424B5 1 y86406e424b5.txt PROSPECTUS SUPPLEMENT Filed Pursuant to Rule 424(b)(5) Registration No. 333-105243 This prospectus supplement and the accompanying prospectus relate to an effective registration statement under the Securities Act of 1933, but are not complete and may be changed. This prospectus supplement and the accompanying prospectus are not an offer to sell these securities and are not soliciting an offer to buy these securities in any state where the offer or sale is not permitted. SUBJECT TO COMPLETION, DATED MAY 15, 2003 PROSPECTUS SUPPLEMENT (TO PROSPECTUS DATED APRIL 19, 2001) AMERICAN ELECTRIC POWER LOGO $300,000,000 AMERICAN ELECTRIC POWER COMPANY, INC. % SENIOR NOTES, SERIES D, DUE 20 --------------------- The Senior Notes will be our unsecured and unsubordinated obligations. Interest on the Senior Notes is payable semi-annually on and of each year, beginning 2003. The Senior Notes will mature on , 20 . We may redeem the Senior Notes at our option at any time, either as a whole or in part, in each case, at a redemption price equal to 100% of the principal amount of the Senior Notes being redeemed plus a make-whole premium, together with accrued and unpaid interest to the redemption date. The Senior Notes do not have the benefit of any sinking fund. The Senior Notes are unsecured and rank equally with all of our other unsecured and unsubordinated indebtedness from time to time outstanding. We will issue the Senior Notes only in registered form in multiples of $1,000. ---------------------

PER SENIOR NOTE TOTAL --------------- -------- Public offering price(1).................................... % $ Underwriting discount....................................... % $ Proceeds, before expenses, to us............................ % $

--------------- (1) Plus accrued interest, if any, from May , 2003. --------------------- INVESTING IN OUR SENIOR NOTES INVOLVES RISKS. SEE "RISK FACTORS" BEGINNING ON PAGE S-7. NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY OTHER REGULATORY BODY HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR DETERMINED IF THIS PROSPECTUS SUPPLEMENT OR THE ACCOMPANYING PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. The Senior Notes will be ready for delivery in book-entry form only through The Depository Trust Company on or about May , 2003. --------------------- Joint Book-Running Managers CREDIT SUISSE FIRST BOSTON UBS WARBURG The date of this prospectus supplement is May , 2003. YOU SHOULD RELY ONLY ON THE INFORMATION CONTAINED IN OR INCORPORATED BY REFERENCE IN THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS. WE HAVE NOT, AND THE UNDERWRITERS HAVE NOT, AUTHORIZED ANY OTHER PERSON TO PROVIDE YOU WITH DIFFERENT INFORMATION. IF ANYONE PROVIDES YOU WITH DIFFERENT OR INCONSISTENT INFORMATION, YOU SHOULD NOT RELY ON IT. WE ARE NOT, AND THE UNDERWRITERS ARE NOT, MAKING AN OFFER TO SELL THESE SECURITIES IN ANY JURISDICTION WHERE THE OFFER OR SALE IS NOT PERMITTED. YOU SHOULD ASSUME THAT THE INFORMATION APPEARING IN THIS PROSPECTUS SUPPLEMENT, THE ACCOMPANYING PROSPECTUS AND THE DOCUMENTS INCORPORATED BY REFERENCE IS ACCURATE ONLY AS OF THEIR RESPECTIVE DATES. OUR BUSINESS, FINANCIAL CONDITION, RESULTS OF OPERATIONS AND PROSPECTS MAY HAVE CHANGED SINCE THOSE DATES. --------------------- TABLE OF CONTENTS

PAGE ---- PROSPECTUS SUPPLEMENT Summary..................................................... S-1 Forward-Looking Statements.................................. S-6 Risk Factors................................................ S-7 Use of Proceeds............................................. S-21 Capitalization.............................................. S-22 American Electric Power Company, Inc........................ S-23 Supplemental Description of the Senior Notes................ S-28 Underwriting................................................ S-31 Notice to Canadian Residents................................ S-32 Legal Matters............................................... S-33 Experts..................................................... S-33 PROSPECTUS The Company................................................. 1 Where You Can Find More Information......................... 1 Prospectus Supplements...................................... 2 Ratio of Earnings to Fixed Charges.......................... 2 Use of Proceeds............................................. 2 Description of the Notes.................................... 2 Plan of Distribution........................................ 6 Legal Opinions.............................................. 7 Experts..................................................... 7

This document is in two parts. The first is this prospectus supplement, which describes the specific terms of the securities we are offering and also adds to and updates information contained in the accompanying prospectus and the documents incorporated by reference in that prospectus. The second part, the accompanying prospectus, gives more general information about securities we may offer from time to time, including securities other than those we are offering in this prospectus supplement. If information in this prospectus supplement is inconsistent with the accompanying prospectus, you should rely on this prospectus supplement. It is important for you to read and consider all of the information contained in this prospectus supplement and the accompanying prospectus in making your investment decision. You should also read and consider the information in the documents we have referred you to in "Where You Can Find More Information" on page 2 of the accompanying prospectus. We include cross-references in this prospectus supplement and the accompanying prospectus to captions in these materials where you can find additional related discussions. The table of contents in this prospectus supplement provides the pages on which these captions are located. SUMMARY The following information supplements, and should be read together with, the information contained in other parts of this prospectus supplement and in the prospectus to which it relates. This summary highlights selected information from this prospectus supplement and the accompanying prospectus. You should also review "Risk Factors" beginning on page S-7 of this prospectus supplement to determine whether an investment in the Senior Notes is appropriate for you. Unless the context requires otherwise, references to "American Electric Power," "AEP", "we", "our" or "us" refer to American Electric Power Company, Inc., a New York corporation, and its consolidated subsidiaries. AMERICAN ELECTRIC POWER COMPANY, INC. American Electric Power Company, Inc. is one of the largest investor-owned public utility companies in the United States. We provide, directly or indirectly, generation, transmission and distribution services to almost five million customers in eleven states (Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia) through our utility operations. Our portfolio of assets includes: - 38,000 megawatts of generating capacity, the largest complement of generation in the United States; - 38,000 miles of transmission lines; - 186,000 miles of distribution lines that support delivery of electricity to our customers' premises; - Substantial coal transportation assets (7,000 railcars, 1,800 barges, 37 tug boats and two coal handling terminals with 20 million tons of annual capacity); - 6,400 miles of gas pipelines in Louisiana and Texas with 128 billion cubic feet of gas storage facilities; and - 4,000 megawatts of generating capacity in the U.K. and other international investments. BUSINESS STRATEGY Our business is focused on utility operations in the United States, which tend to offer more stable and relatively predictable earnings and cash flow. We are continuing to reduce trading in markets where we do not have assets and will focus instead on ensuring maximum value for our assets by selling output in excess of our utility needs. This asset optimization approach has long been part of our strategy as an active seller of excess power in the Midwest. We remain focused on credit quality and liquidity. Our strategy for the core business of utility operations is to: - Maintain moderate but steady earnings growth; - Manage the regulatory process to maximize retention of earnings and operational improvement; - Maximize the value of transmission assets and protect revenue stream through regional transmission organization (RTO) membership; - Continue process improvement to maintain distribution service quality while enhancing financial performance; and - Optimize generation assets through enhanced availability and sale of excess capacity. OVERVIEW OF UTILITY OPERATIONS Our electric utility subsidiaries have traditionally provided electric service, consisting of generation, transmission and distribution, on an integrated basis to their retail customers. Our operating subsidiaries S-1 include AEP Texas Central Company (formerly Central Power and Light Company), AEP Texas North Company (formerly West Texas Utilities Company), Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma, Southwestern Electric Power Company, Kingsport Power Company, Wheeling Power Company and AEP Generating Company. These operating subsidiaries provide, directly or indirectly, electric service to approximately 5 million customers in eleven states through our electric networks of over 38,000 miles of transmission lines and 186,000 miles of distribution lines. RESTRUCTURING Our public utility subsidiaries, like many other electric utilities, have traditionally provided electric generation and energy delivery, consisting of transmission and distribution services, as a single product to their retail customers. Legislation has been enacted in Michigan, Ohio, Texas and Virginia that allows for customer choice of generation supplier. These measures generally allow competition in the generation and sale of electric power, but not in transmission and distribution. Although customer choice legislation has been enacted in Arkansas, Oklahoma and West Virginia, such legislation has been repealed in Arkansas, delayed indefinitely in Oklahoma and has not been implemented in West Virginia. Each of our Ohio utility subsidiaries currently operates as a functionally separated electric utility company and no longer charges bundled rates for its retail sales of electricity. Distribution rates for our Ohio utility subsidiaries are approved by The Public Utilities Commission of Ohio and transmission rates are approved by the Federal Energy Regulatory Commission (FERC). We have sought regulatory approval to legally separate the transmission and distribution assets of our Ohio utility subsidiaries from their generation assets pursuant to Ohio restructuring legislation. However, we are presently determining the regulatory feasibility of complying with Ohio restructuring legislation through continued functional separation. Assuming regulatory compliance, it is currently our intention that our Ohio utility subsidiaries remain functionally separated. Similarly, each of our Texas utility subsidiaries in the Electric Reliability Counsel of Texas (ERCOT) also currently operates as a functionally separated electric utility company with distribution and, for the most part, transmission rates that continue to be set by the Public Utility Commission of Texas (PUCT) and with generation rates that are not set by the PUCT. We have sought regulatory approval to legally separate the generation assets of our Texas utility subsidiaries from their transmission and distribution assets as required by Texas restructuring legislation. Additionally, AEP Texas Central Company (TCC) intends to sell its generation assets in order to accurately determine its stranded costs in accordance with Texas restructuring legislation and PUCT regulations. Transition rules for Michigan and Virginia do not require legal separation. Due in part to difficulties in deregulating other markets, deregulation appears unlikely for the foreseeable future in the other states in which we operate. S-2 SUMMARY CONSOLIDATED FINANCIAL DATA The following table sets forth summary consolidated financial information for each of the periods indicated. You should read the information in this table together with our consolidated financial statements and the other financial information incorporated by reference in this prospectus supplement and the accompanying prospectus.

THREE MONTHS ENDED YEARS ENDED DECEMBER 31, MARCH 31, --------------------------- 2003 2002 2001 2000 ------------ ------- ------- ------- (IN MILLIONS, EXCEPT PER SHARE DATA) (UNAUDITED) (AUDITED) CONSOLIDATED STATEMENTS OF OPERATIONS DATA: Revenues........................................... $4,080 $14,536 $13,252 $11,326 Expenses........................................... 3,480 13,273 11,070 9,552 ------ ------- ------- ------- Operating Income................................... 600 1,263 2,182 1,774 Less: Investment Value and Other Impairment Losses........................................ -- 321 -- -- Other Income (Expenses)............................ 73 124 148 18 Less: Interest, Preferred Dividend Requirements of Subsidiaries and Minority Interest in Finance Subsidiary............................ 217 831 867 1,010 ------ ------- ------- ------- Income Before Income Taxes......................... 456 235 1,463 782 Income Taxes....................................... 200 214 546 602 ------ ------- ------- ------- Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect of Accounting Change................................ 256 21 917 180 Discontinued Operations (Loss) Income (net of tax)............................................. (9) (190) 86 122 Income (Loss) Before Extraordinary Items and Cumulative Effect................................ 247 (169) 1,003 302 Extraordinary Losses (net of tax): Discontinuance of Regulatory Accounting for Generation.................................... -- -- (48) (35) Loss on Reacquired Debt.......................... -- -- (2) -- Cumulative Effect of Accounting Change (net of tax) Goodwill and Other Intangible Assets............. -- (350) 18 -- Accounting for Risk Management Contracts......... (49) -- -- -- Asset Retirement Obligation...................... 242 -- -- -- ------ ------- ------- ------- Net Income (Loss).................................. $ 440 $ (519) $ 971 $ 267 ====== ======= ======= ======= Average Number of Shares Outstanding............... 356 332 322 322 ====== ======= ======= ======= Earnings Per Share: Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect of Accounting Changes............................ $ 0.72 $ 0.06 $ 2.85 $ 0.56 Discontinued Operations (Loss)................... (0.02) (0.57) 0.26 0.38 Extraordinary Losses............................. -- -- (0.16) (0.11) Cumulative Effect of Accounting Changes.......... 0.54 (1.06) 0.06 -- ------ ------- ------- ------- Earnings (Loss) Per Share (Basic and Diluted).... $ 1.24 $ (1.57) $ 3.01 $ 0.83 ====== ======= ======= ======= Cash Dividends Paid Per Share...................... $ 0.60 $ 2.40 $ 2.40 $ 2.40 ====== ======= ======= =======

S-3

MARCH 31, DECEMBER 31, DECEMBER 31, 2003 2002 2001 --------- ------------ ------------ (UNAUDITED) (AUDITED) CONSOLIDATED BALANCE SHEET DATA: Total Current Assets.......................... $ 7,444 $ 6,101 $ 5,664 Net Property, Plant and Equipment............. 22,328 21,684 22,104 Regulatory Assets............................. 2,669 2,688 3,162 Investments and Other Assets.................. 4,180 4,021 3,692 Assets Held for Sale.......................... 280 247 721 Assets of Discontinued Operations............. -- -- 3,954 ------- ------- ------- Total Assets.................................. $36,901 $34,741 $39,297 ======= ======= =======

MARCH 31, DECEMBER 31, DECEMBER 31, 2003 2002 2001 --------- ------------ ------------ CAPITALIZATION: Total Debt(1)................................. $12,747 $13,660 $13,516 Certain Subsidiary Obligated, Mandatorily Redeemable, Preferred Securities of Subsidiary Trusts Holding Solely Junior Subordinated Debentures of Such Subsidiaries................................ 321 321 321 Minority Interest in Finance Subsidiary....... 759 759 750 Cumulative Preferred Stock of Subsidiaries.... 144 145 156 Total Common Shareholders' Equity............. 8,437 7,064 8,229 ------- ------- ------- Total Capitalization........................ $22,408 $21,949 $22,972 ======= ======= =======

--------------- (1) Includes Short-term Debt, Equity Units and Long-term Debt due within one year. S-4 THE OFFERING Senior Notes.................. $300,000,000 principal amount of % Senior Notes, Series D, due 20 . Maturity Date................. The Senior Notes will mature on , 20 . Interest Rate................. The Senior Notes will bear interest at the rate of % per year. Interest Payment Dates........ Interest on the Senior Notes is payable semi-annually on and of each year, beginning 2003. Redemption.................... We may redeem the Senior Notes at our option at any time, either as a whole or in part, in each case, at a redemption price equal to 100% of the principal amount of the Senior Notes being redeemed plus a make-whole premium, together with accrued and unpaid interest to the redemption date. Ranking....................... The Senior Notes will be unsecured and unsubordinated obligations ranking equally with our other outstanding and future unsecured and unsubordinated indebtedness. Restrictive Covenants......... For a discussion of the restrictive covenants relating to the Senior Notes, see "Limitation on Liens on Stock of Certain Subsidiaries" and "Limitation upon Mergers, Consolidations and Sale of Assets" under "Supplemental Description of the Senior Notes -- Restrictive Covenants Relating to the Senior Notes" in this prospectus supplement. S-5 FORWARD-LOOKING STATEMENTS Some statements contained or incorporated by reference in this prospectus supplement, including the discussion of our plans and proposals under "Summary -- American Electric Power Company, Inc." and "American Electric Power Company, Inc." are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are subject to various risks and uncertainties. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to: - electric load and customer growth; - abnormal weather conditions; - available sources and costs of fuel; - availability of generating capacity; - the speed and degree to which competition is introduced in our service territories; - the ability to recover stranded costs in connection with possible/proposed deregulation; - new legislation and government regulation; - oversight and/or investigation of the energy sector or its participants; - our ability to successfully control our costs; - the success of new business ventures and disposing of existing investments that no longer match our corporate profile; - international and country-specific developments affecting our foreign investments, including the dispositions of any current foreign investments and potential additional foreign investments; - the economic climate and growth in our service territory and changes in market demand and demographic patterns; - inflationary trends; - electricity and gas market prices; - interest rates; - liquidity in the banking, capital and wholesale power markets; - actions of rating agencies; - changes in technology, including the increased use of distributed generation within our transmission and distribution service territory; and - other risks and unforeseen events, including wars, the effects of terrorism, embargoes and other catastrophic events. In light of these risks, uncertainties and assumptions, the forward-looking statements contained or incorporated by reference in this prospectus supplement might not occur. Neither AEP nor the underwriters undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. S-6 RISK FACTORS You should carefully consider the risks described below as well as other information contained or incorporated by reference in this prospectus supplement and the accompanying prospectus before buying the Senior Notes. These are risks we consider to be material to your decision whether to invest in the Senior Notes at this time. There may be risks that you view in a different way than we do, and we may omit a risk that we consider immaterial, but you consider important. If any of the following risks occur, our business, financial condition or results of operations could be materially harmed. In that case, the value or trading price of the Senior Notes could decline, and you may lose all or part of your investment. RISKS RELATED TO OUR ENERGY TRADING AND WHOLESALE BUSINESSES WE HAVE SIGNIFICANTLY REDUCED THE SCOPE AND SCALE OF OUR ENERGY TRADING AND MARKETING OPERATIONS. In October 2002, AEP announced its plans to reduce the exposure to energy trading markets of its subsidiaries that trade energy and to downsize the trading and wholesale marketing operations conducted on behalf of such subsidiaries. It is expected that in the future our energy trading and marketing operations will be limited to risk management around our generation assets. Trading and marketing operations that were not limited to risk management around such assets have contributed to our wholesale revenues and earnings in the past. Management is unable to predict the effect this downsizing of our trading operations will have on our future results of operations and cash flows. The following risk factors appearing under this subheading should be read in light of the announcements discussed in this paragraph. OUR REVENUES AND RESULTS OF OPERATIONS ARE SUBJECT TO MARKET RISKS THAT ARE BEYOND OUR CONTROL. We sell power from our generation facilities into the spot market or other competitive power markets or on a contractual basis. We also enter into contracts to purchase and sell electricity, natural gas and coal as part of our power marketing and energy trading operations. With respect to such transactions, we are not guaranteed any rate of return on our capital investments through mandated rates, and our revenues and results of operations are likely to depend, in large part, upon prevailing market prices for power in our regional markets and other competitive markets. These market prices may fluctuate substantially over relatively short periods of time. It is reasonable to expect that trading margins may erode as markets mature and that there may be diminished opportunities for gain should volatility decline. In addition, the FERC, which has jurisdiction over wholesale power rates, as well as independent system operators that oversee some of these markets, may impose price limitations, bidding rules and other mechanisms to address some of the volatility in these markets. Fuel prices may also be volatile, and the price we can obtain for power sales may not change at the same rate as changes in fuel costs. These factors could reduce our margins and therefore diminish our revenues and results of operations. Volatility in market prices for fuel and power may result from: - weather conditions; - seasonality; - power usage; - illiquid markets; - transmission or transportation constraints or inefficiencies; - availability of competitively priced alternative energy sources; - demand for energy commodities; - natural gas, crude oil and refined products, and coal production levels; - natural disasters, wars, embargoes and other catastrophic events; and - federal, state and foreign energy and environmental regulation and legislation. S-7 WE ARE UNABLE TO PREDICT THE COURSE, RESULTS OR IMPACT, IF ANY, OF CURRENT OR FUTURE ENERGY MARKET INVESTIGATIONS. In February 2002, the FERC issued an order directing its staff to conduct a fact-finding investigation into whether any entity, including Enron Corp., manipulated short-term prices in electric energy or natural gas markets in the West or otherwise exercised undue influence over wholesale prices in the West, for the period January 1, 2000, forward. In April 2002, we furnished certain information to the FERC in response to their related data request. Pursuant to the FERC's February order, on May 8, 2002, the FERC issued further data requests, including requests for admissions, with respect to certain trading strategies engaged in by Enron and, allegedly, traders of other companies active in the wholesale electricity and ancillary services markets in the West, particularly California, during the years 2000 and 2001. This data request was issued to us as part of a group of over 100 entities designated by the FERC as all sellers of wholesale electricity and/or ancillary services to the California Independent System Operator and/or the California Power Exchange. The May 8, 2002 FERC data request required senior management to conduct an investigation into our trading activities during 2000 and 2001 and to provide an affidavit as to whether we engaged in certain trading practices that the FERC characterized in the data request as being potentially manipulative. Senior management complied with the order and denied our involvement with those trading practices. On May 21, 2002, the FERC issued a further data request with respect to this matter to us and over 100 other market participants requesting information for the years 2000 and 2001 concerning "wash," "round trip" or "sale/buy back" trading in the Western System Coordinating Council (WSCC), which involves the sale of an electricity product to another company together with a simultaneous purchase of the same product at the same price (collectively, "wash sales"). Similarly, on May 22, 2002, the FERC issued an additional data request with respect to this matter to us and other market participants requesting similar information for the same period with respect to the sale of natural gas products in the WSCC and Texas. After reviewing our records, we responded to the FERC that we did not participate in any "wash sale" transactions involving power or gas in the relevant market. We further informed the FERC that certain of our traders did engage in trades on the Intercontinental Exchange, an electronic electricity trading platform owned by a group of electricity trading companies, including us, on September 21, 2001, the day on which all brokerage commissions for trades on that exchange were donated to charities for the victims of the September 11, 2001 terrorist attacks, which do not meet the FERC criteria for a "wash sale" but do have certain characteristics in common with such sales. In response to a request from the California attorney general for a copy of AEP's responses to the FERC inquiries, we provided the pertinent information. The Public Utilities Commission of Texas also issued similar data requests to us and other power marketers. We responded to such data request by the July 2, 2002 response date. The US Commodity Futures Trading Commission (CFTC) issued a subpoena to us on June 17, 2002 requesting information with respect to "wash sale" trading practices. We responded to CFTC. In addition, the US Department of Justice made a civil investigation demand to us and other electric generating companies concerning their investigation of the Intercontinental Exchange. We have completed a review of our trading activities in the United States for the last three years involving sequential trades with the same terms and counterparties. The revenue from such trading is not material to our financial statements. We believe that substantially all these transactions involve economic substance and risk transference and do not constitute "wash sales". In August 2002, we received an informal data request from the SEC asking us to voluntarily provide documents related to "round trip" or "wash" trades. We have provided the requested information to the SEC. In March 2003, we received a subpoena from the SEC. The subpoena seeks additional information and is part of the SEC's formal investigative process. In September 2002, we received a subpoena from the FERC requesting information about our natural gas transactions and their potential impact on gas commodity prices in the New York City area. We responded to the subpoena in October 2002. S-8 In October 2002, we dismissed several employees involved in natural gas marketing and trading after the company determined that they provided inaccurate price information for use in indexes compiled and published by trade publications. Subsequently, we instituted measures that require all price information for use in market indexes be verified and reported through the organization of our Chief Risk Officer. We have and will continue to provide to the FERC, the SEC and the CFTC information relating to price data given to energy industry publications. Management is unable to predict the course or outcome of these or any future energy market investigations or their impact, if any, on power commodity trading generally or, more specifically, on our trading operations or future results of operations and cash flows. OUR ENERGY TRADING (INCLUDING FUEL PROCUREMENT AND POWER MARKETING) AND RISK MANAGEMENT POLICIES CANNOT ELIMINATE THE RISK ASSOCIATED WITH THESE ACTIVITIES. Our energy trading (including fuel procurement and power marketing) activities expose us to risks of commodity price movements. We attempt to manage our exposure through enforcement of established risk limits and risk management procedures. These risk limits and risk management procedures may not always be followed or may not work as planned and cannot eliminate the risks associated with these activities. As a result, we cannot predict the impact that our energy trading and risk management decisions may have on our business, operating results or financial position. We routinely have open trading positions in the market, within established guidelines, resulting from the management of our trading portfolio. To the extent open trading positions exist, fluctuating commodity prices can improve or diminish our financial results and financial position. Our energy trading and risk management activities, including our power sales agreements with counterparties, rely on projections that depend heavily on judgments and assumptions by management of factors such as the future market prices and demand for power and other energy-related commodities. These factors become more difficult to predict and the calculations become less reliable the further into the future these estimates are made. Even when our policies and procedures are followed and decisions are made based on these estimates, results of operations may be diminished if the judgments and assumptions underlying those calculations prove to be wrong or inaccurate. Our policies and procedures do not typically require us to hedge the new trading positions that we enter into daily. OUR FINANCIAL PERFORMANCE MAY BE ADVERSELY AFFECTED IF WE ARE UNABLE TO SUCCESSFULLY OPERATE OUR ELECTRIC GENERATING FACILITIES. Our performance depends on the successful operation of our electric generating facilities. Operating electric generating facilities involves many risks, including: - operator error and breakdown or failure of equipment or processes; - operating limitations that may be imposed by environmental or other regulatory requirements; - labor disputes; - fuel supply interruptions; and - catastrophic events such as fires, earthquakes, explosions, floods or other similar occurrences. A decrease or elimination of revenues from power produced by our electric generating facilities or an increase in the cost of operating the facilities would adversely affect our results of operations. PARTIES WITH WHOM WE HAVE CONTRACTS MAY FAIL TO PERFORM THEIR OBLIGATIONS, WHICH COULD HARM OUR RESULTS OF OPERATIONS. We are exposed to the risk that counterparties that owe us money or energy will breach their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative hedging arrangements or honor underlying commitments at then-current market prices that may exceed our S-9 contractual prices, which would cause our financial results to be diminished and we might incur losses. Although our estimates take into account the expected probability of default by a counterparty, our actual exposure to a default by a counterparty may be greater than the estimates predict if defaults by counterparties exceed our estimates. WE RELY ON ELECTRIC TRANSMISSION FACILITIES THAT WE DO NOT OWN OR CONTROL. IF THESE FACILITIES DO NOT PROVIDE US WITH ADEQUATE TRANSMISSION CAPACITY, WE MAY NOT BE ABLE TO DELIVER OUR WHOLESALE ELECTRIC POWER TO OUR CUSTOMERS. We depend on transmission facilities owned and operated by other power companies to deliver the power we sell at wholesale. This dependence exposes us to a variety of risks. If transmission is disrupted, or transmission capacity is inadequate, we may not be able to sell and deliver our wholesale products. If a region's power transmission infrastructure is inadequate, our recovery of wholesale costs and profits may be limited. If restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure. The FERC has issued electric and gas transmission initiatives that require electric and gas transmission services to be offered unbundled from commodity sales. Although these initiatives are designed to encourage wholesale market transactions for electricity and gas, access to transmission systems may in fact not be available if transmission capacity is insufficient because of physical constraints or because it is contractually unavailable. We also cannot predict whether transmission facilities will be expanded in specific markets to accommodate competitive access to those markets. WE DO NOT FULLY HEDGE AGAINST PRICE CHANGES IN COMMODITIES. We routinely enter into contracts to purchase and sell electricity, natural gas and coal as part of our power marketing and energy trading operations and to procure fuel. In connection with these trading activities, we routinely enter into financial contracts, including futures and options, over-the counter options, swaps and other derivative contracts. These activities expose us to risks from price movements. If the values of the financial contracts change in a manner we do not anticipate, it could harm our financial position or reduce the financial contribution of our trading operations. We manage our exposure by establishing risk limits (which we have recently lowered as part of our announced effort to reduce the degree and scale of our trading and marketing operations) and entering into contracts to offset some of our positions (i.e., to hedge our exposure to demand, market effects of weather and other changes in commodity prices). However, we do not always hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility, our results of operations and financial position may be improved or diminished based upon our success in the market. WE ARE EXPOSED TO LOSSES RESULTING FROM THE BANKRUPTCY OF ENRON CORP. On October 15, 2002, certain of our subsidiaries filed claims against Enron Corp. and its subsidiaries in the bankruptcy proceeding filed by the Enron entities which are pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron's bankruptcy we had open trading contracts and trading accounts receivables and payables with Enron. In addition, on June 1, 2001, we purchased Houston Pipe Line Company (HPL) from Enron. Various HPL related contingencies and indemnities remained unsettled at the date of Enron's bankruptcy. The timing of the resolution of the claims by the Bankruptcy Court is not certain. In connection with the 2001 acquisition of HPL, we acquired exclusive rights to use and operate the underground Bammel gas storage facility pursuant to an agreement with BAM Lease Company, a now-bankrupt subsidiary of Enron. This right is for a term of 30 years, with a renewal right for another 20 years and includes the use of the Bammel storage reservoir and the related compression, treating and delivery systems. We have engaged in preliminary discussions with Enron concerning the possible purchase of the residual interest held by Enron in the Bammel storage facility and the possible resolution of outstanding issues between AEP and Enron relating to our acquisition of its interest in the Bammel storage facility. We are unable to predict whether these discussions will lead to an agreement on these subjects. If these discussions do not lead S-10 to an agreement, there may be a dispute with Enron concerning our ability to continue utilization of the Bammel storage facility under the existing agreement. We also entered into an agreement with BAM Lease Company which grants HPL the right to use approximately 65 billion cubic feet of cushion gas (or pad gas) required for the normal operation of the Bammel gas storage facility. The Bammel Gas Trust, which purportedly owned approximately 55 billion cubic feet of the gas, had entered into a financing arrangement in 1997 with Enron and a group of banks. These banks purported to have certain rights to the gas in certain events of default. In connection with our acquisition of HPL, the banks entered into an agreement granting HPL's use of the cushion gas and released HPL from liabilities and obligations under the financing arrangement. HPL was thereafter informed by the banks of a purported default by Enron under the terms of the referenced financing arrangement. In July 2002 the banks filed a lawsuit against HPL seeking a declaratory judgment that they have a valid and enforceable security interest in this cushion gas which would permit them to cause the withdrawal of this gas from the storage facility. In September 2002 HPL filed a general denial and certain counterclaims against the banks. Management is unable to predict the outcome of this lawsuit or its impact on results of operations and cash flows. In 2001 we expensed $47 million ($31 million net of tax) for our estimated loss from the Enron bankruptcy. In 2002 we expensed an additional $6 million for a cumulative loss of $53 million ($34 million net of tax). The amounts expensed were based on an analysis of contracts where AEP subsidiaries and Enron entities are counterparties, the offsetting of receivables and payables, the application of deposits from Enron entities and management's analysis of the HPL related purchase contingencies and indemnifications. Enron has recently instituted proceedings against other energy trading counter-parties challenging the practice of utilizing offsetting receivables and payables and related collateral across various Enron entities. We believe that we have the right to utilize similar procedures in dealing with payables, receivables and collateral with Enron entities by offsetting approximately $110 million of trading payables owed to various Enron entities against trading receivables due to us. We believe we have legal defenses to any challenge that may be made to the utilization of such offsets but at this time are unable to predict the ultimate resolution of this issue. WE ARE EXPOSED TO THE RISK OF FURTHER IMPAIRMENT AND LOSSES RESULTING FROM OUR INVESTMENT IN GENERATION ASSETS IN THE UNITED KINGDOM. In December 2001, we acquired two coal-fired generation plants in the United Kingdom for a cash payment of $942.3 million and assumption of certain liabilities. Subsequent to our acquisition, wholesale electric power prices declined sharply in that market as a result of over-capacity and static demand. External industry forecasts and our own projections made during the fourth quarter of 2002 indicate that this situation may extend many years into the future. As a result, the fixed asset carrying value at year-end 2002 for this investment was substantially impaired. A December 2002 probability-weighted discounted cash flow analysis of the fair value of our investment indicated a 2002 pre-tax impairment loss of $548.7 million. At the time this impairment was announced we stated that we would be evaluating if the plants would continue to operate. If we decide to cease operations at these plants or if external market conditions further deteriorate, we could sustain additional impairment to the value of these assets. If we do not cease operations and over-capacity and static demand continue or worsen in that market, we expect to sustain additional losses associated with these plants. Management is unable to predict whether these plants will continue operations or the impact on our future results of operations, cash flows and financial condition resulting from this investment. DIMINISHED LIQUIDITY IN THE WHOLESALE POWER MARKETS COULD NEGATIVELY IMPACT OUR EARNINGS. The Enron Corp. bankruptcy and enhanced regulatory scrutiny have contributed to more rigorous credit rating review of wholesale power market participants. Credit downgrades and financial difficulties of certain other market participants have significantly reduced such participants' participation in the wholesale power markets. These events are causing a decrease in the number of significant participants in the wholesale power markets, at least temporarily, which could result in a decrease in the volume and liquidity in the wholesale power markets. Such decreases have had a negative impact on our results of operations, cash flows and S-11 financial condition. Reduced liquidity in these markets could also hamper our efforts to exit transactions not related to risk management of our assets that we entered into before reducing the scale of our power trading and marketing operations. We are unable to predict the extent of the impact on our power marketing and trading business if such developments continue. POTENTIAL FOR DISRUPTION IF THE DELAY OF A FERC MARKET POWER MITIGATION ORDER IS LIFTED. A FERC order on our triennial market based wholesale power rate authorization update required certain mitigation actions that certain of our subsidiaries would need to take for sales/purchases within their respective control areas and required us to post information on our website regarding our power systems status. As a result of a request for rehearing filed by us and other market participants, FERC issued an order delaying the effective date of the mitigation plan until after a planned technical conference on market power determination. No such conference has been held and management is unable to predict the timing of any further action by the FERC or its affect on future results of our operations and cash flows. RISKS RELATED TO OUR REGULATED BUSINESS AND EVOLVING REGULATION WE OPERATE IN A NON-UNIFORM AND FLUID REGULATORY ENVIRONMENT. AEP is subject to regulation by the SEC under the Public Utility Holding Company Act of 1935 (PUHCA). The rates charged by the domestic utility subsidiaries are approved by the FERC and the eleven state utility commissions. The FERC regulates wholesale electricity operations and transmission rates and the state commissions regulate retail generation and distribution rates. The prices charged by foreign subsidiaries located in China, Mexico and Brazil are regulated by the authorities of those respective countries and are generally subject to price controls. Six of the eleven state retail jurisdictions in which our domestic electric utilities operate have enacted restructuring legislation. Restructuring legislation in Texas requires the legal separation of generation and related assets from the transmission and distribution assets of the electric utilities in that state. In Ohio, we are determining the regulatory feasibility of complying with restructuring legislation through the continued functional separation of the operations of our Ohio utility subsidiaries. As a result of restructuring legislation in Texas and Ohio, approximately one half of our domestic generation is no longer directly regulated by state utility commissions as to rates. The remaining four states of the six that have enacted restructuring legislation contemplated, at least initially, some level of regulatory reform. Our utility operations in the five state retail jurisdictions that have not enacted any restructuring legislation currently plan to adhere to the vertically-integrated utility model with cost recovery through regulated rates. Our business plan is based on the regulatory framework as described and assumes that deregulated generation will not be re-regulated. There can be no assurance that the states that have pursued restructuring will not reverse such policies; nor can there be assurance that the states that have not enacted restructuring legislation will not do so in the future. In addition to the multiple levels of regulation at the state level in which we operate, our business is subject to extensive federal regulation. There can be no assurance that the federal legislative and regulatory initiatives (which have occurred over the past few years and which have generally facilitated competition in the energy sector) will continue or will not be reversed. Further alteration of the regulatory landscape in which we operate will impact the effectiveness of our business plan and may, because of the continued uncertainty, harm our financial condition and results of operations. RISKS RELATING TO STATE RESTRUCTURING WE HAVE LIMITED ABILITY TO PASS ON TO OUR CUSTOMERS OUR COSTS OF PRODUCTION. We are exposed to risk from changes in the market prices of coal and natural gas used to generate power where generation is no longer regulated or where existing fuel clauses are suspended or frozen. The protection afforded by retail fuel clause recovery mechanisms has been eliminated by the implementation of customer choice in Ohio (effective January 1, 2001) and, to a lesser degree, in the ERCOT area of Texas (effective January 1, 2002). We expect that there may be similar risks should customer choice be similarly implemented S-12 in other states. Because the risk of fuel price increases, increased environmental compliance costs and generating unit outage cannot be passed through to customers during the transition period in Ohio and only partially in Texas upon regulatory approval, we retain these risks. The protection afforded by fuel clause recovery mechanisms has been capped or frozen by settlement agreements currently in place in Indiana (through 2004) and Michigan (through 2003). To the extent all of the fuel supply of the generating units in these states are not under fixed price long-term contracts we are subject to market price risk. We continue to be protected against market price changes by active fuel clauses in Oklahoma, Arkansas, Louisiana, Kentucky, Virginia (through the transition to competition on July 1, 2007) and the Southwest Power Pool (SPP) area of Texas (until the implementation of restructuring). A fuel clause in West Virginia has been suspended per a settlement reached in a state restructuring proceeding. However, as restructuring has not been implemented in West Virginia, the fuel clause may be reactivated. Until the transition to full market competition is complete in Ohio on December 31, 2005, our Ohio regulated utility subsidiaries there are required to provide power at capped rates, which may be below current market rates, to retail customers that do not choose an alternative power generation supplier. Following the transition, it is unclear whether our retail sales of power in Ohio will be at a market rate or at a rate determined by some level of state utility commission involvement. Further action by the state utility commission may be necessary to resolve this uncertainty. OUR DEFAULT SERVICE OBLIGATIONS IN OHIO DO NOT RESTRICT CUSTOMERS FROM SWITCHING SUPPLIERS OF POWER. Those default service customers that we serve in Ohio may choose to purchase power from alternative suppliers. Should they choose to switch from us, our sales of power may decrease. Customers originally choosing alternative suppliers may switch to our default service obligations. This may increase demand above our facilities' available capacity. Thus, any such switching by customers could have an adverse effect on our results of operations and financial position. Conversely, to the extent the power sold to meet the default service obligations could have been sold to third parties at more favorable wholesale prices, we will have incurred potentially significant lost opportunity costs. SOME LAWS AND REGULATIONS GOVERNING RESTRUCTURING OF THE WHOLESALE GENERATION MARKET IN MICHIGAN, OKLAHOMA, VIRGINIA AND WEST VIRGINIA HAVE NOT YET BEEN INTERPRETED OR ADOPTED AND COULD HARM OUR BUSINESS, OPERATING RESULTS AND FINANCIAL CONDITION. While the electric restructuring laws in Michigan, Oklahoma, Virginia and West Virginia established the general framework governing the retail electric market, the laws required the utility commission in each state to issue rules and determinations implementing the laws. Some of the regulations governing the retail electric market have not yet been adopted by the utility commission in each state. These laws, when they are interpreted and when the regulations are developed and adopted, may harm our business, results of operations and financial condition. Virginia restructuring legislation was enacted in 1999 providing for retail choice of generation suppliers to be phased in over two years beginning January 1, 2002. It required jurisdictional utilities to unbundle their power supply and energy delivery rates and to file functional separation plans by January 1, 2002. Our Virginia subsidiary filed its plan and, following Virginia state utility commission approval of a settlement agreement, now operates in Virginia as a functionally separated electric utility charging unbundled rates for its retail sales of electricity. The settlement agreement addressed functional separation, leaving decisions related to legal separation for later VSCC consideration. In June 2001, Oklahoma enacted legislation delaying competition indefinitely. The West Virginia legislature approved electricity restructuring; however, the West Virginia Public Service Commission (WVPSC) cannot implement the restructuring plan until the legislature makes tax law changes necessary to preserve the revenues of state and local governments. Since the legislature has not passed the required tax law changes, the restructuring plan has not become effective. We cannot predict the impact of such a development. S-13 THERE IS UNCERTAINTY AS TO OUR RECOVERY OF DEFERRED FUEL BALANCES AND STRANDED COSTS RESULTING FROM INDUSTRY RESTRUCTURING IN TEXAS. The PUCT review and reconciliation of retail fuel clause recovery was eliminated in the ERCOT area of Texas effective January 1, 2002. In 2002 we filed final fuel reconciliation plans with the PUCT to reconcile the fuel costs of our Texas utility subsidiaries for the relevant periods. The ultimate recovery of deferred fuel balances at December 31, 2001 will be decided as part of PUCT-required true-up proceedings in 2004 (the 2004 true-up proceeding). If the final under-recovered fuel balances or any amounts incurred but not yet reconciled are disallowed, it would harm our financial condition and diminish our results of operations. We have reported in a fuel reconciliation that we filed with the PUCT an over-recovery of fuel and related costs of $36.0 million out of a total $1.9 billion in fuel expenses collected by us. The PUCT has yet to act on our filing. As a part of restructuring in Texas, electric utilities are allowed to recover stranded generation costs including generation-related regulatory assets. TCC included regulatory assets not approved for securitization in its request for recovery of $1.1 billion of stranded costs. In a 1997 TCC PUCT rate proceeding, $800 million of nuclear unit costs included in property, plant and equipment-electric and regulatory assets on the consolidated balance sheets was determined to be excess cost over market (ECOM). The PUCT provided for a lower return on ECOM assets and ECOM assets are being amortized on an accelerated basis for rate-making purposes. After hearings on the issue of stranded costs in a proceeding to establish restructured rates for TCC, the PUCT ruled in October 2001 that its current estimate of our stranded costs was negative $615 million. We have appealed the PUCT's ruling. The final amount of stranded costs will be established by the PUCT in the 2004 true-up proceeding. For the purpose of determining stranded costs, we intend to sell the generation assets of TCC. In order to use the sale of assets valuation method, that subsidiary must sell all of its generating assets including its interest in the STP nuclear generating facility. If we do not sell the generation assets, we intend to pursue the use of a combination of other market valuation methods. We have requested that the 2004 true-up proceeding be scheduled after the divestiture of the generation assets is completed, currently anticipated to be mid-year 2004. The amount of stranded costs under this methodology will be the amount by which the net book value of TCC's generating assets including regulatory assets and liabilities that were not securitized exceed the market value of the generation assets as measured by the net proceeds from the sale of assets. If our total stranded costs determined in the 2004 true-up proceeding are less than the amount of securitized regulatory assets, the PUCT can implement an offsetting credit to transmission and distribution rates charged for transmission and distribution service. The Texas Third Court of Appeals ruled in February 2003 that any negative stranded costs in excess of securitized regulatory assets cannot be refunded to customers under Senate Bill 7, the Texas electricity restructuring legislation. In addition, the Court ruled that negative stranded costs cannot be offset against other true-up adjustments including final under-recovered fuel amounts. An offsetting credit, if imposed, would limit our recovery of regulatory assets and may harm our results of operations and financial condition. Management believes that TCC will have stranded costs in 2004, and that the current treatment of excess earnings will be amended at that time. In addition to our appeal of the PUCT's estimate of stranded costs and refund of excess earnings, unaffiliated parties also appealed the PUCT's refund order contending the entire $615 million of negative stranded costs should be refunded presently. Management is unable to predict the outcome of this litigation. An unfavorable ruling would harm our results of operations, cash flows and possibly financial condition. THE NRC AND/OR THE SEC MAY NOT APPROVE THE CORPORATE SEPARATION PLANS WE HAVE SUBMITTED TO COMPLY WITH RESTRUCTURING LEGISLATION IN TEXAS. We have filed requests with the FERC, PUCT and SEC to legally separate and transfer the generation assets of our Texas utility subsidiaries to new subsidiaries formed to hold such assets. The PUCT and the FERC have approved such plans (and, at the FERC, other action unrelated to compliance with Texas restructuring legislation). We intend to sell the generation assets of TCC in order to accurately determine its stranded costs in accordance with Texas restructuring legislation and PUCT regulations. In order to use the S-14 sale of assets valuation method, that subsidiary must sell all of its generating assets including its interest in STP. If we do not sell the generation assets, we intend to pursue the use of a combination of other market valuation methods. Divestiture of our interest in the STP to a nonaffiliate will require NRC approval. The transfer of generation assets from our Texas subsidiaries, whether to affiliated or unaffiliated entities, will require approval by the SEC. We can give no assurance, however, that the NRC and/or the SEC will approve the action necessary to complete the corporate separations. Failure to approve may limit our ability to efficiently operate our business. In addition, while not a condition to implementation of legal separation, we are seeking to exempt our deregulated generation assets in Texas from regulation as utilities under PUHCA. To obtain this exemption, each of the eleven state utility commissions in which we operate must make certain findings regarding the impact of the exemption in their respective states. The SEC and the FERC must also act before the exemption is granted. We believe we will obtain all necessary approvals for the exemption; we can give no assurance, however, that the states, the FERC, the SEC and/or the relevant state utility commissions will approve the action necessary. Failure to do so may limit our ability to maximize the return on our deregulated generation assets. COLLECTION OF OUR REVENUES IN TEXAS IS CONCENTRATED IN A LIMITED NUMBER OF RETAIL ELECTRIC PROVIDERS (REPS). Our revenues from the distribution of electricity in Texas are collected from REPs that supply the electricity we distribute to their customers. Currently, we do business with approximately thirty REPs. Adverse economic conditions, structural problems in the new Texas market or financial difficulties of one or more REPs could impair the ability of these REPs to pay for our services or could cause them to delay such payments. We depend on these REPs for timely remittance of payments. Any delay or default in payment could adversely affect the timing and receipt of our cash flows thereby have an adverse effect on our liquidity. We anticipate that more than half of our revenues from REPs will come from our formerly affiliated REPs that were sold to an affiliate of Centrica plc in December 2002. WE MAY NOT BE ABLE TO RESPOND EFFECTIVELY TO COMPETITION. We may not be able to respond in a timely or effective manner to the many changes in the power industry that may occur as a result of regulatory initiatives to increase competition. These regulatory initiatives may include deregulation of the electric utility industry in some markets and privatization of the electric utility industry in others. To the extent that competition increases, our profit margins may be negatively affected. Industry deregulation and privatization may not only continue to facilitate the current trend toward consolidation in the utility industry but may also encourage the disaggregation of other vertically integrated utilities into separate generation, transmission and distribution businesses. As a result, additional competitors in our industry may be created, and we may not be able to maintain our revenues and earnings levels or pursue our growth strategy. While demand for power is generally increasing throughout the United States, the rate of construction and development of new, more efficient electric generation facilities may exceed increases in demand in some regional electric markets. The start-up of new facilities in the regional markets in which we have facilities could increase competition in the wholesale power market in those regions, which could harm our business, results of operations and financial condition. Also, industry restructuring in regions in which we have substantial operations could affect our operations in a manner that is difficult to predict, since the effects will depend on the form and timing of the restructuring. S-15 GENERAL RISKS OF OUR REGULATED OPERATIONS WE ARE EXPOSED TO NUCLEAR GENERATION RISK. Through our affiliates, Indiana Michigan Power Company and TCC, we have interests in four nuclear generating units, which interests equal 2,740 MW, or 7% of our generation capacity. We are, therefore, also subject to the risks of nuclear generation, which include the following: - the potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials; - limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations or those of others in the United States; - uncertainties with respect to contingencies and assessment amounts if insurance coverage is inadequate; and - uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives. The Nuclear Regulatory Commission (NRC) has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants such as ours. In addition, although we have no reason to anticipate a serious nuclear incident at our plants, if an incident did occur, it could harm our results of operations or financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit. THE DIFFERENT REGIONAL POWER MARKETS IN WHICH WE COMPETE OR WILL COMPETE IN THE FUTURE HAVE CHANGING TRANSMISSION REGULATORY STRUCTURES, WHICH COULD AFFECT OUR PERFORMANCE IN THESE REGIONS. Our results are likely to be affected by differences in the market and transmission regulatory structures in various regional power markets. Problems or delays that may arise in the formation and operation of new regional transmission organizations, or "RTOs", may restrict our ability to sell power produced by our generating capacity to certain markets if there is insufficient transmission capacity otherwise available. The rules governing the various regional power markets may also change from time to time which could affect our costs or revenues. Because it remains unclear which companies will be participating in the various regional power markets, or how RTOs will develop or what regions they will cover, we are unable to assess fully the impact that these power markets may have on our business. In May 2002, we announced an agreement with the Pennsylvania-New Jersey-Maryland RTO (the PJM) Interconnection to pursue terms for participation in its RTO. Final agreements are expected to be negotiated. In July 2002, the FERC tentatively approved the decision of our subsidiaries located in the east to join PJM subject to certain conditions being met. The performance of these conditions is only partially under our control. In October 2002, PJM announced that our east subsidiaries and other unaffiliated utilities planned to turn functional control of their transmission lines over to PJM during the first quarter of 2003 and are scheduled to become full members by May 2003. Virginia has adopted legislation that prevents us and certain other unaffiliated utilities operating in Virginia from joining any RTO, including PJM, before July 2004. Management is unable to predict the ultimate effect of this Virginia legislation. Two of our western subsidiaries are members of the Southwest Power Pool (the "SPP"). The SPP had agreed to merge with the Midwest Independent Transmission System Operator (MISO), an independent operator of transmission assets in the Midwest. MISO and SPP recently announced that they were no longer pursuing their merger. Our two subsidiaries provided notice that they would withdraw from the SPP after October 31, 2002. This action was taken to provide our subsidiaries additional flexibility in deciding which RTO they will ultimately join. S-16 Management is unable to predict the outcome of these transmission regulatory actions and proceedings or their impact on the timing and operation of RTOs, our transmission operations or future results of operations and cash flows. WE ARE SUBJECT TO REGULATION UNDER THE PUBLIC UTILITY HOLDING COMPANY ACT OF 1935. Our system is subject to the jurisdiction of the SEC under PUHCA. The rules and regulations under PUHCA impose a number of restrictions on the operations of registered holding company systems. These restrictions include a requirement that the SEC approve in advance securities issuances, sales and acquisitions of utility assets, sales and acquisitions of securities of utility companies and acquisitions of other businesses. PUHCA also generally limits the operations of a registered holding company to a single integrated public utility system, plus additional energy-related businesses. PUHCA rules limit the dividends that our subsidiaries may pay from unearned surplus. OUR MERGER WITH CSW MAY ULTIMATELY BE FOUND TO VIOLATE PUHCA. We acquired CSW in a merger completed on June 15, 2000. Among the more significant assets we acquired as a result of the merger were four additional domestic electric utility companies -- PSO, SWEPCo, TCC (formerly, CPL) and TNC (formerly, WTU). On January 18, 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC's June 14, 2000 order approving the merger failed to properly find that the merger meets the requirements of PUHCA and sent the case back to the SEC for further review. Specifically, the court told the SEC to revisit its conclusion that the merger met PUHCA's requirement that the electric utilities be "physically interconnected" and confined to a "single area or region." We believe that the merger meets the requirements of PUHCA and expect the matter to be resolved favorably. We intend to fully cooperate with the staff of the SEC in supplementing the record, if necessary, to ensure the merger complies with PUHCA. We can give no assurance, however, that: (i) the SEC or any applicable court review will find that the merger complies with PUHCA, or (ii) the SEC or any applicable court review will not impose material adverse conditions on us in order to find that the merger complies with PUHCA. If the merger were ultimately found to violate PUHCA, it may require us to take remedial actions or divest assets which may harm our results of operations or financial condition. RISKS RELATED TO MARKET, ECONOMIC OR INTERNATIONAL FINANCIAL VOLATILITY WE ARE SUBJECT TO RISKS ASSOCIATED WITH A CHANGING ECONOMIC ENVIRONMENT. In response to the occurrence of several recent events, including the September 11, 2001 terrorist attack on the United States, the ongoing war against terrorism by the United States, and the bankruptcy of Enron Corp., the financial markets have been disrupted in general, and the availability and cost of capital for our business and that of our competitors has been at least temporarily harmed. In addition, following the bankruptcy of Enron Corp., the credit ratings agencies initiated a thorough review of the capital structure and earnings power of energy companies, including us. These events could constrain the capital available to our industry and could limit our access to funding for our operations. Our business is capital intensive, and achievement of our growth targets is dependent, at least in part, upon our ability to access capital at rates and on terms we determine to be attractive. If our ability to access capital becomes significantly constrained, our interest costs will likely increase and our financial condition could be harmed and future results of operations could be significantly harmed. The insurance industry has also been disrupted by these events. As a result, the availability of insurance covering risks we and our competitors typically insure against has decreased. In addition, the insurance we are able to obtain has higher deductibles and higher premiums. S-17 DOWNGRADES IN OUR CREDIT RATINGS COULD NEGATIVELY AFFECT OUR ABILITY TO ACCESS CAPITAL AND/OR TO CONDUCT OUR POWER AND GAS TRADING ACTIVITIES. On February 10, 2003, Moody's downgraded our senior unsecured long-term debt rating to Baa3 (with stable outlook) from Baa2 and our short-term debt rating to P-3 (with stable outlook) from P-2. On March 7, 2003, Standard & Poor's Ratings Service downgraded their rating on our senior unsecured debt to BBB (with stable outlook) from BBB+ (CreditWatch with negative implications) and confirmed their rating on our commercial paper of A-2 (with stable outlook). On March 10, 2003, Fitch Ratings, Inc. downgraded their rating on our senior unsecured debt to BBB (with stable outlook) from BBB+ and confirmed their rating on our commercial paper of F2 (with stable outlook). As a result, our access to the commercial paper market may be limited and our short-term borrowing costs may increase. To strengthen our financial condition, we have announced plans to, among other things, (1) cut operating and capital expenses, and (2) dispose of non-core assets. If the reduction of operating and capital expenses is too severe it may adversely impact the profitable operation of assets, including generating plants, which could adversely impact our results of operations or financial condition. Further, our plans to dispose of non-core assets may not succeed. If we sell such non-core assets below their book value, we would sustain additional impairments. If we retain such assets due to unfavorable market conditions for their sale, we are exposed to the risk of sustaining additional operating losses. There can be no assurance that we will successfully dispose of our non-core assets as planned. Our power trading activity relies on the investment grade ratings of the senior unsecured debt of our utility subsidiaries. Our gas trading activity relies on the investment grade ratings of our senior unsecured debt. While Moody's recently downgraded several of those ratings, our senior unsecured debt ratings and those of our utility subsidiaries continue to be investment grade. Most of our counterparties require the creditworthiness of an investment grade entity to stand behind transactions. If our ratings or those of our utility subsidiaries were to decline below investment grade, we would likely have to deposit cash or cash related instruments, which would reduce our results of operations and impact our financial condition. OUR OPERATING RESULTS MAY FLUCTUATE ON A SEASONAL AND QUARTERLY BASIS. Electric power generation is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. As a result, our overall operating results in the future may fluctuate substantially on a seasonal basis. The pattern of this fluctuation may change depending on the nature and location of facilities we acquire and the terms of power sale contracts we enter into. In addition, we have historically sold less power, and consequently earned less income, when weather conditions are milder. We expect that unusually mild weather in the future could diminish our results of operations and harm our financial condition. CHANGES IN TECHNOLOGY MAY SIGNIFICANTLY AFFECT OUR BUSINESS BY MAKING OUR POWER PLANTS LESS COMPETITIVE. A key element of our business model is that generating power at central power plants achieves economies of scale and produces power at relatively low cost. There are other technologies that produce power, most notably fuel cells, microturbines, windmills and photovoltaic (solar) cells. It is possible that advances in technology will reduce the cost of alternative methods of producing power to a level that is competitive with that of most central power station electric production. If this were to happen and if these technologies achieved economies of scale, our market share could be eroded, and the value of our power plants could be reduced. Changes in technology could also alter the channels through which retail electric customers buy power, thereby harming our financial results. RISKS OF DOING BUSINESS OUTSIDE THE UNITED STATES We currently own and may acquire and/or dispose of material energy-related investments and projects outside the United States. The economic and political conditions in certain countries where we have interests S-18 or in which we may explore development, acquisition or investment opportunities present risks of delays in construction and interruption of business, as well as risks of war, expropriation, nationalization, renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, that are greater than in the United States. The uncertainty of the legal environment in certain foreign countries in which we develop or acquire projects or make investments could make it more difficult to obtain non-recourse project or other financing on suitable terms, could adversely affect the ability of certain customers to honor their obligations with respect to such projects or investments and could impair our ability to enforce our rights under agreements relating to such projects or investments. Operations in foreign countries also can present currency exchange rate and convertibility, inflation and repatriation risk. In certain countries in which we develop or acquire projects, or make investments, economic and monetary conditions and other factors could affect our ability to convert our earnings denominated in foreign currencies to United States dollars or other hard currencies or to move funds offshore from such countries. Furthermore, the central bank of any such country may have the authority in certain circumstances to suspend, restrict or otherwise impose conditions on foreign exchange transactions or to approve distributions to foreign investors. Although we intend to structure our power purchase agreements, joint venture agreements and other project revenue agreements to provide for payments or contributions to be made in, or indexed to, United States dollars or a currency freely convertible into United States dollars, there can be no assurance that we will be able to achieve this structure in all cases or that a power purchaser or other customer will be able to obtain sufficient United States dollars or other hard currency or that available United States dollars will be allocated to pay such obligations or make such contributions. CHANGES IN COMMODITY PRICES MAY INCREASE OUR COST OF PRODUCING POWER OR DECREASE THE AMOUNT WE RECEIVE FROM SELLING POWER, HARMING OUR FINANCIAL PERFORMANCE. We are heavily exposed to changes in the price and availability of coal because most of our generating capacity is coal-fired. We have contracts of varying durations for the supply of coal for most of our existing generation capacity, but as these contracts end, we may not be able to purchase coal on terms as favorable as the current contracts. We also own natural gas-fired facilities, which increases our exposure to the more volatile market prices of natural gas. Changes in the cost of coal or natural gas and changes in the relationship between those costs and the market prices of power will affect our financial results. Since the price we obtain for electricity may not change at the same rate as the change in coal or natural gas costs, we may be unable to pass on the changes in costs to our customers. In addition, the price we can charge our retail customers in some jurisdictions are capped and our fuel recovery mechanisms in other states are frozen for various periods of time. In addition, actual power prices and fuel costs will differ from those assumed in financial projections used to initially value our trading and marketing transactions, and those differences may be material. As a result, our financial results may be diminished in the future as those transactions are marked to market. AT TIMES, DEMAND FOR POWER COULD EXCEED OUR SUPPLY CAPACITY. We are currently obligated to supply power in parts of eleven states. From time to time the demand for power required to meet these obligations could exceed our available generation capacity. If this occurs, we would have to buy power on the market. We may not always have the ability to pass these costs on to our customers because some of the states we operate in do not allow us to increase our rates in response to increased fuel cost charges. Since these situations most often occur during periods of peak demand, it is possible that the market price for power at that time would be very high. Unlike the cooler weather over the summer of 2000, the hotter-than-normal summer of 1999 saw market prices for power in regions in which certain of our regulated utility subsidiaries have supply obligations peak in excess of $5,000 per megawatt hour. Utilities that did not own or purchase sufficient available capacity during those periods incurred significant losses in sourcing incremental power. Even if a supply shortage was brief, we could suffer substantial losses that could diminish our results of operations. S-19 RISKS RELATED TO ENVIRONMENTAL REGULATION OUR COSTS OF COMPLIANCE WITH ENVIRONMENTAL LAWS ARE SIGNIFICANT, AND THE COST OF COMPLIANCE WITH FUTURE ENVIRONMENTAL LAWS COULD HARM OUR CASH FLOW AND PROFITABILITY. Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and health and safety. Compliance with these legal requirements requires us to commit significant capital toward environmental monitoring, installation of pollution control equipment, emission fees and permits at all of our facilities. These expenditures have been significant in the past and we expect that they will increase in the future. Costs of compliance with environmental regulations could harm our industry, our business and our results of operations and financial position, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets we operate increase. WE ANTICIPATE THAT WE WILL INCUR CONSIDERABLE CAPITAL COSTS FOR COMPLIANCE. Most of our generating capacity is coal burning. We plan to install new emissions control equipment and may be required to upgrade existing equipment, purchase emissions allowances or reduce operations. We expect to spend approximately $1.3 to 2 billion in connection with the installation of emission control equipment at our facilities to comply with the new NOx rule (of which approximately $843 million had been expended through December 31, 2002), the Section 126 Rule and certain environmental requirements of Texas. Moreover, environmental laws are subject to change, which may materially increase our costs of compliance or accelerate the timing of these capital expenditures. Our compliance strategy, although reasonably based on the information available to us today, may not successfully address the relevant standards and interpretations of the future. GOVERNMENTAL AUTHORITIES MAY ASSESS PENALTIES ON US FOR FAILURES TO COMPLY WITH ENVIRONMENTAL LAWS AND REGULATIONS. If we fail to comply with environmental laws and regulations, even if caused by factors beyond our control, that failure may result in the assessment of civil or criminal penalties and fines against us. Recent lawsuits by the EPA and various states filed against us highlight the environmental risks faced by generating facilities, in general, and coal-fired generating facilities, in particular. Since 1999, we have been involved in litigation regarding generating plant emissions under the Clean Air Act. Federal EPA and a number of states alleged that we and eleven unaffiliated utilities modified certain units at coal-fired generating plants in violation of the Clean Air Act. Federal EPA filed complaints against certain AEP subsidiaries in U.S. District Court for the Southern District of Ohio. A separate lawsuit initiated by certain special interest groups was consolidated with the Federal EPA case. The alleged modification of the generating units occurred over a 20 year period. If these actions are resolved against us, substantial modifications of our existing coal-fired power plants would be required. In addition, we could be required to invest significantly in additional emission control equipment, accelerate the timing of capital expenditures, pay penalties and/or halt operations. Moreover, our results of operations and financial position could be reduced due to the consequent distraction of management and the expense of ongoing litigation. Other parties have settled similar lawsuits. An unaffiliated utility which operates certain plants jointly owned by CSPCo reached a tentative agreement to settle litigation regarding generating plant emissions under the Clean Air Act. Negotiations are continuing and a settlement could impact the operation of certain of the jointly owned plants. Until a final settlement is reached, CSPCo will be unable to determine the settlement's impact on its jointly owned facilities and its future results of operations and cash flows. S-20 WE ARE UNLIKELY TO BE ABLE TO PASS ON THE COST OF ENVIRONMENTAL COMPLIANCE TO OUR CUSTOMERS. Most of our contracts with wholesale customers do not permit us to recover additional capital and other costs incurred by us to comply with new environmental regulations. Due to the deregulation of generation in Texas, Ohio and Virginia, we cannot recover through rates additional capital and other costs incurred by us to comply with new environmental regulations with respect to our generation previously regulated in those jurisdictions. As a result of rate freezes in effect in Michigan and Indiana (expiring January 1, 2005) we generally cannot recover through rates additional capital and other costs incurred by us to comply with new environmental regulations with respect to our generation subject to those jurisdictions. USE OF PROCEEDS We estimate that we will receive net proceeds from the sale of our Senior Notes in this offering of $ , after deducting expenses and offering discounts. Credit Suisse First Boston LLC and UBS Warburg LLC purchased $250,000,000 aggregate principal amount of AEP's outstanding 5.50% Putable Callable Notes, Series B (the "Outstanding Notes") on May 15, 2003. We have agreed to accept the Outstanding Notes as partial consideration for the Senior Notes and to receive cash for the remaining purchase price of the Senior Notes. Following this offering, we will retire the Outstanding Notes and we expect to use the remaining proceeds to pay down short-term debt. S-21 CAPITALIZATION The following table sets forth our capitalization as of March 31, 2003: - on an actual basis; and - on an as adjusted basis to give effect to the sale of our Senior Notes, after deducting the underwriting discounts and estimated offering expenses, and the expected use of proceeds described herein. Since March 31, 2003, there has not been any material change in the information set forth below, except as may be described elsewhere in this prospectus supplement, in the accompanying prospectus or in any of the documents incorporated by reference therein. The allocation of net proceeds between short-term debt and long-term debt under "As Adjusted" is an estimate and may differ from the actual use of proceeds. You should read the information in this table along with the financial information included or incorporated by reference in this prospectus supplement and the accompanying prospectus.

MARCH 31, 2003 --------------------- ACTUAL AS ADJUSTED ------- ----------- (IN MILLIONS) (UNAUDITED) Debt: Short-term debt, including commercial paper............... $ 239 $ Long-term debt, including current maturities.............. 12,132 Equity Unit Senior Notes.................................. 376 ------- Total debt............................................. 12,747 ------- Certain subsidiary obligated, mandatorily redeemable, preferred securities of subsidiary trusts holding solely junior subordinated debentures of such subsidiaries........................................... 321 ------- Minority interest in finance subsidiary................... 759 ------- Cumulative preferred stock of subsidiaries.................. 144 ------- Common shareholders' equity: Common stock, par value $6.50; 600 million shares authorized, 403,993,412 shares issued at 3/31/03 (8,999,992 shares were held in treasury at 3/31/03).... 2,626 Paid-in capital........................................... 4,175 Accumulated other comprehensive income (loss)............. (602) Retained earnings......................................... 2,238 ------- Total common shareholders' equity...................... 8,437 ------- Total capitalization................................. $22,408 -------

S-22 AMERICAN ELECTRIC POWER COMPANY, INC. The following discussion highlights certain important facts regarding us and our subsidiaries and does not contain all of the information that may be important to you. We encourage you to read the documents referred to in the accompanying prospectus under "Where You Can Find More Information," which contain more complete descriptions of us and our business. American Electric Power Company, Inc. (AEP) is one of the largest investor-owned public utility companies in the United States. We provide, directly or indirectly, generation, transmission and distribution services to almost five million customers in eleven states (Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia) through our utility operations. Our portfolio of assets includes: - 38,000 megawatts of generating capacity, the largest complement of generation in the United States; - 38,000 miles of transmission lines; - 186,000 miles of distribution lines that support delivery of electricity to our customers' premises; - Substantial coal transportation assets (7,000 railcars, 1,800 barges, 37 tug boats and two coal handling terminals with 20 million tons of annual capacity); - 6,400 miles of gas pipelines in Louisiana and Texas with 128 billion cubic feet of gas storage facilities; and - 4,000 megawatts of generating capacity in the U.K. and other minor international investments. BUSINESS STRATEGY Our business is focused on utility operations in the United States, which tend to offer more stable and relatively predictable earnings and cash flow. We are continuing to reduce trading in markets where we do not have assets and will focus instead on ensuring maximum value for our assets by selling output in excess of our utility needs. This asset optimization approach has long been part of our strategy as an active seller of excess power in the Midwest. We remain focused on credit quality and liquidity. Our strategy for the core business of utility operations is to: - Maintain moderate but steady earnings growth; - Maximize the value of transmission assets and protect revenue stream through RTO membership; - Continue process improvement to maintain distribution service quality while enhancing financial performance; - Optimize generation assets through enhanced availability and sale of excess capacity; and - Manage the regulatory process to maximize retention of earnings and operational improvement. UTILITY OPERATIONS Our electric utility subsidiaries, which do business as "American Electric Power," have traditionally provided electric service, consisting of generation, transmission and distribution, on an integrated basis to their retail customers. For discussion on the status of deregulation, see "Restructuring" below. These operating subsidiaries are:

APPROXIMATE MW OPERATING SUBSIDIARY SERVICE TERRITORY CUSTOMERS OWNED/LEASED -------------------- ----------------- ----------- ------------ AEP Generating Company............... N/A(1) N/A(1) 1,300 AEP Texas Central Company (TCC)(2)... Southern Texas 690,000(3) 4,497(4) AEP Texas North Company (TNC)(5)..... West and Central Texas 189,000(3) 1,392(6)

S-23

APPROXIMATE MW OPERATING SUBSIDIARY SERVICE TERRITORY CUSTOMERS OWNED/LEASED -------------------- ----------------- ----------- ------------ Appalachian Power Company (APCo)..... Southwestern Virginia and Southern 925,000 5,850 West Virginia Columbus Southern Power Company...... Ohio 689,000 2,595 Indiana Michigan Power Company (I&M).............................. Northern and Eastern Indiana and 571,000 4,416 Southwestern Michigan Kentucky Power Company............... Eastern Kentucky 174,000 1,060 Kingsport Power Company.............. Kingsport, TN and a portion of 46,000 None(7) Northeastern Tennessee Ohio Power Company (OPCo)............ Northwestern, East Central, 702,000 8,520 Eastern and Southern Sections of Ohio Public Service Company of Oklahoma... Eastern and Southwestern Oklahoma 505,000 4,228 Southwestern Electric Power Company............................ Northeastern Texas, Northwestern 437,000 4,487 Louisiana and Western Arkansas Wheeling Power Company............... Northern West Virginia 41,000 None(8)

--------------- (1) AEP Generating Company sells power to Indiana Michigan Power Company and Kentucky Power Company. (2) Formerly Central Power and Light Company. (3) Via approximately two dozen unaffiliated retail electricity providers. (4) TCC has applied to the Public Utility Commission of Texas (PUCT) to sell these assets. Includes 1,721 MW TCC has deactivated. (5) Formerly West Texas Utilities Company. (6) Includes 390 MW TNC has deactivated. (7) Purchases its electric power requirements from APCo. (8) Purchases its electric power requirements from OPCo. REGULATION Our public utility subsidiaries' retail rates and certain other matters are subject to traditional regulation by state utility commissions in Arkansas, Indiana, Kentucky, Louisiana, Oklahoma, Tennessee and West Virginia. In these states the rates of our public utility subsidiaries are generally based on the cost of providing traditional bundled electric service (i.e., generation, transmission and distribution service). The states of Ohio, Texas and Virginia are transitioning from bundled cost-of-service based rates for electric service to unbundled cost-of-service based rates for transmission and distribution service and market pricing for and/or customer choice of generation. Retail sales in Michigan, while still regulated, are now provided at unbundled rates. The traditional regulatory framework reflects specified fuel costs as part of bundled or unbundled rates or incorporates fuel adjustment clauses in a utility's rates and tariffs. Fuel adjustment clauses permit periodic adjustments to fuel cost recovery from customers and therefore provide protection against exposure to fuel cost changes. However, recovery of increased fuel costs (i) is no longer provided for in Ohio and (ii) may be limited in the states of West Virginia and Michigan, which have capped or suspended clauses. There will be a true-up proceeding in 2004 in Texas to quantify and reconcile unreconciled fuel costs as well as the amount of stranded costs for TCC, the capacity auction true-up, the price-to-beat clawback component and other regulatory assets associated with the generating assets located in the ERCOT area of Texas that were not previously securitized. The findings from the true-up proceeding will have the practical result of increasing or decreasing the transmission and distribution rates that we charge in the ERCOT area of Texas. S-24 A summary of the rate regulation of each of our major utility subsidiaries is contained in the table below:

PROPOSED UTILITY STATES RATES AND FUEL CLAUSES RTO ------- ------ ---------------------- -------- AEP Texas Central................. TX Transmission and distribution rates not ERCOT capped or frozen; true-up proceeding in 2004 AEP Texas North................... TX Transmission and distribution rates not ERCOT capped or frozen; true-up proceeding in 2004 Appalachian Power................. VA Rates capped until as late as July 1, 2007; PJM active fuel clause WV Rates and fuel fixed indefinitely pursuant to stipulation Columbus Southern Power........... OH Rates frozen through 2005 with no fuel PJM adjustment; distribution rates frozen through 2008 Indiana Michigan Power............ IN Rates capped until January 1, 2005 and fuel PJM capped until March 1, 2004 MI Rates capped until January 1, 2005 and fuel capped until January 1, 2004 Kentucky Power.................... KY Rates frozen until June 15, 2003; active PJM fuel clause Ohio Power........................ OH Rates frozen through 2005 with no fuel PJM adjustment; distribution rates frozen through 2007 Public Service of Oklahoma........ OK Rates capped until January 1, 2003 (under SPP review); active fuel clause Southwestern Electric Power....... AR Rates capped until June 15, 2003; active SPP fuel clause LA Rates capped until June 15, 2005 (under review); active fuel clause TX Rates frozen until June 15, 2003; active fuel clause

Our subsidiaries are also subject to regulation by the FERC under the Federal Power Act. I&M and TCC are subject to regulation by the Nuclear Regulatory Commission under the Atomic Energy Act of 1954, as amended, with respect to the operation of the Cook Plant and the South Texas Project (STP), respectively. We are subject to the broad regulatory provisions of the Public Utility Holding Company Act of 1935, as amended, administered by the SEC. UTILITY OPERATIONS AND OTHER INVESTMENTS Our public utility subsidiaries currently own approximately 38,000 MW of domestic generation. A substantial portion of the electric power generated at our generating stations is sold, at bundled or unbundled generation, transmission and distribution rates, to retail customers of our utility subsidiaries in their service territories. The remaining portion is sold on a wholesale basis to non-affiliated electric utilities, municipalities, electric cooperatives, other wholesale customers and power marketers. Our public utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power. Most of the transmission and distribution services are sold, in combination with electric power, to retail customers of our public utility subsidiaries in their service territories. These sales are made at rates established by the state utility commissions of the states in which these subsidiaries operate. In addition, for the three months ended March 31, 2003, there were approximately $111 million in third-party transmission revenues. The FERC regulates and approves the rates for wholesale transmission transactions. In October 2002, we announced plans to reduce our exposure to energy trading markets and to downsize our trading and wholesale marketing operations. We are continuing to reduce trading in markets where we do S-25 not have assets and have focused instead on ensuring maximum value for our assets by selling excess output. Going forward, we plan for our energy trading and marketing operations to be limited to risk management around our assets and focused in regions where we own assets. Our wholesale electric power transactions in the United States are conducted principally through our public utility subsidiaries. Other wholesale transactions are conducted principally through AEP Energy Services, Inc. and AEP Resources, Inc. These operations use and manage the following assets: - Natural gas pipeline, storage and processing facilities; - Coal mines and related facilities; and - Barge, rail and other fuel transportation related assets. These utility and non-utility operations consist of the following: - Through our public utility subsidiaries, the generation and sale of power at wholesale regulated in certain instances by FERC; - Trading and marketing energy commodities in transactions limited to risk management around assets used or managed by our wholesale operations, including electric power, natural gas, natural gas liquids, oil, coal, and SO(2) allowances in North America and, where applicable, Europe; and - Entering into long-term transactions to buy or sell capacity, energy, and ancillary services of electric generating facilities, either existing or to be constructed, at various locations in North America and Europe. In September 2002, we indicated to ERCOT our intent to deactivate 16 gas-fired power plants (eight TCC plants and eight TNC plants). ERCOT subsequently conducted reliability studies that determined that seven plants (four TCC plants and three TNC plants) would be required to ensure reliability of the electricity grid. As a result of these studies, ERCOT and AEP entered into "reliability must run" (RMR) agreements to continue operation of these seven plants. The RMR agreements expired in December 2002 but have been renewed for all but two units of these plants. With ERCOT's approval, we are proceeding with our planned deactivation of the remaining nine plants. TCC intends to sell all of its power generation assets in an effort to determine its level of stranded costs in accordance with the Texas restructuring law and PUCT regulations. The assets we intend to sell have a generating capacity of 4,497 MW and include eight gas-fired plants, one coal-fired plant, TCC's interest in another coal-fired plant, a hydroelectric facility and TCC's interest in STP. RESTRUCTURING Our public utility subsidiaries, like many other electric utilities, have traditionally provided electric generation and energy delivery, consisting of transmission and distribution services, as a single product to their retail customers. Legislation has been enacted in Michigan, Ohio, Texas and Virginia that allows for customer choice of generation supplier. These measures generally allow competition in the generation and sale of electric power, but not in its transmission and distribution. Although customer choice legislation has been enacted in Arkansas, Oklahoma and West Virginia, such legislation has been repealed in Arkansas, delayed indefinitely in Oklahoma and has not been implemented in West Virginia. Each of our Ohio utility subsidiaries currently operates as a functionally separated electric utility company and no longer charges bundled rates for its retail sales of electricity. Distribution rates for our Ohio utility subsidiaries are approved by The Public Utilities Commission of Ohio and transmission rates are approved by the FERC. We have sought regulatory approval to legally separate the transmission and distribution assets of our Ohio utility subsidiaries from their generation assets pursuant to Ohio restructuring legislation. However, we are presently determining the regulatory feasibility of complying with Ohio restructuring legislation through continued functional separation. Assuming regulatory compliance, it is currently our intention that our Ohio utility subsidiaries remain functionally separated. Similarly, each of our Texas utility subsidiaries in ERCOT also currently operates as a functionally separated electric utility S-26 company with distribution and, for the most part, transmission rates that continue to be set by the PUCT and with generation rates that are not set by the PUCT. We have sought regulatory approval to legally separate the generation assets of our Texas utility subsidiaries from their transmission and distribution assets as required by Texas restructuring legislation. Additionally, TCC intends to sell its generation assets in order to accurately determine TCC's stranded costs in accordance with Texas restructuring legislation and PUCT regulation. Transition rules for Michigan and Virginia do not require legal separation. Due in part to difficulties in deregulating other markets, deregulation appears unlikely for the foreseeable future in the other states in which we operate. INVESTMENTS We have made certain investments in telecommunications, international energy and other concerns. In 2002, we wrote down substantially all of the value of certain of these investments and significant portions of the value of certain other of these investments to reflect deterioration in market conditions. We are evaluating our portfolio of non-regulated assets and plan to sell assets that are no longer core to our business strategy. We also consummated the following transactions related to foreign investments in 2002: - The sale of SEEBOARD GROUP plc, an electricity supply and distribution company in the United Kingdom serving 2,000,000 customers and covering 3,000 square miles of service territory; and - The sale of CitiPower Pty., a retail electricity and gas supply and distribution subsidiary in Australia serving 240,000 customers. S-27 SUPPLEMENTAL DESCRIPTION OF THE SENIOR NOTES The following description of the particular terms of the Senior Notes supplements and in certain instances replaces the description of the general terms and provisions of the Senior Notes under "Description of the Notes" in the accompanying Prospectus. We will issue the Senior Notes under an Indenture, dated as of May 1, 2001, between us and The Bank of New York, as Trustee, as supplemented and amended and as to be further supplemented and amended. The Senior Notes will be our unsecured and unsubordinated obligations ranking equally with our other outstanding unsecured and unsubordinated indebtedness. At March 31, 2003, we had approximately $2.3 billion outstanding unsecured and unsubordinated indebtedness. The Indenture contains no restrictions on the amount of additional indebtedness that we may issue. PRINCIPAL AMOUNT, MATURITY, INTEREST AND PAYMENT The Senior Notes will initially be issued in an aggregate principal amount of $300,000,000. We may, without consent of the holders of the Senior Notes, issue additional notes having the same ranking, interest rate, maturity and other terms as the Senior Notes. The Senior Notes will be a single series of notes under the Indenture. The Senior Notes will mature and become due and payable, together with any accrued and unpaid interest, on , 20 and will bear interest at the rate of % per year from , 2003 until , 20 . The Senior Notes are not subject to any sinking fund provision. Interest on each Senior Note will be payable semi-annually in arrears on each and and at redemption, if any, or maturity. The initial interest payment date is , 2003. Each payment of interest shall include interest accrued through the day before such interest payment date. Interest on the Senior Notes will be computed on the basis of a 360-day year consisting of twelve 30-day months. We will pay interest on the Senior Notes (other than interest payable at redemption, if any, or maturity) in immediately available funds to the owners of the Senior Notes as of the Regular Record Date (as defined below) for each interest payment date. We will pay the principal of the Senior Notes and any premium and interest payable at redemption, if any, or at maturity in immediately available funds at the office of The Bank of New York, 101 Barclay Street in New York, New York. If any interest payment date, redemption date or the maturity is not a Business Day (as defined below), we will pay all amounts due on the next succeeding Business Day and no additional interest will be paid. The "Regular Record Date" will be the close of business on the or prior to the relevant interest payment date, whether or not a Business Day. "Business Day" means any day that is not a day on which banking institutions in New York City are authorized or required by law or regulation to close. OPTIONAL REDEMPTION We may redeem the Senior Notes at our option at any time, upon no more than 60 and not less than 30 days' notice by mail. We may redeem the Senior Notes either as a whole or in part at a redemption price equal to the greater of (1) 100% of the principal amount of the Senior Notes being redeemed and (2) the sum of the present values of the remaining scheduled payments of principal and interest on the Senior Notes being redeemed (excluding the portion of any such interest accrued to the date of redemption) discounted (for purposes of determining present value) to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate (as defined below) plus basis points, plus, in each case, accrued interest thereon to the date of redemption. "Treasury Rate" means, with respect to any redemption date for the Senior Notes, the rate per year equal to the semi-annual equivalent yield to maturity of the Comparable Treasury Issue, assuming a price for the S-28 Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such redemption date. "Comparable Treasury Issue" means the United States Treasury security selected by a Senior Independent Investment Banker as having a maturity comparable to the remaining term of the Senior Notes that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of a comparable maturity to the remaining term of the Senior Notes. "Comparable Treasury Price" means, with respect to any redemption date for the Senior Notes, (1) the average of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) on the third Business Day preceding such redemption date, as set forth in the daily statistical release (or any successor release) published by the Federal Reserve Bank of New York and designated "Composite 3:30 p.m. Quotations for U.S. Government Securities" or (2) if such release (or any successor release) is not published or does not contain such prices on such third Business Day, the Reference Treasury Dealer Quotation for such redemption date. "Independent Investment Banker" means one of the Reference Treasury Dealers appointed by us and reasonably acceptable to the Trustee. "Reference Treasury Dealer" means a primary U.S. Government Securities Dealer selected by us and reasonably acceptable to the Trustee. "Reference Treasury Dealer Quotation" means, with respect to the Reference Treasury Dealer and any redemption date, the average, as determined by the Trustee, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the Trustee by such Reference Treasury Dealer at or before 5:00 p.m., New York City time, on the third Business Day preceding such redemption date. RESTRICTIVE COVENANTS RELATING TO THE SENIOR NOTES LIMITATION UPON LIENS ON STOCK OF CERTAIN SUBSIDIARIES For so long as any Senior Notes remain outstanding, we will not create or incur or allow any of our subsidiaries to create or incur any pledge or security interest on any of the capital stock of a Public Utility Subsidiary held by us or one of our subsidiaries or a Significant Subsidiary. For purposes of this covenant, a Public Utility Subsidiary means, at any particular time, a direct or indirect subsidiary of ours that, as a substantial part of its business, distributes or transmits electric energy to retail or wholesale customers at rates or tariffs that are regulated by either a state or Federal regulatory authority. For purposes of this covenant, Significant Subsidiary means, at any particular time, any direct subsidiary of ours whose consolidated gross assets or consolidated gross revenues (having regard to our direct beneficial interest in the shares, or the like, of that subsidiary) represent at least 25% of our consolidated gross assets or our consolidated gross revenues. LIMITATION UPON MERGERS, CONSOLIDATIONS AND SALE OF ASSETS Nothing in the Indenture or the Senior Notes prevents us from consolidating or merging with or into, or selling or otherwise disposing of all or substantially all of our property to another entity, provided that (1) we agree to obtain a supplemental indenture pursuant to which the surviving entity or transferee agrees to assume our obligations relating to all outstanding debt securities issued under the Indenture and (2) the surviving entity or transferee is organized under the laws of the United States, any state thereof or the District of Columbia. S-29 ADDITIONAL INFORMATION For additional important information about the Senior Notes, including: (i) additional information about the terms of the Senior Notes, (ii) general information about the Indenture and the trustee, and (iii) a description of events of default under the Indenture, see "Description of the Notes" in the accompanying prospectus. S-30 UNDERWRITING Subject to the terms and conditions of an underwriting agreement dated the date hereof between us and Credit Suisse First Boston LLC and UBS Warburg LLC (the "Underwriters"), we have agreed to sell to the Underwriters named below and each of the Underwriters has severally and not jointly agreed to purchase from us the respective principal amount of Senior Notes set forth opposite its name below:

PRINCIPAL AMOUNT UNDERWRITER OF SENIOR NOTES ----------- ---------------- Credit Suisse First Boston LLC.............................. $150,000,000 UBS Warburg LLC............................................. 150,000,000 ------------ $300,000,000 ============

In the underwriting agreement, the Underwriters have agreed, subject to the terms and conditions set forth therein, to purchase all of the Senior Notes offered hereby if any of the Senior Notes are purchased. The expenses associated with the offer and sale of the Senior Notes are expected to be approximately $300,000. The Underwriters propose to offer the Senior Notes to the public at the initial public offering prices set forth on the cover page of this prospectus supplement and to certain dealers at such prices less a concession not in excess of % per Senior Note. The Underwriters may allow, and such dealers may reallow, a discount not in excess of % per Senior Note to certain other dealers. After the initial public offering of the Senior Notes, the public offering price, concession and discount may be changed. Prior to this offering, there has been no public market for the Senior Notes. The Senior Notes will not be listed on any securities exchange. The Underwriters have advised us that they intend to make a market in the Senior Notes. The Underwriters will have no obligation to make a market in the Senior Notes, however, and may cease market making activities, if commenced, at any time. No assurance can be given as to the liquidity of the trading market for the Senior Notes or that an active public market for the Senior Notes will develop. If an active public trading market for the Senior Notes does not develop, the market price and liquidity of the Senior Notes may be adversely affected. We have agreed to indemnify the Underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended. In connection with the offering, the Underwriters may engage in transactions that stabilize, maintain or otherwise affect the price of the Senior Notes. These transactions may include over-allotment and stabilizing transactions and purchases to cover syndicate short positions created in connection with the offering. Stabilizing transactions consist of certain bids or purchases for the purposes of preventing or retarding a decline in the market price of the Senior Notes and syndicate short positions involving the sale by the Underwriters of a greater number of Senior Notes than they are required to purchase from us in the offering. The Underwriters also may impose a penalty bid, whereby selling concessions allowed to syndicate members or other broker dealers in respect of the securities sold in the offering for their account may be reclaimed by the syndicate if such Senior Notes are repurchased by the syndicate in stabilizing or covering transactions. Any of these activities may cause the price of the Senior Notes to be higher than the price that might otherwise prevail in the open market; and these activities, if commenced, may be discontinued at any time. These transactions may be effected in the over-the-counter market or otherwise. We have agreed, during the period of 30 days from the date of the underwriting agreement, not to sell, offer to sell, grant any option for the sale of, or otherwise dispose of any Senior Notes, any security convertible into or exchangeable into or exercisable for Senior Notes or any debt securities substantially similar to the Senior Notes (except for the Senior Notes issued pursuant to the underwriting agreement) without the prior written consent of the Underwriters. The Underwriters and certain of their affiliates have performed investment banking, advisory, general financing and commercial banking services for us and our subsidiaries from time to time for which they have S-31 received customary fees and expenses. The Underwriters may, from time to time in the future, engage in transactions with and perform services for us and our subsidiaries in the ordinary course of their business. The Underwriters may make the Senior Notes available for distribution on the Internet through a proprietary Web site and/or third-party system operated by Market Axess Inc., an Internet-based communications technology provider. Market Axess Inc., a registered broker-dealer, will receive compensation from the Underwriters based on transactions the Underwriters conduct through the system. The Underwriters may make the Senior Notes available to their customers through the Internet distributions, whether made through a proprietary or third-party system, on the same terms as distributions made through other channels. Because 10% or more of the proceeds of this offering, not including underwriter compensation, may be paid to affiliates of certain of the Underwriters who are members of the National Association of Securities Dealers, Inc. (NASD), this offering is being conducted pursuant to NASD Conduct Rule 2710(c)(8). NOTICE TO CANADIAN RESIDENTS RESALE RESTRICTIONS The distribution of the Senior Notes in Canada is being made only on a private placement basis exempt from the requirement that we prepare and file a prospectus with the securities regulatory authorities in each province where trades of Senior Notes are made. Any resale of the Senior Notes in Canada must be made under applicable securities laws, which will vary depending on the relevant jurisdiction, and which may require resales to be made under available statutory exemptions or under a discretionary exemption granted by the applicable Canadian securities regulatory authority. Purchasers are advised to seek legal advice prior to any resale of the Senior Notes. REPRESENTATION OF PURCHASERS By purchasing Senior Notes in Canada and accepting a purchase confirmation a purchaser is representing to us and the dealer from whom the purchase confirmation is received that - the purchaser is entitled under applicable provincial securities laws to purchase the Senior Notes without the benefit of a prospectus qualified under those securities laws, - where required by law, the purchaser is purchasing as principal and not as agent, and - the purchaser has reviewed the text above under Resale Restrictions. RIGHTS OF ACTION -- ONTARIO PURCHASERS ONLY Under Ontario securities legislation, a purchaser who purchases a security offered by this prospectus during the period of distribution will have a statutory right of action for damages, or while still the owner of the Senior Notes, for rescission against us in the event that this prospectus contains a misrepresentation. A purchaser will be deemed to have relied on the misrepresentation. The right of action for damages is exercisable not later than the earlier of 180 days from the date the purchaser first had knowledge of the facts giving rise to the cause of action and three years from the date on which payment is made for the Senior Notes. The right of action for rescission is exercisable not later than 180 days from the date on which payment is made for the Senior Notes. If a purchaser elects to exercise the right of action for rescission, the purchaser will have no right of action for damages against us. In no case will the amount recoverable in any action exceed the price at which the Senior Notes were offered to the purchaser and if the purchaser is shown to have purchased the securities with knowledge of the misrepresentation, we will have no liability. In the case of an action for damages we will not be liable for all or any portion of the damages that are proven not to represent the depreciation in value of the Senior Notes as a result of the misrepresentation relied upon. These rights are in addition to and without derogation from, any other rights or remedies available at law to an Ontario purchaser. The foregoing is a S-32 summary of the rights available to an Ontario purchaser. Ontario purchasers should refer to the complete text of the relevant statutory provisions. ENFORCEMENT OF LEGAL RIGHTS All of our directors and officers as well as the experts named herein may be located outside of Canada and, as a result, it may not be possible for Canadian purchasers to effect service of process within Canada upon us or those persons. All or a substantial portion of our assets and the assets of those persons may be located outside of Canada and, as a result, it may not be possible to satisfy a judgment against us or those persons in Canada or to enforce a judgment obtained in Canadian courts against us or those persons outside of Canada. TAXATION AND ELIGIBILITY FOR INVESTMENT Canadian purchasers of Senior Notes should consult their own legal and tax advisors with respect to the tax consequences of an investment in the Senior Notes in their particular circumstances and about the eligibility of the senior notes for investment by the purchaser under relevant Canadian Legislation. LEGAL MATTERS Certain legal matters with respect to this offering of our Senior Notes will be passed on for us by Thomas G. Berkemeyer, Esq., Associate General Counsel of American Electric Power Service Corporation, one of our affiliates, or William E. Johnson, Esq., Senior Counsel of American Electric Power Service Corporation and Simpson Thacher & Bartlett, New York, New York and for the Underwriters by Dewey Ballantine LLP, New York, New York. From time to time, Dewey Ballantine LLP acts as counsel to our affiliates for some matters. EXPERTS The consolidated financial statements of the Company and subsidiaries incorporated in this prospectus supplement by reference from the Company's Current Report on Form 8-K dated May 14, 2003 have been audited by Deloitte & Touche LLP, independent auditors, as stated in their reports which are incorporated herein by reference (which reports express unqualified opinions and include explanatory paragraphs relating to the adoption of SFAS 142 "Goodwill and Other Intangible Assets", the recording of certain impairments of goodwill, long-lived assets and other investments in the fourth quarter of 2002, and to the realignment of segments for financial reporting purposes). The consolidated financial statement schedules of the Company and subsidiaries incorporated by reference in this prospectus supplement from the Company's Annual Report on Form 10-K/A have been audited by Deloitte & Touche LLP, independent auditors, as stated in their report, which is also incorporated herein by reference. The aforementioned reports have been so incorporated in reliance upon such firm given their authority as experts in accounting and auditing. S-33 PROSPECTUS AMERICAN ELECTRIC POWER COMPANY, INC. 1 RIVERSIDE PLAZA COLUMBUS, OHIO 43215 (614) 223-1000 $1,500,000,000 UNSECURED NOTES TERMS OF SALE The following terms may apply to the notes that we may sell at one or more times. A prospectus supplement or pricing supplement will include the final terms for each note. If we decide to list upon issuance any note or notes on a securities exchange, a prospectus supplement or pricing supplement will identify the exchange and state when we expect trading could begin. - Maturity date or dates - Fixed or floating interest rate - Remarketing features - Certificate or book-entry form - Subject to redemption - Not convertible, amortized or subject to a sinking fund - Interest paid on fixed rate notes quarterly or semi-annually - Interest paid on floating rate notes daily, weekly, monthly, quarterly, semi-annually, or annually - Issued in multiples of a minimum denomination THE NOTES HAVE NOT BEEN APPROVED BY THE SECURITIES AND EXCHANGE COMMISSION ("SEC") OR ANY STATE SECURITIES COMMISSION, NOR HAVE THESE ORGANIZATIONS DETERMINED THAT THIS PROSPECTUS IS ACCURATE OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. The date of this prospectus is April 19, 2001. THE COMPANY We are a public utility holding company that owns, directly or indirectly, all of the outstanding common stock of our domestic electric utility subsidiaries and varying degrees of other subsidiaries. Substantially all of our operating revenues derive from the furnishing of electric service. In addition, in recent years we have been pursuing various unregulated business opportunities in the U.S. and worldwide. We were incorporated under the laws of New York in 1906 and reorganized in 1925. Our principal executive offices are located at 1 Riverside Plaza, Columbus, Ohio 43215, and our telephone number is (614) 223-1000. We own, directly or indirectly, all the outstanding common stock of the following operating public utility companies: Appalachian Power Company, Central Power and Light Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Kingsport Power Company, Ohio Power Company, Public Service Company of Oklahoma, Southwestern Electric Power Company, West Texas Utilities Company and Wheeling Power Company. These operating public utility companies supply electric service in portions of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. We also own all of the outstanding common stock of American Electric Power Service Corporation, which provides accounting, administrative, information systems, engineering, financial, legal, maintenance and other services to us and our subsidiaries. On June 15, 2000, one of our wholly-owned subsidiaries merged with and into Central and South West Corporation, a publicly owned electric utility holding company whose public utility companies supply electric service in portions of Arkansas, Louisiana, Oklahoma and Texas. As a result of the merger, the shareholders of Central and South West Corporation became shareholders of us and we became the sole owner of Central and South West Corporation. WHERE YOU CAN FIND MORE INFORMATION This prospectus is part of a registration statement we filed with the SEC. We also file annual, quarterly and special reports and other information with the SEC. You may read and copy any document we file at the SEC's Public Reference Room at 450 Fifth Street, N. W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference rooms. You may also examine our SEC filings through the SEC's web site at http://www.sec.gov. The SEC allows us to "incorporate by reference" the information we file with them, which means that we can disclose important information to you by referring you to those documents. The information incorporated by reference is considered to be part of this prospectus, and later information that we file with the SEC will automatically update and supersede this information. We incorporate by reference the document listed below and any future filings made with the SEC under Sections 13(a), 13(c), 14, or 15(d) of the Securities Exchange Act of 1934 until we sell all the notes. Annual Report on Form 10-K for the year ended December 31, 2000. You may request a copy of these filings, at no cost, by writing or telephoning us at the following address: Mr. G. C. Dean American Electric Power Service Corporation 1 Riverside Plaza Columbus, Ohio 43215 (614) 223-1000 You should rely only on the information incorporated by reference or provided in this prospectus or any supplement. We have not authorized anyone else to provide you with different information. We are not making an offer of these notes in any state where the offer is not permitted. You should not assume that the information in this prospectus or any supplement is accurate as of any date other than the date on the front of those documents. 1 PROSPECTUS SUPPLEMENTS We will provide information to you about the notes in up to three separate documents that progressively provide more detail: (a) this prospectus provides general information some of which may not apply to your notes, (b) the accompanying prospectus supplement provides more specific terms of your notes, and (c) the pricing supplement, if any, provides the final terms of your notes. It is important for you to consider the information contained in this prospectus, the prospectus supplement, and the pricing supplement, if any, in making your investment decision. RATIO OF EARNINGS TO FIXED CHARGES The Ratio of Earnings to Fixed Charges for each of the periods indicated is as follows:

TWELVE MONTHS PERIOD ENDED RATIO ------------- ----- December 31, 1996........................................... 2.22 December 31, 1997........................................... 2.22 December 31, 1998........................................... 2.25 December 31, 1999........................................... 2.14 December 31, 2000........................................... 1.59

For current information on the Ratio of Earnings to Fixed Charges, please see our most recent Form 10-K and 10-Q. See Where You Can Find More Information. USE OF PROCEEDS The net proceeds from the sale of the notes will be used for general corporate purposes relating to our business. Unless stated otherwise in a prospectus supplement, these purposes include redeeming or repurchasing outstanding debt, replenishing working capital, financing our subsidiaries' ongoing construction and maintenance programs. If we do not use the net proceeds immediately, we temporarily invest them in short-term, interest-bearing obligations. At April 3, 2001, our outstanding short-term debt was $3,691,000,000. DESCRIPTION OF THE NOTES GENERAL We will issue the notes under an Indenture to be entered into by us and the Trustee, The Bank of New York. This prospectus briefly outlines some provisions of the Indenture. If you would like more information on these provisions, you should review the Indenture and any supplemental indentures or company orders that we have filed or will file with the SEC. See Where You Can Find More Information on how to locate these documents. You may also review these documents at the Trustee's offices at 101 Barclay Street, New York, New York. The Indenture does not limit the amount of notes that may be issued. The Indenture permits us to issue notes in one or more series or tranches upon the approval of our board of directors and as described in one or more company orders or supplemental indentures. Each series of notes may differ as to their terms. The Indenture also gives us the ability to reopen a previous issue of a series of notes and issue additional notes of such series. Because we are a holding company, the claims of creditors of our subsidiaries will have a priority over our equity rights and the rights of our creditors (including the holders of the notes) to participate in the assets of the subsidiary upon the subsidiary's liquidation. 2 The notes are unsecured and will rank equally with all our unsecured unsubordinated debt. For current information on our debt outstanding see our most recent Form 10-K and 10-Q. See Where You Can Find More Information. The notes will be denominated in U.S. dollars and we will pay principal and interest in U.S. dollars. Unless an applicable pricing or prospectus supplement states otherwise, the notes will not be subject to any conversion, amortization, or sinking fund. We expect that the notes will be "book-entry," represented by a permanent global note registered in the name of The Depository Trust Company, or its nominee. We reserve the right, however, to issue note certificates registered in the name of the noteholders. In the discussion that follows, whenever we talk about paying principal on the notes, we mean at maturity or redemption. Also, in discussing the time for notices and how the different interest rates are calculated, all times are New York City time and all references to New York mean the City of New York, unless otherwise noted. The Indenture does not protect holders of the notes if we engage in a highly leveraged transaction. The following terms may apply to each note as specified in the applicable pricing or prospectus supplement and the note: REDEMPTIONS If we issue redeemable notes, we may redeem such notes at our option unless an applicable pricing or prospectus supplement states otherwise. The pricing or prospectus supplement will state the terms of redemption. We may redeem notes in whole or in part by delivering written notice to the noteholders no more than 60, and not less than 30, days prior to redemption. If we do not redeem all the notes of a series at one time, the Trustee selects the notes to be redeemed in a manner it determines to be fair. REMARKETED NOTES If we issue notes with remarketing features, an applicable pricing or prospectus supplement will describe the terms for the notes including: interest rate, remarketing provisions, our right to purchase or redeem notes, the holders' right to tender notes, and any other provisions. BOOK-ENTRY NOTES -- REGISTRATION, TRANSFER, AND PAYMENT OF INTEREST AND PRINCIPAL Unless otherwise stated in a prospectus supplement, book-entry notes of a series will be issued in the form of a global note that the Trustee will deposit with The Depository Trust Company, New York, New York ("DTC"). This means that we will not issue note certificates to each holder. One or more global notes will be issued to DTC who will keep a computerized record of its participants (for example, your broker) whose clients have purchased the notes. The participant will then keep a record of its clients who purchased the notes. Unless it is exchanged in whole or in part for a note certificate, a global note may not be transferred, except that DTC, its nominees, and their successors may transfer a global note as a whole to one another. Beneficial interests in global notes will be shown on, and transfers of global notes will be made only through, records maintained by DTC and its participants. DTC has provided us the following information: DTC is a limited-purpose trust company organized under the New York Banking Law, a "banking organization" within the meaning of the New York Banking Law, a member of the United States Federal Reserve System, a "clearing corporation" within the meaning of the New York Uniform Commercial Code and a "clearing agency" registered under the provisions of Section 17A of the Securities Exchange Act of 1934. DTC holds securities that its participants ("Direct Participants") deposit with DTC. DTC also records the settlement among Direct Participants of securities transactions, such as transfers and pledges, in deposited securities through computerized records for Direct Participant's accounts. This eliminates the need to exchange note certificates. Direct Participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations. 3 Other organizations such as securities brokers and dealers, banks and trust companies that work through a Direct Participant also use DTC's book-entry system. The rules that apply to DTC and its participants are on file with the SEC. A number of its Direct Participants and the New York Stock Exchange, Inc., The American Stock Exchange, Inc. and the National Association of Securities Dealers, Inc. own DTC. We will wire principal and interest payments to DTC's nominee. We and the Trustee will treat DTC's nominee as the owner of the global notes for all purposes. Accordingly, we, the Trustee and (any paying agent) will have no direct responsibility or liability to pay amounts due on the global notes to owners of beneficial interests in the global notes. It is DTC's current practice, upon receipt of any payment of principal or interest, to credit Direct Participants' accounts on the payment date according to their respective holdings of beneficial interests in the global notes as shown on DTC's records. In addition, it is DTC's current practice to assign any consenting or voting rights to Direct Participants whose accounts are credited with notes on a record date. The customary practices between the participants and owners of beneficial interests will govern payments by participants to owners of beneficial interests in the global notes and voting by participants, as is the case with notes held for the account of customers registered in "street name." However, payments will be the responsibility of the participants and not of DTC, the Trustee or us. According to DTC, the foregoing information with respect to DTC has been provided to the Direct Participants and other members of the financial community for informational purposes only and is not intended to serve as a representation, warranty or contract modification of any kind. Notes represented by a global note will be exchangeable for note certificates with the same terms in authorized denominations only if: DTC notifies us that it is unwilling or unable to continue as depositary or if DTC ceases to be a clearing agency registered under applicable law and a successor depositary is not appointed by us within 90 days; or we determine not to require all of the notes of a series to be represented by a global note and notify the Trustee of our decision. NOTE CERTIFICATES -- REGISTRATION, TRANSFER, AND PAYMENT OF INTEREST AND PRINCIPAL If we issue note certificates, they will be registered in the name of the noteholder. The notes may be transferred or exchanged, pursuant to administrative procedures in the indenture, without the payment of any service charge (other than any tax or other governmental charge) by contacting the paying agent. Payments on note certificates will be made by check. INTEREST RATE The interest rate on the notes will either be fixed or floating. The interest paid will include interest accrued to, but excluding, the date of maturity or redemption. Interest is generally payable to the person in whose name the note is registered at the close of business on the record date before each interest payment date. Interest payable at maturity or redemption, however, will be payable to the person to whom principal is payable. If we issue a note after a record date but on or prior to the related interest payment date, we will pay the first interest payment on the interest payment date after the next record date. We will pay interest payments by check or wire transfer, at our option. FIXED RATE NOTES A pricing or prospectus supplement will designate the record dates, payment dates and the fixed rate of interest payable on a note. We will pay interest quarterly or semi-annually, and upon maturity or redemption. 4 Unless an applicable pricing or prospectus supplement states otherwise, if any payment date falls on a day that is not a business day, we will pay interest on the next business day and no additional interest will be paid. Interest payments will be the amount of interest accrued to, but excluding, each payment date. Interest will be computed using a 360-day year of twelve 30-day months. FLOATING RATE NOTES Each floating rate note will have an interest rate formula. The applicable prospectus supplement or pricing supplement will state the initial interest rate or interest rate formula on each note effective until the first interest reset date. The applicable pricing or prospectus supplement will state the method and dates on which the interest rate will be determined, reset and paid. EVENTS OF DEFAULT "Event of Default" means any of the following: - failure to pay for three business days the principal of (or premium, if any, on) any note of a series when due and payable; - failure to pay for 30 days any interest on any note of any series when due and payable; - failure to perform any other requirements in such notes, or in the Indenture in regard to such notes, for 90 days after notice; - certain events of bankruptcy or insolvency; or - any other event of default specified in a series of notes. An Event of Default for a particular series of notes does not necessarily mean that an Event of Default has occurred for any other series of notes issued under the Indenture. If an Event of Default occurs and continues, the Trustee or the holders of at least 33% of the principal amount of the notes of the series affected may require us to repay the entire principal of the notes of such series immediately ("Repayment Acceleration"). In most instances, the holders of at least a majority in aggregate principal amount of the notes of the affected series may rescind a previously triggered Repayment Acceleration. However, if we cause an Event of Default because we have failed to pay (unaccelerated) principal, premium, if any, or interest, Repayment Acceleration may be rescinded only if we have first cured our default by depositing with the Trustee enough money to pay all (unaccelerated) past due amounts and penalties, if any. The Trustee must within 90 days after a default occurs, notify the holders of the notes of the series of default unless such default has been cured or waived. We are required to file an annual certificate with the Trustee, signed by an officer, concerning any default by us under any provisions of the Indenture. Subject to the provisions of the Indenture relating to its duties in case of default, the Trustee shall be under no obligation to exercise any of its rights or powers under the Indenture at the request, order or direction of any holders unless such holders offer the Trustee reasonable indemnity. Subject to the provisions for indemnification, the holders of a majority in principal amount of the notes of any series may direct the time, method and place of conducting any proceedings for any remedy available to, or exercising any trust or power conferred on, the Trustee with respect to such notes. MODIFICATION OF INDENTURE Under the Indenture, our rights and obligations and the rights of the holders of any notes may be changed. Any change affecting the rights of the holders of any series of notes requires the consent of the holders of not less than a majority in aggregate principal amount of the outstanding notes of all series affected by the change, voting as one class. However, we cannot change the terms of payment of principal or interest, or a reduction in the percentage required for changes or a waiver of default, unless the holder consents. We may issue additional series of notes and take other action that does not affect the rights of holders of any series by executing supplemental indentures without the consent of any noteholders. 5 CONSOLIDATION, MERGER OR SALE We may merge or consolidate with any entity or sell substantially all of our assets as an entirety as long as the successor or purchaser (i) is organized and existing under the laws of the United States, any state thereof or the District of Columbia and (ii) expressly assumes the payment of principal, premium, if any, and interest on the notes. LEGAL DEFEASANCE We will be discharged from our obligations on the notes of any series at any time if: - we deposit with the Trustee sufficient cash or government securities to pay the principal, interest, any premium and any other sums due to the stated maturity date or a redemption date of the note of the series, and - we deliver to the Trustee an opinion of counsel stating that the federal income tax obligations of noteholders of that series will not change as a result of our performing the action described above. If this happens, the noteholders of the series will not be entitled to the benefits of the Indenture except for registration of transfer and exchange of notes and replacement of lost, stolen or mutilated notes. COVENANT DEFEASANCE We will be discharged from our obligations under any restrictive covenant applicable to the notes of a particular series if we perform both actions described above. See Legal Defeasance. If this happens, any later breach of that particular restrictive covenant will not result in Repayment Acceleration. If we cause an Event of Default apart from breaching that restrictive covenant, there may not be sufficient money or government obligations on deposit with the Trustee to pay all amounts due on the notes of that series. In that instance, we would remain liable for such amounts. GOVERNING LAW The Indenture and notes of all series will be governed by the laws of the State of New York. CONCERNING THE TRUSTEE We and our affiliates use or will use some of the banking services of the Trustee in the normal course of business. PLAN OF DISTRIBUTION We may sell the notes (a) through agents; (b) through underwriters or dealers; or (c) directly to one or more purchasers. BY AGENTS Notes may be sold on a continuing basis through agents designated by us. The agents will agree to use their reasonable efforts to solicit purchases for the period of their appointment. Unless the pricing or prospectus supplement states otherwise, the notes will be sold to the public at 100% of their principal amount. Agents will receive commissions from .125% to .750% of the principal amount per note depending on the maturity of the note they sell. The Agents will not be obligated to make a market in the notes. We cannot predict the amount of trading or liquidity of the notes. 6 BY UNDERWRITERS If underwriters are used in the sale, the underwriters will acquire the notes for their own account. The underwriters may resell the notes in one or more transactions, including negotiated transactions, at a fixed public offering price or at varying prices determined at the time of sale. The obligations of the underwriters to purchase the notes will be subject to certain conditions. The underwriters will be obligated to purchase all the notes of the series offered if any of the notes are purchased. Any initial public offering price and any discounts or concessions allowed or re-allowed or paid to dealers may be changed from time to time. DIRECT SALES We may also sell notes directly. In this case, no underwriters or agents would be involved. GENERAL INFORMATION Underwriters, dealers, and agents that participate in the distribution of the notes may be underwriters as defined in the Securities Act of 1933 (the "Act"), and any discounts or commissions received by them from us and any profit on the resale of the notes by them may be treated as underwriting discounts and commissions under the Act. We may have agreements with the underwriters, dealers and agents to indemnify them against certain civil liabilities, including liabilities under the Act. Underwriters, dealers and agents may engage in transactions with, or perform services for, us or our affiliates in the ordinary course of their businesses. LEGAL OPINIONS Our counsel, Simpson Thacher & Bartlett, New York, NY, and one of our lawyers will each issue an opinion about the legality of the notes for us. Dewey Ballantine LLP, New York, NY will issue an opinion for the agents or underwriters. From time to time, Dewey Ballantine LLP acts as counsel to our affiliates for some matters. EXPERTS The financial statements of the Company and its subsidiaries (including Central and South West Corporation and its subsidiaries, as of December 31, 2000, and for the year then ended) and the related financial statement schedule incorporated in this prospectus by reference from the Company's Annual Report on Form 10-K for the year ended December 31, 2000 have been audited by Deloitte & Touche LLP, as stated in their reports dated February 26, 2001 (which report on the financial statements expresses an unqualified opinion and includes an explanatory paragraph referring to the restatement of the 1999 and 1998 financial statements to give retroactive effect to the conforming change in the method of accounting for vacation pay accruals), which are incorporated herein by reference. The financial statements of Central and South West Corporation and its subsidiaries (excluding CSW UK Holdings and CSW UK Finance Company), as of December 31, 1999 and 1998, and for each of the two years ended December 31, 1999, have been audited by Arthur Andersen LLP, as stated in their reports, which are incorporated herein by reference. The financial statements of CSW UK Holdings, as of December 31, 1999, and the year then ended, and CSW UK Finance Company, as of December 31, 1998, and the year then ended, have been audited by KPMG Audit Plc, as stated in their reports, which are incorporated herein by reference. Such financial statements of the Company and its subsidiaries are included herein in reliance upon the respective reports of such firms given upon their authority as experts in accounting and auditing. All of the foregoing firms are independent auditors. 7 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- $300,000,000 AMERICAN ELECTRIC POWER COMPANY, INC. % SENIOR NOTES, SERIES D, DUE 20 AMERICAN ELECTRIC POWER LOGO ----------------------------------------------------- PROSPECTUS SUPPLEMENT ----------------------------------------------------- May , 2003 -------------------------------------------------------------------------------- --------------------------------------------------------------------------------