional as well as certain exclusions. The rule also contains a number of new specific definitions and criteria for determining whether certain other waters are jurisdictional because of a “significant nexus.” Management believes that clarity and efficiency in the permitting process is needed. Management remains concerned that the rule introduces new concepts and could subject more of AEP’s operations to CWA jurisdiction, thereby increasing the time and complexity of permitting. The final rule is being challenged in both courts of appeal and district courts. The U.S. Court of Appeals for the Sixth Circuit granted a nationwide stay of the rule pending jurisdictional determinations. In February 2016, the U.S. Court of Appeals for the Sixth Circuit issued a decision holding that it has exclusive jurisdiction to decide the challenges to the “waters of the United States” rule. Industry, state and related associations have filed petitions for a rehearing of the jurisdictional decision. In April 2016, the U.S. Court of Appeals for the Sixth Circuit denied the petitions. In January 2017, the decision was appealed to the U.S. Supreme Court, which granted certiorari to review the jurisdictional issue. The U.S. Supreme Court denied the Federal EPA’s motion to hold briefing in abeyance pending further Federal EPA actions on the rule. Oral argument was heard in October 2017. In January 2018, the U.S. Supreme Court ruled that challenges to the definition of “waters of the United States” must be filed in the federal district court, and remanded the case to the U.S. Court of Appeals for the Sixth Circuit with directions to dismiss the petitions for review for lack of jurisdiction. In March 2017, the Federal EPA published a notice of intent to review the rule and provide an advanced notice of a proposed rulemaking consistent with the Executive Order of the President of the United States directing the Federal EPA and U.S. Army Corps of Engineers to review and rescind or revise the rule. In June 2017, the agencies signed a notice of proposed rule to rescind the definition of “waters of the United States” that was adopted in June 2015, and to re-codify the definition of that phrase as it existed immediately prior to that action. This action would effectively retain the status quo until a new rule is adopted by the agencies. The Federal EPA and U.S. Army Corps of Engineers also accepted written recommendations on a new rule and proposed to extend the applicability date of the rule by two years in the event the nationwide stay issued by the U.S. Court of Appeals for the Sixth Circuit is lifted. It is not yet clear what action the agencies will take in response to the Supreme Court decision. 21


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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 to serve SSO customers and provides transmission and distribution services for all connected load. AEP Transmission Holdco Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved returns on equity. Development, construction and operation of transmission facilities through investments in AEP’s transmission- only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing Competitive generation in ERCOT and PJM. Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. With the sale of AEPRO in November 2015, the activities related to the AEP River Operations segment have been moved to Corporate and Other for the periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The following discussion of AEP’s results of operations by operating segment includes an analysis of Gross Margin, which is a non-GAAP financial measure. Gross Margin includes Total Revenues less the costs of Fuel and Other Consumables Used for Electric Generation as well as Purchased Electricity for Resale, 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, they do not typically impact Operating Income or Earnings Attributable to AEP Common Shareholders. Management believes that Gross Margin provides a useful measure for investors and other financial statement users to analyze AEP’s financial performance in that it excludes the effect on Total Revenues caused by volatility in these expenses. Operating income, which is presented in accordance with GAAP in AEP’s statements of income, is the most directly comparable GAAP financial measure to the presentation of Gross Margin. AEP’s definition of Gross Margin may not be directly comparable to similarly titled financial measures used by other companies. 22


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    The table below presents Earnings (Loss) Attributable to AEP Common Shareholders by segment: Years Ended December 31, 2017 2016 2015 (in millions) Vertically Integrated Utilities $ 790.5 $ 979.9 $ 896.5 Transmission and Distribution Utilities 636.4 482.1 352.4 AEP Transmission Holdco 352.1 266.3 191.2 Generation & Marketing 166.0 (1,198.0) 366.0 Corporate and Other (32.4) 80.6 241.0 Earnings Attributable to AEP Common Shareholders $ 1,912.6 $ 610.9 $ 2,047.1 AEP CONSOLIDATED 2017 Compared to 2016 Earnings Attributable to AEP Common Shareholders increased from $611 million in 2016 to $1.9 billion in 2017 primarily due to: An increase due to the impairment of certain merchant generation assets in 2016. An increase due to the current year gain on the sale of certain merchant generation assets. An increase in transmission investment primarily at AEP Transmission Holdco which resulted in higher revenues and income. Favorable rate proceedings in AEP’s various jurisdictions. These increases were partially offset by: A decrease in generation revenues associated with the sale of certain merchant generation assets. A decrease in weather-related usage. A decrease in FERC wholesale municipal and cooperative revenues. The prior year reversal of income tax expense for an unrealized capital loss valuation allowance. AEP effectively settled a 2011 audit issue with the IRS resulting in a change in the valuation allowance. 2016 Compared to 2015 Earnings Attributable to AEP Common Shareholders decreased from $2 billion in 2015 to $611 million in 2016 primarily due to: An impairment of certain merchant generation assets. A decrease in generation revenues due to lower capacity revenue and a decrease in wholesale energy prices. These decreases were partially offset by: A decrease in system income taxes primarily due to reduced pretax book income as a result of the impairment of certain merchant generation assets as well as the reversal of valuation allowances related to the pending sale of certain merchant generation assets and the settlement of a 2011 audit issue with the IRS, as well as favorable 2015 income tax return adjustments related to AEP’s commercial barging operations. Favorable rate proceedings during 2016 in AEP’s various jurisdictions. AEP’s results of operations by reportable segment are discussed below. 23


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    VERTICALLY INTEGRATED UTILITIES Years Ended December 31, Vertically Integrated Utilities 2017 2016 2015 (in millions) Revenues $ 9,192.0 $ 9,091.9 $ 9,172.2 Fuel and Purchased Electricity 3,142.7 3,079.3 3,413.6 Gross Margin 6,049.3 6,012.6 5,758.6 Other Operation and Maintenance 2,737.2 2,702.9 2,529.5 Asset Impairments and Other Related Charges 33.6 10.5 — Depreciation and Amortization 1,142.5 1,073.8 1,062.6 Taxes Other Than Income Taxes 413.3 390.8 383.1 Operating Income 1,722.7 1,834.6 1,783.4 Interest and Investment Income 6.8 4.8 4.6 Carrying Costs Income 15.2 10.5 11.8 Allowance for Equity Funds Used During Construction 28.0 45.5 63.2 Interest Expense (540.0) (522.1) (517.4) Income Before Income Tax Expense and Equity Earnings (Loss) 1,232.7 1,373.3 1,345.6 Income Tax Expense 425.6 397.3 449.3 Equity Earnings (Loss) of Unconsolidated Subsidiaries (3.8) 8.0 3.9 Net Income 803.3 984.0 900.2 Net Income Attributable to Noncontrolling Interests 12.8 4.1 3.7 Earnings Attributable to AEP Common Shareholders $ 790.5 $ 979.9 $ 896.5 Summary of KWh Energy Sales for Vertically Integrated Utilities Years Ended December 31, 2017 2016 2015 (in millions of KWhs) Retail: Residential 30,817 32,606 32,720 Commercial 24,423 25,229 25,006 Industrial 34,676 34,029 34,638 Miscellaneous 2,275 2,316 2,279 Total Retail 92,191 94,180 94,643 Wholesale (a) 25,098 23,081 25,353 Total KWhs 117,289 117,261 119,996 (a) Includes off-system sales, municipalities and cooperatives, unit power and other wholesale customers. 24


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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, 2017 2016 2015 (in degree days) Eastern Region Actual – Heating (a) 2,298 2,541 2,710 Normal – Heating (b) 2,746 2,767 2,755 Actual – Cooling (c) 1,088 1,345 1,113 Normal – Cooling (b) 1,078 1,075 1,075 Western Region Actual – Heating (a) 1,040 1,130 1,379 Normal – Heating (b) 1,494 1,495 1,491 Actual – Cooling (c) 2,164 2,480 2,315 Normal – Cooling (b) 2,229 2,215 2,210 (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. 25


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    2017 Compared to 2016 Reconciliation of Year Ended December 31, 2016 to Year Ended December 31, 2017 Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities (in millions) Year Ended December 31, 2016 $ 979.9 Changes in Gross Margin: Retail Margins 6.6 Off-system Sales 12.0 Transmission Revenues 17.3 Other Revenues 0.8 Total Change in Gross Margin 36.7 Changes in Expenses and Other: Other Operation and Maintenance (34.3) Asset Impairments and Other Related Charges (23.1) Depreciation and Amortization (68.7) Taxes Other Than Income Taxes (22.5) Interest and Investment Income 2.0 Carrying Costs Income 4.7 Allowance for Equity Funds Used During Construction (17.5) Interest Expense (17.9) Total Change in Expenses and Other (177.3) Income Tax Expense (28.3) Equity Earnings (Loss) of Unconsolidated Subsidiaries (11.8) Net Income Attributable to Noncontrolling Interests (8.7) Year Ended December 31, 2017 $ 790.5 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 $7 million primarily due to the following: The effect of rate proceedings in AEP’s service territories which include: A $74 million increase for SWEPCo primarily due to rider and base rate revenue increases in Texas and Louisiana. A $63 million increase for I&M from rate proceedings primarily in Indiana. A $22 million increase for PSO from base rate increases implemented in 2017 and revenue increases from rate riders. A $6 million increase for KGPCo due to revenue increases from rate riders/trackers. For the rate increases described above, $87 million relate to riders/trackers which have corresponding increases in expense items below. A $24 million increase primarily due to reduced fuel and other variable production costs not recovered through fuel clauses or other trackers. A $9 million increase in weather-normalized margins due to higher residential and industrial sales partially offset by lower commercial sales. These increases were partially offset by: A $133 million decrease in weather-related usage in the eastern and western regions. A $50 million decrease for I&M and SWEPCo in FERC generation wholesale municipal and cooperative revenues primarily due to an annual formula rate true-up and changes to the annual formula rate. A $9 million decrease for APCo primarily due to prior year recognition of deferred billing in West Virginia as approved by the WVPSC. 26


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    Margins from Off-system Sales increased $12 million primarily due to higher market prices and increased sales volume. Transmission Revenues increased $17 million primarily due the following: A $43 million increase primarily due to increases in formula rates driven by continued investment in transmission assets. This increase was partially offset in Expenses and Other items below. This increase was partially offset by: A $26 million decrease primarily due to I&M’s annual formula rate true-up and reduced net PJM Network Integration Transmission Service revenues resulting from increased affiliated transmission-related charges. Expenses and Other, Income Tax Expense, Equity Earnings (Loss) of Unconsolidated Subsidiaries and Net Income Attributable to Noncontrolling Interests changed between years as follows: Other Operation and Maintenance expenses increased $34 million primarily due to the following: A $134 million increase in recoverable expenses, primarily PJM expenses, fuel support and energy efficiency expenses fully recovered in rate recovery riders/trackers within Gross Margin above. A $14 million increase due to the Wind Catcher Project for PSO and SWEPCo. These increases were partially offset by: A $49 million decrease in employee-related expenses. A $36 million decrease in charitable contributions, primarily to the AEP Foundation. A $17 million decrease in planned plant outages and maintenance primarily in the western region. A $5 million decrease due to an increase in gain on sales of property in 2017. A $4 million decrease due to the reduction of an environmental liability at I&M. Asset Impairments and Other Related Charges increased $23 million primarily due to the following: A $34 million increase at SWEPCo due to asset impairments of Turk Plant and Welsh Plant, Unit 2 and other charges related to the Texas base rate case. This increase was partially offset by: An $11 million decrease due to the impairment of I&M’s Price River Coal reserves in 2016. Depreciation and Amortization expenses increased $69 million primarily due to the following: A $61 million increase primarily due to higher depreciable base. A $22 million increase due to amortization of capitalized software costs. Taxes Other Than Income Taxes increased $23 million primarily due to higher property taxes. Carrying Costs Income increased $5 million primarily due to increased deferred carrying charges at I&M for a Cook Life Cycle Management project. Allowance for Equity Funds Used During Construction decreased $18 million primarily due to completed environmental projects for I&M, PSO and SWEPCo. Interest Expense increased $18 million primarily due to the following: A $10 million increase primarily due to higher long-term debt balances at I&M. An $8 million increase due to lower AFUDC borrowed funds resulting from reduced CWIP balances. Income Tax Expense increased $28 million primarily due to the recording of favorable state and federal income tax adjustments in 2016, the recording of federal income tax adjustments related to Tax Reform and other book/ tax differences which are accounted for on a flow-through basis, partially offset by a decrease in pretax book income. Equity Earnings (Loss) of Unconsolidated Subsidiaries decreased $12 million primarily due to a prior period income tax adjustment for DHLC, a SWEPCo unconsolidated subsidiary. Net Income Attributable to Noncontrolling Interests increased $9 million primarily due to income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine. This increase was offset by a decrease in Income Tax Expense. 27


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    2016 Compared to 2015 Reconciliation of Year Ended December 31, 2015 to Year Ended December 31, 2016 Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities (in millions) Year Ended December 31, 2015 $ 896.5 Changes in Gross Margin: Retail Margins 274.5 Off-system Sales (18.7) Transmission Revenues (6.1) Other Revenues 4.3 Total Change in Gross Margin 254.0 Changes in Expenses and Other: Other Operation and Maintenance (173.4) Asset Impairments and Other Related Charges (10.5) Depreciation and Amortization (11.2) Taxes Other Than Income Taxes (7.7) Interest and Investment Income 0.2 Carrying Costs Income (1.3) Allowance for Equity Funds Used During Construction (17.7) Interest Expense (4.7) Total Change in Expenses and Other (226.3) Income Tax Expense 52.0 Equity Earnings (Loss) of Unconsolidated Subsidiaries 4.1 Net Income Attributable to Noncontrolling Interests (0.4) Year Ended December 31, 2016 $ 979.9 The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows: Retail Margins increased $275 million primarily due to the following: The effect of rate proceedings in AEP’s service territories which include: A $158 million increase in rates in West Virginia and Virginia, which includes recognition of deferred billing in West Virginia as approved by the WVPSC in June 2016. This increase was partially offset by a 2015 adjustment affected by the amended Virginia law that has an impact on biennial reviews. A $48 million increase for KPCo primarily due to increases in base rates and riders. A $41 million increase for I&M due to increases in riders in the Indiana service territory. A $26 million increase for PSO due to base rate increases implemented in January 2016 and rider revenues. A $23 million increase for SWEPCo due to revenue increases from rate riders in Arkansas and Texas. For the increases described above, $177 million relate to riders/trackers which have corresponding increases in expense items below. A $29 million increase in weather-related usage primarily in the eastern region. These increases were partially offset by: A $22 million decrease in weather-normalized margins primarily in the eastern region. A $20 million decrease for SWEPCo in municipal and cooperative revenues due to a true-up of formula rates in 2015. An $11 million decrease for I&M in FERC municipal and cooperative revenues due to annual formula rate adjustments offset by increased formula rate changes. Margins from Off-system Sales decreased $19 million primarily due to lower market prices and decreased sales volumes. 28


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    Transmission Revenues decreased $6 million primarily due to the following: A $27 million decrease due to lower Network Integration Transmission Service (NITS) revenues. This decrease was partially offset by: A $14 million increase in SPP Non-Affiliated Base Plan Funding associated with increased transmission investments. This increase was offset by a corresponding increase in Other Operation and Maintenance expenses below. A $5 million increase in SPP sponsor-funded transmission upgrades recorded in 2016. This increase was offset by a corresponding increase in Other Operation and Maintenance expenses below. Other Revenues increased $4 million primarily due to increased revenues from demand side management programs in Kentucky, partially offset within Other Operation and Maintenance below. Expenses and Other, Income Tax Expense and Equity Earnings (Loss) of Unconsolidated Subsidiaries changed between years as follows: Other Operation and Maintenance expenses increased $173 million primarily due to the following: A $103 million increase in recoverable expenses, primarily including PJM, vegetation management, energy efficiency and storm expenses fully recovered in rate recovery riders/trackers within Retail Margins above. A $57 million increase associated with amortization of deferred transmission costs in accordance with the Virginia Transmission Rate Adjustment Clause effective January 2016. This increase in expense was offset within Retail Margins above. A $35 million increase due to a charitable donation to the AEP Foundation. A $33 million increase in SPP and PJM transmission services expense. A $6 million increase due to the reduction of an environmental liability in 2015 at I&M. These increases were partially offset by: A $61 million decrease in plant outages, primarily planned outages in the eastern region. A $6 million decrease due to a 2016 gain on the sale of property in the APCo region. Asset Impairments and Other Related Charges increased $11 million due to the impairment of I&M’s Price River Coal reserves. Depreciation and Amortization expenses increased $11 million primarily due to: A $42 million increase due to a higher depreciable base. These increases were partially offset by the following: A $14 million decrease in the amortization of capitalized software due to retirements in 2015. An $8 million decrease due to a revision in I&M’s nuclear asset retirement obligation (ARO) estimate, which has a corresponding increase in Other Operation and Maintenance expenses above. A $4 million decrease in amortization related to the advanced metering infrastructure projects in Oklahoma. A $3 million decrease in ARO expenses due to steam plant retirements in 2015. Taxes Other Than Income Taxes increased $8 million primarily due to an increase in property taxes as a result of increased property investment. Allowance for Equity Funds Used During Construction decreased $18 million primarily due to the completion of environmental projects at SWEPCo. Interest Expense increased $5 million primarily due to the following: An $11 million increase due to higher long-term debt balances at I&M. This increase was partially offset by: A $7 million decrease primarily due to the deferral of the debt component of carrying charges on environmental control costs for projects in Oklahoma at Northeastern Plant, Unit 3 and the Comanche Plant. Income Tax Expense decreased $52 million primarily due to the recording of federal and state income tax adjustments and other book/tax differences which are accounted for on a flow-through basis, partially offset by an increase in pretax book income. Equity Earnings (Loss) of Unconsolidated Subsidiaries increased $4 million primarily due to favorable tax adjustments in 2016. 29


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    TRANSMISSION AND DISTRIBUTION UTILITIES Years Ended December 31, Transmission and Distribution Utilities 2017 2016 2015 (in millions) Revenues $ 4,419.3 $ 4,422.4 $ 4,556.6 Purchased Electricity 835.3 837.1 1,144.2 Generation Deferrals — (82.7) (30.7) Amortization of Generation Deferrals 229.2 242.9 169.1 Gross Margin 3,354.8 3,425.1 3,274.0 Other Operation and Maintenance 1,190.4 1,386.7 1,328.9 Depreciation and Amortization 667.5 649.9 686.4 Taxes Other Than Income Taxes 513.7 494.3 478.3 Operating Income 983.2 894.2 780.4 Interest and Investment Income 7.7 14.8 6.4 Carrying Costs Income 3.6 20.0 11.8 Allowance for Equity Funds Used During Construction 13.2 15.1 15.5 Interest Expense (244.1) (256.9) (276.2) Income Before Income Tax Expense 763.6 687.2 537.9 Income Tax Expense 127.2 205.1 185.5 Net Income 636.4 482.1 352.4 Net Income Attributable to Noncontrolling Interests — — — Earnings Attributable to AEP Common Shareholders $ 636.4 $ 482.1 $ 352.4 Summary of KWh Energy Sales for Transmission and Distribution Utilities Years Ended December 31, 2017 2016 2015 (in millions of KWhs) Retail: Residential 25,108 26,191 25,735 Commercial 25,390 25,922 25,268 Industrial 23,082 22,179 22,353 Miscellaneous 682 700 702 Total Retail (a) 74,262 74,992 74,058 Wholesale (b) 2,387 1,888 1,701 Total KWhs 76,649 76,880 75,759 (a) Represents energy delivered to distribution customers. (b) Primarily Ohio’s contractually obligated purchases of OVEC power sold into PJM. 30


  • Page 41

    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, 2017 2016 2015 (in degree days) Eastern Region Actual – Heating (a) 2,709 2,957 3,235 Normal – Heating (b) 3,225 3,245 3,226 Actual – Cooling (c) 1,002 1,248 975 Normal – Cooling (b) 974 969 970 Western Region Actual – Heating (a) 239 201 390 Normal – Heating (b) 330 328 325 Actual – Cooling (d) 2,950 3,058 2,718 Normal – Cooling (b) 2,669 2,648 2,642 (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. 31


  • Page 42

    2017 Compared to 2016 Reconciliation of Year Ended December 31, 2016 to Year Ended December 31, 2017 Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities (in millions) Year Ended December 31, 2016 $ 482.1 Changes in Gross Margin: Retail Margins (25.7) Off-system Sales (83.8) Transmission Revenues 32.3 Other Revenues 6.9 Total Change in Gross Margin (70.3) Changes in Expenses and Other: Other Operation and Maintenance 196.3 Depreciation and Amortization (17.6) Taxes Other Than Income Taxes (19.4) Interest and Investment Income (7.1) Carrying Costs Income (16.4) Allowance for Equity Funds Used During Construction (1.9) Interest Expense 12.8 Total Change in Expenses and Other 146.7 Income Tax Expense 77.9 Year Ended December 31, 2017 $ 636.4 The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows: Retail Margins decreased $26 million primarily due to the following: A $178 million decrease in Ohio revenues associated with the Universal Service Fund (USF) surcharge rate decrease. This decrease was offset by a corresponding decrease in Other Operating and Maintenance expenses below. An $83 million decrease due to the impact of a 2016 regulatory deferral of capacity costs related to OPCo's December 2016 Global Settlement. A $23 million net decrease in recovery of equity carrying charges related to the PIRR in Ohio, net of associated amortizations. A $21 million decrease in revenues associated with smart grid riders in Ohio. This decrease was offset in various expense items below. A $15 million decrease in weather-normalized margins, primarily in the residential class. A $9 million decrease in Energy Efficiency/Peak Demand Reduction rider revenues and associated deferrals in Ohio. This decrease was offset by a corresponding decrease in Other Operation and Maintenance expenses below. A $7 million decrease in state excise taxes due to a decrease in metered KWh in Ohio. This decrease was offset by a corresponding decrease in Taxes Other Than Income Taxes. These decreases were partially offset by: A $150 million net increase due to the impact of 2016 provisions for refund primarily related to OPCo’s December 2016 Global Settlement. 32


  • Page 43

    A $62 million increase in Ohio due to the recovery of losses from a power contract with OVEC. The PUCO approved a PPA rider beginning in January 2017 to recover any net margin related to the deferral of OVEC losses starting in June 2016. This increase was offset by a corresponding decrease in Margins from Off- System Sales below. A $45 million increase in Texas revenues associated with the Distribution Cost Recovery Factor revenue rider. A $31 million net increase in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was offset by a corresponding increase in Other Operation and Maintenance below. A $16 million net increase in Ohio RSR revenues less associated amortizations. A $7 million increase in Ohio rider revenues associated with the DIR. This increase was partially offset in other expense items below. Margins from Off-system Sales decreased $84 million primarily due to the following: A $62 million decrease in Ohio due to current year losses from a power contract with OVEC, which was offset in Retail Margins above as a result of the OVEC PPA rider beginning in January 2017. A $41 million decrease in Ohio due to the 2016 reversal of prior year provisions for regulatory loss. This decrease was partially offset by: An $18 million increase in Ohio primarily due to the impact of prior year losses from a power contract with OVEC which was not included in the OVEC PPA rider. Transmission Revenues increased $32 million primarily due to recovery of increased transmission investment in ERCOT. Other Revenues increased $7 million primarily due the following: A $12 million increase in securitization revenue in Texas. This increase was offset below in Depreciation and Amortization and in Interest Expense. This increase was partially offset by: A $4 million decrease in Texas performance bonus revenues and true-ups related to energy efficiency programs. Expenses and Other and Income Tax Expense changed between years as follows: Other Operation and Maintenance expenses decreased $196 million primarily due to the following: A $178 million decrease in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This decrease was offset by a corresponding decrease in Retail Margins above. A $29 million decrease primarily due to charitable donations in 2016, including the AEP Foundation. A $17 million decrease in employee-related expenses. These decreases were partially offset by: A $19 million increase in recoverable expenses primarily in PJM as well as increased ERCOT transmission expenses, partially offset by energy efficiency expenses that were fully recovered in rate recovery riders/ trackers within Gross Margins above. A $14 million increase in PJM expenses related to the annual formula rate true-up that will be recovered in 2018. A $6 million increase in non-deferred storm expenses, primarily in the Texas region. Depreciation and Amortization expenses increased $18 million primarily due to the following: A $21 million increase due to securitization amortizations related to Texas securitized transition funding. This increase was offset in Other Revenues above and in Interest Expense below. A $15 million increase in depreciation expense primarily due to an increase in depreciable base of transmission and distribution assets. An $8 million increase due to amortization of capitalized software costs. These increases were partially offset by: An $8 million decrease due to recoveries of transmission cost rider carrying costs in Ohio. This decrease was partially offset in Retail Margins above. An $8 million decrease in recoverable DIR depreciation expense in Ohio. A $7 million decrease in recoverable smart grid rider depreciation expenses in Ohio. This decrease was partially offset in Retail Margins above. 33


  • Page 44

    Taxes Other Than Income Taxes increased $19 million primarily due to the following: A $26 million increase in property taxes due to additional investments in transmission and distribution assets and higher tax rates. This increase was partially offset by: A $7 million decrease in state excise taxes due to a decrease in metered KWhs in Ohio. This decrease was offset in Retail Margins above. Interest and Investment Income decreased $7 million primarily due to a prior year tax adjustment in Texas. Carrying Costs Income decreased $16 million primarily due to the impact of a 2016 regulatory deferral of capacity related carrying costs in Ohio. Interest Expense decreased $13 million primarily due to the following: A $10 million decrease primarily due to the maturity of a senior unsecured note in June 2016 in Ohio. A $9 million decrease in the Texas securitization transition assets due to the final maturity of the first Texas securitization bond. This decrease was offset above in Other Revenues and in Depreciation and Amortization. These decreases were partially offset by: A $7 million increase due to the issuance of long-term debt in September 2017 in Texas. Income Tax Expense decreased $78 million primarily due to the following: A $138 million decrease due to the recording of federal income tax adjustments related to Tax Reform. This decrease was partially offset by: A $60 million increase in pretax book income and by the recording of federal and state income tax adjustments. 34


  • Page 45

    2016 Compared to 2015 Reconciliation of Year Ended December 31, 2015 to Year Ended December 31, 2016 Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities (in millions) Year Ended December 31, 2015 $ 352.4 Changes in Gross Margin: Retail Margins 185.4 Off-system Sales 46.3 Transmission Revenues (0.6) Other Revenues (80.0) Total Change in Gross Margin 151.1 Changes in Expenses and Other: Other Operation and Maintenance (57.8) Depreciation and Amortization 36.5 Taxes Other Than Income Taxes (16.0) Interest and Investment Income 8.4 Carrying Costs Income 8.2 Allowance for Equity Funds Used During Construction (0.4) Interest Expense 19.3 Total Change in Expenses and Other (1.8) Income Tax Expense (19.6) Year Ended December 31, 2016 $ 482.1 The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows: Retail Margins increased $185 million primarily due to the following: A $117 million increase in Ohio transmission and PJM revenues primarily due to the energy supplied as a result of the Ohio auction and a regulatory change which resulted in revenues collected through a non- bypassable transmission rider, partially offset by a corresponding decrease in Transmission Revenues below. An $83 million increase due to the impact of a 2016 regulatory deferral of capacity costs related to OPCo's December 2016 Global Settlement. A $44 million increase in Ohio riders such as Universal Service Fund (USF) and smart grid. This increase in Retail Margins was primarily offset by an increase in Other Operation and Maintenance expenses below. A $34 million increase in collections of PIRR carrying charges in Ohio as a result of the June 2016 PUCO order. A $24 million increase in revenues associated with the Ohio DIR. This increase was partially offset in various line items below. A $22 million increase in AEP Texas weather-normalized margins primarily in the residential class. A $20 million increase in AEP Texas revenues primarily due to the recovery of ERCOT transmission expenses, offset in Other Operation and Maintenance expenses below. A $17 million increase in AEP Texas revenues primarily due to the recovery of distribution expenses. These increases were partially offset by: A $150 million net decrease due to the impact of 2016 provisions for refund primarily related to OPCo's December 2016 Global Settlement. A $16 million decrease in revenues associated with the recovery of 2012 storm costs under the Ohio Storm Damage Recovery Rider which ended in April 2015. This decrease in Retail Margins was primarily offset by a decrease in Other Operation and Maintenance expenses below. 35


  • Page 46

    Margins from Off-system Sales increased $46 million primarily due to the following: A $41 million increase due to a reversal of a 2015 provision for regulatory loss in Ohio. An $8 million increase primarily due to prior year losses in Ohio from a power contract with OVEC. These increases were partially offset by: A $3 million decrease in margins from a power contract with AEPEP for Oklaunion. Transmission Revenues decreased $1 million primarily due to the following: A $56 million decrease in NITS revenue primarily due to OPCo assuming the responsibility for items determined to be cost-based transmission-related charges that were the responsibility of the CRES providers prior to June 2015, partially offset by a corresponding increase in Retail Margins above. This decrease was partially offset by: A $36 million increase primarily due to increased transmission investment in ERCOT. A $19 million increase in Ohio due to a FERC settlement recorded in 2015 and FERC formula rate true-up adjustments. Other Revenues decreased $80 million primarily due to a decrease in Texas securitization revenue as a result of the final maturity of the first Texas securitization bond, offset in Depreciation and Amortization and other expense items below. Expenses and Other and Income Tax Expense changed between years as follows: Other Operation and Maintenance expenses increased $58 million primarily due to the following: A $73 million increase in recoverable expenses, primarily including PJM expenses and smart grid expenses, currently fully recovered in rate recovery riders/trackers within Retail Margins above. A $28 million increase due to charitable donations, including the AEP Foundation. A $21 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset by a corresponding increase in Retail Margins above. These increases were partially offset by: A $14 million decrease due to the completion of the Ohio amortization of 2012 deferred storm expenses in April 2015. This decrease was offset by a corresponding decrease in Retail Margins above. A $13 million decrease in distribution expenses primarily related to storms and 2015 asset inspections. A $12 million decrease in vegetation management expenses. A $12 million decrease related to a 2015 regulatory settlement in Ohio. A $6 million decrease due to a PUCO ordered contribution to the Ohio Growth Fund recorded in 2015. Depreciation and Amortization expenses decreased $37 million primarily due to the following: A $65 million decrease in the Texas securitization transition assets due to the final maturity of the first Texas securitization bond, which was offset in Other Revenues above. A $7 million decrease in the amortization of capitalized software due to 2015 retirements. A $4 million decrease in recoverable smart grid depreciation expenses in Ohio. This decrease was partially offset by a corresponding decrease in Retail Margins above. These decreases were partially offset by: A $20 million increase in recoverable Ohio DIR depreciation expense. This increase was offset by a corresponding increase in Retail Margins above. A $20 million increase in depreciation expense primarily due to an increase in depreciable base of transmission and distribution assets. Taxes Other Than Income Taxes increased $16 million primarily due to increased property taxes in Ohio resulting from additional investments in transmission and distribution assets and higher tax rates. Interest and Investment Income increased $8 million primarily due to a settlement with the IRS related to the U.K. Windfall Tax. Carrying Costs Income increased $8 million primarily due to the following: A $14 million increase due to the impact of a 2016 regulatory deferral of carrying costs related to OPCo's December 2016 Global Settlement. A $4 million increase primarily due to a 2015 unfavorable adjustment related to smart grid capital carrying charges in Ohio. 36


  • Page 47

    These increases were partially offset by: A $10 million decrease due to the collection of carrying costs on Ohio deferred capacity charges beginning June 2015. Interest Expense decreased $19 million primarily due to: A $14 million decrease in the Texas securitization transition assets due to the final maturity of the first Texas securitization bond. This decrease was offset by a corresponding decrease in Other Revenues above. A $12 million decrease due to the maturity of an OPCo senior unsecured note in June 2016. A $2 million decrease in recoverable DIR interest expenses in Ohio. This decrease was offset by a corresponding decrease in Retail Margins above. These decreases were partially offset by the following: An $11 million increase due to issuances of senior unsecured notes by AEP Texas. Income Tax Expense increased $20 million primarily due to an increase in pretax book income partially offset by the recording of state and federal income tax adjustments and the settlement of a 2011 audit issue with the IRS. 37


  • Page 48

    AEP TRANSMISSION HOLDCO Years Ended December 31, AEP Transmission Holdco 2017 2016 2015 (in millions) Transmission Revenues $ 766.7 $ 512.8 $ 329.2 Other Operation and Maintenance 74.4 55.3 38.4 Depreciation and Amortization 102.2 67.1 43.0 Taxes Other Than Income Taxes 114.0 88.7 66.0 Operating Income 476.1 301.7 181.8 Interest and Investment Income 1.2 0.4 0.2 Carrying Costs Expense (0.2) (0.3) (0.2) Allowance for Equity Funds Used During Construction 52.5 52.2 53.0 Interest Expense (72.8) (50.3) (37.2) Income Before Income Tax Expense and Equity Earnings 456.8 303.7 197.6 Income Tax Expense 189.8 134.1 91.3 Equity Earnings of Unconsolidated Subsidiaries 88.6 99.7 86.4 Net Income 355.6 269.3 192.7 Net Income Attributable to Noncontrolling Interests 3.5 3.0 1.5 Earnings Attributable to AEP Common Shareholders $ 352.1 $ 266.3 $ 191.2 Summary of Investment in Transmission Assets for AEP Transmission Holdco December 31, 2017 2016 2015 (in millions) Plant in Service $ 5,784.6 $ 4,386.0 $ 2,885.0 CWIP 1,325.6 968.0 1,092.6 Accumulated Depreciation 176.6 101.4 52.3 Total Transmission Property, Net $ 6,933.6 $ 5,252.6 $ 3,925.3 38


  • Page 49

    2017 Compared to 2016 Reconciliation of Year Ended December 31, 2016 to Year Ended December 31, 2017 Earnings Attributable to AEP Common Shareholders from Transmission Holdco (in millions) Year Ended December 31, 2016 $ 266.3 Changes in Transmission Revenues: Transmission Revenues 253.9 Total Change in Transmission Revenues 253.9 Changes in Expenses and Other: Other Operation and Maintenance (19.1) Depreciation and Amortization (35.1) Taxes Other Than Income Taxes (25.3) Interest and Investment Income 0.8 Carrying Costs Expense 0.1 Allowance for Equity Funds Used During Construction 0.3 Interest Expense (22.5) Total Change in Expenses and Other (100.8) Income Tax Expense (55.7) Equity Earnings of Unconsolidated Subsidiaries (11.1) Net Income Attributable to Noncontrolling Interests (0.5) Year Ended December 31, 2017 $ 352.1 The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and non-affiliates were as follows: Transmission Revenues increased $254 million primarily due to: A $246 million increase in formula rates driven by the favorable impact of the modification of the PJM OATT formula combined with an increase driven by continued investments in transmission assets. A $7 million increase due to rental revenue related to various AEPTCo facilities. Expenses and Other, Income Tax Expense and Equity Earnings of Unconsolidated Subsidiaries changed between years as follows: Other Operation and Maintenance expenses increased $19 million primarily due to increased transmission investment. Depreciation and Amortization expenses increased $35 million primarily due to higher depreciable base. Taxes Other Than Income Taxes increased $25 million primarily due to increased property taxes as a result of additional transmission investment. Interest Expense increased $23 million primarily due to higher outstanding long-term debt balances. Income Tax Expense increased $56 million primarily due to an increase in pretax book income. Equity Earnings of Unconsolidated Subsidiaries decreased $11 million primarily due to lower earnings at ETT resulting from increased property taxes, depreciation expense, and decreased AFUDC, partially offset by increased revenues. The revenue increase is primarily due to interim rate increases in the third quarter of 2016 and higher loads, partially offset by an ETT rate reduction that went into effect in March 2017. 39


  • Page 50

    2016 Compared to 2015 Reconciliation of Year Ended December 31, 2015 to Year Ended December 31, 2016 Earnings Attributable to AEP Common Shareholders from Transmission Holdco (in millions) Year Ended December 31, 2015 $ 191.2 Changes in Transmission Revenues: Transmission Revenues 183.6 Total Change in Transmission Revenues 183.6 Changes in Expenses and Other: Other Operation and Maintenance (16.9) Depreciation and Amortization (24.1) Taxes Other Than Income Taxes (22.7) Interest and Investment Income 0.2 Carrying Costs Expense (0.1) Allowance for Equity Funds Used During Construction (0.8) Interest Expense (13.1) Total Change in Expenses and Other (77.5) Income Tax Expense (42.8) Equity Earnings of Unconsolidated Subsidiaries 13.3 Net Income Attributable to Noncontrolling Interests (1.5) Year Ended December 31, 2016 $ 266.3 The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and non-affiliates were as follows: Transmission Revenues increased $184 million primarily due to the following: A $156 million increase due to formula rate increases driven by continued investment in transmission assets and the related increases in recoverable operating expenses. A $28 million increase due to annual formula rate true-up adjustments. Expenses and Other, Income Tax Expense and Equity Earnings of Unconsolidated Subsidiaries changed between years as follows: Other Operation and Maintenance expenses increased $17 million primarily due to increased transmission investment. Depreciation and Amortization expenses increased $24 million primarily due to higher depreciable base. Taxes Other Than Income Taxes increased $23 million primarily due to increased property taxes as a result of additional transmission investment. Interest Expense increased $13 million primarily due to higher outstanding long-term debt balances. Income Tax Expense increased $43 million primarily due to an increase in pretax book income. Equity Earnings of Unconsolidated Subsidiaries increased $13 million primarily due to increased transmission investment by ETT. 40

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