10-Q 1 q20310q.txt 10-Q

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Sections 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X No ----- ----- Indicate by check mark whether American Electric Power Company, Inc. is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes X No ----- ----- Indicate by check mark whether AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company, are accelerated filers (as defined in Rule 12b-2 of the Exchange Act). Yes No X ----- ----- AEP Generating Company, AEP Texas North Company, Columbus Southern Power Company, Kentucky Power Company and Public Service Company of Oklahoma meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q. The number of shares outstanding of American Electric Power Company, Inc. Common Stock, par value $6.50, at July 31, 2003 was 395,001,853.

This combined Form 10-Q is separately filed by American Electric Power Company, Inc., AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.

FORWARD-LOOKING INFORMATION These reports made by AEP and its registrant subsidiaries contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and its registrant subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are: o Electric load and customer growth. o Abnormal weather conditions. o Available sources and costs of fuels. o Availability of generating capacity. o The speed and degree to which competition is introduced to our service territories. o The ability to recover stranded costs in connection with deregulation. o New legislation and government regulation. o Oversight and/or investigation of the energy sector or its participants. o Our ability to successfully control costs. o The success of acquiring new business ventures and disposing of existing investments that no longer match our corporate profile. o International and country-specific developments affecting foreign investments including the disposition of any current foreign investments and potential additional foreign investments. o The economic climate and growth in our service territory and changes in market demand and demographic patterns. o Inflationary trends. o Electricity and gas market prices. o Interest rates. o Liquidity in the banking, capital and wholesale power markets. o Actions of rating agencies. o Changes in technology, including the increased use of distributed generation within our transmission and distribution service territory. o Other risks and unforeseen events, including wars, the effects of terrorism, embargoes and other catastrophic events.

Our Net Income is discussed below according to the operating segments listed above. Income Before Discontinued Operations and Cumulative Effect for the quarter and year-to-date were affected by the weather, weak economy and the availability of electric generation. Year-to-date Net Income of $615 million or $1.64 per share includes $242 million (net of tax) of Income from Cumulative Effect of Accounting Changes in the first quarter resulting from the implementation of SFAS 143 (see Note 4) partially offset by $49 million (net of tax) of Loss from Cumulative Effect of Accounting Changes in the first quarter resulting from the implementation of EITF 02-3 (see Note 4) and discontinued operations of $16 million loss (net of tax) (see Note 11). The loss of $107 million year-to-date 2002 includes discontinued operations of $74 million loss (net of tax) (see Note 11) and a $350 million (net of tax) charge discussed below in the Investments - Other segment for the implementation of SFAS 142 (see Note 4). Utility Operations Net Income for Utility Operations, our core business, decreased in the quarter $6 million and increased year-to-date $309 million due to the fluctuations in operating income along with the year-to-date adjustment for the cumulative effect of accounting changes. Year-to-date Net Income of $750 million included $249 million (net of tax) of Income from Cumulative Effect of Accounting Changes in the first quarter resulting from the implementation of SFAS 143 (see Note 4) partially offset by $11 million (net of tax) Loss from Cumulative Effect of Accounting Changes in the first quarter resulting from the implementation of EITF 02-3 (see Note 4). Operating income decreased in the second quarter and increased on a year-to-date basis primarily due to: o Pre-tax earnings increased $59 million in the quarter and $116 million year-to-date resulting primarily from the non-cash earnings associated with the stranded cost recovery in Texas which recognizes the difference between the actual price received from the state-mandated auction of 15% of generation capacity and the earlier estimate of market price derived by the PUCT model. This regulatory asset is expected to be recovered through the 2004 true-up proceeding established by deregulation laws in Texas. o Pre-tax earnings for systems sales, transmission revenue and other wholesale transactions decreased $7 million in the current quarter as a result of our exit from trading markets where we do not own assets. Year-to-date pre-tax earnings increased by $66 million due to favorable power optimization and higher transmission volumes. o Retail margins from the regulated integrated utilities reduced pre-tax earnings by $64 million for the quarter and $61 million year-to-date due to the combined impact of weather, continued weak economy and costs associated with the Cook Plant outage. o The reduced demand in the Ohio Companies attributable to the mild weather in the quarter and the economic pressures on industrial customers reduced pre-tax earnings by $15 million. Year-to-date pre-tax earnings increased $5 million due to the average fuel costs being less than the set recovery rate in revenues. o The reduction in pre-tax earnings of $38 million for the quarter and $83 million year-to-date of Texas supply is due to lower margins attributable to an outage at the STP nuclear plant and a separate provision for potential disallowance by the PUCT of certain historical fuel expenses. The Texas supply represents the gross margin for output of generating units in the ERCOT region and from "reliability must run" (RMR) contracts with ERCOT. o Federal Income Taxes decreased $21 million in the quarter and increased $19 million year-to-date due to the fluctuation in pre-tax income and the changes in the effective tax rate. Investments - Gas Operations Net Loss for the Gas Operations, which include Louisiana Intrastate Gas and Houston Pipe Line operations, of $24 million in the quarter and $61 million year-to-date is due to lower margins resulting from our reduced risk profile and the year-to-date adjustment for the cumulative effect of accounting changes. These decreases were partially offset by reduced operating and interest expenses. Year-to-date Net Loss of $61 million included $23 million (net of tax) of Loss from Cumulative Effect of Accounting Changes in the first quarter resulting from the implementation of EITF 02-3 (see Note 4). We have selected advisors to assist with developing a plan of divestiture of its Louisiana Intrastate Gas holdings. See "Significant Factors - Possible Divestitures" for additional information. Investments- UK Operations Net Loss for the UK Operations, which include Fiddler's Ferry and Ferrybridge plants (FFF), decreased in the quarter $15 million and increased year-to-date $70 million due to the fluctuations in operating income along with the year-to-date adjustment for the cumulative effect of accounting changes. Year-to-date Net Loss of $59 million included $15 million (net of tax) of Loss from Cumulative Effect of Accounting Changes in the first quarter resulting from the implementation of EITF 02-3 (see Note 4) and a $7 million (net of tax) Loss from Cumulative Effect of Accounting Changes in the first quarter from the implementation of SFAS 143 (see Note 4). During the second quarter, our U.K. operations' improved performance was driven primarily by the results of our coal and freight procurement group and reduced interest expense, as the debt associated with the plants was retired in early April. Year-to-date our U.K. operations posted a loss of $37 million driven by a $40 million loss in the first quarter, due to the continued deterioration in power markets during that period, and higher operations and maintenance costs which included severance and redundancy closure costs of the Nordic trading office. Significant liquidity issues in the U.K. market and the uncertain environmental regulations are still concerns, so we expect this market to remain a difficult one for the foreseeable future. Investments - Other Net Loss for Other investments, which consists of investments in independent power plants, coal mines, river transportation, and communications as well as the discontinued operations of SEEBOARD, CitiPower, Eastex and Pushan, of $26 million in the current quarter 2003 and $15 million year-to-date reflects discontinued operations losses of $7 million in the quarter and $16 million year-to-date. The Loss Before Discontinued Operations and Cumulative Effect of Accounting Changes decreased $7 million in the quarter and $56 million year-to-date due to lower international development costs, reduced interest expense and lower costs to wind down operations. The 2002 Net Loss for Other investments of $122 million in the quarter and $479 million year-to-date includes discontinued operations losses of $96 million in the quarter and $74 million year-to-date as well as a $350 million (net of tax) first quarter cumulative effect adjustment for the implementation of SFAS 142 (see Note 4) . SFAS 142 required that goodwill and intangible assets with indefinite useful lives no longer be amortized and be tested annually for impairment. The implementation of SFAS 142 resulted in a $350 million after tax net transitional loss in 2002 for the SEEBOARD and CitiPower operations. We have selected advisors to assist with developing a plan of divestiture of coal mines and certain independent power plants. See "Significant Factors - Possible Divestitures" for additional information. Financial Condition ------------------- Credit Ratings The rating agencies currently have AEP and our rated subsidiaries on stable outlook. Current ratings for AEP are as follows: Moody's S&P Fitch ------- --- ----- AEP Short-Term Debt P-3 A-2 F-2 AEP Senior Unsecured Debt Baa3 BBB BBB Senior Notes issued by AEP Resources (with support Agreement from AEP) Baa3 BBB BBB+ During the first quarter of 2003, Moody's Investors Service (Moody's), Standard & Poors (S&P) and Fitch Rating Service completed their reviews of AEP and our rated subsidiaries. The reviews resulted in downgrades of debt ratings. The completion of these reviews was a culmination of ratings action started during 2002. Liquidity At June 30, 2003, our liquidity sources totaled $3.9 billion and we had an available liquidity position of $3.3 billion as illustrated in the table below: Credit Facilities (in millions) Maturity -------- Commercial Paper Backup: Lines of Credit $ 750 5/04 Lines of Credit 1,000 5/05 Lines of Credit 750 5/06 Euro Revolving Credit Facilities 345 10/03 ------ Total 2,845 Liquidity Reserves 300* Other Temporary Investments 722* ------ Total Liquidity Sources 3,867 Less: Commercial Paper Outstanding 547 ------ Total Available Liquidity $3,320 ====== * These components comprise the Cash and Cash Equivalents balance on our Consolidated Balance Sheet at June 30, 2003 less $154 million of operational cash on hand. We maintain the $300 million cash liquidity reserve fund to support our marketing operations in the U.S. and keep additional cash on hand as market conditions change. In April 2003, our Board of Directors declared a common stock dividend of $0.35 per share for the second quarter of 2003, which is a 42% decrease from the previous quarter's dividend of $0.60 per share. This reduction will result in annual cash savings of approximately $395 million. Cash Flow

Cash from operations and short-term borrowings provide working capital and meet other short-term cash needs. We generally use short-term borrowings to fund property acquisitions and construction until long-term funding mechanisms are arranged. Sources of long-term funding include issuance of common stock, preferred stock or long-term debt and sale-leaseback or leasing agreements. We operate a money pool and sell accounts receivables to provide liquidity for the domestic electric subsidiaries. Short-term borrowings are supported by a bank-sponsored receivables purchase agreement and three revolving credit agreements. Operating Activities Cash flows from operating activities during the first half of 2003 were $798 million. Beginning with Income Before Discontinued Operations and Cumulative Effect of Accounting Changes of $438 million, we add depreciation and deferred taxes of $702 million and deduct $108 million of non-cash ECOM, $48 million in mark-to-market changes and $190 million for working capital changes. The negative working capital changes includes $90 million paid to Williams companies in settlement for power and gas transactions, and $46 million in increased fuel inventories. Investing Activities Cash flows used for investing activities during the first half of 2003 were $596 million compared to $784 million during the first half of 2002. The major reason for the year-over-year variance was a construction expenditures reduction of $135 million and proceeds of $41 million from the sale of assets in 2003 (see Note 11). Total consolidated plant and property additions for the first half 2003 were $649 million, including continued construction expenditures for emission control technology at several coal-fired generating plants (see Note 8). Financing Activities Cash flows from financing activities in the first half of 2003 decreased by $1,277 million when compared to the first half of 2002 ($(239) million compared to $1,038 million during 2003 and 2002, respectively), primarily as the result of AEP's retirement and restructuring of its short-term and long-term debt during 2003. During the first half of 2003, AEP was able to retire $4,393 million of debt ($2,675 million short-term and $1,718 million of long-term) and increase available cash primarily through the issuance of long-term financing ($3,546 million), issuance of common stock ($1,177 million) and the generation of cash from operating activities. Financing Activity Common Stock Offering On February 27, 2003, we priced our offering of 50 million shares of common stock at a public offering price of $20.95 per share. We granted the underwriters an option to purchase an additional 7.5 million shares of common stock to cover over allotments. The underwriters exercised their over allotment option to purchase an additional 6 million shares. The net proceeds of approximately $1.1 billion from the sale of these securities were used to reduce debt and for other corporate purposes. Debt In May 2003, a third party exercised its option to call $250 million of 5.50% putable callable notes, issued by us in May 2001, for purchase and remarketing. On May 15, 2003, we issued $300 million of 5.25% senior notes due 2015, a portion of which was an exchange for the $250 million putable callable notes due in 2003. In March 2003, we completed an offering of 5.375% Series C Senior Notes which have a principal amount of $500 million and a maturity date of March 15, 2010. The net proceeds of $494 million from the offering were used to repay or redeem current maturities of long-term debt and for other corporate purposes. In February 2003, CSPCo issued $250 million of unsecured senior notes due 2013 at a coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a coupon of 6.60%. OPCo issued $250 million of unsecured senior notes due 2013 at a coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a coupon of 6.60%. TCC issued $100 million of unsecured senior notes due 2005 at a variable rate, $150 million of unsecured senior notes due 2005 at a coupon of 3.0%, $275 million of unsecured senior notes due 2013 at a coupon of 5.50% and $275 million of unsecured senior notes due 2033 at a coupon of 6.65%. TNC issued $225 million of unsecured senior notes due 2013 at a coupon of 5.50%. The proceeds from the bond issuances were used to repay the bank facility due to mature in April 2003, short-term debt and for other corporate purposes. Also, see Note 15 for further information on financing activities. Significant Factors ------------------- Possible Divestitures We have a strong commitment to continually evaluate the need to reallocate resources to areas that effectively match investments with our business strategy, provide greater potential for financial returns, and to dispose of investments that no longer meet these principles. We are seeking to divest assets that consist of domestic and international unregulated generation, gas pipelines, a coal business and a communications business. In June 2003, we began actively seeking buyers for 4,497 megawatts of unregulated generating capacity in Texas to establish a market price for calculation of stranded cost (see Note 7). Also in the second quarter 2003, we hired an advisor to evaluate our coal business which has resulted in receipt of non-binding bids which are currently being evaluated. In the third quarter of 2003, management hired advisors to review business options regarding various components of our Gas Operations investment. This review is expected to be completed before year-end and will include an analysis of alternatives for packaging the business for sale along with review of our investment in gas operations for impairment of value, including related goodwill of approximately $300 million. Management is unable to determine the extent of an impairment, if any, until such evaluation is complete. Management continues to have periodic discussions with various parties on business alternatives for certain of our other non-core investments. The ultimate timing for a disposition of one or more of these assets will depend upon market conditions and the value of any buyer's proposal. If we choose to dispose of these assets, we may realize non-recurring losses in the aggregate that could have a material impact on our results of operations, cash flows and financial condition. Corporate Separation As discussed in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003), we have filed with the FERC and SEC seeking approval to separate our regulated and unregulated operations. With the changes in our business strategy, in response to energy market and business conditions, management continues to evaluate corporate separation plans, including determining whether legal corporate separation is appropriate in jurisdictions where it is not legally required. RTO Formation As discussed in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003), the FERC's AEP-CSW merger approval and many of the settlement agreements with the state regulatory commissions to approve the AEP-CSW merger required the transfer of functional control of the subsidiaries' transmission systems to RTOs. In May 2002, we announced an agreement with PJM to pursue terms for participation in its RTO for AEP East companies with final agreements to be negotiated. In July 2002, FERC issued an order accepting our decision to participate in PJM, subject to specified conditions. AEP and other parties continued to work on the resolution of those conditions. In December 2002, our subsidiaries, which operate in the states of Indiana, Kentucky, Ohio and Virginia, filed for state regulatory commission approval of their plans to transfer functional control of their transmission assets to PJM based on statutory or regulatory requirements in those states. In July 2003, the KPSC ruled in part that we had failed to prove the benefit of our PJM RTO membership to Kentucky retail customers and denied our request for approval of transfer of functional control to PJM. Management plans to seek a rehearing. Proceedings in the other states remain pending. In February 2003, the Virginia Legislature enacted legislation, which the Governor of Virginia signed, that prohibited the transfer of transmission assets in its jurisdiction to an RTO, until at least July 2004 and then only with Virginia SCC approval. In April 2003, FERC approved our transfer of functional control of the AEP East companies' transmission system to PJM. FERC also accepted our proposed rates for joining PJM, but set a number of rate issues for resolution through settlement proceedings or FERC hearings. Settlement discussions continue on certain rate matters. AEP West companies are members of ERCOT or the SPP. In 2002, FERC conditionally accepted filings related to a proposed consolidation of MISO and the SPP. Our SPP companies are also regulated by state public utility commissions. The Louisiana and Arkansas commissions filed responses to the FERC's RTO order indicating that additional analysis was required. Subsequently, the proposed SPP/MISO combination was terminated. Regulatory activities concerning various RTO issues are ongoing in Arkansas and Louisiana. 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 results of operations and cash flows. Industry Restructuring As discussed in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003), restructuring and customer choice are in place in four of the eleven state retail jurisdictions in which our electric utility companies operate. Restructuring legislation generally provides for a transition from cost-based rate regulation of bundled electric service to customer choice and market pricing for the supply of electricity. The status of our transition plans, regulatory issues and proceedings and accounting issues in the state regulatory jurisdictions impacted by restructuring and customer choice is presented in Note 7. Nuclear Plant Outages In April 2003, engineers at STP, during inspections conducted regularly as part of refueling outages, found wall cracks in two bottom mounted instrument guide tubes of STP Unit 1. These cracks have been repaired and the unit is expected to return to service in late summer. Our share of the direct cost of repair was approximately $6 million through June 30, 2003. STP officials are working closely with the NRC to safely return the unit to service. We have commitments to provide power to customers during the outage. Therefore, we will be subject to fluctuations in the market prices of electricity and purchased replacement energy could be a significant cost. In April 2003, both units of Cook Plant were taken offline due to an influx of fish in the plant's cooling water system which caused a reduction in cooling water to essential plant equipment. After repair of damage caused by the fish intrusion, Cook Plant Unit 1 returned to service in May and Unit 2 returned to service in June following completion of a scheduled refueling outage. Litigation Federal EPA Complaint and Notice of Violation As discussed in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003) and as discussed in Part II, Item 1 "Legal Proceedings",AEPSC, APCo, CSPCo, I&M, and OPCo have been involved in litigation since 1999 regarding generating plant emissions under the Clean Air Act. Federal EPA and a number of states alleged APCo, CSPCo, I&M, OPCo and eleven unaffiliated utilities made modifications to generating units at coal-fired generating plants in violation of the Clean Air Act. Federal EPA filed complaints against our 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. Management is unable to estimate the loss or range of loss related to the contingent liability for civil penalties under the Clear Air Act proceedings and is unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. In the event the AEP System companies do not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates and market prices for electricity. See Note 8 for further discussion. NOx Reductions Federal EPA issued a NOx Rule and adopted a revised rule (the Section 126 Rule) under the Clean Air Act requiring substantial reductions in NOx emissions in a number of eastern states, including certain states in which the AEP System's generating plants are located. The compliance date for the rules is May 31, 2004. The Texas Commission on Environmental Quality adopted rules requiring significant reductions in NOx emissions from utility sources, including SWEPCo and TCC. The compliance requirements began in May 2003 for TCC and begin in May 2005 for SWEPCo. We are installing selective catalytic reduction (SCR) technology and non-SCR technology to reduce NOx emissions on certain units to comply with these rules. Our estimates indicate that compliance with the rules could result in required capital expenditures in a range of approximately $1.3 billion to $1.7 billion for the AEP System of which $976 million has been spent through June 30, 2003. The actual cost to comply could be significantly different than the estimates depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless any capital or operating costs for additional pollution control equipment are recovered from customers, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. See Note 8 for further discussion. Enron Bankruptcy In 2002, certain subsidiaries of AEP filed claims in the bankruptcy proceeding of the Enron Corporation and its subsidiaries which is pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron's bankruptcy, AEP and its subsidiaries had open trading contracts and trading accounts receivables and payables with Enron and various HPL related contingencies and indemnities including issues related to the underground Bammel gas storage facility and the cushion gas (or pad gas) required for its normal operation. Management believes that our entities have the right to utilize offsetting receivables and payables and related collateral across various Enron entities by offsetting trading payables owed to various Enron entities against trading receivables due to us. Management believes we have legal defenses to any challenge that may be made to the utilization of such offsets. In this regard, Enron sent to AEPES a demand for payment of approximately $138 million relating to AEPES' termination of trading contracts. At this time management is unable to predict the ultimate resolution of these issues or their impact on results of operations and cash flows. See Note 8 for further discussion. Bank of Montreal Claim In March 2003, Bank of Montreal (BOM) terminated all natural gas trading deals and claimed that we owed approximately $34 million. In April 2003, we filed a lawsuit against BOM claiming BOM had acted contrary to industry practice in calculating termination and liquidation amounts and that BOM had acknowledged in March 2003 that it owed us approximately $68 million. Alternatively, we are claiming that BOM owes us approximately $45 million. Although management is unable to predict the outcome of this matter, it is not expected to have a material impact on results of operations, cash flows or financial condition. Arbitration of Williams Claim In 2002, we filed a demand for arbitration with the American Arbitration Association to initiate formal arbitration proceedings in a dispute with the Williams Companies (Williams). The proceeding results from Williams' repudiation of its obligations to provide physical power deliveries to AEP and Williams' failure to provide the monetary security required for natural gas deliveries. AEP and Williams settled the dispute with AEP paying $90 million to Williams in June 2003. The resolution of this matter had an immaterial impact on results of operations as we had accrued the amount paid. See Note 8 for further discussion. Arbitration of PG&E Energy Trading, LLC Claim In January 2003, PG&E Energy Trading, LLC (PGET) claimed approximately $22 million was owed by AEP in connection with the termination and liquidation of all trading deals. In February 2003, PGET initiated arbitration proceedings. In July 2003, AEP and PGET agreed to a settlement with AEP paying approximately $11 million to PGET. The settlement payment did not have a material impact on results of operations, cash flows or financial condition as the payment approximated our recorded liability. Energy Market Investigations As discussed in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003), AEP and other energy market participants received data requests, subpoenas and requests for information from the FERC, the SEC, the PUCT, the U.S. Commodity Futures Trading Commission, the U.S. Department of Justice and the California attorney general during 2002. Management responded to the inquires and provided the requested information and has continued to respond to supplemental data request in 2003. In March 2003, we received a subpoena from the SEC as part of the SEC's ongoing investigation of energy trading activities. In August 2002, we had received an informal data request from the SEC seeking that we voluntarily provide information. The subpoena sought additional information and is part of the SEC's formal investigation. We responded to the subpoena and will continue to cooperate with the SEC. Management cannot predict what, if any action, any of these governmental agencies may take with respect to these matters. Shareholders' Litigation In 2002, lawsuits alleging securities law violations, a breach of fiduciary duty for failure to establish and maintain adequate internal controls and violations of the Employee Retirement Income Security Act were filed against us, certain executives, members of the Board of Directors and certain investment banking firms. These cases are in the initial pleading stage. We intend to vigorously defend against these actions. See Note 8 for further discussion. California Lawsuit In 2002, the Lieutenant Governor of California filed a lawsuit in California Superior Court against forty energy companies, including AEP, and two publishing companies alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. We intend to vigorously defend against this action. See Note 8 for further discussion. Snohomish Settlement In February 2003, AEP and the Public Utility District No. 1 of Snohomish County, Washington (Snohomish) agreed to terminate their long-term contract signed in January 2001. Snohomish also agreed to withdraw its complaint before the FERC regarding this contract and paid $59 million to us. As a result of the contract termination, we reversed $69 million of unrealized mark-to-market gains previously recorded, resulting in a $10 million pre-tax loss. Other Litigation We continue to be involved in certain other legal matters discussed in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003). Critical Accounting Policies See "Registrants' Combined Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters - Critical Accounting Policies" in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003) for a discussion of the estimates and judgments required for revenue recognition, the valuation of long-lived assets, the accounting for pension benefits and the impact of new accounting pronouncements. New Accounting Pronouncements See Note 2 for a discussion of significant accounting policies and new accounting pronouncements. Quantitative And Qualitative Disclosures About Risk Management Activities ------------------------------------------------------------------------- Market Risks As a major power producer and marketer of wholesale electricity and natural gas, we have certain market risks inherent in our business activities. These risks include commodity price risk, interest rate risk, foreign exchange risk and credit risk. They represent the risk of loss that may impact us due to changes in the underlying market prices or rates. Policies and procedures have been established to identify, assess, and manage market risk exposures in our day to day operations. Our risk policies have been reviewed with the Board of Directors, approved by a Risk Executive Committee and administered by a Chief Risk Officer. The Risk Executive Committee establishes risk limits, approves risk policies, assigns responsibilities regarding the oversight and management of risk and monitors risk levels. This committee receives daily, weekly, and monthly reports regarding compliance with policies, limits and procedures. The committee meets monthly and consists of the Chief Risk Officer, Chief Credit Officer, V.P. Market Risk Oversight, and senior financial and operating managers. AEP has actively participated in the Committee of Chief Risk Officers (CCRO) to develop standard disclosures for risk management activities around energy trading contracts. The CCRO is composed of the chief risk officers of major electricity and gas companies in the United States. Recently the CCRO adopted disclosure standards for energy contracts to improve clarity, understanding and consistency of information reported. Implementation of the new disclosures is voluntary. AEP supports the work of the CCRO and has embraced the new disclosures. The following tables provide information on AEP's risk management activities. Roll-Forward of Mark-to-Market Risk Management Contract Net Assets This table provides detail on changes in AEP's mark-to-market (MTM) net asset or liability balance sheet position from one period to the next.

(a)"(Gain) Loss from Contracts Realized/Settled During the Period" includes realized gains from risk management contracts and related derivatives that settled during 2003 that were entered into prior to 2003. (b) The "Fair Value of New Contracts When Entered Into During the Period" represents the fair value of long-term contracts entered into with customers during 2003. The fair value is calculated as of the execution of the contract. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location. (c)"Net Option Premiums Paid/(Received)" reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered into in 2003. (d)"Changes in Fair Value of Risk Management Contracts" represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc. (e)"Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions" relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Operations. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information. o The source of fair value used in determining the carrying amount of AEP's total MTM asset or liability (external sources or modeled internally) o The maturity, by year, of AEP's net assets/liabilities, giving an indication of when these MTM amounts will settle and generate cash

(a) Prices provided by other external sources - Reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms. (b) Modeled - In the absence of pricing information from external sources, modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the Modeled category in the preceding table varies by market. The following table reports an estimate of the maximum tenors of the liquid portion of each energy market.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income on the Balance Sheet AEP employs fair value hedges and cash flow hedges to mitigate changes in interest rates or fair values on short and long-term debt when management deems it necessary. AEP does not hedge all interest rate risk. AEP employs forward contracts as cash flow hedges to lock-in prices on certain transactions which have been denominated in foreign currencies where deemed necessary. International subsidiaries use currency swaps to hedge exchange rate fluctuations of debt denominated in foreign currencies. AEP does not hedge all foreign currency exposure. The table provides detail on effective cash flow hedges under SFAS 133 included in the balance sheet. The data in the table will indicate the magnitude of SFAS 133 hedges AEP has in place. (However, given that under SFAS 133 only cash flow hedges are recorded in Accumulated Other Comprehensive Income (AOCI), the table does not provide an all-encompassing picture of AEP's hedging activity). The table further indicates what portions of these hedges are expected to be reclassified into the income statement in the next 12 months. The table also includes a roll-forward of the AOCI balance sheet account, providing insight into the drivers of the changes (new hedges placed during the period, changes in value of existing hedges and roll off of hedges). Information on energy merchant activities is presented separately from interest rate, foreign currency risk management activities and other hedging activities. In accordance with GAAP, all amounts are presented net of related income taxes. Cash Flow Hedges included in Accumulated Other Comprehensive Income On the Balance Sheet as of June 30, 2003 Accumulated Other Portion Expected Comprehensive to Be Reclassified Income to Earnings During (Loss) After Tax(a) Next 12 Months (b) ------------------ ------------------ (in millions) Power $ (92) $(44) Foreign Currency (10) (8) Interest Rate (14) (5) ----- ---- Consolidated $(116) $(57) ===== ====

(a) Accumulated other comprehensive income (loss) after tax - Gains/losses are net of related income taxes that have not yet been included in the determination of net income; reported as a separate component of shareholders' equity on the balance sheet. (b) Portion expected to be reclassified to earnings during the next 12 months - Amount of gains or losses (realized or unrealized) from derivatives used as hedging instruments that have been deferred and are expected to be reclassified into net income during the next 12 months at the time the hedged transaction affects net income. (c) Changes in fair value - Changes in the fair value of derivatives designated as hedging instruments in cash flow hedges during the reporting period not yet reclassified into net income, pending the hedged item's affecting net income. Amounts are reported net of related income taxes. (d) Reclassifications from AOCI to net income - Gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes above. Credit Risk AEP limits credit risk by assessing creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness after transactions have been initiated. Only after an entity has met AEP's internal credit rating criteria will we extend unsecured credit. AEP uses Moody's Investor Service, Standard and Poor's and qualitative and quantitative data to independently assess the financial health of counterparties on an ongoing basis. AEP's independent analysis, in conjunction with the rating agencies information, is used to determine appropriate risk parameters. AEP also requires cash deposits, letters of credit and parental/affiliate guarantees as security from counterparties depending upon credit quality in our normal course of business. AEP has risk management contracts with numerous counterparties. Since AEP's open risk management contracts are valued based on changes in market prices of the related commodities, AEP's exposures change daily. AEP believes that credit and market exposures with any one counterparty is not material to AEP's financial condition at June 30, 2003. At June 30, 2003 AEP's credit exposure net of credit collateral to sub investment grade counterparties was approximately 10%, expressed in terms of net MTM assets and net receivables. Net MTM assets represents the aggregate difference between the forward market price for the remaining term of the contract and the contractual price per counterparty. As of June 30, 2003 the following table approximates counterparty credit quality and exposure for AEP based on netting across AEP entities, commodities and instruments:

The counterparty credit quality and exposure for the registrant subsidiaries is generally consistent with that of AEP. Generation Plant Hedging Information This table provides information on operating measures regarding the proportion of output of AEP's generation facilities (based on economic availability projections) economically hedged. This information is forward-looking and provided on a prospective basis through December 31, 2005. Please note that this table is point-in time estimates, subject to changes in market conditions and AEP decisions on how to manage operations and risk. Generation Plant Hedging Information Estimated Next Three Years As of June 30, 2003 2003 2004 2005 ---- ---- ---- Estimated Plant Output Hedged (a) 94% 90% 83% (a) Estimated Plant Output Hedged - Represents the portion of megawatt-hours of future generation/production for which AEP has sales commitments to customers. VaR Associated with Energy Trading Contracts AEP uses a risk measurement model which calculates Value at Risk (VaR) to measure AEP's commodity price risk in the Energy Trading portfolio. The VaR is based on the variance - covariance method using historical prices to estimate volatilities and correlations and assumes 95% confidence level, a one-day holding period and a one-tailed distribution. Based on this VaR analysis, at June 30, 2003 a near term typical change in commodity prices is not expected to have a material effect on AEP's results of operations, cash flows or financial condition. The following table shows the end, high, average, and low market risk as measured by VaR year-to-date: VaR Model --------- June 30, December 31, 2003 2002 (in millions) (in millions) End High Average Low End High Average Low --- ---- ------- --- --- ---- ------- --- $5 $19 $ 7 $5 $5 $24 $12 $4 The High VaR for 2003 occurred in late February 2003 during a period when natural gas and power prices experienced high levels and extreme volatility. Within a few days the VaR returned to levels more representative of the average VaR for the year. The AEP VaR model results are adjusted using standard statistical treatments to calculate the CCRO VaR reporting metrics listed below. The adjustments are made to take the AEP model results from a one-day 95% confidence level to a ten-day 99% confidence level. The AEP VaR model's performance has not been evaluated for its accuracy at calculating VaR using the CCRO VaR Metrics assumptions.

AEP utilizes a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level, a one year holding period and a one-tailed distribution. The volatilities and correlations were based on three years of daily prices. The risk of potential loss in fair value attributable to AEP's exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $1,217 million at June 30, 2003 and $527 million at December 31, 2002. AEP would not expect to liquidate its entire debt portfolio in a one year holding period, therefore a near term change in interest rates should not materially affect results of operations or consolidated financial position. AEP is exposed to risk from changes in the market prices of coal and natural gas used to generate electricity where generation is no longer regulated or where existing fuel clauses are suspended or frozen. The protection afforded by fuel clause recovery mechanisms has either been eliminated by the implementation of customer choice in Ohio (effective January 1, 2001) and in the ERCOT area of Texas (effective January 1, 2002) or frozen by settlement agreements in Michigan and West Virginia or capped in Indiana. To the extent the fuel supply of the generating units in these states is not under fixed price long-term contracts AEP is subject to market price risk. AEP continues to be protected against market price changes by active fuel clauses in Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of Texas. AEP employs physical forward purchase and sale contracts, exchange futures and options, over-the-counter options, swaps, and other derivative contracts to offset price risk where appropriate. AEP engages in risk management of electricity, gas and to a lesser degree other commodities, principally coal and freight. As a result, AEP is subject to price risk. The amount of risk taken is controlled by risk management operations and AEP's Chief Risk Officer and his staff. When the risk from energy trading activities exceeds certain pre-determined limits, the positions are modified or hedged to reduce the risk to be within the limits unless specifically approved by the Risk Executive Committee.

See Notes to Consolidated Financial Statements.

See Notes to Consolidated Financial Statements.

See Notes to Consolidated Financial Statements.

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $364 million and $335 million and for income taxes was $155 million and $307 million in 2003 and 2002, respectively. Noncash acquisitions under capital leases were $1 million in 2003 and $2 million in 2002. See Notes to Consolidated Financial Statements.

See Notes to Consolidated Financial Statements. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS JUNE 30, 2003 ------------- (UNAUDITED) 1. GENERAL ------- The accompanying unaudited interim financial statements should be read in conjunction with the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003) as incorporated in and filed with the Form 10-K/A. Certain prior period financial statement items have been reclassified to conform to current period presentation. These items include the effects of discontinued operations, gains and losses associated with derivative trading contracts presented on a net basis in accordance with EITF 02-3, and counterparty netting in accordance with FASB Interpretation No. 39, "Offsetting of Amounts Related to Certain Contracts" and EITF Topic D-43, "Assurance That a Right of Setoff is Enforceable in a Bankruptcy under FASB Interpretation No. 39". Such reclassifications had no effect on previously reported Net Income. In addition, management determined that certain amounts were misclassified in AEP's 2002 Consolidated Statement of Operations resulting from errors in the coding of certain intercompany transactions and from transactions associated with our UK operations (see Note 30 in the Current Report on Form 8-K dated May 14, 2003). As a result, Gas Operations revenues decreased by $2 million and $49 million, UK Operations and Other revenues decreased by $3 million and $13 million, Fuel for Electric Generation decreased by $17 million and $44 million, and Purchased Gas for Resale decreased by $104 million and $162 million for the three and six month periods ended June 30, 2002, respectively. Expenses for Maintenance and Other Operation increased by $109 million and $130 million and Taxes Other Than Income Taxes increased by $7 million and $14 million for the three and six month periods ended June 30, 2002, respectively. These revisions had no effect on Operating Income or Net Loss. In the opinion of management, the unaudited interim financial statements reflect all normal recurring accruals and adjustments which are necessary for a fair presentation of the results of operations for interim periods. 2. SIGNIFICANT ACCOUNTING POLICIES AND NEW ACCOUNTING PRONOUNCEMENTS ----------------------------------------------------------------- Accumulated Other Comprehensive Income Approximately $57 million of net losses from cash flow hedges in Accumulated Other Comprehensive Income (Loss) at June 30, 2003 are expected to be reclassified to net income in the next twelve months as the items being hedged settle. The actual amounts reclassified from Accumulated Other Comprehensive Income to Net Income can differ as a result of market price changes. The maximum term for which the exposure to the variability of future cash flows is being hedged is approximately seven years. SFAS 143 "Accounting for Asset Retirement Obligations" We implemented SFAS 143, "Accounting for Asset Retirement Obligations", effective January 1, 2003 which requires entities to record a liability at fair value for any legal obligations for asset retirements in the period incurred. Upon establishment of a legal liability, SFAS 143 requires a corresponding asset to be established which will be depreciated over its useful life. SFAS 143 requires that a cumulative effect of change in accounting principle be recognized for the cumulative accretion and accumulated depreciation that would have been recognized had SFAS 143 been applied to existing legal obligations for asset retirements. In addition, the cumulative effect of change in accounting principle is favorably affected by the reversal of accumulated removal cost that had previously been recorded for generation that does not qualify as a legal obligation which was collected in depreciation rates by certain formerly regulated subsidiaries. We completed a review of our asset retirement obligations and concluded that at present, we have related legal liabilities for nuclear decommissioning costs for our Cook Plant and our partial ownership in the South Texas Project, as well as liabilities for the retirement of certain ash ponds, wind farms, the U.K. Plants, and certain coal mining facilities. Since we presently recover our nuclear decommissioning costs in our regulated cash flow and thus had existing balances recorded for such nuclear retirement obligations, we recognized the cumulative difference in the amount already provided through rates versus the new methodology of SFAS 143, as a regulatory asset or liability. Similarly, a regulatory asset was recorded for the cumulative effect of certain retirement costs for ash ponds related to our regulated operations. In the first quarter of 2003, we recorded an unfavorable cumulative effect of $45.4 million after tax for our non-regulated operations ($38.0 million related to Ash Ponds in the Utility Operations segment, $7.2 million related to U.K. Plants in the Investments - UK Operations segment and $0.2 million for Wind Mills in the Investments - Other segment). Certain of our operating companies have recorded in Accumulated Depreciation and Amortization, removal costs collected from ratepayers for certain assets that do not have associated legal asset retirement obligations. To the extent that such operating companies have now been deregulated, in the first quarter 2003, we reversed the balance of such removal costs, totaling $287.2 million after tax, from accumulated depreciation which resulted in a net favorable cumulative effect in the first quarter of 2003. However, we did not adjust the balance of such removal costs for our regulated operations, and in accordance with the present method of recovery, will continue to record such amounts through depreciation expense and accumulated depreciation. We estimate that we have approximately $1.2 billion of such regulatory liabilities recorded in Accumulated Depreciation and Amortization as of both June 30, 2003 and December 31, 2002. The net favorable cumulative effect of the change in accounting principle for the six months ended June 30, 2003 consists of the following: Pre-tax After-tax Income (Loss) Income (Loss) ------------ ------------ (in millions) Ash Ponds $(62.8) $(38.0) U.K. Plants, Wind Mills and Coal Operations (11.3) (7.4) Reversal of Cost of Removal 472.6 287.2 ------ ------ Total $398.5 $241.8 ====== ====== We have identified, but not recognized, asset retirement obligation liabilities related to electric transmission and distribution and gas pipeline assets, as a result of certain easements on property on which we have assets. Generally, such easements are perpetual and require only the retirement and removal of our assets upon the cessation of the property's use. The retirement obligation is not estimable for such easements since we plan to use our facilities indefinitely. The retirement obligation would only be recognized if and when we abandon or cease the use of specific easements. The following is a reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations:

Accretion expense is included in Maintenance and Other Operation in our accompanying Consolidated Statements of Operations. As of June 30, 2003 and December 31, 2002, the fair value of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities totaled $778 million and $716 million, respectively, recorded in Other Assets on our Consolidated Balance Sheets. Pro forma net income and earnings per share have not been presented for the quarter ended June 30, 2002 or the years ended December 31, 2002, 2001 and 2000 because the pro forma application of SFAS 143 would result in pro forma net income and earnings per share not materially different from the actual amounts reported for those periods. Rescission of EITF 98-10 In October 2002, the Emerging Issues Task Force of the FASB reached a final consensus on Issue No. 02-3. See New Accounting Pronouncements in Note 1 of the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003) for further information. SFAS 149 "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" On April 30, 2003, the FASB issued Statement No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149 amends SFAS 133 for certain decisions made by the FASB as part of the Derivative Implementation Group process and to incorporate clarifications of the definition of a derivative and which contracts qualify as "normal purchase/normal sale." SFAS 149 also amends certain other existing pronouncements. Except for certain provisions of SFAS 149 discussed below, SFAS 149 is effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The provisions of SFAS 149 relating to decisions cleared by the FASB as part of the Derivative Implementation Group process shall continue to be applied in accordance with their respective effective dates. In addition, certain paragraphs of SFAS 149, which relate to forward purchases and sales of when-issued securities or other securities that do not yet exist, shall be applied to both existing contracts and new contracts entered into after June 30, 2003. We are currently assessing the impact of the adoption of SFAS 149. SFAS 150 "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" SFAS 150 was effective for us on July 1, 2003. SFAS 150 is the result of the first phase of the FASB's project to eliminate from the balance sheet the "mezzanine" presentation of items with characteristics of both liabilities and equity, so that no such items will be presented between liabilities and equity. SFAS 150 requires that the following three types of freestanding financial instruments be reported as liabilities: (1) mandatorily redeemable shares, (2) instruments other than shares that could require the issuer to buy back some of its shares in exchange for cash or other assets and (3) obligations that can be settled with shares, the monetary value of which is either (a) fixed, (b) tied to the value of a variable other than the issuer's shares, or (c) varies inversely with the value of the issuer's shares. Measurement of these liabilities generally is to be at fair value, with the payment or accrual of "dividends" and other amounts to holders reported as interest cost. Upon adoption of the new statement, any measurement change for these liabilities is to be reported as the cumulative effect of a change in accounting principle. We are currently assessing the impact of the adoption of SFAS 150. Beginning with our third quarter 2003 financial statements, $321 million of certain subsidiary obligated, mandatorily redeemable, preferred securities of subsidiary trusts holding solely junior subordinated debentures of such subsidiaries, $83 million of mandatorily redeemable cumulative preferred stock of subsidiaries, and $376 million of equity unit senior notes, all of which are currently given mezzanine presentation, are expected to be reclassified as liabilities on our balance sheet. We are, however, still assessing the ultimate impact of SFAS 150. Future Accounting Changes FASB's standard-setting process is ongoing. Until new standards have been finalized and issued by FASB, we cannot determine the impact on the reporting of our operations that may result from any such future changes. 3. STOCK-BASED COMPENSATION PLANS ------------------------------ We have two stock-based employee compensation plans with outstanding stock options. We account for these plans under the recognition and measurement principles of APB Opinion No. 25, Accounting for Stock Issued to Employees (APB 25) and related Interpretations. No stock-based employee compensation expense is reflected in our earnings, as all options granted under these plans had exercise prices equal to or above the market value of the underlying common stock on the date of grant. We awarded restricted stock units to certain employees in March 2003 which vest in equal one-third increments in January 2004, 2005 and 2006. At each vesting date, shares will be issued at no cost to the employee. In accordance with APB 25, the compensation expense will be expensed over the vesting period of the units. The value of the units was based on a $21.95 per share value at the grant date. The amount of compensation expense recognized during the first and second quarters of 2003 in AEP's Consolidated Statements of Operations was not significant. The following table illustrates the effect on our Net Income (Loss) and earnings (loss) per share as if we had historically applied the fair value recognition provisions of FASB Statement No. 123, "Accounting for Stock-Based Compensation", to stock-based employee compensation awards:

(a) Compensation expense related to restricted units during the second quarter of 2003 was not significant. 4. CUMULATIVE EFFECT OF ACCOUNTING CHANGES --------------------------------------- SFAS 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized, and SFAS 142 now requires that goodwill and intangible assets be tested annually for impairment. The implementation of SFAS 142 resulted in a $350 million after tax net transitional loss in 2002 for the U.K. and Australian operations and is reported in our Consolidated Statements of Operations as a cumulative effect of accounting change. SFAS 143, "Accounting for Asset Retirement Obligations" (see Note 2), was effective on January 1, 2003. In the first quarter of 2003, we recorded $242 million in after-tax income related to the recording of Asset Retirement Obligations in our Consolidated Statements of Operations as a cumulative effect of accounting change. EITF 02-3 rescinds EITF 98-10 and related interpretive guidance. Under EITF 02-3, mark-to-market accounting is precluded for energy trading contracts that are not derivatives pursuant to SFAS 133. The consensus to rescind EITF 98-10 eliminated any basis for recognizing physical inventories at fair value other than as provided by GAAP. The consensus to rescind EITF 98-10 is effective for all new contracts entered into (and physical inventory purchased) after October 25, 2002. The consensus is effective for fiscal periods beginning after December 15, 2002, and applies to all energy trading contracts that existed on or before October 25, 2002 that remain in effect as of the date of implementation, January 1, 2003. Effective January 2003, nonderivative energy contracts entered into prior to October 25, 2002 are required to be accounted for on a settlement basis and inventory is required to be presented at the lower of cost or market. The effect of implementing this consensus is reported as a cumulative effect of an accounting change. Such contracts and inventory are accounted for at fair value through December 31, 2002. Energy contracts that qualify as derivatives were accounted for at fair value under SFAS 133. We have recorded a $49 million after tax charge against net income as Accounting for Risk Management Contracts in our Consolidated Statements of Operations in Cumulative Effect of Accounting Changes in the first quarter of 2003 ($11 million in Utility Operations, $23 million in Investments - Gas Operations and $15 million in Investments - UK Operations segments). This amount will be realized when the positions settle. 5. GOODWILL AND OTHER INTANGIBLE ASSETS ------------------------------------ Goodwill There were no significant changes in the carrying amount of goodwill for the six months ended June 30, 2003. Acquired Intangible Assets The gross carrying amount, accumulated amortization and amortization life by major asset class are shown in the following table:

The software and customer list intangible asset was sold as part of the transfer of the Nordic Trading Business during the second quarter 2003. Intangible asset amortization expense was $1.4 million and $1.0 million for the three months ended June 30, 2003 and June 30, 2002. Intangible asset amortization expense was $2.6 million and $2.0 million for the six months ended June 30, 2003 and June 30, 2002. Estimated aggregate amortization expense is $4.7 million in 2004, $4.6 million in 2005 through 2007, $4.4 million in 2008 and $4.2 million in 2009. Intangible assets subject to amortization are recorded in Other Assets in the Consolidated Balance Sheets. 6. RATE MATTERS ------------ Fuel in SPP As discussed in Note 6 of the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003), in 2001, the PUCT delayed the start of customer choice in the SPP area of Texas. In May 2003, the PUCT ordered that competition would not begin in the SPP areas before January 1, 2007. The PUCT has ruled that TNC fuel factors in the SPP area will be based upon the price-to-beat fuel factors offered by the retail electric provider (REP) in the ERCOT portion of TNC's service territory. TNC filed with the PUCT in 2002 to determine the most appropriate method to reconcile fuel costs in TNC's SPP area. In April 2003, the PUCT issued an order adopting the methodology proposed in TNC's filing, with adjustments, for reconciling fuel costs in its SPP area. The adjustments removed $3.71 per MWH from reconcilable fuel expense. This adjustment will reduce revenues received from TNC's SPP customers by approximately $400,000 annually. These customers are now served by SWEPCo's REP. TNC Fuel Reconciliation In June 2002, TNC filed with the PUCT to reconcile fuel costs and to defer any unrecovered portion applicable to retail sales within its ERCOT service area for inclusion in the 2004 true-up proceeding. This reconciliation for the period of July 2000 through December 2001 will be the final fuel reconciliation for TNC's ERCOT service territory. At December 31, 2001, the under-recovery balance associated with TNC's ERCOT service area was $27.5 million including interest. During the reconciliation period, TNC incurred $293.7 million of eligible fuel costs serving both ERCOT and SPP retail customers. TNC also requested authority to surcharge its SPP customers. TNC's SPP customers will continue to be subject to fuel reconciliations until competition begins in the SPP area. The under-recovery balance at December 31, 2001 for TNC's service within SPP was $0.7 million including interest. As noted above, TNC's SPP customers are now being served by SWEPCo's REP. In March 2003, the Administrative Law Judges (ALJ) in this proceeding filed their Proposal for Decision (PFD). The PFD recommends that TNC's under-recovered retail fuel balance be reduced by approximately $12.5 million. In March 2003, TNC established a reserve of $13 million, including interest, based on the PFD's recommendations. On April 22, 2003, TNC and intervenors in this proceeding filed exceptions to the PFD. On May 28, 2003, the PUCT remanded TNC's final fuel reconciliation to the ALJ to consider several issues. Two of these remand issues could result in additional disallowances. The issues are the sharing of off-system sales margins from AEP's trading activities with customers through the fuel factor for five years per the PUCT's interpretation of the Texas AEP/CSW merger settlement and the inclusion of January 2002 fuel factor revenues and associated costs in the determination of the under-recovery. TNC made a filing on July 15, 2003 addressing the remand issues. The PUCT is proposing that the sharing of off-system sales margins should continue beyond the termination of the fuel factor. This would result in the sharing of margins for an additional three and one half years after the end of the Texas ERCOT fuel factor. Management believes that the Texas merger settlement only provided for sharing of margins during the period fuel and generation costs were regulated by the PUCT and that after a more thorough review of the evidence it is only reasonably possible that the PUCT will determine after the remand proceeding that TNC should share margins after the end of the Texas fuel factor. Due to a provision established in the first quarter, the resolution of the fuel factor issue should have an immaterial impact on results of operations. However, the decision of the PUCT could result in additional income reductions for these issues. It is presently expected that the ALJ's PFD and the PUCT's final decision of these remanded issues will occur in late 2003 or early 2004. In February 2002, TNC received a final order from the PUCT in a fuel reconciliation covering the period July 1997 - June 2000 and reflected the order in its financial statements. This final order had been appealed to the Travis County District Court. In May 2003, the District Court upheld the PUCT's final order. The plaintiffs appealed the District Court's decision to the Third Court of Appeals. TCC Fuel Reconciliation In December 2002, TCC filed with the PUCT to reconcile fuel costs and to defer its over-recovery of fuel for inclusion in the 2004 true-up proceeding. This reconciliation for the period of July 1998 through December 2001 will be the final fuel reconciliation. At December 31, 2001, the over-recovery balance for TCC was $63.5 million including interest. During the reconciliation period, TCC incurred $1.6 billion of eligible fuel and fuel-related expenses. Recommendations from intervening parties were received in April 2003 and hearings were held in May 2003. Intervening parties have recommended disallowances totaling $170 million. In March 2003, the ALJ hearing the TNC final fuel reconciliation, discussed above, issued a PFD in the TNC proceeding. Various issues addressed in TNC's proceeding may also be applicable to TCC's proceeding. Consequently, TCC established a reserve for potential adverse rulings of $27 million during the first quarter of 2003. Based upon the PUCT's remand of certain TNC issues, TCC established an additional reserve of $9 million in the second quarter of 2003. An adverse ruling from the PUCT in excess of the reserves could have a material impact on future results of operations, cash flows and financial condition. Additional information regarding the 2004 true-up proceeding for TCC can be found in Note 7 "Customer Choice and Industry Restructuring". SWEPCo Fuel Reconciliation In June 2003, SWEPCo filed with the PUCT to reconcile fuel costs. This reconciliation covers the period of January 2000 through December 2002. At December 31, 2002, SWEPCo's filing detailed a $2.2 million over-recovery balance including interest. During the reconciliation period, SWEPCo incurred $434.8 million of eligible fuel expense. An adverse ruling from the PUCT could have a material impact on future results of operations, cash flows and financial condition. ERCOT Price-to-Beat (PTB) Fuel Factor Appeal Several parties including the Office of Public Utility Counsel (OPC) and cities served by both TCC and TNC appealed the PUCT's December 2001 orders establishing initial PTB fuel factors for Mutual Energy CPL and Mutual Energy WTU. On June 25, 2003, the District Court ruled in both appeals. The Court ruled in the Mutual Energy WTU case that the PUCT lacked sufficient evidence to include unaccounted for energy in the fuel factor, erred in including unaccounted for energy in the PTB rate based on its treatment in other proceedings and that the PUCT had improperly shifted the burden of proof from the utility to the intervening parties in not adjusting projected generation requirements for loss of load. The Court upheld the initial PTB orders on all other issues. In the Mutual Energy CPL proceeding, the Court ruled that the PUCT should have adjusted projected generation requirements for the loss of load due to retail competition. The Court remanded the cases to the PUCT for further proceedings consistent with its ruling. The amount of unaccounted for energy built into the PTB fuel factors was approximately $2.7 million for Mutual Energy WTU. At this time, management is unable to estimate the potential financial impact related to the loss of load issue. Management will appeal the District Court decisions and believes, based on the advice of counsel, that the PUCT's original decision will ultimately be upheld. If the District Court's decisions are ultimately upheld the PUCT could reduce the PTB fuel factors charged to retail customers in 2002 and 2003 resulting in an adverse effect on future results of operations and cash flows. Unbundled Cost of Service (UCOS) Appeal TCC placed new transmission and distribution rates into effect as of January 1, 2002 based upon an order issued by the PUCT resulting from an UCOS proceeding. TCC requested and received approval of wholesale transmission rates determined in the UCOS proceeding with the FERC. The UCOS proceeding set the regulated wires rates to be effective when retail electric competition began. Regulated delivery charges include the retail transmission and distribution charge, a system benefit fund fee, a nuclear decommissioning fund charge, a municipal franchise fee and a transition charge associated with securitization of regulatory assets. Certain rulings of the PUCT in the UCOS proceeding, including the initial determination of stranded costs, the commencement of TCC's excess earnings refund, regulatory treatment of nuclear insurance and distribution rates charged municipal customers, were appealed to the Travis County District Court by TCC and other parties to the proceeding. The District Court issued a decision on June 16, 2003 upholding the PUCT's UCOS order with one exception. The Court ruled that the refund of the 1999 - 2001 excess earnings solely as a credit to non-bypassable transmission and distribution rates charged to retail electric providers (REP) discriminates against residential and small commercial customers and is unlawful. The distribution rate credit began in January 2002. This decision could potentially affect the PTB rates charged by the AEP REP (Mutual Energy CPL). Mutual Energy CPL was a subsidiary of AEP until December 23, 2002 when it was sold to Centrica. Management estimates that the effect of reducing the PTB rates for the period prior to the sale is approximately $11 million pre-tax. Management has appealed this decision and, based on advise of counsel, believes that it will ultimately prevail on appeal. If the District Court's decision is ultimately upheld on appeal it could have an adverse effect on future results of operations and cash flows. McAllen Rate Review On June 26, 2003, the City of McAllen requested that TCC provide justification showing that its transmission and distribution rates should not be reduced. Other municipalities served by TCC have passed similar rate review resolutions. In Texas, municipalities have original jurisdiction over rates of electric utilities within their municipal limits. Under Texas law, TCC has a minimum of 120 days to provide support for its rates to the municipalities. TCC has the right to appeal any rate change by the municipalities to the PUCT. Pursuant to an agreement with the cities, TCC will file the requested support for its rates with both the cities and the PUCT on November 3, 2003. Management believes that a rate reduction is not justified. Louisiana Fuel Audit As a result of complaints filed by customers, the LPSC is performing an audit of SWEPCo's fuel rates. Five SWEPCo customers filed a suit in the Caddo Parish District Court in January 2003 and filed a complaint with the LPSC. The customers claim that SWEPCo has over charged them for fuel costs since 1975. Management believes that SWEPCo's fuel rates prior to 1999 were proper and have been approved by the LPSC. If the LPSC or the Court rules against SWEPCo, it could have an adverse impact on results of operations and cash flows. FERC Wholesale Fuel Complaints As discussed in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003), certain TNC wholesale customers filed a complaint with FERC alleging that TNC had overcharged them through the fuel adjustment clause for certain purchased power costs since 1997. Negotiations to settle the complaint and update the contracts have resulted in new contracts. Consequently, an offer of settlement was filed at FERC in June 2003 regarding the fuel complaint and new contracts. Management is unable to predict whether FERC will approve this offer of settlement which is not expected to have a significant impact on TNC's financial condition. In March 2002, TNC recorded a provision for refund of $2.2 million before income taxes. TNC anticipates that the provision for refund will be adequate to cover the financial implications resulting from these new contracts. Should FERC fail to approve the settlement and new contracts, the actual refund and final resolution of this matter could differ materially from the provision and may have a negative impact on future results of operations, cash flows and financial condition. Environmental Surcharge Filing In September 2002, KPCo filed with the KPSC to revise its environmental surcharge tariff (annual revenue increase of approximately $21 million) to recover the cost of emissions control equipment being installed at Big Sandy Plant. See NOx Reductions in Note 8. In March 2003, the KPSC granted approximately $18 million of the request. Annual rate relief of $1.7 million was effective in May 2003 and an additional $16.2 million was effective in July 2003. The recovery of such amounts is intended to offset KPCo's cost of compliance with the Clean Air Act. PSO Rate Review In February 2003, the Director of the Oklahoma Corporation Commission (OCC) filed an application requiring PSO to file all documents necessary for a general rate review before August 1, 2003. The required date to file the case was subsequently changed to October 31, 2003. Management is unable to predict the ultimate effect of this review on PSO's rates. PSO Fuel and Purchased Power As discussed in Note 6 of the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003), PSO had a $44 million under-recovery of fuel costs resulting from a reallocation of purchased power costs for periods prior to January 1, 2002. On July 23, 2003, PSO filed with the OCC seeking recovery of the $44 million over an eighteen month time period. A hearing has been scheduled for October 7, 2003. If the OCC does not permit recovery, there will be an adverse effect on results of operations, cash flows and possibly financial condition. Virginia Fuel Factor Filing APCo filed with the Virginia SCC to reduce its fuel factor effective August 1, 2003. The requested fuel rate reduction would be effective for 17 months and is estimated to reduce revenues by $36 million. By order dated July 23, 2003, the Virginia SCC approved APCo's requested fuel factor reduction on an interim basis, subject to further investigation. This fuel factor adjustment will reduce cash flows without impacting results of operations as any over-recovery of fuel costs would be deferred as a regulatory liability. FERC Long-term Contracts In September 2002, the FERC voted to hold hearings to consider requests from certain wholesale customers located in Nevada and Washington to break long-term contracts which they allege are "high-priced". At issue are long-term contracts entered into during the California energy price spike in 2000 and 2001. The complaints allege that AEP sold power at unjust and unreasonable prices. The FERC delayed hearings to allow the parties to hold settlement discussions. In January 2003, the FERC settlement judge assigned to the case indicated that the parties' settlement efforts were not progressing and he recommended that the complaint be placed back on the schedule for a hearing. In February 2003, AEP and one of the customers agreed to terminate their contract. The customer withdrew its FERC complaint and paid $59 million to AEP. As a result of the contract termination, AEP reversed $69 million of unrealized mark-to-market gains previously recorded, resulting in a $10 million pre-tax loss. In a similar complaint, a FERC administrative law judge (ALJ) ruled in favor of AEP and dismissed, in December 2002, a complaint filed by two Nevada utilities. In 2000 and 2001, we agreed to sell power to the utilities for future delivery. In late 2001, the utilities filed complaints that the prices for power supplied under those contracts should be lowered because the market for power was allegedly dysfunctional at the time such contracts were consummated. The ALJ rejected the utilities' complaint, held that the markets for future delivery were not dysfunctional, and that the utilities had failed to demonstrate that the public interest required that changes be made to the contracts. The ALJ's order is preliminary and is subject to review by the FERC. At a hearing held in April 2003, the utilities asked FERC to void the long-term contracts. The FERC will likely rule on the ALJ's order in 2003. Management is unable to predict the outcome of these proceedings or their impact on future results of operations. RTO Formation/Integration Costs With FERC approval, AEP East companies have been deferring costs incurred under FERC orders to form an RTO (the Alliance RTO) or join an existing RTO (PJM). On July 2, 2003, the FERC issued an order approving our continued deferral of both our Alliance formation costs and our PJM integration costs including the deferral of a carrying charge. The AEP East companies have deferred approximately $22 million of RTO formation and integration costs and related carrying charges through June 30, 2003. As a result of the subsequent delay in the integration of AEP's East transmission system into PJM, FERC declined to rule, at this time, on our request to transfer the deferrals to regulatory assets, and to maintain the deferrals until such time as the costs can be recovered from all users of AEP's East transmission system. The AEP East companies will apply for permission to transfer the deferred formation/integration costs to a regulatory asset prior to integration with PJM. In the first quarter of 2003, the state of Virginia enacted legislation preventing APCo from joining an RTO until after June 30, 2004 and only then with the approval of the Virginia SCC. In the second quarter of 2003, the KPSC denied KPCo's request that they approve our joining PJM based in part on a lack of evidence that it would benefit Kentucky retail customers. Management intends to seek a rehearing in Kentucky. Management does not expect the integration with PJM to occur prior to June 30, 2004. In its July 2 order, FERC indicated that it would review the deferred costs for prudency at the time they are transferred to a regulatory asset account and scheduled for amortization and recovery in the open access transmission tariff (OATT) to be charged by PJM. Management believes that the FERC will grant permission for the deferred RTO costs to be amortized and included in the OATT. Whether the amortized costs will be fully recoverable depends upon the state regulatory commissions' treatment of AEP's East companies' portion of the OATT at the time they join PJM. Presently, retail rates are frozen or capped and cannot be increased for retail customers of CSPCo, I&M and OPCo. We intend to apply with FERC seeking permission to delay the amortization of the deferred RTO formation/integration costs until they are recoverable from all users of the transmission system including retail customers. Management is unable to predict the timing of when AEP will join PJM and if upon joining PJM whether FERC will grant a delay of recovery until the rate caps and freezes end. Management intends to seek recovery of the deferred RTO formation/integration costs. If the FERC ultimately decides not to approve a delay or the state commissions deny recovery, future results of operations and cash flows could be adversely affected. FERC Order on Regional Through and Out Rates (RTOR) On July 23, 2003, the FERC issued an order directing PJM and the Midwest ISO to make compliance filings for their respective Open Access Transmission Tariffs to eliminate, by November 1, 2003, the Regional Through and Out Rates (RTOR) on transactions where the energy is delivered within the Midwest ISO and PJM regions. The elimination of the RTORs will reduce the transmission service revenues collected by the RTOs and thereby reduce the revenues received by transmission owners under the RTOs' revenue distribution protocols. The order provided that affected Transmission Owners could file to offset the elimination of these revenues by increasing rates or utilizing a transitional rate mechanism to recover lost revenues that result from the elimination of the RTORs. The FERC also found that the through and out rates of some of the former Alliance RTO Companies, including AEP, may be unjust, unreasonable, and unduly discriminatory or preferential for energy delivered in the Midwest ISO/PJM regions. FERC has initiated an investigation and hearing in regard to these rates. We will make a filing with the FERC supporting the justness and reasonableness of our rates by August 15, 2003. Management at this time is unable to predict the ultimate outcome of this investigation, or the impact on our results of operations and cash flows. 7. CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING ------------------------------------------ As discussed in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003), retail customer choice began in four of the eleven state retail jurisdictions (Michigan, Ohio, Texas and Virginia) in which the AEP domestic electric utility companies operate. The following paragraphs discuss significant events occurring in 2003 related to customer choice and industry restructuring. Ohio Restructuring On June 27, 2002, the Ohio Consumers' Counsel, Industrial Energy Users-Ohio and American Municipal Power-Ohio filed a complaint with the PUCO alleging that CSPCo and OPCo have violated the PUCO's orders regarding implementation of their transition plan and violated other applicable law by failing to participate in an RTO. The complainants seek, among other relief, an order from the PUCO: o suspending collection of transition charges by CSPCo and OPCo until transfer of control of their transmission assets has occurred o pricing standard offer electric generation effective January 1, 2006 at the market price used by CSPCo and OPCo in their 1999 transition plan filings to estimate transition costs and o imposing a $25,000 per company forfeiture for each day AEP fails to comply with its commitment to transfer control of transmission assets to an RTO Due to the FERC's reversal of its previous approval of our RTO filings and state legislative and regulatory developments, CSPCo and OPCo have been delayed in the implementation of their RTO participation plans. We continue to pursue integration of CSPCo, OPCo and other AEP East companies into PJM. In this regard on December 19, 2002, CSPCo and OPCo filed an application with the PUCO for approval of the transfer of functional control over certain of their transmission facilities to PJM. In February 2003, the PUCO consolidated the June complaint with our December application. CSPCo's and OPCo's motion to dismiss the complaint has been denied by the PUCO and the PUCO affirmed that ruling in rehearing. All further action in the consolidated case has been stayed "until more clarity is achieved regarding matters pending at the FERC and elsewhere". Management is unable to predict the timing of the AEP's East companies' participation in PJM, or the outcome of these proceedings before the PUCO. On March 20, 2003, the PUCO commenced a statutorily-required investigation concerning the desirability, feasibility and timing of declaring retail ancillary, metering or billing and collection service supplied to customers within the certified territories of electric utilities a competitive retail electric service. The PUCO sent out a list of questions and set June 6, 2003 and July 7, 2003, as the dates for initial responses and replies, respectively. CSPCo and OPCo filed comments and responses in compliance with the PUCO's schedule. Management is unable to predict the timing or the outcome of this proceeding. The Ohio Act provides for a Development Period during which retail customers can choose their electric power suppliers or have the protection of Default Service at frozen generation rates from the incumbent utility. The Development Period began on January 1, 2001 and will terminate no later than December 31, 2005, but the PUCO may terminate the Development Period for one or more customer classes before that date if it determines either that effective competition exists in the incumbent utility's certified territory or that there is a twenty percent switching rate of the incumbent utility's load by customer class. Following the Development Period, retail customers will receive distribution and transmission service from the incumbent utility whose distribution rates will be approved by the PUCO and whose transmission rates will be approved by the FERC. Retail customers will continue to have the right to choose their electric power suppliers or have the protection of Default Service which must be offered by the incumbent utility at market rates. The PUCO has circulated a draft of proposed rules but has not yet identified the method by which it will determine market rates for Default Service following the Development Period. As provided in the stipulation agreement approved by the PUCO, we are deferring customer choice implementation costs in excess of $40 million. The agreements provide for the deferral of these costs as a regulatory asset until the next distribution base rate case. We have deferred $22 million of such costs. Recovery of these regulatory assets will be subject to PUCO review in our next Ohio distribution rate filings which will not occur until after 2008 for CSPCo and 2007 for OPCo. Management believes that the amounts deferred represent prudently incurred customer choice implementation costs and should be recoverable in future rates, If the PUCO determines that any of the deferred costs are unrecoverable, it would have an adverse impact on future results of operations and cash flows. Texas Restructuring As discussed in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003), on January 1, 2002, customer choice of electricity supplier began in the ERCOT area of Texas. Customer choice has been delayed in other areas of Texas including the SPP area in which SWEPCo operates. In May 2003, the PUCT approved a stipulation that delays competition in the SPP area until at least January 1, 2007. A 2004 true-up proceeding will determine the amount of stranded costs, final fuel balance, net regulatory assets, certain environmental costs, accumulated excess earnings, excess of price-to-beat revenues over market prices subject to certain conditions and limitations (Retail clawback), a true-up of the power costs used in the PUCT's ECOM model for 2002 and 2003 to reflect actual market prices determined through legislatively-mandated capacity auctions (Wholesale capacity auction true-up) and other restructuring issues. The Texas Legislation allows for several alternative methods to be used to value stranded costs in the final 2004 true-up proceeding including the sale or exchange of generation assets, stock valuation or the use of an ECOM model. Only TCC has stranded costs under the Texas Legislation. In late 2002, TCC decided to obtain a market value of generating assets for purposes of determining stranded costs for the 2004 true-up proceeding and filed a plan of divestiture with the PUCT seeking approval of a sales process for all of its generating facilities. Such sales would quantify the actual stranded costs. The amount of stranded costs under this market valuation methodology will be the amount by which net book value of TCC's generating assets, including regulatory assets and liabilities that were not securitized, exceeds the market value of the generation assets as measured by the net proceeds from the sale of the assets. It is anticipated that any such sale will result in significant stranded costs for purposes of TCC's 2004 true-up proceeding. The filing included a request for the PUCT to issue a declaratory order that TCC's 25.2% ownership interest in its nuclear plant, STP, can be sold to value stranded costs. Intervenors to this proceeding, including the PUCT Staff, made filings to dismiss TCC's filing claiming that the PUCT does not have the authority to issue a declaratory order. The intervenors also argued that the proper time to address the sales process is after the plants are sold during the 2004 true-up proceeding. Since the bidding process is not expected to be completed before mid-2004, TCC requested that the 2004 true-up proceeding be scheduled after completion of the divestiture of the generating assets. In March 2003, the PUCT dismissed TCC's divestiture filing, determining that it was more appropriate to address the nuclear asset stranded costs valuation in a rulemaking proceeding. The PUCT approved a rule, in May 2003, that allows the value obtained by selling nuclear assets to be used in determining stranded costs. Since the PUCT also dismissed the request to certify the proposed divestiture plan, the divestiture plan utilized by TCC will still be subject to a review in the 2004 true-up proceedings. The PUCT adopted a rule regarding the timing of the 2004 true-up proceedings scheduling TNC's filing in May 2004 and TCC's filing in September 2004. Texas Legislation also requires that electric utilities and their affiliated power generation companies (PGC) sell at auction in 2002 and 2003 at least 15% of the PGC's Texas jurisdictional installed generation capacity in order to promote competitiveness in the wholesale market through increased availability of generation and liquidity. Actual market power prices received in the state mandated auctions will replace the PUCT's earlier estimates of those market prices used in the ECOM model to calculate the wholesale capacity auction true-up adjustment for TCC for the 2004 true-up proceeding. The decision to determine stranded costs by selling TCC's generating plants and the expectation that the sales price would produce a significant loss/stranded costs instead of using the PUCT's ECOM model estimates, enabled TCC to record in 2002 a $262 million regulatory asset and related revenues which represents the quantifiable amount of the wholesale capacity auction true-up for the year 2002. Through June 30, 2003, TCC recorded an additional $108 million regulatory asset and related revenues for wholesale capacity auction true-up. Prior to the decision to pursue a sale of TCC's generating assets, the PUCT's ECOM estimate prohibited the recognition of the regulatory assets and revenues as they can not be recovered unless there are stranded costs. As discussed above, a defined process is required in order to determine the amount of stranded costs related to generation facilities for the 2004 true-up proceedings. When the divestiture and the 2004 true-up proceeding are completed, TCC can securitize stranded costs that are in excess of current securitized amounts. The annual costs of securitization will be recovered through a non-bypassable rate surcharge by the regulated transmission and distribution (T&D) utility over the life of the securitization bonds. Any stranded costs and other true-up amounts not recovered through the sale of securitization bonds may be recovered through a separate non-bypassable competition transition charge to T&D utility customers. In the event we are unable, after the 2004 true-up proceeding, to recover all or a portion of our generation-related regulatory assets, unrecovered fuel balances, stranded costs, other true-up adjustments and other restructuring related costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition. Arkansas Restructuring In February 2003, Arkansas repealed customer choice legislation originally enacted in 1999. Consequently, SWEPCo's Arkansas operations reapplied SFAS 71 regulatory accounting which had been discontinued in 1999. The reapplication of SFAS 71 had an insignificant effect on results of operations for the first six months of 2003. As a result of reapplying SFAS 71, derivative contract gains/losses for transactions within AEP's traditional marketing area allocated to Arkansas will not affect income until settled. That is, such positions will be recorded on the balance sheet as either a regulatory asset or liability until realized. West Virginia Restructuring APCo reapplied SFAS 71 for its West Virginia (WV) jurisdiction in the first quarter of 2003 after new developments during the quarter prompted an analysis of the probability of restructuring becoming effective. In 2000, the WVPSC issued an order approving an electricity restructuring plan, which the WV Legislature approved by joint resolution. The joint resolution provided that the WVPSC could not implement the plan until the WV legislature made tax law changes necessary to preserve the revenues of state and local governments. In the 2001 and 2002 legislative sessions, the WV Legislature failed to enact the required legislation that would allow the WVPSC to implement the restructuring plan. Due to this lack of legislative activity, the WVPSC closed two proceedings related to electricity restructuring during the summer of 2002. In the 2003 legislative session, the WV Legislature failed to enact the required tax legislation. Also, a March 2003 WV Legislative Bill clarified the jurisdiction of the WVPSC over electric generation facilities in WV. In March 2003, APCo's outside counsel advised us that restructuring in WV was no longer probable and confirmed facts relating to the WVPSC's jurisdiction and rate authority over APCo's WV generation. APCo has concluded that deregulation of the WV generation business is no longer probable and operations in WV meet the requirements to reapply SFAS 71. The result of reapplying SFAS 71 in WV had an insignificant effect on results of operations during the first six months of 2003. As a result, derivative contract gains/losses related to transactions within AEP's traditional marketing area allocated to WV will not affect income until settled. That is, such positions will be recorded on the balance sheet as either a regulatory asset or liability until realized. Positions outside AEP's traditional marketing area will continue to be marked-to-market. 8. COMMITMENTS AND CONTINGENCIES ----------------------------- Power Generation Facility AEP has agreements with Juniper Capital L.P. (Juniper) under which Juniper will develop, construct, and finance a power generation facility (Facility) near Plaquemine, Louisiana and lease the Facility to AEP. Construction of the Facility was begun by Katco Funding, Limited Partnership (Katco), an unrelated unconsolidated special purpose entity, and Katco assigned its interest in the Facility to Juniper in June 2003. Juniper is a limited partnership, unaffiliated and unconsolidated with AEP, formed to construct or otherwise acquire real and personal property for lease to third parties, to manage financial assets and to undertake other activities related to asset financing. Juniper has arranged to finance the Facility with debt financing up to $471 million and equity up to $29 million (approximately 6%) of the Facility's acquisition cost from investors with no relationship to AEP or any of AEP's subsidiaries. Juniper will own the Facility and lease it to AEP after construction is completed. The lease will be treated as an operating lease for financial accounting purposes. Consequently, the Facility and the related obligations are not reported on AEP's consolidated balance sheet. Payments under the operating lease are expected to commence in the first quarter of 2004. AEP will in turn sublease the Facility to Dow Chemical Company (DOW). The use of Juniper allows AEP to limit its risk associated with the Facility once construction has been completed. In addition, the lease allows AEP to utilize certain tax benefits associated with the Facility. AEP is the construction agent for Juniper. Construction is currently scheduled to be completed by the first quarter of 2004, subject to unforeseen events beyond AEP's control. In the event the project is terminated before completion of construction, AEP has the option to either purchase the Facility for 100% of Juniper's acquisition cost (which, in general, is the outstanding debt and equity associated with the Facility) or terminate the project and make a payment to Juniper for 89.9% of project costs. DOW will use a portion of the energy produced by the Facility and sell the excess energy. AEP has agreed to purchase approximately 800 MW of such excess energy from DOW. AEP has a contract to resell that energy to Tractebel Energy Marketing, Inc. (TEM) for a period of 20 years. Beginning May 1, 2003, AEP had certain contractual rights and obligations in connection with providing replacement energy and other products to TEM. TEM has rejected the replacement energy. On June 27, 2003, AEP and TEM signed a "standstill agreement" whereby negotiations will occur up to August 25, 2003. During this negotiation period, no power will be delivered to TEM under the contract, but both parties will retain all rights as if AEP offered the power and TEM rejected it. If the project is not completed by April 30, 2004, TEM may claim that it can terminate the purchase agreement and is owed liquidating damages of approximately $17.5 million. The initial term of the operating lease between Juniper and AEP commences on the commercial operation date (COD) of the Facility and continues for five years or, if earlier, until June 2009. The lease contains extension options and if all extension options were exercised, the total term of the lease would be 30 years. AEP's lease payments to Juniper during the initial term and each extended term are sufficient for Juniper to make required debt payments under Juniper's debt financing associated with the Facility and provide a return on equity to the investors in Juniper. AEP has the right to purchase the Facility for the acquisition cost during the last month of the initial term or on any monthly rent payment date during any extended term. In addition, AEP may purchase the Facility for the acquisition cost at any time during the initial term if AEP has arranged a sale of the Facility to an unaffiliated third party. A purchase of the Facility from Juniper by AEP would not alter DOW's rights to lease the Facility or AEP's contract to purchase energy from DOW. At the end of the anticipated 30-year lease term, AEP may renew the lease at fair market value subject to Juniper's approval, purchase the Facility at its original construction cost, or sell the Facility, on behalf of Juniper, to an independent third party. If the Facility is sold and the proceeds from the sale are insufficient to pay all of Juniper's acquisition costs, AEP may be required to make a payment (not to exceed $377 million) to Juniper of the excess of Juniper's acquisition costs over the proceeds from the sale up to approximately 75% of the project's cost, provided that AEP would not be required to make any payment if AEP has made the additional rental prepayment described below. AEP has guaranteed the obligations of its subsidiaries to Juniper during the construction and post-construction periods. Due to FIN 45, at COD, AEP will be required to record the fair value (approximately $16 million) of this guarantee as a liability with an offsetting asset. As of June 30, 2003, Juniper's project costs for the Facility totaled $441 million, and total costs for the completed Facility are expected to be approximately $500 million. For the 30-year extended lease term, the base lease rental is a variable rate obligation indexed to three-month LIBOR. Consequently as market interest rates increase, the base rental payments under this operating lease will also increase. Annual payments of approximately $16 million represent future minimum payments during the initial term calculated using the indexed LIBOR rate (1.12% at June 30, 2003). An additional rental prepayment (up to $377 million as of June 30, 2003) may be due on June 30, 2004 unless Juniper has refinanced its present debt financing on a long-term basis. The Facility is collateral for the debt obligation of Juniper. Our maximum exposure to loss as a result of its involvement with Juniper is 100% of Juniper's acquisition costs during the construction phase and up to $377 million once the construction is completed. These calculations could change based on the final amount of total costs or changes in interest rates. Maximum loss is deemed to be remote due to the collateralization. As a result of Katco's transfer of its interest in the Facility to Juniper, we will not consolidate Juniper or any portion of the Facility in accordance with FIN 46. Nuclear Plant Outages In April 2003, engineers at STP, during inspections conducted regularly as part of refueling outages, found wall cracks in two bottom mounted instrument guide tubes of STP Unit 1. These cracks have been repaired and the unit is expected to return to service in late summer. Our share of the direct cost of repair was approximately $6 million through June 30, 2003. STP officials are working closely with the NRC to safely return the unit to service. We have commitments to provide power to customers during the outage. Therefore, we will be subject to fluctuations in the market prices of electricity and purchased replacement energy could be a significant cost. In April 2003, both units of Cook Plant were taken offline due to an influx of fish in the plant's cooling water system which caused a reduction in cooling water to essential plant equipment. After repair of damage caused by the fish intrusion, Cook Plant Unit 1 returned to service in May and Unit 2 returned to service in June following completion of a scheduled refueling outage. Federal EPA Complaint and Notice of Violation As discussed in Note 9 of the Combined Notes to Financial Statements in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003) and as discussed in Part II, Item 1 "Legal Proceedings", AEPSC, APCo, CSPCo, I&M, and OPCo have been involved in litigation regarding generating plant emissions under the Clean Air Act. Federal EPA and a number of states alleged APCo, CSPCo, I&M, OPCo and eleven unaffiliated utilities modified certain units at coal-fired generating plants in violation of the Clean Air Act. Federal EPA filed complaints against our 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. Under the Clean Air Act, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components, or other repairs needed for the reliable, safe and efficient operation of the plant. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). In 2001, the District Court ruled claims for civil penalties based on activities that occurred more than five years before the filing date of the complaints cannot be imposed. There is no time limit on claims for injunctive relief. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and intends to vigorously pursue its defense. Management is unable to estimate the loss or range of loss related to the contingent liability for civil penalties under the Clear Air Act proceedings and unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. In the event the AEP System companies do not prevail, any capital and operating costs of additional pollution control equipment that may be required, as well as any penalties imposed, would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates and market prices for electricity. In December 2000, Cinergy Corp., an unaffiliated utility, which operates certain plants jointly owned by CSPCo, reached a tentative agreement with Federal EPA and other parties to settle litigation regarding generating plant emissions under the Clean Air Act. Negotiations are continuing between the parties in an attempt to reach final settlement terms. Cinergy's settlement could impact the operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 (owned 25.4% and 12.5%, respectively, by CSPCo). 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. NOx Reductions Federal EPA issued a NOx Rule requiring substantial reductions in NOx emissions in a number of eastern states, including certain states in which the AEP System's generating plants are located. The NOx Rule has been upheld on appeal. The compliance date for the NOx Rule is May 31, 2004. In 2000, Federal EPA also adopted a revised rule (the Section 126 Rule) granting petitions filed by certain northeastern states under the Clean Air Act. The rule imposes emissions reduction requirements comparable to the NOx Rule beginning May 1, 2003, for most of our coal-fired generating units. Affected utilities, including certain AEP operating companies, petitioned the D.C. Circuit Court to review the Section 126 Rule. After review, the D.C. Circuit Court instructed Federal EPA to justify the methods it used to allocate allowances and project growth for both the NOx Rule and the Section 126 Rule. AEP subsidiaries and other utilities requested that the D.C. Circuit Court vacate the Section 126 Rule or suspend its May 2003 compliance date. In 2001, the D.C. Circuit Court issued an order tolling the compliance schedule until Federal EPA responds to the Court's remand. On April 30, 2002, Federal EPA announced that May 31, 2004 is the compliance date for the Section 126 Rule. Federal EPA published a notice in the Federal Register on May 1, 2002 advising that no changes in the growth factors used to set the NOx budgets were warranted. In June 2002, our subsidiaries joined other utilities and industrial organizations in seeking a review of Federal EPA's actions in the D.C. Circuit Court. This action is pending. In 2000, the Texas Commission on Environmental Quality adopted rules requiring significant reductions in NOx emissions from utility sources, including TCC and SWEPCo. The compliance requirements began in May 2003 for TCC and begin in May 2005 for SWEPCo. We are installing a variety of emission control technologies to reduce NOx emissions to comply with the applicable state and Federal NOx requirements. This includes selective catalytic reduction (SCR) technology on certain units and non-SCR technologies on a larger number of units. During 2001 SCR technology commenced operations on OPCo's Gavin Plant. Installation of SCR technology on Amos and Mountaineer plants was completed and commenced operation in May 2002. In May 2003, SCR technology installed at Big Sandy and Cardinal plants commenced operation. Construction of SCR technology at certain other AEP generating units continues. Non-SCR technologies have been installed and commenced operation on a number of units across the AEP System and additional units will be equipped with these technologies. Our NOx compliance plan is a dynamic plan that is continually reviewed and revised as new information becomes available on the performance of installed technologies and the cost of planned technologies. Certain compliance steps may or may not be necessary as a result of this new information. Consequently, the plan has a range of possible outcomes. Current estimates indicate that our compliance with the NOx Rule, the Texas Commission on Environmental Quality rule and the Section 126 Rule could result in required capital expenditures in the range of $1.3 billion to $1.7 billion, of which $976 million has been spent through June 30, 2003. Since compliance costs cannot be estimated with certainty, the actual cost to comply could be significantly different than the estimates depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless any capital and operating costs for additional pollution control equipment are recovered from customers, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Enron Bankruptcy On October 15, 2002, certain subsidiaries of AEP filed claims against Enron 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, certain subsidiaries of AEP 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 exclusive right to use the referenced facility is for a term of 30 years, with a renewal right for another 20 years and includes the use of the Bammel storage facility and the appurtenant pipelines. We have engaged in preliminary discussions with Enron concerning the possible purchase of the Bammel storage facility and related assets, the possible resolution of outstanding issues between AEP and Enron relating to our acquisition of HPL and the possible resolution of outstanding energy trading issues. We are unable to predict whether these discussions will lead to an agreement on these subjects. If these discussions do not lead to an agreement, there may be a dispute with Enron concerning our ability to continue utilization of the Bammel storage facility and certain appurtenant pipelines under the existing agreements. 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 exclusive 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. HPL also filed a motion to dismiss. Management is unable to predict the outcome of this lawsuit or its impact on our financial position, results of operations and cash flows. During 2002 and 2001, we expensed a total of $53 million ($34 million net of tax) for our estimated loss from the Enron bankruptcy. The amount expensed was based on an analysis of contracts where AEP 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 counterparties 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 trading payables owed to various Enron entities against trading receivables due to several AEP subsidiaries. In this regard in July 2003, Enron sent to AEPES a demand for payment of approximately $138 million relating to AEPES' termination of trading contracts which amount does not recognize the right of setoff, discussed above. 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. Shareholder Lawsuits In the fourth quarter of 2002 and the first quarter of 2003, lawsuits alleging securities law violations and seeking class action certification were filed in federal District Court, Columbus, Ohio against AEP, certain AEP executives, and in some of the lawsuits, members of the AEP Board of Directors and certain investment banking firms. The lawsuits claim that we failed to disclose that alleged "round trip" trades resulted in an overstatement of revenues, that we failed to disclose that our traders falsely reported energy prices to trade publications that published gas price indices and that we failed to disclose that we did not have in place sufficient management controls to prevent round trip trades or false reporting of energy prices. The plaintiffs seek recovery of an unstated amount of compensatory damages, attorney fees and costs. The Court has appointed a lead plaintiff and allowed the lead plaintiff the opportunity to file an amended complaint. Also, in the first quarter of 2003, a lawsuit making essentially the same allegations and demands was filed in state Common Pleas Court, Columbus, Ohio against AEP, certain executives, members of the Board of Directors and our independent auditor. We removed this case to federal District Court in Columbus. The case is pending on plaintiff's motion to remand. We intend to vigorously defend against these actions. In the fourth quarter of 2002, two shareholder derivative actions were filed in state court in Columbus, Ohio against AEP and its Board of Directors alleging a breach of fiduciary duty for failure to establish and maintain adequate internal controls over our gas trading operations. Also, in the fourth quarter of 2002 and the first quarter of 2003, three lawsuits were filed against AEP, certain executives and AEP's Employee Retirement Income Security Act (ERISA) Plan Administrator alleging violations of ERISA in the selection of AEP stock as an investment alternative and in the allocation of assets to AEP stock. The ERISA actions are pending in federal District Court, Columbus, Ohio. The derivative actions and the ERISA actions are in the initial pleading stage. We intend to vigorously defend against these actions. California Lawsuit In November 2002, the Lieutenant Governor of California filed a lawsuit in Los Angeles County, California Superior Court against forty energy companies, including AEP, and two publishing companies alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. This case is in the initial pleading stage and all defendants have filed motions to dismiss. The plaintiff has moved to dismiss us and has stated an intention to amend the complaint to add an AEP subsidiary as a defendant. We intend to vigorously defend against this action. Texas Commercial Energy, LLP Lawsuit Texas Commercial Energy, LLP (TCE), a Texas REP, has filed a lawsuit in federal District Court in Corpus Christi, Texas against us and four AEP subsidiaries, certain unaffiliated energy companies and ERCOT. The action alleges violations of the Sherman Antitrust Act, fraud, negligent misrepresentation, breach of fiduciary duty, breach of contract, civil conspiracy and negligence. The allegations, not all of which are made against the AEP companies, range from anticompetitive bidding to withholding power. TCE alleges that these activities resulted in price spikes requiring TCE to post additional collateral and ultimately forced it into bankruptcy when it was unable to raise prices to its customers due to fixed price contracts. The suit alleges over $500 million in damages for all defendants and seeks recovery of damages, exemplary damages and court costs. Management believes that the claims against us are without merit. We intend to vigorously defend against the claims. Bank of Montreal Claim In March 2003, Bank of Montreal (BOM) terminated all natural gas trading deals and claimed approximately $34 million was owed to BOM by AEP. In April 2003, we filed a lawsuit against BOM claiming BOM had acted contrary to industry practice in calculating termination and liquidation amounts and that BOM had acknowledged in March 2003 that it owed us approximately $68 million. Alternatively, we are claiming that BOM owes us approximately $45 million. Although management is unable to predict the outcome of this matter, it is not expected to have a material impact on results of operations, cash flows or financial condition. Arbitration of Williams Claim In October 2002, we filed a demand for arbitration with the American Arbitration Association to initiate formal arbitration proceedings in a dispute with the Williams Companies (Williams). The proceeding results from Williams' repudiation of its obligations to provide physical power deliveries to AEP and Williams' failure to provide the monetary security required for natural gas deliveries by AEP. Consequently, both parties claimed default and terminated all outstanding natural gas and electric power trading deals among the various Williams and AEP affiliates. Williams claimed that we owed approximately $130 million in connection with the termination and liquidation of all trading deals. Williams and AEP settled the dispute and we paid $90 million to Williams in June 2003. The resolution of this matter did not have a material impact on results of operations or financial condition as we had accrued the amount paid. Arbitration of PG&E Energy Trading, LLC Claim In January 2003, PG&E Energy Trading, LLC (PGET) claimed approximately $22 million was owed by AEP in connection with the termination and liquidation of all trading deals. In February 2003, PGET initiated arbitration proceedings. In July 2003, AEP and PGET agreed to a settlement and we paid approximately $11 million to PGET. The settlement payment did not have a material impact on results of operations, cash flows or financial condition as the payment approximated our recorded liability. Energy Market Investigation As discussed in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003), AEP and other energy market participants received data requests, subpoenas and requests for information from the FERC, the SEC, the PUCT, the U.S. Commodity Futures Trading Commission, the U.S. Department of Justice and the California attorney general during 2002. Management responded to the inquiries and provided the requested information and has continued to respond to supplemental data requests in 2003. In March 2003, we received a subpoena from the SEC as part of the SEC's ongoing investigation of energy trading activities. In August 2002, we had received an informal data request from the SEC seeking that we voluntarily provide information. The subpoena sought additional information and is part of the SEC's formal investigation. we responded to the subpoena and will continue to cooperate with the SEC. Management cannot predict what, if any action, any of these governmental agencies may take with respect to these matters. FERC Proposed Standard Market Design In July 2002, the FERC issued its Standard Market Design (SMD) notice of proposed rulemaking which sought to standardize the structure and operation of wholesale electricity markets across the country. Key elements of FERC's proposal included standard rules and processes for all users of the electricity transmission grid, new transmission rules and policies, and the creation of certain markets to be operated by independent administrators of the grid in all regions. The FERC issued a white paper on the proposal in April 2003, in response to the numerous comments FERC received on its proposal. Until the rule is finalized, management cannot predict its effect on cash flows and results of operations. FERC Proposed Security Standards As part of the SMD proposed rulemaking, in July 2002, FERC published for comment proposed security standards. These standards were intended to ensure that all market participants would have a basic security program that would effectively protect the electric grid and related market activities. As proposed, these standards would apply to AEP's power transmission systems, distribution systems and related areas of business. The proposed standards have not been adopted. Subsequently, in 2002, the North American Electric Reliability Council (NERC), with FERC's support, developed a new set of standards to address industry compliance. These new standards closely parallel the initial, proposed FERC standards in both content and compliance time frames, and were approved by the NERC ballot body in June of 2003. We are developing financial requirements for security implementation and compliance with these NERC standards. Since these financial requirements are not yet determined, management cannot predict the impacts of such standards on future results of operations and cash flows. 9. GUARANTEES ---------- In November 2002, the FASB issued FIN 45 which clarifies the accounting to recognize a liability related to issuing a guarantee, as well as additional disclosures of guarantees. This new guidance is an interpretation of SFAS 5, 57, and 107 and a rescission of FIN 34. The initial recognition and initial measurement provisions of FIN 45 were effective on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements of FIN 45 were effective for financial statements of interim or annual periods ending after December 15, 2002. There are no liabilities recorded for guarantees entered into prior to December 31, 2002 in accordance with FIN 45. There are certain liabilities recorded for guarantees entered into subsequent to December 31, 2002. These liabilities are immaterial to AEP. There is no collateral held in relation to any guarantees and there is no recourse to third parties in the event any guarantees are drawn unless specified below. Certain of our subsidiaries have entered into standby letters of credit (LOC) with third parties. These LOCs cover gas and electricity trading contracts, construction contracts, insurance programs, security deposits, debt service reserves, drilling funds and credit enhancements for issued bonds. All of these LOCs were issued by an AEP subsidiary in the subsidiaries' ordinary course of business. TCC issued an LOC for credit enhancement of issued bonds. At June 30, 2003, the maximum future payments of all the LOCs are approximately $163 million with maturities ranging from July 2003 to January 2011. TCC's LOC was for approximately $40.9 million with a maturity date of November 2003. Since we are the parent to all these subsidiaries, we hold all assets of the subsidiaries as collateral. There is no recourse to third parties in the event these letters of credit are drawn. The following subsidiaries have entered into guarantees of third-party obligations: CSW Energy and CSW International have guaranteed 50% of the required debt service reserve of Sweeny Cogeneration (Sweeny), an IPP of which CSW Energy is a 50% owner. The guarantee was provided in lieu of Sweeny funding the debt reserve as a part of a financing. In the event that Sweeny does not make the required debt payments, CSW Energy and CSW International have a maximum future payment exposure of approximately $3.7 million, which expires June 2020. Additionally, AEP Utilities guaranteed 50% of the required debt service reserve for Polk Power Partners, another IPP of which CSW Energy owns 50%. In the event that Polk Power does not make the required debt payments, AEP Utilities has a maximum future payment exposure of approximately $4.7 million, which expires July 2010. In connection with reducing the cost of the lignite mining contract for its Henry W. Pirkey Power Plant, SWEPCo has agreed under certain conditions, to assume the obligations under a revolving credit agreement, capital lease obligations, and term loan payments of the mining contractor, Sabine Mining Company (Sabine). In the event Sabine defaults under any of these agreements, SWEPCo's total future maximum payment exposure is approximately $61 million with maturity dates ranging from June 2005 to February 2012. As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo has agreed to provide guarantees of mine reclamation in the amount of approximately $85 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by a third party miner. At June 30, 2003, the cost to reclaim the mine in 2035 is estimated to be approximately $36 million. This guarantee ends upon depletion of reserves estimated at 2035 plus 6 years to complete reclamation. It is reasonably possible that due to the guarantees and contracts in place with Sabine that SWEPCo will consolidate Sabine in the third quarter of 2003, as a result of the issuance of FIN 46. Upon consolidation, SWEPCo would record the assets, liabilities, depreciation expense, minority interest and debt interest expense of Sabine. SWEPCo would eliminate expenses associated with the mining contract against Sabine's revenues. See Note 8 "Commitments and Contingencies" under Power Generation Facility for disclosure of related guarantees. See Note 13 "Leases" for disclosure of lease residual value guarantees. See Note 14 "Minority Interest in Finance Subsidiary" for disclosure of related guarantees. We entered into several types of contracts, which would require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, our exposure generally does not exceed the sale price. We cannot estimate the maximum potential exposure for any of these indemnifications entered prior to December 31, 2002 due to the uncertainty of future events. In the first and second quarters of 2003, we entered into several sale agreements as discussed in Note 11. These sale agreements include indemnifications with a maximum exposure of approximately $67 million. There are no material liabilities recorded for any indemnifications entered during the first six months of 2003. There are no liabilities recorded for any indemnifications entered prior to December 31, 2002. We lease certain equipment under a master operating lease. Under the lease agreement, the lessor is guaranteed to receive up to 87% of the unamortized balance of the equipment at the end of the lease term. If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, we have committed to pay the difference between the fair market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance. At June 30, 2003, the maximum potential loss for these lease agreements was approximately $27 million assuming the fair market value of the equipment is zero at the end of the lease term. 10. SUSTAINED EARNINGS IMPROVEMENT INITIATIVE ----------------------------------------- In response to difficult conditions in our business, a Sustained Earnings Improvement (SEI) initiative was undertaken company-wide in the fourth quarter of 2002, as a cost-saving and revenue-building effort to build long-term earnings growth. Termination benefits expense relating to 1,120 terminated employees totaling $75.4 million pre-tax was recorded in the fourth quarter of 2002. Of this amount, we paid $9.5 million and $51.2 million to these terminated employees in the fourth quarter of 2002 and the first quarter of 2003, respectively. Substantially all SEI related payments have been made as of June 30, 2003. The termination benefits expense was classified as Maintenance and Other Operation expense on our Consolidated Statements of Operations. No additional termination benefits expense related to the SEI initiative was recorded during the first and second quarters of 2003. 11. DISPOSITIONS, DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE -------------------------------------------------------------- DISPOSITIONS First Quarter 2003 Dispositions We completed the sales of C3 Communications, Mutual Energy Service Company, LLC, our water heater rental program assets and our interest in AEP Gas Power Systems, LLC. The impact on our results of operations for the six months ended June 30, 2003 was not significant. Newgulf Facility We completed the sale of the Newgulf facility during the second quarter of 2003 and the impact on earnings was not significant. Newgulf's Property, Plant and Equipment, net of accumulated depreciation, was classified on our Consolidated Balance Sheets as held for sale at December 31, 2002. See the tables at the end of the Assets Held for Sale section for more detailed information. Nordic Trading The transfer of the Nordic Trading business, including its trading portfolio, to new owners was completed during the second quarter of 2003 and the impact on earnings during the second quarter of 2003 was not significant. The assets and liabilities of Nordic Trading were classified on our Consolidated Balance Sheets as held for sale at December 31, 2002. See the tables at the end of the Assets Held for Sale section for more detailed information. DISCONTINUED OPERATIONS The results of operations of the entities shown below, affecting AEP, have been classified as Discontinued Operations for all periods presented. The assets and liabilities of Pushan Power Plant and Eastex were aggregated on our Consolidated Balance Sheets as Assets Held for Sale and Liabilities Held for Sale (see table at the end of the Assets Held For Sale section below for more detailed information): For the quarter ended June 30, 2003 and 2002:

ASSETS HELD FOR SALE As discussed in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003), during 2002, we recorded an estimated loss on disposal of assets held for sale. The following provides an update of those assets still held for sale. Eastex We currently anticipate that the sale of assets will be completed by the end of 2003. Results of operations of Eastex have been reclassified as Discontinued Operations in accordance with SFAS 144. The assets and liabilities of Eastex have been included on our Consolidated Balance Sheets as held for sale. See the tables at the end of this section for more detailed information. Pushan Power Plant We currently anticipate that negotiations to sell our interest in the Pushan Power Plant (Pushan) in Nanyang, China to one of the minority interest partners will be completed by the second quarter of 2004. This anticipated closing date is later than originally expected due to several unusual circumstances including the SARS outbreak. Results of operations of Pushan have been reclassified as Discontinued Operations in accordance with SFAS 144. The assets and liabilities of Pushan have been classified on our Consolidated Balance Sheets as held for sale. See the tables at the end of this section for more detailed information. Excess Equipment In November 2002, as a result of a cancelled development project, we obtained title to a surplus gas turbine generator. We have been unsuccessful in finding potential buyers of the unit, including its own internal generation operators, due to an over-supply of generation equipment available for sale. Sale of the turbine is currently still projected before the end of 2003. The Other Assets have been classified on our Consolidated Balance Sheets as held for sale. See the tables at the end of this section for more detailed information. Excess Real Estate In the fourth quarter of 2002, we began to market an under-utilized office building in Dallas, TX obtained through the merger with CSW. We currently anticipate the sale of the facility to be completed by the end of 2003. The property asset has been classified on our Consolidated Balance Sheets as held for sale. See the tables at the end of this section for more detailed information. The assets and liabilities of the entities held for sale at June 30, 2003 and December 31, 2002 are as follows:

12. BUSINESS SEGMENTS ----------------- Our segments and their related business activities are as follows: Utility Operations o Domestic generation of electricity for sale to retail and wholesale customers o Domestic electricity transmission and distribution o Parent company, which includes corporate related expenditures, interest income and interest expense Investments - Gas Operations o Gas pipeline and storage services Investments - UK Operations o International generation of electricity for sale to wholesale customers Investments - Other o Coal mining, bulk commodity barging operations and other energy supply businesses The tables below present segment information for the six months ended June 30, 2003 and 2002. These amounts include certain estimates and allocations where necessary.

(a) Reconciling adjustments for Total Assets include Assets Held for Sale and/or Assets of Discontinued Operations. 13. LEASES ------ OPCo has entered into an agreement with JMG Funding LLP (JMG), an unrelated unconsolidated special purpose entity. JMG has a capital structure of which 3% is equity from investors with no relationship to AEP or any of its subsidiaries and 97% is debt from pollution control bonds and other bonds. JMG was formed to design, construct and lease the Gavin Scrubber for the Gavin Plant to OPCo. JMG owns the Gavin Scrubber and leases it to OPCo. The lease is accounted for as an operating lease. Payments under the operating lease are based on JMG's cost of financing (both debt and equity) and include an amortization component plus the cost of administration. OPCo and AEP do not have an ownership interest in JMG and do not guarantee JMG's debt. At any time during the lease, OPCo has the option to purchase the Gavin Scrubber for the greater of its fair market value or adjusted acquisition cost (equal to the unamortized debt and equity of JMG) or sell the Gavin Scrubber. The initial 15-year lease term is non-cancelable. At the end of the initial term, OPCo can renew the lease, purchase the Gavin Scrubber (terms previously mentioned), or sell the Gavin Scrubber. In case of a sale at less than the adjusted acquisition cost, OPCo must pay the difference to JMG. The use of JMG allows OPCo to enter into an operating lease while keeping the tax benefits otherwise associated with a capital lease. As of June 30, 2003, AEP has determined that OPCo will consolidate JMG in the third quarter of 2003 as a result of the issuance of FIN 46. Upon consolidation, OPCo will record the assets, liabilities, depreciation expense, minority interest and debt interest expense of JMG. OPCo will eliminate operating lease expense against JMG's rental revenues. As of June 30, 2003, the Company is still reviewing the impact of the consolidation, but will have to record the cumulative effect (net of tax) due to a change in accounting principle. OPCo's maximum exposure to loss as a result of its involvement with JMG is approximately $460 million of outstanding debt and equity of JMG as of June 30, 2003. On March 31, 2003, OPCo made a prepayment of $90 million under this operating lease structure. AEP recognizes lease expense on a straight-line basis over the remaining lease term, in accordance with SFAS 13 "Accounting for Leases." The asset will be amortized over the remaining lease term, which ends in the first quarter of 2010. See Note 8 "Commitments and Contingencies" under Power Generation Facility for discussion of its lease. In June 2003, we entered into an agreement with an unrelated, unconsolidated leasing company to lease 875 coal-transporting aluminum railcars. The lease has an initial term of five years and may be renewed for up to three additional five-year terms, for a maximum of twenty years. We intend to renew the lease for the full twenty years. At the end of each lease term, we may (a) renew for another five-year term, not to exceed a total of twenty years, (b) purchase the railcars for the purchase price amount specified in the lease, projected at the lease inception to be the then fair market value, or (c) return the railcars and arrange a third party sale (return-and-sale option). The lease is accounted for as an operating lease with the future payment obligations included in the annual lease footnote. This operating lease agreement allows us to avoid a large initial capital expenditure, and to spread our railcar cost evenly over the expected twenty-year usage period. In addition, the lease allows us to take the income tax benefits otherwise associated with ownership. Under the lease agreement, the lessor is guaranteed that the sale proceeds under the return-and-sale option discussed above will equal at least a lessee obligation amount specified in the lease, which declines over time from approximately 86% to 77% of the projected fair market value of the equipment. At June 30, 2003, the maximum potential loss was approximately $31.5 million ($20.5 million net of tax) assuming the fair market value of the equipment is zero at the end of the current lease term. The railcars are subleased for one year to an unaffiliated company under an operating lease. The sublessee may renew the lease for up to four additional one-year terms. 14. MINORITY INTEREST IN FINANCE SUBSIDIARY --------------------------------------- In August 2001, AEP formed AEP Energy Services Gas Holding Co. II, LLC (SubOne) and Caddis Partners, LLC (Caddis). SubOne is a wholly owned consolidated subsidiary of AEP that was capitalized with the assets of Houston Pipe Line Company and Louisiana Intrastate Gas Company (AEP subsidiaries) and $321.4 million of AEP Energy Services Gas Holding Company (AEP Gas Holding is an AEP subsidiary and parent of SubOne) preferred stock, that was convertible into AEP common stock at market price on a dollar-for-dollar basis. Caddis was capitalized with $2 million cash and a subscription agreement that represents an unconditional obligation to fund $83 million from SubOne for a managing member interest and $750 million from Steelhead Investors LLC (Steelhead) for a non-controlling preferred member interest. As managing member, SubOne consolidates Caddis. Steelhead is an unconsolidated special purpose entity and had an original capital structure of $750 million of which 3% is equity from investors with no relationship to AEP or any of its subsidiaries and 97% is debt from a syndicate of banks. The $750 million invested in Caddis by Steelhead was loaned to SubOne. This intercompany loan to SubOne is due August 2006. On May 9, 2003, SubOne borrowed $225 million from AEP and used the proceeds to reduce the outstanding balance of the loan from Caddis, which Caddis used to reduce the preferred interest held by Steelhead. This payment eliminated the convertible preferred stock of AEP Gas Holding and the stock price trigger. The use of Steelhead originally allowed AEP to limit its risk associated with Houston Pipe Line Company and Louisiana Intrastate Gas Company. Under the provisions of the Caddis formation agreements, Steelhead receives a quarterly preferred return equal to an adjusted floating reference rate (5.25% and 4.73% for the quarters ended June 30, 2003 and 2002, respectively). Caddis has the right to redeem Steelhead's interest at any time. The credit agreement between Caddis and SubOne contains covenants that restrict certain incremental liens and indebtedness, asset sales, investments, acquisitions, and distributions. The credit agreement also contains covenants that impose minimum financial ratios. Non-performance of these covenants may result in an event of default under the credit agreement. Through June 30, 2003, AEP has complied with the covenants contained in the credit agreement. In addition, a default under any other agreement or instrument relating to AEP and certain subsidiaries' debt outstanding in excess of $50 million is an event of default under the credit agreement. The initial period of Steelhead's investment in Caddis is through August 2006. At the end of the initial period, Caddis will either reset Steelhead's return rate, re-market Steelhead's interests to new investors, redeem Steelhead's interests, in whole or in part including accrued return, or liquidate Caddis in accordance with the provisions of applicable agreements. Steelhead has certain rights as a preferred member in Caddis. Upon the occurrence of certain events, including a default in the payment of the preferred return, Steelhead's rights include forcing a liquidation of Caddis and acting as the liquidator. If Steelhead exercised its rights to force Caddis to liquidate under these conditions, then AEP would evaluate whether to refinance at that time or relinquish the assets that support the intercompany loan to Caddis. Liquidation of Caddis could negatively impact AEP's liquidity. Caddis and SubOne are each a limited liability company, with a separate existence and identity from its members, and the assets of each are separate and legally distinct from AEP. The results of operations, cash flows and financial position of Caddis and SubOne are consolidated with AEP for financial reporting purposes. Steelhead's investment in Caddis and payments made to Steelhead from Caddis are currently reported on AEP's Consolidated Statements of Operations and Consolidated Balance Sheets as Minority Interest in Finance Subsidiary. AEP's maximum exposure to loss as a result of its involvement with Steelhead is a $2 million capital investment, $83 million under the subscription agreement to Caddis for any losses incurred by Caddis and the cash reserve fund balance of approximately $207 million (as of June 30, 2003) due Caddis for default under the intercompany loan agreement. The recourse to AEP for the second quarter will increase in the third quarter 2003 to the full $525 million in order to comply with the covenants. The FASB and other accounting constituencies continue to interpret the application of FIN 46 and SFAS 150. As a result, AEP is continuing to review the application of these new standards as they relate to the Steelhead transaction. 15. FINANCING AND RELATED ACTIVITIES --------------------------------

Other Matters In May 2003, a third party exercised its option to call our $250 million of 5.50% putable callable notes, issued in May 2001, for purchase and remarketing. On May 15, 2003, we issued $300 million of 5.25% senior notes due 2015, a portion of which was an exchange for the $250 million putable callable notes due in 2003. In July 2003, Ohio Power issued the following Senior Unsecured Notes: Principal Due Amount Interest Rate Date ----------- ------------- ---- (in millions) (%) $225 million 4.85% 2014 $225 million 6.375% 2033 Common Stock In March 2003, we issued 56 million shares of common stock at $20.95 per share through an equity offering and received net proceeds of $1,141 million (net of issuance costs of $36 million). Proceeds from the sale of common stock were used to pay down both short-term and long-term debt with the balance being held in cash. AEP GENERATING COMPANY MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS -------------------------------------------------------- AEGCo is engaged in the generation and wholesale sale of electric power to two affiliates under long-term agreements. Operating revenues are derived from the sale of Rockport Plant energy and capacity to two affiliated companies pursuant to FERC approved long-term unit power agreements. The unit power agreements provide for recovery of costs including a FERC approved rate of return on common equity (12.16% annually) and a return on other capital, net of temporary cash investments. Results of Operations --------------------- Net Income increased $50 thousand during the second quarter and decreased $47 thousand in the six month period. The fluctuations in Net Income are a result of terms in the unit power agreements which limit recovery of return on capital related to operating and in-service ratios of the Rockport Plant calculated and adjusted monthly. Operating Income Operating Income was virtually unchanged in the quarter and increased $94 thousand year-to-date reflecting recovery in revenues of increased operating costs in accordance with the unit power agreements. o Operating Revenues increased as a result of increased recoverable expenses, primarily fuel, as net generation increased 14% in the quarter and 30% year-to-date. o Fuel for Electric Generation expense increased due to increased generation in 2003 and higher coal costs. Outages during the first quarter of 2002 reduced the Rockport Plant's availability and generation in 2002. o The decreases in Other Operation and Maintenance expenses are primarily due to higher costs incurred during planned maintenance in 2002. o The decrease in Taxes Other Than Income Taxes reflects a decline in the accrual of real and personal property tax for Indiana for the Rockport Plant, reflecting a favorable change in the tax law effective March 2002. o Income Taxes attributable to operations increased primarily due to state income tax accrual adjustments.

The common stock of AEGCo is wholly owned by AEP. See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $1,186,000 and $1,132,000 and for income taxes was $2,448,000 and $1,217,000 in 2003 and 2002, respectively. See Notes to Respective Financial Statements beginning on page L-1. AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS Results of Operations --------------------- Net Income increased $70 million and $30 million for the year-to-date and second quarter, respectively. The increased income is associated with the recognition of stranded costs in Texas of $70 million and $34 million for the year-to-date and second quarter, respectively. Since REPs are the electricity suppliers to retail customers in the ERCOT area, we sell our generation to the REPs and other market participants and provide transmission and distribution services to retail customers of the REPs in our service territory. As a result of the provision of retail electric service by REPs, effective January 1, 2002, we no longer supply electricity directly to retail customers. The implementation of REPs as suppliers to retail customers has caused a significant shift in our sales as further described below. In December 2002, AEP sold Mutual Energy CPL to an unrelated third party, who assumed the obligations of the affiliated REP including the provision of price-to-beat rates under the Texas Restructuring Legislation. Prior to the sale, during 2002, sales to Mutual Energy CPL were classified as Sales to AEP Affiliates. Subsequent to the sale, energy transactions with Mutual Energy CPL are classified as Electric Generation and delivery charges as Electric Transmission and Distribution. Operating Income Operating Income increased by $69 million for the year-to-date and $32 million for the second quarter due to the following: o Revenues associated with the recovery of stranded costs in Texas, mentioned above, were $108 million for the year-to-date and $52 million for the second quarter (see "Texas Restructuring" in Note 6). o Reliability Must Run (RMR) revenues from ERCOT of $122 million for the year-to-date and $66 million for the second quarter which include fuel recovery (see "Texas Plants" in Note 13 in the Annual Report, as updated by the Current Report on Form 8-K dated May 14, 2003, for discussion of RMR facilities). o Increased sales to REPs for the second quarter consisting of an $11 million increase in delivery revenues offset in part by a decrease of $7 million in generation revenues. o Other generation sales increased $60 million for the year-to-date and $20 million for the second quarter primarily resulting from risk management activities. o Depreciation and Amortization expense decreased $7 million for the year-to-date and $9 million for the second quarter due mainly to decreases resulting from ARO (see Note 2), reduced depreciable plant due to the mothballing of certain generating units in 2002 and changes resulting from amortization of regulatory assets. o Reduced Taxes Other Than Income Taxes of $9 million for the year-to- date and $4 million for the second quarter resulting from lower property taxes and state gross receipts taxes stemming from deregulation in Texas. The increase in Operating Income was partially offset by: o Net increases in fuel and purchased power to replace portions of the energy from the non-RMR mothballed plants and the unscheduled forced outage at the STP Nuclear Unit (See "Significant Factors" below). KWHs purchased increased 172% while the total cost increased 614% due to higher average prices. This increased purchased power cost was offset by lower generation costs resulting from the reduced generation from the non-RMR mothballed units. o Increases in maintenance expense due to both the forced outage and a scheduled refueling outage in the first quarter at STP. The increase in nuclear maintenance over last year was $12 million for the year-to-date and $7 million for the second quarter. o An increase in provisions for rate refunds of $35 million for the year-to-date and $8 million for the second quarter (see "TCC Fuel Reconciliation" in Note 5). o Decreased revenues from REPs year-to-date consisting of a decrease in delivery revenues of $58 million offset in part by an increase of $51 million for generation revenues. The transition to REPs occurred during January and February of 2002, resulting in the variance for the year. o Income Taxes increased $39 million year-to-date and $15 million for the second quarter due to increases in pre-tax operating book income. Other Impacts on Earnings Net nonoperating income and expense increased $5 million year-to-date primarily due to increased gains from risk management activities. Interest Charges increased $4 million year-to-date and $3 million for the second quarter primarily due to less capitalized interest due to declines in the amount of construction work in process in the current year. Cumulative Effect of Accounting Change This amount represents the one-time after-tax effect of the application of EITF 02-3 (see Note 3). Financial Condition ------------------- Credit Ratings The rating agencies currently have TCC on stable outlook. Our current ratings are as follows: Moody's S&P Fitch ------- --- ----- First Mortgage Bonds Baa1 BBB A Senior Unsecured Debt Baa2 BBB A- In February 2003, Moody's Investor Service (Moody's) completed their review of AEP and its rated subsidiaries. The results of that review included a downgrade of TCC's rating for unsecured debt from Baa1 to Baa2. The completion of this review was a culmination of ratings action started during 2002. With the completion of the reviews, Moody's has placed AEP and its rated subsidiaries on stable outlook. In March 2003, S&P lowered AEP and its subsidiaries senior unsecured ratings from BBB+ to BBB along with the first mortgage bonds of AEP subsidiaries. Cash Flow Cash flows for the six months ended June 30, 2003 and 2002 were as follows:

Operating Activities Cash flow from operating activities increased $228 million from the prior year primarily due to a $70 million increase in net income as explained above and accounts receivables changes related to reduced levels of risk management activities, offset by the non-cash Texas wholesale clawback recorded in 2003. Investing Activities Construction expenditures in 2003 versus 2002 decreased by $8 million. The current year investment expenditures of $56 million were primarily focused on improved service reliability projects for transmission and distribution systems. Financing Activities Net cash flow used for financing activities increased $286 million for the current year versus prior year. Prior year funds were used to pay down term debt and retire common stock, whereas current year proceeds were primarily used to pay down short-term debt. Financing Activity TCC issued $100 million of unsecured senior notes due 2005 at a variable rate, $150 million of unsecured senior notes due 2005 at a coupon of 3.0%, $275 million of unsecured senior notes due 2013 at a coupon of 5.50% and $275 million of unsecured senior notes due 2033 at a coupon of 6.65%. The proceeds from the bond issuances were used to repay a bank facility, short-term debt, $18 million of first mortgage bonds due 2023 at 7.50% and for other corporate purposes. During the first quarter of 2003, TCC retired $16 million of first mortgage bonds at maturity and $32 million of securitization bonds due 2005. See Note 12 for additional information related to financing activity. Significant Factors ------------------- Possible Divestitures In June 2003, we began actively seeking buyers for 4,497 megawatts of unregulated generation capacity in Texas to establish a market price for calculation of stranded cost (see Note 6). The ultimate timing for a disposition of one or more of these assets will depend upon market conditions and the value of any buyer's proposal. If we choose to dispose of these assets, we may realize non-recurring losses in the aggregate that could have a material impact on our results of operations, cash flows and financial condition. Nuclear Plant Outage In April 2003, engineers at STP, during inspections conducted regularly as part of scheduled refueling outages, found wall cracks in two bottom mounted instrument guide tubes of STP Unit 1. These cracks have been repaired and the unit is expected to return to service in late summer. AEP's share of the direct cost of repair is approximately $6 million through June 30, 2003. STP officials are working closely with the NRC to safely return the unit to service. We have commitments to provide power to customers during the outage. Therefore, we will be subject to fluctuations in the market prices of electricity and purchased replacement energy could be a significant cost and could affect our results of operations and financial position. Critical Accounting Policies See "Registrants' Combined Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters - Critical Accounting Policies" in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003) for a discussion of the estimates and judgments required for revenue recognition, the valuation of long-lived assets, the accounting for pension benefits and the impact of new accounting pronouncements. Quantitative And Qualitative Disclosures About Risk Management Activities ------------------------------------------------------------------------- Market Risks Risk management policies and procedures are instituted and administered at the AEP consolidated level for all subsidiary registrants. See complete discussion within AEP's "Qualitative And Quantitative Disclosures About Risk Management Activities" section. The following tables provide information about the risk management activities' effect on this specific registrant. Roll-Forward of MTM Risk Management Contract Net Assets This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next. Roll-Forward of MTM Risk Management Contract Net Assets Six Months Ended June 30, 2003 Domestic Power (in thousands) Beginning Balance December 31, 2002 $ 5,414 ----------------------------------- (Gain) Loss from Contracts Realized/Settled During the Period (a) (1,883) Fair Value of New Contracts When Entered Into During the Period (b) - Net Option Premiums Paid/(Received) (c) - Change in Fair Value Due to Valuation Methodology Changes - Effect of 98-10 Rescission 187 Changes in Fair Value of Risk Management Contracts (d) (72) Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e) - ------- Total MTM Risk Management Contract Net Assets 3,646 Net Non-Trading Related Derivative Contracts (1,205) ------- Net Fair Value of Risk Management and Derivative Contracts June 30, 2003 $ 2,441 ======= (a)"(Gain) Loss from Contracts Realized/Settled During the Period" includes realized gains from risk management contracts and related derivatives that settled during 2003 that were entered into prior to 2003. (b) The "Fair Value of New Contracts When Entered Into During the Period" represents the fair value of long-term contracts entered into with customers during 2003. The fair value is calculated as of the execution of the contract. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location. (c)"Net Option Premiums Paid/(Received)" reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered into in 2003. (d)"Changes in Fair Value of Risk Management Contracts" represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, etc. (e)"Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions" relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions. Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information: o The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally). o The maturity, by year, of our net assets/liabilities, giving an indication of when these MTM amounts will settle and generate cash.

(a)"Prices Provided by Other External Sources - OTC Broker Quotes" reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms. (b)"Prices Based on Models and Other Valuation Methods" if there is absence of pricing information from external sources, modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the Modeled category varies by market. Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet The table provides detail on effective cash flow hedges under SFAS 133 included in the balance sheet. The data in the table will indicate the magnitude of SFAS 133 hedges we have in place. (However, given that under SFAS 133 only cash flow hedges are recorded in AOCI, the table does not provide an all-encompassing picture of our hedging activity). The table also includes a roll-forward of the AOCI balance sheet account, providing insight into the drivers of the changes (new hedges placed during the period, changes in value of existing hedges and roll-off of hedges). Information on energy merchant activities is presented separately from interest rate, foreign currency risk management activities and other hedging activities. In accordance with GAAP, all amounts are presented net of related income taxes. Total Other Comprehensive Income (Loss) Activity Six Months Ended June 30, 2003 Domestic Power -------- (in thousands) Accumulated OCI, December 31, 2002 $ (36) ---------------------------------- Changes in Fair Value (a) (767) Reclassifications from OCI to Net Income (b) 20 ----- Accumulated OCI Derivative Gain (Loss) June 30, 2003 $(783) ===== (a) "Changes in Fair Value" shows changes in the fair value of derivatives designated as hedging instruments in cash flow hedges during the reporting period not yet reclassified into net income, pending the hedged item's affecting net income. Amounts are reported net of related income taxes. (b) "Reclassifications from OCI to Net Income" represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes above. The portion of cash flow hedges in Accumulated OCI expected to be reclassified to earnings during the next twelve months is a $532 thousand loss. Credit Risk The counterparty credit quality and exposure for the registrant subsidiaries is generally consistent with that of AEP. VaR Associated with Energy Trading Contracts The following table shows the end, high, average, and low market risk as measured by VaR for year-to-date:

The common stock of TCC is owned by a wholly owned subsidiary of AEP See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $72,918,000 and $40,588,000 and for income taxes was $7,803,000 and $44,322,000 in 2003 and 2002, respectively. See Notes to Respective Financial Statements beginning on page L-1. AEP TEXAS NORTH COMPANY MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS Results of Operations --------------------- Net Income increased $23 million year-to-date and $17 million for the second quarter primarily due to Reliability Must Run (RMR) margins from ERCOT (see "Texas Plants" in Note 13 in the Annual Report, as updated by the Current Report on Form 8-K dated May 14, 2003, for discussion of RMR facilities) and increased revenues from generation sales, mostly to REPs in Texas. Since REPs are the electricity suppliers to retail customers in the ERCOT area, we sell our generation to the REPs and other market participants and provide transmission and distribution services to retail customers of the REPs in our service territory. As a result of the provision of retail electric service by REPs effective January 1, 2002, we no longer supply electricity directly to retail customers. The implementation of REPs as suppliers to retail customers has caused a significant shift in our sales as further described below. In December 2002, AEP sold Mutual Energy WTU to an unrelated third party, who assumed the obligations of the affiliated REP, including the provision of price-to-beat rates under the Texas Restructuring Legislation. Prior to the sale, during 2002, sales to Mutual Energy WTU were classified as Sales to AEP Affiliates. Subsequent to the sale, energy transactions with Mutual Energy WTU are classified as Electric Generation and delivery charges as Electric Transmission and Distribution. Operating Income Operating Income increased by $17 million year-to-date and $18 million for the second quarter primarily due to the following: o RMR stand-by revenues from ERCOT of $7 million year-to-date and $4 million for the second quarter. o Increased revenues from ERCOT for scheduling and balancing services of $13 million year-to-date and $3 million for the second quarter. o Reduction in provision for rate refunds in the second quarter of $3 million. o Reduced Other Operation and Maintenance expenses of $7 million year-to-date and $4 million for the second quarter resulting from the Sustained Earnings Improvement program, reduced expenses for employee benefits due to revaluations, and reduced AEPSC billings for customer-related charges. o Reduced Depreciation and Amortization of $3 million year-to-date and $1 million for the second quarter mainly from the mothballing of several plants in late 2002. o Reduced Taxes Other Than Income Taxes of $3 million year-to-date and $2 million for the second quarter due mainly to declines in gross receipts and property taxes due in large part to the taxable revaluation of plants. The increase in Operating Income was partially offset by: o Increased Income Tax Expense (Credit) of $12 million for the year-to-date and $10 million for the second quarter due to increases in pre-tax operating book income. o Increased provision for rate refunds for the year-to-date of $9 million (see "TNC Fuel Reconciliation" in Note 5). o Increased fuel and purchased power expenses of $30 million year-to-date and $12 million for the second quarter due mainly to higher prices resulting from increased natural gas prices. KWH generation decreased due to the mothballing of several plants in late 2002 and KWH purchases increased to compensate for the mothballing of plants. Other Impacts on Earnings Net nonoperating income and expense increased $3 million year-to-date primarily due to a $1 million increase in income from significantly higher levels of line construction work for others and a $4 million increase in income from risk management activities. Cumulative Effect of Accounting Changes The Cumulative Effect of Accounting Changes is due to a one-time after-tax impact of adopting SFAS 143 (see Note 3). Financial Condition ------------------- Credit Ratings The rating agencies currently have TNC on stable outlook. Our current ratings are as follows: Moody's S&P Fitch ------- --- ----- First Mortgage Bonds A3 BBB A Senior Unsecured Debt Baa1 BBB A- In February 2003, Moody's Investor Service (Moody's) completed their review of AEP and its rated subsidiaries. TNC had its mortgage bond debt downgraded from A2 to A3. The completion of this review was a culmination of ratings action started during 2002. In March 2003, S&P lowered AEP and its subsidiaries senior unsecured ratings from BBB+ to BBB along with the first mortgage bonds of AEP subsidiaries. Financing Activities We issued $225 million of unsecured senior notes due 2013 at a coupon of 5.50%. The proceeds from the bond issuance were used to repay an April 2003 bank facility, short-term debt and other corporate purposes. See Note 12 for additional information related to financing activity. Critical Accounting Policies See "Registrants' Combined Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters - Critical Accounting Policies" in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003) for a discussion of the estimates and judgments required for revenue recognition, the valuation of long-lived assets, the accounting for pension benefits and the impact of new accounting pronouncements. Quantitative And Qualitative Disclosures About Risk Management Activities ------------------------------------------------------------------------- Market Risks Risk management policies and procedures are instituted and administered at the AEP consolidated level for all subsidiary registrants. See complete discussion within AEP's "Qualitative And Quantitative Disclosures About Risk Management Activities" section. The following tables provide information about the risk management activities' effect on this specific registrant. Roll-Forward of MTM Risk Management Contract Net Assets This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next. Roll-Forward of MTM Risk Management Contract Net Assets Six Months Ended June 30, 2003 Domestic Power -------------- (in thousands) Beginning Balance December 31, 2002 $2,043 ----------------------------------- (Gain) Loss from Contracts Realized/Settled During the Period (a) (160) Fair Value of New Contracts When Entered Into During the Period (b) - Net Option Premiums Paid/(Received) (c) - Change in Fair Value Due to Valuation Methodology Changes - Effect of 98-10 Rescission 20 Changes in Fair Value of Risk Management Contracts (d) 2,392 Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e) 673 ------ Total MTM Risk Management Contract Net Assets 4,968 Net Non-Trading Related Derivative Contracts (499) ------ Net Fair Value of Risk Management and Derivative Contracts June 30, 2003 $4,469 ====== (a)"(Gain) Loss from Contracts Realized/Settled During the Period" include realized gains from risk management contracts and related derivatives that settled during 2003 that were entered into prior to 2003. (b) The "Fair Value of New Contracts When Entered Into During the Period" represents the fair value of long-term contracts entered into with customers during 2003. The fair value is calculated as of the execution of the contract. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location. (c) "Net Option Premiums Paid/(Received)" reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered into in 2003. (d)"Changes in Fair Value of Risk Management Contracts" represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, etc. (e)"Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions" relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions. Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information: o The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally). o The maturity, by year, of our net assets/liabilities, giving an indication of when these MTM amounts will settle and generate cash.

(a) "Prices Provided by Other External Sources - OTC Broker Quotes" reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms. (b) "Prices Based on Models and Other Valuation Methods" if there is absence of pricing information from external sources, modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the Modeled category varies by market. Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet The table provides detail on effective cash flow hedges under SFAS 133 included in the balance sheet. The data in the table will indicate the magnitude of SFAS 133 hedges we have in place. (However, given that under SFAS 133 only cash flow hedges are recorded in AOCI, the table does not provide an all-encompassing picture of our hedging activity). The table also includes a roll-forward of the AOCI balance sheet account, providing insight into the drivers of the changes (new hedges placed during the period, changes in value of existing hedges and roll-off of hedges). Information on energy merchant activities is presented separately from interest rate, foreign currency risk management activities and other hedging activities. In accordance with GAAP, all amounts are presented net of related income taxes. Total Other Comprehensive Income (Loss) Activity Six Months Ended June 30, 2003 Domestic Power ----- (in thousands) Accumulated OCI, December 31, 2002 $ (15) ---------------------------------- Changes in Fair Value (a) (317) Reclassifications from OCI to Net Income (b) 8 ------ Accumulated OCI Derivative Gain (Loss) June 30, 2003 $ (324) ====== (a) "Changes in Fair Value" shows changes in the fair value of derivatives designated as hedging instruments in cash flow hedges during the reporting period not yet reclassified into net income, pending the hedged item's affecting net income. Amounts are reported net of related income taxes. (b) "Reclassifications from OCI to Net Income" represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes above. The portion of cash flow hedges in Accumulated OCI expected to be reclassified to earnings during the next twelve months is a $220 thousand loss. Credit Risk The counterparty credit quality and exposure for the registrant subsidiaries is generally consistent with that of AEP. VaR Associated with Energy Trading Contracts The following table shows the end, high, average, and low market risk as measured by VaR for year-to-date:

The common stock of TNC is owned by a wholly owned subsidiary of AEP. See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $5,525,000 and $9,481,000 and for income taxes was $(1,305,000) and $2,408,000 in 2003 and 2002, respectively. See Notes to Respective Financial Statements beginning on page L-1. APPALACHIAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS Results of Operations Net Income for the first half of 2003 increased $69 million over the prior year period primarily due to the Cumulative Effect of Accounting Changes of $77 million recorded in the first quarter of 2003 and improved margins on higher overall sales. These increases were partially offset by a $25 million decrease in Nonoperating Income primarily due to reduced gains from risk management activities. Net Income for the second quarter of 2003 decreased $32 million primarily due to a $15 million increase in capacity charges included in Purchased Electricity from AEP Affiliates and a $15 million decrease in Nonoperating Income primarily due to reduced gains from risk management activities. The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. We, as a member of the AEP Power Pool, share in the revenues and costs of marketing and activities conducted on our behalf by the AEP Power Pool. Our relative share of the AEP Power Pool revenues and expenses increased over the prior periods as a result of our reaching a new peak demand in January 2003, which increased our allocation factor. Operating Income Operating Income for the second quarter of 2003 decreased by $16 million from 2002 primarily due to the following: o An increase in Purchased Electricity from AEP Affiliates of $25 million reflecting the increased capacity charges described above and the increase in our relative share of the AEP Power Pool expenses. o An increase in Maintenance expenses comprised of an increase in power plant maintenance at the Amos and Sporn plants for repairs, combined with an increase in distribution line maintenance due to severe storm damage, for a combined maintenance increase of $9 million. o A decline in retail revenues of $12 million primarily due to decreased residential sales reflecting the mild weather in the second quarter of 2003 and decreased industrial sales reflecting the continued sluggish economy. Cooling degree-days for the quarter decreased 52% from the prior period. The decrease in Operating Income for the second quarter of 2003 was partially offset by: o Higher non-affiliated system sales and Sales to AEP Affiliates reflecting an increase in the volume of AEP Power Pool transactions, as well as our relative share based on the higher allocation factor. o A decrease in income taxes of $11 million primarily due to the decrease in pre-tax operating book income. Operating Income for the first half of 2003 increased $15 million primarily due to the following: o AEP Power Pool sales volume increased over 2002, as well as our relative share based on the higher allocation factor. In addition, our residential MWH increased 8% year-to-date primarily due to the severe winter weather in the first quarter of 2003. o A decrease in Depreciation and Amortization expense of $12 million due primarily to the adoption of SFAS 143 (see Note 2). Additionally, we have reduced depreciation and amortization expense related to the amortization of generation related regulatory assets over the transition period due to the return to SFAS 71 for the West Virginia jurisdiction in the first quarter of 2003. The increase in Operating Income for the first half of 2003 was partially offset by: o An increase of $45 million in power costs primarily due to a year-over-year increase of $23 million in capacity charges and the increase in our relative share of AEP Power Pool expenses. o An increase in Maintenance expense of $16 million, due primarily to increased maintenance at Amos and Sporn plants and maintenance of overhead lines required due to the severe storm damage in 2003. Other Impacts on Earnings Nonoperating Income decreased $15 million and $25 million for the quarter and six months ended June 30, 2003, respectively, primarily due to a decrease in gains from risk management activities. The decreases in Nonoperating Income Tax Expense for both periods were a result of the decreases in Nonoperating Income. Interest Charges increased $6 million and $8 million for the quarter and six months ended June 30, 2003, respectively, primarily due to the effects of the refinancing activities. (See Financing Activities). Cumulative Effect of Accounting Changes The Cumulative Effect of Accounting Changes is due to the implementation of SFAS 143 and EITF 02-03 (see Notes 2 and 3). Financial Condition ------------------- Credit Ratings The rating agencies currently have us on stable outlook. Current ratings are as follows: Moody's S&P Fitch ------- --- ----- First Mortgage Bonds Baa1 BBB A- Senior Unsecured Debt Baa2 BBB BBB+ In February 2003, Moody's Investors Service (Moody's) completed their review of AEP and its rated subsidiaries. The results of that review included a downgrade of our rating for unsecured debt from Baa1 to Baa2. The completion of this review was a culmination of ratings action started during 2002. In March 2003, S&P lowered AEP and its subsidiaries senior unsecured ratings from BBB+ to BBB along with the first mortgage bonds of AEP subsidiaries. Cash Flow Cash flows for six months ended June 30, 2003 and 2002 were as follows:

Operating Activities Cash flow from operating activities increased $141 million primarily due to increases in various accounts receivable balances in the six months ended June 30, 2003. Investing Activities Construction expenditures in 2003 versus 2002 decreased $14 million. The current year expenditures of $115 million were focused on improved service reliability for transmission and distribution, as well as environmental upgrades. Financing Activities During the first half of 2003, we had greater net retirements of long-term debt and advances to affiliates over last year. Financing Activity In 2003, we redeemed the following bonds: Coupon Or Stated Call Principal Rate Rate Due Date Amounts ----- ---- -------- ------- % % (in millions) - - 8.50 100 2022 $70 7.15 100 2023 20 7.80 103.90 2023 30 7.20 100 2038 100 7.30 100 2038 100 See Note 12 for additional information related to financing activity. Significant Factors ------------------- Federal EPA Complaint and Notice of Violation As discussed in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003) and as discussed in Part II, Item 1 "Legal Proceedings", APCo and certain affiliated companies have been involved in litigation since 1999 regarding generating plant emissions under the Clean Air Act. Federal EPA and a number of states alleged APCo and certain affiliated companies and eleven unaffiliated utilities made modifications to generating units at coal-fired generating plants in violation of the Clean Air Act. Federal EPA filed complaints against 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. Management is unable to estimate the loss or range of loss related to the contingent liability for civil penalties under the Clear Air Act proceedings and is unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. In the event we do not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates and market prices for electricity. See Note 7 for further discussion. NOx Reductions Federal EPA issued a NOx Rule and adopted a revised rule (the Section 126 Rule) under the Clean Air Act requiring substantial reductions in NOx emissions in a number of eastern states, including certain states in which the AEP System's generating plants are located. The compliance date for the rules is May 31, 2004. We are installing selective catalytic reduction (SCR) technology and non-SCR technology to reduce NOx emissions on certain units to comply with these rules. Our estimates indicate that compliance with the rules could result in required capital expenditures of approximately $462 million. The actual cost to comply could be significantly different than the estimates depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless any capital or operating costs for additional pollution control equipment are recovered from customers, they will have an adverse effect on future results of operations, cash flows and possibly financial condition (see Note 7). Critical Accounting Policies See "Registrants' Combined Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters - Critical Accounting Policies" in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003) for a discussion of the estimates and judgments required for revenue recognition, the valuation of long-lived assets, the accounting for pension benefits and the impact of new accounting pronouncements. Quantitative And Qualitative Disclosures About Risk Management Activities ------------------------------------------------------------------------- Market Risks Risk management policies and procedures are instituted and administered at the AEP consolidated level for all subsidiary registrants. See complete discussion within AEP's "Qualitative And Quantitative Disclosures About Risk Management Activities" section. The following tables provide information about the risk management activities' effect on this specific registrant. Roll-Forward of MTM Risk Management Contract Net Assets This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next. Roll-Forward of MTM Risk Management Contract Net Assets Six Months Ended June 30, 2003 Domestic Power -------------- (in thousands) Beginning Balance December 31, 2002 $ 96,852 ----------------------------------- (Gain) Loss from Contracts Realized/Settled During the Period (a) (39,981) Fair Value of New Contracts When Entered Into During the Period (b) - Net Option Premiums Paid/(Received) (c) 474 Change in Fair Value Due to Valuation Methodology Changes - Effect of 98-10 Rescission (4,664) Changes in Fair Value of Risk Management Contracts (d) 16,072 Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (e) 4,002 -------- Total MTM Risk Management Contract Net Assets 72,755 Net Non-Trading Related Derivative Contracts (3,594) -------- Net Fair Value of Risk Management and Derivative Contracts June 30, 2003 $ 69,161 ======== (a)"(Gain) Loss from Contracts Realized/Settled During the Period" includes realized gains from risk management contracts and related derivatives that settled during 2003 that were entered into prior to 2003. (b) The "Fair Value of New Contracts When Entered Into During the Period" represents the fair value of long-term contracts entered into with customers during 2003. The fair value is calculated as of the execution of the contract. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location. (c) "Net Option Premiums Paid/(Received)" reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered into in 2003. (d)"Changes in Fair Value of Risk Management Contracts" represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, etc. (e)"Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions" relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Operations. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions. Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information: o The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally). o The maturity, by year, of our net assets/liabilities, giving an indication of when these MTM amounts will settle and generate cash.

(a) "Changes in Fair Value" shows changes in the fair value of derivatives designated as hedging instruments in cash flow hedges during the reporting period not yet reclassified into net income, pending the hedged item's affecting net income. Amounts are reported net of related income taxes. (b) "Reclassifications from OCI to Net Income" represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes above. The portion of cash flow hedges in Accumulated OCI expected to be reclassified to earnings during the next twelve months is a $1,894 thousand loss. Credit Risk The counterparty credit quality and exposure for the registrant subsidiaries is generally consistent with that of AEP. VaR Associated with Energy Trading Contracts The following table shows the end, high, average, and low market risk as measured by VaR year-to-date: June 30, 2003 December 31, 2002 (in thousands) (in thousands) End High Average Low End High Average Low --- ---- ------- --- --- ---- ------- --- $346 $2,354 $1,311 $346 $1,289 $3,948 $1,412 $286

The common stock of APCo is wholly owned by AEP. See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $56,152,000 and $47,676,000 and for income taxes was $21,102,000 and $36,585,000 in 2003 and 2002, respectively. See Notes to Respective Financial Statements beginning on page L-1. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS Results of Operations --------------------- Net Income increased $9 million year-to-date including Cumulative Effect of Accounting Changes of $27 million recorded in the first quarter 2003 (see Note 3). Income Before Cumulative Effect decreased $18 million due to reduced income from energy trading outside of the AEP territory. Net Income for the quarter decreased $22 million due to decreased retail sales and lower revenues from energy trading as a result of cooler weather and a continued sluggish economy. CSPCo, as a member of the AEP Power Pool, shares in the revenues and costs of marketing and activities conducted on its behalf by the AEP Power Pool. Operating Income Operating Income decreased by $15 million for the quarter and $5 million year-to-date primarily due to the following: o Milder weather and a slower-than-expected economic recovery resulting in decreased retail revenues of $19 million during the second quarter. Year-to-date retail revenues decreased $10 million due to a slower-than-expected economic recovery and a mild second quarter partially offset by favorable colder weather in the first quarter. o Fuel for Electric Generation increased $7 million year-to-date, due to increased generation and higher coal costs. o Purchased Electricity from AEP Affiliates was $9 million higher in the quarter and $20 million higher year-to-date due to price and volume increases along with higher capacity charges. o Maintenance expense increased $8 million during the quarter and year-to-date due to scheduled boiler overhaul work and maintenance of overhead lines. o Taxes Other Than Income Taxes increased $2 million during the quarter due to higher property taxes. Taxes Other Than Income Taxes increased $7 million year-to-date due to higher property taxes and state excise taxes. The decrease in Operating Income was partially offset by: o Increased AEP Power Pool revenues of $9 million ($7 million to non-affiliated customers and $2 million to affiliated customers) and $29 million ($19 million to non-affiliated customers and $10 million to affiliated customers) for the quarter and year-to-date periods, respectively. o Other Operation expense decreased $9 million during the quarter due to reduced factoring expense from lower interest rates, reduced post retirement benefits expense and reduced legal expenses. o During the quarter, Income Taxes decreased by $7 million due to a decrease in pre-tax operating book income. Other Impacts on Earnings Nonoperating Income, net of expenses and taxes, decreased $8 million for the quarter and $13 million year-to-date primarily due to the following: o Net revenues resulting from risk management activities decreased $11 million and $24 million for the quarter and year-to-date, respectively, as a result of AEP's decision to exit wholesale markets where it does not own assets. o Nonoperating Income Tax Expense decreased $3 million and $10 million for the quarter and year-to-date, respectively, due to a decrease in pre-tax nonoperating book income. Cumulative Effect of Accounting Changes The Cumulative Effect of Accounting Changes is due to the one-time, after-tax impact of adopting SFAS 143 and implementing the requirements of EITF 02-3 (see Notes 2 and 3). Financial Condition ------------------- Credit Ratings The rating agencies currently have us on stable outlook. Current ratings are as follows: Moody's S&P Fitch ------- --- ----- First Mortgage Bonds A3 BBB A Senior Unsecured Debt A3 BBB A- In February 2003, Moody's Investors Service (Moody's) completed their review of AEP and its rated subsidiaries. The completion of this review was a culmination of ratings action started during 2002. In March 2003, S&P lowered AEP and its subsidiaries senior unsecured ratings from BBB+ to BBB along with the first mortgage bonds of AEP subsidiaries. Financing Activities In February 2003, we issued $250 million of unsecured senior notes due 2013 at a coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a coupon of 6.60%. The proceeds from the issuances were used to repay a bank facility, short-term debt and for other corporate purposes. In 2003, we redeemed or repaid the following first mortgage bonds:

See Note 12 for additional information related to financing activity. Significant Factors ------------------- Federal EPA Complaint and Notice of Violation As discussed in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003) and as discussed in Part II, Item 1 "Legal Proceedings", CSPCo, and certain affiliated companies have been involved in litigation since 1999 regarding generating plant emissions under the Clean Air Act. Federal EPA and a number of states alleged CSPCo, certain affiliated companies and eleven unaffiliated utilities made modifications to generating units at coal-fired generating plants in violation of the Clean Air Act. Federal EPA filed complaints against us 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. Management is unable to estimate the loss or range of loss related to the contingent liability for civil penalties under the Clear Air Act proceedings and is unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. In the event we do not prevail, any capital and operating costs of additional pollution control equipment that may be required, as well as any penalties imposed, would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates and market prices for electricity. See Note 7 for further discussion. NOx Reductions Federal EPA issued a NOx Rule and adopted a revised rule (the Section 126 Rule) under the Clean Air Act requiring substantial reductions in NOx emissions in a number of eastern states, including certain states in which the AEP System's generating plants are located. The compliance date for the rules is May 31, 2004. We are installing non-selective catalytic reduction technology to reduce NOx emissions on certain units to comply with these rules. Our estimates indicate that compliance with the rules could result in required capital expenditures of approximately $87 million. The actual cost to comply could be significantly different than the estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless any capital or operating costs for additional pollution control equipment are recovered from customers, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. See Note 7 for further discussion. Critical Accounting Policies See "Registrants' Combined Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters - Critical Accounting Policies" in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003) for a discussion of the estimates and judgments required for revenue recognition, the valuation of long-lived assets, the accounting for pension benefits and the impact of new accounting pronouncements. Quantitative And Qualitative Disclosures About Risk Management Activities ------------------------------------------------------------------------- Market Risks Risk management policies and procedures are instituted and administered at the AEP consolidated level for all subsidiary registrants. See complete discussion within AEP's "Qualitative And Quantitative Disclosures About Risk Management Activities" section. The following tables provide information about the risk management activities' effect on this specific registrant. Roll-Forward of MTM Risk Management Contract Net Assets This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next. Roll-Forward of MTM Risk Management Contract Net Assets Six Months Ended June 30, 2003 Domestic Power CSPCo -------------- ----- (in thousands) Beginning Balance December 31, 2002 $ 65,117 ----------------------------------- (Gain) Loss from Contracts Realized/Settled During the Period (a) (26,884) Fair Value of New Contracts When Entered Into During the Period (b) - Net Option Premiums Paid/(Received) (c) 278 Change in Fair Value Due to Valuation Methodology Changes - Effect of 98-10 Rescission (3,135) Changes in Fair Value of Risk Management Contracts (d) 7,390 Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (e) - --------- Total MTM Risk Management Contract Net Assets 42,766 Net Non-Trading Related Derivative Contracts (2,096) -------- Net Fair Value of Risk Management and Derivative Contracts Ending Balance June 30, 2003 $ 40,670 ======== (a)"(Gain) Loss from Contracts Realized/Settled During the Period" includes realized gains from risk management contracts and related derivatives that settled during 2003 that were entered into prior to 2003. (b) The "Fair Value of New Contracts When Entered Into During the Period" represents the fair value of long-term contracts entered into with customers during 2003. The fair value is calculated as of the execution of the contract. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location. (c) "Net Option Premiums Paid/(Received)" reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered into in 2003. (d)"Changes in Fair Value of Risk Management Contracts" represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, etc. (e)"Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions" relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions. Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information: o The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally). o The maturity, by year, of our net assets/liabilities, giving an indication of when these MTM amounts will settle and generate cash.

(a) "Prices Provided by Other External Sources - OTC Broker Quotes" reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms. (b) "Prices Based on Models and Other Valuation Methods" if there is absence of pricing information from external sources, modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the Modeled category varies by market. Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet The table provides detail on effective cash flow hedges under SFAS 133 included in the balance sheet. The data in the table will indicate the magnitude of SFAS 133 hedges we have in place. (However, given that under SFAS 133 only cash flow hedges are recorded in AOCI, the table does not provide an all-encompassing picture of our hedging activity). The table also includes a roll-forward of the AOCI balance sheet account, providing insight into the drivers of the changes (new hedges placed during the period, changes in value of existing hedges and roll-off of hedges). Information on energy merchant activities is presented separately from interest rate, foreign currency risk management activities and other hedging activities. In accordance with GAAP, all amounts are presented net of related income taxes. Total Other Comprehensive Income (Loss) Activity Six Months Ended June 30, 2003 Domestic Power (in thousands) Accumulated OCI, December 31, 2002 $ (267) ---------------------------------- Changes in Fair Value (a) (1,274) Reclassifications from OCI to Net Income (b) 81 ------- Accumulated OCI Derivative Gain (Loss) June 30, 2003 $(1,460) ======= (a) "Changes in Fair Value" shows changes in the fair value of derivatives designated as hedging instruments in cash flow hedges during the reporting period not yet reclassified into net income, pending the hedged item's affecting net income. Amounts are reported net of related income taxes. (b) "Reclassifications from OCI to Net Income" represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes above. The portion of cash flow hedges in Accumulated OCI expected to be reclassified to earnings during the next twelve months is a $993 thousand loss. Credit Risk The counterparty credit quality and exposure for the registrant subsidiaries is generally consistent with that of AEP. VaR Associated with Energy Trading Contracts The following table shows the end, high, average, and low market risk as measured by VaR for year-to-date:

The common stock of CSPCo is wholly owned by AEP. See Notes to Respective Financial Statements beginning on Page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $18,442,000 and $26,262,000 and for income taxes was $9,245,000 and $32,254,000 in 2003 and 2002, respectively. See Notes to Respective Financial Statements beginning on page L-1. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS Results of Operations --------------------- In the second quarter of 2003, Net Income decreased $9 million reflecting mild spring weather, higher fuel and purchased power costs, a weak economy and the impact of plant availability. Net Income increased $8 million including an unfavorable $3 million Cumulative Effect of Accounting Change in the first six months of 2003 (see Note 3). Net Income (Loss) Before Cumulative Effect of Accounting Change increased $11 million due to an improvement in earnings from retail and AEP Power Pool sales resulting from the interactions of plant availability, colder winter weather and higher margins partially offset by the weak economy. We, as a member of the AEP Power Pool, share in the revenues and costs of marketing and activities conducted on our behalf by the AEP Power Pool. During the second quarter of 2003, both units of Cook Plant were unavailable due to a forced outage which impacted operating income significantly. See significant factors below. Operating Income Operating Income decreased by less than $1 million in the second quarter primarily due to the following: o Increased Fuel for Electric Generation expense of $13 million reflecting an increase in the average cost of fuel. o Increased Purchased Electricity from AEP Affiliates of $10 million due to purchasing replacement power during outages at both units of Cook Plant. o A $7 million decrease in Electric Generation, Transmission and Distribution revenues due to milder weather during the second quarter of 2003. The decrease in Operating Income during the second quarter was partially offset by: o Sales to AEP Affiliates increased by $15 million due to increased capacity revenue and increased sales volume to the AEP Power Pool and western affiliates. o A decline in Other Operation expense of $13 million due to the favorable effect of cost reduction efforts instituted in the fourth quarter of 2002. o A $6 million decrease in Taxes Other Than Income Taxes due to a favorable tax law change in Indiana effective March 2002 and a lower estimate for Cook Plant's assessed value which reduced real and personal property tax estimates on which 2003 accruals are based. Operating Income increased by $28 million year-to-date primarily due to the following: o Electric Generation, Transmission and Distribution revenues increased $38 million due to an increase in sales reflecting a colder winter. o Sales to AEP Affiliates increased by $37 million due to more power being available for sale in 2003 and our share of sales to our western affiliates. In the first quarter of 2002, one unit of Cook plant was shut down for refueling and both Rockport units were down for planned boiler maintenance. o A decline in Other Operation expense of $22 million due to the impact of cost reduction efforts instituted in the fourth quarter of 2002 and having two refueling outages in 2002 verses one refueling outage in 2003. o A $7 million decrease in Taxes Other Than Income Taxes reflects a favorable tax law change in Indiana effective March 2002 and a lower estimate for Cook Plant's assessed value which reduced real and personal property tax estimates on which 2003 accruals are based. The year-to-date increase in Operating Income was partially offset by: o Increased Fuel for Electric Generation expense of $32 million reflecting an increase in the average cost of fuel and increased generation. o Increased Purchased Electricity from AEP Affiliates of $23 million due to higher power purchases from AEGCo in 2003 compared to 2002 when outages at both units of the Rockport Plant decreased available power and purchases of replacement power during the 2003 Cook outages. o Increased Income Taxes of $13 million reflecting an increase in pre-tax income. Other Impacts on Earnings Nonoperating Income decreased $8 million in the second quarter and $22 million year-to-date primarily due to lower margins for power sold outside of AEP's traditional marketing area reflecting reduced demand and AEP's plan to exit those risk management activities in areas outside of its traditional market area. Interest Charges decreased $2 million in the second quarter primarily due to a reduction in outstanding long-term debt of $255 million retired in May 2003. Cumulative Effect of Accounting Change The Cumulative Effect of Accounting Change is due to the implementation of the requirements of EITF 02-3 (see Note 3). Financial Condition ------------------- Credit Ratings The rating agencies currently have us on stable outlook. Current ratings are as follows: Moody's S&P Fitch ------- --- ----- First Mortgage Bonds Baa1 BBB BBB+ Senior Unsecured Debt Baa2 BBB BBB During the first quarter of 2003, Moody's Investors Service (Moody's), Standard & Poors (S&P) and Fitch Rating Service completed their reviews of AEP and its rated subsidiaries. The reviews resulted in downgrades of debt ratings. The completion of these reviews was a culmination of ratings action started during 2002. Cash Flow Cash flows for six months ended June 30, 2003 and 2002 were as follows:

Operating Activities Operating activities during the first half of 2003 provided $80 million more cash than during the first half of 2002 largely due to the year-over-year increase in net income of $8 million and decreases in various Regulatory Assets. Investing Activities Cash flows used for investing activities during the first half of 2003 were $71 million compared to $67 million during the first half of 2002. The primary reason for the year-over-year variance was a construction expenditures increase of $4 million. Financing Activities Financing activities in the first half of 2003 used $71 million more than in the first half of 2002 primarily due to: o Retirement and restructuring of our short-term and long-term debt during 2003. We retired $255 million of long-term debt using short-term debt. o Dividends paid on common stock of $20 million. Common dividends were not distributed in 2002. Financing Activity In May 2003, we retired $255 million of long-term debt prior to maturity using short-term debt as shown in the following table:

See Note 12 for additional information related to financing activity. Significant Factors ------------------- Nuclear Plant Outages In April 2003, both units of Cook Plant were taken offline due to an influx of fish in the plant's cooling water system which caused a reduction in cooling water to essential plant equipment. After repair of damage caused by the fish intrusion, Cook Plant Unit 1 returned to service in May 2003 and Unit 2 returned to service in June 2003 following completion of a scheduled refueling outage. Federal EPA Complaint and Notice of Violation As discussed in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003) and as discussed in Part II, Item 1 "Legal Proceedings", we have been involved in litigation since 1999 regarding generating plant emissions under the Clean Air Act. Federal EPA and a number of states alleged I&M, certain affiliated companies and eleven unaffiliated utilities made modifications to generating units at coal-fired generating plants in violation of the Clean Air Act. Federal EPA filed complaints against us 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. Management is unable to estimate the loss or range of loss related to the contingent liability for civil penalties under the Clear Air Act proceedings and is unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. In the event we do not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates and market prices for electricity. See Note 7 for further discussion. NOx Reductions Federal EPA issued a NOx Rule and adopted a revised rule (the Section 126 Rule) under the Clean Air Act requiring substantial reductions in NOx emissions in a number of eastern states, including certain states in which the AEP System's generating plants are located. The compliance date for the rules is May 31, 2004. We are installing non-selective catalytic reduction technology to reduce NOx emissions on certain units to comply with these rules. Our estimates indicate that compliance with the rules could result in required capital expenditures of approximately $39 million. The actual cost to comply could be significantly different than the estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless any capital or operating costs for additional pollution control equipment are recovered from customers, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. See Note 7 for further discussion. Critical Accounting Policies See "Registrants' Combined Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters - Critical Accounting Policies" in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003) for a discussion of the estimates and judgments required for revenue recognition, the valuation of long-lived assets, the accounting for pension benefits and the impact of new accounting pronouncements. Quantitative And Qualitative Disclosures About Risk Management Activities ------------------------------------------------------------------------- Market Risks Risk management policies and procedures are instituted and administered at the AEP consolidated level for all subsidiary registrants. See complete discussion within AEP's "Qualitative And Quantitative Disclosures About Risk Management Activities" section. The following tables provide information about the risk management activities' effect on this specific registrant. Roll-Forward of MTM Risk Management Contract Net Assets This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next. Roll-Forward of MTM Risk Management Contract Net Assets Six Months Ended June 30, 2003 Domestic Power -------------- (in thousands) Beginning Balance December 31, 2002 $ 70,861 ----------------------------------- (Gain) Loss from Contracts Realized/Settled During the Period (a) (25,361) Fair Value of New Contracts When Entered Into During the Period (b) - Net Option Premiums Paid/(Received) (c) 298 Change in Fair Value Due to Valuation Methodology Changes - Effect of 98-10 Rescission (4,861) Changes in Fair Value of Risk Management Contracts (d) 5,264 Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (e) 326 -------- Total MTM Risk Management Contract Net Assets 46,527 Net Non-Trading Related Derivative Contracts (2,241) -------- Net Fair Value of Risk Management and Derivative Contracts June 30, 2003 $ 44,286 ======== (a)"(Gain) Loss from Contracts Realized/Settled During the Period" includes realized gains from risk management contracts and related derivatives that settled during 2003 that were entered into prior to 2003. (b) The "Fair Value of New Contracts When Entered Into During the Period" represents the fair value of long-term contracts entered into with customers during 2003. The fair value is calculated as of the execution of the contract. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location. (c) "Net Option Premiums Paid/(Received)" reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered into in 2003. (d)"Changes in Fair Value of Risk Management Contracts" represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, etc. (e)"Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions" relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Operations. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions. Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information: o The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally). o The maturity, by year, of our net assets/liabilities, giving an indication of when these MTM amounts will settle and generate cash.

(a) "Prices Provided by Other External Sources" reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms. (b) "Prices Based on Models and Other Valuation Methods" if there is absence of pricing information from external sources, modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the Modeled category varies by market. Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet The table provides detail on effective cash flow hedges under SFAS 133 included in the balance sheet. The data in the table will indicate the magnitude of SFAS 133 hedges we have in place. (However, given that under SFAS 133 only cash flow hedges are recorded in AOCI, the table does not provide an all-encompassing picture of our hedging activity). The table also includes a roll-forward of the AOCI balance sheet account, providing insight into the drivers of the changes (new hedges placed during the period, changes in value of existing hedges and roll-off of hedges). Information on energy merchant activities is presented separately from interest rate, foreign currency risk management activities and other hedging activities. In accordance with GAAP, all amounts are presented net of related income taxes. Total Other Comprehensive Income (Loss) Activity Six Months Ended June 30, 2003 Domestic Power ----- (in thousands) Accumulated OCI, December 31, 2002 $ (286) ---------------------------------- Changes in Fair Value (a) (1,363) Reclassifications from OCI to Net Income (b) 87 ------- Accumulated OCI Derivative Gain (Loss) June 30, 2003 $(1,562) ======= (a) "Changes in Fair Value" shows changes in the fair value of derivatives designated as hedging instruments in cash flow hedges during the reporting period not yet reclassified into net income, pending the hedged item's affecting net income. Amounts are reported net of related income taxes. (b) "Reclassifications from OCI to Net Income" represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes above. The portion of cash flow hedges in Accumulated OCI expected to be reclassified to earnings during the next twelve months is a $1,063 thousand loss. Credit Risk The counterparty credit quality and exposure for the registrant subsidiaries is generally consistent with that of AEP. VaR Associated with Energy Trading Contracts The following table shows the end, high, average, and low market risk as measured by VaR for year-to-date:

The common stock of I&M is wholly owned by AEP. See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $44,812,000 and $42,695,000 and for income taxes was $50,731,000 and $18,711,000 in 2003 and 2002, respectively. See Notes to Respective Financial Statements beginning on page L-1. KENTUCKY POWER COMPANY MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS Results of Operations --------------------- Net Income for the second quarter and first half of 2003 decreased $1 million and $2 million, respectively, from the corresponding periods of the prior year. Net Income for the first half of 2003 included a loss from Cumulative Effect of Accounting Change of $1 million (see Note 3). The declines from the prior periods are primarily due to reduced gains from risk management activities compared to the prior year partially offset by an improvement in earnings from AEP Power Pool sales. We, as a member of the AEP Power Pool, share in the revenues and costs of marketing and activities conducted on our behalf by the AEP Power Pool. Operating Income Operating Income for the second quarter and six months ended June 30, 2003 increased $1 million and $6 million, respectively, primarily due to: o An increase in system sales of $5 million for the quarter and $12 million year-to-date. o A decrease in the current quarter in Maintenance expense of $1 million due to significant boiler overhaul work performed in the second quarter of 2002. o A decrease in Other Operation expense of $1 million from second quarter 2002 due to lower employee benefits expense and decreased engineering expenses. o An increase in residential sales for the six-month period of $2 million reflecting increased first quarter 2003 demand resulting from more severe winter weather in 2003. The increases in Operating Income were partially offset by: o A decline in retail sales of $2 million in the second quarter of 2003 due to decreased residential sales reflecting the mild weather conditions and decreased industrial sales reflecting the slower-than-expected economic recovery. o Increases in Purchased Electricity from AEP Affiliates of $4 million and $12 million for the quarter and year-to-date, respectively, necessary to support sales during the Big Sandy plant outage for the NOx reduction upgrades. In addition, purchases increased from the Rockport Plant based on plant availability, as required by the unit power agreement with AEGCo, an affiliated company. The unit power agreement with AEGCo provides for our purchase of 15% of the total output of the two unit 2,600-MW capacity Rockport Plant. o An increase for the six months ended June 30, 2003 in Maintenance expense of $1 million primarily due to distribution line maintenance resulting from a major ice storm in February 2003. o Increased Income Taxes of $1 million and $3 million for the quarter and year-to-date, respectively, due to increases in pre-tax operating book income for both periods. Other Impacts on Earnings Nonoperating Income for the second quarter and first half of 2003 decreased $4 million and $8 million, respectively, primarily due to reduced gains from risk management activities compared to the prior year. The decreases for the quarter and six months in Nonoperating Income Tax Expense were a result of the decreases in Nonoperating Income. Cumulative Effect of Accounting Change The Cumulative Effect of Accounting Change is due to the implementation of EITF 02-3 (see Note 3). Financial Condition ------------------- Credit Ratings The rating agencies currently have us on stable outlook. Current ratings are as follows: Moody's S&P Fitch ------- --- ----- First Mortgage Bonds Baa1 BBB BBB+ Senior Unsecured Debt Baa2 BBB BBB In February 2003, Moody's Investors Service (Moody's) completed their review of AEP and its rated subsidiaries. The completion of this review was a culmination of ratings action started during 2002. Financing Activity In June 2003, we issued $75 million in Senior Unsecured Notes due 2032. The proceeds were used to retire $40 million of Junior Subordinated Debentures (JSD), a $15 million Note Payable to AEP and to finance construction activities. In April 2003, we called the following JSD for early redemption on May 30, 2003: Coupon Or Stated Call Principal Rate Rate Due Date Amounts ----- ---- -------- ------- % % (in millions) - - 8.72 100 2025 $40 See Note 12 for additional information related to financing activity. Significant Factors ------------------- NOx Reductions Federal EPA issued a NOx Rule and adopted a revised rule (the Section 126 Rule) under the Clean Air Act requiring substantial reductions in NOx emissions in a number of eastern states, including Kentucky where our generating plant is located. The compliance date for the rules is May 31, 2004. In May 2003, selective catalytic reduction (SCR) technology and non-SCR technology to reduce NOx emissions at our Big Sandy plant commenced operation to comply with these rules. The capital expenditures for the SCR and non-SCR technology totaled $177 million through June 30, 2003. In 2003, the KPSC granted recovery of approximately $18 million annually (see Note 5). See Note 7 for further discussion of emissions control technology. Critical Accounting Policies See "Registrants' Combined Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters - Critical Accounting Policies" in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003) for a discussion of the estimates and judgments required for revenue recognition, the valuation of long-lived assets, the accounting for pension benefits and the impact of new accounting pronouncements. Quantitative And Qualitative Disclosures About Risk Management Activities ------------------------------------------------------------------------- Market Risks Risk management policies and procedures are instituted and administered at the AEP consolidated level for all subsidiary registrants. See complete discussion within AEP's "Qualitative And Quantitative Disclosures About Risk Management Activities" section. The following tables provide information about the risk management activities' effect on this specific registrant. Roll-Forward of MTM Risk Management Contract Net Assets This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next. Roll-Forward of MTM Risk Management Contract Net Assets Six Months Ended June 30, 2003 Domestic Power -------------- (in thousands) Beginning Balance December 31, 2002 $24,998 ----------------------------------- (Gain) Loss from Contracts Realized/Settled During the Period (a) (8,989) Fair Value of New Contracts When Entered Into During the Period (b) - Net Option Premiums Paid/(Received) (c) 108 Change in Fair Value Due to Valuation Methodology Changes - Effect of 98-10 Rescission (1,744) Changes in Fair Value of Risk Management Contracts (d) 1,833 Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (e) 351 ------ Total MTM Risk Management Contract Net Assets 16,557 Net Non-Trading Related Derivative Contracts (810) ------ Net Fair Value of Risk Management and Derivative Contracts June 30, 2003 $15,747 ======= (a)"(Gain) Loss from Contracts Realized/Settled During the Period" includes realized gains from risk management contracts and related derivatives that settled during 2003 that were entered into prior to 2003. (b) The "Fair Value of New Contracts When Entered Into During the Period" represents the fair value of long-term contracts entered into with customers during 2003. The fair value is calculated as of the execution of the contract. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location. (c) "Net Option Premiums Paid/(Received)" reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered into in 2003. (d)"Changes in Fair Value of Risk Management Contracts" represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, etc. (e)"Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions" relates to the net gains (losses) of those contracts that are not reflected in the Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions. Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information: o The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally). o The maturity, by year, of our net assets/liabilities, giving an indication of when these MTM amounts will settle and generate cash.

(a) "Changes in Fair Value" shows changes in the fair value of derivatives designated as hedging instruments in cash flow hedges during the reporting period not yet reclassified into net income, pending the hedged item's affecting net income. Amounts are reported net of related income taxes. (b) "Reclassifications from OCI to Net Income" represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes above. The portion of cash flow hedges in Accumulated OCI expected to be reclassified to earnings during the next twelve months is a $298 thousand loss. Credit Risk The counterparty credit quality and exposure for the registrant subsidiaries is generally consistent with that of AEP. VaR Associated with Energy Trading Contracts The following table shows the end, high, average, and low market risk as measured by VaR for year-to-date:

The common stock of KPCo is wholly owned by AEP. See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $13,245,000 and $13,692,000 in 2003 and 2002, respectively. Cash paid (received) for income taxes was $(5,537,000) and $7,024,000 in 2003 and 2002, respectively. Noncash acquisitions under capital leases were $22,000 in 2002. See Notes to Respective Financial Statements beginning on page L-1. OHIO POWER COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS Results of Operations --------------------- Net Income increased $130 million year-to-date including a $125 million Cumulative Effect of Accounting Changes in the first quarter of 2003 (see Note 3). Net Income Before Cumulative Effect of Accounting Changes increased $5 million year-to-date due primarily to increased Sales to AEP Affiliates. We, as a member of the AEP Power Pool, share in the revenues and the costs of the AEP Power Pool's wholesale sales to neighboring utilities and power marketing transactions. Operating Income Operating Income increased $19 million for the second quarter and $34 million year-to-date primarily due to the following: o Second quarter and year-to-date revenues from non-affiliated system sales increased $9 million and $26 million, respectively, while affiliated system sales increased $25 million and $42 million, respectively. The overall increase in system sales for resale is the result of optimizing our generation capacity and selling our excess generated power due to the unexpected outages at the affiliate owned Cook Plant. o Other Operation expenses decreased $21 million for the second quarter and $19 million year-to-date primarily due to a $7 million pre-tax adjustment to the workers' compensation reserve related to the sale of coal companies coupled with reductions in employee salary and benefit expenses and office related expenses totaling $12 million. The increase in Operating Income was partially offset by: o Second quarter retail revenues decreased $15 million due to milder weather during the second quarter 2003 and the effects of a weak economy. o Year-to-date Fuel for Electric Generation expense increased $16 million due to an increase of 7.7% in MWHs generated. o Second quarter and year-to-date expenses for Purchased Electricity from AEP Affiliates were $4 million and $13 million higher due to price and volume increases. o Second quarter and year-to-date Maintenance expenses increased $24 million and $30 million primarily due to increased boiler overhaul costs coupled with increased expense in maintaining overhead lines due to storm damage in southern Ohio. Other Impacts on Earnings Nonoperating Income decreased $14 million in the second quarter and $31 million year-to-date primarily due to lower margins for power sold outside of AEP's traditional marketing area reflecting reduced demand and AEP's plan to exit risk management activities in areas outside of its traditional market area. Nonoperating Expenses increased $3 million for the second quarter and $6 million year-to-date as a result of an increase in expenses related to the Cook Coal Terminal in both the quarter-to-date and year-to-date periods and a $2 million loss recorded on the sale of our water heater rental program in the year-to-date period. The $7 million year-to-date decrease in Nonoperating Income Tax Expense was the result of the overall decrease in income related to our risk management activities. Cumulative Effect of Accounting Changes The Cumulative Effect of Accounting Changes is due to the one-time after-tax impact of adopting SFAS 143 and implementing the requirements of EITF 02-3 (see Notes 2 and 3). Financial Condition ------------------- Credit Ratings The rating agencies currently have us on stable outlook. Current ratings are as follows: Moody's S&P Fitch ------- --- ----- First Mortgage Bonds A3 BBB A- Senior Unsecured Debt A3 BBB BBB+ In February 2003, Moody's Investor Service (Moody's) completed their review of AEP and its rated subsidiaries. The completion of this review was a culmination of ratings action started during 2002. In March 2003, S&P lowered AEP and its subsidiaries senior unsecured ratings from BBB+ to BBB along with the first mortgage bonds of AEP subsidiaries. Cash Flow Cash flows for six months ended June 30, 2003 and 2002 were as follows:

Operating Activities Cash flow from operating activities during the first half of 2003 decreased $165 million as they were adversely impacted primarily by significant reductions of accounts payable balances partially associated with a wind down of risk management activities in the current year. Investing Activities Cash flows used for investing activities were reduced in the current year directly attributable to a $40 million decrease in construction expenditures. Financing Activities Cash flow from financing activities in the first of half of 2003 used $127 million less than the first half of 2002 primarily due to: o Retirement and restructuring of our long-term and short-term debt during 2003. We retired $300 million of Long-term Debt to Affiliated Companies and $275 million of Short-term Debt to Affiliated Companies with the proceeds of two Senior Unsecured Notes at $250 million each, as well as a $232 million increase in Advances from Affiliates. o Dividends paid on common stock increased $19 million from the prior period. Financing Activity In February 2003, we issued $250 million of unsecured senior notes due 2013 at a coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a coupon of 6.60%. The proceeds from the issuances were used to repay long-term debt, short-term debt and for other corporate purposes. In July 2003, we issued $225 million of unsecured senior notes due 2014 at a coupon of 4.85% and $225 million of unsecured senior notes due 2033 at a coupon of 6.375%. See Note 12 for additional information related to financing activity. Significant Factors ------------------- Federal EPA Complaint and Notice of Violation As discussed in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003) and as discussed in Part II, Item 1 "Legal Proceedings", OPCo and certain affiliated companies have been involved in litigation since 1999 regarding generating plant emissions under the Clean Air Act. Federal EPA and a number of states alleged OPCo, certain affiliated companies and eleven unaffiliated utilities made modifications to generating units at coal-fired generating plants in violation of the Clean Air Act. Federal EPA filed complaints against 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. Management is unable to estimate the loss or range of loss related to the contingent liability for civil penalties under the Clear Air Act proceedings and is unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. In the event the AEP System companies do not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates and market prices for electricity. See Note 7 for further discussion. NOx Reductions Federal EPA issued a NOx Rule and adopted a revised rule (the Section 126 Rule) under the Clean Air Act requiring substantial reductions in NOx emissions in a number of eastern states, including certain states in which the AEP System's generating plants are located. The compliance date for the rules is May 31, 2004. We are installing selective catalytic reduction (SCR) technology and non-SCR technology to reduce NOx emissions on certain units to comply with these rules. Our estimates indicate that compliance with the rules could result in required capital expenditures in a range of $524 million to $853 million. The actual cost to comply could be significantly different than the estimates depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless any capital or operating costs for additional pollution control equipment are recovered from customers, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. See Note 7 for further discussion. Critical Accounting Policies See "Registrants' Combined Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters - Critical Accounting Policies" in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003) for a discussion of the estimates and judgments required for revenue recognition, the valuation of long-lived assets, the accounting for pension benefits and the impact of new accounting pronouncements. Quantitative And Qualitative Disclosures About Risk Management Activities ------------------------------------------------------------------------- Market Risks Risk management policies and procedures are instituted and administered at the AEP consolidated level for all subsidiary registrants. See complete discussion within AEP's "Qualitative And Quantitative Disclosures About Risk Management Activities" section. The following tables provide information about the risk management activities' effect on this specific registrant. Roll-Forward of MTM Risk Management Contract Net Assets This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next. Roll-Forward of MTM Risk Management Contract Net Assets Six Months Ended June 30, 2003 Domestic Power -------------- (in thousands) Beginning Balance December 31, 2002 $94,106 ----------------------------------- (Gain) Loss from Contracts Realized/Settled During the Period (a) (39,181) Fair Value of New Contracts When Entered Into During the Period (b) - Net Option Premiums Paid/(Received) (c) 369 Change in Fair Value Due to Valuation Methodology Changes - Effect of 98-10 Rescission (4,159) Changes in Fair Value of Risk Management Contracts (d) 12,431 Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e) - ------- Total MTM Risk Management Contract Net Assets 63,566 Net Non-Trading Related Derivative Contracts (2,745) ------- Net Fair Value of Risk Management and Derivative Contracts June 30, 2003 $60,821 ======= (a)"(Gain) Loss from Contracts Realized/Settled During the Period" includes realized gains from risk management contracts and related derivatives that settled during 2003 that were entered into prior to 2003. (b) The "Fair Value of New Contracts When Entered Into During the Period" represents the fair value of long-term contracts entered into with customers during 2003. The fair value is calculated as of the execution of the contract. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location. (c) "Net Option Premiums Paid/(Received)" reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered into in 2003. (d)"Changes in Fair Value of Risk Management Contracts" represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc. (e)"Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions" relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions. Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information: o The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally). o The maturity, by year, of our net assets/liabilities, giving an indication of when these MTM amounts will settle and generate cash.

(a) "Changes in Fair Value" shows changes in the fair value of derivatives designated as hedging instruments in cash flow hedges during the reporting period not yet reclassified into net income, pending the hedged item's affecting net income. Amounts are reported net of related income taxes. (b) "Reclassifications from OCI to Net Income" represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes above. The portion of cash flow hedges in Accumulated OCI expected to be reclassified to earnings during the next twelve months is a $1,331 thousand loss. Credit Risk The counterparty credit quality and exposure for the registrant subsidiaries is generally consistent with that of AEP. VaR Associated with Energy Trading Contracts The following table shows the end, high, average, and low market risk as measured by VaR for year-to-date:

The common stock of OPCo is wholly owned by AEP. See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $29,304,000 and $36,585,000 and for income taxes was $26,455,000 and $29,187,000 in 2003 and 2002, respectively. Noncash acquisitions under capital leases were $98,000 in 2002. See Notes to Respective Financial Statements beginning on page L-1. PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS Results of Operations --------------------- Net Income increased year-to-date and for the second quarter by $9 million and $6 million, respectively. Large swings occurred in revenues, fuel and purchased power due to fuel price market volatility (primarily natural gas), however, income is generally not significantly affected due to the functioning of the fuel adjustment clause in Oklahoma. Operating Income Operating Income increased $13 million year-to-date and $9 million for the second quarter primarily due to the following: o Increased wholesale margins year-to-date of $2 million and for the second quarter of $1 million. o Increased other customer service revenues of $3 million year-to-date and $1 million for the second quarter due to increased rents and service work for customers. o Decreased Other Operation and Maintenance expenses of $2 million year-to-date and $2 million for the second quarter due in large part to the absence in 2003 of storm damage that occurred in the first quarter 2002 and reduced transmission and power plant maintenance during the second quarter 2003. o Decreased Income Taxes of $1 million year-to-date and $3 million for the second quarter due to state income tax accrual adjustments offset by increases in pre-tax operating book income. The increase in Operating Income was partially offset by: o Increased Taxes Other Than Income Taxes of $2 million year-to-date due primarily to increased property value assessments and franchise taxes. Other Impacts on Earnings Nonoperating Income decreased approximately $1 million primarily due to a gain on the disposition of an investment in 2002. No such transaction occurred in the current year. Interest Charges increased $5 million year-to-date and $1 million for the second quarter as a result of replacing floating rate short-term debt with longer term fixed rate unsecured debt . Financial Condition ------------------- Credit Ratings The rating agencies currently have us on stable outlook. Current ratings are as follows: Moody's S&P Fitch ------- --- ----- First Mortgage Bonds A3 BBB A Senior Unsecured Debt Baa1 BBB A- In February 2003, Moody's Investor Service (Moody's) completed their review of AEP and its rated subsidiaries. The results of that review included a downgrade of our rating for unsecured debt from A2 to Baa1. The completion of this review was a culmination of ratings action started during 2002. In March 2003, S&P lowered AEP and its subsidiaries' senior unsecured ratings from BBB+ to BBB along with the first mortgage bonds of AEP subsidiaries. Financing Activity Retired $35 million of first mortgage bonds on April 1, 2003 with coupon of 6.25% due 2003, and received a $50 million capital contribution from our parent company. See Note 12 for additional information related to financing activity. Critical Accounting Policies See "Registrants' Combined Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters - Critical Accounting Policies" in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003) for a discussion of the estimates and judgments required for revenue recognition, the valuation of long-lived assets, the accounting for pension benefits and the impact of new accounting pronouncements. Quantitative And Qualitative Disclosures About Risk Management Activities ------------------------------------------------------------------------- Market Risks Risk management policies and procedures are instituted and administered at the AEP consolidated level for all subsidiary registrants. See complete discussion within AEP's "Qualitative And Quantitative Disclosures About Risk Management Activities" section. The following tables provide information about the risk management activities' effect on this specific registrant. Roll-Forward of MTM Risk Management Contract Net Assets This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next. Roll-Forward of MTM Risk Management Contract Net Assets Six Months Ended June 30, 2003 Domestic Power -------------- (in thousands) Beginning Balance December 31, 2002 $ 3,545 ----------------------------------- (Gain) Loss from Contracts Realized/Settled During the Period (a) 220 Fair Value of New Contracts When Entered Into During the Period (b) - Net Option Premiums Paid/(Received) (c) - Change in Fair Value Due to Valuation Methodology Changes - Effect of 98-10 Rescission - Changes in Fair Value of Risk Management Contracts (d) - Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e) 12,120 ------- Total MTM Risk Management Contract Net Assets 15,885 Net Non-Trading Related Derivative Contracts (1,417) ------- Net Fair Value of Risk Management and Derivative Contracts June 30, 2003 $14,468 ======= (a)"(Gain) Loss from Contracts Realized/Settled During the Period" includes realized gains from risk management contracts and related derivatives that settled during 2003 that were entered into prior to 2003. (b) The "Fair Value of New Contracts When Entered Into During the Period" represents the fair value of long-term contracts entered into with customers during 2003. The fair value is calculated as of the execution of the contract. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location. (c) "Net Option Premiums Paid/(Received)" reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered into in 2003. (d)"Changes in Fair Value of Risk Management Contracts" represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, etc. (e)"Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions" relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Operations. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions. Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information: o The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally). o The maturity, by year, of our net assets/liabilities, giving an indication of when these MTM amounts will settle and generate cash.

(a) "Prices Provided by Other External Sources - OTC Broker Quotes reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms. (b) "Prices Based on Models and Other Valuation Methods" if there is absence of pricing information from external sources, modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the Modeled category varies by market. Cash Flow Hedges Included in Accumulated Other Comprehensive Income(Loss) (AOCI) on the Balance Sheet The table provides detail on effective cash flow hedges under SFAS 133 included in the balance sheet. The data in the table will indicate the magnitude of SFAS 133 hedges we have in place. (However, given that under SFAS 133 only cash flow hedges are recorded in AOCI, the table does not provide an all-encompassing picture of our hedging activity). The table also includes a roll-forward of the AOCI balance sheet account, providing insight into the drivers of the changes (new hedges placed during the period, changes in value of existing hedges and roll off of hedges). Information on energy merchant activities is presented separately from interest rate, foreign currency risk management activities and other hedging activities. In accordance with GAAP, all amounts are presented net of related income taxes. Total Other Comprehensive Income (Loss) Activity Six Months Ended June 30, 2003 Domestic Power ----- (in thousands) Accumulated OCI, December 31, 2002 $ (42) ---------------------------------- Changes in Fair Value (a) (903) Reclassifications from OCI to Net Income (b) 24 ----- Accumulated OCI Derivative Gain (Loss) June 30, 2003 $(921) ===== (a) "Changes in Fair Value" shows changes in the fair value of derivatives designated as hedging instruments in cash flow hedges during the reporting period not yet reclassified into net income, pending the hedged item's affecting net income. Amounts are reported net of related income taxes. (b) "Reclassifications from OCI to Net Income" represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes above. The portion of cash flow hedges in Accumulated OCI expected to be reclassified to earnings during the next twelve months is a $626 thousand loss. Credit Risk The counterparty credit quality and exposure for the registrant subsidiaries is generally consistent with that of AEP. VaR Associated with Energy Trading Contracts The following table shows the end, high, average, and low market risk as measured by VaR for year-to-date:

The common stock of PSO is owned by a wholly owned subsidiary of AEP. See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $24,107,000 and $17,870,000 and for income taxes was $8,975,000 and $2,575,000 in 2003 and 2002, respectively. There was a non-cash distribution of $548,000 in preferred shares in AEMT, Inc. to PSO's Parent Company in 2003. See Notes to Respective Financial Statements beginning on page L-1. SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS Results of Operations --------------------- Net Income increased $13 million year-to-date due in large part to the adoption of SFAS 143, which resulted in a Cumulative Effect of Accounting Change of $9 million in the first quarter. Net Income for the second quarter increased $2 million due to increased wholesale margins and gains in risk management activities. Although large swings occurred in revenues, fuel and purchased power, due to fuel price market volatility (primarily natural gas), income was generally not affected due to the functioning of fuel adjustment clauses. Operating Income Operating Income increased by $8 million year-to-date and $4 million for the quarter primarily due to the following: o Increased wholesale margins both year-to-date and for the quarter. o Increased gains in risk management activities of $9 million year-to-date and $5 million for the quarter. o Other Operation expense decreased $9 million year-to-date and $7 million for the quarter primarily due to SWEPCo's ability to defer a portion of fuel expense in the state of Louisiana. o Maintenance decreased $1 million year-to-date and $2 million for the quarter due to reduced scheduled power plant maintenance. The increase in Operating Income was partially offset by: o Taxes Other Than Income Taxes increased year-to-date by $2 million due to increased property taxes resulting from adjustments for revised tax valuations. o Income Taxes increased for both year-to-date and for the quarter due to an increase in pre-tax operating book income. The quarter results are offset slightly by state income tax accrual adjustments. Other Impacts on Earnings Interest Charges increased $3 million year-to-date and $1 million for the quarter primarily due to higher overall levels of outstanding debt and higher average interest rates as floating rate debt was replaced with unsecured fixed rate debt. Cumulative Effect of Accounting Changes The Cumulative Effect of Accounting Changes is due to the one-time, after-tax impact of adopting SFAS 143 and implementing the requirements of EITF 02-3 (see Notes 2 and 3). Financial Condition ------------------- Credit Ratings The rating agencies currently have us on stable outlook. Current ratings are as follows: Moody's S&P Fitch ------- --- ----- First Mortgage Bonds A3 BBB A Senior Unsecured Debt Baa1 BBB A- In February 2003, Moody's Investors Service (Moody's) completed their review of AEP and its rated subsidiaries. The results of that review included a downgrade of our rating for unsecured debt from A2 to Baa1. The completion of this review was a culmination of ratings action started during 2002. In March 2003, S&P lowered AEP and its subsidiaries senior unsecured ratings from BBB+ to BBB along with the first mortgage bonds of AEP subsidiaries. Cash Flow Cash flows for six months ended June 30, 2003 and 2002 were as follows:

Operating Activities Cash flows from operating activities increased $25 million in the first six months of 2003 compared to the first six months of 2002 primarily due to a build-up of fuel inventory during 2002. Investing Activities Cash spent on investing activities increased $26 million in comparison to the prior year. Investment expenditures of $46 million in the current year were related to projects for improved transmission and distribution service reliability. Financing Activities Cash flows used for financing activities in the first half of 2003 were comparable to the first half of 2002. During the first quarter of 2003 we retired $55 million of first mortgage bonds at maturity. In April 2003, we issued $100 million of senior unsecured debt due 2015 at a coupon of 5.375%. In May 2003, our mining subsidiary issued $44 million of notes due in 2011 at a coupon of 4.47%. See Note 12 for additional information related to financing activity. Significant Factors ------------------- NOx Reductions The Texas Commission on Environmental Quality adopted rules requiring significant reductions in NOx emissions from utility sources, including SWEPCo. Our compliance date is May 2005. We are installing non-selective catalytic reduction technology to reduce NOx emissions on certain units to comply with these rules. Our estimates indicate that compliance with the rules could result in required capital expenditures of approximately $35 million. The actual cost to comply could be significantly different than the estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless any capital or operating costs for additional pollution control equipment are recovered from customers, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. See Note 7 for further discussion. Critical Accounting Policies See "Registrants' Combined Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters - Critical Accounting Policies" in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003) for a discussion of the estimates and judgments required for revenue recognition, the valuation of long-lived assets, the accounting for pension benefits and the impact of new accounting pronouncements. Quantitative And Qualitative Disclosures About Risk Management Activities ------------------------------------------------------------------------- Market Risks Risk management policies and procedures are instituted and administered at the AEP consolidated level for all subsidiary registrants. See complete discussion within AEP's "Qualitative And Quantitative Disclosures About Risk Management Activities" section. The following tables provide information about the risk management activities' effect on this specific registrant. Roll-Forward of MTM Risk Management Contract Net Assets This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next. Roll-Forward of MTM Risk Management Contract Net Assets Six Months Ended June 30, 2003 Domestic Power -------------- (in thousands) Beginning Balance December 31, 2002 $ 4,050 ----------------------------------- (Gain) Loss from Contracts Realized/Settled During the Period (a) (218) Fair Value of New Contracts When Entered Into During the Period (b) - Net Option Premiums Paid/(Received) (c) - Change in Fair Value Due to Valuation Methodology Changes - Effect of 98-10 Rescission 151 Changes in Fair Value of Risk Management Contracts (d) 5,012 Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e) 9,151 ------- Total MTM Risk Management Contract Net Assets 18,146 Net Non-Trading Related Derivative Contracts (1,618) ------- Net Fair Value of Risk Management and Derivative Contracts June 30, 2003 $16,528 ======= (a)"(Gain) Loss from Contracts Realized/Settled During the Period" includes realized gains from risk management contracts and related derivatives that settled during 2003 that were entered into prior to 2003. (b) The "Fair Value of New Contracts When Entered Into During the Period" represents the fair value of long-term contracts entered into with customers during 2003. The fair value is calculated as of the execution of the contract. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location. (c) "Net Option Premiums Paid/(Received)" reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered into in 2003. (d)"Changes in Fair Value of Risk Management Contracts" represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, etc. (e)"Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions" relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions. Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information: o The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally). o The maturity, by year, of our net assets/liabilities, giving an indication of when these MTM amounts will settle and generate cash.

(a) "Prices Provided by Other External Sources - OTC Broker Quotes" reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms. (b) "Prices Based on Models and Other Valuation Methods" if there is absence of pricing information from external sources, modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the Modeled category varies by market. Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet The table provides detail on effective cash flow hedges under SFAS 133 included in the balance sheet. The data in the table will indicate the magnitude of SFAS 133 hedges we have in place. (However, given that under SFAS 133 only cash flow hedges are recorded in AOCI, the table does not provide an all-encompassing picture of our hedging activity). The table also includes a roll-forward of the AOCI balance sheet account, providing insight into the drivers of the changes (new hedges placed during the period, changes in value of existing hedges and roll-off of hedges). Information on energy merchant activities is presented separately from interest rate, foreign currency risk management activities and other hedging activities. In accordance with GAAP, all amounts are presented net of related income taxes. Total Other Comprehensive Income (Loss) Activity Six Months Ended June 30, 2003 Domestic Power ----- (in thousands) Accumulated OCI, December 31, 2002 $ (48) ---------------------------------- Changes in Fair Value (a) (1,031) Reclassifications from OCI to Net Income (b) 27 ------- Accumulated OCI Derivative Gain (Loss) June 30, 2003 $(1,052) ======= (a) "Changes in Fair Value" shows changes in the fair value of derivatives designated as hedging instruments in cash flow hedges during the reporting period not yet reclassified into net income, pending the hedged item's affecting net income. Amounts are reported net of related income taxes. (b) "Reclassifications from OCI to Net Income" represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes above. The portion of cash flow hedges in Accumulated OCI expected to be reclassified to earnings during the next twelve months is a $715 thousand loss. Credit Risk The counterparty credit quality and exposure for the registrant subsidiaries is generally consistent with that of AEP. VaR Associated with Energy Trading Contracts The following table shows the end, high, average, and low market risk as measured by VaR for year-to-date:

The common stock of SWEPCo is owned by a wholly owned subsidiary of AEP. See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

See Notes to Respective Financial Statements beginning on page L-1.

Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $27,741,000 and $21,331,000 and for income taxes was $17,062,000 and $24,479,000 in 2003 and 2002, respectively. See Notes to Respective Financial Statements beginning on page L-1.

1. GENERAL ------- The accompanying unaudited interim financial statements should be read in conjunction with the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003) as incorporated in and filed with the Form 10-K. Certain prior period financial statement items have been reclassified to conform to current period presentation. These items include the effects of discontinued operations, gains and losses associated with derivative trading contracts presented on a net basis in accordance with EITF 02-3, and counterparty netting in accordance with FASB Interpretation No. 39, "Offsetting of Amounts Related to Certain Contracts" and EITF Topic D-43, "Assurance That a Right of Setoff is Enforceable in a Bankruptcy under FASB Interpretation No. 39". Such reclassifications had no effect on previously reported Net Income. In the opinion of management, the unaudited interim financial statements reflect all normal recurring accruals and adjustments which are necessary for a fair presentation of the results of operations for interim periods. 2. NEW ACCOUNTING PRONOUNCEMENTS ----------------------------- SFAS 143 "Accounting for Asset Retirement Obligations" We implemented SFAS 143, "Accounting for Asset Retirement Obligations", effective January 1, 2003 which requires entities to record a liability at fair value for any legal obligations for asset retirements in the period incurred. Upon establishment of a legal liability, SFAS 143 requires a corresponding asset to be established which will be depreciated over its useful life. SFAS 143 requires that a cumulative effect of change in accounting principle be recognized for the cumulative accretion and accumulated depreciation that would have been recognized had SFAS 143 been applied to existing legal obligations for asset retirements. In addition, the cumulative effect of change in accounting principle is favorably affected by the reversal of accumulated removal cost that had previously been recorded for generation that does not qualify as a legal obligation which was collected in depreciation rates by certain formerly regulated subsidiaries. We completed a review of our asset retirement obligations and concluded that at present, we have related legal liabilities for nuclear decommissioning costs for I&M's Cook Plant and TCC's partial ownership in the South Texas Project, as well as liabilities for the retirement of certain ash ponds. Since we presently recover our nuclear decommissioning costs in our regulated cash flow and thus had existing balances recorded for such nuclear retirement obligations, we recognized the cumulative difference in the amount already provided through rates versus the new methodology of SFAS 143, as a regulatory asset or liability. Similarly, a regulatory asset was recorded for the cumulative effect of certain retirement costs for ash ponds related to our regulated operations. In the first quarter of 2003, AEP recorded an unfavorable cumulative effect for our non-regulated operations. See the table later in this section for a summary by registrant subsidiary of the cumulative effect of changes in accounting principles for the six months ended June 30, 2003. Certain of AEP's registrant subsidiaries have recorded in Accumulated Depreciation and Amortization, removal costs collected from ratepayers for certain assets that do not have associated legal asset retirement obligations. To the extent that such registrant subsidiaries have now been deregulated, in the first quarter 2003 the registrant subsidiaries reversed the balance of such removal costs from accumulated depreciation which resulted in a net favorable cumulative effect in the first quarter of 2003. However, the registrant subsidiaries did not adjust the balance of such removal costs for their regulated operations, and in accordance with the present method of recovery, will continue to record such amounts through depreciation expense and accumulated depreciation. The following is a summary by registrant subsidiary of the regulatory liabilities for removal costs included in Accumulated Depreciation and Amortization: June 30, 2003 December 31, 2002 ------------- ----------------- (in millions) AEGCo $ 28.7 $ 28.0 APCo 88.7 94.6 CSPCo 98.5 96.0 I&M 257.7 250.5 KPCo 21.5 23.7 OPCo 97.6 97.0 PSO 206.2 202.6 SWEPCo 223.8 219.5 TCC 95.8 97.5 TNC 75.4 75.0 The following is a summary by registrant subsidiary of the cumulative effect of changes in accounting principles, as a result of SFAS 143, for the six months ended June 30, 2003:

We have identified, but not recognized, asset retirement obligation liabilities related to electric transmission and distribution as a result of certain easements on property on which we have assets. Generally, such easements are perpetual and require only the retirement and removal of our assets upon the cessation of the property's use. The retirement obligation is not estimable for such easements since we plan to use our facilities indefinitely. The retirement obligation would only be recognized if and when we abandon or cease the use of specific easements. The following is a reconciliation of beginning and ending aggregate carrying amounts of asset retirement obligations by registrant subsidiary following the adoption of SFAS 143:

(a) Consists of asset retirement obligations related to ash ponds. (b) Consists of asset retirement obligations related to ash ponds ($1.1 million at June 30, 2003) and nuclear decommissioning costs for the Cook Plant ($533.2 million at June 30, 2003). (c) Consists of asset retirement obligations related to nuclear decommissioning costs for STP. Accretion expense is included in Other Operation expense in the respective Income Statements of the individual subsidiary registrants. As of June 30, 2003 and December 31, 2002, the fair value of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities totaled $778 million ($669 million for I&M and $109 million for TCC) and $716 million ($618 million for I&M and $98 million for TCC), respectively, recorded in Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds on I&M's Consolidated Balance Sheets and in Nuclear Decommissioning Trust Fund on TCC's Consolidated Balance Sheets. Pro forma net income has not been presented for the period ended June 30, 2003 or the years ended December 31, 2002, 2001 and 2000 because the pro forma application of SFAS 143 would result in pro forma net income not materially different from the actual amounts reported for those periods. The following is a summary by registrant subsidiary of the pro forma liability for asset retirement obligations which has been calculated as if SFAS 143 had been adopted as of the beginning of each period presented: December 31, 2002 December 31, 2001 ----------------- ----------------- (in millions) AEGCo $ 1.1 $ 1.0 APCo 20.1 18.7 CSPCo 8.1 7.5 I&M 516.1 481.4 KPCo - - OPCo 39.5 36.5 PSO - - SWEPCo - - TCC 203.2 188.8 TNC - - Rescission of EITF 98-10 In October 2002, the Emerging Issues Task Force of the FASB reached a final consensus on Issue No. 02-3. See "New Accounting Pronouncements" in Note 1 of the 2002 Annual Report (as updated by the Current report on Form 8-K dated May 14, 2003) for further information. SFAS 149 "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" On April 30, 2003, the FASB issued Statement No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149 amends SFAS 133 for certain decisions made by the FASB as part of the Derivative Implementation Group process and to incorporate clarifications of the definition of a derivative and which contracts qualify as "normal purchase/normal sale." SFAS 149 also amends certain other existing pronouncements. Except for certain provisions of SFAS 149 discussed below, SFAS 149 is effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The provisions of SFAS 149 relating to decisions cleared by the FASB as part of the Derivative Implementation Group process shall continue to be applied in accordance with their respective effective dates. In addition, certain paragraphs of SFAS 149, which relate to forward purchases and sales of when-issued securities or other securities that do not yet exist, shall be applied to both existing contracts and new contracts entered into after June 30, 2003. We are currently assessing the impact of the adoption of SFAS 149. SFAS 150 "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" SFAS 150 was effective for us on July 1, 2003. SFAS 150 is the result of the first phase of the FASB's project to eliminate from the balance sheet the "mezzanine" presentation of items with characteristics of both liabilities and equity, so that no such items will be presented between liabilities and equity. SFAS 150 requires that the following three types of freestanding financial instruments be reported as liabilities: (1) mandatorily redeemable shares, (2) instruments other than shares that could require the issuer to buy back some of its shares in exchange for cash or other assets and (3) obligations that can be settled with shares, the monetary value of which is either (a) fixed, (b) tied to the value of a variable other than the issuer's shares, or (c) varies inversely with the value of the issuer's shares. Measurement of these liabilities generally is to be at fair value, with the payment or accrual of "dividends" and other amounts to holders reported as interest cost. Upon adoption of the new statement, any measurement change for these liabilities is to be reported as the cumulative effect of a change in accounting principle. We are currently assessing the impact of the adoption of SFAS 150. Beginning with AEP's third quarter 2003 financial statements, $321 million ($136 million TCC, $110 million SWEPCo and $75 million PSO) of certain subsidiary obligated, mandatorily redeemable, preferred securities of subsidiary trusts holding solely junior subordinated debentures of such subsidiaries, $83 million ($11 million APCo, $63 million I&M and $9 million OPCo) of mandatorily redeemable cumulative preferred stock of subsidiaries, and $376 million (all AEP) of equity unit senior notes, all of which are currently given mezzanine presentation, are expected to be reclassified as liabilities on the balance sheet. We are, however, still assessing the ultimate impact of SFAS 150. Future Accounting Changes FASB's standard-setting process is ongoing. Until new standards have been finalized and issued by FASB, we cannot determine the impact on the reporting of our operations that may result from any such future changes. 3. CUMULATIVE EFFECT OF ACCOUNTING CHANGES --------------------------------------- SFAS 143, "Accounting for Asset Retirement Obligations" (see Note 2), was effective on January 1, 2003. In the first quarter of 2003, AEP's registrant subsidiaries recorded after-tax income related to the recording of Asset Retirement Obligations in their respective Statements of Operations as a cumulative effect of accounting change. See the summary by registrant subsidiary of the cumulative effect of changes in accounting principles recorded in the first quarter of 2003 for the adoptions of SFAS 143 and EITF 02-3. EITF 02-3 rescinds EITF 98-10 and related interpretive guidance. Under EITF 02-3, mark-to-market accounting is precluded for energy trading contracts that are not derivatives pursuant to SFAS 133. The consensus to rescind EITF 98-10 eliminated any basis for recognizing physical inventories at fair value other than as provided by GAAP. The consensus to rescind EITF 98-10 is effective for all new contracts entered into (and physical inventory purchased) after October 25, 2002. The consensus is effective for fiscal periods beginning after December 15, 2002, and applies to all energy trading contracts that existed on or before October 25, 2002 that remain in effect as of the date of implementation, January 1, 2003. Effective January 2003, nonderivative energy contracts entered into prior to October 25, 2002 are required to be accounted for on a settlement basis and inventory is required to be presented at the lower of cost or market. The effect of implementing this consensus is reported as a cumulative effect of an accounting change. Such contracts and inventory are accounted for at fair value through December 31, 2002. Energy contracts that qualify as derivatives were accounted for at fair value under SFAS 133. AEP's registrant subsidiaries have recorded after-tax charges against net income as Accounting for Risk Management Contracts in their respective Statements of Operations as Cumulative Effect of Accounting Changes in the first quarter of 2003. This amount will be recognized when the positions settle. The following is a summary by registrant subsidiary of the cumulative effect of changes in accounting principles recorded in the first quarter of 2003 for the adoptions of SFAS 143 and EITF 02-3 (no effect on AEGCo or PSO):

4. GOODWILL AND OTHER INTANGIBLE ASSETS ------------------------------------ Goodwill There continues to be no goodwill recorded at the AEP registrant subsidiaries as of June 30, 2003. Acquired Intangible Assets The gross carrying amount, accumulated amortization and amortization life by major asset class are shown in the following table:

Intangible asset amortization expense was $0.7 million for the three months ended June 30, 2003 and June 30, 2002 and $1.5 million for the six months ended June 30, 2003 and June 30, 2002. Estimated aggregate amortization expense is $3.0 million per year in 2004 through 2009. Intangible assets subject to amortization are recorded in Deferred Charges in SWEPCo's Consolidated Balance Sheets. 5. RATE MATTERS ----------- Fuel in SPP - Affecting SWEPCo and TNC As discussed in Note 6 of the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003), in 2001, the PUCT delayed the start of customer choice in the SPP area of Texas. In May 2003, the PUCT ordered that competition would not begin in the SPP area before January 1, 2007. The PUCT has ruled that TNC fuel factors in the SPP area will be based upon the price-to-beat fuel factors offered by the retail electric provider (REP) in the ERCOT portion of TNC's service territory. TNC filed with the PUCT in 2002 to determine the most appropriate method to reconcile fuel costs in TNC's SPP area. In April 2003, the PUCT issued an order adopting the methodology proposed in TNC's filing, with adjustments, for reconciling fuel costs in its SPP area. The adjustments removed $3.71 per MWH from reconcilable fuel expense. This adjustment will reduce revenues received from TNC's SPP customers by approximately $400 thousand annually. These customers are now served by SWEPCo's REP. TNC Fuel Reconciliation - Affecting TNC In June 2002, TNC filed with the PUCT to reconcile fuel costs and to defer any unrecovered portion applicable to retail sales within its ERCOT service area for inclusion in the 2004 true-up proceeding. This reconciliation for the period of July 2000 through December 2001 will be the final fuel reconciliation for TNC's ERCOT service territory. At December 31, 2001, the under-recovery balance associated with TNC's ERCOT service area was $27.5 million including interest. During the reconciliation period, TNC incurred $293.7 million of eligible fuel costs serving both ERCOT and SPP retail customers. TNC also requested authority to surcharge its SPP customers. TNC's SPP customers will continue to be subject to fuel reconciliations until competition begins in the SPP area. The under-recovery balance at December 31, 2001 for TNC's service within SPP was $0.7 million including interest. As noted above, TNC's SPP customers are now being served by SWEPCo's REP. In March 2003, the Administrative Law Judges (ALJ) in this proceeding filed their Proposal for Decision (PFD). The PFD recommends that TNC's under-recovered retail fuel balance be reduced by approximately $12.5 million. In March 2003, TNC established a reserve of $13 million, including interest, based on the PFD's recommendations. On April 22, 2003, TNC and intervenors in this proceeding filed exceptions to the PFD. On May 28, 2003, the PUCT remanded TNC's final fuel reconciliation to the ALJ to consider several issues. Two of these remand issues could result in additional disallowances. The issues are the sharing of off-system sales margins from AEP's trading activities with customers through the fuel factor for five years per the PUCT's interpretation of the Texas AEP/CSW merger settlement and the inclusion of January 2002 fuel factor revenues and associated costs in the determination of the under-recovery. TNC made a filing on July 15, 2003 addressing the remand issues. The PUCT is proposing that the sharing of off-system sales margins should continue beyond the termination of the fuel factor. This would result in the sharing of margins for an additional three and one half years after the end of the Texas ERCOT fuel factor. Management believes that the Texas merger settlement only provided for sharing of margins during the period fuel and generation costs were regulated by the PUCT and that after a more thorough review of the evidence it is only reasonably possible that the PUCT will determine after the remand proceeding that TNC should share margins after the end of the Texas fuel factor. Due to a provision established in the first quarter, the resolution of the fuel factor issue should have an immaterial impact on results of operations. However, the decision of the PUCT could result in additional income reductions for these issues. It is presently expected that the ALJ's PFD and the PUCT's final decision of these remanded issues will occur in late 2003 or early 2004. In February 2002, TNC received a final order from the PUCT in a fuel reconciliation covering the period July 1997 - June 2000 and reflected the order in its financial statements. This final order had been appealed to the Travis County District Court. In May 2003, the District Court upheld the PUCT's final order. The plaintiffs appealed the District Court's decision to the Third Court of Appeals. TCC Fuel Reconciliation - Affecting TCC In December 2002, TCC filed with the PUCT to reconcile fuel costs and to defer its over-recovery of fuel for inclusion in the 2004 true-up proceeding. This reconciliation for the period of July 1998 through December 2001 will be the final fuel reconciliation. At December 31, 2001, the over-recovery balance for TCC was $63.5 million including interest. During the reconciliation period, TCC incurred $1.6 billion of eligible fuel and fuel-related expenses. Recommendations from intervening parties were received in April 2003 and hearings were held in May 2003. Intervening parties have recommended disallowances totaling $170 million. In March 2003, the ALJ hearing the TNC final fuel reconciliation, discussed above, issued a PFD in the TNC proceeding. Various issues addressed in TNC's proceeding may also be applicable to TCC's proceeding. Consequently, TCC established a reserve for potential adverse rulings of $27 million during the first quarter of 2003. Based upon the PUCT's remand of certain TNC issues, TCC established an additional reserve of $9 million in the second quarter of 2003. An adverse ruling from the PUCT in excess of the reserves could have a material impact on future results of operations, cash flows and financial condition. Additional information regarding the 2004 true-up proceeding for TCC can be found in Note 6 "Customer Choice and Industry Restructuring". SWEPCo Fuel Reconciliation - Affecting SWEPCo In June 2003, SWEPCo filed with the PUCT to reconcile fuel costs. This reconciliation covers the period of January 2000 through December 2002. At December 31, 2002, SWEPCo's filing detailed a $2.2 million over-recovery balance including interest. During the reconciliation period, SWEPCo incurred $434.8 million of eligible fuel expense. An adverse ruling from the PUCT could have a material impact on future results of operations, cash flows and financial condition. ERCOT Price-to-Beat (PTB) Fuel Factor Appeal - Affecting TCC and TNC Several parties including the Office of Public Utility Counsel (OPC) and cities served by both TCC and TNC appealed the PUCT's December 2001 orders establishing initial PTB fuel factors for Mutual Energy CPL and Mutual Energy WTU. On June 25, 2003, the District Court ruled in both appeals. The Court ruled in the Mutual Energy WTU case that the PUCT lacked sufficient evidence to include unaccounted for energy in the fuel factor, erred in including unaccounted for energy in the PTB rate based on its treatment in other proceedings and that the PUCT had improperly shifted the burden of proof from the utility to the intervening parties in not adjusting projected generation requirements for loss of load. The Court upheld the initial PTB orders on all other issues. In the Mutual Energy CPL proceeding, the Court ruled that the PUCT should have adjusted projected generation requirements for the loss of load due to retail competition. The Court remanded the cases to the PUCT for further proceedings consistent with its ruling. The amount of unaccounted for energy built into the PTB fuel factors was approximately $2.7 million for Mutual Energy WTU. At this time, management is unable to estimate the potential financial impact related to the loss of load issue. Management will appeal the District Court decisions and believes, based on the advice of counsel, that the PUCT's original decision will ultimately be upheld. If the District Court's decisions are ultimately upheld, the PUCT could reduce the PTB fuel factors charged to retail customers in 2002 and 2003 resulting in an adverse effect on future results of operations and cash flows. Unbundled Cost of Service (UCOS) Appeal - Affecting TCC TCC placed new transmission and distribution rates into effect as of January 1, 2002 based upon an order issued by the PUCT resulting from an UCOS proceeding. TCC requested and received approval of wholesale transmission rates determined in the UCOS proceeding with the FERC. The UCOS proceeding set the regulated wires rates to be effective when retail electric competition began. Regulated delivery charges include the retail transmission and distribution charge, a system benefit fund fee, a nuclear decommissioning fund charge, a municipal franchise fee and a transition charge associated with securitization of regulatory assets. Certain rulings of the PUCT in the UCOS proceeding, including the initial determination of stranded costs, the commencement of TCC's excess earnings refund, regulatory treatment of nuclear insurance and distribution rates charged municipal customers, were appealed to the Travis County District Court by TCC and other parties to the proceeding. The District Court issued a decision on June 16, 2003 upholding the PUCT's UCOS order with one exception. The Court ruled that the refund of the 1999 - 2001 excess earnings solely as a credit to non-bypassable transmission and distribution rates charged to retail electric providers (REP) discriminates against residential and small commercial customers and is unlawful. The distribution rate credit began in January 2002. This decision could potentially affect the PTB rates charged by the AEP REP (Mutual Energy CPL). Mutual Energy CPL was a subsidiary of AEP until December 23, 2002 when it was sold to Centrica. Management estimates that the effect of reducing the PTB rates for the period prior to the sale is approximately $11 million pre-tax. Management has appealed this decision and, based on advise of counsel, believes that it will ultimately prevail on appeal. If the District Court's decision is ultimately upheld on appeal, it could have an adverse effect on future results of operations and cash flows. McAllen Rate Review - Affecting TCC On June 26, 2003, the City of McAllen requested that TCC provide justification showing that its transmission and distribution rates should not be reduced. Other municipalities served by TCC have passed similar rate review resolutions. In Texas, municipalities have original jurisdiction over rates of electric utilities within their municipal limits. Under Texas law, TCC has a minimum of 120 days to provide support for its rates to the municipalities. TCC has the right to appeal any rate change by the municipalities to the PUCT. Pursuant to an agreement with the cities, TCC will file the requested support for its rates with both the cities and the PUCT on November 3, 2003. Management believes that a rate reduction is not justified. Louisiana Fuel Audit - Affecting SWEPCO As a result of complaints filed by customers, the LPSC is performing an audit of SWEPCo's fuel rates. Five SWEPCo customers filed a suit in the Caddo Parish District Court in January 2003 and filed a complaint with the LPSC. The customers claim that SWEPCo has overcharged them for fuel costs since 1975. Management believes that SWEPCo's fuel rates prior to 1999 were proper and have been approved by the LPSC. If the LPSC or the Court rules against SWEPCo, it could have an adverse impact on results of operations and cash flows. FERC Wholesale Fuel Complaints - Affecting TNC As discussed in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003), certain TNC wholesale customers filed a complaint with FERC alleging that TNC had overcharged them through the fuel adjustment clause for certain purchased power costs since 1997. Negotiations to settle the complaint and update the contracts have resulted in new contracts. Consequently, an offer of settlement was filed at FERC in June 2003 regarding the fuel complaint and new contracts. Management is unable to predict whether FERC will approve this offer of settlement which is not expected to have a significant impact on TNC's financial condition. In March 2002, TNC recorded a provision for refund of $2.2 million before income taxes. TNC anticipates that the provision for refund will be adequate to cover the financial implications resulting from these new contracts. Should FERC fail to approve the settlement and new contracts, the actual refund and final resolution of this matter could differ materially from the provision and may have a negative impact on future results of operations, cash flows and financial condition. Environmental Surcharge Filing - Affecting KPCo In September 2002, KPCo filed with the KPSC to revise its environmental surcharge tariff (annual revenue increase of approximately $21 million) to recover the cost of emissions control equipment being installed at Big Sandy Plant. See NOx Reductions in Note 7. In March 2003, the KPSC granted approximately $18 million of the request. Annual rate relief of $1.7 million was effective in May 2003 and an additional $16.2 million was effective in July 2003. The recovery of such amounts is intended to offset KPCo's cost of compliance with the Clean Air Act. PSO Rate Review - Affecting PSO In February 2003, the Director of the Oklahoma Corporation Commission (OCC) filed an application requiring PSO to file all documents necessary for a general rate review before August 1, 2003. The required date to file the case was subsequently changed to October 31, 2003. Management is unable to predict the ultimate effect of this review on PSO's rates. PSO Fuel and Purchased Power - Affecting PSO As discussed in Note 6 of the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003), PSO had a $44 million under-recovery of fuel costs resulting from a reallocation of purchased power costs for periods prior to January 1, 2002. On July 23, 2003, PSO filed with the OCC seeking recovery of the $44 million over an eighteen month time period. A hearing has been scheduled for October 7, 2003. If the OCC does not permit recovery, there will be an adverse effect on results of operations, cash flows and possibly financial condition. Virginia Fuel Factor Filing - Affecting APCo APCo filed with the Virginia SCC to reduce its fuel factor effective August 1, 2003. The requested fuel rate reduction would be effective for 17 months and is estimated to reduce revenues by $36 million. By order dated July 23, 2003, the Virginia SCC approved APCo's requested fuel factor reduction on an interim basis, subject to further investigation. This fuel factor adjustment will reduce cash flows without impacting results of operations as any over-recovery of fuel costs would be deferred as a regulatory liability. FERC Long-term Contracts - Affecting AEP East and AEP West companies In September 2002, the FERC voted to hold hearings to consider requests from certain wholesale customers located in Nevada and Washington to break long-term contracts which they allege are "high-priced". At issue are long-term contracts entered during the California energy price spike in 2000 and 2001. The complaints allege that AEP sold power at unjust and unreasonable prices. The FERC delayed hearings to allow the parties to hold settlement discussions. In January 2003, the FERC settlement judge assigned to the case indicated that the parties' settlement efforts were not progressing and he recommended that the complaint be placed back on the schedule for a hearing. In February 2003, AEP and one of the customers agreed to terminate their contract. The customer withdrew its FERC complaint and paid $59 million to AEP. As a result of the contract termination, AEP reversed $69 million of unrealized mark-to-market gains previously recorded, resulting in a $10 million pre-tax loss. In a similar complaint, a FERC administrative law judge (ALJ) ruled in favor of AEP and dismissed, in December 2002, a complaint filed by two Nevada utilities. In 2000 and 2001, AEP agreed to sell power to the utilities for future delivery. In late 2001, the utilities filed complaints that the prices for power supplied under those contracts should be lowered because the market for power was allegedly dysfunctional at the time such contracts were consummated. The ALJ rejected the utilities' complaint, held that the markets for future delivery were not dysfunctional, and that the utilities had failed to demonstrate that the public interest required that changes be made to the contracts. The ALJ's order is preliminary and is subject to review by the FERC. At a hearing held in April 2003, the utilities asked FERC to void the long-term contracts. The FERC will likely rule on the ALJ's order in 2003. Management is unable to predict the outcome of these proceedings or their impact on future results of operations. RTO Formation/Integration Costs - Affecting APCo, CSPCo, I&M, KPCo, and OPCo With FERC approval, AEP East companies have been deferring costs incurred under FERC orders to form an RTO (the Alliance RTO) or join an existing RTO (PJM). On July 2, 2003, the FERC issued an order approving our continued deferral of both our Alliance formation costs and our PJM integration costs including the deferral of a carrying charge. The AEP East companies have deferred approximately $22 million of RTO formation and integration costs and related carrying charges (APCo-$6 million, CSPCo-$3 million, I&M-$5 million, KPCo-$1 million, OPCo-$7 million) through June 30, 2003. As a result of the subsequent delay in the integration of AEP's East transmission system into PJM, FERC declined to rule, at this time, on our request to transfer the deferrals to regulatory assets, and to maintain the deferrals until such time as the costs can be recovered from all users of AEP's East transmission system. The AEP East companies will apply for permission to transfer the deferred formation/integration costs to a regulatory asset prior to integration with PJM. In the first quarter of 2003, the state of Virginia enacted legislation preventing APCo from joining an RTO until after June 30, 2004 and only then with the approval of the Virginia SCC. In the second quarter of 2003, the KPSC denied KPCo's request that they approve our joining PJM based in part on a lack of evidence that it would benefit Kentucky retail customers. Management intends to seek a rehearing in Kentucky. Management does not expect the integration with PJM to occur prior to June 30, 2004. In its July 2 order, FERC indicated that it would review the deferred costs for prudency at the time they are transferred to a regulatory asset account and scheduled for amortization and recovery in the open access transmission tariff (OATT) to be charged by PJM. Management believes that the FERC will grant permission for the deferred RTO costs to be amortized and included in the OATT. Whether the amortized costs will be fully recoverable depends upon the state regulatory commissions' treatment of AEP's East companies' portion of the OATT at the time they join PJM. Presently, retail rates are frozen or capped and cannot be increased for retail customers of CSPCo, I&M and OPCo. AEP intends to apply with FERC seeking permission to delay the amortization of the deferred RTO formation/integration costs until they are recoverable from all users of the transmission system including retail customers. Management is unable to predict the timing of when AEP will join PJM and if upon joining PJM whether FERC will grant a delay of recovery until the rate caps and freezes end. Management intends to seek recovery of the deferred RTO formation/integration costs. If the FERC ultimately decides not to approve a delay or the state commissions deny recovery, future results of operations and cash flows could be adversely affected. FERC Order on Regional Through and Out Rates (RTOR) - Affecting APCo, CSPCo, I&M, KPCo and OPCo On July 23, 2003, the FERC issued an order directing PJM and the Midwest ISO to make compliance filings for their respective Open Access Transmission Tariffs to eliminate, by November 1, 2003, the Regional Through and Out Rates (RTOR) on transactions where the energy is delivered within the Midwest ISO and PJM regions. The elimination of the RTORs will reduce the transmission service revenues collected by the RTOs and thereby reduce the revenues received by transmission owners under the RTOs' revenue distribution protocols. The order provided that affected Transmission Owners could file to offset the elimination of these revenues by increasing rates or utilizing a transitional rate mechanism to recover lost revenues that result from the elimination of the RTORs. The FERC also found that the through and out rates of some of the former Alliance RTO Companies, including AEP, may be unjust, unreasonable, and unduly discriminatory or preferential for energy delivered in the Midwest ISO/PJM regions. FERC has initiated an investigation and hearing in regard to these rates. AEP will make a filing with the FERC supporting the justness and reasonableness of its rates by August 15, 2003. Management at this time is unable to predict the ultimate outcome of this investigation, or the impact on the results of operations and cash flows. 6. CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING ------------------------------------------ As discussed in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003), retail customer choice began in four of the eleven state retail jurisdictions (Michigan, Ohio, Texas and Virginia) in which the AEP domestic electric utility companies operate. The following paragraphs discuss significant events occurring in 2003 related to customer choice and industry restructuring. Ohio Restructuring - Affecting CSPCo and OPCo On June 27, 2002, the Ohio Consumers' Counsel, Industrial Energy Users-Ohio and American Municipal Power-Ohio filed a complaint with the PUCO alleging that CSPCo and OPCo have violated the PUCO's orders regarding implementation of their transition plan and violated other applicable law by failing to participate in an RTO. The complainants seek, among other relief, an order from the PUCO: o suspending collection of transition charges by CSPCo and OPCo until transfer of control of their transmission assets has occurred o pricing standard offer electric generation effective January 1, 2006 at the market price used by CSPCo and OPCo in their 1999 transition plan filings to estimate transition costs and o imposing a $25,000 per company forfeiture for each day AEP fails to comply with its commitment to transfer control of transmission assets to an RTO Due to the FERC's reversal of its previous approval of our RTO filings and state legislative and regulatory developments, CSPCo and OPCo have been delayed in the implementation of their RTO participation plans. We continue to pursue integration of CSPCo, OPCo and other AEP East companies into PJM. In this regard on December 19, 2002, CSPCo and OPCo filed an application with the PUCO for approval of the transfer of functional control over certain of their transmission facilities to PJM. In February 2003, the PUCO consolidated the June complaint with our December application. CSPCo's and OPCo's motion to dismiss the complaint has been denied by the PUCO and the PUCO affirmed that ruling in rehearing. All further action in the consolidated case has been stayed "until more clarity is achieved regarding matters pending at the FERC and elsewhere". Management is unable to predict the timing of the AEP's East companies' participation in PJM, or the outcome of these proceedings before the PUCO. On March 20, 2003, the PUCO commenced a statutorily-required investigation concerning the desirability, feasibility and timing of declaring retail ancillary, metering or billing and collection service supplied to customers within the certified territories of electric utilities a competitive retail electric service. The PUCO sent out a list of questions and set June 6, 2003 and July 7, 2003, as the dates for initial responses and replies, respectively. CSPCo and OPCo filed comments and responses in compliance with the PUCO's schedule. Management is unable to predict the timing or the outcome of this proceeding. The Ohio Act provides for a Development Period during which retail customers can choose their electric power suppliers or have the protection of Default Service at frozen generation rates from the incumbent utility. The Development Period began on January 1, 2001 and will terminate no later than December 31, 2005, but the PUCO may terminate the Development Period for one or more customer classes before that date if it determines either that effective competition exists in the incumbent utility's certified territory or that there is a twenty percent switching rate of the incumbent utility's load by customer class. Following the Development Period, retail customers will receive distribution and transmission service from the incumbent utility whose distribution rates will be approved by the PUCO and whose transmission rates will be approved by the FERC. Retail customers will continue to have the right to choose their electric power suppliers or have the protection of Default Service which must be offered by the incumbent utility at market rates. The PUCO has circulated a draft of proposed rules but has not yet identified the method by which it will determine market rates for Default Service following the Development Period. As provided in the stipulation agreement approved by the PUCO, CSPCo and OPCo are deferring customer choice implementation costs in excess of $20 million per company. The agreements provide for the deferral of these costs as a regulatory asset until the company's next distribution base rate case. CSPCo has deferred $10 million and OPCo has deferred $12 million of such costs. Recovery of these regulatory assets will be subject to PUCO review in each company's next Ohio distribution rate filings which will not occur until after 2008 for CSPCo and 2007 for OPCo. Management believes that the amounts deferred represent prudently incurred customer choice implementation costs and should be recoverable in future rates. If the PUCO determines that any of the deferred costs are unrecoverable, it would have an adverse impact on future results of operations and cash flows. Texas Restructuring - Affecting SWEPCo, TCC and TNC As discussed in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003), on January 1, 2002, customer choice of electricity supplier began in the ERCOT area of Texas. Customer choice has been delayed in other areas of Texas including the SPP area in which SWEPCo operates. In May 2003, the PUCT approved a stipulation that delays competition in the SPP area until at least January 1, 2007. A 2004 true-up proceeding will determine the amount of stranded costs, final fuel balance, net regulatory assets, certain environmental costs, accumulated excess earnings, excess of price-to-beat revenues over market prices subject to certain conditions and limitations (Retail clawback), a true-up of the power costs used in the PUCT's ECOM model for 2002 and 2003 to reflect actual market prices determined through legislatively-mandated capacity auctions (Wholesale capacity auction true-up) and other restructuring issues. The Texas Legislation allows for several alternative methods to be used to value stranded costs in the final 2004 true-up proceeding including the sale or exchange of generation assets, stock valuation or the use of an ECOM model. Only TCC has stranded costs under the Texas Legislation. In late 2002, TCC decided to obtain a market value of generating assets for purposes of determining stranded costs for the 2004 true-up proceeding and filed a plan of divestiture with the PUCT seeking approval of a sales process for all of its generating facilities. Such sales would quantify the actual stranded costs. The amount of stranded costs under this market valuation methodology will be the amount by which net book value of TCC's generating assets, including regulatory assets and liabilities that were not securitized, exceeds the market value of the generation assets as measured by the net proceeds from the sale of the assets. It is anticipated that any such sale will result in significant stranded costs for purposes of TCC's 2004 true-up proceeding. The filing included a request for the PUCT to issue a declaratory order that TCC's 25.2% ownership interest in its nuclear plant, STP, can be sold to value stranded costs. Intervenors to this proceeding, including the PUCT Staff, made filings to dismiss TCC's filing claiming that the PUCT does not have the authority to issue a declaratory order. The intervenors also argued that the proper time to address the sales process is after the plants are sold during the 2004 true-up proceeding. Since the bidding process is not expected to be completed before mid-2004, TCC requested that the 2004 true-up proceeding be scheduled after completion of the divestiture of the generating assets. In March 2003, the PUCT dismissed TCC's divestiture filing, determining that it was more appropriate to address the nuclear asset stranded costs valuation in a rulemaking proceeding. The PUCT approved a rule, in May 2003, that allows the value obtained by selling nuclear assets to be used in determining stranded costs. Since the PUCT also dismissed the request to certify the proposed divestiture plan, the divestiture plan utilized by TCC will still be subject to a review in the 2004 true-up proceedings. The PUCT adopted a rule regarding the timing of the 2004 true-up proceedings scheduling TNC's filing in May 2004 and TCC's filing in September 2004. Texas Legislation also requires that electric utilities and their affiliated power generation companies (PGC) sell at auction in 2002 and 2003 at least 15% of the PGC's Texas jurisdictional installed generation capacity in order to promote competitiveness in the wholesale market through increased availability of generation and liquidity. Actual market power prices received in the state mandated auctions will replace the PUCT's earlier estimates of those market prices used in the ECOM model to calculate the wholesale capacity auction true-up adjustment for TCC for the 2004 true-up proceeding. The decision to determine stranded costs by selling TCC's generating plants and the expectation that the sales price would produce a significant loss/stranded costs instead of using the PUCT's ECOM model estimates, enabled TCC to record in 2002 a $262 million regulatory asset and related revenues which represents the quantifiable amount of the wholesale capacity auction true-up for the year 2002. Through June 30, 2003, TCC recorded an additional $108 million regulatory asset and related revenues for the wholesale capacity auction true-up. Prior to the decision to pursue a sale of TCC's generating assets, the PUCT's ECOM estimate prohibited the recognition of the regulatory assets and revenues as they can not be recovered unless there are stranded costs. As discussed above, a defined process is required in order to determine the amount of stranded costs related to generation facilities for the 2004 true-up proceedings. In June 2003, the PUCT Staff proposed a refinement in the calculation of the wholesale capacity auction true-up. The Staff's proposed methodology could result in a material change in the amount of the wholesale capacity auction true-up for 2002 and 2003. The PUCT Staff's proposed true-up filing package has been published for comments that are due in September. A final true-up filing package is expected to be adopted by the end of 2003. When the divestiture and the 2004 true-up proceeding are completed, TCC can securitize stranded costs that are in excess of current securitized amounts. The annual costs of securitization will be recovered through a non-bypassable rate surcharge by the regulated transmission and distribution (T&D) utility over the life of the securitization bonds. Any stranded costs and other true-up amounts not recovered through the sale of securitization bonds may be recovered through a separate non-bypassable competition transition charge to T&D utility customers. In the event TCC and TNC are unable, after the 2004 true-up proceeding, to recover all or a portion of their generation-related regulatory assets, unrecovered fuel balances, stranded costs, other true-up adjustments and other restructuring related costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition. Arkansas Restructuring - Affecting SWEPCo In February 2003, Arkansas repealed customer choice legislation originally enacted in 1999. Consequently, SWEPCo's Arkansas operations reapplied SFAS 71 regulatory accounting which had been discontinued in 1999. The reapplication of SFAS 71 had an insignificant effect on results of operations for the first six months of 2003. As a result of reapplying SFAS 71, derivative contract gains/losses for transactions within AEP's traditional marketing area allocated to Arkansas will not affect income until settled. That is, such positions will be recorded on the balance sheet as either a regulatory asset or liability until realized. West Virginia Restructuring - Affecting APCo APCo reapplied SFAS 71 for its West Virginia (WV) jurisdiction in the first quarter of 2003 after new developments during the quarter prompted an analysis of the probability of restructuring becoming effective. In 2000, the WVPSC issued an order approving an electricity restructuring plan, which the WV Legislature approved by joint resolution. The joint resolution provided that the WVPSC could not implement the plan until the WV legislature made tax law changes necessary to preserve the revenues of state and local governments. In the 2001 and 2002 legislative sessions, the WV Legislature failed to enact the required legislation that would allow the WVPSC to implement the restructuring plan. Due to this lack of legislative activity, the WVPSC closed two proceedings related to electricity restructuring during the summer of 2002. In the 2003 legislative session, the WV Legislature failed to enact the required tax legislation. Also, a March 2003 WV Legislative Bill clarified the jurisdiction of the WVPSC over electric generation facilities in WV. In March 2003, APCo's outside counsel advised us that restructuring in West Virginia was no longer probable and confirmed facts relating to the WVPSC's jurisdiction and rate authority over APCo's WV generation. APCo has concluded that deregulation of the WV generation business is no longer probable and operations in WV meet the requirements to reapply SFAS 71. The result of reapplying SFAS 71 in WV had an insignificant effect on results of operations during the first six months of 2003. As a result, derivative contract gains/losses related to transactions within AEP's traditional marketing area allocated to WV will not affect income until settled. That is, such positions will be recorded on the balance sheet as either a regulatory asset or liability until realized. Positions outside AEP's traditional marketing area will continue to be marked-to-market. 7. COMMITMENTS AND CONTINGENCIES ----------------------------- Nuclear Plant Outages - Affecting I&M and TCC In April 2003, engineers at STP, during inspections conducted regularly as part of refueling outages, found wall cracks in two bottom mounted instrument guide tubes of STP Unit 1. These cracks have been repaired and the unit is expected to return to service in late summer. TCC's share of the direct cost of repair was approximately $6 million through June 30, 2003. STP officials are working closely with the NRC to safely return the unit to service. We have commitments to provide power to customers during the outage. Therefore, we will be subject to fluctuations in the market prices of electricity and purchased replacement energy could be a significant cost. In April 2003, both units of I&M's Cook Plant were taken offline due to an influx of fish in the plant's cooling water system which caused a reduction in cooling water to essential plant equipment. After repair of damage caused by the fish intrusion, Cook Plant Unit 1 returned to service in May and Unit 2 returned to service in June following completion of a scheduled refueling outage. Federal EPA Complaint and Notice of Violation - Affecting APCo, CSPCo, I&M, and OPCo As discussed in Note 9 of the Combined Notes to Financial Statements in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003) and as discussed in Part II, Item 1 "Legal Proceedings", AEPSC, APCo, CSPCo, I&M, and OPCo have been involved in litigation regarding generating plant emissions under the Clean Air Act. Federal EPA and a number of states alleged APCo, CSPCo, I&M, OPCo and eleven unaffiliated utilities modified certain units at coal-fired generating plants in violation of the Clean Air Act. Federal EPA filed complaints against 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. Under the Clean Air Act, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components, or other repairs needed for the reliable, safe and efficient operation of the plant. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). In 2001, the District Court ruled claims for civil penalties based on activities that occurred more than five years before the filing date of the complaints cannot be imposed. There is no time limit on claims for injunctive relief. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and intends to vigorously pursue its defense. Management is unable to estimate the loss or range of loss related to the contingent liability for civil penalties under the Clear Air Act proceedings and unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. In the event the AEP System companies do not prevail, any capital and operating costs of additional pollution control equipment that may be required, as well as any penalties imposed, would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates and market prices for electricity. In December 2000, Cinergy Corp., an unaffiliated utility, which operates certain plants jointly owned by CSPCo, reached a tentative agreement with Federal EPA and other parties to settle litigation regarding generating plant emissions under the Clean Air Act. Negotiations are continuing between the parties in an attempt to reach final settlement terms. Cinergy's settlement could impact the operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 (owned 25.4% and 12.5%, respectively, by CSPCo). 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. NOx Reductions - Affecting AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, SWEPCo and TCC Federal EPA issued a NOx Rule requiring substantial reductions in NOx emissions in a number of eastern states, including certain states in which the AEP System's generating plants are located. The NOx Rule has been upheld on appeal. The compliance date for the NOx Rule is May 31, 2004. In 2000, Federal EPA also adopted a revised rule (the Section 126 Rule) granting petitions filed by certain northeastern states under the Clean Air Act. The rule imposes emissions reduction requirements comparable to the NOx Rule beginning May 1, 2003, for most of our coal-fired generating units. Affected utilities, including certain AEP operating companies, petitioned the D.C. Circuit Court to review the Section 126 Rule. After review, the D.C. Circuit Court instructed Federal EPA to justify the methods it used to allocate allowances and project growth for both the NOx Rule and the Section 126 Rule. AEP subsidiaries and other utilities requested that the D.C. Circuit Court vacate the Section 126 Rule or suspend its May 2003 compliance date. In 2001, the D.C. Circuit Court issued an order tolling the compliance schedule until Federal EPA responds to the Court's remand. On April 30, 2002, Federal EPA announced that May 31, 2004 is the compliance date for the Section 126 Rule. Federal EPA published a notice in the Federal Register on May 1, 2002 advising that no changes in the growth factors used to set the NOx budgets were warranted. In June 2002, AEP subsidiaries joined other utilities and industrial organizations in seeking a review of Federal EPA's actions in the D.C. Circuit Court. This action is pending. In 2000, the Texas Commission on Environmental Quality adopted rules requiring significant reductions in NOx emissions from utility sources, including TCC and SWEPCo. The compliance requirements began in May 2003 for TCC and begin in May 2005 for SWEPCo. We are installing a variety of emission control technologies to reduce NOx emissions to comply with the applicable state and Federal NOx requirements. This includes selective catalytic reduction (SCR) technology on certain units and non-SCR technologies on a larger number of units. During 2001 SCR technology commenced operations on OPCo's Gavin Plant. Installation of SCR technology on Amos and Mountaineer plants was completed and commenced operation in May 2002. In May 2003, SCR technology installed at Big Sandy and Cardinal plants commenced operation. Construction of SCR technology at certain other AEP generating units continues. Non-SCR technologies have been installed and commenced operation on a number of units across the AEP System and additional units will be equipped with these technologies. The NOx compliance plan is a dynamic plan that is continually reviewed and revised as new information becomes available on the performance of installed technologies and the cost of planned technologies. Certain compliance steps may or may not be necessary as a result of this new information. Consequently, the plan has a range of possible outcomes. Our current estimates indicate that AEP's compliance with the NOx Rule, the Texas Commission on Environmental Quality rule and the Section 126 Rule could result in required capital expenditures in the range of $1.3 billion to $1.7 billion, of which $976 million has been spent through June 30, 2003. Estimated compliance cost ranges and amounts spent by registrant subsidiaries are as follows: Estimated Amount Compliance Costs Spent ---------------- ----- (in millions) AEGCo $ 28 $ 6 APCo 462 261 CSPCo 87 61 I&M 39 9 KPCo 180 177 OPCo 524-853 427 SWEPCo 35 23 TCC 5 5 Since compliance costs cannot be estimated with certainty, the actual cost to comply could be significantly different than the estimates depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless any capital and operating costs for additional pollution control equipment are recovered from customers, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Texas Commercial Energy, LLP Lawsuit - Affecting TCC and TNC Texas Commercial Energy, LLP (TCE), a Texas REP, has filed a lawsuit in federal District Court in Corpus Christi, Texas against AEP and four AEP subsidiaries, certain unaffiliated energy companies and ERCOT. The action alleges violations of the Sherman Antitrust Act, fraud, negligent misrepresentation, breach of fiduciary duty, breach of contract, civil conspiracy and negligence. The allegations, not all of which are made against the AEP companies, range from anticompetitive bidding to withholding power. TCE alleges that these activities resulted in price spikes requiring TCE to post additional collateral and ultimately forced it into bankruptcy when it was unable to raise prices to its customers due to fixed price contracts. The suit alleges over $500 million in damages for all defendants and seeks recovery of damages, exemplary damages and court costs. Management believes that the claims against AEP and its subsidiaries are without merit and intends to vigorously defend against the claims. FERC Proposed Standard Market Design - Affecting AEP System In July 2002, the FERC issued its Standard Market Design (SMD) notice of proposed rulemaking which sought to standardize the structure and operation of wholesale electricity markets across the country. Key elements of FERC's proposal included standard rules and processes for all users of the electricity transmission grid, new transmission rules and policies, and the creation of certain markets to be operated by independent administrators of the grid in all regions. The FERC issued a white paper on the proposal in April 2003, in response to the numerous comments FERC received on its proposal. Until the rule is finalized, management cannot predict its effect on cash flows and results of operations. FERC Proposed Security Standards - Affecting AEP System As part of the SMD proposed rulemaking, in July 2002, FERC published for comment proposed security standards. These standards were intended to ensure that all market participants would have a basic security program that would effectively protect the electric grid and related market activities. As proposed, these standards would apply to AEP's power transmission systems, distribution systems and related areas of business. The proposed standards have not been adopted. Subsequently, in 2002, the North American Electric Reliability Council (NERC), with FERC's support, developed a new set of standards to address industry compliance. These new standards closely parallel the initial, proposed FERC standards in both content and compliance time frames, and were approved by the NERC ballot body in June of 2003. AEP is developing financial requirements for security implementation and compliance with these NERC standards. Since these financial requirements are not yet determined, management cannot predict the impacts of such standards on future results of operations and cash flows. 8. GUARANTEES ---------- In November 2002, the FASB issued FIN 45 which clarifies the accounting to recognize a liability related to issuing a guarantee, as well as additional disclosures of guarantees. This new guidance is an interpretation of SFAS 5, 57, and 107 and a rescission of FIN 34. The initial recognition and initial measurement provisions of FIN 45 were effective on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements of FIN 45 were effective for financial statements of interim or annual periods ending after December 15, 2002. There are no liabilities recorded for any guarantees entered into by AEP's registrant subsidiaries in accordance with FIN 45 as these guarantees were entered into prior to December 31, 2002 or have immaterial values which were not recorded. There is no collateral held in relation to these guarantees and there is no recourse to third parties in the event these guarantees are drawn. Certain AEP subsidiaries have entered into standby letters of credit (LOC) with third parties. These LOCs cover gas and electricity trading contracts, construction contracts, insurance programs, security deposits, debt service reserves, drilling funds and credit enhancements for issued bonds. All of these LOCs were issued by an AEP subsidiary in the subsidiaries' ordinary course of business. TCC issued an LOC for credit enhancement of issued bonds. At June 30, 2003, the maximum future payments of all the LOCs are approximately $163 million with maturities ranging from July 2003 to January 2011. TCC's LOC was for approximately $40.9 million with a maturity date of November 2003. Since AEP is the parent to all these subsidiaries, it holds all assets of the subsidiaries as collateral. There is no recourse to third parties in the event these letters of credit are drawn. The following AEP subsidiaries have entered into guarantees of third- party obligations: In connection with reducing the cost of the lignite mining contract for its Henry W. Pirkey Power Plant, SWEPCo has agreed under certain conditions, to assume the obligations under a revolving credit agreement, capital lease obligations, and term loan payments of the mining contractor, Sabine Mining Company (Sabine). In the event Sabine defaults under any of these agreements, SWEPCo's total future maximum payment exposure is approximately $61 million with maturity dates ranging from June 2005 to February 2012. As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo has agreed to provide guarantees of mine reclamation in the amount of approximately $85 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by a third party miner. At June 30, 2003, the cost to reclaim the mine in 2035 is estimated to be approximately $36 million. This guarantee ends upon depletion of reserves estimated at 2035 plus 6 years to complete reclamation. It is reasonably possible that due to the guarantees and contracts in place with Sabine that SWEPCo will consolidate Sabine in the third quarter of 2003, as a result of the issuance of FIN 46. Upon consolidation, SWEPCo would record the assets, liabilities, depreciation expense, minority interest and debt interest expense of Sabine. SWEPCo would eliminate expenses associated with the mining contract against Sabine's revenues. See Note 11 "Leases" for disclosure of lease residual value guarantees. AEP and its subsidiaries enter into several types of contracts, which would require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, AEP's registrant subsidiaries' exposure generally does not exceed the sale price. AEP's registrant subsidiaries cannot estimate the maximum potential exposure for any of these indemnifications entered prior to December 31, 2002 due to the uncertainty of future events. In the first six months of 2003, AEP's registrant subsidiaries entered into sale agreements which included indemnifications with a maximum exposure that was not significant for any individual registrant subsidiary. There are no material liabilities recorded for any indemnifications entered during the first six months of 2003. There are no liabilities recorded for any indemnifications entered prior to December 31, 2002. AEP and its subsidiaries lease certain equipment under a master operating lease. Under the lease agreement, the lessor is guaranteed to receive up to 87% of the unamortized balance of the equipment at the end of the lease term. If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, we have committed to pay the difference between the fair market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance. At June 30, 2003, AEP's maximum potential loss for these lease agreements was approximately $27 million assuming the fair market value of the equipment is zero at the end of the lease term. The maximum potential loss by registrant is as follows: Maximum Potential Loss Subsidiary (in millions) ---------- ---------------------- APCo $ 1 CSPCo 1 I&M 2 KPCo 1 OPCo 3 PSO 3 SWEPCo 3 TCC 6 TNC 2 Other AEP Subsidiaries 5 --- Total AEP $27 === 9. SUSTAINED EARNINGS IMPROVEMENT INITIATIVE ----------------------------------------- In response to difficult conditions in our business, a Sustained Earnings Improvement (SEI) initiative was undertaken company-wide in the fourth quarter of 2002, as a cost-saving and revenue-building effort to build long-term earnings growth. Termination benefits expense relating to terminated employees was recorded in the fourth quarter of 2002. The termination benefits expense was classified as Other Operation expense on the statements of operations. No additional termination benefits expense related to the SEI initiative was recorded during the first and second quarters of 2003, and significantly all SEI related payments have been made as of June 30, 2003. See Note 11 "Sustained Earnings Improvement Initiative" in our 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003) for further information on expenses recorded by registrant subsidiary during the fourth quarter 2002 related to the SEI initiative. 10. BUSINESS SEGMENTS ----------------- All of AEP's registrant subsidiaries have one reportable segment. The one reportable segment is a vertically integrated electricity generation, transmission and distribution business except AEGCo, an electricity generation business. All of the registrants' other activities are insignificant. The registrant subsidiaries operations are managed on an integrated basis because of the substantial impact of bundled cost-based rates and regulatory oversight on the business process, cost structures and operating results. 11. LEASES ------ OPCo has entered into an agreement with JMG Funding LLP (JMG), an unrelated unconsolidated special purpose entity. JMG has a capital structure of which 3% is equity from investors with no relationship to AEP or any of its subsidiaries and 97% is debt from pollution control bonds and other bonds. JMG was formed to design, construct and lease the Gavin Scrubber for the Gavin Plant to OPCo. JMG owns the Gavin Scrubber and leases it to OPCo. The lease is accounted for as an operating lease. Payments under the operating lease are based on JMG's cost of financing (both debt and equity) and include an amortization component plus the cost of administration. OPCo and AEP do not have an ownership interest in JMG and do not guarantee JMG's debt. At any time during the lease, OPCo has the option to purchase the Gavin Scrubber for the greater of its fair market value or adjusted acquisition cost (equal to the unamortized debt and equity of JMG) or sell the Gavin Scrubber. The initial 15-year lease term is non-cancelable. At the end of the initial term, OPCo can renew the lease, purchase the Gavin Scrubber (terms previously mentioned), or sell the Gavin Scrubber. In case of a sale at less than the adjusted acquisition cost, OPCo must pay the difference to JMG. The use of JMG allows OPCo to enter into an operating lease while keeping the tax benefits otherwise associated with a capital lease. As of June 30, 2003, AEP has determined that OPCo will consolidate JMG in the third quarter of 2003 as a result of the issuance of FIN 46. Upon consolidation, OPCo will record the assets, liabilities, depreciation expense, minority interest and debt interest expense of JMG. OPCo will eliminate operating lease expense against JMG's rental revenues. As of June 30, 2003, the Company is still reviewing the impact of the consolidation, but will have to record the cumulative effect (net of tax) due to a change in accounting principle. OPCo's maximum exposure to loss as a result of its involvement with JMG is approximately $460 million of outstanding debt and equity of JMG as of June 30, 2003. On March 31, 2003, OPCo made a prepayment of $90 million under this operating lease structure. AEP recognizes lease expense on a straight-line basis over the remaining lease term, in accordance with SFAS 13 "Accounting for Leases." The asset will be amortized over the remaining lease term, which ends in the first quarter of 2010. 12. FINANCING AND RELATED ACTIVITIES -------------------------------- Long-term debt and other securities issuances and retirements during the first six months of 2003 were:

In July 2003, OPCo issued the following Senior Unsecured Notes: Principal Due Amount Interest Rate Date ----------- ------------- ---- (in millions) (%) $225 million 4.85% 2014 225 million 6.375% 2033 CONTROLS AND PROCEDURES During the second quarter of 2003, AEP's management, including the principal executive officer and principal financial officer, evaluated AEP's disclosure controls and procedures related to the recording, processing, summarization and reporting of information in AEP's periodic reports that it files with the SEC. These disclosure controls and procedures have been designed to ensure that (a) material information relating to AEP, including its consolidated subsidiaries, is made known to AEP's management, including these officers, by other employees of AEP and its subsidiaries, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC's rules and forms. AEP's controls and procedures can only provide reasonable, not absolute, assurance that the above objectives have been met. As of June 30, 2003, these officers concluded that the disclosure controls and procedures in place provide reasonable assurance that the disclosure controls and procedures can accomplish their objectives. AEP continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. There have not been any changes in AEP's internal controls over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the second quarter of 2003 that have materially affected, or are reasonably likely to materially affect, AEP's internal control over financial reporting. PART II. OTHER INFORMATION Item 1. Legal Proceedings. ----------------- For a discussion of material legal proceedings, see Note 8 to AEP's consolidated financial statements and Note 7 to AEP's registrant subsidiaries' respective financial statements, both entitled Commitments and Contingencies, incorporated herein by reference. Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, -------------------------------------------------------------------------- I&M, and OPCo ------------- As discussed in Note 9 of the Combined Notes to Financial Statements in the 2002 Annual Report (as updated by the Current Report on Form 8-K dated May 14, 2003), AEPSC, APCo, CSPCo, I&M, and OPCo have been involved in litigation regarding generating plant emissions under the Clean Air Act. Federal EPA and a number of states alleged APCo, CSPCo, I&M, OPCo and eleven unaffiliated utilities modified certain units at coal-fired generating plants in violation of the Clean Air Act. Federal EPA filed complaints against 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. Under the Clean Air Act, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components, or other repairs needed for the reliable, safe and efficient operation of the plant. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). In 2001, the District Court ruled that claims for civil penalties are limited to the five-year period prior to the filing date of the complaints. There is no time limit on claims for injunctive relief. On August 7, 2003 the District Court issued a decision following a liability trial in a similar case pending in the Southern District of Ohio against Ohio Edison Company, an unrelated utility. The District Court held that replacements of major boiler and turbine components that are infrequently performed at a single unit, that are performed with the assistance of outside contractors, that are accounted for as capital expenditures, and that require the unit to be taken out of service for a number of months are not "routine" maintenance, repair, and replacement. The District Court also held that a comparison of past actual emissions to projected future emissions must be performed prior to any non-routine physical change in order to evaluate whether an emissions increase will occur, and that increased hours of operation that are the result of eliminating forced outages due to the repairs must be included in that calculation. Based on these holdings, the District Court ruled that all of the challenged activities in that case were not routine, and that the changes resulted in significant net increases in emissions for certain pollutants. A remedy trial is scheduled for March 2004. Management believes that the Ohio Edison decision fails to properly evaluate and apply the applicable legal standards. The facts in the AEP case also vary widely from plant to plant. Further, the Ohio Edison decision is limited to liability issues, and provides no insight as to the remedies that might ultimately be ordered by the Court. On June 24, 2003, the United States Court of Appeals for the 11th Circuit issued an order invalidating the administrative compliance order issued by Federal EPA to the Tennessee Valley Authority for similar alleged violations. The 11th Circuit determined that the administrative compliance order was not a final agency action, and that the enforcement provisions authorizing the issuance and enforcement of such orders under the Clean Air Act is unconstitutional. On June 26, 2003, the United States Circuit Court of Appeals for the District of Columbia Circuit granted a petition by the Utility Air Regulatory Group (UARG), of which the AEP subsidiaries are members, to reopen petitions for review of the 1980 and 1992 Clean Air Act rulemakings that are the basis for the Federal EPA claims in the AEP case and other related cases. On August 4, 2003, UARG filed a motion to separate and expedite review of their challenges to the 1980 and 1992 rulemakings from other unrelated claims in the consolidated appeal. The central issue in these petitions concerns the lawfulness of the emissions increase test, as currently interpreted and applied by Federal EPA in its utility enforcement actions. A decision by the D. C. Circuit could significantly impact further proceedings in the AEP case. Management is unable to estimate the loss or range of loss related to the contingent liability for civil penalties under the Clear Air Act proceedings and unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. In the event the AEP System companies do not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates and market prices for electricity. In December 2000, Cinergy Corp., an unaffiliated utility, which operates certain plants jointly owned by CSPCo, reached a tentative agreement with Federal EPA and other parties to settle litigation regarding generating plant emissions under the Clean Air Act. Negotiations are continuing between the parties in an attempt to reach final settlement terms. Cinergy's settlement could impact the operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 (owned 25.4% and 12.5%, respectively, by CSPCo). 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. Item 4. Submission of Matters to a Vote of Security Holders. --------------------------------------------------- AEP The annual meeting of shareholders was held in Columbus, Ohio, on April 23, 2003. The holders of shares entitled to vote at the meeting or their proxies cast votes at the meeting with respect to the following three matters, as indicated below: 1. Election of thirteen directors to hold office until the next annual meeting and until their successors are duly elected. Each nominee for director received the votes of shareholders as follows:

2. Shareholder proposal submitted by First Investors Trust. The proposal was disapproved by a vote of the shareholders as follows: Votes FOR 39,599,579 Votes AGAINST 203,803,580 Votes ABSTAINED 6,390,989 Broker NON-VOTES* 71,809,331 3. Shareholder proposal submitted by Connecticut Retirement and Trust Funds and Christian Brothers Investment Services, Inc. The proposal was disapproved by a vote of the shareholders as follows: Votes FOR 58,589,132 Votes AGAINST 159,143,612 Votes ABSTAINED 32,068,627 Broker NON-VOTES* 71,802,108 *A non-vote occurs when a nominee holding shares for a beneficial owner votes on one proposal, but does not vote on another proposal because the nominee does not have discretionary voting power and has not received instructions from the beneficial owner. APCo The annual meeting of stockholders was held on April 22, 2003 at 1 Riverside Plaza, Columbus, Ohio. At the meeting, 13,499,500 votes were cast FOR each of the following seven persons for election as directors and there were no votes withheld and such persons were elected directors to hold office for one year or until their successors are elected and qualify: E. Linn Draper, Jr. Robert P. Powers Henry W. Fayne Thomas V. Shockley, III Thomas M. Hagan Susan Tomasky Armando A. Pena TCC Pursuant to action by written consent in lieu of an annual meeting of the sole shareholder dated April 10, 2003, the following seven persons were elected directors to hold office for one year or until their successors are elected and qualify: E. Linn Draper, Jr. Robert P. Powers Henry W. Fayne Thomas V. Shockley, III Thomas M. Hagan Susan Tomasky Armando A. Pena I&M Pursuant to action by written consent in lieu of an annual meeting of the sole shareholder dated April 22, 2003, the following thirteen persons were elected directors to hold office for one year or until their successors are elected and qualify: Karl G. Boyd Susanne M. Moorman E. Linn Draper, Jr. Robert P. Powers John E. Ehler John R. Sampson Henry W. Fayne Thomas V. Shockley, III Thomas M. Hagan David B. Synowiec David L. Lahrman Susan Tomasky Marc E. Lewis OPCo The annual meeting of shareholders was held on May 6, 2003 at 1 Riverside Plaza, Columbus, Ohio. At the meeting there were 27,952,473 votes cast FOR: Each of the following seven persons for election as directors and there were no votes withheld and such persons were elected directors to hold office for one year or until their successors are elected and qualify: E. Linn Draper, Jr. Robert P. Powers Henry W. Fayne Thomas V. Shockley, III Thomas M. Hagan Susan Tomasky Armando A. Pena SWEPCo Pursuant to action by written consent in lieu of an annual meeting of the sole shareholder dated April 9, 2003, the following seven persons were elected directors to hold office for one year or until their successors are elected and qualify: E. Linn Draper, Jr. Robert P. Powers Henry W. Fayne Thomas V. Shockley, III Thomas M. Hagan Susan Tomasky Armando A. Pena Item 5. Other Information. ----------------- NONE Item 6. Exhibits and Reports on Form 8-K. -------------------------------- (a) Exhibits: -------- AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC Exhibit 12 - Computation of Consolidated Ratio of Earnings to Fixed Charges. AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC Exhibit 31.1 - Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Exhibit 31.2 - Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Exhibit 32.1 - Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. Exhibit 32.2 - Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. (b) Reports on Form 8-K: AEGCo, APCo, I&M, KPCo, PSO, SWEPCo, TCC and TNC The following reports on Form 8-K were filed during the quarter ended June 30, 2003.

Signatures Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signatures for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. AMERICAN ELECTRIC POWER COMPANY, INC. By: /s/Geoffrey S. Chatas By: /s/Joseph M. Buonaiuto ----------------------- ---------------------------- Geoffrey S. Chatas Joseph M. Buonaiuto Treasurer Controller and Chief Accounting Officer AEP GENERATING COMPANY AEP TEXAS CENTRAL COMPANY AEP TEXAS NORTH 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 By: /s/Geoffrey S. Chatas By: /s/Joseph M. Buonaiuto ----------------------- ---------------------------- Geoffrey S. Chatas Joseph M. Buonaiuto Treasurer Controller and Chief Accounting Officer Date: August 12, 2003

KENTUCKY POWER CO 10-Q